1
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1999
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
---------------------
EL PASO NATURAL GAS COMPANY
(Exact Name of Registrant as Specified in its Charter)
DELAWARE 74-0608280
(State or Other Jurisdiction (I.R.S. Employer
of Incorporation or Organization) Identification No.)
EL PASO ENERGY BUILDING
1001 LOUISIANA STREET
HOUSTON, TEXAS 77002
(Address of Principal Executive Offices) (Zip Code)
Registrant's Telephone Number, Including Area Code: (713) 420-2131
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date.
Common Stock, par value $1.00 per share. Shares outstanding on November 12,
1999: 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.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
2
GLOSSARY
The following abbreviations, acronyms, or defined terms used in this Form
10-Q are defined below:
DEFINITIONS
-----------
ALJ................... Administrative Law Judge
Company............... El Paso Natural Gas Company and its subsidiaries
Court of Appeals...... United States Court of Appeals for the District of Columbia Circuit
Dynegy................ Dynegy Inc., formerly known as NGC Corporation
EBIT.................. Earnings before interest expense and income taxes, excluding affiliated
interest income
Edison................ Southern California Edison Company
EPEC.................. El Paso Energy Corporation, the parent company of El Paso Natural Gas
Company
EPFS.................. El Paso Field Services Company, a wholly owned subsidiary of El Paso
Tennessee Pipeline Co.
EPNG.................. El Paso Natural Gas Company, a wholly owned subsidiary of El Paso Energy
Corporation
FERC.................. Federal Energy Regulatory Commission
PRP(s)................ Potentially responsible party(ies)
i
3
PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
EL PASO NATURAL GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS)
(UNAUDITED)
QUARTER NINE MONTHS
ENDED ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------- -------------
1999 1998 1999 1998
----- ----- ----- -----
Operating revenues.......................................... $120 $118 $359 $357
---- ---- ---- ----
Operating expenses
Operation and maintenance................................. 44 39 126 125
Depreciation, depletion, and amortization................. 16 14 47 45
Taxes, other than income taxes............................ 7 8 23 23
---- ---- ---- ----
67 61 196 193
---- ---- ---- ----
Operating income............................................ 53 57 163 164
---- ---- ---- ----
Other income, net........................................... (1) -- (1) (2)
---- ---- ---- ----
Income before interest, income taxes and discontinued
operations................................................ 54 57 164 166
---- ---- ---- ----
Non-affiliated interest and debt expense.................... 24 32 79 91
Affiliated interest income, net............................. (17) (20) (45) (41)
Income tax expense.......................................... 18 17 50 44
---- ---- ---- ----
25 29 84 94
---- ---- ---- ----
Income before discontinued operations....................... 29 28 80 72
Discontinued operations, net of income taxes................ -- 32 -- 101
---- ---- ---- ----
Net income.................................................. $ 29 $ 60 $ 80 $173
==== ==== ==== ====
The accompanying Notes are an integral part of these
Condensed Consolidated Financial Statements.
1
4
EL PASO NATURAL GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
SEPTEMBER 30, DECEMBER 31,
1999 1998
------------- ------------
(UNAUDITED)
ASSETS
Current assets
Cash and cash equivalents................................. $ 10 $ 9
Accounts and notes receivable, net........................ 1,163 1,107
Materials and supplies.................................... 28 28
Other..................................................... 8 7
------ ------
Total current assets.............................. 1,209 1,151
Property, plant, and equipment, net......................... 1,529 1,537
Other....................................................... 109 98
------ ------
Total assets...................................... $2,847 $2,786
====== ======
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities
Accounts payable.......................................... $ 73 $ 34
Short-term borrowings (including current maturities of
long-term debt)........................................ 201 268
Income taxes payable...................................... 55 18
Other..................................................... 113 99
------ ------
Total current liabilities......................... 442 419
------ ------
Long-term debt, less current maturities..................... 969 980
------ ------
Deferred income taxes....................................... 192 173
------ ------
Other....................................................... 141 170
------ ------
Commitments and contingencies (See Note 3)
Stockholder's equity
Preferred stock, 1,000,000 shares authorized; 8% par value
$0.01 per share: 500,000 shares issued; stated at
liquidation value...................................... 350 350
Common stock, par value $1 per share; authorized 1,000
shares; issued 1,000................................... -- --
Additional paid-in capital................................ 694 694
Retained earnings......................................... 59 --
------ ------
Total stockholder's equity........................ 1,103 1,044
------ ------
Total liabilities and stockholder's equity........ $2,847 $2,786
====== ======
The accompanying Notes are an integral part of these
Condensed Consolidated Financial Statements.
2
5
EL PASO NATURAL GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)
(UNAUDITED)
NINE MONTHS
ENDED
SEPTEMBER 30,
--------------
1999 1998
----- -----
Cash flows from operating activities
Net income................................................ $ 80 $ 173
Less income from discontinued operations, net of income
taxes.................................................. -- 101
----- -----
Income from continuing operations........................... 80 72
Adjustments to reconcile net income to net cash from
operating activities
Depreciation, depletion, and amortization.............. 47 45
Deferred income taxes.................................. 17 14
Other.................................................. (23) (9)
Working capital changes................................... 137 (108)
Other..................................................... (7) 12
----- -----
Cash provided by continuing operations................. 251 26
Cash provided by discontinued operations............... -- 384
----- -----
Net cash provided by operating activities......... 251 410
----- -----
Cash flows from investing activities
Capital expenditures...................................... (36) (21)
Net change in advances to EPEC............................ (138) (719)
Other..................................................... 2 2
Cash used in investing activities by discontinued
operations............................................. -- (246)
----- -----
Net cash used in investing activities............. (172) (984)
----- -----
Cash flows from financing activities
Net commercial paper borrowings........................... 20 278
Other credit facilities borrowings........................ 382 260
Other credit facilities repayments........................ (422) (70)
Long-term debt retirements................................ (58) (26)
Dividends paid on common stock............................ -- (68)
Net proceeds from stock issuance.......................... -- 296
Cash used in financing activities by discontinued
operations............................................. -- (163)
----- -----
Net cash provided by (used in) financing
activities....................................... (78) 507
----- -----
Increase (decrease) in cash and temporary investments....... 1 (67)
Less decrease in cash and temporary investments related to
discontinued operations................................ -- (18)
----- -----
Increase (decrease) in cash and temporary investments from
continuing operations..................................... 1 (49)
Cash and temporary investments
Beginning of period....................................... 9 63
----- -----
End of period............................................. $ 10 $ 14
===== =====
The accompanying Notes are an integral part of these
Condensed Consolidated Financial Statements.
3
6
EL PASO NATURAL GAS COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. BASIS OF PRESENTATION
The 1998 Annual Report on Form 10-K for the Company includes a summary of
significant accounting policies and other disclosures and should be read in
conjunction with this Quarterly Report on Form 10-Q. The condensed consolidated
financial statements at September 30, 1999, and for the quarters and nine months
ended September 30, 1999 and 1998, are unaudited. The condensed consolidated
balance sheet at December 31, 1998, is derived from audited financial statements
at that date. These financial statements do not include all disclosures required
by generally accepted accounting principles, but have been prepared pursuant to
the rules and regulations of the U.S. Securities and Exchange Commission. In the
opinion of management, all material adjustments necessary to present fairly the
results of operations for such periods have been included. All such adjustments,
except for those relating to discontinued operations as described below, are of
a normal, recurring nature. Results of operations for any interim period are not
necessarily indicative of the results of operations for the entire year due to
the seasonal nature of the Company's businesses. Financial statements for the
previous periods include certain reclassifications which were made to conform to
the current presentation. Such reclassifications have no effect on reported net
income or stockholder's equity.
Tax-free Internal Reorganization (Discontinued Operations)
On December 31, 1998, EPEC completed a series of steps to effect a tax-free
internal reorganization. The Company has treated the assets and operations
distributed to EPEC or other subsidiaries of EPEC in the tax-free internal
reorganization as though they were discontinued operations as of December 31,
1998. Accordingly, the information for the quarter and nine months ended
September 30, 1998, in these financial statements has been presented as though
the transactions occurred on January 1, 1998. Revenues related to those items
treated as discontinued operations were $1,497 million and $4,173 million for
the quarter and nine months ended September 30, 1998, respectively.
2. DEBT AND OTHER CREDIT FACILITIES
In August 1999, EPEC established a new $1,250 million 364-day renewable
revolving credit and competitive advance facility. As of September 30, 1999,
EPEC's interest rate for borrowings under this facility was equal to LIBOR plus
50 basis points. The rate will vary based on EPEC's long-term unsecured debt
rating. This facility replaced EPEC's $750 million 364-day renewable revolving
credit and competitive advance facility established in October 1997. EPNG is a
designated borrower under this credit facility. As of September 30, 1999, no
amounts were outstanding under this facility.
In September 1999, the Company retired its outstanding 9.45% Notes in the
principal amount of $47 million.
The weighted average interest rate of short-term borrowings was 5.6% and
5.8% at September 30, 1999 and December 31, 1998, respectively. The Company had
short-term borrowings, including current maturities of long term debt, at
September 30, 1999 and December 31, 1998, as follows:
1999 1998
----- -----
(IN MILLIONS)
Commercial paper............................................ $170 $150
Other credit facilities..................................... 20 60
Current maturities of long-term debt........................ 11 58
---- ----
$201 $268
==== ====
4
7
For the nine month period ended September 30, 1999, the Company accrued $21
million in dividends payable on its 8% preferred stock.
In October 1999, Mojave Pipeline Company ("MPC") retired its variable rate
non-recourse project financing in the principal amount of $107 million.
Concurrently, MPC also unwound its associated interest rate swap at a cost of
approximately $5 million.
3. COMMITMENTS AND CONTINGENCIES
Rates and Regulatory Matters
In July 1998, FERC issued a Notice of Proposed Rulemaking ("NOPR") in which
it sought comments on a wide range of initiatives to change the manner in which
short-term (less than one year) transportation markets are regulated. Among
other things, the NOPR proposes the following: (i) removing the price cap for
the short-term capacity market; (ii) establishing procedures to make pipeline
and shipper-owned capacity comparable; (iii) auctioning all available short-term
pipeline capacity on a daily basis with the pipeline unable to set a reserve
price above variable costs; (iv) changing policies or pipeline penalties,
nomination procedures and services; (v) increasing pipeline reporting
requirements; (vi) permitting the negotiation of terms and conditions of
service; and (vii) potentially modifying the procedures for certificating new
pipeline construction. Also in July 1998, FERC issued a Notice of Inquiry
("NOI") seeking comments on FERC's policy for pricing long-term capacity. The
Company provided comments on the NOPR and NOI in April 1999.
In June 1995, EPNG filed with FERC for approval of new system rates for
mainline transportation to be effective January 1, 1996. In March 1996, EPNG
filed a comprehensive offer of settlement to resolve that proceeding as well as
issues surrounding certain contract reductions and expirations that were to
occur from January 1, 1996 through December 31, 1997. In April 1997, FERC
approved EPNG's settlement, as filed, and determined that only the contesting
party, Edison, should be severed for separate determination of the rates it
ultimately pays EPNG. In July 1997, FERC issued an order denying the requests
for rehearing of the April 1997 order and the settlement was implemented
effective July 1, 1997. Hearings to determine Edison's rates were completed in
May 1998, and an initial decision was issued by the presiding ALJ in July 1998.
Edison also filed a petition with the Court of Appeals for review of FERC's
April 1997 and July 1997 orders, in which it challenged the propriety of FERC's
approving EPNG's settlement over Edison's objections as a customer of Southern
California Gas Company. In December 1998, the Court of Appeals issued its
decision vacating and remanding FERC's order.
In August 1999, EPNG and Edison filed a joint settlement with FERC
resolving all issues related to EPNG's June 1995 rate filing. The joint
settlement provides for Edison to withdraw its opposition to the rate settlement
and to pay EPNG the maximum tariff rate for transportation service to California
from July 1, 1999, through the end of the term of the rate settlement, exclusive
of any risk sharing amounts, and for EPNG to pay Edison $32 million in
resolution of all claims raised by Edison. Payment to Edison is expected to
occur in the fourth quarter of 1999. In addition to not having a risk sharing
obligation, Edison will not participate in revenue sharing. The settlement
payment to Edison exceeds the reserve previously provided by EPNG by
approximately $14 million, and this difference has been reflected in results of
operations for the third quarter of 1999.
On November 10, 1999, FERC approved the joint settlement between EPNG and
Edison. FERC also reapproved EPNG's rate settlement on remand conditioned upon
the immediate adjustment of EPNG's fuel charges with respect to facilities
refunctionalized as gathering (see discussion of Chaco and Blanco below). If
FERC's condition is deemed to be a modification of EPNG's settlement, some
parties to the settlement may assert a right to withdraw support for and become
opponents to the settlement. EPNG is currently evaluating the potential impact
of this ruling on the rate settlement.
The rate settlement effective January 1996, establishes, among other
things, base rates through December 31, 2005. Such rates escalate annually
beginning in 1998. In addition, the settlement provides for settling customers
to (i) pay $295 million (including interest) as a risk sharing obligation, which
approximates
5
8
35 percent of anticipated revenue shortfalls over an 8 year period resulting
from certain contract reductions and expirations identified in the settlement,
(ii) receive 35 percent of additional revenues received by EPNG, above a
threshold, for the same eight-year period, and (iii) have the base rates
increase or decrease if certain changes in laws or regulations result in
increased or decreased costs in excess of $10 million a year.
Through September 30, 1999, approximately $238 million of the risk sharing
obligation had been paid,
and the remaining balance of $57 million will be collected by the end of 2003.
The risk sharing obligation is being recognized in revenues ratably over the
period of the related contractual reductions, and at September 30, 1999, the
balance of the unearned risk sharing revenue was $192 million. This amount will
be recognized ratably through the year 2003.
Under the revenue sharing provisions of its rate case settlement, EPNG was
obligated to return approximately $12 million of non-traditional fixed cost
revenues earned in 1998 to certain customers. This amount was credited to those
customers' transportation invoices between October 1998 and March 1999. EPNG
continues to reserve for the revenue sharing provisions which are expected to be
credited to customer accounts during the period October 1999 through March 2000.
At September 30, 1999, EPNG had a reserve of approximately $10 million.
To partially offset the effects of the reduction in firm capacity
commitments referred to above, EPNG entered into contracts with Dynegy for the
sale of substantially all of its turned back firm capacity available to
California as of January 1, 1998, (approximately 1.3 billion cubic feet) for a
two-year period at rates negotiated pursuant to EPNG's tariff provisions and
FERC policies. The contracts have a transport-or-pay provision requiring Dynegy
to pay a minimum charge equal to the reservation component of the contractual
charge on at least 72 percent of the contracted volumes each month in 1999. EPNG
realized $32 million in revenue in the nine months ended September 30, 1999, and
anticipates realizing at least $11 million in revenues during the fourth quarter
of 1999 for this capacity. Such revenue is subject to the revenue sharing
provisions of the rate settlement. EPNG has offered this capacity for sale
pursuant to EPNG's tariff provisions and FERC regulations, subject to Dynegy's
right of first refusal, and expects that this capacity will be placed. However,
there can be no assurance whether EPNG will be able to replace this capacity
under similar contracts or that the terms of new contracts will be as favorable
to EPNG as existing contracts.
In December 1997, EPNG filed to implement several negotiated rate
contracts, including those with Dynegy. In a protest to this filing, three
shippers (producers/marketers) requested that FERC require EPNG to eliminate
certain provisions from its Dynegy contracts, to publicly disclose and repost
the contracts for competitive bidding, and to suspend their effectiveness. In
June 1998, FERC rejected the protests to the Dynegy contracts, but required EPNG
to file certain modifications to the contracts with FERC. In addition, EPNG
agreed to separately post capacity covered by the Dynegy contracts as it becomes
available. In July 1999, FERC issued an order on rehearing which generally
denied all pending rehearing requests and accepted EPNG's letter agreement,
subject to certain modifications to one of the Dynegy contracts. In September
1999, the FERC issued a letter order accepting the Company's revised letter
agreement filing. In October 1999, the FERC issued an order granting EPNG's
request for clarification of the July 1999 order, but otherwise denied rehearing
of such order.
In a November 1997 order, FERC ruled that EPNG's Chaco Station should be
functionalized as a gathering, not a transmission, facility and should be
transferred to EPFS. In accordance with the FERC orders, the Chaco Station was
transferred to EPFS in April 1998. EPNG and two other parties filed petitions
for review with the Court of Appeals. In October 1999, the Court of Appeals
sustained FERC's determination that the Chaco Station is a gathering facility,
but remanded to FERC issues relating to the appropriate fuel and rate treatment
resulting from this refunctionalization. In an order approved November 10, 1999,
FERC ruled that an immediate adjustment of EPNG's fuel charges with respect to
the refunctionalized facilities was appropriate but that no change should be
made to EPNG's base rates as a result of refunctionalization.
In August 1999, Williams Field Services Group ("Williams") filed a
complaint against the Company seeking a determination that the Company's Blanco
Compressor Station is a non-jurisdictional gathering facility rather than a
jurisdictional transmission facility. Williams also requests the immediate
removal of all costs of the Blanco and Chaco facilities from the Company's
jurisdictional transmission rates, including fuel
6
9
rates. The Company filed an answer in opposition to the complaint. On November
10, 1999, FERC ruled that two of the three Blanco compressor units were
nonjurisdictional gathering facilities. FERC also held that EPNG's fuel charges
should be adjusted to exclude these refunctionalized facilities.
In September 1999, Burlington Resources and Amoco Energy filed a "Fast
Track" complaint requesting that FERC order the Company to cease and desist
selling primary firm delivery point capacity at the Southern California Gas
Company Topock Delivery point in excess of the capacity available at that point.
The Company filed an answer in opposition to the complaint. On November 10,
1999, FERC approved an order finding that EPNG's delivery point and receipt
point allocation methodology may be unjust and unreasonable, and ordered EPNG to
file new proposed tariff provisions regarding receipt and delivery point
allocation rights within 60 days of the date of the order. EPNG is currently
evaluating the impact of this order on its operations and its customers.
EPNG, as an interstate pipeline, is subject to FERC audits of its books and
records. EPNG currently has an open audit covering the years 1990 through 1995.
FERC is expected to issue its final audit report in the fourth quarter of 1999.
In addition, as part of an industry-wide initiative, EPNG's property retirements
are currently under review by the FERC audit staff.
As the aforementioned rate and regulatory matters are fully and
unconditionally resolved, the Company may either recognize an additional refund
obligation or a non-cash benefit to finalize previously estimated liabilities.
Management believes the ultimate resolutions of these matters, which are in
various stages of finalization, will not have a material adverse effect on the
Company's financial position, results of operations, or cash flows.
Legal Proceedings
In November 1993, TransAmerican Natural Gas Corporation ("TransAmerican")
filed a complaint in a Texas state court which, as amended, seeks approximately
$7.5 billion in actual and punitive damages related to a 1990 settlement
agreement between EPNG, TransAmerican, and others. TransAmerican's complaint, as
amended from time to time, has advanced ten causes of action against EPNG. As a
result of orders by the court on various motions for summary judgment, three
causes of action have been dismissed in their entirety and three have been
partially dismissed. The partially dismissed claims allege tortious
interference, civil conspiracy, and fraud, and the other claims that remain
pending allege breach of contract, bad faith, participation in breach of
fiduciary duty, and violation of the Texas Antitrust Act. Motions for summary
judgment on all of TransAmerican's remaining claims are expected to be heard and
decided by the court prior to the current trial setting of January 31, 2000.
Additionally, EPNG has filed a breach of contract counterclaim against
TransAmerican seeking to recover EPNG's expenses incurred in connection with the
lawsuit. TransAmerican's motion for summary judgment on this counterclaim was
denied by the court. In April 1996, a former employee of TransAmerican filed a
related case in Harris County, Texas, Vickroy E. Stone v. Godwin & Carlton,
P.C., et al. ("Stone"), seeking other damages in unspecified amounts related to
litigation consulting work allegedly performed for various entities, including
EPNG, in cases involving TransAmerican. In June 1998, the court granted EPNG's
motion for summary judgment and dismissed all claims in the Stone litigation.
Stone has appealed the court's ruling to the Texas Court of Appeals in Houston,
Texas. Based on information available at this time, management believes that the
claims asserted against it in both cases have no factual or legal basis and that
the ultimate resolution of these matters will not have a material adverse effect
on the Company's financial position, results of operations, or cash flows.
A number of subsidiaries of EPEC, both wholly and partially owned,
including the Company, have been named defendants in actions brought by Jack
Grynberg on behalf of the U.S. Government under the False Claims Act. Generally,
the complaints allege an industry-wide conspiracy to underreport the heating
value as well as the volumes of the natural gas produced from federal and Indian
lands, thereby depriving the U.S. Government of royalties. The Company believes
the complaint to be without merit and that the ultimate resolution of this issue
will not have a material adverse effect on the Company's financial position,
results of operations, or cash flows.
7
10
The Company is a named defendant in numerous lawsuits and a named party in
numerous governmental proceedings arising in the ordinary course of business.
While the outcome of such lawsuits or other proceedings cannot be predicted with
certainty, management currently does not expect these matters to have a material
adverse effect on the Company's financial position, results of operations, or
cash flows.
Environmental
The Company is subject to extensive federal, state, and local laws and
regulations governing environmental quality and pollution control. These laws
and regulations require the Company to remove or remedy the effect on the
environment of the disposal or release of specified substances at current and
former operating sites. As of September 30, 1999, the Company had reserves of
approximately $22 million for expected environmental costs.
Capital expenditures are expected to be approximately $9 million in total
for the years 2000 through 2007. These expenditures primarily relate to
compliance with air regulations.
The Company and certain of its subsidiaries have been designated, have
received notice that they could be designated, or have been asked for
information to determine whether they could be designated as a PRP with respect
to 5 sites under CERCLA or state equivalents. The Company has sought to resolve
its liability as a PRP with respect to these Superfund sites through
indemnification by third parties and/or settlements which provide for payment of
the Company's allocable share of remediation costs. Since the clean-up costs are
estimates and are subject to revision as more information becomes available
about the extent of remediation required, and because in some cases the Company
has asserted a defense to any liability, the Company's estimate of its share of
remediation costs could change. Moreover, liability under the federal Superfund
statute is joint and several, meaning that the Company could be required to pay
in excess of its pro rata share of remediation costs. The Company's
understanding of the financial strength of other PRPs has been considered, where
appropriate, in the determination of its estimated liability. The Company
presently believes that the costs associated with the current status of such
other entities as PRPs at the Superfund sites referenced above will not have a
material adverse effect on the Company's financial position, results of
operations, or cash flows.
The Company has initiated proceedings against its historic liability
insurers seeking payment or reimbursement of costs and liabilities associated
with various environmental matters. In these proceedings, the Company contends
that certain environmental costs and liabilities associated with various
entities or sites, including costs associated with former operating sites, must
be paid or reimbursed by certain of its historic insurers. The proceedings are
in the discovery stage, and it is not yet possible to predict the outcome.
It is possible that new information or future developments could require
the Company to reassess its potential exposure related to environmental matters.
The Company 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, regulations and
enforcement policies thereunder, and claims for damages to property, employees,
other persons and the environment resulting from current or discontinued
operations, could result in substantial costs and liabilities in the future. As
such information becomes available, or other relevant developments occur,
related accrual amounts will be adjusted accordingly. While there are still
uncertainties relating to the ultimate costs which may be incurred, based upon
the Company's evaluation and experience to date, the Company believes the
recorded reserves are adequate.
Other than the items discussed above, management is not aware of any other
commitments or contingent liabilities which would have a material adverse effect
on the Company's financial condition, results of operations, or cash flows.
8
11
4. PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment at September 30, 1999, and December 31,
1998, consisted of the following:
1999 1998
------ ------
(IN MILLIONS)
Property, plant, and equipment, at cost..................... $2,432 $2,417
Less accumulated depreciation and depletion................. 982 961
------ ------
1,450 1,456
Additional acquisition cost assigned to utility plant, net
of accumulated amortization............................... 79 81
------ ------
Total property, plant, and equipment, net......... $1,529 $1,537
====== ======
Current FERC policy does not permit the Company to recover amounts in
excess of original cost allocated in purchase accounting to its regulated
operations through rates.
5. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
Accounting for Derivative Instruments and Hedging Activities
In June 1998, Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging Activities, was issued by the
Financial Accounting Standards Board to establish accounting and reporting
standards for derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities. This pronouncement
requires that an entity classify all derivatives as either assets or liabilities
in the statement of financial position and measure those instruments at fair
value. If certain conditions are met, a derivative may be specifically
designated as (i) a hedge of the exposure to changes in the fair value of a
recognized asset or liability or an unrecognized firm commitment, (ii) a hedge
of the exposure to variable cash flows of a forecasted transaction, or (iii) a
hedge of the foreign currency exposure of a net investment in a foreign
operation, an unrecognized firm commitment, an available-for-sale security or a
foreign-currency-denominated forecasted transaction. The accounting for the
changes in the fair value of a derivative depends on the intended use of the
derivative and the resulting designation. The standard was amended by Statement
of Financial Accounting Standards No. 137 issued in June 1999. The amendment
defers the effective date to fiscal years beginning after June 15, 2000. The
Company is currently evaluating the effects of this pronouncement.
9
12
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The information contained in Item 2 updates, and should be read in
conjunction with, information set forth in Part II, Items 7, 7A, and 8, in the
Company's Annual Report on Form 10-K for the year ended December 31, 1998, in
addition to the interim condensed consolidated financial statements and
accompanying notes presented in Item 1 of this Quarterly Report on Form 10-Q.
GENERAL
On December 31, 1998, EPEC completed a tax-free internal reorganization of
its assets and operations and those of its subsidiaries. Following the
reorganization, the Company's primary assets were the interstate pipeline
systems known as the EPNG System and the Mojave Pipeline Company System. See
Note 1 for a further discussion of the tax-free internal reorganization.
RESULTS OF CONTINUING OPERATIONS
QUARTER NINE MONTHS
ENDED ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------- --------------
1999 1998 1999 1998
----- ----- ----- -----
(IN MILLIONS)
Operating revenues.................................. $120 $118 $ 359 $ 357
Operating expenses.................................. (67) (61) (196) (193)
Other, net.......................................... 1 -- 1 2
---- ---- ----- -----
EBIT.............................................. $ 54 $ 57 $ 164 $ 166
==== ==== ===== =====
Third Quarter 1999 Compared to Third Quarter 1998
Operating revenues for the quarter ended September 30, 1999, were $2
million higher than for the same period of 1998 primarily due to an increase in
revenues from the sale of capacity to Dynegy and an increase in transportation
revenues.
Operating expenses for the quarter ended September 30, 1999, were $6
million higher than for the same period of 1998. This increase was primarily due
to a regulatory settlement charge partially offset by revised estimates of
regulatory recoveries in the third quarter of 1999.
Nine Months Ended 1999 Compared to Nine Months Ended 1998
Operating revenues for the nine months ended September 30, 1999, were $2
million higher for the same period of 1998 primarily due to an increase in
revenues from the sale of capacity to Dynegy and an increase in transportation
revenues. These increases were partially offset by the favorable resolution of a
contested rate matter in the second quarter of 1998.
Operating expenses for the nine months ended September 30, 1999, were $3
million higher than for the same period of 1998. This increase was primarily due
to the effect of a regulatory settlement charge partially offset by revised
estimates of regulatory recoveries and lower fuel usage from greater system
efficiency.
NON-AFFILIATED INTEREST AND DEBT EXPENSE
Non-affiliated interest and debt expense for the quarter and nine months
ended September 30, 1999, was lower than for the same period of 1998 primarily
due to lower average principal balances on commercial paper and other credit
facilities in 1999.
10
13
AFFILIATED INTEREST INCOME, NET
Third Quarter 1999 Compared to Third Quarter 1998
Affiliated interest income, net for the quarter ended September 30, 1999,
was $3 million lower than for the same period of 1998 primarily due to transfer
of intercompany advances to EPEC during the third quarter of 1998 partially
offset by a reduction of affiliate debt.
Nine Months Ended 1999 Compared to Nine Months Ended 1998
Affiliated interest income, net for the nine months ended September 30,
1999, was $4 million higher than for the same period of 1998 primarily due to
the reduction of affiliate debt partially offset by the transfer of intercompany
advances to EPEC during the third quarter of 1998.
OTHER
YEAR 2000
EPEC has established an executive steering committee and a project team to
coordinate the phases of its Year 2000 project to assure that the Company's key
automated systems, equipment, and related processes will remain functional
through the Year 2000. Those phases are: (i) awareness; (ii) assessment; (iii)
remediation; (iv) testing; (v) implementation of the necessary modifications and
(vi) contingency planning. The Company has participated in EPEC's Year 2000
project as described below.
In recognition of the importance of Year 2000 issues and their potential
impact on the Company, the initial phase of the Year 2000 project involved the
establishment of a company-wide awareness program. The awareness program is
directed by the executive steering committee and project team and includes
participation of senior management in each core business area. The awareness
phase is substantially completed, although the Company will continually update
awareness efforts for the duration of the Year 2000 project.
The Company's assessment phase consists of conducting a company-wide
inventory of its key automated systems and related processes, analyzing and
assigning levels of criticality to those systems and processes, identifying and
prioritizing resource requirements, developing validation strategies and testing
plans, and evaluating business partner relationships. The assessment phase is
substantially complete. The assessment phase of the project, among other things,
involves efforts to obtain representations and assurances from third parties,
including third party vendors, that their hardware and equipment products,
embedded chip systems, and software products being used by or impacting the
Company are or will be modified to be Year 2000 compliant. Increasingly, the
responses from such third parties are generally encouraging. Nonetheless, many
of these responses lack the substantive detail to allow the Company to make a
meaningful evaluation of such third-parties' Year 2000 readiness. Furthermore,
in some circumstances, third parties are refusing to provide any response beyond
those contained in their publicly-disseminated information. As a result, the
overall evaluation of the Company's business partners' Year 2000 readiness
remains inconclusive. Accordingly, the Company cannot predict the potential
consequences if these or other third parties or their products are not Year 2000
compliant. The Company continues to evaluate the exposure associated with such
business partner relationships, and will use the contingency planning process to
attempt to mitigate the uncertainty concerning third-party readiness.
The remediation phase involves converting, modifying, replacing or
eliminating key automated systems identified in the assessment phase. The
testing phase involves the validation of the identified key automated systems.
The Company is utilizing test tools and written test procedures to document and
validate, as necessary, its unit, system, integration and acceptance testing.
The implementation phase involves placing the converted or replaced key
automated systems into operation. In October 1999, the Company, in cooperation
with other Interstate Natural Gas Association of America members, reported that
its regulated pipelines, El Paso Natural Gas Pipeline and Mojave Pipeline, will
be Year 2000 compliant on the rollover date
11
14
of January 1, 2000. The Company is substantially complete with its remediation,
testing and implementation phases for its systems.
The Company had previously identified the contingency planning phase as a
subset of the implementation phase, but has now established the process as its
own phase of the overall Year 2000 program. The contingency planning phase
consists of developing a risk profile of the Company's critical business
processes and then providing for actions the Company will pursue to keep such
processes operational in the event of Year 2000 disruptions. The focus of such
contingency planning is on prompt response to any Year 2000 events, and a plan
for subsequent resumption of normal operations. The plan attempts to assess the
risk of a significant failure to critical processes performed by the Company,
and to address the mitigation of those risks. The plan will also consider any
significant failures related to the most reasonably likely worst case scenario,
discussed below, as they may occur. In addition, the plan attempts to factor in
the severity and duration of the impact of a significant failure. The Company
has developed contingency plans for each business unit and significant business
process. By September 30, 1999, the Company had conducted desk-top testing of
its contingency plans and had conducted drills and mock outages, including some
testing with certain customers and other significant third parties. The Year
2000 contingency plans will continue to be tested, modified and adjusted
throughout the year as additional information becomes available.
The goal of the Year 2000 project is to ensure that all of the critical
systems and processes which are under the Company's direct control remain
functional. Certain systems and processes may be interrelated with or dependent
upon systems outside the Company's control. However, systems within the
Company's control may also have unpredicted problems. Accordingly, there can be
no assurance that significant disruptions will be avoided. The Company's present
analysis of its most reasonably likely worst case scenario for Year 2000
disruptions includes sporadic Year 2000 failures in the telecommunications and
electricity industries, as well as interruptions from suppliers that might cause
disruptions in the Company's operations, thus causing temporary financial losses
and an inability to deliver products and services to customers. Virtually all of
the natural gas transported through the Company's interstate pipelines is owned
by third parties. Accordingly, failures of natural gas producers to be ready for
the Year 2000 could significantly disrupt the flow of product to the Company's
customers. In many cases, the producers have no direct contractual relationship
with the Company, and the Company relies on its customers to verify the Year
2000 readiness of the producers from whom they purchase natural gas. Since most
of the Company's revenues from the delivery of natural gas are based upon fees
paid by its customers for the reservation of capacity, and not based upon the
volume of actual deliveries, short-term disruptions in deliveries caused by
factors beyond the Company's control should not have a significant financial
impact on the Company, although it could cause operational problems for the
Company's customers. Longer-term disruptions, however, could materially impact
the Company's results of operations, financial condition, and cash flows.
While the total cost of the Company's Year 2000 project continues to be
evaluated, the Company estimates that the costs remaining to be incurred in 1999
and 2000 associated with assessing, remediating and testing internally developed
computer applications, hardware and equipment, embedded chip systems, and
third-party-developed software will be $1 million. Of these estimated costs, the
Company expects $1 million to be capitalized. As of September 30, 1999, the
Company has incurred expenses of approximately $3 million and has capitalized
costs of approximately $1 million. The Company has previously only traced
incremental expenses related to its Year 2000 project. This means that the costs
of the Year 2000 project related to salaried employees of the Company, including
their direct salaries and benefits, are not available, and have not been
included in the estimated costs of the project. Since the earlier phases of the
project mostly involved work performed by such salaried employees, the costs
expended to date do not reflect the percentage completion of the project. The
Company anticipates that it will expend a substantial amount of the remaining
costs in the contingency planning phase of the project, including the potential
acquisition of back-up assets and systems that may be deployed in the event
primary systems fail to perform fully according to expectations.
Although the Company does not expect the costs of its Year 2000 project to
have a material adverse effect on its financial position, results of operations,
or cash flows, based on information available at this time the Company cannot
conclude that disruption caused by internal or external Year 2000 related
failures will not have such an effect. Specific factors which might affect the
success of the Company's Year 2000 efforts and
12
15
the frequency or severity of a Year 2000 disruption or the amount of expense
include the failure of the Company or its outside consultants to properly
identify deficient systems, the failure of the selected remedial action to
adequately address the deficiencies, the failure of the Company or its outside
consultants to complete the remediation in a timely manner (due to shortages of
qualified labor or other factors), the failure of other parties to joint
ventures in which the Company is involved to meet their obligations, both
financial and operational, under the relevant joint venture agreements to
remediate assets used by the joint venture, unforeseen expenses related to the
remediation of existing systems or the transition to replacement systems, the
failure of third parties to become Year 2000 compliant or to adequately notify
the Company of potential noncompliance and the effects of any significant
disruption at international facilities in which the Company has significant
investments.
The above disclosure is a "YEAR 2000 READINESS DISCLOSURE" made with the
intention to comply fully with the Year 2000 Information and Readiness
Disclosure Act of 1998, Pub. L. No. 105-271, 112 Stat, 2386, signed into law
October 19, 1998. All statements made herein shall be construed within the
confines of that Act. To the extent that any reader of the above Year 2000
Readiness Disclosure is other than an investor or potential investor in the
Company's -- or an affiliate's -- equity or debt securities, this disclosure is
made for the SOLE PURPOSE of communicating or disclosing information aimed at
correcting, helping to correct and/or avoiding Year 2000 failures.
13
16
CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995.
This report contains forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995. Where any such forward-looking
statement includes a statement of the assumptions or bases underlying such
forward-looking statement, the Company cautions that, while such assumptions or
bases are believed to be reasonable and are 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, the Company or its
management expresses an expectation or belief as to future results, such
expectation or belief is expressed in good faith and is believed to have a
reasonable basis, but there can be no assurance that the statement of
expectation or belief will result or be achieved or accomplished. The words
"believe," "expect," "estimate," "anticipate" and similar expressions may
identify forward-looking statements.
Important factors that could cause actual results to differ materially from
those in the forward-looking statements herein include increasing competition
within the Company's industry, the timing and extent of changes in commodity
prices for natural gas and power, uncertainties associated with customer
contract expirations on the EPNG pipeline system, uncertainties associated with
acquisitions and joint ventures, potential environmental liabilities, potential
contingent liabilities and tax liabilities related to the Company's
acquisitions, political and economic risks associated with current and future
operations in foreign countries, conditions of the equity and other capital
markets during the periods covered by the forward-looking statements, and other
risks, uncertainties and factors, including the effect of the Year 2000 date
change, discussed more completely in the Company's other filings with the U.S.
Securities and Exchange Commission, including its Annual Report on Form 10-K for
the year ended December 31, 1998.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information contained in Item 3 updates, and should be read in
conjunction with, information set forth in Part II, Item 7A in the Company's
Annual Report on Form 10-K for the year ended December 31, 1998, in addition to
the interim consolidated financial statements, accompanying notes, and
Management's Discussion and Analysis of Financial Condition and Results of
Operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q.
There are no material changes in market risks faced by the Company from
those reported in the Company's Annual Report on Form 10-K for the year ended
December 31, 1998.
14
17
PART II -- OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Part I, Financial Information, Note 3, which is incorporated herein by
reference.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS
None.
ITEM 5. OTHER INFORMATION
None.
ITEM. 6. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits
Each exhibit identified below is filed as a part of this report.
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.A -- $1,250,000,000 364-Day Revolving Credit and Competitive
Advance Facility Agreement dated as of August 16, 1999,
by and among EPEC, EPNG, TGP, the several banks and other
financial institutions from time to time parties to the
Agreement, The Chase Manhattan Bank, as administrative
agent and as CAF Advance Agent for the Lenders
thereunder, Citibank N.A. and ABN Amro Bank, N.V. as
co-documentation agents for the Lenders and Bank of
America, N.A. as syndication agent for the Lenders.
27 -- Financial Data Schedule
Undertaking
The undersigned hereby undertakes, pursuant to Regulation S-K, Item
601(b), paragraph (4)(iii), to furnish to the U.S. Securities and Exchange
Commission, upon request, all constituent instruments defining the rights
of holders of long-term debt of EPNG and its consolidated subsidiaries not
filed herewith for the reason that the total amount of securities
authorized under any of such instruments does not exceed 10 percent of the
total consolidated assets of EPNG and its consolidated subsidiaries.
b. Reports on Form 8-K
None
15
18
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: November 12, 1999 /s/ H. BRENT AUSTIN
------------------------------------
H. Brent Austin
Executive Vice President and
Chief Financial Officer
Date: November 12, 1999 /s/ JEFFREY I. BEASON
------------------------------------
Jeffrey I. Beason
Senior Vice President and Controller
(Chief Accounting Officer)
16
19
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.A -- $1,250,000,000 364-Day Revolving Credit and Competitive
Advance Facility Agreement dated as of August 16, 1999,
by and among EPEC, EPNG, TGP, the several banks and other
financial institutions from time to time parties to the
Agreement, The Chase Manhattan Bank, as administrative
agent and as CAF Advance Agent for the Lenders
thereunder, Citibank N.A. and ABN Amro Bank, N.V. as
co-documentation agents for the Lenders and Bank of
America, N.A. as syndication agent for the Lenders.
27 -- Financial Data Schedule