<PAGE> 1
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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, 1995
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
(State or Other Jurisdiction 74-0608280
of Incorporation or Organization) (I.R.S. Employer Identification No.)
ONE PAUL KAYSER CENTER,
100 NORTH STANTON STREET, EL PASO, TEXAS 79901
(Address of Principal Executive Offices) (Zip Code)
Registrant's Telephone Number, Including Area Code (915) 541-2600
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.
CLASS OUTSTANDING
---------------------------------------- -------------------
Common Stock, par value $3.00 per share,
as of July 17, 1995 34,116,941 shares
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<PAGE> 2
PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENT OF INCOME
(IN THOUSANDS, EXCEPT PER COMMON SHARE AMOUNTS)
(UNAUDITED)
<TABLE>
<CAPTION>
SECOND QUARTER SIX MONTHS
-------------------- --------------------
1995 1994 1995 1994
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Operating revenues................................. $185,150 $210,805 $389,281 $432,750
-------- -------- -------- --------
Operating charges
Operation and maintenance........................ 74,320 75,243 151,686 145,083
Natural gas and liquids.......................... 30,629 50,411 73,854 113,371
Depreciation, depletion, and amortization........ 17,444 16,156 34,249 32,385
Litigation special charge........................ -- -- -- 15,062
Taxes, other than income taxes................... 9,900 9,397 20,422 19,454
-------- -------- -------- --------
132,293 151,207 280,211 325,355
-------- -------- -------- --------
Operating income................................... 52,857 59,598 109,070 107,395
-------- -------- -------- --------
Other (income) and income deductions
Interest and debt expense........................ 21,098 19,407 42,164 39,122
Other -- net..................................... (1,430) (31) (2,808) (6,655)
-------- -------- -------- --------
19,668 19,376 39,356 32,467
-------- -------- -------- --------
Income before income taxes......................... 33,189 40,222 69,714 74,928
Income taxes....................................... 12,989 16,211 27,544 29,802
-------- -------- -------- --------
Net income......................................... $ 20,200 $ 24,011 $ 42,170 $ 45,126
======== ======== ======== ========
Earnings per common share.......................... $ .58 $ 0.65 $ 1.21 $ 1.22
======== ======== ======== ========
Average common shares outstanding.................. 34,798 36,835 34,976 36,864
======== ======== ======== ========
Dividends declared per common share................ $ 0.3300 $ 0.3025 $ 0.6600 $ 0.6050
======== ======== ======== ========
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of this statement.
1
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EL PASO NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEET
(IN THOUSANDS, EXCEPT PER SHARE AMOUNT)
ASSETS
<TABLE>
<CAPTION>
JUNE 30,
1995 DECEMBER 31,
(UNAUDITED) 1994
----------- -----------
<S> <C> <C>
Current assets
Cash and temporary investments................................... $ 13,836 $ 27,636
Accounts and notes receivable, net............................... 93,739 131,650
Materials and supplies inventory................................. 34,775 34,666
Take-or-pay buy-outs, buy-downs, and prepayments, net............ 26,482 33,356
Other regulatory assets.......................................... 12,000 12,000
Deferred income tax benefit...................................... 36,630 41,257
Other............................................................ 23,868 18,594
----------- -----------
Total current assets..................................... 241,330 299,159
----------- -----------
Property, plant, and equipment, net................................ 1,882,362 1,865,897
Take-or-pay buy-outs, buy-downs, and prepayments, net.............. 1,016 14,502
Other regulatory assets............................................ 53,892 59,021
Other.............................................................. 87,082 93,192
----------- -----------
2,024,352 2,032,612
----------- -----------
Total assets............................................. $ 2,265,682 $ 2,331,771
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable................................................. $ 160,051 $ 229,356
Commercial paper................................................. 144,200 106,800
Take-or-pay financing liability.................................. 17,000 36,700
Current maturities on long-term debt............................. 7,171 6,824
Other............................................................ 67,969 72,375
----------- -----------
Total current liabilities................................ 396,391 452,055
----------- -----------
Long-term debt, less current maturities............................ 775,494 779,097
Deferred income taxes, less current portion........................ 317,794 304,918
Deferred credits................................................... 38,894 40,325
Other.............................................................. 45,678 45,740
----------- -----------
1,177,860 1,170,080
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Commitments and contingent liabilities (See Notes 2, 3, 4, and 5)
Stockholders' equity
Common stock, par value $3 per share; authorized 100,000 shares;
issued 37,351 shares.......................................... 112,054 112,053
Additional paid-in capital....................................... 454,713 454,705
Retained earnings................................................ 221,509 202,558
Less: Treasury stock (at cost) of 3,080 and 1,799 shares......... 96,845 59,680
----------- -----------
Total stockholders' equity............................... 691,431 709,636
----------- -----------
Total liabilities and stockholders' equity............... $ 2,265,682 $ 2,331,771
=========== ===========
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of this statement.
2
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EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
SIX MONTHS
-------------------------
1995 1994
-------- --------
<S> <C> <C>
Cash flows from operating activities
Net income....................................................... $ 42,170 $ 45,126
Adjustments to reconcile net income to net cash provided by
operating activities
Depreciation, depletion, and amortization..................... 34,249 32,385
Deferred income taxes......................................... 17,689 16,094
Net take-or-pay recoveries.................................... 20,360 15,983
Other working capital changes
Accounts and notes receivable............................... 37,911 23,590
Materials and supplies inventory............................ (109) (398)
Other current assets........................................ (5,009) 6,258
Accounts payable............................................ (69,124) (6,320)
Other current liabilities................................... (5,211) (1,363)
Other......................................................... 8,390 (12,297)
-------- --------
Net cash provided by operating activities................ 81,316 119,058
-------- --------
Cash flows from investing activities
Capital expenditures............................................. (51,738) (40,572)
Proceeds from disposal of property............................... 2,184 2,004
Other............................................................ (3,693) (5,301)
-------- --------
Net cash used in investing activities.................... (53,247) (43,869)
-------- --------
Cash flows from financing activities
Long-term debt retirements....................................... (3,667) (3,010)
Net commercial paper borrowings (repayments)..................... 37,400 (1,300)
Repayment of volumetric take-or-pay receivable................... (19,700) (21,908)
Acquisition of treasury stock.................................... (37,313) (4,738)
Dividends paid................................................... (22,424) (21,299)
Other............................................................ 3,835 1,204
-------- --------
Net cash used in financing activities.................... (41,869) (51,051)
-------- --------
Increase (decrease) in cash and temporary investments.............. (13,800) 24,138
Cash and temporary investments
Beginning of period...................................... 27,636 --
-------- --------
End of period............................................ $ 13,836 $ 24,138
======== ========
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of this statement.
3
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EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. BASIS OF PRESENTATION
The 1994 Annual Report on Form 10-K for El Paso Natural Gas Company and
subsidiaries includes a summary of significant accounting policies and should be
read in conjunction with this Form 10-Q. As used herein, the "Company" refers to
El Paso Natural Gas Company and its subsidiaries, and "EPG" refers to El Paso
Natural Gas Company, unless the context otherwise requires. The condensed
consolidated financial statements at June 30, 1995, and the quarter then ended
are unaudited, and the condensed balance sheet at December 31, 1994, is derived
from audited financial statements. These financial statements do not include all
disclosures required by generally accepted accounting principles. 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 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.
Financial statements for the previous periods include certain reclassifications
which were made to conform to current presentation. Such reclassifications have
no effect on reported net income or stockholders' equity.
2. RATES AND REGULATORY MATTERS
In June 1995, EPG made a filing with the Federal Energy Regulatory
Commission ("FERC") for approval of new system rates for mainline transportation
to be effective January 1, 1996. If the rates are approved as filed, annual
revenues would increase by approximately $137 million. FERC must act on EPG's
filing within 30 days.
Consistent with FERC precedent, EPG will allocate its cost-of-service to
the customers served as of January 1, 1996. In addition, EPG has included in its
filing an alternative tariff exit fee mechanism designed to mitigate cost shifts
which may result from future capacity relinquishments. This mechanism would
apply to certain contract reductions or terminations occurring after the
mechanism is approved by FERC. The exit fee mechanism will require certain
payments to EPG which would be appropriately reflected in EPG's rates.
Pacific Gas & Electric ("PG&E") has a contract for 1,140 million cubic feet
per day ("MMcf/d") of firm capacity rights on EPG's system with a primary term
ending December 31, 1997. EPG's reservation revenues from PG&E during 1994 were
approximately $129 million. In June 1995, PG&E notified EPG that it intends to
terminate the contract as of December 31, 1997. PG&E did not preclude the
possibility of continued service from EPG after that date pursuant to a new
agreement. EPG intends to pursue negotiations with PG&E but cannot determine the
outcome at this time. In addition, Southern California Gas Company ("SoCal") has
exercised a right to reduce its firm capacity on EPG's system by 300 MMcf/d
effective January 1, 1996.
If EPG's exit fee mechanism is approved on a timely basis, it would apply
to PG&E's proposed contract termination. In the event the exit fee mechanism is
not approved, and in the absence of other approved procedures, EPG will allocate
its total mainline transportation cost-of-service to the customers served
following the termination of the PG&E contract. EPG cannot predict the impact of
FERC's ultimate decision on these matters.
EPG will seek to offset any reduction in existing firm capacity commitments
and related revenues resulting from customer contract terminations, reductions,
or modifications through new contracts with various natural gas users in
California, East-of-California, and northern Mexico markets. EPG's efforts to
seek new customers in California for such capacity at full tariff rates will be
adversely impacted by the current excess interstate pipeline capacity to
California, which excess is estimated to continue into the next decade.
EPG has made buy-out and buy-down payments and recoupable prepayments to
resolve past and future take-or-pay exposure, to terminate and reform gas
purchase contracts, to amend pricing and take provisions of gas purchase
contracts, and to settle related litigation. EPG is collecting its buy-out and
buy-down costs under
4
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EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FERC cost recovery procedures. The collection period for such costs extends
through March 1996. EPG has established a reserve, based on throughput
projections, for that portion of the receivables balance which is unlikely to be
collected over the period through March 1996. The balances of this reserve were
$6 million and $9 million at June 30, 1995, and December 31, 1994, respectively.
Under FERC procedures, take-or-pay cost recovery filings may be challenged
by pipeline customers on prudence and certain other grounds. In October 1992,
FERC issued an order resolving all but one of the outstanding issues regarding
EPG's take-or-pay proceedings. Certain of EPG's customers sought review of
certain aspects of that order in the United States Court of Appeals for the
District of Columbia Circuit (the "Court of Appeals"). That appeal is currently
pending. The remaining issue unresolved by FERC involved the claim by several
customers that EPG sought to recover an excessive amount for the value of
certain production properties which were transferred to a producer as part of a
1989 take-or-pay settlement. Following a hearing on this issue, in June 1994,
FERC affirmed a decision of an Administrative Law Judge ("ALJ") which found that
the valuation proposed by EPG was excessive and required EPG to refund to its
customers the costs found to be ineligible for take-or-pay recovery. In
accordance with the FERC decision, EPG refunded $34 million, inclusive of
interest, to its customers in September 1994. In December 1994, EPG filed a
petition with the Court of Appeals for review of the FERC decision, which is
currently pending.
Mojave Pipeline Company ("MPC") filed a service and rate design
restructuring plan in November 1992 in compliance with the industry-wide
restructuring directives of FERC. In March 1993, FERC issued an order
essentially approving MPC's compliance filing, subject to changes, which were
made in an amended restructuring plan in March 1993.
Several of MPC's customers have filed petitions with the Court of Appeals
for review of the March 1993 order and certain other FERC orders. These
petitions are currently pending before the Court of Appeals. The primary issues
on appeal pertain to FERC's requirement that MPC's rates for firm transportation
service be based upon Straight Fixed Variable ("SFV") rate design rather than
Modified Fixed Variable ("MFV") rate design. The application of SFV requires
MPC's existing firm shippers to pay a higher proportion of their total
transportation rate in the reservation component of the rate. Such shippers have
contended that FERC's application of SFV rate design to MPC unlawfully abrogates
the rate provisions of MPC's service agreements and constitutes an unlawful rate
increase. Management believes the Court of Appeals will uphold SFV rates as
applied to MPC.
In February 1995, MPC made a filing with FERC seeking authorization to
maintain its existing rates. In March 1995, FERC accepted the filing,
established hearing procedures to determine the justness and reasonableness of
the rates proposed by MPC, and allowed those rates to become effective as of
March 30, 1995, subject to refund. An evidentiary hearing on issues relating to
MPC's rate filing has been scheduled for February 1996.
3. LEGAL PROCEEDINGS
In El Paso Natural Gas Company and Meridian Oil Gathering Inc. v. Amoco
Production Company, filed in Delaware Chancery Court ("the Court") on May 8,
1991, Amoco Production Company ("Amoco") alleged breaches by EPG and a then
affiliated company, Meridian Oil Gathering Inc. ("MOGI"), of certain gas
purchase, gathering, and transportation agreements pertaining to natural gas
produced by Amoco in the San Juan Basin. Amoco alleged breach of "favored
nations" contractual provisions regarding services to be performed by EPG,
including those relating to transportation capacity and rates. Amoco sought a
court order requiring specific performance by EPG and MOGI with respect to
future transportation services and an award of monetary damages of an
undetermined amount for alleged past breaches of contract. On March 4, 1992, the
Court issued a Memorandum Opinion which, among other things, denied Amoco's
motion for partial summary judgment and concluded that the Amoco contracts at
issue do not contain the broad
5
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EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
"favored nations" rights claimed by Amoco. The Court further concluded that
MOGI's motion for summary judgment, seeking dismissal of Amoco's counterclaim
against MOGI, should be granted. Conoco Inc. ("Conoco") asserted claims similar
to Amoco's original claims, involving lesser quantities of gas, in a separate
Delaware Chancery Court proceeding filed on December 30, 1991, Conoco Inc. v. El
Paso Natural Gas Company. In August 1992, the Amoco and Conoco cases were
consolidated, MOGI was dismissed as a party, and Amoco and Conoco filed amended
pleadings to restate their claims in light of the court's March 4, 1992, ruling.
EPG and Conoco concluded a settlement agreement which resulted in dismissal of
the Conoco claims. Trial of the Amoco claims concluded on July 15, 1993, and
post-trial briefing and oral arguments concluded in early November 1993. On
March 29, 1994, the Court rendered a decision in favor of Amoco. After
additional briefing, the Court issued its opinion respecting certain contested
damages issues on December 16, 1994, and entered a final order on January 30,
1995. As a result of the Court's decision, EPG refunded to Amoco approximately
$20 million in the first quarter of 1995. Both EPG and Amoco have filed appeals
with the Delaware Supreme Court; however, both parties are pursuing settlement
negotiations.
TransAmerican Natural Gas Corporation ("TransAmerican") has filed a
complaint in a Texas state court against various parties, including EPG,
alleging fraud, tortious interference with contractual relationships, economic
duress, civil conspiracy, and violation of state antitrust laws. The complaint,
as amended, seeks unspecified actual and exemplary damages. EPG is actively
defending the matter and has initiated collateral proceedings challenging both
the validity of TransAmerican's claims and the jurisdiction of the forum in
which they were filed. No discovery has been commenced pending resolution of
these threshold issues. Based on information available at this time, management
believes that the claims made by TransAmerican have no factual or legal basis
and that the ultimate resolution of this matter will not have a materially
adverse effect on the Company's financial condition.
The United States Department of Justice (the "Justice Department")
terminated an investigation of EPG's natural gas meter sales and installation
practices in the San Juan Basin on January 6, 1995. EPG and the Justice
Department agreed to a consent decree which was filed in the United States
District Court for the District of Columbia (the "District Court") on January
12, 1995. The consent decree requires no material change to EPG's existing
business practices and imposes no fines or monetary penalties. The consent
decree stipulates that EPG may not require a well operator to purchase meter
facilities or meter installation equipment as a condition of access to its
gathering system in the San Juan Basin, and requires EPG to inform well
operators that they have the legal right to provide their own meter installation
services. The consent decree further provides that any meter installation
undertaken by third parties must be done in accordance with environmental and
safety standards specified by EPG. Moreover, EPG has the right to inspect such
installations to ensure that they conform to standards that apply uniformly on
EPG's gathering system. Records of EPG's inspection activities will be
maintained to document compliance with EPG's standards and procedures. A
required 60-day public comment period concerning the consent decree expired on
March 27, 1995. On April 24, 1995, the Justice Department filed with the
District Court a motion for entry of final judgment, which states that no
comments were received with respect to the proposed final judgment. Action by
the District Court is pending.
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 against the Company
cannot be predicted with certainty, management does not expect these matters to
have a materially adverse effect on the Company's financial condition.
6
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EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
4. ENVIRONMENTAL
As of June 30, 1995, EPG had a reserve of approximately $40 million for the
following environmental contingencies with income statement impact:
1 -- EPG has been conducting remediation of polychlorinated biphenyl
("PCB") contamination at certain of its facilities. The majority of the
required PCB remediation has been completed. Future costs are estimated to
range between $7 million and $11 million over the next 5 years.
2 -- EPG executed an Administrative Order on Consent with the United States
Environmental Protection Agency ("EPA") in June 1993 to conduct a Remedial
Investigation/Feasibility Study ("RI/FS") for a site located in
Statesville, North Carolina that has been identified for cleanup. EPG and
other Potentially Responsible Parties ("PRP") have entered into an
agreement to jointly fund the RI/FS for the site. Total remediation costs
are estimated to be between $17 million and $29 million over a 30 year
period. EPG and the other PRP are engaged in negotiations over the
appropriate allocation of the remediation costs.
3 -- In November 1993, in accordance with an EPA order, EPG and Atlantic
Richfield Company ("ARCO") submitted work plans for remediation of the
subsurface at the Prewitt Refinery in McKinley County, New Mexico. EPG and
ARCO have a cost sharing agreement to each pay one-half of any remediation
costs at this site. EPG's share of the remediation costs is estimated to be
between $10 million and $20 million over a 30 year period. Remediation of
the surface began in May of 1995.
4 -- In December 1993, EPA issued EPG a Notice of Liability for the
Colorado School of Mines Research Institute (the "CSMRI") site in Golden,
Colorado. EPA has determined that the volume of hazardous substances sent
to the site by EPG represent less than 2.5 percent of the total volumes
sent by all PRP. Based on this percentage, EPG's share of the potential
remediation costs is estimated to be less than $500,000.
5 -- EPG and other PRP have been notified about potential groundwater and
soil contamination at various sites in southeastern Utah. EPG and other PRP
have been conducting environmental assessments at certain of these sites
and are engaged in negotiations over the appropriate allocation of the
remediation costs. Based upon currently available information, EPG
estimates its costs for remediation will be approximately $4 million.
However, costs could be higher once the environmental assessment has been
completed.
6 -- In August 1992, EPG received a notice from the current owner of a site
in Etowah, Tennessee requesting compensation for remediation expenses
associated with the site. These costs are estimated to be approximately
$1.7 million. EPG and the other PRP are finalizing negotiations over the
appropriate allocation of the alleged costs. EPG's share of the remediation
costs is estimated to be less than $1 million.
7 -- EPG and other PRP entered into an agreement to conduct a RI/FS for a
site located in Fountain Inn, South Carolina. The RI/FS was completed in
October 1994, and EPA issued their proposed plan for the site in November
1994. The proposed remediation and EPA oversight costs are estimated to be
$800,000. The allocation of these costs between EPG and the other PRP is
currently being negotiated. EPG's share of the costs is estimated to be
between $300,000 and $500,000 over a 5 year period.
Management believes the amount reserved as of June 30, 1995, is sufficient
to cover these and other small environmental assessments and remediation
activities.
The State of Tennessee has asserted a claim that EPG is a liable party
under state environmental laws for cleanup costs associated with a site in
Elizabethton, Tennessee. The State and EPA are in the preliminary
7
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EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
stages of investigating the nature and extent of contamination, as well as
identifying other PRP. Since testing is in the initial stages, EPG is unable to
estimate its potential share of any remediation costs.
EPG also has potential expenditures, of a capital nature, for the following
environmental projects:
1 -- EPG has analyzed the Clean Air Act Amendments of 1990 ("CAAA") and
believes that these rules will impact the Company's operations primarily in
the following areas: (i) potential required reductions in the emissions of
nitrogen oxides ("NOx") in non-attainment areas; (ii) the requirement for
air emissions permitting of existing facilities; and (iii) enhanced
monitoring of air emissions. EPG anticipates capitalizing the equipment
costs associated with complying with CAAA and estimates that approximately
$10 million will be spent from 1995 through 2005. However, EPA's proposed
enhanced monitoring rules, when finalized, could potentially impose greater
costs to the Company.
2 -- EPG has been conducting remediation of mercury contamination at
certain facilities and is replacing mercury containing meters with other
measurement devices. The total cost of the project is estimated to be
approximately $11 million. The project is expected to be completed by the
end of 1995. EPG will close and retire about 2,000 earthen
siphon/dehydration pits in the San Juan Basin, as required by certain
environmental regulations, at a cost of approximately $6 million. The
mercury remediation and pit closure costs, which are associated with the
retirement of equipment, will be recorded as adjustments to accumulated
depreciation, as permitted by regulatory accounting principles.
It is possible that new information or future developments could require
the Company to reassess its potential exposure related to environmental matters.
As such information or developments occur, related accrual amounts will be
adjusted accordingly.
5. FINANCING TRANSACTIONS
In August 1994, EPG established with a group of banks a revolving credit
facility of $400 million that expires in 5 years. As of June 30, 1995, and
December 31, 1994, there were no borrowings outstanding under this facility. As
of June 30, 1995, and December 31, 1994, approximately $144 million and $107
million, respectively, of commercial paper were outstanding.
EPG filed a shelf registration statement in August 1994, pursuant to which
EPG may offer up to $400 million of unsecured debt securities, preferred stock,
and common stock from time to time as determined by market conditions. On March
10, 1995, the registration statement was declared effective by the Securities
and Exchange Commission (the "SEC"). As of June 30, 1995, EPG had not issued any
securities pursuant to the shelf registration statement.
In February 1995, El Paso New Chaco Company ("EPNC"), a wholly owned
subsidiary of EPG, entered into a 7.75 year lease for a plant which is being
constructed in the San Juan Basin. The lease is an unconditional "triple net"
lease with the trustee of a special purpose trust. The trust obtains financing
for construction of the plant from a consortium of financial institutions. The
total amount financed via the operating lease will not exceed $80 million, and
the annual lease obligation will be a function of the amount financed, a
variable interest rate, and commitment and other fees. EPNC has an option at the
end of the lease term, and has an obligation upon the occurrence of certain
events, to purchase the plant for a price sufficient to pay the entire amount
financed, interest, and certain expenses. If EPNC does not purchase the plant at
the end of the lease term, it has an obligation to pay a residual guaranty
amount equal to approximately 87 percent of the amount financed, plus interest.
EPG unconditionally guaranteed all obligations of EPNC under the lease.
Construction of the plant began in April 1995, and it is expected to be in
service by early 1996.
8
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EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
6. ACCOUNTING FOR REGULATED OPERATIONS
EPG and MPC are subject to the regulations and accounting procedures of
FERC and therefore, continue to follow the reporting and accounting requirements
of Statement of Financial Accounting Standards ("SFAS") No. 71 Accounting for
the Effects of Certain Types of Regulation. Accounting methods for companies
subject to cost-of-service regulation may differ from those used by
non-regulated companies. However, when the accounting method prescribed by the
regulatory authority is used for rate-making, such accounting conforms to the
generally accepted accounting principle of matching costs against the revenues
to which they apply.
While management believes that EPG and MPC remain "regulated" as the term
is used in the relevant accounting literature, various applications have been
filed with FERC, such as EPG's application to terminate certificates applicable
to certain gathering and processing facilities, which may, at some point in the
future, create circumstances in which application of regulatory accounting
principles is no longer appropriate. The Consolidated Balance Sheet contains
assets and liabilities related to operations which have been recorded pursuant
to regulatory accounting principles. If these accounting principles should no
longer be applied, an amount would be charged to earnings as an extraordinary
item. At June 30, 1995, this amount was estimated to be approximately $56
million, net of income taxes. Management continues to monitor the impact changes
in the regulatory and economic environment may have on the application of these
regulatory accounting principles. Any potential charge would be non-cash and
would have no direct effect on EPG's and MPC's ability to include the underlying
deferred costs in their future rate proceedings or on their ability to collect
the rates set thereby.
7. PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment at June 30, 1995, and December 31, 1994,
consisted of the following:
<TABLE>
<CAPTION>
1995 1994
---------- ----------
(IN THOUSANDS)
<S> <C> <C>
Property, plant, and equipment, at cost..................... $3,000,263 $2,979,368
Less accumulated depreciation and depletion................. 1,214,201 1,212,477
---------- ----------
1,786,062 1,766,891
Additional acquisition cost assigned to utility plant,
net of accumulated amortization........................... 96,300 99,006
---------- ----------
Property, plant, and equipment, net............... $1,882,362 $1,865,897
========= =========
</TABLE>
8. SUPPLEMENTAL DISCLOSURE OF CASH FLOW ACTIVITIES
<TABLE>
<CAPTION>
SIX MONTHS
-------------------
1995 1994
------- -------
<S> <C> <C>
(IN THOUSANDS)
Net cash payments
Interest....................................................... $39,420 $34,717
Income taxes................................................... 9,314 35,343
</TABLE>
9
<PAGE> 11
EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. RECENT PRONOUNCEMENTS
In March 1995, the Financial Accounting Standards Board issued SFAS No. 121
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of. SFAS No. 121 requires that long-lived assets and certain
identifiable intangibles to be held and used by an entity be reviewed for
impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. Certain long-lived assets
and certain identifiable intangibles to be disposed of must be reported at the
lower of carrying amount or fair value less cost to sell. SFAS No. 121 also
requires that a rate-regulated enterprise recognize an impairment for the amount
of costs that a regulator excludes from the enterprise's rate base. SFAS No. 121
is effective for the fiscal years beginning after December 15, 1995. The Company
is in the process of evaluating the implications of SFAS No. 121.
10
<PAGE> 12
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY
Net cash provided by operating activities was $81 million for the six
months ended June 30, 1995, compared with $119 million for the same period of
1994. The decrease from the previous year was primarily due to a payment
resulting from the Amoco decision, 1994 net insurance reimbursements, timing of
insurance premium payments, higher interest payments, and timing differences in
other working capital disbursements. The decrease was partially offset by lower
tax payments, lower take-or-pay payments, and timing differences in other
working capital receipts.
Rates and Regulatory Matters
In January 1994, EPG filed an application with FERC seeking an order which
would terminate, effective January 1, 1996, certificates applicable to certain
gathering and processing facilities owned by EPG on the basis that such
facilities are not subject to FERC jurisdiction.
EPG intends, effective January 1, 1996, to transfer the facilities subject
to the January 1994 application together with its nonjurisdictional gathering
and processing facilities to El Paso Field Services Company, a wholly owned
subsidiary of EPG. Such facilities are used for gathering and other
nonjurisdictional functions and are an inherent part of EPG's current gathering
and processing operations. The facilities to be transferred consist of
approximately 6,700 miles of various sized pipelines, compressors with an
aggregate installed horsepower of 40,600, and various treating and processing
plants.
Several producers and other shippers filed protests and requests for a
formal hearing of the January 1994 application. The primary issues raised in the
protests focus on the extent of competition in EPG's producing basins and the
proper functionalization of its facilities. In response to the producer and
shipper protests, EPG made a filing in March 1994 asserting that the protests
raised issues already settled under EPG's 1993 settlement agreement.
Beginning in May 1994, FERC issued a series of orders which clarified its
policy regarding the regulation of gathering facilities. Under the policy
announced in these orders, FERC will have no authority to regulate the rates,
terms, and conditions that apply to service through gathering facilities owned
by an affiliate of a pipeline, except where the gatherer acts in concert with
its pipeline affiliate to frustrate FERC's effective regulation over interstate
transportation services. FERC has stated it will evaluate applications to
deregulate gathering and processing facilities on a case by case basis, and
management believes EPG's January 1994 application will be approved.
In June 1995, EPG made a filing with FERC for approval of new system rates
for mainline transportation to be effective January 1, 1996. If the rates are
approved as filed, annual revenues would increase by approximately $137 million.
FERC must act on EPG's filing within 30 days.
Consistent with FERC precedent, EPG will allocate its cost-of-service to
the customers served as of January 1, 1996. In addition, EPG has included in its
filing an alternative tariff exit fee mechanism designed to mitigate cost shifts
which may result from future capacity relinquishments. This mechanism would
apply to certain contract reductions or terminations occurring after the
mechanism is approved by FERC. The exit fee mechanism will require certain
payments to EPG which would be appropriately reflected in EPG's rates.
PG&E has a contract for 1,140 MMcf/d of firm capacity rights on EPG's
system with a primary term ending December 31, 1997. EPG's reservation revenues
from PG&E during 1994 were approximately $129 million. In June 1995, PG&E
notified EPG that it intends to terminate the contract as of December 31, 1997.
PG&E did not preclude the possibility of continued service from EPG after that
date pursuant to a new agreement. EPG intends to pursue negotiations with PG&E
but cannot determine the outcome at this time. In addition, SoCal has exercised
a right to reduce its firm capacity on EPG's system by 300 MMcf/d effective
January 1, 1996.
If EPG's exit fee mechanism is approved on a timely basis, it would apply
to PG&E's proposed contract termination. In the event the exit fee mechanism is
not approved, and in the absence of other approved
11
<PAGE> 13
procedures, EPG will allocate its total mainline transportation cost-of-service
to the customers served following the termination of the PG&E contract. EPG
cannot predict the impact of FERC's ultimate decision on these matters.
EPG will seek to offset any reduction in existing firm capacity commitments
and related revenues resulting from customer contract terminations, reductions,
or modifications through new contracts with various natural gas users in
California, East-of-California, and northern Mexico markets. EPG's efforts to
seek new customers in California for such capacity at full tariff rates will be
adversely impacted by the current excess interstate pipeline capacity to
California, which excess is estimated to continue into the next decade.
Under FERC procedures, take-or-pay cost recovery filings may be challenged
by pipeline customers on prudence and certain other grounds. In October 1992,
FERC issued an order resolving all but one of the outstanding issues regarding
EPG's take-or-pay proceedings. Certain of EPG's customers sought review of
certain aspects of that order in the Court of Appeals. That appeal is currently
pending. The remaining issue unresolved by FERC involved the claim by several
customers that EPG sought to recover an excessive amount for the value of
certain production properties which were transferred to a producer as part of a
1989 take-or-pay settlement. Following a hearing on this issue, in June 1994,
FERC affirmed a decision of an ALJ which found that the valuation proposed by
EPG was excessive and required EPG to refund to its customers the costs found to
be ineligible for take-or-pay recovery. In accordance with the FERC decision,
EPG refunded $34 million, inclusive of interest, to its customers in September
1994. In December 1994, EPG filed a petition with the Court of Appeals for
review of the FERC decision, which is currently pending.
MPC filed a service and rate design restructuring plan in November 1992 in
compliance with FERC's industry-wide restructuring directives. In March 1993,
FERC issued an order essentially approving MPC's compliance filing, subject to
changes, which were made in an amended restructuring plan in March 1993.
Several of MPC's customers have filed petitions with the Court of Appeals
for review of the March 1993 order and certain other FERC orders. These
petitions are currently pending before the Court of Appeals. The primary issues
on appeal pertain to FERC's requirement that MPC's rates for firm transportation
service be based upon SFV rate design rather than MFV rate design. The
application of SFV requires MPC's existing firm shippers to pay a higher
proportion of their total transportation rate in the reservation component of
the rate. Such shippers have contended that FERC's application of SFV rate
design to MPC unlawfully abrogates the rate provisions of MPC's service
agreements and constitutes an unlawful rate increase. Management believes the
Court of Appeals will uphold SFV rates as applied to MPC.
In February 1995, MPC made a filing with FERC seeking authorization to
maintain its existing rates. In March 1995, FERC accepted the filing,
established hearing procedures to determine the justness and reasonableness of
the rates proposed by MPC, and allowed those rates to become effective as of
March 30, 1995, subject to refund. An evidentiary hearing on issues relating to
MPC's rate filing has been scheduled for February 1996.
Accounting For Regulated Operations
EPG and MPC are subject to the regulations and accounting procedures of
FERC and therefore, continue to follow the reporting and accounting requirements
of SFAS No. 71 Accounting for the Effects of Certain Types of Regulation.
Accounting methods for companies subject to cost-of-service regulation may
differ from those used by non-regulated companies. However, when the accounting
method prescribed by the regulatory authority is used for rate-making, such
accounting conforms to the generally accepted accounting principle of matching
costs against the revenues to which they apply.
While management believes that EPG and MPC remain "regulated" as the term
is used in the relevant accounting literature, various applications have been
filed with FERC, such as EPG's application to terminate certificates applicable
to certain gathering and processing facilities, which may, at some point in the
future, create circumstances in which application of regulatory accounting
principles is no longer appropriate. The Consolidated Balance Sheet contains
assets and liabilities related to operations which have been recorded pursuant
to regulatory accounting principles. If these accounting principles should no
longer be applied, an
12
<PAGE> 14
amount would be charged to earnings as an extraordinary item. At June 30, 1995,
this amount was estimated to be approximately $56 million, net of income taxes.
Management continues to monitor the impact changes in the regulatory and
economic environment may have on the application of these regulatory accounting
principles. Any potential charge would be non-cash and would have no direct
effect on EPG's and MPC's ability to include the underlying deferred costs in
their future rate proceedings or on their ability to collect the rates set
thereby.
Acquisitions
On May 8, 1995, EPG, El Paso Acquisition Company, a wholly owned subsidiary
of EPG ("EPG Sub"), and Eastex Energy Inc. ("Eastex"), entered into an Agreement
and Plan of Merger (the "Agreement") whereby Eastex will be merged with and into
EPG Sub (the "Merger") pursuant to the terms of the Agreement. The terms of the
Agreement provide for holders of Eastex common stock to receive $4.50 per share
in either common stock of EPG (subject to a maximum and minimum exchange ratio
of 0.1629 and 0.1485, respectively) or in cash, at their option, with a maximum
of 49 percent of the Merger consideration being paid in cash. The Merger is
conditioned upon, among other things, approval by the holders of a majority of
the outstanding shares of Eastex common stock, the transaction being tax-free to
Eastex and its shareholders (except to the extent they receive cash), and
receipt of certain governmental approvals. The Agreement provides for a
termination fee of $1 million plus reimbursement of EPG's out-of-pocket
expenses, payable by Eastex under certain conditions. Management believes that
shareholder approval will be obtained and the Merger will be completed in the
third quarter of 1995. The net value of the transaction is estimated to be
approximately $31 million.
In connection with the execution of the Agreement, EPG entered into a
stockholder agreement with Robert G. Phillips, Chairman and Chief Executive
Officer of Eastex, pursuant to which he has agreed to vote all of his
approximately 2,400,000 shares of Eastex common stock in favor of the Merger.
Pursuant to other agreements, certain Eastex stockholders have agreed, among
other things, to vote an aggregate of approximately 300,000 shares of Eastex
common stock in favor of the Merger. The shares, subject to the stockholder
agreements, represent in the aggregate approximately 43 percent of the shares of
Eastex common stock outstanding as of June 30, 1995. In addition, other Eastex
stockholders have granted options to EPG Sub to purchase all of the shares of
Eastex common stock and warrants owned, beneficially or otherwise, by such other
stockholders. At June 30, 1995, these stockholders beneficially held warrants
immediately exercisable for the purchase of 647,500 shares of Eastex common
stock.
Environmental
As of June 30, 1995, EPG had a reserve of approximately $40 million for the
following environmental contingencies with income statement impact:
1 -- EPG has been conducting remediation of PCB contamination at certain of
its facilities. The majority of the required PCB remediation has been
completed. Future costs are estimated to range between $7 million and $11
million over the next 5 years.
2 -- EPG executed an Administrative Order on Consent with EPA in June 1993
to conduct a RI/FS for a site located in Statesville, North Carolina that
has been identified for cleanup. EPG and other PRP have entered into an
agreement to jointly fund the RI/FS for the site. Total remediation costs
are estimated to be between $17 million and $29 million over a 30 year
period. EPG and the other PRP are engaged in negotiations over the
appropriate allocation of the remediation costs.
3 -- In November 1993, in accordance with an EPA order, EPG and ARCO
submitted work plans for remediation of the subsurface at the Prewitt
Refinery in McKinley County, New Mexico. EPG and ARCO have a cost sharing
agreement to each pay one-half of any remediation costs at this site. EPG's
share of the remediation costs is estimated to be between $10 million and
$20 million over a 30 year period. Remediation of the surface began in May
of 1995.
13
<PAGE> 15
4 -- In December 1993, EPA issued EPG a Notice of Liability for the CSMRI
site in Golden, Colorado. EPA has determined that the volume of hazardous
substances sent to the site by EPG represent less than 2.5 percent of the
total volumes sent by all PRP. Based on this percentage, EPG's share of the
potential remediation costs is estimated to be less than $500,000.
5 -- EPG and other PRP have been notified about potential groundwater and
soil contamination at various sites in southeastern Utah. EPG and other PRP
have been conducting environmental assessments at certain of these sites
and are engaged in negotiations over the appropriate allocation of the
remediation costs. Based upon currently available information, EPG
estimates its costs for remediation will be approximately $4 million.
However, costs could be higher once the environmental assessment has been
completed.
6 -- In August 1992, EPG received a notice from the current owner of a site
in Etowah, Tennessee requesting compensation for remediation expenses
associated with the site. These costs are estimated to be approximately
$1.7 million. EPG and the other PRP are finalizing negotiations over the
appropriate allocation of the alleged costs. EPG's share of the remediation
costs is estimated to be less than $1 million.
7 -- EPG and other PRP entered into an agreement to conduct a RI/FS for a
site located in Fountain Inn, South Carolina. The RI/FS was completed in
October 1994, and EPA issued their proposed plan for the site in November
1994. The proposed remediation and EPA oversight costs are estimated to be
$800,000. The allocation of these costs between EPG and the other PRP is
currently being negotiated. EPG's share of the costs is estimated to be
between $300,000 and $500,000 over a 5 year period.
Management believes the amount reserved as of June 30, 1995, is sufficient
to cover these and other small environmental assessments and remediation
activities.
The State of Tennessee has asserted a claim that EPG is a liable party
under state environmental laws for cleanup costs associated with a site in
Elizabethton, Tennessee. The State and EPA are in the preliminary stages of
investigating the nature and extent of contamination, as well as identifying
other PRP. Since testing is in the initial stages, EPG is unable to estimate its
potential share of any remediation costs.
EPG also has potential expenditures, of a capital nature, for the following
environmental projects:
1 -- EPG has analyzed CAAA, and believes that these rules will impact the
Company's operations primarily in the following areas: (i) potential
required reductions in the emissions of NOx in non-attainment areas; (ii)
the requirement for air emissions permitting of existing facilities; and
(iii) enhanced monitoring of air emissions. EPG anticipates capitalizing
the equipment costs associated with complying with CAAA and estimates that
approximately $10 million will be spent from 1995 through 2005. However,
EPA's proposed enhanced monitoring rules, when finalized, could potentially
impose greater costs to the Company.
2 -- EPG has been conducting remediation of mercury contamination at
certain facilities and is replacing mercury containing meters with other
measurement devices. The total cost of the project is estimated to be
approximately $11 million. The project is expected to be completed by the
end of 1995. EPG will close and retire about 2,000 earthen
siphon/dehydration pits in the San Juan Basin, as required by certain
environmental regulations, at a cost of approximately $6 million. The
mercury remediation and pit closure costs, which are associated with the
retirement of equipment, will be recorded as adjustments to accumulated
depreciation, as permitted by regulatory accounting principles
It is possible that new information or future developments could require
the Company to reassess its potential exposure related to environmental matters.
As such information or developments occur, related accrual amounts will be
adjusted accordingly.
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<PAGE> 16
Long-term Debt and Other Financing Transactions
In August 1994, EPG established with a group of banks a revolving credit
facility of $400 million that expires in 5 years. As of June 30, 1995, and
December 31, 1994, there were no borrowings outstanding under this facility. As
of June 30, 1995, and December 31, 1994, approximately $144 million and $107
million, respectively, of commercial paper was outstanding.
EPG filed a shelf registration statement in August 1994, pursuant to which
EPG may offer up to $400 million of unsecured debt securities, preferred stock,
and common stock from time to time as determined by market conditions. On March
10, 1995, the registration statement was declared effective by the SEC. As of
June 30, 1995, EPG had not issued any securities pursuant to the shelf
registration statement.
Long-term debt maturities over the next 5 years are expected to be paid
using internally generated funds and short-term and long-term borrowings.
In February 1995, EPNC entered into a 7.75 year lease for a plant which is
being constructed in the San Juan Basin. The lease is an unconditional "triple
net" lease with the trustee of a special purpose trust. The trust obtains
financing for construction of the plant from a consortium of financial
institutions. The total amount financed via the operating lease will not exceed
$80 million, and the annual lease obligation will be a function of the amount
financed, a variable interest rate, and commitment and other fees. EPNC has an
option at the end of the lease term, and has an obligation upon the occurrence
of certain events, to purchase the plant for a price sufficient to pay the
entire amount financed, interest, and certain expenses. If EPNC does not
purchase the plant at the end of the lease term, it has an obligation to pay a
residual guaranty amount equal to approximately 87 percent of the amount
financed, plus interest. EPG unconditionally guaranteed all obligations of EPNC
under the lease. Construction of the plant began in April 1995, and it is
expected to be in service by early 1996.
Dividends
The following table reflects quarterly dividends declared and paid on EPG's
common stock:
<TABLE>
<CAPTION>
DECLARATION DATE AMOUNT PER SHARE PAYMENT DATE TOTAL AMOUNT
- ----------------- ---------------- ---------------- -------------
(IN MILLIONS)
<S> <C> <C> <C>
October 13, 1994 $ 0.3025 January 3, 1995 $ 11
January 13, 1995 $ 0.3300 April 3, 1995 $ 12
April 13, 1995 $ 0.3300 July 3, 1995 $ 11
</TABLE>
On July 21, 1995, the Board of Directors ("the Board") declared a quarterly
dividend of $.33 per share on EPG's common stock, payable on October 2, 1995, to
shareholders of record on September 8, 1995.
In November 1994, the Board authorized the repurchase of up to 3.5 million
shares of EPG's outstanding common stock from time to time in the open market.
Shares repurchased are held in EPG's treasury and are expected to be used in
connection with EPG stock option compensation plans and for other corporate
purposes. This authorization is in addition to a two million share authorization
received in October 1992. Pursuant to the foregoing authorizations, the Company
has purchased 3.9 million shares as of June 30, 1995.
CAPITAL EXPENDITURES
The Company's planned capital expenditures for 1995 of $200 million are
primarily for maintenance of business, system expansion, and system enhancement.
Capital expenditures for the six months ended June 30, 1995, were $52 million
compared to $41 million for the same period of 1994.
EPG is a member of a consortium that plans to build the proposed Samalayuca
II Power Plant near Ciudad Juarez, Chihuahua, Mexico. In December 1992, an award
for construction was granted to the consortium by the Comision Federal de
Electricidad ("CFE"). In August 1994, EPG increased its prospective ownership
interest in the Samalayuca II Power Plant from 10 percent to 20 percent. CFE and
the consortium signed a trust agreement in August 1994. Negotiation of the
annexes to the trust and other
15
<PAGE> 17
commercial documents is substantially complete. Upon final approval by the
appropriate entities within the Mexican government, the trust agreement, annexes
to the trust agreement, and other commercial documents will form the basis for
seeking international financing for the Samalayuca II Power Plant project.
In March 1993, EPG filed an application with FERC to expand its system in
order to provide natural gas service to the proposed Samalayuca II Power Plant
and to an existing power plant in the same location. The proposed expansion
would provide an additional 300 MMcf/d of capacity at a cost of approximately
$57 million. In November 1993, FERC issued an order that approved the proposed
border crossing facility south of Clint, Texas that would connect EPG's
facilities with facilities in Mexico. FERC deferred action on the remainder of
the March 1993 filing and in November 1994 required EPG to provide the executed
long-term contracts or binding agreements for a substantial amount of the firm
capacity of the proposed facilities by January 1995. EPG advised FERC that
although the contracts or agreements had not been obtained, EPG believes the
project remains viable and that the application should therefore not be
dismissed. In December 1993, PG&E, SoCal, and the California Public Utilities
Commission ("CPUC") jointly filed a motion with FERC seeking clarification or
rehearing of the November 1993 order on the Samalayuca II Power Plant project
discussed above.
In April 1994, EPG filed an application with FERC for a certificate of
public convenience and necessity to build a 98 mile pipeline to parallel and
loop its existing Havasu Crossover Line (the "North/South Transfer Project").
The proposed pipeline would allow for the transfer of 468 MMcf/d of San Juan
Basin gas to EPG's south system and would enhance EPG's overall system
flexibility to meet market demands. The project is expected to cost
approximately $62 million. At the request of several of EPG's customers, FERC
held a technical conference in August 1994 with respect to the April 1994
application.
In June 1994, EPG filed an application with FERC for a certificate of
public convenience and necessity to expand its existing mainline system in the
San Juan Basin by approximately 300 MMcf/d at a cost of about $26 million. The
proposed expansion would accommodate increased volumes and provide markets with
enhanced access to San Juan Basin gas supplies. FERC held a technical conference
in August 1994 with respect to the June 1994 application. The project is
expected to be completed by the end of 1995.
In early 1995, FERC preliminarily approved nonenvironmental aspects of the
North/South Transfer Project and the San Juan Basin mainline expansion project.
FERC accepted EPG proposals requiring that the projects benefit EPG's customers
or meet such other standard as might be established by FERC in order for the
projects' costs to be included in EPG's rates. Final approval of both projects
is dependent on favorable environmental reviews. SoCal has filed a request for
rehearing of the preliminary determination issued on the San Juan Basin mainline
expansion project. The CPUC, PG&E, and SoCal, jointly, have filed requests for
rehearing of the preliminary determination issued on the North/South Transfer
Project. In May 1995, EPG provided notice of an open season on the North/South
Transfer Project. The open season ended June 30, 1995, and EPG is currently
reviewing facility designs that would accurately match customer interest and/or
contracted volumes.
In March 1993, MPC filed an application, which was amended in November 1993
and April 1994, for a certificate of public convenience and necessity to build
and operate a 475 MMcf/d expansion of its existing system at an estimated cost
of approximately $500 million.
In December 1993, FERC held a public conference to examine the question
raised by the CPUC and PG&E regarding MPC's proposed expansion. The primary
issue was whether FERC or the CPUC should
16
<PAGE> 18
have jurisdiction over the expansion. In February 1994, FERC issued an order
determining that it has exclusive jurisdiction over MPC and its proposed
expansion. In March 1994, the CPUC, PG&E and other parties filed for rehearing
or clarification of FERC's February 1994 order. The petitions for rehearing
and/or clarification are currently pending action by FERC. In November 1994,
FERC unanimously issued an order which addressed all nonenvironmental issues
and, on that basis, granted MPC a certificate of public convenience and
necessity for the proposed expansion, subject to certain conditions. This order
is subject to possible later modification as a result of FERC's consideration of
environmental issues. In addition, FERC requested certain further information
from the parties to determine whether PG&E, which is currently the principal gas
supplier in the region to be served by the expansion project, is entitled to any
bypass compensation from MPC and/or EPG as a result of MPC's proposed expansion.
MPC and EPG have provided FERC with the requested information and urged that any
compensation or other relief to PG&E would be inappropriate. (Similar
information was later requested by FERC and provided by MPC regarding the
potential for bypass compensation to SoCal). In December 1994, MPC and other
parties filed requests for rehearing of certain aspects of FERC's November 1994
order. In February and March 1995, FERC issued orders which granted in part and
denied in part rehearing and accordingly modified the November 1994 order.
Whether MPC goes forward with the expansion will depend on, among other things,
the final actions taken by FERC and whether there is a satisfactory market for
the project.
The capital projects discussed above are expected to be financed through
internally generated funds and short-term and long-term borrowings.
RESULTS OF OPERATIONS
Second Quarter 1995 Compared to Second Quarter 1994
Operating revenues for the quarter ended June 30, 1995, were $26 million
lower than for the same period of 1994. Lower gas sales volumes, gas sales
rates, mainline transportation rates, and mainline transportation volumes,
contributed $11 million, $8 million, $2 million, and $1 million, respectively,
to the decrease.
Operating charges were $19 million lower for the quarter ended June 30,
1995, compared to the same period of 1994. Lower average cost of gas and lower
gas sales volumes contributed $7 million and $12 million, respectively, to the
decrease.
Interest and debt expense for the quarter ended June 30, 1995, was $2
million higher than for the same period of 1994 primarily due to higher interest
on short-term debt.
EPG's mainline throughput for the quarter ended June 30, 1995, was 318
billion cubic feet ("Bcf") compared to 313 Bcf for the same period of 1994. The
higher throughput was primarily due to an increase in off-system deliveries,
which was offset in part by lower mainline transportation deliveries to the
California market. Deliveries to California decreased due primarily to lower
demand in northern California, a result of an increase in the availability of
hydroelectric power.
Six Months Ended 1995 Compared to Six Months Ended 1994
Operating revenues for the six months ended June 30, 1995, were $43 million
lower than for the same period of 1994. Lower gas sales rates, gas sales
volumes, mainline transportation rates, mainline transportation volumes, and
gathering and processing volumes contributed $23 million, $19 million, $5
million, $2 million, and $1 million, respectively, to the decrease. An increase
in return on take-or-pay receivables, higher liquid revenues, as well as amounts
related to the Amoco decision partially offset the decrease in operating
revenues by $3 million, $1 million, and $4 million, respectively.
Operating charges for the six months ended June 30, 1995, were $45 million
lower than for the same period of 1994. Lower average cost of gas, lower gas
sales volumes, and a 1994 litigation special charge contributed $20 million, $19
million, and $15 million, respectively, to the decrease in operating charges.
Offsetting this decrease was an increase in operation and maintenance expense
and depreciation expense. The increase in operation and maintenance expense was
due primarily to higher severance accruals, higher stock related benefits, and a
1994 adjustment for Gas Research Institute fees.
17
<PAGE> 19
Interest and debt expense for the six months ended June 30, 1995, was $3
million higher than for the same period of 1994 due primarily to higher interest
on short-term debt.
Other-net income was $4 million lower for the six months ended June 30,
1995, than for the same period of 1994. The 1994 results contain income related
to the recovery of EPG's investment in its underground storage facility and
interest expense related to a litigation special charge.
EPG's mainline throughput for the six months ended June 30, 1995, was 634
Bcf compared to 626 Bcf for the same period of 1994. The higher throughput was
primarily due to an increase in off-system deliveries, which was offset in part
by lower mainline transportation deliveries to the California market. Deliveries
to California decreased due primarily to lower demand in northern California, as
a result of an increase in the availability of hydroelectric power.
RECENT PRONOUNCEMENTS
In March 1995, the Financial Accounting Standards Board issued SFAS No. 121
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of. SFAS No. 121 requires that long-lived assets and certain
identifiable intangibles to be held and used by an entity be reviewed for
impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. Certain long-lived assets
and certain identifiable intangibles to be disposed of must be reported at the
lower of carrying amount or fair value less cost to sell. SFAS No. 121 also
requires that a rate-regulated enterprise recognize an impairment for the amount
of costs that a regulator excludes from the enterprise's rate base. SFAS No. 121
is effective for the fiscal years beginning after December 15, 1995. The Company
is in the process of evaluating the implications of SFAS No. 121.
18
<PAGE> 20
PART II -- OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Notes 2, 3, and 4 of the Notes to Consolidated Financial Statements.
ITEM 2. CHANGES IN SECURITIES
None
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS
None
ITEM 5. OTHER INFORMATION
Continuous Odd-Lot Stock Sales Program
EPG has made available a Continuous Odd-Lot Stock Sales Program
("Program") in which shareholders of EPG owning beneficially fewer than
100 shares of EPG's common stock ("Odd-lot Holders") are offered a
convenient method of disposing of all their shares without incurring the
customary brokerage costs associated with the sale of an odd-lot. Only
Odd-lot Holders are eligible to participate in the Program. The Program
is strictly voluntary, and no Odd-lot Holder is obligated to sell
pursuant to the Program. A brochure and related materials describing the
Program were sent to Odd-lot Holders in February 1994. The Program
currently does not have a termination date, but EPG may suspend the
Program at any time. Inquiries regarding the Program should be directed
to The First National Bank of Boston.
The Program has been made available to Odd-lot Holders pursuant to
no-action letter relief granted by the SEC which expires on January 31,
1996. EPG cannot currently determine whether the SEC will extend,
modify, or terminate such exemptive relief.
Dividend Reinvestment and Common Stock Purchase Plan
EPG has made available a Dividend Reinvestment and Common Stock
Purchase Plan ("Plan") which provides all shareholders of record a
convenient and economical means of increasing their holdings in EPG's
common stock. A shareholder who owns shares of common stock in street
name or broker name and who wishes to participate in the Plan will need
to have his or her broker or nominee transfer the shares into the
shareholder's name. The Plan is strictly voluntary, and no shareholder
of record is obligated to participate in the Plan. A brochure and
related materials describing the Plan were sent to shareholders of
record in November 1994. The Plan currently does not have a termination
date, but EPG may suspend the Plan at any time. Inquiries regarding the
Plan should be directed to The First National Bank of Boston.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
A. Exhibits
<TABLE>
<S> <C>
10.J.1 -- Amendment No. 1 to EPG's 1995 Incentive Compensation Plan, effective
as of July 21, 1995.
10.Z.1 -- Amendment No. 1 to EPG's 1995 Omnibus Compensation Plan, effective as
of July 21, 1995.
11 -- Computation of Earnings Per Common Share
27 -- Financial Data Schedule
</TABLE>
B. Reports on Form 8-K
On May 23, 1995, the Company filed a report on Form 8-K, dated May
23, 1995, with respect to the Agreement with Eastex.
19
<PAGE> 21
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
--------------------------------
(Registrant)
Date: July 21, 1995 /s/ H. BRENT AUSTIN
--------------------------------
H. Brent Austin
Executive Vice President and
Chief Financial Officer
Date: July 21, 1995 /s/ THOMAS E. RICKS
--------------------------------
Thomas E. Ricks
Vice President, Controller and
Chief Accounting Officer
<PAGE> 22
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NUMBER EXHIBIT
- ---------------------------------------------------------------------------------------------
<S> <C>
10.J.1 -- Amendment No. 1 to EPG's 1995 Incentive Compensation Plan, effective
as of July 21, 1995.
10.Z.1 -- Amendment No. 1 to EPG's 1995 Omnibus Compensation Plan, effective as
of July 21, 1995.
11 -- Computation of Earnings Per Common Share
27 -- Financial Data Schedule
</TABLE>
<PAGE> 1
AMENDMENT NO. 1 TO THE
1995 INCENTIVE COMPENSATION PLAN
Pursuant to Section 9.12 of the El Paso Natural Gas Company 1995 Incentive
Compensation Plan (the "Plan"), the Plan is hereby amended as follows,
effective July 21, 1995:
Section 7.4 is amended to read as follows:
"7.4 PAYMENT UPON CHANGE IN CONTROL
Notwithstanding any other provision of this Plan, in the event of a
Change in Control of the Company, the award attributable to the Performance
Period in which the Change in Control occurs shall become fully vested and
distributable, in cash, within 30 days after the date of the Change in
Control, as follows:
Participants employed by the Company holding
any of the following positions and
Participants employed by Company subsidiaries
with positions equivalent thereto, but not
Percentage of Annual Salary necessarily with the same titles:
100% of Annual Salary Chairman of the Board, President, Chief
Executive Officer, Vice Chairman of the
Board, Chief Operating Officer, or
Executive Vice President
80% of Annual Salary Senior Vice President
60% of Annual Salary Vice President
The term "Annual Salary" as used in this Plan shall mean a Participant's
annual base salary in effect on the date of a Change in Control.
In the event a Change in Control occurs after the end of a
Performance Period, but before the Award Date, each Participant shall
be entitled to receive in cash, within 30 days after the date of the
Change in Control, those amounts set forth above in this Section 7.4 for
such Performance Period. Such amounts are in addition to the amount to
which Participants shall be entitled for the Performance Period in which a
Change in Control is deemed to occur.
For purposes of this Plan a "Change in Control" shall be deemed
to occur:
(a) if any person (as such term is used in Sections 13(d) and
14(d)(2) of the Exchange Act) is or becomes the "beneficial owner"
(as defined in Rule 13d-3 of the Exchange Act), directly or
indirectly, of securities of the Company representing twenty percent
(20%) or more of the combined voting power of the Company's then
outstanding securities;
<PAGE> 2
(b) upon the first purchase of the Common Stock pursuant to a
tender or exchange offer (other than a tender or exchange offer made
by the Company);
(c) upon the approval by the Company's stockholders of a merger
or consolidation, a sale, or disposition of all or substantially all
the Company's assets or a plan of liquidation or dissolution of the
Company; or
(d) if, during any period of two (2) consecutive years,
individuals who at the beginning of such period constitute the Board
cease for any reason to constitute at least a majority thereof,
unless the election or nomination for the election by the Company's
stockholders of each new director was approved by a vote of at least
two-thirds (2/3) of the directors then still in office who were
directors at the beginning of the period.
Notwithstanding the foregoing, a Change in Control shall not be deemed
to occur if the Company either merges or consolidates with or into another
company or sells or disposes of all or substantially all of its assets to
another company, if such merger, consolidation, sale or disposition is in
connection with a corporate restructuring wherein the stockholders of the
Company immediately before such merger, consolidation, sale or disposition
own, directly or indirectly, immediately following such merger,
consolidation, sale or disposition at least eighty percent (80%) of the
combined voting power of all outstanding classes of securities of the
company resulting from such merger or consolidation, or to which the
Company sells or disposes of its assets, in substantially the same
proportion as their ownership in the Company immediately before such
merger, consolidation, sale or disposition."
IN WITNESS WHEREOF, El Paso Natural Gas Company has caused this amendment
to be duly executed on this 21st day of July, 1995.
EL PASO NATURAL GAS COMPANY
Attest: By: /s/ JOEL RICHARDS III
/s/ STACY J. JAMES Title: Senior Vice President
Human Resources and
Administration
<PAGE> 1
AMENDMENT NO. 1 TO THE
1995 OMNIBUS COMPENSATION PLAN
Pursuant to Section 15 of the El Paso Natural Gas Company 1995 Omnibus
Compensation Plan (the "Plan"), the Plan is hereby amended as follows,
effective July 21, 1995:
Section 9.5(c) is amended to read as follows:
"(c) Form of Payment
A Participant or a Participant's Beneficiary shall be entitled to
receive from the Company a benefit payment as provided pursuant to
Sections 9.5(b)(i) or 9.5(b)(ii), as applicable, equal to the product of
the Adjusted Value and the number of vested Units of a Participant. Such
payment shall be made as soon as practicable following the applicable
Valuation Date in accordance with this Section 9.5(c).
Except as provided in Sections 9.5(d) and 9.7, benefit payments made
to a Participant pursuant to this Section 9, shall be made as follows:
(i) Participants employed by the Company holding the position of
Chairman of the Board, President or Chief Executive Officer and
Participants employed by Company Subsidiaries holding equivalent
positions, but not necessarily the same title, shall receive their
Performance Unit payout as follows:
(A) 50% (fifty percent) in cash and
(B) 50% (fifty percent) in Common Stock.
(ii) Participants employed by the Company holding the position of
Vice Chairman of the Board, Chief Operating Officer, or
Executive Vice President and Participants employed by Company
Subsidiaries holding equivalent positions, but not necessarily the
same title, shall receive their Performance Unit payout as follows:
(A) 60% (sixty percent) in cash and
(B) 40% (forty percent) in Common Stock.
(iii) Participants employed by the Company holding the position of
Senior Vice President and Participants employed by Company
Subsidiaries holding equivalent positions, but not necessarily the
same title, shall receive their Performance Unit payout as follows:
(A) 75% (seventy-five percent) in cash and
(B) 25% (twenty-five percent) in Common Stock."
<PAGE> 2
Section 9.6 is amended to read as follows:
"9.6 DEFERRED PAYMENT
Prior to the time that Units first vest pursuant to Section 9.3, the
Participant may, subject to the consent of the Management Committee and
in accordance with procedures that the Management Committee has approved,
elect to have all or a portion (subject to a $1,000 minimum) of the lump-
sum cash payment payable pursuant to section 9.5(c) with respect to such
vested Units deferred according to the terms and conditions of the
Company's Deferred Compensation Plan."
IN WITNESS WHEREOF, El Paso Natural Gas Company has caused this
amendment to be duly executed on this 21st day of July, 1995.
EL PASO NATURAL GAS COMPANY
Attest: By: /s/ Joel Richards III
/s/ Stacy J. Jones Title: Senior Vice President
Human Resources and
Administration
<PAGE> 1
EL PASO NATURAL GAS COMPANY
EARNINGS PER COMMON SHARE
Form 10-Q, Exhibit 11
<TABLE>
<CAPTION>
Second Quarter Six Months Ended June 30,
-------------------------- -------------------------
1995 1994 1995 1994
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Income available for common stock dividends $20,200,000 $24,011,000 $42,170,000 $45,126,000
Fully diluted average common shares outstanding 35,037,981 37,231,380 35,222,724 37,291,545
Fully diluted earnings per common share $0.5765 $0.6449 $1.1972 $1.2101
</TABLE>
Outstanding stock options of EPNG are common stock equivalents but are excluded
from primary earnings per common share due to immateriality. See following
calculation:
<TABLE>
<CAPTION>
Second Quarter Six Months Ended June 30,
-------------------------- -------------------------
1995 1994 1995 1994
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Total primary earnings per common share $0.5805 $0.6518 $1.2057 $1.2241
Fully diluted earnings per common share
(includes stock options) $0.5765 $0.6449 $1.1972 $1.2101
Percent dilution 0.6891% 1.0586% 0.7050% 1.1437%
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> JUN-30-1995
<CASH> 13,836
<SECURITIES> 0
<RECEIVABLES> 93,739
<ALLOWANCES> 0<F1>
<INVENTORY> 34,775
<CURRENT-ASSETS> 241,330
<PP&E> 1,882,362
<DEPRECIATION> 0<F1>
<TOTAL-ASSETS> 2,265,682
<CURRENT-LIABILITIES> 396,391
<BONDS> 775,494
<COMMON> 112,054
0
0
<OTHER-SE> 579,377
<TOTAL-LIABILITY-AND-EQUITY> 2,265,682
<SALES> 0
<TOTAL-REVENUES> 389,281
<CGS> 0
<TOTAL-COSTS> 280,211
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 42,164
<INCOME-PRETAX> 69,714
<INCOME-TAX> 27,544
<INCOME-CONTINUING> 42,170
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 42,170
<EPS-PRIMARY> 1.21
<EPS-DILUTED> 0
<FN>
<F1>Not separately provided for in interim document.
</FN>
</TABLE>
