El Paso Natural Gas 10-Q 2005 Q2 Quarterly report

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 June 30, 2005

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 of Incorporation or Organization)	74-0608280 (I.R.S. Employer Identification No.)
El Paso Building 1001 Louisiana Street Houston, Texas (Address of Principal Executive Offices)	77002 (Zip Code)

Telephone Number:(713) 420-2600

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ No o

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).     Yes o No þ

     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 per share. Shares outstanding on August 5, 2005: 1,000

     EL PASO NATURAL GAS COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTION H(1)(a) AND (b) TO FORM 10-Q AND IS THEREFORE FILING THIS REPORT WITH A REDUCED DISCLOSURE FORMAT AS PERMITTED BY SUCH INSTRUCTION.

EL PASO NATURAL GAS COMPANY

TABLE OF CONTENTS

	Caption	Page
	PART I — Financial Information
Item 1.	Financial Statements		1
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		11
	Cautionary Statements for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995		15
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		*
Item 4.	Controls and Procedures		15
	PART II — Other Information
Item 1.	Legal Proceedings		17
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		*
Item 3.	Defaults Upon Senior Securities		*
Item 4.	Submission of Matters to a Vote of Security Holders		*
Item 5.	Other Information		17
Item 6.	Exhibits		17
	Signatures		18

*  We have not included a response to this item in this document since no response is required pursuant to the reduced disclosure format permitted by General Instruction H to Form 10-Q.

      Below is a list of terms that are common to our industry and used throughout this document:

/d	= per day
BBtu	= billion British thermal units
Bcf	= billion cubic feet
MMcf	= million cubic feet
Certification of Principal Executive Officer pursuant to Section 302
Certification of Chief Financial Officer pursuant to Section 302
Certification of Principal Executive Officer pursuant to Section 906
Certification of Chief Financial Officer pursuant to Section 906

     When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

     When we refer to “us”, “we”, “our” or “ours”, we are describing El Paso Natural Gas Company and/or our subsidiaries.

i

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

EL PASO NATURAL GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In millions)

(Unaudited)

		Quarter Ended						Six Months Ended
		June 30,						June 30,
		2005			2004			2005			2004
Operating revenues		$	123		$	130		$	246		$	254
Operating expenses
	Operation and maintenance		42			36			91			75
	Depreciation, depletion and amortization		18			18			37			35
	Gain on long-lived assets		(2	)		(1	)		(2	)		(1	)
	Taxes, other than income taxes		8			8			16			16
			66			61			142			125
Operating income			57			69			104			129
Other income, net			2			1			4			3
Interest and debt expense			(23	)		(23	)		(46	)		(45	)
Affiliated interest income, net			8			4			13			9
Income before income taxes			44			51			75			96
Income taxes			17			19			29			30
Net income		$	27		$	32		$	46		$	66

See accompanying notes.

1

EL PASO NATURAL GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions, except share amounts)

(Unaudited)

				June 30,		December 31,
				2005		2004
ASSETS
Current assets
	Cash and cash equivalents			$	—	$	1
	Accounts and notes receivable
		Customer, net of allowance of $18 in 2005 and 2004			69		73
		Affiliates			5		38
		Other			2		3
	Taxes receivable				93		102
	Materials and supplies				39		41
	Deferred income taxes				33		27
	Other				11		19
			Total current assets		252		304
Property, plant and equipment, at cost					3,374		3,355
	Less accumulated depreciation, depletion and amortization				1,223		1,222
			Total property, plant and equipment, net		2,151		2,133
Other assets
	Note receivable from affiliate				792		702
	Other				87		86
					879		788
			Total assets	$	3,282	$	3,225
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
	Accounts payable
		Trade		$	30	$	36
		Affiliates			17		16
		Other			4		4
	Short-term borrowings				7		7
	Accrued interest				25		25
	Taxes payable				28		29
	Contractual deposits				8		11
	Other				10		11
			Total current liabilities		129		139
Long-term debt					1,110		1,110
Other liabilities
	Deferred income taxes				384		359
	Other				100		104
					484		463
Commitments and contingencies
Stockholder’s equity
	Common stock, par value $1 per share; 1,000 shares authorized, issued and outstanding				—		—
	Additional paid-in capital				1,267		1,267
	Retained earnings				292		246
			Total stockholder’s equity		1,559		1,513
			Total liabilities and stockholder’s equity	$	3,282	$	3,225

See accompanying notes.

2

EL PASO NATURAL GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)

				Six Months Ended
				June 30,
				2005			2004
Cash flows from operating activities
	Net income			$	46		$	66
	Adjustments to reconcile net income to net cash from operating activities
		Depreciation, depletion and amortization			37			35
		Deferred income taxes			19			84
		Gain on long lived assets			(2	)		(1	)
		Asset and liability changes			10			(664	)
			Net cash provided by (used in) operating activities		110			(480	)
Cash flows from investing activities
	Additions to property, plant and equipment				(51	)		(76	)
	Net change in restricted cash				—			443
	Net change in affiliate advances				(62	)		38
	Net proceeds from the sale of assets				2			1
			Net cash provided by (used in) investing activities		(111	)		406
Cash flows from financing activities
	Capital contributions				—			73
			Net cash provided by financing activities		—			73
Net change in cash and cash equivalents					(1	)		(1	)
Cash and cash equivalents
	Beginning of period				1			26
	End of period			$	—		$	25

See accompanying notes.

3

EL PASO NATURAL GAS COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation and Significant Accounting Policies

     Basis of Presentation

      We are an indirect wholly owned subsidiary of El Paso Corporation (El Paso). We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the United States Securities and Exchange Commission (SEC). Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by generally accepted accounting principles. You should read it along with our 2004 Annual Report on Form 10-K, which includes a summary of our significant accounting policies and other disclosures. The financial statements as of June 30, 2005, and for the quarters and six months ended June 30, 2005 and 2004, are unaudited. We derived the balance sheet as of December 31, 2004, from the audited balance sheet filed in our 2004 Annual Report on Form 10-K. In our opinion, we have made all adjustments which are of a normal, recurring nature to fairly present our interim period results. Due to the seasonal nature of our business, information for interim periods may not be indicative of our results of operations for the entire year.

     Significant Accounting Policies

      Our significant accounting policies are consistent with those discussed in our 2004 Annual Report on Form 10-K.

     New Accounting Pronouncements Issued But Not Yet Adopted

      As of June 30, 2005, there were several accounting standards and interpretations that had not yet been adopted by us. Below is a discussion of significant standards that may impact us.

     Accounting for Asset Retirement Obligations.In March 2005, the Financial Accounting Standards Board (FASB) issued FASB Interpretation (FIN) No. 47,Accounting for Conditional Asset Retirement Obligations. FIN No. 47 requires companies to record a liability for those asset retirement obligations in which the timing and/or amount of settlement of the obligation are uncertain. These conditional obligations were not addressed by Statement of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligations, which we adopted on January 1, 2003. FIN No. 47 will require us to accrue a liability when a range of scenarios indicate that the potential timing and/or settlement amounts of our conditional asset retirement obligations can be determined. We will adopt the provisions of this standard in the fourth quarter of 2005 and have not yet determined the impact, if any, that this pronouncement will have on our financial statements.

     Accounting for Pipeline Integrity Costs.In June 2005, the Federal Energy Regulatory Commission (FERC) issued an accounting release that will impact certain costs we incur related to our pipeline integrity programs. This release will require us to expense certain pipeline integrity costs incurred after January 1, 2006 instead of capitalizing them as part of our property, plant and equipment. Although we continue to evaluate the impact that this accounting release will have on our consolidated financial statements, we currently estimate that we would be required to expense an additional amount of pipeline integrity costs under the release in the range of approximately $5 million to $14 million annually.

2. Credit Facilities

      We are an eligible borrower under El Paso’s $3 billion credit agreement. At June 30, 2005, El Paso had $1.2 billion outstanding under the term loan and $1.4 billion of letters of credit issued under the credit agreement, none of which was borrowed by or issued on behalf of us. For a further discussion of El Paso’s $3 billion credit agreement and our restrictive covenants, see our 2004 Annual Report on Form 10-K.

4

3. Commitments and Contingencies

  Legal Proceedings

     Sierra Pacific Resources and Nevada Power Company v. El Paso et al. In April 2003, Sierra Pacific Resources and Nevada Power Company filed a suit in U.S. District Court for the District of Nevada against us, our affiliates and unrelated third parties, alleging that the defendants conspired to manipulate prices and supplies of natural gas in the California-Arizona border market from 1996 to 2001. In January 2004, the court dismissed the lawsuit. Plaintiffs subsequently amended the complaint, which was dismissed again in November 2004. Plaintiffs have appealed that dismissal to the US Court of Appeals for the Ninth Circuit. We expect this appeal to be fully briefed by the end of the summer of 2005. Our costs and legal exposure related to this lawsuit are not currently determinable.

     IMC Chemicals (IMCC) v. El Paso Marketing, L.P. (EPM), et al. In January 2003, IMCC filed a lawsuit in California state court against us and our affiliates. The suit seeks to void the gas purchase agreement between IMCC and EPM, the term of which was to continue until December 2003. IMCC contends that EPM and its affiliates manipulated market prices for natural gas and, as a part of the manipulation, induced IMCC to enter into the contract. IMCC’s total claim appears to be in excess of $20 million. IMCC alternatively seeks $5.7 million as damages it maintains it was entitled to at the termination of the contract. EPM’s counterclaim seeks in excess of $5 million in damages. Our costs and legal exposure related to this lawsuit are not currently determinable.

     Phelps Dodge vs. EPNG. In February 2004, one of our customers, Phelps Dodge, and a number of its affiliates filed a lawsuit against us in the state court of Arizona. Plaintiffs claim we violated Arizona anti-trust statutes and allege that during 2000-2001, we unlawfully withheld capacity and thereby manipulated and inflated gas prices. We removed this lawsuit to the U.S. District Court for the District of Arizona. Plaintiffs filed a motion to remand the matter to state court which the district court granted in March 2005. Our motion to dismiss is pending. Our costs and legal exposure related to this lawsuit are not currently determinable.

     Shareholder Class Action Suit. In November 2002, we and certain of our affiliates were named as a defendant in a shareholder derivative suit titledMarilyn Clark v. Byron Allumbaugh, David A. Arledge, John M. Bissell, Juan Carlos Braniff, James F. Gibbons, Anthony W. Hall, Ronald L. Kuehn, J. Carleton MacNeil, Thomas McDade, Malcolm Wallop, William Wise, Joe B. Wyatt, El Paso Natural Gas Company and El Paso Merchant Energy Companyfiled in state court in Houston. This shareholder derivative suit generally alleges that manipulation of California gas supply and gas prices exposed our parent, El Paso, to claims of antitrust conspiracy, FERC penalties and erosion of share value. The plaintiffs have not asked for any relief with regard to us.

     Carlsbad. In August 2000, a main transmission line owned and operated by us ruptured at the crossing of the Pecos River near Carlsbad, New Mexico. Twelve individuals at the site were fatally injured. In June 2001, the U.S. Department of Transportation’s (DOT) Office of Pipeline Safety issued a Notice of Probable Violation and Proposed Civil Penalty to us. The Notice alleged violations of DOT regulations, proposed fines totaling $2.5 million and proposed corrective actions. In April 2003, the National Transportation Safety Board issued its final report on the rupture finding that the rupture was probably caused by internal corrosion that was not detected by our corrosion control program. In December 2003, this matter was referred by the DOT to the Department of Justice (DOJ). We recently entered into a tolling agreement with the DOJ to attempt to reach resolution of this civil proceeding. In addition, we and several of our current and former employees had received several federal grand jury subpoenas for documents or testimony related to the Carlsbad rupture. In July 2005, we were informed by the DOJ that they are not pursuing any criminal prosecutions associated with the rupture.

      In addition, a lawsuit entitledBaldonado et al. vs. EPNG was filed in June 2003, in state court in Eddy County, New Mexico, on behalf of 23 firemen and emergency medical service personnel who responded to the fire and who allegedly have suffered psychological trauma. This case was dismissed by the trial court, but has been appealed to the New Mexico Court of Appeals. The appeal is currently being briefed. Our costs and legal

5

exposure related to theBaldonado lawsuit are currently not determinable, however, we believe these matters will be fully covered by insurance. All other personal injury suits related to the rupture have been settled.

     Grynberg. In 1997, we and a number of our affiliates were named defendants in actions brought by Jack Grynberg on behalf of the U.S. Government under the False Claims Act. Generally, these complaints allege an industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas produced from federal and Native American lands, which deprived the U.S. Government of royalties due to the alleged mismeasurement. The plaintiff in this case seeks royalties, along with interest, expenses, and punitive damages. The plaintiff also seeks injunctive relief with regard to future gas measurement practices. No monetary relief has been specified in this case. These matters have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming, filed June 1997). Motions to dismiss were argued before a representative appointed by the court. In May 2005, the representative issued its recommendation, which if adopted by the district court judge, will result in the dismissal on jurisdictional grounds of the suit against us. If the district court judge adopts the representative’s recommendation, an appeal by the plaintiff of the district court’s order is likely. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.

     Will Price (formerly Quinque). We and a number of our affiliates are named defendants inWill Price, et al. v. Gas Pipelines and Their Predecessors, et al., filed in 1999 in the District Court of Stevens County, Kansas. Plaintiffs allege that the defendants mismeasured natural gas volumes and heating content of natural gas on non-federal and non-Native American lands and seek to recover royalties that they contend they should have received had the volume and heating value of natural gas produced from their properties been differently measured, analyzed, calculated and reported, together with prejudgment and post judgment interest, punitive damages, treble damages, attorneys’ fees, costs and expenses, and future injunctive relief to require the defendants to adopt allegedly appropriate gas measurement practices. No monetary relief has been specified in this case. Plaintiffs’ motion for class certification of a nationwide class of natural gas working interest owners and natural gas royalty owners was denied in April 2003. Plaintiffs were granted leave to file a Fourth Amended Petition, which narrows the proposed class to royalty owners in wells in Kansas, Wyoming and Colorado, and removes claims as to heating content. A second class action petition has since been filed as to the heating content claims. Motions for class certification have been briefed and argued in both proceedings, and the parties are awaiting the court’s ruling. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.

     Bank of America.We are a named defendant, along with Burlington Resources, Inc. (Burlington), in two class action lawsuits styled asBank of America, et al. v. El Paso Natural Gas Company, et al.,andDeane W. Moore, et al. v. Burlington Northern, Inc., et al.,each filed in 1997 in the District Court of Washita County, State of Oklahoma and subsequently consolidated by the court. The plaintiffs have filed reports alleging damages of approximately $480 million, which includes alleged royalty underpayments from 1982 to the present on natural gas produced from specified wells in Oklahoma, plus interest from the time such amounts were allegedly due. The plaintiffs have also requested punitive damages. The court has certified the plaintiff classes of royalty and overriding royalty interest owners. The consolidated class action has been set for trial in the fourth quarter of 2005. While Burlington accepted our tender of the defense of these cases in 1997, pursuant to the spin-off agreement entered into in 1992 between us and Burlington, and had been defending the matter since that time, at the end of 2003 it asserted contractual claims for indemnity against us. A third action, styledBank of America, et al. v. El Paso Natural Gas and Burlington Resources Oil and Gas Company,was filed in October 2003 in the District Court of Kiowa County, Oklahoma asserting similar claims as to specified shallow wells in Oklahoma, Texas and New Mexico. Defendants succeeded in transferring this action to Washita County. A class has not been certified. We have filed an action styledEl Paso Natural Gas Company v. Burlington Resources, Inc. and Burlington Resources Oil and Gas Company, L.P. against Burlington in state court in Harris County relating to the indemnity issues between Burlington and us. That action is currently stayed by agreement of the parties. We believe we have substantial defenses to the plaintiffs’ claims as well as to the claims for indemnity by Burlington. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.

6

      In addition to the above matters, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business.

      For each of our outstanding legal matters, we evaluate the merits of the case, our exposure in the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. As further information becomes available, or other relevant developments occur, we adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our current reserves are adequate. At June 30, 2005, we had accrued approximately $3 million for our outstanding legal matters.

  Environmental Matters

      We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. At June 30, 2005, we had accrued approximately $32 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and for related environmental legal costs. This accrual includes $25 million for environmental contingencies related to properties we previously owned. Our accrual was based on the most likely outcome that can be reasonably estimated; however, our exposure could be as high as $57 million. Below is a reconciliation of our accrued liability from January 1, 2005 to June 30, 2005 (in millions).

Balance at January 1, 2005	$	32
Additions/adjustments for remediation activities		1
Payments for remediation activities		(1	)
Balance at June 30, 2005	$	32

      For the remainder of 2005, we estimate that our total remediation expenditures will be approximately $5 million, which will be expended under government directed clean-up plans. In addition, we expect to make capital expenditures for environmental matters of approximately $25 million in the aggregate for the years 2005 through 2009. These expenditures primarily relate to compliance with clean air regulations.

     CERCLA Matters. We have received notice that we could be designated, or have been asked for information to determine whether we could be designated, as a Potentially Responsible Party (PRP) with respect to three active sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or state equivalents. We have sought to resolve our liability as a PRP at these sites through indemnification by third parties and settlements which provide for payment of our allocable share of remediation costs. As of June 30, 2005, we have estimated our share of the remediation costs at these sites to be between $12 million and $17 million. 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 we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute is joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in estimating our liabilities. Accruals for these matters are included in the environmental reserve discussed above.

     New Mexico Ambient Air Quality Standards. In October 2004, the State of New Mexico’s Environmental Department proposed a new rule that would impose an eight-hour ambient air quality standard on all New Mexico industrial facilities that are currently under the federal Title 5 program. In June 2005, we reached a settlement with the state that established a schedule for our facilities to satisfy the proposed standards. The rulemaking procedure has been vacated as the result of the negotiated agreement with the state. The cost to comply with the agreement has been included in the capital expenditures for environmental matters of approximately $25 million listed above.

     State of Arizona Chromium Review. In April 2004, the State of Arizona’s Department of Environmental Quality requested information from us regarding the historical use of chromium in our

7

operations. By June 2004, we had responded fully to the request. We are currently working with the State of Arizona on this matter and have commenced a study of our facilities in Arizona to determine if there are any issues concerning the usage of chromium. We will also study our facilities on tribal lands in Arizona and New Mexico and our facility at El Paso Station in El Paso, Texas. Our costs related to this matter are not currently determinable.

      It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws and regulations and claims for damages to property, employees, other persons and the environment resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate.

  Rates and Regulatory Matters

     CPUC Complaint Proceeding. In April 2000, the California Public Utility Commission (CPUC) filed a complaint under Section 5 of the Natural Gas Act (NGA) with the FERC alleging that our sale of approximately 1.2 Bcf/d of capacity to our affiliate, EPM, raised issues of market power and violation of the FERC’s marketing affiliate regulations and asked that the contracts be voided. In the spring and summer of 2001, two hearings were held before an Administrative Law Judge (ALJ) to address the market power issue and the affiliate issue. In November 2003, the FERC vacated both of the ALJ’s Initial Decisions that were adverse to us. That decision was upheld by the FERC in a rehearing order issued in March 2004. Certain shippers have appealed both FERC orders to the U.S. Court of Appeals for the District of Columbia, where the matter is pending. This matter has been fully briefed, but has not been set for oral arguments.

     Rate Settlement.Our current rate settlement establishes our base rates through December 31, 2005. The settlement has certain requirements applicable to the post-settlement period that includes a provision which limits the rates to be charged to a portion of our contracted portfolio to a level equal to the inflation-escalated rate from our 1996 rate settlement. In our rate case filed in June 2005, we proposed that the rate limitation should no longer apply. The FERC has stated it will address this issue in a technical conference in our current rate proceeding.

     Rate Case. In June 2005, we filed a rate case with the FERC proposing an increase in revenues of 10.6 percent or $56 million over current tariff rates, subject to refund, and also proposing new services and revisions to certain terms and conditions of existing services, including the adoption of a fuel tracking mechanism. The rate case would be effective January 1, 2006. In addition, the reduced tariff rates provided to our former full requirements (FR) customers under the terms of our FERC approved systemwide capacity allocation proceeding will expire on January 1, 2006. The combined effect of the proposed increase in tariff rates and the expiration of the lower rates to our FR customers are estimated to increase our revenues by approximately $138 million. In July 2005, the FERC accepted certain of the proposed tariff revisions, including the adoption of a fuel tracking mechanism and set the rate case for hearing and technical conference. The FERC directed the scheduling of the technical conference within 150 days of the order and delayed setting a date for the hearing pending resolution of the various matters identified for consideration at the technical conference. We anticipate continued discussions with intervening parties in an attempt to settle the matter and are uncertain of the outcome of this rate case.

     FERC Order 2004 Audit. In February 2005, we were notified that the FERC’s Office of Market Oversight and Investigations had selected us to undergo an audit of our FERC Order 2004 compliance efforts. We are cooperating fully with the auditors and have provided initial responses to the data requests. The final outcome of this audit can not be predicted with certainty, nor can its impact on us or our affiliated pipelines be determined at this time.

     CPUC’s OIR Proceeding.The CPUC initiated an Order Instituting Rulemaking (OIR) in Docket No. R04-01-025 addressing California’s utilities’ energy supply plans for the period of 2006 and beyond. The

8

proceeding is broken into two phases, with the first focusing on issues that need to be addressed more immediately such as interstate capacity and utility access to liquified natural gas supplies. In September 2004, the CPUC issued a decision on these issues that is generally favorable to us. However, it authorizes the California utilities to issue notices of termination of their contracts with us in order to permit them to negotiate reduced contract levels and diversify their supply portfolios. This means, for instance, that our largest customer, Southern California Gas Company (SoCal), had the CPUC’s permission to terminate its contract with us for approximately 1.2 Bcf/d, which it did in April 2005. The termination will be effective August 2006. In late April 2005, the CPUC’s Administrative Law Judge dismissed, without further consideration, the issue pending in Phase II of its OIR proceeding of whether the CPUC should require California utilities to hold capacity to serve, or backup, the interstate transportation needs of their non-core customers. Although we have successfully recontracted with SoCal for 750 MMcf/d of capacity for various terms extending through 2011, we will have approximately 500 MMcf/d of capacity formerly held by SoCal for its use in serving its non-core customers available for recontracting, effective September 2006. We are continuing in our efforts to remarket expiring capacity, including marketing efforts to serve SoCal’s non-core customers or to serve new markets. We are also pursuing the option of using some or all of this capacity to provide new services to existing markets. At this time, we are uncertain whether this remaining capacity will be recontracted or at what rates this capacity will ultimately be recontracted.

     Selective Discounting Notice of Inquiry. In November 2004, the FERC issued a Notice of Inquiry seeking comments on its policy regarding selective discounting by natural gas pipelines. In May 2005, the FERC issued an order reaffirming its prior practice of permitting pipelines to adjust their ratemaking throughput downward in rate cases to reflect discounts given by pipelines for competitive reasons when the discount is given to meet competition from another natural gas pipeline.

      While the outcome of our outstanding rates and regulatory matters cannot be predicted with certainty, based on current information, we do not expect the ultimate resolution of these matters to have a material adverse effect on our financial position, operating results or cash flows. However, it is possible that new information or future developments could require us to reassess our potential exposure related to these matters, which could have a material effect on our results of operations, our financial position, and our cash flows in the periods these events occur.

     Other Matters

     Navajo Nation.Nearly 900 looped pipeline miles of the north mainline of our EPNG pipeline system are located on property inside the Navajo Nation. We currently pay approximately $2 million per year for the real property interests, such as easements, leases and rights-of-way, located on Navajo Nation trust lands. These real property interests are scheduled to expire in October 2005. We are in negotiations with the Navajo Nation to obtain their consent to renew these interests, but the Navajo Nation has made a demand of more than ten times the existing fee. We will continue to negotiate in order to reach an agreement on a renewal, but we are also exploring other options including potentially developing collaborative projects to benefit the Navajo Nation in lieu of cash payments. If we are unable to reach a new consent agreement with the Navajo Nation (which is arguably required for renewal of the U.S. Department of the Interior’s extension of our current easement across trust lands), the impact is uncertain. Historically, we have continued renewal negotiations with the Navajo Nation substantially beyond the prior easement’s expiration, without litigation or interruption to our operations. As our renewal efforts continue, we may incur litigation and other costs and, ultimately, higher fees. Although the FERC has rejected a request made in the rate case filed on June 25, 2005 for a tracking mechanism that would have provided an assurance of recovery of the cost of the Navajo right-of-way, the FERC did invite us to seek permission to include the cost of the right-of-way in our pending rate case if the final cost becomes known and measurable within a reasonable time after the close of the test period on December 31, 2005.

Guarantees

      We are involved in various joint ventures and other ownership arrangements that sometimes require additional financial support that results in the issuance of financial and performance guarantees. See our 2004

9

Annual Report on Form 10-K for a description of these guarantees. As of June 30, 2005, we had approximately $16 million of both financial and performance guarantees not otherwise reflected in our financial statements.

4. Transactions with Affiliates

     Cash Management Program. We participate in El Paso’s cash management program which matches short-term cash surpluses and needs of participating affiliates, thus minimizing total borrowings from outside sources. At June 30, 2005 and December 31, 2004, we had advanced to El Paso $792 million and $730 million. The interest rate was 4.3% at June 30, 2005 and 2.0% at December 31, 2004. This receivable is due upon demand; however, we do not anticipate settlement of the entire amount in the next twelve months. At December 31, 2004, we classified $28 million of this receivable as current and at June 30, 2005 and December 31, 2004, we classified $792 million and $702 million as non-current.

     Taxes. We are a party to a tax accrual policy with El Paso whereby El Paso files U.S. and certain state tax returns on our behalf. In certain states, we file and pay directly to the state taxing authorities. We have income taxes receivable of $93 million at June 30, 2005 and $102 million at December 31, 2004. We also have income taxes payable of $3 million at June 30, 2005 and $9 million at December 31, 2004, included in taxes payable on our balance sheet. The majority of these balances will become payable to or receivable from El Paso.

     Capital Contributions. In January 2004, El Paso contributed to us $73 million in proceeds from the issuance of its common stock. The proceeds were placed in escrow and released to the Western Energy Settlement parties in June 2004.

     Other Affiliate Balances. The following table shows other balances with our affiliates:

	June 30,		December 31,
	2005		2004
	(In millions)
Contractual deposits	$	6	$	6

     Affiliate Revenues and Expenses. We are allocated a portion of El Paso’s general and administrative costs. The allocation is based on the estimated level of effort devoted to our operations and the relative size of our EBIT, gross property and payroll. We are also allocated costs from Tennessee Gas Pipeline Company associated with our shared pipeline services. The following table shows revenues and charges from our affiliates for the periods ended June 30:

					Six Months
	Quarter Ended				Ended
	June 30,				June 30,
	2005		2004		2005		2004
	(In millions)
Revenues from affiliates	$	4	$	5	$	8	$	9
Operations and maintenance expenses from affiliates		17		13		34		27
Reimbursement of operating expenses charged to affiliates		4		3		8		7

10

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, the information disclosed in our 2004 Annual Report on Form 10-K, and the financial statements and notes presented in Item 1 of this Quarterly Report on Form 10-Q.

Results of Operations

      Our management, as well as El Paso’s management, uses earnings before interest expense and income taxes (EBIT) to assess the operating results and effectiveness of our business. We define EBIT as net income adjusted for (i) items that do not impact our income from continuing operations, (ii) income taxes and (iii) interest, which includes interest and debt expense and affiliated interest income. We exclude interest from this measure so that our management can evaluate our operating results without regard to our financing methods. We believe the discussion of our results of operations based on EBIT is useful to our investors because it allows them to more effectively evaluate the operating performance of our business using the same performance measure analyzed internally by our management. EBIT may not be comparable to measurements used by other companies. Additionally, EBIT should be considered in conjunction with net income and other performance measures such as operating income or operating cash flows.

      The following is a reconciliation of EBIT to net income for the periods ended June 30:

		Quarter Ended						Six Months Ended
		June 30,						June 30,
		2005			2004			2005			2004
		(In millions, except volume amounts)
Operating revenues		$	123		$	130		$	246		$	254
Operating expenses			(66	)		(61	)		(142	)		(125	)
	Operating income		57			69			104			129
Other income, net			2			1			4			3
	EBIT		59			70			108			132
Interest and debt expense			(23	)		(23	)		(46	)		(45	)
Affiliated interest income, net			8			4			13			9
Income taxes			(17	)		(19	)		(29	)		(30	)
	Net income	$	27		$	32		$	46		$	66
Total throughput (BBtu/d)			4,089			4,152			4,071			4,067

      The following items contributed to our overall EBIT decrease of $11 million and $24 million for the quarter and six months ended June 30, 2005 as compared to the same periods in 2004:

		Quarter Ended											Six Months Ended
		June 30,											June 30,
										EBIT											EBIT
		Revenue			Expense			Other		Impact			Revenue			Expense			Other		Impact
		Favorable/(Unfavorable)
		(In millions)
Impact of capacity obligations to former full requirements (FR) customers		$	2		$	—		$	—	$	2		$	5		$	—		$	—	$	5
Gas not used in operations			(6	)		(1	)		—		(7	)		(10	)		(6	)		—		(16	)
Higher benefits and allocation of overhead and shared service costs from affiliates			—			(6	)		—		(6	)		—			(11	)		—		(11	)
Higher depreciation resulting from increase in depreciable assets			—			(1	)		—		(1	)		—			(3	)		—		(3	)
Other(1)			(3	)		3			1		1			(3	)		3			1		1
	Total impact on EBIT	$	(7	)	$	(5	)	$	1	$	(11	)	$	(8	)	$	(17	)	$	1	$	(24	)

⁽¹⁾  Consists of individual insignificant items.

     The following provides further discussions on some of the significant items listed above as well as events that may affect our operations in the future.

11

     Impact of capacity obligations to former FR customers. Under the terms of our FERC approved systemwide capacity allocation proceeding, the impact of the capacity obligations for former FR customers terminated with the completion of Phases I and II of our Line 2000 Power-up project in April 2004. As a result, we are now able to remarket this capacity; however, we must demonstrate that such sales do not adversely impact our service to our firm customers and we are at risk for portions that were turned back to us on a permanently released basis.

     Gas Not Used in Operations. The financial impact of operational gas is based on the amount of natural gas we are allowed to recover, relative to the amounts of natural gas we use for operating purposes and the price of natural gas. Gas not needed for operations results in revenues to us, which are driven by volumes and prices during a given period. During 2004, we recovered, fairly consistently, volumes of natural gas that were not utilized for operations. These recoveries were based on factors such as system throughput, facility enhancements and the ability to operate the systems in the most efficient and safe manner. During 2005, we have experienced a net usage of natural gas in excess of amounts we recovered under our tariff. This, along with a steadily increasing natural gas price environment during this timeframe, resulted in unfavorable impacts on our operating results in 2005 versus 2004. In our rate case filed in June 2005, we proposed the adoption of a fuel tracker to recover the actual costs of fuel, with a true-up mechanism for over or under recoveries. In its July 2005 order, the FERC determined that the fuel tracker was just and reasonable, although the FERC noted that certain procedurals aspects of the fuel tracker (such as the adjustments for gas volumes that are periodically purchased and sold, the determination of the initial fuel retention levels and the mechanism for making periodic adjustments to the retention levels) required further investigation. Accordingly, following the implementation of the fuel tracker on January 1, 2006, this matter will not have a material impact on future EBIT.

     Allocated Costs. We are allocated a portion of El Paso’s general and administrative costs. The allocation is based on the estimated level of effort devoted to our operations and the relative size of our EBIT, gross property and payroll. We are also allocated costs from Tennessee Gas Pipeline Company associated with our shared pipeline services. During the quarter and six months ended June 30, 2005, we were allocated higher costs than the same periods in 2004, primarily due to an increase in El Paso’s benefits accrued under its retirement plan and higher insurance and professional fees. In addition, we were allocated a larger percentage of El Paso’s total corporate costs due to the significance of our asset base and earnings to the overall El Paso asset base and earnings.

     Expansions. In order to meet increased demand in our markets and comply with FERC orders, we completed Phases I, II, and III of our EPNG Line 2000 Power-up project in 2004, which increased the capacity of that line by 320 MMcf/d. In addition, in June 2005, we received FERC certificate approval for the EPNG Cadiz to Ehrenberg (Line 1903) project that will increase our north-to-south capacity by 372 MMcf/d. The project is scheduled to be in service by late 2005. Construction and conversion will begin as soon as we receive approval from the California State Land Commission and the U.S. Department of the Interior’s Bureau of Land Management. We expect to earn revenues associated with these expansions beginning in January 2006, the effective date of EPNG’s recent rate filing.

     Recontracting. SoCal successfully acquired approximately 750 MMcf/d of capacity on our system under new contracts with various terms extending from 2009 to 2011 commencing September 2006. We are in the process of consummating the transaction we entered into in December 2004 by executing the relevant transportation service agreements with SoCal. Effective September 2006, approximately 500 MMcf/d of capacity formerly held by SoCal to serve its non-core customers will be available for recontracting. We are continuing in our efforts to remarket the remaining expiring capacity to serve SoCal’s non-core customers or to serve new markets. We are also pursuing the option of using some or all of this capacity to provide new services to existing markets. At this time, we are uncertain how much of this remaining capacity formerly held by SoCal will be recontracted, and if so at what rates.

     Accounting for Pipeline Integrity Costs.In June 2005, the FERC issued an accounting release that will impact certain costs we incur related to our pipeline integrity programs. This release will require us to expense certain pipeline integrity costs incurred after January 1, 2006 instead of capitalizing them as part of our

12

property, plant and equipment. Although we continue to evaluate the impact that this accounting release will have on our consolidated financial statements, we currently estimate that we would be required to expense an additional amount of pipeline integrity costs under the release in the range of approximately $5 million to $14 million annually.

     Regulatory Matter.In June 2005, we filed a rate case with the FERC proposing an increase in revenues of 10.6 percent or $56 million over current tariff rates, subject to refund, and also proposing new services and revisions to certain terms and conditions of existing services, including the adoption of a fuel tracking mechanism. The rate case would be effective January 1, 2006. In addition, the reduced tariff rates provided to our former full requirements (FR) customers under the terms of our FERC approved systemwide capacity allocation proceeding will expire on January 1, 2006. The combined effect of the proposed increase in tariff rates and the expiration of the lower rates to our FR customers are estimated to increase our revenues by approximately $138 million. In July 2005, the FERC accepted certain of the proposed tariff revisions, including the adoption of a fuel tracking mechanism and set the rate case for hearing and technical conference. The FERC directed the scheduling of the technical conference within 150 days of the order and delayed setting a date for the hearing pending resolution of the various matters identified for consideration at the technical conference. We anticipate continued discussions with intervening parties in an attempt to settle the matter and are uncertain of the outcome of this rate case.

Affiliated Interest Income, Net

Second Quarter 2005 Compared to Second Quarter 2004

      Affiliated interest income, net for the quarter ended June 30, 2005, was $4 million higher than the same period in 2004. The average short-term interest rates for the second quarter increased from 2.3% in 2004 to 4.0% in 2005. However, the average advance balance due from El Paso of $785 million for the second quarter of 2004 decreased to $763 million in 2005.

Six Months Ended 2005 Compared to Six Months Ended 2004

      Affiliated interest income, net for the six months ended June 30, 2005, was $4 million higher than the same period in 2004. The average short-term interest rates increased from 2.5% in 2004 to 3.5% in 2005. However, the average advance balance due from El Paso of $777 million for the six months of 2004 decreased to $742 million in 2005.

Income Taxes

	Quarter						Six Months
	Ended						Ended
	June 30,						June 30,
	2005			2004			2005			2004
	(In millions, except for rates)
Income taxes	$	17		$	19		$	29		$	30
Effective tax rate		39	%		37	%		39	%		31	%

      Our effective tax rates for the quarters ended June 30, 2005 and 2004 and for the six months ended June 30, 2005 were higher than the statutory rate of 35 percent primarily due to the effect of state income taxes.

      Our effective tax rate for the six months ended June 30, 2004, was lower than the statutory rate of 35 percent due to a state income tax adjustment related to the Western Energy Settlement. As of December 31, 2003, we maintained a valuation allowance on deferred tax assets related to our ability to realize state tax benefits from the deduction of the charge we took related to the Western Energy Settlement. During the first quarter of 2004, we evaluated this allowance and, based on our estimates, we believe that these state tax benefits would be fully realized. Consequently, we reversed this valuation allowance. Net of federal taxes, this benefit totaled approximately $6 million.

13

Liquidity

      Our liquidity needs have historically been provided by cash flows from operating activities and the use of El Paso’s cash management program. Under El Paso’s cash management program, depending on whether we have short-term cash surpluses or requirements, we either provide cash to El Paso or El Paso provides cash to us. We have historically provided cash advances to El Paso, and we reflect these advances as investing activities in our statement of cash flows. At June 30, 2005, we had a cash advance receivable from El Paso of $792 million as a result of this program. This receivable is due upon demand; however, we do not anticipate settlement within the next twelve months. At June 30, 2005, this receivable was classified as a non-current note receivable from affiliate on our balance sheet. In addition to El Paso’s cash management program, we are also eligible to borrow amounts available under El Paso’s $3 billion credit agreement, under which we and our ownership in Mojave Pipeline Company are pledged as collateral. We believe that cash flows from operating activities and amounts available under El Paso’s cash management program, if necessary, will be adequate to meet our short-term capital requirements for our existing operations.

Capital Expenditures

      Our capital expenditures for the six months ended June 30, 2005 were approximately $51 million. We expect to spend approximately $108 million for the remainder of 2005 for capital expenditures, consisting of approximately $28 million to expand the capacity on our systems and $80 million for maintenance capital. Approximately $21 million of our remaining 2005 expansion capacity expenditures relate to the Cadiz to Ehrenberg (Line 1903) project. We expect to fund capital expenditures through a combination of internally generated funds and/or by recovering amounts advanced to El Paso under its cash management program, if necessary.

Commitments and Contingencies

      See Item 1, Financial Statements, Note 3, which is incorporated herein by reference.

14

CAUTIONARY STATEMENTS FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

      This Report contains or incorporates by reference forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Where any forward-looking statement includes a statement of the assumptions or bases underlying the forward-looking statement, we caution that, while we believe these assumptions or bases to be reasonable and to be made in good faith, assumed facts or bases almost always vary from the actual results, and the differences between assumed facts or bases and actual results can be material, depending upon the circumstances. Where, in any forward-looking statement, we or our management express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the statement of expectation or belief will result or be achieved or accomplished. The words “believe,” “expect,” “estimate,” “anticipate” and similar expressions will generally identify forward-looking statements.

      With this in mind, you should consider the risks discussed elsewhere in this Report and other documents we file with the Securities and Exchange Commission from time to time.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

      Omitted from this Report pursuant to the reduced disclosure format permitted by General Instruction H to Form 10-Q.

Item 4.  Controls and Procedures

Material Weakness Previously Disclosed

      As discussed in our 2004 Annual Report on Form 10-K, we did not maintain effective controls as of December 31, 2004, over access to financial application programs and data in certain information technology environments. The remedial actions implemented in 2005 related to this material weakness are described below.

Evaluation of Disclosure Controls and Procedures

      As of June 30, 2005, we carried out an evaluation under the supervision and with the participation of our management, including our President and our Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures (pursuant to Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)). As discussed below, we have made various changes in our internal controls which we believe remediate the material weakness previously identified by the company. We are relying on those changes in internal controls as an integral part of our disclosure controls and procedures. Based upon the results of the evaluation of our disclosure controls and procedures and based upon our reliance on these revised internal controls, management, including our President and CFO, concluded that our disclosure controls and procedures were effective as of June 30, 2005.

Changes in Internal Control Over Financial Reporting

      During the first quarter of 2005, we implemented the following changes in our internal control over financial reporting:

•  Implemented automated and manual controls for our primary financial system to monitor unauthorized password changes; and

•  Developed a segregation of duties matrix for our primary financial system that documents existing role assignments.

      During the second quarter of 2005, we implemented the following changes in our internal control over financial reporting:

15

•  Performed an in-depth analysis of the company’s primary financial accounting system to examine existing functional access to identify any potentially incompatible duties.

•  Enhanced the segregation of duties matrix for our primary financial accounting system based on the in-depth analysis of user access.

•  Modified the primary financial accounting system to eliminate or modify potentially conflicting functionality.

•  Implemented a process to evaluate all new user access requests against segregation of duties matrices to ensure no new conflicts are created for our applications described above.

•  Separated security administration rights from system update capabilities for our applications described above.

•  Implemented monitoring procedures to monitor activities of security administration roles for our applications described above.

      We believe that the changes in our internal controls described above have remediated the material weakness. Our testing and evaluation of the operating effectiveness and sustainability of the changes in internal controls has not been completed at this time. As a result, we may identify additional changes that are required to remediate or improve our internal controls over financial reporting.

16

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

      See Part I, Item 1, Financial Statements, Note 3, which is incorporated herein by reference.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

      Omitted from this Report pursuant to the reduced disclosure format permitted by General Instruction H to Form 10-Q.

Item 3. Defaults Upon Senior Securities

      Omitted from this Report pursuant to the reduced disclosure format permitted by General Instruction H to Form 10-Q.

Item 4. Submission of Matters to a Vote of Security Holders

      Omitted from this Report pursuant to the reduced disclosure format permitted by General Instruction H to Form 10-Q.

Item 5. Other Information

      None.

Item 6. Exhibits

      Each exhibit identified below is filed as a part of this Report. Exhibits not incorporated by reference to a prior filing are designated by an “*”. Exhibits designated by “**” are furnished with this filing pursuant to Item 601(b)(32) of Regulation S-K. All exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

Exhibit
Number			Description
	*31	.A	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	*31	.B	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	**32	.A	Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	**32	.B	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

     Undertaking

      We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4)(iii), to furnish to the U.S. Securities and Exchange Commission, upon request, all constituent instruments defining the rights of holders of our long-term debt not filed herewith for the reason that the total amount of securities authorized under any of such instruments does not exceed 10 percent of our total consolidated assets.

17

SIGNATURES

      Pursuant to the requirements of the Securities Exchange Act of 1934, El Paso Natural Gas Company has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EL PASO NATURAL GAS COMPANY

Date: August 5, 2005

/s/JAMES J. CLEARY

James J. Cleary

Chairman of the Board and President

(Principal Executive Officer)

Date: August 5, 2005

/s/GREG G. GRUBER

Greg G. Gruber

Senior Vice President,

Chief Financial Officer and Treasurer

(Principal Financial and Accounting Officer)

18

EL PASO NATURAL GAS COMPANY

EXHIBIT INDEX

      Each exhibit identified below is filed as a part of this Report. Exhibits not incorporated by reference to a prior filing are designated by an “*”. Exhibits designated by “**” are furnished with this filing pursuant to Item 601(b)(32) of Regulation S-K. All exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

Exhibit
Number			Description
	*31	.A	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	*31	.B	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	**32	.A	Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	**32	.B	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.