UNITED STATES SECURITIES AND EXCHANGE COMMISSION

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-Q

(Mark One)

x COMBINED QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

~~SECURITIES~~For ~~EXCHANGE~~the ~~ACT~~quarterly OFperiod ~~1934~~ended September 30, 2003

For the quarterly period ended June 30, 2003

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 1-8847

TNP ENTERPRISES, INC.

(Exact name of registrant as specified in its charter)

Texas (State of incorporation) 75-1907501 (I.R.S. employer identification number)

Texas		75-1907501
(State of incorporation)		(I.R.S. employer identification number)

4100 International Plaza, P. O. Box 2943, Fort Worth, Texas 76113

(Address and zip code of principal executive offices)

Registrant’s telephone number, including area code 817-731-0099

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 ¨

TNP Enterprises, Inc. has no publicly traded shares of common stock outstanding.

Commission File Number: 2-97230

TEXAS-NEW MEXICO POWER COMPANY

(Exact name of registrant as specified in its charter)

Texas (State of incorporation) 75-0204070 (I.R.S. employer identification number)

Texas		75-0204070
(State of incorporation)		(I.R.S. employer identification number)

4100 International Plaza, P. O. Box 2943, Fort Worth, Texas 76113

(Address and zip code of principal executive offices)

Registrant’s telephone number, including area code 817-731-0099

TNP Enterprises, Inc. holds all 10,705 outstanding common shares of Texas-New Mexico Power Company.

TNP Enterprises, Inc. And Subsidiaries

Texas New-Mexico Power Company and Subsidiaries

Combined Quarterly Report on Form 10-Q for the period ended ~~June~~September 30, 2003

This Combined Quarterly Report on Form 10-Q is filed separately by TNP Enterprises, Inc., and Texas-New Mexico Power Company. Texas-New Mexico Power Company makes no representation as to information relating to TNP Enterprises, Inc., except as it may relate to Texas-New Mexico Power Company, or to any other affiliate or subsidiary of TNP Enterprises, Inc.

TABLE OF CONTENTS

PART 1. FINANCIAL STATEMENTS
Item 1.	Financial Statements.
	TNP Enterprises, Inc. (TNP) and Subsidiaries:
		Consolidated Statements of Income (Loss) Three and Six Month Periods Ended June 30, 2003 and 2002	3
		Consolidated Statements of Comprehensive Income (Loss) Three and Six Month Periods Ended June 30, 2003 and 2002	4
		Consolidated Statements of Cash Flows Six Month Periods Ended June 30, 2003 and 2002	5
		Consolidated Balance Sheets June 30, 2003, and December 31, 2002	6
	Texas-New Mexico Power Company (TNMP) and Subsidiaries:
		Consolidated Statements of Income Three and Six Month Periods Ended June 30, 2003 and 2002	7
		Consolidated Statements of Comprehensive Income Three and Six Month Periods Ended June 30, 2003 and 2002	8
		Consolidated Statements of Cash Flows Six Month Periods Ended June 30, 2003 and 2002	9
		Consolidated Balance Sheets June 30, 2003, and December 31, 2002	10
	Notes to Consolidated Financial Statements		11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		21
Item 4.	Controls and Procedures		32
		PART 2. OTHER INFORMATION
Item 1.	Legal Proceedings		33
Item 6.	Exhibits and Reports on Form 8-K		33
	(a)	Exhibit Index	33
	(b)	Reports on Form 8-K	33
	Statement Regarding Forward Looking Information		33
Signature page			34
Certifications			35

PART 1. FINANCIAL STATEMENTS


Item 1.	Financial Statements.

	TNP Enterprises, Inc. (TNP) and Subsidiaries:

	Consolidated Statements of Income (Loss) Three and Nine Month Periods Ended September 30, 2003 and 2002	3
	Consolidated Statements of Comprehensive Income (Loss) Three and Nine Month Periods Ended September 30, 2003 and 2002	4
	Consolidated Statements of Cash Flows Nine Month Periods Ended September 30, 2003 and 2002	5
	Consolidated Balance Sheets September 30, 2003, and December 31, 2002	6

	Texas-New Mexico Power Company (TNMP) and Subsidiaries:

	Consolidated Statements of Income Three and Nine Month Periods Ended September 30, 2003 and 2002	7
	Consolidated Statements of Comprehensive Income Three and Nine Month Periods Ended September 30, 2003 and 2002	8
	Consolidated Statements of Cash Flows Nine Month Periods Ended September 30, 2003 and 2002	9
	Consolidated Balance Sheets September 30, 2003, and December 31, 2002	10

	Notes to Consolidated Interim Financial Statements	11

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24

Item 4.	Controls and Procedures	36

PART 2. OTHER INFORMATION

Item 1.	Legal Proceedings	37

Item 6.	Exhibits and Reports on Form 8-K	37

	(a) Exhibit Index	37

	(b) Reports on Form 8-K	37

	Statement Regarding Forward Looking Information	37

Signature page		38

Certifications		39

-2-

TNP ENTERPRISES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(Unaudited)

Three Months Ended June 30,

Six Months Ended June 30,

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

2003

2002

2003

2002

(In thousands)

OPERATING REVENUES

~~223~~252,~~525~~687

~~173~~229,~~376~~161

~~407~~659,~~246~~933

~~294~~523,~~041~~202

OPERATING EXPENSES:

Purchased power and fuel

~~138~~143,~~024~~144

87108,~~598~~642

~~274~~418,~~993~~137

~~141~~250,~~853~~495

Other operating and maintenance

5455,~~948~~837

4151,~~722~~676

~~107~~162,~~010~~847

71122,~~053~~730

Accrual for payment to TNMP (Note 2)

~~419~~3,589

—

~~419~~4,008

—

Depreciation

7,~~196~~277

76,~~026~~857

1421,~~320~~597

1420,~~048~~904

Credit for recovery of stranded plant

—

(733

)

Taxes other than income taxes

68,~~939~~328

79,~~739~~245

1322,~~709~~037

1525,~~807~~051

Total operating expenses

~~207~~218,~~526~~175

~~144~~176,~~085~~420

~~410~~628,~~451~~626

~~242~~418,~~028~~447

OPERATING INCOME (LOSS)

15,999

29,291

(3,205

)

52,013

OPERATING INCOME

34,512

52,741

31,307

104,755

INTEREST CHARGES AND OTHER INCOME AND DEDUCTIONS:

Interest on long-term debt

1615,~~065~~416

13,~~725~~589

2843,~~499~~915

2741,~~444~~033

Other interest and amortization of debt-related costs

2,~~249~~669

1,~~326~~918

36,~~366~~035

24,~~602~~520

Other income and deductions, net

(~~505~~787

)

(~~185~~19

)

(~~875~~1,663

)

(~~287~~306

)

Total

17,~~809~~298

1415,~~866~~488

3048,~~990~~287

2945,~~759~~247

INCOME (LOSS) BEFORE INCOME TAXES

(117,~~810~~214

)

1437,~~425~~253

(3416,~~195~~980

)

2259,~~254~~508

Income taxes

~~(792~~6,698

)

513,~~210~~922

(136,~~151~~452

)

721,~~870~~792

NET INCOME (LOSS)

(110,~~018~~516

)

923,~~215~~331

(2110,~~044~~528

)

1437,~~384~~716

Dividends on preferred stock and other

5,515

4,808

1016,~~664~~179

914,~~299~~108

INCOME (LOSS) APPLICABLE TO COMMON STOCK

(65,~~533~~001

)

418,~~407~~523

(3126,~~708~~707

)

523,~~085~~608

The accompanying notes are an integral part of these consolidated financial statements.

-3-

TNP ENTERPRISES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three Months Ended June 30,					Six Months Ended June 30,
	Three Months EndedSeptember 30,					Nine Months EndedSeptember 30,
	2003			2002		2003			2002
	(In thousands)
NET INCOME (LOSS)	$	(110,~~018~~516	)	$	923,~~215~~331	$	(2110,~~044~~528	)	$	1437,~~384~~716
Cash flow hedges, net of tax:
Interest rate hedge, net of reclassification adjustment (Note 4)		~~(990~~364	)		—		(1,~~635~~271	)		—
Gas hedge		762			—		(2,262	)		—
Gas hedge (Note 4)		(2,563	)		—		(4,825	)		—
Total cash flow hedges		(~~228~~2,199	)		—		(36,~~897~~096	)		—
COMPREHENSIVE INCOME (LOSS)	$	(18,~~246~~317	)	$	923,~~215~~331	$	(2416,~~941~~624	)	$	1437,~~384~~716

The accompanying notes are an integral part of these consolidated financial statements.

-4-

TNP ENTERPRISES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	Nine Months Ended September 30,
	2003			2002
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Cash received from sales to customers	$	~~362~~613,~~723~~008		$	~~202~~394,~~448~~144
Purchased power and fuel costs paid		(~~233~~389,~~001~~594	)		(~~138~~240,~~283~~935	)
Natural gas option premiums paid		(19,~~147~~642	)		—
Cash paid for payroll and to other suppliers		(92140,~~703~~041	)		(5794,~~230~~779	)
Interest paid, net of amounts capitalized		(3239,~~137~~023	)		(2837,~~707~~991	)
Income taxes received (paid)		1,~~044~~172			(3,~~292~~848	)
Other taxes paid		(1519,~~468~~877	)		(2127,~~997~~118	)
Other operating cash receipts and payments, net		~~104~~164			(71106	)
NET CASH USED IN OPERATING ACTIVITIES		(28,585	)		(47,132	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		6,167			(10,633	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and other investing activities		(2028,~~075~~361	)		(1425,~~827~~495	)
NET CASH USED IN INVESTING ACTIVITIES		(2028,~~075~~361	)		(1425,~~827~~495	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of TNMP senior notes, net of discount		248,923			—
Issuances:
Borrowings from (repayments to) TNMP/First Choice credit facility—net		(164,000	)		67,000
TNMP senior notes, net of discount		248,923			—
TNP senior secured credit facility		112,500			—
Borrowings from (repayments to) TNMP/First Choice credit facility—net		(171,000	)		56,000
Other		—			(5,839	)
Redemptions:
TNP term loan		(~~800~~71,300	)		(~~800~~1,200	)
Deferred costs associated with financings		(2,332	)		—
TNP senior secured credit facility		(281	)		—
NET CASH PROVIDED BY FINANCING ACTIVITIES		81,791			60,361
Deferred costs associated with financings		(5,534	)		(570	)
NET CHANGE IN CASH AND CASH EQUIVALENTS		33,131			(1,598	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		113,308			48,391
NET CHANGE IN CASH AND CASH EQUIVALENTS		91,114			12,263
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		16,690			14,145
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	49107,~~821~~804		$	1226,~~547~~408
RECONCILIATION OF NET INCOME (LOSS) TO NET
RECONCILIATION OF NET INCOME (LOSS) TO NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES:
CASH USED IN OPERATING ACTIVITIES:
Net income (loss)	$	(10,528	)	$	37,716
Net income (loss)	$	(21,044	)	$	14,384
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Accrual for payment to TNMP		4,008			—
Accrual for payment to TNMP		419			—
Depreciation		21,597			20,904
Depreciation		14,320			14,048
Credit for Texas system benefit fund regulatory asset		(3,960	)		—
Credit for recovery of stranded plant		—			(733	)
Amortization of debt-related costs and other deferred charges		36,~~205~~171			23,~~111~~738
Allowance for funds used during construction		(~~457~~693	)		(~~161~~309	)
Deferred income taxes		~~118~~1,573			513,~~487~~827
Investment tax credits		(~~397~~635	)		(~~780~~2,352	)
Deferred purchased power and fuel costs		12,~~324~~513			1011,~~641~~756
Cash flows impacted by changes in current assets and liabilities:
Accounts receivable		(2921,~~317~~815	)		(84116,~~605~~795	)
Accounts payable		4320,~~175~~432			1022,~~245~~249
Accrued interest		~~705~~9,333			(13,~~077~~336	)
Accrued taxes		(134,~~900~~622	)		(54,~~898~~624	)
Changes in other current assets and liabilities		(165,~~798~~131	)		(109,~~631~~328	)
Interest rate lock on issuance of TNMP senior notes		(4,162	)		—
Other, net		(57,~~776~~914	)		~~(163~~734	)
NET CASH USED IN OPERATING ACTIVITIES	$	(28,585	)	$	(47,132	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	6,167		$	(10,633	)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Payment of dividends on preferred stock by issuance of additional preferred shares	$	10,080		$	8,763

The accompanying notes are an integral part of these consolidated financial statements.

-5-

TNP ENTERPRISES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	June 30, 2003 (Unaudited)			December 31, 2002
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	49,821		$	16,690
Accounts receivable		123,701			94,384
Materials and supplies, at lower of cost or market		1,035			992
Deferred purchased power and fuel costs		581			1,320
Accumulated deferred income taxes		120			122
Gas options		12,219			—
Other current assets		2,232			1,202
Total current assets		189,709			114,710
UTILITY PLANT:
Electric plant		588,701			569,615
Construction work in progress		13,133			11,707
Total		601,834			581,322
Less accumulated depreciation		88,951			74,632
Net utility plant		512,883			506,690
LONG-TERM AND OTHER ASSETS:
Other property and investments, at cost		1,273			1,273
Goodwill		270,256			270,256
Recoverable stranded costs		298,748			298,748
Regulatory tax assets		1,242			914
Deferred charges		45,081			46,334
Total long-term and other assets		616,600			617,525
	$	1,319,192		$	1,238,925
LIABILITIES AND SHAREHOLDER'S EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt	$	8,600		$	172,600
Accounts payable		85,162			41,987
Accrued interest		13,411			12,706
Accrued taxes		583			14,483
Customers' deposits		6,478			6,438
Other current liabilities		7,470			11,016
Total current liabilities		121,704			259,230
LONG-TERM AND OTHER LIABILITIES:
Deferred purchased power and fuel costs		24,241			23,656
Accumulated deferred income taxes		132,545			134,498
Accumulated deferred investment tax credits		18,936			19,333
Deferred credits and other liabilities		48,795			52,478
Total long-term and other liabilities		224,517			229,965
LONG-TERM DEBT, LESS CURRENT MATURITIES		767,377			519,195
REDEEMABLE CUMULATIVE PREFERRED STOCK		151,116			140,452
COMMON SHAREHOLDER'S EQUITY
Common shareholder's equity:
Common stock—no par value per share.
Authorized 1,000,000 shares; issued 100 shares		100,000			100,000
Accumulated deficit		(39,922	)		(8,214	)
Accumulated other comprehensive loss-gas hedge		(2,262	)		—
Accumulated other comprehensive loss-other		(3,338	)		(1,703	)
Total common shareholder's equity		54,478			90,083
COMMITMENTS AND CONTINGENCIES (Note 7)
	$	1,319,192		$	1,238,925

(Unaudited)

	September 30, 2003			December 31, 2002
	(In thousands)
*ASSETS*

CURRENT ASSETS:
Cash and cash equivalents	$	107,804		$	16,690
Accounts receivable		116,199			94,384
Materials and supplies, at lower of cost or market		1,040			992
Deferred purchased power costs		—			1,320
Accumulated deferred income taxes		141			122
Gas options		2,581			—
Other current assets		2,159			1,202

Total current assets		229,924			114,710

UTILITY PLANT:
Electric plant		596,579			569,615
Construction work in progress		13,798			11,707

Total		610,377			581,322
Less accumulated depreciation		96,229			74,632

Net utility plant		514,148			506,690


LONG-TERM AND OTHER ASSETS:
Other property and investments, at cost		1,273			1,273
Goodwill		270,256			270,256
Recoverable stranded costs		298,748			298,748
Regulatory tax assets		1,423			914
Deferred charges		47,458			46,334

Total long-term and other assets		619,158			617,525

	$	1,363,230		$	1,238,925

*LIABILITIES AND SHAREHOLDER'S EQUITY*

CURRENT LIABILITIES:
Current maturities of long-term debt	$	1,125		$	172,600
Accounts payable		62,419			41,987
Accrued interest		22,039			12,706
Accrued taxes		9,862			14,483
Customers' deposits		6,280			6,438
Deferred purchased power costs		528			—
Other current liabilities		9,629			11,016

Total current liabilities		111,882			259,230

LONG-TERM AND OTHER LIABILITIES:
Deferred purchased power and fuel costs		24,321			23,656
Accumulated deferred income taxes		132,826			134,498
Accumulated deferred investment tax credits		18,698			19,333
Deferred credits and other liabilities		51,947			52,478

Total long-term and other liabilities		227,792			229,965

LONG-TERM DEBT, LESS CURRENT MATURITIES		809,645			519,195

REDEEMABLE CUMULATIVE PREFERRED STOCK		156,631			140,452

COMMON SHAREHOLDER'S EQUITY
Common shareholder's equity:
Common stock—no par value per share.
Authorized 1,000,000 shares; issued 100 shares		100,000			100,000
Accumulated deficit		(34,921	)		(8,214	)
Accumulated other comprehensive loss-gas hedge		(4,825	)		—
Accumulated other comprehensive loss-other		(2,974	)		(1,703	)

Total common shareholder's equity		57,280			90,083

COMMITMENTS AND CONTINGENCIES (Note 7)

	$	1,363,230		$	1,238,925

The accompanying notes are an integral part of these consolidated financial statements.

-6-

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

(a wholly owned subsidiary of TNP Enterprises, Inc.)

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

Three Months EndedJune 30,

Six Months Ended June 30,

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

2003

2002

2003

2002

(In thousands)

OPERATING REVENUES

6769,~~761~~953

7686,~~568~~367

~~129~~199,~~126~~079

~~154~~240,~~146~~513

OPERATING EXPENSES:

Purchased power and fuel

1617,~~342~~542

2526,~~971~~588

3350,~~301~~843

5683,~~505~~093

Other operating and maintenance

1713,~~217~~554

1820,~~661~~402

3347,~~990~~544

3657,~~831~~233

Depreciation of utility plant

7,~~122~~197

6,~~966~~795

1421,~~177~~374

1320,~~930~~725

Credit for recovery of stranded plant

—

(733

)

Taxes other than income taxes

5,~~055~~976

57,~~981~~019

1016,~~112~~088

1219,~~730~~749

Total operating expenses

4544,~~736~~269

5760,~~579~~804

91135,~~580~~849

~~119~~180,~~263~~067

OPERATING INCOME

2225,~~025~~684

1825,~~989~~563

3763,~~546~~230

3460,~~883~~446

INTEREST CHARGES AND OTHER INCOME AND DEDUCTIONS:

Interest on long-term debt

76,~~792~~592

4,~~719~~579

1218,~~078~~670

913,~~303~~883

Other interest and amortization of debt-related costs

~~1,020~~277

~~859~~946

1,~~700~~977

12,~~741~~686

Other income and deductions, net

(~~501~~783

)

(~~197~~60

)

(~~847~~1,631

)

(~~255~~315

)

Total

86,~~311~~086

5,~~381~~465

1219,~~931~~016

1016,~~789~~254

INCOME BEFORE INCOME TAXES

1319,~~714~~598

1320,~~608~~098

2444,~~615~~214

2444,~~094~~192

Income taxes

47,~~882~~295

46,~~574~~995

816,~~735~~031

714,~~935~~930

NET INCOME

812,~~832~~303

913,~~034~~103

1528,~~880~~183

1629,~~159~~262

The accompanying notes are an integral part of these consolidated financial statements.

-7-

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

(a wholly owned subsidiary of TNP Enterprises, Inc.)

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,							Six Months Ended June 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
	2003			2002	~~2002~~		2003	~~2003~~			2002	~~2002~~
	(In thousands)
NET INCOME	$	812,~~832~~303		$	$13,103	~~9,034~~	$	$28,183	~~15,880~~		$	$29,262	~~16,159~~
Cash flow hedges, net of tax:
Interest rate hedge, net of reclassification adjustment (Note 4)		~~(941~~129	)		—	—		(1,240	~~(1,369~~)	)		—	—
Total cash flow hedges		~~(941~~129	)		—	—		(1,240	~~(1,369~~)	)		—	—
COMPREHENSIVE INCOME	$	712,~~891~~432		$	$13,103	~~9,034~~	$	$26,943	~~14,511~~		$	$29,262	~~16,159~~

The accompanying notes are an integral part of these consolidated financial statements.

-8-

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

(a wholly owned subsidiary of TNP Enterprises, Inc.)

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	Nine Months EndedSeptember 30,
	2003			2002
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Cash received from sales to customers	$	~~118~~188,~~807~~758		$	~~103~~194,~~045~~272
Purchased power and fuel costs paid		(3349,~~348~~409	)		(75102,~~354~~163	)
Cash paid for payroll and to other suppliers		(3142,~~245~~342	)		(3245,~~333~~722	)
Interest paid, net of amounts capitalized		(1521,~~884~~365	)		(917,~~765~~344	)
Income taxes paid		(710,~~041~~103	)		(34,~~626~~715	)
Other taxes paid		(1316,~~404~~034	)		(2125,~~887~~370	)
Other operating cash receipts and payments, net		71133			(~~106~~163	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		1749,~~956~~638			(401,~~026~~205	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(1928,~~848~~087	)		(1425,~~514~~028	)
NET CASH USED IN INVESTING ACTIVITIES		(1928,~~848~~087	)		(1425,~~514~~028	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid on common stocks		(18,400	)		(1418,000	)
Issuance of senior notes, net of discount		248,923			—
Borrowings from (repayments to) credit facility—net		(171,000	)		7362,000
Deferred expenses associated with financings		(1,~~407~~583	)		~~130~~195
Capitalization of First Choice Power		—			(23,000	)
Notes issued (repaid) to affiliate		(14,557	)		195,~~000~~900
Other		—			(5,839	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		43,~~559~~383			4921,~~291~~256
NET CHANGE IN CASH AND CASH EQUIVALENTS		4164,~~667~~934			(54,~~249~~977	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		284			5,634
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	4165,~~951~~218		$	~~385~~657
RECONCILIATION OF NET INCOME TO NET
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES:
Net income	$	1528,~~880~~183		$	1629,~~159~~262
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation of utility plant		1421,~~177~~374			1320,~~930~~725
Credit for Texas system benefit fund regulatory asset		(3,960	)		—
Credit for recovery of stranded plant		—			(733	)
Amortization of debt-related costs and other deferred charges		12,~~546~~207			1,~~146~~723
Allowance for funds used during construction		(~~457~~693	)		(~~161~~309	)
Deferred income taxes		~~540~~5,427			512,~~911~~094
Investment tax credits		(~~397~~635	)		(~~780~~1,170	)
Deferred purchased power and fuel costs		12,~~324~~513			1011,~~641~~756
Cash flows impacted by changes in current assets and liabilities:
Accounts receivable		~~(670~~2,990	)		(4131,~~491~~859	)
Accounts payable		(~~497~~879	)		(19,~~278~~186	)
Accrued interest		~~529~~1,655			(~~173~~2,986	)
Accrued taxes		~~(2,238~~530	)		(96,~~582~~123	)
Changes in other current assets and liabilities		(54,~~009~~316	)		(1615,~~483~~099	)
Interest rate lock on issuance of senior notes		(4,162	)		—
Other, net		(~~2,610~~596	)		~~868~~700
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	1749,~~956~~638		$	(401,~~026~~205	)

The accompanying notes are an integral part of these consolidated financial statements.

-9-

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

(a wholly owned subsidiary of TNP Enterprises, Inc.)

CONSOLIDATED BALANCE SHEETS

	June 30, 2003 (Unaudited)			December 31, 2002
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	41,951		$	284
Accounts receivable		34,348			33,678
Materials and supplies, at lower of cost or market		1,035			992
Deferred purchased power and fuel costs		581			1,320
Accumulated deferred income taxes		70			70
Other current assets		1,158			612
Total current assets		79,143			36,956
UTILITY PLANT:
Electric plant		786,336			770,960
Construction work in progress		13,135			11,707
Total		799,471			782,667
Less accumulated depreciation		289,452			278,757
Net utility plant		510,019			503,910
LONG-TERM AND OTHER ASSETS:
Other property and investments, at cost		343			343
Recoverable stranded costs		298,748			298,748
Regulatory tax assets		1,241			913
Deferred charges		22,320			21,935
Total long-term and other assets		322,652			321,939
	$	911,814		$	862,805
LIABILITIES AND SHAREHOLDER’S EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt	$	—		$	171,000
Notes payable to affiliate		—			14,557
Accounts payable		9,046			9,543
Accrued interest		5,874			5,345
Accrued taxes		7,685			9,923
Customers’ deposits		637			1,092
Other current liabilities		5,207			9,172
Total current liabilities		28,449			220,632
LONG-TERM AND OTHER LIABILITIES:
Deferred purchased power and fuel costs		24,241			23,656
Accumulated deferred income taxes		148,995			148,971
Accumulated deferred investment tax credits		18,936			19,333
Deferred credits and other liabilities		20,611			24,724
Total long-term and other liabilities		212,783			216,684
LONG-TERM DEBT, LESS CURRENT MATURITIES		423,477			174,495
COMMON SHAREHOLDER’S EQUITY:
Common stock, $10 par value per share
Authorized 12,000,000 shares; issued 10,705 shares		107			107
Capital in excess of par value		197,751			197,751
Retained earnings		51,996			54,516
Accumulated other comprehensive loss		(2,749	)		(1,380	)
Total common shareholder’s equity		247,105			250,994
COMMITMENTS AND CONTINGENCIES (Note 7)
	$	911,814		$	862,805

(Unaudited)

	September 30, 2003			December 31, 2002
	(In thousands)
*ASSETS*

CURRENT ASSETS:
Cash and cash equivalents	$	65,218		$	284
Accounts receivable		30,688			33,678
Materials and supplies, at lower of cost or market		1,040			992
Deferred purchased power costs		—			1,320
Accumulated deferred income taxes		70			70
Other current assets		979			612

Total current assets		97,995			36,956


UTILITY PLANT:
Electric plant		792,213			770,960
Construction work in progress		13,800			11,707

Total		806,013			782,667
Less accumulated depreciation		294,697			278,757

Net utility plant		511,316			503,910


LONG-TERM AND OTHER ASSETS:
Other property and investments, at cost		343			343
Recoverable stranded costs		298,748			298,748
Regulatory tax assets		1,423			913
Deferred charges		27,577			21,935

Total long-term and other assets		328,091			321,939

	$	937,402		$	862,805

*LIABILITIES AND SHAREHOLDER'S EQUITY*

CURRENT LIABILITIES:
Current maturities of long-term debt	$	—		$	171,000
Notes payable to affiliate		—			14,557
Accounts payable		8,664			9,543
Accrued interest		7,000			5,345
Accrued taxes		10,453			9,923
Customers' deposits		685			1,092
Deferred purchased power costs		528			—
Other current liabilities		16,678			9,172

Total current liabilities		44,008			220,632


LONG-TERM AND OTHER LIABILITIES:
Deferred purchased power and fuel costs		24,321			23,656
Accumulated deferred income taxes		154,144			148,971
Accumulated deferred investment tax credits		18,698			19,333
Deferred credits and other liabilities		24,142			24,724

Total long-term and other liabilities		221,305			216,684


LONG-TERM DEBT, LESS CURRENT MATURITIES		423,552			174,495


COMMON SHAREHOLDER'S EQUITY:
Common stock, $10 par value per share
Authorized 12,000,000 shares; issued 10,705 shares		107			107
Capital in excess of par value		197,751			197,751
Retained earnings		53,299			54,516
Accumulated other comprehensive loss		(2,620	)		(1,380	)

Total common shareholder's equity		248,537			250,994


COMMITMENTS AND CONTINGENCIES (Note 7)

	$	937,402		$	862,805

The accompanying notes are an integral part of these consolidated financial statements.

-10-

TNP Enterprises Inc. and Subsidiaries

Texas-New Mexico Power Company and Subsidiaries

Notes to Consolidated Interim Financial Statements

Note 1. Interim Financial Statements

The interim consolidated financial statements of TNP and subsidiaries, and TNMP and subsidiaries, are unaudited and contain all adjustments (consisting primarily of normal recurring accruals) necessary for a fair statement of the results for the interim periods presented. Results for interim periods are not necessarily indicative of results to be expected for a full year or for previously reported periods due in part to seasonal revenue fluctuations. It is suggested that these consolidated interim financial statements be read in conjunction with the audited consolidated financial statements and notes thereto included in TNP’s and TNMP’s 2002 Combined Annual Report on Form 10-K.

Prior period statements have been reclassified in order to be consistent with current period presentation. The reclassification had no effect on net income or common shareholder’s equity.

Note 2. Regulatory Matters

Texas

Retail Competition. As reported in the 2002 Combined Annual Report on Form 10-K, the Texas electricity market has been open to retail competition since January 1, 2002. In accordance with Senate Bill 7, the legislation that established retail competition, TNMP provides transmission and distribution services at regulated rates to customers within its service area. While TNMP provides transmission and distribution services to individual consumers, its revenues are collected from the various retail electric providers that provide electric service within TNMP’s service area.

First Choice Power (First Choice), TNMP’s affiliated retail electric provider, performs activities related to the sale of electricity to retail customers in Texas. The operations of First Choice are included in the consolidated financial statements of TNP.

First Choice must offer former TNMP customers whose loads are less than 1 megawatt a regulated price, commonly called the “price-to-beat.” The price-to-beat will be offered through December 31, 2006, and First Choice cannot offer former TNMP customers any other rate before the loss of 40 percent of the energy consumed by its price-to-beat customers, or January 1, 2005, whichever occurs first. In October 2003, TNMP filed a report with the PUCT stating that First Choice had lost more than 40 percent of the energy consumed by its small commercial price-to-beat customers. First Choice remains below the 40 percent loss threshold with respect to residential price-to-beat customers. The TNMP report is subject to PUCT review and approval. TNMP and First Choice do not expect Public Utility Commission of Texas (PUCT) action allowing First Choice to offer rates other than the price-to-beat prior to December 2003.

First Choice is responsible for energy supply related to the sale of electricity to retail customers in Texas. Senate Bill 7 contains no provisions for the specific recovery of fuel and purchased power costs, although First Choice can request that the ~~Public Utility Commission of Texas (~~PUCT) change the price-to-beat twice a year to recognize changes in natural gas prices. The rates charged to new customers acquired by First Choice outside of TNMP’s service territory are not regulated by the PUCT, but are negotiated with each customer. As a result, changes in fuel and purchased power costs will affect First Choice’s operating results.

Price-to-Beat Fuel Factor. In response to increases in natural gas prices beginning in December 2002, First Choice has requested and implemented several changes in the price-to-beat fuel factor. The changes in the price-to-beat fuel factor are shown in the following table (dollar amounts in millions):

Date Filed	Date Approved	Percentage Increase in Fuel Factor	Estimated Increase in Annual Revenue
December 2002	February 2003	19%	$17.0
February 2003	March 2003	14%	15.0
March 2003	April 2003	15%	19.0

While First Choice may request only two changes to the price-to-beat fuel factor in a year, it may also file with the PUCT to change the overall price-to-beat in emergency circumstances in order to preserve its financial integrity.

-11-

In March 2003, the PUCT adopted a new rule governing the price-to-beat fuel factor. The new rule would limit the ability of First Choice to respond to changes in the market price of natural gas by causing First Choice to calculate proposed changes to the price-to-beat fuel factor based on natural gas prices over a twenty-day period, as opposed to the previous ten-day period. In addition, gas prices must change by five percent before the price-to-beat fuel factor can be changed under the new rule, rather than four percent previously. The PUCT also affirmed its authority to reduce the price-to-beat fuel factor infollowing the 2004 true-up proceeding. The rule would require the PUCT to reduce the price-to-beat fuel factor “if natural gas prices are below the prices embedded in the then-current factors.” The new rule took ~~effect~~ effect in April 2003.

Clawback. Senate Bill 7 includes a a provision, commonly known as the “clawback,” that would require First Choice to credit TNMP the difference between the price-to-beat and the market price of electricity during the years 2002 and 2003. ~~TNMP~~The PUCT will ~~include~~determine the amount of the clawback credit in the true-up proceeding that will occur in 2004. The maximum credit to TNMP is limited to $150 multiplied by the difference between the number of First Choice price-to-beat customers and the number of First Choice competitively acquired residential and small commercial customers as of January 1, 2004. Based on current ~~assumptions~~projections, First Choice estimates that its clawback liability will be $1316.17 million. Accordingly, First Choice increased its pre-tax reserve of $12.7 million recorded at December 31, 2002, by $0.4.0 million infor the ~~second~~nine ~~quarter~~months ofended ~~2003.~~September To30, ~~the extent that acquisition of competitive customers and loss of price-to-beat customers differs from current projections~~2003, anwhich ~~adjustment~~includes toa ~~the clawback liability could be required~~$3.6 ~~First Choice~~million ~~estimates that significant variations from its current projections could~~ increase ~~its~~in ~~clawback~~the ~~liability~~third byquarter upof ~~to an additional $6~~2003.1 ~~million.~~

Final Fuel Reconciliation. Prior to the beginning of retail competition, TNMP recovered fuel and the energy-related portion of purchased power costs from customers through the fuel adjustment clause authorized by the PUCT. The demand-related portion of purchased power was recovered through base rates and, unlike the fuel and energy-related portion, was not subject to adjustment or future reconciliation. As of ~~June~~September 30, 2003, TNMP had an over-recovered balance of fuel and energy-related purchased power costs of $24.23 million. On April 1, 2003, TNMP filed an application with the PUCT for the final reconciliation of its fuel and energy-related purchased power costs. This proceeding will reconcile fuel and energy-related purchased power costs incurred between January 1, 2000, and December 31, 2001, in accordance with the provisions of Senate Bill 7. The balance of fuel and energy-related purchased power costs resulting from the final fuel reconciliation will be included in the true-up proceeding for stranded costs that will occur in 2004. Subject to the results of the final fuel reconciliation, any over-recovered balance may reduce the amount of stranded costs TNMP would be entitled to recover from its transmission and distribution customers.

The final fuel reconciliation has been referred to the State Office of Administrative Hearings (SOAH). ~~The schedule that~~ SOAH ~~adopted~~held ~~for~~hearings on the final fuel reconciliation ~~calls~~in ~~for~~August ~~hearings~~2003. inIn ~~August~~October 2003, ~~and~~the administrative law judge assigned to this proceeding extended the regulatory deadline for a final order inbeyond the original date for this decision, which was October 2003. TNMP cannot predict when a decision in the fuel reconciliation will be rendered.

2001 Excess Earnings. As reported in the 2002 Combined Annual Report on Form 10-K, TNMP filed a petition in November 2002 asking the PUCT to allow TNMP to establish a regulatory asset of $3.1 million, the amount of its 2001 Annual Report earnings deficiency that is attributable to System Benefit Fund payments. AIn ~~hearing~~August on2003, the ~~merits~~PUCT ofapproved ~~the~~TNMP’s petition ~~was~~and ~~held~~granted init ~~April~~authority ~~2003.~~to ~~TNMP~~record ~~expects~~the aregulatory ~~decision~~asset inand ~~this~~accrue ~~matter~~a ~~during~~return retroactive ~~the~~to ~~third~~December ~~quarter~~31, ~~of 2003~~2001. ~~Should~~ ~~the~~The ~~PUCT~~order ~~approve~~requires TNMP’s ~~petition,~~to seek recovery of the regulatory asset ~~established~~in ~~would~~a ~~result~~base inrate aproceeding ~~reduction~~instituted on or before July 1, 2005, or forfeit the right to seek recovery of ~~operating~~the ~~expenses~~regulatory asset.

As a result of the PUCT order, TNMP’s pre-tax net income for the three and nine months ended September 30, 2003, increased $3.6 million ($2.3 million after tax).

Merger Commitments. As conditions for approval of the Merger, TNMP made a number of commitments to both the PUCT and New Mexico Public Regulation Commission (NMPRC). The commitments cover a wide range of financial, operational, electric reliability, and other standards with which TNMP agreed to comply. TNMP made 55 commitments in New Mexico and Texas, of which 47 are currently in effect. TNMP monitors compliance on a monthly basis and could be subject to financial penalties for non-compliance with certain commitments. During the years ended December 31, 2002 and 2001, TNMP was not in compliance with certain commitments regarding electric reliability standards in Texas, and as a result paid $0.2 million in penalties during the second quarter of 2003.

2004 True-Up Proceeding. The PUCT established the schedule for the stranded cost true-up proceeding that will occur in 2004. TNMP is required to file its stranded cost true up under the provisions of Senate Bill 7 between January 12 and January 22, 2004.

~~New~~Cities ~~Mexico~~Rate Review. In October 2003, the City of Dickinson passed an ordinance requiring TNMP to file certain financial information with the city so that the city may determine whether TNMP’s transmission and distribution rates are reasonable. TNMP cannot predict what action the city may take, or what effects any such action may have on its financial position, cash flows, or results of operation at this time.

Reorganization of New Mexico Operations. In June 2003, TNMP asked the NMPRC for the authority to place its New Mexico operations in a separate wholly owned subsidiary of TNMP. The Federal Energy Regulatory Commission must also approve the request.

-12-

New Mexico

Affiliated Guarantee. In October 2003, the NMPRC granted TNMP’s request for the authority to extend a portion of the guarantees that TNMP provides for certain power supply obligations of First Choice. The NMPRC originally granted TNMP authority to guarantee up to $75 million of First Choice obligations in December 2001. That authority was set to expire at the end of October 2003. TNMP agreed to a number of conditions in return for the authority to guarantee First Choice’s power supply obligations, including the following:

•

TNMP withdrew the request it made in June 2003 for authority to place its New Mexico operations in a separate wholly owned subsidiary of TNMP.

•

TNMP’s authority to guarantee First Choice’s power supply obligations is limited to $50 million. That amount will consist of TNMP’s $25 million guarantee of First Choice’s performance under the Constellation power supply agreement and no more than $25 million in guarantees of First Choice’s performance under additional power supply agreements.

•

TNMP’s authority to guarantee First Choice’s power supply obligations ends on December 31, 2004, or on the date that First Choice executes power supply agreements that no longer require TNMP’s guarantee, whichever occurs first.

•

TNMP will not seek to recover any liability for performance under the guarantees from its New Mexico customers.

•

During the term of the guarantee, TNMP will not seek to recover a cost of capital from its New Mexico customers other than the cost of capital that would be available to TNMP if it had an investment grade credit rating, regardless of TNMP’s actual credit rating.

Reorganization of New Mexico Operations. As noted above, TNMP withdrew its motion for authority to place its New Mexico operations in a separate wholly owned subsidiary of TNMP in October 2003 when the NMPRC granted TNMP’s request for authority to guarantee certain power supply obligations of First Choice.

Restructuring. During its 2003 regular session, the New Mexico Legislature repealed the New Mexico Restructuring Act, which had established a framework for retail competition in the New Mexico electricity market. Retail competition was scheduled to begin no earlier than 2007 prior to the repeal. Accordingly, TNMP’s New Mexico operations will continue to be subject to cost-based regulation and the repeal had no effect on the financial position, results of operations or cash flows of TNMP, as retail competition had not been implemented yet.

Note 3. Accounting Developments

Accounting for Goodwill and Other Intangible Assets

Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets,” which TNP adopted on January 1, 2002, requires that TNP test the goodwill recorded as a result of the Merger for impairment at least annually. TNP may be required to test goodwill for impairment between annual tests if “an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount.” In June 2003, TNP tested the goodwill related to the Merger based on the current five-year forecast that reflects changes regarding customer growth and other factors at First Choice resulting from current market conditions. TNP concluded that, based on the current forecast, the fair value of the goodwill related to the Merger exceeded its carrying value.

Accounting for Asset Retirement Obligations

TNP and TNMP adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” on January 1, 2003. The adoption had no impact on the financial position, results of operations, or cash flows of TNP and TNMP. As a result of the adoption of SFAS 143, TNP and TNMP identified costs recorded in accumulated depreciation related to inclusion of removal costs of utility plant in TNMP’s rates by the PUCT and NMPRC. Such costs do not arise from legal obligations. Rather, they represent long-standing regulatory policy to include charges for removal costs of utility plant in accumulated depreciation. As of ~~June~~September 30, 2003, $37.19 million of estimated utility plant removal costs were included in accumulated depreciation.

Derivative Instruments and Hedging Activities

TNP and TNMP adopted SFAS No.149, “Amendments of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS 149), on June 30, 2003. The adoption had no impact on the financial position, results of operations, or cash flows of TNP and TNMP. SFAS 149 amends SFAS 133 for decisions made by the Derivatives Implementation Group that required amendments to SFAS 133, in connection with other Financial Accounting Standards Board (FASB) projects regarding financial instruments, and for implementation issues regarding the application of the definition of a derivative.

Note 4. Derivative Instruments and Hedging Activities

Hedging Activities

TNP, TNMP and First Choice may enter into derivative instruments, including options and swaps, to manage risks related to changes in interest rates and commodity prices. At the inception of any such transactions, TNP, TNMP, and First Choice document relationships between the hedging instruments and the items being hedged. The documentation includes the strategy that supports executing the specific transaction.

TNP Interest Rate Swaps. In October 2002, TNP executed a $70 million interest rate swap transaction designed to manage interest rate risk associated with the Senior Credit Facility. The swap will terminate in October 2004. Under the terms of the swap, TNP pays a fixed rate of approximately 2.5 percent and receives variable rates that are currently set at approximately 1.1 percent. As of June 30, 2003, the variable interest rate on the Senior Credit Facility was approximately 6.4 percent, including the effects of the swap.

The fair value of TNP’s swap as of June 30, 2003, was a liability of $1.3 million, which is recorded on its balance sheet in deferred credits and other liabilities.

-13-

~~The~~Financial ~~interest~~Instruments ~~rate~~with ~~swap~~Characteristics ~~was~~of ~~designated~~both asLiabilities ~~a cash flow hedge. The swap is highly effective in offsetting future cash flow volatility caused by changes in interest rates. For the three~~ and ~~six~~Equity months ended June 30, 2003, TNP recorded unrealized gains (losses), net of reclassification adjustments, associated with its interest rate swap in other comprehensive income as shown in the following table.

	Three Months Ended June 30, 2003									Six Months Ended June 30, 2003
	Before-Tax Amount			Tax Benefit(Expense)			After-TaxAmount			Before-Tax Amount			Tax Benefit(Expense)			After-TaxAmount
	(In thousands)
Change in market value	$	(281	)	$	107		$	(174	)	$	(809	)	$	308		$	(501	)
Reclassification adjustments		202			(77	)		125			380			(145	)		235
Other comprehensive income (loss)	$	(79	)	$	30		$	(49	)	$	(429	)	$	163		$	(266	)

The FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity (SFAS 150), in May 2003. SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS 150 requires that an issuer classify a financial instrument that is within its scope as a liability or, in some circumstances, as an asset. SFAS 150 becomes effective for TNP and TNMP during the first quarter of 2004. At that time, TNP will reclassify its redeemable cumulative preferred stock as a liability.

~~Over the next twelve~~Note ~~months TNP anticipates that $0~~4.6 ~~million~~Derivative ofInstruments ~~unrealized~~and ~~after-tax~~Hedging ~~losses~~Activities ~~will be reclassified from other comprehensive income to interest expense. The estimated amounts to be reclassified represent the earnings volatility that is avoided by using the interest rate swaps.~~

Hedging Activities

TNP, TNMP and First Choice may enter into agreements for derivative instruments, including options and swaps, to manage risks related to changes in interest rates and commodity prices. At the inception of any such transactions, TNP, TNMP, and First Choice document relationships between the hedging instruments and the items being hedged. The documentation includes the strategy that supports executing the specific transaction.

TNP Interest Rate Swaps. In October 2002, TNP executed a $70 million interest rate swap transaction designed to manage interest rate risk associated with the Senior Credit Facility. The swap will terminate in October 2004. Under the terms of the swap, TNP pays a fixed rate of approximately 2.5 percent and receives variable rates that are currently set at approximately 1.2 percent. As of September 30, 2003, the variable interest rate on the Senior Credit Facility was approximately 7.1 percent, including the effects of the swap.

The fair value of TNP’s swap as of September 30, 2003, was a liability of $0.9 million, which is recorded on its balance sheet in deferred credits and other liabilities.

The interest rate swap was designated as a cash flow hedge. The swap is highly effective in offsetting future cash flow volatility caused by changes in interest rates. For the three and nine months ended September 30, 2003, TNP recorded unrealized gains (losses), net of reclassification adjustments, associated with its interest rate swap in other comprehensive income as shown in the following table.

	Three Months Ended September 30, 2003							Nine Months Ended September 30, 2003
	Before-Tax Amount		Tax Benefit (Expense)			After-Tax Amount		Before-Tax Amount			Tax Benefit (Expense)			After-Tax Amount
	(In thousands)
Change in market value	$	140	$	(53	)	$	87	$	(669	)	$	255		$	(414	)
Reclassification adjustments		239		(91	)		148		619			(236	)		383

Other comprehensive income (loss)	$	379	$	(144	)	$	235	$	(50	)	$	19		$	(31	)

Over the next twelve months TNP anticipates that $0.5 million of unrealized after-tax losses will be reclassified from other comprehensive income to interest expense. The estimated amounts to be reclassified represent the earnings volatility that is avoided by using the interest rate swaps.

TNMP Interest Rate Hedges. In October 2002, TNMP executed two $75 million interest rate swap transactions designed to manage interest rate risk associated with the TNMP/First Choice Credit Facility. As discussed in Note 5, TNMP issued $250 million of Senior Notes in June 2003. A portion of the proceeds from that borrowing was used to repay amounts outstanding under the TNMP/First Choice Credit Facility. As a result, TNMP terminated the swaps in June 2003 at a cost of $3.1 million, which was recorded in interest expense.

In May 2003, TNMP executed a $250 million Treasury rate lock transaction designed to manage interest rate risk associated with the issuance of its $250 million of Senior Notes discussed in Note 5. The rate lock effectively fixed the five-year Treasury yield upon which the yield of the Senior Notes was based at approximately 2.6 percent. TNMP paid $4.2 million upon the issuance of the Senior Notes in June 2003 to settle the rate lock. The cost of the rate lock was recorded in accumulated other comprehensive income and will be amortized to interest expense over the life of the Senior Notes.

The interest rate swaps and the Treasury rate lock were designated as cash flow hedges. The instruments were highly effective in offsetting future cash flow volatility caused by changes in interest rates. For the three and six months ended June 30, 2003, TNMP recorded unrealized gains (losses), net of reclassification adjustments, associated with its interest rate swaps and Treasury rate lock in other comprehensive income as shown in the following table.

	Three Months Ended June 30, 2003									Six Months Ended June 30, 2003
	Before-TaxAmount			Tax Benefit (Expense)			After-Tax Amount			Before-Tax Amount			Tax Benefit (Expense)			After-Tax Amount
	(In thousands)
Change in market value	$	(4,856	)	$	1,850		$	(3,006	)	$	(5,922	)	$	2,256		$	(3,666	)
Reclassification adjustments		3,336			(1,271	)		2,065			3,711			(1,414	)		2,297
Other comprehensive income (loss)	$	(1,520	)	$	579		$	(941	)	$	(2,211	)	$	842		$	(1,369	)

TNMP displays cash flows from interest rate hedging transactions in the cash flow statement as cash flow from operations, in accordance with the provisions of SFAS No. 104, “Statement of Cash Flows-Net Reporting of Certain Cash Receipts and Cash Payments and Classification of Cash Flows form Hedging Transactions.”

Natural Gas Call Options. For the three months ended June 30, 2003, First Choice paid $0.4 million to purchase natural gas call options to cover approximately 0.1 million megawatt-hours (MWh) of firm commitments to customers. The options were purchased to mitigate commodity price risk associated with those commitments. First Choice also paid additional premiums of $0.1 million on options purchased during the first quarter of 2003 to modify the settlement provisions of those options.

For the six months ended June 30, 2003, First Choice paid $19.1 million to purchase natural gas options to cover approximately 5.9 million MWh of firm commitments to customers.

The aggregate fair value of First Choice’s natural gas call options as of June 30, 2003, was $12.2 million, as shown in the current assets section of TNP’s consolidated balance sheet.

-14-

The ~~options~~interest rate swaps and the Treasury rate lock were designated as cash flow hedges. The ~~options~~instruments were ~~are~~ highly effective in offsetting future cash flow volatility caused by ~~increases~~changes in ~~natural~~interest ~~gas prices~~rates. For the three and ~~six~~nine months ended ~~June~~September 30, 2003, ~~First~~TNMP Choice’s purchased power expense included pre-tax gains of $1.9 million ($1.2 million after tax) and $2.5 million ($1.5 million after tax), respectively, related to the exercise of natural gas call options. In addition, First Choice recorded unrealized gains (losses), net of reclassification adjustments, associated with its ~~natural~~interest ~~gas~~rate ~~options~~swaps and Treasury rate lock in other comprehensive income as shown in the following table.

	Three Months Ended June 30, 2003												Six Months Ended June 30, 2003
	Three Months Ended September 30, 2003										Nine Months Ended September 30, 2003
	Before-Tax Amount			Tax Benefit (Expense)	~~Tax Benefit (Expense)~~			After-Tax Amount	~~After-Tax Amount~~		Before-Tax Amount		~~Before-Tax Amount~~		Tax Benefit (Expense)		~~Tax Benefi (Expense)~~		After-Tax Amount		~~After-TaxAmount~~
	(In thousands)
Change in market value	$	~~(2,013~~—	)	$	$—	~~767~~		$	$—	~~(1,246~~	)$	(5,922	$)	~~(6,927~~	)$	2,256	$	~~2,639~~	$	(3,666	$)	~~(4,288~~	)
Reclassification adjustments		~~3,244~~208			(79	~~(1,236~~)	)		129	~~2,008~~		3,919		~~3,273~~		(1,493	)	~~(1,247~~	)	2,426		~~2,026~~
Other comprehensive income (loss)	$	~~1,231~~208		$	$(79	~~(469~~)	)	$	$129	~~762~~	$	(2,003	$)	~~(3,654~~	)$	763	$	~~1,392~~	$	(1,240	$)	~~(2,262~~	)

~~Over~~TNMP displays cash flows from interest rate hedging transactions in the ~~next~~cash ~~twelve months,~~flow ~~First~~statement ~~Choice~~as ~~estimates~~cash ~~that~~flow ~~$9.8~~from ~~million~~operations, in accordance with the provisions of ~~unrealized~~SFAS ~~after-tax~~No. ~~costs~~104, ~~related~~“Statement toof ~~natural~~Cash ~~gas~~Flows-Net ~~call~~Reporting ~~options~~of ~~will~~Certain beCash ~~reclassified~~Receipts ~~through~~and ~~other~~Cash ~~comprehensive~~Payments ~~income~~and Classification toof ~~purchased~~Cash ~~power~~Flows ~~expense~~from Hedging Transactions.”

Natural Gas Hedges. For the three months ended September 30, 2003, First Choice paid $0.5 million to purchase natural gas call options to cover approximately 0.1 million megawatt-hours (MWh) of firm commitments to customers. The options were purchased to mitigate commodity price risk associated with those commitments.

For the nine months ended September 30, 2003, First Choice paid $19.6 million to purchase natural gas options to cover approximately 6.0 million MWh of firm commitments to customers.

The aggregate fair value of First Choice’s natural gas call options as of September 30, 2003, was $2.6 million, as shown in the current assets section of TNP’s consolidated balance sheet.

The options were designated as cash flow hedges. The options are highly effective in offsetting future cash flow volatility caused by increases in natural gas prices. For the three and nine months ended September 30, 2003, First Choice’s purchased power expense included pre-tax gains of $0.2 million ($0.1 million after tax) and $2.7 million ($1.7 million after tax), respectively, related to the exercise of natural gas call options. First Choice’s purchased power expense also includes pre-tax charges of $0.7 million ($0.5 million after tax) for both the three and nine months ended September 30, 2003, related to changes in the value of options that are no longer designated as cash flow hedges.

In the third quarter of 2003, First Choice took advantage of favorable conditions in the natural gas market to purchase natural gas swaps, fixing the price of a portion of its power supply. As a result of those purchases, First Choice de-designated the natural gas call options related to those purchases. The fair value of the natural gas swaps as of September 30, 2003, was a liability of $1.3 million, which is recorded on TNP’s balance sheet in other current liabilities.

In addition, First Choice recorded unrealized gains (losses), net of reclassification adjustments, associated with its natural gas hedges in other comprehensive income as shown in the following table.

	Three Months Ended September 30, 2003									Nine Months Ended September 30, 2003
	Before-Tax Amount			Tax Benefit (Expense)			After-Tax Amount			Before-Tax Amount			Tax Benefit (Expense)			After-Tax Amount
	(In thousands)
Change in market value	$	(10,723	)	$	4,085		$	(6,638	)	$	(17,651	)	$	6,725		$	(10,926	)
Reclassification adjustments		6,583			(2,508	)		4,075			9,856			(3,755	)		6,101

Other comprehensive income (loss)	$	(4,140	)	$	1,577		$	(2,563	)	$	(7,795	)	$	2,970		$	(4,825	)

Over the next twelve months, First Choice estimates that $5.6 million of unrealized after-tax costs related to natural gas call options will be reclassified through other comprehensive income to purchased power expense. In addition, $0.8 million of unrealized after-tax costs related to natural gas swaps will be reclassified through other comprehensive income to purchased power expense.

-15-

Note 5. Financing

TNP

Senior Credit Facility. In August 2003, TNP and the banks participating in TNP’s Senior Credit Facility ~~includes~~agreed to increase the commitment under, and extend the maturity of, the Senior Credit Facility. As a result the Senior Credit Facility is now composed of a $70112.5 million term loan ~~due~~that matures in ~~2005~~December ~~and~~2006. aThe commitment under the term loan increased $1542 million ~~revolving~~and ~~credit~~TNP used ~~facility~~the ~~that~~proceeds ~~expires~~to onprovide ~~August~~First 7,Choice ~~2003.~~with ~~The~~$25 million in additional capital and to replace the working capital available under the revolving portion of the Senior Credit Facility. ~~originally~~The ~~had~~revolving aportion ~~commitment~~ of ~~$25~~the ~~million~~Senior ~~and~~Credit ~~was~~Facility ~~scheduled~~expired ~~to expire~~ in ~~April~~ August 2003. ~~Banks~~and ~~with~~had ~~commitments~~a commitment of $15 million. ~~have~~The ~~agreed~~extension toof ~~extend~~ the ~~revolving~~ ~~portion~~maturity of the Senior Credit Facility oncoordinates ~~two~~the ~~occasions,~~refunding ~~resulting~~of in the ~~current~~term ~~commitment~~loan ~~level~~with ~~and~~the ~~expiration~~anticipated ~~date.~~issuance ~~TNP~~of ~~anticipates~~securitization ~~either~~bonds ~~securing~~related ~~financing~~ to ~~replace,~~the orrecovery ~~extending~~of ~~the~~stranded ~~revolving~~costs ~~portion~~as discussed ofin ~~the~~Note ~~Senior~~2 ~~Credit~~of ~~Facility prior~~these toconsolidated ~~its~~interim ~~expiration~~financial statements.

The Senior Credit Facility contains various financial covenants with which TNP must comply. Due to losses during the first quarter of 2003 at First Choice resulting from high natural gas prices, and increased amounts of outstanding debt due to the termination of TNMP’s factoring agreement early in 2002, TNP did not comply with one financial covenant for the period ended March 31, 2003. In May 2003, TNP obtained a modification of that financial covenant, as well as a second covenant. Additional covenants pertaining to risk management practices were implemented with this amendment. The amendment allows TNP to meet the covenant, which was in noncompliance for the period ended March 31, 2003, and TNP expects to comply with all covenants for the periods covered by the modifications, which extend to September 30, 2004.

TNMP and First Choice

TNMP~~/First~~ ~~Choice~~Senior ~~Credit Facility~~Notes. ~~Prior~~ toOn June 10, 2003, TNMP completed the sale of ~~TNMP~~$250 ~~Senior~~million ~~Notes~~of ~~described~~6.125% ~~below,~~Senior ~~First~~Notes ~~Choice~~due ~~and~~2008. ~~TNMP~~A ~~had~~portion of the ~~ability~~proceeds tofrom ~~borrow~~this sale upwas used to ~~$291.9~~repay ~~million~~TNMP’s outstanding borrowings under the TNMP/First Choice Credit Facility. ~~TNMP~~of ~~may~~$207 ~~borrow subject to a guarantee by First Choice~~million. ~~First~~At ~~Choice~~the ~~may~~same ~~borrow funds~~time, orTNMP ~~have~~reduced ~~letters~~the ofcommitments ~~credit issued,~~ under ~~the~~that ~~credit~~ facility ~~subject~~from to$291.9 amillion ~~guarantee~~to by$90 ~~TNMP~~million. ~~TNMP’s~~As ~~guarantee~~a isresult ~~limited~~of tothe ~~$75~~sale, TNMP ~~million~~has ~~due~~adequate cash to anmeet ~~order~~its ~~issued~~working bycapital ~~the~~needs ~~NMPRC~~without inthe ~~December~~need ~~2001.~~for ~~Accordingly,~~additional ~~First~~bank ~~Choice’s~~financing ~~borrowings~~through ~~and issuances~~at ofleast ~~letters~~the end of ~~credit are limited to $75 million~~2005.

~~On June~~TNMP/First ~~10,~~Choice ~~2003,~~Credit ~~TNMP~~Facility. ~~completed~~Following the sale of ~~$250~~the ~~million~~TNMP ~~of 6.125%~~ Senior Notes, ~~due~~First ~~2008~~Choice was able to borrow from the TNMP/First Choice Credit Facility until its expiration in October 2003. AFirst ~~portion~~Choice could borrow funds, or have letters of ~~the~~credit ~~proceeds~~issued, ~~from~~under ~~this~~the ~~sale~~credit ~~was~~facility ~~used~~subject to ~~repay~~a guarantee by TNMP. TNMP’s ~~outstanding~~guarantee ~~borrowings~~was limited to $75 million due to an order issued by the NMPRC in December 2001. At September 30, 2003, First Choice had issued letters of credit of $28.7 million under the TNMP/First Choice Credit Facility. AtIn ~~the same time~~addition, TNMP ~~reduced~~ ~~the~~had ~~commitments~~guaranteed First Choice’s performance under ~~that~~the ~~facility~~power ~~from~~supply contract ~~$291.9~~with ~~million~~Constellation tofor $9025 million. As a result ~~of the sale~~, ~~TNMP~~First ~~has~~Choice ~~adequate~~had ~~cash~~additional capacity to ~~meet~~borrow ~~its~~or ~~working~~issue ~~capital~~letters ~~needs~~of ~~without~~credit under the ~~need~~TNMP/First ~~for~~Choice ~~additional~~Credit ~~bank~~Facility ~~financing~~of ~~through~~$21.3 atmillion ~~least~~as ~~the~~of ~~end~~September of30, ~~2005~~2003.

~~-15-~~The guarantees made by TNMP and First Choice required each to assume the obligations of the other in the event of default. As of September 30, 2003, TNMP had a maximum potential liability under its guarantees of First Choice borrowings, issuances of letters of credit and performance under the Constellation contract of $53.7 million. The guarantees were in force until the expiration of the TNMP/First Choice Credit Facility in October 2003.

As of September 30, 2003, First Choice had no guarantees of TNMP borrowings in force as a result of TNMP’s repayment of its outstanding borrowings under the TNMP/First Choice Credit Facility, as discussed above.

The TNMP/First Choice Credit Facility expired in October 2003. Also in October 2003, the NMPRC granted TNMP the authority to guarantee up to $50 million of First Choice power supply obligations as discussed in Note 2.

As noted above, the issuance of TNMP’s Senior Notes resulted in TNMP having adequate cash to meet its working capital needs. As discussed in Note 8, First Choice has provided for its working capital needs by executing a new power supply agreement with Constellation.

The new agreement with Constellation requires TNMP to continue to guarantee First Choice’s performance under the agreement for $25 million. However, the $28.7 million of letters of credit that First Choice had outstanding at September 30, 2003, were released as a result of the new Constellation agreement. In addition, Constellation has agreed to waive its right to require First Choice to post collateral to cover both settlement exposure and mark-to-market exposure. Accordingly, TNMP had a maximum potential liability under its guarantee of First Choice performance under the new Constellation agreement of $25 million as of October 27, 2003, the date upon which the new Constellation agreement was executed. The guarantee will be in force until the earlier of December 31, 2004 or the date upon which Constellation releases TNMP from its obligation to guarantee First Choice’s performance under the new Constellation agreement, as described in Note 8.

-16-

Following the sale of the TNMP Senior Notes, First Choice may continue to borrow from the TNMP/First Choice Credit Facility. As noted above, First Choice can borrow or issue letters of credit for up to $75 million under the TNMP/First Choice Credit Facility, subject to TNMP’s guarantee. At June 30, 2003, First Choice had outstanding borrowings of $7.0 million and had issued letters of credit of $28.7 million under the TNMP/First Choice Credit Facility. In addition, TNMP had guaranteed First Choice’s performance under the power supply contract with Constellation for $25 million. As discussed in Note 7, First Choice amended its power supply agreement with Constellation. As a result of the amendment, TNMP’s ability to guarantee First Choice’s $25 million performance under the Constellation contract is subject to TNMP maintaining a credit rating of at least BB+ from S&P or at least Ba1 from Moody’s. Should TNMP’s ratings fall below those levels, First Choice would be required to issue additional letters of credit under the TNMP/First Choice Credit Facility.

As of June 30, 2003, First Choice had additional capacity to borrow or issue letters of credit under the TNMP/First Choice Credit Facility of $14.3 million.

The guarantees made by TNMP and First Choice require each to assume the obligations of the other in the event of default. As of June 30, 2003, TNMP had a maximum potential liability under its guarantees of First Choice borrowings, issuances of letters of credit and performance under the Constellation contract of $60.7 million. The guarantees are in force until the expiration of the TNMP/First Choice Credit Facility in October 2003.

First Choice does not have any guarantees of TNMP borrowings in force as a result of TNMP’s repayment of its outstanding borrowings under the TNMP/First Choice Credit Facility, as discussed above.

Note 6. Segment and Related Information

TNP has two reportable segments that reflect the separation of TNMP’s business according to the provisions of Senate Bill 7. The first segment includes TNMP’s regulated transmission and distribution business in Texas and its New Mexico operations, and the second includes the unregulated activities of First Choice relating to the sale of electricity to retail customers in Texas.

The following tables present information about revenues, profits, and assets of TNP’s reportable segments (in thousands). Amounts below in “All Other and Eliminations” include amounts related to the assets and operations of TNP One, which TNMP sold in October 2002.

-16-

	Three Months Ended June 30, 2003
	Regulated Transmission and Distribution			First Choice			All OtherandEliminations			TNPConsolidated
Income Statement Data
Revenue from external customers	$	39,399		$	184,126		$	—		$	223,525
Intercompany revenue		28,362			—			(28,362	)		—
Purchased power and fuel		(16,342	)		(121,682	)		—			(138,024	)
Other direct costs		(5,215	)		(54,572	)		27,965			(31,822	)
Depreciation expense		(7,122	)		(73	)		(1	)		(7,196	)
Other operating expenses		(17,055	)		(12,201	)		(1,228	)		(30,484	)
Operating income (loss)		22,027			(4,402	)		(1,626	)		15,999
Other income and deductions, net		499			—			6			505
Interest charges		(8,812	)		(316	)		(9,186	)		(18,314	)
Income (loss) before taxes		13,714			(4,718	)		(10,806	)		(1,810	)
Income taxes		(4,882	)		1,836			3,838			792
Net income (loss)	$	8,832		$	(2,882	)	$	(6,968	)	$	(1,018	)
Cash Flow Data
Cash received from customers	$	68,758		$	163,733		$	(33,703	)	$	198,788
Purchased power and fuel costs paid		(19,161	)		(117,458	)		—			(136,619	)
Natural gas option premiums paid		—			(495	)		—			(495	)
Cash paid for payroll and to other suppliers		(16,854	)		(8,078	)		(507	)		(25,439	)
Transmission and distribution charges		—			(56,229	)		33,306			(22,923	)
Interest and other taxes paid		(12,162	)		(695	)		(15,310	)		(28,167	)
Intercompany dividends, income taxes refunded (paid), and other		(8,069	)		(819	)		7,199			(1,689	)
Net cash provided by (used in) operations		12,512			(20,041	)		(9,015	)		(16,544	)
Net cash used in investing activities, primarily additions to utility plant		(10,964	)		(76	)		—			(11,040	)
Borrowings from (repayments of) credit facilities		(185,000	)		7,000			(400	)		(178,400	)
Issuance of senior notes, net of discount		248,923			—			—			248,923
Intercompany dividends		(18,400	)		—			18,400			—
Intercompany financing		—			10,000			(10,000	)		—
Intercompany borrowing (lending)		(3,800	)		3,800			—			—
Other		(1,480	)		(172	)		(680	)		(2,332	)
Net cash provided by (used in) financing activities	$	40,243		$	20,628		$	7,320		$	68,191
Balance Sheet Data as of June 30, 2003
Cash and cash equivalents	$	41,949		$	1,884		$	5,988		$	49,821
Accounts receivable		35,008			106,042			(17,349	)		123,701
Other current assets		2,844			13,164			179			16,187
Net utility plant		510,019			2,844			20			512,883
Goodwill		—			—			270,256			270,256
Recoverable stranded costs		298,748			—			—			298,748
Other property, regulatory tax assets and deferred charges		23,186			124			24,286			47,596
Total assets	$	911,754		$	124,058		$	283,380		$	1,319,192
Current maturities of long-term debt	$	—		$	7,000		$	1,600		$	8,600
Accounts payable		8,986			92,187			(16,011	)		85,162
Other current liabilities		19,403			437			8,102			27,942
Deferred purchased power and fuel costs		24,241			—			—			24,241
Accumulated deferred income taxes and investment tax credits		167,931			(6,363	)		(10,087	)		151,481
Deferred credits		20,611			13,144			15,040			48,795
Long-term debt, less current maturities		423,477						343,900			767,377
Redeemable cumulative preferred stock		—			—			151,116			151,116
Common shareholder's equity		247,105			17,653			(210,280	)		54,478
Total liabilities and shareholder's equity	$	911,754		$	124,058		$	283,380		$	1,319,192

-17-

	Three Months Ended June 30, 2002
Three Months Ended September 30, 2003
	Regulated Transmission and Distribution			First Choice			All Other and Eliminations			TNP Consolidated
	RegulatedTransmissionand Distribution			FirstChoice			All OtherandEliminations			TNPConsolidated
Income Statement Data
Revenue from external customers	$	3240,~~834~~054		$	~~123~~212,~~341~~631		$	~~17,201~~2		$	~~173~~252,~~376~~687
Intercompany revenue		2629,~~733~~899			—			(2629,~~733~~899	)		—
Purchased power and fuel		(1517,~~308~~542	)		(61125,~~426~~602	)		~~(10,864~~—	)		(87143,~~598~~144	)
Other direct costs		(45,~~716~~257	)		(4060,~~994~~125	)		2629,~~307~~502			(1935,~~403~~880	)
Depreciation expense		(67,~~966~~197	)		(5979	)		(1	)		(7,~~026~~277	)
Other operating expenses		(1614,~~494~~272	)		(816,~~956~~243	)		(41,~~608~~359	)		(3031,~~058~~874	)
Operating income (loss)		1625,~~083~~685			1110,~~906~~582			(1,~~302~~755	)		2934,~~291~~512
Other income and deductions, net		~~2,755~~782			~~118~~(21	)		~~(2,688~~26	)		~~185~~787
Interest charges		(56,~~230~~869	)		(~~307~~363	)		(910,~~514~~853	)		(1518,~~051~~085	)
Income (loss) before taxes		1319,~~608~~598			1110,~~717~~198			(1012,~~900~~582	)		1417,~~425~~214
Income taxes		(47,~~574~~295	)		(43,~~519~~681	)		34,~~883~~278			(56,~~210~~698	)
Net income (loss)	$	912,~~034~~303		$	76,~~198~~517		$	(78,~~017~~304	)	$	910,~~215~~516
Cash Flow Data
Cash received from customers	$	4869,~~094~~951		$	97212,~~995~~854		$	(1532,~~658~~520	)	$	~~130~~250,~~431~~285
Purchased power and fuel costs paid		(1516,~~594~~060	)		(58140,~~582~~534	)		~~(5,413~~—	)		(79156,~~589~~594	)
Natural gas option premiums paid		—			—(495	)		—			—(495	)
Cash paid for payroll and to other suppliers		(1511,~~965~~098	)		(37,~~737~~246	)		(1,~~411~~438	)		(2119,~~113~~782	)
Transmission and distribution charges		—			(3059,~~202~~683	)		2132,~~366~~126			(827,~~836~~557	)
Interest and other taxes paid		(58,~~568~~110	)		(~~445~~1,901	)		(161,~~243~~285	)		(2211,~~256~~296	)
Intercompany dividends, income taxes refunded (paid), and other		(3,~~686~~000	)		(~~1,925~~20	)		23,~~248~~212			~~(3,363~~192	)
Net cash provided by (used in) operations		731,~~281~~683			32,~~104~~975			~~(15,111~~95	)		(434,~~726~~753	)
Net cash used in investing activities, primarily additions to utility plant		(78,~~167~~238	)		(4644	)		(395	)		(78,~~252~~287	)
Borrowings from (repayments of) credit facilities		~~15,000~~—			—(7,000	)		(~~400~~70,781	)		14(77,~~600~~781	)
Intercompany dividends		(9,000	)		(5,000	)		14,000			—
Issuance of senior notes, net of discount		—			—			—			—
Intercompany financing		—			—			—			—
Issuance of term loan under TNP senior credit facility		—			—			112,500			112,500
Intercompany borrowing (lending)		(6,000	)		6,000			—			—
Intercompany dividends		—			—			—			—
Other		155			(130	)		(25	)		—
Intercompany financing		—			25,000			(25,000	)		—
Net cash provided by (used in) financing activities	$	155		$	870		$	13,575		$	14,600
Intercompany borrowing		—			—			—			—
Balance Sheet Data as of June 30, 2002
Other		(176	)		(322	)		(2,704	)		(3,202	)
Cash and cash equivalents	$	329		$	3,991		$	8,227		$	12,547
Net cash provided by (used in) financing activities	$	(176	)	$	17,678		$	14,015		$	31,517
Accounts receivable		45,521			69,424			(20,803	)		94,142
Balance Sheet Data as of September 30, 2003
Other current assets		5,363			334			118,528			124,225
Cash and cash equivalents	$	65,218		$	22,493		$	20,093		$	107,804
Net utility plant		492,680			2,659			26			495,365
Accounts receivable		31,349			99,297			(14,447	)		116,199
Other current assets		2,088			3,732			101			5,921
Net utility plant		511,316			2,810			22			514,148
Goodwill		—			—			270,256			270,256
Recoverable stranded costs		298,~~250~~748			—			—			298,~~250~~748
Other property, regulatory tax assets and deferred charges		8728,~~349~~621			~~18,975~~363			~~(52~~21,~~809~~170	)		5350,~~515~~154
Total assets	$	~~929~~937,~~492~~340		$	95128,~~383~~695		$	~~323~~297,~~425~~195		$	1,~~348~~363,~~300~~230
Current maturities of long-term debt	$	—		$	—		$	1,~~600~~125		$	1,~~600~~125
Accounts payable		8,~~575~~602			5467,~~995~~207			(1913,~~724~~390	)		4362,~~846~~419
Other current liabilities		2235,~~513~~344			109,~~662~~297			113,~~513~~697			4448,~~688~~338
Deferred purchased power and fuel costs		2224,~~326~~321			—			—			2224,~~326~~321
Accumulated deferred income taxes and investment tax credits		~~149~~172,~~787~~842			8(11,149	)		(1110,~~571~~169	)		~~138~~151,~~224~~524
Deferred credits		1024,~~724~~142			—16,733			2711,~~252~~072			3751,~~976~~947
Long-term debt, less current maturities		~~401~~423,~~353~~552			—			~~443~~386,~~900~~093			~~845~~809,~~253~~645
Redeemable cumulative preferred stock		—			—			~~130~~156,~~490~~631			~~130~~156,~~490~~631
Common shareholder's equity		~~314~~248,~~214~~537			2946,~~718~~607			(~~260~~237,~~035~~864	)		8357,~~897~~280
Total liabilities and shareholder's equity	$	929,492		$	95,383		$	323,425		$	1,348,300
Total liabilities and shareholders' equity	$	937,340		$	128,695		$	297,195		$	1,363,230

-18-

	Six Months Ended June 30, 2003
Three Months Ended September 30, 2002
	RegulatedTransmissionand Distribution			~~First Choice~~FirstChoice			All OtherandEliminations			TNPConsolidated
Income Statement Data
Revenue from external customers	$	7535,~~208~~798		$	~~332~~175,~~038~~401		$	—17,962		$	~~407~~229,~~246~~161
Intercompany revenue		5332,~~918~~607			—			(5332,~~918~~607	)		—
Purchased power and fuel		(3315,~~378~~326	)		(~~241~~82,~~692~~054	)		77(11,262	)		(~~274~~108,~~993~~642	)
Other direct costs		(105,~~359~~045	)		(~~102~~54,~~577~~779	)		5332,~~124~~181			(5927,~~812~~643	)
Depreciation expense		(146,~~177~~795	)		(~~140~~60	)		(32	)		(146,~~320~~857	)
Other operating expenses		(3318,~~657~~666	)		(249,~~978~~645	)		(24,~~691~~967	)		(6133,~~326~~278	)
Operating income (loss)		3722,~~555~~573			~~(37~~28,~~349~~863	)		(31,~~411~~305	)		(352,~~205~~741	)
Other income and deductions, net		~~838~~2,764			~~112~~138			(752,883	)		~~875~~19
Interest charges		(135,~~778~~239	)		(~~620~~251	)		(1710,~~467~~017	)		(3115,~~865~~507	)
Income (loss) before taxes		2420,~~615~~098			~~(37~~28,~~857~~750	)		(2011,~~953~~595	)		~~(34~~37,~~195~~253	)
Income taxes		(86,~~735~~995	)		14(11,~~438~~075	)		74,~~448~~148			(13,~~151~~922	)
Net income (loss)	$	1513,~~880~~103		$	~~(23~~17,~~419~~675	)	$	(137,~~505~~447	)	$	~~(21~~23,~~044~~331	)
Cash Flow Data
Cash received from customers	$	~~118~~68,~~807~~073		$	~~297~~137,~~652~~481		$	(5313,~~736~~858	)	$	~~362~~191,~~723~~696
Purchased power and fuel costs paid		(3315,~~132~~202	)		(~~199~~75,~~652~~642	)		(~~217~~11,808	)		(~~233~~102,~~001~~652	)
Natural gas option premiums paid		—			~~(19,147~~—	)		—			~~(19,147~~—	)
Cash paid for payroll and to other suppliers		(312,~~463~~305	)		(206,~~793~~432	)		(212,~~422~~279	)		(5421,~~678~~016	)
Transmission and distribution charges		—			(9053,~~974~~320	)		5236,~~949~~787			(3816,~~025~~533	)
Interest and other taxes paid		(2910,~~287~~696	)		(21,~~197~~609	)		(162,~~121~~100	)		(4714,~~605~~405	)
Intercompany dividends, income taxes refunded (paid), and other		(61,~~969~~145	)		~~697~~(4,279	)		74,~~420~~833			~~1,148~~(591	)
Net cash provided by (used in) operations		1738,~~956~~725			(343,~~414~~801	)		~~(12~~1,~~127~~575	)		~~(28~~36,~~585~~499	)
Net cash used in investing activities, primarily additions to utility plant		(1910,~~848~~414	)		(~~227~~93	)		—(161	)		(2010,~~075~~668	)
Borrowings from (repayments of) credit facilities		(~~171~~11,000	)		~~7,000~~—			(~~800~~400	)		(~~164~~11,~~800~~400	)
Issuance of senior notes, net of discount		248,923			—			—			248,923
Intercompany dividends		(4,000	)		(10,000	)		14,000			—
Intercompany dividends		(18,400	)		—			18,400			—
Intercompany financing		—			—			—			—
Intercompany financing		—			10,000			(10,000	)		—
Intercompany borrowing		(13,100	)		13,100			—			—
Intercompany borrowing (lending)		(14,557	)		14,557			—			—
Other		94			(65	)		(599	)		(570	)
Other		(1,407	)		(245	)		(680	)		(2,332	)
Net cash provided by (used in) financing activities	$	(28,006	)	$	3,035		$	13,001		$	(11,970	)
Net cash provided by (used in) financing activities	$	43,559		$	31,312		$	6,920		$	81,791
Balance Sheet Data as of September 30, 2002
Balance Sheet Data as of June 30, 2003
Cash and cash equivalents	$	634		$	3,132		$	22,642		$	26,408
Cash and cash equivalents	$	41,949		$	1,884		$	5,988		$	49,821
Accounts receivable		32,958			105,999			(12,625	)		126,332
Accounts receivable		35,008			106,042			(17,349	)		123,701
Other current assets		3,875			482			118,776			123,133
Other current assets		2,844			13,164			179			16,187
Net utility plant		496,448			2,693			25			499,166
Net utility plant		510,019			2,844			20			512,883
Goodwill		—			—			270,256			270,256
Recoverable stranded costs		298,~~748~~250			—			—			298,~~748~~250
Other property, regulatory tax assets and deferred charges		23,186			124			24,286			47,596
Notes receivable		—			5,900			(5,900	)		—
Total assets	$	911,754		$	124,058		$	283,380		$	1,319,192
Other property, regulatory tax assets and deferred charges		95,536			(140	)		(43,706	)		51,690
Current maturities of long-term debt	$	—		$	7,000		$	1,600		$	8,600
Total assets	$	927,701		$	118,066		$	349,468		$	1,395,235
Accounts payable		8,986			92,187			(16,011	)		85,162
Current maturities of long-term debt	$	—		$	—		$	1,600		$	1,600
Other current liabilities		19,403			437			8,102			27,942
Accounts payable		9,088			62,504			(15,742	)		55,850
Deferred purchased power and fuel costs		24,241			—			—			24,241
Other current liabilities		23,449			18,089			19,262			60,800
Accumulated deferred income taxes and investment tax credits		167,931			(6,363	)		(10,087	)		151,481
Deferred purchased power and fuel costs		22,273			—			—			22,273
Deferred credits		20,611			13,144			15,040			48,795
Accumulated deferred income taxes and investment tax credits		155,752			82			(10,671	)		145,163
Long-term debt, less current maturities		423,477						343,900			767,377
Deferred credits		10,704			—			27,252			37,956
Redeemable cumulative preferred stock		—			—			151,116			151,116
Long-term debt, less current maturities		377,274						456,600			833,874
Common shareholder's equity		247,105			17,653			(210,280	)		54,478
Redeemable cumulative preferred stock		—			—			135,299			135,299
Total liabilities and shareholder's equity	$	911,754		$	124,058		$	283,380		$	1,319,192
Common shareholder's equity		329,161			37,391			(264,132	)		102,420
Total liabilities and shareholder's equity	$	927,701		$	118,066		$	349,468		$	1,395,235

-19-

	Six Months Ended June 30, 2002
Nine Months Ended September 30, 2003
	RegulatedTransmissionand Distribution			~~First Choice~~FirstChoice			All OtherandEliminations			TNPConsolidated
Income Statement Data
Revenue from external customers	$	73115,~~672~~263		$	~~203~~544,~~167~~668		$	~~17,202~~2		$	~~294~~659,~~041~~933
Intercompany revenue		4883,~~082~~816			—			(4883,~~082~~816	)		—
Purchased power and fuel		(3450,~~415~~920	)		(~~100~~367,~~538~~294	)		~~(6,900~~77	)		(~~141~~418,~~853~~137	)
Other direct costs		(915,~~710~~616	)		(66162,~~618~~702	)		4782,~~230~~626			(2995,~~098~~692	)
Depreciation expense		(1321,~~930~~374	)		(~~115~~219	)		(34	)		(1421,~~048~~597	)
Other operating expenses		(3147,~~947~~929	)		(1541,~~585~~221	)		(94,~~497~~050	)		(5793,~~029~~200	)
Operating income (loss)		3163,~~752~~240			20(26,~~311~~768	)		(505,165	)		5231,~~013~~307
Other income and deductions, net		21,~~817~~620			~~189~~91			(~~2,719~~48	)		~~287~~1,663
Interest charges		(1020,~~475~~646	)		(~~465~~982	)		(1928,~~106~~322	)		(3049,~~046~~950	)
Income (loss) before taxes		2444,~~094~~214			20(27,~~035~~659	)		(2133,~~875~~535	)		22(16,~~254~~980	)
Income taxes		(716,~~935~~031	)		(710,~~726~~757	)		711,~~791~~726			(76,~~870~~452	)
Net income (loss)	$	1628,~~159~~183		$	12(16,~~309~~902	)	$	(1421,~~084~~809	)	$	14(10,~~384~~528	)
Cash Flow Data
Cash received from customers	$	81188,~~519~~758		$	~~139~~510,~~193~~507		$	(1786,~~845~~257	)	$	~~202~~613,~~867~~008
Purchased power and fuel costs paid		(5349,~~566~~192	)		(78340,~~320~~185	)		(~~6,397~~217	)		(~~138~~389,~~283~~594	)
Natural gas option premiums paid		—			—(19,642	)		—			—(19,642	)
Cash paid for payroll and to other suppliers		(3442,~~006~~560	)		(1128,~~506~~039	)		(~~913~~3,860	)		(4674,~~425~~459	)
Transmission and distribution charges		—			(34150,~~493~~657	)		2385,~~269~~075			(1165,~~224~~582	)
Interest and other taxes paid		(2537,~~364~~397	)		(~~132~~4,097	)		(2517,~~208~~406	)		(5058,~~704~~900	)
Intercompany dividends, income taxes refunded (paid), and other		1(9,~~139~~969	)		~~(5,398~~675	)		~~896~~10,630			(31,~~363~~336	)
Net cash provided by (used in) operations		~~(30~~49,~~278~~640	)		9(31,~~344~~438	)		(2612,~~198~~035	)		~~(47~~6,~~132~~167	)
Net cash used in investing activities, primarily additions to utility plant		(1428,~~415~~087	)		(~~110~~271	)		(~~302~~3	)		(1428,~~827~~361	)
Borrowings from (repayments of) credit facilities		73(171,000	)		~~(6,000~~—	)		(~~800~~71,581	)		66(242,~~200~~581	)
Intercompany dividends		(14,000	)		(5,000	)		19,000			—
Issuance of senior notes, net of discount		248,923			—			—			248,923
Intercompany financing		(32,963	)		23,000			9,963			—
Issuance of term loan under TNP senior credit facility		—			—			112,500			112,500
Intercompany borrowing (lending)		19,000			(19,100	)		100			—
Intercompany dividends		(18,400	)		—			18,400			—
Other		(5,651	)		(130	)		(58	)		(5,839	)
Intercompany financing		—			35,000			(35,000	)		—
Net cash provided by (used in) financing activities	$	39,386		$	(7,230	)	$	28,205		$	60,361
Intercompany borrowing		(14,557	)		14,557			—			—
Balance Sheet Data as of June 30, 2002
Other		(1,583	)		(568	)		(3,383	)		(5,534	)
Cash and cash equivalents	$	329		$	3,991		$	8,227		$	12,547
Net cash provided by (used in) financing activities	$	43,383		$	48,989		$	20,936		$	113,308
Accounts receivable		45,521			69,424			(20,803	)		94,142
Balance Sheet Data as of September 30, 2003
Other current assets		5,363			334			118,528			124,225
Cash and cash equivalents	$	65,218		$	22,493		$	20,093		$	107,804
Net utility plant		492,680			2,659			26			495,365
Accounts receivable		31,349			99,297			(14,447	)		116,199
Other current assets		2,088			3,732			101			5,921
Net utility plant		511,316			2,810			22			514,148
Goodwill		—			—			270,256			270,256
Recoverable stranded costs		298,~~250~~748			—			—			298,~~250~~748
Other property, regulatory tax assets and deferred charges		8728,~~349~~621			~~18,975~~363			~~(52~~21,~~809~~170	)		5350,~~515~~154
Total assets	$	~~929~~937,~~492~~340		$	95128,~~383~~695		$	~~323~~297,~~425~~195		$	1,~~348~~363,~~300~~230
Current maturities of long-term debt	$	—		$	—		$	1,~~600~~125		$	1,~~600~~125
Accounts payable		8,~~575~~602			5467,~~995~~207			(1913,~~724~~390	)		4362,~~846~~419
Other current liabilities		2235,~~513~~344			109,~~662~~297			113,~~513~~697			4448,~~688~~338
Deferred purchased power and fuel costs		2224,~~326~~321			—			—			2224,~~326~~321
Accumulated deferred income taxes and investment tax credits		~~149~~172,~~787~~842			8(11,149	)		(1110,~~571~~169	)		~~138~~151,~~224~~524
Deferred credits		1024,~~724~~142			—16,733			2711,~~252~~072			3751,~~976~~947
Long-term debt, less current maturities		~~401~~423,~~353~~552			—			~~443~~386,~~900~~093			~~845~~809,~~253~~645
Redeemable cumulative preferred stock		—			—			~~130~~156,~~490~~631			~~130~~156,~~490~~631
Common shareholder’s equity		314,214			29,718			(260,035	)		83,897
Common shareholder's equity		248,537			46,607			(237,864	)		57,280
Total liabilities and shareholder’s equity	$	929,492		$	95,383		$	323,425		$	1,348,300
Total liabilities and shareholder's equity	$	937,340		$	128,695		$	297,195		$	1,363,230

-20-

As of June 30, 2003, TNP has assigned approximately $178.7 million of goodwill to the Regulated Transmission and Distribution segment and approximately $91.6 million to First Choice.

Nine Months Ended September 30, 2002
	Regulated Transmission and Distribution			First Choice			All Other and Eliminations			TNP Consolidated

Income Statement Data

Revenue from external customers	$	109,470		$	378,569		$	35,163		$	523,202
Intercompany revenue		80,689			—			(80,689	)		—
Purchased power and fuel		(49,741	)		(182,593	)		(18,161	)		(250,495	)
Other direct costs		(14,755	)		(121,397	)		79,411			(56,741	)
Depreciation expense		(20,725	)		(174	)		(5	)		(20,904	)
Other operating expenses		(50,613	)		(25,231	)		(14,463	)		(90,307	)


Operating income (loss)		54,325			49,174			1,256			104,755
Other income and deductions, net		5,581			327			(5,602	)		306
Interest charges		(15,714	)		(716	)		(29,123	)		(45,553	)


Income (loss) before taxes		44,192			48,785			(33,469	)		59,508
Income taxes		(14,930	)		(18,801	)		11,939			(21,792	)


Net income (loss)	$	29,262		$	29,984		$	(21,530	)	$	37,716


Cash Flow Data

Cash received from customers	$	149,592		$	276,255		$	(31,703	)	$	394,144
Purchased power and fuel costs paid		(68,768	)		(153,962	)		(18,205	)		(240,935	)
Natural gas option premiums paid		—			—			—			—
Cash paid for payroll and to other suppliers		(36,311	)		(17,519	)		(13,192	)		(67,022	)
Transmission and distribution charges		—			(87,813	)		60,056			(27,757	)
Interest and other taxes paid		(36,060	)		(1,741	)		(27,308	)		(65,109	)
Intercompany dividends, income taxes refunded (paid), and other		(6	)		(9,677	)		5,729			(3,954	)


Net cash provided by (used in) operations		8,447			5,543			(24,623	)		(10,633	)


Net cash used in investing activities, primarily additions to utility plant		(24,829	)		(203	)		(463	)		(25,495	)


Borrowings from (repayments of) credit facilities		62,000			(6,000	)		(1,200	)		54,800
Intercompany dividends		(18,000	)		(15,000	)		33,000			—
Intercompany financing		(32,963	)		23,000			9,963			—
Intercompany borrowing		5,900			(6,000	)		100			—
Other		(5,557	)		(195	)		(657	)		(6,409	)


Net cash provided by (used in) financing activities	$	11,380		$	(4,195	)	$	41,206		$	48,391


Balance Sheet Data as of September 30, 2002

Cash and cash equivalents	$	634		$	3,132		$	22,642		$	26,408
Accounts receivable		32,958			105,999			(12,625	)		126,332
Other current assets		3,875			482			118,776			123,133
Net utility plant		496,448			2,693			25			499,166
Goodwill		—			—			270,256			270,256
Recoverable stranded costs		298,250			—			—			298,250
Notes receivable		—			5,900			(5,900	)		—
Other property, regulatory tax assets and deferred charges		95,536			(140	)		(43,706	)		51,690

Total assets	$	927,701		$	118,066		$	349,468		$	1,395,235


Current maturities of long-term debt	$	—		$	—		$	1,600		$	1,600
Accounts payable		9,088			62,504			(15,742	)		55,850
Other current liabilities		23,449			18,089			19,262			60,800
Deferred purchased power and fuel costs		22,273			—			—			22,273
Accumulated deferred income taxes and investment tax credits		155,752			82			(10,671	)		145,163
Deferred credits		10,704			—			27,252			37,956
Long-term debt, less current maturities		377,274						456,600			833,874
Redeemable cumulative preferred stock		—			—			135,299			135,299
Common shareholder's equity		329,161			37,391			(264,132	)		102,420


Total liabilities and shareholder’s equity	$	927,701		$	118,066		$	349,468		$	1,395,235

-21-

As of September 30, 2003, TNP has assigned approximately $178.7 million of goodwill to the Regulated Transmission and Distribution segment and approximately $91.6 million to First Choice.

Note 7. Commitments and Contingencies

Energy Supply.

Amendment to Power Supply and Service Agreement. On March 31, 2003, First Choice and Constellation amended the power supply and service agreement under which First Choice purchases power to serve its price-to-beat load. The amendment requires First Choice to pay Constellation $9.2 million during 2004. In return, First Choice will no longer be required to assign the output from a power supply contract with a third party to Constellation from January 1, 2004 to August 31, 2004. The third party power contract, which represents approximately 1.4 million MWh at a cost of approximately $30 per MWh, was originally executed by TNMP and was assigned to First Choice at the beginning of retail competition in Texas. The amendment will have no impact on Constellation’s obligation to provide power for First Choice’s price-to-beat customers or the price at which Constellation provides that power.

As reported in the 2002 Combined Annual Report on Form 10-K, First Choice had firm commitments to supply approximately 0.7 million MWh of energy to competitive customers during 2004, for which it had not secured supplier commitments. Approximately 0.5 million MWh of those commitments applied to the January to August time period. As a result of the amendment to the power supply and service agreement, and the termination of First Choice’s requirement to assign the third party power contract to Constellation, First Choice obtained fixed-price power to cover its 2004 firm commitments, from January through August.

The amended power supply and service agreement also reduces the need for First Choice to purchase natural gas call options that would mitigate price risk associated with the 1.4 million MWh of firm and potential commitments in 2004 referred to above. In addition, the amended power supply and service agreement resulted in a reduction of $4.8 million of mark-to-market exposure that Constellation had to First Choice, and the extension of $3.0 million of unsecured credit by Constellation to First Choice. These two items resulted in the release of $7.8 million of letters of credit that First Choice had issued to Constellation under the TNMP/First Choice Credit Facility.

Finally, the conditions under which TNMP is able to guarantee First Choice’s performance under the power supply and service agreement have been modified. Previously, TNMP’s ability to guarantee up to $25 million of First Choice’s performance under the power supply and service agreement was subject to TNMP maintaining credit ratings of at least BBB- by S&P and at least Ba1 by Moody’s. As amended, TNMP can guarantee First Choice’s performance for up to $25 million if its credit rating is at least BB+ by S&P or at least Ba1 by Moody’s.

Legal Actions

Transmission Cost of Service. In June 2001 the Supreme Court of Texas overturned the methodology adopted by the PUCT to determine how much companies pay and charge for transmission services for the period January 1, 1997, through August 31, 1999. The PUCT had ordered a uniform methodology for the entire state and the Supreme Court stated that the costs needed to be determined on an individual company basis. During the third quarter of 2003, parties to the proceedings agreed to a settlement of the contested issues. As a result of the settlement, TNMP paid $0.2 million to the plaintiffs.

Other

TNP and TNMP are involved in various claims and other legal proceedings arising in the ordinary course of business. In the opinion of management, the dispositions of these matters will not have a material adverse effect on TNP’s and TNMP’s consolidated financial condition or results of operations.

Note 8. Subsequent Events

First Choice Energy Supply. On October 28, 2003, First Choice executed a Letter of Intent and Security Agreement with Constellation under which Constellation will supply First Choice the majority of its remaining power requirements through the end of 2006. As part of the agreement, First Choice will grant a security interest in its accounts receivable to Constellation, providing First Choice with sufficient credit for its Texas operations. This agreement eliminates the need for a new credit facility First Choice had been negotiating, or the renewal of the existing revolving credit facility.

-22-

The letter of intent commits First Choice and Constellation to an agreement with three phases. In phase one, which began on October 28, 2003, First Choice purchased fixed-price power to supply approximately 0.6 million MWh of forecasted commitments to its price-to-beat and competitive customers in 2004, supply for which had not previously been secured. First Choice also purchased supply for approximately 5.7 million MWh of forecasted commitments to price-to-beat customers in 2005 and 2006, at prices that vary with monthly natural gas prices.

During phase one, all supply provided by Constellation will be governed by the existing agreement between First Choice and Constellation. However, Constellation has agreed to waive its right to require First Choice to post collateral to cover both settlement exposure and mark-to-market exposure. Settlement exposure is the cost of energy that First Choice has received but for which payment has not yet been made. Mark-to-market exposure is the difference between the contracted price of energy for future periods and the current forward market price of the contracted energy. An increase in the quantity and/or price of energy, such as in the summer months, increases the settlement exposure. A decrease in the market price of energy increases the mark-to-market exposure. Conversely, an increase in the market price of energy decreases the mark-to-market exposure. In return for foregoing its right to demand additional collateral, Constellation will receive a lien against billed and unbilled receivables and a variable amount of cash required to cover up to the current month’s invoice due. However, if a dramatic change in electricity or gas forward prices created an increase in Constellation’s credit exposure to First Choice beyond a limit based on cash and accounts receivable, First Choice would be constrained in its ability to sign up additional customers.

During phase one, TNMP will continue to guarantee $25 million of First Choice’s performance under the existing Constellation agreement. As discussed in Note 7, First Choice amended its existing power supply agreement with Constellation. As a result of the amendment, TNMP’s ability to guarantee First Choice’s $25 million performance under the Constellation contract is subject to TNMP maintaining a credit rating of at least BB+ from S&P or at least Ba1 from Moody’s. Should TNMP’s ratings fall below those levels, First Choice would be required to provide additional collateral to Constellation.

Phase two of the agreement begins with the execution of a restructured power supply agreement that is being negotiated with Constellation to replace the existing agreement. The Letter of Intent provides that the restructured agreement will result in the assumption by Constellation of the risks associated with differences in actual customer usage and customer attrition for a fixed fee above the cost of energy. First Choice will continue to retain the credit risk of the customers. The credit terms described in phase one, including the $25 million guarantee from TNMP, will remain in place during phase two. Execution of the phase two agreement is targeted for December 31, 2003.

Phase three of the agreement begins once First Choice establishes a bankruptcy remote Special Purpose Entity (SPE) to hold all customer contracts and wholesale power and gas contracts. Some of the provisions in phase three of the agreement are subject to PUCT approval. First Choice expects to have the SPE established by the end of the third quarter of 2004. In return for a lien on accounts receivable, customer contracts, cash, and the equity of the SPE, Constellation will continue to waive any rights to demand additional collateral from First Choice, and release TNMP from its $25 million guarantee to Constellation. Phase three will continue until the expiration of the agreement on December 31, 2006.

During the first two phases of the new agreement, Constellation may terminate the agreement with six months prior notice if the SPE described above is not established by the earlier of thirty days after the PUCT approves the provisions in phase three over which it has jurisdiction or September 1, 2004. First Choice may terminate the agreement upon ninety days prior notice to Constellation, for any reason.

In the event of termination, the security interest in First Choice’s accounts receivable granted to Constellation would remain in effect until First Choice’s obligations are paid in full, and until the Letter of Intent and power supply agreements with Constellation are terminated. Alternatively First Choice can provide Constellation with alternate collateral. Provisions of the Letter of Intent and power supply agreements that by their terms survive termination would expire on their original expiration dates.

-23-

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A).

Competitive Conditions

First Choice Customer Operations

As discussed in Note 2, the Texas electricity market has been open to retail competition since January 1, 2002. First Choice has addressed, and continues to address, a number of issues related to the development of retail competition.

Customer Retention and Acquisition. At ~~June~~September 30, 2003, First Choice served approximately ~~186~~180,000 customers at price-to-beat rates and approximately 75 74,000 customers at competitive rates. At ~~June~~September 30, 2002, First Choice served approximately ~~190~~186,000 and 2428,000 price-to-beat and competitive customers, respectively. First Choice’s customer totals do not include entities that have chosen First Choice as their retail electric provider, but have yet to receive a bill pending completion of the switching process.

Customer Service Issues. First Choice has the right to disconnect customers that reside in TNMP’s transmission and distribution service territory for non-21payment. First Choice is prohibited from disconnecting customers who reside outside TNMP’s transmission and distribution service territory for non-payment, but may transfer such a customer to the affiliated retail electric provider of the transmission and distribution service provider that serves the transferred customer.

~~Table~~The structure described above limits First Choice’s collection activities, and affects both bad debt expense and the level of ~~Contents~~delinquent accounts receivable. Bad debt expense as a percentage of operating revenues for First Choice was approximately 1.6 percent for the nine months ended September 30, 2003, which is the same rate it experienced during 2002. On average delinquent accounts receivable were approximately 6.0 percent of monthly operating revenue for the nine months ended September 30, 2003, compared with the 2002 delinquency rate of 9.7 percent. First Choice expects that its delinquency rate will continue to decrease during 2003 due to a number of internal and external factors that are discussed in the remainder of this section.

Customer Service Issues. First Choice has the right to disconnect customers that reside in TNMP’s transmission and distribution service territory for non-payment. It is prohibited from disconnecting customers who reside outside TNMP’s transmission and distribution service territory for non-payment, but may transfer such customers to the provider of last resort. The provider of last resort is an entity established under the provisions of Senate Bill 7 to allow customers who cannot otherwise procure electric service in the competitive market to have access to such service.

The structure described above limits First Choice’s collection activities, and affects both bad debt expense and the level of delinquent accounts receivable. Bad debt expense as a percentage of operating revenues for First Choice was approximately 1.3 percent for the six months ended June 30, 2003, which is the same rate it experienced during 2002. On average, delinquent accounts receivable were approximately 5.4 percent of monthly operating revenue for the six months ended June 30, 2003, compared with the 2002 delinquency rate of 9.7 percent. First Choice expects that its delinquency rate will continue to decrease during 2003 due to a number of internal and external factors that are discussed in the remainder of this section.

Switching and Billing Issues. At the beginning of retail competition, transactions and data did not flow between the market participants as accurately or in the volumes that the system was designed to accommodate. The impaired data flow limited the ability of retail electric providers to switch customers from one retailer to another, and caused billing inaccuracies at First Choice. Retail electric providers, transmission and distribution service providers and the Electric Reliability Council of Texas (ERCOT) are all working together to address these problems in order to improve the infrastructure and processes that support the competitive electric market. The efforts of the various market participants have resulted in improvements in the switching process, correction of errors that occurred shortly after the market opened and improved data flows between the market participants. TNMP and First Choice expect these improvements to continue.

Under retail competition, First Choice must bill its customers using data not only from TNMP, but also from the other transmission and distribution utilities that serve First Choice’s customers. The wider range of sources providing billing data to First Choice has also contributed to billing inaccuracies since the beginning of retail competition. The frequency of these issues has decreased as First Choice has gained experience under retail competition. However, First Choice expects it will experience some level of billing issues in the competitive market related to multiple sources of billing data.

First Choice Energy Supply

First Choice assumed the energy supply activities of TNMP in Texas on January 1, 2002. The competitive market created under the provisions of Senate Bill 7 contains no provisions for the specific recovery of fuel and purchased power costs, although First Choice can request that the PUCT change the price-to-beat twice a year to recognize changes in natural gas prices. As a result, changes in the market prices of fuel and purchased power will affect First Choice’s operating results. To manage this risk, First Choice has established a strategy to mitigate the effects of changing prices.

~~Constellation~~As isa result of the ~~primary~~new agreement ~~supplier~~between ofConstellation ~~power~~and ~~for~~ First Choice’s ~~price-to-beat~~described ~~customers.~~in AsNote ~~First~~8, ~~Choice~~Constellation ~~gains~~is ~~competitive~~the ~~customers,~~primary itsupplier ~~procures~~of power for ~~those~~First ~~competitive~~Choice’s customers, ~~from~~both aprice-to-beat ~~number~~and ~~of suppliers~~competitive.

Strategy for mitigating fluctuation in costs of energy supply. First Choice has adopted a risk management policy that establishes minimal amounts of risk that First Choice may assume. First Choice’s basic strategy is to minimize its exposure to fluctuations in market energy prices by matching fixed price sales contracts with fixed price supply or by purchasing options to limit exposure to upward movements in prices of its floating price energy supply. In addition, First Choice uses its ability to change the price-to-beat fuel factor, as described below, to mitigate fluctuations in the cost of its price-to-beat energy supply.

~~Price~~-to24-~~Beat~~ Customers. For the first half of 2003, First Choice purchased its power supply for price-to-beat customers primarily from Constellation at prices that varied with monthly natural gas prices. Although it has the ability to purchase supply at fixed prices under its contract with Constellation, First Choice expects to continue purchasing power supply from Constellation and other suppliers with varying natural gas prices for the remainder of 2003, in order to minimize the required collateral posting to power suppliers. The price-to-beat fuel factor plus a fixed component of price-to-beat rates of approximately $19 per megawatt hour (“MWh”) comprise the total price-to-beat fuel recovery rate. As a result of significant gas price increases in early 2003, First Choice requested a change in the factor in February 2003, which was approved by the PUCT in March 2003. As a result, the total price-to-beat fuel rate increased to approximately $55 per MWh.

In April 2003, the PUCT approved First Choice’s second request for a change in the price-to beat fuel factor in 2003, the maximum number of changes that First Choice is allowed to request for the year. As a result, the total price-to-beat fuel rate increased to $60 per MWh.

-22-

Price-to-Beat Customers. For the first nine months of 2003, First Choice purchased its power supply for price-to-beat customers primarily from Constellation at prices that varied with monthly natural gas prices. First Choice’s new agreement with Constellation, which is described in Note 8, will allow First Choice to purchase supply at fixed prices for 2004 and beyond. The price-to-beat fuel factor plus a fixed component of price-to-beat rates of approximately $19 per megawatt hour (“MWh”) comprise the total price-to-beat fuel recovery rate. As a result of significant gas price increases in early 2003, First Choice requested a change in the factor in February 2003, which was approved by the PUCT in March 2003. As a result, the total price-to-beat fuel rate increased to approximately $55 per MWh.

Since First Choice has received both of its allowed changes in the price-to-beat fuel factor for 2003, First Choice purchased natural gas call options in mid-March 2003 to cap the exposure to further increases in natural gas on its forecasted price-to-beat load. The purchase of the options limited the price of energy to supply First Choice’s price-to-beat load to slightly lower than the price inherent in the current price-to-beat fuel factor.

Competitive Customers. Early in 2002, First Choice purchased power supplies at fixed prices for the entire term of a customer’s contract at the time the customer signed a contract. During 2002, First Choice recognized that purchasing fixed price supply during periods of high gas prices subjected it to additional credit requirements. When gas prices fell below the levels of the fixed price purchase commitments, First Choice was required to post collateral to its suppliers. First Choice’s ability to post collateral is limited by factors discussed in “TNMP and First Choice Liquidity”. To address this issue, First Choice developed a strategy based on the purchase of call options to mitigate the risk of increasing gas prices, which was adopted in November 2002. As previously disclosed in the Combined Annual Report on Form 10-K, implementation of this strategy was delayed due to the discovery that the initial option purchase had been made with an organization created by a now former First Choice employee. At the time, the former employee had the responsibility of negotiating and contracting with energy counter parties.

By mid-March 2003, First Choice secured natural gas call options to cover its projected sales to competitive customers for the period from April 2003 to December 2003. First Choice has mitigated its risks by covering new customer contracts subsequent to March by purchasing natural gas call options as soon after the contracts are executed as practical. In addition, First Choice took advantage of favorable conditions in the natural gas market and purchased natural gas swaps to fix the price of a portion of its supply for the last half of 2003.

First Choice executed a number of contracts for competitive customers in late 2002, prior to purchasing the natural gas call options in March 2003. At the time of executing the contracts, First Choice estimated that energy prices would average $35 per MWh based on gas costs of $3.99 per million British Thermal Units (“mmbtu”). Natural gas prices started to rise above $3.99 per mmbtu in December 2002 and monthly average prices ranged between $4.9969 per mmbtu and $9.13 per mmbtu during the first ~~half~~nine months of 2003. Due to the increase in natural gas prices First Choice realized a net decrease in gross margin of $78.12 million and $4048.68 million for the three and ~~six~~nine months ended ~~June~~September 30, 2003, respectively, when compared to the same periods of 2002. During the three and ~~six~~nine months ended ~~June~~September 30, 2003, the price of natural gas paid by First Choice averaged $54.4097 per mmbtu and $65.0066 per mmbtu, respectively.

Future Impact of Gas Price Movement. For the remainder of 2003, First Choice has limited its exposure to gas prices as discussed above. As a result, First Choice is exposed to changes in natural gas prices only for the month of December 2003. If the cost of gas iswere above $65.5075 per mmbtu ~~for~~during ~~the~~December ~~remainder of the year~~2003, the result would be a decrease in gross margin of $596.57 million for the last quarter ~~half~~ of 2003, when compared to gross margins for the last ~~half~~quarter of 2002, when gross margins were $468.93 million. Gross margins for the last ~~half~~quarter of 2003 will also be affected by factors other than changes to the cost of natural gas. Based on forward prices as of ~~July~~October 1629, 2003, which suggest an average price for the remainder of the year of $54.1180 per mmbtu, the impact on gross margins would be a reduction of approximately $~~45.~~5.2 million, when compared to the last ~~half~~quarter of 2002. For every $0.50 per mmbtu change in average gas price ~~for~~during ~~the~~December ~~remainder of the year~~2003, we would expect a change in gross margins of approximately $131.82 million, excluding the effects of exercising natural gas options.

As of September 30, 2003, First Choice had forecasted commitments in 2004 of 3.4 million MWh to its price-to-beat customers, and forecasted commitments of 2.2 million MWh to its existing competitive customers. First Choice has secured supply whose price will vary with natural gas prices to cover approximately 3.0 million MWh of forecasted commitments to its price-to-beat customers. First Choice can mitigate the risk of rising natural gas prices by asking the PUCT to change the price-to-beat. First Choice can request changes in the price-to-beat twice a year. For competitive customers, First Choice has secured fixed price supply to cover approximately 2.0 million MWh of forecasted commitments.

-25-

Under the new Constellation agreement, First Choice purchased fixed-price power to supply the remaining 0.6 million MWh of forecasted commitments to its price-to-beat and competitive customers in 2004, which had not previously been secured.

For 2005 and 2006, First Choice has forecasted commitments to supply approximately 1.2 million MWh to its competitive customers. Supply to cover those commitments has not been secured at this time.

Load Forecasting Risks. First Choice’s load forecast is continually monitored and revised to account for changing customer loads (both price-to-beat and competitive) due to among other things, customer additions and losses, changes in customers’ usage, severe or unexpected weather, and timing of customer switching. Short-term load forecasts are developed to identify short-term load surpluses and shortages, and to insure that hedges are in place to cover expected sales. To the extent these short-term load forecasts identify shortages, First Choice covers any on-peak shortages through short-term power purchases. First Choice may cover off-peak shortages through purchases on the ERCOT balancing market where off-peak prices are generally lower than can be contracted through short-term purchases.

When the restructured power supply agreement in phase two of the new Constellation agreement is executed, the Letter of Intent provides for the assumption by Constellation of the risks associated with differences to load forecasts in 2004.

TNMP

TNMP is providing transmission and distribution services at regulated rates to customers within its service area. Senate Bill 7 provides for recovery of “stranded” costs, the difference between the regulatory value of TNMP’s investment in generation assets and the market price for energy in a competitive market. Any such stranded costs would be recoverable from TNMP’s Texas transmission and distribution customers. The PUCT will conduct a proceeding in 2004 that will quantify and reconcile the amount of recoverable stranded costs, if any. The proceeding will consider a number of issues, including the sale of TNP One that occurred in October 2002, the final fuel reconciliation and the amount of the clawback.

-23-

Critical Accounting Policies

TNP and TNMP are required to use estimates in order to prepare the consolidated interim financial statements in accordance with generally accepted accounting principles. Those estimates include accruals for estimated revenues for electricity delivered from the latest billing date to the end of the accounting period and estimated purchased power expenses incurred but not billed at the end of the accounting period. The use of these estimates is customary in the electric utility industry. Estimated revenues and purchased power expenses are adjusted to the actual amounts billed or incurred in the following month. ~~TNP and~~In ~~TNMP~~addition, ~~also~~purchased power ~~employ~~expenses ~~certain critical accounting policies that require use of judgments and assumptions that~~ are subject to ~~uncertainty.~~adjustment ~~The~~due ~~amounts~~to ~~reported~~revisions inthat ~~the~~ERCOT ~~consolidated~~may ~~interim~~make ~~financial~~to ~~statements~~the ~~that~~metered ~~are~~load ~~related~~of toFirst ~~those~~Choice ~~critical accounting~~during ~~policies~~ERCOT’s ~~could~~settlement beprocess. ~~different~~These ifadjustments ~~either~~may ~~different~~occur ~~judgments~~several ~~were~~months ~~made~~after orthe ~~different~~actual ~~assumptions~~usage ~~were~~and ~~used.~~the ~~Those~~amounts ~~critical~~of ~~accounting~~these adjustments ~~policies~~can ~~are~~be ~~discussed below~~significant.

~~Clawback.~~TNP ~~First~~and ~~Choice~~TNMP isalso ~~subject~~employ certain tocritical aaccounting ~~provision~~policies ofthat ~~Senate Bill 7 commonly known as the “clawback.” The clawback would~~ require ~~First~~use ~~Choice to credit TNMP the difference between the price-to-beat and the market price~~ of ~~electricity~~judgments ~~during the years 2002~~ and ~~2003.~~assumptions ~~Additional~~that ~~details regarding the clawback~~ are ~~discussed~~subject ~~in Note 2. First Choice increased the pre-tax reserve related~~ to ~~its estimated clawback liability of $12~~uncertainty.7 ~~million~~The ~~recorded~~amounts atreported ~~December 31, 2002, by $0.4 million~~ in the ~~second~~consolidated ~~quarter~~interim offinancial ~~2003.~~statements ~~First~~that ~~Choice’s~~are ~~estimated~~related ~~clawback liability is based upon its current estimates of the number of competitive customers it will acquire and the number of price-~~to~~-beat~~ ~~customers~~those itcritical ~~will~~accounting ~~lose~~policies ~~through~~could ~~January 1, 2004. To the extent First Choice’s acquisition of competitive customers and loss of price-to-beat customers differs~~be ~~from~~different ~~current~~if ~~projections,~~either ~~the~~different ~~amount~~judgments ofwere ~~the~~made ~~clawback~~or ~~liability~~different ~~would~~assumptions bewere ~~different~~used. ~~First~~Those ~~Choice~~critical ~~estimates~~accounting ~~that~~policies ~~significant~~are ~~variations~~discussed ~~from its current projections could increase its clawback liability by up to an additional $6~~below.1 ~~million.~~

~~Goodwill~~Clawback. ~~and~~First ~~Intangible~~Choice ~~Assets.~~is ~~TNP~~subject ~~has~~to ~~goodwill~~a ~~related~~provision toof ~~the Merger~~Senate ~~that~~Bill ~~had~~7 acommonly ~~carrying~~known ~~value~~as ofthe ~~$270~~“clawback.3” ~~million~~The asclawback ofwould ~~June~~require ~~30,~~First Choice ~~2003.~~to Ascredit ~~discussed~~TNMP inthe ~~Note~~difference 6,between ~~TNP~~the ~~has~~price-to-beat ~~apportioned~~and the ~~carrying~~market ~~value~~price of electricity during the ~~goodwill~~years ~~between~~2002 ~~its~~and ~~Regulated~~2003. ~~Transmission~~The terms “clawback” and ~~Distribution~~“price-to-beat” ~~segment~~are defined and discussed in Note 2. First Choice. increased Asits pre-tax reserve of ~~June~~$12.7 million recorded at December 31, 2002, by $4.0 million for nine months ended September 30, 2003, ~~TNP~~ ~~had~~which ~~assigned~~includes ~~approximately~~a $~~178~~3.76 million increase in the third quarter of ~~goodwill~~2003. toFirst Choice’s estimated clawback liability is based upon its current estimates of the ~~Regulated~~number ~~Transmission~~of ~~and~~competitive ~~Distribution~~customers ~~segment~~it will acquire and ~~approximately~~the ~~$91.6~~number ~~million~~of price-to-beat ~~First~~customers ~~Choice~~it will lose through January 1, 2004.

Goodwill and Intangible Assets. TNP has goodwill related to the Merger that had a carrying value of $270.3 million as of September 30, 2003. As discussed in Note 6, TNP has apportioned the carrying value of the goodwill between its Regulated Transmission and Distribution segment and First Choice. As of September 30, 2003, TNP had assigned approximately $178.7 million of goodwill to the Regulated Transmission and Distribution segment and approximately $91.6 million to First Choice.

SFAS 142 requires TNP to test goodwill for impairment at least annually and more frequently when indicators of impairment exist. TNP performed its annual goodwill impairment test as of December 31, 2002, and concluded that the fair value of the goodwill related to the Merger exceeded its carrying value.

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To determine the fair value of the goodwill, TNP estimated the fair value of the Regulated Transmission and Distribution and First Choice segments. TNP’s estimate was based on the present value of the projected cash flows of each segment. Projected cash flows for the segments were derived from TNP’s five-year financial forecast.

The five-year forecast is subject to a number of estimates, including projections of customer growth and margins at First Choice. To the extent the assumptions are not achieved, or cannot be sustained, future assumptions may require modification, and such modifications would affect the estimates of expected cash flows contained in TNP’s annual goodwill impairment test. Accordingly, TNP’s conclusion regarding the fair value of goodwill would be affected by changes in the five-year financial forecast.

In June 2003, TNP tested the goodwill related to the Merger based on the current five-year forecast that reflects changes regarding customer growth and other factors at First Choice resulting from current market conditions. TNP concluded that, based on the current forecast, the fair value of the goodwill related to the Merger exceeded its carrying value.

Accounting for Derivatives— – Normal Purchases and Sales. In the normal course of business TNMP and First Choice enter into commodity contracts, which include “swing” components for additional purchases of electricity, in order to meet customer requirements. In most circumstances, such contracts would be defined as derivatives under SFAS 133, “Accounting for Derivative Instruments and Hedging Activities.” However, the ~~Financial Accounting Standards Board (~~FASB) has defined criteria by which option-type and forward contracts for electricity could qualify for the normal purchase and sales exception provided by SFAS 133. Based on the FASB’s guidance, the management of TNMP and First Choice has determined that their respective contracts for electricity qualify for the normal purchases and sales exception. Accordingly, TNMP and First Choice do not account for their respective electricity contracts as derivatives.

If TNMP and First Choice were required to account for their respective electricity contracts as derivatives, the fair values of the contracts would be recorded on the balance sheet as assets or liabilities. Changes in the fair values of the contracts would be recognized in earnings.

~~-24-~~Recoverable Stranded Costs – Sale of TNP One. TNMP sold TNP One in October 2002. Based on the sale, the fair value of TNP One, less cost to sell, was $117.5 million. The book value of TNP One at December 31, 2001, was approximately $418.5 million. TNMP believes that the difference between the fair value of TNP One, net of selling costs, and its book value at December 31, 2001, is recoverable from TNMP’s Texas transmission and distribution customers under the provisions of Senate Bill 7. Accordingly, TNMP has recorded a regulatory asset for recoverable stranded cost of approximately $301.0 million.

Recoverable Stranded Costs—Sale of TNP One. TNMP sold TNP One in October 2002. Based on the sale, the fair value of TNP One, less cost to sell, was $117.5 million. The book value of TNP One at December 31, 2001, was approximately $418.5 million. TNMP believes that the difference between the fair value of TNP One, net of selling costs, and its book value at December 31, 2001, is recoverable from TNMP’s Texas transmission and distribution customers under the provisions of Senate Bill 7. Accordingly, TNMP has recorded a regulatory asset for recoverable stranded cost of approximately $301.0 million.

Under the provisions of Senate Bill 7, the amount and manner of stranded cost recovery is subject to review and approval by the PUCT as part of the stranded cost true-up proceeding that will occur in 2004. Accordingly, action taken by the PUCT in the true-up proceeding could affect the ultimate recovery of the amounts recorded as recoverable stranded costs. Recovery of significantly less than the $301 million of estimated stranded costs currently recorded could have a material impact on the financial position and cash flows of TNMP and TNP.

-27-

Results of Operations

The following discussion should be read in conjunction with the related ~~interim~~ consolidated interim financial statements and notes.

Overall Results

TNP had aincome ~~loss~~ applicable to common stock of $6.5.0 million for the quarter ended ~~June~~September 30, 2003, compared with income applicable to common stock of $418.45 million for the quarter ended ~~June~~September 30, 2002. For the ~~six~~nine months ended ~~June~~September 30, 2003, TNP had a loss applicable to common stock of $3126.7 million compared with income applicable to common stock of $523.16 million for the ~~six~~nine months ended ~~June~~September 30, 2002. The changes in TNP’s earnings for the quarter and ~~six~~nine months ended ~~June~~September 30, 2003 are attributable to the factors listed below (in millions):

	Earnings Increase (Decrease)
	Earnings Increase(Decrease)
	Three Months Ended June 30, 2003 v. 2002			Six Months Ended June 30, 2003 v. 2002
	Three Months Ended September 30,2003 v. 2002			Nine MonthsEnded September 30,2003 v. 2002
Change in First Choice earnings	$	(10.1	)	$	(35.7	)
Change in First Choice net income (loss)	$	(11.2	)	$	(46.9	)
Change in TNMP consolidated earnings		(0.2	)		(0.3	)
Change in TNMP net income		(0.8	)		(1.1	)
All other and intercompany eliminations		(0.6	)		(0.8	)
TNP Preferred stock dividends		(0.7	)		(2.0	)
Change in TNP consolidated earnings	$	(10.9	)	$	(36.8	)
All other and intercompany eliminations		(0.8	)		(0.3	)
TNP consolidated earnings decrease	$	(13.5	)	$	(50.3	)

First Choice Results

First Choice had a net ~~loss~~income of $26.95 million for the quarter ended ~~June~~September 30, 2003, compared with net income of $717.27 million for the quarter ended ~~June~~September 30, 2002. For the ~~six~~nine months ended ~~June~~September 30, 2003, First Choice had a net loss of $2316.49 million, compared with net income of $1230.30 million for the ~~six~~nine months ended ~~June~~September 30, 2002. The changes in First Choice’s earnings for the quarter and ~~six~~nine months ended ~~June~~September 30, 2003 are attributable to the factors listed below (in millions):

	Earnings Increase (Decrease)
	Earnings Increase(Decrease)
	Three Months Ended June 30, 2003 v. 2002			Six Months Ended June 30, 2003 v. 2002
	Three Months Ended September 30,2003 v. 2002			Nine MonthsEnded September 30,2003 v. 2002
Changes in gross profit	$	(1311.17	)	$	(4859.29	)
Other operating and maintenance		(36.25	)		(915.05	)
All other (including income tax effects on the items above)		67.20			2128.5
Change in First Choice earnings	$	(10.1	)	$	(35.7	)
First Choice net loss	$	(11.2	)	$	(46.9	)

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First Choice Gross Profit

The following table summarizes the components of First Choice gross profit (in thousands).

	Three Months Ended June 30,							Six Months Ended June 30,
	Three Months Ended September 30,							Nine Months Ended September 30,
	2003		2002		Increase (Decrease)			2003			2002	~~2002~~		Increase(Decrease)	~~Increase (Decrease)~~
Operating revenues	$	~~184~~212,~~126~~631	$	~~123~~175,~~341~~401	$	6037,~~785~~230		$	~~332~~544,~~038~~668		$	$378,569	~~203,167~~	$	$166,099	~~128,871~~
Transmission and distribution costs		5456,~~153~~536		4054,~~993~~779		131,~~160~~757			~~102,~~158,694			121,397	~~66,618~~		37,297	~~35,540~~
Operating revenues, net of
Operating revenues, net of transmission and distribution costs		156,095		120,622		35,473			385,974			257,172			128,802
transmission and distribution costs		129,973		82,348		47,625			229,880				136,549			93,331
Purchased power and fuel		125,602		82,054		43,548			367,294			182,593			184,701
Purchased power and fuel		121,682		61,426		60,256			241,692				100,538			141,154
Clawback accrual		3,589		—		3,589			4,008			—			4,008
Clawback accrual		419		—		419			419				—			419
Gross profit	$	26,904	$	38,568	$	(11,664	)	$	14,672		$	74,579		$	(59,907	)
Gross profit (loss)	$	7,872	$	20,922	$	(13,050	)	$	(12,231	)		$	36,011		$	(48,242	)

Transmission and distribution costs are included in the “Other operating and maintenance” line of TNP’s consolidated income statement. The clawback accrual is shown on the income statement as “Accrual for payment to TNMP.” The following table summarizes the components of the change in First Choice’s gross profit for the three and ~~six~~nine months ended ~~June~~September 30, 2003, compared with the same periods in 2002 (in thousands).

	Three Months Ended June 30, 2003 v. 2002			Six Months Ended June 30, 2003 v. 2002
	Three Months Ended September 30,2003 v. 2002			Nine MonthsEnded September 30,2003 v. 2002
Price variance
Price variances
Changes in price-to-beat rates, primarily fuel factor increases	$	1916,~~034~~533		$	3148,~~523~~056
Changes in competitive rates		1114,~~821~~010			1024,~~336~~346
Increased purchased power expenses attributable to higher prices		(3738,~~891~~787	)		(82121,~~373~~160	)
Quantity variance
Quantity variances
Increased sales to competitive customers, net of transmission and distribution charges		1721,~~952~~398			5374,~~271~~669
Increased purchased power expenses attributable to higher sales		(22,987	)		(55,071	)
Increased purchased power expenses attributable to higher competitive customer sales		(25,843	)		(79,963	)
All other		(979	)		(5,928	)
Decreased sales to price-to-beat customers, net of transmission and distribution charges		(17,603	)		(21,098	)
Gross profit decrease	$	(13,050	)	$	(48,242	)
Decreased purchased power expenses attributable to lower price-to-beat sales		12,981			12,030
ERCOT wholesale resettlement of 2002 purchased power expense		8,105			4,392
All other		(2,458	)		(1,179	)
Gross profit decrease	$	(11,664	)	$	(59,907	)

Gross profit for the three and ~~six~~nine months ended ~~June~~September 30, 2003, decreased $1311.17 million and $4859.29 million, respectively, compared with the corresponding 2002 periods. The ~~decreases~~decrease in ~~both~~the ~~periods~~quarter resulted from higher purchased power expenses, and lower price-to-beat revenues partially offset by increased revenues from ~~both~~competitive customers. For the nine months ended September 30, 2003, the decrease resulted primarily from higher purchased power expenses, partially offset by higher revenues from both price-to-beat and competitive customers.

Revenues from price-to-beat customers for the ~~second~~third quarter, ~~and~~net ~~the~~of ~~six~~transmission ~~months~~and ~~ended~~distribution ~~June 30~~charges, ~~2003~~decreased ~~increased~~ $191.01 million ~~and $31.5 million, respectively,~~ compared ~~with~~to the same period in 2002. The ~~increases~~decrease ~~resulted~~was ~~from~~caused ~~changes~~by milder than normal weather and a decrease in the number of price-to-beat ~~fuel~~customers, ~~factor~~partially ~~that~~offset ~~were~~by ~~implemented~~increases in ~~August~~the ~~2002,~~price-to-beat ~~February~~fuel ~~2003,~~factor ~~March~~that ~~2003~~were ~~and~~implemented ~~April~~during 2003.

~~Revenues from competitive customers, net of transmission and distribution charges, increased $~~-29.8- million for the quarter ended June 30, 2003, compared with the quarter ended June 30, 2002. Changes in rates accounted for $11.8 million of the increase. During the second quarter of 2003, First Choice charged competitive customers higher rates to offset increasing natural gas prices. The remaining $18.0 million increase reflects higher sales resulting from First Choice’s acquisition of customers in the competitive market.

Revenues from competitive customers, net of transmission and distribution charges, increased $63.6 million for the six months ended June 30, 2003, compared with the six months ended June 30, 2002. Changes in rates accounted for $10.3 million of the increase, and higher sales accounted for $53.3 million of the increase. The increases are attributable to the same factors that affected revenues from competitive customers for the second quarter.

-26-

~~Retail~~For ~~electric providers such as First Choice include a transmission and distribution charge in~~ the ~~prices~~ ~~they~~nine charge their customers for electric service. The transmission and distribution charge is regulated by the PUCT and is designed to allow the utility that provides transmission and distribution services within a specific service area, referred to as the transmission and distribution service provider, to recover its cost of service. During the three months ended ~~June~~September 30, 2003, ~~First~~revenues ~~Choice~~from ~~billed its customers and incurred transmission and distribution costs related~~ price-to-beat ~~sales to competitive~~ customers ofincreased $27.5 0 million, compared with ~~$13.7 million for~~ the ~~three~~nine months ended ~~June~~September 30, 2002. ~~For~~The ~~the~~increase ~~six~~resulted ~~months~~from ~~ended~~increases ~~June~~in ~~30,~~the ~~2003, First Choice billed and incurred transmission and distribution costs related~~ price-to-beat ~~sales~~fuel ~~to competitive~~factor ~~customers~~during ~~of $51.1 million~~2003, ~~compared~~partially ~~with~~offset ~~$21.6~~by ~~million~~milder ~~for~~than ~~the~~normal ~~six~~weather ~~months~~in ~~ended June 30, 2002. As noted above,~~ the ~~increases~~third ~~reflect~~quarter ~~the acquisition~~ of ~~customers in the competitive market by First Choice~~2003.

~~Transmission~~Revenues ~~and~~from ~~distribution~~competitive ~~revenues~~customers, ~~and~~net ~~costs~~of ~~related~~transmission toand ~~price-to-beat~~distribution ~~sales~~charges, ~~were~~increased $2635.64 million for the ~~second~~ quarter ofended September 30, 2003, compared with ~~$27.2 million for~~ the ~~second~~ quarter ofended September 30, 2002. ~~Price-to-beat-related~~Changes ~~transmission~~in ~~and~~rates ~~distribution~~accounted ~~costs~~for ~~were~~ $5114.0 million ~~for~~of the ~~six~~increase. ~~months~~During ~~ended~~2003, ~~June~~First ~~30,~~Choice ~~2003,~~charged ~~compared~~competitive ~~with~~customers higher rates to offset increasing natural gas prices. The remaining $4521.04 million ~~for~~increase ~~the~~reflects ~~six~~higher ~~months~~sales ~~for~~resulting ~~the~~from ~~six~~First ~~months~~Choice’s ~~ended~~acquisition ~~June~~of ~~30,~~customers ~~2003~~in the competitive market.

~~Purchased~~Revenues ~~power~~from ~~and~~competitive ~~fuel~~customers, ~~expenses~~net of transmission and distribution charges, increased $6099.30 million for the ~~three~~nine months ended ~~June~~September 30, 2003, compared with the ~~amount~~nine ~~incurred~~months inended ~~the~~September ~~same~~30, ~~period in~~ 2002. ~~Increases~~Changes in ~~the~~rates ~~price~~accounted ~~of natural gas were primarily responsible~~ for $3724.93 million of the increase~~. The price increases accelerated in December 2002~~, and ~~First~~higher ~~Choice~~sales ~~responded~~accounted tofor ~~the increases by seeking increases in the price-to-beat fuel factor and by purchasing natural gas options to mitigate the risk of increasing natural gas prices~~$74. ~~First Choice began implementing its strategy in November 2002, as discussed in Note~~ 7. ~~An additional $23.0~~ million of the increase. isThe ~~primarily~~increases are attributable to ~~increased~~the ~~purchases~~same offactors ~~power~~that toaffected ~~supply~~revenues ~~customers acquired~~from bycompetitive ~~First~~customers ~~Choice~~for in the ~~competitive~~third ~~market~~quarter.

~~Purchased power~~Retail electric providers such as First Choice include a transmission and ~~fuel~~distribution ~~expenses~~charge ~~increased~~in ~~$141.2~~the ~~million~~prices they charge their customers for electric service. The transmission and distribution charge is regulated by the ~~six~~PUCT and is designed to allow the utility that provides transmission and distribution services within a specific service area, referred to as the transmission and distribution service provider, to recover its cost of service. During the three months ended ~~June~~September 30, 2003, ~~compared~~First ~~with~~Choice ~~the~~billed ~~amount~~its customers and incurred intransmission ~~the~~and ~~same~~distribution ~~period~~costs inrelated ~~2002.~~to ~~Increases~~sales into ~~the~~competitive ~~price~~customers of ~~natural~~$28.6 ~~gas~~million, compared ~~were~~with ~~primarily responsible for~~ $8223.4 million offor the ~~increase~~ three months ended September 30, 2002. ~~Increases~~For inthe ~~fees~~nine ~~charged~~months byended ~~ERCOT~~September ~~related~~30, to2003, ~~administration~~First ofChoice ~~the~~billed ~~competitive~~and ~~market~~incurred ~~also~~transmission ~~contributed~~and todistribution ~~the~~costs ~~increase~~related into ~~purchased~~sales ~~power~~to ~~and~~competitive ~~fuel~~customers ~~expense~~of $79.7 Anmillion, compared ~~additional~~with $5545.10 million offor the ~~increase~~nine ismonths ~~primarily~~ended ~~attributable~~September to30, ~~increased purchases~~2002. ofAs ~~power~~noted toabove, ~~supply~~the ~~customers~~increases ~~acquired~~reflect bythe ~~First~~acquisition ~~Choice~~of customers in the competitive market by First Choice.

Transmission and distribution revenues and costs related to price-to-beat sales were $27.9 million for the third quarter of 2003, compared with $31.4 million for the third quarter of 2002. The decreased revenues and costs reflect decreased sales due to milder than normal weather, as noted above. Price-to-beat-related transmission and distribution revenues and costs were $79.0 million for the nine months ended September 30, 2003, compared with $76.4 million for the nine months ended September 30, 2003. The increase is primarily attributable to higher sales in the first half of 2003 compared with the first half of 2002, partially offset by lower sales due to milder than normal weather in the third quarter of 2003.

Purchased power and fuel expenses increased $43.5 million for the three months ended September 30, 2003, compared with the amount incurred in the same period in 2002. Increases in the price of natural gas were primarily responsible for $38.8 million of the increase. The price increases accelerated in December 2002, and First Choice responded to the increases by seeking increases in the price-to-beat fuel factor and by purchasing natural gas options to mitigate the risk of increasing natural gas prices. First Choice began implementing its strategy in November 2002. An additional $25.8 million of the increase is primarily attributable to increased purchases of power to supply customers acquired by First Choice in the competitive market.

These increases were partially offset by adjustments resulting from the resettlement of 2002 purchased power expense by ERCOT, and by reduced purchases to supply price-to-beat customers of $13.0 million due to milder than normal weather. As discussed earlier in “Competitive Conditions,” participants in the competitive market experienced impaired data flows at the beginning of competition. As a result, First Choice and other retail electric providers had difficulty determining when to transfer ownership of customers that had switched from one retail electric provider to another. In addition, the metering data that ERCOT used to determine the various retail electric providers’ electric load during 2002 was not accurate in every case. First Choice and the other market participants have been working to correct the impaired data flows and have made considerable progress. As a result of this corrective process, ERCOT adjusted the metered load of First Choice for the period August through December 2002, in September 2003. The adjustment to metered load reduced purchased power expenses by $8.1 million.

Purchased power and fuel expenses increased $184.7 million for the nine months ended September 30, 2003, compared with the amount incurred in the same period in 2002. Increases in the price of natural gas were primarily responsible for $121.2 million of the increase. An additional $80.0 million of the increase is primarily attributable to increased purchases of power to supply customers acquired by First Choice in the competitive market. As discussed above, adjustments that related to the resettlement of 2002 purchased power expense by ERCOT and reduced purchases to supply price-to-beat customers due to milder than normal weather partially offset the increases.

-30-

Other Operating and Maintenance

Other operating and maintenance expenses for the ~~second~~third quarter of 2003 increased $36.25 million compared with the same period in 2002. For the ~~six~~nine months ended ~~June~~September 30, 2003, other operating and maintenance expenses increased $915.05 million compared with the same period in 2002. The increases resulted from a higher reserve for uncollectible accounts receivable, higher customer acquisition costs and increased personnel costs in First Choice’s customer service organization.

TNMP Results

TNMP had income applicable to common stock of $812.83 million for the quarter ended ~~June~~September 30, 2003, compared with income applicable to common stock of $913.01 million for the quarter ended ~~June~~September 30, 2002. For the ~~six~~nine months ended ~~June~~September 30, 2003, TNMP had income applicable to common stock of $1528.92 million compared with income applicable to common stock of $1629.23 million for the ~~six~~nine months ended ~~June~~September 30, 2002. The changes in TNMP’s earnings for the quarter and ~~six~~nine months ended ~~June~~September 30, 2003 are attributable to the factors listed below (in millions):

	Earnings Increase (Decrease)
	Earnings Increase(Decrease)
	Three Months Ended June 30, 2003 v. 2002			Six Months Ended June 30, 2003 v. 2002
	Three MonthsEnded September 30, 2003 v. 2002			Nine MonthsEnded September 30,2003 v. 2002
Changes in gross profit	$	0(7.36	)	$	(210.50	)
Other operating and maintenance		17.91			310.5
Taxes other than income taxes		01.90			23.67
Interest charges		(31.23	)		(24.71	)
All other (including income tax effects on the items above)		~~(0.1~~—	)		(1.2	)
Change in TNMP consolidated earnings	$	(0.2	)	$	(0.3	)
TNMP consolidated earnings decrease	$	(0.8	)	$	(1.1	)

-27-

TNMP Gross Profit

The following table summarizes the components of TNMP gross profit (in thousands).

Three Months Ended June 30,

Six Months Ended June 30,

Three Months Ended September 30,

Nine Months Ended September 30,

2003

2002

Increase (Decrease)

2003

2002

Increase (Decrease)

Operating revenues

6769,~~761~~953

7686,~~568~~367

(816,~~807~~414

)

~~129~~199,~~126~~079

~~154~~240,~~146~~513

(2541,~~020~~434

)

Purchased power and fuel

1617,~~342~~542

2526,~~971~~588

(9,~~629~~046

)

3350,~~301~~843

5683,~~505~~093

(2332,~~204~~250

)

Transmission expense

5,~~215~~257

45,~~716~~045

~~499~~212

1015,~~359~~616

914,~~710~~755

~~649~~861

Gross profit

4647,~~204~~154

4554,~~881~~734

~~323~~(7,580

)

85132,~~466~~620

87142,~~931~~665

(210,~~465~~045

)

Transmission expense is included in the “Other operating and maintenance” line of TNMP’s consolidated income statement.

The following table summarizes the components of the change in TNMP’s gross profit for the three and ~~six~~nine months ended ~~June~~September 30, 2003, compared ~~with~~ with the same periods in 2002 (in thousands).

	Three Months Ended June 30, 2003 v. 2002			Six Months Ended June 30, 2003 v. 2002
	Three MonthsEnded September 30, 2003 v. 2002			Nine MonthsEnded September 30,2003 v. 2002
January 2002 bundled rates	$	—		$	(4,606	)
January 2002 unbundled rates	$	—		$	(4,606	)
Sales of TNP One output—2002		(6,338	)		(10,225	)
Sales of TNP One output – 2002, net		(6,700	)		(16,925	)
Customer growth		574			1,831
Electric service revenues		219			3,614
Weather related		1,534			4,507
Customer growth		640			2,471
Electric service and rental revenues		2,189			3,395
Weather related		(2,207	)		2,300
Price/sales mix and other		~~2,364~~468			23,~~633~~101
Gross profit increase (decrease)	$	323		$	(2,465	)
Gross profit decrease	$	(7,580	)	$	(10,045	)

Gross profit for the three months ended June 30, 2003, increased $0.3 million, or 0.7 percent compared with the corresponding 2002 period. The overall increase is attributable to higher electric service revenues, including fees, and higher weather-~~related~~31- ~~sales in residential and commercial classes. These increases were offset by revenue received from the sale of TNP One output during 2002.~~

Gross profit for the six months ended June 30, 2003, decreased $2.5 million, or 2.8 percent compared with the corresponding 2002 period. The decrease is attributable to revenue received from the sale of TNP One output during 2002 and revenues from the billing of bundled rates in January 2002. The decrease was partially offset by the same factors that increased revenues for the second quarter, as discussed above.

In the first quarter of 2002, TNMP sold the output of TNP One to First Choice, which used the power to serve the load of its customers. Beginning in April 2002, TNMP sold the output of TNP One to third parties, until the sale of TNP One in October 2002.

Purchased power and fuel expenses decreased $9.6 million for the three months ended June 30, 2003, compared with the amount incurred in the same period in 2002. Expenses in 2002 included $10.7 million of TNP One fuel costs.

Purchased power and fuel expenses decreased $23.2 million for the six months ended June 30, 2003, compared with the amount incurred in the same period in 2002. Expenses in 2002 included $22.1 million of TNP One fuel costs.

-28-

Gross profit for the three months ended September 30, 2003, decreased $7.6 million compared with the corresponding 2002 period. The overall decrease is attributable to the loss of revenue from the sale of TNP One output during 2002. TNP One was sold in October 2002. Lower sales in residential and commercial classes due to milder than normal weather also contributed to the decrease.

Gross profit for the nine months ended September 30, 2003, decreased $10.0 million compared with the corresponding 2002 period. The decrease is attributable to the loss of revenue from the sale of TNP One output described above. In addition, 2002 gross profit included revenues from the billing of bundled rates in January 2002 that were not present in 2003. The decrease was partially offset by higher electric service revenues, growth in the number of residential and commercial customers, and higher weather related sales.

Although retail competition began on January 1, 2002, former customers of TNMP were transferred to First Choice following their January 2002 meter reading. As a result, TNMP’s January 2002 revenues include charges for service rendered through January 2002 meter reading dates at prices that reflect the integrated operations of TNMP prior to competition. Beginning in February 2002, TNMP’s revenues reflected rates designed to recover TNMP’s cost of providing transmission and distribution service under the provisions of Senate Bill 7. Those rates are lower than the rates TNMP charged prior to the beginning of competition, and resulted in decreased gross profit in the nine months ended September 30, 2003. The table above quantifies the impact of changing TNMP’s rates to recover its cost of providing only transmission and distribution service.

In the first quarter of 2002, TNMP sold the output of TNP One to First Choice at cost, which was 2.5 cent per kilowatt-hour (KWH). First Choice used the power to serve the load of its customers. Beginning in April 2002, TNMP sold the output of TNP One to third parties at prices that averaged 2.8 cents per KWH, until the sale of TNP One in October 2002. TNMP realized pre-tax income of $5.3 million related to third party sales for the nine months ended September 30, 2002.

Electric service revenues increased because TNMP provided a greater number of fee-based services to retail electric providers in the nine months ended September 30, 2003, compared with the same period in 2002. The fee-based services included account initiation charges, service call charges, disconnect/reconnect charges and various metering charges, among others. Some of the charges for fee-based services that TNMP provided to retail electric providers were included in the bundled rates TNMP charged its customers prior to competition.

The $3.1 million gross profit increase described as “price/sales mix and other” for the nine months ended September 30, 2003, compared to the corresponding 2002 period, is primarily attributable to increased revenues from commercial and industrial customers in Texas. A significant portion of those customers’ revenues are calculated based upon those customers’ highest peak demand for electricity in the twelve month period ending in the month that the customers are billed. Customers’ bills through the third quarter of 2003 were based upon a full twelve months of demand data, but customers’ bills through the third quarter of 2002 were based upon less than twelve months of demand data due to the beginning of retail competition in January 2002. As a result, the 2002 bills were lower than they normally would be, because the demand data for the summer months of 2001, during which these customers typically have their highest demand, could not be included in the calculation of the customers’ bills.

Purchased power and fuel expenses decreased $9.0 million for the three months ended September 30, 2003, compared with the amount incurred in the same period in 2002. Expenses in 2002 included $11.3 million of TNP One fuel costs, which was sold in October 2002.

Purchased power and fuel expenses decreased $32.3 million for the nine months ended September 30, 2003, compared with the amount incurred in the same period in 2002. Expenses in 2002 included $33.4 million of TNP One fuel costs, which was sold in October 2002.

Operating Expenses

TNMP incurred operating expenses of $4544.73 million for the quarter ended ~~June~~September 30, 2003, a decrease of $1116.85 million from the amount incurred during the corresponding period of 2002. For the ~~six~~nine months ended ~~June~~September 30, 2003, TNMP incurred operating expenses of $91135.68 million, a decrease of $2744.72 million from the amount incurred during the corresponding period of 2002. ~~Operating~~ ~~expenses~~The ~~included~~primary inreason for the ~~determination~~decreases ~~of gross profit decreased $9.1 million and $22.6 million~~ for both the three and ~~six~~nine months ended ~~June~~September 30, 2003, compared with the ~~same~~corresponding 2002 periods was the absence of the operating expenses related to TNP One in 2003 resulting from the sale of TNP One in October 2002. We do not expect similar decreases in operating expenses in the future.

~~Operating~~-32- ~~expenses that are included in the determination of gross profit are discussed above in “TNMP Gross Profit.” The remaining components of the changes in operating expenses are discussed below.~~

Operating expenses include purchased power and fuel, and transmission expense. Those expenses decreased $8.8 million and $31.4 million for the three and nine months ended September 30, 2003, compared with the same periods in 2002.

The details in the changes of purchased power and fuel, and transmission expense, are discussed above in “TNMP Gross Profit.” The remaining components of the changes in operating expenses are discussed below.

Other Operating and Maintenance

Other operating and maintenance expenses decreased $17.91 million and $310.5 million for the quarter and ~~six~~nine months ended ~~June~~September 30, 2003, compared with the same periods in 2002 respectively. The decrease is related to operating ~~cost~~ expenses of TNP One, which was sold in October 2002 and to TNMP’s establishment of a regulatory asset related to unrecovered System Benefit Fund payments, as discussed in Note 2.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $01.90 million and $23.67 million for the three and ~~six~~nine months ended ~~June~~September 30, 2003, compared with the corresponding 2002 periods. The decrease is primarily related to ad valorem taxes at TNP One, which was sold in October 2002.

Interest Expenses

Interest expenses increased $31.23 million and $24.71 million for the three and ~~six~~nine months ended ~~June~~September 30, 2003, respectively, compared to the same periods in 2002. The ~~increases~~increase ~~are~~for the quarter is attributable to interest on $250 million of Senior Notes that TNMP issued in June 2003. For the nine months ended, the increase reflects interest on the Senior Notes and $3.1 million of charges associated with the termination of TNMP’s interest rate swaps upon the issuance of ~~$250~~the ~~million of~~ Senior Notes ~~by TNMP~~ in June 2003.

TNP Preferred Stock Dividends

Dividends on preferred stock increased $0.7 million and $2.1 million for the three and nine months ended September 30, 2003, respectively, compared with the corresponding periods in 2002. The increases are attributable to TNP paying dividends on preferred stock through the issuance of additional shares of preferred stock.

Financial Condition

TNP Liquidity

TNP’s main sources of liquidity, and its ability to service the debt issued to finance the Merger, depend primarily on the earnings of its subsidiaries, TNMP and First Choice. TNP receives distributions of those earnings in the form of cash dividends, as well as payments from its subsidiaries under a tax sharing agreement.

Senior Credit Facility. ~~TNP’s~~In ~~Senior Credit~~August ~~Facility~~2003, ~~includes~~TNP aand ~~$70.5~~the ~~million~~banks ~~term~~participating ~~loan due~~ in ~~2005~~TNP’s ~~and~~Senior aCredit ~~$15~~Facility ~~million~~agreed to ~~revolving~~increase ~~credit~~the ~~facility~~commitment ~~that~~under, ~~expires~~and onextend ~~August~~the 7maturity of, ~~2003.~~the ~~The~~Senior ~~revolving~~Credit ~~portion~~Facility. ofAs a result the Senior Credit Facility ~~originally~~is ~~had~~now acomposed ~~commitment~~ of a $25112.5 million ~~and~~term ~~was scheduled~~loan tothat ~~expire~~matures in ~~April~~December ~~2003~~2006. ~~Banks~~The ~~with~~commitment ~~commitments~~under ofthe term loan increased $1542 million ~~have~~and ~~agreed~~TNP toused ~~extend~~ the ~~revolving~~proceeds ~~portion~~to ofprovide ~~the~~First ~~Senior~~Choice ~~Credit~~with ~~Facility~~$25 onmillion ~~two occasions, resulting~~ in ~~the~~additional ~~current~~capital ~~commitment level~~ and ~~expiration~~replace ~~date.~~the ~~TNP~~working ~~had~~capital noavailable ~~borrowings against~~under the revolving portion of the Senior Credit Facility. asThe revolving portion of ~~June~~the ~~30,~~Senior Credit Facility expired in August 2003, and ~~the~~had ~~entire~~a commitment of $15 million. ~~was~~The ~~available~~extension toof ~~TNP,~~the ~~subject~~maturity toof ~~compliance~~the ~~with~~Senior ~~covenants~~Credit inFacility ~~this~~allows ~~facility.~~ TNP ~~anticipates~~flexibility ~~either~~to ~~securing~~coordinate ~~financing~~the torefunding ~~replace,~~of ~~or extending~~the term loan with the ~~revolving~~anticipated ~~portion~~issuance of securitization bonds related to the ~~Senior~~recovery ~~Credit~~of ~~Facility~~stranded ~~prior~~costs toresulting ~~its~~from ~~expiration~~TNMP’s sale of TNP One.

The Senior Credit Facility contains various financial covenants with which TNP must comply. Due to losses during the first quarter of 2003 at First Choice resulting from high natural gas prices, and increased amounts of outstanding debt due to the termination of TNMP’s factoring agreement early in 2002, TNP did not comply with one financial covenant for the period ended March 31, 2003. In May 2003, TNP obtained a modification of that financial covenant, as well as a second covenant. Additional covenants pertaining to risk management practices ~~will~~were be implemented with this amendment. The amendment allows TNP to meet the covenant, which was in noncompliance for the period ended March 31, 2003, and TNP expects to comply with all covenants for the periods covered by the modifications, which extend to September 30, 2004.

-2933-

For the ~~six~~nine months ended ~~June~~September 30, 2003, TNP’s cash flow from operations was $1816.58 million ~~higher~~ higher than in the ~~six~~nine months ended ~~June~~September 30, 2002. The factors causing the increase in cash flow from operations are summarized in the following table (in millions).

	Cash Flow Increase (Decrease)
	Cash FlowIncrease(Decrease)
	Six Months Ended June 30, 2003 v. 2002
	Nine MonthsEnded September 30,2003 v. 2002
Increased cash flow from sales	$	~~110~~170.72
Reversal of cash flow reduction in 2002 due to termination of factoring agreement		49.6
Cash paid in 2002 due to termination of factoring agreement		48.7
Higher purchased power payments		(94148.7	)
Cash paid for natural gas options		(19.16	)
Increased cash paid to suppliers		(3545.52	)
All other		7.5
Lower payments for taxes other than income taxes		7.2
Change in TNP consolidated cash flow from operations	$	18.5
All other		4.2
TNP consolidated cash flow from operations increase	$	16.8

Cash flow from sales increased due to the acquisition of customers in the competitive market and increases in the price-to-beat fuel factor. Cash flow in the first ~~half~~nine months of 2002 was reduced due to the termination of TNMP’s factoring agreement in February 2002. As discussed in First Choice Gross Profit, purchased power expenses increased in the first ~~half~~nine months of 2003 due to rising natural gas prices and increased purchases primarily as a result of higher sales to ~~both~~ competitive ~~and price-to-beat~~ customers. ~~First~~ First Choice purchased natural gas options in primarily the first half of 2003 as part of a strategy to mitigate the risk of increasing natural gas prices, as discussed in Note 74. The increased payments to suppliers are primarily attributable to ~~increased~~ increased transmission and distribution charges, which were addressed in First Choice Gross Profit. Payments for taxes other than income taxes have decreased primarily due to reduced payments for ad valorem taxes resulting from the sale of TNP One in October 2002.

Cash dividends from TNMP and First Choice to TNP are limited by restrictions in the respective companies’ debt indentures and bank agreements. In addition, the regulatory orders from the PUCT and the NMPRC approving the Merger contain additional restrictions on TNMP’s ability to pay cash dividends to TNP. For the ~~six~~nine months ended ~~June~~September 30, 2003, TNMP paid dividends $18.4 million to TNP.

For the ~~six~~nine months ended ~~June~~September 30 2003, TNMP made a tax sharing ~~payment~~ payments of $811.46 million to TNP, and TNP made a tax sharing ~~payment~~payments of $1.2 million to First Choice.

InFor ~~April~~the ~~2003~~nine months ended September 30, 2003, TNP made aequity contributions of $1035 million ~~equity contribution~~ to First Choice.

Management believes that dividends from its subsidiaries, payments under the tax sharing agreement, and ~~periodic~~cash ~~borrowings~~ on hand as a result of increasing the commitment under ~~its~~the ~~revolving~~Senior ~~credit~~Credit ~~facility~~Facility should be sufficient to meet TNP’s working capital requirements at least through the end of 2004.

TNMP and First Choice Liquidity

TNMP/First Choice Credit Facility. Until its expiration in October 2003, First Choice and TNMP ~~may~~could borrow up to $90 million, in the aggregate, under the TNMP/First Choice Credit ~~Facility.~~ ~~Prior to the sale of TNMP Senior Notes described below, First Choice and TNMP had the ability to borrow up to $291.9 million under the TNMP/First Choice Credit~~ Facility. TNMP ~~may~~could borrow subject to a guarantee by First Choice. First Choice ~~may~~ could borrow funds, or have letters of credit issued, under the credit facility subject to a guarantee by TNMP. TNMP’s guarantee iswas limited to $75 million due to an order issued by the NMPRC in December 2001. Accordingly, First Choice’s borrowings and issuances of letters of credit ~~are~~were limited to $75 million. The following sections discuss the liquidity of TNMP and First Choice following the expiration of the TNMP/First Choice Credit Facility.

TNMP Liquidity. On June 10, 2003, TNMP completed the sale of $250 million of 6.125% Senior Notes due 2008. A portion of the proceeds from this sale was used to repay TNMP’s outstanding borrowings under the TNMP/First Choice Credit Facility of $207 million. At the same time, TNMP reduced the commitments under that facility from $291.9 million to $90 million. As a result of the sale, TNMP has adequate cash to meet its working capital needs without the need for additional bank financing.

-3034-

TNMP’s cash flow from operations for the ~~six~~nine months ended ~~June~~September 30, 2003 was $5850.08 million ~~higher~~ higher than in the ~~six~~nine months ended ~~June~~September 30, 2002. The increased cash flow was primarily due to First Choice assuming the energy supply activities of TNMP in Texas at the beginning of retail competition, which resulted in TNMP making lower payments for fuel and purchased power costs in the first ~~half~~nine months of 2003. In addition, the sale of TNP One resulted in lower ad valorem tax payments in the first ~~half~~nine months of 2003 compared with the corresponding period in 2002.

TNMP has sufficient liquidity to satisfy the possibility of any known contingencies. Management believes cash flow from operations and cash on hand as a result of the issuance of the TNMP Senior Notes should be sufficient to meet working capital requirements at least through the end of 2005.

First Choice Liquidity. ~~Following~~On ~~the~~October ~~sale of the TNMP Senior Notes~~28, ~~First~~ ~~Choice may continue to borrow from the TNMP/First Choice Credit Facility. As noted above~~2003, First Choice ~~can~~executed ~~borrow~~a Letter ~~or issue letters~~ of ~~credit~~Intent ~~for~~and upSecurity toAgreement ~~$75~~with ~~million~~Constellation under ~~the~~which ~~TNMP/First~~Constellation ~~Choice~~will ~~Credit~~supply ~~Facility, subject to TNMP’s guarantee. At June 30, 2003,~~ First Choice ~~had~~the ~~outstanding~~majority ~~borrowings~~ of $7its ~~million~~remaining ~~and~~power ~~had~~requirements ~~issued~~through ~~letters~~the ofend ~~credit~~ of ~~$28~~2006.7 ~~million~~As ~~under~~part of the ~~TNMP/First Choice Credit Facility. In addition~~agreement, ~~TNMP had guaranteed~~ First Choice’s ~~performance~~will ~~under~~grant ~~the~~a ~~power~~security ~~supply~~interest ~~contract with Constellation for $25 million. As discussed~~ in ~~Note 7, First Choice amended~~ its ~~power~~accounts ~~supply~~receivable ~~agreement~~to ~~with~~ Constellation~~. As a result of the amendment~~, ~~TNMP’s~~providing ~~ability to guarantee~~ First Choice’s ~~$25~~with ~~million performance~~sufficient ~~under the Constellation contract is subject to TNMP maintaining a~~ credit ~~rating~~for ofits atTexas ~~least~~operations. ~~BB+~~This ~~from~~agreement ~~S&P~~eliminates orthe atneed ~~least~~for ~~Ba1~~a ~~from~~new ~~Moody’s.~~credit ~~Should~~facility ~~TNMP’s~~that ~~ratings fall below those levels,~~ First Choice ~~would~~had bebeen ~~required~~negotiating, toor ~~issue additional~~the ~~letters~~renewal of ~~credit under~~ the existing ~~TNMP/First~~revolving ~~Choice~~credit ~~Credit Facility~~facility.

AsThe letter of ~~June~~intent commits 30First Choice and Constellation to an agreement with three phases. In phase one, which began on October 28, 2003, First Choice ~~had~~purchased ~~the~~fixed-price ~~ability~~power to ~~borrow~~supply orapproximately ~~issue~~0.6 ~~letters~~million MWh of ~~credit~~forecasted ~~under~~commitments ~~the~~to ~~TNMP/First~~its ~~Choice~~price-to-beat and ~~Credit~~competitive ~~Facility~~customers in ~~the~~2004, ~~amount~~supply offor ~~$14~~which had not previously been secured.3 First Choice also purchased supply for approximately 5.7 million MWh of forecasted commitments to price-to beat customers in 2005 and 2006, at prices that vary with monthly natural gas prices.

~~First~~During ~~Choice’s~~phase ~~ability~~one, toall ~~continue~~supply provided toby ~~grow~~Constellation ~~its~~will ~~operations~~be isgoverned ~~contingent upon~~by the ~~availability~~existing ofagreement ~~adequate~~between ~~credit~~First ~~capacity~~Choice and Constellation. ~~This~~However, ~~capacity~~Constellation ishas ~~needed~~agreed to ~~provide~~waive ~~credit~~its ~~support~~right to ~~power~~require ~~suppliers when arranging for long-term purchases of power. Under the terms of~~ First Choice’s ~~energy supply agreements, First Choice is required~~ to post collateral ~~with suppliers~~ to cover both settlement exposure and mark-to-market exposure. Settlement exposure is the cost of energy that First Choice has received but for which payment has not yet been made. Mark-to-market exposure is the difference between the contracted price of energy for future periods and the ~~then-~~current forward market price of the contracted energy. An increase in the quantity and/or price of energy, such as in the summer months, increases the settlement exposure. A decrease in the market price of energy increases the mark-to-market exposure. Conversely, an increase in the market price of energy decreases the mark-to-market exposure. AIn ~~significant~~return ~~decline~~for inforegoing ~~the~~its ~~market~~right ~~price~~to ofdemand ~~natural gas~~additional ~~and/or electricity~~collateral, orConstellation awill ~~continuation~~receive ofa ~~First~~lien ~~Choice’s~~against ~~success~~billed inand ~~acquiring~~unbilled ~~new~~receivables ~~customers,~~and ~~absent~~a variable ~~the~~amount ~~availability~~ of ~~additional~~cash ~~credit~~required ~~resources, could limit First Choice’s ability~~ to ~~provide~~cover ~~additional~~up ~~credit support~~ to ~~Constellation~~ orthe ~~other~~current ~~power~~month’s ~~suppliers~~invoice due. ~~Potential~~However, ~~additional~~if ~~credit~~a ~~resources~~dramatic ~~for~~change ~~First~~in ~~Choice~~electricity ~~other~~or ~~than~~gas ~~the~~forward ~~existing~~prices ~~TNMP/First~~created ~~Choice~~an ~~Credit~~increase ~~Facility, which expires~~ in ~~October~~Constellation’s ~~2003,~~credit ~~include,~~exposure ~~but~~to ~~are~~First ~~not~~Choice ~~limited~~beyond ~~to,~~a ~~posting~~limit ofbased on cash ~~collateral~~and ~~with power~~accounts ~~suppliers~~receivable, orFirst ~~with~~Choice ~~lenders~~would ~~who~~be ~~would,~~constrained in ~~turn,~~its ~~provide~~ability ~~letters~~to ofsign ~~credit~~up additional customers.

~~First~~During ~~Choice~~phase isone, ~~currently~~TNMP ~~negotiating~~will continue to ~~secure~~guarantee a$25 ~~credit~~million ~~facility~~of ~~that~~First ~~would~~Choice’s beperformance ~~secured~~under bythe ~~its~~existing ~~accounts~~Constellation ~~receivable~~agreement. ~~The~~As ~~proposed~~discussed in ~~facility~~Note ~~would~~7, ~~have~~First aChoice ~~term~~amended ofits ~~three~~existing ~~years,~~power asupply ~~total~~agreement ~~commitment~~with ofConstellation. ~~approximately~~As ~~$125 million~~a ~~and~~result ~~borrowings~~of ~~under~~ the ~~proposed~~amendment, ~~facility~~TNMP’s ~~would~~ability ~~be limited~~ to aguarantee ~~ratio of~~ First Choice’s ~~eligible~~$25 ~~accounts~~million ~~receivable.~~performance ~~First~~under ~~Choice~~the ~~estimates~~Constellation ~~that~~contract ~~the~~is ~~proposed~~subject ~~facility~~to ~~would~~TNMP maintaining ~~provide~~ a ~~minimum~~credit rating of ~~approximately~~at ~~$60~~least ~~million~~BB+ ~~and~~from aS&P ~~maximum of~~or ~~$105~~at ~~million~~least ofBa1 ~~borrowing~~from ~~capacity~~Moody’s. ~~Borrowings~~Should ~~under~~TNMP’s ~~the~~ratings ~~proposed~~fall ~~facility~~below those levels, First Choice would ~~not~~be ~~require~~required ~~TNMP’s~~to ~~guarantee~~provide additional collateral to Constellation.

InPhase ~~April~~two ~~2003,~~of ~~First~~the ~~Choice~~agreement ~~received~~begins with the execution of a ~~$10~~restructured ~~million~~power supply ~~equity~~agreement ~~contribution~~that ~~from~~is ~~TNP~~being negotiated with Constellation to replace the existing agreement. The Letter of Intent provides that the restructured agreement will result in the assumption by Constellation of the risks associated with differences in actual customer usage and customer attrition for a fixed fee above the cost of energy. First Choice ~~used~~will continue to retain the ~~funds~~credit risk of the customers. The credit terms described in phase one, including the $25 million guarantee from TNMP, will remain in place during phase two. Execution of the phase two agreement is targeted for ~~general~~December ~~corporate~~31, ~~purposes~~2003.

~~Management~~Phase ~~believes~~three ~~cash~~of ~~flow~~the ~~from~~agreement ~~operations,~~begins ~~equity~~once ~~infusions~~First ~~from~~Choice ~~TNP, periodic~~establishes ~~borrowings~~a ~~under~~bankruptcy ~~existing~~remote ~~credit~~Special ~~facilities~~Purpose Entity (SPE) to hold all customer contracts and wholesale power and gas contracts. Some of the ~~sale~~provisions in phase three of ~~assets~~the ~~should~~agreement beare ~~sufficient~~subject to ~~meet~~PUCT ~~working~~approval. ~~capital~~First ~~and~~Choice ~~credit~~expects ~~requirements~~to athave ~~least~~the ~~through~~SPE established by the ~~expiration~~end of the ~~credit~~third ~~facility~~quarter inof ~~October 2003~~2004. AsIn ~~discussed~~return ~~above,~~for ~~First~~a ~~Choice~~lien on accounts isreceivable, ~~negotiating~~customer contracts, cash, and the equity of the SPE, Constellation will continue to ~~secure~~waive ~~financing~~any rights to ~~provided~~demand additional ~~credit~~collateral ~~and~~from ~~replace~~First ~~the~~Choice, and release TNMP~~/First~~ ~~Choice~~from ~~Credit~~its ~~Facility~~$25 ~~prior~~million guarantee to ~~October~~Constellation. ~~2003~~Phase three will continue until the expiration of the agreement on December 31, 2006.

~~Guarantees~~During ~~Under~~ the ~~TNMP/First~~first ~~Choice~~two ~~Credit~~phases ~~Facility.~~of ~~The~~the ~~guarantees~~new ~~made~~agreement, byConstellation ~~TNMP~~may ~~and~~terminate ~~First Choice under~~ the ~~TNMP/First~~agreement ~~Choice~~with ~~Credit~~six ~~Facility require~~months ~~each~~prior tonotice ~~assume~~if the ~~obligations~~SPE ofdescribed ~~the~~above ~~other~~is innot established by the ~~event~~earlier of ~~default.~~thirty Asdays ofafter ~~June~~the ~~30,~~PUCT ~~2003,~~approves ~~TNMP~~the ~~had~~provisions ain phase ~~maximum~~three ~~potential~~over ~~liability~~which ~~under~~it ~~its~~has ~~guarantees~~jurisdiction ofor ~~First~~September ~~Choice borrowings~~1, ~~issuances of letters of credit and performance under the Constellation contract of $60~~2004.7 ~~million.~~First ~~The~~Choice ~~guarantees~~may ~~are~~terminate ~~in force until~~ the ~~expiration~~agreement ofupon ~~the~~ninety ~~TNMP/First~~days ~~Choice~~prior ~~Credit~~notice ~~Facility~~to inConstellation, ~~October~~for ~~2003~~any reason.

-3135-

In the event of termination, the security interest in First Choice’s ~~does~~accounts ~~not~~receivable ~~have~~granted ~~any~~to Constellation ~~guarantees~~would ofremain ~~TNMP~~in ~~borrowings~~effect until First Choice’s obligations are paid in ~~force~~full, asand auntil ~~result~~the Letter of ~~TNMP’s repayment~~Intent ofand ~~its~~power ~~outstanding~~supply ~~borrowings~~agreements ~~under~~with ~~the~~Constellation ~~TNMP/~~are terminated. Alternatively First Choice ~~Credit~~can ~~Facility,~~provide asConstellation ~~discussed~~with alternate incollateral. ~~TNMP~~Provisions ~~Liquidity~~of the Letter of Intent and power supply agreements that by their terms survive termination would expire on their original expiration dates.

~~Intercompany~~Management ~~Loans.~~believes ~~Both~~cash ~~the~~flow ~~TNMP/First~~from ~~Choice~~operations ~~Credit Facility~~ and ~~the~~cash ~~Senior~~on ~~Credit~~hand ~~Facility~~should ~~allow~~be ~~intercompany~~sufficient ~~loans~~ to bemeet ~~made~~working ~~between~~capital ~~TNMP~~ and credit ~~First~~requirements ~~Choice.~~at Asleast ofthrough ~~June 30, 2003, all intercompany loans were retired. Due to~~ the ~~sale~~expiration of ~~TNMP~~the ~~Senior~~new ~~Notes~~Constellation ~~discussed~~agreement in ~~TNMP~~December ~~Liquidity, TNMP and First Choice do not expect to utilize intercompany loans in the foreseeable future~~2006.

TNMP Guarantees. The guarantee made by TNMP requires it to assume the obligations of First Choice in the event of default. As of October 27, 2003, TNMP had a maximum potential liability under its guarantee of First Choice performance under the new Constellation agreement of $25.0 million. The guarantee will be in force until the earlier of December 31, 2004 or the date upon which Constellation releases TNMP from its obligation to guarantee First Choice’s performance under the new Constellation agreement, as described in Note 8.

Intercompany Loans. The Senior Credit Facility allows intercompany loans to be made between TNMP and First Choice. As of June 30, 2003, all intercompany loans were retired. Due to the sale of TNMP Senior Notes discussed in TNMP Liquidity, TNMP and First Choice do not expect to utilize intercompany loans in the foreseeable future.

Item 4. Controls and Procedures.

As of ~~July~~October 1829, 2003, the Chief Executive Officers and Chief Financial Officers of TNP and TNMP evaluated the effectiveness of the companies’ disclosure controls and procedures pursuant to applicable Exchange Act Rules. Based upon that evaluation, the Chief Executive Officers and Chief Financial Officers of TNP and TNMP have each concluded that these disclosure controls and procedures are effective in timely alerting them to material information relating to their respective companies (including their consolidated subsidiaries) that is required to be included in TNP’s or TNMP’s periodic SEC filings.

There have been no significant changes in TNP’s or TNMP’s internal controls or in other factors that could significantly affect these controls subsequent to ~~July~~October 1829, 2003.

-3236-

PART II— – OTHER INFORMATION

Item 1. Legal Proceedings

See Notes 2 and 7 for information regarding additional regulatory and legal matters.

Item 6. Exhibits and Reports on Form 8-K

(a)

Exhibits

(4)		Second Supplemental Indenture dated June 1, 2003, to Indenture dated January 1, 1999, between TNMP and JPMorgan Chase Bank.
(99.1)		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(99.2)		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(99.3)		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(99.4)		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(31.1) Certification Pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act.

(31.2) Certification Pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act.

(31.3) Certification Pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act.

(31.4) Certification Pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act.

(32.1) Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(32.2) Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(32.3) Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(32.4) Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(b)	Reports on Form 8-K:

TNP filed an 8-K dated ~~May~~July 1524, 2003 to report the issuance of its ~~first~~second quarter 2003 Earnings Release.

TNP filed an 8-K dated ~~June~~October 1028, 2003 to report the ~~issuance~~new ofpower ~~TNMP’s~~supply agreement ~~$250~~between ~~million~~First ofChoice ~~Senior Notes~~ and ~~the extension of the revolving portion of TNP’s Senior Credit Facility~~Constellation.

Statement Regarding Forward Looking Information

The discussions in this document that are not historical facts, including, but not limited to, future cash flows and the potential recovery of stranded costs are based upon current expectations. Actual results may differ materially. Among the facts that could cause the results to differ materially from expectations are the following: our ability to adapt to open market competition; ~~resolution~~the ofability ~~problems~~to ~~with~~negotiate ~~computer~~and ~~systems~~enter ofinto ~~ERCOT~~definitive ~~and~~agreements ~~other~~relating ~~market participants~~to ~~that support~~ the Letter ~~competitive~~of ~~market~~Intent, ~~in Texas~~ and ~~facilitate~~Security ~~the~~Agreement ~~customer~~with ~~switching process~~Constellation; the ability of First Choice to attract and retain customers as competition moves forward; the effects of accounting pronouncements that may be issued periodically; changes in regulations affecting TNP’s and TNMP’s businesses; decisions in connection with regulatory proceedings; insurance coverage available for claims made in litigation; general business and economic conditions, and price fluctuations in the electric power and natural gas markets; ~~extensions~~ and ~~refinancings of expiring credit facilities; waivers or modifications of provisions in the Senior Credit Facility; and~~ other factors described from time to time in TNP’s and TNMP’s reports filed with the SEC. TNP and TNMP wish to caution readers not to place undue reliance on any such forward looking statements, which are made pursuant to the Private Securities Litigation Reform Act of 1995 and, as such, speak only as of the date made.

-3337-

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.

(Registrant)	TNP ENTERPRISES, INC.		~~TNP ENTERPRISES, INC.~~
Date: July 24, 2003			By:	/s/ THEODORE A. BABCOCK
Date: November 12, 2003	By	\s\ THEODORE A. BABCOCK
				Theodore A. Babcock Chief Financial Officer
		Theodore A. Babcock
		Chief Financial Officer
	TEXAS-NEW MEXICO POWER COMPANY
Date: November 12, 2003	By	\s\ SCOTT FORBES
		Scott Forbes
		Senior Vice President & Chief Financial Officer
Date: November 12, 2003	By	\s\ JOSEPH B. HEGWOOD
		Joseph B. Hegwood
		Vice President & Controller

	TEXAS-NEW MEXICO POWER COMPANY
Date: July 24, 2003	By:	/s/ SCOTT FORBES
		Scott Forbes Senior Vice President – Chief Financial and Accounting Officer

-34-

CERTIFICATIONS

I, William J. Catacosinos, certify that:

1. I have reviewed this quarterly report on Form 10-Q of TNP Enterprises, Inc.;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statement made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of the registrant’s board of directors:

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: July 24, 2003

/s/ WILLIAM J. CATACOSINOS William J. Catacosinos Chief Executive Officer

-35-

I, Theodore A. Babcock, certify that:

1. I have reviewed this quarterly report on Form 10-Q of TNP Enterprises, Inc.;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: July 24, 2003

/s/ THEODORE A. BABCOCK Theodore A. Babcock Chief Financial Officer

-36-

I, Jack V. Chambers, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Texas-New Mexico Power Company;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: July 24, 2003

/s/ JACK V. CHAMBERS Jack V. Chambers Chief Executive Officer

-37-

I, Scott Forbes, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Texas-New Mexico Power Company;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: July 24, 2003

/s/ SCOTT FORBES Scott Forbes Chief Financial and Accounting Officer

-38-

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Filing Compare · TNP ENTERPRISES INC