FORM 10-Q
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
[ X ]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 2003
For the Quarterly Period Ended June 30, 2004
OR
[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

	Exact Name of Registrant as
	Specified in Charter, State of
	Incorporation, Address of
Commission	Principal Executive	~~IRS Employer~~	IRS Employer
File Number	Office and Telephone Number	~~Identification Number~~	Identification Number
1-5540	PEOPLES ENERGY CORPORATION	~~36-2642766~~	36-2642766
	(an Illinois Corporation)
2-26983	THE PEOPLES GAS LIGHT AND COKE COMPANY		36-1613900
	130 East Randolph Drive, 24th Floor
2-35965	NORTH SHORE GAS COMPANY		36-1558720
	Chicago, Illinois 60601-6207
	(Illinois Corporations)
	Telephone (312) 240-4000
	130 East Randolph Drive, 24th Floor
2-26983	THE PEOPLES GAS LIGHT AND COKE COMPANY	36-1613900
	Chicago, Illinois 60601-6207
	(an Illinois Corporation)
	Telephone (312) 240-4000
	130 East Randolph Drive, 24th Floor
Indicate by check mark whether the registrants (1) have 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 registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes [x] No [ ]
	Chicago, Illinois 60601-6207
Indicate by a check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
	Telephone (312) 240-4000
Peoples Energy Corporation		Yes [x] No [ ]
2-35965	NORTH SHORE GAS COMPANY	36-1558720
The Peoples Gas Light and Coke Company		Yes [ ] No [x]
	(an Illinois Corporation)
North Shore Gas Company		Yes [ ] No [x]
	130 East Randolph Drive, 24th Floor
	Chicago, Illinois 60601-6207
	Telephone (312) 240-4000
Indicate by check mark whether the registrants (1) have 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 shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes [x] No [ ]

Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date (July 31, 2003):
Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date (July 31, 2004):
Peoples Energy Corporation	Common Stock, Nono par value, 3637,~~666~~630,~~025~~892 shares outstanding
The Peoples Gas Light and Coke Company	Common Stock, Nono par value, 24,817,566 shares outstanding (all of which are owned beneficially and of record by Peoples Energy Corporation)
North Shore Gas Company	Common Stock, Nono par value, 3,625,887 shares outstanding (all of which are owned beneficially and of record by Peoples Energy Corporation)
This combined Form 10-Q is separately filed by Peoples Energy Corporation, The Peoples Gas Light and Coke Company, and North Shore Gas Company. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes no representation as to information relating to the other companies. The Peoples Gas Light and Coke Company and North Shore Gas Company meet the conditions set forth in General Instruction H.1(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format permitted by General Instruction H.2 of Form 10-Q.
This combined Form 10-Q is separately filed by Peoples Energy Corporation, The Peoples Gas Light and Coke Company, and North Shore Gas Company. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes no representation as to information relating to the other companies. The Peoples Gas Light and Coke Company and North Shore Gas Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format permitted by General Instruction H(2) of Form 10-Q.

Part I - Financial Information

Item I1. Financial Statements

The condensed, unaudited financial statements of Peoples Energy Corporation (the Company), The Peoples Gas Light and Coke Company (Peoples Gas) and North Shore Gas Company (North Shore Gas), have been prepared by the Company pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). Peoples Gas and North Shore Gas are wholly-owned subsidiaries of the Company.

Peoples Energy Corporation
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)


	Three Months Ended		Nine Months Ended
	June 30,		June 30,
	2004	2003	2004	2003
(In Thousands, Except Per-Share Amounts)
Revenues	$ 401,137	$ 398,147	$ 1,933,042	$ 1,851,092

Operating Expenses:
Cost of energy sold	247,146	238,092	1,260,197	1,165,829
Operation and maintenance	83,739	84,058	270,106	261,570
Depreciation, depletion and amortization	29,749	27,658	89,641	83,135
Taxes, other than income taxes	29,761	27,729	148,508	144,835
Gains on property sales	(1,476)	-	(1,476)	-
Total Operating Expenses	388,919	377,537	1,766,976	1,655,369

Equity investment income (loss)	4,866	3,811	6,110	3,545

Operating Income	17,084	24,421	172,176	199,268

Other income and expense - net	918	661	2,299	1,751

Interest expense	11,758	12,004	36,420	37,376

Income Before Income Taxes	6,244	13,078	138,055	163,643

Income tax expense	621	5,065	46,178	61,148

Net Income	$ 5,623	$ 8,013	$ 91,877	$ 102,495

Average Shares of Common Stock Outstanding
Basic	37,549	36,265	37,212	35,867
Diluted	37,722	36,435	37,393	35,999

Earnings Per Share of Common Stock
Basic	$ 0.15	$ 0.22	$ 2.47	$ 2.86
Diluted	$ 0.15	$ 0.22	$ 2.46	$ 2.85

Dividends Declared Per Share	$ 0.54	$ 0.53	$ 1.61	$ 1.58

The Notes to Consolidated Financial Statements are an integral part of these statements.

This Quarterly Report on Form 10-Q is a combined report of the Company, Peoples Gas and North Shore Gas.

Certain footnote disclosures and other information, normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (GAAP), have been condensed or omitted from these interim financial statements, pursuant to SEC rules and regulations. Therefore, the statements should be read in conjunction with the consolidated financial statements and related notes contained in the Company's, Peoples Gas' and North Shore Gas' Annual Report on Form 10-K for the fiscal year ended September 30, 2002, as updated by the Current Report on Form 8-K dated April 22, 2003. Certain items previously reported for the prior periods have been reclassified to conform with the presentation in the current period. Due to a number of factors, including seasonality of businesses and market price volatility, the quarterly results of operations and statements of financial position and cash flows should not be considered indicative of the year as a whole.

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments, consisting of normal recurring accruals unless otherwise noted, necessary to present fairly the Company's, Peoples Gas', and North Shore Gas' financial position, its results of operations and cash flows for the interim periods presented.

Peoples Energy Corporation
CONSOLIDATED STATEMENTS OF INCOME
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	Three Months Ended		Nine Months Ended
	June 30,	September 30,	June 30,
	June 30,		June 30,
(In Thousands)	2004	2003	2003
	2003	2002	2003	2002
ASSETS
(In Thousands, Except Per-Share Amounts)
CAPITAL INVESTMENTS:
Revenues	$ 398,147	$ 347,149	$ 1,851,092	$ 1,247,532
Property, plant and equipment
Operating Expenses:
Utility plant	$ 2,600,526	$ 2,552,464	$ 2,532,654
Cost of energy sold	238,092	199,244	1,165,829	662,374
Oil and gas	473,067	391,135	372,238
Operation and maintenance	84,058	83,617	261,570	221,665
Other	20,450	18,357	17,092
Depreciation, depletion and amortization	27,658	24,393	83,135	73,691
Total property, plant and equipment	3,094,043	2,961,956	2,921,984
Taxes, other than income taxes	27,729	30,638	144,835	116,602
Less - Accumulated depreciation, depletion and amortization	1,201,012	1,123,783	1,103,946
Total Operating Expenses	377,537	337,892	1,655,369	1,074,332
Net property, plant and equipment	1,893,031	1,838,173	1,818,038
Equity investment income (loss)	3,811	2,330	3,545	(1,756)
Investment in equity investees	130,950	142,142	137,216
Operating Income	24,421	11,587	199,268	171,444
Other investments	23,847	21,768	20,112
Other income and expense - net	661	1,289	1,751	6,675
Total Capital Investments - Net	2,047,828	2,002,083	1,975,366
Interest expense	12,004	13,585	37,376	43,531
CURRENT ASSETS:
Earnings (Loss) Before Income Taxes	13,078	(709)	163,643	134,588
Cash and cash equivalents	75,900	13,648	52,007
Income tax expense (credit)	5,065	(2,045)	61,148	47,237
Deposits with broker or trustee	15,493	19,361	18,368
Net Income	$ 8,013	$ 1,336	$ 102,495	$ 87,351
Receivables -
Average Shares of Common Stock Outstanding
Customers, net of reserve for uncollectible accounts
Basic	36,265	35,466	35,867	35,452
of $31,267, $33,185, and $33,318, respectively	267,880	212,901	313,455
Diluted	36,438	35,514	36,000	35,499
Other	31,447	9,036	24,549
Earnings Per Share of Common Stock
Materials and supplies, at average cost	10,083	9,754	9,841
Basic	$ 0.22	$ 0.04	$ 2.86	$ 2.46
Gas in storage	98,010	165,583	78,430
Diluted	$ 0.22	$ 0.04	$ 2.85	$ 2.46
Gas costs recoverable through rate adjustments	21,878	22,665	32,319
Dividends Declared Per Share	$ 0.53	$ 0.52	$ 1.58	$ 1.55
Regulatory assets of utility subsidiaries	26,307	27,279	4,914
The Notes to Consolidated Financial Statements are an integral part of these statements.
Other	14,701	9,917	8,387
Total Current Assets	561,699	490,144	542,270
OTHER ASSETS:
Prepaid pension costs	184,059	186,961	189,763
Noncurrent regulatory assets of utility subsidiaries	187,261	181,223	187,204
Deferred charges and other	74,143	68,127	41,639
Total Other Assets	445,463	436,311	418,606
Total Assets	$ 3,054,990	$ 2,928,538	$ 2,936,242
The Notes to Consolidated Financial Statements are an integral part of these statements.

Peoples Energy Corporation
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	~~June 30,~~	June 30,	~~September 30,~~	September 30,	~~June 30,~~	June 30,
(In Thousands)	2003		2002		2002
(In Thousands, Except Shares)		2004		2003		2003
ASSETS
CAPITALIZATION AND LIABILITIES
CAPITAL INVESTMENTS:
CAPITALIZATION:
Property, plant and equipment
Common Stockholders' Equity:
Utility plant	$ 2,532,654		$ 2,493,323		$ 2,478,421
Common stock, no par value -
Oil and gas	372,238		285,885		276,158
Authorized 60,000,000 shares
Other	17,092		15,422		17,874
Issued 37,826,054, 36,936,068 and
Total property, plant and equipment	2,921,984		2,794,630		2,772,453
36,863,602 shares, respectively		$ 381,864		$ 346,545		$ 343,430
Less - Accumulated depreciation, depletion and amortization	1,103,946		1,020,729		1,007,943
Treasury stock - 243,100, 246,100 and 246,100 shares, respectively		(6,677)		(6,760)		(6,760)
Net property, plant and equipment	1,818,038		1,773,901		1,764,510
Retained earnings		581,756		549,969		567,976
Investment in equity investees	137,216		154,857		96,075
Accumulated other comprehensive loss		(66,390)		(41,755)		(28,988)
Other investments	23,952		22,893		26,347
Total Common Stockholders' Equity		890,553		847,999		875,658
Total Capital Investments - Net	1,979,206		1,951,651		1,886,932
Long-term debt, exclusive of maturities due within one
CURRENT ASSETS:
year and adjustable-rate bonds classified as short-term debt		846,330		744,345		744,345
Cash and cash equivalents	52,007		5,433		96,741
Total Capitalization		1,736,883		1,592,344		1,620,003
Deposits with broker or trustee	18,368		28,645		14,975
CURRENT LIABILITIES:
Receivables -
Commercial paper		-		55,949		-
Customers, net of reserve for uncollectible accounts
Adjustable-rate bonds classified as short-term debt		50,000		152,000		152,000
of $33,318, $34,730, and $37,365, respectively	313,455		181,819		246,947
Accounts payable		187,356		148,769		184,409
Other	24,549		41,761		30,462
Accrued taxes		51,726		45,730		76,067
Materials and supplies, at average cost	9,841		9,948		14,019
Other accrued liabilities		134,328		98,870		97,846
Gas in storage	78,430		89,568		42,662
Regulatory liabilities of utility subsidiaries		17,502		-		24,246
Gas costs recoverable through rate adjustments	32,319		10,218		12,199
Dividends payable		20,293		19,446		19,407
Regulatory assets of utility subsidiaries	4,914		18,274		14,226
Customer deposits		28,619		26,369		23,833
Other	8,387		6,203		2,573
Customer credit balances		26,820		48,402		25,089
Total Current Assets	542,270		391,869		474,804
Gas costs refundable through rate adjustments		29		5,039		5,967
OTHER ASSETS:
Temporary LIFO liquidation credit		50,539		-		47,916
Prepaid pension costs	189,763		179,678		178,713
Total Current Liabilities		567,212		600,574		656,780
Noncurrent regulatory assets of utility subsidiaries	187,204		167,236		133,483
DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred charges	37,799		33,213		31,865
Deferred income taxes		401,829		407,835		387,176
Total Other Assets	414,766		380,127		344,061
Investment tax credits		26,818		27,642		27,741
Total Assets	$ 2,936,242		$ 2,723,647		$ 2,705,797
Environmental, pension and other		322,248		300,143		244,542
The Notes to Consolidated Financial Statements are an integral part of these statements.
Total Deferred Credits and Other Liabilities		750,895		735,620		659,459
Total Capitalization and Liabilities		$ 3,054,990		$ 2,928,538		$ 2,936,242
The Notes to Consolidated Financial Statements are an integral part of these statements.

Peoples Energy Corporation
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	June 30,		September 30,		June 30,
		Nine Months Ended
(In Thousands, Except Shares)	2003		2002		2002
		June 30,
CAPITALIZATION AND LIABILITIES
(In Thousands)		2004		2003
CAPITALIZATION:
Operating Activities:
Common Stockholders' Equity:
Net income		$ 91,877		$ 102,495
Common stock, without par value -
Adjustments to reconcile net income to cash provided by operations:
Authorized 60,000,000 shares
Depreciation, depletion and amortization		93,765		86,816
Issued 36,863,602, 35,705,106, and
Deferred income taxes and investment tax credits - net		9,106		14,645
35,716,261 shares, respectively	$ 343,430		$ 301,699		$ 300,850
Change in environmental, pension and other liabilities		6,475		31,008
Treasury stock (246,100, 246,100 and 246,100 shares,
Change in undistributed earnings from equity investments		(383)		10,497
respectively, at cost)	(6,760)		(6,760)		(6,760)
Other changes in noncurrent operating activities		(24,328)		(46,952)
Retained earnings	567,976		522,381		539,100
Changes in current assets and liabilities:
Accumulated other comprehensive income (loss)	(28,988)		(10,996)		(14,750)
Receivables - net		(77,390)		(114,424)
Total Common Stockholders' Equity	875,658		806,324		818,440
Gas in storage		67,573		11,138
Long-term debt, exclusive of sinking fund payments,
Gas costs recoverable/refundable through rate adjustments		(4,223)		(16,162)
maturities due within one year and long-term maturities
Net regulatory assets/liabilities of utility subsidiaries		18,474		7,630
classified as short-term debt	744,345		554,014		554,020
Payables and other accrued liabilities		49,132		98,083
Total Capitalization	1,620,003		1,360,338		1,372,460
Accrued taxes		5,996		28,784
CURRENT LIABILITIES:
Temporary LIFO liquidation credit		50,539		47,916
Commercial paper	-		85,871		-
Other		(24,446)		(23,799)
Current maturities of long-term debt	-		90,000		90,000
Net Cash Provided by Operating Activities		262,167		237,675
Other short-term debt	152,000		202,000		302,000
Investing Activities:
Accounts payable	296,111		213,912		198,608
Capital spending		(144,855)		(133,326)
Regulatory liabilities of utility subsidiaries	24,246		29,976		-
Return of capital investments		11,576		7,134
Dividends payable	19,407		18,495		18,501
Decrease in deposits with broker or trustee		3,868		10,277
Customer deposits	23,833		6,536		5,870
Proceeds from the sale of assets		1,250		-
Customer credit balances	25,088		64,105		43,328
Other		(73)		(1,721)
Accrued taxes	76,067		47,283		65,906
Net Cash Used in Investing Activities		(128,234)		(117,636)
Gas costs refundable through rate adjustments	5,967		28		3,080
Financing Activities:
Temporary LIFO liquidation credit	47,916		-		37,811
Proceeds from (payment of) overdrafts		14,045		(21,632)
Accrued interest	14,597		11,582		14,069
Retirement of commercial paper		(55,949)		(85,871)
Total Current Liabilities	685,232		769,788		779,173
Retirement of short-term debt		(102,000)		(140,000)
DEFERRED CREDITS AND OTHER LIABILITIES:
Issuance of long-term debt		177,000		265,000
Deferred income taxes	387,176		378,225		356,835
Retirement of long-term debt		(75,015)		(74,669)
Investment tax credits	27,741		28,340		28,534
Long-term debt issuance/retirement costs		(5,954)		(2,037)
Environmental and other	216,090		186,956		168,795
Issuance of common/treasury stock		35,402		41,731
Total Deferred Credits and Other Liabilities	631,007		593,521		554,164
Dividends paid on common stock		(59,210)		(55,987)
Total Capitalization and Liabilities	$ 2,936,242		$ 2,723,647		$ 2,705,797
Net Cash Used in Financing Activities		(71,681)		(73,465)
The Notes to Consolidated Financial Statements are an integral part of these statements.
Net Increase in Cash and Cash Equivalents		62,252		46,574
Cash and Cash Equivalents at Beginning of Period		13,648		5,433
Cash and Cash Equivalents at End of Period		$ 75,900		$ 52,007
Supplemental Information:
Income taxes paid		$ 12,149		$ 10,973
Interest paid		$ 31,281		$ 31,545
The Notes to Consolidated Financial Statements are an integral part of these statements.

Peoples Energy Corporation
The Peoples Gas Light and Coke Company
CONSOLIDATED STATEMENTS OF CASH FLOWS
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
			Nine Months Ended
	Three Months Ended			Nine Months Ended
	June 30,		~~June 30,~~	June 30,
(In Thousands)			2003		2002
	2004	2003		2004		2003
Operating Activities:
(In Thousands)
Net Income			$ 102,495		$ 87,351
Revenues	$ 202,279	$ 228,429		$ 1,150,188		$ 1,159,241
Adjustments to reconcile net income to cash provided by operations:
Operating Expenses:
Depreciation, depletion and amortization			86,816		77,509
Gas costs	98,929	115,317		668,426		645,474
Deferred income taxes and investment tax credits - net			14,645		34,144
Operation and maintenance	58,528	61,322		197,235		196,191
Change in environmental and other liabilities			22,841		31,102
Depreciation and amortization	15,694	15,136		46,055		44,882
Change in undistributed earnings from equity investments			10,497		16,277
Taxes, other than income taxes	23,237	20,920		124,716		121,224
Other changes in noncurrent operating activities			(48,989)		(44,002)
Gains on property sales	(111)	-		(111)		-
Changes in current assets and liabilities:
Total Operating Expenses	196,277	212,695		1,036,321		1,007,771
Receivables - net			(114,424)		123,604
Operating Income	6,002	15,734		113,867		151,470
Gas in storage			11,138		43,842
Other income and expense - net	767	500		2,022		1,647
Gas costs recoverable/refundable through rate adjustments			(16,162)		(49,617)
Interest expense	4,934	5,311		15,601		17,115
Net regulatory assets/liabilities of utility subsidiaries			7,630		(10,346)
Income Before Income Taxes	1,835	10,923		100,288		136,002
Accounts payable			98,751		(96,135)
Income tax expense (credit)	(618)	4,370		36,774		51,458
Accrued interest			3,015		1,499
Net Income	$ 2,453	$ 6,553		$ 63,514		$ 84,544
Accrued taxes			28,784		34,706
The Notes to Consolidated Financial Statements are an integral part of these statements.
Temporary LIFO liquidation credit			47,916		37,811
Other			(23,799)		8,950
Net Cash Provided by (Used in) Operating Activities			231,154		296,695
Investing Activities:
Capital spending			(133,326)		(114,060)
Net change in advances to joint venture partnerships			-		147,616
Return of capital investments			7,134		62,922
Decrease (increase) in deposits with broker or trustee			10,277		(11,650)
Proceeds from sale of assets			-		1,871
Other			(1,721)		(350)
Net Cash Provided by (Used in) Investing Activities			(117,636)		86,349
Financing Activities:
Proceeds from (payment of) overdraft facility			(17,148)		7,261
Commercial paper - net			(85,871)		-
Retirement of short-term debt			(140,000)		(305,454)
Issuance of long-term debt			265,000		-
Retirement of long-term debt			(74,669)		(288)
Proceeds from issuance of common stock			41,731		1,523
Dividends paid on common stock			(55,987)		(54,511)
Net Cash Provided by (Used in) Financing Activities			(66,944)		(351,469)
Net Increase (Decrease) in Cash and Cash Equivalents			46,574		31,575
Cash and Cash Equivalents at Beginning of Period			5,433		65,166
Cash and Cash Equivalents at End of Period			$ 52,007		$ 96,741
Supplemental information:
Income taxes paid, net of refunds			$ 10,973		$ 15,380
Interest paid, net of amounts capitalized			$ 31,545		$ 39,939
The Notes to Consolidated Financial Statements are an integral part of these statements.

The Peoples Gas Light and Coke Company
CONSOLIDATED STATEMENTS OF INCOME
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	Three Months Ended		Nine Months Ended
		June 30,	September 30,	June 30,
	June 30,		June 30,
		2004	2003	2003
	2003	2002	2003	2002
(In Thousands)
Revenues	$ 228,429	$ 207,161	$ 1,159,241	$ 803,960
ASSETS
Operating Expenses:
CAPITAL INVESTMENTS:
Gas costs	115,317	90,720	645,474	349,360
Property, plant and equipment		$ 2,246,808	$ 2,203,842	$ 2,185,851
Operation and maintenance	61,322	66,477	196,191	162,336
Less - Accumulated depreciation and amortization		894,146	858,838	850,595
Depreciation and amortization	15,136	15,689	44,882	46,469
Net property, plant and equipment		1,352,662	1,345,004	1,335,256
Taxes, other than income taxes	20,920	26,808	121,224	102,555
Other investments		2,012	1,969	2,381
Total Operating Expenses	212,695	199,694	1,007,771	660,720
Total Capital Investments - Net		1,354,674	1,346,973	1,337,637
Operating Income	15,734	7,467	151,470	143,240
CURRENT ASSETS:
Other income and expense - net	500	442	1,647	3,019
Cash and cash equivalents		45,960	-	8,620
Interest expense	5,311	5,209	17,115	18,255
Deposits with broker or trustee		772	11,080	10,158
Earnings Before Income Taxes	10,923	2,700	136,002	128,004
Receivables -
Income tax expense	4,370	719	51,458	48,726
Customers, net of reserve for uncollectible accounts
Net Income	$ 6,553	$ 1,981	$ 84,544	$ 79,278
of $27,423, $29,207 and $29,454, respectively		163,369	131,248	206,540
Intercompany receivables		29,447	27,094	27,452
Other		3,417	2,971	4,082
Materials and supplies, at average cost		8,874	8,404	8,571
Gas in storage, at last-in, first-out cost		40,196	111,992	36,847
Gas costs recoverable through rate adjustments		18,082	22,341	32,308
Regulatory assets		24,372	23,223	3,916
Other		4,238	3,456	2,517
Total Current Assets		338,727	341,809	341,011
OTHER ASSETS:
Prepaid pension costs		176,122	178,003	189,764
Noncurrent regulatory assets		149,363	141,987	148,113
Deferred charges and other		48,546	47,073	29,569
Total Other Assets		374,031	367,063	367,446
Total Assets		$ 2,067,432	$ 2,055,845	$ 2,046,094
The Notes to Consolidated Financial Statements are an integral part of these statements.

The Peoples Gas Light and Coke Company
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,	September 30,	June 30,
	2003	2002	2002
	2004	2003	2003
(In Thousands)
(In Thousands, Except Shares)
ASSETS
CAPITALIZATION AND LIABILITIES
CAPITAL INVESTMENTS:
CAPITALIZATION:
Property, plant and equipment	$ 2,185,851	$ 2,150,825	$ 2,138,475
Common Stockholder's Equity:
Less - Accumulated depreciation and amortization	850,595	813,909	809,225
Common stock, without par value -
Net property, plant and equipment	1,335,256	1,336,916	1,329,250
Authorized 40,000,000 shares
Other investments	11,739	11,724	10,948
Outstanding 24,817,566 shares	$ 165,307	$ 165,307	$ 165,307
Total Capital Investments - Net	1,346,995	1,348,640	1,340,198
Retained earnings	499,830	482,228	503,014
CURRENT ASSETS:
Accumulated other comprehensive loss	(21,019)	(21,052)	(911)
Cash and cash equivalents	8,620	-	-
Total Common Stockholder's Equity	644,118	626,483	667,410
Deposits with broker or trustee	10,158	21,802	10,894
Long-term debt, exclusive of maturities due within one
Receivables -
year and adjustable-rate bonds classified as short-term debt	452,000	350,000	350,000
Customers, net of reserve for uncollectible accounts
Total Capitalization	1,096,118	976,483	1,017,410
of $29,454, $31,569 and $35,311, respectively	206,540	120,825	175,981
CURRENT LIABILITIES:
Intercompany receivables	27,452	20,071	10,821
Commercial paper	-	55,949	-
Other	4,082	11,889	12,159
Other short-term debt	50,000	176,400	152,000
Materials and supplies, at average cost	8,571	8,973	9,242
Accounts payable	91,457	83,409	89,427
Gas in storage, at last-in, first-out cost	36,847	65,364	28,052
Accrued taxes	58,209	29,421	70,888
Gas costs recoverable through rate adjustments	32,308	7,058	11,001
Other accrued liabilities	54,161	43,892	38,550
Regulatory assets	3,916	17,747	13,848
Intercompany payables	17,805	45,720	25,267
Other	2,517	1,354	1,903
Regulatory liabilities	14,758	-	20,908
Total Current Assets	341,011	275,083	273,901
Dividends payable	13,200	-	17,400
OTHER ASSETS:
Customer deposits	26,546	24,470	22,237
Prepaid pension costs	189,764	182,339	176,142
Customer credit balances	21,741	39,728	21,587
Noncurrent regulatory assets	148,113	138,742	111,906
Gas costs refundable through rate adjustments	29	28	2,285
Deferred charges	20,211	15,706	17,809
Temporary LIFO liquidation credit	36,227	-	32,386
Total Other Assets	358,088	336,787	305,857
Total Current Liabilities	384,133	499,017	492,935
Total Assets	$ 2,046,094	$ 1,960,510	$ 1,919,956
DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes	355,862	355,160	353,892
Investment tax credits	23,892	24,634	24,718
Environmental, pension and other	207,427	200,551	157,139
Total Deferred Credits and Other Liabilities	587,181	580,345	535,749
Total Capitalization and Liabilities	$ 2,067,432	$ 2,055,845	$ 2,046,094
The Notes to Consolidated Financial Statements are an integral part of these statements.

The Peoples Gas Light and Coke Company
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	June 30,	September 30,	June 30,
		Nine Months Ended
	2003	2002	2002
		June 30,
(In Thousands, Except Shares)
		2004	2003
CAPITALIZATION AND LIABILITIES
(In Thousands)
CAPITALIZATION:
Operating Activities:
Common Stockholder's Equity:
Net income		$ 63,514	$ 84,544
Common stock, without par value -
Adjustments to reconcile net income to cash provided by operations:
Authorized 40,000,000 shares
Depreciation and amortization		49,607	48,160
Outstanding 24,817,566 shares	$ 165,307	$ 165,307	$ 165,307
Deferred income taxes and investment tax credits - net		(1,558)	4,516
Retained earnings	503,014	471,070	484,754
Change in environmental, pension and other liabilities		8,394	10,222
Accumulated other comprehensive income (loss)	(911)	(491)	(3,015)
Other changes in noncurrent operating activities		(1,538)	(20,288)
Total Common Stockholder's Equity	667,410	635,886	647,046
Changes in current assets and liabilities:
Long-term debt, exclusive of sinking fund payments, maturities
Receivables - net		(34,920)	(85,289)
due within one year and long-term maturities classified
Gas in storage		71,796	28,517
as short-term debt	350,000	175,000	175,000
Gas costs recoverable/refundable through rate adjustments		4,260	(22,993)
Total Capitalization	1,017,410	810,886	822,046
Net regulatory assets/liabilities		13,609	9,976
CURRENT LIABILITIES:
Payables and other accrued liabilities		(22,327)	50,957
Commercial paper	-	82,671	-
Accrued taxes		28,788	33,078
Current maturities of long-term debt	-	75,000	75,000
Temporary LIFO liquidation credit		36,227	32,386
Other short-term debt	152,000	202,000	202,000
Other		(17,166)	(17,329)
Accounts payable	147,226	126,445	113,955
Net Cash Provided by Operating Activities		198,686	156,457
Intercompany payables	25,267	18,845	61,220
Investing Activities:
Regulatory liabilities	20,908	24,763	-
Capital spending		(46,249)	(46,555)
Dividends payable	17,400	11,913	17,620
Decrease in deposits with broker or trustee		10,308	11,644
Customer deposits	22,237	6,222	5,598
Other		(81)	-
Customer credit balances	21,587	54,167	36,629
Net Cash Used in Investing Activities		(36,022)	(34,911)
Accrued taxes	70,888	37,810	71,311
Financing Activities:
Gas costs refundable through rate adjustments	2,285	28	2,890
Proceeds from (payment of) overdrafts		2,168	(16,277)
Temporary LIFO liquidation credit	32,386	-	30,459
Retirement of commercial paper		(55,949)	(82,671)
Accrued interest	3,884	5,208	2,819
Retirement of short-term debt		(126,400)	(140,475)
Total Current Liabilities	516,068	645,072	619,501
Issuance of long-term debt		177,000	225,000
DEFERRED CREDITS AND OTHER LIABILITIES:
Retirement of long-term debt		(75,000)	(50,000)
Deferred income taxes	353,892	346,723	332,308
Long-term debt issuance/retirement costs		(5,923)	(1,391)
Investment tax credits	24,718	25,280	25,426
Dividends paid on common stock		(32,600)	(47,112)
Environmental and other	134,006	132,549	120,675
Net Cash Used in Financing Activities		(116,704)	(112,926)
Total Deferred Credits and Other Liabilities	512,616	504,552	478,409
Net Increase in Cash and Cash Equivalents		45,960	8,620
Total Capitalization and Liabilities	$ 2,046,094	$ 1,960,510	$ 1,919,956
Cash and Cash Equivalents at Beginning of Period		-	-
Cash and Cash Equivalents at End of Period		$ 45,960	$ 8,620
Supplemental Information:
Income taxes paid		$ 5,932	$ 3,771
Interest paid		$ 15,923	$ 16,194
The Notes to Consolidated Financial Statements are an integral part of these statements.

The Peoples Gas Light and Coke Company
North Shore Gas Company
CONSOLIDATED STATEMENTS OF CASH FLOWS
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
		Nine Months Ended
	Three Months Ended		Nine Months Ended
	June 30,	~~June 30,~~	June 30,
		2003	2002
	2004	2003	2004	2003
(In Thousands)
Operating Activities:
Revenues	$ 33,678	$ 40,313	$ 198,825	$ 208,526
Net Income		$ 84,544	$ 79,278
Operating Expenses:
Adjustments to reconcile net income to cash provided by operations:
Gas costs	19,707	24,871	131,330	137,917
Depreciation and amortization		48,160	49,931
Operation and maintenance	8,300	8,132	26,637	24,048
Deferred income taxes and investment tax credits - net		6,607	22,636
Depreciation	1,784	1,769	5,386	5,284
Change in environmental and other liabilities		1,457	31,762
Taxes, other than income taxes	2,840	2,952	13,735	14,266
Other changes in noncurrent operating activities		(21,679)	(40,273)
Gains on property sales	(1,130)	-	(1,130)	-
Changes in current assets and liabilities:
Total Operating Expenses	31,501	37,724	175,958	181,515
Receivables - net		(85,289)	84,639
Operating Income	2,177	2,589	22,867	27,011
Gas in storage		28,517	39,100
Other income and expense - net	82	77	130	(85)
Gas costs recoverable/refundable through rate adjustments		(22,993)	(39,280)
Interest expense	911	825	2,776	2,688
Net regulatory assets/liabilities		9,976	(10,790)
Income Before Income Taxes	1,348	1,841	20,221	24,238
Accounts payable		59,411	(102,506)
Income tax expense	427	982	7,489	9,379
Accrued interest		(1,324)	(2,335)
Net Income	$ 921	$ 859	$ 12,732	$ 14,859
Accrued taxes		33,078	27,046
The Notes to Consolidated Financial Statements are an integral part of these statements.
Temporary LIFO liquidation credit		32,386	30,459
Other		(17,329)	6,708
Net Cash Provided by (Used in) Operating Activities		155,522	176,375
Investing Activities:
Capital spending		(46,555)	(56,598)
Decrease (increase) in deposits with broker or trustee		11,644	(10,894)
Proceeds from sale of assets		-	1,871
Other		-	(350)
Net Cash Provided by (Used in) Investing Activities		(34,911)	(65,971)
Financing Activities:
Proceeds from (payment of) overdraft facility		(16,733)	7,261
Commercial paper - net		(82,671)	(143,245)
Retirement of short-term debt		(140,475)	-
Issuance of long-term debt		225,000	-
Retirement of long-term debt		(50,000)	-
Dividends paid on common stock		(47,112)	(35,241)
Net Cash Provided by (Used in) Financing Activities		(111,991)	(171,225)
Net Increase (Decrease) in Cash and Cash Equivalents		8,620	(60,821)
Cash and Cash Equivalents at Beginning of Period		-	60,821
Cash and Cash Equivalents at End of Period		$ 8,620	$ -
Supplemental information:
Income taxes paid, net of refunds		$ 3,771	$ 18,210
Interest paid, net of amounts capitalized		$ 16,194	$ 19,203
The Notes to Consolidated Financial Statements are an integral part of these statements.

North Shore Gas Company
CONSOLIDATED STATEMENTS OF INCOME
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	Three Months Ended				Nine Months Ended
		June 30,		September 30,		June 30,
	June 30,				June 30,
		2004		2003		2003
	2003		2002		2003		2002
(In Thousands)
(In Thousands)
ASSETS
Revenues	$ 40,313		$ 34,742		$ 208,526		$ 138,410
CAPITAL INVESTMENTS:
Operating Expenses:
Property, plant and equipment		$ 353,718		$ 348,622		$ 346,803
Gas costs	24,871		18,875		137,917		75,568
Less - Accumulated depreciation		140,625		136,299		135,809
Operation and maintenance	8,132		6,416		24,048		20,693
Net property, plant and equipment		213,093		212,323		210,994
Depreciation	1,769		1,669		5,284		4,915
CURRENT ASSETS:
Taxes, other than income taxes	2,952		2,929		14,266		11,524
Cash and cash equivalents		20,747		12,108		29,839
Total Operating Expenses	37,724		29,889		181,515		112,700
Deposits with broker or trustee		813		2,766		2,274
Operating Income	2,589		4,853		27,011		25,710
Receivables -
Other income and expense - net	77		77		(85)		117
Customers, net of reserve for uncollectible
Interest expense	825		1,219		2,688		3,819
accounts of $1,024, $1,012 and $1,107, respectively		29,221		16,090		25,829
Earnings Before Income Taxes	1,841		3,711		24,238		22,008
Intercompany receivables		4,529		1,466		2,668
Income tax expense	982		1,376		9,379		8,443
Other		1,622		800		762
Net Income	$ 859		$ 2,335		$ 14,859		$ 13,565
Materials and supplies, at average cost		1,209		1,351		1,270
The Notes to Consolidated Financial Statements are an integral part of these statements.
Gas in storage, at last-in, first-out cost		5,856		9,442		4,481
Gas costs recoverable through rate adjustments		3,796		323		11
Regulatory assets		1,935		4,055		999
Other		517		202		330
Total Current Assets		70,245		48,603		68,463
OTHER ASSETS:
Noncurrent regulatory assets		37,898		39,236		39,091
Deferred charges and other		3,208		3,980		2,775
Total Other Assets		41,106		43,216		41,866
Total Assets		$ 324,444		$ 304,142		$ 321,323
The Notes to Consolidated Financial Statements are an integral part of these statements.

North Shore Gas Company
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,	September 30,	June 30,
	2003	2002	2002
	2004	2003	2003
(In Thousands)
(In Thousands, Except Shares)
ASSETS
CAPITALIZATION AND LIABILITIES
CAPITAL INVESTMENTS:
CAPITALIZATION:
Property, plant and equipment	$ 346,803	$ 342,498	$ 339,946
Common Stockholder's Equity:
Less - Accumulated depreciation	135,809	131,523	131,223
Common stock, without par value -
Net property, plant and equipment	210,994	210,975	208,723
Authorized 5,000,000 shares
Other investments	22	22	22
Outstanding 3,625,887 shares	$ 24,757	$ 24,757	$ 24,757
Total Capital Investments - Net	211,016	210,997	208,745
Retained earnings	84,813	80,882	83,985
CURRENT ASSETS:
Accumulated other comprehensive loss	(2,260)	(2,278)	(224)
Cash and cash equivalents	29,839	-	11,789
Total Common Stockholder's Equity	107,310	103,361	108,518
Deposits with broker or trustee	2,274	5,062	2,464
Long-term debt, exclusive of maturities due within one year	69,330	69,345	69,345
Receivables -
Total Capitalization	176,640	172,706	177,863
Customers, net of reserve for uncollectible
CURRENT LIABILITIES:
accounts of $1,107, $493, and $686, respectively	25,829	13,550	17,799
Accounts payable	15,760	13,202	14,918
Intercompany receivables	2,668	5,608	2,200
Accrued taxes	6,500	315	8,885
Other	762	599	524
Other accrued liabilities	4,431	5,143	4,200
Materials and supplies, at average cost	1,270	974	1,689
Intercompany payables	4,252	10,060	1,825
Gas in storage, at last-in, first-out cost	4,481	9,529	5,162
Regulatory liabilities	2,744	-	3,338
Gas costs recoverable through rate adjustments	11	3,160	1,198
Dividends payable	2,500	-	3,700
Regulatory assets	999	527	379
Customer deposits	2,073	1,899	1,596
Other	330	235	471
Customer credit balances	4,186	6,963	3,441
Total Current Assets	68,463	39,244	43,675
Gas costs refundable through rate adjustments	-	5,011	3,682
OTHER ASSETS:
Temporary LIFO liquidation credit	14,312	-	15,529
Prepaid pension costs	-	-	2,572
Total Current Liabilities	56,758	42,593	61,114
Noncurrent regulatory assets	39,091	28,494	21,577
DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred charges	2,753	3,353	3,686
Deferred income taxes	32,275	31,126	30,063
Total Other Assets	41,844	31,847	27,835
Investment tax credits	2,926	3,008	3,023
Total Assets	$ 321,323	$ 282,088	$ 280,255
Environmental, pension and other	55,845	54,709	49,260
Total Deferred Credits and Other Liabilities	91,046	88,843	82,346
Total Capitalization and Liabilities	$ 324,444	$ 304,142	$ 321,323
The Notes to Consolidated Financial Statements are an integral part of these statements.

North Shore Gas Company
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	June 30,	September 30,	June 30,
		Nine Months Ended
	2003	2002	2002
		June 30,
(In Thousands, Except Shares)
		2004	2003
CAPITALIZATION AND LIABILITIES
(In Thousands)
CAPITALIZATION:
Operating Activities:
Common Stockholder's Equity:
Net income		$ 12,732	$ 14,859
Common stock, without par value -
Adjustments to reconcile net income to cash provided by operations:
Authorized 5,000,000 shares
Depreciation		5,958	5,682
Outstanding 3,625,887 shares	$ 24,757	$ 24,757	$ 24,757
Deferred income taxes and investment tax credits - net		1,874	1,967
Retained earnings	83,985	77,726	81,670
Change in environmental, pension and other liabilities		329	9,597
Accumulated other comprehensive income (loss)	(224)	-	-
Other changes in noncurrent operating activities		973	(10,221)
Total Common Stockholder's Equity	108,518	102,483	106,427
Changes in current assets and liabilities:
Long-term debt, exclusive of sinking fund payments and
Receivables - net		(17,016)	(9,502)
maturities due within one year	69,345	54,014	54,020
Gas in storage		3,586	5,048
Total Capitalization	177,863	156,497	160,447
Gas costs recoverable/refundable through rate adjustments		(8,484)	6,831
CURRENT LIABILITIES:
Net regulatory assets/liabilities		4,864	(2,347)
Current maturities of long-term debt	-	15,000	15,000
Payables and other accrued liabilities		(4,230)	3,976
Accounts payable	21,291	16,864	14,507
Accrued taxes		6,185	6,684
Intercompany payables	1,825	5,754	2,516
Temporary LIFO liquidation credit		14,312	15,529
Regulatory liabilities	3,338	5,213	-
Other		(2,777)	(5,576)
Dividends payable	3,700	-	-
Net Cash Provided by Operating Activities		18,306	42,527
Customer deposits	1,595	314	272
Investing Activities:
Customer credit balances	3,442	9,907	6,669
Capital spending		(6,781)	(5,700)
Accrued taxes	8,885	2,201	8,181
Decrease in deposits with broker or trustee		1,953	2,788
Gas costs refundable through rate adjustments	3,682	-	190
Proceeds from the sale of assets		1,250	-
Temporary LIFO liquidation credit	15,529	-	7,352
Other		(42)	-
Accrued interest	435	1,704	606
Net Cash Used in Investing Activities		(3,620)	(2,912)
Total Current Liabilities	63,722	56,957	55,293
Financing Activities:
DEFERRED CREDITS AND OTHER LIABILITIES:
Proceeds from (payment of) overdrafts		268	(2,997)
Deferred income taxes	30,063	26,768	27,507
Issuance of short-term debt		-	(17,210)
Investment tax credits	3,023	3,061	3,107
Issuance of long-term debt		-	40,000
Environmental and other	46,652	38,805	33,901
Retirement of long-term debt		(15)	(24,669)
Total Deferred Credits and Other Liabilities	79,738	68,634	64,515
Dividends paid on common stock		(6,300)	(4,900)
Total Capitalization and Liabilities	$ 321,323	$ 282,088	$ 280,255
Net Cash Used in Financing Activities		(6,047)	(9,776)
Net Increase in Cash and Cash Equivalents		8,639	29,839
Cash and Cash Equivalents at Beginning of Period		12,108	-
Cash and Cash Equivalents at End of Period		$ 20,747	$ 29,839
Supplemental Information:
Income taxes paid		$ 254	$ 302
Interest paid		$ 3,436	$ 3,743
The Notes to Consolidated Financial Statements are an integral part of these statements.

North Shore Gas Company
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
June 30,
2003 2002
(In Thousands)
Operating Activities:
Net Income $ 14,859 $ 13,565
Adjustments to reconcile net income to cash provided by operations:
Depreciation 5,682 5,265
Deferred income taxes and investment tax credits - net 1,967 1,831
Change in environmental and other liabilities 9,137 1,857
Other changes in noncurrent operating activities (10,221) 458
Changes in current assets and liabilities:
Receivables - net (9,502) 1,568
Gas in storage 5,048 3,612
Gas costs recoverable/refundable through rate adjustments 6,831 (10,338)
Net regulatory assets/liabilities (2,347) 444
Accounts payable 3,123 (7,820)
Accrued interest (1,269) (1,106)
Accrued taxes 6,684 7,268
Temporary LIFO liquidation credit 15,529 7,352
Other (5,576) 2,170
Net Cash Provided by (Used in) Operating Activities 39,945 26,126
Investing Activities:
Capital spending (5,700) (7,228)
Decrease (increase) in deposits with broker or trustee 2,788 (2,464)
Net Cash Provided by (Used in) Investing Activities (2,912) (9,692)
Financing Activities:
Proceeds from (payment of) overdraft facility (415) -
Retirement of short-term debt (17,210) -
Issuance of long-term debt 40,000 -
Retirement of long-term debt (24,669) (288)
Dividends paid on common stock (4,900) (7,832)
Net Cash Provided by (Used in) Financing Activities (7,194) (8,120)
Net Increase (Decrease) in Cash and Cash Equivalents 29,839 8,314
Cash and Cash Equivalents at Beginning of Period - 3,475
Cash and Cash Equivalents at End of Period $ 29,839 $ 11,789
Supplemental information:
Income taxes paid, net of refunds $ 302 $ -
Interest paid, net of amounts capitalized $ 3,743 $ 4,523
The Notes to Consolidated Financial Statements are an integral part of these statements.
Notes to Consolidated Financial Statements (Unaudited)

141. BASIS OF PRESENTATION

~~NOTES~~ The TOcondensed, ~~CONSOLIDATED~~unaudited ~~FINANCIAL~~financial ~~STATEMENTS~~statements of Peoples Energy Corporation (the Company or Peoples Energy), The Peoples Gas Light and Coke Company (Peoples Gas) and North Shore Gas Company (North Shore Gas), have been prepared by the Company pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). Peoples Gas and North Shore Gas are wholly-owned subsidiaries of the Company.

This Quarterly Report on Form 10-Q is a combined report of the Company, Peoples Gas and North Shore Gas. Certain footnote disclosures and other information, normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (~~Unaudited~~GAAP), have been condensed or omitted from these interim financial statements, pursuant to SEC rules and regulations. Therefore, the statements should be read in conjunction with the consolidated financial statements and related notes contained in the Annual Report on Form 10-K for the Company, Peoples Gas and North Shore Gas for the fiscal year ended September 30, 2003. Certain items previously reported for the prior periods have been reclassified to conform with the presentation in the current period. Due to a number of factors, including seasonality of businesses and market price volatility, the quarterly results of operations and statements of financial position and cash flows should not be considered indicative of the year as a whole.

1. In ~~SIGNIFICANT~~the ~~ACCOUNTING~~opinion ~~POLICIES~~of management, the accompanying unaudited consolidated financial statements contain all adjustments, consisting of normal recurring accruals unless otherwise noted, necessary to present fairly the financial position of the Company, Peoples Gas and North Shore Gas and their results of operations and cash flows for the interim periods presented.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Gas in Storage

Peoples Gas' and North Shore Gas' inventories are carried at cost on a last-in, first-out (LIFO) method ~~on a fiscal year basis~~. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation credit. ~~Any~~Due ~~interim~~to ~~reductions~~seasonality inrequirements, the ~~LIFO~~Company ~~layers~~expects ~~are~~interim ~~due~~reductions toin ~~seasonality~~LIFO ~~and~~layers ~~are expected~~ to be replenished by the fiscal year end.

Recovery of Gas Costs
Under the tariffs of Peoples Gas and North Shore Gas, all prudently incurred gas costs are recoverable from customers. The difference for any month between costs recoverable through the Gas Charge and the actual amount billed to customers under the Gas Charge is recovered from or refunded to customers through future adjustments to the Gas Charge. Such difference for any month is recorded either as a current asset or as a current liability (with a contra entry to Gas Costs). Gas Costs consist of two types - Commodity and Non-Commodity costs. The two types are tracked independently and may cause both an accounts receivable from and an accounts payable to customers.
For each utility subsidiary, the Illinois Commerce Commission (Commission) conducts annual proceedings regarding the reconciliation of revenues from the Gas Charge and related gas costs. In these proceedings, the accuracy of the reconciliation of revenues and costs is reviewed and the prudence of gas costs recovered through the Gas Charge is examined by interested parties. If the Commission were to find that the reconciliation was inaccurate or any gas costs were imprudently incurred, the Commission would order the utility to refund the affected amount to customers through subsequent Gas Charge filings. The proceedings are typically initiated shortly after the close of the fiscal year and take at least a year to 18 months to complete. Proceedings regarding Peoples Gas and North Shore Gas for the fiscal year 2001 costs are currently pending before the Commission. On August 7, 2003, three intervenors (Citizens Utility Board (CUB), Illinois Attorney General and the City of Chicago) filed testimony in Peoples Gas' proceeding and one intervenor (CUB) filed testimony in North Shore Gas' proceeding. Prudence issues raised by the intervenors in the Peoples Gas proceeding related primarily to not having financially hedged gas costs during the winter of 2000-2001 and the use of its Manlove storage field to support transactions with third parties ("hub" transactions). Each of the intervenors requested disallowances, which vary in amount depending upon the issues raised and the assumptions and methodologies used to measure the impact of the issues. In the Peoples Gas proceeding, the Illinois Attorney General and CUB have requested disallowances, which range from $8.0 million to $56.0 million, covering a variety of alleged issues other than financial hedging. CUB has requested an additional disallowance of $53.0 million based on the financial hedging issue and the City of Chicago has requested a disallowance of $230.0 million based entirely on the contention that Peoples Gas should have hedged all of its minimum winter supply requirements. In the North Shore Gas proceeding, CUB raised only the hedging issue and recommended a disallowance of $10.0 million. The Company believes that its 2001 purchasing practices were consistent with the standards applied by the Commission in its past Orders and upheld by the Illinois courts. Although the Company cannot predict the outcome of these proceedings, the Company is confident that it conducted business prudently and in the best interest of customers within these established standards.
The Commission's Staff is expected to file its testimony in both cases by August 15, 2003. Peoples Gas and North Shore Gas will respond to the intervenors in rebuttal testimony that will be submitted at a date that has not yet been set by the Administrative Law Judge (Judge). The remaining procedural schedule is currently suspended, pending expected discussion of a schedule at an August 22, 2003 status hearing. An order from the Commission is not expected before the third quarter of fiscal 2004.
15
The fiscal year 2002 Gas Charge reconciliation case for each utility subsidiary was initiated on November 7, 2002. On December 18, 2002, the Judge granted each utility subsidiary's motion to extend time to file its direct testimony to May 1, 2003 and on April 4, 2003 the Judge granted a second motion extending that date to August 1, 2003. Each utility subsidiary filed its direct testimony and exhibit on August 1. There is a status hearing on September 10, 2003 and no other procedural dates have been set.
Stock Compensation Plans

~~The~~A ~~Financial~~new ~~Accounting~~compensation ~~Standards~~plan, ~~Board~~the ~~(FASB)~~2004 ~~Statement~~Incentive ofCompensation ~~Financial~~Plan ~~Accounting Standards~~ (~~SFAS~~2004 Plan) ~~No.~~was ~~123,~~approved ~~"Accounting~~by ~~for~~shareholders ~~Stock-Based~~at ~~Compensation,"~~the ~~was~~Company's ~~amended~~annual bymeeting ~~Statement~~held ofon ~~Financial~~February 27, ~~Accounting Standards No~~2004. ~~148,~~The ~~"Accounting~~2004 ~~for~~Plan ~~Stock-Based~~is ~~Compensation~~comprised -of ~~Transition~~two ~~and Disclosure~~sub-plans, anthe ~~amendment~~Long-Term ofPlan ~~FASB~~and ~~Statement~~the NoShort-Term Plan. ~~123,"~~The ~~(SFAS~~adoption ~~No.~~of ~~148)~~the to2004 ~~provide~~Plan ~~alternative~~effectively ~~methods~~replaces ofthe ~~transition~~Company's ~~for~~Long-Term aIncentive ~~voluntary~~Compensation ~~change~~Plan to(LTIC ~~the~~Plan) ~~fair~~and ~~value~~Short-Term ~~based~~Incentive ~~method~~Compensation ofPlan. ~~accounting~~The ~~for~~2004 ~~stock-based~~Plan ~~employee~~does ~~compensation.~~not Inprovide ~~addition,~~for the ~~disclosure~~grant ~~requirements~~ of ~~SFAS~~stock Nooptions. ~~148~~No ~~requires~~expense ~~prominent~~has ~~disclosures~~been inaccrued ~~both~~with ~~annual~~respect ~~and~~to ~~interim~~performance ~~financial~~shares ~~statements~~awarded ~~about~~under the ~~method~~2004 ofPlan ~~accounting for stock-~~based ~~employee~~upon ~~compensation~~current ~~and~~estimates ~~the effect~~ of ~~the~~Company ~~method used on reported results~~performance.

As allowed under Statement of Financial Accounting Standards (SFAS) ~~Nos~~No. ~~123~~148, "Accounting for Stock-Based Compensation - Transition and ~~148~~Disclosure, an amendment of Financial Accounting Standards Board (FASB) Statement No. 123," the Company has chosen to continue accounting for stock-based compensation under Accounting Principles Board ~~(APB)~~ Opinion No. 25. Therefore, no compensation cost has been recognized for nonqualified stock options (under ~~both~~ the ~~Long-Term~~superceded ~~Incentive~~LTIC ~~Compensation~~ Plan ~~(LTIC)~~ and ~~Director~~the Directors Stock and Option Plan (DSOP)) and shares issued under the Employee Stock Purchase Plan (ESPP). No options were granted in the nine-month period ended June 30, 2004. There were 426,900 ~~and 550,500~~ options granted in the nine-month ~~periods~~period ofended ~~fiscal~~June ~~2003 and 2002~~30, ~~respectively~~2003. There were 1213,~~926~~244 shares and 12,~~921~~926 shares sold through the ESPP in the nine-month periods ofended ~~fiscal~~June ~~2003~~30, 2004 and ~~2002~~2003, respectively.

~~The following table presents the stock-based employee compensation cost included in reported net income for the three- and nine-month periods.~~14

	Three Months Ended June 30,		Nine Months Ended June 30,
(In Thousands)	2003	2002	2003	2002
Stock appreciation rights	$2,420	$(957)	$2,937	$(1,063)
Director fees paid in stock	451	101	730	193
Restricted stock awards	8	119	814	1,073
Total stock-based compensation cost included in net income	$2,879	$(737)	$4,481	$ 203

Stock-based employee compensation cost relative to stock appreciation rights, restricted stock awards and directors fees paid in stock included in reported net income for the three- and nine-month periods ended June 30, 2004 totaled $0.1 million and $1.5 million, respectively. Stock-based employee compensation cost included in reported net income for the three- and nine-month periods ended June 30, 2003 totaled $2.9 million and $5.4 million, respectively. Had compensation cost for stock options and shares issued under the superceded LTIC Plan, DSOP and ESPP been determined consistent with SFAS No. 123, the Company's net income and earnings per share would have been reduced to the following pro forma amounts:

Had compensation cost for stock options (under both LTIC and DSOP) and shares issued under the ESPP been determined consistent with SFAS Nos. 123 as amended, and 148, the Company's net income and earnings per share would have been reduced to the following pro forma amounts:

	Three Months Ended		Nine Months Ended
	June 30,		June 30,
(In Thousands, Except Per-Share Amounts)	2004	2003	2004	2003
Net income as reported	$ 5,623	$ 8,013	$ 91,877	$ 102,495
Pro forma effects of LTIC, DSOP and ESPP
compensation expense under SFAS No. 123	17	227	29	672
Pro forma net income	$ 5,606	$ 7,786	$ 91,848	$ 101,823
Earnings per average common share:
Basic	$ 0.15	$ 0.22	$ 2.47	$ 2.86
Diluted	0.15	0.22	2.46	2.85
Pro forma basic	0.15	0.22	2.47	2.84
Pro forma diluted	0.15	0.21	2.46	2.83

	Three Months Ended June 30,			Nine Months Ended June 30,
(In Thousands, Except Per-Share Amounts)		2003	2002		2003	2002
Net income as reported		$8,013	$1,336		$102,495	$87,351
Pro forma stock option and ESPP compensation expense under SFAS 123		227	413		672	1,186
Pro forma net income		$7,786	$ 923		$101,823	$86,165
Earnings per average common share:
Basic		$ 0.22	$ 0.04		$ 2.86	$ 2.46
Diluted		0.22	0.04		2.85	2.46
Pro forma basic		0.22	0.03		2.84	2.43
Pro forma diluted		$ 0.21	$ 0.03		$ 2.83	$ 2.43

For the three and nine months ended June 30, 2004, all outstanding options were included in the computation of diluted earnings per share. For the three and nine months ended June 30, 2003, options to purchase 470,300 shares and 580,900 shares of common stock, respectively, were excluded from the computation of diluted earnings per share because the option exercise prices were greater than the average market price of the common shares, and therefore were antidilutive.

16 The following table summarizes the assumptions used to calculate the fair value of each option grant. The pro forma disclosures are based upon recognizing expense over the vesting period of the options, the longest of which is 12 months. There was no pro forma effect for the three months ended June 30, 2004 as all outstanding options had vested prior to that period.

For the three and nine months ended June 30, 2003, options to purchase 470,300 and 580,900 shares of common stock, respectively, were excluded from the computation of diluted earnings per share because the option exercise prices were greater than the average market price of the common shares, and therefore were antidilutive. For the three and nine months ended June 30, 2002, 563,900 and 568,900 antidilutive shares were excluded from the computation of diluted earnings per share.

	Three Months Ended		Nine Months Ended
	June 30,		June 30,
	2004	2003	2004	2003
Expected volatility	N/A	25.84%	25.90%	25.80%
Dividend yield	N/A	4.9%	5.1%	4.9%
Risk-free interest rate	N/A	2.09%	2.47%	2.13%
Expected lives (years)	N/A	3	3	3
Weighted average fair value	N/A	$ 3.34	$ 3.83	$ 3.37

The fair value of each option grant used to determine pro forma net income is estimated as of the date of grant using a variation of the Black-Scholes option-pricing model with the following weighted average assumptions used for grants in the three and nine months ended June 30, 2003 and 2002. The pro forma expense is recognized over the vesting period of the options, the longest of which is 12 months.
Three Months Ended June 30, Nine Months Ended June 30,
2003 2002 2003 2002
Expected volatility 25.84% 24.72% 25.80% 24.74%
Dividend yield 4.9% 5.7% 4.9% 5.7%
Risk-free interest rate 2.09% 3.17% 2.13% 3.16%
Expected lives (years) 3 3 3 3
Weighted average fair value $3.34 $4.83 $3.37 $4.84
Derivative Instruments and Hedging Activities

The Company's earnings may vary due to changes in commodity prices and interest rates (market risk) that affect its subsidiaries' operations and investments. To manage this market risk, the Company uses forward contracts and financial instruments, including commodity futures contracts, swaps and options.

~~The~~Cash ~~Company~~Flow ~~has hedged various anticipated cash flow transactions through December 2006~~Hedges. The majority of these hedges are related to the Company's forecasted sales of oil and gas produced by its oil and gas subsidiary. During the nine months ended June 30, 2003, the Company recorded in earnings a $19.9 million loss ($12.0 million, net of tax) related to oil and gas hedge activity. The majority of this activity was recorded in accumulated other comprehensive income (AOCI) as of September 30, 2002 with the exception of gains and losses attributable to hedges entered into and settled during the first nine months of fiscal 2003, which accounted for $3.8 million. The Company anticipates reclassifying, in the next 12 months as the underlying hedged physical transactions are recorded in earnings, $23.5 million of deferred losses from AOCI into earnings, as calculated using commodity prices at June 30, 2003. As of June 30, 2003, the Company has $49.7 million of derivative liabilities, $7.3 million of derivative assets and cumulative deferred losses in AOCI of $25.6 million, net of taxes, related to oil and gas cash flow hedges.
The Company has positions in oil and gas reserves, natural gas, and transportation as part of its Oil and Gas Production, Midstream Services and Retail Energy Services businesses. The Company uses derivative financial instruments to protect against loss of value of future anticipated cash transactions caused by changes in the market place. These instruments are designated cash flow hedges, which allow for the unrealized changes in value during the life of the hedge to be recorded in other comprehensive income. The Company has also used cash flow hedges to reduce interest rate risk associated with debt refinancing activities. Realized gains and

The Company's Midstream Services segment also uses derivative instruments to hedge its storage and transportation assets. As of June 30, 2003, the recorded loss in AOCI related to this activity is $0.5 million, net of taxes. The Company anticipates reclassifying all of this activity into earnings over the next 12 months as the underlying hedged physical transactions are recorded in earnings.15

~~The~~losses ~~Company~~from ~~also~~cash ~~records~~flow ~~adjustments~~hedges toare ~~AOCI to reflect its share of AOCI amounts~~ recorded byin ~~partnerships~~the ~~related~~income tostatement ~~their hedging activity. The Company records an offsetting amount to its investment~~ in the ~~partnership.~~same Asmonth ~~of June 30, 2003,~~ the ~~recorded loss in AOCI~~ related tophysical ~~these~~sales ~~investments~~and ~~was~~purchases ~~$4.0~~and ~~million,~~interest ~~net~~expense ofis ~~taxes~~recorded.

~~Peoples~~The ~~Gas~~following ~~and~~table ~~North~~summarizes ~~Shore~~selected ~~Gas,~~information asrelated ~~part of the gas price protection program, use derivative transactions~~ to ~~mitigate~~cash ~~volatility~~flow ~~in their respective Gas Charges. Since these derivative instruments are not designated as~~ hedges ~~and~~included ~~are~~in ~~employed to support gas costs charged to regulated gas customers,~~ the ~~accounting~~Consolidated ~~for~~Income ~~these~~Statement ~~derivative~~and ~~instruments~~Balance isSheet ~~subject~~through ~~to SFAS No. 71. As of~~ June 30, ~~2003, Peoples Gas and North Shore Gas have net regulatory liabilities related to these transactions of $20~~2004.~~9 million and $3.3 million, respectively. Any realized gains or losses associated with this activity will be included in gas costs passed through to utility customers.~~

		Interest	Partnership
(In Thousands)	Commodities	Rate	Transactions	Total
Portion of after tax gains (losses) on hedging instruments determined
to be ineffective and included in net income during the
nine months ended June 30, 2004	$ (422)	$ -	$ -	$ (422)
Accumulated other comprehensive income (loss) after tax at
June 30, 2004	$ (37,659)	$ (579)	$ (4,207)	$(42,445)
Portion of accumulated other comprehensive income (loss) expected
to be reclassified to earnings during the next 12 months based on
prices at June 30, 2004	$ (25,003)	$ (131)	N/A	$(25,134)
Maximum term	39 months	106 months

The maturities of the open cash flow hedges are summarized in the table below. All valuations are based on New York Mercantile Exchange (NYMEX) closing prices at June 30, 2004.

Cash Flow Hedges
Value by Year of Maturity

		Less than	1 to 2	2 to 3	3 to 4
(In Thousands)	Total	1 Year	Years	Years	Years
Gain (loss) at June 30, 2004	$(64,040)	$(39,351)	$(21,046)	$ (4,024)	$ 381
Loss at June 30, 2003	$(41,773)	$(22,567)	$(11,786)	$ (5,638)	$ (1,782)

Mark-To-Market Derivative Instruments.
Peoples Gas and North Shore Gas use derivative instruments to manage each utility's cost of gas supply and mitigate price volatility. The regulated utilities' tariffs allow for full recovery from their customers of prudently incurred gas supply cost. Since the utilities do not bear the price risk associated with future gas supply purchases, any associated derivative activity will not qualify for hedge accounting and therefore must be mark to market. SFAS No. 71 allows any of these derivative gains or losses to be recorded as regulatory assets or regulatory liabilities. Realized gains or losses are recorded as an adjustment to the cost of gas supply in the period that the underlying gas purchase transaction takes place. The costs and benefits of this activity are passed through to customers under the tariffs of Peoples Gas and North Shore Gas. The following table summarizes this activity and other derivative instruments that are not hedges and are recorded on a mark-to-market basis. All amounts are expected to be settled during the next 12 months.

	June 30,
(In Thousands)	2004	2003
Peoples Gas mark-to-market asset	$ 14,758	$ 20,859
North Shore Gas mark-to-market asset	2,744	3,329
Other mark-to-market asset (liability)	128	(100)
Total	$ 17,630	$ 24,088

Fair Value Hedges.
A small portion of the Company's financial hedges are used to protect the value of gas in storage and are accounted for as fair value hedges. The change in value of these hedges along with the change in value of the inventory hedged are recorded in the income statement.

Derivative Summary.
The following table summarizes the changes in valuation of all outstanding derivative contracts during the nine months ended June 30, 2004 and 2003.

	Derivative Type
	Cash Flow		Fair Value
	Hedges		Hedges		Mark-to-Market
(In Thousands)	2004	2003	2004	2003	2004	2003
Gain (loss) on contracts outstanding at 10/01/2003	$(26,571)	$(35,029)	$ (65)	$ (3)	$ 13,691	$ 37,065
Less: Gain (loss) on contracts realized or otherwise
settled during the period	(17,291)	(8,410)	2	95	3,853	19,639
Plus: Gain (loss) on new contracts entered into during the
period and outstanding at end of period	(24,992)	1,220	157	102	14,320	(2,937)
Plus: Other gain (loss)	(29,768)	(16,374)	38	98	(6,528)	9,599
Gain (loss) on contracts outstanding at 06/30/2004	$ (64,040)	$ (41,773)	$ 128	$ 102	$ 17,630	$ 24,088

Revenue Recognition

Gas and electricity sales and transportation revenues are recorded on the accrual basis for all gas and electricity delivered during the month, including an estimate for gas and electricity delivered but unbilled at the end of each month. The amount of accrued unbilled revenue is summarized below.

	June 30,
(In Thousands)	2004	2003
Peoples Gas	$ 15,516	$ 21,131
North Shore Gas	3,666	3,799
Peoples Energy Services	15,701	11,190
Consolidated Peoples Energy	$ 34,883	$ 36,120

In Illinois, delivering, supplying, furnishing or selling gas for use or consumption and not for resale is subject to state and, in some cases, municipal taxes (revenue taxes). The Illinois Public Utility Act provides that the tax may be recovered from utility customers by adding an additional charge to customers' bills. These taxes are due only to the extent they are collected as cash receipts as opposed to amounts billed. As a result, most revenue taxes are reported on a gross basis. The billed amounts for the recovery of these taxes are included in revenues and an offsetting expense amount representing the expected cash payment of the taxes is included in taxes, other than income taxes on the income statement. Revenue tax amounts included in utility revenues are as follows:

	Three Months Ended		Nine Months Ended
	June 30,		June 30,
(In Thousands)	2004	2003	2004	2003
Peoples Gas	$ 18,997	$ 21,975	$ 112,855	$117,284
North Shore Gas	1,711	2,053	10,969	11,608
Consolidated Peoples Energy	$ 20,708	$ 24,028	$ 123,824	$128,892

Natural gas and crude oil production revenues are recorded on the entitlement method. Under the entitlement method, revenue is recorded when title is transferred based on the Company's net interest. The Company records its entitled share of revenues based on estimated production volumes. Subsequently, these estimated volumes are adjusted to reflect actual volumes that are supported by third party statements and/or cash receipts.

~~The~~Statement ~~Company periodically utilizes derivative instruments to reduce interest rate risk associated with the issuance~~ of ~~debt.~~Cash During this fiscal year, the Company entered into treasury lock agreements totaling $115.0 million that hedged the 10-year treasury component of a portion of the total anticipated 2003 debt financings. On April 24, 2003, in connection with the issuance of the utility subsidiaries' new debt, the Company unwound all of its treasury lock positions resulting in a $0.7 million loss recorded by Peoples Gas and a $0.4 million loss recorded by North Shore Gas to other comprehensive income. This amount will be amortized over the 10-year term of the debt. Flows

~~Taxes~~ For onpurposes ~~Revenues~~of reporting cash flows, the Company considers all highly liquid financial instruments with a maturity at the date of purchase of three months or less to be cash equivalents. Under the Company's cash management practices, checks issued pending clearance that result in overdraft balances for accounting purposes are included in accounts payable and total $19.8 million and $0.7 million as of June 30, 2004 and 2003, respectively. For Peoples Gas, the amounts in accounts payable at June 30, 2004 and 2003 were $7.7 million and $0.5 million, respectively. North Shore Gas' amount in accounts payable at June 30, 2004 and 2003 was immaterial.

In Illinois, the occupation of delivering, supplying, furnishing or selling gas for use or consumption and not for resale is subject to state, and in some cases municipal, taxes (revenue taxes). The Illinois Public Utility Act provides that the tax may be recovered from utility customers by adding an additional charge to customers' bills. These taxes are due only to the extent they are collected as cash receipts as opposed to amounts billed.
As a result, revenue taxes are reported on a gross basis. The billed amounts for the recovery of these taxes are included in revenues and an offsetting expense amount representing the expected cash payment of the taxes is included in taxes other than income taxes on the Consolidated Statements of Income. Revenue tax amounts included in revenues are as follows:
Three Months Ended Nine Months Ended
June 30, June 30,
2003 2002 2003 2002
Peoples Gas $24,128 $23,289 $123,941 $92,865
North Shore Gas 2,412 2,358 12,712 9,880
Total $26,540 $25,647 $136,653 $102,745
Recent Accounting Pronouncements

InUnder ~~May~~Financial ~~2003~~Interpretation No. (FIN) 46R, ~~the~~"Consolidation ~~FASB~~of ~~issued~~Variable ~~SFAS~~Interest Entities - An Interpretation of ARB No. ~~150~~51, "~~Accounting~~ ~~for~~as ~~Certain~~amended, ~~Financial~~if ~~Instruments~~a ~~with~~business ~~Characteristics~~enterprise ofhas ~~Both~~a ~~Liabilities~~controlling ~~and~~financial ~~Equity."~~interest Itin ~~provides~~a ~~guidance~~variable oninterest ~~how~~entity, anthe ~~entity~~assets, ~~classifies~~liabilities and ~~measures~~results ~~certain~~of ~~financial~~the ~~instruments~~activities ~~with characteristics~~ of ~~both~~the ~~liabilities~~variable ~~and~~interest ~~equity.~~entity ~~This~~should ~~statement~~be isincluded ~~effective~~in ~~for~~consolidated financial ~~instruments~~statements ~~entered~~with ~~into~~those orof ~~modified~~the ~~after~~business ~~May~~enterprise. ~~31,~~The ~~2003,~~Company's ~~and~~only ~~otherwise~~off-balance sheet financing is ~~effective~~through atits ~~the~~equity ~~beginning~~method ofinvestments, ~~the~~none ~~first~~of ~~interim~~which ~~period~~qualify ~~beginning~~as ~~after~~a ~~June~~Variable ~~15,~~Interest ~~2003~~Entity. ~~The~~Adoption ~~Company~~of ~~does~~FIN 46R did not ~~have~~affect ~~any~~the Company's financial ~~instruments~~condition ~~that~~or ~~would~~results beof ~~affected~~operations.

InOn ~~April~~October 16, 2003, the FASB ~~issued~~posted ~~SFAS~~FASB ~~No.~~Staff ~~149,~~Position ~~"Amendment of Statement 133 on Derivative Instruments and Hedging Activities~~ (~~SFAS No. 149~~FSP)." ~~This statement amends and clarifies the accounting and reporting for derivative instruments, including embedded derivatives, and for hedging activities under SFAS~~ No. ~~133~~150-2, "Accounting for ~~Derivative~~Mandatorily ~~Instruments~~Redeemable ~~and~~Shares ~~Hedging~~Requiring ~~Activities."~~Redemption Itby ~~amends~~Payment ~~SFAS~~of ~~133~~an toAmount ~~reflect~~That ~~the~~Differs ~~decisions~~from ~~made~~the asBook ~~part~~Value of ~~the~~Those ~~Derivatives~~Shares, ~~Implementation~~under ~~Group (DIG) and in other~~ FASB ~~projects~~Statement orNo. ~~deliberations~~150." Under SFAS No. ~~149 is effective for contracts entered into or modified after June 30~~150, ~~2003,~~the ~~and~~investment ~~for~~in ~~hedging~~Southeast ~~relationships~~Chicago ~~designated~~Energy ~~after June 30~~Project, ~~2003.~~LLC Atwas ~~June~~deemed ~~30,~~to ~~2003,~~be ~~the~~a ~~statement~~mandatorily ~~did~~redeemable ~~not~~investment ~~alter~~and the Company's ~~current~~equity ~~reporting~~in ~~practices~~the orpartnership ~~disclosures.~~was ~~The~~reclassified ~~Company~~to ~~has~~long-term ~~begun~~liabilities toon ~~evaluate~~ the ~~impacts~~partnership ~~of adopting SFAS No~~books. ~~149~~The ~~but~~change aton ~~this time has not been able to determine whether~~ the ~~impacts,~~partnership ifbooks ~~any,~~has ~~will~~no beeffect ~~material to~~ the Company's reporting its results ofusing ~~operations~~the orequity ~~financial~~method ~~position~~investment.

In ~~January~~December 2003, the ~~FASB~~"Medicare ~~issued~~Prescription ~~Financial~~Drug, ~~Interpretation~~Improvement ~~No.~~and Modernization Act of 2003" (~~FIN~~Medicare Act) ~~46,~~was ~~"Consolidation~~signed ofinto ~~Variable~~law. ~~Interest~~The ~~Entities~~Company -has Ana ~~Interpretation~~postretirement ofhealth ~~ARB~~care Noplan that may be affected by the Medicare Act. 51Initially, the FASB issued FSP No. 106-1 "Accounting ~~Under~~and ~~FIN~~Disclosure ~~46,~~Requirements ifRelated ato ~~business~~the ~~enterprise~~Medicare ~~has~~Prescription aDrug, ~~controlling~~Improvement ~~financial~~and ~~interest~~Modernization Act of 2003," in January 2004, to permit companies to elect a ~~variable~~deferral ~~interest~~of ~~entity~~the accounting until additional guidance could be provided. In May 2004, the ~~assets~~FASB issued FSP No. 106-2, ~~liabilities~~"Accounting and ~~results~~Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003" to provide the ~~activities~~additional accounting guidance. However, for the Company to make an accurate determination of any potential impact from the ~~variable~~Medicare ~~interest~~Act, ~~entity~~additional ~~should~~guidance beis ~~included~~still inrequired ~~consolidated~~from the U.S. Department of Health and Human Services to define terms like "Medicare Equivalent." The effective date for FSP No. 106-2 is the quarter ended September 30, 2004. The Company has elected to defer any potential accounting impact. At this time, the Company cannot determine what effect, if any, the Medicare Act will have on the financial ~~statements~~position ~~with~~or ~~those~~results of ~~the~~operations ~~business~~of ~~enterprise~~the Company.

SFAS No. 132 (Revised 2003), "Employers' Disclosures about Pensions and Other Postretirement Benefits - An Amendment of FASB Statements No. 87, 88, and 106" revises employers' disclosures about pension plans and other postretirement benefit plans. It does not change the measurement or recognition of those plans. This Statement requires additional disclosures to those in the original SFAS No. 132 about the assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans, and requires new disclosures in interim financial statements. The required information should be provided separately for pension plans and for other postretirement benefit plans. The interim disclosures were adopted in the

~~The~~second ~~Company's~~quarter ~~only off-balance sheet financing is through its equity method investments, none~~ of ~~which~~fiscal ~~qualify as a Variable Interest Entity~~2004. The ~~Company~~annual ~~does~~requirements ~~not~~will ~~expect~~be ~~FIN~~adopted 46for ~~to significantly affect~~ the ~~Company's~~fiscal ~~financial~~year ~~condition~~ended orSeptember ~~results of operations upon adoption as of July 1~~30, ~~2003~~2004.

~~In December 2002, the FASB issued SFAS No~~3. ~~148,~~BUSINESS "Accounting for Stock-Based Compensation - Transition and Disclosure." It is an amendment of SFAS No. 123 to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation and APB No. 28, Interim Financial Reporting. In addition, this statement allows companies to continue to report using the intrinsic method. It amends the disclosure requirements of SFAS No. 123 for reporting under the intrinsic method to require prominent disclosures in both annual and interim financial statements about the pro forma stock option expense. The Company has continued to report based on the intrinsic method and has disclosed pro forma stock option expense. (See Stock Compensation Plans.)SEGMENTS

InTotal ~~November~~segment ~~2002,~~capital ~~the~~assets ~~FASB~~include ~~issued~~net ~~FIN 45~~property, ~~"Guarantor's~~plant ~~Accounting~~ and ~~Disclosure~~equipment ~~Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of SFAS No. 5, 57~~ and ~~107 and rescission of FIN 34." FIN 45 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under~~ certain ~~guarantees~~intangible ~~that~~assets itclassified ~~has issued and~~ in ~~certain~~other ~~circumstances requires recognition of a liability for the fair value of the obligation undertaken in issuing the guarantee~~investments. ~~While~~Financial ~~the~~data ~~Company~~by ~~was~~business ~~not~~segment ~~required~~is topresented ~~recognize a liability for any of its existing guarantees, it has, however, expanded the disclosure of certain guarantees~~below.

In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires an entity to record a liability and corresponding asset representing the present value of legal obligations associated with the retirement of tangible, long-lived assets. SFAS No. 143 is effective for fiscal years beginning after June 2002. Adoption of this standard by the Company on October 1, 2002 did not have a significant effect on the Company's financial condition or results of operations.

					Retail		Corporate
	Gas	Oil and Gas	Power	Midstream	Energy		and
(In Thousands)	Distribution	Production	Generation	Services	Services	Other	Adjustments	Total
Three Months Ended June 30, 2004
Revenues	$ 234,611	$ 30,523	$ -	$ 83,506	$ 62,913	$ 36	$ (10,452)	$ 401,137
Depreciation, depletion and amortization	17,478	11,550	32	112	452	4	121	29,749
Equity investment income (loss)	-	1,725	3,091	-	-	50	-	4,866
Operating income (loss)	11,261	7,390	1,695	835	833	(116)	(4,814)	17,084
Segment capital assets - net	1,565,755	315,137	10,466	6,092	7,398	960	2,035	1,907,843
Investments in equity investees	-	19,807	107,469	-	-	3,674	-	130,950
Capital spending	17,133	13,918	1,517	4	481	-	260	33,313
Three Months Ended June 30, 2003
Revenues	$ 267,031	$ 27,988	$ -	$ 58,859	$ 50,372	$ 70	$ (6,173)	$ 398,147
Depreciation, depletion and amortization	16,905	10,759	32	106	(171)	4	23	27,658
Equity investment income (loss)	-	722	2,900	-	-	189	-	3,811
Operating income (loss)	19,121	10,168	1,704	(800)	792	(79)	(6,485)	24,421
Segment capital assets - net	1,546,250	261,097	7,150	5,790	7,403	1,343	1,423	1,830,456
Investments in equity investees	-	20,991	112,282	-	-	3,943	-	137,216
Capital spending	19,490	24,957	504	-	282	(264)	711	45,680
Nine Months Ended June 30, 2004
Revenues	$ 1,344,010	$ 93,915	$ -	$ 257,860	$270,627	$ 290	$ (33,660)	$ 1,933,042
Depreciation, depletion and amortization	51,441	36,093	95	336	1,326	12	338	89,641
Equity investment income (loss)	-	3,119	2,584	-	-	407	-	6,110
Operating income (loss)	142,009	31,287	(954)	7,642	8,802	111	(16,721)	172,176
Segment capital assets - net	1,565,755	315,137	10,466	6,092	7,398	960	2,035	1,907,843
Investments in equity investees	-	19,807	107,469	-	-	3,674	-	130,950
Capital spending	53,031	86,980	2,255	137	1,478	400	574	144,855
Nine Months Ended June 30, 2003
Revenues	$ 1,359,823	$ 78,122	$ -	$ 233,501	$211,935	$ 141	$ (32,430)	$ 1,851,092
Depreciation, depletion and amortization	50,166	31,238	95	319	1,235	12	70	83,135
Equity investment income (loss)	-	55	2,690	-	-	800	-	3,545
Operating income (loss)	177,603	23,839	(740)	9,827	5,100	15	(16,376)	199,268
Segment capital assets - net	1,546,250	261,097	7,150	5,790	7,403	1,343	1,423	1,830,456
Investments in equity investees	-	20,991	112,282	-	-	3,943	-	137,216
Capital spending	52,257	76,714	2,173	15	825	624	718	133,326

The Company adopted SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," as of October 1, 2001. These statements, in part, clarify that more assets should be distinguished and classified between tangible and intangible. The Company did not change or reclassify contractual mineral rights included in oil and gas properties on the balance sheet upon adoption of SFAS No. 142. The Company believes the treatment of such mineral rights as tangible assets under the successful efforts method of accounting for crude oil and natural gas properties is appropriate. However, the accounting profession and others are engaged in industry-wide deliberations regarding whether SFAS Nos. 141 and 142 require contractual mineral rights to be classified as intangible assets rather than tangible assets. If it is determined that certain mineral rights should be reclassified, the Company's oil and gas properties would be reduced by approximately $55.0 million and $14.0 million and intangible assets will be increased by a like amount at June 30, 2003 and September 30, 2002, respectively, representing costs incurred from the effective date of October 1, 2001. The applicable provisions of SFAS Nos. 141 and 142 impact only the balance sheet and associated footnote disclosure. Any reclassifications necessary would not impact the Company's cash flows or results of operations.

2 The financial results of Peoples Gas and North Shore Gas are reported primarily within the Gas Distribution segment. ~~BUSINESS~~Operating ~~SEGMENTS~~income by business segment for Peoples Gas and North Shore Gas is presented below.

The activities of Peoples Gas and North Shore Gas are mainly within the Gas Distribution segment with only immaterial amounts of activity in other segments. Total segment capital assets include net property, plant and equipment and certain intangible assets classified in other investments.

	The Peoples Gas Light and Coke Company				North Shore Gas Company
			Corporate			Corporate
	Gas	Midstream	and		Gas	and
(In Thousands)	Distribution	Services	Adjustments	Total	Distribution	Adjustments	Total

Three Months Ended June 30, 2004	$ 8,805	$ 886	$ (3,689)	$ 6,002	$ 2,644	$ (467)	$ 2,177
Three Months Ended June 30, 2003	16,523	1,261	(2,050)	15,734	2,790	(201)	2,589
Nine Months Ended June 30, 2004	119,487	4,060	(9,680)	113,867	24,093	(1,226)	22,867
Nine Months Ended June 30, 2003	151,308	7,230	(7,068)	151,470	27,865	(854)	27,011

~~Financial~~4. ~~data~~EQUITY ~~by business segment is presented below.~~INVESTMENTS

				Retail			Corporate
(In Thousands)	Gas	Power	Midstream	Energy	Oil and Gas		and
Three Months Ended 06-30-03	Distribution	Generation	Services	Services	Production	Other	Adjustments	Total
Revenues	$ 267,031	$ -	$ 58,859	$ 50,372	$ 27,988	$ 70	$ (6,173)	$ 398,147
Depreciation, depletion and amortization	16,905	32	106	(171)	10,759	4	23	27,658
Equity investment income (loss)	-	2,900	-	-	722	189	-	3,811
Operating income (loss)	19,121	1,704	(800)	792	10,168	(79)	(6,485)	24,421
Segment capital assets - net	1,546,250	993	5,791	7,403	261,097	1,343	1,423	1,824,300
Investments in equity investees	-	112,282	-	-	20,991	3,943	-	137,216
Capital spending	$ 19,490	$ 504	$ -	$ 282	$ 24,957	$ (264)	$ 711	$ 45,680
				Retail			Corporate
	Gas	Power	Midstream	Energy	Oil and Gas		and
Three Months Ended 06-30-02	Distribution	Generation	Services	Services	Production	Other	Adjustments	Total
Revenues	$ 236,447	$ -	$ 72,893	$ 32,173	$ 14,337	$ 12	$ (8,713)	$ 347,149
Depreciation, depletion and amortization	17,358	30	171	488	6,313	6	27	24,393
Equity investment income (loss)	-	1,621	-	-	646	63	-	2,330
Operating income (loss)	8,352	156	2,849	403	4,149	(171)	(4,151)	11,587
Segment capital assets - net	1,537,973	5,551	7,196	9,326	213,588	1,552	975	1,776,161
Investments in equity investees	-	64,713	-	-	27,014	4,348	-	96,075
Capital spending	$ 24,009	$ 261	$ -	$ 240	$ 15,922	$ 8	$ 28	$ 40,468
				Retail			Corporate
	Gas	Power	Midstream	Energy	Oil and Gas		and
Nine Months Ended 06-30-03	Distribution	Generation	Services	Services	Production	Other	Adjustments	Total
Revenues	$ 1,359,823	$ -	$ 233,501	$ 211,935	$ 78,122	$ 141	$ (32,430)	$ 1,851,092
Depreciation, depletion and amortization	50,166	95	319	1,235	31,238	12	70	83,135
Equity investment income (loss)	-	2,690	-	-	55	800	-	3,545
Operating income (loss)	177,603	(740)	9,827	5,100	23,839	15	(16,376)	199,268
Segment capital assets - net	1,546,250	993	5,791	7,403	261,097	1,343	1,423	1,824,300
Investments in equity investees	-	112,282	-	-	20,991	3,943	-	137,216
Capital spending	$ 52,257	$ 2,173	$ 15	$ 825	$ 76,714	$ 624	$ 718	$ 133,326
				Retail			Corporate
	Gas	Power	Midstream	Energy	Oil and Gas		and
Nine Months Ended 06-30-02	Distribution	Generation	Services	Services	Production	Other	Adjustments	Total
Revenues	$ 941,591	$ -	$ 130,139	$ 140,057	$ 49,656	$ 31	$ (13,942)	$ 1,247,532
Depreciation, depletion and amortization	51,385	89	578	1,308	20,230	24	77	73,691
Equity investment income (loss)	-	(1,607)	1,297	-	(1,758)	312	-	(1,756)
Operating income (loss)	171,944	(5,380)	9,428	1,672	13,942	(580)	(19,582)	171,444
Segment capital assets - net	1,537,973	5,551	7,196	9,326	213,588	1,552	975	1,776,161
Investments in equity investees	-	64,713	-	-	27,014	4,348	-	96,075
Capital spending	$ 63,826	$ 8,737	$ 4,156	$ 454	$ 36,192	$ 592	$ 103	$ 114,060

The Company has several investments in the form of partnerships that are accounted for as unconsolidated equity method investments. Individually, the Company's equity investments do not meet the requirements for financial disclosure. However, in aggregate these investments are material. The Company records its share of income gains and losses based on financial information it receives from the partnerships. All information is current or based on estimated results for the quarter. The Company is not a managing partner in any of these investments.

The following table summarizes the combined partnership financial results and financial position of the Company's unconsolidated equity method investments.

	Three Months Ended		Nine Months Ended
	June 30,		June 30,
(In Thousands)	2004	2003	2004	2003
Revenues	$ 43,264	$ 40,281	$ 88,917	$ 91,641
Operating income	20,303	19,952	44,074	42,557
Interest expense	10,001	8,506	28,773	26,620
Net income (loss)	8,984	11,607	16,700	16,601

Total assets	822,131	848,336	822,131	848,336
Total liabilities	508,429	460,217	508,429	460,217

3.The ~~EQUITY~~following ~~INVESTMENTS~~table summarizes the Company's equity method investment ownership percentage and its equity share of the net income (loss) shown in the previous table.

The Company has several investments that are accounted for as unconsolidated equity method investments. During the second quarter of fiscal 2002, the Company acquired Enron Midwest LLC's 50 percent interest in enovate LLC (enovate), its partnership with Enron. Results from this business were recorded in the Midstream Services segment as a consolidated subsidiary from March 2002 until enovate was liquidated in September 2002. Individually, the Company's equity investments do not meet the requirements for financial disclosure. However, in aggregate these investments were material at June 30, 2003. The Company records its share of income gains and losses based on financial information it receives from the partnerships. The Company is not a managing partner in any of these investments.

		Ownership Percentage						Equity Investment Income (Loss)
								Three Months Ended		Nine Months Ended
(Dollars in Thousands)		At June 30,						June 30,		June 30,
Investment	Segment	2004			2003			2004	2003	2004	2003
EnerVest	Oil and Gas		30	%		30	%	$ 1,725	$ 722	$ 3,119	$ 55
Elwood	Power		50			50		1,672	1,406	(1,729)	(1,849)
SCEP	Power		27			27		1,419	1,494	4,313	4,539
Trigen-Peoples	Other		50			50		50	189	407	797
Peoples NGV (1)	Other		0			0		-	-	-	3

Total equity investment income								$ 4,866	$ 3,811	$ 6,110	$ 3,545

Undistributed partnership income included in the
Company's retained earnings at the end of each period								$ 12,156	$ 6,015	$ 12,156	$ 6,015

(1) The ~~following~~Company ~~table~~liquidated ~~summarizes~~its ~~the~~investment ~~aggregate~~in ~~financial~~Peoples ~~results~~NGV ~~and~~Corp. ~~financial~~in ~~position of~~ the ~~Company's~~first ~~unconsolidated~~quarter ~~equity~~of ~~method~~fiscal ~~investments~~2003.

Three Months Ended Nine Months Ended
June 30, June 30,
(In Thousands) 2003 2002 2003 2002
Revenues $ 42,223 $ 48,442 $ 96,349 $ 158,599
Operating income 20,205 17,160 40,709 25,580
Interest expense 8,537 12,151 26,429 31,958
Net income (loss) 11,849 5,512 14,944 (5,833)
Total assets 848,336 752,544 848,336 752,544
Total liabilities 460,217 524,868 460,217 524,868
5. ENVIRONMENTAL MATTERS

The following table presents the Company's equity method investment ownership percentage and related equity investment income (loss).
Ownership Percentage Equity Investment Income (Loss)
Three Months Ended Nine Months Ended
At June 30, June 30, June 30,
Investment Segment 2003 2002 2003 2002 2003 2002
Elwood Power 50% 50% $1,406 $1,621 $(1,849) $(1,607)
SCEP (*) Power 27% 30% 1,494 -- 4,539 --
enovate (*) Midstream 0% 0% -- -- -- 1,297
EnerVest Oil and Gas 30% 29% 722 646 55 (1,758)
Trigen-Peoples Other 50% 50% 189 69 797 338
NGV (*) Other 0% 50% -- (6) 3 (26)
Total equity investment income (loss) $3,811 $2,330 $3,545 $(1,756)
Undistributed partnership income included in the Company's retained earnings at the end of each period $6,015 $13,743 $6,015 $13,743
(*) The Company's investment interest in SCEP began in the fourth quarter of fiscal 2002. The Company liquidated its investments in enovate and NGV in the second quarter of fiscal 2002 and the first quarter of fiscal 2003, respectively.
4. ENVIRONMENTAL MATTERS
Former Manufactured Gas Plant Operations

The Company's utility subsidiaries, their predecessors and certain former affiliates operated facilities in the past at multiple sites for the purpose of manufacturing gas and storing manufactured gas. In connection with manufacturing and storing gas, various by-products and waste materials were produced, some of which might have been disposed of rather than sold. Under certain laws and regulations relating to the protection of the environment, the subsidiaries might be required to undertake remedial action with respect to some of these materials. ~~Two of the manufactured gas sites are discussed in more detail below.~~ The subsidiaries are addressing anthese ~~additional 32 manufactured gas~~ sites under a program supervised by the Illinois Environmental Protection Agency ~~(IEPA)~~. ~~Investigations have been completed at all or portions of 27 sites. Remediations have been completed at all or portions of four sites.~~

InPeoples ~~1990, North Shore~~ Gas ~~entered~~is ~~into~~addressing an29 ~~Administrative Order on Consent (AOC) with the United States Environmental Protection Agency (EPA) and the IEPA to implement and conduct a remedial investigation/feasibility study (RI/FS) of a~~ manufactured gas ~~site located in Waukegan~~sites, ~~Illinois,~~including ~~where~~two ~~manufactured~~sites ~~gas~~described ~~and~~in ~~coking~~more ~~operations~~detail ~~were formerly conducted (Waukegan Site)~~below. ~~The~~Investigations ~~RI/FS~~have ~~was~~been ~~comprised~~completed ~~of an investigation to determine the nature and extent of contamination~~ at ~~the~~all ~~Waukegan~~or ~~Site~~portions and a feasibility study to develop and evaluate possible remedial actions. North Shore Gas entered into the AOC after being notified by the EPA that North Shore Gas, General Motors Corporation (GMC) and Outboard Marine Corporation (OMC) were each a potentially responsible party (PRP) under the Comprehensive Environmental Response, Compensation and Liability Act of ~~1980,~~23 ~~as amended (CERCLA), with respect to the Waukegan Site~~sites. ARemediations ~~PRP~~have isbeen ~~potentially~~completed ~~liable~~at ~~for~~all ~~the~~or ~~cost~~portions of ~~any~~four ~~investigative and remedial work that the EPA determines is necessary~~sites. ~~Other parties identified as PRPs did not enter into the AOC.~~

~~Under the terms of the AOC,~~ North Shore Gas is ~~responsible~~addressing ~~for~~five ~~the~~manufactured ~~cost~~gas ~~of the RI/FS. North Shore Gas believes~~sites, ~~however,~~including ~~that~~one itsite ~~will~~described ~~recover~~in amore ~~significant~~detail ~~portion of the costs of the RI/FS from other entities~~below. ~~GMC~~Investigations ~~has~~have ~~shared~~been ~~equally~~completed ~~with~~at ~~North~~all ~~Shore~~or ~~Gas~~portions ~~in funding~~ of ~~the~~four ~~RI/FS~~sites. ~~cost,~~Remediations ~~without~~have ~~prejudice~~not toyet ~~GMC's~~been orcompleted ~~North Shore Gas' right to seek a lesser cost responsibility~~ at athese ~~later date~~sites.

InThe ~~1999,~~United ~~the~~States Environmental Protection Agency (EPA) ~~notified~~has ~~GMC,~~identified ~~OMC,~~North ~~Elgin~~Shore ~~Joliet~~Gas ~~and~~as ~~Eastern~~a ~~Railway~~potentially ~~Company~~responsible party (~~EJ&E~~PRP) ~~and~~under ~~North~~the ~~Shore~~Comprehensive ~~Gas~~Environmental ~~that~~Response, ~~they~~Compensation ~~were~~and ~~potentially~~Liability ~~liable~~Act ~~with~~of ~~respect~~1980, toas amended (CERCLA), at the Waukegan Coke Plant Site ~~and~~located ~~that~~in Waukegan, Illinois (Waukegan Site). The Waukegan Site is part of the Outboard Marine Corporation (OMC) Superfund Site. The EPA ~~intended~~also tohas ~~begin~~identified ~~discussions~~General ~~regarding~~Motors ~~the~~Corporation, ~~design~~OMC, Elgin Joliet and ~~implementation~~Eastern ofRailway Company, Larsen Marine Service and the ~~remedial~~City ~~action~~of ~~selected~~Waukegan ~~for~~as PRPs at the Waukegan Site. OMC has filed for bankruptcy.

In September 1999, the EPA issued ~~the~~a ~~Record~~record of ~~Decision~~decision (ROD) selecting the remedial action for the Waukegan Site. The selected remedy consists of on-site treatment of ~~ground~~groundwater ~~water,~~and off-site ~~treatment and~~ disposal of soil containing polynuclear ~~aeromatic~~aromatic hydrocarbons ~~or creosote,~~ and ~~on-site solidification/stabilization of~~ arsenic~~-contaminated soils~~. The EPA has estimated the present worth of the remedy to be $26.5 million (representing the present worth of estimated capital costs and of estimated operation and maintenance costs). North Shore Gas and the other PRPs (except for the City of Waukegan) are conducting the remedial design for the Waukegan Site.

In 2000, OMC filed a petition in federal bankruptcy court seeking protection under Chapter 11 of the United States Bankruptcy Code. On August 20, 2001, the bankruptcy court entered an order converting OMC's Chapter 11 case to a Chapter 7 case.21

In July 2004, North Shore Gas and the other ~~parties~~PRPs ~~notified~~executed bya ~~the~~remedial ~~EPA~~action ~~have~~consent ~~been~~decree. ~~discussing~~The ~~implementation~~consent ofdecree ~~the~~is ~~remedy~~currently undergoing review by EPA and ~~the~~other ~~allocation~~government ofagencies. ~~costs~~If ~~associated~~approved ~~with~~by the ~~investigation~~government agencies and ~~remediation~~lodged ofwith ~~the~~and ~~Waukegan~~entered ~~Site.~~by Inthe ~~July~~federal ~~2001~~district court, ~~North~~the ~~Shore~~consent ~~Gas~~decree ~~and~~will ~~the~~require ~~other~~North ~~PRPs~~Shore ~~entered~~Gas ~~into~~and anGeneral ~~AOC~~Motors ~~with~~to perform the ~~EPA~~remedial toaction ~~conduct~~and ~~the~~establish ~~remedial~~and ~~design~~maintain ~~for~~financial ~~the~~assurance ~~Waukegan~~of ~~Site~~$27 million.

~~North~~The ~~Shore~~current owner of a site in the City of Chicago, Illinois (Chicago), formerly called Pitney Court Station, filed suit against Peoples Gas ~~has~~in ~~entered~~federal ~~into~~district acourt ~~settlement~~under ~~agreement~~CERCLA. ~~with~~The ~~one~~suit seeks recovery of the ~~PRPs~~past and isfuture ~~continuing~~costs ~~discussion~~of ~~with~~investigating and remediating the ~~remaining~~site. ~~parties~~The owners of another property in the vicinity of the former Pitney Court Station have filed suit against Peoples Gas in federal district court under the Resource Conservation and Recovery Act (RCRA). The suit seeks an order directing Peoples Gas to remediate the site. Peoples Gas is contesting both suits.

InThe ~~June~~current ~~2002,~~owner ~~the~~of ~~City~~a portion of ~~Waukegan~~another ~~purchased~~site ~~the~~in ~~Waukegan~~Chicago, ~~Site~~formerly ~~from~~called the ~~OMC~~22nd ~~bankruptcy~~Street ~~trustee.~~Station, Inhas ~~October~~notified ~~2002,~~Peoples ~~the~~Gas ~~City~~that ofit ~~Waukegan~~intends ~~rezoned~~to ~~the~~file ~~property~~suit ~~from~~under ~~industrial~~RCRA seeking an order directing Peoples Gas to ~~residential~~remediate the site.

22 The utility subsidiaries are accruing and deferring liabilities and costs incurred in connection with all of the manufactured gas sites, including related legal expenses, pending recovery through rates or from other entities. At June 30, 2004, the total of these deferred liabilities and costs (stated in current year dollars) for Peoples Gas was $134.6 million; for North Shore Gas the total was $36.7 million; and for the Company on a consolidated basis, the total deferred was $171.3 million. Each of these deferred amounts reflects the net amount of (1) costs incurred to date, (2) carrying costs, (3) amounts recovered from insurance companies and from customers, and (4) management's best estimates of the costs the utilities will spend in the future for investigating and remediating the manufactured gas sites. Management also estimates that additional costs in the following amounts are reasonably possible: for Peoples Gas, $73 million; for North Shore Gas, $27 million; and for the Company on a consolidated basis, $100 million. Management's estimates are based upon an ongoing review by management and its outside consultants of potential costs associated with conducting investigative and remedial actions at the manufactured gas sites, and of the likelihood of incurring such costs. While each subsidiary intends to seek contribution from other entities for the costs incurred at the sites, the full extent of such contributions cannot be determined at this time.

InManagement ~~October~~believes ~~2002,~~that the ~~City~~liabilities ofincurred ~~Waukegan~~by ~~enacted~~Peoples anGas ~~ordinance~~and ~~that~~by ~~purports~~North Shore Gas for environmental activities relating to ~~require~~former ~~the~~manufactured ~~remediation~~gas ofoperations ~~soil~~are recoverable through rates for utility service, atfrom ~~sites~~insurance ~~within~~carriers aor ~~defined~~other ~~geographic~~entities. ~~area~~Accordingly, management believes that ~~includes~~the costs incurred by the ~~Waukegan~~subsidiaries ~~Site,~~in toconnection ~~levels~~with ~~more~~former ~~stringent~~manufactured ~~than~~gas ~~those~~operations ~~set~~will ~~forth~~not inhave a material adverse effect on the ~~ROD~~financial position or results of operations of the utilities. Peoples Gas and North Shore Gas are recovering the costs of environmental activities relating to the utilities' former manufactured gas operations, including carrying charges on the unrecovered balances, under rate mechanisms approved by the Illinois Commerce Commission (Commission).

In May 2003, the EPA sent a special notice of liability letter to EJ&E, GMC, Larson Marine Services, North Shore Gas and the City of Waukegan requesting that the parties enter into formal negotiations with the EPA regarding both cost reimbursement and performance of the selected remedial activities in the ROD. In July 2003, North Shore Gas and three of the other PRPs (EJ&E, GMC and Larsen Marine Services) submitted a proposal to the EPA to finance and perform the ROD remedy. The City of Waukegan declined to participate in the proposal and instead submitted a request to the EPA to amend the ROD so as to make the remedy and clean-up standard consistent with various proposed future uses of the Waukegan Site, including urban residential development.
At this time, management is unable to determine whether, or to what extent, the change in ownership, change in zoning, enactment of the ordinance or request to amend the ROD will affect remedial costs at the Waukegan Site.
The current owner of a site in Chicago, formerly called Pitney Court Station, filed suit against Peoples Gas in federal district court under CERCLA. The suit seeks recovery of the past and future costs of investigating and remediating the site. Peoples Gas is contesting this suit.
The utility subsidiaries are accruing and deferring liabilities incurred in connection with all of the manufactured gas sites, including related legal expenses, pending recovery through rates or from insurance carriers or other entities. At June 30, 2003, the total of the costs deferred (stated in current year dollars) for Peoples Gas was $124.7 million; for North Shore Gas the total was $37.7 million; and for the Company on a consolidated basis the total deferred was $162.4 million. Each of these amounts includes management's best estimates of the costs the utilities will spend in investigating and remediating the manufactured gas sites. Management estimates that additional costs in the following amounts are reasonably possible: for Peoples Gas, $65.6 million; for North Shore Gas, $26.8 million; and for the Company on a consolidated basis, $92.4 million. Management's estimates are based upon an ongoing review by management and its outside consultants of potential costs associated with conducting investigative and remedial actions at the manufactured gas sites, including updated estimates based on completed investigations or specific remedial plans. While each subsidiary intends to seek contribution from other entities for the costs incurred at the sites, the full extent of such contributions cannot be determined at this time.
Peoples Gas and North Shore Gas have filed suit against a number of insurance carriers for the recovery of environmental costs relating to the utilities' former manufactured gas operations. The suit asks the court to declare, among other things, that the insurers are liable under policies in effect between 1937 and 1986 for costs incurred or to be incurred by the utilities in connection with five of their manufactured gas sites in Chicago and Waukegan. The utilities are also asking the court to award damages stemming from the insurers' breach of their contractual obligation to defend and indemnify the utilities against these costs. The utilities have reached settlement agreements with several of the insurance carriers. The utilities are applying portions of the proceeds from these settlements to pay costs otherwise recoverable through rates. The costs deferred at June 30, 2003 have been reduced by the portions of the settlement proceeds that have yet to be applied to pay such costs. At this time, management cannot determine the timing and extent of the subsidiaries' recovery of costs from the other insurance carriers. Accordingly, the costs deferred at June 30, 2003 have not been reduced to reflect recoveries from other insurance carriers.
Management believes that the liabilities incurred by Peoples Gas and by North Shore Gas for environmental activities relating to former manufactured gas operations are recoverable from insurance carriers, other entities or through rates for utility service. Accordingly, management believes that the costs incurred by the subsidiaries in connection with former manufactured gas operations will not have a material adverse effect on the financial position or results of operations of the utilities. Peoples Gas and North Shore Gas are recovering the costs of environmental activities relating to the utilities' former manufactured gas operations, including carrying charges on the unrecovered balances, under rate mechanisms approved by the Commission.
23
Former Mineral Processing Site in Denver, Colorado

In 1994, North Shore Gas received a demand from the S.W. Shattuck Chemical Company, Inc. (Shattuck), a responsible party under CERCLA, for reimbursement, indemnification and contribution for response costs incurred at a former mineral processing site in Denver, Colorado (Denver site). Shattuck is a wholly-owned subsidiary of Salomon, Inc. (Salomon). The demand alleges that North Shore Gas is a successor to the liability of a former entity that was allegedly responsible during the period 1934-1941 for the disposal of mineral processing wastes containing radium and other hazardous substances at the site. In 1992, the EPA issued the ROD for the Denver site. The remedy selected in the ROD consisted of the on-site stabilization, solidification and capping of soils containing radioactive wastes. In 1997, the remedial action was completed. The cost of the remedy at the site has been estimated by Shattuck to be approximately $31.0 million. Salomon has provided financial assurance for the performance of the remediation of the site.

North Shore Gas filed a declaratory judgment action against Salomon in the District Court for the Northern District of Illinois. The suit asked the court to declare that North Shore Gas is not liable for response costs at the Denver site. Salomon filed a counterclaim for costs incurred by Salomon and Shattuck with respect to the site. In ~~1997, the District Court granted North Shore Gas' motion for summary judgment, declaring that North Shore Gas is not liable for any response costs in connection with the Denver site.~~

1997, the District Court granted North Shore Gas' motion for summary judgment, declaring that North Shore Gas is not liable for any response costs in connection with the Denver site.

In 1998, the United States Court of Appeals, Seventh Circuit, reversed the District Court's decision and remanded the case for determination of what liability, if any, the former entity has, and therefore North Shore Gas has, for activities at the site.

In 1999, the EPA announced that it was reopening the ROD for the Denver site. The EPA's announcement followed a six-month scientific/technical review by the agency of the remedy's effectiveness. In 2000, the EPA amended the ROD to require removal of the radioactive wastes from the site to a licensed off-site disposal facility. The EPA estimates that this action will cost an additional $2122.50 million (representing the present worth of estimated capital costs and estimated operation and maintenance costs).

In December 2001, Shattuck entered into a proposed settlement agreement with the United States and the State of Colorado regarding past and future response costs at the site. In August 2002, the agreement was approved by the District Court for the District of Colorado. Under the terms of the agreement, Shattuck will pay, in addition to amounts already paid for response costs at the site, approximately $7.2 million in exchange for a release from further obligations at the site. The release will not apply in the event that new information shows that the remedy selected in the amended ROD is not protective of human health or the environment or if it becomes necessary to remediate contaminated groundwater beneath or emanating from the site.

North Shore Gas does not believe that it has liability for the response costs, but cannot determine the matter with certainty. At this time, North Shore Gas cannot reasonably estimate what range of loss, if any, may occur. In the event that North Shore Gas ~~incurred~~incurs liability, it would pursue reimbursement from insurance carriers, other responsible parties, if any, and through its rates for utility service.

56. ~~ACCOUNTS~~GAS ~~RECEIVABLE~~CHARGE RECONCILIATION PROCEEDINGS AND RELATED MATTERS

~~Accounts~~For ~~receivable~~each ~~balances~~utility ~~for~~subsidiary, the ~~Company~~Commission ~~includes~~conducts ~~accrued~~annual ~~unbilled~~proceedings ~~revenues~~regarding ofthe ~~$36.1~~reconciliation ~~million,~~of ~~$32.1~~revenues ~~million~~from ~~and~~the ~~$30.3~~Gas ~~million~~Charge atand ~~June~~related ~~30,~~gas ~~2003,~~costs. ~~September~~In ~~30,~~these ~~2002 and June 30~~proceedings, ~~2002,~~the ~~respectively,~~accuracy ~~related~~of ~~primarily~~the toreconciliation ~~Gas~~of ~~Distribution~~revenues ~~operations.~~and ~~Accounts~~costs ~~receivable~~is ~~balances~~reviewed ~~for~~and ~~Peoples~~the ~~Gas~~prudence ~~includes accrued unbilled revenues~~ of ~~$21.1~~gas ~~million,~~costs ~~$21.0~~recovered ~~million~~through ~~and~~the ~~$20.6~~Gas ~~million~~Charge atis ~~June~~examined ~~30,~~by ~~2003,~~interested ~~September~~parties. ~~30,~~If ~~2002~~the ~~and~~Commission ~~June~~were ~~30,~~to ~~2002,~~find ~~respectively.~~that ~~Accounts~~the ~~receivable~~reconciliation ~~balances~~was ~~for~~inaccurate ~~North~~or ~~Shore~~any ~~Gas~~gas ~~includes~~costs ~~accrued~~were ~~unbilled~~imprudently ~~revenues of $3.8 million~~incurred, ~~$3.4~~the ~~million~~Commission ~~and~~would ~~$3.0~~order ~~million~~the atutility ~~June~~to ~~30,~~refund ~~2003,~~the ~~September~~affected ~~30,~~amount ~~2002~~to ~~and~~customers ~~June~~through ~~30,~~subsequent ~~2002,~~Gas ~~respectively~~Charge filings. ~~Accounts~~The ~~receivable~~proceedings ~~balances~~are ~~for~~typically ~~Peoples~~initiated ~~Energy~~shortly ~~Services~~after ~~includes~~the ~~accrued~~close ~~unbilled revenues~~ of ~~$11.2~~the ~~million,~~fiscal ~~$7.6~~year ~~million~~ and ~~$6.7~~take ~~million~~ at ~~June~~least ~~30,~~a ~~2003,~~year ~~September~~to ~~30,~~18 ~~2002~~months ~~and~~to ~~June 30, 2002, respectively~~complete.

Proceedings regarding Peoples Gas and North Shore Gas for fiscal 2001 costs are currently pending before the Commission. Three intervenors (Citizens Utility Board (CUB), Illinois Attorney General (AG) and Chicago filed testimony in Peoples Gas' proceeding and one intervenor (CUB) filed testimony in North Shore Gas' proceeding. Issues raised by the intervenors in the Peoples Gas proceeding related primarily to not having financially hedged gas costs during the winter of 2000-2001 and the use of its Manlove storage field to support transactions with third parties ("hub" transactions). Each of the intervenors requested disallowances, which vary in amount depending upon the issues raised and the assumptions and methodologies used to measure the impact of the issues. In the Peoples Gas proceeding, the AG and CUB have requested disallowances, which range from $8 million to $56 million, covering a variety of alleged issues other than financial hedging. CUB has requested an additional disallowance of $53 million and Chicago has requested a disallowance of $230 million based on the financial hedging issue. In the North Shore Gas proceeding, CUB raised only the hedging issue and recommended a disallowance of $10 million. The Commission's Staff (the Staff) requested a disallowance of $31 million in the Peoples Gas proceeding and $1.4 million in the North Shore Gas proceeding covering a variety of alleged issues, none of which relate to hedging.

Peoples Gas and North Shore Gas submitted rebuttal testimony in response to the Staff and the intervenors on November 13, 2003. In that testimony, Peoples Gas stated that it would not oppose two disallowances proposed by the Staff, totaling approximately $5.2 million. One of these proposed disallowances, totaling $4.7 million, results

in a change in the treatment for accounting and rate making purposes of gas used to support operational capabilities of Peoples Gas' underground storage. During the first quarter, this amount was capitalized as property, plant and equipment and will be depreciated over the asset's useful life. An offsetting liability for this amount, which is expected to be refunded to customers, was recorded. During the first quarter, Peoples Gas also recorded property, plant and equipment and liabilities totaling $5.9 million for similar amounts recovered through the Gas Charge in fiscal 2003 and fiscal 2002. A liability was also established for the second proposed disallowance of $0.5 million resulting in a charge to income. Peoples Gas opposed all other proposed disallowances and North Shore Gas opposed all disallowances in its case. At a status hearing on June 23, 2004, the Administrative Law Judge established a schedule for testimony and hearings in the fiscal 2001 cases. The schedule provides for the Staff and intervenors to file supplemental direct testimony on September 8, 2004, and Peoples Gas and North Shore Gas to file rebuttal testimony on October 6, 2004. Hearings in both cases are scheduled to commence on November 3, 2004. The schedule also provides for other routine procedural dates, including status hearings, prior to the hearings. An order from the Commission is not expected before the third quarter of fiscal 2005.

In January 2004, the Company received and responded to a subpoena from the AG requesting, among other things, information regarding transactions between the Company and Enron North America Corp. or its affiliates related to certain issues raised by the Staff and intervenors in the 2001 Gas Charge reconciliation proceedings.

The Company believes that its fiscal 2001 purchasing practices were consistent with the standards applied by the Commission in its past orders and upheld by the Illinois courts and that it conducted business prudently and in the best interest of customers within these established standards. However, management cannot predict the outcome of these proceedings or the potential resulting exposure and has not recorded a liability associated with this contingency other than with respect to the disallowances that Peoples Gas did not oppose as described above.

Fiscal 2002 Gas Charge reconciliation cases were initiated on November 7, 2002. Peoples Gas and North Shore Gas each filed direct testimony on August 1, 2003. A status hearing is scheduled for November 16, 2004. Fiscal 2003 Gas Charge reconciliation cases were initiated on November 12, 2003. Peoples Gas and North Shore Gas each filed direct testimony on April 1, 2004. A status hearing is scheduled for November 9, 2004.

Separately, in February 2004 a purported class action was filed against the Company and Peoples Gas by a Peoples Gas customer alleging, among other things, violation of the Illinois Consumer Fraud and Deceptive Business Practices Act related to matters at issue in Peoples Gas' gas reconciliation proceedings. The suit seeks unspecified compensatory and punitive damages. The Company and Peoples Gas deny the allegations made in the suit and intend to vigorously defend against the suit. Management cannot predict the outcome of this litigation or the potential exposure resulting from it and has not recorded a liability associated with this contingency.

~~The~~7. ~~following~~COMPREHENSIVE ~~table presents the status of customer accounts receivable balances of the Company's utility subsidiaries.~~INCOME

	Peoples Gas			North Shore Gas
	Accounts Receivable Balance At			Accounts Receivable Balance At
	June 30,	September 30,	June 30,	June 30,	September 30,	June 30,
	2003	2002	2002	2003	2002	2002
	(Dollars in Millions)
Gross customer accounts receivable	$ 236.0	$ 152.4	$ 211.3	$ 26.9	$ 14.0	$ 18.5
Reserve for uncollectible accounts	29.5	31.6	35.3	1.1	0.5	0.7
Net customer accounts receivable	$ 206.5	$ 120.8	$ 176.0	$ 25.8	$ 13.5	$ 17.8
Reserve for uncollectible accounts
as a percent of gross customer
accounts receivable	12.5%	20.7%	16.7%	4.1%	3.6%	3.8%

Comprehensive income is the total of net income and all other nonowner changes in equity. Comprehensive income recorded includes net income plus the effect of the unrealized hedge gain or loss on derivative instruments. Total comprehensive income for the Company is summarized below.

The provision rate for uncollectible accounts at Peoples Gas was increased beginning in the first quarter of fiscal 2003 from 2.0 percent of revenues to approximately 2.5 percent in order to conservatively manage the possible impact on future collections of higher customer bills due to higher natural gas prices and colder weather. Based on an ongoing review of estimated future utility charge offs, Peoples Gas recorded an additional $5.0 million provision in the third quarter to increase the reserve for uncollectible accounts to $29.5 million at June 30, 2003. Peoples Gas and North Shore Gas believe that their reserves are adequate given what is known at this time. However, the reserve for uncollectible accounts remains an estimate and could require further adjustments if circumstances change.

	Three Months Ended		Nine Months Ended
	June 30,		June 30,
(In Thousands)	2004	2003	2004	2003
Comprehensive income
Net income	$ 5,623	$ 8,013	$ 91,877	$ 102,495
Other comprehensive income (loss), net of tax	(4,885)	(3,283)	(24,635)	(17,992)

Total comprehensive income	$ 738	$ 4,730	$ 67,242	$ 84,503

~~The~~Peoples ~~following~~Gas ~~table~~and ~~details~~North ~~Peoples~~Shore Gas' ~~aging~~recorded an insignificant amount of ~~customer~~other ~~accounts~~comprehensive ~~receivable~~income ~~balances:~~related to the amortization of interest rate lock cash flow hedges.

Total
Accounts Past Due
Receivable Current 30-89 Days 90-149 Days Over 150 Days
(Dollars in Millions)
June 30, 2003 $236.0 $74.5 $75.7 $48.3 $37.5
Percentage 100 32 32 20 16
September 30, 2002 $152.4 $53.2 $21.7 $19.0 $58.5
Percentage 100 35 14 13 38
June 30, 2002 $211.3 $68.8 $51.4 $30.1 $61.0
Percentage 100 33 24 14 29
June 30, 2001 $405.1 $92.1 $116.1 $130.5 $66.4
Percentage 100 23 29 32 16
8. RETIREMENT AND POSTRETIREMENT BENEFITS

The Company and its subsidiaries participate in two defined benefit pension plans, the Retirement Plan and the Service Annuity System, covering substantially all employees. These plans provide pension benefits that generally are based on an employee's length of service, compensation during the five years preceding retirement and social security benefits. Employees who began participation in the Retirement Plan July 1, 2001 and thereafter will have their benefits determined based on their compensation during the five years preceding termination of employment and an aged-based percentage credited to them for each year of their participation. The Company and its subsidiaries make contributions to the plans based upon actuarial determinations and in consideration of tax regulations and funding requirements under federal law. The Company also has a nonqualified pension plan (Supplemental Plan) that provides certain employees with pension benefits in excess of qualified plan limits imposed by federal tax law. Retiring employees have the option of receiving retirement benefits in the form of an annuity or a lump sum payment.

The Company follows the procedures specified in SFAS No. 88 to account for unrecognized gains and losses related to the settlement of its pension plans' Projected Benefit Obligations (PBO). During fiscal 2004, as in past fiscal years, a portion of each plans' PBO was settled by the payment of lump sum benefits, resulting in a settlement cost (credit) under SFAS No. 88 for the Retirement Plan, Service Annuity System and Supplemental Plan.

In addition, the Company and its subsidiaries currently provide certain health care and life insurance benefits for retired employees. Substantially all employees may become eligible for such benefit coverage if they reach retirement age while working for the Company. These plans, like the pension plans, are funded based upon actuarial determinations, consideration of tax regulations and the Company's funding policy. The Company accrues the expected costs of such benefits over the average remaining service lives of all employees.

6. Net ~~COMPREHENSIVE~~pension ~~INCOME~~benefit ~~(LOSS)~~cost and net other postretirement benefit cost for all plans include the following components:

Comprehensive income (loss) for the Company in the reported periods includes unrealized gains and losses from derivative financial instruments accounted for as cash flow hedges. Total comprehensive income (loss) for the Company consisted of the following:

			Other Postretirement
	Pension Benefits		Benefits
	Three Months Ended June 30,
(In Millions)	2004	2003	2004	2003
Service cost	$ 4.5	$ 3.4	$ 1.4	$ 0.6
Interest cost	6.9	7.3	1.9	1.9
Expected return on plan assets (gain)	(11.7)	(13.0)	(1.0)	(1.1)
Amortization of:
Net transition (asset) obligation	(0.3)	(0.3)	0.5	0.8
Prior service costs	0.8	0.8	-	-
Net (gain) loss	0.4	(0.1)	0.2	-
Net periodic benefit cost (credit)	0.6	(1.9)	3.0	2.2
Effect of lump sum settlements upon retirement	2.3	0.2	-	-
Net cost (credit)	$ 2.9	$ (1.7)	$ 3.0	$ 2.2



			Other Postretirement
	Pension Benefits		Benefits
	Nine Months Ended June 30,
(In Millions)	2004	2003	2004	2003
Service cost	$ 13.5	$ 10.2	$ 3.8	$ 2.9
Interest cost	20.7	21.9	5.7	5.7
Expected return on plan assets (gain)	(35.1)	(39.0)	(3.0)	(3.3)
Amortization of:
Net transition (asset) obligation	(0.9)	(0.9)	1.5	2.4
Prior service costs	2.4	2.4	-	-
Net (gain) loss	1.2	(0.3)	0.6	-
Net periodic benefit cost (credit)	1.8	(5.7)	8.6	7.7
Effect of lump sum settlements upon retirement	6.9	5.3	-	-
Net cost (credit)	$ 8.7	$ (0.4)	$ 8.6	$ 7.7

Three Months Ended Nine Months Ended
June 30, June 30,
2003 2002 2003 2002
(In Thousands)
Comprehensive Income
Net income $ 8,013 $ 1,336 $ 102,495 $ 87,351
Other comprehensive income (loss), net of tax (3,283) (1,607) (17,992) (14,241)
Total comprehensive income $ 4,730 $ (271) $ 84,503 $ 73,110
9. SUBSEQUENT EVENTS - STRATEGIC RESTRUCTURING

Subsequent to the close of the third quarter, the Company announced that it has initiated a strategic restructuring plan, which includes key senior management changes affecting the Company and its utility subsidiaries, Peoples Gas and North Shore Gas. ~~did~~William ~~not~~E. ~~record~~Morrow, ~~any~~48, ~~amounts~~was toelected ~~other~~Executive ~~comprehensive~~Vice ~~income~~President of Operations for Peoples Energy. Desiree G. Rogers, ~~therefore~~45, ~~total~~was ~~comprehensive~~elected ~~income~~President ~~for~~of Peoples Gas and North Shore Gas, issucceeding ~~the~~Donald ~~same~~M. asField, ~~net~~who ~~income~~will asretire ~~shown~~ on ~~the~~October ~~their~~1, ~~respective income statements~~2004.

7 Additionally, the Company announced it is offering an enhanced severance package to non-union employees of Peoples Energy, Peoples Gas, North Shore Gas and employees of its diversified Power Generation and Midstream Services business who elect a voluntary resignation of employment. ~~COMMON~~The ~~STOCK~~enhanced severance offer can be accepted by employees from the vice president level and below through August 30, 2004. The cost of this program will be expensed in the fourth quarter of fiscal 2004 and the related pension settlement cost will be expensed in fiscal 2005.

The Company has filed a universal shelf registration statement on Form S-3 for the issuance from time-to-time of up to 1.5 million shares of common stock pursuant to a continuous equity offering in one or more negotiated transactions or "at-the-market" offerings. As of June 30, 2003, 858,300 shares of common stock have been issued through the continuous equity offering. Proceeds, net of issuance costs, totaled $32.4 million. Subsequent to June 30, 2003, and through August 12, 2003, the Company has not issued any additional shares through the program.

In addition, the Company issues common stock through other plans such as direct purchase and investment and employee stock purchase plans. Stock activity for the three- and nine-month periods is shown below.

	Three Months Ended		Nine Months Ended
	June 2003 vs. March 2003		June 2003 vs. September 2002
(Dollars in thousands)	Shares	Dollars	Shares	Dollars
Shares outstanding - beginning of period	35,852,944	$ 315,097	35,459,006	$ 301,699
Shares issued:
Employee Stock Purchase Plan	5,467	$ 210	12,926	$ 452
Long-Term Incentive Compensation Plan - net	31,489	866	70,757	855
Equity program shares issued	652,300	24,400	858,300	32,445
Directors Deferred Compensation Plan	-	-	6,142	187
Direct Purchase and Investment Plan	75,302	2,857	210,371	7,792
Total activity for the period	764,558	$ 28,333	1,158,496	$ 41,731
Shares outstanding - end of period	36,617,502	$ 343,430	36,617,502	$ 343,430

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

EXECUTIVE SUMMARY

Peoples Energy is a diversified energy company comprised of five main business segments: the core business - Gas Distribution, and diversified businesses - Oil and Gas Production, Power Generation, Midstream Services and Retail Energy Services. The Company's Gas Distribution segment consists of two regulated utilities, Peoples Gas and North Shore Gas. This segment has the most significant impact on the consolidated financial results of Peoples Energy, accounting for a major portion of operating income. Since 1998, the Company has developed a portfolio of complementary energy businesses that help to diversify the sources of consolidated operating income. The Company expects these businesses to provide increasing contributions to its long-term growth.

Net income for the fiscal 2004 third quarter and fiscal year-to-date was down $0.07 and $0.39 per share, respectively, from the same periods last year. Both the quarter and year-to-date comparisons with the year-ago periods were negatively affected by lower gas deliveries in the Gas Distribution business. The decline in deliveries reflects the impacts of both warmer weather and lower non-weather related demand. In terms of the non-weather related component, it became more apparent in the third quarter that customers are responding to the current high gas price environment by lowering their energy usage. Natural gas prices are not expected to decline significantly anytime soon, and it is anticipated they will continue to have a dampening effect on gas distribution demand over the next year. These negative effects were partially offset by lower provision for uncollectible accounts compared to the three- and nine-month periods of the previous fiscal year.

The Oil and Gas Production segment is progressing toward another year of significant production growth and increased profitability, with fiscal 2004 operating income expected to be up 35 to 40 percent from the prior year. However, in the third quarter, higher exploration expense and lower than expected production volumes resulted in a decline in operating income compared to a year ago. In terms of production levels, several operational and timing issues resulted in third quarter production volumes that were essentially flat with the year-ago period and less than had been anticipated. Fourth quarter production is expected to increase from third quarter levels. Operating income from the other diversified businesses as a group is up over last year with mixed results from each segment in the quarter and year-to-date periods.

In July, Peoples Energy announced a strategic reorganization of the utilities and corporate support organization. The objectives of this reorganization are to streamline the Company's management structure and to refocus on new sources of efficiency and revenue. The Company believes that a rough estimate of fiscal 2005 cost savings is $8 million to $12 million.

Management now estimates that fiscal 2004 earnings will be in the range of $2.60 to $2.70 per diluted share, excluding any expenses in the fourth quarter related to the above mentioned restructuring. This estimate includes fourth quarter gains on asset sales in the Power Generation and Gas Distribution segments totaling approximately $0.10 per share. Although discussions are continuing on those potential sales, the timing is difficult to predict and they could potentially extend into fiscal 2005. (See Forward-Looking Information).

RESULTS OF OPERATIONS

~~Summary~~ Net income for the third quarter was $5.6 million, or $0.15 per diluted share, compared to $8.0 million, or $0.22 per diluted share in the year-ago quarter. Fiscal year-to-date net income was $91.9 million, or $2.46 per diluted share, compared to $102.5 million, or $2.85 per diluted share a year ago. Operating income for the current quarter and fiscal year-to-date totaled $17.1 million and $172.2 million, respectively, versus $24.4 million and $199.3 million in the same periods last year.

Net income for the fiscal 2003 third quarter ended June 30, 2003 was $8.0 million, or $0.22 per diluted share, compared with $1.3 million or $0.04 per diluted share for the prior year third quarter. Fiscal year-to-date net income was $102.5 million or $2.85 per diluted share, compared to $87.3 million or $2.46 per diluted share a year-ago. Operating income for the third quarter and fiscal year-to-date totaled $24.4 million and $199.3 million, respectively, versus $11.6 million and $171.4 million in the same periods last year.

The increase in the current quarter versus last year reflects 60 percent higher operating results from the diversified energy businesses, as well as the impact of last year's $17.0 million charge to increase the reserve for uncollectible accounts in the Gas Distribution business, partially offset by a $5.0 million increase to the reserve in the current third quarter. Before the impact of these two adjustments, quarter-over-quarter results were essentially flat. Much higher operating income from the diversified energy businesses and the impact of a reduction to the utility revenue tax accruals were offset by lower pension credits, lower utility margin and higher corporate expenses due to the impact on equity compensation expenses resulting from a higher Peoples Energy stock price as of June 30, 2003.

For the year-to-date period, the $27.9 million positive variation in operating income is due primarily to a $19.0 million improvement in operating results from the diversified energy businesses, as well as colder weather in the Gas Distribution segment and a reduction in the utility tax accrual, partially offset by significantly lower pension credits.

A summary of variations affecting the Company's net income between periods is presented below, followed by explanations of significant differences.

	Fiscal 2003 vs. Fiscal 2002
	Three Months	Nine Months
(In Thousands)	Ended	Ended
Revenues	$ 50,998	$ 603,560
Operating Expenses:
Cost of energy sold	38,848	503,455
Operation and maintenance	441	39,905
Depreciation, depletion and amortization	3,265	9,444
Taxes, other than income taxes	(2,909)	28,233
Total Operating Expenses	39,645	581,037
Equity investment income (loss)	1,481	5,301
Operating Income	12,834	27,824
Other income and expense - net	(628)	(4,924)
Interest expense	(1,581)	(6,155)
Earnings Before Income Taxes	13,787	29,055
Income tax expense	7,110	13,911
Net Income	$ 6,677	$ 15,144

Revenues and cost of energy sold increased $51.0 million to $398.1 million and $38.8 million to $238.1 million, respectively, for the three months ended June 30, 2003. For the nine-month period, revenues and cost of energy sold increased $603.6 million to $1,851.1 million and $503.5 million to $1,165.8 million. Higher gas prices in the current fiscal year were a major factor in the quarter and fiscal year-to-date variations. Additionally, colder weather in the nine-month period contributed to increased sales and related gas costs in the Gas Distribution, Retail Energy Services and Midstream Services segments. Revenues were also impacted by increased production in the Oil and Gas Production segment.

~~Operation~~Financial ~~and~~results ~~maintenance expense~~ for the ~~current~~three ~~quarter~~months ~~increased~~ended ~~modestly~~June by30, ~~$0.4~~2004 ~~million~~reflect lower operating results primarily due to ~~$84.1~~lower ~~million.~~deliveries ~~Significant~~in ~~offsetting~~the ~~items~~Gas ~~include~~Distribution asegment ~~$5.0~~resulting ~~million~~from ~~current~~weather ~~quarter~~that ~~charge~~was to18 ~~increase~~percent ~~the~~warmer ~~reserve~~than ~~for~~the ~~uncollectible~~same ~~accounts~~period ~~compared~~last toyear aand ~~$17~~customer conservation.0 ~~million~~Lower ~~charge~~performance in the ~~previous~~third ~~year;~~quarter aby ~~current~~the ~~quarter~~Oil ~~net~~and ~~increase~~Gas inProduction ~~equity~~segment ~~compensation~~also ~~expenses~~affected ofthe ~~$3.4~~quarterly ~~million;~~results, ~~lower~~primarily ~~current~~as ~~quarter~~a ~~pension~~result ~~credits~~ of ~~$2.6~~increased ~~million;~~exploration ~~and~~expense ~~higher~~due ~~environmental~~to ~~costs~~an ofunsuccessful ~~$1.8~~well ~~million~~in Louisiana. ~~For~~Financial results for the nine~~-month~~ ~~period,~~months ~~operation~~ended ~~and~~June ~~maintenance~~30, ~~expense~~2004 ~~increased~~reflect ~~$39.9~~the ~~million~~adverse toimpact ~~$261.6~~of ~~million~~lower ~~due~~deliveries ~~primarily~~resulting tofrom ~~lower~~weather ~~pension~~that ~~credits~~was ofnine ~~$19.4~~percent ~~million;~~warmer ~~increased~~than ~~provision~~the ~~for~~same ~~uncollectible~~period ~~accounts~~last ofyear $7and customer conservation.4 ~~million~~Continued ~~and~~strong ~~higher~~growth ~~group~~from ~~insurance~~the ~~expenses~~diversified ofenergy ~~$2.5~~businesses ~~million~~partially offset the negative delivery impact. The ~~fiscal~~Oil ~~2003~~and ~~pension~~Gas ~~credits~~Production ~~for~~segment ~~the~~benefited ~~three~~from ~~and~~higher ~~nine~~production ~~months~~volumes ~~ended~~and ~~June~~higher ~~30,~~realized ~~2003~~natural ~~are~~gas ~~$1.7~~and ~~million~~oil ~~and~~prices ~~$0.5~~than ~~million,~~a ~~respectively~~year ago.

~~Depreciation,~~Income ~~depletion~~Statement and amortization increased by $3.3 million to $27.6 million for the quarter and $9.4 million to $83.1 million for the nine-month period as a result of increased production in the oil and gas business directly related to additional acquisitions and its ongoing drilling program. Variations

~~Taxes,~~The ~~other~~Company's ~~than~~revenues ~~income~~and ~~taxes~~cost ~~for~~of ~~the~~energy ~~quarter~~sold ~~decreased~~increased $23.90 million toand $279.71 million, asrespectively, afor ~~result of a $5.6 million adjustment in~~ the ~~municipal and state utility tax accrual offset by taxes on higher revenues. For the nine~~three-month period, ~~taxes,~~and ~~other than income taxes~~ increased $2882.20 million toand $~~144~~94.84 million, ~~due to higher revenues caused by higher gas prices and increased deliveries caused by colder weather~~respectively, ~~offset~~for ~~by a $9.6 million adjustment to~~ the ~~municipal~~nine-month ~~and~~period ~~state~~due ~~tax accrual.~~ to:

~~Equity~~higher ~~investment~~realized ~~income~~commodity ~~increased~~prices; ~~for the quarter by $1.5 million to $3.8 million~~ and ~~$5.3 million to $3.5 million for the nine-month period primarily resulting from equity investment income generated from the Southeast Chicago Energy Plant (SCEP).~~
~~Other~~increased ~~income,~~sales ~~net~~volumes ~~of other expense, declined by $0.6 million~~ in the ~~third~~Oil ~~quarter~~ and ~~$4.9~~Gas ~~million~~Production on a year-to-date basis compared to the same periods last year. A reduction in interest income along with a gain on the disposition of property in the prior year period contributed to the fiscal year-to-date variation. Interest expense declined $1.6 million in the third quarter to $12.0 million and ~~$6.2~~Retail ~~million~~Energy toServices ~~$37~~segments.4 ~~million on a year-to-date basis due to lower interest rates and reduced average borrowings outstanding.~~

~~Income~~These ~~taxes~~increases ~~increased~~were ~~$7.1~~offset ~~million~~by toa ~~$5.1~~10 ~~million~~percent and ~~$13.9~~eight ~~million~~percent todecrease ~~$61.1~~in ~~million,~~Gas ~~respectively,~~Distribution ~~due~~deliveries ~~primarily~~in ~~to higher pretax income along with~~ the ~~expiration~~three- onand ~~December~~nine-month 31periods, ~~2002~~respectively, ofresulting ~~Section~~from 29warmer ~~income~~weather ~~tax credits related to the Oil~~ and ~~Gas~~lower ~~Production~~normalized ~~segment~~deliveries.

AOperation ~~summary~~and ofmaintenance ~~the~~expense ~~Company's~~for ~~operating~~the ~~income~~three-month byperiod ~~segment,~~decreased slightly and ~~variations~~increased ~~between~~$8.5 ~~periods,~~million isfor ~~presented~~the ~~below~~nine-month period. Significant items to note in both periods were:

	Three Months Ended		Nine Months Ended		Increase/(Decrease)
	June 30,		June 30,		Three Months	Nine Months
(In Thousands)	2003	2002	2003	2002	Ended	Ended
Operating Income:
Gas Distribution	$ 19,121	$ 8,352	$ 177,603	$ 171,944	$ 10,769	$ 5,659
Power Generation	1,704	156	(740)	(5,380)	1,548	4,640
Midstream Services	(800)	2,849	9,827	9,428	(3,649)	399
Retail Energy Services	792	403	5,100	1,672	389	3,428
Oil and Gas Production	10,168	4,149	23,839	13,942	6,019	9,897
Other	(79)	(171)	15	(580)	92	595
Corporate and Adjustments	(6,485)	(4,151)	(16,376)	(19,582)	(2,334)	3,206
Total Operating Income	$ 24,421	$ 11,587	$ 199,268	$ 171,444	$ 12,834	$ 27,824

higher pension expense of $4.3 million and $8.0 million. Pension expense related to normal activity increased as expected due to the ongoing effects of both lower pension plan returns in recent years and a lower discount rate. The prior nine-month period included a $4.7 million impact on pension expense related to a retiring executive officer.
higher outside professional services ($3.2 million and $5.5 million) mainly related to higher legal costs associated with the utilities ongoing gas reconciliation case before the Commission;
higher expense in the Oil and Gas Production segment ($5.2 million and $6.8 million) resulting primarily from an increase in lease operating expense and exploration expense;
decreased provision for uncollectible accounts ($5.5 million and $5.2 million), mainly as a result of improving credit and collection metrics in its Gas Distribution businesses;
lower corporate expenses resulting from the impact of a lower Peoples Energy stock price on the value of stock appreciation rights ($2.8 million and $2.7 million); and
lower utility environmental costs of $0.2 million and $5.0 million, respectively. (These costs are recovered through the utilities' rate mechanism and a like amount is included in revenues; therefore, these costs do not affect operating income).

Depreciation, depletion and amortization for the three- and nine-month periods increased $2.1 million and $6.5 million, respectively, mainly resulting from higher production and a higher depletion rate in the Oil and Gas Production segment and from higher depreciable property in the Gas Distribution segment.

Taxes, other than income taxes, which are typically directly related to the level of utility revenues, increased for the three- and nine-month periods by $2.0 million and $3.7 million, respectively, due to adjustments to reduce municipal and state utility tax accruals recorded in the previous periods. For the three- and nine-month periods, these adjustments were $5.6 million and $9.7 million, respectively. Absent this impact, these taxes declined due to lower levels of utility revenues. The period-to-period comparison was also affected by a change in the state revenue tax law that resulted in the Company recording more taxes as a direct liability to the state where previous period amounts were included in both revenue and revenue tax expense.

~~Gas~~Income ~~Distribution~~tax ~~Segment~~expense for the three- and nine-month periods decreased $4.4 million and $15.0 million, respectively, primarily from lower pre-taxable income. The fiscal year-to-date period also benefited from a lower effective tax rate due to prior fiscal 2004 adjustments in accrued income taxes and due to the ability under recent tax legislation to realize tax benefits from dividends reinvested in Peoples Energy stock under the Company's Employee Stock Ownership Plan.

~~The~~Segment Company's core business is the distribution of natural gas. Peoples Gas and North Shore Gas purchase, store, distribute, sell and transport natural gas to approximately one million customers (843,000 for Peoples Gas and 151,000 for North Shore Gas). Peoples Gas' 4,000 mile distribution system serves the City of Chicago and North Shore Gas' 2,000 mile distribution system serves 54 communities in northeastern Illinois. The customer base includes residential, commercial and industrial retail sales and transportation accounts, and provides a broad foundation that is not concentrated with any particular group of customers. Peoples Gas also owns a storage facility in central Illinois and a pipeline that connects the storage facility and seven major interstate pipelines to Chicago.Discussion

~~Revenues~~A ofsummary ~~Peoples Gas and North Shore Gas are directly impacted by fluctuations in weather because both companies have a large number~~ of ~~heating customers. Fluctuations in weather have~~ the ~~potential~~Company's ~~to significantly impact year-to-year comparisons of~~ operating income ~~and~~by ~~cash~~segment, ~~flow.~~and Avariations ~~common~~between ~~statistic~~periods, ~~used as an indicator of the affect of weather~~ is ~~Heating~~presented ~~Degree Days (HDD)~~below. ~~A HDD is a unit of measure used to represent each degree that the mean temperature for a 24-hour period is less than 65 degrees Fahrenheit.~~

Revenues of Peoples Gas and North Shore Gas are also affected by changes in the unit cost of the utilities' gas purchases and do not include the cost of gas supplies for customers who purchase gas directly from producers and marketers. In a normal gas price environment, the unit cost of gas does not have a significant direct effect on operating income because the utilities' tariffs provide for dollar-for-dollar recovery of gas costs. (See Note 1 of the Notes to Consolidated Financial Statements.) However, significant changes in gas costs can materially affect the reserve for uncollectible accounts and working capital needs. (See Note 5 of the Notes to Consolidated Financial Statements.)

	Three Months Ended		Nine Months Ended		Increase/(Decrease)
	June 30,		June 30,		Three Months	Nine Months
(In Thousands)	2004	2003	2004	2003	Ended	Ended
Operating income (loss):
Gas Distribution	$ 11,261	$ 19,121	$ 142,009	$ 177,603	$ (7,860)	$ (35,594)
Oil and Gas Production	7,390	10,168	31,287	23,839	(2,778)	7,448
Power Generation	1,695	1,704	(954)	(740)	(9)	(214)
Midstream Services	835	(800)	7,642	9,827	1,635	(2,185)
Retail Energy Services	833	792	8,802	5,100	41	3,702
Other	(116)	(79)	111	15	(37)	96
Corporate and Adjustments	(4,814)	(6,485)	(16,721)	(16,376)	1,671	(345)
Total operating income	$ 17,084	$ 24,421	$ 172,176	$ 199,268	$ (7,337)	$ (27,092)

~~The following table sets forth gross and net margin and degree day statistics for the~~ Gas Distribution ~~segment~~Segment.
The following table summarizes revenue, deliveries and other statistics for the Gas Distribution segment.

Gas Distribution Statistics
	Three Months Ended		Nine Months Ended		Increase/(Decrease)
Margin Data	June 30,		June 30,		~~2003~~Three ~~vs. 2002~~Months	Nine Months
(In Thousands)	~~2003~~2004	~~2002~~2003	~~2003~~2004	~~2002~~2003	~~Three Months~~Ended	~~Nine Months~~Ended
Gas Distribution revenues:
Sales
Residential	$ 176,009	$ 200,072	$1,041,623	$1,046,277	$ (24,063)	$ (4,654)
Heating	$ 188,321	$ 167,910	$ 1,005,401	$ 672,178	$ 20,411	$ 333,223
Commercial	27,624	29,571	165,288	158,467	(1,947)	6,821
Non-heating	11,751	12,241	40,876	36,202	(490)	4,674
Industrial	4,504	4,495	27,391	29,068	9	(1,677)
Commercial	29,571	24,388	158,467	97,193	5,183	61,274
Total sales	208,137	234,138	1,234,302	1,233,812	(26,001)	490
Industrial	4,495	5,070	29,068	17,770	(575)	11,298
Total sales	234,138	209,609	1,233,812	823,343	24,529	410,469
Transportation
Residential	75,~~229~~878	67,~~586~~229	3328,~~297~~449	2733,~~758~~297	~~643~~(1,351)	5(4,~~539~~848)
Commercial	98,~~114~~468	9,~~325~~114	4440,~~428~~830	3944,~~576~~428	(~~211~~646)	4(3,~~852~~598)
Industrial	3,~~540~~841	43,~~449~~540	1615,~~937~~954	16,~~776~~937	~~(909)~~301	~~161~~(983)
Contract pooling	83,~~433~~914	38,~~704~~433	1912,~~335~~135	719,~~430~~335	(4,~~729~~519)	11(7,~~905~~200)
Total transportation	2822,~~316~~101	2428,~~064~~316	~~113~~97,~~997~~368	91113,~~540~~997	4(6,~~252~~215)	22(16,~~457~~629)
Other Gas Distribution revenues	4,~~577~~373	24,~~774~~577	12,~~014~~340	2612,~~708~~014	~~1,803~~(204)	~~(14,694)~~326
Total Gas Distribution revenues	~~267~~234,~~031~~611	~~236~~267,~~447~~031	1,~~359~~344,~~823~~010	~~941~~1,~~591~~359,823	30(32,~~584~~420)	~~418~~(15,~~232~~813)
Less: Gas costs	~~140~~118,~~187~~637	~~109~~140,~~596~~187	~~783~~799,~~391~~756	~~424~~783,~~929~~391	30(21,~~591~~550)	~~358~~16,~~462~~365
Gross margin	126,844	126,851	576,432	516,662	(7)	59,770
Gross margin (1)	115,974	126,844	544,254	576,432	(10,870)	(32,178)
Less: Revenue taxes	1922,~~921~~257	2419,~~768~~921	~~121~~125,~~824~~548	99121,~~296~~824	(42,~~847)~~336	223,~~528~~724
Environmental costs recovered	3,~~262~~052	13,~~439~~262	2015,~~119~~142	520,~~266~~119	~~1,823~~(210)	14(4,~~853~~977)
Net margin *	$ 103,661	$ 100,644	$ 434,489	$ 412,100	$ 3,017	$ 22,389
Net margin (1)	$ 90,665	$ 103,661	$ 403,564	$ 434,489	$ (12,996)	$ (30,925)
Gas Distribution deliveries (MDth):
Gas sales
Residential	15,279	17,753	109,271	120,356	(2,474)	(11,085)
Heating	17,132	20,046	117,590	103,382	(2,914)	14,208
Commercial	2,731	2,990	18,598	19,445	(259)	(847)
Non-heating	621	772	2,766	2,909	(151)	(143)
Industrial	503	503	3,302	3,878	-	(576)
Commercial	2,990	3,194	19,445	15,995	(204)	3,450
Total gas sales	18,513	21,246	131,171	143,679	(2,733)	(12,508)
Industrial	503	779	3,878	3,378	(276)	500
Total gas sales	21,246	24,791	143,679	125,664	(3,545)	18,015
Transportation
Residential	43,~~190~~236	4,~~174~~190	2219,~~173~~552	1922,~~776~~173	16(954)	(2,~~397~~621)
Commercial	7,~~397~~219	87,~~366~~397	3938,~~631~~491	3639,~~845~~631	(~~969~~178)	2(1,~~786~~140)
Industrial	4,~~969~~864	54,~~716~~969	2019,~~542~~318	20,~~849~~542	(~~747~~105)	(~~307~~1,224)
Total transportation	1615,~~556~~319	1816,~~256~~556	8277,~~346~~361	7782,~~470~~346	(1,~~700~~237)	(4,~~876~~985)
Total Gas Distribution deliveries	3733,~~802~~832	4337,~~047~~802	~~226~~208,~~025~~532	~~203~~226,~~134~~025	(53,~~245~~970)	22(17,~~891~~493)
Gross margin per Dth delivered	$ 3.3643	$ 23.9536	$ 2.5561	$ 2.5455	$ 0.4107	$ 0.0206
Net margin per Dth delivered	$ 2.7468	$ 2.3474	$ 1.9294	$ 21.0392	$ (0.4006)	$ (0.~~11)~~02
Actual heating degree days	848	854	6,570	5,581	(6)	989
Average cost per Dth of gas sold	$ 6.41	$ 6.60	$ 6.10	$ 5.45	$ (0.19)	$ 0.65
Normal heating degree days	774	774	6,307	6,307
Actual heating degree days (HDD)	692	845	6,002	6,567	(153)	(565)
Heating degree days as a percent of
Normal heating degree days (2)	752	774	6,307	6,307
normal (actual/normal)**	110	110	104	88
Actual heating degree days as a percent
of normal (actual/normal)	92	109	95	104

*(1) As used above, net margin is not a ~~non-GAAP~~ financial measure computed under GAAP. Gross margin is the GAAP measure most closely related to net margin. Management believes net margin to be useful in understanding the Gas Distribution segment's operations because the utility subsidiaries are allowed, under their tariffs, to recover gas costs, revenue taxes and environmental costs from their customers on a dollar-for-dollar basis.

**(2) Normal ~~HDD~~heating degree days are based on a 30-year average of monthly temperatures at Chicago's O'Hare Airport for the years 1970-1999. The difference between fiscal 2004 and 2003 third quarter normal degree days is caused by a shift of one heating season day from the third quarter to the second quarter due to leap year.

~~The~~Revenues ~~discussion~~for of the Gas Distribution segment ~~variations~~for ~~is primarily~~ the ~~results~~three- ofand ~~Peoples~~nine-month ~~Gas~~periods ~~and~~decreased ~~North~~$32.4 ~~Shore~~million ~~Gas~~and ~~activity~~$15.8 ~~Segment~~million, ~~results~~respectively, ~~also~~from ~~include~~ the ~~impact~~previous ofperiods. ~~the~~The ~~Company's~~decreases ~~weather~~were ~~insurance~~mainly ~~policy,~~due ~~which~~to isa ~~recorded~~decline byin ~~Peoples~~deliveries ~~Energy~~($40.9 ~~This~~million ~~policy~~and ~~protects~~$100.9 ~~earnings~~million) ~~when~~resulting from weather ~~falls~~that ~~below~~was ~~6,000~~18 ~~HDD.~~percent ~~This~~and isnine apercent ~~five~~warmer ~~year~~than ~~policy~~the ~~scheduled~~previous toperiods ~~expire~~and atconservation. ~~the~~Partially ~~end~~offsetting ofthese ~~fiscal~~effects ~~2004~~was higher realized gas prices ($8.5 ~~Prior~~million ~~period~~and ~~revenues~~$85.1 million). Operating income for the three- and nine-month ~~period~~periods ~~includes~~decreased a$7.8 million and $335.16 million, ~~adjustment~~respectively, compared with the previous periods due mainly to ~~weather~~the ~~insurance~~effects ~~income~~of weather ($1.6 ~~Prior~~million ~~period~~and ~~revenues~~$14.1 ~~for~~million) ~~the~~and ~~nine~~lower non-~~month~~weather ~~period~~related ~~includes~~delivery variations ($75.4 million and $9.2 million). inAlso ~~weather~~contributing ~~insurance~~to lower operating income. ~~There~~were ~~are~~reductions noin ~~weather~~municipal ~~insurance~~and state utility tax accruals ~~reflected~~recorded in the ~~current~~previous ~~period~~periods ($5.6 million and $9.7 million) and higher pension expense ($3.9 million and $7.1 million). Partially offsetting these effects was a decrease in the provision for uncollectible accounts ($5.5 million and $5.0 million) mainly as a result of improved credit and collection experience.

~~Revenues~~The ~~for~~Company ~~Peoples~~expects ~~Gas for~~ the ~~three-month~~provision ~~period increased $21.9 million over the previous period resulting from higher gas prices. Revenues~~ for ~~the~~uncollectibles ~~nine-month period increased $355.3 million over the previous period resulting from higher gas prices and from increased deliveries due~~ to ~~weather~~be ~~that~~lower ~~was almost 18 percent colder, or 989 HDD ($25.1 million). Operating income~~ for the ~~three-~~full ~~and~~fiscal ~~nine-month~~year ~~periods~~as ~~increased $9.9 million and $11.5 million, respectively,~~ compared ~~with~~to ~~the~~fiscal ~~previous periods~~2003. The ~~previous~~utilities ~~fiscal~~continue ~~quarter included a $17.0 million increase~~ to ~~the~~improve ~~reserve for uncollectible accounts related to~~ the ~~winter~~collection of ~~fiscal~~accounts ~~2001, which favorably impacted the current year comparisons~~receivable. ~~Another~~Peoples ~~factor~~Gas ~~positively affecting both the three~~ and ~~nine-month~~North ~~periods~~Shore ~~was~~Gas abelieve ~~reduction~~that intheir ~~the~~reserves ~~municipal~~are ~~and~~adequate ~~state~~given ~~utility~~what ~~tax~~is ~~accrual~~known ~~($5.6~~at ~~million~~this ~~and $9~~time.7 ~~million).~~ The over-accruals resulted primarily from the effect of higher uncollectibles on the tax liabilities, which are paid based upon cash receipts. However, partially offsetting these positive impacts was a $5.0 million charge in the current quarter to boost the reserve for uncollectible accounts. ~~Additionally,~~remains ~~lower~~an ~~pension~~estimate ~~credits of $2.1 million~~ and ~~$17.4~~could ~~million~~require ~~for~~future ~~the three and nine months ended, respectively, lowered operating income~~adjustments. The ~~fiscal~~following ~~2003~~table ~~pension~~summarizes ~~credits~~collection ~~are~~statistics ~~$2.3 million and $2.2 million~~ for ~~the~~Peoples ~~three- and nine-month periods, respectively~~Gas. ~~The decrease in pension credits were expected due to the ongoing effects of both lower pension plan returns and the effect of falling interest rates on the discount rate.~~

The fluctuation in net margin per dekatherm delivered for the current periods versus the same periods last year reflect the variation in margin primarily caused by weather impacts. The Company's rate structure establishes a lower unit cost as volumes delivered to a customer increase. Other items affecting net margins include the revenue tax accrual adjustments and a decrease in other gas distribution revenues primarily reflecting weather insurance accrued last year.

	Peoples Gas
	Accounts Receivable Balance
	At June 30,
(Dollars in Millions)	2004	2003	2002
Current	$ 61.3	$ 74.5	$ 81.0
30-89 days	60.0	75.7	55.1
90-149 days	41.1	48.3	31.6

150 days - active	11.4	19.5	32.0
150 days - terminated	17.0	18.0	30.0
Total 150 days	28.4	37.5	62.0

Accounts receivable	$ 190.8	$ 236.0	$ 229.7

Reserve balance	$ 27.4	$ 29.5	$ 36.0
Reserve to accounts receivable ratio	14.4%	12.5%	15.7%
Reserve to 90 days +	39.4%	34.4%	38.5%
Days sales outstanding	56	69	83

The ~~provision~~Company's ~~rate~~weather ~~for~~insurance ~~uncollectible~~policy ~~accounts~~expires aton ~~Peoples~~September ~~Gas~~30, ~~was~~2004. ~~increased~~The ~~beginning~~Company inhas ~~the~~obtained ~~first~~a ~~quarter~~new ofinsurance ~~fiscal~~policy ~~2003~~for ~~from~~fiscal ~~2.0~~year ~~percent~~2005 ofthrough ~~revenues~~a tosubsidiary ~~approximately~~of 2X.5L. ~~percent~~America, inInc. ~~order~~Under tothis ~~conservatively~~policy, ~~manage~~ the ~~possible~~Company ~~impact~~will onreceive ~~future~~$20,000 ~~collections~~for ofeach ~~higher~~heating ~~customer~~degree ~~bills~~day ~~due~~in tofiscal ~~higher~~year ~~natural~~2005 ~~gas~~below ~~prices~~6,100 ~~and colder weather~~(i.e., ~~Based~~approximately onfive anpercent ~~ongoing~~warmer ~~review~~than ~~of estimated future utility charge offs~~normal), ~~Peoples~~up ~~Gas~~to ~~recorded~~a anmaximum ~~additional~~of $~~5.0~~10 million. ~~provision~~If intotal ~~the~~heating ~~third~~degree ~~quarter~~days toduring ~~increase~~fiscal ~~the~~year ~~reserve~~2005 ~~for~~exceed ~~uncollectible~~6,800 ~~accounts to $29~~(i.~~5 million at June 30~~e., ~~2003.~~approximately ~~Peoples~~six ~~Gas~~percent ~~and~~colder ~~North~~than ~~Shore~~normal), ~~Gas~~the ~~believe~~Company ~~that~~will ~~their~~pay ~~reserves~~an ~~are~~additional ~~adequate~~premium ~~given~~to ~~what~~the isinsurer ~~known~~of ~~at this time. However~~$10,000 ~~the reserve~~ for ~~uncollectible~~each ~~accounts~~heating ~~remains~~degree anday ~~estimate~~above ~~and could require further adjustments if circumstances change~~6,800.

The utilities have implemented more aggressive policies in an attempt to improve the collection of accounts receivable, such as: requiring deposits from customers identified as high risk for payment problems; prioritizing and expediting disconnection of service to delinquent accounts; utilizing letter writing campaigns and outbound calling to medium- and low-risk customers with delinquent accounts; faster reporting of delinquent accounts to credit reporting agencies and using secondary collection agents when primary collection agents are not successful.

Revenues for North Shore Gas for the three-month period increased $5.6 million over the prior period resulting from higher gas prices. Revenues for the nine-month period increased $70.1 million over the prior period resulting from higher gas prices and from increased deliveries due to weather that was almost 18 percent colder, or 989 HDD ($3.6 million). Operating income for the three-month period decreased $2.3 million. Operating income for the nine-month period increased $1.4 million. Contributing to the income variations was an increase in pension expense of $0.5 million and $1.8 million for the three- and nine-month periods, respectively. The fiscal 2003 pension expense is $0.4 million and $1.1 million for the three- and nine-month periods, respectively.

~~Power~~Oil ~~Generation~~and Gas Production Segment.
Revenues for the three- and nine-month periods increased $2.5 million and $15.8 million compared with the same periods last year. Operating income for the three-month period decreased $2.8 million compared with the previous period. The decrease in operating income for the three-month period was due to higher operating expenses and higher exploration expense ($3.8 million) related primarily to an unsuccessful exploratory well in Louisiana. Gas production was flat compared to the same period a year ago and lower than second quarter levels due to several operational and timing issues, as described below. Partially offsetting these effects was higher net realized commodity prices and higher income from the Company's equity investment in EnerVest Energy, L.P. (EnerVest). Operating income for the nine-month period increased $7.5 million compared with the previous period due mainly to higher production volumes and higher realized commodity prices, as well as higher income from the Company's investment in EnerVest ($3.1 million). On an equivalent basis, production increased 10 percent compared to the prior year nine-month period due primarily to the current and previous fiscal year's acquisitions and successful drilling program. An increase in depreciation, depletion and amortization expense ($4.9 million) resulted from higher production and an increase in the depletion rate.

~~The~~Several ~~Power~~operational ~~Generation~~and ~~segment,~~timing ~~through~~issues ~~Peoples~~resulted ~~Energy~~in ~~Resources,~~third isquarter ~~engaged~~production involumes ~~the~~that ~~development,~~were ~~construction,~~essentially ~~operation~~flat with the year-ago period and ~~ownership~~less ofthan ~~electric~~had ~~generation~~been ~~facilities~~anticipated. ~~for~~Production ~~sales~~was tohampered ~~electric~~by ~~utilities~~a ~~and~~pipeline ~~marketers.~~force ~~Currently,~~majeure ~~the~~that ~~Company~~resulted ~~has~~in an4 ~~ownership~~MMcfe ~~interest~~per day of net production being shut in ~~two~~for ~~electric~~nearly ~~generation~~the ~~facilities~~entire month of June. The Company ~~and~~experienced ~~Dominion~~a ~~Energy,~~number ~~Inc.~~of ~~(Dominion)~~smaller ~~are~~production ~~equal~~disruptions ~~investors~~due into ~~Elwood~~mechanical ~~Energy~~problems ~~L.L.C.~~or ~~(Elwood)~~well work operations during the quarter, all of which ~~owns~~have ~~and~~been ~~operates~~rectified agoing 1into the fiscal fourth quarter. Combined,~~400~~ these shut-~~megawatt~~ins ~~peaking~~resulted ~~facility~~in ~~near~~nearly ~~the~~3 ~~City~~MMcfe ofper ~~Chicago.~~day ~~Power~~being ~~generated~~off byproduction ~~Elwood~~for isthe ~~sold~~quarter. ~~through~~The ~~long-term~~Company ~~contracts~~drilled ~~with~~15 ~~Exelon~~wells ~~Generation~~during ~~Company,~~the ~~LLC~~third quarter (~~Exelon~~of which 93 percent were successful), ~~Engage~~but ~~Energy~~only ~~America,~~six ~~LLC~~of ~~(Engage)~~these wells produced for a portion of the quarter due to timing delays of getting the wells completed and ~~Aquila,~~ready ~~Inc~~for production. ~~(Aquila)~~Over 2 MMcfe per day of net production for the quarter was delayed as a result. The Company ~~has~~expects ato 27have ~~percent~~these ~~interest~~wells inand ~~SCEP,~~ a ~~partnership~~substantial ~~with~~portion ~~Exelon,~~of ~~that~~the ~~owns~~fourth ~~and~~quarter ~~operates~~program aon ~~350-megawatt~~line ~~facility.~~for ~~The~~a ~~Power~~large ~~Generation~~part ~~segment~~of isthe ~~also~~fourth ~~developing~~quarter. ~~three~~The ~~additional~~Company ~~sites~~still toexpects ~~partner~~solid ~~with~~production orgrowth ~~sell~~of to10 ~~additional~~percent ~~investors~~over fiscal 2003.

~~Revenue~~The ~~recognition~~following ~~for~~table ~~the~~summarizes ~~Elwood~~hedges ~~facility~~in isplace ~~based~~for onthe ~~contract~~remaining ~~provisions,~~fiscal ~~which~~2004 ~~assign~~(July ~~higher~~through ~~value~~September) toand ~~summer~~2005 ~~capacity.~~for ~~The~~the ~~majority~~Oil ofand ~~Elwood's~~Gas ~~annual~~Production ~~capacity~~segment ~~revenues~~as ~~are~~of ~~recognized~~July in22, ~~the~~2004 ~~June~~(date toof ~~September~~information ~~period,~~used ~~resulting~~ in ~~operating losses in~~ the ~~first~~Company's ~~and~~third ~~second~~quarter ~~quarters.~~earnings ~~Revenue is recognized by SCEP evenly across the fiscal year based on contract provisions~~release).

Operating income for the three-month period increased $1.5 million. The operating loss for the nine-month period amounted to $0.7 million, compared to a previous period loss of $5.4 million. The improvement for both periods was primarily due to equity investment income generated from the 350-megawatt SCEP plant, which began commercial operations in July 2002. Because the majority of Elwood's capacity revenues are recognized in the June to September period, Elwood recorded operating losses during the first two fiscal quarters.

	Remaining Fiscal 2004	Fiscal 2005
Gas hedges in place (MMbtus)	6,549,000	22,143,500
Gas hedges as a percent of estimated fiscal production ⁽¹⁾	95%	75%
Percent of gas hedges that are swaps	52%	38%
Average swap price ($/MMbtu)	$ 4.14	$ 4.10
Percent of gas hedges that are no cost collars	48%	62%
Weighted average floor price ($/MMbtu)	$ 4.76	$ 4.37
Weighted average ceiling price ($/MMbtu)	$ 5.61	$ 5.45
Oil hedges in place (MBbls)	113	418
Oil hedges as a percent of estimated fiscal production ⁽¹⁾	80%	70%
Average hedge price ($/Bbl)	$ 26.60	$ 26.94

~~Moody's~~Based Investors Service (Moody's) and Standard & Poor's Ratings Services (S&P) have downgraded Aquila's senior unsecured debt rating to below investment grade. As a result of Aquila's credit rating downgrades and consistent with the requirements of its power sales contracts, Aquila has provided Elwood with security in the form of letters of credit and a cash escrow equal to 12 months of capacity payments. Under its power sales agreement with Elwood, Aquila continues to make monthly capacity payments of approximately $3.1 million on ~~time.~~expected ~~However,~~production asfor ~~previously~~fiscal ~~reported,~~2004 Aquila has informed Elwood that it would like to discuss restructuring or terminating its contracts. In the event Aquila does not fulfill its payment obligations or terminates its power sales contracts and ~~Elwood~~assumes ~~cannot~~fiscal ~~make~~2005 ~~adequate~~production ~~alternate~~increases ~~arrangements,~~10 ~~Elwood~~percent ~~could~~over ~~suffer~~fiscal a2004 ~~revenue shortfall or an increase in its costs that could adversely affect the ability of Elwood to fully perform its obligations under the indenture related to its outstanding bonds~~levels. If Elwood is adversely affected by the failure of Aquila to make payments under its power sales agreements, the Company may receive substantially reduced equity investment income from Elwood. At this time, the Company cannot determine whether or to what extent Aquila's failure to pay Elwood would result in a material adverse effect on the Company.

Midstream Services Segment

The Midstream Services segment is engaged in wholesale activities that provide services to marketers, utilities, pipelines and gas-fired power generation facilities in the upper Midwest. The segment's services are asset-based by virtue of having the physical ability to deliver the gas. The phrase "asset-based" is intended to differentiate Peoples Energy's business from that of certain marketers in the wholesale natural gas business who enter into gas supply and storage contracts without any means of delivering the physical commodity, intending instead to always settle with counterparties on the delivery date through the payment of money without delivery of gas. In addition, Peoples Gas owns and operates a natural gas hub and Peoples Energy Resources owns a natural gas liquids peaking facility. Period-to-period comparisons can have large fluctuations caused by volatility in the energy markets.

~~Revenues~~The ~~for~~following ~~the~~table ~~three-month~~summarizes ~~period~~operating ~~decreased~~statistics ~~$14.0~~from ~~million as compared with~~ the ~~previous~~Oil ~~period. Revenues for the nine-month period increased $103.4 million as compared with the previous period. The Company is expanding its wholesale marketing~~ and ~~asset~~Gas ~~management~~Production ~~activities, which are now performed in a 100 percent owned subsidiary and therefore, year-to-date revenues and expenses have increased versus last year~~segment.

Operating income for the three-month period decreased $3.6 million compared with the prior period. The reduction was primarily due to lower wholesale marketing results ($1.7 million), as well as income in the year-ago period associated with the termination of the equity investment in enovate. Operating income for the nine-month period increased $0.4 million compared with the prior period. Higher operating income in the current year resulted from wholesale marketing and asset management activities ($2.1 million), mostly offset by income in the prior year associated with enovate.

	Three Months Ended June 30,		Nine Months Ended June 30,
	2004	2003	2004	2003
Total production - gas equivalent (MMcfe)⁽¹⁾	6,649	6,574	21,089	19,138
Daily average gas production (MMcfd)	64.2	64.4	67.9	62.5
Daily average oil production (MBd)	1.5	1.3	1.5	1.3
Daily average production - gas equivalent (MMcfed)⁽¹⁾	73.1	72.2	77.0	70.1
Gas production as a percentage of total production	88.0	89.0	88.0	89.0
Percent of production hedged during the period - gas	100.0	78.0	91.0	78.0
Percent of production hedged during the period - oil	83.0	55.0	75.0	60.0
Net realized gas price received ($/Mcf)	$ 4.60	$ 4.31	$ 4.46	$ 4.12
Net realized oil price received ($/Bbl)	$ 27.19	$ 22.72	$ 26.27	$22.53
Depreciation, depletion and amortization rate ($/Mcfe)	$ 1.72	$ 1.63	$ 1.70	$ 1.62
Average lease operating expense ($/Mcfe)	$ 0.58	$ 0.42	$ 0.43	$ 0.41
Average production taxes ($/Mcfe)	$ 0.43	$ 0.36	$ 0.34	$ 0.38

~~Retail~~(1) ~~Energy~~Oil ~~Services~~production ~~Segment~~is converted to gas equivalents based on a conversion of six Mcf of gas per barrel of oil.

~~The~~Certain ~~Retail~~producing properties owned by Peoples Energy ~~Services~~Production ~~segment~~Company ~~provides~~qualified ~~energy,~~for ~~including~~income ~~energy~~tax ~~alternatives,~~credits toas ~~industrial,~~defined ~~commercial~~in ~~and~~Section ~~residential~~29 ~~customers~~of ~~regionally~~the ~~within~~Internal ~~Illinois.~~Revenue ~~Residential~~Code ~~customer~~of ~~choice~~1986. ~~for~~These ~~Illinois~~credits ~~became~~expired ~~available~~on ~~during~~December ~~the~~31, ~~period~~2002. ofThe ~~March~~amount ~~through~~recorded ~~May~~to ~~2002,~~income for ~~both~~the ~~gas~~nine ~~and~~months ~~electricity~~ended June 30, 2003 was $1.1 million.

~~During~~On ~~the~~December ~~third~~31, ~~quarter~~2003, ~~Peoples~~the ~~Energy~~Company ~~Services~~acquired, ~~entered~~through ~~into~~a anseries ~~agreement~~of totransactions, ~~become~~certain ~~the~~oil ~~natural~~and gas ~~provider~~properties ~~for~~located ~~the~~in ~~State~~Texas offor ~~Illinois~~approximately $33.1 ~~Under~~million. ~~this~~The ~~agreement~~acquired reserves, ~~Peoples~~88 ~~Energy~~percent ~~Services~~of ~~will~~which ~~provide~~are ~~nearly~~natural ~~three~~gas, ~~BCF~~contributed ofapproximately ~~natural~~3.2 ~~gas~~MMcfe per day of production to the ~~State~~Company's fiscal year-to-date production. The majority of ~~Illinois~~the ~~facilities~~acquired ~~resulting~~properties are located adjacent to or in anclose ~~estimated~~proximity ~~five~~to ~~percent~~existing ~~increase~~holdings inof ~~total~~the ~~natural~~Company, ~~gas~~and ~~volumes~~each ~~for~~of ~~this~~the ~~segment~~acquired properties are operated by the Company.

~~Revenues~~On ~~for~~July ~~the~~30, ~~three-~~2004, ~~and~~subsequent ~~nine-month~~to ~~periods~~the ~~increased~~end ~~$18.2~~of ~~million~~the ~~and~~third ~~$71.9 million~~quarter, ~~respectively, compared with~~ the ~~previous~~Company ~~periods.~~acquired ~~The~~certain ~~improvement~~oil ~~was~~and ~~due~~gas ~~primarily~~properties toin ~~customer~~east ~~growth,~~Texas ~~colder~~from ~~weather~~a ~~and~~private toentity ~~increases~~for inapproximately ~~natural~~$9.5 ~~gas~~million. ~~commodity~~The ~~prices~~acquisition ~~and~~includes ~~deliveries.~~approximately ~~Gross~~5,300 ~~margin~~gross ~~for~~acres ~~the three-~~ and ~~nine-month~~estimated ~~periods~~proved ~~increased~~undeveloped ~~$0.5~~reserves ~~million~~of ~~and~~approximately ~~$4.2~~10 ~~million~~Bcfe, ~~respectively.~~with ~~Higher~~an ~~electric~~additional ~~margins~~10 ~~and~~to ~~customer~~20 ~~growth~~Bcfe ~~positively~~of ~~impacted~~low ~~operating~~risk, ~~results~~upside ~~for~~reserve ~~both~~potential. ~~periods,~~Initial ~~while~~development of the ~~fiscal~~acquired ~~year-to-date~~reserves ~~comparison~~will ~~also~~begin ~~benefited~~in ~~from~~fiscal ~~higher~~2005 ~~gas~~with ~~margins.~~anticipated ~~Operating~~capital ~~income~~spending ~~for~~on ~~the~~these ~~three-~~properties ~~and~~of ~~nine-month~~between ~~periods~~$10 ~~increased~~million to $~~0.4~~15 million ~~and~~of $3a planned fiscal 2005 capital program.4 ~~million,~~The ~~respectively~~acquired properties, ~~reflecting~~which ~~the~~will ~~benefits~~be ofoperated by the ~~increased~~Company, ~~margins~~are ~~offset~~located ~~partially~~in byclose ~~increased~~proximity ~~operating~~to ~~expenses~~the ~~associated~~existing ~~with~~Peoples ~~the~~Energy ~~segment's~~Production ~~growth.~~holdings in east Texas.

~~The~~Power ~~following~~Generation ~~table summarizes operating statistics for Peoples Energy Services, the main contributor to the Retail Energy Services segment:~~Segment.
Results for the three and nine months ended were relatively unchanged from the prior period. Impacting the results was an increase in expenses related to the development of new power projects, partially offset by lower operating losses compared to the previous period related to Elwood Energy LLC (Elwood).

	Three Months Ended June 30,		Nine Months Ended June 30,
(In Thousands, Except Customers)	2003	2002	2003	2002
Gas sales sendout (Dth)	7,919	6,805	35,780	31,338
Number of gas customers*	16,798	10,452	16,798	10,452
Electric sales sendout (Mwh)	216	190	656	642
Number of electric customers*	1,377	945	1,377	945

This segment is engaged in the development of power generation sites. The costs of activities related to these sites are either expensed as incurred or are capitalized as specific site development assets, as appropriate. Included in other investment at June 30, 2004 was $9.3 million related to this activity. The Company is actively pursuing the sale of one its power generation sites under development in the western United States.

*Actual The ~~number~~electric capacity of ~~customers~~Elwood athas ~~end~~been ofsold ~~each~~through ~~reporting~~long-term ~~period~~contracts with Exelon Generation Company, LLC, Engage Energy America LLC and Aquila, Inc. (Aquila). Standard & Poor's Rating Services (S&P) recently downgraded Aquila's senior unsecured debt rating to CCC+ and placed the rating on CreditWatch with developing implications. In fiscal 2003, Moody's Investor Services (Moody's) downgraded Aquila's senior unsecured debt rating to Caa1 with a negative outlook. S&P and Moody's have lowered the ratings on Elwood's bonds to B+ with a negative outlook and Ba2 with a stable outlook, respectively. As a result of earlier downgrading in Aquila's credit

~~Oil~~ratings, Aquila provided Elwood with security in the form of letters of credit and ~~Gas~~a ~~Production~~cash ~~Segment~~escrow equal to one year of capacity payments of approximately $37.7 million. In the event Aquila does not fulfill its payment obligations or terminates its power sales agreements and Elwood cannot make adequate alternate arrangements, Elwood could suffer a revenue shortfall or an increase in its costs that could adversely affect the ability of Elwood to fully perform its obligations under the indenture related to its outstanding bonds. If Elwood is adversely affected by the failure of Aquila to make payments under its power sales agreements, the Company may receive substantially reduced or no investment income from Elwood. At this time, the Company cannot determine whether or to what extent Aquila's failure to pay Elwood would result in a material adverse effect on the Company.

~~The~~Midstream ~~Oil~~Services ~~and Gas Production segment, through Peoples Energy Production, is active in the acquisition, development and production of oil and gas reserves in selected onshore basins in North America~~Segment. Business is pursued through direct ownership interests in oil, gas and mineral leases. Peoples Energy Production's primary focus is on natural gas, with growth coming from low-to-moderate-risk drilling opportunities and acquisition of proved reserves with upside potential, which can be realized through drilling, production enhancements and reservoir optimization programs. Peoples Energy Production also has an equity investment in EnerVest ($21.0 million as of June 30, 2003), which develops and manages a portfolio of oil and gas producing properties. Results from the equity investment in EnerVest continued to show operating improvement. Equity investment income increased $1.8 million for the year-to-date period as compared to the prior year. The Company and its partners continue to review alternatives as to how to maximize the value of this investment.
Revenues for the three- and nine-month periods increased $24.6 million and $24.4 million, respectively, compared with the previous periods due to higher commodity prices and increased volumes. Operating income for the three-month period increased $1.6 million compared with the prior period due to improved results from wholesale and asset management activities. Operating income for the nine-month period decreased $2.2 million compared with the prior period due primarily to lower results from the hub ($3.2 million). Partially offsetting this effect was higher contributions from wholesale and asset management activities and the Company's propane-based peaking facility.

~~Certain~~Retail ~~producing properties owned by Peoples~~ Energy ~~Production~~Services ~~qualified for income tax credits as defined in Section 29 of the Internal Revenue Code of 1986~~Segment. The Section 29 income tax credits were computed based on units of production and recorded to income as earned. These credits expired on December 31, 2002. The amount of Section 29 income tax credits that were recorded to income for the three months ended June 30, 2002 was $1.0 million. The amount recorded to income for the nine months ended June 30, 2003 and 2002 was $1.1 million and $3.4 million, respectively.
The following table summarizes operating statistics for Peoples Energy Services Corporation.

In November 2002, the Company acquired an interest in five properties in south Texas and the upper Texas gulf area from a subsidiary of Magnum Hunter Resources, Inc. (Magnum Hunter). The reserves acquired, 99 percent of which are natural gas, were purchased for approximately $33.0 million and added approximately 11 MMcfe per day production at the time of the acquisition. In April of 2003, the Company acquired additional interest in the Corpus Christi West Field from Royal Production and several affiliated entities for approximately $9.0 million. This acquisition added more than 2 MMcfe per day production at the time of the acquisition.

	Three Months Ended June 30,		Nine Months Ended June 30,
(In Thousands, Except Customers)	2004	2003	2004	2003
Gas sales sendout (MDth)	8,525	7,919	41,638	35,780
Number of gas customers	20,554	16,798	20,554	16,798
Electric sales sendout (Mwh)	267	216	759	656
Number of electric customers	1,794	1,377	1,794	1,377

Revenues for the three- and nine-month periods increased ~~$13.7~~from ~~million~~last ~~and~~year by $2812.5 million, ~~respectively, compared with the previous periods. Operating income for the three-~~ and ~~nine-month periods increased~~ $658.07 million ~~and $9.9 million~~, respectively, ~~compared~~primarily ~~with the previous periods. Last year's fiscal year results included the one time benefit of a settlement on hedges of $5.1 million. Excluding that impact, year-to-date results tripled~~ due ~~mainly~~ to ~~improved~~continued ~~commodity~~customer ~~prices~~growth and ~~increased~~higher ~~production. Realized~~ gas ~~prices increased from $3.18~~ and ~~$3.08~~energy ~~per Mcf in the previous periods to $4~~prices.31 ~~and~~Operating ~~$4.12~~income ~~per~~for ~~Mcf in~~ the ~~current periods, respectively. Three months ended and fiscal year~~three-~~to-date~~month ~~2003~~period ~~gas production~~ increased toslightly, ~~64.4 MMcf per day and 62.5 MMcf per day compared~~ with ~~43.0~~customer ~~MMcf per day~~ and ~~45.9~~volume ~~MMcf~~growth ~~per~~offset ~~day~~by ~~for~~higher ~~the~~operating ~~previous periods~~expenses. ~~Oil~~Operating ~~production~~income increased ~~from~~by 1$3.07 ~~and~~million ~~1.1 MBbls per day~~ in the ~~previous periods to 1.3 and 1.3 MBbls per day for the current quarter and~~ fiscal year-to-date. ~~The~~period ~~increase in production in both periods was~~ due to ~~the~~customer ~~impact~~growth ~~of the acquired properties~~ and ~~the~~enhanced ~~success~~gas ~~of the Company's drilling program~~margin. The acquired properties contributed 12.8 MMcfe per day and 10.5 MMcfe per day for the three- and nine-month periods, respectively. The drilling program offset normal production decline and added 8.6 Mmcfe per day and 6.1 MMcfe per day for the three- and nine-month periods.

AsPeoples of June 30, 2003, the Company had hedges in place for 4,665,000 Mmbtus, or about 75 percent, of its remaining expected fiscal 2003 production. Of the hedges in place, approximately 55 percent are swaps at an average price of $3.50 per MMbtu. The remainder are no cost collars with a weighted average floor price of $3.85 per MMbtu and a weighted average ceiling price of $4.80 per MMbtu. The majority of these hedges are valued against the New York Merchantile Exchange's Henry Hub Natural Gas Contract. In addition, as of June 30, 2003, the Company had hedges in place for 65,800 Bbls of its remaining expected fiscal 2003 oil production at an average price of $21.25 per Bbl. The oil hedges are valued using the average daily price for the month for the New York Merchantile Exchange's West Texas Intermediate Cushing, Oklahoma Oil Contract. Discussion

Most of Peoples Gas' results are recorded in the Gas Distribution segment, with some activity in the Midstream Services and Corporate segments. The following discussion supplements Peoples Gas information included in the Company's Gas Distribution discussion within this Management's Discussion and Analysis of Results of Operations and Financial Condition (MD&A).

Revenues for Peoples Gas for the three- and nine-month periods decreased approximately $26.2 million and $9.1 million, respectively, from the previous periods. The decrease was mainly due to a decline in deliveries ($35.1 million and $90.8 million) resulting from weather that was 18 percent and nine percent warmer than the previous periods and conservation. Partially offsetting these effects were higher realized gas prices ($9.1 million and $84.7 million). Operating income for the three-and nine-month periods decreased $9.7 million and $37.6 million compared with the previous periods due mainly to the effects of weather ($1.4 million and $12.3 million), lower non-weather related deliveries ($4.5 million and $8.1 million) and lower hub results ($0.4 million and $3.2 million). Also negatively impacting operating income were reductions in municipal and state utility tax accruals recorded in the previous periods ($5.6 million and $9.7 million) and increases in pension expense ($3.7 million and $6.4 million) and other non-labor operating costs. Partially offsetting these effects was a decrease in the provision for uncollectible accounts ($5.0 million and $4.5 million).

AsInterest ofexpense ~~June~~for ~~30, 2003,~~ the ~~Company~~three- ~~had~~and innine-month ~~place~~periods ~~hedges~~decreased ~~covering~~$0.4 ~~about~~million 60and ~~percent~~$1.5 ofmillion, ~~estimated fiscal 2004 production~~respectively, ~~assuming~~compared 10with ~~percent growth over fiscal 2003 production. Of~~ the ~~hedges~~previous inperiods ~~place,~~primarily ~~approximately~~due 60to ~~percent~~lower ~~are~~interest ~~swaps at an average price of $3~~rates.56 ~~per MMbtu.~~ The ~~remainder~~reduction ~~are~~was ~~collars~~due ~~with~~to athe ~~weighted~~impact ~~average~~of ~~floor~~lower ~~price~~interest ofrates ~~$3.71~~on ~~per~~variable ~~MMbtu~~rate debt and athe ~~weighted~~retirement ~~average~~or ~~ceiling~~refinancing ~~price~~ of ~~$5.79~~higher ~~per~~cost ~~MMbtu~~bonds.

~~The~~North ~~following~~Shore ~~table summarizes operating statistics for the Oil and~~ Gas ~~Production segment:~~Discussion

	Three Months Ended June 30,		Nine Months Ended June 30,
	2003	2002	2003	2002
Total production - gas equivalent (MMcfe) (1)	6,574	4,488	19,138	14,385
Daily average production - gas equivalent (MMcfed) (1)	72.2	49.3	70.1	52.7
Gas production as a percentage of total	89%	87%	89%	87%
Net realized gas prices received - ($/Mcf)	4.31	3.18	4.12	3.08
Net realized oil price received - ($/Bbl)	22.72	19.65	22.53	19.08
Depreciation, depletion and amortization rate ($/Mcfe)	1.63	1.40	1.62	1.40
Average lifting costs	$0.42	$0.44	$0.41	$0.38
Average production taxes	$0.41	$0.13	$0.38	$0.11

Most of North Shore Gas' results are recorded in the Gas Distribution segment, with some activity in the Corporate segment. The following discussion supplements North Shore Gas information included in the Company's Gas Distribution discussion within this MD&A.

Revenues for North Shore Gas for the three- and nine-month periods decreased $6.6 million and $9.7 million over the previous periods resulting from a decrease in deliveries ($5.8 million and $10.1 million) ~~Oil~~ ~~production~~due isprimarily ~~converted~~to warmer weather. Operating income for the three- and nine-month periods decreased $0.4 million and $4.1 million compared with the previous periods due mainly to ~~gas~~the ~~equivalents~~effects ~~based~~of onweather ($0.2 million and $1.8 million) and lower non-weather related deliveries ($0.9 million and $1.0 million). Also contributing to lower operating income were increases in pension expense, group insurance expense and outside services expense, partially offset by a ~~conversion~~gain ofon ~~six~~the ~~Mcf~~sale of ~~gas~~property ~~per~~and ~~barrel~~a ofdecrease ~~oil~~in the provision for uncollectible accounts.

The increase in the depreciation, depletion and amortization rate was caused by the inclusion of costs to develop reserves that were previously classified as proved, undeveloped and the transfer of acquisition and development costs and reserves related to properties previously classified as probable, which are now classified as proved. These costs have been added to the depreciation, depletion and amortization pool.

The increase in average production taxes is the result of increased revenues during fiscal 2003. In most states, production taxes are assessed as a percentage of revenues before the impact of hedges. Revenues, excluding hedges, for the third quarter and nine months ended June 30, 2003 increased 118 percent and 150 percent respectively, compared to the same periods in 2002.

Other Segment

The Company is involved in other activities such as district heating and cooling through its Trigen-Peoples District Energy Company (Trigen-Peoples) partnership and miscellaneous nonmaterial investments. These and certain business development activities do not fall under the above segments and are reported in the Other segment. The reported results also include income from the operation of fueling stations for natural gas vehicles.

The revenues, operating expense and operating income variations for the three- and nine-month periods were insignificant as compared with the year-ago periods.

Corporate and Adjustments

Corporate activities that support the business segments, as well as consolidating adjustments, are included in Corporate and Adjustments.

The operating loss for the three- and nine-month periods was $6.5 million and $16.4 million compared to $4.2 million and $19.6 million in the previous periods, respectively. Increased losses in the quarter were primarily due to higher compensation expense resulting from the impact of the higher Peoples Energy stock price on the value of stock appreciation rights. For the fiscal year, losses declined mainly due to lower compensation expense and a continued focus on reducing corporate costs.

The Peoples Gas Light and Coke Company
Gas Distribution Statistics

	Three Months Ended		Nine Months Ended		Increase/(Decrease)
Margin Data	June 30,		June 30,		Three Months	Nine Months
(In Thousands)	2004	2003	2004	2003	Ended	Ended
Gas Distribution revenues:
Sales
Residential	$ 149,910	$ 169,042	$ 885,293	$ 882,741	$ (19,132)	$ 2,552
Commercial	23,540	24,505	139,681	131,316	(965)	8,365
Industrial	3,775	3,624	21,489	23,077	151	(1,588)
Total sales	177,225	197,171	1,046,463	1,037,134	(19,946)	9,329

Transportation
Residential	5,559	6,944	26,978	32,041	(1,385)	(5,063)
Commercial	7,306	7,946	35,572	39,381	(640)	(3,809)
Industrial	3,221	2,884	13,757	14,579	337	(822)
Contract pooling	3,633	7,588	11,056	17,120	(3,955)	(6,064)
Total transportation	19,719	25,362	87,363	103,121	(5,643)	(15,758)

Other Gas Distribution revenues	3,989	4,185	11,359	11,042	(196)	317

Total Gas Distribution revenues	200,933	226,718	1,145,185	1,151,297	(25,785)	(6,112)
Less: Gas costs	98,929	115,317	668,427	645,474	(16,388)	22,953
Gross margin ⁽¹⁾	102,004	111,401	476,758	505,823	(9,397)	(29,065)
Less: Revenue taxes	20,162	17,542	113,679	109,323	2,620	4,356
Environmental costs recovered	2,933	3,092	14,066	19,434	(159)	(5,368)
Net margin ⁽¹⁾	$ 78,909	$ 90,767	$ 349,013	$ 377,066	$ (11,858)	$ (28,053)

Gas Distribution deliveries (MDth):
Gas sales
Residential	12,705	14,578	90,925	100,005	(1,873)	(9,080)
Commercial	2,305	2,433	15,449	15,895	(128)	(446)
Industrial	419	401	2,523	3,041	18	(518)
Total gas sales	15,429	17,412	108,897	118,941	(1,983)	(10,044)

Transportation
Residential	3,108	4,065	18,766	21,476	(957)	(2,710)
Commercial	6,127	6,391	32,872	34,510	(264)	(1,638)
Industrial	3,551	3,785	14,891	16,300	(234)	(1,409)
Total transportation	12,786	14,241	66,529	72,286	(1,455)	(5,757)

Total Gas Distribution deliveries	28,215	31,653	175,426	191,227	(3,438)	(15,801)

Gross margin per Dth delivered	$ 3.62	$ 3.52	$ 2.72	$ 2.65	$ 0.10	$ 0.07

Net margin per Dth delivered	$ 2.80	$ 2.87	$ 1.99	$ 1.97	$ (0.07)	$ 0.02

Average cost per Dth of gas sold	$ 6.41	$ 6.62	$ 6.14	$ 5.43	$ (0.21)	$ 0.71

Actual heating degree days (HDD)	692	845	6,002	6,567	(153)	(565)
Normal heating degree days⁽²⁾	752	774	6,307	6,307

Actual heating degree days as a percent
of normal (actual/normal)	92	109	95	104

~~Other~~(1) ~~Income~~As used above, net margin is not a financial measure computed under GAAP. Gross margin is the GAAP measure most closely related to net margin. Management believes net margin to be useful in understanding the Gas Distribution segment's operations because the utility subsidiaries are allowed, under their tariffs, to recover gas costs, revenue taxes and ~~Expense~~environmental costs from their customers on a dollar-for-dollar basis.

~~Other~~(2) ~~income,~~Normal ~~net~~heating ofdegree ~~other~~days ~~expense,~~are ~~for~~based ~~the~~on ~~three-~~a ~~and nine~~30-~~month~~year ~~periods~~average ~~for~~of ~~the~~monthly ~~Company~~temperatures ~~decreased~~at ~~$0.6~~Chicago's ~~million~~O'Hare ~~and~~Airport ~~$4.9~~for ~~million compared with~~ the ~~previous~~years ~~periods~~1970-1999. ~~due~~The ~~mainly~~difference tobetween afiscal ~~reduction~~2004 inand ~~interest~~2003 ~~income~~third ~~($0.5~~quarter ~~million~~normal ~~and~~degree ~~$2.6~~days ~~million).~~is ~~Also~~caused ~~contributing~~by toa ~~the~~shift ~~decrease~~of ~~was~~one aheating ~~previous~~season ~~period~~day ~~gain~~from on the ~~disposition~~third ofquarter ~~property~~to ~~($1.7~~the ~~million).~~second ~~The~~quarter ~~following~~due ~~items~~to ~~are~~leap ~~included in this category:~~year.

	Three Months Ended		Nine Months Ended
	June 30,		June 30,
(In Thousands)	2003	2002	2003	2002
Interest income from Company cash investment	$ 421	$ 647	$ 1,557	$ 1,905
Interest income on notes receivable	-	285	-	2,011
Gain on sale of land	-	-	-	1,748
Miscellaneous other - net	240	357	194	1,011
Other income and expense	$ 661	$ 1,289	$ 1,751	$ 6,675

Other income, net of other expense, for Peoples Gas for the three-month period remained relatively flat. For the nine-month period, other income, net of other expense decreased $1.4 million due mainly to a previous period gain on the disposition of property ($1.7 million).

Interest Expense

Interest expense for the Company for both the three- and nine-month periods decreased $1.6 million and $6.2 million, respectively, as compared to the previous periods, due to both lower interest rates and lower average borrowing requirements. The reduction was primarily the result of lower interest rates on variable rate debt, the retirement or refinancing of higher cost notes and bonds, and, for the nine-month period, increased use of commercial paper. Average borrowing requirements were reduced due to a combination of factors including increased cash flow from the diversified businesses and increased issuances of common stock.

For Peoples Gas, the interest expense variation for the three-month period was insignificant. For the nine-month period, interest expense decreased $1.1 million as compared to the previous period due to lower interest rates on variable rate debt, to the refinancing of higher cost notes and bonds, and to financing short-term needs principally with commercial paper in the current period and principally with higher cost notes in the prior period.

For North Shore Gas, interest expense for the three- and nine-month periods decreased $0.4 million and $1.1 million, respectively, as compared with the previous periods, primarily due to lower interest rates.

Fiscal Outlook

The Company continues to estimate that fiscal 2003 earnings will be in the range of $2.85 to $2.95 per share assuming, for the remainder of the fiscal year, normal weather and a $5.25 per MMbtu average Henry Hub natural gas price index.

Given the lower interest rate environment compared to a year ago, the Company will likely use lower pension and postretirement benefit accounting discount rate assumptions, compared to fiscal year 2003, for the calculation of fiscal year 2004 pension and postretirement benefit expenses. Although assumptions are not finalized, the current projection for fiscal 2004 pension and postretirement benefit expense is at the high end of a previously communicated range of $6.0 million to $11.0 million, compared to a forecasted fiscal 2003 credit of $1.6 million. In conjunction with finalizing the fiscal 2003 actuarial computations, the Company expects to record in the fourth quarter an additional minimum pension liability and related charge to other comprehensive income estimated to be $35.0 million to $43.0 million, or $21.0 million to $26.0 million, net of tax.

North Shore Gas Company
Gas Distribution Statistics

	Three Months Ended		Nine Months Ended		Increase/(Decrease)
Margin Data	June 30,		June 30,		Three Months	Nine Months
(In Thousands)	2004	2003	2004	2003	Ended	Ended
Gas Distribution revenues:
Sales
Residential	$ 26,099	$ 31,030	$ 156,330	$ 163,536	$ (4,931)	$ (7,206)
Commercial	4,084	5,066	25,607	27,151	(982)	(1,544)
Industrial	729	871	5,902	5,991	(142)	(89)
Total sales	30,912	36,967	187,839	196,678	(6,055)	(8,839)

Transportation
Residential	319	285	1,471	1,256	34	215
Commercial	1,162	1,168	5,258	5,047	(6)	211
Industrial	620	656	2,197	2,358	(36)	(161)
Contract pooling	281	845	1,079	2,215	(564)	(1,136)
Total transportation	2,382	2,954	10,005	10,876	(572)	(871)

Other Gas Distribution revenues	384	392	981	972	(8)	9

Total Gas Distribution revenues	33,678	40,313	198,825	208,526	(6,635)	(9,701)
Less: Gas costs	19,708	24,870	131,329	137,917	(5,162)	(6,588)
Gross margin ⁽¹⁾	13,970	15,443	67,496	70,609	(1,473)	(3,113)
Less: Revenue taxes	2,095	2,379	11,869	12,501	(284)	(632)
Environmental costs recovered	119	170	1,076	685	(51)	391
Net margin ⁽¹⁾	$ 11,756	$ 12,894	$ 54,551	$ 57,423	$ (1,138)	$ (2,872)

Gas Distribution deliveries (MDth):
Gas sales
Residential	2,574	3,175	18,346	20,351	(601)	(2,005)
Commercial	426	557	3,149	3,550	(131)	(401)
Industrial	84	102	779	837	(18)	(58)
Total gas sales	3,084	3,834	22,274	24,738	(750)	(2,464)

Transportation
Residential	128	125	786	697	3	89
Commercial	1,092	1,006	5,619	5,121	86	498
Industrial	1,313	1,184	4,427	4,242	129	185
Total transportation	2,533	2,315	10,832	10,060	218	772

Total Gas Distribution deliveries	5,617	6,149	33,106	34,798	(532)	(1,692)

Gross margin per Dth delivered	$ 2.49	$ 2.51	$ 2.04	$ 2.03	$ (0.02)	$ 0.01

Net margin per Dth delivered	$ 2.09	$ 2.10	$ 1.65	$ 1.65	$ (0.01)	$ 0.00

Average cost per Dth of gas sold	$ 6.39	$ 6.49	$ 5.90	$ 5.58	$ (0.10)	$ 0.32

Actual heating degree days (HDD)	692	845	6,002	6,567	(153)	(565)
Normal heating degree days⁽²⁾	752	774	6,307	6,307

Actual heating degree days as a percent
of normal (actual/normal)	92	109	95	104

(1) As used above, net margin is not a financial measure computed under GAAP. Gross margin is the GAAP measure most closely related to net margin. Management believes net margin to be useful in understanding the Gas Distribution segment's operations because the utility subsidiaries are allowed, under their tariffs, to recover gas costs, revenue taxes and environmental costs from their customers on a dollar-for-dollar basis.

(2) Normal heating degree days are based on a 30-year average of monthly temperatures at Chicago's O'Hare Airport for the years 1970-1999. The difference between fiscal 2004 and 2003 third quarter normal degree days is caused by a shift of one heating season day from the third quarter to the second quarter due to leap year.

Fiscal 2004 and 2005 Outlook

While operating income from the diversified energy businesses is expected to be up 25 to 30 percent over last year, this strong performance will not overcome the negative effects of lower Gas Distribution deliveries. As a result, the Company now expects that fiscal 2004 earnings will be in the range of $2.60 to $2.70 per share, excluding the charge expected to be incurred in the fourth fiscal quarter associated with the Company's restructuring, which cannot be estimated at this time. This range is based on several factors, including a return to normal weather for the rest of the fiscal year, an assumed average NYMEX price for gas of $5.90 per MMbtu, ongoing cost control measures, pension expense of approximately $10 million, and a higher average number of shares outstanding of approximately 37.5 million. Also included in this estimate are expected gains on the sale of assets in the Power Generation and Gas Distribution segments totaling approximately $0.10 per share. Although progress continues in moving toward those sales, the timing is difficult to predict and these transaction could potentially occur in fiscal 2005. The current estimate for fiscal 2004 capital spending is $190 million. (See Forward-Looking Information.)

The Company is optimistic that fiscal 2005 results will improve over fiscal 2004. The Gas Distribution business remains fundamentally strong, and the Company is confident that the recently announced strategic reorganization and other ongoing cost reduction initiatives within the utilities and corporate support organization will provide immediate savings in fiscal 2005. In addition, the Company expects to achieve 10 percent or better growth from the diversified businesses. Although the Company currently is in the process of preparing the budget for fiscal 2005, on a preliminary basis, the July 22, 2004 First Call range of analysts' estimates of $2.70 to $2.88 per share is reasonable, assuming normal weather. (See Forward-Looking Information.)

Critical Accounting Policies

See ~~Management's~~the ~~Discussion and Analysis of Results of Operations and Financial Condition (~~MD&A) in the Company's Annual Report on Form 10-K for the fiscal year ended September 30, ~~2002~~2003 for a detailed discussion of the Company's critical accounting policies. These policies include Regulated Operations, Environmental Activities Relating to Former Manufactured Gas Operations, Retirement and Postretirement Benefits, Derivative Instruments and Hedging Activities, and ~~Depreciation~~Provision for Uncollectible Accounts. In May 2004, ~~Depletion~~the FASB issued FSP No. 106-2, "Accounting and ~~Amortization~~Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003." (See Note 2 of the Notes to Consolidated Financial Statements.)

Other Matters

~~Accounting~~Strategic ~~Standards~~Restructuring.
Subsequent to the close of the third quarter, the Company announced that it has initiated a strategic restructuring plan. (See Note 9 of the Notes to Consolidated Financial Statements.)

LIQUIDITY AND CAPITAL RESOURCES

The following is a summary of cash flows for the Company ~~for the nine months ended June 30~~:

	Nine Months Ended June 30,
(In Thousands)	~~2003~~2004	~~2002~~2003
Net cash provided by (used in) operations	$ 231,154	$ 296,695
Net cash provided by operating activities	$ 262,167	$ 237,675
Net cash provided by (used in) investing activities	$(117,636)	$ 86,349
Net cash used in investing activities	$ (128,234)	$ (117,636)
Net cash provided by (used in) financing activities	$( 66,944)	$(351,469)
Net cash used in financing activities	$ (71,681)	$ (73,465)

Cash provided by ~~operations~~operating ~~decreased~~activities ~~primarily~~increased ~~due~~for tothe annine ~~increase~~months inended ~~accounts~~June ~~receivable~~30, ~~partially~~2004 ~~offset~~as bycompared to the ~~increase~~nine inmonths ~~accounts~~ended ~~payable.~~June ~~The~~30, ~~increase~~2003, inprimarily ~~net cash used in investing activities was~~ due to afavorable ~~prior~~net ~~period~~changes ~~repayment~~to ofworking ~~advances and return of~~ capital, ~~primarily~~that ~~made~~were inpartially ~~connection~~offset ~~with~~by ~~the~~lower ~~expansion~~net ~~of the Elwood facility~~income. The increase in net cash used in ~~financing~~investing activities ~~decreased~~was ~~for~~due ~~the~~to ~~current~~increased ~~period~~capital ~~due~~spending toin athe ~~reduction~~Oil inand ~~short-term~~Gas ~~debt~~Production insegment. While the ~~prior~~change ~~period~~in ~~resulting~~net ~~from~~cash ~~the~~used ~~project~~in financing ofactivities ~~the~~was ~~Elwood~~relatively ~~facility.~~flat,

notable activity included lower retirements of short-term debt and commercial paper in the current period and lower net issuance of long-term debt in the current period.

See the Consolidated Statements of Cash Flows and the discussion of major balance sheet variations for more detail.

37
Balance Sheet Variations

~~The~~Total ~~Company's total~~ assets at June 30, ~~2003~~2004 increased $~~212~~126.65 million as compared to September 30, ~~2002~~2003 primarily due to the seasonal increase in the Gas Distribution and Retail Energy Services segments, customer accounts receivable, additional capital investment in the Gas Distribution and Oil and Gas Production segments, receivables from hedges and increased cash and cash equivalents. These items were offset, in part, by normal seasonal changes in gas inventory levels. The Company's decrease in current liabilities was driven primarily by refinancing short-term debt with long-term debt and by having no commercial paper outstanding, partially offset by increases in liabilities related to normal seasonal LIFO gas inventory adjustment, liabilities related to hedging, revenue tax and income tax accruals and accounts payable. The Company's capitalization increased as a result of the refinancing of a portion of short-term debt with long-term debt, fiscal year-to-date earnings, net of dividends declared, and common stock issued through the continuous equity program, dividend reinvestments and long-term incentive compensation plans.

~~The~~Total ~~increase~~assets inat ~~total~~June ~~assets~~30, ~~from~~2004 ~~September~~increased $118.7 million compared to June 30, ~~2002~~2003 ~~was~~reflecting ~~primarily~~the ~~due~~Company's tocontinued ancapital ~~increase~~investment in ~~customer~~its ~~accounts~~Gas ~~receivable~~Distribution ofand ~~$127~~Oil and Gas Production segments.6 ~~million,~~The aCompany's ~~result~~inventory ofincrease ~~seasonality,~~can ~~colder~~be ~~weather~~attributed ~~and~~to higher gas prices and 5.8 ~~Also,~~Bcf anhigher ~~increase~~inventory volume in the ~~oil~~Gas Distribution, Midstream Services and ~~gas~~Retail ~~property~~Energy ofServices ~~$86~~segments.4 ~~million~~Offsetting ~~was~~these ~~primarily~~increases awere ~~result~~lower ofcustomer accounts receivable balances resulting from the Company's ~~acquiring~~continuing ancollection ~~interest~~efforts. inLong-term ~~five~~assets, ~~properties~~long-term liabilities and accumulated other comprehensive income (AOCI) were affected by a pension adjustment recorded in ~~south~~September ~~Texas~~2003 caused by lower discount rates and returns on pension assets. The Company's capitalization increased as a result of refinancing a portion of short-term debt with long-term debt and ongoing common stock issuances through the ~~upper~~continuous ~~Texas~~equity ~~gulf~~program, ~~area~~dividend reinvestments and ~~developing~~long-term ~~current~~incentive ~~properties~~compensation plans.

Total debt decreased $35.5 million from September 30, 2002 resulting from a combination of factors including the issuance of common stock and reduced working capital requirements. The composition of the debt has changed due to refinancing of maturing long-term debt and variable rate short-term debt with long-term debt. The temporary LIFO liquidation credit increased $47.9 million due to the anticipated replenishment of the lower cost LIFO price layer by fiscal year end. This credit is higher than the June 30, 2002 level due to higher gas prices in the current period.
Within the equity section, the common stock increase of $41.7 million is primarily due to the issuance of 858,300 shares in the continuous equity offering program (see Note 7 of the Notes to Consolidated Financial Statements). The increase in the debit balance in AOCI is mainly due to larger deferred losses on cash flow hedges in place related to future oil and gas production of Peoples Energy Production. These mark-to-market losses result from higher natural gas and oil commodity forward prices compared to the price hedged and will be amortized to income when production is sold.
The change in gas costs recoverable and gas costs refundable is a short-term timing difference between cost of gas delivered by Peoples Gas and North Shore Gas and the gas costs billed to customers.
Other changes compared to September 30, 2002 include the increase in accounts payable, which is primarily due to the increase in gas costs resulting from higher gas prices and the higher demand due to the colder weather. The decrease in regulatory liabilities is due to a reduction in volumes related to the utilities' price protection program and the transfer of gains realized to reduce gas costs. The decrease in the investment in equity method investees is primarily due to the timing of the distributions from Elwood ($9.2 million) and EnerVest ($6.7 million). Deferred charges include approximately $6.1 million of costs related to developing future power production projects.
Changes in Debt Securities

~~During~~There ~~the~~were ~~current~~no ~~fiscal~~changes ~~year,~~to the Company's ~~has~~debt ~~taken~~securities ~~advantage~~during of the ~~low~~third ~~interest~~quarter ~~rate~~of ~~environment~~fiscal ~~to refinance existing debt with lower interest rate debt~~2004. The following table ~~reports~~summarizes the changes that have occurred in the composition of the Company's debt. Induring ~~general, debt classified as short-term due to~~ the ~~technical~~current ~~tender~~fiscal ~~provisions was replaced by long-term debt~~year.

(Dollars In Millions)	Issuances			Retirements
Peoples Gas	$ 51.0	(1)	Auction Rate 34-year,	$ 27.0	(1)(3)	Variable rate, Series EE
			Series OO (2)	37.5	(1)(3)	Variable rate, Series II
	51.0	(1)	Auction Rate 34-year,	37.5	(1)(3)	Variable rate, Series JJ
			Series PP (2)	75.0	(1)	5.75%, Series DD
	75.0	(1)	Variable rate, 35-year (4.875%
			fixed 15 years), Series QQ
Total	$177.0			$177.0

(1) Tax Exempt
(2) Current Mode Auction Rate 35-day period
(3) Classified as short-term debt

Changes in Debt Securities
Nine Months Ended
June 30, 2003
(Dollars In Millions)	Issuances		Retirements
First quarter
North Shore Gas			$ 24.7	8%, Series J
Second quarter
Peoples Gas	$ 50.0	5.00% 30-year, Series KK	$ 50.0	6.875%, Series X
	$ 50.0	Variable rate, 30-year (3.05%	$ 50.0	Variable rate, Series GG
		first 5 years), Series LL	$ 100.0
	$ 50.0	4.0% 7-year, Series MM-1
	$ 150.0
Third quarter
Peoples Gas	$ 75.0	4.625% 10-year, Series NN-1	$ 75.0	6.37%, Series CC
North Shore Gas	$ 40.0	4.625% 10-year, Series N-1	$ 15.0	6.37%, Series L
	$ 115.0		$ 90.0

In addition, subsequent to the close of the quarter, the Company fixed the interest rate for the Peoples Gas $50 million Series HH bonds at 4.75% until July 2014. Due to the tender provisions of the Series HH Bonds and the remarketing periods being less than one year, at June 30, 2004 the debt was classified as short term. Since the new remarketing period exceeds one year, beginning in the fourth quarter the debt will be classified as long term.

Financial Sources

The Company and its two regulated utilities have access to outside capital markets, commercial paper markets and internal sources of funds that together provide sufficient resources to meet cash requirements. The Company does not anticipate any changes that would materially alter its current liquidity position.

Due to the seasonal nature of gas usage, a major portion of the utilities' cash collections occurs between January and June. Because of timing differences in the receipt and disbursement of cash and the level of construction requirements, the utility subsidiaries borrow from time-to-time on a short-term basis. Short-term borrowings are repaid with cash from operations, other short-term borrowings or refinanced on a permanent basis with debt or equity, depending on market conditions and capital structure considerations.

In addition to cash generated internally by operations, as of June 30, 2003, the Company had credit facilities of $150.0 million, which primarily support its commercial paper borrowing, all of which was available. The Company's credit facilities provide that the lenders under such facilities may terminate the credit commitments and declare any outstanding amounts due and payable if the Company's debt-to-total capital ratio exceeds 65 percent. Also, as of June 30, 2003, Peoples Gas had $117.3 million of credit facilities of which up to $34.0 million may be utilized by North Shore Gas. As of June 30, 2003, all of the line was available except for $0.2 million of the line used to back up three Standby Letters of Credit for Peoples Gas. As of June 30, 2003, neither Peoples Gas nor North Shore Gas had outstanding loans from the Company.

The current credit ratings for the Company, Peoples Gas and North Shore Gas are shown on the table below.

	Corporate Credit Rating	Senior Unsecured Debt	Utility Senior Secured Debt	Corporate Commercial Paper	Utility Commercial Paper
Moody's	A3	A3	Aa3	P-2	P-1
Standard and Poor's	A-	BBB+	A-	A-2	A-2
Fitch Ratings	A	A	AA-	F1	F1

On July 29, 2003 Fitch lowered the Company's senior unsecured rating from A+ to A. For both Peoples Gas and North Shore Gas, the senior secured rating was lowered from AA to AA- and the commercial paper rating was lowered from F1+ to F1. The Company's F1 commercial paper rating was affirmed and the ratings outlook for all three companies was raised from Negative to Stable. Fitch noted that the Company's consolidated business risk profile resulting from its diversification strategy has resulted in leverage and credit protection measures that are more consistent with the revised rating.

~~Moody's~~Financial describes double-A rated debt (Aa1, Aa2, and Aa3) as high-grade and single-A rated debt (A1, A2, and A3) as upper-medium-grade. S&P describes A-rated debt (A+, A, and A-) as strong and triple-B rated debt (BBB+, BBB, and BBB-) as adequate. Fitch Ratings (Fitch) describes double-A rated debt (AA+, AA, and AA-) as having a very high credit quality and single-A rated debt (A+, A, and A-) as having high credit quality. The lowest investment grade credit ratings for Moody's is Baa3, for S&P is BBB- and for Fitch is BBB-. Thus, all three credit rating agencies give the Company, Peoples Gas and North Shore Gas investment grade ratings.Sources

~~Regarding~~In ~~short-term~~addition ~~ratings~~to ~~applicable~~cash togenerated ~~commercial~~internally ~~paper~~by operations, ~~Moody's~~as ~~describes~~of June 30, 2004, the ~~P-1~~Company ~~rating~~had ascommitted ~~indicating~~credit afacilities ~~superior~~of ~~repayment~~$392.5 ~~ability~~million ~~and~~(Peoples ~~P-2~~Energy, as$225.0 ~~indicating~~million; aPeoples ~~strong~~Gas, ~~repayment~~$167.5 ~~ability~~million, of which $37.0 ~~S&P~~million ~~describes~~could anbe ~~A-2~~utilized ~~rating~~by asNorth ~~satisfactory~~Shore Gas). ~~Fitch~~These ~~describes~~various facilities primarily support the F1Company's ~~ratings~~ability ~~(F1+~~to borrow using commercial paper. As of June 30, 2004, all of Peoples Energy's $225.0 million facilities were available and ~~F1)~~$167.0 asmillion ~~indicating~~of the ~~highest~~$167.5 million Peoples Gas and North Shore Gas facilities were available. The Peoples Energy credit ~~quality~~facilities expire in March 2007.

On August 4, 2004, Peoples Gas replaced the $167.5 million of bilateral credit facilities available to Peoples Gas and North Shore Gas with a $200.0 million 364-day syndicated facility available to Peoples Gas that will expire in August 2005. North Shore Gas intends to meet its future short-term borrowing requirements through loans from Peoples Energy or Peoples Gas. The banks that are party to Peoples Gas' syndicated facility are ABN AMRO Bank, N.V. (Agent), Harris Nesbitt Financing, Inc., JPMorgan Chase Bank, The Northern Trust Company, Sumitomo Mitsui Banking Corporation, KBC Bank N.V., U.S. Bank National Association, The Bank of New York, Merill Lynch Bank USA and Fifth Third Bank.

The Company's and Peoples Gas' credit facilities contain debt triggers that permit the lenders to terminate the credit commitments to the borrowing company and declare any outstanding amounts due and payable if the borrowing company's debt-to-total capital ratio exceeds 65 percent. The current debt-to-total capital ratio for the Company, Peoples Gas and North Shore Gas is 50 percent, 44 percent and 39 percent, respectively.

In addition to the committed credit facilities discussed above, the Company has an uncommitted line of credit of $15.0 million, which was unused as of June 30, 2004. Peoples Gas and North Shore Gas also have the authority to borrow up to $150.0 million and $50.0 million, respectively, from Peoples Energy. As of June 30, 2004, neither Peoples Gas nor North Shore Gas had any loans outstanding from Peoples Energy.

The current credit ratings for the Company, Peoples Gas and North Shore Gas have not changed since the filing of the September 30, 2003 Annual Report on Form 10-K.

Changes in Equity Securities

~~The~~During ~~Company~~fiscal ~~has~~2003 the Company filed a universal shelf registration statement on Form S-3 for the issuance from time- to- time of up to 1.5 million shares of common stock pursuant to a continuous equity offering in one or more negotiated transactions or "at-the-market" offerings. AsSince inception of ~~June~~this 30plan, ~~2003,~~the ~~858,300~~Company ~~shares~~has ~~of common stock have been~~ issued ~~through~~1,235,700 ~~the~~shares ~~continuous~~with ~~equity offering. Proceeds~~proceeds, net of issuance costs, ~~totaled~~totaling $3247.49 million. ~~Subsequent~~No toshares ~~June~~have ~~30,~~been ~~2003,~~issued ~~and~~subsequent ~~through~~to ~~August~~March 1231, ~~2003, the Company has not issued any additional shares through the program~~2004. InThis ~~addition,~~and ~~the~~other ~~Company issues~~ common stock ~~through~~activity ~~other~~is ~~plans~~summarized ~~such~~in ~~as direct purchase and investment and employee stock purchase plans. (See Note 7 of~~ the ~~Notes~~table ~~to Consolidated Financial Statements~~below.)

Off-balance Sheet Financing

	Three Months Ended		Nine Months Ended
	June 2004		June 2004
(Dollars in Thousands)	Shares	Dollars	Shares	Dollars
Beginning balance	37,502,425	$ 371,621	36,689,968	$ 339,785
Shares issued:
Employee Stock Purchase Plan	6,937	258	13,244	487
Long-Term Incentive Compensation
Plan - net	8,081	542	305,212	11,179
Continuous equity offerings	-	(8)	377,400	15,450
Directors Stock and Option Plan	-	-	766	32
Direct Purchase and Investment Plan	65,511	2,774	196,364	8,254
Total activity for the period	80,529	3,566	892,986	35,402

Ending balance	37,582,954	$ 375,187	37,582,954	$ 375,187

Off-balance sheet debt at June 30, 2003 and June 30, 2002 consists of the Company's pro rata share of nonrecourse debt of various equity investments, including Trigen-Peoples ($15.4 million and $15.7 million), EnerVest ($2.7 million and $15.1 million) and Elwood ($191.1 million and $198.2 million). 40

Financial Uses

Capital Spending.
In the nine-month period ended June 30, 2004, the Company spent $144.9 million on capital projects. The Gas Distribution segment spent $53.0 million on property, plant and equipment of which $46.2 million was spent by Peoples Gas and $6.8 million was spent by North Shore Gas. The majority of the remaining $91.9 million was spent by the Oil and Gas Production segment, which spent $87.0 million on the acquisition of reserves, drilling projects and the exploitation of the acquired and existing assets. Management currently estimates that capital spending for fiscal 2004 will total approximately $190 million. Including the acquisition of properties on July 30, 2004, expenditures in the Oil and Gas Production segment are expected to total $100 million to $105 million assuming no additional acquisitions in the fiscal year. Most of the remaining balance of the Company's total capital expenditures for fiscal year 2004 is targeted for the Gas Distribution segment.

Dividends
. On February 4, 2004, the Directors of the Company voted to increase the regular quarterly dividend on the Company's common stock from 53 cents per share to 54 cents per share. The first payment at this new level was made on April 15, 2004 to shareholders of record at the close of business on March 22, 2004.

Commitments and Contingencies

~~Contractual~~ The ~~Obligations~~Company has certain contractual obligations directly related to the Company's operations and unconsolidated equity investees. The majority of these are long-term debt related with other substantial commitments for gas supply, transportation and storage contracts.

40Contractual Obligations and Other Commitments.
Since the filing of the September 30, 2003 Annual Report on Form 10-K there have been no significant changes to contractual obligations.

~~Guarantees~~Off-balance ofSheet ~~Unconsolidated Equity Investees and Standby Letters of Credit~~Financing.
Off-balance sheet debt at June 30, 2004 and 2003 consists of the Company's pro rata share of nonrecourse debt of various equity investments, including Trigen-Peoples District Energy Company (Trigen-Peoples) ($15.1 million and $15.4 million), EnerVest ($8.3 million and $2.7 million) and Elwood ($184.0 million and $191.1 million). The Company believes this off-balance sheet financing will not have a material effect on the Company's future financial condition. The Company also has commercial obligations of $50.4 million in guarantees and $7.2 million in letters of credit at June 30, 2004.

Commitments Due by Period
Total
(In Millions) Amounts Less than 1 to 3 4 to 5 More than
Other commercial commitments Committed 1 Year Years Years 5 Years
Standby letters of credit $ 6.0 $ 3.9 $ - $ 0.1 $ 2.0
Guarantees of unconsolidated equity investees 50.4 - 12.5 - 37.9
Total other commercial commitments $ 56.4 $ 3.9 $ 12.5 $ 0.1 $ 39.9
Peoples Gas has four standby letters of credit totaling $4.0 million as of June 30, 2003. North Shore Gas has none.
As of June 30,
2003
(In Millions)
Guarantees of unconsolidated equity investees
Elwood - Debt service reserve account $ 8.9
- Operational 22.5
Trigen-Peoples - Operational 19.0
Total guarantees of unconsolidated equity investees $50.4
In connection with Elwood's project financing, the Company and Dominion have each guaranteed 50 percent of the amount required to be maintained by Elwood in a debt service reserve account. The amount of the Company's guarantee varies over the life of the loan but will not exceed $16.5 million. Subject to the Company's right to terminate the guarantee upon Elwood's depositing sufficient cash in the debt service reserve account, the guarantee continues until Elwood's payment of its outstanding bonds in full, expected to occur July 5, 2026.
The Company has guaranteed 50 percent of Elwood's financial obligations to Aquila in connection with the Aquila power sales agreements. The Company's aggregate liability under the guarantees is limited to $10.0 million. The guarantees terminate August 31, 2016 and August 31, 2017. The Company has also guaranteed 50 percent of Elwood's financial obligations to Engage in connection with the Engage power sales agreement. The Company's aggregate liability under this guarantee is limited to $12.5 million. The guarantee terminates December 31, 2004.
The Company and Trigen Energy Corporation (Trigen) are equal partners in Trigen-Peoples, which provides heating and cooling services to the Metropolitan Pier and Exposition Authority (MPEA) at the McCormick Place Exposition Center in Chicago pursuant to a Development and Energy Services Agreement (MPEA Agreement). Under the MPEA Agreement, Trigen-Peoples must deliver to MPEA and maintain a standby letter of credit to secure Trigen-Peoples' obligations. In addition, the Company and Trigen have provided MPEA with a joint and several guarantee of Trigen-Peoples' obligations under the MPEA Agreement. The guarantee is limited to $11.0 million, plus providing from $4.0 million to $8.0 million in replacement letters of credit, of which the Company would be entitled to collect half of such amounts from Trigen. The guarantee continues for the term of the MPEA Agreement, which ends January 1, 2022.
The Company and Trigen are also party to a Sponsor Support and Equity Contribution Agreement (Sponsor Agreement) with Trigen-Peoples' lender, Prudential Insurance Company of America (Prudential). Under the Sponsor Agreement, the Company and Trigen each agree to pay Prudential 50 percent of Trigen-Peoples' outstanding loan obligations only upon the occurrence of certain events relating to material destruction of the plant, taking of the plant by eminent domain, purchase of the plant by MPEA or default by Trigen-Peoples, the Company or Trigen of certain obligations under the MPEA Agreement and only to the extent that proceeds
41
received by Trigen-Peoples as a result of any such events, plus other cash of Trigen-Peoples, are not sufficient to pay the Prudential loan obligations. None of such events is currently expected to occur. Trigen-Peoples' outstanding loan from Prudential was $30.2 million at June 30, 2003. The guarantee continues until payment of the Prudential loan in full, expected to occur December 31, 2017. The Company is not able to estimate the maximum potential amount of future payments under the Sponsor Agreement, if any, because it cannot ascertain the amount of eminent domain proceeds that would be available to the partnership in the unlikely event of a government taking of the plant, nor can it estimate the amount of yield maintenance premium payable with respect to the partnership's loan obligations as such amount is a function of the outstanding loan balance and interest rates at the time the event occurs.
Environmental Matters
. Peoples Gas and North Shore Gas are conducting environmental investigations and remedial work at certain sites that were the locations of former manufactured gas operations. (See Note 5 of the Notes to Consolidated Financial Statements.)

In 1994, North Shore Gas received a demand from a responsible party under CERCLA for environmental costs associated with a former mineral processing site in Denver, Colorado. The demand alleged that North Shore Gas is a successor to the liability of a former entity that allegedly disposed of mineral processing wastes there between 1934 and 1941. (See Note 45 of the Notes to Consolidated Financial Statements.)

Gas Charge Reconciliation Proceedings and Related Matters.
For each utility subsidiary, the Commission conducts annual proceedings regarding the reconciliation of revenues from the Gas Charge and related gas costs. In these proceedings, the accuracy of the reconciliation of revenues and costs is reviewed and the prudence of gas costs recovered through the Gas Charge is examined by interested parties. Proceedings regarding Peoples Gas and North Shore Gas for fiscal 2003, 2002 and 2001 costs are currently pending before the Commission. In February 2004, a purported class action was filed against the Company and Peoples Gas by a Peoples Gas customer alleging, among other things, violation of the Illinois Consumer Fraud and Deceptive Business Practices Act related to matters at issue in Peoples Gas' gas reconciliation proceedings. (See Note 6 of the Notes to Consolidated Financial Statements.)

Indenture Restrictions

~~Peoples~~North ~~District~~Shore ~~Energy~~Gas' ~~owns~~indenture arelating 50to ~~percent~~its ~~equity~~first ~~interest~~mortgage inbonds ~~Trigen-Peoples.~~contains ~~The~~provisions ~~Construction~~ and ~~Term~~covenants ~~Loan~~restricting ~~Agreement~~the ~~between~~payment ~~Trigen-Peoples and Prudential Insurance Company~~ of ~~America~~cash ~~related~~dividends toand ~~Trigen-Peoples'~~the ~~project~~purchase ~~financing~~or ~~prohibits~~redemption ~~any~~of ~~distribution that would result in the partners' total~~ capital ~~account in Trigen-Peoples being less than $7~~stock.0 ~~million.~~ At June 30, ~~2003~~2004, ~~the~~such ~~partners'~~restrictions ~~capital~~amounted ~~account~~to ~~was~~ $76.9 million. ~~The~~of ~~Construction~~North ~~and~~Shore ~~Term Loan Agreement also prohibits any distribution unless the partnership~~Gas's ~~debt~~total ~~service~~retained ~~coverage~~earnings ~~ratio~~of ~~for the four fiscal quarters prior to the distribution was at least 1~~$84.258 ~~to 1~~million.~~0. Trigen-Peoples' debt service coverage ratios for the last four fiscal quarters were 1.85 to 1.0, 2.28 to 1.0, 2.07 to 1.0 and 2.01 to 1.0.~~

Peoples District Energy ~~Resources~~Corporation owns a 50 percent equity interest in ~~Elwood~~Trigen-Peoples. ~~Elwood's~~The ~~trust~~Construction ~~indenture~~and Term Loan Agreement between Trigen-Peoples and ~~other~~Prudential ~~agreements~~Insurance Company of America related to ~~its~~Trigen-Peoples' project financing ~~prohibit~~prohibits ~~Elwood~~any ~~from~~distribution ~~making~~that ~~distributions,~~would ~~unless~~result ~~Elwood~~in ~~has~~the ~~maintained~~partners' ~~certain~~total ~~minimum~~capital ~~historic~~account ~~and~~in ~~projected~~Trigen-Peoples ~~debt~~being ~~service~~less ~~coverage~~than ~~ratios~~$7.0 million. At ~~July~~June 730, ~~2003~~2004, the ~~most~~partners' ~~recent~~capital ~~semi-annual~~account was $7.3 million. The Construction and Term Loan Agreement also prohibits any distribution ~~date,~~unless the ~~minimum~~partnership's debt service coverage ratio offor the four fiscal quarters prior to the distribution was at least 1.225 to 1.0. ~~was required and Elwood~~Trigen-Peoples's ~~actual~~ debt service coverage ~~ratio~~ratios ~~was~~for ~~approximately~~the last four fiscal quarters starting with the most recent quarter were 1.585 to 1.0, 2.09 to 1.0, 1.72 to 1.0, and 1.90 to 1.0.

~~Risk~~ Peoples ~~Management~~Energy Resources Company, LLC owns a 50 percent equity interest in Elwood. Elwood's trust indenture and other agreements related to its project financing prohibit Elwood from making distributions, unless Elwood has maintained certain minimum historic and projected debt service coverage ratios. At July 6, 2004, the most recent semi-annual distribution date, a minimum debt service coverage ratio of 1.2 to 1.0 was required and Elwood's actual debt service coverage ratio was approximately 1.5 to 1.0.

Market Risk.
42
The following table presents the valuation of outstanding contracts at June 30, 2003 and 2002:
Derivative Type
Cash Flow Fair Value
Hedges Hedges Mark-to-Market
(In Thousands) 2003 2002 2003 2002 2003 2002
Value of contracts outstanding at the beginning of the period $ (35,029) $ (10,939) $ (3) $ - $ 37,065 $ 5,420
Less: contracts realized or otherwise settled during the period (8,410) (1,969) 95 - 19,639 -
Plus: value of new contracts entered into during the period
and outstanding at end of period 1,220 (451) 102 - (2,937) (3)
Plus: changes in fair value attributable to changes in valuation
techniques and assumptions - - - - - -
Plus: other changes in fair values (16,374) (4,716) 98 - 9,599 5,806
Value of contracts outstanding at the end of the period $ (41,773) $ (14,137) $ 102 $ - $ 24,088 $ 11,223
The maturity of the fair value hedges and the mark-to-market contracts fall within the next 12 months. Included in the value of mark-to-market contracts are amounts relating to the utility subsidiaries' gas price protection program ($24.2 million). All gains or losses from these contracts at maturity will be included in the gas charge to customers. The maturities of the cash flow hedges are detailed in the table below. All valuations are based on NYMEX closing prices at June 30, 2003.
Cash Flow Hedges
Value by Year of Maturity
(In Thousands)
Less than 1 to 2 2 to 3 3 to 4 4 to 5
Total 1 Year Years Years Years Years
Value at June 30, 2003 $(41,773) $ (22,567) $(11,786) $(5,638) $(1,782) $ -
MMbtue 35,698 17,731 11,139 5,523 1,305 -
Average Hedge Price $ 3.55 $ 3.59 $ 3.56 $ 3.48 $ 3.07 $ -
Value at June 30, 2002 $(14,137) $ (3,791) $ (4,686) $(2,799) $(1,841) $(1,020)
MMbtue 40,498 15,903 11,761 7,732 4,082 1,020
Average Hedge Price $ 3.32 $ 3.26 $ 3.32 $ 3.46 $ 3.43 $ 2.94
Interest Rate Risk
FORWARD-LOOKING INFORMATION

43 This MD&A contains statements that may be considered forward-looking, such as: management's expectations, the statements of the Company's business and financial goals regarding its business segments, the effect of weather on net income, cash position, source of funds, financing activities, market risk, the insignificant effect on income arising from changes in revenue from customers' gas purchases from entities other than the Gas Distribution subsidiaries, the adequacy of the Gas Distribution segment's reserves for uncollectible accounts, capital expenditures of the Company's subsidiaries, and environmental matters. These statements speak of the Company's plans, goals, beliefs, or expectations, refer to estimates or use similar terms. Generally, the words "may," "could," "project," "believe," "anticipate," "estimate," "plan," "forecast," "will be" and similar words identify forward-looking statements. Actual results could differ materially, because the realization of those results is subject to many uncertainties including:

~~"may,"~~adverse ~~"could,"~~decisions ~~"project,"~~in ~~"believe,"~~proceedings ~~"anticipate,"~~before ~~"estimate,"~~the ~~"plan,"~~Commission ~~"forecast,"~~concerning ~~"will~~the ~~be"~~prudence ~~and~~review ~~similar~~of ~~words identify forward-looking statements. Actual results could differ materially, because~~ the ~~realization~~utility ofsubsidiaries' ~~those~~gas ~~results~~purchases; ~~is subject to many uncertainties including:~~
~~Adverse decisions in proceedings before~~ the ~~Commission~~effects ~~concerning the prudence review~~ of the ~~utility subsidiaries~~Company's ~~gas~~announced ~~purchases~~strategic reorganization;
the future health of the United States and Illinois economies;
the timing and extent of changes in interest rates and energy commodity prices, including but not limited to the effect of ~~unusually high~~ gas prices on cost of gas supplies, accounts receivable and the provision for uncollectible accounts and interest expense;
adverse resolution of material litigation;
business and competitive conditions resulting from deregulation and consolidation of the energy industry;
effectiveness of the Company's risk management policies and the creditworthiness of customers and counterparties;
regulatory developments in the United States, Illinois and other states where the Company does business;
changes in the nature of the Company's competition resulting from industry consolidation, legislative change, regulatory change and other factors, as well as action taken by particular competitors;
the Company's success in identifying diversified business segment projects on financially acceptable terms and generating earnings from projects in a reasonable time;
operational factors affecting the Company's Gas Distribution, ~~Power Generation and~~ Oil and Gas Production and Power Generation segments;
Aquila's financial ability to perform under its power sales ~~tolling~~ agreements with Elwood;
drilling risks and the inherent uncertainty of oil and gas reserve estimates;

~~weather related energy demand; and~~42

weather and price effects on energy demand; and
terrorist activities.

Some of these uncertainties that may affect future results are discussed in more detail in Item 1 - Business and Item 7 - MD&A, in the combined Annual Report on Form 10-K most recently filed with the SEC by the Company, Peoples Gas and North Shore Gas. All forward-looking statements included in this MD&A are based upon information presently available, and the Company, Peoples Gas and North Shore Gas assume no obligation to update any forward-looking statements.

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

Quantitative and qualitative disclosures about market risk are reported inunder ~~Item~~Note 2. ~~MD&A~~of -the ~~Risk~~Notes ~~Management~~to ~~Activities~~Consolidated Financial Statements.

44
ITEM 4. Controls and Procedures

The Company, Peoples Gas and North Shore Gas maintain disclosure controls and procedures (as defined in Rule 13a-1415e of the Securities Exchange Act of 1934, as amended) which are designed to ensure that information required to be disclosed by the Company, Peoples Gas and North Shore Gas in the reports that are submitted or filed with the ~~Commission~~SEC is recorded, processed, summarized and reported within the time periods specified in the ~~Commission~~SEC's rules and forms. Thomas M. Patrick, principal executive officer and Thomas A. Nardi, principal financial officer of the Company, Peoples Gas and North Shore Gas, have evaluated the disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, Messrs. Patrick and Nardi have concluded that the disclosure controls and procedures are effective.

~~There~~During ~~was~~the noperiod ~~change~~covered inby ~~the~~this ~~Company's~~report, ~~Peoples~~there ~~Gas'~~was orno ~~North~~change ~~Shore~~in ~~Gas~~the companies' internal control over financial reporting ~~that~~identified ~~occurred~~in ~~during~~connection with the ~~last~~evaluation ~~fiscal~~of ~~quarter~~the disclosure controls and procedures that has materially affected, or is reasonably likely to materially affect, ~~any~~the ~~such company~~companies's internal control over financial reporting.

Part II - Other Information

Item 1. Legal Proceedings

See Note 5 of the Notes to Consolidated Financial Statements - Environmental Matters for a discussion pertaining to environmental matters and Note 6 of the Notes to Consolidated Financial Statements - Gas Charge Reconciliation Proceedings and Other Matters pertaining to proceedings at the Commission regarding the prudency of gas purchases by Peoples Gas and North Shore Gas, which notes are incorporated herein by reference.

Item 2. Changes in Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

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

None.

Item 5. Other Information

None.

Item 6. Exhibits and Reports on Form 8-K

Peoples Energy Corporation
:

a. Exhibits

Exhibit

Number

Description of Document

10(a)

Directors Deferred Compensation Plan, as amended April 7, 2004.

10(b)

Amendment No. 3 to FTS Service Agreement, Contract No. 113418 between Natural Gas Pipeline Company of America and Peoples Gas, dated February 18, 2004.

10(c)

FTS Service Agreement, Contract No. 130626 between Natural Gas Pipeline Company of America and Peoples Gas, dated February 18, 2004.

10(d)

FTS Service Agreement, Contract No. 130628 between Natural Gas Pipeline Company of America and Peoples Gas, dated February 18, 2004.

10(e)

Amendment No. 4 to DSS Storage Agreement, Contract No. 117164 between Natural Gas Pipeline Company of America and North Shore Gas, dated February 17, 2004.

10(f)

Amendment No. 2 to FTS Service Agreement, Contract No. 117117 between Natural Gas Pipeline Company of America and North Shore Gas, dated February 18, 2004.

			10(g)		Amendment No. 3 to FTS Service Agreement, Contract No. 113421 between Natural Gas Pipeline Company of America and North Shore Gas, dated February 18, 2004.
			10(h)		FTS Service Agreement, Contract No. 130625 between Natural Gas Pipeline Company of America and North Shore Gas, dated February 18, 2004.
			10(i)		FTS Service Agreement, Contract No. 130629 between Natural Gas Pipeline Company of America and North Shore Gas, dated February 18, 2004.
			12		Statement re: Computation of Ratio of Earnings to Fixed Charges for the Company
			31(a)		Certification of Thomas M. Patrick on behalf of the Company pursuant to 17 CFR 240.13a-14(a) or 17 CFR 240.15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
			31(b)		Certification of Thomas A. Nardi on behalf of the Company pursuant to 17 CFR 240.13a-14(a) or 17 CFR 240.15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
			32(a)		Certification of Thomas M. Patrick on behalf of the Company, Peoples Gas and North Shore Gas pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
			32(b)		Certification of Thomas A. Nardi on behalf of the Company, Peoples Gas and North Shore Gas 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 filed or furnished during the quarter ended June 30, 2004
			Date of Report - April 14, 2004
			Item 5 - Other Events
			Item 12 - Disclosure of Results of Operations and Financial Condition
			Analyst Presentation

			Date of Report - April 23, 2004
			Item 9 - Regulation FD Disclosure
			Item 12 - Disclosure of Results of Operations and Financial Condition
			Press Release

			Date of Report - April 29, 2004
			Item 5 - Other Events
			Conference Call Script and Forward-Looking Information

			Date of Report - April 30, 2004
			Item 9 - Regulation FD Disclosure
			Item 12 - Disclosure of Results of Operations and Financial Condition
			Analyst Presentation

PART II. OTHER INFORMATION

The Peoples Gas Light and Coke Company :

	a. Exhibits

		Exhibit
		Number	Description of Document
		10(b)	Amendment No. 3 to FTS Service Agreement, Contract No. 113418 between Natural Gas Pipeline Company of America and Peoples Gas, dated February 18, 2004.
		10(c)	FTS Service Agreement, Contract No. 130626 between Natural Gas Pipeline Company of America and Peoples Gas, dated February 18, 2004.
		10(d)	FTS Service Agreement, Contract No. 130628 between Natural Gas Pipeline Company of America and Peoples Gas, dated February 18, 2004.
		31(a)	Certification of Thomas M. Patrick on behalf of Peoples Gas pursuant to 17 CFR 240.13a-14(a) or 17 CFR 240.15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
		31(b)	Certification of Thomas A. Nardi on behalf of Peoples Gas pursuant to 17 CFR 240.13a-14(a) or 17 CFR 240.15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
		32(a)	Certification of Thomas M. Patrick on behalf of the Company, Peoples Gas and North Shore Gas pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
		32(b)	Certification of Thomas A. Nardi on behalf of the Company, Peoples Gas and North Shore Gas pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

~~Item 1~~b. ~~Legal~~Reports ~~Proceedings~~on ~~See~~Form ~~Note 4 of the Notes to Consolidated Financial Statements for a discussion pertaining to environmental matters and Note 1 of the Notes to Consolidated Financial Statements~~ 8-K ~~Recovery~~filed ofduring ~~Gas Costs pertaining to proceeding at~~ the ~~Commission~~quarter ~~regarding~~ended ~~the~~June ~~prudency of gas purchases by Peoples Gas and North Shore Gas. Item 2. Changes in Securities and Use of Proceeds On May 1~~30, ~~2003,~~2004 under the Directors Stock and Option Plan, the Company issued to each of the nonemployee directors of the Company 1,000 deferred shares of common stock, for a total of 9,000 deferred shares. Deferred shares are issued to nonemployee directors as part of their annual retainer. These securities are exempt from registration under the Securities Act of 1933, as amended, pursuant to Section 4(2) thereof. Deferred shares are automatically deferred until the earliest of (i) the director's retirement from the Company's Board of Directors following attaining the age of 70, (ii) one year after the director ceases to be a director of the Company for any other reason, and (iii) a change of control of the Company, and are not delivered by the Company until such date. Directors may elect to defer receipt of common stock in whole or in part for a period of time after the date on which distribution would otherwise occur by making an election to receive shares of common stock in installments no later than the calendar year prior to the year in which the distribution would otherwise occur. The director is entitled to receive amounts representing dividends from deferred shares equal to dividends paid with respect to a like number of shares of common stock of the Company. Each director can make an election from time to time as to whether to receive dividends in the form of cash payments or in the form of additional deferred shares. A bookkeeping account is maintained for each nonemployee director. Each grant of deferred shares is automatically deferred and credited to the account of the director. The account of a director who elects to receive dividends in the form of additional deferred shares is credited with a number of deferred shares determined by dividing the amount of the dividend by the mean price of a share of Company common stock on the New York Stock Exchange on the dividend payment date. Deferred shares do not entitle a director to vote on any matter to be considered by the Company's shareholders prior to the date of distribution of common stock and are generally not transferable other than upon a director's death. Item 3. Defaults Upon Senior Securities None. ~~Item 4. Submission of Matters to a Vote of Security Holders None. Item 5. Other Information None.~~

North Shore Gas Company :

	a. Exhibits

		Exhibit
		Number	Description of Document
		10(e)	Amendment No. 4 to DSS Storage Agreement, Contract No. 117164 between Natural Gas Pipeline Company of America and North Shore Gas, dated February 17, 2004.
		10(f)	Amendment No. 2 to FTS Service Agreement, Contract No. 117117 between Natural Gas Pipeline Company of America and North Shore Gas, dated February 18, 2004.

Item 6. Exhibits and Reports on Form 8-K
			10(g)		Amendment No. 3 to FTS Service Agreement, Contract No. 113421 between Natural Gas Pipeline Company of America and North Shore Gas, dated February 18, 2004.
	Peoples Energy Corporation:
			10(h)		FTS Service Agreement, Contract No. 130625 between Natural Gas Pipeline Company of America and North Shore Gas, dated February 18, 2004.
			a. Exhibits
			10(i)		FTS Service Agreement, Contract No. 130629 between Natural Gas Pipeline Company of America and North Shore Gas, dated February 18, 2004.
				Exhibit
			31(a)		Certification of Thomas M. Patrick on behalf of North Shore Gas pursuant to 17 CFR 240.13a-14(a) or 17 CFR 240.15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
				Number		Description of Document
			31(b)		Certification of Thomas A. Nardi on behalf of North Shore Gas pursuant to 17 CFR 240.13a-14(a) or 17 CFR 240.15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
				3(a)		Amendment to the By-Laws of the Registrant dated April 2, 2003 and June 4, 2003
			32(a)		Certification of Thomas M. Patrick on behalf of the Company, Peoples Gas and North Shore Gas pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
				3(b)		By-Laws of the Registrant, as amended, dated April 2, 2003.
			32(b)		Certification of Thomas A. Nardi on behalf of the Company, Peoples Gas and North Shore Gas pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
				3(c)		By-Laws of the Registrant, as amended, dated June 4, 2003.
		b. Reports on Form 8-K filed during the quarter ended June 30, 2004
				10(a)		Amendment No. 00004 to EFT Transportation Agreement No. 016774 between Panhandle Eastern Pipe Line Company and Peoples Gas, dated April 1, 2003.
			None.
				10(b)		Amendment No. 00004 to EFT Transportation Agreement No. 016775 between Panhandle Eastern Pipe Line Company and Peoples Gas, dated April 1, 2003.

			10(c)		FSS Storage Agreement No. 018110 between Panhandle Eastern Pipe Line Company and Peoples Gas, dated April 1, 2003.
			10(d)		EFT Agreement No. 017633 between CMS Trunkline Gas Company, LLC and Peoples Gas, effective December 1, 2003.
			10(e)		EFT Agreement No. 017634 between CMS Trunkline Gas Company, LLC and Peoples Gas, effective December 1, 2003.
			10(f)		ETS Service Agreement No. 109011 between ANR Pipeline Company and Peoples Gas, dated March 19, 2003.
			10(g)		FSS Service Agreement No. 109012 between ANR Pipeline Company and Peoples Gas, dated March 19, 2003.
			10(h)		NNS Service Agreement No. 109013 between ANR Pipeline Company and Peoples Gas, dated March 19, 2003.
			10(i)		ETS Service Agreement No. 109014 between ANR Pipeline Company and Peoples Gas, dated March 20, 2003.
			10(j)		FSS Service Agreement No. 109015 between ANR Pipeline Company and Peoples Gas, dated March 20, 2003.
			10(k)		NNS Service Agreement No. 109016 between ANR Pipeline Company and Peoples Gas, dated March 20, 2003.
			10(l)		FTS-1 Service Agreement No. 109030 between ANR Pipeline Company and Peoples Gas, dated March 21, 2003.

		10(m)	FSS Service Agreement No. 109018 between ANR Pipeline Company and North Shore Gas, dated March 20, 2003.
SIGNATURE
		10(n)	FTS-1 Service Agreement No. 109019 between ANR Pipeline Company and North Shore Gas, dated March 20, 2003.
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
		10(o)	NNS Service Agreement No. 109020 between ANR Pipeline Company and North Shore Gas, dated March 20, 2003.
	Peoples Energy Corporation
		10(p)	FTS-1 Service Agreement No. 109021 between ANR Pipeline Company and North Shore Gas, dated March 20, 2003.
	(Registrant)
		10(q)	FTS-1 Service Agreement No. 109022 between ANR Pipeline Company and North Shore Gas, dated March 20, 2003.
August 10, 2004	By: /s/ THOMAS A. NARDI
		10(r)	FTS-1 Service Agreement No. 109023 between ANR Pipeline Company and North Shore Gas, dated March 20, 2003.
(Date)	Thomas A. Nardi
		10(s)	FTS-1 Service Agreement No. 109024 between ANR Pipeline Company and North Shore Gas, dated March 20, 2003.
	Senior Vice President and Chief Financial Officer
		10(t)	FTS-1 Service Agreement No. 109025 between ANR Pipeline Company and North Shore Gas, dated March 20, 2003.
	(Same as above)
		10(u)	FTS-1 Service Agreement No. 109026 between ANR Pipeline Company and North Shore Gas, dated March 20, 2003.
	Principal Financial Officer
		12	Statement re: Computation of Ratio of Earnings to Fixed Charges for the Company
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
	The Peoples Gas Light and Coke Company
	(Registrant)
August 10, 2004	By: /s/ THOMAS A. NARDI
(Date)	Thomas. A. Nardi
	Senior Vice President and Chief Financial Officer
	(Same as above)
	Principal Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
	North Shore Gas Company
	(Registrant)
August 10, 2004	By: /s/ THOMAS A. NARDI
(Date)	Thomas. A. Nardi
	Senior Vice President and Chief Financial Officer
	(Same as above)
	Principal Financial Officer

			31(a)		Certification of Thomas M. Patrick on behalf of the Company pursuant to 17 CFR 240.13a-14(a) or 17 CFR 240.15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
			31(b)		Certification of Thomas A. Nardi on behalf of the Company pursuant to 17 CFR 240.13a-14(a) or 17 CFR 240.15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
			32(a)		Certification of Thomas M. Patrick on behalf of the Company, Peoples Gas and North Shore Gas pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
			32(b)		Certification of Thomas A. Nardi on behalf of the Company, Peoples Gas and North Shore Gas 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 filed or furnished during the quarter ended June 30, 2003
			Date of Report - April 7, 2003
			Item 5 - Other Events
			Moody's Ratings Downgrade of Aquila

Date of Report - April 22, 2003 Item 5 - Other Events Regulation G Amendment Date of Report - April 25, 2003 Item 9 - Regulation FD Disclosure Item 12 - Disclosure of Results of Operations and Financial Condition Press Release Date of Report - April 29, 2003 Item 9 - Regulation FD Disclosure Item 12 - Disclosure of Results of Operations and Financial Condition Conference Call Script Date of Report - May 1, 2003 Item 5 - Other Events Forward Looking Financial Information Date of Report - May 2, 2003 Item 5 - Other Events AGA Presentation Date of Report - May 2, 2003 Item 9 - Regulation FD Disclosure Forward Looking Financial Information

The Peoples Gas Light and Coke Company:
	a. Exhibits
		Exhibit
		Number	Description of Document
		10(a)	Amendment No. 00004 to EFT Transportation Agreement No. 016774 between Panhandle Eastern Pipe Line Company and Peoples Gas, dated April 1, 2003.
		10(b)	Amendment No. 00004 to EFT Transportation Agreement No. 016775 between Panhandle Eastern Pipe Line Company and Peoples Gas, dated April 1, 2003.
		10(c)	FSS Storage Agreement No. 018110 between Panhandle Eastern Pipe Line Company and Peoples Gas, dated April 1, 2003.
		10(d)	EFT Agreement No. 017633 between CMS Trunkline Gas Company, LLC and Peoples Gas, effective December 1, 2003.
		10(e)	EFT Agreement No. 017634 between CMS Trunkline Gas Company, LLC and Peoples Gas, effective December 1, 2003.
		10(f)	ETS Service Agreement No. 109011 between ANR Pipeline Company and Peoples Gas, dated March 19, 2003.

			10(g)		FSS Service Agreement No. 109012 between ANR Pipeline Company and Peoples Gas, dated March 19, 2003.
			10(h)		NNS Service Agreement No. 109013 between ANR Pipeline Company and Peoples Gas, dated March 19, 2003.
			10(i)		ETS Service Agreement No. 109014 between ANR Pipeline Company and Peoples Gas, dated March 20, 2003.
			10(j)		FSS Service Agreement No. 109015 between ANR Pipeline Company and Peoples Gas, dated March 20, 2003.
			10(k)		NNS Service Agreement No. 109016 between ANR Pipeline Company and Peoples Gas, dated March 20, 2003.
			10(l)		FTS-1 Service Agreement No. 109030 between ANR Pipeline Company and Peoples Gas, dated March 21, 2003.
			31(a)		Certification of Thomas M. Patrick on behalf of Peoples Gas pursuant to 17 CFR 240.13a-14(a) or 17 CFR 240.15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
			31(b)		Certification of Thomas A. Nardi on behalf of Peoples Gas pursuant to 17 CFR 240.13a-14(a) or 17 CFR 240.15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
			32(a)		Certification of Thomas M. Patrick on behalf of the Company, Peoples Gas and North Shore Gas pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
			32(b)		Certification of Thomas A. Nardi on behalf of the Company, Peoples Gas and North Shore Gas 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 filed during the quarter ended June 30, 2003
			Date of Report - April 22, 2003
			Item 5 - Other Events
			Regulation G Amendment

North Shore Gas Company:
	a. Exhibits
		Exhibit
		Number	Description of Document
		10(m)	FSS Service Agreement No. 109018 between ANR Pipeline Company and North Shore Gas, dated March 20, 2003.

			10(n)		FTS-1 Service Agreement No. 109019 between ANR Pipeline Company and North Shore Gas, dated March 20, 2003.
			10(o)		NNS Service Agreement No. 109020 between ANR Pipeline Company and North Shore Gas, dated March 20, 2003.
			10(p)		FTS-1 Service Agreement No. 109021 between ANR Pipeline Company and North Shore Gas, dated March 20, 2003.
			10(q)		FTS-1 Service Agreement No. 109022 between ANR Pipeline Company and North Shore Gas, dated March 20, 2003.
			10(r)		FTS-1 Service Agreement No. 109023 between ANR Pipeline Company and North Shore Gas, dated March 20, 2003.
			10(s)		FTS-1 Service Agreement No. 109024 between ANR Pipeline Company and North Shore Gas, dated March 20, 2003.
			10(t)		FTS-1 Service Agreement No. 109025 between ANR Pipeline Company and North Shore Gas, dated March 20, 2003.
			10(u)		FTS-1 Service Agreement No. 109026 between ANR Pipeline Company and North Shore Gas, dated March 20, 2003.

			31(a)		Certification of Thomas M. Patrick on behalf of North Shore Gas pursuant to 17 CFR 240.13a-14(a) or 17 CFR 240.15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
			31(b)		Certification of Thomas A. Nardi on behalf of North Shore Gas pursuant to 17 CFR 240.13a-14(a) or 17 CFR 240.15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
			32(a)		Certification of Thomas M. Patrick on behalf of the Company, Peoples Gas and North Shore Gas pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
			32(b)		Certification of Thomas A. Nardi on behalf of the Company, Peoples Gas and North Shore Gas 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 filed during the quarter ended June 30, 2003
			Date of Report - April 22, 2003
			Item 5 - Other Events
			Regulation G Amendment

SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
		Peoples Energy Corporation
		(Registrant)
August 13, 2003		By: /s/ THOMAS A. NARDI
(Date)		Thomas A. Nardi
		Senior Vice President, Chief Financial Officer and Treasurer
		(Same as above)
		Principal Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
		The Peoples Gas Light and Coke Company
		(Registrant)
August 13, 2003		By: /s/ THOMAS A. NARDI
(Date)		Thomas. A. Nardi
		Senior Vice President, Chief Financial Officer and Treasurer
		(Same as above)
		Principal Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
		North Shore Gas Company
		(Registrant)
August 13, 2003		By: /s/ THOMAS A. NARDI
(Date)		Thomas. A. Nardi
		Senior Vice President, Chief Financial Officer and Treasurer
		(Same as above)
		Principal Financial Officer

	Total
	Accounts		Past Due
	Receivable	Current	30-89 Days	90-149 Days	Over 150 Days
	(Dollars in Millions)
June 30, 2003	$236.0	$74.5	$75.7	$48.3	$37.5
Percentage	100	32	32	20	16
September 30, 2002	$152.4	$53.2	$21.7	$19.0	$58.5
Percentage	100	35	14	13	38
June 30, 2002	$211.3	$68.8	$51.4	$30.1	$61.0
Percentage	100	33	24	14	29
June 30, 2001	$405.1	$92.1	$116.1	$130.5	$66.4
Percentage	100	23	29	32	16

	Commitments Due by Period
	Total
(In Millions)	Amounts	Less than	1 to 3	4 to 5	More than
Other commercial commitments	Committed	1 Year	Years	Years	5 Years
Standby letters of credit	$ 6.0	$ 3.9	$ -	$ 0.1	$ 2.0
Guarantees of unconsolidated equity investees	50.4	-	12.5	-	37.9
Total other commercial commitments	$ 56.4	$ 3.9	$ 12.5	$ 0.1	$ 39.9

		As of June 30,
		2003
		(In Millions)
Guarantees of unconsolidated equity investees
Elwood	- Debt service reserve account	$ 8.9
	- Operational	22.5
Trigen-Peoples	- Operational	19.0
Total guarantees of unconsolidated equity investees		$50.4

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