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, 2005
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
File Number	Office and Telephone Number		Identification Number
1-5540	PEOPLES ENERGY CORPORATION		36-2642766
2-26983	THE PEOPLES GAS LIGHT AND COKE COMPANY		36-1613900
2-35965	NORTH SHORE GAS COMPANY		36-1558720

	(Illinois Corporations)
	130 East Randolph Drive, 24^th 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 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 [ ]

Indicate by a check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Peoples Energy Corporation		Yes [x] No [ ]
The Peoples Gas Light and Coke Company		Yes [ ] No [x]
North Shore Gas Company		Yes [ ] No [x]

Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date (July 29, 2005):

Peoples Energy Corporation	Common Stock, no par value, 38,139,661 shares outstanding

The Peoples Gas Light and Coke Company	Common Stock, no 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, no 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.

Part I - Financial Information

Item I. Financial Statements

Peoples Energy Corporation
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)


	Three Months Ended		Nine Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
(In Thousands, Except Per-Share Amounts)
Revenues	$ 455,931	$ 401,137	$ 2,220,248	$ 1,933,042

Operating Expenses:
Cost of energy sold	303,886	247,146	1,540,493	1,260,197
Operation and maintenance, excluding
restructuring and environmental costs	73,580	80,687	243,621	254,964
Restructuring costs	52	-	13,216	-
Environmental costs	4,599	3,052	27,727	15,142
Depreciation, depletion and amortization	24,039	29,749	83,348	89,641
Taxes, other than income taxes	31,669	29,761	160,541	148,508
Losses (gains) on property sales	(960)	(1,476)	(745)	(1,476)
Total Operating Expenses	436,865	388,919	2,068,201	1,766,976

Equity investment income	4,053	4,866	8,229	6,110

Operating Income	23,119	17,084	160,276	172,176

Other income and expense - net	1,681	918	3,560	2,299

Interest expense	12,586	11,758	37,940	36,420

Income Before Income Taxes	12,214	6,244	125,896	138,055

Income tax expense	5,415	621	45,449	46,178


Net Income	$ 6,799	$ 5,623	$ 80,447	$ 91,877

Average Shares of Common Stock Outstanding
Basic	38,030	37,549	37,926	37,212
Diluted	38,185	37,722	38,091	37,393

Earnings Per Share of Common Stock
Basic	$ 0.18	$ 0.15	$ 2.12	$ 2.47
Diluted	$ 0.18	$ 0.15	$ 2.11	$ 2.46

Dividends Declared Per Share	$ 0.545	$ 0.540	$ 1.630	$ 1.610

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

- 2 -

Peoples Energy Corporation

CONSOLIDATED BALANCE SHEETS
(Unaudited)

	June 30,	September 30,	June 30,
(In Thousands)	2005	2004	2004
ASSETS
CAPITAL INVESTMENTS:
Property, plant and equipment
Utility plant	$ 2,655,328	$ 2,615,002	$ 2,600,526
Oil and gas	539,924	488,275	473,067
Other	21,823	21,010	20,450
Total property, plant and equipment	3,217,075	3,124,287	3,094,043
Less - Accumulated depreciation, depletion and amortization	1,288,203	1,220,102	1,201,012
Net property, plant and equipment	1,928,872	1,904,185	1,893,031
Investment in equity investees	115,901	135,819	130,950
Other investments	23,968	23,921	23,847
Total Capital Investments - Net	2,068,741	2,063,925	2,047,828

CURRENT ASSETS:
Cash and cash equivalents	64,439	7,228	71,900
Short-term investments	35,625	-	4,000
Deposits with broker or trustee	17,499	13,891	15,493
Receivables -
Customers, net of reserve for uncollectible accounts
of $36,898, $29,138, and $31,267, respectively	288,963	190,379	271,636
Other	18,953	55,769	27,691
Materials and supplies, at average cost	10,290	10,444	10,083
Gas in storage	126,397	191,052	98,010
Gas costs recoverable through rate adjustments	3,767	20,612	21,878
Regulatory assets of utility subsidiaries	24,691	37,076	26,307
Other	19,255	25,910	14,701
Total Current Assets	609,879	552,361	561,699

OTHER ASSETS:
Prepaid pension costs	184,386	176,329	184,059
Noncurrent regulatory assets of utility subsidiaries	287,935	228,186	187,261
Deferred charges and other	51,079	73,989	74,143
Total Other Assets	523,400	478,504	445,463

Total Assets	$ 3,202,020	$ 3,094,790	$ 3,054,990

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

- 3 -

Peoples Energy Corporation

CONSOLIDATED BALANCE SHEETS
(Unaudited)

	June 30,	September 30,	June 30,
(In Thousands, Except Shares)	2005	2004	2004
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stockholders' Equity:
Common stock, no par value -
Authorized 60,000,000 shares
Issued 38,341,662, 37,976,994 and
37,826,054 shares, respectively	$ 402,269	$ 387,845	$ 381,864
Treasury stock - 243,100 shares	(6,677)	(6,677)	(6,677)
Retained earnings	573,470	554,222	581,756
Accumulated other comprehensive income (loss)	(89,344)	(65,307)	(66,390)
Total Common Stockholders' Equity	879,718	870,083	890,553

Long-term debt, exclusive of maturities due within one
year and adjustable-rate bonds classified as short-term debt	897,114	897,377	846,330
Total Capitalization	1,776,832	1,767,460	1,736,883

CURRENT LIABILITIES:
Commercial paper	15,200	55,625	-
Adjustable-rate bonds classified as short-term debt	-	-	50,000
Accounts payable	163,539	144,709	187,356
Accrued taxes	65,399	26,056	51,726
Other accrued liabilities	157,627	164,039	119,611
Regulatory liabilities of utility subsidiaries	5,705	33,575	17,502
Dividends payable	20,764	20,367	20,293
Customer deposits	30,103	27,833	28,619
Customer credit balances	26,259	52,576	26,820
Gas costs refundable through rate adjustments	2,303	29	29
Accrued interest	15,604	11,307	14,717
Temporary LIFO liquidation credit	68,563	-	50,539
Total Current Liabilities	571,066	536,116	567,212

DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes	399,691	423,356	401,829
Investment tax credits	26,131	26,597	26,818
Environmental, pension and other	428,300	341,261	322,248
Total Deferred Credits and Other Liabilities	854,122	791,214	750,895

Total Capitalization and Liabilities	$ 3,202,020	$ 3,094,790	$ 3,054,990

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

- 4 -

Peoples Energy Corporation
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Nine Months Ended
	June 30,
(In Thousands)	2005	2004
Operating Activities:
Net income	$ 80,447	$ 91,877
Adjustments to reconcile net income to cash provided by operations:
Depreciation, depletion and amortization	87,594	93,765
Deferred income taxes and investment tax credits - net	17,921	9,106
Change in environmental, pension and other liabilities	(6,817)	6,475
Change in undistributed earnings from equity investments	11,613	(383)
Other changes in noncurrent operating activities	(15,202)	(24,328)
Changes in current assets and liabilities:
Receivables - net	(61,768)	(77,390)
Gas in storage	64,655	67,573
Gas costs recoverable/refundable through rate adjustments	19,119	(4,223)
Net regulatory assets/liabilities of utility subsidiaries	(15,485)	18,474
Accounts payable	17,979	24,234
Other accrued liabilities	(6,412)	21,179
Accrued taxes	39,342	5,996
Temporary LIFO liquidation credit	68,563	50,539
Other	(15,652)	(20,728)
Net Cash Provided by Operating Activities	285,897	262,166

Investing Activities:
Capital spending	(113,371)	(144,855)
Return of capital investments	8,713	11,576
Short-term investments	(35,625)	6,400
Other	(3,431)	3,795
Proceeds from sale of assets	1,191	1,250
Net Cash Used in Investing Activities	(142,523)	(121,834)

Financing Activities:
Proceeds from overdrafts	3,563	14,045
Retirement of commercial paper	(40,425)	(55,949)
Retirement of short-term debt	-	(102,000)
Issuance of long-term debt	48,047	172,547
Retirement of long-term debt	(50,263)	(76,515)
Issuance of common stock	14,424	35,402
Dividends paid on common stock	(61,509)	(59,210)
Net Cash Used in Financing Activities	(86,163)	(71,680)

Net Increase in Cash and Cash Equivalents	57,211	68,652
Cash and Cash Equivalents at Beginning of Period	7,228	3,248
Cash and Cash Equivalents at End of Period	$ 64,439	$ 71,900

Supplemental Information:
Income taxes paid	$ 20,726	$ 12,149
Interest paid	$ 32,495	$ 31,281

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

- 5 -

The Peoples Gas Light and Coke Company
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)


	Three Months Ended		Nine Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
(In Thousands)
Revenues	$ 219,275	$ 202,279	$ 1,285,612	$ 1,150,188

Operating Expenses:
Gas costs	114,628	98,929	790,783	668,426
Operation and maintenance, excluding
restructuring and environmental costs	52,900	55,595	176,749	183,169
Restructuring costs	(172)	-	8,295	-
Environmental costs	4,161	2,933	26,105	14,066
Depreciation and amortization	11,414	15,694	42,073	46,055
Taxes, other than income taxes	25,266	23,237	135,249	124,716
Losses (gains) on property sales	41	(111)	163	(111)
Total Operating Expenses	208,238	196,277	1,179,417	1,036,321

Operating Income	11,037	6,002	106,195	113,867

Other income and expense - net	1,351	767	2,902	2,022

Interest expense	5,990	4,934	18,053	15,601

Income Before Income Taxes	6,398	1,835	91,044	100,288

Income tax expense (benefit)	2,451	(618)	34,189	36,774

Net Income	$ 3,947	$ 2,453	$ 56,855	$ 63,514


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

- 6 -

The Peoples Gas Light and Coke Company

CONSOLIDATED BALANCE SHEETS
(Unaudited)


	June 30,	September 30,	June 30,
	2005	2004	2004
(In Thousands)
ASSETS
CAPITAL INVESTMENTS:
Property, plant and equipment	$ 2,294,310	$ 2,258,516	$ 2,246,808
Less - Accumulated depreciation and amortization	934,718	901,938	894,146
Net property, plant and equipment	1,359,592	1,356,578	1,352,662
Other investments	1,588	1,776	2,012
Total Capital Investments - Net	1,361,180	1,358,354	1,354,674

CURRENT ASSETS:
Cash and cash equivalents	46,250	6	41,960
Short-term investments	19,875	-	4,000
Deposits with broker or trustee	-	-	772
Receivables -
Customers, net of reserve for uncollectible accounts
of $33,712, $26,536 and $27,423, respectively	177,897	109,506	166,752
Intercompany receivables	9,701	33,388	29,447
Other	42	1,193	34
Materials and supplies, at average cost	9,086	9,169	8,874
Gas in storage, at last-in, first-out cost	41,602	107,275	40,196
Gas costs recoverable through rate adjustments	3,559	17,950	18,082
Regulatory assets	21,855	34,522	24,372
Other	7,451	6,865	4,238
Total Current Assets	337,318	319,874	338,727

OTHER ASSETS:
Prepaid pension costs	180,052	175,279	176,122
Noncurrent regulatory assets	222,731	180,690	149,363
Deferred charges and other	36,093	52,161	48,546
Total Other Assets	438,876	408,130	374,031

Total Assets	$ 2,137,374	$ 2,086,358	$ 2,067,432

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

- 7 -

The Peoples Gas Light and Coke Company

CONSOLIDATED BALANCE SHEETS
(Unaudited)


	June 30,	September 30,	June 30,
	2005	2004	2004
(In Thousands, Except Shares)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stockholder's Equity:
Common stock, without par value -
Authorized 40,000,000 shares
Outstanding 24,817,566 shares	$ 165,307	$ 165,307	$ 165,307
Retained earnings	492,584	471,293	499,830
Accumulated other comprehensive income (loss)	(19,244)	(7,080)	(21,019)
Total Common Stockholder's Equity	638,647	629,520	644,118

Long-term debt, exclusive of maturities due within one
year and adjustable-rate bonds classified as short-term debt	502,000	502,000	452,000
Total Capitalization	1,140,647	1,131,520	1,096,118

CURRENT LIABILITIES:
Commercial paper	-	31,000	-
Other short-term debt	-	-	50,000
Accounts payable	79,921	70,222	91,457
Accrued taxes	48,854	22,544	58,209
Other accrued liabilities	69,819	70,439	50,163
Intercompany payables	11,001	36,676	17,805
Regulatory liabilities	4,475	27,923	14,758
Dividends payable	9,900	-	13,200
Customer deposits	27,697	25,692	26,546
Customer credit balances	21,069	43,831	21,741
Gas costs refundable through rate adjustments	908	29	29
Accrued interest	5,232	5,532	3,998
Temporary LIFO liquidation credit	48,731	-	36,227
Total Current Liabilities	327,607	333,888	384,133

DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes	364,357	376,745	355,862
Investment tax credits	23,306	23,735	23,892
Environmental, pension and other	281,457	220,470	207,427
Total Deferred Credits and Other Liabilities	669,120	620,950	587,181

Total Capitalization and Liabilities	$ 2,137,374	$ 2,086,358	$ 2,067,432

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

- 8 -

The Peoples Gas Light and Coke Company
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Nine Months Ended
	June 30,
	2005	2004
(In Thousands)
Operating Activities:
Net income	$ 56,855	$ 63,514
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization	45,669	49,607
Deferred income taxes and investment tax credits - net	(5,632)	(1,558)
Change in environmental, pension and other liabilities	14,407	8,394
Other changes in noncurrent operating activities	(1,302)	(1,538)
Changes in current assets and liabilities:
Receivables - net	(41,733)	(34,920)
Gas in storage	65,673	71,796
Gas costs recoverable/refundable through rate adjustments	15,270	4,260
Net regulatory assets/liabilities	(10,782)	13,609
Accounts payable	4,919	5,880
Other accrued liabilities	(26,295)	(27,145)
Accrued taxes	26,311	28,788
Temporary LIFO liquidation credit	48,731	36,227
Other	(23,379)	(18,227)
Net Cash Provided by Operating Activities	168,712	198,687

Investing Activities:
Capital spending	(48,819)	(46,249)
Short-term investments	(19,875)	(4,000)
Other	198	10,227
Net Cash Used in Investing Activities	(68,496)	(40,022)

Financing Activities:
Proceeds from overdrafts	4,781	2,168
Retirement of commercial paper	(31,000)	(55,949)
Retirement of short-term debt	-	(126,400)
Issuance of long-term debt	48,047	172,576
Retirement of long-term debt	(50,000)	(76,500)
Dividends paid on common stock	(25,800)	(32,600)
Net Cash Used in Financing Activities	(53,972)	(116,705)

Net Increase in Cash and Cash Equivalents	46,244	41,960
Cash and Cash Equivalents at Beginning of Period	6	-
Cash and Cash Equivalents at End of Period	$ 46,250	$ 41,960

Supplemental Information:
Income taxes paid	$ 21,512	$ 5,932
Interest paid	$ 17,153	$ 15,923

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

- 9 -

North Shore Gas Company
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)


	Three Months Ended		Nine Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
(In Thousands)
Revenues	$ 38,957	$ 33,678	$ 234,201	$ 198,825

Operating Expenses:
Gas costs	24,200	19,707	165,825	131,330
Operation and maintenance, excluding
restructuring and environmental costs	8,092	8,181	25,170	25,561
Restructuring costs	6	-	568	-
Environmental costs	438	119	1,622	1,076
Depreciation	816	1,784	4,266	5,386
Taxes, other than income taxes	2,804	2,840	14,449	13,735
Losses (gains) on property sales	-	(1,130)	-	(1,130)
Total Operating Expenses	36,356	31,501	211,900	175,958

Operating Income	2,601	2,177	22,301	22,867

Other income and expense - net	361	82	503	130

Interest expense	912	911	2,785	2,776

Income Before Income Taxes	2,050	1,348	20,019	20,221

Income tax expense	855	427	7,606	7,489

Net Income	$ 1,195	$ 921	$ 12,413	$ 12,732

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

- 10 -

North Shore Gas Company

CONSOLIDATED BALANCE SHEETS
(Unaudited)


	June 30,	September 30,	June 30,
	2005	2004	2004
(In Thousands)
ASSETS
CAPITAL INVESTMENTS:
Property, plant and equipment	$ 361,018	$ 356,486	$ 353,718
Less - Accumulated depreciation	145,113	141,346	140,625
Net property, plant and equipment	215,905	215,140	213,093

CURRENT ASSETS:
Cash and cash equivalents	15,635	2	20,747
Short-term investments	15,750	-	-
Deposits with broker or trustee	-	-	813
Receivables -
Customers, net of reserve for uncollectible
accounts of $1,533, $943 and $1,024, respectively	19,974	12,157	29,593
Intercompany receivables	1,900	20,629	4,529
Other	-	1,335	1,250
Materials and supplies, at average cost	1,204	1,275	1,209
Gas in storage, at last-in, first-out cost	5,495	14,921	5,856
Gas costs recoverable through rate adjustments	208	2,662	3,796
Regulatory assets	2,836	2,553	1,935
Other	572	1,458	517
Total Current Assets	63,574	56,992	70,245

OTHER ASSETS:
Prepaid pension costs	2,148	-	-
Noncurrent regulatory assets	65,204	47,496	37,898
Deferred charges and other	2,800	3,358	3,208
Total Other Assets	70,152	50,854	41,106

Total Assets	$ 349,631	$ 322,986	$ 324,444

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

- 11 -

North Shore Gas Company

CONSOLIDATED BALANCE SHEETS
(Unaudited)


	June 30,	September 30,	June 30,
	2005	2004	2004
(In Thousands, Except Shares)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stockholder's Equity:
Common stock, without par value -
Authorized 5,000,000 shares
Outstanding 3,625,887 shares	$ 24,757	$ 24,757	$ 24,757
Retained earnings	84,271	80,258	84,813
Accumulated other comprehensive income (loss)	(2,027)	(1,336)	(2,260)
Total Common Stockholder's Equity	107,001	103,679	107,310

Long-term debt, exclusive of maturities due within one year	69,250	69,330	69,330
Total Capitalization	176,251	173,009	176,640

CURRENT LIABILITIES:
Other short-term debt	-	3,810	-
Accounts payable	13,661	12,697	15,760
Accrued taxes	2,649	1,679	6,500
Other accrued liabilities	5,091	5,711	3,991
Intercompany payables	2,333	6,220	4,252
Regulatory liabilities	1,231	5,652	2,744
Dividends payable	2,600	-	2,500
Customer deposits	2,406	2,141	2,073
Customer credit balances	4,106	7,130	4,186
Gas costs refundable through rate adjustments	1,395	-	-
Accrued interest	452	1,270	440
Temporary LIFO liquidation credit	19,831	-	14,312
Total Current Liabilities	55,755	46,310	56,758

DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes	38,696	35,652	32,275
Investment tax credits	2,824	2,862	2,926
Environmental, pension and other	76,105	65,153	55,845
Total Deferred Credits and Other Liabilities	117,625	103,667	91,046

Total Capitalization and Liabilities	$ 349,631	$ 322,986	$ 324,444

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

- 12 -

North Shore Gas Company
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Nine Months Ended
	June 30,
	2005	2004
(In Thousands)
Operating Activities:
Net income	$ 12,413	$ 12,732
Adjustments to reconcile net income to cash provided by operations:
Depreciation	4,916	5,958
Deferred income taxes and investment tax credits - net	5,363	1,874
Change in environmental, pension and other liabilities	(3,815)	329
Other changes in noncurrent operating activities	(7,577)	973
Changes in current assets and liabilities:
Receivables - net	12,359	(17,016)
Gas in storage	9,426	3,586
Gas costs recoverable/refundable through rate adjustments	3,848	(8,484)
Net regulatory assets/liabilities	(4,704)	4,864
Accounts payables	1,028	2,289
Accrued other liabilities	(4,507)	(5,685)
Accrued taxes	970	6,185
Temporary LIFO liquidation credit	19,831	14,312
Other	(2,732)	(3,611)
Net Cash Provided by Operating Activities	46,819	18,306

Investing Activities:
Capital spending	(5,680)	(6,781)
Short-term investments	(15,750)	10,400
Decrease in deposits with broker or trustee	-	1,953
Proceeds from the sale of assets	-	1,250
Other	(2)	(42)
Net Cash Used in Investing Activities	(21,432)	6,780

Financing Activities:
Proceeds from (payment of) overdrafts	(64)	268
Retirement of short-term debt	(3,810)	-
Retirement of long-term debt	(80)	(15)
Dividends paid on common stock	(5,800)	(6,300)
Net Cash Used in Financing Activities	(9,754)	(6,047)

Net Increase in Cash and Cash Equivalents	15,633	19,039
Cash and Cash Equivalents at Beginning of Period	2	1,708
Cash and Cash Equivalents at End of Period	$ 15,635	$ 20,747

Supplemental Information:
Income taxes paid	$ 3,536	$ 254
Interest paid	$ 3,503	$ 3,436

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

- 13 -

Notes to Consolidated Financial Statements (Unaudited)

1: BASIS OF PRESENTATION

The condensed, unaudited financial 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 (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, 2004. 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 adjustments 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 price storage injections at the fiscal year average of the costs of natural gas supply purchased. Withdrawals from storage for the utilities are priced on the LIFO cost method. 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. Due to seasonality requirements, the Company expects interim reductions in LIFO layers to be replenished by the fiscal year end. The Retail Energy Services and Midstream Services segments account for gas in inventory primarily using the lower of average cost or market method. A small portion of gas in storage reported for Midstream Services represents the effects of fair value hedges accounted for in accordance with Statement of Financial Accounting Standards (SFAS) 133, "Accounting for Derivatives and Hedging Activities" (SFAS No. 133).

Stock Compensation Plans

The 2004 Incentive Compensation Plan (2004 Plan) is comprised of two sub-plans, the Long-Term Incentive Compensation Plan and the Short-Term Incentive Compensation Plan. The adoption of the 2004 Plan effectively replaced the Company's Long-Term Incentive Compensation Plan (superseded LTIC Plan) and Short-Term Incentive Compensation Plan. The 2004 Plan does not provide for the grant of stock options, but instead provides for the issuance of restricted stock, restricted stock units and performance shares. No expense has been accrued with respect to performance shares awarded under the 2004 Plan based upon current estimates of Company performance.

As allowed under SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure, an amendment of Financial Accounting Standards Board (FASB) Statement No. 123," the Company has chosen to continue accounting for stock-based compensation using the intrinsic value method under Accounting Principles Board Opinion No. 25. Therefore, no compensation cost has been recognized for nonqualified stock options (under the superseded LTIC Plan and 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 periods ended June 30, 2005

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Notes to Consolidated Financial Statements (Unaudited)

and 2004. There were 12,228 shares and 13,244 shares sold through the ESPP in the nine-month periods ended June 30, 2005 and 2004, respectively.

Stock-based employee compensation cost (income) 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, 2005 totaled $0.7 million and $2.0 million. For the three- and nine-month periods ended June 30, 2004 stock-based employee compensation was $0.1 million and $1.5 million, respectively. Had compensation cost for stock options and shares issued under the superseded LTIC Plan, DSOP and ESPP been determined consistent with SFAS No. 123, the effect on the Company's net income and earnings per share is shown in the following pro forma amounts:

	Three Months Ended		Nine Months Ended
	June 30,		June 30,
(In Thousands, Except Per-Share Amounts)	2005	2004	2005	2004
Net income as reported	$ 6,799	$ 5,623	$ 80,447	$ 91,877
Pro forma effects of LTIC, DSOP and ESPP
compensation expense under SFAS No. 123	16	17	32	29
Pro forma net income	$ 6,783	$ 5,606	$ 80,415	$ 91,848
Earnings per average common share:
Basic	$ 0.18	$ 0.15	$ 2.12	$ 2.47
Diluted	0.18	0.15	2.11	2.46
Pro forma basic	0.18	0.15	2.12	2.47
Pro forma diluted	0.18	0.15	2.11	2.46

For the three and nine months ended June 30, 2005 and 2004, all outstanding options were included in the computation of average shares outstanding used to calculate diluted earnings per share and pro forma diluted earnings per share.

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. As all outstanding options became fully vested as of December 31, 2003, the following assumptions relate only to activity in the first quarter of fiscal 2004. For pro forma presentation purposes, the effect of unvested options is only applicable to the nine months ended June 30, 2004.

	Nine Months Ended
	June 30, 2004

Expected volatility	25.90%
Dividend yield	5.1%
Risk-free interest rate	2.47%
Expected lives (years)	3
Weighted average fair value	$ 3.83

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 operations and investments. To manage this risk, the Company uses forward contracts and financial instruments, including commodity futures contracts, swaps and options. It is the policy of the Company to use these instruments solely for the purpose of managing risk and not for any speculative purpose. The Company accounts for derivative financial instruments pursuant to SFAS No. 133. Under the provisions of SFAS No. 133, all derivatives are recognized on the balance sheet at their fair value unless they qualify for the normal purchases and normal sales exception.

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Notes to Consolidated Financial Statements (Unaudited)

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 price changes in the marketplace. The Company has also used derivative instruments to reduce interest rate risk associated with debt refinancing activities. Additionally, the Company uses interest rate derivatives to adjust the portfolio composition of debt from floating-rate to fixed-rate debt. All these instruments are designated cash flow hedges, which allow for the effective portion of unrealized changes in value during the life of the hedge to be recorded in other comprehensive income. Realized gains and losses from cash flow hedges are recorded in the income statement in the same month the related physical sales and purchases and interest expense is recorded.

Cash flow hedge accounting is discontinued when it is no longer probable that the original forecasted transactions will occur. The carrying value of contracts which no longer qualify for hedge accounting are prospectively marked-to-market, with the change in value recorded in each reporting period in the income statement. If the original forecasted transactions are probable of not occurring, any amounts previously recorded in other comprehensive income are immediately recorded in the income statement. In the third quarter of fiscal 2005, the Company recognized a pretax loss of $52,000 in the income statement related to dedesignated oil hedges for which the forecasted transactions are probable of not occurring.

The following tables summarize selected information related to outstanding cash flow hedges included in the Consolidated Income Statements and Balance Sheets for the periods ended June 30, 2005 and 2004, respectively.

Periods ended June 30, 2005		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
at June 30, 2005 - three months ended	$ (659)	$ -	N/A	$ (659)
- nine months ended	$ (520)	$ -	N/A	$ (520)

After-tax gains (losses) resulting from discontinuance of
cash flow hedges
at June 30, 2005 - three months ended	$ (31)	$ -	N/A	$ (31)
- nine months ended	$ (31)	$ -	N/A	$ (31)

Accumulated other comprehensive income (loss) after-tax at
June 30, 2005	$ (62,478)	$ (513)	$ (4,846)	$ (67,837)
Portion of accumulated other comprehensive income (loss)
expected to be reclassified to earnings during the next
12 months based on prices at June 30, 2005	$ (36,174)	$ (66)	N/A	$ (36,240)
Maximum term	39 months	94 months

Periods ended June 30, 2004
(In Thousands)
Portion of after-tax gains (losses) on hedging instruments
determined to be ineffective and included in net income
at June 30, 2004 - three months ended	$ 46	$ -	N/A	$ 46
- nine months ended	$ 88	$ -	N/A	$ 88
Accumulated other comprehensive income (loss) after tax at
June 30, 2004	$ (37,707)	$ (579)	$ (4,159)	$ (42,445)

The maturities of the open cash flow hedges are summarized in the table below. Valuations are based on the New York Mercantile Exchange (NYMEX) closing prices for the respective NYMEX Henry Hub futures contracts and on the closing prices published in various commodity pricing publications for the geographical differential between a specific location price and the NYMEX Henry Hub futures contract closing price where applicable.

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Notes to Consolidated Financial Statements (Unaudited)

Cash Flow Hedges
Value by Year of Maturity

		Less than	1 to 2	2 to 3	3 to 4	4 to 5
(In Thousands)	Total	1 Year	Years	Years	Years	Years
Loss at June 30, 2005	$(105,750)	$(60,132)	$(35,591)	$ (9,221)	$ (806)	$ -
Loss at September 30, 2004	$ (89,306)	$(57,374)	$(26,628)	$ (5,253)	$ (51)	$ -
Gain (Loss) at June 30, 2004	$ (63,858)	$(39,899)	$(20,317)	$ (4,024)	$ 382	$ -

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 costs. 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 marked-to-market. SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation", allows for unrealized gains or losses on the derivative instruments 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 the market value of these outstanding instruments and other derivative instruments that do not qualify for hedge accounting and are recorded on a mark-to-market basis. All amounts are expected to be settled during the next 12 months.

	June 30,	September 30,	June 30,
(In Thousands)	2005	2004	2004
Peoples Gas mark-to-market asset (liability)	$ (590)	$ 22,768	$ 10,350
North Shore Gas mark-to-market asset	275	4,653	1,892
Other mark-to-market asset (liability)	(907)	257	128
Total	$ (1,222)	$ 27,678	$ 12,370

Fair Value Hedges.
The Company uses financial hedges to protect the value of a small portion of Midstream Services' gas in storage and these 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 each reporting period in the income statement. The Company also uses certain financial instruments to adjust the portfolio composition of its debt from fixed-rate to floating-rate debt. These derivative instruments are accounted for as fair value hedges. The change in value of these hedges along with the change in value of the debt hedged are recorded in each reporting period in the income statement.

Derivative Summary.
The following table summarizes the changes in valuation of all outstanding derivative contracts during the three and nine months ended June 30, 2005 and 2004. All amounts are based on fair values at the end of the period and do not necessarily indicate that a gain or loss on the derivative will be recognized in income in future periods. Generally hedges are held to maturity, which coincides with recognition of the transaction being hedged (e.g., anticipated sales or cost of purchases in income), thereby achieving the realization of prices contemplated by the underlying risk management strategies.

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Notes to Consolidated Financial Statements (Unaudited)

	Derivative Type
	Cash Flow		Fair Value
Fiscal Quarter	Hedges		Hedges		Mark-to-Market
(In Thousands)	2005	2004	2005	2004	2005	2004
Value of contracts outstanding at beginning of period	$ (120,980)	$ (56,689)	$ (1,005)	$ (146)	$ 22,016	$ 18,657
Loss on contracts discontinued as cash flow hedges	590				(590)
Less: Gain (loss) on contracts realized or otherwise
settled during the period	(12,596)	(9,558)	(130)	17	1,900	8,559
Plus: Unrealized gain (loss) on new contracts
entered into during the period and outstanding
at end of period	(24)	(147)	(4)	157	1,910	(847)
Plus: Other unrealized gain (loss), primarily changes
in market prices on contracts outstanding at the
beginning of the period	2,068	(16,580)	1,942	163	(22,658)	3,119
Value of contracts outstanding at June 30,	$ (105,750)	$ (63,858)	$ 1,063	$ 157	$ (1,222)	$ 12,370


	Derivative Type
	Cash Flow		Fair Value
Fiscal Year-to-Date	Hedges		Hedges		Mark-to-Market
(In Thousands)	2005	2004	2005	2004	2005	2004
Value of contracts outstanding at beginning of period	$ (89,306)	$ (23,791)	$ 908	$ (65)	$ 27,678	$ (13,538)
Loss on contracts discontinued as cash flow hedges	590				(590)
Less: Gain (loss) on contracts realized or otherwise
settled during the period	(34,731)	(15,752)	260	17	296	3,963
Plus: Unrealized gain (loss) on new contracts
entered into during the period and outstanding
at end of period	(6,068)	(25,026)	199	157	4,232	14,320
Plus: Other unrealized gain (loss), primarily changes
in market prices on contracts outstanding at the
beginning of the period	(45,697)	(30,793)	216	82	(32,246)	15,551
Value of contracts outstanding at June 30,	$ (105,750)	$ (63,858)	$ 1,063	$ 157	$ (1,222)	$ 12,370

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 in gross receivables from customers is summarized below.

	June 30,	September 30,	June 30,
(In Thousands)	2005	2004	2004
Peoples Gas	$ 25,018	$ 30,755	$ 15,516
North Shore Gas	4,338	5,322	3,666
Peoples Energy Services	13,949	13,829	15,701
Consolidated Peoples Energy	$ 43,305	$ 49,906	$ 34,883

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, whereby the billed amounts for the recovery of these taxes are included in revenues and an offsetting expense amount (net of an administrative fee), representing the expected cash payment of the

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Notes to Consolidated Financial Statements (Unaudited)

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)	2005	2004	2005	2004
Peoples Gas	$20,048	$ 18,997	$121,816	$ 112,855
North Shore Gas	1,882	1,711	11,885	10,969
Consolidated Peoples Energy	$21,930	$ 20,708	$133,701	$ 123,824

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.

Exploratory Drilling Costs

The Company's Oil and Gas Production segment identifies and tracks expenditures associated with exploratory drilling. The project costs of drilling exploratory wells are capitalized as part of the segment's property and equipment, pending determination of whether the well has found proved reserves. The success or failure of the exploration project dictates the appropriate accounting treatment of those capital expenditures. If an exploration well is successful, resulting in proved reserves, then the exploratory and associated costs are capitalized and become part of the segment's capitalized cost of wells and related equipment and facilities for depreciation, depletion and amortization (DD&A) purposes. If, however, the exploration well is not successful and has not resulted in proved reserves, the capitalized costs of drilling the well, net of any salvage value, are charged to expense. In accordance with the provisions of SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies" (SFAS No. 19), it is the Company's policy to make the final capitalization or expense determination of exploratory drilling costs upon completion of the drilling operations, but in no case later than one year thereafter. On April 4, 2005, the FASB issued FASB Staff Position No. 19-1, "Accounting for Suspended Well Costs" (FSP No. 19-1). Among other provisions, FSP No. 19-1 amends SFAS No. 19 with respect to the continued capitalization of exploratory well costs after the completion of drilling but prior to the determining whether the well has found proved reserves. The Company's adoption of FSP No. 19-1 in the third quarter of fiscal 2005 did not have a significant effect on the financial condition or results of operations of the Company.

At June 30, 2005, the Company did not have any exploratory pre-production wells requiring additional major capital expenditures (to determine presence of proved reserves) or any exploratory wells where more than one year had elapsed since the completion of drilling without a determination of well results.

At June 30, 2004, the Company had no capitalized exploratory well costs pending determination of proved reserves. A portion of exploration expense recognized in the third quarter of fiscal 2004 relates to the expensing of $2.7 million in costs previously capitalized.

Statement of Cash Flows

For purposes 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 $10.0 million, $6.5 million and $19.8 million as of June 30, 2005, September 30, 2004 and June 30, 2004, respectively. For Peoples Gas, the amounts in accounts payable at June 30, 2005, September 30, 2004 and June 30, 2004 were $9.7 million, $4.9 million and $7.7 million, respectively. North Shore Gas' amounts in accounts payable at June 30, 2005, September 30, 2004 and June 30, 2004 were immaterial.

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Notes to Consolidated Financial Statements (Unaudited)

Short-term investments at June 30, 2005, consist entirely of auction rate debt securities and are carried at cost, which approximates fair value. The Company records the related interest income in other income and expense-net on the Consolidated Statements of Income. These investments are classified as "available for sale" under the provisions of SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities". At June 30, 2005, available for sale investments had contractual maturity dates of July 5 through July 15, 2005.

Contingencies, Indemnities and Commitments

Contingent obligations, including indemnities, litigation and other possible commitments are accounted for in accordance with SFAS No. 5, "Accounting for Contingencies," which requires that an estimated loss be recorded if it is probable that an asset has been impaired or a liability has been incurred at the date of the financial statements and the amount of the loss can be reasonably estimated. Accordingly, those contingencies that are deemed to be probable and where the amount of loss is reasonably estimable are accrued in the financial statements. If only a range of loss can be determined, the best estimate within that range is accrued; if none of the estimates within that range is better than another, the low end of the range is accrued. Disclosure of a contingency is required if there is at least a reasonable possibility that a loss has been or will be incurred, even if the amount is not estimable. The assessment of contingencies is a highly subjective process that requires judgments about future events. Contingencies are reviewed at least quarterly to determine the adequacy of the accruals and related financial statement disclosure. The ultimate settlement of contingencies may differ materially from amounts accrued in the financial statements.

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Notes to Consolidated Financial Statements (Unaudited)

3: BUSINESS SEGMENTS

Total segment capital assets include net property, plant and equipment and certain intangible assets classified in other investments. Financial data by business segment is presented below.

					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, 2005
Revenues	$ 257,836	$ 25,416	$ -	$ 111,009	$ 69,160	$ -	$ (7,490)	$ 455,931
Cost of energy sold	138,829	-	-	107,927	65,035	-	(7,905)	303,886
Operation and maintenance	57,748	6,944	450	1,750	2,278	479	3,931	73,580
Restructuring charge	-	-	-	-	-	-	52	52
Environmental costs	4,599	-	-	-	-	-	-	4,599
Depreciation, depletion and amortization	12,230	10,969	-	111	443	35	251	24,039
Taxes, other than income taxes	28,069	2,720	25	53	102	38	662	31,669
Losses (gains) on property sales	41	(988)	-	(2)	-	(11)	-	(960)
Equity investment income	-	83	3,744	-	-	226	-	4,053
Operating income (loss)	16,320	5,854	3,269	1,170	1,302	(315)	(4,481)	23,119
Segment capital assets - net	1,575,713	341,019	11,312	5,730	4,833	1,110	4,400	1,944,117
Investments in equity investees	-	9,973	102,274	-	-	3,654	-	115,901
Capital spending	19,396	25,093	303	-	14	-	500	45,306
Three Months Ended June 30, 2004
Revenues	$ 234,611	$ 30,523	$ -	$ 83,506	$ 62,913	$ 36	$ (10,452)	$ 401,137
Cost of energy sold	118,636	-	-	80,907	58,480	8	(10,885)	247,146
Operation and maintenance	59,348	10,528	1,323	1,617	3,026	315	4,530	80,687
Environmental costs	3,052	-	-	-	-	-	-	3,052
Depreciation, depletion and amortization	17,478	11,550	32	112	452	4	121	29,749
Taxes, other than income taxes	26,078	2,879	41	35	122	10	596	29,761
Losses (gains) on property sales	(1,242)	(99)	-	-	-	(135)	-	(1,476)
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
Nine Months Ended June 30, 2005
Revenues	$ 1,514,433	$ 82,246	$ -	$ 365,342	$335,162	$ -	$ (76,935)	$2,220,248
Cost of energy sold	956,609	-	-	351,358	310,704	-	(78,178)	1,540,493
Operation and maintenance	195,499	21,549	1,458	5,242	9,172	1,363	9,338	243,621
Restructuring charge	-	-	-	-	-	-	13,216	13,216
Environmental costs	27,727	-	-	-	-	-	-	27,727
Depreciation, depletion and amortization	46,339	34,596	1	335	1,255	104	718	83,348
Taxes, other than income taxes	149,697	8,765	37	198	317	74	1,453	160,541
Losses (gains) on property sales	163	(988)	143	(2)	(50)	(11)	-	(745)
Equity investment income	-	1,298	6,175	-	-	756	-	8,229
Operating income (loss)	138,399	19,622	4,536	8,211	13,764	(774)	(23,482)	160,276
Segment capital assets - net	1,575,713	341,019	11,312	5,730	4,833	1,110	4,400	1,944,117
Investments in equity investees	-	9,973	102,274	-	-	3,654	-	115,901
Capital spending	54,499	56,675	939	8	144	400	706	113,371
Nine Months Ended June 30, 2004
Revenues	$ 1,344,010	$ 93,915	$ -	$ 257,860	$270,627	$ 290	$ (33,660)	$1,933,042
Cost of energy sold	799,756	-	-	245,257	249,989	94	(34,899)	1,260,197
Operation and maintenance	198,451	22,452	3,343	4,540	10,150	614	15,414	254,964
Environmental costs	15,142	-	-	-	-	-	-	15,142
Depreciation, depletion and amortization	51,441	36,093	95	336	1,326	12	338	89,641
Taxes, other than income taxes	138,453	7,301	100	85	360	1	2,208	148,508
Losses (gains) on property sales	(1,242)	(99)	-	-	-	(135)	-	(1,476)
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

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Notes to Consolidated Financial Statements (Unaudited)

4: RESTRUCTURING COSTS

During the fourth quarter of fiscal 2004, the Company commenced a restructuring plan to enhance operating efficiency and customer service and to help protect utility customers from the impact of rising operating costs, while maintaining solid financial results for the Company. The restructuring activities were designed to result in a reduction of over 100 nonunion permanent positions at all levels in the utility business and corporate support functions. An enhanced voluntary termination severance package was offered to nonunion employees including a termination allowance of three weeks' pay for each completed year of service up to a maximum of 52 weeks of pay, outplacement assistance, enhanced educational assistance, and reduced COBRA rates. Approximately 300 employees accepted the package, resulting in about 200 open positions, some of which have been filled in fiscal 2005 with the remainder expected to be filled in fiscal 2006.

The restructuring activities were substantially completed by September 30, 2004. The restructuring plan resulted in aggregate charges of $17.0 million to the Consolidated Statement of Income for fiscal 2004. Included in this amount were charges of $9.7 million and $0.9 million related to Peoples Gas and North Shore Gas, respectively, based primarily upon severance payments and related employer payroll taxes at each respective utility.

A total of approximately $2.4 million and $14.9 million for the third quarter and fiscal year-to-date through June 30, 2005, respectively, has been paid for severance payments, program expenses, employer taxes and legal fees. In addition, approximately $0.4 million in severance costs originally expensed was reversed in connection with the revocation of severance agreements. The Company has approximately $1.8 million of unpaid liabilities related to the restructuring costs included in accounts payable on the Consolidated Balance Sheet at June 30, 2005.

In the third quarter and year-to-date for fiscal 2005, the Company recorded $0.1 million and $13.2 million, respectively for pension benefits, net of capitalized amounts, associated with the restructuring plan described above. Minimal additional amounts are expected for the fourth quarter.

5: EQUITY INVESTMENTS

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 separate financial statement disclosure. However, in aggregate these investments are material. The Company records its share of equity investment income 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)	2005	2004	2005	2004
Revenues	$ 46,570	$ 43,264	$ 112,985	$ 45,652
Operating income	22,246	20,303	53,855	23,771
Interest expense	9,264	10,001	28,112	17,335
Net income	4,645	8,984	16,655	9,154

Current assets	67,821	61,589	67,821	61,589
Noncurrent assets	708,353	760,775	708,353	760,775
Current liabilities	76,256	55,438	76,256	55,438
Noncurrent liabilities	430,281	453,224	430,281	453,224

- 22 -

Notes to Consolidated Financial Statements (Unaudited)

The following table summarizes the Company's equity method investment ownership percentage and its equity share of the net income shown in the previous table.

		Ownership Percentage						Equity Investment Income (Loss)
								Three Months Ended		Nine Months Ended
(Dollars in Thousands)		At June 30,						June 30,		June 30,
Investment	Segment	2005			2004			2005	2004	2005	2004
EnerVest	Oil and Gas		30	%		30	%	$ 83	$ 1,725	$ 1,298	$ 3,119
Elwood	Power		50			50		2,400	1,672	2,085	(1,729)
SCEP	Power		28			27		1,344	1,419	4,090	4,313
Trigen-Peoples	Other		50			50		226	50	756	407

Total equity investment income								$ 4,053	$ 4,866	$ 8,229	$ 6,110

Undistributed partnership income included in the
Company's retained earnings at the end of each period								$ 8,485	$ 12,156	$ 8,485	$ 12,156

6: ENVIRONMENTAL MATTERS

A. 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, waste materials were produced that may have resulted in soil and groundwater contamination at these sites. 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. The subsidiaries are addressing these sites under a program supervised by the Illinois Environmental Protection Agency (IEPA).

Peoples Gas is addressing 29 manufactured gas sites, including two sites described in more detail below. Investigations have been completed at all or portions of 23 sites. Remediations have been completed at all or portions of six sites.

North Shore Gas is addressing five manufactured gas sites, including one site described in more detail below. Investigations have been completed at all or portions of four sites. Remediations have not yet been completed at these sites.

The United States Environmental Protection Agency (EPA) has identified North Shore Gas as a potentially responsible party (PRP) under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA) at the Waukegan Coke Plant Site located in Waukegan, Illinois (Waukegan Site). The Waukegan Site is part of the Outboard Marine Corporation (OMC) Superfund Site. The EPA also has identified OMC, General Motors Corporation and certain other parties as PRPs at the Waukegan Site. The EPA has issued a record of decision (ROD) selecting the remedial action for the Waukegan Site. The selected remedy consists of on-site treatment of groundwater and off-site disposal of soil containing polynuclear aromatic hydrocarbons and arsenic. North Shore Gas and the other PRPs have executed a remedial action consent decree which has been entered by the federal district court. The consent decree requires North Shore Gas and General Motors, jointly and severally, to perform the remedial action and establish and maintain financial assurance of $27 million. Remedial activities have commenced.

In 1996, the current owner of a site in Chicago, formerly called Pitney Court Station, filed suit under CERCLA against Peoples Gas in the U.S. District Court for the Northern District of Illinois, Continental Title Company v. The Peoples Gas Light and Coke Company, (case no. 96 C 3257). The suit seeks recovery of the past and future

- 23 -

Notes to Consolidated Financial Statements (Unaudited)

costs of investigating and remediating the site. In ruling on cross motions for summary judgment, the court determined that Peoples Gas is a liable party under CERCLA and that the owner has established certain, but not all, elements of a defense to liability. Further proceedings have been stayed pending settlement discussions between the parties.

In 2004, the owners of another property in the vicinity of the former Pitney Court Station and the current site owner filed suit against Peoples Gas in the U.S. District Court for the Northern District of Illinois under the Resource Conservation and Recovery Act (RCRA). The suit, River Village West LLC et al v. The Peoples Gas Light and Coke Co., (case no. 04 C 3392), seeks an order directing Peoples Gas to remediate the site.

With respect to portions of certain other sites in Chicago, Peoples Gas has received demands from site owners and others asserting standing regarding the investigation or remediation of their parcels. Some of these demands seek to require Peoples Gas to perform extensive investigations or remediations. These demands include notice letters sent to Peoples Gas by River Village West. These letters informed Peoples Gas of River Village West's intent to file suit under RCRA seeking an order directing Peoples Gas to remediate seven former manufactured gas plant sites located on or near the Chicago River. In April 2005, River Village West filed suit against Peoples Gas in the U.S. District Court for the Northern District of Illinois under RCRA. The suit, River Village West LLC et al v. The Peoples Gas Light and Coke Company, (case no. 05 C 2103), seeks an order directing Peoples Gas to remediate three of the seven sites: the former South Station, the former Throop Street Station and the former Hough Place Station.

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, 2005, the total of these deferred liabilities and costs (stated in current year dollars) for Peoples Gas was $202 million; for North Shore Gas the total was $65 million; and for the Company on a consolidated basis, the total deferred was $267 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, other entities 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 ($183 million for Peoples Gas; $64 million for North Shore Gas; and $247 million for the Company on a consolidated basis). Management also estimates that additional costs in the following amounts are reasonably possible: for Peoples Gas, $105 million; for North Shore Gas, $77 million; and for the Company on a consolidated basis, $182 million.

Management's foregoing estimates are developed with the aid of probabilistic modeling. They are based upon an ongoing review and judgement 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. Actual costs, which may differ materially from these estimates, will depend on several factors, including whether contamination exists at all sites, the nature and extent of contamination and the type of remediation that may be required. With respect to certain sites or portions of sites, the subsidiaries have received demands to investigate and remediate to extensive levels. While management does not believe that the utility subsidiaries are legally required to comply with such demands, should the subsidiaries be required to investigate and remediate to extensive levels at all of the sites that have not yet been remediated, the Company's aggregate maximum potential liability could be substantially higher than the reserves and estimates of additional reasonably possible costs indicated above.

Each subsidiary intends to seek contribution from other entities for the costs incurred at the sites, but the full extent of such contributions cannot be determined at this time.

Management believes that any costs incurred by Peoples Gas and by North Shore Gas for environmental activities relating to former manufactured gas operations that are not recoverable through contribution from other entities or from insurance carriers are recoverable 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

- 24 -

Notes to Consolidated Financial Statements (Unaudited)

operations, including carrying charges on the unrecovered balances, under rate mechanisms approved by the Illinois Commerce Commission (Commission) which authorize recovery of prudently incurred costs. Environmental costs are expensed in the income statement in the same period they are billed to customers and recognized as revenues.

B. 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 Shattuck's 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 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 U.S. 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.

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 $22.0 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 incurs liability, it would pursue reimbursement from insurance carriers, other responsible parties, if any, and through its rates for utility service.

7: GAS CHARGE RECONCILIATION PROCEEDINGS AND RELATED MATTERS

A. Illinois Commerce Commission Proceedings

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

- 25 -

Notes to Consolidated Financial Statements (Unaudited)

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 initiated shortly after the close of the fiscal year and historically take at least a year to 18 months to complete.

Proceedings regarding Peoples Gas and North Shore Gas for fiscal 2001 costs are currently pending before the Commission. In August 2003, three intervenors (Citizens Utility Board (CUB), Illinois Attorney General (AG) and City of Chicago (Chicago)) filed direct testimony in Peoples Gas' proceeding and one intervenor (CUB) filed testimony in North Shore Gas' proceeding. In January 2005, CUB and Chicago jointly filed additional direct testimony in the Peoples Gas proceeding. No intervenor filed additional direct testimony in the 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, the use of its Manlove storage field to support transactions with third parties ("hub" transactions), its gas purchase agreement with Enron North America Corp. (Enron), transactions conducted and income earned by an affiliated company (enovate L.L.C. (enovate)) and the level of lost and unaccounted for gas costs Peoples Gas recovered through its Gas Charge. 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 intervenors have requested disallowances, on a variety of issues other than financial hedging, that range in their initial testimony from $8 million to $56 million and in their additional testimony from $8 million to $150 million. 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), based on additional direct and rebuttal testimony submitted in January 2005, increased the requested disallowance from $31 million to $92 million in the Peoples Gas proceeding and from $1.4 million to $4.0 million in the North Shore Gas proceeding covering a variety of alleged issues, none of which relate to hedging. The Staff stated in both the Peoples Gas and North Shore Gas proceedings that it did not recommend a disallowance based on allegations related to financial hedging. The Staff also recommended that the Commission should reopen the fiscal year 2000 Gas Charge reconciliation cases for Peoples Gas and North Shore Gas.

Peoples Gas and North Shore Gas submitted additional rebuttal testimony on January 28, 2005, which rejected the proposed disallowances by the intervenors and the Staff in their respective additional direct and rebuttal testimony. Peoples Gas' additional rebuttal testimony responded to all issues raised by the Staff and intervenors, including countering criticisms of the gas purchase agreement with Enron, defending the operation of the storage field as prudent, explaining why enovate transactions are unrelated to this proceeding and pointing out numerous errors in the proposed disallowance related to lost and unaccounted for gas. North Shore Gas' additional rebuttal testimony responded to all issues raised by the Staff, in particular, countering criticisms of the gas purchase agreement with Enron. On February 18, 2005, the Staff and intervenors filed rebuttal testimony in both utilities' cases, and no new issues or recommendations were included in that testimony. On March 4, 2005, Peoples Gas and North Shore Gas submitted surrebuttal testimony in response to the Staff and intervenor rebuttal testimony. Hearings were held in both utilities' cases on April 18 through April 22, 2005. At a status hearing on May 5, 2005, the records in both cases were marked "heard and taken" and a briefing schedule was set. Initial briefs were filed on June 30, 2005, and reply briefs are due August 11, 2005, although, on August 4, 2005, intervenors moved for an extension to August 19, 2005. In a joint initial brief filed in the Peoples Gas case by CUB, Chicago and AG, these intervenors recommended a gas cost disallowance of $381 million, and in its brief the Staff recommended a gas cost disallowance of $92 million. In initial briefs in the North Shore Gas case, CUB recommended a gas cost disallowance of $9.7 million, the Staff recommended a $3.96 million disallowance, and the AG, adopting Staff's positions, recommended a $3.96 million disallowance.

Peoples Gas and North Shore Gas previously 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 of fiscal 2004, this amount was capitalized as property, plant and equipment and will be depreciated over the asset's useful life. An

- 26 -

Notes to Consolidated Financial Statements (Unaudited)

offsetting liability for this amount, which is expected to be refunded to customers, was recorded. During the first quarter of fiscal 2004, 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.

An order from the Commission related to the fiscal 2001 Gas Charge reconciliation proceedings is not expected before the first quarter of fiscal 2006.

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 reasonably estimate a range of potential loss and, accordingly, 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. 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. Fiscal 2004 Gas Charge reconciliation cases were initiated on November 10, 2004. Peoples Gas and North Shore Gas each filed direct testimony on April 7, 2005. Status hearings are scheduled for all three fiscal years on October 5, 2005.

B. Illinois Attorney General and the City of Chicago Lawsuits

On March 21, 2005, the AG and Chicago filed separate lawsuits in the Circuit Court of Cook County, Illinois against the Company and several of its subsidiaries, including Peoples Gas and, in the case of the AG's lawsuit, North Shore Gas. The AG's lawsuit alleges that during the period 1999 to 2002 the Company and four of its subsidiaries engaged in midstream gas transactions with Enron and certain of its affiliates in violation of the Illinois Consumer Fraud and Deceptive Business Practices Act. Chicago's lawsuit alleges that during the period from 2000 to the present, the Company and three of its subsidiaries engaged in similar transactions in violation of certain consumer protection provisions of the City of Chicago Municipal Code. Both lawsuits seek to impose fines and damages and seek injunctive orders to cease further violations. On April 12, 2005, the Court granted a motion to consolidate the proceedings. On May 13, 2005, the Company filed Motions to Dismiss the complaints filed by the AG and Chicago. On June 30, 2005, the AG and Chicago filed responses to the Company's Motions to Dismiss. The Company's Replies in support of its Motions to Dismiss were filed on August 4, 2005. A hearing is scheduled for August 17, 2005.

The Company believes that the issues raised in complaints filed by the AG and Chicago are substantially the same as those already under consideration by the Commission in proceedings regarding Peoples Gas and North Shore Gas for fiscal 2001 gas costs, as described in Note 7A. The Company believes it has meritorious defenses to the lawsuits. However, at this time, the Company cannot predict the outcome of the lawsuits and has not recorded a liability associated with these contingencies.

C. Class Action

In February 2004, a purported class action was filed in Cook County Circuit Court against the Company and Peoples Gas by Stephen Alport, 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. On September 22, 2004, the Court granted a motion to dismiss all counts against Peoples Gas. On October 21, 2004, the plaintiffs filed an amended complaint against the Company. On November 22, 2004, the Company filed a motion to dismiss the amended complaint. On April 6, 2005, the Court denied the Company's motion in part, by allowing

- 27 -

Notes to Consolidated Financial Statements (Unaudited)

to stand the plaintiffs' claims for violation of the Consumer Fraud and Deceptive Business Practices Act and claims that the Company acted in concert with others to commit a tortious act, and granted the Company's motion in part by dismissing all of the plaintiffs' other claims, though without prejudice to plaintiffs' ability to amend its complaint. Management cannot predict the outcome of this litigation and has not recorded a liability associated with this contingency.

D. CFTC Subpoena

In February, 2005, the Company received a subpoena from the U.S. Commodity Futures Trading Commission (CFTC) requesting information regarding price reporting of transactional data to the energy trade press, other information related to gas supply, the midstream gas trading and services business and the retail energy services business for the years 2000 through 2002 and a copy of certain documents produced in response to a separate subpoena issued by the AG. The Company has produced the requested information and is cooperating with the CFTC. The Company has not been charged by the CFTC with any violation nor does it have any knowledge of any violations concerning the matters covered by the subpoena.

8: OTHER LITIGATION

A. Oil and Gas Production Royalties Dispute

The Oil and Gas Production segment pays royalties and overriding royalties (collectively, royalties) to parties who own the mineral rights on wells operated by the Company. The royalties are computed based upon the amount of oil and gas produced and terms and conditions specified in the royalty agreements, which may provide the recipient with certain rights to review and challenge the royalties received. Pursuant to an audit, a claim was made against the Company by Coates Energy Trust and Coates Energy Interests, Ltd. for underpayment of royalties totaling approximately $2.4 million. In accordance with the royalty agreements (which were assigned to a subsidiary of Peoples Energy Production Company pursuant to an acquisition) the Company was required to pay the claim in December of 2004 while disputing the audit findings. In December 2004, the claimant filed suit in the District Court of Starr County, Texas seeking a declaratory judgment that the $2.4 million is owed to the claimant and that the Company cannot contest the audit's findings. The parties are attempting to resolve the dispute through mediation. The Company believes that the lawsuit and the matters asserted by the claimant are not consistent with the terms of the royalty agreements or applicable laws. The Company intends to vigorously defend the suit and believes, but cannot assure, that it will prevail in this matter and that the amounts will be refunded. Pending resolution of these matters, the Company has not recorded a royalty expense for these claims.

B. Chicago Municipal Tax Audit

In December, 2004, the City of Chicago served Peoples Gas with a Notice of Tax Determination and Assessment alleging that Peoples Gas owed approximately $9.4 million, inclusive of interest and penalties, with respect to Chicago's Natural Gas Occupation Tax for the period January 1, 1998 through June 30, 2002. After an exchange of information and discussions between Peoples Gas and the City of Chicago, in July 2005, the Company was notified by the City of Chicago that it had withdrawn its prior assessment and that no additional tax liability was due.

C. Ford City Incident

On January 12, 2005, an explosion occurred in an underground tunnel beneath a shopping mall parking lot in Chicago. Peoples Gas' facilities were in close proximity to the explosion. The cause of the explosion is not known at this time. Peoples Gas has no knowledge of fatalities or life-threatening injuries. There was property damage to the parking lot, vehicles in the parking lot and several mall stores. The mall was closed until January 17, 2005. The Company has received two lawsuits involving four plaintiffs and notice that seven additional suits may be filed involving ten potential plaintiffs. Peoples Gas has received business interruption claims from three mall businesses and two businesses located near the mall. At this time, the Company cannot predict the outcome of any pending or potential litigation. Based on the nature and extent of the known damages, management

- 28 -

Notes to Consolidated Financial Statements (Unaudited)

believes that insurance will cover the liability, if any, above Peoples Gas' self-insured retention amount and, accordingly, does not expect that this incident will have a material adverse affect on the financial position or results of operation of the Company or Peoples Gas.

9: COMPREHENSIVE INCOME

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 unrealized hedge gains or losses on derivative instruments and the effect of the minimum pension liability adjustment. Total comprehensive income for the Company is summarized below.

	Three Months Ended		Nine Months Ended
	June 30,		June 30,
(In Thousands)	2005	2004	2005	2004
Comprehensive income
Net income	$ 6,799	$ 5,623	$ 80,447	$ 91,877
Other comprehensive income (loss), net of tax
Minimum pension liability adjustment	-	-	(13,609)	-
Unrealized hedge gain or (loss)	10,018	(4,885)	(10,428)	(24,635)

Total comprehensive income	$ 16,817	$ 738	$ 56,410	$ 67,242

10: RETIREMENT AND POSTRETIREMENT BENEFITS

The Company and its subsidiaries participate in two noncontributory 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 non-qualified pension plan (Supplemental Plan) that provides certain employees with pension benefits in excess of qualified plan limits imposed by federal tax law. Effective October 1, 2004, the Company began including amounts related to deferred compensation in the calculation of supplemental pension expense. 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 "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits" (SFAS No. 88) to account for unrecognized gains and losses related to the settlement of its pension plans' Projected Benefit Obligations (PBO). During the nine months of fiscal 2005, as in past fiscal periods, 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 contributory 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 service lives of all employees.

- 29 -

Notes to Consolidated Financial Statements (Unaudited)

For the three- and nine-month periods ending June 30, 2005 the Company contributed $29.0 million and $31.3 million, respectively, to its pension plans. The Company does not expect to make additional contributions to its pension plans or to its other post-retirement plans for the remainder of fiscal 2005.

Net pension benefit cost and net postretirement benefit cost (before consideration of capitalized costs) for all plans include the following components:

			Other Postretirement
Three Months Ended June 30,	Pension Benefits		Benefits
(In Millions)	2005	2004	2005	2004
Service cost	$ 4.0	$ 4.5	$ 2.1	$ 1.4
Interest cost	6.8	6.9	2.0	1.9
Expected return on plan assets (gain)	(10.8)	(11.7)	(0.8)	(1.0)
Amortization of:
Net transition (asset) obligation	(0.2)	(0.3)	0.4	0.5
Prior service costs	0.7	0.8	-	-
Net (gain) loss	0.5	0.4	0.4	0.2
Net periodic benefit cost (credit)	1.0	0.6	4.1	3.0

Effect of lump sum settlements upon retirement-restructuring (See Note 4)	0.2	-	-	-
Effect of lump sum settlements upon retirement-other	1.5	2.3	-	-
Cumulative recognition of pension expense on deferred compensation	2.2	-	-	-
Net benefit cost (credit)	$ 4.9	$ 2.9	$ 4.1	$ 3.0

			Other Postretirement
Nine Months Ended June 30,	Pension Benefits		Benefits
(In Millions)	2005	2004	2005	2004
Service cost	$ 11.9	$ 13.5	$ 4.7	$ 3.8
Interest cost	20.4	20.7	6.4	5.7
Expected return on plan assets (gain)	(32.3)	(35.1)	(2.5)	(3.0)
Amortization of:
Net transition (asset) obligation	(0.6)	(0.9)	1.5	1.5
Prior service costs	2.1	2.4	-	-
Net (gain) loss	1.5	1.2	1.3	0.6
Net periodic benefit cost (credit)	3.0	1.8	11.4	8.6

Effect of lump sum settlements upon retirement-restructuring (See Note 4)	10.4	-	-	-
Effect of lump sum settlements upon retirement-other	4.5	6.9	-	-
Curtailment cost-restructuring (See Note 4)	5.1	-	0.4	-
Cumulative recognition of pension expense on deferred compensation	2.2
Net benefit cost (credit)	$ 25.2	$ 8.7	$ 11.8	$ 8.6


			Other Postretirement
As of June 30,	Pension Benefits		Benefits
(In Millions)	2005	2004	2005	2004
Amounts recognized in the Company's consolidated
balance sheets consist of:
Prepaid pension cost	$ 151.2	$ 146.5	$ -	$ -
Accrued benefit cost	(33.2)	(43.8)	(52.6)	(37.1)
Intangible asset	22.9	30.5	-	-
Accumulated other comprehensive income	35.7	39.7	-	-
Net amount recognized	$ 176.6	$ 172.9	$ (52.6)	$ (37.1)

- 30 -

Notes to Consolidated Financial Statements (Unaudited)

On December 8, 2003, the president signed the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) into law. The Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Detailed regulations needed to implement the Act were issued in January of 2005 and the Company has recently concluded that the benefits provided by the Plan are actuarially equivalent to Medicare Part D under the Act. In accordance with FSP FAS 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" (the FSP), the Company has accounted for the subsidy as an actuarial experience gain reducing the Company's net periodic benefit cost and Accumulated Postretirement Benefit Obligation (APBO). The impact of the Act on the Company's postretirement benefit plan is considered a significant event and a remeasurement of plan assets and obligations was performed as of February 28, 2005. Amortization of the actuarial gain, before consideration of capitalized costs, resulted in a $0.4 million reduction in net periodic benefit cost for the third quarter of fiscal 2005 and is expected to result in a $1.4 million reduction for all of fiscal 2005.

- 31 -

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

EXECUTIVE SUMMARY

The tables and discussion below summarize third quarter and fiscal year-to-date highlights as reported in accordance with generally accepted accounting principles (GAAP) and on a non-GAAP basis before the effects of the Company's fiscal year 2004 organizational restructuring:

	Three Months Ended June 30,
	Ongoing - Before		Effects of
	Restructuring		Restructuring		As Reported
	(non-GAAP)		Costs		(GAAP)
(In Thousands)	2005	2004	2005	2004	2005	2004
Operating Income (Loss)	$ 23,171	$ 17,084	$ (52)	$ -	$ 23,119	$ 17,084
Net Income (Loss)	$ 6,831	$ 5,623	$ (32)	$ -	$ 6,799	$ 5,623
Net Income (Loss) per diluted share	$ 0.18	$ 0.15	$ -	$ -	$ 0.18	$ 0.15

	Nine Months Ended June 30,
	Ongoing - Before		Effects of
	Restructuring		Restructuring		As Reported
	(non-GAAP)		Costs		(GAAP)
(In Thousands)	2005	2004	2005	2004	2005	2004
Operating Income (Loss)	$ 173,492	$ 172,176	$ (13,216)	$ -	$ 160,276	$ 172,176
Net Income (Loss)	$ 88,410	$ 91,877	$ (7,963)	$ -	$ 80,447	$ 91,877
Net Income (Loss) per diluted share	$ 2.32	$ 2.46	$ (0.21)	$ -	$ 2.11	$ 2.46

Management believes that ongoing net income (non-GAAP) and ongoing operating income (non-GAAP) are useful for year over year comparisons since restructuring costs of this magnitude are infrequent and affect the comparability of operating results. Ongoing net income and ongoing operating income are used internally to measure performance against budget and in reports for management and the Board of Directors.

Notable items for the third quarter and year-to-date periods of fiscal 2005 include the following -

Ongoing operating income in total for both the quarter and year-to-date periods increased despite the impact of warmer weather on Gas Distribution segment income compared to the year-ago periods. Operating income for the third quarter increased at each of the Company's segments with the exception of Oil and Gas Production.
Oil and Gas Production volumes were down approximately 13% for both the quarter and year-to-date periods compared to a year ago, as the Company's drilling program continued to be hampered by well performance issues, rig availability, and other timing delays.
Weather on a year-to-date basis was 8% warmer than normal and 3% warmer than a year ago, negatively impacting earnings by approximately $0.04 compared to the year-ago period, net of weather insurance recoveries.
Weather normalized deliveries in the Gas Distribution segment were down approximately 3% on a year-to-date basis compared to last year, reflecting ongoing conservation measures by utility customers.
Labor-related savings associated with the Company's 2004 organizational restructuring continued to exceed expectations in the third quarter, and savings for the full year are now expected to total approximately $18 million versus an original estimate of $15 million. Most of these savings will occur in the Gas Distribution and Corporate segments.
As previously disclosed, Gas Distribution segment results for the quarter and year-to-date periods also benefited (approximately $5 million impact in both periods) from lower depreciation expense due to approval by the Illinois Commerce Commission in April of new depreciation rates that reflect longer useful lives on utility plant (the "Commission Depreciation Order"). The new rates are expected to lower fiscal year 2005 depreciation expense by $6.6 million compared to the previous rates in effect.

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

Quarter and year-to-date results were negatively impacted by $0.06 and $0.11 per share, respectively, compared to the year-ago periods, due to higher effective tax rates. For the 2005 year-to-date period, the effective income tax rate of 36% is in line with expectations and up from last year's 33% rate, which benefited from several tax expense adjustments.

Oil and Gas Production volumes have not rebounded as anticipated and as a result, fiscal 2005 operating income for the Oil and Gas Production segment will be significantly lower than last year's results. However, the Company is working to conclude the sale of several non-strategic properties and investments in the fourth quarter, which are expected to mostly offset the Oil and Gas Production income shortfalls. As a result, the Company continues to estimate that fiscal 2005 earnings will be at the low end of our previously communicated range of $2.30 to $2.45 per share (or $2.55 to $2.70 on an ongoing, non-GAAP basis, which excludes the effects of the restructuring charge). (See Item 2-MD&A-Forward-Looking Information.)

Looking ahead to fiscal 2006, large increases in pension costs, coupled with the ongoing negative effects of high gas prices on customer demand and bad debt expense, will likely make 2006 a difficult year for the Gas Distribution segment. Peoples Gas and North Shore Gas are evaluating the need to file a general rate case in fiscal 2006. The impact of any approved rate or rate design changes would not be effective until fiscal 2007.

RESULTS OF OPERATIONS

Income Statement Variations

The Company's revenues and cost of energy sold increased $54.8 million and $56.7 million, respectively, for the three-month period ended June 30, 2005 compared to the same year ago period, and increased $287.2 million and $280.3 million, respectively, for the nine-month period. The increases in both periods are due to higher realized commodity prices in the Gas Distribution segment and increased sales volumes in the Midstream Services and Retail Energy Services segments, partially offset by decreases in Gas Distribution deliveries (7% and 5%, respectively) resulting from warmer weather and ongoing conservation measures by utility customers. In addition, average daily production volumes at the Oil and Gas Production segment were down 13% for both the quarter and nine months ended June 30, 2005.

The Company recorded in the three- and nine-month periods ended June 30, 2005, $0.1 million and $13.2 million, respectively, in pension-related charges resulting from its organizational restructuring commenced last fall (as described in Note 4 of the Notes to the Consolidated Financial Statements).

Utility environmental costs increased $1.5 million and $12.6 million for the three- and nine-month periods ended June 30, 2005, respectively, and relate to investigation and remediation activities at multiple sites that formerly had operations for gas manufacturing and the storage of manufactured gas (see Note 6 of the Notes to Consolidated Financial Statement for further discussion). 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.

Operation and maintenance expense for the three- and nine-month periods ended June 30, 2005, excluding the above mentioned environmental costs and restructuring-related pension charges, decreased $7.1 million (9%) and $11.3 million (4%), respectively. Significant items to note in the three- and nine-month periods ended June 30, 2005, compared to the corresponding prior year periods were:

Decreased direct labor costs at Corporate and the Gas Distribution segment of $2.0 million and $12.1 million, as a result of the organization restructuring;
Exploration costs in the Oil and Gas Production segment decreased $3.9 million and $5.0 million, reflecting a significant dry hole expense recognized in the third quarter of fiscal 2004;
Lease operating expense in the Oil and Gas Production segment increased $0.3 million and $3.4 million, primarily as a result of a general increase in the cost of goods and services.

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

Depreciation, depletion and amortization for the three- and nine-month periods decreased $5.7 million and $6.3 million, respectively, mainly resulting from the $5.0 million impact of the Commission Depreciation Order issued in the third quarter. The impact of the depreciation change on the results of fiscal 2005 is cumulative since October 1, 2004, the effective date of the Commission Depreciation Order.

Taxes, other than income taxes, for the three- and nine-month periods increased $1.9 million and $12.0 million, respectively, primarily due to higher revenue taxes in the Gas Distribution segment.

Equity investment income for the three- and nine-month periods decreased $0.8 million and increased $2.1 million, respectively. The decrease in the three-month period was due, in part, to reduced operating income from the EnerVest Partnership resulting from its sale of certain properties in December 2004. The increase in the nine-month period was due to results at the Power Generation segment's Elwood Energy LLC (Elwood) facility, which included the Company's portion ($2.2 million) of a reduction in prior period depreciation expense on generating equipment.

Interest expense for the three- and nine-month periods increased $0.8 million and $1.5 million, respectively, due to higher interest rates.

Income tax expense for the three- and nine-month periods increased $4.8 million and decreased $0.7 million, respectively. Results for both periods of fiscal 2005 were negatively impacted by higher effective tax rates. For the 2005 year-to-date period, the effective income tax rate was 36%, up from last year's 33% rate, which benefited from several tax expense adjustments.

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

Segment Discussion

The table below summarizes third quarter and fiscal year-to-date operating results for Peoples Energy's business segments and provides a reconciliation of GAAP and Non-GAAP operating income. See Item 2 - MD&A - Executive Summary for a discussion of management's use of non-GAAP financial measures.

	Three Months Ended June 30,
	Before		Effects of
	Restructuring		Restructuring		As Reported
(In Thousands)	(non-GAAP)		Costs		(GAAP)
Operating Income (Loss)	2005	2004	2005	2004	2005	2004
Gas Distribution	$ 16,320	$ 11,261	$ -	$ -	$ 16,320	$ 11,261
Oil and Gas Production	5,854	7,390	-	-	5,854	7,390
Power Generation	3,269	1,695	-	-	3,269	1,695
Midstream Services	1,170	835	-	-	1,170	835
Retail Energy Services	1,302	833	-	-	1,302	833
Corporate and Other	(4,744)	(4,930)	(52)	-	(4,796)	(4,930)
Total Operating Income (Loss)	$ 23,171	$ 17,084	$ (52)	$ -	$ 23,119	$ 17,084


	Nine Months Ended June 30,
	Before		Effects of
	Restructuring		Restructuring		As Reported
(In Thousands)	(non-GAAP)		Costs		(GAAP)
Operating Income (Loss)	2005	2004	2005	2004	2005	2004
Gas Distribution	$ 138,399	$ 142,009	$ -	$ -	$ 138,399	$ 142,009
Oil and Gas Production	19,622	31,287	-	-	19,622	31,287
Power Generation	4,536	(954)	-	-	4,536	(954)
Midstream Services	8,211	7,642	-	-	8,211	7,642
Retail Energy Services	13,764	8,802	-	-	13,764	8,802
Corporate and Other	(11,040)	(16,610)	(13,216)	-	(24,256)	(16,610)
Total Operating Income (Loss)	$ 173,492	$ 172,176	$(13,216)	$ -	$ 160,276	$ 172,176

The Company's financial results and applicable operating statistics by segment are discussed in this section.

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

Gas Distribution 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,		Three Months	Nine Months
(In Thousands)	2005	2004	2005	2004	Ended	Ended
Gas Distribution revenues:
Sales
Residential	$ 193,114	$ 176,009	$1,175,606	$1,041,623	$ 17,105	$ 133,983
Commercial	30,857	27,624	187,649	165,288	3,233	22,361
Industrial	4,396	4,504	33,085	27,391	(108)	5,694
Total sales	228,367	208,137	1,396,340	1,234,302	20,230	162,038

Transportation
Residential	5,757	5,878	28,394	28,449	(121)	(55)
Commercial	8,714	8,468	42,281	40,830	246	1,451
Industrial	3,966	3,841	16,392	15,954	125	438
Contract pooling	5,276	3,914	16,847	12,135	1,362	4,712
Total transportation	23,713	22,101	103,914	97,368	1,612	6,546
Other Gas Distribution revenues⁽³⁾	5,756	4,373	14,179	12,340	1,383	1,839
Total Gas Distribution revenues	257,836	234,611	1,514,433	1,344,010	23,225	170,423
Less: Gas costs	138,829	118,636	956,609	799,756	20,193	156,853
Gross margin ⁽¹⁾	119,007	115,975	557,824	544,254	3,032	13,570
Less: Revenue taxes and surcharges	23,384	22,257	135,054	125,548	1,127	9,506
Environmental costs recovered	4,599	3,052	27,727	15,142	1,547	12,585
Net margin ⁽¹⁾	$ 91,024	$ 90,666	$ 395,043	$ 403,564	$ 358	$ (8,521)

Gas Distribution deliveries (MDth):
Gas sales
Residential	14,736	15,279	103,537	109,271	(543)	(5,734)
Commercial	2,699	2,731	17,623	18,598	(32)	(975)
Industrial	421	503	3,326	3,302	(82)	24
Total gas sales	17,856	18,513	124,486	131,171	(657)	(6,685)

Transportation
Residential	3,080	3,236	18,407	19,552	(156)	(1,145)
Commercial	5,727	7,219	35,931	38,491	(1,492)	(2,560)
Industrial	4,761	4,864	18,724	19,318	(103)	(594)
Total transportation	13,568	15,319	73,062	77,361	(1,751)	(4,299)
Total Gas Distribution deliveries	31,424	33,832	197,548	208,532	(2,408)	(10,984)

Gross margin per Dth delivered	$ 3.79	$ 3.43	$ 2.82	$ 2.61	$ 0.36	$ 0.21
Net margin per Dth delivered	$ 2.90	$ 2.68	$ 2.00	$ 1.94	$ 0.22	$ 0.06
Average cost per Dth of gas sold	$ 7.77	$ 6.41	$ 7.68	$ 6.10	$ 1.36	$ 1.58

Actual heating degree days (HDD)	664	692	5,827	6,002	(28)	(175)
Normal heating degree days⁽²⁾	774	752	6,307	6,307
Actual heating degree days as a percent
of normal (actual/normal)	86	92	92	95

(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 the fiscal 2005 and 2004 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 in 2004.

(3) Includes accruals for weather insurance recoveries.

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

Revenues for the Gas Distribution segment for the three- and nine-month periods ended June 30, 2005 increased $23.2 million and $170.4 million, respectively, compared to the year ago periods, primarily due to the impact on revenues of higher commodity prices ($25.0 million and $203.0 million) that are recovered on a dollar for dollar basis. Partially offsetting this effect were decreases in deliveries due primarily to warmer weather ($3.5 million and $29.0 million, respectively). Weather for the three- and nine-month periods ended June 30, 2005, was 4% and 3% warmer, respectively, compared to the year ago periods.

Operating income for the three- and nine-month periods ended June 30, 2005 increased $5.1 million (45%) and decreased $3.6 million (3%), respectively, compared with the same year ago periods. The increase for the three- month period is due to weather insurance accruals ($1.1 million), decreased labor costs related to the organizational restructuring ($1.2 million) and reduced depreciation expense ($5.3 million) primarily as a result of the Commission Depreciation Order. Partially offsetting these increases are the combined negative effects ($1.0 million) of warmer weather and lower weather-normalized deliveries as well as lower gains on property sales ($1.3 million). The decrease in the nine-month period was due to the effects of warmer weather ($4.6 million), lower weather-normalized deliveries ($5.7 million), higher non-labor expenses (primarily outside services, insurance, pension and taxes other than income taxes) and lower gains on property sales ($1.4 million). Partially offsetting these negative variations are weather insurance accruals ($2.0 million), decreased labor costs related to the organizational restructuring ($7.5 million) and reduced depreciation expense ($5.1 million), primarily as a result of the Commission Depreciation Order.

The Company lowered its bad debt provision rate from 2.5% of revenues in 2004 to 2.2% in 2005 based on improved experience and credit and collection results. As a result, bad debt expense on a year-to date basis is essentially flat with last year despite higher distribution revenues resulting from increased natural gas prices. Overall, Peoples Gas and North Shore Gas believe their reserves for uncollectible accounts are adequate given what is known at this time. The reserves for uncollectible accounts remain estimates and could require future adjustments. The following table summarizes customer receivable statistics for Peoples Gas and North Shore Gas combined.

	Gas Distribution
	Accounts Receivable Balance
	At June 30,	At September 30,	At June 30,
(Dollars in Millions)	2005	2004	2004
Current	$ 85.3	$ 62.6	$ 87.2
30-89 days	71.0	20.9	65.0
90-149 days	46.4	19.2	43.4

150 days - active	12.0	14.3	11.8
150 days - terminated	18.4	32.1	17.4
Total 150 days	30.4	46.4	29.2

Accounts receivable	$ 233.1	$ 149.1	$ 224.8

Reserve balance	$ 35.2	$ 27.5	$ 28.4
Reserve to accounts receivable ratio	15.1%	18.4%	12.6%
Reserve to 90 days +	45.8%	41.9%	39.1%
Days sales outstanding	51.9	36.7	56.3

Oil and Gas Production Segment.
Revenues for the three- and nine-month periods ended June 30, 2005 decreased $5.1 million and $11.7 million, respectively, compared with the same periods last year. Operating income for the three- and nine-month periods decreased $1.5 million (21%) and $11.7 million (37%), respectively, compared with the year ago periods. The decreases in revenue and operating income are due mainly to lower production volumes. On an equivalent basis, average daily production volumes fell 13% compared to the prior year three- and nine-month periods due to well performance, rig availability, and other timing delays. For

- 37 -

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

the three- and nine-month periods ended June 30, 2005, increases in lease operating expenses ($0.3 million and $3.4 million, respectively) and lower equity investment income from the Company's investment in EnerVest Energy, L.P. (EnerVest) (decreases of $1.6 million and $1.8 million, respectively) reduced operating income. Higher production taxes (associated with higher wellhead gas prices) and administrative costs also reduced operating income for the nine-month period. These negative impacts on operating income were partially offset by lower DD&A expense, lower exploration expense and a gain on the sale of producing properties in the three- and nine-month periods ended June 30, 2005 compared to the same year ago periods.

The following table summarizes hedges in place for the remainder of fiscal 2005 and 2006 for the Oil and Gas Production segment as of July 1, 2005 (date of information used in the Company's earnings release). Hedges in place are net of approximately 155,000 MMbtu of open gas swaps and 22 Mbl of open oil swaps that are excluded as a result of hedge dedesignation. These swaps have been dedesignated as hedges due to higher than anticipated hedge percentages relative to current production estimates.

	Remaining
	Fiscal 2005	Fiscal 2006
Gas hedges in place (MMbtus)	5,811,000	17,055,000
Gas hedges as a percent of estimated fiscal production ⁽¹⁾	85-95%	70-75%
Percent of gas hedges that are swaps	41%	63%
Average swap price ($/MMbtu)	$ 4.41	$ 5.02
Percent of gas hedges that are no cost collars	59%	37%
Weighted average floor price ($/MMbtu)	$ 4.75	$ 4.34
Weighted average ceiling price ($/MMbtu)	$ 5.45	$ 5.56
Oil hedges in place (MBbls)	93	365
Oil hedges as a percent of estimated fiscal production ⁽¹⁾	85-95%	80-85%
Average hedge price ($/Bbl)	$ 26.62	$ 28.26

(1) Based on expected production for fiscal 2005 and assumes fiscal 2006 production is flat with fiscal 2005 levels.

Net realized commodity prices fell 4% in the third quarter and were up about 1% on a year-to-date basis compared to a year ago, as production shortfalls resulted in higher than planned hedge percentages. The following table summarizes operating statistics from the Oil and Gas Production segment.

	Three Months Ended June 30,		Nine Months Ended June 30,
	2005	2004	2005	2004
Total production - gas equivalent (MMcfe)⁽¹⁾	5,792	6,649	18,296	21,089
Daily average gas production (MMcfd)	57.1	64.2	59.6	67.9
Daily average oil production (MBd)	1.1	1.5	1.2	1.5
Daily average production - gas equivalent (MMcfed)⁽¹⁾	63.7	73.1	67.0	77.0
Gas production as a percentage of total production	90	88	89	88
Percent of production hedged during the period - gas⁽³⁾	103	102	98	91
Percent of production hedged during the period - oil⁽³⁾	115	83	97	75
Net realized gas price received ($/Mcf)	$ 4.47	$ 4.60	$ 4.50	$ 4.46
Net realized oil price received ($/Bbl)	$ 22.18	$ 27.19	$ 26.69	$ 26.27
Depreciation, depletion and amortization rate ($/Mcfe)⁽²⁾	$ 1.88	$ 1.72	$ 1.88	$ 1.70
Average lease operating expense ($/Mcfe)	$ 0.72	$ 0.58	$ 0.69	$ 0.43
Average production taxes ($/Mcfe)	$ 0.45	$ 0.43	$ 0.46	$ 0.34

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

(2) 2005 increase due to creation of additional DD&A pools and production mix and the addition of unproved capital and costs associated with the development of unproved reserves.

(3) Due to higher than anticipated hedge percentages, a small amount of open hedges have been dedesignated, reflecting current production estimates.

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

Power Generation Segment.
Operating income totaled $3.3 million and $4.5 million on a quarter and year-to-date basis, respectively, improvements of $1.6 million and $5.5 million from the year-ago periods. The increases largely result from the impact of lower depreciation expense on equity investment income for the Elwood generation facility. In connection with its fiscal 2004 year-end audit, the Elwood partnership determined that depreciation expense related to current and prior periods should be adjusted, primarily to recognize greater salvage value of its generating equipment. This adjustment positively impacted year-to-date results by $3.3 million, of which $2.2 million related to prior periods.

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. At June 30, 2005, $10.4 million related to this activity was capitalized or deferred as investments.

The electric capacity of Elwood has been sold through long-term contracts with Exelon Generation Company, LLC (Exelon), Engage Energy America LLC (Engage) and Aquila, Inc. (Aquila). Effective December 31, 2004, the contract with Engage terminated and the related electric capacity is being purchased by Exelon. In August 2004, Standard & Poor's Rating Services (S&P) upgraded Aquila's senior unsecured debt rating to B-. In September 2004, Moody's Investor Services (Moody's) upgraded Aquila's senior unsecured debt rating to B2 with a stable outlook. S&P and Moody's ratings on Elwood's bonds remain at B+ with a negative outlook and Ba2 with a stable outlook, respectively. As a result of earlier downgrading in Aquila's credit ratings, Aquila provided Elwood with security in the form of letters of credit and a cash escrow equal to one year of capacity payments of approximately $37.6 million. The letters of credit and the cash escrow agreement expire in March of 2006. In the event Aquila does not fulfill its payment obligations or terminates its power sales agreements (PSAs) 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 PSAs, 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.

Midstream Services Segment.
Revenues for the three- and nine-month periods ended June 30, 2005 increased $27.5 million and $107.5 million, respectively, compared to the year-ago periods due to higher commodity prices and increased wholesale and hub volumes. Operating income for the three- and nine-month periods increased $0.3 million and $0.6 million, respectively, compared with the year-ago periods. The increases primarily reflect higher hub revenues. The following table summarizes operating statistics for the Midstream Services segment.

	Three Months Ended June 30,		Nine Months Ended June 30,
	2005	2004	2005	2004
Wholesale volumes sold (MDth)	15,663	13,164	47,906	42,621
Hub volumes delivered (MDth)	3,050	3,227	18,567	15,628
Number of hub customers	19	17	30	30

Retail Energy Services Segment.
Revenues for the three- and nine-month periods ended June 30, 2005 increased $6.2 million and $64.5 million, respectively, compared with the year-ago periods primarily due to higher gas prices and higher gas and electric volumes. Operating income increased by $0.5 million and $5.0 million (56%) in the third quarter and fiscal year-to-date, respectively. The improvement for the three-month period was primarily due to reduced operating costs. The increase in the nine-month period was driven by higher gas margins, higher gas and electric volumes delivered and lower operating costs. Relevant operating statistics are summarized in the following table.

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

	Three Months Ended June 30,		Nine Months Ended June 30,
(In Thousands, Except Customers)	2005	2004	2005	2004
Gas sales sendout (Dth)	8,532	8,525	43,973	41,638
Number of gas customers	23,721	23,703	23,721	23,703
Electric sales sendout (Mwh)	335	267	999	759
Number of electric customers	2,177	1,794	2,177	1,794

Critical Accounting Policies

See the Management's 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, 2004 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 Provision for Uncollectible Accounts.

New Accounting Standards

On December 16, 2004, the FASB issued Statement No. 123 (revised 2004), "Share-based Payment" (SFAS 123 (R)), that will require compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity or liability instrument issued. In addition, liability awards will be remeasured each reporting period. Compensation cost will be recognized over the period that the employee provides service in exchange for the award. SFAS 123 (R) replaces SFAS No. 123, "Accounting for Stock-Based Compensation" and supersedes APB Opinion No. 25, "Accounting for Stock Issued to Employees". SFAS 123 (R) is effective as of the first annual reporting period that begins after June 15, 2005. In addition, the SEC issued Staff Accounting Bulletin 107 (SAB 107) on March 29, 2005, to provide public companies with additional guidance in applying the provisions of SFAS 123 (R). The Company is evaluating the impact of SFAS 123 (R) and SAB 107 on accounting for its compensation plans, but does not expect either to significantly affect the Company's financial condition or results of operations.

On March 30, 2005, the FASB issued FASB FIN 47, "Accounting for Conditional Asset Retirement Obligations" (FIN 47). FIN 47 states that the term conditional asset retirement obligation refers to an unconditional, legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are uncertain and conditional on a future event. If sufficient information exists for fair value measurement of the obligation, FIN 47 requires the entity to recognize a liability when incurred. The Company will adopt FIN 47 in the first quarter of fiscal 2006 and is still evaluating whether the requirements of FIN 47 will have a significant effect on the financial condition or results of operations of the Company.

LIQUIDITY AND CAPITAL RESOURCES

The following is a summary of cash flows for the Company:

	Nine Months Ended June 30,
(In Thousands)		2005	2004
Net cash provided by (used in) operating activities		$ 285,897	$ 262,166
Net cash provided by (used in) investing activities		$ (142,523)	$ (121,834)
Net cash provided by (used in) financing activities		$ (86,163)	$ (71,680)

Cash provided by operating activities increased for the nine months ended June 30, 2005 as compared to the nine months ended June 30, 2004, primarily due to favorable net changes in working capital. Net cash used in investing activities increased in 2004 due primarily to increases in short-term and other investments, partially

- 40 -

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

offset by a decline in capital spending. Capital spending in the fiscal 2004 period included approximately $35 million in acquisitions of certain oil and gas properties located in Texas. The net cash used in financing activities increased in 2005 primarily as a result of lower amounts of common stock issued under both the continuous equity offering program and the Long-Term Incentive Compensation Plan in fiscal 2005 compared to fiscal 2004.

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

Balance Sheet Variations

Total assets at June 30, 2005 increased $107.2 million as compared to September 30, 2004 primarily due to the higher seasonal levels in cash and cash equivalents, short-term investments and customer accounts receivable for the Gas Distribution segment, driven in part by higher billed commodity prices. These items were offset, in part, by lower seasonal levels of gas in storage at the Gas Distribution segment and decreases in other current assets, primarily derivative financial instruments. The Company's noncurrent regulatory assets and deferred credits and other liabilities also increased, primarily due to higher liability accruals of certain utility environmental costs that are also deferred as regulatory assets recoverable under utility tariffs. The Company's increase in current liabilities was driven primarily by seasonal increases in the gas inventory replenishment liability (temporary LIFO liquidation credit) and accounts payable. These items were partially offset by a decline in commercial paper. Contributing to the Company's capitalization increase were primarily fiscal year-to-date earnings and common stock issued through its Direct Purchase and Investment and Long-Term Incentive Compensation plans.

Total assets at June 30, 2005 increased $147.0 million compared to June 30, 2004 primarily as a result of increases in short-term investments, gas in storage at the Midstream Services and Retail Services segments and capital investments in utility plant and oil and gas properties. The Company's noncurrent regulatory assets and deferred credits and other liabilities also increased, primarily due to higher liability accruals of certain utility environmental costs that are also deferred as regulatory assets recoverable under utility tariffs. The Company's current liabilities increased due to increases in the gas inventory replenishment liability (temporary LIFO liquidation credit) driven by higher commodity prices, and increases in accrued taxes and derivative financial instruments. The Company's capitalization increased due to common stock issued primarily through its Direct Purchase and Investment and Long-Term Incentive Compensation plans.

Changes in Debt Securities

As part of its continuing program to reduce long-term financing costs and manage interest rate risk, in January of 2005, Peoples Gas entered into agreements to issue $50 million principal amount of Series RR first mortgage bonds due June 1, 2035 in connection with a tax-exempt municipal financing through the Illinois Finance Authority. The bonds were issued on June 1, 2005 and are in Term Rate mode at a rate of 4.30% until June 1, 2016. Proceeds from the issuance of the Series RR bonds were used to redeem $50 million principal amount of its Series FF first mortgage bonds at a price of 102% of principal, plus accrued interest.

On July 12, 2005, Peoples Gas entered into a 5-year syndicated revolving credit agreement with eleven financial institutions that provides backup for Peoples Gas' seasonal commercial paper borrowing program. The maximum amount that may be borrowed under the credit agreement is $250 million. This replaces the previous $200 million credit facility that was scheduled to expire in August 2005.

Financial Sources

In addition to cash generated internally by operations, as of June 30, 2005, the Company had committed credit facilities of $425 million (Peoples Energy, $225 million; Peoples Gas, $200 million). These various facilities primarily support the Company's ability to borrow using commercial paper. As of June 30, 2005, $209.8 million of Peoples Energy's and all of Peoples Gas' facilities were available. The Peoples Energy credit facility expires in March 2007 and is expected to be renewed. North Shore Gas intends to meet its future short-term borrowing requirements through loans from Peoples Energy or Peoples Gas.

- 41 -

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

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%. At June 30, 2005, the Company's ratio of total debt-to-total debt plus equity was 51%, compared to 50% a year ago. The current debt-to-total capital ratio for Peoples Gas is 44%.

In addition to the committed credit facilities discussed above, the Company has an uncommitted line of credit and letter of credit backup of $25.0 million, of which $21.6 million was unused as of June 30, 2005. 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, 2005, Peoples Gas and North Shore Gas had no loans outstanding from Peoples Energy.

Peoples Gas and North Shore Gas also have the ability to loan between themselves as utilities up to $50.0 million. As of June 30, 2005, no loans were outstanding between Peoples Gas and North Shore Gas.

The current credit ratings for the Company, Peoples Gas and North Shore Gas have not changed since the filing of the September 30, 2004 Annual Report on Form 10-K.

Changes in Equity Securities

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. Since inception of this plan, the Company has issued 1,235,700 shares with proceeds, net of issuance costs, totaling $47.9 million. No shares have been issued subsequent to March 31, 2004. Common stock activity related to various Company plans is summarized in the table below.

	Three Months Ended		Nine Months Ended
	June 30, 2005		June 30, 2005
(Dollars in Thousands)	Shares	Dollars	Shares	Dollars
Shares outstanding - beginning of period	37,968,496	$ 390,283	37,733,894	$ 381,168
Shares issued:
Employee Stock Purchase Plan	6,304	242	12,228	479
Long-Term Incentive Compensation
Plan - net	60,631	2,499	169,251	6,298
Directors Deferred Compensation Plan	-	-	3,971	151
Direct Purchase and Investment Plan	63,131	2,568	179,218	7,496
Total activity for the period	130,066	5,309	364,668	14,424

Shares outstanding - end of period	38,098,562	$ 395,592	38,098,562	$ 395,592

Financial Uses

Capital Spending.
In the nine-month period ended June 30, 2005, the Company spent $113.4 million on capital projects. The Gas Distribution segment spent $54.5 million on property, plant and equipment of which $48.8 million was spent by Peoples Gas and $5.7 million was spent by North Shore Gas. The majority of the remaining $58.9 million was spent by the Oil and Gas Production segment, which spent $56.7 million on drilling projects, acquisitions and the exploitation of existing assets. Management currently estimates that fiscal 2005 capital spending will total approximately $168 million, with about $78 million of expenditures estimated for the Oil and Gas Production segment and most of the remaining balance targeted for the Gas Distribution segment. In April 2005, the Oil and Gas Production segment acquired properties in South Texas for approximately $6 million that are expected to provide future drilling opportunities.

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

Dividends
. On February 4, 2005, the Company's Board of Directors voted to raise the regular quarterly dividend on the Company's common stock from 54 cents per share to 54 1/2 cents per share. The first payment at this new level was made on April 15, 2005 to shareholders of record at the close of business on March 22, 2005.

Commitments, Contractual Obligations and Uncertainties

Off-balance Sheet Arrangements.
Off-balance sheet debt at June 30, 2005 and 2004 consists of the Company's pro rata share of nonrecourse debt of various equity investments, including Trigen-Peoples District Energy Company (Trigen-Peoples) ($14.7 million and $15.1 million), EnerVest ($2.9 million and $2.5 million) and Elwood ($176.2 million and $184.0 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 $52.9 million in guarantees and $11.5 million in letters of credit at June 30, 2005.

Contractual Obligations.
Since the filing of the September 30, 2004 Annual Report on Form 10-K there have been no significant changes to contractual obligations with the exception of the following transactions. The Oil and Gas Production segment has entered into a long term drilling contract to drill wells in East Texas. The term of the contract is one year and the total commitment exceeds $4 million. The Midstream Services segment has entered into a 10-year agreement with a pipeline company for natural gas transportation services totaling $2 million per year. In July of 2005 the Company increased its maximum commitment to lend funds to Elwood under the working capital credit agreement from $5 million to $10 million. The primary term of the credit agreement ends in July 2006, but the agreement automatically extends for an additional year, and year to year thereafter, unless terminated by any party upon 30 day notice.

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 6A 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 the Denver Site. 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 6B 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 year 2004, 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. On March 21, 2005, the AG and Chicago filed separate lawsuits against the Company and several of its subsidiaries alleging violations against its customers under certain state and city regulations, respectively. The Company has also received a subpoena from the U.S. Commodity Futures trading Commission. (See Note 7 of the Notes to Consolidated Financial Statements.)

Other Litigation.
See Note 8 of the Notes to Consolidated Financial Statements for discussions regarding proceedings related to a municipal tax audit conducted by the City of Chicago, a royalty dispute involving the Oil and Gas Production segment and the Ford City incident.

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

Indenture Restrictions

North Shore Gas' indenture relating to its first mortgage bonds contains provisions and covenants restricting the payment of cash dividends and the purchase or redemption of capital stock. At June 30, 2005, such restrictions amounted to $6.9 million of North Shore Gas' total retained earnings of $84.3 million.

Peoples District Energy Corporation owns a 50% equity interest in Trigen-Peoples. The Construction and Term Loan Agreement between Trigen-Peoples and Prudential Insurance Company of America related to Trigen-Peoples' project financing prohibits any distribution that would result in the partners' total capital account in Trigen-Peoples being less than $7.0 million. At June 30, 2005, the partners' capital account was $7.7 million. The Construction and Term Loan Agreement also prohibits any distribution unless the partnership's debt service coverage ratio for the four fiscal quarters prior to the distribution was at least 1.25 to 1.0. Trigen-Peoples' debt service coverage ratios for the last four fiscal quarters starting with the most recent quarter were 1.86 to 1.0, 1.96 to 1.0, 2.02 to 1.0, and 1.97 to 1.0.

Peoples Energy Resources Company, LLC owns a 50% 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 5, 2005 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.

PEOPLES GAS AND NORTH SHORE GAS DISCUSSIONS

The financial results of Peoples Gas and North Shore Gas are reported primarily within the Gas Distribution segment. A portion of each companies' results are included in the Corporate and Other segment, while Peoples Gas' hub activity is included in the Midstream Services segment. Operating income (GAAP) and ongoing operating income (non-GAAP) by business segment for Peoples Gas and North Shore Gas is presented below.

	The Peoples Gas Light and Coke Company				North Shore Gas Company
	Gas	Midstream			Gas
(In Thousands)	Distribution	Services	Corporate	Total	Distribution	Corporate	Total
For the Three Months Ended
June 30, 2005 (GAAP)	$ 12,556	$ 987	$ (2,506)	$ 11,037	$ 2,964	$ (363)	$ 2,601
June 30, 2005 (non-GAAP) (1)	12,556	987	(2,678)	10,865	2,964	(357)	2,607
June 30, 2004	8,805	886	(3,689)	6,002	2,644	(467)	2,177

For the Nine Months Ended
June 30, 2005 (GAAP)	$ 115,162	$ 5,834	$ (14,801)	$ 106,195	$ 23,736	$ (1,435)	$ 22,301
June 30, 2005 (non-GAAP) (2)	115,162	5,834	(6,506)	114,490	23,736	(867)	22,869
June 30, 2004	119,487	4,060	(9,680)	113,867	24,093	(1,226)	22,867

(1) 2005 ongoing income (non-GAAP) is defined as GAAP operating income adjusted to exclude the effects of a pension expense related restructuring costs of $(0.1) million and $6,000 at Peoples Gas and North Shore Gas, respectively. See Item 2- MD&A- Executive Summary for a discussion of management's use of non-GAAP financial measures and a reconciliation of 2005 GAAP and non-GAAP earnings.

(2) 2005 ongoing income (non-GAAP) is defined as GAAP operating income adjusted to exclude the effects of a pension expense related restructuring costs of $8.3 million and $0.6 million at Peoples Gas and North Shore Gas, respectively. See Item 2- MD&A- Executive Summary for a discussion of management's use of non-GAAP financial measures and a reconciliation of 2005 GAAP and non-GAAP earnings.

The following discussions supplement Peoples Gas' and North Shore Gas' information included in Liquidity and Capital Resources and in the Company's Gas Distribution segment discussion within this MD&A.

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

Peoples Gas Discussion

GAAP net income for Peoples Gas for the three and nine months ended June 30, 2005 was $3.9 million and $56.9 million, respectively, compared to $2.5 million and $63.5 million for the three and nine months ended June 30, 2004, respectively. Excluding pension-related charges ($5.0 million, after tax, for the nine months ended June 30, 2005) resulting from the fiscal year 2004 organizational restructuring, on-going net income (non-GAAP) at Peoples Gas for the nine months ended June 30, 2005 was $61.9 million.

Revenues for the three- and nine-month periods ended June 30, 2005 increased $17.0 million and $135.4 million, respectively, compared with the same year ago periods. The main reason for the increase was due to the impact on revenues of higher gas prices ($20.0 million and $163.0 million). Partially offsetting these effects were lower revenues resulting from a decrease in deliveries due to weather ($3.0 million and $25.0 million) that was 4% and 3% warmer compared with the same year-ago periods, respectively. GAAP operating income for the three- and nine-month periods ended June 30, 2005 increased $5.0 million and decreased $7.7 million, respectively, compared with the same year-ago periods. Operating income for the three-and nine- month periods was favorably impacted by decreased labor costs related to the organizational restructuring ($0.8 million and $6.4 million, respectively) and a decrease in depreciation expense ($4.3 million and $4.0 million) primarily due to the Commission Depreciation Order. Negative impacts on fiscal 2005 three- and nine-month period results include lower deliveries resulting from warmer weather ($0.5 million and $4.0 million) and lower weather-normalized deliveries ($0.5 million and $6.0 million).In addition, the restructuring related pension charge decreased operating income for the nine-month period by $8.3 million.

Interest expense for the three- and nine-month periods increased $1.1 million and $2.5 million, respectively, compared with the same year ago periods primarily due to higher interest rates.

North Shore Gas Discussion

GAAP net income for North Shore Gas for the three and nine months ended June 30, 2005 was $1.2 million and $12.4 million, respectively, compared to $0.9 million and $12.7 million for the three and nine months ended June 30, 2004, respectively. Excluding pension-related charges ($0.3 million, after tax, for the nine months ended June 30, 2005) resulting from the fiscal year 2004 organizational restructuring, on-going net income (non-GAAP) at North Shore Gas for the nine months ended June 30, 2005 was $12.7 million.

Revenues for the three- and nine-month periods ended June 30, 2005 increased $5.3 million and $35.4 million, respectively, compared with the previous periods. The main reason for the increase was due to the impact on revenues of higher gas prices ($5.0 million and $40.0 million). Partially offsetting these effects was lower revenues resulting from decrease in deliveries due to weather ($0.5 million and $4.0 million) that was 4% and 3% warmer compared with the same year ago periods, respectively. GAAP operating income for the three- and nine-month periods ended June 30, 2005 increased $0.4 million and decreased $0.6 million, respectively, compared with the same year-ago periods. Fiscal 2005 results for both periods were positively impacted by a decrease in depreciation expense ($1.0 million and $1.1 million) primarily due to the Commission Depreciation Order. Fiscal 2005 results were both negatively impacted by lower deliveries resulting from warmer weather ($0.1 million and $0.5 million for the three- and nine-month periods, respectively). For the fiscal 2005 nine-month period the restructuring-related pension charge of $0.6 million also reduced operating income.

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

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)	2005	2004	2005	2004	Ended	Ended
Gas Distribution revenues:
Sales
Residential	$ 163,000	$ 149,910	$ 990,717	$ 885,293	$ 13,090	$ 105,424
Commercial	26,001	23,540	157,252	139,681	2,461	17,571
Industrial	3,505	3,775	25,770	21,489	(270)	4,281
Total sales	192,506	177,225	1,173,739	1,046,463	15,281	127,276

Transportation
Residential	5,439	5,559	26,981	26,978	(120)	3
Commercial	7,444	7,306	36,841	35,572	138	1,269
Industrial	3,329	3,221	14,176	13,757	108	419
Contract pooling	4,847	3,633	15,382	11,056	1,214	4,326
Total transportation	21,059	19,719	93,380	87,363	1,340	6,017
Other Gas Distribution revenues	4,204	3,989	11,083	11,359	215	(276)
Total Gas Distribution revenues	217,769	200,933	1,278,202	1,145,185	16,836	133,017
Less: Gas costs	114,628	98,929	790,783	668,426	15,699	122,357
Gross margin ⁽¹⁾	103,141	102,004	487,419	476,759	1,137	10,660
Less: Revenue taxes and surcharges	21,181	20,162	122,344	113,679	1,019	8,665
Environmental costs recovered	4,161	2,933	26,105	14,066	1,228	12,039
Net margin ⁽¹⁾	$ 77,799	$ 78,909	$ 338,970	$ 349,014	$ (1,110)	$ (10,044)

Gas Distribution deliveries (MDth):
Gas sales
Residential	12,114	12,705	85,713	90,925	(591)	(5,212)
Commercial	2,248	2,305	14,569	15,449	(57)	(880)
Industrial	332	419	2,546	2,523	(87)	23
Total gas sales	14,694	15,429	102,828	108,897	(735)	(6,069)

Transportation
Residential	2,959	3,108	17,677	18,766	(149)	(1,089)
Commercial	4,704	6,127	30,520	32,872	(1,423)	(2,352)
Industrial	3,558	3,551	14,510	14,891	7	(381)
Total transportation	11,221	12,786	62,707	66,529	(1,565)	(3,822)
Total Gas Distribution deliveries	25,915	28,215	165,535	175,426	(2,300)	(9,891)

Gross margin per Dth delivered	$ 3.98	$ 3.62	$ 2.94	$ 2.72	$ 0.36	$ 0.22
Net margin per Dth delivered	$ 3.00	$ 2.80	$ 2.05	$ 1.99	$ 0.20	$ 0.06
Average cost per Dth of gas sold	$ 7.80	$ 6.41	$ 7.69	$ 6.14	$ 1.39	$ 1.55

Actual heating degree days (HDD)	664	692	5,827	6,002	(28)	(175)
Normal heating degree days⁽²⁾	774	752	6,307	6,307
Actual heating degree days as a percent
of normal (actual/normal)	86	92	92	95

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

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)	2005	2004	2005	2004	Ended	Ended
Gas Distribution revenues:
Sales
Residential	$ 30,114	$ 26,099	$ 184,889	$ 156,330	$ 4,015	$ 28,559
Commercial	4,856	4,084	30,397	25,607	772	4,790
Industrial	891	729	7,315	5,902	162	1,413
Total sales	35,861	30,912	222,601	187,839	4,949	34,762

Transportation
Residential	318	319	1,413	1,471	(1)	(58)
Commercial	1,270	1,162	5,440	5,258	108	182
Industrial	637	620	2,216	2,197	17	19
Contract pooling	429	281	1,465	1,079	148	386
Total transportation	2,654	2,382	10,534	10,005	272	529
Other Gas Distribution revenues	442	384	1,066	981	58	85
Total Gas Distribution revenues	38,957	33,678	234,201	198,825	5,279	35,376
Less: Gas costs	24,201	19,708	165,826	131,329	4,493	34,497
Gross margin ⁽¹⁾	14,756	13,970	68,375	67,496	786	879
Less: Revenue taxes and surcharges	2,203	2,095	12,710	11,869	108	841
Environmental costs recovered	438	119	1,622	1,076	319	546
Net margin ⁽¹⁾	$ 12,115	$ 11,756	$ 54,043	$ 54,551	$ 359	$ (508)

Gas Distribution deliveries (MDth):
Gas sales
Residential	2,622	2,574	17,824	18,346	48	(522)
Commercial	451	426	3,054	3,149	25	(95)
Industrial	89	84	780	779	5	1
Total gas sales	3,162	3,084	21,658	22,274	78	(616)

Transportation
Residential	121	128	730	786	(7)	(56)
Commercial	1,023	1,092	5,411	5,619	(69)	(208)
Industrial	1,203	1,313	4,214	4,427	(110)	(213)
Total transportation	2,347	2,533	10,355	10,832	(186)	(477)
Total Gas Distribution deliveries	5,509	5,617	32,013	33,106	(108)	(1,093)

Gross margin per Dth delivered	$ 2.68	$ 2.49	$ 2.14	$ 2.04	$ 0.19	$ 0.10
Net margin per Dth delivered	$ 2.20	$ 2.09	$ 1.69	$ 1.65	$ 0.11	$ 0.04
Average cost per Dth of gas sold	$ 7.65	$ 6.39	$ 7.66	$ 5.90	$ 1.26	$ 1.76

Actual heating degree days (HDD)	664	692	5,827	6,002	(28)	(175)
Normal heating degree days⁽²⁾	774	752	6,307	6,307
Actual heating degree days as a percent
of normal (actual/normal)	86	92	92	95

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FORWARD-LOOKING INFORMATION

This document contains statements that may be considered forward-looking, such as: management's expectations and outlook for earnings, 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:

adverse decisions in proceedings before the Commission concerning the prudence review of the utility subsidiaries' gas purchases;
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 gas prices on cost of gas supplies, accounts receivable and the provision for uncollectible accounts, interest expense and earnings from the Oil and Gas Production segment;
adverse resolution of material litigation;
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;
the Company's success in completing anticipated asset sale transactions prior to the end of fiscal year 2005.
operational factors affecting the Company's Gas Distribution, Oil and Gas Production and Power Generation segments;
Aquila's financial ability to perform under its PSAs with Elwood;
drilling and production risks and the inherent uncertainty of oil and gas reserve estimates;
weather related energy demand; and
terrorist activities.

Also, projections to future periods of the effectiveness of internal control over financial reporting are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 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 document are based upon information presently available, and the Company, Peoples Gas and North Shore Gas assume no obligation to update any forward-looking statements.

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ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

Quantitative and qualitative disclosures about market risk are reported under Note 2 of the Notes to Consolidated Financial Statements.

ITEM 4. Controls and Procedures

In accordance with Exchange Act Rules 13a-15 and 15d-15, the Company, Peoples Gas and North Shore Gas carried out an evaluation, under the supervision and with the participation of management, including Thomas M. Patrick, our principal executive officer, and Thomas A. Nardi, our principal financial officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report.

Thomas M. Patrick and Thomas A. Nardi concluded that our disclosure controls and procedures were effective for the period covered by this report on Form 10-Q to provide reasonable assurance that information required to be disclosed and filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. There have been no changes in internal control over financial reporting that occurred during the period covered by this report on Form 10-Q that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

In adherence with Section 404 of the Sarbanes-Oxley Act of 2002, the Company is in the process of performing its assessment of the effectiveness of internal control over financial reporting. In the course of performing the assessment, the Company has identified certain internal control deficiencies, none of which are considered material weaknesses. The Company is taking the appropriate steps to make the internal control improvements necessary to remediate these deficiencies in a timely manner. Management will consider the results of the remediation efforts and related testing as part of its assessment of the effectiveness of internal control over financial reporting as of September 30, 2005.

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Part II - Other Information

Item 1. Legal Proceedings

See Note 6 of the Notes to Consolidated Financial Statements - Environmental Matters for a discussion pertaining to environmental matters, Note 7 of the Notes to Consolidated Financial Statements - Gas Charge Reconciliation Proceedings and Related Matters pertaining to proceedings at the Commission regarding the prudency of gas purchases by Peoples Gas and North Shore Gas, and Note 8 of the Notes to Consolidated Financial Statements - Other Litigation for a discussion of other events and proceedings, which notes are incorporated herein by reference.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 5. Other Information

The following information is being reported timely in this Form 10-Q instead of being reported under Item 1.01 of Form 8-K. On August 3, 2005, the Company's Board of Directors elected Thomas A. Nardi, Senior Vice President and Chief Financial Officer of the Company and its subsidiaries, to the position of Executive Vice President and Chief Financial Officer, and approved an increase in Mr. Nardi's annual base salary, effective retroactively to August 1, 2005, from $320,000 to $350,000.

The following information is being reported timely in this Form 10-Q instead of being reported under Item 5.03 of Form 8-K. On August 3, 2005, the Board of Directors amended Section 4.1 of the By-Laws of the Company to provide that the officers elected by the Board of Directors shall include such number of Executive Vice Presidents as the Board may decide upon. A copy of the By-Laws as amended is attached to this Form 10-Q as Exhibit 3.

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Part II - Other Information

Item 6. Exhibits

	Peoples Energy Corporation :

		Exhibit
		Number	Description of Document

		3	By-Laws of the Company, as amended August 3, 2005.

		10(a)	Severance Agreement between the Company and Desiree G. Rogers dated as of April 22, 2005.

		10(b)	Retainer Agreement between the Company and Theodore R. Tetzlaff dated as of June 30, 2005.

		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.

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Part II - Other Information

The Peoples Gas Light and Coke Company :

	Exhibit
	Number	Description of Document

	10(b)	Retainer Agreement between the Company and Theodore R. Tetzlaff dated as of June 30, 2005.

	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.

North Shore Gas Company :

	Exhibit
	Number	Description of Document

	10(b)	Retainer Agreement between the Company and Theodore R. Tetzlaff dated as of June 30, 2005.

	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.

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SIGNATURES


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 9, 2005		By: /s/ THOMAS A. NARDI
(Date)		Thomas A. Nardi
		Executive 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.

		The Peoples Gas Light and Coke Company
		(Registrant)

August 9, 2005		By: /s/ THOMAS A. NARDI
(Date)		Thomas. A. Nardi
		Executive 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 9, 2005		By: /s/ THOMAS A. NARDI
(Date)		Thomas. A. Nardi
		Executive Vice President and Chief Financial Officer

		(Same as above)
		Principal Financial Officer

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PEOPLES GAS LIGHT & COKE CO 10-Q