Edgar Filing: CHESAPEAKE UTILITIES CORP

cpk_3qq.htm

United States

Securities and Exchange Commission

Washington, D.C. 20549

_______________________________

FORM 10-Q

[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended: September 30, 2008

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

For the transition period from ______ to ______

Commission File Number: 001-11590

Chesapeake Utilities Corporation

(Exact name of registrant as specified in its charter)

Delaware	51-0064146
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

909 Silver Lake Boulevard, Dover, Delaware 19904

(Address of principal executive offices, including Zip Code)

(302) 734-6799

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company filer. See definitions of “accelerated filer” and “large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer [ ] Accelerated filer [X] Non-accelerated filer [ ] Smaller reporting company [ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]

Common Stock, par value $0.4867 — 6,820,050 shares outstanding as of October 31, 2008.

Table of Contents

PART I — FINANCIAL INFORMATION			1
Item 1. Financial Statements			1
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations			22
Item 3. Quantitative and Qualitative Disclosures about Market Risk			45
Item 4. Controls and Procedures			46
PART II — OTHER INFORMATION			47
Item 1. Legal Proceedings			47
Item 1A. Risk Factors			47
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			47
Item 3. Defaults upon Senior Securities			48
Item 4. Submission of Mattters to a Vote of Security Holders			48
Item 5. Other Information			48
Item 6. Exhibits			48
SIGNATURES			49

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PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Income (Unaudited)


For the Three Months Ended September 30,	2008			2007
Operating Revenues	$	49,698,013		$	41,418,718

Operating Expenses
Cost of sales, excluding costs below		33,650,630			25,826,902
Operations		10,341,082			10,530,152
Maintenance		655,889			512,201
Depreciation and amortization		2,267,471			2,144,926
Other taxes		1,612,548			1,418,903
Total operating expenses		48,527,620			40,433,084

Operating Income		1,170,393			985,634

Other loss, net of other expenses		(91,631	)		(13,481	)

Interest charges		1,487,812			1,695,597

Loss Before Income Taxes		(409,050	)		(723,444	)

Income tax benefit		(210,752	)		(363,474	)

Loss from Continuing Operations		(198,298	)		(359,970	)

Gain from discontinued operations, net of income tax expense of $0 and $4,249		-			4,072

Net Loss	$	(198,298	)	$	(355,898	)

Weighted Average Shares Outstanding:
Basic		6,815,886			6,754,650
Diluted		6,817,536			6,754,650

Loss Per Share of Common Stock:
Basic:
From continuing operations	$	(0.03	)	$	(0.05	)
From discontinued operations		-			-
Net Loss	$	(0.03	)	$	(0.05	)

Diluted:
From continuing operations	$	(0.03	)	$	(0.05	)
From discontinued operations		-			-
Net Loss	$	(0.03	)	$	(0.05	)

Cash Dividends Declared Per Share of Common Stock:	$	0.305		$	0.295

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Income (Unaudited)


For the Nine Months Ended September 30,	2008			2007
Operating Revenues	$	219,028,473		$	187,447,528

Operating Expenses
Cost of sales, excluding costs below		153,170,526			123,991,093
Operations		31,853,299			31,370,800
Terminated acquisition costs		1,239,628			-
Maintenance		1,644,438			1,657,219
Depreciation and amortization		6,695,479			6,828,243
Other taxes		4,884,555			4,302,901
Total operating expenses		199,487,925			168,150,256

Operating Income		19,540,548			19,297,272

Other income (loss), net of other expenses		(10,535	)		277,194

Interest charges		4,469,918			4,889,548

Income Before Income Taxes		15,060,095			14,684,918

Income taxes		5,865,127			5,545,725

Income from Continuing Operations		9,194,968			9,139,193

Loss from discontinued operations, net oftax benefit of $0 and $11,995		-			(22,212	)

Net Income	$	9,194,968		$	9,116,981

Weighted Average Common Shares Outstanding:
Basic		6,807,919			6,732,800
Diluted		6,922,105			6,845,725

Earnings Per Share of Common Stock:
Basic
From continuing operations	$	1.35		$	1.35
From discontinued operations		-			-
Net Income	$	1.35		$	1.35

Diluted
From continuing operations	$	1.34		$	1.34
From discontinued operations		-			-
Net Income	$	1.34		$	1.34

Cash Dividends Declared Per Share of Common Stock:	$	0.91		$	0.88

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

For the Nine Months Ended September 30,	2008			2007
Operating Activities
Net Income	$	9,194,968		$	9,116,981
Depreciation and amortization		6,695,479			6,828,244
Depreciation and accretion included in other costs		1,635,618			2,535,385
Deferred income taxes, net		6,101,985			1,580,609
Gain on sale of assets		-			(204,882	)
Unrealized loss (gain) on commodity contracts		32,927			(794,745	)
Unrealized loss (gain) on investments		227,059			(206,309	)
Employee benefits		102,197			728,214
Share based compensation		538,986			836,888
Other, net		4,014			(1,738	)
Changes in assets and liabilities:
Sale (purchase) of investments		(132,464	)		172,942
Accounts receivable and accrued revenue		18,551,078			2,180,615
Propane inventory, storage gas and other inventory		(7,269,841	)		(1,473,887	)
Regulatory assets		223,456			212,735
Prepaid expenses and other current assets		(8,204,433	)		(1,955,877	)
Other deferred charges		(404,215	)		(1,801,079	)
Long-term receivables		164,560			59,799
Accounts payable and other accrued liabilities		(6,888,622	)		(1,184,523	)
Income taxes receivable		(3,237,459	)		(1,480,312	)
Accrued interest		841,623			959,191
Customer deposits and refunds		(1,236,384	)		1,392,738
Accrued compensation		(692,206	)		157,000
Regulatory liabilities		(2,842,423	)		2,185,361
Other liabilities		17,211			(151,422	)
Net cash provided by operating activities		13,423,114			19,691,928

Investing Activities
Property, plant and equipment expenditures		(23,724,330	)		(22,877,580	)
Proceeds from sale of assets		-			204,882
Environmental expenditures		(402,530	)		(166,172	)
Net cash used by investing activities		(24,126,860	)		(22,838,870	)

Financing Activities
Common stock dividends		(5,877,515	)		(5,245,496	)
Issuance of stock for Dividend Reinvestment Plan		15,338			244,695
Change in cash overdrafts due to outstanding checks		1,419,026			582,701
Net borrowing under line of credit agreements		16,193,096			5,001,601
Repayment of long-term debt		(1,020,130	)		(1,020,183	)
Net cash provided (used) by financing activities		10,729,815			(436,682	)

Net Increase (decrease) in Cash and Cash Equivalents		26,069			(3,583,624	)
Cash and Cash Equivalents — Beginning of Period		2,592,801			4,488,367
Cash and Cash Equivalents — End of Period	$	2,618,870		$	904,743

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Stockholders' Equity (Unaudited)

	For the Nine Months Ended September 30, 2008			For the Twelve Months Ended December 31, 2007
Common Stock
Balance — beginning of period	$	3,298,473		$	3,254,998
Dividend Reinvestment Plan		3,541			17,197
Retirement Savings Plan		1,073			14,388
Conversion of debentures		2,659			3,945
Stock-based compensation		12,165			7,945
Balance — end of period	$	3,317,911		$	3,298,473

Additional Paid-in Capital
Balance — beginning of period	$	65,591,552		$	61,960,220
Dividend Reinvestment Plan		218,451			1,121,190
Retirement Savings Plan		66,704			934,295
Conversion of debentures		90,211			133,839
Stock-based compensation		289,605			1,442,008
Tax benefit of warrants		50,244			-
Balance — end of period	$	66,306,767		$	65,591,552

Retained Earnings
Balance — beginning of period	$	51,538,194		$	46,270,884
Net income		9,194,968			13,197,710
Cash dividends declared		(6,165,690	)		(7,930,400	)
Balance — end of period	$	54,567,472		$	51,538,194

Accumulated Other Comprehensive Loss
Balance — beginning of period	$	(851,674	)	$	(334,550	)
Loss on funded status of Employee Benefit Plans, net of tax		-			(517,124	)
Balance — end of period	$	(851,674	)	$	(851,674	)

Deferred Compensation Obligation
Balance — beginning of period	$	1,403,922		$	1,118,509
New deferrals		125,793			285,413
Balance — end of period	$	1,529,715		$	1,403,922

Treasury Stock
Balance — beginning of period	$	(1,403,922	)	$	(1,118,509	)
New deferrals related to compensation obligation		(125,793	)		(285,413	)
Purchase of treasury stock (1)		(52,800	)		(29,771	)
Sale and distribution of treasury stock (2)		52,800			29,771
Balance — end of period	$	(1,529,715	)	$	(1,403,922	)


Total Stockholders’ Equity	$	123,340,476		$	119,576,545

(1)Amount includes shares purchased in the open market for the Company's Rabbi Trust to secure its obligations under the Company's Deferred Compensation Plan.
(2)Amount includes shares issued to the Company's Rabbi Trust as an obligation under the Deferred Compensation Plan.

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

Assets	September 30, 2008			December 31, 2007
Property, Plant and Equipment
Natural gas	$	299,398,970		$	289,706,066
Propane		50,760,867			48,506,231
Advanced information services		1,422,641			1,157,808
Other plant		10,608,170			8,567,833
Total property, plant and equipment		362,190,648			347,937,938

Less: Accumulated depreciation and amortization		(98,794,111	)		(92,414,289	)
Plus: Construction work in progress		12,393,799			4,899,608
Net property, plant and equipment		275,790,336			260,423,257

Investments		1,814,676			1,909,271

Current Assets
Cash and cash equivalents		2,618,870			2,592,801
Accounts receivable (less allowance for uncollectible accounts of $929,454 and $952,074, respectively)		56,135,547			72,218,191
Accrued revenue		2,797,040			5,265,474
Propane inventory, at average cost		8,900,052			7,629,295
Other inventory, at average cost		1,602,279			1,280,506
Regulatory assets		1,117,447			1,575,072
Storage gas prepayments		11,719,481			6,042,169
Income taxes receivable		4,525,141			1,237,438
Deferred income taxes		1,233,635			2,155,393
Prepaid expenses		11,746,016			3,496,517
Mark-to-market energy assets		11,978,970			7,812,456
Other current assets		146,849			146,253
Total current assets		114,521,327			111,451,565

Deferred Charges and Other Assets
Goodwill		674,451			674,451
Other intangible assets, net		167,719			178,073
Pension		0			0
Long-term receivables		576,120			740,680
Regulatory assets		2,720,069			2,539,235
Other deferred charges		4,007,434			3,640,480
Total deferred charges and other assets		8,145,793			7,772,919




Total Assets	$	400,272,132		$	381,557,012

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

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Capitalization and Liabilities	September 30, 2008			December 31, 2007
Capitalization
Stockholders' equity
Common Stock, par value $0.4867 per share(authorized 12,000,000 shares)	$	3,317,911		$	3,298,473
Additional paid-in capital		66,306,767			65,591,552
Retained earnings		54,567,472			51,538,194
Accumulated other comprehensive loss		(851,674	)		(851,674	)
Deferred compensation obligation		1,529,715			1,403,922
Treasury stock		(1,529,715	)		(1,403,922	)
Total stockholders' equity		123,340,476			119,576,545

Long-term debt, net of current maturities		63,142,637			63,255,636
Total capitalization		186,483,113			182,832,181

Current Liabilities
Current portion of long-term debt		6,656,364			7,656,364
Short-term borrowing		63,276,066			45,663,944
Accounts payable		45,835,034			54,893,071
Customer deposits and refunds		8,800,536			10,036,920
Accrued interest		1,707,127			865,504
Dividends payable		2,079,324			1,999,343
Accrued compensation		2,714,936			3,400,112
Regulatory liabilities		3,502,320			6,300,766
Mark-to-market energy liabilities		11,358,082			7,739,261
Other accrued liabilities		5,341,854			2,500,542
Total current liabilities		151,271,643			141,055,827

Deferred Credits and Other Liabilities
Deferred income taxes		33,976,112			28,795,885
Deferred investment tax credits		245,991			277,698
Regulatory liabilities		915,624			1,136,071
Environmental liabilities		555,748			835,143
Other pension and benefit costs		2,547,449			2,513,030
Accrued asset removal cost		20,398,012			20,249,948
Other liabilities		3,878,440			3,861,229
Total deferred credits and other liabilities		62,517,376			57,669,004

Other Commitments and Contingencies (Note 4)


Total Capitalization and Liabilities	$	400,272,132		$	381,557,012

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

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Notes to Condensed Consolidated Financial Statements

1.	Basis of Presentation

References in this document to “the Company,” “Chesapeake,” “we,” “us” and “our” are intended to mean Chesapeake Utilities Corporation and its subsidiaries.

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and United States of America Generally Accepted Accounting Principles (“GAAP”). In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in the Company’s latest Annual Report on Form 10-K filed with the SEC on March 10, 2008. In the opinion of management, these statements reflect normal recurring adjustments that are necessary for a fair presentation of the Company’s results of operations, financial position and cash flows for the interim periods presented.

2.	Comprehensive Income

Comprehensive income contains items that are excluded from net income and recorded directly to stockholders’ equity. For the first nine months of 2008 and 2007, Chesapeake did not have any adjustments to comprehensive income that are required to be reported by Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 130, “Reporting Comprehensive Income.” Accumulated other comprehensive loss was $851,674 at September 30, 2008 and December 31, 2007.

3.	Calculation of Earnings Per Share

	Three Months Ended						Nine Months Ended
For the Periods Ended September 30,	2008			2007			2008		2007
Calculation of Basic Earnings Per Share:
Net Income (Loss)	$	(198,298	)	$	(355,898	)	$	9,194,968	$	9,116,981
Weighted average shares outstanding		6,815,886			6,754,650			6,807,919		6,732,800
Basic Earnings Per Share	$	(0.03	)	$	(0.05	)	$	1.35	$	1.35

Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income (Loss)	$	(198,298	)	$	(355,898	)	$	9,194,968	$	9,116,981
Effect of 8.25% Convertible debentures (1)		-			-			67,355		72,312
Adjusted numerator — Diluted	$	(198,298	)	$	(355,898	)	$	9,262,323	$	9,189,293

Reconciliation of Denominator:
Weighted shares outstanding — Basic		6,815,886			6,754,650			6,807,919		6,732,800
Effect of dilutive securities (1):
Restricted Stock		1,650			-			9,099		-
8.25% Convertible debentures		-			-			105,087		112,925
Adjusted denominator — Diluted		6,817,536			6,754,650			6,922,105		6,845,725

Diluted Earnings (Loss) Per Share	$	(0.03	)	$	(0.05	)	$	1.34	$	1.34

(1) Amounts associated with conversion of securities that result in an anti-dilutive effect on earnings per share are not included in this calculation.

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4.	Commitments and Contingencies

Rates and Regulatory Matters

The Company’s natural gas distribution operations in Delaware, Maryland and Florida are regulated by their state Public Service Commissions (“PSCs”). Eastern Shore Natural Gas Company (“Eastern Shore”), the Company’s natural gas transmission operation, is regulated by the Federal Energy Regulatory Commission (“FERC”).

Delaware. On July 6, 2007, the Company filed with the Delaware PSC an application seeking approval of the following: (i) participation by the Company’s Delaware commercial and industrial customers in gas supply buying pools served by third-party natural gas marketers; (ii) an annual base rate adjustment of $1,896,000 that represents approximately a 3.25 percent rate increase on average for the Delaware division’s firm customers; (iii) an alternative rate design for residential customers in a defined expansion area in eastern Sussex County, Delaware; and (iv) a revenue normalization mechanism that mitigates the price and revenue impacts of seasonal natural gas consumption patterns on both customers and the Company. As part of that filing, the Company also proposed that the Delaware division be permitted to earn a return on equity of up to fifteen percent (15%) as an incentive to make the significant capital investments to serve the growing areas of eastern Sussex County, in support of Delaware’s Energy Policy, and to ensure that the Company’s investors are adequately compensated for the increased risk associated with the higher levels of capital investment necessary to provide natural gas in those areas. On August 21, 2007, the Delaware PSC authorized the Company to implement charges reflecting the proposed $1,896,000 increase, effective September 4, 2007, on a temporary basis and subject to refund, pending the completion of full evidentiary hearings and a final decision by the Delaware PSC. The Delaware PSC Staff filed testimony recommending a rate decrease of $693,245. The Delaware Public Advocate (“DPA”) recommended a rate decrease of $588,670. Neither party recommended approval of the Delaware division’s other proposals mentioned above. The Delaware division disagreed with these positions in its rebuttal, which was filed on February 7, 2008. At an evidentiary hearing on July 9, 2008, the parties presented a joint proposed settlement agreement that would effectively resolve all issues in this docket, and the Delaware PSC granted approval of this settlement agreement on September 2, 2008. The major components of the settlement include the following: (i) a rate increase for the Delaware division of $325,000, including miscellaneous fees; (ii) an overall rate of return of 8.91% and a return on equity of 10.25%; (iii) a change in depreciation rates that will reduce depreciation expense by approximately $897,000; (iv) the division would be permitted to retain one hundred percent (100%) of margins on interruptible service over 10,000 Mcf per year, and all interruptible customers would receive transportation service only; (v) the division would continue to share with firm service customers, through its Gas Service Revenue (“GSR”) mechanism, eighty percent (80%) of any margins received from its Asset Manager and any off-system sales; and (vi) the residential service rate schedule would be divided into two separate schedules based on annual volumetric levels.

On September 10, 2007, the Company filed with the Delaware PSC its annual GSR Application, seeking approval to change its GSR rates effective November 1, 2007. On October 2, 2007, the Delaware PSC authorized the Company to implement the GSR charges on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. The Company is required by its natural gas tariff to file a revised application if its projected under-collection of gas costs for the determination period of November through October exceeds six percent (6%) of total firm gas costs. As a result of continued increases in the cost of natural gas, the Company filed with the Delaware PSC, on July 1, 2008, a supplemental GSR Application, seeking approval to change its GSR rates effective August 1, 2008. On July 8, 2008, the Delaware PSC authorized the Company to implement the supplemental GSR charges on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. The Delaware PSC granted final approval of both of the Delaware Division’s GSR rate filings on October 7, 2008.

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On September 1, 2008, the Delaware division filed with the Delaware PSC its annual GSR Application, seeking approval to change its GSR rates effective November 1, 2008. On September 16, 2008, the Delaware PSC authorized the Company to implement the GSR charges on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. The Company anticipates a final decision by the Delaware PSC during the first half of 2009.

On November 1, 2007, the Delaware division filed with the Delaware PSC its annual Environmental Rider (“ER”) rate application to become effective December 1, 2007. The Delaware PSC granted approval of the ER rate at its regularly scheduled meeting on November 20, 2007, subject to full evidentiary hearings and a final decision. On February 5, 2008, the Delaware PSC granted final approval of the ER rates as filed. Since all of the division’s environmental expenses subject to recovery pursuant to the ER recovery mechanism will have been collected by the end of the determination period, no additional ER rate applications will be filed, and ER charges will cease to appear on the division’s customers’ bills as of November 30, 2008.

Maryland. On September 26, 2006, the Maryland PSC approved a base rate increase for the Maryland division of approximately $780,000 annually. In a settlement agreement entered into in that proceeding, the division was required to file a depreciation study, which was filed on April 9, 2007. The division filed formal testimony on July 10, 2007, initiating a Phase II of this proceeding. In this filing, the division proposed a rate decrease of approximately $80,000 annually, resulting from a change in depreciation expense. On November 29, 2007, the Maryland PSC approved a settlement agreement for a rate decrease of $132,155, effective December 1, 2007, based on the change in the Company’s depreciation rates. Under the settlement, the division has reduced its depreciation expense by approximately $119,000 and its asset removal costs by approximately $167,000. The difference between the decrease in depreciation expense and the decrease in delivery service rates is due to an increase in rate case expense amortization and an increase in rates to offset the loss of margin from a large customer in Maryland

On December 17, 2007, the Maryland PSC held an evidentiary hearing to determine the reasonableness of the Maryland division’s four quarterly gas cost recovery filings during the twelve months ended September 30, 2007. No issues were raised at the hearing, and on February 7, 2008, the Maryland PSC approved, without exception, the Maryland division’s four quarterly gas cost recovery filings.

Florida. In compliance with state law, the Florida division filed its 2007 Depreciation Study (“Study”) with the Florida PSC on May 17, 2007. This Study, which supersedes the last study performed in 2002, provides the Florida PSC the opportunity to review and address changes in plant and equipment lives, salvage values, reserves and resulting life depreciation rates. The division responded to interrogatories concerning the Study on October 15, 2007, December 24, 2007, and February 7, 2008. Based on the recommendation issued by the Florida PSC Staff, the Commission, at its May 20, 2008 agenda conference, approved certain revisions to the division’s utility plant remaining lives, net salvage values, depreciation reserves, and depreciation rates, effective January 1, 2008. These changes have reduced depreciation expense by approximately $11,000 through September 30, 2008. The Florida PSC issued an order on June 27, 2008, which closed this docket.

On August 15, 2008, the Company filed with the Florida PSC a petition seeking a permanent waiver of certain aspects of meter-reading rules that could prevent the Company and its customers from realizing fully the accuracy and efficiency benefits of automatic meter-reading (AMR) equipment, which enables the Company to take daily meter readings remotely for every customer. Existing Commission rules, established well before AMR technology existed, can be read to require a monthly visit to each customer to take a reading from a meter located on the customer’s premises. The Commission, at its October 14, 2008 Agenda Conference, approved the Company’s petition, with a minor modification requiring the Company to read all meters physically once each year. An initial order is expected within twenty days thereafter, and a consummating order, which will close the docket, is expected within 21 days after the issuance of the initial order.

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On August 18, 2008, the Company filed with the Commission a petition seeking recovery of costs incurred to implement Phase 2 of its experimental Transitional Transportation Service (TTS) program. The Company incurred certain incremental, non-recurring costs from May 2007 through June 2008 ($77,980) and is projecting that it will incur additional non-recurring expenses through May 2009 ($100,000) for a total of approximately $177,980. The Company is seeking recovery of these expenses, plus applicable Regulatory Assessment Fees and interest, through a fixed monthly surcharge from the two approved TTS Shippers on the Company’s system. The Commission approved the Company’s petition at its October 14, 2008 Agenda Conference, and an initial order is expected within twenty days thereafter. A consummating order, which will close this docket, is expected within 21 days after the initial order.

Eastern Shore. Eastern Shore had the following regulatory activity with the FERC regarding the expansion of its transmission system:

System Expansion 2006 – 2008. On November 15, 2007, Eastern Shore requested FERC authorization to commence construction of facilities (approximately 9.2 miles) included in the third phase of the 2006-08 System Expansion. The FERC granted this authorization on January 7, 2008. Construction began in the first quarter of 2008, and the facilities are to be completed and placed in service by November 1, 2008. These Phase III facilities will provide 5,650 Dekatherms (“Dts”) of additional firm service capacity per day and annualized gross margin contribution of approximately $1.0 million.

Eastern Shore Energylink Expansion Project (“E3 Project”). In 2006, Eastern Shore proposed to develop, construct and operate approximately 75 miles of new pipeline facilities to transport natural gas from the existing Cove Point liquefied natural gas (“LNG”) terminal located in Calvert County, Maryland, crossing under the Chesapeake Bay into Dorchester and Caroline Counties, Maryland, to points on the Delmarva Peninsula, where such facilities would interconnect with Eastern Shore’s existing facilities in Sussex County, Delaware.

On May 31, 2006, Eastern Shore entered into Precedent Agreements (the “Precedent Agreements”) with Delmarva Power & Light Company (“Delmarva”) and Chesapeake, through its Delaware and Maryland divisions, to provide additional firm transportation services upon completion of the E3 Project. Both Chesapeake and Delmarva are parties to existing firm natural gas transportation service agreements with Eastern Shore, and each desired additional firm transportation service under the E3 Project, as evidenced by the Precedent Agreements. Pursuant to the Precedent Agreements, the parties agreed to proceed with the required initiatives to obtain the governmental and regulatory authorizations necessary for Eastern Shore to provide, and for Chesapeake and Delmarva to utilize, additional firm transportation service under the E3 Project.

As part of the Precedent Agreements, Eastern Shore, Chesapeake and Delmarva also entered into Letter Agreements, which provide that, if the E3 Project is not certificated and placed in service, Chesapeake and Delmarva will each pay its proportionate share of certain pre-certification costs by means of a negotiated surcharge over a period of not less than 20 years.

In furtherance of the E3 Project, Eastern Shore submitted a petition to the FERC on June 27, 2006, seeking approval of the pre-construction cost agreements as part of a rate-related Settlement Agreement (the “Settlement Agreement”), which would provide benefits to Eastern Shore and its customers, including but not limited to: (1) advancement of a necessary infrastructure project to meet the growing demand for natural gas on the Delmarva Peninsula; (2) sharing of project development costs by the participating customers in the E3 Project; and (3) no development cost risk for non-participating customers. On August 1, 2006, the FERC approved the Settlement Agreement. On September 6, 2006, Eastern Shore submitted to the FERC proposed tariff sheets to implement the provisions of the Settlement Agreement. By Letter Order dated October 6, 2006, the FERC accepted the tariff sheets, effective September 7, 2006.

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On April 23, 2007, Eastern Shore submitted to the FERC its request to commence a pre-filing process, and on May 15, 2007, the FERC notified Eastern Shore that its request had been approved. The pre-filing process was intended to engage all interested and affected stakeholders early in the process with the intention of resolving all environmental issues prior to the formal certificate application being filed. As part of this process, Eastern Shore performed environmental, engineering and cultural surveys and studies in the interest of protecting the environment, minimizing any potential impacts to landowners, and cultural resources. Eastern Shore also held meetings with federal, state and local permitting/regulatory agencies, non-governmental organizations, landowners, and other interested stakeholders.

As part of an updated engineering study, Eastern Shore received additional construction cost estimates for the E3 Project, which indicated substantially higher costs than previously estimated. In an effort to optimize the feasibility of the overall project development plan, Eastern Shore explored all potential construction methods, construction cost mitigation strategies, potential design changes and project schedule changes. Eastern Shore also held discussions and meetings with several potential new customers, who expressed interest in the E3 project, but elected not to participate.

On December 20, 2007, Eastern Shore withdrew from the pre-filing process as a result of insufficient customer commitments for capacity to make the project economical. Eastern Shore will continue to explore potential construction methods, construction cost mitigation strategies, additional market requests, and potential design changes in its efforts to improve the overall economics of the E3 project.

If Eastern Shore decides to abandon the E3 Project, it will initiate billing of a pre-certification costs surcharge in accordance with the terms of the above described Precedent Agreements and Letter Agreements executed with two of its customers, which provide for these customers to reimburse Eastern Shore for pre-certification costs incurred in connection with the E3 Project, up to a maximum amount of $2.0 million each, with interest, over a period of 20 years. As of September 30, 2008, the Company had incurred $3.17 million of pre-certification costs relating to the E3 Project.

Eastern Shore also had developments in the following FERC rate and certificate matters:

On June 6, 2007, Eastern Shore and interested parties reached a settlement agreement in principle on its base rate proceeding filed with the FERC on October 31, 2006. The negotiated settlement provides for an annual cost of service of $21,536,000, which reflects a pretax rate of return of 13.6 percent and a rate increase of approximately $1.07 million on an annual basis. On September 10, 2007, Eastern Shore submitted its Settlement Offer to the Presiding Administrative Law Judge (“ALJ”) for review and certification to the full Commission.

Eastern Shore filed concurrently with its Settlement Agreement a Motion to place the settlement rates into effect on September 1, 2007, in order to expedite the implementation of the reduced settlement rates pending final approval of the settlement. The Commission issued an order on September 25, 2007, authorizing Eastern Shore to commence billing its settlement rates, effective September 1, 2007.

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On October 1, 2007, the Presiding ALJ forwarded to the full Commission an order certifying the uncontested Settlement Agreement as fair, reasonable, and in the public interest. A final Commission Order approving the settlement was issued on January 31, 2008. In compliance with the Settlement Agreement, refunds, inclusive of interest, totaling $1.26 million, based on the higher interim rates that were effective for the period from May 15, 2007 through August 31, 2007, were distributed to Eastern Shore’s customers on February 1, 2008.

On May 15, 2008, Eastern Shore submitted its annual Interruptible Revenue Sharing Report to the FERC. In this filing, Eastern Shore reported that, since its interruptible service revenue exceeded its annual threshold amount, it refunded a total of $63,675 in the second quarter of 2008 to its eligible firm service customers in accordance with the terms of its tariff and the rate case Settlement Agreement described above.

On June 24, 2008, Eastern Shore submitted its annual Fuel Retention Percentage (“FRP”) and Cash-Out Surcharge filings to the FERC. In these filings, Eastern Shore proposed to retain its current FRP rate of zero percent and also a zero rate for its Cash-Out Surcharge. Eastern Shore also proposed to refund a total of $ 412,013, including interest, to its eligible customers in the third quarter of 2008 as a result of netting its over-recovered Gas Required for Operations against its under-recovered Cash-Out Cost. The FERC approved these proposals on July 11, 2008, and customer refunds were distributed that same month.

On July 2, 2008, Eastern Shore submitted to the FERC a Prior Notice filing under its Blanket Certificate Authority to add a new delivery point to serve an industrial customer located in Seaford, Delaware. In accordance with FERC regulations, a Prior Notice filing requires a 60-day window for protests. No protests were received, and Eastern Shore is authorized to construct and operate the new delivery point. In mid-October, however, the industrial customer notified Eastern Shore that, based on adverse developments affecting the market for its products, it will not require the new delivery point. Pursuant to a contract between the parties, the industrial customer is required to reimburse pre-construction costs incurred by Eastern Shore, which are currently being determined.

Environmental Matters

Chesapeake is subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require the Company to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites.

Chesapeake has participated in the investigation, assessment or remediation, and has accrued liabilities, at three former manufactured gas plant sites located in Delaware, Maryland and Florida, referred to, respectively, as the Dover Gas Light Site, the Salisbury Town Gas Light Site and the Winter Haven Coal Gas Site. The Company has also been in discussions with the Maryland Department of the Environment (“MDE”) regarding a fourth former manufactured gas plant site located in Cambridge, Maryland. The following discussion provides details on each site.

Dover Gas Light Site

The Dover Gas Light site is a former manufactured gas plant site located in Dover, Delaware. On January 15, 2004, the Company received a Certificate of Completion of Work from the United States Environmental Protection Agency (“EPA”) regarding this site. This concluded Chesapeake’s remedial action obligation related to this site and relieves Chesapeake from liability for future remediation at the site, unless previously unknown conditions are discovered there, or information previously unknown to the EPA is received which indicates that the remedial action that has been taken is not sufficiently protective. These contingencies are standard and are required by the EPA in all liability settlements.

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The Company has reviewed its remediation costs incurred to date for the Dover Gas Light site and has concluded that all costs incurred have been paid. The Company does not expect any future environmental expenditure for this site. Through September 30, 2008, the Company has incurred and paid approximately $9.67 million in costs related to environmental testing and remedial action studies at the site. Approximately $9.71 million has been recovered through September 2008, from other parties or through rates. As of September 30, 2008, a regulatory liability of approximately $47,000, representing the over-recovery portion of the clean-up costs, has been recorded. The over-recovery is temporary and will be refunded by the Company to customers in future rates.

Salisbury Town Gas Light Site

In cooperation with the MDE, the Company has completed remediation of the Salisbury Town Gas Light site, located in Salisbury, Maryland, where it was determined that a former manufactured gas plant had caused localized ground-water contamination. During 1996, the Company completed construction of an Air Sparging and Soil-Vapor Extraction (“AS/SVE”) system and began remediation procedures. Chesapeake has reported the remediation and monitoring results to the MDE on an ongoing basis since 1996. In February 2002, the MDE granted permission to decommission permanently the AS/SVE system and to discontinue all on-site and off-site well monitoring, except for one well which is being maintained for continued product monitoring and recovery. Chesapeake has requested and is awaiting a No Further Action determination from the MDE.

Through September 30, 2008, the Company has incurred and paid approximately $2.9 million for remedial actions and environmental studies at the Salisbury Town Gas Light site. Of this amount, approximately $1.94 million has been recovered through insurance proceeds or in rates. On September 26, 2006, the Company received approval from the Maryland PSC to recover, through its rates charged to customers, $1.16 million of environmental remediation costs incurred as of that date. As of September 30, 2008, a regulatory asset of approximately $927,000 has been recorded to represent the portion of the clean-up costs not yet recovered.

Winter Haven Coal Gas Site

The Winter Haven Coal Gas site is located in Winter Haven, Florida. Chesapeake has been working with the Florida Department of Environmental Protection (“FDEP”) in assessing this coal gas site. In May 1996, the Company filed with the FDEP an AS/SVE Pilot Study Work Plan (the “Work Plan”) for the Winter Haven Coal Gas site. After discussions with the FDEP, the Company filed a modified Work Plan, which contained a description of the scope of work to complete the site assessment activities and a report describing a limited sediment investigation performed in 1997. In December 1998, the FDEP approved the modified Work Plan, which the Company completed during the third quarter of 1999. In February 2001, the Company filed a Remedial Action Plan (“RAP”) with the FDEP to address the contamination of the subsurface soil and ground-water in a portion of the site. The FDEP approved the RAP on May 4, 2001. Construction of the AS/SVE system was completed in the fourth quarter of 2002, and the system remains fully operational.

Through September 30, 2008, the Company has incurred approximately $1.24 million of environmental costs associated with this site. At September 30, 2008, the Company had recorded a regulatory asset of $797,000 related to this site, including approximately $241,000 of costs incurred but which have not been collected through rates, and offsetting a liability associated with this site of $556,000.

The FDEP has indicated that the Company may be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the Winter Haven Coal Gas site. Based on studies performed to date, the Company objects to the FDEP’s suggestion that the sediments have been contaminated and will require remediation. The Company’s early estimates indicate that some of the corrective measures discussed by the FDEP may cost as much as $1 million. Given the Company’s view as to the absence of ecological effects, the Company believes that cost expenditures of this magnitude are unwarranted and intends to oppose any requirement that it undertake corrective measures in the offshore sediments. Chesapeake anticipates that it will be several years before this issue is resolved. At this time, the Company has not recorded a liability for sediment remediation. The outcome of this matter cannot be predicted at this time.

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Other

The Company is in discussions with the MDE regarding a manufactured gas plant site located in Cambridge, Maryland. The outcome of this matter cannot be determined at this time; therefore, the Company has not recorded an environmental liability for this location.

Other Commitments and Contingencies

Natural Gas and Propane Supply

The Company’s natural gas and propane distribution operations have entered into contractual commitments to purchase gas from various suppliers. The contracts have various expiration dates. In March 2008, the Company renewed its contract with an energy marketing and risk management company to manage a portion of the Company’s natural gas transportation and storage capacity. This contract expires on March 31, 2009.

Corporate Guarantees

The Company has issued corporate guarantees to certain vendors of its subsidiaries, the largest portion of which are for the Company’s propane wholesale marketing subsidiary and its natural gas supply management subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. None of these subsidiaries has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in the Consolidated Financial Statements when incurred. The aggregate amount guaranteed at September 30, 2008 was $22.9 million, with the guarantees expiring on various dates in 2008 and the first nine months of 2009.

In addition to the corporate guarantees, the Company has issued a letter of credit to its primary insurance company for $775,000, which expires on May 31, 2009. The letter of credit is provided as security to satisfy the deductibles under the Company’s various insurance policies. There have been no draws on this letter of credit as of September 30, 2008.

Internal Revenue Service Examination

In November 2007, the Internal Revenue Service (“IRS”) initiated an examination of our consolidated federal tax return for the year ended December 31, 2005. During the review, the IRS expanded its examination to include our 2006 consolidated federal tax return as well.

In September 2008, the IRS completed its examination of our 2005 and 2006 consolidated federal tax returns and issued its Examination Report. As a result of the examination, the Company reduced its income tax receivable by $27,000 for the tax liability associated with disallowed expense deductions included on the tax returns. The Company is in the process of amending its 2005 and 2006 federal and state corporate income tax returns to reflect the disallowed expense deductions.

Application of SFAS No. 71

Certain assets and liabilities of the Company are accounted for in accordance with Statement of Financial Accounting Standard (“SFAS”) No. 71 “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 provides guidance for public utilities and other regulated operations where the rates (prices) charged to customers are subject to regulatory review and approval. Regulators sometimes include allowable costs in a period other than the period in which the costs would be charged to expense by an unregulated enterprise. That procedure can create assets, reduce assets, or create liabilities for the regulated enterprise. For financial reporting, an incurred cost for which a regulatory body permits recovery in a future period is accounted for like an incurred cost that is reimbursable under a cost-reimbursement type contract. The Company believes that all regulatory assets as of September 30, 2008 are probable of recovery through rates. If the Company were required to terminate the application of SFAS No. 71 to its regulated operations, all such deferred amounts would be recognized in the income statement at that time. This could result in a charge to earnings, net of applicable income taxes, which could be material.

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Other

The Company is involved in certain legal actions and claims arising in the normal course of business. The Company is also involved in certain legal and administrative proceedings before various governmental agencies concerning rates. In the opinion of management, the ultimate disposition of these proceedings will not have a material effect on the consolidated financial position, results of operations or cash flows of the Company.

5.	Recent Authoritative Pronouncements on Financial Reporting and Accounting

Recent accounting pronouncements:

In December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 141 (revised 2007) “Business Combinations” (“SFAS 141(R)”). SFAS 141(R) retains the fundamental requirements of the original pronouncement requiring that the acquisition method be used for all business combinations. SFAS 141(R): (a) defines the acquirer as the entity that obtains control of one or more businesses in a business combination, (b) establishes the acquisition date as the date that the acquirer achieves control and (c) requires the acquirer to recognize the assets acquired, liabilities assumed and any non-controlling interests at their fair values as of the acquisition date. SFAS 141(R) also requires that acquisition-related costs be expensed as incurred. SFAS 141(R) is effective for fiscal years beginning after December 15, 2008. The Company does not expect the adoption of SFAS 141(R) to have a material impact on its current consolidated financial position and results of operations. However, depending upon the size, nature and complexity of future acquisition transactions, the adoption of SFAS 141(R) could materially affect the Company’s consolidated financial statements.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements,” an amendment of ARB No. 51. SFAS 160 changes the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests and classified as a component of equity. This new consolidation method significantly changes the accounting for transactions with minority interest holders. SFAS 160 is effective for fiscal years beginning after December 15, 2008. No other entity has a minority interest in any of the Company’s subsidiaries; therefore, the Company does not expect the adoption of SFAS 160 to have an impact on its current consolidated financial position and results of operations.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133.” This new standard requires enhanced disclosures for derivative instruments, including those used in hedging activities. It is effective for fiscal years and interim periods beginning after November 15, 2008, and will be applicable to the Company in the first quarter of fiscal 2009. The Company is assessing the potential impact that SFAS 161 may have on its financial statements.

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In April 2008, the FASB issued FASB Staff Position (“FSP”) FAS 142-3, “Determination of the Useful Life of Intangible Assets.” This FSP amends the factors which should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS 141R and other GAAP. This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. The Company is evaluating the potential impact that this FSP may on its consolidated financial statements.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of GAAP.” This standard is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP in the United States for non-governmental entities. SFAS No. 162 is effective 60 days following approval by the U.S. Securities and Exchange Commission of the Public Company Accounting Oversight Board’s amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” We do not expect SFAS No. 162 to have a material impact on the preparation of our consolidated financial statements.

In May 2008, the FASB issued FASB Staff Position (“FSP”) APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement).” FSP APB 14-1 clarifies that convertible debt instruments that may be settled in cash upon either mandatory or optional conversion (including partial cash settlement) are not addressed by paragraph 12 of APB Opinion No. 14, “Accounting for Convertible Debt and Debt issued with Stock Purchase Warrants.” In addition, FSP APB 14-1 specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. FSP APB 14-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. The Company is assessing the potential impact that FSP APB 14-1 may have on its consolidated financial statements.

In June 2008, the FASB issued FSP Emerging Issues Task Force (“EITF”) 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” This FSP clarifies that all outstanding unvested share-based payment awards that contain rights to nonforfeitable dividends participate in undistributed earnings with common shareholders. Awards of this nature are considered participating securities and the two-class method of computing basic and diluted earnings per share must be applied. This FSP is effective for fiscal years beginning after December 15, 2008. The Company is evaluating the potential impact the new pronouncement may have on its consolidated financial statements.

In June 2008, the FASB ratified EITF Issue No. 07-5, “Determining Whether an Instrument (or an Embedded Feature) Is Indexed to an Entity’s Own Stock” (“EITF 07-5”). EITF 07-5 provides that an entity should use a two-step approach to evaluate whether an equity-linked financial instrument (or embedded feature) is indexed to its own stock, including evaluating the instrument’s contingent exercise and settlement provisions. It also clarifies the impact of foreign-currency-denominated strike prices and market-based employee stock option valuation instruments on the evaluation. EITF 07-5 is effective for fiscal years beginning after December 15, 2008. The Company is evaluating the potential impact the new pronouncement may have on its consolidated financial statements.

In June 2008, the FASB ratified EITF Issue No. 08-3, “Accounting for Lessees for Maintenance Deposits Under Lease Arrangements” (“EITF 08-3”). EITF 08-3 provides guidance for accounting for nonrefundable maintenance deposits. It also provides revenue recognition accounting guidance for the lessor. EITF 08-3 is effective for fiscal years beginning after December 15, 2008. The Company is evaluating the potential impact the new pronouncement may have on its consolidated financial statements.

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In September 2008, the FASB ratified EITF Issue No. 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value With a Third-Party Credit Enhancement” (EITF 08-5). EITF 08-5 provides guidance for measuring liabilities issued with an attached third-party credit enhancement (such as a guarantee). It clarifies that the issuer of a liability with a third-party credit enhancement should not include the effect of the credit enhancement in the fair value measurement of the liability. EITF 08-5 is effective for the first reporting period beginning after December 15, 2008. The Company does not expect the adoption of EITF 08-5 to have a material impact on its current consolidated financial position and results of operations.

During the first nine months of 2008, the Company adopted the following accounting standards:

In September 2008, the FASB issued FSP 133-1 and FIN 45-4, “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161” (FSP 133-1 and FIN 45-4). FSP 133-1 and FIN 45-4 amends and enhances disclosure requirements for sellers of credit derivatives and financial guarantees. It also clarifies that the disclosure requirements of SFAS No. 161 are effective for quarterly periods beginning after November 15, 2008, and fiscal years that include those periods. FSP 133-1 and FIN 45-4 is effective for reporting periods (annual or interim) ending after November 15, 2008. The implementation of this standard will not have a material impact on our consolidated financial position and results of operations.

In October 2008, the FASB issued FSP SFAS No. 157-3, “Determining the Fair Value of a Financial Asset When The Market for That Asset Is Not Active” (FSP 157-3), to clarify the application of the provisions of SFAS 157 in an inactive market and how an entity would determine fair value in an inactive market. FSP 157-3 is effective immediately and applies to our September 30, 2008 financial statements. The application of the provisions of FSP 157-3 did not materially affect our results of operations or financial condition as of and for the periods ended September 30, 2008.

Effective January 1, 2008, Chesapeake adopted FSP No. FIN 39-1, “Amendment of FASB Interpretation No. 39” (“FSP FIN 39-1”). FSP FIN 39-1 modifies FIN No. 39, “Offsetting of Amounts Related to Certain Contracts,” and permits companies to offset cash collateral receivables or payables with net derivative positions under certain circumstances. Based on the derivative contracts entered into to date, adoption of this FSP has not materially affected our consolidated financial statements.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 provides guidance for using fair value to measure assets and liabilities. It also responds to investors’ requests for expanded information about the extent to which companies’ measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. SFAS No. 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value and does not expand the use of fair value in any new circumstances. In February 2008, the FASB issued FSP 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13” (“FSP 157-1”) and FSP 157-2, “Effective Date of FASB Statement No. 157” (“FSP 157-2”). FSP 157-1 amends SFAS No. 157 to remove certain leasing transactions from its scope. FSP 157-2 delays the effective date of SFAS No. 157 until fiscal years beginning after November 15, 2009 for all non-financial assets and non-financial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis. These non-financial items include assets and liabilities such as reporting units measured at fair value in a goodwill impairment test and non-financial assets acquired and liabilities assumed in a business combination. SFAS No. 157 was effective for financial statements issued for fiscal years beginning after November 15, 2007 and was adopted by the Company, as it applies to its financial instruments, effective January 1, 2008. Adoption of SFAS No. 157 had no financial impact on the Company’s consolidated financial statements. The disclosures required by SFAS 157 are discussed in Note 11 – “Fair Value of Financial Instruments” of the unaudited Condensed Consolidated Financial Statements.

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In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115,” which permits entities to elect to measure at fair value many financial instruments and certain other items that are not currently required to be measured at fair value. This election is irrevocable. SFAS No. 159 became effective in the first quarter of fiscal 2008. The Company has not elected to apply the fair value option to any of its financial instruments.

6.	Segment Information

Chesapeake uses the management approach to identify operating segments. The Company organizes its business around differences in products or services, and the operating results of each segment are regularly reviewed by the Company’s chief operating decision maker in order to make decisions about the allocation of resources and to assess performance. The following table presents information about the Company’s reportable segments. The table excludes financial data related to our distributed energy company, which was reclassified to discontinued operations for each period presented. The impact of discontinued operations is discussed within Note 13, “Discontinued Operations,” of the unaudited Condensed Consolidated Financial Statements.

	Three Months Ended						Nine Months Ended
For the Periods Ended September 30,	2008			2007			2008			2007
Operating Revenues, Unaffiliated Customers
Natural gas	$	37,245,165		$	29,542,424		$	159,841,655		$	134,261,695
Propane		8,758,648			7,923,129			48,055,256			42,339,698
Advanced information services		3,694,200			3,953,166			11,131,562			10,846,136
Other		-			-			-			(2	)
Total operating revenues, unaffiliated customers	$	49,698,013		$	41,418,719		$	219,028,473		$	187,447,527

Intersegment Revenues (1)
Natural gas	$	113,513		$	96,528		$	323,884		$	252,677
Propane		-			-			1,349			406
Advanced information services		47,977			121,613			84,029			349,840
Other		163,074			156,513			489,222			465,759
Total intersegment revenues	$	324,564		$	374,654		$	898,484		$	1,068,682

Operating Income (Loss)
Natural gas	$	2,938,444		$	2,118,594		$	18,143,831		$	15,726,858
Propane		(2,134,919	)		(1,445,093	)		684,517			2,882,565
Advanced information services		276,633			238,877			451,574			466,404
Other and eliminations		90,235			73,256			260,626			221,444
Total operating income	$	1,170,393		$	985,634		$	19,540,548		$	19,297,271

Other Income (Loss)		(91,631	)		(13,481	)	$	(10,535	)	$	277,193
Interest Charges		1,487,812			1,695,597		$	4,469,918		$	4,889,548
Income Taxes		(210,752	)		(363,474	)	$	5,865,127		$	5,545,725
Net income (loss) from continuing operations	$	(198,298	)	$	(359,970	)	$	9,194,968		$	9,139,191

(1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.


	September 30,			December 31,
	2008			2007
Identifiable Assets
Natural gas	$	284,433,020		$	273,500,890
Propane		99,293,700			94,966,212
Advanced information services		3,110,161			2,507,910
Other		13,386,512			10,533,511
Total identifiable assets	$	400,223,393		$	381,508,523

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The Company’s operations are primarily domestic. The advanced information services segment has infrequent transactions with foreign companies, located primarily in Canada, which are denominated and paid in U.S. dollars. These transactions are immaterial to the consolidated revenues.

7.	Employee Benefit Plans

Net periodic benefit costs for the defined benefit pension plan, the executive excess defined benefit pension plan and other post-retirement benefits are shown below:

	Defined Benefit						Executive Excess Defined				Other Post-Retirement
	Pension Plan						Benefit Pension Plan				Benefits
For the Three Months Ended September 30,	2008			2007			2008		2007		2008		2007
Service Cost	$	-		$	-		$	-	$	-	$	896	$	2,528
Interest Cost		148,430			155,514			31,381		30,840		27,564		23,234
Expected return on plan assets		(156,475	)		(174,100	)		-		-		-		-
Amortization of prior service cost		(1,174	)		(1,174	)		-		-		-		-
Amortization of net loss		-			-			11,611		12,934		46,215		41,640
Net periodic (benefit) cost	$	(9,219	)	$	(19,760	)	$	42,992	$	43,774	$	74,675	$	67,402

	Defined Benefit						Executive Excess Defined				Other Post-Retirement
	Pension Plan						Benefit Pension Plan				Benefits
For the Nine Months Ended September 30,	2008			2007			2008		2007		2008		2007
Service Cost	$	-		$	-		$	-	$	-	$	2,688	$	7,585
Interest Cost		445,292			466,543			94,144		92,521		82,693		69,701
Expected return on plan assets		(469,425	)		(522,299	)		-		-		-		-
Amortization of prior service cost		(3,524	)		(3,524	)		-		-		-		-
Amortization of net loss		-			-			34,833		38,801		138,645		124,920
Net periodic (benefit) cost	$	(27,657	)	$	(59,280	)	$	128,977	$	131,322	$	224,026	$	202,206

As disclosed in the December 31, 2007 financial statements, no contributions are expected to be required in 2008 for the defined benefit pension plan. The cost of the executive excess defined benefit pension plan and the other post-retirement benefit plan are unfunded and are expected to be paid out of the general funds of the Company. Cash benefits paid under the executive excess defined benefit pension plan for the three months and nine months ended September 30, 2008, were $22,300 and $66,900, respectively; for the year 2008, such benefits paid are expected to be $89,200. Cash benefits paid for other post-retirement benefits, primarily for medical claims, for the three months and nine months ended September 30, 2008, totaled $12,000 and $29,000, respectively; for the year 2008, the Company has estimated that $196,000 will be paid for such benefits.

8.	Investments

The investment balance at September 30, 2008 represents a Rabbi Trust associated with the Company’s Supplemental Executive Retirement Savings Plan. In accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” the Company classifies these investments as trading securities. As a result, the Company is required to report the securities at their fair value, with any unrealized gains and losses included in other income in the Unaudited Condensed Consolidated Statements of Income. The Company also has an associated liability that is recorded and adjusted each month for the gains and losses incurred by the Trust. At September 30, 2008, total investments had a fair value of $1.8 million.

9.	Share-Based Compensation

The Company accounts for its share-based compensation arrangements under SFAS No. 123 (revised 2004), “Share Based Payments” (“SFAS 123R”), which requires companies to record compensation costs for all share-based awards over the respective service period for which employee services are received in exchange for an award of equity or equity-based compensation. The compensation cost is based on the fair value of the grant on the date it was awarded. The Company currently has two share-based compensation plans, the Directors Stock Compensation Plan (“DSCP”) and the Performance Incentive Plan (“PIP”), that require accounting under SFAS 123R.

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The table below presents the amounts included in net income related to share-based compensation expense for the restricted stock awards issued under the DSCP and the PIP for the three and nine months ended September 30, 2008 and 2007.

	Three Months Ended				Nine Months Ended
For the periods ended September 30,	2008		2007		2008		2007
Directors Stock Compensation Plan	$	39,866	$	45,893	$	131,652	$	135,027
Performance Incentive Plan		103,503		265,353		487,845		681,661
Total compensation expense		143,369		311,246		619,497		816,688
Less: Tax benefit		57,088		121,386		246,676		318,508
SFAS 123R amounts included in net income	$	86,281	$	189,860	$	372,821	$	498,180

10.	Stockholders’ Equity

The changes in common stock shares issued and outstanding are shown below:


	For the Nine Months Ended September 30, 2008			For the Twelve Months Ended December 31, 2007
Common Stock shares issued and outstanding (1)
Shares issued — beginning of period balance		6,777,410			6,688,084
Dividend Reinvestment Plan (2)		7,275			35,333
Retirement Savings Plan		2,206			29,563
Conversion of debentures		5,463			8,106
Employee award plan		250			350
Stock Based Compensation (3)		24,744			15,974
Shares issued — end of period balance (4)		6,817,348			6,777,410

Treasury shares — beginning of period balance		-			-
Purchases		(1,831	)		(971	)
Deferred Compensation Plan		1,831			971
Treasury Shares — end of period balance		-			-

Total Shares Outstanding		6,817,348			6,777,410

(1) 12,000,000 shares are authorized at a par value of $0.4867 per share.
(2) Includes shares purchased with reinvested dividends and optional cash payments.
(3) Includes shares issued for the Directors Stock Compensation Plan and Performance Incentive Plan.
(4) Includes 61,610 and 57,309 shares at Septemer 30, 2008 and December 31, 2007, respectively, held in a Rabbi Trust established by the Company relating to the Deferred Compensation Plan.

11.	Financial Instruments

Xeron, Inc. (“Xeron”), the Company’s propane wholesale marketing operation, engages in trading activities, using forward and futures contracts, which have been accounted for using the mark-to-market method of accounting. Under mark-to-market accounting, the Company’s trading contracts are recorded at fair value, net of future servicing costs. Changes in market price are recognized as gains or losses in revenues on the income statement in the period of change, and the resulting unrealized gains and losses are recorded as assets or liabilities. There were unrealized gains of $621,000 and $179,000 at September 30, 2008 and December 31, 2007, respectively. Trading assets and liabilities are recorded as mark-to-market energy assets and liabilities on the Unaudited Condensed Consolidated Balance Sheets.

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The Company’s propane distribution operation may enter into a fair-value hedge of its inventory in order to mitigate the impact of wholesale price fluctuations. At September 30, 2008, the propane distribution operation had entered into a price swap agreement to protect the Company from the impact of price increases on the price-cap plan that we offer to customers. The Company considered this agreement to be an economic hedge that did not qualify for hedge accounting, as defined in SFAS 133. At September 30, 2008, the market price of propane had dropped below the swap agreement unit price. Consequently, the Company marked the agreement to market and recorded an unrealized loss of $475,000.

12.	Fair Value of Financial Instruments

Effective January 1, 2008, the Company adopted SFAS No. 157 for financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and liabilities that are measured and reported on a fair value basis. There was no impact from adoption of SFAS No. 157 to the Unaudited Condensed Consolidated Balance Sheets and Statements of Income. The primary effect of SFAS No. 157 on the Company was to expand the required disclosures pertaining to the methods used to determine fair values.

SFAS No. 157 also establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under SFAS 157 are the following:

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;

Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability; and

Level 3: Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e. supported by little or no market activity).

The following table summarizes the Company’s financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements by level within the fair value hierarchy used at September 30, 2008:

			Fair Value Measurements Using:
(in thousands)	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Investments	$	1,815	$	1,815	$	-	$	-
Mark-to-market energy assets		11,979		-		11,979		-

Liabilities:
Mark-to-market energy liabilities		11,358		-		11,358		-
Price swap agreement		475		-		475		-

The following valuation techniques were used to measure fair value assets in the table above on a recurring basis as of September 30, 2008:

Level 1 Fair Value Measurements:

Investments - The fair values of these available-for-sale securities are recorded at fair value based on unadjusted quoted prices in active markets for identical securities.

Level 2 Fair Value Measurements:

Mark-to-market energy assets and liabilities - These forward contracts are valued using broker or dealer quotations, or market transactions in either the listed or OTC markets.

Propane price swap agreement – The fair value of the propane price swap agreement is valued using broker or dealer quotations, or market transactions in either the listed or OTC markets.

The Company’s adoption of SFAS No. 157 applies only to its financial instruments and does not apply to those non-financial assets and non-financial liabilities delayed under FSP No. 157-2, which will be implemented for the fiscal years beginning after November 15, 2009.

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13.	Discontinued Operations

During the quarter ended September 30, 2007, the Company decided to close its distributed energy services subsidiary, Chesapeake OnSight Services LLC (“OnSight”), which had experienced operating losses since its inception in 2004. As a result of these actions, the financial data related to OnSight is presented as discontinued operations for all periods presented. The discontinued operations had no impact on the Company’s Unaudited Condensed Consolidated Financial Statements during the three and nine months ended September 30, 2008, compared to a net gain of approximately $4,000 for the three months ended September 30, 2007, and a net loss of approximately $22,000 for the nine months ended September 30, 2007.

14.	Subsequent Events

On October 13, 2008, the Company entered into agreements with one of its commercial lenders, Bank of America, N.A., (“BOA”) regarding the short-term lines of credit available with the financial institution. These agreements increase the dollars available under the committed short-term loan facility, and decrease the dollars available under the uncommitted loan facility by an equal amount. The total loan capacity available from BOA remains unchanged. The modifications to existing loan documents increased the committed line amount from $5 million to $30 million, while simultaneously reducing the uncommitted line capacity from $45 million to $20 million. The other terms of the uncommitted line of credit remain unchanged. The spread on the committed facility was increased to 75 basis points over the British Bankers Association LIBOR rate, with the unused commitment fee declining to 17.5 basis points.

On October 29, 2008, the Company and PNC Bank, Delaware executed modifications to existing loan documents that increased the committed line amount from $10 million to $25 million, while simultaneously reducing the uncommitted line capacity from $30 million to $15 million. The other terms of the uncommitted line of credit remain unchanged. The spread on the committed facility was increased to 125 basis points with an unused commitment fee at the rate of 15 basis points. An advance outstanding under the committed facility will bear interest at the Bank’s Base Rate (as defined in the agreement) plus 125 basis points if requested and advanced on the same day, or LIBOR for the applicable period plus 125 basis points if requested three (3) days prior to the advance date.

On October 31, 2008, the Company issued $30 million of 5.93 percent unsecured Senior Notes to two institutional investors (General American Life Insurance Company and New England Life Insurance Company). The terms of the Notes require principal repayments of $1,500,000 on the 30th day of April and the 31st day of October in each year, commencing on April 30, 2014. The Notes will mature on October 31, 2023. The proceeds of sale of the Notes will be used to refinance capital expenditures and for general corporate purposes.

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is designed to provide a reader of the financial statements with a narrative report on the Company’s financial condition, results of operations and liquidity. This discussion and analysis should be read in conjunction with the attached unaudited condensed consolidated financial statements and notes thereto and Chesapeake’s Annual Report on Form 10-K for the year ended December 31, 2007, including the audited consolidated financial statements and notes contained in the Form 10-K.

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Safe Harbor for Forward-Looking Statements

Chesapeake makes statements in this Form 10-Q that are considered to be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are not matters of historical fact and are typically identified by words such as, but not limited to, “believes,” “expects,” “intends,” “plans,” and similar expressions, or future or conditional verbs such as “may,” “will,” “should,” “would,” and “could.” These statements relate to matters such as customer growth, changes in revenues or gross margins, capital expenditures, environmental remediation costs, regulatory trends and decisions, market risks associated with our propane operations, the competitive position of the Company and other matters. It is important to understand that these forward-looking statements are not guarantees, but are subject to certain risks and uncertainties and other important factors that could cause actual results to differ materially from those in the forward-looking statements. The factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to:

·	the temperature sensitivity of the natural gas and propane businesses;

·	the effects of spot, forward, futures market prices, and the Company’s use of derivative instruments for the Company’s distribution, wholesale marketing and energy trading businesses;

·	the amount and availability of natural gas and propane supplies;

·	access to interstate pipelines’ transportation and storage capacities and the construction of new facilities to support future growth;

·	the effects of natural gas and propane commodity price changes on the operating costs and competitive positions of our natural gas and propane distribution operations;

·	third-party competition for the Company’s unregulated and regulated businesses;

·	changes in federal, state or local regulation and tax requirements, including deregulation;

·	changes in technology affecting the Company’s advanced information services segment;

·	changes in credit risk and credit requirements affecting the Company’s energy marketing subsidiaries;

·	the effects of accounting changes;

·	changes in benefit plan assumptions;

·	the cost of compliance with environmental regulations or the remediation of environmental damage;

·	the effects of general economic conditions, including interest rates, on the Company and its customers;

·	the ability of the Company’s new and planned facilities and acquisitions to generate expected revenues;

·	the ability of the Company to construct facilities at or below estimated costs;

·	the Company’s ability to obtain the rate relief and cost recovery requested from regulators and the timing of the requested regulatory actions;

·	the Company’s ability to obtain necessary approvals and permits from regulatory agencies on a timely basis;

·	the impact of inflation on the results of operations, cash flows, financial position and on the Company’s planned capital expenditures;

·	inability to access financial markets to secure capital to a degree that may impair future growth; and

·	operating and litigation risks that may not be covered by insurance.

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Overview

Chesapeake is a diversified utility company engaged, directly or through subsidiaries, in natural gas distribution, transmission and marketing, propane distribution and wholesale marketing, advanced information services and other related businesses. For additional information regarding segments, refer to Note 6, “Segment Information,” of the Notes to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

The Company’s strategy is focused on growing the earnings produced from a stable utility foundation and investing in related businesses and services that provide opportunities for returns greater than traditional utility returns. The key elements of this strategy include:

·	executing a capital investment program in pursuit of organic growth opportunities that generate returns equal to or greater than our cost of capital;

·	expanding the natural gas distribution and transmission business through expansion into new geographic areas in our current and potentially new service territories;

·	expanding the propane distribution business in existing and new markets by leveraging our community gas system services and our bulk delivery capabilities;

·	utilizing the Company’s expertise across our various businesses to improve overall performance;

·	enhancing marketing channels to attract new customers;

·	providing reliable and responsive service to retain existing customers;

·	maintaining a capital structure that enables the Company to access capital as needed; and

·	maintaining a consistent and competitive dividend for shareholders.

Due to the seasonality of the Company’s business, results for interim periods are not necessarily indicative of results for the entire fiscal year. Revenue and earnings are typically greater during the Company’s first and fourth quarters, when consumption of natural gas and propane is highest due to colder temperatures.

Results of Operations for the Quarter Ended September 30, 2008

The following discussions on operating income and segment results for the three months ended September 30, 2008 and 2007 include use of the term “gross margin.” Gross margin is determined by deducting the cost of sales from operating revenue. Cost of sales includes the purchased gas cost for natural gas and propane and the cost of labor spent on direct revenue-producing activities. Gross margin should not be considered an alternative to operating income or net income, which are determined in accordance with GAAP. Chesapeake believes that gross margin, although a non-GAAP measure, is useful and meaningful to investors as a basis for making investment decisions. It provides investors with information that demonstrates the profitability achieved by the Company under its allowed rates for regulated operations and under its competitive pricing structure for non-regulated segments. Chesapeake’s management uses gross margin in measuring the performance of its business units and has historically analyzed and reported gross margin information publicly. Other companies may calculate gross margin in a different manner.

Consolidated Overview

The Company’s seasonal net loss for the quarter ended September 30, 2008 decreased by $158,000, or 44 percent, compared to the same period in 2007. The Company experienced a net loss of approximately $198,000, or $0.03 per share (diluted) during the quarter compared to a net loss of approximately $356,000, or $0.05 per share (diluted) during the same quarter in 2007. The Company’s Delmarva natural gas distribution and propane distribution operations typically experience seasonal losses or reduced earnings during the third quarter, because heating customers do not require natural gas or propane in the summer months.

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For the Three Months Ended September 30,	2008			2007			Change
Net Income (Loss)
Continuing operations	$	(198,298	)	$	(359,970	)	$	161,672
Discontinued operations		-			4,072			(4,072	)
Total Net Loss	$	(198,298	)	$	(355,898	)	$	157,600

Diluted Loss Per Share
Continuing operations	$	(0.03	)	$	(0.05	)	$	0.02
Discontinued operations		-			-			-
Total Diluted Loss Per Share	$	(0.03	)	$	(0.05	)	$	0.02

The period-over-period decrease in quarterly losses reflects primarily an increase in the operating income from the Company’s natural gas segment, partially offset by an increased operating loss from the propane segment.

For the Three Months Ended September 30,	2008			2007			Change
Operating Income (Loss)
Natural Gas	$	2,938,444		$	2,118,594		$	819,850
Propane		(2,134,919	)		(1,445,093	)		(689,826	)
Advanced Information Services		276,633			238,877			37,756
Other & eliminations		90,235			73,256			16,979
Operating Income		1,170,393			985,634			184,759

Other Loss		(91,631	)		(13,481	)		(78,150	)
Interest Charges		1,487,812			1,695,597			(207,785	)
Income Taxes		(210,752	)		(363,474	)		152,722
Net Loss from Continuing Operations	$	(198,298	)	$	(359,970	)	$	161,672

The period-over-period increase in operating income resulted primarily from the following:

·	Growth in the number of customers and improved supply management techniques produced a period-over-period increase of $481,000 or a 198 percent in gross margin for the Company’s natural gas marketing operation.

·	The Company estimates that weather contributed $231,000 to gross margin in the third quarter of 2008 compared to the same period in 2007, as temperatures on the Delmarva Peninsula were colder during the current period.

Lower depreciation allowances and lower asset removal cost allowances approved in rate proceedings for the Company’s Delmarva natural gas distribution operations, contributed to the period-over-period decrease in depreciation expense and asset removal costs of $22,000 and $319,000, respectively, in the third quarter of 2008.

·	New transportation capacity contracts implemented for the natural gas transmission operation in November 2007 provided $316,000 of additional gross margin in the third quarter of 2008.

Despite the continued slowdown in new housing construction as a result of the unfavorable economic conditions in that market, the Delmarva natural gas distribution operations continued to experience strong period-over-period customer growth with a five-percent increase in residential customers over the third quarter of 2007.

·	Volatile wholesale propane prices in the third quarter of 2008 contributed to the gross margin increase of $220,000 for the Company’s propane wholesale and marketing operation.

Declining propane prices during September of 2008 had a negative impact on operating income for the propane distribution operations as the Company adjusted the valuation of its propane inventory to current market prices in accordance with Accounting Research Bulletin No. 43. This adjustment resulted in reduced gross margin during the third quarter of 2008 compared to the same period in 2007. Additionally, the Company recognized a charge of $475,000 to cost of sales as its price swap agreement was marked-to-market as of the end of the third quarter of 2008.

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Natural Gas

The natural gas segment earned operating income of $2.9 million for the third quarter in 2008 compared to $2.1 million for the corresponding quarter in 2007, an increase of $820,000, or 39 percent.

For the Three Months Ended September 30,	2008		2007		Change
Revenue	$	37,358,678	$	29,638,951	$	7,719,727
Cost of sales		24,866,887		18,266,820		6,600,067
Gross margin		12,491,791		11,372,131		1,119,660

Operations & maintenance		6,598,154		6,585,289		12,865
Depreciation & amortization		1,682,804		1,600,909		81,895
Other taxes		1,272,389		1,067,339		205,050
Other operating expenses		9,553,347		9,253,537		299,810
Total Operating Income	$	2,938,444	$	2,118,594	$	819,850


Statistical Data — Delmarva Peninsula
Heating degree-days ("HDD"):
Actual		69		25		44
10-year average (normal)		55		59		(4	)

Estimated gross margin per HDD	$	1,937	$	2,283	$	(346	)

Per residential customer added:
Estimated gross margin	$	375	$	372	$	3
Estimated other operating expenses	$	103	$	106	$	(3	)

Residential Customer Information
Average number of customers:
Delmarva		44,726		42,742		1,984
Florida		13,221		13,127		94
Total		57,947		55,869		2,078

Gross margin for the Company’s natural gas segment increased by $1.1 million, or 10 percent, and other operating expenses increased by $300,000, or three percent, for the third quarter of 2008 compared to the same period in 2007. The gross margin increases of $331,000 for the natural gas transmission operation, $308,000 for the natural gas distribution operations and $481,000 for the natural gas marketing operation are further explained below.

Natural Gas Transmission

The natural gas transmission operation achieved gross margin growth of $331,000, or seven percent, in the third quarter of 2008 compared to the same period in 2007. The significant items contributing to the increase in gross margin include the following:

·	New transportation capacity contracts implemented in November 2007 contributed $316,000 to gross margin in the third quarter of 2008 and are expected to generate a total annual increase in gross margin of $1.2 million above the gross margin for 2007.

The increase in gross margin for the third quarter of 2008 was impacted by a $115,000 adjustment made during the third quarter of 2007, which reduced gross margin for that quarter, as the operation settled its FERC rate proceeding, and the settlement rates became effective on September 1, 2007. A further discussion of the FERC rate proceeding is provided within the “Rates and Regulatory” section of Note 4, “Commitments and Contingencies,” to these unaudited Condensed Consolidated Financial Statements.

Interruptible sales revenue, net of required margin-sharing, decreased by $221,000 in the third quarter of 2008 compared to the same period in 2007. Interruptible customers include large industrial customers whose service can be temporarily interrupted when necessary to meet the needs of firm customers. The settlement in the 2007 FERC rate proceeding requires the Company to share with its firm service customers ninety percent of its interruptible natural gas transmission revenues above a margin-sharing threshold. The third quarter 2008 decrease in interruptible revenue, compared to third quarter 2007, is the result of the operation reaching its margin-sharing threshold during the second quarter of 2008, whereas it reached that threshold in the fourth quarter of 2007. For the same reason, the Company expects its natural gas transmission operation to report a decrease of approximately $94,000 in interruptible services revenue for the fourth quarter, compared to the corresponding period in 2007.

·	The remaining $121,000 increase in gross margin in the third quarter of 2008 was attributable to other various factors.

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An increase of $44,000 in other operating expenses partially offset the increased gross margin. The factors contributing to the increase in other operating expenses are the following:

·	The increased level of capital investment resulted in higher depreciation expense and property taxes of $98,000 and $128,000, respectively.

·	Rent expense increased $44,000 as Eastern Shore began incurring additional rental expense in January 2008 for a new office building.

Offsetting these increases was a decrease of $270,000 in pipeline integrity costs, which the Company incurred in the third quarter of 2007 to comply with federal pipeline integrity regulations, issued in May 2004, requiring natural gas transmission companies to assess the integrity of at least fifty percent of their covered pipeline segments by December 17, 2007.

·	Other operating expenses relating to various items increased collectively by approximately $44,000.

Natural Gas Distribution

Gross margin for the Company’s natural gas distribution operations increased by $308,000, or five percent, for the third quarter in 2008 compared to the same period in 2007. The gross margin increases of $275,000 for the Delmarva natural gas distribution operations and $33,000 for the Florida natural gas distribution operations are further explained below.

The Delmarva distribution operations experienced an increase of $275,000, or eight percent, in gross margin. The significant items contributing to the increase in gross margin include the following:

Continued residential customer growth contributed to the increase in gross margin. Although the Company continues to see a slowdown in new housing construction market as a result of the unfavorable conditions in that market, the average number of residential customers on the Delmarva Peninsula increased by 1,983, or five percent, for the third quarter of 2008 compared to the same period in 2007, and the Company estimates that these additional residential customers contributed approximately $117,000 to gross margin during the third quarter of 2008.

The Company estimates that weather contributed $123,000 to gross margin in the three months ended September 30, 2008 compared to the same period in 2007, as temperatures on the Delmarva Peninsula were colder in 2008. The colder weather in the third quarter of 2008 provided for 69 heating degree-days compared to 25 for the same period in 2007. Degree-day data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature. A degree-day is the measure of the variation in the weather based on the extent to which the average daily temperature (from 10:00 am to 10:00 am) falls below 65 degrees Fahrenheit. Each degree of temperature below 65 degrees Fahrenheit is counted as one heating degree day.

·	Interruptible sales revenue, net of required margin-sharing, increased by $84,000 in the third quarter of 2008 compared to the same period in 2007, as customers took advantage of lower natural gas prices in comparison to prices for alternative fuels.

·	Offsetting the increases in gross margin in the third quarter of 2008 was a $49,000 decrease in gross margin attributable to other various factors.

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Gross margin for the Florida distribution operation increased by $33,000, or one percent, in the third quarter of 2008 compared to the same period in 2007. This increase in gross margin is due primarily to higher volumes sold to non-residential customers during the period.

Other operating expenses for the natural gas distribution operations increased by $196,000 in the third quarter of 2008 compared to the same period in 2007. Among the key components of the increase were the following:

·	Corporate costs allocated to the natural gas distribution operations increased by $192,000.

·	Vehicle fuel and vehicle depreciation increased by $26,000 and $60,000, respectively, compared to the prior year as a result of rising gasoline and diesel fuel costs and higher depreciation rates for vehicles.

·	Costs relating to outside services, such as legal fees and consulting costs increased by $134,000 as a result of an increased number of projects currently under review.

·	Property taxes increased by $65,000 as a result of the Company’s continued capital investments.

Depreciation expense and asset removal costs decreased by $13,000 and $290,000, respectively, in the third quarter of 2008 compared to the same period in 2007, primarily as a result of the Delmarva operations’ rate proceedings, which provided for lower depreciation allowances and lower asset removal cost allowances. These decreases were partially offset by depreciation expense on higher plant balances as a result of the Company’s continued capital investments.

·	In addition, other operating expenses relating to various minor items increased by approximately $22,000.

Natural Gas Marketing

Gross margin for the natural gas marketing operation increased by $481,000, or 198 percent, for the third quarter of 2008 compared to the same period in 2007. This increase was primarily the result of growth in the number of its customers and enhanced gas supply management processes. Other operating expenses increased by $59,000 for the natural gas marketing operation; this increase is attributable to higher incentive compensation based on the improved earnings in 2008 and to a higher allowance for uncollectible accounts that normally accompany customer growth.

Propane

The propane segment experienced a seasonal operating loss of $2.1 million, representing an increased loss of $690,000, or 48 percent, for the third quarter of 2008 compared to an operating loss of $1.4 million for the same period in 2007.

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For the Three Months Ended September 30,	2008			2007			Change
Revenue	$	8,758,648		$	7,923,129		$	835,519
Cost of sales		6,641,832			5,383,480			1,258,352
Gross margin		2,116,816			2,539,649			(422,833	)

Operations & maintenance		3,572,654			3,330,952			241,702
Depreciation & amortization		509,100			468,698			40,402
Other taxes		169,981			185,092			(15,111	)
Other operating expenses		4,251,735			3,984,742			266,993
Total Operating Loss	$	(2,134,919	)	$	(1,445,093	)	$	(689,826	)


Statistical Data — Delmarva Peninsula
Heating degree-days ("HDD"):
Actual		69			25			44
10-year average (normal)		55			59			(4	)

Estimated gross margin per HDD	$	2,465		$	1,974		$	491

Gross margin for the Company’s propane segment decreased by $423,000, or 17 percent, and other operating expenses increased by $267,000, or seven percent, for the third quarter of 2008 compared to the same period in 2007. The gross margin decrease of $722,000 for the Delmarva propane distribution operations was partially offset by higher gross margins of $79,000 for the Florida propane distribution operations, and $220,000 for the propane wholesale and marketing operation, which are further explained below.

Delmarva Propane Distribution

The Delmarva propane distribution operation’s decrease in gross margin of $722,000 resulted from the following:

As discussed in Note 11 “Financial Instruments,” the Company marked its price swap agreement to market as a result of the continual decline in propane prices experienced during the third quarter of 2008. The marking of this agreement to market resulted in a $475,000 increase to cost of sales during the period.

Gross margin decreased by $151,000 in the third quarter of 2008, compared to the same period in 2007, because of a $0.08 decrease in the average gross margin per retail gallon. This decrease was partially attributed to the Company’s write-down of its inventory valuation at quarter end in response to market prices of propane declining below the Company’s inventory price per gallon.

Non-weather-related volumes sold in the third quarter of 2008 decreased by 238,000 gallons, or 11 percent. This decrease in gallons sold reduced gross margin by approximately $165,000 for the Delmarva propane distribution operation compared to the third quarter of 2007. Factors contributing to this decrease in gallons sold were customer conservation, a reduced number of customers and the timing of propane deliveries.

Partially offsetting these decreases was an increase in gross margin from colder weather on the Delmarva Peninsula. Temperatures on the Delmarva Peninsula in the third quarter of 2008 provided for 69 heating degree-days compared to 25 for the same period in 2007, which contributed to an estimated increase of 149,000 gallons, or five percent, sold during this period in 2008 compared to the same period in 2007. The Company estimates that the colder weather and increased volumes sold had a positive impact of approximately $108,000 for the Delmarva propane distribution operation compared to the third quarter of 2007.

·	The remaining $39,000 decrease in gross margin can be attributed to various other factors, including higher tank and meter rental fees.

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Total other operating expenses increased by $167,000 for the Delmarva propane operations in the third quarter of 2008 compared to the same period in 2007. The significant items contributing to this increase are explained below:

·	Vehicle fuel and maintenance expense increased by $59,000 and $57,000, respectively, as a result of rising costs of gasoline, diesel fuel, repairs and maintenance.

·	Sales expense increased by $19,000 in the third quarter of 2008 compared to the same period in 2007 as a result of additional Community Gas Systems (“CGS”) customers. This expenditure will continue to increase as more CGS customers are added.

·	Depreciation and amortization expense increased by $18,000 as a result of the Company’s increase in capital investments over the prior year.

·	Incentive compensation and commissions costs decreased by $62,000 as a result of the lower operating results in the third quarter of 2008 compared to the same period in 2007.

·	In addition, other operating expenses relating to various items increased by approximately $76,000.

Florida Propane Distribution

The Florida propane distribution operation experienced an increase in gross margin of $79,000, or 36 percent, in the third quarter of 2008 compared to the same period in 2007. The higher gross margin is attributable to an increase of $51,000 from an increased number of gallons sold to residential customers and $31,000 from a higher average gross margin per retail gallon. These increases were partially offset by a decrease in the number of gallons sold to non-residential customers. Other operating expenses in the third quarter of 2008, compared to the same period in 2007, increased by $39,000, due primarily to increases in depreciation expense and allowances for uncollectible accounts, which were partially offset by lower payroll related costs.

Propane Wholesale and Marketing

Gross margin for the Company’s propane wholesale marketing operation increased by $220,000, or 41 percent, in the third quarter of 2008 compared to the same period in 2007. This increase reflects the larger number of market opportunities that arose in the third quarter of 2008, due to price volatility in the propane wholesale market, which exceeded the level of price fluctuations experienced in 2007. The increase in gross margin was partially offset by higher other operating expenses of $61,000, due primarily to higher incentive compensation as a result of the improved operating results in the third quarter of 2008 compared to the third quarter of 2007.

Advanced Information Services

The advanced information services segment earned operating income of $277,000 for the third quarter in 2008 compared to $239,000 for the corresponding quarter in 2007, an increase of $38,000, or 16 percent.

For the Three Months Ended September 30,	2008		2007		Change
Revenue	$	3,742,177	$	4,074,779	$	(332,602	)
Cost of sales		2,141,910		2,176,602		(34,692	)
Gross margin		1,600,267		1,898,177		(297,910	)

Operations & maintenance		1,121,819		1,472,527		(350,708	)
Depreciation & amortization		47,715		36,544		11,171
Other taxes		154,100		150,230		3,870
Other operating expenses		1,323,634		1,659,301		(335,667	)
Total Operating Income	$	276,633		238,876	$	37,757

Gross margin for the Company’s advanced information services segment decreased by $298,000, or 16 percent, and other operating expenses decreased by $336,000, or 20 percent, for the third quarter of 2008 compared to the same period in 2007.

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The period-over-period decrease in gross margin was attributable to lower consulting revenues as the number of billable hours decreased by 16 percent in the third quarter of 2008 compared to the same period in 2007. The lower number of billable hours was partially offset by a six percent increase in the average billing rate.

Other operating expenses decreased by $336,000 in the third quarter of 2008, compared to the same period in 2007. This decrease in operating expenses is primarily attributable to the following developments:

·	Incentive compensation decreased by $269,000 during the period as a result of the lower gross margin.

·	The decrease of $179,000 in the allowance for uncollectible accounts in the third quarter of 2008 was driven by an increase of $228,000 in that allowance during the third quarter of 2007 for a customer in the mortgage lending business that filed for bankruptcy during that period.

·	These decreases in other operating expenses were partially offset by a $100,000 increase in payroll costs due to an increase in non-billable staffing levels added to support future growth.

·	In addition, other operating expenses relating to various items increased by approximately $12,000.

Other Business Operations and Eliminations

Other operations, consisting primarily of subsidiaries that own real estate leased to other Company subsidiaries, generated an operating income of approximately $90,000 for the third quarter of 2008 compared to an operating income of approximately $73,000 for the same period in 2007.

For the Three Months Ended September 30,	2008		2007		Change
Revenue	$	163,074	$	156,513	$	6,561
Cost of sales		-		-		-
Gross margin		163,074		156,513		6,561

Operations & maintenance		28,909		28,239		670
Depreciation & amortization		28,622		39,545		(10,923	)
Other taxes		16,078		16,242		(164	)
Other operating expenses		73,609		84,026		(10,417	)
Operating Income - Other		89,465		72,487		16,978
Operating Income - Eliminations (1)		770		770		-
Total Operating Income	$	90,235	$	73,257	$	16,978

(1) Eliminations are entries required to eliminate activities between business segments from the consolidated results.

Interest Expense

Total interest expense for the third quarter of 2008 decreased by approximately $208,000, or 12 percent, compared to the same period in 2007. The lower interest expense is primarily a result of the following developments:

Interest on long-term debt decreased by $140,000 in the third quarter of 2008 compared to the same period in 2007 as the Company reduced its average long-term debt balance by $7.8 million. The Company’s average long-term debt during the third quarter of 2008 was $69.8 million, with a weighted average interest rate of 6.61 percent, compared to $77.6 million, with a weighted average interest rate of 6.67 percent, for the same period in 2007.

Interest on short-term borrowings increased by $22,000 in the third quarter of 2008 compared to the same period in 2007, based upon an increase of $24.3 million in the Company’s average short-term borrowing balance. The impact of the higher borrowing was partially offset by a weighted average interest rate that was nearly three percentage points lower in 2008 and a higher amount of interest that was capitalized during the period associated with increased capital expenditures. The Company’s average short-term borrowing during the third quarter of 2008 was $43.5 million, with a weighted average interest rate of 2.67 percent, compared to $19.2 million, with a weighted average interest rate of 5.66 percent, for the same period in 2007.

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Income Taxes

The Company had an income tax benefit for the three months ended September 30, 2008 of $211,000 compared to an income tax benefit of $363,000 for the three months ended September 30, 2007. The effective tax rate for the third quarter of 2008 is 51.5 percent compared to an effective tax rate of 50.2 percent for the third quarter of 2007. Contributing to the period-over-period increase in the effective tax rate is an increase in the corporate income tax rate for the State of Maryland. The Maryland legislature enacted legislation that increased the corporate income tax rate from 7.0 percent to 8.25 percent for tax years that began after December 31, 2007. In addition, the seasonality of the Company’s business segments impacts the effective tax rate for interim reporting periods.

Results of Operations for the Nine Months Ended September 30, 2008

The following discussions of operating income and segment results for the nine months ended September 30, 2008 and 2007 include use of the term “gross margin.” Gross margin is determined by deducting the cost of sales from operating revenue. Cost of sales includes the purchased gas cost for natural gas and propane and the cost of labor spent on direct revenue-producing activities. Gross margin should not be considered an alternative to operating income or net income, which is determined in accordance with GAAP. Chesapeake believes that gross margin, although a non-GAAP measure, is useful and meaningful to investors as a basis for making investment decisions. It provides investors with information that demonstrates the profitability achieved by the Company under its allowed rates for regulated operations and under its competitive pricing structure for non-regulated segments. Chesapeake’s management uses gross margin in measuring the performance of its business units and has historically analyzed and reported gross margin information publicly. Other companies may calculate gross margin in a different manner.

Consolidated Overview

The Company experienced an increase of $78,000 in net income for the nine months ended September 30, 2008, compared to the same period in 2007, despite taking a charge of $1.2 million in the second quarter to other operating expenses for an unconsummated acquisition. Earnings per share remained unchanged at $1.34 per share (diluted) in the first nine months of 2008 compared to the first nine months of 2007. Absent the charge for the unconsummated acquisition, the Company estimates that net income would have increased by $835,000 in the first nine months of 2008 to $10.0 million, or $1.44 per share (diluted).

For the Nine Months Ended September 30,	2008		2007			Change
Net Income (Loss)
Continuing operations	$	9,194,968	$	9,139,193		$	55,775
Discontinued operations		-		(22,212	)		22,212
Total Net Income	$	9,194,968	$	9,116,981		$	77,987

Diluted Earnings Per Share
Continuing operations	$	1.34	$	1.34			-
Discontinued operations		-		-			-
Total Diluted Earnings Per Share	$	1.34	$	1.34			-

The period-over-period increase in net income reflects an increase in operating income and a decrease in interest expense, which were partially offset by higher income taxes and lower other income. Operating income increased by $243,000 to $19.5 million for the first nine months of 2008 compared to $19.3 million for the same period in 2007, as the gross margin increase of $2.4 million, or four percent, was partially offset by a $1.7 million increase in other operating expenses. The increase in gross margin was driven primarily by continued growth, increased interruptible services revenue, and increased rates for the natural gas segment, partially offset by warmer weather on the Delmarva Peninsula and, for the propane segment, lower non-weather-related sales volumes and margin per gallon. Contributing to the higher operating expenses in 2008 was the $1.2 million charge associated with the unconsummated acquisition in the second quarter.

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For the Nine Months Ended September 30,	2008			2007		Change
Operating Income
Natural Gas	$	18,143,831		$	15,726,858	$	2,416,973
Propane		684,517			2,882,565		(2,198,048	)
Advanced Information Services		451,574			466,404		(14,830	)
Other & eliminations		260,626			221,444		39,182
Operating Income		19,540,548			19,297,271		243,277

Other Income (Loss)		(10,535	)		277,194		(287,729	)
Interest Charges		4,469,918			4,889,548		(419,630	)
Income Taxes		5,865,127			5,545,725		319,402
Net Income from Continuing Operations	$	9,194,968			9,139,192	$	55,776

The period-over-period increase in operating income resulted primarily from the following:

Rate increases, lower depreciation allowances and lower asset removal cost allowances contributed $1.9 million to operating income for the natural gas segment in the first nine months of 2008 as a result of rate proceedings for the Company’s Delmarva natural gas distribution and natural gas transmission operations.

·	Growth in the number of customers, improved supply management techniques and favorable imbalance resolutions with interstate pipelines produced a higher gross margin of $1.1 million for the Company’s natural gas marketing operation.

·	New transportation capacity contracts implemented for the natural gas transmission operation in November 2007, provided for $925,000 of additional gross margin in the first nine months of 2008.

·	The Company’s natural gas transmission and Delmarva natural gas distribution operations experienced a combined increased in interruptible services revenue, net of required margin-sharing, of $477,000 in the first nine months of 2008 compared to the same period in 2007.

·	The Delmarva natural gas distribution operations have experienced residential and commercial customer growth of five percent and two percent, respectively, in 2008, generating $893,000 of additional gross margin.

Warmer weather on the Delmarva Peninsula reduced gross margin by $341,000 for the first nine months of 2008 for the Company’s Delmarva natural gas and propane distribution operations. In addition, gross margin from the propane segment decreased as the Delmarva distribution operations experienced lower non-weather related sales volumes and decreases in the average gross margin per retail gallon.

Declining propane prices had a negative impact on operating income for the Company’s propane distribution operations as it adjusted the valuation of its propane inventory to current market prices in accordance with Accounting Research Bulletin No. 43. This adjustment resulted in an increased cost of sales during the first nine months of 2008 compared to the same period in 2007.

·	Additionally, the Delmarva propane distribution division marked its price swap agreement to market to reflect the declining propane prices experienced during the third quarter of 2008. The marking of this agreement to market resulted in a $475,000 increase to cost of sales during the period.

Natural Gas

The natural gas segment earned operating income of $18.1 million for the first nine months in 2008 compared to $15.7 million for the corresponding period in 2007, an increase of $2.4 million, or 15 percent.

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For the Nine Months Ended September 30,	2008		2007		Change
Revenue	$	160,165,539	$	134,514,372	$	25,651,167
Cost of sales		113,130,229		91,166,528		21,963,701
Gross margin		47,035,310		43,347,844		3,687,466

Operations & maintenance		19,388,915		19,288,860		100,055
Terminated acquisition costs		890,053		-		890,053
Depreciation & amortization		4,977,463		5,231,101		(253,638	)
Other taxes		3,635,048		3,101,025		534,023
Other operating expenses		28,891,479		27,620,986		1,270,493
Total Operating Income	$	18,143,831	$	15,726,858	$	2,416,973


Statistical Data — Delmarva Peninsula
Heating degree-days ("HDD"):
Actual		2,772		2,991		(219	)
10-year average (normal)		2,855		2,819		36

Estimated gross margin per HDD	$	1,937	$	2,283	$	(346	)

Per residential customer added:
Estimated gross margin	$	375	$	372	$	3
Estimated other operating expenses	$	103	$	106	$	(3	)

Residential Customer Information
Average number of customers:
Delmarva		45,427		43,228		2,199
Florida		13,418		13,250		168
Total		58,845		56,478		2,367

Gross margin for the Company’s natural gas segment increased by $3.7 million, or nine percent, and other operating expenses increased by $1.3 million, or five percent, for the first nine months of 2008 compared to the same period in 2007. Gross margin increases of $1.6 million for the natural gas transmission operation, $974,000 for the natural gas distribution operations and $1.1 million for the natural gas marketing operation, are further explained below.

Natural Gas Transmission

The natural gas transmission operation achieved gross margin growth of $1.6 million, or ten percent, in the first nine months of 2008 compared to the same period in 2007. The significant items contributing to the increase in gross margin include the following:

New transportation capacity contracts implemented in November 2007 contributed $925,000 to gross margin in the first nine months of 2008. In 2008, these new transportation capacity contracts are expected to generate an additional annual gross margin of $1.2 million above the gross margin achieved in 2007.

Interruptible sales revenue, net of required margin-sharing, increased by $111,000 in the first nine months of 2008 compared to the same period in 2007. For the fourth quarter of 2008, however, the Company expects its natural gas transmission operation to report a decrease of approximately $94,000 in interruptible services revenue, compared to the corresponding period in 2007, because the operation reached its margin-sharing threshold in the second quarter of 2008; in 2007, it reached the threshold in the fourth quarter. The settlement in the 2007 FERC rate proceeding requires the Company, upon reaching the margin-sharing threshold, to share ninety percent of its interruptible natural gas transmission revenues with its firm service customers.

The implementation of rate case settlement rates, effective September 1, 2007, contributed an additional $405,000 to gross margin in the first nine months of 2008 compared to the same period in 2007. A further discussion of the FERC rate proceeding is provided within the “Rates and Regulatory” section of Note 4, “Commitments and Contingencies,” to the unaudited Condensed Consolidated Financial Statements.

The increase in gross margin for the third quarter of 2008 was impacted by a $115,000 adjustment made during the third quarter of 2007, which reduced gross margin for that quarter, as the operation settled its FERC rate proceeding and the settlement rates became effective on September 1, 2007. A further discussion of the FERC rate proceeding is provided within the “Rates and Regulatory” section of Note 4, “Commitments and Contingencies,” to these unaudited Condensed Consolidated Financial Statements.

·	The remaining $44,000 increase to gross margin was attributable to various other items.

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An increase of $647,000 in other operating expenses partially offset the increased gross margin. The factors contributing to the increase in other operating expenses include the following:

·	Corporate costs allocated to the natural gas transmission operation increased by $579,000 as a result of: (1) $341,000 for the allocation of a portion of the unconsummated acquisition costs previously discussed, and (2) the Company updating its annual corporate cost allocations.

·	Incentive compensation costs increased by $58,000 as a result of the improved operating results in 2008 compared to 2007.

·	Rent and utility expenses increased by $132,000 and $47,000, respectively, as Eastern Shore began incurring additional rental expense in January 2008 for new office facilities.

·	The higher level of capital investment caused increased property taxes of $276,000.

·	Other operating expenses relating to various items increased by approximately $95,000.

The Company experienced a decrease of $282,000 in pipeline integrity costs, which the Company incurred in the third quarter of 2007 to comply with federal pipeline integrity regulations, issued in May 2004, requiring natural gas transmission pipeline companies to assess the integrity of at least fifty percent of their covered pipeline segments by December 17, 2007.

Partially offsetting these increases was a decrease of $125,000 in depreciation expense and a decrease of $133,000 in regulatory expense. Both of these lower expenses are a result of the 2007 rate case. As part of the rate case settlement that became effective September 1, 2007, the FERC approved a reduction in depreciation rates for Eastern Shore. The impact of the lower depreciation rates were partially offset by the additional depreciation expense from higher plant balances produced by increased capital investment. Also, the Company incurred regulatory expenses in the first nine months of 2007 associated with the FERC rate proceeding.

Natural Gas Distribution

Gross margin for the Company’s natural gas distribution operations increased by $974,000, or four percent, for the first nine months of 2008 compared to the same period in 2007. The gross margin increases of $839,000 for the Delmarva natural gas distribution operations and $135,000 for the Florida natural gas distribution operations are further explained below.

The Delmarva distribution operations experienced an increase of $839,000, or five percent, in gross margin. The significant items contributing to the increase in gross margin include the following:

Continued residential and commercial customer growth contributed to increases in gross margin. Although the Company continues to see a slowdown in new housing construction as a result of unfavorable market conditions in the housing industry, the average number of residential customers on the Delmarva Peninsula increased by 2,199, or five percent, for the first nine months of 2008 compared to the same period in 2007, and the Company estimates that these additional residential customers contributed approximately $667,000 to gross margin during the first nine months of 2008. The Company further estimates that the commercial customers added during the first nine months of 2008 generated additional gross margin of $238,000 during the period.

·	Interruptible services revenue, net of required margin-sharing, increased by $366,000 in the first nine months of 2008, compared to the same period in 2007, as customers took advantage of lower natural gas prices compared to prices for alternative fuels.

Partially offsetting these increases to gross margin was the negative impact of warmer weather on the Delmarva Peninsula and lower consumption per customer in the first nine months of 2008 compared to the same period in 2007. The Company estimates that warmer weather reduced gross margin by $341,000 as temperatures on the Delmarva Peninsula were seven percent warmer in the first nine months of 2008. In addition, the Company estimates that lower consumption per customer further reduced gross margin by $83,000. The lower consumption reflects customer conservation efforts in light of higher energy costs, more energy-efficient housing, and current economic conditions.

·	The remaining $6,000 net decrease to gross margin was attributable to various other items.

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Gross margin for the Florida distribution operation increased by $135,000, or two percent, in the first nine months of 2008 compared to the same period in 2007. The higher gross margin for the period is attributable primarily to the increase in customers as the operation experienced a one percent growth in residential customers, an increase in non-residential customer volumes, and higher revenues from third-party natural gas marketers.

Other operating expenses for the natural gas distribution operations increased by $625,000 in the first nine months of 2008 compared to the same period in 2007. Among the key components producing this net increase were the following:

·	Corporate costs allocable to the natural gas distribution operations increased by $1.1 million as a result of: (1) $533,000 for the allocation of a portion of the terminated acquisition costs previously discussed, and (2) the Company updating its annual corporate cost allocations.

·	Incentive compensation increased by $256,000 in the first nine months of 2008 as the Delmarva and Florida operations experienced improved earnings compared to the prior year.

·	Costs relating to outside services, such as legal fees and consulting costs, increased by $234,000 as a result of several new projects.

·	Property taxes increased by $179,000 as a result of the Company’s continued capital investments.

·	Vehicle fuel and depreciation expense increased by $73,000 and $68,000, respectively, when compared to the prior year as a result of rising costs of gasoline and diesel fuel, and higher depreciation rates for vehicles.

Depreciation expense and asset removal costs decreased by $118,000 and $1.1 million, respectively, in the first nine months of 2008 compared to the same period in 2007, primarily as a result of the Delmarva operations’ rate proceedings, which provided for lower depreciation allowances and lower asset removal cost allowances

·	Maintenance costs for the Florida operation decreased by $76,000 during the first nine months of 2008 compared with the same period in 2007 due to the timing of costs to comply with federal pipeline integrity regulations, which were incurred in 2007.

·	Merchant payment fees decreased by $93,000, which resulted primarily from the Delmarva operations outsourcing the processing of credit card payments in April 2007.

·	In addition, other operating expenses relating to various other items increased by approximately $102,000.

Natural Gas Marketing

Gross margin for the natural gas marketing operation increased by $1.1 million, or 87 percent, for the first nine months of 2008 compared to the same period in 2007. The increase in gross margin was primarily the result of an increase in the number of customers to which it provides supply management services, enhanced gas supply management processes, and favorable imbalance resolutions with interstate pipelines. Other operating expenses decreased slightly by $1,000, which was attributable to lower payroll-related and benefit costs, partially offset with higher incentive compensation incurred as a result of the improved operating results and increases in the allowance for uncollectible accounts that normally accompany customer growth.

- 36 -

Propane

The propane segment earned operating income of $685,000 for the first nine months of 2008 compared to $2.9 million for the corresponding period in 2007, a decrease of $2.2 million, or 76 percent.

For the Nine Months Ended September 30,	2008		2007		Change
Revenue	$	48,056,605	$	42,340,104	$	5,716,501
Cost of sales		33,898,689		26,646,852		7,251,837
Gross margin		14,157,916		15,693,252		(1,535,336	)

Operations & maintenance		11,029,664		10,790,941		238,723
Terminated acquisition costs		272,718		-		272,718
Depreciation & amortization		1,510,908		1,373,066		137,842
Other taxes		660,109		646,680		13,429
Other operating expenses		13,473,399		12,810,687		662,712
Total Operating Income	$	684,517	$	2,882,565	$	(2,198,048	)


Statistical Data — Delmarva Peninsula
Heating degree-days ("HDD"):
Actual		2,772		2,991		(219	)
10-year average (normal)		2,855		2,819		36

Estimated gross margin per HDD	$	2,465	$	1,974	$	491

The period-over-period decrease in operating income was due primarily to the Delmarva propane distribution operation, which experienced a lower gross margin from warmer weather on the Delmarva Peninsula, a lower margin per retail gallon from decreased propane market prices and lower sales volumes in the first nine months of 2008.

The gross margin decrease of $2.0 million for the Delmarva propane distribution operations was partially offset by higher gross margin of $65,000 for the Florida propane distribution operations and $390,000, for the propane wholesale and marketing operation, which are further explained below:

Delmarva Propane Distribution

The Delmarva propane distribution operation’s decrease in gross margin of $2.0 million resulted from the following:

Temperatures on the Delmarva Peninsula were seven percent warmer in the first nine months of 2008 compared to the same period in 2007, which contributed to a decrease of 743,000 gallons, or five percent, sold during this period in 2008 compared to the same period in 2007. The Company estimates that the warmer weather and decreased volumes sold had a negative impact of approximately $540,000 for the Delmarva propane distribution operation compared to the first nine months of 2007.

Non-weather-related volumes sold in the first nine months of 2008 decreased by 1.0 million gallons, or six percent. This decrease in gallons sold reduced gross margin by approximately $719,000 for the Delmarva propane distribution operation compared to the first nine months of 2007. Factors contributing to this decrease in gallons sold included: customer conservation, a reduced number of customers and the timing of propane deliveries.

·	As discussed in Note 11 “Financial Instruments,” the Company marked its price swap agreement to market to reflect the declining propane prices experienced during the third quarter of 2008. The marking of this agreement to market resulted in a $475,000 increase to cost of sales during the period.

Gross margin decreased by $376,000 in the first nine months of 2008, compared to the same period in 2007, because of a $0.03 decrease in the average gross margin per retail gallon. This decrease occurs when market prices decrease and move closer to the Company’s inventory price per gallon, and the trend reverses when market prices of propane are greater than the Company’s average inventory price per gallon.

·	Gross margin from miscellaneous fees, including items such as tank and meter rentals, increased by $116,000 during the first nine months of 2008 compared to the same period in 2007.

·	The remaining $6,000 net decrease in gross margin can be attributed to various other items.

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Total other operating expenses increased by $425,000 for the Delmarva propane operations in the first nine months of 2008, compared to the same period in 2007. The significant items contributing to this increase are explained below:

·	Corporate costs allocable to the propane distribution operations increased by $519,000 as a result of, (1) $227,000 for the allocation of a portion of the unconsummated acquisition costs previously discussed, and (2) the Company updating its annual corporate cost allocations.

·	Vehicle fuel expense increased by $165,000 as a result of rising gasoline and diesel fuel costs.

·	The allowance for uncollectible accounts increased $58,000 due to increased revenues resulting from the higher cost of propane.

·	Sales expense increased by $69,000 in the first nine months of 2008 compared to the same period in 2007 as a result of added CGS customers. This expenditure will continue to increase as more CGS customers are added.

·	Depreciation and amortization expense increased by $58,000 as a result of an increase in the Company’s capital investments compared to the prior year.

Lower expenses of $178,000 were incurred in the first nine months of 2008 compared to the same period in 2007 for propane tank recertifications and maintenance. The Company incurred these costs in 2007 to maintain compliance with U.S. Department of Transportation (“DOT”) standards, which require propane tanks or cylinders to be recertified twelve years from their date of manufacture and every five years thereafter.

·	Incentive compensation and commissions costs decreased by $258,000 as a result of the lower operating results in 2008 compared to 2007.

·	Other operating expenses relating to various items decreased collectively by approximately $8,000.

Florida Propane Distribution

The Florida propane distribution operation experienced an increase in gross margin of $65,000, or seven percent, in the first nine months of 2008 compared to the same period in 2007. The higher gross margin is attributable to an increase of $88,000 from an increase in the number of gallons sold to residential customers, and $31,000, from a higher average gross margin per retail gallon. These increases in gross margin were partially offset by a decrease in the number of gallons sold to non-residential customers and lower service sales. Other operating expenses in the third quarter of 2008, compared to the same period in 2007, increased by $116,000, due primarily to increases in depreciation expense and allowance for uncollectible accounts, which were partially offset by lower payroll-related costs

Propane Wholesale and Marketing

Gross margin for the Company’s propane wholesale marketing operation increased by $390,000, or 21 percent, in the first nine months of 2008 compared to the same period in 2007. This increase reflects the larger number of market opportunities that arose in the first nine months of 2008 due to price volatility in the propane wholesale market, which exceeded the level of price fluctuations experienced in 2007. The increase in gross margin was partially offset by higher other operating expenses of $121,000, due primarily to higher payroll costs, incentive compensation and increased corporate costs, as $26,000 was allocated to the operation for a portion of the unconsummated acquisition costs. The higher period-over-period payroll costs and incentive compensation is the result of a position that was vacant during 2007 being filled in 2008 and higher operating results in 2008.

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Advanced Information Services

The advanced information services business experienced gross margin growth of approximately $54,000, or one percent, and contributed operating income of $452,000 for the first nine months of 2008, a decrease of $15,000 compared to the same period in 2007. Absent the unconsummated acquisition costs of $64,000 allocated to the advanced information services segment in the second quarter of 2008, the segment would have experienced an increase in its operating income of $49,000 for the first nine months of 2008 compared to the same period in 2007.

For the Nine Months Ended September 30,	2008		2007		Change
Revenue	$	11,215,591	$	11,195,976	$	19,615
Cost of sales		6,142,859		6,177,712		(34,853	)
Gross margin		5,072,732		5,018,264		54,468

Operations & maintenance		3,888,766		3,937,187		(48,421	)
Terminated acquisition costs		64,461		-		64,461
Depreciation & amortization		123,552		106,028		17,524
Other taxes		544,379		508,645		35,734
Other operating expenses		4,621,158		4,551,860		69,298
Total Operating Income	$	451,574	$	466,404	$	(14,830	)

Gross margin for the Company’s advanced information services segment increased by $54,000, or one percent, and other operating expenses increased by $69,000, or two percent, for the first nine months of 2008 compared to the same period in 2007.

The period-over-period increase in gross margin was attributable to the following:

·	Product sales increased by $326,000 as the operation enlarged its marketing and sales force; and

·	Consulting revenues decreased by $216,000 as higher average billing rates were not able to overcome a thirty-percent decrease in the number of billable hours.

Other operating expenses increased by $69,000 in the first nine months of 2008, compared to the same period in 2007. This increase in operating expenses is primarily attributable to the following developments:

·	Payroll and benefit costs increased by $356,000 and $25,000, respectively, due to an increase in non-billable staffing levels added to support future growth.

·	Incentive compensation decreased by $239,000 during the period as a result of the lower operating results.

·	The decrease of $205,000 in the allowance for uncollectible accounts in the first nine months of 2008 was driven by an increase of $228,000 in the allowance during the third quarter of 2007 for a customer in the mortgage lending business that filed for bankruptcy.

·	Corporate costs increased due primarily to the allocation of $64,000 as the segment’s portion of the terminated acquisition costs.

·	Other operating expenses relating to various items increased by approximately $68,000.

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Other Business Operations and Eliminations

Other operations, consisting primarily of subsidiaries that own real estate leased to other Company subsidiaries, generated an operating income of approximately $261,000 for the first nine months of 2008 compared to an operating income of approximately $221,000 for the same period in 2007.

For the Nine Months Ended September 30,	2008		2007		Change
Revenue	$	489,222	$	465,758	$	23,464
Cost of sales		-		-		-
Gross margin		489,222		465,758		23,464

Operations & maintenance		87,626		79,714		7,912
Terminated acquisition costs		12,396		-		12,396
Depreciation & amortization		85,866		120,358		(34,492	)
Other taxes		45,018		46,552		(1,534	)
Other operating expenses		230,906		246,624		(15,718	)
Operating Income - Other		258,316		219,134		39,182
Operating Income - Eliminations (1)		2,310		2,310		-
Total Operating Income	$	260,626	$	221,444	$	39,182

(1) Eliminations are entries required to eliminate activities between business segments from the consolidated results.

Interest Expense

Total interest expense for the first nine months of 2008 decreased by approximately $420,000, or nine percent, compared to the same period in 2007. The lower interest expense is primarily the result of the following developments:

Interest on long-term debt decreased by $420,000 in the first nine months of 2008 compared to the same period in 2007 as the Company reduced its average long-term debt balance by $7.9 million. The Company’s average long-term debt during the first nine months of 2008 was $69.8 million, with a weighted average interest rate of 6.63 percent, compared to $77.7 million, with a weighted average interest rate of 6.67 percent for the same period in 2007.

Interest on short-term borrowings increased by $152,000 in the first nine months of 2008 compared to the same period in 2007, based upon an increase of $21.3 million in the Company’s average short-term borrowing balance. The impact of the higher borrowing was partially offset by a weighted average interest rate that was nearly 2.7 percentage points lower in 2008 and a higher amount of interest that was capitalized during the period associated with increased capital expenditures. The Company’s average short-term borrowing during the first nine months of 2008 was $38.3 million, with a weighted average interest rate of 3.01 percent, compared to $17.0 million, with a weighted average interest rate of 5.70 percent, for the same period in 2007.

Income Taxes

Income tax expense for the first nine months of 2008 was $5.9 million compared to $5.5 million for the same period in 2007. The increase in income tax expense reflects primarily the higher earnings for the period and an increase of $27,000 to our tax accrual pursuant to the results of the IRS examination of our 2005 and 2006 consolidated federal tax returns. The effective tax rate for the first nine months of 2008 is 38.9 percent compared to an effective tax rate of 37.7 percent for the same period in 2007. Contributing to the period-over-period increase in the effective tax rate is an increase in the corporate income tax rate for the State of Maryland. The Maryland legislature enacted legislation that increased the corporate income tax rate from 7.0 percent to 8.25 percent for tax years that began after December 31, 2007.

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Financial Position, Liquidity and Capital Resources

Chesapeake’s capital requirements reflect the capital-intensive nature of its business and are principally attributable to its investment in new plant and equipment and the retirement of outstanding debt. The Company relies on cash generated from operations, short-term borrowing and other sources to meet normal working capital requirements and to finance capital expenditures. During the first nine months of 2008, net cash provided by operating activities was $13.4 million, cash used by investing activities was $24.1 million, and cash provided by financing activities was $10.7 million.

By comparison, during the first nine months of 2007, net cash provided by operating activities was $19.7 million, cash used by investing activities was $22.8 million, and cash used by financing activities was $437,000.

As of August 6, 2008, the Board of Directors has authorized the Company to borrow up to $85.0 million of short-term debt, as required, from various banks and trust companies under short-term lines of credit. As of September 30, 2008, Chesapeake had five unsecured bank lines of credit with three financial institutions, totaling $100.0 million, none of which requires compensating balances. These bank lines are available to provide funds for the Company’s short-term cash needs, to meet seasonal working capital requirements and to fund temporarily portions of its capital expenditures. Two of the bank lines, totaling $15.0 million, are committed. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks. The Company’s outstanding balance of short-term borrowing at September 30, 2008 and December 31, 2007 was $63.2 million and $45.7 million, respectively.

Chesapeake has budgeted $37.5 million for capital expenditures during 2008. This amount includes $17.0 million for natural gas distribution, $13.3 million for natural gas transmission, $5.9 million for propane distribution and wholesale marketing, $290,000 for advanced information services and $887,000 for other operations. The natural gas distribution and transmission expenditures are for expansion and improvement of facilities. The propane expenditures are to support customer growth, to acquire land for a future bulk storage facility, and to replace equipment. The advanced information services expenditures are for computer hardware, software and related equipment. The other operations category includes general plant, computer software and hardware. The Company expects to fund the 2008 capital expenditures program from short-term borrowing, cash provided by operating activities, and other sources. The capital expenditure program is subject to continuous review and modification. Actual capital requirements may vary from the above estimates due to a number of factors, including changing economic conditions, customer growth in existing areas, regulation, new growth opportunities, acquisition opportunities and availability of capital.

Capital Structure

The following presents the Company’s capitalization as of September 30, 2008 and December 31, 2007:

	September 30, 2008				December 31, 2007
	(In thousands, except percentages)
Long-term debt, net of current maturities	$	63,143	34	%	$	63,255	35	%
Stockholders' equity	$	123,340	66	%	$	119,577	65	%
Total capitalization, excluding short-term debt	$	186,483	100	%	$	182,832	100	%

As of September 30, 2008, common equity represented 66 percent of total capitalization, compared to 65 percent at December 31, 2007. If short-term borrowing and the current portion of long-term debt were included in total capitalization, the equity component of the Company’s capitalization would have been 48 percent at September 30, 2008, compared to 51 percent at December 31, 2007. Chesapeake remains committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access capital markets when required. This commitment, along with adequate and timely rate relief for the Company’s regulated operations, is intended to ensure that Chesapeake will be able to attract capital from outside sources at a reasonable cost. The Company believes that the achievement of these objectives will provide benefits to its customers, creditors, and investors.

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Shelf Registration

In July 2006, the Company filed a registration statement on Form S-3 with the SEC to issue up to $40.0 million in new common stock and/or debt securities. The registration statement was declared effective by the SEC in November 2006. In the fourth quarter of 2006, the Company sold 600,300 shares of common stock, including the underwriter’s exercise of an over-allotment option of 90,045 shares, under this registration statement, generating net proceeds of $19.7 million. At September 30, 2008, the Company had approximately $20.0 million remaining under this registration statement.

Cash Flows Provided By Operating Activities

Cash flows provided by operating activities were as follows:

For the Nine Months Ended September 30,	2008			2007			Change
Net Income	$	9,194,968		$	9,116,981		$	77,987
Non-cash adjustments to net income		15,338,265			11,301,666			4,036,600
Changes in working capital		(11,110,119	)		(726,719	)		(10,383,401	)
Net cash provided by operating activties	$	13,423,114		$	19,691,928		$	(6,268,814	)

Period-over-period changes in our cash flows from operating activities are attributable primarily to net income, non-cash adjustments, such as depreciation and deferred income taxes, and changes in our working capital. Changes in working capital are affected by weather, the price of natural gas and propane, the timing of customer collections, payments of natural gas and propane purchases, and deferred gas cost recoveries.

For the first nine months of 2008, net cash flow provided by operating activities was $13.4 million, a reduction of $6.3 million compared to the same period in 2007. The decrease was due primarily to the following developments:

·	Net cash flows due to the timing of collections and payments of trading contracts entered into by the Company’s propane wholesale and marketing operation;

·	Cash used for the purchase of propane inventory and natural gas purchases injected into storage for the upcoming winter season;

·	Reduction in regulatory liabilities, which resulted primarily from environmental expenditures and refunds to customers; and

·	Cash flows provided by non-cash adjustments for deferred income taxes. The increased deferred income taxes are the result of higher book-to-tax timing differences during the period that are attributable to the 2008 Economic Stimulus Act, which authorized bonus depreciation for certain assets.

Cash Flows Used in Investing Activities

Net cash flows used in investing activities totaled $24.1 million and $22.8 million during the nine months ended September 30, 2008 and 2007, respectively.

Cash utilized for capital expenditures was $23.7 million and $22.9 million for the first nine months of 2008 and 2007, respectively. Additions to property, plant and equipment in the first nine months of 2008 were primarily for natural gas transmission ($8.8 million), natural gas distribution ($10.9 million), propane distribution ($2.3 million), and other operations ($1.1 million).

·	The Company’s environmental expenditures exceeded amounts recovered through rates charged to customers in the first nine months of 2008 and 2007 by $403,000 and $166,000, respectively.

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Cash Flows Provided (Used) by Financing Activities

Cash flows provided by financing activities totaled $10.7 million for the first nine months of 2008 compared to cash used of $437,000 for the first nine months of 2007. Significant financing activities included the following:

·	During the first nine months of 2008, the Company had net borrowings from short-term debt of $16.2 million compared to net borrowings of $5.0 million in the first nine months of 2007.

During the first nine months of 2008, the Company paid $5.9 million in cash dividends compared with dividend payments of $5.2 million for the same time period in 2007. The increase in dividends paid in the first nine months of 2008, compared to 2007, reflects both growth in the annualized dividend rate and the increase in the number of shares outstanding.

·	The Company repaid $1.0 million of long-term debt during the first nine months of 2008 and 2007, respectively.

Off-Balance Sheet Arrangements

The Company has issued corporate guarantees to certain vendors of its propane wholesale marketing subsidiary and its Florida natural gas supply management subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of either subsidiary’s default. Neither subsidiary has ever defaulted on its obligations to pay suppliers. The liabilities for these purchases are recorded in the Consolidated Financial Statements when incurred. The aggregate amount guaranteed at September 30, 2008 was $22.9 million, with the guarantees expiring on various dates in 2008 and the first nine months of 2009.

Contractual Obligations

There has not been any material change in the contractual obligations presented in the Company’s 2007 Annual Report on Form 10-K, except for commodity purchase obligations and forward contracts entered into in the ordinary course of the Company’s business. Below is a summary of the commodity and forward contract obligations at September 30, 2008.

	Payments Due by Period
Purchase Obligations	Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years		Total
Commodities (1)	$	26,564,438	$	2,596,261	$	0	$	0	$	29,160,699
Propane (2)		64,144,260		-		-		-		64,144,260
Total Purchase Obligations	$	90,708,698	$	2,596,261	$	0	$	0	$	93,304,959

(1) The Company’s propane distribution operation may enter into a fair-value hedge of its inventory in order to mitigate the impact of wholesale price fluctuations. At September 30, 2008, the propane distribution operation had entered into a price swap agreement to protect the Company from the impact of price increases on the price-cap plan that we offer to customers. The Company considered this agreement to be an economic hedge that did not qualify for hedge accounting, as defined in SFAS 133. At September 30, 2008, the market price of propane had dropped below the swap agreement unit price. Consequently, the Company marked the agreement to market and recorded an unrealized loss of $475,000.
(2)The Company has also entered into forward sale contracts in the aggregate amount of $66.7 million. See Part I, Item 3, “Quantitative and Qualitative Disclosures about Market Risk,” below for further information.

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Environmental Matters

As more fully described in Note 4, “Commitments and Contingencies,” to these Unaudited Condensed Consolidated Financial Statements, Chesapeake has incurred costs relating to the completed or ongoing environmental remediation at three former manufactured gas plant sites. In addition, Chesapeake is currently participating in discussions regarding possible responsibility of the Company for remediation of a fourth former manufactured gas plant site located in Cambridge, Maryland. Chesapeake believes that future costs associated with these sites will be recoverable in rates or through sharing arrangements with, or contributions by, other responsible parties.

Other Matters

Rates and Regulatory Matters

The Company’s natural gas distribution operations in Delaware, Maryland and Florida are regulated by their state PSCs. Eastern Shore is subject to regulation by the FERC. At September 30, 2008, Chesapeake was involved in rates and/or regulatory matters in each of the jurisdictions in which it operates. Each of these rates or regulatory matters is fully described in Note 4, “Commitments and Contingencies,” to these Unaudited Condensed Consolidated Financial Statements.

Competition

The Company’s natural gas operations compete with other forms of energy, including electricity, oil and propane. The principal competitive factors are price and, to a lesser extent, accessibility. The Company’s natural gas distribution operations have several large volume industrial customers that have the capacity to use fuel oil as an alternative to natural gas. When oil prices decline, these interruptible customers may convert to oil to satisfy their fuel requirements. Oil prices, as well as the prices of electricity and other fuels, which are normally lower than the price of natural gas, are subject to fluctuation for a variety of reasons; therefore, future competitive conditions are not predictable. To address this uncertainty, the Company uses flexible pricing arrangements on both the supply and sales sides of this business to compete with the fluctuations in its customers’ alternative fuel prices. As a result of the transmission operation’s conversion to open access and the Florida gas distribution division’s restructuring of its services, these businesses have shifted from providing competitive sales service to providing transportation and contract storage services.

The Company’s natural gas distribution operations in Delaware, Maryland and Florida offer transportation services to certain commercial and industrial customers. In 2002, the Florida operation extended such service to residential customers. With transportation service available on the Company’s distribution systems, the Company is competing with third-party suppliers to sell gas to industrial customers. With respect to unbundled transportation services, the Company’s competitors include interstate transmission companies if distribution customers are located close enough to a transmission company’s pipeline to make a connection economically feasible. The customers at risk are usually large volume commercial and industrial customers with the financial resources and capability to bypass the Company’s distribution operations in this manner. In certain situations, the Company’s distribution operations may adjust services and rates for these customers to retain their business. The Company expects to continue to expand the availability of transportation service to additional classes of distribution customers in the future. The Company established a natural gas sales and supply operation in Florida to compete for customers eligible for transportation services. The Company also provides such sales service in Delaware.

The Company’s propane distribution operations compete with several other propane distributors in their service territories, primarily on the basis of service and price, emphasizing reliability of service and responsiveness. Competition is generally from local outlets of national distribution companies and local businesses, because distributors located in close proximity to customers incur lower costs of providing service. Propane competes with electricity as an energy source, because propane is typically less expensive than electricity, based on equivalent BTU value. Propane also competes with home heating oil as an energy source. Since natural gas has historically been less expensive than propane, propane is generally not distributed in geographic areas serviced by natural gas pipeline or distribution systems.

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The propane wholesale marketing operation competes against various marketers, many of which have significantly greater resources and are able to obtain price or volumetric advantages.

The advanced information services business faces significant competition from a number of larger competitors having substantially greater resources available to them. In addition, changes in the advanced information services industry are occurring rapidly, which could adversely impact the markets for the products and services offered by such businesses. This segment of the Company competes on the basis of technological expertise, service reputation and price.

Inflation

Inflation affects the cost of supply, labor, products and services required for operations, maintenance and capital improvements. While the impact of inflation has remained low in recent years, natural gas and propane prices are subject to rapid fluctuations. In the Company’s regulated natural gas distribution operations, fluctuations in natural gas prices are passed on to customers through the gas cost recovery mechanism in the Company’s tariffs. To help cope with the effects of inflation on its capital investments and returns, the Company seeks rate relief from regulatory commissions for its regulated operations and closely monitors the returns of its unregulated business operations. To compensate for fluctuations in propane gas prices, the Company adjusts its propane selling prices to the extent allowed by the market.

Recent Authoritative Pronouncements on Financial Reporting and Accounting

Recent accounting developments and their impact on our financial position, results of operations and cash flows are described in Note 5, “Recent Authoritative Pronouncements on Financial Reporting and Accounting,” to these Unaudited Condensed Consolidated Financial Statements.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market risk represents the potential loss arising from adverse changes in market rates and prices. Long-term debt is subject to potential losses based on changes in interest rates. The Company’s long-term debt consists of first mortgage bonds, fixed-rate senior notes and convertible debentures. All of the Company’s long-term debt is fixed-rate debt and was not entered into for trading purposes. The carrying value of long-term debt, including current maturities, was $69.8 million at September 30, 2008, as compared to a fair value of $69.7 million, based mainly on current market prices or discounted cash flows, using current rates for similar issues with similar terms and remaining maturities. The Company evaluates whether to refinance existing debt or permanently refinance existing short-term borrowing, based in part on the fluctuation in interest rates.

The Company’s propane distribution business is exposed to market risk in connection with propane storage activities and fixed-price contracts for supply. The Company can store (in leased storage and/or in rail cars) up to approximately four million gallons of propane during the winter season to meet its customers’ peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause the value of stored propane to decline. To mitigate the impact of price fluctuations, the Company has adopted a Risk Management Policy that allows the propane distribution operation to enter into fair value hedges of its inventory. On July 21, 2008, the propane distribution operation had entered into a price swap agreement to protect the Company from the impact of price increases on the price-cap plan that we offer to customers. At September 30, 2008, the market price of propane dropped below the unit price in the swap agreement. As a result of the price drop, the Company marked the agreement to market and recorded an unrealized loss of $475,000.

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The Company’s propane wholesale marketing operation is a party to natural gas liquids (“NGLs”) forward contracts, primarily propane contracts, with various third parties. These contracts require that the propane wholesale marketing operation purchase or sell NGLs at a fixed price at fixed future dates. At expiration, the contracts are settled by the delivery of NGLs to the Company or the counter-party or by booking out the transaction. Booking out is a procedure for financially settling a contract in lieu of physical delivery. The propane wholesale marketing operation also enters into futures contracts that are traded on the New York Mercantile Exchange. In certain cases, the futures contracts are settled by the payment or receipt of a net amount equal to the difference between the current market price of the futures contract and the original contract price; however, they may also be settled for physical receipt or delivery of propane.

The forward and futures contracts are entered into for trading and wholesale marketing purposes. The propane wholesale marketing business is subject to commodity price risk on its open positions to the extent that market prices for NGLs deviate from fixed contract settlement prices. Market risk associated with the trading of futures and forward contracts is monitored daily for compliance with the Company’s Risk Management Policy, which includes volumetric limits for open positions. To manage exposure to changing market prices, open positions are marked up or down to market prices and reviewed by the Company’s oversight officials daily. In addition, the Risk Management Committee reviews periodic reports on markets and the credit risk of counter-parties, approves any exceptions to the Risk Management Policy (within limits established by the Board of Directors) and authorizes the use of any new types of contracts. Quantitative information on forward and futures contracts at September 30, 2008 is presented in the following table.

At September 30, 2008	Quantity in gallons	Estimated Market Prices		Weighted Average Contract Prices
Forward Contracts
Sale	37,977,720	$1.3650 — $2.0050		$1.7549
Purchase	36,872,994	$1.3550 — $1.9450	$1.7396

Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expire in 2008 or in the first quarter of 2009.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Chief Executive Officer and Chief Financial Officer of the Company, with the participation of other Company officials, have evaluated the Company’s “disclosure controls and procedures” (as such term is defined under Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended) as of September 30, 2008. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2008.

Changes in Internal Control Over Financial Reporting

During the quarter ended September 30, 2008, there was no change in the Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings

As disclosed in Note 4, “Commitments and Contingencies,” of these unaudited Condensed Consolidated Financial Statements, the Company is involved in certain legal actions and claims arising in the normal course of business. The Company is also involved in certain legal and administrative proceedings before various government agencies concerning rates. In the opinion of management, the ultimate disposition of these proceedings and claims will not have a material effect on the consolidated financial position, results of operations or cash flows of the Company.

Item 1A. Risk Factors

Certain risks described below update the risk factors in Part 1, Item 1A. “Risk Factors” in the Company’s Form 10-K for the year ended December 31, 2007. Because of the following factors, as well as other factors affecting the Company’s financial condition and operating results, past financial performance should not be considered to be a reliable indicator of future performance, and investors should not use historical trends to anticipate results or trends in future periods.

Instability and volatility in the financial markets could have a negative impact on our growth strategy.

Our business strategy has included, and will continue to include, growth both organically and through acquisitions. To the extent we do not generate sufficient cash from operations, we may need to incur additional indebtedness to finance our plans for growth. Recent turmoil in the credit markets and the potential impact on the liquidity of major financial institutions may have an adverse effect on our customer's and our ability to fund our business strategy through borrowings, under either existing or newly created instruments in the public or private markets on terms we believe to be reasonable.

Risks Relating to the Financial Services Industry and Financial Markets

Recent government actions to stabilize credit markets and financial institutions may not be effective and could adversely affect our competitive position.

The U.S. Government recently enacted legislation and created several programs to help stabilize credit markets and financial institutions and restore liquidity, including the Emergency Economic Stabilization Act of 2008, the Federal Reserve’s Commercial Paper Funding Facility (CPFF) and Money Market Investor Funding Facility and the Federal Deposit Insurance Corporation’s (FDIC) Temporary Liquidity Guarantee Program. There is no assurance that these programs individually or collectively will have beneficial effects in the credit markets, will address credit or liquidity issues of companies that participate in the programs or will reduce volatility or uncertainty in the financial markets. The failure of these programs to have their intended effects could have a material adverse effect on the financial markets, which in turn could materially and adversely affect our business, financial condition and results of operations.

Current levels of market volatility are unprecedented.

The capital and credit markets have been experiencing extreme volatility and disruption for more than 12 months. In recent weeks, the volatility and disruption have reached unprecedented levels. In some cases, the markets have exerted downward pressure on stock prices and credit capacity for certain issuers. If current levels of market disruption and volatility continue or worsen, we would seek to meet our liquidity needs by drawing upon contractually committed lending agreements primarily provided by banks and/or by seeking other funding sources. However, under such extreme market conditions, there can be no assurance such agreements and other funding sources would be available or sufficient.

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Difficult conditions in the financial services markets have materially and adversely affected the business and results of operations of many financial institutions and we do not know when and if these conditions may improve in the near future.

Dramatic declines in the housing market during the prior year, with falling home prices and increasing foreclosures and unemployment, have resulted in significant write-downs of asset values by financial institutions, including government-sponsored entities and major commercial and investment banks. These write-downs, initially of mortgage-backed securities but spreading to credit default swaps and other derivative securities, have caused many financial institutions to seek additional capital, to merge with larger and stronger institutions and, in some cases, to fail. Many lenders and institutional investors have reduced, and in some cases, ceased to provide funding to borrowers, including other financial institutions. This market turmoil and tightening of credit have led to an increased level of commercial and consumer delinquencies, lack of consumer confidence, increased market volatility and widespread reduction of business activity generally.

The soundness of financial institutions could adversely affect the Company.

The Company has exposure to different industries and counterparties, and may periodically execute transactions with counterparties in the financial services industry, including brokers and dealers, commercial banks, investment banks and other institutional clients. These transactions may expose the Company to credit risk in the event of default of a counterparty or client. There can be no assurance that any such losses or impairments would not materially and adversely affect the Company’s business and results of operations.

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

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)		Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs (2)
July 1, 2008 through July 31, 2008 (1)		728	$	25.56		0		0
August 1, 2008 through August 31, 2008		0	$	0.00		0		0
September 1, 2008 through September 30, 2008		0	$	0.00		0		0

Total		728	$	25.56		0		0

(1) Chesapeake purchased shares of stock on the open market for the purpose of reinvesting the dividend on deferred stock units held in the Rabbi Trust accounts for certain Senior Executives and Directors under the Deferred Compensation Plan. The Deferred Compensation Plan is discussed in detail in Note K to the Consolidated Financial Statements of the Company's Form 10-K for the year ended December 31, 2007 filed with the Securities Exchange Commission on March 10, 2008. During the quarter, 728 shares were purchased through the reinvestment of dividends on deferred stock units.
(2) Except for the purposes described in Footnote (1), Chesapeake has no publicly announced plans or programs to repurchase its shares.

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Item 3. Defaults upon Senior Securities

None

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

None.

Item 5. Other Information

None

Item 6. Exhibits

Exhibit	Description
4.1	Rights agreement dated August 20, 1999, by and between Chesapeake Utilities Corporation and BankBoston, N.A., rights agent, is incorporated herein by reference to Exhibit 4.1 of the Company's Current Report on Form 8-K, filed August 24, 1999, File No. 001-11590.

4.2	First Amendment to Rights Agreement dated September 12, 2008, by and between Chesapeake Utilities Corporation and Computershare Trust Company, N.A., as successor rights agent to BankBoston, N.A., is incorporated herein by references to Exhibit 4.1 of the Company's Current Report on Form 8-K, filed September 12, 2008, File No. 001-11590.

31.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, dated November 7, 2008.

31.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, dated November 7, 2008.

32.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated November 7, 2008.

32.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated November 7, 2008.

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SIGNATURES

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

Chesapeake Utilities Corporation

/s/ Beth W. Cooper

Beth W. Cooper

Senior Vice President and Chief Financial Officer

Date: November 7, 2008

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