Chesapeake Utilities - 10-Q quarterly report FY

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: June 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 UtilitiesCorporation

(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 — 6,815,763 shares outstanding as of July 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	15
	Item 3. Quantitative and Qualitative Disclosures about Market Risk	29
	Item 4. Controls and Procedures	29
PART II — OTHER INFORMATION		30
	Item 1. Legal Proceedings	30
	Item 1A. Risk Factors	30
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	30
	Item 3. Defaults upon Senior Securities	30
	Item 4. Submission of Mattters to a Vote of Security Holders	30
	Item 5. Other Information	30
	Item 6. Exhibits	31
SIGNATURES		32

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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 June 30,	2008		2007
Operating Revenues	$	69,056,959	$	52,501,920
Operating Expenses
Cost of sales, excluding costs below		48,539,716		34,228,323
Operations		10,742,546		10,310,904
Terminated acquisition costs		1,239,628		-
Maintenance		503,223		564,856
Depreciation and amortization		2,225,344		2,367,523
Other taxes		1,477,063		1,332,249
Total operating expenses		64,727,520		48,803,855
Operating Income		4,329,439		3,698,065
Other income, net of other expenses		63,507		234,194
Interest charges		1,388,735		1,594,701
Income Before Income Taxes		3,004,211		2,337,558
Income taxes		1,185,287		849,877
Income from Continuing Operations		1,818,924		1,487,681
Loss from discontinued operations,
net of tax benefit of $0 and $4,115		-		(5,891	)
Net Income	$	1,818,924	$	1,481,790

Weighted Average Shares Outstanding:
Basic		6,812,474		6,737,384
Diluted		6,920,042		6,849,890
Earnings Per Share of Common Stock:
Basic:
From continuing operations	$	0.27	$	0.22
From discontinued operations		-		-
Net Income	$	0.27	$	0.22
Diluted:
From continuing operations	$	0.27	$	0.22
From discontinued operations		-		-
Net Income	$	0.27	$	0.22

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

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

Page 1

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Income (Unaudited)


For the Six Months Ended June 30,		2008		2007
Operating Revenues	$		169,330,460	$	146,028,811
Operating Expenses
Cost of sales, excluding costs below			119,519,896		98,164,191
Operations			21,512,217		20,840,649
Terminated acquisition costs			1,239,628		-
Maintenance			988,549		1,145,019
Depreciation and amortization			4,428,008		4,683,319
Other taxes			3,272,008		2,883,996
Total operating expenses			150,960,306		127,717,174
Operating Income			18,370,154		18,311,637
Other income, net of other expenses			81,097		290,675
Interest charges			2,982,106		3,193,951
Income Before Income Taxes			15,469,145		15,408,361
Income taxes			6,075,879		5,909,199
Income from Continuing Operations			9,393,266		9,499,162
Loss from discontinued operations, net of
tax benefit of $0 and $17,073			-		(26,284	)
Net Income	$		9,393,266	$	9,472,878

Weighted Average Common Shares Outstanding:
Basic			6,803,892		6,721,694
Diluted			6,917,308		6,835,257
Earnings Per Share of Common Stock:
Basic
From continuing operations	$		1.38	$	1.41
From discontinued operations			-		-
Net Income	$		1.38	$	1.41
Diluted
From continuing operations	$		1.36	$	1.39
From discontinued operations			-		-
Net Income	$		1.36	$	1.39

Cash Dividends Declared Per Share of Common Stock:	$		0.600	$	0.585

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

Page 2

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

For the Six Months Ended June 30,			2008	2007

Operating Activities
	Net Income		$9,393,266	$9,472,879
		Depreciation and amortization	4,428,008	4,683,318
		Depreciation and accretion included in other costs	901,099	1,682,980
		Deferred income taxes, net	2,162,750	1,590,955
		Gain on sale of assets	-	(204,882)
		Unrealized gain on commodity contracts	(358,045)	(296,892)
		Unrealized loss (gain) on investments	86,263	(188,203)
		Employee benefits and compensation	558,159	920,994
		Other, net	3,461	(1,839)
	Changes in assets and liabilities:		558,159
		Sale (purchase) of investments	(88,092)	71,432
		Accounts receivable and accrued revenue	(11,632,776)	6,961,621
		Propane inventory, storage gas and other inventory	(229,499)	2,781,638
		Regulatory assets	281,841	597,354
		Prepaid expenses and other current assets	1,578,990	(686,387)
		Other deferred charges	(531,731)	(1,405,003)
		Long-term receivables	122,746	51,557
		Accounts payable and other accrued liabilities	3,453.229	(7,026,332)
		Income taxes receivable (payable)	1,136,846	(139,486)
		Accrued interest	716,183	(20,910)
		Customer deposits and refunds	(1,003,221)	361,078
		Accrued compensation	(1,042,081)	(401,493)
		Regulatory liabilities	(384,659)	1,798,097
		Other liabilities	89,916	15,582
Net cash provided by operating activities			9,642,653	20,618,058

Investing Activities
	Property, plant and equipment expenditures		(15,440,474)	(15,969,557)
	Proceeds from sale of assets		-	204,882
	Environmental expenditures		(198,754)	(135,953)
Net cash used by investing activities			(15,639,228)	(15,900,628)

Financing Activities
	Common stock dividends		(3,799,030)	(3,465,986)
	Issuance of stock for Dividend Reinvestment Plan		15,338	174,314
	Change in cash overdrafts due to outstanding checks		(128,683)	843,845
	Net borrowing (repayment) under line of credit agreements		11,519,892	(4,829,053)
	Repayment of long-term debt		(1,020,072)	(1,020,132)
Net cash provided (used) by financing activities			6,587,445	(8,297,012)

Net Increase (decrease) in Cash and Cash Equivalents			590,870	(3,579,582)
Cash and Cash Equivalents — Beginning of Period			2,592,801	4,488,366
Cash and Cash Equivalents — End of Period			$3,183,671	$908,784

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

Page 3

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Stockholders' Equity (Unaudited)

			For the Six Months Ended June 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	1,573	3,945
		Stock-based Compensation	11,965	7,945
	Balance — end of period		$3,316,625	$3,298,473

Additional Paid-in Capital
	Balance — beginning of period		$65,591,552	$61,960,220
		Dividend Reinvestment Plan	219,034	1,121,190
		Retirement Savings Plan	66,704	934,295
		Conversion of debentures	53,355	133,839
		Stock-based compensation	179,624	1,442,008
		Tax benefit of warrants	50,244	-
	Balance — end of period		$66,160,513	$65,591,552

Retained Earnings
	Balance — beginning of period		$51,538,194	$46,270,884
		Net income	9,393,266	13,197,710
		Cash dividends declared	(4,086,399)	(7,930,400)
	Balance — end of period		$56,845,061	$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	107,228	285,413
	Balance — end of period		$1,511,150	$1,403,922

Treasury Stock
	Balance — beginning of period		($1,403,922)	($1,118,509)
		New deferrals related to compensation obligation	(107,228)	(285,413)
		Purchase of treasury stock (1)	(34,328)	(29,771)
		Sale and distribution of treasury stock (2)	34,328	29,771
	Balance — end of period		($1,511,150)	($1,403,922)


Total Stockholders’ Equity			$125,470,525	$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.

Page 4

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

Assets	June 30, 2008			December 31, 2007

Property, Plant and Equipment
Natural gas	$	296,681,205		$	289,706,066
Propane		49,647,049			48,506,231
Advanced information services		1,234,107			1,157,808
Other plant		10,486,075			8,567,833
Total property, plant and equipment		358,048,436			347,937,938
Less: Accumulated depreciation and amortization		(96,835,370	)		(92,414,289	)
Plus: Construction work in progress		9,749,213			4,899,608
Net property, plant and equipment		270,962,279			260,423,257

Investments		1,911,100			1,909,271

Current Assets
Cash and cash equivalents		3,183,671			2,592,801
Accounts receivable (less allowance for uncollectible
accounts of $944,898 and $952,075, respectively)		86,639,996			72,218,191
Accrued revenue		2,476,445			5,265,474
Propane inventory, at average cost		8,143,492			7,629,295
Other inventory, at average cost		1,131,474			1,280,506
Regulatory assets		1,018,750			1,575,072
Storage gas prepayments		5,906,504			6,042,169
Income taxes receivable		150,836			1,237,438
Deferred income taxes		1,920,098			2,155,393
Prepaid expenses		1,917,178			3,496,517
Mark-to-market energy assets		7,014,698			7,812,456
Other current assets		146,603			146,253
Total current assets		119,649,745			111,451,565

Deferred Charges and Other Assets
Goodwill		674,451			674,451
Other intangible assets, net		171,171			178,073
Long-term receivables		617,934			740,680
Regulatory assets		2,778,159			2,539,235
Other deferred charges		4,146,654			3,640,480
Total deferred charges and other assets		8,388,369			7,772,919







Total Assets	$	400,911,493		$	381,557,012

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

Page 5

Capitalization and Liabilities	June 30, 2008			December 31, 2007

Capitalization
Stockholders' equity
Common Stock, par value $0.4867 per share
(authorized 12,000,000 shares)	$	3,316,625		$	3,298,473
Additional paid-in capital		66,160,513			65,591,552
Retained earnings		56,845,061			51,538,194
Accumulated other comprehensive loss		(851,674	)		(851,674	)
Deferred compensation obligation		1,511,150			1,403,922
Treasury stock		(1,511,150	)		(1,403,922	)
Total stockholders' equity		125,470,525			119,576,545

Long-term debt, net of current maturities		63,180,636			63,255,636
Total capitalization		188,651,161			182,832,181

Current Liabilities
Current portion of long-term debt		6,656,364			7,656,364
Short-term borrowing		57,055,153			45,663,944
Accounts payable		58,826,720			54,893,071
Customer deposits and refunds		9,033,699			10,036,920
Accrued interest		1,581,687			865,504
Dividends payable		2,078,518			1,999,343
Accrued compensation		2,358,031			3,400,112
Regulatory liabilities		5,929,229			6,300,766
Mark-to-market energy liabilities		6,477,672			7,739,261
Other accrued liabilities		2,706,335			2,500,542
Total current liabilities		152,703,408			141,055,827

Deferred Credits and Other Liabilities
Deferred income taxes		30,723,340			28,795,885
Deferred investment tax credits		256,560			277,698
Regulatory liabilities		973,185			1,136,071
Environmental liabilities		750,596			835,143
Other pension and benefit costs		2,535,976			2,513,030
Accrued asset removal cost		20,366,122			20,249,948
Other liabilities		3,951,145			3,861,229
Total deferred credits and other liabilities		59,556,924			57,669,004

Other Commitments and Contingencies (Note 4)


Total Capitalization and Liabilities	$	400,911,493		$	381,557,012

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

Page 6

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 six 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 June 30, 2008 and December 31, 2007.

3.	Calculation of Earnings Per Share

	Three Months Ednded		Six Months Ednded
For the Periods Ended June 30,	2008	2007	2008	2007

Calculation of Basic Earnings Per Share:
Net Income	$1,818,924	$1,481,790	$9,393,266	$9,472,878
Weighted average shares outstanding	6,812,474	6,737,384	6,803,892	6,721,694
Basic Earnings Per Share	$0.27	$0.22	$1.38	$1.41

Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$1,818,924	$1,481,790	$9,393,266	$9,472,878
Effect of 8.25% Convertible debentures (1)	22,306	24,015	45,114	48,214
Adjusted numerator — Diluted	$1,841,230	$1,505,805	$9,438,380	$9,521,092

Reconciliation of Denominator:
Weighted shares outstanding — Basic	6,812,474	6,737,384	6,803,892	6,721,694
Effect of dilutive securities (1):
Restricted Stock	2,780	-	7,449	-
8.25% Convertible debentures	104,788	112,506	105,967	113,563
Adjusted denominator — Diluted	6,920,042	6,849,890	6,917,308	6,835,257

Diluted Earnings Per Share	$0.27	$0.22	$1.36	$1.39

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

4.	Commitments and Contingencies

Rates and Regulatory Matters

The Company’s natural gas distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective state Public Service Commissions (“PSC’s”). Eastern Shore Natural Gas Company (“Eastern Shore”), the Company’s natural gas transmission operation, is subject to regulation 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 proposed settlement agreement that would effectively resolve all issues in this docket. The major components of the proposed 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 results in a reduction in depreciation expense of approximately $897,000; (iv) the Delaware division would be permitted to retain 100% of all interruptible margins, there would be a minimum usage threshold for interruptible service of 10,000 Mcf per year, and all interruptible customers would be required to transport; (v) the Delaware division would continue to share any margins received from its Asset Manager and any off-system sales on an 80%/20% basis, with 80% being returned to the firm customers through the GSR mechanism; (vi) the residential service rate schedule would be divided into two separate schedules based on annual volumetric levels; (vii) individual customers with multiple meters would be able to aggregate meters in order to qualify for transportation service; and (viii) the Delaware division would have the ability to aggregate main extension projects over 500 feet at the time of its next base rate proceeding to determine rate base treatment. The Delaware division anticipates a final decision by the Delaware PSC during the third quarter of 2008.

On September 10, 2007, the Company filed with the Delaware PSC its annual Gas Service Revenue (“GSR”) Application, seeking approval to change its GSR rates effective for service rendered on and after 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, on July 1, 2008, the Company filed with the Delaware PSC a supplemental GSR Application, seeking approval to change its GSR rates effective for service rendered on and after August 1, 2008. On July 8, 2008, the Delaware PSC authorized the Company to implement the revised GSR charges on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. The Delaware division anticipates a final decision by the Delaware PSC on both filings during the fourth quarter of 2008.

On November 1, 2007, the Delaware division filed with the Delaware PSC its annual Environmental Rider (“ER”) rate application to become effective for service rendered on and after 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, which are subject to recovery pursuant to the ER recovery mechanism, will have been collected by the end of the determination period, no further ER rate applications will be filed by the Delaware division, and ER charges will cease to appear on the Delaware division’s customers’ bills as of November 30, 2008.

Page 7

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 Maryland division was required to file a depreciation study, which was filed on April 9, 2007. The Maryland division filed formal testimony on July 10, 2007, initiating a Phase II of this proceeding. In this filing, the Maryland 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 Maryland division has reduced its depreciation expense by approximately $119,000 and its cost of removal 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 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 Florida 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 Florida division’s utility plant remaining lives, net salvage values, depreciation reserves, and depreciation rates, effective January 1, 2008. These changes were not material to the financial results of the Florida division. The Florida PSC issued an order on June 27, 2008, which closes this docket.

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 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 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.

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 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 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 Precedent 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 June 30, 2008, the Company had incurred $3.18 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.

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. Eastern Shore reported in this filing that its interruptible revenue was in excess of its annual threshold amount and refunded a total of $63,675 in the second quarter of 2008 to its eligible firm customers.

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.

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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.

In 2004, Chesapeake received a Certificate of Completion for the remedial work performed at a former manufactured gas plant site located in Dover, Delaware. Chesapeake is also currently participating in the investigation, assessment or remediation of two additional former manufactured gas plant sites located in Maryland and Florida. The Company has accrued liabilities for the three sites, referred to, respectively, as the Dover Gas Light, Salisbury Town Gas Light and the Winter Haven Coal Gas sites. The Company has 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 at the site, or information previously unknown to the EPA is received that indicates 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.

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 June 30, 2008, the Company has incurred approximately $9.67 million in costs related to environmental testing and remedial action studies at the site. Approximately $9.73 million has been recovered through June 2008 from other parties or through rates. As of June 30, 2008, a regulatory liability of approximately $68,000, 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 and began Air Sparging and Soil-Vapor Extraction (“AS/SVE”) remediation procedures. Chesapeake has been reporting 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 that is being maintained for continued product monitoring and recovery. Chesapeake has requested a No Further Action determination and is awaiting such a determination from the MDE.

Through June 30, 2008, the Company has incurred 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, $1.02 million of incurred environmental remediation costs. As of June 30, 2008, a regulatory asset of approximately $956,000 has been recorded to represent the remaining under-recovery portion of the clean-up costs.

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 June 30, 2008, the Company has incurred approximately $1.8 million of environmental costs associated with this site. At June 30, 2008, the Company had accrued a liability of $751,000 related to this site, offsetting: (a) $64,000 collected through rates in excess of costs incurred and (b) a regulatory asset of approximately $815,000, representing the uncollected portion of the estimated clean-up costs. The Company expects to recover the remaining clean-up costs through rates.

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 plans 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.

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.

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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 new contract expires on March 31, 2009.

Corporate Guarantees

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 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 June 30, 2008 was $24.2 million, with the guarantees expiring on various dates in 2008 and the first six 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 June 30, 2008.

Internal Revenue Service Audit

The Internal Revenue Service (“IRS”) is in the process of auditing our consolidated federal tax return for the year ended December 31, 2005. On July 5, 2008, the Company received a notice of proposed adjustments from the IRS related to the 2005 tax year as a result of this audit. The Company increased its tax accrual by $50,000 in the second quarter of 2008 for uncertain tax positions as defined by FASB Interpretation No. 48, “Uncertainty in Income Taxes (“FIN 48”),” related to this notice. The Company is continuing its discussions with the IRS concerning the proposed adjustments and believes that the final resolution of these adjustments will not have a material adverse effect on the financial condition or results of operations of the Company.

Application of SFAS No. 71

Certain assets and liabilities of the Company are accounted for in accordance with SFAS No. 71 ¾“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 regulator 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 June 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 would result in a charge to earnings, net of applicable income taxes, which could be material.

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 Statement of Financial Accounting Standards No. 141 (revised 2007) “Business Combinations” (“SFAS 141(R)”). SFAS 141(R) retains the fundamental requirements of the original pronouncement requiring that the purchase method be used for all business combinations. SFAS 141(R) defines the acquirer as the entity that obtains control of one or more businesses in the business combination, establishes the acquisition date as the date that the acquirer achieves control and requires the acquirer to recognize the assets acquired, liabilities assumed and any non-controlling interest 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 FASB Statement No. 160, “Noncontrolling Interests in Consolidated Financial Statements,” an amendment of ARB No. 51 (“SFAS 160”). 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” (“SFAS 161”). 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 the adoption of SFAS 161 may have on its financial statements.

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 that 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 currently evaluating the potential impact the new pronouncement will have on its consolidated financial statements.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” 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 generally accepted accounting principles 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.

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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 the adoption of FSP APB 14-1 may have on its financial statements.

In June 2008, the FASB issued FASB Staff Position (FSP) 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 currently evaluating the potential impact the new pronouncement will 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 currently evaluating the potential impact the new pronouncement will 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 currently evaluating the potential impact the new pronouncement will have on its consolidated financial statements.

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

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, the adoption of this FSP did not have a material effect on 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 FASB Staff Position 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 nonfinancial items include assets and liabilities such as reporting units measured at fair value in a goodwill impairment test and nonfinancial 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. The adoption of SFAS No. 157 did not have any 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.

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 was 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.

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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 12 “Discontinued Operations” of the unaudited Condensed Consolidated Financial Statements.


	Three Months Ended						Six Months Ended
For the Periods Ended June 30,	2008			2007			2008		2007
Operating Revenues, Unaffiliated Customers
Natural gas	$	53,773,960		$	39,287,667		$	122,596,489	$	104,719,271
Propane		11,488,807			9,494,170			39,296,608		34,416,570
Advanced information services		3,794,192			3,720,083			7,437,362		6,892,971
Other		-			-			-		-
Total operating revenues, unaffiliated customers	$	69,056,959		$	52,501,920		$	169,330,459	$	146,028,812
Intersegment Revenues (1)
Natural gas	$	104,519		$	78,087		$	210,372	$	156,150
Propane		-			-			1,349		406
Advanced information services		28,083			95,991			36,051		228,226
Other		163,073			154,623			326,148		309,246
Total intersegment revenues	$	295,675		$	328,701		$	573,920	$	694,028
Operating Income (Loss)
Natural gas	$	4,736,363		$	3,992,282		$	15,205,387	$	13,608,264
Propane		(624,699	)		(545,898	)		2,819,436		4,327,658
Advanced information services		137,077			178,708			174,941		227,528
Other and eliminations		80,698			72,973			170,390		148,188
Total operating income	$	4,329,439		$	3,698,065		$	18,370,154	$	18,311,638

Other Income		63,507			234,194			81,097		290,675
Interest Charges		1,388,735			1,594,701			2,982,106		3,193,951
Income Taxes		1,185,287			849,877			6,075,879		5,909,199
Net income from continuing operations	$	1,818,924		$	1,487,681		$	9,393,266	$	9,499,163

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


	June 30,			December 31,
	2008			2007
Identifiable Assets
Natural gas	$	276,404,244		$	273,500,890
Propane		108,722,729			94,966,212
Advanced information services		2,820,065			2,507,910
Other		12,915,716			10,533,511
Total identifiable assets	$	400,862,754		$	381,508,523

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.

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7.	Employee Benefit Plans

Net periodic benefit costs for the defined benefit pension plan, the executive excess benefit 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 June 30,	2008			2007			2008		2007		2008		2007
Service Cost	$	-		$	-		$	-	$	-	$	896	$	2,529
Interest Cost		148,431			155,514			31,382		30,841		27,565		23,233
Expected return on plan assets		(156,475	)		(174,100	)		-		-		-		-
Amortization of prior service cost		(1,175	)		(1,175	)		-		-		-		-
Amortization of net loss		-			-			11,611		12,933		46,215		41,640
Net periodic (benefit) cost	$	(9,219	)	$	(19,761	)	$	42,993	$	43,774	$	74,676	$	67,402



	Defined Benefit						Executive Excess Defined				Other Post-Retirement
	Pension Plan						Benefit Pension Plan				Benefits
For the Six Months Ended June 30,	2008			2007			2008		2007		2008		2007
Service Cost	$	-		$	-		$	-	$	-	$	1,792	$	5,057
Interest Cost		296,862			311,029			62,763		61,681		55,129		46,467
Expected return on plan assets		(312,950	)		(348,199	)		-		-		-		-
Amortization of prior service cost		(2,350	)		(2,350	)		-		-		-		-
Amortization of net loss		-			-			23,222		25,867		92,430		83,280
Net periodic (benefit) cost	$	(18,438	)	$	(39,520	)	$	85,985	$	87,548	$	149,351	$	134,804

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 retirement benefit plan and the other post-retirement benefit plans are unfunded and are expected to be paid out of the general funds of the Company. Cash benefits paid under the executive excess retirement benefit plan for the three months and six months ended June 30, 2008 were $22,300 and $44,600, respectively; for the year 2008, such benefits paid are expected to be $89,200. The Company incurred a credit of $8,500 for post-retirement benefits for medical claims for the three months ended June 30, 2008 compared to cash benefits paid of $17,000 for the first six months of 2008; for the year 2008, the Company has estimated that such benefits to be paid are $196,000. The credit incurred in the second quarter of 2008 is the result of being reimbursed for claims that were previously paid in 2007.

8.	Investments

The investment balance at June 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. The Company also has an associated liability that is recorded and adjusted each month for the gains and losses incurred by the Trust. At June 30, 2008, total investments had a fair value of $1.9 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.

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 six months ended June 30, 2008 and 2007.


	Three Months Ended				Six Months Ended
For the periods ended June 30,	2008		2007		2008		2007
Directors Stock Compensation Plan	$	45,893	$	45,230	$	91,786	$	89,134
Performance Incentive Plan		198,984		214,373		384,342		416,308
Total compensation expense		244,877		259,603		476,128		505,442
Less: tax benefit		97,507		101,245		189,588		197,122
SFAS 123R amounts included in net income	$	147,370	$	158,358	$	286,540	$	308,320

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10.	Stockholders’ Equity

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


	For the Six Months Ended June 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		3,231			8,106
Employee award plan		250			350
Stock-based Compensation (3)		24,333			15,974
Shares issued — end of period balance (4)		6,814,705			6,777,410

Treasury shares — beginning of period balance		-			-
Purchases		(1,103	)		-
Deferred Compensation Plan		1,103			-
Other issuances		-			-
Treasury Shares — end of period balance		-			-

Total Shares Outstanding		6,814,705			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 Director's compensation and Performance Incentive Plan.
(4)Includes 60,870 and 57,309 shares at June 30, 2008 and December 31, 2007, respectively, held
in a Rabbi Trust established by the Company relating to the Deferred Compensation Plan.

11.	Fair Value of Financial Instruments

The Company adopted SFAS No. 157 effective January 1, 2008 for financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and financial liabilities that are being 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 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 as follows:

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 June 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		$1,911		$1,911		$-		$-
Mark-to-market energy assets		7,015		-		7,015		-

Liabilities:
Mark-to-market energy liabilities		6,478		-		6,478		-

The following valuation techniques were used to measure fair value assets in the table above on a recurring basis as of June 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.

The Company’s adoption of SFAS No. 157 applies only to its financial instruments. The adoption did 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.

Page 14

12.	Discontinued Operations

During the quarter ended September 30, 2007, the Company decided to close its distributed energy services subsidiary, OnSight Energy, LLC (“OnSight”), as it 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 did not have any impact on the Company’s condensed consolidated financial statements during the three and six months ended June 30, 2008 compared to net losses of $6,000 and $26,000 for the three and six months ended June 30, 2007.

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.

Safe Harbor for Forward-Looking Statements

Chesapeake Utilities Corporation has made 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 on the Company’s distribution, wholesale marketing and energy trading businesses;

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

·	the access to interstate pipelines’ transportation and storage capacity 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 a degree that may impair future growth; and

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

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 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 customer 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 June 30, 2008

The following discussions on operating income and segment results for the three months ended June 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 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.

Page 15

Consolidated Overview

The Company’s net income for the quarter ended June 30, 2008 increased $337,000, or 23 percent, compared to the same period in 2007. The Company earned a net income of approximately $1.8 million, or $0.27 per share (diluted) during the quarter compared to a net income of approximately $1.5 million, or $0.22 per share (diluted) during the same quarter in 2007.


For the Three Months Ended June 30,	2008		2007			Change
Net Income (Loss)
Continuing operations	$	1,818,924	$	1,487,681		$	331,243
Discontinued operations		-		(5,891	)		5,891
Total Net Income	$	1,818,924	$	1,481,790		$	337,134

Diluted Earnings Per Share
Continuing operations	$	0.27	$	0.22		$	0.05
Discontinued operations		-		-			-
Total Diluted Earnings Per Share	$	0.27	$	0.22		$	0.05

When compared to the second quarter of 2007, the Company was able to increase net income for the second quarter of 2008 by $337,000, despite taking a charge of $1.2 million to other operating expense in 2008 for costs relating to an unconsummated acquisition. The Company initiated discussions in the third quarter of 2007 with a potential acquisition target. These discussions continued through the first part of the second quarter of 2008, at which time, we determined that we would not be able to complete the acquisition. In the course of these negotiations, the Company incurred certain accounting, legal and other professional fees and expenses, which were expensed in the second quarter of 2008 in accordance with SFAS 141 “Business Combinations.” Absent the charge for the unconsummated acquisition, the Company estimates that net income would have increased by $1.1 million in the second quarter to $2.6 million, or $0.37 per share (diluted), compared to the same period in 2007.

The period-over-period increase in net income reflects higher operating income from the Company’s natural gas segment and lower interest expense, partially offset by a decrease in other income.


For the Three Months Ended June 30,	2008			2007			Change
Operating Income
Natural Gas	$	4,736,363		$	3,992,282		$	744,081
Propane		(624,699	)		(545,898	)		(78,801	)
Advanced Information Services		137,077			178,708			(41,631	)
Other & Eliminations		80,698			72,973			7,725
Operating Income		4,329,439			3,698,065			631,374

Other Income		63,507			234,194			(170,687	)
Interest Charges		1,388,735			1,594,701			(205,966	)
Income Taxes		1,185,287			849,877			335,410
Net Income from Continuing Operations	$	1,818,924		$	1,487,681		$	331,243

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 96 percent in gross margin for the Company’s natural gas marketing operation.

Rate increases, lower depreciation allowances and lower asset removal cost allowances, approved in rate proceedings for the Company’s Delmarva natural gas distribution and natural gas transmission operations, contributed $653,000 to operating income for the natural gas segment in the second quarter of 2008

·	The Company’s natural gas transmission and Delmarva natural gas distribution operations experienced a combined increase in interruptible service revenue of $392,000, net of required margin-sharing, in the second quarter of 2008 compared to the same period in 2007.

·	New transportation capacity contracts implemented for the natural gas transmission operation in November 2007 provided $299,000 of additional gross margin in the second quarter of 2008.

Despite a slowdown in the new housing market 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 second quarter of 2007. In addition, the Delmarva natural gas distribution operations have been able to offset partially this slowdown with growth in commercial customers. Overall, these growth factors contributed $290,000 to the increase in gross margins for the Delmarva natural gas distribution operations in the second quarter of 2008. .

The average gross margin per retail gallon sold to customers increased $0.10 in the second quarter of 2008 for the Delmarva propane distribution operations, which contributed $307,000 to gross margins. This increase was partially offset by a decrease to gross margin of $222,000 as the Delmarva propane distribution operations experienced lower volumes delivered to customers during the second quarter of 2008 compared to the same period in 2007.

·	Volatile wholesale propane prices in the second quarter of 2008 contributed to the gross margin increase of $207,000 for the Company’s propane wholesale and marketing operation.

Page 16

Natural Gas

The natural gas segment earned operating income of $4.7 million for the second quarter in 2008 compared to $4.0 million for the corresponding quarter in 2007, an increase of $744,000, or 19 percent.

For the Three Months Ended June 30,	2008		2007		Change
Revenue	$	53,878,479	$	39,365,754	$	14,512,725
Cost of sales		38,945,802		26,130,962		12,814,840
Gross margin		14,932,677		13,234,792		1,697,885

Operations & maintenance		6,524,529		6,440,171		84,358
Terminated acquisition costs		890,053		-		890,053
Depreciation & amortization		1,654,980		1,834,712		(179,732	)
Other taxes		1,126,752		967,627		159,125
Other operating expenses		10,196,314		9,242,510		953,804
Total Operating Income	$	4,736,363	$	3,992,282	$	744,081


Statistical Data — Delmarva Peninsula
Heating degree-days ("HDD"):
Actual		481		527		(46	)
10-year average (normal)		490		496		(6	)

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

Per residential customer added:
Estimated gross margin	$	372	$	372	$	0
Estimated other operating expenses	$	106	$	106	$	0

Residential Customer Information
Average number of customers:
Delmarva		45,540		43,331		2,209
Florida		13,463		13,361		102
Total		59,003		56,692		2,311

Gross margin for the Company’s natural gas segment increased by $1.7 million, or 13 percent, and other operating expenses increased by $954,000, or 10 percent, for the second quarter in 2008 compared to the same period in 2007. The gross margin increases of $683,000 for the natural gas transmission operation, $556,000 for the natural gas distribution operations and $459,000 for the natural gas marketing operation are further explained below.

Natural Gas Transmission

The natural gas transmission operation achieved gross margin growth of $683,000, or 13 percent, in the second 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 $299,000 to gross margin in the second quarter of 2008 and are expected to generate a total annual increase in gross margin of $1.2 million above 2007 gross margin.

Interruptible revenue, net of required margin-sharing, increased $324,000 in the second 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. For the remainder of 2008, however, the Company expects its natural gas transmission operation to report a decrease of $192,000 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. Currently effective settlements in rate proceedings require the Company, upon reaching the margin-sharing threshold, to share 90% of its interruptible natural gas transmission revenues with its customers.

The implementation of rate case settlement rates, effective September 1, 2007, contributed an additional $42,000 to gross margins in the second quarter of 2008 compared to the same period in 2007. The period-over-period increase in gross margin would have been larger, but for temporary implementation in May 2007 of rates, which were subject to refund, when the settled 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 $18,000 increase in gross margin in the second quarter of 2008 is attributable to other various minor factors.

An increase of $372,000 in other operating expenses partially offset the increased gross margin. The factors contributing to the increase in other operating expenses are as follow:

·	Corporate costs allocated to the natural gas transmission operation increased $411,000 as a result of: (1) $341,000 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 costs increased by $61,000 as a result of the improved operating results in 2008 compared to 2007.

·	Rent and utility expenses increased $44,000 and $18,000, respectively, as Eastern Shore began incurring additional rental expense in January 2008 for a new office building.

·	The increased level of capital investment caused increased property taxes of $75,000.

Partially offsetting the previously mentioned increases was a decrease of $118,000 in depreciation expense and a decrease of $61,000 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. Also, the Company incurred regulatory expenses in the second quarter of 2007 associated with the FERC rate proceeding.

·	Other operating expenses relating to various items decreased collectively by approximately $58,000.

Page 17

Natural Gas Distribution

Gross margin for the Company’s natural gas distribution operations increased by $556,000, or seven percent, for the second quarter in 2008 compared to the same period in 2007. The gross margin increases of $481,000 for the Delmarva natural gas distribution operations and $75,000 for the Florida natural gas distribution operations are further explained below.

The Delmarva distribution operations experienced an increase of $481,000, or 10 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 the new housing market as a result of the unfavorable market conditions in the housing market, the average number of residential customers on the Delmarva Peninsula increased by 2,209, or five percent, for the second quarter of 2008 compared to the same period in 2007, and the Company estimates that these additional residential customers contributed approximately $180,000 to gross margin during the second quarter of 2008. The Company further estimates that a two percent growth in the number of its commercial customers during the second quarter of 2008 compared to the same period in 2007 contributed approximately $93,000 to gross margin during the second quarter of 2008.

·	The Company’s estimate for unbilled revenue for the second quarter of 2008 contributed $263,000 more to gross margin than normal, partially due to the warmer weather experienced during the first quarter of 2008.

·	Interruptible sales revenue, net of required margin-sharing, increased $68,000 in the second 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.

Partially offsetting these increases to gross margin was the negative impact oflower consumption per customer that reflects customer conservation efforts in light of higher energy costs and more energy-efficient housing. The Company estimates that lower consumption reduced margins by $56,000 in the second quarter of 2008.

·	The remaining $61,000 net increase in gross margin can be attributed to various factors, including the implementation of temporary rates by the Delaware division and lower industrial volumes.

Gross margin for the Florida distribution operation increased by $75,000, or three percent, in the second quarter of 2008 compared to the same period in 2007. This increase in gross margin is primarily due to higher volumes sold to non-residential customers and higher revenues from third-party natural gas marketers.

Other operating expense for the natural gas distribution operations increased by $582,000 in the second 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 $678,000 primarily due to $533,000 for the allocation of a portion of the terminated acquisition costs previously discussed.

·	Incentive compensation increased $121,000 in the second quarter of 2008 as the Delmarva operations experienced improved earnings compared to the prior year.

·	Property taxes increased by $57,000 as a result of the Company’s continued capital investments.

·	The allowance for uncollectible accounts increased $86,000 in 2008 compared to 2007 as a result of the adjustments to the reserve balances for historical collection practices.

Depreciation expense and asset removal costs decreased $58,000 and $357,000, respectively, in the second quarter of 2008 compared to the same period in 2007, primarily as a result of the Delmarva operations’s rate proceedings. These rate proceedings provided for lower depreciation allowances and lower asset removal cost allowances, which resulted in reductions of $95,000 and $409,000 in depreciation expense and asset removal costs during the second quarter of 2008. A portion of this reduction, or $77,000, represents adjustments to the amount reserved for refund as of March 31, 2008 based on the depreciation and asset removal cost allowances contained in the negotiated settlement agreements. As part of the Delaware division’s rate case, the Delaware PSC granted the Company permission to lower the depreciation and asset removal costs for its assets.

·	In addition, other operating expenses relating to various minor items increased by approximately $55,000.

Natural Gas Marketing

Gross margin for the natural gas marketing operation increased by $459,000, or 96 percent, for the second quarter of 2008 compared to the same period in 2007. The increase in gross margin was primarily the result of growth in the number of customers to which it provides supply management services and improved gas supply management techniques. Other operating expenses decreased slightly by $2,000 for the marketing operation; this decrease is attributable to lower payroll-related costs and benefits, which was partially offset by higher incentive compensation and higher corporate costs as $16,000 was allocated to the operation for a portion the terminated acquisition costs.

Page 18

Propane

The propane segment experienced a decrease of $79,000, or 14 percent, in operating income for the second quarter of 2008 compared to the same period in 2007. Gross margin increased by $390,000, which was more than offset by an increase in other operating expenses of $469,000. Absent the terminated acquisition costs of $273,000 allocated to the propane segment, it would have reduced its operating loss by $194,000, or 35 percent, for the second quarter of 2008 compared to the same period in 2007.

For the Three Months Ended June 30,	2008			2007			Change
Revenue	$	11,488,807		$	9,494,170		$	1,994,637
Cost of sales		7,534,539			5,930,398			1,604,141
Gross margin		3,954,268			3,563,772			390,496

Operations & maintenance		3,624,049			3,463,047			161,002
Terminated acquisition costs		272,718			-			272,718
Depreciation & amortization		503,929			458,788			45,141
Other taxes		178,271			187,835			(9,564	)
Other operating expenses		4,578,967			4,109,670			469,297
Total Operating Loss	$	(624,699	)	$	(545,898	)	$	(78,801	)


Statistical Data — Delmarva Peninsula
Heating degree-days ("HDD"):
Actual		481			527			(46	)
10-year average (normal)		490			496			(6	)

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

The period-over-period decrease in operating income was due to higher other operating expenses, which resulted from the allocation of a portion of the terminated acquisition costs in the second quarter of 2008. Absent these costs, the propane segment would have earned a period-over-period increase in operating income of $194,000. The gross margin increases of $182,000 for the Delmarva propane distribution operations, $2,000 for the Florida propane distribution operations and $207,000 for the propane wholesale and marketing operation, are further explained below.

Delmarva Propane Distribution

The Delmarva propane distribution operation’s increase in gross margin of $182,000 resulted from the following:

Gross margin increased by $307,000 in the second quarter of 2008, compared to the same period in 2007, because of a $0.10 increase in the average gross margin per retail gallon. This increase occurs when market prices rise at a greater rate than the Company’s inventory price per gallon. This trend reverses, as it did in the first quarter of 2008, when market prices of propane decrease and move closer to the Company’s average inventory price per gallon.

Temperatures on the Delmarva Peninsula were nine percent warmer in the second quarter of 2008 compared to the same period in 2007, which contributed to a decrease of 156,000 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 $113,000 for the Delmarva propane distribution operation compared to the second quarter of 2007.

Non-weather-related volumes sold in the second quarter of 2008 decreased by 176,000 gallons, or five percent. This decrease in gallons sold reduced gross margin by approximately $109,000 for the Delmarva propane distribution operation compared to the second quarter of 2007. Contributing to this decrease in gallons sold was customer conservation, a reduced number of customers and the timing of propane deliveries.

·	The remaining $97,000 increase in gross margin can be attributed to various other factors, such as higher tank and meter rental fees.

Total other operating expenses increased by $358,000 for the Delmarva propane operations in the second quarter 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 $338,000 as a result of: (1) $227,000 for the allocation of a portion of the terminated acquisition costs previously discussed, and (2) the Company updating its annual corporate cost allocations.

·	Vehicle fuel increased $53,000 as a result of rising gasoline and diesel fuel costs.

·	The allowance for uncollectable accounts increased $31,000 due to increased revenues resulting from the higher cost of propane.

·	Customer charges increased by $26,000 in the second quarter 2008 compared to the same period 2007 as a result of added Community Gas Systems (“CGS”) customers. This expenditure will continue to increase as more CGS customers are added.

·	Depreciation and amortization expense increased by $19,000 as a result of the Company’s increase in capital investments over the prior year.

The operation experienced lower expenses of $121,000 in the second quarter 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 requires propane tanks or cylinders to be recertified twelve years from their date of manufacture and every five years after that.

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

Florida Propane Distribution

The Florida propane distribution operation experienced a slight increase in gross margin of $2,000, or one percent, in the second quarter of 2008 compared to the same period in 2007. The higher gross margin is attributable to an increase of $15,000 based upon a higher average gross margin per retail gallon, which was partially offset by a decrease of $13,000 in service sales. Other operating expenses in the second quarter of 2008, compared to the same period in 2007, increased by $65,000, primarily due to increases in depreciation expense, allowance for uncollectible accounts and increased corporate costs as $20,000 was allocated to the operations for a portion of the terminated acquisition costs.

Propane Wholesale and Marketing

Gross margin for the Company’s propane wholesale marketing operation increased by $207,000, or 35 percent, in the second quarter of 2008 compared to the same period in 2007. This increase reflects the larger number of market opportunities that arose in the second 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 $46,000, due primarily to higher payroll costs, including incentive compensation, and increased corporate costs as $26,000 was allocated to the operation for a portion of the terminated acquisition costs.

Page 19

Advanced Information Services

The advanced information services segment experienced gross margin growth of approximately $114,000, or seven percent, and contributed operating income of $137,000 for the second quarter of 2008, a decrease of $42,000 compared to the same period in 2007. Absent the terminated acquisition costs of $64,000 allocated to the advanced information segment, it would have increased its operating income by $22,000, or 13 percent, for the second quarter of 2008 compared to the same period in 2007.


For the Three Months Ended June 30,	2008		2007		Change
Revenue	$	3,822,274	$	3,816,074	$	6,200
Cost of sales		2,059,375		2,166,963		(107,588	)
Gross margin		1,762,899		1,649,111		113,788

Operations & maintenance		1,363,082		1,273,239		89,843
Terminated acquisition costs		64,461		-		64,461
Depreciation & amortization		38,583		35,248		3,335
Other taxes		159,696		161,916		(2,220	)
Other operating expenses		1,625,822		1,470,403		155,419
Total Operating Income	$	137,077	$	178,708	$	(41,631	)

The period-over-period increase in gross margin was attributable to lower cost of sales. Cost of sales decreased by $108,000 as the number of billable employees was reduced. Also, lower reimbursable expenses contributed to the reduction in cost of sales as employees performed less travel during the period.

Other operating expenses increased by $155,000 in the second quarter of 2008, compared to the same period in 2007. This increase in operating expenses is attributable to payroll costs, payroll taxes, and increased corporate costs as $64,000 was allocated to the segment for a portion of the terminated acquisition costs. Payroll costs increased as a result of the increase in non-billable staffing levels added to support future growth.

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 $81,000 for the second quarter of 2008 compared to an operating income of approximately $73,000 for the same period in 2007.


For the Three Months Ended June 30,	2008		2007		Change
Revenue	$	163,074	$	154,623	$	8,451
Cost of sales		-		-		-
Gross margin		163,074		154,623		8,451

Operations & maintenance		29,784		28,004		1,780
Terminated acquisition costs		12,396		-		12,396
Depreciation & amortization		28,622		39,545		(10,923	)
Other taxes		12,344		14,871		(2,527	)
Other operating expenses		83,146		82,420		726
Operating Income - Other		79,928		72,203		7,725
Operating Income - Eliminations(1)		770		770		-
Total Operating Income	$	80,698	$	72,973	$	7,725

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

Page 20

Interest Expense

Total interest expense for the second quarter of 2008 decreased by approximately $206,000, or approximately 13 percent, compared to the same period in 2007. The lower interest expense is a result of the following developments:

Interest on short-term borrowings increased $44,000 in the second quarter of 2008 compared to the same period in 2007, based upon an increase of $21.2 million in the Company’s average short-term borrowing balance. The impact of the higher borrowing was partially offset by a lower weighted average interest rate that was nearly three percentage points lower in 2008 and the amount of interest capitalized during the period. The Company’s average short-term borrowing during the second quarter of 2008 was $35.3 million with a weighted average interest rate of 2.51 percent, compared to $14.1 million with a weighted average interest rate of 5.74 percent for the same period in 2007.

Interest on long-term debt decreased $141,000 in the second 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 second 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 expense for other items, such as interest on refunds to customers and meter deposits, increased $31,000 in the second quarter of 2008 compared to the corresponding period in 2007.

Income Taxes

Income tax expense for the second quarter of 2008 was $1.2 million compared to $850,000 for the second quarter of 2007. The increase in income tax expense primarily reflects the higher earnings for the period and an increase of $50,000 to our tax accrual for uncertain tax positions as defined by FIN 48,” related to our 2005 tax return that is currently under audit by the IRS. The effective tax rate for the second quarter of 2008 is 39.5 percent compared to an effective tax rate of 36.4 percent for the second quarter of 2007.

Results of Operations for the Six Months Ended June 30, 2008

The following discussions on operating income and segment results for the six months ended June 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 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 a slight decrease of $80,000, or less than one percent, in net income for the six months ended June 30, 2008, compared to the same period in 2007. Earnings per share decreased by $0.03 per share (diluted) in the first six months of 2008 to $1.36 per share (diluted), compared to $1.39 per share (diluted) in 2007, due to an increased number of shares outstanding in 2008.

For the Six Months Ended June 30,	2008		2007			Change
Net Income
Continuing operations	$	9,393,266	$	9,499,162		$	(105,896	)
Discontinued operations		-		(26,284	)		26,284
Total Net Income	$	9,393,266	$	9,472,878		$	(79,612	)

Diluted Earnings (Loss) Per Share
Continuing operations	$	1.36	$	1.39		$	(0.03	)
Discontinued operations		-		-			-
Total Diluted Earnings Per Share	$	1.36	$	1.39		$	(0.03	)

The period-over-period decreases in net income reflects higher income taxes and lower other income, which were partially offset by a slight increase in operating income and a decrease in interest expense. Operating income increased by $59,000 to $18.4 million for the first six months of 2008 compared to $18.3 million for the same period in 2007, as the gross margin increase of $1.9 million, or four percent, was almost completely offset by an 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 lower non-weather-related sales volumes and margin per gallon for the propane segment. Contributing to the higher operating expenses in 2008 was the $1.2 million of costs associated with the unconsummated acquisition in the second quarter of 2008.


For the Six Months Ended June 30,	2008		2007		Change
Operating Income
Natural Gas	$	15,205,387	$	13,608,264	$	1,597,123
Propane		2,819,436		4,327,658		(1,508,222	)
Advanced Information Services		174,941		227,528		(52,587	)
Other & Eliminations		170,390		148,187		22,203
Operating Income		18,370,154		18,311,637		58,517

Other Income		81,097		290,675		(209,578	)
Interest Charges		2,982,106		3,193,951		(211,845	)
Income Taxes		6,075,879		5,909,199		166,680
Net Income from Continuing Operations	$	9,393,266	$	9,499,162	$	(105,896	)

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

·	Growth in the number of customers, improved supply management techniques and favorable imbalance resolutions with interstate pipelines produced a higher gross margin of $618,000 for the Company’s natural gas marketing operation.

·	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 $610,000 in the first six months of 2008 compared to the same period in 2007.

·	New transportation capacity contracts implemented for the natural gas transmission operation in November 2007 provided for $591,000 of additional gross margin in the first six months of 2008.

·	Period-over-period residential and commercial customer growth of five percent and two percent, respectively, for the Delmarva natural gas distribution operations in 2008.

Rate increases, lower depreciation allowances and lower asset removal cost allowances contributed $1.7 million to operating income for the natural gas segment in the first six months of 2008 as a result of rate proceedings for the Company’s Delmarva natural gas distribution and natural gas transmission operations.

Partially offsetting these increases in gross margin was the negative impact that warmer weather on the Delmarva Peninsula had on gross margin for the 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.

Page 21

Natural Gas

The natural gas segment earned operating income of $15.2 million for the first six months in 2008 compared to $13.6 million for the corresponding period in 2007, an increase of $1.6 million, or 12 percent.

For the Six Months Ended June 30,	2008		2007		Change
Revenue	$	122,806,861	$	104,875,421	$	17,931,440
Cost of sales		88,263,342		72,899,708		15,363,634
Gross margin		34,543,519		31,975,713		2,567,806

Operations & maintenance		12,790,761		12,703,572		87,189
Terminated acquisition costs		890,053		-		890,053
Depreciation & amortization		3,294,659		3,630,193		(335,534	)
Other taxes		2,362,659		2,033,684		328,975
Other operating expenses		19,338,132		18,367,449		970,683
Total Operating Income	$	15,205,387	$	13,608,264	$	1,597,123


Statistical Data — Delmarva Peninsula
Heating degree-days ("HDD"):
Actual		2,703		2,966		(263	)
10-year average (normal)		2,760		2,737		23

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

Per residential customer added:
Estimated gross margin	$	372	$	372	$	0
Estimated other operating expenses	$	106	$	106	$	0

Residential Customer Information
Average number of customers:
Delmarva		45,778		43,471		2,307
Florida		13,517		13,311		206
Total		59,295		56,782		2,513

Gross margin for the Company’s natural gas segment increased by $2.6 million, or eight percent, and other operating expenses increased by $971,000, or five percent, for the first six months of 2008 compared to the same period in 2007. The gross margin increases of $1.3 million for the natural gas transmission operation, $667,000 for the natural gas distribution operations and $618,000 for the natural gas marketing operation, are further explained below.

Natural Gas Transmission

The natural gas transmission operation achieved gross margin growth of $1.3 million, or 12 percent, in the first six 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 $591,000 to gross margin in the first six months of 2008. In 2008, these new transportation capacity contracts are expected to generate an additional annual gross margin of $1.2 million above 2007 gross margin.

Interruptible sales revenue, net of required margin-sharing, increased $328,000 in the first six months 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. For the remainder of 2008, however, the Company expects its natural gas transmission operation to report a decrease of $192,000 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. Currently effective settlements in rate proceedings require the Company, upon reaching the margin-sharing threshold, to share 90% of its interruptible natural gas transmission revenues with its customers.

The implementation of rate case settlement rates, effective September 1, 2007, contributed an additional $315,000 to gross margins in the first six 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 remaining $50,000 increase to gross margin is attributable to various other items.

An increase of $602,000 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 $543,000 as a result of: (1) $341,000 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 costs increased by $49,000 as a result of the improved operating results in 2008 compared to 2007.

·	Rent and utility expenses increased $88,000 and $39,000, respectively, as Eastern Shore began incurring additional rental expense in January 2008 for a new office building.

·	The increased level of capital investment caused increased property taxes of $148,000.

·	Eastern Shore experienced increased costs of $40,000 for line locating in the first six months of 2008 compared to the same period in 2007.

·	Other operating expenses relating to various items increased collectively by approximately $45,000.

Partially offsetting the previously mentioned increases was a decrease of $230,000 in depreciation expense and a decrease of $120,000 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. Also, the Company incurred regulatory expenses in the first six months of 2007 associated with the FERC rate proceeding.

Page 22

Natural Gas Distribution

Gross margin for the Company’s natural gas distribution operations increased by $667,000, or three percent, for the first six months of 2008 compared to the same period in 2007. The gross margin increases of $565,000 for the Delmarva natural gas distribution operations and $102,000 for the Florida natural gas distribution operations are further explained below.

The Delmarva distribution operations experienced an increase of $565,000, or four 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 the new housing market as a result of unfavorable market conditions in the housing industry, the average number of residential customers on the Delmarva Peninsula increased by 2,307, or five percent, for the first six months of 2008 compared to the same period in 2007, and the Company estimates that these additional residential customers contributed approximately $518,000 to gross margin during the first six months of 2008. The Company further estimates that a two percent growth in the number of the Company’s commercial customers during the first six months of 2008 in comparison to the same period in 2007 contributed approximately $221,000 to gross margin during the first six months of 2008.

·	Interruptible services revenue, net of required margin-sharing, increased $282,000 in the second 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.

Partially offsetting these increases to gross margin was the negative impact of warmer weather and lower consumption per customer in the first six months of 2008 compared to the same period in 2007. The Company estimates that warmer weather reduced gross margin by approximately $464,000 as temperatures on the Delmarva Peninsula were nine percent warmer in the first six months of 2008 compared to the same period in 2007. In addition, the Company estimates that lower consumption per customer reduced margins by approximately $73,000 in 2008.

·	The remaining $81,000 net increase in gross margin can be attributed to various factors, including the implementation of temporary rates by the Delaware division and lower industrial volumes.

Gross margin for the Florida distribution operation increased by $102,000, or two percent, in the first six months of 2008 compared to the same period in 2007. The higher gross margin for the period is primarily attributed to the increase in customers as the operation experienced a two percent growth in residential customers, an increase in non-residential customer volumes, and higher revenues from third-party natural gas marketers.

Other operating expense for the natural gas distribution operations increased by $429,000 in the first six 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 $927,000 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 $295,000 in the first six months of 2008 as the Delmarva and Florida operations experienced improved earnings compared to the prior year.

·	The Florida distribution operation experienced higher expense of $113,000 for outside services as the operation incurred additional costs for meter reading services and higher commissions to a third-party marketer.

·	Property taxes increased by $114,000 as a result of the Company’s continued capital investments.

·	Vehicle fuel increased $47,000 in the first six months of 2008 as a result of higher gasoline and diesel prices.

Depreciation expense and asset removal costs decreased $105,000 and $836,000, respectively, in the first six months of 2008 compared to the same period in 2007, primarily as a result of the Delmarva operations’s rate proceedings. These rate proceedings provided for lower depreciation allowances and lower asset removal cost allowances, which resulted in reductions of $179,000 and $937,000 in depreciation expense and asset removal costs, respectively, during the first six months of 2008.

·	Maintenance costs for the Florida operation decreased $108,000 during the first six months of 2008 compared with the same period in 2007 due to the timing of compliance costs with the new federal pipeline integrity regulations, which were incurred in 2007.

·	Merchant payment fees decreased by $97,000 primarily from the Company’s Delmarva operations outsourcing the processing of credit card payments in April of 2007.

·	In addition, other operating expenses relating to various other items increased by approximately $79,000.

Natural Gas Marketing

Gross margin for the natural gas marketing operation increased by $618,000, or 61 percent, for the first six months of 2008 compared to the same period in 2007. The increase in gross margin was primarily the result of a higher number of customers to which it provides supply management services, improved gas supply management techniques, and favorable imbalance resolutions with interstate pipelines. Other operating expenses decreased by $60,000 for the marketing operation; this decrease is attributable to lower payroll-related costs, benefits, and allowance for uncollectible accounts. These lower costs were partially offset by higher incentive compensation incurred as a result of the improved operating results and higher corporate costs as $16,000 was allocated to the operation for a portion the terminated acquisition costs.

Page 23

Propane

The propane segment earned operating income of $2.8 million for the first six months of 2008 compared to $4.3 million for the corresponding quarter in 2007, a decrease of $1.5 million, or 35 percent.


For the Six Months Ended June 30,	2008		2007		Change
Revenue	$	39,297,957	$	34,416,976	$	4,880,981
Cost of sales		27,256,857		21,263,372		5,993,485
Gross margin		12,041,100		13,153,604		(1,112,504	)

Operations & maintenance		7,457,009		7,459,990		(2,981	)
Terminated acquisition costs		272,718		-		272,718
Depreciation & amortization		1,001,808		904,368		97,440
Other taxes		490,129		461,588		28,541
Other operating expenses		9,221,664		8,825,946		395,718
Total Operating Income	$	2,819,436	$	4,327,658	$	(1,508,222	)


Statistical Data — Delmarva Peninsula
Heating degree-days ("HDD"):
Actual		2,703		2,966		(263	)
10-year average (normal)		2,760		2,737		23

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 and lower sales volumes in the first six months of 2008.

The gross margin decreases of $1.3 million for the Delmarva propane distribution operations and $14,000 for the Florida propane distribution operations, which were partially offset by a higher gross margin of $170,000 for the propane wholesale and marketing operation, are further explained below.

Delmarva Propane Distribution

The Delmarva propane distribution operation’s decrease in gross margin of $1.3 million resulted from the following:

Temperatures on the Delmarva Peninsula were nine percent warmer in the first six months of 2008 compared to the same period in 2007, which contributed to a decrease of 891,000 gallons, or six 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 $648,000 for the Delmarva propane distribution operation compared to the first six months of 2007.

Non-weather-related volumes sold in the first six months of 2008 decreased by 766,000 gallons, or six percent. This decrease in gallons sold reduced gross margin by approximately $567,000 for the Delmarva propane distribution operation compared to the first six 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.

Gross margin decreased by $213,000 in the first six months of 2008, compared to the same period in 2007, because of a $0.02 decrease in the average gross margin per retail gallon. This decrease occur 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.

·	Revenues from miscellaneous fees, including items such as tank and meter rentals increased by $108,000 during the first six months of 2008 compared to the same period in 2007.

·	The remaining $52,000 net increase in gross margin can be attributed to various factors, including service revenue.

Total other operating expenses increased by $258,000 for the Delmarva propane operations in the first six 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 $415,000 as a result of (1) $227,000 for the allocation of a portion of the terminated acquisition costs previously discussed, and (2) the Company updating its annual corporate cost allocations.

·	Vehicle fuel increased $106,000 as a result of rising gasoline and diesel fuel costs.

·	The allowance for uncollectible accounts increased $62,000 due to increased revenues resulting from the higher cost of propane.

·	Mains fees increased by $51,000 in the first six 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 $41,000 as a result of an increase in the Company’s capital investments compared to the prior year.

The operations experienced lower expenses of $174,000 in the first six 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 $239,000 as a result of the lower operating results in 2008 compared to 2007.

·	Other operating expenses relating to various items decreased collectively by approximately $4,000.

Page 24

Florida Propane Distribution

The Florida propane distribution operation experienced a decrease in gross margin of $14,000, or two percent, in the first six months of 2008 compared to the same period in 2007. The lower gross margin is attributable to a decrease of $25,000 in service sales as the operation exits this portion of the business, which was partially offset by an increase of $12,000 based upon a higher average gross margin per retail gallon. Other operating expenses in the first six months of 2008, compared to the same period in 2007, increased by $77,000, primarily due to increased depreciation expense and increased corporate costs as $20,000 was allocated to the operations for a portion of the terminated acquisition costs.

Propane Wholesale and Marketing

Gross margin for the Company’s propane wholesale marketing operation increased by $170,000, or 13 percent, in the first six months of 2008 compared to the same period in 2007. This increase reflects the larger number of market opportunities that arose in the first six 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 $61,000, due primarily to higher payroll costs and increased corporate costs as $26,000 was allocated to the operation for a portion of the terminated acquisition costs. The higher period-over-period payroll cost is the result of a position vacant during 2007 being filled in 2008.

Advanced Information Services

The advanced information services business experienced gross margin growth of approximately $352,000, or 11 percent, and contributed operating income of $175,000 for the second quarter of 2008, a decrease of $53,000 compared to the same period in 2007. Absent the terminated acquisition costs of $64,000 allocated to the advanced information segment in the second quarter of 2008, the segment would have experienced a slight increase in its operating income of $11,000 for the first six months of 2008 compared to the same period in 2007.


For the Six Months Ended June 30,	2008		2007		Change
Revenue	$	7,473,413	$	7,121,197	$	352,216
Cost of sales		4,000,948		4,001,111		(163	)
Gross margin		3,472,465		3,120,086		352,379

Operations & maintenance		2,766,947		2,464,659		302,288
Terminated acquisition costs		64,461		-		64,461
Depreciation & amortization		75,838		69,485		6,353
Other taxes		390,278		358,414		31,864
Other operating expenses		3,297,524		2,892,558		404,966
Total Operating Income	$	174,941	$	227,528	$	(52,587	)

The increase of revenues in the first six months of 2008 resulted primarily from the following:

·	Product sales increased by $204,000 as the operation enlarged its marketing and sales force.

·	Consulting revenues increased by $87,000 as higher average billing rates overcame a two-percent decrease in the number of billable hours;

·	Managed Database Administration (“MDBA”) services, which provide clients with professional database monitoring and support solutions during business hours or around the clock increased by $75,000; and

·	Revenues from other products and services decreased collectively by approximately $14,000.

Cost of sales remained relatively unchanged from period-to-period. An increase in cost of sales to provide services for the additional revenue earned in 2008 was offset by a reduction in cost of sales for billable employees that transferred to non-billable positions. Also, lower reimbursable expenses contributed to the reduction in cost of sales as employees performed less travel during the period.

Other operating expenses increased by $405,000 in the first six months of 2008, compared to the same period in 2007. This increase in operating expenses is attributable to payroll costs, payroll taxes, and higher corporate costs as $64,000 was allocated to the segment for a portion of the terminated acquisition costs. Payroll costs increased as a result of the increase in non-billable staffing levels previously discussed.

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 $170,000 for the first six months of 2008 compared to an operating income of approximately $148,000 for the same period in 2007.


For the Six Months Ended June 30,	2008		2007		Change
Revenue	$	326,148	$	309,246	$	16,902
Cost of sales		-		-		-
Gross margin		326,148		309,246		16,902

Operations & maintenance		58,716		51,475		7,241
Terminated acquisition costs		12,396		-		12,396
Depreciation & amortization		57,244		80,813		(23,569	)
Other taxes		28,941		30,310		(1,369	)
Other operating expenses		157,297		162,598		(5,301	)
Operating Income - Other		168,851		146,648		22,203
Operating Income - Eliminations(1)		1,539		1,539		-
Total Operating Income	$	170,390	$	148,187	$	22,203

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

Page 25

Interest Expense

Total interest expense for the first six months of 2008 decreased by approximately $212,000, or seven percent, compared to the same period in 2007. The lower interest expense is a result of the following developments:

Interest on short-term borrowings increased by $130,000 in the first six months of 2008 compared to the same period in 2007, based upon an increase of $19.8 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 2.6 percentage points lower in 2008 and interest that was capitalized during the period. The Company’s average short-term borrowing during the first six months of 2008 was $35.6 million, with a weighted average interest rate of 3.14 percent, compared to $15.8 million, with a weighted average interest rate of 5.72 percent for the same period in 2007.

Interest on long-term debt decreased by $282,000 in the first six 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 six months of 2008 was $69.9 million, with a weighted average interest rate of 6.63 percent, compared to $77.8 million, with a weighted average interest rate of 6.68 percent for the same period in 2007.

·	Interest expense for customer refunds increased by $210,000 in the first six months of 2008 due to the timing of regulatory filings and the settlement of rate cases.

·	Interest expense for other items, such as interest on refunds and meter deposits, increased by $27,000 in the first six months of 2008 compared to the corresponding period in 2007.

Income Taxes

Income tax expense for the first six months of 2008 was $6.1 million compared to $5.9 million for the same period in 2007. The increase in income tax expense primarily reflects the higher earnings for the period and an increase of $50,000 to our tax accrual for uncertain tax positions as defined in FIN 48 related to our 2005 tax return that is currently under audit by the IRS. The effective tax rate for the first six months of 2008 is 39.3 percent compared to an effective tax rate of 38.4 percent for the same period in 2007.

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 six months of 2008, net cash provided by operating activities was $9.6 million, cash used by investing activities was $15.6 million, and cash provided by financing activities was $6.6 million.

By comparison, during the first six months of 2007, net cash provided by operating activities was $20.6 million, cash used by investing activities was $15.9 million, and cash used by financing activities was $8.3 million.

As of February 20, 2008, the Board of Directors has authorized the Company to borrow up to $70.0 million of short-term debt, as required, from various banks and trust companies under short-term lines of credit. As of June 30, 2008, Chesapeake had five unsecured bank lines of credit with three financial institutions, totaling $90.0 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 June 30, 2008 and December 31, 2007 was $57.1 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 June 30, 2008 and December 31, 2007:

	June 30, 2008				December 31, 2007
	(In thousands, except percentages)

Long-term debt, net of current maturities	$	63,181	33	%	$	63,255	35	%
Stockholders' equity	$	125,470	67	%	$	119,577	65	%
Total capitalization, excluding short-term debt	$	188,651	100	%	$	182,832	100	%

As of June 30, 2008, common equity represented 67 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 50 percent at June 30, 2008, compared to 49 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 customers and creditors, as well as to the Company’s investors.

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 their over-allotment option of 90,045 shares, under this registration statement, generating net proceeds of $19.7 million. At June 30, 2008, the Company had approximately $20.0 million remaining under this registration statement.

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Cash Flows Provided By Operating Activities

Cash flows provided by operating activities were as follow:


For the Six Months Ended June 30,	2008			2007		Change
Net Income	$	9,393,266		$	9,472,879	$	(79,613	)
Non-cash adjustments to net income		7,505,849			8,186,431		(680,582	)
Changes in working capital		(7,256,462	)		2,958,748		(10,215,210	)
Net cash provided by operating activties	$	9,642,653		$	20,618,058	$	(10,975,405	)

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. The 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 six months of 2008, net cash flow provided by operating activities was $9.6 million, a reduction of $11.0 million compared to the same period of 2007. The decrease was due primarily to an increase in accounts receivable, which was partially offset by an increase in accounts payable. These increases are due to the timing of collections and payments of trading contracts entered into by the Company’s propane wholesale and marketing operation. Also contributing to the decrease in net cash flows provided by operating activities, was a reduction in regulatory liabilities, which resulted primarily from environmental expenditures and refunds to customers.

Cash Flows Used in Investing Activities

Net cash flows used in investing activities totaled $15.6 million and $15.9 million during the six months ended June 30, 2008 and 2007, respectively.

Cash utilized for capital expenditures was $15.4 million and $16.0 million for the first six months of 2008 and 2007, respectively. Additions to property, plant and equipment in the first six months of 2008 were primarily for natural gas transmission ($5.9 million), natural gas distribution ($7.0 million), propane distribution ($1.6 million), and other operations ($889,000).

·	The Company’s environmental expenditures exceeded amounts recovered through rates charged to customers in the first six months of 2008 and 2007 by $199,000 and $136,000, respectively.

Cash Flows Provided by Financing Activities

Cash flows provided by financing activities totaled $6.6 million for the first six months of 2008 compared to $8.3 million of cash used for the first six months of 2007. Significant financing activities included the following:

·	During the first six months of 2008, the Company had net borrowings from short-term debt of $11.5 million compared to a net repayment of $4.8 million in the first six months of 2007.

During the first six months of 2008, the Company paid $3.8 million in cash dividends compared with dividend payments of $3.5 million for the same time period in 2007. The increase in dividends paid in the first six 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 six 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 June 30, 2008 was $24.2 million, with the guarantees expiring on various dates in 2008 and the first six 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 June 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)	$	20,342,267	$	1,329,764	$	0	$	0	$	21,672,031
Propane(2)		66,118,237		-		-		-		66,118,237
Total Purchase Obligations	$	86,460,504	$	1,329,764	$	0	$	0	$	87,790,268

(1)

In addition to the obligations noted above, the natural gas distribution and propane distribution operations have agreements with commodity suppliers that have provisions allowing the Company to reduce or eliminate the quantities purchased. There are no monetary penalties for reducing the amounts purchased; however, the propane contracts allow the suppliers to reduce the amounts available in the winter season if the Company does not purchase specified amounts during the summer season. Under these contracts, the commodity prices will fluctuate as market prices fluctuate.

(2)	The Company has also entered into forward sale contracts in the aggregate amount of $68.6 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 the 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 subject to regulation by their respective state PSCs. Eastern Shore is subject to regulation by the FERC. At June 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 the 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.

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 the unaudited Condensed Consolidated Financial Statements.

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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 June 30, 2008, as compared to a fair value of $72.9 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 as a result of propane storage activities and when it enters into fixed-price contracts for supply. The Company can store up to approximately four million gallons (including leased storage and rail cars) 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. Management reviewed the Company’s storage position as of June 30, 2008 and elected not to hedge any of its inventories.

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 booking out the transaction. Booking out is a procedure for financially settling a contract in lieu of the physical delivery of energy. 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 are monitored daily for compliance with the Company’s Risk Management Policy, which includes volumetric limits for open positions. To manage exposures 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 market 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 June 30, 2008 is presented in the following table.


At June 30, 2008	Quantity in gallons	Estimated Market Prices	Weighted Average Contract Prices
Forward Contracts
Sale	38,472,000	$1.3550 — $1.9200	$1.7837
Purchase	37,379,982	$1.3650 — $1.9250	$1.7688

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 June 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 June 30, 2008.

Changes in Internal Control Over Financial Reporting

During the quarter ended June 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 the 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

In addition to the other information set forth in this Form 10-Q, including the risks and uncertainties described under Item 2 of Part I of this Form 10-Q, in the section entitled “Safe Harbor and Forward Looking Statements,” consideration should be given to the factors discussed under Item 1A. “Risk Factors,” in the Company’s Form 10-K for the fiscal year ended December 31, 2007. These risks could affect the operations and/or financial performance of the Company. The risks described in the Form 10-K and this Form 10-Q are not the only risks that the Company faces. The Company’s operations and/or financial performance could also be affected by additional factors that at present are not known to it or that the Company considers immaterial to its operations and/or financial performance.

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	Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs
	April 1, 2008
	through April 30, 2008 (1)	557	$30.99	-	-
	May 1, 2008
	through May 30, 2008	-	-	-	-
	June 1, 2008
	through June 30, 2008	-	-	-	-

Total		557	$30.99	-	-

(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 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 filed with the Securities Exchange Commission on March 10, 2008. During the quarter,
557 shares were purchased through the reinvestment of dividends on deferred stock units.

Item 3. Defaults upon Senior Securities

None

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

The Annual Meeting of the Stockholders of Chesapeake Utilities Corporation was held on May 1, 2008. The items set forth below were submitted to a vote of security holders. Proxies for the meeting were solicited in accordance with Regulation 14A under the Securities Exchange Act of 1934, as amended.

The stockholders elected three nominees to the Company’s Board of Directors to serve as Class III directors for three-year terms ending in 2011, and until their successors are elected and qualify. The following shows the separate tabulation of votes for each nominee:

Name	Votes For	Votes Withheld
Thomas J. Bresnan	6,357,555	182,717
Joseph E. Moore	6,308,808	231,464
John R. Schimkaitis	6,354,089	186,183

The terms of the following directors were not subject to vote (or election) and they remained in office after the meeting:

Class I Directors (Terms Expire in 2009)	Class II Directors (Terms Expire in 2010)
Calvert A. Morgan, Jr.	Ralph J. Adkins
Eugene H. Bayard	Richard Bernstein
Thomas P. Hill, Jr.	J. Peter Martin

The stockholders approved the ratification of the appointment of Beard Miller Company LLP as the Company’s independent registered public accounting firm for the fiscal year ending December 31, 2008. There were 6,473,303 affirmative votes, 35,107 negative votes, and 31,862 abstentions. There were no broker non-votes for this matter.

The stockholders did not approve a shareholder proposal requesting that the Board of Directors take the steps necessary to eliminate classification of terms of the Board of Directors. The Board of Directors opposed this proposal. There were 2,418,582 affirmative votes, 2,635,724 negative votes, 71,889 abstentions, and 1,414,077 broker non-votes.

As of the Record Date, March 14, 2008, 6,806,487 shares of common stock of the Company, the only class of voting or equity securities of the Company, were outstanding.

Item 5. Other Information

None

Page 30

Item 6. Exhibits

Exhibit	Description
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 August 11, 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 August 11, 2008.

32.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated August 11, 2008.

32.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated August 11, 2008.

Page 31

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/ Michael P. McMasters

Michael P. McMasters

Senior Vice President and Chief Financial Officer

Date: August 11, 2008

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Chesapeake Utilities - 10-Q quarterly report FY

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