Chesapeake Utilities (CPK) 10-Q 2007 Q3 Quarterly report

United States

Securities and Exchange Commission

Washington, D.C. 20549

_______________________________

FORM 10-Q

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

For the quarterly period ended: September 30, 2007

OR

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

For the transition period from ______ to ______

Commission File Number: 001-11590

Chesapeake Utilities Corporation

(Exact name of registrant as specified in its charter)

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

909 Silver Lake Boulevard, Dover, Delaware 19904

(Address of principal executive offices, including Zip Code)

(302) 734-6799

(Registrant’s telephone number, including area code)

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

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

Large accelerated filer [  ]Accelerated filer [X]Non-accelerated filer [  ]

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 — 6,771,365 shares outstanding as of October 31, 2007.

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	26
	Item 4. Controls and Procedures	27
PART II — OTHER INFORMATION		28
	Item 1. Legal Proceedings	28
	Item 1A. Risk Factors	28
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	28
	Item 3. Defaults upon Senior Securities	28
	Item 4. Submission of Mattters to a Vote of Security Holders	28
	Item 5. Other Information	28
	Item 6. Exhibits	28
SIGNATURES		29

PART I — FINANCIAL INFORMATION

Item 1.  Financial Statements

Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Income (Unaudited)
For the Three Months Ended September 30,	2007			2006
Operating Revenues	$	41,418,718		$	35,141,531
Operating Expenses
Cost of sales, excluding costs below		25,826,902			21,758,558
Operations		10,530,152			9,292,099
Maintenance		512,201			513,356
Depreciation and amortization		2,144,926			2,044,179
Other taxes		1,418,903			1,210,667
Total operating expenses		40,433,084			34,818,859
Operating Income		985,634			322,672
Other loss, net of other expenses		(13,481	)		(12,096	)
Interest charges		1,695,597			1,339,950
Loss Before Income Taxes		(723,444	)		(1,029,374	)
Income taxes		(363,474	)		(467,859	)
Loss from Continuing Operations		(359,970	)		(561,515	)
Gain (loss) from discontinued operations,
net of tax of $4,249 and ($39,583)		4,072			(95,064	)
Net Loss	$	(355,898	)	$	(656,579	)
Basic weighted average shares outstanding		6,754,650			5,973,149
Diluted weighted average shares outstanding		6,754,650			5,973,149
Loss Per Share of Common Stock:
Basic
From continuing operations	$	(0.05	)	$	(0.09	)
From discontinued operations		-		$	(0.02	)
Net Loss	$	(0.05	)	$	(0.11	)
Diluted
From continuing operations	$	(0.05	)	$	(0.09	)
From discontinued operations		-		$	(0.02	)
Net Loss	$	(0.05	)	$	(0.11	)
Cash Dividends Declared Per Share of Common Stock:	$	0.295		$	0.290

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

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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Income (Unaudited)
For the Nine Months Ended September 30,	2007			2006
Operating Revenues	$	187,447,528		$	170,394,930
Operating Expenses
Cost of sales, excluding costs below		123,991,093			116,187,972
Operations		31,370,800			27,558,356
Maintenance		1,657,219			1,540,960
Depreciation and amortization		6,828,243			6,058,529
Other taxes		4,302,901			3,887,797
Total operating expenses		168,150,256			155,233,614
Operating Income		19,297,272			15,161,316
Other income, net of other expenses		277,194			130,197
Interest charges		4,889,548			4,333,862
Income Before Income Taxes		14,684,918			10,957,651
Income taxes		5,545,725			4,174,361
Income from Continuing Operations		9,139,193			6,783,290
Loss from discontinued operations, net of
tax of ($11,955) and ($147,334)		(22,212	)		(210,944	)
Net Income	$	9,116,981		$	6,572,346
Basic weighted average shares outstanding		6,754,650			5,973,149
Diluted weighted average shares outstanding		6,754,650			5,973,149
Earnings (Loss) Per Share of Common Stock:
Basic
From continuing operations	$	1.35		$	1.14
From discontinued operations		-		$	(0.03	)
Net Income	$	1.35		$	1.11
Diluted
From continuing operations	$	1.34		$	1.13
From discontinued operations		-		$	(0.03	)
Net Income	$	1.34		$	1.10
Cash Dividends Declared Per Share of Common Stock:	$	0.880		$	0.865

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

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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)
For the Nine Months Ended September 30,	2007	2006
Operating Activities
Net Income	$9,116,981	$6,572,346
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization	6,828,244	6,058,529
Depreciation and accretion included in other costs	2,535,385	2,288,510
Deferred income taxes, net	1,580,609	(2,304,069)
Gain on sale of assets	(204,882)	-
Unrealized gain on commodity contracts	(794,745)	(708,915)
Unrealized gain on investments	(206,309)	(65,810)
Employee benefits and compensation	1,430,074	1,355,773
Other, net	(1,738)	(3,085)
Changes in assets and liabilities:
Sale (purchase) of investments	172,942	(120,476)
Accounts receivable and accrued revenue	2,180,615	17,284,219
Propane inventory, storage gas and other inventory	(1,473,887)	(1,477,854)
Regulatory assets	212,735	3,729,327
Prepaid expenses and other current assets	(2,004,422)	(770,472)
Other deferred charges	(1,801,079)	33,696
Long-term receivables	59,799	108,608
Accounts payable and other accrued liabilities	(1,184,523)	(19,573,625)
Income taxes receivable (payable)	(1,480,312)	3,123,440
Accrued interest	959,191	1,024,867
Customer deposits and refunds	1,392,738	767,475
Accrued compensation	340,573	(853,616)
Regulatory liabilities	2,185,361	2,785,997
Other liabilities	(151,422)	(85,853)
Net cash provided by operating activities	19,691,928	19,169,012
Investing Activities
Property, plant and equipment expenditures	(22,877,580)	(28,531,235)
Proceeds from sale of assets	204,882	-
Environmental expenditures	(166,172)	(9,626)
Net cash used in investing activities	(22,838,870)	(28,540,861)
Financing Activities
Common stock dividends	(5,245,496)	(4,462,309)
Issuance of stock for Dividend Reinvestment Plan	244,695	229,756
Cash settlement of warrants	-	(434,782)
Change in cash overdrafts due to outstanding checks	582,701	1,042,051
Net borrowing under line of credit agreements	5,001,601	14,790,072
Repayment of long-term debt	(1,020,183)	(1,929,619)
Net cash provided (used) by financing activities	(436,682)	9,235,169
Net Decrease in Cash and Cash Equivalents	(3,583,624)	(136,680)
Cash and Cash Equivalents — Beginning of Period	4,488,367	2,487,658
Cash and Cash Equivalents — End of Period	$904,743	$2,350,978
Supplemental Disclosures of Non-Cash Investing Activities:
Capital property and equipment acquired on account, but not paid as of September 30	$437,676	$4,288,688

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

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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
Assets	September 30, 2007			December 31, 2006
Property, Plant and Equipment
Natural gas	$	282,018,703		$	269,012,516
Propane		47,239,919			44,791,552
Advanced information services		1,133,460			1,054,368
Other plant		9,403,935			9,147,500
Total property, plant and equipment		339,796,017			324,005,936
Less:  Accumulated depreciation and amortization		(91,778,706	)		(85,010,472	)
Plus:  Construction work in progress		6,719,861			1,829,948
Net property, plant and equipment		254,737,172			240,825,412
Investments		2,048,944			2,015,577
Current Assets
Cash and cash equivalents		904,743			4,488,366
Accounts receivable (less allowance for uncollectible accounts of $927,708 and $661,597, respectively)		44,946,194			44,969,182
Accrued revenue		2,167,724			4,325,351
Propane inventory, at average cost		8,181,131			7,187,035
Other inventory, at average cost		1,399,740			1,564,937
Regulatory assets		1,028,847			1,275,653
Storage gas prepayments		8,038,323			7,393,335
Income taxes receivable		2,559,194			1,078,882
Deferred income taxes		1,087,155			1,365,316
Prepaid expenses		4,312,916			2,280,900
Mark-to-market energy assets		13,175,102			1,379,896
Other current assets		145,794			173,388
Total current assets		87,946,863			77,482,241
Deferred Charges and Other Assets
Goodwill		674,451			674,451
Other intangible assets, net		181,524			191,878
Pension		649,842			590,562
Long-term receivables		764,534			824,333
Other regulatory assets		2,545,824			1,765,088
Other deferred charges		2,976,439			1,215,004
Total deferred charges and other assets		7,792,614			5,261,316
Total Assets	$	352,525,593		$	325,584,546

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

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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
Capitalization and Liabilities	September 30, 2007			December 31, 2006
Capitalization
Stockholders' equity
Common Stock, par value $0.4867 per share (authorized 12,000,000 shares)	$	3,290,841		$	3,254,998
Additional paid-in capital		64,961,972			61,960,220
Retained earnings		49,456,800			46,270,884
Accumulated other comprehensive loss		(334,550	)		(334,550	)
Deferred compensation obligation		1,387,164			1,118,509
Treasury stock		(1,387,164	)		(1,118,509	)
Total stockholders' equity		117,375,063			111,151,552
Long-term debt, net of current maturities		69,911,000			71,050,000
Total capitalization		187,286,063			182,201,552
Current Liabilities
Current portion of long-term debt		7,656,364			7,656,364
Short-term borrowing		33,138,243			27,553,941
Accounts payable		31,425,364			33,870,552
Customer deposits and refunds		8,895,003			7,502,265
Accrued interest		1,791,583			832,392
Dividends payable		1,993,946			1,939,482
Accrued compensation		2,622,743			2,901,053
Regulatory liabilities		6,510,801			4,199,147
Mark-to-market energy liabilities		12,371,840			1,371,379
Other accrued liabilities		2,831,251			2,634,416
Total current liabilities		109,237,138			90,460,991
Deferred Credits and Other Liabilities
Deferred income taxes		27,819,546			26,517,098
Deferred investment tax credits		288,267			328,277
Other regulatory liabilities		1,036,903			1,236,254
Environmental liabilities		865,132			211,581
Other pension and benefit costs		2,262,762			2,198,874
Accrued asset removal cost		19,862,275			18,410,992
Other liabilities		3,867,507			4,018,927
Total deferred credits and other liabilities		56,002,392			52,922,003
Other Commitments and Contingencies (Note 4)
Total Capitalization and Liabilities	$	352,525,593		$	325,584,546

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

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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Stockholders' Equity (Unaudited)
	For the Nine Months Ended September 30, 2007			For the Twelve Months Ended December 31, 2006
Common Stock
Balance — beginning of period	$	3,254,998		$	2,863,212
Dividend Reinvestment Plan		13,343			18,685
Retirement Savings Plan		11,153			14,457
Conversion of debentures		3,402			8,117
Performance shares and options exercised		7,945			14,536
Stock issuance		-			335,991
Balance — end of period	$	3,290,841		$	3,254,998
Additional Paid-in Capital
Balance — beginning of period	$	61,960,220		$	39,619,849
Dividend Reinvestment Plan		861,086			1,148,100
Retirement Savings Plan		712,453			900,354
Conversion of debentures		115,415			275,300
Stock-based compensation		1,312,798			887,426
Stock issuance		-			19,362,518
Exercise of warrants		-			(233,327	)
Balance — end of period	$	64,961,972		$	61,960,220
Retained Earnings
Balance — beginning of period	$	46,270,884		$	42,854,894
Net income		9,116,981			10,506,525
Cash dividends declared		(5,931,065	)		(7,090,535	)
Balance — end of period	$	49,456,800		$	46,270,884
Accumulated Other Comprehensive Loss
Balance — beginning of period	$	(334,550	)	$	(578,151	)
Minimum pension liability adjustment, net of tax		-			74,036
Gain on funded status of Employee Benefit Plans, net of tax		-			169,565
Balance — end of period	$	(334,550	)	$	(334,550	)
Deferred Compensation Obligation
Balance — beginning of period	$	1,118,509		$	794,535
New deferrals		268,655			323,974
Balance — end of period	$	1,387,164		$	1,118,509
Treasury Stock
Balance — beginning of period	$	(1,118,509	)	$	(797,156	)
New deferrals related to compensation obligation		(268,655	)		(323,974	)
Purchase of treasury stock (1)		(29,771	)		(51,572	)
Sale and distribution of treasury stock (2)		29,771			54,193
Balance — end of period	$	(1,387,164	)	$	(1,118,509	)
Total Stockholders’ Equity	$	117,375,063		$	111,151,552
(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 obligation under the Deferred Compensation Plan.

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

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Notes to Condensed Consolidated Financial Statements

1.   Basis of Presentation

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

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and United States of America Generally Accepted Accounting Principles (“GAAP”). In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in the Company’s latest Annual Report on Form 10-K filed with the SEC on March 14, 2007. 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. Chesapeake did not have any adjustments to the components of 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,” for the first nine months of 2007 and 2006.  Accumulated other comprehensive loss was $334,550 at September 30, 2007 and December 31, 2006.

3.   Calculation of Earnings Per Share

	Three Months Ended						Nine Months Ended
For the Periods Ended September 30,	2007			2006			2007		2006
Calculation of Basic Earnings (Loss) Per Share:
Net Income  (Loss)	$	(355,898	)	$	(656,579	)	$	9,116,981	$	6,572,346
Weighted average shares outstanding		6,754,650			5,973,149			6,732,800		5,945,119
Basic Earnings (Loss) Per Share	$	(0.05	)	$	(0.11	)	$	1.35	$	1.11
Calculation of Diluted Earnings (Loss) Per Share:
Reconciliation of Numerator:
Net Income (Loss)	$	(355,898	)	$	(656,579	)	$	9,116,981	$	6,572,346
Effect of 8.25% Convertible debentures (1)		-			-			72,312		79,900
Adjusted numerator — Diluted	$	(355,898	)	$	(656,579	)	$	9,189,293	$	6,652,246
Reconciliation of Denominator:
Weighted shares outstanding — Basic		6,754,650			5,973,149			6,732,800		5,945,119
Effect of dilutive securities (1)
8.25% Convertible debentures		-			-			112,925		124,774
Adjusted denominator — Diluted		6,754,650			5,973,149			6,845,725		6,069,893
Diluted Earnings (Loss) Per Share	$	(0.05	)	$	(0.11	)	$	1.34	$	1.10
(1) Amounts associated with conversion of securities that result in an anti-dilutive effect on earnings per share
are not included in this calculation.

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4.   Commitments and Contingencies

Rates and Regulatory Matters

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

Delaware.On September 2, 2005, the Delaware division filed an application with the Delaware Public Service Commission (“Delaware PSC”) requesting approval of an alternative rate design and rate structure in order to provide natural gas service to prospective customers in eastern Sussex County (“2005 Proceeding”). While Chesapeake provides natural gas service to residents and businesses in portions of Sussex County under the Company’s current tariff, natural gas distribution lines have not been extended to a large portion of the State of Delaware’s recently targeted growth areas in eastern Sussex County. In April 2002, Governor Ruth Ann Minner established the Delaware Energy Task Force (“Task Force”), whose mission was to address the State of Delaware’s long-term and short-term energy challenges. In September 2003, the Task Force issued its final report to the Governor that included a strategy related to enhancing the availability of natural gas within the State by evaluating possible incentives for expanding residential and commercial natural gas service. Chesapeake believes its current proposal to implement a rate design that will enable the Company to provide natural gas as a viable energy choice to a broader number of prospective customers within eastern Sussex County  supports the Task Force recommendation. As the Delaware division included these proposals in its base rate filing made on July 6, 2007, the Delaware division closed the 2005 Proceeding with the intent to continue discussions in the context of the 2007 base rate proceeding.

On September 1, 2006, the Company filed with the Delaware PSC its annual Gas Sales Service Rates (“GSR”) Application  seeking the approval of the Delaware PSC to change its GSR rates effective for service rendered on and after November 1, 2006. On October 3, 2006, the Delaware PSC authorized the Company to implement the GSR charges on a temporary basis and subject to refund, pending the completion of full evidentiary hearings and a final decision by the Delaware PSC. The Division of the Public Advocate (“DPA”) recommended a cost disallowance of approximately $4.4 million related to the Delaware division’s commodity procurement purchases and a disallowance of approximately $275,000 related to pipeline capacity the Delaware division holds in eastern Sussex County, Delaware. The Delaware PSC Staff recommended a cost disallowance of approximately $2.2 million related to the Delaware division’s commodity procurement purchases and the deferral of approximately $535,000 related to pipeline capacity the Delaware division holds in eastern Sussex County, Delaware. The Company disagreed with these recommendations and opposed the proposed cost disallowance and deferral in its rebuttal position submitted on April 19, 2007. Under established Delaware law, gas procurement costs, like other normally accepted operating expenses, cannot be disallowed unless it is shown that the costs were the result of an abuse of discretion, bad faith, or waste. Management believes that the Company’s gas procurement practices and pipeline capacity costs were reasonable and that, in no event were the costs at issue incurred as a result of any abuse of discretion, bad faith, or waste on the part of the Company. On July 24, 2007, the Delaware PSC approved a settlement agreement between the parties resulting in a complete recovery of the Delaware division’s costs.  As a result of the settlement agreement, the Delaware division has agreed to contribute an amount equal to $37,500 per year for the next three years to a program designed to benefit elderly, disabled, and low-income customers of the Delaware division. Additionally, with respect to the allowances for recovery of costs associated with pipeline capacity in eastern Sussex County, the settlement provides for the Delaware division to reduce the total amount of GSR charges to be collected from its customers by $275,000, effective beginning with the billing period from November 1, 2007 through October 31, 2008.  The settlement also provides for the Delaware division subsequently to add $275,000 to the total GSR charges to be collected from customers effective for billings from November 1, 2008 through October 31, 2009.

On November 1, 2006, 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, 2006. The Delaware PSC granted approval of the ER rate at its regularly scheduled meeting on November 21, 2006, subject to full evidentiary hearings and a final decision. On January 23, 2007, the Delaware PSC granted final approval of the ER rate as filed.

On November 9, 2006, the Delaware division filed two applications with the Delaware PSC requesting approval for a Town of Millsboro Franchise Fee Rider and a Town of Georgetown Franchise Fee Rider. These Riders will allow the Delaware division to charge all respective natural gas customers within town limits the franchise fee paid by the Delaware division to the Towns of Millsboro and Georgetown as a condition to providing natural gas service. The Delaware PSC granted approval of both Riders on January 23, 2007.

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 transportation buying pools served by third-party natural gas marketers; (ii) a base rate adjustment of $1,896,000 annually 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 reduces the impact of natural gas consumption on both customers and the Company. As an incentive for the Delaware division to make the significant capital investments to serve the growing areas of eastern Sussex County and in supporting Delaware’s Energy Policy, the Company has proposed as part of the filing that the Delaware division be permitted to earn a return on equity up to 15 percent. This level of return would 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 growing 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 division anticipates a final decision by the Delaware PSC during the first half of 2008.

On September 10, 2007, the Company filed with the Delaware PSC its annual GSR Application, seeking the approval of the Delaware PSC 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 and subject to refund, pending the completion of full evidentiary hearings and a final decision by the Delaware PSC.  The Delaware division anticipates a final decision by the Delaware PSC during the first half of 2008.

Maryland. On September 26, 2006, the Maryland Public Service Commission (“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. The Maryland division anticipates a decision from the Maryland PSC on its proposed change in depreciation expense during the fourth quarter of 2007.

On December 14, 2006, 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, 2006. On December 15, 2006, the Hearing Examiner issued proposed findings approving the quarterly gas cost recovery rates as filed by the Maryland division and permitting complete recovery of its purchased gas costs for the period under review. No appeals or written exceptions to the proposed findings were made, and a final order approving the quarterly gas cost recovery rates, as filed, was issued by the Maryland PSC on January 17, 2007.

Florida. On September 15, 2006, the Florida division filed a petition with the Florida Public Service Commission (“Florida PSC”) for approval of its Energy Conservation Cost Recovery Factors for the year 2007. Approved on November 30, 2006by the Florida PSC, the new factors went into effect on January 1, 2007.

On October 10, 2006, the Florida division filed a petition with the Florida PSC for authority to implement phase two of its experimental transitional transportation service (“TTS”) pilot program, and for approval of a new tariff to reflect the division’s transportation service environment. Phase two of the TTS program for residential and certain small commercial consumers will expand the number of pool managers from one to two and increase the gas supply pricing options available to these consumers. Approved on April 24, 2007by the Florida PSC, phase two of the TTS program went into effect on July 1, 2007.

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On November 29, 2006, the Florida division filed a petition with the Florida PSC for authority to modify its energy conservation programs. In this petition, the Florida division was seeking approval to increase the cash allowances paid within the Residential Homebuilder Program and the Residential Appliance Replacement Program, and to expand the scope of the Residential Water Heater Retention Program to add natural gas heating systems, cooking and clothes drying appliances. The Florida PSC granted approval of the petition in an order dated March 5, 2007. The modifications and new cash allowances became effective on March 30, 2007.

On May 2, 2007, the Florida division filed its summary of activity and true-up calculation for its 2006 Energy Conservation Cost Recovery Program with the Florida PSC. On September 5,2007, the Florida PSC issued its audit report in which less than $8,000, or one percent, of the 2006 expenditures were disallowed as non-conservation-related.  The results of the audit were incorporated into the calculation of the 2008 Energy Conservation Cost Recovery Factors, which were filed with the Florida PSC on September 13, 2007.  The Florida PSC will authorize new conservation factors in an early November agenda conference, which will then become effective on January 1, 2008.

In compliance with the Florida Administrative Code, the Florida division filed its 2007 Depreciation Study (“Study”) with the Florida PSC on May 17, 2007. This study provides the Florida PSC with the opportunity to review and address the lives, salvage values, reserves and resulting life depreciation rates since the last study performed in 2002. In its filing, the Florida division has requested that any changes to the depreciation rates be made effective January 1, 2008.  The Florida division has received numerous interrogatories concerning the Study, which was responded to on October 15, 2007.  While the Company cannot predict the outcome of the Florida PSC’s review at this time, the Company anticipates a final decision regarding the depreciation rates in early 2008.

On July 6, 2007, the Company and Peoples Gas Service (“PGS”), another local gas distribution company in Florida, filed a joint petition for Commission action on a territorial agreement for portions of Pasco County, a Master Territorial Agreement and a Gas Transportation Agreement filed as a special contract.  PGS operates a natural gas distribution system in Pasco County, but is unable to serve economically certain areas of the county.  The Company entered into negotiations with PGS that would allow the Company to serve these areas by connecting to PGS’ existing distribution system, extend its facilities into these specific territories and provide service to primarily residential and commercial consumers.  The negotiations concluded with the execution of a Pasco County Territorial Agreement that provides the Company with two distinct areas as its territory and a Gas Transportation Agreement that specifies the terms, conditions and rates for transportation service across the PGS distribution system.  The Company and PGS have also entered into a Master Territorial Agreement that contains terms and conditions which will govern all existing and potential territorial agreements.  The Florida PSC approved these agreements at its October 9, 2007 agenda conference.

On August 27, 2007, the Florida division filed with the Florida PSC its petition for approval of a natural gas transmission pipeline tariff for Peninsula Pipeline Company in order to establish operating rules and regulations for the Company.  The Florida PSC has asked the Company for additional time to complete its review of the petition.  The Company has agreed to this request and the Florida PSC is now expected to rule on the petition at its November 27, 2007 agenda conference.

Eastern Shore. The system expansion and other regulatory matters for Eastern Shore include the following:

System Expansion 2006 – 2008. On January 20, 2006, Eastern Shore filed an application for a Certificate of Public Convenience and Necessity for its 2006-2008 system expansion project (“the 2006 – 2008 Project”) with the FERC. The application requested authority to construct and operate approximately 55 miles of new pipeline facilities and two new metering and regulating station facilities to provide an additional 47,350 dekatherms per day (“dt/d”) of firm transportation service in accordance with the phased-in customer requests of 26,200 dt/d in 2006, 10,300 dt/d in 2007, and 10,850 dt/d in 2008, at a total estimated cost of approximately $33.6 million. On June 13, 2006, the FERC issued a certificate authorizing Eastern Shore to construct and operate the 2006 – 2008 Project as proposed. Eastern Shore has completed and placed in service the authorized Phase I facilities. The actual capital investment for Phase I was $25.5 million, compared to the $17.0 million original estimate included in the filing.

On July 24, 2007, Eastern Shore requested FERC authorization to commence construction of a portion (approximately 4 miles) of the Phase II facilities. Eastern Shore received the requested FERC authorization on August 11, 2007, and construction of those facilities is currently underway and is expected to begin providing transportation service beginning November 1, 2007. These additional facilities will provide for 8,300 dekatherms of additional firm capacity per day and annualized gross margin contribution of $1.2 million, instead of the amounts included in the original filing of 10,300 dekatherms of additional firm capacity per day and $1.5 million annualized gross margin contribution.  Eastern Shore will request authorization to construct additional facilities when the final facilities plan is determined.

Eastern Shore Energylink Expansion Project (“E3 Project”). Eastern Shore has proposed to develop, construct and operate approximately 75 miles of new pipeline facilities to transport natural gas from 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.

Chesapeake and Delmarva are parties to existing firm natural gas transportation service agreements with Eastern Shore, and each desires firm transportation services 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 that are necessary for Eastern Shore to provide, and for Chesapeake and Delmarva to utilize firm transportation services under the E3 Project.

Eastern Shore, Chesapeake and Delmarva also entered into Letter Agreements which provide that, in the event that the E3 Project is not certificated and placed in service, Chesapeake and Delmarva will each pay their proportionate share of certain pre-certification costs by means of a negotiated surcharge of up to $2 million, 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 an uncontested rate-related Settlement Agreement by and between Eastern Shore, Chesapeake and Delmarva (the “Settlement Agreement”). The Settlement Agreement provides Eastern Shore and all customers utilizing Eastern Shore’s system with benefits, including but not limited to the following: (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, which was uncontested. 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.

Eastern Shore submitted its Request for Pre-Filing to the FERC on April 23, 2007, and on May 15, 2007, the FERC notified Eastern Shore that its request had been approved. The pre-filing process is 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.

Eastern Shore remains actively involved in the FERC’s pre-filing process. Eastern Shore has made progress in continuing to perform environmental, engineering and cultural surveys and studies in the interest of protecting the environment, minimizing any potential impacts to landowners, and cultural resources. To further advance the project, Eastern Shore has 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 is currently exploring the following as part of its overall project development plan: exploring all potential construction methods, construction cost mitigation strategies, additional market requests, potential design changes and project schedule changes.   Eastern Shore is currently in discussions and meetings with several potential new customers who have expressed an interest in the project that would expand its size and likely have significant impact on the cost, timeline and in-service date.  The viability of the E3 project depends upon satisfactory resolution of the foregoing matters, as well as a number of external factors, which cannot be predicted at this time.

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Rate Matters. On October 31, 2006 Eastern Shore filed a base rate proceeding with the FERC in compliance with the settlement approved in its prior base rate proceeding. Eastern Shore’s filed rates, proposed to be effective November 1, 2006, reflected an annual increase of $5,589,000 in its annual operating revenues based on increases in operating and maintenance expenses, depreciation expense, taxes other than income taxes, and return on existing gas plant facilities and new facilities placed into service by March 31, 2007.

On November 30, 2006 the FERC issued an order suspending the effectiveness of Eastern Shore’s proposed rate increase until May 1, 2007, subject to refund and the outcome of the hearing established in the order. On December 19, 2006, the Presiding Administrative Law Judge (“ALJ”) approved a procedural schedule to govern further proceedings in this case.

Settlement conferences were held on April 17, May 30, and June 6, 2007 at the FERC’s offices in Washington, D.C. On May 14, 2007, Eastern Shore filed a motion, which the FERC granted, to make its suspended rate increase effective on May 15, 2007, subject to refund, pending the ultimate resolution of the rate case. At the June 6, 2007 conference, the parties reached a settlement agreement in principle, and on June 8, 2007, the Chief ALJ suspended the procedural schedule to allow time for the parties to draft a formal Stipulation and Agreement. The negotiated settlement provides for an overall cost of service of $21,536,000, which reflects a pretax return on equity 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 Commission for the ALJ’s review and certification to the full Commission. There were no comments filed objecting to, or in protest of, the Settlement Offer.

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 is expected in the fourth quarter of 2007.

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 gas manufacturing plant site located in Cambridge, Maryland. The following provides details of 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 September 30, 2007, the Company has incurred approximately $9.67 million in costs related to environmental testing and remedial action studies at the site. Approximately $9.96 million has been recovered through September 2007 from other parties or through rates. As of September 30, 2007, a regulatory liability of approximately $294,500, 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 September 30, 2007, 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 $1.86 million has been recovered through insurance proceeds or in rates. On September 26, 2006, the Company received approval from the Maryland Public Service Commission to recover, through its rates charged to customers, the remaining $1.04 million of the incurred environmental remediation 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 an AS/SVE Pilot Study Work Plan (the “Work Plan”) for the Winter Haven Coal Gas site with the FDEP. After discussions with the FDEP, the Company filed a modified Work Plan, which contained a description of the scope of work to complete the site assessment activities and a report describing a limited sediment investigation performed in 1997. In December 1998, the FDEP approved the modified Work Plan, which the Company completed during the third quarter of 1999. In February 2001, the Company filed a Remedial Action Plan (“RAP”) with the FDEP to address the contamination of the subsurface soil and ground-water in a portion of the site. The FDEP approved the RAP on May 4, 2001. Construction of the AS/SVE system was completed in the fourth quarter of 2002, and the system remains fully operational.

Through September 30, 2007, the Company has incurred approximately $1.8 million of environmental costs associated with this site.  At September 30, 2007, the Company had accrued a liability of $865,000 related to this site, offsetting (a.) $3,000 collected through rates in excess of costs incurred and (b.) a regulatory asset of approximately $868,000, 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.

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Other

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

Other Commitments and Contingencies

Natural Gas and Propane Supply

The Company’s natural gas and propane distribution operations have entered into contractual commitments to purchase gas from various suppliers. The contracts have various expiration dates. In April 2007, 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, 2008.

Corporate Guarantees

The Company has issued corporate guarantees to certain vendors of its propane wholesale marketing subsidiary and its Florida natural gas supply and management subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the subsidiaries’ default. The liabilities for these purchases are recorded in the Consolidated Financial Statements. The aggregate amount guaranteed at September 30, 2007 totaled $20.7 million, with the guarantees expiring on various dates in 2007 and 2008.

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, 2008. The letter of credit is provided as security to satisfy the deductibles under the Company’s various insurance policies.  There have been no draws on this letter of credit as of September 30, 2007.

Application of Statement of Financial Accounting Standard (“SFAS”) No. 71

Certain assets and liabilities of the Company are accounted for in accordance with SFAS No. 71 -“Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 provides guidance for public utilities and other regulated operations where the rates (prices) charged to customers are subject to regulatory review and approval. Regulators sometimes include allowable costs in a period other than the period in which the costs would be charged to expense by an unregulated enterprise. That procedure can create assets, reduce assets, or create liabilities for the regulated enterprise. For financial reporting, an incurred cost for which a 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 September 30, 2007 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 and other matters. 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

In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation (“FIN”) No. 48, “Employers’ Accounting for Uncertainty in Income Taxes.” This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition and classification of uncertain tax positions, reporting of interest and penalties, accounting in interim periods, disclosure, and transition.  FIN 48 is effective for fiscal years beginning after December 15, 2006 and Chesapeake’s adoption of it in the first quarter of 2007 did not have any impact on the Company’s Consolidated Financial Statements through September 30, 2007.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This statement defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting pronouncements that require or permit fair value measurements, the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, this statement does not require any new fair value measurements. Since SFAS No. 157 is effective for financial statements issued within fiscal years beginning after November 15, 2007, Chesapeake will be required to adopt this statement in the first quarter of 2008 and has not yet evaluated the impact, if any, that its adoption may have on the Company’s 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.” SFAS No. 159 permits entities to measure at fair value many financial instruments and certain other items that are not currently required to be measured at fair value, with unrealized gains and losses related to these financial instruments reported in earnings at each subsequent reporting date. This Statement is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007 and the Company has not yet evaluated the impact, if any, that election of the valuation method permitted by this statement would have on its Consolidated Financial Statements.

In April 2007, the FASB directed the FASB Staff to issue 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. FSP FIN 39-1 is effective for fiscal years beginning after November 15, 2007, with early adoption permitted. The Company is evaluating the effect, if any, that adoption of FSP FIN 39-1 would have on its Consolidated Financial Statements.

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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.

	Three Months Ended						Nine Months Ended
For the Periods Ended September 30,	2007			2006			2007			2006
Operating Revenues, Unaffiliated Customers
Natural gas	$	29,542,423		$	25,949,068		$	134,261,695		$	126,855,571
Propane		7,923,129			5,850,616			42,339,698			34,338,931
Advanced information services		3,953,166			3,341,847			10,846,136			9,200,427
Other		-			-			(1	)		1
Total operating revenues, unaffiliated customers	$	41,418,718		$	35,141,531		$	187,447,528		$	170,394,930
Intersegment Revenues (1)
Natural gas	$	96,528		$	66,213		$	252,677		$	183,931
Propane		-			-			406			-
Advanced information services		121,613			12,475			349,840			33,988
Other		156,513			154,623			465,759			463,868
Total intersegment revenues	$	374,654		$	233,311		$	1,068,682		$	681,787
Operating Income (Loss)
Natural gas	$	2,118,594		$	1,760,552		$	15,726,858		$	13,256,385
Propane		(1,445,093	)		(1,826,353	)		2,882,565			1,165,748
Advanced information services		238,876			321,528			466,404			509,898
Other and eliminations		73,257			66,945			221,444			229,285
Total operating income	$	985,634		$	322,672		$	19,297,271		$	15,161,316
Other Income		(13,481	)	$	(12,096	)	$	277,194		$	130,197
Interest Charges		1,695,597		$	1,339,950		$	4,889,548		$	4,333,862
Income Taxes (Benefit)		(363,474	)	$	(467,859	)	$	5,545,725		$	4,174,361
Net income (loss) from continuing operations	$	(359,970	)	$	(561,515	)	$	9,139,192		$	6,783,290
(1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.
	September 30,			December 31,
	2007			2006
Identifiable Assets
Natural gas	$	256,834,255		$	252,292,600
Propane		80,346,963			60,170,200
Advanced information services		3,137,961			2,573,810
Other		12,168,561			10,503,804
Total identifiable assets	$	352,487,740		$	325,540,414

The Company’s operations are primarily domestic. The advanced information services segment, headquartered in Norcross, Georgia, provides domestic and international clients with information technology-related business services and solutions. Transactions with foreign companies are denominated and paid in U.S. dollars and are immaterial to the consolidated revenues.

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				Other Post-Retirement
	Pension Plan						Retirement Benefit Plan				Benefits
For the Three Months Ended September 30,	2007			2006			2007		2006		2007		2006
Service Cost	$	0		$	0		$	0	$	0	$	2,528	$	1,564
Interest Cost		155,514			161,212			30,840		29,897		23,234		19,468
Expected return on plan assets		(174,100	)		(174,191	)		-		-		-		-
Amortization of transition amount		-			-			-		-		-		6,964
Amortization of prior service cost		(1,174	)		(1,174	)		-		-		-		-
Amortization of net loss		-			-			12,934		14,259		41,640		22,074
Net periodic (benefit) cost	$	(19,760	)	$	(14,153	)	$	43,774	$	44,156	$	67,402	$	50,070
	Defined Benefit						Executive Excess				Other Post-Retirement
	Pension Plan						Retirement Benefit Plan				Benefits
For the Nine Months Ended September 30,	2007			2006			2007		2006		2007		2006
Service Cost	$	0		$	0		$	0	$	0	$	7,585	$	4,693
Interest Cost		466,543			474,664			92,521		89,691		69,701		58,404
Expected return on plan assets		(522,299	)		(516,343	)		-		-		-		-
Amortization of transition amount		-			-			-		-		-		20,894
Amortization of prior service cost		(3,524	)		(3,524	)		-		-		-		-
Amortization of net loss		-			-			38,801		42,779		124,920		66,221
Net periodic (benefit) cost	$	(59,280	)	$	(45,203	)	$	131,322	$	132,470	$	202,206	$	150,212

As disclosed in the December 31, 2006 financial statements, no contributions are expected to be required in 2007 for the defined benefit pension plan. The cost of the executive excess defined benefit pension 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 defined benefit pension plan for the three months and nine months ended September 30, 2007 were $22,000 and $66,000, respectively; for the year 2007, such benefits paid are expected to be $89,000. Cash benefits paid for other post-retirement benefits, primarily for medical claims, for the three months and nine months ended September 30, 2007 totaled $24,000 and $185,000, respectively.  The other-post retirement benefits incurred to date have exceeded the Company’s annual actuarial estimate of $180,000 for benefits to be paid as a result of experiencing higher than expected medical claims during the second quarter.

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8.   Investments

The investment balance at September 30, 2007 represents a Rabbi Trust (“the 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 of classifying them as trading securities, 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 September 30, 2007, total investments had a fair value of $2.0 million.

9.   Share-Based Compensation

The Company accounts for its share-based compensation arrangements under the revised SFAS No. 123, “Share Based Payments” (“SFAS 123R”), which requires the recognition of compensation cost over the respective service period for employee services 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, after tax, related to share-based compensation expense, in respect of restricted stock awards issued under the DSCP and the PIP.

	Three Months Ended				Nine Months Ended
For the periods ended September 30,	2007		2006		2007		2006
Directors Stock Compensation Plan	$	28,000	$	26,900	$	82,400	$	52,000
Performance Incentive Plan		161,900		146,000		415,800		363,300
Amounts included in net income, after tax	$	189,900	$	172,900	$	498,200	$	415,300

Stock Options

The Company did not have any stock options outstanding at September 30, 2007 or December 31, 2006, nor were any stock options issued during the nine months ended September 30, 2007 and September 30, 2006.  Stock options cannot be issued pursuant to the terms of the DSCP and PIP.

Directors Stock Compensation Plan

Under the DSCP, each non-employee director of the Company received in 2007 an annual retainer of 600 shares of common stock and an additional 150 shares of common stock for services as a committee chairman. Shares issued under the DSCP are fully vested as of the date of the grant.  The Company records a prepaid expense as of the date of the grant equal to the fair value of the shares issued and amortizes the expense equally over the service period of one year.

Compensation expense related to DSCP awards recorded by the Company for the three months and nine months ended September 30, 2007 and 2006 is presented in the following table:

	Three Months Ended				Nine Months Ended
For the periods ended September 30,	2007		2006		2007		2006
Compensation expense for DSCP	$	45,900	$	44,100	$	135,000	$	121,300

A summary of restricted stock activity under the DSCP as of September 30, 2007, and changes during the nine months then ended, is presented below:

	Number of Restricted Shares		Weighted Average Grant Date Fair Value
Outstanding — December 31, 2006		-
Issued — May 2, 2007		5,850	$	31.38
Vested		5,850
Outstanding — September 30, 2007		-

Performance Incentive Plan (“PIP”)

The Company’s Compensation Committee of the Board of Directors is authorized to grant key employees of the Company the right to receive awards of shares of the Company’s common stock, contingent upon the achievement of established performance goals. These awards are subject to certain post-vesting transfer restrictions. The Company issued 10,124 and 23,666 restricted stock awards during the three months of March 2007 and 2006, respectively, to key employees under the Company’s PIP. The shares granted under the PIP are fully vested, and the fair value of each share is equal to the market price of the Company’s common stock on the date of grant. The fair value of these restricted stock awards, based on the fair value of the Company’s stock on the issue date, was $30.89 and $30.40, for the shares issued in March 2007 and 2006, respectively.

Compensation expense related to the PIP recorded by the Company for the three months and nine months ended September 30, 2007 and 2006 is presented in the following table:

	Three Months Ended				Nine Months Ended
For the periods ended September 30,	2007		2006		2007		2006
Compensation expense for PIP	$	265,400	$	239,400	$	681,700	$	595,600

A summary of restricted stock activity under the PIP as of September 30, 2007, and changes during the nine months then ended, is presented below:

	Number of Restricted Shares		Weighted Average Grant Date Fair Value
Outstanding — December 31, 2006		-
Issued — March 1, 2007		10,124	$	30.89
Vested		10,124
Outstanding — September 30, 2007		-

- 13 -

10.   Stockholders’ Equity

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

	For the Nine Months Ended September 30, 2007		For the Twelve Months Ended December 31, 2006
Common Stock shares issued and outstanding (1)
Shares issued — beginning of period balance		6,688,084		5,883,099
Dividend Reinvestment Plan (2)		27,415		38,392
Retirement Savings Plan		22,915		29,705
Conversion of debentures		6,990		16,677
Employee award plan		350		350
Performance shares and options exercised (3)		15,974		29,516
Public offering		-		690,345
Shares issued — end of period balance (4)		6,761,728		6,688,084
Treasury shares — beginning of period balance		-		(97	)
Other issuances		-		97
Treasury Shares — end of period balance		-		-
Total Shares Outstanding		6,761,728		6,688,084
(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 DSCP.
(4) Includes 56,804 and 48,187 shares at September 30, 2007 and December 31, 2006, respectively, held in a Rabbi Trust established by the Company
relating to the Deferred Compensation Plan.

11.   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 has 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.

12.   Reclassifications

The Company reclassified some previously reported amounts to conform to current period classifications.

·   Share-based compensation was recorded as a liability to Accrued Compensation at December 31, 2006. Accordingly, the Company reclassified the $123,000 remaining in the liability account, after the issuance of the 2006 performance shares, to Additional Paid in Capital. This reclassification is considered immaterial to the overall presentation of the Company’s Consolidated Financial Statements.

·   Pension assets were netted against the liabilities for the executive excess defined benefit pension plan and the other post-retirement benefit plan at December 31, 2006.  Accordingly, the Company reclassified the pension assets of $630,000 at June 30, 2007 to the asset side of the balance sheet.  For comparison, the balance of $591,000 at December 31, 2006 has also been reclassed to the asset side of the balance sheet.  This reclassification is considered immaterial to the overall presentation of the Company’s Consolidated Financial Statements.

- 14 -

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 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, 2006, 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;

·   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 regulatory 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;

·   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 its estimated costs;

·   the Company’s ability to obtain the rate relief and cost recovery requested from utility 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;

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

·   inability to access the financial markets 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 earnings 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 through 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 September 30, 2007

The following discussions on operating income and segment results for the three months ended September 30, 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.

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Consolidated Overview

The Company’s seasonal net loss for the quarter ended September 30, 2007 decreased $301,000, or 46 percent, compared to the same period in 2006. The Company experienced a net loss of approximately $356,000, or $0.05 per share (diluted) during the quarter compared to a net loss of approximately $657,000, or $0.11 per share (diluted) in 2006. The Company’s Delmarva natural gas distribution and propane distribution operations typically experience seasonal losses during the third quarter, because heating customers do not require gas in the summer months.

For the Three Months Ended September 30,	2007			2006			Change
Net Income (Loss)
Continuing operations	$	(359,970	)	$	(561,515	)	$	201,545
Discontinued operations		4,072			(95,064	)		99,136
Total Net Loss	$	(355,898	)	$	(656,579	)	$	300,681
Diluted Earnings Per Share
Continuing operations	$	(0.05	)	$	(0.09	)	$	0.04
Discontinued operations		-			(0.02	)		0.02
Total Loss Per Share	$	(0.05	)	$	(0.11	)	$	0.06

The period-over-period decrease in quarterly losses reflects an increase in the operating income from the Company’s natural gas segment and a decreased operating loss from the propane segment, partially offset by a decrease in operating income from the advanced information services segment.

For the Three Months Ended September 30,	2007			2006			Change
Operating Income (Loss)
Natural Gas	$	2,118,594		$	1,760,552		$	358,042
Propane		(1,445,093	)		(1,826,353	)		381,260
Advanced Information Services		238,876			321,528			(82,652	)
Other & Eliminations		73,257			66,945			6,312
Operating Income		985,634			322,672			662,962
Other Income		(13,481	)		(12,096	)		(1,385	)
Interest Charges		1,695,597			1,339,950			355,647
Income Taxes		(363,474	)		(467,859	)		104,385
Net Loss from Continuing Operations	$	(359,970	)	$	(561,515	)	$	201,545

The period-over-period increase in quarterly operating income resulted primarily from the Company’s continued growth and increased per unit margins from our natural gas and propane segments. The Company estimates that the growth and per unit margins increases contributed $1.2 million and $435,000, respectively, to gross margin during the third quarter of 2007.

Natural Gas

The natural gas segment earned operating income of approximately $2.1 million for the third quarter ended September 30, 2007 compared to $1.8 million for the corresponding period in 2006, an increase of approximately $358,000, or 20 percent.

For the Three Months Ended September 30,	2007		2006		Change
Revenue	$	29,638,951	$	26,015,281	$	3,623,670
Cost of sales		18,266,820		15,982,581		2,284,239
Gross margin		11,372,131		10,032,700		1,339,431
Operations & maintenance		6,585,289		5,800,783		784,506
Depreciation & amortization		1,600,909		1,562,522		38,387
Other taxes		1,067,339		908,843		158,496
Other operating expenses		9,253,537		8,272,148		981,389
Total Operating Income	$	2,118,594	$	1,760,552	$	358,042
Statistical Data — Delmarva Peninsula
Heating degree-days ("HDD"):
Actual		25		45		(20	)
10-year average (normal)		59		60		(1	)
Estimated gross margin per HDD	$	2,283	$	2,234	$	49
Per residential customer added:
Estimated gross margin	$	372	$	372	$	0
Estimated other operating expenses	$	106	$	111	$	(5	)
Residential Customer Information
Average number of customers:
Delmarva		42,742		40,086		2,656
Florida		13,127		12,695		432
Total		55,869		52,781		3,088

- 16 -

Natural Gas Transmission

The natural gas transmission operation achieved gross margin growth of $951,000, or 24 percent. This increase was primarily attributed to new transportation capacity contracts implemented in November 2006 and the implementation of temporary rates, subject to refund, based on the status of the Company’s rate proceeding discussed previously in the “Rates and Regulatory Matters” section of Note 4. In total for 2007, these new transportation capacity contracts are expected to generate a gross margin of $3.3 million above the 2006 gross margin. An increase of $501,000 in other operating expenses partially offset the increased gross margin. The factors contributing to the increase in other operating expenses are as follows:

·   Payroll and benefit costs increased by $100,000 and $29,000, respectively, to comply with new federal pipeline integrity regulations and to serve the additional growth experienced by the operation.

·   The Company incurred an additional $262,000 of third-party costs in the third quarter of 2007 compared to the same period in 2006 to comply with new federal pipeline integrity regulations issued in May 2004.  The new regulations require natural gas transmission pipeline companies to assess the integrity of at least 50 percent of their covered pipeline segments by December 17, 2007.

·   The increased level of investment in plant caused property taxes to increase by $62,000.

·   Other operating expenses relating to various items increased collectively by approximately $48,000.

Natural Gas Distribution

The Delmarva natural gas distribution operations experienced an increase of $420,000, or 13 percent, in gross margin. The significant factors contributing to the increase in gross margin include:

·   Continued residential customer growth contributed to the increase in gross margin. The average number of residential customers on the Delmarva Peninsula increased by 2,656, or seven percent, for the third quarter 2007 compared to the same period in 2006, and the Company estimates that these additional residential customers contributed approximately $149,000 to gross margin.

·   In October 2006, the Maryland PSC granted the Company a base rate increase, which resulted in a $120,000 period-over-period increase to gross margin in the third quarter of 2007.

·   The remaining $151,000 increase in gross margin can be attributed to various factors, including increases in the number of commercial and industrial customers.

Gross margin for the Florida natural gas distribution operation increased by $67,000, or 3 percent, in the third quarter of 2007 compared to the third quarter of 2006. The gross margin increase from a three percent growth in residential customers and commercial customers, respectively, was offset by lower volumes sold to industrial customers.

- 17 -

Other operating expense for the natural gas distribution operations increased by $425,000 in the third quarter of 2007 compared to the third quarter of 2006. Among the key components of the increase were the following:

·   Payroll costs increased by $45,000 to serve the additional growth experienced by the operations.

·   Health care costs increased by $26,000 during the third quarter of 2007 compared to the third quarter of 2006 as the Company experienced higher cost of health care claims during this period.

·   Depreciation and amortization expense, asset removal cost and property taxes increased by $86,000, $52,000 and $65,000, respectively, as a result of the Company’s continued capital investments.

·   The Florida distribution operation experienced an increase of $66,000 during the third quarter of 2007 compared with the same period in 2006 for compliance with the federal pipeline integrity maintenance regulations.

·   The Florida distribution operation experienced an increase of $67,000 in advertising costs during the third quarter of 2007 compared with the same period in 2006 to promote energy conservation.

·   In addition, other operating expenses relating to various minor items increased by approximately $18,000.

Natural Gas Marketing

Gross margin for the natural gas marketing operation decreased by $65,000, or 21 percent, for the third quarter of 2007 compared to the same period in 2006. The decline in gross margin was primarily the result of a shift in the market that prevented the Company from selling as much of its available capacity in the third quarter of 2007 as was sold during the same period in 2006.  Other operating expenses increased by $56,000 for the marketing operation due to increased payroll and benefit costs, partially offset by a decrease in the allowance for uncollectible accounts.

Propane

The propane segment experienced a seasonal operating loss of $1.4 million, representing an improvement of $381,000, or 21 percent, for the third quarter of 2007 when compared to an operating loss of $1.8 million for the same period in 2006. Gross margin increased by $656,000, which was partially offset by an increase in other operating expenses of $275,000.

For the Three Months Ended September 30,	2007			2006			Change
Revenue	$	7,923,129		$	5,850,616		$	2,072,513
Cost of sales		5,383,480			3,967,428			1,416,052
Gross margin		2,539,649			1,883,188			656,461
Operations & maintenance		3,330,952			3,123,666			207,286
Depreciation & amortization		468,698			415,982			52,716
Other taxes		185,092			169,893			15,199
Other operating expenses		3,984,742			3,709,541			275,201
Total Operating Loss	$	(1,445,093	)	$	(1,826,353	)	$	381,260
Statistical Data — Delmarva Peninsula
Heating degree-days ("HDD"):
Actual		25			45			(20	)
10-year average (normal)		59			60			(1	)
Estimated gross margin per HDD	$	1,974		$	1,743		$	231

- 18 -

Delmarva Propane Distribution

The Delmarva propane distribution operation’s increase in gross margin of $497,000 resulted from the following:

·   Gross margin increased by $222,000 in the third quarter of 2007 compared to the same period in 2006 because of a $0.12 increase in the average gross margin per retail gallon. This increase is attained when market prices of propane are greater than the Company’s average inventory price per gallon. This trend reverses, as it did in the second quarter of 2007, when market prices decrease and move closer to the Company’s inventory price per gallon.  Propane gross margin is also impacted by changes in the Company’s pricing of sales to its customers.

·   Volumes sold in the third quarter of 2007 increased by 164,000 gallons, or 8 percent.  This increase in gallons sold contributed approximately $121,000 to gross margin for the Delmarva propane distribution operation compared to the third quarter of 2006.  Continued customer growth for the Delmarva Community Gas Systems (“CGS”) contributed to the increase in gallons sold.  The average number of CGS customers increased by 1,055 to a total count of 4,998, or a 27 percent increase, compared to the third quarter 2006. The Company expects the growth of its CGS operation to continue, as the number of systems currently under construction or under contract is anticipated to provide an additional 8,080 CGS customers once the systems are built out.

·   The remaining $154,000 increase in gross margin can be attributed to various factors, including service sales and wholesale sales.

Total other operating expenses increased by $188,000 for the Delmarva propane distribution operations in the quarter ended September 30, 2007 compared to the same period in 2006. The significant items contributing to this increase are explained below.

·   Incentive compensation increased $58,000 during the third quarter of 2007 compared to the third quarter of 2006 as a result of the improved earnings.

·   Health care costs increased by $35,000 during the third quarter of 2007 compared to the third quarter of 2006 as the Company experienced increased health care claims during the period.

·   The operation incurred an additional expense of $44,000 in the third quarter of 2007 compared to 2006 for propane tank recertifications and maintenance to comply with Department of Transportation standards.

·   Depreciation and amortization expense increased by $29,000 as a result of the Company’s continued capital investments.

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

Florida Propane Distribution

The Florida propane distribution operation experienced an increase in gross margin of $30,000, or 15 percent, in the third quarter of 2007 compared to the same period in 2006. This increase reflects a 33 percent increase in gallons sold to residential customers, primarily caused by an 11 percent increase in the number of residential customers, partially offset by a decrease in the average gross margin per retail gallon. Other operating expenses in the third quarter of 2007 compared to the third quarter of 2006 increased by $41,000 primarily due to an increase in payroll costs and higher depreciation expense.

Propane Wholesale and Marketing

Gross margin for the Company’s propane wholesale marketing operation increased by $130,000, or 32 percent, in the third quarter of 2007 compared to the same period in 2006. This increase reflects the larger number of market opportunities that arose in the third quarter of 2007 due to price volatility in the propane wholesale market. The increase in gross margin was partially offset by higher other operating expenses of $47,000, primarily due to higher incentive compensation based on the increased earnings in 2007.

Advanced Information Services

The advanced information services segment provides domestic and international clients with information-technology-related business services and solutions for both enterprise and e-business applications. The advanced information services business experienced gross margin growth of approximately $352,000, or 23 percent, however, operating income decreased by approximately $83,000 for the three months ended September 30, 2007 when compared to the same period in 2006.  Increases in revenue and gross margin were completely offset by increases in other operating expenses, which resulted in the decreased operating income.

For the Three Months Ended September 30,	2007		2006		Change
Revenue	$	4,074,779	$	3,354,322	$	720,457
Cost of sales		2,176,602		1,808,549		368,053
Gross margin		1,898,177		1,545,773		352,404
Operations & maintenance		1,472,527		1,081,606		390,921
Depreciation & amortization		36,544		25,325		11,219
Other taxes		150,230		117,314		32,916
Other operating expenses		1,659,301		1,224,245		435,056
Total Operating Income	$	238,876	$	321,528	$	(82,652	)

The increase of revenues in the three months ended September 30, 2007 is primarily attributable to:

·   An increase of $630,000 in consulting revenues as the number of billable hours increased by 18 percent; and

·   An increase of $64,000 from Managed Database Administration (“MDBA”) services, first offered in 2006, which provide clients with professional database monitoring and support solutions during business hours or around the clock.

Other operating expenses increased by $435,000 in the three months ended September 30, 2007 to $1.7 million, compared to $1.2 million for the same period in 2006. This increase in operating expenses is primarily due to an increase in costs incurred to support the segment’s growth, such as payroll and benefit costs, and an increase of $228,000 in the allowance for uncollectable accounts associated with a customer in the mortgage lending business that filed for bankruptcy in the third quarter of 2007.

Other Business Operations and Eliminations

Other operations and eliminating entries generated operating income of approximately $73,000 for the three months ended September 30, 2007 compared to approximately $67,000 for the same period in 2006. Other operations consist primarily of subsidiaries that own real estate leased to other Company subsidiaries.

For the Three Months Ended September 30,	2007		2006		Change
Revenue	$	156,513	$	154,623	$	1,890
Cost of sales		-		-		-
Gross margin		156,513		154,623		1,890
Operations & maintenance		28,239		32,711		(4,472	)
Depreciation & amortization		39,545		41,120		(1,575	)
Other taxes		16,242		14,617		1,625
Other operating expenses		84,026		88,448		(4,422	)
Operating Income - Other		72,487		66,175		6,312
Operating Income - Eliminations (1)		770		770		-
Total Operating Income	$	73,257	$	66,945	$	6,312

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

- 19 -

Interest Expense

Total interest expense for the three months ended September 30, 2007 increased approximately $356,000, or 27 percent, compared to the same period in 2006. The higher interest expense is a result of the following developments:

·   In the current quarter, the Company capitalized $267,000 less interest on debt associated with ongoing capital projects than in the corresponding quarter in 2006.

·   The Company’s average long-term debt balance during the three months ended September 30, 2007 was $77.6 million with a weighted average interest rate of 6.67 percent, compared to $62.3 million with a weighted average interest rate of 7.15 percent for the same period in 2006. The large period-over-period increase in the average long-term debt balance is the result of a debt placement of $20 million Senior Notes (“Notes”) at 5.5 percent in October 2006 with three institutional investors (The Prudential Insurance Company of America, Prudential Retirement Insurance and Annuity Company and United Omaha Life Insurance Company).

·   A decrease in the Company’s average short-term interest rate in the three months ended September 30, 2007 compared to 2006. The average interest rate for short-term borrowing decreased from 5.74 percent for the third quarter in 2006 to an average of 5.68 percent for the same period in 2007.

·   A decrease in the Company’s average short-term debt balance during the three months ended September 30, 2007 compared to the same period in 2006. The average short-term borrowing balance decreased $10.8 million in 2007 to $19.2 million compared to $30.0 million in 2006.

Income Taxes

The Company had an income tax benefit for the three months ended September 30, 2007 of $363,000 compared to an income tax benefit of $468,000 for the three months ended September 30, 2006. The effective tax rate for the third quarter of 2007 is 50.2 percent compared to an effective tax rate of 45.6 percent for the same period in 2006.  The seasonality of the Company’s business segments impacts the effective tax rate for interim reporting periods.

Results of Operations for the Nine Months Ended September 30, 2007

The following discussions of operating income and segment results for the nine months ended September 30, 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.

Consolidated Overview

The Company’s net income for the nine months ended September 30, 2007 increased $2.5 million, or 39 percent, compared to the same period in 2006. Net income was $9.1 million, or $1.34 per share (diluted), an increase of $0.24 per share, compared to $6.6 million, or $1.10 per share (diluted), for 2006.

For the Nine Months Ended September 30,	2007			2006			Change
Net Income (Loss)
Continuing operations	$	9,139,193		$	6,783,290		$	2,355,903
Discontinued operations		(22,212	)		(210,944	)		188,732
Total Net Income	$	9,116,981		$	6,572,346		$	2,544,635
Diluted Earnings (Loss) Per Share
Continuing operations	$	1.34		$	1.13		$	0.21
Discontinued operations		-			(0.03	)		0.03
Total Earnings Per Share	$	1.34		$	1.10		$	0.24

The period-over-period increase in earnings reflects an increase in operating income for the Company’s natural gas and propane operations as a result of continued growth and colder temperatures on the Delmarva Peninsula, which increased volumes sold to customers. The Company estimates that the growth and colder weather contributed $4.6 million and $1.8 million, respectively, to gross margin during the first nine months of 2007.

For the Nine Months Ended September 30,	2007		2006		Change
Operating Income
Natural Gas	$	15,726,858	$	13,256,385	$	2,470,473
Propane		2,882,565		1,165,748		1,716,817
Advanced Information Services		466,404		509,898		(43,494	)
Other & Eliminations		221,444		229,285		(7,841	)
Operating Income		19,297,271		15,161,316		4,135,955
		��
Other Income		277,194		130,197		146,997
Interest Charges		4,889,548		4,333,862		555,686
Income Taxes		5,545,725		4,174,361		1,371,364
Net Income from Continuing Operations	$	9,139,192	$	6,783,290	$	2,355,902
Diluted Earnings Per Share	$	1.34	$	1.13	$	0.21

- 20 -

The natural gas segment earned operating income of $15.7 million for the nine months ended September 30, 2007 compared to $13.2 million for the corresponding period in 2006, an increase of $2.5 million, or 19 percent.

For the Nine Months Ended September 30,	2007		2006		Change
Revenue	$	134,514,372	$	127,039,502	$	7,474,870
Cost of sales		91,166,528		89,149,159		2,017,369
Gross margin		43,347,844		37,890,343		5,457,501
Operations & maintenance		19,288,860		17,168,706		2,120,154
Depreciation & amortization		5,231,101		4,615,605		615,496
Other taxes		3,101,025		2,849,647		251,378
Other operating expenses		27,620,986		24,633,958		2,987,028
Total Operating Income	$	15,726,858	$	13,256,385	$	2,470,473
Statistical Data — Delmarva Peninsula
Heating degree-days ("HDD"):
Actual		2,991		2,502		489
10-year average (normal)		2,819		2,797		22
Estimated gross margin per HDD	$	2,283	$	2,234	$	49
Per residential customer added:
Estimated gross margin	$	372	$	372	$	0
Estimated other operating expenses	$	106	$	111	$	(5	)
Residential Customer Information
Average number of customers:
Delmarva		43,228		40,112		3,116
Florida		13,250		12,545		705
Total		56,478		52,657		3,821

Gross margin for the Company’s natural gas segment increased by $5.5 million, or 14 percent, and other operating expenses increased $3.0 million, or 12 percent, for the nine months ended September 30, 2007 compared to the same period in 2006. The gross margin increases of $2.9 million for the natural gas transmission operation, $2.7 million for the Delmarva natural gas distribution operations, and $200,000 for the Florida natural gas distribution operation were partially offset by a lower gross margin of $340,000 for the natural gas marketing operation, as further explained below.

Natural Gas Transmission

The natural gas transmission operation achieved gross margin growth of $2.9 million, or 23 percent. This increase was primarily attributed to new transportation capacity contracts implemented in November 2006 and the implementation of temporary rates, subject to refund, based on the status of the FERC rate proceeding discussed previously in the “Rates and Regulatory Matters” section of Note 4 “Commitments and Contingencies” to the unaudited Condensed Consolidated Financial Statements. In total for 2007, these new transportation capacity contracts are expected to generate a gross margin of $3.3 million above the 2006 gross margin. An increase of $1.8 million in other operating expenses partially offset the increased gross margin. The factors contributing to the increase in other operating expenses are as follows:

·   Payroll and benefit costs increased by $249,000 and $74,000, respectively, to comply with new federal pipeline integrity regulations and to serve the additional growth experienced by the operation.

·   The Company incurred an additional $312,000 of third-party costs in the nine months ended September 30, 2007 compared to the same period in 2006 to comply with federal pipeline integrity regulations.

·   Regulatory expenses increased by $108,000 in the first nine months of 2007 as the Company incurred costs associated with its rate filing with the FERC.

·   The increased level of capital investment caused higher depreciation and asset removal costs of $397,000 and increased property taxes of $114,000.

·   Corporate costs increased $224,000 as the Company incurred additional costs associated with the continued growth.

·   The increase in operating expenses for the first nine months of 2007 is magnified by the FERC’s approval, in July 2006, to defer pre-service costs of the Company’s E3 as a regulatory asset. The deferral of these costs resulted in the reduction of $190,000 in other operating expenses in 2006. Please refer to the “Rates and Regulatory Matters” section of Note 4 “Commitments and Contingencies” to the unaudited Condensed Consolidated Financial Statements for further information on this expansion project.

·   Other operating expenses relating to various items increased collectively by approximately $113,000.

Natural Gas Distribution

The Delmarva distribution operations experienced an increase of $2.7 million, or 18 percent, in gross margin. The significant items contributing to the increase in gross margin include the following:

·   The Company estimates that weather contributed $756,000 to gross margin in the nine months ended September 30, 2007 compared to the same period in 2006, as temperatures on the Delmarva Peninsula were 20 percent colder in 2007. The colder temperatures did not have a significant impact on the Maryland distribution operation’s gross margin in the first nine months of 2007, because the operation’s approved rate structure now includes a weather normalization adjustment (“WNA”) mechanism. The WNA mechanism was implemented in October 2006 and is designed to protect a portion of the Company’s revenues against warmer-than-normal weather, as deviations from normal weather can affect our financial performance. The WNA also serves to offset the impact of colder-than-normal weather by reducing the amounts the Company can charge its customers during such periods.

·   Continued residential customer growth also contributed to the increase in gross margin. The average number of residential customers on the Delmarva Peninsula increased by 3,116, or eight percent, for the nine months ended September 30, 2007 compared to the same period in 2006, and the Company estimates that these additional residential customers contributed approximately $900,000 to gross margin.

·   In October 2006, the Maryland PSC granted the Company a base rate increase, which resulted in a $615,000 period-over-period increase to gross margin in the first nine months of 2007.

·   Growth in commercial and industrial customers have contributed $75,000 and $79,000, respectively, to gross margin in the first nine months of 2007 compared to the same period in 2006.

·   The remaining $275,000 increase in gross margin can be attributed to various factors, including an increase in interruptible volumes sold and implementation of temporary rates by the Delaware division.

Gross margin for the Florida distribution operation increased by $199,000, or two percent, in the first nine months of 2007 compared to the same period in 2006. The higher gross margin for the period is primarily attributed to the increase in customers as the operation experienced a six percent growth in residential customers and a three percent growth in commercial customers.

Other operating expense for the natural gas distribution operations increased by $1.0 million in the first nine months of 2007 compared to the same period in 2006. Among the key components of the increase were the following:

·   Payroll costs increased by $107,000 to serve the additional growth experienced by the operation.

·   Health care costs increased by $139,000 as the Company experienced a higher cost of claims in the first nine months of 2007 compared to the same period in 2006.

·   Depreciation and amortization expense, asset removal cost and property taxes increased by $287,000, $150,000 and $117,000, respectively, as a result of the Company’s continued capital investments.

·   The Florida distribution operation experienced an increased expense of $66,000 during the first nine months of 2007 compared with the same period in 2006 to maintain compliance with the new federal pipeline integrity regulations.

·   The Florida distribution operation experienced an increase of $67,000 in advertising costs during the first nine months of 2007 compared with the same period in 2006 to promote energy conservation.

·   In addition, other operating expenses relating to various minor items increased by approximately $135,000.

·   Merchant payment fees decreased by $68,000, as the Company’s Delmarva operation outsourced the processing of credit card payments in April of 2007.

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Natural Gas Marketing

Gross margin for the natural gas marketing operation decreased by $340,000, or 21 percent, for the first nine months of 2007 compared to the same period in 2006. The decline in gross margin was primarily the result of increases in natural gas supply costs that the Company was contractually unable to pass through to its customers.  In addition, a shift in the market prevented the Company from selling as much of its available capacity in the first nine months of 2007 as was sold during the same period in 2006.  Other operating expenses increased by $181,000 for the marketing operation primarily due to increases in payroll and benefit costs, allowance for uncollectible accounts and corporate overhead costs.

Propane

The propane segment experienced an increase of $1.7 million, or 147 percent, in operating income for the nine months ended September 30, 2007 compared to the same period in 2006. Gross margin increased by $3.2 million, which was partially offset by an increase in other operating expenses of $1.5 million.

For the Nine Months Ended September 30,	2007		2006		Change
Revenue	$	42,340,104	$	34,338,931	$	8,001,173
Cost of sales		26,646,852		21,845,239		4,801,613
Gross margin		15,693,252		12,493,692		3,199,560
Operations & maintenance		10,790,941		9,488,865		1,302,076
Depreciation & amortization		1,373,066		1,235,366		137,700
Other taxes		646,680		603,713		42,967
Other operating expenses		12,810,687		11,327,944		1,482,743
Total Operating Income	$	2,882,565	$	1,165,748	$	1,716,817
Statistical Data — Delmarva Peninsula
Heating degree-days ("HDD"):
Actual		2,991		2,502		489
10-year average (normal)		2,819		2,797		22
Estimated gross margin per HDD	$	1,974	$	1,743	$	231

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Operating income for the propane segment increased by $1.7 million to $2.9 million for the nine months ended September 30, 2007 compared to the same period in 2006. This increase was due primarily to colder weather on the Delmarva Peninsula in the first nine months of 2007, which resulted in increased consumption by customers. Gross margin in the Delmarva propane distribution operations increased, compared to the first nine months of 2006, by $2.6 million, primarily due to colder weather. Gross margin also increased in the Florida propane distribution operation and the Company’s wholesale propane marketing operation by $92,000 and $497,000, respectively.

Delmarva Propane Distribution

The Delmarva propane distribution operation’s increase in gross margin of $2.6 million resulted from the following:

·   Temperatures on the Delmarva Peninsula were 20 percent colder in the first nine months of 2007 compared the same period in 2006, which contributed to the increase of 1.4 million gallons, or 10 percent, sold during this period in 2007 compared to the same period in 2006. The Company estimates that the colder weather and increased volumes sold contributed $965,000 to gross margin for the Delmarva propane distribution operation compared to the first nine months of 2006.

·   Non-weather related volumes sold in the first nine months of 2007 increased by 1.0 million gallons, or 7 percent.  This increase in gallons sold contributed approximately $630,000 to gross margin for the Delmarva propane distribution operation compared to the first nine months of 2006.  Contributing to the increase of gallons sold is the continued customer growth for the Delmarva CGS.  The average number of CGS customers increased by 1,021 to a total count of 4,784, or a 27 percent increase, compared to the first nine months of 2006. The Company expects the growth of its CGS operation to continue as the number of systems currently under construction or under contract is anticipated to provide an additional 7,900 CGS customers, an increase of 169 percent.

·   Gross margin further increased by $876,000 in the first nine months of 2007, compared to the same period in 2006, because of a $0.06 increase in the average gross margin per retail gallon. This increase occurs when market prices of propane are greater than the Company’s average inventory price per gallon. This trend reverses when market prices decrease and move closer to the Company’s inventory price per gallon.  Propane gross margin is also impacted by changes in the Company’s pricing of sales to its customers.

·   The remaining $129,000 increase in gross margin can be attributed to various factors, including higher service sales and wholesale sales.

Total other operating expenses increased by $1.2 million for the Delmarva propane operations in the nine months ended September 30, 2007, compared to the same period in 2006. The significant items contributing to this increase are explained below:

·   The increase in operating expenses for the first nine months of 2007 is magnified by the Company’s one-time recovery of previously incurred costs of $387,000 from one of its propane suppliers. This recovery reimbursed the Company for fixed costs incurred in the removal of above-normal levels of petroleum by-products contained in approximately 75,000 gallons of propane that it purchased from the supplier. The recovery of these costs reduced other operating expenses in the first nine months of 2006.

·   Incentive compensation increased by $241,000 as a result of the improved operating results in 2007 compared to 2006.

·   Health care costs increased by $115,000 during the first nine months of 2007 compared to the same period in 2006 as the Company experienced a higher cost of claims during the period.

·   The operation incurred an additional $160,000 in 2007 for propane tank recertifications and maintenance to maintain compliance with Department of Transportation standards.

·   Depreciation and amortization expense increased by $89,000 as a result of the Company’s capital investments over the prior year.

·   In addition, other operating expenses relating to various items increased collectively by approximately $208,000.

Florida Propane Distribution

The Florida propane distribution operation experienced an increase in gross margin of $92,000, or 11 percent, in the first nine months 2007 compared to the same period in 2006, primarily because of an increase in the average gross margin per retail gallon.  Other operating expenses in the first nine months of 2007, compared to the same period in 2006, increased by $158,000, primarily due to increases in payroll costs, insurance and depreciation expense, which were partially offset by lower incentive compensation.

Propane Wholesale and Marketing

Gross margin for the Company’s propane wholesale marketing operation increased by $497,000, or 36 percent, in the first nine months of 2007 compared to the same period in 2006. This increase reflects the larger number of market opportunities that arose in the first nine months of 2007, due to price volatility in the propane wholesale market, which exceeded the level of price fluctuations experienced in the same period of 2006. The increase in gross margin was partially offset by higher other operating expenses of $141,000, due primarily to higher incentive compensation based on the increased earnings in 2007.

Advanced Information Services

The advanced information services business experienced gross margin growth of approximately $977,000, or 24 percent, and contributed operating income of $466,000 for the nine months ended September 30, 2007, a decrease of $43,000 compared to the same period in 2006.

For the Nine Months Ended September 30,	2007		2006		Change
Revenue	$	11,195,976	$	9,234,415	$	1,961,561
Cost of sales		6,177,712		5,193,574		984,138
Gross margin		5,018,264		4,040,841		977,423
Operations & maintenance		3,937,187		3,054,287		882,900
Depreciation & amortization		106,028		87,264		18,764
Other taxes		508,645		389,392		119,253
Other operating expenses		4,551,860		3,530,943		1,020,917
Total Operating Income	$	466,404	$	509,898	$	(43,494	)

The increase of revenues in the nine months ended September 30, 2007 resulted primarily from:

·   An increase of $1.5 million in consulting revenues as the number of billable hours increased by 17 percent; and

·   An increase of $213,000 from Managed Database Administration (“MDBA”) services, first offered in 2006, which provide clients with professional database monitoring and support solutions during business hours or around the clock.

Other operating expenses increased by $1.0 million to $4.6 million in the nine months ended September 30, 2007, compared to $3.5 million for the same period in 2006. This increase in operating expenses is due primarily to an increase in accrued incentive compensation based on improved operating results, allowance for uncollectible accounts, and other costs incurred to support the growth and improved earnings. The increase in the allowance for uncollectible accounts represents a $228,000 increase associated with a customer in the mortgage lending business that filed for bankruptcy in the third quarter of 2007.

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Other Business Operations and Eliminations

Other operations generated an operating income of approximately $221,000 for the nine months ended September 30, 2007 compared to an operating income of approximately $229,000 for the same period in 2006.

For the Nine Months Ended September 30,	2007		2006		Change
Revenue	$	465,758	$	463,869	$	1,889
Cost of sales		-		-		-
Gross margin		465,758		463,869		1,889
Operations & maintenance		79,714		69,245		10,469
Depreciation & amortization		120,358		122,604		(2,246	)
Other taxes		46,552		45,045		1,507
Other operating expenses		246,624		236,894		9,730
Operating Income - Other		219,134		226,975		(7,841	)
Operating Income - Eliminations (1)		2,310		2,310		-
Total Operating Income	$	221,444	$	229,285	$	(7,841	)

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

Interest Expense

Total interest expense for the first nine months of 2007 increased approximately $556,000, or 13 percent, compared to the same period in 2006. The higher interest expense is a result of the following developments:

·   In the first nine months of 2007, the Company capitalized $267,000 less interest on debt associated with ongoing capital projects than in the corresponding period in 2006.

·   The Company’s average long-term debt balance during the first nine months of 2007 was $77.7 million with a weighted average interest rate of 6.67 percent, compared to $62.7 million with a weighted average interest rate of 7.14 percent for the same period in 2006. The large year-over-year increase in the average long-term debt balance is the result of a debt placement of $20 million in Senior Notes (“Notes”) at 5.5 percent in October 2006 with three institutional investors (The Prudential Insurance Company of America, Prudential Retirement Insurance and Annuity Company and United Omaha Life Insurance Company).

·   An increase in the average short-term interest rates in the first nine months of 2007 compared to the same period in 2006. The Company’s average interest rate for short-term borrowing increased from 5.40 percent to 5.70 percent.

·   A decrease in the Company’s average short-term debt balance during the first nine months of 2007 compared to the same period in 2006. The average short-term borrowing balance decreased $10.7 million in 2007 to $17.0 million compared to an average balance $27.7 million in 2006.

Income Taxes

Income tax expense for the nine months ended September 30, 2007 was $5.5 million compared to $4.2 million for the nine months ended September 30, 2006. The increase in income tax expense primarily reflects higher earnings. The effective tax rate for the first nine months of 2007 is 37.8 percent compared to an effective tax rate of 38.1 percent for the same period in 2006.

Financial Position, Liquidity and Capital Resources

Chesapeake’s capital requirements reflect the capital-intensive nature of its business and are principally attributable to its investment in new plant and equipment and the retirement of outstanding debt. The Company relies on cash generated from operations, short-term borrowing, and other sources to meet normal working capital requirements and to finance capital expenditures. During the first nine months of 2007, net cash provided by operating activities was $19.7 million, cash used by investing activities was $22.8 million, and cash used by financing activities was $437,000.

By comparison, during the first nine months of 2006, net cash provided by operating activities was $19.2 million, cash used by investing activities was $28.5 million, and cash provided by financing activities was $9.2 million.

The Board of Directors has authorized the Company to borrow up to $55.0 million of short-term debt, as required, from various banks and trust companies under short-term lines of credit. As of September 30, 2007, Chesapeake had four unsecured bank lines of credit with two financial institutions, totaling $80.0 million. 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. The other two lines are subject to the availability of bank funds. The outstanding balance of short-term borrowing at September 30, 2007 and December 31, 2006 was $33.1 million and $27.6 million, respectively.

Chesapeake has budgeted $45.5 million for capital expenditures during 2007. This amount includes $20.2 million for natural gas distribution, $16.5 million for natural gas transmission, $7.5 million for propane distribution and wholesale marketing, $154,000 for advanced information services and $915,000 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 and the replacement of 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 2007 capital expenditure 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 acquisition opportunities, changing economic conditions, customer growth in existing areas, regulation, new growth opportunities and availability of capital.

Chesapeake expects to incur approximately $75,000 for environmental-related expenditures in 2007 and the same amount in 2008. Additional expenditures may be required in future years (see Note 4 to the Consolidated Financial Statements). Management does not expect financing of future environmental-related expenditures to have a material adverse effect on the financial position or capital resources of the Company.

Capital Structure

The following presents the Company’s capitalization as of September 30, 2007 and December 31, 2006:

	September 30, 2007				December 31, 2006
	(In thousands, except percentages)
Long-term debt, net of current maturities	$	69,911	37	%	$	71,050	39	%
Stockholders' equity	$	117,375	63	%	$	111,152	61	%
Total capitalization, excluding short-term debt	$	187,286	100	%	$	182,202	100	%

As of September 30, 2007, common equity represented 63 percent of total capitalization, compared to 61 percent at December 31, 2006. 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 51 percent at both September 30, 2007 and December 31, 2006. 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.

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Shelf Registration

In July 2006, the Company filed a registration statement on Form S-3 with the SEC to issue up to $40.0 million in new common stock and/or debt securities. The registration statement was declared effective by the SEC in November 2006. In the fourth quarter of 2006, the Company sold 600,300 shares of common stock, including the underwriter’s exercise of their over-allotment option of 90,045 shares, under this registration statement, generating net proceeds of $19.7 million.  At September 30, 2007, the Company had approximately $20.0 million remaining under this registration statement.

Cash Flows Provided By Operating Activities

Cash flows provided by operating activities were as follows:

For the Nine Months Ended September 30,	2007			2006		Change
Net Income	$	9,116,981		$	6,572,346	$	2,544,635
Non-cash adjustments to net income		11,166,638			6,620,933		4,545,705
Changes in working capital		(591,691	)		5,975,733		(6,567,424	)
Net cash provided by operating activties	$	19,691,928		$	19,169,012	$	522,916

Period-over-period changes in our cash flows from operating activities are attributable primarily to net income, depreciation, deferred income taxes, and working capital changes. The changes in working capital are impacted 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 nine months ended September 30, 2007, net cash flow provided by operating activities was $19.7 million, an increase of $523,000 compared to the same period of 2006. The increase was due primarily to higher net income and higher non-cash adjustments for depreciation and amortization expense and changes in deferred income taxes, partially offset by a reduction in working capital. The reduction in working capital was due primarily to the decrease in cash provided from accounts receivable, regulatory assets and income taxes, which was partially offset by a decrease in cash used by accounts payable for gas purchases payable. The changes in accounts receivable and accounts payable were impacted by the weather and the lower gas commodity costs.

Cash Flows Used in Investing Activities

Net cash flows used in investing activities totaled $22.8 million and $28.5 million during the nine months ended September 30, 2007 and 2006, respectively.

·   Cash utilized for capital expenditures was $22.9 million and $28.5 million for the first nine months of 2007 and 2006, respectively. Additions to property, plant and equipment in these quarters were primarily for natural gas transmission, natural gas distribution and propane distribution. In both 2007 and 2006, the natural gas distribution expenditures were used primarily to fund expansion and facilities improvements. In both periods, the natural gas transmission capital expenditures related primarily to expanding the Company’s transmission system.

·   The sale of property, plant, and equipment generated $205,000 of cash in the first nine months of 2007.

·   In the first nine months of 2007, the Company paid $166,000 more for environmental expenditures than was recovered through rates charged to customers compared to $10,000 for the same period in 2006.

Cash Flows Used in Financing Activities

Cash flows used by financing activities totaled $437,000 for the nine months ended September 30, 2007 compared to cash provided of $9.2 million for the nine months ended September 30, 2006. Significant financing activities included the following:

·   During the first nine months of 2007, the Company had net borrowings from short-term debt of $5.0 million compared to a net borrowing of $14.8 million in the first nine months of 2006.

·   During the first nine months of 2007, the Company paid $5.2 million in cash dividends compared with dividend payments of $4.5 million for the same time period in 2006. The increase in dividends paid over the prior year reflects an increase in the annualized dividend rate from $1.16 per share during the first quarter of 2006 to $1.18 per share in the second quarter of 2007 and the issuance of additional shares of common stock.

·   The Company repaid $1.0 million and $1.9 million of long-term debt during the first nine months of 2007 and 2006, 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 and management subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of a subsidiary’s default. Liabilities for these purchases are recorded in the Consolidated Financial Statements. The aggregate amount guaranteed at September 30, 2007 was $20.7 million, with the guarantees expiring on various dates in 2007 and 2008.

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, 2008. The letter of credit is provided as security to satisfy the deductibles for the Company’s various insurance policies.  There have been no draws on this letter of credit as of September 30, 2007.

Contractual Obligations

There have not been any material changes in the contractual obligations presented in the Company’s 2006 Annual Report on Form 10-K, except for commodity purchase obligations and forward contracts entered into in the ordinary course of the Company’s business. Below is a summary of the commodity and forward contract obligations at September 30, 2007.

	Payments Due by Period
Purchase Obligations	Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years		Total
Commodities (1)	$	1,297,586	$	657,551	$	0	$	0	$	1,955,137
Propane (2)		92,282,786		2,433,716		-		-		94,716,502
Total Purchase Obligations	$	93,580,372	$	3,091,267	$	0	$	0	$	96,671,639

⁽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 $92.3 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 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 the respective Public Service Commissions. Eastern Shore Natural Gas (“Eastern Shore”), the Company’s natural gas transmission operation, is subject to regulation by the FERC.  At September 30, 2007, 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 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. Lower levels of interruptible sales occur when oil prices are lower than the price of natural gas. Oil prices, as well as the prices of electricity and other fuels, 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 side of this business to maximize sales volumes. As a result of the transmission operation’s conversion to open access and the Florida gas distribution division’s restructuring of its services, their 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 transportation 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. As it relates to transportation services, the Company’s competitors include interstate transmission companies if the distribution customer is 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 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 it 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 than does the Company. In addition, changes in the advanced information services business are occurring rapidly, which could adversely impact the markets for the products and services offered by these businesses. This segment competes on the basis of technological expertise, 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. 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 while monitoring 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.

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 $77.6 million at September 30, 2007, as compared to a fair value of $80.1 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 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 September 30, 2007 and elected not to hedge any of its inventories.

The Company’s propane wholesale marketing operation is a party to natural gas liquids (“NGL”) forward contracts, primarily propane contracts, with various third parties. These contracts require that the propane wholesale marketing operation purchase or sell NGL at a fixed price at fixed future dates. At expiration, the contracts are settled by the delivery of NGL 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 NGL 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 on a daily basis. 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 September 30, 2007 is presented in the following table.

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At September 30, 2007	Quantity in gallons		Estimated Market Prices		Weighted Average Contract Prices
Forward Contracts
Sale		78,346,884	$	0.8850 — $1.3550	$	1.1784
Purchase		76,335,000	$	0.8700 — $1.3500	$	1.1881
Estimated market prices and weighted average contract prices are in dollars per gallon.  All contracts expire in 2007 or the first quarter 2008.

Item 4.                 Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Chief Executive Officer and Chief Financial Officer of the Company, with the participation of other Company officials, have evaluated the Company’s “disclosure controls and procedures” (as such term is defined under Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended) as of September 30, 2007. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2007.

Changes in Internal Control Over Financial Reporting

During the quarter ended September 30, 2007, 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 the MD&A hereof 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, 2006. 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 are not presently 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 (2)		Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs (2)
July 1, 2007 through July 31, 2007 (1)		471	$	35.35		0		0
August 1, 2007 through August 31, 2007		0	$	0.00		0		0
September 1, 2007 through September 30, 2007		0	$	0.00		0		0
Total		471	$	35.35		0		0
(1) Chesapeake purchased shares of stock on the open market for the purpose of reinvesting the dividend on deferred stock units held in the Rabbi Trust
accounts for certain Senior Executives. During the quarter, 471 shares were purchased through the reinvestment of dividends on deferred stock units.
(2) Except for the purpose described in Footnote (1), Chesapeake has no publicly announced plans or programs to repurchase its shares.

Item 3.                 Defaults upon Senior Securities

None

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

None

Item 5.                 Other Information

None

Item 6.                 Exhibits

The exhibits listed on the following Exhibit Index are filed as part of this Report. Exhibits required by Item 601 of Regulation S−K, but which are not listed below, are not applicable.

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 November 9, 2007
	31.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the
		Securities Exchange Act of 1934, dated November 9, 2007
	32.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated November 9, 2007
	32.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated November 9, 2007

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SIGNATURES

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

Chesapeake Utilities Corporation

/s/ Michael P. McMasters

Michael P. McMasters

Senior Vice President and Chief Financial Officer

Date: November 9, 2007

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