SEC Filing | Chesapeake Utilities Corporation

Compared to 2006, operating income in 2007 increased by $4.8 million, or 20 percent. Factors affecting this improvement included the following:

·	New transportation capacity contracts implemented for the natural gas transmission operation in November 2006 and November 2007 provided for $3.3 million of additional gross margin in 2007.

Weather on the Delmarva Peninsula was 15 percent colder in 2007 than 2006, which the Company estimates contributed approximately $2.0 million in additional gross margin for its Delmarva natural gas and propane distribution operations. This amount differs from the $2.2 million of additional gross margin that the Company had expected the colder weather to contribute. The variance occurred as a result of the season or month that the heating degree day variance occurred.

·	Rate increases to customers of the natural gas transmission and distribution operations in Delaware and Maryland added $1.4 million to gross margin in 2007.

·	Strong period-over-period residential customer growth of seven percent and five percent, respectively, for the Delmarva and Florida natural gas distribution operations in 2007.

·	The average gross margin per retail gallon sold to customers increased $0.05 in 2007 for the Delmarva propane distribution operations, which contributed $1.1 million to gross margins.

·	The Delmarva Community Gas Systems continued to experience strong customer growth as the number of customers increased 22 percent in 2007 compared to 2006.

Operating income in 2006 increased $1.4 million, or 6.5 percent, compared to 2005, despite significantly warmer weather in 2006. The improvement in 2006 results of operations compared to 2005 was affected by the following factors:

·	Weather on the Delmarva Peninsula was 18 percent warmer in 2006 than in 2005; as a result, the Company estimates that 2006 gross margin for its Delmarva natural gas and propane distribution operations was approximately $3.4 million less than in 2005.

·	Strong residential customer growth of nine percent and eight percent, respectively, for the Delmarva and Florida natural gas distribution operations in 2006.

·	The natural gas transmission operation achieved gross margin growth of $1.8 million, or 11 percent, due to additional capacity contracts that went into effect in November 2005 and November 2006.

·	A 67 percent increase in the number of customers for the Company’s natural gas marketing operation.

·	Gross margin for the Delmarva propane distribution operations decreased $834,000, primarily, as a result of the warmer weather in 2006.

·	The Delmarva Community Gas Systems continued to experience strong customer growth increasing by 34 percent in 2006 compared to 2005.

Operating income for the advanced information services segment decreased $430,000 in 2006. Although revenues from consulting increased $749,000 in 2006, the 2005 results contained $993,000 of operating income for the Lightweight Association Management Processing Systems (“LAMPSTM”) product, which was sold in the fourth quarter 2005. The LAMPSTM product was an internally developed software that was developed and marketed specifically for REALTOR® Associations.

Natural Gas

The natural gas segment earned operating income of $22.5 million for 2007, $19.7 million for 2006, and $17.2 million for 2005, resulting in increases of $2.8 million, or 13.9 percent for 2007, and $2.5 million, or 14.5 percent, for 2006.

Natural Gas (in thousands)
					Increase						Increase
For the Years Ended December 31,	2007		2006		(decrease)		2006		2005		(decrease)
Revenue	$	181,202	$	170,374	$	10,828	$	170,374	$	166,582	$	3,792
Cost of gas		121,550		117,948		3,602		117,948		116,178		1,770
Gross margin		59,652		52,426		7,226		52,426		50,404		2,022

Operations & maintenance		26,024		22,673		3,351		22,673		23,874		(1,201	)
Depreciation & amortization		6,918		6,312		606		6,312		5,682		630
Other taxes		4,225		3,708		517		3,708		3,612		96
Other operating expenses		37,167		32,693		4,474		32,693		33,168		(475	)
Total Operating Income	$	22,485	$	19,733	$	2,752	$	19,733	$	17,236	$	2,497

Heating Degree-Day (HDD) and Customer Analysis
					Increase							Increase
For the Years Ended December 31,	2007		2006		(decrease)			2006		2005		(decrease)
Heating degree-day data — Delmarva
Actual HDD		4,504		3,931		573			3,931		4,792		(861	)
10-year average HDD		4,376		4,372		4			4,372		4,436		(64	)

Estimated gross margin per HDD	$	1,937	$	2,013	$	(76	)	$	2,013	$	2,234	$	(221	)

Estimated dollars per residential customer added:
Gross margin	$	372	$	372	$	0		$	372	$	372	$	0
Other operating expenses	$	106	$	111	$	(5	)	$	111	$	106	$	5

Average number of residential customers
Delmarva		43,485		40,535		2,950			40,535		37,346		3,189
Florida		13,250		12,663		587			12,663		11,717		946
Total		56,735		53,198		3,537			53,198		49,063		4,135

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Gross margin for the Company’s natural gas segment increased by $7.2 million, or 14 percent, and other operating expenses increased $4.5 million, or 14 percent, for 2007 compared to 2006. The gross margin increases of $3.9 million for the natural gas transmission operation, $3.4 million for the Delmarva natural gas distribution operations, and $88,000 for the Florida natural gas distribution operation were partially offset by a lower gross margin of $207,000 for the natural gas marketing operation, as further explained below.

Natural Gas Transmission

The natural gas transmission operation achieved gross margin growth of $3.9 million, or 22 percent, in 2007 compared to 2006. Of the $3.9 million increase, $3.3 million was attributable to new transportation capacity contracts implemented in November 2006 and 2007. In 2008, the new transportation capacity contracts implemented in November 2007 are expected to generate an additional annual gross margin of $1.2 million above 2007 gross margins. In addition, the implementation of rate case settlement rates, effective September 1, 2007, contributed an additional $563,000 to gross margins in 2007. A further discussion of the FERC rate proceeding is provided in detail within the “Regulatory Activities” listed later in this section. The remaining $43,000 increase to gross margin in 2007 is attributable to other factors, such as higher interruptible sales. An increase of $2.3 million in other operating expenses partially offset the increased gross margin. The factors contributing to the increase in other operating expenses are as follow:

Payroll and benefit costs increased by $282,000 and $90,000, respectively, as the operation increased its staffing levels to comply with new federal pipeline integrity regulations and to serve the additional growth. The new pipeline integrity regulations require the Company to assess the integrity of each covered segment of its line pipe. These regulations require the assessment of at least 50 percent of the covered segments by December 17, 2007 and completion of the baseline assessment of all covered segments by December 17, 2012.

·	Eastern Shore also incurred an additional $385,000 of third-party costs in 2007 compared to 2006 to comply with the new federal pipeline integrity regulations previously discussed.

·	The increased level of capital investment caused higher depreciation and asset removal costs of $371,000 and increased property taxes of $188,000.

·	Corporate costs increased $568,000 as the Company updated its annual corporate cost allocations based on a methodology accepted by the FERC.

The increase in operating expenses for 2007 is magnified by the FERC’s authorization, in July 2006, to defer certain pre-service costs of Eastern Shore’s E3 Project, allowing the Company to treat such costs as a regulatory asset. The deferral of these costs resulted in the reduction of $190,000 in other operating expenses in 2006 for expenses incurred in 2005. Please refer to the “Regulatory Activities” discussion below for further information on the E3 Project.

·	Other operating expenses relating to various items increased collectively by approximately $226,000.

Natural Gas Distribution

The Delmarva distribution operations experienced an increase in gross margin of $3.4 million, or 16 percent. The significant items contributing to the increase in gross margin include the following:

Continued residential customer growth contributed to the increase in gross margin. The average number of residential customers on the Delmarva Peninsula increased by 2,950, or seven percent, for 2007 compared to 2006, and the Company estimates that these additional residential customers contributed approximately $1.2 million to gross margin. The Company does not expect to maintain the growth rate of residential customers, which it has experienced in the past few years. The Company has seen a slow-down in the new housing market in 2007 as a result of unfavorable market conditions in the housing industry, which include: (a) increased new and resale home inventory levels, (b) decreased homebuyer demand due to lower consumer confidence in the overall housing market, (c) increased uncertainty in the overall mortgage market, and (d) increased underwriting standards.

Rate increases for both the Delaware and Maryland divisions generated an additional $848,000 in gross margin in 2007 compared to 2006. In October 2006, the Maryland PSC granted the Company a base rate increase, which resulted in a $693,000 period-over-period increase to gross margin in 2007. The Delaware Division received approval from the Delaware PSC to implement temporary rates, subject to refund, which contributed an additional $155,000 to gross margin in 2007.

The Company estimates that weather contributed $819,000 to gross margin in 2007 compared to 2006, as temperatures on the Delmarva Peninsula were 15 percent colder in 2007. This amount differs from the $1.1 million of additional gross margin that the Company had expected the colder weather to contribute. This variance occurred as a result of the season or month that the heating degree day variance occurred.

The colder temperatures did not have a significant impact on the Maryland distribution operation’s gross margin in 2007, because the operation’s approved rate structure now includes a weather normalization adjustment (“WNA”) mechanism, which 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 on our customers by reducing the amounts the Company can charge them during such periods.

·	Growth in commercial and industrial customers contributed $224,000 and $102,000, respectively, to gross margin in 2007 compared to 2006.

·	Increased sales volumes to interruptible customers contributed $224,000 to gross margin in 2007 compared to 2006.

·	The remaining $31,000 increase in gross margin can be attributed to various other factors.

Gross margin for the Florida distribution operation increased by $88,000, or one percent, in 2007 compared to 2006. The higher gross margin, which resulted from an increase in residential customers, was partially offset by lower volumes sold to industrial customers. The operation experienced a five percent growth in residential customers in 2007 compared to 2006, which provided for an additional $142,000 in gross margin. The Florida distribution operation also experienced a slowdown in the housing market in 2007 attributable to the same unfavorable housing market conditions previously discussed.

Other operating expense for the natural gas distribution operations increased by $2.0 million in 2007 compared 2006. Among the key components of the increase were the following:

·	Payroll costs increased by $110,000 as vacant positions in 2006 were filled in 2007 and additional positions were added to serve the growth experienced by the operations.

·	Health care costs increased by $177,000 as a result of the additional personnel and a higher cost of claims in 2007 compared to 2006.

·	Incentive compensation increased $229,000 in 2007 as the Delmarva operations experienced improved earnings and increased staffing levels.

·	Depreciation and amortization expense, asset removal cost and property taxes increased by $316,000, $121,000 and $156,000, respectively, as a result of the Company’s continued capital investments.

·	The Florida distribution operation experienced an increased expense of $227,000 in 2007 compared with 2006 to maintain compliance with the new federal pipeline integrity regulations.

·	Sales and advertising costs increased $129,000 in 2007 compared to 2006, primarily to promote energy conservation and customer awareness of the availability of natural gas service.

·	Regulatory expenses increased $113,000 as the Delaware and Maryland operations began expensing costs associated with their respective rate cases.

·	The allowance for uncollectible accounts increased $183,000 in 2007 compared to 2006 due to increased revenues resulting from customer growth and colder temperatures.

·	Merchant payment fees decreased by $116,000 as the Company’s Delmarva operation outsourced the processing of credit card payments in April 2007.

·	Other operating expenses relating to various other items increased by approximately $355,000.

Natural Gas Marketing

Gross margin for the natural gas marketing operation decreased by $207,000, or 11 percent, for 2007 compared to 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 2007 as was sold during 2006. Other operating expenses for the marketing operation increased by $258,000 primarily due to increases in payroll and benefit costs, allowance for uncollectible accounts and corporate overhead costs, which were partially offset by lower expenses for consulting services.

Gross margin for the Company’s natural gas segment increased $2.0 million, or 4 percent, and other operating expenses decreased $475,000, or 1 percent, in 2006 compared to 2005. The gross margin increases of $1.8 million for the natural gas transmission operation, $395,000 for the Florida natural gas distribution operation and $75,000 for the natural gas marketing operation were partially offset by a lower gross margin of $210,000 for the Delmarva natural gas distribution operations.

Natural Gas Transmission

The natural gas transmission operation achieved gross margin growth of $1.8 million, or 11 percent. Of the $1.8 million increase, $1.1 million was attributable to new transportation capacity contracts implemented in November 2005 and $612,000 due to new transportation capacity contracts implemented in November 2006. An increase of $416,000 in other operating expenses partially offset the increased gross margin. The factors contributing to the increased expenses are as follow:

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·	Payroll costs and incentive compensation increased $108,000 to serve the additional growth experienced by the operation.

·	Depreciation and asset removal costs increased by $558,000 and property taxes by $109,000 due to an increase in the level of capital investment.

As a result of the operation receiving approval from the FERC to recover certain pre-service costs associated with the E3 Project, the Company deferred $188,000 of costs previously incurred and expensed in 2005. As a result of this deferral, the amounts recognized in the Company’s income statement declined from 2005 by $376,000. Please refer to the “Regulatory Activities” discussion for further information on this expansion project.

·	Other operating expenses relating to various other items increased by approximately $17,000.

Natural Gas Distribution

Gross margin for the Florida distribution operation increased by $395,000 in 2006 compared to 2005. An eight percent growth in residential customers contributed $230,000 of this increase in gross margin. In addition to residential customer growth, new commercial and industrial customers contributed $91,000 to gross margin in 2006. The remaining $74,000 increase in gross margin is attributed to various factors, including turn-on revenue.

The Delmarva distribution operations experienced a decrease of $210,000 in gross margin. Weather significantly affected gross margin in 2006 compared to 2005. The Company estimates that the warmer temperatures in 2006, which were 18 percent warmer than in 2005, led to a decrease in gross margin of approximately $1.7 million when compared to 2005. This decrease was partially offset by continued residential customer growth. The average number of residential customers on the Delmarva Peninsula increased 3,189, or 9 percent, for 2006 compared to 2005 and the Company estimates that additional residential customers contributed approximately $1.2 million to gross margin. The remaining $190,000 increase in gross margin can be attributed to various factors, including an increase in the number of commercial customers and a decrease in interruptible sales.

Other operating expense for the natural gas distribution operations decreased $814,000 in 2006 compared to 2005. Some of the significant components of the decrease in other operating expenses in 2006, compared to 2005, include the following:

·	Health care costs decreased by $313,000 as a result of the Company changing health care service providers in November 2005 and experiencing lower costs related to claims.

·	Allowance for uncollectible accounts decreased by $289,000 in 2006 compared to 2005 due to increased collection efforts and lower revenues resulting from lower prices and warmer temperatures.

·	Incentive compensation decreased by $177,000 in 2006, reflecting lower than expected earnings.

·	Corporate costs were reduced by $407,000 due to lower payroll and related expenses.

·	Depreciation and amortization expense and asset removal cost increased by $132,000 and $186,000, respectively, as a result of the Company’s continued capital investments.

·	Merchant payment fees increased by $136,000 in 2006 compared to 2005 as the Company experienced more customers making payments with the use of credit cards.

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

Natural Gas Marketing

Gross margin for the natural gas marketing operation increased by $75,000 for 2006 compared to 2005. The increase was due primarily to growth in the number of customers to which the operation provided supply management services. Other operating expenses decreased by $78,000 due to lower levels of consulting services, partially offset by an increase in the allowance for uncollectible accounts.

Propane

The propane segment experienced an increase of $2.0 million, or 78 percent, in operating income in 2007 compared to 2006. Gross margin increased $4.0 million, which was partially offset by an increase in other operating expenses of $2.0 million. During 2006, operating income for the propane segment decreased by $675,000, or 21 percent, compared to 2005, reflecting a gross margin decrease of $1.1 million, which was partially offset by a decrease in operating expenses of $464,000.

Propane (in thousands)
					Increase						Increase
For the Years Ended December 31,	2007		2006		(decrease)		2006		2005		(decrease)
Revenue	$	62,838	$	48,576	$	14,262	$	48,576	$	48,976	$	(400	)
Cost of sales		41,038		30,780		10,258		30,780		30,041		739
Gross margin		21,800		17,796		4,004		17,796		18,935		(1,139	)

Operations & maintenance		14,594		12,823		1,771		12,823		13,355		(532	)
Depreciation & amortization		1,842		1,659		183		1,659		1,574		85
Other taxes		866		780		86		780		797		(17	)
Other operating expenses		17,302		15,262		2,040		15,262		15,726		(464	)
Total Operating Income	$	4,498	$	2,534	$	1,964	$	2,534	$	3,209	$	(675	)

Propane Heating Degree-Day (HDD) Analysis — Delmarva
					Increase						Increase
For the Years Ended December 31,	2007		2006		(decrease)		2006		2005		(decrease)
Heating degree-days
Actual		4,504		3,931		573		3,931		4,792		(861	)
10-year average		4,376		4,372		4		4,372		4,436		(64	)

Estimated gross margin per HDD	$	1,974	$	1,743	$	231	$	1,743	$	1,743	$	0

Operating income for the propane segment increased by $2.0 million to $4.5 million for 2007 compared to 2006. Gross margin in the Delmarva propane distribution operations increased by $3.2 million, compared to 2006, primarily due to increases in retail margin per gallon and colder weather on the Delmarva Peninsula. Gross margin also increased in the Florida propane distribution operation and the Company’s wholesale propane marketing operation by $100,000 and $677,000, respectively.

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Delmarva Propane Distribution

The Delmarva propane distribution operation’s increase in gross margin of $3.2 million, or 22 percent, resulted from the following:

Gross margin increased by $1.1 million in 2007, compared to 2006, because of a $0.05 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 affected by changes in the Company’s pricing of sales to its customers.

Temperatures on the Delmarva Peninsula were 15 percent colder in 2007 compared to 2006, which contributed to the increase of 1.7 million retail gallons, or nine percent, sold during 2007. The Company estimates that the colder weather and increased volumes sold contributed $1.1 million to gross margin for the Delmarva propane distribution operation compared to 2006.

·	Wholesale volumes sold in 2007 increased by 2.9 million gallons, or 70 percent, which contributed approximately $119,000 to gross margin for the Delmarva propane distribution operation compared to 2006.

·	The remaining $216,000 increase in gross margin can be attributed to various other factors, including higher service sales and service fees.

Total other operating expenses increased by $1.5 million for the Delmarva propane operations in 2007, compared to the same period in 2006. The significant items contributing to this increase were:

Increased operating expenses for 2007 were magnified by the Company’s one-time recovery in 2006 of previously incurred costs of $387,000 from one of its propane suppliers in 2006. 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 $361,000 as a result of the improved operating results in 2007 compared to 2006.

·	Health care costs increased by $119,000 during 2007 compared to the same period in 2006 as the Company experienced a higher cost of claims during the year.

The operation incurred an additional $233,000 expense in 2007 for propane tank recertifications and maintenance to maintain compliance with Department of Transportation (“DOT”) standards. The DOT standards require propane tanks or cylinders to be recertified twelve years from their date of manufacture and every five years after that.

·	Mains fees increased by $100,000 in 2007 compared to 2006 as a result of added CGS customers. This expenditure will continue to increase as more CGS customers are added.

·	Depreciation and amortization expense increased by $107,000 over the prior year as a result of the Company’s increased capital investments.

·	In addition, other operating expenses relating to various items increased collectively by approximately $193,000.

Florida Propane Distribution

The Florida propane distribution operation experienced an increase in gross margin of $100,000, or nine percent, in 2007 compared to 2006, primarily because of an increase in the average gross margin per retail gallon and higher service margins. Other operating expenses in 2007, compared to 2006, increased by $223,000, primarily due to increases in payroll costs, insurance and depreciation expense.

Propane Wholesale and Marketing

Gross margin for the Company’s propane wholesale marketing operation increased by $677,000, or 40 percent, in 2007 compared to 2006. This increase reflects the larger number of market opportunities that arose in 2007, due to price volatility in the propane wholesale market, which exceeded the level of price fluctuations experienced in 2006. The increase in gross margin was partially offset by higher other operating expenses of $318,000, due primarily to higher incentive compensation based on the increased earnings in 2007.

Operating income for the propane segment decreased $675,000, or 21 percent, to $2.5 million for 2006 compared to 2005. This decrease was due primarily to warmer weather on the Delmarva Peninsula in 2006, which resulted in reduced customer consumption. Gross margin in the Delmarva propane distribution operations was $834,000 lower than in 2005, primarily due to warmer weather in 2006. Gross margin also decreased in the Florida propane distribution operation and the Company’s wholesale propane marketing operation by $146,000 and $159,000, respectively.

Delmarva Propane Distribution

The Delmarva propane distribution operation’s decrease in gross margin of $834,000 resulted from the following factors:

Volumes sold in 2006 decreased 1.9 million gallons, or eight percent, due primarily to 18 percent warmer temperatures on the Delmarva Peninsula in 2006 than in 2005. The Company estimates that the warmer temperatures resulted in a decrease in gross margin of approximately $1.7 million when compared to 2005.

·	Gross margin increased by $956,000 due to an increase of three cents in the average gross margin per retail gallon in 2006 compared to 2005.

·	Gross margin for the Delmarva CGS activities increased by $155,000 compared to 2005 due primarily to an increase in the average number of customers, which grew by approximately 1,000 to a total count of approximately 3,900, or a 34 percent increase, compared to 2005.

·	Gross margin was adversely affected by a $272,000 write-down of propane inventory, reflecting the lower of cost or market.

·	The remaining gross margin decrease of $29,000 was attributable primarily to customer conservation and changes in the timing of deliveries to customers.

Other operating expenses decreased by $335,000 for the Delmarva operations in 2006 compared to 2005. The significant factors contributing to the decrease included:

The Company recovered $387,000 in fixed costs from one of its propane suppliers in response to a propane contamination incident that occurred in a previous period when approximately 75,000 gallons of propane that the Company purchased from the supplier contained above-normal levels of petroleum byproducts.

·	Health care costs decreased by $324,000. The Company changed health care service providers in November 2005 and subsequently experienced lower costs related to claims.

·	In addition, there was a decrease of approximately $39,000 in other operating expenses relating to various minor items.

·	These lower costs were partially offset by increased costs of $176,000 for one of the Pennsylvania start-ups, which began operation in July 2005, increased payroll costs of $165,000 and higher costs of $74,000 associated with vehicle fuel.

Florida Propane Distribution

In 2006, the Florida propane distribution operation experienced a decrease in gross margin of $146,000, or 12 percent, when compared to 2005. The lower gross margin reflected a decrease of $208,000 for in-house piping sales as the operation exited the house piping service, which was partially offset by an increase in gross margin of $62,000 from propane sales due primarily to an increase in the average gross margin per retail gallon, partially offset by a one percent decrease in the volumes sold in 2006. The Florida propane operation experienced a decrease of $49,000 in other operating expenses in 2006 compared to 2005, attributable to lower payroll and benefits costs related to vacant positions during the year, partially offset by higher expenses related to leak testing and depreciation expense.

Propane Wholesale and Marketing

Gross margin for the Company’s propane wholesale marketing operation decreased by $159,000 in 2006 compared to 2005. This decrease from the 2005 results reflects the increased market opportunities that arose in 2005 due to the extreme price volatility in the propane wholesale market following the hurricanes in the Gulf of Mexico area, but did not extend into 2006. The decrease in gross margin was partially offset by lower other operating expenses of $79,000 attributed primarily to lower incentive compensation as a result of lower earnings in 2006.

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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 contributed operating income of $836,000 for 2007, $767,000 for 2006, and $1.2 million for 2005.

Advanced Information Services (in thousands)
					Increase						Increase
For the Years Ended December 31,	2007		2006		(decrease)		2006		2005		(decrease)
Revenue	$	15,099	$	12,568	$	2,531	$	12,568	$	14,140	$	(1,572	)
Cost of sales		8,260		7,082		1,178		7,082		7,181		(99	)
Gross margin		6,839		5,486		1,353		5,486		6,959		(1,473	)

Operations & maintenance		5,225		4,119		1,106		4,119		5,129		(1,010	)
Depreciation & amortization		144		113		31		113		123		(10	)
Other taxes		634		487		147		487		510		(23	)
Other operating expenses		6,003		4,719		1,284		4,719		5,762		(1,043	)
Total Operating Income	$	836	$	767	$	69	$	767	$	1,197	$	(430	)

The advanced information services business experienced gross margin growth of approximately $1.4 million, or 25 percent, and contributed operating income of $836,000 for 2007, an increase of $69,000, or nine percent, compared to 2006.

The period-over-period increase of gross margin resulted primarily from:

·	A strong demand for the segment’s consulting services in 2007 generated an increase of $1.9 million in consulting revenues as the number of billable hours increased by 15 percent; and

·	An increase of $276,000 from Managed Database Administration (“MDBA”) services, first offered in the first quarter of 2006, which provide clients with professional database monitoring and support solutions during business hours or around the clock.

Other operating expenses increased by $1.3 million to $6.0 million in 2007, compared to $4.7 million for 2006. This increase in operating expenses in 2007 is attributable to the following:

Payroll, incentive compensation and commissions, payroll taxes, benefit claims, and consulting expense accounted for $937,000 of the period-over-period increase. These costs increased as a result of improved earnings and increased staffing levels to support the growth and customer demand experienced in 2007.

·	An increase in allowance for uncollectible accounts of $223,000 associated with a customer in the mortgage lending business that had filed for bankruptcy in the third quarter of 2007.

·	In addition, other operating expenses relating to various minor items increased by approximately $140,000.

Operating income for the advanced information services segment decreased by $430,000 to $767,000 for 2006 compared to $1.2 million in 2005. The greater operating income in 2005 included $993,000 for the LAMPS™ product, which in turn included a $924,000 pre-tax gain on the sale of the product in October 2005 to Fidelity National Information Solutions, Inc., a subsidiary of Fidelity National Financial, Inc.

Revenues for the period decreased $1.6 million compared to 2005, due primarily to elimination of $1.9 million of revenue generated by the LAMPSTM product in 2005. Consulting revenues increased $749,000 in 2006 compared to 2005, primarily from offering MDBA services to its customers in 2006, which accounted for $740,000 of the increase, and an increase of 7.6 percent in the average hourly billing rate, while the number of billable hours remained at the same level attained in 2005. Partially offsetting the increase in consulting revenues were decreases of $128,000 in training and product sales and $244,000 in other revenues.

Cost of sales for 2006 decreased by $99,000 to $7.08 million, compared to the 2005 cost of sales of $7.18 million, which included $401,000 related to LAMPSTM. After deducting the 2005 cost of sales associated with the LAMPSTM product, cost of sales increased in 2006 compared to 2005 to support the higher 2006 revenues.

Other operating expenses decreased $1.0 million in 2006 to $4.7 million compared to 2005. The reduction in expenses primarily reflects expenses of $554,000 in 2005 associated with LAMPSTM and lower benefits costs, rent expense and consulting costs.

Other Operations and Eliminations

Other operations consist primarily of subsidiaries that own real estate leased to other Company subsidiaries. Eliminations are entries required to eliminate activities between business segments from the consolidated results. Other operations and eliminating entries contributed operating income of $295,000 for 2007, $298,000 for 2006, and $279,000 for 2005.

Other Operations & Eliminations (in thousands)
					Increase							Increase
For the Years Ended December 31,	2007		2006		(decrease)			2006		2005		(decrease)
Revenue	$	622	$	618	$	4		$	618	$	618	$	0
Cost of sales		-		-		-			-		-		-
Gross margin		622		618		4			618		618		-

Operations & maintenance		109		96		13			96		67		29
Depreciation & amortization		160		163		(3	)		163		220		(57	)
Other taxes		62		65		(3	)		65		81		(16	)
Other operating expenses		331		324		7			324		368		(44	)

Operating Income — Other	$	291	$	294	$	(3	)	$	294	$	250	$	44
Operating Income — Eliminations	$	4		4	$	0		$	4		29	$	(25	)
Total Operating Income	$	295		298	$	(3	)	$	298		279	$	19

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Other Income

Other income for the years 2007, 2006, and 2005, respectively, was $291,000, $189,000, and $383,000, which include interest income, late fees charged to customers and gains or losses from the sale of assets.

Interest Expense

Total interest expense for 2007 increased approximately $816,000, or 14 percent, compared to 2006. The higher interest expense was a result of the following developments:

·	As the result of fewer capital projects in 2007 compared to 2006, the Company capitalized $469,000 less interest on debt in 2007 associated with ongoing capital projects.

The Company’s average long-term debt balance during 2007 was $76.5 million, with a weighted average interest rate of 6.71 percent, compared to $67.2 million, with a weighted average interest rate of 6.98 percent for 2006. The large year-over-year increase in the average long-term debt balance was 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).

The average short-term borrowing balance decreased by $6.3 million in 2007 to $20.6 million compared to an average balance of $26.9 million in 2006. The weighted average interest rates for short-term borrowing of 5.46 percent for 2007 and 5.47 percent for 2006, had minimum impact on the change in short-term borrowing expense.

Total interest expense for 2006 increased approximately $642,000, or 12.5 percent, compared to 2005. The increase reflected the following:

Average short-term debt balance and short-term interest rates both increased in 2006 compared to 2005. The average short-term borrowing balance increased by $21.2 million in 2006 to $26.9 million compared to $5.7 million in 2005 primarily to finance the $39.3 million of net property, plant, and equipment added in 2006.

·	The weighted average interest rate for short-term borrowing increased from 4.47 percent for 2005 to 5.47 percent for 2006.

The average long-term debt balance during 2006 was $67.2 million with a weighted average interest rate of 6.98 percent, compared to $67.4 million with a weighted average interest rate of 7.18 percent for 2005. The Company also capitalized $586,000 of interest as part of capital project costs during 2006.

Income Taxes

Income tax expense for 2007 was $8.6 million compared to $7.0 million for 2006. Income taxes increased in 2007 compared to 2006, due primarily to increased taxable income and income taxes increased in 2006 compared to 2005, again due to increased taxable income. The effective federal income tax rate for each of the three years 2007, 2006 and 2005 was 35 percent and the Company realized a benefit of $226,000, $220,000, and $223,000 in those years, respectively, resulting from a change in the tax law allowing tax deductions for dividends paid on Company stock held in Employee Stock Ownership Plans (“ESOP”).

Discontinued Operations

During the quarter ended September 30, 2007, Chesapeake decided to close its distributed energy services company, Chesapeake OnSight Services, LLC (“OnSight”), which experienced operating losses since its inception in 2004. OnSight was previously reported as part of the Company’s Other Operations business segment. At December 31, 2007, the results of operations for OnSight have been reclassified to discontinued operations and shown net of tax for all periods presented. The discontinued operations experienced net losses of $20,000 for 2007, $241,000 for 2006 and $231,000 for 2005.

Liquidity and Capital Resources

Chesapeake’s capital requirements reflect the capital-intensive nature of its business and are principally attributable to investment in new plant and equipment and 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 2007, net cash provided by operating activities was $25.7 million, cash used by investing activities was $31.3 million and cash provided by financing activities was $3.7 million.

During 2006, net cash provided by operating activities was $30.1 million, cash used by investing activities was $48.9 million, and cash provided by financing activities was $20.7 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 December 31, 2007, Chesapeake had five unsecured bank lines of credit with three financial institutions, totaling $90.0 million, none of which requires compensating balances. These bank lines are available to provide funds for the Company’s short-term cash needs to meet seasonal working capital requirements and to fund temporarily portions of its capital expenditures. Three of the bank lines, totaling $25.0 million, are committed. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks. The outstanding balance of short-term borrowing at December 31, 2007 and 2006 was $45.7 million and $27.6 million, respectively. The level of short-term debt was reduced in 2006 with funds provided from the placement of $20 million of 5.5 percent Senior Notes in October 2006 and from the proceeds of the issuance of 600,300 shares of common stock in November 2006.

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

Capital Structure

The following presents our capitalization as of December 31, 2007 and 2006:

	December 31,
	2007				2006
	(In thousands, except percentages)

Long-term debt, net of current maturities	$	63,256	35	%	$	71,050	39	%
Stockholders' equity	$	119,576	65	%	$	111,152	61	%
Total capitalization, excluding short-term debt	$	182,832	100	%	$	182,202	100	%

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As of December 31, 2007, common equity represented 65 percent of total capitalization, compared to 61 percent at December 31, 2006.

The following presents our capitalization as of December 31, 2007 and 2006, if short-term borrowing and the current portion of long-term debt were included in capitalization:

	December 31,
	2007				2006
	(In thousands, except percentages)

Short-term debt	$	45,664	19	%	$	27,554	13	%
Long-term debt, including current maturities	$	70,912	30	%	$	78,706	36	%
Stockholders' equity	$	119,576	51	%	$	111,152	51	%
Total capitalization, including short-term debt	$	236,152	100	%	$	217,412	100	%

If short-term borrowing and the current portion of long-term debt were included in capitalization, total capitalization increased by $18.7 million in 2007 compared to 2006. The increased capitalization was primarily used to fund a portion of the $31.3 million of net property, plant, and equipment added in 2007 and for other general working capital. In addition, 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 December 31, 2007 and 2006.

Chesapeake remains committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access the 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 its investors.

Shelf Registration

In July 2006, the Company filed a registration statement on Form S-3 with the SEC to issue up to $40.0 million in new common stock and/or debt securities. The registration statement was declared effective by the SEC in November 2006. In November 2006, we 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. The net proceeds from the sale were used for general corporate purposes, including financing of capital expenditures, repayment of short-term debt, and funding working capital requirements. At December 31, 2007 and 2006, the Company had approximately $20.0 million remaining under this registration statement.

Cash Flows Provided by Operating Activities

Our cash flows provided by (used in) operating activities were as follows:

For the Years Ended December 31,	2007			2006		2005
Net income	$	13,197,710		$	10,506,525	$	10,467,614
Non-cash adjustments to net income		15,554,639			11,186,418		13,059,678
Changes in working capital		(3,070,465	)		8,424,055		(9,927,351	)
Net cash from operating activties	$	25,681,884		$	30,116,998	$	13,599,941

Period-over-period changes in our cash flows from operating activities are attributable primarily to changes in net income and working capital. Changes in working capital are determined by a variety of factors, including 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.

The Company generates a large portion of its annual net income and subsequent increases in our accounts receivable in the first and fourth quarters of each year due to significant volumes of natural gas and propane delivered by our Delmarva natural gas and propane distribution operations to our customers during the peak heating season. In addition, our natural gas and propane inventories, which usually peak in the fall months, are largely drawn down in the heating season and provide a source of cash as the inventory is used to satisfy winter sales demand.

In 2007, our net cash flow provided by operating activities was $25.7 million, a decrease of $4.4 million from 2006. The 2007 operating cash flows reflect the favorable timing of payments for accounts payable and accrued liabilities, which increased operating cash flow by $22.1 million. In addition, increased net income and favorable non-cash adjustments, primarily depreciation expense, contributed to the increase in operating cash flow. Partially offsetting these increases in operating cash flow was an increase in accounts receivable of $28.2 million associated with increased revenues and the timing of invoicing by our propane wholesale and marketing operation.

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In 2006, our net cash flow provided by operating activities was $30.1 million, an increase of $16.5 million over 2005. This increase was primarily a result of the recovery during 2006 of working capital that was deployed in 2005 due to significantly higher commodity prices and the amount of working capital required for operations. Also, contributing to this increase was a reduction of $6.1 million in natural gas and propane purchased for inventory as a result of mild weather in the prior heating season and therefore higher inventory balances for the current heating season.

Cash Flows Used in Investing Activities

Net cash flows used in investing activities totaled $31.3 million, $48.9 million and $33.1 million during fiscal years 2007, 2006, and 2005, respectively.

Cash utilized for capital expenditures was $31.3 million, $48.9 million and $33.3 million for 2007, 2006, and 2005, respectively. Additions to property, plant and equipment in 2007 were primarily for natural gas transmission ($9.2 million), natural gas distribution ($15.2 million), propane distribution ($5.2 million), and other operations ($1.7 million). 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.

·	Sales of property, plant, and equipment generated $205,000 of cash in 2007.

·	The Company’s environmental expenditures exceeded amounts recovered through rates charged to customers in 2007 and 2006 by $228,000 and $16,000, respectively; in 2005, the Company recovered from its customers $240,000 in excess of its environmental expenditures for the period.

Cash Flows Provided by Financing Activities

Cash flows provided by financing activities totaled $3.7 million during 2007, $20.7 million during 2006, and $20.4 million during 2005. Significant financing activities included the following:

·	During 2007 and 2005, net borrowing of short-term debt increased by $18.7 million and $29.6 million, respectively, primarily to support our capital investments. During 2006, the Company reduced it short-term debt by $8.0 million.

·	The Company repaid $7.7 million of long-term debt during 2007 compared with $4.9 million during 2006 and $4.8 million during 2005.

During 2007, the Company paid $7.0 million in cash dividends compared with dividend payments of $6.0 million and $5.8 million for 2006 and 2005, respectively. The increase in dividends paid in 2007 compared to 2006 reflects both growth in the annualized dividend rate, from $1.16 per share during 2006 to $1.18 per share during 2007, and the increase in shares outstanding following the issuance of additional shares of common stock in the fourth quarter of 2006.

·	In November 2006, the Company sold 600,300 shares of common stock, including the underwriter’s exercise of their over-allotment option of 90,045 shares, pursuant to a shelf registration statement declared effective in November 2006, generating net proceeds of $19.7 million.

·	In October 2006, the Company placed $20.0 million of 5.5 percent Senior Notes (“Notes”) to three institutional investors (The Prudential Insurance Company of America, Prudential Retirement Insurance and Annuity Company and United Omaha Life Insurance Company).

·	In August 2006, the Company paid cash of $435,000, in lieu of issuing shares of the Company’s common stock for the 30,000 stock warrants outstanding at December 31, 2005.

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Contractual Obligations

We have the following contractual obligations and other commercial commitments as of December 31, 2007:

	Payments Due by Period
Contractual Obligations	Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years		Total
Long-term debt (1)	$	7,656,364	$	13,312,727	$	14,474,545	$	35,468,364	$	70,912,000
Operating leases (2)		790,801		1,211,720		1,166,800		2,252,714		5,422,035
Purchase obligations (3)
Transmission capacity		9,302,772		20,794,882		6,266,171		21,339,713		57,703,538
Storage — Natural Gas		1,553,175		4,210,670		3,015,217		1,838,948		10,618,010
Commodities		13,907,762		63,515		-		-		13,971,277
Forward purchase contracts — Propane (4)		41,781,709		-		-		-		41,781,709
Unfunded benefits (5)		308,552		628,143		645,350		1,945,895		3,527,940
Funded benefits (6)		73,939		133,864		119,852		1,572,844		1,900,499
Total Contractual Obligations	$	75,375,074	$	40,355,521	$	25,687,935	$	64,418,478	$	205,837,008

(1) Principal payments on long-term debt, see Note H, "Long-Term Debt," in the Notes to the Consolidated Financial Statements for additional discussion of this item. The expected interest payments on long-term debt are $5.2 million, $8.8 million, $6.9 million and $10.0 million, respectively, for the periods indicated above. Expected interest payments for all periods total $ 30.9 million.
(2) See Note J, "Lease Obligations," in the Notes to the Consolidated Financial Statements for additional discussion of this item.
(3) See Note N, "Other Commitments and Contingencies," in the Notes to the Consolidated Financial Statements for further information.
(4) The Company has also entered into forward sale contracts. See "Market Risk" of the Management's Discussion and Analysis for further information.
(5) The Company has recorded long-term liabilities of $4.2 million at December 31, 2006 for unfunded post-retirement benefit plans. The amounts specified in the table are based on expected payments to current retirees and assumes a retirement age of 65 for currently active employees. There are many factors that would cause actual payments to differ from these amounts, including early retirement, future health care costs that differ from past experience and discount rates implicit in calculations.
(6) The Company has recorded long-term liabilities of $2.0 million at December 31, 2006 for funded benefits. These liabilities have been funded using a Rabbi Trust and an asset in the same amount is recorded under Investments on the Balance Sheet. The defined benefit pension plan was closed to new participants on January 1, 1999 and participants in the plan on that date were given the option to leave the plan. See Note K, "Employee Benefit Plans," in the Notes to the Consolidated Financial Statements for further information on the plan. Since the plan modification, no additional funding has been required from the Company and none is expected for the next five years, based on factors in effect at December 31, 2006. However, this is subject to change based on the actual return earned by the plan assets and other actuarial assumptions, such as the discount rate and long-term expected rate of return on plan assets.

Off-Balance Sheet Arrangements

The Company has issued corporate guarantees to certain vendors of its propane wholesale marketing subsidiary and its Florida natural gas supply management subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event either subsidiary’s default. Neither of these subsidiaries has ever defaulted in its obligations to pay its suppliers. The liabilities for these purchases are recorded in the Consolidated Financial Statements when incurred. The aggregate amount guaranteed at December 31, 2007 was $24.2 million, with the guarantees expiring on various dates in 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 December 31, 2007.

Regulatory Activities

The Company’s natural gas distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSCs; Eastern Shore, the Company’s natural gas transmission operation, is subject to regulation by the FERC.

Delaware. On September 2, 2005, the Delaware division filed an application with the 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 eastern Sussex County targeted for growth by the State of Delaware. In April 2002, Governor Ruth Ann Minner established the Delaware Energy Task Force (“Task Force”), whose mission was to address the State’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 to enhance 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 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.

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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 PSC Staff filed testimony recommending a rate decrease of $693,245. The DPA recommended a rate decrease of $588,670. Neither party recommended approval of the Delaware division’s other proposals mentioned above. The Delaware division strongly disagrees with these positions and is currently in the process of drafting its rebuttal position which was filed on February 7, 2008. The Delaware division anticipates a final decision by the Delaware PSC during the second quarter 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 second or third quarter of 2008.

On November 1, 2007, the Delaware division filed with the Delaware PSC its annual Environmental Rider (“ER”) rate application to become effective for service rendered on and after December 1, 2007. The Delaware PSC granted approval of the ER rate at its regularly scheduled meeting on November 20, 2007, subject to full evidentiary hearings and a final decision. The Delaware division anticipates a final decision by the Delaware PSC during the first quarter of 2008.

Maryland. On September 26, 2006, the Maryland PSC approved a base rate increase for the Maryland division of approximately $780,000 annually. In a settlement agreement entered into in that proceeding, the Maryland division was required to file a depreciation study, which was filed on April 9, 2007. The Maryland division filed formal testimony on July 10, 2007, initiating a phase II of this proceeding. In this filing, the Maryland division proposed a rate decrease of approximately $80,000 annually, resulting from a change in depreciation expense. On November 29, 2007 the Maryland PSC approved a settlement agreement for a rate decrease of $132,155, effective December 1, 2007 based on the change in the Company’s depreciation rates.

On December 17, 2007, the Maryland PSC held an evidentiary hearing to determine the reasonableness of the Maryland division’s four quarterly gas cost recovery filings during the twelve months ended September 30, 2007. No issues were raised at the hearing. The Maryland division anticipates a final decision by the Maryland PSC during the first quarter of 2008.

Florida. On October 10, 2006, the Florida division filed with the Florida PSC a petition 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, 2007 by the Florida PSC, phase two of the TTS program went into effect on July 1, 2007.

On November 29, 2006, the Florida division filed with the Florida PSC a petition for authority to modify its energy conservation programs. In this petition, the Florida division sought approval to increase the cash allowances paid within its Residential Homebuilder Program and the Residential Appliance Replacement Program, and to expand the scope of its 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, approved on November 6, 2007, and became 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 changes in plant and equipment 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 responded to interrogatories concerning the Study on October 15 and December 24, 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 the second quarter of 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 and to extend its facilities into these specific territories to serve 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, PIPECO, filed with the Florida PSC its petition for approval of a natural gas transmission pipeline tariff in order to establish its operating rules and regulations. The Florida PSC approved the petition at its December 4, 2007 agenda conference.

Eastern Shore. During 2007, FERC regulatory activity regarding the expansion of Eastern Shore’s transmission system included the following:

System Expansion 2006 – 2008 On January 20, 2006, Eastern Shore filed with the FERC an application for a Certificate of Public Convenience and Necessity for its 2006-2008 system expansion project (“the 2006 – 2008 Project”). 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 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. On November 1, 2006, Eastern Shore completed and placed in service the authorized Phase I facilities.

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. Facilities have been completed and were placed in service on November 1, 2007. These additional facilities provide for 8,300 Dts 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 Dts of additional firm capacity per day and $1.5 million annualized gross margin contribution.

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On November 15, 2007 Eastern Shore requested FERC authorization to commence construction of Phase III facilities (approximately 9.2 miles). The FERC granted this authorization on January 7, 2008. Construction activities are to begin in the first quarter of 2008 and are to be completed and placed in service on November 1, 2008. These Phase III facilities provide for 5,650 Dts of additional firm capacity per day and annualized gross margin contribution of approximately $1.0 million instead of the amounts included in the original filing of 10,850 Dts of additional firm capacity per day and $1.6 million annualized gross margin contribution.

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

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

As part of the Precedent Agreements, Eastern Shore, Chesapeake and Delmarva also entered into Letter Agreements which provide that, if the 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.

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

As part of an updated engineering study, Eastern Shore received additional construction cost estimates for the E3 project, which indicated substantially higher costs than previously estimated. In an effort to optimize the feasibility of the overall project development plan, Eastern Shore explored all potential construction methods, construction cost mitigation strategies, potential design changes and project schedule changes. Eastern Shore also held discussions and meetings with several potential new customers, who 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.

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

If Eastern Shore decides to abandon the E3 Project, it will initiate billing of pre-certification costs surcharge in accordance with the terms of the Precedent Agreements executed with two of its customers, which provide for these customers to reimburse Eastern Shore for pre-certification costs incurred in connection with the E3 Project, up to a maximum amount of $2.0 million each over a period of 20 years. As of December 31, 2007, the Company had incurred $2.97 million of pre-certification costs relating to the E3 Project.

During 2007, Eastern Shore also had developments in the following FERC 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 annual 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 was issued on January 31, 2008.

- Page 28 - -

Environmental Matters

The Company continues to work with federal and state environmental agencies to assess the environmental impact and explore corrective action at three environmental sites (see Note M to the Consolidated Financial Statements). The Company believes that future costs associated with these sites will be recoverable in rates or through sharing arrangements with, or contributions by, other responsible parties.

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 (see Note H to the Consolidated Financial Statements for annual maturities of consolidated long-term debt). 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 $70.9 million at December 31, 2007, as compared to a fair value of $75.0 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 entering into fixed price contracts for supply. The Company can store up to approximately four million gallons (including leased storage and rail cars) of propane during the winter season to meet its customers’ peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause the value of stored propane to decline. To mitigate the impact of price fluctuations, the Company has adopted a Risk Management Policy that allows the propane distribution operation to enter into fair value hedges of its inventory. Management reviewed the Company’s storage position as of December 31, 2007, and elected not to hedge any of its inventories. At December 31, 2006, the propane distribution operation had entered into a swap agreement to protect the Company from the impact of price increases on the price-cap plan that we offer to customers. The Company considered this agreement to be an economic hedge that did not qualify for hedge accounting as described in SFAS 133. At the end of 2006, the market price of propane dropped below the unit price within the swap agreement. As a result of the price drop, the Company marked the agreement to market, which resulted in an unrealized loss of $84,000. The Company did not enter into a similar agreement in 2007.

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 by 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 is monitored daily for compliance with the Company’s Risk Management Policy, which includes volumetric limits for open positions. To manage exposures to changing market prices, open positions are marked up or down to market prices and reviewed by the Company’s oversight officials daily. In addition, the Risk Management Committee reviews periodic reports on market and the credit risk of counter-parties, approves any exceptions to the Risk Management Policy (within limits established by the Board of Directors) and authorizes the use of any new types of contracts. Quantitative information on forward and futures contracts at December 31, 2007 and 2006 is presented in the following tables.

At December 31, 2007	Quantity in gallons	Estimated Market Prices	Weighted Average Contract Prices
Forward Contracts
Sale	30,941,400	$0.8925 — $1.6025	$1.3555
Purchase	30,954,000	$0.8700 — $1.6000	$1.3498

Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expire in 2008.

Estimated market prices and weighted average contract prices are in dollars per gallon.

All contracts expired in 2007.

The Company’s natural gas distribution and marketing operations have entered into agreements with natural gas suppliers to purchase natural gas for resale to their customers. Purchases under these contracts either do not meet the definition of derivatives in SFAS No. 133 or are considered “normal purchases and sales” under SFAS No. 138 and are not marked to market.

- Page 29 - -

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 can 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 may 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 sides of this business to compete with the fluctuations in its customers’ alternative fuel prices. As a result of the transmission operation’s conversion to open access and the Florida gas distribution division’s restructuring of its services, their businesses have shifted from providing bundled transportation and sales service to providing only transportation and contract storage services.

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

The Company’s propane distribution operations compete with several other propane distributors in their service territories, primarily on the basis of service and price, emphasizing reliability of service and responsiveness. Competition is generally from local outlets of national distribution companies and local businesses because distributors located in close proximity to customers incur lower costs of providing service. Propane competes with electricity as an energy source, because 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 served by natural gas pipeline or distribution systems.

The propane wholesale marketing operation competes against various regional and national 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 affect 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. In the Company’s regulated natural gas distribution operations, fluctuations in natural gas prices are passed on to customers through the gas cost recovery mechanism in the Company’s tariffs. To help cope with the effects of inflation on its capital investments and returns, the Company seeks rate relief from regulatory commissions for its regulated operations and closely monitors the returns of its unregulated business operations. To compensate for fluctuations in propane gas prices, the Company adjusts its propane selling prices to the extent allowed by the market.

- Page 30 - -

Cautionary Statement

Chesapeake Utilities Corporation has made statements in this Form 10-K 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, inflation, and other matters. It is important to understand that these forward-looking statements are not guarantees, but are subject to certain risks and uncertainties and other important factors that could cause actual results to differ materially from those in the forward-looking statements. The factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to:

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

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

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

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

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

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

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

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

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

·	the effects of accounting changes;

·	changes in benefit plan assumptions;

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

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

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

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

·	the Company’s ability to obtain the rate relief and cost recovery requested from 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 to a degree that may impair future growth; and

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

- Page 31 - -

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Information concerning quantitative and qualitative disclosure about market risk is included in Item 7 under the heading “Management’s Discussion and Analysis — Market Risk.”

Item 8. Financial Statements and Supplementary Data.

Management’s Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, Chesapeake’s management conducted an evaluation of the effectiveness of its internal control over financial reporting based on the criteria established in a report entitled “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Chesapeake’s management has evaluated and concluded that Chesapeake’s internal control over financial reporting was effective as of December 31, 2007.

- Page 32 - -

Report of Independent Registered Public Accounting Firm

________

To the Board of Directors and

Stockholders of Chesapeake Utilities Corporation

We have audited the accompanying consolidated balance sheet of Chesapeake Utilities Corporation as of December 31, 2007, and the related consolidated statements of income, stockholders’ equity, comprehensive income, cash flows and income taxes for the year then ended. Chesapeake Utilities Corporation’s management is responsible for these consolidated financial statements. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Chesapeake Utilities Corporation and subsidiaries as of December 31, 2007 and the results of their operations and their cash flows for the year ended in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Chesapeake Utilities Corporation’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 10, 2008 expressed an unqualified opinion.

/s/ Beard Miller Company LLP

————————————————

Beard Miller Company LLP

Reading, Pennsylvania

March 10, 2008

- Page 33 - -

Report of Independent Registered Public Accounting Firm

________

To the Board of Directors and Stockholders

of Chesapeake Utilities Corporation

In our opinion, the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, comprehensive income, cash flows, stockholders’ equity and income taxes for each of the two years in the period ended December 31, 2006, before the effects of the adjustments to retrospectively reflect the discontinued operations described in Note B, present fairly, in all material respects, the financial position of Chesapeake Utilities Corporation and its subsidiaries at December 31, 2006, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America (the 2006 financial statements before the effects of the adjustments discussed in Note B are not presented herein). In addition, in our opinion, the financial statement schedule for the each of the two years in the period ended December 31, 2006, presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements before the effects of the adjustments described above. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits, before the effects of the adjustments described above, of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note K to the consolidated financial statements, the Company changed the manner in which it accounts for defined benefit pension and other postretirement plans, effective December 31, 2006.

We were not engaged to audit, review, or apply any procedures to the adjustments to retrospectively reflect the discontinued operations described in Note B and accordingly, we do not express an opinion or any other form of assurance about whether such adjustments are appropriate and have properly applied. Those adjustments were audited by other auditors.

/s/ PricewaterhouseCoopers LLP

————————————————

PricewaterhouseCoopers LLP

Boston, MA

March 10, 2007

- Page 34 - -

Consolidated Statements of Income

For the Twelve Months Ended December 31,	2007			2006			2005
Operating Revenues	$	258,286,495		$	231,199,565		$	229,485,352
Operating Expenses
Cost of sales, excluding costs below		170,848,211			155,809,747		$	153,398,723
Operations		42,274,023			36,670,302			39,778,597
Maintenance		2,203,800			2,103,558			1,818,981
Depreciation and amortization		9,060,185			8,243,715		$	7,568,209
Other taxes		5,786,694			5,040,306		$	4,999,963
Total operating expenses		230,172,913			207,867,628			207,564,473
Operating Income		28,113,582			23,331,937			21,920,879
Other income, net of other expenses		291,305			189,093		$	382,610
Interest charges		6,589,639			5,773,993		$	5,132,458
Income Before Income Taxes		21,815,248			17,747,037			17,171,031
Income taxes		8,597,461			6,999,072			6,472,220
Income from Continuing Operations		13,217,787			10,747,965			10,698,811
Loss from discontinued operations, net of
tax benefit of $10,898, $162,510 and $160,204		(20,077	)		(241,440	)		(231,197	)
Net Income	$	13,197,710		$	10,506,525		$	10,467,614

Weighted Average Common Shares Outstanding:
Basic		6,743,041			6,032,462			5,836,463
Diluted		6,854,716			6,155,131			5,992,552

Earnings (Loss) Per Share of Common Stock:
Basic
From continuing operations	$	1.96		$	1.78		$	1.83
From discontinued operations		-		$	(0.04	)		(0.04	)
Net Income	$	1.96		$	1.74		$	1.79

Diluted
From continuing operations	$	1.94		$	1.76		$	1.81
From discontinued operations		-		$	(0.04	)		(0.04	)
Net Income	$	1.94		$	1.72		$	1.77

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

- Page 35 - -

Consolidated Statements of Cash Flows

For the Years Ended December 31,	2007			2006			2005
Operating Activities
Net Income	$	13,197,710		$	10,506,525		$	10,467,614
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization		9,060,185			8,243,715			7,568,209
Depreciation and accretion included in other costs		3,336,506			3,102,066			2,705,620
Deferred income taxes, net		1,831,030			(408,533	)		1,510,777
Gain on sale of assets		(204,882	)		-			-
Unrealized gain (loss) on commodity contracts		(170,465	)		37,110			(227,193	)
Unrealized loss on investments		(122,819	)		(151,952	)		(56,650	)
Employee benefits and compensation		1,825,028			382,608			1,621,607
Other, net		56			(18,596	)		(62,692	)
Changes in assets and liabilities:
Sale (purchase) of investments		229,125			(177,990	)		(1,242,563	)
Accounts receivable and accrued revenue		(28,189,132	)		9,705,860			(16,831,751	)
Propane inventory, storage gas and other inventory		1,193,336			354,764			(5,704,040	)
Regulatory assets		(344,680	)		2,498,954			(1,719,184	)
Prepaid expenses and other current assets		(1,188,481	)		(271,438	)		36,704
Other deferred charges		(2,477,879	)		(231,822	)		(102,561	)
Long-term receivables		83,653			137,101			247,600
Accounts payable and other accrued liabilities		22,130,049			(11,434,370	)		15,569,924
Income taxes receivable (payable)		(158,556	)		1,800,913			(2,006,762	)
Accrued interest		33,112			273,672			(42,376	)
Customer deposits and refunds		2,534,655			2,361,265			462,781
Accrued compensation		1,117,941			(542,512	)		875,342
Regulatory liabilities		2,124,091			2,824,068			144,501
Other liabilities		(157,699	)		1,125,590			385,034
Net cash provided by operating activities		25,681,884			30,116,998			13,599,941

Investing Activities
Property, plant and equipment expenditures		(31,277,390	)		(48,845,828	)		(33,319,613	)
Proceeds from sale of assets		204,882			-			-
Environmental recoveries (expenditures)		(227,979	)		(15,549	)		240,336
Net cash used by investing activities		(31,300,487	)		(48,861,377	)		(33,079,277	)

Financing Activities
Common stock dividends		(7,029,821	)		(5,982,531	)		(5,789,180	)
Issuance of stock for Dividend Reinvestment Plan		299,436			321,865			458,757
Stock issuance		-			19,698,509			-
Cash settlement of warrants		-			(434,782	)		-
Change in cash overdrafts due to outstanding checks		(541,052	)		49,047			874,083
Net borrowing (repayment) under line of credit agreements		18,651,055			(7,977,347	)		29,606,400
Proceeds from issuance of long-term debt		-			20,000,000			-
Repayment of long-term debt		(7,656,580	)		(4,929,674	)		(4,794,827	)
Net cash provided by financing activities		3,723,038			20,745,087			20,355,233

Net Increase (Decrease) in Cash and Cash Equivalents		(1,895,565	)		2,000,708			875,897
Cash and Cash Equivalents — Beginning of Period		4,488,366			2,487,658			1,611,761
Cash and Cash Equivalents — End of Period	$	2,592,801		$	4,488,366		$	2,487,658

Supplemental Disclosures of Non-Cash Investing Activities:
Capital property and equipment acquired on account,
but not paid as of December 31	$	365,890		$	1,490,890		$	1,367,348

Supplemental Disclosure of Cash Flow information
Cash paid for interest	$	5,592,279		$	5,334,477		$	5,052,013
Cash paid for income taxes	$	7,009,206		$	6,285,272		$	6,342,476

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

- Page 36 - -

Consolidated Balance Sheets

Assets	December 31, 2007			December 31, 2006

Property, Plant and Equipment
Natural gas	$	289,706,066		$	269,012,516
Propane		48,506,231			44,791,552
Advanced information services		1,157,808			1,054,368
Other plant		8,567,833			9,147,500
Total property, plant and equipment		347,937,938			324,005,936
Less: Accumulated depreciation and amortization		(92,414,289	)		(85,010,472	)
Plus: Construction work in progress		4,899,608			1,829,948
Net property, plant and equipment		260,423,257			240,825,412

Investments		1,909,271			2,015,577

Current Assets
Cash and cash equivalents		2,592,801			4,488,366
Accounts receivable (less allowance for uncollectible
accounts of $952,075 and $661,597, respectively)		72,218,191			44,969,182
Accrued revenue		5,265,474			4,325,351
Propane inventory, at average cost		7,629,295			7,187,035
Other inventory, at average cost		1,280,506			1,564,937
Regulatory assets		1,575,072			1,275,653
Storage gas prepayments		6,042,169			7,393,335
Income taxes receivable		1,237,438			1,078,882
Deferred income taxes		2,155,393			1,365,316
Prepaid expenses		3,496,517			2,280,900
Mark-to-market energy assets		7,812,456			1,379,896
Other current assets		146,253			173,388
Total current assets		111,451,565			77,482,241

Deferred Charges and Other Assets
Goodwill		674,451			674,451
Other intangible assets, net		178,073			191,878
Long-term receivables		740,680			824,333
Regulatory assets		2,539,235			1,765,088
Other deferred charges		3,640,480			1,215,004
Total deferred charges and other assets		7,772,919			4,670,754







Total Assets	$	381,557,012		$	324,993,984

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

- Page 37 - -

Consolidated Balance Sheets

Capitalization and Liabilities	December 31, 2007			December 31, 2006

Capitalization
Stockholders' equity
Common Stock, par value $0.4867 per share
(authorized 12,000,000 shares)	$	3,298,473		$	3,254,998
Additional paid-in capital		65,591,552			61,960,220
Retained earnings		51,538,194			46,270,884
Accumulated other comprehensive loss		(851,674	)		(334,550	)
Deferred compensation obligation		1,403,922			1,118,509
Treasury stock		(1,403,922	)		(1,118,509	)
Total stockholders' equity		119,576,545			111,151,552

Long-term debt, net of current maturities		63,255,636			71,050,000
Total capitalization		182,832,181			182,201,552

Current Liabilities
Current portion of long-term debt		7,656,364			7,656,364
Short-term borrowing		45,663,944			27,553,941
Accounts payable		54,893,071			33,870,552
Customer deposits and refunds		10,036,920			7,502,265
Accrued interest		865,504			832,392
Dividends payable		1,999,343			1,939,482
Accrued compensation		3,400,112			2,901,053
Regulatory liabilities		6,300,766			4,199,147
Mark-to-market energy liabilities		7,739,261			1,371,379
Other accrued liabilities		2,500,542			2,634,416
Total current liabilities		141,055,827			90,460,991

Deferred Credits and Other Liabilities
Deferred income taxes		28,795,885			26,517,098
Deferred investment tax credits		277,698			328,277
Regulatory liabilities		1,136,071			1,236,254
Environmental liabilities		835,143			211,581
Other pension and benefit costs		2,513,030			1,608,311
Accrued asset removal cost		20,249,948			18,410,992
Other liabilities		3,861,229			4,018,928
Total deferred credits and other liabilities		57,669,004			52,331,441

Other Commitments and Contingencies (Note N)


Total Capitalization and Liabilities	$	381,557,012		$	324,993,984

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

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Consolidated Statements of Stockholders’ Equity

For the Years Ended December 31,	2007			2006			2005

Common Stock
Balance — beginning of year	$	3,254,998		$	2,863,212		$	2,812,538
Dividend Reinvestment Plan		17,197			18,685			20,038
Retirement Savings Plan		14,388			14,457			10,255
Conversion of debentures		3,945			8,117			11,004
Performance shares and options exercised (1)		7,945			14,536			9,377
Stock issuance		-			335,991			-
Balance — end of year		3,298,473			3,254,998			2,863,212

Additional Paid-in Capital
Balance — beginning of year		61,960,220			39,619,849			36,854,717
Dividend Reinvestment Plan		1,121,190			1,148,100			1,224,874
Retirement Savings Plan		934,295			900,354			682,829
Conversion of debentures		133,839			275,300			373,259
Performance shares and options exercised (1)		498,674			887,426			484,170
Stock-based compensation		943,334			-			-
Stock issuance		-			19,362,518			-
Exercise warrants, net of tax		-			(233,327	)		-
Balance — end of year		65,591,552			61,960,220			39,619,849

Retained Earnings
Balance — beginning of year		46,270,884			42,854,894			39,015,087
Net income		13,197,710			10,506,525			10,467,614
Cash dividends (2)		(7,930,400	)		(7,090,535	)		(6,627,807	)
Balance — end of year		51,538,194			46,270,884			42,854,894

Accumulated Other Comprehensive Income (Loss)
Balance — beginning of year		(334,550	)		(578,151	)		(527,246	)
Minimum pension liability adjustment, net of tax		28,106			74,036			(50,905	)
Gain (Loss) on funded status of Employee Benefit Plans, net of tax		(545,230	)		169,565			-
Balance — end of year		(851,674	)		(334,550	)		(578,151	)

Deferred Compensation Obligation
Balance — beginning of year		1,118,509			794,535			816,044
New deferrals		285,413			323,974			130,426
Payout of deferred compensation		-			-			(151,935	)
Balance — end of year		1,403,922			1,118,509			794,535

Treasury Stock
Balance — beginning of year		(1,118,509	)		(797,156	)		(1,008,696	)
New deferrals related to compensation obligation		(285,413	)		(323,974	)		(130,426	)
Purchase of treasury stock		(29,771	)		(51,572	)		(182,292	)
Sale and distribution of treasury stock		29,771			54,193			524,258
Balance — end of year		(1,403,922	)		(1,118,509	)		(797,156	)


Total Stockholders’ Equity	$	119,576,545		$	111,151,552		$	84,757,183

(1) Includes amounts for shares issued for Directors' compensation.
(2) Cash dividends declared per share for 2007, 2006 and 2005 were $1.18, $1.16 and $1.14, respectively.

Consolidated Statements of Comprehensive Income
Net income	$	13,197,710		$	10,506,525		$	10,467,614
Pension adjustments, net of tax of
$342,320, ($48,889) and $33,615, respectively		(517,124	)		74,036			(50,905	)
Comprehensive Income	$	12,680,586		$	10,580,561		$	10,416,709

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

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Consolidated Statements of Income Taxes

For the Years Ended December 31,	2007			2006			2005

Current Income Tax Expense
Federal	$	5,512,071		$	5,994,296		$	3,687,800
State		1,223,145			1,424,485			789,233
Investment tax credit adjustments, net		(50,579	)		(54,816	)		(54,816	)
Total current income tax expense		6,684,637			7,363,965			4,422,217

Deferred Income Tax Expense (1)
Property, plant and equipment		2,958,758			1,697,024			1,380,628
Deferred gas costs		(629,228	)		(2,085,066	)		1,064,310
Pensions and other employee benefits		(9,154	)		(97,436	)		(340,987	)
Environmental expenditures		45,872			(5,580	)		(98,229	)
Other		(464,322	)		(36,345	)		(115,923	)
Total deferred income tax expense (benefit)		1,901,926			(527,403	)		1,889,799
Total Income Tax Expense	$	8,586,563		$	6,836,562		$	6,312,016

Reconciliation of Effective Income Tax Rates
Continuing Operations
Federal income tax expense (2)	$	7,635,336		$	6,212,237		$	6,009,861
State income taxes, net of federal benefit		1,086,680		$	829,630		$	732,046
Other		(124,555	)	$	(42,795	)	$	(269,687	)
Total continuing operations	$	8,597,461		$	6,999,072		$	6,472,220
Discontinued operations	$	(10,898	)	$	(162,510	)	$	(160,204	)
Total income tax expense	$	8,586,563		$	6,836,562		$	6,312,016

Effective income tax rate		39.4	%		39.4	%		37.6	%

At December 31,	2007			2006

Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	31,058,050		$	27,997,744
Environmental costs		250,021			204,149
Other		860,993			870,424
Total deferred income tax liabilities		32,169,064			29,072,317

Deferred income tax assets:
Pension and other employee benefits		2,581,853			2,225,944
Self insurance		384,009			468,922
Deferred gas costs		1,146,133			528,814
Other		1,416,577			696,855
Total deferred income tax assets		5,528,572			3,920,535
Deferred Income Taxes Per Consolidated Balance Sheet	$	26,640,492		$	25,151,782

(1) Includes $260,000, ($60,000), and $146,000 of deferred state income taxes for the years 2007, 2006, and 2005, respectively.
(2) Federal income taxes were recorded at 35% for each year represented.

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

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A. Summary of Accounting Policies

Nature of Business

Chesapeake is engaged in natural gas distribution to 62,852 customers located in central and southern Delaware, Maryland’s Eastern Shore and Florida. The Company’s natural gas transmission subsidiary operates an interstate pipeline from various points in Pennsylvania and northern Delaware to the Company’s Delaware and Maryland distribution divisions as well as other utility and industrial customers in Pennsylvania, Delaware and the Eastern Shore of Maryland. The Company’s propane distribution and wholesale marketing segment provides distribution service to 34,143 customers in central and southern Delaware, the Eastern Shore of Maryland, southeastern Pennsylvania, central Florida and the Eastern Shore of Virginia and markets propane to wholesale customers including large independent oil and petrochemical companies, resellers and propane distribution companies in the southeastern United States. 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.

Principles of Consolidation

The Consolidated Financial Statements include the accounts of the Company and its wholly owned subsidiaries. The Company does not have any ownership interests in investments accounted for using the equity method or any variable interests in a variable interest entity. All intercompany transactions have been eliminated in consolidation.

System of Accounts

The natural gas distribution divisions of the Company located in Delaware, Maryland and Florida are subject to regulation by their respective PSCs with respect to their rates for service, maintenance of their accounting records and various other matters. Eastern Shore is an open access pipeline and is subject to regulation by the FERC. Our financial statements are prepared in accordance with GAAP, which give appropriate recognition to the ratemaking and accounting practices and policies of the various commissions. The propane, advanced information services and other business segments are not subject to regulation with respect to rates or maintenance of accounting records.

Property, Plant, Equipment and Depreciation

Utility and non-utility property is stated at original cost. Costs include direct labor, materials and third-party construction contractor costs, allowance for capitalized interest and certain indirect costs related to equipment and employees engaged in construction. The costs of repairs and minor replacements are charged against income as incurred, and the costs of major renewals and betterments are capitalized. Upon retirement or disposition of non-utility property, the gain or loss, net of salvage value, is charged to income. Upon retirement or disposition of utility property, the gain or loss, net of salvage value, is charged to accumulated depreciation. The provision for depreciation is computed using the straight-line method at rates that amortize the unrecovered cost of depreciable property over the estimated remaining useful life of the asset. Depreciation and amortization expenses are provided at an annual rate for each segment. The three-year average rates were three percent for natural gas distribution and transmission, five percent for propane, eleven percent for advanced information services and six percent for general plant.

At December 31,	2007	2006	Useful Life (1)
Plant in service
Mains	$166,202,413	$151,890,304	27-41 years
Services — utility	35,127,633	32,334,145	14-33 years
Compressor station equipment	24,959,330	24,921,976	28 years
Liquefied petroleum gas equipment	25,575,213	24,627,398	30-33 years
Meters and meter installations	18,111,466	16,093,737	Propane 10-33 years, Natural gas 26-44 years
Measuring and regulating station equipment	14,067,262	13,272,201	27-54 years
Office furniture and equipment	9,947,881	10,114,101	Non-regulated 3-10 years, Regulated 14-28 years
Transportation equipment	11,194,916	10,686,259	3-11 years
Structures and improvements	10,024,105	9,538,345	10-44 years (2)
Land and land rights	7,404,679	7,386,268	Not depreciable, except certain regulated assets
Propane bulk plants and tanks	5,313,061	5,301,457	15 - 40 years
Various	20,009,979	17,839,745	Various
Total plant in service	347,937,938	324,005,936
Plus construction work in progress	4,899,608	1,829,948
Less accumulated depreciation	(92,414,289)	(85,010,472)
Net property, plant and equipment	$260,423,257	$240,825,412

(1) Certain immaterial account balances may fall outside this range.

The regulated operations compute depreciation in accordance with rates approved by either the state Public Service Commission
or the FERC. These rates are based on depreciation studies and may change periodically upon receiving approval from the
appropriate regulatory body. The depreciation rates shown above are based on the remaining useful lives of the assets at the
time of the depreciation study, rather than their original lives. The depreciation rates are composite, straight-line rates applied
to the average investment for each class of depreciable property and are adjusted for anticipated cost of removal less salvage
value.

The non-regulated operations compute depreciation using the straight-line method over the estimated useful life of the asset.

(2) Includes buildings, structures used in connection with natural gas and propane operations, improvements to those facilities
and leasehold improvements.

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Cash and Cash Equivalents

The Company’s policy is to invest cash in excess of operating requirements in overnight income-producing accounts. Such amounts are stated at cost, which approximates market value. Investments with an original maturity of three months or less when purchased are considered cash equivalents.

Inventories

The Company uses the average cost method to value propane and materials and supplies inventory. If market prices drop below cost, inventory balances that are subject to price risk are adjusted to market values.

Regulatory Assets, Liabilities and Expenditures

The Company accounts for its regulated operations in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” This standard includes accounting principles for companies whose rates are determined by independent third-party regulators. When setting rates, regulators often make decisions, the economics of which require companies to defer costs or revenues in different periods than may be appropriate for unregulated enterprises. When this situation occurs, the regulated utility defers the associated costs as assets (regulatory assets) on the balance sheet and records them as expense on the income statement as it collects revenues. Further, regulators can also impose liabilities upon a company for amounts previously collected from customers, and for recovery of costs that are expected to be incurred in the future (regulatory liabilities).

At December 31, 2007 and 2006, the regulated utility operations had recorded the following regulatory assets and liabilities on the Balance Sheets. These assets and liabilities will be recognized as revenues and expenses in future periods as they are reflected in customers’ rates.

At December 31,	2007		2006
Regulatory Assets
Current
Underrecovered purchased gas costs	$	1,389,454	$	1,076,921
Conservation cost recovery		-		51,408
PSC Assessment		22,290		22,290
Flex rate asset		107,394		81,926
Other		55,934		43,108
Total current		1,575,072		1,275,653

Non-Current
Income tax related amounts due from customers		1,115,638		1,300,544
Deferred regulatory and other expenses		446,642		188,686
Deferred gas supply		15,201		15,201
Deferred post retirement benefits		111,159		138,949
Environmental regulatory assets and expenditures		850,594		121,708
Total non-current		2,539,234		1,765,088

Total Regulatory Assets	$	4,114,306	$	3,040,741

Regulatory Liabilities
Current
Self insurance — current	$	191,004	$	568,897
Overrecovered purchased gas costs		4,225,845		2,351,553
Shared interruptible margins		11,202		100,355
Conservation cost recovery		395,379		-
Operational flow order penalties		-		7,831
Swing transportation imbalances		1,477,336		1,170,511
Total current		6,300,766		4,199,147

Non-Current
Self insurance — long-term		757,557		600,787
Income tax related amounts due to customers		151,521		285,819
Environmental overcollections		226,993		349,648
Total non-current		1,136,071		1,236,254

Accrued asset removal cost		20,249,948		18,410,992

Total Regulatory Liabilities	$	27,686,785	$	23,846,393

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Included in the regulatory assets listed above are $107,000 of which is accruing interest. Of the remaining regulatory assets, $2.6 million will be collected in approximately one to two years, $293,000 will be collected within approximately 3 to 10 years, and $721,000 will be collected within approximately 11 to 15 years. In addition, there is approximately $466,000 for which the Company is awaiting regulatory approval for recovery, but once approved is expected to be collected within 12 months.

As required by SFAS No. 71, the Company monitors its regulatory and competitive environment to determine whether the recovery of its regulatory assets continues to be probable. If the Company were to determine that recovery of these assets is no longer probable, it would write off the assets against earnings. The Company believes that SFAS No. 71 continues to apply to its regulated operations, and that the recovery of its regulatory assets is probable.

Goodwill and Other Intangible Assets

The Company accounts for its goodwill and other intangibles under SFAS No. 142, “Goodwill and Other Intangible Assets.” Under SFAS No. 142, goodwill is not amortized but is tested for impairment at least annually. In addition, goodwill of a reporting unit is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives. Please refer to Note F “Goodwill and Other Intangible Assets” for additional discussions of this subject.

Other Deferred Charges

Other deferred charges include discount, premium and issuance costs associated with long-term debt. Debt costs are deferred and then are amortized to interest expense over the original lives of the respective debt issuances.

Income Taxes and Investment Tax Credit Adjustments

The Company files a consolidated federal income tax return. Income tax expense allocated to the Company’s subsidiaries is based upon their respective taxable incomes and tax credits.

Deferred tax assets and liabilities are recorded for the tax effect of temporary differences between the financial statements bases and tax bases of assets and liabilities and are measured using the enacted tax rates in effect in the years in which the differences are expected to reverse. The portions of the Company’s deferred tax liabilities applicable to utility operations, which have not been reflected in current service rates, represent income taxes recoverable through future rates. Deferred tax assets are recorded net of any valuation allowance when it is more likely than not that such tax benefits will be realized. Investment tax credits on utility property have been deferred and are allocated to income ratably over the lives of the subject property.

The Company adopted the provisions of FIN 48 “Accounting for Uncertainty in Income Taxes,” effective January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a Company’s financial statements in accordance with SFAS 109 “Accounting for Income Taxes.” FIN 48 requires that an uncertain tax position should be recognized only if it is “more likely than not” that the position is sustainable based on technical merits. Recognizable tax positions should then be measured to determine the amount of benefit recognized in the financial statements. The Company’s adoption of FIN 48 did not have an impact on its financial condition or results of operations.

Financial Instruments

Xeron, Inc. (“Xeron”), the Company’s propane wholesale marketing operation, engages in trading activities using forward and futures contracts, which have been accounted for using the mark-to-market method of accounting. Under mark-to-market accounting, the Company’s trading contracts are recorded at fair value, net of future servicing costs. The changes in market price are recognized as gains or losses in revenues on the income statement in the period of change. The resulting unrealized gains and losses are recorded as assets or liabilities, respectively. There were unrealized gains of $179,000 and $8,500 at December 31, 2007 and 2006, respectively. Trading liabilities are recorded in mark-to-market energy liabilities. Trading assets are recorded in mark-to-market energy assets.

The Company’s natural gas and propane distribution operations have entered into agreements with natural gas and propane suppliers to purchase gas for resale to their customers. Purchases under these contracts either do not meet the definition of derivatives of SFAS No. 133 or are considered “normal purchases and sales” under SFAS No. 138 and are accounted for on an accrual basis.

The propane distribution operation may enter into a fair value hedge of its inventory in order to mitigate the impact of wholesale price fluctuations. At December 31, 2007, the Company decided not to hedge any of its propane inventories. At December 31, 2006, the propane distribution operation had entered into a swap agreement to protect the Company from the impact of price increases on the price-cap plan that we offer to customers. The Company considered this agreement to be an economic hedge that did not qualify for hedge accounting as described in SFAS 133. At the end of the 2006, the market price of propane dropped below the unit price within the swap agreement. As a result of the price drop, the Company marked the agreement to market, which resulted in an unrealized loss of $84,000.

Earnings Per Share

Chesapeake calculates earnings per share in accordance with SFAS 128 “Earnings per Share.” The calculations of both basic and diluted earnings per share are presented in the following chart.

For the Periods Ended December 31,	2007		2006		2005
Calculation of Basic Earnings Per Share:
Net Income	$	13,197,710	$	10,506,525	$	10,467,614
Weighted average shares outstanding		6,743,041		6,032,462		5,836,463
Basic Earnings Per Share	$	1.96	$	1.74	$	1.79

Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	13,197,710	$	10,506,525	$	10,467,614
Effect of 8.25% Convertible debentures		95,611		105,024		123,559
Adjusted numerator — Diluted	$	13,293,321	$	10,611,549	$	10,591,173

Reconciliation of Denominator:
Weighted shares outstanding — Basic		6,743,041		6,032,462		5,836,463
Effect of dilutive securities
Warrants		-		-		11,711
8.25% Convertible debentures		111,675		122,669		144,378
Adjusted denominator — Diluted		6,854,716		6,155,131		5,992,552

Diluted Earnings Per Share	$	1.94	$	1.72	$	1.77

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Operating Revenues

Allowance for Doubtful Accounts

Certain Risks and Uncertainties

The Company’s financial statements are prepared in conformity with generally accepted accounting principles that require management to make estimates in measuring assets and liabilities and related revenues and expenses (see Notes M and N to the Consolidated Financial Statements for significant estimates). These estimates involve judgments with respect to, among other things, various future economic factors that are difficult to predict and are beyond the control of the Company; therefore, actual results could differ from those estimates.

The Company records certain assets and liabilities in accordance with SFAS No. 71. If the Company were required to terminate application of SFAS No. 71 for its regulated operations, all such deferred amounts would be recognized in the income statement at that time. This could result in a charge to earnings, net of applicable income taxes, which could be material.

FASB Statements and Other Authoritative Pronouncements

In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation (“FIN”) No. 48, “Employers’ Accounting for Uncertainty in Income Taxes.” This interpretation: (i) 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;” (ii) 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; and (iii) provides guidance on derecognition and classification of uncertain tax positions, reporting of interest and penalties, accounting in interim periods, disclosure, and transition. FIN No.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.

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. The Company does not expect SFAS No. 157 will have a material impact on its 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. The Company does not expect SFAS No. 159 will have a material impact 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 does not expect FSP FIN 39-1 will have a material impact its Consolidated Financial Statements.

Reclassification of Prior Years’ Amounts

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

B. Business Dispositions and Discontinued Operations

During the quarter ended September 30, 2007, Chesapeake decided to close its distributed energy services subsidiary, Chesapeake OnSight Services, LLC (“OnSight”), which has experienced operating losses since its inception in 2004. OnSight was previously reported as part of the Company’s Other business segment. At December 31, 2007, the results of operations for OnSight have been reclassified to discontinued operations and shown net of tax for all periods presented. For 2007, the discontinued operations experienced a net loss of $20,000, compared to a net loss of $241,000 for 2006 and a net loss of $231,000 for 2005.

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C. Segment Information

The following table presents information about the Company’s reportable segments. The table excludes financial data related to our distributed energy company, which was reclassed to discontinued operations for each year presented.

For the Years Ended December 31,	2007		2006		2005
Operating Revenues, Unaffiliated Customers
Natural gas distribution, transmission and marketing	$	180,842,699	$	170,114,512	$	166,388,562
Propane		62,837,696		48,575,976		48,975,349
Advanced information services		14,606,100		12,509,077		14,121,441
Other		-		-		-
Total operating revenues, unaffiliated customers	$	258,286,495	$	231,199,565	$	229,485,352

Intersegment Revenues (1)
Natural gas distribution, transmission and marketing	$	359,235	$	259,970	$	193,404
Propane		406		-		668
Advanced information services		492,840		58,532		18,123
Other		622,272		618,492		618,492
Total intersegment revenues	$	1,474,753	$	936,994	$	830,687

Operating Income
Natural gas distribution, transmission and marketing	$	22,485,266	$	19,733,487	$	17,235,810
Propane		4,497,843		2,534,035		3,209,388
Advanced information services		835,981		767,160		1,196,545
Other and eliminations		294,492		297,255		279,136
Operating Income		28,113,582		23,331,937		21,920,879
Other income		291,305		189,093		382,610
Interest charges		6,589,639		5,773,993		5,132,458
Income taxes		8,597,461		6,999,072		6,472,220
Net income from continuing operations	$	13,217,787	$	10,747,965	$	10,698,811

Depreciation and Amortization
Natural gas distribution, transmission and marketing	$	6,917,609	$	6,312,277	$	5,682,137
Propane		1,842,047		1,658,554		1,574,357
Advanced information services		143,706		112,729		122,569
Other and eliminations		156,823		160,155		189,146
Total depreciation and amortization	$	9,060,185	$	8,243,715	$	7,568,209

Capital Expenditures
Natural gas distribution, transmission and marketing	$	23,086,713	$	43,894,614	$	28,433,671
Propane		5,290,215		4,778,891		3,955,799
Advanced information services		174,184		159,402		294,792
Other		1,591,272		321,204		739,079
Total capital expenditures	$	30,142,384	$	49,154,111	$	33,423,341
(1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.

At December 31,	2007		2006		2005
Identifiable Assets
Natural gas distribution, transmission and marketing	$	273,500,890	$	252,292,600	$	225,667,049
Propane		94,966,212		60,170,200		57,344,859
Advanced information services		2,507,910		2,573,810		2,062,902
Other		10,533,511		10,503,804		10,911,229
Total identifiable assets	$	381,508,523	$	325,540,414	$	295,986,039

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Chesapeake uses the management approach to identify operating segments. Chesapeake 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 resources and to assess performance. The segments are evaluated based on their pre-tax operating income.

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

D. Fair Value of Financial Instruments

Various items within the balance sheet are considered to be financial instruments, because they are cash or are to be settled in cash. The carrying values of these items generally approximate their fair value (see Note E to the Consolidated Financial Statements for disclosure of fair value of investments). The Company’s open forward and futures contracts at December 31, 2007 had a gain of $179,000 and at December 31, 2006 had a gain in fair value of $8,500, based on market rates at the respective dates. The fair value of the Company’s long-term debt is estimated using a discounted cash flow methodology. The Company’s long-term debt at December 31, 2007, including current maturities, had an estimated fair value of $75.0 million as compared to a carrying value of $70.9 million. At December 31, 2006, the estimated fair value was approximately $81.4 million as compared to a carrying value of $78.7 million. These estimates are based on published corporate borrowing rates for debt instruments with similar terms and average maturities.

E. Investments

The investment balances at December 31, 2007 and 2006 represent a Rabbi Trust associated with the Company’s Supplemental Executive Retirement Savings Plan. In accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” the Company classifies these investments as trading securities. As a result 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 December 31, 2007 and 2006, total investments had a fair value of $1.9 million and $2.0 million, respectively.

F. Goodwill and Other Intangible Assets

In accordance with SFAS No. 142, goodwill is tested for impairment at least annually. In addition, goodwill of a reporting unit is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. The propane unit had $674,000 in goodwill for the two years ended December 31, 2007 and 2006. Testing for 2007 and 2006 has indicated that no impairment of the goodwill has occurred.

The carrying value and accumulated amortization of intangible assets subject to amortization for the years ended December 31, 2007 and 2006 are as follow:

	December 31, 2007				December 31, 2006
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer lists	$	115,333	$	82,269	$	115,333	$	75,057
Acquisition costs		263,659		118,649		263,659		112,057
Total	$	378,992	$	200,918	$	378,992	$	187,114

Amortization of intangible assets was $14,000 for the years ended December 31, 2007 and 2006. The estimated annual amortization of intangibles is $14,000 per year for each of the years 2008 through 2012.

G. Stockholders’ Equity

Changes in common stock shares issued and outstanding are shown in the table below:

For the Years Ended December 31,	2007		2006			2005
Common Stock shares issued and outstanding (1)
Shares issued — beginning of period balance		6,688,084		5,883,099			5,778,976
Dividend Reinvestment Plan (2)		35,333		38,392			41,175
Retirement Savings Plan		29,563		29,705			21,071
Conversion of debentures		8,106		16,677			22,609
Employee award plan		350		350			-
Performance shares and options exercised (3)		15,974		29,516			19,268
Public offering		-		690,345			-
Shares issued — end of period balance (4)		6,777,410		6,688,084			5,883,099

Treasury shares — beginning of period balance		-		(97	)		(9,418	)
Purchases		-		-			(4,852	)
Dividend Reinvestment Plan		-		-			2,142
Retirement Savings Plan		-		-			12,031
Other issuances		-		97			-
Treasury Shares — end of period balance		-		-			(97	)

Total Shares Outstanding		6,777,410		6,688,084			5,883,002

(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 Directors' compensation.
(4) Includes 57,309, 48,187, and 37,528 shares at December 31, 2007, 2006 and 2005, respectively, held in a Rabbi Trust established by the Company relating to the Deferred Compensation Plan.

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In 2000 and 2001, the Company entered into agreements with an investment banker to assist in identifying acquisition candidates. Under the agreements, the Company issued warrants to the investment banker to purchase 15,000 shares of Chesapeake stock in 2000, at an exercise price of $18.00 per share and 15,000 in 2001 at an exercise price of $18.25 per share. In August 2006, the investment banker exercised the 30,000 warrants pursuant to the terms of the agreement at $33.3657 per share. At the request of the investment banker, Chesapeake settled the warrants with a cash payment of $435,000, in lieu of issuing shares of the Company’s common stock. At December 31, 2007 and 2006, Chesapeake did not have any stock warrants outstanding.

On November 21, 2006, the Company completed a public offering of 600,300 shares of its common stock at a price per share of $30.10. On November 30, 2006, the Company completed the sale of 90,045 additional shares of its common stock, pursuant to the over-allotment option granted to the Underwriters by the Company. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $19.8 million, which were added to the Company’s general funds and used primarily to repay a portion of the Company’s short-term debt under unsecured lines of credit.

H. Long-term Debt

The Company’s outstanding long-term debt, net of current maturities, is as shown below.

At December 31,	2007	2006
Uncollateralized senior notes:
7.97% note, due February 1, 2008	$0	$1,000,000
6.91% note, due October 1, 2010	1,818,182	2,727,273
6.85% note, due January 1, 2012	3,000,000	4,000,000
7.83% note, due January 1, 2015	12,000,000	14,000,000
6.64% note, due October 31, 2017	24,545,454	27,272,727
5.50% note, due October 12, 2020	20,000,000	20,000,000
Convertible debentures:
8.25% due March 1, 2014	1,832,000	1,970,000
Promissory note	60,000	80,000
Total Long-Term Debt	$63,255,636	$71,050,000

Annual maturities of consolidated long-term debt for the next five years are as follows: $7,656,364 for 2008;
$6,656,364 for 2009,$6,656,364 for 2010, $7,747,273 for 2011, $6,727,273 for 2012.

The convertible debentures may be converted, at the option of the holder, into shares of the Company’s common stock at a conversion price of $17.01 per share. During 2007 and 2006, debentures totaling $138,000 and $284,000, respectively, were converted to stock. The debentures are also redeemable for cash at the option of the holder, subject to an annual non-cumulative maximum limitation of $200,000. In 2007 and 2006, no debentures were redeemed for cash. During 2005, debentures totaling $5,000 were redeemed for cash. At the Company’s option, the debentures may be redeemed at stated amounts.

On October 12, 2006, the Company issued $20 million of 5.5 percent Senior Notes to three institutional investors (The Prudential Insurance Company of America, Prudential Retirement Insurance and Annuity Company and United Omaha Life Insurance Company). The original note agreement was executed on October 18, 2005 and provided for the Company to sell the Notes at any time prior to January 15, 2007. The terms of the Notes require annual principal repayments of $2 million beginning on the fifth anniversary of the issuance of the Notes. The Notes will mature on October 12, 2020. The proceeds from this issuance were used to reduce a portion of the Company’s outstanding short-term debt.

Indentures to the long-term debt of the Company and its subsidiaries contain various restrictions. The most stringent restrictions state that the Company must maintain equity of at least 40 percent of total capitalization, and the pro-forma fixed charge coverage ratio must be 1.5 times. The Company is in compliance with all of its debt covenants.

I. Short-term Borrowing

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 December 31, 2007, Chesapeake had five unsecured bank lines of credit with three financial institutions, totaling $90.0 million, none of which requires compensating balances. These bank lines are available to provide funds for the Company’s short-term cash needs to meet seasonal working capital requirements and to fund temporarily portions of its capital expenditures. Three of the bank lines, totaling $25.0 million, are committed. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks. The outstanding balance of short-term borrowing at December 31, 2007 and 2006 was $45.7 million and $27.6 million, respectively. The annual weighted average interest rates on short-term debt were 5.46 percent and 5.47 percent for 2007 and 2006, respectively.

The Company also had a letter of credit outstanding with its primary insurance company in the amount of $775,000 as security to satisfy the deductibles under the Company’s various insurance policies. This letter of credit reduced the amounts available under the lines of credit and is scheduled to expire on May 31, 2008. The Company does not anticipate that this letter of credit will be drawn upon by the counterparty, and the Company expects that it will be renewed as necessary.

J. Lease Obligations

The Company has entered into several operating lease arrangements for office space at various locations, equipment and pipeline facilities. Rent expense related to these leases was $736,000, $680,000, and $837,000 for 2007, 2006, and 2005, respectively. Future minimum payments under the Company’s current lease agreements are $791,000, $668,000, $544,000, $531,000 and $636,000 for the years 2008 through 2012, respectively; and $2.3 million thereafter, with an aggregate total of $5.4 million.

K. Employee Benefit Plans

Retirement Plans

Before 1999, Company employees generally participated in both a defined benefit pension plan (“Defined Pension Plan”) and a Retirement Savings Plan. Effective January 1, 1999, the Company restructured its retirement program to compete more effectively with similar businesses. As part of this restructuring, the Company closed the Defined Pension Plan to new participants. Employees who participated in the Defined Pension Plan at that time were given the option of remaining in (and continuing to accrue benefits under) the Defined Pension Plan or receiving an enhanced matching contribution in the Retirement Savings Plan.

Because the Defined Pension Plan was not open to new participants, the number of active participants in that plan decreased and is approaching the minimum number needed for the Defined Pension Plan to maintain its tax-qualified status. To avoid jeopardizing the tax-qualified status of the Defined Pension Plan, the Company’s Board of Directors amended the Defined Pension Plan on September 24, 2004. To ensure that the Company continues to provide appropriate levels of benefits to the Company’s employees, the Board amended the Defined Pension Plan and the Retirement Savings Plan, effective January 1, 2005, so that Defined Pension Plan participants who were actively employed by the Company on that date: (1) receive two additional years of benefit service credit to be used in calculating their Defined Pension Plan benefit (subject to the Defined Pension Plan’s limit of 35 years of benefit service credit), (2) have the option to receive their Defined Pension Plan benefit in the form of a lump sum at the time they retire, and (3) are eligible to receive the enhanced matching contribution in the Retirement Savings Plan. In addition, effective January 1, 2005, the Board amended the Defined Pension Plan so that participants will not accrue any additional benefits under that plan. These changes were communicated to the Company’s employees during the first week of November 2004.

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In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS 158). The Company adopted SFAS 158 prospectively on December 31, 2006. SFAS 158 requires that we recognize all obligations related to defined benefit pensions and other postretirement benefits. This statement requires that we quantify the plans’ funded status as an asset or a liability on our consolidated balance sheets.

SFAS 158 requires that we measure the plans’ assets and obligations that determine our funded status as of the end of the fiscal year. The Company is also required to recognize as a component of accumulated other comprehensive income (“AOCI”) the changes in funded status that occurred during the year that are not recognized as part of net periodic benefit cost, as explained in SFAS No. 87, “Employers’ Accounting for Pensions,” or SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.”

At December 31, 2007, the funded status of the Company’s Defined Pension Plan was a liability of $274,739; at December 31, 2006 it was an asset of $590,560. In order to account for the liability and decrease in the funded status in accordance with FAS 158, the Company took a charge of $568,316, net of tax, to Comprehensive Income. In addition, the funded status of the postretirement health and life insurance plan was a liability of $1.756 million at December 31, 2007 compared to $1.763 million at December 31, 2006. To adjust for the reduced liability for the postretirement health and life insurance plan, as required by FAS 158, the Company recorded income of $23,086, net of tax, to Comprehensive Income.

The amounts in AOCI for the respective retirement plans that are expected to be recognized as a component of net benefit cost in 2008 are set forth in the following table.


	Defined	Executive Excess	Other
	Benefit	Defined Benefit	Postretirement
	Pension	Pension	Benefit
Prior service cost (credit)	$(4,699)	-	-
Loss (gain)	-	$46,444	$130,973

Defined Benefit Pension Plan

As described above, effective January 1, 2005, the Defined Pension Plan was frozen with respect to additional years of service or additional compensation. Benefits under the plan were based on each participant’s years of service and highest average compensation, prior to the freeze. The Company’s funding policy provides that payments to the trustee shall be equal to the minimum funding requirements of the Employee Retirement Income Security Act of 1974. The Company does not expect to be required to make any funding payments to the Defined Pension Plan in 2008. The measurement dates for the Pension Plan were December 31, 2007 and 2006.

The following schedule summarizes the assets of the Defined Pension Plan, by investment type, at December 31, 2007, 2006 and 2005:

At December 31,	2007		2006		2005
Asset Category
Equity securities	49.03	%	77.34	%	76.12	%
Debt securities	50.26	%	18.59	%	23.28	%
Other	0.71	%	4.07	%	0.60	%
Total	100.00	%	100.00	%	100.00	%

The asset listed as “Other” in the above table represents monies temporarily held in money market funds. The money market fund invests at least 80 percent of its total assets in:

·	United States Government obligations; and

·	Repurchase agreements that are fully collateralized by such obligations.

The investment policy of the Plan calls for an allocation of assets between equity and debt instruments with equity being 60 percent and debt at 40 percent, but allowing for a variance of 20 percent in either direction. In addition, as changes are made to holdings, cash, money market funds or United States Treasury Bills may be held temporarily by the fund. Investments in the following are prohibited: options, guaranteed investment contracts, real estate, venture capital, private placements, futures, commodities, limited partnerships and Chesapeake stock; short selling and margin transactions are prohibited as well. During 2004, Chesapeake modified its investment policy to allow the Employee Benefits Committee to reallocate investments to better match the expected life of the plan.

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The following schedule sets forth the funded status of the Defined Pension Plan at December 31, 2007, 2006 and 2005:

At December 31,	2007			2006			2005
Change in benefit obligation:
Benefit obligation — beginning of year	$	11,449,725		$	12,399,621		$	12,053,063
Interest cost		622,057			635,877			645,740
Change in assumptions		-			(301,851	)		388,979
Actuarial loss		282,684			607			28,895
Benefits paid		(1,280,946	)		(1,284,529	)		(717,056	)
Benefit obligation — end of year		11,073,520			11,449,725			12,399,621

Change in plan assets:
Fair value of plan assets — beginning of year		12,040,287			11,780,866			12,097,248
Actual return on plan assets		39,440			1,543,950			400,674
Benefits paid		(1,280,946	)		(1,284,529	)		(717,056	)
Fair value of plan assets — end of year		10,798,781			12,040,287			11,780,866

Reconciliation of funded status: (1)
Plan assets in excess (less than) benefit obligation at year-end		(274,739	)		590,560			(618,755	)
Unrecognized prior service cost		-			-			(34,259	)
Unrecognized net actuarial gain		-			-			(129,739	)
Net amount accrued	$	(274,739	)	$	590,560		$	(782,753	)

Assumptions:
Discount rate		5.50	%		5.50	%		5.25	%
Expected return on plan assets		6.00	%		6.00	%		6.00	%

(1) After the adoption of SFAS 158 on December 31, 2006, these amounts are recorded and this reconciliation is no longer required.

The Company reviewed the assumptions used for the discount rate to calculate the benefit obligation of the plan and has elected to maintain the rate at 5.50 percent, reflecting relatively no change in the interest rates of high quality bonds and reflecting the expected life of the plan, in light of the lump sum payment option. In addition, the average expected return on plan assets for the Defined Pension Plan remained constant at six percent due to the adoption of a change in the investment policy that allows for a higher level of investment in bonds and a lower level of equity investments. Since the Plan is frozen in regard additional years of service and compensation, the rate of assumed compensation rate increases is not applicable. The accumulated benefit obligation was $11.1 million and $11.4 million at December 31, 2007 and 2006, respectively.

Net periodic pension benefit for the Defined Pension Plan for 2007, 2006, and 2005 include the components as shown below:

For the Years Ended December 31,	2007	2006	2005
Components of net periodic pension cost:
Interest cost	$622,057	$635,877	$645,740
Expected return on assets	(696,398)	(690,533)	(703,285)
Amortization of:
Prior service cost	(4,699)	(4,699)	(4,699)
Net periodic pension benefit	($79,040)	($59,355)	($62,244)

Assumptions:
Discount rate	5.50%	5.25%	5.50%
Expected return on plan assets	6.00%	6.00%	6.00%

Executive Excess Defined Benefit Pension Plan

The Company also provides an unfunded executive excess defined benefit pension plan (“Pension SERP”). As noted above, this plan was frozen with respect to additional years of service and additional compensation as of December 31, 2004. Benefits under the plan were based on each participant’s years of service and highest average compensation, prior to the freeze. The accumulated benefit obligation was $2.32 million and $2.29 million at December 31, 2007 and 2006, respectively.

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The following schedule sets forth the status of the Pension SERP:

At December 31,	2007			2006			2005
Change in benefit obligation:
Benefit obligation — beginning of year	$	2,286,970		$	2,322,471		$	2,162,952
Interest cost		123,361			119,588			119,658
Actuarial (gain) loss		5,123			(65,886	)		133,839
Benefits paid		(89,204	)		(89,203	)		(93,978	)
Benefit obligation — end of year		2,326,250			2,286,970			2,322,471

Change in plan assets:
Fair value of plan assets — beginning of year		-			-			-
Employer contributions		89,204			89,203			93,978
Benefits paid		(89,204	)		(89,203	)		(93,978	)
Fair value of plan assets — end of year		-			-			-

Funded status		(2,326,250	)		(2,286,970	)		(2,322,471	)
Unrecognized net actuarial loss		-			-			959,492
Net amount accrued (1)	$	(2,326,250	)	$	(2,286,970	)	$	(1,362,979	)

Assumptions:
Discount rate		5.50	%		5.50	%		5.25	%

(1) After the adoption of SFAS 158 on December 31, 2006, these amounts are recorded and this reconciliation is no longer required.

The Company reviewed the assumptions used for the discount rate of the plan to calculate the benefit obligation and has elected to maintain the rate at 5.50 percent, reflecting relatively no change in the interest rates of high quality bonds and a reduction in the expected life of the plan. Since the Plan is frozen in regard to additional years of service and compensation, the rate of assumed pay rate increases is not applicable. The measurement dates for the Pension SERP were December 31, 2007 and 2006.

Net periodic pension costs for the Pension SERP for 2007, 2006, and 2005 include the components as shown below:

For the Years Ended December 31,	2007			2006			2005
Components of net periodic pension cost:
Service cost	$	0		$	0		$	0
Interest cost		123,361			119,588			119,658
Amortization of:
Actuarial loss		51,734			57,039			49,319
Net periodic pension cost	$	175,095		$	176,627		$	168,977

Assumptions:
Discount rate		5.50	%		5.25	%		5.50	%

Other Postretirement Benefits

The Company sponsors a defined benefit postretirement health care and life insurance plan that covers substantially all employees. The following schedule sets forth the status of the postretirement health care and life insurance plan:

At December 31,	2007			2006			2005
Change in benefit obligation:
Benefit obligation — beginning of year	$	1,763,108		$	1,534,684		$	1,599,280
Retirees		56,123			264,470			(59,152	)
Fully-eligible active employees		21,012			(114,082	)		(31,761	)
Other active		(84,679	)		78,036			26,317
Benefit obligation — end of year	$	1,755,564		$	1,763,108		$	1,534,684

Change in plan assets:
Fair value of plan assets — beginning of year		-			-			-
Employer contributions		243,660			300,360			89,238
Plan participant's contributions		100,863			94,914			72,866
Benefits paid		(344,523	)		(395,274	)		(162,104	)
Fair value of plan assets — end of year		-			-			-


Funded status	$	(1,755,564	)	$	(1,763,108	)	$	(1,534,684	)
Unrecognized transition obligation		-			-			22,282
Unrecognized net actuarial loss		-			-			751,450
Net amount accrued (1)	$	(1,755,564	)	$	(1,763,108	)	$	(760,952	)

Assumptions:
Discount rate		5.50	%		5.50	%		5.25	%

(1) After the adoption of SFAS 158 on December 31, 2006, these amounts are recorded and this reconciliation is no longer required.

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Net periodic postretirement costs for 2007, 2006 and 2005 include the following components:

For the Years Ended December 31,	2007		2006		2005
Components of net periodic postretirement cost:
Service cost	$	6,203	$	9,194	$	6,257
Interest cost		101,776		93,924		77,872
Amortization of:
Transition obligation		-		22,282		27,859
Actuarial loss		166,423		144,694		88,291
Net periodic postretirement cost	$	274,402	$	270,094	$	200,279

The health care inflation rate for 2007 to calculate the benefit obligation is assumed to be 5.5 percent for medical and 7 percent for prescription drugs. These rates are projected to decrease to ultimate rates of five and six percent, respectively, by the year 2009. A one percentage point increase in the health care inflation rate from the assumed rate would increase the accumulated postretirement benefit obligation by approximately $242,000 as of January 1, 2008, and would increase the aggregate of the service cost and interest cost components of the net periodic postretirement benefit cost for 2008 by approximately $15,000. A one percentage point decrease in the health care inflation rate from the assumed rate would decrease the accumulated postretirement benefit obligation by approximately $200,000 as of January 1, 2008, and would decrease the aggregate of the service cost and interest cost components of the net periodic postretirement benefit cost for 2008 by approximately $12,000. The measurement dates were December 31, 2007 and 2006.

Estimated Future Benefit Payments

The schedule below shows the estimated future benefit payments for each of the years 2008 through 2012 and the aggregate of the next five years for each of the plans previously described.

	Defined Benefit Pension Plan (1)		Executive Excess Defined Benefit Pension Plan (2)		Other Post-Retirement Benefits (2)
2008	$	734,940	$	87,959	$	196,449
2009		1,363,074		86,586		199,250
2010		921,490		85,081		208,938
2011		437,213		83,444		195,679
2012		1,332,896		113,415		204,524
Years 2013 through 2017		3,755,455		835,415		1,081,460

(1) The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.
(2) Benefit payments are expected to be paid out of the general funds of the Company.

Retirement Savings Plan

The Company sponsors a 401(k) Retirement Savings Plan, which provides participants a mechanism for making contributions for retirement savings. Each participant may make pre-tax contributions of up to 15 percent of eligible base compensation, subject to Internal Revenue Service limitations. These participants were eligible for the enhanced matching described below, effective January 1, 2005.

Effective January 1, 1999, the Company began offering an enhanced 401(k) Plan to all new employees, as well as existing employees who elected to no longer participate in the Defined Pension Plan. The Company makes matching contributions of up to six percent of each employee's pre-tax compensation for the year, except for the employees of our Advanced Information Services segment. The match is between 100 percent and 200 percent of the employee’s contribution, based on the employee’s age and years of service. The first 100 percent is matched with Chesapeake common stock. The remaining match is invested in the Company’s 401(k) Plan according to each employee’s election options.

Effective July 1, 2006, the Company’s contribution made on behalf of Advanced Information Services segment employees, is a 50 percent matching contribution, up to six percent of the employee’s annual compensation. The matching contribution is funded in Chesapeake common stock. The Plan was also amended at the same time to enable it to receive discretionary profit-sharing contributions in the form of employee pre-tax deferrals. The extent to which the Advanced Information Services segment has any dollars available for profit-sharing is dependent upon the extent to which actual earnings exceed budgeted earnings. Any profit-sharing dollars made available to employees can be deferred into the Plan and/or paid out in the form of a bonus.

On December 1, 2001, the Company converted the 401(k) fund holding Chesapeake stock to an Employee Stock Ownership Plan (“ESOP”).

Effective January 1, 1999, the Company began offering a non-qualified supplemental employee retirement savings plan (“401(k) SERP”) open to Company executives over a specific income threshold. Participants receive cash only matching contribution percentage equivalent to their 401(k) match level. All contributions and matched funds can be invested among the twenty-one mutual funds available for investment. These same funds are available for investment of employee contributions within the Retirement Savings Plan. All obligations arising under the 401(k) SERP are payable from the general assets of Chesapeake, although Chesapeake has established a Rabbi Trust to help pay benefits under the 401(k) SERP. As discussed further in Note E – “Investments,” to the Consolidated Financial Statements, the assets held in the Rabbi Trust had a fair value of $1.9 million and $2.0 million at December 31, 2007 and 2006, respectively. The assets of the Rabbi Trust are at all times subject to the claims of Chesapeake’s general creditors.

The Company’s contributions to the 401(k) plans totaled $1.48 million, $1.61 million, and $1.68 million for the years ended December 31, 2007, 2006, and 2005, respectively. As of December 31, 2007, there are 47,916 shares reserved to fund future contributions to the Retirement Savings Plan.

Deferred Compensation Plan

On December 7, 2006, the Board of Directors approved the Chesapeake Utilities Corporation Deferred Compensation Plan (“Deferred Compensation Plan”), as amended, effective January 1, 2007. The Deferred Compensation Plan is a non-qualified, deferred compensation arrangement under which certain executives and members of the Board of Directors are able to defer payment of part or all of certain specified types of compensation, including executive cash bonuses, executive performance shares, and directors' fees. At December 31, 2007, the Deferred Compensation Plan consists solely of shares of common stock related to the deferral of executive performance shares and directors’ stock retainers.

Participants in the Deferred Compensation Plan are able to elect the payment of benefits to begin on a specified future date after the election is made in the form of a lump sum or annual installments. Deferrals of executive cash bonuses and directors’ cash retainers and fees shall be paid in cash. All deferrals of executive performance shares and directors’ stock retainers shall be paid in shares of the Company’s common stock, except that cash shall be paid in lieu of fractional shares.

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The Company established a Rabbi Trust in connection with the Deferred Compensation Plan. The value of the Company’s stock held in the Rabbi Trust is classified within the stockholders’ equity section of the Balance Sheet and has been accounted for in a manner similar to treasury stock. The amounts recorded under the Deferred Compensation Plan totaled $1.4 million and $1.1 million at December 31, 2007 and 2006, respectively.

L. Share-Based Compensation Plans

The Company accounts for its share-based compensation arrangements under SFAS No. 123 (revised 2004), “Share Based Payments” (“SFAS 123R”), which requires companies to record compensation costs for all share-based awards over the respective service period for 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, for the restricted stock awards issued under the DSCP and the PIP.

For the year ended December 31,	2007		2006		2005

Directors Stock Compensation Plan	$	110,360	$	100,860	$	83,980
Performance Incentive Plan		493,510		332,110		439,580

Amounts included in net income, after tax	$	603,870	$	432,970	$	523,560

Stock Options

The Company did not have any stock options outstanding at December 31, 2007 or December 31, 2006, nor were any stock options issued during 2007 and 2006.

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 a service period of one year.

A summary of restricted stock activity under the DSCP for the three years of 2007, 2006, and 2005 is presented below:


	Number of Restricted Shares		Weighted Average Grant Date Fair Value
Outstanding — December 31, 2004		-
Issued — May 5, 2005		5,850	$	24.68
Vested		5,850
Outstanding — December 31, 2005		-
Issued — May 2, 2006		5,850	$	30.02
Vested		5,850
Outstanding — December 31, 2006		-
Issued — May 2, 2007		5,850	$	31.38
Vested		5,850
Outstanding — December 31, 2007		-

Compensation expense related to DSCP awards recorded by the Company for the years 2007, 2006, and 2005 is presented in the following table:

For the year ended December 31,	2007	2006	2005

Compensation expense for DSCP	$ 180,920	$ 165,340	$ 137,670

As of December 31, 2007, there were 57,450 shares reserved for issuance under the terms of the Company’s DSCP.

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 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.

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A summary of restricted stock activity under the PIP for the three years of 2007, 2006, and 2005 is presented below:

	Number of Restricted Shares		Weighted Average Grant Date Fair Value
Outstanding — December 31, 2004		-
Issued — February 24, 2005		10,130	$	27.00
Vested		10,130
Outstanding — December 31, 2005		-
Issued — February 23, 2006		23,666	$	30.40
Vested		23,666
Outstanding — December 31, 2006		-
Issued — March 1, 2007		10,124	$	30.89
Vested		10,124
Outstanding — December 31, 2007		-

Compensation expense related to the PIP recorded by the Company during the three years of 2007, 2006, and 2005 is presented in the following table:

For the year ended December 31,	2007	2006	2005

Compensation expense for PIP	$ 809,030	$ 544,450	$ 720,630

As of December 31, 2007, there were 389,876 shares reserved for issuance under the terms of the Company’s PIP.

M. Environmental Commitments and Contingencies

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

In 2004, Chesapeake received a Certificate of Completion for the remedial work performed at a former manufactured gas plant site located in Dover, Delaware. Chesapeake is also currently participating in the investigation, assessment or remediation of two additional former manufactured gas plant sites located in Maryland and Florida. The Company has accrued liabilities for the three sites referred to, respectively, as the Dover Gas Light, Salisbury Town Gas Light and the Winter Haven Coal Gas sites. The Company has been in discussions with the Maryland Department of the Environment (“MDE”) regarding a fourth former manufactured gas plant site located in Cambridge, Maryland. The following discussion provides details 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 December 31, 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 December 2007 from other parties or through rates. As of December 31, 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 December 31, 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 $1.88 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 $1.02 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 with the FDEP an AS/SVE Pilot Study Work Plan (the “Work Plan”) for the Winter Haven Coal Gas site. After discussions with the FDEP, the Company filed a modified Work Plan, which contained a description of the scope of work to complete the site assessment activities and a report describing a limited sediment investigation performed in 1997. In December 1998, the FDEP approved the modified Work Plan, which the Company completed during the third quarter of 1999. In February 2001, the Company filed a Remedial Action Plan (“RAP”) with the FDEP to address the contamination of the subsurface soil and ground-water in a portion of the site. The FDEP approved the RAP on May 4, 2001. Construction of the AS/SVE system was completed in the fourth quarter of 2002, and the system remains fully operational.

In the third quarter of 2007, the Company performed an updated environmental review of this site, including a review of any potential liabilities related to the investigation and remediation actions. Based on this review, the Company increased its liability by approximately $700,000 for the updated estimate of costs to remediate this site. Through December 31, 2007, the Company has incurred approximately $1.8 million of environmental costs associated with this site. At December 31, 2007, the Company had accrued a liability of $835,000 related to this site, offsetting (a) $15,000 collected through rates in excess of costs incurred and (b) a regulatory asset of approximately $851,000, representing the uncollected portion of the estimated clean-up costs. The Company expects to recover the remaining clean-up costs through rates.

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

Other

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

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N. 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. PESCO is currently in the process of obtaining and reviewing supply proposals from suppliers and anticipates executing agreements prior to the existing contracts.

Corporate Guarantees

The Company has issued corporate guarantees to certain vendors of its propane wholesale marketing subsidiary and its Florida natural gas supply management subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of either subsidiary’s default. The liabilities for these purchases are recorded in the Consolidated Financial Statements when incurred. The aggregate amount guaranteed at December 31, 2007 totaled $24.2 million, with the guarantees expiring on various dates in 2008. No guarantees were recorded by the Company in 2007.

Internal Revenue Service Audit

In November 2007, the Company was notified by the Internal Revenue Service (“IRS”) that its consolidated federal income tax return for the year ended December 31, 2005 has been selected for examination. The IRS audit is ongoing and is expected to be completed in the second quarter of 2008. The outcome of this audit cannot be determined at this time; therefore, the Company has not recorded any reserves for potential assessments that may result from the examination.

Other

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

O. Quarterly Financial Data (Unaudited)

In the opinion of the Company, the quarterly financial information shown below includes all adjustments necessary for a fair presentation of the operations for such periods and to disclose OnSight as a discontinued operation. The quarterly information shown has been adjusted to reflect the reclassification of OnSight’s operations for all periods presented. Due to the seasonal nature of the Company’s business, there are substantial variations in operations reported on a quarterly basis.

For the Quarters Ended	March 31		June 30		September 30			December 31
2007
Operating Revenue	$	93,526,891	$	52,501,920	$	41,418,718		$	70,838,968
Operating Income	$	14,613,572	$	3,698,066	$	985,634		$	8,816,310
Net Income (Loss)	$	7,991,088	$	1,481,791	$	(355,898	)	$	4,080,730
Earnings per share:
Basic	$	1.19	$	0.22	$	(0.05	)	$	0.60
Diluted	$	1.18	$	0.22	$	(0.05	)	$	0.60

2006
Operating Revenue	$	90,950,160	$	44,303,239	$	35,141,531		$	60,804,636
Operating Income	$	11,535,195	$	3,303,448	$	322,672		$	8,170,621
Net Income (Loss)	$	6,096,416	$	1,132,509	$	(656,579	)	$	3,934,179
Earnings per share:
Basic	$	1.03	$	0.19	$	(0.11	)	$	0.63
Diluted	$	1.01	$	0.19	$	(0.11	)	$	0.62

Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure.

On March 20, 2007, the Audit Committee of the Board of Directors of Chesapeake Utilities Corporation (the “Company”) dismissed PricewaterhouseCoopers LLP (“PwC”) as the Company's independent registered public accounting firm.

The reports of PwC on the consolidated financial statements of the Company for the years ended December 31, 2006 and 2005 did not contain an adverse opinion or a disclaimer of opinion, nor were they qualified or modified as to uncertainty, audit scope, or accounting principle.

During the years ended December 31, 2006 and 2005 and through March 20, 2007, there have been no (a) disagreements, as described under Item 304(a)(1)(iv) of Regulation S-K, with PwC on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of PwC, would have caused PwC to make reference thereto in their reports on the Company’s consolidated financial statements for such years, or (b) reportable events, as described under Item 304(a)(1)(v) of Regulation S-K.

The Company engaged Beard Miller Company LLP as its new independent registered public accounting firm. During the years ended December 31, 2006 and 2005 and through March 20, 2007, the Company had not consulted with Beard Miller Company LLP on any matters or events described in Item 304(a)(2) (i) and (ii) of Regulation S-K.

Item 9A. 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 Rule 13a-15(e) and 15d – 15(e) promulgated under the Securities Exchange Act of 1934, as amended) as of December 31, 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 December 31, 2007.

Changes in Internal Controls

There has been no change in internal control over financial reporting (as such term is defined in Exchange Act Rule 13a-15(f)) that occurred during the quarter ended December 31, 2007, that materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

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CEO and CFO Certifications

The Company’s Chief Executive Officer as well as the Senior Vice President and Chief Financial Officer have filed with the Securities and Exchange Commission the certifications required by Section 302 of the Sarbanes-Oxley Act of 2002 as Exhibits 31.1 and 31.2 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007. In addition, on May 27, 2007, the Company’s CEO certified to the New York Stock Exchange that he was not aware of any violation by the Company of the NYSE corporate governance listing standards.

Management’s Report on Internal Control Over Financial Reporting

The report of management required under this Item 9A is contained in Item 8 of this Form 10-K under the caption “Management’s Report on Internal Control over Financial Reporting.”

Our independent auditors, Beard Miller Company LLP, have audited and issued their report on effectiveness of the Company’s internal control over financial reporting. That report appears below.

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Report of Independent Registered Public Accounting Firm

________

To the Board of Directors and

Stockholders of Chesapeake Utilities Corporation

We have audited Chesapeake Utilities Corporation’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Chesapeake Utilities Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Chesapeake Utilities Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Chesapeake Utilities Corporation as of December 31, 2007, and the related consolidated statements of income, stockholders’ equity, comprehensive income, cash flows and income taxes for the year then ended, and our report dated March 10, 2008 expressed an unqualified opinion.

/s/ Beard Miller Company LLP

————————————————

Beard Miller Company LLP

Reading, Pennsylvania

March 10, 2008

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Item 9B. Other Information.

None

Part III

Item 10. Directors, Executive Officers of the Registrant and Corporate Governanace.

The information required by this Item is incorporated herein by reference to the portions of the Proxy Statement, captioned “Proposal I – Election of Directors,” “Information Regarding the Board of Directors and Nominees,” “Corporate Governance Practices and Stockholder Communications – Nomination of Directors,” “Committees of the Board – Audit Committee” and “Section 16(a) Beneficial Ownership Reporting Compliance” to be filed not later than March 31, 2008 in connection with the Company’s Annual Meeting to be held on May 1, 2008.

The information required by this Item with respect to executive officers is, pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, set forth in this report following Item 4, as Item 4A, under the caption “Executive Officers of the Company.”

The Company has adopted a Code of Ethics for Financial Officers, which applies to its principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions. The information set forth under Item 1 hereof concerning the Code of Ethics for Financial Officers is incorporated herein by reference.

Item 11. Executive Compensation.

The information required by this Item is incorporated herein by reference to the portion of the Proxy Statement captioned “Director Compensation,” “Executive Compensation” and “Compensation Discussion and Analysis” in the Proxy Statement to be filed not later than March 31, 2008, in connection with the Company’s Annual Meeting to be held on May 1, 2008.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required by this Item is incorporated herein by reference to the portion of the Proxy Statement captioned “Beneficial Ownership of Chesapeake’s Securities” to be filed not later than March 31, 2008 in connection with the Company’s Annual Meeting to be held on May 1, 2008.

The following table sets forth information, as of December 31, 2007, with respect to compensation plans of Chesapeake and its subsidiaries, under which shares of Chesapeake common stock are authorized for issuance:

( a )

( b )

( c )

Number of securities to be issued upon exercise of outstanding options, warrants and rights

Weighted-average exercise price of outstanding options, warrants and rights

Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)

Equity compensation plans approved by security holders

(1)

471,626

(2)

Equity compensation plans not approved by security holders

(3)

Total

(1) All options to purchase shares under the 1992 Performance Incentive Plan, as amended, were exercised as of 12/31/05.

(2) Includes 389,876 shares under the 2005 Performance Incentive Plan, 57,450 shares available under the 2005 Directors Stock Compensation Plan, and 24,300 shares available under the 2005 Employee Stock Awards Plan.

(3) All warrants were exercised in 2006.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

None

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Item 14. Principal Accounting Fees and Services.

The information required by this Item is incorporated herein by reference to the portion of the Proxy Statement captioned “Fees and Services of the Independent Public Accounting Firm” to be filed not later than March 31, 2008, in connection with the Company’s Annual Meeting to be held on May 1, 2008.

Part IV

Item 15. Exhibits, Financial Statement Schedules.

(a) The following documents are filed as part of this report:

1. Financial Statements:

·	Report of Independent Registered Public Accounting Firm;

·	Consolidated Statements of Income for each of the three years ended December 31, 2007, 2006 and 2005;

·	Consolidated Balance Sheets at December 31, 2007 and December 31, 2006;

·	Consolidated Statements of Cash Flows for each of the three years ended December 31, 2007, 2006, and 2005;

·	Consolidated Statements of Common Stockholders’ Equity for each of the three years ended December 31, 2007, 2006, and 2005;

·	Consolidated Statements of Comprehensive Income for each of the three years ended December 31, 2007, 2006, and 2005;

·	Consolidated Statements of Income Taxes for each of the three years ended December 31,2007, 2006, and 2005;

·	Notes to the Consolidated Financial Statements.

Financial Statement Schedule:

·	Report of Independent Registered Public Accounting Firm; and

·	Schedule II - Valuation and Qualifying Accounts.

All other schedules are omitted, because they are not required, are inapplicable or the information is otherwise shown in the financial statements or notes thereto.

3. Exhibits

· Exhibit 1.1

Underwriting Agreement entered into by Chesapeake Utilities Corporation and Robert W. Baird & Co. Incorporated and A.G. Edwards & Sons, Inc., on November 15, 2007, relating to the sale and issuance of 600,300 shares of the Company’s common stock, is incorporated herein by reference to Exhibit 1.1 of the Company’s Current Report on Form 8-K, filed November 16, 2007, File No. 001-11590.

· Exhibit 3.1

Restated Certificate of Incorporation of Chesapeake Utilities Corporation is incorporated herein by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 1998, File No. 001-11590.

· Exhibit 3.2

Amended and Restated Bylaws of Chesapeake Utilities Corporation, effective December 12, 2007, is filed herewith.

· Exhibit 4.1

Form of Indenture between the Company and Boatmen’s Trust Company, Trustee, with respect to the 8 1/4% Convertible Debentures is incorporated herein by reference to Exhibit 4.2 of the Company’s Registration Statement on Form S-2, Reg. No. 33-26582, filed on January 13, 1989.

· Exhibit 4.2

Note Agreement dated February 9, 1993, by and between the Company and Massachusetts Mutual Life Insurance Company and MML Pension Insurance Company, with respect to $10 million of 7.97% Unsecured Senior Notes due February 1, 2008, is incorporated herein by reference to Exhibit 4 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1992, File No. 0-593.

· Exhibit 4.3

Note Purchase Agreement, entered into by the Company on October 2, 1995, pursuant to which the Company privately placed $10 million of its 6.91% Senior Notes, due in 2010, is not being filed herewith, in accordance with Item 601(b)(4)(iii) of Regulation S-K. The Company hereby agrees to furnish a copy of that agreement to the SEC upon request.

· Exhibit 4.4

Note Purchase Agreement, entered into by the Company on December 15, 1997, pursuant to which the Company privately placed $10 million of its 6.85% Senior Notes due in 2012, is not being filed herewith, in accordance with Item 601(b)(4)(iii) of Regulation S-K. The Company hereby agrees to furnish a copy of that agreement to the SEC upon request.

· Exhibit 4.5

Note Purchase Agreement entered into by the Company on December 27, 2000, pursuant to which the Company privately placed $20 million of its 7.83% Senior Notes, due in 2015, is not being filed herewith, in accordance with Item 601(b)(4)(iii) of Regulation S-K. The Company hereby agrees to furnish a copy of that agreement to the SEC upon request.

· Exhibit 4.6

Note Agreement entered into by the Company on October 31, 2002, pursuant to which the Company privately placed $30 million of its 6.64% Senior Notes, due in 2017, is incorporated herein by reference to Exhibit 2 of the Company’s Current Report on Form 8-K, filed November 6, 2002, File No. 001-11590.

· Exhibit 4.7

Note Agreement entered into by the Company on October 18, 2005, pursuant to which the Company, on October 12, 2006, privately placed $20 million of its 5.5% Senior Notes, due in 2020, with Prudential Investment Management, Inc., is incorporated herein by reference to Exhibit 4.1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2005, File No. 001-11590.

· Exhibit 4.8

Form of Senior Debt Trust Indenture between Chesapeake Utilities Corporation and the trustee for the debt securities is incorporated herein by reference to Exhibit 4.3.1 of the Company’s Registration Statement on Form S-3A, Reg. No. 333-135602, dated November 6, 2006.

· Exhibit 4.9

Form of Subordinated Debt Trust Indenture between Chesapeake Utilities Corporation and the trustee for the debt securities is incorporated herein by reference to Exhibit 4.3.2 of the Company’s Registration Statement on Form S-3A, Reg. No. 333-135602, dated November 6, 2006.

· Exhibit 4.10

Form of debt securities is incorporated herein by reference to Exhibit 4.4 of the Company’s Registration Statement on Form S-3A, Reg. No. 333-135602, dated November 6, 2006.

· Exhibit 10.1*

Chesapeake Utilities Corporation Cash Bonus Incentive Plan, dated January 1, 2005, is incorporated herein by reference to Exhibit 10.3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-11590.

· Exhibit 10.2*

Chesapeake Utilities Corporation Directors Stock Compensation Plan, adopted in 2005, is incorporated herein by reference to the Company’s Proxy Statement dated March 28, 2005, in connection with the Company’s Annual Meeting held on May 5, 2005, File No. 001-11590.

· Exhibit 10.3*

Chesapeake Utilities Corporation Employee Stock Award Plan, adopted in 2005, is incorporated herein by reference to the Company’s Proxy Statement dated March 28, 2005, in connection with the Company’s Annual Meeting held on May 5, 2005, File No. 001-11590.

· Exhibit 10.4*

Chesapeake Utilities Corporation Performance Incentive Plan, adopted in 2005, is incorporated herein by reference to the Company’s Proxy Statement dated March 28, 2005, in connection with the Company’s Annual Meeting held on May 5, 2005, File No. 001-11590.

· Exhibit 10.5*

Deferred Compensation Program (amended and restated as of December 7, 2006) is incorporated herein by reference to Exhibit 10 of the Company’s Current Report on Form 8-K, filed December 13, 2006, File No. 001-11590.

· Exhibit 10.6*

Executive Employment Agreement dated December 29, 2006, by and between Chesapeake Utilities Corporation and S. Robert Zola, is incorporated herein by reference to Exhibit 10.7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, File No. 001-11590.

· Exhibit 10.7*

Executive Employment Agreement dated December 29, 2006, by and between Chesapeake Utilities Corporation and Stephen C. Thompson, is incorporated herein by reference to Exhibit 10.8 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, File No. 001-11590.

· Exhibit 10.8*

Executive Employment Agreement dated December 29, 2006, by and between Chesapeake Utilities Corporation and Beth W. Cooper, is incorporated herein by reference to Exhibit 10.9 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, File No. 001-11590.

· Exhibit 10.9*

Executive Employment Agreement dated December 29, 2006, by and between Chesapeake Utilities Corporation and Michael P. McMasters, is incorporated herein by reference to Exhibit 10.10 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, File No. 001-11590.

· Exhibit 10.10*

*Executive Employment Agreement dated December 29, 2006, by and between Chesapeake Utilities Corporation and John R. Schimkaitis, is incorporated herein by reference to Exhibit 10.11 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, File No. 001-11590.

· Exhibit 10.11*

Performance Share Agreement dated January 23, 2008 for the period 2008 to 2009, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and John R. Schimkaitis, filed herewith.

· Exhibit 10.12*

Performance Share Agreement dated January 23, 2008 for the period 2008 to 2010, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and John R. Schimkaitis, is filed herewith.

· Exhibit 10.13*

· Exhibit 10.14*

· Exhibit 10.15*

· Exhibit 10.16*

· Exhibit 10.17*

· Exhibit 10.18*

· Exhibit 10.19*

· Exhibit 10.20*

- Page 58 - -

· Exhibit 12

Computation of Ratio of Earning to Fixed Charges is filed herewith.

· Exhibit 14.1

Code of Ethics for Financial Officers is incorporated herein by reference to Exhibit 14 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, File No. 001-11590.

· Exhibit 14.2

Business Code of Ethics and Conduct is filed herewith.

· Exhibit 16

Letter Regarding Change in Certifying Accountant is filed herewith.

· Exhibit 21

Subsidiaries of the Registrant is filed herewith.

· Exhibit 22

Published Report Regarding Matters Submitted to Vote of Security Holders is incorporated herein by reference to Part II, Item 4 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2006, File No. 001-11590.

· Exhibit 23.1

Consent of Independent Registered Public Accounting Firm is filed herewith.

· Exhibit 23.2

Consent of Preceding Independent Registered Public Accounting Firm for years 2006 and 2005 is filed herewith.

· Exhibit 31.1

Certificate of Chief Executive Office of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a), dated March 10, 2008, is filed herewith.

· Exhibit 31.2

Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a), dated March 10, 2008, is filed herewith.

· Exhibit 32.1

Certificate of Chief Executive Office of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated March 10, 2008, is filed herewith.

· Exhibit 32.2

Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated March 10, 2008, is filed herewith.

* Management contract or compensatory plan or agreement.

- Page 59 - -

Signatures

Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, Chesapeake Utilities Corporation has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Chesapeake Utilities Corporation

By: /s/ John R. Schimkaitis

John R. Schimkaitis

President and Chief Executive Officer

Date: March 10, 2008

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

/s/ Ralph J. Adkins /s/ John R. Schimkaitis

Ralph J. Adkins, Chairman of the Board John R. Schimkaitis, President,

and Director Chief Executive Officer and Director

Date: February 20, 2008 Date: March 10, 2008

/s/ Michael P. McMasters /s/ Richard Bernstein

Michael P. McMasters, Senior Vice President Richard Bernstein, Director

and Chief Financial Officer Date: February 20, 2008

(Principal Financial and Accounting Officer)

Date: March 10, 2008

/s/ Eugene H. Bayard /s/ Thomas J. Bresnan

Eugene H. Bayard, Director Thomas J. Bresnan, Director

Date: February 20, 2008 Date: March 10, 2008

/s/ Thomas P. Hill, Jr. /s/ Walter J. Coleman

Thomas P. Hill, Jr., Director Walter J. Coleman, Director

Date: February 20, 2008 Date: February 20, 2008

/s/ J. Peter Martin /s/ Joseph E. Moore, Esq.

J. Peter Martin, Director Joseph E. Moore, Esq., Director

Date: February 20, 2008 Date: February 20, 2008

/s/ Calvert A. Morgan, Jr.

Calvert A. Morgan, Jr., Director

Date: February 20, 2008

- Page 60 - -

Report of Independent Registered Public Accounting Firm

________

To the Board of Directors and

Stockholders of Chesapeake Utilities Corporation

The audit referred to in our report dated March 10, 2008 relating to the consolidated financial statements of Chesapeake Utilities Corporation as of December 31, 2007 and for the year then ended, which is contained in Item 8 of this Form 10-K also included the audit of the financial statement schedules listed in Item 15. These financial statement schedules are the responsibility of the Chesapeake Utilities Corporation’s management. Our responsibility is to express an opinion on these financial statement schedules based on our audit.

In our opinion such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

/s/ Beard Miller Company LLP

————————————————

Beard Miller Company LLP

Reading, Pennsylvania

March 10, 2008

Chesapeake Utilities Corporation and Subsidiaries
Schedule II
Valuation and Qualifying Accounts




			Additions
For the Year Ended December 31,	Balance at Beginning of Year		Charged to Income		Other Accounts (1)		Deductions (2)			Balance at End of Year
Reserve Deducted From Related Assets
Reserve for Uncollectible Accounts
2007	$	661,597	$	818,561	$	26,190	$	(554,273	)	$	952,075
2006	$	861,378	$	381,424	$	65,519	$	(646,724	)	$	661,597
2005	$	610,819	$	632,644	$	158,409	$	(540,494	)	$	861,378


(1) Recoveries.
(2) Uncollectible accounts charged off.

Upon written request,

Chesapeake will provide, free of

charge, a copy of any exhibit to

the 2007 Annual Report on

Form 10-K not included

in this document.

bylaws.htm

Exhibit 3.2

TEXT OF AMENDMENTS TO THE BYLAWS OF

CHESAPEAKE UTILITIES CORPORATION

As of December 12, 2007 Article VI of the Bylaws of Chesapeake Utilities Corporation was adopted, amended and restated by the Board of Directors in its entirety to be and read as follows:

ARTICLE VI

STOCK CERTIFICATES, TRANSFERS AND RECORD DATE

6.1 Certificates of Stock; Uncertificated Shares. Shares of capital stock of the Corporation may be certificated or uncertificated, as provided under the Delaware General Corporation Law. The certificates of stock of the Corporation shall be numbered and registered in the stock ledger and transfer books of the Corporation as they are issued. The stock certificates of the Corporation shall be signed by the Chief Executive Officer, the President or a Vice President and the Treasurer or an Assistant Treasurer or the Secretary or an Assistant Secretary, and shall bear the corporate seal, which may be a facsimile, engraved or printed. Any or all of the signatures on the certificate may be facsimiles, engraved or printed. In the event that any officer, transfer agent, or registrar who has signed or whose facsimile signature has been placed upon any share certificate shall have ceased to be such officer, transfer agent, or registrar before such certificate is issued, it may be issued with the same effect as if such person were such officer, transfer agent, or registrar at the date of issue. Stock certificates of the Corporation shall be in such form as provided by statute and approved by the Board of Directors. The stock record books and the blank stock certificates books shall be kept by the Secretary or by any agency designated by the Board of Directors for that purpose.

6.2 Registration of Transfer. Upon surrender to the Corporation or the transfer agent of the Corporation of a certificate for shares, if such shares are certificated, duly endorsed or accompanied by proper evidence of succession, assignment or authority to transfer, it shall be the duty of the Corporation to issue a new certificate or to register the issuance of uncertificated shares to the person entitled thereto, cancel the old certificate and record the transaction upon its books. Upon the receipt of proper transfer instructions from the registered owner of uncertificated shares, such uncertificated shares shall be cancelled, issuance of new equivalent uncertificated shares or certificated shares shall be recorded upon the books of the Corporation. The Board of Directors shall have authority to make such rules and regulations not inconsistent with law, the Certificate of Incorporation or these Bylaws, as it deems expedient concerning the issuance, transfer and registration of certificates for shares and the shares represented thereby and of uncertificated shares.

6.3 Record Date for Stockholders. For the purpose of determining the stockholders entitled to notice of or to vote at any annual or special meeting of stockholders or any adjournment thereof, or for the purpose of determining stockholders entitled to receive payment of any dividend or other distribution or the allotment of any rights, or entitled to exercise any rights in respect of any change, conversion, or exchange of stock, or for the purpose of any other lawful action, the Directors may fix, in advance, a date as the record date for any such determination of stockholders. Such date shall not be more than sixty days nor less than ten days before the date of such meeting, nor more than sixty days prior to any other action. If no record date is fixed, the record date for the determination of stockholders entitled to notice of or to vote at a meeting of stockholders shall be at the close of business on the day next preceding the day on which notice is given, or if notice is waived, at the close of business on the day next preceding the day on which the meeting is held; the record date for determining stockholders for any other purpose shall be at the close of business on the day on which the Board of Directors adopts the resolution relating thereto. When a determination of stockholders of record entitled to notice of or to vote at any meeting of stockholders has been made as provided in this paragraph, such determination shall apply to any adjournment thereof; provided, however, that the Board of Directors may fix a new record date for the adjourned meeting.

6.4 Registered Stockholders. The Corporation shall be entitled to treat the holder of record of any share or shares of stock as the holder in fact thereof and, accordingly, shall not be bound to recognize any equitable or other claim to or interest in such share or shares on the part of any other person, whether or not it shall have express or other notice thereof, except as otherwise provided by law.

6.5 Lost Certificates. The Board of Directors may direct that (i) a new certificate or certificates or (ii) uncertificated shares in place of any certificate or certificates previously issued by the Corporation, be issued in place of any certificate or certificates theretofore issued by the Corporation alleged to have been lost, stolen or destroyed, upon the making of an affidavit of that fact by the person claiming the certificate of stock to be lost, stolen or destroyed. When authorizing such issue of such (i) new certificate or certificates or (ii) uncertificated shares, the Board of Directors may, in its discretion and as a condition precedent to the issuance thereof, require the owner of such lost, stolen or destroyed certificate or certificates, or the owner's legal representative, to advertise the same in such manner as it shall require and/or give the Corporation a bond in such sum as it may direct as indemnity against any claim that may be made against the Corporation with respect to the certificate alleged to have been lost, stolen or destroyed.

ratioofearnings.htm

Exhibit 12

Chesapeake Utilities Corporation

Ratio of Earnings to Fixed Charges

For the Years Ended December 31,	2007	2006	2005	2004	2003
Income from continuing operations	$13,217,787	$10,747,965	$10,698,811	$9,686,449	$10,079,483
Add:
Income taxes	8,597,461	6,999,072	6,472,220	5,771,333	6,032,445
Portion of rents representative of interest factor	245,399	226,583	278,846	309,446	351,445
Interest on indebtedness	6,539,004	5,721,912	5,076,666	5,145,243	5,527,601
Amortization of debt discount and expense	50,635	52,081	55,792	61,421	89,155
Earnings as adjusted	$28,650,286	$23,747,613	$22,582,335	$20,973,892	$22,080,129

Fixed Charges
Portion of rents representative of interest factor	$245,399	$226,583	$278,846	$309,446	$351,445
Interest on indebtedness	6,539,004	5,721,912	5,076,666	5,145,243	5,527,601
Amortization of debt discount and expense	50,635	52,081	55,792	61,421	89,155
Fixed Charges	$6,835,038	$6,000,576	$5,411,304	$5,516,110	$5,968,201
Ratio of Earnings to Fixed Charges	4.19	3.96	4.17	3.80	3.70

codeofethics.htm

Exhibit 14

[Logo of Chesapeake Utilities Corporation]

CODE OF ETHICS FOR FINANCIAL OFFICERS

Adopted December 7, 2006

This Code of Ethics for Financial Officers has been adopted by the Board of Directors of Chesapeake Utilities Corporation (“Chesapeake”) to promote honest and ethical conduct, accurate and timely disclosure of financial information in Chesapeake’s filings with the Securities and Exchange Commission (SEC), and compliance with all applicable laws, rules and regulations.

Chesapeake expects all of its employees to carry out their responsibilities in accordance with the highest standards of personal and professional integrity and to abide by the provisions of Chesapeake’s Business Code of Ethics and Conduct and all other policies and procedures that may be adopted by the Company from time to time governing the conduct of its employees. This Code of Ethics for Financial Officers supplements the Company’s Business Code of Ethics and Conduct as it relates to the activities of Chesapeake’s Chief Executive Officer, Chief Financial Officer, Treasurer, and Corporate Controller, hereafter referred to as the “Financial Officers”.

Each Financial Officer when performing his or her duties must:

·	Maintain high standards of honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships.

·	Take reasonable actions within the scope of his or her responsibilities to ensure that the disclosures in reports and documents filed by Chesapeake with the SEC and in other public communications made by Chesapeake are accurate, complete, fairly stated, timely and understandable.

·	Comply with applicable governmental laws, rules and regulations, including the rules, regulations and policies of public regulatory agencies.

·	Act at all times in good faith, responsibly, with due care, and diligence in carrying out his or her responsibilities.

·	Maintain the confidentiality of confidential financial or other information acquired in the course of employment, except when disclosure is properly authorized or is required by applicable law or legal process, and not use any such confidential information for personal advantage.

Not take any action to coerce, manipulate, mislead or fraudulently influence an independent accountant or internal auditor engaged in the performance of an audit or review of Chesapeake’s financial statements or accounting books and records, with the purpose of rendering the financial statements false or misleading.

·	Report promptly any violation of this Code of Ethics for Financial Officers either directly to the Director of Internal Audit or the Chairman of the Audit Committee.

Any Financial Officer who violates this Code of Ethics for Financial Officers will be subject to appropriate disciplinary action, including possible termination of employment.

The Audit Committee shall be responsible for overseeing compliance with this Code of Ethics for Financial Officers and shall direct the investigation of any alleged violation and report its findings, including any recommended action, to the Board of Directors.

accountant.htm

Exhibit 16

[Logo of PricewaterhouseCoopers]

PricewaterhouseCoopers LLP

125 High Street

Boston MA 02110

Telephone (617) 530 5000

Facsimile (617) 530 5001

March 21, 2007

Securities and Exchange Commission

100 F Street, N.E.

Washington, DC 20549

Commissioners:

We have read the statements made by Chesapeake Utilities Corporation (copy attached), which we understand will be filed with the Securities and Exchange Commission, pursuant to Item 4.01 of Form 8-K, as part of the Form 8-K of Chesapeake Utilities Corporation dated March 21, 2007. We agree with the statements concerning our Firm in such Form 8-K.

Very truly yours,

/s/ PricewaterhouseCoopers LLP

————————————————

PricewaterhouseCoopers LLP

subsidiaries.htm

Exhibit 21

Chesapeake Utilities Corporation

Subsidiaries of the Registrant

Subsidiaries	State Incorporated

Eastern Shore Natural Gas Company	Delaware
Sharp Energy, Inc.	Delaware
Chesapeake Service Company	Delaware
Xeron, Inc.	Mississippi
Sam Shannahan Well Company, Inc.	Maryland
Sharp Water, Inc.	Delaware
Chesapeake OnSight Services LLC	Delaware
Peninsula Energy Services Company, Inc.	Delaware
Peninsula Pipeline Company, Inc.	Delaware


Subsidiaries of Sharp Energy, Inc.	State Incorporated
Sharpgas, Inc.	Delaware
Tri-County Gas Co., Incorporated	Maryland


Subsidiaries of Chesapeake Service Company	State Incorporated
Skipjack, Inc.	Delaware
BravePoint, Inc.	Georgia
Chesapeake Investment Company	Delaware
Eastern Shore Real Estate, Inc.	Delaware


Subsidiaries of Sharp Water, Inc.	State Incorporated
Sharp Water of Idaho, Inc.	Delaware
Sharp Water of Minnesota, Inc.	Delaware

auditorconsent.htm

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

________

Chesapeake Utilities Corporation

We hereby consent to the incorporation by reference in the Registration Statements on S-8 (Nos. 333-01175, 333-94159, 333-124646, 333-124694 and 333-124717) of our reports dated March 10, 2008, relating to the consolidated financial statements, the effectiveness of internal control over financial reporting, and financial statement schedules of Chesapeake Utilities Corporation appearing in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007.

/s/ Beard Miller Company LLP

————————————————

Beard Miller Company LLP

Reading, Pennsylvania

March 10, 2008

precedingauditconsent.htm

Exhibit 23.2

Consent of Independent Registered Public Accounting Firm

________

Chesapeake Utilities Corporation

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-63381 and 333-121524) and Form S-8 (Nos. 333-01175, 333-94159, 333-124646, 333-124694 and 333-124717) of Chesapeake Utilities Corporation of our report dated March 13, 2007 relating to the consolidated financial statements and financial statement schedule which appears in this Form 10-K.

PricewaterhouseCoopers LLP

Boston, Massachusetts

March 10, 2008

ceocert.htm

Exhibit 31.1

CERTIFICATE PURSUANT TO RULE 13A-14(A) AND 15D-14(A)

UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John R. Schimkaitis, certify that:

I have reviewed this annual report on Form 10-K of Chesapeake Utilities Corporation;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a–15(e) and 15d–15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluations; and

disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant 's internal control over financial reporting; and

The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 10, 2008

/s/ John R. Schimkaitis

John R. Schimkaitis

President and Chief Executive Officer

cfocert.htm

Exhibit 31.2

CERTIFICATE PURSUANT TO RULE 13A-14(A) AND 15D-14(A)

UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Michael P. McMasters, certify that:

I have reviewed this annual report on Form 10-K of Chesapeake Utilities Corporation;

c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluations; and

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 10, 2008

/s/ Michael P. McMasters

Michael P. McMasters

Senior Vice President and Chief Financial Officer

certceo.htm

Exhibit 32.1

CERTIFICATED OF CHIEF EXECUTIVE OFFICER

OF CHESAPEAKE UTLITIES CORPORATION

PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED

PUSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, John R. Schimkaitis, President and Chief Executive Officer of Chesapeake Utilities Corporation, certify that, to the best of my knowledge, the Annual Report on Form 10-K of Chesapeake Utilities Corporation (“Chesapeake”) for the year ended December 31, 2007, filed with the Securities and Exchange Commission on the date hereof (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Chesapeake.

/s/ John R. Schimkaitis

John R. Schimkaitis

March 10, 2008

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Chesapeake Utilities Corporation and will be retained by Chesapeake Utilities Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

certcfo.htm

Exhibit 32.2

CERTIFICATED OF CHIEF FINANCIAL OFFICER

OF CHESAPEAKE UTLITIES CORPORATION

PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED

PUSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Michael P. McMasters, Senior Vice President and Chief Financial Officer of Chesapeake Utilities Corporation, certify that, to the best of my knowledge, the Annual Report on Form 10-K of Chesapeake Utilities Corporation (“Chesapeake”) for the year ended December 31, 2007, filed with the Securities and Exchange Commission on the date hereof (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Chesapeake.

/s/ Michael P. McMasters

Michael P. McMasters

March 10, 2008

psagreement2009jrs.htm

Exhibit 10.11

pursuant to the

CHESAPEAKE UTILITIES CORPORATION

PERFORMANCE INCENTIVE PLAN

On January 23, 2008, (the “Grant Date”), Chesapeake Utilities Corporation, a Delaware corporation (the “Company”), has granted to John R. Schimkaitis (the “Grantee”), who resides at 1700 N. DuPont Highway, Apartment A-101, Dover, DE 19904, a Performance Share Award on the terms and subject to the conditions of this Performance Share Agreement.

Recitals

WHEREAS, the Chesapeake Utilities Corporation Performance Incentive Plan (the “Plan”) has been duly adopted by action of the Company's Board of Directors (the “Board”) on February 24, 2005, and approved by the Shareholders of the Company at a meeting held on May 5, 2005; and

WHEREAS, the Plan is effective January 1, 2006; and

WHEREAS, the Committee of the Board of Directors of the Company referred to in the Plan (the “Committee”) has determined that it is in the best interests of the Company to grant the Performance Share Award described herein pursuant to the Plan; and

WHEREAS, the shares of the Common Stock of the Company (“Shares”) that are subject to this Agreement, when added to the other shares of Common Stock that are subject to awards granted under the Plan, do not exceed the total number of shares of Common Stock with respect to which awards are authorized to be granted under the Plan.

Agreement

It is hereby covenanted and agreed by and between the Company and the Grantee as follows:

Section 1. Performance Share Award and Performance Period

The Company hereby grants to the Grantee a Performance Share Award as of the Grant Date. As more fully described herein, the Grantee may earn up to 24,000 Shares upon the Company's achievement of the performance criteria set forth in Section 2 (the “Performance Shares”) over the performance period from January 1, 2008 to December 31, 2009 (the “Performance Period”). This Award has been granted pursuant to the Plan; capitalized terms used in this agreement which are not specifically defined herein shall have the meanings ascribed to such terms in the Plan.

Section 2. Performance Criteria and Terms of Share Award

(a) The Committee selected and established in writing performance criteria for the Performance Period, which, if met, may entitle the Grantee to some or all of the Performance Shares under this Award. If this Award is intended by the Committee to comply with the exception from Code Section 162(m) for qualified performance-based compensation for Grantees who are “Covered Employees” as defined in Code Section 162(m), the performance criteria established shall be based on one or more Performance Goals selected by the Committee in writing within 90 days following the first day of the Performance Period (or, if earlier, before 25% of that period has elapsed), and at a time when the outcome relative to the attainment of the performance criteria is not substantially certain. As soon as practicable after the Company’s independent auditors have certified the Company’s financial statements for each fiscal year of the Company in the Performance Period, the Committee shall determine for purposes of this Agreement the Company’s (1) total shareholder return, defined as the cumulative total return to shareholders (“Shareholder Value”), (2) growth in long-term earnings, defined as the growth in total capital expenditures as a percentage of total capitalization (“Growth”) and (3) earnings performance, defined as average return on equity (“RoE”), in accordance with procedures established by the Committee. The Shareholder Value, Growth and RoE (each a “Performance Metric” and collectively, the “Performance Metrics”) shall be determined by the Committee in accordance with the terms of the Plan and this Agreement based on financial results reported to shareholders in the Company’s annual reports and shall be subject to adjustment by the Committee for extraordinary events during the Performance Period, as applicable. Both the Shareholder Value and the Growth Performance Metrics will be compared to those of the peer group consisting of gas utility companies listed in the Edward Jones Natural Gas Distribution Group (the “Peer Group”) for the Performance Period and Awards will be determined according to the schedule in subsection (b) below. For the average RoE Performance Metric, the Company’s performance will be compared to pre-determined RoE thresholds established by the Committee. At the end of the Performance Period, the Committee shall certify in writing the extent to which the Performance Goals were met during the Performance Period for Awards for Covered Employees. If the Performance Goals for the Performance Period are met, Covered Employees shall be entitled to the Award, subject to the Committee’s exercise of discretion to reduce any Award to a Covered Employee based on business objectives established for that Covered Employee or other factors as determined by the Committee in its sole discretion. The Committee shall promptly notify the Grantee of its determination.

(b) The Grantee may earn 50 percent or more of the target award of 19,200 Performance Shares (the “Target Award”) up to a maximum number of Performance Shares set forth in Section 1 above (the “Maximum Award”) based upon achievement of threshold and target levels of performance against the Performance Metrics established for the Performance Period . The Committee shall confirm the level of Award attained for the Performance Period after the Company’s independent auditors have certified the Company’s financial statements for each fiscal year of the Company in the Performance Period.

(c) Once established, the performance criteria identified above normally shall not be changed during the Performance Period. However, if the Committee determines that external changes or other unanticipated business conditions have materially affected the fairness of the goals, or that a change in the business, operations, corporate structure or capital structure of the Company, or the manner in which it conducts its business, or acquisitions or divestitures of subsidiaries or business units, or other events or circumstances materially affect the performance criteria or render the performance criteria unsuitable, then the Committee may approve appropriate adjustments to the performance criteria (either up or down) during the Performance Period. Notwithstanding the foregoing, no changes shall be made to an Award intended to satisfy the requirements of Code Section 162(m) if such changes would affect the qualification of the Award as performance-based compensation within the meaning of Code Section 162(m).

(d) Performance Shares that are earned by the Grantee pursuant to this Section 2 shall be issued promptly, without payment of consideration by the Grantee, within 2 ½ months of the end of the Performance Period. The Grantee shall have the right to vote the Performance Shares and to receive the dividends distributable with respect to such Shares on and after, but not before, the date on which the Grantee is recorded on the Company's ledger as holder of record of the Performance Shares (the “Issue Date”). If, however, the Grantee receives Shares as part of any dividend or other distribution with respect to the Performance Shares, such Shares shall be treated as if they are Performance Shares, and such Shares shall be subject to all of the terms and conditions imposed by this Section 2. Notwithstanding the foregoing, the Grantee shall be entitled to receive an amount in cash, equivalent to the dividends that would have been paid on the awarded Performance Shares from the Grant Date to the Issue Date for those Performance Shares actually earned by the Grantee during the applicable Performance Period. Such dividend equivalents shall be payable at the time such Performance Shares are issued.

(e) The Performance Shares will not be registered for resale under the Securities Act of 1933 or the laws of any state except when and to the extent determined by the Board pursuant to a resolution. Until a registration statement is filed and becomes effective, however, transfer of the Performance Shares shall require the availability of an exemption from such registration, and prior to the issuance of new certificates, the Company shall be entitled to take such measures as it deems appropriate (including but not limited to obtaining from the Grantee an investment representation letter and/or further legending the new certificates) to ensure that the Performance Shares are not transferred in the absence of such exemption.

(f) In the event of a Change in Control, as defined in the Plan, during the Performance Period, the Grantee shall earn the Maximum Award of Performance Shares set forth in this Section 2, as if all performance criteria were satisfied, without any pro ration based on the proportion of the Performance Period that has expired as of the date of such Change in Control.

(g) If, during the Performance Period, the Grantee is separated from employment, Performance Shares shall be deemed earned or forfeited as follows:

(1) Upon voluntary termination by the Grantee or termination by the Company for failure of job performance or other just cause as determined by the Committee, all unearned Performance Shares shall be forfeited immediately;

(2) If the Grantee separates from employment by reason of death or total and permanent disability (as determined by the Committee), the number of Performance Shares that would otherwise have been earned at the end of the Performance Period shall be reduced by pro rating such Performance Shares based on the proportion of the Performance Period during which the Grantee was employed by the Company, unless the Committee determines that the Performance Shares shall not be so reduced;

(3) Upon retirement by the Grantee at age 55 or thereafter, all unearned Performance Shares shall be forfeited immediately.

(h) The Grantee shall be solely responsible for any federal, state and local taxes of any kind imposed in connection with the vesting or delivery of the Performance Shares. Prior to the transfer of any Performance Shares to the Grantee, the Grantee shall remit to the Company an amount sufficient to satisfy any federal, state, local and other withholding tax requirements. The Grantee may elect to have all or part of any withholding tax obligation satisfied by having the Company withhold Shares otherwise deliverable to the Grantee as Performance Shares, unless the Committee determines otherwise by resolution. If the Grantee fails to make such payments or election, the Company and its subsidiaries shall, to the extent permitted by law, have the right to deduct from any payments of any kind otherwise due to the Grantee any taxes required by law to be withheld with respect to the Performance Shares. In the case of any amounts withheld for taxes pursuant to this provision in the form of Shares, the amount withheld shall not exceed the minimum required by applicable law and regulations.

(i) Notwithstanding any other provision of this Agreement, if any payment or distribution (a "Payment") by the Company or any other person or entity to or for the benefit of the Grantee is determined to be an "excess parachute payment" (within the meaning of Code Section 280G(b)(1) or any successor provision of similar effect), whether paid or payable or distributed or distributable pursuant to this Agreement or otherwise, then the Grantee’s benefits under this Agreement may, unless the Grantee elects otherwise pursuant to his employment agreement, be reduced by the amount necessary so that the Grantee’s total "parachute payment" as defined in Code Section 280G(b)(2)(A) under this and all other agreements will be $1.00 less than the amount that would be a "parachute payment". The payment of any “excess parachute payment” pursuant to this paragraph shall also comply with the terms of the Grantee’s employment agreement.

Section 3. Additional Conditions to Issuance of Shares

Each transfer of Performance Shares shall be subject to the condition that if at any time the Committee shall determine, in its sole discretion, that it is necessary or desirable as a condition of, or in connection with, transfer of Performance Shares (i) to satisfy withholding tax or other withholding liabilities, (ii) to effect the listing, registration or qualification on any securities exchange or under any state or federal law of any Shares deliverable in connection with such exercise, or (iii) to obtain the consent or approval of any regulatory body, then in any such event such transfer shall not be effective unless such withholding, listing, registration, qualification, consent or approval shall have been effected or obtained free of any conditions not acceptable to the Company.

Section 4. Adjustment of Shares

(a) If the Company shall become involved in a merger, consolidation or other reorganization, whether or not the Company is the surviving corporation, any right to earn Performance Shares shall be deemed a right to earn or to elect to receive the consideration into which the Shares represented by the Performance Shares would have been converted under the terms of the merger, consolidation or other reorganization. If the Company is not the surviving corporation, the surviving corporation (the “Successor”) shall succeed to the rights and obligations of the Company under this Agreement.

(b) If any subdivision or combination of Shares or any stock dividend, capital reorganization or recapitalization occurs after the adoption of the Plan, the Committee shall make such proportionate adjustments as are appropriate to the number of Performance Shares to be earned in order to prevent the dilution or enlargement of the rights of the Grantee.

Section 5. No Right to Employment

Nothing contained in this Agreement shall be deemed by implication or otherwise to confer upon the Grantee any right to continued employment by the Company or any affiliate of the Company.

Section 6. Notice

Any notice to be given hereunder by the Grantee shall be sent by mail addressed to Chesapeake Utilities Corporation, 909 Silver Lake Boulevard, Dover, Delaware 19904, for the attention of the Committee, c/o the Corporate Secretary, and any notice by the Company to the Grantee shall be sent by mail addressed to the Grantee at the address of the Grantee shown on the first page hereof. Either party may, by notice given to the other in accordance with the provisions of this Section, change the address to which subsequent notices shall be sent.

Section 7. Beneficiary Designation

Grantee may designate a beneficiary to receive any Performance Shares to which Grantee is entitled which vest as a result of Grantee’s death. Grantee acknowledges that the Company may exercise all rights under this Agreement and the Plan against Grantee and Grantee’s estate, heirs, lineal descendants and personal representatives and shall not be limited to exercising its rights against Grantee’s beneficiary.

Section 8. Assumption of Risk

It is expressly understood and agreed that the Grantee assumes all risks incident to any change hereafter in the applicable laws or regulations or incident to any change in the market value of the Performance Shares.

Section 9. Terms of Plan

This Agreement is entered into pursuant to the Plan (a copy of which has been delivered to the Grantee). This Agreement is subject to all of the terms and provisions of the Plan, which are incorporated into this Agreement by reference, and the actions taken by the Committee pursuant to the Plan. In the event of a conflict between this Agreement and the Plan, the provisions of the Plan shall govern. All determinations by the Committee shall be in its sole discretion and shall be binding on the Company and the Grantee.

Section 10. Governing Law; Amendment

This Agreement shall be governed by, and shall be construed and administered in accordance with, the laws of the State of Delaware (without regard to its choice of law rules) and the requirements of any applicable federal law. This Agreement may be modified or amended only by a writing signed by the parties hereto.

Section 11. Action by the Committee

The parties agree that the interpretation of this Agreement shall rest exclusively and completely within the sole discretion of the Committee. The parties agree to be bound by the decisions of the Committee with regard to the interpretation of this Agreement and with regard to any and all matters set forth in this Agreement. The Committee may delegate its functions under this Agreement to an officer of the Company designated by the Committee (hereinafter the “Designee”). In fulfilling its responsibilities hereunder, the Committee or its Designee may rely upon documents, written statements of the parties or such other material as the Committee or its Designee deems appropriate. The parties agree that there is no right to be heard or to appear before the Committee or its Designee and that any decision of the Committee or its Designee relating to this Agreement shall be final and binding unless such decision is arbitrary and capricious.

Section 12. Terms of Agreement

This Agreement shall remain in full force and effect and shall be binding on the parties hereto for so long as any Performance Shares issued to the Grantee under this Agreement continue to be held by the Grantee.

IN WITNESS WHEREOF, the Company has caused this Agreement to be executed in its corporate name, and the Grantee has executed the same in evidence of the Grantee's acceptance hereof, upon the terms and conditions herein set forth, as of the day and year first above written.

CHESAPEAKE UTILITIES CORPORATION

By:

Its:

Grantee:

psagreement2010jrs.htm

Exhibit 10.12

CHESAPEAKE UTILITIES CORPORATION

PERFORMANCE INCENTIVE PLAN

Recitals

WHEREAS, the Plan is effective January 1, 2006; and

Agreement

It is hereby covenanted and agreed by and between the Company and the Grantee as follows:

Section 1. Performance Share Award and Performance Period

The Company hereby grants to the Grantee a Performance Share Award as of the Grant Date. As more fully described herein, the Grantee may earn up to 12,000 Shares upon the Company's achievement of the performance criteria set forth in Section 2 (the “Performance Shares”) over the performance period from January 1, 2008 to December 31, 2010 (the “Performance Period”). This Award has been granted pursuant to the Plan; capitalized terms used in this agreement which are not specifically defined herein shall have the meanings ascribed to such terms in the Plan.

Section 2. Performance Criteria and Terms of Share Award

(b) The Grantee may earn 50 percent or more of the target award of 9,600 Performance Shares (the “Target Award”) up to a maximum number of Performance Shares set forth in Section 1 above (the “Maximum Award”) based upon achievement of threshold and target levels of performance against the Performance Metrics established for the Performance Period . The Committee shall confirm the level of Award attained for the Performance Period after the Company’s independent auditors have certified the Company’s financial statements for each fiscal year of the Company in the Performance Period.

(g) If, during the Performance Period, the Grantee is separated from employment, Performance Shares shall be deemed earned or forfeited as follows:

(3) Upon retirement by the Grantee at age 55 or thereafter, all unearned Performance Shares shall be forfeited immediately.

Section 3. Additional Conditions to Issuance of Shares

Section 4. Adjustment of Shares

Section 5. No Right to Employment

Nothing contained in this Agreement shall be deemed by implication or otherwise to confer upon the Grantee any right to continued employment by the Company or any affiliate of the Company.

Section 6. Notice

Section 7. Beneficiary Designation

Section 8. Assumption of Risk

Section 9. Terms of Plan

Section 10. Governing Law; Amendment

Section 11. Action by the Committee

Section 12. Terms of Agreement

CHESAPEAKE UTILITIES CORPORATION

By:

Its:

Grantee:

psagreement2009mpm.htm

Exhibit 10.13

pursuant to the

CHESAPEAKE UTILITIES CORPORATION

PERFORMANCE INCENTIVE PLAN

On January 23, 2008, (the “Grant Date”), Chesapeake Utilities Corporation, a Delaware corporation (the “Company”), has granted to Michael P. McMasters (the “Grantee”), who resides at 312 Quail Run, Wyoming, DE 19934, a Performance Share Award on the terms and subject to the conditions of this Performance Share Agreement.

Recitals

WHEREAS, the Plan is effective January 1, 2006; and

Agreement

It is hereby covenanted and agreed by and between the Company and the Grantee as follows:

Section 1. Performance Share Award and Performance Period

The Company hereby grants to the Grantee a Performance Share Award as of the Grant Date. As more fully described herein, the Grantee may earn up to 12,800 Shares upon the Company's achievement of the performance criteria set forth in Section 2 (the “Performance Shares”) over the performance period from January 1, 2008 to December 31, 2009 (the “Performance Period”). This Award has been granted pursuant to the Plan; capitalized terms used in this agreement which are not specifically defined herein shall have the meanings ascribed to such terms in the Plan.

Section 2. Performance Criteria and Terms of Share Award

(b) The Grantee may earn 50 percent or more of the target award of 10,240 Performance Shares (the “Target Award”) up to a maximum number of Performance Shares set forth in Section 1 above (the “Maximum Award”) based upon achievement of threshold and target levels of performance against the Performance Metrics established for the Performance Period . The Committee shall confirm the level of Award attained for the Performance Period after the Company’s independent auditors have certified the Company’s financial statements for each fiscal year of the Company in the Performance Period.

(g) If, during the Performance Period, the Grantee is separated from employment, Performance Shares shall be deemed earned or forfeited as follows:

(3) Upon retirement by the Grantee at age 55 or thereafter, all unearned Performance Shares shall be forfeited immediately.

Section 3. Additional Conditions to Issuance of Shares

Section 4. Adjustment of Shares

Section 5. No Right to Employment

Nothing contained in this Agreement shall be deemed by implication or otherwise to confer upon the Grantee any right to continued employment by the Company or any affiliate of the Company.

Section 6. Notice

Section 7. Beneficiary Designation

Section 8. Assumption of Risk

Section 9. Terms of Plan

Section 10. Governing Law; Amendment

Section 11. Action by the Committee

Section 12. Terms of Agreement

CHESAPEAKE UTILITIES CORPORATION

By:

Its:

Grantee:

psagreement2010mpm.htm

Exhibit 10.14

pursuant to the

CHESAPEAKE UTILITIES CORPORATION

PERFORMANCE INCENTIVE PLAN

Recitals

WHEREAS, the Plan is effective January 1, 2006; and

Agreement

It is hereby covenanted and agreed by and between the Company and the Grantee as follows:

Section 1. Performance Share Award and Performance Period

The Company hereby grants to the Grantee a Performance Share Award as of the Grant Date. As more fully described herein, the Grantee may earn up to 6,400 Shares upon the Company's achievement of the performance criteria set forth in Section 2 (the “Performance Shares”) over the performance period from January 1, 2008 to December 31, 2010 (the “Performance Period”). This Award has been granted pursuant to the Plan; capitalized terms used in this agreement which are not specifically defined herein shall have the meanings ascribed to such terms in the Plan.

Section 2. Performance Criteria and Terms of Share Award

(b) The Grantee may earn 50 percent or more of the target award of 5,120 Performance Shares (the “Target Award”) up to a maximum number of Performance Shares set forth in Section 1 above (the “Maximum Award”) based upon achievement of threshold and target levels of performance against the Performance Metrics established for the Performance Period . The Committee shall confirm the level of Award attained for the Performance Period after the Company’s independent auditors have certified the Company’s financial statements for each fiscal year of the Company in the Performance Period.

(g) If, during the Performance Period, the Grantee is separated from employment, Performance Shares shall be deemed earned or forfeited as follows:

(3) Upon retirement by the Grantee at age 55 or thereafter, all unearned Performance Shares shall be forfeited immediately.

Section 3. Additional Conditions to Issuance of Shares

Section 4. Adjustment of Shares

Section 5. No Right to Employment

Nothing contained in this Agreement shall be deemed by implication or otherwise to confer upon the Grantee any right to continued employment by the Company or any affiliate of the Company.

Section 6. Notice

Section 7. Beneficiary Designation

Section 8. Assumption of Risk

Section 9. Terms of Plan

Section 10. Governing Law; Amendment

Section 11. Action by the Committee

Section 12. Terms of Agreement

CHESAPEAKE UTILITIES CORPORATION

By:

Its:

Grantee:

psagreement2009sct.htm

Exhibit 10.15

pursuant to the

CHESAPEAKE UTILITIES CORPORATION

PERFORMANCE INCENTIVE PLAN

On January 23, 2008, (the “Grant Date”), Chesapeake Utilities Corporation, a Delaware corporation (the “Company”), has granted to Stephen C. Thompson (the “Grantee”), who resides at 2 Wood Duck Lane, Wyoming, DE 19934, a Performance Share Award on the terms and subject to the conditions of this Performance Share Agreement.

Recitals

WHEREAS, the Plan is effective January 1, 2006; and

Agreement

It is hereby covenanted and agreed by and between the Company and the Grantee as follows:

Section 1. Performance Share Award and Performance Period

The Company hereby grants to the Grantee a Performance Share Award as of the Grant Date. As more fully described herein, the Grantee may earn up to 10,000 Shares upon the Company's achievement of the performance criteria set forth in Section 2 (the “Performance Shares”) over the performance period from January 1, 2008 to December 31, 2009 (the “Performance Period”). This Award has been granted pursuant to the Plan; capitalized terms used in this agreement which are not specifically defined herein shall have the meanings ascribed to such terms in the Plan.

Section 2. Performance Criteria and Terms of Share Award

(b) The Grantee may earn 50 percent or more of the target award of 8,000 Performance Shares (the “Target Award”) up to a maximum number of Performance Shares set forth in Section 1 above (the “Maximum Award”) based upon achievement of threshold and target levels of performance against the Performance Metrics established for the Performance Period . The Committee shall confirm the level of Award attained for the Performance Period after the Company’s independent auditors have certified the Company’s financial statements for each fiscal year of the Company in the Performance Period.

(g) If, during the Performance Period, the Grantee is separated from employment, Performance Shares shall be deemed earned or forfeited as follows:

(3) Upon retirement by the Grantee at age 55 or thereafter, all unearned Performance Shares shall be forfeited immediately.

Section 3. Additional Conditions to Issuance of Shares

Section 4. Adjustment of Shares

Section 5. No Right to Employment

Nothing contained in this Agreement shall be deemed by implication or otherwise to confer upon the Grantee any right to continued employment by the Company or any affiliate of the Company.

Section 6. Notice

Section 7. Beneficiary Designation

Section 8. Assumption of Risk

Section 9. Terms of Plan

Section 10. Governing Law; Amendment

Section 11. Action by the Committee

Section 12. Terms of Agreement

CHESAPEAKE UTILITIES CORPORATION

By:

Its:

Grantee:

psagreement2010sct.htm

Exhibit 10.16

pursuant to the

CHESAPEAKE UTILITIES CORPORATION

PERFORMANCE INCENTIVE PLAN

Recitals

WHEREAS, the Plan is effective January 1, 2006; and

Agreement

It is hereby covenanted and agreed by and between the Company and the Grantee as follows:

Section 1. Performance Share Award and Performance Period

The Company hereby grants to the Grantee a Performance Share Award as of the Grant Date. As more fully described herein, the Grantee may earn up to 5,000 Shares upon the Company's achievement of the performance criteria set forth in Section 2 (the “Performance Shares”) over the performance period from January 1, 2008 to December 31, 2010 (the “Performance Period”). This Award has been granted pursuant to the Plan; capitalized terms used in this agreement which are not specifically defined herein shall have the meanings ascribed to such terms in the Plan.

Section 2. Performance Criteria and Terms of Share Award

(b) The Grantee may earn 50 percent or more of the target award of 4,000 Performance Shares (the “Target Award”) up to a maximum number of Performance Shares set forth in Section 1 above (the “Maximum Award”) based upon achievement of threshold and target levels of performance against the Performance Metrics established for the Performance Period . The Committee shall confirm the level of Award attained for the Performance Period after the Company’s independent auditors have certified the Company’s financial statements for each fiscal year of the Company in the Performance Period.

(g) If, during the Performance Period, the Grantee is separated from employment, Performance Shares shall be deemed earned or forfeited as follows:

(3) Upon retirement by the Grantee at age 55 or thereafter, all unearned Performance Shares shall be forfeited immediately.

Section 3. Additional Conditions to Issuance of Shares

Section 4. Adjustment of Shares

Section 5. No Right to Employment

Nothing contained in this Agreement shall be deemed by implication or otherwise to confer upon the Grantee any right to continued employment by the Company or any affiliate of the Company.

Section 6. Notice

Section 7. Beneficiary Designation

Section 8. Assumption of Risk

Section 9. Terms of Plan

Section 10. Governing Law; Amendment

Section 11. Action by the Committee

Section 12. Terms of Agreement

CHESAPEAKE UTILITIES CORPORATION

By:

Its:

Grantee:

psagreement2009bwc.htm

Exhibit 10.17

pursuant to the

CHESAPEAKE UTILITIES CORPORATION

PERFORMANCE INCENTIVE PLAN

On January 23, 2008, (the “Grant Date”), Chesapeake Utilities Corporation, a Delaware corporation (the “Company”), has granted to Beth W. Cooper (the “Grantee”), who resides at 46 Milbourn Manor Drive, Wyoming, DE 19934, a Performance Share Award on the terms and subject to the conditions of this Performance Share Agreement.

Recitals

WHEREAS, the Plan is effective January 1, 2006; and

Agreement

It is hereby covenanted and agreed by and between the Company and the Grantee as follows:

Section 1. Performance Share Award and Performance Period

The Company hereby grants to the Grantee a Performance Share Award as of the Grant Date. As more fully described herein, the Grantee may earn up to 8,000 Shares upon the Company's achievement of the performance criteria set forth in Section 2 (the “Performance Shares”) over the performance period from January 1, 2008 to December 31, 2009 (the “Performance Period”). This Award has been granted pursuant to the Plan; capitalized terms used in this agreement which are not specifically defined herein shall have the meanings ascribed to such terms in the Plan.

Section 2. Performance Criteria and Terms of Share Award

(b) The Grantee may earn 50 percent or more of the target award of 6,400 Performance Shares (the “Target Award”) up to a maximum number of Performance Shares set forth in Section 1 above (the “Maximum Award”) based upon achievement of threshold and target levels of performance against the Performance Metrics established for the Performance Period . The Committee shall confirm the level of Award attained for the Performance Period after the Company’s independent auditors have certified the Company’s financial statements for each fiscal year of the Company in the Performance Period.

(g) If, during the Performance Period, the Grantee is separated from employment, Performance Shares shall be deemed earned or forfeited as follows:

(3) Upon retirement by the Grantee at age 55 or thereafter, all unearned Performance Shares shall be forfeited immediately.

Section 3. Additional Conditions to Issuance of Shares

Section 4. Adjustment of Shares

Section 5. No Right to Employment

Nothing contained in this Agreement shall be deemed by implication or otherwise to confer upon the Grantee any right to continued employment by the Company or any affiliate of the Company.

Section 6. Notice

Section 7. Beneficiary Designation

Section 8. Assumption of Risk

Section 9. Terms of Plan

Section 10. Governing Law; Amendment

Section 11. Action by the Committee

Section 12. Terms of Agreement

CHESAPEAKE UTILITIES CORPORATION

By:

Its:

Grantee:

psagreement2010bwc.htm

Exhibit 10.18

pursuant to the

CHESAPEAKE UTILITIES CORPORATION

PERFORMANCE INCENTIVE PLAN

Recitals

WHEREAS, the Plan is effective January 1, 2006; and

Agreement

It is hereby covenanted and agreed by and between the Company and the Grantee as follows:

Section 1. Performance Share Award and Performance Period

The Company hereby grants to the Grantee a Performance Share Award as of the Grant Date. As more fully described herein, the Grantee may earn up to 4,000 Shares upon the Company's achievement of the performance criteria set forth in Section 2 (the “Performance Shares”) over the performance period from January 1, 2008 to December 31, 2010 (the “Performance Period”). This Award has been granted pursuant to the Plan; capitalized terms used in this agreement which are not specifically defined herein shall have the meanings ascribed to such terms in the Plan.

Section 2. Performance Criteria and Terms of Share Award

(b) The Grantee may earn 50 percent or more of the target award of 3,200 Performance Shares (the “Target Award”) up to a maximum number of Performance Shares set forth in Section 1 above (the “Maximum Award”) based upon achievement of threshold and target levels of performance against the Performance Metrics established for the Performance Period . The Committee shall confirm the level of Award attained for the Performance Period after the Company’s independent auditors have certified the Company’s financial statements for each fiscal year of the Company in the Performance Period.

(g) If, during the Performance Period, the Grantee is separated from employment, Performance Shares shall be deemed earned or forfeited as follows:

(3) Upon retirement by the Grantee at age 55 or thereafter, all unearned Performance Shares shall be forfeited immediately.

Section 3. Additional Conditions to Issuance of Shares

Section 4. Adjustment of Shares

Section 5. No Right to Employment

Nothing contained in this Agreement shall be deemed by implication or otherwise to confer upon the Grantee any right to continued employment by the Company or any affiliate of the Company.

Section 6. Notice

Section 7. Beneficiary Designation

Section 8. Assumption of Risk

Section 9. Terms of Plan

Section 10. Governing Law; Amendment

Section 11. Action by the Committee

Section 12. Terms of Agreement

CHESAPEAKE UTILITIES CORPORATION

By:

Its:

Grantee:

psagreement2009srz.htm

Exhibit 10.19

pursuant to the

CHESAPEAKE UTILITIES CORPORATION

PERFORMANCE INCENTIVE PLAN

On January 23, 2008, (the “Grant Date”), Chesapeake Utilities Corporation, a Delaware corporation (the “Company”), has granted to S. Robert Zola (the “Grantee”), who resides at 923 S. Schumaker Drive, Salisbury, MD 21804, a Performance Share Award on the terms and subject to the conditions of this Performance Share Agreement.

Recitals

WHEREAS, the Plan is effective January 1, 2006; and

Agreement

It is hereby covenanted and agreed by and between the Company and the Grantee as follows:

Section 1. Performance Share Award and Performance Period

Section 2. Performance Criteria and Terms of Share Award

(g) If, during the Performance Period, the Grantee is separated from employment, Performance Shares shall be deemed earned or forfeited as follows:

(3) Upon retirement by the Grantee at age 55 or thereafter, all unearned Performance Shares shall be forfeited immediately.

Section 3. Additional Conditions to Issuance of Shares

Section 4. Adjustment of Shares

Section 5. No Right to Employment

Nothing contained in this Agreement shall be deemed by implication or otherwise to confer upon the Grantee any right to continued employment by the Company or any affiliate of the Company.

Section 6. Notice

Section 7. Beneficiary Designation

Section 8. Assumption of Risk

Section 9. Terms of Plan

Section 10. Governing Law; Amendment

Section 11. Action by the Committee

Section 12. Terms of Agreement

CHESAPEAKE UTILITIES CORPORATION

By:

Its:

Grantee:

psagreement2010srz.htm

Exhibit 10.20