
2005			2004			2003			2002			2001			2000			1999

$	166,582		$	124,246		$	110,247		$	93,588		$	107,418		$	101,138		$	75,637
	48,976			41,500			41,029			29,238			35,742			31,780			25,199
	14,140			12,427			12,578			12,764			14,104			12,390			13,531
	(213	)		(218	)		(286	)		(334	)		(113	)		(131	)		(14	)

$	229,485		$	177,955		$	163,568		$	135,256		$	157,151		$	145,177		$	114,353

$	17,236		$	17,091		$	16,653		$	14,973		$	14,405		$	12,798		$	10,388
	3,209			2,364			3,875			1,052			913			2,135			2,622
	1,197			387			692			343			517			336			1,470
	279			335			359			237			386			816			495

$	21,921		$	20,177		$	21,579		$	16,605		$	16,221		$	16,085		$	14,975

$	10,699		$	9,686		$	10,079		$	7,535		$	7,341		$	7,665		$	8,372


$	280,345		$	250,267		$	234,919		$	229,128		$	216,903		$	192,925		$	172,068
$	201,504		$	177,053		$	167,872		$	166,846		$	161,014		$	131,466		$	117,663
$	295,980		$	241,938		$	222,058		$	223,721		$	222,229		$	211,764		$	166,958
$	33,423		$	17,830		$	11,822		$	13,836		$	26,293		$	22,057		$	21,365


$	84,757		$	77,962		$	72,939		$	67,350		$	67,517		$	64,669		$	60,714
	58,991			66,190			69,416			73,408			48,409			50,921			33,777

$	143,748		$	144,152		$	142,355		$	140,758		$	115,926		$	115,590		$	94,491

	4,929			2,909			3,665			3,938			2,686			2,665			2,665
	35,482			5,002			3,515			10,900			42,100			25,400			23,000

$	184,159		$	152,063		$	149,535		$	155,596		$	160,712		$	143,655		$	120,156

Page 26 Chesapeake Utilities Corporation 2008 Form 10-K

For the Years Ended December 31,

2005

2004

2003

2002⁽¹⁾

2001⁽¹⁾

Operating (in thousands of dollars)⁽³⁾

Revenues
Natural gas distribution and transmission
$
166,582
$ 124,246 $ 110,247 $ 93,588 $ 107,418
Propane
48,976
41,500 41,029 29,238 35,742
Advanced informations systems
14,140
12,427 12,578 12,764 14,104
Other and eliminations
(68
)
(218 ) (286 ) (334 ) (113 )
Total revenues
$
229,630
$ 177,955 $ 163,568 $ 135,256 $ 157,151

Operating income
Natural gas distribution and transmission
$
17,236
$ 17,091 $ 16,653 $ 14,973 $ 14,405
Propane
3,209
2,364 3,875 1,052 913
Advanced informations systems
1,197
387 692 343 517
Other and eliminations
(112
)
128 359 237 386
Total operating income
$
21,530
$ 19,970 $ 21,579 $ 16,605 $ 16,221

Net income from continuing operations
$
10,468
$ 9,550 $ 10,079 $ 7,535 $ 7,341

Assets (in thousands of dollars)

Gross property, plant and equipment
$
280,345
$ 250,267 $ 234,919 $ 229,128 $ 216,903
Net property, plant and equipment ⁽⁴⁾

$
201,504
$ 177,053 $ 167,872 $ 166,846 $ 161,014
Total assets ⁽⁴⁾

$
295,980
$ 241,938 $ 222,058 $ 223,721 $ 222,229
Capital expenditures ⁽³⁾

$
33,423
$ 17,830 $ 11,822 $ 13,836 $ 26,293

Capitalization (in thousands of dollars)

Stockholders' equity
$
84,757
$ 77,962 $ 72,939 $ 67,350 $ 67,517
Long-term debt, net of current maturities
58,991
66,190 69,416 73,408 48,409
Total capitalization
$
143,748
$ 144,152 $ 142,355 $ 140,758 $ 115,926

Current portion of long-term debt
$
4,929
$ 2,909 $ 3,665 $ 3,938 $ 2,686
Short-term debt
35,482
5,002 3,515 10,900 42,100
Total capitalization and short-term financing
$
184,159
$ 152,063 $ 149,535 $ 155,596 $ 160,712

⁽¹⁾ The years 2002, 2001, 2000 and 1999 have been restated in order to reflect the Company’s Delaware and Maryland natural gas divisions on the “accrual” rather than the “as billed” revenue recognition method.

⁽²⁾ The years 1998, 1997, and 1996 have not been restated to reflect the “accrual” revenue recognition method due to the immateriality of the impact on the Company’s financial results.

⁽³⁾ These amounts exclude the results of water services due to their reclassification to discontinued operations. The assets of all of the water businesses were sold in 2004 and 2003.

⁽⁴⁾ The years 2005, 2004, 2003, 2002 and 2001 reflect the results of adopting SFAS 143.

~~- Page 14 -~~

Item 6. Selected Financial Data


For the Years Ended December 31,	2008			2007			2006⁽³⁾
Common Stock Data and Ratios
Basic earnings per share from continuing operations⁽¹⁾	$	2.00		$	1.96		$	1.78
Diluted earnings per share from continuing operations⁽¹⁾	$	1.98		$	1.94		$	1.76

Return on average equity from continuing operations⁽¹⁾		11.2	%		11.5	%		11.0	%

Common equity / total capitalization		58.7	%		65.4	%		61.0	%
Common equity / total capitalization and short-term financing		49.4	%		50.6	%		51.1	%

Book value per share	$	18.03		$	17.64		$	16.62


Market price:
High	$	34.840		$	37.250		$	35.650
Low	$	21.930		$	28.000		$	27.900
Close	$	31.480		$	31.850		$	30.650


Average number of shares outstanding		6,811,848			6,743,041			6,032,462
Shares outstanding at year-end		6,827,121			6,777,410			6,688,084
Registered common shareholders		1,914			1,920			1,978

Cash dividends declared per share	$	1.21		$	1.18		$	1.16
Dividend yield (annualized)⁽²⁾		3.9	%		3.7	%		3.8	%
Payout ratio from continuing operations^{(1) (4)}		60.5	%		60.2	%		65.2	%


Additional Data
Customers
Natural gas distribution and transmission		65,201			62,884			59,132
Propane distribution		34,981			34,143			33,282


Volumes
Natural gas deliveries (in MMCF)		39,778			34,820			34,321
Propane distribution (in thousands of gallons)		27,956			29,785			24,243


Heating degree-days (Delmarva Peninsula)
Actual HDD		4,431			4,504			3,931
10 -year average HDD (normal)		4,401			4,376			4,372

Propane bulk storage capacity (in thousands of gallons)		2,471			2,441			2,315

Total employees⁽¹⁾		448			445			437


⁽¹⁾		These amounts exclude the results of distributed energy and water services due to their reclassification to discontinued operations. The Company closed its distributed energy operation in 2007. All assets of all of the water businesses were sold in 2004 and 2003.

⁽²⁾		Dividend yield (annualized) is calculated by multiplying the fourth quarter dividend by four (4), then dividing that amount by the closing common stock price at December 31.

⁽³⁾		SFAS No. 123R and SFAS No. 158 were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006.

⁽⁴⁾		The payout ratio from continuing operations is calculated by dividing cash dividends declared per share (for the year) by basic earnings per share from continuing operations.

Chesapeake Utilities Corporation 2008 Form 10-K Page 27


2005			2004			2003			2002			2001			2000			1999
$	1.83		$	1.68		$	1.80		$	1.37		$	1.37		$	1.46		$	1.63
$	1.81		$	1.64		$	1.76		$	1.37		$	1.35		$	1.43		$	1.59

	13.2	%		12.8	%		14.4	%		11.2	%		11.1	%		12.2	%		14.3	%

	59.0	%		54.1	%		51.2	%		47.8	%		58.2	%		55.9	%		64.3	%
	46.0	%		51.3	%		48.8	%		43.3	%		42.0	%		45.0	%		50.5	%

$	14.41		$	13.49		$	12.89		$	12.16		$	12.45		$	12.21		$	11.71


$	35.780		$	27.550		$	26.700		$	21.990		$	19.900		$	18.875		$	19.813
$	23.600		$	20.420		$	18.400		$	16.500		$	17.375		$	16.250		$	14.875
$	30.800		$	26.700		$	26.050		$	18.300		$	19.800		$	18.625		$	18.375


	5,836,463			5,735,405			5,610,592			5,489,424			5,367,433			5,249,439			5,144,449
	5,883,099			5,778,976			5,660,594			5,537,710			5,424,962			5,297,443			5,186,546
	2,026			2,026			2,069			2,130			2,171			2,166			2,212

$	1.14		$	1.12		$	1.10		$	1.10		$	1.10		$	1.07		$	1.03
	3.7	%		4.2	%		4.2	%		6.0	%		5.6	%		5.8	%		5.7	%
	62.3	%		66.7	%		61.1	%		80.3	%		80.3	%		73.3	%		63.2	%


	54,786			50,878			47,649			45,133			42,741			40,854			39,029
	32,117			34,888			34,894			34,566			35,530			35,563			35,267


	34,981			31,430			29,375			27,935			27,264			30,830			27,383
	26,178			24,979			25,147			21,185			23,080			28,469			27,788


	4,792			4,553			4,715			4,161			4,368			4,730			4,082
	4,436			4,389			4,409			4,393			4,446			4,356			4,409

	2,315			2,045			2,195			2,151			1,958			1,928			1,926

	423			426			439			455			458			471			466

Page 28 Chesapeake Utilities Corporation 2008 Form 10-K

For the Years Ended December 31,

2000⁽¹⁾

1999⁽¹⁾

1998⁽²⁾

1997⁽²⁾

1996⁽²⁾

Operating (in thousands of dollars)⁽³⁾

Revenues
Natural gas distribution and transmission $ 101,138 $ 75,637 $ 68,770 $ 88,108 $ 90,044
Propane 31,780 25,199 23,377 28,614 36,727
Advanced informations systems 12,390 13,531 10,331 7,786 7,230
Other and eliminations (131 ) (14 ) (15 ) (182 ) (243 )
Total revenues $ 145,177 $ 114,353 $ 102,463 $ 124,326 $ 133,758

Operating income
Natural gas distribution and transmission $ 12,798 $ 10,388 $ 8,820 $ 9,240 $ 9,627
Propane 2,135 2,622 965 1,137 2,668
Advanced informations systems 336 1,470 1,316 1,046 1,056
Other and eliminations 816 495 485 558 560
Total operating income $ 16,085 $ 14,975 $ 11,586 $ 11,981 $ 13,911

Net income from continuing operations $ 7,665 $ 8,372 $ 5,329 $ 5,812 $ 7,764

Assets (in thousands of dollars)

Gross property, plant and equipment $ 192,925 $ 172,068 $ 152,991 $ 144,251 $ 134,001
Net property, plant and equipment ⁽⁴⁾
$ 131,466 $ 117,663 $ 104,266 $ 99,879 $ 94,014
Total assets ⁽⁴⁾
$ 211,764 $ 166,958 $ 145,029 $ 145,719 $ 155,786
Capital expenditures ⁽³⁾
$ 22,057 $ 21,365 $ 12,516 $ 13,471 $ 15,399

Capitalization (in thousands of dollars)

Stockholders' equity $ 64,669 $ 60,714 $ 56,356 $ 53,656 $ 50,700
Long-term debt, net of current maturities 50,921 33,777 37,597 38,226 28,984
Total capitalization $ 115,590 $ 94,491 $ 93,953 $ 91,882 $ 79,684

Current portion of long-term debt $ 2,665 $ 2,665 $ 520 $ 1,051 $ 3,526
Short-term debt 25,400 23,000 11,600 7,600 12,735
Total capitalization and short-term financing $ 143,655 $ 120,156 $ 106,073 $ 100,533 $ 95,945

⁽¹⁾ The years 2002, 2001, 2000 and 1999 have been restated in order to reflect the Company’s Delaware and Maryland natural gas divisions on the “accrual” rather than the “as billed” revenue recognition method.

⁽²⁾ The years 1998, 1997, and 1996 have not been restated to reflect the “accrual” revenue recognition method due to the immateriality of the impact on the Company’s financial results.

⁽³⁾ These amounts exclude the results of water services due to their reclassification to discontinued operations. The assets of all of the water businesses were sold in 2004 and 2003.

⁽⁴⁾ The years 2005, 2004, 2003, 2002 and 2001 reflect the results of adopting SFAS 143.

~~- Page 15 -~~

~~Item 6. Selected Financial Data~~

For the Years Ended December 31,

2005

2004

2003

2002⁽¹⁾

2001⁽¹⁾

Common Stock Data and Ratios

Basic earnings per share from continuing operations ⁽³⁾

$
1.79
$ 1.66 $ 1.80 $ 1.37 $ 1.37
Diluted earnings per share from continuing operations ⁽³⁾

$
1.77
$ 1.64 $ 1.76 $ 1.37 $ 1.35

Return on average equity from continuing operations ⁽³⁾

12.9
%
12.7 % 14.4 % 11.2 % 11.1 %

Common equity / total capitalization
59.0
%
54.1 % 51.2 % 47.8 % 58.2 %
Common equity / total capitalization and short-term financing
46.0
%
51.3 % 48.8 % 43.3 % 42.0 %

Book value per share
$
14.41
$ 13.49 $ 12.89 $ 12.16 $ 12.45

Market price:
High
$
35.780
$ 27.550 $ 26.700 $ 21.990 $ 19.900
Low
$
23.600
$ 20.420 $ 18.400 $ 16.500 $ 17.375
Close
$
30.800
$ 26.700 $ 26.050 $ 18.300 $ 19.800

Average number of shares outstanding
5,836,463
5,735,405 5,610,592 5,489,424 5,367,433
Shares outstanding at year-end
5,845,571
5,730,801 5,612,935 5,500,357 5,394,516
Registered common shareholders
2,026
2,026 2,069 2,130 2,171

Cash dividends declared per share
$
1.14
$ 1.12 $ 1.10 $ 1.10 $ 1.10
Dividend yield (annualized) ⁽⁴⁾

3.7
%
4.2 % 4.2 % 6.0 % 5.6 %
Payout ratio from continuing operations ^{(3) (5)}

63.7
%
67.5 % 61.1 % 80.3 % 80.3 %

Additional Data

Customers
Natural gas distribution and transmission
54,786
50,878 47,649 45,133 42,741
Propane distribution
35,367
34,888 34,894 34,566 35,530

Volumes
Natural gas deliveries (in MMCF)
34,981
31,430 29,375 27,935 27,264
Propane distribution (in thousands of gallons)
26,178
24,979 25,147 21,185 23,080

Heating degree-days (Delmarva Peninsula)
4,792
4,553 4,715 4,161 4,368

Propane bulk storage capacity (in thousands of gallons)
2,315
2,045 2,195 2,151 1,958

Total employees ⁽³⁾

423
426 439 455 458

⁽¹⁾ The years 2002, 2001, 2000 and 1999 have been restated in order to reflect the Company’s Delaware and Maryland natural gas divisions on the “accrual” rather than the “as billed” revenue recognition method.

⁽²⁾ The years 1998, 1997, and 1996 have not been restated to reflect the “accrual” revenue recognition method due to the immateriality of the impact on the Company’s financial results.

⁽³⁾ These amounts exclude the results of water services due to their reclassification to discontinued operations. The assets of all of the water businesses were sold in 2004 and 2003.

⁽⁴⁾ Dividend yield (annualized) is calculated by multiplying the fourth quarter dividend declared by four (4), then dividing that amount by the closing common stock price at December 31.

⁽⁵⁾ The payout ratio from continuing operations is calculated by dividing cash dividends declared per share (for the year) by basic earnings per share from continuing operations.

~~- Page 16 -~~

~~Item 6. Selected Financial Data~~

For the Years Ended December 31,

2000⁽¹⁾

1999⁽¹⁾

1998⁽²⁾

1997⁽²⁾

1996⁽²⁾

Common Stock Data and Ratios

Basic earnings per share from continuing operations ⁽³⁾
$ 1.46 $ 1.63 $ 1.05 $ 1.17 $ 1.58
Diluted earnings per share from continuing operations ⁽³⁾
$ 1.43 $ 1.59 $ 1.04 $ 1.15 $ 1.54

Return on average equity from continuing operations ⁽³⁾
12.2 % 14.3 % 9.7 % 11.1 % 16.1 %

Common equity / total capitalization 55.9 % 64.3 % 60.0 % 58.4 % 63.6 %
Common equity / total capitalization and short-term financing 45.0 % 50.5 % 53.1 % 53.4 % 52.8 %

Book value per share $ 12.21 $ 11.71 $ 11.06 $ 10.72 $ 10.26

Market price:
High $ 18.875 $ 19.813 $ 20.500 $ 21.750 $ 18.000
Low $ 16.250 $ 14.875 $ 16.500 $ 16.250 $ 15.125
Close $ 18.625 $ 18.375 $ 18.313 $ 20.500 $ 16.875

Average number of shares outstanding 5,249,439 5,144,449 5,060,328 4,972,086 4,912,136
Shares outstanding at year-end 5,290,001 5,186,546 5,093,788 5,004,078 4,939,515
Registered common shareholders 2,166 2,212 2,271 2,178 2,213

Cash dividends declared per share $ 1.07 $ 1.03 $ 1.00 $ 0.97 $ 0.93
Dividend yield (annualized) ⁽⁴⁾
5.8 % 5.7 % 5.5 % 4.7 % 5.5 %
Payout ratio from continuing operations ^{(3) (5)}
73.3 % 63.2 % 95.2 % 82.9 % 58.9 %

Additional Data

Customers
Natural gas distribution and transmission 40,854 39,029 37,128 35,797 34,713
Propane distribution 35,563 35,267 34,113 33,123 31,961

Volumes
Natural gas deliveries (in MMCF) 30,830 27,383 21,400 23,297 24,835
Propane distribution (in thousands of gallons) 28,469 27,788 25,979 26,682 29,975

Heating degree-days (Delmarva Peninsula) 4,730 4,082 3,704 4,430 4,717

Propane bulk storage capacity (in thousands of gallons) 1,928 1,926 1,890 1,866 1,860

Total employees ⁽³⁾
471 466 431 397 338

⁽¹⁾ The years 2002, 2001, 2000 and 1999 have been restated in order to reflect the Company’s Delaware and Maryland natural gas divisions on the “accrual” rather than the “as billed” revenue recognition method.

⁽²⁾ The years 1998, 1997, and 1996 have not been restated to reflect the “accrual” revenue recognition method due to the immateriality of the impact on the Company’s financial results.

⁽³⁾ These amounts exclude the results of water services due to their reclassification to discontinued operations. The assets of all of the water businesses were sold in 2004 and 2003.

⁽⁴⁾ Dividend yield (annualized) is calculated by multiplying the fourth quarter dividend declared by four (4), then dividing that amount by the closing common stock price at December 31.

⁽⁵⁾ The payout ratio from continuing operations is calculated by dividing cash dividends declared per share (for the year) by basic earnings per share from continuing operations.

~~- Page 17 -~~

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

INTRODUCTION

This section provides management’s discussion of Chesapeake and its consolidated subsidiaries, with specific information on results of operations and liquidity and capital resources. It includes management’s interpretation of our financial results, the factors affecting these results, the major factors expected to affect future operating results and future investment and financing plans. This discussion should be read in conjunction with our consolidated financial statements and notes thereto.

~~Business Description~~Several factors exist that could influence our future financial performance, some of which are described in Item 1A above, “Risk Factors.” They should be considered in connection with evaluating forward-looking statements contained in this report, or otherwise made by or on behalf of us, since these factors could cause actual results and conditions to differ materially from those set out in such forward-looking statements.

EXECUTIVE OVERVIEW

Chesapeake ~~Utilities Corporation (“Chesapeake” or “the Company”)~~ is a diversified utility company engaged, directly or through subsidiaries in natural gas distribution, transmission and marketing, propane distribution and wholesale marketing, advanced information services and other related businesses.

~~Critical Accounting Policies~~

~~Chesapeake’s reported financial condition~~The Company’s strategy is focused on growing earnings from a stable utility foundation and ~~results~~investing in related businesses and services that provide opportunities for returns greater than traditional utility returns. The key elements of operations are affected by the accounting methods, assumptions and estimates that are used in the preparation of the Company’s financial statements. Because most of Chesapeake’s businesses are regulated, the accounting methods used by Chesapeake must comply with the requirements of the regulatory bodies; therefore, the choices available are limited by these regulatory requirements. Management believes that the following policies require significant estimates or other judgments of matters that are inherently uncertain. These policies and their application have been discussed with Chesapeake’s Audit Committee.

~~Regulatory Assets and Liabilities~~

Chesapeake records certain assets and liabilities in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 71 “Accounting for the Effects of Certain Types of Regulation.” Costs are deferred when there is a probable expectation that they will be recovered in future revenues as a result of the regulatory process. At December 31, 2005, Chesapeake had recorded regulatory assets of $5.6 million, including $4.0 million for under-recovered purchased gas costs, $712,000 for tax-related regulatory assets, and $304,000 for conservation cost recovery. The Company has recorded regulatory liabilities totaling $19.3 million, including $16.7 million for accrued asset removal cost, $1.4 million for self-insurance, $483,000 for cash in/cash out, and $328,000 for tax-related regulatory assets at December 31, 2005. If the Company were required to terminate application of SFAS No. 71, it would be required to recognize all such deferred amounts as a charge to earnings, net of applicable income taxes. Such a charge could have a material adverse effect on the Company’s results of operations.

~~Valuation of Environmental Assets and Liabilities~~

As more fully described in Note M to the Financial Statements, Chesapeake has completed its responsibilities related to one environmental site and is currently participating in the investigation, assessment or remediation of three other former gas manufacturing plant sites. Amounts have been recorded as environmental liabilities and associated environmental regulatory assets based on estimates of future costs provided by independent consultants. There is uncertainty in these amounts because the Environmental Protection Agency (“EPA”) or state authority may not have selected the final remediation methods. Additionally, there is uncertainty due to the outcome of legal remedies sought from other potentially responsible parties. At December 31, 2005, Chesapeake had recorded environmental regulatory assets of $195,000 and a regulatory liability of $298,000 for over-collections and an additional liability of $353,000 for environmental costs.

~~Propane Wholesale Marketing Contracts~~

Chesapeake’s propane wholesale marketing operation enters into forward and futures contracts that are considered derivatives under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” In accordance with the pronouncement, open positions are marked to market prices at the end of each reporting period and unrealized gains or losses are recorded in the Consolidated Statement of Income as revenue. The contracts all mature within one year, and are almost exclusively for propane commodities with delivery points of Mt. Belvieu, Texas, Conway, Kansas and Hattiesburg, Mississippi. Management estimates the market valuation based on references to exchange-traded futures prices, historical differentials and actual trading activity at the end of the reporting period. At December 31, 2005, these contracts had net unrealized gains of $46,000 that was recorded in the financial statements. At December 31, 2004, these contracts had net unrealized losses of $182,000 that were recorded in the financial statements.

this strategy include:

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

~~- Page 18 -~~

~~Operating Revenues~~

~~Revenues for~~expanding the natural gas distribution ~~operations of~~and transmission business through expansion into new geographic areas in our current service territories;

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

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

enhancing marketing channels to attract new customers;

providing reliable and responsive customer service to retain existing customers;

maintaining a capital structure that enables the Company are based on rates approved by the public service commissions of the jurisdictions in which we operate. The natural gas transmission operation’s revenues are based on rates approved by the Federal Energy Regulatory Commission (“FERC”). Customers’ base rates may not be changed without formal approval by these commissions. However, the regulatory authorities have granted the Company’s regulated natural gas distribution operations the ability to negotiate rates with customers that have competitive alternatives using approved methodologies. In addition, the natural gas transmission operation can negotiate rates above or below the FERC approved tariff rates.

~~Chesapeake’s natural gas distribution operations in Delaware~~access capital as needed; and Maryland each have a gas cost recovery mechanism that provides for the adjustment of rates charged to customers as gas costs fluctuate. These amounts are collected or refunded through adjustments to rates in subsequent periods.

The Company charges flexible rates to the natural gas distribution’s industrial interruptible customers to make them competitive with alternative types of fuel. Based on pricing, these customers can choose natural gas or alternative types of supply. Neither the Company nor the interruptible customer is contractually obligated to deliver or receive natural gas.

The propane wholesale marketing operation records trading activity, on a net mark-to-market basis in the Company’s income statement, for open contracts. The natural gas segment recognizes revenue on an accrual basis. The propane distribution, advanced information services and other segments record revenue in the period the products are delivered and/or services are rendered.

~~Goodwill Impairment~~

In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets,” Chesapeake no longer amortizes goodwill. Instead, 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 initial test was performed upon adoption of SFAS No. 142 on January 1, 2002, and again at the end of each subsequent year. These tests were based on subjective measurements, including discounted cash flows of expected future operating results and market valuations of similar businesses. The propane unit had $674,000 in goodwill at both December 31, 2005 and 2004. Testing for 2005 and 2004 has indicated that no impairment has occurred.

~~Results of Operations~~

Net Income & Diluted Earnings Per Share Summary

For the Years Ended December 31,

2005

2004

Increase (decrease)

2004

2003

Increase (decrease)

Net Income *

Continuing operations
$
10,468
$ 9,550 $ 918 $ 9,550 $ 10,080 ($530 )
Discontinued operations
-
(121 ) 121 (121 ) (788 ) 667
Total Net Income
$
10,468
$ 9,429 $ 1,039 $ 9,429 $ 9,292 $ 137

Diluted Earnings Per Share

Continuing operations
$
1.77
$ 1.64 $ 0.13 $ 1.64 $ 1.76 ($0.12 )
Discontinued operations
-
(0.02 ) 0.02 (0.02 ) (0.13 ) 0.11
Total Earnings Per Share
$
1.77
$ 1.62 $ 0.15 $ 1.62 $ 1.63 ($0.01 )

* Dollars in thousands.

maintaining a consistent and competitive dividend for shareholders.

~~- Page 19 -~~

The Company’s net income from continuing operations increased $918,000, or 10 percent, in 2005 compared to 2004. Net income from continuing operations was $10.5 million, or $1.77 per share (diluted), compared to a net income from continuing operations of $9.6 million, or $1.64 per share (diluted) for 2004.

Net income from continuing operations for 2004 was $9.6 million, or $1.64 per share (diluted), a decline of $530,000 compared to net income from continuing operations of $10.1 million, or $1.76 per share (diluted), for 2003.

During 2003, Chesapeake decided to exit the water services business and had sold the assets of six of seven dealerships by December 31, 2003. The remaining operation was sold in 2004. The results of water services were classified as discontinued operations for years 2004 and 2003. Discontinued operations experienced losses of $0.02 and $0.13 per share (diluted) for 2004 and 2003, respectively.

Operating Income Summary (in thousands)

For the Years Ended December 31,

2005

2004

Increase (decrease)

2004

2003

Increase (decrease)

Business Segment:

Natural gas distribution & transmission
$
17,236
$ 17,091 $ 145 $ 17,091 $ 16,653 $ 438
Propane
3,209
2,364 845 2,364 3,875 (1,511 )
Advanced information services
1,197
387 810 387 692 (305 )
Other & eliminations
(112
)
128 (240 ) 128 359 (231 )
Total Operating Income

$
21,530
$ 19,970 $ 1,560 $ 19,970 $ 21,579 ($1,609 )

~~The improvement in results for 2005 was primarily driven by:~~

The Lightweight Association Management Processing Systems (“LAMPS™”) product, including the sale of its property rights, contributed $622,000 to operating income in 2005 for the Company’s advanced information services segment. The LAMPS product was an internally developed software that was developed and marketed specifically for REALTOR® Associations.

·	~~The Delmarva and Florida natural gas distribution operations experienced strong residential customer growth of 8.7 percent and 7.4 percent, respectively, in 2005.~~

·	Temperatures on the Delmarva Peninsula were 5 percent colder than 2004, which led to increased contributions from the Company’s natural gas and propane distribution operations. This increase was offset by conservation efforts by customers.

·	~~The natural gas transmission operation achieved gross margin growth of 9 percent due to additional transportation capacity contracts that went into effect in November 2004.~~

·	~~A 100 percent increase of the number of customers for the Company’s natural gas marketing operation.~~

·	~~An increase of 1.1 million gallons sold by the Delmarva propane distribution operation.~~

Improvement in Chesapeake’s 2005 overall results compared to 2004 was primarily related to a $924,000 pre-tax gain on the sale of its LAMPS™ by the Company’s advanced information service operation, continued strong customer growth, and colder weather, which led to increased contributions from the Company’s natural gas and propane operations. The Company’s natural gas operations experienced an increase of 7.9 percent in residential customers. Weather, measured in heating degree-days, was 5 percent colder than 2004. The gross margin increases from growth and weather was partially offset by energy conservation efforts by customers in light of increased natural gas and propane costs and also, an increase in operating expenses.

Chesapeake’s 2004 results reflected strong customer growth, warmer weather as compared to 2003, customers’ energy conservation and costs incurred to comply with Sarbanes-Oxley. Weather, measured in heating degree-days, was 4 percent warmer than 2003. Management estimates that warmer weather negatively impacted gross margin by $566,000. The natural gas segment was able to offset the impact of warmer weather through customer growth of 7 percent. Additionally, the Company incurred approximately $600,000 of expenses through December 31, 2004 related to compliance with Section 404 of Sarbanes-Oxley. These costs include incremental audit fees, expansion of the Internal Audit Department and the temporary hiring of an outside consultant. The increase in operating income from the Company’s natural gas operations was more than offset by decreases in the propane and advanced information services businesses.

~~- Page 20 -~~

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

Chesapeake Utilities Corporation 2008 Form 10-K Page 29

Management’s Discussion and Analysis

~~Natural Gas Distribution~~Chesapeake had a successful 2008, in spite of the state of the global economic and ~~Transmission~~financial markets. For the year, net income increased by three percent as the Company earned $13.6 million in net income, or $1.98 per share (diluted), compared to net income of $13.2 million, or $1.94 per share (diluted), earned in 2007. We were able to achieve this growth despite taking a charge of $1.2 million in other operating expenses for costs related to an unconsummated acquisition. Absent this charge, the Company estimates that, compared to 2007, net income would have increased to $14.3 million, or $2.08 per share (diluted).

The higher period-over-period net income was attributable primarily to our natural gas segment. Our natural gas transmission and distribution operations continued to invest capital in current growth initiatives that favorably positioned us for future growth as well. These operations invested $25.6 million in property, plant, and equipment during 2008, primarily to expand our transmission and distribution systems. These expansions were undertaken pursuant to additional long-term firm transportation service contracts for our transmission operation and continued customer growth for the distribution operations. Collectively, these growth initiatives contributed $2.8 million to gross margin in 2008.

As a result of market conditions in the housing industry, the Company continued to see a slowdown in the number of new houses being constructed. Despite this slowdown, the average number of residential customers served by our natural gas distribution operations increased by four percent. While this growth percentage is lower than that experienced in recent years, it is still significantly above the national average.

PESCO experienced a record year as gross margin increased by 91 percent over 2007. This increase was achieved through enhanced sales contract terms, margins on spot sales of approximately $600,000 and a 26-percent growth in its customer base. A 26-percent increase in its customer base contributed to a 41-percent increase in volumes sold in 2008.

The successful completion of rate proceedings for the Company’s natural gas transmission and Delmarva distribution operations added $387,000 to gross margin in 2008. In addition, these rate proceedings provided for lower depreciation allowances and lower asset removal cost allowances, which contributed to the period-over-period decrease in depreciation expense and asset removal costs of $2.3 million in 2008.

Propane price volatility during 2008 affected our wholesale marketing operation positively and our propane distribution operation negatively. Xeron capitalized on the price volatility, seizing opportunities to sell at prices above cost and to manage effectively the larger spreads between the market (spot) prices and forward propane prices experienced in 2008, which contributed to the operation’s 38-percent year-over-year growth in gross margin.

In contrast, the volatility of wholesale propane prices had a negative impact on our propane distribution operations. Wholesale propane prices rose dramatically during the spring months of 2008, when they are traditionally falling. In efforts to protect the Company from the impact that additional price increases would have on our Pro-Cap (propane price-cap) Plan that we offer to customers, the propane distribution operation entered into a swap agreement. By December 31, 2008, the market price of propane had plummeted well below the unit price in the swap agreement. As a result, the Company marked the agreement relating to the January 2009 and February 2009 gallons to market, which increased cost of sales by $939,000 for 2008 and resulted in the Company adjusting the valuation of its propane inventory to current market prices in accordance with Accounting Research Bulletin No. 43. Both of these adjustments reduced gross margin during 2008 by a total of $2.3 million compared to 2007. The Company subsequently terminated the swap agreement in January 2009.

Adverse economic conditions severely affected the advanced information services segment. BravePoint experienced lower consulting revenues as customers began to conserve their information technology spending, resulting in a nine percent decline in billable hours in 2008 compared to 2007.

In response to the instability and volatility of the financial markets, we increased the amounts of our committed short-term borrowing capacity from $15.0 million to $55.0 million, while maintaining total short-term line-of-credit capacity of $100.0 million. In addition, on October 31, 2008, the Company executed a $30.0 million long-term debt placement of 5.93 percent Unsecured Senior Notes, maturing on October 31, 2023.

Page 30 Chesapeake Utilities Corporation 2008 Form 10-K

Operating Income

The year-over-year increase in operating income for 2008, driven by the strong performance of our natural gas business segment, was partially offset by lower operating income from the propane and advanced information services business segments.


								Percentage
(In thousands)	2008		2007		Change			Change
Natural gas	$	25,846	$	22,485	$	3,361			15	%
Propane		1,586		4,498		(2,912	)		-65	%
Advanced information services		695		836		(141	)		-17	%
Other & eliminations		352		295		57			19	%

Total operating income	$	28,479	$	28,114	$	365			1	%

The Company’s financial performance is discussed in greater detail below in “Results of Operations.”

Critical Accounting Policies

Chesapeake prepares its financial statements in accordance with GAAP. Application of these accounting principles requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingencies during the reporting period. Chesapeake bases its estimates on historical experience and on various assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Since most of Chesapeake’s businesses are regulated and the accounting methods used by these businesses must comply with the requirements of the regulatory bodies, the choices available are limited by these regulatory requirements. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from estimates. Management believes that the following policies require significant estimates or other judgments of matters that are inherently uncertain. These policies and their application have been discussed with Chesapeake’s Audit Committee.

Regulatory Assets and Liabilities

As a result of the ratemaking process, Chesapeake records certain assets and liabilities in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation;” consequently, the accounting principles applied by our regulated utilities differ in certain respects from those applied by the unregulated businesses. Costs are deferred when there is a probable expectation that they will be recovered in future revenues as a result of the regulatory process. As more fully described in Note A to the Consolidated Financial Statements, Chesapeake had recorded regulatory assets of $3.6 million and regulatory liabilities of $24.7 million, at December 31, 2008. If the Company were required to terminate application of SFAS No. 71, it would be required to recognize all such deferred amounts as a charge or a credit to earnings, net of applicable income taxes. Such an adjustment could have a material effect on the Company’s results of operations.

Valuation of Environmental Assets and Liabilities

As more fully described in Note N, “Environmental Commitments and Contingencies,” in the Notes to the Consolidated Financial Statements, Chesapeake has completed its responsibilities related to one environmental site and is currently participating in the investigation, assessment or remediation of three other former manufactured gas plant sites. Amounts have been recorded as environmental liabilities and associated environmental regulatory assets based on estimates of future costs provided by independent consultants. There is uncertainty in these amounts, because the United States Environmental Protection Agency (“EPA”) or other applicable state environmental authority may not have selected the final remediation methods. In addition, there is uncertainty with regard to amounts that may be recovered from other potentially responsible parties.

Chesapeake Utilities Corporation 2008 Form 10-K Page 31

Management’s Discussion and Analysis

Since the Company’s management believes that recovery of these expenditures, including any litigation costs, is probable through the regulatory process, the Company has recorded, in accordance with SFAS No. 71, a regulatory asset and corresponding regulatory liability. At December 31, 2008, Chesapeake had recorded an environmental regulatory asset of $779,000 and a liability of $511,000 for environmental costs.

Derivatives

Chesapeake may use derivative instruments to manage the price risk of its natural gas and propane purchasing activities. The Company continually monitors the use of these instruments to ensure compliance with its risk management policies and accounts for them in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” by recording their fair value as assets and liabilities. If the derivative contracts meet the “normal purchase and normal sale” scope exception of SFAS No. 133, the related activities and services are accounted for on an accrual basis of accounting.

The following is a review of Chesapeake’s use of derivative instruments at December 31, 2008 and 2007:

The natural gas distribution and ~~transmission segment earned operating income~~marketing operations, during 2008 and 2007, entered into physical contracts for the purchase and sale of ~~$17.2 million~~natural gas, which qualified for ~~2005, $17.1 million~~the “normal purchases and normal sales” scope exception under SFAS No. 133 in that they provided for ~~2004, and $16.7 million for 2003, resulting~~the purchase or sale of natural gas to be delivered in ~~increases~~quantities expected to be used or sold by the Company over a reasonable period of ~~$145,000 for 2005 and $438,000 for 2004.~~

time in the normal course of business. Accordingly, they were not subject to the accounting requirements of SFAS No. 133.

Natural Gas Distribution and Transmission (in thousands)

For the Years Ended December 31,

2005

2004

Increase (decrease)

2004

2003

Increase (decrease)

Revenue
$
166,582
$ 124,246 $ 42,336 $ 124,246 $ 110,247 $ 13,999
Cost of gas
116,178
77,456 38,722 77,456 65,495 11,961
Gross margin
50,404
46,790 3,614 46,790 44,752 2,038

Operations & maintenance
23,874
21,129 2,745 21,129 19,893 1,236
Depreciation & amortization
5,682
5,418 264 5,418 5,188 230
Other taxes
3,612
3,152 460 3,152 3,018 134
Other operating expenses
33,168
29,699 3,469 29,699 28,099 1,600

Total Operating Income

$
17,236
$ 17,091 $ 145 $ 17,091 $ 16,653 $ 438

During 2008 and 2007, Chesapeake’s propane distribution operations entered into physical contracts to buy propane supplies, which qualified for the “normal purchases and normal sales” scope exception under SFAS No. 133 in that they provided for the purchase or sale of propane to be delivered in quantities expected to be used or sold by the Company over a reasonable period of time in the normal course of business. Accordingly, the related liabilities incurred and assets acquired under these contracts were recorded when title to the underlying commodity passed.

During 2008, but not during 2007, the propane distribution operation entered into a swap agreement to protect the Company from the impact of price increases on the Pro-Cap (propane 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 No. 133. At the end of the period, the market price of propane dropped below the unit price in the swap agreement. As a result of the price drop, the Company marked the agreement relating to the January 2009 and February 2009 gallons to market, which increased cost of sales in 2008 by approximately $939,000. In January 2009, the Company terminated this swap agreement.

Chesapeake’s propane wholesale marketing operation enters into forward and futures contracts that are considered derivatives under SFAS No. 133. In accordance with SFAS No. 133, open positions are marked to market using prices at the end of each reporting period and unrealized gains or losses are recorded in the Consolidated Statement of Income as revenue or expense. The contracts mature within one year and are almost exclusively for propane commodities, with delivery points at Mt. Belvieu, Texas; Conway, Kansas; and Hattiesburg, Mississippi. Management estimates the market valuation based on references to exchange-traded futures prices, historical differentials and actual trading activity at the end of the reporting period. Commodity price volatility may have a significant impact on the gain or loss in any given period. At December 31, 2008, these contracts had net unrealized gains of $1.4 million that were recorded in the financial statements. At December 31, 2007, these contracts had net unrealized gains of $179,000 that were recorded in the financial statements.

Natural Gas Heating Degree-Day (HDD) and Customer Analysis

For the Years Ended December 31,

2005

2004

Increase (decrease)

2004

2003

Increase (decrease)

Heating degree-day data — Delmarva
Actual HDD
4,792
4,553 239 4,553 4,715 (162 )
10-year average HDD
4,436
4,383 53 4,383 4,409 (26 )

Estimated gross margin per HDD
$
2,234
$ 1,800 $ 434 $ 1,800 $ 1,680 $ 120

Estimated dollars per residential customer added:
Gross margin
$
372
$ 372 $ 0 $ 372 $ 360 $ 12
Other operating expenses
$
106
$ 104 $ 2 $ 104 $ 100 $ 4

Average number of residential customers
Delmarva
37,346
34,352 2,994 34,352 31,996 2,356
Florida
11,717
10,910 807 10,910 10,189 721
Total
49,063
45,262 3,801 45,262 42,185 3,077
Operating Revenues

Revenues for the natural gas distribution operations of the Company are based on rates approved by the PSCs of the jurisdictions in which we operate. The natural gas transmission operation’s revenues are based on rates approved by the FERC. Customers’ base rates may not be changed without formal approval by these commissions. The PSCs, however, have granted the Company’s regulated natural gas distribution operations the ability to negotiate rates, based on approved methodologies, with customers that have competitive alternatives. In addition, the natural gas transmission operation can negotiate rates above or below the FERC-approved tariff rates.

~~2005 Compared~~Page 32 Chesapeake Utilities Corporation 2008 Form 10-K

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⁾
$ 4,929,091 $ 15,312,727 $ 13,312,727 $ 30,364,909 $ 63,919,454
Operating leases ⁽²⁾
645,576 1,062,394 692,741 2,376,302 4,777,013
Purchase obligations ⁽³⁾

Transmission capacity 7,585,816 12,497,472 11,890,259 25,015,062 56,988,609
Storage — Natural Gas 1,422,987 2,709,353 2,696,217 6,518,563 13,347,120
Commodities 20,012,976 - - - 20,012,976
Forward purchase contracts — Propane ⁽⁴⁾
21,622,201 - - - 21,622,201
Unfunded benefits ⁽⁵⁾
259,399 528,995 551,782 2,678,755 4,018,931
Funded benefits ⁽⁶⁾
68,680 129,697 111,081 1,376,178 1,685,636
Total Contractual Obligations

$
56,546,726

$
32,240,638

$
29,254,807

$
68,329,769

$
186,371,940

⁽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 $4.5 million, $7.7 million, $5.7 million and $7.2 million, respectively, for the periods indicated above. Expected interest payments for all periods total $25.1 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 $4.0 million at December 31, 2005 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 $1.7 million at December 31, 2005 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, 2005. 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.

~~- Page 29 -~~

Off-Balance Sheet Arrangements

The Company has issued corporate guarantees to certain vendors of its subsidiaries, primarily its propane wholesale marketing subsidiary ~~advanced information services,~~ and ~~the Florida~~its natural gas supply ~~and~~ management ~~services~~ subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases ~~and office rent~~ in the event of the ~~subsidiaries’~~respective subsidiary’s default. None of these subsidiaries has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are ~~included~~recorded in ~~our~~the Consolidated Financial ~~Statements.~~Statements when incurred. The ~~guarantees~~aggregate amount guaranteed at December 31, ~~2005, totaled $11.2~~2008 was $22.2 million, ~~and expire~~with the guarantees expiring on various dates in ~~2006.~~2009.

Chesapeake Utilities Corporation 2008 Form 10-K Page 51

Management’s Discussion and Analysis

~~The~~In addition to the corporate guarantees, the Company has issued a letter of credit to its ~~main~~primary insurance company for ~~$694,000,~~$775,000, which expires on May 31, ~~2006.~~2009. The letter of credit ~~was~~is provided as security ~~for claims amounts below~~to satisfy the deductibles onunder the Company’s various insurance policies. There have been no draws on this letter of credit as of December 31, 2008.

Rate Filings and Other Regulatory Activities

The Company’s natural gas distribution operations in Delaware, Maryland and Florida are subject to regulation by ~~the Delaware, Maryland and Florida Public Service Commissions. The natural gas transmission operation~~their respective PSC; ESNG is subject to regulation by the FERC.

~~Delaware.~~ ~~On October 3, 2005, the Delaware division filed its annual Gas Sales Service Rates (“GSR”) application that~~ At December 31, 2008, Chesapeake was effective for service rendered on and after November 1, 2005 with the Delaware Public Service Commission (“Delaware PSC”). On October 11, 2005, the Delaware PSC approved the GSR charges, subject to full evidentiary hearings and a final decision. An evidentiary hearing is currently scheduled for April 6, 2006, with a final decision by the Delaware PSC expected during the second involved in rate filings and/or ~~third quarter of 2006.~~

On November 1, 2005, the Delaware division filed with the Delaware PSC its annual Environmental Rider (“ER”) Rate application that was effective for service rendered on and after December 1, 2005. The Delaware PSC granted approvalregulatory matters in each of the ERjurisdictions in which it operates. Each of these rate ~~at its regularly scheduled meeting on November 8, 2005, subject to full evidentiary hearings~~filings or regulatory matters is fully described in Note O, “Other Commitments and ~~a final decision. An evidentiary hearing is currently scheduled for April 5, 2006, with a final decision by the Delaware PSC expected during the second or third quarter of 2006.~~

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. While Chesapeake does provide natural gas service to residents and businesses in portions of Sussex County, under the Company’s current tariff and traditional ratemaking processes, natural gas has not been extendedContingencies,” to the State of Delaware’s recently targeted growth areas in eastern Sussex County. In April 2002, Governor Ruth Ann Minner established the Delaware Energy Task Force (“Task Force”), whose mission was to address the State of Delaware’s long-term and short-term energy challenges. In September 2003, the Task Force issued its final report to the Governor that included a strategy related to enhancing the availability of natural gas within the State by evaluating possible incentives for expanding residential and commercial natural gas service. Chesapeake believes its current proposal to implement a rate design that will enable the Company to provide natural gas as a viable energy choice to a broad number of prospective customers within eastern Sussex County is consistent with the Task Force recommendation. While the Company cannot predict the outcome of its application at this time, the Company anticipates a final decision from the Delaware PSC regarding its application during the first half of 2006.Consolidated Financial Statements.

~~Maryland.~~ On December 8, 2005, the Maryland Public Service Commission (“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, 2005. On January 12, 2006, the Hearing Examiner issued proposed findings approving the quarterly gas cost recovery rates as filed by the Maryland division, permitting complete recovery of its purchased gas costs for the period under review. The Maryland PSC did not receive any appeals or written exceptions to the proposed findings and as a result a final order was issued on February 14, 2006.

~~Florida.~~ On August 25, 2004, the Florida division filed a petition with the Florida Public Service Commission (“Florida PSC”) for authorization to restructure rates and establish new customer classifications. The filing was revenue-neutral, but would allow the Florida division to collect a greater percentage of revenues from fixed charges, rather than variable charges based upon consumption. On February 1, 2005, the Florida PSC voted to approve the petition, as modified by the PSC staff. The Florida PSC issued a final order on February 22, 2005.

~~- Page 30 -~~

On May 16, 2005, the Florida division filed for approval of a Special Contract with the Department of Management Services, an agency of the State of Florida, for service to the Washington Correction Institution (“WCI”). The Florida Public Service Commission approved the Company’s request on July 19, 2005, and service to the existing WCI facility is expected to begin during the first quarter of 2006. WCI is located in Washington County in the Florida panhandle and would become the thirteenth county served by the Company’s Florida division.

On September 2, 2005, the Florida division filed a petition for a Declaratory Statement with the FPSC for a determination that Peninsula Pipeline Company, Inc. (“PPC”), a wholly owned subsidiary of the Company, qualifies as a natural gas transmission company under the Natural Gas Transmission Pipeline Intrastate Regulatory Act. The Florida PSC approved this Petition at its December 20, 2005 agenda conference, and a final order was issued on January 9, 2006. A determination that PPC does qualify as a natural gas transmission company would provide opportunities for investment to deliver gas service to industrial customers in Florida by an intra-state pipeline, instead of through Chesapeake Utilities Corporation, to certain niche markets.

~~Eastern Shore~~. During October 2002, Eastern Shore filed for recovery of gas supply realignment costs, which totaled $196,000 (including interest), associated with the implementation of FERC Order No. 636. At that time, the FERC deferred review of the filing pending settlement of a related matter concerning another transmission company. Chesapeake understands that the other matter has now been resolved and Eastern Shore intends to resubmit its gas supply realignment filing during first quarter of 2006.

On April 1, 2003, Eastern Shore filed an application for a Certificate of Public Convenience and Necessity (“Application”) before the FERC requesting authorization to construct the necessary facilities to enable Eastern Shore to provide additional daily firm transportation capacity of 15,100 dekatherms over a three-year period commencing November 1, 2003. On October 8, 2003, the FERC issued an order granting Eastern Shore the authority to construct and operate certain pipeline and measurement facilities in its service territories as requested. Phases I and II of the Application began providing services November 1, 2003 and 2004, respectively. On December 22, 2004, Eastern Shore filed to amend the above-referenced Application to seek FERC authorization to construct and operate new pipeline facilities to provide an additional 7,450 dekatherms of daily firm transportation service, as requested by its customers, to be available November 1, 2005. On June 27, 2005, the FERC issued an Order Amending Certificate, granting approval to Eastern Shore to construct and operate the additional pipeline facilities requested. Phase III began November 1, 2005.

On December 9, 2005, Eastern Shore filed revised tariff sheets to replace its existing fixed price penalties with penalties that are the higher of a fixed price or a multiple of a daily index price. The revised penalties are applicable to customers who violate operational Flow Orders and customers who take unauthorized overrun quantities that could threaten the operational integrity of the pipeline, or to Eastern Shore’s ability to render reliable service. By letter order dated January 6, 2006, the FERC accepted Eastern Shore’s proposed changes, effective December 21, 2005.

Eastern Shore is also following the FERC’s recent rulemaking pertaining to creditworthiness standards for customers of interstate natural gas pipelines. FERC has not yet issued its final rules in this proceeding. Upon such issuance, Eastern Shore will evaluate its currently effective tariff creditworthiness provisions to determine whether any actions will need to be taken to conform to the FERC’s final rules.

Environmental Matters

The Company continues to work with federal and state environmental agencies to assess the environmental impact and explore corrective action at three ~~other~~ environmental sites (see Note MN 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.

~~- Page 31 -~~

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 ~~the change~~changes in interest rates. The Company’s long-term debt consists of ~~first mortgage bonds,~~fixed-rate senior notes and convertible debentures (see Note HI to the Consolidated Financial Statements for annual maturities of consolidated long-term debt). All of ~~Chesapeake’s~~the Company’s long-term debt is fixed-rate debt and was not entered into for trading purposes. The carrying value of ~~the Company’s~~ long-term debt, including current maturities, was ~~$63.9~~$93.1 million at December 31, ~~2005,~~2008, as compared to a fair value of ~~$68.5~~$92.3 million, based ~~mainly~~ on ~~current market prices or~~a discounted cash ~~flows using current~~flow methodology that incorporates a market interest rate that is based on published corporate borrowing rates for ~~similar issues~~debt instruments with similar terms and ~~remaining maturities.~~average maturities with adjustments for duration, optionality, and risk profile. The Company evaluates whether to refinance existing debt or permanently ~~finance~~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 ~~of propane~~ (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. At December 31, ~~2005,~~2008, the propane distribution operation had entered into a ~~put contract~~swap agreement to protect the ~~value~~Company from the impact of ~~2.1 million gallons~~price increases on the Pro-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 No. 133. At the end of 2008, the market price of propane, ~~inventory from~~valued using broker or dealer quotations, or market transactions in either the listed or OTC markets, dropped below the unit price in the swap agreement. As a result of the price drop, the Company marked the January and February gallons in ~~fair value. The Company settled~~ the ~~put in January 2006,~~agreement to market, which resulted in an increase to cost of sales of $939,000. The Company subsequently terminated the swap agreement in January 2009. The Company did not enter into a ~~benefit of $28,000.~~

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~~natural gas liquids at a fixed price at fixed future dates. At expiration, the contracts are settled by the delivery of ~~NGL~~natural gas liquids to the Company or the ~~counter party~~counter-party or ~~booking out~~“booking out” the ~~transaction (booking~~transaction. Booking out is a procedure for financially settling a contract in lieu of the physical delivery of ~~energy).~~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.~~price; however, they may also be settled by physical receipt or delivery of propane.

Page 52 Chesapeake Utilities Corporation 2008 Form 10-K

The forward and futures contracts are entered into for trading and wholesale marketing purposes. The propane wholesale marketing ~~operation~~business is subject to commodity price risk on its open positions to the extent that market prices for ~~NGL~~natural gas liquids deviate from fixed contract settlement ~~amounts.~~prices. Market risk associated with the trading of futures and forward contracts ~~are~~is monitored daily for compliance with ~~Chesapeake’s~~the Company’s Risk Management Policy, which includes volumetric limits for open positions. To manage exposures to changing market prices, open positions are marked up or down to market prices and reviewed by the Company’s oversight officials ~~on a daily basis. Additionally,~~daily. In addition, the Risk Management Committee reviews periodic reports on ~~market~~markets and the credit risk of counter-parties, approves any exceptions to the Risk Management Policy (within ~~the~~ limits established by the Board of Directors) and authorizes the use of any new types of contracts. Quantitative information on ~~the~~ forward and futures contracts at December 31, ~~2005~~2008 and ~~2004~~2007 is ~~shown~~presented in the following ~~charts.~~

tables.


	Quantity in		Estimated Market	Weighted Average
At December 31, 2008	gallons		Prices	Contract Prices
Forward Contracts
Sale		10,626,000	$0.5450 – $1.9100	$	0.9984
Purchase		9,949,800	$0.7000 – $1.9600	$	1.0233

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

~~- Page 32 -~~


	Quantity in		Estimated Market	Weighted Average
At December 31, 2007	gallons		Prices	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.

At December 31, 2008 and 2007, the Company marked these forward contracts to market, using broker or dealer quotations, or market transactions in either the listed or OTC markets, which resulted in the following assets and liabilities:


December 31,	2008		2007
(in thousands)
Marked-to-market energy assets	$	4,482	$	7,812
Marked-to-market energy liabilities	$	3,052	$	7,739

At December 31, 2005

Quantity in gallons

Estimated Market Prices

Weighted Average Contract Prices

Forward Contracts

Sale 20,794,200 $1.0350 — $1.1013 $1.0718
Purchase 20,202,000 $1.0100 — $1.0450 $1.0703

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

All contracts expire in 2006.

At December 31, 2004

Quantity in gallons

Estimated Market Prices

Weighted Average Contract Prices

Forward Contracts

Sale 10,044,510 $0.7725 — $0.7750 $0.7828
Purchase 9,975,000 $0.7300 — $0.7500 $0.8007

Futures Contracts

Sale 378,000 $0.7450 — $0.7500 $0.7868
Purchase 420,000 $0.7200 — $0.7300 $0.7500

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

All contracts expired in 2005.

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.

Chesapeake Utilities Corporation 2008 Form 10-K Page 53

Management’s Discussion and Analysis

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~~large-volume industrial customers that ~~have the capacity to~~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 in~~requirements, and our interruptible sales ~~occur when~~volumes may decline because oil prices are lower ~~relative to~~than the price of natural gas. Oil prices, as well as the prices of electricity and other fuels, ~~are subject to fluctuation~~fluctuate for a variety of reasons; therefore, future competitive conditions are not predictable. To address this uncertainty, the Company uses flexible pricing arrangements on both the supply and sales ~~side~~sides of this business to ~~maximize sales volumes.~~compete with alternative fuel price fluctuations. As a result of the transmission ~~business’~~operation’s conversion to open access and the Florida gas distribution division’s restructuring of its services, ~~their~~these businesses have shifted from providing ~~competitive~~bundled transportation and sales service to providing only transportation and contract storage services.

The Company’s natural gas distribution operations ~~located~~ in Delaware, Maryland and Florida offer unbundled transportation services to certain commercial and industrial customers. In 2002, the Florida operation extended ~~transportation~~such service to residential customers. With such transportation service available on the Company’s distribution systems, the Company is competing with ~~third party~~third-party suppliers to sell gas to industrial customers. ~~As it relates~~With respect to unbundled transportation services, the Company’s competitors include ~~the~~ interstate transmission ~~company~~companies, if the distribution ~~customer is~~customers are located close enough to ~~the~~a transmission company’s pipeline to make ~~a connection~~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 unbundled transportation service to additional classes of distribution customers in the future. The Company has also established a natural gas sales and supply management operation in Florida, Delaware and Maryland to ~~compete for~~provide such service to customers eligible for unbundled transportation services. ~~The Company also provides sales service in Delaware.~~

~~- Page 33 -~~

The Company’s propane distribution operations compete with several other propane distributors in their ~~service territories,~~respective geographic markets, primarily on the basis of service and price, emphasizing ~~reliability of service~~responsive and ~~responsiveness. Competition is~~reliable service. Our competitors generally ~~from~~include local outlets of national ~~distribution companies~~distributors and local ~~businesses, because~~independent distributors, ~~located in close~~whose proximity to customers ~~incur~~entails lower costs ~~of providing~~to provide service. Propane competes with electricity as an energy source, because it is typically less expensive than electricity, based on equivalent BTU value. Propane also competes with home heating oil as an energy source. Since natural gas has historically been less expensive than propane, propane is generally not distributed in geographic areas ~~serviced~~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~~and could adversely ~~impact~~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 ~~operation,~~operations, maintenance and capital improvements. While the impact of inflation has remained low in recent years, natural gas and propane prices are subject to rapid fluctuations. ~~Fluctuations~~In 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 ~~while monitoring~~and closely monitors the returns of its unregulated business operations. To compensate for fluctuations in propane gas prices, ~~Chesapeake~~the Company adjusts its propane selling prices to the extent allowed by the market.

Page 54 Chesapeake Utilities Corporation 2008 Form 10-K

~~Recent Pronouncements~~

In December 2004, the FASB released a revision (“Share-Based Payment”) to SFAS No. 123 “Accounting for Stock-Based Compensation,” referred to as SFAS No. 123R. In April 2005, the SEC approved a new rule that delayed the effective date for SFAS No. 123R until the first annual period beginning after June 15, 2005. This Statement establishes financial accounting and reporting standards for stock-based employee compensation plans. Those plans include all arrangements by which employees receive shares of stock or other equity instruments of the employer or the employer incurs liabilities to employees in amounts based on the price of the employer’s stock. Examples are stock purchase plans, stock options, restricted stock and stock appreciation rights. The adoption of this pronouncement will not have a material impact on the Company’s financial statements.

In March 2005, the FASB issued Interpretation No. 47 (“FIN No. 47”), “Accounting for Conditional Asset Retirement Obligations,” an interpretation of SFAS No. 143. FIN No. 47 clarifies that the term conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event. FIN No. 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The Company adopted FIN No. 47 during the fourth quarter of 2005 and it did not have a material impact on its financial statements.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3”. SFAS No. 154 primarily requires retrospective application to prior periods’ financial statements for the direct effects of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. This statement applies to all voluntary changes in accounting principle and also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. The statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company is required to adopt the provision of SFAS No. 154, as applicable, beginning in fiscal year 2006.

~~- Page 34 -~~

Cautionary Statement

Chesapeake Utilities Corporation has made statements in this ~~report~~Form 10-K that are considered to be ~~forward-looking statements.~~“forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are not matters of historical ~~fact. Sometimes they contain~~fact and are typically identified by words such as, but not limited to, “believes,” “expects,” “intends,” “plans,” ~~“will”~~and similar expressions, or future or conditional verbs such as “may,” “will,” “should,” “would,” and ~~other similar words of a predictive nature.~~“could.” These statements relate to matters such as customer growth, changes in revenues or gross ~~margin,~~margins, capital expenditures, environmental remediation costs, regulatory ~~approvals,~~trends and decisions, market risks associated with our propane operations, the ~~Company’s propane wholesale marketing operation, competition,~~competitive position of the Company, inflation, and other matters. It is important to understand that these forward-looking statements are not ~~guarantees but~~guarantees; rather, they 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. ~~These~~Such factors include, ~~among other things:~~but are not limited to:

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

o	~~the effect of spot, forward and futures market prices on the Company’s distribution, wholesale marketing and energy trading businesses;~~

o	~~the effects of competition on the Company’s unregulated and regulated businesses;~~

o	~~the effect of changes in federal, state or local regulatory and tax requirements, including deregulation;~~

o	~~the effect of accounting changes;~~

o	~~the effect of changes in benefit plan assumptions;~~

o	~~the effect of compliance with environmental regulations or the remediation of environmental damage;~~

o	~~the effects of general economic conditions on the Company and its customers;~~

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

o	~~the Company’s ability to obtain the rate relief and cost recovery requested from utility regulators and the timing of the requested regulatory actions.~~

~~- Page 35 -~~

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;

the impact that declining propane prices may have on the valuation of our propane inventory;

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, return on plan assets, and funding requirements;

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 impact of the volatility in the financial and credit markets on the Company’s ability to access credit;

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;

the 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.

Chesapeake Utilities Corporation 2008 Form 10-K Page 55

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 ~~Supplemental~~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”~~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, ~~2005.~~2008.

Page 56 Chesapeake Utilities Corporation 2008 Form 10-K

Management’s assessment of the effectiveness of Chesapeake’s internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

~~- Page 36 -~~

Report of Independent Registered Public Accounting Firm

~~________~~

To the Board of Directors and
Stockholders

of Chesapeake Utilities Corporation

We have ~~completed integrated audits~~audited the accompanying consolidated balance sheets of Chesapeake Utilities ~~Corporation’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting~~Corporation as of December 31, ~~2005,~~2008 and 2007, and the related consolidated statements of income, stockholders’ equity, cash flows and income taxes for the years then ended. Chesapeake Utilities Corporation’s management is responsible for these consolidated financial statements. Our responsibility is to express an ~~audit of its 2003~~opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). ~~Our opinions, based~~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 audits ~~are presented below.~~

~~Consolidated financial statements and financial statement schedule~~

provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements ~~listed in the index appearing under Item 15(a)(1)~~referred to above present fairly, in all material respects, the financial position of Chesapeake Utilities Corporation and ~~its~~ subsidiaries atas of December 31, ~~2005~~2008 and ~~2004,~~2007, and the results of their operations and their cash flows for ~~each of~~ the ~~three~~ years ~~in the period~~then ended ~~December 31, 2005,~~ in conformity with accounting principles generally accepted in the United States of America.

We also have audited the adjustments to the 2006 consolidated financial statements to retrospectively reflect the discontinued operations described in Note B. In our opinion, such adjustments were appropriate and have been properly applied. We were not engaged to audit, review, or apply any procedures to the 2006 consolidated financial statements of Chesapeake Utilities Corporation other than with respect to the adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2006 consolidated financial statements taken as a whole.

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, 2008, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 9, 2009 expressed an unqualified opinion.

/s/ Beard Miller Company LLP
Beard Miller Company LLP
Reading, Pennsylvania
March 9, 2009

Chesapeake Utilities Corporation 2008 Form 10-K Page 57

Consolidated Statements of Income

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders
of Chesapeake Utilities Corporation

In our opinion, the consolidated statements of income, cash flows, stockholders’ equity and income taxes for the year 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 results of operations and cash flows of Chesapeake Utilities Corporation and its subsidiaries for the year 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 ~~listed in~~for the ~~index appearing under Item 15(a)(2)~~year 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.~~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.~~audit. We conducted our ~~audits~~audit, 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 ~~of financial statements~~ 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~~audit provides a reasonable basis for our opinion.

~~Internal control over~~As discussed in Note L to the consolidated financial ~~reporting~~

~~Also, in our opinion, management’s assessment, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 8, that~~statements, the Company ~~maintained~~changed the manner in which it accounts for defined benefit pension and other postretirement plans, effective ~~internal control over financial reporting as of~~ December 31, ~~2005, based on criteria established~~2006.

We were not engaged to audit, review, or apply any procedures to the adjustments to retrospectively reflect the discontinued operations described in ~~Internal Control - Integrated Framework~~ ~~issued by the Committee~~Note B and accordingly, we do not express an opinion or any other form of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in ~~Internal Control - Integrated Framework~~ issued by the COSO. The Company’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. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting 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. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testingsuch adjustments are appropriate and ~~evaluating the design and operating effectiveness of internal control, and performing such~~have been properly applied. Those adjustments were audited by other ~~procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.~~auditors.


/s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP
Boston, MA
March 13, 2007

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.

~~- Page 37 -~~

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.

~~/s/ PricewaterhouseCoopers LLP~~

~~PricewaterhouseCoopers LLP~~

~~Boston, MA~~

~~March 6, 2006~~

~~- Page 38 -~~

~~This page intentionally left blank.~~

~~- Page 39 -~~

Consolidated Statements of Income

For the Years Ended December 31,

2005

2004

2003

Operating Revenues

$
229,629,736
$ 177,955,441 $ 163,567,592

Operating Expenses

Cost of sales, excluding costs below
153,514,739
109,626,377 95,246,819
Operations
40,181,649
35,146,595 33,526,804
Maintenance
1,818,981
1,518,774 1,737,855
Depreciation and amortization
7,568,209
7,257,538 7,089,836
Other taxes
5,015,659
4,436,411 4,386,878
Total operating expenses
208,099,237
157,985,695 141,988,192

Operating Income

21,530,499
19,969,746 21,579,400

Other income net of other expenses
382,626
549,156 238,439

Interest charges
5,133,495
5,268,145 5,705,911

Income Before Income Taxes

16,779,630
15,250,757 16,111,928

Income taxes
6,312,016
5,701,090 6,032,445

Net Income from Continuing Operations

10,467,614
9,549,667 10,079,483

Loss from discontinued operations, net of tax benefit of $0, $59,751 and $74,997
-
(120,900 ) (787,607 )

Net Income

$
10,467,614
$ 9,428,767 $ 9,291,876

Earnings Per Share of Common Stock:

Basic

From continuing operations
$
1.79
$ 1.66 $ 1.80
From discontinued operations
-
(0.02 ) (0.14 )
Net Income

$
1.79
$ 1.64 $ 1.66

Diluted

From continuing operations
$
1.77
$ 1.64 $ 1.76
From discontinued operations
-
(0.02 ) (0.13 )
Net Income

$
1.77
$ 1.62 $ 1.63

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

Page 58 Chesapeake Utilities Corporation 2008 Form 10-K


For the Twelve Months Ended December 31,	2008		2007			2006

Operating Revenues	$	291,443,477	$	258,286,495		$	231,199,565

Operating Expenses
Cost of sales, excluding costs below		200,643,518		170,848,211			155,809,747
Operations		43,475,794		42,242,218			36,612,683
Unconsummated acquisition costs		1,152,844		—			—
Maintenance		2,215,123		2,235,605			2,161,177
Depreciation and amortization		9,004,911		9,060,185			8,243,715
Other taxes		6,472,353		5,786,694			5,040,306

Total operating expenses		262,964,543		230,172,913			207,867,628

Operating Income		28,478,934		28,113,582			23,331,937

Other income, net of other expenses		103,039		291,305			189,093

Interest charges		6,157,552		6,589,639			5,773,993


Income Before Income Taxes		22,424,421		21,815,248			17,747,037
Income taxes		8,817,162		8,597,461			6,999,072

Income from Continuing Operations		13,607,259		13,217,787			10,747,965

Loss from discontinued operations, net of tax benefit of $0,$10,898 and $162,510		—		(20,077	)		(241,440	)

Net Income	$	13,607,259	$	13,197,710		$	10,506,525


Weighted Average Common Shares Outstanding:
Basic		6,811,848		6,743,041			6,032,462
Diluted		6,927,483		6,854,716			6,155,131

Earnings Per Share of Common Stock:
Basic
From continuing operations	$	2.00	$	1.96		$	1.78
From discontinued operations		—		—			(0.04	)

Net Income	$	2.00	$	1.96		$	1.74

Diluted
From continuing operations	$	1.98	$	1.94		$	1.76
From discontinued operations		—		—			(0.04	)

Net Income	$	1.98	$	1.94		$	1.72


Cash Dividends Declared Per Share of Common Stock:	$	1.21	$	1.18		$	1.16

~~- Page 40 -~~

Consolidated Statements of Cash Flows

For the Years Ended December 31,

2005

2004

2003

Operating Activities

Net Income
$
10,467,614
$ 9,428,767 $ 9,291,876
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization
7,568,209
7,257,538 8,030,399
Depreciation and accretion included in other costs
2,705,619
2,611,779 2,468,647
Deferred income taxes, net
1,510,776
4,559,207 2,397,594
Unrealized (loss) gain on commodity contracts
(227,193
)
353,183 457,901
Employee benefits and compensation
1,621,607
1,536,586 2,042,093
Other, net
(62,692
)
67,079 15,874
Changes in assets and liabilities:
Sale (purchase) of investments
(1,242,563
)
43,354 -
Accounts receivable and accrued revenue
(16,831,750
)
(11,723,505 ) (3,565,363 )
Propane inventory, storage gas and other inventory
(5,704,040
)
(1,741,941 ) (466,412 )
Regulatory assets
(1,719,184
)
428,516 116,153
Prepaid expenses and other current assets
36,703
(221,137 ) (316,425 )
Other deferred charges
(102,562
)
(168,898 ) 43,844
Long-term receivables
247,600
428,964 (101,373 )
Accounts payable and other accrued liabilities
15,258,551
11,079,661 564,270
Income taxes receivable (payable)
(2,006,763
)
(229,237 ) 25,090
Accrued interest
(42,374
)
(51,272 ) (47,464 )
Customer deposits and refunds
462,781
665,549 128,704
Accrued compensation
875,342
(794,194 ) 910,587
Regulatory liabilities
144,499
(191,266 ) 466,923
Environmental and other liabilities
328,383
12,721 550,977
Net cash provided by operating activities
13,288,563
23,351,454 23,013,895

Investing Activities

Property, plant and equipment expenditures
(33,008,235
)
(17,784,240 ) (11,790,364 )
Sale of investments
-
135,170 -
Sale of discontinued operations
-
415,707 3,732,649
Environmental recoveries and other
240,336
369,719 2,127,248
Net cash used by investing activities
(32,767,899
)
(16,863,644 ) (5,930,467 )

Financing Activities

Common stock dividends
(5,789,179
)
(5,560,535 ) (5,403,536 )
Issuance of stock for Dividend Reinvestment Plan
458,756
200,551 347,546
Change in cash overdrafts due to outstanding checks
874,083
(143,720 ) (46,853 )
Net borrowing (repayment) under line of credit agreements
29,606,400
1,184,743 (7,384,743 )
Repayment of long-term debt
(4,794,827
)
(3,665,589 ) (3,945,617 )
Net cash used by financing activities
20,355,233
(7,984,550 ) (16,433,203 )

Net Increase (Decrease) in Cash and Cash Equivalents

875,897
(1,496,740 ) 650,225
Cash and Cash Equivalents — Beginning of Period

1,611,761
3,108,501 2,458,276
Cash and Cash Equivalents — End of Period

$
2,487,658
$ 1,611,761 $ 3,108,501

Supplemental Disclosure of Cash Flow information

Cash paid for interest
$
5,052,013
$ 5,280,299 $ 5,648,332
Cash paid for income taxes
$
6,342,476
$ 1,977,223 $ 3,767,816

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

Chesapeake Utilities Corporation 2008 Form 10-K Page 59

Consolidated Statements of Cash Flows

~~- Page 41 -~~


For the Years Ended December 31,	2008			2007			2006

*Operating Activities*
Net Income	$	13,607,259		$	13,197,710		$	10,506,525
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization		9,004,911			9,060,185			8,243,715
Depreciation and accretion included in other costs		2,239,018			3,336,506			3,102,066
Deferred income taxes, net		11,441,660			1,831,030			(408,533	)
Gain on sale of assets		—			(204,882	)		—
Unrealized (gain) loss on commodity contracts		(1,146,486	)		(170,465	)		37,110
Unrealized (gain) loss on investments		509,084			(122,819	)		(151,952	)
Employee benefits and compensation		151,910			1,004,273			(158,825	)
Share based compensation		820,175			989,945			709,789
Other, net		4,045			56			13,300
Changes in assets and liabilities:
Sale (purchase) of investments		(200,603	)		229,125			(177,990	)
Accounts receivable and accrued revenue		19,410,552			(28,189,132	)		9,705,860
Propane inventory, storage gas and other inventory		(1,729,641	)		1,193,336			354,764
Regulatory assets		410,989			(344,680	)		2,498,954
Prepaid expenses and other current assets		(1,182,142	)		(1,185,829	)		(261,017	)
Other deferred charges		(153,005	)		(2,477,879	)		(231,822	)
Long-term receivables		207,324			83,653			137,101
Accounts payable and other accrued liabilities		(15,139,134	)		22,130,049			(11,434,370	)
Income taxes receivable		(6,155,239	)		(158,556	)		1,800,913
Accrued interest		158,154			33,112			273,672
Customer deposits and refunds		(502,479	)		2,534,655			2,361,265
Accrued compensation		(174,946	)		946,099			(721,289	)
Regulatory liabilities		(3,107,401	)		2,124,091			2,824,068
Other liabilities		68,384			(157,699	)		1,125,590

Net cash provided by operating activities		28,542,389			25,681,884			30,148,894


*Investing Activities*
Property, plant and equipment expenditures		(30,755,845	)		(31,277,390	)		(48,845,828	)
Proceeds from sale of assets		—			204,882			—
Environmental expenditures		(479,799	)		(227,979	)		(15,549	)

Net cash used by investing activities		(31,235,644	)		(31,300,487	)		(48,861,377	)


*Financing Activities*
Common stock dividends		(7,956,843	)		(7,029,821	)		(5,982,531	)
Issuance of stock for Dividend Reinvestment Plan		28,541			299,436			321,865
Stock issuance		—			—			19,698,509
Cash settlement of warrants		—			—			(434,782	)
Change in cash overdrafts due to outstanding checks		(683,836	)		(541,052	)		49,047
Net borrowing (repayment) under line of credit agreements		(11,980,108	)		18,651,055			(7,977,347	)
Proceeds from issuance of long-term debt		29,960,518			—			19,968,104
Repayment of long-term debt		(7,656,623	)		(7,656,580	)		(4,929,674	)

Net cash provided by financing activities		1,711,649			3,723,038			20,713,191


*Net Increase (Decrease) in Cash and Cash Equivalents*		(981,606	)		(1,895,565	)		2,000,708

*Cash and Cash Equivalents — Beginning of Period*		2,592,801			4,488,366			2,487,658


*Cash and Cash Equivalents — End of Period*	$	1,611,195		$	2,592,801		$	4,488,366

Supplemental Cash Flow Disclosures (see Note D)

Consolidated Balance Sheets

Assets
At December 31,

2005

2004

Property, Plant and Equipment

Natural gas distribution and transmission
$
220,685,461
$ 198,306,668
Propane
41,563,810
38,344,983
Advanced information services
1,221,177
1,480,779
Other plant
9,275,729
9,368,153
Total property, plant and equipment
272,746,177
247,500,583
Less: Accumulated depreciation and amortization
(78,840,413
)
(73,213,605 )
Plus: Construction work in progress
7,598,531
2,766,209
Net property, plant and equipment
201,504,295
177,053,187

Investments

1,685,635
386,422

Current Assets

Cash and cash equivalents
2,487,658
1,611,761
Accounts receivable (less allowance for uncollectible accounts of $861,378 and $610,819, respectively)
54,284,011
36,938,688
Accrued revenue
4,716,383
5,229,955
Propane inventory, at average cost
6,332,956
4,654,119
Other inventory, at average cost
1,538,936
1,056,530
Regulatory assets
4,434,828
2,435,284
Storage gas prepayments
8,628,179
5,085,382
Income taxes receivable
2,725,840
719,078
Prepaid expenses
2,021,164
1,759,643
Other current assets
1,596,797
459,908
Total current assets
88,766,752
59,950,348

Deferred Charges and Other Assets

Goodwill
674,451
674,451
Other intangible assets, net
205,683
219,964
Long-term receivables
961,434
1,209,034
Other regulatory assets
1,178,232
1,542,741
Other deferred charges
1,003,393
902,281
Total deferred charges and other assets
4,023,193
4,548,471

Total Assets

$
295,979,875
$ 241,938,428

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

Page 60 Chesapeake Utilities Corporation 2008 Form 10-K

Consolidated Balance Sheets

~~- Page 42 -~~


	December 31,			December 31,
Assets	2008			2007

Property, Plant and Equipment
Natural gas	$	316,124,761		$	289,706,066
Propane		51,827,293			48,506,231
Advanced information services		1,439,390			1,157,808
Other plant		10,815,345			8,567,833

Total property, plant and equipment		380,206,789			347,937,938

Less: Accumulated depreciation and amortization		(101,017,551	)		(92,414,289	)
Plus: Construction work in progress		1,481,448			4,899,608

Net property, plant and equipment		280,670,686			260,423,257


Investments		1,600,790			1,909,271


Current Assets
Cash and cash equivalents		1,611,195			2,592,801
Accounts receivable (less allowance for uncollectible accounts of $1,159,014 and $952,074, respectively)		52,905,447			72,218,191
Accrued revenue		5,167,666			5,265,474
Propane inventory, at average cost		5,710,673			7,629,295
Other inventory, at average cost		1,479,249			1,280,506
Regulatory assets		826,009			1,575,072
Storage gas prepayments		9,491,690			6,042,169
Income taxes receivable		7,442,921			1,237,438
Deferred income taxes		1,577,805			2,155,393
Prepaid expenses		4,679,368			3,496,517
Mark-to-market energy assets		4,482,473			7,812,456
Other current assets		146,820			146,253


Total current assets		95,521,316			111,451,565


Deferred Charges and Other Assets
Goodwill		674,451			674,451
Other intangible assets, net		164,268			178,073
Long-term receivables		533,356			740,680
Regulatory assets		2,806,195			2,539,235
Other deferred charges		3,823,448			3,640,480


Total deferred charges and other assets		8,001,718			7,772,919


Total Assets	$	385,794,510		$	381,557,012

Consolidated Balance Sheets

Capitalization and Liabilities
At December 31,

2005

2004

Capitalization

Stockholders' equity
Common Stock, par value $.4867 per share; (authorized 12,000,000 shares) ⁽¹⁾

$
2,863,212
$ 2,812,538
Additional paid-in capital
39,619,849
36,854,717
Retained earnings
42,854,894
39,015,087
Accumulated other comprehensive income
(578,151
)
(527,246 )
Deferred compensation obligation
794,535
816,044
Treasury stock
(797,156
)
(1,008,696 )
Total stockholders' equity
84,757,183
77,962,444

Long-term debt, net of current maturities
58,990,363
66,189,454
Total capitalization
143,747,546
144,151,898

Current Liabilities

Current portion of long-term debt
4,929,091
2,909,091
Short-term borrowing
35,482,241
5,001,758
Accounts payable
45,645,228
30,938,272
Customer deposits and refunds
5,140,999
4,678,218
Accrued interest
558,719
601,095
Dividends payable
1,676,398
1,617,245
Deferred income taxes payable
1,150,828
571,876
Accrued compensation
3,793,244
2,680,370
Regulatory liabilities
550,546
571,111
Other accrued liabilities
3,560,055
1,800,540
Total current liabilities
102,487,349
51,369,576

Deferred Credits and Other Liabilities

Deferred income taxes payable
24,248,624
23,350,414
Deferred investment tax credits
367,085
437,909
Other regulatory liabilities
2,008,779
1,578,374
Environmental liabilities
352,504
461,656
Accrued pension costs
3,099,882
3,007,949
Accrued asset removal cost
16,727,268
15,024,849
Other liabilities
2,940,838
2,555,803
Total deferred credits and other liabilities
49,744,980
46,416,954

Other Commitments and Contingencies (Note N)

Total Capitalization and Liabilities

$
295,979,875
$ 241,938,428

⁽¹⁾ Shares issued were 5,883,099 and 5,778,976 for 2005 and 2004, respectively.

Shares outstanding were 5,883,002 and 5,769,558 for 2005 and 2004, respectively.

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

Chesapeake Utilities Corporation 2008 Form 10-K Page 61

Consolidated Balance Sheets

~~- Page 43 -~~


	December 31,			December 31,
Capitalization and Liabilities	2008			2007

Capitalization
Stockholders’ equity
Common Stock, par value $0.4867 per share (authorized 12,000,000 shares)	$	3,322,668		$	3,298,473
Additional paid-in capital		66,680,696			65,591,552
Retained earnings		56,817,921			51,538,194
Accumulated other comprehensive loss		(3,748,093	)		(851,674	)
Deferred compensation obligation		1,548,507			1,403,922
Treasury stock		(1,548,507	)		(1,403,922	)

Total stockholders’ equity		123,073,192			119,576,545

Long-term debt, net of current maturities		86,422,273			63,255,636


Total capitalization		209,495,465			182,832,181


Current Liabilities
Current portion of long-term debt		6,656,364			7,656,364
Short-term borrowing		33,000,000			45,663,944
Accounts payable		40,202,280			54,893,071
Customer deposits and refunds		9,534,441			10,036,920
Accrued interest		1,023,658			865,504
Dividends payable		2,082,267			1,999,343
Accrued compensation		3,304,736			3,400,112
Regulatory liabilities		3,227,337			6,300,766
Mark-to-market energy liabilities		3,052,440			7,739,261
Other accrued liabilities		2,967,905			2,500,542


Total current liabilities		105,051,428			141,055,827


Deferred Credits and Other Liabilities
Deferred income taxes		37,719,859			28,795,885
Deferred investment tax credits		235,422			277,698
Regulatory liabilities		875,106			1,136,071
Environmental liabilities		511,223			835,143
Other pension and benefit costs		7,335,116			2,513,030
Accrued asset removal cost		20,641,279			20,249,948
Other liabilities		3,929,612			3,861,229


Total deferred credits and other liabilities		71,247,617			57,669,004


Other Commitments and Contingencies (Note N)

Total Capitalization and Liabilities	$	385,794,510		$	381,557,012

Consolidated Statements of Stockholders' Equity

For the Years Ended December 31,

2005

2004

2003

Common Stock

Balance — beginning of year
$
2,812,538
$ 2,754,748 $ 2,694,935
Dividend Reinvestment Plan
20,038
20,125 24,888
Retirement Savings Plan
10,255
19,058 21,047
Conversion of debentures
11,004
9,060 9,144
Performance shares and options exercised ⁽¹⁾

9,377
9,547 4,734
Balance — end of year
2,863,212
2,812,538 2,754,748

Additional Paid-in Capital

Balance — beginning of year
36,854,717
34,176,361 31,756,983
Dividend Reinvestment Plan
1,224,874
996,715 1,066,386
Retirement Savings Plan
682,829
946,319 899,475
Conversion of debentures
373,259
307,940 310,293
Performance shares and options exercised ⁽¹⁾

484,170
427,382 143,224
Balance — end of year
39,619,849
36,854,717 34,176,361

Retained Earnings

Balance — beginning of year
39,015,087
36,008,246 32,898,283
Net income
10,467,614
9,428,767 9,291,876
Cash dividends ⁽²⁾

(6,627,807
)
(6,403,450 ) (6,181,913 )
Loss on issuance of treasury stock
-
(18,476 ) -
Balance — end of year
42,854,894
39,015,087 36,008,246

Accumulated Other Comprehensive Income

Balance — beginning of year
(527,246
)
- -
Minimum pension liability adjustment, net of tax
(50,905
)
(527,246 ) -
Balance — end of year
(578,151
)
(527,246 ) 0

Deferred Compensation Obligation

Balance — beginning of year
816,044
913,689 711,109
New deferrals
130,426
296,790 202,580
Payout of deferred compensation
(151,935
)
(394,435 ) -
Balance — end of year
794,535
816,044 913,689

Treasury Stock

Balance — beginning of year
(1,008,696
)
(913,689 ) (711,109 )
New deferrals related to compensation obligation
(130,426
)
(296,790 ) (202,580 )
Purchase of treasury stock
(182,292
)
(344,753 ) -
Sale and distribution of treasury stock
524,258
546,536 -
Balance — end of year
(797,156
)
(1,008,696 ) (913,689 )

Total Stockholders’ Equity

$
84,757,183
$ 77,962,444 $ 72,939,355

⁽¹⁾ Includes amounts for shares issued for Directors’ compensation.

⁽²⁾ Cash dividends declared per share for 2005, 2004 and 2003 were $1.14, $1.12 and $1.10, respectively.

Consolidated Statements of Comprehensive Income

For the Years Ended December 31,

2005

2004

2003

Net income
$
10,467,614
$ 9,428,767 $ 9,291,876
Minimum pension liability adjustment, net of tax of $33,615 and $347,726, respectively
(50,905
)
(527,246 ) -
Comprehensive Income

$
10,416,709
$ 8,901,521 $ 9,291,876

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

Page 62 Chesapeake Utilities Corporation 2008 Form 10-K

Consolidated Statements of Stockholders’ Equity


	Common Stock					Additional						Accumulated Other
	Number of					Paid-In			Retained			Comprehensive			Deferred		Treasury
	Shares			Par Value		Capital			Earnings			Income			Compensation		Stock			Total
Balances at December 31, 2005		5,883,099		$	2,863,212	$	39,619,849		$	42,854,894		$	(578,151	)	$	794,535	$	(797,156	)	$	84,757,183
Net earnings										10,506,525											10,506,525
Other comprehensive income, net of tax:
Minimum pension liability, net of tax⁽¹⁾													74,036								74,036

Total comprehensive income																					10,580,561

Adjustment to initially apply SFAS No. 158, net of tax^{(5) (6)}													169,565								169,565
Dividend Reinvestment Plan		38,392			18,685		1,148,100														1,166,785
Retirement Savings Plan		29,705			14,457		900,354														914,811
Conversion of debentures		16,677			8,117		275,300														283,417
Share based compensation⁽²⁾⁽⁴⁾		29,866			14,536		887,426														901,962
Stock warrants, net of tax							(233,327	)													(233,327	)
Deferred Compensation Plan																323,974		(323,974	)		—
Purchase of treasury stock		(97	)															(51,572	)		(51,572	)
Sale and distribution of treasury stock		97																54,193			54,193
Stock issuance		690,345			335,991		19,362,518														19,698,509
Cash dividends⁽³⁾										(7,090,535	)										(7,090,535	)

Balances at December 31, 2006		6,688,084			3,254,998		61,960,220			46,270,884			(334,550	)		1,118,509		(1,118,509	)		111,151,552
Net earnings										13,197,710											13,197,710
Other comprehensive income, net of tax:
Employee Benefit Plans, net of tax:
Amortization of prior service costs⁽⁵⁾													(2,828	)							(2,828	)
Net loss⁽⁶⁾													(514,296	)							(514,296	)

Total comprehensive income																					12,680,586

Dividend Reinvestment Plan		35,333			17,197		1,121,190														1,138,387
Retirement Savings Plan		29,563			14,388		934,295														948,683
Conversion of debentures		8,106			3,945		133,839														137,784
Share based compensation^{(2) (4)}		16,324			7,945		1,442,008														1,449,953
Deferred Compensation Plan																285,413		(285,413	)		—
Purchase of treasury stock		(971	)															(29,771	)		(29,771	)
Sale and distribution of treasury stock		971																29,771			29,771
Cash dividends⁽³⁾										(7,930,400	)										(7,930,400	)

Balances at December 31, 2007		6,777,410			3,298,473		65,591,552			51,538,194			(851,674	)		1,403,922		(1,403,922	)		119,576,545
Net earnings										13,607,259											13,607,259
Other comprehensive income, net of tax:
Employee Benefit Plans, net of tax:
Amortization of prior service costs⁽⁵⁾													(71,438	)							(71,438	)
Net loss⁽⁶⁾													(2,824,981	)							(2,824,981	)

Total comprehensive income																					10,710,840

Dividend Reinvestment Plan		9,060			4,410		269,127														273,537
Retirement Savings Plan		5,260			2,560		156,195														158,755
Conversion of debentures		10,397			5,060		171,680														176,740
Share based compensation^{(2) (4)}		24,994			12,165		441,898														454,063
Tax benefit on stock warrants							50,244														50,244
Deferred Compensation Plan																144,585		(144,585	)		—
Purchase of treasury stock		(2,425	)															(71,573	)		(71,573	)
Sale and distribution of treasury stock		2,425																71,573			71,573
Dividends on stock-based compensation										(79,570	)										(79,570	)
Cash dividends⁽³⁾										(8,247,962	)										(8,247,962	)

Balances at December 31, 2008		6,827,121		$	3,322,668	$	66,680,696		$	56,817,921		$	(3,748,093	)	$	1,548,507	$	(1,548,507	)	$	123,073,192


⁽¹⁾		Tax expense recognized on the minimum pension liability adjustment for 2006 was $48,889.

⁽²⁾		Includes amounts for shares issued for Directors’ compensation.

⁽³⁾		Cash dividends per share for 2008, 2007 and 2006 were $1.22, $1.18 and $1.16, respectively.

⁽⁴⁾		The shares issued under the PIP are net of shares withheld for employee taxes. For 2008, the Company withheld 12,511 shares for taxes, 2,420 shares for 2007 and 9,054 shares for 2006.

⁽⁵⁾		Tax expense (benefit) recognized on the prior service cost component of employees benefit plans for 2008, 2007 and 2006 were ($51,841), ($1,871) and $11,756, respectively.

⁽⁶⁾		Tax expense (benefit) recognized on the net gain (loss) component of employees benefit plans for 2008, 2007 and 2006 were ($1.9 million), ($340,449) and $100,217, respectively.

~~- Page 44 -~~

Consolidated Statements of Income Taxes

For the Years Ended December 31,

2005

2004

2003

Current Income Tax Expense

Federal
$
3,687,800
$ 1,221,155 $ 4,168,433
State
789,233
618,916 948,023
Investment tax credit adjustments, net
(54,816
)
(54,816 ) (54,816 )
Total current income tax expense
4,422,217
1,785,255 5,061,640

Deferred Income Tax Expense ⁽¹⁾

Property, plant and equipment
1,380,628
4,230,650 1,980,070
Deferred gas costs
1,064,310
283,547 105,846
Pensions and other employee benefits
(340,987
)
(49,620 ) (203,229 )
Environmental expenditures
(98,229
)
(150,864 ) (866,206 )
Other
(115,923
)
(397,878 ) (45,676 )
Total deferred income tax expense
1,889,799
3,915,835 970,805
Total Income Tax Expense

$
6,312,016
$ 5,701,090 $ 6,032,445

Reconciliation of Effective Income Tax Rates

Federal income tax expense ⁽²⁾

$
5,872,871
$ 5,185,257 $ 5,478,056
State income taxes, net of federal benefit
708,192
736,176 737,370
Other
(269,047
)
(220,343 ) (182,981 )
Total Income Tax Expense

$
6,312,016
$ 5,701,090 $ 6,032,445
Effective income tax rate

37.6
%
37.4 % 37.4 %

At December 31,

2005

2004

Deferred Income Taxes

Deferred income tax liabilities:

Property, plant and equipment
$
26,795,452
$ 25,736,718
Deferred gas costs
1,664,252
599,945
Other
612,943
749,259
Total deferred income tax liabilities
29,072,647
27,085,922

Deferred income tax assets:

Pension and other employee benefits
2,289,370
1,914,402
Self insurance
575,303
535,755
Environmental costs
181,734
83,510
Other
626,788
629,965
Total deferred income tax assets
3,673,195
3,163,632
Deferred Income Taxes Per Consolidated Balance Sheet
$
25,399,452
$ 23,922,290

⁽¹⁾ Includes $146,000, $386,000 and $113,000 of deferred state income taxes for the years 2005, 2004 and 2003, respectively.

⁽²⁾ Federal income taxes were recorded at 35% for the year 2005. They were recorded at 34% in both 2004 and 2003.

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

Chesapeake Utilities Corporation 2008 Form 10-K Page 63

Consolidated Statements of Income Taxes


For the Years Ended December 31,	2008			2007			2006

Current Income Tax Expense
Federal	$	(2,551,138	)	$	5,512,071		$	5,994,296
State		—			1,223,145			1,424,485
Investment tax credit adjustments, net		(42,276	)		(50,579	)		(54,816	)

Total current income tax expense (benefit)		(2,593,414	)		6,684,637			7,363,965


Deferred Income Tax Expense⁽¹⁾
Property, plant and equipment		10,347,035			2,958,758			1,697,024
Deferred gas costs		781,635			(629,228	)		(2,085,066	)
Pensions and other employee benefits		(174,365	)		(9,154	)		(97,436	)
Environmental expenditures		144,848			45,872			(5,580	)
Other		311,423			(464,322	)		(36,345	)

Total deferred income tax expense (benefit)		11,410,576			1,901,926			(527,403	)

Total Income Tax Expense	$	8,817,162		$	8,586,563		$	6,836,562


Reconciliation of Effective Income Tax Rates
Continuing Operations
Federal income tax expense⁽²⁾	$	7,862,760		$	7,635,336		$	6,212,237
State income taxes, net of federal benefit		1,162,081			1,086,680			829,630
Other		(207,679	)		(124,555	)		(42,795	)

Total continuing operations		8,817,162			8,597,461			6,999,072
Discontinued operations		—			(10,898	)		(162,510	)

Total income tax expense	$	8,817,162		$	8,586,563		$	6,836,562


Effective income tax rate		39.3	%		39.4	%		39.4	%


At December 31,	2008		2007

Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	41,248,245	$	31,058,050
Environmental costs		394,869		250,021
Other		2,414,121		860,993

Total deferred income tax liabilities		44,057,235		32,169,064


Deferred income tax assets:
Pension and other employee benefits		4,679,075		2,581,853
Self insurance		370,398		384,009
Deferred gas costs		364,498		1,146,133
Other		2,501,210		1,416,577

Total deferred income tax assets		7,915,181		5,528,572

Deferred Income Taxes Per Consolidated Balance Sheet	$	36,142,054	$	26,640,492


(1)		Includes $1,588,000, $260,000 and ($60,000) of deferred state income taxes for the years 2008, 2007 and 2006, respectively.

(2)		Federal income taxes were recorded at 35% for each year represented.

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

Page ~~45 -~~64 Chesapeake Utilities Corporation 2008 Form 10-K

A. Summary of Accounting Policies

Nature of Business

Chesapeake ~~Utilities Corporation (“Chesapeake” or “the Company”)~~ is engaged in natural gas distribution to approximately ~~54,800~~65,200 customers located in central and southern Delaware, Maryland’s Eastern Shore and Florida. The Company’s natural gas transmission subsidiary operates an ~~intrastate~~interstate pipeline from various points in Pennsylvania and northern Delaware to the Company’s Delaware and Maryland distribution divisions as well as to other utility and industrial customers in Pennsylvania, Delaware and the Eastern Shore of Maryland. The Company’s natural gas marketing subsidiary sells natural gas supplies directly to commercial and industrial customers in the States of Florida, Delaware and Maryland. The Company’s propane distribution and wholesale marketing segment provides distribution service to ~~approximately 32,900~~35,200 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~~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~~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 ~~significant~~ 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 ~~public service commissions~~PSCs with respect to their rates for service, maintenance of their accounting records and various other matters. ~~Eastern Shore Natural Gas Company~~ESNG is an open access pipeline and is subject to regulation by the ~~Federal Energy Regulatory Commission (“FERC”).~~FERC. Our financial statements are prepared in accordance with ~~generally accepted accounting principles,~~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 while the assets of the non-utility segments are recorded at~~ 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 3 percent for natural gas distribution and transmission, 5 percent for propane, 11 percent for advanced information services and 7 percent for general plant.~~

Chesapeake Utilities Corporation 2008 Form 10-K Page 65

Notes to the Consolidated Financial Statements


At December 31,	2008			2007			Useful Life⁽¹⁾
Plant in service
Mains	$	184,124,950		$	166,202,413		27-65 years
Services — utility		37,946,690			35,127,633		14-55 years
Compressor station equipment		24,980,668			24,959,330		44 years
Liquefied petroleum gas equipment		26,303,832			25,575,213		5-33 years
Meters and meter installations		19,479,360			18,111,466		Propane 10-33 years, Natural gas 25-49 years
Measuring and regulating station equipment		15,092,354			14,067,262		24-54 years
Office furniture and equipment		12,536,281			9,947,881		Non-regulated 3-10 years, Regulated 14-25 years
Transportation equipment		11,266,723			11,194,916		3-11 years
Structures and improvements		10,601,819			10,024,105		10-79 years⁽²⁾
Land and land rights		7,901,058			7,404,679		Not depreciable, except certain regulated assets
Propane bulk plants and tanks		6,296,155			5,313,061		15-40 years
Various		23,676,899			20,009,979		Various

Total plant in service		380,206,789			347,937,938
Plus construction work in progress		1,481,448			4,899,608
Less accumulated depreciation		(101,017,551	)		(92,414,289	)

Net property, plant and equipment	$	280,670,686		$	260,423,257


⁽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.

~~- Page 46 -~~

At December 31,

2005

2004

Useful Life ⁽¹⁾

Plant in service
Mains
$
113,111,408
$ 99,154,938 24-37 years
Services — utility
29,010,008
25,733,797 14-28 years
Compressor station equipment
23,853,871
23,766,105 28 years
Liquefied petroleum gas equipment
22,162,867
21,483,969 30-39 years
Meters and meter installations
15,165,212
13,656,918 Propane 15-33 years, Natural gas 17-49 years
Measuring and regulating station equipment
12,219,964
10,142,531 17-37 years
Office furniture and equipment
9,572,926
10,171,180 Non-regulated 3-10 years, Regulated 3-20 years
Transportation equipment
9,822,272
9,425,605 2-11 years
Structures and improvements
9,161,696
9,177,011 5-44 years⁽²⁾
Land and land rights
5,646,852
4,703,683 Not depreciable, except certain regulated assets
Propane bulk plants and tanks
6,097,036
5,024,462 15 - 40 years
Various
16,922,065
15,060,384 Various
Total plant in service
272,746,177
247,500,583
Plus construction work in progress
7,598,531
2,766,209
Less accumulated depreciation
(78,840,413
)
(73,213,605 )
Net property, plant and equipment
$
201,504,295
$ 177,053,187

⁽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 Federal Energy Regulatory Commission. 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.

Cash and Cash Equivalents

The Company’s policy is to invest cash in excess of operating requirements in overnight ~~income producing~~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. ~~The appliance inventory is valued at first-in first-out (“FIFO”).~~ If ~~the~~ 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).

Page 66 Chesapeake Utilities Corporation 2008 Form 10-K

At December 31, ~~2005~~2008 and ~~2004,~~2007, 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,	2008		2007
Regulatory Assets
Current
Underrecovered purchased gas costs	$	650,820	$	1,389,454
Swing transportation imbalances		2,059		—
PSC Assessment		18,575		22,290
Flex rate asset		107,943		107,394
Other		46,612		55,934

Total current		826,009		1,575,072

Non-Current
Income tax related amounts due from customers		1,284,552		1,115,638
Deferred regulatory and other expenses		646,126		446,642
Deferred gas supply		12,667		15,201
Deferred post retirement benefits		83,370		111,159
Environmental regulatory assets and expenditures		779,480		850,594

Total non-current		2,806,195		2,539,234


Total Regulatory Assets	$	3,632,204	$	4,114,306


Regulatory Liabilities
Current
Self insurance — current	$	162,616	$	191,004
Overrecovered purchased gas costs		1,542,174		4,225,845
Shared interruptible margins		231,919		11,202
Conservation cost recovery		743,874		395,379
Swing transportation imbalances		546,754		1,477,336

Total current		3,227,337		6,300,766

Non-Current
Self insurance — long-term		749,827		757,557
Income tax related amounts due to customers		125,279		151,521
Environmental overcollections		—		226,993

Total non-current		875,106		1,136,071

Accrued asset removal cost		20,641,279		20,249,948


Total Regulatory Liabilities	$	24,743,722	$	27,686,785

~~- Page 47 -~~

At December 31,

2005

2004

Regulatory Assets

Current

Underrecovered purchased gas costs
$
4,016,522
$ 1,479,358
Conservation cost recovery
303,930
186,234
Swing transportation imbalances
454
32,707
Flex rate asset
113,922
736,985
Total current
4,434,828
2,435,284

Non-Current

Income tax related amounts due from customers
711,961
711,961
Deferred regulatory and other expenses
89,258
200,746
Deferred gas supply
15,201
15,201
Deferred gas required for operations
-
141,082
Deferred post retirement benefits
166,739
194,529
Environmental regulatory assets and expenditures
195,073
279,222
Total non-current
1,178,232
1,542,741

Total Regulatory Assets
$
5,613,060
$ 3,978,025

Regulatory Liabilities

Current

Self insurance — current
$
44,221
$ 127,000
Shared interruptible margins
3,039
135,098
Operational flow order penalties
7,831
130,338
Swing transportation imbalances
495,455
178,675
Total current
550,546
571,111

Non-Current

Self insurance — long-term
1,383,247
1,221,101
Income tax related amounts due to customers
327,893
324,974
Environmental overcollections
297,639
32,299
Total non-current
2,008,779
1,578,374

Accrued asset removal cost
16,727,268
15,024,849

Total Regulatory Liabilities
$
19,286,593
$ 17,174,334

Included in the current regulatory assets listed above ~~are $1.8 million~~is a flex rate asset of approximately $108,000, which ~~are~~is accruing interest. Of the remaining regulatory assets, ~~$2.7~~$1.7 million will be collected in approximately one to two years, ~~$360,000~~$623,000 will be collected within approximately 3three to 10ten years, $83,000 will be collected within approximately 11 to 15 years, and ~~$729,000 are~~$481,000 will be collected within approximately 16-25 years. In addition, there is approximately $711,000 for which the Company is awaiting regulatory approval for ~~recovery, but~~recovery; once approved, ~~are~~this amount is expected to be collected ~~within~~over a period greater than 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.

Chesapeake Utilities Corporation 2008 Form 10-K Page 67

Notes to the Consolidated Financial Statements

Goodwill and Other Intangible Assets

~~Goodwill~~The Company accounts for its goodwill and other ~~intangible assets are associated with the acquisition of non-utility companies. In accordance with~~intangibles under SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142). Under SFAS No. 142, goodwill is not amortized but is tested for impairment onat least annually. In addition, goodwill of a reporting unit is tested for impairment between annual tests if an ~~annual basis and when events change.~~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 G, “Goodwill and Other Intangible Assets,” for additional discussion of this subject.

~~- Page 48 -~~

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. ~~Deferred post-employment benefits~~

Pension and Other Postretirement Plans

Pension and other postretirement plan costs and liabilities are ~~adjusted based~~determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected return on plan assets, assumed discount rates, the level of contributions made to the plans, current ~~age,~~demographic and actuarial mortality data. The Company annually reviews the estimates and assumptions underlying our pension and other postretirement plan costs and liabilities with the assistance of a third-party actuarial firm. The assumed discount rate and the expected return on plan assets are the assumptions that generally have the most significant impact on the Company’s pension costs and liabilities. The assumed discount rate, the assumed health care cost trend rate and the assumed rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities.

The discount rate is utilized principally in calculating the actuarial present value of our pension and postretirement obligations and net pension and postretirement costs. When establishing its discount rate, the ~~projected~~Company considers high quality corporate bond rates based on Moody’s Aa bond index, changes in those rates from the prior year, and other pertinent factors, such as the expected life of the plan and the lump-sum-payment option.

The expected long-term rate of return on assets is utilized in calculating the expected return on plan assets component of our annual ~~benefit received~~pension and postretirement plan costs. The Company estimates the expected return on plan assets by evaluating expected bond returns, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. The Company also considers the guidance from its investment advisors in making a final determination of its expected rate of return on assets.

The Company estimates the assumed health care cost trend rate used in determining our postretirement net expense based upon its actual health care cost experience, the effects of recently enacted legislation and general economic conditions. The Company’s assumed rate of retirement is estimated ~~life expectancy.~~based upon its annual review of its participant census information as of the measurement date.

Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension costs ultimately recognized. A 0.25 percent change in the Company’s discount rate would impact our defined pension cost by approximately $10,000, impact the Pension SERP costs by approximately $2,000 and postretirement costs by approximately $7,000. A 0.25 percent change in the Company’s expected rate of return would impact our defined pension costs by approximately $16,000 and will not have an impact on either the Pension SERP or the other postretirement costs because these plans are unfunded.

Page 68 Chesapeake Utilities Corporation 2008 Form 10-K

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 ~~current effective income~~the enacted tax ~~rates.~~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, “Uncertain Tax Positions,” (“FIN 48”) 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 No. 109. 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 ~~$46,000~~$1.4 million and ~~unrealized losses of $182,000~~$179,000 at December 31, ~~2005~~2008 and ~~2004,~~2007, respectively. Trading liabilities are recorded in ~~other accrued~~mark-to-market energy liabilities. Trading assets are recorded in ~~prepaid expenses and other current~~mark-to-market energy assets.

The Company’s natural gas and propane distribution operations have entered into agreements with suppliers to purchase 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 inunder 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 ~~has entered~~may enter into a fair value ~~hedges~~hedge of its inventory in order to mitigate the impact of wholesale price fluctuations. ~~At December 31, 2005,~~Wholesale propane prices rose dramatically during the spring months of 2008, when they are traditionally at their lowest. In efforts to protect the Company from the impact that additional price increases would have on the Pro-Cap (propane price cap) Plan that we offer to customers, the propane distribution operation had entered into a ~~put contract to protect 2.1 million gallons~~swap agreement. By December 31, 2008, the market price of propane ~~inventory from a drop in value~~declined well below the ~~strike~~unit price in the swap agreement. As a result, the Company marked the January 2009 and February 2009 gallons in the agreement to market, which increased 2008 cost of ~~the put.~~sales by $939,000. The Company ~~settled the put~~terminated this swap agreement in January ~~2006, which resulted in a benefit~~2009. At December 31, 2007, the Company had not hedged any of ~~$28,000.~~its propane inventories.

Chesapeake Utilities Corporation 2008 Form 10-K Page 69

Notes to the Consolidated Financial Statements

~~- Page 49 -~~

Earnings Per Share

Chesapeake calculates earnings per share in accordance with SFAS No. 128. The calculations of both basic and diluted earnings per share ~~from continuing operations~~ are presented in the following chart.


For the Periods Ended December 31,	2008		2007		2006

Calculation of Basic Earnings Per Share:
Net Income	$	13,607,259	$	13,197,710	$	10,506,525
Weighted average shares outstanding		6,811,848		6,743,041		6,032,462

Basic Earnings Per Share	$	2.00	$	1.96	$	1.74


Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	13,607,259	$	13,197,710	$	10,506,525
Effect of 8.25% Convertible debentures		88,657		95,611		105,024

Adjusted numerator — Diluted	$	13,695,916	$	13,293,321	$	10,611,549


Reconciliation of Denominator:
Weighted shares outstanding — Basic		6,811,848		6,743,041		6,032,462
Effect of dilutive securities:
Share-based Compensation		12,083		—		—
8.25% Convertible debentures		103,552		111,675		122,669

Adjusted denominator — Diluted		6,927,483		6,854,716		6,155,131


Diluted Earnings Per Share	$	1.98	$	1.94	$	1.72

For the Period Ended December 31,

2005

2004

2003

Calculation of Basic Earnings Per Share from Continuing Operations:

Income from continuing operations
$
10,467,614
$ 9,549,667 $ 10,079,483
Weighted average shares outstanding
5,836,463
5,735,405 5,610,592
Basic Earnings Per Share from Continuing Operations

$
1.79
$ 1.66 $ 1.80

Calculation of Diluted Earnings Per Share from Continuing Operations:

Reconciliation of Numerator:

Income from continuing operations — Basic
$
10,467,614
$ 9,549,667 $ 10,079,483
Effect of 8.25% Convertible debentures
123,559
139,097 157,557
Adjusted numerator — Diluted
$
10,591,173
$ 9,688,764 $ 10,237,040

Reconciliation of Denominator:

Weighted shares outstanding — Basic
5,836,463
5,735,405 5,610,592
Effect of dilutive securities
Stock options
-
1,784 1,361
Warrants
11,711
7,900 5,481
8.25% Convertible debentures
144,378
162,466 184,532
Adjusted denominator — Diluted
5,992,552
5,907,555 5,801,966

Diluted Earnings Per Share from Continuing Operations

$
1.77
$ 1.64 $ 1.76

Operating Revenues

Revenues for the natural gas distribution operations of the Company are based on rates approved by the ~~various public service commissions.~~PSCs in the jurisdictions in which the Company operates. The natural gas transmission operation’s revenues are based on rates approved by the FERC. Customers’ base rates may not be changed without formal approval by these ~~commissions;~~commissions. The PSCs, however, ~~the regulatory authorities~~ have ~~granted our regulated~~allowed the natural gas distribution operations ~~the ability~~ to negotiate rates, based on approved methodologies, with customers that have competitive ~~alternatives using approved methodologies. In addition, the~~alternatives. The natural gas transmission operation can also negotiate rates above or below the FERC-approved ~~tariff~~maximum rates, which customers can elect as recourse to negotiated rates.

For regulated deliveries of natural gas, Chesapeake reads meters and bills customers on monthly cycles that do not coincide with the accounting periods used for financial reporting purposes. Chesapeake accrues unbilled revenues for gas that has been delivered but not yet billed at the end of an accounting period to the extent that they do not coincide. In connection with this accrual, Chesapeake must estimate the amount of gas that has not been accounted for on its delivery system and must estimate the amount of the unbilled revenue by jurisdiction and customer class. A similar computation is made to accrue unbilled revenues for propane customers with meters, such as community gas system customers.

The propane wholesale marketing operation records trading activity for open contracts, on a net mark-to-market basis in the Company’s income statement. The propane distribution, advanced information services and other segments record revenue in the period in which the products are delivered and/or services are rendered.

Chesapeake’s ~~Maryland and Delaware~~ natural gas distribution operations ~~each~~in Delaware and Maryland have a PSC-approved purchased gas cost recovery mechanism. This mechanism ~~that~~ provides the Company with a method of adjusting the billing rates with its customers for changes in the ~~adjustment~~cost of purchased gas included in base rates. The difference between the current cost of gas purchased and the cost of gas recovered in billed rates ~~charged to customers~~is deferred and accounted for as either unrecovered purchased gas costs ~~fluctuate. These~~or amounts payable to customers. Generally, these deferred amounts are ~~collected~~recovered or refunded ~~through adjustments to rates in subsequent periods.~~within one year.

Page 70 Chesapeake Utilities Corporation 2008 Form 10-K

The Company charges flexible rates to ~~the~~its natural gas distribution’s industrial interruptible customers to compete with alternative types of fuel. Based on pricing, these customers can choose natural gas or alternative ~~types of supply.~~fuels. Neither the Company nor the interruptible customer is contractually obligated to deliver or receive natural gas.

Cost of Sales

~~The~~Cost of sales includes the direct costs attributable to the products sold or services provided by the Company for its utility and non-utility operations. These costs primarily include the variable cost of natural gas and propane ~~wholesale marketing operation records trading activity net on~~commodities, pipeline capacity costs needed to transport and store natural gas, transportation costs to transport propane purchases to our storage facilities, and the ~~Company’s income statement, on a mark-to-market basis,~~direct cost of labor for ~~open contracts. The propane distribution,~~our advanced information services segment.

Operations and Maintenance Expenses

Operations and maintenance expenses are costs associated with the operation and maintenance of the Company’s utility and non-utility operations. Major cost components include operation and maintenance salaries and benefits, materials and supplies, usage of vehicles, tools and equipment, payments to contractors, utility plant maintenance, customer service, professional fees and other ~~segments record revenue~~outside services, insurance expense, minor amounts of depreciation, accretion of cost of removal for future retirements of utility assets, and other administrative expenses.

Depreciation and Accretion Included in Operations Expenses

Depreciation and accretion included in operations expenses consist of the ~~period~~accretion of the ~~products~~costs of removal for future retirement of utility assets, vehicle depreciation, computer software and hardware depreciation, and other minor amounts of depreciation expense.

Allowance for Doubtful Accounts

An allowance for doubtful accounts is recorded against amounts due to reduce the net receivables balance to the amount we reasonably expect to collect based upon the Company’s collections experiences and the Company’s assessment of its customers’ inability or reluctance to pay. If circumstances change, our estimates of recoverable accounts receivable may also change. Circumstances which could affect such estimates include, but are ~~delivered and/or services~~not limited to, customer credit issues, the level of natural gas prices and general economic conditions. Accounts are ~~rendered.~~written off when they are deemed to be uncollectible.

Certain Risks and Uncertainties

The Company’s financial statements are prepared in conformity with ~~generally accepted accounting principles~~GAAP that require management to make estimates in measuring assets and liabilities and related revenues and expenses (see Notes MN and NO 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.

~~- Page 50 -~~

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~~amounts deferred ~~amounts~~in accordance with SFAS No. 71 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~~Financial Accounting Standards Board (“FASB”) Statements and Other Authoritative Pronouncements

Recent accounting pronouncements:

In December ~~2004,~~2007, the FASB ~~released a revision (“Share-Based Payment”) to~~issued SFAS No. ~~123 “Accounting~~141(R), which retains the fundamental requirements of the original pronouncement requiring that the acquisition method be used for ~~Stock-Based Compensation,” referred~~all business combinations. SFAS No.141(R): (a) defines the acquirer as the entity that obtains control of one or more businesses in a business combination, (b) establishes the acquisition date as the date that the acquirer achieves control and (c) requires the acquirer to recognize the assets acquired, liabilities assumed and any non-controlling interests at their fair values as of the acquisition date. SFAS No. ~~123R. In April 2005, the SEC approved a new rule~~141(R) also requires that ~~delayed the effective date for~~acquisition-related costs be expensed as incurred. SFAS No. ~~123R until the first annual period~~141(R) is effective for fiscal years beginning after ~~June~~December 15, ~~2005. This Statement establishes~~2008. The Company does not expect the adoption of SFAS No.141(R) to have a material impact on its current consolidated financial position and results of operations. However, depending upon the size, nature and complexity of future acquisition transactions, the adoption of SFAS No. 141(R) could materially affect the Company’s consolidated financial statements.

Chesapeake Utilities Corporation 2008 Form 10-K Page 71

Notes to the Consolidated Financial Statements

In December 2007, the FASB issued SFAS No. 160, an amendment of Accounting Research Bulletin No. 51, which changes the accounting and reporting ~~standards~~ for ~~stock-based employee compensation plans. Those plans include all arrangements~~minority interests by ~~which employees receive shares~~recharacterizing them as noncontrolling interests and classifying them as a component of ~~stock or~~equity. This new consolidation method significantly changes the accounting for transactions with minority interest holders. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008. No other ~~equity instruments~~entity has a minority interest in any of the ~~employer or~~Company’s subsidiaries; therefore, the ~~employer incurs liabilities~~Company does not expect the adoption of SFAS No. 160 to ~~employees~~have a material impact on its current consolidated financial position and results of operations.

In November 2008, the SEC released a proposed roadmap regarding the potential use by U.S. issuers of financial statements prepared in ~~amounts based~~accordance with International Financial Reporting Standards (IFRS). IFRS is a comprehensive series of accounting standards published by the International Accounting Standards Board (“IASB”). Under the proposed roadmap, the Company may be required to prepare financial statements in accordance with IFRS as early as 2014. The SEC will make a determination in 2011 regarding the mandatory adoption of IFRS. The Company is currently assessing the impact that this potential change would have on its consolidated financial statements, and it will continue to monitor the ~~price~~development of the ~~employer’s stock. Examples are stock purchase plans, stock options, restricted stock~~potential implementation of IFRS.

In March 2008, the FASB issued SFAS No. 161, an amendment of FASB Statement No. 133, which requires enhanced disclosures for derivative instruments, including those used in hedging activities. It is effective for fiscal years and ~~stock appreciation rights.~~interim periods beginning after November 15, 2008, and will be applicable to the Company in the first quarter of fiscal 2009. The Company does not expect the adoption of SFAS No. 161 to have a material impact on its current consolidated financial position and results of operations.

In April 2008, the FASB issued FSP 142-3. This FSP amends the factors which should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”). The intent of this ~~pronouncement will~~FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141R and other GAAP. This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. The Company does not expect the adoption of FSP SFAS No. 142-3 to have a material impact on its current consolidated financial position and results of operations.

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

In ~~March 2005,~~May 2008, the FASB issued FSP Accounting Principles Board (“APB”) APB 14-1, which clarifies that convertible debt instruments that may be settled in cash upon either mandatory or optional conversion (including partial cash settlement) are not addressed by paragraph 12 of APB Opinion No. 14, “Accounting for Convertible Debt and Debt issued with Stock Purchase Warrants.” In addition, FSP APB 14-1 specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. FSP APB 14-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. The Company does not expect the adoption of FSP APB 14-1 to have a material impact on its current consolidated financial position and results of operations.

Page 72 Chesapeake Utilities Corporation 2008 Form 10-K

In June 2008, the FASB issued Emerging Issues Task force (“EITF”) 03-6-1 to clarify that all outstanding unvested share-based payment awards that contain rights to nonforfeitable dividends participate in undistributed earnings with common shareholders. Awards of this nature are considered participating securities, and the two-class method of computing basic and diluted earnings per share must be applied. This FSP is effective for fiscal years beginning after December 15, 2008. The Company does not expect the adoption of EITF 03-6-1 to have a material impact on its current consolidated financial position and results of operations.

In June 2008, the FASB ratified EITF 07-5. EITF 07-5 provides that an entity should use a two-step approach to evaluate whether an equity-linked financial instrument (or embedded feature) is indexed to its own stock, including evaluating the instrument’s contingent exercise and settlement provisions. It also clarifies the impact of foreign-currency-denominated strike prices and market-based employee stock option valuation instruments on the evaluation. EITF 07-5 is effective for fiscal years beginning after December 15, 2008. The Company does not expect the adoption of EITF 07-5 to have a material impact on its current consolidated financial position and results of operations.

In June 2008, the FASB ratified EITF 08-3 to provide guidance for accounting for nonrefundable maintenance deposits. It also provides revenue recognition accounting guidance for the lessor. EITF 08-3 is effective for fiscal years beginning after December 15, 2008. The Company does not expect the adoption of EITF 08-3 to have a material impact on its current consolidated financial position and results of operations.

In September 2008, the FASB ratified EITF 08-5 to provide guidance for measuring liabilities issued with an attached third-party credit enhancement (such as a guarantee). It clarifies that the issuer of a liability with a third-party credit enhancement should not include the effect of the credit enhancement in the fair value measurement of the liability. EITF 08-5 is effective for the first reporting period beginning after December 15, 2008. The Company does not expect the adoption of EITF 08-5 to have a material impact on its current consolidated financial position and results of operations.

During 2008, the Company adopted the following accounting standards:

In September 2008, the FASB issued FSP 133-1 and FIN 45-4, “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 4745; and Clarification of the Effective Date of FASB Statement No. 161” (“FSP 133-1/FIN ~~No. 47”~~45-4”)~~, “Accounting~~. FSP 133-1/FIN 45-4 amends and enhances disclosure requirements for ~~Conditional Asset Retirement Obligations” an interpretation~~sellers of credit derivatives and financial guarantees. It also clarifies that the disclosure requirements of SFAS No. ~~143.~~ 161 are effective for quarterly periods beginning after November 15, 2008, and fiscal years that include those periods. FSP 133-1/FIN No. 47 clarifies that the term conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may45-4 is effective for reporting periods (annual or ~~may not be within the control of the entity.~~interim) ending after November 15, 2008. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event. FIN No. 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The Company adopted FIN No. 47 in the fourth quarter of 2005. The adoptionimplementation of this ~~interpretation~~standard did not have a material impact on the ~~company’s~~Company’s consolidated financial position and results of operations.

In October 2008, the FASB issued FSP 157-3 to clarify the application of the provisions of SFAS No. 157 in an inactive market and how an entity would determine fair value in an inactive market. FSP 157-3 is effective immediately and applied to the Company’s September 30, 2008 financial statements. The application of the provisions of FSP 157-3 did not materially affect the company’s results of operations or financial condition as of and for the period ended December 31, 2008.

Chesapeake Utilities Corporation 2008 Form 10-K Page 73

Notes to the Consolidated Financial Statements

Effective January 1, 2008, Chesapeake adopted FIN 39-1, which permits companies to offset cash collateral receivables or payables with net derivative positions under certain circumstances. Based on the derivative contracts entered into to date, adoption of this FSP has not materially affected the Company’s consolidated financial statements for the period ended December 31, 2008.

In ~~May 2005,~~September 2006, the FASB issued SFAS No. ~~154, “Accounting Changes~~157, which provides guidance for using fair value to measure assets and ~~Error Corrections — a replacement~~liabilities. It also responds to investors’ requests for expanded information about the extent to which companies’ measure assets and liabilities at fair value, the information used to measure fair value, and the effect of ~~APB Opinion~~fair value measurements on earnings. SFAS No. 20157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value and does not expand the use of fair value in any new circumstances. In February 2008, the FASB issued FSP 157-1, “Application of FASB Statement No. 3”157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement No. 13” (“FSP 157-1”), and FSP 157-2, “Effective Date of FASB Statement No. 157” (“FSP 157-2”). FSP 157-1 amends SFAS ~~154 primarily requires retrospective application~~No. 157 to ~~prior periods’ financial statements for~~remove certain leasing transactions from its scope. FSP 157-2 delays the ~~direct effects~~effective date of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. This statement applies to all voluntary changes in accounting principle and also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. The statement is effective for accounting changes and corrections of errors made inSFAS No. 157 until fiscal years beginning after ~~December~~November 15, ~~2005.~~2009 for all non-financial assets and non-financial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis. These non-financial items include assets and liabilities, such as reporting units measured at fair value in a goodwill impairment test and non-financial assets acquired and liabilities assumed in a business combination. SFAS No. 157 was effective for financial statements issued for fiscal years beginning after November 15, 2007 and was adopted by the Company, as it applies to its financial instruments, effective January 1, 2008. Adoption of SFAS No. 157 had no financial impact on the Company’s consolidated financial statements. The disclosures required by SFAS No. 157 are discussed in Note E — “Fair Value of Financial Instruments” of the Consolidated Financial Statements.

In February 2007, the FASB issued SFAS No. 159, which permits entities to elect to measure at fair value many financial instruments and certain other items that are not currently required to be measured at fair value. This election is irrevocable. SFAS No. 159 became effective in the first quarter of fiscal 2008. The Company ~~is required~~has not elected to ~~adopt~~apply the ~~provision~~fair value option to any of ~~SFAS 154, as applicable, beginning in fiscal year 2006.~~its financial instruments.

Reclassification of Prior Years’ Amounts

~~Certain prior years’~~The Company reclassified some previously reported amounts ~~have been reclassified~~ to conform to ~~the~~ current ~~year’s presentation.~~period classifications.

B. Business Dispositions and Discontinued Operations

During ~~2003,~~2007, Chesapeake decided to ~~exit~~close its distributed energy services subsidiary, OnSight, which had experienced operating losses since its inception in 2004. OnSight was previously reported as part of the water services business and sold six of its seven operations. The remaining operation was disposed of in October 2004. At December 31, 2005, Chesapeake owned one piece of property that was formerly used by a water subsidiary. That property was listed for sale at December 31, 2005 and subsequently sold in January 2006.Company’s Other Business segment. The results of operations for ~~all water service businesses~~OnSight have been reclassified to discontinued operations and shown net of tax for all periods presented. AThe discontinued operations experienced a net loss of ~~$52,000 and~~$20,000 for 2007, compared to a ~~gain~~net loss of ~~$12,000, net of tax, were recorded~~$241,000 for ~~2004 and 2003, respectively, on the sale of the water operations.~~2006. The Company did not have any discontinued operations in ~~2005.~~2008.

Page 74 Chesapeake Utilities Corporation 2008 Form 10-K

~~- Page 51 -~~

Operating revenues for discontinued operations were $1.1 million and $9.8 million for 2004 and 2003, respectively. Operating losses for discontinued operations were $94,000 and $917,000 for 2004 and 2003, respectively. The balance sheet included the following discontinued operations for December 31, 2004:

·	~~Net property, plant, and equipment of $184,000;~~

·	~~Cash and other current assets were $5,000 and $63,000, respectively;~~

·	~~Common stock, additional paid-in capital, and retained deficits were $51,000, $3.9 million, and $6.5 million, respectively; and~~

·	~~Due to affiliates and other current liabilities were $2.7 million and $45,000, respectively.~~

~~- Page 52 -~~

C. Segment Information

The following table presents information about the Company’s reportable segments. The table excludes financial data related to its distributed energy company, which was reclassified to discontinued ~~operations.~~

operations for each year presented.


For the Years Ended December 31,	2008		2007		2006
Operating Revenues, Unaffiliated Customers
Natural gas	$	210,957,687	$	180,842,699	$	170,114,512
Propane		65,873,930		62,837,696		48,575,976
Advanced information services		14,611,860		14,606,100		12,509,077

Total operating revenues, unaffiliated customers	$	291,443,477	$	258,286,495	$	231,199,565

Intersegment Revenues⁽¹⁾
Natural gas	$	444,083	$	359,235	$	259,970
Propane		2,861		406		—
Advanced information services		108,596		492,840		58,532
Other		652,296		622,272		618,492

Total intersegment revenues	$	1,207,836	$	1,474,753	$	936,994

Operating Income
Natural gas	$	25,846,346	$	22,485,266	$	19,733,487
Propane		1,586,414		4,497,843		2,534,035
Advanced information services		694,636		835,981		767,160
Other and eliminations		351,538		294,492		297,255

Operating Income		28,478,934		28,113,582		23,331,937

Other income		103,039		291,305		189,093
Interest charges		6,157,552		6,589,639		5,773,993
Income taxes		8,817,162		8,597,461		6,999,072

Net income from continuing operations	$	13,607,259	$	13,217,787	$	10,747,965


Depreciation and Amortization
Natural gas	$	6,694,037	$	6,917,609	$	6,312,277
Propane		2,024,172		1,842,047		1,658,554
Advanced information services		175,295		143,706		112,729
Other and eliminations		111,407		156,823		160,155

Total depreciation and amortization	$	9,004,911	$	9,060,185	$	8,243,715


Capital Expenditures
Natural gas	$	25,386,046	$	23,086,713	$	43,894,614
Propane		3,416,514		5,290,215		4,778,891
Advanced information services		678,705		174,184		159,402
Other		1,362,246		1,591,272		321,204

Total capital expenditures	$	30,843,511	$	30,142,384	$	49,154,111


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


At December 31,	2008		2007		2006

Identifiable Assets
Natural gas	$	297,407,548	$	273,500,890	$	252,292,600
Propane		72,954,861		94,966,212		60,170,200
Advanced information services		3,544,847		2,507,910		2,573,810
Other		11,849,010		10,533,511		10,503,804

Total identifiable assets	$	385,756,266	$	381,508,523	$	325,540,414

For the Years Ended December 31,

2005

2004

2003

Operating Revenues, Unaffiliated Customers

Natural gas distribution and transmission
$
166,388,562
$ 124,073,939 $ 110,071,054
Propane
48,975,349
41,499,687 41,029,121
Advanced information services
14,121,441
12,381,815 12,476,746
Other
144,384
- ($9,329 )
Total operating revenues, unaffiliated customers
$
229,629,736
$ 177,955,441 $ 163,567,592

Intersegment Revenues ⁽¹⁾

Natural gas distribution and transmission
$
193,404
$ 172,427 $ 175,757
Propane
668
- -
Advanced information services
18,123
45,266 100,804
Other
618,492
647,378 711,159
Total intersegment revenues
$
830,687
$ 865,071 $ 987,720

Operating Income

Natural gas distribution and transmission
$
17,235,810
$ 17,091,360 $ 16,653,111
Propane
3,209,388
2,363,884 3,875,351
Advanced information services
1,196,544
387,193 691,909
Other and eliminations
(111,243
)
127,309 359,029
Total operating income
$
21,530,499
$ 19,969,746 $ 21,579,400

Depreciation and Amortization

Natural gas distribution and transmission
$
5,682,137
$ 5,418,007 $ 5,188,273
Propane
1,574,357
1,524,016 1,506,201
Advanced information services
122,569
138,007 190,548
Other and eliminations
189,146
177,508 204,814
Total depreciation and amortization
$
7,568,209
$ 7,257,538 $ 7,089,836

Capital Expenditures

Natural gas distribution and transmission
$
28,433,671
$ 13,945,214 $ 9,078,043
Propane
3,955,799
3,395,190 2,244,583
Advanced information services
294,792
84,185 76,924
Other
739,079
404,941 422,789
Total capital expenditures
$
33,423,341
$ 17,829,530 $ 11,822,339

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

Chesapeake Utilities Corporation 2008 Form 10-K Page 75

Notes to the Consolidated Financial Statements

At December 31,

2005

2004

2003

Identifiable Assets

Natural gas distribution and transmission
$
225,667,049
$ 184,412,301 $ 170,758,784
Propane
57,344,859
47,531,106 38,359,251
Advanced information services
2,062,902
2,387,440 2,912,733
Other
10,905,065
7,379,794 7,791,796
Total identifiable assets
$
295,979,875
$ 241,710,641 $ 219,822,564

~~- Page 53 -~~

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 ~~all~~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. Supplemental Cash Flow Disclosures

Cash paid for interest and income taxes during the years ended December 31, 2008, 2007, and 2006 was as follow:


For the Years Ended December 31,	2008		2007		2006
Cash paid for interest	$	5,835,321	$	5,592,279	$	5,334,477
Cash paid for income taxes	$	3,884,921	$	7,009,206	$	6,285,272

Non-cash investing and financing activities during the years ended December 31, 2008, 2007, and 2006 were as follow:


For the Years Ended December 31,	2008		2007		2006
Capital property and equipment acquired on account, but not paid as of December 31	$	696,268	$	365,890	$	1,490,890
Retirement Savings Plan	$	158,756	$	948,683	$	914,811
Dividends Reinvestment Plan	$	208,194	$	840,718	$	844,920
Conversion of Debentures	$	176,740	$	137,784	$	283,417
Performance Incentive Plan	$	568,361	$	435,309	$	715,494
Director Stock Compensation Plan	$	181,312	$	183,573	$	175,617
Tax benefit on stock warrants	$	50,244		—	$	201,455

D.E. Fair Value of Financial Instruments

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

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

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

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

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

Page 76 Chesapeake Utilities Corporation 2008 Form 10-K

The following table summarizes the Company’s financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy used at December 31, 2008:


			Fair Value Measurements Using:
					Significant
					Other		Significant
			Quoted Prices in		Observable		Unobservable
			Active Markets		Inputs		Inputs
(in thousands)	Fair Value		(Level 1)		(Level 2)		(Level 3)
Assets:
Investments	$	1,601	$	1,601		—		—
Mark-to-market energy assets	$	4,482		—	$	4,482		—

Liabilities:
Mark-to-market energy liabilities	$	3,052		—	$	3,052		—
Price swap agreement	$	105		—	$	105		—

The following valuation techniques were used to measure fair value assets in the table above on a recurring basis as of December 31, 2008:

Level 1 Fair Value Measurements:

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

Level 2 Fair Value Measurements:

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

Propane price swap agreement —The fair value of the propane price swap agreement is valued using market transactions in either the listed or OTC markets.

In addition, 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, 2005 had a gain in fair value of $46,000 and at December 31, 2004 had a loss in fair value of $182,000 based on market rates.value. 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, 2005, including current maturities, had an estimated fair value of $68.5 million as compared to~~methodology that incorporates a ~~carrying value of $63.9 million. At December 31, 2004, the estimated fair value was approximately $74.8 million as compared to a carrying value of $69.1 million. These estimates are~~market interest rate that is based on published corporate borrowing rates for debt instruments with similar terms and average ~~maturities.~~maturities with adjustments for duration, optionality, and risk profile. The Company’s long-term debt at December 31, 2008, including current maturities, had an estimated fair value of $92.3 million compared to a carrying value of $93.1 million. At December 31, 2007, the estimated fair value was approximately $75.0 million compared to a carrying value of $70.9 million.

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

Chesapeake Utilities Corporation 2008 Form 10-K Page 77

Notes to the Consolidated Financial Statements

E.F. Investments

The investment balances at December 31, ~~2005~~2008 and ~~2004,~~2007 represent a Rabbi Trust ~~(“the trust”)~~ associated with the Company’s Supplemental Executive Retirement Savings ~~Plan.~~Plan and a Rabbi Trust related to a stay bonus agreement with a former executive. 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, ~~we are~~the Company is required to report the securities at their fair value, with any unrealized gains and losses included in other income. WeThe Company also ~~have~~has an associated liability that is recorded and adjusted each month ~~along with other expense,~~ for the gains and losses incurred by the ~~trust.~~

Trust. At December 31, 2008 and 2007, total investments had a fair value of $1.6 million and $1.9 million, respectively.

F.G. 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~~segment reported $674,000 in goodwill for the two years ended December 31, ~~2005~~2008 and ~~2004.~~2007. Testing for ~~2005~~2008 and ~~2004 has~~2007 indicated that no impairment of the goodwill has occurred.

~~- Page 54 -~~

The carrying value and accumulated amortization of intangible assets subject to amortization for the ~~two~~ years ended December 31, ~~2005~~2008 and 2007 are as ~~follows:~~

follow:


	December 31, 2008				December 31, 2007
	Gross				Gross
	Carrying		Accumulated		Carrying		Accumulated
	Amount		Amortization		Amount		Amortization

Customer lists	$	115,333	$	89,481	$	115,333	$	82,269
Acquisition costs		263,659		125,243		263,659		118,650

Total	$	378,992	$	214,724	$	378,992	$	200,919

December 31, 2005

December 31, 2004

Gross Carrying Amount

Accumulated Amortization

Gross Carrying Amount

Accumulated Amortization

Customer lists
$
115,333

$
67,845
$ 115,333 $ 60,155
Acquisition costs
263,659

105,465
263,659 98,873
Total
$
378,992

$
173,310
$ 378,992 $ 159,028

Amortization of intangible assets was $14,000 ~~and $15,000~~ for the years ended December 31, ~~2005~~2008 and ~~2004, respectively.~~2007. The estimated annual amortization of intangibles is $14,000 per year for each of the years ~~2006~~2009 through ~~2010, respectively.~~2013.

Page 78 Chesapeake Utilities Corporation 2008 Form 10-K

G. H. Stockholders’ Equity

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


For the Years Ended December 31,	2008			2007			2006

Common Stock shares issued and outstanding⁽¹⁾
Shares issued — beginning of period balance		6,777,410			6,688,084			5,883,099
Dividend Reinvestment Plan⁽²⁾		9,060			35,333			38,392
Retirement Savings Plan		5,260			29,563			29,705
Conversion of debentures		10,397			8,106			16,677
Employee award plan		250			350			350
Share-based compensation⁽³⁾		24,744			15,974			29,516
Public offering		—			—			690,345

Shares issued — end of period balance⁽⁴⁾		6,827,121			6,777,410			6,688,084
Treasury shares — beginning of period balance		—			—			(97	)
Purchases		(2,425	)		(971	)		—
Deferred Compensation Plan		2,425			971			—
Other issuances		—			—			97

Treasury Shares — end of period balance		—			—			—


Total Shares Outstanding		6,827,121			6,777,410			6,688,084


⁽¹⁾		12,000,000 shares are authorized at a par value of $0.4867 per share.

⁽²⁾		Includes shares purchased with reinvested dividends and optional cash payments.

⁽³⁾		Includes shares issued for Directors’ compensation.

⁽⁴⁾		Includes 62,221, 57,309, and 48,187 shares at December 31, 2008, 2007 and 2006, respectively, held in a Rabbi Trust established by the Company relating to the Deferred Compensation Plan.

For the Years Ended December 31,

2005

2004

2003

Common Stock shares issued and outstanding ⁽¹⁾

Shares issued — beginning of period balance
5,778,976
5,660,594 5,537,710
Dividend Reinvestment Plan ⁽²⁾

41,175
40,993 51,125
Retirement Savings Plan
21,071
39,157 43,245
Conversion of debentures
22,609
18,616 18,788
Performance shares and options exercised ⁽³⁾

19,268
19,616 9,726
Shares issued — end of period balance ⁽⁴⁾

5,883,099
5,778,976 5,660,594

Treasury shares — beginning of period balance
(9,418
)
- -
Purchases
(4,852
)
(15,316 ) -
Dividend Reinvestment Plan
2,142
- -
Retirement Savings Plan
12,031
- -
Other issuances
-
5,898 -
Treasury Shares — end of period balance
(97
)
(9,418 ) -

Total Shares Outstanding
5,883,002

5,769,558

5,660,594

⁽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 37,528, 48,175, and 47,659 shares at December 31, 2005, 2004 and 2003, respectively, held in a Rabbi Trust established by the Company relating to the Supplemental Executive Retirement Savings Plan.

~~In 2000 and 2001,~~On November 21, 2006, the Company ~~entered into agreements with an investment banker to assist in identifying acquisition candidates. Under the agreements,~~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 ~~issued warrants~~completed the sale of 90,045 additional shares of its common stock, pursuant to the ~~investment banker~~over-allotment option granted to ~~purchase 15,000 share~~the underwriters by the Company. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $19.7 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.

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. The warrants are exercisable during a seven-year period after~~Utilities Corporation 2008 Form 10-K Page 79

Notes to the grant date. At December 31, 2005, the Company had outstanding warrants of 30,000 at an average exercise price of $18.125 per share — 15,000 warrants expire in 2007 and the remaining 15,000 expire in 2008.

~~- Page 55 -~~

Consolidated Financial Statements

H.I. Long-term Debt

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


At December 31,	2008			2007
Uncollateralized senior notes:
7.97% note, due February 1, 2008	$	—		$	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		24,545,455			27,272,727
5.50% note, due October 12, 2020		20,000,000			20,000,000
5.93% note, due October 31, 2023		30,000,000			—
Convertible debentures:
8.25% due March 1, 2014		1,655,000			1,832,000
Promissory note		60,000			80,000

Total long-term debt		93,078,637			70,912,000
Less: current maturities		(6,656,364	)		(7,656,364	)

Total long-term debt, net of current maturities	$	86,422,273		$	63,255,636

Annual maturities of consolidated long-term debt are as follows: $6,656,364 for 2009, $6,656,364 for 2010, $7,747,273 for 2011, $6,727,273 for 2012, $6,727,273 for 2013, and $58,564,091 thereafter.

At December 31,

2005

2004

Uncollateralized senior notes:
7.97% note, due February 1, 2008
$
2,000,000
$ 3,000,000
6.91% note, due October 1, 2010
3,636,363
4,545,454
6.85% note, due January 1, 2012
5,000,000
6,000,000
7.83% note, due January 1, 2015
16,000,000
20,000,000
6.64% note, due October 31, 2017
30,000,000
30,000,000
Convertible debentures:
8.25% due March 1, 2014
2,254,000
2,644,000
Promissory note
100,000
-
Total Long-Term Debt
$
58,990,363
$ 66,189,454

Annual maturities of consolidated long-term debt for the next five years are as follows: $4,929,091 for 2006; $7,656,364 for 2007; $7,656,364 for 2008; $6,656,364 for 2009 and $6,656,364 for 2010.

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 ~~2005~~2008 and ~~2004,~~2007, debentures totaling ~~$385,000~~$177,000 and ~~$317,000,~~$138,000, 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. ~~During 2005, debentures totaling $5,000 were redeemed for cash.~~ In ~~2004,~~2008 and 2007, no debentures were redeemed for cash. At the Company’s option, the debentures may be redeemed at stated amounts.

On ~~June 29, 2005,~~October 31, 2008, the Company ~~entered into an agreement in principal with Prudential Investment Management Inc. Subsequently, the Company executed a Note Agreement, dated October 18, 2005, with three~~issued $30 million of 5.93 percent Unsecured Senior Notes to two institutional investors ~~(The Prudential~~(General American Life Insurance Company ~~of America, Prudential Retirement Insurance~~ and ~~Annuity Company and United Omaha~~New England Life Insurance Company)~~, pursuant to which~~. The terms of the ~~investors agreed, subject to certain conditions, to purchase from the Company $20 million in principal of 5.5 percent~~ Senior Notes ~~(the “Notes”) issued by~~require principal repayments of $1.5 million on the ~~Company provided that the Company elects to effect~~30^th day of April and 31st day of October in each year, commencing on April 30, 2014. The Senior Notes will mature on October 31, 2023. The proceeds of the sale of the Senior Notes ~~at any time prior~~were used to ~~January 15, 2007. The terms of the Notes will require annual principal repayments of $2 million beginning on the fifth anniversary of the issuance of the Notes.~~refinance capital expenditures and for general corporate purposes.

Debt Covenants

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~~Failure to comply with those covenants could result in accelerated due dates and/or termination of the agreements. As of December 31, 2008, the Company is in compliance with all of its debt covenants.

In terms of restrictions which limit the payment of dividends by the Company, each of the Company’s Unsecured Senior Notes contains a “Restricted Payments” covenant. The most restrictive covenants of this type are included within the 7.83% Senior Notes, due January 1, 2015. The covenant provides that the Company cannot pay or declare any dividends or make any other Restricted Payments (such as dividends) in excess of the sum of $10.0 million, plus consolidated net income of the Company accrued on and after January 1, 2001. As of December 31, 2008, the Company’s cumulative consolidated net income base was $86.9 million, offset by Restricted Payments of $54.4 million, leaving $32.5 million of cumulative net income free of restrictions.

In addition, the Company’s subsidiaries are not restricted from transferring funds to the Company in the form of loans, advances or cash dividends under the terms of the covenants of the Company’s various Unsecured Senior Notes.

Page 80 Chesapeake Utilities Corporation 2008 Form 10-K

I.J. Short-term Borrowing

At December 31, 2008 and 2007, we had $33.0 million and $45.7 million, respectively, of short-term borrowing outstanding under our bank credit facilities. The annual weighted average interest rates on our short-term borrowing were 2.79 percent and 5.46 percent for 2008 and 2007, 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 Company’s lines of credit and is scheduled to expire on May 31, 2009. 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.

Credit facilities

As of December ~~31, 2005,~~22, 2008, the Board of Directors ~~(“Board”) had~~has authorized the Company to borrow up to ~~$50.0~~$65.0 million of short-term debt, as required, from various banks and trust companies under short-term lines of credit. As of December 31, ~~2005, the Company~~2008, Chesapeake had ~~three uncommitted and two committed, short-term~~five unsecured bank lines of credit with three financial institutions, totaling ~~$65.0~~$100.0 million, none of which ~~required~~requires compensating balances. ~~Under these~~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. We maintain both committed and uncommitted credit facilities. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks.

Committed credit facilities

As of December 31, 2008, we had two committed revolving credit facilities totaling $55.0 million. The first facility is an unsecured $30.0 million revolving line of credit that bears interest at the respective LIBOR rate, plus 0.75 percent per annum. At December 31, 2008, there was $17.0 million available under this credit facility.

The second facility is a $25.0 million committed revolving line of credit that bears interest at a base rate plus 125 basis points, if requested and advanced on the same day, or LIBOR for the applicable period plus 125 basis points if requested three days prior to the advance date. At December 31, 2008, the entire borrowing capacity of $25.0 million was available under this credit facility.

The availability of funds under our credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in our revolving credit facilities to maintain, at the end of each fiscal year:

	•		a funded indebtedness ratio of no greater than 65 percent; and

	•		A fixed charge coverage ratio of at least 1.20 to 1.0.

The Company is in compliance with all of its debt covenants.

Uncommitted credit facilities

As of December 31, 2008, we had three uncommitted lines of credit facilities totaling $45.0 million. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks.

The first facility is an uncommitted $20.0 million line of credit that bears interest at a rate per annum as offered by the bank for the applicable period. At December 31, 2008, the Company ~~had short-term debt outstanding~~has reached the $20.0 million borrowing capacity under this credit facility.

The second facility is a $10.0 million uncommitted revolving line of ~~approximately $35.5 million and $5.0 million~~credit that bears interest at either the Prime Rate or the daily LIBOR Rate for the applicable period. At December 31, ~~2005 and 2004, respectively.~~ 2008, the entire borrowing capacity of $10.0 million was available under this credit facility.

Chesapeake Utilities Corporation 2008 Form 10-K Page 81

Notes to the Consolidated Financial Statements

The ~~annual weighted average~~final facility is a $15.0 million uncommitted line of credit that bears interest ~~rates were 4.6~~at the bank’s base rate or the respective LIBOR rate, plus 1.25 percent per annum. At December 31, 2008, there was $14.2 million available under this credit facility, which was reduced by $775,000 for ~~2005 and 3.7 percent for 2004. The Company also had~~ a letter of credit ~~outstanding in~~issued to our primary insurance company. The letter of credit is provided as security to satisfy the ~~amount of $694,000 that reduced the amounts available~~deductibles under the ~~lines~~Company’s various insurance policies and expires on May 31, 2009. The Company does not anticipate that this letter of ~~credit.~~

~~- Page 56 -~~

credit will be drawn upon by the counter-party and it expects that it will be renewed as necessary.

J.K. 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 ~~$837,000, $934,000~~$880,000, $736,000, and ~~$1.1 million~~$680,000 for ~~2005, 2004~~2008, 2007, and ~~2003,~~2006, respectively. Future minimum payments under the Company’s current lease agreements are ~~$646,000, $597,000, $466,000, $395,000~~$770,000, $612,000, $605,000, $560,000 and ~~$298,000~~$369,000 for the years ~~of 2006~~2009 through ~~2010,~~2013, respectively; and $2.4 million thereafter, ~~totaling $4.8~~with an aggregate total of $5.4 million.

K.L. Employee Benefit Plans

Retirement ~~Plan~~s

Plans

Before 1999, Company employees generally participated in both a defined benefit pension plan (“Defined Pension ~~Plan~~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 benefit~~Defined Pension Plan to new participants. Employees who participated in the ~~defined benefit~~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 benefit~~Defined Pension Plan was not open to new participants, the number of active participants in that plan decreased and iswas 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 benefit~~Defined Pension Plan on September 24, 2004. To ensure that the Company ~~continues~~would continue to provide appropriate levels of benefits to the Company’s employees, the Board amended the ~~defined benefit~~Defined Pension Plan and the Retirement Savings Plan, effective January 1, 2005, so that Defined Pension Plan participants who ~~are~~were actively employed by the Company on that date would: (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~~be eligible to receive the enhanced matching contribution in the Retirement Savings Plan. In addition, effective January 1, 2005, the Board amended the ~~defined benefit~~Defined Pension Plan so that participants ~~will~~would not accrue any additional benefits under that plan. These changes were communicated to the Company’s employees during the first week of November 2004. As

The Company also provides an unfunded pension supplemental executive retirement plan (“Pension SERP”), formerly called the Executive Excess Retirement Plan. 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. In December 2008, the Pension SERP was amended to allow participants to elect a ~~result~~lump sum payment and to add the other optional forms of benefit payments currently available under the Defined Pension Plan.

In addition to the Defined Pension Plan and the Pension SERP, the Company provides an unfunded postretirement health care and life insurance plan that covers employees who have met certain age and service requirements. The measurement date for each of the ~~amendments~~three plans was December 31, 2008 and 2007.

Page 82 Chesapeake Utilities Corporation 2008 Form 10-K

In September 2006, the FASB issued SFAS No. 158, which the Company adopted, prospectively, for the Defined Pension, Pension SERP and Other Postretirement Benefits on December 31, 2006. SFAS No. 158 requires that we recognize all obligations related to defined benefit pensions and other postretirement benefits and that we quantify the plans’ funded status as an asset or a liability on our consolidated balance sheets.

SFAS No. 158 further 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 or SFAS No. 106.

At December 31, 2008, the funded status of the Company’s Defined Pension Plan was a ~~gain~~liability of ~~approximately $172,000 (after tax)~~$4.9 million; at December 31, 2007, it was a liability of $275,000. In order to account for the decrease in the funded status in accordance with SFAS No. 158, the Company recorded ~~during 2004.~~a charge of $2.8 million, net of tax, to Comprehensive Income. In addition, the funded status of the postretirement health and life insurance plan was a liability of $2.2 million at December 31, 2008 compared to $1.8 million at December 31, 2007. To adjust for the increased liability for the postretirement health and life insurance plan, as required by SFAS No. 158, the Company took a charge of $30,400, 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 2009 are set forth in the following table.

Defined Other
Benefit Pension Postretirement
Pension SERP Benefit
Prior service cost (credit) $ (4,699 ) $ 13,176 —
Net loss $ 268,276 $ 59,089 $ 158,378

The following table presents the amounts not yet reflected in net periodic benefit cost and included in AOCI as of December 31, 2008.

Defined Other
Benefit Pension Postretirement
Pension SERP Benefit
Prior service cost (credit) $ (20,162 ) $ 118,580 —
Net loss (gain) 4,319,514 (175,725 ) 1,049,291

Subtotal 4,299,352 (57,145 ) 1,049,291
Tax expense (benefit) (1,721,460 ) 20,041 (420,136 )

AOCI $ 2,577,892 $ (37,104 ) $ 629,155

Defined Benefit Pension Plan

As previously described, ~~above,~~ effective January 1, 2005, the ~~defined benefit~~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~~was not ~~expect to be~~ required to make any funding payments ~~in 2006. The measurement dates for~~to the Defined Pension Plan ~~were December 31, 2005 and 2004, respectively.~~in 2008.

Chesapeake Utilities Corporation 2008 Form 10-K Page 83

Notes to the Consolidated Financial Statements

The following schedule summarizes the assets of the Defined Pension Plan, by investment type, at December 31, ~~2005~~2008, 2007 and ~~2004:~~

2006:


At December 31,	2008			2007			2006
Asset Category
Equity securities		48.70	%		49.03	%		77.34	%
Debt securities		51.24	%		50.26	%		18.59	%
Other		0.06	%		0.71	%		4.07	%

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:

~~At December 31,~~	•	~~2005~~ United States Government obligations; and		~~2004~~

~~Asset Category~~	•
~~Equity securities~~		~~76.12~~	%		~~72.64~~	%
~~Debt securities~~		~~23.28~~	%		~~12.91~~	%
~~Other~~		~~0.60~~	%		~~14.45~~	%
~~Total~~		~~100.00~~	%		~~100.00~~	%Repurchase agreements that are fully collateralized by such obligations.

~~- Page 57 -~~

The investment policy of the Plan calls for an allocation of assets between equity and debt instruments, with equity being 6030 percent and debt at 4070 percent, but allowing for a variance of 20 percent in either direction. ~~Additionally,~~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. Additionally,~~stock; short selling and margin transactions are ~~prohibited.~~prohibited as well. During ~~2004,~~2007, Chesapeake modified its investment policy to allow the Employee Benefits Committee to reallocate investments to better match the expected life of the plan.

The following schedule sets forth the funded status of the Defined Pension Plan at December 31, ~~2005~~2008 and ~~2004:~~

2007:


At December 31,	2005			2004			2008			2007
Change in benefit obligation:
Benefit obligation — beginning of year	$	12,053,063		$	11,948,755		$	11,073,520		$	11,449,725
Service cost		-			338,352
Interest cost		645,740			690,620			593,723			622,057
Change in assumptions		388,979			573,639			267,953			—
Actuarial loss		28,895			220,842			83,704			282,684
Amendments		-			883,753
Effect of curtailment/settlement		-			(2,171,289	)
Benefits paid		(717,056	)		(431,609	)		(426,652	)		(1,280,946	)

Benefit obligation — end of year		12,399,621			12,053,063			11,592,248			11,073,520


Change in plan assets:
Fair value of plan assets — beginning of year		12,097,248			11,301,548			10,798,781			12,040,287
Actual return on plan assets		400,674			1,227,309			(3,683,183	)		39,440
Benefits paid		(717,056	)		(431,609	)		(426,652	)		(1,280,946	)

Fair value of plan assets — end of year		11,780,866			12,097,248			6,688,946			10,798,781


Reconciliation:
Funded status		(618,755	)		44,185			(4,903,302	)		(274,739	)
Unrecognized prior service cost		(34,259	)		(38,958	)
Unrecognized net actuarial gain		(129,739	)		(850,224	)
Net amount accrued		($782,753	)		($844,997	)

Accrued pension cost							$	(4,903,302	)	$	(274,739	)


Assumptions:
Discount rate		5.25	%		5.50	%		5.25	%		5.50	%
Rate of compensation increase		4.00	%		4.00	%
Expected return on plan assets		6.00	%		7.88	%		6.00	%		6.00	%

The Company reviewed the assumptions used for the discount rate to calculate the benefit obligation of the plan ~~were reviewed by the Company~~ and ~~lowered from 5.5 percent to~~has elected a rate of 5.25 percent in 2008, reflecting a reduction of 25 basis points in the interest rates of ~~high quality~~high-quality bonds in 2008, and reflecting the expected life of the plan, ~~due to~~in light of the ~~lump sum payment~~lump-sum-payment option. ~~Additionally,~~In addition, the average expected return on plan assets for the ~~qualified plan was lowered from 7.88 percent to 6~~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. ~~There was no change in~~Since the Plan is frozen with respect to additional years of service and compensation, the rate of assumed compensation rate ~~increases.~~increases is not applicable. The accumulated benefit obligation was ~~$12.4~~$11.6 million and ~~$12.1~~$11.1 million at December 31, ~~2005~~2008 and ~~2004,~~2007, respectively.

- Page ~~58 -~~84 Chesapeake Utilities Corporation 2008 Form 10-K

Net periodic pension ~~costs~~benefit for the ~~defined benefit~~Defined Pension Plan for ~~2005, 2004~~2008, 2007, and ~~2003~~2006 include the components as shown below:


For the Years Ended December 31,	2008			2007			2006
Components of net periodic pension cost:
Interest cost	$	593,723		$	622,057		$	635,877
Expected return on assets		(629,432	)		(696,398	)		(690,533	)
Amortization of prior service cost		(4,699	)		(4,699	)		(4,699	)

Net periodic pension benefit	$	(40,408	)	$	(79,040	)	$	(59,355	)


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

For the Years Ended December 31,

2005

2004

2003

Components of net periodic pension cost:

Service cost
$
0
$ 338,352 $ 325,366
Interest cost
645,740
690,620 684,239
Expected return on assets
(703,285
)
(869,336 ) (784,476 )
Amortization of:
Transition assets
-
(11,328 ) (15,104 )
Prior service cost
(4,699
)
(4,699 ) (4,699 )
Net periodic pension cost (benefit)

($62,244
)
$ 143,609 $ 205,326

Pension Supplemental Executive Retirement Plan

~~The following actuarial assumptions were used in calculating net periodic pension cost or benefit.~~

For the Years Ended December 31,

2005

2004

2003

Assumptions:

Discount rate
5.50
%
5.88 % 6.50 %
Rate of compensation increase
4.00
%
4.00 % 4.50 %
Expected return on plan assets
6.00
%
7.88 % 8.50 %

~~Executive Excess Defined Benefit Pension Plan~~

~~The Company also sponsors an unfunded executive excess defined benefit pension plan.~~ As ~~noted above,~~previously described, 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 for the Pension SERP, which is unfunded, was ~~$2.3~~$2.5 million and ~~$2.2~~$2.3 million at December 31, ~~2005~~2008 and ~~2004,~~2007, respectively. ~~Accrued pension costs at December 31, 2005 include $959,000 related to a minimum pension liability. The minimum pension liability is a component of other comprehensive income.~~

~~Net periodic pension costs for the executive excess benefit pension plan for 2005, 2004 and 2003 include the components as shown below:~~

For the Years Ended December 31,

2005

2004

2003

Components of net periodic pension cost:

Service cost
$
0
$ 105,913 $ 107,877
Interest cost
119,658
87,568 80,039
Amortization of:
Prior service cost
-
2,090 2,787
Actuarial loss
49,319
21,699 18,677
Net periodic pension cost

$
168,977
$ 217,270 $ 209,380

~~- Page 59 -~~

The following schedule sets forth the status of the ~~executive excess benefit plan:~~

Pension SERP:


At December 31,	2005			2004			2008			2007
Change in benefit obligation:
Benefit obligation — beginning of year	$	2,162,952		$	1,406,190		$	2,326,250		$	2,286,970
Service cost		-			105,913
Interest cost		119,658			87,568			124,771			123,361
Actuarial loss		133,839			713,225
Actuarial (gain) loss								39,227			5,123
Amendments		-			60,000			118,580			—
Effect of curtailment/settlement		-			(184,844	)
Benefits paid		(93,978	)		(25,100	)		(89,204	)		(89,204	)

Benefit obligation — end of year		2,322,471			2,162,952			2,519,624			2,326,250


Change in plan assets:
Fair value of plan assets — beginning of year		-			-			—			—
Employer contributions		93,978			25,100			89,204			89,204
Benefits paid		(93,978	)		(25,100	)		(89,204	)		(89,204	)

Fair value of plan assets — end of year		-			-			—			—


Reconciliation:
Funded status		(2,322,471	)		(2,162,952	)		(2,519,624	)		(2,326,250	)
Unrecognized net actuarial loss		959,492			874,972
Net amount accrued		($1,362,979	)		($1,287,980	)

Accrued pension costs							$	(2,519,624	)	$	(2,326,250	)


Assumptions:
Discount rate		5.25	%		5.50	%		5.25	%		5.50	%
Rate of compensation increase		4.00	%		4.00	%

The Company reviewed the assumptions used for the discount rate of the plan ~~were reviewed by~~to calculate the ~~Company~~benefit obligation and ~~lowered from 5.5 percent to~~has elected a rate of 5.25 percent, reflecting a reduction of 25 basis points in the interest rates of ~~high quality~~high-quality bonds in 2008 and a reduction in the expected life of the plan. ~~There was no change~~Since the Plan is frozen in regard to additional years of service and compensation, the rate of assumed ~~pay rate increases.~~pay-rate increases is not applicable. The measurement dates for the ~~executive excess benefit plan~~Pension SERP were December 31, ~~2005~~2008 and ~~2004, respectively.~~2007.

Chesapeake Utilities Corporation 2008 Form 10-K Page 85

Notes to the Consolidated Financial Statements

Net periodic pension costs for the Pension SERP for 2008, 2007, and 2006 include the components shown below:

For the Years Ended December 31, 2008 2007 2006
Components of net periodic pension cost:

Interest cost $ 124,771 $ 123,361 $ 119,588
Amortization of actuarial loss 45,416 51,734 57,039

Net periodic pension cost
$ 170,187 $ 175,095 $ 176,627

Assumptions:

Discount rate 5.50 % 5.50 % 5.25 %

Other ~~Post-Retirement~~Postretirement Benefits

The Company sponsors ~~a defined benefit post-retirement~~an unfunded postretirement health care and life insurance plan that covers substantially all employees.

~~Net periodic post-retirement costs for 2005, 2004 and 2003 include the following components:~~

For the Years Ended December 31,

2005

2004

2003

Components of net periodic post-retirement cost:

Service cost
$
6,257
$ 5,354 $ 5,138
Interest cost
77,872
86,883 85,319
Amortization of:
Transition obligation
27,859
27,859 27,859
Actuarial loss
88,291
78,900 66,271
Net periodic post-retirement cost

$
200,279
$ 198,996 $ 184,587

~~- Page 60 -~~

The following schedule sets forth the status of the ~~post-retirement~~postretirement health care and life insurance plan:


At December 31,	2008			2007
Change in benefit obligation:
Benefit obligation — beginning of year	$	1,755,564		$	1,763,108
Retirees		551,684			56,123
Fully-eligible active employees		(19,329	)		21,012
Other active		(109,852	)		(84,679	)

Benefit obligation — end of year	$	2,178,067		$	1,755,564


Change in plan assets:
Fair value of plan assets — beginnning of year		—			—
Employer contributions		39,598			243,660
Plan participant’s contributions		103,572			100,863
Benefits paid		(143,170	)		(344,523	)

Fair value of plan assets — end of year		—			—


Reconciliation:
Funded status	$	(2,178,067	)	$	(1,755,564	)

Accrued OPRB costs	$	(2,178,067	)	$	(1,755,564	)


Assumptions:
Discount rate		5.25	%		5.50	%

Net periodic postretirement costs for 2008, 2007, and 2006 include the following components:

At December 31,

2005

2004

Change in benefit obligation:

Benefit obligation — beginning of year
$
1,599,280
$ 1,471,664
Retirees
(59,152
)
91,747
Fully-eligible active employees
(31,761
)
22,071
Other active
26,317
13,798
Benefit obligation — end of year
$
1,534,684
$ 1,599,280

Funded status
($1,534,684
)
($1,599,280 )
Unrecognized transition obligation
22,282
50,141
Unrecognized net actuarial loss
751,450
899,228
Net amount accrued

($760,952
)
($649,911 )

Assumptions:

Discount rate
5.25
%
5.50 %


For the Years Ended December 31,	2008		2007		2006
Components of net periodic postretirement cost:
Service cost	$	2,826	$	6,203	$	9,194
Interest cost		114,282		101,776		93,924
Amortization of:
Transition obligation		—		—		22,282
Actuarial loss		289,838		166,423		144,694

Net periodic postretirement cost	$	406,946	$	274,402	$	270,094

The health care inflation rate for ~~2005~~2008 used to calculate the benefit obligation is assumed to be 8five percent for medical and 10six percent for prescription drugs. ~~These rates are projected to gradually decrease to ultimate rates of 5 and 6 percent, respectively, by the year 2009.~~ A ~~one percentage point~~one-percentage-point increase in the health care inflation rate from the assumed rate would increase the accumulated ~~post-retirement~~postretirement benefit obligation by approximately ~~$204,000~~$347,300 as of January 1, ~~2006,~~2009, and would increase the aggregate of the service cost and interest cost components of the net periodic ~~post-retirement~~postretirement benefit cost for ~~2006~~2009 by approximately ~~$13,000.~~$20,000. A ~~one percentage point~~one-percentage-point decrease in the health care inflation rate from the assumed rate would decrease the accumulated ~~post-retirement~~postretirement benefit obligation by approximately ~~$169,000~~$282,500 as of January 1, ~~2006,~~2009, and would decrease the aggregate of the service cost and interest cost components of the net periodic ~~post-retirement~~postretirement benefit cost for ~~2006~~2009 by approximately ~~$11,000.~~$16,000. The measurement dates were December 31, ~~2005~~2008 and ~~2004, respectively.~~2007.

Page 86 Chesapeake Utilities Corporation 2008 Form 10-K

Estimated Future Benefit Payments

The schedule below shows the estimated future benefit payments for each of the years ~~2006~~2009 through ~~2010~~2013 and the aggregate of the next five years for each of the plans previously described.


	Defined		Pension		Other Post-
	Benefit		Supplemental		Retirement
	Pension Plan⁽¹⁾		Executive Retirement⁽²⁾		Benefits⁽²⁾
2009	$	1,116,199	$	87,810	$	224,683
2010		936,064		805,978		237,850
2011		441,760		84,623		215,670
2012		1,351,260		82,833		226,548
2013		491,266		80,911		220,874
Years 2014 through 2018		3,643,521		585,796		1,201,769


⁽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.

In 2009, the Company expects to contribute $450,000 to the Defined Pension Plan and $87,810 to the Pension SERP and $224,683 to the Other Postretirement Benefit Plan for these two plans are unfunded.

Defined Benefit Pension Plan ⁽¹⁾

Executive Excess Defined Benefit Pension Plan ⁽²⁾

Other Post-Retirement Benefits ⁽²⁾

2006 $ 440,904 $ 89,204 $ 146,051
2007 713,051 88,490 152,321
2008 851,435 87,782 152,114
2009 1,431,421 87,080 155,098
2010 895,710 86,384 174,932
Years 2011 through 2015 4,089,216 692,464 987,030

⁽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 1580 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.

~~- Page 61 -~~

Effective January 1, 1999, the Company began offering an enhanced 401(k) ~~plan~~Plan to all new employees, as well as existing employees ~~that~~who elected to no longer participate in the ~~defined benefit plan.~~Defined Pension Plan. The Company makes matching contributions on ~~a basis of~~ up to six percent of each ~~employee's~~employee’s eligible pre-tax compensation for the ~~year.~~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 ~~a combination of~~ the employee’s age and years of service. The first 100 percent ~~of the funds are~~is matched with Chesapeake common ~~stock. The~~stock; the remaining match is invested in the Company’s 401(k) ~~plan~~Plan according to each employee’s election options.

Effective July 1, 2006, the Company’s contribution made on behalf of the Advanced Information Services segment employees, is a 50 percent matching contribution, on 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 the segment’s 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”).~~Plan.

Chesapeake Utilities Corporation 2008 Form 10-K Page 87

Notes to the Consolidated Financial Statements

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 a ~~cash only~~cash-only matching contribution percentage equivalent to their 401(k) match level. All contributions and matched funds ~~earn interest income monthly.~~

can be invested among the 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 for the 401(k) SERP. As discussed further in Note F — “Investments,” to the Consolidated Financial Statements, the assets held in the Rabbi Trust had a fair value of $1.6 million and $1.9 million at December 31, 2008 and 2007, 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 ~~$1,681,000, $1,497,000~~$1.55 million, $1.48 million, and ~~$1,444,000~~$1.61 million for the years ended December 31, ~~2005, 2004~~2008, 2007, and ~~2003,~~2006, respectively. As of December 31, ~~2005,~~2008, there are ~~111,738~~42,656 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’ retainer and fees. At December 31, 2008, 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 are paid in cash. All deferrals of executive performance shares and directors’ stock retainers are paid in shares of the Company’s common stock, except that cash shall be paid in lieu of fractional shares.

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 $1.5 million and $1.4 million at December 31, 2008 and 2007, respectively.

~~L. Executive Incentive~~M. Share-Based Compensation Plans

AThe Company accounts for its share-based compensation arrangements under SFAS No. 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 ~~Plan”) adopted~~amounts included in ~~1992 and amended in April 1998 allows~~net income related to share-based compensation expense, for the ~~granting of performance shares,~~restricted stock awards issued under the DSCP and the PIP.


For the year ended December 31,	2008		2007		2006
Directors Stock Compensation Plan	$	180,037	$	180,920	$	165,340
Performance Incentive Plan		640,138		809,030		544,450

Total compensation expense		820,175		989,950		709,790
Less: tax benefit		326,585		386,080		276,820

Amounts included in net income	$	493,590	$	603,870	$	432,970

Page 88 Chesapeake Utilities Corporation 2008 Form 10-K

Stock Options

The Company did not have any stock options outstanding at December 31, 2008 or December 31, 2007, nor were any stock options issued during 2008 and ~~stock appreciation rights to certain officers~~2007.

Directors Stock Compensation Plan

Under the DSCP, each non-employee director of the ~~Company.~~Company received in 2008 an annual retainer of 650 shares of common stock and additional shares of common stock to serve as a committee chairperson. For 2008, the Corporate Governance and Compensation Committee Chairperson each received 150 additional shares of common stock and the Audit Committee Chairperson received 250 additional shares of common stock. Shares granted under the DSCP are issued in advance of the directors’ service period; therefore, these shares are fully vested as of the date of the grant. The Company ~~now uses performance shares exclusively. All stock options granted in prior years were exercised~~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 stock activity under the DSCP is presented below:


			Weighted
	Number of		Average Grant
	Shares		Date Fair Value
Outstanding — December 31, 2006		—		—

Granted		5,850	$	31.38
Vested		5,850	$	31.38
Forfeited		—		—

Outstanding — December 31, 2007		—		—

Granted^(a)		6,161	$	29.43
Vested		6,161	$	29.43
Forfeited		—		—

Outstanding — December 31, 2008		—		—


(a)		On September 15, 2008, the Company added a new member to its Board of Directors. The number of shares issued to this Director for her annual retainer was prorated.

Compensation expense related to DSCP awards recorded by the Company for the years 2008, 2007, and 2006 is presented in the following table:


For the year ended December 31,	2008		2007		2006

Compensation expense for DSCP	$	180,037	$	180,920	$	165,340

The weighted-average grant-date fair value of DSCP awards granted during fiscal 2008 and 2007 was $29.43 and $31.38, respectively, per share. The intrinsic values of the DSCP awards are equal to the fair market value of these awards on the date of grant. At December 31, ~~2005 and all stock appreciation rights (“SARs”) were exercised prior to December 31, 2003.~~

~~The Plan enables participants the right to earn performance shares upon the Company’s achievement~~2008, there was $62,470 of ~~certain performance goals, as set forth in the specific agreements, and the individual’s achievement of goals set annually for each executive. The Company recorded~~unrecognized compensation expense related to DSCP awards that is expected to be recognized over the first four months of ~~$701,000, $490,000 and $726,000 associated with these performance shares in 2005, 2004 and 2003, respectively.~~

In 1997, the Company executed Stock Option Agreements for a three-year performance period ending December 31, 2000, with certain executive officers. One-half of these options became exercisable over time and the other half became exercisable if certain performance targets were achieved. SFAS No. 123 requires the disclosure of pro forma net income and earnings per share as if fair value based accounting had been used to account for the stock-based compensation costs. The assumptions used in calculating the pro forma information were: dividend yield, 4.73 percent; expected volatility, 15.53 percent; risk-free interest rate, 5.89 percent; and an expected life of four years. No options have been granted since 1997; therefore, there is no pro forma impact for 2005, 2004 or 2003. The weighted average exercise price of outstanding options was $20.50 for all years presented. All outstanding options were exercised as of December 31, 2005.

~~Changes in outstanding options are shown on the chart below:~~

2005

2004

2003

Number of shares

Option Price

Number of shares

Option Price

Number of shares

Option Price

Balance — beginning of year
17,537

$
20.50
29,490 $ 20.50 41,948 $ 20.50
Options exercised
(17,537
)
$
20.50
(11,834 ) $ 20.50 (12,458 ) $ 20.50
Options forteited
-
(119 ) $ 20.50 -
Balance — end of year
-
17,537 $ 20.50 29,490 $ 20.50
Exercisable
-
17,537 $ 20.50 29,490 $ 20.50

~~- Page 62 -~~

In 2000, the Company replaced the third year of this Stock Option Agreement with Stock Appreciation Rights. The SARs were awarded based on performance with a minimum number of SARs established for each participant. During 2001 and 2000, the Company granted 10,650 and 13,150 SARs, respectively, in conjunction with the agreement. During 2003, all SARs were exercised.

2009.

As of December 31, ~~2005,~~2008, there were ~~293,481~~51,289 shares reserved for issuance under the terms of the Company’s DSCP.

Performance Incentive ~~Plan.~~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 granted under the PIP are subject to certain post-vesting transfer restrictions.

Chesapeake Utilities Corporation 2008 Form 10-K Page 89

Notes to the Consolidated Financial Statements

In 2006 and 2007, the Board of Directors granted each executive officer equity incentive awards, which entitled each to earn shares of common stock to the extent that pre-established performance goals were achieved by the Company at the end of a one-year performance period. For 2008, the Company adopted multi-year performance plans to be used in lieu of the one-year awards. Similar to the one-year plans, the multi-year plans will provide incentives based upon the achievement of long-term goals, development and success of the Company. The long-term goals have both market-based and performance-based conditions or targets.

The shares granted under the PIP in 2006 and 2007 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 the grant. The shares granted under the 2008 long-term plans are unvested at December 31, 2008, and the fair value of each performance-based condition or target is equal to the market price of the Company’s common stock on the date of the grant. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each market-based award granted.

A summary of stock activity under the PIP is presented below:


			Weighted
	Number of		Average Fair
	Shares		Value
Outstanding — December 31, 2006		31,140	$	31.00

Granted		33,760	$	29.90
Vested		12,544	$	31.00
Fortfeited		6,820	$	31.00
Expired		11,776	$	31.00

Outstanding — December 31, 2007		33,760	$	29.90

Granted		94,200	$	27.71
Vested		31,094	$	29.90
Fortfeited		—		—
Expired		2,666	$	29.90

Outstanding — December 31, 2008		94,200	$	27.71

For the years 2008 and 2007, the Company withheld shares with value equivalent to the employees’ minimum statutory obligation for the applicable income and other employment taxes, and remitted the cash to the appropriate taxing authorities with the executives receiving the net shares. The total number of shares withheld (12,511) for 2008 was based on the value of the PIP shares on their vesting date as determined by the average of the high and low of the Company’s stock price. The total number of shares withheld (2,420) for 2007 was based on the value of the PIP shares on their vesting date as determined by the closing price of the Company’s stock. Total payments for the employees’ tax obligations to the taxing authorities were approximately $382,650 and $69,200 in 2008 and 2007, respectively.

Compensation expense related to the PIP recorded by the Company during 2008, 2007, and 2006 is presented in the following table:


For the year ended December 31,	2008		2007		2006

Compensation expense for PIP	$	640,138	$	809,030	$	544,450

The weighted-average grant-date fair value of PIP awards granted during fiscal 2008, 2007 and 2006 was $27.71, $29.90 and $31.00, respectively, per share. The intrinsic value of the PIP awards was $1,080,161 for 2008. The intrinsic values of the 2007 and 2006 PIP awards are equal to the fair market value of these awards on the date of grant.

As of December 31, 2008, there were 371,293 shares reserved for issuance under the terms of the Company’s PIP.

Page 90 Chesapeake Utilities Corporation 2008 Form 10-K

M.N. 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 remedial work at one former gas manufacturing plant site and is currently participating~~has participated in the investigation, assessment or remediation, ~~of two other former gas manufacturing plant sites. These sites are located in three different jurisdictions. The Company~~and has accrued liabilities, ~~for~~at three former manufactured gas plant sites located in Delaware, Maryland and Florida, referred to, respectively, as the Dover Gas Light Site, the Salisbury Town Gas Light Site and the Winter Haven Coal Gas ~~sites.~~Site. The Company ~~is currently~~has also been in discussions with the Maryland Department of ~~the Environment~~Environmental (“MDE”) regarding ~~the possible responsibilities of the Company with respect to~~ a fourth former manufactured gas ~~manufacturing~~ plant site located in Cambridge, Maryland. The following discussion provides details on each site.

Dover Gas Light Site

The Dover Gas Light site is a former manufactured gas plant site located in Dover, Delaware. On January 15, 2004, the Company received a Certificate of Completion of Work from the United States ~~Environmental Protection Agency (“EPA”)~~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,~~there, or information previously unknown to the EPA is received which indicates that ~~indicates~~ the remedial action that has been taken is not sufficiently protective. These contingencies are standard and are required by the ~~United States~~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.~~paid and recovered through rates or other parties. The Company does not expect any future environmental ~~expenditures~~expenditure for this site. ~~Through December 31, 2005,~~On February 5, 2008, the ~~Company has incurred approximately $9.7 million~~Delaware PSC granted final approval to cease the recovery of environmental costs through the Company’s Environmental Rider recovery mechanism, effective November 30, 2008. Any residual balance shall be included in ~~costs related to environmental testing and remedial action studies at~~ the site. Approximately $9.9 million has been recovered through December 2005 from other parties or through rates. As of December 31, 2005, a regulatory liability of approximately $298,000, representing the over-recovery portion of the clean-up costs, has been recorded. The over-recovery is temporary and will be refunded by the Company to customers in future rates.Company’s Gas Sales Service Rate application.

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~~of an Air Sparging and Soil-Vapor Extraction (“AS/SVE”) system and began remediation procedures. Chesapeake has ~~been reporting~~reported the remediation and monitoring results to the MDE on an ongoing basis since 1996. In February 2002, the MDE granted permission to decommission permanently ~~decommission~~ the AS/SVE system and to discontinue all on-site and off-site well monitoring, except for one well ~~that~~which is being maintained for continued product monitoring and recovery. ~~In November 2002,~~ Chesapeake ~~submitted~~has requested and is awaiting a ~~letter to the MDE requesting~~ No Further Action ~~(“NFA”) determination. The Company has been in discussions with the MDE regarding such request and is waiting on a~~ determination from the MDE.

~~- Page 63 -~~

The Company has adjusted the liability with respect to the Salisbury Town Gas Light site to $2,300 at December 31, 2005. This amount is based on the estimated costs to perform limited product monitoring and recovery efforts and fulfill ongoing reporting requirements. A corresponding regulatory asset has been recorded, reflecting the Company’s belief that costs incurred will be recoverable in base rates.

Through December 31, ~~2005,~~2008, the Company has incurred and paid approximately $2.9 million for remedial actions and environmental studies at the Salisbury Town Gas Light site. Of this amount, approximately ~~$1.8~~$2.03 million has been recovered through insurance proceeds or in rates. ~~The~~On September 26, 2006, the Company ~~expects~~received approval from the Maryland PSC to recover, through its rates charged to customers, $1.16 million of environmental remediation costs incurred as of that date. As of December 31, 2008, a regulatory asset of approximately $899,000 has been recorded to represent the ~~remaining~~portion of the clean-up costs ~~through rates.~~not yet recovered.

Winter Haven Coal Gas Site

The Winter Haven Coal Gas site is located in Winter Haven, Florida. Chesapeake has been working with the Florida Department of Environmental Protection (“FDEP”) in assessing this coal gas site. In May 1996, the Company filed with the FDEP an ~~Air Sparging and Soil Vapor Extraction~~AS/SVE Pilot Study Work Plan (the “Work Plan”) for the Winter Haven ~~site with the FDEP. The Work Plan described the Company’s proposal to undertake an AS/SVE pilot study to evaluate the~~Coal Gas site. After discussions with the FDEP, the Company filed a modified ~~AS/SVE Pilot Study~~ Work Plan, ~~the~~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 ~~AS/SVE Pilot Study~~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 ~~is now~~remains fully operational.

Chesapeake Utilities Corporation 2008 Form 10-K Page 91

Notes to the Consolidated Financial Statements

Through December 31, 2008, the Company has incurred approximately $1.8 million of environmental costs associated with this site. At December 31, 2008, the Company had recorded a liability associated with this site of $511,000, which partially offsetting (a) approximately $268,000 collected through rates in excess of costs incurred and (b) a regulatory asset of $779,000, representing the uncollected portion of the estimated clean-up costs related to this site.

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. ~~Early~~The Company’s early estimates ~~by the Company’s environmental consultant~~ 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~~intends to ~~vigorously~~ oppose any ~~requirements~~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.

The Company has accrued a liability of $350,000 as of December 31, 2005 for the Winter Haven site. Through December 31, 2005, the Company has incurred approximately $1.5 million of environmental costs associated with the Winter Haven site. At December 31, 2005 the Company had collected through rates $158,000 in excess of costs incurred. A regulatory asset of approximately $193,000, representing the uncollected portion of the estimated clean-up costs, has also been recorded. The Company expects to recover the remaining costs through rates.

Other

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

N.O. Other Commitments and Contingencies

~~Application of Florida Gross Receipts Tax~~

Rates and Other Regulatory Activities

The ~~Company provides~~Company’s natural gas ~~supply~~distribution operations in Delaware, Maryland and ~~management services through its affiliate, Peninsula Energy Services~~Florida are subject to regulation by their respective PSCs; ESNG, the Company’s natural gas transmission operation, is subject to regulation by the FERC.

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

Page 92 Chesapeake Utilities Corporation 2008 Form 10-K

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

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

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

On September 29, 2008, the Delaware division filed an application with the Delaware PSC, requesting approval for the issuance of $10,000,000 of debt securities. The PSC granted approval of the issuance at its regularly scheduled meeting on October 23, 2008.

On December 2, 2008, the Delaware division filed two applications with the Delaware PSC requesting approval for a Town of Milton Franchise Fee Rider and a City of Seaford Franchise Fee Rider. These Riders will allow the division to charge all natural gas ~~purchased~~customers within the respective town and city limits the franchise fee paid by ~~PESCO’s customers is sold~~the division to the ~~customers at~~Town of Milton and City of Seaford as a condition to providing natural gas service. The PSC granted approval of both Franchise Fee Riders on January 29, 2009.

Maryland. On September 26, 2006, the Maryland PSC approved a base rate increase for the Maryland division based on an annual cost of service increase of approximately $780,000. As part of a settlement agreement in that proceeding, however, the division was required to file a depreciation study, and it did so on April 9, 2007. The division then filed formal testimony on July 10, 2007, initiating a Phase II of this proceeding and proposing a rate decrease of approximately $80,000 annually, based on lower depreciation expense. On November 29, 2007, the PSC approved a settlement agreement for a rate decrease of $132,155 based on the Company’s revised approved depreciation rates, effective December 1, 2007. Under the settlement, the division reduced its depreciation expense by approximately $119,000 and its asset removal costs by approximately $167,000. The difference between the decrease in depreciation expense and the decrease in delivery ~~points located outside~~service rates is due to an increase in rate case expense amortization and an increase in rates to offset the ~~State~~loss of ~~Florida and because title~~margin from a large customer in Maryland.

Chesapeake Utilities Corporation 2008 Form 10-K Page 93

Notes to the Consolidated Financial Statements

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

On December 16, 2008, 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, 2008. No issues were raised at the hearing, and on December 19, 2008, the Hearing Examiner in this proceeding issued a proposed Order approving the division’s four quarterly gas cost recovery filings, which became a final Order of the Maryland PSC on January 21, 2009.

Florida. In compliance with state law, the Florida ~~PESCO does not collect gross receipts taxes~~division filed its 2007 Depreciation Study (“Study”) with the Florida PSC on May 17, 2007. This Study, which superseded the last study performed in 2002, provided the PSC the opportunity to review and address changes in plant and equipment lives, salvage values, reserves and resulting life depreciation rates. The division responded to interrogatories regarding the Study on October 15, 2007, December 24, 2007, and February 7, 2008. Based on the recommendation issued by the PSC Staff, the Commission, at its May 20, 2008 agenda conference, approved certain revisions to the division’s utility plant remaining lives, net salvage values, depreciation reserves, and depreciation rates, effective January 1, 2008. The Florida PSC issued an order on June 27, 2008, which closed this docket.

On August 15, 2008, the Company filed with the Florida PSC a petition seeking a permanent waiver of certain aspects of meter-reading rules that could prevent the Company and its customers from realizing fully the accuracy and efficiency benefits of automatic meter-reading equipment, which enables the Company to take daily meter readings remotely for every customer. Existing Commission rules, established well before automatic meter-reading technology existed, can be read to require a monthly visit to each customer to take a reading from a meter located on the customer’s premises. The Commission, at its ~~customers.~~October 14, 2008 Agenda Conference, approved the Company’s petition, with a minor modification requiring the Company to read all meters physically once each year. The Florida PSC issued an order on November 3, 2008 confirming its approval and a consummating order on December 2, 2008, which closed this docket.

On August 18, 2008, the Company filed with the Florida PSC a petition seeking recovery of costs incurred to implement Phase 2 of its experimental Transitional Transportation Service program. The Company ~~understands~~incurred certain incremental, non-recurring costs from May 2007 through June 2008 ($77,980) and is projecting that it will incur additional non-recurring expenses through May 2009 ($100,000) for a total of approximately $177,980. The Company is seeking recovery of these expenses, plus applicable Regulatory Assessment Fees and interest, through a fixed monthly surcharge from the two approved Transitional Transportation Service Shippers on the Company’s system. The Florida ~~Department~~PSC approved the Company’s petition at its October 14, 2008 Agenda Conference. The PSC issued an order on November 3, 2008, and a consummating order on November 26, 2008, which closed this docket.

ESNG. ESNG had the following regulatory activity with the FERC regarding the expansion of ~~Revenue has alleged that other companies~~its transmission system:

System Expansion 2006 — 2008. On November 15, 2007, ESNG requested FERC authorization to commence construction of facilities (approximately nine miles) included in the third phase of the 2006-08 System Expansion. The FERC granted this authorization on January 7, 2008. Construction began in January 2008, and the facilities were completed and have been placed in service. The 2008 facilities provide 5,650 Dts of additional firm service capacity per day and an annualized gross margin contribution of approximately $988,000. ESNG has until June 2009 to construct the remaining facilities that were included in the 2006-08 System Expansion filing with the FERC, that will provide for the remaining 7,200 Dts of additional firm service capacity approved by the FERC, and which will permit ESNG to earn additional annualized gross margin of approximately $1. million.

Page 94 Chesapeake Utilities Corporation 2008 Form 10-K

E3 Project.In 2006, ESNG proposed to develop, construct and operate approximately 75 miles of new pipeline facilities to transport natural gas ~~marketing industry should have collected the gross receipts tax~~ from the ~~purchasers~~existing Cove Point Liquefied Natural Gas terminal located in Calvert County, Maryland, crossing under the Chesapeake Bay into Dorchester and Caroline Counties, Maryland, to points on the Delmarva Peninsula, where such facilities would interconnect with ESNG’s existing facilities in Sussex County, Delaware.

On May 31, 2006, ESNG entered into Precedent Agreements (the “Precedent Agreements”) with Delmarva Power & Light Co. and Chesapeake, through its Delaware and Maryland divisions, to provide additional firm transportation services upon completion of the ~~gas under similar circumstances. On June 8, 2005, new legislation was enacted that establishes the responsibilities of regulated utilities, including~~E3 Project. Both Chesapeake ~~(d/b/a/ Central Florida Gas), as well as unregulated~~and Delmarva Power & Light Co. are parties to existing firm natural gas ~~marketers, such~~transportation service agreements with ESNG, and each desired additional firm transportation service under the E3 Project, as ~~PESCO,~~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 ESNG to provide, and for Chesapeake and Delmarva Power & Light Co. to utilize, additional firm transportation service under the E3 Project.

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

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

On April 23, 2007, ESNG submitted to the FERC its request to commence a pre-filing process, and on May 15, 2007, the FERC notified ESNG that its request had been approved. The pre-filing process was intended to engage all interested and affected stakeholders early in the process with the intention of resolving all environmental issues prior to the formal certificate application being filed. As part of this process, ESNG performed environmental, engineering and cultural surveys and studies in the interest of protecting the environment, minimizing any potential impacts to landowners, and cultural resources. ESNG 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, ESNG received additional construction cost estimates for the ~~collection~~E3 Project, which indicated substantially higher costs than previously estimated. In an effort to optimize the feasibility of the ~~gross receipts tax. The law~~overall project development plan, ESNG explored all potential construction methods, construction cost mitigation strategies, potential design changes and project schedule changes. ESNG also ~~contains amnesty provisions~~held discussions and meetings with several potential new customers, who expressed interest in the E3 Project, but elected not to participate.

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

If ESNG decides to abandon the E3 Project, it will initiate billing of a pre-certification costs surcharge in accordance with the terms of the above described Precedent Agreements and Letter Agreements executed with two of its customers, which provide for these customers to reimburse ESNG for pre-certification costs incurred in connection with the E3 Project, up to a maximum amount of $2.0 million each, with interest, over a period of 20 years. As of December 31, 2008, ESNG had incurred $3.17 million of pre-certification costs relating to the ~~failure~~E3 Project.

Chesapeake Utilities Corporation 2008 Form 10-K Page 95

Notes to ~~collect gross receipts taxes~~the Consolidated Financial Statements

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

Natural Gas Act Section 4 General Rate Proceeding. On June 6, 2007, ESNG and interested parties reached a settlement agreement in principle on ~~sales made prior~~its base rate proceeding filed with the FERC on October 31, 2006. The negotiated settlement provided for an annual cost of service of $21,536,000, which reflected a pretax rate of return of 13.6 percent and a rate increase of approximately $1.07 million on an annual basis. On September 10, 2007, ESNG submitted its Settlement Offer to the Presiding Administrative Law Judge (“ALJ”) for review and certification to the full Commission.

ESNG 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 FERC issued an order on September 25, 2007, authorizing ESNG 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 FERC Order approving the settlement was issued on January 31, 2008. In compliance with the Settlement Agreement, refunds, inclusive of interest, totaling $1.26 million, based on the higher interim rates that were effective for the period from May 15, 2007 through August 31, 2007, were distributed to ESNG’s customers on February 1, ~~2006. While~~2008.

Interruptible Revenue Sharing. On May 15, 2008, ESNG submitted its annual Interruptible Revenue Sharing Report to the ~~Company does not believe~~FERC. In this filing, ESNG reported that, since its interruptible service revenue exceeded its annual threshold amount, it ~~has any liability, it has prepared~~refunded a total of $63,675 in the ~~required amnesty documents~~second quarter of 2008 to beits eligible firm service customers in accordance with the terms of its tariff and the rate case Settlement Agreement described above.

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

Prior Notice Activity — Blanket Certificate Authority. On July 2, 2008, ESNG submitted to the ~~Department~~FERC a Prior Notice filing under its Blanket Certificate Authority to add a new delivery point to serve an industrial customer located in Seaford, Delaware. In accordance with FERC regulations, a Prior Notice filing requires a 60-day window for protests. No protests were received, and ESNG was authorized to construct and operate the new delivery point. In mid-October and prior to the commencement of ~~Revenue~~any construction, the customer notified ESNG that, based on adverse developments affecting the market for ~~both Chesapeake and PESCO during~~its products, it did not require the ~~fourth quarter~~new delivery point. Pursuant to a pre-construction contract between the parties, the customer reimbursed ESNG a total of 2005. The Company received a conditional approval of its amnesty documents from the Florida Department of Revenue in a letter dated October 18, 2005. This conditional approval is stated in the Company’s amnesty application and is expressly conditioned on those facts being accurate.$500,000 for pre-construction costs incurred by ESNG as it pursued this project.

~~- Page 64 -~~

Natural Gas and Propane Supply

The Company’s natural gas and propane distribution operations have entered into contractual commitments ~~for~~to purchase gas from various suppliers. The contracts have various expiration dates. In ~~November 2004,~~March 2008, the Company renewed its contract with an energy marketing and risk management company to manage a portion of the Company’s natural gas transportation and storage capacity. ~~The~~This contract expires on March 31, ~~2007.~~2009. PESCO is currently in the process of obtaining and reviewing proposals from suppliers and anticipates executing agreements before the existing agreements expire in May 2009.

Page 96 Chesapeake Utilities Corporation 2008 Form 10-K

Corporate Guarantees

The Company has issued corporate guarantees to certain vendors of its subsidiaries, the largest portion of which are for the Company’s propane wholesale marketing subsidiary ~~advanced information services subsidiary,~~ and its ~~Florida~~ natural gas supply ~~and~~ management ~~services~~ subsidiary. ~~The~~These corporate guarantees provide for the payment of propane and natural gas purchases ~~and office rent~~ in the event of the respective subsidiary’s default. None of these subsidiaries has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in the Consolidated Financial Statements when incurred. The aggregate amount ~~of the obligations~~ guaranteed at December 31, ~~2005 totaled $11.2~~2008 was $22.2 million, with the guarantees expiring on various dates in ~~2006. All payables of~~2009.

In addition to the ~~subsidiaries are recorded in~~corporate guarantees, the ~~Consolidated Financial Statements.~~

~~The~~ Company has issued a letter of credit to its primary insurance company for ~~$694,000,~~$775,000, which expires ~~June 1, 2006.~~on May 31, 2009. The letter of credit ~~was~~is provided as security ~~for claims amounts below~~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, 2008.

Internal Revenue Service Examination

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

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

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 proceedings 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.

Chesapeake Utilities Corporation 2008 Form 10-K Page 97

~~- Page 65 -~~

Notes to the Consolidated Financial Statements

O.P. Quarterly Financial Data (Unaudited) ~~(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.~~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
2008
Operating Revenue	$	100,273,502	$	69,056,959	$	49,698,013		$	72,415,004
Operating Income	$	14,040,715	$	4,329,439	$	1,170,393		$	8,938,386
Net Income (Loss)	$	7,574,343	$	1,818,924	$	(198,298	)	$	4,412,291
Earnings per share:
Basic	$	1.11	$	0.27	$	(0.03	)	$	0.65
Diluted	$	1.10	$	0.27	$	(0.03	)	$	0.64

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

Page 98 Chesapeake Utilities Corporation 2008 Form 10-K

For the Quarters Ended

March 31

June 30

September 30

December 31

2005

Operating Revenue
$
77,845,248

$
42,220,377

$
35,155,121

$
74,408,990

Operating Income
11,504,343

2,324,945

(99,149
)

7,800,360

Net Income (Loss)
From continuing operations
$
6,232,796

$
795,924

($693,774
)
$
4,132,668

Net Income (Loss)
$
6,232,796

$
795,924

($693,774
)
$
4,132,668

Earnings per share:
Basic
From continuing operations
$
1.08

$
0.14

($0.12
)
$
0.70

Net Income (Loss)
$
1.08

$
0.14

($0.12
)
$
0.70

Diluted
From continuing operations
$
1.05

$
0.14

($0.12
)
$
0.69

Net Income (Loss)
$
1.05

$
0.14

($0.12
)
$
0.69

2004

Operating Revenue $ 63,762,360 $ 34,292,972 $ 26,614,699 $ 53,285,410
Operating Income 10,699,307 2,162,794 282,738 6,824,907

Net Income (Loss)
From continuing operations $ 5,773,534 $ 611,518 ($584,171 ) $ 3,748,786
From discontinued operations (34,335 ) 19,148 (72,041 ) (33,672 )
Net Income (Loss) $ 5,739,199 $ 630,666 ($656,212 ) $ 3,715,114

Earnings per share:
Basic
From continuing operations $ 1.01 $ 0.11 ($0.10 ) $ 0.65
From discontinued operations - - (0.01 ) (0.01 )
Net Income (Loss) $ 1.01 $ 0.11 ($0.11 ) $ 0.64

Diluted
From continuing operations $ 0.99 $ 0.11 ($0.10 ) $ 0.64
From discontinued operations (0.01 ) - (0.01 ) (0.01 )
Net Income (Loss) $ 0.98 $ 0.11 ($0.11 ) $ 0.63

~~- Page 66 -~~

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

None.

~~None~~

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, ~~2005.~~2008. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, ~~2005.~~2008.

Changes in Internal Controls

~~During the fiscal quarter of the Company ended December 31, 2005, there was~~There has been no change in ~~the Company’s~~ internal control over financial reporting (as such term is defined in Exchange Act Rule 13a-15(f)) that ~~has~~occurred during the quarter ended December 31, 2008, that materially affected, or is reasonably likely to materially affect, ~~the Company’s~~ internal control over financial reporting.

CEO and CFO Certifications

The Company’s Chief Executive Officer and Chief Financial Officer have filed with the SEC 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, 2008. In addition, on May 20, 2008, the Company’s Chief Executive Officer certified to the NYSE 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.

Chesapeake Utilities Corporation 2008 Form 10-K Page 99

Report of Independent Registered Public Accounting Firm

~~See~~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, 2008, based on criteria established inInternal Control—Integrated Frameworkissued 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 ~~Item 8, “Financial Statements~~accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and ~~Supplemental Data.”~~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.

In our opinion, Chesapeake Utilities Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established inInternal Control—Integrated Frameworkissued 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 sheets of Chesapeake Utilities Corporation as of December 31, 2008 and 2007, and the related consolidated statements of income, stockholders’ equity, cash flows and income taxes for the years then ended, and our report dated March 9, 2009 expressed an unqualified opinion.

/s/ Beard Miller Company LLP
Beard Miller Company LLP
Reading, Pennsylvania
March 9, 2009

Page 100 Chesapeake Utilities Corporation 2008 Form 10-K

Item 9B. Other Information.

None

The Company filed a Current Report on Form 8-K, dated December 5, 2005, discussing the Compensation Committee's (the “Committee”) actions on November 30, 2005, including their approval of the compensation arrangements relating to the executive officers of the Company for 2006.

On November 30, 2005, the Committee approved awards under the Company’s Performance Incentive Plan to John R. Schimkaitis, President and Chief Executive Officer; Paul M. Barbas, Executive Vice President and Chief Operating Officer; and Michael P. McMasters, Senior Vice President and Chief Financial Officer. According to the terms of the awards, each executive officer is entitled to earn up to a specified number of shares of the Company’s common stock (“Contingent Performance Shares”) depending on the extent to which pre-established performance goals (the “Performance Goals”) are achieved during the year ended December 31, 2006 (the “2006 Award Year”). In addition, any Contingent Performance Shares that are not earned by the applicable executive officer during the 2006 Award Year may be earned in 2007 or 2008, if in either of those two succeeding years cumulative pre-established Performance Goals are achieved over, respectively, the three-year period ending in that year.

On November 30, 2005, the Compensation Committee also approved awards under the Company’s Performance Incentive Plan to (i) Stephen C. Thompson, Senior Vice President, and (ii) S. Robert Zola, President of Sharp Energy, Inc., a Company subsidiary, for the three-year period ending December 31, 2008. For a performance period beginning January 1, 2006 and ending December 31, 2006, each executive officer is entitled to earn, in the form of shares of restricted stock, up to 30 percent of the annual award of Contingent Performance Shares if the Company achieves certain Performance Goals. The second component consists of performance awards pursuant to which the remaining 70 percent of the annual award of Contingent Performance Shares will be earned, if certain Performance Goals for the three-year period ending December 31, 2008 for each of the respective business units for which they are individually responsible, are achieved.

~~- Page 67 -~~

Part III

Item 10. Directors, ~~and~~ Executive Officers of the ~~Registrant.~~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”~~Compliance,” to be filed not later than March 31, ~~2006~~2009, in connection with the Company’s Annual Meeting to be held on May ~~2, 2006.~~

6, 2009.

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 ~~Part I of~~ this ~~Form 10-K~~report following Item 4, as Item 4A, under the caption “Executive Officers of the ~~Registrant.~~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 ~~“Management Compensation”~~“Compensation Discussion and Analysis” in the Proxy Statement to be filed not later than March 31, ~~2006,~~2009, in connection with the Company’s Annual Meeting to be held on May ~~2, 2006.~~6, 2009.

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, ~~2006~~2009, in connection with the Company’s Annual Meeting to be held on May ~~2, 2006.~~6, 2009.

-Chesapeake Utilities Corporation 2008 Form 10-K Page ~~68 -~~101

The following table sets forth information, as of December 31, ~~2005,~~2008, with respect to compensation plans of Chesapeake and its subsidiaries, under which shares of Chesapeake common stock are authorized for issuance:

(c)

Number of securities

(a)

(b)

remaining available for future

Number of securities to

Weighted-average

issuance under equity

be issued upon exercise

exercise price

compensation plans

of outstanding options,

(excluding securities

warrants and rights

reflected in column (a))

Equity compensation plans approved by security holders

—

446,632

(1)

Equity compensation plans not approved by security holders

—

(2)

—

Total

—

446,632


(1)		Includes 371,293 shares under the 2005 Performance Incentive Plan, 51,289 shares available under the 2005 Directors Stock Compensation Plan, and 24,050 shares available under the 2005 Employee Stock Awards Plan.

(2)		All warrants were exercised in 2006.

(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 0
(1)
293,481 (2)
Equity compensation plans not approved by security holders 30,000 (3) $18.125 0
Total 30,000 $18.125 293,481

(1) All options to purchase shares under the 1992 Performance Incentive Plan, as amended, were exercised as of 12/31/05.
(2) Includes 293,481 shares under the 1992 Performance Incentive Plan.
(3) In 2000 and 2001, the Company entered into agreements with an investment banker to assist in identifying acquisition candiates. Under the agreements, the Company issued warrants to the investment banker to purchase 15,000 shares of Chesapeake stock in 2001 at a price of $18.25 per share and 15,000 shares in 2000 at a price of $18.00. The warrants are exercisable during a seven-year period after the date granted.

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

None

~~None~~

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 ~~PricewaterhouseCoopers LLP”~~the Independent Public Accounting Firm,” to be filed not later than March 31, ~~2006,~~2009, in connection with the Company’s Annual Meeting to be held on May ~~2, 2006.~~6, 2009.

Page 102 Chesapeake Utilities Corporation 2008 Form 10-K

~~- Page 69 -~~

Part IV

Item 15. Exhibits, Financial Statement Schedules.

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

1.~~Financial Statements:~~

o(a)

The following documents are filed as part of this report:

	1.		Financial Statements:

	•		Report of Independent Registered Public Accounting ~~Firm~~Firm;

o
	•		Consolidated Statements of Income for each of the three years ended December 31, ~~2005, 2004~~2008, 2007, and ~~2003~~2006;

o
	•		Consolidated Balance Sheets at December 31, ~~2005~~2008 and December 31, ~~2004~~2007;

o
	•		Consolidated Statements of Cash Flows for each of the three years ended December 31, ~~2005, 2004~~2008, 2007, and ~~2003~~2006;

o
	•		Consolidated Statements of ~~Common~~ Stockholders’ Equity for each of the three years ended December 31, ~~2005, 2004~~2008, 2007, and ~~2003~~2006;

o
	•		Consolidated Statements of Income Taxes for each of the three years ended December ~~31, 2005, 2004~~31,2008, 2007, and ~~2003~~2006;

o
	•	Notes to the Consolidated Financial ~~Statements~~Statements.

	2.	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

2.~~Financial Statement Schedules — 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.~~

~~(b)~~~~Reports on Form 8-K:~~

·	~~Sale~~
•		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 ~~LAMPS (Item 8.01)~~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.

·	~~Earnings press release dated November 4, 2004 (Items 2.02~~
•		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 ~~9.01)~~

·	~~Compensation Committee approval of Compensation Arrangements (Item 1.01)~~

·	~~Approval of Paul M. Barbas to Chief Operating Officer (Item 5.02)~~

~~(c)~~~~Exhibits:~~

~~Exhibit 3(a)~~ ~~Amended~~Restated Bylaws of Chesapeake Utilities Corporation, effective December 11, 2008, are filed herewith.

•

Exhibit 4.1Form 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 4.2Note 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 4.3Note 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.

Chesapeake Utilities Corporation ~~effective February 24, 2005, is incorporated herein by reference to Exhibit 3 of the Company’s Annual Report on~~2008 Form 10-K ~~for the year ended December 31, 2004, File No. 001-11590.~~Page 103


•	Exhibit 4.4	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 4.5	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 4.6	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 4.7	Note Agreement entered into by the Company on October 31, 2008, pursuant to which the Company, on October 31, 2008, privately placed $30 million of its 5.93% Senior Notes, due in 2023, with General American Life Insurance Company and New England Life Insurance Company, 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 4.8	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*	Chesapeake Utilities Corporation Deferred Compensation Plan, as amended and restated effective January 1, 2009, is filed herewith.

~~Exhibit 4(a)~~ 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(b)~~ 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(c)~~ 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(d)~~ 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 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.

- Page ~~70 -~~

~~Exhibit 4(e)~~ 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 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(f)~~ 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 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(g)~~ ~~Agreement in principle between Prudential Investment Management, Inc. and~~104 Chesapeake Utilities Corporation ~~related to the prospective purchase by Prudential of $20 million of 5.5% Senior Notes dated June 29, 2005, is incorporated herein by reference to Exhibit 4.1 of the Company’s Quarterly Report on~~2008 Form ~~10-Q for the period ended June 30, 2005, File No. 001-11590.~~10-K

~~Exhibit 4(h)~~ Note Agreement entered into by the Company on October 18, 2005, pursuant to which the Company, on or before December 28, 2006, will privately place $20 million of its 5.5% Senior Notes due 2020, is filed herewith as Exhibit 4.1.

*Exhibit 10(a) ~~Executive Employment Agreement dated January 1, 2006, by and between Sharp Energy, Inc. and S. Robert Zola, is filed herewith as Exhibit 10.1.~~

*Exhibit 10(b) ~~Form of Performance Share Agreement dated November 9, 2004,~~


•	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*	Amendment to Executive Employment Agreement, effective January 1, 2009, by and between Chesapeake Utilities Corporation and S. Robert Zola, is filed herewith.

•	Exhibit 10.8*	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 10.9*	Amendment to Executive Employment Agreement, effective January 1, 2009, by and between Chesapeake Utilities Corporation and Stephen C. Thompson, is filed herewith.

•	Exhibit 10.10*	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 10.11*	Amendment to Executive Employment Agreement, effective January 1, 2009, by and between Chesapeake Utilities Corporation and Beth W. Cooper, is filed herewith.

•	Exhibit 10.12*	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 10.13*	Amendment to Executive Employment Agreement, effective January 1, 2009, by and between Chesapeake Utilities Corporation and Michael P. McMasters, is filed herewith.

•	Exhibit 10.14*	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 10.15*	Amendment to Executive Employment Agreement, effective January 1, 2009, by and between Chesapeake Utilities Corporation and John R. Schimkaitis, is filed herewith.

•	Exhibit 10.16*	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, 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, 2007, File No. 001-11590.

•	Exhibit 10.17*	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 incorporated herein by reference to Exhibit 10.12 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.

•	Exhibit 10.18*	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 Michael P. McMasters, is incorporated herein by reference to Exhibit 10.13 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.

•	Exhibit 10.19*	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 Michael P. McMasters, is incorporated herein by reference to Exhibit 10.14 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.

Chesapeake Utilities Corporation 2008 Form 10-K Page 105


•	Exhibit 10.20*	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 Stephen C. Thompson, is incorporated herein by reference to Exhibit 10.15 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.

•	Exhibit 10.21*	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 Stephen C. Thompson, is incorporated herein by reference to Exhibit 10.16 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.

•	Exhibit 10.22*	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 Beth W. Cooper, is incorporated herein by reference to Exhibit 10.17 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.

•	Exhibit 10.23*	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 Beth W. Cooper, is incorporated herein by reference to Exhibit 10.18 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.

•	Exhibit 10.24*	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 S. Robert Zola, is incorporated herein by reference to Exhibit 10.19 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.

•	Exhibit 10.25*	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 S. Robert Zola, is incorporated herein by reference to Exhibit 10.20 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590.

•	Exhibit 10.26*	Form of Performance Share Agreement effective January 7, 2009, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and each of John R. Schimkaitis, Michael P. McMasters, Beth W. Cooper, and Stephen C. Thompson, is filed herewith.

•	Exhibit 10.27*	Chesapeake Utilities Corporation Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2009, is filed herewith.

•	Exhibit 10.28*	Chesapeake Utilities Corporation Supplemental Executive Retirement Savings Plan, as amended and restated effective January 1, 2009, is filed herewith.

•	Exhibit 12	Computation of Ratio of Earning to Fixed Charges is filed herewith.

Page 106 Chesapeake Utilities Corporation ~~and each of John R. Schimkaitis, Michael P. McMasters and Paul Barbas, is incorporated herein by reference to Exhibit 10.1 of the Company’s Annual Report on~~2008 Form 10-K ~~for the year ended December 31, 2004, File No. 001-11590.~~

*Exhibit 10(c) ~~Performance Share Agreement dated December 30, 2005,~~


•	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 21	Subsidiaries of the Registrant is filed herewith.

•	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 the year 2006 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 9, 2009, 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 9, 2009, 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 9, 2009, 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 9, 2009, is filed herewith.


*		Management contract or compensatory plan or agreement.

Chesapeake Utilities Corporation ~~Performance Incentive Plan by and between Chesapeake Utilities Corporation and each of John R. Schimkaitis, Paul M. Barbas and Michael P. McMasters, is filed herewith as Exhibit 10.2.~~

*Exhibit 10(d) Performance Share Agreement dated December 23, 2005, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Stephen C. Thompson, is filed herewith as Exhibit 10.3.

*Exhibit 10(e) Performance Share Agreement dated December 26, 2005, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and S. Robert Zola, is filed herewith as Exhibit 10.4.

*Exhibit 10(f) ~~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~~2008 Form 10-K ~~for the year ended December 31, 2004, File No. 001-11590.~~Page 107

*Exhibit 10(g) Signatures~~Executive Officer Compensation Arrangements, filed herewith as Exhibit 10.5.~~

*Exhibit 10(h) 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(i) 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(j) 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(k) Non-Employee Director Compensation Arrangements, incorporated herein by reference to Exhibit 10.5 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-11590.

~~- Page 71 -~~

~~Exhibit 12~~ ~~Computation of Ratio of Earning to Fixed Charges, filed herewith.~~

~~Exhibit 21~~ ~~Subsidiaries of the Registrant, filed herewith.~~

~~Exhibit 23~~ ~~Consent of Independent Registered Public Accounting Firm, filed herewith.~~

~~Exhibit 31.1~~ ~~Certificate of Chief Executive Office of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a), dated March 6, 2006, filed herewith.~~

~~Exhibit 31.2~~ ~~Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a), dated March 6, 2006, filed herewith.~~

~~Exhibit 32.1~~ ~~Certificate of Chief Executive Office of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated March 6, 2006, filed herewith.~~

~~Exhibit 32.2~~ ~~Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated March 6, 2006, filed herewith.~~

* Management contract or compensatory plan or agreement.

~~- Page 72 -~~

~~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 6, 2006~~


		Chesapeake Utilities Corporation

		By:		/s/ John R. Schimkaitis John R. Schimkaitis
				President and Chief Executive Officer

		Date:		March 9, 2009

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		/s/ John R. Schimkaitis John R. Schimkaitis, President,
and Director		Chief Executive Officer and Director
Date: ~~February 23, 2006~~March 9, 2009		Date: March ~~6, 2006~~9, 2009

~~/s/ Michael P. McMasters~~	~~/s/ Richard Bernstein~~
~~Michael P. McMasters,~~/s/ Beth W. Cooper		/s/ Eugene H. Bayard

Beth W. Cooper, Senior Vice President	~~Richard Bernstein,~~	Eugene H. Bayard, Director
and Chief Financial Officer		Date: February ~~23, 2006~~24, 2009
(Principal Financial and Accounting Officer)
Date: March ~~6, 2006~~9, 2009

/s/ Richard Bernstein		/s/ Thomas J. Bresnan	~~/s/ Walter J. Coleman~~

Richard Bernstein, Director		Thomas J. Bresnan, Director	~~Walter J. Coleman, Director~~
Date: ~~March 6, 2006~~February 24, 2009		Date: ~~February 23, 2006~~March 9, 2009

/s/ Thomas P. Hill, Jr.		/s/ J. Peter Martin

Thomas P. Hill, Jr., Director		J. Peter Martin, Director
Date: February 24, 2009		Date: February 24, 2009

/s/ Joseph E. Moore, ~~Esq.~~Esq		/s/ Calvert A. Morgan, Jr.
~~J. Peter Martin, Director~~
Joseph E. Moore, Esq., Director
~~Date: February 23, 2006~~	~~Date: February 23, 2006~~

~~/s/ Calvert A. Morgan, Jr.~~	~~/s/ Rudolph M. Peins, Jr.~~
Calvert A. Morgan, Jr., Director	~~Rudolph M. Peins, Jr., Director~~
Date: February ~~23, 2006~~24, 2009		Date: February ~~23, 2006~~24, 2009

/s/ ~~Robert~~Dianna F. ~~Rider~~Morgan Dianna F. Morgan, Director
~~Robert F. Rider, Director~~
Date: February ~~23, 2006~~24, 2009

Page 108 Chesapeake Utilities Corporation 2008 Form 10-K

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 9, 2009 relating to the consolidated financial statements of Chesapeake Utilities Corporation as of December 31, 2008 and 2007 and for the years then ended, which is contained in Item 8 of this Form 10-K also included the audits of the financial statement schedule listed in Item 15. This financial statement schedule is the responsibility of the Chesapeake Utilities Corporation’s management. Our responsibility is to express an opinion on this financial statement schedule based on our audits.

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

/s/ Beard Miller Company LLP
Beard Miller Company LLP
Reading, Pennsylvania
March 9, 2009

Chesapeake Utilities Corporation and Subsidiaries
Schedule II
Valuation and Qualifying Accounts

~~- Page 73 -~~


	Balance at		Additions
	Beginning of		Charged to		Other					Balance at End
For the Year Ended December 31,	Year		Income		Accounts⁽¹⁾		Deductions⁽²⁾			of Year
Reserve Deducted From Related Assets Reserve for Uncollectible Accounts

2008	$	952,075	$	1,185,906	$	241,153	$	(1,220,120	)	$	1,159,014


2007	$	661,597	$	818,561	$	26,190	$	(554,273	)	$	952,075


2006	$	861,378	$	381,424	$	65,519	$	(646,724	)	$	661,597


⁽¹⁾		Recoveries.

⁽²⁾		Uncollectible accounts charged off.

Upon written request,
Chesapeake will provide, free of
charge, a copy of any exhibit to
the 2008 Annual Report on
Form 10-K not included
in this document.

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

2005

$
610,819

$
632,645

$
158,408

$
(540,494
)
$
861,378

2004 $ 682,002 $ 505,595 $ 103,020 $ (679,798 ) $ 610,819
2003 $ 659,628 $ 660,390 $ 10,093 $ (648,109 ) $ 682,002

⁽¹⁾ Recoveries.

⁽²⁾ Uncollectible accounts charged off.

~~UNITED STATES~~
~~SECURITIES AND EXCHANGE COMMISSION~~ State of Delaware
~~Washington, D.C. 20549~~	51-0064146



~~FORM 10-K~~

~~ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF~~
~~THE SECURITIES EXCHANGE ACT OF 1934~~

~~For the Fiscal Year Ended: December 31, 2005 Commission File Number: 001-11590~~

~~Chesapeake Utilities Corporation~~
~~(Exact name of registrant as specified in its charter)~~

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

Title of each class		Name of each exchange on which registered

Common Stock -— par value per share $.4867		New York Stock Exchange, Inc.


Large accelerated filero		Accelerated filerþ		Non-accelerated filero		Smaller Reporting Companyo


BravePoint		BravePoint, Inc., a wholly-owned subsidiary of Chesapeake Services Company, which is a wholly-owned subsidiary of Chesapeake Utilities Corporation

Chesapeake		The Registrant, the Registrant and its subsidiaries, or the Registrant’s subsidiaries, as appropriate in the context of the disclosure

Company		The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries, as appropriate in the context of the disclosure

ESNG		Eastern Shore Natural Gas Company, a wholly-owned subsidiary of Chesapeake

OnSight		Chesapeake OnSight Services, LLC, a wholly-owned subsidiary of Chesapeake

PESCO		Peninsula Energy Services Company, Inc., a wholly-owned subsidiary of Chesapeake

PIPECO		Peninsula Pipeline Company, Inc., a wholly-owned subsidiary of Chesapeake

Sharp Energy		Sharp Energy, Inc., a wholly-owned subsidiary of Chesapeake Utilities Corporation

Sharpgas		Sharpgas, Inc., a wholly-owned subsidiary of Sharp Energy, Inc.

Skipjack		Skipjack, Inc., a wholly-owned subsidiary of Chesapeake Service Company, which is a wholly-owned subsidiary of Chesapeake Utilities Corporation

Tri-County		Tri-County Gas Co., Inc. a wholly-owned subsidiary of Sharp Energy

Xeron		Xeron, Inc., a wholly-owned subsidiary of Chesapeake

	~~Page~~
~~Part I~~	1
		Page
*Part I*			4

Item 1. Business	1		4

Item 1A. Risk Factors	8		12

Item 1B. Unresolved Staff Comments	11		19

Item 2. ~~Proprties~~Properties	11		19

Item 3. Legal Proceedings	11		20

Item 4. Submission of Matters to a Vote of Security Holders	11		20
~~Part II~~
12Item 4A. Executive Officers of the Registrant			20

*Part II*			22

Item 5. Market for the ~~Registrant's~~Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	12		22

Item 6. Selected Financial Data	14		25

Item 7. ~~Management's~~Management’s Discussion and Analysis of Financial Condition and Results of Operations	18		29

Item 7A. Quantitative and Qualitative Disclosures About Market Risk	36		56

Item 8. Financial Statements and ~~Supplemental~~Supplementary Data	36		56

Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	67		99

Item 9A. Controls and Procedures	67		99

Item 9B. Other Information	67		101

*Part III*	68		*101*

Item 10. Directors, ~~and~~ Executive Officers of the Registrant and Corporate Governanace	68		101

Item 11. Executive Compensation	68		101

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	68		101

Item 13. Certain Relationships and Related Transactions, and Director Independence	69		102

Item 14. Principal Accounting Fees and Services	69		102
~~Part IV~~	70
*Part IV*			*103*

Item 15. Exhibits, Financial Statement Schedules	70		103
~~Signatures~~
73Signatures			*108*

Exhibit 3.2
Exhibit 10.5
Exhibit 10.7
Exhibit 10.9
Exhibit 10.11
Exhibit 10.13
Exhibit 10.15
Exhibit 10.26
Exhibit 10.27
Exhibit 10.28
Exhibit 12
Exhibit 14.2
Exhibit 21
Exhibit 23.1
Exhibit 23.2
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2


APB		Accounting Principles Board

Delaware PSC		Delaware Public Service Commission

DOT		United States Department of Transportation

EPA		United States Environmental Protection Agency

FASB		Financial Accounting Standards Board

FERC		Federal Energy Regulatory Commission

FDEP		Florida Department of Environmental Protection

Florida PSC		Florida Public Service Commission

IRS		Internal Revenue Service

Maryland PSC		Maryland Public Service Commission

MDE		Maryland Department of Environment

SEC		Securities and Exchange Commission


AOCI		Accumulated Other Comprehensive Income

AS/SVE		Air Sparging and Soil/Vapor Extraction

CGS		Community Gas Systems

Columbia		Columbia Gas Transmission Corporation

DSCP		Directors Stock Compensation Plan

Dts		Dekatherms

E3 Project		ESNG Energylink Expansion Project

ER		Environmental rider

EITF		Financial Accounting Standards Board Emerging Issues Task Force

FIN		Financial Accounting Standards Board Interpretation Number

FSP		Financial Accounting Standards Board Staff Position

GAAP		Generally Accepted Accounting Principles

GSR		Gas sales service rates


Gulf		Columbia Gulf Transmission Company

Gulfstream		Gulfstream Natural Gas System, LLC

HDD		Heating degree-days

MMBtus		One million (1,000,000) British Thermal Units

NYSE		New York Stock Exchange

PIP		Performance Incentive Plan

S&P 500 Index		Standard & Poor’s 500

SFAS		Statement of Financial Accounting Standards


EITF 03-6-1		EITF 03-6-1, Determining Whether instruments Granted in Share-based Payment Transactions are Participating Securities

EITF 07-05		EITF 07-05, Determining Whether an Instrument (of an Embedded Feature) is Indexed to an Entity’s Own Stock

EITF 08-03		EITF 08-03, Accounting for Maintenance Deposits Under Lease Arrangements

EITF 08-05		EITF 08-05, Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement

FIN 39-1		FIN 39-1, a modification to FIN 39, Offsetting of Amounts Related to Certain Contracts

FIN 47		FIN 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143

FIN 48		FIN 48, Accounting for Uncertainty in Income Taxes, an interpretation of SFAS Statement No. 109

FSP APB 14-1		FSP APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlements)

FSP 142-3		FSP 142-3, Determining the Useful Life of Intangible Assets

FSP 157-3		FSP 157-3, Determining the Fair Value of a Financial Asset When the Market for that Asset is Not Active

SFAS No. 71		Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation

SFAS No. 87		Statement of Financial Accounting Standards No. 87, Employers’ Accounting for Pensions

SFAS No. 88		Statement of Financial Accounting Standards No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits

SFAS No. 106		Statement of Financial Accounting Standards No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions

SFAS No. 109		Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes

SFAS No. 112		Statement of Financial Accounting Standards No. 112, Employers’ Accounting for Postemployment Benefits

SFAS No. 115		Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities

SFAS No. 123		Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation

SFAS No. 123R		Statement of Financial Accounting Standards No. 123R, Share-Based Payment

SFAS No. 128		Statement of Financial Accounting Standards No. 128, Earnings Per Share

SFAS No. 132R		Statement of Financial Accounting Standards No. 132R, Employers’ Disclosures about Pensions and Other Postretirement Benefits

SFAS No. 133		Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities


SFAS No. 141R		Statement of Financial Accounting Standards No. 141R, Business Combinations

SFAS No. 142		Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets

SFAS No. 143		Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations

SFAS No. 157		Statement of Financial Accounting Standards No. 157, Fair Value Measurements

SFAS No. 158		Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an Amendment of SFAS Nos. 87, 88, 106, and 132R

SFAS No. 159		Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of SFAS No. 115

SFAS No. 160		Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of Accounting Research Bulletin 51

SFAS No. 161		Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS No. 133

SFAS No. 162		Statement of Financial Accounting Standards No. 162, The Hierarchy of Generally Accepted Accounting Principles


					Net Property, Plant
*(Thousands)*	Operating Income				& Equipment
Natural Gas	$	25,846	91	%	$	242,882	87	%
Propane		1,586	6	%		30,180	11	%
Advanced information services		695	2	%		915	<1	%
Other & eliminations		352	1	%		6,694	2	%

Total	$	28,479	100	%	$	280,671	100	%


	Operating Revenues				Deliveries
	(Thousands)				(MMcf’s)
Residential	$	47,994	53	%		2,590,425	39	%
Commercial		29,480	33	%		2,312,644	34	%
Industrial		2,130	2	%		812,224	12	%

Subtotal		79,604	88	%		5,715,293	85	%
Interruptible		9,041	10	%		1,035,540	15	%
Other ⁽¹⁾		1,934	2	%		—	—

Total	$	90,579	100	%		6,750,833	100	%


⁽¹⁾		Operating revenues from “Other” sources include unbilled revenue, rental of gas properties, and other miscellaneous charges.


	Firm transportation
	capacity maximum		Firm storage capacity
	peak-day daily		maximum peak-day
Pipeline	deliverability (Dts)		daily withdrawal (Dts)		Expiration
Transco		21,356		6,407	Various dates between 2012 and 2028
Columbia		3,460		8,224	Various dates between 2009 and 2020
Gulf		880		—	Expires in 2009
Eastern Shore		61,637		4,146	Various dates between 2009 and 2023


	Operating Revenues				Total Gallons Sold				Average No. of
	(Thousands)				(Thousands)				Customers
Delmarva	$	59,173	95	%		26,765	96	%		32,889	94	%
Florida		3,412	5	%		1,182	4	%		2,280	6	%

Total	$	62,585	100	%		27,947	100	%		35,169	100	%


Name	Age		Position
John R. Schimkaitis		61	President and Chief Executive Officer
Michael P. McMasters		50	Executive Vice President and Chief Operating Officer
Beth W. Cooper		42	Senior Vice President and Chief Financial Officer
Stephen C. Thompson		48	Senior Vice President and President, ESNG
S. Robert Zola		56	President, Sharp Energy


Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.


								Dividends
								Declared
Quarter Ended		High		Low		Close		Per Share
2008
	March 31	$	33.60	$	27.21	$	29.64	$	0.295
	June 30		31.88		25.02		25.72		0.305
	September 30		34.84		24.65		33.21		0.305
	December 31		34.66		21.93		31.48		0.305

2007
	March 31	$	31.10	$	28.85	$	30.94	$	0.290
	June 30		35.58		29.92		34.24		0.295
	September 30		37.25		28.00		33.94		0.295
	December 31		36.38		29.59		31.85		0.295

Quarter Ended	High		Low		Close		Dividends Declared Per Share
2005
March 31	$	27.5900	$	25.8300	$	26.6000	$	0.2800
June 30		30.9500		23.6000		30.5800		0.2850
September 30		35.6000		59.5000		35.1620		0.2850
December 31		35.7799		30.3227		30.8000		0.2850

2004
March 31	$	26.5100	$	24.3000	$	25.6200	$	0.2750
June 30		26.2000		20.4200		22.7000		0.2800
September 30		25.4000		22.1000		25.1000		0.2800
December 31		27.5500		24.5000		26.7000		0.2800


	Total				Total Number of Shares		Maximum Number of
	Number of		Average		Purchased as Part of		Shares That May Yet Be
	Shares		Price Paid		Publicly Announced Plans		Purchased Under the
Period	Purchased		Per Share		or Programs⁽²⁾		Plans or Programs⁽²⁾
October 1, 2008 through October 31, 2008⁽¹⁾		594	$	31.62		0		0
November 1, 2008 through November 30, 2008		0	$	0.00		0		0
December 1, 2008 through December 31, 2008		0	$	0.00		0		0

Total		594	$	31.62		0		0


⁽¹⁾		Chesapeake purchased shares of stock on the open market for the purpose of reinvesting the dividend on deferred stock units held in the Rabbi Trust accounts for certain Senior Executives and Directors under the Deferred Compensation Plan. The Deferred Compensation Plan is discussed in detail in Note K to the Consolidated Financial Statements. During the quarter, 594 shares were purchased through the reinvestment of dividends on deferred stock units.

⁽²⁾		Except for the purposes described in Footnote (1), Chesapeake has no publicly announced plans or programs to repurchase its shares.

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs ⁽²⁾		Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs ⁽²⁾
October 1, 2005 through October 31, 2005 ⁽¹⁾		295	$	36.00		0		0
November 1, 2005 through November 30, 2005		0	$	0.00		0		0
December 1, 2005 through December 31, 2005		0	$	0.00		0		0
Total		295	$	36.00		0		0

⁽¹⁾ Chesapeake purchased shares of stock on the open market to add to shares held in a Rabbi Trust to adjust the balance to the contractual value. 295 shares were purchased through executive dividend deferrals.
⁽²⁾ Chesapeake has no publicly announced plans or programs to repurchase its shares.

For the Years Ended December 31,	2005			2004			2003			2002⁽¹⁾			2001⁽¹⁾
Operating *(in thousands of dollars)*⁽³⁾
Revenues
Natural gas distribution and transmission	$	166,582		$	124,246		$	110,247		$	93,588		$	107,418
Propane		48,976			41,500			41,029			29,238			35,742
Advanced informations systems		14,140			12,427			12,578			12,764			14,104
Other and eliminations		(68	)		(218	)		(286	)		(334	)		(113	)
Total revenues	$	229,630		$	177,955		$	163,568		$	135,256		$	157,151

Operating income
Natural gas distribution and transmission	$	17,236		$	17,091		$	16,653		$	14,973		$	14,405
Propane		3,209			2,364			3,875			1,052			913
Advanced informations systems		1,197			387			692			343			517
Other and eliminations		(112	)		128			359			237			386
Total operating income	$	21,530		$	19,970		$	21,579		$	16,605		$	16,221

Net income from continuing operations	$	10,468		$	9,550		$	10,079		$	7,535		$	7,341


Assets *(in thousands of dollars)*
Gross property, plant and equipment	$	280,345		$	250,267		$	234,919		$	229,128		$	216,903
Net property, plant and equipment ⁽⁴⁾	$	201,504		$	177,053		$	167,872		$	166,846		$	161,014
Total assets ⁽⁴⁾	$	295,980		$	241,938		$	222,058		$	223,721		$	222,229
Capital expenditures ⁽³⁾	$	33,423		$	17,830		$	11,822		$	13,836		$	26,293


Capitalization *(in thousands of dollars)*
Stockholders' equity	$	84,757		$	77,962		$	72,939		$	67,350		$	67,517
Long-term debt, net of current maturities		58,991			66,190			69,416			73,408			48,409
Total capitalization	$	143,748		$	144,152		$	142,355		$	140,758		$	115,926

Current portion of long-term debt	$	4,929		$	2,909		$	3,665		$	3,938		$	2,686
Short-term debt		35,482			5,002			3,515			10,900			42,100
Total capitalization and short-term financing	$	184,159		$	152,063		$	149,535		$	155,596		$	160,712



⁽¹⁾ The years 2002, 2001, 2000 and 1999 have been restated in order to reflect the Company’s Delaware and Maryland natural gas divisions on the “accrual” rather than the “as billed” revenue recognition method.
⁽²⁾ The years 1998, 1997, and 1996 have not been restated to reflect the “accrual” revenue recognition method due to the immateriality of the impact on the Company’s financial results.
⁽³⁾ These amounts exclude the results of water services due to their reclassification to discontinued operations. The assets of all of the water businesses were sold in 2004 and 2003.
⁽⁴⁾ The years 2005, 2004, 2003, 2002 and 2001 reflect the results of adopting SFAS 143.

For the Years Ended December 31,	2000⁽¹⁾			1999⁽¹⁾			1998⁽²⁾			1997⁽²⁾			1996⁽²⁾
Operating *(in thousands of dollars)*⁽³⁾
Revenues
Natural gas distribution and transmission	$	101,138		$	75,637		$	68,770		$	88,108		$	90,044
Propane		31,780			25,199			23,377			28,614			36,727
Advanced informations systems		12,390			13,531			10,331			7,786			7,230
Other and eliminations		(131	)		(14	)		(15	)		(182	)		(243	)
Total revenues	$	145,177		$	114,353		$	102,463		$	124,326		$	133,758

Operating income
Natural gas distribution and transmission	$	12,798		$	10,388		$	8,820		$	9,240		$	9,627
Propane		2,135			2,622			965			1,137			2,668
Advanced informations systems		336			1,470			1,316			1,046			1,056
Other and eliminations		816			495			485			558			560
Total operating income	$	16,085		$	14,975		$	11,586		$	11,981		$	13,911

Net income from continuing operations	$	7,665		$	8,372		$	5,329		$	5,812		$	7,764


Assets *(in thousands of dollars)*
Gross property, plant and equipment	$	192,925		$	172,068		$	152,991		$	144,251		$	134,001
Net property, plant and equipment ⁽⁴⁾	$	131,466		$	117,663		$	104,266		$	99,879		$	94,014
Total assets ⁽⁴⁾	$	211,764		$	166,958		$	145,029		$	145,719		$	155,786
Capital expenditures ⁽³⁾	$	22,057		$	21,365		$	12,516		$	13,471		$	15,399


Capitalization *(in thousands of dollars)*
Stockholders' equity	$	64,669		$	60,714		$	56,356		$	53,656		$	50,700
Long-term debt, net of current maturities		50,921			33,777			37,597			38,226			28,984
Total capitalization	$	115,590		$	94,491		$	93,953		$	91,882		$	79,684

Current portion of long-term debt	$	2,665		$	2,665		$	520		$	1,051		$	3,526
Short-term debt		25,400			23,000			11,600			7,600			12,735
Total capitalization and short-term financing	$	143,655		$	120,156		$	106,073		$	100,533		$	95,945



⁽¹⁾ The years 2002, 2001, 2000 and 1999 have been restated in order to reflect the Company’s Delaware and Maryland natural gas divisions on the “accrual” rather than the “as billed” revenue recognition method.
⁽²⁾ The years 1998, 1997, and 1996 have not been restated to reflect the “accrual” revenue recognition method due to the immateriality of the impact on the Company’s financial results.
⁽³⁾ These amounts exclude the results of water services due to their reclassification to discontinued operations. The assets of all of the water businesses were sold in 2004 and 2003.
⁽⁴⁾ The years 2005, 2004, 2003, 2002 and 2001 reflect the results of adopting SFAS 143.


						Increase								Increase
For the Years Ended December 31,	2008		2007			(decrease)		2007			2006			(decrease)
Net Income (Loss)*
Continuing operations	$	13,607	$	13,218		$	389	$	13,218		$	10,748		$	2,470
Discontinued operations		—		(20	)		20		(20	)		(241	)		221

Total Net Income	$	13,607	$	13,198		$	410	$	13,198		$	10,507		$	2,691

Diluted Earnings (Loss) Per Share
Continuing operations	$	1.98	$	1.94		$	0.04	$	1.94		$	1.76		$	0.18
Discontinued operations		—		—			—		—			(0.04	)		0.04

Total Earnings Per Share	$	1.98	$	1.94		$	0.04	$	1.94		$	1.72		$	0.22

Propane (in thousands)

For the Years Ended December 31,	2005		2004		Increase (decrease)		2004		2003		Increase (decrease)
Revenue	$	48,976	$	41,500	$	7,476	$	41,500	$	41,029	$	471
Cost of sales		30,041		25,155		4,886		25,155		22,762		2,393
Gross margin		18,935		16,345		2,590		16,345		18,267		(1,922	)

Operations & maintenance		13,355		11,718		1,637		11,718		12,053		(335	)
Depreciation & amortization		1,574		1,524		50		1,524		1,506		18
Other taxes		797		739		58		739		833		(94	)
Other operating expenses		15,726		13,981		1,745		13,981		14,392		(411	)

Total Operating Income	$	3,209	$	2,364	$	845	$	2,364	$	3,875		($1,511	)

Propane Heating Degree-Day (HDD) Analysis — Delmarva

For the Years Ended December 31,	2005		2004		Increase (decrease)		2004		2003		Increase (decrease)
Heating degree-days
Actual		4,792		4,553		239		4,553		4,715		(162	)
10-year average		4,436		4,383		53		4,383		4,409		(26	)

Estimated gross margin per HDD	$	1,743	$	1,691	$	52	$	1,691	$	1,670	$	21

Advanced Information Services (in thousands)

For the Years Ended December 31,	2005		2004		Increase (decrease)			2004		2003		Increase (decrease)
Revenue	$	14,140	$	12,427	$	1,713		$	12,427	$	12,578		($151	)
Cost of sales		7,181		7,015		166			7,015		7,018		(3	)
Gross margin		6,959		5,412		1,547			5,412		5,560		(148	)

Operations & maintenance		5,129		4,405		724			4,405		4,196		209
Depreciation & amortization		123		138		(15	)		138		191		(53	)
Other taxes		510		482		28			482		481		1
Other operating expenses		5,762		5,025		737			5,025		4,868		157

Total Operating Income	$	1,197	$	387	$	810		$	387	$	692		($305	)

Other Operations & Eliminations (in thousands)

For the Years Ended December 31,	2005			2004		Increase (decrease)			2004		2003		Increase (decrease)
Revenue	$	763		$	647	$	116		$	647	$	702		($55	)
Cost of sales		116			-		116			-		-		-
Gross margin		647			647		-			647		702		(55	)

Operations & maintenance		472			279		193			279		79		200
Depreciation & amortization		220			210		10			210		238		(28	)
Other taxes		97			63		34			63		55		8
Other operating expenses		789			552		237			552		372		180

Operating Income — Other		($142	)	$	95		($237	)	$	95	$	330		($235	)
Operating Income — Eliminations	$	30		$	33		($3	)	$	33	$	29	$	4

Total Operating Income (Loss)		($112	)	$	128		($240	)	$	128	$	359		($231	)


	Payments Due by Period
	Less than 1						More than 5
Contractual Obligations	year		1 – 3 years		3 – 5 years		years		Total
Long-term debt⁽¹⁾	$	6,656,364	$	14,403,636	$	13,454,545	$	58,564,091	$	93,078,636
Operating leases⁽²⁾		770,329		1,217,087		929,756		2,446,248		5,363,420
Purchase obligations⁽³⁾
Transmission capacity		8,881,750		22,168,145		10,162,156		48,665,180		89,877,231
Storage — Natural Gas		1,507,998		4,145,743		2,719,878		1,707,063		10,080,682
Commodities		31,597,588		57,545		—		—		31,655,133
Forward purchase contracts — Propane⁽⁴⁾		10,181,630		—		—		—		10,181,630
Unfunded benefits⁽⁵⁾		336,637		1,392,409		659,454		1,810,947		4,199,447
Funded benefits⁽⁶⁾		519,319		120,615		60,308		1,396,143		2,096,385

Total Contractual Obligations	$	60,451,615	$	43,505,180	$	27,986,097	$	114,589,672	$	246,532,564


⁽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 $5.7 million, $10.0 million, $8.0 million and $13.1 million, respectively, for the periods indicated above. Expected interest payments for all periods total $36.8 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 $4.6 million at December 31, 2008 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 62 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 $6.5 million at December 31, 2008 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. The Company expects to contribute $450,000 to the plan in 2009. Additional contributions may be required 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.

	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⁾	$	4,929,091	$	15,312,727	$	13,312,727	$	30,364,909	$	63,919,454
Operating leases ⁽²⁾		645,576		1,062,394		692,741		2,376,302		4,777,013
Purchase obligations ⁽³⁾
Transmission capacity		7,585,816		12,497,472		11,890,259		25,015,062		56,988,609
Storage — Natural Gas		1,422,987		2,709,353		2,696,217		6,518,563		13,347,120
Commodities		20,012,976		-		-		-		20,012,976
Forward purchase contracts — Propane ⁽⁴⁾		21,622,201		-		-		-		21,622,201
Unfunded benefits ⁽⁵⁾		259,399		528,995		551,782		2,678,755		4,018,931
Funded benefits ⁽⁶⁾		68,680		129,697		111,081		1,376,178		1,685,636
Total Contractual Obligations	$	56,546,726	$	32,240,638	$	29,254,807	$	68,329,769	$	186,371,940

⁽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 $4.5 million, $7.7 million, $5.7 million and $7.2 million, respectively, for the periods indicated above. Expected interest payments for all periods total $25.1 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 $4.0 million at December 31, 2005 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 $1.7 million at December 31, 2005 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, 2005. 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.

At December 31, 2005	Quantity in gallons		Estimated Market Prices		Weighted Average Contract Prices
Forward Contracts
Sale		20,794,200		$1.0350 — $1.1013		$1.0718
Purchase		20,202,000		$1.0100 — $1.0450		$1.0703

Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expire in 2006.

At December 31, 2004	Quantity in gallons		Estimated Market Prices		Weighted Average Contract Prices
Forward Contracts
Sale		10,044,510		$0.7725 — $0.7750		$0.7828
Purchase		9,975,000		$0.7300 — $0.7500		$0.8007

Futures Contracts
Sale		378,000		$0.7450 — $0.7500		$0.7868
Purchase		420,000		$0.7200 — $0.7300		$0.7500

Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expired in 2005.