10-Q

United States
Securities and Exchange Commission

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended: March 31, 2010

OR

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

For the transition period from                      to                     

Commission File Number: 001-11590

Chesapeake Utilities Corporation

(Exact name of registrant as specified in its charter)

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

909 Silver Lake Boulevard, Dover, Delaware 19904

(Address of principal executive offices, including Zip Code)

(302) 734-6799

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes o No o

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

Large accelerated filer o Accelerated filer þ Non-accelerated filer o Smaller reporting company o

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

Common Stock, par value $0.4867 — 9,458,048 shares outstanding as of April 30, 2010.

Table of Contents

PART I — FINANCIAL INFORMATION	1
Item 1. Financial Statements	1
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3. Quantitative and Qualitative Disclosures about Market Risk	40
Item 4. Controls and Procedures	42
PART II — OTHER INFORMATION	43
Item 1. Legal Proceedings	43
Item 1A. Risk Factors	43
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 3. Defaults upon Senior Securities	44
Item 5. Other Information	44
Item 6. Exhibits	45
SIGNATURES	46
Exhibit 10.1
Exhibit 10.2
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

GLOSSARY OF KEY TERMS

Frequently used abbreviations, acronyms, or terms used in this report:

Subsidiaries of Chesapeake Utilities Corporation

BravePoint	BravePoint, Inc. is a wholly-owned subsidiary of Chesapeake Services company, which is a wholly-owned subsidiary of Chesapeake
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
FPU	Florida Public Utilities Company, a wholly-owned subsidiary of Chesapeake, effective October 28, 2009
PESCO	Peninsula Energy Services Company, Inc., a wholly-owned subsidiary of Chesapeake
PIPECO	Peninsula Pipeline Company, Inc., a wholly-owned subsidiary of Chesapeake
Sharp	Sharp Energy, Inc., a wholly-owned subsidiary of Chesapeake’s and Sharp’s subsidiary, Sharpgas, Inc.
Xeron	Xeron, Inc. a wholly-owned subsidiary of Chesapeake

Regulatory Agencies

Delaware PSC	Delaware Public Service Commission
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
IASB	International Accounting Standards Board
Maryland PSC	Maryland Public Service Commission
MDE	Maryland Department of the Environment
PSC	Public Service Commission
SEC	Securities and Exchange Commission

Other

AS/SVE	Air Sparging and Soil/Vapor Extraction
BS/SVE	Bio-Sparging and Soil/Vapor Extraction
CGS	Community Gas Systems
DSCP	Directors Stock Compensation Plan
Dts	Dekatherms
Dts/d	Dekatherms per day
GSR	Gas Sales Service Rates
HDD	Heating Degree-Days
Mcf	Thousand Cubic Feet
MWH	Megawatt Hour
MGP	Manufactured Gas Plant
NYSE	New York Stock Exchange
PIP	Performance Incentive Plan
RAP	Remedial Action Plan

Accounting Standard

ASC	FASB Accounting Standards CodificationTM (Codification)
ASU	FASB Accounting Standards Update
GAAP	Generally Accepted Accounting Principles
IFRS	International Financial Reporting Standards

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Income (Unaudited)

For the Three Months Ended March 31,	2010		2009
(in thousands, except shares and per share data)
Operating Revenues
Regulated Energy	$	91,626	$	52,181
Unregulated Energy		59,269		49,394
Other		2,365		2,904
Total operating revenues		153,260		104,479
Operating Expenses
Regulated energy cost of sales		53,768		32,513
Unregulated energy and other cost of sales		45,091		38,709
Operations		18,695		12,245
Transaction-related costs		19		114
Maintenance		1,700		615
Depreciation and amortization		5,623		2,384
Other taxes		2,966		1,933
Total operating expenses		127,862		88,513
Operating Income		25,398		15,966
Other income, net of expenses		115		33
Interest charges		2,363		1,642
Income Before Income Taxes		23,150		14,357
Income tax expense		9,176		5,764
Net Income	$	13,974	$	8,593
Weighted-Average Common Shares Outstanding:
Basic		9,419,932		6,832,675
Diluted		9,524,298		6,943,129
Earnings Per Share of Common Stock:
Basic	$	1.48	$	1.26
Diluted	$	1.47	$	1.24
Cash Dividends Declared Per Share of Common Stock	$	0.315	$	0.305

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

- 1 -

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

For the Three Months Ended March 31,	2010			2009
(in thousands)
Operating Activities
Net Income	$	13,974		$	8,593
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		5,623			2,384
Depreciation and accretion included in other costs		861			664
Deferred income taxes, net		369			(790	)
Unrealized loss (gain) on commodity contracts		(215	)		1,294
Unrealized loss (gain) on investments		(51	)		94
Employee benefits		(272	)		412
Share-based compensation		333			241
Other, net		41			—
Changes in assets and liabilities:
Sale (purchase) of investments		(30	)		34
Accounts receivable and accrued revenue		15,800			9,217
Propane inventory, storage gas and other inventory		6,155			8,527
Regulatory assets		1,669			604
Prepaid expenses and other current assets		1,923			1,360
Accounts payable and other accrued liabilities		(12,741	)		(10,940	)
Income taxes receivable		8,580			6,345
Accrued interest		949			1,140
Customer deposits and refunds		604			(1,854	)
Accrued compensation		(980	)		(1,608	)
Regulatory liabilities		3,314			5,357
Other liabilities		503			(38	)
Net cash provided by operating activities		46,409			31,036
Investing Activities
Property, plant and equipment expenditures		(6,099	)		(4,124	)
Purchase of investments		(310	)		—
Environmental expenditures		(367	)		(8	)
Net cash used in investing activities		(6,776	)		(4,132	)
Financing Activities
Common stock dividends		(2,683	)		(1,791	)
Issuance (purchase) of stock for Dividend Reinvestment Plan		152			(227	)
Change in cash overdrafts due to outstanding checks		(834	)		—
Net repayment under line of credit agreements		(88	)		(23,200	)
Repayment of long-term debt		(28,858	)		(20	)
Net cash used in financing activities		(32,311	)		(25,238	)
Net Increase in Cash and Cash Equivalents		7,322			1,666
Cash and Cash Equivalents — Beginning of Period		2,828			1,611
Cash and Cash Equivalents — End of Period	$	10,150		$	3,277

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

- 2 -

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

	March 31,			December 31,
Assets	2010			2009
(in thousands, except shares and per share data)
Property, Plant and Equipment
Regulated energy	$	467,147		$	463,856
Unregulated energy		59,066			61,360
Other		16,073			16,054
Total property, plant and equipment		542,286			541,270
Less: Accumulated depreciation and amortization		(111,497	)		(107,318	)
Plus: Construction work in progress		3,720			2,476
Net property, plant and equipment		434,509			436,428
Investments		2,040			1,959
Current Assets
Cash and cash equivalents		10,150			2,828
Accounts receivable (less allowance for uncollectible accounts of $1,460 and $1,609, respectively)		55,165			70,029
Accrued revenue		11,877			12,838
Propane inventory, at average cost		6,142			7,901
Other inventory, at average cost		3,331			3,149
Regulatory assets		66			1,205
Storage gas prepayments		1,566			6,144
Income taxes receivable		—			2,614
Deferred income taxes		3,324			1,498
Prepaid expenses		3,857			5,843
Mark-to-market energy assets		198			2,379
Other current assets		146			147
Total current assets		95,822			116,575
Deferred Charges and Other Assets
Goodwill		34,782			34,095
Other intangible assets, net		3,809			3,951
Long-term receivables		247			343
Regulatory assets		21,936			19,860
Other deferred charges		3,799			3,891
Total deferred charges and other assets		64,573			62,140
Total Assets	$	596,944		$	617,102

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

- 3 -

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

	March 31,			December 31,
Capitalization and Liabilities	2010			2009
(in thousands, except shares and per share data)
Capitalization
Stockholders’ equity
Common stock, par value $0.4867 per share (authorized 12,000,000 shares)	$	4,594		$	4,572
Additional paid-in capital		144,866			144,502
Retained earnings		74,205			63,231
Accumulated other comprehensive loss		(2,484	)		(2,524	)
Deferred compensation obligation		748			739
Treasury stock		(748	)		(739	)
Total stockholders’ equity		221,181			209,781
Long-term debt, net of current maturities		98,988			98,814
Total capitalization		320,169			308,595
Current Liabilities
Current portion of long-term debt		8,125			35,299
Short-term borrowing		29,100			30,023
Accounts payable		37,809			51,948
Customer deposits and refunds		25,650			24,960
Accrued interest		2,836			1,887
Dividends payable		2,974			2,959
Income taxes payable		5,901			—
Accrued compensation		2,493			3,445
Regulatory liabilities		12,171			8,882
Mark-to-market energy liabilities		118			2,514
Other accrued liabilities		10,543			8,683
Total current liabilities		137,720			170,600
Deferred Credits and Other Liabilities
Deferred income taxes		68,666			66,923
Deferred investment tax credits		170			193
Regulatory liabilities		4,179			4,154
Environmental liabilities		10,066			11,104
Other pension and benefit costs		17,212			17,505
Accrued asset removal cost — Regulatory liability		33,731			33,214
Other liabilities		5,031			4,814
Total deferred credits and other liabilities		139,055			137,907
Total Capitalization and Liabilities	$	596,944		$	617,102

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

- 4 -

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements Stockholders’ Equity (Unaudited)

	Common Stock					Additional						Accumulated Other
	Number of					Paid-In			Retained			Comprehensive			Deferred			Treasury
(in thousands, except per share and share data)	Shares(7)			Par Value		Capital			Earnings			Loss			Compensation			Stock			Total
Balances at December 31, 2008		6,827,121		$	3,323	$	66,681		$	56,817		$	(3,748	)	$	1,549		$	(1,549	)	$	123,073
Net Income										15,897												15,897
Other comprehensive income, net of tax:
Employee Benefit Plans, net of tax:
Amortization of prior service costs (4)													7									7
Net Gain (5)													1,217									1,217
Total comprehensive income																					$	17,121
Dividend Reinvestment Plan		31,607			15		921															936
Retirement Savings Plan		32,375			16		966															982
Conversion of debentures		7,927			4		131															135
Share based compensation (1) (3)		7,374			3		1,332															1,335
Deferred Compensation Plan (6)																(810	)		810			—
Purchase of treasury stock		(2,411	)																(73	)		(73	)
Sale and distribution of treasury stock		2,411																	73			73
Common stock issued in the merger		2,487,910			1,211		74,471															75,682
Dividends on stock-based compensation										(104	)											(104	)
Cash dividends (2)										(9,379	)											(9,379	)
Balances at December 31, 2009		9,394,314			4,572		144,502			63,231			(2,524	)		739			(739	)		209,781
Net Income										13,974												13,974
Other comprehensive income, net of tax:
Employee Benefit Plans, net of tax:
Amortization of prior service costs (4)													2									2
Net Gain (5)													38									38
Total comprehensive income																					$	14,014
Dividend Reinvestment Plan		13,714			6		416															422
Retirement Savings Plan		3,539			2		111															113
Conversion of debentures		2,173			1		36															37
Tax benefit on share based compensation							75															75
Share based compensation (1) (3)		26,515			13		(274	)														(261	)
Deferred Compensation Plan (6)																9			(9	)		—
Purchase of treasury stock		(279	)																(9	)		(9	)
Sale and distribution of treasury stock		279																	9			9
Dividends on stock-based compensation										(26	)											(26	)
Cash dividends (2)										(2,974	)											(2,974	)
Balances at March 31, 2010		9,440,255		$	4,594	$	144,866		$	74,205		$	(2,484	)	$	748		$	(748	)	$	221,181

(1)	Includes amounts for shares issued for Directors’ compensation.
(2)	Cash dividends per share for the periods ended March 31, 2010 and December 31, 2009 were $0.315 and $1.250, respectively.
(3)	The shares issued under the Performance Incentive Plan (“PIP”) are net of shares withheld for employee taxes. For the period ended March 31, 2010, the Company withheld 17,695 shares for taxes. We did not issue any shares under PIP in 2009.
(4)	Tax expense recognized on the prior service cost component of employees benefit plans for the periods ended March 31, 2010 and December 31, 2009 were approximately $1 and $5, respectively.
(5)	Tax expense recognized on the net gain (loss) component of employees benefit plans for the periods ended March 31, 2010 and December 31, 2009 were $26 and $794, respectively.
(6)	In May and November 2009, certain participants of the Deferred Compensation Plan received distributions totaling $883. There were no distributions in the first quarter of 2010.
(7)	Includes 28,731 and 28,452 shares at March 31, 2010 and December 31, 2009, respectively, held in a Rabbi Trust established by the Company relating to the Deferred Compensation Plan.

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

- 5 -

Notes to Condensed Consolidated Financial Statements (Unaudited)

1. Summary of Accounting Policies

Basis of Presentation

References in this document to “the Company,” “Chesapeake,” “we,” “us” and “our” are intended to mean the Registrant and its subsidiaries, or the Registrant’s subsidiaries, as appropriate in the context of the disclosure.

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and United States of America Generally Accepted Accounting Principles (“GAAP”). In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K filed with the SEC on March 8, 2010. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

As a result of the merger with Florida Public Utilities Company (“FPU”) in October 2009, we changed our operating segments (see Note 5, “Segment Information,” for further discussion). We revised the segment information as of and for the three months ended March 31, 2009, to reflect the new segments. We also revised certain presentations and reclassified certain amounts reported in the condensed consolidated statements of income and cash flows for the three months ended March 31, 2009 to conform to current period presentations and classifications. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.

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

We have assessed and reported on subsequent events through the date of issuance of these condensed consolidated financial statements.

Recent Accounting Amendments Yet to be Adopted by the Company

In November 2008, the SEC released a proposed roadmap regarding the potential use by U.S. issuers of financial statements prepared in accordance with International Financial Reporting Standards (“IFRS”), a comprehensive series of accounting standards published by the International Accounting Standards Board (“IASB”). Under the proposed roadmap, we may be required to prepare our financial statements in accordance with IFRS as early as 2014. The SEC will make a determination in 2011 regarding the mandatory adoption of IFRS. In July 2009, the IASB issued an exposure draft of “Rate-regulated Activities,” which sets out the scope, recognition and measurement criteria, and accounting disclosures for assets and liabilities that arise in the context of cost-of-service regulation, to which our rate-regulated businesses are subject. We will continue to monitor the development of the potential implementation of IFRS.

Other Accounting Amendments Adopted by the Company during the first quarter of 2010

In January 2010, the Financial Accounting Standards Board (“FASB”) issued FASB Accounting Standards Update (“ASU”) 2010-06, “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements.” This ASU requires certain new disclosures and clarifies certain existing disclosure requirements about fair value measurement, as set forth in FASB Accounting Standards Codification (“ASC”) Subtopic 820-10. The FASB’s objective is to improve these disclosures and, thus, increase the transparency in financial reporting. Specifically, ASU 2010-06 amends ASC Subtopic 820-10 to now require a reporting entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers; and, in the reconciliation for fair value measurements using significant unobservable inputs, a reporting entity should present separate information about purchases, sales, issuances, and settlements. In addition, ASU 2010-06 clarifies certain requirements of the existing disclosures. We adopted the disclosures required by this ASU in the first quarter of 2010, except for disclosures about purchases, sales, issuances, and settlements in the roll-forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. We currently do not have any assets or liabilities that would require Level 3 fair value measurements. Adoption of this ASU did not have an impact on our condensed consolidated financial position and results of operations.

- 6 -

In April 2010, the FASB issued FASB ASU 2010-12 — Income Taxes (Topic 740), “Accounting for Certain Tax effects of the 2010 Health Care Reform Acts.” This ASU codifies the SEC staff announcement relating to the accounting for the Health Care and Education Reconciliation Act and the Patient Protection and Affordable Care Act, which allows the two Acts to be considered together for accounting purposes. We adopted this ASU in the first quarter of 2010 and have determined that these Acts did not have a material impact on our income tax accounting (see Note 6, “Employee Benefits,” to these unaudited condensed consolidated financial statements for further discussion).

2. Acquisitions

FPU

On October 28, 2009, we completed the previously announced merger with FPU, pursuant to which FPU became a wholly-owned subsidiary of Chesapeake. The merger was accounted for under the acquisition method of accounting, with Chesapeake treated as the acquirer for accounting purposes.

The merger allowed us to become a larger energy company serving approximately 200,000 customers in the Mid-Atlantic and Florida markets, which is twice the number of energy customers we served previously. The merger increased our overall presence in Florida by adding approximately 51,000 natural gas distribution customers and 12,000 propane distribution customers to our existing Florida operations. It also introduced us to the electric distribution business as we incorporated FPU’s approximately 31,000 electric customers in northwest and northeast Florida.

In consummating the merger, we issued 2,487,910 shares of Chesapeake common stock at a price per share of $30.42 in exchange for all outstanding common stock of FPU. We also paid approximately $16,000 in lieu of issuing fractional shares in the exchange. There is no contingent consideration in the merger. Total value of considerations transferred by Chesapeake in the merger was approximately $75.7 million.

The assets acquired and liabilities assumed in the merger were recorded at their respective fair values at the completion of the merger. For certain assets acquired and liabilities assumed, such as pension and post-retirement benefit obligations, income taxes and contingencies without readily determinable fair value, for which GAAP provides specific exception to the fair value recognition and measurement, we applied other specified GAAP or accounting treatment as appropriate.

- 7 -

The following table summarizes an adjusted allocation of the purchase price to the assets acquired and liabilities assumed at the date of the merger. Estimates of deferred income taxes, recovery of certain regulatory assets, and certain accruals are subject to change, pending the finalization of income tax returns and availability of additional information about the facts and circumstances that existed as of the merger closing. We will complete the purchase price allocation as soon as practicable but no later than one year from the merger closing.

(In thousands)	October 28, 2009
Purchase price	$	75,699
Current assets		26,761
Property, plant and equipment		138,998
Regulatory assets		19,584
Investments and other deferred charges		3,659
Intangible assets		4,019
Total assets acquired		193,021
Long term debt		47,812
Borrowings from line of credit		4,249
Other current liabilities		17,427
Other regulatory liabilities		19,414
Pension and post retirement obligations		14,276
Environmental liabilities		12,414
Deferred income taxes		20,371
Customer deposits and other liabilities		15,467
Total liabilities assumed		151,430
Net identifiable assets acquired		41,591
Goodwill	$	34,108

During the first quarter of 2010, we adjusted the allocation of purchase price based on additional information available. The adjustments are related to certain accruals, regulatory assets and deferred tax assets. These adjustments also resulted in a change in fair value of propane property, plant and equipment. Goodwill from the merger increased to $34.1 million after incorporating these adjustments, compared to $33.4 million prior to the adjustments.

None of the $34.1 million in goodwill recorded in connection with the merger is deductible for tax purposes. All of the goodwill recorded in connection with the merger is related to the regulated energy segment. We believe the goodwill recognized is attributable primarily to the strength of FPU’s regulated energy businesses and the synergies and opportunities in the combined company. The intangible assets acquired in connection with the merger are related to propane customer relationships ($3.5 million) and favorable propane contracts ($519,000). The intangible value assigned to FPU’s existing propane customer relationships will be amortized over a 12-year period based on the expected duration of benefit arising from the relationships. The intangible value assigned to FPU’s favorable propane contracts will be amortized over a period ranging from one to 14 months based on contractual terms.

Current assets of $26.8 million acquired during the merger include notes receivable of approximately $5.8 million, for which we received payment in March 2010, and accounts receivable of approximately $3.1 million, $6.0 million and $891,000 for FPU’s natural gas, electric and propane distribution businesses, respectively.

- 8 -

The financial position and results of operations and cash flows of FPU from the effective date of the merger are included in our consolidated financial statements. The revenue and net income from FPU for the three months ended March 31, 2010, included in our condensed consolidated statements of income, were $54.2 million and $4.5 million, respectively.

The following table shows the actual results of combined operations for the three months ended March 31, 2010 and pro forma results of combined operations for the three months ended March 31, 2009, as if the merger had been completed at January 1, 2009. Since the effects of the merger for the three months ended March 31, 2010 were already included in the actual results of our consolidated operations, there is no pro forma adjustment for the three months ended March 31, 2010.

For the Three Months Ended March 31,	2010		2009
(in thousands, except per share data)
Operating Revenues	$	153,260	$	147,672
Operating Income		25,398		18,344
Net income		13,974		9,556
Earnings per share — basic	$	1.48	$	1.03
Earnings per share — diluted	$	1.47	$	1.01

Pro forma results are presented for informational purposes only, and are not necessarily indicative of what the actual results would have been had the acquisition actually occurred on January 1, 2009.

The acquisition method of accounting requires acquisition-related costs to be expensed in the period in which those costs are incurred, rather than including them as a component of consideration transferred. It also prohibits an accrual of certain restructuring costs at the time of the merger. As we intend to seek recovery in future rates in Florida of a certain portion of the purchase premium paid and merger-related costs incurred, we also considered the impact of ASC Topic 980, “Regulated Operations,” in determining the proper accounting treatment for the merger-related costs. As of March 31, 2010, we incurred approximately $3.0 million in costs to consummate the merger, including the cost associated with merger-related litigation, and integrating operations following the merger. This includes $40,000 incurred during the three months ended March 31, 2010. We deferred approximately $1.5 million of the total costs incurred as a regulatory asset at March 31, 2010, which represents our estimate, based on similar proceedings in Florida in the past, of the costs which we expect to be permitted to recover when we complete the appropriate rate proceedings.

Included in the $3.0 million merger-related costs incurred as of March 31, 2010 were approximately $28,000 of severance and other restructuring charges for our efforts to integrate the operations of the two companies. We expect to incur an additional $300,000 in severance and other restructuring costs related to that effort during the second quarter of 2010.

Virginia LP Gas

On February 4, 2010, Sharp Energy, Inc. (“Sharp”), our propane distribution subsidiary, purchased the operating assets of Virginia LP Gas, Inc., a regional propane distributor serving approximately 1,000 retail customers in Northampton and Accomack Counties in Virginia. The total consideration for the purchase was $600,000, of which $300,000 was paid at the closing and the remaining $300,000 will be paid over 60 months. Based on our preliminary valuation, we allocated $412,000 of the purchase price to property, plant and equipment and the remaining $188,000 to intangible assets. There was no goodwill recorded in connection with this acquisition. The intangible assets acquired include customer relationships ($85,000) and non-compete agreements ($103,000), which will both be amortized over a seven-year period. The revenue and net income from this acquisition that are included in our condensed consolidated statement of income for the three months ended March 31, 2010 were not material. The allocation of purchase price is preliminary and we will complete the purchase price allocation as soon as practicable but no later than one year from the purchase of the assets.

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3. Calculation of Earnings Per Share

For the Three Months Ended March 31,	2010		2009
(in thousands, except Shares and Per Share Data)
Calculation of Basic Earnings Per Share:
Net Income	$	13,974	$	8,593
Weighted average shares outstanding		9,419,932		6,832,675
Basic Earnings Per Share	$	1.48	$	1.26
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	13,974	$	8,593
Effect of 8.25% Convertible debentures		19		20
Adjusted numerator — Diluted	$	13,993	$	8,613
Reconciliation of Denominator:
Weighted shares outstanding — Basic		9,419,932		6,832,675
Effect of dilutive securities:
Share-based Compensation		16,090		14,246
8.25% Convertible debentures		88,276		96,208
Adjusted denominator — Diluted		9,524,298		6,943,129
Diluted Earnings Per Share	$	1.47	$	1.24

4. Commitments and Contingencies

Rates and Other Regulatory Activities

Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective Public Service Commission (“PSC”); Eastern Shore Natural Gas Company (“ESNG”), our natural gas transmission operation, is subject to regulation by the Federal Energy Regulatory Commission (“FERC”). Chesapeake’s Florida natural gas distribution division and FPU’s natural gas and electric operations continue to be subject to regulation by the Florida Public Service Commission (“Florida PSC”) as separate entities.

Delaware. On September 2, 2008, our Delaware division filed with the Delaware Public Service Commission (“Delaware PSC”) its annual Gas Sales Service Rates (“GSR”) Application, seeking approval to change its GSR, effective November 1, 2008. On July 7, 2009, the Delaware PSC granted approval of a settlement agreement presented by the parties in this docket, which included the Delaware PSC, our Delaware division and the Division of the Public Advocate. As part of the settlement, the parties agreed to develop a record in a later proceeding on the price charged by the Delaware division for the temporary release of transmission pipeline capacity to our natural gas marketing subsidiary, Peninsula Energy Services Company, Inc. (“PESCO”). On January 8, 2010, the Hearing Examiner in this proceeding issued a report of Findings and Recommendations in which he recommended, among other things, that the Delaware PSC require the Delaware division to refund to its firm service customers the difference between what the Delaware division would have received had the capacity released to PESCO been priced at the maximum tariff rates under asymmetrical pricing principles, and the amount actually received by the Delaware division for capacity released to PESCO. The Hearing Examiner has also recommended

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that the Delaware PSC require us to adhere to asymmetrical pricing principles by applying the maximum tariff rates regarding all future capacity releases by the Delaware division to PESCO, if any. Accordingly, if the Hearing Examiner’s recommendation were approved without modification by the Delaware PSC and if the Delaware division temporarily released any capacity to PESCO, the Delaware division would have to credit to its firm service customers amounts equal to the maximum tariff rates that the Delaware division pays for long-term capacity, even though the temporary releases were made at lower rates based on competitive bidding procedures required by the FERC’s capacity release rules. We disagreed with the Hearing Examiner’s recommendations and filed exceptions to those recommendations on February 18, 2010. At the hearing on March 30, 2010, the Delaware PSC agreed with us that the Delaware division had been releasing capacity based on a previous settlement approved by the Delaware PSC and therefore, did not require the Delaware division to issue any refunds for past capacity releases. The Delaware PSC, however, required the Delaware division to adhere to asymmetrical pricing principles for future capacity releases to PESCO until a more appropriate pricing methodology is developed and approved. We expect the Delaware PSC to issue an order in May 2010 outlining its decisions at the March hearing. The Delaware PSC’s decision with regard to future capacity releases to PESCO contemplates that the parties will reconvene in a separate docket to determine if a pricing methodology other than asymmetrical pricing principles should apply to future capacity release by the Delaware division to PESCO.

On September 4, 2009, our Delaware division filed with the Delaware PSC its annual GSR Application, seeking approval to change its GSR, effective November 1, 2009. On October 6, 2009, the Delaware PSC authorized the Delaware division to implement the GSR charges on November 1, 2009, on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. The first evidentiary hearing in this matter is scheduled for May 19, 2010. The Delaware division anticipates a final decision by the Delaware PSC on this application late in the second quarter or early in the third quarter of 2010.

On December 17, 2009, our Delaware division filed an application with the Delaware PSC, requesting approval for an Individual Contract Rate for service to be rendered to a potential large industrial customer. The Delaware PSC granted approval of the Individual Contract Rate on February 18, 2010.

Maryland. On December 1, 2009, the Maryland Public Service Commission (“Maryland PSC”) held an evidentiary hearing to determine the reasonableness of the four quarterly gas cost recovery filings submitted by our Maryland division during the 12 months ended September 30, 2009. No issues were raised at the hearing, and on December 9, 2009, the Hearing Examiner in this proceeding issued a proposed Order approving the division’s four quarterly filings. On January 8, 2010, the Maryland PSC issued an Order substantially affirming the Hearing Examiner’s decision in the matter.

Florida. On July 14, 2009, Chesapeake’s Florida division filed with the Florida PSC its petition for a rate increase and request for interim rate relief. In the application, the Florida division sought approval of: (a) an interim rate increase of $417,555; (b) a permanent rate increase of $2,965,398, which represented an average base rate increase, excluding fuel costs, of approximately 25 percent for the Florida division’s customers; (c) implementation or modification of certain surcharge mechanisms; (d) restructuring of certain rate classifications; and (e) deferral of certain costs and the purchase premium associated with the then pending merger with FPU. On August 18, 2009, the Florida PSC approved the full amount of the Florida division’s interim rate request, subject to refund, applicable to all meters read on or after September 1, 2009. On December 15, 2009, the Florida PSC: (a) approved a $2,536,307 permanent rate increase (86 percent of the requested amount) applicable to all meters read on or after January 14, 2010; (b) determined that there is no refund required of the interim rate increase; and (c) ordered Chesapeake’s Florida division and FPU’s natural gas distribution operations to submit data no later than April 29, 2011 (which is 18 months after the merger) that details all known benefits, synergies and cost savings and cost increases that have resulted from the merger.

Also on December 15, 2009, the Florida PSC approved the settlement agreement for a final natural gas rate increase of $7,969,000 for FPU’s natural gas distribution operation, which represents approximately 80 percent of the requested base rate increase of $9,917,690 filed by FPU in the fourth quarter of 2008. The Florida PSC had approved an annual interim rate increase of $984,054 on February 10, 2009 and approved the permanent rate increase of $8,496,230 in an order issued on May 5, 2009, with the new rates to be effective beginning on June 4, 2009. On June 17, 2009, however, the Office of Public Counsel entered a protest to the Florida PSC’s order and its final natural gas rate increase ruling, which the protest required a full hearing to be held within eight months. Subsequent negotiations led to the settlement agreement between the Office of Public Counsel and FPU, which the Florida PSC approved on December 15, 2009. The rates authorized pursuant to the order approving the settlement agreement became effective on January 14, 2010. In February 2010, FPU refunded to its natural gas customers approximately $290,000, representing revenues in excess of the amount provided by the settlement agreement that had been billed to customers from June 2009 through January 14, 2010.

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On September 1, 2009, FPU’s electric distribution operation filed its annual Fuel and Purchased Power Recovery Clause, which seeks final approval of its 2008 fuel-related revenues and expenses and new fuel rates for 2010. On January 4, 2010, the Florida PSC approved the proposed 2010 fuel rates, effective on or after January 1, 2010.

On September 11, 2009, Chesapeake’s Florida division and FPU’s natural gas distribution operation separately filed their respective annual Energy Conservation Cost Recovery Clauses, seeking final approval of their 2008 conservation-related revenues and expenses and new conservation surcharge rates for 2010. On November 2, 2009, the Florida PSC approved the proposed 2010 conservation surcharge rates for both the Florida division and FPU, effective for meters read on or after January 1, 2010.

Also on September 11, 2009, FPU’s natural gas distribution operation filed its annual Purchased Gas Adjustment Clause, seeking final approval of its 2008 purchased gas-related revenues and expenses and new purchased gas adjustment cap rate for 2010. On November 4, 2009, the Florida PSC approved the proposed 2010 purchased gas adjustment cap, effective on or after January 1, 2010.

The City of Marianna Commissioners voted on July 7, 2009 to enter into a new 10-year franchise agreement with FPU, effective February 1, 2010. The agreement provides that new interruptible and time-of-use rates shall become available for certain customers prior to February 2011, or, at the option of the City, the franchise agreement could be voided nine months after that date. The new franchise agreement contains a provision that permits the City to purchase the Marianna portion of FPU’s electric system. Should FPU fail to make available the new interruptible and time-of-use rates, and if the franchise agreement is then voided by the City and the City elects to purchase the Marianna portion of the distribution system, the agreement would require the City to pay FPU severance/reintegration costs, the fair market value for the system, and an initial investment in the infrastructure to operate this limited facility. If the City purchased the electric system, FPU would have a gain in the year of the disposition; but, ongoing financial results would be negatively impacted from the loss of the Marianna area from its electric operations.

ESNG. The following are regulatory activities involving FERC Orders applicable to ESNG and the expansions of ESNG’s transmission system:

Energylink Expansion Project: In 2006, ESNG proposed to develop, construct and operate approximately 75 miles of new pipeline facilities from the existing Cove Point Liquefied Natural Gas terminal 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. In April 2009, ESNG terminated this project based on inadequate market support and initiated billing to recover approximately $3.2 million of costs incurred in connection with this project and the related cost of capital over a period of 20 years in accordance with the terms of the precedent agreements executed with the two participating customers and approved by the FERC. One of the two participating customers is Chesapeake, through its Delaware and Maryland divisions.

Prior Notice Request: On November 25, 2009, ESNG filed a prior notice request, proposing to construct, own and operate new mainline facilities to deliver additional firm entitlements of 1,594 Mcfs per day of natural gas to Chesapeake’s Delaware division. The FERC published the notice of this filing on December 7, 2009 and with no protest having been filed during the 60-day period following the notice, the proposed activity became effective on February 6, 2010. ESNG expects to realize an annualized margin of approximately $343,000 upon its completion of the facilities and implementation of the new service, which is expected in May 2010.

Mainline Extension Interconnect Project: On March 5, 2010, ESNG submitted an Application for Certificate of Public Convenience and Necessity to the FERC related to its mainline extension interconnect project that would tie into the new expansion project undertaken by Texas Eastern Transmission, LP (“TETLP”). ESNG’s project involves building and operating the eight-mile mainline extension from Honey Brook, Pennsylvania to ESNG’s existing facility in Parkesburg, Pennsylvania. The estimated capital costs associated with construction of the mainline extension by ESNG is approximately $19.4 million. FERC noticed the application on March 15, 2010 and the comment period ended on April 5, 2010. There were three protests to this application. ESNG filed an answer to the protests on April 28, 2010.

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On December 11, 2009, ESNG filed revised tariff sheets to reflect a new section 42, Consolidation of Service Agreements, to the General Terms and Conditions of its FERC Gas Tariff. Section 42 states that shippers may, at their option and subject to certain conditions, consolidate multiple service agreements under a rate schedule into a new service agreement(s) under that rate schedule. The tariff sheets were accepted by the FERC on January 7, 2010, as proposed and were made effective January 15, 2010. As this new section allows for consolidation of existing service agreements only, there will be no financial impact on ESNG.

Environmental Commitments and Contingencies

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

We have participated in the investigation, assessment or remediation and have certain exposures at six former Manufactured Gas Plant (“MGP”) sites. Those sites are located in Salisbury, Maryland, and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the Maryland Department of the Environment (“MDE”) regarding a seventh former MGP site located in Cambridge, Maryland. The Key West, Pensacola, Sanford and West Palm Beach sites are related to FPU, for which we assumed in the merger any existing and future contingencies.

As of March 31, 2010, we had recorded $468,000 in environmental liabilities related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of the future costs associated with those sites. As of March 31, 2010, we have recorded approximately $1.6 million in regulatory and other assets for future recovery of environmental costs from Chesapeake’s customers through its approved rates. As of March 31, 2010, we had recorded approximately $11.9 million in environmental liabilities related to FPU’s MGP sites in Florida, primarily from the West Palm Beach site, which represents our estimate of the future costs associated with those sites. FPU is approved to recover its environmental costs up to $14.0 million from insurance and customers through rates. Approximately $7.5 million of FPU’s expected environmental costs have been recovered from insurance and customers through rates as of March 31, 2010. We also had recorded approximately $6.5 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

The following discussion provides details on each site.

Salisbury, Maryland

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

Through March 31, 2010, we have incurred and paid approximately $2.9 million for remedial actions and environmental studies at this site and do not expect to incur any additional costs. We have recovered approximately $2.1 million through insurance proceeds or in rates and have $754,000 of the clean-up costs not yet recovered.

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Winter Haven, Florida

The Winter Haven site is located on the eastern shoreline of Lake Shipp, in Winter Haven, Florida. Pursuant to a Consent Order entered into with the Florida Department of Environmental Protection (“FDEP”), we are obligated to assess and remediate environmental impacts at this former MGP site. In 2001, the FDEP approved a Remedial Action Plan (“RAP”) requiring construction and operation of a bio-sparge/soil vapor extraction (“BS/SVE”) treatment system to address soil and groundwater impacts at a portion of the site. The BS/SVE treatment system has been in operation since October 2002. The Fourteenth Semi-Annual RAP Implementation Status Report was submitted to the FDEP in January 2010. The groundwater sampling results through October 2009 show, in general, a reduction in contaminant concentrations, although the rate of reduction has declined recently. Modifications and upgrades to the BS/SVE treatment system were completed in October 2009. At present, we predict that remedial action objectives may be met for the area being treated by the BS/SVE treatment system in approximately three years.

The BS/SVE treatment system does not address impacted soils in the southwest corner of the site. We are currently completing additional soil and groundwater sampling at this location for the purpose of designing a remedy for this portion of the site. Following the completion of this field work, we will submit a soil excavation plan to the FDEP for its review and approval.

The FDEP has indicated that we may be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the site. Based on studies performed to date, we object to FDEP’s suggestion that the sediments have been adversely impacted by the former operations of the MGP. Our early estimates indicate that some of the corrective measures discussed by the FDEP could cost as much as $1.0 million. We believe that corrective measures for the sediments are not warranted and intend to oppose any requirement that we undertake corrective measures in the offshore sediments. We have not recorded a liability for sediment remediation, as the final resolution of this matter cannot be predicted at this time.

Through March 31, 2010, we have incurred and paid approximately $1.5 million for this site and estimate an additional cost of $468,000 in the future, which has been accrued. We have recovered through rates $1.1 million of the costs and continue to expect that the remaining $829,000, which is included in regulatory assets, will be recoverable from customers through our approved rates.

Key West, Florida

FPU formerly owned and operated an MGP in Key West, Florida. Field investigations performed in the 1990s identified limited environmental impacts at the site, which is currently owned by an unrelated third party. The FDEP has not required any further work at the site as of this time. Our portion of the consulting/remediation costs which may be incurred at this site is projected to be $93,000.

Pensacola, Florida

FPU formerly owned and operated an MGP in Pensacola, Florida. The MGP was also owned by Gulf Power Corporation (“Gulf Power”). Portions of the site are now owned by the City of Pensacola and the Florida Department of Transportation. In October 2009, the FDEP informed Gulf Power that FDEP would approve a conditional No Further Action determination for the site, which must include a requirement for institutional/engineering controls. The group, consisting of Gulf Power, City of Pensacola, Florida Department of Transportation and FPU, is proceeding with preparation of the necessary documentation to submit the No Further Action justification. Consulting/remediation costs are projected to be $13,000.

Sanford, Florida

FPU is the current owner of property in Sanford, Florida, a former MGP site which was operated by several other entities before FPU acquired the property. FPU was never an owner/operator of the MGP. In late September 2006, the U.S. Environmental Protection Agency (“EPA”) sent a Special Notice Letter, notifying FPU, and the other responsible parties at the site (Florida Power Corporation, Florida Power & Light Company, Atlanta Gas Light Company, and the City of Sanford, Florida, collectively with FPU, “the Sanford Group”), of EPA’s selection of a final remedy for OU1 (soils), OU2 (groundwater), and OU3 (sediments) for the site. The total estimated remediation costs for this site were projected at the time by EPA to be approximately $12.9 million.

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In January 2007, FPU and other members of the Sanford Group signed a Third Participation Agreement, which provides for funding the final remedy approved by EPA for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13 million, or $650,000. As of March 31, 2010, FPU has paid $650,000 to the Sanford Group escrow account for its share of funding requirements.

The Sanford Group, EPA and the U.S. Department of Justice agreed to a Consent Decree in March 2008, which was entered by the federal court in Orlando on January 15, 2009. The Consent Decree obligates the Sanford Group to implement the remedy approved by EPA for the site. The total cost of the final remedy is now estimated at approximately $18 million. FPU has advised the other members of the Sanford Group that it is unwilling at this time to agree to pay any sum in excess of the $650,000 committed by FPU in the Third Participation Agreement.

Several members of the Sanford Group have concluded negotiations with two adjacent property owners to resolve damages that the property owners allege they have/will incur as a result of the implementation of the EPA-approved remediation. In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third-party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third-party claims.

As of March 31, 2010, FPU’s remaining share of remediation expenses, including attorneys’ fees and costs, is estimated to be $36,000. However, we are unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept FPU’s asserted defense to liability for costs exceeding $13 million to implement the final remedy for this site or will pursue a claim against FPU for a sum in excess of the $650,000 that FPU has funded under the Third Participation Agreement.

West Palm Beach, Florida

We are currently evaluating remedial options to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West Palm Beach, Florida, where FPU previously operated an MGP. Pursuant to a Consent Order between FPU and the FDEP, effective April 8, 1991, FPU completed the delineation of soil and groundwater impacts at the site. On June 30, 2008, FPU transmitted a revised feasibility study, evaluating appropriate remedies for the site, to the FDEP. On April 30, 2009, the FDEP issued a remedial action order, which it subsequently withdrew. In response to the order and as a condition to its withdrawal, FPU committed to perform additional field work in 2009 and complete an additional engineering evaluation of certain remedial alternatives. The scope of this work has increased in response to FDEP’s demands for additional information. The total projected cost of this work is approximately $763,000.

The feasibility study evaluated a wide range of remedial alternatives based on criteria provided by applicable laws and regulations. Based on the likely acceptability of proven remedial technologies described in the feasibility study and implemented at similar sites, management believes that consulting and remediation costs to address the impacts now characterized at the West Palm Beach site will range from $7.4 million to $18.9 million. This range of costs covers such remedies as in situ solidification for deeper soil impacts, excavation of superficial soil impacts, installation of a barrier wall with a permeable biotreatment zone, monitored natural attenuation of dissolved impacts in groundwater, or some combination of these remedies.

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Negotiations between FPU and the FDEP on a final remedy for the site continue. Prior to the conclusion of those negotiations, we are unable to determine, to a reasonable degree of certainty, the full extent or cost of remedial action that may be required. As of March 31, 2010, and subject to the limitations described above, we estimate the remediation expenses, including attorneys’ fees and costs, will range from approximately $7.8 million to $19.4 million for this site.

We continue to expect that all costs related to these activities will be recoverable from customers through rates.

Other

We are in discussions with the MDE regarding a former MGP site located in Cambridge, Maryland. The outcome of this matter cannot be determined at this time; therefore, we have not recorded an environmental liability for this location.

Other Commitments and Contingencies

Natural Gas, Electric and Propane Supply

Our natural gas, electric and propane distribution operations have entered into contractual commitments to purchase gas, electricity and propane from various suppliers. The contracts have various expiration dates. We have a contract with an energy marketing and risk management company to manage a portion of our natural gas transportation and storage capacity. This contract expires on March 31, 2012.

PESCO is currently in the process of obtaining and reviewing proposals from suppliers and anticipates executing agreements before the existing agreements expire in May 2010.

FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEA (formerly known as Jacksonville Electric Authority) requires FPU to comply with the following ratios based on the result of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75; and (b) fixed charge coverage greater than 1.5. If either of the ratios is not met by FPU, we have 30 days to cure the default or provide an irrevocable letter of credit if the default is not cured. FPU’s agreement with Gulf Power Company requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operation interest coverage (minimum of 2 to 1); and (b) total debt to total capital (maximum of 0.65 to 1). If FPU fails to meet the requirements, we have to provide the supplier a written explanation of action taken or proposed to be taken to be compliant. Failure to comply with the ratios specified in the agreement with Gulf Power Company could result in FPU having to provide an irrevocable letter of credit. FPU was in compliance with these requirements as of March 31, 2010.

Corporate Guarantees

We have issued corporate guarantees to certain vendors of our subsidiaries, the largest portion of which are for our propane wholesale marketing subsidiary and our natural gas marketing subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in our financial statements when incurred. The aggregate amount guaranteed at March 31, 2010 was $24.2 million, with the guarantees expiring on various dates through 2011.

In addition to the corporate guarantees, we have issued a letter of credit to our primary insurance company for $725,000, which expires on August 31, 2010. The letter of credit is provided as security to satisfy the deductibles under our various insurance policies. There have been no draws on this letter of credit as of March 31, 2010. We do not anticipate that this letter of credit will be drawn upon by the counterparty, and we expect that it will be renewed to the extent necessary in the future.

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Agreements for Access to New Natural Gas Supplies

On April 8, 2010, our Delaware and Maryland divisions entered into a Precedent Agreement with TETLP to secure firm transportation service from TETLP in conjunction with its new expansion project, which is expected to expand TETLP’s mainline system by up to 190,000 dekatherms per day (“Dts/d”). The Precedent Agreement provides that, upon satisfaction of certain conditions, the parties will execute two firm transportation service contracts, one for our Delaware Division and one for our Maryland Division, for 30,000 and 10,000 Dts/d, respectively, to be effective on the service commencement date of the project, which is currently projected to occur in November 2012. Each firm transportation service contract shall, among other things, provide for: (a) the maximum daily quantity of Dts/d described above; (b) a term of 15 years; (c) a receipt point at Clarington, Ohio; (d) a delivery point at Honey Brook, Pennsylvania; and (f) certain credit standards and requirements for security. Commencement of service and TETLP’s and our rights and obligations under the two firm transportation service contracts are subject to satisfaction of various conditions specified in the Precedent Agreement.

Our present sources of natural gas supplies are received primarily from the Gulf of Mexico natural gas production region and transported through two interstate upstream pipelines, which interconnect with the ESNG pipeline. These new contracts will provide our Delaware and Maryland divisions with access to new supplies of natural gas, providing increased reliability and diversity. They will also provide our Delaware and Maryland divisions additional upstream transportation capacity, which is essential to meet their current customer demands and to plan for sustainable growth.

On March 17, 2010, our Delaware and Maryland divisions entered into a separate Precedent Agreement with our natural gas transmission subsidiary, ESNG, to extend ESNG’s mainline by eight miles to interconnect with TETLP at Honey Brook, Pennsylvania. The estimated capital costs associated with construction of the mainline extension by ESNG is approximately $19.4 million, and the proposed rate for transmission service on this extension is ESNG’s current tariff rate for service in that area.

ESNG and TETLP are proceeding with obtaining the necessary approvals, authorizations or exemptions for construction and operation of their respective projects, including, but not limited to, approval by the FERC. Our Delaware and Maryland divisions require no regulatory approvals or exemptions to receive transmission service from TETLP or ESNG.

As the final scope of TETLP’s expansion facilities is not known at this time, the reservation rates for service under the firm transportation service contracts were not specified in the Precedent Agreement with TETLP. TETLP is required to provide our Delaware and Maryland divisions a good faith estimate of the reservation rate by no later than June 30, 2010.

Once the TETLP firm transportation service contracts commence, our Delaware and Maryland divisions will incur costs from those services based on the agreed reservation rate, which will become an integral component of the costs associated with providing natural gas supplies to our Delaware and Maryland divisions. The costs from the TETLP firm transportation service contracts will be included in the annual GSR filings for each of our respective divisions.

If the reservation rate provided by TETLP in June 2010 is higher than the range of rates included in the TETLP Precedent Agreement, and we determine that the higher rate causes the value of service to be uneconomic to us, the Precedent Agreement provides that the parties shall promptly meet and work in good faith to negotiate a mutually acceptable reservation rate. If, however, the parties are unable to agree upon a mutually acceptable reservation rate, either party may terminate the Precedent Agreement and the related firm transportation service contracts. In the unlikely event of such termination, we may be required to reimburse TETLP for our proportionate share (prorated based on our total commitment of 40,000 Dts/d and the project total of 190,000 Dts/d) of TETLP’s pre-service costs incurred as of the date of the termination. We estimate that our proportionate share could be approximately $363,000 upon such termination.

After our Delaware and Maryland divisions execute the negotiated rate agreements with TETLP, we would only be required to reimburse TETLP for our proportionate share of TETLP’s pre-service costs incurred to date, if we terminate the Precedent Agreement, are unwilling or unable to perform our material duties and obligations thereunder, or take certain other actions whereby TETLP is unable to obtain the authorizations and exemptions required for this project. We believe that the likelihood of our Delaware and Maryland divisions terminating the Precedent Agreement after executing the negotiated rate agreements and having to reimburse TETLP for our proportionate share of TETLP’s pre-service costs is remote. If such termination were to occur, we estimate that our proportionate share of TETLP’s pre-service costs could be approximately $4.7 million by December 31, 2010. If we were to terminate the Precedent Agreement after TETLP completed its construction of all facilities, which is expected to be in the fourth quarter of 2011, our proportionate share could be as much as approximately $45 million. The actual amount of our proportionate share of such costs could differ significantly and would ultimately be based on the level of pre-service costs at the time of any potential termination.

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We provided a letter of credit for $363,000 under the Precedent Agreement with TETLP in April 2010 as required. The letter of credit is expected to increase quarterly as TETLP’s pre-service costs increases. The letter of credit will not exceed more than the three-month reservation charge under the firm transportation service contracts, which we currently estimate to be $2.1 million.

Other

We are involved in certain legal actions and claims arising in the normal course of business. We are 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 our consolidated financial position, results of operations or cash flows.

5. Segment Information

We use the management approach to identify operating segments, and we organize our business around differences in regulatory environment and/or products or services. The operating results of each segment are regularly reviewed by the chief operating decision maker (our Chief Executive Officer) in order to make decisions about resources and to assess performance. The segments are evaluated based on their pre-tax operating income.

As a result of the merger with FPU in October 2009, we changed our operating segments to better reflect how the chief operating decision maker reviews the various operations of our Company. Our three operating segments are now composed of the following:

• Regulated Energy. The regulated energy segment includes natural gas distribution, electric distribution and natural gas transmission operations. All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of ESNG.

• Unregulated Energy. The unregulated energy segment includes natural gas marketing, propane distribution and propane wholesale marketing operations, which are unregulated as to their rates and services.

• Other. The “Other” segment consists primarily of the advanced information services operation, unregulated subsidiaries that own real estate leased to Chesapeake and certain corporate costs not allocated to other operations.

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The following table presents information about our reportable segments.

For the Three Months Ended March 31,	2010		2009
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	91,300	$	51,793
Unregulated Energy		59,027		49,392
Other		2,933		3,294
Total operating revenues, unaffiliated customers	$	153,260	$	104,479
Intersegment Revenues (1)
Regulated Energy	$	326	$	388
Unregulated Energy		242		2
Other		187		183
Total intersegment revenues	$	755	$	573
Operating Income (Loss)
Regulated Energy	$	17,516	$	9,497
Unregulated Energy		7,760		6,592
Other and eliminations		122		(123	)
Total operating income		25,398		15,966
Other income, net of other expenses		115		33
Interest		2,363		1,642
Income taxes		9,176		5,764
Net income	$	13,974	$	8,593

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

	March 31,		December 31,
(in thousands)	2010		2009
Identifiable Assets
Regulated energy	$	482,955	$	480,903
Unregulated energy		76,725		101,437
Other		37,264		34,724
Total identifiable assets	$	596,944	$	617,064

Our operations are almost entirely domestic. Our advanced information services subsidiary, BravePoint, has infrequent transactions in foreign countries, primarily Canada, which are denominated and paid in U.S. dollars. These transactions are immaterial to the consolidated revenues.

6. Employee Benefit Plans

Net periodic benefit costs for our pension and post-retirement benefits plans for the three months ended March 31, 2010 and 2009 are set forth in the following table:

														Chesapeake
	Chesapeake						FPU			Chesapeake				Postretirement				FPU
	Pension Plan						Pension Plan			SERP				Plan				Medical Plan
For the Three Months Ended March 31,	2010			2009			2010			2010		2009		2010		2009		2010
(in thousands)
Service Cost	$	—		$	—		$	—		$	—	$	—	$	—	$	—	$	28
Interest Cost		145			140			638			34		32		30		27		34
Expected return on plan assets		(106	)		(86	)		(619	)		—		—		—		—		—
Amortization of prior service cost		(1	)		(1	)		—			5		3		—		—		—
Amortization of net loss		39			68			—			16		15		15		40		—
Net periodic cost	$	77		$	121		$	19		$	55	$	50	$	45	$	67	$	62

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We expect to record pension and postretirement benefit costs of approximately $1.0 million for 2010 of which $320,000 is attributable to FPU’s pension and medical plans. In addition, we expect to contribute $450,000 and $1.6 million to the Chesapeake and FPU pension plans, respectively, in 2010, of which $377,000 has been contributed for the FPU pension plan during the three months ended March 31, 2010. The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake SERP for the three months ended March 31, 2010, were $22,000; for the year 2010, such benefits paid are expected to be approximately $88,000. Cash benefits paid for the Chesapeake Postretirement Plan and the FPU Medical Plan, primarily for medical claims, for the three months ended March 31, 2010, totaled $17,000 and $20,000, respectively; for the year 2010, we have estimated that approximately $115,000 and $144,000, respectively, will be paid for such benefits.

On March 23, 2010, the Patient Protection and Affordable Care Act was signed into law. On March 30, 2010, a companion bill, the Health Care and Education Reconciliation Act of 2010, was also signed into law. Among other things, these new laws, when taken together, reduce the tax benefits available to an employer that receives the Medicare Part D subsidy. The deferred tax effects of the reduced deductibility of the postretirement prescription drug coverage must be recognized in the period these new laws were enacted. The FPU Medical Plan receives the Medicare Part D subsidy. We assessed the deferred tax effects on the reduced deductibility as a result of these new laws during the three months ended March 31, 2010 and determined that the deferred tax effects were not material to our financial results.

7. Investments

The investment balance at March 31, 2010 represents a Rabbi Trust associated with our Supplemental Executive Retirement Savings Plan and a Rabbi Trust related to a stay bonus agreement with a former executive. We classify these investments as trading securities and report them at their fair value. Any unrealized gains and losses, net of other expenses, are included in other income in the condensed consolidated statements of income. We also have an associated liability that is recorded and adjusted each month for the gains and losses incurred by the Rabbi Trusts. At March 31, 2010 and December 31, 2009, total investments had a fair value of $2.0 million.

8. Share-Based Compensation

Our non-employee directors and key employees are awarded share-based awards through our Directors Stock Compensation Plan (“DSCP”) and the Performance Incentive Plan (“PIP”), respectively. We record these share-based awards as compensation costs over the respective service period for which services are received in exchange for an award of equity or equity-based compensation. The compensation cost is based on the fair value of the grant on the date it was awarded.

The table below presents the amounts included in net income related to share-based compensation expense for the awards granted under the DSCP and the PIP for the three months ended March 31, 2010 and 2009.

For the Three Months Ended March 31,	2010		2009
(in thousands)
Directors Stock Compensation Plan	$	64	$	47
Performance Incentive Plan		269		194
Total compensation expense		333		241
Less: tax benefit		134		97
Share-Based Compensation amounts included in net income	$	199	$	144

Directors Stock Compensation Plan

Shares granted under the DSCP are issued in advance of the directors’ service periods and are fully vested as of the date of the grant. We record a prepaid expense of the shares issued and amortize the expense equally over a service period of one year. No additional shares were granted under the DSCP during the three months ended March 31, 2010.

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Performance Incentive Plan

The table below presents the summary of the stock activity for the PIP for the three months ended March 31, 2010:

			Weighted Average
	Number of Shares		Fair Value
Outstanding — December 31, 2009		123,075	$	28.15
Granted		40,875	$	28.83
Vested		43,960		27.94
Fortfeited		—		—
Expired		18,840		27.94
Outstanding — March 31, 2010		101,150	$	28.56

In January 2010, the Board of Directors granted awards under the PIP for 40,875 shares. The shares granted in January 2010 are multi-year awards, 8,000 shares of which will vest at the end of the two-year service period, or December 31, 2011. The remaining 32,875 shares will vest at the end of the three-year service period, or December 31, 2012. These awards are based upon the achievement of long-term goals, development and our success, and they comprise both market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the date of the grant. For the market-based conditions, we used the Monte-Carlo pricing model to estimate the fair value of each market-based award granted.

At March 31, 2010, the aggregate intrinsic value of the PIP awards was $1.5 million.

9. Derivative Instruments

We use derivative and non-derivative contracts to engage in trading activities and manage risks related to obtaining adequate supplies and the price fluctuations of natural gas and propane. Our natural gas and propane distribution operations have entered into agreements with suppliers to purchase natural gas and propane for resale to their customers. Purchases under these contracts either do not meet the definition of derivatives or are considered “normal purchases and sales” and are accounted for on an accrual basis. Our propane distribution operation may also enter into fair value hedges of its inventory in order to mitigate the impact of wholesale price fluctuations. As of March 31, 2010, our natural gas and propane distribution operations did not have any outstanding derivative contracts.

Xeron, our propane wholesale and marketing operation, engages in trading activities using forward and futures contracts. These contracts are considered derivatives and have been accounted for using the mark-to-market method of accounting. Under the mark-to-market method of accounting, the trading contracts are recorded at fair value, net of future servicing costs, and the changes in fair value of those contracts are recognized as unrealized gains or losses in the statement of income in the period of change. As of March 31, 2010, we had the following outstanding trading contracts which we accounted for as derivatives:

	Quantity in		Estimated Market		Weighted Average
At March 31, 2010	gallons		Prices		Contract Prices
Forward Contracts
Sale		9,870,000	$	1.0900 — $1.19250	$	1.1235
Purchase		10,374,000	$	1.0675 — $1.19093	$	1.1169

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

All contracts expire within the second quarter of 2010.

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We did not have any derivative contracts with a credit-risk-related contingency.

Fair values of the derivative contracts recorded in the condensed consolidated balance sheet as of March 31, 2010 and December 31, 2009, are the following:

	Asset Derivatives
		Fair Value
(in thousands)	Balance Sheet Location	March 31, 2010		December 31, 2009
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy assets	$	198	$	2,379
Put option (1)	Mark-to-market energy assets		—		—
Total asset derivatives		$	198	$	2,379

	Liability Derivatives
		Fair Value
(in thousands)	Balance Sheet Location	March 31, 2010		December 31, 2009
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy liabilities	$	118	$	2,514
Total liability derivatives		$	118	$	2,514

⁽¹⁾ We purchased a put option for the Pro-Cap (propane price cap) plan in September 2009. The put option expired on March 31, 2010. The put option had a fair value of $0 at December 31, 2009.

The effects of gains and losses from derivative instruments on the condensed consolidated statements of income for the three months ended March 31, 2010 and 2009, are the following:

	Amount of Gain (Loss) on Derivatives:
	Location of Gain	For the Three Months Ended March 31,
(in thousands)	(Loss) on Derivatives	2010		2009
Derivatives designated as fair value hedges
Propane swap agreement (1)	Cost of Sales	$	—	$	(42	)
Derivatives not designated as fair value hedges
Unrealized gains (losses) on forward contracts	Revenue		215		(1,294	)
Total		$	215	$	(1,336	)

⁽¹⁾ Our propane distribution operation entered into a propane swap agreement to protect it from the impact that wholesale propane price increases would have on the Pro-Cap (propane price cap) Plan that was offered to customers. We terminated this swap agreement in January 2009.

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The effects of trading activities on the condensed consolidated statements of income for the three months ended March 31, 2010 and 2009, are the following:

		Amount of Trading Revenue:
	Location in the	For the Three Months Ended March 31,
(in thousands)	Statement of Income	2010		2009
Realized gains on forward contracts	Revenue	$	677	$	1,782
Unrealized gains (losses) on forward contracts	Revenue		215		(1,294	)
Total		$	892	$	488

10. Fair Value of Financial Instruments

GAAP 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 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).

The following table summarizes our 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 March 31, 2010:

			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	$	2,040	$	2,040	$	—	$	—
Mark-to-market energy assets	$	198	$	—	$	198	$	—
Liabilities:
Mark-to-market energy liabilities	$	118	$	—	$	118	$	—

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The following table summarizes our 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, 2009:

			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	$	1,959	$	1,959	$	—	$	—
Mark-to-market energy assets, including put option	$	2,379	$	—	$	2,379	$	—
Liabilities:
Mark-to-market energy liabilities	$	2,514	$	—	$	2,514	$	—

The following valuation techniques were used to measure fair value assets in the table above on a recurring basis as of March 31, 2010 and December 31, 2009:

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 put option — The fair value of the propane put option is valued using market transactions for similar assets and liabilities in either the listed or OTC markets.

At March 31, 2010, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.

Other Financial Assets and Liabilities

Financial assets with carrying values approximating fair value include cash and cash equivalents and accounts receivable. Financial liabilities with carrying values approximating fair value include accounts payable and other accrued liabilities and short-term debt. The carrying value of these financial assets and liabilities approximates fair value due to their short maturities and because interest rates approximate current market rates for short-term debt.

At March 31, 2010, long-term debt, which includes the current maturities of long-term debt, had a carrying value of $107.1 million, compared to a fair value of $119.6 million, using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, with adjustments for duration, optionality, and risk profile. At December 31, 2009, long-term debt, including the current maturities, had a carrying value of $134.1 million, compared to the estimated fair value of $145.5 million.

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11. Long Term Debt

Our outstanding long-term debt is shown below:

	March 31,			December 31,
(in thousands)	2010			2009
Secured first mortgage bonds:
9.57% bond, due May 1, 2018	$	8,156		$	8,156
10.03% bond, due May 1, 2018		4,486			4,486
9.08% bond, due June 1, 2022		7,950			7,950
6.85% bond, due October 1, 2031		—			14,012
4.90% bond, due November 1, 2031		—			13,222
Uncollateralized senior notes:
6.91% note, due October 1, 2010		909			909
6.85% note, due January 1, 2012		2,000			2,000
7.83% note, due January 1, 2015		10,000			10,000
6.64% note, due October 31, 2017		21,818			21,818
5.50% note, due October 12, 2020		20,000			20,000
5.93% note, due October 31, 2023		30,000			30,000
Convertible debentures:
8.25% due March 1, 2014		1,484			1,520
Promissory notes		310			40
Total long-term debt		107,113			134,113
Less: current maturities		(8,125	)		(35,299	)
Total long-term debt, net of current maturities	$	98,988		$	98,814

In January 2010, we redeemed the 6.85 percent and 4.90 percent series of FPU’s secured first mortgage bonds prior to their respective maturity for $29.1 million, which included the outstanding principal balances, interest accrued, premium and fees. We used short-term borrowing to finance the redemption of these bonds. The difference between the carrying value of those bonds and the amount paid at redemption, totaling $1.5 million, was deferred as a regulatory asset as allowed by the Florida PSC.

We initially used our existing short-term borrowing facilities to finance the redemption of those bonds. On March 16, 2010, we entered into a new $29.1 million term loan credit facility with an existing lender to continue to finance the redemption. We borrowed $29.1 million for a nine-month period under this new facility, which bears interest at 1.88 percent per annum. We are currently in discussions with an existing noteholder for the long-term financing of the redeemed bonds.

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations is designed to provide a reader of the financial statements with a narrative report on our financial condition, results of operations and liquidity. This discussion and analysis should be read in conjunction with the attached unaudited condensed consolidated financial statements and notes thereto and our Annual Report on Form 10-K for the year ended December 31, 2009, including the audited consolidated financial statements and notes thereto.

Safe Harbor for Forward-Looking Statements

We make statements in this Quarterly Report on Form 10-Q that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “project,” “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “continue,” “potential,” “forecast” or other similar words, or future or conditional verbs such as “may,” “will,” “should,” “would” or “could.” These statements represent our intentions, plans, expectations, assumptions and beliefs about future financial performance, business strategy, projected plans and objectives of the Company. These statements are subject to many risks, uncertainties and other important factors that could cause actual results to differ materially from those expressed in the forward-looking statements. Such factors include, but are not limited to:

• state and federal legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures, and affect the speed at and degree to which competition enters the electric and natural gas industries (including deregulation);

• the outcomes of regulatory, tax, environmental and legal matters, including whether pending matters are resolved within current estimates;

• industrial, commercial and residential growth or contraction in our service territories;

• the weather and other natural phenomena, including the economic, operational and other effects of hurricanes and ice storms;

• the timing and extent of changes in commodity prices and interest rates;

• general economic conditions, including any potential effects arising from terrorist attacks and any consequential hostilities or other hostilities or other external factors over which we have no control;

• changes in environmental and other laws and regulations to which we are subject;

• the results of financing efforts, including our ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings and general economic conditions;

• declines in the market prices of equity securities and resultant cash funding requirements for our defined benefit pension plans;

• the creditworthiness of counterparties with which we are engaged in transactions;

• growth in opportunities for our business units;

• the extent of success in connecting natural gas and electric supplies to transmission systems and in expanding natural gas and electric markets;

• the effect of accounting pronouncements issued periodically by accounting standard-setting bodies;

• conditions of the capital markets and equity markets during the periods covered by the forward-looking statements;

• the ability to successfully execute, manage and integrate merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture;

• the ability to manage and maintain key customer relationships;

• the ability to maintain key supply sources;

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• the effect of spot, forward and future market prices on our distribution, wholesale marketing and energy trading businesses;

• the effect of competition on our businesses;

• the ability to construct facilities at or below estimated costs;

• changes in technology affecting our advanced information services business; and

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

The following discussions and 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 cost of natural gas, electricity and propane and the cost of labor spent on direct revenue-producing activities. Gross margin should not be considered an alternative to operating income or net income, which are determined in accordance with GAAP. We believe 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 energy operations and under its competitive pricing structure for unregulated natural gas marketing and propane distribution operations. Our management uses gross margin in measuring our business units’ performance and has historically analyzed and reported gross margin information publicly. Other companies may calculate gross margin in a different manner.

In addition, certain information is presented, which, for comparison purposes, includes only FPU’s results of operations or excludes FPU’s results from the consolidated results of operations for the first quarter of 2010. Although non-GAAP measures are not intended to replace the GAAP measures for evaluation of our performance, we believe that the portions of the presentation, which include only the FPU results, or which excludes FPU’s financial results for the post-merger period, provide helpful comparisons for an investor’s evaluation purposes.

Introduction

We are a diversified utility company engaged, directly or through subsidiaries, in regulated energy businesses, unregulated energy businesses, and other unregulated businesses, including advanced information services.

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

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

• expanding the regulated energy distribution and transmission businesses through expansion into new geographic areas and providing new services 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 our 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 us to access capital as needed;

• maintaining a consistent and competitive dividend for shareholders; and

• creating and maintaining a diversified customer base, energy portfolio and utility foundation.

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

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As a result of the merger with FPU in October 2009, we changed our operating segments to better reflect how the chief operating decision maker (our Chief Executive Officer) reviews the various operations of the Company. Our three operating segments are now composed of the following:

• Regulated Energy. The regulated energy segment includes natural gas distribution, electric distribution and natural gas transmission operations. All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of ESNG.

• Unregulated Energy. The unregulated energy segment includes natural gas marketing, propane distribution and propane wholesale marketing operations, which are unregulated as to their rates and services.

• Other. The “Other” segment consists primarily of the advanced information services operation, unregulated subsidiaries that own real estate leased to Chesapeake and certain corporate costs not allocated to other operations.

We revised the segment information for the quarter ended March 31, 2009 to reflect the new operating segments.

Overview and Highlights

Our net income for the quarter ended March 31, 2010 was $14.0 million, or $1.47 per share (diluted). This represents an increase of $5.4 million, compared to a net income of $8.6 million, or $1.24 per share (diluted), reported in the same period in 2009.

For the Three Months Ended March 31,	2010		2009			Change
(in thousands)
Operating Income (Loss):
Regulated Energy	$	17,516	$	9,497		$	8,019
Unregulated Energy		7,760		6,592			1,168
Other & eliminations		122		(123	)		245
Operating Income		25,398		15,966			9,432
Other Income, net of expenses		115		33			82
Interest Charges		2,363		1,642			721
Income Taxes		9,176		5,764			3,412
Net Income	$	13,974	$	8,593		$	5,381

The increased period-over-period operating results reflect an increase of $21.1 million in gross margin and an increase of $11.7 million in other operating expenses.

FPU Results

Our results for the first quarter of 2010 included approximately $4.5 million in net income contributed by FPU. Pursuant to the acquisition method of accounting, we consolidated FPU’s results into our results from October 28, 2009, which is the effective date of the merger. Therefore, our results for the first quarter of 2009 did not include any results from FPU. The following is a summary of FPU’s results for the quarter ended March 31, 2010 included in our consolidated results.

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For the Three Months Ended March 31, 2010
(in thousands)
Operating Income:
Regulated Energy	$	6,690
Unregulated Energy		1,362
Operating Income		8,052
Other Income, net of expenses		59
Interest Charges		893
Income Taxes		2,756
Net Income	$	4,462
Heating degree-days (“HDD”):
Actual		933
10-year average (normal)		564

FPU’s operating results by business for the quarter ended March 31, 2010 are presented in the following table:

	Regulated Energy				Unregulated Energy
For the Three Months Ended March 31, 2010	Natural Gas		Electric		Propane		Other
(in thousands)
Revenue	$	23,163	$	24,255	$	6,228	$	581
Cost of fuel		11,332		19,628		2,991		339
Gross margin		11,831		4,627		3,237		242
Other operating expenses		6,389		3,379		2,018		99
Operating Income	$	5,442	$	1,248	$	1,219	$	143
Average number of residential customers		52,071		30,916		13,742		—

FPU’s results for the first quarter of 2010 were positively affected by the increased natural gas and propane sales driven primarily by the colder than normal temperatures in Florida compared to the prior year, the increased natural gas gross margin resulting from the settlement of the permanent rate increase proceeding and lower interest expense following the redemption of two outstanding bond series and refinancing at short-term rates after the merger. FPU’s propane results for the first quarter of 2010 also include approximately $390,000 in gross margin generated from customers transferred from Chesapeake to FPU after the merger in an effort to integrate operations.

Other Key Factors

The following is a summary of other key factors affecting our businesses and their impacts on our results in the first quarter of 2010. More detailed discussion and analysis are provided in the following section as we discuss our results by segment.

• Weather. Temperatures on the Delmarva Peninsula during the first quarter of 2010 were four-percent colder than the same period in 2009 and nine-percent colder than normal (10-year average). The colder weather on the Delmarva Peninsula generated approximately $300,000 in additional gross margin in the first quarter of 2010 compared to the same period in 2009. The colder weather throughout Florida in the first quarter of 2010 also positively affected gross margins from the Florida operations.

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• Growth. Our Delmarva natural gas distribution operation experienced two-percent residential customer growth in the first quarter of 2010. Including the increase in commercial and industrial customers, growth in our Delmarva natural gas distribution operation contributed approximately $443,000 in period-over-period additional gross margin. New transmission services and new expansion facilities placed in service during 2009 by our natural gas transmission subsidiary, ESNG, contributed an additional gross margin of $323,000 in the first quarter of 2010 compared to the same period in 2009. Chesapeake’s Florida natural gas distribution division experienced a period-over-period net customer loss, primarily from the loss of several large industrial customers in 2009 due to economic conditions in the region, which decreased gross margin by $34,000.

• Rates and Regulatory Matters. In December 2009, the Florida PSC approved a permanent rate increase of approximately $2.5 million, applicable to all meters read on or after January 14, 2010, for Chesapeake’s Florida natural gas distribution division. The rate increase contributed an additional gross margin of $600,000 in the first quarter of 2010 compared to the same period in 2009.

• Propane Prices. During the first half of 2009, our Delmarva propane distribution operation benefited from increased margin generated from the lower propane costs, largely attributable to inventory valuation adjustments in late 2008. The average propane cost in the first quarter of 2010 was 28 percent higher than the average propane cost in the same period in 2009, which decreased gross margin by $614,000. Increased volatility in wholesale propane prices provided opportunities for our propane wholesale marketing subsidiary, Xeron, as its trading volume increased by 12 percent in the first quarter of 2010 compared to the same period in 2009, increasing its gross margin by $405,000.

• Natural Gas Spot Sale Opportunities. During the first quarter of 2009, our unregulated natural gas marketing subsidiary, PESCO, benefited from increased spot sales on the Delmarva Peninsula. Although PESCO continued to identify spot sale opportunities on the Delmarva Peninsula during the first quarter of 2010, the decreased spot sales, largely due to reduced sales to one industrial customer, resulted in a decrease in gross margin of $599,000 in the first quarter of 2010 compared to the same period in 2009. Spot sales are not predictable, and, therefore, are not included in our long-term financial plans or forecasts.

• Other Operating Expenses. Our other operating expenses, excluding expenses reported by FPU, decreased by $175,000 in the first quarter of 2010 compared to the same period in 2009. Lower expenses related to collection and allowance for doubtful accounts receivable and cost containment measures implemented throughout 2009 for the advanced information services operation more than fully offset the increases in other operating expenses related to increased compensation and increased costs associated with increased capital investments.

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Regulated Energy

For the Three Months Ended March 31,	2010		2009		Change
(in thousands)
Revenue	$	91,626	$	52,181	$	39,445
Cost of sales		53,768		32,513		21,255
Gross margin		37,858		19,668		18,190
Operations & maintenance		13,531		6,951		6,580
Depreciation & amortization		4,504		1,792		2,712
Other taxes		2,307		1,428		879
Other operating expenses		20,342		10,171		10,171
Operating Income	$	17,516	$	9,497	$	8,019
Statistical Data — Delmarva Peninsula
Heating degree-days (“HDD”) (1):
Actual		2,543		2,453		90
10-year average (normal)		2,336		2,306		30
Estimated gross margin per HDD	$	2,429	$	1,937	$	492
Per residential customer added:
Estimated gross margin	$	375	$	375	$	—
Estimated other operating expenses	$	105	$	103	$	2
Residential Customer Information
Average number of customers (1):
Delmarva		48,184		47,379		805
Florida — Chesapeake		13,465		13,473		(8	)
Total		61,649		60,852		797

⁽¹⁾ Heating degree-days and average number of residential customers for FPU are included in the discussions of FPU’s results on page 29.

Operating income for the regulated energy segment increased by approximately $8.0 million, or 84 percent, in the first quarter of 2010, compared to the same period in 2009, which was generated from a gross margin increase of $18.2 million, offset partially by an operating expense increase of $10.2 million.

Gross Margin

Gross margin for our regulated energy segment increased by $18.2 million, or 92 percent. FPU’s natural gas and electric distribution operations had $11.8 million and $4.6 million in gross margin, respectively, in the first quarter of 2010, which contributed to this increase.

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The natural gas distribution operations for the Delmarva Peninsula generated an increase in gross margin of $401,000 in the first quarter of 2010. The factors contributing to this increase are as follows:

• The Delmarva natural gas distribution operations experienced growth in residential, commercial and industrial customers, which contributed $443,000 to the gross margin increase. Residential, commercial and industrial growth by our Delaware division contributed $219,000, $76,000 and $51,000, respectively, to the gross margin increase, and commercial growth by our Maryland division contributed $104,000, to the gross margin increase. We experienced a two-percent increase in residential customers by the Delmarva natural gas distribution operation during the first quarter, and we expect that growth rate to continue in the near future.

• Colder weather on the Delmarva Peninsula generated an additional $200,000 to the gross margin as heating degree-days increased by four percent over the previous first quarter. Residential heating rates for the Maryland division are weather-normalized, and we typically do not experience an impact on gross margin from the weather for our residential customers in Maryland.

• Increases in gross margin were partially offset by a net decrease of $128,000 as a result of changes in customer rates and rate classes. Rates and rate classes for a commercial and an industrial customer in Maryland and certain residential customers in Delaware were revised in late 2009 and in the first quarter of 2010, based upon our review of their consumption, the prices of alternative fuels and a corresponding change in their rate, which led to this decrease.

• In addition, a decrease of $101,000 in gross margin was attributable to the decline in non-weather related customer consumption. The decrease in consumption is a result of conservation primarily by residential customers.

Chesapeake’s Florida natural gas distribution operation, excluding FPU, experienced an increase in gross margin of $892,000 in the first quarter of 2010. Approximately $600,000 of this increase was attributable to a permanent rate increase approved on December 15, 2009 (applicable to all meters read on or after January 14, 2010) by the Florida PSC. The increase was also attributable to increased customer consumption, which was heavily affected by the colder weather in Florida in the first quarter of 2010 and contributed $245,000 to the gross margin during the period. A decrease of $34,000 in gross margin due primarily to a loss of several large industrial customers in 2009 due to economic conditions in the region, was almost fully offset by an increase in gross margin of $33,000 attributable to increased consumption by existing industrial customers. Also gross margin increased by $41,000 as a result of changes in rates for certain customers.

The natural gas transmission operations achieved gross margin growth of $439,000 in the first quarter of 2010. The factors contributing to this increase are as follows:

• New long-term transmission services implemented by ESNG in November 2009 as a result of the completion of its latest expansion program provided for an additional 6,957 Mcfs per day and added $254,000 to gross margin in the first quarter of 2010.

• New long-term firm transmission service agreements with an industrial customer for the period from November 2009 to October 2012 provided for an additional 9,662 Mcfs per day for the period January 1, 2010 through February 5, 2010, and an additional 2,705 Mcfs per day for the period February 6, 2010 through March 31, 2010. They added $153,000 to gross margin in the first quarter of 2010.

• In April 2009, ESNG changed its rates to recover specific project costs in accordance with the terms of precedent agreements with certain customers. These new rates generated $127,000 in gross margin in the first quarter of 2010. ESNG is currently in discussions with those customers to potentially reduce the period over which ESNG will recover its specific project costs in accordance with the terms of the precedent agreements.

• ESNG received notice from a customer of its intention not to renew two firm transmission service contracts, which expired in October 2009 and March 2010, respectively, which decreased its gross margin by $84,000 in the first quarter of 2010.

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Other Operating Expenses

Other operating expenses for the regulated energy segment increased by $10.2 million, or 100 percent, in the first quarter of 2010 compared to the same period in 2009, of which $9.8 million was related to other operating expenses of FPU’s regulated energy segment during the period. The remaining increase in other operating expenses is due primarily to the following factors:

• Deprecation, asset removal costs and property taxes increased by $244,000 as a result of our increased capital investments made in 2009 and 2010 to support growth.

• Payroll and benefits increased by $166,000 due primarily to annual salary increases and increased incentive pay as a result of improved performance.

• Consulting expenses related to various regulatory proceedings involving our natural gas distribution operations increased by $107,000 during the quarter.

Other Developments

The following developments, which are not discussed above, may affect the future operating results of the regulated energy segment:

• On March 15, 2010, we announced the signing of an agreement with an industrial customer to provide natural gas service to its poultry plant in southern Delaware. The anticipated annual margin from this agreement equates to approximately 850 average residential heating customers. The service is expected to begin in early 2011. This also provides us with an opportunity to extend our natural gas distribution and transmission infrastructures to serve other potential customers in the same area.

• On April 8, 2010, we entered into a Precedent Agreement with TETLP to secure firm transportation service from TETLP in conjunction with its new expansion project. The Precedent Agreement provides that, upon satisfaction of certain conditions, the parties will execute two firm transportation service contracts, one for our Delaware division and one for our Maryland division, for 30,000 and 10,000 Dts/d, respectively, to be effective on the service commencement date of the project, currently projected to occur in November 2012. Commencement of service and TETLP’s and our rights and obligations under the two firm transportation service contracts are subject to satisfaction of various conditions specified in the Precedent Agreement. As a result of this new service, our Delaware and Maryland divisions will have access to new supplies of natural gas, providing increased reliability and diversity. This will also provide them additional upstream transportation capacity, which is essential to meet their current customer demands and to plan for sustainable growth. The Precedent Agreement with TETLP is fully described in Note 4, “Commitments and Contingencies,” to these unaudited condensed consolidated financial statements.

Unregulated Energy

For the Three Months Ended March 31,	2010		2009		Change
(in thousands)
Revenue	$	59,269	$	49,394	$	9,875
Cost of sales		43,958		37,088		6,870
Gross margin		15,311		12,306		3,005
Operations & maintenance		6,026		4,905		1,121
Depreciation & amortization		1,046		514		532
Other taxes		479		295		184
Other operating expenses		7,551		5,714		1,837
Operating Income	$	7,760	$	6,592	$	1,168
Statistical Data — Delmarva Peninsula
Heating degree-days (“HDD”):
Actual		2,543		2,453		90
10-year average (normal)		2,336		2,306		30
Estimated gross margin per HDD	$	3,083	$	2,465	$	618

Operating income for the unregulated energy segment increased by approximately $1.2 million, or 18 percent, in the first quarter of 2010 compared to the same period in 2009, which was attributable to a gross margin increase of $3.0 million, offset partially by an operating expense increase of $1.8 million.

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Gross Margin

Gross margin for our unregulated energy segment increased by $3.0 million, or 24 percent, in the first quarter of 2010, compared to the same period in 2009. FPU’s unregulated energy operation, which is primarily its propane distribution operation, contributed $3.1 million, net of approximately $390,000 generated from customers previously served by Chesapeake, as certain Chesapeake propane customers are now served by FPU after the merger in an effort to integrate operations.

Chesapeake’s propane distribution operation, excluding FPU, now consists primarily of our Delmarva propane distribution operation. This operation experienced an increase in gross margin of $111,000, net of the $390,000 generated from customers previously served by Chesapeake who are now served by FPU. The factors contributing to this change are as follows:

• Temperatures on the Delmarva Peninsula were four-percent colder in the first quarter of 2010, compared to the same period in 2009, which generated an additional $100,000 of gross margin.

• Non-weather related volumes sold in the first quarter of 2010 increased by 1.1 million gallons, or eight percent, and provided for an increase in gross margin of approximately $497,000. The increase in non-weather related volumes was related to the addition of 390 community gas system customers and 1,000 additional retail customers acquired in February 2010 as part of the purchase of the operating assets of a regional propane distributor serving the Northampton and Accomack Counties in Virginia areas, which contributed $131,000 and $92,000 in gross margins during the quarter, respectively. Also contributing to the increase was $274,000 in additional gross margins related to the timing of propane deliveries to certain customers.

• Other fees contributed $127,000 due primarily to the continued growth and successful implementation of various customer loyalty programs.

• Partially offsetting the increases described above was a decline in propane margin per gallon. During the first quarter, our propane distribution operations experienced a decreased margin generated by higher propane costs, which were 28-percent higher than the average propane cost in the same period of 2009. This increase in the propane cost per gallon decreased margin by $614,000 during the first quarter.

Xeron, our propane wholesale marketing operation, experienced an increase in gross margin of $405,000 in the first quarter of 2010. Increased volatility in wholesale propane prices during the first quarter of 2010, compared to the same period in 2009, increased Xeron’s trading opportunities as Xeron’s trading volume increased by 12 percent. Also contributing to the increase were the significant wholesale propane price declines during the first quarter of 2009, which negatively affected Xeron’s gross margin from trading activity in that period.

During the first quarter of 2009, our unregulated natural gas marketing subsidiary, PESCO, benefited from increased spot sales on the Delmarva Peninsula. Although PESCO continued to identify spot sale opportunities on the Delmarva Peninsula during the first quarter of 2010, the decreased spot sales, largely due to reduced sales to one industrial customer, resulted in a decrease in gross margin of $599,000 in the first quarter of 2010 compared to the same period in 2009. Spot sales are not predictable, and, therefore, are not included in our long-term financial plans or forecasts.

Other Operating Expenses

Total “Other” operating expenses for the unregulated energy segment increased by $1.8 million in 2010, of which $2.1 million was related to other operating expenses of FPU during the first quarter of 2010. Excluding FPU, total “Other” operating expenses decreased, due primarily to increased efforts to collect receivables for the natural gas marketing operations which resulted in a decrease in bad debt expense of $239,000.

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Other

For the Three Months Ended March 31,	2010		2009			Change
(in thousands)
Revenue	$	2,365	$	2,904		$	(539	)
Cost of sales		1,133		1,621			(488	)
Gross margin		1,232		1,283			(51	)
Operations & maintenance		838		1,004			(166	)
Transaction-related costs		19		114			(95	)
Depreciation & amortization		73		78			(5	)
Other taxes		180		210			(30	)
Other operating expenses		1,110		1,406			(296	)
Operating Income (Loss)	$	122	$	(123	)	$	245

Note:  Eliminations are entries required to eliminate activities between business segments from the consolidated results.

Operating income for the “Other” segment increased by approximately $245,000 in the first quarter of 2010 compared to the same period in 2009.

Gross margin

The period-over-period decrease in gross margin for the “Other” segment was a result of a decrease in consulting revenues by the advanced information services operation due to a seven-percent decrease in the average consulting billing rate charged to customers, reflecting current economic conditions and information technology spending in the market. The number of billable consulting hours has remained unchanged. Despite the reduction in average consulting billing rate, the advanced information services operation was able to maintain its gross margin in the first quarter of 2010 compared to the same period in 2009 due to cost containment actions implemented in March, September and October 2009 and an increase in revenue and gross margin of $45,000 from its professional database monitoring and support solution services.

Operating expenses

“Other” operating expenses decreased by $296,000 in the first quarter of 2010. The decrease in operating expenses was attributable primarily to the cost containment actions, including layoffs and compensation adjustments, implemented by the advanced information services operation in March, September and October 2009 that reduced costs to offset the decline in revenues. In addition, we recorded lower merger-related costs in the first quarter of 2010.

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Interest Expense

Our total interest expense for the first quarter of 2010 increased by approximately $721,000, or 44 percent, compared to the same period in 2009. The primary drivers of the increased interest expense are related to FPU, including:

• An increase of long-term interest expense of $622,000 is related to interest on FPU’s first mortgage bonds.

• Two of the FPU series of bonds, 4.9 percent and 6.85 percent series, were redeemed by using a new short-term term loan facility at the end of January 2010. Interest expense from this short-term term loan facility during the first quarter of 2010 was $46,000.

• Additional interest expense of $173,000 is related to interest on deposits from FPU’s customers.

Offsetting the increased interest expense from FPU was lower long-term debt interest expense of $120,000 from Chesapeake’s unsecured senior notes as the principal balances decreased from scheduled payments. Short-term interest expense remained relatively unchanged as a decrease in the average short-term borrowings of $6.8 million offset an increase in the average short-term interest rate of 35 basis points.

Income Taxes

We recorded an income tax expense of $9.2 million for the three months ended March 31, 2010, compared to $5.8 million for the three months ended March 31, 2009. The increase in income tax expense primarily reflects the higher earnings for the period. The effective income tax rate for the first quarter of 2010 is 39.6 percent compared to an effective tax rate of 40.2 percent for the first quarter of 2009. The decreased effective income tax rate resulted from a greater portion of our consolidated pre-tax income having been generated from entities in states with lower income tax rates, largely as a result of our expansion in Florida operations through the merger with FPU.

Financial Position, Liquidity and Capital Resources

Our capital requirements reflect the capital-intensive nature of our business and are principally attributable to investment in new plant and equipment and retirement of outstanding debt. We rely on cash generated from operations, short-term borrowing, and other sources to meet normal working capital requirements and to finance capital expenditures.

During the first quarter of 2010, net cash provided by operating activities was $46.4 million, cash used in investing activities was $6.8 million, and cash used in financing activities was $32.3 million.

During the first quarter of 2009, net cash provided by operating activities was $31.0 million, cash used in investing activities was $4.1 million, and cash used in financing activities was $25.2 million.

As of March 31, 2010, we had four unsecured bank lines of credit with two financial institutions, for a total of $100.0 million, two of which totaling $60.0 million are available under committed lines of credit. None of the unsecured bank lines of credit requires compensating balances. These bank lines are available to provide funds for our short-term cash needs to meet seasonal working capital requirements and to fund temporarily portions of the capital expenditure program. We are currently authorized by our Board of Directors to borrow up to $85.0 million of short-term debt, as required, from these short-term lines of credit. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks. In addition to the four unsecured bank lines of credit, we entered into a new credit facility for $29.1 million with one of the financial institutions in March 2010. We borrowed $29.1 million under this new credit facility for a term of nine months to finance the early redemption of two series of FPU’s secured first mortgage bonds. The outstanding balance of short-term borrowing at March 31, 2010 and December 31, 2009 was $29.1 and $30.0 million, respectively.

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We have budgeted $53.9 million for capital expenditures during 2010. This amount includes $49.2 million for the regulated energy segment, $3.3 million for the unregulated energy segment and $1.4 million for the “Other” segment. The amount for the regulated energy segment includes estimated capital expenditures for the following: natural gas distribution operation ($20.2 million), natural gas transmission operation ($25.4 million) and electric distribution operation ($3.6 million) for expansion and improvement of facilities. The amount for the unregulated energy segment includes estimated capital expenditures for the propane distribution operations for customer growth and replacement of equipment. The amount for the “Other” segment includes an estimated capital expenditure of $288,000 for the advanced information services operation with the remaining balance for other general plant, computer software and hardware. We expect to fund the 2010 capital expenditures program from short-term borrowing, cash provided by operating activities, and other sources. The capital expenditure program is subject to continuous review and modification. Actual capital requirements may vary from the above estimates due to a number of factors, including changing economic conditions, customer growth in existing areas, regulation, new growth or acquisition opportunities and availability of capital.

Capital Structure

The following presents our capitalization, excluding short-term borrowing, as of March 31, 2010 and December 31, 2009:

	March 31,				December 31,
(in thousands)	2010				2009
Long-term debt, net of current maturities	$	98,988	31	%	$	98,814	32	%
Stockholders’ equity		221,181	69	%		209,781	68	%
Total capitalization, excluding short-term debt	$	320,169	100	%	$	308,595	100	%

At March 31, 2010, common equity represented 69 percent of total capitalization, excluding short-term borrowing, compared to 68 percent at December 31, 2009. If short-term borrowing and the current portion of long-term debt were included in total capitalization, the equity component of our capitalization would have been 62 percent at March 31, 2010, compared to 56 percent at December 31, 2009.

We remain committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access capital markets when required. This commitment, along with adequate and timely rate relief for our regulated operations, is intended to ensure our ability to attract capital from outside sources at a reasonable cost. We believe that the achievement of these objectives will provide benefits to our customers, creditors and investors.

Cash Flows Provided By Operating Activities

Cash flows provided by operating activities were as follows:

For the Three Months Ended March 31,	2010		2009
(in thousands)
Net Income	$	13,974	$	8,593
Non-cash adjustments to net income		6,689		4,299
Changes in assets and liabilities		25,746		18,144
Net cash provided by operating activities	$	46,409	$	31,036

During the three months ended March 31, 2010 and 2009, net cash flow provided by operating activities was $46.4 million and $31.0 million, respectively, a period-over-period increase of $15.4 million. FPU’s operating activities in the first quarter of 2010 contributed $19.1 million to the period-over-period increase. The remaining net decrease in cash flow provided by operating activities was due primarily to the following:

• Non-cash adjustment reflecting unrealized losses on commodity contracts decreased by approximately $1.5 million.

• Net cash flows from the changes in regulatory liabilities decreased by approximately $3.9 million as we experienced lower over-collection of gas costs from rate-payers for Delmarva natural gas distribution operations.

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• Net cash flows from changes in inventory decreased by approximately $2.4 million due primarily to increased commodity costs.

• Offsetting these decreases partially were: (a) increased net cash flows from customer deposits and refunds by approximately $2.3 million due to a new industrial customer for our Delmarva natural gas distribution operations requiring a large deposit and (b) higher net income by $920,000.

Cash Flows Used in Investing Activities

Net cash flows used in investing activities totaled $6.8 million and $4.1 million during the three months ended March 31, 2010 and 2009, respectively. Cash utilized for capital expenditures was $6.1 million and $4.1 million for the first three months of 2010 and 2009, respectively. Additions to property, plant and equipment in the first three months of 2010 include $2.3 million of FPU’s capital expenditures. We also paid $310,000 of the $600,000 in total consideration for the purchase of certain propane assets from a regional propane distributor during the first quarter of 2010.

Cash Flows Used by Financing Activities

Cash flows used in financing activities totaled $32.3 million and $25.2 million for the first three months of 2010 and 2009, respectively. Significant financing activities reflected in the change in cash flows used by financing activities are as follows:

• During the first three months of 2010, we repaid approximately $30.0 million of our short-term borrowings related to working capital, compared to net repayments of $23.2 million in the first three months of 2009, as we generated higher amounts of cash from operating activities.

• In January 2010, we borrowed $29.1 million from our short-term credit facilities to redeem two series of FPU’s secured first mortgage bonds prior to their respective maturities. We paid $28.9 million, including fees and penalties, related to the redemption.

• We paid $2.7 million and $1.8 million in cash dividends for the three months ended March 31, 2010 and 2009, respectively. Dividends paid in the first quarter of 2010 increased as a result of growth in the annualized dividend rate and in the number of shares outstanding.

Off-Balance Sheet Arrangements

We have issued corporate guarantees to certain vendors of our subsidiaries, primarily the propane wholesale marketing subsidiary and the natural gas marketing subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. None of these subsidiaries have ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in our financial statements when incurred. The aggregate amount guaranteed at March 31, 2010 was $24.2 million, with the guarantees expiring on various dates in 2010.

In addition to the corporate guarantees, we have issued a letter of credit to our primary insurance company for $725,000, which expires on August 31, 2010. The letter of credit is provided as security to satisfy the deductibles under our various insurance policies. There have been no draws on this letter of credit as of March 31, 2010, and we do not anticipate that this letter of credit will be drawn upon by the counterparty in the future.

In April 2010, we provided a letter of credit for $363,000 under the Precedent Agreement with TETLP in April 2010 as required. The letter of credit is expected to increase quarterly as TETLP’s pre-service costs increases. The letter of credit will not exceed more than the three-month reservation charge under the firm transportation service contracts, which we currently estimate to be $2.1 million.

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Contractual Obligations

There have not been any material changes in the contractual obligations presented in our 2009 Annual Report on Form 10-K, except for commodity purchase obligations and forward contracts entered into in the ordinary course of our business. The following table summarizes the commodity and forward contract obligations at March 31, 2010.

Purchase Obligations (in thousands)	Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years		Total
Commodities (1) (3)	$	40,894	$	173	$	—	$	—	$	41,067
Propane (2)		11,586		—		—		—		11,586
Total Purchase Obligations	$	52,480	$	173	$	—	$	—	$	52,653

(1)	In addition to the obligations noted above, the natural gas distribution, the electric distribution and propane distribution operations have agreements with commodity suppliers that have provisions with no minimum purchase requirements. There are no monetary penalties for reducing the amounts purchased; however, the propane contracts allow the suppliers to reduce the amounts available in the winter season if we do not purchase specified amounts during the summer season. Under these contracts, the commodity prices will fluctuate as market prices fluctuate.
(2)	We have also entered into forward sale contracts in the aggregate amount of $11.1 million. See Part I, Item 3, “Quantitative and Qualitative Disclosures about Market Risk,” below, for further information.
(3)	In March 2009, we renewed our contract with an energy marketing and risk management company to manage a portion of our natural gas transportation and storage capacity. There were no material changes to the contract’s terms, as reported in our 2009 Annual Report on Form 10-K.

Environmental Matters

As more fully described in Note 4, “Commitments and Contingencies,” to these unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q, we continue to work with federal and state environmental agencies to assess the environmental impact and explore corrective action at seven environmental sites. We believe that future costs associated with these sites will be recoverable in rates or through sharing arrangements with, or contributions by, other responsible parties.

Other Matters

Rates and Regulatory Matters

Our natural gas distribution operations in Delaware, Maryland and Florida and electric distribution operation in Florida are subject to regulation by their respective PSC; ESNG is subject to regulation by the FERC; and Peninsula Pipeline Company, Inc. (“PIPECO”) is subject to regulation by the Florida PSC. At March 31, 2010, we were involved in rate filings and/or regulatory matters in each of the jurisdictions in which we operate. Each of these rates or regulatory matters is fully described in Note 4, “Commitments and Contingencies,” to these unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q.

Competition

Our natural gas and electric distribution operations and our natural gas transmission operation compete with other forms of energy including natural gas, electricity, oil and propane. The principal competitive factors are price and, to a lesser extent, accessibility. Our natural gas distribution operations have several large-volume industrial customers that are able to use fuel oil as an alternative to natural gas. When oil prices decline, these interruptible customers may convert to oil to satisfy their fuel requirements, and our interruptible sales volumes may decline. Oil prices, as well as the prices of other fuels, fluctuate for a variety of reasons; therefore, future competitive conditions are not predictable. To address this uncertainty, we use flexible pricing arrangements on both the supply and sales sides of this business to compete with alternative fuel price fluctuations. As a result of the transmission operation’s conversion to open access and Chesapeake’s Florida natural gas distribution division’s restructuring of its services, these businesses have shifted from providing bundled transportation and sales service to providing only transmission and contract storage services. Our electric distribution operation currently does not face substantial competition as the electric utility industry in Florida has not been deregulated. In addition, natural gas is the only viable alternative fuel to electricity in our electric service territories and is available only in a small area.

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

Our propane distribution operations compete with several other propane distributors in their respective geographic markets, primarily on the basis of service and price, emphasizing responsive and reliable service. Our competitors generally include local outlets of national distributors and local independent distributors, whose proximity to customers entails lower costs 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 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, and could adversely affect the markets for the products and services offered by these businesses. This segment competes on the basis of technological expertise, reputation and price.

Inflation

Inflation affects the cost of supply, labor, products and services required for operations, maintenance and capital improvements. While the impact of inflation has remained low in recent years, natural gas and propane prices are subject to rapid fluctuations. In the regulated natural gas and electric distribution operations, fluctuations in natural gas and electricity prices are passed on to customers through the fuel cost recovery mechanism in our tariffs. To help cope with the effects of inflation on our capital investments and returns, we seek rate increases from regulatory commissions for our regulated operations and closely monitor the returns of our unregulated business operations. To compensate for fluctuations in propane gas prices, we adjust propane selling prices to the extent allowed by the market.

Recent Authoritative Pronouncements on Financial Reporting and Accounting

Recent accounting developments and their impact on our financial position, results of operations and cash flows are described in the Recent Accounting Pronouncements section of Note 1, “Summary of Accounting Policies,” to these unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market risk represents the potential loss arising from adverse changes in market rates and prices. Long-term debt is subject to potential losses based on changes in interest rates. Our long-term debt consists of fixed-rate senior notes, secured debt and convertible debentures. All of our long-term debt is fixed-rate debt and was not entered into for trading purposes. The carrying value of long-term debt, including current maturities, was $107.1 million at March 31, 2010, as compared to a fair value of $119.6 million, based on a discounted cash flow methodology that incorporates a market interest rate that is based on published corporate borrowing rates for debt instruments with similar terms and average maturities with adjustments for duration, optionality, credit risk, and risk profile. We evaluate whether to refinance existing debt or permanently refinance existing short-term borrowing, based in part on the fluctuation in interest rates.

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Our propane distribution business is exposed to market risk as a result of propane storage activities and entering into fixed price contracts for supply. We can store up to approximately four million gallons (including leased storage and rail cars) of propane during the winter season to meet our 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, we have adopted a Risk Management Policy that allows the propane distribution operation to enter into fair value hedges or other economic hedges of our inventory.

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

The forward and futures contracts are entered into for trading and wholesale marketing purposes. The propane wholesale marketing business is subject to commodity price risk on its open positions to the extent that market prices for natural gas liquids deviate from fixed contract settlement prices. Market risk associated with the trading of futures and forward contracts is monitored daily for compliance with our 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 daily by our oversight officials. In addition, the Risk Management Committee reviews periodic reports on markets and the credit risk of counter-parties, approves any exceptions to the Risk Management Policy (within limits established by the Board of Directors) and authorizes the use of any new types of contracts. Quantitative information on forward and futures contracts at March 31, 2010 is presented in the following tables.

	Quantity in		Estimated Market		Weighted Average
At March 31, 2010	gallons		Prices		Contract Prices
Forward Contracts
Sale		9,870,000	$	1.0900 — $1.19250	$	1.1235
Purchase		10,374,000	$	1.0675 — $1.19093	$	1.1169

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

All contracts expire within the second quarter of 2010.

At March 31, 2010 and December 31, 2009, we marked these forward contracts to market, using market transactions in either the listed or OTC markets, which resulted in the following assets and liabilities:

	March 31,		December 31,
(in thousands)	2010		2009
Mark-to-market energy assets	$	198	$	2,379
Mark-to-market energy liabilities	$	118	$	2,514

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Chief Executive Officer and Chief Financial Officer of the Company, with the participation of other Company officials, have evaluated our “disclosure controls and procedures” (as such term is defined under Rules 13a-15(e) and 15d-15(e), promulgated under the Securities Exchange Act of 1934, as amended) as of March 31, 2010. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2010.

Changes in Internal Control Over Financial Reporting

During the quarter ended March 31, 2010, there was no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

On October 28, 2009, the merger between Chesapeake and FPU was consummated. We are currently in the process of integrating FPU’s operations and have not included FPU’s activity in our evaluation of internal control over financial reporting. FPU’s operations will be included in our assessment and report on internal control over financial reporting as of December 31, 2010.

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings

As disclosed in Note 4, “Commitments and Contingencies,” of these unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q, we are involved in certain legal actions and claims arising in the normal course of business. We are also involved in certain legal and administrative proceedings before various governmental or regulatory agencies concerning rates and other regulatory actions. In the opinion of management, the ultimate disposition of these proceedings and claims will not have a material effect on our condensed consolidated financial position, results of operations or cash flows.

Item 1A. Risk Factors

Our business, operations, and financial condition are subject to various risks and uncertainties. The risk factors described in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2009, should be carefully considered, together with the other information contained or incorporated by reference in the Quarterly Report on Form 10-Q including risks described below and in our other filings with the SEC in connection with evaluating the Company, our business and the forward-looking statements contained in this Report. Additional risks and uncertainties not presently known to us or that we currently deem immaterial also may affect the Company. The occurrence of any of these known or unknown risks could have a material adverse impact on our business, financial condition, and results of operations.

We may be required to reimburse TETLP for our proportionate share of its pre-service costs under the Precedent Agreement, which could be material to our financial position, results of operations and cash flows.

On April 8, 2010, we entered into a Precedent Agreement with TETLP to secure firm transportation service from TETLP in connection with its new expansion projects. As a result of this new transportation service, we would have access to new supplies of natural gas, providing increased reliability and diversity. The Precedent Agreement specifies certain events that would require us to reimburse TETLP for our proportionate share (prorated based on our total commitment of 40,000 Dts/d and the TETLP project total of 190,000 Dts/d) of TETLP’s pre-service costs incurred as of such events. One such event would be the parties’ inability to agree within a specified time period upon a mutually acceptable negotiated reservation rate for the firm transportation service. Other such events include termination of the Precedent Agreement by us, our unwillingness or inability to perform our material duties and obligations as specified in the Precedent Agreement, or certain other actions by us that result in TETLP’s inability to obtain the authorizations and exemptions required for this project. We believe that the likelihood of such events occurring that would require us to reimburse TETLP for our proportionate share of TETLP’s pre-service costs pursuant to the Precedent Agreement is remote. If such unlikely events were to occur, we estimate that our proportionate share of TETLP’s pre-service costs could be approximately $4.7 million by December 31, 2010. If we were to terminate the Precedent Agreement after TETLP completed its construction of all facilities, our proportionate share could be as much as approximately $45 million. The actual amount of our proportionate share could differ significantly and would ultimately be based on the level of pre-service costs only if and when that any such event occurs.

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

	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 Plans
Period	Purchased		per Share		or Programs (2)		or Programs(2)
January 1, 2010 through January 31, 2010 (1)		279	$	32.12		—		—
February 1, 2010 through February 28, 2010		—	$	—		—		—
March 1, 2010 through March 31, 2010		—	$	—		—		—
Total		279	$	32.12		—		—

(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 Directors and Senior Executives under the Deferred Compensation Plan. The Deferred Compensation Plan is discussed in detail in Item 8 under the heading “Notes to the Consolidated Financial Statements - Note M, Employee Benefit Plans” of our Form 10-K filed with the Securities and Exchange Commission on March 8, 2010. During the quarter, 279 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.

Item 3. Defaults upon Senior Securities

None.

Item 5. Other Information

None.

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Item 6. Exhibits

3.1	Amended and Restated Bylaws of Chesapeake Utilities Corporation, effective April 7, 2010, are incorporated herein by reference to Exhibit 3 of the Company’s Current Report on Form 8-K, filed April 13, 2010, File No. 001-11590.
10.1	Term Note Agreement entered into by Chesapeake Utilities Corporation on March 16, 2010, pursuant to the $29.1 million credit facility with PNC Bank, N.A., is filed herewith.
10.2	Precedent Agreement between Chesapeake Utilities Corporation and Texas Eastern Transmission, LP, dated April 8, 2010, is filed herewith.1
31.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, dated May 7, 2010.
31.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, dated May 7, 2010.
32.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated May 7, 2010.
32.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated May 7, 2010.

¹Portions of the Precedent Agreement have been omitted pursuant to a request for confidential treatment and have been filed separately with the SEC.

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SIGNATURES

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

Chesapeake Utilities Corporation
 

/s/ Beth W. Cooper  

Beth W. Cooper 

Senior Vice President and Chief Financial Officer 

Date: May 7, 2010

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EX-10.1

Exhibit 10.1

Term Note (Multi-Rate Options)
$29,100,000.00	March 16, 2010

FOR VALUE RECEIVED, CHESAPEAKE UTILITIES COROPORATION (the “Borrower”), with an address at 909 Silver Lake Boulevard, Dover, Delaware 19904, promises to pay to the order of PNC BANK, NATIONAL ASSOCIATION (the “Bank”), in lawful money of the United States of America in immediately available funds at its offices located at 222 Delaware Avenue, Wilmington, Delaware 19899, or at such other location as the Bank may designate from time to time, the principal sum of TWENTY-NINE MILLION ONE HUNDRED THOUSAND AND 00/100 DOLLARS ($29,100,000.00), together with interest accruing on the outstanding principal balance from the date hereof, all as provided below.

1. Rate of Interest. Amounts outstanding under this Note will bear interest at a rate or rates per annum as may be selected by the Borrower from the interest rate options set forth below (each, an “Option”):

(i) Base Rate Option. A rate of interest per annum which is at all times equal to (A) the Base Rate plus (B) two hundred twenty-five (225) basis points (2.25%). If and when the Base Rate (or any component thereof) changes, the rate of interest with respect to any amounts to which the Base Rate Option applies will change automatically without notice to the Borrower, effective on the date of any such change. There are no required minimum interest periods for amounts bearing interest under the Base Rate Option.

(ii) LIBOR Option. A rate per annum equal to (A) LIBOR plus (B) one hundred twenty-five (125) basis points (1.25%), for the applicable LIBOR Interest Period.

For purposes hereof, the following terms shall have the following meanings:

“Base Rate” shall mean the highest of (A) the Prime Rate, and (B) the sum of the Federal Funds Open Rate plus fifty (50) basis points (0.50%), and (C) the sum of the Daily LIBOR Rate plus one hundred (100) basis points (1.0%), so long as a Daily LIBOR Rate is offered, ascertainable and not unlawful.

“Business Day” shall mean any day other than a Saturday or Sunday or a legal holiday on which commercial banks are authorized or required by law to be closed for business in Wilmington, Delaware.

“Daily LIBOR Rate” shall mean, for any day, the rate per annum determined by the Bank by dividing (x) the Published Rate by (y) a number equal to 1.00 minus the LIBOR Reserve Percentage.

“Federal Funds Open Rate” shall mean, for any day, the rate per annum (based on a year of 360 days and actual days elapsed) which is the daily federal funds open rate as quoted by ICAP North America, Inc. (or any successor) as set forth on the Bloomberg Screen BTMM for that day opposite the caption “OPEN” (or on such other substitute Bloomberg Screen that displays such rate), or as set forth on such other recognized electronic source used for the purpose of displaying such rate as selected by the Bank (an “Alternate Source”) (or if such rate for such day does not appear on the Bloomberg Screen BTMM (or any substitute screen) or on any Alternate Source, or if there shall at any time, for any reason, no longer exist a Bloomberg Screen BTMM (or any substitute screen) or any Alternate Source, a comparable replacement rate determined by the Bank at such time (which determination shall be conclusive absent manifest error); provided however, that if such day is not a Business Day, the Federal Funds Open Rate for such day shall be the “open” rate on the immediately preceding Business Day. The rate of interest charged shall be adjusted as of each Business Day based on changes in the Federal Funds Open Rate without notice to the Borrower.

“LIBOR” shall mean, with respect to any amount to which the LIBOR Option applies for the applicable LIBOR Interest Period, the interest rate per annum determined by the Bank by dividing (the resulting quotient rounded upwards, at the Bank’s discretion, to the nearest 1/100th of 1%) (i) the rate of interest determined by the Bank in accordance with its usual procedures (which determination shall be conclusive absent manifest error) to be the eurodollar rate two (2) Business Days prior to the first day of such LIBOR Interest Period for such amount and having a borrowing date and a maturity comparable to such LIBOR Interest Period by (ii) a number equal to 1.00 minus the LIBOR Reserve Percentage.

“LIBOR Interest Period” shall mean, with respect to any amount to which the LIBOR Option applies, the period of one (1), two (2), three (3), six (6), nine (9) or twelve (12) months as selected by the Borrower on the date of disbursement of such amount (or the date of conversion of any amount to the LIBOR Option, as the case may be) and each successive period selected by the Borrower thereafter; provided that, (i) if a LIBOR Interest Period would end on a day which is not a Business Day, it shall end on the next succeeding Business Day unless such day falls in the next succeeding calendar month in which case the LIBOR Interest Period shall end on the next preceding Business Day, (ii) the Borrower may not select a LIBOR Interest Period that would end on a day after the Maturity Date (as hereinafter defined), and (iii) any LIBOR Interest Period that begins on the last Business Day of a calendar month (or a day for which there is no numerically corresponding day in the last calendar month of such LIBOR Interest Period) shall end on the last Business Day of the last calendar month of such LIBOR Interest Period.

“LIBOR Reserve Percentage” shall mean the maximum effective percentage in effect on such day as prescribed by the Board of Governors of the Federal Reserve System (or any successor) for determining the reserve requirements (including, without limitation, supplemental, marginal and emergency reserve requirements) with respect to eurocurrency funding (currently referred to as “Eurocurrency liabilities”).

“Prime Rate” shall mean the rate publicly announced by the Bank from time to time as its prime rate. The Prime Rate is determined from time to time by the Bank as a means of pricing some loans to its borrowers. The Prime Rate is not tied to any external rate of interest or index, and does not necessarily reflect the lowest rate of interest actually charged by the Bank to any particular class or category of customers.

“Published Rate” shall mean the rate of interest published each Business Day in the Wall Street Journal “Money Rates” listing under the caption “London Interbank Offered Rates” for a one month period (or, if no such rate is published therein for any reason, then the Published Rate shall be the eurodollar rate for a one month period as published in another publication selected by the Bank).

LIBOR and the Daily LIBOR Rate shall be adjusted with respect to any amounts to which the LIBOR Option or Base Rate Option applies, as applicable, on and as of the effective date of any change in the LIBOR Reserve Percentage. The Bank shall give prompt notice to the Borrower of LIBOR or the Daily LIBOR Rate as determined or adjusted in accordance herewith, which determination shall be conclusive absent manifest error.

If the Bank determines (which determination shall be final and conclusive) that, by reason of circumstances affecting the eurodollar market generally, deposits in dollars (in the applicable amounts) are not being offered to banks in the eurodollar market for the selected term, or adequate means do not exist for ascertaining LIBOR, then the Bank shall give notice thereof to the Borrower. Thereafter, until the Bank notifies the Borrower that the circumstances giving rise to such suspension no longer exist, (a) the availability of the LIBOR Option shall be suspended, and (b) the interest rate for all amounts then bearing interest under the LIBOR Option shall be converted at the expiration of the then current LIBOR Interest Period(s) to the Base Rate Option.

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In addition, if, after the date of this Note, the Bank shall determine (which determination shall be final and conclusive) that any enactment, promulgation or adoption of or any change in any applicable law, rule or regulation, or any change in the interpretation or administration thereof by a governmental authority, central bank or comparable agency charged with the interpretation or administration thereof, or compliance by the Bank with any guideline, request or directive (whether or not having the force of law) of any such authority, central bank or comparable agency shall make it unlawful or impossible for the Bank to make or maintain or fund loans based on LIBOR, the Bank shall notify the Borrower. Upon receipt of such notice, until the Bank notifies the Borrower that the circumstances giving rise to such determination no longer apply, (a) the availability of the LIBOR Option shall be suspended, and (b) the interest rate on all amounts then bearing interest under the LIBOR Option shall be converted to the Base Rate Option either (i) on the last day of the then current LIBOR Interest Period(s) if the Bank may lawfully continue to maintain or fund loans based on LIBOR to such day, or (ii) immediately if the Bank may not lawfully continue to maintain or fund loans based on LIBOR.

The foregoing notwithstanding, it is understood that the Borrower may select different Options to apply simultaneously to different portions of this Note and may select up to three (3) different interest periods to apply simultaneously to different portions of this Note bearing interest under the LIBOR Option. Interest hereunder will be calculated based on the actual number of days that principal is outstanding over a year of 360 days. In no event will the rate of interest hereunder exceed the maximum rate allowed by law.

2. Interest Rate Election. Subject to the terms and conditions of this Note, at the end of each interest period applicable to any amounts hereunder, the Borrower may renew the Option applicable to such amounts or convert such amounts to a different Option; provided that, during any period in which any Event of Default (as hereinafter defined) has occurred and is continuing, any amounts bearing interest under the LIBOR Option shall, at the Bank’s sole discretion, be converted at the end of the applicable LIBOR Interest Period to the Base Rate Option, and the LIBOR Option will not be available to Borrower with respect to the conversion or renewal of any other amounts until such Event of Default has been cured by the Borrower or waived by the Bank. The Borrower shall notify the Bank of each election of an Option, each conversion from one Option to another, the amount of the portions hereunder to be allocated to each Option and where relevant the interest periods therefor. In the case of converting to the LIBOR Option, such notice shall be given at least three (3) Business Days prior to the commencement of any LIBOR Interest Period. If no interest period is specified in any such notice for an amount that is to bear interest under the LIBOR Option, the Borrower shall be deemed to have selected a LIBOR Interest Period of one month’s duration. If no notice of election, conversion or renewal is timely received by the Bank with respect to any amount hereunder, the Borrower shall be deemed to have elected the Base Rate Option therefor. Any such election shall be promptly confirmed in writing by such method as the Bank may require.

3. Payment of Interest. The Borrower shall pay accrued interest on the unpaid principal balance of this Note in arrears: (a) for amounts hereunder bearing interest under the Base Rate Option, on the first day of each calendar quarter during the term hereof, (b) for amounts hereunder bearing interest under the LIBOR Option, on the last day of the respective LIBOR Interest Period for such amounts, (c) if any LIBOR Interest Period is longer than three (3) months, then also on the three (3) month anniversary of such interest period and every three (3) months thereafter, and (d) for all outstanding amounts, at maturity, whether by acceleration of this Note or otherwise, and after maturity, on demand until paid in full.

4. Payment of Principal. All principal outstanding under this Note shall be due and payable in full on March 15, 2011 (the “Maturity Date”). Any unpaid accrued interest shall be due and payable in full on the Maturity Date.

If any payment under this Note shall become due on a Saturday, Sunday or public holiday under the laws of the State where the Bank’s office indicated above is located, such payment shall be made on the next succeeding Business Day and such extension of time shall be included in computing interest in connection with such payment. The Borrower hereby authorizes the Bank to charge the Borrower’s deposit account at the Bank for any payment when due hereunder. Payments received will be applied to charges, fees and expenses (including attorneys’ fees), accrued interest and principal in any order the Bank may choose, in its sole discretion.

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5. Late Payments; Default Rate. If the Borrower fails to make any payment of principal, interest or other amount coming due pursuant to the provisions of this Note within fifteen (15) calendar days of the date due and payable, the Borrower also shall pay to the Bank a late charge equal to the lesser of five percent (5%) of the amount of such payment or $100.00 (the “Late Charge”). Such fifteen (15) day period shall not be construed in any way to extend the due date of any such payment. Upon maturity, whether by acceleration, demand or otherwise, and at the Bank’s option upon the occurrence of any Event of Default (as hereinafter defined) and during the continuance thereof, amounts outstanding under this Note shall bear interest at a rate per annum (based on the actual number of days that principal is outstanding over a year of 360 days) which shall be three percentage points (3%) in excess of the interest rate in effect from time to time under this Note but not more than the maximum rate allowed by law (the “Default Rate”). The Default Rate shall continue to apply whether or not judgment shall be entered on this Note. Both the Late Charge and the Default Rate are imposed as liquidated damages for the purpose of defraying the Bank’s expenses incident to the handling of delinquent payments, but are in addition to, and not in lieu of, the Bank’s exercise of any rights and remedies hereunder, under the other Loan Documents or under applicable law, and any fees and expenses of any agents or attorneys which the Bank may employ. In addition, the Default Rate reflects the increased credit risk to the Bank of carrying a loan that is in default. The Borrower agrees that the Late Charge and Default Rate are reasonable forecasts of just compensation for anticipated and actual harm incurred by the Bank, and that the actual harm incurred by the Bank cannot be estimated with certainty and without difficulty.

6. Prepayment. The Borrower shall have the right to prepay any amount hereunder at any time and from time to time, in whole or in part; subject, however, to payment of any break funding indemnification amounts owing pursuant to paragraph 7 below.

7. Yield Protection; Break Funding Indemnification. The Borrower shall pay to the Bank on written demand therefor, together with the written evidence of the justification therefor, all direct costs incurred, losses suffered or payments made by Bank by reason of any change in law or regulation or its interpretation imposing any reserve, deposit, allocation of capital, or similar requirement (including without limitation, Regulation D of the Board of Governors of the Federal Reserve System) on the Bank, its holding company or any of their respective assets. In addition, the Borrower agrees to indemnify the Bank against any liabilities, losses or expenses (including, without limitation, loss of margin, any loss or expense sustained or incurred in liquidating or employing deposits from third parties, and any loss or expense incurred in connection with funds acquired to effect, fund or maintain any amounts hereunder (or any part thereof) bearing interest under the LIBOR Option which the Bank sustains or incurs as a consequence of either (i) the Borrower’s failure to make a payment on the due date thereof, (ii) the Borrower’s revocation (expressly, by later inconsistent notices or otherwise) in whole or in part of any notice given to Bank to request, convert, renew or prepay any amounts bearing interest under the LIBOR Option, or (iii) the Borrower’s payment or prepayment (whether voluntary, after acceleration of the maturity of this Note or otherwise) or conversion of any amounts bearing interest under the LIBOR Option on a day other than the regularly scheduled due date therefor. A notice as to any amounts payable pursuant to this paragraph given to the Borrower by the Bank shall, in the absence of manifest error, be conclusive and shall be payable upon demand. The Borrower’s indemnification obligations hereunder shall survive the payment in full of all amounts payable hereunder.

8. Other Loan Documents. This Note is issued in connection with a letter agreement between the Borrower and the Bank, dated on or before the date hereof, and the other agreements and documents executed and/or delivered in connection therewith or referred to therein, the terms of which are incorporated herein by reference (as amended, modified or renewed from time to time, collectively the “Loan Documents”), and is secured by the property (if any) described in the Loan Documents and by such other collateral as previously may have been or may in the future be granted to the Bank to secure this Note.

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9. Events of Default. The occurrence of any of the following events will be deemed to be an “Event of Default” under this Note: (i) the nonpayment when due of any principal, interest or other indebtedness under this Note or under the Second Amended and Restated Committed Line of Credit Note (Multi-Rate Options) in the original principal amount of $30,000,000 dated January 13, 2010, made by the Borrower in favor of the Bank or under the Sixth Amended and Restated Discretionary Line of Credit Demand Note (As-Offered Rate) in the original principal amount of $20,000,000 dated January 13, 2010, made by the Borrower in favor of the Bank; (ii) the occurrence of any event of default or any default and the lapse of any notice or cure period, or any Obligor’s failure to observe or perform any covenant or other agreement, under or contained in any Loan Document or any other document now or in the future evidencing or securing any debt, liability or obligation of any Obligor to the Bank; (iii) the filing by or against any Obligor of any proceeding in bankruptcy, receivership, insolvency, reorganization, liquidation, conservatorship or similar proceeding (and, in the case of any such proceeding instituted against any Obligor, such proceeding is not dismissed or stayed within 30 days of the commencement thereof, provided that the Bank shall not be obligated to advance additional funds hereunder during such period); (iv) any assignment by any Obligor for the benefit of creditors, or any levy, garnishment, attachment or similar order is issued against any property of any Obligor held by or deposited with the Bank; (v) a default with respect to any other indebtedness of any Obligor for borrowed money in excess of $5,000,000 individually or in the aggregate, if the effect of such default is to cause or permit the acceleration of such debt; (vi) the commencement of any foreclosure or forfeiture proceeding, execution or attachment against any collateral securing the obligations of any Obligor to the Bank; (vii) the entry of one or more final judgments against any Obligor in excess of $5,000,000 individually or in the aggregate and the failure of such Obligor to discharge the judgments within thirty (30) days of the entry thereof; (viii) any material adverse change in any Obligor’s business, assets, operations, financial condition or results of operations; (ix) any Obligor ceases doing business as a going concern; (x) any representation or warranty made by any Obligor to the Bank in any Loan Document or any other documents now or in the future evidencing or securing the obligations of any Obligor to the Bank, is false, erroneous or misleading in any material respect; (xi) if this Note or any guarantee executed by any Obligor is secured (other than the security described in section 5 of the Working Cash Sweep Rider of even date herewith), the failure of any Obligor to provide the Bank with additional collateral if in the Bank’s opinion at any time or times, the market value of any of the collateral securing this Note or any guarantee has depreciated below that required pursuant to the Loan Documents or, if no specific value is so required, then in an amount reasonably deemed by the Bank as necessary to secure the Loan evidenced by this Note; (xii) the revocation or attempted revocation, in whole or in part, of any guarantee by any Obligor; or (xiii) the death, incarceration, indictment or legal incompetency of any individual Obligor or, if any Obligor is a partnership or limited liability company, the death, incarceration, indictment or legal incompetency of any individual general partner or member. As used herein, the term “Obligor” means any Borrower and any guarantor of, or any pledgor, mortgagor or other person or entity providing collateral support for, the Borrower’s obligations to the Bank existing on the date of this Note or arising in the future.

Upon the occurrence of an Event of Default: (a) the Bank shall be under no further obligation to make advances hereunder; (b) if an Event of Default specified in clause (iii) or (iv) above shall occur, the outstanding principal balance and accrued interest hereunder together with any additional amounts payable hereunder shall be immediately due and payable without demand or notice of any kind; (c) if any other Event of Default shall occur, the outstanding principal balance and accrued interest hereunder together with any additional amounts payable hereunder, at the Bank’s option and without demand or notice of any kind, may be accelerated and become immediately due and payable; (d) at the Bank’s option, this Note will bear interest at the Default Rate from the date of the occurrence of the Event of Default; and (e) the Bank may exercise from time to time any of the rights and remedies available under the Loan Documents or under applicable law.

10. [INTENTIONALLY DELETED]

11. Right of Setoff. In addition to all liens upon and rights of setoff against the Borrower’s money, securities or other property given to the Bank by law, the Bank shall have, with respect to the Borrower’s obligations to the Bank under this Note and to the extent permitted by law, a contractual possessory security interest in and a contractual right of setoff against, and the Borrower hereby grants the Bank a security interest in, and hereby assigns, conveys, delivers, pledges and transfers to the Bank, all of the Borrower’s right, title and interest in and to, all of the Borrower’s deposits, moneys, securities and other property now or hereafter in the possession of or on deposit with, or in transit to, the Bank or any other direct or indirect subsidiary of The PNC Financial Services Group, Inc., whether held in a general or special account or deposit, whether held jointly with someone else, or whether held for safekeeping or otherwise, excluding, however, all IRA, Keogh, and trust accounts. Every such security interest and right of setoff may be exercised without demand upon or notice to the Borrower. Every such right of setoff shall be deemed to have been exercised immediately upon the occurrence of an Event of Default hereunder without any action of the Bank, although the Bank may enter such setoff on its books and records at a later time.

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12. Indemnity. The Borrower agrees to indemnify each of the Bank, each legal entity, if any, who controls, is controlled by or is under common control with the Bank, and each of their respective directors, officers and employees (the “Indemnified Parties”), and to defend and hold each Indemnified Party harmless from and against any and all claims, damages, losses, liabilities and expenses (including all fees and charges of internal or external counsel with whom any Indemnified Party may consult and all expenses of litigation and preparation therefor) which any Indemnified Party may incur or which may be asserted against any Indemnified Party by any person, entity or governmental authority (including any person or entity claiming derivatively on behalf of the Borrower), in connection with or arising out of or relating to the matters referred to in this Note or in the other Loan Documents or the use of any advance hereunder, whether (a) arising from or incurred in connection with any breach of a representation, warranty or covenant by the Borrower, or (b) arising out of or resulting from any suit, action, claim, proceeding or governmental investigation, pending or threatened, whether based on statute, regulation or order, or tort, or contract or otherwise, before any court or governmental authority; provided, however, that the foregoing indemnity agreement shall not apply to any claims, damages, losses, liabilities and expenses solely attributable to an Indemnified Party’s gross negligence or willful misconduct. The indemnity agreement contained in this Section shall survive the termination of this Note, payment of any amounts hereunder and the assignment of any rights hereunder. The Borrower may participate at its expense in the defense of any such action or claim. No Indemnified Party will settle any claim for which indemnification hereunder has been or will be sought without the prior written consent of the Borrower, which consent shall not be unreasonably withheld or delayed. In the event the Borrower participates in the defense of any such action or claim, the Borrower will not, without the prior written consent of the Bank, settle or compromise or consent to the entry of any judgment in any pending or threatened claim, action, suit, proceeding or investigation or agree to any fine where any Indemnified Party is an actual or potential party unless such settlement, compromise, consent or agreement includes an unconditional release of each Indemnified Party hereunder from all liability arising out of such claim, action, suit, proceeding or investigation, and does not impose an injunction, equitable relief, prohibition or restriction of any kind on the Indemnified Party.

13. Miscellaneous. All notices, demands, requests, consents, approvals and other communications required or permitted hereunder (“Notices”) must be in writing (except as may be agreed otherwise above with respect to borrowing requests) and will be effective upon receipt. Notices may be given in any manner to which the parties may separately agree, including electronic mail. Without limiting the foregoing, first-class mail, facsimile transmission and commercial courier service are hereby agreed to as acceptable methods for giving Notices. Regardless of the manner in which provided, Notices may be sent to a party’s address as set forth above or to such other address as any party may give to the other for such purpose in accordance with this paragraph. No delay or omission on the Bank’s part to exercise any right or power arising hereunder will impair any such right or power or be considered a waiver of any such right or power, nor will the Bank’s action or inaction impair any such right or power. The Bank’s rights and remedies hereunder are cumulative and not exclusive of any other rights or remedies which the Bank may have under other agreements, at law or in equity. No modification, amendment or waiver of, or consent to any departure by the Borrower from, any provision of this Note will be effective unless made in a writing signed by the Bank, and then such waiver or consent shall be effective only in the specific instance and for the purpose for which given. The Borrower agrees to pay on demand, to the extent permitted by law, all costs and expenses incurred by the Bank in the enforcement of its rights in this Note and in any security therefor, including without limitation reasonable fees and expenses of the Bank’s counsel. If any provision of this Note is found to be invalid, illegal or unenforceable in any respect by a court, all the other provisions of this Note will remain in full force and effect. The Borrower and all other makers and indorsers of this Note hereby forever waive presentment, protest, notice of dishonor and notice of non-payment. The Borrower also waives all defenses based on suretyship or impairment of collateral. If this Note is executed by more than one Borrower, the obligations of such persons or entities hereunder will be joint and several. This Note shall bind the Borrower and its heirs, executors, administrators, successors and assigns, and the benefits hereof shall inure to the benefit of the Bank and its successors and assigns; provided, however, that the Borrower may not assign this Note in whole or in part without the Bank’s written consent and the Bank at any time may assign this Note in whole or in part.

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This Note has been delivered to and accepted by the Bank and will be deemed to be made in the State where the Bank’s office indicated above is located. This Note will be interpreted and the rights and liabilities of the Bank and the Borrower determined in accordance with the laws of the State where the Bank’s office indicated above is located, excluding its conflict of laws rules. The Borrower hereby irrevocably consents to the exclusive jurisdiction of any state or federal court in the county or judicial district where the Bank’s office indicated above is located; provided that nothing contained in this Note will prevent the Bank from bringing any action, enforcing any award or judgment or exercising any rights against the Borrower individually, against any security or against any property of the Borrower within any other county, state or other foreign or domestic jurisdiction. The Borrower acknowledges and agrees that the venue provided above is the most convenient forum for both the Bank and the Borrower. The Borrower waives any objection to venue and any objection based on a more convenient forum in any action instituted under this Note.

14. Authorization to Obtain Credit Reports. By signing below, each Borrower who is an individual provides written authorization to the Bank or its designee (and any assignee or potential assignee hereof) to obtain the Borrower’s personal credit profile from one or more national credit bureaus. Such authorization shall extend to obtaining a credit profile in considering this Note and subsequently for the purposes of update, renewal or extension of such credit or additional credit and for reviewing or collecting the resulting account.

[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK]

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15. WAIVER OF JURY TRIAL. The Borrower irrevocably waives any and all rights the Borrower may have to a trial by jury in any action, proceeding or claim of any nature relating to this Note, any documents executed in connection with this Note or any transaction contemplated in any of such documents. The Borrower acknowledges that the foregoing waiver is knowing and voluntary.

The Borrower acknowledges that it has read and understood all the provisions of this Note, including the confession of judgment and the waiver of jury trial, and has been advised by counsel as necessary or appropriate.

WITNESS the due execution hereof as a document under seal, as of the date first written above, with the intent to be legally bound hereby.

WITNESS / ATTEST:	CHESAPEAKE UTILITIES CORPORATION
	By:
		(SEAL)
Print Name:		Print Name:
Title:		Title:
(Include title only if an officer of entity signing to the right)

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EX-10.2

Exhibit 10.2

PRECEDENT AGREEMENT

This PRECEDENT AGREEMENT (“Precedent Agreement”) is made and entered into this _____ day of April, 2010, by and between Texas Eastern Transmission, LP, a Delaware limited partnership (“Texas Eastern” or “Pipeline”), and Chesapeake Utilities Corporation (“Customer”). Pipeline and Customer are sometimes referred to herein individually as a “Party,” or collectively as the “Parties.”

W I T N E S S E T H:

WHEREAS, Pipeline owns and operates an interstate natural gas transmission system extending from the State of Texas and offshore Louisiana through the Appalachian area to the Eastern Seaboard in the Philadelphia, New Jersey and New York areas;

WHEREAS, Pipeline proposes to expand its interstate natural gas transmission system by constructing, owning and operating certain pipeline, compression and related facilities to provide expansion transportation service from receipt point(s) in the Appalachian production region in West Virginia, Ohio and Pennsylvania that span both of Texas Eastern’s market zones M2 and M3, to delivery points across Texas Eastern’s market area including, but not limited to, Lambertville, N.J., Transco Station 195 in York County, PA, Dominion Transmission at Chambersburg, PA and Columbia Gas Transmission near Marietta or Eagle, Pa. (the “Project”);

WHEREAS, Customer submitted a service request pursuant to a “Non-Binding Open Season” conducted by Pipeline from August 1, 2008 through August 29, 2008, and a service request pursuant to a Binding Open Season from November 17, 2009 through December 1, 2009, and Customer desires to obtain firm transportation service from Pipeline as part of the Project for certain quantities of Customer’s natural gas; and

WHEREAS, subject to the terms and conditions of this Precedent Agreement, Pipeline is willing to construct the Project and provide the firm transportation service Customer desires;

NOW, THEREFORE, in consideration of the mutual covenants and agreements herein contained, and intending to be legally bound, Pipeline and Customer agree to the following:

1. Subject to the terms and conditions of this Precedent Agreement, Pipeline shall proceed with due diligence to obtain from all governmental and regulatory authorities having competent jurisdiction over the premises, including, but not limited to, the Federal Energy Regulatory Commission (“Commission” or “FERC”), the authorizations and/or exemptions Pipeline determines are necessary: (i) for Pipeline to construct, own, operate, and maintain the Project facilities necessary to provide the firm transportation service contemplated herein; and (ii) for Pipeline to perform its obligations as contemplated in this Precedent Agreement. Pipeline reserves the right to file and prosecute any and all applications for such authorizations and/or exemptions, any supplements or amendments thereto, and, if necessary, any court review, which are consistent with this Precedent Agreement in a manner it deems to be in its best interest. During the term of this Precedent Agreement, Customer agrees to support and cooperate with, and to not oppose, obstruct or otherwise interfere with in any manner, the efforts of Pipeline to obtain all authorizations and/or exemptions and supplements and amendments thereto necessary for Pipeline to construct, own, operate, and maintain the Project facilities and to provide the firm transportation service contemplated in this Precedent Agreement and to perform its obligations as contemplated by this Precedent Agreement.

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2. Within thirty (30) days after execution of this Precedent Agreement, Customer will advise Pipeline in writing of: (i) any facilities which Customer must construct, or cause to be constructed, in order for Customer to utilize the firm transportation service contemplated in this Precedent Agreement; and (ii) any necessary or desirable governmental, contractual and/or regulatory authorizations, approvals, certificates, permits and/or exemptions associated with the facilities identified pursuant to (i) above (“Customer’s Authorizations”).

3. Subject to the terms and conditions of this Precedent Agreement, Customer shall proceed with due diligence to obtain Customer’s Authorizations. Customer reserves the right to file and prosecute applications for Customer’s Authorizations, and, if necessary, any court review, in a manner it deems to be in its best interest; provided, however, Customer shall pursue Customer’s Authorizations in a manner designed to implement the firm transportation service contemplated herein in a timely manner. Pipeline agrees to use reasonable efforts to assist Customer in obtaining Customer’s Authorizations. Customer agrees to promptly notify Pipeline in writing when each of the required authorizations, approvals and/or exemptions are received, obtained, rejected or denied. Customer shall also promptly notify Pipeline in writing as to whether any such authorizations, approvals and/or exemptions received or obtained are acceptable to Customer.

4. (A) To effectuate the firm transportation service contemplated herein, Customer and Pipeline agree that no later than thirty (30) days after the date on which all of the conditions precedent set forth in Paragraph 8, except for the condition precedent in Paragraph 8(A)(v), of this Precedent Agreement have been satisfied or waived, they will execute two firm transportation service agreements one in the name of Chesapeake Utilities Corporation d/b/a Chesapeake Utilities Corporation – Delaware

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Division (“Delaware Service Agreement”) and one in the name of Chesapeake Utilities Corporation d/b/a/ Chesapeake Utilities Corporation – Maryland Division (“Maryland Service Agreement”), collectively the “Service Agreements” under Pipeline’s Rate Schedule FT-1, which shall specify:

(1) in the case of the Delaware Service Agreement, a Maximum Daily Quantity (“MDQ”) of 30,000 dekatherms per day (“Dth/d”) exclusive of fuel requirements, effective on the Service Commencement Date (as determined in accordance with Paragraph 5 of this Precedent Agreement), and in the case of the Maryland Service Agreement, an MDQ of 10,000 Dth/d, exclusive of fuel requirements, effective on the Service Commencement Date (as determined in accordance with Paragraph 5 of this Precedent Agreement); and,

(2) in both Service Agreements: (i) a primary term of fifteen (15) years commencing on the Service Commencement Date (“Primary Term”), (ii) a Primary Point of Receipt at Clarington, Ohio, (iii) a Primary Point of Delivery at ESNG-Honeybrook, PA, and (iv) incorporate security requirements consistent with the provisions set forth in Paragraph 13 below. The rate that will apply to service under the Service Agreements shall be a Natural Gas Act Section 7(c) initial rate, plus applicable fuel retainage and all other applicable usage charges, charges and surcharges, unless the Parties otherwise mutually agree to a negotiated or discounted rate as further defined in Exhibits A and A-1.

(B) Pipeline and Customer have agreed to the following with regard to the negotiated rate for service under the Service Agreements.

(1) Subject to the terms and conditions set forth herein and in the form of negotiated rate agreements attached hereto as Exhibits A and A-1, Customer shall pay Pipeline a negotiated rate for service under the Service Agreements during the Primary Term thereof based upon Pipeline’s reasonable good faith estimate of the capital costs associated with constructing the Project facilities and all other costs associated with providing the service contemplated herein.

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(2) Pipeline and Customer acknowledge that the Project is expected to involve an expansion of Pipeline’s mainline system of up to 190,000 Dth/d in its Zones M2 and M3, although the final scope of the expansion facilities is not known with precision at this time. For this reason, the estimated capital costs associated with construction of the Project facilities and the estimated Reservation Rate for service under the Service Agreements are represented by blanks in the attached Exhibits A and A-1 form of negotiated rate agreements that will be filled in at a future time. Pipeline currently estimates that the negotiated Reservation Rate for service under the Service Agreements will be [ ^* ].

(3) No later than June 30, 2010, Pipeline shall provide Customer with a good faith estimate of the capital costs associated with construction of the Project facilities and the related negotiated Reservation Rate. At the same time that Pipeline provides such capital cost estimate and negotiated Reservation Rate to Customer, Pipeline shall also tender to Customer two (2) negotiated rate agreements, in the form set forth in Exhibits A and A-1 hererto, with the blanks for capital costs, negotiated Reservation Rate and the formula for the adjustment to the negotiated Reservation Rate filled in a manner consistent with such capital cost estimate and negotiated Reservation Rate. Pipeline and Customer shall promptly execute such negotiated rate agreements; provided, however, Customer shall not be obligated to execute the negotiated rate agreements, if the negotiated Reservation Rates set forth therein are higher than the range of negotiated Reservation Rates provided in clause (2) of this Paragraph 4(B) and such higher negotiated Reservation Rates cause the value of the commercial transaction with respect to the natural gas to be transported under the Service Agreements to be uneconomic to Customer, as determined by Customer in its good faith reasonable discretion.

^* This confidential portion has been omitted and filed separately with the Securities and Exchange Commission.

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(4) In the event that Customer has elected not to execute the negotiated rate agreements in accordance with the proviso in the last sentence of clause (3) of this Paragraph 4(B), Pipeline and Customer shall promptly meet and work in a good faith attempt to agree upon a negotiated Reservation Rate that is commercially acceptable to both Parties. If after a reasonable time, the Parties are unable to agree upon a mutually acceptable negotiated Reservation Rate, either Party shall have the right to terminate this Precedent Agreement and the Service Agreements by providing the other Party with thirty (30) days prior written notice of its intent to terminate such agreements. If this Precedent Agreement and the Service Agreements are terminated in accordance with this Paragraph 4(B), Customer shall, at the option and election of Pipeline, reimburse Pipeline for Customer’s proportionate share (as prorated based on total Project MDQs of 190,000 dths/d) of Pipeline’s Pre-service Costs incurred to the date of such termination.

5. Upon satisfaction or waiver of all the conditions precedent set forth in Paragraph 8 of this Precedent Agreement, Pipeline shall notify Customer of such fact, and that service under the Service Agreements will commence on a date certain, which date will be the later of: (i) November 1, 2012, or (ii) the date that all of the conditions precedent set forth in Paragraph 8 of this Precedent Agreement are satisfied or waived (“Service Commencement Date”). On and after the date on which Pipeline has notified Customer that service under the Service Agreements will commence, Pipeline shall provide firm transportation service for Customer pursuant to the terms of the Service Agreements and Customer will pay Pipeline for all applicable charges required by the Service Agreements.

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6. Pipeline will undertake the design of the Project facilities and any other preparatory actions necessary for Pipeline to complete and file its certificate application(s) related to the Project with the Commission. Prior to satisfaction of the conditions precedent set forth in Paragraph 8 of this Precedent Agreement (with the exception of 8(A)(v)), Pipeline shall have the right, but not the obligation, to proceed with the necessary design of facilities, acquisition of materials, supplies, properties, rights-of-way and any other necessary preparations to implement the firm transportation service under the Service Agreement as contemplated in this Precedent Agreement.

7. Upon satisfaction of the conditions precedent set forth in Paragraphs 8(A), except for 8(A)(v), and 8(B)(i) of this Precedent Agreement, or waiver of the same by Pipeline or Customer, as applicable, Pipeline shall proceed (subject to the continuing commitments of all customers executing precedent agreements and service agreements for service utilizing the firm transportation capacity to be made available by the Project) with due diligence to construct the authorized Project facilities and to implement the firm transportation service contemplated in this Precedent Agreement on November 1, 2012. Notwithstanding Pipeline’s due diligence, if Pipeline is unable to commence the firm transportation service for Customer as contemplated herein on November 1, 2012, Pipeline will continue to proceed with due diligence to complete arrangements for such firm transportation service, and commence the firm transportation service for Customer at the earliest practicable date thereafter. Pipeline will neither be liable nor will this Precedent Agreement or the Service Agreements be subject to cancellation if Pipeline is unable to complete the construction of such authorized Project facilities and commence the firm transportation service contemplated herein by November 1, 2012.

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8. Commencement of service under the Service Agreements and Pipeline’s and Customer’s rights and obligations under the Service Agreements are expressly made subject to satisfaction of the following conditions precedent:

(A) Pipeline’s (only Pipeline shall have the right to waive the conditions precedent set forth in this Paragraph 8(A)):

(i) receipt and acceptance by March 1, 2012, of all necessary certificates and authorizations from the Commission to construct, own, operate and maintain the Project facilities, all as described in Pipeline’s certificate application as it may be amended from time to time, necessary to provide the firm transportation service contemplated herein and in the Service Agreements;

(ii) receipt of approval, within thirty (30) days after Pipeline’s acceptance of the certificates and authorizations specified in Paragraph 8(A)(i), from its Board of Directors, or similar governing body, to expend the capital necessary to construct the Project facilities;

(iii) receipt of all necessary governmental authorizations, approvals, and permits required to construct the Project facilities necessary to provide the firm transportation service contemplated herein and in the Service Agreements other than those specified in Paragraph 8(A)(i);

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(iv) procurement of all necessary rights-of-way, easements or permits in form and substance acceptable to Pipeline;

(v) completion of construction of the necessary Project facilities, and all other facilities required to render firm transportation service for Customer pursuant to the Service Agreements and Pipeline being ready and able to place such facilities into gas service; provided however, satisfaction of this condition precedent is not conditioned upon completion of the Interconnection Facilities, as defined below;

(vi) the receipt by Eastern Shore Natural Gas Company (“Eastern Shore”) by December 1, 2010 to be in service by 2011, of all necessary certificates, and authorizations from the Commission to construct and operate the interconnection facilities, all as described in Eastern Shore’s certificate application as it may be amended from time to time, necessary to interconnect the pipeline systems of Pipeline and Eastern Shore in or near Honeybrook, Pennsylvania (“the Interconnection Facilities”); and

(vii) Eastern Shore, by March 1, 2011, has commenced construction of the Interconnection Facilities.

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(B) Customer’s (only Customer shall have the right to waive the conditions precedent set forth in this Paragraph 8(B)):

(i) receipt and acceptance by April 1, 2010, of all Customer’s Authorizations.

(ii) the receipt by Eastern Shore Natural Gas Company (“Eastern Shore”) by December 1, 2010 to be in service by 2011 of all necessary certificates and authorizations from the Commission to construct and operate the Interconnection Facilities.; and

(v) Eastern Shore, by March 1, 2011, has commenced construction of the Interconnection Facilities.

(C) Unless otherwise provided for herein, the Commission authorization(s) and approval(s) contemplated in Paragraph 1 of this Precedent Agreement must be issued in form and substance reasonably satisfactory to both Parties hereto. For purposes of this Precedent Agreement, such Commission authorization(s) and approval(s) shall be deemed satisfactory if issued or granted in form and substance as requested, or if issued in a manner acceptable to Pipeline and such authorization(s) and approval(s), as issued, will not have a material adverse effect on Customer. Customer shall notify Pipeline in writing not later than fifteen (15) days after the issuance of the Commission certificate(s), authorization(s) and approval(s), including any order issued as a preliminary determination on non-environmental issues, contemplated in Paragraph 1 of this Precedent Agreement if such certificate(s), authorization(s) and approval(s) are not satisfactory to Customer. All other governmental authorizations, approvals, permits and/or exemptions that Pipeline must obtain must be issued in form and substance reasonably acceptable to Pipeline. All governmental approvals that Pipeline is required by this Precedent Agreement to obtain must be duly granted by the Commission or other governmental agency or authority having jurisdiction, and must be final and no longer subject to rehearing or appeal; provided, however, Pipeline may waive the requirement that such authorization(s) and approval(s) be final and no longer subject to rehearing or appeal.

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9. If Customer (i) terminates this Precedent Agreement for any reason; (ii) otherwise fails to perform, in whole or in part, its material duties and obligations hereunder; or (iii) during the term of this Precedent Agreement, interferes with or obstructs the receipt by Pipeline of the authorizations and/or exemptions contemplated by and consistent with this Precedent Agreement as requested by Pipeline and, as a result of such actions by Customer, Pipeline does not receive the authorizations and/or exemptions in form and substance as requested by Pipeline or does not receive such authorizations and/or exemptions at all, then in any of the above events, Customer shall, at the option and election of Pipeline, reimburse Pipeline within 30 days of Pipeline’s invoice for Customer’s proportionate share (as prorated based on initial MDQs among all customers taking actions described in this Paragraph 9) of Pre-service Costs as hereinafter defined. The term, “Pre-service Costs” for all purposes in this Precedent Agreement shall include, but will not be limited to, those expenditures and/or costs incurred, accrued, allocated to, or for which Pipeline is contractually obligated to pay associated with engineering, construction, materials and equipment, environmental, regulatory, and/or legal activities, allowance for funds used during construction, negative salvage, internal overhead and administration and any other costs incurred in furtherance of Pipeline’s efforts to develop and construct the Project and to satisfy its obligations under this Precedent Agreement and all other precedent agreements for service on the Project facilities including, without limitation, the federal and state income tax liability, if any, to Pipeline associated with its receipt of such reimbursement amount. Pipeline shall use commercially reasonable efforts to mitigate Pre-service Costs. If Customer terminates this Precedent Agreement and the Service Agreements in accordance with the provisions of Paragraph 4(B)(4), and if Customer, at the option and election of Pipeline, is assessed Customer’s proportionate share (as prorated based on total Project MDQs of 190,000dths/d) of Pipeline’s Pre-service Costs incurred to the date of such termination, Customer shall not be assessed any additional Pre-service Costs pursuant to Paragraph 9.

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NOTWITHSTANDING THE FOREGOING, THE PARTIES HERETO AGREE THAT NEITHER PARTY SHALL BE LIABLE TO THE OTHER PARTY FOR ANY PUNITIVE, SPECIAL, EXEMPLARY, INDIRECT, INCIDENTAL OR CONSEQUENTIAL DAMAGES (INCLUDING, WITHOUT LIMITATION, LOSS OF PROFITS OR BUSINESS INTERRUPTIONS) ARISING OUT OF OR IN ANY MANNER RELATED TO THIS PRECEDENT AGREEMENT, AND WITHOUT REGARD TO THE CAUSE OR CAUSES THEREOF OR THE SOLE, CONCURRENT OR CONTRIBUTORY NEGLIGENCE (WHETHER ACTIVE OR PASSIVE), STRICT LIABILITY (INCLUDING, WITHOUT LIMITATION, STRICT STATUTORY LIABILITY AND STRICT LIABILITY IN TORT) OR OTHER FAULT OF EITHER PARTY. THE IMMEDIATELY PRECEDING SENTENCE SPECIFICALLY PROTECTS EACH PARTY AGAINST SUCH PUNITIVE, EXEMPLARY, INDIRECT, INCIDENTAL OR CONSEQUENTIAL DAMAGES EVEN IF WITH RESPECT TO THE NEGLIGENCE, GROSS NEGLIGENCE, WILLFUL MISCONDUCT, STRICT LIABILITY OR OTHER FAULT OR RESPONSIBILITY OF SUCH PARTY; AND ALL RIGHTS TO RECOVER SUCH DAMAGES OR PROFITS ARE HEREBY WAIVED AND RELEASED.

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10. (A) If the conditions precedent set forth in Paragraph 8 of this Precedent Agreement, excluding the condition precedent set forth in Paragraph 8(A)(v) have not been fully satisfied, or waived by Pipeline or Customer, as applicable, by the earlier of the applicable dates specified therein or within one (1) year after the date specified in Paragraph 5(i), and this Precedent Agreement has not been terminated pursuant to Paragraphs 11 or 12 hereof, then either Pipeline or Customer may thereafter terminate this Precedent Agreement (and the Service Agreements, if executed) by giving ninety (90) days prior written notice of its intention to terminate to the non-terminating Party; provided, however, if the conditions precedent are satisfied, or waived by Pipeline or Customer, as applicable, within such ninety (90) day notice period, then termination of such agreements will not become effective.

(B) Notwithstanding any other provision of this Precedent Agreement, if Pipeline has not completed construction of the Project facilities and made such facilities available for service by November 1, 2013, and the conditions precedent set forth in Paragraph 8(B) hereof have been satisfied, Customer and Pipeline shall cause their senior management to meet promptly to resolve any timing issues and if after ninety (90) days no resolution has been reached, then Customer shall have the right to terminate this Precedent Agreement (and the Service Agreements and the Negotiated Rate Agreements) by providing ninety (90) days prior written notice of its intention to terminate this Precedent Agreement to Pipeline; provided, however, if Pipeline completes construction of the Project facilities and makes such facilities available for service during such ninety (90)-day period, then termination of this Precedent Agreement (and the Service Agreements and the Negotiated Rate Agreements) will not be effective; further, in the event the delay in meeting the November 1, 2013 in-service date is due to issues arising out of or directly related to any horizontal directional drilling activities or legal appeals or other legal or regulatory activities that have resulted in a delay in the issuance of any necessary permit or authorization, then in such event the November 1, 2013 date shall be extended to November 1, 2014. If this Precedent Agreement terminates in accordance with this Paragraph 10(B), then, notwithstanding any other provision of this Precedent Agreement, Customer shall have no obligation to pay Pipeline Pre-service Costs under Paragraph 9 hereof.

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11. In addition to the provisions of Paragraph 10 hereof, Pipeline may terminate this Precedent Agreement at any time upon fifteen (15) days prior written notice to Customer, if: (i) Pipeline, in its sole discretion, determines for any reason that the Project contemplated herein is no longer economically viable, or (ii) substantially all of the other precedent agreements, service agreements or other contractual arrangements for the firm service to be made available by the Project are terminated, other than by reason of commencement of service.

12. If this Precedent Agreement is not terminated pursuant to Paragraphs 10 or 11 hereof, it will terminate by its express terms on the Service Commencement Date, and thereafter Pipeline’s and Customer’s rights and obligations related to the transportation service contemplated herein shall be determined pursuant to the terms and conditions of such Service Agreements and Pipeline’s FERC Gas Tariff, as effective from time to time. Notwithstanding any termination of this Precedent Agreement pursuant to Paragraphs 10, 11 or 12 hereof, to the extent that a provision of this Precedent Agreement contemplates that one or both Parties may have further rights and/or obligations hereunder following such termination, the provision shall survive such termination as necessary to give full effect to such rights and/or obligations.

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13. Customer shall satisfy the creditworthiness requirements as set forth in this Paragraph 13 within 7 days from the effective date of this Precedent Agreement, or from the date of any subsequent request from Pipeline. Customer shall at all times during the effectiveness of this Precedent Agreement and the Service Agreement meet the creditworthiness requirements set forth in the table below:

Credit Requirements

Creditworthiness Conditions	Category A1	Category B2	Category C3	Category D4
Customer or Guarantor’s S&P or Moody’s or Fitch Rating	BBB/Baa2/BBB or higher	BBB-/Baa3/BBB-	BB+ to BB-/Ba1 to Ba3 /BB+ to BB-	B+/B1/B+ or lower
Other Conditions	See “Rating” definition in 13(A)
Letter of Credit Requirement (as fixed amount or months of reservation charges under the Service Agreement)
On or about the effective date of the Precedent Agreement	0	$100,000	$100,000	$100,000
When pro-rata share of Pre-service Costs exceeds $100,000	0	Pro-rata share of Pre-service Costs, save that such amount will not be less than $100,000 or greater than the amount required below
From and after the Service Commencement Date	0	lesser of 3 months or remaining term of Service Agreement	lesser of 24 months or remaining term of Service Agreement	lesser of 30 months or remaining term of Service Agreement

1

A Category A customer meeting all creditworthiness conditions is considered Creditworthy (“Creditworthy”). No additional credit support is required.

2

Category B will apply to a customer that meets the creditworthiness requirements of Category B but not Category A, A Category B customer that does not have a sufficient open credit line shall (a) post a “Guaranty”, as hereinafter defined, from a “Guarantor”, as hereinafter defined, meeting Category A creditworthiness conditions, or (b) provide a “Letter of Credit” , as hereinafter defined, in the amount required for Category B.

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3

A customer in Category C shall (a) post a Guaranty from a Guarantor meeting Category A creditworthiness conditions, (b) provide a Guaranty from a Guarantor meeting Category B creditworthiness conditions, and a Letter of Credit in the amount required for Category B, or (c) provide a Letter of Credit in the amount required for Category C.

4

A customer in Category D shall (a) post a Guaranty from a Guarantor meeting Category A creditworthiness conditions, (b) provide a Guaranty from a Guarantor meeting Category B creditworthiness conditions, and a Letter of Credit in the amount required for Category B, (c) provide a Guaranty from a Guarantor meeting Category C creditworthiness conditions, and a Letter of Credit in the amount required for Category C, or (d) provide a Letter of Credit in the amount required for Category D.

In the event Customer does not have the external credit rating listed in the table above, Customer may qualify as the equivalent of a Category B if it meets and maintains throughout the term of the service agreement all three of the following conditions:

1.) Tangible Net Worth of $100 million or greater.  

2.) Fixed Charge Coverage Ratio of 150% or greater.   If any future indebtedness covenants have or reasonably imply a Fixed Charge Coverage Ratio limit greater than 120%, this 150%  limit will adjust upwards so as to maintain at least a 30% gap. 

3.) Funded Indebtedness of the Customer (including Current and Funded Indebtedness of Customer’s subsidiaries) as a percent of Total Capitalization of no more than 60%.  If any future indebtedness covenants have or reasonably imply a Current and Funded Indebtedness as a percent of Total Capitalization limit of less than 65%, this 60% limit will adjust downwards so as to maintain at least a 5% gap.

Customer meeting two out of the three conditions above qualifies as a Category C equivalent. Customer meeting less than two out of the three conditions above qualifies as a Category D equivalent.

Customer qualifying for credit under this equivalent rating option shall provide financial information and reports to Pipeline including, but not limited to, quarterly covenant compliance reports, bond, note and credit facility agreements, and detailed financial statements.

(A) For the purposes of this Paragraph 13:

“Rating” – shall mean long-term senior unsecured debt rating from Moody’s Investors Service, Inc. (“Moody’s”) or Standard & Poor’s Rating Services, a division of The McGraw-Hill Companies, Inc. (“S&P), or Fitch Ratings (“Fitch”). If the entity is rated by two rating agencies, the lower rating shall apply to the minimum requirement of the applicable Category A, B or C. If the entity is rated by three rating agencies, at least two ratings shall meet the minimum requirement of the applicable Category A, B or C.

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“Guaranty” – shall mean that Customer’s parent company or a third party meeting the creditworthiness conditions of Category A, B, or C (“Guarantor”): (i) guarantees all payment obligations of Customer under this Precedent Agreement and the Service Agreements, (ii) remains in effect until all payment obligations under this Precedent Agreement and Service Agreements have been satisfied in full, and (iii) shall be in a form acceptable to Pipeline, which for purposes herein shall mean in form and content acceptable to Pipeline in its reasonable discretion. The Guarantor must meet the creditworthiness conditions of Category A, B or C for so long as it guarantees Customer’s payment obligations. Pipeline may require Customer to provide, or cause to be provided, a replacement Guaranty from a replacement Guarantor if the original Guarantor is, at any time, no longer meeting the creditworthiness conditions of Category A, B or C.

“Letter of Credit” – shall mean a standby irrevocable letter of credit from a “Qualified Financial Institution” , as defined below, which shall be: (i) issued for an annual period (ii) automatically renewed annually, until all payment obligations under this Precedent Agreement and the Service Agreements have been satisfied in full, (iii) in a form acceptable to Pipeline, which for purposes herein shall mean in form and content substantially similar to Exhibit B hereto, and (iv) be provided at no cost to Pipeline.

“Qualified Financial Institution” – shall mean a major U.S. commercial bank, or the U.S. branch office of a foreign bank, which is not the Customer or Customer’s Guarantor (or a subsidiary or affiliate of the Customer or Customer’s Guarantor) and which has assets of at least $10 billion dollars and a credit rating of at least “A” by S&P, or “A3” by Moody’s. Pipeline may require Customer, at no cost to Pipeline, to substitute a Qualified Financial Institution if the Letter of Credit provided is, at any time, from a financial institution which is no longer a Qualified Financial Institution.

““Tangible Net Worth” – shall mean Stockholder Equity less Intangibles, Pension, Other Deferred Charges, Other Regulatory Assets and Non-Current Receivables.

“Fixed Charge Coverage ratio” – shall mean Interest Expense and Lease Rental Expense divided by Net Income before Interest Expense, Taxes, Lease Rental Expense, and any Net Gain or Loss on Sale of Investment or Fixed Assets.

“Funded Indebtedness” – shall mean Long Term Debt, current portion of Long Term Debt, Long Term Lease Obligation and current portion of Long Term Lease Obligation.

“Total Capitalization” – shall mean Long Term Debt, current portion of Long Term Debt, Long Term Lease Obligation, current portion of Long Term Lease Obligation, plus Stockholder Equity.

For purposes of this paragraph 13, “Customer’s pro-rata share of Pre-service Costs” will be determined by an estimated cost and commitments schedule.

(B) The requirements set forth in this Paragraph 13 shall be in addition to and not in lieu of any requirements under Pipeline’s FERC Gas Tariff, which are applicable to Customer with respect to service on and after the Service Commencement Date under the Service Agreements.

(C) If at any time and from time to time during the effectiveness of this Precedent Agreement and/or the Service Agreements. Pipeline determines that Customer is not satisfying the requirements in this Paragraph 13, Pipeline shall notify Customer in writing, and Customer shall satisfy, or cause to be satisfied, such requirement(s) as soon as reasonably practicable, but in no event later than the close of the seventh (7^th) business day following receipt of such notice from Pipeline.

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(D) The failure of Customer to timely satisfy or maintain the requirements set forth in this Paragraph 13 shall in no way relieve Customer of its other obligations under this Precedent Agreement and/or the Service Agreements, nor shall it affect Pipeline’s right to seek damages or performance under this Precedent Agreement and/or the Service Agreements. Further, if Customer fails to timely satisfy or maintain the requirements of this Paragraph 13, Pipeline shall have the right, but not the obligation, to suspend performance under this Precedent Agreement, or to terminate this Precedent Agreement, upon ten (10) days prior written notice by Pipeline.

(E) This Paragraph 13 shall survive the termination of this Precedent Agreement and shall remain in effect until all payment obligations under this Precedent Agreement and the Service Agreements have been satisfied in full.

(F) In the event Customer assigns this Precedent Agreement and/or the Service Agreements in accordance with the applicable assignment provisions(s), or in the event Customer permanently releases all or a portion of Customer’s capacity under the Service Agreements in accordance with Section 3.14 of the General Terms & Conditions of Pipeline’s FERC Gas Tariff, the assignee and/or the permanent replacement customer, as applicable, shall be required to satisfy the requirements of this Paragraph 13 until all payment obligations under this Precedent Agreement and the Service Agreements have been satisfied in full.

14. This Precedent Agreement may not be modified or amended unless the Parties execute written agreements to that effect.

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15. Any company which succeeds by purchase, merger, or consolidation of title to the properties, substantially as an entirety, of Pipeline or Customer, will be entitled to the rights and will be subject to the obligations of its predecessor in title under this Precedent Agreement. Otherwise, neither Customer nor Pipeline may assign any of its rights or obligations under this Precedent Agreement without the prior written consent of the other Party hereto. Further in the event of any assignment of this Precedent Agreement or the Service Agreements by Customer or a permanent release of all or any portion of Customer’s capacity under the Service Agreements, Customer’s assignee or permanent replacement shipper, as the case may be, shall be required to comply with the provisions of Paragraph 13 for the remaining term of this Precedent Agreement and/or the Service Agreements.

16. Except as expressly provided for in this Precedent Agreement, nothing herein expressed or implied is intended or shall be construed to confer upon or give to any person not a Party hereto any rights, remedies or obligations under or by reason of this Precedent Agreement.

17. Each and every provision of this Precedent Agreement shall be considered as prepared through the joint efforts of the Parties and shall not be construed against either Party as a result of the preparation or drafting thereof. It is expressly agreed that no consideration shall be given or presumption made on the basis of who drafted this Precedent Agreement or any specific provision hereof.

18. The recitals and representations appearing first above are hereby incorporated in and made a part of this Precedent Agreement.

19. This Precedent Agreement shall be governed by, construed, interpreted, and performed in accordance with the laws of the State of Texas, without recourse to any laws governing the conflict of laws.

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20. Except as herein otherwise provided, any notice, request, demand, statement, or bill provided for in this Precedent Agreement, or any notice which either Party desires to give to the other, must be in writing and will be considered duly delivered when mailed by registered or certified mail, or overnight courier, to the other Party’s post office address set forth below:

Pipeline:	Texas Eastern Transmission, LP 5400 Westheimer Court Houston, Texas 77056 Attn: Vice President, Northeast Marketing and Business Development Phone: (713) 627-5400 Fax: (713) 989-3190
Customer:	Chesapeake Utilities Corporation 350 South Queen Street Dover, Delaware 19904 Attn: Jennifer Clausius Phone: 302-736-7818 Fax: 302-734-6011

or at such other address as either Party designates by written notice. Routine communications, including monthly statements, will be considered duly delivered when mailed by registered mail, certified mail, ordinary mail, or overnight courier.

21. When used in this Precedent Agreement, and unless otherwise defined herein, capitalized terms shall have the meanings set forth in Pipeline’s FERC Gas Tariff on file with the Commission, as amended from time to time.

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22. Customer represents and warrants that neither the execution, delivery and performance of this Precedent Agreement, the Service Agreements, the Negotiated Rate Agreements by Customer nor the consummation of the transactions contemplated by this Precedent Agreement, the Service Agreements or the Negotiated Rate Agreements , (A) conflicts or will conflict with or constitutes or will constitute a violation of the partnership agreement, limited liability company agreement, certificate of formation or conversion, certificate or articles of incorporation, bylaws or other constituent document (collectively, the “Organizational Documents”) of Customer, (B) conflicts or will conflict with or constitutes or will constitute a breach or violation of, or a default (or an event that, with notice or lapse of time or both, would constitute such a default) under any indenture, mortgage, deed of trust, loan agreement, lease or other agreement or instrument to which any Customer any of its subsidiaries (collectively, the “Customer Entities”) is a party or by which any of them or any of their respective properties may be bound, or (C) violates or will violate any statute, law or regulation or any order, judgment, decree or injunction of any court or governmental agency or body directed to any of the Customer Entities or any of their properties in a proceeding to which any of them or their property is a party.

IN WITNESS WHEREOF, the Parties hereto have caused this Precedent Agreement to be duly executed by their duly authorized officers as of the day and year first above written.

Texas Eastern Transmission, LP	Chesapeake Utilities Corporation
by its General Partner
Spectra Energy Transmission Services, LLC
By:	By:
Title:	Title:

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Texas Estern Transmission, LP
5400 Westheimer Court
Houston, TX 77056-5310

713.627.5400 main Mailing Address:
P.O. Box 1642
Houston, TX 77251-1642

EXHIBIT A

April 7, 2010

Chesapeake Utilities Corporation
350 South Queen Street
Dover, DE 19904
Attn: Jennifer Clausius

Re: Rate Schedule FT-1 Service Agreement between Texas Eastern and Customer dated on or about the date hereof — Negotiated Rate Agreement

Dear Jennifer:

By this transmittal letter, Texas Eastern Transmission, LP (“Texas Eastern” or “Pipeline”) and Chesapeake Utilities Corporation (“Customer”) are implementing a negotiated rate applicable to service under the above-referenced Rate Schedule FT-1 Service Agreement.

Texas Eastern and Customer hereby agree that the provisions on the attached pro forma tariff sheet(s) reflect the terms of their agreement, including the effectiveness of the negotiated rate. After execution of this letter by both Texas Eastern and Customer, Texas Eastern shall file the tariff sheet(s) with the Commission containing rate-related provisions identical to those provisions on the attached pro forma tariff sheet(s) in accordance with Section 29.7 of the General Terms and Conditions of the Texas Eastern tariff.

If the foregoing accurately sets forth your understanding of the matter covered herein, please so indicate by having a duly authorized representative sign in the space provided below and returning an original signed copy to the undersigned.

Sincerely,

Texas Eastern Transmission, LP
By its General Partner
Spectra Energy Transmission Services, LLC

ACCEPTED AND AGREED TO
THIS  _____  DAY OF APRIL, 2010

CHESAPEAKE UTILITIES CORPORATION

Name:

Title:

www.spectraenergy.com

TEXAS EASTERN TRANSMISSION, LP
FERC Gas Tariff	Pro Forma Sheet No.  _____
Seventh Revised Volume No. 1

STATEMENT OF NEGOTIATED RATES 1/ 2/ 3/

Customer Name: Chesapeake Utilities Corporation – Delaware Division

Service Agreement: [tbd]

Term of Negotiated Rate: The term of this negotiated rate commences on the Service Commencement Date (as such term is defined in the Service Agreement) and continues for the “Primary Term,” (as such term is defined in the Service Agreement).

Rate Schedule: FT-1

MDQ: 30,000 Dth/d

Reservation Rate: During the Primary Term, Customer shall pay a “Negotiated Reservation Rate” equal to a fixed monthly Reservation Charge of [$ ]. Such Negotiated Reservation Rate shall be stated per Dth, per month of Customer’s MDQ under the Service Agreement and will be adjusted as set forth in footnote 3 below. Customer shall also be responsible for any ASA (defined below) reservation surcharge applicable to Customer’s Service Agreement under Rate Schedule FT-1.

Usage Rate: During the Primary Term, shall be as follows:

(a) with respect to service from any Primary Receipt Point to any Primary Delivery Point, as such points are described below, and with respect to service provided from a Receipt Point to a Delivery Point located entirely within the “Transportation Path” (as defined in Pipeline’s FERC Gas Tariff), the Usage Charge shall be $0.00/Dth delivered, and Customer shall also be responsible for and pay the Applicable Shrinkage Adjustment (“ASA”) charge, the applicable ACA charge, ASA usage surcharge, EPC adjustment and all other charges and surcharges applicable to Customer’s Service Agreement under Rate Schedule FT-1 (provided, with respect to the applicable ASA charge, the charge is currently estimated to be 1.98%, but it will be the applicable incremental ASA charge in effect from time to time under Pipeline’s FERC Gas Tariff for the Project and in particular Customer’s Service Agreement);and while Customer may not nominate more than Customer’s MDQ, in the event actual quantities exceed the MDQ then with respect to service for such quantities above Customer’s MDQ, customer shall pay Pipeline, for all gas quantities transported, a usage rate, which shall be a negotiated rate equal to the maximum applicable Usage-2 Charge under Texas Eastern’s Rate Schedule FT-1 for this Project multiplied by the quantity of gas, in Dekatherms, delivered in the applicable day, and Customer shall also pay the applicable ASA charge, ACA charge, ASA usage surcharge, EPC adjustment and all other charges and surcharges applicable to the Service Agreement under Rate Schedule FT-1.

(b) with respect to service provided from a Receipt Point to a Delivery Point where one or both such points are located outside of the Transportation Path, the usage rate shall be the maximum applicable system Usage Charge under Texas Eastern’s Rate Schedule FT-1 multiplied by the quantity of gas, in Dekatherms, delivered in the applicable day, and Customer shall also pay the applicable system ASA charge, ACA charge, ASA usage surcharge, EPC adjustment and all other system charges and surcharges applicable to the Service Agreement under Rate Schedule FT-1.

Primary Receipt Points: Interconnection of Pipeline and Kinder Morgan REX Clarington, Monroe County, OH (Meter #73580)

Primary Delivery Points: at a proposed new interconnect to be established with Eastern Shore Natural Gas at Honeybrook, PA (Meter # ).

Recourse Rate(s): The Recourse Rate(s) applicable to this service is the applicable maximum rate(s) stated on Texas Eastern’s Tariff Sheets at the applicable time.

Issued by: D. A. McCallum, Director, Rates and Tariffs
Issued on:	Effective on:

TEXAS EASTERN TRANSMISSION, LP
FERC Gas Tariff	Pro Forma Sheet No.  _____
Seventh Revised Volume No. 1

1/ This agreement conforms to the applicable form of service agreement.

2/ This negotiated rate shall apply only to service under Contract No. [tbd] and using the points designated herein, as further described herein; provided, if Customer amends the Service Agreement to change one or more of its primary points listed above pursuant to the provisions of Pipeline’s FERC Gas Tariff, Pipeline shall have the option to terminate this negotiated rate by providing Customer with written notice of Pipeline’s intent to terminate the negotiated rate and, in such case, Pipeline’s maximum recourse rates referenced above shall apply for the remaining term of the Service Agreement, unless and until otherwise agreed in writing between Customer and Pipeline; provided, further that following the term of this negotiated rate as such term is described above, Pipeline’s maximum recourse rates referenced above shall apply for any remaining term under the Service Agreement.

3/ Pipeline and Customer acknowledge that the Capital Costs attributable to the Project facilities which underlie the monthly Reservation Charge described in the Reservation Rate section above are reasonably estimated to be $[tbd dollars]. Such estimate of Capital Costs is expected to be substantially the same as the estimated Project capital costs reflected in the Exhibit K included with the certificate application filed by Pipeline with the Federal Energy Regulatory Commission (“Commission”) for the Project. The monthly Reservation Charge shall be adjusted, pursuant to the formula set forth in this footnote 3, solely to reflect any differences between the estimated $[tbd] and the amount of Capital Costs attributable to the Project facilities reflected by Pipeline in an amended Exhibit K that is filed by Pipeline with the Commission in the certificate proceeding regarding the Project. Pipeline shall prepare such amended Exhibit K in accordance with Section 157.14(a)(13) of Title 18 of the Code of Federal Regulations and such amended Exhibit K shall reflect Pipeline’s reasonable good faith estimate at the time of the total Capital Costs attributable to the Project, and Pipeline shall file such amended Exhibit K at least thirty (30) days, but no more than sixty (60) days, prior to the in-service date of the Project, as such in-service date is estimated to occur by Pipeline at the time (“Amended Exhibit K”).

Such monthly Reservation Charge shall be adjusted by an amount per Dth of MDQ equal to $0.3042 (equivalent to $0.01 per Dth per Day) for each $[tbd] million increment of Capital Costs as reflected in the Amended Exhibit K above or below the estimated $[tbd] amount (to be clear, the Reservation Charge adjustment will occur to the fourth decimal point and thus the rate may be adjusted in increments as small as $0.0001 per Dth per Day); provided, if the Capital Costs reflected in the Amended Exhibit K exceed 15% above the estimated Capital Costs of $[tbd], then the amount used for the Reservation Charge adjustment shall be deemed to be 1.15 multiplied by the estimated Capital Costs, and if the Capital Costs reflected in the Cost Report are more than 10% below the estimated Capital Costs of $[tbd], then the amount used for the Reservation Charge adjustment shall be deemed to be .90 multiplied by the estimated Capital Costs.

For purposes of this Negotiated Rate Agreement, (1) the term “Project” shall mean the Project as generally described in the recitals to the Precedent Agreement between the Parties regarding construction of facilities necessary to provide the service contemplated in the Service Agreement, and as more specifically described in the certificate application, as amended, related to such facilities on file with the Commission, and(2) the term “Capital Costs” means the total capital costs incurred by Pipeline for the development and construction of the Project, including, without limitation, the allowance for funds used during construction, as such costs are reflected in the Amended Exhibit K, including all costs incurred to the date of the Amended Exhibit K and estimated to be incurred for final completion of the applicable project.

Issued by: D. A. McCallum, Director, Rates and Tariffs
Issued on:	Effective on:

TEXAS EASTERN TRANSMISSION, LP
FERC Gas Tariff	Pro Forma Sheet No.  _____
Seventh Revised Volume No. 1

4/ Texas Eastern and Customer agree that Contract No. [tbd] is a ROFR Agreement and will remain a ROFR Agreement following the end of the Negotiated Rate Term.

5/ Texas Eastern and Customer agree that in the event any carbon emissions tax or other greenhouse gas assessment is imposed on Texas Eastern as a surcharge, or other form of rate recovery, during the term of this Negotiated Rate Agreement, then Customer shall agree to modify the negotiated rate set forth herein to include Customer’s ratable share of such amounts. Further, if Texas Eastern is required to incur additional expense to comply with any greenhouse gas laws, rules or regulations, then Customer shall agree to modify the negotiated rate set forth herein to include Customer’s ratable share of such additional expense.

Issued by: D. A. McCallum, Director, Rates and Tariffs
Issued on:	Effective on:

Texas Estern Transmission, LP
5400 Westheimer Court
Houston, TX 77056-5310

713.627.5400 main Mailing Address:
P.O. Box 1642
Houston, TX 77251-1642

EXHIBIT A-1

April 7, 2010

Chesapeake Utilities Corporation
350 South Queen Street
Dover, DE 19904
Attn: Jennifer Clausius

Re: Rate Schedule FT-1 Service Agreement between Texas Eastern and Customer dated on or about the date hereof — Negotiated Rate Agreement

Dear Jennifer:

By this transmittal letter, Texas Eastern Transmission, LP (“Texas Eastern” or “Pipeline”) and Chesapeake Utilities Corporation (“Customer”) are implementing a negotiated rate applicable to service under the above-referenced Rate Schedule FT-1 Service Agreement.

Texas Eastern and Customer hereby agree that the provisions on the attached pro forma tariff sheet(s) reflect the terms of their agreement, including the effectiveness of the negotiated rate. After execution of this letter by both Texas Eastern and Customer, Texas Eastern shall file the tariff sheet(s) with the Commission containing rate-related provisions identical to those provisions on the attached pro forma tariff sheet(s) in accordance with Section 29.7 of the General Terms and Conditions of the Texas Eastern tariff.

If the foregoing accurately sets forth your understanding of the matter covered herein, please so indicate by having a duly authorized representative sign in the space provided below and returning an original signed copy to the undersigned.

Sincerely,

Texas Eastern Transmission, LP
By its General Partner
Spectra Energy Transmission Services, LLC

ACCEPTED AND AGREED TO
THIS  _____  DAY OF APRIL, 2010

CHESAPEAKE UTILITIES CORPORATION

Name:

Title:

www.spectraenergy.com

TEXAS EASTERN TRANSMISSION, LP
FERC Gas Tariff	Pro Forma Sheet No.  _____
Seventh Revised Volume No. 1

STATEMENT OF NEGOTIATED RATES 1/ 2/ 3/

Customer Name: Chesapeake Utilities Corporation — Maryland Division

Service Agreement: [tbd]

Term of Negotiated Rate: The term of this negotiated rate commences on the Service Commencement Date (as such term is defined in the Service Agreement) and continues for the “Primary Term,” (as such term is defined in the Service Agreement).

Rate Schedule: FT-1

MDQ: 10,000 Dth/d

Reservation Rate: During the Primary Term, Customer shall pay a “Negotiated Reservation Rate” equal to a fixed monthly Reservation Charge of [$ ]. Such Negotiated Reservation Rate shall be stated per Dth, per month of Customer’s MDQ under the Service Agreement and will be adjusted as set forth in footnote 3 below. Customer shall also be responsible for any ASA (defined below) reservation surcharge applicable to Customer’s Service Agreement under Rate Schedule FT-1.

Usage Rate: During the Primary Term, shall be as follows:

(a) with respect to service from any Primary Receipt Point to any Primary Delivery Point, as such points are described below, and with respect to service provided from a Receipt Point to a Delivery Point located entirely within the “Transportation Path” (as defined in Pipeline’s FERC Gas Tariff), the Usage Charge shall be $0.00/Dth delivered, and Customer shall also be responsible for and pay the Applicable Shrinkage Adjustment (“ASA”) charge, the applicable ACA charge, ASA usage surcharge, EPC adjustment and all other charges and surcharges applicable to Customer’s Service Agreement under Rate Schedule FT-1 (provided, with respect to the applicable ASA charge, the charge is currently estimated to be 1.98%, but it will be the applicable incremental ASA charge in effect from time to time under Pipeline’s FERC Gas Tariff for the Project and in particular Customer’s Service Agreement);and while Customer may not nominate more than Customer’s MDQ, in the event actual quantities exceed the MDQ then with respect to service for such quantities above Customer’s MDQ, customer shall pay Pipeline, for all gas quantities transported, a usage rate, which shall be a negotiated rate equal to the maximum applicable Usage-2 Charge under Texas Eastern’s Rate Schedule FT-1 for this Project multiplied by the quantity of gas, in Dekatherms, delivered in the applicable day, and Customer shall also pay the applicable ASA charge, ACA charge, ASA usage surcharge, EPC adjustment and all other charges and surcharges applicable to the Service Agreement under Rate Schedule FT-1.

(b) with respect to service provided from a Receipt Point to a Delivery Point where one or both such points are located outside of the Transportation Path, the usage rate shall be the maximum applicable system Usage Charge under Texas Eastern’s Rate Schedule FT-1 multiplied by the quantity of gas, in Dekatherms, delivered in the applicable day, and Customer shall also pay the applicable system ASA charge, ACA charge, ASA usage surcharge, EPC adjustment and all other system charges and surcharges applicable to the Service Agreement under Rate Schedule FT-1.

Primary Receipt Points: Interconnection of Pipeline and Kinder Morgan REX Clarington, Monroe County, OH (Meter #73580)

Primary Delivery Points: at a proposed new interconnect to be established with Eastern Shore Natural Gas at Honeybrook, PA (Meter # ).

Recourse Rate(s): The Recourse Rate(s) applicable to this service is the applicable maximum rate(s) stated on Texas Eastern’s Tariff Sheets at the applicable time.

Issued by: D. A. McCallum, Director, Rates and Tariffs
Issued on:	Effective on:

TEXAS EASTERN TRANSMISSION, LP
FERC Gas Tariff	Pro Forma Sheet No.  _____
Seventh Revised Volume No. 1

1/ This agreement conforms to the applicable form of service agreement.

2/ This negotiated rate shall apply only to service under Contract No. [tbd] and using the points designated herein, as further described herein; provided, if Customer amends the Service Agreement to change one or more of its primary points listed above pursuant to the provisions of Pipeline’s FERC Gas Tariff, Pipeline shall have the option to terminate this negotiated rate by providing Customer with written notice of Pipeline’s intent to terminate the negotiated rate and, in such case, Pipeline’s maximum recourse rates referenced above shall apply for the remaining term of the Service Agreement, unless and until otherwise agreed in writing between Customer and Pipeline; provided, further that following the term of this negotiated rate as such term is described above, Pipeline’s maximum recourse rates referenced above shall apply for any remaining term under the Service Agreement.

3/ Pipeline and Customer acknowledge that the Capital Costs attributable to the Project facilities which underlie the monthly Reservation Charge described in the Reservation Rate section above are reasonably estimated to be $[tbd dollars]. Such estimate of Capital Costs is expected to be substantially the same as the estimated Project capital costs reflected in the Exhibit K included with the certificate application filed by Pipeline with the Federal Energy Regulatory Commission (“Commission”) for the Project. The monthly Reservation Charge shall be adjusted, pursuant to the formula set forth in this footnote 3, solely to reflect any differences between the estimated $[tbd] and the amount of Capital Costs attributable to the Project facilities reflected by Pipeline in an amended Exhibit K that is filed by Pipeline with the Commission in the certificate proceeding regarding the Project. Pipeline shall prepare such amended Exhibit K in accordance with Section 157.14(a)(13) of Title 18 of the Code of Federal Regulations and such amended Exhibit K shall reflect Pipeline’s reasonable good faith estimate at the time of the total Capital Costs attributable to the Project, and Pipeline shall file such amended Exhibit K at least thirty (30) days, but no more than sixty (60) days, prior to the in-service date of the Project, as such in-service date is estimated to occur by Pipeline at the time (“Amended Exhibit K”).

Such monthly Reservation Charge shall be adjusted by an amount per Dth of MDQ equal to $0.3042 (equivalent to $0.01 per Dth per Day) for each $[tbd] million increment of Capital Costs as reflected in the Amended Exhibit K above or below the estimated $[tbd] amount (to be clear, the Reservation Charge adjustment will occur to the fourth decimal point and thus the rate may be adjusted in increments as small as $0.0001 per Dth per Day); provided, if the Capital Costs reflected in the Amended Exhibit K exceed 15% above the estimated Capital Costs of $[tbd], then the amount used for the Reservation Charge adjustment shall be deemed to be 1.15 multiplied by the estimated Capital Costs, and if the Capital Costs reflected in the Cost Report are more than 10% below the estimated Capital Costs of $[tbd], then the amount used for the Reservation Charge adjustment shall be deemed to be .90 multiplied by the estimated Capital Costs.

For purposes of this Negotiated Rate Agreement, (1) the term “Project” shall mean the Project as generally described in the recitals to the Precedent Agreement between the Parties regarding construction of facilities necessary to provide the service contemplated in the Service Agreement, and as more specifically described in the certificate application, as amended, related to such facilities on file with the Commission, and(2) the term “Capital Costs” means the total capital costs incurred by Pipeline for the development and construction of the Project, including, without limitation, the allowance for funds used during construction, as such costs are reflected in the Amended Exhibit K, including all costs incurred to the date of the Amended Exhibit K and estimated to be incurred for final completion of the applicable project.

Issued by: D. A. McCallum, Director, Rates and Tariffs
Issued on:	Effective on:

TEXAS EASTERN TRANSMISSION, LP
FERC Gas Tariff	Pro Forma Sheet No.  _____
Seventh Revised Volume No. 1

4/ Texas Eastern and Customer agree that Contract No. [tbd] is a ROFR Agreement and will remain a ROFR Agreement following the end of the Negotiated Rate Term.

5/ Texas Eastern and Customer agree that in the event any carbon emissions tax or other greenhouse gas assessment is imposed on Texas Eastern as a surcharge, or other form of rate recovery, during the term of this Negotiated Rate Agreement, then Customer shall agree to modify the negotiated rate set forth herein to include Customer’s ratable share of such amounts. Further, if Texas Eastern is required to incur additional expense to comply with any greenhouse gas laws, rules or regulations, then Customer shall agree to modify the negotiated rate set forth herein to include Customer’s ratable share of such additional expense.

Issued by: D. A. McCallum, Director, Rates and Tariffs
Issued on:	Effective on:

EXHIBIT B

IRREVOCABLE STANDBY LETTER OF CREDIT

Letter of Credit No:	Date:                     , 2010
	Date of Expiry:                     , 201_____
Beneficiary:	Account Party:
Texas Eastern Transmission, LP	Chesapeake Utilities Corporation
5400 Westheimer Court	350 South Queen Street
Houston, TX 77056	Dover, DE 19904

Attn: Credit Director

[Name of Bank] (“Issuing Bank”) hereby establishes this Irrevocable and Transferable Standby Letter of Credit No.                      in favor of Texas Eastern Transmission, LP (“Beneficiary”) for the account of Chesapeake Utilities Corporation (“Account Party”) for the aggregate amount of up to (dollar amount) available to Beneficiary by presenting sight draft(s) to Issuing Bank when accompanied by a signed and dated statement by a purported officer of Beneficiary certifying one or more of the following, as applicable:

1. “The amount drawn herein is to satisfy obligations of Account Party between Beneficiary and Account Party. Wherefore, the undersigned Beneficiary does hereby demand payment of $                    . Beneficiary further certifies that supporting documents when required were presented to Account Party and that Account Party has not satisfied its obligations.” And / or

2. “This Letter of Credit will expire in less than thirty (30) days and Beneficiary has not received an extension of said Letter of Credit or other acceptable replacement collateral from Account Party. Wherefore, the undersigned Beneficiary does hereby demand payment of $                    . Upon timely receipt of an amendment extending this Letter of Credit, this drawing is to be considered automatically rescinded.” And / or

3. “Issuing Bank no longer has one of the following: an individual rating of at least “A-” from Fitch Investor Service, Inc., or a long-term senior unsecured debt rating of at least “A-” by Standard & Poor’s Rating Group, or a long-term senior unsecured debt rating of at least “A3” by Moody’s Investor Services, Inc., and Account Party has not caused a replacement Letter of Credit from an alternate financial institution acceptable to Beneficiary to be issued to Beneficiary. Wherefore, the undersigned Beneficiary does hereby demand payment of $                                        .”

SPECIAL TERMS AND CONDITIONS

1. Partial and multiple drawings are allowed hereunder. The amount that may be drawn by Beneficiary under this Letter of Credit shall be automatically reduced by the amount of any payments made through Issuing Bank referencing this Letter of Credit.

2. This Letter of Credit shall automatically extend without amendment for periods of one year each from the present or any future expiry date unless Issuing Bank notifies Beneficiary in writing at least sixty (60) days prior to such present or future expiry date, as applicable, that Issuing Bank elects not to further extend this Letter of Credit.

3. This letter of Credit is transferable without charge any number of times, but only (a) to a party which succeeds to or is assigned and assumes in writing the rights and obligations of the transferor under that certain Precedent Agreement dated as of April  _____, 2010, between Texas Eastern Transmission, LP, the initial Beneficiary, and the Account Party (the “Agreement”) in accordance with or as permitted by the terms of the Agreement and only in connection with such succession or assignment, (b) in the amount of the full unutilized balance hereof and not in part, and (c) with the written approval of Account Party which consent shall not be unreasonably withheld, conditioned or delayed.

4. The term “Beneficiary” includes any successor by operation of law of the named beneficiary to this Letter of Credit, including, without limitation, any liquidator, any rehabilitator, receiver or conservator.

5. Presentations for drawing may be delivered in person, by mail, by express delivery, or by facsimile.

6. All Bank charges are for the account of Account Party.

7. Article 36 under UCP 600 is modified as follows: If the Letter of Credit expires while the place for presentation is closed due to events described in said Article, the expiry date of this Letter of Credit shall be automatically extended without amendment to a date thirty (30) calendar days after the place for presentation reopens for business.

Issuing Bank hereby agrees with Beneficiary that documents presented for drawing in compliance with the terms of this Letter of Credit will be duly honored upon presentation at Issuing Bank’s counters if presented on or before the expiry date.

Unless otherwise expressly stated herein, this Letter of Credit is subject to the Uniform Customs and Practice for Documentary Credits (“UCP”), 2007 Revision, International Chamber of Commerce Publication No. 600. Matters not covered by the UCP shall be governed and construed in accordance with the laws of the state of New York.

ISSUING BANK SIGNATURE

EX-31.1

Exhibit 31.1

CERTIFICATE PURSUANT TO RULE 13A-14(A)
UNDER THE SECURITIES EXCHANGE ACT OF 1934

I, John R. Schimkaitis, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended March 31, 2010 of Chesapeake Utilities Corporation;

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

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

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

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2010

/s/ John R. Schimkaitis

John R. Schimkaitis

Vice Chairman and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATE PURSUANT TO RULE 13A-14(A)
UNDER THE SECURITIES EXCHANGE ACT OF 1934

I, Beth W. Cooper, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended March 31, 2010 of Chesapeake Utilities Corporation;

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

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

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

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2010

/s/ Beth W. Cooper

Beth W. Cooper

Senior Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

Certificate of Chief Executive Officer

of

Chesapeake Utilities Corporation

(pursuant to 18 U.S.C. Section 1350)

I, John R. Schimkaitis, Vice Chairman and Chief Executive Officer of Chesapeake Utilities Corporation, certify that, to the best of my knowledge, the Quarterly Report on Form 10-Q of Chesapeake Utilities Corporation (“Chesapeake”) for the period ended March 31, 2010, filed with the Securities and Exchange Commission on the date hereof (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Chesapeake.

/s/ John R. Schimkaitis

John R. Schimkaitis

May 7, 2010

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

EX-32.2

Exhibit 32.2

Certificate of Chief Financial Officer

of

Chesapeake Utilities Corporation

(pursuant to 18 U.S.C. Section 1350)

I, Beth W. Cooper, Senior Vice President and Chief Financial Officer of Chesapeake Utilities Corporation, certify that, to the best of my knowledge, the Quarterly Report on Form 10-Q of Chesapeake Utilities Corporation (“Chesapeake”) for the period ended March 31, 2010, filed with the Securities and Exchange Commission on the date hereof (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Chesapeake.

/s/ Beth W. Cooper

Beth W. Cooper

May 7, 2010

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