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, 2009

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 þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company filer. See definitions of “large accelerated filer” and “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 — 6,855,640 shares outstanding as of April 30, 2009.

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	18
Item 3. Quantitative and Qualitative Disclosures about Market Risk	31
Item 4. Controls and Procedures	32
PART II — OTHER INFORMATION	33
Item 1. Legal Proceedings	33
Item 1A. Risk Factors	33
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	33
Item 3. Defaults upon Senior Securities	33
Item 4. Submission of Matters to a Vote of Security Holders	33
Item 5. Other Information	33
Item 6. Exhibits	34
SIGNATURES	35
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

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

Subsidiaries of Chesapeake Utilities Corporation
Chesapeake	The Registrant, the Registrant and its subsidiaries, or the Registrant’s subsidiaries, as appropriate in the context of the disclosure
Company	The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries, as appropriate in the context of the disclosure
ESNG	Eastern Shore Natural Gas Company, a wholly-owned subsidiary of Chesapeake
PESCO	Peninsula Energy Services Company, Inc., a wholly-owned subsidiary of Chesapeake
Xeron	Xeron, Inc, a wholly-owned subsidiary of Chesapeake
Regulatory Agencies
APB	Accounting Principles Board
Delaware PSC	Delaware Public Service Commission
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FDEP	Florida Department of Environmental Protection
Maryland PSC	Maryland Public Service Commission
MDE	Maryland Department of the Environment
SEC	Securities and Exchange Commission
Other
AS/SVE	Air Sparging and Soil/Vapor Extraction
CGS	Community Gas Systems
DSCP	Directors Stock Compensation Plan
Dts	Dekatherms
E3 Project	ESNG Energylink Expansion Project
EITF	Financial Accounting Standards Board Emerging Issues Task Force
FSP	Financial Accounting Standards Board Staff Position
GAAP	Generally Accepted Accounting Principles
GSR	Gas Sales Service Rates
HDD	Heating Degree-Days
MMBtus	One million (1,000,000) British Thermal Units
PIP	Performance Incentive Plan
RAP	Remedial Action Plan
SFAS	Statement of Financial Accounting Standards
Accounting Standards
EITF 08-03	EITF 08-03, Accounting for Maintenance Deposits Under Lease Arrangements
FSP APB 14-1	FSP APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlements)
FSP EITF 03-6-1	FSP EITF 03-6-1, Determining Whether Instruments Granted in Share-based Payment Transactions are Participating Securities
FSP FAS 107-1 and APB 28-1	FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments
FSP FAS 115-2 and FAS 124-2	FSP FAS 115-2 and SFAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments
FSP FAS 132(R)-1	FSP FAS 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets
FSP FAS 141(R)-1	FSP FAS 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies
FSP FAS 142-3	FSP FAS 142-3, Determining the Useful Life of Intangible Assets
FSP FAS 157-4	FSP FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly
SFAS No. 71	SFAS No. 71, Accounting for the Effects of Certain Types of Regulation

SFAS No. 115	SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities
SFAS No. 123(R)	SFAS No. 123(R), Share-Based Payment
SFAS No. 133	SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities
SFAS No. 138	SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities
SFAS No. 141(R)	SFAS No. 141(R), Business Combinations
SFAS No. 157	SFAS No. 157, Fair Value Measurements
SFAS No. 160	SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of Accounting Research Bulletin 51
SFAS No. 161	SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS No. 133

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PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Income (Unaudited)
(in Thousands, Except Shares and Per Share Data)

For the Three Months Ended March 31,	2009		2008
Operating Revenues	$	104,479	$	100,274
Operating Expenses
Cost of sales, excluding costs below		71,222		70,981
Operations		12,359		10,769
Maintenance		615		485
Depreciation and amortization		2,384		2,203
Other taxes		1,933		1,795
Total operating expenses		88,513		86,233
Operating Income		15,966		14,041
Other income, net of other expenses		33		17
Interest charges		1,642		1,593
Income Before Income Taxes		14,357		12,465
Income taxes		5,764		4,891
Net Income	$	8,593	$	7,574
Weighted-average common shares outstanding:
Basic		6,832,675		6,795,309
Diluted		6,943,129		6,907,124
Earnings Per Share of Common Stock:
Basic	$	1.26	$	1.11
Diluted	$	1.24	$	1.10
Cash Dividends Declared Per Share of Common Stock:	$	0.305	$	0.295

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)
(in Thousands)

For The Three Months Ended March 31,	2009			2008
Operating Activities
Net Income	$	8,593		$	7,574
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		2,384			2,203
Depreciation and accretion included in other costs		664			376
Deferred income taxes, net		(790	)		512
Unrealized loss on commodity contracts		1,294			174
Unrealized loss on investments		94			78
Employee benefits		412			92
Share based compensation		241			231
Changes in assets and liabilities:
Sale (purchase) of investments		34			(17	)
Accounts receivable and accrued revenue		9,217			129
Propane inventory, storage gas and other inventory		8,527			6,691
Regulatory assets		604			13
Prepaid expenses and other current assets		1,360			956
Accounts payable and other accrued liabilities		(10,940	)		(13,071	)
Income taxes receivable		6,345			4,112
Accrued interest		1,140			682
Customer deposits and refunds		(1,854	)		(1,514	)
Accrued compensation		(1,608	)		(2,066	)
Regulatory liabilities		5,357			154
Other liabilities		(38	)		(199	)
Net cash provided by operating activities		31,036			7,110
Investing Activities
Property, plant and equipment expenditures		(4,124	)		(4,412	)
Environmental expenditures		(8	)		(129	)
Net cash used by investing activities		(4,132	)		(4,541	)
Financing Activities
Common stock dividends		(2,082	)		(1,791	)
Issuance of stock for Dividend Reinvestment Plan		64			15
Change in cash overdrafts due to outstanding checks		—			(498	)
Net borrowing (repayment) under line of credit agreements		(23,200	)		1,020
Repayment of long-term debt		(20	)		(1,020	)
Net cash used by financing activities		(25,238	)		(2,274	)
Net Increase in Cash and Cash Equivalents		1,666			295
Cash and Cash Equivalents — Beginning of Period		1,611			2,593
Cash and Cash Equivalents — End of Period	$	3,277		$	2,888

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)
(in Thousands, Except Shares and Per Share Data)

	March 31,			December 31,
Assets	2009			2008
Property, Plant and Equipment
Natural gas	$	317,954		$	316,125
Propane		52,144			51,827
Advanced information services		1,454			1,439
Other plant		10,875			10,816
Total property, plant and equipment		382,427			380,207
Less: Accumulated depreciation and amortization		(103,606	)		(101,018	)
Plus: Construction work in progress		2,602			1,482
Net property, plant and equipment		281,423			280,671
Investments		1,473			1,601
Current Assets
Cash and cash equivalents		3,277			1,611
Accounts receivable (less allowance for uncollectible accounts of $1,324 and $1,159, respectively)		43,103			52,905
Accrued revenue		5,754			5,168
Propane inventory, at average cost		3,388			5,711
Other inventory, at average cost		1,447			1,479
Regulatory assets		295			826
Storage gas prepayments		3,320			9,492
Income taxes receivable		1,098			7,443
Deferred income taxes		3,836			1,578
Prepaid expenses		3,272			4,679
Mark-to-market energy assets		453			4,482
Other current assets		146			147
Total current assets		69,389			95,521
Deferred Charges and Other Assets
Goodwill		674			674
Other intangible assets, net		161			164
Long-term receivables		480			533
Regulatory assets		2,716			2,806
Other deferred charges		3,854			3,825
Total deferred charges and other assets		7,885			8,002
Total Assets	$	360,170		$	385,795

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)
(in Thousands, Except Shares and Per Share Data)

	March 31,			December 31,
Capitalization and Liabilities	2009			2008
Capitalization
Stockholders’ equity
Common Stock, par value $0.4867 per share (authorized 12,000,000 shares)	$	3,329		$	3,323
Additional paid-in capital		67,198			66,681
Retained earnings		63,319			56,817
Accumulated other comprehensive loss		(3,674	)		(3,748	)
Deferred compensation obligation		1,567			1,549
Treasury stock		(1,567	)		(1,549	)
Total stockholders’ equity		130,172			123,073
Long-term debt, net of current maturities		86,358			86,422
Total capitalization		216,530			209,495
Current Liabilities
Current portion of long-term debt		6,656			6,656
Short-term borrowing		9,800			33,000
Accounts payable		28,537			40,202
Customer deposits and refunds		7,681			9,534
Accrued interest		2,163			1,024
Dividends payable		2,086			2,082
Accrued compensation		1,702			3,305
Regulatory liabilities		8,615			3,227
Mark-to-market energy liabilities		317			3,052
Other accrued liabilities		3,108			2,969
Total current liabilities		70,665			105,051
Deferred Credits and Other Liabilities
Deferred income taxes		39,237			37,720
Deferred investment tax credits		225			235
Regulatory liabilities		844			875
Environmental liabilities		486			511
Other pension and benefit costs		7,418			7,335
Accrued asset removal cost		20,901			20,641
Other liabilities		3,864			3,932
Total deferred credits and other liabilities		72,975			71,249
Commitments and Contingencies (Note 3)
Total Capitalization and Liabilities	$	360,170		$	385,795

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Stockholders’ Equity
(in Thousands, Except Shares and Per Share Data)

											Accumulated
	Common Stock					Additional					Other
	Number of					Paid-In		Retained			Comprehensive			Deferred		Treasury
	Shares			Par Value		Capital		Earnings			Loss			Compensation		Stock			Total
Balances at December 31, 2007		6,777,410		$	3,298	$	65,592	$	51,538		$	(852	)	$	1,404	$	(1,404	)	$	119,576
Net earnings									13,607											13,607
Other comprehensive income, net of tax:
Employee Benefit Plans, net of tax:
Amortization of prior service costs (4)												(71	)							(71	)
Net loss (5)												(2,825	)							(2,825	)
Total comprehensive income																				10,711
Dividend Reinvestment Plan		9,060			5		269													274
Retirement Savings Plan		5,260			3		156													159
Conversion of debentures		10,397			5		172													177
Share based compensation (1) (3)		24,994			12		442													454
Tax benefit on stock warrants							50													50
Deferred Compensation Plan															145		(145	)		—
Purchase of treasury stock		(2,425	)														(72	)		(72	)
Sale and distribution of treasury stock		2,425															72			72
Dividends on stock-based compensation									(81	)										(81	)
Cash dividends (2)									(8,247	)										(8,247	)
Balances at December 31, 2008 (Unaudited)		6,827,121			3,323		66,681		56,817			(3,748	)		1,549		(1,549	)		123,073
Net earnings									8,593											8,593
Other comprehensive income, net of tax:
Employee Benefit Plans, net of tax:
Amortization of prior service costs (4)												1								1
Net Gain (5)												73								73
Total comprehensive income																				8,667
Dividend Reinvestment Plan		3,286			2		79													81
Retirement Savings Plan		7,166			3		195													198
Conversion of debentures		2,585			1		43													44
Share based compensation (1) (3)		200			—		201													201
Deferred Compensation Plan															18		(18	)		—
Purchase of treasury stock		(648	)														21			21
Sale and distribution of treasury stock		648															(21	)		(21	)
Dividends on stock-based compensation									(6	)										(6	)
Cash dividends (2)									(2,085	)										(2,085	)
Balances at March 31, 2009		6,840,358		$	3,329	$	67,198	$	63,319		$	(3,674	)	$	1,567	$	(1,567	)	$	130,172

(1)	Includes amounts for shares issued for Directors’ compensation.
(2)	Cash dividends per share for the periods ended March 31, 2009 and December 31, 2008 were $0.305 and $1.21, respectively.
(3)	The shares issued under the PIP are net of shares withheld for employee taxes. For 2008, the Company withheld 12,511 shares for taxes. The Company did not issue any shares for the PIP in 2009.
(4)	Tax expense (benefit) recognized on the prior service cost component of employees benefit plans for the periods ended March 31, 2009 and December 31, 2008 were approximately $1 and ($52), respectively.
(5)	Tax expense (benefit) recognized on the net gain (loss) component of employees benefit plans for the periods ended March 31, 2009 and December 31, 2008 were $49 and ($1,900), respectively.

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

- 5 -

Notes to Condensed Consolidated Financial Statements

1. Basis of Presentation

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

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and United States of America Generally Accepted Accounting Principles (“GAAP”). In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in the Company’s latest Annual Report on Form 10-K filed with the SEC on March 9, 2009. In the opinion of management, these statements reflect normal recurring adjustments that are necessary for a fair presentation of the Company’s results of operations, financial position and cash flows for the interim periods presented.

The Company reclassified certain amounts reported in the three months ended March 31, 2008 to conform to current period classifications. These reclassifications are considered immaterial to the overall presentation of the Company’s condensed consolidated financial statements.

2. Calculation of Earnings Per Share

For the Three Months Ended March 31,	2009		2008
(in Thousands, Except Shares and Per Share Data)
Calculation of Basic Earnings Per Share:
Net Income	$	8,593	$	7,574
Weighted average shares outstanding		6,832,675		6,795,309
Basic Earnings Per Share	$	1.26	$	1.11
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	8,593	$	7,574
Effect of 8.25% Convertible debentures		20		23
Adjusted numerator — Diluted	$	8,613	$	7,597
Reconciliation of Denominator:
Weighted shares outstanding — Basic		6,832,675		6,795,309
Effect of dilutive securities:
Share-based Compensation		14,246		4,669
8.25% Convertible debentures		96,208		107,146
Adjusted denominator — Diluted		6,943,129		6,907,124
Diluted Earnings Per Share	$	1.24	$	1.10

3. Commitments and Contingencies

Rates and Regulatory Matters

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

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Delaware. On September 1, 2008, the 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 rates, effective November 1, 2008. On September 16, 2008, the Delaware PSC authorized the Delaware division to implement the GSR charges on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. The Delaware division was required by its natural gas tariff to file a revised application if its projected over-collection of gas costs for the determination period of November 2007 through October 2008 exceeded four and one half percent (4.5 percent) of total firm gas costs. As a result of a dramatic decrease in the cost of natural gas, on January 8, 2009, the Delaware division filed with the Delaware PSC a supplemental GSR Application, seeking approval to change its GSR rates, effective February 1, 2009. On January 29, 2009, the Delaware PSC authorized the Delaware division to implement the supplemental GSR charges on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. The parties to the docket, the Delaware PSC and the Division of the Public Advocate, have recommended either a deferral of the recovery or a cost disallowance of approximately $275,000 related to pipeline expansion costs and a prospective adjustment to the margin-sharing mechanism related to the division’s Asset Management Agreement that would potentially decrease the division’s share of the margin by approximately $80,000 per year. The Delaware division disagrees with this recommendation on the merits and because it ignores the legal standard in Delaware for the disallowance of fuel procurement costs. The Delaware division submitted its rebuttal position on April 24, 2009 and anticipates a final decision by the Delaware PSC during the second or third quarter of 2009. The Delaware division will appeal any unfavorable decisions by the Delaware PSC. As of March 31, 2009, the Company continued to include the $275,000 related to the pipeline expansion costs in question as a regulatory asset in the accompanying condensed consolidated balance sheet.

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

Maryland. On December 16, 2008, the Maryland Public Service Commission (“Maryland PSC”) held an evidentiary hearing to determine the reasonableness of the Maryland division’s four quarterly gas cost recovery filings during the twelve months ended September 30, 2008. No issues were raised at the hearing, and on December 19, 2008, the Hearing Examiner in this proceeding issued a proposed Order approving the division’s four quarterly gas cost recovery filings, which became a final Order of the Maryland PSC on January 21, 2009.

On April 24, 2009, the Maryland PSC issued an Order whereby it defined payment plan parameters and termination procedures for utilities that would increase the likelihood that customers could pay their past due amounts to avoid termination of natural gas service. This Order requires the Maryland Division to notify customers in writing, prior to issuing a termination notice, certain details about their past due balance, the availability of payment plans, and that it must continue to offer flexible and tailored payment plans.

Florida. On March 13, 2009, the Company filed a test-year notification letter with the Florida Public Service Commission requesting that a docket be opened for its general rate increase proceeding. The Company expects to file the required schedules, direct testimony and other supporting documentation during the second half of 2009. The Company intends to seek its permanent rate relief through the Proposed Agency Action procedure and will request interim rate relief in this proceeding.

ESNG. The following activities related to certain FERC Orders and the expansions of its transmission system were undertaken by ESNG:

System Expansion 2006 — 2008. In accordance with the requirements in the FERC’s Order Issuing Certificate for the 2006 — 2008 System Expansion, ESNG had until June 13, 2009 to construct the remaining facilities that were authorized in the project filing. On February 3, 2009, ESNG requested authorization to modify the previously required completion date, and to commence construction of the facilities, which will provide for the remaining 7,200 dekatherms (“Dts”) of additional firm service capacity previously approved by the FERC, and which will permit ESNG to earn additional annualized gross margin of approximately $1.0 million. On March 13, 2009, the FERC granted the requested authorization, and construction of these facilities has commenced and they are expected to be placed into service by November 1, 2009.

- 7 -

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

As part of an updated engineering study, ESNG received additional construction cost estimates for the E3 Project, which indicated substantially higher costs than previously estimated. In an effort to optimize the feasibility of the overall project development plan, ESNG explored all potential construction methods, construction cost mitigation strategies, potential design changes and project schedule changes. ESNG also held discussions and meetings with several potential new customers, who expressed interest in the E3 Project, but elected not to participate.

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

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

FERC Order Nos. 712 and 712-A. In June and November of 2008, the FERC issued Order Nos. 712 and 712-A which revised its regulations to improve the efficiency of interstate natural gas pipeline capacity release programs and to reflect changes in the market for short-term transportation services on pipelines. The Orders: (i) removed the rate ceiling on capacity release transactions of one year or less, allowing for market-based pricing for short-term capacity releases; (ii) facilitated the use of asset management arrangements by relaxing the prohibition on tying and on the bidding requirements for certain capacity releases; (iii) clarified that the prohibition on tying does not apply to conditions associated with gas inventory held in storage for releases of firm capacity; and (iv) facilitated of retail open access programs by waiving the prohibition on tying and on the bidding requirements for capacity releases made as part of state-approved retail open access programs. As a result of the revised regulations outlined in the Orders, interstate gas pipeline companies were required to remove any inconsistent tariff provisions within 180 days of the effective date of the rule. On February 2, 2009, ESNG submitted revised tariff sheets to comply with the requirements set forth in the Orders. Amended tariff sheets were subsequently filed on February 26, 2009 to make minor clarifications and corrections. On March 27, 2009, ESNG received FERC approval of these amended tariff sheets with an effective date of March 1, 2009.

Environmental Commitments and Contingencies

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

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Chesapeake has participated in the investigation, assessment or remediation, and has accrued liabilities, at two former manufactured gas plant sites located in Maryland and Florida, referred to, respectively, as the Salisbury Town Gas Light Site and the Winter Haven Coal Gas Site. The Company has also been in discussions with the Maryland Department of the Environment (“MDE”) regarding a third former manufactured gas plant site located in Cambridge, Maryland. The following discussion provides details on each site.

Salisbury Town Gas Light Site

In cooperation with the MDE, the Company has completed remediation of the Salisbury Town Gas Light site, located in Salisbury, Maryland, where it was determined that a former manufactured gas plant had caused localized ground-water contamination. During 1996, the Company completed construction of an Air Sparging and Soil-Vapor Extraction (“AS/SVE”) system and began remediation procedures. Chesapeake has reported the remediation and monitoring results to the MDE on an ongoing basis since 1996. In February 2002, the MDE granted permission to decommission permanently 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. Chesapeake has requested and is awaiting a No Further Action determination from the MDE.

Through March 31, 2009, the Company has incurred and paid approximately $2.9 million for remedial actions and environmental studies at the Salisbury Town Gas Light site. Of this amount, approximately $2.1 million has been recovered through insurance proceeds or in rates pursuant to an approval from the Maryland PSC dated September 26, 2006. As of March 31, 2009, a regulatory asset of approximately $870, 000 has been recorded to represent the portion of the clean-up costs not yet recovered.

Winter Haven Coal Gas Site

The Winter Haven Coal Gas site is located in Winter Haven, Florida. Chesapeake has been working with the Florida Department of Environmental Protection (“FDEP”) in assessing this coal gas site. In May 1996, the Company filed with the FDEP an AS/SVE Pilot Study Work Plan (the “Work Plan”) for the Winter Haven Coal Gas site. After discussions with the FDEP, the Company filed a modified Work Plan, which contained a description of the scope of work to complete the site assessment activities and a report describing a limited sediment investigation performed in 1997. In December 1998, the FDEP approved the modified Work Plan, which the Company completed during the third quarter of 1999. In February 2001, the Company filed a Remedial Action Plan (“RAP”) with the FDEP to address the contamination of the subsurface soil and ground-water in a portion of the site. The FDEP approved the RAP on May 4, 2001. Construction of the AS/SVE system was completed in the fourth quarter of 2002, and the system remains fully operational.

Through March 31, 2009, the Company has incurred approximately $1.8 million of environmental costs associated with this site. At March 31, 2009, the Company had accrued a liability of $486,000 related to this site, offsetting: (a) approximately $276,000 collected through rates in excess of costs incurred, and (b) a regulatory asset of approximately $762,000, representing the uncollected portion of the estimated clean-up costs. The Company expects to recover the remaining clean-up costs through rates.

The FDEP has indicated that the Company may be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the Winter Haven Coal Gas site. Based on studies performed to date, the Company objects to the FDEP’s suggestion that the sediments have been contaminated and will require remediation. The Company’s early estimates indicate that some of the corrective measures discussed by the FDEP may cost as much as $1.0 million. Given the Company’s view as to the absence of ecological effects, the Company believes that cost expenditures of this magnitude are unwarranted and intends to oppose any requirement that it undertake corrective measures in the offshore sediments. The Company anticipates that it will be several years before this issue is resolved. At this time, the Company has not recorded a liability for sediment remediation. The outcome of this matter cannot be predicted at this time.

Other

The MDE previously inquired with the Company regarding a manufactured gas plant site located in Cambridge, Maryland. No further discussions were held. The outcome of this matter cannot be determined at this time; therefore, the Company has not recorded an environmental liability for this location.

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Other Commitments and Contingencies

Natural Gas and Propane Supply

The Company’s natural gas and propane distribution operations have entered into contractual commitments to purchase natural gas and propane from various suppliers. The contracts have various expiration dates. In March 2009, the Company renewed its contract with an energy marketing and risk management company to manage a portion of the Company’s natural gas transportation and storage capacity. This contract expires on March 31, 2012.

The Company’s natural gas marketing subsidiary, Peninsula Energy Services Company, Inc. (“PESCO”), is currently in the process of obtaining and reviewing proposals from suppliers and anticipates executing agreements before the existing agreements expire in May 2009.

Corporate Guarantees

The Company has issued corporate guarantees to certain vendors of its subsidiaries, the largest portion of which is for the Company’s propane wholesale marketing subsidiary and its natural gas supply management subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary defaults. None of these subsidiaries has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in the condensed consolidated financial statements when incurred. The aggregate amount guaranteed at March 31, 2009 was $25.4 million, with the guarantees expiring on various dates in 2009 and the first half of 2010.

In addition to the corporate guarantees, the Company has issued a letter of credit to its primary insurance company for $775,000, which expires on May 31, 2009. The letter of credit is provided as security to satisfy the deductibles under the Company’s various insurance policies. There have been no draws on this letter of credit as of March 31, 2009.

Application of SFAS No. 71

The Company accounts for its regulated operations in accordance with Statement of Financial Accounting Standard (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation.” In applying SFAS No. 71, the Company’s regulated operations may defer costs or revenues in different periods than its unregulated operations would recognize, resulting in assets or liabilities on the balance sheet. If the Company were required to terminate the application of SFAS No. 71 to its regulated operations, all such deferred amounts would be recognized in the income statement at that time. This would result in a charge to earnings, net of applicable income taxes, which could be material.

Other

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

4. Recent Authoritative Pronouncements on Financial Reporting and Accounting

Recent accounting pronouncements:

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”). IFRS is a comprehensive series of accounting standards published by the International Accounting Standards Board. Under the proposed roadmap, the Company may be required to prepare financial statements in accordance with IFRS as early as 2014. The SEC will make a determination in 2011 regarding the mandatory adoption of IFRS. The Company is currently assessing the impact that this potential change would have on its condensed consolidated financial statements, and it will continue to monitor the development of the potential implementation of IFRS.

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In December 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) on SFAS 132(R)-1, “Employers Disclosures about Postretirement Benefit Plan Assets.” This FSP expands the disclosure requirements of a defined benefit pension or other postretirement plan by including the following discussions about plan assets: (i) how investment allocation decisions are made, including the plan’s investment policies and strategies; (ii) the major categories of plan assets; (iii) the inputs and valuation techniques used to measure the fair value of plan assets; (iv) the effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period; and (v) significant concentrations of risk within plan assets. This FSP is effective for fiscal years beginning after December 15, 2009. The Company will comply with the new disclosure requirements upon the adoption of this FSP.

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” to enhance the consistency in financial reporting by increasing the frequency of fair value disclosures. The Company does not expect the adoption of FSP FAS 107-1 and APB 28-1 to have a material impact on the Company’s condensed consolidated financial position and results of operations. The Company will comply with the disclosure requirements of FSP FAS 107-1 and APB 28-1 in the second quarter of 2009.

In April 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments,” to provide additional guidance designed to create greater clarity and consistency in accounting for and presenting impairment losses on securities. The Company does not expect the adoption of FSP FAS 115-2 and FSP FAS 124-2 to have a material impact on the Company’s condensed consolidated financial position and results of operations.

During the first quarter of 2009, the Company adopted the following accounting standards

In December 2007, the FASB issued SFAS No. 141 (revised 2007) “Business Combinations” (“SFAS 141(R)”). SFAS 141(R) retains the fundamental requirements of the original pronouncement requiring that the acquisition method be used for all business combinations. SFAS 141(R): (i) defines the acquirer as the entity that obtains control of one or more businesses in a business combination; (ii) establishes the acquisition date as the date that the acquirer achieves control; and (iii) requires the acquirer to recognize the assets acquired, liabilities assumed and any non-controlling interests at their fair values as of the acquisition date. SFAS 141(R) also requires that acquisition-related costs be expensed as incurred. SFAS 141(R) was effective for financial statements issued for fiscal years beginning after November 15, 2008, and was adopted by the Company, effective January 1, 2009. The adoption of this standard did not have a material impact on the Company’s condensed consolidated financial position and results of operations for the first quarter of 2009. However, depending upon the size, nature and complexity of future acquisition transactions, SFAS 141(R) could have a material impact on the Company’s condensed consolidated financial statements.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 changes the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests and classified as a component of equity. This new consolidation method significantly changes the accounting for transactions with minority interest holders. SFAS 160 was effective for financial statements issued for fiscal years beginning after November 15, 2008 and was adopted by the Company effective January 1, 2009. The adoption of this standard did not have an impact on the Company’s condensed consolidated financial position and results of operations.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS 161”). This new standard requires enhanced disclosures for derivative instruments and hedging activities about: (i) how and why a company uses derivative instruments; (ii) how derivative instruments and related hedged items are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and its related interpretations; and (iii) how derivative instruments and related hedged items affect a company’s financial position, financial performance and cash flows. SFAS 161 was effective for financial statements issued for fiscal years beginning after November 15, 2008, and was adopted by the Company effective January 1, 2009. Adoption of SFAS 161 had no financial impact on the Company’s condensed consolidated financial statements. The disclosures required by SFAS 161 are discussed in Note 9 — “Derivative Instruments” to the condensed consolidated financial statements.

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In April 2008, the FASB issued FSP FAS 142-3, “Determination of the Useful Life of Intangible Assets.” This FSP amends the factors which should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS 141(R) and other GAAP. This FSP was effective for financial statements issued for fiscal years beginning after November 15, 2008, and was adopted by the Company effective January 1, 2009. The adoption of this standard did not have an impact on the Company’s condensed consolidated financial position and results of operations.

In May 2008, the FASB issued FSP APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)” (“FSP APB 14-1”). FSP APB 14-1 clarifies that convertible debt instruments that may be settled in cash upon either mandatory or optional conversion (including partial cash settlement) should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. This FSP was effective for financial statements issued for fiscal years beginning after November 15, 2008, and was adopted by the Company effective January 1, 2009. The adoption of this standard did not have an impact on the Company’s condensed consolidated financial position and results of operations.

In June 2008, the FASB issued FSP Emerging Issues Task Force (“EITF”) 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” This FSP clarifies that all outstanding unvested share-based payment awards that contain rights to nonforfeitable dividends participate in undistributed earnings with common shareholders. Awards of this nature are considered participating securities and the two-class method of computing basic and diluted earnings per share must be applied. This FSP was effective for financial statements issued for fiscal years beginning after November 15, 2008, and was adopted by the Company effective January 1, 2009. The adoption of EITF 03-6-1 did not have an impact on the Company’s condensed consolidated financial position and results of operations.

In June 2008, the FASB ratified EITF 08-3, “Accounting for Lessees for Maintenance Deposits Under Lease Arrangements” (“EITF 08-3”). EITF 08-3 provides guidance for accounting for nonrefundable maintenance deposits. It also provides revenue recognition accounting guidance for the lessor. EITF 08-3 was effective for financial statements issued for fiscal years beginning after November 15, 2008, and was adopted by the Company effective January 1, 2009. The adoption of EITF 08-3 did not have an impact on the Company’s condensed consolidated financial position and results of operations.

In April 2009, the FASB issued FSP SFAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies,” (“FSP SFAS 141(R)-1”). This FSP amends and clarifies SFAS 141(R) to require that an acquirer recognize at fair value, at the acquisition date, an asset acquired or a liability assumed in a business combination that arises from a contingency if the acquisition-date fair value of that asset or liability can be determined during the measurement period. If the acquisition-date fair value of such an asset acquired or liability assumed cannot be determined, the acquirer should apply the provisions of SFAS No. 5, “Accounting for Contingencies,” to determine whether the contingency should be recognized at the acquisition date or after it. FSP FAS 141(R)-1 is effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is after the beginning of the first annual reporting period beginning after December 15, 2008. The adoption of this standard did not have an impact on the Company’s condensed consolidated financial position and results of operations. However, depending upon the size, nature and complexity of future acquisition transactions, this FSP could have a material impact on the Company’s condensed consolidated financial statements.

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5. Segment Information

The Company uses the management approach to identify operating segments. The Company organizes its business around differences in products or services, and the operating results of each segment are regularly reviewed by the Company’s chief operating decision-maker in order to make decisions about the allocation of resources and to assess performance. The following table presents information about the Company’s reportable segments.

For the Three Months Ended March 31,	2009			2008
	(in Thousands)
Operating Revenues, Unaffiliated Customers
Natural gas	$	73,903		$	68,823
Propane		27,283			27,808
Advanced information services		3,293			3,643
Total operating revenues, unaffiliated customers	$	104,479		$	100,274
Intersegment Revenues (1)
Natural gas	$	137		$	106
Propane		2			1
Advanced information services		12			8
Other		171			163
Total intersegment revenues	$	322		$	278
Operating Income (Loss)
Natural gas	$	10,517		$	10,469
Propane		5,465			3,444
Advanced information services		(112	)		38
Other and eliminations		96			90
Total operating income	$	15,966		$	14,041
Other Income, net of other expenses		33			17
Interest Charges		1,642			1,593
Income Taxes		5,764			4,891
Net income	$	8,593		$	7,574

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

	March 31,		December 31,
	2009		2008
	(in Thousands)
Identifiable Assets
Natural gas	$	286,298	$	297,407
Propane		57,822		72,955
Advanced information services		3,831		3,545
Other		12,219		11,849
Total identifiable assets	$	360,170	$	385,756

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

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6. Employee Benefit Plans

Net periodic benefit costs for the defined benefit pension plan, the pension supplemental executive retirement plan and other post-retirement benefits are shown below:

	Defined Benefit						Pension Supplemental				Other Post-Retirement
	Pension Plan						Executive Retirement Plan				Benefits
For the Three Months Ended March 31,	2009			2008			2009		2008		2009		2008
(in Thousands)
Service Cost	$	—		$	—		$	—	$	—	$	—	$	1
Interest Cost		140			148			32		31		27		28
Expected return on plan assets		(86	)		(157	)		—		—		—		—
Amortization of prior service cost		(1	)		(1	)		3		—		—		—
Amortization of net loss		68			—			15		11		40		46
Net periodic cost (benefit)	$	121		$	(10	)	$	50	$	42	$	67	$	75

The Company expects to recognize increased pension and postretirement benefit costs in the range of $400,000 to $600,000 in 2009 as a result of the market decline in the values of the defined pension plan assets during 2008. In addition, the Company expects to contribute $450,000 to the defined benefit pension plan in 2009. The pension supplemental executive retirement plan and the other post-retirement benefit plan are unfunded and are expected to be paid out of the general funds of the Company. Cash benefits paid under the pension supplemental executive retirement plan for the three months ended March 31, 2009, were $22,000; for the year 2009, such benefits paid are expected to be approximately $88,000. Cash benefits paid for other post-retirement benefits, primarily for medical claims, for the three months ended March 31, 2009, totaled $10,000; for the year 2009, the Company has estimated that approximately $225,000 will be paid for such benefits.

7. Investments

The investment balance at March 31, 2009, represents a Rabbi Trust associated with the Company’s Supplemental Executive Retirement Savings Plan. In accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” the Company classifies these investments as trading securities. As a result, the Company is required to report the securities at their fair value, with any unrealized gains and losses included in other income, net of other expenses, in the condensed consolidated statements of income. The Company also has an associated liability that is recorded and adjusted each month for the gains and losses incurred by the Rabbi Trust. At March 31, 2009, total investments had a fair value of $1.5 million.

8. Share-Based Compensation

The Company accounts for its share-based compensation arrangements under SFAS No. 123 (revised 2004), “Share Based Payments” (“SFAS 123(R)”), which requires companies to record compensation costs for all share-based awards over the respective service period for which employee services are received in exchange for an award of equity or equity-based compensation. The compensation cost is based on the fair value of the grant on the date it was awarded. The Company currently has two share-based compensation plans, the Directors Stock Compensation Plan (“DSCP”) and the Performance Incentive Plan (“PIP”), that require accounting under SFAS 123(R).

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, 2009, and 2008.

For the three months ended March 31,	2009		2008
(in Thousands)
Directors Stock Compensation Plan	$	47	$	46
Performance Incentive Plan		194		185
Total compensation expense		241		231
Less: tax benefit		97		92
Amounts included in net income	$	144	$	139

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In January 2009, the Company’s Board of Directors granted 28,875 share-based awards under the PIP. The table below presents the stock activity for the awards granted under the PIP for the three months ended March 31, 2009:

			Weighted
	Number of		Average Fair
	Shares		Value
Outstanding — December 31, 2008		94,200	$	27.71
Granted		28,875	$	29.36
Vested		—		—
Fortfeited		—		—
Expired		—		—
Outstanding — March 31, 2009		123,075	$	28.19

No additional shares were granted under the DSCP during the three months ended March 31, 2009.

9. Derivative Instruments

The Company uses derivative and non-derivative contracts to manage the risks related to obtaining adequate supplies and the price fluctuations of natural gas and propane and to engage in trading activities. The Company’s 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 under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” or are considered “normal purchases and sales” under SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities — an amendment of SFAS No. 133,” and are accounted for on an accrual basis. The Company’s 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, 2009, the Company’s natural gas and propane distribution operations did not have any outstanding derivative contracts.

Xeron, the Company’s propane wholesale marketing operation, engages in trading activities using forward and futures contracts. These contracts are considered derivatives under SFAS No. 133 and have been accounted for using the mark-to-market method of accounting. Under the mark-to-market method of accounting, the Company’s trading contracts are recorded at fair value, net of future servicing costs, and the changes in fair value of those contracts are recognized as gains or losses in the income statement in the period of change. As of March 31, 2009, the Company had the following outstanding trading contracts:

	Quantity in		Estimated Market	Weighted Average
At March 31, 2009	Gallons		Prices	Contract Prices
Forward Contracts
Sale		13,587,000	$0.6125 — $0.9800	$	0.6775
Purchase		13,608,000	$0.6000 — $0.9200	$	0.6685

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The following tables present the information about fair value and related gains and losses of the Company’s derivative contracts. The Company did not have any derivative contracts with a credit-risk-related contingency.

Fair value of the derivative contracts recorded in the Balance Sheet as of March 31, 2009 and December 31, 2008 are as follows:

	Asset Derivatives
		Fair Value
(in thousands)	Balance Sheet Location	March 31, 2009		December 31, 2008
Derivatives not designated as hedging instruments under SFAS No. 133:
Forward contracts	Mark-to-market energy assets	$	453	$	4,482
Total asset derivatives		$	453	$	4,482

	Liability Derivatives
		Fair Value
(in thousands)	Balance Sheet Location	March 31, 2009		December 31, 2008
Derivatives designated as fair value hedges under SFAS No. 133:
Propane swap agreement (1)	Other current liabilities		—	$	105
Derivatives not designated as hedging instruments under SFAS No. 133:
Forward contracts	Mark-to-market energy liabilities	$	317	$	3,052
Total liability derivatives		$	317	$	3,157

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

The effect of gains and losses from derivative instruments on the Statement of Income for the three months ended March 31, 2009 and 2008 are as follows:

		Amount of Gain (Loss) on
		Derivatives for the Three Months
	Location of Gain	Ended March 31:
(in thousands)	(Loss) on Derivatives	2009			2008
Derivatives designated as fair value hedges under SFAS No. 133:
Propane swap agreement (1)	Cost of Sales	$	(42	)		—
Derivatives not designated as hedging instruments under SFAS No. 133:
Unrealized gains on forward contracts	Revenue	$	136		$	5
Total		$	94		$	5

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

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The effect of trading activities on the Statement of Income for the three months ended March 31, 2009 and 2008 are as follows:

		Amount of Trading Revenues for
	Location in the	the Three Months Ended March 31:
(in thousands)	Statement of Income	2009		2008
Realized gains on forward contracts	Revenue	$	352	$	699
Unrealized gains on forward contracts	Revenue		136		5
Total		$	488	$	704

10. Fair Value of Financial Instruments

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

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

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

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

The following table summarizes the Company’s financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements by level within the fair value hierarchy used at March 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	$	1,473	$	1,473		—		—
Mark-to-market energy assets	$	453		—	$	453		—
Liabilities:
Mark-to-market energy liabilities	$	317		—	$	317		—

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

			Fair Value Measurements Using:
					Significant
					Other		Significant
			Quoted Prices in		Observable		Unobservable
			Active Markets		Inputs		Inputs
(in thousands)	Fair Value		(Level 1)		(Level 2)		(Level 3)
Assets:
Investments	$	1,601	$	1,601		—		—
Mark-to-market energy assets	$	4,482		—	$	4,482		—
Liabilities:
Mark-to-market energy liabilities	$	3,052		—	$	3,052		—
Price Swap Agreement	$	105		—	$	105		—

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The following valuation techniques were used to measure fair value assets in the tables above on a recurring basis as of March 31, 2009, and December 31, 2008:

Level 1 Fair Value Measurements:

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

Level 2 Fair Value Measurements:

Mark-to-market energy assets and liabilities — These forward contracts are valued using market transactions from OTC markets.

Propane swap agreement — The fair value of the propane price swap agreement is valued using market transactions from OTC markets.

At March 31, 2009, there were no non-financial assets or liabilities required to be reported at fair value. The Company complies with SFAS 144, “Accounting for Impairment or Disposal of Long-Lived Assets,” by reviewing its non-financial assets for impairment at least on an annual basis.

11. Subsequent Event

On April 20, 2009, the Company and Florida Public Utilities Company (“FPU”) (NYSE AMEX: FPU) announced that they had entered into a definitive merger agreement pursuant to which FPU will merge with a wholly owned subsidiary of the Company with FPU being the surviving corporation and operating as a wholly owned subsidiary of the Company after the merger. The merger was unanimously approved by both companies’ Boards of Directors on April 17, 2009. Under the merger agreement, holders of FPU common stock will receive 0.405 shares of the Company’s common stock in exchange for each outstanding share of FPU. Based on the number of FPU shares outstanding at March 20, 2009, the Company would issue approximately 2.5 million shares of its shares in exchange for the outstanding FPU shares. The merger intended to qualify as a tax-free reorganization and is subject to various regulatory approvals, approval by the shareholders of both companies, and other conditions. The merger is expected to close during the fourth quarter of 2009. Although the Company believes that its expectation as to timing for the closing of the merger is reasonable, no assurance can be given as to if or when all closing conditions will be satisfied, including obtaining the required regulatory and shareholder approvals, or as to the closing of the merger.

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 the Company’s financial condition, results of operations and liquidity. This discussion and analysis should be read in conjunction with the attached unaudited condensed consolidated financial statements and notes thereto and Chesapeake’s Annual Report on Form 10-K for the year ended December 31, 2008, including the audited consolidated financial statements and notes contained in the Annual Report on Form 10-K.

Safe Harbor for Forward-Looking Statements

The Company has made statements in this Quarterly Report on Form 10-Q that are considered to be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are not matters of historical fact and are typically identified by words such as, but not limited to, “believes,” “expects,” “intends,” “plans,” and similar expressions, or future or conditional verbs such as “may,” “will,” “should,” “would,” and “could.” These statements relate to matters such as customer growth, changes in revenues or gross margins, capital expenditures, environmental remediation costs, regulatory trends and decisions, market risks associated with our propane operations, the competitive position of the Company, mergers, inflation, and other matters. It is important to understand that these forward-looking statements are not guarantees; rather, they are subject to certain risks, uncertainties and other important factors that could cause actual results to differ materially from those in the forward-looking statements. Such factors include, but are not limited to:

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

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

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

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

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

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

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

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

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

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

• the effects of accounting changes;

• changes in benefit plan assumptions, return on plan assets, and funding requirements;

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

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

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

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

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

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

• the Company’s ability to obtain necessary approvals and permits from regulatory agencies on a timely basis;

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

• inability to access the financial markets to a degree that may impair future growth; and

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

Certain of the forward-looking statements in this report relate to the merger with FPU and include statements regarding the expectation that the merger will close and the timing thereof, the tax treatment of the proposed merger, the benefits of the proposed merger and the expectation that earnings will be neutral or slightly accretive in 2010 and meaningfully accretive in 2011. These statements are based on the current expectations of the Company’s management. There are a number of risks and uncertainties that could cause actual results to differ materially from the forward-looking statements included in this document. These risks and uncertainties include the following: the companies may be unable to obtain regulatory approvals required for the transaction, or obtaining the required regulatory approvals may delay the transaction or result in the imposition of conditions that could have a material adverse effect on the combined company or cause the companies to abandon the transaction; the companies may be unable to obtain shareholder approvals required for the transaction; conditions to the closing of the merger may not be satisfied; or the tax treatment for the transaction may be different from the companies’ expectations.

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Overview

Chesapeake is a diversified utility company engaged, directly or through subsidiaries, in natural gas distribution, transmission and marketing, propane distribution and wholesale marketing, advanced information services and other related businesses. For additional information regarding segments, refer to Note 5, “Segment Information,” of the Notes to the condensed consolidated financial statements in this Quarterly Report on Form 10-Q.

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

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

• expanding the natural gas distribution and transmission business through expansion into new geographic areas in our current and potentially new service territories;

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

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

• enhancing marketing channels to attract new customers;

• providing reliable and responsive service to retain existing customers;

• maintaining a capital structure that enables the Company to access capital as needed; and

• maintaining a consistent and competitive dividend for shareholders.

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

Results of Operations for the Quarter Ended March 31, 2009

The following discussions on operating income and segment results for the three months ended March 31, 2009 and 2008, include use of the term “gross margin.” Gross margin is determined by deducting the cost of sales from operating revenue. Cost of sales includes the purchased gas cost for natural gas and propane and the cost of labor spent on direct revenue-producing activities. Gross margin should not be considered an alternative to operating income or net income, which are determined in accordance with GAAP. Chesapeake believes that gross margin, although a non-GAAP measure, is useful and meaningful to investors as a basis for making investment decisions. It provides investors with information that demonstrates the profitability achieved by the Company under its allowed rates for regulated operations and under its competitive pricing structure for non-regulated segments. Chesapeake’s management uses gross margin in measuring the performance of its business units and has historically analyzed and reported gross margin information publicly. Other companies may calculate gross margin in a different manner.

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Consolidated Overview

The Company’s net income for the quarter ended March 31, 2009, increased by $1.0 million, or 13 percent, compared to the same period in 2008. The Company reported a net income of approximately $8.6 million, or $1.24 per share (diluted), during the quarter ended March 31, 2009, compared to a net income of approximately $7.6 million, or $1.10 per share (diluted), during the same period in 2008.

For the Three Months Ended March 31,	2009			2008		Change
(in Thousands)
Operating Income (Loss)
Natural Gas	$	10,517		$	10,469	$	48
Propane		5,465			3,444		2,021
Advanced Information Services		(112	)		38		(150	)
Other & eliminations		96			90		6
Operating Income		15,966			14,041		1,925
Other Income, Net of Other Expenses		33			17		16
Interest Charges		1,642			1,593		49
Income Taxes		5,764			4,891		873
Net Income	$	8,593		$	7,574	$	1,019

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

• The Company’s Delmarva propane operation experienced increases in average margin per retail gallon sold during the period, which resulted in higher gross margin of $1.2 million in the quarter ended March 31, 2009, compared to the same period in 2008. Gross margin during the current quarter was aided by propane inventory write-downs of approximately $800,000 during 2008, which resulted in a lower inventory price per gallon.

• Colder weather on the Delmarva Peninsula, which was 10 percent colder in the first quarter of 2009 compared to the same period in 2008, had a positive impact on gross margin for the Company’s Delmarva natural gas and propane distribution operations. The Company estimates that the colder weather resulted in an increase of $1.0 million to gross margin in 2009.

• Increased spot sales on the Delmarva Peninsulas and enhancements in sales contract terms for the Company’s natural gas marketing subsidiary provided for a period-over-period increase of $913,000 in its gross margin.

• Continued customer growth and increased capacity contributed approximately $767,000 to gross margin increase for the natural gas segment during the period.

• Increased gross margin was partially offset by the increase in operating expenses from additional costs primarily to support current and future growth.

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Natural Gas

The natural gas segment’s operating income for the first quarter of 2009, remained relatively unchanged at $10.5 million, or an increase of $48,000, compared to the first quarter of 2008.

For the Three Months Ended March 31,	2009		2008		Change
(in Thousands)
Revenue	$	74,039	$	68,928	$	5,111
Cost of sales		52,756		49,317		3,439
Gross margin		21,283		19,611		1,672
Operations & maintenance		7,530		6,266		1,264
Depreciation & amortization		1,792		1,640		152
Other taxes		1,444		1,236		208
Other operating expenses		10,766		9,142		1,624
Operating Income	$	10,517	$	10,469	$	48
Statistical Data — Delmarva Peninsula
Heating degree-days (“HDD”):
Actual		2,453		2,222		231
10-year average (normal)		2,306		2,270		36
Estimated gross margin per HDD	$	1,937	$	1,937	$	0
Per residential customer added:
Estimated gross margin	$	375	$	372	$	3
Estimated other operating expenses	$	103	$	106	$	(3	)
Residential Customer Information
Average number of customers:
Delmarva		47,379		46,015		1,364
Florida		13,473		13,571		(98	)
Total		60,852		59,586		1,266

Gross margin for the Company’s natural gas segment increased by $1.7 million, or nine percent, and operating expenses increased by $1.6 million, or 18 percent, for the first quarter in 2009 compared to the same period in 2008. The gross margin increases of $461,000 for the natural gas transmission operation, $298,000 for the natural gas distribution operations and $913,000 for the natural gas marketing operation, are further explained below.

Natural Gas Transmission

The natural gas transmission operation achieved gross margin growth of $461,000, or seven percent, in the first quarter of 2009 over the same period in 2008, due to the following developments:

• New long-term transportation capacity contracts implemented by ESNG in November 2008 provided for 5,650 Dts of additional firm transportation service per day, generated $247,000 of gross margin in the first quarter of 2009. These contracts are expected to generate approximately $988,000 of annualized gross margin.

• ESNG entered into a firm transportation service agreement with an industrial customer in Northern Delaware for the period of February 6, 2009 through October 31, 2009, to provide firm transportation service for a maximum of 7,200 Dts. For the first quarter of 2009, this service provided $118,000 of gross margin. In addition, ESNG entered into a firm transportation service agreement with this customer for the period of November 1, 2009 through October 31, 2012 for a maximum of 10,000 Dts and will recognize annual gross margin of approximately $1.1 million for this service. For the years 2009 and 2010, these two agreements will contribute approximately $754,000 and $1.1 million, respectively, to gross margin.

ESNG has commenced construction for the remaining facilities included in its multi-year system expansion project. While this had no impact in the first quarter of 2009, these facilities, which are expected to be placed into service in November 2009, will provide for 7,200 Dts of firm service capacity per day. For the years 2009 and 2010, these facilities are expected to contribute $169,000 and $1.0 million, respectively, to gross margin.

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In April of 2009, ESNG received notice from a customer of its intention not to renew two firm transportation service contracts expiring in October of 2009 and March of 2010. If not renewed, gross margin will be negatively impacted by approximately $56,000 in 2009 and approximately $427,000 in 2010.

Natural Gas Distribution

Gross margin for the Company’s natural gas distribution operations increased by $298,000, or two percent, for the first quarter of 2009 over the same period in 2008. This increase in gross margin was the result of $307,000 produced by the Delmarva natural gas distribution operations partially offset by the Florida natural gas distribution operations’ reduced gross margin of $9,000.

Contributing to the Delmarva distribution operations increase in gross margin of $307,000, or three percent, were the following factors:

• Weather contributed to the increase in gross margin in the first quarter of 2009 compared to the first quarter in 2008. The Company estimates that colder temperatures contributed approximately $455,000 to gross margin as temperatures on the Delmarva Peninsula were 10 percent colder in the first quarter of 2009.

• Growth in commercial and industrial customers contributed $251,000 to gross margin in 2009.

• The Company estimates that customer consumption, which increased in the first quarter of 2009 compared to the same period in 2008, contributed $105,000 to gross margin.

• The Delmarva distribution operation continues to experience strong customer growth. Despite a slowdown in the new housing market, residential customer growth contributed $85,000 to gross margin as the average number of residential customers on the Delmarva Peninsula increased by approximately 1,400, or three percent, for the first quarter of 2009 compared to the same quarter in 2008.

• Gross margin on firm customers for the Delaware Division decreased in the first quarter by approximately $398,000, compared to the same period in 2008, as a result of a new rate structure approved by the Delaware PSC in the third quarter of 2008. The new rate structure allows a greater portion of the revenue requirements to be collected through non-volume based charges and provides less volatility in gross margin based on weather. Compared to the previous rate structure, this resulted in a reduction in margin during the first quarter of 2009, but will represent an increase in margin during non-heating periods.

• Interruptible margins decreased by $264,000 in the first quarter of 2009, primarily the result of a reduction in the price of alternative fuels (propane and fuel oil).

• The remaining $73,000 net increase in gross margin can be attributed to the increase in miscellaneous service fees and rental revenue.

Gross margin for the Florida distribution operation remained relatively unchanged, with a $9,000 decrease, in the first quarter of 2009. Lower gross margin attributed to non-residential customers was partially offset by increased gross margin from residential customers.

The Florida distribution operation expects a decline in gross margin of approximately $72,000 during the second-half of 2009 from the loss of two industrial customers due to their facility closings in June and September of 2009. These customers generated an annualized gross margin of approximately $210,000 in 2008.

Natural Gas Marketing

Gross margin for PESCO increased by $913,000 for the first quarter of 2009. The increase in gross margin was primarily the result of increased margins on spot sales of approximately $812,000 and enhanced sales contract terms. Of the $812,000 increase in spot sales, $732,000 was generated from two industrial customers located on the Delmarva Peninsula. Spot sales are opportunistic transactions, the future availability of which are dependent upon market conditions.

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Other Operating Expenses

An increase of $1.6 million in other operating expenses for the natural gas segment substantially offset the increased gross margin. The factors contributing to the increase in other operating expenses are as follow:

• Depreciation expense, asset removal costs and property taxes increased by approximately $506,000 as a result of the Company’s continued capital investments.

• Allowance for uncollectible accounts in the natural gas segment increased by $321,000 due to the growth in customers and revenues billed in the natural gas segment and the general economic climate.

• Payroll costs increased by $200,000 due to salary adjustments that were effective January 1, 2009 as a result of a compensation survey completed in the fourth quarter of 2008, annual salary increases, and additional staffing levels to support the continued growth.

• Benefit costs increased by $131,000 due to higher pension costs as a result of the decline in the value of pension assets in 2008 and other benefit costs relating to increased payroll costs.

• Other operating expense increases included $227,000 in increased corporate overhead.

Propane

The propane segment experienced an increase of $2.0 million, or 59 percent, in operating income for the first quarter of 2009 compared to the same period in 2008. Gross margin increased by $2.6 million, or 32 percent, which was partially offset by an increase in other operating expenses of $583,000.

For the Three Months Ended March 31,	2009		2008		Change
(in Thousands)
Revenue	$	27,285	$	27,809	$	(524	)
Cost of sales		16,594		19,722		(3,128	)
Gross margin		10,691		8,087		2,604
Operations & maintenance		4,433		3,833		600
Depreciation & amortization		514		498		16
Other taxes		279		312		(33	)
Other operating expenses		5,226		4,643		583
Operating Income	$	5,465	$	3,444	$	2,021
Statistical Data — Delmarva Peninsula
Heating degree-days (“HDD”):
Actual		2,453		2,222		231
10-year average (normal)		2,306		2,270		36
Estimated gross margin per HDD	$	2,465	$	1,974	$	491

The gross margin increases of $2.7 million for the Delmarva propane distribution operations and $157,000 for the Florida propane distribution operations were partially offset by lower gross margin of $216,000 for the propane wholesale and marketing operation, which are further explained below.

Delmarva Propane Distribution

The Delmarva propane distribution operation’s increase in gross margin of $2.7 million resulted primarily from the following:

• Gross margin increased by $1.2 million in the first quarter of 2009, compared to the same period in 2008, because of higher retail unit margins resulting from a sharp decline in propane costs. Gross margin in the first quarter of 2009 was aided by propane inventory write-downs of approximately $800,000 during the second-half of 2008, which resulted in a lower inventory price per gallon.

• Non-weather-related volumes sold in the first quarter of 2009 increased by 1.0 million gallons, or 43 percent. This increase in gallons sold, which provided for an increase in gross margin of approximately $670,000, was primarily driven by the timing of propane deliveries to certain customers and the addition of approximately 380 Community Gas Systems (“CGS”) customers, an increase of seven percent. The Company expects the growth of its CGS operation to continue, although at a slower pace given the current economic climate.

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• Colder temperatures on the Delmarva Peninsula in the first quarter of 2009 increased the volumes sold during the three months ended March 31, 2009, by 804,000 gallons, or 34 percent, compared to the same period in 2008 as temperatures were 10 percent colder during this period in 2009. The Company estimates the colder weather contributed an additional $584,000 of gross margin.

• Wholesale volumes increased by 1.2 million gallons in the first quarter of 2009, which resulted in a gross margin increase of $126,000.

Florida Propane Distribution

The Florida propane distribution operation experienced an increase in gross margin of $157,000, or 42 percent, in the first quarter of 2009, compared to the same period in 2008. The higher gross margin is attributable to higher retail unit margins resulting from a sharp decline in propane costs during the current quarter.

Propane Wholesale and Marketing

Gross margin for the Company’s propane wholesale marketing operation decreased by $216,000 in the first quarter of 2009 compared to the same period in 2008. This decrease reflects the decline of market opportunities as propane wholesale prices were less volatile in 2009.

Other Operating Expenses

An increase of $583,000 in other operating expenses for the propane segment partially offset the increased gross margin. The factors contributing to the increase in other operating expenses are as follow:

• Payroll costs increased by $446,000 in the first quarter of 2009, primarily due to an increase of $237,000 in incentive compensation and commission costs as a result of the improved operating results. In addition, other payroll costs increased due to salary adjustments that were effective January 1, 2009 as a result of a compensation survey completed in the fourth quarter of 2008, annual salary increases and seasonal employees.

• Benefit costs increased by $20,000 as a result of the significant decline in the value of pension plan assets during 2008.

• The allowance for uncollectable accounts increased by $56,000 due to increased amounts billed during the period and the overall economic climate.

• Other operating expense increases included additional costs of $22,000 related to the additional CGS customers and an additional $36,000 expense for propane tank maintenance to maintain compliance with United States Department of Transportation standards.

Advanced Information Services

The advanced information services business experienced an operating loss of $112,000 for the first quarter in 2009, a decrease of $150,000 compared to an operating income of $38,000 that was achieved for the same period in 2008.

For the Three Months Ended March 31,	2009			2008		Change
(in Thousands)
Revenue	$	3,305		$	3,651	$	(346	)
Cost of sales		1,871			1,941		(70	)
Gross margin		1,434			1,710		(276	)
Operations & maintenance		1,303			1,404		(101	)
Depreciation & amortization		50			37		13
Other taxes		193			231		(38	)
Other operating expenses		1,546			1,672		(126	)
Operating Income (Loss)	$	(112	)	$	38	$	(150	)

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The decrease in operating income is the result of lower gross margin of $276,000, or 16 percent, partially offset by lower operating expenses of $126,000. The period-over-period decrease in gross margin is due to a decrease of $605,000 in consulting revenues as the number of billable hours decreased by 27 percent. The reduction in the number of billable hours is a result of current economic conditions in which information technology spending has broadly declined. The decrease in consulting revenues was partially offset with $329,000 in increased revenues from product sales, training and Managed Database Administration services.

Other operating expenses decreased by $126,000 to $1.5 million in the first quarter of 2009, compared to $1.7 million for the same period in 2008; this decrease is attributable primarily to lower incentive compensation due to the lower operating results, partially offset by higher payroll costs for increased sales and administrative staffing levels that resulted from the acquisition of SI Systems in July 2008. On March 16, 2009, the Company instituted layoffs and other cost-containment actions that are estimated to offset the decline in revenues and that are expected to reduce costs by $851,000 for the remainder of 2009.

Other Business Operations and Eliminations

Other operations, consisting primarily of subsidiaries that own real estate leased to other Company subsidiaries, generated an operating income of approximately $96,000 for the first quarter of 2009, compared to an operating income of approximately $90,000 for the same period in 2008.

For the Three Months Ended March 31,	2009			2008			Change
(in Thousands)
Revenue	$	(150	)	$	(114	)	$	(36	)
Cost of sales		1			1			—
Gross margin		(151	)		(115	)		(36	)
Operations & maintenance		(292	)		(249	)		(43	)
Depreciation & amortization		28			28			—
Other taxes		17			16			1
Other operating expenses		(247	)		(205	)		(42	)
Operating Income	$	96		$	90		$	6

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

Interest Expense

Total interest expense for the first quarter of 2009 increased by approximately $49,000, or three percent, compared to the same period in 2008. The higher interest expense is primarily attributed to the following:

• Interest on long-term debt increased by $317,000 in the first quarter of 2009, compared to the same period in 2008, as the Company increased its average long-term debt balance by $23.2 million. The Company’s weighted average interest rate decreased to 6.36 percent during the first quarter of 2009, compared to 6.65 percent for the same period in 2008. The change in the average long-term debt balance and weighted average interest rate is a result of the placement of $30.0 million of 5.93 percent Unsecured Senior Notes in October 2008.

• Interest on short-term borrowings decreased by $250,000 in the first quarter of 2009, compared to the same period in 2008, based upon a decrease of $13.9 million in the Company’s average short-term borrowing balance coupled with a lower weighted average interest rate. The Company’s average short-term borrowing during the first quarter of 2009 was $22.1 million, with a weighted average interest rate of 1.45 percent, compared to $36.0 million, with a weighted average interest rate of 3.76 percent, for the same period in 2008.

Income Taxes

Income tax expense for the first quarter of 2009 was $5.8 million, compared to $4.9 million for the first quarter of 2008. The increase in income tax expense primarily reflects the higher earnings for the period. The effective income tax rate for the first quarter of 2009 is 40.1 percent, compared to an effective tax rate of 39.2 percent for the first quarter of 2008. The increased effective income tax rate resulted from a greater portion of the Company’s pre-tax income having been generated from entities in states with higher income tax rates.

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Financial Position, Liquidity and Capital Resources

Chesapeake’s capital requirements reflect the capital-intensive nature of its business and are principally attributable to its investment in new plant and equipment and the retirement of outstanding debt. The Company relies on cash generated from operations, short-term borrowing and other sources to meet normal working capital requirements and to finance capital expenditures. During the first three months of 2009, net cash provided by operating activities was $31.0 million, cash used by investing activities was $4.1 million, and cash used by financing activities was $25.2 million. By comparison, during the first three months of 2008, net cash provided by operating activities was $7.1 million, cash used by investing activities was $4.5 million, and cash used by financing activities was $2.3 million.

The Board of Directors has authorized the Company to borrow up to $65.0 million of short-term debt, as required, from various banks and trust companies under short-term lines of credit. As of March 31, 2009, Chesapeake had five unsecured bank lines of credit with three financial institutions, totaling $100.0 million, none of which requires compensating balances. These bank lines are available to provide funds for the Company’s short-term cash needs to meet seasonal working capital requirements and to fund temporarily portions of its capital expenditures. Two of the bank lines, totaling $55.0 million, are committed. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks. The Company’s outstanding balance of short-term borrowing at March 31, 2009 and December 31, 2008, was $9.8 million and $33.0 million, respectively.

Chesapeake has budgeted $34.8 million for capital expenditures during 2009. This amount includes $30.5 million for the natural gas segment, $3.6 million for the propane segment, $250,000 for the advanced information services segment and $447,000 for the other operations segment. The natural gas expenditures are for expansion and improvement of facilities. The propane expenditures are to support customer growth and to replace equipment. The advanced information services expenditures are for computer hardware, software and related equipment. The other operations category includes general plant, computer software and hardware. The Company expects to fund the 2009 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 the availability of capital.

Capital Structure

The following presents the Company’s capitalization, excluding short-term borrowing, as of March 31, 2009 and December 31, 2008:

	March 31, 2009				December 31, 2008
	(In thousands, except percentages)
Long-term debt, net of current maturities	$	86,358	40	%	$	86,422	41	%
Stockholders’ equity	$	130,172	60	%	$	123,073	59	%
Total capitalization, excluding short-term debt	$	216,530	100	%	$	209,495	100	%

As of March 31, 2009, common equity represented 60 percent of total capitalization, excluding short-term borrowing, compared to 59 percent at December 31, 2008. If short-term borrowing and the current portion of long-term debt were included in total capitalization, the equity component of the Company’s capitalization would have been 56 percent at March 31, 2009, compared to 49 percent at December 31, 2008.

Chesapeake remains committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access capital markets when required. This commitment, along with adequate and timely rate relief for the Company’s regulated operations, is intended to ensure that Chesapeake will be able to attract capital from outside sources at a reasonable cost. The Company believes that the achievement of these objectives will provide benefits to its customers and creditors, as well as its investors.

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Shelf Registration

In July 2006, the Company filed a registration statement on Form S-3 with the SEC to issue up to $40.0 million in new common stock and/or debt securities. The registration statement was declared effective by the SEC in November 2006. In the fourth quarter of 2006, the Company sold 690,345 shares of common stock, including the underwriter’s exercise of an over-allotment option of 90,045 shares, under this registration statement, generating net proceeds of $19.7 million. At March 31, 2009, the Company had approximately $20.0 million remaining under this registration statement.

Cash Flows Provided By Operating Activities

Cash flows provided by operating activities were as follow:

For The Three Months Ended March 31,	2009		2008			Change
(in Thousands)
Net Income	$	8,593	$	7,574		$	1,019
Non-cash adjustments to net income		4,299		3,666			633
Changes in assets and liabilities		18,144		(4,130	)		22,274
Net cash provided by operating activities	$	31,036	$	7,110		$	23,926

Period-over-period changes in our cash flows from operating activities are attributable primarily to changes in net income, changes in non-cash adjustments to net income, such as depreciation and deferred income taxes, and changes in our working capital. Changes in working capital are determined by a variety of factors, including weather, the price of natural gas and propane, the timing of customer collections, payments of natural gas and propane purchases, and deferred gas cost recoveries.

For the first three months of 2009, net cash flow provided by operating activities was $31.0 million, an increase of $23.9 million, compared to the same period in 2008. The increase was due primarily to the following developments:

• Net cash flows from changes in accounts receivable and accounts payable were primarily due to collections and payments from the Company’s propane and natural gas distribution operations. In addition, the timing of trading contracts entered into by the Company’s propane wholesale and marketing operation contributed to the net cash flows from changes in accounts receivable and accounts payable.

• Non-cash adjustments reflected unrealized losses on commodity contracts, as there were fewer opportunities in the propane wholesale trading market during the quarter.

• The net cash flows from propane and natural gas inventories were the result of lower commodity prices coupled with seasonality of sales to customers.

• Net cash flows from the changes in regulatory liabilities are related to the increase of the over-collected gas costs from rate-payers for Delmarva natural gas distribution operations and will be refunded in future periods.

• The net cash flows used by non-cash adjustments for deferred income taxes is primarily the result of the timing of the Company’s regulatory filings for its gas cost recovery mechanisms, partially offset by higher book-to-tax timing differences generated by the 2009 American Recovery and Reinvestment Act, which authorized bonus depreciation for certain assets.

Cash Flows Used in Investing Activities

Net cash flows used in investing activities totaled $4.1 million and $4.5 million during the three months ended March 31, 2009 and 2008, respectively. Cash utilized for capital expenditures was $4.1 million and $4.4 million for the first three months of 2009 and 2008, respectively. Additions to property, plant and equipment in the first three months of 2009 were primarily for the natural gas segment ($3.5 million), the propane segment ($420,000), the advanced information services segment ($144,000), and the other operations segment ($75,000).

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Cash Flows Used by Financing Activities

Cash flows used by financing activities totaled $25.2 million for the first three months of 2009, compared to cash used of $2.3 million for the first three months of 2008. Significant financing activities included the following:

• During the first three months of 2009, the Company had a net repayment of short-term debt of $23.2 million, compared to net borrowings of $1.0 million in the first three months of 2008, as it generated higher amounts of cash from operating activities.

• During the first three months of 2009, the Company paid $2.1 million in cash dividends, compared with dividend payments of $1.8 million for the same time period in 2008. The increase in dividends paid in the first three months of 2009 reflects both growth in the annualized dividend rate and the increase in the number of shares outstanding.

• The Company repaid $20,000 of long-term debt during the first three months of 2009, compared to $1.0 million in the first three months of 2008, in accordance with its repayment schedules.

Off-Balance Sheet Arrangements

The Company has issued corporate guarantees to certain vendors of its subsidiaries, primarily its propane wholesale marketing subsidiary and its natural gas supply management subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of either subsidiary’s default. None of these subsidiaries has ever defaulted on its obligations to pay suppliers. The liabilities for these purchases are recorded in the condensed consolidated financial statements when incurred. The aggregate amount guaranteed at March 31, 2009, was $25.4 million, with the guarantees expiring on various dates in 2009 and the first half of 2010.

In addition to the corporate guarantees, the Company has issued a letter of credit to its primary insurance company for $775,000, which expires on May 31, 2009. The letter of credit is provided as security to satisfy the deductibles under the Company’s various insurance policies. There have been no draws on this letter of credit as of March 31, 2009 and the Company does not anticipate that this letter of credit will be drawn upon by the counterparty in the future. The Company expects that the letter of credit will be renewed prior to its expiration on May 31, 2009.

Contractual Obligations

There have not been any material changes in the contractual obligations presented in the Company’s 2008 Annual Report on Form 10-K, except for commodity purchase obligations and forward contracts entered into in the ordinary course of the Company’s business. Below is a summary of the commodity and forward contract obligations at March 31, 2009.

	Payments Due by Period
	Less than						More than
Purchase Obligations	1 year		1 - 3 years		3 - 5 years		5 years		Total
(in Thousands)
Commodities (1) (3)	$	21,821	$	79		—		—	$	21,900
Propane (2)		9,097						—		9,097
Total Purchase Obligations	$	30,919	$	79		—		—	$	30,997

(1)	In addition to the obligations noted above, the natural gas distribution and propane distribution operations have agreements with commodity suppliers that have provisions allowing the Company to reduce or eliminate the quantities purchased. There are no monetary penalties for reducing the amounts purchased; however, the propane contracts allow the suppliers to reduce the amounts available in the winter season if the Company does not purchase specified amounts during the summer season. Under these contracts, the commodity prices will fluctuate as market prices fluctuate.
(2)	The Company has also entered into forward sale contracts in the aggregate amount of $9.2 million. See Part I, Item 3, “Quantitative and Qualitative Disclosures about Market Risk,” below, for further information.
(3)	In March 2009, the Company renewed its contract with an energy marketing and risk management company to manage a portion of the Company’s natural gas transportation and storage capacity. There were no material changes to the contract’s terms as reported on the Company’s 2008 Annual Report on Form 10-K.

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Environmental Matters

As more fully described in Note 3, “Commitments and Contingencies,” to these unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q, Chesapeake has incurred costs relating to the completed or ongoing environmental remediation at two former manufactured gas plant sites. In addition, Chesapeake is currently participating in discussions regarding possible responsibility of the Company for remediation of a third former manufactured gas plant site located in Cambridge, Maryland. Chesapeake believes that future costs associated with these sites will be recoverable in rates or through sharing arrangements with, or contributions by, other responsible parties.

Other Matters

Rates and Regulatory Matters

The Company’s natural gas distribution operations in Delaware, Maryland and Florida are regulated by their respective state PSC. Eastern Shore is subject to regulation by the FERC. At March 31, 2009, Chesapeake was involved in rates and/or regulatory matters in each of the jurisdictions in which it operates. Each of these rates or regulatory matters is fully described in Note 3, “Commitments and Contingencies,” to these unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q.

Competition

The Company’s natural gas operations compete with other forms of energy, including electricity, oil and propane. The principal competitive factors are price and, to a lesser extent, accessibility. The Company’s natural gas distribution operations have several large volume industrial customers that have the capacity to use fuel oil as an alternative to natural gas. When oil prices decline, these interruptible customers may convert to oil to satisfy their fuel requirements, and our interruptible sales volumes may decline because oil prices are lower than the price of natural gas. Oil prices, as well as the prices of electricity and other fuels, fluctuate for a variety of reasons; therefore, future competitive conditions are not predictable. To address this uncertainty, the Company uses flexible pricing arrangements on both the supply and sales sides of this business to compete with alternative fuel price fluctuations. As a result of the transmission operation’s conversion to open access and the Florida gas distribution division’s restructuring of its services, these businesses have shifted from providing competitive sales service to providing only transportation and contract storage services.

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

The Company’s propane distribution operations compete with several other propane distributors in their service territories, primarily on the basis of service and price, emphasizing 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 serviced 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 industry are occurring rapidly, and could adversely impact the markets for the products and services offered by these businesses. This segment of the Company competes on the basis of technological expertise, reputation and price.

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Inflation

Inflation affects the cost of supply, labor, products and services required for operations, maintenance and capital improvements. While the impact of inflation has remained low in recent years, natural gas and propane prices are subject to rapid fluctuations. In the Company’s regulated natural gas distribution operations, fluctuations in natural gas prices are passed on to customers through the gas cost recovery mechanisms in the Company’s tariffs. To help cope with the effects of inflation on its capital investments and returns, the Company seeks rate relief from regulatory commissions for its regulated operations and closely monitors the returns of its unregulated business operations. To compensate for fluctuations in propane gas prices, the Company adjusts its propane selling prices to the extent allowed by the market.

Merger with Florida Public Utilities Company

On April 20, 2009, the Company and FPU announced that they have entered into a definitive merger agreement pursuant to which FPU will merge with a wholly owned subsidiary of the Company. The merger was unanimously approved by both companies’ Boards of Directors on April 17, 2009. Under the merger agreement, holders of FPU common stock will receive 0.405 shares of the Company’s common stock in exchange for each outstanding share of FPU. Based on the average of the Company’s closing stock price for the fifteen trading days prior to April 15, 2009, the transaction has an approximate value of $12.20 per FPU share. Based on the number of FPU shares outstanding at March 20, 2009, the Company would issue approximately 2.5 million of its shares in exchange for all of the issued and outstanding FPU shares. The merger is intended to qualify as a tax-free reorganization and is subject to various regulatory approvals as well as approval by the shareholders of both companies. The merger is expected to close during the fourth quarter of 2009. Although the Company and FPU believe that the expectation as to timing for the closing of the merger described above is reasonable, no assurance can be given as to the timing of the satisfaction of all closing conditions or that all required approvals will be received.

The merger will create a combined energy company serving approximately 200,000 customers (117,000 natural gas, 48,000 propane and 31,000 electric customers) in the Mid-Atlantic and Florida markets with assets totaling $595 million. The Company and FPU recognized $291.4 million and $168.5 million in revenues, respectively, and $13.6 million and $3.5 million in net income, respectively, for 2008. The Company’s management expects the transaction to be earnings neutral or slightly accretive in 2010 and meaningfully accretive in 2011.

Further information concerning the proposed merger can be found in Chesapeake’s Current Report on Form 8-K dated April 20, 2009.

Recent Authoritative Pronouncements on Financial Reporting and Accounting

Recent accounting developments and their impact on our financial position, results of operations and cash flows are described in Note 4, “Recent Authoritative Pronouncements on Financial Reporting and Accounting,” 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. The Company’s long-term debt consists of fixed-rate senior notes and convertible debentures. All of the Company’s long-term debt is fixed-rate debt and was not entered into for trading purposes. The carrying value of long-term debt, including current maturities, was $93.0 million at March 31, 2009, compared to a fair value of $93.3 million, based on 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. The Company evaluates 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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The Company’s propane distribution business is exposed to market risk as a result of propane storage activities and entering into fixed-price contracts for supply. The Company can store up to approximately four million gallons (including leased storage and rail cars) of propane during the winter season to meet its customers’ peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause the value of stored propane to decline. To mitigate the impact of price fluctuations, the Company has adopted a Risk Management Policy that allows the propane distribution operation to enter into fair value hedges of its inventory. Management reviewed the Company’s storage position as of March 31, 2009, and elected not to hedge any of its inventories.

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

The forward and futures contracts are entered into for trading and wholesale marketing purposes. The propane wholesale marketing business is subject to commodity price risk on its open positions to the extent that market prices for NGLs deviate from fixed contract settlement prices. Market risk associated with the trading of futures and forward contracts is monitored daily for compliance with the Company’s Risk Management Policy, which includes volumetric limits for open positions. To manage exposure to changing market prices, open positions are marked up or down to market prices and reviewed by the Company’s oversight officials daily. In addition, the Risk Management Committee reviews periodic reports on 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, 2009, is presented in the following table.

	Quantity in		Estimated Market		Weighted Average
At March 31, 2009	Gallons		Prices		Contract Prices
Forward Contracts
Sale		13,587,000	$	0.6125 — $0.9800	$	0.6775
Purchase		13,608,000	$	0.6000 — $0.9200	$	0.6685

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

At March 31, 2009 and December 31, 2008 the Company marked these forward contracts to market, using broker or dealer quotations, or market transactions in either the listed or OTC markets, which resulted in the following assets and liabilities:

(in thousands)	March 31, 2009		December 31, 2008
Mark-to-market energy assets	$	453	$	4,482
Mark-to-market energy liabilities	$	317	$	3,052

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Chief Executive Officer and Chief Financial Officer of the Company, with the participation of other Company officials, have evaluated the Company’s “disclosure controls and procedures” (as such term is defined under Rules 13a-15(e) and 15d-15(e), promulgated under the Securities Exchange Act of 1934, as amended) as of March 31, 2009. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2009.

Changes in Internal Control Over Financial Reporting

During the quarter ended March 31, 2009, there was no change in the Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings

As disclosed in Note 3, “Commitments and Contingencies,” of these unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q, the Company is involved in certain legal actions and claims arising in the normal course of business. The Company is also involved in certain legal and administrative proceedings before various government agencies concerning rates. In the opinion of management, the ultimate disposition of these proceedings and claims will not have a material effect on the condensed consolidated financial position, results of operations or cash flows of the Company.

Item 1A. Risk Factors

There has not been any material changes from the risk factors as previously disclosed by the Company in its Annual Report on Form 10-K for the year ended December 31, 2008.

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
Period	Purchased		per Share		or Programs (2)		Plans or Programs (2)
January 1, 2009 through January 31, 2009 (1)		596	$	31.80		0		0
February 1, 2009 through February 28, 2009 (1)		52	$	30.61		0		0
March 1, 2009 through March 31, 2009		0	$	0.00		0		0
Total		648	$	31.72		0		0

(1)

Chesapeake purchased shares of stock on the open market for the purpose of reinvesting the dividend on deferred stock units held in the Rabbi Trust accounts for certain Senior Executives under the Deferred Compensation Plan. The Deferred Compensation Plan is discussed in detail in Note L to the Consolidated Financial Statements of the Company’s Form 10-K filed with the Securities Exchange Commission on March 9, 2009. During the quarter, 648 shares were purchased through the reinvestment of dividends on deferred stock units.

(2)

Except for the purposes described in Footnotes (1) & (2), Chesapeake has no publicly announced plans or programs to repurchase its shares.

Item 3. Defaults upon Senior Securities

None.

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

None.

Item 5. Other Information

None

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Item 6. Exhibits

2.1	Agreement and Plan of Merger between Chesapeake Utilities Corporation and Florida Public Utilities Company dated April 17, 2009, is incorporated herein by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K, filed April 20, 2009, File No. 001-11590.
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 8, 2009.
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 8, 2009.
32.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated May 8, 2009.
32.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated May 8, 2009.

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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 8, 2009

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EXHIBIT INDEX

Exhibit
No.		Description
	31.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, dated May 8, 2009.
	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 8, 2009.
	32.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated May 8, 2009.
	32.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated May 8, 2009.

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