Chesapeake Utilities - 10-Q quarterly report FY

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: June 30, 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).Yeso Noo

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


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

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

Common Stock, par value $0.4867 — 6,880,661 shares outstanding as of July 31, 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			22

Item 3. Quantitative and Qualitative Disclosures about Market Risk			43

Item 4. Controls and Procedures			44

PART II — OTHER INFORMATION			45

Item 1. Legal Proceedings			45

Item 1A. Risk Factors			45

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			45

Item 3. Defaults upon Senior Securities			46

Item 4. Submission of Matters to a Vote of Security Holders			46

Item 5. Other Information			46

Item 6. Exhibits			47

SIGNATURES			48

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
PIPECO		Peninsula Pipeline 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
FPU		Florida Public Utilities Company
FSP		Financial Accounting Standards Board Staff Position
GAAP		Generally Accepted Accounting Principles
GSR		Gas Sales Service Rates
HDD		Heating Degree-Days
PIP		Performance Incentive Plan
RAP		Remedial Action Plan
SFAS		Statement of Financial Accounting Standards


		Accounting Standards
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 132(R)-1		FSP FAS 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets
FSP FAS 142-3		FSP FAS 142-3, Determining the Useful Life of Intangible Assets
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. 161		SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS No. 133
SFAS No. 165		SFAS No. 165, Subsequent Events
SFAS No. 168		SFAS No. 168, The FASB Accounting Standards Codification^TM and the Hierarchy of Generally Accepted Accounting Principles, a replacement of SFAS No. 162

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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 June 30,	2009		2008

Operating Revenues	$	40,834	$	69,057

Operating Expenses
Cost of sales, excluding costs below		20,467		48,540
Operations		11,575		10,743
Transaction costs		1,090		1,240
Maintenance		716		503
Depreciation and amortization		2,413		2,225
Other taxes		1,717		1,477

Total operating expenses		37,978		64,728


Operating Income		2,856		4,329

Other income, net of other expenses		12		64

Interest charges		1,573		1,389


Income Before Income Taxes		1,295		3,004

Income taxes		489		1,185


Net Income	$	806	$	1,819


Weighted-average common shares outstanding:
Basic		6,862,248		6,812,474
Diluted		6,868,717		6,920,042

Earnings Per Share of Common Stock:
Basic	$	0.12	$	0.27
Diluted	$	0.12	$	0.27

Cash Dividends Declared Per Share of Common Stock:	$	0.315	$	0.305

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

- 1 -

Chesapeake Utilities Corporation and Subsidiaries

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


For the Six Months Ended June 30,	2009		2008

Operating Revenues	$	145,313	$	169,330

Operating Expenses

Cost of sales, excluding costs below		91,689		119,519
Operations		23,820		21,512
Transaction costs		1,204		1,240
Maintenance		1,332		989
Depreciation and amortization		4,797		4,428
Other taxes		3,649		3,272

Total operating expenses		126,491		150,960


Operating Income		18,822		18,370

Other income, net of other expenses		45		81

Interest charges		3,215		2,982


Income Before Income Taxes		15,652		15,469

Income taxes		6,253		6,076


Net Income	$	9,399	$	9,393


Weighted Average Common Shares Outstanding:
Basic		6,847,543		6,803,892
Diluted		6,963,132		6,917,308

Earnings Per Share of Common Stock:
Basic	$	1.37	$	1.38
Diluted	$	1.36	$	1.36

Cash Dividends Declared Per Share of Common Stock:	$	0.620	$	0.600

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 Six Months Ended June 30,	2009			2008

Operating Activities
Net Income	$	9,399		$	9,393
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		4,797			4,428
Depreciation and accretion included in other costs		1,318			901
Deferred income taxes, net		2,673			2,163
Unrealized loss (gain) on commodity contracts		1,135			(358	)
Unrealized loss (gain) on investments		(19	)		86
Employee benefits		977			101
Share based compensation		585			476
Changes in assets and liabilities:
Accounts receivable and accrued revenue		25,406			(11,633	)
Propane inventory, storage gas and other inventory		5,006			(229	)
Regulatory assets		309			282
Prepaid expenses and other current assets		2,957			1,656
Other deferred charges		64			(497	)
Accounts payable and other accrued liabilities		(15,071	)		3,360
Income taxes receivable		6,111			1,137
Accrued interest		632			716
Customer deposits and refunds		(1,902	)		(1,003	)
Accrued compensation		(1,151	)		(1,042	)
Regulatory liabilities		3,454			(385	)
Other liabilities		141			91

Net cash provided by operating activities		46,821			9,643


Investing Activities
Property, plant and equipment expenditures		(11,969	)		(15,440	)
Environmental expenditures		(7	)		(199	)

Net cash used by investing activities		(11,976	)		(15,639	)


Financing Activities
Common stock dividends		(3,948	)		(3,799	)
Issuance of stock for Dividend Reinvestment Plan		126			15
Change in cash overdrafts due to outstanding checks		—			(129	)
Net borrowing (repayment) under line of credit agreements		(31,000	)		11,520
Repayment of long-term debt		(20	)		(1,020	)

Net cash provided (used) by financing activities		(34,842	)		6,587


Net Increase in Cash and Cash Equivalents		3			591
Cash and Cash Equivalents — Beginning of Period		1,611			2,593

Cash and Cash Equivalents — End of Period	$	1,614		$	3,184

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)


	June 30,			December 31,
	2009			2008
Assets

Property, Plant and Equipment
Natural gas	$	321,413		$	316,125
Propane		52,044			51,827
Advanced information services		1,430			1,439
Other plant		10,920			10,816

Total property, plant and equipment		385,807			380,207

Less: Accumulated depreciation and amortization		(105,293	)		(101,018	)
Plus: Construction work in progress		6,502			1,482

Net property, plant and equipment		287,016			280,671


Investments		1,647			1,601


Current Assets
Cash and cash equivalents		1,614			1,611
Accounts receivable (less allowance for uncollectible accounts of $1,386 and $1,159, respectively)		31,062			52,905
Accrued revenue		1,605			5,168
Propane inventory, at average cost		4,507			5,711
Other inventory, at average cost		1,322			1,479
Regulatory assets		589			826
Storage gas prepayments		5,847			9,492
Income taxes receivable		1,332			7,443
Deferred income taxes		3,053			1,578
Prepaid expenses		1,821			4,679
Mark-to-market energy assets		944			4,482
Other current assets		146			147

Total current assets		53,842			95,521


Deferred Charges and Other Assets
Goodwill		674			674
Other intangible assets, net		157			164
Long-term receivables		435			533
Regulatory assets		2,699			2,806
Other deferred charges		3,819			3,825

Total deferred charges and other assets		7,784			8,002


Total Assets	$	350,289		$	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)


	June 30,			December 31,
	2009			2008
Capitalization and Liabilities

Capitalization
Stockholders’ equity
Common stock, par value $0.4867 per share (authorized 12,000,000 shares)	$	3,344		$	3,323
Additional paid-in capital		68,352			66,681
Retained earnings		61,931			56,817
Accumulated other comprehensive loss		(3,600	)		(3,748	)
Deferred compensation obligation		1,315			1,549
Treasury stock		(1,315	)		(1,549	)

Total stockholders’ equity		130,027			123,073

Long-term debt, net of current maturities		86,313			86,422

Total capitalization		216,340			209,495


Current Liabilities
Current portion of long-term debt		6,656			6,656
Short-term borrowing		2,000			33,000
Accounts payable		25,321			40,202
Customer deposits and refunds		7,632			9,534
Accrued interest		1,655			1,024
Dividends payable		2,164			2,082
Accrued compensation		2,190			3,305
Regulatory liabilities		6,719			3,227
Mark-to-market energy liabilities		650			3,052
Other accrued liabilities		2,771			2,970

Total current liabilities		57,758			105,052


Deferred Credits and Other Liabilities
Deferred income taxes		41,967			37,720
Deferred investment tax credits		214			235
Regulatory liabilities		837			875
Environmental liabilities		469			511
Other pension and benefit costs		7,502			7,335
Accrued asset removal cost		21,133			20,641
Other liabilities		4,069			3,931

Total deferred credits and other liabilities		76,191			71,248


Commitments and Contingencies (Note 3)

Total Capitalization and Liabilities	$	350,289		$	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 (Unaudited)
(in Thousands, Except Shares and Per Share Data)


	Common Stock										Accumulated
	Number					Additional					Other
	of			Par		Paid-In		Retained			Comprehensive			Deferred			Treasury
	Shares			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		6,827,121			3,323		66,681		56,817			(3,748	)		1,549			(1,549	)		123,073
Net earnings									9,399												9,399
Other comprehensive income, net of tax:
Employee Benefit Plans, net of tax:
Amortization of prior service costs ⁽⁴⁾												2									2
Net Gain ⁽⁵⁾												146									146

Total comprehensive income																					9,547

Dividend Reinvestment Plan		12,727			6		352														358
Retirement Savings Plan		18,980			9		547														556
Conversion of debentures		5,227			3		86														89
Share based compensation ^{(1) (3)}		6,700			3		686														689
Deferred Compensation Plan ⁽⁶⁾															(234	)		234			—
Purchase of treasury stock		(1,297	)															(38	)		(38	)
Sale and distribution of treasury stock		1,297																38			38
Dividends on stock-based compensation									(36	)											(36	)
Cash dividends ⁽²⁾									(4,249	)											(4,249	)

Balances at June 30, 2009		6,870,755		$	3,344	$	68,352	$	61,931		$	(3,600	)	$	1,315		$	(1,315	)	$	130,027


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

⁽²⁾		Cash dividends per share for the periods ended June 30, 2009 and December 31, 2008 were $0.62 and $1.21, respectively .

⁽³⁾		The shares issued under the Performance Incentive Plan (“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 June 30, 2009 and December 31, 2008 were approximately $2 and ($52), respectively .

⁽⁵⁾		Tax expense (benefit) recognized on the net gain (loss) component of employees benefit plans for the periods ended June 30, 2009 and December 31, 2008 were $97 and ($1,900), respectively.

⁽⁶⁾		In May 2009, certain participants of the Deferred Compensation Plan received distributions totaling $271.

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

- 6 -

Notes to Condensed Consolidated Financial Statements

1.

Summary of Accounting Policies

Basis of Presentation

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

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and United States of America Generally Accepted Accounting Principles (“GAAP”). In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in the Company’s latest Annual Report on Form 10-K filed with the SEC on March 9, 2009. In the opinion of management, these financial 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 statement of cash flows for the six months ended June 30, 2008 to conform to current period classifications. In addition, the Company revised its 2008 segment information by reclassifying transaction costs, which were previously allocated to the natural gas, propane and advanced information services segments, to the “other and eliminations” segment. These reclassifications are considered immaterial to the overall presentation of the Company’s condensed consolidated financial statements.

Pending Merger with Florida Public Utilities Company

On April 20, 2009, Chesapeake and Florida Public Utilities Company (“FPU”) announced a definitive merger agreement, pursuant to which FPU will merge with a wholly-owned subsidiary of Chesapeake with FPU being the surviving corporation and operating as a wholly-owned subsidiary of Chesapeake after the merger. Prior to completion of the merger, Chesapeake and FPU will continue to operate as separate companies. Additional discussions regarding the detail of this pending merger are provided in Note 10, “Merger with Florida Public Utilities Company”.

The merger will be accounted for under the acquisition method of accounting pursuant to Statement of Financial Accounting Standard (“SFAS”) No. 141(R), “Business Combinations,” (“SFAS No. 141(R)”) which Chesapeake adopted on January 1, 2009, with Chesapeake treated as the acquirer. Under the acquisition method of accounting, the assets acquired and liabilities assumed are recorded, as of completion of the merger, at their respective fair values and added to those of Chesapeake, and acquisition-related transaction costs are expensed in the periods in which the costs are incurred, rather than including the costs as a component of consideration transferred. Accordingly, the Company expensed approximately $1.2 million related to the merger in 2009. The Company may seek regulatory approval to defer costs related to the acquisition of regulated operations and receive future rate recovery. Future regulatory developments may allow the Company to defer those costs pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.”

The Company assesses the income tax effect of acquisition-related transaction costs based on circumstances that exist as of the date the costs are incurred, without assuming the merger will ultimately occur, and records a deferred tax asset related to acquisition-related transaction costs as needed. The Company may be required to reassess the income tax effect of acquisition-related transaction costs in the future depending on the status of the pending merger.

- 7 -

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.

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 June 2009, the FASB issued SFAS No. 168, “the FASB Accounting Standards Codification^TMand the Hierarchy of Generally Accepted Accounting Principles, a replacement of SFAS No. 162” (“SFAS No. 168”). SFAS No. 168 establishes the FASB Accounting Standards Codification (“Codification”) as the source of authoritative accounting principles recognized by the FASB, which are to be applied by nongovernmental entities in the preparation of financial statements in conformity with GAAP. On the effective date (September 15, 2009), the Codification will supersede all then-existing non-SEC accounting and reporting standards. Other than resolving certain minor inconsistencies in GAAP, the Codification is not intended to change GAAP. As a result of the adoption of SFAS No. 168, the Company’s presentation of accounting and reporting standards included in its third quarter Form 10-Q is expected to be substantially different from current practice, but the Company expects no material impact on its financial position and results of operations.

During the first six months of 2009, the Company adopted the following other accounting standards:

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS No. 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 No. 161 is 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 No. 161 had no financial impact on the Company’s condensed consolidated financial statements. The disclosures required by SFAS No. 161 are discussed in Note 8, “Derivative Instruments,” to the condensed consolidated financial statements.

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 SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”). The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141(R) and other GAAP. This FSP is 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.

- 8 -

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, which 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 is 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 containing rights to nonforfeitable dividends participate in undistributed earnings with common shareholders. Awards of this nature are considered participating securities, and the two-class method of computing basic and diluted earnings per share must be applied. This FSP is effective for 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 April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” to enhance consistency in financial reporting by increasing the frequency of fair value disclosures. FSP FAS 107-1 and APB 28-1 are effective for interim and annual reporting periods ending after June 15, 2009. The adoption of this standard did not have an impact on the Company’s condensed consolidated financial position and results of operations. The disclosures required by FSP FAS 107-1 and APB 28-1 are discussed in Note 9, “Fair Value of Financial Instruments,” to the condensed consolidated financial statements.

In May 2009, the FASB issued SFAS No. 165, “Subsequent Events,” (“SFAS No. 165”), which the Company adopted in the second quarter of 2009. SFAS No. 165 establishes general standards of accounting for, and disclosure of, events that occur after the balance sheet date, but before financial statements are issued or are available to be issued. Although SFAS No. 165 contains new terminology, it is based on the same principles as those that currently exist in the auditing standards. Adoption of SFAS No. 165 did not have an impact on the Company’s condensed consolidated financial position and results of operations. In accordance with SFAS No. 165, the Company assessed subsequent events through August 7, 2009, the date of issuance of these condensed consolidated financial statements.

2.

Calculation of Earnings Per Share


	Three Months				Six Months
For the Periods Ended June 30,	2009		2008		2009		2008
(in Thousands, except Shares and Per Share Data)
Calculation of Basic Earnings Per Share:
Net Income	$	806	$	1,819	$	9,399	$	9,393
Weighted average shares outstanding		6,862,248		6,812,474		6,847,543		6,803,892

Basic Earnings Per Share	$	0.12	$	0.27	$	1.37	$	1.38


Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	806	$	1,819	$	9,399	$	9,393
Effect of 8.25% Convertible debentures⁽¹⁾		—		22		40		45

Adjusted numerator — Diluted	$	806	$	1,841	$	9,439	$	9,438


Reconciliation of Denominator:
Weighted shares outstanding — Basic		6,862,248		6,812,474		6,847,543		6,803,892
Effect of dilutive securities: ⁽¹⁾
Share-based Compensation		6,469		2,780		20,714		7,449
8.25% Convertible debentures		—		104,788		94,875		105,967

Adjusted denominator — Diluted		6,868,717		6,920,042		6,963,132		6,917,308


Diluted Earnings Per Share	$	0.12	$	0.27	$	1.36	$	1.36


(1)		Amounts associated with securities resulting in an anti-dilutive effect on earnings per share are not included in this calculation.

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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 Company (“ESNG”), the Company’s natural gas transmission operation, is subject to regulation by the Federal Energy Regulatory Commission (“FERC”).

Regulatory matters related to the pending merger with FPU are discussed in Note 10, “Merger with Florida Public Utilities Company.”

Delaware. On September 2, 2008, the Company’s Delaware division filed with the Delaware Public Service Commission (“Delaware PSC”) its annual Gas Sales Service Rates (“GSR”) Application, seeking approval to change its GSR, effective November 1, 2008. On 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, effective February 1, 2009. On January 29, 2009, the Delaware PSC authorized the Delaware division to implement the revised GSR charges on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. On July 7, 2009, the Delaware PSC granted approval of a settlement agreement presented by the parties in this docket, the Delaware PSC, the Company’s Delaware division and the Division of the Public Advocate. Pursuant to the settlement agreement, the Company’s Delaware division will prospectively adjust the margin-sharing mechanism related to its Asset Management Agreement to reduce its proportionate share of such margin beginning in November 2009. The Company anticipates a net margin reduction of approximately $8,000 per year from this change. As part of the settlement, the parties also agreed to develop a record in a later proceeding on the price charged by the Delaware division for the temporary release of transmission pipeline capacity to the Company’s natural gas marketing subsidiary, Peninsula Energy Services Company (“PESCO”). This later proceeding may be completed by the end of 2009.

On December 2, 2008, the Company’s 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 allow 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 Milford and the 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 Company’s 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 defining 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 Company’s Maryland division to: (a) provide customers in writing, prior to issuing a termination notice, certain details about their past due balance and information about available payment plans, and (b) continue to offer flexible and tailored payment plans. The Company’s Maryland division has implemented procedures to comply with this Order.

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Florida. On July 17, 2009, the Company’s Florida division filed with the Florida Public Service Commission (“Florida PSC”) its petition for a rate increase and request for interim rate relief. In the application, the Florida division seeks approval of: (a) an interim rate increase of $417,555; (b) a permanent rate increase of $2,965,398, which represents an average base rate increase (not including fuel) of approximately 25 percent for the Florida division’s customers; (c) implementation of or modification to certain surcharge mechanisms; (d) restructuring of certain rate classifications; and (e) deferral of certain costs and the purchase premium associated with the pending merger with FPU. The Florida division anticipates an interim rate decision by the FPSC during the third quarter of 2009 and a final decision on the permanent rate increase during the fourth quarter of 2009.

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.

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

In April 2009, ESNG terminated the E3 Project and initiated billing of a pre-certification costs surcharge in accordance with the terms of the Precedent Agreements and Letter Agreements executed with the two participating customers, one of which is Chesapeake, through its Delaware and Maryland divisions. The surcharge will reimburse ESNG for the $3.17 million of pre-certification costs incurred in connection with the E3 Project, including cost of capital, over a period of 20 years.

FERC Order Nos. 712 and 712-A. In June and November 2008, the FERC issued Order Nos. 712 and 712-A, which revised its regulations regarding interstate natural gas pipeline capacity release programs. The Orders: (a) remove the rate ceiling on capacity release transactions of one year or less; (b) facilitate the use of asset management arrangements for certain capacity releases; and (c) facilitate state-approved retail open access programs. The Orders required interstate gas pipeline companies 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.

ESNG also had developments in the following FERC matters:

On April 30, 2009, ESNG submitted its annual Interruptible Revenue Sharing Report to the FERC. ESNG reported in this filing that it refunded a total of $245,500, inclusive of interest, in the second quarter of 2009 to its eligible firm customers.

On May 29, 2009, ESNG submitted its annual Fuel Retention Percentage (“FRP”) and Cash-Out Surcharge filings to the FERC. In these filings, ESNG proposed to implement an FRP rate of 0.12 percent and a zero rate for its Cash-Out Surcharge. ESNG also proposed to refund a total of $294,540, inclusive of interest, to its eligible customers in the second quarter of 2009 by netting its over-recovered fuel cost against its under-recovered Cash-Out cost. The FERC approved these proposals, and ESNG refunded $294,540 to customers in July 2009.

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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.

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 June 30, 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 June 30, 2009, a regulatory asset of approximately $841,000 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 June 30, 2009, the Company has accrued $1.8 million of environmental costs associated with this site. At June 30, 2009, the Company had accrued a liability of $469,000 related to this site, offsetting: (a) a regulatory asset of approximately $744,000, representing the uncollected portion of the estimated clean-up costs, and (b) approximately $275,000 collected through rates in excess of costs incurred. The Company expects to recover the remaining clean-up costs through rates.

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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.

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.

In May 2009, the Company’s natural gas marketing subsidiary, PESCO, renewed contracts to purchase natural gas from various suppliers. These contracts expire on May 31, 2010.

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, Xeron, and its natural gas marketing subsidiary, PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases in the event that either subsidiary defaults. Neither subsidiary 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 June 30, 2009 was $22.4 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, 2010. 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 June 30, 2009.

Application of SFAS No. 71

The Company accounts for its regulated operations in accordance with SFAS No 71. 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.

Litigation matters related to the pending merger with FPU are discussed in Note 10, “Merger with Florida Public Utilities Company.”

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4.

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.

During 2009, the Company revised the 2008 segment information by reclassifying transaction costs, previously allocated to the natural gas, propane and advanced information services segments, to the “other and eliminations” segment. These costs, related to an unconsummated acquisition in 2008, were not directly attributable to operations of the Company’s natural gas, propane and advanced information services segments, but were allocated to those segments as corporate overhead costs in 2008. In conjunction with the pending merger in 2009 and related acquisition costs (see Notes 1 and 10), the Company reassessed its previous practice of allocating transaction costs that are not attributable to operations to each of its reportable segments and decided not to allocate those costs for the purpose of analyzing segment profitability. As a result of this change, $890,000, $273,000 and $64,000 of transaction costs allocated to the natural gas, propane and advanced information services segments, respectively, in the second quarter of 2008, were reclassified to “other and eliminations” segment.

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The following table presents information about the Company’s reportable segments.


	Three Months Ended						Six Months Ended
For the Periods Ended June 30,	2009			2008			2009			2008
	(in Thousands)						(in Thousands)
Operating Revenues, Unaffiliated Customers
Natural gas	$	30,268		$	53,774		$	104,170		$	122,596
Propane		7,948			11,489			35,232			39,297
Advanced information services		2,618			3,794			5,911			7,437

Total operating revenues, unaffiliated customers	$	40,834		$	69,057		$	145,313		$	169,330


Intersegment Revenues ⁽¹⁾
Natural gas	$	136		$	104		$	273		$	211
Propane		252			—			254			1
Advanced information services		22			28			34			36
Other		171			163			343			326

Total intersegment revenues	$	581		$	295		$	904		$	574


Operating Income (Loss)
Natural gas	$	4,648		$	5,626		$	15,251		$	16,095
Propane		(561	)		(352	)		4,925			3,092
Advanced information services		(240	)		202			(345	)		239
Other and eliminations		(991	)		(1,147	)		(1,009	)		(1,056	)

Total operating income	$	2,856		$	4,329		$	18,822		$	18,370

Other Income, net of other expenses		12			64		$	45		$	81
Interest		1,573			1,389			3,215			2,982
Income Taxes		489			1,185			6,253			6,076

Net income	$	806		$	1,819		$	9,399		$	9,393


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


	June 30,		December 31,
	2009		2008
	(in Thousands)

Identifiable Assets
Natural gas	$	280,193	$	297,407
Propane		56,706		72,955
Advanced information services		3,670		3,545
Other		9,682		11,849

Total identifiable assets	$	350,251	$	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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5.

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 June 30,	2009			2008			2009		2008		2009		2008
(in Thousands)
Service Cost	$	—		$	—		$	—	$	—	$	1	$	1
Interest Cost		140			148			32		32		27		28
Expected return on plan assets		(87	)		(156	)		—		—		—		—
Amortization of prior service cost		(1	)		(1	)		4		—		—		—
Amortization of net loss		69			—			15		12		39		46

Net periodic (benefit) cost	$	121		$	(9	)	$	51	$	44	$	67	$	75


	Defined Benefit						Pension Supplemental				Other Post-Retirement
	Pension Plan						Executive Retirement Plan				Benefits
For the Six Months Ended June 30,	2009			2008			2009		2008		2009		2008
(in Thousands)
Service Cost	$	—		$	—		$	—	$	—	$	1	$	2
Interest Cost		280			297			64		63		54		55
Expected return on plan assets		(173	)		(313	)		—		—		—		—
Amortization of prior service cost		(2	)		(2	)		7		—		—		—
Amortization of net loss		137			—			30		23		79		92

Net periodic (benefit) cost	$	242		$	(18	)	$	101	$	86	$	134	$	149

The Company expects to recognize increased pension and post-retirement 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 during the fourth quarter of 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 and six months ended June 30, 2009, were $22,000 and $45,000, respectively; 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 and six months ended June 30, 2009, totaled $24,000 and $34,000, respectively. Based on actuarial assumptions and historical data, the Company has estimated that approximately $225,000 will be paid for such benefits during 2009.

6.

Investments

The investment balance at June 30, 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 June 30, 2009, total investments had a fair value of $1.6 million.

7.

Share-Based Compensation

The Company accounts for its share-based compensation arrangements under SFAS No. 123 (revised 2004), “Share Based Payments” (“SFAS No. 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”), which require accounting under SFAS No. 123(R).

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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 and six months ended June 30, 2009 and 2008.


(in Thousands)	Three Months Ended				Six Months Ended
For the periods ended June 30,	2009		2008		2009		2008
Directors Stock Compensation Plan	$	48	$	46	$	95	$	92
Performance Incentive Plan		295		199		490		384

Total compensation expense		343		245		585		476
Less: tax benefit		137		98		234		189

SFAS No. 123R amounts included in net income	$	206	$	147	$	351	$	287

Directors Stock Compensation Plan

Shares granted under the DSCP are issued in advance of the directors’ service period and are fully vested as of the date of the grant. The Company records a prepaid expense of the shares issued and amortizes the expense equally over a service period of one year. In May 2009, 6,500 shares were granted to the directors of the Company. A summary of stock activity under the DSCP for the six months ended June 30, 2009 is presented below:


			Weighted Average
	Number of Shares		Grant Date Fair Value
Outstanding — December 31, 2008		—

Granted		6,500	$	29.76
Vested		6,500	$	29.76
Forfeited		—		—
Expired		—		—

Outstanding — June 30, 2009		—

At June 30, 2009, there was $161,000 of unrecognized compensation expense related to the DSCP awards that is expected to be recognized over the remaining 10 months of the directors’ service period ending April 30, 2010.

Performance Incentive Plan

In January 2009, the Company’s Board of Directors granted 28,875 share-based awards under the PIP. The table below presents the summary of the stock activity for the PIP for the six months ended June 30, 2009:


			Weighted Average Fair
	Number of Shares		Value
Outstanding — December 31, 2008		94,200	$	27.71

Granted		28,875	$	29.36
Vested		—		—
Forfeited		—		—
Expired		—		—

Outstanding — June 30, 2009		123,075	$	28.19

The shares granted in January 2009 are multi-year awards that will vest at the end of the three-year service period or December 31, 2011. These awards are based upon the achievement of long-term goals, development and success of the Company, and they comprise both market-based and performance-based conditions and targets. The fair value of each performance-based condition or target is equal to the market price of the Company’s common stock on the date of the grant. For the market-based conditions, the Company used the Monte-Carlo pricing model to estimate the fair value of each market-based award granted.

At June 30, 2009, the aggregate intrinsic value of the PIP awards was $2.1 million.

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8.

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 June 30, 2009, the Company’s natural gas and propane distribution operations did not have any outstanding derivative contracts.

Xeron, the Company’s propane wholesale and marketing subsidiary, 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 statement of income in the period of change. As of June 30, 2009, the Company had the following outstanding trading contracts:


	Quantity in		Estimated Market	Weighted Average
At June 30, 2009	Gallons		Prices	Contract Prices
Forward Contracts:
Sales		18,270,000	$0.6625 - $0.9800	$	0.8130
Purchases		17,346,000	$0.6488 - $0.9300	$	0.7981

The following tables present information about the 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 values of the derivative contracts recorded in the Balance Sheet as of June 30, 2009 and December 31, 2008, are as follows:


	Asset Derivatives
		Fair Value
(in Thousands)	Balance Sheet Location	June 30, 2009		December 31, 2008
Derivatives not designated as fair value hedges under SFAS No. 133:
Forward contracts	Mark-to-market energy assets	$	944	$	4,482


Total asset derivatives		$	944	$	4,482

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	Liability Derivatives
		Fair Value
(in Thousands)	Balance Sheet Location	June 30, 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 fair value hedges under SFAS No. 133:
Forward contracts	Mark-to-market energy liabilities	$	650	$	3,052


Total liability derivatives		$	650	$	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 was offered to customers. The Company terminated this swap agreement in January 2009.

The effects of gains and losses from derivative instruments on the Statement of Income for the three and six months ended June 30, 2009 and 2008, are as follows:


	Amount of Gain (Loss) on Derivatives:
	Location of Gain	Three months ended June 30,				Six months ended June 30,
(in Thousands)	(Loss) on Derivatives	2009		2008		2009			2008
Derivatives designated as fair value hedges under SFAS No. 133:
Propane swap agreement ⁽¹⁾	Cost of Sales	$	—	$	—	$	(42	)	$	—

Derivatives not designated as fair value hedges under SFAS No. 133:
Unrealized gains on forward contracts	Revenue	$	159	$	532	$	295		$	537


Total		$	159	$	532	$	253		$	537


⁽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 was offered to customers. The Company terminated this swap agreement in January 2009.

The effects of trading activities on the Statement of Income for the three and six months ended June 30, 2009 and 2008, are as follows:


	Amount of Trading Revenue:
	Location in the	Three months ended June 30				Six months ended June 30,
(in Thousands)	Statement of Income	2009		2008		2009			2008
Realized gains on forward contracts	Revenue	$	287	$	265	$	2,068		$	1,142
Changes in mark-to-market energy assets	Revenue		159		532		(1,135	)		358

Total		$	446	$	797	$	933		$	1,500

9.

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).

- 19 -

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 June 30, 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	$	1,647	$	1,647		—		—
Mark-to market energy assets	$	944		—	$	944		—

Liabilities:
Mark-to-market energy liabilities	$	650		—	$	650		—

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		—
Propane Swap Agreement	$	105		—	$	105		—

- 20 -

The following valuation techniques were used to measure fair value assets in the tables above on a recurring basis as of June 30, 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 for similar assets and liabilities from OTC markets.

At June 30, 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.

Other Financial Assets and Liabilities

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

At June 30, 2009, long-term debt, which includes the current maturities of long-term debt, had a carrying value of $93.0 million, compared to a fair value of $91.7 million, using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, with adjustments for duration, optionality, and risk profile.

10.

Merger with Florida Public Utilities Company

On April 20, 2009, Chesapeake and FPU announced a definitive merger agreement, pursuant to which FPU will merge with a wholly-owned subsidiary of Chesapeake with FPU being the surviving corporation and operating as a wholly-owned subsidiary of Chesapeake after the merger. The merger was unanimously approved by the Board of Directors of each company 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 of common stock outstanding at April 17, 2009, the last trading day prior to the public announcement of the merger, Chesapeake shareholders will own approximately 73 percent of the combined company, and FPU common shareholders will own approximately 27 percent of the combined company.

FPU distributes natural gas, propane and electricity to residential, commercial and industrial customers in Florida. FPU also sells merchandise and other service-related products as a complement to its natural gas and propane operations. FPU serves approximately 96,000 customers, employs 348 people and generated $168.5 million in revenues for 2008.

The merger agreement contains certain termination rights for Chesapeake and FPU, including the right to terminate the merger agreement if the merger is not completed by January 31, 2010 (subject to possible extension to March 31, 2010, under specified circumstances). The merger agreement further provides that, upon termination of the merger agreement under certain circumstances involving a third-party takeover proposal of FPU or a change in the FPU board of directors’ recommendation of the merger, FPU would be required, subject to certain conditions, to pay Chesapeake a termination fee of $3.4 million.

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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 statutory waiting period for the Hart-Scott-Rodino Act expired on June 4, 2009, without comment from the Antitrust Division of the United States Department of Justice or the Federal Trade Commission, thus allowing the companies to continue with the merger. The expiration of the waiting period does not, however, preclude the Department of Justice or the Federal Trade Commission from challenging the merger on antitrust grounds. Chesapeake has also received all of the necessary regulatory approvals from the Delaware, Maryland and Florida Public Service Commissions for the merger. Special shareholder meetings for Chesapeake and FPU to vote on the merger-related matters have not been scheduled.

On May 8, 2009, a putative class action lawsuit purportedly on behalf of the shareholders of FPU, challenging the merger was filed in Palm Beach County, Florida, against FPU, each member of FPU’s board of directors and Chesapeake. The complaint alleges, among other things, that the approval of the proposed merger by the directors of FPU constituted a breach of their fiduciary duties. The suit seeks to enjoin completion of the merger. While FPU, its directors, and Chesapeake believe that the allegations in the lawsuit are without merit and intend to defend vigorously against these allegations, no assurance can be given as to the outcome of this lawsuit, including the costs associated with defending this claim, or any other liabilities or costs the parties may incur in connection with the litigation or settlement of this claim.

Chesapeake’s management believes that the merger will close in the fourth quarter of 2009. Although management believes that its expectation as to timing for the closing of the merger is reasonable, no assurance can be given as to whether the merger will close, which requires that certain conditions be satisfied, including obtaining shareholder approvals and resolving the above described putative shareholder class action lawsuit, or as to the timing of closing.

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 weather or 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;

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

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

- 22 -

	•		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 and new accounting pronouncements;

	•		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. There are a number of risks and uncertainties that could cause actual results to differ materially from the forward-looking statements included in this report. These risks and uncertainties include the following: the companies may be unable to obtain regulatory approvals required for the transaction, or that 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; problems may arise in successfully integrating the businesses of the companies, which may result in the combined company not operating as effectively and efficiently as expected; the combined company may be unable to achieve cost-cutting synergies or it may take longer than expected to achieve those synergies; the transaction may involve unexpected costs or unexpected liabilities, or that the accounting for the transaction may be different from the companies’ expectations; the businesses of the companies may suffer as a result of uncertainty surrounding the transaction; the natural gas and electric industries may be subject to future regulatory or legislative actions that could adversely affect the combined company; and the combined company may be adversely affected by other economic, business, and/or competitive factors.

- 23 -

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 4, “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.

Pending Merger with Florida Public Utilities Company

On April 20, 2009, Chesapeake and Florida Public Utilities Company (“FPU”) announced a definitive merger agreement, pursuant to which FPU will merge with a wholly-owned subsidiary of Chesapeake. The merger was unanimously approved by the Board of Directors of each company 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 of common stock outstanding at April 17, 2009, the last trading day prior to the public announcement of the merger, Chesapeake shareholders will own approximately 73 percent of the combined company, and FPU common shareholders will own approximately 27 percent of the combined company.

FPU distributes natural gas, propane and electricity to residential, commercial and industrial customers in Florida. FPU also sells merchandise and other service-related products as a complement to its natural gas and propane operations. FPU serves approximately 96,000 customers, employs 348 people and generated $168.5 million in revenues for 2008. 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.

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 waiting period for the Hart-Scott-Rodino Act expired on June 4, 2009, and Chesapeake received all of the necessary regulatory approvals from the Delaware, Maryland and Florida Public Service Commissions. Special shareholder meetings for Chesapeake and FPU to vote on the merger related matters will be scheduled.

- 24 -

The merger will be accounted for under the acquisition method of accounting pursuant to Statement of Financial Accounting Standard (“SFAS”) No. 141(R), “Business Combinations,” which Chesapeake adopted on January 1, 2009, with Chesapeake treated as the acquirer. Under acquisition method accounting, the assets acquired and liabilities assumed are recorded, as of completion of the merger, at their respective fair values and added to those of Chesapeake, and acquisition-related transaction costs are expensed in the periods in which the costs are incurred, rather than including them as a component of consideration transferred. Accordingly, the Company expensed approximately $1.2 million related to the merger in 2009. The Company may seek regulatory approval to defer costs related to the acquisition of regulated operations and to receive future rate recovery. Future regulatory developments may allow the Company to defer those costs pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.”

Further information concerning the proposed merger can be found in Chesapeake’s Current Reports on Form 8-K dated April 20, 2009 and July 21, 2009.

Results of Operations for the Quarter Ended June 30, 2009

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

Consolidated Overview

The Company’s net income for the quarter ended June 30, 2009, decreased by $1.0 million or 56 percent, compared to the same period in 2008. The Company reported net income of approximately $806,000, or $0.12 per share (diluted), during the quarter ended June 30, 2009, compared to net income of approximately $1.8 million, or $0.27 per share (diluted), during the same period in 2008.


For the Three Months Ended June 30,	2009			2008			Change
(in Thousands)
Operating Income (Loss):
Natural Gas	$	4,648		$	5,626		$	(978	)
Propane		(561	)		(352	)		(209	)
Advanced Information Services		(240	)		202			(442	)
Other & Eliminations		(991	)		(1,147	)		156

Operating Income		2,856			4,329			(1,473	)

Other Income, Net of Other Expenses		12			64			(52	)
Interest Charges		1,573			1,389			184
Income Taxes		489			1,185			(696	)

Net Income	$	806		$	1,819		$	(1,013	)

The Company’s quarterly period-over-period operating results from three of its reportable segments reflects a slight decline in gross margin of $150,000 and an increase in other operating expenses of $1.3 million. The Company typically experiences a decline in earnings in the second quarter as a result of fluctuations in energy consumption by customers. The slowdown in the economy intensified the seasonal effects for natural gas distribution operations in the second quarter by lowering energy usage and causing a higher allowance for uncollectible accounts from the heating season. The Company’s advanced information services and propane wholesale marketing businesses, which typically offset the seasonal effects in the Company’s earnings, also contributed to the decline in the second quarter’s results as they were affected by adverse market conditions in their respective businesses.

- 25 -

The increase in other operating expenses included the effects of the following unfavorable variances that are not expected to recur in the second-half of 2009: $251,000 in increased costs related to collection and allowance for uncollectible customer accounts from the heating season, a one-time reduction in depreciation expense by $77,000 in the second quarter of 2008 related to the Delaware negotiated rate settlement that did not occur in 2009 and $185,000 in the true-up of certain corporate accrual estimates in the second quarter of 2009.

During 2009, the Company decided not to allocate merger-and-acquisition-related transaction costs to its natural gas, propane and advanced information services segments for the purpose of reporting their operating profitability because such costs are not directly attributable to their operations. Consequently, all of the $1.1 million in transaction costs for the three months ended June 30, 2009, was allocated to the “other and eliminations” segment. The Company also revised the 2008 segment information to reclassify the $1.2 million of costs related to an unconsummated transaction ($890,000, $273,000, and $64,000 were reclassified from natural gas, propane and advanced information services, respectively, to the “other and eliminations” segment).

Natural Gas

The natural gas segment reported operating income of $4.6 million for the second quarter of 2009, a decrease of $978,000, or 17 percent, compared to the second quarter of 2008.


For the Three Months Ended June 30,	2009		2008		Change
(in Thousands)
Revenue	$	30,404	$	53,878	$	(23,474	)
Cost of sales		14,964		38,945		(23,981	)

Gross margin		15,440		14,933		507

Operations & maintenance		7,612		6,525		1,087
Depreciation & amortization		1,820		1,655		165
Other taxes		1,360		1,127		233

Other operating expenses		10,792		9,307		1,485

Operating Income	$	4,648	$	5,626	$	(978	)


Statistical Data — Delmarva Peninsula
Heating degree-days (“HDD”):
Actual		470		481		(11	)
10-year average (normal)		494		490		4
Estimated gross margin per HDD	$	1,937	$	1,937		—

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		46,756		45,540		1,216
Florida		13,342		13,463		(121	)

Total		60,098		59,003		1,095

Operating income for the natural gas segment decreased by $978,000 as the increase of $507,000, or three percent, in gross margin was more than offset by increased other operating expenses of $1.5 million, or 16 percent, for the second quarter in 2009 compared to the same period in 2008.

Gross Margin

Gross margin increases of $509,000 for the natural gas transmission operation and $78,000 for the natural gas distribution operations were partially offset by decreased gross margin of $80,000 for the natural gas marketing operations.

- 26 -

The natural gas transmission operation achieved gross margin growth of $509,000 in the second quarter of 2009, an increase of nine percent over the same period in 2008, primarily due to the following new arrangements:

•

New long-term transportation capacity contracts implemented by ESNG in November 2008 provided for 5,650 Dts of additional firm transportation service per day, generating $247,000 of gross margin in the second 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 of 7,200 Dts per day. For the second quarter of 2009, this service provided $195,000 of additional 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 10,000 Dts per day and, although there was no impact from this contract in the second quarter of 2009, ESNG will recognize annual gross margin of approximately $1.1 million for this service in the future. For the years 2009 and 2010, these two agreements will contribute approximately $754,000 and $1.1 million, respectively, to gross margin.

•

ESNG began to bill the pre-certification costs surcharge in April 2009 in accordance with the terms of the Precedent Agreements and Letter Agreements following termination of the E3 Project. This surcharge billing contributed $129,000 in gross margin for the second quarter of 2009 and will contribute $387,000 of annualized gross margin in 2009 and $516,000 annually thereafter for a period of 20 years.

Although there was no impact in the second quarter of 2009, the natural gas transmission operation could be impacted by the following developments in its future results:

•

ESNG has commenced construction of the remaining facilities included in its multi-year system expansion project, which are expected to be placed into service in November 2009, and 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.

•

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

The natural gas distribution operations for the Delmarva Peninsula reported a net increase in gross margin of $209,000 for the second quarter of 2009, compared to the same period in 2008. In spite of the continued slowdown in the new housing market and industrial growth in the region, the Delmarva natural gas distribution operations experienced growth in residential, commercial, and industrial customers, which contributed $212,000 to the increased gross margin. The new rate structure in Delaware implemented in the third quarter of 2008 also contributed $209,000 to the increased gross margin. This 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. This change contributed $103,000 to the increase in gross margin. Although not representing additional revenue, also included in the new rate structure is the collection of miscellaneous service fees of $106,000, which had previously been offset against other operating expenses. The aforementioned increases to gross margin was sufficient to overcome the negative impact of warmer weather as temperatures on the Delmarva Peninsula were 11 heating degree days warmer and lower energy usage, due largely to general economic conditions, during the second quarter of 2009. These conditions reduced gross margin by $246,000 and $108,000, respectively.

The Florida natural gas distribution operation experienced a decrease in gross margin of $131,000 in the second quarter of 2009, due primarily to reduced customer consumption by residential and non-residential customers and loss of an industrial customer in October 2008, all attributable to adverse economic conditions in the region. The Florida division expects a further decline in gross margin of approximately $61,000 during the second half of 2009 from the loss of two other industrial customers which recently closed their facilities. On July 17, 2009, the Florida natural gas distribution operation filed with the Florida Public Service Commission a petition for a rate increase of approximately $3.0 million, which represents a 25-percent base rate increase on average for the Florida division’s customers.

- 27 -

The Company’s natural gas marketing operation experienced a decrease in gross margin of $80,000 for the second quarter 2009 due to a five-percent decrease in customer consumption and unfavorable imbalance resolutions with interstate pipelines.

Other Operating Expenses

An increase of $1.5 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, collectively, increased by approximately $388,000 as a result of the Company’s continued capital investments to support customer growth. The increased depreciation expense also reflects a $77,000 depreciation credit as a result of the Delaware negotiated rate settlement agreement in the second quarter of 2008.

•

Allowance for uncollectible accounts in the natural gas segment increased by $192,000 due to the growth in customers and the general economic climate.

•

Salaries and incentive compensation increased by $43,000, due primarily to compensation adjustments for non-executive employees that were effective January 1, 2009 associated with the compensation survey completed in the fourth quarter of 2008, partially offset by a decrease in incentive compensation as a result of lower operating results.

•

Other outside services increased by $127,000 primarily due to an increase in expenses related to pipeline integrity projects by ESNG and the Florida division to maintain compliance with various regulations.

•

Benefit costs increased by $45,000, due primarily to higher pension costs resulting from the decline in the value of pension assets in 2008 and other benefit costs relating to increased payroll costs.

•

Corporate costs allocated to the natural gas segment increased by $123,000 in the second quarter of 2009 compared to the same period in 2008 from the true-up of corporate accrual estimates in the second quarter of 2009.

•

Costs for corporate services increased by $177,000 primarily from increased information technology spending to improve the infrastructure and performance.

Propane

The propane segment experienced an increased operating loss of $209,000, or 59 percent, for the second quarter of 2009, compared to the same period in 2008.


For the Three Months Ended June 30,	2009			2008			Change
(in Thousands)
Revenue	$	8,200		$	11,489		$	(3,289	)
Cost of sales		4,369			7,535			(3,166	)

Gross margin		3,831			3,954			(123	)

Operations & maintenance		3,676			3,624			52
Depreciation & amortization		517			504			13
Other taxes		199			178			21

Other operating expenses		4,392			4,306			86

Operating Loss	$	(561	)	$	(352	)	$	(209	)


Statistical Data — Delmarva Peninsula
Heating degree-days (“HDD”):
Actual		470			481			(11	)
10-year average (normal)		494			490			4

Estimated gross margin per HDD	$	2,465		$	2,465			—

- 28 -

The propane segment experienced an increased operating loss, which resulted from a decrease of $123,000, or three percent, in gross margin, coupled with increased other operating expenses of $86,000.

Gross Margin

Gross margin increases of $139,000 for the Delmarva propane distribution operations and $89,000 for the Florida propane distribution operations were more than offset by lower gross margin of $351,000 for the propane wholesale and marketing operation.

The Delmarva propane distribution operation’s increase in gross margin of $139,000 resulted primarily from the increased margins of $215,000 on retail propane sales in 2009, offset partially by a reduction in miscellaneous revenues, such as service work, fuel surcharges and tank rentals, by $92,000. The Delmarva propane distribution operations experienced higher retail margins resulting from a sharp decline in propane costs in late 2008 and early 2009. This allowed the propane distribution operations to enjoy the lower cost of propane sales and maintain higher retail margins. The cost of propane sales was also lowered by propane inventory write-downs of approximately $800,000 during the second-half of 2008.

The Florida propane distribution operation also benefited from higher retail margins resulting from a sharp decline in propane costs in late 2008 and early 2009. This contributed to the $89,000 increase in gross margin in the second quarter of 2009.

The propane wholesale marketing operation experienced a large decrease in gross margin of $351,000 in the second quarter of 2009. This operation typically capitalizes on the price volatility in the wholesale propane market by selling at prices above cost and effectively managing the larger spreads between market (spot) prices and forward prices. Overall lack of volatility in wholesale propane prices during the second quarter of 2009, compared to the same period in 2008, reduced such revenue enhancement opportunities and decreased trading volumes by 34 percent.

Other Operating Expenses

Total other operating expenses for the propane segment increased by $86,000 for the quarter ended June 30, 2009, compared to the same period in 2008, due primarily to an increase of $14,000 in the benefit costs resulting from the significant decline in the value of pension plan assets during 2008, additional costs of approximately $59,000 to maintain propane tanks in compliance with United States Department of Transportation standards during the current period, and higher corporate overhead costs allocated to the propane segment of $104,000 resulting primarily from the true-up of corporate accrual estimates in the second quarter of 2009. These increases were offset by lower vehicle-related costs of $61,000 and reduced incentive compensation in the propane wholesale and marketing operation of $43,000.

Advanced Information Services

The advanced information services business experienced an operating loss of $240,000 for the quarter ended June 30, 2009, a decrease of $442,000 compared to an operating income of $202,000 that was achieved for the same period in 2008.


For the Three Months Ended June 30,	2009			2008		Change
(in Thousands)
Revenue	$	2,640		$	3,822	$	(1,182	)
Cost of sales		1,386			2,059		(673	)

Gross margin		1,254			1,763		(509	)

Operations & maintenance		1,301			1,362		(61	)
Depreciation & amortization		48			39		9
Other taxes		145			160		(15	)

Other operating expenses		1,494			1,561		(67	)

Operating Income (Loss)	$	(240	)	$	202	$	(442	)

- 29 -

The decrease in operating income is the result of lower gross margin of $509,000, or 29 percent, partially offset by lower other operating expenses of $67,000.

Gross Margin

The period-over-period decrease in gross margin is due to a decrease of $968,000 in consulting revenues, as the number of billable hours declined by 36 percent in the current quarter compared to the same period last year. The reduction in the number of billable hours is a result of current economic conditions in which information technology spending has broadly declined.

Other Operating Expenses

Other operating expenses decreased by $67,000 to $1.5 million in the second quarter of 2009, compared to $1.6 million for the same period in 2008. This decrease was attained from the layoffs and other cost containment actions and 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. In March of 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 $587,000 for the remainder of 2009.

Other and Eliminations

The other and eliminations segment, consisting primarily of subsidiaries that own real estate leased to other Company subsidiaries and costs relating to mergers or acquisitions, experienced an operating loss of approximately $991,000 for the second quarter of 2009, compared to an operating loss of $1.1 million for the same period in 2008. The operating losses experienced in the second quarter of 2009 and 2008 were primarily due to merger and acquisitions related-transaction costs.


For the Three Months Ended June 30,	2009			2008			Change
(in Thousands)
Revenue	$	(410	)	$	(132	)	$	(278	)
Cost of sales		(252	)		1			(253	)

Gross margin		(158	)		(133	)		(25	)

Operations & maintenance		(298	)		(265	)		(33	)
Transaction costs		1,090			1,240			(150	)
Depreciation & amortization		28			27			1
Other taxes		13			12			1

Other operating expenses		833			1,014			(181	)

Operating Loss	$	(991	)	$	(1,147	)	$	156


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

Interest Expense

Total interest expense for the second quarter of 2009 increased by approximately $184,000, or 13 percent, compared to the same period in 2008. The higher interest expense is attributable primarily to the following:

•

Interest on long-term debt increased by $323,000 in the second quarter of 2009, compared to the same period in 2008, as the Company increased its average long-term debt balance by $23.1 million. The Company’s weighted average interest rate decreased to 6.36 percent during the second quarter of 2009, compared to 6.61 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 $213,000 in the second quarter of 2009, compared to the same period in 2008, based upon a decrease of $31.8 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 second quarter of 2009 was $3.6 million, with a weighted average interest rate of 3.53 percent, compared to $35.3 million, with a weighted average interest rate of 2.74 percent, for the same period in 2008.

- 30 -

Income Taxes

Income tax expense for the second quarter of 2009 was $489,000, compared to $1.2 million for the second quarter of 2008. The decrease in income tax expense is primarily a function of lower earnings for the period. The effective income tax rate for the second quarter of 2009 is 37.8 percent, compared to an effective tax rate of 39.5 percent for the second quarter of 2008. The higher 2008 effective income tax rate is the result of additional income tax expense of $50,000 recorded during the period for uncertain tax positions, as defined in Financial Accounting Standards Board’s Financial Interpretation No. 48, Uncertain Tax Positions, related to an Internal Revenue Service audit of the Company’s 2005 and 2006 consolidated income tax returns, which was subsequently completed in September 2008.

Results of Operations for the Six Months Ended June 30, 2009

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

Consolidated Overview

The Company’s net income for the six months ended June 30, 2009, remained relatively unchanged as it increased by $6,000, compared to net income for the same period in 2008. The Company reported a net income of approximately $9.4 million and earnings per share of $1.36 (diluted) for the six months ended June 30, 2009 and 2008.


For the Six Months Ended June 30,	2009			2008			Change
(in Thousands)
Operating Income (Loss):
Natural Gas	$	15,251		$	16,095		$	( 844	)
Propane		4,925			3,092			1,833
Advanced Information Services		(345	)		239			(584	)
Other & eliminations		(1,009	)		(1,056	)		47

Operating Income		18,822			18,370			452

Other Income, Net of Other Expenses		45			81			(36	)
Interest Charges		3,215			2,982			233
Income Taxes		6,253			6,076			177

Net Income	$	9,399		$	9,393		$	6

The company’s period-over-period operating results reflects an increase of $3.8 million, or eight percent, in gross margin. Customer growth in the natural gas and propane distribution operations, along with new transportation service contracts placed into service by the natural gas transmission operation positively impacted gross margin in 2009. The propane distribution operation also achieved increased retail unit margins due to sustained retail prices, coupled with lower propane costs. Colder than normal temperatures on the Delmarva Peninsula and spot sales executed by the natural gas marketing operation also contributed to the gross margin increase. These positive achievements were able to offset the effects of general decline in customer consumption from energy conservation and adverse market conditions faced by the advanced information services and propane wholesale and marketing operations.

- 31 -

Other operating expenses increased by $3.4 million, which partially offset the gross margin increase. The increase primarily reflects the rising costs associated with supporting growth. Other operating expenses for the first six months of 2009 also reflects certain effects of the economic slowdown, including $518,000 increase in allowance for uncollectible accounts and $260,000 in higher pension costs. Also contributing to the increase was additional corporate overhead costs of $510,000, some of which was related to the $185,000 in the true-up of certain corporate accrual estimates in the second quarter of 2009. Also contributing to the increase was a one-time reduction in depreciation expense by $297,000 in the first half of 2008 related to the Delaware negotiated rate settlement that did not recur in 2009.

During 2009, the Company decided not to allocate merger-and-acquisition-related transaction costs to its natural gas, propane, and advanced information services segments for the purpose of reporting their operating profitability, because such costs are not directly attributable to their operations. Consequently, all of the $1.2 million in transaction costs for the six months ended June 30, 2009 was allocated to the “other and eliminations” segment. The Company also revised the 2008 segment information to reclassify the $1.2 million of costs related to an unconsummated transaction to the “other and eliminations” segment ($890,000, $273,000, and $64,000 were reclassified from natural gas, propane and advanced information services, respectively, to the “other and eliminations” segment).

Natural Gas

The natural gas segment reported operating income of $15.3 million for the first six months of 2009, compared to $16.1 million for the corresponding period in 2008, representing a decrease of $844,000, or five percent.


For the Six Months Ended June 30,	2009		2008		Change
(in Thousands)
Revenue	$	104,443	$	122,807	$	(18,364	)
Cost of sales		67,720		88,263		(20,543	)

Gross margin		36,723		34,544		2,179

Operations & maintenance		15,056		12,791		2,265
Depreciation & amortization		3,612		3,295		317
Other taxes		2,804		2,363		441

Other operating expenses		21,472		18,449		3,023

Total Operating Income	$	15,251	$	16,095	$	(844	)


Statistical Data — Delmarva Peninsula
Heating degree-days (“HDD”):
Actual		2,923		2,703		220
10-year average (normal)		2,800		2,760		40
Estimated gross margin per HDD	$	1,937	$	1,937		—

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		47,068		45,778		1,290
Florida		13,407		13,517		(110	)

Total		60,475		59,295		1,180

Operating income for the natural gas segment decreased $844,000 as the increase of $2.2 million, or six percent, in gross margin was more than offset by increased other operating expenses of $3.0 million, or 16 percent, for the first six months of 2009, compared to the same period in 2008.

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Gross Margin

Gross margin increased by $2.2 million for the natural gas segment for the first six months of 2009, which was derived from increases of $969,000 for the natural gas transmission operation, $377,000 for the natural gas distribution operations and $833,000 for the natural gas marketing operation.

The natural gas transmission operation achieved gross margin growth of $969,000, or eight percent, for the six months ended June 30, 2009, compared to the same period in 2008, due to the following new arrangements on the Delmarva Peninsula and in Florida:

•

New long-term transportation capacity contracts implemented by ESNG in November 2008 provided for 5,650 Dts of additional firm transportation service per day, generating $496,000 of gross margin for the six months ended June 30, 2009. These contracts are expected to generate approximately $988,000 of annualized gross margin in 2009.

•

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 7,200 Dts per day. For the six months ended June 30, 2009, this service provided $313,000 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 10,000 Dts per day. Although there was no impact from this contract during the six months ended June 30, 2009, these two agreements will contribute approximately $754,000 and $1.1 million, respectively, to gross margin in 2009 and 2010.

•

ESNG began to bill the pre-certification costs surcharge in April 2009 in accordance with the terms of the Precedent Agreements and Letter Agreements following the termination of the E3 Project. This surcharge billing contributed $129,000 in gross margin for the first six months of 2009 and will contribute $387,000 of gross margin in 2009 and $516,000 annually thereafter for a period of 20 years.

•

During January 2009, Peninsula Pipeline Company, Inc., the Company’s intra-state pipeline subsidiary in Florida, entered into its first contract to provide natural gas transportation services to a customer for a period of 20 years. For the first six months of 2009, this agreement contributed $132,000 to gross margin and is expected to contribute $264,000 in annualized gross margin.

Although there was no impact in the first six months of 2009, the natural gas transmission operation could be impacted by the following developments in its future results:

•

ESNG has commenced construction of the remaining facilities included in its multi-year system expansion project, which are expected to be placed into service in November 2009, and 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.

•

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

The natural gas distribution operations for the Delmarva Peninsula reported an increase in gross margin of $516,000 for the first six months of 2009, compared to the same period in 2008. In spite of the continued slowdown in the new housing market and industrial growth in the region, the Delmarva natural gas distribution operations experienced growth in residential, commercial, and industrial customers, which contributed $524,000 to the gross margin increase. The Delaware and Maryland divisions have experienced slower customer growth in 2009 and expect that trend to continue in the near future. The colder temperatures on the Delmarva Peninsula also contributed $210,000 to the increased gross margin. The aforementioned increases to gross margin overcame the negative impact of decreased interruptible sales revenues due to a reduction in the price of alternative fuels, making those more attractive fuel choices to industrial customers with interruptible services, and new rate structures that were implemented in the third quarter of 2008, which reduced gross margin by $185,000 and $105,000, respectively. This 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 of $295,000 in margin during the first six months of 2009, but will represent an increase in margin during non-heating periods. Although not representing additional revenue, also included in the new rate structure, is the collection of miscellaneous service fees of $187,000, which had previously been offset against other operating expenses.

- 33 -

The Florida natural gas distribution operation experienced a decrease in gross margin of $139,000 in the first six months of 2009, due primarily to reduced customer consumption in residential and non-residential customers and loss of an industrial customer in October 2008, all attributable to adverse economic conditions in the region. The Florida division expects a further decline in gross margin of approximately $61,000 during the second half of 2009 from the loss of two other industrial customers which have closed their facilities. Although there was no impact in the second quarter of 2009, the Florida natural gas distribution operation filed with the Florida Public Service Commission on July 17, 2009 a petition for a rate increase of approximately $3.0 million, which represents a 25-percent base rate increase on average for the Florida division’s customers.

The natural gas marketing operation experienced an increase in gross margin of $833,000 during the first six months of 2009, as it benefited from increased spot sales in 2009. Most of the gross margin increases from spot sales were generated from two industrial customers located on the Delmarva Peninsula. Such sales are opportunistic and unpredictable, and their future availability is highly dependent upon market conditions.

Other Operating Expenses

Other operating expenses for the natural gas segment increased by $3.0 million due primarily to the following factors:

•

Depreciation expense, asset removal costs and property taxes, collectively, increased by approximately $674,000 as a result of the Company’s continued capital investments to support customer growth. The increased depreciation expense also reflects a $297,000 depreciation credit as a result of the Delaware negotiated rate settlement agreement in the second quarter of 2008.

•

Allowance for uncollectible accounts in the natural gas segment increased by $513,000 due to the growth in customers and the general economic climate.

•

Salaries and bonuses increased by $196,000, primarily due to compensation adjustments for non-executive employees that were effective January 1, 2009 associated with the compensation survey completed in the fourth quarter of 2008 and annual salary increases, offset by a decrease in incentive compensation as a result of lower operating results.

•

ESNG incurred $101,000 related to the pipeline integrity projects in 2009 to maintain compliance with various regulations.

•

Benefit costs increased by $177,000, due primarily 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.

•

Corporate overhead costs allocated to the natural gas segment increased $123,000 in the first six months of 2009 compared to the same period in 2008 primarily from true-up of corporate accrual estimates in the second quarter of 2009.

•

Costs for corporate services increased by $270,000 primarily from increased information technology spending to improve the infrastructure and increased information technology support.

- 34 -

Propane

Operating income for the propane segment increased by $1.8 million, or 59 percent, to $4.9 million for the first six months of 2009 compared to $3.1 million for the corresponding period in 2008.


For the Six Months Ended June 30,	2009		2008		Change
(in Thousands)
Revenue	$	35,486	$	39,298	$	(3,812	)
Cost of sales		20,964		27,257		(6,293	)

Gross margin		14,522		12,041		2,481

Operations & maintenance		8,088		7,457		631
Depreciation & amortization		1,031		1,002		29
Other taxes		478		490		(12	)

Other operating expenses		9,597		8,949		648

Total Operating Income	$	4,925	$	3,092	$	1,833


Statistical Data — Delmarva Peninsula
Heating degree-days (“HDD”):
Actual		2,923		2,703		220
10-year average (normal)		2,800		2,760		40

Estimated gross margin per HDD	$	2,465	$	2,465		—

Operating income for the propane segment increased by $1.8 million as the increase of $2.5 million, or 21 percent, in gross margin more than offset the increased other operating expenses of $648,000, or seven percent, for the first six months of 2009, compared to the same period in 2008.

Gross Margin

The gross margin increase of $2.5 million for the propane segment in the first six months of 2009 was derived from increases of $2.8 million for the Delmarva propane distribution operations and $246,000 for the Florida propane distribution operations was partially offset by a lower gross margin of $567,000 for the propane wholesale and marketing operation.

The Delmarva propane distribution operations benefited from higher retail margins, customer growth and favorable weather on the Delmarva Peninsula in 2009. The gross margin increase of $2.8 million is attributable to the following:

•

A sharp decline in propane costs in late 2008 and early 2009 allowed the Delmarva propane distribution operations to experience relatively low propane inventory costs while maintaining higher retail margins. The cost of propane sales was also lowered by propane inventory write-downs of approximately $800,000 during the second-half of 2008. These factors contributed $1.4 million to the gross margin increase in 2009.

•

Non-weather-related volumes sold in the first six months of 2009 increased by 1.0 million gallons, or nine percent compared to the same period in 2008. This increase in gallons sold, which provided for an increase in gross margin of approximately $708,000, was primarily driven by the timing of propane deliveries to certain customers and the addition of approximately 208 Community Gas Systems customers, an increase of four percent. The Company expects the growth of its Community Gas Systems operation to continue, although at a slower pace, given the current economic climate.

•

Colder temperatures on the Delmarva Peninsula in the first six months of 2009 increased the volumes sold during the period by 766,000 gallons, or six percent, compared to the same period in 2008, as temperatures were eight percent colder during this period in 2009. The Company estimates that colder weather contributed an additional $557,000 of gross margin.

•

Wholesale volumes increased by 1.9 million gallons in the first six months of 2009, which resulted in a gross margin increase of $160,000 compared to the same period in 2008.

- 35 -

The Florida propane distribution operation also benefitted from higher retail margins resulting from a sharp decline in propane costs in late 2008 and early 2009, which contributed to the $246,000 increase in gross margin in the first six months of 2009.

The propane wholesale marketing operation experienced a decrease in gross margin of $567,000 in the first six months of 2009 compared to the same period in 2008. The propane wholesale marketing operation typically capitalizes on price volatility by selling at prices above cost and effectively managing the larger spreads between the market (spot) prices and forward prices. Overall lack of volatility in wholesale propane prices during the first six months of 2009 compared to the same period in 2008, reduced such revenue opportunities.

Other Operating Expenses

Total other operating expenses increased by $648,000 for the propane segment for the six months ended June 30, 2009, compared to the same period in 2008, due primarily to higher payroll costs of $431,000 resulting from an increased accrual for incentive compensation, increased costs to maintain propane tanks in compliance with United States Department of Transportation standards of $97,000, higher benefit costs of $34,000 as a result of the significant decline in the value of pension plan assets and higher corporate overhead costs allocated to the segment of $118,000 primarily from the true-up of corporate accrual estimates in the second quarter of 2009. These increases were partially offset by lower vehicle-related expenses of $82,000.

Advanced Information Services

The advanced information services business experienced an operating loss of $345,000 for the six months ended June 30, 2009, a decrease of $584,000, compared to an operating income of $239,000 that was achieved during the same period in 2008.


For the Six Months Ended June 30,	2009			2008		Change
(in Thousands)
Revenue	$	5,945		$	7,473	$	(1,528	)
Cost of sales		3,257			4,001		(744	)

Gross margin		2,688			3,472		(784	)

Operations & maintenance		2,597			2,767		(170	)
Depreciation & amortization		98			76		22
Other taxes		338			390		(52	)

Other operating expenses		3,033			3,233		(200	)

Total Operating Income (Loss)	$	(345	)	$	239	$	(584	)

The change from operating income to operating loss is the result of lower gross margin of $784,000, or 23 percent, partially offset by lower other operating expenses of $200,000.

Gross Margin

The period-over-period decrease in gross margin is due to a decrease of $1.5 million in consulting revenues as the number of billable hours declined by 31 percent for the six months ended June 30, 2009, compared to the same period in 2008. The reduction in the number of billable hours is a result of current economic conditions in which information technology spending has broadly declined.

Other Operating Expenses

Other operating expenses decreased by $200,000 to $3.0 million in the first six months of 2009 compared to $3.2 million for the same period in 2008. This decrease was attained from layoffs and other cost containment actions and 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. In the first quarter of 2009, the Company instituted layoffs and other cost-containment actions that are estimated to offset the decline in revenues and are expected to reduce costs by $587,000 for the remainder of 2009.

- 36 -

Other and Eliminations

The other and eliminations segment, consisting primarily of subsidiaries that own real estate leased to other Company subsidiaries and costs relating to mergers and/or acquisitions, experienced an operating loss of approximately $1.0 for the first six months of 2009, compared to an operating loss of approximately $1.1 million for the same period in 2008. The operating losses experienced in the first six months of 2009 and 2008 were primarily due to merger and acquisition-related transaction costs.


For the Six Months Ended June 30,	2009			2008			Change
(in Thousands)
Revenue	$	(561	)	$	(248	)	$	(313	)
Cost of sales		(252	)		(2	)		(250	)

Gross margin		(309	)		(246	)		(63	)

Operations & maintenance		(589	)		(514	)		(75	)
Transaction costs		1,204			1,240			(36	)
Depreciation & amortization		56			55			1
Other taxes		29			29			—

Other operating expenses		700			810			(110	)

Total Operating Loss	$	(1,009	)	$	(1,056	)	$	47


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

Interest Expense

Total interest expense for the first six months of 2009 increased by approximately $233,000, or eight percent, compared to the same period in 2008. The higher interest expense is primarily attributable to the following:

•

Interest on long-term debt increased by $640,000 in the first six months 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 six months of 2009, compared to 6.63 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 $475,000 in the first six months of 2009, compared to the same period in 2008, based upon a decrease of $22.9 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 six months of 2009 was $12.8 million, with a weighted average interest rate of 1.74 percent, compared to $35.6 million, with a weighted average interest rate of 3.26 percent, for the same period in 2008.

Income Taxes

Income tax expense for the first six months of 2009 was $6.3 million, compared to $6.1 million for the same period in 2008. The effective income tax rate for the first six months of 2009 is 40.0 percent, compared to an effective tax rate of 39.3 percent for the first six months of 2008. The increased tax expense and effective income tax rate are the result of a greater portion of the Company’s pre-tax income being generated from entities in states with higher income tax rates.

Financial Position, Liquidity and Capital Resources

Chesapeake’s capital requirements reflect the capital-intensive nature of its business and are principally attributable to its investments 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 six months of 2009, net cash provided by operating activities was $46.8 million, cash used by investing activities was $12.0 million, and cash used by financing activities was $34.8 million. By comparison, during the first six months of 2008, net cash provided by operating activities was $9.6 million, cash used by investing activities was $15.6 million, and cash provided by financing activities was $6.6 million.

- 37 -

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 June 30, 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 June 30, 2009 and December 31, 2008, was $2.0 million and $33.0 million, respectively. The large decrease in the Company’s outstanding balance of short-term borrowing during the first six months of 2009 is primarily due to a larger increase in net cash provided by operating activities and seasonal factors.

Chesapeake 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 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. As a result of the continued slowdown in the new housing market and industrial growth, the Company reduced its 2009 capital spending projections by $3.4 million primarily for amounts budgeted for the natural gas segment. At June 30, 2009, the Company had invested $11.9 million of the revised capital budget. The Company expects to fund the remaining 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 June 30, 2009 and December 31, 2008:


	June 30,				December 31,
	2009				2008
	(in thousands, except percentages)
Long-term debt, net of current maturities	$	86,313	40	%	$	86,422	41	%
Stockholders’ equity		130,027	60	%		123,073	59	%

Total capitalization, excluding short-term debt	$	216,340	100	%	$	209,495	100	%

As of June 30, 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 58 percent at June 30, 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 June 30, 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 Six Months Ended June 30,	2009		2008			Change
(in thousands)
Net income	$	9,399	$	9,393		$	6
Non-cash adjustments to net income		11,466		7,797			3,669
Changes in assets and liabilities		25,956		(7,548	)		33,504

Net cash provided by operating activities	$	46,821	$	9,642		$	37,179

Period-over-period changes in the Company’s 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 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, payments of income taxes and deferred gas cost recoveries.

For the first six months of 2009, net cash flow provided by operating activities was $46.8 million, an increase of $37.2 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 natural gas and propane distribution operations coupled with lower commodity prices. 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.

•

The net cash flows provided by natural gas and propane inventories were the result of lower commodity prices and the seasonality of sales to customers.

•

Net cash flows generated by income tax receivables were primarily due to the receipt of the Company’s refund of federal income taxes for the year ended December 31, 2008, and increased book-to-tax timing differences associated with depreciation which are lowering the Company’s current taxes payable.

•

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

•

Non-cash adjustments reflected unrealized losses on commodity contracts, as there were fewer opportunities in the propane wholesale trading market during the first six months of the year.

•

The net cash flows used by non-cash adjustments for deferred income taxes are 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 $12.0 million and $15.6 million during the six months ended June 30, 2009 and 2008, respectively. Cash utilized for capital expenditures was $12.0 million and $15.4 million for the first six months of 2009 and 2008, respectively. Additions to property, plant and equipment in the first six months of 2009 were primarily for the natural gas segment ($10.5 million), the propane segment ($943,000), the advanced information services segment ($262,000), and the other operations segment ($273,000).

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Cash Flows Used by Financing Activities

Cash flows used by financing activities totaled $34.8 million for the first six months of 2009, compared to cash provided of $6.6 million for the same period in 2008. Significant financing activities included the following:

•

During the first six months of 2009, the Company had a net repayment of short-term debt of $31.0 million, compared to net borrowings of $11.5 million in the first six months of 2008, as it generated higher amounts of cash from operating activities.

•

During the first six months of 2009, the Company paid $3.9 million in cash dividends, compared with dividend payments of $3.8 million for the same time period in 2008. The increase in dividends paid in the first six 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 six months of 2009, compared to $1.0 million in the first six 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 and marketing subsidiary, Xeron, and its natural gas supply management subsidiary, PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of either subsidiary’s default. Neither subsidiary 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 June 30, 2009, was $22.4 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, 2010. 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 June 30, 2009, and the Company does not anticipate that this letter of credit will be drawn upon by the counterparty in the future.

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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. The following table summarizes the commodity and forward contract obligations at June 30, 2009.


(in Thousands)	Payments Due by Period
Purchase Obligations	Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years		Total
Commodities ^{(1) (3)}	$	16,830	$	58		—		—	$	16,888
Propane ⁽²⁾		13,844		—		—		—		13,844

Total Purchase Obligations	$	30,674	$	58		—		—	$	30,732


⁽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 $14.9 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 in the Company’s 2008 Annual Report on Form 10-K.

⁽⁴⁾		The Company expects to contribute $450 to the defined benefit pension plan during the fourth quarter of 2009. The above table does not reflect this payment, because it is a voluntary contribution to the defined benefit pension plan.

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 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 PSCs. ESNG is subject to regulation by the FERC. At June 30, 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 natural 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.

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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 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.

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.

Recent Authoritative Pronouncements on Financial Reporting and Accounting

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

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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 June 30, 2009, compared to a fair value of $91.7 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.

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 June 30, 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 June 30, 2009, is presented in the following table.


	Quantity in		Estimated Market		Weight Average
At June 30, 2009	Gallons		Prices		Contract Prices
Forward Contracts:
Sale		18,270,000	$	0.6625 - $0.9800	$	0.8130
Purchase		17,346,000	$	0.6488 - $0.9300	$	0.7981

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

All contracts expire in 2009 or in the first quarter of 2010.

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At June 30, 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:


	June 30,		December 31,
(in thousands)	2009		2008
Mark-to-market energy assets	$	944	$	4,482
Mark-to-market energy liabilities	$	650	$	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 June 30, 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 June 30, 2009.

Changes in Internal Control Over Financial Reporting

During the quarter ended June 30, 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.

The Company and its wholly-owned subsidiary, CPK Pelican, Inc., a Florida corporation formed for the purpose of engaging in the merger with FPU, are defendants in a putative class action lawsuit purportedly on behalf of FPU shareholders to challenge the merger with FPU. The suit was filed in the Circuit Court of the Fifteenth Judicial Circuit in and for Palm Beach County, Florida on May 8, 2009. Other named defendants in the suit are FPU, FPU’s Chief Executive Officer, and each member of FPU’s Board of Directors.

The complaint filed in the suit alleges that in pursuing the merger FPU’s Chief Executive Officer and members of FPU’s Board of Directors have breached their fiduciary duties of loyalty, due care, independence, candor, good faith and fair dealing by failing to maximize value to FPU’s shareholders in the merger and by attempting to provide certain FPU insiders and directors with preferential treatment in connection with their efforts to complete the sale of FPU to Chesapeake through CPK. The complaint further alleges that FPU, Chesapeake and CPK have aided and abetted such breaches. The complaint seeks equitable remedies only, primarily being an injunction against the defendants consummating the merger.

Item 1A. Risk Factors

There have not been any material changes in the risk factors 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)
April 1, 2009 through April 30, 2009 ⁽¹⁾		649	$	29.52		—		—
May 1, 2009 through May 31, 2009		—	$	—		—		—
June 1, 2009 through June 30, 2009		—	$	—		—		—

Total		649	$	29.52		—		—


⁽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, 649 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.

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Item 3. Defaults upon Senior Securities

None.

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

The Annual Meeting of the Stockholders of Chesapeake Utilities Corporation was held on May 6, 2009. The items set forth below were submitted to a vote of security holders. Proxies for the meeting were solicited in accordance with Regulation 14A under the Securities Exchange Act of 1934, as amended.

The stockholders elected one nominee to the Company’s Board of Directors to serve as a Class III director for a two-year term ending in 2011 and until her successor is elected and qualified, and three nominees to serve as Class I directors for three-year terms ending in 2012 and until their successors are elected and qualify. The following shows the separate tabulation of votes for each nominee:


Class	Name	Votes For		Votes Withheld
III	Dianna F. Morgan		6,242,146		179,025
I	Calvert A. Morgan, Jr.		5,142,194		1,278,977
I	Eugene H. Bayard		4,795,000		1,626,171
I	Thomas P. Hill, Jr.		5,164,479		1,256,692

The terms of the following directors were not subject to vote (or election), and they remained in office after the meeting:


Class II Directors (Terms Expire in 2010)		Class III Directors (Terms Expire in 2010)
Ralph J. Adkins		Thomas J. Bresnan
Richard Bernstein		Joseph E. Moore
J. Peter Martin		John R. Schimkaitis

The stockholders approved the ratification of the appointment of Beard Miller Company LLP as the Company’s independent registered public accounting firm for the fiscal year ending December 31, 2009. There were 6,327,462 affirmative votes, 69,490 negative votes, and 24,219 abstentions. There were no broker non-votes for this matter.

As of the Record Date, March 13, 2009, 6,839,829 shares of common stock of the Company, the only outstanding class of voting or equity securities of the Company, were outstanding.

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 August 7, 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 August 7, 2009.

	32.1			Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated August 7, 2009.

	32.2			Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated August 7, 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: August 7, 2009

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EXHIBIT INDEX


Exhibit Number		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 August 7, 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 August 7, 2009.

	32.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated August 7, 2009.

	32.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated August 7, 2009.

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