CHESAPEAKE UTILITIES CORP - FORM 10-Q

Attached files

file	filename
EX-31.2 - EXHIBIT 31.2 - CHESAPEAKE UTILITIES CORP	c91883exv31w2.htm
EX-32.2 - EXHIBIT 32.2 - CHESAPEAKE UTILITIES CORP	c91883exv32w2.htm
EX-31.1 - EXHIBIT 31.1 - CHESAPEAKE UTILITIES CORP	c91883exv31w1.htm
EX-32.1 - EXHIBIT 32.1 - CHESAPEAKE UTILITIES CORP	c91883exv32w1.htm

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: September 30, 2009


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

For the transition period from to

Commission File Number: 001-11590

Chesapeake Utilities Corporation

(Exact name of registrant as specified in its charter)


Delaware		51-0064146

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

909 Silver Lake Boulevard, Dover, Delaware 19904
(Address of principal executive offices, including Zip Code)

(302) 734-6799
(Registrant’s telephone number, including area code)

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

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

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


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

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

Common Stock, par value $0.4867 — 6,900,124⁽¹⁾ shares outstanding as of October 31, 2009.


⁽¹⁾		The number of shares outstanding does not include shares issuable for the merger with Florida Public Utilities Company, which became effective on October 28, 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			44

Item 4. Controls and Procedures			45

PART II — OTHER INFORMATION			46

Item 1. Legal Proceedings			46

Item 1A. Risk Factors			46

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			46

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


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
ASC		FASB Accounting Standards Codification^TM(Codification)
ASU		FASB Accounting Standards Update
CGS		Community Gas Systems
DSCP		Directors Stock Compensation Plan
Dts		Dekatherms
E3 Project		ESNG Energylink Expansion Project
Florida PSC		Florida Public Service Commission
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

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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 September 30,	2009			2008

Operating Revenues	$	31,758		$	49,698
Operating Expenses
Cost of sales, excluding costs below		14,416			33,651
Operations		11,001			10,341
Transaction-related costs		(675	)		—
Maintenance		600			656
Depreciation and amortization		2,437			2,267
Other taxes		1,722			1,613

Total operating expenses		29,501			48,528

Operating Income		2,257			1,170
Other loss, net of other income		(26	)		(91	)
Interest charges		1,540			1,488

Income (Loss) Before Income Taxes		691			(409	)
Income tax expense (benefits)		383			(211	)

Net Income (Loss)	$	308		$	(198	)


Weighted-Average Common Shares Outstanding:
Basic		6,883,070			6,815,886
Diluted		6,888,024			6,815,886

Earnings (Loss) Per Share of Common Stock:
Basic	$	0.04		$	(0.03	)
Diluted	$	0.04		$	(0.03	)

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 Nine Months Ended September 30,	2009		2008

Operating Revenues	$	177,071	$	219,028
Operating Expenses
Cost of sales, excluding costs below		106,105		153,170
Operations		34,820		31,853
Transaction-related costs		530		1,240
Maintenance		1,932		1,644
Depreciation and amortization		7,235		6,695
Other taxes		5,371		4,885

Total operating expenses		155,993		199,487

Operating Income		21,078		19,541
Other income (loss), net of other expenses		19		(11	)
Interest charges		4,755		4,470

Income Before Income Taxes		16,342		15,060
Income taxes		6,636		5,865

Net Income	$	9,706	$	9,195


Weighted Average Common Shares Outstanding:
Basic		6,859,516		6,807,919
Diluted		6,981,010		6,922,105

Earnings Per Share of Common Stock:
Basic	$	1.41	$	1.35
Diluted	$	1.40	$	1.34

Cash Dividends Declared Per Share of Common Stock	$	0.935	$	0.905

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 Nine Months Ended September 30,	2009			2008

*Operating Activities*
Net Income	$	9,706		$	9,195
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		7,235			6,695
Depreciation and accretion included in other costs		1,987			1,636
Deferred income taxes, net		5,575			6,102
Unrealized loss on commodity contracts		1,382			33
Unrealized loss (gain) on investments		(161	)		227
Employee benefits		1,396			114
Share-based compensation		897			621
Changes in assets and liabilities:
Accounts receivable and accrued revenue		25,513			18,551
Propane inventory, storage gas and other inventory		2,071			(7,270	)
Regulatory assets		(1,182	)		223
Prepaid expenses and other current assets		480			(8,200	)
Other deferred charges		70			(371	)
Accounts payable and other accrued liabilities		(13,409	)		(6,989	)
Income taxes receivable		3,543			(3,237	)
Accrued interest		1,160			842
Customer deposits and refunds		(1,027	)		(1,236	)
Accrued compensation		(280	)		(685	)
Regulatory liabilities		2,179			(2,842	)
Other liabilities		317			15

Net cash provided by operating activities		47,452			13,424


*Investing Activities*
Property, plant and equipment expenditures		(19,674	)		(23,724	)
Environmental expenditures		(33	)		(403	)

Net cash used by investing activities		(19,707	)		(24,127	)


*Financing Activities*
Common stock dividends		(5,878	)		(5,878	)
Issuance of stock for Dividend Reinvestment Plan		186			15
Change in cash overdrafts due to outstanding checks		471			1,419
Net borrowing (repayment) under line of credit agreements		(23,387	)		16,193
Repayment of long-term debt		(20	)		(1,020	)

Net cash provided (used) by financing activities		(28,628	)		10,729


Net Increase (Decrease) in Cash and Cash Equivalents		(883	)		26
Cash and Cash Equivalents — Beginning of Period		1,611			2,593

Cash and Cash Equivalents — End of Period	$	728		$	2,619

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)


	September 30,			December 31,
Assets	2009			2008

Property, Plant and Equipment
Natural gas	$	322,527		$	316,125
Propane		52,588			51,827
Advanced information services		1,434			1,439
Other plant		10,911			10,816

Total property, plant and equipment		387,460			380,207
Less: Accumulated depreciation and amortization		(104,822	)		(101,018	)
Plus: Construction work in progress		8,889			1,482

Net property, plant and equipment		291,527			280,671


Investments		1,834			1,601


Current Assets
Cash and cash equivalents		728			1,611
Accounts receivable (less allowance for uncollectible accounts of $1,246 and $1,159, respectively)		30,757			52,905
Accrued revenue		1,803			5,168
Propane inventory, at average cost		5,355			5,711
Other inventory, at average cost		1,542			1,479
Regulatory assets		671			826
Storage gas prepayments		7,713			9,492
Income taxes receivable		677			7,443
Deferred income taxes		2,591			1,578
Prepaid expenses		4,250			4,679
Mark-to-market energy assets		1,532			4,482
Other current assets		148			147

Total current assets		57,767			95,521


Deferred Charges and Other Assets
Goodwill		674			674
Other intangible assets, net		154			164
Long-term receivables		390			533
Regulatory assets		4,090			2,806
Other deferred charges		3,798			3,825

Total deferred charges and other assets		9,106			8,002


Total Assets	$	360,234		$	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)


	September 30,			December 31,
Capitalization and Liabilities	2009			2008

Capitalization
Stockholders’ equity
Common stock, par value $0.4867 per share (authorized 12,000,000 shares)	$	3,352		$	3,323
Additional paid-in capital		69,138			66,681
Retained earnings		60,043			56,817
Accumulated other comprehensive loss		(3,526	)		(3,748	)
Deferred compensation obligation		1,333			1,549
Treasury stock		(1,333	)		(1,549	)

Total stockholders’ equity		129,007			123,073

Long-term debt, net of current maturities		86,282			86,422

Total capitalization		215,289			209,495


Current Liabilities
Current portion of long-term debt		6,656			6,656
Short-term borrowing		10,084			33,000
Accounts payable		26,355			40,202
Customer deposits and refunds		8,508			9,534
Accrued interest		2,184			1,024
Dividends payable		2,170			2,082
Accrued compensation		3,087			3,305
Regulatory liabilities		5,451			3,227
Mark-to-market energy liabilities		1,484			3,052
Other accrued liabilities		3,125			2,970

Total current liabilities		69,104			105,052


Deferred Credits and Other Liabilities
Deferred income taxes		41,234			37,720
Deferred investment tax credits		204			235
Regulatory liabilities		831			875
Environmental liabilities		425			511
Other pension and benefit costs		7,585			7,335
Accrued asset removal cost		21,317			20,641
Other liabilities		4,245			3,931

Total deferred credits and other liabilities		75,841			71,248


Total Capitalization and Liabilities	$	360,234		$	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 Other
	Number of					Additional Paid-In					Comprehensive			Deferred
	Shares			Par Value		Capital		Retained Earnings			Loss			Compensation			Treasury 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									9,706												9,706
Other comprehensive income, net of tax:
Employee Benefit Plans, net of tax:
Amortization of prior service costs ⁽⁴⁾												4									4
Net Gain ⁽⁵⁾												218									218


Total comprehensive income																					9,928


Dividend Reinvestment Plan		21,745			11		636														647
Retirement Savings Plan		25,521			12		755														767
Conversion of debentures		7,047			3		116														119
Share based compensation ^{(1) (3)}		6,700			3		950														953
Deferred Compensation Plan ⁽⁶⁾															(216	)		216			—
Purchase of treasury stock		(1,824	)															(56	)		(56	)
Sale and distribution of treasury stock		1,824																56			56
Dividends on stock-based compensation									(62	)											(62	)
Cash dividends ⁽²⁾									(6,418	)											(6,418	)

Balances at September 30, 2009		6,888,134		$	3,352	$	69,138	$	60,043		$	(3,526	)	$	1,333		$	(1,333	)	$	129,007


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

⁽²⁾		Cash dividends per share for the periods ended September 30, 2009 and December 31, 2008 were $0.935 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 September 30, 2009 and December 31, 2008 were approximately $3 and ($52), respectively.

⁽⁵⁾		Tax expense (benefit) recognized on the net gain (loss) component of employees benefit plans for the periods ended September 30, 2009 and December 31, 2008 were $146 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.

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Notes to Condensed Consolidated Financial Statements

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 nine months ended September 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.

The Company has assessed and reported on subsequent events through November 6, 2009, the date of issuance of these condensed consolidated financial statements.

Beginning in this third quarter 2009 Form 10-Q, the Company adopted the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification^TM (“Codification”), which is now the single source of authoritative accounting principles recognized by the FASB. The adoption of the Codification did not have a material impact on the Company’s financial position and results of operations. As a result of this adoption, the Company updated all references to accounting and reporting standards included in this Form 10-Q and in some instances provided references to both pre-and post-Codification standards, as appropriate.

Recent Accounting Amendments Yet to be Adopted by the Company

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

In December 2008, the FASB issued FASB Staff Position (“FSP”) on Statement of Financial Accounting Standard (“SFAS”) 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” This FSP is codified within FASB Accounting Standards Codification^TM (“ASC”) Section 715-20-65, of the Topic, “Compensation — Retirement Benefits.” It 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. The Company will comply with the required disclosures, which are effective for the fiscal years ending after December 15, 2009.

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Other Accounting Amendments Adopted by the Company During the First Nine Months of 2009:

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”). SFAS No. 161 was codified within FASB ASC Sections 815-10-15 and 65, of the Topic, “Derivatives and Hedging,” and it 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 the Derivatives and Hedging Topic, and (iii) how derivative instruments and related hedged items affect a company’s financial position, financial performance and cash flows. Disclosures required by this standard were adopted by the Company, effective January 1, 2009. Adoption of this standard did not have an impact on the Company’s condensed consolidated financial position and results of operations. These disclosures are discussed in Note 9, “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,” which is codified within FASB ASC Sections 350-30-50, 55 and 65 of the Topic, “Intangibles — Goodwill and Other,” and FASB ASC Section 275-10-50, of the Topic, “Risks and Uncertainties.” It amended factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset. The intent of these provisions is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value of the asset. This standard was adopted by the Company, effective January 1, 2009. Adoption of this standard did not have an impact on the Company’s condensed consolidated financial position and results of operations.

In May 2008, the FASB issued FSP APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement),” FSP APB 14-1 was codified within: (i) FASB ASC Sections 470-20-10, 15, 25, 30, 35, 40, 45, 50, 55 and 65 of the Topic, “Debt,” (ii) FASB ASC Section 815-15-55, of the Topic, “Derivatives and Hedging,” (iii) FASB ASC Section 825-10-15, of the Topic, “Financial Instruments.” It 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 standard 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 September 2008, the FASB issued FSP Emerging Issues Task Force 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” This FSP, codified within FASB ASC Sections 260-10-45, 55 and 65, of the Topic, “Earnings Per Share,” clarifies that holders of outstanding unvested share-based payment awards containing rights to nonforfeitable dividends participate with common shareholders in undistributed earnings. 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 standard 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 April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” This FSP, codified within FASB ASC Section 825-10-65, of the Topic, “Financial Instruments,” enhances consistency in financial reporting by increasing the frequency of fair value disclosures. The provisions of this standard are effective for interim and annual reporting periods ending after June 15, 2009, and they did not have an impact on the Company’s condensed consolidated financial position and results of operations. The disclosures required by this standard are discussed in Note 10, “Fair Value of Financial Instruments,” to the condensed consolidated financial statements.

In May 2009, the FASB issued SFAS No. 165, “Subsequent Events,” which the Company adopted in the second quarter of 2009. The provisions of this standard, now residing in FASB ASC Sections 855-10-05, 15, 25, 45, 50 and 55, of the Topic, “Subsequent Events,” establish 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. The adoption of this standard did not have an impact on the Company’s condensed consolidated financial position and results of operations.

- 8 -

In August 2009, the FASB issued FASB Accounting Standards Update (“ASU”) No. 2009-05, “Fair Value Measurement and Disclosures — Measuring Liabilities at Fair Value.” The ASU provides clarification that in circumstances in which a quoted price in an active market for an identical liability is not available, a reporting entity is required to measure fair value, using: (i) a valuation technique that uses the quoted price of the identical liability when traded as an asset or quoted prices for similar liabilities when traded as assets; or (ii) another valuation technique that is consistent with the principles of the Topic, “Fair Value Measurements and Disclosures.” This ASU, adopted by the Company in the third quarter of 2009, did not have an impact on the Company’s condensed consolidated financial position and results of operations.

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. On October 22, 2009, shareholders of both Chesapeake and FPU approved the merger, which became effective on October 28, 2009 and each outstanding share of FPU common stock was converted into a 0.405 share of Chesapeake’s common stock. At closing, FPU had 6,140,592 common shares outstanding, and Chesapeake’s common stock was valued at $30.42 per share, which resulted in total consideration of approximately $75.7 million paid by Chesapeake. The total consideration is based upon the closing price of Chesapeake’s common stock on October 27, 2009, the last trading day prior to the effective date of the merger. Immediately after the merger, Chesapeake’s stockholders owned approximately 73.5 percent of the combined company, and FPU’s stockholders owned approximately 26.5 percent of the combined company.

On September 29, 2009, a putative class action lawsuit, which had been filed on May 8, 2009 in Palm Beach County, Florida, challenging the merger, purportedly on behalf of the shareholders of FPU, against FPU, each member of FPU’s board of directors and Chesapeake, was dismissed without prejudice.

The merger is intended to qualify as a reorganization, within the meaning of Section 368(a) of the Internal Revenue Code of 1986, as amended, and is accounted for under the acquisition method of accounting under GAAP, with Chesapeake being treated as the acquirer. Under this method, the assets acquired and liabilities assumed are recorded at their respective fair values and added to those of Chesapeake. Chesapeake is in the process of finalizing its evaluation of the tangible and intangible assets acquired and liabilities assumed, as well as the initial purchase price allocation as of the acquisition date, including the determination of any resulting goodwill. Therefore, this information cannot be provided at this time.

In connection with the merger, Chesapeake has incurred $1.9 million in transaction-related costs during the nine months ended September 30, 2009. Chesapeake has begun the process of seeking regulatory approval to defer a portion of these costs related to regulated operations for future rate recovery. Based on precedents established by the Florida Public Service Commission (“Florida PSC”) in previous business combinations involving natural gas utilities in Florida, the Company determined that future rate recovery of the acquisition-related transaction costs for regulated operations is probable and deferred $1.4 million of the transaction-related costs as a regulatory asset as of September 30, 2009. This regulatory asset of $1.4 million includes deferrals of $89,000 and $850,000 incurred during the first and second quarters of 2009, respectively, that were previously accounted for as expenses. The reversal of these amounts is presented as a credit to transaction-related costs in the accompanying condensed and consolidated statement of income for the three months ended September 30, 2009. Transaction-related costs not subject to future rate recovery ($265,000 and $530,000 for the three and nine months ended September 30, 2009, respectively), are also included in transaction-related costs in the accompanying condensed and consolidated statements of income. Future regulatory developments may require Chesapeake to re-assess the probability of future rate recovery with regard to the costs deferred as a regulatory asset.

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Calculation of Earnings Per Share


For the Periods Ended September 30,	Three Months					Nine Months
*(in Thousands, except Shares and Per Share Data)*	2009		2008			2009		2008
Calculation of Basic Earnings Per Share:
Net Income (Loss)	$	308	$	(198	)	$	9,706	$	9,195
Weighted average shares outstanding		6,883,070		6,815,886			6,859,516		6,807,919

Basic Earnings (Loss) Per Share	$	0.04	$	(0.03	)	$	1.41	$	1.35


Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income (Loss)	$	308	$	(198	)	$	9,706	$	9,195
Effect of 8.25% Convertible debentures (1)		—		—			60		67

Adjusted numerator — Diluted	$	308	$	(198	)	$	9,766	$	9,262


Reconciliation of Denominator:
Weighted shares outstanding — Basic		6,883,070		6,815,886			6,859,516		6,807,919
Effect of dilutive securities: (1)
Share-based Compensation		4,954		—			27,838		9,099
8.25% Convertible debentures		—		—			93,656		105,087

Adjusted denominator — Diluted		6,888,024		6,815,886			6,981,010		6,922,105


Diluted Earnings (Loss) Per Share	$	0.04	$	(0.03	)	$	1.40	$	1.34

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”).

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 significant 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, commencing in November 2009, will adjust the margin-sharing mechanism related to its Asset Management Agreement to reduce its proportionate share of such margin. 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. An unfavorable outcome of this later proceeding may affect PESCO’s spot-sale opportunities and profitability on the Delmarva Peninsula in the future.

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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 recover from natural gas customers located within the Town of Milford or the City of Seaford a proportionate share of the franchise fees paid by the division. The Delaware PSC granted approval of both Franchise Fee Riders on January 29, 2009.

On September 4, 2009, the Company’s Delaware division filed with the Delaware PSC its annual GSR Application, seeking approval to change its GSR, effective November 1, 2009. On October 6, 2009, the Delaware PSC authorized the Delaware division to implement the GSR charges on November 1, 2009, on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. The Delaware division anticipates a final decision by the Delaware PSC on this application in the second quarter of 2010.

Maryland. On December 16, 2008, the Maryland Public Service Commission (“Maryland PSC”) held an evidentiary hearing to determine the reasonableness of the four quarterly gas cost recovery filings submitted by the Company’s Maryland division 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 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 utilities’ payment plan parameters and termination procedures 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.

Florida. On July 14, 2009, the Company’s Florida division filed with the Florida PSC its petition for a rate increase and request for interim rate relief. In the application, the Florida division 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, excluding fuel costs, of approximately twenty-five percent for the Florida division’s customers; (c) implementation or modification of certain surcharge mechanisms; (d) restructuring of certain rate classifications; and (e) deferral of certain costs and the purchase premium associated with the pending merger with FPU. On August 18, 2009, the Florida PSC approved the full amount of the Florida division’s interim rate request, subject to refund, applicable to all meters read on or after September 1, 2009. A final decision on the permanent rate increase is expected during the fourth quarter of 2009, as the docket is tentatively scheduled on December 15, 2009 agenda for the Florida PSC.

On September 11, 2009, the Florida division filed its annual Energy Conservation Cost Recovery Clause, which seeks final approval of the division’s 2008 conservation-related revenues and expenses and new conservation surcharge rates for 2010. A final decision by the Florida PSC on the proposed 2010 conservation surcharge rates is expected in November 2009.

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

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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 provide for the remaining 7,200 dekatherms (“Dts”) of additional firm service capacity previously approved by the FERC. On March 13, 2009, the FERC granted the requested authorization. On October 30, 2009, ESNG received approval from the FERC to commence services on these expansion facilities in November 2009, which will permit ESNG to realize an additional annualized gross margin of approximately $1.0 million.

Energylink Expansion Project (“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 to recover specified project costs in accordance with the terms of the precedent agreements executed with the two participating customers, one of which is Chesapeake, through its Delaware and Maryland divisions. These billings will reimburse ESNG for the $3.17 million of costs incurred in connection with the E3 Project, including the 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, which made 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.

On June 1, 2009, ESNG submitted revised tariff sheets to comply with FERC Order No. 587-T, which adopted Version 1.8 of the North American Energy Standards Board Wholesale Gas Quadrant’s standards. FERC found this rule necessary to increase the efficiency of the pipeline grid, make pipelines’ electronic communications more secure and provide consistency with the mandate that agencies provide for electronic disclosure of information. ESNG’s revised tariff sheets were approved on August 11, 2009, by the FERC, which will have no financial impact on ESNG.

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On August 21, 2009, ESNG filed revised tariff sheets to reflect an increase in the Annual Charge Adjustment (“ACA”) surcharge from $0.0017 per Dt to $0.0019 per Dt. The ACA surcharge is designed to recover applicable program costs incurred by the FERC. The tariff sheets were accepted as proposed and were made effective on October 1, 2009. As the ACA is passed-through to ESNG’s customers, there will be no financial impact on ESNG.

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. On November 4, 2002, Chesapeake requested, and is awaiting, a No Further Action determination from the MDE.

Through September 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 Order from the Maryland PSC issued on September 26, 2006. As of September 30, 2009, a regulatory asset of approximately $812,000 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 September 30, 2009, the Company has accrued $1.8 million of environmental costs associated with this site. At September 30, 2009, the Company had accrued a liability of $425,000 related to this site, offsetting: (a) a regulatory asset of approximately $726,000, representing the uncollected portion of the estimated clean-up costs, and (b) approximately $301,000 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 could 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

During 1999, the MDE queried with the Company regarding a manufactured gas plant site located in Cambridge, Maryland. The Company responded, and no further discussions ensued. 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, primarily its 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 of either subsidiary’s default. 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 September 30, 2009 was $22.4 million, with the guarantees expiring on various dates in 2009 and 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 September 30, 2009, and the Company does not anticipate that this letter of credit will be drawn upon by the counterparty in the future.

Accounting for Regulated Operations

The Company accounts for its regulated operations in accordance with the FASB ASC 980, “Regulated Operations.” In applying provisions of this Topic, 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 these provisions 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.

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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.

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 merger in 2009 and related acquisition costs (see Note 2), 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 nine months ended September 30, 2008, were reclassified to the “other and eliminations” segment.

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


	Three Months Ended						Nine Months Ended
For the Periods Ended September 30,	2009			2008			2009			2008
	(in Thousands)						(in Thousands)
Operating Revenues, Unaffiliated Customers
Natural gas	$	22,949		$	37,245		$	127,120		$	159,840
Propane		6,198			8,759			41,429			48,056
Advanced information services		2,611			3,694			8,522			11,132

Total operating revenues, unaffiliated customers	$	31,758		$	49,698		$	177,071		$	219,028


Intersegment Revenues ⁽¹⁾
Natural gas	$	140		$	114		$	412		$	324
Propane		—			—			254			1
Advanced information services		36			48			70			84
Other		173			163			517			489

Total intersegment revenues	$	349		$	325		$	1,253		$	898


Operating Income (Loss)
Natural gas	$	3,181		$	2,938		$	18,432		$	19,034
Propane		(1,570	)		(2,135	)		3,354			957
Advanced information services		(103	)		277			(448	)		516
Other and eliminations ⁽²⁾		749			90			(260	)		(966	)

Total operating income	$	2,257		$	1,170		$	21,078		$	19,541

Other income (loss), net of other expenses		(26	)		(91	)		19			(11	)
Interest		1,540			1,488			4,755			4,470
Income taxes (benefits)		383			(211	)		6,636			5,865

Net income (loss)	$	308			( $198	)	$	9,706		$	9,195


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

⁽²⁾		Other and eliminations includes transaction-related costs (credit) of ($675,000) and $0 for the three months ended September 30, 2009 and 2008, respectively, and $530,000 and $1.2 million for the nine months ended September 30, 2009 and 2008, respectively.


	September 30,		December 31,
	2009		2008
	(in Thousands)
Identifiable Assets
Natural gas	$	286,481	$	297,407
Propane		57,379		72,955
Advanced information services		3,716		3,545
Other		12,620		11,849

Total identifiable assets	$	360,196	$	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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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 September 30,	2009			2008			2009		2008		2009		2008
(in Thousands)
Service Cost	$	—		$	—		$	—	$	—	$	—	$	1
Interest Cost		140			148			33		31		27		28
Expected return on plan assets		(86	)		(156	)		—		—		—		—
Amortization of prior service cost		(2	)		(1	)		3		—		—		—
Amortization of net loss		68			—			14		12		40		46

Net periodic (benefit) cost	$	120		$	(9	)	$	50	$	43	$	67	$	75


	Defined Benefit						Pension Supplemental				Other Post-Retirement
	Pension Plan						Executive Retirement Plan				Benefits
For the Nine Months Ended September 30,	2009			2008			2009		2008		2009		2008
(in Thousands)
Service Cost	$	—		$	—		$	—	$	—	$	1	$	3
Interest Cost		420			445			97		94		81		83
Expected return on plan assets		(259	)		(469	)		—		—		—		—
Amortization of prior service cost		(4	)		(4	)		10		—		—		—
Amortization of net loss		205			—			44		35		119		138

Net periodic (benefit) cost	$	362		$	(28	)	$	151	$	129	$	201	$	224

The Company expects to recognize increased pension costs of approximately $483,000 in 2009 as a result of the decline in market 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 nine months ended September 30, 2009, were $22,000 and $67,000, 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 nine months ended September 30, 2009, totaled $57,000 and $91,000, respectively. Based on actuarial assumptions and historical data, the Company has estimated that approximately $225,000 will be paid for such benefits during 2009.

Investments

The investment balance at September 30, 2009, represents a Rabbi Trust associated with the Company’s Supplemental Executive Retirement Savings Plan. The Company classifies these investments as trading securities and reports them at their fair value. Any unrealized gains and losses, net of other expenses, are included in other income in the condensed consolidated statements of income. 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 September 30, 2009, total investments had a fair value of $1.8 million.

Share-Based Compensation

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

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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 nine months ended September 30, 2009 and 2008.


(in Thousands)	Three Months Ended				Nine Months Ended
For the periods ended September 30,	2009		2008		2009		2008
Directors Stock Compensation Plan	$	48	$	40	$	143	$	132
Performance Incentive Plan		264		104		754		489

Total compensation expense		312		144		897		621
Less: tax benefit		125		57		359		247

Share-Based Compensation amounts included in net income	$	187	$	87	$	538	$	374

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 nine months ended September 30, 2009, is presented below:


			Weighted Averagee
	Number of Shares		Fair Value
Outstanding — December 31, 2008		—

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

Outstanding — September 30, 2009		—

At September 30, 2009, there was $113,000 of unrecognized compensation expense related to the DSCP awards that is expected to be recognized over the remaining seven 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 nine months ended September 30, 2009:


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

Granted		28,875	$	29.19
Vested		—		—
Forfeited		—		—
Expired		—		—

Outstanding — September 30, 2009		123,075	$	28.15

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 or 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 September 30, 2009, the aggregate intrinsic value of the PIP awards was $1.9 million.

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Derivative Instruments

The Company uses derivative and non-derivative contracts to engage in trading activities and manage the risks related to obtaining adequate supplies and the price fluctuations of natural gas and propane. 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 or are considered “normal purchases and sales” 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 September 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 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 September 30, 2009, the Company had the following outstanding trading contracts:


	Quantity in		Estimated Market		Weighted Average
At September 30, 2009	Gallons		Prices		Contract Prices
Forward Contracts
Sale		26,098,800	$	0.6900 — $0.9950	$	0.8962
Purchase		26,590,200	$	0.6650 — $0.9975	$	0.8946

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 September 30, 2009 and December 31, 2008, are the following:


	Asset Derivatives
		Fair Value
(in Thousands)	Balance Sheet Location	September 30, 2009		December 31, 2008
Derivatives not designated as fair value hedges:
Forward contracts	Mark-to-market energy assets	$	1,532	$	4,482

Total asset derivatives		$	1,532	$	4,482


	Liability Derivatives
		Fair Value
(in Thousands)	Balance Sheet Location	September 30, 2009		December 31, 2008
Derivatives designated as fair value hedges:
Propane swap agreement ⁽¹⁾	Other current liabilities	$	—	$	105

Derivatives not designated as fair value hedges:
Forward contracts	Mark-to-market energy liabilities	$	1,484	$	3,052


Total liability derivatives		$	1,484	$	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.

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The effects of gains and losses from derivative instruments on the Statement of Income for the three and nine months ended September 30, 2009 and 2008, are the following:


	Amount of Gain (Loss) on Derivatives:
	Location of Gain	Three months ended September 30,					Nine months ended September 30,
(in Thousands)	(Loss) on Derivatives	2009			2008		2009			2008
Derivatives designated as fair value hedges:
Propane swap agreement ⁽¹⁾	Cost of Sales	$	—		$	475	$	(42	)	$	475

Derivatives not designated as fair value hedges:
Unrealized gains (losses) on forward contracts	Revenue	$	(246	)	$	84	$	(1,382	)	$	548


Total		$	(246	)	$	559	$	(1,424	)	$	1,023


⁽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 nine months ended September 30, 2009 and 2008, are the following:


	Amount of Trading Revenue:
	Location in the	Three months ended September 30,					Nine months ended September 30,
(in Thousands)	Statement of Income	2009			2008		2009			2008
Realized gains on forward contracts	Revenue	$	915		$	678	$	2,984		$	1,714
Changes in mark-to-market energy assets	Revenue		(246	)		84		(1,382	)		548

Total		$	669		$	762	$	1,602		$	2,262

10.

Fair Value of Financial Instruments

FASB ASC 820, “Fair Value Measurements and Disclosures,” establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. The hierarchy gives the highest priority to unadjusted, quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are the following:

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

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

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

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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 September 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	$	1,834	$	1,834
Mark-to market energy assets	$	1,532		—	$	1,532		—

Liabilities:
Mark-to-market energy liabilities	$	1,484		—	$	1,484		—


			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		—

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The following valuation techniques were used to measure fair value assets in the tables above on a recurring basis as of September 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 for similar assets and liabilities.

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 September 30, 2009, there were no non-financial assets or liabilities required to be reported at fair value. The Company reviews its non-financial assets for impairment at least on an annual basis, as required.

Other Financial Assets and Liabilities

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

At September 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 $96.0 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.


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;

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	•		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;

	•		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 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, and certain merger-related costs will be allowed to be recovered through rates. 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: problems which may arise in successfully integrating the businesses of the companies and 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 the accounting for the transaction may be different from the Company’s expectations; 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.

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Overview

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

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

•

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

•

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

•

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

•

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

•

enhancing marketing channels to attract new customers;

•

providing reliable and responsive service to retain existing customers;

•

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

•

maintaining a consistent and competitive dividend for shareholders.

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

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 would 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. On October 22, 2009, shareholders of both Chesapeake and FPU approved the merger, which became effective on October 28, 2009 and each outstanding share of FPU common stock was converted into 0.405 share of Chesapeake’s common stock. At closing, FPU had 6,140,592 common shares outstanding and Chesapeake’s common stock was valued at $30.42 per share, which resulted in total consideration paid by Chesapeake of approximately $75.7 million. The total consideration is based upon the closing price of Chesapeake’s common stock on October 27, 2009, the last trading day prior to the effective date of the merger. Immediately after the merger, Chesapeake’s stockholders owned approximately 73.5 percent of the combined company, and FPU’s stockholders owned approximately 26.5 percent of the combined company.

The merger is intended to qualify as a reorganization within the meaning of Section 368(a) of the Internal Revenue Code of 1986, as amended, and will be accounted for under the acquisition method of GAAP, with Chesapeake being treated as the acquirer. Under this method, the assets acquired and liabilities assumed are recorded at their respective fair values and added to those of Chesapeake. Chesapeake is in the process of finalizing its evaluation of the tangible and intangible assets acquired and liabilities assumed, as well as the initial purchase price allocation as of the acquisition date, including the determination of any resulting goodwill. Therefore, this information cannot be provided at this time.

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In connection with the merger, Chesapeake has incurred $1.9 million in transaction-related costs during the nine months ended September 30, 2009. Chesapeake has begun the process of seeking regulatory approval to defer a portion of these costs related to regulated operations for future rate recovery. Based on precedents established by the Florida PSC in previous business combinations involving natural gas utilities in Florida, Chesapeake determined that future rate recovery of the acquisition-related transaction costs for regulated operations is probable and deferred a portion of these costs as a regulatory asset as of September 30, 2009. This regulatory asset includes deferrals of merger-related costs incurred during the first and second quarters of 2009, respectively, that were previously accounted for as expenses. The reversal of these amounts is presented as a credit to Chesapeake’s operating expenses for the three months ended September 30, 2009. Future regulatory developments may require Chesapeake to re-assess the probability of future rate recovery with regard to the costs deferred as a regulatory asset.

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 and employs 348 people. 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. Chesapeake’s management expects the transaction to be earnings neutral or slightly accretive in 2010 and meaningfully accretive in 2011.

Results of Operations for the Quarter Ended September 30, 2009

The following discussions on operating income and segment results for the three months ended September 30, 2009 and 2008, include use of the term “gross margin,” which 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 Generally Accepted Accounting Principles (“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 Chesapeake 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. In addition, certain information is presented, which excludes for comparison purposes, all merger-related transaction costs incurred in connection with the FPU merger. Although the non-GAAP measures are not intended to replace the GAAP measures for evaluation of Chesapeake’s performance, Chesapeake believes that the portions of the presentation which exclude merger-related transaction costs are helpful on a comparative basis for investors to understand Chesapeake’s performance.

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Consolidated Overview

The Company’s net income for the quarter ended September 30, 2009 was $308,000, or $0.04 per share (diluted). This represents an increase of $506,000, compared to a net loss of $198,000, or $0.03 per share (diluted), reported in the same period in 2008. The Company’s Delmarva natural gas distribution and propane distribution operations typically experience seasonal losses or reduced earnings during the third quarter, because customers do not require natural gas or propane for heating purposes during the summer months. Net income for the quarter ended September 30, 2009, included the effect of deferring as a regulatory asset certain merger-related transaction costs, which the Company will seek to recover in subsequent rate proceedings. Absent the effects of the merger-related costs and related income taxes, the Company would have generated net income of $78,000, or $0.01 per share (diluted), for the quarter ended September 30, 2009.


For the Three Months Ended September 30,	2009			2008			Change
(in Thousands)
Operating Income (Loss):
Natural Gas	$	3,181		$	2,938		$	243
Propane		(1,570	)		(2,135	)		565
Advanced Information Services		(103	)		277			(380	)
Other & eliminations		749			90			659

Operating Income		2,257			1,170			1,087

Other Loss, Net of Other Income		(26	)		(91	)		65
Interest Charges		1,540			1,488			52
Income Taxes (Benefit)		383			(211	)		594

Net Income (Loss)	$	308		$	(198	)	$	506

The Company’s period-over-period operating results reflect an increase of $1.3 million, or eight percent, in gross margin and an increase of other operating expenses of $208,000. Customer growth in the Delmarva natural gas distribution operations and new transportation services placed into service by the natural gas transmission operation positively impacted gross margin during the third quarter of 2009. The Delmarva natural gas distribution operations contributed to the gross margin increase from the implementation of new rate structures in October 2008, which allows collection of a greater portion of revenue through non-volume-based charges. Absent the costs related to inventory valuation adjustments, including a mark-to-market loss on a price swap agreement, by the propane distribution operations totaling $975,000 in the third quarter of 2008, which did not recur in the same period in 2009, also contributed to the increase in gross margin. These increases were partially offset by the advanced information services segment’s gross margin decrease, a result of current economic conditions in which information technology spending has broadly declined. The Company has taken actions in the first and third quarters to reduce costs within the advanced information services segment to offset the decline in revenues.

The increase of $208,000 in other operating expenses includes the effects of a credit of $939,000 associated with the deferral of previously expensed merger-related costs and additional merger-related costs, of $265,000 in the third quarter of 2009, which are not subject to recovery through rates. Exclusive of the net effects of merger-related transaction costs, the increase in other operating expenses was $883,000, which is due to: (i) increased compensation costs of $608,000, attributable primarily to payroll adjustments that commenced on January 1, 2009, pursuant to the results of a salary survey conducted during the fourth quarter of 2008; (ii) increased accruals for incentive compensation due to improved non-merger related operating results; and (iii) increased pension costs of $195,000 due to the decline in the value of pension plan assets in 2008.

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Natural Gas

The natural gas segment reported operating income of $3.2 million for the third quarter of 2009, an increase of $243,000, or eight percent, compared to operating income of $2.9 million reported in the third quarter of 2008.


For the Three Months Ended September 30,	2009		2008		Change
(in Thousands)
Revenue	$	23,091	$	37,359	$	(14,268	)
Cost of sales		9,545		24,867		(15,322	)

Gross margin		13,546		12,492		1,054

Operations & maintenance		7,170		6,599		571
Depreciation & amortization		1,841		1,683		158
Other taxes		1,354		1,272		82

Other operating expenses		10,365		9,554		811

Operating Income	$	3,181	$	2,938	$	243


Statistical Data — Delmarva Peninsula
Heating degree-days (“HDD”):
Actual		80		69		11
10-year average (normal)		58		55		3
Estimated gross margin per HDD	$	1,937	$	1,937		—

Per residential customer added:
Estimated gross margin	$	375	$	375		—
Estimated other operating expenses	$	103	$	103		—

Residential Customer Information
Average number of customers:
Delmarva		45,871		44,726		1,145
Florida		13,059		13,221		(162	)

Total		58,930		57,947		983

Operating income for the natural gas segment increased by $243,000 as the result of a gross margin increase of $1.1 million, or eight percent, which was partially offset by increased other operating expenses of $811,000, or eight percent, for the third quarter in 2009 compared to the same period in 2008.

Gross Margin

Gross margin increases of $707,000 for the natural gas transmission operation and $552,000 for the natural gas distribution operations were partially offset by decreased gross margin of $205,000 for the natural gas marketing operations.

The natural gas transmission operation achieved gross margin growth of $707,000 in the third quarter of 2009, an increase of 14 percent over the same period in 2008, due primarily to the implementation of the following new transportation services:

•

New long-term transportation services, implemented by ESNG in November 2008, which provided for an additional 5,650 Dts per day, generated $247,000 of gross margin in the third quarter of 2009. These new services are expected to generate approximately $988,000 of annualized gross margin.

•

New transportation services provided to an industrial customer for the period of February 6, 2009 through October 31, 2009, provided for an additional 7,200 Dts per day. For the third quarter of 2009, this service provided $195,000 of additional gross margin and is expected to generate approximately $573,000 of gross margin for 2009. In addition, ESNG entered into two other firm transportation service agreements with this customer for the period of (i) November 1, 2009 through October 31, 2012, for 10,000 Dts per day, and (ii) November 1, 2009 through November 30, 2009, for 3,131 Dts per day. Although there was no impact from these contracts in the third quarter of 2009, they are expected to increase gross margin by approximately $209,000 in the fourth quarter of 2009 and by $1.1 million in 2010.

•

ESNG changed its rates effective April 2009 to recover specified project costs in accordance with the terms of precedent agreements with certain customers. These rates generated $129,000 in gross margin for the third 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.

- 27 -

Although the following had no impact in the third quarter of 2009, they could affect future results for the natural gas transmission operation:

•

The remaining facilities included in ESNG’s most recent multi-year system expansion 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, one expiring in October 2009 and the other in March 2010. If these contracts are not renewed, or equivalent firm service capacity is not subscribed to by other customers, gross margin could be reduced by approximately $56,000 in 2009 and approximately $427,000 in 2010. ESNG also received notice from a smaller customer that it does not intend to renew its firm transportation service contract, which expires in April 2010. This contract provides for annualized gross margin of approximately $54,000.

The natural gas distribution operations for the Delmarva Peninsula generated an increase in gross margin of $682,000 for the third quarter of 2009, compared to the same period in 2008. The new rate structure in Delaware, implemented in October of 2008, contributed $323,000 of 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 reduces volatility in gross margin based on weather changes. The new rate structure also allows collection of miscellaneous service fees of $74,000, which, although not representing additional revenue, had previously been offset against other operating expenses. Despite 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 $300,000 to the increased gross margin. The aforementioned increases to gross margin overcame the negative impact of decreased interruptible sales to industrial customers, due to a reduction in the price of alternative fuels, which reduced gross margin by $133,000.

The Florida natural gas distribution operation experienced a decrease in gross margin of $130,000 in the third quarter of 2009, due primarily to reduced customer consumption and loss of three industrial customers, one in October 2008 and two in the third quarter of 2009, all attributable to adverse economic conditions in the region. On July 14, 2009, the division filed with the Florida PSC a petition for a rate increase of approximately $3.0 million, which represents a twenty-five percent base rate increase on average for the Florida operation’s customers. In the same filing, the Company sought an increase of approximately $418,000 in its interim rates, which was approved by the Florida PSC on August 18, 2009. The Company began billing the increased interim rates, subject to refund, on September 17, 2009.

The Company’s natural gas marketing operation experienced a decrease in gross margin of $205,000 for the third quarter of 2009, as prior year’s gross margin included favorable imbalance resolutions with interstate pipelines that did not recur during the third quarter of 2009, and as a result of a four-percent decrease in customer consumption in the current quarter.

Other Operating Expenses

The factors contributing to the increase in other operating expenses by $811,000 for the natural gas segment are as follows:

•

Salaries and incentive compensation increased by $370,000, due primarily to compensation adjustments for non-executive employees that were made effective January 1, 2009, pursuant to the results of a compensation survey completed in the fourth quarter of 2008, and an increase in accruals for incentive compensation as a result of improved operating results. Benefit costs increased by $149,000, 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.

•

Partially offsetting the increases in operating expenses was a decrease of $108,000 in allowance for doubtful accounts attributable to lower energy prices in the current quarter.

•

Depreciation expense, asset removal costs and property taxes, collectively, increased by approximately $197,000 as a result of the Company’s continued capital investments to support customer growth.

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Propane

The propane segment experienced a seasonal operating loss of $1.6 million for the third quarter of 2009, a reduction of $565,000, or twenty-six percent, compared to an operating loss of $2.1 million in the third quarter of 2008.


For the Three Months Ended September 30,	2009			2008			Change
(in Thousands)
Revenue	$	6,198		$	8,759		$	(2,561	)
Cost of sales		3,416			6,642			(3,226	)

Gross margin		2,782			2,117			665

Operations & maintenance		3,619			3,573			46
Depreciation & amortization		521			509			12
Other taxes		212			170			42

Other operating expenses		4,352			4,252			100

Operating Loss	$	(1,570	)	$	(2,135	)	$	565


Statistical Data — Delmarva Peninsula
Heating degree-days (“HDD”):
Actual		80			69			11
10-year average (normal)		58			55			3

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

The propane segment experienced a decreased operating loss, which resulted from an increase of $665,000, or thirty-one percent, in gross margin, partially offset by increased other operating expenses of $100,000.

Gross Margin

A gross margin increase of $779,000 for the Delmarva propane distribution operations was slightly offset by reduced gross margin of $21,000 for the Florida propane distribution operations and $93,000 for the propane wholesale and marketing operation.

The Delmarva propane distribution operation’s increase in gross margin of $779,000 resulted primarily from the absence of $975,000 in inventory valuation adjustments, including a mark-to-market loss on a price swap agreement, incurred in the third quarter of 2008, as a result of the sharp decline in propane prices, which did not recur in the third quarter of 2009.

Gross margin for the Florida propane distribution operation decreased by $21,000 in the third quarter of 2009, compared to the same period in the prior year, as a decline in residential and non-residential consumption was partially offset by an increase in margin per gallon.

The propane wholesale marketing operation experienced a decrease in gross margin of $93,000 in the third quarter of 2009. This operation typically capitalizes on 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 third quarter of 2009, compared to the same period in 2008, reduced opportunities and decreased trading volumes by thirteen percent.

- 29 -

Other Operating Expenses

Total other operating expenses for the propane segment increased by $100,000 for the quarter ended September 30, 2009, compared to the same period in 2008, due primarily to: (i) higher payroll costs of $83,000 reflecting annual salary increases, (ii) an increase of $69,000 in benefit costs resulting from the significant decline in the value of pension plan assets during 2008, and (iii) additional costs of approximately $21,000 to maintain propane tanks in compliance with United States Department of Transportation standards during the current period. These increases were offset by lower vehicle-related costs of $101,000 due primarily to a decrease in the cost of fuel.

Advanced Information Services

The advanced information services business experienced an operating loss of $103,000 for the quarter ended September 30, 2009, a decrease of $380,000 compared to operating income of $277,000 achieved during the same period in 2008.


For the Three Months Ended September 30,	2009			2008		Change
(in Thousands)
Revenue	$	2,647		$	3,742	$	(1,095	)
Cost of sales		1,454			2,142		(688	)

Gross margin		1,193			1,600		(407	)

Operations & maintenance		1,111			1,121		(10	)
Depreciation & amortization		47			48		(1	)
Other taxes		138			154		(16	)

Other operating expenses		1,296			1,323		(27	)

Operating Income (Loss)	$	(103	)	$	277	$	(380	)

The decrease in operating income is the result of lower gross margin of $407,000, or twenty-five percent, partially offset by lower other operating expenses of $27,000.

Gross Margin

The period-over-period decrease in gross margin is due primarily to a decrease of $980,000 in consulting revenues, as the number of billable hours declined by twenty-seven 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 $27,000, or two percent, to $1.3 million in the third quarter of 2009. The Company implemented cost-containment actions, including layoffs and compensation adjustments, in March, September and October to reduce costs to offset the decline in revenues. The September cost-containment actions resulted in a one-time charge of $38,000 in the third quarter of 2009. Other operating expenses for the third quarter of 2008 reflected a reversal of accruals for incentive compensation of $179,000, which resulted in lower other operating expenses during that period. Absent these cost adjustments, other operating expenses would have decreased by $244,000 in the third quarter of 2009. The aforementioned cost-containment actions, net of severance packages, are expected to further reduce operating costs by $392,000 in the fourth quarter of 2009 and return the advanced information segment to an operating profit.

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Other and Eliminations

The other and eliminations segment, which primarily reflects the revenues and expenses of subsidiaries that own real estate leased to other Company subsidiaries and the merger-related costs, which have not been deferred and are not subject to future rate recovery, experienced an operating income of approximately $749,000 for the third quarter of 2009, an increase of $659,000 compared to operating income of $90,000 for the same period in 2008. The operating income experienced in the third quarter of 2009 was due primarily to the aforementioned net effects of the merger-related costs.


For the Three Months Ended September 30,	2009			2008			Change
(in Thousands)
Revenue	$	(178	)	$	(162	)	$	(16	)
Cost of sales		1			—			1

Gross margin		(179	)		(162	)		(17	)

Operations & maintenance		(299	)		(296	)		(3	)
Non-recoverable transaction and other legal costs		(675	)		—			(675	)
Depreciation & amortization		28			27			1
Other taxes		18			17			1

Other operating expenses		(928	)		(252	)		(676	)

Operating Income	$	749		$	90		$	659


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

Interest Expense

Total interest expense for the third quarter of 2009 increased by approximately $52,000, or three percent, compared to the same period in 2008. The increase in the interest expense is attributable primarily to the following:

•

Interest on long-term debt increased by $323,000 in the third 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 third 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 $260,000 in the third quarter of 2009, compared to the same period in 2008, based upon a decrease of $38.5 million in the Company’s average short-term borrowing balance partially offset with a higher weighted average interest rate. The Company’s average short-term borrowing during the third quarter of 2009 was $5.1 million, with a weighted average interest rate of 3.01 percent, compared to $43.5 million, with a weighted average interest rate of 2.69 percent, for the same period in 2008.

Income Taxes

The Company recorded an income tax expense of $383,000 for the three months ended September 30, 2009, compared to an income tax benefit of $211,000 for the three months ended September 30, 2008. Exclusive of the tax effects of the merger-related costs, a portion of which are non-deductible for income tax purposes, resulted in a tax benefit of $63,000 for the three months ended September 30, 2009. The decreased income tax benefit is primarily a function of higher earnings for the period.

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Results of Operations for the Nine Months Ended September 30, 2009

The following discussions on operating income and segment results for the nine months ended September 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. In addition, certain information is presented, which excludes for comparison purposes, all merger-related transaction costs incurred in connection with the FPU merger. Although the non-GAAP measures are not intended to replace the GAAP measures for evaluation of Chesapeake’s performance, Chesapeake believes that the portions of the presentation which exclude the merger-related transaction costs are helpful on a comparative basis for investors to understand Chesapeake’s performance.

Consolidated Overview

The Company’s net income for the nine months ended September 30, 2009, increased by $511,000, compared to the same period in 2008. The Company reported net income of approximately $9.7 million, or $1.40 per share (diluted), for the nine months ended September 30, 2009. This includes $530,000 in merger-related costs that are not subject to recovery through future rates. Net income of $9.2 million, or $1.34 per share (diluted), for the nine months ended September 30, 2008, also includes $1.2 million in merger-related costs. Excluding the effects of merger-related costs and related income taxes, net income for the nine months ended September 30, 2009, would have been $10.2 million, or $1.46 per share (diluted), compared to $9.9 million, or $1.44 per share (diluted), for the same period in 2008.


For the Nine Months Ended September 30,	2009			2008			Change
(in Thousands)
Operating Income (Loss):
Natural Gas	$	18,432		$	19,034		$	(602	)
Propane		3,354			957			2,397
Advanced Information Services		(448	)		516			(964	)
Other & eliminations		(260	)		(966	)		706

Operating Income		21,078			19,541			1,537

Other Income, Net of Other Expenses		19			(11	)		30
Interest Charges		4,755			4,470			285
Income Taxes		6,636			5,865			771

Net Income	$	9,706		$	9,195		$	511

The Company’s period-over-period operating results reflect an increase of $5.1 million, or eight percent, in gross margin and an increase of other operating expenses of $3.6 million, which includes the impact of the decreased merger-related costs. Colder than normal temperatures on the Delmarva Peninsula, customer growth in the natural gas and propane distribution operations, new transportation services placed into service by the natural gas transmission operation, increased retail margins by the propane distribution operations and spot sale opportunities executed by the natural gas marketing operations all contributed to the gross margin increase. The Company’s propane distribution operations recorded $975,000 in expenses related to inventory valuation adjustments, including a mark-to-market loss on a price swap agreement, in the third quarter of 2008, which did not recur in 2009. These positive achievements offset the gross margin impact of lower demand and adverse market conditions faced by the advanced information services and propane wholesale marketing operations.

Other operating expenses, exclusive of merger-related costs, increased by $4.3 million, or nine percent, which reflects the rising costs associated with supporting growth of the Company’s businesses. Other operating expenses for the first nine months of 2009 also reflect certain effects of the economic slowdown, including a $350,000 increase in allowance for uncollectible accounts and $397,000 in higher pension costs attributable to declining pension plan assets in 2008. Also contributing to the increase was the reduction in depreciation expenses of $305,000 related to the Delaware rate case, in the third quarter of 2008 that did not recur in 2009.

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During 2009, the Company decided not to allocate merger-related 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 $530,000 in merger-related costs for the nine months ended September 30, 2009, that are not subject to recovery through future rates, was allocated to the “other and eliminations” segment. The Company also revised the 2008 segment information to reclassify the $1.2 million of such costs 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 generated an operating income of $18.4 million for the first nine months of 2009, compared to $19.0 million for the corresponding period in 2008, representing a decrease of $602,000, or three percent.


For the Nine Months Ended September 30,	2009		2008		Change
(in Thousands)
Revenue	$	127,534	$	160,166	$	(32,632	)
Cost of sales		77,266		113,131		(35,865	)

Gross margin		50,268		47,035		3,233

Operations & maintenance		22,225		19,389		2,836
Depreciation & amortization		5,453		4,977		476
Other taxes		4,158		3,635		523

Other operating expenses		31,836		28,001		3,835

Total Operating Income	$	18,432	$	19,034	$	(602	)


Statistical Data — Delmarva Peninsula
Heating degree-days (“HDD”):
Actual		3,003		2,772		231
10-year average (normal)		2,889		2,855		34
Estimated gross margin per HDD	$	1,937	$	1,937		—

Per residential customer added:
Estimated gross margin	$	375	$	375		—
Estimated other operating expenses	$	103	$	103		—

Residential Customer Information
Average number of customers:
Delmarva		46,669		45,427		1,242
Florida		13,291		13,418		(127	)

Total		59,960		58,845		1,115

Operating income for the natural gas segment decreased by $602,000 as the increase of $3.2 million, or seven percent, in gross margin was more than offset by increased other operating expenses of $3.8 million, or fourteen percent, for the first nine months of 2009, compared to the same period in 2008.

Gross Margin

Gross margin increased by $3.2 million for the natural gas segment for the first nine months of 2009, which was derived from increases of $1.7 million for the natural gas transmission operation, $929,000 for the natural gas distribution operations and $627,000 for the natural gas marketing operation.

The natural gas transmission operation achieved gross margin growth of $1.7 million, or ten percent, for the nine months ended September 30, 2009, compared to the same period in 2008, due to the following new transportation services on the Delmarva Peninsula and in Florida:

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	•		New long-term transportation services implemented by ESNG in November 2008, which provided for an additional 5,650 Dts per day, generated $743,000 of gross margin for the nine months ended September 30, 2009. These new services are expected to generate approximately $988,000 of annualized gross margin in 2009.

	•		New firm transportation services provided to an industrial customer for the period of February 6, 2009 through October 31, 2009, provided for an additional 7,200 Dts per day. For the nine months ended September 30, 2009, this service provided $508,000 of gross margin, and is expected to contribute $573,000 of annualized gross margin in 2009. In addition, ESNG entered into two additional firm transportation service agreements with this customer: (1) 10,000 Dts per day from November 1, 2009 through October 31, 2012, and (2) 3,131 Dts per day from November 1, 2009 through November 31 2009. Although there contracts had no gross margin impact during the nine months ended September 30, 2009, they are expected to contribute approximately $209,000 in the fourth quarter of 2009 and $1.1 million in 2010.

	•		In April 2009, ESNG changed its rates to recover specific project costs in accordance with the terms of precedent agreements with certain customers. These new rates generated $258,000 in gross margin for ESNG during the first nine months of 2009 and will contribute $387,000 of annualized gross margin to ESNG 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 service to a customer for a period of 20 years. For the first nine months of 2009, this agreement contributed $198,000 to gross margin and is expected to contribute $264,000 in annualized gross margin.

Although the following developments had no impact in the first nine months of 2009, they could affect future results for the natural gas transmission operation:

	•		The remaining facilities included in its most recent multi-year system expansion project to be placed into service in November 2009, and will provide an additional 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, one expiring in October 2009 and the other in March 2010. If these contracts are not renewed, or equivalent firm service capacity is not subscribed to by other customers, gross margin will be reduced by approximately $56,000 in 2009 and approximately $427,000 in 2010. ESNG also received notice from a smaller customer that it does not intend to renew its firm transportation service contract, which expires in April 2010. This contract provides for annualized gross margin of approximately $54,000.

The natural gas distribution operations for the Delmarva Peninsula generated an increase in gross margin of $1.2 million for the first nine 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 $875,000 to the gross margin increase. The Delaware and Maryland divisions have experienced slower customer growth in 2009 than in recent years and expect that trend to continue in the near future. Colder weather on the Delmarva Peninsula contributed $266,000 to the increased gross margin, as temperatures were eight percent colder in the first nine months of 2009 compared to the same period in 2008. In addition, Delaware division’s new rate structure allows collection of miscellaneous service fees of $260,000, which, although not representing additional revenue, had previously been offset against other operating expenses. The aforementioned increases to gross margin overcame the negative impact of decreased interruptible sales to industrial customers due to a reduction in the price of alternative fuels, which reduced gross margin by $310,000.

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The Florida natural gas distribution operation experienced a decrease in gross margin of $269,000, in the first nine months of 2009, due primarily to reduced consumption by customers and loss of three industrial customers, one in October 2008 and two in the third quarter of 2009, all attributable to adverse economic conditions in the region. On July 14, 2009, the Florida natural gas distribution operation filed with the Florida PSC a petition for a rate increase of approximately $3.0 million, which represents a twenty-five percent base rate increase on average for the Florida division’s customers. In the same filing, the Company sought an increase in the interim rates of approximately $418,000, which was approved by the Florida PSC on August 18, 2009, subject to refund, and the Company began billing customers the approved interim rates on September 17, 2009.

The Company’s natural gas marketing operation experienced an increase in gross margin of $627,000 during the first nine months of 2009, as it benefited from increased spot sales. 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 $3.8 million, due primarily to the following factors:

	•		Depreciation expense, asset removal costs and property taxes, collectively, increased by approximately $1.2 million as a result of the Company’s continued capital investments to support customer growth. The increased depreciation expense also reflects a $305,000 depreciation credit as a result of the Delaware negotiated rate settlement agreement in the third quarter of 2008, of which $295,000 related to depreciation for the months of October through December 2007.

	•		Salaries and incentive compensation increased by $566,000, due primarily to January 1, 2009 compensation adjustments for non-executive employees, based on a compensation survey completed in the fourth quarter of 2008, and annual salary increases, coupled with a slight increase in the accrual for incentive compensation as a result of improved operating results.

	•		The allowance for uncollectible accounts in the natural gas segment increased by $405,000 due to growth in customers and the general economic climate.

	•		Benefit costs increased by $326,000, 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.

	•		Increased information technology spending to improve the infrastructure and information technology support generated increased costs of $274,000.

	•		ESNG incurred expenses of $107,000 related to pipeline integrity projects in 2009 to maintain compliance with various regulations.

	•		The increases in operating expenses were partially offset by a decrease of $132,000 in vehicle expenses due primarily to a decrease in the cost of fuel.

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Propane

Operating income for the propane segment increased by $2.4 million, or 250 percent, to $3.4 million for the first nine months of 2009, compared to $957,000 for the corresponding period in 2008.


For the Nine Months Ended September 30,	2009		2008		Change
(in Thousands)
Revenue	$	41,683	$	48,057	$	(6,374	)
Cost of sales		24,379		33,899		(9,520	)

Gross margin		17,304		14,158		3,146

Operations & maintenance		11,708		11,030		678
Depreciation & amortization		1,552		1,511		41
Other taxes		690		660		30

Other operating expenses		13,950		13,201		749

Total Operating Income	$	3,354	$	957	$	2,397


Statistical Data — Delmarva Peninsula
Heating degree-days (“HDD”):
Actual		3,003		2,772		231
10-year average (normal)		2,889		2,855		34

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

Operating income for the propane segment increased by $2.4 million, as the increase of $3.1 million, or 22 percent, in gross margin was partially offset by increased other operating expenses of $749,000, or six percent, for the first nine months of 2009, compared to the same period in 2008.

Gross Margin

The gross margin increase of $3.1 million for the propane segment in the first nine months of 2009 was derived from increases of $3.6 million for the Delmarva propane distribution operations and $225,000 for the Florida propane distribution operations, partially offset by a lower gross margin of $660,000 for the propane wholesale and marketing operation.

The Delmarva propane distribution operations benefited from higher retail margins, increased non-weather-related volumes sold and colder weather on the Delmarva Peninsula in 2009. The gross margin increase of $3.6 million is attributable to the following:

	•		The Delmarva propane distribution operations generated $2.2 million of gross margin from higher retail margins as a result of sustaining retail prices and lower propane costs. The absence of inventory valuation adjustments, including a mark-to-market loss on a price swap agreement, during the third and fourth quarters of 2008 ($975,000 and $300,000, respectively), which did not recur in 2009, contributed to relatively low propane inventory costs in 2009 for the Delmarva propane operations.

	•		Non-weather-related volumes sold in the first nine months of 2009 increased by 1.0 million gallons, or seven percent, compared to the same period in 2008. This increase in gallons sold, which provided for an increase in gross margin of approximately $639,000, was driven primarily by the timing of propane deliveries to certain customers, increased participation in retention programs targeted to low consumption customers, and the addition of approximately 167 Community Gas Systems (“CGS”) customers served, an increase of three percent. The Company expects the growth of its CGS operation to continue, although at a slower pace, given the current economic climate.

	•		Colder weather on the Delmarva Peninsula in the first nine months of 2009 increased the volumes sold during the period by 804,000 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 $584,000 of gross margin.

	•		Wholesale volumes increased by 2.0 million gallons in the first nine months of 2009, which resulted in a gross margin increase of $168,000 compared to the same period in 2008.

- 36 -

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, which contributed to the $225,000 increase in gross margin in the first nine months of 2009.

The propane wholesale marketing operation experienced a decrease in gross margin of $660,000 in the first nine 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 nine months of 2009 compared to the same period in 2008, reduced such revenue opportunities.

Other Operating Expenses

Other operating expenses increased by $749,000 for the propane segment for the nine months ended September 30, 2009, compared to the same period in 2008, due primarily to: (i) higher payroll costs of $514,000 resulting from increased accruals for incentive compensation based on increased operating results; (ii) increased costs to maintain propane tanks in compliance with United States Department of Transportation standards of $118,000; (iii) higher benefit costs of $103,000 as a result of the significant decline in the value of pension plan assets; and (iv) increased customer charges of $74,000. These increases were partially offset by lower vehicle-related expenses of $248,000 due to decrease in the price of fuel.

Advanced Information Services

The advanced information services business experienced an operating loss of $448,000 for the nine months ended September 30, 2009, a decrease of $964,000, compared to the operating income of $516,000 that was achieved during the same period in 2008.


For the Nine Months Ended September 30,	2009			2008		Change
(in Thousands)
Revenue	$	8,592		$	11,216	$	(2,624	)
Cost of sales		4,711			6,143		(1,432	)

Gross margin		3,881			5,073		(1,192	)

Operations & maintenance		3,707			3,889		(182	)
Depreciation & amortization		146			124		22
Other taxes		476			544		(68	)

Other operating expenses		4,329			4,557		(228	)

Total Operating Income (Loss)	$	(448	)	$	516	$	(964	)

The change from operating income to operating loss is the results of lower gross margin of $1.2 million, partially offset by lower other operating expenses of $228,000.

Gross Margin

The period-over-period decrease in gross margin is due to a decrease of $2.5 million in consulting revenues, as the number of billable hours declined by thirty percent for the nine months ended September 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 $228,000 to $4.3 million in the first nine months of 2009 compared to $4.6 million for the same period in 2008. This decrease was attained from layoffs and other cost containment actions and lower accruals for incentive compensation due to the lower operating results. In March, September and October 2009, the Company instituted layoffs, compensation adjustments and other cost-containment actions that are estimated to offset the decline in revenues and are expected to reduce costs by $392,000, respectively, for the remainder of 2009. These cost-containment actions are expected to return the advanced information segment to an operating profit.

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Other and Eliminations

The other and eliminations segment, which reflects primarily the revenues and expenses of subsidiaries that own real estate leased to other Company subsidiaries and merger-related costs that are not subject to future rate recovery, experienced an operating loss of approximately $260,000 for the first nine months of 2009, compared to an operating loss of approximately $966,000 for the same period in 2008. The operating losses experienced in the first nine months of 2009 and 2008 were due primarily to merger-related costs.


For the Nine Months Ended September 30,	2009			2008			Change
(in Thousands)
Revenue	$	(738	)	$	(411	)	$	(327	)
Cost of sales		(251	)		(3	)		(248	)

Gross margin		(487	)		(408	)		(79	)

Operations & maintenance		(888	)		(811	)		(77	)
Non-recoverable transaction and legal costs		530			1,240			(710	)
Depreciation & amortization		84			83			1
Other taxes		47			46			1

Other operating expenses		(227	)		558			(785	)

Total Operating Loss	$	(260	)	$	(966	)	$	706


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

Interest Expense

Total interest expense for the first nine months of 2009 increased by approximately $285,000, or six 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 $963,000 in the first nine months 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 first nine 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 $735,000 in the first nine months of 2009, compared to the same period in 2008, based upon a decrease of $28.1 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 nine months of 2009 was $10.2 million, with a weighted average interest rate of 1.96 percent, compared to $38.3 million, with a weighted average interest rate of 3.04 percent, for the same period in 2008.

Income Taxes

Income tax expense for the first nine months of 2009 was $6.6 million, compared to $5.9 million for the same period in 2008. The effective income tax rate for the first nine months of 2009 is 40.6 percent, compared to an effective tax rate of 38.9 percent for the first nine months of 2008. The Company estimates that $455,000 of merger-related costs in the nine months ended September 30, 2009, would not be tax-deductible, based on the nature and timing of those costs. The effective income tax rate, excluding the effects of non-deductible merger-related costs, for the first nine months of 2009 would have been 39.5 percent. The slight increase in effective income tax rate, excluding the effect of non-deductible merger-related costs, is the result of a greater portion of the Company’s pre-tax income being generated from entities in states with higher income tax rates.

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Financial Position, Liquidity and Capital Resources

Chesapeake’s capital requirements reflect the capital-intensive nature of its business and are principally attributable to its 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 nine months of 2009, net cash provided by operating activities was $47.5 million, cash used by investing activities was $19.7 million, and cash used by financing activities was $28.6 million. By comparison, during the first nine months of 2008, net cash provided by operating activities was $13.4 million, cash used by investing activities was $24.1 million, and cash provided by financing activities was $10.7 million.

The Board of Directors has authorized the Company to borrow up to $65.0 million of short-term debt, as required, from various banks and trust companies under short-term lines of credit. As of September 30, 2009, Chesapeake had four unsecured bank lines of credit with two financial institutions, totaling $90.0 million, none of which requires compensating balances. These bank lines are available to provide funds for the Company’s short-term cash needs to meet seasonal working capital requirements and to fund temporarily portions of its capital expenditures. 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 September 30, 2009 and December 31, 2008, was $10.1 million and $33.0 million, respectively. The large decrease in the Company’s outstanding balance of short-term borrowing during the first nine months of 2009 is due primarily 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 September 30, 2009, the Company had invested $19.1 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 September 30, 2009 and December 31, 2008:


	September 30, 2009				December 31, 2008
	(in Thousands, except percentages)

Long-term debt, net of current maturities	$	86,282	40	%	$	86,422	41	%
Stockholders’ equity	$	129,007	60	%	$	123,073	59	%

Total capitalization, excluding short-term debt	$	215,289	100	%	$	209,495	100	%

As of September 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 56 percent at September 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 September 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 follows:


For the Nine Months Ended September 30,	2009		2008			Change
Net Income	$	9,706	$	9,195		$	511
Non-cash adjustments to net income		18,311		15,428			2,883
Changes in assets and liabilities		19,435		(11,199	)		30,634

Net cash provided by operating activties	$	47,451	$	13,424		$	34,028

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 nine months of 2009, net cash flow provided by operating activities was $47.5 million, an increase of $34.0 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 due primarily to collections and payments from the Company’s natural gas and propane distribution operations coupled with lower commodity prices.

	•		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, accounts payable, and prepaid expenses.

	•		The net cash flows provided by natural gas and propane inventories were the result of lower commodity prices.

	•		Net cash flows generated by income tax receivables were due primarily 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 nine 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.

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Cash Flows Used in Investing Activities

Net cash flows used in investing activities totaled $19.7 million and $24.1 million during the nine months ended September 30, 2009 and 2008, respectively. Cash utilized for capital expenditures was $19.6 million and $23.7 million for the first nine months of 2009 and 2008, respectively. Additions to property, plant and equipment in the first nine months of 2009 were primarily for the natural gas segment ($17.4 million), the propane segment ($1.3 million), the advanced information services segment ($408,000), and the other operations segment ($487,000).

Cash Flows Used by Financing Activities

Cash flows used by financing activities totaled $28.6 million for the first nine months of 2009, compared to cash provided of $10.7 million for the same period in 2008. Significant financing activities included the following:

	•		During the first nine months of 2009, the Company had a net repayment of short-term debt of $23.4 million, compared to net borrowings of $16.2 million in the first nine months of 2008, as it generated higher amounts of cash from operating activities.

	•		The Company paid $5.9 million in cash dividends for the nine months ended September 30, 2009 and 2008. Dividends paid in the first nine months of 2009 increased as a result of growth in the annualized dividend rate and in the number of shares outstanding. These increases were offset by an increased number of shares issued from reserve balances in lieu of cash dividend payments pursuant to the Company’s Dividend Reinvestment Plan.

	•		The Company repaid $20,000 of long-term debt during the first nine months of 2009, compared to $1.0 million in the first nine 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 September 30, 2009, was $22.4 million, with the guarantees expiring on various dates in 2009 and 2010.

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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 September 30, 2009.


	Payments Due by Period
Purchase Obligations (in Thousands)	Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years		Total
Commodities ^{(1) (3)}	$	20,954	$	320		—		—	$	21,274
Propane ⁽²⁾		23,787		—		—		—		23,787

Total Purchase Obligations	$	44,741	$	320		—		—	$	45,061


⁽¹⁾		In addition to the obligations noted above, the natural gas distribution and propane distribution operations have agreements with commodity suppliers that have provisions with no minimum purchase requirements. There are no monetary penalties for reducing the amounts purchased; however, the propane contracts allow the suppliers to reduce the amounts available in the winter season if 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 $23.4 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 $450,000 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 4, “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 September 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 4, “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 September 30, 2009, compared to a fair value of $96.0 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 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. At July 31, 2009, the propane distribution operation had entered into a put agreement to protect the Company from the impact of price decreases on our price-cap plan that the Company offers to customers. The Company considered this put agreement an economic hedge that did not qualify for hedge accounting. As of September 30, 2009, the Company marked the put agreement to market, which resulted in an unrealized loss of $76,000.

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


	Quantity in		Estimated Market		Weighted Average
At September 30, 2009	Gallons		Prices		Contract Prices
Forward Contracts
Sale		26,098,800	$	0.6900 — $0.9950	$	0.8962
Purchase		26,590,200	$	0.6650 — $0.9975	$	0.8946

Estimated 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 September 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:


	September 30,		December 31,
(in thousands)	2009		2008
Mark-to-market energy assets	$	1,532	$	4,482
Mark-to-market energy liabilities	$	1,484	$	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 September 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 September 30, 2009.

Changes in Internal Control Over Financial Reporting

During the quarter ended September 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 4, “Commitments and Contingencies,” of these unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q, the Company is involved in certain legal actions and claims arising in the normal course of business. The Company is also involved in certain legal and administrative proceedings before various government agencies concerning rates. In the opinion of management, the ultimate disposition of these proceedings and claims will not have a material effect on the condensed consolidated financial position, results of operations or cash flows of the Company.


Item 1A.		Risk Factors

There 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 Plans
Period	Purchased		per Share		or Programs ⁽²⁾		or Programs ⁽²⁾
July 1, 2009 through July 31, 2009 ⁽¹⁾		527	$	33.30		—		—
August 1, 2009 through August 31, 2009		—	$	—		—		—
September 1, 2009 through September 30, 2009		—	$	—		—		—


Total		527	$	33.30		—		—


⁽¹⁾		Chesapeake purchased shares of stock on the open market for the purpose of reinvesting the dividend on deferred stock units held in the Rabbi Trust accounts for certain Directors and Senior Executives under the Deferred Compensation Plan. The Deferred Compensation Plan is discussed in detail in 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, 527 shares were purchased through the reinvestment of dividends on deferred stock units.

⁽²⁾		Except for the purposes described in Footnote (1), Chesapeake has not publicly announced plans or programs to repurchase its shares.


Item 3.		Defaults upon Senior Securities

None.


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

None.


Item 5.		Other Information

None.

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Item 6.		Exhibits


	2.1			Agreement and Plan of Merger between Chesapeake Utilities Corporation and Florida Public Utilities Company dated April 17, 2009, is incorporated herein by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K, filed April 20, 2009, File No. 001-11590.

	31.1			Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, dated November 6, 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 November 6, 2009.

	32.1			Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated November 6, 2009.

	32.2			Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated November 6, 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: November 6, 2009

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EXHIBIT INDEX


Exhibit No.		Description

	31.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, dated November 6, 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 November 6, 2009.

	32.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated November 6, 2009.

	32.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated November 6, 2009.

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CHESAPEAKE UTILITIES CORP - FORM 10-Q - November 6, 2009

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