CHESAPEAKE UTILITIES CORP - Quarter Report: 2009 March (Form 10-Q)

 

 

United States
Securities and Exchange Commission

Washington, D.C. 20549

 

FORM 10-Q

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

For the quarterly period ended: March 31, 2009

OR

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

For the transition period from  _____  to  _____ 

Commission File Number: 001-11590

Chesapeake Utilities Corporation

(Exact name of registrant as specified in its charter)

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

909 Silver Lake Boulevard, Dover, Delaware 19904

(302) 734-6799

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

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

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

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

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

Common Stock, par value $0.4867 — 6,855,640 shares outstanding as of April 30, 2009.

 

 

Table of Contents

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

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

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

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

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PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Chesapeake Utilities Corporation and Subsidiaries

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

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

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

Chesapeake Utilities Corporation and Subsidiaries

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

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

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

Chesapeake Utilities Corporation and Subsidiaries

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

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

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

Chesapeake Utilities Corporation and Subsidiaries

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

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

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

Chesapeake Utilities Corporation and Subsidiaries

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

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

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

Notes to Condensed Consolidated Financial Statements

1.

Basis of Presentation

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

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

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

2.

Calculation of Earnings Per Share

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

3.

Commitments and Contingencies

Rates and Regulatory Matters

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

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

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

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

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

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

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

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

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

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

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

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

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

Environmental Commitments and Contingencies

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

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

Salisbury Town Gas Light Site

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

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

Winter Haven Coal Gas Site

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

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

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

Other

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

Other Commitments and Contingencies

Natural Gas and Propane Supply

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

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

Corporate Guarantees

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

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

Application of SFAS No. 71

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

Other

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

4.

Recent Authoritative Pronouncements on Financial Reporting and Accounting

Recent accounting pronouncements:

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

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

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

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

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

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

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

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

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

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

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

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

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

5.

Segment Information

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

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

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

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

6.

Employee Benefit Plans

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

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

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

7.

Investments

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

8.

Share-Based Compensation

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

The table below presents the amounts included in net income related to share-based compensation expense for the awards granted under the DSCP and the PIP for the three months ended March 31, 2009, and 2008.

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

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

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

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

9.

Derivative Instruments

The Company uses derivative and non-derivative contracts to manage the risks related to obtaining adequate supplies and the price fluctuations of natural gas and propane and to engage in trading activities. The Company’s natural gas and propane distribution operations have entered into agreements with suppliers to purchase natural gas and propane for resale to their customers. Purchases under these contracts either do not meet the definition of derivatives under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” or are considered “normal purchases and sales” under SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities — an amendment of SFAS No. 133,” and are accounted for on an accrual basis. The Company’s propane distribution operation may also enter into fair value hedges of its inventory in order to mitigate the impact of wholesale price fluctuations. As of March 31, 2009, the Company’s natural gas and propane distribution operations did not have any outstanding derivative contracts.

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

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

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

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

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

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

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

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

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

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

10.

Fair Value of Financial Instruments

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

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

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

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

The following table summarizes the Company’s financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements by level within the fair value hierarchy used at March 31, 2009:

							Fair Value Measurements Using:
										Significant
										Other				Significant
						Quoted Prices in				Observable				Unobservable
						Active Markets				Inputs				Inputs
(in thousands)		Fair Value				(Level 1)				(Level 2)				(Level 3)
Assets:
Investments		$	1,473			$	1,473				—				—
Mark-to-market energy assets		$	453				—			$	453				—
Liabilities:
Mark-to-market energy liabilities		$	317				—			$	317				—

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

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

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

Level 1 Fair Value Measurements:

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

Level 2 Fair Value Measurements:

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

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

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

11.

Subsequent Event

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

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations is designed to provide a reader of the financial statements with a narrative report on the Company’s financial condition, results of operations and liquidity. This discussion and analysis should be read in conjunction with the attached unaudited condensed consolidated financial statements and notes thereto and Chesapeake’s Annual Report on Form 10-K for the year ended December 31, 2008, including the audited consolidated financial statements and notes contained in the Annual Report on Form 10-K.

Safe Harbor for Forward-Looking Statements

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

	•		the temperature sensitivity of the natural gas and propane businesses;
	•		the effects of spot, forward, futures market prices, and the Company’s use of derivative instruments on the Company’s distribution, wholesale marketing and energy trading businesses;
	•		the amount and availability of natural gas and propane supplies;
	•		the access to interstate pipelines’ transportation and storage capacity and the construction of new facilities to support future growth;

	•		the effects of natural gas and propane commodity price changes on the operating costs and competitive positions of our natural gas and propane distribution operations;
	•		the impact that declining propane prices may have on the valuation of our propane inventory;
	•		third-party competition for the Company’s unregulated and regulated businesses;
	•		changes in federal, state or local regulation and tax requirements, including deregulation;
	•		changes in technology affecting the Company’s advanced information services segment;
	•		changes in credit risk and credit requirements affecting the Company’s energy marketing subsidiaries;
	•		the effects of accounting changes;
	•		changes in benefit plan assumptions, return on plan assets, and funding requirements;
	•		cost of compliance with environmental regulations or the remediation of environmental damage;
	•		the effects of general economic conditions, including interest rates, on the Company and its customers;
	•		the impact of the volatility in the financial and credit markets on the Company’s ability to access credit;
	•		the ability of the Company’s new and planned facilities and acquisitions to generate expected revenues;
	•		the ability of the Company to construct facilities at or below estimated costs;
	•		the Company’s ability to obtain the rate relief and cost recovery requested from utility regulators and the timing of the requested regulatory actions;
	•		the Company’s ability to obtain necessary approvals and permits from regulatory agencies on a timely basis;
	•		the impact of inflation on the results of operations, cash flows, financial position and on the Company’s planned capital expenditures;
	•		inability to access the financial markets to a degree that may impair future growth; and
	•		operating and litigation risks that may not be covered by insurance.

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

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:

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

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

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

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

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enhancing marketing channels to attract new customers;

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providing reliable and responsive service to retain existing customers;

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

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maintaining a consistent and competitive dividend for shareholders.