Edgar Filing: CHESAPEAKE UTILITIES CORP

submission1q08.htm

United States

Securities and Exchange Commission

Washington, D.C. 20549

_______________________________

FORM 10-Q

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

For the quarterly period ended: March 31, 2008

[ ]	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	(I.R.S. Employer
incorporation or organization)	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 [X] No [ ]

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 “accelerated filer” and “large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer [ ] Accelerated filer [X] Non-accelerated filer [ ] Smaller reporting company [ ]

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

Common Stock, par value $0.4867 — 6,808,662 shares outstanding as of April 30, 2008.

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	14
	Item 3. Quantitative and Qualitative Disclosures about Market Risk	23
	Item 4. Controls and Procedures	23
PART II — OTHER INFORMATION		24
	Item 1. Legal Proceedings	24
	Item 1A. Risk Factors	24
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	24
	Item 3. Defaults upon Senior Securities	24
	Item 4. Submission of Mattters to a Vote of Security Holders	24
	Item 5. Other Information	24
	Item 6. Exhibits	24
SIGNATURES		25

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PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Income (Unaudited)


For the Three Months Ended March 31,	2008		2007
Operating Revenues	$	100,273,502	$	93,526,891
Operating Expenses
Cost of sales, excluding costs below		70,980,181		63,935,868
Operations		11,223,745		10,529,743
Maintenance		479,283		580,165
Depreciation and amortization		1,754,524		2,315,796
Other taxes		1,795,054		1,551,748
Total operating expenses		86,232,787		78,913,320
Operating Income		14,040,715		14,613,571
Other income, net of other expenses		17,591		56,482
Interest charges		1,593,371		1,599,250
Income Before Income Taxes		12,464,935		13,070,803
Income taxes		4,890,592		5,059,323
Income from Continuing Operations		7,574,343		8,011,480
Loss from discontinued operations,
net of tax benefit of $0 and $14,236		-		(20,392	)
Net Income	$	7,574,343	$	7,991,088

Weighted Average Shares Outstanding:
Basic		6,795,309		6,705,829
Diluted		6,907,124		6,820,462
Earnings Per Share of Common Stock:
Basic:
From continuing operations	$	1.11	$	1.19
From discontinued operations		-		-
Net Income	$	1.11	$	1.19
Diluted:
From continuing operations	$	1.10	$	1.18
From discontinued operations		-		-
Net Income	$	1.10	$	1.18

Cash Dividends Declared Per Share of Common Stock:	$	0.295	$	0.290

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

Page 1

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

For the Three Months Ended March 31,	2008	2007

Operating Activities
Net Income	$7,574,343	$7,991,088
Depreciation and amortization	1,754,524	2,315,795
Depreciation and accretion included in other costs	824,061	837,624
Deferred income taxes, net	511,961	(956,532)
Unrealized loss (gain) on commodity contracts	174,432	(233,596)
Unrealized loss (gain) on investments	77,533	(27,956)
Employee benefits and compensation	76,806	455,521
Other, net	1,811	(839)
Changes in assets and liabilities:
Purchase of investments	(16,639)	(27,014)
Accounts receivable and accrued revenue	129,159	(879,644)
Propane inventory, storage gas and other inventory	6,691,361	7,601,692
Regulatory assets	13,450	673,854
Prepaid expenses and other current assets	1,001,627	1,066,292
Other deferred charges	(300,855)	(703,099)
Long-term receivables	94,122	33,654
Accounts payable and other accrued liabilities	(13,070,730)	(6,184,675)
Income taxes receivable	4,111,676	3,695,290
Accrued interest	681,632	880,420
Customer deposits and refunds	(1,514,215)	(1,125,068)
Accrued compensation	(1,690,909)	(958,133)
Regulatory liabilities	154,132	2,481,819
Other liabilities	7,715	(15,222)
Net cash provided by operating activities	7,286,997	16,921,271

Investing Activities
Property, plant and equipment expenditures	(4,411,890)	(8,357,391)
Environmental expenditures	(128,600)	(68,284)
Net cash used by investing activities	(4,540,490)	(8,425,675)

Financing Activities
Common stock dividends	(1,791,115)	(1,724,536)
Issuance of stock for Dividend Reinvestment Plan	15,339	66,007
Purchase of treasury stock	(176,947)	-
Change in cash overdrafts due to outstanding checks	(497,571)	1,299,731
Net borrowing (repayment) under line of credit agreements	1,019,892	(7,329,054)
Repayment of long-term debt	(1,020,039)	(1,020,069)
Net cash used by financing activities	(2,450,441)	(8,707,921)

Net Increase (decrease) in Cash and Cash Equivalents	296,066	(212,325)
Cash and Cash Equivalents — Beginning of Period	2,592,802	4,488,366
Cash and Cash Equivalents — End of Period	$2,888,868	$4,276,041

Supplemental Disclosures of Non-Cash Investing Activities:
Property, plant and equipment acquired on account,
but not paid as of March 31	$347,820	$1,219,839

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

Page 2

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Stockholders' Equity (Unaudited)

	For the Three Months Ended March 31, 2008	For the Twelve Months Ended December 31, 2007

Common Stock
Balance — beginning of period	$3,298,473	$3,254,998
Dividend Reinvestment Plan	3,541	17,197
Retirement Savings Plan	1,074	14,388
Conversion of debentures	371	3,945
Performance shares and options exercised	9,166	7,945
Balance — end of period	$3,312,625	$3,298,473

Additional Paid-in Capital
Balance — beginning of period	$65,591,552	$61,960,220
Dividend Reinvestment Plan	219,563	1,121,190
Retirement Savings Plan	66,704	934,295
Conversion of debentures	12,590	133,839
Stock-based compensation	(188,558)	1,442,008
Balance — end of period	$65,701,851	$65,591,552

Retained Earnings
Balance — beginning of period	$51,538,194	$46,270,884
Net income	7,574,343	13,197,710
Cash dividends declared	(2,007,914)	(7,930,400)
Balance — end of period	$57,104,623	$51,538,194

Accumulated Other Comprehensive Loss
Balance — beginning of period	($851,674)	($334,550)
Loss on funded status of Employee Benefit Plans, net of tax	-	(517,124)
Balance — end of period	($851,674)	($851,674)

Deferred Compensation Obligation
Balance — beginning of period	$1,403,922	$1,118,509
New deferrals	44,310	285,413
Balance — end of period	$1,448,232	$1,403,922

Treasury Stock
Balance — beginning of period	($1,403,922)	($1,118,509)
New deferrals related to compensation obligation	(44,310)	(285,413)
Purchase of treasury stock (1)	(193,853)	(29,771)
Sale and distribution of treasury stock (2)	193,853	29,771
Balance — end of period	($1,448,232)	($1,403,922)


Total Stockholders’ Equity	$125,267,425	$119,576,545

(1) Amount includes shares purchased in the open market for the Company's Rabbi Trust to secure its
obligations under the Company's Deferred Compensation Plan and to fund its Retirement Savings Plan.
(2) Amount includes shares issued to the Company's Rabbi Trust as an obligation under the Deferred
Compensation Plan and to fund its Retirement Savings Plan.

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

Page 3

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

Assets	March 31, 2008	December 31, 2007

Property, Plant and Equipment
Natural gas	$292,502,187	$289,706,066
Propane	49,368,064	48,506,231
Advanced information services	1,175,080	1,157,808
Other plant	9,325,062	8,567,833
Total property, plant and equipment	352,370,393	347,937,938
Less: Accumulated depreciation and amortization	(94,287,329)	(92,414,289)
Plus: Construction work in progress	4,681,713	4,899,608
Net property, plant and equipment	262,764,777	260,423,257

Investments	1,848,377	1,909,271

Current Assets
Cash and cash equivalents	2,888,868	2,592,801
Accounts receivable (less allowance for uncollectible
accounts of $900,830 and $952,075, respectively)	72,478,022	72,218,191
Accrued revenue	4,876,484	5,265,474
Propane inventory, at average cost	5,664,495	7,629,295
Other inventory, at average cost	1,220,190	1,280,506
Regulatory assets	1,355,059	1,575,072
Storage gas prepayments	1,375,925	6,042,169
Income taxes receivable	-	1,237,438
Deferred income taxes	2,397,087	2,155,393
Prepaid expenses	2,494,694	3,496,517
Mark-to-market energy assets	322,799	7,812,456
Other current assets	146,448	146,253
Total current assets	95,220,071	111,451,565

Deferred Charges and Other Assets
Goodwill	674,451	674,451
Other intangible assets, net	174,622	178,073
Long-term receivables	646,558	740,680
Regulatory assets	2,728,020	2,539,235
Other deferred charges	3,928,526	3,640,480
Total deferred charges and other assets	8,152,177	7,772,919




Total Assets	$367,985,402	$381,557,012

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

Page 4

Capitalization and Liabilities	March 31, 2008	December 31, 2007

Capitalization
Stockholders' equity
Common Stock, par value $0.4867 per share
(authorized 12,000,000 shares)	$3,312,625	$3,298,473
Additional paid-in capital	65,701,851	65,591,552
Retained earnings	57,104,623	51,538,194
Accumulated other comprehensive loss	(851,674)	(851,674)
Deferred compensation obligation	1,448,232	1,403,922
Treasury stock	(1,448,232)	(1,403,922)
Total stockholders' equity	125,267,425	119,576,545

Long-term debt, net of current maturities	63,222,636	63,255,636
Total capitalization	188,490,061	182,832,181

Current Liabilities
Current portion of long-term debt	6,656,364	7,656,364
Short-term borrowing	46,186,265	45,663,944
Accounts payable	41,700,860	54,893,071
Customer deposits and refunds	8,522,705	10,036,920
Accrued interest	1,547,136	865,504
Dividends payable	2,007,948	1,999,343
Income taxes payable	2,874,238	-
Accrued compensation	1,709,203	3,400,112
Regulatory liabilities	6,461,459	6,300,766
Mark-to-market energy liabilities	318,249	7,739,261
Other accrued liabilities	2,709,742	2,500,542
Total current liabilities	120,694,169	141,055,827

Deferred Credits and Other Liabilities
Deferred income taxes	29,549,540	28,795,885
Deferred investment tax credits	267,129	277,698
Regulatory liabilities	1,025,980	1,136,071
Environmental liabilities	792,296	835,143
Other pension and benefit costs	2,524,503	2,513,030
Accrued asset removal cost	20,772,783	20,249,948
Other liabilities	3,868,941	3,861,229
Total deferred credits and other liabilities	58,801,172	57,669,004

Other Commitments and Contingencies (Note 4)


Total Capitalization and Liabilities	$367,985,402	$381,557,012

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

Page 5

Notes to Condensed Consolidated Financial Statements

1.	Basis of Presentation

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

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and United States of America Generally Accepted Accounting Principles (“GAAP”). In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in the Company’s latest Annual Report on Form 10-K filed with the SEC on March 10, 2008. 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 presente

2.	Comprehensive Income

Comprehensive income contains items that are excluded from net income and recorded directly to stockholders’ equity. Chesapeake did not have any adjustments to comprehensive income that are required to be reported by Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 130, “Reporting Comprehensive Income,” for the first quarters of 2008 and 2007. Accumulated other comprehensive loss was $851,674 at March 31, 2008 and December 31, 2007.

3.	Calculation of Earnings Per Share


For the Three Months Ended March 31,	2008	2007

Calculation of Basic Earnings Per Share:
Net Income	$7,574,343	$7,991,088
Weighted average shares outstanding	6,795,309	6,705,829
Basic Earnings Per Share	$1.11	$1.19

Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$7,574,343	$7,991,088
Effect of 8.25% Convertible debentures (1)	22,808	24,200
Adjusted numerator — Diluted	$7,597,151	$8,015,288

Reconciliation of Denominator:
Weighted shares outstanding — Basic	6,795,309	6,705,829
Effect of dilutive securities (1):
Restricted Stock	4,669	-
8.25% Convertible debentures	107,146	114,633
Adjusted denominator — Diluted	6,907,124	6,820,462

Diluted Earnings Per Share	$1.10	$1.18

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

Page 6

4.	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 Commissions (“PSC”). Eastern Shore Natural Gas Company (“Eastern Shore”), the Company’s natural gas transmission operation, is subject to regulation by the Federal Energy Regulatory Commission (“FERC”).

Delaware. On July 6, 2007, the Company filed with the Delaware PSC an application seeking approval of the following: (i) participation by the Company’s Delaware commercial and industrial customers in transportation buying pools served by third-party natural gas marketers; (ii) an annual base rate adjustment of $1,896,000 that represents approximately a 3.25 percent rate increase on average for the Delaware division’s firm customers; (iii) an alternative rate design for residential customers in a defined expansion area in eastern Sussex County, Delaware; and (iv) a revenue normalization mechanism that reduces the impact of natural gas consumption on both customers and the Company. As an incentive for the Delaware division to make the significant capital investments to serve the growing areas of eastern Sussex County in support of Delaware’s Energy Policy, the Company has proposed as part of the filing that the Delaware division be permitted to earn a return on equity up to 15 percent. This level of return would ensure that the Company’s investors are adequately compensated for the increased risk associated with the higher levels of capital investment necessary to provide natural gas in those growing areas. On August 21, 2007, the Delaware PSC authorized the Company to implement charges reflecting the proposed $1,896,000 increase effective September 4, 2007, on a temporary basis and subject to refund, pending the completion of full evidentiary hearings and a final decision by the Delaware PSC. The Delaware PSC Staff filed testimony recommending a rate decrease of $693,245. The Delaware Public Advocate (“DPA”) recommended a rate decrease of $588,670. Neither party recommended approval of the Delaware division’s other proposals mentioned above. The Delaware division strongly disagreed with these positions in its rebuttal which was filed on February 7, 2008. Evidentiary hearings, which began in March 2008, have been suspended until May 7, 2008, in order to provide the parties an opportunity to continue settlement discussions. The Delaware division anticipates a final decision by the Delaware PSC during the second quarter of 2008.

On September 10, 2007, the Company filed with the Delaware PSC its annual Gas Service Revenue (“GSR”) Application, seeking approval to change its GSR rates effective for service rendered on and after November 1, 2007. On October 2, 2007, the Delaware PSC authorized the Company to implement the GSR charges on a temporary basis and 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 during the second or third quarter of 2008.

On November 1, 2007, the Delaware division filed with the Delaware PSC its annual Environmental Rider (“ER”) rate application to become effective for service rendered on and after December 1, 2007. The Delaware PSC granted approval of the ER rate at its regularly scheduled meeting on November 20, 2007, subject to full evidentiary hearings and a final decision. On February 5, 2008, the Delaware PSC granted final approval of the ER rates as filed. No future ER rate applications will be filed by the Delaware division as all of the division’s environmental expenses, which are subject to recovery pursuant to the ER recovery mechanism, will have been collected by the end of the determination period. The recovery of ER charges will cease to appear on the Delaware division’s customers’ bills as of November 30, 2008.

Maryland. On September 26, 2006, the Maryland PSC approved a base rate increase for the Maryland division of approximately $780,000 annually. In a settlement agreement entered into in that proceeding, the Maryland division was required to file a depreciation study, which was filed on April 9, 2007. The Maryland division filed formal testimony on July 10, 2007, initiating a Phase II of this proceeding. In this filing, the Maryland division proposed a rate decrease of approximately $80,000 annually, resulting from a change in depreciation expense. On November 29, 2007 the Maryland PSC approved a settlement agreement for a rate decrease of $132,155, effective December 1, 2007, based on the change in the Company’s depreciation rates.

On December 17, 2007, the 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, 2007. No issues were raised at the hearing. On February 7, 2008, the Maryland PSC granted final approval without taking any exceptions to the Maryland division’s four quarterly gas cost recovery filings.

Florida. In compliance with the Florida Administrative Code, the Florida division filed its 2007 Depreciation Study (“Study”) with the Florida PSC on May 17, 2007. This study, which supersedes the last study performed in 2002, provides the Florida PSC with the opportunity to review and address changes in plant and equipment lives, salvage values, reserves and resulting life depreciation rates. The Florida division responded to interrogatories concerning the Study on October 15 and December 24, 2007. While the Company cannot predict the outcome of the Florida PSC’s review at this time, the Company anticipates a final decision regarding the depreciation rates in the second quarter of 2008.

Eastern Shore. Eastern Shore had the following regulatory activity with the FERC regarding the expansion of its transmission system:

System Expansion 2006 – 2008. On November 15, 2007 Eastern Shore requested FERC authorization to commence construction of facilities (approximately 9.2 miles) included in the third phase of the 2006-08 System Expansion. The FERC granted this authorization on January 7, 2008. Construction began in the first quarter of 2008, and the facilities are to be completed and placed in service by November 1, 2008. These Phase III facilities will provide 5,650 Dekatherms (“Dts”) of additional firm service capacity per day and annualized gross margin contribution of approximately $1.0 million, instead of $1.6 million, an amount based on 10,850 Dts of additional firm service capacity per day projected from these services in the original filing.

Eastern Shore Energylink Expansion Project (“E3 Project”). In 2006, Eastern Shore proposed to develop, construct and operate approximately 75 miles of new pipeline facilities to transport natural gas from 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 Eastern Shore’s existing facilities in Sussex County, Delaware.

On May 31, 2006, Eastern Shore entered into Precedent Agreements (the “Precedent Agreements”) with Delmarva Power & Light Company (“Delmarva”) and Chesapeake, through its Delaware and Maryland divisions, to provide additional firm transportation services upon completion of the E3 Project. Both Chesapeake and Delmarva are parties to existing firm natural gas transportation service agreements with Eastern Shore, and each desires additional firm transportation service under the E3 Project, as evidenced by the Precedent Agreements. Pursuant to the Precedent Agreements, the parties agreed to proceed with the required initiatives to obtain the governmental and regulatory authorizations necessary for Eastern Shore to provide, and for Chesapeake and Delmarva to utilize, additional firm transportation service under the E3 Project.

As part of the Precedent Agreements, Eastern Shore, Chesapeake and Delmarva also entered into Letter Agreements which provide that, if the E3 Project is not certificated and placed in service, Chesapeake and Delmarva will each pay its proportionate share of certain pre-certification costs by means of a negotiated surcharge over a period of not less than 20 years.

In furtherance of the E3 Project, Eastern Shore submitted a petition to the FERC on June 27, 2006 seeking approval of the pre-construction cost agreements as part of a rate-related Settlement Agreement (the “Settlement Agreement”), which would provide benefits to Eastern Shore and its customers, including but not limited to: (1) advancement of a necessary infrastructure project to meet the growing demand for natural gas on the Delmarva Peninsula; (2) sharing of project development costs by the participating customers in the project; and (3) no development cost risk for non-participating customers. On August 1, 2006, the FERC approved the Settlement Agreement. On September 6, 2006, Eastern Shore submitted to FERC proposed tariff sheets to implement the provisions of the Settlement Agreement. By Letter Order dated October 6, 2006, the FERC accepted the tariff sheets, effective September 7, 2006.

On April 23, 2007, Eastern Shore submitted to the FERC its request to commence a pre-filing process, and on May 15, 2007, the FERC notified Eastern Shore that its request had been approved. The pre-filing process is intended to engage all interested and affected stakeholders early in the process with the intention of resolving all environmental issues prior to the formal certificate application being filed. As part of this process, Eastern Shore has performed environmental, engineering and cultural surveys and studies in the interest of protecting the environment, minimizing any potential impacts to landowners, and cultural resources. Eastern Shore has also held meetings with federal, state and local permitting/regulatory agencies, non-governmental organizations, landowners, and other interested stakeholders.

Page 7

As part of an updated engineering study, Eastern Shore 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, Eastern Shore explored all potential construction methods, construction cost mitigation strategies, potential design changes and project schedule changes. Eastern Shore also held discussions and meetings with several potential new customers, who have expressed an interest in the project that would expand its size and likely have significant impact on the cost, timeline and in-service date.

On December 20, 2007, Eastern Shore withdrew from the pre-filing process as a result of insufficient customer commitments for capacity to make the project economical. Eastern Shore 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 project.

If Eastern Shore decides to abandon the E3 Project, it will initiate billing of pre-certification costs surcharge in accordance with the terms of the Precedent Agreements executed with two of its customers, which provide for these customers to reimburse Eastern Shore 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, the Company had incurred $3.18 million of pre-certification costs relating to the E3 Project.

Eastern Shore also had developments in the following FERC rate matters:

On June 6, 2007, Eastern Shore and interested parties reached a settlement agreement in principle on its base rate proceeding filed with the FERC on October 31, 2006. The negotiated settlement provides for an annual cost of service of $21,536,000, which reflects a pretax return on equity of 13.6 percent and a rate increase of approximately $1.07 million on an annual basis. On September 10, 2007, Eastern Shore submitted its Settlement Offer to the Presiding Administrative Law Judge (“ALJ”) for review and certification to the full Commission.

Eastern Shore filed concurrently with its Settlement Agreement a Motion to place the settlement rates into effect on September 1, 2007, in order to expedite the implementation of the reduced settlement rates pending final approval of the settlement. The Commission issued an order on September 25, 2007, authorizing Eastern Shore to commence billing its settlement rates effective September 1, 2007.

On October 1, 2007, the Presiding ALJ forwarded to the full Commission an order certifying the uncontested Settlement Agreement as fair, reasonable, and in the public interest. A final Commission Order approving the settlement was issued on January 31, 2008. In compliance with the Settlement Agreement, refunds, inclusive of interest, totaling $1.26 million, based on the higher interim rates that were effective for the period from May 15, 2007 through August 31, 2007, were distributed to Eastern Shore’s customers on February 1, 2008.

Environmental Matters

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.

In 2004, Chesapeake received a Certificate of Completion for the remedial work performed at a former manufactured gas plant site located in Dover, Delaware. Chesapeake is also currently participating in the investigation, assessment or remediation of two additional former manufactured gas plant sites located in Maryland and Florida. The Company has accrued liabilities for the three sites referred to, respectively, as the Dover Gas Light, Salisbury Town Gas Light and the Winter Haven Coal Gas sites. The Company has been in discussions with the Maryland Department of the Environment (“MDE”) regarding a fourth former manufactured gas plant site located in Cambridge, Maryland. The following discussion provides details of each site.

Dover Gas Light Site

The Dover Gas Light site is a former manufactured gas plant site located in Dover, Delaware. On January 15, 2004, the Company received a Certificate of Completion of Work from the United States Environmental Protection Agency (“EPA”) regarding this site. This concluded Chesapeake’s remedial action obligation related to this site and relieves Chesapeake from liability for future remediation at the site, unless previously unknown conditions are discovered at the site, or information previously unknown to the EPA is received that indicates the remedial action that has been taken is not sufficiently protective. These contingencies are standard and are required by the EPA in all liability settlements.

The Company has reviewed its remediation costs incurred to date for the Dover Gas Light site and has concluded that all costs incurred have been paid. The Company does not expect any future environmental expenditure for this site. Through March 31, 2008, the Company has incurred approximately $9.67 million in costs related to environmental testing and remedial action studies at the site. Approximately $9.96 million has been recovered through March 2008 from other parties or through rates. As of March 31, 2008, a regulatory liability of approximately $294,500, representing the over-recovery portion of the clean-up costs, has been recorded. The over-recovery is temporary and will be refunded by the Company to customers in future rates.

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 and began Air Sparging and Soil-Vapor Extraction (“AS/SVE”) remediation procedures. Chesapeake has been reporting 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 that is being maintained for continued product monitoring and recovery. Chesapeake has requested a No Further Action determination and is awaiting such a determination from the MDE.

Through March 31, 2008, the Company has incurred approximately $2.9 million for remedial actions and environmental studies at the Salisbury Town Gas Light site. Of this amount, approximately $1.94 million has been recovered through insurance proceeds or in rates. On September 26, 2006, the Company received approval from the Maryland Public Service Commission to recover, through its rates charged to customers, the remaining $991,000 of the incurred environmental remediation costs.

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, 2008, the Company has incurred approximately $1.9 million of environmental costs associated with this site. At March 31, 2008, the Company had accrued a liability of $792,000 related to this site, offsetting (a) $41,000 collected through rates in excess of costs incurred and (b) a regulatory asset of approximately $833,000, 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 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 plans to oppose any requirement that it undertake corrective measures in the offshore sediments. Chesapeake 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 Company is in discussions with the MDE regarding a manufactured gas plant site located in Cambridge, Maryland. The outcome of this matter cannot be determined at this time; therefore, the Company has not recorded an environmental liability for this location.

Page 8

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 gas from various suppliers. The contracts have various expiration dates. In March 2008, 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 new contract expires on March 31, 2009.

Corporate Guarantees

The Company has issued corporate guarantees to certain vendors of its propane wholesale marketing subsidiary and its Florida natural gas supply management subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of either subsidiary’s default. Neither of these subsidiaries has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in the Consolidated Financial Statements when incurred. The aggregate amount guaranteed at March 31, 2008 was $22.2 million, with the guarantees expiring on various dates in 2008 and the first quarter of 2009.

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, 2008. 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, 2008.

Internal Revenue Service Audit

In November 2007, the Company was notified by the Internal Revenue Service (“IRS”) that its consolidated federal income tax return for the year ended December 31, 2005 has been selected for examination. The IRS audit is ongoing and is expected to be completed in the second quarter of 2008. The outcome of this audit cannot be determined at this time; therefore, the Company has not recorded any reserves for potential assessments that may result from the examination.

Application of SFAS No. 71

Certain assets and liabilities of the Company are accounted for in accordance with SFAS No. 71 ¾ “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 provides guidance for public utilities and other regulated operations where the rates (prices) charged to customers are subject to regulatory review and approval. Regulators sometimes include allowable costs in a period other than the period in which the costs would be charged to expense by an unregulated enterprise. That procedure can create assets, reduce assets, or create liabilities for the regulated enterprise. For financial reporting, an incurred cost for which a regulator permits recovery in a future period is accounted for like an incurred cost that is reimbursable under a cost-reimbursement type contract. The Company believes that all regulatory assets as of March 31, 2008 are probable of recovery through rates. 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 consolidated financial position, results of operations or cash flows of the Company.

5.	Recent Authoritative Pronouncements on Financial Reporting and Accounting

Recent accounting pronouncements:

In December 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 141 (revised 2007) “Business Combinations” (“SFAS 141(R)”). SFAS 141(R) retains the fundamental requirements of the original pronouncement requiring that the purchase method be used for all business combinations. SFAS 141(R) defines the acquirer as the entity that obtains control of one or more businesses in the business combination, establishes the acquisition date as the date that the acquirer achieves control and requires the acquirer to recognize the assets acquired, liabilities assumed and any non-controlling interest at their fair values as of the acquisition date. SFAS 141(R) also requires that acquisition-related costs be recognized separately from the acquisition. SFAS 141(R) is effective for fiscal years beginning after December 15, 2008. The Company does not expect the adoption of SFAS 141(R) to have a material impact on its current consolidated financial position and results of operations. However, depending upon the size, nature and complexity of future acquisition transactions, the adoption of SFAS 141(R) could materially impact the Company’s consolidated financial statements.

In December 2007, the FASB issued FASB Statement 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 is effective for fiscal years beginning after December 15, 2008. No other entity has a minority interest in any of the Company’s subsidiaries; therefore, the Company does not expect the adoption of SFAS 160 to have an impact on its current 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, including those used in hedging activities. It is effective for fiscal years and interim periods beginning after November 15, 2008, and will be applicable to the Company in the first quarter of fiscal 2009. The Company is assessing the potential impact that the adoption of SFAS 161 may have on its financial statements.

Page 9

During the first quarter of 2008, the Company adopted the following accounting standards:

Effective January 1, 2008, Chesapeake adopted FSP No. FIN 39-1, “Amendment of FASB Interpretation No. 39” (“FSP FIN 39-1”). FSP FIN 39-1 modifies FIN No. 39, “Offsetting of Amounts Related to Certain Contracts,” and permits companies to offset cash collateral receivables or payables with net derivative positions under certain circumstances. Based on the derivative contracts entered into to date, the adoption of this FSP did not have a material effect on our consolidated financial statements.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 provides guidance for using fair value to measure assets and liabilities. It also responds to investors’ requests for expanded information about the extent to which companies’ measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. SFAS No. 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value and does not expand the use of fair value in any new circumstances. In February 2008, the FASB issued FASB Staff Position 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13” (“FSP 157-1”) and FSP 157-2, “Effective Date of FASB Statement No. 157” (“FSP 157-2”). FSP 157-1 amends SFAS No. 157 to remove certain leasing transactions from its scope. FSP 157-2 delays the effective date of SFAS No. 157 until fiscal years beginning after November 15, 2009 for all non-financial assets and non-financial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis. These nonfinancial items include assets and liabilities such as reporting units measured at fair value in a goodwill impairment test and nonfinancial assets acquired and liabilities assumed in a business combination. SFAS No. 157 was effective for financial statements issued for fiscal years beginning after November 15, 2007 and was adopted by the Company, as it applies to its financial instruments, effective January 1, 2008. The adoption of SFAS No. 157 did not have any financial impact on the Company’s consolidated financial statements. The disclosures required by SFAS 157 are discussed in Note 11 – Fair Value of Financial Instruments of the unaudited Condensed Consolidated Financial Statements.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115,” which permits entities to elect to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. This election is irrevocable. SFAS No. 159 was effective in the first quarter of fiscal 2008. The Company has not elected to apply the fair value option to any of its financial instruments.

6.	Segment Information

Chesapeake 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. The table excludes financial data related to our distributed energy company, which was reclassed to discontinued operations for each period presented. The impact of discontinued operations is discussed within Note 12 “Discontinued Operations” of the unaudited Condensed Consolidated Financial Statements.

Page 10



For the Three Months Ended March 31,		2008	2007
Operating Revenues, Unaffiliated Customers
	Natural gas	$68,822,530	$65,431,604
	Propane	27,807,801	24,922,400
	Advanced information services	3,643,171	3,172,887
	Other	-	-
Total operating revenues, unaffiliated customers		$100,273,502	$93,526,891
Intersegment Revenues (1)
	Natural gas	$105,853	$78,063
	Propane	1,349	406
	Advanced information services	7,969	132,236
	Other	163,073	154,623
Total intersegment revenues		$278,244	$365,328
Operating Income
	Natural gas	$10,469,024	$9,615,981
	Propane	3,444,135	4,873,555
	Advanced information services	37,863	48,820
	Other and eliminations	89,693	75,215
Total operating income		$14,040,715	$14,613,571

Other Income		17,591	56,482
Interest Charges		1,593,371	1,599,250
Income Taxes		4,890,592	5,059,323
Net income from continuing operations		$7,574,343	$8,011,480

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


		March 31,	December 31,
		2008	2007
Identifiable Assets
	Natural gas	$270,609,417	$273,500,890
	Propane	84,595,739	94,966,212
	Advanced information services	2,533,216	2,507,910
	Other	10,198,291	10,533,511
Total identifiable assets		$367,936,663	$381,508,523

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 revenues.

Page 11

7.	Employee Benefit Plans

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

	Defined Benefit		Executive Excess Defined		Other Post-Retirement
	Pension Plan		Benefit Pension Plan		Benefits
For the Three Months Ended March 31,	2008	2007	2008	2007	2008	2007
Service Cost	$ -	$ -	$ -	$ -	$ 896	$ 2,528
Interest Cost	148,431	155,514	31,381	30,840	27,564	23,234
Expected return on plan assets	(156,475)	(174,100)	-	-	-	-
Amortization of prior service cost	(1,175)	(1,175)	-	-	-	-
Amortization of net loss	-	-	11,611	12,934	46,215	41,640
Net periodic (benefit) cost	$ (9,219)	$ (19,761)	$ 42,992	$ 43,774	$ 74,675	$ 67,402

As disclosed in the December 31, 2007 financial statements, no contributions are expected to be required in 2008 for the defined benefit pension plan. The cost of the executive excess defined benefit pension plan and the other post-retirement benefit plans are unfunded and are expected to be paid out of the general funds of the Company. Cash benefits paid under the executive excess defined benefit pension plan for the three months ended March 31, 2008 were $22,300; for the year 2008, such benefits paid are expected to be $89,200. Cash benefits paid for other post-retirement benefits, primarily for medical claims, for the three months ended March 31, 2008, totaled $25,500; for the year 2008, the Company has estimated that such benefits to be paid are $196,000.

8.	Investments

The investment balances at March 31, 2008 represent 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 of classifying them as trading securities, the Company is required to report the securities at their fair value, with any unrealized gains and losses included in other income. The Company also has an associated liability that is recorded and adjusted each month for the gains and losses incurred by the Trust. At March 31, 2008, total investments had a fair value of $1.8 million.

9.	Share-Based Compensation

The Company accounts for its share-based compensation arrangements under SFAS No. 123 (revised 2004), “Share Based Payments” (“SFAS 123R”), which requires companies to record compensation costs for all share-based awards over the respective service period for 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 123R.

The table below presents the amounts included in net income related to share-based compensation expense for the restricted stock awards issued under the DSCP and the PIP.


For the three months ended March 31,	2008	2007
Directors Stock Compensation Plan	$ 45,893	$ 43,904
Performance Incentive Plan	185,358	201,835
Total compensation expense	231,251	245,739
Less: tax benefit	92,081	95,838
SFAS 123R amounts included in net income	$ 139,170	$ 149,901

10.	Stockholders’ Equity

The changes in common stock shares issued and outstanding are shown below:


			For the Three Months Ended March 31, 2008	For the Twelve Months Ended December 31, 2007

Common Stock shares issued and outstanding (1)
	Shares issued — beginning of period balance		6,777,410	6,688,084
		Dividend Reinvestment Plan (2)	7,275	35,333
		Retirement Savings Plan	2,206	29,563
		Conversion of debentures	763	8,106
		Employee award plan	250	350
		Performance shares and options exercised (3)	18,583	15,974
	Shares issued — end of period balance (4)		6,806,487	6,777,410

	Treasury shares — beginning of period balance		-	-
		Purchases	(6,114)	-
		Retirement Savings Plan	6,114	-
		Other issuances	-	-
	Treasury Shares — end of period balance		-	-

	Total Shares Outstanding		6,806,487	6,777,410

(1) 12,000,000 shares are authorized at a par value of $0.4867 per share.
(2) Includes shares purchased with reinvested dividends and optional cash payments.
(3) Includes shares issued for Director's compensation and Performance Incentive Plan.
(4) Includes 58,747 and 57,309 shares at March 31, 2008 and December 31, 2007, respectively, held
in a Rabbi Trust established by the Company relating to the Deferred Compensation Plan.

Page 12

11.	Fair Value of Financial Instruments

The Company adopted SFAS No. 157 effective January 1, 2008 for financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and financial liabilities that are being measured and reported on a fair value basis. There was no impact for adoption of SFAS No. 157 to the consolidated balance sheets and statements of income. The primary effect of SFAS 157 on the company was to expand the required disclosures pertaining to the methods used to determine fair values.

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 157 are as follow:

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;

Level 3: Prices or valuation techniques that 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, 2008:

		Fair Value Measurements Using:
(in thousands)	Fair Value	Quoted Prices in Active Markets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)
Assets:
Investments	$1,848	$1,848	$ -	$ -
Mark-to-market energy assets	323		323	-

Liabilities:
Mark-to-market energy liabilities	318		318	-

The following valuation techniques were used to measure fair value assets in the table above on a recurring basis as of March 31, 2008.

Level 1 Fair Value Measurements:

Investments - The fair values of these available-for-sale 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 broker or dealer quotations, or market transactions in either the listed or OTC markets.

The Company’s adoption of SFAS 157 applies only to its financial instruments. The adoption did not apply to those non-financial assets and non-financial liabilities delayed under FSP 157-2 and will be implemented for the fiscal years beginning after November 15, 2009.

12.	Discontinued Operations

During the quarter ended September 30, 2007, the Company decided to close its distributed energy services subsidiary, OnSight Energy, LLC (“OnSight”), as it had experienced operating losses since its inception in 2004. As a result of these actions, the financial data related to OnSight is presented as discontinued operations for all periods presented. The discontinued operations did not have any impact on the Company’s financial statements during the first quarter of 2008 compared to a net loss of $20,000 for the same period in 2007.

Page 13

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 (“MD&A”) 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, 2007, including the audited consolidated financial statements and notes contained in the Form 10-K.

Safe Harbor for Forward-Looking Statements

Chesapeake Utilities Corporation has made statements in this 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 and other matters. It is important to understand that these forward-looking statements are not guarantees, but are subject to certain risks and uncertainties and other important factors that could cause actual results to differ materially from those in the forward-looking statements. The factors that could cause actual results to differ materially from the Company’s expectations 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;

·	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;

·	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 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 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 financial markets to a degree that may impair future growth; and

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

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 6, 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 the earnings produced 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 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 customer service to retain existing customers;

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

·	maintaining a consistent and competitive dividend for shareholders.

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

Results of Operations for the Quarter Ended March 31, 2008

The following discussions on operating income and segment results for the three months ended March 31, 2008 and 2007 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 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.

Page 14

Consolidated Overview

The Company’s net income for the quarter ended March 31, 2008 decreased $417,000, or five percent, compared to the same period in 2007. The Company earned a net income of approximately $7.6 million, or $1.10 per share (diluted) during the quarter compared to a net income of approximately $8.0 million, or $1.18 per share (diluted) in 2007.


For the Three Months Ended March 31,	2008	2007	Change
Net Income (Loss)
Continuing operations	$7,574,343	$8,011,480	($437,137)
Discontinued operations	-	(20,392)	20,392
Total Net Income	$7,574,343	$7,991,088	($416,745)

Diluted Earnings Per Share
Continuing operations	$1.10	$1.18	($0.08)
Discontinued operations	-	-	-
Total Earnings Per Share	$1.10	$1.18	($0.08)

The period-over-period decrease in net income reflects lower operating income from the Company’s propane segment, partially offset by an increase in operating income from the natural gas segment.


For the Three Months Ended March 31,	2008	2007	Change
Operating Income
Natural Gas	$10,469,024	$9,615,981	$853,043
Propane	3,444,135	4,873,555	(1,429,420)
Advanced Information Services	37,863	48,820	(10,957)
Other & eliminations	89,693	75,215	14,478
Operating Income	14,040,715	14,613,571	(572,856)

Other Income	17,591	56,482	(38,891)
Interest Charges	1,593,371	1,599,250	(5,879)
Income Taxes	4,890,592	5,059,323	(168,731)
Net Income from Continuing Operations	$7,574,343	$8,011,480	($437,137)

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

Warmer weather on the Delmarva Peninsula, which was nine percent warmer in the first quarter of 2008 compared to the same period in 2007, had a negative impact on gross margin for the Company’s Delmarva natural gas and propane distribution operations. The Company estimates that the warmer weather resulted in a decrease of $1.2 million to gross margin in 2008.

·	The Company’s Delmarva propane operation experienced decreases in the average margin per retail gallon sold during the period, which resulted in lower gross margin of $512,000 compared to the same period in 2007.

·	Lower sales volumes by the Delmarva propane operation in the first quarter of 2008 compared to the same period in 2007, resulted in a decrease of $467,000 in gross margin.

·	Partially offsetting these reductions in gross margin was an increase in gross margin generated from the natural gas segment produced by increased capacity and customer growth, increased rates to customers, and higher sales to interruptible customers.

Page 15

Natural Gas

The natural gas segment earned operating income of $10.5 million for the first quarter in 2008 compared to $9.6 million for the corresponding quarter in 2007, an increase of $853,000, or nine percent.


For the Three Months Ended March 31,	2008	2007	Change
Revenue	$68,928,383	$65,509,667	$3,418,716
Cost of sales	49,317,541	46,768,746	2,548,795
Gross margin	19,610,842	18,740,921	869,921

Operations & maintenance	6,714,372	6,263,402	450,970
Depreciation & amortization	1,191,538	1,795,481	(603,943)
Other taxes	1,235,908	1,066,057	169,851
Other operating expenses	9,141,818	9,124,940	16,878
Total Operating Income	$10,469,024	$9,615,981	$853,043


Statistical Data — Delmarva Peninsula
Heating degree-days ("HDD"):
Actual	2,222	2,439	(217)
10-year average (normal)	2,270	2,241	29

Estimated gross margin per HDD	$1,937	$2,234	($297)

Per residential customer added:
Estimated gross margin	$372	$372	$0
Estimated other operating expenses	$106	$111	($5)

Residential Customer Information
Average number of customers:
Delmarva	46,015	43,610	2,405
Florida	13,571	13,262	309
Total	59,586	56,872	2,714

Gross margin for the Company’s natural gas segment increased by $870,000, or five percent, and other operating expenses increased slightly by $17,000, or less than one percent, for the first quarter in 2008 compared to the same period in 2007. The gross margin increases of $600,000 for the natural gas transmission operation, $111,000 for the natural gas distribution operations and $159,000 for the natural gas marketing operation, are further explained below.

Natural Gas Transmission

The natural gas transmission operation achieved gross margin growth of $600,000, or 11 percent, in the first quarter of 2008 compared to the same period in 2007. Of the $600,000 increase, $299,000 was attributable to new transportation capacity contracts implemented in November 2007. In 2008, these new transportation capacity contracts are expected to generate an additional annual gross margin of $1.2 million above 2007 gross margins. In addition, the implementation of rate case settlement rates, effective September 1, 2007, contributed an additional $306,000 to gross margins in the first quarter. A further discussion of the FERC rate proceeding is provided within the “Rates and Regulatory” section of Note 4 “Commitments and Contingencies” to these unaudited Condensed Consolidated Financial Statements. The remaining $5,000 decrease to gross margin in the first quarter of 2008 is attributable to other minor factors.

An increase of $229,000 in other operating expenses partially offset the increased gross margin. The factors contributing to the increase in other operating expenses are as follow:

·	Rent expense increased $43,000 as Eastern Shore began incurring additional rental expense in January 2008 for a new office building.

The Company incurred an additional $65,000 of third-party costs in the first quarter of 2008 compared to the same period in 2007 to perform underwater surveys in compliance with the new federal pipeline integrity regulations. These new regulations require the Company to assess the integrity of each covered segment of its pipeline and to complete a baseline assessment by December 17, 2012.

·	The increased level of capital investment caused increased property taxes of $72,000.

·	Corporate costs allocable to the natural gas transmission operation increased $133,000 as the Company updated its annual corporate cost allocations based on a methodology accepted by the FERC.

·	Other operating expenses relating to various items increased collectively by approximately $24,000.

·	Partially offsetting the previously mentioned increases was a decrease of $108,000 in depreciation expense. As part of the rate case settlement that became effective September 1, 2007, the FERC approved an extension of Eastern Shore’s asset lives, which resulted in reduced depreciation rates.

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Natural Gas Distribution

The Delmarva distribution operations experienced an increase of $84,000, or one percent, in gross margin. The significant items contributing to the increase in gross margin include the following:

Continued residential customer growth contributed to an increase in gross margin. The average number of residential customers on the Delmarva Peninsula increased by 2,405, or six percent, for the first quarter of 2008 compared to the same period in 2007, and the Company estimates that these additional residential customers contributed approximately $337,000 to gross margin during the first quarter of 2008. The Company has seen a slowdown in the new housing market as a result of unfavorable market conditions in the housing industry. Partially offsetting this slowdown was a two percent growth in the number of the Company’s commercial customers during the first quarter of 2008 in comparison to the same period in 2007. The Company estimates that the additional commercial customers contributed $127,000 to gross margin during the first quarter of 2008.

Interruptible sales revenue, net of required margin sharing, increased $214,000 in the first quarter of 2008 compared to the same period in 2007 as customers took advantage of lower natural gas prices in comparison to prices for alternative fuels. Interruptible customers consist of large industrial and commercial customers whose service can be temporarily interrupted in order for the regulated utility to meet the needs of firm customers. These customers pay a lower delivery rate than firm customers and they must be able to substitute an alternate fuel for natural gas.

Partially offsetting these increases to gross margin was the negative impact of warmer weather in the first quarter of 2008 compared to the same period in 2007. The Company estimates that warmer weather reduced gross margin by $617,000 as temperatures on the Delmarva Peninsula were nine percent warmer in the first quarter of 2008 compared to the first quarter of 2007.

·	The remaining $23,000 net increase in gross margin can be attributed to various factors, including the implementation of temporary rates by the Delaware division and lower industrial volumes.

Gross margin for the Florida distribution operation increased by $27,000, or one percent, in the first quarter of 2008 compared to the same period in 2007. A two-percent increase in residential customers and a four-percent increase in non-residential customers contributed to the increase in gross margin. The Florida distribution operation also experienced a slowdown in the housing market attributable to the same unfavorable housing market conditions previously discussed.

Other operating expense for the natural gas distribution operations decreased by $154,000 in the first quarter of 2008 compared to the same period in 2007. Among the key components of the decrease were the following:

Depreciation expense decreased $496,000 in the first quarter of 2008 compared to the same period in 2007. As part of the Maryland division’s rate case settlement that became effective December 1, 2007, and the current status of the Delaware division’s rate case, the respective PSCs extended asset lives for the Company’s depreciable assets in these divisions, which resulted in reduced depreciation rates and lower depreciation expense. The Company estimates that the lower depreciation rates will result in an annualized reduction of $914,000 in depreciation expense.

·	Merchant payment fees decreased by $79,000 as the Company’s Delmarva operations outsourced the processing of credit card payments in April of 2007.

·	Facilities maintenance costs decreased $92,000 due to timing of annual maintenance procedures, a majority of which occurred in the first quarter of 2007.

·	Incentive compensation increased $174,000 in the first quarter of 2008 as the Delmarva operations experienced improved earnings compared to the prior year.

·	Corporate costs allocable to the natural gas distribution operations increased $233,000 as the Company updated its annual corporate cost allocations based on a methodology accepted by the FERC.

·	The Florida distribution operation experienced an increased expense of $65,000 during the first quarter of 2008 compared with the same period in 2007 to maintain compliance with the new federal pipeline integrity regulations.

·	Property taxes increased by $57,000 as a result of the Company’s continued capital investments.

·	In addition, other operating expenses relating to various minor items decreased by approximately $16,000.

Natural Gas Marketing

Gross margin for the natural gas marketing operation increased by $159,000, or 29 percent, for the first quarter of 2008 compared to the same period in 2007. The increase in gross margin was primarily the result of a higher number of customers to which it provides supply management services and improved gas supply management. Other operating expenses decreased by $58,000 for the marketing operation; this decrease is attributable to various factors, such as payroll related-costs and lower allowance for uncollectible accounts.

Page 17

Propane

The propane segment experienced a decrease of $1.4 million, or 29 percent, in operating income for the first quarter of 2008 compared to the same period in 2007. Gross margin decreased by $1.5 million, which was partially offset by a decrease in other operating expenses of $74,000.


For the Three Months Ended March 31,	2008	2007	Change
Revenue	$27,809,150	$24,922,806	$2,886,344
Cost of sales	19,722,318	15,332,974	4,389,344
Gross margin	8,086,832	9,589,832	(1,503,000)

Operations & maintenance	3,832,851	3,996,944	(164,093)
Depreciation & amortization	497,879	445,580	52,299
Other taxes	311,967	273,753	38,214
Other operating expenses	4,642,697	4,716,277	(73,580)
Total Operating Income	$3,444,135	$4,873,555	($1,429,420)


Statistical Data — Delmarva Peninsula
Heating degree-days ("HDD"):
Actual	2,222	2,439	(217)
10-year average (normal)	2,270	2,241	29

Estimated gross margin per HDD	$1,974	$1,743	$231

The period-over-period decrease in operating income was due primarily to the Delmarva propane distribution operation, which experienced a lower gross margin from warmer weather on the Delmarva Peninsula, a lower margin per retail gallon and lower sales volumes in the first quarter of 2008.

The gross margin decreases of $1.5 million for the Delmarva propane distribution operations, $16,000 for the Florida propane distribution operations and $36,000 for the propane wholesale and marketing operation, are further explained below.

Delmarva Propane Distribution

The Delmarva propane distribution operation’s decrease in gross margin of $1.5 million resulted from the following:

Gross margin decreased by $512,000 in the first quarter of 2008, compared to the same period in 2007, because of a $0.06 decrease in the average gross margin per retail gallon. This decrease will occur when market prices decrease and move closer to the Company’s inventory price per gallon. This trend reverses when market prices of propane are greater than the Company’s average inventory price per gallon.

Temperatures on the Delmarva Peninsula were nine percent warmer in the first quarter of 2008 compared the same period in 2007, which contributed to a decrease of 736,000 gallons, or seven percent, sold during this period in 2008 compared to the same period in 2007. The Company estimates that the warmer weather and decreased volumes sold had a negative impact of $535,000 for the Delmarva propane distribution operation compared to the first quarter of 2007.

Non-weather-related volumes sold in the first quarter of 2008 decreased by 576,000 gallons, or six percent. This decrease in gallons sold reduced gross margin by approximately $467,000 for the Delmarva propane distribution operation compared to the first quarter of 2007. Contributing to this decrease in gallons sold was customer conservation, a reduced number of customers and the timing of propane deliveries.

Total other operating expenses decreased by $100,000 for the Delmarva propane operations in the first quarter of 2008, compared to the same period in 2007. The significant items contributing to this increase are explained below:

·	Incentive compensation and commissions costs decreased by $216,000 as a result of the lower operating results in 2008 compared to 2007.

·	Vehicle fuel increased $53,000 as a result of rising fuel costs.

·	The allowance for uncollectable accounts increased $31,000 due to increased revenues resulting from the higher cost of propane.

·	Depreciation and amortization expense increased by $22,000 as a result of the Company’s capital investments over the prior year.

·	In addition, other operating expenses relating to various items increased collectively by approximately $10,000.

Florida Propane Distribution

The Florida propane distribution operation experienced a decrease in gross margin of $16,000, or four percent, in the first quarter of 2008 compared to the same period in 2007. The lower gross margin is attributable to decreases of $23,000 in the average gross margin per retail gallon and $12,000 in service sales. Partially offsetting these decreases was a seven-percent increase in volumes sold to residential customers primarily from a 12-percent increase in the average number of residential customers. Other operating expenses in the first quarter of 2008, compared to the same period in 2007, increased by $12,000, primarily due to increases in payroll and benefit costs incurred by filling positions that were vacant in 2007.

Propane Wholesale and Marketing

Gross margin for the Company’s propane wholesale marketing operation decreased by $36,000, or five percent, in the first quarter of 2008 compared to the same period in 2007. This decrease reflects fewer market opportunities in the first quarter of 2008 due to lower price volatility in the propane wholesale market, which was below the level of price fluctuations experienced in the same period of 2007. Also contributing to the lower operating income for the period were higher other operating expenses of $15,000, due primarily to higher payroll and benefits costs.

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Advanced Information Services

The advanced information services business experienced gross margin growth of approximately $239,000, or 16 percent and contributed operating income of $38,000 for the first quarter of 2008, a decrease of $11,000 compared to the same period in 2007.


For the Three Months Ended March 31,	2008	2007	Change
Revenue	$3,651,139	$3,305,123	$346,016
Cost of sales	1,941,573	1,834,148	107,425
Gross margin	1,709,566	1,470,975	238,591

Operations & maintenance	1,403,865	1,191,419	212,446
Depreciation & amortization	37,255	34,237	3,018
Other taxes	230,583	196,499	34,084
Other operating expenses	1,671,703	1,422,155	249,548
Total Operating Income	$37,863	$48,820	($10,957)

The increase of revenues in the first quarter of 2008 resulted primarily from:

·	An increase of $215,000 in consulting revenues as the number of billable hours increased by five percent and an increase in the average bill rate;

·	An increase of $46,000 from Managed Database Administration (“MDBA”) services, which provide clients with professional database monitoring and support solutions during business hours or around the clock; and

·	An increase of $85,000 attributable to various factors, such as higher product sales and training.

Other operating expenses increased by $250,000 to $1.7 million in the first quarter of 2008, compared to $1.4 million for the same period in 2007. This increase in operating expenses is attributable to payroll costs, incentive compensation, payroll taxes, and benefit claims which accounted for $249,000 of the period-over-period increase. These costs increased as a result of an increase in non-billable staffing levels to support and maintain the growth and customer demand.

Other Business Operations and Eliminations

Other operations consist primarily of subsidiaries that own real estate leased to other Company subsidiaries, generated an operating income of approximately $90,000 for the first quarter of 2008 compared to an operating income of approximately $75,000 for the same period in 2007.

For the Three Months Ended March 31,	2008	2007	Change
Revenue	$163,074	$154,623	$8,451
Cost of sales	-	-	-
Gross margin	163,074	154,623	8,451

Operations & maintenance	28,933	23,471	5,462
Depreciation & amortization	28,622	41,268	(12,646)
Other taxes	16,596	15,439	1,157
Other operating expenses	74,151	80,178	(6,027)
Operating Income - Other	88,923	74,445	14,478
Operating Income - Eliminations (1)	770	770	-
Total Operating Income	$89,693	$75,215	$14,478

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

Interest Expense

Total interest expense for the first quarter of 2008 decreased approximately $6,000, or less than one percent, compared to the same period in 2007. The lower interest expense is a result of the following developments:

·	In the first quarter of 2008, the Company capitalized $151,000 more interest on debt associated with ongoing capital projects than in the corresponding period in 2007, which resulted in lower interest expense in the current period.

Interest on long-term debt decreased $140,000 in the first quarter of 2008 compared to the same period in 2007 as the Company reduced its average long-term debt balance by $8.1 million. The Company’s average long-term debt during the first quarter of 2008 was $69.9 million with a weighted average interest rate of 6.65 percent, compared to $78.0 million with a weighted average interest rate of 6.61 percent for the same period in 2007.

Interest on short-term borrowings increased $86,000 in the first quarter of 2008 compared to the same period in 2007, despite an increase of $18.2 million in the Company’s average short-term borrowing balance. The impact of the higher borrowing was minimized by a lower weighted average interest rate that was nearly two percentage points lower in 2008. The Company’s average short-term borrowing during the first quarter of 2008 was $35.8 million with a weighted average interest rate of 3.73 percent, compared to $17.5 million with a weighted average interest rate of 5.71 percent for the same period in 2007.

·	Interest expense for other items, such as interest on refunds and meter deposits, increased $199,000 in the first quarter of 2008 compared to the corresponding period in 2007.

Income Taxes

Income tax expense for the first quarter of 2008 was $4.9 million compared to $5.1 million for the first quarter of 2007. The decrease in income tax expense primarily reflects the lower earnings for the period. The effective tax rate for the first quarter of 2008 is 39.2 percent compared to an effective tax rate of 38.7 percent for the same period in 2007.

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Financial Position, Liquidity and Capital Resources

Chesapeake’s capital requirements reflect the capital-intensive nature of its business and are principally attributable to its investment in new plant and equipment and the retirement of outstanding debt. The Company relies on cash generated from operations, short-term borrowing and other sources to meet normal working capital requirements and to finance capital expenditures. During the first three months of 2008, net cash provided by operating activities was $7.3 million, cash used by investing activities was $4.5 million, and cash used by financing activities was $2.5 million.

By comparison, during the first three months of 2007, net cash provided by operating activities was $16.9 million, cash used by investing activities was $8.4 million, and cash used by financing activities was $8.7 million.

As of February 20, 2008, the Board of Directors has authorized the Company to borrow up to $70.0 million of short-term debt, as required, from various banks and trust companies under short-term lines of credit. As of March 31, 2008, Chesapeake had five unsecured bank lines of credit with three 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. Three of the bank lines, totaling $25.0 million, are committed. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks. The Company’s outstanding balance of short-term borrowing at March 31, 2008 and December 31, 2007 was $46.1 million and $45.7 million, respectively.

Chesapeake has budgeted $37.5 million for capital expenditures during 2008. This amount includes $17.0 million for natural gas distribution, $13.3 million for natural gas transmission, $5.9 million for propane distribution and wholesale marketing, $290,000 for advanced information services and $887,000 for other operations. The natural gas distribution and transmission expenditures are for expansion and improvement of facilities. The propane expenditures are to support customer growth, to acquire land for a future bulk storage facility, and to replace equipment. The advanced information services expenditures are for computer hardware, software and related equipment. The other operations category includes general plant, computer software and hardware. The Company expects to fund the 2008 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 opportunities, acquisition opportunities and availability of capital.

Capital Structure

The following presents the Company’s capitalization as of March 31, 2008 and December 31, 2007:

	March 31, 2008		December 31, 2007
	(In thousands, except percentages)

Long-term debt, net of current maturities	$63,223	34%	$69,984	37%
Stockholders' equity	$125,267	66%	$118,410	63%
Total capitalization, excluding short-term debt	$188,490	100%	$188,394	100%

As of March 31, 2008, common equity represented 66 percent of total capitalization, compared to 65 percent at December 31, 2007. 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 52 percent at March 31, 2008, compared to 49 percent at December 31, 2007. 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 customers and creditors, as well as to the Company’s investors.

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 600,300 shares of common stock, including the underwriter’s exercise of their over-allotment option of 90,045 shares, under this registration statement, generating net proceeds of $19.7 million. At March 31, 2008, the Company had approximately $20.0 million remaining under this registration statement.

Page 20

Cash Flows Provided By Operating Activities

Cash flows provided by operating activities were as follows:

For the Three Months Ended March 31,	2008	2007	Change
Net Income	$7,574,343	$7,991,088	($416,745)
Non-cash adjustments to net income	3,421,128	2,390,017	1,031,111
Changes in working capital	(3,708,474)	6,540,166	(10,248,640)
Net cash provided by operating activties	$7,286,997	$16,921,271	($9,634,274)

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

For the first three months of 2008, net cash flow provided by operating activities was $7.3 million, a reduction of $9.6 million compared to the same period of 2007. The decrease was due primarily to: (1) a reduction in working capital, as cash used for accounts payable increased during the period due to the timing of payments to vendors, and (2) a reduction of cash resulting from decreased regulatory liabilities.

Cash Flows Used in Investing Activities

Net cash flows used in investing activities totaled $4.5 million and $8.4 million during the three months ended March 31, 2008 and 2007, respectively.

Cash utilized for capital expenditures was $4.4 million and $8.4 million for the first three months of 2008 and 2007, respectively. Additions to property, plant and equipment in the first three months of 2008 were primarily for natural gas transmission ($1.1 million), natural gas distribution ($2.5 million), propane distribution ($645,000), and other operations ($233,000).

·	The Company’s environmental expenditures exceeded amounts recovered through rates charged to customers in the first three months of 2008 and 2007 by $129,000 and $68,000, respectively.

Cash Flows Used in Financing Activities

Cash flows used by financing activities totaled $2.5 million for the first three months of 2008 compared to $8.7 million of cash used for the first three months of 2007. Significant financing activities included the following:

·	During the first three months of 2008, the Company had net borrowings from short-term debt of $1.0 million compared to a net repayment of $7.3 million in the first three months of 2007.

During the first three months of 2008, the Company paid $1.8 million in cash dividends compared with dividend payments of $1.7 million for the same time period in 2007. The increase in dividends paid in the first three months of 2008 compared to 2007 reflects both growth in the annualized dividend rate, from $1.16 per share during 2007 to $1.18 per share during 2008, and the increase in the number of shares outstanding.

·	The Company repaid $1.0 million of long-term debt during the first three months of 2008 and 2007, respectively.

Off-Balance Sheet Arrangements

The Company has issued corporate guarantees to certain vendors of its propane wholesale marketing subsidiary and its Florida natural gas supply management subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of either subsidiary’s default. Neither subsidiary has ever defaulted on its obligations to pay suppliers. The liabilities for these purchases are recorded in the Consolidated Financial Statements when incurred. The aggregate amount guaranteed at March 31, 2008 was $22.2 million, with the guarantees expiring on various dates in 2008 and the first quarter of 2009.

Contractual Obligations

There have not been any material changes in the contractual obligations presented in the Company’s 2007 Annual Report on Form 10-K, except for commodity purchase obligations and forward contracts entered into in the ordinary course of the Company’s business. Below is a summary of the commodity and forward contract obligations at March 31, 2008.

	Payments Due by Period
Purchase Obligations	Less than 1 year	1 - 3 years	3 - 5 years	More than 5 years	Total
Commodities (1)	$16,622,636	$63,515	$0	$0	$16,686,151
Propane (2)	10,367,994	-	-	-	10,367,994
Total Purchase Obligations	$26,990,630	$63,515	$0	$0	$27,054,145

(1)

In addition to the obligations noted above, the natural gas distribution and propane distribution operations have

agreements with commodity suppliers that have provisions allowing the Company to reduce or eliminate the quantities

purchased. There are no monetary penalties for reducing the amounts purchased; however, the propane contracts

allow the suppliers to reduce the amounts available in the winter season if the Company does not purchase specified

amounts during the summer season. Under these contracts, the commodity prices will fluctuate as market prices fluctuate.

(2)	The Company has also entered into forward sale contracts in the aggregate amount of $11.0 million. See Part I, Item 3, “Quantitative and Qualitative Disclosures about Market Risk,” below for further information.

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Environmental Matters

As more fully described in Note 4 “Commitments and Contingencies” to the Condensed Consolidated Financial Statements, Chesapeake has incurred costs relating to the completed or ongoing environmental remediation at three former manufactured gas plant sites. In addition, Chesapeake is currently participating in discussions regarding possible responsibility of the Company for remediation of a fourth 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 subject to regulation by their respective PSCs. Eastern Shore is subject to regulation by the FERC. At March 31, 2008, 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 the Condensed Consolidated Financial Statements.

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. Oil prices, as well as the prices of electricity and other fuels, are lower than the price of natural gas. Oil prices, as well as the prices of electricity and other fuels, are subject to fluctuation 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 the fluctuations in its customers’ alternative fuel prices.. As a result of the transmission operation’s conversion to open access and the Florida gas distribution division’s restructuring of its services, their businesses have shifted from providing competitive sales service to providing transportation and contract storage services.

The Company’s natural gas distribution operations in Delaware, Maryland and Florida offer transportation services to certain commercial and industrial customers. In 2002, the Florida operation extended such service to residential customers. With 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 distribution customers are located close enough to a transmission company’s pipeline to make a connection economically feasible. The customers at risk are usually large volume commercial and industrial customers with the financial resources and capability to bypass the Company’s distribution operations in this manner. In certain situations, the Company’s distribution operations may adjust services and rates for these customers to retain their business. The Company expects to continue to expand the availability of transportation service to additional classes of distribution customers in the future. The Company established a natural gas sales and supply operation in Florida to compete for customers eligible for transportation services. The Company also provides such sales service in Delaware.

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 reliability of service and responsiveness. Competition is generally from local outlets of national distribution companies and local businesses because distributors located in close proximity to customers incur lower costs of providing service. Propane competes with electricity as an energy source, because propane 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 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. In addition, changes in the advanced information services industry are occurring rapidly, which could adversely impact the markets for the products and services offered by such 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 mechanism 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 Note 5, “Recent Authoritative Pronouncements on Financial Reporting and Accounting,” to the unaudited Condensed Consolidated Financial Statements.

Page 22

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 first mortgage bonds, 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 $69.9 million at March 31, 2008, as compared to a fair value of $76.1 million, based mainly on current market prices or discounted cash flows, using current rates for similar issues with similar terms and remaining maturities. 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 when it enters into fixed-price contracts for supply. The Company can store up to approximately four million gallons (including leased storage and rail cars) of propane during the winter season to meet its customers’ peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause the value of stored propane to decline. To mitigate the impact of price fluctuations, the Company has adopted a Risk Management Policy that allows the propane distribution operation to enter into fair value hedges of its inventory. Management reviewed the Company’s storage position as of March 31, 2008 and elected not to hedge any of its inventories.

The Company’s propane wholesale marketing operation is a party to natural gas liquids (“NGLs”) forward contracts, primarily propane contracts, with various third parties. These contracts require that the propane wholesale marketing operation purchase or sell NGLs at a fixed price at fixed future dates. At expiration, the contracts are settled by the delivery of NGLs to the Company or the counter-party or 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 NGL deviate from fixed contract settlement prices. Market risk associated with the trading of futures and forward contracts are monitored daily for compliance with the Company’s Risk Management Policy, which includes volumetric limits for open positions. To manage exposures to changing market prices, open positions are marked up or down to market prices and reviewed by the Company’s oversight officials daily. In addition, the Risk Management Committee reviews periodic reports on market and the credit risk of counter-parties, approves any exceptions to the Risk Management Policy (within limits established by the Board of Directors) and authorizes the use of any new types of contracts. Quantitative information on forward and futures contracts at March 31, 2008 is presented in the following table.

At March 31, 2008	Quantity in gallons	Estimated Market Prices	Weighted Average Contract Prices
Forward Contracts
Sale	7,603,260	$1.3650 — $1.5150	$1.4526
Purchase	7,140,000	$1.3550 — $1.5739	$1.4521

Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expire in 2008.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Chief Executive Officer and Chief Financial Officer of the Company, with the participation of other Company officials, have evaluated the Company’s “disclosure controls and procedures” (as such term is defined under Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended) as of March 31, 2008. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2008.

Changes in Internal Control Over Financial Reporting

During the quarter ended March 31, 2008, 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 the unaudited Condensed Consolidated Financial Statements, 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 consolidated financial position, results of operations or cash flows of the Company.

Item 1A. Risk Factors

In addition to the other information set forth in this Form 10-Q, including the risks and uncertainties described under Item 2 of Part I of this Form 10-Q, in the section entitled “Safe Harbor and Forward Looking Statements,” consideration should be given to the factors discussed under Item 1A. “Risk Factors,” in the Company’s Form 10-K for the fiscal year ended December 31, 2007. These risks could affect the operations and/or financial performance of the Company. The risks described in the Form 10-K and this Form 10-Q are not the only risks that the Company faces. The Company’s operations and/or financial performance could also be affected by additional factors that at present are not known to it or that the Company considers immaterial to its operations and/or financial performance.

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



Period		Total Number of Shares Purchased	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs
	January 1, 2008
	through January 31, 2008 (1)	546	$31.04	0	0
	February 1, 2008
	through February 29, 2008 (2)	2,925	$29.43	0	0
	March 1, 2008
	through March 31, 2008 (2)	3,189	$28.50	0	0

Total		6,660	$29.65	0	0

(1) Chesapeake purchased shares of stock on the open market for the purpose of reinvesting the dividend on deferred
stock units held in the Rabbi Trust accounts for certain Senior Executives under the Deferred Compensation Plan.
The Deferred Compensation Plan is discussed in detail in Note K to the Consolidated Financial Statements of the
Company's Form 10-K filed with the Securities Exchange Commission on March 10, 2008. During the quarter,
546 shares were purchased through the reinvestment of dividends on deferred stock units.

(2) Commencing in February 2008, Chesapeake purchased shares of stock on the open market for the purpose of
funding its Retirement Savings Plan. During the quarter, 6,114 shares were purchased for this purpose.

Item 3. Defaults upon Senior Securities

None

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

None

Item 5. Other Information

None

Item 6. Exhibits

Exhibit	Description
31.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, dated May 6, 2008

31.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, dated May 6, 2008

32.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated May 6, 2008

32.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated May 6, 2008

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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/ Michael P. McMasters

Michael P. McMasters

Senior Vice President and Chief Financial Officer

Date: May 6, 2008

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