Edgar Filing: CHESAPEAKE UTILITIES CORP

Chesapeake Utilities Corporation - Form 10-Q - March 31, 2007

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, 2007

[ ]	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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer [ ] Accelerated filer [X] Non-accelerated filer [ ]

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 — 6,731,775 shares outstanding as of April 30, 2007.

Table of Contents

	Page
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		30
Item 4. Controls and Procedures		31
PART II — OTHER INFORMATION		32
Item 1. Legal Proceedings		32
Item 1A. Risk Factors		32
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		32
Item 3. Defaults upon Senior Securities		32
Item 4. Submission of Mattters to a Vote of Security Holders		32
Item 5. Other Information		32
Item 6. Exhibits		32
SIGNATURES		33

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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,	2007		2006
Operating Revenues	$	93,526,891	$	90,950,673
Operating Expenses
Cost of sales, excluding costs below		63,935,867		65,924,761
Operations		10,559,701		9,601,281
Maintenance		580,165		443,968
Depreciation and amortization		2,315,795		1,977,347
Other taxes		1,553,312		1,566,088
Total operating expenses		78,944,840		79,513,445
Operating Income		14,582,051		11,437,228
Other income net of other expenses		53,374		78,583
Interest charges		1,599,250		1,493,337
Income Before Income Taxes		13,036,175		10,022,474
Income taxes		5,045,087		3,926,059
Net Income	$	7,991,088	$	6,096,415

Earnings Per Share of Common Stock:
Basic	$	1.19	$	1.03
Diluted	$	1.18	$	1.01
Basic weighted average shares outstanding		6,705,829		5,909,434
Diluted weighted average shares outstanding		6,820,462		6,052,985

Cash Dividends Declared Per Share of Common Stock:	$	0.290	$	0.285

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,	2007			2006
*Operating Activities*
Net Income	$	7,991,088		$	6,096,415
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization		2,315,795			1,977,347
Depreciation and accretion included in other costs		837,624			741,846
Deferred income taxes, net		(956,532	)		(1,934,480	)
Unrealized gain on commodity contracts		(233,596	)		(56,091	)
Unrealized gain on investments		(27,956	)		(69,450	)
Employee benefits and compensation		454,987			423,771
Other, net		(839	)		(528	)
Changes in assets and liabilities:
Purchase of investments		(27,014	)		(44,183	)
Accounts receivable and accrued revenue		(879,644	)		10,974,718
Propane inventory, storage gas and other inventory		7,601,692			7,327,791
Regulatory assets		673,854			3,388,280
Prepaid expenses and other current assets		1,066,292			882,229
Other deferred charges		(703,099	)		26,414
Long-term receivables		33,654			57,641
Accounts payable and other accrued liabilities		(6,184,675	)		(15,345,408	)
Income taxes receivable		3,695,290			4,691,297
Accrued interest		880,420			967,278
Customer deposits and refunds		(1,125,068	)		(238,954	)
Accrued compensation		(957,599	)		(1,932,479	)
Regulatory liabilities		2,481,819			1,839,081
Other liabilities		(15,222	)		128,824
Net cash provided by operating activities		16,921,271			19,901,359

*Investing Activities*
Property, plant and equipment expenditures		(8,357,392	)		(7,114,420	)
Environmental recoveries (expenditures)		(68,284	)		40,390
Net cash used by investing activities		(8,425,676	)		(7,074,030	)

*Financing Activities*
Common stock dividends		(1,724,536	)		(1,466,011	)
Issuance of stock for Dividend Reinvestment Plan		66,007			113,021
Change in cash overdrafts due to outstanding checks		1,299,731			335,059
Net repayment under line of credit agreements		(7,329,054	)		(10,509,392	)
Repayment of long-term debt		(1,020,069	)		(1,020,244	)
Net cash used by financing activities		(8,707,921	)		(12,547,567	)

*Net Increase (Decrease) in Cash and Cash Equivalents*		(212,326	)		279,762
*Cash and Cash Equivalents — Beginning of Period*		4,488,367			2,487,658
*Cash and Cash Equivalents — End of Period*	$	4,276,041		$	2,767,420

Supplemental Disclosures of Non-Cash Investing Activities:
Capital property and equipment acquired on account, but not paid as of March 31	$	1,219,839		$	1,209,309

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, 2007			For the Twelve Months Ended December 31, 2006
Common Stock
Balance — beginning of period	$	3,254,998		$	2,863,212
Dividend Reinvestment Plan		4,532			18,685
Retirement Savings Plan		3,870			14,457
Conversion of debentures		1,315			8,117
Performance shares and options exercised		5,098			14,536
Stock issuance		-			335,991
Balance — end of period	$	3,269,813		$	3,254,998

Additional Paid-in Capital
Balance — beginning of period	$	61,960,220		$	39,619,849
Dividend Reinvestment Plan		275,934			1,148,100
Retirement Savings Plan		234,224			900,354
Conversion of debentures		44,616			275,300
Stock-based compensation		645,391			887,426
Stock issuance		-			19,362,518
Exercise of warrants		-			(233,327	)
Balance — end of period	$	63,160,385		$	61,960,220

Retained Earnings
Balance — beginning of period	$	46,270,884		$	42,854,894
Net income		7,991,088			10,506,525
Cash dividends declared		(1,948,031	)		(7,090,535	)
Balance — end of period	$	52,313,941		$	46,270,884

Accumulated Other Comprehensive Loss
Balance — beginning of period		($334,550	)		(578,151	)
Minimum pension liability adjustment, net of tax		-			74,036
Gain on funded status of Employee Benefit Plans, net of tax		-			169,565
Balance — end of period		($334,550	)		($334,550	)

Deferred Compensation Obligation
Balance — beginning of period	$	1,118,509		$	794,535
New deferrals		193,878			323,974
Balance — end of period	$	1,312,387		$	1,118,509

Treasury Stock
Balance — beginning of period		($1,118,509	)		($797,156	)
New deferrals related to compensation obligation		(193,878	)		(323,974	)
Purchase of treasury stock ⁽¹⁾		(13,974	)		(51,572	)
Sale and distribution of treasury stock ⁽²⁾		13,974			54,193
Balance — end of period		($1,312,387	)		($1,118,509	)


Total Stockholders’ Equity	$	118,409,589		$	111,151,552

⁽¹⁾Amount includes shares purchased in the open market for the Company's Rabbi Trust to secure its obligations under the Company's Executive Deferral Compensation Plan.
⁽²⁾Amount includes shares issued to the Company's Rabbi Trust as obligation under the Executive Deferral Compensation Plan.

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

	For the Three Months Ended March 31, 2007		For the Three Months Ended March 31, 2006
Net income	$	7,991,088	$	6,096,415
Minimum pension liability adjustment, net of tax benefit of $0 and $0, respectively		-		-
Comprehensive Income	$	7,991,088	$	6,096,415

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, 2007			December 31, 2006
Property, Plant and Equipment
Natural gas	$	273,760,950		$	269,012,516
Propane		45,454,876			44,791,552
Advanced information services		1,080,338			1,054,368
Other plant		9,072,036			9,147,500
Total property, plant and equipment		329,368,200			324,005,936
Less: Accumulated depreciation and amortization		(87,432,163	)		(85,010,472	)
Plus: Construction work in progress		4,231,721			1,829,948
Net property, plant and equipment		246,167,758			240,825,412

Investments		2,070,547			2,015,577

Current Assets
Cash and cash equivalents		4,276,041			4,488,366
Accounts receivable (less allowance for uncollectible accounts of $716,173 and $661,597, respectively)		45,391,335			44,969,182
Accrued revenue		4,782,842			4,325,351
Propane inventory, at average cost		5,044,619			7,187,035
Other inventory, at average cost		1,342,936			1,564,937
Regulatory assets		677,707			1,275,653
Storage gas prepayments		2,156,060			7,393,335
Income taxes receivable		-			1,078,882
Deferred income taxes		2,580,102			1,365,316
Prepaid expenses		1,243,550			2,280,900
Other current assets		2,458,252			1,553,284
Total current assets		69,953,444			77,482,241

Deferred Charges and Other Assets
Goodwill		674,451			674,451
Other intangible assets, net		188,427			191,878
Long-term receivables		790,679			824,333
Other regulatory assets		1,671,402			1,765,088
Other deferred charges		1,904,772			1,215,004
Total deferred charges and other assets		5,229,731			4,670,754


Total Assets	$	323,421,480		$	324,993,984

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

Page 4

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

Capitalization and Liabilities	March 31, 2007			December 31, 2006
Capitalization
Stockholders' equity
Common Stock par value $0.4867 per share (authorized 12,000,000 shares)	$	3,269,813		$	3,254,998
Additional paid-in capital		63,160,385			61,960,220
Retained earnings		52,313,941			46,270,884
Accumulated other comprehensive loss		(334,550	)		(334,550	)
Deferred compensation obligation		1,312,387			1,118,509
Treasury stock		(1,312,387	)		(1,118,509	)
Total stockholders' equity		118,409,589			111,151,552

Long-term debt, net of current maturities		69,984,000			71,050,000
Total capitalization		188,393,589			182,201,552

Current Liabilities
Current portion of long-term debt		7,656,364			7,656,364
Short-term borrowing		21,524,618			27,553,941
Accounts payable		27,381,642			33,870,552
Customer deposits and refunds		6,377,197			7,502,265
Accrued interest		1,712,812			832,392
Dividends payable		1,948,053			1,939,482
Income taxes payable		2,616,408			-
Accrued compensation		1,508,144			2,901,053
Regulatory liabilities		6,795,101			4,199,147
Other accrued liabilities		4,728,679			4,005,795
Total current liabilities		82,249,018			90,460,991

Deferred Credits and Other Liabilities
Deferred income taxes		26,775,352			26,517,098
Deferred investment tax credits		314,573			328,277
Other regulatory liabilities		1,078,441			1,236,254
Environmental liabilities		169,197			211,581
Accrued pension costs		1,610,024			1,608,311
Accrued asset removal cost		18,827,580			18,410,992
Other liabilities		4,003,706			4,018,928
Total deferred credits and other liabilities		52,778,873			52,331,441

Other Commitments and Contingencies *(Note 4)*


Total Capitalization and Liabilities	$	323,421,480		$	324,993,984

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 14, 2007. In the opinion of management, these statements reflect normal recurring adjustments that are necessary for a fair presentation of the Company’s results of operations, financial position and cash flows for the interim periods presented.

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 the components of 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 2007 and 2006. Accumulated other comprehensive loss was $334,550 at March 31, 2007 and December 31, 2006.

3.	Calculation of Earnings Per Share

For the Three Months Ended March 31,	2007		2006
Calculation of Basic Earnings Per Share:
Net Income	$	7,991,088	$	6,096,415
Weighted average shares outstanding		6,705,829		5,909,434
Basic Earnings Per Share	$	1.19	$	1.03

Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	7,991,088	$	6,096,415
Effect of 8.25% Convertible debentures⁽¹⁾		24,200		27,473
Adjusted numerator — Diluted	$	8,015,288	$	6,123,888

Reconciliation of Denominator:
Weighted shares outstanding — Basic		6,705,829		5,909,434
Effect of dilutive securities⁽¹⁾
Warrants		-		12,485
8.25% Convertible debentures		114,633		131,066
Adjusted denominator — Diluted		6,820,462		6,052,985
Diluted Earnings per Share	$	1.18	$	1.01

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

Page 6

4.	Commitments and Contingencies

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 gas manufacturing plant site located in Cambridge, Maryland. The following 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, 2007, 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 2007 from other parties or through rates. As of March 31, 2007, 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, 2007, 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 $1.77 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 $1.16 million of the incurred environmental remediation costs.

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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 an AS/SVE Pilot Study Work Plan (the “Work Plan”) for the Winter Haven Coal Gas site with the FDEP. 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.

The Company has accrued a liability of $169,000 as of March 31, 2007 for the Winter Haven Coal Gas site. Through March 31, 2007, the Company has incurred approximately $1.7 million of environmental costs associated with this site. At March 31, 2007, the Company had collected, through rates, $65,000 in excess of costs incurred. In addition, a regulatory asset of approximately $104,000, representing the uncollected portion of the estimated clean-up costs, has also been recorded. The Company expects to recover the remaining 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.

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 April 2007, 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. The contract expires on March 31, 2008.

Corporate Guarantees

The Company has issued corporate guarantees to certain vendors of its propane wholesale marketing subsidiary, its Florida natural gas supply and management subsidiary, and its Delmarva propane distribution subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the subsidiaries’ default. The liabilities for these purchases are recorded in the Consolidated Financial Statements. The aggregate amount guaranteed at March 31, 2007 totaled $22.2 million, with the guarantees expiring on various dates in 2007 and the first half of 2008.

Page 8

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, 2007. The letter of credit is provided as security to satisfy the deductibles for claim amounts on the Company’s policies.

Application of SFAS No. 71

Certain assets and liabilities of the Company are accounted for in accordance with SFAS No. 71 –“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, 2007 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 that could be material.

Commodity and Pipeline Capacity Cost Recovery

In response to the Company’s annual Gas Sales Service Rates Application (“GSR”) filed with the Delaware Public Service Commission (“Delaware PSC”) on September 1, 2006, the Division of the Public Advocate (“DPA”) has recommended a cost disallowance of approximately $4.4 million related to the Delaware division’s commodity procurement purchases and a disallowance of approximately $275,000 related to pipeline capacity the Delaware division holds in eastern Sussex County, Delaware. The Delaware PSC Staff has recommended a cost disallowance of approximately $2.2 million related to the Delaware division’s commodity procurement purchases and the deferral of approximately $535,000 related to pipeline capacity the Delaware division holds in eastern Sussex County, Delaware. The Company disagrees with these recommendations and intends to oppose vigorously any proposed cost disallowance and deferral. Under established Delaware law, gas procurement costs, like other normally accepted operating expenses, cannot be disallowed unless it is shown that the costs were the result of an abuse of discretion, bad faith, or waste. The Company submitted its rebuttal position on April 19, 2007. Management believes that the Company’s gas procurement practices and pipeline capacity costs were reasonable and that, in no event were the costs at issue incurred as a result of any abuse of discretion, bad faith, or waste on the part of the Company. Also in Management’s opinion, neither the DPA nor the Delaware PSC Staff has presented any evidence to support a finding of abuse of discretion, bad faith, or waste on the part of the Company. The Company expects a final decision by the Delaware PSC during the second or third quarter of 2007. At this time, the Company believes that it has strong defenses to the proposed disallowance of costs.

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 and other matters. 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.

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5.	Recent Authoritative Pronouncements on Financial Reporting and Accounting

In June 2006, the FASB issued FASB Interpretation (“FIN”) No. 48, “Employers’ Accounting for Uncertainty in Income Taxes.” This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition and classification of uncertain tax positions, reporting of interest and penalties, accounting in interim periods, disclosure, and transition. This interpretation is effective for fiscal years beginning after December 15, 2006. Chesapeake was required to adopt FIN No. 48 in the first quarter of 2007 and the adoption of FIN 48 did not have any impact on the Company’s financial statements.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This statement defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting pronouncements that require or permit fair value measurements, the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, this statement does not require any new fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Chesapeake will be required to adopt SFAS No. 157 in the first quarter of 2008. The Company has not yet evaluated the impact that SFAS No. 157 will have on its 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.” SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value, with unrealized gains and losses related to these financial instruments reported in earnings at each subsequent reporting date. This Statement is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. The Company has not yet evaluated the impact that this statement will have on its financial statements.

Page 10

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.

For the Three Months Ended March 31,	2007		2006
Operating Revenues, Unaffiliated Customers
Natural gas	$	65,431,604	$	67,578,658
Propane		24,922,400		20,550,937
Advanced information services		3,172,887		2,820,566
Other		-		512
Total operating revenues, unaffiliated customers	$	93,526,891	$	90,950,673
Intersegment Revenues ⁽¹⁾
Natural gas	$	78,063	$	58,949
Propane		406		-
Advanced information services		132,236		4,638
Other		154,623		154,623
Total intersegment revenues	$	365,328	$	218,210
Operating Income
Natural gas	$	9,615,982	$	7,995,205
Propane		4,873,555		3,433,733
Advanced information services		48,821		16,309
Other and eliminations		43,693		(8,019	)
Total operating income	$	14,582,051	$	11,437,228
⁽¹⁾ All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.

		March 31, 2007		December 31, 2006
Identifiable Assets
Natural gas	$	253,318,146	$	252,292,600
Propane		57,251,565		60,170,200
Advanced information services		2,579,823		2,573,810
Other		10,271,946		9,957,374
Total identifiable assets	$	323,421,480	$	324,993,984

The Company’s operations are all domestic. The advanced information services segment, headquartered in Norcross, Georgia, provides domestic and international clients with information technology related business services and solutions. Transactions with foreign companies are denominated and paid in U.S. dollars and 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 Pension Plan						Executive Excess Defined Benefit Pension Plan				Other Post-Retirement Benefits
For the Three Months Ended March 31,	2007			2006			2007		2006		2007		2006
Service Cost	$	0		$	0		$	0	$	0	$	2,528	$	1,564
Interest Cost		155,514			156,726			30,840		29,897		23,234		19,468
Expected return on plan assets		(174,100	)		(171,076	)		-		-		-		-
Amortization of transition amount		-			-			-		-		-		6,965
Amortization of prior service cost		(1,175	)		(1,175	)		-		-		-		-
Amortization of net loss		-			-			12,934		14,260		41,640		22,073
Net periodic (benefit) cost		($19,761	)		($15,525	)	$	43,774	$	44,157	$	67,402	$	50,070

As disclosed in the December 31, 2006 financial statements, no contributions are expected to be required in 2007 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 first three months of 2007 were $22,000; for the year 2007, such benefits paid are expected to be $89,000. Cash benefits paid for other post-retirement benefits, primarily for medical claims, totaled $44,000 for the first three months of 2007; for the year 2007, the Company’s actuary has estimated that such benefits to be paid are $180,000.

8.	Investments

The investment balance at March 31, 2007 represents a Rabbi Trust (“the 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, 2007, total investments had a fair value of $2.1 million.

9.	Share-Based Compensation

For the three months ended March 31, 2007 and 2006, included in net income are amounts of $150,000 and $104,000, after-tax, respectively, related to share-based compensation expense, in respect of restricted stock awards issued under the Company’s Director’s Stock Compensation and Performance Incentive Plans.

Stock Options

The Company did not have any stock options outstanding at March 31, 2007 or December 31, 2006, nor were any stock options issued during the three months ended March 31, 2007 and March 31, 2006.

Director’s Stock Compensation Plan

Under the Directors’ Stock Compensation Plan (“DSCP”), each non-employee director of the Company received in 2006 an annual retainer of 600 shares of common stock and an additional 150 shares of common stock for services as a committee chairman. Shares issued under the DSCP are fully vested as of the date of grant. At the date of grant, the Company records a prepaid expense equal to the fair value of the shares issued and amortizes the expense equally over the service period of one year. Compensation expense recorded by the Company related to the DSCP awards was $44,000 and $36,000 for the three-month periods ended March 31, 2007 and 2006, respectively.

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Performance Incentive Plans

The Company’s Compensation Committee of the Board of Directors is authorized to grant key employees of the Company the rights to receive awards of shares of the Company’s common stock, contingent upon the achievement of established performance goals. These awards are subject to certain post-vesting transfer restrictions. The Company issued 10,124 and 23,666 restricted stock awards in the three months ended March 31, 2007 and 2006, respectively, to key employees under the Company’s Performance Incentive Plan (“PIP”). The shares granted under the PIP are fully vested and the fair value of each share is equal to the market price of the Company’s common stock on the date of grant. The fair value of these restricted stock awards, based on the fair value of the Company’s stock on the issue date, was $30.89 and $30.40, for the three months ended March 31, 2007 and 2006, respectively. Compensation expense recorded by the Company related to the restricted stock awards was $202,000 and $135,000 for the three-month periods ended March 31, 2007 and 2006, respectively.

A summary of restricted stock activity as of March 31, 2007, and changes during the three months then ended, is presented below:

	Number of Restricted Shares		Weighted Average Grant Date Fair Value
Outstanding — December 31, 2006		-
Issued — March 1, 2007		10,124	$	30.89
Vested		10,124
Outstanding — March 31, 2007		-

10.

Stockholders’ Equity

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

	For the Three Months Ended March 31, 2007		For the Twelve Months Ended December 31, 2006
Common Stock shares issued and outstanding ⁽¹⁾
Shares issued — beginning of period balance		6,688,084		5,883,099
Dividend Reinvestment Plan ⁽²⁾		9,311		38,392
Retirement Savings Plan		7,952		29,705
Conversion of debentures		2,702		16,677
Employee award plan		350		350
Performance shares and options exercised ⁽³⁾		10,124		29,516
Public offering		-		690,345
Shares issued — end of period balance ⁽⁴⁾		6,718,523		6,688,084

Treasury shares — beginning of period balance		-		(97	)
Other issuances		-		97
Treasury Shares — end of period balance		-		-
Total Shares Outstanding		6,718,523		6,688,084

⁽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 Directors' compensation.
⁽⁴⁾ Includes 54,473 and 48,187 shares at March 31, 2007 and December 31, 2006, respectively, held in a Rabbi Trust established by the Company relating to the Executive Deferred Compensation Plan.

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11.

Reclassifications

The Company reclassified some previously reported amounts to conform to current period classifications. Share-based compensation was recorded as a liability to Accrued Compensation at December 31, 2006. Accordingly, the Company reclassified the $123,000 remaining in the liability account after the issuance of the 2006 performance shares to Additional Paid in Capital. This reclassification is considered immaterial to the overall presentation of the Company’s consolidated financial statements.

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 on the Company’s financial condition, results of operations and liquidity. This discussion and analysis should be read in conjunction with the attached unaudited consolidated financial statements and notes thereto and Chesapeake’s Annual Report on Form 10-K for the year ended December 31, 2006, 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 effect 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;

·	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 may affect the operating costs and competitive positions of our natural gas and propane distribution operations;

·	third-party competition on the Company’s unregulated and regulated businesses;

·	changes in federal, state or local regulatory and tax requirements, including deregulation;

·	changes in technology on the Company’s advanced information services segment;

·	credit risk and credit requirements on the Company’s energy marketing subsidiaries;

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

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

·	inflation may impact the results of operations, cash flows and financial position;

·	inability to access the financial markets may impair future growth; and

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

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Overview

Chesapeake is a diversified utility company engaged directly or through subsidiaries in natural gas distribution, transmission and marketing, propane distribution and wholesale marketing, advanced information services and other related businesses. For additional information regarding segments, refer to Note 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 earnings from a stable utility foundation and investing in related businesses and services that provide opportunities for returns greater than traditional utility returns. The key elements of this strategy include:

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

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

·	Expanding the propane distribution business in existing and new markets through 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 natural gas and propane consumption is highest due to colder temperatures.

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Results of Operations for the Quarter Ended March 31, 2007

Consolidated Overview

The Company’s net income for the quarter ended March 31, 2007 increased $1.9 million, or 31 percent, compared to the same period in 2006. Net income was $8.0 million, or $1.18 per share (diluted), an increase of $0.17 per share compared to 2006. The year-over-year increase in earnings reflects an increase in the operating income at the Company’s natural gas and propane operations from continued growth and colder temperatures on the Delmarva Peninsula, which increased volumes sold to customers. The Company estimates that the growth and colder weather contributed $2.0 million and $1.3 million, respectively, to gross margin during the first quarter of 2007.

For the Three Months Ended March 31,	2007		2006			Change
Operating Income
Natural Gas	$	9,615,982	$	7,995,205		$	1,620,777
Propane		4,873,555		3,433,733			1,439,822
Advanced Information Services		48,821		16,309			32,512
Other & eliminations		43,693		(8,019	)		51,712
Operating Income		14,582,051		11,437,228			3,144,823

Other Income		53,374		78,583			(25,209	)
Interest Charges		1,599,250		1,493,337			105,913
Income Taxes		5,045,087		3,926,059			1,119,028
Net Income	$	7,991,088	$	6,096,415		$	1,894,673
Diluted Earnings Per Share	$	1.18	$	1.01		$	0.17

The following discussions and those later in the document on operating income and segment results 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 its business units’ performance and has historically analyzed and reported gross margin information publicly. Other companies may calculate gross margin in a different manner.

Page 16

Natural Gas

The natural gas segment earned operating income of $9.6 million for the quarter ended March 31, 2007 compared to $8.0 million for the corresponding period in 2006, an increase of $1.6 million, or 20 percent.

For the Three Months Ended March 31,	2007		2006		Change
Revenue	$	65,509,667	$	67,637,607		($2,127,940	)
Cost of sales		46,768,746		51,225,173		(4,456,427	)
Gross margin		18,740,921		16,412,434		2,328,487

Operations & maintenance		6,263,401		5,804,448		458,953
Depreciation & amortization		1,795,481		1,487,088		308,393
Other taxes		1,066,057		1,125,693		(59,636	)
Other operating expenses		9,124,939		8,417,229		707,710
Total Operating Income	$	9,615,982	$	7,995,205	$	1,620,777

Statistical Data — Delmarva Peninsula
Heating degree-days ("HDD")
Actual		2,439		2,069		370
10-year average (normal)		2,241		2,281		(40	)

Estimated gross margin per HDD	$	2,234	$	2,234	$	0

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

Residential Customer Information
Average number of customers
Delmarva		43,610		40,213		3,397
Florida		13,262		12,429		833
Total		56,872		52,642		4,230

Gross margin for the Company’s natural gas segment increased by $2.3 million, or 14 percent, and other operating expenses increased $708,000, or eight percent, in the three months ended March 31, 2007 compared to the same period in 2006. The gross margin increases of $916,000 for the natural gas transmission operation, $1.5 million for the Delmarva natural gas distribution operations, and $126,000 for the Florida natural gas distribution operation were partially offset by lower gross margin of $204,000 for the natural gas marketing operation, as further explained below.

Natural Gas Transmission

The natural gas transmission operation achieved gross margin growth of $916,000, or 19 percent. This increase was attributed to new transportation capacity contracts implemented in November 2006. In total for 2007, these new transportation capacity contracts are expected to generate an additional gross margin of $3.3 million above and beyond 2006 gross margins. An increase of $437,000 in other operating expenses partially offset the increased gross margin. The factors contributing to the increase in other operating expenses are as follow:

·	Payroll costs increased by $66,000 to comply with federal pipeline integrity maintenance regulations and to serve the additional growth experienced by the operation.

·	Regulatory expenses increased by $54,000 in the first quarter of 2007 as the Company incurred costs associated with its rate filing with the Federal Energy Regulatory Commission (“FERC”).

·	The increased level of capital investment caused higher depreciation and asset removal costs of $230,000 and increased property taxes of $21,000.

·	Other operating expenses relating to various items increased collectively by approximately $66,000.

Page 17

Natural Gas Distribution

The Delmarva distribution operations experienced an increase of $1.5 million, or 19 percent, in gross margin. The significant items contributing to the increase in gross margin include:

The Company estimates that weather contributed $533,000 to gross margin in the first quarter 2007 compared to the same period in 2006, as temperatures on the Delmarva Peninsula were 18 percent colder in 2007. The colder temperatures did not have a significant impact on the Maryland distribution operation’s gross margin in the first quarter of 2007 because the operation’s approved rate structure now includes a weather normalization adjustment (WNA) mechanism. The WNA mechanism was implemented in October 2006 and is designed to protect a portion of the Company’s revenues against warmer-than-normal weather as deviations from normal weather can affect our financial performance and liquidity. The WNA also serves to offset the impact of colder-than-normal weather by reducing the amounts the Company can charge its customers during such periods.

Continued residential customer growth also contributed to the increase in gross margin. The average number of residential customers on the Delmarva Peninsula increased by 3,397, or eight percent, for the first quarter 2007 compared to the same period in 2006 and the Company estimates that these additional residential customers contributed approximately $460,000 to gross margin.

·	In October 2006, the Maryland PSC granted the Company a base rate increase, which resulted in $313,000 year-over-year increase to gross margin in the first quarter of 2007.

·	The remaining $185,000 increase in gross margin can be attributed to various factors, including an increase in the number of commercial and industrial customers.

Gross margin for the Florida distribution operation increased by $126,000, or four percent. The impact of a seven percent growth in residential customers and a four percent growth in commercial customers contributed to the increase in gross margin.

Other operating expense for the natural gas distribution operations increased by $379,000 in the first quarter 2007 compared to the first quarter 2006. Among the key components of the increase were the following:

·	Payroll costs have increased by $44,000 to serve the additional growth experienced by the operation.

·	Incentive compensation increased by $104,000 as a result of the improved operating results in 2007 compared to 2006.

·	Allowance for uncollectible accounts increased by $74,000 due to higher revenues from the colder temperatures on the Delmarva Peninsula and customer growth.

·	Facilities maintenance costs increased by $75,000 as the operations performed increased maintenance and repairs on meters and mains.

·	Depreciation and amortization expense, asset removal cost and property taxes increased by $104,000, $48,000 and $31,000, respectively, as a result of the Company’s continued capital investments.

·	Merchant payment fees increased by $57,000 as the Company experienced more customers making payments with the use of credit cards.

·	Corporate costs decreased by $133,000 due to lower payroll and related expenses.

·	In addition, other operating expenses relating to various minor items decreased by approximately $25,000.

Natural Gas Marketing

Gross margin for the natural gas marketing operation decreased by $204,000, or 27 percent, for the first three months ended March 31, 2007 compared to the same period in 2006. The decline in gross margin was primarily the result of unfavorable imbalance resolutions with interstate pipelines, which caused an increase in the cost of gas. Other operating expenses decreased by $108,000 for the marketing operation due to lower levels of incentive compensation as a result of lower operating results in the first quarter of 2007, partially offset by an increase in the allowance for uncollectible accounts.

Page 18

Propane

The propane segment experienced an increase of $1.4 million, or 42 percent, in operating income for the three months ended March 31, 2007 compared to the same period in 2006. Gross margin increased by $2.1 million, which was partially offset by an increase in other operating expenses of $695,000.

For the Three Months Ended March 31,	2007		2006		Change
Revenue	$	24,922,806	$	20,550,937	$	4,371,869
Cost of sales		15,332,974		13,095,992		2,236,982
Gross margin		9,589,832		7,454,945		2,134,887

Operations & maintenance		3,996,944		3,340,475		656,469
Depreciation & amortization		445,580		416,709		28,871
Other taxes		273,753		264,028		9,725
Other operating expenses		4,716,277		4,021,212		695,065
Total Operating Income	$	4,873,555	$	3,433,733	$	1,439,822

Statistical Data — Delmarva Peninsula
Heating degree-days ("HDD")
Actual		2,439		2,069		370
10-year average (normal)		2,241		2,281		(40	)

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

Operating income for the propane segment increased by $1.4 million, or 42 percent, to $4.9 million for the three months ended March 31, 2007 compared to the same period in 2006. This increase was due primarily to colder weather on the Delmarva Peninsula in the first quarter of 2007, which resulted in increased consumption by customers. Gross margin in the Delmarva propane distribution operations increased, compared to first quarter 2006, by $1.9 million, primarily due to colder weather. Gross margin also increased in the Florida propane distribution operation and the Company’s wholesale propane marketing operation by $24,000 and $214,000, respectively.

Delmarva Propane Distribution

The Delmarva propane distribution operation’s increase in gross margin of $1.9 million resulted from the following:

Volumes sold in the first quarter 2007 increased by 1.5 million gallons, or 20 percent, primarily because temperatures on the Delmarva Peninsula were 18 percent colder during this period in 2007 when compared to the same period in 2006. The Company estimates that the colder weather increased gross margin by approximately $730,000 for the Delmarva propane distribution operation compared to the first quarter of 2006.

Gross margin further increased by $767,000 in the first quarter of 2007 compared to the same period in 2006 because of a $0.08 increase in the average gross margin per retail gallon. This increase is attained when market prices of propane rise greater than the Company’s average inventory price per gallon. This trend reverses when market prices decrease and moves closer to the Company’s inventory price per gallon. Contributing to the Company’s lower average inventory price were write-downs of approximately $272,000 of its propane inventory in the third and fourth quarters of 2006 as market prices were lower than the Company’s cost.

Gross margin for the Delmarva Community Gas Systems (“CGS”) increased by $413,000 in the first quarter 2007, compared to the same period in 2006, primarily because of colder weather and an increase in the average number of customers. The average number of CGS customers increased by approximately 1,000 to a total count of approximately 4,600, or a 28 percent increase, compared to the first quarter 2006. The Company expects the growth of its CGS operation to continue as the number of systems currently under construction or under contract is anticipated to provide an additional 7,700 CGS customers.

Page 19

Total other operating expenses increased by $616,000 for the Delmarva operations in the three months ended March 31, 2007, compared to the same period in 2006. The significant items contributing to this increase are explained below.

The increase in operating expenses for the first quarter of 2007 is magnified by the Company’s one-time recovery of previously incurred costs of $300,000 from one of its propane suppliers in March 2006. This recovery reimbursed the Company for fixed costs incurred in the removal of above-normal levels of petroleum by-products contained in approximately 75,000 gallons of propane that it purchased from the supplier. The recovery of these costs substantially reduced other operating expenses in the first quarter of 2006.

·	Payroll costs increased by $59,000 to serve the additional delivery of propane as a result of the colder temperatures in the first quarter of 2007.

·	Incentive compensation increased by $181,000 in the first quarter 2007 as the Delmarva distribution operations experienced improved operating results.

·	In addition, other operating expenses relating to various items decreased collectively by approximately $76,000.

Florida Propane Distribution

The Florida propane distribution operation experienced an increase in gross margin of $24,000, or six percent, in the three months ended March 31, 2007 compared to the same period in 2006. Gross margin from propane sales increased $13,000 as a higher average gross margin per retail gallon was partially offset by a nine percent decrease in the volumes sold in 2007. The remaining increase of $11,000 is attributed to higher in-house piping sales. Other operating expenses in the first quarter 2007 compared to the first quarter 2006 increased by $49,000 due to an increase in corporate services and higher depreciation expense.

Propane Wholesale and Marketing

Gross margin for the Company’s propane wholesale marketing operation increased by $214,000, or 41 percent, in the first quarter of 2007 compared to the same period in 2006. This increase reflects the larger number of market opportunities that arose in 2007 due to price volatility in the propane wholesale market, which exceeded the level of price fluctuations experienced in 2006. The increase in gross margin was partially offset by higher other operating expenses of $30,000 primarily due to higher incentive compensation based on the increased earnings in 2007.

Page 20

Advanced Information Services

The advanced information services segment provides domestic and international clients with information technology related business services and solutions for both enterprise and e-business applications. The advanced information services business contributed operating income of $49,000 for 2007, representing an increase of $33,000 compared to the same period in 2006 on gross margin growth of approximately $249,000, or 20 percent.

For the Three Months Ended March 31,	2007		2006		Change
Revenue	$	3,305,123	$	2,825,204	$	479,919
Cost of sales		1,834,147		1,603,159		230,988
Gross margin		1,470,976		1,222,045		248,931

Operations & maintenance		1,191,419		1,014,448		176,971
Depreciation & amortization		34,237		33,664		573
Other taxes		196,499		157,624		38,875
Other operating expenses		1,422,155		1,205,736		216,419
Total Operating Income	$	48,821	$	16,309	$	32,512

The increase of revenues in the first quarter 2007 is derived from:

·	An increase of $371,000 in consulting revenues as the number of billable hours increased by 13 percent;

·	An increase of $81,000 from Managed Database Administration (“MDBA”) services, first offered in 2006, which provide clients with professional database monitoring and support solutions during business hours or around the clock;

·	An increase of $73,000 in product revenues; and

·	A decrease of $45,000 in revenue from training services.

Other operating expenses increased by $216,000 in the first quarter 2007 to $1.4 million, compared to $1.2 million for the same period in 2006. This increase in operating expenses is primarily due to an increase in incentive compensation based on improved operating results and other costs incurred to support the growth and improved earnings.

Other Business Operations and Eliminations

Other operations consist primarily of subsidiaries that own real estate leased to other Company subsidiaries and the results of operations for OnSight Energy, LLC (“OnSight”). Other operations generated an operating income of approximately $44,000 for the three months ended March 31, 2007 compared to an operating loss of approximately $8,000 for the same period in 2006. The improved results are primarily from OnSight experiencing a reduced operating loss in the first quarter of 2007.

The Company formed OnSight in 2004 to provide distributed energy services. Distributed energy refers to a variety of small, modular power generating technologies that may be combined with heating and/or cooling systems. For the three months ended March 31, 2007, OnSight had an operating loss of $32,000 compared to an operating loss of $98,000 for the same period in 2006. The reduced operating loss in 2007 is a direct result of lower operating expenses as the Company took actions in the third quarter of 2006 to reduce operating expenses going forward.

Page 21

For the Three Months Ended March 31,	2007		2006			Change
Revenue	$	154,623	$	155,135			($512	)
Cost of sales		-		437			(437	)
Gross margin		154,623		154,698			(75	)

Operations & maintenance		53,428		104,089			(50,661	)
Depreciation & amortization		41,268		40,656			612
Other taxes		17,003		18,743			(1,740	)
Other operating expenses		111,699		163,488			(51,789	)
Operating Income (Loss) - Other		42,924		(8,790	)		51,714
Operating Income - Eliminations *		769		771			(2	)
Total Operating Income (Loss)	$	43,693		($8,019	)	$	51,712
* Eliminations are entries required to eliminated activities between business segments from the consolidated results.

Income Taxes

Income tax expense for the three months ended March 31, 2007 was $5.0 million compared to $3.9 million for the three months ended March 31, 2006. The increase in income tax expense primarily reflects higher earnings. The effective tax rate for the first quarter of 2007 is 38.7 percent compared to an effective tax rate of 39.2 percent for the same period in 2006.

Interest Expense

Total interest expense for the first quarter of 2007 increased approximately $106,000, or seven percent, compared to the same period in 2006. The higher interest expense is a result of the following developments:

The average long-term debt balance during first quarter 2007 was $78.0 million with a weighted average interest rate of 6.68 percent, compared to $62.8 million with a weighted average interest rate of 7.16 percent for first quarter 2006. The large year-over-year increase in the average long-term debt balance is the result of a debt placement of $20 million Senior Notes (“Notes”) at 5.5 percent in October 2006 with three institutional investors (The Prudential Insurance Company of America, Prudential Retirement Insurance and Annuity Company and United Omaha Life Insurance Company). The funds received from the debt placement were used to finance a portion of the more than $39.3 million of net property, plant, and equipment added in 2006.

·	An increase in the average short-term interest rates in the first quarter of 2007 compared to 2006. The average interest rate for short-term borrowing increased from 4.99 percent to 5.71 percent.

·	A decrease in the average short-term debt balance during the first quarter of 2007 compared to the same period in 2006. The average short-term borrowing balance decreased $11.6 million in 2007 to $17.5 million compared to $29.1 million in 2006.

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 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.

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By comparison, during the first three months of 2006, net cash provided by operating activities was $19.9 million, cash used by investing activities was $7.1 million and cash used by financing activities was $12.5 million.

The Board of Directors has authorized the Company to borrow up to $55.0 million of short-term debt from various banks and trust companies under short-term lines of credit. As of March 31, 2007, Chesapeake currently has four unsecured bank lines of credit with two financial institutions, totaling $80.0 million. These bank lines will provide funds for the Company’s short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of its capital expenditures. Two of the bank lines, totaling $15.0 million, are committed. The other two lines are subject to the availability of bank funds. The outstanding balance of short-term borrowing at March 31, 2007 and December 31, 2006 was $21.5 million and $27.6 million, respectively.

Chesapeake has budgeted $45.5 million for capital expenditures during 2007. This amount includes $20.2 million for natural gas distribution, $16.5 million for natural gas transmission, $7.5 million for propane distribution and wholesale marketing, $154,000 for advanced information services and $915,000 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 and the replacement of 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. Financing for the 2007 capital expenditure program is expected 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 acquisition opportunities, changing economic conditions, customer growth in existing areas, regulation, new growth opportunities and availability of capital.

Chesapeake expects to incur approximately $75,000 for environmental-related expenditures in 2007 and the same amount in 2008. Additional expenditures may be required in future years (see Note 4 to the Consolidated Financial Statements). Management does not expect financing of future environmental-related expenditures to have a material adverse effect on the financial position or capital resources of the Company.

Capital Structure

The following presents the Company’s capitalization as of March 31, 2007 and December 31, 2006:

	March 31, 2007				December 31, 2006
	(In thousands, except percentages)

Long-term debt, net of current maturities	$	69,984	37	%	$	71,050	39	%
Stockholders' equity	$	118,410	63	%	$	111,152	61	%
Total capitalization, excluding short-term debt	$	188,394	100	%	$	182,202	100	%

As of March 31, 2007, common equity represented 63 percent of total capitalization, compared to 61 percent at December 31, 2006. 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 54 percent and 51 percent at March 31, 2007 and December 31, 2006, respectively. 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.

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Shelf Registration

In July 2006, the Company filed a registration statement on Form S-3 with the SEC to issue up to $40.0 million in new common stock and/or debt securities. The registration statement was declared effective by the SEC in November 2006. At March 31, 2007, the Company had approximately $20.0 million remaining under this registration statement.

Cash Flows Provided By Operating Activities

Cash flows provided by operating activities were as follows:

For the Three Months Ended March 31,	2007		2006
Net Income	$	7,991,088	$	6,096,415
Non-cash adjustments to net income		2,389,483		1,082,415
Changes in working capital		6,540,700		12,722,529
Net cash provided by operating activties	$	16,921,271	$	19,901,359

Year-over-year changes in our cash flows from operating activities are attributable primarily to net income, depreciation and working capital changes. The changes in working capital are impacted 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 three months ended March 31, 2007, net cash flow provided by operating activities was $16.9 million, a decrease of $3.0 million compared to the same period of 2006. The decrease was due primarily to changes in working capital, which were partially offset by higher net income and higher depreciation and amortization expense. The reduction in working capital was due primarily to the decrease in cash provided from accounts receivable, which was partially offset by a decrease in cash used by accounts payable for gas purchases payable. These changes were impacted by the weather and the lower gas commodity costs.

Cash Flows Used in Investing Activities

Net cash flows used in investing activities totaled $8.4 million and $7.1 million during the three months ended March 31, 2007 and 2006, respectively. Cash utilized for capital expenditures was $8.4 million and $7.1 million for the first three months of 2007 and 2006, respectively. Additions to property, plant and equipment in these quarters were primarily for natural gas transmission, natural gas distribution and propane distribution. In both 2007 and 2006, the natural gas distribution expenditures were used primarily to fund expansion and facilities improvements. In both periods, the natural gas transmission capital expenditures related primarily to expanding the Company’s transmission system. In addition, $68,000 more than what was recovered through rates charged to customers was used for environmental expenditures in the first quarter of 2007 compared to a net recovery of $40,000 for environmental costs through rates charged to customers in the same period in 2006.

Cash Flows Used in Financing Activities

Cash flows used in financing activities totaled $8.7 million and $12.5 million for the three months ended March 31, 2007 and 2006, respectively. Significant financing activities include the following:

·	The Company repaid $1.0 million of long-term debt during the first three months of 2007 and 2006.

·	During the first three months of 2007, the Company reduced short-term debt by $7.3 million compared to a $10.5 million reduction in the first three months of 2006.

During the first three months of 2007, the Company paid $1.7 million in cash dividends compared with dividend payments of $1.5 million for the same time period in 2006. The increase in dividends paid over the prior year reflects an increase in the annualized dividend rate from $1.14 per share during first quarter 2006 to $1.16 per share in the first quarter 2007 and the issuance of additional shares of common stock.

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Off-Balance Sheet Arrangements

The Company has issued corporate guarantees to certain vendors of its propane wholesale marketing subsidiary, its Florida natural gas supply and management subsidiary, and its Delmarva propane distribution subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of a subsidiary’s default. Liabilities for these purchases are recorded in the Consolidated Financial Statements. The aggregate amount guaranteed at March 31, 2007 was $22.2 million, with the guarantees expiring on various dates in 2007 and 2008.

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, 2007. The letter of credit is provided as security for claims amounts to satisfy the deductibles on the Company’s policies.

Contractual Obligations

There have not been any material changes in the contractual obligations presented in the Company’s 2006 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, 2007.

	Payments Due by Period
Purchase Obligations	Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years		Total
Commodities ⁽¹⁾	$	1,396,163	$	74,008	$	0	$	0	$	1,470,171
Propane ⁽²⁾		22,087,913		-		-		-		22,087,913
Total Purchase Obligations	$	23,484,076	$	74,008	$	0	$	0	$	23,558,084

⁽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 $23.5 million. See Part I, Item 3, “Quantitative and Qualitative Disclosures about Market Risk,” below for further information.

Environmental Matters

As more fully described above in Note 4 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.

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Other Matters

Regulatory Matters

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

Delaware. On September 1, 2006, the Company filed with the Delaware Public Service Commission (“Delaware PSC”) its annual Gas Sales Service Rates Application (“GSR”) seeking the approval of the Delaware PSC to change its GSR rates effective for service rendered on and after November 1, 2006. On October 3, 2006, 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 by the Delaware PSC. The Division of the Public Advocate (“DPA”) has recommended a cost disallowance of approximately $4.4 million related to the Delaware division’s commodity procurement purchases and a disallowance of approximately $275,000 related to pipeline capacity the Delaware division holds in eastern Sussex County, Delaware. The Delaware PSC Staff has recommended a cost disallowance of approximately $2.2 million related to the Delaware division’s commodity procurement purchases and the deferral of approximately $535,000 related to pipeline capacity the Delaware division holds in eastern Sussex County, Delaware. The Company disagrees with these recommendations and intends to oppose vigorously any proposed cost disallowance and deferral. Under established Delaware law, gas procurement costs, like other normally accepted operating expenses, cannot be disallowed unless it is shown that the costs were the result of an abuse of discretion, bad faith, or waste. The Company submitted its rebuttal position on April 19, 2007. Management believes that the Company’s gas procurement practices and pipeline capacity costs were reasonable and that, in no event were the costs at issue incurred as a result of any abuse of discretion, bad faith, or waste on the part of the Company. In Management’s opinion, neither the DPA nor the Delaware PSC Staff has presented any evidence to support a finding of abuse of discretion, bad faith, or waste on the part of the Company. The Company expects a final decision by the Delaware PSC during the second or third quarter of 2007. At this time, the Company believes that it has valid defenses to the proposed disallowance of costs.

On September 2, 2005, the Delaware division filed an application with the Delaware PSC requesting approval of an alternative rate design and rate structure in order to provide natural gas service to prospective customers in eastern Sussex County. While Chesapeake does provide natural gas service to residents and businesses in portions of Sussex County, under the Company’s current tariff, natural gas distribution lines have not been extended to a large portion of the State of Delaware’s recently targeted growth areas in eastern Sussex County. In April 2002, Governor Ruth Ann Minner established the Delaware Energy Task Force (“Task Force”), whose mission was to address the State of Delaware’s long-term and short-term energy challenges. In September 2003, the Task Force issued its final report to the Governor that included a strategy related to enhancing the availability of natural gas within the State by evaluating possible incentives for expanding residential and commercial natural gas service. Chesapeake believes its current proposal to implement a rate design that will enable the Company to provide natural gas as a viable energy choice to a broad number of prospective customers within eastern Sussex County is consistent with the Task Force recommendation. While the Company cannot predict the outcome at this time, the Company anticipates a final decision from the Delaware PSC regarding its proposed alternative rate design and rate structure in the second half of 2007.

On November 1, 2006, 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, 2006. The Delaware PSC granted approval of the ER rate at its regularly scheduled meeting on November 21, 2006, subject to full evidentiary hearings and a final decision. On January 23, 2007, the Delaware PSC granted final approval of the ER rate as filed.

On November 9, 2006, the Delaware division filed two applications with the Delaware PSC requesting approval for a Town of Millsboro Franchise Fee Rider and a Town of Georgetown Franchise Fee Rider. These Riders will allow the Delaware division to charge all respective natural gas customers within town limits the franchise fee paid by the Delaware division to the Towns of Millsboro and Georgetown as a condition to providing natural gas service. The Delaware PSC granted approval of both Riders on January 23, 2007.

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Maryland. On December 14, 2006, the Maryland Public Service Commission (“Maryland PSC”) held an evidentiary hearing to determine the reasonableness of the Maryland division’s four quarterly gas cost recovery filings during the twelve months ended September 30, 2006. On December 15, 2006, the Hearing Examiner issued proposed findings approving the quarterly gas cost recovery rates as filed by the Maryland division, permitting complete recovery of its purchased gas costs for the period under review. No appeals or written exceptions to the proposed findings were made and a final order approving the quarterly gas cost recovery rates as filed was issued by the Maryland PSC on January 17, 2007.

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, and which, if approved, would result in a decrease in its depreciation expense, which would equate to a rate decrease of approximately $155,000 annually. The Maryland division anticipates a decision from the Maryland PSC on its proposed change in depreciation expense during the second or third quarter of 2007.

Florida. On September 15, 2006, the Florida gas distribution division filed a petition with the Florida Public Service Commission (“Florida PSC”) for approval of its Energy Conservation Cost Recovery Factors for the year 2007. Approved on November 30^thby the Florida PSC, the new factors went into effect on January 1, 2007.

On October 10, 2006, the Florida division filed a petition with the Florida PSC for authority to implement phase two of its experimental transitional transportation service (“TTS”) pilot program, and for approval of a new tariff to reflect the division’s transportation service environment. When approved, the implementation of phase two of the TTS program for residential and certain small commercial consumers will expand the number of pool managers from one to two, and increase the gas supply pricing options available to these consumers. Approved on April 24, 2007by the Florida PSC, the new factors will go into effect in the third quarter of 2007.

On November 29, 2006, the Florida division filed a petition with the Florida PSC for authority to modify its energy conservation programs. In this petition, the Florida division is seeking approval to increase the cash allowances paid within the Residential Homebuilder Program and the Residential Appliance Replacement Program, and to expand the scope of the Residential Water Heater Retention Program to add natural gas heating systems, cooking and clothes drying appliances. The Florida PSC granted approval of the petition in an order dated March 5, 2007. The modifications and new cash allowances became effective on March 30, 2007.

Eastern Shore. The system expansion and rate matters for Eastern Shore include:

System Expansion 2006 - 2008. On January 20, 2006, Eastern Shore filed an application for a Certificate of Public Convenience and Necessity for its 2006-2008 system expansion project (the “2006 - 2008 Project”) with the FERC. The application requested authority to construct and operate approximately 55 miles of new pipeline facilities and two new metering and regulating station facilities to provide an additional 47,350 dekatherms per day (“dt/d”) of firm transportation service in accordance with the phased-in customer requests of 26,200 dt/d in 2006, 10,300 dt/d in 2007, and 10,850 dt/d in 2008, at a total estimated cost of approximately $33.6 million. On June 13, 2006, the FERC issued a Certificate to Eastern Shore authorizing it to construct and operate the 2006 - 2008 Project as proposed. The following table provides a breakdown for the additional amounts of firm capacity per day, the estimated capital investment required, and the estimated annual gross margin contribution for the new services that will become effective November 1^st for each of the respective years of the project:

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	Year
Services implemented November 1,	2006	2007	2008
Additional firm capacity per day	26,200	10,300	10,850
Capital investment	$17 million	$8 million	$8 million
Annualized gross margin contribution	$3,670,000	$1,484,000	$1,595,000

Eastern Shore has completed and placed in service the authorized Phase I facilities. Phase II and Phase III facilities are expected to be constructed in 2007 and 2008, respectively.

Bay Crossing Project. Eastern Shore has proposed to develop, construct and operate approximately 63 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 Bay Crossing Project.

Chesapeake and Delmarva are parties to existing firm natural gas transportation service agreements with Eastern Shore and each desires firm transportation services under the Bay Crossing Project, as evidenced by the Precedent Agreements. Pursuant to the Precedent Agreements, the parties have agreed to proceed with the required initiatives to obtain the governmental and regulatory authorizations that are necessary for Eastern Shore to provide, and for Chesapeake and Delmarva to utilize firm transportation services under the Bay Crossing Project.

Eastern Shore, Chesapeake and Delmarva have also entered into Letter Agreements which provide that, in the event that the Bay Crossing Project is not certified and placed in service, Chesapeake and Delmarva will each pay their proportionate share of certain pre-certification costs by means of a negotiated surcharge of up to $2 million, over a period of no less than 20 years.

In connection with the Bay Crossing Project, on June 27, 2006 Eastern Shore submitted a petition to the FERC seeking approval of an uncontested rate-related Settlement Agreement by and between Eastern Shore, Chesapeake and Delmarva (the “Settlement Agreement”). The Settlement Agreement provides Eastern Shore and all customers utilizing Eastern Shore’s system with benefits, including but not limited to the following: (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 granted approval of the Settlement Agreement, which was uncontested. 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.

Eastern Shore anticipates entering into a pre-filing process at the FERC during the first half of 2007 with the ultimate goal of obtaining FERC approval to construct the Bay Crossing Project. Eastern Shore will be required to obtain permits from other federal, state and local agencies prior to proceeding with construction. The total estimated cost of the Bay Crossing Project is $93 million, the majority of which will not be spent until the Company obtains the appropriate approvals and permits. The final cost will depend upon the final size and route of the pipeline, as well as the final costs of design, construction materials and labor.

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Rate Matters. On October 31, 2006 Eastern Shore filed a Section 4 base rate proceeding with the FERC in compliance with the settlement approved in its prior base rate proceeding. Eastern Shore’s filed rates, proposed to be effective November 1, 2006, reflect an annual increase of $5,589,000 over its current annual operating revenues. The proposed rates reflect increases in operating and maintenance expenses, depreciation expense, taxes other than income taxes, and return on new gas plant facilities placed into service before March 31, 2007.

On November 30, 2006 the FERC issued its Order Accepting and Suspending Tariff Sheets Subject to Refund and Establishing a Hearing. The FERC accepted and suspended the effectiveness of Eastern Shore’s rate increase until May 1, 2007, subject to refund and the outcome of the hearing established in the order.

On December 19, 2006 the FERC’s Presiding Administrative Law Judge approved a procedural schedule to govern further proceedings in this case. An initial settlement conference was held on April 17, 2007 at the FERC’s offices in Washington, D.C. A final outcome of this preceding cannot be determined at this time.

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 convert to oil to satisfy their fuel requirements. Lower levels of interruptible sales occur when oil prices 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 side of this business to maximize sales volumes. 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 transportation 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. As it relates to transportation services, the Company’s competitors include interstate transmission companies if the distribution customer is 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 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 it is typically less expensive than electricity, based on equivalent BTU value. Propane also competes with home heating oil as an energy source. Since natural gas has historically been less expensive than propane, propane is generally not distributed in geographic areas serviced by natural gas pipeline or distribution systems.

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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 than does the Company. In addition, changes in the advanced information services business are occurring rapidly, which could adversely impact the markets for the products and services offered by these businesses. This segment 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. 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 while monitoring 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 to the unaudited condensed consolidated financial statements.

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 $77.6 million at March 31, 2007, as compared to a fair value of $80.4 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 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, 2007 and elected not to hedge any of its inventories.

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The Company’s propane wholesale marketing operation is a party to natural gas liquids (“NGL”) forward contracts, primarily propane contracts, with various third parties. These contracts require that the propane wholesale marketing operation purchase or sell NGL at a fixed price at fixed future dates. At expiration, the contracts are settled by the delivery of NGL 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 on a daily basis. 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, 2007 is presented in the following table.

At March 31, 2007	Quantity in gallons	Estimated Market Prices	Weighted Average Contract Prices
Forward Contracts
Sale	22,675,926	$0.8775 — $1.1225	$1.0346
Purchase	21,798,000	$0.8700 — $1.0963	$1.0133

Estimated market prices and weighted average contract prices are in dollars per gallon. All contracts expire in 2007 or the first quarter 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, 2007. 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, 2007.

Changes in Internal Control Over Financial Reporting

During the quarter ended March 31, 2007, 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

None.

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 (2)		Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs (2)
January 1, 2007 through January 31, 2007 ⁽¹⁾		466	$	29.96		0		0
February 1, 2007 through February 28, 2007		0	$	0.00		0		0
March 1, 2007 through March 31, 2007		0	$	0.00		0		0
Total		466	$	29.96		0		0

⁽¹⁾ Chesapeake purchased shares of stock on the open market for the purpose of reinvesting the dividend on shares held in Rabbi Trust accounts for certain Senior Executives. During the quarter, 466 shares were purchased through executive dividend deferrals.
⁽²⁾ Except for the purpose described in Footnote (1), Chesapeake has no publicly announced plans or programs to repurchase its shares.

Item 3. Defaults upon Senior Securities

None

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

None

Item 5. Other Information

None

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 9, 2007
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 9, 2007
32.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated May 9, 2007
32.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated May 9, 2007

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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 9, 2007

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