Edgar Filing: CHESAPEAKE UTILITIES CORP

Chesapeake Utilities Corporation Form 10-Q - September 30, 2006

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: September 30, 2006

[ ]	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 — 5,990,582 shares outstanding as of October 31, 2006.

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	18
	Item 3. Quantitative and Qualitative Disclosures about Market Risk	39
	Item 4. Controls and Procedures	40
PART II — OTHER INFORMATION		41
	Item 1. Legal Proceedings	41
	Item 1A. Risk Factors	41
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	46
	Item 3. Defaults upon Senior Securities	46
	Item 4. Submission of Mattters to a Vote of Security Holders	46
	Item 5. Other Information	46
	Item 6. Exhibits	46
SIGNATURES		47

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Income (Unaudited)

For the Three Months Ended September 30,	2006			2005
Operating Revenues	$	35,141,530		$	35,155,121

Operating Expenses
Cost of sales, excluding costs below		21,758,558			21,957,971
Operations		9,446,616			9,815,819
Maintenance		513,356			461,586
Depreciation and amortization		2,044,179			1,889,266
Other taxes		1,216,684			1,129,628
Total operating expenses		34,979,393			35,254,270
Operating Income (Loss)		162,137			(99,149	)
Other income (loss) net of other expenses		(12,091	)		19,493
Interest charges		1,340,879			1,272,196
Loss Before Income Taxes		(1,190,833	)		(1,351,852	)
Income taxes		(534,254	)		(658,078	)
Net Loss		($656,579	)		($693,774	)

Earnings Per Share of Common Stock:
Basic		($0.11	)		($0.12	)
Diluted		($0.11	)		($0.12	)
Basic weighted average shares outstanding		5,973,149			5,851,926
Diluted weighted average shares outstanding		5,973,149			5,851,926

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 Income (Unaudited)

For the Nine Months Ended September 30,	2006		2005
Operating Revenues	$	170,395,955	$	155,220,745

Operating Expenses
Cost of sales, excluding costs below		116,188,846		101,453,132
Operations		27,899,729		29,325,623
Maintenance		1,540,963		1,279,820
Depreciation and amortization		6,058,529		5,701,357
Other taxes		3,903,155		3,730,674
Total operating expenses		155,591,222		141,490,606
Operating Income		14,804,733		13,730,139
Other income net of other expenses		130,208		330,354
Interest charges		4,335,568		3,823,140
Income Before Income Taxes		10,599,373		10,237,353
Income taxes		4,027,027		3,902,407
Net Income	$	6,572,346	$	6,334,946

Earnings Per Share of Common Stock:
Basic	$	1.11	$	1.09
Diluted	$	1.10	$	1.07
Basic weighted average shares outstanding		5,945,119		5,823,144
Diluted weighted average shares outstanding		6,069,893		5,982,303

Cash Dividends Declared Per Share of Common Stock:	$	0.865	$	0.850

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

Page 2

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

For the Nine Months Ended September 30,	2006			2005
*Operating Activities*
Net Income	$	6,572,346		$	6,334,946
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization		6,058,529			5,701,357
Depreciation and accretion included in other costs		2,288,509			2,006,726
Deferred income taxes, net		(2,304,070	)		(922,437	)
Unrealized loss on commodity contracts		(708,915	)		(630,560	)
Unrealized loss on investments		(65,810	)		(18,866	)
Employee benefits and compensation		1,344,924			1,333,363
Other, net		(3,085	)		(2,508	)
Changes in assets and liabilities:
Purchase of investments		(120,476	)		(1,183,889	)
Accounts receivable and accrued revenue		17,284,220			4,828,374
Propane inventory, storage gas and other inventory		(1,477,854	)		(5,432,158	)
Regulatory assets		3,729,326			686,281
Prepaid expenses and other current assets		(770,470	)		(478,960	)
Other deferred charges		35,101			(40,790	)
Long-term receivables		108,608			141,221
Accounts payable and other accrued liabilities		(19,769,594	)		3,077,798
Income taxes receivable		3,123,440			92,961
Accrued interest		1,024,865			897,341
Customer deposits and refunds		767,474			305,828
Accrued compensation		(842,766	)		108,798
Regulatory liabilities		2,785,999			1,999,921
Other liabilities		(85,854	)		148,823
Net cash provided by operating activities		18,974,447			18,953,570

*Investing Activities*
Property, plant and equipment expenditures		(28,335,269	)		(19,940,043	)
Environmental recoveries (expenditures)		(9,625	)		205,689
Net cash used by investing activities		(28,344,894	)		(19,734,354	)

*Financing Activities*
Common stock dividends		(4,462,307	)		(4,334,573	)
Issuance of stock for Dividend Reinvestment Plan		228,352			282,453
Cash settlement of warrants		(434,782	)		-
Change in cash overdrafts due to outstanding checks		1,042,051			842,674
Net borrowing under line of credit agreements		14,790,072			4,779,169
Repayment of long-term debt		(1,929,619	)		(1,794,596	)
Net cash provided (used) by financing activities		9,233,767			(224,873	)

*Net Decrease in Cash and Cash Equivalents*		(136,680	)		(1,005,657	)
*Cash and Cash Equivalents — Beginning of Period*		2,487,658			1,611,761
*Cash and Cash Equivalents — End of Period*	$	2,350,978		$	606,104

Supplemental Disclosures of Non-Cash Investing Activities:
Capital property and equipment acquired on account, but not paid as of September 30	$	4,291,387		$	68,504

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

Page 3

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

Assets	September 30, 2006			December 31, 2005
Property, Plant and Equipment
Natural gas distribution and transmission	$	238,607,537		$	220,685,461
Propane		43,174,349			41,563,810
Advanced information services		951,500			1,221,177
Other plant		9,110,426			9,275,729
Total property, plant and equipment		291,843,812			272,746,177
Less: Accumulated depreciation and amortization		(83,605,340	)		(78,840,413	)
Plus: Construction work in progress		17,711,608			7,598,531
Net property, plant and equipment		225,950,080			201,504,295

Investments		1,871,921			1,685,635

Current Assets
Cash and cash equivalents		2,350,978			2,487,658
Accounts receivable (less allowance for uncollectible accounts of $849,292 and $861,378, respectively)		39,638,501			54,284,011
Accrued revenue		2,077,674			4,716,383
Propane inventory, at average cost		7,462,209			6,332,956
Other inventory, at average cost		1,580,509			1,538,936
Regulatory assets		633,663			4,434,828
Storage gas prepayments		8,935,207			8,628,179
Income taxes receivable		-			2,725,840
Deferred income taxes		1,643,394			-
Prepaid expenses		2,780,135			2,021,164
Other current assets		3,189,770			1,596,797
Total current assets		70,292,040			88,766,752

Deferred Charges and Other Assets
Goodwill		674,451			674,451
Other intangible assets, net		195,329			205,683
Long-term receivables		852,826			961,434
Other regulatory assets		1,194,483			1,178,232
Other deferred charges		930,265			1,003,393
Total deferred charges and other assets		3,847,354			4,023,193


Total Assets	$	301,961,395		$	295,979,875

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	September 30, 2006			December 31, 2005
Capitalization
Stockholders' equity
Common Stock, par value $0.4867 per share (authorized 12,000,000 shares) ⁽¹⁾	$	2,910,261		$	2,863,212
Additional paid-in capital		41,927,856			39,619,849
Retained earnings		44,276,164			42,854,894
Accumulated other comprehensive income		(578,151	)		(578,151	)
Deferred compensation obligation		1,104,670			794,535
Treasury stock		(1,104,670	)		(797,156	)
Total stockholders' equity		88,536,130			84,757,183

Long-term debt, net of current maturities		56,792,273			58,990,363
Total capitalization		145,328,403			143,747,546

Current Liabilities
Current portion of long-term debt		4,929,091			4,929,091
Short-term borrowing		51,314,364			35,482,241
Accounts payable		27,994,213			45,645,228
Customer deposits and refunds		5,908,474			5,140,999
Accrued interest		1,583,586			558,719
Dividends payable		1,733,280			1,676,398
Income taxes payable		397,600			-
Deferred income taxes		-			1,150,828
Accrued compensation		2,652,758			3,793,244
Regulatory liabilities		3,801,066			550,546
Other accrued liabilities		5,431,341			3,560,055
Total current liabilities		105,745,773			102,487,349

Deferred Credits and Other Liabilities
Deferred income taxes		24,738,777			24,248,624
Deferred investment tax credits		325,973			367,085
Other regulatory liabilities		1,590,010			2,008,779
Environmental liabilities		241,538			352,504
Accrued pension costs		3,126,275			3,099,882
Accrued asset removal cost		18,057,163			16,727,268
Other liabilities		2,807,483			2,940,838
Total deferred credits and other liabilities		50,887,219			49,744,980

Commitments and Contingencies *(Note 4)*


Total Capitalization and Liabilities	$	301,961,395		$	295,979,875

⁽¹⁾ Shares issued were 5,979,769 and 5,883,099 for 2006 and 2005, respectively.
Shares outstanding were 5,979,769 and 5,883,002 for 2006 and 2005, respectively.

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

Page 5

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Stockholders' Equity (Unaudited)

	For the Nine Months Ended September 30, 2006			For the Twelve Months Ended December 31, 2005
Common Stock
Balance — beginning of period	$	2,863,212		$	2,812,538
Dividend Reinvestment Plan		13,664			20,038
Retirement Savings Plan		11,161			10,255
Conversion of debentures		7,688			11,004
Performance shares and options exercised		14,536			9,377
Balance — end of period	$	2,910,261		$	2,863,212

Additional Paid-in Capital
Balance — beginning of period	$	39,619,849		$	36,854,717
Dividend Reinvestment Plan		846,573			1,224,874
Retirement Savings Plan		700,506			682,829
Conversion of debentures		260,784			373,259
Performance shares and options exercised		887,426			484,170
Exercise of warrants		(387,282	)		-
Balance — end of period	$	41,927,856		$	39,619,849

Retained Earnings
Balance — beginning of period	$	42,854,894		$	39,015,087
Net income		6,572,346			10,467,614
Cash dividends declared		(5,151,076	)		(6,627,807	)
Balance — end of period	$	44,276,164		$	42,854,894

Accumulated Other Comprehensive Income
Balance — beginning of period		($578,151	)		(527,246	)
Minimum pension liability adjustment, net of tax		-			(50,905	)
Balance — end of period		($578,151	)		($578,151	)

Deferred Compensation Obligation
Balance — beginning of period	$	794,535		$	816,044
New deferrals		310,135			130,426
Payout of deferred compensation		-			(151,935	)
Balance — end of period	$	1,104,670		$	794,535

Treasury Stock
Balance — beginning of period		($797,156	)		($1,008,696	)
New deferrals related to compensation obligation		(310,135	)		(130,426	)
Purchase of treasury stock ⁽¹⁾		(37,719	)		(182,292	)
Sale and distribution of treasury stock ⁽²⁾		40,340			524,258
Balance — end of period		($1,104,670	)		($797,156	)


Total Stockholders’ Equity	$	88,536,130		$	84,757,183

(1) Amount includes shares purchased in the open market for the Company’s Rabbi Trust to secure it's obligations under the Company’s Supplemental Executive Retirement Savings Plan (“SERP plan”).
⁽²⁾ Amount includes shares issued to the Company’s Rabbi Trust as obligation under the SERP plan.

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

Page 6

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

	For the Nine Months Ended September 30, 2006		For the Twelve Months Ended December 31, 2005
Net income	$	6,572,346	$	10,467,614
Minimum pension liability adjustment, net of tax benefit of $33,615		-		(50,905	)
Comprehensive Income	$	6,572,346	$	10,416,709

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

Page 7

Notes to the 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 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 for the year ended December 31, 2005 filed on March 7, 2006. 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 (Loss)

Comprehensive income contains items that are excluded from “net income (loss)” 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 three and nine months ended September 30 2006 and 2005. Accumulated other comprehensive income was ($578,151) at September 30, 2006 and December 31, 2005 and ($527,246) at September 30, 2005 and December 31, 2004.

3.	Calculation of Earnings Per Share (“EPS”)

	Three Months Ended						Nine Months Ended
For the Periods Ended September 30,	2006			2005			2006		2005
Calculation of Basic Earnings Per Share:
Net Income (Loss)		($656,579	)		($693,774	)	$	6,572,346	$	6,334,946
Weighted average shares outstanding		5,973,149			5,851,926			5,945,119		5,823,144
Basic Earnings Per Share		($0.11	)		($0.12	)	$	1.11	$	1.09

Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income (Loss)		($656,579	)		($693,774	)	$	6,572,346	$	6,334,946
Effect of 8.25% Convertible debentures⁽¹⁾		-			-			79,900		94,441
Adjusted numerator — Diluted		($656,579	)		($693,774	)	$	6,652,246	$	6,429,387

Reconciliation of Denominator:
Weighted shares outstanding — Basic		5,973,149			5,851,926			5,945,119		5,823,144
Effect of dilutive securities⁽¹⁾
Stock options		-			-			-		371
Warrants		-			-			-		11,262
8.25% Convertible debentures		-			-			124,774		147,526
Adjusted denominator — Diluted		5,973,149			5,851,926			6,069,893		5,982,303

Diluted Earnings per Share		($0.11	)		($0.12	)	$	1.10	$	1.07

⁽¹⁾ The amount of interest accumulated, per common share, for the three-month periods ended September 30, 2006 and 2005, obtainable from the 8.25% Convertible Debentures exceeds Basic EPS. The inclusion of these securities would therefore have an anti-dilutive effect on EPS for the three-month periods presented and, accordingly, have been omitted from this calculation for the quarter. The Company did not have any outstanding stock options or warrants at September 30, 2006.

Page 8

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 gas manufacturing plant site located in Dover, Delaware. Chesapeake is also currently participating in the investigation, assessment or remediation of two additional former gas manufacturing 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 United States 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 expenditures for this site. Through September 30, 2006, the Company has incurred approximately $9.7 million in costs related to environmental testing and remedial action studies at the site. Approximately $10.0 million has been recovered through September 2006 from other parties or through rates. As of September 30, 2006, a regulatory liability of approximately $343,000, 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 permanently decommission 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. In November 2002, Chesapeake submitted a letter to the MDE requesting a No Further Action determination. The Company has been in discussions with the MDE regarding such request and is awaiting a determination from the MDE.

Through September 30, 2006, 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 $1.8 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 $1.1 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 site with the FDEP. The Work Plan described the Company’s proposal to undertake an AS/SVE pilot study to evaluate the site. After discussions with the FDEP, the Company filed a modified Work Plan, the 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 $242,000 as of September 30, 2006 for the Winter Haven Coal Gas site. Through September 30, 2006, the Company has incurred approximately $1.6 million of environmental costs associated with this site. At September 30, 2006, the Company had collected $102,000 through rates in excess of costs incurred. A regulatory asset of approximately $140,000, 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 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 requirements 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 gas manufacturing 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 November 2004, 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 March 31, 2007.

Page 10

Corporate Guarantees

The Company has issued corporate guarantees to certain vendors of its propane wholesale marketing subsidiary, its Florida natural gas marketing subsidiary, and 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 September 30, 2006, totaled $18.9 million, with the guarantees expiring on various dates in 2006 and 2007.

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. The current letter of credit was renewed during the second quarter of 2006 when the insurance policies were renewed.

Application of SFAS No. 71

Certain assets and liabilities of the Company are accounted for in accordance with SFAS No. 71 ¾“Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 provides guidance for public utilities and other regulated operations where the rates (prices) charged to customers are subject to regulatory review and approval. Regulators sometimes include allowable costs in a period other than the period in which the costs would be charged to expense by an unregulated enterprise. That procedure can create assets, reduce assets, or create liabilities for the regulated enterprise. For financial reporting, an incurred cost for which a regulator permits recovery in a future period is accounted for like an incurred cost that is reimbursable under a cost-reimbursement type contract. The Company believes that all regulatory assets as of September 30, 2006 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.

Other

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

5.	Recent Authoritative Pronouncements on Financial Reporting and Accounting

In December 2004, the FASB released a revision (“Share-Based Payment”) to SFAS No. 123, “Accounting for Stock-Based Compensation,” referred to as SFAS No. 123R. SFAS 123R establishes financial accounting and reporting standards for stock-based employee compensation plans. Those plans include all arrangements by which employees receive shares of stock or other equity instruments of the employer or the employer incurs liabilities to employees in amounts based on the price of the employer’s stock. Examples are stock purchase plans, stock options, restricted stock and stock appreciation rights. The impact of the Company’s adoption of this pronouncement is disclosed in Note 9 to the financial statements entitled “Share Based Compensation.”

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In July 2006, the FASB issued FASB Interpretation 48, “Accounting for Income Tax Uncertainties,” (“FIN 48”). FIN 48 defines the threshold for recognizing the benefits of tax return positions in the financial statements as “more-likely-than-not” to be sustained by the taxing authority. The recently issued literature also provides guidance on the derecognition, measurement and classification of income tax uncertainties, along with any related interest and penalties. FIN 48 also includes guidance concerning accounting for income tax uncertainties in interim periods and increases the level of disclosures associated with any recorded income tax uncertainties. FIN 48 is effective for fiscal years beginning after December 15, 2006. The differences between the amounts recognized in the statements of financial position prior to the adoption of FIN 48 and the amounts reported after adoption will be accounted for as a cumulative-effect adjustment recorded in retained earnings. The Company is continuing to evaluate the impact of this new standard, if any, on the Company’s financial statements.

In September 2006, the FASB issued Statement No. 157, “Fair Value Measurements ” (“SFAS No. 157”), which clarifies that the term fair value is intended to mean a market-based measure, not an entity-specific measure and gives the highest priority to quoted prices in active markets in determining fair value. SFAS No. 157 requires disclosures about (1) the extent to which companies measure assets and liabilities at fair value, (2) the methods and assumptions used to measure fair value, and (3) the effect of fair value measures on earnings. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. The Company is continuing to evaluate the impact of this new standard, if any, on the Company’s financial statements.

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R).” This statement would require a company to (a) recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, (b) measure a plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year, and (c) recognize changes in the funded status of a defined postretirement plan in the year in which the changes occur and to report the changes as adjustments to comprehensive income. The requirement to recognize the funded status of a benefit plan and the disclosure requirements are effective as of the end of the fiscal year ending after December 15, 2006. The requirement to measure the plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2006. The Company does not anticipate that the adoption of SFAS No. 158 will have a material impact on the Company’s financial position, and anticipates no impact to the statements of income or cash flows.

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”), which provides interpretive guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB 108 is effective as of the end of our 2006 fiscal year, allowing a one-time transitional cumulative effect adjustment to beginning retained earnings as of January 1, 2006, for errors that were not previously deemed material, but are material under the guidance in SAB 108. The Company does not anticipate that the adoption of SAB 108 will have a material impact on our Consolidated Financial Statements.

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6.	Segment Information

Chesapeake uses the management approach to identify operating segments. Chesapeake 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 resources and to assess performance. The following table presents information about the Company’s reportable segments.

	Three Months Ended						Nine Months Ended
For the Periods Ended September 30,	2006			2005			2006			2005
Operating Revenues, Unaffiliated Customers
Natural gas	$	25,949,067		$	26,085,513		$	126,855,572		$	112,336,037
Propane		5,850,616			5,913,760			34,338,931			33,399,579
Advanced information services		3,341,847			3,151,372			9,200,427			9,341,258
Other		-			4,476			1,025			143,871
Total operating revenues, unaffiliated customers	$	35,141,530		$	35,155,121		$	170,395,955		$	155,220,745

Intersegment Revenues ⁽¹⁾
Natural gas	$	66,214		$	57,466		$	183,930		$	141,483
Propane		-			-			-			668
Advanced information services		12,475			2,624			33,988			13,433
Other		154,623			154,623			463,869			463,869
Total intersegment revenues	$	233,312		$	214,713		$	681,787		$	619,453

Operating Income
Natural gas	$	1,760,552		$	1,130,620		$	13,256,385		$	12,116,857
Propane		(1,826,353	)		(1,425,028	)		1,165,748			1,814,135
Advanced information services		321,528			186,425			509,898			(77,165	)
Other and eliminations		(93,590	)		8,834			(127,298	)		(123,688	)
Total operating income	$	162,137			($99,149	)	$	14,804,733		$	13,730,139
⁽¹⁾ All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.


		September 30, 2006			December 31, 2005
Identifiable Assets
Natural gas	$	224,192,686		$	225,667,049
Propane		64,449,789			57,344,859
Advanced information services		2,701,590			2,062,902
Other		10,617,330			10,905,065
Total identifiable assets	$	301,961,395		$	295,979,875

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. These transactions with foreign companies are denominated and paid in U.S. dollars. These transactions are immaterial to the consolidated revenues.

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7.	Employee Benefit Plans

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

	Defined Benefit Pension Plan						Executive Excess Retirement Benefit Plan				Other Post-Retirement Benefits
For the Three Months Ended September 30,	2006			2005			2006		2005		2006		2005
Service Cost	$	0		$	0		$	0	$	0	$	1,564	$	1,564
Interest Cost		161,212			161,435			29,897		29,915		19,468		19,468
Expected return on plan assets		(174,191	)		(175,821	)		-		-		-		-
Amortization of transition amount		-			-			-		-		6,964		6,964
Amortization of prior service cost		(1,174	)		(1,174	)		-		-		-		-
Amortization of net loss (gain)		-			-			14,259		12,329		22,072		22,072
Net periodic (benefit) cost		($14,153	)		($15,560	)	$	44,156	$	42,244	$	50,068	$	50,068

	Defined Benefit Pension Plan						Executive Excess Retirement Benefit Plan				Other Post-Retirement Benefits
For the Nine Months Ended September 30,	2006			2005			2006		2005		2006		2005
Service Cost	$	0		$	0		$	0	$	0	$	4,693	$	4,693
Interest Cost		474,664			484,305			89,691		89,744		58,404		58,404
Expected return on plan assets		(516,343	)		(527,464	)		-		-		-		-
Amortization of transition amount		-			-			-		-		20,894		20,894
Amortization of prior service cost		(3,524	)		(3,524	)		-		-		-		-
Amortization of net loss (gain)		-			-			42,779		36,989		66,218		66,218
Net periodic (benefit) cost		($45,203	)		($46,683	)	$	132,470	$	126,733	$	150,209	$	150,209

As disclosed in the December 31, 2005 financial statements, no contributions are expected to be required in 2006 for the defined benefit pension plan. The Company maintains a Rabbi Trust to cover the costs of the executive excess retirement benefit plan (Note 8); however, the other post-retirement benefit plans are unfunded. Cash benefits paid under the executive excess retirement benefit plan for the first nine months of 2006 were $73,000, and for the year 2006, benefits paid are expected to be $100,000. Net benefits paid for other post-retirement benefits are primarily for medical claims and were $121,000 for the first nine months of 2006. For the year 2006, the Company has estimated that the benefits to be paid are $215,000.

8.	Investments

The Company maintains investments in a Rabbi Trust to cover the cost of the Company’s Supplemental Executive Retirement Savings Plan. In accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and based on the Company’s intentions regarding these instruments, the Company classifies all investments in equity securities 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 earnings. At the end of September 2006, total investments had a fair value of $1.9 million.

9.	Share-Based Compensation

Effective January 1, 2006, the Company adopted SFAS No. 123R, “Share-Based Payment,” which establishes accounting for equity instruments exchanged for employee services. Prior to January 1, 2006, the Company accounted for share-based compensation to employees in accordance with Accounting Principles Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. The Company also followed the disclosure requirements of SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.” Commencing January 1, 2006, the Company elected to adopt the modified prospective method as provided by SFAS No. 123R and, accordingly, financial statement amounts for the prior periods presented in this Form 10-Q have not been restated to reflect the fair value of expensing stock-based compensation.

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For the three months ended September 30, 2006 and 2005, included in net income are expense amounts of $173,000 and $206,000, after-tax, respectively, related to stock-based compensation expense from restricted stock awards issued under the Company’s Director’s Stock Compensation and Performance Incentive Plans. For the first nine months of 2006 and 2005, included in net income are expense amounts of $437,000 and $465,000, after-tax, respectively, related to stock-based compensation expense from 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 September 30, 2006 or December 31, 2005, nor were any stock options issued during the nine months ended September 30, 2006.

Director’s Stock Compensation Plan (“DSCP”)

Under the Company’s DSCP, each non-employee director receives an annual retainer of 600 shares of common stock and an additional 150 shares of common stock for services as a committee chairman, subject to adjustment in future years consistent with the terms of the DSCP. Shares issued under the DSCP are fully vested as of the date of the 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 relating to the DSCP awards was $44,000 and $36,000 for the three-month periods ended September 30, 2006 and 2005, respectively, and $121,000 and $104,000 for the first nine months of 2006 and 2005, respectively.

A summary of restricted stock activity for the DSCP as of September 30, 2006, and changes during the nine months then ended, is presented below:

	Number of Restricted Shares		Weighted Average Grant Date Fair Value
Outstanding — December 31, 2005		-
Issued — May 2, 2006		5,850	$	30.02
Vested		5,850
Outstanding — September 30, 2006		-

Performance Incentive Plans (“PIP”)

The Company’s Compensation Committee of the Board of Directors is authorized to grant to 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 made pursuant to the Company’s Performance Incentive Plan, subject to certain post-vesting transfer restrictions, and are granted in the first quarter of each year based upon the performance achieved in the previous fiscal year. In the first quarters of 2006 and 2005, the Company granted 23,666 and 10,130 shares, respectively, to key employees as PIP stock awards for each of the preceding fiscal years.

The Company accrues an expense each month of the fiscal year, preceding the date of grant, representing an estimate of the value of the stock awards to be granted for the current fiscal year. This accrual process matches the compensation expense with the employees’ service period rather than recognizing the expense on the grant date, which occurs in the first quarter of the subsequent year. 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 stock on the date of grant. Compensation expense recorded by the Company relating to the PIP was $239,000 and $302,000 for the three-month periods ended September 30, 2006 and 2005, respectively, and $596,000 and $659,000 for the first nine months of 2006 and 2005, respectively.

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A summary of restricted stock activity for the PIP as of September 30, 2006, and changes during the nine months then ended, is presented below:

	Number of Restricted Shares		Weighted Average Grant Date Fair Value
Outstanding — December 31, 2005		-
Issued — February 23, 2006		23,666	$	30.3999
Vested		23,666
Outstanding — September 30, 2006		-

10. Stockholders’ Equity

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

	For the Nine Months Ended September 30, 2006			For the Twelve Months Ended December 31, 2005
Common Stock shares issued and outstanding ⁽¹⁾
Shares issued — beginning of period balance		5,883,099			5,778,976
Dividend Reinvestment Plan ⁽²⁾		28,075			41,175
Retirement Savings Plan		22,932			21,071
Conversion of debentures		15,797			22,609
Employee award plan		350			-
Performance shares and options exercised ⁽³⁾		29,516			19,268
Shares issued — end of period balance ⁽⁴⁾		5,979,769			5,883,099

Treasury shares — beginning of period balance		(97	)		(9,418	)
Purchases		-			(4,852	)
Dividend Reinvestment Plan		-			2,142
Retirement Savings Plan		-			12,031
Other issuances		97			-
Treasury Shares — end of period balance		-			(97	)

Total Shares Outstanding		5,979,769			5,883,002

⁽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 47,721 and 37,528 shares at September 30, 2006 and December 31, 2005, respectively, held in a Rabbi Trust established by the Company relating to the Supplemental Executive Retirement Savings Plan.

In 2000 and 2001, the Company entered into agreements with an investment banker to assist in identifying acquisition candidates. Under the agreements, the Company issued warrants to the investment banker to purchase 15,000 share of Chesapeake stock in 2000 at an exercise price of $18.00 per share and 15,000 shares in 2001 at an exercise price of $18.25 per share.

In August 2006, the investment banker exercised the 30,000 warrants pursuant to the terms of the agreement at $33.3657 per share. At the request of the investment banker, Chesapeake settled the warrants with a cash payment of $434,782, in lieu of issuing shares of the Company’s common stock. Chesapeake does not have any other stock warrants outstanding at September 30, 2006.

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11. Other Event

In March 2006, the Company’s propane distribution subsidiary, Sharp Energy, Inc. (“Sharp”), identified that approximately 75,000 gallons of propane that it purchased contained above-normal levels of petroleum byproducts. The supplier’s testing identified above-normal concentration levels of the petroleum byproduct benzene. Benzene, which may be found in trace amounts in propane, is used to make plastics, resins, nylon, synthetic fibers, detergents, lubricants, drugs, dyes and pesticides. It is also routinely found in crude oil and gasoline. The supplier has conducted modeling and testing of the propane in combustion situations and has stated that they have found no health or safety concerns.

Sharp replaced the propane for each of the approximately 600 customers impacted by this event at no cost to the customers. Sharp also replaced any remaining propane contained at its storage facilities. The propane that the Company retrieved from customers and Sharp’s storage facilities was returned to the supplier.

The supplier indicated that it would reimburse Sharp for all damages, costs and expenses incurred by Sharp or the Company in connection with this matter. As a result of the supplier’s commitment, Sharp invoiced the supplier $734,000 for costs relating to this incident through September 2006. The supplier has paid the entire amount and no amounts remain outstanding at September 30, 2006. The Company does not anticipate any additional costs in relation to the incident and does not believe that the event will ultimately have a material adverse effect on the Company or its business, results of operations or long-term financial condition.

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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. The Company’s MD&A is presented in nine sections: Overview, Results of Operations, Liquidity and Capital Resources, Off-Balance Sheet Arrangements, Contractual Obligations, Environmental Matters, Other Matters, Competition, and Recent Accounting Pronouncements. This discussion and analysis should be read in conjunction with the attached unaudited consolidated financial statements and notes thereto and Chesapeake’s 2005 Annual Report on Form 10-K, including the audited consolidated financial statements and notes contained in the 2005 Annual Report on Form 10-K.

Overview

Chesapeake Utilities Corporation (the “Company” or “Chesapeake”) is a diversified utility company engaged 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 to grow earnings from a stable utility foundation by investing in related businesses and services that provide opportunities for higher, unregulated returns. This growth strategy includes acquisitions and investments in unregulated businesses, as well as the continued investment and expansion of the Company’s utility operations that provide the stable base of earnings. The Company continually reevaluates its investments to ensure that they are consistent with its strategy and the goal of enhancing shareholder value. The Company’s unregulated businesses and services currently include natural gas marketing, propane distribution and wholesale marketing, advanced information services and other related businesses.

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.

The principal business, economic and other factors that affect the operations and/or financial performance of the Company include:

·	weather conditions and weather patterns;

·	regulatory environment and regulatory decisions;

·	availability of natural gas and propane supplies;

·	natural gas and propane production levels;

·	interstate pipeline transportation and storage capacity;

·	natural gas and propane prices and the prices of competing fuels, such as oil and electricity;

·	changes in natural gas and propane usage resulting from customer conservation, including improved appliance efficiencies;

·	the level of capital expenditures for adding new customers and replacing facilities worn beyond economic repair;

·	use of derivative instruments;

·	changes in credit risk;

·	competitive environment;

·	environmental matters;

·	economic conditions and interest rates;

·	inflation / deflation;

·	changes in technology; and

·	changes in accounting principles.

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Results of Operations for the Three Months Ended September 30, 2006

Consolidated Overview

The Company’s operating income increased by $261,000 for the quarter ended September 30, 2006 compared to the same period in 2005. The Company’s seasonal net loss for the quarter ended September 30, 2006 decreased $37,000, or 5 percent, compared to the same period in 2005. The Company experienced a net loss of $657,000, or $0.11 per share (diluted) — a decrease of $0.01 in the loss per share when compared to 2005. The Company’s Delmarva natural gas distribution and propane distribution operations typically experience seasonal losses during the third quarter, because heating customers do not require gas in the summer months.

For the Three Months Ended September 30,	2006			2005			Change
Operating Income
Natural Gas	$	1,760,552		$	1,130,620		$	629,932
Propane		(1,826,353	)		(1,425,028	)		(401,325	)
Advanced Information Services		321,528			186,425			135,103
Other & eliminations		(93,590	)		8,834			(102,424	)
Operating Income		162,137			(99,149	)		261,286

Other Income (Loss)		(12,091	)		19,493			(31,584	)
Interest Charges		1,340,879			1,272,196			68,683
Income Taxes		(534,254	)		(658,078	)		123,824
Net Loss		($656,579	)		($693,774	)	$	37,195
Diluted Earnings Per Share		($0.11	)		($0.12	)	$	0.01

The following discussions for the three months ended September 30, 2006 of 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 the natural gas and propane segments and the cost of labor spent on direct revenue-producing activities. Gross margin should not be considered an alternative to operating income or net income, which are determined in accordance with Generally Accepted Accounting Principles (“GAAP”). Chesapeake believes that gross margin, although a non-GAAP measure, is useful and meaningful to investors as a basis for making investment decisions. It provides investors with information that demonstrates the profitability achieved by the Company under its allowed rates for regulated operations and under its competitive pricing structure for unregulated 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.

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Natural Gas

The natural gas segment earned operating income of $1.8 million for the third quarter of 2006 compared to $1.1 million for the corresponding period last year, an increase of $630,000 or 56 percent. Gross margin increased by $706,000, or 8 percent, while other operating expenses increased $76,000, or 1 percent.

For the Three Months Ended September 30,	2006		2005		Change
Revenue	$	26,015,281	$	26,142,979		($127,698	)
Cost of gas		15,982,581		16,816,684		(834,103	)
Gross margin		10,032,700		9,326,295		706,405

Operations & maintenance		5,800,783		5,946,564		(145,781	)
Depreciation & amortization		1,562,522		1,416,664		145,858
Other taxes		908,843		832,447		76,396
Other operating expenses		8,272,148		8,195,675		76,473
Total Operating Income	$	1,760,552	$	1,130,620	$	629,932

Statistical Data — Delmarva Peninsula
Heating degree-days (“HDD”)
Actual		45		31		14
10-year average (normal)		60		60		-

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		40,086		36,803		3,283
Florida		12,695		11,599		1,096
Total		52,781		48,402		4,379

Gross margin for the Company’s natural gas segment increased $706,000 in the third quarter of 2006 compared to the same period in 2005.

The Delmarva distribution operations experienced an increase of $121,000 in gross margin. The Company added an average of 3,283 residential customers in Delmarva, an increase of 9 percent, over 2005. The Company estimates that these additional customers added $165,000 to gross margin, which was partially offset by lower volumes sold to existing customers and lower off-system sales.

The natural gas transmission operation achieved gross margin growth of $486,000, or 14 percent. The increase was attributed to new transportation services implemented in November 2005 and an increase in interruptible revenues. The Company estimates that its annual gross margin for its natural gas transmission operation will be $1.7 million higher in 2006 than in 2005.

·	Gross margin for the Florida natural gas distribution and the unregulated natural gas marketing operations increased $85,000 and $14,000, respectively. The increases were attained primarily from continued growth, including a 9 percent increase in the average number of residential customers.

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Other operating expenses for the natural gas operations increased $76,000, or 1 percent, in the third quarter of 2006 compared to the same period in 2005. Items contributing to the increase include:

·	Due to the additional capital investments by the Company, depreciation and amortization expense, asset removal cost, and property taxes increased $146,000, $60,000, and $82,000, respectively.

Payroll costs decreased $137,000 primarily due to a decrease of $69,000 in amounts recognized in respect of incentive compensation reflecting the lower than expected earnings as a result of warmer weather. Also contributing to the reduction in payroll costs are other factors such as vacant positions and lower sales commissions.

·	Health care costs decreased by $101,000 for the natural gas segment during the third quarter of 2006. The Company changed health care service providers in November 2005 and has subsequently experienced lower cost of claims.

Propane

The seasonal operating loss for the propane segment increased $401,000, or 28 percent in the third quarter of 2006 compared to the same period in 2005. This segment typically experiences a loss during the third quarter, as heating customers do not require propane during the summer months. The operating loss for the third quarter of 2006 was $1.8 million compared to an operating loss of $1.4 million for the same period in 2005.

For the Three Months Ended September 30,	2006			2005			Change
Revenue	$	5,850,616		$	5,913,760			($63,144	)
Cost of sales		3,967,428			3,427,896			539,532
Gross margin		1,883,188			2,485,864			(602,676	)

Operations & maintenance		3,123,666			3,349,367			(225,701	)
Depreciation & amortization		415,982			394,317			21,665
Other taxes		169,893			167,208			2,685
Other operating expenses		3,709,541			3,910,892			(201,351	)
Total Operating Loss		($1,826,353	)		($1,425,028	)		($401,325	)

Statistical Data — Delmarva Peninsula
Heating degree-days (“HDD”)
Actual		45			31			14
10-year average (normal)		60			60			-

Estimated gross margin per HDD	$	1,743		$	1,743		$	0

The Company’s propane segment experienced a decrease of $603,000 in gross margin in the third quarter of 2006 compared to the same period in 2005, primarily from a decrease of $357,000 for the Delmarva propane distribution operation, a decrease of $206,000 for the propane wholesale and marketing operation and a decrease of $39,000 for the Florida propane distribution operation.

During the third quarter of 2006, the Delmarva propane distribution operation experienced a decrease in gross margin of $357,000. The reduction in gross margin is primarily attributed to a reduction in the average gross margin per retail gallon and lower service sales. The average gross margin per retail gallon decreased $0.13 in the third quarter of 2006 compared to the same period in 2005, which negatively affected gross margin by $244,000. The decrease in gross margin per retail gallon was principally the result of a $175,000 write-down of propane inventory to reflect the lower of cost or market. The remaining $113,000 decrease of gross margin is from a combination of miscellaneous items, including lower service sales, partially offset by an increase in fuel surcharges and other various fees.

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Gross margin for the Company’s propane wholesale marketing operation decreased by $206,000 in the third quarter of 2006 compared to the same period in 2005. The decrease is primarily due to the decrease of wholesale propane prices experienced in the third quarter of 2006, in contrast to the rising prices experienced in the third quarter of 2005 in response to the hurricanes in the Gulf of Mexico area.

The Florida propane distribution operation experienced a decrease of $39,000 in gross margin for the third quarter of 2006 compared to the same period in 2005. The lower gross margin reflects a decrease of $70,000 in house-piping sales as the operation is exiting the house-piping service. This was partially offset by an increase in propane margins of $34,000.

Other operating expenses decreased for the three months ended September 30, 2006 by $201,000, compared to the same period in 2005. Items contributing to the decrease include payroll and health care costs:

·	Payroll costs decreased $94,000 primarily due to a decrease of $116,000 in amounts recognized with respect to incentive compensation reflecting the lower than expected earnings.

·	Health care costs decreased by $104,000 for the third quarter of 2006. The Company changed health care service providers in November 2005 and has subsequently experienced lower cost of claims.

Advanced Information Services

Operating income for the Company’s advanced information services business increased $135,000 for the three months ended September 30, 2006 compared to the same period in 2005. Operating income for the third quarter was $322,000 compared to $186,000 for the same period in 2005. Negatively affecting operating income in the third quarter of 2005 was an operating loss of $111,000 for the Lightweight Association Management Processing Systems (“LAMPS™”) product. LAMPS™ is an internet-based membership management software tool specifically developed for REALTOR® Associations, which provides real time integration with the National Association of REALTOR® Database System. The LAMPS^TM product was sold to Fidelity National Information Solutions, Inc., a subsidiary of Fidelity National Financial, Inc. in October 2005.

For the Three Months Ended September 30,	2006		2005		Change
Revenue	$	3,354,322	$	3,153,996	$	200,326
Cost of sales		1,808,549		1,710,440		98,109
Gross margin		1,545,773		1,443,556		102,217

Operations & maintenance		1,081,606		1,114,599		(32,993	)
Depreciation & amortization		25,325		31,038		(5,713	)
Other taxes		117,314		111,494		5,820
Other operating expenses		1,224,245		1,257,131		(32,886	)
Total Operating Income	$	321,528	$	186,425	$	135,103

The Company’s advanced information services segment increased gross margin by $102,000 to $1.5 million, compared to the same period in 2005. Revenues for the period increased $200,000 to $3.4 million in the third quarter 2006 compared to 2005, due primarily to an increase of $373,000 in consulting revenues. The number of billable hours and the average hourly billing rate both increased 15 percent for the quarter ended September 30, 2006 compared to the same period in 2005. Included in the 2005 revenue is $92,000 of revenue generated by the LAMPS^TM product.

Cost of sales for the three months ended September 30, 2006 increased $98,000 to $1.8 million, compared to the same period in 2005. The 2005 cost of sales of $1.7 million includes $116,000 related to LAMPS^TM. The higher cost of sales in 2006 is related directly to the increased revenues.

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Other operating expenses decreased $33,000 for the three months ended September 30, 2006 to $1.2 million, when compared to same period in 2005. The reduction in other operating expenses is primarily attributed to the following:

·	The elimination of $87,000 of expenses in the third quarter of 2005 associated with the LAMPS^TMproduct.

·	Payroll and benefit costs were lower by $63,000 and $43,000, respectively.

·	Lower rental expense of $60,000 as the operation eliminated unnecessary office space.

·	Incentive compensation and commissions increased $137,000 and $50,000, respectively, to reflect the improved earnings.

Effective July 1, 2006, the Company changed the retirement savings, or 401(k), plan for the employees of its advanced information services segment and implemented a profit sharing plan. The net effect of the change is to reduce the Company’s costs during those years when the segment is not meeting its earnings targets in exchange for higher compensation to the employees when the segment exceeds its targets.

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”). Eliminations are entries required to eliminate activities between business segments from the consolidated results. Other operations and eliminating entries resulted in an operating loss of $94,000 for the third quarter of 2006 compared to operating income of $9,000 for the same period in 2005. The loss in 2006 is attributed primarily to the OnSight operation.

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 third quarter of 2006, OnSight had an operating loss of $160,000 compared to an operating loss of $63,000 for the same period in 2005. OnSight has taken action to reduce costs going forward, which has caused a one-time charge of $65,000 to other operating expense in the month of September 2006.

For the Three Months Ended September 30,	2006			2005		Change
Revenue	$	154,623		$	159,099		($4,476	)
Cost of sales		-			2,951		(2,951	)
Gross margin		154,623			156,148		(1,525	)

Operations & maintenance		187,229			81,589		105,640
Depreciation & amortization		41,120			54,448		(13,328	)
Other taxes		20,633			18,479		2,154
Other operating expenses		248,982			154,516		94,466
Operating Income (Loss) - Other		(94,359	)		1,632		(95,991	)
Operating Income - Eliminations		769			7,202		(6,433	)
Total Operating Income (Loss)		($93,590	)	$	8,834		($102,424	)

Interest Expense

Interest expense for the third quarter of 2006 increased approximately $69,000, or 5 percent, to $1.34 million compared to $1.27 million for the same period in 2005. The higher interest expense is attributed to the following:

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The Company’s outstanding average short-term borrowing balance was $30.0 million for the quarter ended September 30, 2006 compared to $1.5 million outstanding for the quarter ended September 30, 2005. The increased borrowing, resulting in higher interest expense, is related to the Company’s capital investments made in the 12 months ended September 30, 2006 and higher working capital due to the rising costs of natural gas and propane.

·	The average interest rate on short-term borrowing increased from 4.30% in the third quarter of 2005, to 5.73% for the same period in 2006.

The increase in interest expense on short-term borrowing was partially offset by a decrease in interest expense on long-term debt. The Company’s average long-term debt balance declined from $68.1 million in the third quarter of 2005 to $62.7 million for the third quarter of 2006, which lowered interest expense for the period by $94,000.

Income Taxes

Due to the seasonal loss, Chesapeake had an income tax benefit of $534,000 for the three months ended September 30, 2006 compared to a benefit of $658,000 for the three months ended September 30, 2005. The effective tax rate for the third quarter of 2006 is 44.8 percent compared to an effective tax rate of 48.7 percent for the same period in 2005. The seasonality of the Company’s business segments impacts the effective tax rate on interim reporting periods.

Results of Operations for the Nine Months Ended September 30, 2006

Consolidated Overview

Net income for the Company increased $237,000, or 4 percent, for the nine months ended September 30, 2006 when compared to the same period in 2005, despite temperatures on the Delmarva Peninsula being 20 percent warmer in 2006. The Company estimates that the warmer weather reduced net income by $1.5 million, or $0.25 per share, and reduced gross margin by $2.5 million in the first nine months of 2006. The warmer weather was more than offset by the increase from the growth experienced by the natural gas operations, the improved results from advanced information services and continued cost management. Net income was $6.6 million, or $1.10 per share (diluted), for the nine months ended September 30, 2006 compared to $6.3 million, or $1.07 per share (diluted), for the same period in 2005.

For the Nine Months Ended September 30,	2006			2005			Change
Operating Income
Natural Gas	$	13,256,385		$	12,116,857		$	1,139,528
Propane		1,165,748			1,814,135			(648,387	)
Advanced Information Services		509,898			(77,165	)		587,063
Other & eliminations		(127,298	)		(123,688	)		(3,610	)
Operating Income		14,804,733			13,730,139			1,074,594

Other Income		130,208			330,354			(200,146	)
Interest Charges		4,335,568			3,823,140			512,428
Income Taxes		4,027,027			3,902,407			124,620
Net Income	$	6,572,346		$	6,334,946		$	237,400
Diluted Earnings Per Share	$	1.10		$	1.07		$	0.03

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The following discussions for the nine months ended September 30, 2006 of 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 the natural gas and propane segments 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 is determined in accordance with Generally Accepted Accounting Principles (“GAAP”). Chesapeake believes that gross margin, although a non-GAAP measure, is useful and meaningful to investors as a basis for making investment decisions. It provides investors with information that demonstrates the profitability achieved by the Company under its allowed rates for regulated operations and under its competitive pricing structure for unregulated 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.

Natural Gas

The natural gas segment earned an operating income of $13.3 million for the first nine months of 2006 compared to $12.1 million for the corresponding period in 2005, an increase of $1.1 million, or 9 percent.

For the Nine Months Ended September 30,	2006		2005		Change
Revenue	$	127,039,502	$	112,477,520	$	14,561,982
Cost of gas		89,149,159		75,830,911		13,318,248
Gross margin		37,890,343		36,646,609		1,243,734

Operations & maintenance		17,168,706		17,612,547		(443,841	)
Depreciation & amortization		4,615,605		4,262,737		352,868
Other taxes		2,849,647		2,654,468		195,179
Other operating expenses		24,633,958		24,529,752		104,206
Total Operating Income	$	13,256,385	$	12,116,857	$	1,139,528

Statistical Data — Delmarva Peninsula
Heating degree-days (“HDD”)
Actual		2,502		3,138		(636	)
10-year average (normal)		2,797		2,853		(56	)

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		40,112		37,023		3,089
Florida		12,545		11,643		902
Total		52,657		48,666		3,991

Gross margin for the Company’s natural gas segment increased $1.2 million in the first nine months of 2006 compared to the same period in 2005. The gross margin for the Delmarva natural gas distribution operations was lower when compared to the same period in 2005 by $516,000, primarily due to warmer weather. However, this decline was offset by increased gross margin in the natural gas transmission operation of $1.1 million, increased gross margin in the natural gas marketing operation of $417,000 and increased gross margin for the Florida natural gas distribution operation of $197,000.

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The Delmarva distribution operations experienced a decrease of $516,000 in gross margin. Temperatures on the Delmarva Peninsula were 20 percent warmer during the first nine months of 2006 compared to same period in 2005. The Company estimates that the warmer temperatures led to a decrease in gross margin of approximately $1.4 million when compared to 2005. This decrease was partially offset by the continued residential customer growth in the Delmarva Peninsula. The average number of residential customers increased 3,089, or 8 percent, for the first nine months of 2006 compared to the same period in 2005. The Company estimates these new residential customers contributed approximately $885,000 to gross margin.

The natural gas transmission operation achieved gross margin growth of $1.1 million, or 10 percent. The increase was attributed primarily to the new transportation services implemented in November 2005. The Company estimates that its annual gross margin for its natural gas transmission operation will be $1.7 million higher in 2006 than in 2005.

·	Gross margin for the natural gas marketing operation increased $417,000, or 35 percent. The increase was attained primarily from an increase in the number of customers to which the operation provides supply management services and the operation’s ability to sell excess capacity.

·	Gross margin for the Florida distribution operation increased by $197,000. The impact of an 8 percent growth in residential customers more than offset the decrease in gross margin from lower volumes sold to commercial and industrial customers.

Other operating expenses for the natural gas operations increased $104,000 for the nine months ended September 30, 2006 compared to the same period in 2005. The significant items contributing to the increase are explained below. In addition, there is a decrease of approximately $49,000 in other operating expenses relating to various immaterial items.

·	Depreciation and amortization expense, asset removal cost, and property taxes increased $353,000, $173,000, and $171,000, respectively, as a result of the Company’s continued capital investments.

Payroll costs increased $164,000 as the Company increased its staff to support strong customer growth. This increase was offset by a decrease of $280,000 in incentive compensation to reflect lower than expected earnings, primarily from the Delmarva distribution operations, as weather was warmer than normal.

·	Health care costs decreased by $240,000 for the natural gas segment during the first nine months of 2006. The Company changed health care service providers in November 2005 and has subsequently experienced lower costs related to claims.

On August 1, 2006, the Company’s interstate pipeline subsidiary, Eastern Shore Natural Gas Company, (“Eastern Shore”) received approval from the FERC to recover the pre-service costs associated with a future pipeline project through its rates with two of its customers. Please refer to the Regulatory Matters section under Other Matters within Item 2 of the Management’s Discussion and Analysis for additional details. As a result of the FERC’s recent approval, the Company deferred these costs by recording a regulatory asset. Of the costs deferred as a regulatory asset, $188,000 had been previously recorded as other operating expense in 2005 prior to the receipt of the FERC’s approval to defer.

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Propane

Operating income for the propane segment decreased $648,000, or 36 percent, to $1.2 million for the first nine months of 2006 compared to the same period in 2005. This decrease was due primarily to warmer weather in the first nine months of 2006, resulting in reduced customer consumption.

For the Nine Months Ended September 30,	2006		2005		Change
Revenue	$	34,338,931	$	33,400,247	$	938,684
Cost of sales		21,845,239		19,968,448		1,876,791
Gross margin		12,493,692		13,431,799		(938,107	)

Operations & maintenance		9,488,865		9,830,244		(341,379	)
Depreciation & amortization		1,235,366		1,194,644		40,722
Other taxes		603,713		592,776		10,937
Other operating expenses		11,327,944		11,617,664		(289,720	)
Total Operating Income	$	1,165,748	$	1,814,135		($648,387	)

Statistical Data — Delmarva Peninsula
Heating degree-days (“HDD”)
Actual		2,502		3,138		(636	)
10-year average (normal)		2,797		2,853		(56	)

Estimated gross margin per HDD	$	1,743	$	1,743	$	0

The Company’s propane segment experienced a decrease of approximately $938,000 in gross margin in the first nine months of 2006 compared to the same period in 2005. Gross margin in the Delmarva propane distribution operations was lower when compared to the same period in 2005 by $933,000, primarily due to warmer weather. Gross margin also decreased in the Florida propane operation by $151,000. The negative impact of the warmer weather experienced by the Delmarva propane distribution operation was partially offset by increased gross margin from Community Gas Systems (“CGS”) of $60,000 and increased gross margin from the Company’s wholesale propane marketing operation of $86,000.

The Delmarva propane distribution operation experienced a decrease in gross margin of $933,000. Volumes sold in 2006 decreased 1.9 million gallons, or 12 percent. Temperatures on the Delmarva Peninsula were 20 percent warmer during the first nine months of 2006 compared to 2005. The Company estimates that the warmer temperatures resulted in a decrease in gross margin of approximately $1.1 million when compared to 2005. Partially offsetting the weather impact is an increase of $434,000 in gross margin from an increase in the average gross margin per retail gallon of $0.017 in 2006 compared to 2005. The remaining gross margin decrease of $267,000 can be attributed to such items as customer conservation and changes in the timing of deliveries to customers.

Gross margin for the CGS increased $60,000 when compared to the prior period, primarily from an increase in the number of customers. The average number of customers increased 1,038, or 35 percent, to 4,010 for the first nine months of 2006, compared to the same period in 2005. 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 for an additional 8,000 customers.

The Florida propane distribution operation experienced a decrease in gross margin of $151,000 when compared to the same period in 2005. The lower gross margin reflects a decrease of $321,000 for in-house piping sales as the operation exits the house piping service, which was partially offset by an increase in gross margin of $107,000 from propane sales.

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·	Gross margin for the Company’s propane wholesale marketing operation increased by $86,000 in the first nine months of 2006 compared to the same period in 2005. The increase is primarily due to the increase in volatility of wholesale propane prices that occurred during the nine.

Other operating expenses of the propane segment decreased for the first nine months of 2006 by $290,000, compared to the same period in 2005. The decrease is primarily attributed to a decrease of $267,000 in other operating expenses for the Delmarva propane distribution operation, including CGS. The decreased costs for the Delmarva operations were due to $387,000 in fixed costs being recovered in the first quarter of 2006 from a propane supplier as a result of the delivery of propane to the Company that contained above normal levels of petroleum by-products, as well as, a decrease of $207,000 in health insurance costs. Please refer to Note 11, “Other Event”, for more information on the event relating to the delivery of the product containing above normal levels of petroleum by-product. These lower costs were partially offset by increased costs of $176,000 for one of the Pennsylvania start-ups, which began operation in July 2005, and increased payroll costs of $109,000 and higher costs of $84,000 associated with vehicle fuel.

Advanced Information Services

Operating income for advanced information services business increased $587,000 for the nine months ended September 30, 2006 compared to the same period in 2005. Operating income for the first nine months was $510,000 compared to an operating loss of $77,000 for the same period in 2005. Contributing to the operating loss in 2005 was an operating loss of $461,000 for LAMPS™. The LAMPS^TM product was sold to Fidelity National Information Solutions, Inc., a subsidiary of Fidelity National Financial, Inc. in October 2005.

For the Nine Months Ended September 30,	2006		2005			Change
Revenue	$	9,234,415	$	9,354,691			($120,276	)
Cost of sales		5,193,574		5,538,195			(344,621	)
Gross margin		4,040,841		3,816,496			224,345

Operations & maintenance		3,054,288		3,392,482			(338,194	)
Depreciation & amortization		87,264		91,167			(3,903	)
Other taxes		389,391		410,012			(20,621	)
Other operating expenses		3,530,943		3,893,661			(362,718	)
Total Operating Income (Loss)	$	509,898		($77,165	)	$	587,063

The Company’s advanced information services segment increased gross margin by $224,000 to $4.0 million for the first nine months of 2006, compared to the same period in 2005. Revenues for the period decreased $120,000 compared to 2005, due primarily to decreases of $355,000 and $109,000 in product sales and training revenues, respectively, which were partially offset by an increase of $376,000 in consulting revenues. The number of billable hours and average hourly billing rate increased 1 and 7 percents, respectively, for the nine months ended September 30, 2006 compared to the same period in 2005. Included in the 2005 revenue is $308,000 of revenue generated by the LAMPS^TM product.

Cost of sales for the nine months ended September 30, 2006 decreased $345,000 to $5.2 million, compared to the same period in 2005. The 2005 cost of sales of $5.5 million includes $372,000 related to LAMPS^TM. Absent the cost of sales associated with the LAMPS^TM product, cost of sales remained consistent in first nine months of 2006 compared to the first nine months of 2005.

Other operating expenses decreased $363,000 for the nine months ended September 30, 2006 to $3.5 million, when compared to same period in 2005. The reduction in expenses primarily reflects expenses of $397,000 in the nine months ended September 2005 associated with LAMPS^TM, partially offset by an increase in incentive compensation to reflect the improved earnings.

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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. Eliminations are entries required to eliminate activities between business segments from the consolidated results. Other operations and eliminating entries resulted in an operating loss of $127,000 for the first nine months of 2006 compared to an operating loss of $124,000 for the same period in 2005. The losses in 2006 and 2005 are primarily attributed to the OnSight operation. For the first nine months of 2006, OnSight had an operating loss of $357,000 compared to an operating loss of $318,000 for the same period in 2005.

For the Nine Months Ended September 30,	2006			2005			Change
Revenue	$	464,894		$	607,740			($142,846	)
Cost of sales		874			115,578			(114,704	)
Gross margin		464,020			492,162			(28,142	)

Operations & maintenance		410,620			389,623			20,997
Depreciation & amortization		122,604			176,089			(53,485	)
Other taxes		60,404			73,418			(13,014	)
Other operating expenses		593,628			639,130			(45,502	)
Operating Loss - Other		(129,608	)		(146,968	)		17,360
Operating Income - Eliminations		2,310			23,280			(20,970	)
Total Operating Loss		($127,298	)		($123,688	)		($3,610	)

Interest Expense

Interest expense for the first nine months of 2006 increased approximately $512,000, or 13 percent, to $4.3 million compared to $3.8 million for the same period in 2005. The higher interest expense is attributed to the following:

Interest on short-term debt increased $1.1 million during the first nine months of 2006, compared to the same period during 2005, as a result of an increase in the average balance of short-term debt outstanding increased from $1.2 million for the first nine months of 2005 to $27.7 million for the first nine months of 2006.

·	The average interest rate on short-term borrowing increased from 3.66 percent for the first nine months of 2005, to 5.39 percent for the same period in 2006.

The increase in interest expense on short-term borrowing was partially offset by a decrease in interest expense on long-term debt. Interest on long-term debt decreased $291,000 as a result of the average long-term debt balance declining from $67.9 million in the first nine months of 2005 to $62.8 million for the first nine months of 2006 due to scheduled principal repayments.

Income Taxes

Income tax expense for the nine-month periods ended September 30, 2006 was $4.0 million compared to $3.9 million for the nine months ended September 30, 2005. The effective tax rate for the first nine months of 2006 is 38.0 percent compared to an effective tax rate of 38.1 percent for the same period in 2005.

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 and short-term borrowing to meet normal working capital requirements and to temporarily finance capital expenditures. During the first nine months of 2006, net cash provided by operating activities was $19.0 million, cash used by investing activities was $28.3 million and cash generated by financing activities was $9.2 million.

Page 29

During the first nine months of 2005, net cash provided by operating activities was $19.0 million, cash used by investing activities was $19.7 million and cash used by financing activities was $225,000.

At the Company’s meeting of the Board of Directors (“the Board”) on August 8, 2006, the Board increased the Company’s authority to borrow short-term debt from $60.0 million to $75.0 million. 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 banks’ availability of funds. The outstanding balance of short-term borrowing at September 30, 2006 and 2005 was $51.3 million and $10.6 million, respectively.

On October 12, 2006, the Company issued $20 million of 5.5 percent Senior Notes (“Notes”) to three institutional investors (The Prudential Insurance Company of America, Prudential Retirement Insurance and Annuity Company and United Omaha Life Insurance Company). The original note agreement was executed on October 18, 2005 and provided for the Company to sell the Notes at any time prior to January 15, 2007. The terms of the Notes require annual principal repayments of $2 million beginning on the fifth anniversary of the issuance of the Notes. The Notes will mature on October 12, 2020.

Chesapeake has budgeted $54.4 million for capital expenditures during 2006. This amount includes $20.8 million for natural gas distribution, $26.7 million for natural gas transmission, $5.7 million for propane distribution and wholesale marketing, $178,000 for advanced information services and $1.0 million 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 for 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 2006 capital expenditure program is expected to be provided from short-term borrowing, cash provided by operating activities and other sources to be determined from a shelf registration of the Company’s equity and debt securities. 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 has budgeted to incur approximately $300,000 in 2006 and $25,000 in 2007 for environmental-related expenditures. Additional expenditures may be required in future years. 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.

Page 30

Capital Structure

As of September 30, 2006, common equity represented 60.9 percent of total capitalization, compared to 56.8 percent in 2005. 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 43.9 percent and 51.2 percent at September 30, 2006 and September 30, 2005, respectively. The decrease in the capitalization percent is from the increase of $40.7 million in net short-term borrowing in 2006. Chesapeake remains committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access the 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.

Cash Flows from Operating Activities

The primary drivers for the Company’s operating cash flows are cash payments received from gas customers, offset by payments made by the Company for gas costs, operation and maintenance expenses, taxes and interest costs.

Net cash provided by operating activities totaled $18.97 million and $18.95 million for the nine months ended September 30, 2006 and 2005, respectively. Certain material changes in working capital are listed below for the first nine months of 2006:

Accounts receivable and accrued revenue decreased $17.3 million, which generated an increase in cash. The decrease in accounts receivable was primarily as a result of the seasonality of the Company’s business as it collects balances outstanding at December 31, 2005 and it experiences the warmer summer months.

Accounts payable and other accrued liabilities decreased $19.9 million, which resulted in a decrease in cash. The decreases in accounts payable and accrued liabilities primarily resulted from the lower cost of natural gas and propane in first nine months of 2006 compared to December 2005. In addition, the payment of invoices for capital expenditures in the first nine months of 2006 and those outstanding at December 31, 2005 contributed to the decrease.

·	Income taxes receivable decreased $3.1 million, which resulted in an increase of cash. This decrease in the receivable was the result of the Company being in a refund status of $2.7 million at December 31, 2005 and applying the refunds to the current year’s tax liability.

Certain material changes in working capital are listed below for the first nine months of 2005:

·	Accounts receivable and accrued revenue decreased $4.8 million due to the seasonality of the Company’s business as it collects balances outstanding at December 31, 2004.

·	Propane inventory, storage gas and other inventory increased $5.4 million resulting in a reduction in cash. The increase in the inventory levels is attributed to the higher cost of natural gas and propane resulting from the hurricanes that hit the Gulf of Mexico.

Accounts payable and other accrued liabilities increased $3.0 million. The increase in accounts payable and accrued liabilities primarily resulted from an increase of propane payables outstanding by the Company’s wholesale propane and marketing operation at the end of September compared to December 31, 2004.

Page 31

Cash Flows Used in Investing Activities

Net cash flows used in investing activities totaled $28.3 million and $19.7 million during the nine months ended September 30, 2006 and 2005, respectively. Cash utilized for capital expenditures was $28.2 million and $19.9 million for the first nine months of 2006 and 2005, respectively. Additions to property, plant and equipment in the first nine months of 2006 and 2005 were primarily for natural gas transmission, natural gas distribution and propane distribution. In both periods in 2006 and 2005, 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. Additionally, net cash of $10,000 was paid in the first nine months ended September 2006 and net cash of $206,000 was received during the first nine months ended September 30, 2005 for recovery of environmental costs through rates charged to customers.

Cash Flows from Financing Activities

Cash flows generated from financing activities totaled $9.2 million for the nine months ended September 30, 2006 and cash flows used in the nine months ended September 30, 2005 totaled $225,000. During the first nine months of 2006, the Company:

·	borrowed $14.8 million under its short-term line of credit agreements;

·	paid common stock dividends totaling $4.5 million;

·	reduced its outstanding long-term notes payable balance by $1.9 million; and

·	paid cash of $435,000 in lieu of issuing shares of the Company’s common stock for the 30,000 stock warrants outstanding at December 31, 2005. The stock warrants were exercised in the third quarter of 2006.

During the first nine months of 2005, the Company borrowed $4.8 million under its short-term line of credit agreements. Additionally, the Company paid common stock dividends totaling $4.3 million and reduced its outstanding long-term notes payable balance by $1.8 million.

Shelf Registration

On July 5, 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. Under this registration statement, Chesapeake may sell common stock and/or debt securities in one or more separate offerings with the size, price and terms to be determined at the time of sale. The net proceeds from the sale of common stock and/or debt securities will be added to the Company’s general corporate funds and may be used for general corporate purposes including, but not limited to, financing of capital expenditures, repayment of short-term debt, funding share repurchases, financing acquisitions, investing in subsidiaries and general working capital purposes.

Off-Balance Sheet Arrangements

As noted in the Company’s 2005 Annual Report on Form 10-K, the Company has issued corporate guarantees to certain vendors of its propane wholesale marketing subsidiary, its Delmarva propane distribution subsidiary, and its natural gas marketing subsidiary in Florida. 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 in this Quarterly Report on Form 10-Q. The aggregate amount guaranteed at September 30, 2006, totaled $18.9 million, with the guarantees expiring on various dates in 2006 and 2007.

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 claim amounts to satisfy the deductibles on the Company’s policies. The current letter of credit was renewed during the second quarter of 2006 when the insurance policies were renewed.

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Contractual Obligations

There have been no material changes in the contractual obligations presented in the Company’s 2005 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 September 30, 2006:

	Payments Due by Period
Purchase Obligations	Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years		Total
Commodities ⁽¹⁾	$	24,174,050	$	0	$	0	$	0	$	24,174,050
Propane ⁽²⁾		25,151,543		-		-		-		25,151,543
Total Purchase Obligations	$	49,325,593	$	0	$	0	$	0	$	49,325,593

⁽¹⁾In addition to the obligations noted above, the natural gas distribution and propane distribution operations have agreements with commodity suppliers that have provisions that allow 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 $27.8 million. See Part I, Item 3, “Quantitative and Qualitative Disclosures about Market Risk,” below for further information.

Environmental Matters

As more fully described in Note 4 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, Chesapeake has incurred costs relating to the completed or ongoing environmental remediation at three former gas manufacturing plant sites. In addition, Chesapeake is currently participating in discussions regarding the possible responsibilities of the Company for remediation of a fourth former gas manufacturing plant site located in Cambridge, Maryland. Chesapeake believes that future costs associated with these sites will be recoverable in rates or through sharing arrangements with, or contributions by, other responsible parties.

Other Matters

Regulatory Matters

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

Eastern Shore. During October 2002, Eastern Shore filed for recovery of gas supply realignment costs, which totaled $196,000 (including interest), associated with the implementation of FERC Order No. 636. At that time, the FERC deferred review of the filing pending settlement of a related matter concerning another transmission company. Chesapeake understands that the other matter has now been resolved. Eastern Shore updated its gas supply realignment filing and entered into pre-filing discussions with customers potentially impacted by the filing before re-filing its application with the FERC. Discussions with customers were completed during the first quarter of 2006. Eastern Shore resubmitted its filing to the FERC on June 22, 2006, requesting authorization to recover a total of $222,848 (including interest) of gas supply realignment costs.

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On December 9, 2005, Eastern Shore filed revised tariff sheets to replace its existing fixed price penalties with penalties that are the higher of a fixed price or a multiple of a daily index price. The revised penalties are applicable to customers who violate Operational Flow Orders and customers who take unauthorized overrun quantities that could threaten the operational integrity of the pipeline, or to Eastern Shore’s ability to render reliable service. By letter order dated January 6, 2006, the FERC accepted Eastern Shore’s proposed changes, effective December 21, 2005.

On January 20, 2006, Eastern Shore filed an application for a Certificate of Public Convenience and Necessity for its 2006-2008 system expansion project with the FERC. The proposed expansion application requests 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. 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:

	Year
	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	$3,670,256	$1,484,146	$1,594,785

A Scoping Meeting was held on March 29, 2006 at which the public and all other interested stakeholders were invited to attend to review the project. No opposition to the project was received. On June 13, 2006, the FERC issued an Order Issuing Certificate to Eastern Shore authorizing it to construct and operate the 2006-2008 system expansion project. Eastern Shore has commenced construction of certain Phase I facilities. Phase II and Phase III facilities are expected to be constructed in 2007 and 2008, respectively.

On May 31, 2006, Eastern Shore entered into Precedent Agreements with Chesapeake, through its Delaware and Maryland Divisions, and Delmarva Power & Light Company (“Delmarva”) to provide additional firm transportation services upon completion of its latest proposed pipeline project (the “Proposed Project”).

Eastern Shore has proposed to develop, construct and operate new pipeline facilities that would transport natural gas from Calvert County, Maryland, through Dorchester and Caroline Counties, Maryland, to points on the Delmarva Peninsula where such facilities would interconnect with its existing facilities in Sussex County, Delaware. The total cost of the Proposed Project is estimated at $93 million, depending upon the final size and route of the pipeline, as well as construction materials and labor costs.

Chesapeake and Delmarva are currently parties to existing firm natural gas transportation service agreements with Eastern Shore and each desires firm transportation services under the Proposed Project. Pursuant to these agreements (“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, such firm transportation services under the Proposed Project.

During the negotiations of the Precedent Agreements, Eastern Shore and each of the customers entered into Letter Agreements, which provide that, in the event that the Proposed Project is not certified and placed in service, the customers will 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.

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In connection with the Proposed Project, on June 27, 2006, Eastern Shore submitted a petition to the FERC for approval of an uncontested Settlement Agreement, to implement the rate-related Settlement Agreement to address the development costs of the Proposed Project. The filed Settlement Agreement was entered into by Eastern Shore and its firm customers. 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 uncontested Settlement Agreement. On September 6, 2006, Eastern Shore submitted to FERC proposed revised tariff sheets to implement the provisions of the above-referenced Settlement Agreement. By Letter Order dated October 6, 2006, the FERC accepted the tariff sheets effective September 7, 2006.

On September 19, 2006, Eastern Shore submitted its Annual Charge Adjustment (“ACA”) compliance filing to reflect the most current ACA surcharge rate as established by the FERC. The revised ACA surcharge, proposed to be effective October 1, 2006, is currently pending before the FERC.

Delaware. On October 3, 2005, the Delaware division filed its annual Gas Sales Service Rates (“GSR”) application that was effective for service rendered on and after November 1, 2005 with the Delaware Public Service Commission (“Delaware PSC”). On February 23, 2006, the Delaware division filed a supplemental GSR application with the Delaware PSC that was consolidated with the previously filed application. In its supplemental application, the Delaware division proposed reduced GSR charges to be effective March 15, 2006. On September 19, 2006, the Delaware PSC granted final approval of both GSR applications.

On September 1, 2006, the Delaware division filed its annual GSR application to be effective for service rendered on and after November 1, 2006 with the Delaware PSC. On October 3, 2006, the Delaware PSC approved the GSR charges, subject to full evidentiary hearings and a final decision. The Delaware division expects a final decision during the first half of 2007.

On November 1, 2005, 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, 2005. The Delaware PSC granted approval of the ER rate at its regularly scheduled meeting on November 8, 2005, subject to full evidentiary hearings and a final decision. An evidentiary hearing was held on April 5, 2006, which was uncontested. The Delaware PSC granted final approval of the ER rate at its regularly scheduled meeting on May 9, 2006.

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 and traditional ratemaking processes, natural gas has not been extended to 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 of its application at this time, the Company anticipates a final decision from the Delaware PSC regarding its application in late 2006 or the first half of 2007.

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Maryland. On May 1, 2006, the Maryland division filed a base rate application with the Maryland Public Service Commission (“Maryland PSC”) requesting an overall increase in base rates of approximately $1,137,000 annually, based on a proposed overall rate of return of 9.7 percent and a return on equity of 11.5 percent. On September 26, 2006, the Maryland PSC approved a base rate increase of approximately $780,000 annually, based on an overall rate of return of 9.03 percent and a return on equity of 10.75 percent. This increase would result in an average increase in revenues of approximately 4.5 percent for the Maryland division’s firm residential, commercial and industrial customers. The PSC also approved the Company’s proposal to implement a revenue normalization mechanism for its residential heating and smaller commercial heating customers, reducing the Company’s risk due to weather and usage changes.

On December 14, 2006, the Maryland PSC will be holding 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. While the Company cannot predict the outcome of this proceeding at this time, the Company anticipates a final decision from the Maryland PSC during the first quarter of 2007.

Florida. On March 22, 2006, the Florida division filed a petition with the Florida Public Service Commission (“Florida PSC”) seeking approval of special contracts to provide Delivery Point Operator (“DPO”) services. Under the proposed contracts, the DPO services would be provided to an affiliate company, Peninsula Energy Services Company, Inc. The Florida PSC approved the petition on July 7, 2006, ordering that the special contracts be effective June 20, 2006.

On May 16, 2005, the Florida division filed a request with the Florida PSC for approval of a Special Contract with the Department of Management Services, an agency of the State of Florida, for service to the Washington Correction Institution (“WCI”). The Florida PSC approved the Company’s request on July 19, 2005, and service to the existing WCI facility began in February 2006. WCI is located in Washington County in the Florida panhandle and is the thirteenth county served by the Company’s Florida division.

On September 2, 2005, the Florida division filed a petition for a Declaratory Statement with the Florida PSC for a determination that Peninsula Pipeline Company, Inc. (“PPC”), a wholly owned subsidiary of the Company, qualifies as a natural gas transmission company under the Natural Gas Transmission Pipeline Intrastate Regulatory Act. The Florida PSC approved this Petition at its December 20, 2005 agenda conference, and a final order was issued on January 9, 2006. The determination that PPC qualifies as a natural gas transmission company provides opportunities for investment by PPC to deliver natural gas transmission service to industrial customers in Florida by an intra-state pipeline.

On September 15, 2006, the Florida division filed a petition for approval of its Energy Conservation Cost Recovery Factors for the year 2007 with the Florida PSC. When approved, the new factors will go into effect on January 1, 2007.

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 in interruptible sales occur when oil prices are lower relative to the price of natural gas. Oil prices, as well as the prices of electricity and other fuels are subject to fluctuation for a variety of reasons; therefore, future competitive conditions are not predictable. To address this uncertainty, the Company uses flexible pricing arrangements on both the supply and sales sides of its business to maximize sales volumes. As a result of the transmission business’ conversion to open access, this business has shifted from providing competitive sales service to providing transportation and contract storage services.

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The Company’s natural gas distribution operations located in Delaware, Maryland and Florida offer transportation services to certain industrial customers. The Florida operation extended transportation service to commercial customers in 2001 and to residential customers in 2002. With transportation service available on the Company’s distribution systems, the Company is competing with third-party suppliers to sell gas to certain customers. As it relates to transportation services, the Company’s competitors include interstate transmission companies that are in close proximity to the Company’s pipeline. The customers at risk are usually large-volume commercial and industrial customers with the financial resources and capability to bypass the Company’s distribution operations. In certain situations, the Company’s distribution operations may adjust services and rates for these customers to retain their business. The Company expects to continue to expand the availability of transportation service to additional classes of distribution customers in the future. The Company operates a natural gas marketing operation in Florida to compete for customers eligible for transportation services.

The Company’s propane distribution operations compete with several other propane distributors in their service territories, primarily on the basis of service and price, emphasizing 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 primarily with electricity and heating oil as energy sources. Since natural gas has historically been less expensive than propane, propane is generally not distributed in geographic areas serviced by natural gas pipeline or distribution systems.

The propane wholesale marketing operation competes against various marketers, many of which have significantly greater resources and are able to obtain price or volumetric advantages.

The advanced information services business faces significant competition from a number of larger competitors having substantially greater resources available to them 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.

Recent Pronouncements

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In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R).” This statement would require a company to (a) recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, (b) measure a plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year, and (c) recognize changes in the funded status of a defined postretirement plan in the year in which the changes occur and to report the changes as adjustments to comprehensive income. The requirement to recognize the funded status of a benefit plan and the disclosure requirements are effective as of the end of the fiscal year ending after December 15, 2006. The requirement to measure the plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2006. The Company does not anticipate that the adoption of SFAS No. 158 will have a material impact on the Company’s financial position, and expects no impact to the statements of income or cash flows.

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”), which provides interpretive guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB 108 is effective as of the end of our 2006 fiscal year, allowing a one-time transitional cumulative effect adjustment to beginning retained earnings as of January 1, 2006, for errors that were not previously deemed material, but are material under the guidance in SAB 108. We do not anticipate that the adoption of SAB 108 will have a material impact on the Company’s Consolidated Financial Statements.

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 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.

Cautionary Statement

Chesapeake has made statements in this report that are considered to be forward-looking statements. These statements are not matters of historical fact. Sometimes they contain words such as “believes,” “expects,” “intends,” “plans,” “will,” or “may,” and other similar words of a predictive nature. These statements relate to matters such as customer growth, changes in revenues or gross margins, capital expenditures, environmental remediation costs, regulatory approvals, market risks associated with the Company’s propane wholesale marketing operation, competition, inflation 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. These factors include, among other things:

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o	the temperature sensitivity of the natural gas and propane businesses;

o	the effect of spot, forward and futures market prices on the Company’s distribution, wholesale marketing and energy trading businesses;

o	the effects of competition on the Company’s unregulated and regulated businesses;

o	the effect of changes in federal, state or local regulatory and tax requirements, including deregulation;

o	the effect of accounting changes;

o	the effect of compliance with environmental regulations or the remediation of environmental damage;

o	the effects of general economic conditions on the Company and its customers;

o	the ability of the Company’s new and planned facilities and acquisitions to generate expected revenues; and

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

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 the change 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 $61.7 million at September 30, 2006, as compared to a fair value of $65.0 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 in part on the fluctuation in interest rates.

The Company’s propane distribution business is exposed to market risk as a result of propane storage activities and entering into fixed price contracts for supply. The Company can store up to approximately four million gallons (including leased storage and rail cars) of propane during the winter season to meet its customers’ peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause the value of stored propane to decline. To mitigate the impact of price fluctuations, the Company has adopted a Risk Management Policy that allows the propane distribution operation to enter into fair value hedges of its inventory. As of September 30, 2006 management reviewed the Company’s storage position and several hedging strategies and elected not to hedge any of its inventories.

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.

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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 oversight officials on a daily basis. Additionally, 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 September 30, 2006 is presented in the following table.

At September 30, 2006	Quantity in gallons	Estimated Market Prices	Weighted Average Contract Prices
Forward Contracts
Sale	25,337,550	$0.93750 — $1.22375	$1.09770
Purchase	23,541,000	$0.93750 — $1.22000	$1.06840

Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expire in 2006 or the first quarter of 2007.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Chief Executive Officer and Chief Financial Officer of the Company, with the participation of other Company officials, have evaluated the Company’s “disclosure controls and procedures” (as such term is defined under Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended) as of September 30, 2006. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

During the quarter ended September 30, 2006, 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

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

The following is a discussion of the primary factors that may affect the operations and/or financial performance of the regulated and/or unregulated businesses of Chesapeake. These risk factors include:

Fluctuations in weather have the potential to adversely affect our results of operations, cash flows, and financial condition.

Our utility and propane distribution operations are sensitive to fluctuations in weather, and weather conditions directly influence the volume of natural gas and propane delivered by our utility and propane distribution operations to customers. A significant portion of our utility and propane distribution operations’ revenues are derived from the delivery of natural gas and propane to residential and commercial heating customers during the five-month peak heating season of November through March. If the weather is warmer than normal, we deliver less natural gas and propane to customers, and earn less revenue. In addition, hurricanes or other extreme weather conditions could damage production or transportation facilities, which could result in decreased supplies of natural gas and propane, increased supply costs and higher prices for customers.

Regulation of the Company, including changes in the regulatory environment in general, may adversely affect our results of operations, cash flows and financial condition.

The state Public Service Commissions of Delaware, Maryland and Florida regulate our natural gas distribution operations. ESNG, our natural gas transmission subsidiary, is regulated by the FERC. These regulatory commissions set the rates in their respective jurisdictions that we can charge customers for our rate-regulated services. Changes in these rates, as ordered by regulatory commissions, affect our financial performance. Our ability to obtain timely future rate increases and rate supplements to maintain current rates of return depends on regulatory discretion, and there can be no assurance that our divisions and ESNG will be able to obtain rate increases or supplements or continue receiving currently authorized rates of return.

The amount and availability of natural gas and propane supplies are difficult to predict, which may reduce our earnings.

Natural gas and propane production can be impacted by factors outside of our control, such as weather and refinery closings. If we are unable to obtain sufficient natural gas and propane supplies to meet demand, our results of operation may be negatively impacted.

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We rely on having access to interstate pipelines’ transportation and storage capacity. If these pipelines or storage facilities were not available, it may impair our ability to meet our customers’ full requirements.

We must acquire both sufficient natural gas supplies and interstate pipeline and storage capacity to meet customer requirements. We must contract for reliable and adequate delivery capacity for our distribution system, while considering the dynamics of the interstate pipeline and storage capacity market, our own on-system resources, as well as the characteristics of our customer base. Local natural gas distribution companies, including us, and other participants in the energy industry, have raised concerns regarding the future availability of additional upstream interstate pipeline and storage capacity. Additional available pipeline and storage capacity is a business issue that must be managed by us, as our customer base grows.

Natural gas and propane commodity price changes may affect the operating costs and competitive positions of our natural gas and propane distribution operations, which may adversely affect our results of operations, cash flows and financial condition.

Natural Gas. Over the last four years, natural gas costs have increased significantly and become more volatile. In addition, the hurricane activity in 2005 reduced the natural gas available from the Gulf Coast region, further contributing to the volatility of natural gas prices. Higher natural gas prices can result in significant increases in the cost of gas billed to customers during the winter heating season. Under our regulated gas cost recovery mechanisms, we record cost of gas expense equal to the cost of gas recovered in revenues from customers. Therefore, an increase in the cost of gas due to an increase in the price of the natural gas commodity generally has no direct effect on our revenues and net income. However, our net income may be reduced due to higher expenses that may be incurred for uncollectible customer accounts, as well as lower volumes of natural gas deliveries to customers due to lower natural gas consumption caused by customer conservation. Increases in the price of natural gas also can affect our operating cash flows, as well as the competitiveness of natural gas as an energy source.

Propane. The level of profitability in the retail propane business is largely dependent on the difference between the cost of propane and the revenues derived from our sale of propane to our customers. Propane costs are subject to volatile changes as a result of product supply or other market conditions, including, economic and political factors impacting crude oil and natural gas supply or pricing. Propane cost changes can occur rapidly over a short period of time and can impact profitability. There is no assurance that we will be able to pass on propane cost increases fully or immediately, particularly when propane costs increase or decrease rapidly. Therefore, average retail sales prices can vary significantly from year to year as product costs fluctuate with propane, fuel oil, crude oil and natural gas commodity market conditions. In addition, in periods of sustained higher commodity prices, retail sales volumes may be negatively impacted by customer conservation efforts and increased amounts of uncollectible accounts.

We compete in a competitive environment and may be faced with losing customers to a competitor.

We compete with third-party suppliers to sell gas to industrial customers. As it relates to transportation services, our competitors include the interstate transmission company if the distribution customer is located close enough to the transmission company’s pipeline to make a connection economically feasible.

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Our 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. Some of our competitors have significantly greater resources. The retail propane industry is mature, and we foresee only modest growth in total demand. Given this limited growth, we expect that year-to-year industry volumes will be principally affected by weather patterns. Therefore, our ability to grow the propane distribution business is contingent upon execution of our community gas systems strategy to capture market share and to employ pricing programs that retain and grow our customer base. Any failure to retain and grow our customer base would have an adverse effect on our results.

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 to compete on the basis of technological expertise, reputation and price.

Costs of compliance with environmental laws may be significant.

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These evolving laws and regulations may require expenditures over a long timeframe to control environmental effects at current and former operating sites, including former gas manufactured sites that we have acquired from third parties. Compliance with these legal requirements requires us to commit capital toward environmental compliance. If we fail to comply with environmental laws and regulations, even if such failure is caused by factors beyond our control, we may be assessed civil or criminal penalties and fines.

To date, we have been able to recover through approved rate mechanisms the costs of recovery associated with the remediation of former gas manufactured sites. However, there is no guarantee that we will be able to recover future remediation costs in the same manner or at all. A change in our approved rate mechanisms for recovery of environmental remediation costs at former manufacturer gas sites could adversely affect our results of operations, cash flows and financial condition.

Further, existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to us. Revised or additional laws and regulations could result in additional operating restrictions on our facilities or increased compliance costs which may not be fully recoverable by us.

A change in the economic conditions and interest rates may adversely affect our results of operations and cash flows.

A downturn in the economies of the regions in which we operate, which we cannot accurately predict, might adversely affect our ability to grow our customer base and other businesses at the same rate they have grown in the recent past. Further, an increase in interest rates without the recovery of the higher cost of debt in the sales and/or transportation rates we charge our utility customers, could adversely affect future earnings. An increase in short-term interest rates would negatively affect our results of operations, which depend on short-term debt to finance accounts receivable, storage gas inventories, and to temporarily finance capital expenditures.

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Inflation may impact our results of operations, cash flows and financial position.

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. To help cope with the effects of inflation on our capital investments and returns, we seek rate relief from regulatory commissions for regulated operations while monitoring the returns of our unregulated business operations. There can be no assurance that we will be able to obtain adequate and timely rate relief to offset the effects of inflation. To compensate for fluctuations in propane gas prices, we adjust our propane selling prices to the extent allowed by the market. However, there can be no assurance that we will be able to increase propane sales prices sufficiently to fully compensate for such fluctuations in the cost of propane gas to us.

Changes in technology may adversely affect our advanced information services segment’s results of operations, cash flows and financial condition.

Our advanced information services segment participates in a market that is characterized by rapidly changing technology and accelerating product introduction cycles. The success of our advanced information services segment depends upon our ability to address the rapidly changing needs of our customers by developing and supplying high-quality, cost-effective products, product enhancements and services on a timely basis, and by keeping pace with technological developments and emerging industry standards. There can be no assurance that we will be able to keep up with technological advancements necessary to make our products competitive.

Our energy marketing subsidiaries have credit risk and credit requirements that may adversely affect our results of operations, cash flows and financial condition.

Xeron, our propane wholesale and marketing subsidiary, and PESCO, our natural gas marketing subsidiary in Florida, extend credit to counter-parties. While we believe Xeron and PESCO utilize prudent credit policies, each of these subsidiaries is exposed to the risk that it may not be able to collect amounts owed to it. If the counter-party to such a transaction fails to perform and any underlying collateral is inadequate, we could experience financial losses.

Our subsidiaries Xeron and PESCO are dependent upon the availability of credit to buy propane and natural gas for resale or to trade. If the financial condition of these subsidiaries declines, or if our financial condition declines, then the cost of credit available to these subsidiaries could increase. If credit is not available, or if credit is more costly, our results of operations, cash flows and financial condition may be adversely affected.

Our use of derivative instruments may adversely affect our results of operations.

Fluctuating commodity prices cause our earnings and financing costs to be impacted. Our propane distribution and wholesale marketing segment uses derivative instruments, including forwards, swaps and puts, to hedge price risk. In addition, we may decide, after further evaluation, to utilize derivative instruments to hedge price risk for our Delaware and Maryland divisions, as well as PESCO. While we have a risk policy and operating procedures in place to control our exposure to risk, if we purchase derivative instruments that are not properly matched to our exposure, our results of operations, cash flows, and financial conditions may be adversely impacted.

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Inability to access the capital markets may impair our future growth.

We rely on access to both short-term and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flow from our operations. Currently, $65 million of the total $80 million of short-term lines of credit utilized to satisfy our short-term financing requirements are discretionary, uncommitted lines of credit. We utilize discretionary lines of credit to reduce the cost associated with these short-term financing requirements. We are committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access the capital markets when required. However, if we are not able to access capital at competitive rates, our ability to implement our strategic plan, undertake improvements and make other investments required for our future growth may be limited.

We are subject to operating and litigation risks that may not be covered by insurance.

Our operations are subject to the operating hazards and risks normally incidental to handling, storing, transporting and otherwise providing natural gas and propane to end users. As a result, we are sometimes a defendant in legal proceedings and litigation arising in the ordinary course of business. We maintain insurance policies with insurers in such amounts and with such coverages and deductibles as we believe are reasonable and prudent. There can be no assurance, however, that such insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that such levels of insurance will be available in the future at economical prices.

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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⁾
July 1, 2006 through July 31, 2006 ⁽¹⁾		446	$	30.72		0		0
August 1, 2006 through August 31, 2006		0	$	0.00		0		0
September 1, 2006 through September 30, 2006		0	$	0.00		0		0
Total		446	$	30.72		0		0

⁽¹⁾ Chesapeake purchases shares of stock on the open market for the reinvestment of the dividend on shares held in a Rabbi Trust to secure its obligations under the Company’s Supplemental Executive Retirement Savings Plan (“SERP plan”). During the quarter, 446 shares were purchased for this purpose.
⁽²⁾ 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 November 9, 2006
31.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, dated November 9, 2006
32.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated November 9, 2006
32.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated November 9, 2006

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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: November 9, 2006

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