10-Q

United States
Securities and Exchange Commission

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended: June 30, 2011

OR

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

For the transition period from                      to                     

Commission File Number: 001-11590

Chesapeake Utilities Corporation

(Exact name of registrant as specified in its charter)

Delaware	51-0064146
(State or other jurisdiction of	(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 þ No o

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

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

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

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

Common Stock, par value $0.4867 — 9,564,197 shares outstanding as of July 31, 2011.

Table of Contents

PART I — FINANCIAL INFORMATION	1
Item 1. Financial Statements	1
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 3. Quantitative and Qualitative Disclosures about Market Risk	55
Item 4. Controls and Procedures	56
PART II — OTHER INFORMATION	57
Item 1. Legal Proceedings	57
Item 1A. Risk Factors	57
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	57
Item 3. Defaults upon Senior Securities	57
Item 5. Other Information	57
Item 6. Exhibits	58
SIGNATURES	59
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

GLOSSARY OF KEY TERMS

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

Subsidiaries of Chesapeake Utilities Corporation

BravePoint	BravePoint®, Inc. is a wholly-owned subsidiary of Chesapeake Services Company, which is a wholly-owned subsidiary of Chesapeake
Chesapeake	The Registrant, the Registrant and its subsidiaries, or the Registrant’s subsidiaries, as appropriate in the context of the disclosure
Company	The Registrant, the Registrant and its subsidiaries, or the Registrant’s subsidiaries, as appropriate in the context of the disclosure
Eastern Shore	Eastern Shore Natural Gas Company, a wholly-owned subsidiary of Chesapeake
FPU	Florida Public Utilities Company, a wholly-owned subsidiary of Chesapeake, effective October 28, 2009
PESCO	Peninsula Energy Services Company, Inc., a wholly-owned subsidiary of Chesapeake
Peninsula Pipeline	Peninsula Pipeline Company, Inc., a wholly-owned subsidiary of Chesapeake
Sharp	Sharp Energy, Inc., a wholly-owned subsidiary of Chesapeake’s and Sharp’s subsidiary, Sharpgas, Inc.
Xeron	Xeron, Inc., a wholly-owned subsidiary of Chesapeake

Regulatory Agencies

Delaware PSC	Delaware Public Service Commission
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
FDEP	Florida Department of Environmental Protection
FDOT	Florida Department of Transportation
Florida PSC	Florida Public Service Commission
Maryland PSC	Maryland Public Service Commission
MDE	Maryland Department of the Environment
PSC	Public Service Commission
SEC	Securities and Exchange Commission

Accounting Standards Related

FASB	Financial Accounting Standards Board
GAAP	Generally Accepted Accounting Principles

Other

AS/SVE	Air Sparging and Soil/Vapor Extraction
BS/SVE	Bio-Sparging and Soil/Vapor Extraction
CDD	Cooling Degree-Days
DSCP	Directors Stock Compensation Plan
Dts	Dekatherms
Dts/d	Dekatherms per day
ECCR	Energy Conservation Cost Recovery
FGT	Florida Gas Transmission Company
FRP	Fuel Retention Percentage
GSR	Gas Sales Service Rates
Gulf Power	Gulf Power Corporation
Gulfstream	Gulfstream Natural Gas System, LLC
HDD	Heating Degree-Days
MWH	Megawatt Hour
Mcf	Thousand Cubic Feet
MGP	Manufactured Gas Plant
NYSE	New York Stock Exchange
OCI	Other Comprehensive Income
OTC	Over-the-Counter
PIP	Performance Incentive Plan
RAP	Remedial Action Plan
Sanford Group	FPU and Other Responsible Parties involved with the Sanford Environmental Site
TETLP	Texas Eastern Transmission, LP
TOU	Time-of-Use

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Income (Unaudited)

For the Three Months Ended June 30,	2011		2010
(in thousands, except shares and per share data)
Operating Revenues
Regulated Energy	$	54,327	$	52,740
Unregulated Energy		29,692		24,615
Other		2,812		2,706
Total operating revenues		86,831		80,061
Operating Expenses
Regulated energy cost of sales		24,882		24,625
Unregulated energy and other cost of sales		24,420		20,384
Operations		20,401		18,526
Maintenance		1,892		1,789
Depreciation and amortization		4,937		4,545
Other taxes		2,523		2,431
Total operating expenses		79,055		72,300
Operating Income		7,776		7,761
Other income (loss), net of expenses		27		(11	)
Interest charges		2,114		2,305
Income Before Income Taxes		5,689		5,445
Income tax expense		2,169		2,105
Net Income	$	3,520	$	3,340
Weighted-Average Common Shares Outstanding:
Basic		9,557,707		9,467,222
Diluted		9,650,887		9,557,352
Earnings Per Share of Common Stock:
Basic	$	0.37	$	0.35
Diluted	$	0.37	$	0.35
Cash Dividends Declared Per Share of Common Stock	$	0.345	$	0.330

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Income (Unaudited)

For the Six Months Ended June 30,	2011		2010
(in thousands, except shares and per share data)
Operating Revenues
Regulated Energy	$	139,329	$	144,367
Unregulated Energy		88,442		83,885
Other		5,658		5,069
Total operating revenues		233,429		233,321
Operating Expenses
Regulated energy cost of sales		72,872		78,889
Unregulated energy and other cost of sales		68,711		65,474
Operations		40,237		37,524
Maintenance		3,595		3,489
Depreciation and amortization		9,958		9,389
Other taxes		5,441		5,397
Total operating expenses		200,814		200,162
Operating Income		32,615		33,159
Other income, net of expenses		50		103
Interest charges		4,265		4,667
Income Before Income Taxes		28,400		28,595
Income tax expense		11,133		11,281
Net Income	$	17,267	$	17,314
Weighted-Average Common Shares Outstanding:
Basic		9,546,606		9,443,708
Diluted		9,642,374		9,550,670
Earnings Per Share of Common Stock:
Basic	$	1.81	$	1.83
Diluted	$	1.79	$	1.82
Cash Dividends Declared Per Share of Common Stock	$	0.675	$	0.645

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

For the Six Months Ended June 30,	2011			2010
(in thousands)
Operating Activities
Net Income	$	17,267		$	17,314
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		9,958			9,389
Depreciation and accretion included in other costs		2,473			2,199
Deferred income taxes, net		12,449			3,683
Loss on sale of assets		94			71
Unrealized (gain) loss on commodity contracts		30			(374	)
Unrealized (gain) loss on investments		(131	)		60
Employee benefits		309			(383	)
Share-based compensation		705			612
Other, net		(18	)		(105	)
Changes in assets and liabilities:
Sale (purchase) of investments		258			(131	)
Accounts receivable and accrued revenue		14,017			26,485
Propane inventory, storage gas and other inventory		3,315			3,382
Regulatory assets		601			1,226
Prepaid expenses and other current assets		1,792			3,539
Accounts payable and other accrued liabilities		674			(14,796	)
Income taxes receivable		(2,666	)		2,201
Accrued interest		(241	)		(259	)
Customer deposits and refunds		(1,182	)		1,041
Accrued compensation		(2,234	)		83
Regulatory liabilities		2,887			1,194
Other liabilities		(268	)		583
Net cash provided by operating activities		60,089			57,014
Investing Activities
Property, plant and equipment expenditures		(21,236	)		(13,600	)
Proceeds from sales of assets		344			34
Purchase of investments		(200	)		(310	)
Environmental expenditures		(326	)		(410	)
Net cash used in investing activities		(21,418	)		(14,286	)
Financing Activities
Common stock dividends		(5,685	)		(5,369	)
(Purchase) issuance of stock for Dividend Reinvestment Plan		(609	)		268
Change in cash overdrafts due to outstanding checks		(3,193	)		(834	)
Net repayment under line of credit agreements		(27,417	)		(29,188	)
Other short-term borrowing		(29,100	)		29,100
Proceeds from issuance of long-term debt		29,000			—
Repayment of long-term debt		(1,482	)		(30,277	)
Net cash used in financing activities		(38,486	)		(36,300	)
Net Increase in Cash and Cash Equivalents		185			6,428
Cash and Cash Equivalents — Beginning of Period		1,643			2,828
Cash and Cash Equivalents — End of Period	$	1,828		$	9,256

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

	June 30,			December 31,
Assets	2011			2010
(in thousands, except shares and per share data)
Property, Plant and Equipment
Regulated energy	$	511,008		$	500,689
Unregulated energy		62,399			61,313
Other		18,926			16,989
Total property, plant and equipment		592,333			578,991
Less: Accumulated depreciation and amortization		(129,054	)		(121,628	)
Plus: Construction work in progress		8,317			5,394
Net property, plant and equipment		471,596			462,757
Investments, at fair value		4,109			4,036
Current Assets
Cash and cash equivalents		1,828			1,643
Accounts receivable (less allowance for uncollectible accounts of $1,095 and $1,194, respectively)		80,381			88,074
Accrued revenue		8,655			14,978
Propane inventory, at average cost		6,790			8,876
Other inventory, at average cost		3,266			3,084
Regulatory assets		289			51
Storage gas prepayments		3,672			5,084
Income taxes receivable		9,414			6,748
Deferred income taxes		2,170			2,191
Prepaid expenses		3,111			4,613
Mark-to-market energy assets		335			1,642
Other current assets		226			245
Total current assets		120,137			137,229
Deferred Charges and Other Assets
Goodwill		35,613			35,613
Other intangible assets, net		3,293			3,459
Long-term receivables		26			155
Regulatory assets		22,300			23,884
Other deferred charges		3,415			3,860
Total deferred charges and other assets		64,647			66,971
Total Assets	$	660,489		$	670,993

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

	June 30,			December 31,
Capitalization and Liabilities	2011			2010
(in thousands, except shares and per share data)
Capitalization
Stockholders’ equity
Common stock, par value $0.4867 per share (authorized 25,000,000 shares)	$	4,654		$	4,635
Additional paid-in capital		148,796			148,159
Retained earnings		87,549			76,805
Accumulated other comprehensive loss		(2,999	)		(3,360	)
Deferred compensation obligation		796			777
Treasury stock		(796	)		(777	)
Total stockholders’ equity		238,000			226,239
Long-term debt, net of current maturities		117,123			89,642
Total capitalization		355,123			315,881
Current Liabilities
Current portion of long-term debt		9,196			9,216
Short-term borrowing		4,248			63,958
Accounts payable		64,427			65,541
Customer deposits and refunds		25,135			26,317
Accrued interest		1,548			1,789
Dividends payable		3,299			3,143
Accrued compensation		4,623			6,784
Regulatory liabilities		11,960			9,009
Mark-to-market energy liabilities		216			1,492
Other accrued liabilities		12,081			10,393
Total current liabilities		136,733			197,642
Deferred Credits and Other Liabilities
Deferred income taxes		92,700			80,031
Deferred investment tax credits		203			243
Regulatory liabilities		3,670			3,734
Environmental liabilities		9,414			10,587
Other pension and benefit costs		17,816			18,199
Accrued asset removal cost — Regulatory liability		35,919			35,092
Other liabilities		8,911			9,584
Total deferred credits and other liabilities		168,633			157,470
Other commitments and contingencies (Note 4 and 5)
Total Capitalization and Liabilities	$	660,489		$	670,993

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

													Accumulated
	Common Stock						Additional						Other
	Number of						Paid-In			Retained			Comprehensive			Deferred		Treasury
(in thousands, except shares and per share data)	Shares(6)			Par Value			Capital			Earnings			Loss			Compensation		Stock			Total
Balances at December 31, 2009		9,394,314	(6)	$	4,572		$	144,502		$	63,231		$	(2,524	)	$	739	$	(739	)	$	209,781
Net Income											26,056											26,056
Other comprehensive income, net of tax:
Employee Benefit Plans, net of tax:
Amortization of prior service costs (4)														8	(4)							8
Net Loss (5)														(844	)(5)							(844	)
Total comprehensive income																						25,220
Dividend Reinvestment Plan		53,806			26			1,699														1,725
Retirement Savings Plan		27,795			14			889														903
Conversion of debentures		11,865			6			196														202
Tax benefit on share based compensation								253														253
Share based compensation (1) (3)		36,415	(1)(3)		17	(1)(3)		620	(1)(3)													637
Deferred Compensation Plan																	38		(38	)		—
Purchase of treasury stock		(1,144	)																(38	)		(38	)
Sale and distribution of treasury stock		1,144																	38			38
Dividends on stock-based compensation											(104	)										(104	)
Cash dividends (2)											(12,378	)(2)										(12,378	)
Balances at December 31, 2010		9,524,195	(6)		4,635			148,159			76,805			(3,360	)		777		(777	)		226,239
Net Income											17,267											17,267
Other comprehensive income, net of tax:
Employee Benefit Plans, net of tax:
Amortization of prior service costs (4)														4	(4)							4
Net Gain (5)														357	(5)							357
Total comprehensive income																						17,628
Dividend Reinvestment Plan		—						(11	)													(11	)
Retirement Savings Plan		2,002			1			79														80
Conversion of debentures		5,691			3			94														97
Share based compensation (1) (3)		30,430			15	(1)(3)		475	(1)(3)													490
Deferred Compensation Plan																	19		(19	)		—
Purchase of treasury stock		(473	)																(19	)		(19	)
Sale and distribution of treasury stock		473																	19			19
Dividends on stock-based compensation											(73	)										(73	)
Cash dividends (2)											(6,450	)(2)										(6,450	)
Balances at June 30, 2011		9,562,318		$	4,654		$	148,796		$	87,549		$	(2,999	)	$	796	$	(796	)	$	238,000

(1)	Includes amounts for shares issued for Directors’ compensation.
(2)	Cash dividends declared per share for the periods ended June 30, 2011 and December 31, 2010 were $0.675 and $1.305, respectively.
(3)	The shares issued under the Performance Incentive Plan (“PIP”) are net of shares withheld for employee taxes. For the periods ended June 30, 2011 and December 31, 2010 the Company withheld 12,324 and 17,695 shares, respectively, for taxes.
(4)	Tax expense recognized on the prior service cost component of employees benefit plans for the periods ended June 30, 2011 and December 31, 2010 were approximately $3 and $5, respectively.
(5)	Tax expense (benefit) recognized on the net gain (loss) component of employees benefit plans for the periods ended June 30, 2011 and December 31, 2010, were $239 and ($541), respectively.
(6)	Includes 30,078 and 29,596 shares at June 30, 2011 and December 31, 2010, respectively, held in a Rabbi Trust established by the Company relating to the Deferred Compensation Plan.

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

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Notes to Condensed Consolidated Financial Statements (Unaudited)

1. Summary of Accounting Policies

Basis of Presentation

References in this document to the “Company,” “Chesapeake,” “we,” “us” and “our” are intended to mean the Registrant and its subsidiaries, or the Registrant’s subsidiaries, as appropriate in the context of the disclosure.

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and United States of America Generally Accepted Accounting Principles (“GAAP”). In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K filed with the SEC on March 8, 2011. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

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

We have assessed and reported on subsequent events through the date of issuance of these condensed consolidated financial statements.

Reclassifications

We reclassified certain amounts in the condensed consolidated statements of income for the three and six months ended June 30, 2010, and the condensed consolidated statement of cash flows for the six months ended June 30, 2010, to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.

Recent Accounting Amendments Yet to be Adopted by the Company

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.” Amendments in the ASU do not extend the use of fair value accounting, but provide guidance on how it should be applied where its use is already required or permitted by other standards within International Financial Accounting Standards (“IFRS”) or U.S. GAAP. ASU 2011-04 supersedes most of the guidance in Topic 820, although many of the changes are clarifications of existing guidance or wording changes to align with IFRS. Certain amendments in ASU 2011-04 change a particular principle or requirement for measuring fair value or disclosing information about fair value measurements. The amendments in ASU 2011-04 are effective for public entities for interim and annual periods beginning after December 15, 2011, and should be applied prospectively. Early adoption is not permitted for public entities. We expect the adoption of ASU 2011-04 to have no material impact on our financial position and results of operations.

In June 2011, the FASB issued ASU 2011-05, “Presentation of Comprehensive Income.” ASU 2011-05 amends the guidance in Topic 220 “Comprehensive Income,” by eliminating the option to present components of other comprehensive income in the statement of stockholders’ equity. Instead, the new guidance now requires entities to present all non-owner changes in stockholders’ equity either as a single continuous statement of comprehensive income or as two separate but consecutive statements. The components of other comprehensive income (“OCI”) have not changed nor has the guidance on when OCI items are reclassified to net income; however, the amendments require entities to present all reclassification adjustments from OCI to net income on the face of the statement of comprehensive income. Similarly, ASU 2011-05 does not change the guidance to disclose OCI components gross or net of the effect of income taxes, provided that the tax effects are presented on the face of the statement in which OCI is presented, or disclosed in the notes to the financial statements. For public entities, the amendments in ASU 2011-05 are effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2011. The amendments should be applied retrospectively, and early adoption is permitted. We plan on complying with the new OCI presentation at the end of 2011.

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2. Calculation of Earnings Per Share

	Three Months				Six Months
For the Periods Ended June 30,	2011		2010		2011		2010
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	3,520	$	3,340	$	17,267	$	17,314
Weighted average shares outstanding		9,557,707		9,467,222		9,546,606		9,443,708
Basic Earnings Per Share	$	0.37	$	0.35	$	1.81	$	1.83
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	3,520	$	3,340	$	17,267	$	17,314
Effect of 8.25% Convertible debentures		15		19		31		37
Adjusted numerator — Diluted	$	3,535	$	3,359	$	17,298	$	17,351
Reconciliation of Denominator:
Weighted shares outstanding — Basic		9,557,707		9,467,222		9,546,606		9,443,708
Effect of dilutive securities:
Share-based Compensation		20,699		3,347		21,958		19,437
8.25% Convertible debentures		72,481		86,783		73,810		87,525
Adjusted denominator — Diluted		9,650,887		9,557,352		9,642,374		9,550,670
Diluted Earnings Per Share	$	0.37	$	0.35	$	1.79	$	1.82

3. Rates and Other Regulatory Activities

Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective Public Service Commission (“PSC”); Eastern Shore Natural Gas Company (“Eastern Shore”), our natural gas transmission operation, is subject to regulation by the Federal Energy Regulatory Commission (“FERC”); and Peninsula Pipeline Company, Inc. (“Peninsula Pipeline”) is subject to regulation by the Florida Public Service Commission (“Florida PSC”). Chesapeake’s Florida natural gas distribution division and the natural gas and electric distribution operations of Florida Public Utilities Company (“FPU”) continue to be subject to regulation by the Florida PSC as separate entities.

Delaware

Capacity Release: On September 2, 2008, our Delaware division filed with the Delaware Public Service Commission (“Delaware PSC”) its annual Gas Sales Service Rates (“GSR”) Application, seeking approval to change its GSR, effective November 1, 2008. On July 7, 2009, the Delaware PSC granted approval of a settlement agreement presented by the parties in this docket, which included the Delaware PSC, our Delaware division and the Division of the Public Advocate. As part of the settlement agreement, the parties agreed to develop a record in a later proceeding on the price charged by the Delaware division for the temporary release of transmission pipeline capacity to our natural gas marketing subsidiary, Peninsula Energy Services Company, Inc. (“PESCO”). On January 8, 2010, the Hearing Examiner in this proceeding issued a report of Findings and Recommendations in which he recommended, among other things, that the Delaware PSC require the Delaware division to refund to its firm service customers the difference between what the Delaware division would have received had the capacity released to PESCO been priced at the maximum tariff rates under asymmetrical pricing principles and the amount actually received by the Delaware division for capacity released to PESCO. The Hearing Examiner also recommended that the Delaware PSC require us to adhere to asymmetrical pricing principles in all future capacity releases by the Delaware division to PESCO, if any. If the Hearing Examiner’s refund recommendation for past capacity releases were ultimately approved without modification by the Delaware PSC, the Delaware division would have to credit to its firm service customers amounts equal to the maximum tariff rates that the Delaware division pays for long-term capacity, which we estimated to be approximately $700,000, even though the temporary releases were made at lower rates based on competitive bidding procedures required by the FERC’s capacity release rules. On February 18, 2010, we filed exceptions to the Hearing Examiner’s recommendations.

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At the hearing on March 30, 2010, the Delaware PSC agreed with us that the Delaware division had been releasing capacity based on a previous settlement approved by the Delaware PSC and, therefore, did not require the Delaware division to issue any refunds for past capacity releases. The Delaware PSC, however, required the Delaware division to adhere to asymmetrical pricing principles for future capacity releases to PESCO until a more appropriate pricing methodology is developed and approved. The Delaware PSC issued an order on May 18, 2010, elaborating its decisions at the March hearing and directing the parties to reconvene in a separate docket to determine if a pricing methodology other than asymmetrical pricing principles should apply to future capacity releases by the Delaware division to PESCO.

On June 17, 2010, the Division of the Public Advocate filed an appeal with the Delaware Superior Court, asking it to overturn the Delaware PSC’s decision with regard to refunds for past capacity releases. On June 28, 2010, the Delaware division filed a Notice of Cross Appeal with the Delaware Superior Court, asking it to overturn the Delaware PSC’s decision with regard to requiring the Delaware division to adhere to asymmetrical pricing principles for future capacity releases to PESCO. On June 13, 2011, the Delaware Superior Court issued its decision affirming all aspects of the Delaware PSC’s Order of May 18, 2010, which included its decision not to require the Delaware division to issue any refunds for past releases.

On June 29, 2011, the Delaware Attorney General filed an appeal with the Delaware Supreme Court, asking it to review the Delaware Superior Court’s decision affirming the Delaware PSC decision with regard to refunds for past capacity releases. The Delaware Attorney General was substituted in the case for the Division of the Public Advocate in the period between when the former Public Advocate retired and a new Public Advocate was appointed by the Governor. On July 12, 2011, the Delaware division filed a Notice of Cross Appeal with the Delaware Supreme Court, asking it to overturn the Superior Court’s decision with regard to the Delaware PSC’s decision on future capacity releases to PESCO. We have not accrued any contingent liability related to potential refunds for past capacity releases. We anticipate that the Delaware Supreme Court will render a decision sometime in the first half of 2012. In addition, due to the ongoing legal proceedings, the parties have not yet opened a separate docket to determine an alternative pricing methodology for future capacity releases. Since the Delaware PSC’s Order on May 18, 2010, the Delaware division has not released any capacity to PESCO.

Chesapeake’s Delaware division also had developments in the following matters with the Delaware PSC:

On September 1, 2010, the Delaware division filed with the Delaware PSC its annual GSR Application, seeking approval to change its GSR, effective November 1, 2010. On September 21, 2010, the Delaware PSC authorized the Delaware division to implement the GSR charges on November 1, 2010, on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. The Delaware PSC granted approval of the GSR charges at its regularly scheduled meeting on June 7, 2011.

On March 10, 2011, the Delaware division filed with the Delaware PSC an application requesting approval to guarantee certain debt of FPU. Specifically, the Delaware division sought approval to execute a Seventeenth Supplemental Indenture, in which Chesapeake guarantees the payment of certain debt of FPU and FPU is permitted to deliver Chesapeake’s consolidated financial statements in lieu of FPU’s stand-alone financial statements to satisfy certain covenants within the indentures of FPU’s debt. The Delaware PSC granted approval of the guarantee of certain debt of FPU at its regularly scheduled meeting on April 4, 2011.

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Maryland

On December 14, 2010, the Maryland Public Service Commission (“Maryland PSC”) held an evidentiary hearing to determine the reasonableness of the four quarterly gas cost recovery filings submitted by the Maryland division during the 12 months ended September 30, 2010. No issues were raised at the hearing, and on December 20, 2010, the Hearing Examiner in this proceeding issued a proposed Order approving the division’s four quarterly filings. This proposed Order became a final Order of the Maryland PSC on January 20, 2011.

On March 2, 2011, the Maryland division filed with the Maryland PSC an application for the approval of a franchise executed between the Maryland division and the Board of County Commissioners of Cecil County, Maryland. In this franchise agreement, the County granted the Maryland division a 50-year, non-exclusive, franchise to construct and operate natural gas distribution facilities within the present and future jurisdictional boundaries of Cecil County. On April 11, 2011, the Maryland PSC issued an Order approving the franchise between the Maryland division and Cecil County, subject to no adverse comments being received within 30 days after the issuance of the Order. On May 10, 2011, comments opposing the application were filed by Pivotal Utility Holdings, Inc. d/b/a Elkton Gas (“Pivotal”). Pivotal also provides natural gas service to customers in a portion of Cecil County. On June 8, 2011, the Maryland PSC granted the Maryland division the authority to exercise its franchise in a majority of the area requested in the Maryland division’s application. The approval for a small portion of the area within the requested franchise area, which is closest to the area served by Pivotal, has been withheld until an evidentiary hearing is convened. It is anticipated that the Maryland PSC will render a decision on the remaining area in the fourth quarter of 2011 or the first quarter of 2012.

On May 17, 2011, the Maryland division filed with the Maryland PSC an application for the approval of a franchise executed between the Maryland division and the Board of County Commissioners for Worcester County, Maryland. In this franchise agreement, the County granted the Maryland division a 25-year, non-exclusive, franchise to construct and operate natural gas distribution facilities within the present and future jurisdictional boundaries of Worcester County. On June 14, 2011, the Maryland PSC issued an Order approving the franchise between the Maryland division and Worcester County, subject to no adverse comments being received within 20 days after the issuance of the Order. No adverse comments were filed within the comment period and the order became effective on July 5, 2011.

Florida

“Come-Back” Filing: As part of our rate case settlement in Florida in 2010, the Florida PSC required us to submit a “Come-Back” filing, detailing all known benefits, synergies, cost savings and cost increases resulting from the merger with FPU. We submitted this filing on April 29, 2011. We are requesting the recovery, through rates, of approximately $34.2 million in acquisition adjustment (the price paid in excess of the book value) and $2.2 million in merger-related costs. In the past, the Florida PSC has allowed recovery of an acquisition adjustment under certain circumstances to provide an incentive for larger utilities to purchase smaller utilities. The Florida PSC requires a company seeking recovery of the acquisition adjustment and merger-related costs to demonstrate that customers will benefit from the acquisition. They use the following five factors to determine if the customers are benefiting from the transaction: (a) increased quality of service; (b) lower operating costs; (c) increased ability to attract capital for improvements; (d) lower overall cost of capital; and (e) more professional and experienced managerial, financial, technical and operational resources. With respect to lower costs, the Florida PSC effectively requires that the synergies be sufficient to offset the rate impact of the recovery of the acquisition adjustment and merger-related costs. The Florida PSC’s decision on our request for recovery of the acquisition adjustment and merger-related costs is expected in the fourth quarter of 2011.

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If the Florida PSC approves recovery of the acquisition adjustment and merger-related costs, we would be able to classify these amounts as regulatory assets and include them in our investment, or rate base, when determining our Florida natural gas rates. Additionally, we would calculate our rate of return based upon this higher level of investment which effectively enables us to earn a return on this investment. We would also be able to amortize the acquisition adjustment and merger-related costs over 30 and five years, respectively. Amortization expense would be included in the calculation of our rates.

Our earnings may be reduced by as much as $1.6 million annually for the amortization expense (approximately $1.3 million is non-tax-deductible) until 2014 and $1.1 million annually (non-tax deductible) thereafter until 2039. This amortization expense would be a non-cash charge, and the net effect of the recovery would be positive cash flow. Over the long-term, however, the inclusion of the acquisition adjustment and merger-related costs in our rate base and the recovery of these regulatory assets through amortization expense will increase our earnings and cash flows above what we would have otherwise been able to achieve.

If the Florida PSC does not allow recovery of the acquisition adjustment and merger-related costs, there is some likelihood that we would have to reduce rates in the State of Florida, which would adversely affect our future earnings.

We continue to maintain a $750,000 accrual, which was recorded in 2010 based on management’s assessment of FPU’s earnings and regulatory risk to its earnings associated with possible Florida PSC action related to our requested recovery and the matters set forth in this filing.

Marianna Franchise: On July 7, 2009, the City Commission of Marianna, Florida (“Marianna Commission”) adopted an ordinance granting a franchise to FPU effective February 1, 2010 for a period not to exceed 10 years for the operation and distribution and/or sale of electric energy (the “Franchise Agreement”). The Franchise Agreement provides that FPU will develop and implement new time-of-use (“TOU”) and interruptible electric power rates mutually agreeable to FPU and the City of Marianna. The Franchise Agreement further provides for the TOU and interruptible rates to be effective no later than February 17, 2011, and available to all customers within the corporate limits of the City of Marianna. If the rates were not in effect by February 17, 2011, the City of Marianna would have the right to give notice to FPU within 180 days thereafter of its intent to exercise its option to purchase FPU’s property (consisting of the electric distribution assets) within the City of Marianna. Any such purchase would be subject to approval by the Marianna Commission, which would also need to approve the presentation of a referendum to voters in the City of Marianna for the approval of the purchase and the operation by the City of Marianna of an electric distribution facility. If the purchase is approved by the Marianna Commission and by the referendum, the closing of the purchase must occur within 12 months after the referendum is approved. If the City of Marianna elects to purchase the Marianna property, the Franchise Agreement requires the City of Marianna to pay FPU the fair market value for such property as determined by three qualified appraisers. Future financial results would be negatively affected by the loss in earnings generated by FPU from its approximately 3,000 customers in the City under the Franchise Agreement.

In accordance with the terms of the Franchise Agreement, FPU developed reasonable TOU and interruptible rates and on December 14, 2010, FPU filed a petition with the Florida PSC for authority to implement such proposed TOU and interruptible rates on or before February 17, 2011. On February 11, 2011, the Florida PSC issued an Order approving FPU’s petition for authority to implement the proposed TOU and interruptible rates, which became effective on February 8, 2011. The City of Marianna has objected to the proposed rates and has filed a petition protesting the entry of the Florida PSC’s Order. On March 17, 2011, FPU filed a Motion to Dismiss the petition by the City of Marianna and requested oral argument. On June 14, 2011, the Florida PSC granted FPU’s request for oral argument and on July 5, 2011, issued an Order approving FPU’s Motion to Dismiss the protest by the City of Marianna, without prejudice. On July 25, 2011, the City of Marianna filed an amended petition protesting the entry of the Florida PSC’s Order.

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On January 26, 2011, FPU filed a petition with the Florida PSC for approval of an amendment to FPU’s Generation Services Agreement entered into between FPU and Gulf Power Corporation (“Gulf Power”). The amendment provides for a reduction in the capacity demand quantity, which generates the savings necessary to support the TOU and interruptible rates approved by the Florida PSC. The amendment also extends the current agreement by two years, with a new expiration date of December 31, 2019. Pursuant to its Order dated June 21, 2011, the Florida PSC approved the amendment. On July 12, 2011, the City of Marianna filed a protest of this decision and requested a hearing on the amendment.

On April 7, 2011, FPU filed a petition for approval of a mid-course reduction to its Northwest Division fuel rates based on two factors: 1) the previously discussed amendment to the Generation Services Agreement with Gulf Power; and 2) a weather-related increase in sales resulting in an accelerated collection of prior year’s under-recovered costs. Pursuant to its Order dated July 5, 2011, the Florida PSC approved the petition, which is projected to reduce customers’ fuel rates by approximately 10 percent per month.

As disclosed in Note 5, “Other Commitments and Contingencies,” to the unaudited condensed consolidated financial statements, the City of Marianna, on March 2, 2011, filed a complaint against FPU in the Circuit Court of the Fourteenth Judicial Circuit in and for Jackson County, Florida, alleging breaches of the Franchise Agreement by FPU and seeking a declaratory judgment that the City of Marianna has the right to exercise its option to purchase FPU’s property in the City of Marianna in accordance with the terms of the Franchise Agreement. On March 28, 2011, FPU filed its answer to the declaratory action by the City of Marianna, in which it denied the material allegation by the City of Marianna and asserted several affirmative defenses.

Eastern Shore

The following are regulatory activities involving FERC Orders applicable to Eastern Shore and the expansions of Eastern Shore’s transmission system:

Energylink Expansion Project: In 2006, Eastern Shore proposed to develop, construct and operate approximately 75 miles of new pipeline facilities from the existing Cove Point Liquefied Natural Gas terminal in Calvert County, Maryland, crossing under the Chesapeake Bay into Dorchester and Caroline Counties, Maryland, to points on the Delmarva Peninsula, where such facilities would interconnect with Eastern Shore’s existing facilities in Sussex County, Delaware. In April 2009, Eastern Shore terminated this project based on increased construction costs over its original projection. As approved by the FERC, Eastern Shore initiated billing to recover approximately $3.2 million of costs incurred in connection with this project and the related cost of capital over a period of 20 years in accordance with the terms of the precedent agreements executed with the two participating customers. One of the two participating customers is Chesapeake, through its Delaware and Maryland divisions. During 2010, Eastern Shore and the participating customers negotiated to reduce the recovery period of this cost from 20 years to five years. On January 27, 2011, Eastern Shore filed with the FERC the request to amend the cost recovery period, which was approved by the FERC on February 14, 2011. Eastern Shore revised its billing to reflect the five-year surcharge effective March 1, 2011.

Rate Case Filing: On December 30, 2010, Eastern Shore filed with the FERC a base rate proceeding in compliance with the terms of the settlement in its prior base rate proceeding. The rate filing reflects increases in operating and maintenance expenses, depreciation expense, and a return on existing and new gas plant facilities expected to be placed into service before June 30, 2011. The FERC issued a notice of the filing on January 3, 2011. Protests were received from several interested parties, and other parties intervened in the proceeding. On January 31, 2011, the FERC issued its Order accepting the filing and suspending its effectiveness for the full five-month period permitted under the Natural Gas Act. The discovery process commenced on February 22, 2011, and FERC Staff performed an on-site audit on March 16-17, 2011. Settlement conferences involving Eastern Shore, FERC Staff and other interested parties were held beginning in April and have extended through early August 2011. Eastern Shore expects the base rate proceeding to be resolved in 2011.

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Mainline Extension Project: On April 1, 2011, Eastern Shore filed a notice of its intent under its blanket certificate to construct, own and operate new mainline facilities to deliver additional firm service of 3,405 Dekatherms per day (“Dts/d”) of natural gas to an existing industrial customer. The FERC published notice of this filing on April 7, 2011. The 60-day comment period subsequent to the FERC notice expired on June 6, 2011, and the requested authorization became effective on that date. Construction is expected to commence during the third quarter of 2011.

On April 28, 2011, Eastern Shore filed a notice of its intent under its blanket certificate to construct, own and operate new mainline facilities to deliver additional firm service of 6,250 Dts/d of natural gas to Chesapeake’s Delaware and Maryland divisions and Eastern Shore Gas, an unaffiliated provider of piped propane service in Maryland. The FERC published notice of this filing on May 12, 2011 and one of Eastern Shore’s customers filed a conditional protest with the FERC, which it withdrew on July 29, 2011. Upon withdrawal of the protest, the requested authorization became effective.

Also on April 28, 2011, Eastern Shore filed a notice of its intent under its blanket certificate to construct, own and operate new mainline facilities to deliver additional firm service of 4,070 Dts/d of natural gas to Chesapeake’s Maryland division to provide new natural gas service in Cecil County, Maryland. The FERC published notice of this filing on May 12, 2011 and one of Eastern Shore’s customers filed a conditional protest with the FERC, which it withdrew on July 29, 2011. Upon withdrawal of the protest, the requested authorization became effective.

Eastern Shore also had developments in the following FERC matters:

On March 7, 2011, Eastern Shore filed certain tariff sheets to amend the creditworthiness provisions contained in its FERC Gas Tariff. On April 6, 2011, the FERC issued an Order accepting and suspending Eastern Shore’s filed tariff revisions for an effective date of April 1, 2011, subject to Eastern Shore submitting certain clarifications with regard to several proposed revisions.

On April 18, 2011, Eastern Shore submitted its annual Interruptible Revenue Sharing Report to the FERC. Eastern Shore reported in this filing that its interruptible revenue did not exceed its annual threshold amount, which would trigger sharing of excess interruptible revenues with its firm service customers. Consequently, Eastern Shore is not required to refund to its firm customers any portion of its interruptible revenue received for the period April 2010 through March 2011.

On June 24, 2011, Eastern Shore filed certain tariff sheets to amend the General Terms and Conditions and the Firm Transportation Service Agreement contained in its FERC Gas Tariff to allow for specification of minimum delivery pressures and maximum hourly quantity. The FERC published the notice of this filing on June 27, 2011, and no protests or adverse comments opposing this filing were submitted. On July 15, 2011, the FERC issued a Letter Order, accepting the tariff revisions as proposed, effective July 24, 2011.

4. Environmental Commitments and Contingencies

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

We have participated in the investigation, assessment or remediation, and have certain exposures at six former Manufactured Gas Plant (“MGP”) sites. Those sites are located in Salisbury, Maryland, and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the Maryland Department of the Environment (“MDE”) regarding a seventh former MGP site located in Cambridge, Maryland.

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As of June 30, 2011, we had approximately $11.2 million in environmental liabilities related to all of FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites, representing our estimate of the future costs associated with those sites. FPU has approval to recover up to $14.0 million of its environmental costs related to all of its MGP sites from insurance and from customers through rates. Approximately $8.1 million of FPU’s expected environmental costs have been recovered from insurance and customers through rates as of June 30, 2011. We also had approximately $5.9 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

West Palm Beach, Florida

Remedial options are being evaluated to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West Palm Beach, Florida, where FPU previously operated an MGP. Pursuant to a Consent Order between FPU and the Florida Department of Environmental Protection (“FDEP”), effective April 8, 1991, FPU is required to complete the delineation of soil and groundwater impacts at the site, and implement an effective remedy.

On June 30, 2008, FPU transmitted to the FDEP a revised feasibility study, evaluating appropriate remedies for the site. This revised feasibility study evaluated a wide range of remedial alternatives based on criteria provided by applicable laws and regulations. On April 30, 2009, the FDEP issued a remedial action order, which it subsequently withdrew. In response to the Order and as a condition to its withdrawal, FPU committed to perform additional field work in 2009 and complete an additional engineering evaluation of certain remedial alternatives. The scope of this work has increased in response to FDEP’s requests for additional information.

FPU performed additional field work in August 2010, which included the installation of additional groundwater monitoring wells and performance of a comprehensive groundwater sampling event. FPU also performed vapor intrusion sampling in October 2010. The results of the field work were submitted to FDEP for their review and comment in October 2010. On November 4, 2010, FDEP issued its comments on the feasibility study and the proposed remedy.

On November 16, 2010, FPU presented to FDEP a new remedial action plan for the site, and FDEP agreed with FPU’s proposal to implement a phased approach to remediation. On December 22, 2010, FPU submitted to FDEP an interim Remedial Action Plan (“RAP”) to remediate the east parcel of the site, which FDEP conditionally approved on February 4, 2011. Subsequent modifications to the interim RAP, dated March 12, 2011 and April 18, 2011, were submitted to address potential concerns raised by FDEP. An Approval Order for the interim RAP was issued by FDEP on May 2, 2011, and subsequently modified by FDEP on May 18, 2011.

FPU is currently implementing the interim RAP for the east parcel of the West Palm Beach site, including the incorporation of FDEP’s conditions for approval. The operations on the east parcel have been relocated, and the structures removed. New monitoring wells and Air Sparging and Soil-Vapor Extraction (“AS/SVE”) test wells were installed on the east parcel in May of 2011. The initial round of SVE and sparging pilot testing was completed in July of 2011 and the results of the testing are currently being analyzed.

Estimated costs of remediation for the West Palm Beach site range from approximately $4.9 million to $13.1 million. This estimate does not include any costs associated with relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties.

We continue to expect that all costs related to these activities will be recoverable from customers through rates.

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Sanford, Florida

FPU is the current owner of property in Sanford, Florida, which was a former MGP site that was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of the MGP. In late September 2006, the United States Environmental Protection Agency (“EPA”) sent a Special Notice Letter, notifying FPU, and the other responsible parties at the site (Florida Power Corporation, Florida Power & Light Company, Atlanta Gas Light Company, and the city of Sanford, Florida, collectively with FPU, “the Sanford Group”), of EPA’s selection of a final remedy for OU1 (soils), OU2 (groundwater), and OU3 (sediments) for the site. The EPA projected the total estimated remediation costs for this site to be approximately $12.9 million.

In January 2007, FPU and other members of the Sanford Group signed a Third Participation Agreement, which provides for funding the final remedy approved by EPA for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13 million, or $650,000. As of June 30, 2011, FPU has paid $650,000 to the Sanford Group escrow account for its share of the funding requirements.

The Sanford Group, EPA and the U.S. Department of Justice agreed to a Consent Decree in March 2008, which was entered by the Federal Court in Orlando, Florida on January 15, 2009. The Consent Decree obligates the Sanford Group to implement the remedy approved by EPA for the site. The total cost of the final remedy is now estimated at approximately $18 million. FPU has advised the other members of the Sanford Group that it is unwilling at this time to agree to pay any sum in excess of the $650,000 committed by FPU in the Third Participation Agreement.

Several members of the Sanford Group have concluded negotiations with two adjacent property owners to resolve damages that the property owners allege they have and will incur as a result of the implementation of the EPA-approved remediation. In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third-party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third-party claims.

As of June 30, 2011, FPU’s remaining share of remediation expenses, including attorneys’ fees and costs, is estimated to be $20,000. However, we are unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept FPU’s asserted defense to liability for costs exceeding $13.0 million to implement the final remedy for this site or will pursue a claim against FPU for a sum in excess of the $650,000 that FPU has paid under the Third Participation Agreement. No such claims have been made as of June 30, 2011.

Key West, Florida

FPU formerly owned and operated an MGP in Key West, Florida. Field investigations performed in the 1990s identified limited environmental impacts at the site, which is currently owned by an unrelated third party. In September 2010, FDEP issued a Preliminary Contamination Assessment Report, for additional soil and groundwater investigation work that was undertaken by FDEP in November 2009 and January 2010, after 17 years of regulatory inactivity. Because FDEP observed that some soil and groundwater standards were exceeded, FDEP is requesting implementation of additional fieldwork which FDEP believes is warranted for the site.

FPU and the current site owner have had several discussions regarding the approach to be taken with FDEP and the proposed scope of work. Representatives of FPU, FDEP and the current site owner participated in a teleconference on July 7, 2011. During that call, the scope of work was tentatively agreed upon, and FDEP agreed to proceed without using a consent order. FPU and the current site owner will submit a work plan and schedule to FDEP in August of 2011. Total potential costs for investigation and remediation are projected to be $153,000.

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Pensacola, Florida

FPU formerly owned and operated an MGP in Pensacola, Florida, which was subsequently owned by Gulf Power. Portions of the site are now owned by the City of Pensacola and the Florida Department of Transportation (“FDOT”). In October 2009, FDEP informed Gulf Power that FDEP would approve a conditional No Further Action (“NFA”) determination for the site, which must include a requirement for institutional and engineering controls. On November 9, 2010, an NFA Proposal was submitted to FDEP, along with a draft restrictive covenant for that portion of the property currently owned by FDOT. FPU, FDOT and the City of Pensacola are working together to obtain a restrictive covenant that is acceptable to FDEP to complete closure of the site, and it is anticipated that no further monitoring will be required on the site. FPU’s total remaining consulting and remediation costs for this site are projected to be $5,000.

In addition, we had $284,000 in environmental liabilities at June 30, 2011, related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of future costs associated with these sites. As of June 30, 2011, we had approximately $1.2 million in regulatory and other assets for future recovery through rates. The following discussion provides details on MGP sites for Chesapeake’s Maryland and Florida divisions:

Salisbury, Maryland

We have substantially completed remediation of a site in Salisbury, Maryland, where it was determined that a former MGP caused localized ground-water contamination. During 1996, we completed construction of an AS/SVE system and began remediation procedures. We have reported 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, which is being maintained for periodic product monitoring and recovery.

Through June 30, 2011, we have incurred and paid approximately $2.9 million for remedial actions and environmental studies related to this site. We have recovered approximately $2.3 million through insurance proceeds or in rates, and $609,000 is expected to be recovered through future rates.

Winter Haven, Florida

The Winter Haven site is located on the eastern shoreline of Lake Shipp, in Winter Haven, Florida. Pursuant to a Consent Order entered into with the FDEP, we are obligated to assess and remediate environmental impacts at this former MGP site. In 2001, FDEP approved a RAP requiring construction and operation of a Bio-Sparging and Soil/Vapor Extraction (“BS/SVE”) treatment system to address soil and groundwater impacts at a portion of the site. The BS/SVE treatment system has been in operation since October 2002. Modifications and upgrades to the BS/SVE treatment system were completed in October 2009. The Seventeenth Semi-Annual RAP Implementation Status Report was submitted to FDEP in June 2011. The groundwater sampling results through June 2011 show a continuing reduction in contaminant concentrations and indicate that the recent treatment system modifications and upgrades have had a beneficial impact on the rate of reduction. At present, we predict that remedial action objectives could be met in approximately two to three years for the area being treated by the BS/SVE treatment system. The total expected cost of operating and monitoring the system is approximately $46,000.

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The BS/SVE treatment system at the Winter Haven site does not address impacted soils in the southwest corner of the site. On April 16, 2010, a soil excavation interim RAP describing the proposed excavation of approximately 4,000 cubic yards of impacted soils from the southwest corner of the site was submitted to FDEP for review. On June 24, 2010, FDEP provided comments on the soil excavation interim RAP by letter, to which we responded, and a subsequent conditional approval letter was issued by FDEP on August 27, 2010. The cost to implement this excavation plan has been estimated at $250,000; however, this estimate does not include costs associated with dewatering or shoreline stabilization, which would be required to complete the excavation. Because the costs associated with shoreline stabilization and dewatering (including treatment and discharge of the pumped water) are likely to be substantial, alternatives to this excavation plan are being evaluated. One alternative currently being evaluated involves sparging into the southwest portion of the property to treat soils rather than excavating the soils.

Two new sparge points were installed in the southwest portion of the property in February of 2011. Sparging into these points has been initiated and operational and monitoring data over the next few quarters should provide the information needed to make this evaluation.

FDEP has indicated that we may be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the site. Based on studies performed to date, we object to FDEP’s suggestion that the sediments have been adversely impacted by the former operations of the MGP. Our early estimates indicate that some of the corrective measures discussed by FDEP could cost as much as $1.0 million. We believe that corrective measures for the sediments are not warranted and intend to oppose any requirement that we undertake corrective measures in the offshore sediments. We have not recorded a liability for sediment remediation, as the final resolution of this matter cannot be predicted at this time.

Through June 30, 2011, we have incurred and paid approximately $1.7 million for remedial activities at this site, and we have estimated and accrued for additional future costs of $284,000. We have recovered through rates $1.4 million of the costs to remediate the Winter Haven site and continue to expect that the remaining $542,000, which is included in regulatory assets, will be recoverable from customers through our approved rates.

Other

We are in discussions with the MDE regarding a former MGP site located in Cambridge, Maryland. The outcome of this matter cannot be determined at this time; therefore, we have not recorded an environmental liability for this location.

5. Other Commitments and Contingencies

Litigation

In May 2010, an FPU propane customer filed a class action complaint against FPU in Palm Beach County, Florida, alleging, among other things, that FPU acted in a deceptive and unfair manner related to a particular charge by FPU on its bills to propane customers and the description of such charge. The suit sought to certify a class comprised of FPU propane customers to whom such charge was assessed since May 2006 and requested damages and statutory remedies based on the amounts paid by FPU customers for such charge. FPU vigorously denied any wrongdoing and maintained that the particular charge at issue is customary, proper and fair. Without admitting any wrongdoing, validity of the claims or a properly certifiable class for the complaint, FPU entered into a settlement agreement with the plaintiff in September 2010 to avoid the burden and expenses of continued litigation. The court approved the final settlement agreement, and the judgment became final on March 13, 2011. In 2010, we recorded $1.2 million of the total estimated costs related to this litigation. Pursuant to the final settlement agreement, the distribution to the class was made by May 13, 2011.

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On March 2, 2011, the City of Marianna, Florida filed a complaint against FPU in the Circuit Court of the Fourteenth Judicial Circuit in and for Jackson County, Florida, alleging that FPU breached its obligations under its franchise with the City of Marianna to provide electric service to customers within and without the City of Marianna by failing: (i) to develop and implement TOU and interruptible rates that were mutually agreed to by the City of Marianna and FPU; (ii) to have such mutually agreed upon rates in effect by February 17, 2011; and (iii) to have such rates available to all of FPU’s customers located within and without the corporate limits of the City of Marianna. The City of Marianna is seeking a declaratory judgment allowing it to exercise its option under the Franchise Agreement to purchase FPU’s property (consisting of the electric distribution assets) within the City of Marianna. Any such purchase would be subject to approval by the Marianna Commission, which would also need to approve the presentation of a referendum to voters in the City of Marianna related to the purchase and the operation by the City of Marianna of an electric distribution facility. If the purchase is approved by the Marianna Commission and the referendum is approved by the voters, the closing of the purchase must occur within 12 months after the referendum is approved. On March 28, 2011, FPU filed its answer to the declaratory action by the City of Marianna, in which it denied the material allegations by the City of Marianna and asserted several affirmative defenses. FPU intends to vigorously contest this litigation and intends to oppose the adoption of any proposed referendum to approve the purchase of the FPU property in the City of Marianna.

Natural Gas, Electric and Propane Supply

Our natural gas, electric and propane distribution operations have entered into contractual commitments to purchase gas, electricity and propane from various suppliers. The contracts have various expiration dates. We have a contract with an energy marketing and risk management company to manage a portion of our natural gas transportation and storage capacity. This contract expires on March 31, 2012.

Chesapeake’s Florida natural gas distribution division has firm transportation service contracts with Florida Gas Transmission Company (“FGT”) and Gulfstream Natural Gas System, LLC (“Gulfstream”). Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties, including PESCO. Under the terms of these capacity release agreements, Chesapeake is contingently liable to FGT and Gulfstream, should any party that acquired the capacity through release fail to pay for the service.

In May 2011, PESCO renewed contracts to purchase natural gas from various suppliers. These contracts expire in May 2012.

As discussed in Note 3 “Rates and Other Regulatory Activities,” on January 25, 2011, FPU entered into an amendment to its Generation Services Agreement with Gulf Power, which reduces the capacity demand quantity and provides the savings necessary to support the TOU and interruptible rates for the customers in the City of Marianna, both of which were approved by the Florida PSC. The amendment also extends the current agreement by two years, with a new expiration date of December 31, 2019.

FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEA requires FPU to comply with the following ratios based on the results of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 times, and (b) fixed charge coverage ratio greater than 1.5 times. If either ratio is not met by FPU, it has 30 days to cure the default or provide an irrevocable letter of credit if the default is not cured. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken or proposed to be taken to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could result in FPU providing an irrevocable letter of credit. As of June 30, 2011, FPU was in compliance with all of the requirements of its fuel supply contracts.

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Corporate Guarantees

The Board of Directors has previously authorized the Company to issue up to $35 million of corporate guarantees or letters of credit on behalf of our subsidiaries. On March 2, 2011, the Board increased this limit from $35 million to $45 million.

We have issued corporate guarantees to certain vendors of our subsidiaries, the largest portion of which are for our propane wholesale marketing subsidiary and our natural gas marketing subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in our financial statements when incurred. The aggregate amount guaranteed at June 30, 2011 was $25.6 million, with the guarantees expiring on various dates through December 2011.

Chesapeake guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under the guarantee is the outstanding principal and accrued interest balances. The outstanding principal balances of FPU’s first mortgage bonds approximate their carrying values (see Note 12, “Long-Term Debt,” to the unaudited condensed consolidated financial statements for further details).

In addition to the corporate guarantees, we have issued a letter of credit to our primary insurance company for $441,000, which expires on December 2, 2011. The letter of credit is provided as security to satisfy the deductibles under our various outstanding insurance policies. As a result of a change in our primary insurance company in 2010, we renewed the letter of credit for $725,000 to our former primary insurance company, which will expire on June 1, 2012. There have been no draws on these letters of credit as of June 30, 2011. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that the letters of credit will be renewed to the extent necessary in the future.

We provided a letter of credit for $2.5 million to Texas Eastern Transmission, LP (“TETLP”) related to the Precedent Agreement, which is further described below.

Agreements for Access to New Natural Gas Supplies

On April 8, 2010, our Delaware and Maryland divisions entered into a Precedent Agreement with TETLP to secure firm transportation service from TETLP in conjunction with its new expansion project, which is expected to expand TETLP’s mainline system by up to 190,000 Dts/d. The Precedent Agreement provides that, upon satisfaction of certain conditions, the parties will execute two firm transportation service contracts, one for our Delaware division and one for our Maryland division, for 34,100 and 15,900 Dts/d, respectively, including the additional volume subscribed in a subsequent agreement, to be effective on the service commencement date of the project, which is currently projected to occur in November 2012. Each firm transportation service contract shall, among other things, provide for: (a) the maximum daily quantity of Dts/d described above; (b) a term of 15 years; (c) a receipt point at Clarington, Ohio; (d) a delivery point at Honey Brook, Pennsylvania; and (e) certain credit standards and requirements for security. Commencement of service and TETLP’s and our rights and obligations under the two firm transportation service contracts are subject to satisfaction of various conditions specified in the Precedent Agreement.

Our Delmarva natural gas supplies are currently received primarily from the Gulf of Mexico natural gas production region and are transported through three interstate upstream pipelines, two of which interconnect directly with Eastern Shore’s transmission system. The new firm transportation service contracts between our Delaware and Maryland divisions and TETLP will provide us with an additional direct interconnection with Eastern Shore’s transmission system and access to new sources of natural gas supplies from other natural gas production regions, including the Appalachian production region, thereby providing increased reliability and diversity of supply. They will also provide our Delaware and Maryland divisions with additional upstream transportation capacity to meet current customer demands and to plan for sustainable growth.

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The Precedent Agreement provides that the parties shall promptly meet and work in good faith to negotiate a mutually acceptable reservation rate. Failure to agree upon a mutually acceptable reservation rate would have enabled either party to terminate the Precedent Agreement, and would have subjected us to reimburse TETLP for certain pre-construction costs; however, on July 2, 2010, our Delaware and Maryland divisions executed the required reservation rate agreements with TETLP.

The Precedent Agreement requires us to reimburse TETLP for our proportionate share of TETLP’s pre-service costs incurred to date, if we terminate the Precedent Agreement, are unwilling or unable to perform our material duties and obligations thereunder, or take certain other actions whereby TETLP is unable to obtain the authorizations and exemptions required for this project. If such termination were to occur, we estimate that our proportionate share of TETLP’s pre-service costs could be approximately $8.6 million as of June 30, 2011. If we were to terminate the Precedent Agreement after TETLP completed its construction of all facilities, which is expected to be in the fourth quarter of 2011, our proportionate share could be as much as approximately $50 million. The actual amount of our proportionate share of such costs could differ significantly and would ultimately be based on the level of pre-service costs at the time of any potential termination. As our Delaware and Maryland divisions have now executed the required reservation rate agreements with TETLP, we believe that the likelihood of terminating the Precedent Agreement and having to reimburse TETLP for our proportionate share of TETLP’s pre-service costs is remote.

As previously mentioned, we have provided a letter of credit for $2.5 million, which is the maximum amount required under the Precedent Agreement with TETLP.

On March 17, 2010, our Delaware and Maryland divisions entered into a separate Precedent Agreement with Eastern Shore to extend its mainline by eight miles to interconnect with TETLP at Honey Brook, Pennsylvania. As discussed in Note 3, “Rates and Other Regulatory Activities,” to the unaudited condensed consolidated financial statements, Eastern Shore completed the extension project in December 2010 and commenced the service in January 2011. The rate for the transportation service on this extension is Eastern Shore’s current tariff rate for service in that area.

TETLP is proceeding with obtaining the necessary approvals, authorizations or exemptions for construction and operation of its portion of the project, including, but not limited to, approval by the FERC. TETLP is expecting the FERC approval by the end of 2011. Our Delaware and Maryland divisions require no regulatory approvals or exemptions to receive transmission service from TETLP or Eastern Shore.

As the Eastern Shore and TETLP firm transportation services commence, our Delaware and Maryland divisions incur costs for those services based on the agreed and FERC-approved reservation rates, which will become an integral component of the costs associated with providing natural gas supplies to our Delaware and Maryland divisions and will be included in the annual GSR filings for each of our respective divisions.

Non-income-based Taxes

From time to time, we are subject to various audits and reviews by the states and other regulatory authorities regarding non-income-based taxes. We are currently undergoing a sales tax audit in Florida. As of June 30, 2011, we maintained an accrual of $698,000 related to additional sales taxes and gross receipts taxes owed to various states, all of which were recorded in 2010.

Other Contingency

As of June 30, 2011, we maintained a $750,000 accrual, which was recorded in 2010 based on management’s assessment of FPU’s earnings and regulatory risk to its earnings associated with possible Florida PSC action related to our requested recovery and the matters set forth in the “Come-Back” filing (See Note 3, “Rates and Other Regulatory Activities,” to the unaudited condensed consolidated financial statements for further discussion).

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6. Segment Information

We use the management approach to identify operating segments. We organize our business around differences in regulatory environment and/or products or services, and the operating results of each segment are regularly reviewed by the chief operating decision maker (our Chief Executive Officer) in order to make decisions about resources and to assess performance. The segments are evaluated based on their pre-tax operating income. Our operations comprise three operating segments:

• Regulated Energy. The regulated energy segment includes natural gas distribution, electric distribution and natural gas transmission operations. All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of Eastern Shore.

• Unregulated Energy. The unregulated energy segment includes natural gas marketing, propane distribution and propane wholesale marketing operations, which are unregulated as to their rates and charges for their services.

• Other. The “other” segment consists primarily of the advanced information services operation, unregulated subsidiaries that own real estate leased to Chesapeake and certain corporate costs not allocated to other operations.

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The following table presents information about our reportable segments.

	Three Months Ended						Six Months Ended
For the Perionds Ended June 30,	2011			2010			2011			2010
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	54,011		$	52,543		$	138,695		$	143,845
Unregulated Energy		29,692			24,494			88,442			83,521
Other		3,128			3,024			6,292			5,955
Total operating revenues, unaffiliated customers	$	86,831		$	80,061		$	233,429		$	233,321
Intersegment Revenues (1)
Regulated Energy	$	316		$	197		$	634		$	522
Unregulated Energy		—			121			—			364
Other		195			259			389			447
Total intersegment revenues	$	511		$	577		$	1,023		$	1,333
Operating Income
Regulated Energy	$	7,863		$	8,308		$	24,171		$	25,824
Unregulated Energy		4			(791	)		8,518			6,969
Other and eliminations		(91	)		244			(74	)		366
Total operating income		7,776			7,761			32,615			33,159
Other income, net of other expenses		27			(11	)		50			103
Interest		2,114			2,305			4,265			4,667
Income taxes		2,169			2,105			11,133			11,281
Net income	$	3,520		$	3,340		$	17,267		$	17,314

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

	June 30,		December 31,
(in thousands)	2011		2010
Identifiable Assets
Regulated energy	$	517,737	$	520,192
Unregulated energy		111,357		113,039
Other		31,395		37,762
Total identifiable assets	$	660,489	$	670,993

Our operations are almost entirely domestic. Our advanced information services subsidiary, BravePoint, has infrequent transactions in foreign countries, primarily Canada, which 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 our pension and post-retirement benefits plans for the three and six months ended June 30, 2011 and 2010 are set forth in the following table:

																	Chesapeake
	Chesapeake						FPU						Chesapeake				Postretirement				FPU
	Pension Plan						Pension Plan						SERP				Plan				Medical Plan
For the Three Months Ended June 30,	2011			2010			2011			2010			2011		2010		2011		2010		2011		2010
(in thousands)
Service Cost	$	—		$	—		$	—		$	—		$	—	$	—	$	—	$	—	$	27	$	27
Interest Cost		130			144			672			637			27		34		15		31		39		34
Expected return on plan assets		(101	)		(106	)		(684	)		(619	)		—		—		—		—		—		—
Amortization of prior service cost		(2	)		(2	)		—			—			5		5		—		—		—		—
Amortization of net loss		39			39			—			—			9		14		—		14		5		—
Net periodic cost (benefit)		66			75			(12	)		18			41		53		15		45		71		61
Amortization of pre-merger regulatory asset		—			—			191			190			—		—		—		—		2		2
Total periodic cost	$	66		$	75		$	179		$	208		$	41	$	53	$	15	$	45	$	73	$	63
																	Chesapeake
	Chesapeake						FPU						Chesapeake				Postretirement				FPU
	Pension Plan						Pension Plan						SERP				Plan				Medical Plan
For the Six Months Ended June 30,	2011			2010			2011			2010			2011		2010		2011		2010		2011		2010
(in thousands)
Service Cost	$	—		$	—		$	—		$	—		$	—	$	—	$	—	$	—	$	53	$	55
Interest Cost		260			289			1,343			1,275			54		68		30		61		78		68
Expected return on plan assets		(202	)		(212	)		(1,368	)		(1,238	)		—		—		—		—		—		—
Amortization of prior service cost		(3	)		(3	)		—			—			10		10		—		—		—		—
Amortization of net loss		78			78			—			—			19		30		—		29		10		—
Net periodic cost (benefit)		133			152			(25	)		37			83		108		30		90		141		123
Settlement expense		217			—			—			—			—		—		—		—		—		—
Amortization of pre-merger regulatory asset		—			—			381			507			—		—		—		—		4		5
Total periodic cost	$	350		$	152		$	356		$	544		$	83	$	108	$	30	$	90	$	145	$	128

We expect to record pension and postretirement benefit costs of approximately $1.9 million for 2011. Included in that amount is a pension settlement expense of $217,000 recorded during the first six months of 2011 related to a lump-sum pension distribution of $844,000 from the Chesapeake Pension Plan in January 2011 and $219,000 of settlement expense in July 2011 related to a lump-sum distribution from the Chesapeake SERP. Also included in that amount is $769,000 related to continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU’s regulated energy operations of the changes in funded status that occurred but were not recognized as part of net periodic benefit costs prior to the merger. This was deferred as a regulatory asset by FPU prior to the merger to be recovered through rates pursuant to a previous order by the Florida PSC. The unamortized balance of this regulatory asset was $6.3 million and $6.7 million at June 30, 2011 and December 31, 2010, respectively.

During the six months ended June 30, 2011, we contributed $68,000 to the Chesapeake pension plan. We also contributed $292,000 and $555,000 to the FPU pension plan during the three and six months ended June 30, 2011, respectively. We expect to contribute $955,000 and $1.3 million to the Chesapeake and FPU pension plans, respectively, during the year 2011.

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The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake SERP for the three and six months ended June 30, 2011, were $22,000 and $45,000, respectively; for the year 2011, such benefits paid are expected to be approximately $853,000, which includes the expected lump-sum distribution of $765,000 as mentioned above. Cash benefits paid for the Chesapeake Postretirement Plan, primarily for medical claims for the three and six months ended June 30, 2011, totaled $22,000 and $47,000, respectively; for the year 2011, we have estimated that approximately $96,000 will be paid for such benefits. Cash benefits paid for the FPU Medical Plan, primarily for medical claims for the three and six months ended June 30, 2011, totaled $24,000 and $35,000, respectively; for the year 2011, we have estimated that approximately $158,000 will be paid for such benefits.

In connection with the lump-sum pension distribution from the Chesapeake Pension Plan in January 2011 and the Chesapeake SERP in July 2011, and related settlement accounting, we re-measured the assets and obligations of the Chesapeake Pension Plan. The assumptions used for the discount rate to calculate the benefit obligation remained unchanged at five percent. The average expected return on plan assets also did not change and remained at six percent.

8. Investments

The investment balance at June 30, 2011, represents: (a) a Rabbi Trust associated with our Supplemental Executive Retirement Savings Plan, (b) a Rabbi Trust related to a stay bonus agreement with a former executive, and (c) investments in equity securities. We classify these investments as trading securities and report them at their fair value. Any unrealized gains and losses, net of other expenses, are included in other income in the condensed consolidated statements of income. We also have recorded an associated liability that is adjusted each month for the gains and losses incurred by the Rabbi Trusts. At June 30, 2011 and December 31, 2010, total investments had a fair value of $4.1 million and $4.0 million, respectively.

9. Share-Based Compensation

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

The table below presents the amounts included in net income related to share-based compensation expense for the awards granted under the DSCP and the PIP for the three and six months ended June 30, 2011 and 2010:

	Three Months Ended				Six Months Ended
For the Periods Ended June 30,	2011		2010		2011		2010
(in thousands)
Directors Stock Compensation Plan	$	102	$	71	$	185	$	135
Performance Incentive Plan		274		208		520		477
Total compensation expense		376		279		705		612
Less: tax benefit		151		112		283		245
Share-Based Compensation amounts included in net income	$	225	$	167	$	422	$	367

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Directors Stock Compensation Plan

Shares granted under the DSCP are issued in advance of the directors’ service periods and are fully vested as of the date of the grant. We record a prepaid expense of the shares issued and amortize the expense equally over a service period of one year. In May 2011, each of our non-employee directors received an annual retainer of 900 shares of common stock under the DSCP. A summary of stock activity under the DSCP during the six months ended June 30, 2011 is presented below:

	Number of		Weighted Average
	Shares		Grant Date Fair Value
Outstanding — December 31, 2010		—		—
Granted(1)		11,104	$	41.03
Vested		11,104	$	41.03
Forfeited		—		—
Outstanding — June 30, 2011		—		—

⁽¹⁾ In January 2011, our former Chief Executive Officer John Schimkaitis, retired from the Company and was awarded 304 shares of common stock for the prorated portion of his service period as he began his service as a non-executive board member.

At June 30, 2011, there was $369,000 of unrecognized compensation expense related to the DSCP awards. This expense is expected to be recognized over the remaining directors’ service periods ending as of the 2012 Annual Meeting.

Performance Incentive Plan

The table below presents the summary of the stock activity for the PIP for the six months ended June 30, 2011:

			Weighted Average
	Number of Shares		Fair Value
Outstanding — December 31, 2010		101,150	$	28.78
Granted		41,664		40.16
Vested		31,400		27.63
Forfeited		24,000		29.31
Expired		—		—
Outstanding — June 30, 2011		87,414	$	34.47

In January 2011, the Board of Directors granted awards under the PIP for 41,664 shares. The shares granted in January 2011 are multi-year awards, of which 10,500 shares will vest at the end of the two-year service period, or December 31, 2012. The remaining 31,164 shares will vest at the end of the three-year service period, or December 31, 2013. These awards are earned based upon the successful achievement of long-term goals, growth and financial results, which comprised both market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the date of the grant. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each market-based award granted.

In conjunction with his retirement, our former Chief Executive Officer forfeited 24,000 shares, which represents the shares awarded under the PIP in January 2009 for the performance period ending December 31, 2011 and in January 2010 for the performance period ending December 31, 2012, that had not vested.

At June 30, 2011, the aggregate intrinsic value of the PIP awards was $1.9 million.

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10. Derivative Instruments

We use derivative and non-derivative contracts to engage in trading activities and manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane. Our natural gas, electric and propane distribution operations have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to their customers. Purchases under these contracts either do not meet the definition of derivatives or are considered “normal purchases and sales” and are accounted for on an accrual basis. Our propane distribution operation may also enter into fair value hedges of its inventory in order to mitigate the impact of wholesale price fluctuations. As of June 30, 2011, our natural gas, electric and propane distribution operations did not have any outstanding derivative contracts.

Xeron, our propane wholesale and marketing subsidiary, engages in trading activities using forward and futures contracts. These contracts are considered derivatives and have been accounted for using the mark-to-market method of accounting. Under the mark-to-market method of accounting, the trading contracts are recorded at fair value, and the changes in fair value of those contracts are recognized as unrealized gains or losses in the statement of income in the period of change. As of June 30, 2011, we had the following outstanding trading contracts which we accounted for as derivatives:

	Quantity in		Estimated Market	Weighted Average
At June 30, 2011	Gallons		Prices	Contract Prices
Forward Contracts
Sale		9,240,000	$1.3900 – $1.5700	$	1.5005
Purchase		8,106,000	$1.3344 – $1.5850	$	1.4878

Estimated market prices and weighted average contract prices are in dollars per gallon.

All contracts expire during or prior to the first quarter of 2012.

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

Fair values of the derivative contracts recorded in the condensed consolidated balance sheet as of June 30, 2011 and December 31, 2010, are the following:

	Asset Derivatives
		Fair Value
(in thousands)	Balance Sheet Location	June 30, 2011		December 31, 2010
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy assets	$	335	$	1,642
Put option (1)	Mark-to-market energy assets		—		—
Total asset derivatives		$	335	$	1,642

	Liability Derivatives
		Fair Value
(in thousands)	Balance Sheet Location	June 30, 2011		December 31, 2010
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy liabilities	$	216	$	1,492
Total liability derivatives		$	216	$	1,492

(1) We purchased a put option for the Pro-Cap (propane price cap) Plan in October 2010. The put option, which expired in January and February 2011, had a fair value of $0 at December 31, 2010.

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The effects of gains and losses from derivative instruments on the condensed consolidated statements of income are the following:

		Amount of Gain (Loss) on Derivatives:
	Location of Gain	For the Three Months Ended June 30,					For the Six Months Ended June 30,
(in thousands)	(Loss) on Derivatives	2011			2010		2011			2010
Derivatives not designated as hedging instruments:
Put Option(1) (2)	Cost of Sales	$	—		$	—	$	—		$	—
Unrealized gain on forward contracts	Revenue		(112	)		160		(30	)		374
Total		$	(112	)	$	160	$	(30	)	$	374

(1)	We purchased a put option for the Pro-Cap Plan in October 2010. The put option, which expired in January and February 2011, had a fair value of $0 at December 31, 2010.
(2)	We purchased a put option for the Pro-Cap Plan in September 2009. The put option, which expired on March 31, 2010, had a fair value of $0 at March 31, 2010.

The effects of trading activities on the condensed consolidated statements of income are the following:

	Location in the	Three months ended June 30,					Six months ended June 30,
(in thousands)	Statement of Income	2011			2010		2011			2010
Realized gains on forward contracts	Revenue	$	647		$	60	$	1,554		$	738
Changes in mark-to-market energy assets	Revenue		(112	)		160		(30	)		374
Total		$	535		$	220	$	1,524		$	1,112

11. Fair Value of Financial Instruments

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

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

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

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

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The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy used at June 30, 2011:

			Fair Value Measurements Using:
					Significant Other		Significant
			Quoted Prices in		Observable		Unobservable
			Active Markets		Inputs		Inputs
(in thousands)	Fair Value		(Level 1)		(Level 2)		(Level 3)
Assets:
Investments — equity securities	$	1,705	$	1,705	$	—	$	—
Investments — other	$	2,404	$	2,404	$	—	$	—
Mark-to-market energy assets	$	335	$	—	$	335	$	—
Liabilities:
Mark-to-market energy liabilities	$	216	$	—	$	216	$	—

The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy used at December 31, 2010:

	Fair Value Measurements Using:
					Significant Other		Significant
			Quoted Prices in		Observable		Unobservable
			Active Markets		Inputs		Inputs
(in thousands)	Fair Value		(Level 1)		(Level 2)		(Level 3)
Assets:
Investments — equity securities	$	1,515	$	1,515	$	—	$	—
Investments — other	$	2,521	$	2,521	$	—	$	—
Mark-to-market energy assets, including put option	$	1,642	$	—	$	1,642	$	—
Liabilities:
Mark-to-market energy liabilities	$	1,492	$	—	$	1,492	$	—

The following valuation techniques were used to measure fair value assets in the table above on a recurring basis as of June 30, 2011 and December 31, 2010:

Level 1 Fair Value Measurements:

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

Investments- other – The fair values of these investments, comprised of money market and mutual funds, are recorded at fair value based on quoted net asset values of the shares.

Level 2 Fair Value Measurements:

Mark-to-market energy assets and liabilities — These forward contracts are valued using market transactions in either the listed or over the counter (“OTC”) markets.

Propane put option — The fair value of the propane put option is determined using market transactions for similar assets and liabilities in either the listed or OTC markets.

At June 30, 2011, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.

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Other Financial Assets and Liabilities

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

At June 30, 2011, long-term debt, which includes the current maturities of long-term debt, had a carrying value of $126.3 million, compared to a fair value of $145.0 million, using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, with adjustments for duration, optionality, and risk profile. At December 31, 2010, long-term debt, including the current maturities, had a carrying value of $98.9 million, compared to the estimated fair value of $113.4 million.

12. Long-Term Debt

Our outstanding long-term debt is shown below:

	June 30,			December 31,
(in thousands)	2011			2010
FPU secured first mortgage bonds (A):
9.57% bond, due May 1, 2018	$	6,346		$	7,248
10.03% bond, due May 1, 2018		3,490			3,986
9.08% bond, due June 1, 2022		7,956			7,950
Uncollateralized senior notes:
6.85% note, due January 1, 2012		1,000			1,000
7.83% note, due January 1, 2015		8,000			8,000
6.64% note, due October 31, 2017		19,091			19,091
5.50% note, due October 12, 2020		20,000			20,000
5.93% note, due October 31, 2023		30,000			30,000
5.68% note, due June 30, 2026		29,000			—
Convertible debentures:
8.25% due March 1, 2014		1,221			1,318
Promissory note		215			265
Total long-term debt		126,319			98,858
Less: current maturities		(9,196	)		(9,216	)
Total long-term debt, net of current maturities	$	117,123		$	89,642

(A) FPU secured first mortgage bonds are guaranteed by Chesapeake.

On June 23, 2011, we issued $29.0 million of 5.68 percent unsecured senior notes to Metropolitan Life Insurance Company and New England Life Insurance Company, pursuant to an agreement we entered into with them on June 29, 2010. These notes have similar covenants and default provisions as Chesapeake’s existing senior notes, and they require annual principal payments of $2.9 million beginning in the sixth year after the issuance. We used the proceeds to permanently finance the redemption of the 6.85 percent and 4.90 percent series of FPU first mortgage bonds. These redemptions occurred in January 2010 and were previously financed by Chesapeake’s short-term loan facilities. Under the same agreement, we may issue an additional $7.0 million of unsecured senior notes prior to May 3, 2013, at a rate ranging from 5.28 percent to 6.43 percent based on the timing of the issuance. These notes, if issued, will have similar covenants and default provisions as the senior notes issued in June 2011.

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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 is designed to provide a reader of the financial statements with a narrative report on our financial condition, results of operations and liquidity. This discussion and analysis should be read in conjunction with the attached unaudited condensed consolidated financial statements and notes thereto and our Annual Report on Form 10-K for the year ended December 31, 2010, including the audited consolidated financial statements and notes thereto.

Safe Harbor for Forward-Looking Statements

We make statements in this Quarterly Report on Form 10-Q that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. One can typically identify forward-looking statements by the use of forward-looking words, such as “project,” “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “continue,” “potential,” “forecast” or other similar words, or future or conditional verbs such as “may,” “will,” “should,” “would” or “could.” These statements represent our intentions, plans, expectations, assumptions and beliefs about future financial performance, business strategy, projected plans and objectives of the Company. These statements are subject to many risks, uncertainties and other important factors that could cause actual results to differ materially from those expressed in the forward-looking statements. Such factors include, but are not limited to:

• state and federal legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures, and affect the speed at and degree to which competition enters the electric and natural gas industries (including deregulation);

• the outcomes of regulatory, tax, environmental and legal matters, including whether pending matters are resolved within current estimates;

• the loss of customers due to government mandated sale of our utility distribution facilities;

• industrial, commercial and residential growth or contraction in our service territories;

• the weather and other natural phenomena, including the economic, operational and other effects of hurricanes and ice storms;

• the timing and extent of changes in commodity prices and interest rates;

• general economic conditions, including any potential effects arising from terrorist attacks and any consequential hostilities or other hostilities or other external factors over which we have no control;

• changes in environmental and other laws and regulations to which we are subject;

• the results of financing efforts, including our ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings and general economic conditions;

• declines in the market prices of equity securities and resultant cash funding requirements for our defined benefit pension plans;

• the creditworthiness of counterparties with which we are engaged in transactions;

• growth in opportunities for our business units;

• the extent of success in connecting natural gas and electric supplies to transmission systems and in expanding natural gas and electric markets;

• the effect of accounting pronouncements issued periodically by accounting standard-setting bodies;

• conditions of the capital markets and equity markets during the periods covered by the forward-looking statements;

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• the ability to successfully execute, manage and integrate merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture;

• the ability to manage and maintain key customer relationships;

• the ability to maintain key supply sources;

• the effect of spot, forward and future market prices on our distribution, wholesale marketing and energy trading businesses;

• the effect of competition on our businesses;

• the ability to construct facilities at or below estimated costs;

• changes in technology affecting our advanced information services business; and

• operation and litigation risks that may not be covered by insurance.

Introduction

We are a diversified utility company engaged, directly or through subsidiaries, in regulated energy businesses, unregulated energy businesses, and other unregulated businesses, including advanced information services.

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

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

• expanding the regulated energy distribution and transmission businesses into new geographic areas and providing new services in our current service territories;

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

• utilizing our expertise across our various businesses to improve overall performance;

• enhancing marketing channels to attract new customers;

• providing reliable and responsive customer service to retain existing customers;

• maintaining a capital structure that enables us to access capital as needed;

• maintaining a consistent and competitive dividend for shareholders; and

• creating and maintaining a diversified customer base, energy portfolio and utility foundation.

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

The following discussions and those later in the document on operating income and segment results include use of the term “gross margin.” Gross margin is determined by deducting the cost of sales from operating revenue. Cost of sales includes the purchased cost of natural gas, electricity and propane and the cost of labor spent on direct revenue-producing activities. Gross margin should not be considered an alternative to operating income or net income, which are determined in accordance with GAAP. We believe 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 energy operations and under its competitive pricing structure for unregulated natural gas marketing and propane distribution operations. Our management uses gross margin in measuring our 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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Results of Operations for the Quarter Ended June 30, 2011

Overview and Highlights

Our net income for the quarter ended June 30, 2011 was $3.5 million, or $0.37 per share (diluted). This represents an increase of $180,000, or $0.02 per share (diluted), compared to a net income of $3.3 million, or $0.35 per share (diluted), as reported in the same period in 2010.

							Increase
For the Three Months Ended June 30,	2011			2010			(decrease)
(in thousands except per share)
Business Segment:
Regulated Energy	$	7,863		$	8,308			($445	)
Unregulated Energy		4			(791	)		795
Other		(91	)		244			(335	)
Operating Income		7,776			7,761			15
Other Income		27			(11	)		38
Interest Charges		2,114			2,305			(191	)
Income Taxes		2,169			2,105			64
Net Income	$	3,520		$	3,340		$	180
Earnings Per Share of Common Stock
Basic	$	0.37		$	0.35		$	0.02
Diluted	$	0.37		$	0.35		$	0.02

Key Factors Affecting Our Businesses

The following is a summary of key factors affecting our businesses and their impacts on our results during the second quarter of 2011. More detailed analysis of our results by segment is provided in the following section.

Growth. We are continuing to see growth in our natural gas businesses from our efforts over the past several years to expand our services by delivering clean-burning, environmentally friendly natural gas to customers. We are identifying and developing additional opportunities that will generate growth over the next several years.

Eastern Shore, our natural gas transmission subsidiary, generated gross margin of $542,000 in the second quarter of 2011 from new transportation services associated with its eight-mile mainline extension to interconnect with TETLP’s pipeline system. These services commenced in January 2011 and have a three-year phase-in from 19,324 Mcfs per day to 38,647 Mcfs per day, and an estimated gross margin of $2.4 million in 2011, $3.9 million in 2012 and $4.3 million annually thereafter.

14 large commercial and industrial customers added by the Delmarva natural gas operation since July 2010 generated $261,000 in additional gross margin during the second quarter of 2011. These new customers are expected to generate annual margin of $1.1 million in 2011, compared to $196,000 of gross margin generated from these customers in 2010. Also generating additional gross margin of $105,000 for the second quarter of 2011 was a three-percent growth in residential customers for the Delmarva natural gas distribution operation.

The Florida natural gas distribution operations generated $376,000 from one-percent growth in residential customers and three-percent growth in commercial customers in the second quarter of 2011, compared to the same quarter in 2010. In addition, 700 new customers, added as a result of our purchase of the operating assets of Indiantown Gas Company in August 2010, generated $142,000 of additional gross margin during the quarter.

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We are continuing our efforts to extend natural gas service to Lewes, Delaware and Cecil and Worcester Counties, Maryland. We signed service agreements in March 2011 with Beebe Medical Center and SPI Pharma, both located in Lewes, Delaware, with natural gas service expected to commence to these customers in the third and fourth quarters of 2011, respectively. Gross margin from these customers is expected to equate to gross margin generated by approximately 1,000 residential customers. We have obtained the necessary natural gas franchises from Cecil and Worcester Counties, Maryland and the approval from the Maryland PSC to exercise those franchises, except for the final determination of the service boundary in a small portion of the franchise area in Cecil County.

Propane Prices. Higher price volatility and trading volumes in Xeron, our wholesale marketing subsidiary, resulted in a 56-percent increase in its trading volumes during the second quarter of 2011, compared to the same quarter in 2010, and generated $314,000 of additional gross margin.

Our propane distribution operations generated additional gross margin of $658,000 from higher margins per gallon in the second quarter of 2011, compared to the same quarter in 2010. Propane retail margins per gallon on the Delmarva Peninsula during the second quarter of 2011 returned to more normal levels, compared to the lower margins per gallon reported during the second quarter of 2010 caused by the higher cost of spot purchases during the peak heating season. Propane retail margins per gallon in Florida also increased in the second quarter of 2011, compared to the same quarter in 2010, as we continued to adjust our retail pricing in response to market conditions.

Rates and Regulatory Matters. Eastern Shore’s base rate proceeding, which was filed with the FERC on December 30, 2010, is still underway. Eastern Shore expects this proceeding to be completed in 2011. The “Come-Back” filing in Florida, which includes our request for recovery, through rates, of approximately $34.2 million in acquisition adjustment and $2.2 million in merger-related costs, is also still underway. See Note 3, “Rates and Other Regulatory Activities,” to the unaudited condensed consolidated financial statements for further discussion.

Advanced Information Services. BravePoint, our advanced information services subsidiary, reported $188,000 in operating loss in the second quarter of 2011, compared to operating income of $230,000 reported in the same quarter in 2010. BravePoint’s operating results in the second quarter of 2011 reflect approximately $341,000 in additional costs associated with the initial roll-out and implementation of a new product, ProfitZoom™. BravePoint completed the first successful implementation of ProfitZoom™ in July 2011. At present, BravePoint has three customers, which have implemented, or are in the process of implementing, this new product and has several outstanding sales proposals under consideration by other customers. ProfitZoom™ is an integrated system designed specifically for the fire protection and specialty contracting industries, which includes a comprehensive suite of financial, job costing and service management modules, and is a successor product to another software solution that BravePoint previously marketed and supported for companies in the fire suppression industry. Understanding the needs of the industry and utilizing its technology expertise, BravePoint began developing the ProfitZoom™ product in 2009.

Other Operating Expenses. Our other operating expenses increased by $2.5 million in the second quarter of 2011, compared to the same quarter in 2010. Included in this increase are $808,000 in non-recurring charges incurred during the second quarter of 2011, which were comprised of $259,000 in additional marketing and development costs of ProfitZoom™, and $549,000 in one-time charges in May 2011 associated with the voluntary workforce reduction of 31 employees in Florida as we continue to integrate our Florida operations. The voluntary workforce reduction in Florida is expected to generate $500,000 in cost savings in 2011 and $800,000 in annual savings thereafter.

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The remaining $1.7 million of the increase in other operating expenses, or a six-percent increase compared to other operating expenses during the second quarter of 2010, was attributable to the following factors:

• $558,000 in increased payroll and benefits expense, excluding one-time charges associated with the voluntary workforce reduction, due primarily to enhanced benefits offered to FPU and BravePoint employees and higher accruals for performance incentive compensation;

• Increased regulatory, legal and other costs related to our regulated energy businesses, including $316,000 of additional costs associated with our electric franchise dispute in Marianna, Florida and $83,000 in costs with respect to our “Come-Back” filing in Florida and the rate case proceeding for Eastern Shore;

• $258,000 in higher depreciation expense and asset removal costs in our regulated energy businesses from capital investments made since the second half of 2010;

• $153,000 in additional expenses related to pipeline integrity projects for Eastern Shore to comply with pipeline regulatory requirements; and

• $79,000 of other operating expenses during the second quarter of 2011 from the purchase of the operating assets of Indiantown Gas Company in August 2010.

Both the “Come-Back” filing and the Eastern Shore rate case proceeding are expected to be resolved in 2011. Eastern Shore projects pipeline integrity expenditures to be at about the same level in 2011 and 2012 and projects a decrease in such expenditures in 2013.

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Regulated Energy

					Increase
For the Three Months Ended June 30,	2011		2010		(decrease)
(in thousands, except degree-day and customer information)
Revenue	$	54,327	$	52,740	$	1,587
Cost of sales		24,882		24,625		257
Gross margin		29,445		28,115		1,330
Operations & maintenance		15,552		14,074		1,478
Depreciation & amortization		4,020		3,754		266
Other taxes		2,010		1,979		31
Other operating expenses		21,582		19,807		1,775
Operating Income	$	7,863	$	8,308	$	(445	)
Weather and Customer analysis
Delmarva Peninsula
Heating degree-days (“HDD”):
Actual		382		428		(46	)
10-year average		487		495		(8	)
Per residential customer added:
Estimated gross margin	$	375	$	375	$	0
Estimated other operating expenses	$	111	$	105	$	6
Florida
HDD:
Actual		14		9		5
10-year average		30		33		(3	)
Cooling degree-days:
Actual		1,027		1,037		(10	)
10-year average		894		880		14
Residential Customer Information
Average number of customers:
Delmarva natural gas distribution		48,660		47,431		1,229
Florida natural gas distribution		61,659		60,580		1,079
Florida electric distribution		23,593		23,585		8
Total		133,912		131,596		2,316

Operating income for the regulated energy segment decreased by approximately $445,000, or five percent, in the second quarter of 2011, compared to the same quarter in 2010. An increase in gross margin of $1.3 million, offset by an increase in other operating expense of $1.8 million, resulted in the decrease in operating income.

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Gross Margin

Gross margin for our regulated energy segment increased by $1.3 million, or five percent, in the second quarter of 2011 compared to the same quarter in 2010.

Our Delmarva natural gas distribution operation generated an increase in gross margin of $426,000 in the second quarter of 2011, compared to the same quarter in 2010. The factors contributing to this increase were as follows:

• Customer growth generated a $400,000 increase in gross margin in the second quarter of 2011, compared to the same quarter in 2010. Commercial and industrial customer growth, due primarily to $261,000 in additional gross margin generated from 14 large commercial and industrial customers added since July 2010, generated $295,000 of this increase. These 14 new large commercial and industrial customers are expected to generate annual gross margin of $1.1 million in 2011. The same customers generated $196,000 of gross margin following their addition in the second half of 2010. Three-percent growth in residential customers generated an additional $105,000 in gross margin.

• The remaining increase in gross margin of $26,000 was attributable to increased non-weather-related customer consumption, offset partially by a decrease from a change in customer rates and rate classes.

Gross margin for our Florida natural gas distribution operation increased by $141,000 in the second quarter of 2011, compared to the same quarter in 2010. The factors contributing to this increase were as follows:

• One-percent growth in residential customers and three-percent growth in commercial customers generated additional gross margin of $376,000 in the second quarter of 2011, compared to the same quarter in 2010.

• 700 new customers, added as a result of our purchase of the operating assets of Indiantown Gas Company in August 2010, generated $142,000 in gross margin in the second quarter of 2011.

• These increases in gross margin in the second quarter were partially offset by decreased gross margin of $377,000, primarily attributable to lower customer consumption during the second quarter, compared to the same quarter in 2010.

Our natural gas transmission operations achieved gross margin growth of $761,000 in the second quarter of 2011, compared to the same quarter in 2010. The factors contributing to this increase were as follows:

• New transportation services associated with Eastern Shore’s eight-mile mainline extension to interconnect with TETLP’s pipeline system generated an additional $542,000 of gross margin in the second quarter. These new services commenced in January 2011 and have a three-year phase-in from 19,324 Mcfs per day to 38,647 Mcfs per day, and an estimated annual gross margin of $2.4 million in 2011, $3.9 million in 2012 and $4.3 million annually thereafter.

• New transportation services implemented by Eastern Shore in May 2010 and November 2010 as a result of its system expansion projects generated an additional $103,000 of gross margin in the second quarter of 2011, compared to the same quarter in 2010. These expansions added 2,666 Mcfs per day and an estimated annual gross margin of $574,000 in 2011. In 2010, these projects generated $216,000 of gross margin, of which $40,000 was recorded in the second quarter of 2010.

• Eastern Shore entered into two additional transportation services agreements with an existing industrial customer, one for the period of May 2011 through April 2021 for an additional 3,290 Mcfs per day and the other one for the period of November 2011 through October 2012 for an additional 9,212 Mcfs. These services generated additional gross margin of $61,000 in the second quarter of 2011 and are expected to generate additional gross margin of $356,000 in 2011, $1.2 million in 2012 and $369,000 annually thereafter.

• The remaining gross margin increase of $55,000 was attributable primarily to higher volumes delivered to customers on a non-recurring basis during the second quarter.

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Gross margin for our Florida electric distribution operation remained relatively unchanged with a slight increase of $2,000 in the second quarter of 2011, compared to the same quarter in 2010.

Other Operating Expenses

Other operating expenses for the regulated energy segment increased by $1.8 million, or nine percent, in the second quarter of 2011, compared to the same quarter in 2010, due largely to the following factors:

• One-time charges of $481,000 for the regulated energy businesses associated with the voluntary workforce reduction in Florida;

• Increased regulatory, legal and other costs, including $316,000 of additional costs associated with our electric franchise dispute in Marianna, Florida and $83,000 in costs associated with the “Come-Back” filing in Florida and the rate case proceeding for Eastern Shore;

• $258,000 in higher depreciation expense and asset removal costs from capital investments made since the second half of 2010;

• $153,000 in additional expenses related to pipeline integrity projects for Eastern Shore to comply with increased pipeline regulatory requirements; and

• $79,000 of other operating expenses associated with the purchase of the operating assets of Indiantown Gas Company in August 2010.

Other Development

In June 2011, Allen Family Foods, Inc. and related entities (collectively, “Allen”) filed for bankruptcy. Our Delmarva natural gas distribution operation serves two of Allen’s poultry facilities, one of which is included in our discussion of 14 new large commercial and industrial customers added since July 2010. Gross margin generated from our natural gas service to these two Allen facilities was approximately $94,000 and $24,000 for the three months ended June 30, 2011 and 2010, respectively, and approximately $211,000 and $51,000 for the first six months of 2011 and 2010, respectively. The total gross margin for 2010 from our natural gas service to these two facilities was approximately $156,000. As of June 30, 2011, we had approximately $40,000 in outstanding receivable balances with Allen. Since the bankruptcy filing, these two facilities have been sold to another poultry processor. We cannot predict the future plan for these two facilities by the new purchaser or the level of natural gas consumption, if any, at these two facilities in the future.

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Unregulated Energy

						Increase
For the Three Months Ended June 30,	2011		2010			(decrease)
(in thousands, except degree-day data)
Revenue	$	29,692	$	24,615		$	5,077
Cost of sales		22,849		19,068			3,781
Gross margin		6,843		5,547			1,296
Operations & maintenance		5,692		5,331			361
Depreciation & amortization		807		718			89
Other taxes		340		289			51
Other operating expenses		6,839		6,338			501
Operating Income (Loss)	$	4	$	(791	)	$	795
Weather Analysis — Delmarva Peninsula
Actual HDD		382		428			(46	)
10-year average HDD		487		495			(8	)

Operating income for the unregulated energy segment in the second quarter of 2011 was $4,000, an increase of $795,000, compared to an operating loss of $791,000 in the same quarter in 2010. The increase resulted from an increase in gross margin of $1.3 million, which was offset by an increase in other operating expense of $501,000.

Gross Margin

Gross margin for our unregulated energy segment increased by $1.3 million, or 23 percent, in the second quarter of 2011, compared to the same quarter in 2010.

Our Delmarva propane distribution operation generated an increase in gross margin of $481,000, or 21 percent, in the second quarter of 2011, compared to the same quarter in 2010. The factors contributing to this increase were as follows:

• Our Delmarva propane distribution operation generated additional gross margin of $220,000 due to higher margins per gallon in the second quarter of 2011, compared to the same quarter in 2010, as margins per gallon returned to more normal levels during the current quarter. Propane margins per gallon during the second quarter of 2010 were low, compared to historical levels, due to additional spot purchases at increased costs during the peak heating season to meet the weather-related increase in customer consumption. More normal temperatures and fewer spot purchases during 2011 resulted in margins per gallon returning to more normal levels in the second quarter of 2011.

• An increase in volumes sold in the second quarter of 2011, compared to the same period in 2010, generated additional gross margin of $109,000. This increase was attributable to the timing of deliveries to bulk customers, offset partially by a decrease in weather-related consumption due to the warmer temperatures on the Delmarva Peninsula.

• The remaining gross margin increase of $152,000 is due primarily to increased wholesale margins and higher fees generated from increased service work, continued growth and successful implementation of various customer loyalty programs.

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Our Florida propane distribution operations generated increased gross margin of $302,000 in the second quarter of 2011, compared to the same quarter in 2010. Higher margins per gallon, as we continued to adjust our retail pricing in response to market conditions, generated $438,000 of additional gross margin. Also generating additional gross margin of $77,000 during the current quarter was a new propane rail terminal arrangement with a supplier from November 2010 to May 2011 to provide terminal and storage services. These additional gross margins were offset partially by a decrease in volume sold in the second quarter of 2011, compared to the same period in 2010.

Xeron, our propane wholesale marketing subsidiary, generated $314,000 of increase in gross margin during the second quarter of 2011, compared to the same quarter in 2010, due primarily to an increase in Xeron’s trading activity by 56 percent in the second quarter of 2011, compared to the same period in 2010.

Gross margin generated by PESCO, our natural gas marketing subsidiary, increased by $291,000 in the second quarter of 2011 compared to the same quarter in 2010. This increase was due to favorable imbalance resolutions during the second quarter of 2011 with third-party intrastate pipelines, with which PESCO contracts for supply. Revenues generated from such favorable imbalance resolutions are not predictable and, therefore, are not included in our long-term financial plans or forecasts.

Merchandise sales in Florida decreased in the second quarter of 2011, compared to the same period in 2010, resulting in lower gross margin of $92,000.

Other Operating Expenses

Other operating expenses for the unregulated energy segment increased by $501,000 for the second quarter of 2011, compared to the same period in 2010, due primarily to: (a) increased payroll and benefit costs of $344,000, attributable primarily to higher accruals for performance incentive compensation; (b) increased vehicle expenses of $108,000 resulting from an increase in fuel prices; and (c) one-time charges of $67,000 for the unregulated energy businesses associated with the voluntary workforce reduction in Florida.

Other

						Increase
For the Three Months Ended June 30,	2011			2010		(decrease)
(in thousands)
Revenue	$	2,812		$	2,706	$	106
Cost of sales		1,571			1,316		255
Gross margin		1,241			1,390		(149	)
Operations & maintenance		1,049			910		139
Depreciation & amortization		110			73		37
Other taxes		173			163		10
Other operating expenses		1,332			1,146		186
Operating Income — Other		(91	)		244		(335	)
Operating Income — Eliminations		—			—		—
Operating Income	$	(91	)	$	244	$	(335	)

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

Operating income for the “other” segment decreased by approximately $335,000 in the second quarter of 2011, compared to the same quarter in 2010, which was attributable to a gross margin decrease of $149,000, and an operating expense increase of $186,000.

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Gross margin

The gross margin for our “other” segment decreased by $149,000 in the second quarter of 2011, compared to the same quarter in 2010, due primarily to BravePoint, our advanced information services subsidiary. Gross margin for BravePoint decreased by $114,000 as a result of decreased product sales, lower consulting margin and additional costs incurred during initial implementations of ProfitZoom™.

Other Operating Expenses

Other operating expenses for our “other” segment increased by $186,000 in the second quarter of 2011, compared to the same quarter in 2010. Other operating expenses for BravePoint increased by $304,000, due primarily to $259,000 in additional marketing and development costs, as it began to roll out ProfitZoom™, and $116,000 in increased benefit costs. Benefit costs increased for BravePoint as Chesapeake adopted a safe harbor 401(k) plan design on January 1, 2011, which resulted in an increased 401(k) benefit for BravePoint employees in 2011. The increase in BravePoint’s other operating expenses was partially offset by the absence in 2011 of $92,000 in merger-related costs in the second quarter of 2010.

Interest Expense

Interest expense for the quarter ended June 30, 2011 decreased by approximately $191,000, or eight percent, compared to the same quarter in 2010, due primarily to lower interest expenses on short-term borrowings and long-term debt. Short-term interest expense decreased by $42,000, which is largely attributable to lower rates on the $29.1 million term loan credit facility used to temporarily refinance the redemption of the 6.85 percent and 4.90 percent series of FPU first mortgage bonds in January 2010. Long-term interest expense decreased by $135,000 due to lower long-term debt as a result of scheduled principal payments.

On June 23, 2011, we issued $29 million of 5.68 percent unsecured senior notes to Metropolitan Life Insurance Company and New England Life Insurance Company, pursuant to an agreement executed in June 2010. We used the proceeds to permanently refinance the redemption of the two series of FPU first mortgage bonds mentioned previously, which were temporarily refinanced using a short-term loan credit facility. Compared to interest expense incurred under the short-term loan credit facility during the first half of 2011, issuance of these senior notes will result in an increase in interest expense of $550,000 in the second half of 2011.

Income Taxes

We recorded an income tax expense of $2.2 million for the quarter ended June 30, 2011, compared to $2.1 million for the quarter ended June 30, 2010. The increase is attributable to increased earnings in the second quarter of 2011 compared to the same period in 2010.

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Results of Operations for the Six Months Ended June 30, 2011

Overview and Highlights

Our net income during the six months ended June 30, 2011 was $17.3 million, or $1.79 per share (diluted). This represents a decrease of $0.03 per share (diluted), compared to $1.82 per share (diluted), as reported for the same period in 2010.

						Increase
For the Six Months Ended June 30,	2011			2010		(decrease)
(in thousands, except per share)
Business Segment:
Regulated Energy	$	24,171		$	25,824	$	(1,653	)
Unregulated Energy		8,518			6,969		1,549
Other		(74	)		366		(440	)
Operating Income		32,615			33,159		(544	)
Other Income		50			103		(53	)
Interest Charges		4,265			4,667		(402	)
Income Taxes		11,133			11,281		(148	)
Net Income	$	17,267		$	17,314	$	(47	)
Earnings Per Share of Common Stock
Basic	$	1.81		$	1.83	$	(0.02	)
Diluted	$	1.79		$	1.82	$	(0.03	)

Key Factors Affecting Our Businesses

The following is a summary of key factors affecting our businesses and their impacts on our results during the first six months of 2011. More detailed analysis of our results by segment is provided in the following section.

Growth. We are continuing to see growth in our natural gas businesses from our efforts over the past several years to expand our services by delivering clean-burning, environmentally friendly natural gas to customers. We are identifying and developing additional opportunities that will generate growth over the next several years.

Eastern Shore, our natural gas transmission subsidiary, generated gross margin of $1.1 million in the first six months of 2011 from new transportation services associated with its eight-mile mainline extension to interconnect with TETLP’s system. These services commenced in January 2011 and have a three-year phase-in from 19,324 Mcfs per day to 38,647 Mcfs per day, and an estimated gross margin of $2.4 million in 2011, $3.9 million in 2012 and $4.3 million annually thereafter.

14 large commercial and industrial customers added by the Delmarva natural gas operation since July 2010 generated $509,000 in additional gross margin during the first six months of 2011. These new customers are expected to generate annual margin of $1.1 million in 2011, compared to $196,000 of gross margin generated from these customers in the second half of 2010. Also generating additional gross margin of $271,000 for the first six months of 2011 was a two-percent growth in residential customers for the Delmarva natural gas distribution operation.

The Florida natural gas distribution operations generated $576,000 from one-percent growth in residential customers and three-percent growth in commercial customers in the six months ended June 30, 2011, compared to the same period in 2010. In addition, 700 new customers, added as a result of our purchase of the operating assets of Indiantown Gas Company in August 2010, generated $325,000 of additional gross margin during the first half of 2011.

We are continuing our efforts to extend natural gas service to Lewes, Delaware and Cecil and Worcester Counties, Maryland. We signed service agreements in March 2011 with Beebe Medical Center and SPI Pharma, both located in Lewes, Delaware, with natural gas service expected to commence to these customers in the third and fourth quarters of 2011, respectively. Gross margin from these customers is expected to equate to gross margin generated by approximately 1,000 residential customers. We have obtained the necessary natural gas franchises from Cecil and Worcester Counties, Maryland and the approval from the Maryland PSC to exercise those franchises, except for the final determination of the service boundary in a small portion of the franchise area in Cecil County.

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Weather. Warmer temperatures on the Delmarva Peninsula and in Florida during the first half of 2011, compared to the same period in 2010, particularly during the peak heating season, decreased consumer consumption of natural gas and electricity. Lower consumption, attributable primarily to warmer weather, decreased our period-over-period gross margin by approximately $2.4 million. Heating degree-days decreased by five percent, or 144 heating degree-days, on the Delmarva Peninsula and by 43 percent, or 408 heating degree-days, in Florida during the first six months of 2011, compared to the same period in 2010.

Propane Prices. Xeron, our wholesale marketing subsidiary, generated a period-over-period gross margin increase of $412,000, resulting from higher price volatility and a 50-percent increase in its trading activity during the first six months of 2011, compared to the same period in 2010.

The propane distribution operations generated additional gross margin of $980,000 from higher margins per gallon in the first six months of 2011, compared to the same period in 2010. Propane retail margins per gallon on the Delmarva Peninsula during the first half of 2011 returned to more normal levels, compared to the lower margins per gallon reported during the same period in 2010 caused by colder temperatures and the high cost of spot purchases during the peak heating season. Propane retail margins per gallon in Florida also increased in the first half of 2011, compared to the same period in 2010, as we continued to adjust our retail pricing in response to market conditions.

Rates and Regulatory Matters. Eastern Shore’s base rate proceeding, which was filed with the FERC on December 30, 2010, is still underway. Eastern Shore expects this proceeding to be completed in 2011. The “Come-Back” filing in Florida, which includes our request for recovery, through rates, of approximately $34.2 million in acquisition adjustment and $2.2 million in merger-related costs, is also still underway. See Note 3, “Rates and Other Regulatory Activities,” to the unaudited condensed consolidated financial statements for further discussion.

Advanced Information Services. BravePoint, our advanced information services subsidiary, reported $282,000 in operating loss in the six months ended June 30, 2011, compared to operating income of $265,000 reported in the same period in 2010. BravePoint’s operating results for the six months ended June 30, 2011 reflected approximately $549,000 in additional costs associated with the initial roll-out and implementation of a new product, ProfitZoom™. BravePoint completed the first successful implementation of ProfitZoom™ in July 2011. At present, BravePoint has three customers, which have implemented, or are currently implementing, this new product and has several outstanding sales proposals under consideration by other potential customers. ProfitZoom™ is an integrated system designed specifically for the fire protection and specialty contracting industries, which includes a comprehensive suite of financial, job costing and service management modules, and is a successor product to another software solution previously marketed and supported for companies in the fire suppression industry. Understanding the needs of the industry and utilizing its technology expertise, BravePoint began developing the ProfitZoom™ product in 2009.

Other Operating Expenses. Our other operating expenses increased by $3.4 million in the six months ended June 30, 2011, compared to the same period in 2010. Included in this increase are approximately $1.2 million in non-recurring charges incurred during the first six months of 2011, which were comprised of $439,000 in additional marketing and development costs of ProfitZoom™ and $788,000 in one-time charges associated with the voluntary workforce reduction in Florida and a pension settlement.

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The remaining $2.2 million of the increase in other operating expenses, or a four-percent increase compared to other operating expenses during the first six months of 2010, was attributable to the following factors:

• $559,000 in higher depreciation expense and asset removal costs in our regulated energy businesses from capital investments made since the second half of 2010;

• Increased regulatory, legal and other costs related to our regulated energy businesses, including $316,000 of additional costs associated with our electric franchise dispute in Marianna, Florida and $137,000 in costs with respect to our “Come-Back” filing in Florida and the rate case proceeding for Eastern Shore;

• $416,000 in additional expenses related to pipeline integrity projects for Eastern Shore to comply with pipeline regulatory requirements; and

• $147,000 of other operating expenses during the first six months of 2011 from the purchase of the operating assets of Indiantown Gas Company in August 2010.

Both the “Come-Back” filing and the Eastern Shore rate case proceeding are expected to be resolved in 2011. Eastern Shore projects pipeline integrity expenditures to be at about the same level in 2011 and 2012 and projects a decrease in such expenditures in 2013.

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Regulated Energy

					Increase
For the Six Months Ended June 30,	2011		2010		(decrease)
(in thousands, except degree-day and customer information)
Revenue	$	139,329	$	144,367	$	(5,038	)
Cost of sales		72,872		78,889		(6,017	)
Gross margin		66,457		65,478		979
Operations & maintenance		29,862		27,889		1,973
Depreciation & amortization		8,187		7,478		709
Other taxes		4,237		4,287		(50	)
Other operating expenses		42,286		39,654		2,632
Operating Income	$	24,171	$	25,824	$	(1,653	)
Weather and Customer analysis
Delmarva Peninsula
Heating degree-days (“HDD”):
Actual		2,827		2,971		(144	)
10-year average		2,863		2,831		32
Per residential customer added:
Estimated gross margin	$	375	$	375	$	0
Estimated other operating expenses	$	111	$	105	$	6
Florida
HDD:
Actual		534		942		(408	)
10-year average		594		547		47
Cooling degree-days:
Actual		1,107		1,040		67
10-year average		961		952		9
Residential Customer Information
Average number of customers:
Delmarva natural gas distribution		48,986		47,808		1,178
Florida natural gas distribution		61,603		60,530		1,073
Florida electric distribution		23,591		23,558		33
Total		134,180		131,896		2,284

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Operating income for the regulated energy segment decreased by approximately $1.7 million, or six percent, during the first six months of 2011, compared to the same period in 2010. An increase in gross margin of $979,000, offset by an increase in other operating expenses of $2.6 million, resulted in the decrease in operating income.

Gross Margin

Gross margin for our regulated energy segment increased by $979,000, or two percent, during the first six months of 2011, compared to the same period in 2010.

Our Delmarva natural gas distribution operation generated an increase in gross margin of $866,000 in the first six months of 2011, compared to the same period in 2010. The factors contributing to this increase were as follows:

• Customer growth generated an $855,000 increase in gross margin in the first six months of 2011, compared to the same period in 2010. Commercial and industrial customer growth, due primarily to $509,000 in addition gross margin generated from 14 large commercial and industrial customers added since the second half of 2010, generated $584,000 of this increase. These 14 new large commercial and industrial customers are expected to generate annual gross margin of $1.1 million in 2011. The same customers generated $196,000 of gross margin following their addition in the second half of 2010. Two-percent growth in residential customers generated an additional $271,000 in gross margin for the Delmarva natural gas distribution operation.

• The remaining increase in gross margin of $11,000 was attributable to higher customer consumption, offset partially by a decrease from a change in customer rates and rate classes.

Gross margin for our Florida natural gas distribution operation decreased by $977,000 during the first six months of 2011 compared to the same quarter in 2010. The factors contributing to this decrease were as follows:

• Lower customer consumption during the first six months of 2011, compared to the same period in 2010, due primarily to significantly warmer weather during the heating season, decreased gross margin by $1.9 million. Heating degree-days in Florida decreased by 43 percent, or 408 heating degree-days, during the first six months of 2011, compared to the same period in 2010.

• One-percent customer growth in residential customers and three-percent growth in commercial customers for the Florida natural gas distribution operation generated additional gross margin of $576,000 in the first half of 2011, compared to the same period in 2010.

• 700 new customers, added as a result of our purchase of the operating assets of Indiantown Gas Company in August 2010, generated $325,000 in new gross margin in the first six months of 2011.

Our natural gas transmission operations achieved gross margin growth of $1.4 million during the first six months of 2011 compared to the same period in 2010. The factors contributing to this increase were as follows:

• New transportation services associated with Eastern Shore’s eight-mile mainline extension to interconnect with TETLP’s pipeline system generated an additional $1.1 million of gross margin in the six months ended June 30, 2011. These new services commenced in January 2011 and have a three-year phase-in from 19,324 Mcfs per day to 38,647 Mcfs per day, and an estimated annual gross margin of $2.4 million in 2011, $3.9 million in 2012 and $4.3 million annually thereafter.

• New transportation services implemented by Eastern Shore in May 2010 and November 2010 as a result of its system expansion projects generated an additional $247,000 of gross margin during the first half of 2011, compared to 2010. These expansions added 2,666 Mcfs of capacity per day and an estimated annual gross margin of $574,000 in 2011. These projects generated $216,000 of gross margin in 2010, $40,000 of which was recorded in the first half of 2010.

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• Eastern Shore entered into two additional transportation services agreements with an existing industrial customer, one for the period of May 2011 through April 2021 for an additional 3,290 Mcfs per day and the other one for the period of November 2011 through October 2012 for an additional 9,192 Mcfs per day. These services generated additional gross margin of $61,000 in the first half of 2011 and are expected to generate additional gross margin of $356,000 in 2011, $1.2 million in 2012 and $369,000 annually thereafter.

• The foregoing increases to gross margin were offset by the expiration of two small firm transportation service contracts in April 2010, decreasing gross margin by $40,000 in the second half of 2011.

Gross margin for our Florida electric distribution operation decreased by $319,000 in the first six months of 2011, compared to the same period in 2010, due primarily to lower customer consumption during the heating season. Heating degree-days in Florida decreased by 43 percent, or 408 heating degree-days during the first six months of 2011, compared to the same period in 2010.

Other Operating Expenses

Other operating expenses for the regulated energy segment increased by $2.6 million in the six months ended June 30, 2011, due largely to the following factors:

• One-time charges totaling $651,000 associated with the voluntary workforce reduction in Florida and a pension settlement;

• Increased regulatory, legal and other costs, including $316,000 of additional costs associated with the electric franchise dispute in Marianna, Florida and $137,000 in costs with respect to the “Come-Back” filing in Florida and the rate case proceeding for Eastern Shore;

• $559,000 in higher depreciation expense and asset removal costs from capital investments made since the second half of 2010;

• $416,000 in additional expenses related to pipeline integrity projects for Eastern Shore to comply with increased pipeline regulatory requirements; and

• $147,000 of other operating expenses during the first half of 2011 associated with the purchase of the operating assets of Indiantown Gas Company in August 2010.

Other Development

In June 2011, Allen Family Foods, Inc. and related entities (collectively, “Allen”) filed for bankruptcy. Our Delmarva natural gas distribution operation serves two of Allen’s poultry facilities, one of which is included in our discussion of 14 new large commercial and industrial customers added since July 2010. Gross margin generated from our natural gas service to these two Allen facilities was approximately $94,000 and $24,000 for the three months ended June 30, 2011 and 2010, respectively, and approximately $211,000 and $51,000 for the first six months of 2011 and 2010, respectively. The total gross margin for 2010 from our natural gas service to these two facilities was approximately $156,000. As of June 30, 2011, we had approximately $40,000 in outstanding receivable balances with Allen. Since the bankruptcy filing, these two facilities have been sold to another poultry processor. We cannot predict the future plan for these two facilities by the new purchaser or the level of natural gas consumption, if any, at these two facilities in the future.

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Unregulated Energy

					Increase
For the Six Months Ended June 30,	2011		2010		(decrease)
(in thousands, except degree-day data)
Revenue	$	88,442	$	83,885	$	4,557
Cost of sales		65,604		63,027		2,577
Gross margin		22,838		20,858		1,980
Operations & maintenance		11,924		11,356		568
Depreciation & amortization		1,562		1,765		(203	)
Other taxes		834		768		66
Other operating expenses		14,320		13,889		431
Operating Income	$	8,518	$	6,969	$	1,549
Weather Analysis — Delmarva Peninsula
Actual HDD		2,827		2,971		(144	)
10-year average HDD		2,863		2,831		32

Operating income for the unregulated energy segment increased by approximately $1.5 million, or 22 percent, during the first six months of 2011, compared to the same period in 2010, primarily due to a gross margin increase of $2.0 million, partially offset by an operating expense increase of $431,000.

Gross Margin

Gross margin for our unregulated energy segment increased by $2.0 million, or nine percent, for the first six months of 2011, compared to the same period in 2010.

Our Delmarva propane distribution operation experienced an increase in gross margin of $1.4 million for the first six months of 2011, compared to the same period in 2010. The factors contributing to this increase were as follows:

• Our Delmarva propane distribution operation generated additional gross margin of $980,000 due to higher margins per gallon during the first six months of 2011, compared to the same quarter in 2010, as margins per gallon returned to more normal levels during the current period. Propane margins per gallon during the first half of 2010 were low, compared to historical levels, due to additional spot purchases at increased costs during the peak heating season to meet the weather-related increase in customer consumption. More normal temperatures and fewer spot purchases during 2011 resulted in margins per gallon in the first six months of 2011 returning to more normal levels.

• A one-time gain of $575,000 was recorded in the first six months of 2011, as a result of our share of proceeds received from an antitrust litigation settlement with a major propane supplier.

• An increase in other fees generated additional gross margin of $152,000, due primarily to the continued growth and successful implementation of various customer pricing programs.

• A decline in volumes sold in the first half of 2011, compared to the same period in 2010, decreased gross margin by $279,000. This decrease was attributable to timing of deliveries to bulk customers and a decrease in weather-related consumption due to the warmer temperatures on the Delmarva Peninsula.

Our Florida propane distribution operations experienced an increase in gross margin of $75,000 during the first half of 2011 compared to the same period in 2010. Higher margins per gallon, as we continued to adjust our retail pricing in response to market conditions, were offset by a decrease in volume sold during the period.

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Xeron, the Company’s propane wholesale marketing subsidiary, generated $412,000 of increase in gross margin during the first six months of 2011, compared to the same period in 2010, due primarily to an increase in Xeron’s trading activity by 50 percent in the first six months of 2011, compared to the same period in 2010.

Gross margin generated by PESCO, our natural gas marketing subsidiary, increased by $301,000 during the first six months of 2011, compared to the same period in 2010. This increase was due to favorable imbalance resolutions during the first half of 2011 with third-party intrastate pipelines, with which PESCO contracts for supply. Revenues generated from favorable imbalance resolutions with intrastate pipelines are not predictable and, therefore, are not included in our long-term financial plans or forecasts.

Merchandise sales in Florida decreased in the first six months of 2011, compared to the same period in 2010, resulting in lower gross margin of $174,000.

Other Operating Expenses

Other operating expenses for the unregulated energy segment increased by $430,000 for the first half of 2011, compared to the same period in 2010, due primarily to the following factors: (a) increased payroll and benefit costs of $347,000, attributable primarily to higher accruals for performance incentive compensation; (b) increased vehicle expenses of $202,000 resulting from an increase in fuel prices; and (c) one-time charges of $67,000 for the unregulated energy businesses associated with the voluntary workforce reduction in Florida.

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Other

						Increase
For the Six Months Ended June 30,	2011			2010		(decrease)
(in thousands)
Revenue	$	5,658		$	5,069	$	589
Cost of sales		3,107			2,448		659
Gross margin		2,551			2,621		(70	)
Operations & maintenance		2,046			1,768		278
Depreciation & amortization		209			145		64
Other taxes		370			342		28
Other operating expenses		2,625			2,255		370
Operating Income — Other		(74	)		366		(440	)
Operating Income — Eliminations		—			—		—
Operating Income		($74	)	$	366		($440	)

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

Operating income for the “other” segment decreased by approximately $440,000 during the first six months of 2011, compared to the same period in 2010, which was attributable to a gross margin decrease of $70,000 and an operating expense increase of $370,000.

Gross margin

The gross margin decrease of $70,000 for our “other” segment was primarily a result of lower consulting margin and additional costs associated with initial implementation of ProfitZoom™, which were slightly offset by an increase of product sales for BravePoint, our advanced information services subsidiary.

Other Operating Expenses

Other operating expenses increased by $370,000 in the first six months of 2011, compared to the same period in 2010. Other operating expenses for BravePoint increased by $498,000, due primarily to $439,000 in additional marketing and development costs, as it began to roll out ProfitZoom™, and $249,000 in increased benefit costs. Benefit costs increased for BravePoint as Chesapeake adopted a safe harbor 401(k) plan design on January 1, 2011, which resulted in an increased 401(k) benefit for BravePoint employees in 2011. The increase in BravePoint’s other operating expenses was offset partially by the absence in 2011 of $111,000 in merger-related costs in the first half of 2010.

Interest Expense

Interest expense for the six months ended June 30, 2011 decreased by approximately $403,000, or nine percent, compared to the same period in 2010, due primarily to a decrease of $424,000 in other long-term interest expense as the outstanding principal balance decreased as a result of scheduled repayments.

On June 23, 2011, we issued $29 million of 5.68 percent unsecured senior notes to Metropolitan Life Insurance Company and New England Life Insurance Company, pursuant to an agreement executed in June 2010. We used the proceeds to permanently refinance the redemption of the two series of FPU first mortgage bonds mentioned previously, which were temporarily refinanced using a short-term loan credit facility. Compared to interest expense incurred under the short-term loan credit facility during the first half of 2011, issuance of these senior notes will result in an increase in interest expense of $550,000 in the second half of 2011.

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Income Taxes

We recorded an income tax expense of $11.1 million for the first half of 2011, compared to $11.3 million for the same period in 2010. The period-over-period decrease in income tax expense is primarily a function of lower earnings for the period.

Financial Position, Liquidity and Capital Resources

Our capital requirements reflect the capital-intensive and seasonal nature of our business and are principally attributable to investment in new plant and equipment, retirement of outstanding debt and seasonal variability in working capital. We rely on cash generated from operations, short-term borrowings, and other sources to meet normal working capital requirements and to finance capital expenditures.

Our energy businesses are weather sensitive and seasonal. We normally generate a large portion of our annual net income and subsequent increases in our accounts receivable in the first and fourth quarters of each year due to significant volumes of natural gas and propane delivered by our natural gas and propane distribution operations to customers during the peak heating season. In addition, our natural gas and propane inventories, which usually peak in the fall months, are largely drawn down in the heating season and provide a source of cash as the inventory is used to satisfy winter sales demand.

Capital expenditures are one of our largest capital requirements. We originally budgeted $51.7 million for capital expenditures during 2011. As a result of continued growth, expansion opportunities and timing of capital projects, we increased our capital spending projection for 2011 to $62.6 million. This amount includes $54.3 million for the regulated energy segment, $2.9 million for the unregulated energy segment and $5.4 million for the “other” segment. The amount for the regulated energy segment includes estimated capital expenditures for expansion and improvement of facilities for the following: (a) natural gas distribution operation ($21.8 million); (b) natural gas transmission operation ($27.3 million); and (c) electric distribution operation ($5.2 million). The amount for the unregulated energy segment includes estimated capital expenditures for the propane distribution operations for customer growth and replacement of equipment. The amount for the “other” segment includes an estimated capital expenditure of $377,000 for the advanced information services operation, with the remaining balance for other general plant, computer software and hardware. We expect to fund the 2011 capital expenditures program from short-term borrowing, cash provided by operating activities, and other sources. The capital expenditures program is subject to continuous review and modification. Actual capital requirements may vary from the above estimates due to a number of factors, including changing economic conditions, customer growth in existing areas, regulation, new growth or acquisition opportunities and availability of capital.

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Capital Structure

We are committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access capital markets when required. This commitment, along with adequate and timely rate relief for our regulated operations, is intended to ensure our ability to attract capital from outside sources at a reasonable cost. We believe that the achievement of these objectives will provide benefits to our customers, creditors and investors. The following presents our capitalization, excluding and including short-term borrowings, as of June 30, 2011 and December 31, 2010:

	June 30,				December 31,
(in thousands)	2011				2010
Long-term debt, net of current maturities	$	117,123	33	%	$	89,642	28	%
Stockholders’ equity		238,000	67	%		226,239	72	%
Total capitalization, excluding short-term debt	$	355,123	100	%	$	315,881	100	%

	June 30,				December 31,
(in thousands)	2011				2010
Short-term debt	$	4,248	1	%	$	63,958	16	%
Long-term debt, including current maturities		126,319	34	%		98,858	25	%
Stockholders’ equity		238,000	65	%		226,239	59	%
Total capitalization, including short-term debt	$	368,567	100	%	$	389,055	100	%

Short-term Borrowings

Our outstanding short-term borrowings at June 30, 2011 and December 31, 2010 were $4.2 million and $64.0 million, respectively, at weighted average interest rates of 1.54 percent and 1.77 percent, respectively.

We utilize bank lines of credit to provide funds for our short-term cash needs to meet seasonal working capital requirements and to fund temporarily portions of the capital expenditure program. As of June 30, 2011, we had four unsecured bank lines of credit with two financial institutions for a total of $100.0 million. Two of these unsecured bank lines, totaling $60.0 million, are available under committed lines of credit. None of these unsecured bank lines of credit requires compensating balances. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks. We are currently authorized by our Board of Directors to borrow up to $85.0 million of short-term debt, as required, from these unsecured bank lines of credit.

Our outstanding borrowings under these unsecured bank lines of credit at June 30, 2011 and December 31, 2010 were $3.4 million and $30.8 million, respectively, at weighted average interest rates of 1.50 percent and 1.65 percent, respectively. In addition to the four unsecured bank lines of credit, we entered into a new short-term credit facility for $29.1 million with an existing lender in March 2010 to temporarily finance the early redemption of the 6.85 percent and 4.90 percent series of FPU’s secured first mortgage bonds. On June 23, 2011, we issued $29.0 million of 5.68 percent Chesapeake’s unsecured senior notes to repay the new short-term credit facility and permanently finance the FPU first mortgage bonds.

Cash Flows Provided By Operating Activities

Cash flows provided by operating activities were as follows:

For the Six Months Ended June 30,	2011		2010
(in thousands)
Net Income	$	17,267	$	17,314
Non-cash adjustments to net income		25,869		15,152
Changes in assets and liabilities		16,953		24,549
Net cash provided by operating activities	$	60,089	$	57,015

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During the six months ended June 30, 2011 and 2010, net cash flow provided by operating activities was $60.1 million and $57.0 million, respectively, a period-over-period increase of $3.1 million. Significant operating activities reflected in the change in cash flows provided by operating activities were as follows:

• Net cash flows related to income taxes, which include deferred income taxes in non-cash adjustments to net income and the change in income taxes receivable, increased by $3.9 million in the first half of 2011, compared to the same period in 2010, due primarily to the 100 percent bonus depreciation deduction allowed in 2011, which is reducing our income tax payments in the current period.

• Net cash flows from trading receivables and payables increased by $3.0 million, due primarily to the timing of collections and payments of trading contracts entered into by our propane wholesale marketing operation, offset partially by a decrease in net cash flows from receivables and payables in the natural gas and propane distributions operations.

• Net cash flows from customer deposits decreased by $2.2 million, due primarily to a large deposit received from a new industrial customer during the first half of 2010, which increased the cash flow for that period.

• Net cash flows from accrued compensation decreased by $2.3 million, as a result of a smaller decrease in the change in accrued payroll due to timing of payroll periods and higher incentive compensation payments in the first half of 2011, compared to the same period in 2010.

Cash Flows Used in Investing Activities

Net cash flows used in investing activities totaled $21.4 million and $14.3 million during the six months ended June 30, 2011 and 2010, respectively. Cash utilized for capital expenditures was $21.2 million and $13.6 million for the first six months of 2011 and 2010, respectively.

Cash Flows Used by Financing Activities

Cash flows used in financing activities totaled $38.5 million and $36.3 million for the first six months of 2011 and 2010, respectively. Significant financing activities reflected in the change in cash flows used by financing activities were as follows:

• During the first six months of 2011 we had a net repayment of $27.4 million under our line of credit agreements related to working capital, compared to $29.2 million in the same period in 2010, resulting in a period-over-period net cash increase of $1.8 million. Changes in cash overdrafts increased by $2.4 million, resulting in a period-over-period net cash decrease.

• Net repayments of other short-term debt and long-term debt during the first six months of 2011 were $1.6 million, compared to net repayments of $1.2 million in the same period in 2010. During the first six months of 2010, we redeemed the 6.85 and 4.90 series of FPU’s secured first mortgage bonds prior to their respective maturities by using the proceeds from a new short-term credit facility. During the first six months of 2011, we issued Chesapeake’s unsecured senior notes, using the proceeds to repay the new short-term credit facility and permanently finance the FPU bonds.

• We paid $5.7 million and $5.4 million in cash dividends for the six months ended June 30, 2011 and 2010, respectively.

Off-Balance Sheet Arrangements

We have issued corporate guarantees to certain vendors of our subsidiaries, primarily the propane wholesale marketing subsidiary and the natural gas marketing subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. None of these subsidiaries has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in our financial statements when incurred. The aggregate amount guaranteed at June 30, 2011 was $25.6 million, with the guarantees expiring on various dates through 2012.

- 52 -

In addition to the corporate guarantees, we have issued a letter of credit to our primary insurance company for $441,000, which expires on December 2, 2011. The letter of credit is provided as security to satisfy the deductibles under our various insurance policies. Although we recently changed our primary insurance company, we still have an outstanding letter of credit for $725,000 to our former primary insurance company, which will expire on June 1, 2012. There have been no draws on these letters of credit as of June 30, 2011. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that the letters of credit will be renewed to the extent necessary in the future.

We provided a letter of credit for $2.5 million under the Precedent Agreement with TETLP, which is the maximum amount required under the agreement.

Contractual Obligations

There has not been any material change in the contractual obligations presented in our 2010 Annual Report on Form 10-K, except for commodity purchase obligations and forward contracts entered into in the ordinary course of our business. The following table summarizes the commodity and forward contract obligations at June 30, 2011.

	Payments Due by Period
Purchase Obligations	Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years		Total
(in thousands)
Commodities (1)	$	13,892	$	—	$	—	$	—	$	13,892
Propane (2)		24,406		—		—		—		24,406
Total Purchase Obligations	$	38,298	$	—	$	—	$	—	$	38,298

(1)

In addition to the obligations noted above, the natural gas distribution, the electric distribution and propane distribution operations have agreements with commodity suppliers that have provisions with no minimum purchase requirements. There are no monetary penalties for reducing the amounts purchased; however, the propane contracts allow the suppliers to reduce the amounts available in the winter season if we do not purchase specified amounts during the summer season. Under these contracts, the commodity prices will fluctuate as market prices fluctuate.

(2)

We have also entered into forward sale contracts in the aggregate amount of $13.9 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, “Environmental Commitments and Contingencies,” to the unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q, we continue to work with federal and state environmental agencies to assess the environmental impact and explore corrective action at seven environmental sites. We believe that future costs associated with these sites will be recoverable in rates or through sharing arrangements with, or contributions by, other responsible parties.

Other Matters

Rates and Regulatory Matters

Our natural gas distribution operations in Delaware, Maryland and Florida and electric distribution operation in Florida are subject to regulation by their respective PSC; Eastern Shore is subject to regulation by the FERC; and Peninsula Pipeline is subject to regulation by the Florida PSC. At June 30, 2011, we were involved in rate filings and/or regulatory matters in each of the jurisdictions in which we operate. Each of these rate filings and/or regulatory matters is fully described in Note 3, “Rates and Other Regulatory Activities,” to the unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q.

- 53 -

Competition

Our natural gas and electric distribution operations and our natural gas transmission operation compete with other forms of energy, including natural gas, electricity, oil and propane. The principal competitive factors are price and, to a lesser extent, accessibility. Our natural gas distribution operations have several large-volume industrial customers that are able to use fuel oil as an alternative to natural gas. When oil prices decline, these interruptible customers may convert to oil to satisfy their fuel requirements, and our interruptible sales volumes may decline. Oil prices, as well as the prices of other fuels, fluctuate for a variety of reasons; therefore, future competitive conditions are not predictable. To address this uncertainty, we use flexible pricing arrangements on both the supply and sales sides of this business to compete with alternative fuel price fluctuations. As a result of the transmission operation’s conversion to open access and Chesapeake’s Florida natural gas distribution division’s restructuring of its services, these businesses have shifted from providing bundled transportation and sales service to providing only transmission and contract storage services. Our electric distribution operation currently does not face substantial competition because the electric utility industry in Florida has not been deregulated. In addition, natural gas is the only viable alternative fuel to electricity in our electric service territories and is available only in a small area.

Our natural gas distribution operations in Delaware, Maryland and Florida offer unbundled transportation services to certain commercial and industrial customers. In 2002, Chesapeake’s Florida natural gas distribution division, Central Florida Gas, extended such service to residential customers. With such transportation service available on our distribution systems, we are competing with third-party suppliers to sell gas to industrial customers. With respect to unbundled transportation services, our competitors include interstate transmission companies, if the distribution customers are located close enough to a transmission company’s pipeline to make connections economically feasible. The customers at risk are usually large volume commercial and industrial customers with the financial resources and capability to bypass our existing distribution operations in this manner. In certain situations, our distribution operations may adjust services and rates for these customers to retain their business. We expect to continue to expand the availability of unbundled transportation service to additional classes of distribution customers in the future. We have also established a natural gas marketing operation in Florida, Delaware and Maryland to provide such service to customers eligible for unbundled transportation services.

Our propane distribution operations compete with several other propane distributors in their respective geographic markets, primarily on the basis of service and price, emphasizing responsive and reliable service. Our competitors generally include local outlets of national distributors and local independent distributors, whose proximity to customers entails lower costs to provide service. Propane competes with electricity as an energy source, because it is typically less expensive than electricity, based on equivalent BTU value. Propane also competes with home heating oil as an energy source. Since natural gas has historically been less expensive than propane, propane is generally not distributed in geographic areas served by natural gas pipeline or distribution systems.

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

Our advanced information services subsidiary faces significant competition from a number of larger competitors having substantially greater resources available to them than does our subsidiary. In addition, changes in the advanced information services business are occurring rapidly and could adversely affect the markets for the products and services offered by these businesses. This segment competes on the basis of technological expertise, reputation and price.

Inflation

Inflation affects the cost of supply, labor, products and services required for operations, maintenance and capital improvements. While the impact of inflation has remained low in recent years, natural gas and propane prices are subject to rapid fluctuations. In the regulated natural gas and electric distribution operations, fluctuations in natural gas and electricity prices are passed on to customers through the fuel cost recovery mechanism in our tariffs. To help cope with the effects of inflation on our capital investments and returns, we seek rate increases from regulatory commissions for our regulated operations and closely monitor the returns of our unregulated business operations. To compensate for fluctuations in propane gas prices, we adjust propane selling prices to the extent allowed by the market.

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Recent Authoritative Pronouncements on Financial Reporting and Accounting

Recent accounting developments applicable to us and their impact on our financial position, results of operations and cash flows are described in Note 1, “Summary of Accounting Policies,” to the unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market risk represents the potential loss arising from adverse changes in market rates and prices. Long-term debt is subject to potential losses based on changes in interest rates. Our long-term debt consists of fixed-rate senior notes, secured debt and convertible debentures. All of our 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 $126.3 million at June 30, 2011, as compared to a fair value of $145.0 million, based on a discounted cash flow methodology that incorporates a market interest rate that is based on published corporate borrowing rates for debt instruments with similar terms and average maturities with adjustments for duration, optionality, credit risk, and risk profile. We evaluate whether to refinance existing debt or permanently refinance existing short-term borrowing, based in part on the fluctuation in interest rates.

Our propane distribution business is exposed to market risk as a result of propane storage activities and entering into fixed price contracts for supply. We can store up to approximately six million gallons of propane (including leased storage and rail cars) during the winter season to meet our 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, we have adopted a Risk Management Policy that allows the propane distribution operation to enter into fair value hedges or other economic hedges of our inventory.

Our propane wholesale marketing operation is a party to natural gas liquids forward contracts, primarily propane contracts, with various third parties. These contracts require that the propane wholesale marketing operation purchase or sell natural gas liquids at a fixed price at fixed future dates. At expiration, the contracts are settled by the delivery of natural gas liquids to us 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 by 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 natural gas liquids deviate from fixed contract settlement prices. Market risk associated with the trading of futures and forward contracts is monitored daily for compliance with our 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 daily by our oversight officials. In addition, the Risk Management Committee reviews periodic reports on markets and the credit risk of counter-parties, approves any exceptions to the Risk Management Policy (within limits established by the Board of Directors) and authorizes the use of any new types of contracts. Quantitative information on forward and futures contracts at June 30, 2011 is presented in the following tables.

	Quantity in	Estimated Market		Weighted Average
At June 30, 2011	Gallons	Prices		Contract Prices
Forward Contracts
Sale	9,240,000	$	1.3900 – $1.5700	$	1.5005
Purchase	8,106,000	$	1.3344 – $1.5850	$	1.4878

Estimated market prices and weighted average contract prices are in dollars per gallon.

All contracts expire during or prior to the first quarter of 2012.

At June 30, 2011 and December 31, 2010, we marked these forward contracts to market, using market transactions in either the listed or OTC markets, which resulted in the following assets and liabilities:

	June 30,		December 31,
(in thousands)	2011		2010
Mark-to-market energy assets	$	335	$	1,642
Mark-to-market energy liabilities	$	216	$	1,492

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 our “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 June 30, 2011. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2011.

Changes in Internal Control over Financial Reporting

During the quarter ended June 30, 2011, there was no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings

As disclosed in Note 5, “Other Commitments and Contingencies,” of the unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q, we are involved in certain legal actions and claims arising in the normal course of business. We are also involved in certain legal and administrative proceedings before various governmental or regulatory agencies concerning rates and other regulatory actions. In the opinion of management, the ultimate disposition of these proceedings and claims will not have a material effect on our condensed consolidated financial position, results of operations or cash flows.

Item 1A. Risk Factors

Our business, operations, and financial condition are subject to various risks and uncertainties. The risk factors described in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2010, should be carefully considered, together with the other information contained or incorporated by reference in this Quarterly Report on Form 10-Q and in our other filings with the SEC in connection with evaluating the Company, our business and the forward-looking statements contained in this Report. Additional risks and uncertainties not presently known to us or that we currently deem immaterial also may affect the Company. The occurrence of any of these known or unknown risks could have a material adverse impact on our business, financial condition, and results of operations.

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

	Total				Total Number of Shares		Maximum Number of
	Number of		Average		Purchased as Part of		Shares That May Yet Be
	Shares		Price Paid		Publicly Announced Plans		Purchased Under the
Period	Purchased		per Share		or Programs (2)		Plans or Programs(2)
April 1, 2011 through April 30, 2011 (1)		231	$	42.62		—		—
May 1, 2011 through May 31, 2011		—	$	—		—		—
June 1, 2011 through June 30, 2011		—	$	—		—		—
Total		231	$	42.62		—		—

(1)

Chesapeake purchased shares of stock on the open market for the purpose of reinvesting the dividend on deferred stock units held in the Rabbi Trust accounts for certain Directors and Senior Executives under the Deferred Compensation Plan. The Deferred Compensation Plan is discussed in detail in Item 8 under the heading “Notes to the Consolidated Financial Statements — Note M, Employee Benefit Plans” of our Form 10-K filed with the Securities and Exchange Commission on March 8, 2011. During the quarter, 231 shares were purchased through the reinvestment of dividends on deferred stock units.

(2)

Except for the purposes described in Footnote (1), Chesapeake has no publicly announced plans or programs to repurchase its shares.

Item 3. Defaults upon Senior Securities

None.

Item 5. Other Information

None.

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Item 6. Exhibits

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 August 5, 2011.
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 August 5, 2011.
32.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated August 5, 2011.
32.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated August 5, 2011.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Chesapeake Utilities Corporation
 

/s/ Beth W. Cooper  

Beth W. Cooper 

Senior Vice President and Chief Financial Officer 

Date: August 5, 2011

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EX-31.1

Exhibit 31.1

CERTIFICATE PURSUANT TO RULE 13A-14(A)
UNDER THE SECURITIES EXCHANGE ACT OF 1934

I, Michael P. McMasters, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2011 of Chesapeake Utilities Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a—15(e) and 15d—15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a—15(f) and 15d—15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 5, 2011

/s/ Michael P. McMasters

Michael P. McMasters

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATE PURSUANT TO RULE 13A-14(A)
UNDER THE SECURITIES EXCHANGE ACT OF 1934

I, Beth W. Cooper, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2011 of Chesapeake Utilities Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a—15(e) and 15d—15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a—15(f) and 15d—15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 5, 2011

/s/ Beth W. Cooper

Beth W. Cooper

Senior Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

Certificate of Chief Executive Officer

of

Chesapeake Utilities Corporation

(pursuant to 18 U.S.C. Section 1350)

I, Michael P. McMasters, President and Chief Executive Officer of Chesapeake Utilities Corporation, certify that, to the best of my knowledge, the Quarterly Report on Form 10-Q of Chesapeake Utilities Corporation (“Chesapeake”) for the period ended June 30, 2011, filed with the Securities and Exchange Commission on the date hereof (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Chesapeake.

/s/ Michael P. McMasters  

Michael P. McMasters 

August 5, 2011 

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Chesapeake Utilities Corporation and will be retained by Chesapeake Utilities Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

Certificate of Chief Financial Officer

of

Chesapeake Utilities Corporation

(pursuant to 18 U.S.C. Section 1350)

I, Beth W. Cooper, Senior Vice President and Chief Financial Officer of Chesapeake Utilities Corporation, certify that, to the best of my knowledge, the Quarterly Report on Form 10-Q of Chesapeake Utilities Corporation (“Chesapeake”) for the period ended June 30, 2011, filed with the Securities and Exchange Commission on the date hereof (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Chesapeake.

/s/ Beth W. Cooper  

Beth W. Cooper 

August 5, 2011 

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Chesapeake Utilities Corporation and will be retained by Chesapeake Utilities Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

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Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $) In Thousands	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Operating Activities
Net Income	$ 17,267	$ 17,314
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	9,958	9,389
Depreciation and accretion included in other costs	2,473	2,199
Deferred income taxes, net	12,449	3,683
Loss on sale of assets	94	71
Unrealized (gain) loss on commodity contracts	30	(374)
Unrealized (gain) loss on investments	(131)	60
Employee benefits	309	(383)
Share-based compensation	705	612
Other, net	(18)	(105)
Changes in assets and liabilities:
Sale (purchase) of investments	258	(131)
Accounts receivable and accrued revenue	14,017	26,485
Propane inventory, storage gas and other inventory	3,315	3,382
Regulatory assets	601	1,226
Prepaid expenses and other current assets	1,792	3,539
Accounts payable and other accrued liabilities	674	(14,796)
Income taxes receivable	(2,666)	2,201
Accrued interest	(241)	(259)
Customer deposits and refunds	(1,182)	1,041
Accrued compensation	(2,234)	83
Regulatory liabilities	2,887	1,194
Other liabilities	(268)	583
Net cash provided by operating activities	60,089	57,014
Investing Activities
Property, plant and equipment expenditures	(21,236)	(13,600)
Proceeds from sales of assets	344	34
Purchase of investments	(200)	(310)
Environmental expenditures	(326)	(410)
Net cash used in investing activities	(21,418)	(14,286)
Financing Activities
Common stock dividends	(5,685)	(5,369)
(Purchase) issuance of stock for Dividend Reinvestment Plan	(609)	268
Change in cash overdrafts due to outstanding checks	(3,193)	(834)
Net repayment under line of credit agreements	(27,417)	(29,188)
Other short-term borrowing	(29,100)	29,100
Proceeds from issuance of long-term debt	29,000
Repayment of long-term debt	(1,482)	(30,277)
Net cash used in financing activities	(38,486)	(36,300)
Net Increase in Cash and Cash Equivalents	185	6,428
Cash and Cash Equivalents - Beginning of Period	1,643	2,828
Cash and Cash Equivalents - End of Period	$ 1,828	$ 9,256

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Condensed Consolidated Balance Sheets (Unaudited) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Property, Plant and Equipment
Regulated energy	$ 511,008	$ 500,689
Unregulated energy	62,399	61,313
Other	18,926	16,989
Total property, plant and equipment	592,333	578,991
Less: Accumulated depreciation and amortization	(129,054)	(121,628)
Plus: Construction work in progress	8,317	5,394
Net property, plant and equipment	471,596	462,757
Investments, at fair value	4,109	4,036
Current Assets
Cash and cash equivalents	1,828	1,643
Accounts receivable (less allowance for uncollectible accounts of $1,095 and $1,194, respectively)	80,381	88,074
Accrued revenue	8,655	14,978
Propane inventory, at average cost	6,790	8,876
Other inventory, at average cost	3,266	3,084
Regulatory assets	289	51
Storage gas prepayments	3,672	5,084
Income taxes receivable	9,414	6,748
Deferred income taxes	2,170	2,191
Prepaid expenses	3,111	4,613
Mark-to-market energy assets	335	1,642
Other current assets	226	245
Total current assets	120,137	137,229
Deferred Charges and Other Assets
Goodwill	35,613	35,613
Other intangible assets, net	3,293	3,459
Long-term receivables	26	155
Regulatory assets	22,300	23,884
Other deferred charges	3,415	3,860
Total deferred charges and other assets	64,647	66,971
Total Assets	660,489	670,993
Stockholders' equity
Common stock, par value $0.4867 per share (authorized 25,000,000 shares)	4,654	4,635
Additional paid-in capital	148,796	148,159
Retained earnings	87,549	76,805
Accumulated other comprehensive loss	(2,999)	(3,360)
Deferred compensation obligation	796	777
Treasury stock	(796)	(777)
Total stockholders' equity	238,000	226,239
Long-term debt, net of current maturities	117,123	89,642
Total capitalization	355,123	315,881
Current Liabilities
Current portion of long-term debt	9,196	9,216
Short-term borrowing	4,248	63,958
Accounts payable	64,427	65,541
Customer deposits and refunds	25,135	26,317
Accrued interest	1,548	1,789
Dividends payable	3,299	3,143
Accrued compensation	4,623	6,784
Regulatory liabilities	11,960	9,009
Mark-to-market energy liabilities	216	1,492
Other accrued liabilities	12,081	10,393
Total current liabilities	136,733	197,642
Deferred Credits and Other Liabilities
Deferred income taxes	92,700	80,031
Deferred investment tax credits	203	243
Regulatory liabilities	3,670	3,734
Environmental liabilities	9,414	10,587
Other pension and benefit costs	17,816	18,199
Accrued asset removal cost - Regulatory liability	35,919	35,092
Other liabilities	8,911	9,584
Total deferred credits and other liabilities	168,633	157,470
Other commitments and contingencies (Note 4 and 5)
Total Capitalization and Liabilities	$ 660,489	$ 670,993

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Document and Entity Information (USD $) In Millions, except Share data	6 Months Ended
	Jun. 30, 2011	Jul. 31, 2011	Jun. 30, 2010
Document and Entity Information [Abstract]
Entity Registrant Name	CHESAPEAKE UTILITIES CORP
Entity Central Index Key	0000019745
Document Type	10-Q
Document Period End Date	Jun. 30, 2011
Amendment Flag	false
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Public Float			$ 297.6
Entity Common Stock, Shares Outstanding		0

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Other Commitments and Contingencies

6 Months Ended

Jun. 30, 2011

Other Commitments and Contingencies [Abstract]

Other Commitments and Contingencies

5. Other Commitments and Contingencies

Litigation

In May 2010, an FPU propane customer filed a class action complaint against FPU in Palm Beach County, Florida, alleging, among other things, that FPU acted in a deceptive and unfair manner related to a particular charge by FPU on its bills to propane customers and the description of such charge. The suit sought to certify a class comprised of FPU propane customers to whom such charge was assessed since May 2006 and requested damages and statutory remedies based on the amounts paid by FPU customers for such charge. FPU vigorously denied any wrongdoing and maintained that the particular charge at issue is customary, proper and fair. Without admitting any wrongdoing, validity of the claims or a properly certifiable class for the complaint, FPU entered into a settlement agreement with the plaintiff in September 2010 to avoid the burden and expenses of continued litigation. The court approved the final settlement agreement, and the judgment became final on March 13, 2011. In 2010, we recorded $1.2 million of the total estimated costs related to this litigation. Pursuant to the final settlement agreement, the distribution to the class was made by May 13, 2011.

On March 2, 2011, the City of Marianna, Florida filed a complaint against FPU in the Circuit Court of the Fourteenth Judicial Circuit in and for Jackson County, Florida, alleging that FPU breached its obligations under its franchise with the City of Marianna to provide electric service to customers within and without the City of Marianna by failing: (i) to develop and implement TOU and interruptible rates that were mutually agreed to by the City of Marianna and FPU; (ii) to have such mutually agreed upon rates in effect by February 17, 2011; and (iii) to have such rates available to all of FPU’s customers located within and without the corporate limits of the City of Marianna. The City is seeking a declaratory judgment allowing it to exercise its option under the Franchise Agreement to purchase FPU’s property (consisting of the electric distribution assets) within the City of Marianna. Any such purchase would be subject to approval by the Marianna Commission, which would also need to approve the presentation of a referendum to voters in the City of Marianna related to the purchase and the operation by the City of Marianna of an electric distribution facility. If the purchase is approved by the Marianna Commission and the referendum is approved by the voters, the closing of the purchase must occur within 12 months after the referendum is approved. On March 28, 2011, FPU filed its answer to the declaratory action by the City of Marianna, in which it denied the material allegations by the City of Marianna and asserted several affirmative defenses. FPU intends to vigorously contest this litigation and intends to oppose the adoption of any proposed referendum to approve the purchase of the FPU property in the City of Marianna.

Natural Gas, Electric and Propane Supply

Our natural gas, electric and propane distribution operations have entered into contractual commitments to purchase gas, electricity and propane from various suppliers. The contracts have various expiration dates. We have a contract with an energy marketing and risk management company to manage a portion of our natural gas transportation and storage capacity. This contract expires on March 31, 2012.

Chesapeake’s Florida natural gas distribution division has firm transportation service contracts with Florida Gas Transmission Company (“FGT”) and Gulfstream Natural Gas System, LLC (“Gulfstream”). Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties, including PESCO. Under the terms of these capacity release agreements, Chesapeake is contingently liable to FGT and Gulfstream, should any party that acquired the capacity through release fail to pay for the service.

In May 2011, PESCO renewed contracts to purchase natural gas from various suppliers. These contracts expire in May 2012.

As discussed in Note 3 “Rates and Other Regulatory Activities,” on January 25, 2011, FPU entered into an amendment to its Generation Services Agreement with Gulf Power, which reduces the capacity demand quantity and provides the savings necessary to support the TOU and interruptible rates for the customers in the City of Marianna, both of which were approved by the Florida PSC. The amendment also extends the current agreement by two years, with a new expiration date of December 31, 2019.

FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEA requires FPU to comply with the following ratios based on the results of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 times, and (b) fixed charge coverage ratio greater than 1.5 times. If either ratio is not met by FPU, it has 30 days to cure the default or provide an irrevocable letter of credit if the default is not cured. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken or proposed to be taken to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could result in FPU providing an irrevocable letter of credit. As of June 30, 2011, FPU was in compliance with all of the requirements of its fuel supply contracts.

Corporate Guarantees

The Board of Directors has previously authorized the Company to issue up to $35 million of corporate guarantees or letters of credit on behalf of our subsidiaries. On March 2, 2011, the Board increased this limit from $35 million to $45 million.

We have issued corporate guarantees to certain vendors of our subsidiaries, the largest portion of which are for our propane wholesale marketing subsidiary and our natural gas marketing subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in our financial statements when incurred. The aggregate amount guaranteed at June 30, 2011 was $25.6 million, with the guarantees expiring on various dates through December 2011.

Chesapeake guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under the guarantee is the outstanding principal and accrued interest balances. The outstanding principal balances of FPU’s first mortgage bonds approximate their carrying values (see Note 12, “Long-Term Debt,” to the unaudited condensed consolidated financial statements for further details).

In addition to the corporate guarantees, we have issued a letter of credit to our primary insurance company for $441,000, which expires on December 2, 2011. The letter of credit is provided as security to satisfy the deductibles under our various outstanding insurance policies. As a result of a change in our primary insurance company in 2010, we renewed the letter of credit for $725,000 to our former primary insurance company, which will expire on June 1, 2012. There have been no draws on these letters of credit as of June 30, 2011. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that the letters of credit will be renewed to the extent necessary in the future.

We provided a letter of credit for $2.5 million to Texas Eastern Transmission, LP (“TETLP”) related to the Precedent Agreement, which is further described below.

Agreements for Access to New Natural Gas Supplies

On April 8, 2010, our Delaware and Maryland divisions entered into a Precedent Agreement with TETLP to secure firm transportation service from TETLP in conjunction with its new expansion project, which is expected to expand TETLP’s mainline system by up to 190,000 Dts/d. The Precedent Agreement provides that, upon satisfaction of certain conditions, the parties will execute two firm transportation service contracts, one for our Delaware division and one for our Maryland division, for 34,100 and 15,900 Dts/d, respectively, including the additional volume subscribed in a subsequent agreement, to be effective on the service commencement date of the project, which is currently projected to occur in November 2012. Each firm transportation service contract shall, among other things, provide for: (a) the maximum daily quantity of Dts/d described above; (b) a term of 15 years; (c) a receipt point at Clarington, Ohio; (d) a delivery point at Honey Brook, Pennsylvania; and (e) certain credit standards and requirements for security. Commencement of service and TETLP’s and our rights and obligations under the two firm transportation service contracts are subject to satisfaction of various conditions specified in the Precedent Agreement.

Our Delmarva natural gas supplies are currently received primarily from the Gulf of Mexico natural gas production region and are transported through three interstate upstream pipelines, two of which interconnect directly with Eastern Shore’s transmission system. The new firm transportation service contracts between our Delaware and Maryland divisions and TETLP will provide us with an additional direct interconnection with Eastern Shore’s transmission system and access to new sources of natural gas supplies from other natural gas production regions, including the Appalachian production region, thereby providing increased reliability and diversity of supply. They will also provide our Delaware and Maryland divisions with additional upstream transportation capacity to meet current customer demands and to plan for sustainable growth.

The Precedent Agreement provides that the parties shall promptly meet and work in good faith to negotiate a mutually acceptable reservation rate. Failure to agree upon a mutually acceptable reservation rate would have enabled either party to terminate the Precedent Agreement, and would have subjected us to reimburse TETLP for certain pre-construction costs; however, on July 2, 2010, our Delaware and Maryland divisions executed the required reservation rate agreements with TETLP.

The Precedent Agreement requires us to reimburse TETLP for our proportionate share of TETLP’s pre-service costs incurred to date, if we terminate the Precedent Agreement, are unwilling or unable to perform our material duties and obligations thereunder, or take certain other actions whereby TETLP is unable to obtain the authorizations and exemptions required for this project. If such termination were to occur, we estimate that our proportionate share of TETLP’s pre-service costs could be approximately $8.6 million as of June 30, 2011. If we were to terminate the Precedent Agreement after TETLP completed its construction of all facilities, which is expected to be in the fourth quarter of 2011, our proportionate share could be as much as approximately $50 million. The actual amount of our proportionate share of such costs could differ significantly and would ultimately be based on the level of pre-service costs at the time of any potential termination. As our Delaware and Maryland divisions have now executed the required reservation rate agreements with TETLP, we believe that the likelihood of terminating the Precedent Agreement and having to reimburse TETLP for our proportionate share of TETLP’s pre-service costs is remote.

As previously mentioned, we have provided a letter of credit for $2.5 million, which is the maximum amount required under the Precedent Agreement with TETLP.

On March 17, 2010, our Delaware and Maryland divisions entered into a separate Precedent Agreement with Eastern Shore to extend its mainline by eight miles to interconnect with TETLP at Honey Brook, Pennsylvania. As discussed in Note 3, “Rates and Other Regulatory Activities,” to the unaudited condensed consolidated financial statements, Eastern Shore completed the extension project in December 2010 and commenced the service in January 2011. The rate for the transportation service on this extension is Eastern Shore’s current tariff rate for service in that area.

TETLP is proceeding with obtaining the necessary approvals, authorizations or exemptions for construction and operation of its portion of the project, including, but not limited to, approval by the FERC. TETLP is expecting the FERC approval by the end of 2011. Our Delaware and Maryland divisions require no regulatory approvals or exemptions to receive transmission service from TETLP or Eastern Shore.

As the Eastern Shore and TETLP firm transportation services commence, our Delaware and Maryland divisions incur costs for those services based on the agreed and FERC-approved reservation rates, which will become an integral component of the costs associated with providing natural gas supplies to our Delaware and Maryland divisions and will be included in the annual GSR filings for each of our respective divisions.

Non-income-based Taxes

From time to time, we are subject to various audits and reviews by the states and other regulatory authorities regarding non-income-based taxes. We are currently undergoing a sales tax audit in Florida. As of June 30, 2011, we maintained an accrual of $698,000 related to additional sales taxes and gross receipts taxes owed to various states, all of which were recorded in 2010.

Other Contingency

As of June 30, 2011, we maintained a $750,000 accrual, which was recorded in 2010 based on management’s assessment of FPU’s earnings and regulatory risk to its earnings associated with possible Florida PSC action related to our requested recovery and the matters set forth in the “Come-Back” filing (See Note 3, “Rates and Other Regulatory Activities,” to the unaudited condensed consolidated financial statements for further discussion).

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Derivative Instruments

6 Months Ended

Jun. 30, 2011

Derivative Instruments [Abstract]

Derivative Instruments

10. Derivative Instruments

We use derivative and non-derivative contracts to engage in trading activities and manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane. Our natural gas, electric and propane distribution operations have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to their customers. Purchases under these contracts either do not meet the definition of derivatives or are considered “normal purchases and sales” and are accounted for on an accrual basis. Our propane distribution operation may also enter into fair value hedges of its inventory in order to mitigate the impact of wholesale price fluctuations. As of June 30, 2011, our natural gas, electric and propane distribution operations did not have any outstanding derivative contracts.

Xeron, our propane wholesale and marketing subsidiary, engages in trading activities using forward and futures contracts. These contracts are considered derivatives and have been accounted for using the mark-to-market method of accounting. Under the mark-to-market method of accounting, the trading contracts are recorded at fair value, and the changes in fair value of those contracts are recognized as unrealized gains or losses in the statement of income in the period of change. As of June 30, 2011, we had the following outstanding trading contracts which we accounted for as derivatives:

	Quantity in		Estimated Market	Weighted Average
At June 30, 2011	Gallons		Prices	Contract Prices
Forward Contracts
Sale		9,240,000	$1.3900 – $1.5700	$	1.5005
Purchase		8,106,000	$1.3344 – $1.5850	$	1.4878

Estimated market prices and weighted average contract prices are in dollars per gallon.

All contracts expire during or prior to the first quarter of 2012.

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

Fair values of the derivative contracts recorded in the condensed consolidated balance sheet as of June 30, 2011 and December 31, 2010, are the following:

	Asset Derivatives
		Fair Value
(in thousands)	Balance Sheet Location	June 30, 2011		December 31, 2010
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy assets	$	335	$	1,642
Put option (1)	Mark-to-market energy assets		—		—
Total asset derivatives		$	335	$	1,642

	Liability Derivatives
		Fair Value
(in thousands)	Balance Sheet Location	June 30, 2011		December 31, 2010
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy liabilities	$	216	$	1,492
Total liability derivatives		$	216	$	1,492

(1) We purchased a put option for the Pro-Cap (propane price cap) Plan in October 2010. The put option, which expired in January and February 2011, had a fair value of $0 at December 31, 2010.

The effects of gains and losses from derivative instruments on the condensed consolidated statements of income are the following:

		Amount of Gain (Loss) on Derivatives:
	Location of Gain	For the Three Months Ended June 30,					For the Six Months Ended June 30,
(in thousands)	(Loss) on Derivatives	2011			2010		2011			2010
Derivatives not designated as hedging instruments:
Put Option(1) (2)	Cost of Sales	$	—		$	—	$	—		$	—
Unrealized gain on forward contracts	Revenue		(112	)		160		(30	)		374
Total		$	(112	)	$	160	$	(30	)	$	374

(1)	We purchased a put option for the Pro-Cap Plan in October 2010. The put option, which expired in January and February 2011, had a fair value of $0 at December 31, 2010.
(2)	We purchased a put option for the Pro-Cap Plan in September 2009. The put option, which expired on March 31, 2010, had a fair value of $0 at March 31, 2010.

The effects of trading activities on the condensed consolidated statements of income are the following:

	Location in the	Three months ended June 30,					Six months ended June 30,
(in thousands)	Statement of Income	2011			2010		2011			2010
Realized gains on forward contracts	Revenue	$	647		$	60	$	1,554		$	738
Changes in mark-to-market energy assets	Revenue		(112	)		160		(30	)		374
Total		$	535		$	220	$	1,524		$	1,112

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Summary of Accounting Policies

6 Months Ended

Jun. 30, 2011

Summary of Accounting Policies [Abstract]

Summary of Accounting Policies

1. Summary of Accounting Policies

Basis of Presentation

References in this document to the “Company,” “Chesapeake,” “we,” “us” and “our” are intended to mean the Registrant and its subsidiaries, or the Registrant’s subsidiaries, as appropriate in the context of the disclosure.

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and United States of America Generally Accepted Accounting Principles (“GAAP”). In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K filed with the SEC on March 8, 2011. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

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

We have assessed and reported on subsequent events through the date of issuance of these condensed consolidated financial statements.

Reclassifications

We reclassified certain amounts in the condensed consolidated statements of income for the three and six months ended June 30, 2010, and the condensed consolidated statement of cash flows for the six months ended June 30, 2010, to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.

Recent Accounting Amendments Yet to be Adopted by the Company

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.” Amendments in the ASU do not extend the use of fair value accounting, but provide guidance on how it should be applied where its use is already required or permitted by other standards within International Financial Accounting Standards (“IFRS”) or U.S. GAAP. ASU 2011-04 supersedes most of the guidance in Topic 820, although many of the changes are clarifications of existing guidance or wording changes to align with IFRS. Certain amendments in ASU 2011-04 change a particular principle or requirement for measuring fair value or disclosing information about fair value measurements. The amendments in ASU 2011-04 are effective for public entities for interim and annual periods beginning after December 15, 2011, and should be applied prospectively. Early adoption is not permitted for public entities. We expect the adoption of ASU 2011-04 to have no material impact on our financial position and results of operations.

In June 2011, the FASB issued ASU 2011-05, “Presentation of Comprehensive Income.” ASU 2011-05 amends the guidance in Topic 220 “Comprehensive Income,” by eliminating the option to present components of other comprehensive income in the statement of stockholders’ equity. Instead, the new guidance now requires entities to present all non-owner changes in stockholders’ equity either as a single continuous statement of comprehensive income or as two separate but consecutive statements. The components of other comprehensive income (“OCI”) have not changed nor has the guidance on when OCI items are reclassified to net income; however, the amendments require entities to present all reclassification adjustments from OCI to net income on the face of the statement of comprehensive income. Similarly, ASU 2011-05 does not change the guidance to disclose OCI components gross or net of the effect of income taxes, provided that the tax effects are presented on the face of the statement in which OCI is presented, or disclosed in the notes to the financial statements. For public entities, the amendments in ASU 2011-05 are effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2011. The amendments should be applied retrospectively, and early adoption is permitted. We plan on complying with the new OCI presentation at the end of 2011.

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Employee Benefit Plans

6 Months Ended

Jun. 30, 2011

Employee Benefit Plans [Abstract]

Employee Benefit Plans

7. Employee Benefit Plans

Net periodic benefit costs for our pension and post-retirement benefits plans for the three and six months ended June 30, 2011 and 2010 are set forth in the following table:

																	Chesapeake
	Chesapeake						FPU						Chesapeake				Postretirement				FPU
	Pension Plan						Pension Plan						SERP				Plan				Medical Plan
For the Three Months Ended June 30,	2011			2010			2011			2010			2011		2010		2011		2010		2011		2010
(in thousands)
Service Cost	$	—		$	—		$	—		$	—		$	—	$	—	$	—	$	—	$	27	$	27
Interest Cost		130			144			672			637			27		34		15		31		39		34
Expected return on plan assets		(101	)		(106	)		(684	)		(619	)		—		—		—		—		—		—
Amortization of prior service cost		(2	)		(2	)		—			—			5		5		—		—		—		—
Amortization of net loss		39			39			—			—			9		14		—		14		5		—
Net periodic cost (benefit)		66			75			(12	)		18			41		53		15		45		71		61
Amortization of pre-merger regulatory asset		—			—			191			190			—		—		—		—		2		2
Total periodic cost	$	66		$	75		$	179		$	208		$	41	$	53	$	15	$	45	$	73	$	63
																	Chesapeake
	Chesapeake						FPU						Chesapeake				Postretirement				FPU
	Pension Plan						Pension Plan						SERP				Plan				Medical Plan
For the Six Months Ended June 30,	2011			2010			2011			2010			2011		2010		2011		2010		2011		2010
(in thousands)
Service Cost	$	—		$	—		$	—		$	—		$	—	$	—	$	—	$	—	$	53	$	55
Interest Cost		260			289			1,343			1,275			54		68		30		61		78		68
Expected return on plan assets		(202	)		(212	)		(1,368	)		(1,238	)		—		—		—		—		—		—
Amortization of prior service cost		(3	)		(3	)		—			—			10		10		—		—		—		—
Amortization of net loss		78			78			—			—			19		30		—		29		10		—
Net periodic cost (benefit)		133			152			(25	)		37			83		108		30		90		141		123
Settlement expense		217			—			—			—			—		—		—		—		—		—
Amortization of pre-merger regulatory asset		—			—			381			507			—		—		—		—		4		5
Total periodic cost	$	350		$	152		$	356		$	544		$	83	$	108	$	30	$	90	$	145	$	128

We expect to record pension and postretirement benefit costs of approximately $1.9 million for 2011. Included in that amount is a pension settlement expense of $217,000 recorded during the first six months of 2011 related to a lump-sum pension distribution of $844,000 from the Chesapeake Pension Plan in January 2011 and $219,000 of settlement expense in July 2011 related to a lump-sum distribution from the Chesapeake SERP. Also included in that amount is $769,000 related to continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU’s regulated energy operations of the changes in funded status that occurred but were not recognized as part of net periodic benefit costs prior to the merger. This was deferred as a regulatory asset by FPU prior to the merger to be recovered through rates pursuant to a previous order by the Florida PSC. The unamortized balance of this regulatory asset was $6.3 million and $6.7 million at June 30, 2011 and December 31, 2010, respectively.

During the six months ended June 30, 2011, we contributed $68,000 to the Chesapeake pension plan. We also contributed $292,000 and $555,000 to the FPU pension plan during the three and six months ended June 30, 2011, respectively. We expect to contribute $955,000 and $1.3 million to the Chesapeake and FPU pension plans, respectively, during the year 2011.

The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake SERP for the three and six months ended June 30, 2011, were $22,000 and $45,000, respectively; for the year 2011, such benefits paid are expected to be approximately $853,000, which includes the expected lump-sum distribution of $765,000 as mentioned above. Cash benefits paid for the Chesapeake Postretirement Plan, primarily for medical claims for the three and six months ended June 30, 2011, totaled $22,000 and $47,000, respectively; for the year 2011, we have estimated that approximately $96,000 will be paid for such benefits. Cash benefits paid for the FPU Medical Plan, primarily for medical claims for the three and six months ended June 30, 2011, totaled $24,000 and $35,000, respectively; for the year 2011, we have estimated that approximately $158,000 will be paid for such benefits.

In connection with the lump-sum pension distribution from the Chesapeake Pension Plan in January 2011 and the Chesapeake SERP in July 2011, and related settlement accounting, we re-measured the assets and obligations of the Chesapeake Pension Plan. The assumptions used for the discount rate to calculate the benefit obligation remained unchanged at five percent. The average expected return on plan assets also did not change and remained at six percent.

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Long-Term Debt

6 Months Ended

Jun. 30, 2011

Long-Term Debt [Abstract]

Long-Term Debt

12. Long-Term Debt

Our outstanding long-term debt is shown below:

	June 30,			December 31,
(in thousands)	2011			2010
FPU secured first mortgage bonds (A):
9.57% bond, due May 1, 2018	$	6,346		$	7,248
10.03% bond, due May 1, 2018		3,490			3,986
9.08% bond, due June 1, 2022		7,956			7,950
Uncollateralized senior notes:
6.85% note, due January 1, 2012		1,000			1,000
7.83% note, due January 1, 2015		8,000			8,000
6.64% note, due October 31, 2017		19,091			19,091
5.50% note, due October 12, 2020		20,000			20,000
5.93% note, due October 31, 2023		30,000			30,000
5.68% note, due June 30, 2026		29,000			—
Convertible debentures:
8.25% due March 1, 2014		1,221			1,318
Promissory note		215			265
Total long-term debt		126,319			98,858
Less: current maturities		(9,196	)		(9,216	)
Total long-term debt, net of current maturities	$	117,123		$	89,642

(A) FPU secured first mortgage bonds are guaranteed by Chesapeake.

On June 23, 2011, we issued $29.0 million of 5.68 percent unsecured senior notes to Metropolitan Life Insurance Company and New England Life Insurance Company, pursuant to an agreement we entered into with them on June 29, 2010. These notes have similar covenants and default provisions as Chesapeake’s existing senior notes, and they require annual principal payments of $2.9 million beginning in the sixth year after the issuance. We used the proceeds to permanently finance the redemption of the 6.85 percent and 4.90 percent series of FPU first mortgage bonds. These redemptions occurred in January 2010 and were previously financed by Chesapeake’s short-term loan facilities. Under the same agreement, we may issue an additional $7.0 million of unsecured senior notes prior to May 3, 2013, at a rate ranging from 5.28 percent to 6.43 percent based on the timing of the issuance. These notes, if issued, will have similar covenants and default provisions as the senior notes issued in June 2011.

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Investments

6 Months Ended

Jun. 30, 2011

Investments [Abstract]

Investments

8. Investments

The investment balance at June 30, 2011, represents: (a) a Rabbi Trust associated with our Supplemental Executive Retirement Savings Plan, (b) a Rabbi Trust related to a stay bonus agreement with a former executive, and (c) investments in equity securities. We classify these investments as trading securities and report them at their fair value. Any unrealized gains and losses, net of other expenses, are included in other income in the condensed consolidated statements of income. We also have recorded an associated liability that is adjusted each month for the gains and losses incurred by the Rabbi Trusts. At June 30, 2011 and December 31, 2010, total investments had a fair value of $4.1 million and $4.0 million, respectively.

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Segment Information

6 Months Ended

Jun. 30, 2011

Segment Information [Abstract]

Segment Information

6. Segment Information

We use the management approach to identify operating segments. We organize our business around differences in regulatory environment and/or products or services, and the operating results of each segment are regularly reviewed by the chief operating decision maker (our Chief Executive Officer) in order to make decisions about resources and to assess performance. The segments are evaluated based on their pre-tax operating income. Our operations comprise three operating segments:

• Regulated Energy. The regulated energy segment includes natural gas distribution, electric distribution and natural gas transmission operations. All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of Eastern Shore.

• Unregulated Energy. The unregulated energy segment includes natural gas marketing, propane distribution and propane wholesale marketing operations, which are unregulated as to their rates and charges for their services.

• Other. The “other” segment consists primarily of the advanced information services operation, unregulated subsidiaries that own real estate leased to Chesapeake and certain corporate costs not allocated to other operations.

The following table presents information about our reportable segments.

	Three Months Ended						Six Months Ended
For the Perionds Ended June 30,	2011			2010			2011			2010
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	54,011		$	52,543		$	138,695		$	143,845
Unregulated Energy		29,692			24,494			88,442			83,521
Other		3,128			3,024			6,292			5,955
Total operating revenues, unaffiliated customers	$	86,831		$	80,061		$	233,429		$	233,321
Intersegment Revenues (1)
Regulated Energy	$	316		$	197		$	634		$	522
Unregulated Energy		—			121			—			364
Other		195			259			389			447
Total intersegment revenues	$	511		$	577		$	1,023		$	1,333
Operating Income
Regulated Energy	$	7,863		$	8,308		$	24,171		$	25,824
Unregulated Energy		4			(791	)		8,518			6,969
Other and eliminations		(91	)		244			(74	)		366
Total operating income		7,776			7,761			32,615			33,159
Other income, net of other expenses		27			(11	)		50			103
Interest		2,114			2,305			4,265			4,667
Income taxes		2,169			2,105			11,133			11,281
Net income	$	3,520		$	3,340		$	17,267		$	17,314

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

	June 30,		December 31,
(in thousands)	2011		2010
Identifiable Assets
Regulated energy	$	517,737	$	520,192
Unregulated energy		111,357		113,039
Other		31,395		37,762
Total identifiable assets	$	660,489	$	670,993

Our operations are almost entirely domestic. Our advanced information services subsidiary, BravePoint, has infrequent transactions in foreign countries, primarily Canada, which are denominated and paid in U.S. dollars. These transactions are immaterial to the consolidated revenues.

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Condensed Consolidated Statements of Stockholders' Equity (Unaudited) (USD $) In Thousands, except Share data		Total	Common Stock	Additional Paid-In Capital	Retained Earnings	Accumulated Other Comprehensive Loss	Deferred Compensation	Treasury Stock
Balance at Dec. 31, 2009		$ 209,781	$ 4,572	$ 144,502	$ 63,231	$ (2,524)	$ 739	$ (739)
Balance, shares at Dec. 31, 2009	[1]		9,394,314
Net Income		26,056			26,056
Employee Benefit Plans, net of tax:
Amortization of prior service costs (4)	[2]	8				8
Net Gain (Loss) (5)	[3]	(844)				(844)
Total comprehensive income		25,220
Dividend Reinvestment Plan, shares	[1]		53,806
Dividend Reinvestment Plan		1,725	26	1,699
Retirement Savings Plan, shares	[1]		27,795
Retirement Savings Plan		903	14	889
Conversion of debentures, shares	[1]		11,865
Conversion of debentures		202	6	196
Tax benefit on share based compensation		253		253
Share based compensation (1)(3), shares	[1][4][5]		36,415
Share based compensation (1)(3)	[4][5]	637	17	620
Deferred Compensation Plan							38	(38)
Purchase of treasury stock, shares	[1]		(1,144)
Purchase of treasury stock		(38)						(38)
Sale and distribution of treasury stock, shares	[1]		1,144
Sale and distribution of treasury stock		38						38
Dividends on stock-based compensation		(104)			(104)
Cash dividends (2)	[6]	(12,378)			(12,378)
Balance at Dec. 31, 2010		226,239	4,635	148,159	76,805	(3,360)	777	(777)
Balance, shares at Dec. 31, 2010	[1]		9,524,195
Net Income		17,267			17,267
Employee Benefit Plans, net of tax:
Amortization of prior service costs (4)	[2]	4				4
Net Gain (Loss) (5)	[3]	357				357
Total comprehensive income		17,628
Dividend Reinvestment Plan		(11)		(11)
Retirement Savings Plan, shares	[1]		2,002
Retirement Savings Plan		80	1	79
Conversion of debentures, shares	[1]		5,691
Conversion of debentures		97	3	94
Share based compensation (1)(3), shares	[1][4][5]		30,430
Share based compensation (1)(3)	[4][5]	490	15	475
Deferred Compensation Plan							19	(19)
Purchase of treasury stock, shares	[1]		(473)
Purchase of treasury stock		(19)						(19)
Sale and distribution of treasury stock, shares	[1]		473
Sale and distribution of treasury stock		19						19
Dividends on stock-based compensation		(73)			(73)
Cash dividends (2)	[6]	(6,450)			(6,450)
Balance at Jun. 30, 2011		$ 238,000	$ 4,654	$ 148,796	$ 87,549	$ (2,999)	$ 796	$ (796)
Balance, shares at Jun. 30, 2011	[1]		9,562,318

[1] Includes 30,078 and 29,596 shares at June 30, 2011 and December 31, 2010, respectively, held in a Rabbi Trust established by the Company relating to the Deferred Compensation Plan.

[2] Tax expense recognized on the prior service cost component of employees benefit plans for the periods ended June 30, 2011 and December 31, 2010 were approximately $3 and $5, respectively.

[3] Tax expense (benefit) recognized on the net gain (loss) component of employees benefit plans for the periods ended June 30, 2011 and December 31, 2010, were $239 and ($541), respectively.

[4] Includes amounts for shares issued for Directors' compensation.

[5] The shares issued under the Performance Incentive Plan ("PIP") are net of shares withheld for employee taxes. For the periods ended June 30, 2011 and December 31, 2010 the Company withheld 12,324 and 17,695 shares, respectively, for taxes.

[6] Cash dividends declared per share for the periods ended June 30, 2011 and December 31, 2010 were $0.675 and $1.305, respectively.

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Calculation of Earnings Per Share

6 Months Ended

Jun. 30, 2011

Calculation of Earnings Per Share [Abstract]

Calculation of Earnings Per Share

2. Calculation of Earnings Per Share

	Three Months				Six Months
For the Periods Ended June 30,	2011		2010		2011		2010
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	3,520	$	3,340	$	17,267	$	17,314
Weighted average shares outstanding		9,557,707		9,467,222		9,546,606		9,443,708
Basic Earnings Per Share	$	0.37	$	0.35	$	1.81	$	1.83
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	3,520	$	3,340	$	17,267	$	17,314
Effect of 8.25% Convertible debentures		15		19		31		37
Adjusted numerator — Diluted	$	3,535	$	3,359	$	17,298	$	17,351
Reconciliation of Denominator:
Weighted shares outstanding — Basic		9,557,707		9,467,222		9,546,606		9,443,708
Effect of dilutive securities:
Share-based Compensation		20,699		3,347		21,958		19,437
8.25% Convertible debentures		72,481		86,783		73,810		87,525
Adjusted denominator — Diluted		9,650,887		9,557,352		9,642,374		9,550,670
Diluted Earnings Per Share	$	0.37	$	0.35	$	1.79	$	1.82

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Rates and Other Regulatory Activities

6 Months Ended

Jun. 30, 2011

Rates and Other Regulatory Activities [Abstract]

Rates and Other Regulatory Activities

3. Rates and Other Regulatory Activities

Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective Public Service Commission (“PSC”); Eastern Shore Natural Gas Company (“Eastern Shore”), our natural gas transmission operation, is subject to regulation by the Federal Energy Regulatory Commission (“FERC”); and Peninsula Pipeline Company, Inc. (“Peninsula Pipeline”) is subject to regulation by the Florida Public Service Commission (“Florida PSC”). Chesapeake’s Florida natural gas distribution division and the natural gas and electric distribution operations of Florida Public Utilities Company (“FPU”) continue to be subject to regulation by the Florida PSC as separate entities.

Delaware

Capacity Release: On September 2, 2008, our Delaware division filed with the Delaware Public Service Commission (“Delaware PSC”) its annual Gas Sales Service Rates (“GSR”) Application, seeking approval to change its GSR, effective November 1, 2008. On July 7, 2009, the Delaware PSC granted approval of a settlement agreement presented by the parties in this docket, which included the Delaware PSC, our Delaware division and the Division of the Public Advocate. As part of the settlement agreement, the parties agreed to develop a record in a later proceeding on the price charged by the Delaware division for the temporary release of transmission pipeline capacity to our natural gas marketing subsidiary, Peninsula Energy Services Company, Inc. (“PESCO”). On January 8, 2010, the Hearing Examiner in this proceeding issued a report of Findings and Recommendations in which he recommended, among other things, that the Delaware PSC require the Delaware division to refund to its firm service customers the difference between what the Delaware division would have received had the capacity released to PESCO been priced at the maximum tariff rates under asymmetrical pricing principles and the amount actually received by the Delaware division for capacity released to PESCO. The Hearing Examiner also recommended that the Delaware PSC require us to adhere to asymmetrical pricing principles in all future capacity releases by the Delaware division to PESCO, if any. If the Hearing Examiner’s refund recommendation for past capacity releases were ultimately approved without modification by the Delaware PSC, the Delaware division would have to credit to its firm service customers amounts equal to the maximum tariff rates that the Delaware division pays for long-term capacity, which we estimated to be approximately $700,000, even though the temporary releases were made at lower rates based on competitive bidding procedures required by the FERC’s capacity release rules. On February 18, 2010, we filed exceptions to the Hearing Examiner’s recommendations.

At the hearing on March 30, 2010, the Delaware PSC agreed with us that the Delaware division had been releasing capacity based on a previous settlement approved by the Delaware PSC and, therefore, did not require the Delaware division to issue any refunds for past capacity releases. The Delaware PSC, however, required the Delaware division to adhere to asymmetrical pricing principles for future capacity releases to PESCO until a more appropriate pricing methodology is developed and approved. The Delaware PSC issued an order on May 18, 2010, elaborating its decisions at the March hearing and directing the parties to reconvene in a separate docket to determine if a pricing methodology other than asymmetrical pricing principles should apply to future capacity releases by the Delaware division to PESCO.

On June 17, 2010, the Division of the Public Advocate filed an appeal with the Delaware Superior Court, asking it to overturn the Delaware PSC’s decision with regard to refunds for past capacity releases. On June 28, 2010, the Delaware division filed a Notice of Cross Appeal with the Delaware Superior Court, asking it to overturn the Delaware PSC’s decision with regard to requiring the Delaware division to adhere to asymmetrical pricing principles for future capacity releases to PESCO. On June 13, 2011, the Delaware Superior Court issued its decision affirming all aspects of the Delaware PSC’s Order of May 18^th, 2010, which included its decision not to require the Delaware division to issue any refunds for past releases.

On June 29, 2011, the Delaware Attorney General filed an appeal with the Delaware Supreme Court, asking it to review the Delaware Superior Court’s decision affirming the Delaware PSC decision with regard to refunds for past capacity releases. The Delaware Attorney General was substituted in the case for the Division of the Public Advocate in the period between when the former Public Advocate retired and a new Public Advocate was appointed by the Governor. On July 12, 2011, the Delaware division filed a Notice of Cross Appeal with the Delaware Supreme Court, asking it to overturn the Superior Court’s decision with regard to the Delaware PSC’s decision on future capacity releases to PESCO. We have not accrued any contingent liability related to potential refunds for past capacity releases. We anticipate that the Delaware Supreme Court will render a decision sometime in the first half of 2012. In addition, due to the ongoing legal proceedings, the parties have not yet opened a separate docket to determine an alternative pricing methodology for future capacity releases. Since the Delaware PSC’s Order on May 18, 2010, the Delaware division has not released any capacity to PESCO.

Chesapeake’s Delaware division also had developments in the following matters with the Delaware PSC:

On September 1, 2010, the Delaware division filed with the Delaware PSC its annual GSR Application, seeking approval to change its GSR, effective November 1, 2010. On September 21, 2010, the Delaware PSC authorized the Delaware division to implement the GSR charges on November 1, 2010, on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. The Delaware PSC granted approval of the GSR charges at its regularly scheduled meeting on June 7, 2011.

On March 10, 2011, the Delaware division filed with the Delaware PSC an application requesting approval to guarantee certain debt of FPU. Specifically, the Delaware division sought approval to execute a Seventeenth Supplemental Indenture, in which Chesapeake guarantees the payment of certain debt of FPU and FPU is permitted to deliver Chesapeake’s consolidated financial statements in lieu of FPU’s stand-alone financial statements to satisfy certain covenants within the indentures of FPU’s debt. The Delaware PSC granted approval of the guarantee of certain debt of FPU at its regularly scheduled meeting on April 4, 2011.

Maryland

On December 14, 2010, the Maryland Public Service Commission (“Maryland PSC”) held an evidentiary hearing to determine the reasonableness of the four quarterly gas cost recovery filings submitted by the Maryland division during the 12 months ended September 30, 2010. No issues were raised at the hearing, and on December 20, 2010, the Hearing Examiner in this proceeding issued a proposed Order approving the division’s four quarterly filings. This proposed Order became a final Order of the Maryland PSC on January 20, 2011.

On March 2, 2011, the Maryland division filed with the Maryland PSC an application for the approval of a franchise executed between the Maryland division and the Board of County Commissioners of Cecil County, Maryland. In this franchise agreement, the County granted the Maryland division a 50-year, non-exclusive, franchise to construct and operate natural gas distribution facilities within the present and future jurisdictional boundaries of Cecil County. On April 11, 2011, the Maryland PSC issued an Order approving the franchise between the Maryland division and Cecil County, subject to no adverse comments being received within 30 days after the issuance of the Order. On May 10, 2011, comments opposing the application were filed by Pivotal Utility Holdings, Inc. d/b/a Elkton Gas (“Pivotal”). Pivotal also provides natural gas service to customers in a portion of Cecil County. On June 8, 2011, the Maryland PSC granted the Maryland division the authority to exercise its franchise in a majority of the area requested in the Maryland division’s application. The approval for a small portion of the area within the requested franchise area, which is closest to the area served by Pivotal, has been withheld until an evidentiary hearing is convened. It is anticipated that the Maryland PSC will render a decision on the remaining area in the fourth quarter of 2011 or the first quarter of 2012.

On May 17, 2011, the Maryland division filed with the Maryland PSC an application for the approval of a franchise executed between the Maryland division and the Board of County Commissioners for Worcester County, Maryland. In this franchise agreement, the County granted the Maryland division a 25-year, non-exclusive, franchise to construct and operate natural gas distribution facilities within the present and future jurisdictional boundaries of Worcester County. On June 14, 2011, the Maryland PSC issued an Order approving the franchise between the Maryland division and Worcester County, subject to no adverse comments being received within 20 days after the issuance of the Order. No adverse comments were filed within the comment period and the order became effective on July 5, 2011.

Florida

“Come-Back” Filing: As part of our rate case settlement in Florida in 2010, the Florida PSC required us to submit a “Come-Back” filing, detailing all known benefits, synergies, cost savings and cost increases resulting from the merger with FPU. We submitted this filing on April 29, 2011. We are requesting the recovery, through rates, of approximately $34.2 million in acquisition adjustment (the price paid in excess of the book value) and $2.2 million in merger-related costs. In the past, the Florida PSC has allowed recovery of an acquisition adjustment under certain circumstances to provide an incentive for larger utilities to purchase smaller utilities. The Florida PSC requires a company seeking recovery of the acquisition adjustment and merger-related costs to demonstrate that customers will benefit from the acquisition. They use the following five factors to determine if the customers are benefiting from the transaction: (a) increased quality of service; (b) lower operating costs; (c) increased ability to attract capital for improvements; (d) lower overall cost of capital; and (e) more professional and experienced managerial, financial, technical and operational resources. With respect to lower costs, the Florida PSC effectively requires that the synergies be sufficient to offset the rate impact of the recovery of the acquisition adjustment and merger-related costs. The Florida PSC’s decision on our request for recovery of the acquisition adjustment and merger-related costs is expected in the fourth quarter of 2011.

If the Florida PSC approves recovery of the acquisition adjustment and merger-related costs, we would be able to classify these amounts as regulatory assets and include them in our investment, or rate base, when determining our Florida natural gas rates. Additionally, we would calculate our rate of return based upon this higher level of investment which effectively enables us to earn a return on this investment. We would also be able to amortize the acquisition adjustment and merger-related costs over 30 and five years, respectively. Amortization expense would be included in the calculation of our rates.

Our earnings may be reduced by as much as $1.6 million annually for the amortization expense (approximately $1.3 million is non-tax-deductible) until 2014 and $1.1 million annually (non-tax deductible) thereafter until 2039. This amortization expense would be a non-cash charge, and the net effect of the recovery would be positive cash flow. Over the long-term, however, the inclusion of the acquisition adjustment and merger-related costs in our rate base and the recovery of these regulatory assets through amortization expense will increase our earnings and cash flows above what we would have otherwise been able to achieve.

If the Florida PSC does not allow recovery of the acquisition adjustment and merger-related costs, there is some likelihood that we would have to reduce rates in the State of Florida, which would adversely affect our future earnings.

We continue to maintain a $750,000 accrual, which was recorded in 2010 based on management’s assessment of FPU’s earnings and regulatory risk to its earnings associated with possible Florida PSC action related to our requested recovery and the matters set forth in this filing.

Marianna Franchise: On July 7, 2009, the City Commission of Marianna, Florida (“Marianna Commission”) adopted an ordinance granting a franchise to FPU effective February 1, 2010 for a period not to exceed 10 years for the operation and distribution and/or sale of electric energy (the “Franchise Agreement”). The Franchise Agreement provides that FPU will develop and implement new time-of-use (“TOU”) and interruptible electric power rates mutually agreeable to FPU and the City of Marianna. The Franchise Agreement further provides for the TOU and interruptible rates to be effective no later than February 17, 2011, and available to all customers within the corporate limits of the City of Marianna. If the rates were not in effect by February 17, 2011, the City of Marianna would have the right to give notice to FPU within 180 days thereafter of its intent to exercise its option to purchase FPU’s property (consisting of the electric distribution assets) within the City of Marianna. Any such purchase would be subject to approval by the Marianna Commission, which would also need to approve the presentation of a referendum to voters in the City of Marianna for the approval of the purchase and the operation by the City of Marianna of an electric distribution facility. If the purchase is approved by the Marianna Commission and by the referendum, the closing of the purchase must occur within 12 months after the referendum is approved. If the City of Marianna elects to purchase the Marianna property, the Franchise Agreement requires the City of Marianna to pay FPU the fair market value for such property as determined by three qualified appraisers. Future financial results would be negatively affected by the loss in earnings generated by FPU from its approximately 3,000 customers in the City under the Franchise Agreement.

In accordance with the terms of the Franchise Agreement, FPU developed reasonable TOU and interruptible rates and on December 14, 2010, FPU filed a petition with the Florida PSC for authority to implement such proposed TOU and interruptible rates on or before February 17, 2011. On February 11, 2011, the Florida PSC issued an Order approving FPU’s petition for authority to implement the proposed TOU and interruptible rates, which became effective on February 8, 2011. The City of Marianna has objected to the proposed rates and has filed a petition protesting the entry of the Florida PSC’s Order. On March 17, 2011, FPU filed a Motion to Dismiss the petition by the City of Marianna and requested oral argument. On June 14, 2011, the Florida PSC granted FPU’s request for oral argument and on July 5, 2011, issued an Order approving FPU’s Motion to Dismiss the protest by the City of Marianna, without prejudice. On July 25, 2011, the City of Marianna filed an amended petition protesting the entry of the Florida PSC’s Order.

On January 26, 2011, FPU filed a petition with the Florida PSC for approval of an amendment to FPU’s Generation Services Agreement entered into between FPU and Gulf Power Corporation (“Gulf Power”). The amendment provides for a reduction in the capacity demand quantity, which generates the savings necessary to support the TOU and interruptible rates approved by the Florida PSC. The amendment also extends the current agreement by two years, with a new expiration date of December 31, 2019. Pursuant to its Order dated June 21, 2011, the Florida PSC approved the amendment. On July 12, 2011, the City of Marianna filed a protest of this decision and requested a hearing on the amendment.

On April 7, 2011, FPU filed a petition for approval of a mid-course reduction to its Northwest Division fuel rates based on two factors: 1) the previously discussed amendment to the Generation Services Agreement with Gulf Power; and 2) a weather-related increase in sales resulting in an accelerated collection of prior year’s under-recovered costs. Pursuant to its Order dated July 5, 2011, the Florida PSC approved the petition, which is projected to reduce customers’ fuel rates by approximately 10 percent per month.

As disclosed in Note 5, “Other Commitments and Contingencies,” to the unaudited condensed consolidated financial statements, the City of Marianna, on March 2, 2011, filed a complaint against FPU in the Circuit Court of the Fourteenth Judicial Circuit in and for Jackson County, Florida, alleging breaches of the Franchise Agreement by FPU and seeking a declaratory judgment that the City of Marianna has the right to exercise its option to purchase FPU’s property in the City of Marianna in accordance with the terms of the Franchise Agreement. On March 28, 2011, FPU filed its answer to the declaratory action by the City of Marianna, in which it denied the material allegation by the City of Marianna and asserted several affirmative defenses.

Eastern Shore

The following are regulatory activities involving FERC Orders applicable to Eastern Shore and the expansions of Eastern Shore’s transmission system:

Energylink Expansion Project: In 2006, Eastern Shore proposed to develop, construct and operate approximately 75 miles of new pipeline facilities from the existing Cove Point Liquefied Natural Gas terminal in Calvert County, Maryland, crossing under the Chesapeake Bay into Dorchester and Caroline Counties, Maryland, to points on the Delmarva Peninsula, where such facilities would interconnect with Eastern Shore’s existing facilities in Sussex County, Delaware. In April 2009, Eastern Shore terminated this project based on increased construction costs over its original projection. As approved by the FERC, Eastern Shore initiated billing to recover approximately $3.2 million of costs incurred in connection with this project and the related cost of capital over a period of 20 years in accordance with the terms of the precedent agreements executed with the two participating customers. One of the two participating customers is Chesapeake, through its Delaware and Maryland divisions. During 2010, Eastern Shore and the participating customers negotiated to reduce the recovery period of this cost from 20 years to five years. On January 27, 2011, Eastern Shore filed with the FERC the request to amend the cost recovery period, which was approved by the FERC on February 14, 2011. Eastern Shore revised its billing to reflect the five-year surcharge effective March 1, 2011.

Rate Case Filing: On December 30, 2010, Eastern Shore filed with the FERC a base rate proceeding in compliance with the terms of the settlement in its prior base rate proceeding. The rate filing reflects increases in operating and maintenance expenses, depreciation expense, and a return on existing and new gas plant facilities expected to be placed into service before June 30, 2011. The FERC issued a notice of the filing on January 3, 2011. Protests were received from several interested parties, and other parties intervened in the proceeding. On January 31, 2011, the FERC issued its Order accepting the filing and suspending its effectiveness for the full five-month period permitted under the Natural Gas Act. The discovery process commenced on February 22, 2011, and FERC Staff performed an on-site audit on March 16-17, 2011. Settlement conferences involving Eastern Shore, FERC Staff and other interested parties were held beginning in April and have extended through early August 2011. Eastern Shore expects the base rate proceeding to be resolved in 2011.

Mainline Extension Project: On April 1, 2011, Eastern Shore filed a notice of its intent under its blanket certificate to construct, own and operate new mainline facilities to deliver additional firm service of 3,405 Dekatherms per day (“Dts/d”) of natural gas to an existing industrial customer. The FERC published notice of this filing on April 7, 2011. The 60-day comment period subsequent to the FERC notice expired on June 6, 2011, and the requested authorization became effective on that date. Construction is expected to commence during the third quarter of 2011.

On April 28, 2011, Eastern Shore filed a notice of its intent under its blanket certificate to construct, own and operate new mainline facilities to deliver additional firm service of 6,250 Dts/d of natural gas to Chesapeake’s Delaware and Maryland divisions and Eastern Shore Gas, an unaffiliated provider of piped propane service in Maryland. The FERC published notice of this filing on May 12, 2011 and one of Eastern Shore’s customers filed a conditional protest with the FERC, which it withdrew on July 29, 2011. Upon withdrawal of the protest, the requested authorization became effective.

Also on April 28, 2011, Eastern Shore filed a notice of its intent under its blanket certificate to construct, own and operate new mainline facilities to deliver additional firm service of 4,070 Dts/d of natural gas to Chesapeake’s Maryland division to provide new natural gas service in Cecil County, Maryland. The FERC published notice of this filing on May 12, 2011 and one of Eastern Shore’s customers filed a conditional protest with the FERC, which it withdrew on July 29, 2011. Upon withdrawal of the protest, the requested authorization became effective.

Eastern Shore also had developments in the following FERC matters:

On March 7, 2011, Eastern Shore filed certain tariff sheets to amend the creditworthiness provisions contained in its FERC Gas Tariff. On April 6, 2011, the FERC issued an Order accepting and suspending Eastern Shore’s filed tariff revisions for an effective date of April 1, 2011, subject to Eastern Shore submitting certain clarifications with regard to several proposed revisions.

On April 18, 2011, Eastern Shore submitted its annual Interruptible Revenue Sharing Report to the FERC. Eastern Shore reported in this filing that its interruptible revenue did not exceed its annual threshold amount, which would trigger sharing of excess interruptible revenues with its firm service customers. Consequently, Eastern Shore is not required to refund to its firm customers any portion of its interruptible revenue received for the period April 2010 through March 2011.

On June 24, 2011, Eastern Shore filed certain tariff sheets to amend the General Terms and Conditions and the Firm Transportation Service Agreement contained in its FERC Gas Tariff to allow for specification of minimum delivery pressures and maximum hourly quantity. The FERC published the notice of this filing on June 27, 2011, and no protests or adverse comments opposing this filing were submitted. On July 15, 2011, the FERC issued a Letter Order, accepting the tariff revisions as proposed, effective July 24, 2011.

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Fair Value of Financial Instruments

6 Months Ended

Jun. 30, 2011

Fair Value of Financial Instruments [Abstract]

Fair Value of Financial Instruments

11. Fair Value of Financial Instruments

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

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

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

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

The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy used at June 30, 2011:

			Fair Value Measurements Using:
					Significant Other		Significant
			Quoted Prices in		Observable		Unobservable
			Active Markets		Inputs		Inputs
(in thousands)	Fair Value		(Level 1)		(Level 2)		(Level 3)
Assets:
Investments — equity securities	$	1,705	$	1,705	$	—	$	—
Investments — other	$	2,404	$	2,404	$	—	$	—
Mark-to-market energy assets	$	335	$	—	$	335	$	—
Liabilities:
Mark-to-market energy liabilities	$	216	$	—	$	216	$	—

The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy used at December 31, 2010:

	Fair Value Measurements Using:
					Significant Other		Significant
			Quoted Prices in		Observable		Unobservable
			Active Markets		Inputs		Inputs
(in thousands)	Fair Value		(Level 1)		(Level 2)		(Level 3)
Assets:
Investments — equity securities	$	1,515	$	1,515	$	—	$	—
Investments — other	$	2,521	$	2,521	$	—	$	—
Mark-to-market energy assets, including put option	$	1,642	$	—	$	1,642	$	—
Liabilities:
Mark-to-market energy liabilities	$	1,492	$	—	$	1,492	$	—

The following valuation techniques were used to measure fair value assets in the table above on a recurring basis as of June 30, 2011 and December 31, 2010:

Level 1 Fair Value Measurements:

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

Investments- other – The fair values of these investments, comprised of money market and mutual funds, are recorded at fair value based on quoted net asset values of the shares.

Level 2 Fair Value Measurements:

Mark-to-market energy assets and liabilities — These forward contracts are valued using market transactions in either the listed or over the counter (“OTC”) markets.

Propane put option — The fair value of the propane put option is determined using market transactions for similar assets and liabilities in either the listed or OTC markets.

At June 30, 2011, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.

Other Financial Assets and Liabilities

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

At June 30, 2011, long-term debt, which includes the current maturities of long-term debt, had a carrying value of $126.3 million, compared to a fair value of $145.0 million, using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, with adjustments for duration, optionality, and risk profile. At December 31, 2010, long-term debt, including the current maturities, had a carrying value of $98.9 million, compared to the estimated fair value of $113.4 million.

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Environmental Commitments and Contingencies

6 Months Ended

Jun. 30, 2011

Environmental Commitments and Contingencies [Abstract]

Environmental Commitments and Contingencies

4. Environmental Commitments and Contingencies

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

We have participated in the investigation, assessment or remediation, and have certain exposures at six former Manufactured Gas Plant (“MGP”) sites. Those sites are located in Salisbury, Maryland, and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the Maryland Department of the Environment (“MDE”) regarding a seventh former MGP site located in Cambridge, Maryland.

As of June 30, 2011, we had approximately $11.2 million in environmental liabilities related to all of FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites, representing our estimate of the future costs associated with those sites. FPU has approval to recover up to $14.0 million of its environmental costs related to all of its MGP sites from insurance and from customers through rates. Approximately $8.1 million of FPU’s expected environmental costs have been recovered from insurance and customers through rates as of June 30, 2011. We also had approximately $5.9 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

West Palm Beach, Florida

Remedial options are being evaluated to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West Palm Beach, Florida, where FPU previously operated an MGP. Pursuant to a Consent Order between FPU and the Florida Department of Environmental Protection (“FDEP”), effective April 8, 1991, FPU is required to complete the delineation of soil and groundwater impacts at the site, and implement an effective remedy.

On June 30, 2008, FPU transmitted to the FDEP a revised feasibility study, evaluating appropriate remedies for the site. This revised feasibility study evaluated a wide range of remedial alternatives based on criteria provided by applicable laws and regulations. On April 30, 2009, the FDEP issued a remedial action order, which it subsequently withdrew. In response to the Order and as a condition to its withdrawal, FPU committed to perform additional field work in 2009 and complete an additional engineering evaluation of certain remedial alternatives. The scope of this work has increased in response to FDEP’s requests for additional information.

FPU performed additional field work in August 2010, which included the installation of additional groundwater monitoring wells and performance of a comprehensive groundwater sampling event. FPU also performed vapor intrusion sampling in October 2010. The results of the field work were submitted to FDEP for their review and comment in October 2010. On November 4, 2010, FDEP issued its comments on the feasibility study and the proposed remedy.

On November 16, 2010, FPU presented to FDEP a new remedial action plan for the site, and FDEP agreed with FPU’s proposal to implement a phased approach to remediation. On December 22, 2010, FPU submitted to FDEP an interim Remedial Action Plan (“RAP”) to remediate the east parcel of the site, which FDEP conditionally approved on February 4, 2011. Subsequent modifications to the interim RAP, dated March 12, 2011 and April 18, 2011, were submitted to address potential concerns raised by FDEP. An Approval Order for the interim RAP was issued by FDEP on May 2, 2011, and subsequently modified by FDEP on May 18, 2011.

FPU is currently implementing the interim RAP for the east parcel of the West Palm Beach site, including the incorporation of FDEP’s conditions for approval. The operations on the east parcel have been relocated, and the structures removed. New monitoring wells and Air Sparging and Soil-Vapor Extraction (“AS/SVE”) test wells were installed on the east parcel in May of 2011. The initial round of SVE and sparging pilot testing was completed in July of 2011 and the results of the testing are currently being analyzed.

Estimated costs of remediation for the West Palm Beach site range from approximately $4.9 million to $13.1 million. This estimate does not include any costs associated with relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties.

We continue to expect that all costs related to these activities will be recoverable from customers through rates.

Sanford, Florida

FPU is the current owner of property in Sanford, Florida, which was a former MGP site that was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of the MGP. In late September 2006, the United States Environmental Protection Agency (“EPA”) sent a Special Notice Letter, notifying FPU, and the other responsible parties at the site (Florida Power Corporation, Florida Power & Light Company, Atlanta Gas Light Company, and the city of Sanford, Florida, collectively with FPU, “the Sanford Group”), of EPA’s selection of a final remedy for OU1 (soils), OU2 (groundwater), and OU3 (sediments) for the site. The EPA projected the total estimated remediation costs for this site to be approximately $12.9 million.

In January 2007, FPU and other members of the Sanford Group signed a Third Participation Agreement, which provides for funding the final remedy approved by EPA for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13 million, or $650,000. As of June 30, 2011, FPU has paid $650,000 to the Sanford Group escrow account for its share of the funding requirements.

The Sanford Group, EPA and the U.S. Department of Justice agreed to a Consent Decree in March 2008, which was entered by the Federal Court in Orlando, Florida on January 15, 2009. The Consent Decree obligates the Sanford Group to implement the remedy approved by EPA for the site. The total cost of the final remedy is now estimated at approximately $18 million. FPU has advised the other members of the Sanford Group that it is unwilling at this time to agree to pay any sum in excess of the $650,000 committed by FPU in the Third Participation Agreement.

Several members of the Sanford Group have concluded negotiations with two adjacent property owners to resolve damages that the property owners allege they have and will incur as a result of the implementation of the EPA-approved remediation. In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third-party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third-party claims.

As of June 30, 2011, FPU’s remaining share of remediation expenses, including attorneys’ fees and costs, is estimated to be $20,000. However, we are unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept FPU’s asserted defense to liability for costs exceeding $13.0 million to implement the final remedy for this site or will pursue a claim against FPU for a sum in excess of the $650,000 that FPU has paid under the Third Participation Agreement. No such claims have been made as of June 30, 2011.

Key West, Florida

FPU formerly owned and operated an MGP in Key West, Florida. Field investigations performed in the 1990s identified limited environmental impacts at the site, which is currently owned by an unrelated third party. In September 2010, FDEP issued a Preliminary Contamination Assessment Report, for additional soil and groundwater investigation work that was undertaken by FDEP in November 2009 and January 2010, after 17 years of regulatory inactivity. Because FDEP observed that some soil and groundwater standards were exceeded, FDEP is requesting implementation of additional fieldwork which FDEP believes is warranted for the site.

FPU and the current site owner have had several discussions regarding the approach to be taken with FDEP and the proposed scope of work. Representatives of FPU, FDEP and the current site owner participated in a teleconference on July 7, 2011. During that call, the scope of work was tentatively agreed upon, and FDEP agreed to proceed without using a consent order. FPU and the current site owner will submit a work plan and schedule to FDEP in August of 2011. Total potential costs for investigation and remediation are projected to be $153,000.

Pensacola, Florida

FPU formerly owned and operated an MGP in Pensacola, Florida, which was subsequently owned by Gulf Power. Portions of the site are now owned by the City of Pensacola and the Florida Department of Transportation (“FDOT”). In October 2009, FDEP informed Gulf Power that FDEP would approve a conditional No Further Action (“NFA”) determination for the site, which must include a requirement for institutional and engineering controls. On November 9, 2010, an NFA Proposal was submitted to FDEP, along with a draft restrictive covenant for that portion of the property currently owned by FDOT. FPU, FDOT and the City of Pensacola are working together to obtain a restrictive covenant that is acceptable to FDEP to complete closure of the site, and it is anticipated that no further monitoring will be required on the site. FPU’s total remaining consulting and remediation costs for this site are projected to be $5,000.

In addition, we had $284,000 in environmental liabilities at June 30, 2011, related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of future costs associated with these sites. As of June 30, 2011, we had approximately $1.2 million in regulatory and other assets for future recovery through rates. The following discussion provides details on MGP sites for Chesapeake’s Maryland and Florida divisions:

Salisbury, Maryland

We have substantially completed remediation of a site in Salisbury, Maryland, where it was determined that a former MGP caused localized ground-water contamination. During 1996, we completed construction of an AS/SVE system and began remediation procedures. We have reported 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, which is being maintained for periodic product monitoring and recovery.

Through June 30, 2011, we have incurred and paid approximately $2.9 million for remedial actions and environmental studies related to this site. We have recovered approximately $2.3 million through insurance proceeds or in rates, and $609,000 is expected to be recovered through future rates.

Winter Haven, Florida

The Winter Haven site is located on the eastern shoreline of Lake Shipp, in Winter Haven, Florida. Pursuant to a Consent Order entered into with the FDEP, we are obligated to assess and remediate environmental impacts at this former MGP site. In 2001, FDEP approved a RAP requiring construction and operation of a Bio-Sparging and Soil/Vapor Extraction (“BS/SVE”) treatment system to address soil and groundwater impacts at a portion of the site. The BS/SVE treatment system has been in operation since October 2002. Modifications and upgrades to the BS/SVE treatment system were completed in October 2009. The Seventeenth Semi-Annual RAP Implementation Status Report was submitted to FDEP in June 2011. The groundwater sampling results through June 2011 show a continuing reduction in contaminant concentrations and indicate that the recent treatment system modifications and upgrades have had a beneficial impact on the rate of reduction. At present, we predict that remedial action objectives could be met in approximately two to three years for the area being treated by the BS/SVE treatment system. The total expected cost of operating and monitoring the system is approximately $46,000.

The BS/SVE treatment system at the Winter Haven site does not address impacted soils in the southwest corner of the site. On April 16, 2010, a soil excavation interim RAP describing the proposed excavation of approximately 4,000 cubic yards of impacted soils from the southwest corner of the site was submitted to FDEP for review. On June 24, 2010, FDEP provided comments on the soil excavation interim RAP by letter, to which we responded, and a subsequent conditional approval letter was issued by FDEP on August 27, 2010. The cost to implement this excavation plan has been estimated at $250,000; however, this estimate does not include costs associated with dewatering or shoreline stabilization, which would be required to complete the excavation. Because the costs associated with shoreline stabilization and dewatering (including treatment and discharge of the pumped water) are likely to be substantial, alternatives to this excavation plan are being evaluated. One alternative currently being evaluated involves sparging into the southwest portion of the property to treat soils rather than excavating the soils.

Two new sparge points were installed in the southwest portion of the property in February of 2011. Sparging into these points has been initiated and operational and monitoring data over the next few quarters should provide the information needed to make this evaluation.

FDEP has indicated that we may be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the site. Based on studies performed to date, we object to FDEP’s suggestion that the sediments have been adversely impacted by the former operations of the MGP. Our early estimates indicate that some of the corrective measures discussed by FDEP could cost as much as $1.0 million. We believe that corrective measures for the sediments are not warranted and intend to oppose any requirement that we undertake corrective measures in the offshore sediments. We have not recorded a liability for sediment remediation, as the final resolution of this matter cannot be predicted at this time.

Through June 30, 2011, we have incurred and paid approximately $1.7 million for remedial activities at this site, and we have estimated and accrued for additional future costs of $284,000. We have recovered through rates $1.4 million of the costs to remediate the Winter Haven site and continue to expect that the remaining $542,000, which is included in regulatory assets, will be recoverable from customers through our approved rates.

Other

We are in discussions with the MDE regarding a former MGP site located in Cambridge, Maryland. The outcome of this matter cannot be determined at this time; therefore, we have not recorded an environmental liability for this location.

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Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $) In Thousands, except Share data	Jun. 30, 2011	Dec. 31, 2010
Current Assets
Allowance for uncollectible accounts receivable	$ 1,095	$ 1,194
Stockholders' equity
Common stock, par value	$ 0.4867	$ 0.4867
Common stock, shares authorized	25,000,000	25,000,000

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Condensed Consolidated Statements of Stockholders' Equity (Unaudited) (Parenthetical) (USD $) In Thousands, except Share data	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2011	Jun. 30, 2011	Dec. 31, 2010
Condensed Consolidated Statements of Stockholders' Equity [Abstract]
Deferred compensation plan held Rabbi Trust	30,078	30,078	29,596
Tax expense recognized on the prior service cost component of employees benefit plans		$ 3	$ 5
Tax expense (benefit) recognized on the net gain (loss) component of employee benefit plans		$ 239	$ (541)
Shares issued under the performance incentive plan withheld for employee taxes		12,324	17,695
Cash Dividends Declared Per Share of Common Stock	$ 0.345	$ 0.675	$ 1.305

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Share-Based Compensation

6 Months Ended

Jun. 30, 2011

Share-Based Compensation [Abstract]

Share-Based Compensation

9. Share-Based Compensation

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

The table below presents the amounts included in net income related to share-based compensation expense for the awards granted under the DSCP and the PIP for the three and six months ended June 30, 2011 and 2010:

	Three Months Ended				Six Months Ended
For the Periods Ended June 30,	2011		2010		2011		2010
(in thousands)
Directors Stock Compensation Plan	$	102	$	71	$	185	$	135
Performance Incentive Plan		274		208		520		477
Total compensation expense		376		279		705		612
Less: tax benefit		151		112		283		245
Share-Based Compensation amounts included in net income	$	225	$	167	$	422	$	367

Directors Stock Compensation Plan

Shares granted under the DSCP are issued in advance of the directors’ service periods and are fully vested as of the date of the grant. We record a prepaid expense of the shares issued and amortize the expense equally over a service period of one year. In May 2011, each of our non-employee directors received an annual retainer of 900 shares of common stock under the DSCP. A summary of stock activity under the DSCP during the six months ended June 30, 2011 is presented below:

	Number of		Weighted Average
	Shares		Grant Date Fair Value
Outstanding — December 31, 2010		—		—
Granted(1)		11,104	$	41.03
Vested		11,104	$	41.03
Forfeited		—		—
Outstanding — June 30, 2011		—		—

⁽¹⁾ In January 2011, our former Chief Executive Officer John Schimkaitis, retired from the Company and was awarded 304 shares of common stock for the prorated portion of his service period as he began his service as a non-executive board member.

At June 30, 2011, there was $369,000 of unrecognized compensation expense related to the DSCP awards. This expense is expected to be recognized over the remaining directors’ service periods ending as of the 2012 Annual Meeting.

Performance Incentive Plan

The table below presents the summary of the stock activity for the PIP for the six months ended June 30, 2011:

			Weighted Average
	Number of Shares		Fair Value
Outstanding — December 31, 2010		101,150	$	28.78
Granted		41,664		40.16
Vested		31,400		27.63
Forfeited		24,000		29.31
Expired		—		—
Outstanding — June 30, 2011		87,414	$	34.47

In January 2011, the Board of Directors granted awards under the PIP for 41,664 shares. The shares granted in January 2011 are multi-year awards, of which 10,500 shares will vest at the end of the two-year service period, or December 31, 2012. The remaining 31,164 shares will vest at the end of the three-year service period, or December 31, 2013. These awards are earned based upon the successful achievement of long-term goals, growth and financial results, which comprised both market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the date of the grant. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each market-based award granted.

In conjunction with his retirement, our former Chief Executive Officer forfeited 24,000 shares, which represents the shares awarded under the PIP in January 2009 for the performance period ending December 31, 2011 and in January 2010 for the performance period ending December 31, 2012, that had not vested.

At June 30, 2011, the aggregate intrinsic value of the PIP awards was $1.9 million.

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Condensed Consolidated Statements of Income (Unaudited) (USD $) In Thousands, except Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Operating Revenues
Regulated Energy	$ 54,327	$ 52,740	$ 139,329	$ 144,367
Unregulated Energy	29,692	24,615	88,442	83,885
Other	2,812	2,706	5,658	5,069
Total operating revenues	86,831	80,061	233,429	233,321
Operating Expenses
Regulated energy cost of sales	24,882	24,625	72,872	78,889
Unregulated energy and other cost of sales	24,420	20,384	68,711	65,474
Operations	20,401	18,526	40,237	37,524
Maintenance	1,892	1,789	3,595	3,489
Depreciation and amortization	4,937	4,545	9,958	9,389
Other taxes	2,523	2,431	5,441	5,397
Total operating expenses	79,055	72,300	200,814	200,162
Operating Income	7,776	7,761	32,615	33,159
Other income (loss), net of expenses	27	(11)	50	103
Interest charges	2,114	2,305	4,265	4,667
Income Before Income Taxes	5,689	5,445	28,400	28,595
Income tax expense	2,169	2,105	11,133	11,281
Net Income	$ 3,520	$ 3,340	$ 17,267	$ 17,314
Weighted-Average Common Shares Outstanding:
Basic	9,557,707	9,467,222	9,546,606	9,443,708
Diluted	9,650,887	9,557,352	9,642,374	9,550,670
Earnings Per Share of Common Stock:
Basic	$ 0.37	$ 0.35	$ 1.81	$ 1.83
Diluted	$ 0.37	$ 0.35	$ 1.79	$ 1.82
Cash Dividends Declared Per Share of Common Stock	$ 0.345	$ 0.330	$ 0.675	$ 0.645