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: September 30, 2010

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

(302) 734-6799

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No 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 — 9,510,532 shares outstanding as of October 31, 2010.

 

 

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			54
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			58
Item 6. Exhibits			58
SIGNATURES			59
Exhibit 10.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

GLOSSARY OF KEY TERMS

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

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
ESNG		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
PIPECO		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

Delaware PSC		Delaware Public Service Commission
EPA		United States Environmental Protection Agency
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FDEP		Florida Department of Environmental Protection
Florida PSC		Florida Public Service Commission
IASB		International Accounting Standards Board
Maryland PSC		Maryland Public Service Commission
MDE		Maryland Department of the Environment
PSC		Public Service Commission
SEC		Securities and Exchange Commission

Accounting Standards Related

ASC		FASB Accounting Standards CodificationTM (Codification)
ASU		FASB Accounting Standards Update
GAAP		Generally Accepted Accounting Principles
IFRS		International Financial Reporting Standards

AS/SVE		Air Sparging and Soil/Vapor Extraction
BS/SVE		Bio-Sparging and Soil/Vapor Extraction
CGS		Community Gas Systems
DSCP		Directors Stock Compensation Plan
Dts		Dekatherms
Dts/d		Dekatherms per day
FRP		Fuel Retention Percentage
GSR		Gas Sales Service Rates
Gulf Power		Gulf Power Corporation
HDD		Heating Degree-Days
Mcf		Thousand Cubic Feet
MWH		Megawatt Hour
MGP		Manufactured Gas Plant
NYSE		New York Stock Exchange
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

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Income (Unaudited)

For the Three Months Ended September 30,		2010				2009
(in thousands, except shares and per share data)
Operating Revenues
Regulated energy		$	53,412			$	15,372
Unregulated energy			20,134				14,011
Other			2,920				2,375
Total operating revenues			76,466				31,758
Operating Expenses
Regulated energy cost of sales			27,148				2,345
Unregulated energy and other cost of sales			17,238				12,071
Operations			17,993				11,001
Transaction-related costs			68				(675	)
Maintenance			1,899				600
Depreciation and amortization			5,058				2,437
Other taxes			2,479				1,722
Total operating expenses			71,883				29,501
Operating Income			4,583				2,257
Other income (loss), net of expenses			102				(26	)
Interest charges			2,256				1,540
Income Before Income Taxes			2,429				691
Income tax expense			801				383
Net Income		$	1,628			$	308
Weighted Average Common Shares Outstanding:
Basic			9,493,425				6,883,070
Diluted			9,497,696				6,888,024
Earnings Per Share of Common Stock:
Basic		$	0.17			$	0.04
Diluted		$	0.17			$	0.04
Cash Dividends Declared Per Share of Common Stock		$	0.330			$	0.315

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

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Income (Unaudited)

For the Nine Months Ended September 30,		2010				2009
(in thousands, except shares and per share data)
Operating Revenues
Regulated energy		$	197,779			$	86,422
Unregulated energy			104,018				83,236
Other			7,990				7,413
Total operating revenues			309,787				177,071
Operating Expenses
Regulated energy cost of sales			105,322				39,143
Unregulated energy and other cost of sales			82,713				66,962
Operations			54,848				34,820
Transaction-related costs			179				530
Maintenance			5,388				1,932
Depreciation and amortization			15,719				7,235
Other taxes			7,876				5,371
Total operating expenses			272,045				155,993
Operating Income			37,742				21,078
Other income, net of expenses			206				19
Interest charges			6,924				4,755
Income Before Income Taxes			31,024				16,342
Income tax expense			12,082				6,636
Net Income		$	18,942			$	9,706
Weighted-Average Common Shares Outstanding:
Basic			9,460,462				6,859,516
Diluted			9,570,921				6,981,010
Earnings Per Share of Common Stock:
Basic		$	2.00			$	1.41
Diluted		$	1.98			$	1.40
Cash Dividends Declared Per Share of Common Stock		$	0.975			$	0.935

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

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

For the Nine Months Ended September 30,		2010				2009
(in thousands)
Operating Activities
Net Income		$	18,942			$	9,706
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			15,719				7,235
Depreciation and accretion included in other costs			2,428				1,987
Deferred income taxes, net			9,847				2,353
Unrealized loss (gain) on commodity contracts			(443	)			1,382
Unrealized gain on investments			(13	)			(161	)
Employee benefits			(594	)			1,394
Share-based compensation			899				897
Changes in assets and liabilities:
Accounts receivable and accrued revenue			23,337				25,513
Propane inventory, storage gas and other inventory			(411	)			2,071
Regulatory assets			967				(1,182	)
Prepaid expenses and other current assets			631				480
Accounts payable and other accrued liabilities			(13,922	)			(13,409	)
Income taxes receivable			(6,392	)			6,766
Accrued interest			1,381				1,160
Customer deposits and refunds			1,891				(1,027	)
Accrued compensation			735				(280	)
Regulatory liabilities			453				2,179
Other liabilities			191				388
Net cash provided by operating activities			55,646				47,452
Investing Activities
Property, plant and equipment expenditures			(26,953	)			(19,674	)
Purchase of investments			(2,308	)			—
Environmental expenditures			(522	)			(33	)
Net cash used in investing activities			(29,783	)			(19,707	)
Financing Activities
Common stock dividends			(8,187	)			(5,683	)
Issuance (purchase) of stock for Dividend Reinvestment Plan			405				(9	)
Change in cash overdrafts due to outstanding checks			7,020				471
Net repayment under line of credit agreements			(23,069	)			(23,387	)
Other short-term borrowing			29,100				—
Repayment of long-term debt			(31,207	)			(20	)
Net cash used in financing activities			(25,938	)			(28,628	)
Net Decrease in Cash and Cash Equivalents			(75	)			(883	)
Cash and Cash Equivalents — Beginning of Period			2,828				1,611
Cash and Cash Equivalents — End of Period		$	2,753			$	728

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

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

		September 30,				December 31,
Assets		2010				2009
(in thousands, except shares and per share data)
Property, Plant and Equipment
Regulated energy		$	478,048			$	463,856
Unregulated energy			60,614				61,360
Other			16,582				16,054
Total property, plant and equipment			555,244				541,270
Less: Accumulated depreciation and amortization			(118,393	)			(107,318	)
Plus: Construction work in progress			11,029				2,476
Net property, plant and equipment			447,880				436,428
Investments			3,006				1,959
Current Assets
Cash and cash equivalents			2,753				2,828
Accounts receivable (less allowance for uncollectible accounts of $1,030 and $1,609, respectively)			52,166				70,029
Accrued revenue			7,410				12,838
Propane inventory, at average cost			7,804				7,901
Other inventory, at average cost			3,586				3,149
Regulatory assets			53				1,205
Storage gas prepayments			6,215				6,144
Income taxes receivable			9,071				2,614
Deferred income taxes			523				1,498
Prepaid expenses			5,301				5,843
Mark-to-market energy assets			2,290				2,379
Other current assets			147				147
Total current assets			97,319				116,575
Deferred Charges and Other Assets
Goodwill			35,609				34,095
Other intangible assets, net			3,547				3,951
Long-term receivables			235				343
Regulatory assets			20,835				19,860
Other deferred charges			3,844				3,891
Total deferred charges and other assets			64,070				62,140
Total Assets		$	612,275			$	617,102

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

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

		September 30,				December 31,
Capitalization and Liabilities		2010				2009
(in thousands, except shares and per share data)
Capitalization
Stockholders’ equity
Common stock, par value $0.4867 per share (authorized 25,000,000 and 12,000,000 shares, respectively)		$	4,623			$	4,572
Additional paid-in capital			147,022				144,502
Retained earnings			72,858				63,231
Accumulated other comprehensive loss			(2,404	)			(2,524	)
Deferred compensation obligation			767				739
Treasury stock			(767	)			(739	)
Total stockholders’ equity			222,099				209,781
Long-term debt, net of current maturities			97,491				98,814
Total capitalization			319,590				308,595
Current Liabilities
Current portion of long-term debt			7,216				35,299
Short-term borrowing			43,073				30,023
Accounts payable			34,363				51,948
Customer deposits and refunds			26,591				24,960
Accrued interest			3,267				1,887
Dividends payable			3,135				2,959
Accrued compensation			4,261				3,445
Regulatory liabilities			9,573				8,882
Mark-to-market energy liabilities			1,982				2,514
Other accrued liabilities			13,353				8,683
Total current liabilities			146,814				170,600
Deferred Credits and Other Liabilities
Deferred income taxes			75,396				66,923
Deferred investment tax credits			125				193
Regulatory liabilities			3,475				4,154
Environmental liabilities			10,946				11,104
Other pension and benefit costs			16,257				17,505
Accrued asset removal cost — Regulatory liability			34,683				33,214
Other liabilities			4,989				4,814
Total deferred credits and other liabilities			145,871				137,907
Total Capitalization and Liabilities		$	612,275			$	617,102

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

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

		Common Stock																Accumulated Other
		Number of								Additional Paid-In								Comprehensive				Deferred
(in thousands, except shares and per share data)		Shares(7)				Par Value				Capital				Retained Earnings				Loss				Compensation				Treasury Stock				Total
Balances at December 31, 2008			6,827,121			$	3,323			$	66,681			$	56,817			$	(3,748	)		$	1,549			$	(1,549	)			123,073
Net Income															15,897																15,897
Other comprehensive income, net of tax:
Employee Benefit Plans, net of tax:
Amortization of prior service costs (4)																			7												7
Net Gain (5)																			1,217												1,217
Total comprehensive income																														$	17,121
Dividend Reinvestment Plan			31,607				15				921																				936
Retirement Savings Plan			32,375				16				966																				982
Conversion of debentures			7,927				4				131																				135
Share based compensation (1) (3)			7,374				3				1,332																				1,335
Deferred Compensation Plan (6)																							(810	)			810				—
Purchase of treasury stock			(2,411	)																							(73	)			(73	)
Sale and distribution of treasury stock			2,411																								73				73
Common stock issued in the merger			2,487,910				1,211				74,471																				75,682
Dividends on stock-based compensation															(104	)															(104	)
Cash dividends (2)															(9,379	)															(9,379	)
Balances at December 31, 2009			9,394,314				4,572				144,502				63,231				(2,524	)			739				(739	)			209,781
Net Income															18,942																18,942
Other comprehensive income, net of tax:
Employee Benefit Plans, net of tax:
Amortization of prior service costs (4)																			6												6
Net Gain (5)																			114												114
Total comprehensive income																														$	19,062
Dividend Reinvestment Plan			41,100				20				1,240																				1,260
Retirement Savings Plan			21,998				11				675																				686
Conversion of debentures			5,636				3				93																				96
Tax benefit on share based compensation											73																				73
Share based compensation (1) (3)			36,415				17				439																				456
Deferred Compensation Plan (6)																							28				(28	)			—
Purchase of treasury stock			(886	)																							(28	)			(28	)
Sale and distribution of treasury stock			886																								28				28
Dividends on stock-based compensation															(80	)															(80	)
Cash dividends (2)															(9,235	)															(9,235	)
Balances at September 30, 2010			9,499,463			$	4,623			$	147,022			$	72,858			$	(2,404	)		$	767			$	(767	)		$	222,099

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

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, 2010. 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.

As a result of the merger with Florida Public Utilities Company (“FPU”) in October 2009, we changed our operating segments (see Note 7, “Segment Information,” for further discussion). We revised the segment information as of and for the three months and nine months ended September 30, 2009, to reflect the new segments. We also revised certain presentations and reclassified certain amounts reported in the condensed consolidated statements of income and cash flows for the three months and nine months ended September 30, 2009 to conform to current period presentations and classifications. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.

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.

Recent Accounting Amendments Yet to be Adopted by the Company

In November 2008, the SEC released a proposed roadmap regarding the potential use by U.S. issuers of financial statements prepared in accordance with International Financial Reporting Standards (“IFRS”), a comprehensive series of accounting standards published by the International Accounting Standards Board (“IASB”). Under the proposed roadmap, we may be required to prepare our financial statements in accordance with IFRS as early as 2015. The SEC will make a determination in 2011 regarding the mandatory adoption of IFRS. In July 2009, the IASB issued an exposure draft of “Rate-regulated Activities,” which sets out the scope, recognition and measurement criteria, and accounting disclosures for assets and liabilities that arise in the context of cost-of-service regulation, to which our rate-regulated businesses are subject. Throughout 2010, IASB has continued its deliberation on the exposure draft and comments received on the overall concept of the recognition of assets and liabilities arising out of cost-of-service regulation. We will continue to monitor the development of the potential implementation of IFRS.

Other Accounting Amendments Adopted by the Company during the first nine months of 2010

In January 2010, the Financial Accounting Standards Board (“FASB”) issued FASB Accounting Standards Update (“ASU”) 2010-06, “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements.” This ASU requires certain new disclosures and clarifies certain existing disclosure requirements about fair value measurement, as set forth in FASB Accounting Standards Codification (“ASC”) Subtopic 820-10. The FASB’s objective is to improve these disclosures and, thus, increase the transparency in financial reporting. Specifically, ASU 2010-06 amends ASC Subtopic 820-10 to now require a reporting entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers; and, in the reconciliation for fair value measurements using significant unobservable inputs, a reporting entity should present separate information about purchases, sales, issuances, and settlements. In addition, ASU 2010-06 clarifies certain requirements of the existing disclosures. We adopted the disclosures required by this ASU in the first quarter of 2010, except for disclosures about purchases, sales, issuances, and settlements in the roll-forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. We currently do not have any assets or liabilities that would require Level 3 fair value measurements. Adoption of this ASU did not have an impact on our condensed consolidated financial position and results of operations.

In April 2010, the FASB issued FASB ASU 2010-12 — Income Taxes (Topic 740), “Accounting for Certain Tax effects of the 2010 Health Care Reform Acts.” This ASU codifies the SEC staff announcement relating to the accounting for the Health Care and Education Reconciliation Act and the Patient Protection and Affordable Care Act, which allows the two Acts to be considered together for accounting purposes. We adopted this ASU in the first quarter of 2010 and have determined that these Acts did not have a material impact on our income tax accounting (see Note 8, “Employee Benefit Plans,” to these unaudited condensed consolidated financial statements for further discussion).

2.

Acquisitions

FPU

On October 28, 2009, we completed a merger with FPU, pursuant to which FPU became a wholly-owned subsidiary of Chesapeake. The merger was accounted for under the acquisition method of accounting, with Chesapeake treated as the acquirer for accounting purposes.

The merger increased our overall presence in Florida by adding approximately 51,000 natural gas distribution customers and 12,000 propane distribution customers to our existing Florida operations. It also introduced us to the electric distribution business as we incorporated FPU’s approximately 31,000 electric customers in northwest and northeast Florida.

In consummating the merger, we issued 2,487,910 shares of Chesapeake common stock at a price per share of $30.42 in exchange for all outstanding common stock of FPU. We also paid approximately $16,000 in lieu of issuing fractional shares in the exchange. There was no contingent consideration in the merger. The total value of consideration transferred by Chesapeake in the merger was approximately $75.7 million.

The assets acquired and liabilities assumed in the merger were recorded at their respective fair values at the completion of the merger. For certain assets acquired and liabilities assumed, such as pension and post-retirement benefit obligations, income taxes and contingencies without readily determinable fair values, for which GAAP provides specific exception to the fair value recognition and measurement, we applied other specified GAAP or accounting treatment as appropriate.

The following table summarizes the final allocation of the purchase price to the assets acquired and liabilities assumed at the date of the merger.

(in thousands)		October 28, 2009
Purchase price		$	75,699
Current assets			26,761
Property, plant and equipment			139,709
Regulatory assets			19,899
Investments and other deferred charges			3,659
Intangible assets			4,019
Total assets acquired			194,047
Long term debt			47,812
Borrowings from line of credit			4,249
Other current liabilities			17,427
Pre-merger contingencies			923
Other regulatory liabilities			19,414
Pension and post retirement obligations			14,276
Environmental liabilities			12,414
Deferred income taxes			20,559
Customer deposits and other liabilities			15,467
Total liabilities assumed			152,541
Net identifiable assets acquired			41,506
Goodwill		$	34,193

During 2010, we adjusted the allocation of the purchase price based on additional information available. The adjustments are related to certain accruals, regulatory assets, deferred and current income tax assets and liabilities, and pre-merger contingencies (see discussion below). These adjustments also resulted in a change in fair value of the propane property, plant and equipment. Goodwill from the merger increased to $34.2 million after incorporating these adjustments, compared to $33.4 million as previously disclosed at December 31, 2009.

None of the $34.2 million in goodwill recorded in connection with the merger is deductible for tax purposes. All of the goodwill recorded in connection with the merger is related to the regulated energy segment. We believe the goodwill recognized is attributable to the synergies and opportunities primarily related to FPU’s regulated energy businesses. The intangible assets acquired in connection with the merger are related to propane customer relationships ($3.5 million) and favorable propane supply contracts ($519,000). The intangible value assigned to FPU’s existing propane customer relationships is being amortized over a 12-year period based on the expected duration of the benefit arising from the relationships. The intangible value assigned to FPU’s favorable propane contracts is being amortized over a period ranging from one to 14 months based on contractual terms.

Current assets of $26.8 million acquired during the merger included notes receivable of approximately $5.8 million, for which we received full payment in March 2010, and accounts receivable of approximately $3.1 million, $6.0 million and $891,000 for FPU’s natural gas, electric and propane distribution businesses, respectively.

The pre-merger contingencies of $923,000 included in the final allocation of the purchase price is primarily related to a proposed settlement agreement for a class action complaint against FPU from a FPU propane customer, which is further discussed in Note 6, “Other Commitments and Contingencies.” The proposed settlement addresses a particular charge by FPU to its propane customers during the period from May 27, 2006 to September 24, 2010, which encompasses both pre-merger and post-merger periods. We used the ratio of such charge made to customers during the pre-merger period to those made during the settlement period to estimate that $835,000 of the $1.1 million total contingency was related to FPU’s operations prior to the merger with Chesapeake. The remaining $278,000 of the liability related to FPU’s operations after the merger with Chesapeake was expensed in September 2010. Also included in the pre-merger contingencies are liabilities related to FPU’s income taxes for periods prior to the merger.

The financial position and results of operations and cash flows of FPU from the effective date of the merger are included in our condensed consolidated financial statements. The revenue from FPU for the three months and nine months ended September 30, 2010, included in our condensed consolidated statements of income, were $41.4 million and $135.4 million, respectively, and the net income from FPU for the three months and nine months ended September 30, 2010, included in our condensed consolidated statements of income, were $1.1 million and $7.3 million, respectively.

The following table shows the actual results of combined operations for the nine months ended September 30, 2010 and pro forma results of combined operations for the nine months ended September 30, 2009, as if the merger had been completed at January 1, 2009. Since the effects of the merger for the nine months ended September 30, 2010 were already included in the actual results of our consolidated operations, there is no pro forma adjustment for the nine months ended September 30, 2010.

For the Nine Months Ended September 30,		2010				2009
(in thousands, except per share data)
Operating Revenues		$	309,787			$	291,389
Operating Income			37,742				30,106
Net income			18,942				13,319
Earnings per share — basic		$	2.00			$	1.43
Earnings per share — diluted		$	1.98			$	1.41

Pro forma results are presented for informational purposes only and are not necessarily indicative of what the actual results would have been had the acquisition actually occurred on January 1, 2009.

The acquisition method of accounting requires acquisition-related costs to be expensed in the period in which those costs are incurred, rather than including them as a component of consideration transferred. It also prohibits an accrual of certain restructuring costs at the time of the merger. As we intend to seek recovery in future rates in Florida of a certain portion of the purchase premium paid and merger-related costs incurred, we also considered the impact of ASC Topic 980, “Regulated Operations,” in determining the proper accounting treatment for the merger-related costs. As of September 30, 2010, we incurred approximately $3.3 million in costs to consummate the merger, including the cost associated with merger-related litigation and integrating operations following the merger. This includes $369,000 incurred during the nine months ended September 30, 2010. We deferred approximately $1.7 million of the total costs incurred as a regulatory asset at September 30, 2010, which represents our estimate, based on similar proceedings in Florida in the past, of the costs which we expect to be permitted to recover when we complete the appropriate rate proceedings.

Included in the $3.3 million merger-related costs incurred as of September 30, 2010, were approximately $452,000 of severance and other restructuring charges for our efforts to integrate the operations of the two companies.

Virginia LP Gas

On February 4, 2010, Sharp Energy, Inc. (“Sharp”), our propane distribution subsidiary, purchased the operating assets of Virginia LP Gas, Inc., a propane distributor serving approximately 1,000 retail customers in Northampton and Accomack Counties in Virginia. The total consideration for the purchase was $600,000, of which $300,000 was paid at the closing and the remaining $300,000 will be paid over 60 months. Based on our valuation, we allocated $188,000 of the purchase price to intangible assets, which consist of customer relationship and non-compete agreements. These intangible assets are being amortized over a seven-year period. There was no goodwill recorded in connection with this acquisition. The revenue and net income from this acquisition that were included in our condensed consolidated statement of income for the three months and nine months ended September 30, 2010 were not material.

Indiantown Gas Company

On August 9, 2010, FPU purchased the natural gas operating assets of Indiantown Gas Company, which provides natural gas distribution services to approximately 700 customers including two large industrial customers in Indiantown, Florida. FPU paid approximately $1.2 million for these assets. FPU recorded $742,000 in goodwill in connection with this acquisition, all of which is deductible for income tax purposes. There was no intangible asset recorded in connection with this acquisition. The revenue and net income from this acquisition that were included in our condensed and consolidated statement of income for the three months and nine months ended September 30, 2010 were not material.

3.

Calculation of Earnings Per Share

		Three Months								Nine Months
For the Periods Ended September 30,		2010				2009				2010				2009
(in thousands, except Shares and Per Share Data)
Calculation of Basic Earnings Per Share:
Net Income		$	1,628			$	308			$	18,942			$	9,706
Weighted average shares outstanding			9,493,425				6,883,070				9,460,462				6,859,516
Basic Earnings Per Share		$	0.17			$	0.04			$	2.00			$	1.41
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income		$	1,628			$	308			$	18,942			$	9,706
Effect of 8.25% Convertible debentures (1)			—				—				56				60
Adjusted numerator — Diluted		$	1,628			$	308			$	18,998			$	9,766
Reconciliation of Denominator:
Weighted shares outstanding — Basic			9,493,425				6,883,070				9,460,462				6,859,516
Effect of dilutive securities: (1)
Share-based Compensation			4,271				4,954				23,708				27,838
8.25% Convertible debentures			—				—				86,751				93,656
Adjusted denominator — Diluted			9,497,696				6,888,024				9,570,921				6,981,010
Diluted Earnings Per Share		$	0.17			$	0.04			$	1.98			$	1.40

4.

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 (“ESNG”), our natural gas transmission operation, is subject to regulation by the Federal Energy Regulatory Commission (“FERC”); and Peninsula Pipeline Company, Inc. (“PIPECO”) is subject to regulation by the Florida Public Service Commission (“Florida PSC”). Chesapeake’s Florida natural gas distribution division and FPU’s natural gas and electric operations continue to be subject to regulation by the Florida PSC as separate entities.

Delaware

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, 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. Accordingly, if the Hearing Examiner’s refund recommendation for past capacity releases were 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. We disagreed with the Hearing Examiner’s recommendations and filed exceptions to those recommendations on February 18, 2010. 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. Both the Delaware division and the Division of the Public Advocate filed opening briefs with the Delaware Superior Court on September 30, 2010. It is not anticipated that the Court will render a decision prior to the end of the year. Due to the ongoing legal proceeding, the parties have not yet opened a separate docket to determine an alternative pricing methodology for future capacity releases. We did not accrue any contingent liability related to potential refunds for past capacity releases. Since the Delaware PSC’s Order on May 18, 2010, the Delaware division has not released any capacity to PESCO.

On September 4, 2009, the Delaware division filed with the Delaware PSC its annual GSR Application, seeking approval to change its GSR, effective November 1, 2009. On October 6, 2009, the Delaware PSC authorized the Delaware division to implement the GSR charges on November 1, 2009, on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. The evidentiary hearing in this matter was held on May 19, 2010. At the evidentiary hearing, the parties in this docket, which included the Delaware PSC, the Delaware division and the Division of the Public Advocate, presented a proposed settlement agreement to resolve all issues addressed in this docket. The settlement agreement contemplates that the Delaware division will begin to share interruptible margins with its firm ratepayers when those margins reach a certain level in each twelve-month period ending October 31. Based on the current level of interruptible margins generated by the Delaware division, we do not anticipate that sharing of future interruptible margins will have a significant impact on our results. The Delaware PSC approved the settlement agreement on September 7, 2010.

On December 17, 2009, the Delaware division filed an application with the Delaware PSC, requesting approval for an Individual Contract Rate for service to be rendered to a potential large industrial customer. The Delaware PSC granted approval of the Individual Contract Rate on February 18, 2010.

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 division anticipates a final decision in no later than the third quarter of 2011.

Maryland

On December 1, 2009, 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, 2009. No issues were raised at the hearing, and on December 9, 2009, the Hearing Examiner in this proceeding issued a proposed Order approving the division’s four quarterly filings. On January 8, 2010, the Maryland PSC issued an Order substantially affirming the Hearing Examiner’s decision in the matter.

On September 14, 2010, the Maryland division filed with the Maryland PSC, its four quarterly gas cost recovery filings for the twelve months ended September 30, 2010. The Maryland PSC is scheduled to hold an evidentiary hearing on December 14, 2010 to determine the reasonableness of the filings. The Maryland division anticipates a final decision in the first quarter of 2011.

Florida

On July 14, 2009, Chesapeake’s Florida division filed with the Florida PSC its petition for a rate increase and request for interim rate relief. In the application, the Florida division sought approval of: (a) an interim rate increase of $417,555; (b) a permanent rate increase of $2,965,398, which represented an average base rate increase, excluding fuel costs, of approximately 25 percent for the Florida division’s customers; (c) implementation or modification of certain surcharge mechanisms; (d) restructuring of certain rate classifications; and (e) deferral of certain costs and the purchase premium associated with the then pending merger with FPU. On August 18, 2009, the Florida PSC approved the full amount of the Florida division’s interim rate request, subject to refund, applicable to all meters read on or after September 1, 2009. On December 15, 2009, the Florida PSC: (a) approved a $2,536,307 permanent rate increase applicable to all meters read on or after January 14, 2010; (b) determined that there is no refund required of the interim rate increase; and (c) ordered Chesapeake’s Florida division and FPU’s natural gas distribution operations to submit data no later than April 29, 2011 (which is 18 months after the merger) that details all known benefits, synergies, cost savings and cost increases that have resulted from the merger.

Also on December 15, 2009, the Florida PSC approved the settlement agreement for a final natural gas rate increase of $7,969,000 for FPU’s natural gas distribution operation. The Florida PSC had approved an annual interim rate increase of $984,054 on February 10, 2009 and approved the permanent rate increase of $8,496,230 in an order issued on May 5, 2009, with the new rates to be effective beginning on June 4, 2009. On June 17, 2009, however, the Office of Public Counsel entered a protest to the Florida PSC’s order and its final natural gas rate increase ruling. Subsequent negotiations led to the settlement agreement between the Office of Public Counsel and FPU, which the Florida PSC approved on December 15, 2009. The rates authorized pursuant to the order approving the settlement agreement became effective on January 14, 2010. In February 2010, FPU refunded to its natural gas customers approximately $290,000, representing revenues in excess of the amount provided by the settlement agreement that had been billed to customers from June 2009 through January 14, 2010.

In the third quarter of 2010, we accrued $500,000 to reserve for FPU natural gas regulatory risk. We recorded this reserve based on our assessment of the regulatory risk related to FPU’s current earnings and how they may have been affected by various factors, including the benefits, synergies, cost savings and cost increases resulting from the merger. We are required to submit by April 29, 2011 data that details such known benefits, synergies, cost savings and cost increases.

On September 1, 2009, FPU’s electric distribution operation filed its annual Fuel and Purchased Power Recovery Clause, which seeks final approval of its 2008 fuel-related revenues and expenses and new fuel rates for 2010. On January 4, 2010, the Florida PSC approved the proposed 2010 fuel rates, effective on or after January 1, 2010.

On September 11, 2009, Chesapeake’s Florida division and FPU’s natural gas distribution operation separately filed their respective annual Energy Conservation Cost Recovery Clauses, seeking final approval of their 2008 conservation-related revenues and expenses and new conservation surcharge rates for 2010. On November 2, 2009, the Florida PSC approved the proposed 2010 conservation surcharge rates for both the Florida division and FPU, effective for meters read on or after January 1, 2010.

Also on September 11, 2009, FPU’s natural gas distribution operation filed its annual Purchased Gas Adjustment Clause, seeking final approval of its 2008 purchased gas-related revenues and expenses and new purchased gas adjustment cap rate for 2010. On November 4, 2009, the Florida PSC approved the proposed 2010 purchased gas adjustment cap, effective on or after January 1, 2010.

On September 1, 2010, FPU’s electric distribution operation filed its annual Fuel and Purchased Power Cost Recovery Clause, which seeks final approval of the levelized fuel adjustment and purchased power cost recovery factors for 2011. A final decision on the proposed 2011 fuel adjustment factors is expected in December 2010.

On September 13, 2010, Chesapeake’s Florida division and FPU’s natural gas distribution operation separately filed their annual Energy Conservation Cost Recovery Clauses, seeking final approval of the 2009 conservation-related revenues and expenses and new conservation surcharge rates for 2011. A final decision on the proposed 2011 conservation rates is expected in December 2010.

On September 13, 2010, FPU’s natural gas distribution operation filed its annual Purchase Gas Adjustment Clause seeking final approval of its 2009 purchased gas-related revenues and expenses and new purchased gas adjustment cap rate for 2011. A final decision on the proposed 2011 Purchased Gas Adjustment is expected in December 2010.

The City of Marianna Commissioners voted on July 7, 2009 to enter into a new 10-year franchise agreement with FPU, effective February 1, 2010. The agreement provides that new interruptible and time-of-use rates shall become available for certain customers prior to February 2011, or, at the option of the City, the franchise agreement could be voided nine months after that date. The new franchise agreement contains a provision that permits the City to purchase the Marianna portion of FPU’s electric system. Should FPU fail to make available the new interruptible and time-of-use rates, and if the franchise agreement is then voided by the City and the City elects to purchase the Marianna portion of the distribution system, the agreement would require the City to pay FPU severance/reintegration costs, the fair market value for the system, and an initial investment in the infrastructure to operate this limited facility. If the City purchased the electric system, FPU would have a gain in the year of the disposition, but ongoing financial results would be negatively impacted from the loss of the Marianna area from FPU’s electric operations.

ESNG

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

Energylink Expansion Project: In 2006, ESNG 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 ESNG’s existing facilities in Sussex County, Delaware. In April 2009, ESNG terminated this project based on increased construction costs over its original projection and 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 and approved by the FERC. One of the two participating customers is Chesapeake, through its Delaware and Maryland divisions.

Mainline Extension Project: On November 25, 2009, ESNG filed a notice of its intent under its blanket certificate to construct, own and operate new mainline facilities to deliver additional firm service of 1,594 Mcfs per day of natural gas to Chesapeake’s Delaware division. The FERC published the notice of this filing on December 7, 2009. No protest was filed during the 60-day period following the notice, and ESNG commenced construction on February 6, 2010. The facilities were completed on April 29, 2010, and ESNG commenced billing for the new service on May 1, 2010.

Mainline Extension and Interconnect Project: On March 5, 2010, ESNG submitted an Application for Certificate of Public Convenience and Necessity to the FERC related to a proposed mainline extension and interconnect project that would tie into the interstate pipeline system of Texas Eastern Transmission, LP (“TETLP”). ESNG’s project involves building and operating an eight-mile mainline extension from ESNG’s existing facility in Parkesburg, Pennsylvania to the interconnection with TETLP at Honey Brook, Pennsylvania. The estimated capital cost of this project is approximately $19.4 million. On September 3, 2010, the FERC approved ESNG’s application, subject to certain environmental conditions, some of which have to be met prior to the commencement of construction. ESNG accepted the Order Issuing Certificate on October 4, 2010. On October 13, 2010, the FERC issued a Notice to Proceed with the construction of the project’s facilities as all conditions that must be met prior to the commencement of construction were satisfied. Construction is anticipated to be completed during the fourth quarter of 2010.

ESNG also had developments in the following FERC matters:

On April 30, 2010, ESNG submitted its annual Interruptible Revenue Sharing Report to the FERC. ESNG reported in this filing that its interruptible revenue was in excess of its annual threshold amount and refunded $90,718, inclusive of interest, in the second quarter of 2010 to its eligible firm customers.

On May 28, 2010, ESNG submitted its annual Fuel Retention Percentage (“FRP”) and Cash-Out Surcharge filings to the FERC. In these filings, ESNG proposed to implement a FRP rate of 0.00 percent and a zero rate for its Cash-Out Surcharge. ESNG also proposed to refund $310,117, inclusive of interest, to its eligible customers in the second quarter of 2010 as a result of combining its over-recovered Gas Required for Operations and its over-recovered Cash-Out Cost. The FERC approved these proposals on June 29, 2010, and ESNG issued refunds to eligible customers.

On August 16, 2010, ESNG submitted its compliance filing with regard to the FERC’s Order on Electronic Tariff Filings (Order No. 714). This Order required all natural gas, oil and electric pipelines subject to FERC jurisdiction to file baseline tariff sheets electronically. All subsequent rate and tariff-related filings are to be made electronically. On October 13, 2010, the FERC approved ESNG’s compliance filing for this Order.

On September 1, 2010, ESNG submitted its compliance filing with regard to the FERC’s most recent Order adopting Standards for Business Practices for Interstate Natural Gas Pipelines (Order No. 587-U). With this Order, FERC incorporated by reference into its regulations Version 1.9 of the North American Energy Standards Board Wholesale Gas Quadrant’s standards. On October 13, 2010, FERC approved ESNG’s compliance filing.

5.

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 the effect on the environment of the disposal or release of specified substances at current and former operating sites.

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. The Key West, Pensacola, Sanford and West Palm Beach sites are related to FPU, for which we assumed in the merger any existing and future contingencies.

As of September 30, 2010, we had $381,000 in environmental liabilities related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of the future costs associated with those sites. As of September 30, 2010, we had approximately $1.4 million in regulatory and other assets for future recovery of environmental costs from Chesapeake’s customers through our approved rates. As of September 30, 2010, we had approximately $11.8 million in environmental liabilities related to FPU’s MGP sites in Florida, primarily from the West Palm Beach site, which represents our estimate of the future costs associated with those sites. FPU has approval to recover up to $14.0 million of its environmental costs from insurance and from customers through rates. Approximately $7.7 million of FPU’s expected environmental costs have been recovered from insurance and customers through rates as of September 30, 2010. We also had approximately $6.3 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

The following discussion provides details on each site.

Salisbury, Maryland

We have substantially completed remediation of this site in Salisbury, Maryland, where it was determined that a former MGP caused localized ground-water contamination. During 1996, we completed construction of an Air Sparging and Soil-Vapor Extraction (“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. We have requested and are awaiting a No Further Action determination from the MDE.

Through September 30, 2010, we have incurred and paid approximately $2.9 million for remedial actions and environmental studies. We have recovered approximately $2.2 million through insurance proceeds or in rates and have $696,000 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 Florida Department of Environmental Protection (“FDEP”), we are obligated to assess and remediate environmental impacts at this former MGP site. In 2001, the FDEP approved a Remedial Action Plan (“RAP”) requiring construction and operation of a BioSparging 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 Fifteenth Semi-Annual RAP Implementation Status Report was submitted to the FDEP in July 2010. The groundwater sampling results through July 2010 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 may be met for the area being treated by the BS/SVE treatment system in approximately two to three years.

The BS/SVE treatment system 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 the FDEP for review. The FDEP provided comments to the soil excavation interim RAP by letter, dated June 24, 2010. A meeting is proposed with the FDEP in November 2010 to discuss the proposed soil excavation RAP with the prospect of proceeding with actual field work in late 2011 or early 2012.

The 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 the 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 September 30, 2010, we have incurred and paid approximately $1.6 million for this site and estimate an additional cost of $381,000 in the future, which has been accrued. We have recovered through rates $1.3 million of the costs and continue to expect that the remaining $715,000, which is included in regulatory assets, will be recoverable from customers through our approved rates.

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. The FDEP has not required any further work at the site as of this time. Our portion of the consulting/remediation costs which may be incurred at this site is projected to be $93,000.

Pensacola, Florida

FPU formerly owned and operated an MGP in Pensacola, Florida. The MGP was also owned by Gulf Power Corporation (“Gulf Power”). Portions of the site are now owned by the City of Pensacola and the Florida Department of Transportation. In October 2009, the FDEP informed Gulf Power that FDEP would approve a conditional No Further Action determination for the site, which must include a requirement for institutional and engineering controls. The group, consisting of Gulf Power, City of Pensacola, Florida Department of Transportation and FPU, is proceeding with preparation of the necessary documentation to submit the No Further Action justification. Consulting and remediation costs are projected to be $11,000.

Sanford, Florida

FPU is the current owner of property in Sanford, Florida, a former MGP site which 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 U.S. 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 total estimated remediation costs for this site were projected at the time by EPA 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 September 30, 2010, FPU has paid $650,000 to the Sanford Group escrow account for its share of 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 September 30, 2010, FPU’s remaining share of remediation expenses, including attorneys’ fees and costs, is estimated to be $22,000. 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 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.

West Palm Beach, Florida

We are currently evaluating remedial options 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 FDEP, effective April 8, 1991, FPU completed the delineation of soil and groundwater impacts at the site. On June 30, 2008, FPU transmitted a revised feasibility study, evaluating appropriate remedies for the site, to the FDEP. 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 recently performed additional field work in August 2010, which included the installation of additional groundwater monitoring wells and performance of a comprehensive groundwater sampling event. The results of the field work were submitted to the FDEP for their review and comment. FPU also performed vapor intrusion sampling in October 2010. The total projected cost of this additional field work requested by the FDEP is approximately $750,000.

The revised feasibility study completed in 2008 evaluated a wide range of remedial alternatives based on criteria provided by applicable laws and regulations. Based on the likely acceptability of proven remedial technologies described in the feasibility study and implemented at similar sites, management believes that consulting and remediation costs to address the impacts now characterized at the West Palm Beach site will range from $7.4 million to $19.0 million. This range of costs covers such remedies as in situ solidification for deeper soil impacts, excavation of superficial soil impacts, installation of a barrier wall with a permeable biotreatment zone, monitored natural attenuation of dissolved impacts in groundwater, or some combination of these remedies.

Negotiations between FPU and the FDEP on a final remedy for the site continue. Until those negotiations are concluded, we are unable to determine, to a reasonable degree of certainty, the full extent or cost of remedial action that may be required. As of September 30, 2010, and subject to the limitations described above, we estimate the remediation expenses, including attorneys’ fees and costs, will range from approximately $7.8 million to $19.4 million for this site.

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

6.

Other Commitments and Contingencies

Litigation

In May 2010, a 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 denies any wrongdoing and maintains that the particular charge at issue is customary, proper and fair. Without any admission by FPU of 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 settlement agreement has been preliminarily approved by the court. The hearing for final approval of the settlement, after providing notice to the class, is scheduled for February 11, 2011. We recorded $1.1 million as a contingent liability related to this litigation in September 2010 based on the proposed settlement agreement, which includes the proposed settlement payment, attorneys’ fees and expenses and costs of notice and class administration. As discussed in Note 2, “Acquisitions,” $835,000 of this contingent liability was determined to be associated with FPU’s operations prior to the merger with Chesapeake and was recorded as part of the purchase price allocation. The remaining $278,000 of the liability, which is related to FPU’s operations after the merger with Chesapeake, was expensed in September 2010.

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

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.

In May 2010, our natural gas marketing subsidiary, PESCO, renewed contracts to purchase natural gas from various suppliers. These contracts expire in May 2011.

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 (formerly known as Jacksonville Electric Authority) 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; and (b) fixed charge coverage greater than 1.5. If either ratio is not met by FPU, we have 30 days to cure the default or provide an irrevocable letter of credit if the default is not cured. FPU’s agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior nine quarters: (a) funds from operation interest coverage (minimum of 2 to 1); and (b) total debt to total capital (maximum of 0.65 to 1). If FPU fails to meet the requirements, we have to provide the supplier a written explanation of action taken or proposed to be taken to be compliant. Failure to comply with the ratios specified in the agreement with Gulf Power could result in FPU having to provide an irrevocable letter of credit. FPU was in compliance with these requirements as of September 30, 2010.

Corporate Guarantees

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 September 30, 2010 was $23.3 million, with the guarantees expiring on various dates through 2011.

In addition to the corporate guarantees, we have issued a letter of credit to our previous primary insurance company for $725,000, which expires on June 1, 2011. The letter of credit to our previous primary insurance company is provided as security to satisfy the deductibles under our various insurance policies. There have been no draws on this letter of credit as of September 30, 2010. We do not anticipate that this letter of credit will be drawn upon by the counterparty. As a result of the change in our primary insurance company in September 2010, we may be required to provide a separate letter of credit to our new primary insurance company. In addition, we have issued a letter of credit for $978,000 to TETLP related to a 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 dekatherms per day (“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 30,000 and 10,000 Dts/d, respectively, 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 (f) 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 ESNG’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 ESNG’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 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 $4.7 million by December 31, 2010. 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 $45 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 of September 30, 2010, we provided a letter of credit for $978,000 under the Precedent Agreement with TETLP as required. This letter of credit is expected to increase quarterly as TETLP’s pre-service costs increase and will not exceed more than the three-month reservation charge under the firm transportation service contracts, which we currently estimate to be $2.1 million.

On March 17, 2010, our Delaware and Maryland divisions entered into a separate Precedent Agreement with ESNG to extend its mainline by eight miles to interconnect with TETLP at Honey Brook, Pennsylvania. The estimated capital cost associated with construction of this mainline extension and interconnection is approximately $19.4 million, and the proposed rate for transmission service on this extension is ESNG’s current tariff rate for service in that area. As discussed in Note 4, “Rates and Other Regulatory Activities,” ESNG obtained the necessary approvals from the FERC to commence construction, which is anticipated to be completed during the fourth quarter of 2010.

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. Our Delaware and Maryland divisions require no regulatory approvals or exemptions to receive transmission service from TETLP or ESNG.

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

7.

Segment Information

We use the management approach to identify operating segments, and we organize our business around differences in regulatory environment and/or products or services. 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.

As a result of the merger with FPU in October 2009, we changed our operating segments to better reflect how the chief operating decision maker reviews the various operations of our Company. Our three operating segments are now composed of the following:

•

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 various PSCs having jurisdiction in each operating territory or by the FERC in the case of ESNG.

•

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 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								Nine Months Ended
For the Periods Ended September 30,		2010				2009				2010				2009
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy		$	53,215			$	15,098			$	196,966			$	85,529
Unregulated Energy			20,134				14,011				103,646				82,982
Other			3,117				2,649				9,175				8,560
Total operating revenues, unaffiliated customers		$	76,466			$	31,758			$	309,787			$	177,071
Intersegment Revenues (1)
Regulated Energy		$	300			$	274			$	822			$	893
Unregulated Energy			—				—				364				254
Other			197				170				644				546
Total intersegment revenues		$	497			$	444			$	1,830			$	1,693
Operating Income (Loss)
Regulated Energy		$	6,536			$	2,971			$	32,360			$	16,554
Unregulated Energy			(2,237	)			(1,361	)			4,732				5,233
Other and eliminations			284				647				650				(709	)
Total operating income		$	4,583			$	2,257			$	37,742			$	21,078
Other income (loss), net of other expenses			102				(26	)			206				19
Interest			2,256				1,540				6,924				4,755
Income taxes			801				383				12,082				6,636
Net income		$	1,628			$	308			$	18,942			$	9,706

		September 30,				December 31,
(in thousands)		2010				2009
Identifiable Assets
Regulated energy		$	498,483			$	480,903
Unregulated energy			84,046				101,437
Other			29,746				34,724
Total identifiable assets		$	612,275			$	617,064

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.

8.

Employee Benefit Plans

Net periodic benefit costs for our pension and post-retirement benefits plans for the three months and nine months ended September 30, 2010 and 2009 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 September 30,		2010				2009				2010				2010				2009				2010				2009				2010
(in thousands)
Service Cost		$	—			$	—			$	—			$	—			$	—			$	—			$	—			$	28
Interest Cost			147				140				638				35				33				30				27				33
Expected return on plan assets			(108	)			(86	)			(618	)			—				—				—				—				—
Amortization of prior service cost			(1	)			(2	)			—				5				3				—				—				—
Amortization of net loss			40				68				—				15				14				15				40				—
Net periodic cost		$	78			$	120			$	20			$	55			$	50			$	45			$	67			$	61
																						Chesapeake
		Chesapeake								FPU				Chesapeake								Postretirement								FPU
		Pension Plan								Pension Plan				SERP								Plan								Medical Plan
For the Nine Months Ended September 30,		2010				2009				2010				2010				2009				2010				2009				2010
(in thousands)
Service Cost		$	—			$	—			$	—			$	—			$	—			$	—			$	1			$	83
Interest Cost			441				420				1,913				105				97				91				81				101
Expected return on plan assets			(323	)			(259	)			(1,856	)			—				—				—				—				—
Amortization of prior service cost			(4	)			(4	)			—				15				10				—				—				—
Amortization of net loss			119				205				—				45				44				44				119				—
Net periodic cost		$	233			$	362			$	57			$	165			$	151			$	135			$	201			$	184