##### Table of Contents



United StatesSecurities 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: March 31, 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
  Delaware
    
    51-0064146(State or other jurisdiction of
    
    (I.R.S. Employerincorporation 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)
 þ o
 o o
  Large accelerated filer o
    
    Accelerated filer þ
    
    Non-accelerated filer o
    
    Smaller reporting company o
 o þ




---



##### 



Table of Contents
 PART I  FINANCIAL INFORMATION
    
    
    1Item 1. Financial Statements
    
    
    1Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
    
    
    27Item 3. Quantitative and Qualitative Disclosures about Market Risk
    
    
    42Item 4. Controls and Procedures
    
    
    43PART II  OTHER INFORMATION
    
    
    44Item 1. Legal Proceedings
    
    
    44Item 1A. Risk Factors
    
    
    44Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
    
    
    44Item 3. Defaults upon Senior Securities
    
    
    44Item 5. Other Information
    
    
    44Item 6. Exhibits
    
    
    45SIGNATURES
    
    
    46Exhibit 4.1Exhibit 31.1Exhibit 31.2Exhibit 32.1Exhibit 32.2




---



##### Table of Contents



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 ChesapeakeChesapeake
    
    The Registrant, the Registrant and its subsidiaries, or the Registrants
subsidiaries, as appropriate in the context of the disclosureCompany
    
    The Registrant, the Registrant and its subsidiaries, or the Registrants
subsidiaries, as appropriate in the context of the disclosureEastern Shore
    
    Eastern Shore Natural Gas Company, a wholly-owned subsidiary of ChesapeakeFPU
    
    Florida Public Utilities Company, a wholly-owned subsidiary of Chesapeake,
effective October 28, 2009PESCO
    
    Peninsula Energy Services Company, Inc., a wholly-owned subsidiary of ChesapeakePeninsula Pipeline
    
    Peninsula Pipeline Company, Inc., a wholly-owned subsidiary of ChesapeakeSharp
    
    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 CommissionEPA
    
    United Sates Environmental
Protection AgencyFERC
    
    Federal Energy Regulatory CommissionFDEP
    
    Florida Department of Environmental ProtectionFDOT
    
    Florida Department of TransportationFlorida PSC
    
    Florida Public Service CommissionMaryland PSC
    
    Maryland Public Service CommissionMDE
    
    Maryland Department of the EnvironmentPSC
    
    Public Service CommissionSEC
    
    Securities and Exchange Commission
 Accounting Standards Related
 GAAP
    
    Generally Accepted Accounting Principles
 Other
 AS/SVE
    
    Air Sparging and Soil/Vapor ExtractionBS/SVE
    
    Bio-Sparging and Soil/Vapor ExtractionCDD
    
    Cooling Degree-DaysDSCP
    
    Directors Stock Compensation PlanDts
    
    DekathermsDts/d
    
    Dekatherms per dayECCR
    
    Energy Conservation Cost RecoveryFGT
    
    Florida Gas Transmission CompanyFRP
    
    Fuel Retention PercentageGSR
    
    Gas Sales Service RatesGulf Power
    
    Gulf Power CorporationGulfstream
    
    Gulfstream Natural Gas System, LLCHDD
    
    Heating Degree-DaysMWH
    
    Megawatt HourMcf
    
    Thousand Cubic FeetMGP
    
    Manufactured Gas PlantNYSE
    
    New York Stock ExchangeOTC
    
    Over-the-CounterPIP
    
    Performance Incentive PlanRAP
    
    Remedial Action PlanSanford Group
    
    FPU and Other Responsible Parties involved with the Sanford Environmental SiteTETLP
    
    Texas Eastern Transmission, LPTOU
    
    Time-of-Use




---



##### Table of Contents



PART I  FINANCIAL INFORMATION
 
 Item 1.
    
    Financial Statements
 Chesapeake Utilities Corporation and Subsidiaries
 Condensed Consolidated Statements of Income

(Unaudited)
 For the Three Months Ended March 31,
    
    2011
    
    
    2010(in thousands, except shares and per share data)Operating RevenuesRegulated Energy
    
    $
    85,002
    
    
    $
    91,626Unregulated Energy
    
    
    58,750
    
    
    
    59,269Other
    
    
    2,845
    
    
    
    2,365Total operating revenues
    
    
    146,597
    
    
    
    153,260Operating ExpensesRegulated energy cost of sales
    
    
    47,990
    
    
    
    54,263Unregulated energy and other cost of sales
    
    
    44,289
    
    
    
    45,091Operations
    
    
    19,837
    
    
    
    18,714Maintenance
    
    
    1,702
    
    
    
    1,700Depreciation and amortization
    
    
    5,021
    
    
    
    5,128Other taxes
    
    
    2,919
    
    
    
    2,966Total operating expenses
    
    
    121,758
    
    
    
    127,862Operating Income
    
    
    24,839
    
    
    
    25,398Other income, net of expenses
    
    
    22
    
    
    
    115Interest charges
    
    
    2,150
    
    
    
    2,363Income Before Income Taxes
    
    
    22,711
    
    
    
    23,150Income tax expense
    
    
    8,964
    
    
    
    9,176Net Income
    
    $
    13,747
    
    
    $
    13,974Weighted-Average Common Shares Outstanding:Basic
    
    
    9,535,381
    
    
    
    9,419,932Diluted
    
    
    9,633,796
    
    
    
    9,524,298Earnings Per Share of Common Stock:Basic
    
    $
    1.44
    
    
    $
    1.48Diluted
    
    $
    1.43
    
    
    $
    1.47Cash Dividends Declared Per Share of Common Stock
    
    $
    0.330
    
    
    $
    0.315
   - 1 -




---



##### Table of Contents



Chesapeake Utilities Corporation and Subsidiaries
 Condensed Consolidated Statements of Cash Flows


(Unaudited)
 For the Three Months Ended March 31,
    
    2011
    
    
    2010(in thousands)Operating ActivitiesNet Income
    
    $
    13,747
    
    
    $
    13,974Adjustments to reconcile net income to net cash provided by operating activities:Depreciation and amortization
    
    
    5,021
    
    
    
    5,128Depreciation and accretion included in other costs
    
    
    1,055
    
    
    
    861Deferred income taxes, net
    
    
    8,889
    
    
    
    369Loss on sale of assets
    
    
    57
    
    
    
    Unrealized gain on commodity contracts
    
    
    (83
    )
    
    
    (215
    )Unrealized gain on investments
    
    
    (143
    )
    
    
    (51
    )Employee benefits
    
    
    497
    
    
    
    (272
    )Share-based compensation
    
    
    329
    
    
    
    333Other, net
    
    
    (16
    )
    
    
    41Changes in assets and liabilities:Purchase of investments
    
    
    (44
    )
    
    
    (30
    )Accounts receivable and accrued revenue
    
    
    7,466
    
    
    
    15,800Propane inventory, storage gas and other inventory
    
    
    5,777
    
    
    
    6,155Regulatory assets
    
    
    488
    
    
    
    2,164Prepaid expenses and other current assets
    
    
    1,528
    
    
    
    1,913Accounts payable and other accrued liabilities
    
    
    (10,670
    )
    
    
    (12,741
    )Income taxes receivable
    
    
    (270
    )
    
    
    8,580Accrued interest
    
    
    844
    
    
    
    949Customer deposits and refunds
    
    
    (2,165
    )
    
    
    604Accrued compensation
    
    
    (2,009
    )
    
    
    (980
    )Regulatory liabilities
    
    
    4,372
    
    
    
    3,314Other liabilities
    
    
    (400
    )
    
    
    503Net cash provided by operating activities
    
    
    34,270
    
    
    
    46,399Investing ActivitiesProperty, plant and equipment expenditures
    
    
    (8,355
    )
    
    
    (6,099
    )Proceeds from sales of assets
    
    
    299
    
    
    
    Purchase of investments
    
    
    
    
    
    
    (310
    )Environmental expenditures
    
    
    (164
    )
    
    
    (367
    )Net cash used in investing activities
    
    
    (8,220
    )
    
    
    (6,776
    )Financing ActivitiesCommon stock dividends
    
    
    (2,836
    )
    
    
    (2,683
    )(Purchase) issuance of stock for Dividend Reinvestment Plan
    
    
    (307
    )
    
    
    152Change in cash overdrafts due to outstanding checks
    
    
    (2,791
    )
    
    
    (834
    )Net repayment under line of credit agreements
    
    
    (19,740
    )
    
    
    (29,188
    )Other Short-term borrowing
    
    
    
    
    
    
    29,100Repayment of long-term debt
    
    
    (35
    )
    
    
    (28,858
    )Net cash used in financing activities
    
    
    (25,709
    )
    
    
    (32,311
    )Net Decrease in Cash and Cash Equivalents
    
    
    341
    
    
    
    7,312Cash and Cash Equivalents  Beginning of Period
    
    
    1,643
    
    
    
    2,828Cash and Cash Equivalents  End of Period
    
    $
    1,984
    
    
    $
    10,140
   - 2 -




---



##### Table of Contents



Chesapeake Utilities Corporation and Subsidiaries
 Condensed Consolidated Balance Sheets


(Unaudited)
 March 31,
    
    
    December 31,Assets
    
    2011
    
    
    2010(in thousands, except shares and per share data)Property, Plant and EquipmentRegulated energy
    
    $
    505,448
    
    
    $
    500,689Unregulated energy
    
    
    61,595
    
    
    
    61,313Other
    
    
    18,326
    
    
    
    16,989Total property, plant and equipment
    
    
    585,369
    
    
    
    578,991Less: Accumulated depreciation and amortization
    
    
    (125,437
    )
    
    
    (121,628
    )Plus: Construction work in progress
    
    
    4,941
    
    
    
    5,394Net property, plant and equipment
    
    
    464,873
    
    
    
    462,757Investments, at fair value
    
    
    3,835
    
    
    
    4,036Current AssetsCash and cash equivalents
    
    
    1,984
    
    
    
    1,643Accounts receivable (less allowance for uncollectible
accounts of $1,122 and $1,194, respectively)
    
    
    85,699
    
    
    
    88,074Accrued revenue
    
    
    9,888
    
    
    
    14,978Propane inventory, at average cost
    
    
    6,553
    
    
    
    8,876Other inventory, at average cost
    
    
    3,103
    
    
    
    3,084Regulatory assets
    
    
    227
    
    
    
    51Storage gas prepayments
    
    
    1,610
    
    
    
    5,084Income taxes receivable
    
    
    7,018
    
    
    
    6,748Deferred income taxes
    
    
    2,138
    
    
    
    2,191Prepaid expenses
    
    
    3,077
    
    
    
    4,613Mark-to-market energy assets
    
    
    339
    
    
    
    1,642Other current assets
    
    
    182
    
    
    
    245Total current assets
    
    
    121,818
    
    
    
    137,229Deferred Charges and Other AssetsGoodwill
    
    
    35,613
    
    
    
    35,613Other intangible assets, net
    
    
    3,376
    
    
    
    3,459Long-term receivables
    
    
    77
    
    
    
    155Regulatory assets
    
    
    22,857
    
    
    
    23,884Other deferred charges
    
    
    3,853
    
    
    
    3,860Total deferred charges and other assets
    
    
    65,776
    
    
    
    66,971Total Assets
    
    $
    656,302
    
    
    $
    670,993
   - 3 -




---



##### Table of Contents



Chesapeake Utilities Corporation and Subsidiaries
 Condensed Consolidated Balance Sheets (Unaudited)
 March 31,
    
    
    December 31,Capitalization and Liabilities
    
    2011
    
    
    2010(in thousands, except shares and per share data)CapitalizationStockholders equityCommon stock, par value $0.4867 per share
(authorized 25,000,000 shares)
    
    $
    4,648
    
    
    $
    4,635Additional paid-in capital
    
    
    148,055
    
    
    
    148,159Retained earnings
    
    
    87,355
    
    
    
    76,805Accumulated other comprehensive loss
    
    
    (3,043
    )
    
    
    (3,360
    )Deferred compensation obligation
    
    
    786
    
    
    
    777Treasury stock
    
    
    (786
    )
    
    
    (777
    )Total stockholders equity
    
    
    237,015
    
    
    
    226,239Long-term debt, net of current maturities
    
    
    89,565
    
    
    
    89,642Total capitalization
    
    
    326,580
    
    
    
    315,881Current LiabilitiesCurrent portion of long-term debt
    
    
    9,196
    
    
    
    9,216Short-term borrowing
    
    
    41,427
    
    
    
    63,958Accounts payable
    
    
    53,307
    
    
    
    65,541Customer deposits and refunds
    
    
    24,221
    
    
    
    26,317Accrued interest
    
    
    2,633
    
    
    
    1,789Dividends payable
    
    
    3,151
    
    
    
    3,143Accrued compensation
    
    
    4,821
    
    
    
    6,784Regulatory liabilities
    
    
    13,440
    
    
    
    9,009Mark-to-market energy liabilities
    
    
    107
    
    
    
    1,492Other accrued liabilities
    
    
    12,527
    
    
    
    10,393Total current liabilities
    
    
    164,830
    
    
    
    197,642Deferred Credits and Other LiabilitiesDeferred income taxes
    
    
    89,079
    
    
    
    80,031Deferred investment tax credits
    
    
    223
    
    
    
    243Regulatory liabilities
    
    
    3,675
    
    
    
    3,734Environmental liabilities
    
    
    9,205
    
    
    
    10,587Other pension and benefit costs
    
    
    18,077
    
    
    
    18,199Accrued asset removal cost  Regulatory liability
    
    
    35,593
    
    
    
    35,092Other liabilities
    
    
    9,040
    
    
    
    9,584Total deferred credits and other liabilities
    
    
    164,892
    
    
    
    157,470Total Capitalization and Liabilities
    
    $
    656,302
    
    
    $
    670,993
   - 4 -




---



##### Table of Contents



Chesapeake Utilities Corporation and Subsidiaries
 Condensed Consolidated Statements of Stockholders Equity

(Unaudited)
 Common Stock
    
    
    Additional
    
    
    
    
    
    
    Accumulated OtherNumber of
    
    
    
    
    
    
    Paid-In
    
    
    Retained
    
    
    Comprehensive
    
    
    Deferred
    
    
    Treasury(in thousands, except shares and per share data)
    
    Shares(6)
    
    
    Par Value
    
    
    Capital
    
    
    Earnings
    
    
    Loss
    
    
    Compensation
    
    
    Stock
    
    
    TotalBalances at December 31, 2009
    
    
    9,394,314
    
    
    $
    4,572
    
    
    $
    144,502
    
    
    $
    63,231
    
    
    $
    (2,524
    )
    
    $
    739
    
    
    $
    (739
    )
    
    $
    209,781Net Income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    26,056
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    26,056Other comprehensive income, net of tax:Employee Benefit Plans, net of tax:Amortization of prior service costs (4)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    8
    
    
    
    
    
    
    
    
    
    
    
    8Net Loss (5)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (844
    )
    
    
    
    
    
    
    
    
    
    
    (844
    )Total comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    25,220Dividend Reinvestment Plan
    
    
    53,806
    
    
    
    26
    
    
    
    1,699
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,725Retirement Savings Plan
    
    
    27,795
    
    
    
    14
    
    
    
    889
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    903Conversion of debentures
    
    
    11,865
    
    
    
    6
    
    
    
    196
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    202Tax benefit on share based compensation
    
    
    
    
    
    
    
    
    
    
    253
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    253Share based compensation (1) (3)
    
    
    36,415
    
    
    
    17
    
    
    
    620
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    637Deferred Compensation Plan
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    38
    
    
    
    (38
    )
    
    
    Purchase of treasury stock
    
    
    1,144
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (38
    )
    
    
    (38
    )Sale and distribution of treasury stock
    
    
    (1,144
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    38
    
    
    
    38Dividends on stock-based compensation
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (104
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (104
    )Cash dividends (2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (12,378
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (12,378
    )Balances at December 31, 2010
    
    
    9,524,195
    
    
    
    4,635
    
    
    
    148,159
    
    
    
    76,805
    
    
    
    (3,360
    )
    
    
    777
    
    
    
    (777
    )
    
    
    226,239Net Income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    13,747
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    13,747Other comprehensive income, net of tax:Employee Benefit Plans, net of tax:Amortization of prior service costs (4)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    
    
    
    
    
    
    
    
    2Net Gain (5)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    315
    
    
    
    
    
    
    
    
    
    
    
    315Total comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    14,064Dividend Reinvestment Plan
    
    
    
    
    
    
    
    
    
    
    (5
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (5
    )Retirement Savings Plan
    
    
    2,002
    
    
    
    1
    
    
    
    78
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    79Conversion of debentures
    
    
    3,637
    
    
    
    2
    
    
    
    60
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    62Share based compensation (1) (3)
    
    
    19,630
    
    
    
    10
    
    
    
    (237
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (227
    )Deferred Compensation Plan
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    9
    
    
    
    (9
    )
    
    
    Purchase of treasury stock
    
    
    (242
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (9
    )
    
    
    (9
    )Sale and distribution of treasury stock
    
    
    242
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    9
    
    
    
    9Dividends on stock-based compensation
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (46
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (46
    )Cash dividends (2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (3,151
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (3,151
    )Balances at March 31, 2011
    
    
    9,549,464
    
    
    $
    4,648
    
    
    $
    148,055
    
    
    $
    87,355
    
    
    $
    (3,043
    )
    
    $
    786
    
    
    $
    (786
    )
    
    $
    237,015
 (1)
    
    Includes amounts for shares issued for Directors compensation.(2)
    
    Cash dividends declared per share for the periods ended March 31, 2011 and December
31, 2010 were $0.33 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 March 31, 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 March 31, 2011 and December 31, 2010 were approximately $1 and $5,
respectively.(5)
    
    Tax expense (benefit) recognized on the net gain (loss) component of employees
benefit plans for the periods ended March 31, 2011 and December 31, 2010, were $211 and ($541),
respectively.(6)
    
    Includes 29,838 and 29,596 shares at March 31, 2011 and December 31, 2010,
respectively, held in a Rabbi Trust established by the Company relating to the Deferred
Compensation Plan.   - 5 -




---



##### Table of Contents



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 and cash
flows for the three months ended March 31, 2010 to conform to the current years presentation.
These reclassifications are considered immaterial to the overall presentation of our
consolidated financial statements.
  - 6 -




---



##### Table of Contents



2.
    
    Calculation of Earnings Per Share
 For the Three Months Ended March 31,
    
    2011
    
    
    2010(in thousands, except shares and per share data)Calculation of Basic Earnings Per Share:Net Income
    
    $
    13,747
    
    
    $
    13,974Weighted average shares outstanding
    
    
    9,535,381
    
    
    
    9,419,932Basic Earnings Per Share
    
    $
    1.44
    
    
    $
    1.48Calculation of Diluted Earnings Per Share:Reconciliation of Numerator:Net Income
    
    $
    13,747
    
    
    $
    13,974Effect of 8.25% Convertible debentures
    
    
    16
    
    
    
    19Adjusted numerator  Diluted
    
    $
    13,763
    
    
    $
    13,993Reconciliation of Denominator:Weighted shares outstanding  Basic
    
    
    9,535,381
    
    
    
    9,419,932Effect of dilutive securities:Share-based Compensation
    
    
    23,246
    
    
    
    16,0908.25% Convertible debentures
    
    
    75,169
    
    
    
    88,276Adjusted denominator  Diluted
    
    
    9,633,796
    
    
    
    9,524,298Diluted Earnings Per Share
    
    $
    1.43
    
    
    $
    1.47
 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 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. 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.
  - 7 -




---



##### Table of Contents



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. The parties involved filed opening briefs with the Delaware Superior Court
on September 30, 2010, answering briefs on October 20, 2010, and reply briefs on November 3,
2010. Oral arguments were presented on March 14, 2011, in which the parties presented their respective
positions. We have not accrued any contingent liability related to potential refunds for past
capacity releases. We anticipate that the Court will render a decision sometime in 2011. In
addition, 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. Since the
Delaware PSCs Order on May 18, 2010, the Delaware division has not released any capacity to
PESCO.
 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 no later than
the third quarter of 2011.
 On March 10, 2011, the Delaware division filed with the Delaware PSC an application requesting
approval to guarantee certain debt of Florida Public Utilities Company (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 indenture of FPUs debt. The Delaware PSC granted
approval of this guarantee at its regularly scheduled meeting on April 4, 2011.
  - 8 -




---



##### Table of Contents



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 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. No adverse comments have been filed since the Order.
 Florida
 In the Order dated December 15, 2009, approving the rate increase for Chesapeakes Florida
division, the Florida PSC ordered Chesapeakes Florida division and FPUs natural gas
distribution operation to submit data that details all known benefits, synergies, cost savings and cost increases resulting
from the merger in a Come-Back filing. We submitted this filing on April 29, 2010 and also
requested 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. We did not request any change to the existing rates previously approved
by the Florida PSC.
 In 2010, we recorded a $750,000 accrual based on our assessment of FPUs current 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.
 On September 1, 2010, FPUs electric distribution operation filed its annual Fuel and Purchased
Power Cost Recovery Clause, seeking final approval of the levelized fuel adjustment and
purchased power cost recovery factors for 2011. On December 20, 2010, the Florida PSC issued an
order approving the proposed 2011 fuel rates, effective for meters read on and after January 1,
2011.
 On September 10, 2010, FPUs electric distribution operation filed its annual Energy
Conservation Cost Recovery (ECCR) Clause, seeking final approval of the 2009
conservation-related revenues and expenses and new ECCR recovery factors for 2011. On November
29, 2010, the Florida PSC issued an order approving the proposed 2011 ECCR recovery factors,
effective for meters read on and after January 1, 2011.
 On September 13, 2010, Chesapeakes Florida division, FPUs Indiantown division and FPUs
natural gas distribution operation separately filed their annual ECCR Clauses, seeking final
approval of the 2009 conservation-related revenues and expenses and new ECCR recovery factors
for 2011. On November 29, 2010, the Florida PSC issued an order approving all of the proposed
2011 ECCR recovery factors, effective for meters read on or after January 1, 2011.
 On September 13, 2010, FPUs natural gas distribution operation filed its annual Purchased Gas
Adjustment (PGA) Clause, seeking final approval of its 2009 purchased gas-related revenues and
expenses and new PGA cap rate for 2011. On November 29, 2010, the Florida PSC issued an order
approving the proposed 2011 PGA cap rate, effective for meters read on or after January 1, 2011.
  - 9 -




---



##### Table of Contents



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 that shall be mutually agreed upon by FPU and the City. 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 are not in effect by February 17, 2011, the City has 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 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 elects to
purchase the Marianna property, the Franchise Agreement requires the City to pay FPU the fair
market value for such property as determined by three qualified appraisers. Future financial
results would be negatively impacted from 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, filed a petition with the Florida PSC for
authority to implement such proposed TOU and interruptible rates for approval and implementation
on or before February 17, 2011. On February 11, 2011, the Florida PSC issued an order approving
the proposed TOU and interruptible rates for a four-year period. The City has objected to the
proposed rates and has filed a petition protesting the entry of the Florida PSCs order.
 As disclosed in Note 5, Other Commitments and Contingencies, the City, on March 2, 2011, filed
a declaratory action 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 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. FPU
filed its answer with the court in the declaratory action on March 28, 2011.
 On January 26, 2011, FPU filed a Petition with the Florida PSC for approval of an amendment to the Generation Services Agreement
with Gulf Power Corporation. The amendment provides for a reduction in the capacity demand
quantity, which provides for the savings necessary to support the TOU and interruptible rates
approved in Docket No. 100459-EI. The amendment also extends the current agreement by two
years, with a new expiration date of December 31, 2019. The Florida PSC Staff is expected to
issue their recommendation on May 12, 2011. This Petition is scheduled for the May 24, 2011
Florida PSC Agenda Conference.
 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, 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. 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 began billing the five-year surcharge effective March 1, 2011.
  - 10 -




---



##### Table of Contents



Mainline Extension and Interconnect Project: On March 5, 2010, Eastern Shore 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 TETLP. Eastern Shores project involved building and operating an eight-mile mainline
extension from Eastern Shores existing facility in Parkesburg, Pennsylvania to the
interconnection with TETLP at Honey Brook, Pennsylvania. The estimated capital cost of this
project was approximately $19.4 million. On September 3, 2010, the FERC approved Eastern
Shores application, subject to certain environmental conditions, some of which had to be met
prior to the commencement of construction. Eastern Shore 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. The facilities were completed on December 15,
2010, and on December 21, Eastern Shore received FERC approval to place the facilities into
service. Eastern Shore commenced billing for the new service on January 1, 2011.
 Rate Case Filing:On December 30, 2010, Eastern Shore filed a base rate proceeding in
compliance with the terms of the settlement in its prior base rate proceeding. Eastern Shores
filed rates, proposed to be effective February 1, 2011, reflect an annual increase of $6,748,628
over its current rates. The proposed rate increase reflects increases in operating and
maintenance expenses, depreciation expense, and return on existing and new gas plant facilities
that are expected to be placed into service before June 30, 2011. Eastern Shore proposed a
return on equity of 13.5 percent. 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. Staff issued their Top Sheet on April 7, 2011, summarizing Staffs initial position on this case, and the first settlement
conference was held on April 14, 2011. Eastern Shore expects the base rate proceeding to be
completed 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 the Delaware City Refining
Company LLC. The FERC published notice of this filing on April 7, 2011; assuming no protest
during the 60-day period following the notice, the requested authorization will become
effective.
 On April 28, 2011, Eastern Shore filed a notice of its intent under its blanket certification 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 will publish notice of this filing within ten days of the date of the filing; assuming no protest during the 60-day period following the notice, the requested authorization will become effective.
 Also on April 28, 2011,
Eastern Shore file a notice of its intent under its blanket certification 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. The FERC will publish notice of this filing within ten days of the date of the filing; assuming no protest during the 60-day period
following the notice, the requested authorization will become effective.
 Eastern Shore also had developments in the following FERC matters:
    - 11 -




---



##### Table of Contents



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 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 March 31, 2011, we had $324,000 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 March 31, 2011, we had approximately $1.2 million in regulatory and other
assets for future recovery of environmental costs from Chesapeakes customers through our
approved rates. As of March 31, 2011, we had approximately $11.4 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 $7.9 million of FPUs expected environmental costs have been
recovered from insurance and customers through rates as of March 31, 2011. We also had
approximately $6.1 million in regulatory assets for future recovery of environmental costs from
FPUs customers.
 The following discussion provides details on each site.
 Salisbury, Maryland
   Winter Haven, Florida
   - 12 -




---



##### Table of Contents



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 the FDEP for review. On June 24, 2010, the 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. As a result, we plan to
perform the excavation 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 March 31, 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
$324,000. We have recovered through rates $1.4 million of the costs to remediate the Winter
Haven site and continue to expect that the remaining $602,000, 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. 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 seeking to meet with FPU and the current site owner to discuss additional field work
which the FDEP believes is warranted for the site. Potential costs for investigation and
remediation are projected to be $153,000.
 Pensacola, Florida
 FPU formerly owned and operated an MGP in Pensacola, Florida. The MGP 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. At this point, 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 $7,000.
 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 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 total estimated
remediation costs for this site were projected at the time by EPA to be approximately $12.9
million.
  - 13 -




---



##### Table of Contents



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 March 31, 2011, 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 March 31, 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 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 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 the FDEP for their review and comment in October 2010.
On November 4, 2010, the FDEP issued its comments on the feasibility study and the proposed
remedy. On November 16, 2010, FPU presented to the FDEP a new remedial action plan for the
site, and the FDEP agreed with FPUs proposal to implement a phased approach to remediation.
On December 22, 2010, FPU submitted to the FDEP an interim RAP to remediate the east parcel
of the site, which the FDEP conditionally approved on February 4, 2011.
  - 14 -




---



##### Table of Contents



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. We estimate that the
updated costs of remediation will range from approximately $5.1 million to $13.3 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 re-development of the properties.
 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.
 5.
    
    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 court approved the final settlement, 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, the distribution to the class must be made by
May 13, 2011.
 On March 2, 2011, the City of Marianna, Florida filed a declaratory action 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 to provide
electric service to customers within and without the City by failing: (i) to develop and
implement TOU and interruptible rates that were mutually agreed to by the City 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. The City is seeking a declaratory judgment 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 for approval of the purchase and the operation by the City of
an electric distribution facility. If the purchase is approved by the Marianna Commission
and the referendum, the closing of the purchase must occur within 12 months after the
referendum is approved. On March 17, 2011, FPU filed a Motion to Dismiss the Citys protest
and request for hearing. On March 24, 2011, the City filed its response to FPUs Motion to
Dismiss. On March 28, 2011, FPU filed its answer with the court in the declaratory action. 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.
  - 15 -




---



##### Table of Contents



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.
 PESCO is currently in the process of obtaining and reviewing proposals from suppliers and
anticipates executing agreements before its existing agreements 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 requires FPU
to comply with the following ratios based on the result 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. 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 operation 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 action taken
or proposed to be taken to be 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
March 31, 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 March 31, 2011 was $26.0 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 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 the recent change in our primary insurance company, we have issued
an additional letter of credit for $725,000 to our former primary insurance company, which
will expire on June 1, 2011. There have been no draws on these letters of credit as of
March 31, 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 $2.1 million to TETLP related to the Precedent Agreement
with TETLP, which is further described below.
  - 16 -




---



##### Table of Contents



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 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 (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 $9.6 million as of
March 31, 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 $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 March 31, 2011, we provided a letter of credit for $2.1 million, as required under the
Precedent Agreement with TETLP. This letter of credit 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 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, 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.
  - 17 -




---



##### Table of Contents



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 Eastern Shore.
 As the Eastern Shore and TETLP firm transportation services commence, our Delaware and
Maryland divisions 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 Eastern Shore and TETLP
firm transportation services 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 March 31, 2011, we maintained an accrual of $698,000
related to additional sales taxes and gross receipts taxes owed to various states.
 Other Contingency
 As of March 31, 2011, we maintained a $750,000 accrual, which was recorded in 2010 based on managements assessment of FPUs current 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 Condensed Consolidated Financial Statements for further discussion).
 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 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.
  - 18 -




---



##### Table of Contents



The following table presents information about our reportable segments.
 For the Three Months Ended March 31,
    
    2011
    
    
    2010(in thousands)Operating Revenues, Unaffiliated CustomersRegulated Energy
    
    $
    84,683
    
    
    $
    91,300Unregulated Energy
    
    
    58,750
    
    
    
    59,027Other
    
    
    3,164
    
    
    
    2,933Total operating revenues, unaffiliated customers
    
    $
    146,597
    
    
    $
    153,260Intersegment Revenues(1)Regulated Energy
    
    $
    319
    
    
    $
    326Unregulated Energy
    
    
    
    
    
    
    242Other
    
    
    194
    
    
    
    187Total intersegment revenues
    
    $
    513
    
    
    $
    755Operating IncomeRegulated Energy
    
    $
    16,309
    
    
    $
    17,516Unregulated Energy
    
    
    8,515
    
    
    
    7,760Other and eliminations
    
    
    15
    
    
    
    122Total operating income
    
    
    24,839
    
    
    
    25,398Other income, net of other expenses
    
    
    22
    
    
    
    115Interest
    
    
    2,150
    
    
    
    2,363Income taxes
    
    
    8,964
    
    
    
    9,176Net income
    
    $
    13,747
    
    
    $
    13,974
 (1)
    
    All significant intersegment revenues are billed at market rates and have been eliminated
from consolidated operating revenues. March 31,
    
    
    December 31,(in thousands)
    
    2011
    
    
    2010Identifiable AssetsRegulated energy
    
    $
    509,275
    
    
    $
    520,192Unregulated energy
    
    
    109,375
    
    
    
    113,039Other
    
    
    37,652
    
    
    
    37,762Total identifiable assets
    
    $
    656,302
    
    
    $
    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.
  - 19 -




---



##### Table of Contents



7.
    
    Employee Benefit Plans
 Net periodic benefit costs for our pension and postretirement benefits plans for the three
months ended March 31, 2011 and 2010 are set forth in the following table:
 ChesapeakeChesapeake
    
    
    FPU
    
    
    Chesapeake
    
    
    Postretirement
    
    
    FPUPension Plan
    
    
    Pension Plan
    
    
    SERP
    
    
    Plan
    
    
    Medical PlanFor the Three Months Ended March 31,
    
    2011
    
    
    2010
    
    
    2011
    
    
    2010
    
    
    2011
    
    
    2010
    
    
    2011
    
    
    2010
    
    
    2011
    
    
    2010(in thousands)Service Cost
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    26
    
    
    $
    28Interest Cost
    
    
    130
    
    
    
    145
    
    
    
    671
    
    
    
    638
    
    
    
    27
    
    
    
    34
    
    
    
    15
    
    
    
    30
    
    
    
    39
    
    
    
    34Expected return on plan assets
    
    
    (101
    )
    
    
    (106
    )
    
    
    (684
    )
    
    
    (619
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Amortization of prior service cost
    
    
    (1
    )
    
    
    (1
    )
    
    
    
    
    
    
    
    
    
    
    5
    
    
    
    5
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Amortization of net loss
    
    
    39
    
    
    
    39
    
    
    
    
    
    
    
    
    
    
    
    10
    
    
    
    16
    
    
    
    
    
    
    
    15
    
    
    
    5
    
    
    
    Net periodic cost (benefit)
    
    
    67
    
    
    
    77
    
    
    
    (13
    )
    
    
    19
    
    
    
    42
    
    
    
    55
    
    
    
    15
    
    
    
    45
    
    
    
    70
    
    
    
    62Settlement expense
    
    
    217
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Amortization of pre-merger regulatory asset
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    317
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    3Total periodic cost
    
    $
    284
    
    
    $
    77
    
    
    $
    (13
    )
    
    $
    336
    
    
    $
    42
    
    
    $
    55
    
    
    $
    15
    
    
    $
    45
    
    
    $
    72
    
    
    $
    65
 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 in the
first quarter of 2011 related to a lump-sum pension distribution of $844,000 from the Chesapeake
Pension Plan in January 2011 and $219,000 of an estimated 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 $6.5 million and $6.7 million at March 31, 2011 and December 31, 2010, respectively.
 During the three months ended March 31, 2011, we contributed $68,000 and $263,000 to the
Chesapeake and FPU pension plans, respectively. We expect to contribute $205,000 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 months ended March 31, 2011, were $22,000; 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 months ended March 31, 2011,
totaled $24,000; 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 months ended March 31, 2011, totaled $11,000; 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 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.
  - 20 -




---



##### Table of Contents



8.
    
    Investments
 The investment balance at March 31, 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 an associated liability that is recorded and adjusted each
month for the gains and losses incurred by the Rabbi Trusts. At March 31, 2011 and December 31,
2010, total investments had a fair value of $3.8 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 months ended March 31,
2011 and 2010:
 For the Three Months Ended March 31,
    
    2011
    
    
    2010(in thousands)Directors Stock Compensation Plan
    
    $
    84
    
    
    $
    64Performance Incentive Plan
    
    
    245
    
    
    
    269Total compensation expense
    
    
    329
    
    
    
    333Less: tax benefit
    
    
    132
    
    
    
    134Share-Based Compensation amounts included in net income
    
    $
    197
    
    
    $
    199
 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 January 2011, 304 shares
were granted to our former Chief Executive Officer John Schimkaitis, under the DSCP as he
retired from the Company and began his service as a non-executive Vice Chairman of the Board.
 Number of
    
    
    Weighted AverageShares
    
    
    Grant Date Fair ValueOutstanding  December 31, 2010
    
    
    
    
    
    
    Granted
    
    
    304
    
    
    $
    41.54Vested
    
    
    304
    
    
    $
    41.54Forfeited
    
    
    
    
    
    
    Outstanding  March 31, 2011
    
    
    
    
    
    
    
 At March 31, 2011, there was $28,000 of unrecognized compensation expense related to the
DSCP awards that is expected to be recognized over the remaining directors service periods
ending April 30, 2011.
  - 21 -




---



##### Table of Contents



Performance Incentive Plan
 The table below presents the summary of the stock activity for the PIP for the three months
ended March 31, 2011:
 Weighted AverageNumber of Shares
    
    
    Fair ValueOutstanding  December 31, 2010
    
    
    101,150
    
    
    $
    28.78Granted
    
    
    41,664
    
    
    
    39.81Vested
    
    
    31,400
    
    
    
    27.63Fortfeited
    
    
    24,000
    
    
    
    29.31Expired
    
    
    
    
    
    
    Outstanding  March 31, 2011
    
    
    87,414
    
    
    $
    34.31
 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 March 31, 2011, the aggregate intrinsic value of the PIP awards was $1.9 million.
 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 and propane.
Our natural gas and propane distribution operations have entered into agreements with suppliers
to purchase natural gas 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 March 31, 2011, our natural gas and propane distribution operations
did not have any outstanding derivative contracts.
 Xeron, our propane wholesale and marketing operation, 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 March 31, 2011, we had the following outstanding trading contracts
which we accounted for as derivatives:
 Quantity in
    
    
    Estimated Market
    
    
    Weighted AverageAt March 31, 2011
    
    Gallons
    
    
    Prices
    
    
    Contract PricesForward ContractsSale
    
    
    11,844,000
    
    
    $
    1.0800  $1.4525
    
    
    $
    1.3405Purchase
    
    
    12,054,000
    
    
    $
    1.1200  $1.4500
    
    
    $
    1.3222
 Estimated market prices and weighted average contract prices are in dollars per gallon.
 All contracts expire during or prior to the fourth quarter of 2011.
  - 22 -




---



##### Table of Contents



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 March 31, 2011 and December 31, 2010, are the following:
 Asset DerivativesFair Value(in thousands)
    
    Balance Sheet Location
    
    
    March 31, 2011
    
    
    December 31, 2010Derivatives not designated
as hedging instrumentsForward contracts
    
    Mark-to-market energy assets
    
    
    $
    339
    
    
    $
    1,642Put option (1)
    
    Mark-to-market energy assets
    
    
    
    
    
    
    
    Total asset derivatives
    
    
    
    
    
    $
    339
    
    
    $
    1,642
 Liability DerivativesFair Value(in thousands)
    
    Balance Sheet Location
    
    
    March 31, 2011
    
    
    December 31, 2010Derivatives not designated
as hedging instrumentsForward contracts
    
    Mark-to-market energy liabilities
    
    
    $
    107
    
    
    $
    1,492Total liability derivatives
    
    
    
    
    
    $
    107
    
    
    $
    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 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 March 31,(in thousands)
    
    (Loss) on Derivatives
    
    
    2011
    
    
    2010Derivatives not designated
as hedging instruments:Put Option(1) (2)
    
    Cost of Sales
    
    $
    
    
    
    $
    Unrealized gain on forward contracts
    
    Revenue
    
    
    83
    
    
    
    215Total
    
    
    
    
    
    $
    83
    
    
    $
    215
 (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
  - 23 -




---



##### Table of Contents



The effects of trading activities on the condensed consolidated statements of income
are the following:
 Amount of Trading RevenueLocation of Gain
    
    
    For the Three Months Ended March 31,(in thousands)
    
    (Loss) on Derivatives
    
    
    2011
    
    
    2010Realized gain on forward contracts
    
    Revenue
    
    $
    907
    
    
    $
    677Unrealized gain on forward contracts
    
    Revenue
    
    
    83
    
    
    
    215Total
    
    
    
    
    
    $
    990
    
    
    $
    892
 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 March 31, 2011:
 Fair Value Measurements Using:Significant Other
    
    
    SignificantQuoted Prices in
    
    
    Observable
    
    
    UnobservableActive Markets
    
    
    Inputs
    
    
    Inputs(in thousands)
    
    Fair Value
    
    
    (Level 1)
    
    
    (Level 2)
    
    
    (Level 3)Assets:Investments
    
    $
    3,835
    
    
    $
    3,835
    
    
    $
    
    
    
    $
    Mark-to-market energy assets
    
    $
    339
    
    
    $
    
    
    
    $
    339
    
    
    $
    Liabilities:Mark-to-market energy liabilities
    
    $
    107
    
    
    $
    
    
    
    $
    107
    
    
    $
    
  - 24 -




---



##### Table of Contents



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
    
    
    SignificantQuoted Prices in
    
    
    Observable
    
    
    UnobservableActive Markets
    
    
    Inputs
    
    
    Inputs(in thousands)
    
    Fair Value
    
    
    (Level 1)
    
    
    (Level 2)
    
    
    (Level 3)Assets:Investments
    
    $
    4,036
    
    
    $
    4,036
    
    
    $
    
    
    
    $
    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 March 31, 2011 and December 31, 2010:
 Level 1 Fair Value Measurements:Investments The fair values of these trading securities are recorded at
fair value based on unadjusted quoted prices in active markets for identical securities.Level 2 Fair Value Measurements:Mark-to-market energy assets and liabilities These forward contracts are valued using
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 March 31, 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 March 31, 2011, long-term debt, which includes the current maturities of long-term debt, had
a carrying value of $98.8 million, compared to a fair value of $110.5 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.
  - 25 -




---



##### Table of Contents



12.
    
    Long-Term Debt
 Our outstanding long-term debt is shown below:
 March 31,
    
    
    December 31,(in thousands)
    
    2011
    
    
    2010FPU secured first mortgage bonds:9.57% bond, due May 1, 2018
    
    $
    7,248
    
    
    $
    7,24810.03% bond, due May 1, 2018
    
    
    3,986
    
    
    
    3,9869.08% bond, due June 1, 2022
    
    
    7,950
    
    
    
    7,950Uncollateralized senior notes:6.85% note, due January 1, 2012
    
    
    1,000
    
    
    
    1,0007.83% note, due January 1, 2015
    
    
    8,000
    
    
    
    8,0006.64% note, due October 31, 2017
    
    
    19,091
    
    
    
    19,0915.50% note, due October 12, 2020
    
    
    20,000
    
    
    
    20,0005.93% note, due October 31, 2023
    
    
    30,000
    
    
    
    30,000Convertible debentures:8.25% due March 1, 2014
    
    
    1,256
    
    
    
    1,318Promissory note
    
    
    230
    
    
    
    265Total long-term debt
    
    
    98,761
    
    
    
    98,858Less: current maturities
    
    
    (9,196
    )
    
    
    (9,216
    )Total long-term debt, net of current maturities
    
    $
    89,565
    
    
    $
    89,642
 On June 29, 2010, we entered into an agreement with an existing senior note holder to issue
up to $36 million in uncollateralized senior notes. We expect to use $29 million of the
uncollateralized senior notes to permanently finance the redemption of the 6.85 percent and 4.90
percent series of FPU bonds. These redemptions occurred in January 2010 and have been financed
by short-term loan facilities. The terms of the agreement require us to issue $29 million of
the $36 million in uncollateralized senior notes committed by the lender on or before July 9,
2012, with a 15-year term at a rate ranging from 5.28 percent to 6.13 percent based on the
timing of the issuance. The remaining $7 million will be issued 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,
when issued, will have similar covenants and default provisions as the existing senior notes and
will have an annual principal payment beginning in the sixth year after the issuance.
  - 26 -




---



##### Table of Contents



Item 2.
    
    Managements Discussion and Analysis of Financial Condition and Results of Operations
  Safe Harbor for Forward-Looking Statements
  
    
    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;
 
    
    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;
 
    
    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;
  - 27 -




---



##### Table of Contents




    
    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
   
    
    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.
  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.
  - 28 -




---



##### Table of Contents



Overview and Highlights
  IncreaseFor the Three Months Ended March 31,
    
    2011
    
    
    2010
    
    
    (decrease)(in thousands except per share)Business Segment:Regulated Energy
    
    $
    16,309
    
    
    $
    17,516
    
    
    $
    (1,207
    )Unregulated Energy
    
    
    8,515
    
    
    
    7,760
    
    
    
    755Other
    
    
    15
    
    
    
    122
    
    
    
    (107
    )Operating Income
    
    
    24,839
    
    
    
    25,398
    
    
    
    (559
    )Other Income
    
    
    22
    
    
    
    115
    
    
    
    (93
    )Interest Charges
    
    
    2,150
    
    
    
    2,363
    
    
    
    (213
    )Income Taxes
    
    
    8,964
    
    
    
    9,176
    
    
    
    (212
    )Net Income
    
    $
    13,747
    
    
    $
    13,974
    
    
    $
    (227
    )Earnings Per Share of Common StockBasic
    
    $
    1.44
    
    
    $
    1.48
    
    
    $
    (0.04
    )Diluted
    
    $
    1.43
    
    
    $
    1.47
    
    
    $
    (0.04
    )
 Key Factors Affecting Our Businesses
  Weather.
  Growth.
   - 29 -




---



##### Table of Contents



Rates and Regulatory Matters.
     - 30 -




---



##### Table of Contents



Propane Prices.
  Other Operating Expenses.
   - 31 -




---



##### Table of Contents



Regulated Energy
 IncreaseFor the Three Months Ended March 31,
    
    2011
    
    
    2010
    
    
    (decrease)(in thousands)Revenue
    
    $
    85,002
    
    
    $
    91,626
    
    
    $
    (6,624
    )Cost of sales
    
    
    47,990
    
    
    
    54,263
    
    
    
    (6,273
    )Gross margin
    
    
    37,012
    
    
    
    37,363
    
    
    
    (351
    )Operations & maintenance
    
    
    14,310
    
    
    
    13,531
    
    
    
    779Depreciation & amortization
    
    
    4,166
    
    
    
    4,009
    
    
    
    157Other taxes
    
    
    2,227
    
    
    
    2,307
    
    
    
    (80
    )Other operating expenses
    
    
    20,703
    
    
    
    19,847
    
    
    
    856Operating Income
    
    $
    16,309
    
    
    $
    17,516
    
    
    $
    (1,207
    )Weather and Customer analysisDelmarva PeninsulaHeating degree-days (HDD):Actual
    
    
    2,445
    
    
    
    2,543
    
    
    
    (98
    )10-year average
    
    
    2,376
    
    
    
    2,336
    
    
    
    40Per residential customer added:Estimated gross margin
    
    $
    375
    
    
    $
    375
    
    
    $
    0Estimated other operating expenses
    
    $
    111
    
    
    $
    105
    
    
    $
    6FloridaHDD:Actual
    
    
    520
    
    
    
    933
    
    
    
    (413
    )10-year average
    
    
    564
    
    
    
    514
    
    
    
    50Cooling degree-days:Actual
    
    
    80
    
    
    
    3
    
    
    
    7710-year average
    
    
    67
    
    
    
    72
    
    
    
    (5
    )Residential Customer InformationAverage number of customers:Delmarva natural gas distribution
    
    
    49,312
    
    
    
    48,183
    
    
    
    1,129Florida natural gas distribution
    
    
    61,547
    
    
    
    60,482
    
    
    
    1,065Florida electric distribution
    
    
    23,589
    
    
    
    23,531
    
    
    
    58Total
    
    
    134,448
    
    
    
    132,196
    
    
    
    2,252
  - 32 -




---



##### Table of Contents



Gross Margin
   
    
    Two percent growth in residential customers and the addition of several large
commercial and industrial customers for our Delmarva natural gas distribution operations
generated a $455,000 increase in gross margin. Residential, commercial and industrial
growth by our Delaware and Maryland divisions generated $166,000, $27,000 and $262,000,
respectively, in gross margin for the quarter. Since the second half of 2010, our Delmarva
natural gas distribution operations have added 12 large commercial and industrial customers
with total expected annualized margin contribution of $1.0 million in 2011, of which
$249,000 has been reflected in the first quarter results. The same customers generated
$196,000 of gross margin following their addition in 2010.
 
    
    An increase in non-weather-related customer consumption, primarily by residential
customers of our Delaware division, increased gross margin by $176,000.
 
    
    The increase in gross margin in the first quarter was offset by $118,000 due to the
warmer weather on the Delmarva Peninsula as heating degree-days decreased by 98, or four
percent, in the first quarter of 2011, compared to the same quarter in 2010. This decrease
in gross margin is primarily related to our Delaware division, as residential heating rates
for our Maryland division are weather-normalized, and we typically do not experience an
impact on gross margin from the weather for our residential customers in Maryland.
 
    
    In addition, a decrease in gross margin of $76,000 was due primarily to a change in
customer rates and rate classes.
  
    
    Warmer weather reduced gross margin by $1.4 million in the first quarter of 2011,
compared to the same quarter in 2010. Heating degree-days decreased by 413, or 44 percent.
This decrease was due primarily to weather in the first quarter of 2010 being 82 percent
(419 heating degree-days) colder than normal. Comparing to normal, the weather in the
first quarter of 2011 was eight percent warmer (44 heating
degree-days). The warmer-than-normal weather in the first quarter of 2011 represents approximately $477,000 in lower gross
margin in Florida.
 
    
    Two percent customer growth in the Florida natural gas distribution operation generated
additional gross margin of $200,000 in the first quarter of 2011, compared to the same
quarter in 2010.
 
    
    700 new customers added as a result of the purchase of the operating assets of
Indiantown Gas Company in August 2010 generated $182,000 in gross margin in the first
quarter of 2011.
  - 33 -




---



##### Table of Contents




    
    New transportation services implemented by Eastern Shore in May 2010 and November
2010 as result of its system expansion projects generated an additional $143,000 of gross
margin in the first quarter of 2011, compared to 2010. These expansion projects added
2,666 Mcfs of capacity per day with estimated annual gross margin of $574,000 in 2011.
These projects generated $216,000 of gross margin in 2010.
 
    
    New transportation services implemented by Eastern Shore in January 2011 for
Chesapeakes Delaware and Maryland divisions generated an additional $542,000 of gross
margin in the first quarter. These new services have a three-year phase-in from
19,324 Mcfs per day to 38,647 Mcfs per day, providing estimated annual gross margin of
$2.4 million in 2011, $3.9 million in 2012 and $4.3 million thereafter. These new
services were added as a result of Eastern Shores completion of the eight-mile mainline
extension in December 2010 to interconnect with TETLPs pipeline system.
 
    
    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
first quarter of 2011.
  Other Operating Expenses
  Unregulated Energy
 IncreaseFor the Three Months Ended March 31,
    
    2011
    
    
    2010
    
    
    (decrease)(in thousands)Revenue
    
    $
    58,750
    
    
    $
    59,269
    
    
    $
    (519
    )Cost of sales
    
    
    42,755
    
    
    
    43,958
    
    
    
    (1,203
    )Gross margin
    
    
    15,995
    
    
    
    15,311
    
    
    
    684Operations & maintenance
    
    
    6,232
    
    
    
    6,026
    
    
    
    206Depreciation & amortization
    
    
    755
    
    
    
    1,046
    
    
    
    (291
    )Other taxes
    
    
    493
    
    
    
    479
    
    
    
    14Other operating expenses
    
    
    7,480
    
    
    
    7,551
    
    
    
    (71
    )Operating Income
    
    $
    8,515
    
    
    $
    7,760
    
    
    $
    755Weather Analysis  Delmarva PeninsulaActual HDD
    
    
    2,445
    
    
    
    2,543
    
    
    
    (98
    )10-year average HDD
    
    
    2,376
    
    
    
    2,336
    
    
    
    40
   - 34 -




---



##### Table of Contents



Gross Margin
   
    
    Additional gross margin of $775,000 was generated by higher margins per gallon in the first
quarter of 2011, compared to the same quarter in 2010, as margins per gallon returned to more normal levels. Significantly colder temperatures
during the first quarter of 2010 increased customer consumption and led to the propane
distribution operations having to purchase additional propane supply at increased costs,
resulting in a higher propane inventory cost and lower margins per gallon during that period. The absence of much colder
than normal temperatures during the first quarter of 2011 and fewer spot purchases during
the peak heating season resulted in margins per gallon returning to more normal levels in 2011.
 
    
    A one-time gain of $575,000 was recorded in the first quarter of 2011, as a result of
our share of proceeds received from an antitrust litigation settlement with a major propane
supplier.
 
    
    The warmer weather on the Delmarva Peninsula and a decrease in propane deliveries to
bulk customers decreased gross margin by $403,000. Heating degree-days decreased by 98, or
four percent, in the first quarter of 2011, compared to the same quarter in 2010. The
decline in deliveries is primarily related to the timing of deliveries to bulk customers
year-over-year.
     Other Operating Expenses
   - 35 -




---



##### Table of Contents



Other
 IncreaseFor the Three Months Ended March 31,
    
    2011
    
    
    2010
    
    
    (decrease)(in thousands)Revenue
    
    $
    2,845
    
    
    $
    2,365
    
    
    $
    480Cost of sales
    
    
    1,534
    
    
    
    1,133
    
    
    
    401Gross margin
    
    
    1,311
    
    
    
    1,232
    
    
    
    79Operations & maintenance
    
    
    997
    
    
    
    857
    
    
    
    140Depreciation & amortization
    
    
    100
    
    
    
    73
    
    
    
    27Other taxes
    
    
    199
    
    
    
    180
    
    
    
    19Other operating expenses
    
    
    1,296
    
    
    
    1,110
    
    
    
    186Operating Income  Other
    
    
    15
    
    
    
    122
    
    
    
    (107
    )Operating Income  Eliminations
    
    
    
    
    
    
    
    
    
    
    Operating Income
    
    $
    15
    
    
    $
    122
    
    
    $
    (107
    )
 Note:
    
    Eliminations are entries required to eliminate activities between business segments from
the consolidated results.  Gross margin
  Operating expenses
  Interest Expense
  
    
    In January 2010, we redeemed two series of First Mortgage Bonds, the 4.90 percent and
6.85 percent series, by using a new short-term loan facility. These redemptions reduced
the amount of FPUs secured long-term debt. Borrowing under the short-term facility lowered interest
expense by $57,000 in the first quarter of 2011, compared to the same period in 2010.
 
    
    Other long-term interest expense decreased by $165,000 in the first quarter of 2011,
compared to the same period in 2010, due to scheduled repayments.
 
    
    Other short-term interest expense remained substantially unchanged. Higher short-term
borrowing rates during the first quarter of 2011 were offset by lower working capital
requirements.
  - 36 -




---



##### Table of Contents



Income Taxes
  Financial Position, Liquidity and Capital Resources
     - 37 -




---



##### Table of Contents



Capital Structure
  March 31,
    
    
    December 31,(in thousands)
    
    2011
    
    
    2010Long-term debt, net of current maturities
    
    $
    89,565
    
    
    
    27
    %
    
    $
    89,642
    
    
    
    28
    %Stockholders equity
    
    
    237,015
    
    
    
    73
    %
    
    
    226,239
    
    
    
    72
    %Total capitalization, excluding short-term debt
    
    $
    326,580
    
    
    
    100
    %
    
    $
    315,881
    
    
    
    100
    %
 March 31,
    
    
    December 31,(in thousands)
    
    2011
    
    
    2010Short-term debt
    
    $
    41,427
    
    
    
    11
    %
    
    $
    63,958
    
    
    
    16
    %Long-term debt, including current maturities
    
    
    98,761
    
    
    
    26
    %
    
    
    98,858
    
    
    
    25
    %Stockholders equity
    
    
    237,015
    
    
    
    63
    %
    
    
    226,239
    
    
    
    59
    %Total capitalization, including short-term debt
    
    $
    377,203
    
    
    
    100
    %
    
    $
    389,055
    
    
    
    100
    %
 Short-term Borrowings
      - 38 -




---



##### Table of Contents



Cash Flows Provided By Operating Activities
  For the Three Months Ended March 31,
    
    2011
    
    
    2010(in thousands)Net Income
    
    $
    13,747
    
    
    $
    13,974Non-cash adjustments to net income
    
    
    15,606
    
    
    
    6,194Changes in assets and liabilities
    
    
    4,917
    
    
    
    26,231Net cash provided by operating activities
    
    $
    34,270
    
    
    $
    46,399
  
    
    Net cash flows from trading receivables and payables by Xeron, our propane wholesale
marketing subsidiaries, decreased by $6.3 million due to the timing of propane trading
activities. Xeron collects from and pays to its counterparties all of the receivables and
payables from trading activities within one month.
 
    
    Net cash flows from customer deposits decreased by $2.8 million, due primarily to a
large deposit received from a new industrial customer during the first quarter of 2010,
which increased the cash flow for that period.
 
    
    Net cash flows from accrued
compensation decreased by $1.0 million as a result of increased
payments for incentive compensation and severance in the first
quarter of 2011, compared to the same
period in 2010.
 Cash Flows Used in Investing Activities
  Cash Flows Used by Financing Activities
  
    
    During the first three months of 2011 we had a net repayment of $19.7 million under our
line of credit agreements related to working capital compared to $29.2 million in the same
period in 2010. Changes in cash overdrafts decreased by $2.0 million.
 
    
    We paid $2.8 million and $2.7 million in cash dividends for the three months ended March
31, 2011 and 2010, respectively.
 
    
    During the first three months of 2010 we issued $29.1 million in short-term term notes
and used the proceeds to finance the redemption, in January 2010, of two series of FPUs
secured first mortgage bonds prior to their respective maturities.
  - 39 -




---



##### Table of Contents



Off-Balance Sheet Arrangements
    Contractual Obligations
  Payments Due by PeriodPurchase Obligations
    
    Less than 1 year
    
    
    1 - 3 years
    
    
    3 - 5 years
    
    
    More than 5 years
    
    
    Total(in thousands)Commodities (1)
    
    $
    22,962
    
    
    $
    373
    
    
    $
    
    
    
    $
    
    
    
    $
    23,335Propane (2)
    
    
    15,938
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    15,938Total Purchase Obligations
    
    $
    38,900
    
    
    $
    373
    
    
    $
    
    
    
    $
    
    
    
    $
    39,273
 (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 $15.9 million. See Part I, Item 3, Quantitative and Qualitative
Disclosures about Market Risk, below, for further information. Environmental Matters
  Other Matters
 Rates and Regulatory Matters
   - 40 -




---



##### Table of Contents



Competition
       - 41 -




---



##### Table of Contents



Inflation
  Recent Authoritative Pronouncements on Financial Reporting and Accounting
  
 Item 3.
    
    Quantitative and Qualitative Disclosures about Market Risk
     - 42 -




---



##### Table of Contents



Quantity in
    
    
    Estimated Market
    
    
    Weighted AverageAt March 31, 2011
    
    Gallons
    
    
    Prices
    
    
    Contract PricesForward ContractsSale
    
    
    11,844,000
    
    
    $
    1.0800  $1.4525
    
    
    $
    1.3405Purchase
    
    
    12,054,000
    
    
    $
    1.1200  $1.4500
    
    
    $
    1.3222
 Estimated market prices and weighted average contract prices are in dollars per gallon.All contracts expire during or prior to the fourth quarter of 2011.  March 31,
    
    
    December 31,(in thousands)
    
    2011
    
    
    2010Mark-to-market energy assets
    
    $
    339
    
    
    $
    1,642Mark-to-market energy liabilities
    
    $
    107
    
    
    $
    1,492
 
 Item 4.
    
    Controls and Procedures
 Evaluation of Disclosure Controls and Procedures
  Changes in Internal Control over Financial Reporting
   - 43 -




---



##### Table of Contents



PART II  OTHER INFORMATION
 
 Item 1.
    
    Legal Proceedings
  
 Item 1A.
    
    Risk Factors
  
 Item 2.
    
    Unregistered Sales of Equity Securities and Use of Proceeds
 Total Number of Shares
    
    
    Maximum Number ofTotal Number of
    
    
    Average
    
    
    Purchased as Part of
    
    
    Shares That May Yet BeShares
    
    
    Price Paid
    
    
    Publicly Announced Plans
    
    
    Purchased Under thePeriod
    
    Purchased
    
    
    per Share
    
    
    or Programs(2)
    
    
    Plans or Programs (2)January 1, 2011through January 31, 2011 (1)
    
    
    242
    
    
    $
    40.21
    
    
    
    
    
    
    
    February 1, 2011through February 28, 2011
    
    
    
    
    
    $
    
    
    
    
    
    
    
    
    March 1, 2011through March 31, 2011
    
    
    
    
    
    $
    
    
    
    
    
    
    
    
    Total
    
    
    242
    
    
    $
    40.21
    
    
    
    
    
    
    
    
 (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, 242 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
  
 Item 5.
    
    Other Information
   - 44 -




---



##### Table of Contents



Item 6.
    
    Exhibits
 4.1
    
    
    Seventeenth Supplemental Indenture entered into by Chesapeake
Utilities Corporation and Florida Public Utilities Company, on April
12, 2011, pursuant to which Chesapeake Utilities Corporation
guarantees the payment and performance obligations of Florida Public
Utilities Company under the Indenture, is filed herewith.31.1
    
    
    Certificate of Chief Executive Officer of Chesapeake Utilities
Corporation pursuant to Rule 13a-14(a) under the Securities Exchange
Act of 1934, dated May 4, 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 May 4, 2011.32.1
    
    
    Certificate of Chief Executive Officer of Chesapeake Utilities
Corporation pursuant to 18 U.S.C. Section 1350, dated May 4, 2011.32.2
    
    
    Certificate of Chief Financial Officer of Chesapeake Utilities
Corporation pursuant to 18 U.S.C. Section 1350, dated May 4, 2011.
  - 45 -




---



##### Table of Contents



SIGNATURES
  Chesapeake Utilities Corporation/s/ Beth W. Cooper

Beth W. CooperSenior Vice President and Chief Financial OfficerDate: May 4, 2011
  - 46 -