Chesapeake Utilities Corporation - Form 10-Q - June 30, 2007
United States 
Securities and Exchange Commission
Washington, D.C. 20549
_______________________________
FORM 10-Q

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

For the quarterly period ended: June 30, 2007

OR

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

For the transition period from ______ to ______


Commission File Number: 001-11590


Chesapeake Utilities Corporation
(Exact name of registrant as specified in its charter)
 

Delaware
51-0064146
(State or other jurisdiction of
(I.R.S. Employer
incorporation or organization)
Identification No.)

 
909 Silver Lake Boulevard, Dover, Delaware 19904
(Address of principal executive offices, including Zip Code)


(302) 734-6799
(Registrant’s telephone number, including area code)


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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer [  ]   Accelerated filer [X]   Non-accelerated filer [  ]

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

Common Stock, par value $0.4867 — 6,751,983 shares outstanding as of July 31, 2007.
 
 
 
 

Table of Contents
 

PART I — FINANCIAL INFORMATION
1
 
Item 1. Financial Statements
1
 
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
16
 
Item 3. Quantitative and Qualitative Disclosures about Market Risk
40
 
Item 4. Controls and Procedures
41
PART II — OTHER INFORMATION
42
 
Item 1. Legal Proceedings
42
 
Item 1A. Risk Factors
42
 
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
42
 
Item 3. Defaults upon Senior Securities
42
 
Item 4. Submission of Mattters to a Vote of Security Holders
42
 
Item 5. Other Information
43
 
Item 6. Exhibits
43
SIGNATURES
  
44
 

 
 

PART I — FINANCIAL INFORMATION
Item 1. Financial Statements

Chesapeake Utilities Corporation and Subsidiaries
         
           
Condensed Consolidated Statements of Income (Unaudited)
         
           
For the Three Months Ended June 30,
 
2007
  
2006
  
Operating Revenues
 
$
52,501,920
  
$
44,303,752
  
Operating Expenses
             
Cost of sales, excluding costs below
   
34,232,939
   
28,505,528
 
Operations
   
10,316,296
   
8,851,831
 
Maintenance
   
564,854
   
583,638
 
Depreciation and amortization
   
2,367,523
   
2,037,003
 
Other taxes
   
1,332,249
   
1,120,384
 
Total operating expenses
   
48,813,861
   
41,098,384
 
Operating Income
   
3,688,059
   
3,205,368
 
Other income net of other expenses
   
234,195
   
63,715
 
Interest charges
   
1,594,701
   
1,501,352
 
Income Before Income Taxes
   
2,327,553
   
1,767,731
 
Income taxes
   
845,762
   
635,222
 
Net Income
 
$
1,481,791
  
$
1,132,509
  
               
Earnings Per Share of Common Stock:
             
Basic
 
$
0.22
  
$
0.19
  
Diluted
 
$
0.22
  
$
0.19
  
Basic weighted average shares outstanding
   
6,737,384
   
5,952,074
 
Diluted weighted average shares outstanding
   
6,849,890
   
5,963,596
 
               
Cash Dividends Declared Per Share of Common Stock:
 
$
0.295
  
$
0.290
  
 


 
The accompanying notes are an integral part of these financial statements.
- 1 -


Chesapeake Utilities Corporation and Subsidiaries
         
           
Condensed Consolidated Statements of Income (Unaudited)
         
           
For the Six Months Ended June 30,
 
2007
  
2006
  
Operating Revenues
 
$
146,028,811
  
$
135,254,425
  
Operating Expenses
             
Cost of sales, excluding costs below
   
98,168,806
   
94,430,289
 
Operations
   
20,875,996
   
18,453,112
 
Maintenance
   
1,145,019
   
1,027,607
 
Depreciation and amortization
   
4,683,318
   
4,014,350
 
Other taxes
   
2,885,561
   
2,686,471
 
Total operating expenses
   
127,758,700
   
120,611,829
 
Operating Income
   
18,270,111
   
14,642,596
 
Other income net of other expenses
   
287,567
   
142,299
 
Interest charges
   
3,193,951
   
2,994,689
 
Income Before Income Taxes
   
15,363,727
   
11,790,206
 
Income taxes
   
5,890,848
   
4,561,281
 
Net Income
 
$
9,472,879
  
$
7,228,925
  
               
Earnings Per Share of Common Stock:
             
Basic
 
$
1.41
  
$
1.22
  
Diluted
 
$
1.39
  
$
1.20
  
Basic weighted average shares outstanding
   
6,721,694
   
5,930,872
 
Diluted weighted average shares outstanding
   
6,835,257
   
6,070,191
 
               
Cash Dividends Declared Per Share of Common Stock:
 
$
0.585
  
$
0.575
  


The accompanying notes are an integral part of these financial statements.
- 2 -

Chesapeake Utilities Corporation and Subsidiaries
         
           
Condensed Consolidated Statements of Cash Flows (Unaudited)
         
           
For the Six Months Ended June 30,
  
2007
  
2006
  
Operating Activities
              
Net Income
  
$
9,472,879
  
$
7,228,925
  
Adjustments to reconcile net income to net operating cash:
              
Depreciation and amortization 
    
4,683,318
   
4,014,350
 
Depreciation and accretion included in other costs 
    
1,682,980
   
1,503,982
 
Deferred income taxes, net 
    
1,590,955
   
(2,594,606
)
Gain on sale of assets 
    
(204,882
)
  
-
 
Unrealized gain on commodity contracts 
    
(296,892
)
  
(99,715
)
Unrealized gain on investments 
    
(188,203
)
  
(56,628
)
Employee benefits and compensation 
    
920,460
   
876,543
 
Other, net 
    
(1,839
)
  
(1,806
)
Changes in assets and liabilities:
              
Sale (purchase) of investments 
    
71,432
   
(66,146
)
Accounts receivable and accrued revenue 
    
6,961,621
   
20,855,446
 
Propane inventory, storage gas and other inventory 
    
2,781,638
   
2,947,555
 
Regulatory assets 
    
597,354
   
3,826,484
 
Prepaid expenses and other current assets 
    
(686,387
)
  
(145,410
)
Other deferred charges 
    
(1,405,003
)
  
27,409
 
Long-term receivables 
    
51,557
   
87,643
 
Accounts payable and other accrued liabilities 
    
(7,026,333
)
  
(20,874,990
)
Income taxes receivable (payable) 
    
(139,486
)
  
5,346,331
 
Accrued interest 
    
(20,910
)
  
54,094
 
Customer deposits and refunds 
    
361,078
   
(468,019
)
Accrued compensation 
    
(400,959
)
  
(1,532,150
)
Regulatory liabilities 
    
1,798,097
   
2,110,251
 
Other liabilities 
    
15,582
   
(68,757
)
Net cash provided by operating activities
    
20,618,057
   
22,970,786
 
               
Investing Activities
              
Property, plant and equipment expenditures
    
(15,969,557
)
  
(16,825,679
)
Proceeds from sale of assets
    
204,882
   
-
 
Environmental recoveries (expenditures)
    
(135,953
)
  
1,620
 
Net cash used in investing activities
    
(15,900,628
)
  
(16,824,059
)
               
Financing Activities
              
Common stock dividends
    
(3,465,987
)
  
(2,945,899
)
Issuance of stock for Dividend Reinvestment Plan
    
174,315
   
177,077
 
Change in cash overdrafts due to outstanding checks
    
843,845
   
1,268,914
 
Net repayment under line of credit agreements
    
(4,829,053
)
  
(3,747,750
)
Repayment of long-term debt
    
(1,020,132
)
  
(1,020,454
)
Net cash used in financing activities
    
(8,297,012
)
  
(6,268,112
)
               
Net Decrease in Cash and Cash Equivalents
    
(3,579,583
)
  
(121,385
)
Cash and Cash Equivalents — Beginning of Period
    
4,488,367
   
2,487,658
 
Cash and Cash Equivalents — End of Period
  
$
908,784
  
$
2,366,273
  
               
Supplemental Disclosures of Non-Cash Investing Activities:
              
Capital property and equipment acquired on account, but not paid as of June 30
  
$
1,216,749
  
$
788,758
  
 
 
The accompanying notes are an integral part of these financial statements.
- 3 -

 
Chesapeake Utilities Corporation and Subsidiaries
         
           
Condensed Consolidated Balance Sheets (Unaudited)
         
           
Assets
 
June 30,
2007
  
December 31, 2006
  
Property, Plant and Equipment
             
Natural gas
 
$
277,239,562
  
$
269,012,516
  
Propane
   
46,361,641
   
44,791,552
 
Advanced information services
   
1,098,355
   
1,054,368
 
Other plant
   
9,140,526
   
9,147,500
 
Total property, plant and equipment
   
333,840,084
   
324,005,936
 
Less: Accumulated depreciation and amortization
   
(89,484,746
)
  
(85,010,472
)
Plus: Construction work in progress
   
6,739,641
   
1,829,948
 
Net property, plant and equipment
   
251,094,979
   
240,825,412
 
               
Investments
   
2,132,348
   
2,015,577
 
               
Current Assets
             
Cash and cash equivalents
   
908,784
   
4,488,366
 
Accounts receivable (less allowance for uncollectible accounts of $720,353 and $661,597, respectively)
   
40,938,891
   
44,969,182
 
Accrued revenue
   
1,394,021
   
4,325,351
 
Propane inventory, at average cost
   
6,874,869
   
7,187,035
 
Other inventory, at average cost
   
1,368,907
   
1,564,937
 
Regulatory assets
   
650,139
   
1,275,653
 
Storage gas prepayments
   
5,119,893
   
7,393,335
 
Income taxes receivable
   
1,218,368
   
1,078,882
 
Deferred income taxes
   
412,493
   
1,365,316
 
Prepaid expenses
   
2,995,506
   
2,280,900
 
Other current assets
   
3,641,451
   
1,553,284
 
Total current assets
   
65,523,322
   
77,482,241
 
               
Deferred Charges and Other Assets
             
Goodwill
   
674,451
   
674,451
 
Other intangible assets, net
   
184,976
   
191,878
 
Pension
   
630,082
   
590,562
 
Long-term receivables
   
772,776
   
824,333
 
Other regulatory assets
   
1,757,691
   
1,765,088
 
Other deferred charges
   
2,593,474
   
1,215,004
 
Total deferred charges and other assets
   
6,613,450
   
5,261,316
 
               
               
Total Assets
 
$
325,364,099
  
$
325,584,546
 

 
The accompanying notes are an integral part of these financial statements.
- 4 -
 

Chesapeake Utilities Corporation and Subsidiaries
 
Condensed Consolidated Balance Sheets (Unaudited)
 
Capitalization and Liabilities
 
June 30,
2007
  
December 31, 2006
  
Capitalization
             
Stockholders' equity
             
Common Stock, par value $0.4867 per share (authorized 12,000,000 shares)
 
$
3,281,792
  
$
3,254,998
  
Additional paid-in capital
   
64,129,089
   
61,960,220
 
Retained earnings
   
51,806,645
   
46,270,884
 
Accumulated other comprehensive loss
   
(334,550
)
  
(334,550
)
Deferred compensation obligation
   
1,370,547
   
1,118,509
 
Treasury stock
   
(1,370,547
)
  
(1,118,509
)
Total stockholders' equity
   
118,882,976
   
111,151,552
 
               
Long-term debt, net of current maturities
   
69,965,000
   
71,050,000
 
Total capitalization
   
188,847,976
   
182,201,552
 
               
Current Liabilities
             
Current portion of long-term debt
   
7,656,364
   
7,656,364
 
Short-term borrowing
   
23,568,733
   
27,553,941
 
Accounts payable
   
26,645,349
   
33,870,552
 
Customer deposits and refunds
   
7,863,343
   
7,502,265
 
Accrued interest
   
811,482
   
832,392
 
Dividends payable
   
1,989,086
   
1,939,482
 
Accrued compensation
   
1,881,211
   
2,901,053
 
Regulatory liabilities
   
6,117,618
   
4,199,147
 
Other accrued liabilities
   
5,739,405
   
4,005,795
 
Total current liabilities
   
82,272,591
   
90,460,991
 
               
Deferred Credits and Other Liabilities
             
Deferred income taxes
   
27,155,230
   
26,517,098
 
Deferred investment tax credits
   
300,869
   
328,277
 
Other regulatory liabilities
   
1,053,294
   
1,236,254
 
Environmental liabilities
   
102,656
   
211,581
 
Other pension and benefit costs
   
2,241,819
   
2,198,874
 
Accrued asset removal cost
   
19,355,153
   
18,410,992
 
Other liabilities
   
4,034,511
   
4,018,927
 
Total deferred credits and other liabilities
   
54,243,532
   
52,922,003
 
               
Other Commitments and Contingencies (Note 4)
             
               
               
Total Capitalization and Liabilities
 
$
325,364,099
  
$
325,584,546


The accompanying notes are an integral part of these financial statements.
- 5 -

Chesapeake Utilities Corporation and Subsidiaries
         
           
Condensed Consolidated Statements of Stockholders' Equity (Unaudited)
         
           
   
For the Six
Months Ended
June 30, 2007
  
For the Twelve Months Ended December 31, 2006
  
Common Stock
              
Balance — beginning of period
  
$
3,254,998
  
$
2,863,212
  
Dividend Reinvestment Plan
    
9,375
   
18,685
 
Retirement Savings Plan
    
7,616
   
14,457
 
Conversion of debentures
    
1,858
   
8,117
 
Performance shares and options exercised
    
7,945
   
14,536
 
Stock issuance
    
-
   
335,991
 
Balance — end of period
  
$
3,281,792
  
$
3,254,998
  
               
Additional Paid-in Capital
              
Balance — beginning of period
  
$
61,960,220
  
$
39,619,849
  
Dividend Reinvestment Plan
    
585,503
   
1,148,100
 
Retirement Savings Plan
    
476,758
   
900,354
 
Conversion of debentures
    
63,010
   
275,300
 
Stock-based compensation
    
1,043,598
   
887,426
 
Stock issuance
    
-
   
19,362,518
 
Exercise of warrants
    
-
   
(233,327
)
Balance — end of period
  
$
64,129,089
  
$
61,960,220
  
               
Retained Earnings
              
Balance — beginning of period
  
$
46,270,884
  
$
42,854,894
  
Net income
    
9,472,879
   
10,506,525
 
Cash dividends declared
    
(3,937,118
)
  
(7,090,535
)
Balance — end of period
  
$
51,806,645
  
$
46,270,884
  
               
Accumulated Other Comprehensive Loss
              
Balance — beginning of period
    
($334,550
)
  
(578,151
)
Minimum pension liability adjustment, net of tax
    
-
   
74,036
 
Gain on funded status of Employee Benefit Plans, net of tax
    
-
   
169,565
 
Balance — end of period
    
($334,550
)
  
($334,550
)
               
Deferred Compensation Obligation
              
Balance — beginning of period
  
$
1,118,509
  
$
794,535
  
New deferrals
    
252,038
   
323,974
 
Balance — end of period
  
$
1,370,547
  
$
1,118,509
  
               
Treasury Stock
              
Balance — beginning of period
    
($1,118,509
)
  
($797,156
)
New deferrals related to compensation obligation
    
(252,038
)
  
(323,974
)
Purchase of treasury stock (1)
    
(29,771
)
  
(51,572
)
Sale and distribution of treasury stock (2)
    
29,771
   
54,193
 
Balance — end of period
    
($1,370,547
)
  
($1,118,509
)
               
               
Total Stockholders’ Equity
  
$
118,882,976
  
$
111,151,552
  
               
(1) Amount includes shares purchased in the open market for the Company's Rabbi Trust to secure its obligations under the Company's Executive Deferred Compensation Plan.
  
(2) Amount includes shares issued to the Company's Rabbi Trust as obligation under the Executive Deferred Compensation Plan.
  
 

The accompanying notes are an integral part of these financial statements.
- 6 -
 
 
Notes to Condensed Consolidated Financial Statements

1.  
Basis of Presentation
References in this document to “the Company,” “Chesapeake,” “we,” “us” and “our” are intended to mean Chesapeake Utilities Corporation and its subsidiaries.

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and United States of America Generally Accepted Accounting Principles (“GAAP”). In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in the Company’s latest Annual Report on Form 10-K filed with the SEC on March 14, 2007. In the opinion of management, these statements reflect normal recurring adjustments that are necessary for a fair presentation of the Company’s results of operations, financial position and cash flows for the interim periods presented.

2.  
Comprehensive Income
Comprehensive income contains items that are excluded from net income and recorded directly to stockholders’ equity. Chesapeake did not have any adjustments to the components of comprehensive income that are required to be reported by Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 130, “Reporting Comprehensive Income,” for the first six months of 2007 and 2006. Accumulated other comprehensive loss was $334,550 at June 30, 2007 and December 31, 2006.

3.  
Calculation of Earnings Per Share

 
Three Months Ended
 
Six Months Ended
 
For the Periods Ended June 30,
 
2007
  
2006
  
2007
  
2006
  
Calculation of Basic Earnings Per Share:
                         
Net Income
 
$
1,481,791
  
$
1,132,509
  
$
9,472,879
  
$
7,228,925
  
Weighted average shares outstanding
   
6,737,384
   
5,952,074
   
6,721,694
   
5,930,872
 
Basic Earnings Per Share
 
$
0.22
  
$
0.19
  
$
1.41
  
$
1.22
  
                           
Calculation of Diluted Earnings Per Share:
                         
Reconciliation of Numerator:
                         
Net Income
 
$
1,481,791
  
$
1,132,509
  
$
9,472,879
  
$
7,228,925
  
Effect of 8.25% Convertible debentures (1)
   
24,015
   
-
   
48,214
   
54,048
 
Adjusted numerator — Diluted
 
$
1,505,806
  
$
1,132,509
  
$
9,521,093
  
$
7,282,973
  
                           
Reconciliation of Denominator:
                         
Weighted shares outstanding — Basic
   
6,737,384
   
5,952,074
   
6,721,694
   
5,930,872
 
Effect of dilutive securities (1)
                         
Warrants
   
-
   
11,522
   
-
   
12,016
 
8.25% Convertible debentures
   
112,506
   
-
   
113,563
   
127,303
 
Adjusted denominator — Diluted
   
6,849,890
   
5,963,596
   
6,835,257
   
6,070,191
 
Diluted Earnings per Share
 
$
0.22
  
$
0.19
  
$
1.39
  
$
1.20
  
                           
(1) Amounts associated with securities resulting in an anti-dilutive effect on earnings per share are not included in this calculation.

4.  
Commitments and Contingencies
Environmental Matters
 
Chesapeake is subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require the Company to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites.
 
 
- 7 -
 
 
In 2004, Chesapeake received a Certificate of Completion for the remedial work performed at a former manufactured gas plant site located in Dover, Delaware. Chesapeake is also currently participating in the investigation, assessment or remediation of two additional former manufactured gas plant sites located in Maryland and Florida. The Company has accrued liabilities for the three sites referred to, respectively, as the Dover Gas Light, Salisbury Town Gas Light and the Winter Haven Coal Gas sites. The Company has been in discussions with the Maryland Department of the Environment (“MDE”) regarding a fourth former gas manufacturing plant site located in Cambridge, Maryland. The following provides details of each site.

Dover Gas Light Site
The Dover Gas Light site is a former manufactured gas plant site located in Dover, Delaware. On January 15, 2004, the Company received a Certificate of Completion of Work from the United States Environmental Protection Agency (“EPA”) regarding this site. This concluded Chesapeake’s remedial action obligation related to this site and relieves Chesapeake from liability for future remediation at the site, unless previously unknown conditions are discovered at the site, or information previously unknown to the EPA is received that indicates the remedial action that has been taken is not sufficiently protective. These contingencies are standard and are required by the EPA in all liability settlements.

The Company has reviewed its remediation costs incurred to date for the Dover Gas Light site and has concluded that all costs incurred have been paid. The Company does not expect any future environmental expenditure for this site. Through June 30, 2007, the Company has incurred approximately $9.67 million in costs related to environmental testing and remedial action studies at the site. Approximately $9.96 million has been recovered through June 2007 from other parties or through rates. As of June 30, 2007, a regulatory liability of approximately $294,500, representing the over-recovery portion of the clean-up costs, has been recorded. The over-recovery is temporary and will be refunded by the Company to customers in future rates.

Salisbury Town Gas Light Site
In cooperation with the MDE, the Company has completed remediation of the Salisbury Town Gas Light site, located in Salisbury, Maryland, where it was determined that a former manufactured gas plant had caused localized ground-water contamination. During 1996, the Company completed construction and began Air Sparging and Soil-Vapor Extraction (“AS/SVE”) remediation procedures. Chesapeake has been reporting the remediation and monitoring results to the MDE on an ongoing basis since 1996. In February 2002, the MDE granted permission to decommission permanently the AS/SVE system and to discontinue all on-site and off-site well monitoring, except for one well that is being maintained for continued product monitoring and recovery. Chesapeake has requested a No Further Action determination and is awaiting such a determination from the MDE.

Through June 30, 2007, the Company has incurred approximately $2.9 million for remedial actions and environmental studies at the Salisbury Town Gas Light site. Of this amount, approximately $1.77 million has been recovered through insurance proceeds or in rates. On September 26, 2006, the Company received approval from the Maryland Public Service Commission to recover, through its rates charged to customers, the remaining $1.16 million of the incurred environmental remediation costs.

Winter Haven Coal Gas Site
The Winter Haven Coal Gas site is located in Winter Haven, Florida. Chesapeake has been working with the Florida Department of Environmental Protection (“FDEP”) in assessing this coal gas site. In May 1996, the Company filed an AS/SVE Pilot Study Work Plan (the “Work Plan”) for the Winter Haven Coal Gas site with the FDEP. After discussions with the FDEP, the Company filed a modified Work Plan, which contained a description of the scope of work to complete the site assessment activities and a report describing a limited sediment investigation performed in 1997. In December 1998, the FDEP approved the modified Work Plan, which the Company completed during the third quarter of 1999. In February 2001, the Company filed a Remedial Action Plan (“RAP”) with the FDEP to address the contamination of the subsurface soil and ground-water in a portion of the site. The FDEP approved the RAP on May 4, 2001. Construction of the AS/SVE system was completed in the fourth quarter of 2002, and the system remains fully operational.
 
 
- 8 -

Through June 30, 2007, the Company has incurred approximately $1.8 million of environmental costs associated with this site. At June 30, 2007, the Company had accrued a liability of $103,000 related to this site, offsetting 1.) $17,000 collected, through rates in excess of costs incurred and 2.) a regulatory asset of approximately $86,000, representing the uncollected portion of the estimated clean-up costs. The Company expects to recover the remaining clean-up costs through rates.

The FDEP has indicated that the Company may be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the Winter Haven Coal Gas site. Based on studies performed to date, the Company objects to the FDEP’s suggestion that the sediments have been contaminated and will require remediation. The Company’s early estimates indicate that some of the corrective measures discussed by the FDEP may cost as much as $1 million. Given the Company’s view as to the absence of ecological effects, the Company believes that cost expenditures of this magnitude are unwarranted and plans to oppose any requirement that it undertake corrective measures in the offshore sediments. Chesapeake anticipates that it will be several years before this issue is resolved. At this time, the Company has not recorded a liability for sediment remediation. The outcome of this matter cannot be predicted at this time.

Other
The Company is in discussions with the MDE regarding a manufactured gas plant site located in Cambridge, Maryland. The outcome of this matter cannot be determined at this time; therefore, the Company has not recorded an environmental liability for this location.

Other Commitments and Contingencies
 
Natural Gas and Propane Supply
The Company’s natural gas and propane distribution operations have entered into contractual commitments to purchase gas from various suppliers. The contracts have various expiration dates. In April 2007, the Company renewed its contract with an energy marketing and risk management company to manage a portion of the Company’s natural gas transportation and storage capacity. This new contract expires on March 31, 2008.

Corporate Guarantees
The Company has issued corporate guarantees to certain vendors of its propane wholesale marketing subsidiary, its Florida natural gas supply and management subsidiary, and its Delmarva propane distribution subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the subsidiaries’ default. The liabilities for these purchases are recorded in the Consolidated Financial Statements. The aggregate amount guaranteed at June 30, 2007 totaled $21.7 million, with the guarantees expiring on various dates in 2007 and 2008.

In addition to the corporate guarantees, the Company has issued a letter of credit to its primary insurance company for $775,000, which expires on May 31, 2008. The letter of credit is provided as security to satisfy the deductibles for claim amounts on the Company’s policies.

Application of SFAS No. 71
Certain assets and liabilities of the Company are accounted for in accordance with SFAS No. 71 ¾“Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 provides guidance for public utilities and other regulated operations where the rates (prices) charged to customers are subject to regulatory review and approval. Regulators sometimes include allowable costs in a period other than the period in which the costs would be charged to expense by an unregulated enterprise. That procedure can create assets, reduce assets, or create liabilities for the regulated enterprise. For financial reporting, an incurred cost for which a regulator permits recovery in a future period is accounted for like an incurred cost that is reimbursable under a cost-reimbursement type contract. The Company believes that all regulatory assets as of June 30, 2007 are probable of recovery through rates. If the Company were required to terminate the application of SFAS No. 71 to its regulated operations, all such deferred amounts would be recognized in the income statement at that time. This would result in a charge to earnings, net of applicable income taxes, which could be material.
 
- 9 -

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

5.  
Recent Authoritative Pronouncements on Financial Reporting and Accounting
In June 2006, the FASB issued FASB Interpretation (“FIN”) No. 48, “Employers’ Accounting for Uncertainty in Income Taxes.” This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition and classification of uncertain tax positions, reporting of interest and penalties, accounting in interim periods, disclosure, and transition. This interpretation is effective for fiscal years beginning after December 15, 2006. Chesapeake was required to adopt FIN No. 48 in the first quarter of 2007, and its adoption did not have any impact on the Company’s Consolidated Financial Statements.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This statement defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting pronouncements that require or permit fair value measurements, the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, this statement does not require any new fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Chesapeake will be required to adopt SFAS No. 157 in the first quarter of 2008. The Company has not yet evaluated the impact that SFAS No. 157 will have on its Consolidated Financial Statements.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities-including an amendment of FASB Statement No. 115.” SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value, with unrealized gains and losses related to these financial instruments reported in earnings at each subsequent reporting date. This Statement is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. The Company has not yet evaluated the impact that this statement will have on its Consolidated Financial Statements.

In April 2007, the FASB directed the FASB Staff to issue FSP No. FIN 39-1, “Amendment of FASB Interpretation No. 39” (“FSP FIN 39-1”). FSP FIN 39-1 modifies FIN No. 39, “Offsetting of Amounts Related to Certain Contracts,” and permits companies to offset cash collateral receivables or payables with net derivative positions under certain circumstances. FSP FIN 39-1 is effective for fiscal years beginning after November 15, 2007, with early adoption permitted. The Company is evaluating the effect of adopting FSP FIN 39-1 on its Consolidated Financial Statements.
 
- 10 -
 
 
6.  
Segment Information
Chesapeake uses the management approach to identify operating segments. The Company organizes its business around differences in products or services, and the operating results of each segment are regularly reviewed by the Company’s chief operating decision maker in order to make decisions about the allocation of resources and to assess performance. The following table presents information about the Company’s reportable segments.

 
Three Months Ended
 
Six Months Ended
 
For the Periods Ended June 30,
  
2007
  
2006
  
2007
  
2006
  
Operating Revenues, Unaffiliated Customers
                  
Natural gas
  
$
39,287,667
  
$
33,327,846
  
$
104,719,271
  
$
100,906,504
  
Propane
   
9,494,170
   
7,937,378
   
34,416,570
   
28,488,315
 
Advanced information services
    
3,720,083
   
3,038,015
   
6,892,970
   
5,858,581
 
Other
    
-
   
513
   
-
   
1,025
 
Total operating revenues, unaffiliated customers
  
$
52,501,920
  
$
44,303,752
  
$
146,028,811
  
$
135,254,425
  
Intersegment Revenues (1)
                          
Natural gas
  
$
78,087
  
$
58,769
  
$
156,150
  
$
117,717
  
Propane
    
-
   
-
   
406
   
-
 
Advanced information services
    
95,991
   
16,875
   
228,227
   
21,513
 
Other
    
154,623
   
154,623
   
309,246
   
309,246
 
Total intersegment revenues
  
$
328,701
  
$
230,267
  
$
694,029
  
$
448,476
  
Operating Income
                          
Natural gas
  
$
3,992,282
  
$
3,500,628
  
$
13,608,264
  
$
11,495,833
  
Propane
   
(545,898
)
  
(441,632
)
  
4,327,658
   
2,992,101
 
Advanced information services
    
178,706
   
172,061
   
227,528
   
188,371
 
Other and eliminations
    
62,969
   
(25,689
)
  
106,661
   
(33,709
)
Total operating income
  
$
3,688,059
  
$
3,205,368
  
$
18,270,111
  
$
14,642,596
  
(1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.
                           
                           
 
    
June 30, 
    
December 31,
             
     
2007
    
2006
              
Identifiable Assets
                          
Natural gas
  
$
249,358,307
  
$
252,292,600
              
Propane
    
62,151,633
   
60,170,200
             
Advanced information services
    
2,877,021
   
2,573,810
             
Other
    
10,977,138
   
10,547,936
             
Total identifiable assets
  
$
325,364,099
  
$
325,584,546
              

The Company’s operations are primarily domestic. The advanced information services segment, headquartered in Norcross, Georgia, provides domestic and international clients with information technology related business services and solutions. Transactions with foreign companies are denominated and paid in U.S. dollars and are immaterial to the consolidated revenues.
 
- 11 -
 
 
7.  
Employee Benefit Plans
Net periodic benefit costs for the defined benefit pension plan, the executive excess benefit plan and other post-retirement benefits are shown below:

 
 
Defined Benefit
  
Executive Excess
  
Other Post-Retirement
  
   
Pension Plan
  
Retirement Benefit Plan
  
Benefits
  
For the Three Months Ended June 30,
  
2007
  
2006
  
2007
  
2006
  
2007
  
2006
  
Service Cost
  
$
0
  
$
0
  
$
0
  
$
0
  
$
2,529
  
$
1,565
  
Interest Cost
    
155,514
   
156,726
   
30,841
   
29,897
   
23,233
   
19,468
 
Expected return on plan assets
    
(174,100
)
  
(171,076
)
  
-
   
-
   
-
   
-
 
Amortization of transition amount
    
-
   
-
   
-
   
-
   
-
   
6,965
 
Amortization of prior service cost
    
(1,175
)
  
(1,175
)
  
-
   
-
   
-
   
-
 
Amortization of net loss
   
-
   
-
   
12,933
   
14,260
   
41,640
   
22,074
 
Net periodic (benefit) cost
    
($19,761
)
  
($15,525
)
$
43,774
  
$
44,157
  
$
67,402
  
$
50,072
  
 

   
Defined Benefit
  
Executive Excess
  
Other Post-Retirement
  
   
Pension Plan
  
Retirement Benefit Plan
  
Benefits
  
For the Six Months Ended June 30,
  
2007
  
2006
  
2007
  
2006
  
2007
  
2006
  
Service Cost
  
$
0
  
$
0
  
$
0
  
$
0
  
$
5,057
  
$
3,129
  
Interest Cost
    
311,029
   
313,452
   
61,681
   
59,794
   
46,467
   
38,936
 
Expected return on plan assets
    
(348,199
)
  
(342,152
)
  
-
   
-
   
-
   
-
 
Amortization of transition amount
    
-
   
-
   
-
   
-
   
-
   
13,930
 
Amortization of prior service cost
    
(2,350
)
  
(2,350
)
  
-
   
-
   
-
   
-
 
Amortization of net loss
    
-
   
-
   
25,867
   
28,520
   
83,280
   
44,147
 
Net periodic (benefit) cost
    
($39,520
)
  
($31,050
)
$
87,548
  
$
88,314
  
$
134,804
  
$
100,142
  

As disclosed in the December 31, 2006 financial statements, no contributions are expected to be required in 2007 for the defined benefit pension plan. The cost of the executive excess defined benefit pension plan and the other post-retirement benefit plans are unfunded, and are expected to be paid out of the general funds of the Company. Cash benefits paid under the executive excess defined benefit pension plan for the three months and six months ended June 30, 2007 were $23,000 and $45,000, respectively; for the year 2007, such benefits paid are expected to be $89,000. Cash benefits paid for other post-retirement benefits, primarily for medical claims, for the three months and six months ended June 30, 2007 totaled $117,000 and $161,000, respectively; for the year 2007, the Company’s actuary has estimated that such benefits to be paid are $180,000.

8.  
Investments
The investment balance at June 30, 2007 represents a Rabbi Trust (“the Trust”) associated with the Company’s Supplemental Executive Retirement Savings Plan. In accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” the Company classifies these investments as trading securities. As a result of classifying them as trading securities, the Company is required to report the securities at their fair value, with any unrealized gains and losses included in other income. The Company also has an associated liability that is recorded and adjusted each month for the gains and losses incurred by the Trust. At June 30, 2007, total investments had a fair value of $2.1 million.

9.  
Share-Based Compensation 
The Company accounts for its share-based compensation arrangements under the revised SFAS No. 123, “Share Based Payments” (“SFAS 123R”), which requires the recognition of compensation cost over the respective service period for employee services received in exchange for an award of equity or equity-based compensation based on the fair value of the grant on the date it was awarded. The Company currently has two share-based compensation plans, Director’s Stock Compensation (“DSCP”) and the Performance Incentive Plan (“PIP”), that require accounting under SFAS 123R.


- 12 -
 
 
The table below presents the amounts included in net income, after tax, related to share-based compensation expense, in respect of restricted stock awards issued under the DSCP and the PIP.
 
 
Three Months Ended
  
Six Months Ended
  
For the periods ended June 30,
  
2007
  
2006
  
2007
  
2006
  
Director's Stock Compensation Plan
  
$
27,600
  
$
25,100
  
$
54,400
  
$
47,100
  
Performance Incentive Plans
    
130,800
   
134,900
   
253,900
   
217,300
 
Amounts included in net income, after tax
  
$
158,400
  
$
160,000
  
$
308,300
  
$
264,400
  
 
Stock Options
The Company did not have any stock options outstanding at June 30, 2007 or December 31, 2006, nor were any stock options issued during the six months ended June 30, 2007 and June 30, 2006.

Director’s Stock Compensation Plan
Under the DSCP, each non-employee director of the Company received in 2007 an annual retainer of 600 shares of common stock and an additional 150 shares of common stock for services as a committee chairman. Shares issued under the DSCP are fully vested as of the date of the grant. The Company records a prepaid expense as of the date of the grant equal to the fair value of the shares issued and amortizes the expense equally over the service period of one year.

Compensation expense related to DSCP awards recorded by the Company for the three months and six months ended June 30, 2007 and 2006 is presented in the following table:
 
 
Three Months Ended
  
Six Months Ended
  
For the periods ended June 30,
  
2007
  
2006
  
2007
  
2006
  
Compensation expense for DSCP
  
$
45,200
  
$
41,200
  
$
89,100
  
$
77,200
  

A summary of restricted stock activity under the DSCP as of June 30, 2007, and changes during the six months then ended, is presented below:

 
Number of Restricted Shares
  
Weighted Average Grant Date Fair Value
  
Outstanding — December 31, 2006
  
-
      
Issued — May 2, 2007
    
5,850
 
$
31.38
  
Vested
    
5,850
       
Outstanding — June 30, 2007
    
-
      

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

Compensation expense related to the PIP recorded by the Company for the three months and six months ended June 30, 2007 and 2006 is presented in the following table:
 
 
Three Months Ended
  
Six Months Ended
  
For the periods ended June 30,
  
2007
  
2006
  
2007
  
2006
  
Compensation expense for PIP
  
$
214,400
  
$
221,100
  
$
416,300
  
$
356,200
  
 
 
 
- 13 -
 
 
A summary of restricted stock activity under the PIP as of June 30, 2007, and changes during the six months then ended, is presented below:

 
Number of Restricted Shares
  
Weighted Average Grant Date Fair Value
  
Outstanding — December 31, 2006
    
-
        
Issued — March 1, 2007
    
10,124
  
$
30.89
  
Vested
    
10,124
        
Outstanding — June 30, 2007
    
-
        

10.  
Stockholders’ Equity
The changes in common stock shares issued and outstanding are shown below:

 
For the Six Months Ended June 30, 2007
  
For the Twelve Months Ended December 31, 2006
  
Common Stock shares issued and outstanding (1)
          
Shares issued — beginning of period balance
    
6,688,084
   
5,883,099
 
Dividend Reinvestment Plan (2)
    
19,262
   
38,392
 
Retirement Savings Plan
    
15,649
   
29,705
 
Conversion of debentures
    
3,817
   
16,677
 
Employee award plan
    
350
   
350
 
Performance shares and options exercised (3)
    
15,974
   
29,516
 
Public offering
    
-
   
690,345
 
Shares issued — end of period balance (4)
    
6,743,136
   
6,688,084
 
               
Treasury shares — beginning of period balance
    
-
   
(97
)
Other issuances
    
-
   
97
 
Treasury Shares — end of period balance
    
-
   
-
 
Total Shares Outstanding
    
6,743,136
   
6,688,084
 
               
(1) 12,000,000 shares are authorized at a par value of $0.4867 per share.
              
(2) Includes shares purchased with reinvested dividends and optional cash payments.
              
(3) Includes shares issued for DSCP.
              
(4) Includes 54,978 and 48,187 shares at June 30, 2007 and December 31, 2006, respectively, held in a Rabbi Trust established by the Company relating to the Executive Deferred Compensation Plan.
 
 
- 14 -
 
 
11.  
Reclassifications
The Company reclassified some previously reported amounts to conform to current period classifications.

·  
Share-based compensation was recorded as a liability to Accrued Compensation at December 31, 2006. Accordingly, the Company reclassified the $123,000 remaining in the liability account, after the issuance of the 2006 performance shares, to Additional Paid in Capital. This reclassification is considered immaterial to the overall presentation of the Company’s consolidated financial statements.
 
·  
Pension assets were netted against the liabilities for the executive excess defined benefit pension plan and the other post-retirement benefit plans at December 31, 2006 and March 31, 2007. Accordingly, the Company reclassified the pension assets of $630,000 at June 30, 2007 to the asset side of the balance sheet. For comparison, the balance of $591,000 at December 31, 2006 has also been reclassed to the asset side of the balance sheet. This reclassification is considered immaterial to the overall presentation of the Company’s consolidated financial statements.

 
- 15 -
 
 
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is designed to provide a reader of the financial statements with a narrative on the Company’s financial condition, results of operations and liquidity. This discussion and analysis should be read in conjunction with the attached unaudited condensed consolidated financial statements and notes thereto and Chesapeake’s Annual Report on Form 10-K for the year ended December 31, 2006, including the audited consolidated financial statements and notes contained in the Form 10-K.

Safe Harbor for Forward-Looking Statements
Chesapeake Utilities Corporation has made statements in this Form 10-Q that are considered to be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are not matters of historical fact and are typically identified by words such as, but not limited to, “believes,” “expects,” “intends,” “plans,” and similar expressions, or future or conditional verbs such as “may,” “will,” “should,” “would,” and “could.” These statements relate to matters such as customer growth, changes in revenues or gross margins, capital expenditures, environmental remediation costs, regulatory trends and decisions, market risks associated with our propane operations, the competitive position of the Company and other matters. It is important to understand that these forward-looking statements are not guarantees, but are subject to certain risks and uncertainties and other important factors that could cause actual results to differ materially from those in the forward-looking statements. The factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to:

·  
the temperature sensitivity of the natural gas and propane businesses;
·  
the effects of spot, forward, futures market prices, and the Company’s use of derivative instruments on the Company’s distribution, wholesale marketing and energy trading businesses;
·  
amount and availability of natural gas and propane supplies;
·  
the access to interstate pipelines’ transportation and storage capacity and the construction of new facilities to support future growth;
·  
the effects of natural gas and propane commodity price changes on the operating costs and competitive positions of our natural gas and propane distribution operations;
·  
third-party competition for the Company’s unregulated and regulated businesses;
·  
changes in federal, state or local regulatory and tax requirements, including deregulation;
·  
changes in technology affecting the Company’s advanced information services segment;
·  
changes in credit risk and credit requirements affecting the Company’s energy marketing subsidiaries;
·  
the effects of accounting changes;
·  
changes in benefit plan assumptions;
·  
cost of compliance with environmental regulations or the remediation of environmental damage;
·  
the effects of general economic conditions, including interest rates, on the Company and its customers;
·  
the ability of the Company’s new and planned facilities and acquisitions to generate expected revenues;
·  
the ability of the Company to construct facilities at its estimated costs;
·  
the Company’s ability to obtain the rate relief and cost recovery requested from utility regulators and the timing of the requested regulatory actions;
·  
the Company’s ability to obtain necessary approvals and permits from regulatory agencies on a timely basis;
·  
impact of inflation on the results of operations, cash flows, financial position and on the Company’s planned capital expenditures;
·  
inability to access the financial markets that may impair future growth; and
·  
operating and litigation risks that may not be covered by insurance.
 
 
- 16 -
 
 
Overview
Chesapeake is a diversified utility company engaged directly or through subsidiaries in natural gas distribution, transmission and marketing, propane distribution and wholesale marketing, advanced information services and other related businesses. For additional information regarding segments, refer to Note 6, Segment Information, of the Notes to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

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

·  
executing a capital investment program in pursuit of organic growth opportunities that generate returns equal to or greater than our cost of capital;
·  
expanding the natural gas distribution and transmission business through expansion into new geographic areas in our current service territories;
·  
expanding the propane distribution business in existing and new markets through leveraging our community gas system services and our bulk delivery capabilities;
·  
utilizing the Company’s expertise across our various businesses to improve overall performance;
·  
enhancing marketing channels to attract new customers;
·  
providing reliable and responsive customer service to retain existing customers;
·  
maintaining a capital structure that enables the Company to access capital as needed; and
·  
maintaining a consistent and competitive dividend for shareholders.

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


Results of Operations for the Quarter Ended June 30, 2007
The following discussions on operating income and segment results for the three months ended June 30, 2007 include use of the term “gross margin.” Gross margin is determined by deducting the cost of sales from operating revenue. Cost of sales includes the purchased gas cost for natural gas and propane and the cost of labor spent on direct revenue-producing activities. Gross margin should not be considered an alternative to operating income or net income, which are determined in accordance with GAAP. Chesapeake believes that gross margin, although a non-GAAP measure, is useful and meaningful to investors as a basis for making investment decisions. It provides investors with information that demonstrates the profitability achieved by the Company under its allowed rates for regulated operations and under its competitive pricing structure for non-regulated segments. Chesapeake’s management uses gross margin in measuring its business units’ performance and has historically analyzed and reported gross margin information publicly. Other companies may calculate gross margin in a different manner.


- 17 -
 
 
Consolidated Overview
The Company’s net income for the quarter ended June 30, 2007 increased $349,000, or 31 percent, compared to the same period in 2006. Net income was $1.5 million, or $0.22 per share (diluted), an increase of $0.03 per share compared to 2006. The period-over-period period increase in quarterly earnings reflects an increase in the operating income of the Company’s natural gas and other segments, partially offset by a decrease in the propane segment. The period-over-period increase in the quarterly operating income resulted primarily from the Company’s continued growth, colder weather on the Delmarva Peninsula, and increased rates for our natural gas customers. The Company estimates that the growth, colder weather, and rate increases contributed $1.4 million, $425,000, and $295,000, respectively, to gross margin during the second quarter of 2007.

For the Three Months Ended June 30,
  
2007
  
2006
  
Change
 
Operating Income
                   
Natural Gas
 
$
3,992,282
  
$
3,500,628
  
$
491,654
  
Propane
   
(545,898
)
  
(441,632
)
  
(104,266
)
Advanced Information Services
   
178,706
   
172,061
   
6,645
 
Other & Eliminations
   
62,969
   
(25,689
)
  
88,658
 
Operating Income
   
3,688,059
   
3,205,368
   
482,691
 
                     
Other Income
   
234,195
   
63,715
   
170,480
 
Interest Charges
   
1,594,701
   
1,501,352
   
93,349
 
Income Taxes
   
845,762
   
635,222
   
210,540
 
Net Income
 
$
1,481,791
  
$
1,132,509
  
$
349,282
  
Diluted Earnings Per Share
 
$
0.22
  
$
0.19
  
$
0.03
  

Natural Gas 
The natural gas segment earned operating income of approximately $4.0 million for the second quarter ended June 30, 2007 compared to $3.5 million for the corresponding period in 2006, an increase of approximately $492,000, or 14 percent.

For the Three Months Ended June 30,
  
2007
  
2006
  
Change
 
Revenue
 
$
39,365,754
  
$
33,386,615
  
$
5,979,139
  
Cost of sales
   
26,130,962
   
21,941,405
   
4,189,557
 
Gross margin
   
13,234,792
   
11,445,210
   
1,789,582
 
                     
Operations & maintenance
   
6,440,171
   
5,563,477
   
876,694
 
Depreciation & amortization
   
1,834,712
   
1,565,995
   
268,717
 
Other taxes
   
967,627
   
815,110
   
152,517
 
Other operating expenses
   
9,242,510
   
7,944,582
   
1,297,928
 
Total Operating Income
 
$
3,992,282
  
$
3,500,628
  
$
491,654
  
                     
                     
Statistical Data — Delmarva Peninsula
                   
Heating degree-days ("HDD"):
                   
Actual
   
527
   
388
   
139
 
10-year average (normal)
   
496
   
512
   
(16
)
                     
Estimated gross margin per HDD
 
$
2,283
  
$
2,234
  
$
49
  
                     
Per residential customer added:
                   
Estimated gross margin
 
$
372
  
$
372
  
$
0
  
Estimated other operating expenses
 
$
106
  
$
106
  
$
0
  
                     
Residential Customer Information
                   
Average number of customers:
                   
Delmarva
   
43,331
   
40,037
   
3,294
 
Florida
   
13,361
   
12,511
   
850
 
Total
   
56,692
   
52,548
   
4,144
 
 
 
- 18 -

 
Gross margin for the Company’s natural gas segment increased by $1.8 million, or 16 percent, and other operating expenses increased $1.3 million, or 16 percent, in the quarter ended June 30, 2007, compared to the same period in 2006. The gross margin increases of $1.1 million for the natural gas transmission operation, $790,000 for the Delmarva natural gas distribution operations, and $7,000 for the Florida natural gas distribution operation were partially offset by lower gross margin of $70,000 for the natural gas marketing operation, as further explained below.

Natural Gas Transmission
The natural gas transmission operation achieved gross margin growth of $1.1 million, or 26 percent. This increase was primarily attributed to new transportation capacity contracts implemented in November 2006 and the implementation of temporary rates, subject to refund, based on the status of the Company’s rate proceeding discussed below in the “Regulatory Matters” section. In total for 2007, these new transportation capacity contracts are expected to generate a gross margin of $3.3 million above the 2006 gross margin. An increase of $845,000 in other operating expenses partially offset the increased gross margin. The factors contributing to the increase in other operating expenses are as follow:

·  
The increase in operating expenses for the second quarter of 2007 relative to the second quarter of 2006 is magnified by the approval from the Federal Energy Regulatory Commission (“FERC”) in July 2006 to defer pre-service costs of the Company’s Energylink Expansion Project as a regulatory asset. The deferral of these costs resulted in the reduction of $310,000 in other operating expenses in the second quarter of 2006. Please refer to the “Regulatory Matters” section below for further information regarding this expansion project.
·  
Payroll and benefit costs increased by $76,000 and $34,000, respectively, to comply with federal pipeline integrity maintenance regulations and to serve the additional growth experienced by the operation.
·  
Incentive compensation increased by $71,000 as a result of the improved operating results in 2007 compared to 2006.
·  
Regulatory expenses increased by $55,000 in the second quarter of 2007 as the Company incurred costs associated with its rate filing with the FERC.
·  
The increased level of capital investment caused higher depreciation and asset removal costs of $194,000 and increased property taxes of $31,000.
·  
Other operating expenses relating to various items increased collectively by approximately $74,000.
 
Natural Gas Distribution
The Delmarva distribution operations experienced an increase of $790,000, or 20 percent, in gross margin. The significant factors contributing to the increase in gross margin include:

·  
Continued residential customer growth contributed to the increase in gross margin. The average number of residential customers on the Delmarva Peninsula increased by 3,294, or eight percent, for the second quarter 2007 compared to the same period in 2006, and the Company estimates that these additional residential customers contributed approximately $243,000 to gross margin.
·  
The Company estimates that colder weather contributed $224,000 to gross margin in the second quarter of 2007 compared to the same period in 2006, as temperatures on the Delmarva Peninsula were 36 percent colder in 2007. The colder temperatures did not have a significant impact on the Maryland distribution operation’s gross margin in the second quarter of 2007 because the operation’s approved rate structure now includes a weather normalization adjustment (“WNA”) mechanism. The WNA mechanism was implemented in October 2006 and is designed to protect a portion of the Company’s revenues against warmer-than-normal weather, as deviations from normal weather can affect our financial performance and liquidity. The WNA also serves to offset the impact of colder-than-normal weather by reducing the amounts the Company can charge its customers during such periods.
·  
In October 2006, the Maryland PSC granted the Company a base rate increase, which resulted in an $183,000 period-over-period increase to gross margin in the second quarter of 2007.
·  
The remaining $140,000 increase in gross margin can be attributed to various factors, including increases in the number of commercial and industrial customers.
 
 
- 19 -

 
Gross margin for the Florida distribution operation increased by $7,000 in the second quarter of 2007 compared to the second quarter of 2006. The impact of a seven percent growth in residential customers and a three percent growth in commercial customers was offset by lower volumes sold to industrial customers.

Other operating expense for the natural gas distribution operations increased by $220,000 in the second quarter of 2007 compared to the second quarter of 2006. Among the key components of the increase were the following:

·  
Payroll costs increased by $48,000 to serve the additional growth experienced by the operations.
·  
Health care costs increased by $103,000 during the second quarter of 2007 compared to the second quarter of 2006 as the Company experienced higher cost of health care claims during this period.
·  
Depreciation and amortization expense, asset removal cost and property taxes increased by $96,000, $51,000 and $21,000, respectively, as a result of the Company’s continued capital investments.
·  
The 2007 increase in revenue related taxes is magnified by the Company’s receipt of approval in the second quarter of 2006 from the Delaware Public Service Commission to defer $74,000 of previously expensed taxes associated with the Annual Gross Revenue Tax as a regulatory asset.
·  
In addition, other operating expenses relating to various minor items increased by approximately $36,000.
·  
The above increases were partially offset by a decrease of $111,000 in the allowance for uncollectible accounts, which was due primarily to increased collection efforts. In addition, merchant payment fees decreased by $98,000 as the Company’s Delmarva operation outsourced the processing of credit card payments in April of 2007 in an effort to reduce operating costs.

Natural Gas Marketing
Gross margin for the natural gas marketing operation decreased by $70,000, or 13 percent, for the second quarter of 2007 compared to the same period in 2006. The decline in gross margin was primarily the result of unfavorable imbalance resolutions with interstate pipelines, which caused an increase in the cost of gas. Other operating expenses increased by $233,000 for the marketing operation due to increased payroll and benefit costs and increased incentive compensation. The year-over-year increase in incentive compensation is due to an adjustment that occurred in second quarter 2006 to record compensation at the expected payout based on the level of earnings.


- 20 -

 
Propane
The propane segment incurred an operating loss of $546,000, representing an increased loss of $104,000, or 24 percent, for the second quarter of 2007 compared to the same period in 2006. Gross margin increased by $408,000, which was offset by an increase in other operating expenses of $512,000.

For the Three Months Ended June 30,
  
2007
  
2006
  
Change
 
Revenue
 
$
9,494,170
  
$
7,937,378
  
$
1,556,792
  
Cost of sales
   
5,930,398
   
4,781,819
   
1,148,579
 
Gross margin
   
3,563,772
   
3,155,559
   
408,213
 
                     
Operations & maintenance
   
3,463,047
   
3,024,725
   
438,322
 
Depreciation & amortization
   
458,788
   
402,675
   
56,113
 
Other taxes
   
187,835
   
169,791
   
18,044
 
Other operating expenses
   
4,109,670
   
3,597,191
   
512,479
 
Total Operating Loss
   
($545,898
)
  
($441,632
)
  
($104,266
)
                     
                     
Statistical Data — Delmarva Peninsula
                   
Heating degree-days ("HDD"):
                   
Actual
   
527
   
388
   
139
 
10-year average (normal)
   
496
   
512
   
(16
)
                     
Estimated gross margin per HDD
 
$
1,974
  
$
1,743
  
$
231
  

Gross margin for the Company’s propane segment increased by $408,000, or 13 percent, and other operating expenses increased $512,000, or 14 percent, in the three months ended June 30, 2007 compared to the same period in 2006. The gross margin increases of $216,000 for the Delmarva propane distribution operations, $39,000 for the Florida propane distribution operations, and $153,000 for the propane wholesale marketing are further explained below.
 
Delmarva Propane Distribution
The Delmarva propane distribution operation’s increase in gross margin of $216,000 resulted from the following:

·  
Volumes sold in the second quarter 2007 increased by 365,000 gallons, or 13 percent, primarily because temperatures on the Delmarva Peninsula were 36 percent colder during this period in 2007 when compared to the same period in 2006. The Company estimates that the colder weather increased gross margin by approximately $201,000 for the Delmarva propane distribution operation compared to the second quarter of 2006.
·  
Gross margin for the Delmarva Community Gas Systems (“CGS”) increased by $116,000 in the second quarter of 2007, compared to the same period in 2006, primarily because of an increase in the average number of customers and the colder weather on the Delmarva Peninsula. The average number of CGS customers increased by approximately 1,020 to a total count of approximately 4,800, or a 27 percent increase, compared to the second quarter 2006. The Company expects the growth of its CGS operation to continue, as the number of systems currently under construction or under contract is anticipated to provide an additional 7,900 CGS customers once the systems are built out.
·  
The remaining $90,000 increase in gross margin can be attributed to various factors, including service sales and wholesale sales.
·  
Partially offsetting the increases to gross margin listed above, the Delmarva propane distribution operations experienced a decrease in gross margin of $191,000 in the second quarter of 2007 compared to the same period in 2006 because of a $0.06 decrease in the average gross margin per retail gallon. This decrease occurs when the market price of propane decreases to levels closer to the Company’s average inventory price per gallon. Propane gross margin is also impacted by the Company’s pricing with its customers.
 
 
- 21 -


Total other operating expenses increased by $379,000 for the Delmarva propane distribution operations in the quarter ended June 30, 2007 compared to the same period in 2006. The significant items contributing to this increase are explained below.

·  
The increase in operating expenses for the second quarter of 2007 is magnified by the Company’s one-time recovery of previously incurred costs of $87,000 from one of its propane suppliers. This recovery reimbursed the Company for fixed costs incurred in the removal of above-normal levels of petroleum by-products contained in approximately 75,000 gallons of propane that it purchased from the supplier. The recovery of these costs reduced other operating expenses in the second quarter of 2006.
·  
Health care costs increased by $85,000 during the second quarter of 2007 compared to the second quarter of 2006 as the Company experienced a higher cost of health care claims during the period.
·  
The operation incurred an additional $108,000 in the second quarter of 2007 compared to 2006 for propane tank recertifications and maintenance to comply with Department of Transportation standards.
·  
Depreciation and amortization expense increased by $40,000 as a result of the Company’s continued capital investments.
·  
In addition, other operating expenses relating to various items increased collectively by approximately $59,000.
 
Florida Propane Distribution
The Florida propane distribution operation experienced an increase in gross margin of $39,000, or 15 percent, in the second quarter of 2007 compared to the same period in 2006. Gross margin from propane sales increased $32,000 as a higher average gross margin per retail gallon was partially offset by a nine percent decrease in the volumes sold in 2007. The remaining increase of $7,000 is attributed to higher in-house piping sales. Other operating expenses in the second quarter 2007 compared to the second quarter 2006 increased by $69,000 primarily due to an increase in payroll costs, insurance and higher depreciation expense, partially offset by lower incentive compensation.

Propane Wholesale and Marketing
Gross margin for the Company’s propane wholesale marketing operation increased by $153,000, or 35 percent, in the second quarter of 2007 compared to the same period in 2006. This increase reflects the larger number of market opportunities that arose in the second quarter of 2007 due to price volatility in the propane wholesale market. The increase in gross margin was partially offset by higher other operating expenses of $64,000 primarily due to higher incentive compensation based on the increased earnings in 2007.


- 22 -

 
Advanced Information Services
The advanced information services segment provides domestic and international clients with information-technology-related business services and solutions for both enterprise and e-business applications. The advanced information services business experienced gross margin growth of approximately $376,000, or 30 percent, and contributed operating income of approximately $179,000 for the three months ended June 30, 2007. Increases in revenue and gross margin were almost completely offset by increases in other operating expenses, consequently, operating income increased by only $7,000 compared to the same period in 2006.

For the Three Months Ended June 30,
  
2007
  
2006
  
Change
 
Revenue
 
$
3,816,074
  
$
3,054,890
  
$
761,184
  
Cost of sales
   
2,166,963
   
1,781,866
   
385,097
 
Gross margin
   
1,649,111
   
1,273,024
   
376,087
 
                     
Operations & maintenance
   
1,273,241
   
958,234
   
315,007
 
Depreciation & amortization
   
35,248
   
28,276
   
6,972
 
Other taxes
   
161,916
   
114,453
   
47,463
 
Other operating expenses
   
1,470,405
   
1,100,963
   
369,442
 
Total Operating Income
 
$
178,706
  
$
172,061
  
$
6,645
  

The increase of revenues in the three months ended June 30, 2007 is attributable to:

·  
An increase of $654,000 in consulting revenues as the number of billable hours increased by 20 percent;
·  
An increase of $69,000 from Managed Database Administration (“MDBA”) services, first offered in 2006, which provide clients with professional database monitoring and support solutions during business hours or around the clock; and
·  
An increase of $38,000 in revenue from training services and product sales.

Other operating expenses increased by $369,000 in the three months ended June 30, 2007 to $1.5 million, compared to $1.1 million for the same period in 2006. This increase in operating expenses is primarily due to an increase in accrued incentive compensation based on improved operating results and other costs incurred to support the growth.

Other Business Operations and Eliminations
Other operations consist primarily of subsidiaries that own real estate leased to other Company subsidiaries and the results of operations for OnSight Energy, LLC (“OnSight”). Other operations generated an operating income of approximately $63,000 for the three months ended June 30, 2007 compared to an operating loss of approximately $26,000 for the same period in 2006. The improved results are primarily from OnSight experiencing a reduced operating loss in the second quarter of 2007.


- 23 -

 
The Company formed OnSight in 2004 to provide distributed energy services. Distributed energy refers to a variety of small, modular power generating technologies that may be combined with heating and/or cooling systems. For the three months ended June 30, 2007, OnSight had an operating loss of $10,000 compared to an operating loss of $98,000 for the same period in 2006. The reduced operating loss in 2007 is a direct result of actions which the Company took in the third quarter of 2006 to reduce operating expenses going forward.
 
For the Three Months Ended June 30,
  
2007
  
2006
  
Change
 
Revenue
 
$
154,623
  
$
155,136
    
($513
)
Cost of sales
   
4,616
   
438
   
4,178
 
Gross margin
   
150,007
   
154,698
   
(4,691
)
                     
Operations & maintenance
   
33,394
   
119,301
   
(85,907
)
Depreciation & amortization
   
39,545
   
40,827
   
(1,282
)
Other taxes
   
14,871
   
21,029
   
(6,158
)
Other operating expenses
   
87,810
   
181,157
   
(93,347
)
Operating Income (Loss) - Other
   
62,197
   
(26,459
)
  
88,656
 
Operating Income - Eliminations (1)
   
772
   
770
   
2
 
Total Operating Income (Loss)
 
$
62,969
    
($25,689
)
$
88,658
  
                     
(1) Eliminations are entries required to eliminate activities between business segments from the consolidated results.
  

Interest Expense
Total interest expense for the three months ended June 30, 2007 increased approximately $93,000, or six percent, compared to the same period in 2006. The higher interest expense is a result of the following developments:

·  
The Company’s average long-term debt balance during the three months ended June 30, 2007 was $78.0 million with a weighted average interest rate of 6.67 percent, compared to $62.8 million with a weighted average interest rate of 7.11 percent for the same period in 2006. The large period-over-period increase in the average long-term debt balance is the result of a debt placement of $20 million Senior Notes (“Notes”) at 5.5 percent in October 2006 with three institutional investors (The Prudential Insurance Company of America, Prudential Retirement Insurance and Annuity Company and United Omaha Life Insurance Company).
·  
An increase in the Company’s average short-term interest rate in the three months ended June 30, 2007 compared to 2006. The average interest rate for short-term borrowing increased from 5.46 percent to 5.73 percent.
·  
A decrease in the Company’s average short-term debt balance during the three months ended June 30, 2007 compared to the same period in 2006. The average short-term borrowing balance decreased $9.8 million in 2007 to $14.1 million compared to $23.9 million in 2006.
 
Income Taxes
Income tax expense for the three months ended June 30, 2007 was $846,000 compared to $635,000 for the three months ended June 30, 2006. The increase in income tax expense primarily reflects higher earnings. The effective tax rate for the second quarter of 2007 is 36.3 percent compared to an effective tax rate of 35.9 percent for the same period in 2006.


- 24 -

 
Results of Operations for the Six Months Ended June 30, 2007
The following discussions on operating income and segment results for the six months ended June 30, 2007 include use of the term “gross margin.” Gross margin is determined by deducting the cost of sales from operating revenue. Cost of sales includes the purchased gas cost for natural gas and propane and the cost of labor spent on direct revenue-producing activities. Gross margin should not be considered an alternative to operating income or net income, which are determined in accordance with GAAP. Chesapeake believes that gross margin, although a non-GAAP measure, is useful and meaningful to investors as a basis for making investment decisions. It provides investors with information that demonstrates the profitability achieved by the Company under its allowed rates for regulated operations and under its competitive pricing structure for non-regulated segments. Chesapeake’s management uses gross margin in measuring its business units’ performance and has historically analyzed and reported gross margin information publicly. Other companies may calculate gross margin in a different manner.

Consolidated Overview
The Company’s net income for the six months ended June 30, 2007 increased $2.2 million, or 31 percent, compared to the same period in 2006. Net income was $9.4 million, or $1.39 per share (diluted), an increase of $0.19 per share compared to 2006. The period-over-period increase in earnings reflects an increase in operating income at the Company’s natural gas and propane operations as a result of continued growth and colder temperatures on the Delmarva Peninsula, which increased volumes sold to customers. The Company estimates that the growth and colder weather contributed $3.4 million and $1.7 million, respectively, to gross margin during the first six months of 2007.

For the Six Months Ended June 30,
  
2007
  
2006
  
Change
 
Operating Income
                   
Natural Gas
 
$
13,608,264
  
$
11,495,833
  
$
2,112,431
  
Propane
   
4,327,658
   
2,992,101
   
1,335,557
 
Advanced Information Services
   
227,528
   
188,371
   
39,157
 
Other & Eliminations
   
106,661
   
(33,709
)
  
140,370
 
Operating Income
   
18,270,111
   
14,642,596
   
3,627,515
 
                     
Other Income
   
287,567
   
142,299
   
145,268
 
Interest Charges
   
3,193,951
   
2,994,689
   
199,262
 
Income Taxes
   
5,890,848
   
4,561,281
   
1,329,567
 
Net Income
 
$
9,472,879
  
$
7,228,925
  
$
2,243,954
  
Diluted Earnings Per Share
 
$
1.39
  
$
1.20
  
$
0.19
  


- 25 -

 
Natural Gas
The natural gas segment earned operating income of $13.6 million for the six months ended June 30, 2007 compared to $11.5 million for the corresponding period in 2006, an increase of $2.1 million, or 18 percent.

For the Six Months Ended June 30,
 
2007
  
2006
  
Change
 
Revenue
 
$
104,875,421
  
$
101,024,221
  
$
3,851,200
  
Cost of sales
   
72,899,708
   
73,166,577
   
(266,869
)
Gross margin
   
31,975,713
   
27,857,644
   
4,118,069
 
                     
Operations & maintenance
   
12,703,572
   
11,367,924
   
1,335,648
 
Depreciation & amortization
   
3,630,193
   
3,053,083
   
577,110
 
Other taxes
   
2,033,684
   
1,940,804
   
92,880
 
Other operating expenses
   
18,367,449
   
16,361,811
   
2,005,638
 
Total Operating Income
 
$
13,608,264
  
$
11,495,833
  
$
2,112,431
  
                     
                     
Statistical Data — Delmarva Peninsula
                   
Heating degree-days ("HDD"):
                   
Actual
   
2,966
   
2,457
   
509
 
10-year average (normal)
   
2,737
   
2,793
   
(56
)
                     
Estimated gross margin per HDD
 
$
2,283
  
$
2,234
  
$
49
  
                     
Per residential customer added:
                   
Estimated gross margin
 
$
372
  
$
372
  
$
0
  
Estimated other operating expenses
 
$
106
  
$
106
  
$
0
  
Residential Customer Information
                   
Average number of customers:
                   
Delmarva
   
43,471
   
40,126
   
3,345
 
Florida
   
13,311
   
12,470
   
841
 
Total
   
56,782
   
52,596
   
4,186
 

Gross margin for the Company’s natural gas segment increased by $4.1 million, or 15 percent, and other operating expenses increased $2.0 million, or 12 percent, in the six months ended June 30, 2007 compared to the same period in 2006. The gross margin increases of $2.0 million for the natural gas transmission operation, $2.3 million for the Delmarva natural gas distribution operations, and $132,000 for the Florida natural gas distribution operation were partially offset by a lower gross margin of $274,000 for the natural gas marketing operation, as further explained below.

Natural Gas Transmission
The natural gas transmission operation achieved gross margin growth of $2.0 million, or 22 percent. This increase was primarily attributed to new transportation capacity contracts implemented in November 2006 and the implementation of temporary rates, subject to refund, based on the status of the FERC rate proceeding discussed below in the “Regulatory Matters” section. In total for 2007, these new transportation capacity contracts are expected to generate a gross margin of $3.3 million above the 2006 gross margin. An increase of $1.3 million in other operating expenses partially offset the increased gross margin. The factors contributing to the increase in other operating expenses are as follows:

·  
The increase in operating expenses for the first six months of 2007 is magnified by the FERC’s approval, in July 2006, to defer pre-service costs of the Company’s Energylink Expansion Project as a regulatory asset. The deferral of these costs resulted in the reduction of $310,000 in other operating expenses in the second quarter of 2006. Please refer to the “Regulatory Matters” section below for further information on this expansion project.
·  
Payroll and benefit costs increased by $149,000 and $45,000, respectively, to comply with federal pipeline integrity maintenance regulations and to serve the additional growth experienced by the operation.
·  
Incentive compensation increased by $24,000 as a result of the improved operating results in 2007 compared to 2006.
·  
Regulatory expenses increased by $108,000 in the first six months of 2007 as the Company incurred costs associated with its rate filing with the FERC.
·  
The increased level of capital investment caused higher depreciation and asset removal costs of $425,000 and increased property taxes of $52,000.
·  
Other operating expenses relating to various items increased collectively by approximately $169,000.
 
 
- 26 -
 
 
Natural Gas Distribution
The Delmarva distribution operations experienced an increase of $2.3 million, or 19 percent, in gross margin. The significant items contributing to the increase in gross margin include the following:

·  
The Company estimates that weather contributed $756,000 to gross margin in the six months ended June 30, 2007 compared to the same period in 2006, as temperatures on the Delmarva Peninsula were 21 percent colder in 2007. The colder temperatures did not have a significant impact on the Maryland distribution operation’s gross margin in the first six months of 2007, because the operation’s approved rate structure now includes a WNA mechanism. The WNA mechanism was implemented in October 2006 and is designed to protect a portion of the Company’s revenues against warmer-than-normal weather, as deviations from normal weather can affect our financial performance and liquidity. The WNA also serves to offset the impact of colder-than-normal weather by reducing the amounts the Company can charge its customers during such periods.
·  
Continued residential customer growth also contributed to the increase in gross margin. The average number of residential customers on the Delmarva Peninsula increased by 3,345, or eight percent, for the six months ended June 30, 2007 compared to the same period in 2006, and the Company estimates that these additional residential customers contributed approximately $703,000 to gross margin.
·  
In October 2006, the Maryland PSC granted the Company a base rate increase, which resulted in a $495,000 period-over-period increase to gross margin in the first six months of 2007.
·  
The remaining $205,000 increase in gross margin can be attributed to various factors, including an increase in the number of commercial and industrial customers.

Gross margin for the Florida distribution operation increased by $133,000, or two percent, in the first six months of 2007 compared to the same period in 2006. The higher gross margin for the period is primarily attributed to the increase in customers as the operation experienced a seven percent growth in residential customers and a three percent growth in commercial customers.


- 27 -

 
Other operating expense for the natural gas distribution operations increased by $599,000 in the first six months of 2007 compared to the same period in 2006. Among the key components of the increase were the following:

·  
Payroll costs increased by $90,000 to serve the additional growth experienced by the operation.
·  
Health care costs increased by $113,000 as the Company experienced a higher cost of claims in the first six months of 2007 compared to the same period in 2006.
·  
Depreciation and amortization expense, asset removal cost and property taxes increased by $200,000, $99,000 and $52,000, respectively, as a result of the Company’s continued capital investments.
·  
In addition, other operating expenses relating to various minor items increased by approximately $86,000.
·  
Merchant payment fees decreased by $41,000, as the Company’s Delmarva operation outsourced the processing of credit card payments in April of 2007; this decrease was partially offset by the increased merchant payment fees incurred in the first quarter of 2007.

Natural Gas Marketing
Gross margin for the natural gas marketing operation decreased by $274,000, or 21 percent, for the first six months of 2007 compared to the same period in 2006. The decline in gross margin was primarily the result of unfavorable imbalance resolutions with interstate pipelines, which caused an increase in the cost of gas. Other operating expenses increased by $125,000 for the marketing operation primarily due to increases in payroll and benefit costs, allowance for uncollectible accounts and corporate overhead costs.

Propane
The propane segment experienced an increase of $1.3 million, or 45 percent, in operating income for the six months ended June 30, 2007 compared to the same period in 2006. Gross margin increased by $2.5 million, which was partially offset by an increase in other operating expenses of $1.2 million.

For the Six Months Ended June 30,
  
2007
  
2006
  
Change
 
Revenue
 
$
34,416,976
  
$
28,488,315
  
$
5,928,661
  
Cost of sales
   
21,263,372
   
17,877,811
   
3,385,561
 
Gross margin
   
13,153,604
   
10,610,504
   
2,543,100
 
                     
Operations & maintenance
   
7,459,990
   
6,365,200
   
1,094,790
 
Depreciation & amortization
   
904,368
   
819,384
   
84,984
 
Other taxes
   
461,588
   
433,819
   
27,769
 
Other operating expenses
   
8,825,946
   
7,618,403
   
1,207,543
 
Total Operating Income
 
$
4,327,658
  
$
2,992,101
  
$
1,335,557
  
                     
                     
Statistical Data — Delmarva Peninsula
                   
Heating degree-days ("HDD"):
                   
Actual
   
2,966
   
2,457
   
509
 
10-year average (normal)
   
2,737
   
2,793
   
(56
)
                     
Estimated gross margin per HDD
 
$
1,974
  
$
1,743
  
$
231
  

Operating income for the propane segment increased by $1.3 million, or 45 percent, to $4.3 million for the six months ended June 30, 2007 compared to the same period in 2006. This increase was due primarily to colder weather on the Delmarva Peninsula in the first six months of 2007, which resulted in increased consumption by customers. Gross margin in the Delmarva propane distribution operations increased, compared to the first six months of 2006, by $2.1 million, primarily due to colder weather. Gross margin also increased in the Florida propane distribution operation and the Company’s wholesale propane marketing operation by $62,000 and $367,000, respectively.
 
 
- 28 -

 
Delmarva Propane Distribution
The Delmarva propane distribution operation’s increase in gross margin of $2.1 million resulted from the following:

·  
Volumes sold in the first six months of 2007 increased by 1.9 million gallons, or 13 percent, primarily because temperatures on the Delmarva Peninsula were 21 percent colder during the first six months of 2007 than during the same period in 2006. The Company estimates that the colder weather increased gross margin by approximately $931,000 for the Delmarva propane distribution operation compared to the first six months of 2006.
·  
Gross margin further increased by $577,000 in the first six months of 2007, compared to the same period in 2006, because of a $0.05 increase in the average gross margin per retail gallon. This increase occurs when market prices of propane rise greater than the Company’s average inventory price per gallon. This trend reverses, as it did in the second quarter of 2007, when market prices decrease and moves closer to the Company’s inventory price per gallon. Propane gross margin is also impacted by the Company’s pricing with its customers.
·  
Gross margin for the Delmarva Community Gas Systems (“CGS”) increased by $529,000 in the first six months of 2007, compared to the same period in 2006, primarily because of the colder weather and an increase in the average number of customers. The average number of CGS customers increased by approximately 1,000 to a total count of approximately 4,680, or a 27 percent increase, compared to the first six months of 2006. The Company expects the growth of its CGS operation to continue as the number of systems currently under construction or under contract is anticipated to provide an additional 7,900 CGS customers, an increase of 169 percent.
·  
The remaining $77,000 decrease in gross margin can be attributed to various factors, including lower service sales and wholesale sales.

Total other operating expenses increased by $995,000 for the Delmarva operations in the six months ended June 30, 2007, compared to the same period in 2006. The significant items contributing to this increase are explained below:

·  
The increase in operating expenses for the first six months of 2007 is magnified by the Company’s one-time recovery of previously incurred costs of $387,000 from one of its propane suppliers. This recovery reimbursed the Company for fixed costs incurred in the removal of above-normal levels of petroleum by-products contained in approximately 75,000 gallons of propane that it purchased from the supplier. The recovery of these costs reduced other operating expenses in the first six months of 2006.
·  
Payroll costs have increased by $73,000 to serve the additional growth experienced by the operation.
·  
Incentive compensation increased by $183,000 as a result of the improved operating results in 2007 compared to 2006.
·  
Health care costs increased by $80,000 during the first six months of 2007 compared to the same period in 2006 as the Company experienced a higher cost of claims during the period.
·  
The operation incurred an additional $116,000 in 2007 for propane tank recertifications and maintenance to comply with Department of Transportation standards.
·  
Depreciation and amortization expense increased by $60,000 as a result of the Company’s continued capital investments.
·  
In addition, other operating expenses relating to various items increased collectively by approximately $96,000.
 
 
- 29 -

 
Florida Propane Distribution
The Florida propane distribution operation experienced an increase in gross margin of $62,000, or 10 percent, in the first six months 2007 compared to the same period in 2006. Gross margin from propane sales increased $14,000 as a higher average gross margin per retail gallon was partially offset by a two percent decrease in the volumes sold in 2007. The remaining increase of $48,000 is attributed to higher in-house piping sales. Other operating expenses in the first six months of 2007, compared to the same period in 2006, increased by $118,000, primarily due to increases in payroll costs, insurance and depreciation expense, which were partially offset by lower incentive compensation.

Propane Wholesale and Marketing
Gross margin for the Company’s propane wholesale marketing operation increased by $367,000, or 38 percent, in the first six months of 2007 compared to the same period in 2006. This increase reflects the larger number of market opportunities that arose in the first six months of 2007, due to price volatility in the propane wholesale market, which exceeded the level of price fluctuations experienced in the same period of 2006. The increase in gross margin was partially offset by higher other operating expenses of $94,000, due primarily to higher incentive compensation based on the increased earnings in 2007.

Advanced Information Services
The advanced information services business experienced gross margin growth of approximately $625,000, or 25 percent, and contributed operating income of $228,000 for the six months ended June 30, 2007, an increase of $39,000 compared to the same period in 2006.

For the Six Months Ended June 30,
  
2007
  
2006
  
Change
 
Revenue
 
$
7,121,197
  
$
5,880,094
  
$
1,241,103
  
Cost of sales
   
4,001,111
   
3,385,026
   
616,085
 
Gross margin
   
3,120,086
   
2,495,068
   
625,018
 
                     
Operations & maintenance
   
2,464,659
   
1,972,680
   
491,979
 
Depreciation & amortization
   
69,485
   
61,940
   
7,545
 
Other taxes
   
358,414
   
272,077
   
86,337
 
Other operating expenses
   
2,892,558
   
2,306,697
   
585,861
 
Total Operating Income
 
$
227,528
  
$
188,371
  
$
39,157
  

The increase of revenues in the six months ended June 30, 2007 is resulted from:

·  
An increase of $1.0 million in consulting revenues as the number of billable hours increased by 17 percent;
·  
An increase of $150,000 from Managed Database Administration (“MDBA”) services, first offered in 2006, which provide clients with professional database monitoring and support solutions during business hours or around the clock; and
·  
An increase of $66,000 in revenue from training services and product sales.

Other operating expenses increased by $586,000 to $2.9 million in the six months ended June 30, 2007, compared to $2.3 million for the same period in 2006. This increase in operating expenses is due primarily to an increase in accrued incentive compensation based on improved operating results and other costs incurred to support the growth and improved earnings.

 
- 30 -

 
Other Business Operations and Eliminations
Other operations generated an operating income of approximately $107,000 for the six months ended June 30, 2007 compared to an operating loss of approximately $34,000 for the same period in 2006. The improved results are attainable primarily to OnSight experiencing a reduced operating loss in the first six months of 2007.

For the six months ended June 30, 2007, OnSight had an operating loss of $42,000 compared to an operating loss of $196,000 for the same period in 2006. The reduced operating loss in 2007 is a direct result of actions which the Company took in the third quarter of 2006 to reduce operating expenses going forward.

For the Six Months Ended June 30,
  
2007
  
2006
  
Change
 
Revenue
 
$
309,246
  
$
310,271
    
($1,025
)
Cost of sales
   
4,616
   
875
   
3,741
 
Gross margin
   
304,630
   
309,396
   
(4,766
)
                     
Operations & maintenance
   
86,822
   
223,390
   
(136,568
)
Depreciation & amortization
   
80,813
   
81,484
   
(671
)
Other taxes
   
31,874
   
39,771
   
(7,897
)
Other operating expenses
   
199,509
   
344,645
   
(145,136
)
Operating Income (Loss) - Other
   
105,121
   
(35,249
)
  
140,370
 
Operating Income - Eliminations (1)
   
1,540
   
1,540
   
0
 
Total Operating Income (Loss)
 
$
106,661
    
($33,709
)
$
140,370
  
                     
(1) Eliminations are entries required to eliminate activities between business segments from the consolidated results.

Interest Expense
Total interest expense for the first six months of 2007 increased approximately $199,000, or seven percent, compared to the same period in 2006. The higher interest expense is a result of the following developments:

·  
The Company’s average long-term debt balance during the first six months of 2007 was $77.8 million with a weighted average interest rate of 6.68 percent, compared to $62.8 million with a weighted average interest rate of 7.14 percent for the same period in 2006. The large year-over-year increase in the average long-term debt balance is the result of a debt placement of $20 million Senior Notes (“Notes”) at 5.5 percent in October 2006 with three institutional investors (The Prudential Insurance Company of America, Prudential Retirement Insurance and Annuity Company and United Omaha Life Insurance Company).
·  
An increase in the average short-term interest rates in the first six months of 2007 compared to the same period in 2006. The Company’s average interest rate for short-term borrowing increased from 5.20 percent to 5.72 percent.
·  
A decrease in the Company’s average short-term debt balance during the first six months of 2007 compared to the same period in 2006. The average short-term borrowing balance decreased $10.7 million in 2007 to $15.8 million compared to $26.5 million in 2006.

Income Taxes
Income tax expense for the six months ended June 30, 2007 was $5.9 million compared to $4.6 million for the six months ended June 30, 2006. The increase in income tax expense primarily reflects higher earnings. The effective tax rate for the first six months of 2007 is 38.3 percent compared to an effective tax rate of 38.7 percent for the same period in 2006.
 
 
 
- 31 -
 
 
Financial Position, Liquidity and Capital Resources

Chesapeake’s capital requirements reflect the capital-intensive nature of its business and are principally attributable to its investment in new plant and equipment and the retirement of outstanding debt. The Company relies on cash generated from operations, short-term borrowing, and other sources to meet normal working capital requirements and to finance capital expenditures. During the first six months of 2007, net cash provided by operating activities was $20.6 million, cash used by investing activities was $15.9 million and cash used by financing activities was $8.3 million.

By comparison, during the first six months of 2006, net cash provided by operating activities was $23.0 million, cash used by investing activities was $16.8 million and cash used by financing activities was $6.3 million.

The Board of Directors has authorized the Company to borrow up to $55.0 million of short-term debt, as required, from various banks and trust companies under short-term lines of credit. As of June 30, 2007, Chesapeake had four unsecured bank lines of credit with two financial institutions, totaling $80.0 million. These bank lines will provide funds for the Company’s short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of its capital expenditures. Two of the bank lines, totaling $15.0 million, are committed. The other two lines are subject to the availability of bank funds. The outstanding balance of short-term borrowing at June 30, 2007 and December 31, 2006 was $23.6 million and $27.6 million, respectively.

Chesapeake has budgeted $45.5 million for capital expenditures during 2007. This amount includes $20.2 million for natural gas distribution, $16.5 million for natural gas transmission, $7.5 million for propane distribution and wholesale marketing, $154,000 for advanced information services and $915,000 for other operations. The natural gas distribution and transmission expenditures are for expansion and improvement of facilities. The propane expenditures are to support customer growth and the replacement of equipment. The advanced information services expenditures are for computer hardware, software and related equipment. The other operations category includes general plant, computer software and hardware. Financing for the 2007 capital expenditure program is expected from short-term borrowing, cash provided by operating activities, and other sources. The capital expenditure program is subject to continuous review and modification. Actual capital requirements may vary from the above estimates due to a number of factors, including acquisition opportunities, changing economic conditions, customer growth in existing areas, regulation, new growth opportunities and availability of capital.

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

Capital Structure
The following presents the Company’s capitalization as of June 30, 2007 and December 31, 2006:

 
June 30, 2007
  
December 31, 2006
  
   
(In thousands, except percentages)
  
                   
Long-term debt, net of current maturities
  
$
69,965
    
37
%
$
71,050
    
39
%
Stockholders' equity
  
$
118,883
    
63
%
$
111,152
    
61
%
Total capitalization, excluding short-term debt
  
$
188,848
    
100
%
$
182,202
    
100
%
 
 
- 32 -

 
As of June 30, 2007, common equity represented 63 percent of total capitalization, compared to 61 percent at December 31, 2006. If short-term borrowing and the current portion of long-term debt were included in total capitalization, the equity component of the Company’s capitalization would have been 54 percent and 51 percent at June 30, 2007 and December 31, 2006, respectively. Chesapeake remains committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access capital markets when required. This commitment, along with adequate and timely rate relief for the Company’s regulated operations, is intended to ensure that Chesapeake will be able to attract capital from outside sources at a reasonable cost. The Company believes that the achievement of these objectives will provide benefits to customers and creditors, as well as to the Company’s investors.

Shelf Registration
In July 2006, the Company filed a registration statement on Form S-3 with the SEC to issue up to $40.0 million in new common stock and/or debt securities. The registration statement was declared effective by the SEC in November 2006. At June 30, 2007, the Company had approximately $20.0 million remaining under this registration statement.
 
Cash Flows Provided By Operating Activities
Cash flows provided by operating activities were as follows:

For the Six Months Ended June 30,
  
2007
  
2006
  
Net Income
  
$
9,472,879
  
$
7,228,925
  
Non-cash adjustments to net income
    
8,185,897
   
3,642,120
 
Changes in working capital
    
2,959,281
   
12,099,741
 
Net cash provided by operating activties
  
$
20,618,057
  
$
22,970,786
  

Period-over-period changes in our cash flows from operating activities are attributable primarily to net income, depreciation and working capital changes. The changes in working capital are impacted by weather, the price of natural gas and propane, the timing of customer collections, payments of natural gas and propane purchases, and deferred gas cost recoveries.

For the six months ended June 30, 2007, net cash flow provided by operating activities was $20.6 million, a decrease of $2.4 million compared to the same period of 2006. The decrease was due primarily to changes in working capital, which were partially offset by higher net income and higher non-cash adjustments for depreciation and amortization expense and changes in deferred income taxes. The reduction in working capital was due primarily to the decrease in cash provided from accounts receivable and income tax receivable, which was partially offset by a decrease in cash used by accounts payable for gas purchases payable. The changes in accounts receivable and accounts payable were impacted by the weather and the lower gas commodity costs. 
 
Cash Flows Used in Investing Activities 
Net cash flows used in investing activities totaled $15.9 million and $16.8 million during the six months ended June 30, 2007 and 2006, respectively. Cash utilized for capital expenditures was $16.0 million and $16.8 million for the first six months of 2007 and 2006, respectively. Additions to property, plant and equipment in these quarters were primarily for natural gas transmission, natural gas distribution and propane distribution. In both 2007 and 2006, the natural gas distribution expenditures were used primarily to fund expansion and facilities improvements. In both periods, the natural gas transmission capital expenditures related primarily to expanding the Company’s transmission system. In addition, $136,000 more than what was recovered through rates charged to customers was used for environmental expenditures in the first six months of 2007 compared to a net recovery of $2,000 for environmental costs through rates charged to customers in the same period in 2006.


- 33 -

 
Cash Flows Used in Financing Activities 
Cash flows used in financing activities totaled $8.3 million and $6.3 million for the six months ended June 30, 2007 and 2006, respectively. Significant financing activities included the following:

·  
During the first six months of 2007, the Company reduced short-term debt by $4.8 million compared to a $3.7 million reduction in the first six months of 2006.
 
·  
During the first six months of 2007, the Company paid $3.5 million in cash dividends compared with dividend payments of $2.9 million for the same time period in 2006. The increase in dividends paid over the prior year reflects an increase in the annualized dividend rate from $1.14 per share during the first quarter of 2006 to $1.16 per share in the first quarter of 2007 and the issuance of additional shares of common stock.
 
·  
The Company repaid $1.0 million of long-term debt during the first six months of 2007 and 2006.
 

Off-Balance Sheet Arrangements
The Company has issued corporate guarantees to certain vendors of its propane wholesale marketing subsidiary, its Florida natural gas supply and management subsidiary and its Delmarva propane distribution subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of a subsidiary’s default. Liabilities for these purchases are recorded in the Consolidated Financial Statements. The aggregate amount guaranteed at June 30, 2007 was $21.7 million, with the guarantees expiring on various dates in 2007 and 2008.

In addition to the corporate guarantees, the Company has issued a letter of credit to its primary insurance company for $775,000, which expires on May 31, 2008. The letter of credit is provided as security for claims amounts to satisfy the deductibles on the Company’s policies.

Contractual Obligations
There have not been any material changes in the contractual obligations presented in the Company’s 2006 Annual Report on Form 10-K, except for commodity purchase obligations and forward contracts entered into in the ordinary course of the Company’s business. Below is a summary of the commodity and forward contract obligations at June 30, 2007.

 
Payments Due by Period
  
Purchase Obligations
  
Less than 1 year
  
1 - 3 years
  
3 - 5 years
  
More than 5 years
  
Total
  
Commodities (1)
  
$
2,264,343
  
$
55,506
  
$
0
  
$
0
  
$
2,319,849
  
Propane (2)
    
67,461,710
   
-
   
-
   
-
   
67,461,710
 
Total Purchase Obligations
  
$
69,726,053
  
$
55,506
  
$
0
  
$
0
  
$
69,781,559
  

(1)  
In addition to the obligations noted above, the natural gas distribution and propane distribution operations have agreements with commodity suppliers that have provisions allowing the Company to reduce or eliminate the quantities purchased. There are no monetary penalties for reducing the amounts purchased; however, the propane contracts allow the suppliers to reduce the amounts available in the winter season if the Company does not purchase specified amounts during the summer season. Under these contracts, the commodity prices will fluctuate as market prices fluctuate.
(2)  
The Company has also entered into forward sale contracts in the aggregate amount of $69.6 million. See Part I, Item 3, “Quantitative and Qualitative Disclosures about Market Risk,” below for further information.

Environmental Matters
As more fully described above in Note 4 to the Condensed Consolidated Financial Statements, Chesapeake has incurred costs relating to the completed or ongoing environmental remediation at three former manufactured gas plant sites. In addition, Chesapeake is currently participating in discussions regarding possible responsibility of the Company for remediation of a fourth former manufactured gas plant site located in Cambridge, Maryland. Chesapeake believes that future costs associated with these sites will be recoverable in rates or through sharing arrangements with, or contributions by, other responsible parties.
 
 
 
- 34 -
 
 
Other Matters

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

Delaware. On September 2, 2005, the Delaware division filed an application with the Delaware Public Service Commission (“Delaware PSC”) requesting approval of an alternative rate design and rate structure in order to provide natural gas service to prospective customers in eastern Sussex County. While Chesapeake does provide natural gas service to residents and businesses in portions of Sussex County under the Company’s current tariff, natural gas distribution lines have not been extended to a large portion of the State of Delaware’s recently targeted growth areas in eastern Sussex County. In April 2002, Governor Ruth Ann Minner established the Delaware Energy Task Force (“Task Force”), whose mission was to address the State of Delaware’s long-term and short-term energy challenges. In September 2003, the Task Force issued its final report to the Governor that included a strategy related to enhancing the availability of natural gas within the State by evaluating possible incentives for expanding residential and commercial natural gas service. Chesapeake believes its current proposal to implement a rate design that will enable the Company to provide natural gas as a viable energy choice to a broad number of prospective customers within eastern Sussex County is consistent with the Task Force recommendation. As the Delaware division has included these proposals in its filing made on July 6, 2007, the Delaware division anticipates closing this particular proceeding and continuing discussions in the context of the base rate proceeding.

On September 1, 2006, the Company filed with the Delaware PSC its annual Gas Sales Service Rates Application (“GSR”) seeking the approval of the Delaware PSC to change its GSR rates effective for service rendered on and after November 1, 2006. On October 3, 2006, the Delaware PSC authorized the Company to implement the GSR charges on a temporary basis and subject to refund, pending the completion of full evidentiary hearings and a final decision by the Delaware PSC. The Division of the Public Advocate (“DPA”) recommended a cost disallowance of approximately $4.4 million related to the Delaware division’s commodity procurement purchases and a disallowance of approximately $275,000 related to pipeline capacity the Delaware division holds in eastern Sussex County, Delaware. The Delaware PSC Staff recommended a cost disallowance of approximately $2.2 million related to the Delaware division’s commodity procurement purchases and the deferral of approximately $535,000 related to pipeline capacity the Delaware division holds in eastern Sussex County, Delaware. The Company disagreed with these recommendations and opposed the proposed cost disallowance and deferral in its rebuttal position submitted on April 19, 2007. Under established Delaware law, gas procurement costs, like other normally accepted operating expenses, cannot be disallowed unless it is shown that the costs were the result of an abuse of discretion, bad faith, or waste. Management believes that the Company’s gas procurement practices and pipeline capacity costs were reasonable and that, in no event were the costs at issue incurred as a result of any abuse of discretion, bad faith, or waste on the part of the Company. On July 24, 2007, the Delaware PSC approved a settlement agreement between the parties resulting in no cost disallowance for the Delaware division. As a result of the settlement agreement, the Delaware division has agreed to contribute an amount equal to $37,500 per year for the next three years to its internal program designed to benefit elderly, disabled, and low-income customers of the Delaware division. Additionally, with respect to the allowances for recovery of costs associated with pipeline capacity in eastern Sussex County, the settlement provides for the Delaware division to reduce the total amount of GSR charges to be collected from its customers by $275,000, effective beginning with the billing period from November 1, 2007 through October 31, 2008, and provides for the Delaware division to subsequently add $275,000 to the total of its GSR charges to be collected from customers effective for billings from November 1, 2008 through October 31, 2009.
 
 
- 35 -

 
On November 1, 2006, the Delaware division filed with the Delaware PSC its annual Environmental Rider (“ER”) rate application to become effective for service rendered on and after December 1, 2006. The Delaware PSC granted approval of the ER rate at its regularly scheduled meeting on November 21, 2006, subject to full evidentiary hearings and a final decision. On January 23, 2007, the Delaware PSC granted final approval of the ER rate as filed.

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

On July 6, 2007, the Company filed with the Delaware PSC an application seeking approval of the following: (i) participation by the Company’s Delaware commercial and industrial customers in transportation buying pools served by third-party natural gas marketers; (ii) a base rate adjustment of $1,896,000 annually that represents approximately a 3.25 percent rate increase on average for the Delaware division’s firm customers; (iii) an alternative rate design for residential customers in a defined expansion area in eastern Sussex County, Delaware; and (iv) a revenue normalization mechanism that reduces the impact of natural gas consumption on both customers and the Company. As an incentive for the Delaware division to make the significant capital investments to serve the growing areas of eastern Sussex County and in supporting Delaware’s Energy Policy, the Company has proposed as part of the filing that the Delaware division be permitted to earn a return on equity up to 15 percent. This level of return ensures that the Company’s investors are adequately compensated for the increased risk associated with the higher levels of capital investment necessary to provide natural gas in those growing areas.

Maryland. On September 26, 2006, the Maryland PSC approved a base rate increase for the Maryland division of approximately $780,000 annually. In a settlement agreement entered into in that proceeding, the Maryland division was required to file a depreciation study, which was filed on April 9, 2007. The Maryland division filed formal testimony on July 10, 2007, initiating a phase II of this proceeding. In this filing, the Maryland division proposed a rate decrease of approximately $80,000 annually, resulting from a change in depreciation expense. The Maryland division anticipates a decision from the Maryland PSC on its proposed change in depreciation expense during the fourth quarter of 2007.

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

Florida. On September 15, 2006, the Florida gas distribution division filed a petition with the Florida PSC for approval of its Energy Conservation Cost Recovery Factors for the year 2007. Approved on November 30, 2006 by the Florida PSC, the new factors went into effect on January 1, 2007.
 
 
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On October 10, 2006, the Florida division filed a petition with the Florida PSC for authority to implement phase two of its experimental transitional transportation service (“TTS”) pilot program, and for approval of a new tariff to reflect the division’s transportation service environment. Phase two of the TTS program for residential and certain small commercial consumers will expand the number of pool managers from one to two and increase the gas supply pricing options available to these consumers. Approved on April 24, 2007 by the Florida PSC, phase two of the TTS program will go into effect in the third quarter of 2007.

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

On May 2, 2007, the Florida division filed its summary of activity and true-up calculation for its 2006 Energy Conservation Cost Recovery Program with the Florida PSC. The outcome of this filing is dependent upon an audit of the costs by the Florida PSC, which is expected in the third quarter of 2007. The results of the audit will be incorporated into the calculation of the 2008 Energy Conservation Cost Recovery Factors, which is expected to be filed with the Florida PSC in mid-September 2007.

In compliance with the Florida Administrative Code, the Florida division filed its 2007 Depreciation Study with the Florida PSC on May 17, 2007. This study provides the Florida PSC with the opportunity to review and address the lives, salvage values, reserves and resulting life depreciation rates since the last study performed in 2002. In its filing, the Florida division has requested that any changes to the depreciation rates be made effective January 1, 2008. While the Company cannot predict the outcome of the Florida PSC’s review at this time, the Company anticipates a final decision regarding the depreciation rates in the fourth quarter of 2008.

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

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

Year
Services implemented November 1,
2006
2007
2008
Additional firm capacity per day
26,200
10,300
10,850
Capital investment
$17 million
$8 million
$8 million
Annualized gross margin contribution
$3.7 million
$1.5 million
$1.6 million

Eastern Shore has completed and placed in service the authorized Phase I facilities. The actual capital investment for Phase I was $25.5 million, compared to the $17.0 million original estimate included in the filing. Phase II and Phase III facilities are expected to be constructed in 2007 and 2008, respectively.
 
 
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Eastern Shore Energylink Expansion Project (“E3 Project”). Eastern Shore has proposed to develop, construct and operate approximately 63 miles of new pipeline facilities to transport natural gas from Calvert County, Maryland, crossing under the Chesapeake Bay into Dorchester and Caroline Counties, Maryland, to points on the Delmarva Peninsula where such facilities would interconnect with Eastern Shore’s existing facilities in Sussex County, Delaware.

On May 31, 2006, Eastern Shore entered into Precedent Agreements (the “Precedent Agreements”) with Delmarva Power & Light Company (“Delmarva”) and Chesapeake, through its Delaware and Maryland Divisions, to provide additional firm transportation services upon completion of the E3 Project.

Chesapeake and Delmarva are parties to existing firm natural gas transportation service agreements with Eastern Shore, and each desires firm transportation services under the E3 Project, as evidenced by the Precedent Agreements. Pursuant to the Precedent Agreements, the parties have agreed to proceed with the required initiatives to obtain the governmental and regulatory authorizations that are necessary for Eastern Shore to provide, and for Chesapeake and Delmarva to utilize firm transportation services under the E3 Project.

Eastern Shore, Chesapeake and Delmarva have also entered into Letter Agreements which provide that, in the event that the E3 Project is not certificated and placed in service, Chesapeake and Delmarva will each pay their proportionate share of certain pre-certification costs by means of a negotiated surcharge of up to $2 million each, over a period of not less than 20 years.

In furtherance of the E3 Project, Eastern Shore submitted a petition to the FERC on June 27, 2006 seeking approval of an uncontested rate-related Settlement Agreement by and between Eastern Shore, Chesapeake and Delmarva (the “Settlement Agreement”). The Settlement Agreement provides Eastern Shore and all customers utilizing Eastern Shore’s system with benefits, including but not limited to the following: (1) advancement of a necessary infrastructure project to meet the growing demand for natural gas on the Delmarva Peninsula; (2) sharing of project development costs by the participating customers in the project; and (3) no development cost risk for non-participating customers. On August 1, 2006, the FERC approved the Settlement Agreement, which was uncontested. On September 6, 2006, Eastern Shore submitted to FERC proposed tariff sheets to implement the provisions of the Settlement Agreement. By Letter Order dated October 6, 2006, the FERC accepted the tariff sheets effective September 7, 2006.

Eastern Shore submitted its Request for Pre-Filing to the FERC on April 23, 2007, and on May 15, 2007, the FERC notified Eastern Shore that its request had been approved. The pre-filing process is intended to engage all interested and affected stakeholders early in the process with the intention of resolving all environmental issues prior to the formal certificate application being filed.

Eastern Shore is actively involved in the FERC’s pre-filing process. Eastern Shore has performed various environmental, engineering and cultural surveys and studies to advance the project and has held meetings with federal, state and local permitting/regulatory agencies, non-governmental organizations and other interested stakeholders. As part of an updated and revised engineering study, Eastern Shore received construction cost estimates for the E3 project which are significantly higher than previous estimates. Eastern Shore has initiated additional analyses to identify and quantify alternative construction methods, cost mitigation strategies and additional markets to retain the economic viability of the project. Eastern Shore has had discussions with several potential new customers who have interest in the project; their participation in the project could offset the impact of the increased project cost. The ultimate success of the E3 project, however, depends upon a number of external factors which cannot be predicted at this time.
 
 
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Rate Matters. On October 31, 2006 Eastern Shore filed a Section 4 base rate proceeding with the FERC in compliance with the settlement approved in its prior base rate proceeding. Eastern Shore’s filed rates, proposed to be effective November 1, 2006, reflect an annual increase of $5,589,000 over its current annual operating revenues. The proposed rates reflect increases in operating and maintenance expenses, depreciation expense, taxes other than income taxes, and return on new gas plant facilities placed into service before March 31, 2007.

On November 30, 2006 the FERC issued its Order Accepting and Suspending Tariff Sheets Subject to Refund and Establishing a Hearing. The FERC accepted and suspended the effectiveness of Eastern Shore’s rate increase until May 1, 2007, subject to refund and the outcome of the hearing established in the order. On December 19, 2006 the FERC’s Presiding Administrative Law Judge approved a procedural schedule to govern further proceedings in this case.

An initial settlement conference was held on April 17, 2007 at the FERC’s offices in Washington, D.C. On May 14, 2007, Eastern Shore filed a motion to implement its suspended rate increase on May 15, 2007, subject to refund, pending ultimate resolution of the rate case. The Parties reached an agreement in principle at the June 6, 2007 conference. On June 8, 2007, the Chief Administrative Law Judge suspended the procedural schedule to allow time for the Parties to memorialize the settlement in principle into a formal Stipulation and Agreement (“Stipulation”). The Stipulation is currently being circulated among the Parties for final review and revisions. It is anticipated that the Stipulation will be forwarded to the FERC for final approval in the second half of 2007.

Competition
The Company’s natural gas operations compete with other forms of energy including electricity, oil and propane. The principal competitive factors are price, and to a lesser extent, accessibility. The Company’s natural gas distribution operations have several large volume industrial customers that have the capacity to use fuel oil as an alternative to natural gas. When oil prices decline, these interruptible customers convert to oil to satisfy their fuel requirements. Lower levels of interruptible sales occur when oil prices are lower than the price of natural gas. Oil prices, as well as the prices of electricity and other fuels, are subject to fluctuation for a variety of reasons; therefore, future competitive conditions are not predictable. To address this uncertainty, the Company uses flexible pricing arrangements on both the supply and sales side of this business to maximize sales volumes. As a result of the transmission operation’s conversion to open access and the Florida gas distribution division’s restructuring of its services, their businesses have shifted from providing competitive sales service to providing transportation and contract storage services.

The Company’s natural gas distribution operations in Delaware, Maryland and Florida offer transportation services to certain commercial and industrial customers. In 2002, the Florida operation extended transportation service to residential customers. With transportation service available on the Company’s distribution systems, the Company is competing with third-party suppliers to sell gas to industrial customers. As it relates to transportation services, the Company’s competitors include interstate transmission companies if the distribution customer is located close enough to a transmission company’s pipeline to make a connection economically feasible. The customers at risk are usually large volume commercial and industrial customers with the financial resources and capability to bypass the Company’s distribution operations in this manner. In certain situations, the Company’s distribution operations may adjust services and rates for these customers to retain their business. The Company expects to continue to expand the availability of transportation service to additional classes of distribution customers in the future. The Company established a natural gas sales and supply operation in Florida to compete for customers eligible for transportation services. The Company also provides sales service in Delaware.
 
 
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The Company’s propane distribution operations compete with several other propane distributors in their service territories, primarily on the basis of service and price, emphasizing reliability of service and responsiveness. Competition is generally from local outlets of national distribution companies and local businesses; because distributors located in close proximity to customers incur lower costs of providing service. Propane competes with electricity as an energy source, because it is typically less expensive than electricity, based on equivalent BTU value. Propane also competes with home heating oil as an energy source. Since natural gas has historically been less expensive than propane, propane is generally not distributed in geographic areas serviced by natural gas pipeline or distribution systems.

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

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

Inflation
Inflation affects the cost of supply, labor, products and services required for operations, maintenance and capital improvements. While the impact of inflation has remained low in recent years, natural gas and propane prices are subject to rapid fluctuations. Fluctuations in natural gas prices are passed on to customers through the gas cost recovery mechanism in the Company’s tariffs. To help cope with the effects of inflation on its capital investments and returns, the Company seeks rate relief from regulatory commissions for its regulated operations while monitoring the returns of its unregulated business operations. To compensate for fluctuations in propane gas prices, the Company adjusts its propane selling prices to the extent allowed by the market.

Recent Authoritative Pronouncements on Financial Reporting and Accounting
Recent accounting developments and their impact on our financial position, results of operations and cash flows are described in Note 5 to the unaudited condensed consolidated financial statements.


Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market risk represents the potential loss arising from adverse changes in market rates and prices. Long-term debt is subject to potential losses based on changes in interest rates. The Company’s long-term debt consists of first mortgage bonds, fixed-rate senior notes and convertible debentures. All of the Company’s long-term debt is fixed-rate debt and was not entered into for trading purposes. The carrying value of long-term debt, including current maturities, was $77.6 million at June 30, 2007, as compared to a fair value of $79.4 million, based mainly on current market prices or discounted cash flows, using current rates for similar issues with similar terms and remaining maturities. The Company evaluates whether to refinance existing debt or permanently refinance existing short-term borrowing, based in part on the fluctuation in interest rates.

The Company’s propane distribution business is exposed to market risk as a result of propane storage activities and fixed price contracts for supply. The Company can store up to approximately four million gallons (including leased storage and rail cars) of propane during the winter season to meet its customers’ peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause the value of stored propane to decline. To mitigate the impact of price fluctuations, the Company has adopted a Risk Management Policy that allows the propane distribution operation to enter into fair value hedges of its inventory. Management reviewed the Company’s storage position as of June 30, 2007 and elected not to hedge any of its inventories.
 
 
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The Company’s propane wholesale marketing operation is a party to natural gas liquids (“NGL”) forward contracts, primarily propane contracts, with various third parties. These contracts require that the propane wholesale marketing operation purchase or sell NGL at a fixed price at fixed future dates. At expiration, the contracts are settled by the delivery of NGL to the Company or the counter-party or booking out the transaction (booking out is a procedure for financially settling a contract in lieu of the physical delivery of energy). The propane wholesale marketing operation also enters into futures contracts that are traded on the New York Mercantile Exchange. In certain cases, the futures contracts are settled by the payment or receipt of a net amount equal to the difference between the current market price of the futures contract and the original contract price; however, they may also be settled for physical receipt or delivery of propane.

The forward and futures contracts are entered into for trading and wholesale marketing purposes. The propane wholesale marketing business is subject to commodity price risk on its open positions to the extent that market prices for NGL deviate from fixed contract settlement prices. Market risk associated with the trading of futures and forward contracts are monitored daily for compliance with the Company’s Risk Management Policy, which includes volumetric limits for open positions. To manage exposures to changing market prices, open positions are marked up or down to market prices and reviewed by the Company’s oversight officials on a daily basis. In addition, the Risk Management Committee reviews periodic reports on market and the credit risk of counter-parties, approves any exceptions to the Risk Management Policy (within limits established by the Board of Directors) and authorizes the use of any new types of contracts. Quantitative information on forward and futures contracts at June 30, 2007 is presented in the following table.

At June 30, 2007
 
Quantity in gallons
  
Estimated Market Prices
  
Weighted Average Contract Prices
  
Forward Contracts
                   
Sale
   
62,081,838
 
$
0.8850 — $1.2100
  
$
1.1209
  
Purchase
   
59,934,000
 
$
0.8700 — $1.2000
  
$
1.1256
  
                     
Estimated market prices and weighted average contract prices are in dollars per gallon.  All contracts expire in 2007 or the first quarter 2008.

 
Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures
The Chief Executive Officer and Chief Financial Officer of the Company, with the participation of other Company officials, have evaluated the Company’s “disclosure controls and procedures” (as such term is defined under Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended) as of June 30, 2007. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2007.

Changes in Internal Control Over Financial Reporting
During the quarter ended June 30, 2007, there was no change in the Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings
As disclosed in Note 4 “Commitments and Contingencies” of the unaudited condensed consolidated financial statements, the Company is involved in certain legal actions and claims arising in the normal course of business. The Company is also involved in certain legal and administrative proceedings before various government agencies concerning rates. In the opinion of management, the ultimate disposition of these proceedings and claims will not have a material effect on the consolidated financial position, results of operations or cash flows of the Company.

Item 1A. Risk Factors
In addition to the other information set forth in this Form 10-Q, including the risks and uncertainties described under Item 2 of the MD&A hereof entitled “Safe Harbor and Forward Looking Statements,” consideration should be given to the factors discussed under “Item 1A. Risk Factors” in the Company’s Form 10-K for the fiscal year ended December 31, 2006. These risks could affect the operations and/or financial performance of the Company. The risks described in the Form 10-K and this Form 10-Q are not the only risks that the Company faces. The Company’s operations and/or financial performance could also be affected by additional factors that are not presently known to it or that the Company considers immaterial to its operations and/or financial performance.

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

Period
  
Total Number of Shares Purchased
  
Average Price Paid per Share
  
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)
  
Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs (2)
  
April 1, 2007 through April 30, 2007 (1)
    
505
 
$
31.22
    
0
   
0
 
May 1, 2007 through May 31, 2007
    
0
 
$
0.00
    
0
   
0
 
June 1, 2007 through June 30, 2007
    
0
 
$
0.00
    
0
   
0
 
Total
    
505
 
$
31.22
    
0
   
0
 
                           
(1) Chesapeake purchased shares of stock on the open market for the purpose of reinvesting the dividend on shares held in Rabbi Trust
  
accounts for certain Senior Executives. During the quarter, 505 shares were purchased through executive dividend deferrals.
  
(2) Except for the purpose described in Footnote (1), Chesapeake has no publicly announced plans or programs to repurchase its shares.

Item 3. Defaults upon Senior Securities
None

Item 4. Submission of Matters to a Vote of Security Holders
The Annual Meeting of the Stockholders of Chesapeake Utilities Corporation was held on May 2, 2007. The items set forth below were submitted to a vote of security holders. Proxies for the meeting were solicited in accordance with Regulation 14A under the Securities Exchange Act of 1934, as amended. Broker non-votes had no effect on the outcome of the vote on these matters.

The stockholders elected three nominees to the Company’s Board of Directors to serve as Class II directors for three-year terms ending in 2010, and until their successors are duly elected and qualified.
 

 
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The following shows the separate tabulation of votes for each nominee:
 
 
Name
Votes For
Votes Withheld
Ralph J. Adkins
6,072,913
297,758
Richard Bernstein
6,181,633
189,038
J. Peter Martin
6,222,313
148,358



The terms of the following directors were not subject to re-nomination or re-election on May 2, 2007 and their terms are continuing:

Class III Directors (Terms Expire in 2008)
  
Class I Directors (Terms Expire in 2009)
Thomas J. Bresnan
  
Calvert A. Morgan, Jr.
Walter J. Coleman
  
Eugene H. Bayard
Joseph E. Moore
  
Thomas P. Hill, Jr.
John R. Schimkaitis
    

The stockholders approved the ratification of the appointment of Beard Miller Company LLP as the Company’s independent auditors for the fiscal year ending December 31, 2007. There were 6,299,634 affirmative votes, 54,095 negative votes, and 16,942 abstentions.

As of the Record Date, March 15, 2007, 6,717,348 shares of common stock of the Company, the only outstanding class of voting or equity securities of the Company, were outstanding.

Item 5. Other Information
None

Item 6. Exhibits 
The exhibits listed on the following Exhibit Index are filed as part of this Report. Exhibits required by Item 601 of Regulation S−K, but which are not listed below, are not applicable.


Exhibit
Description
31.1
Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, dated August 9, 2007
31.2
Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, dated August 9, 2007
32.1
Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated August 9, 2007
32.2
Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated August 9, 2007

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SIGNATURES

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


Chesapeake Utilities Corporation




/s/ Michael P. McMasters
Michael P. McMasters
Senior Vice President and Chief Financial Officer


Date: August 9, 2007
 
 
 
 
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