The Company charges flexible rates to the natural gas distribution’s industrial interruptible customers to make them competitive with alternative types of fuel. Based on pricing, these customers can choose natural gas or alternative fuels. Neither the Company nor the interruptible customer is contractually obligated to deliver or receive natural gas.

 

Allowance for Doubtful Accounts

An allowance for doubtful accounts is recorded against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect based upon our collections experiences and our assessment of our customers’ inability or reluctance to pay. If circumstances change, however, our estimate of the recoverability of accounts receivable may also change. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices and general economic conditions. Accounts are written off once they are deemed to be uncollectible.

Results of Operations

 

 

Net Income & Diluted Earnings Per Share Summary
										Increase												Increase
For the Years Ended December 31,		2007				2006				(decrease)				2006				2005				(decrease)
Net Income *
Continuing operations		$	13,218			$	10,748			$	2,470			$	10,748			$	10,699			$	49
Discontinued operations			(20	)			(241	)			221				(241	)			(231	)			(10	)
Total Net Income		$	13,198			$	10,507			$	2,691			$	10,507			$	10,468			$	39
Diluted Earnings (Loss) Per Share
Continuing operations		$	1.94			$	1.76			$	0.18			$	1.76			$	1.81			$	(0.05	)
Discontinued operations			-				(0.04	)			0.04				(0.04	)			(0.04	)			-
Total Earnings Per Share		$	1.94			$	1.72			$	0.22			$	1.72			$	1.77			$	(0.05	)
* Dollars in thousands.

 

The Company’s net income from continuing operations increased $2.5 million in 2007 when compared to 2006. Net income from continuing operations was $13.22 million, or $1.94 per share (diluted), for 2007, compared to a net income from continuing operations of $10.75 million, or $1.76 per share (diluted) in 2006.

The Company’s net income from continuing operations increased $49,000 in 2006 when compared to 2005. Net income from continuing operations was $10.75 million, or $1.76 per share (diluted), for 2006, compared to a net income from continuing operations of $10.70 million, or $1.81 per share (diluted) in 2005.

 

During 2007, Chesapeake decided to close its distributed energy services company, Chesapkeake OnSight Services, LLC (“OnSight”), which consistently experienced operating losses since 2004.  At December 31, 2007, the results of operations for OnSight have been reclassified to discontinued operations and shown net of tax for all periods presented.  For 2007, the discontinued operations experienced a net loss of $20,000 compared to a net loss of $241,000, or $0.04 per share (diluted), for 2006 and a net loss of $231,000, or $0.04 per share (diluted), for 2005.

 

Operating Income Summary (in thousands)
										Increase												Increase
For the Years Ended December 31,		2007				2006				(decrease)				2006				2005				(decrease)
Business Segment:
Natural gas		$	22,485			$	19,733			$	2,752			$	19,733			$	17,236			$	2,497
Propane			4,498				2,534				1,964				2,534				3,209				(675	)
Advanced information services			836				767				69				767				1,197				(430	)
Other & eliminations			295				298				(3	)			298				279				19
Operating Income		$	28,114			$	23,332			$	4,782			$	23,332			$	21,921			$	1,411
Other Income			291				189				102				189				383				(194	)
Interest Charges			6,590				5,774				816				5,774				5,132				642
Income Taxes			8,597				6,999				1,598				6,999				6,472				527
Net Income from Continuing Operations		$	13,218			$	10,748			$	2,470			$	10,748			$	10,700			$	48

 

 

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2007 Compared to 2006

Compared to 2006, operating income in 2007 increased by $4.8 million, or 20 percent.  Factors affecting this improvement included the following:

·	New transportation capacity contracts implemented for the natural gas transmission operation in November 2006 and November 2007 provided for $3.3 million of additional gross margin in 2007.

·

Weather on the Delmarva Peninsula was 15 percent colder in 2007 than 2006, which the Company estimates contributed approximately $2.0 million in additional gross margin for its Delmarva natural gas and propane distribution operations.  This amount differs from the $2.2 million of additional gross margin that the Company had expected the colder weather to contribute.  The variance occurred as a result of the season or month that the heating degree day variance occurred.

·	Rate increases to customers of the natural gas transmission and distribution operations in Delaware and Maryland added $1.4 million to gross margin in 2007.

·	Strong period-over-period residential customer growth of seven percent and five percent, respectively, for the Delmarva and Florida natural gas distribution operations in 2007.

·	The average gross margin per retail gallon sold to customers increased $0.05 in 2007 for the Delmarva propane distribution operations, which contributed $1.1 million to gross margins.

·	The Delmarva Community Gas Systems continued to experience strong customer growth as the number of customers increased 22 percent in 2007 compared to 2006.

 

2006 Compared to 2005

Operating income in 2006 increased $1.4 million, or 6.5 percent, compared to 2005, despite significantly warmer weather in 2006. The improvement in 2006 results of operations compared to 2005 was affected by the following factors:

·	Weather on the Delmarva Peninsula was 18 percent warmer in 2006 than in 2005; as a result, the Company estimates that 2006 gross margin for its Delmarva natural gas and propane distribution operations was approximately $3.4 million less than in 2005.

·	Strong residential customer growth of nine percent and eight percent, respectively, for the Delmarva and Florida natural gas distribution operations in 2006.

·	The natural gas transmission operation achieved gross margin growth of $1.8 million, or 11 percent, due to additional capacity contracts that went into effect in November 2005 and November 2006.

·	A 67 percent increase in the number of customers for the Company’s natural gas marketing operation.

·	Gross margin for the Delmarva propane distribution operations decreased $834,000, primarily, as a result of the warmer weather in 2006.

·	The Delmarva Community Gas Systems continued to experience strong customer growth increasing by 34 percent in 2006 compared to 2005.

·

Operating income for the advanced information services segment decreased $430,000 in 2006. Although revenues from consulting increased $749,000 in 2006, the 2005 results contained $993,000 of operating income for the Lightweight Association Management Processing Systems (“LAMPSTM”) product, which was sold in the fourth quarter 2005.  The LAMPSTM product was an internally developed software that was developed and marketed specifically for REALTOR® Associations.

 

Natural Gas

The natural gas segment earned operating income of $22.5 million for 2007, $19.7 million for 2006, and $17.2 million for 2005, resulting in increases of $2.8 million, or 13.9 percent for 2007, and $2.5 million, or 14.5 percent, for 2006.

 

Natural Gas (in thousands)
										Increase												Increase
For the Years Ended December 31,		2007				2006				(decrease)				2006				2005				(decrease)
Revenue		$	181,202			$	170,374			$	10,828			$	170,374			$	166,582			$	3,792
Cost of gas			121,550				117,948				3,602				117,948				116,178				1,770
Gross margin			59,652				52,426				7,226				52,426				50,404				2,022
Operations & maintenance			26,024				22,673				3,351				22,673				23,874				(1,201	)
Depreciation & amortization			6,918				6,312				606				6,312				5,682				630
Other taxes			4,225				3,708				517				3,708				3,612				96
Other operating expenses			37,167				32,693				4,474				32,693				33,168				(475	)
Total Operating Income		$	22,485			$	19,733			$	2,752			$	19,733			$	17,236			$	2,497

 

Heating Degree-Day (HDD) and Customer Analysis
										Increase												Increase
For the Years Ended December 31,		2007				2006				(decrease)				2006				2005				(decrease)
Heating degree-day data — Delmarva
Actual HDD			4,504				3,931				573				3,931				4,792				(861	)
10-year average HDD			4,376				4,372				4				4,372				4,436				(64	)
Estimated gross margin per HDD		$	1,937			$	2,013			$	(76	)		$	2,013			$	2,234			$	(221	)
Estimated dollars per residential customer added:
Gross margin		$	372			$	372			$	0			$	372			$	372			$	0
Other operating expenses		$	106			$	111			$	(5	)		$	111			$	106			$	5
Average number of residential customers
Delmarva			43,485				40,535				2,950				40,535				37,346				3,189
Florida			13,250				12,663				587				12,663				11,717				946
Total			56,735				53,198				3,537				53,198				49,063				4,135

 

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2007 Compared to 2006

Gross margin for the Company’s natural gas segment increased by $7.2 million, or 14 percent, and other operating expenses increased $4.5 million, or 14 percent, for 2007 compared to 2006. The gross margin increases of $3.9 million for the natural gas transmission operation, $3.4 million for the Delmarva natural gas distribution operations, and $88,000 for the Florida natural gas distribution operation were partially offset by a lower gross margin of $207,000 for the natural gas marketing operation, as further explained below.

Natural Gas Transmission

The natural gas transmission operation achieved gross margin growth of $3.9 million, or 22 percent, in 2007 compared to 2006.  Of the $3.9 million increase, $3.3 million was attributable to new transportation capacity contracts implemented in November 2006 and 2007. In 2008, the new transportation capacity contracts implemented in November 2007 are expected to generate an additional annual gross margin of $1.2 million above 2007 gross margins.  In addition, the implementation of rate case settlement rates, effective September 1, 2007, contributed an additional $563,000 to gross margins in 2007.  A further discussion of the FERC rate proceeding is provided in detail within the “Regulatory Activities” listed later in this section.  The remaining $43,000 increase to gross margin in 2007 is attributable to other factors, such as higher interruptible sales.  An increase of $2.3 million in other operating expenses partially offset the increased gross margin. The factors contributing to the increase in other operating expenses are as follow:

·

Payroll and benefit costs increased by $282,000 and $90,000, respectively, as the operation increased its staffing levels to comply with new federal pipeline integrity regulations and to serve the additional growth.  The new pipeline integrity regulations require the Company to assess the integrity of each covered segment of its line pipe.  These regulations require the assessment of at least 50 percent of the covered segments by December 17, 2007 and completion of the baseline assessment of all covered segments by December 17, 2012.

·	Eastern Shore also incurred an additional $385,000 of third-party costs in 2007 compared to 2006 to comply with the new federal pipeline integrity regulations previously discussed.

·	The increased level of capital investment caused higher depreciation and asset removal costs of $371,000 and increased property taxes of $188,000.

·	Corporate costs increased $568,000 as the Company updated its annual corporate cost allocations based on a methodology accepted by the FERC.

·

The increase in operating expenses for 2007 is magnified by the FERC’s authorization, in July 2006, to defer certain pre-service costs of Eastern Shore’s E3 Project, allowing the Company to treat such costs as a regulatory asset. The deferral of these costs resulted in the reduction of $190,000 in other operating expenses in 2006 for expenses incurred in 2005. Please refer to the “Regulatory Activities” discussion below for further information on the E3 Project.

·	Other operating expenses relating to various items increased collectively by approximately $226,000.

 

Natural Gas Distribution

The Delmarva distribution operations experienced an increase in gross margin of $3.4 million, or 16 percent. The significant items contributing to the increase in gross margin include the following:

·

Continued residential customer growth contributed to the increase in gross margin. The average number of residential customers on the Delmarva Peninsula increased by 2,950, or seven percent, for 2007 compared to 2006, and the Company estimates that these additional residential customers contributed approximately $1.2 million to gross margin.  The Company does not expect to maintain the growth rate of residential customers, which it has experienced in the past few years.  The Company has seen a slow-down in the new housing market in 2007 as a result of unfavorable market conditions in the housing industry, which include: (a) increased new and resale home inventory levels, (b) decreased homebuyer demand due to lower consumer confidence in the overall housing market, (c) increased uncertainty in the overall mortgage market, and (d) increased underwriting standards.

·

Rate increases for both the Delaware and Maryland divisions generated an additional $848,000 in gross margin in 2007 compared to 2006.  In October 2006, the Maryland PSC granted the Company a base rate increase, which resulted in a $693,000 period-over-period increase to gross margin in 2007.  The Delaware Division received approval from the Delaware PSC to implement temporary rates, subject to refund, which contributed an additional $155,000 to gross margin in 2007.

·

The Company estimates that weather contributed $819,000 to gross margin in 2007 compared to 2006, as temperatures on the Delmarva Peninsula were 15 percent colder in 2007. This amount differs from the $1.1 million of additional gross margin that the Company had expected the colder weather to contribute.  This variance occurred as a result of the season or month that the heating degree day variance occurred.

·

The colder temperatures did not have a significant impact on the Maryland distribution operation’s gross margin in 2007, because the operation’s approved rate structure now includes a weather normalization adjustment (“WNA”) mechanism, which 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. The WNA also serves to offset the impact of colder-than-normal weather on our customers by reducing the amounts the Company can charge them during such periods.

·	Growth in commercial and industrial customers contributed $224,000 and $102,000, respectively, to gross margin in 2007 compared to 2006.

·	Increased sales volumes to interruptible customers contributed $224,000 to gross margin in 2007 compared to 2006.

·	The remaining $31,000 increase in gross margin can be attributed to various other factors.

Gross margin for the Florida distribution operation increased by $88,000, or one percent, in 2007 compared to 2006. The higher gross margin, which resulted from an increase in residential customers, was partially offset by lower volumes sold to industrial customers.  The operation experienced a five percent growth in residential customers in 2007 compared to 2006, which provided for an additional $142,000 in gross margin.  The Florida distribution operation also experienced a slowdown in the housing market in 2007 attributable to the same unfavorable housing market conditions previously discussed.

 

Other operating expense for the natural gas distribution operations increased by $2.0 million in 2007 compared 2006. Among the key components of the increase were the following:

·	Payroll costs increased by $110,000 as vacant positions in 2006 were filled in 2007 and additional positions were added to serve the growth experienced by the operations.

·	Health care costs increased by $177,000 as a result of the additional personnel and a higher cost of claims in 2007 compared to 2006.

·	Incentive compensation increased $229,000 in 2007 as the Delmarva operations experienced improved earnings and increased staffing levels.

·	Depreciation and amortization expense, asset removal cost and property taxes increased by $316,000, $121,000 and $156,000, respectively, as a result of the Company’s continued capital investments.

·	The Florida distribution operation experienced an increased expense of $227,000 in 2007 compared with 2006 to maintain compliance with the new federal pipeline integrity regulations.

·	Sales and advertising costs increased $129,000 in 2007 compared to 2006, primarily to promote energy conservation and customer awareness of the availability of natural gas service.

·	Regulatory expenses increased $113,000 as the Delaware and Maryland operations began expensing costs associated with their respective rate cases.

·	The allowance for uncollectible accounts increased $183,000 in 2007 compared to 2006 due to increased revenues resulting from customer growth and colder temperatures.

·	Merchant payment fees decreased by $116,000 as the Company’s Delmarva operation outsourced the processing of credit card payments in April 2007.

·	Other operating expenses relating to various other items increased by approximately $355,000.

Natural Gas Marketing

Gross margin for the natural gas marketing operation decreased by $207,000, or 11 percent, for 2007 compared to 2006. The decline in gross margin was primarily the result of increases in natural gas supply costs that the Company was contractually unable to pass through to its customers.  In addition, a shift in the market prevented the Company from selling as much of its available capacity in 2007 as was sold during 2006.  Other operating expenses for the marketing operation increased by $258,000 primarily due to increases in payroll and benefit costs, allowance for uncollectible accounts and corporate overhead costs, which were partially offset by lower expenses for consulting services.

 

 

2006 Compared to 2005

Gross margin for the Company’s natural gas segment increased $2.0 million, or 4 percent, and other operating expenses decreased $475,000, or 1 percent, in 2006 compared to 2005. The gross margin increases of $1.8 million for the natural gas transmission operation, $395,000 for the Florida natural gas distribution operation and $75,000 for the natural gas marketing operation were partially offset by a lower gross margin of $210,000 for the Delmarva natural gas distribution operations.

Natural Gas Transmission

The natural gas transmission operation achieved gross margin growth of $1.8 million, or 11 percent. Of the $1.8 million increase, $1.1 million was attributable to new transportation capacity contracts implemented in November 2005 and $612,000 due to new transportation capacity contracts implemented in November 2006.  An increase of $416,000 in other operating expenses partially offset the increased gross margin. The factors contributing to the increased expenses are as follow:

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·	Payroll costs and incentive compensation increased $108,000 to serve the additional growth experienced by the operation.

·	Depreciation and asset removal costs increased by $558,000 and property taxes by $109,000 due to an increase in the level of capital investment.

·

As a result of the operation receiving approval from the FERC to recover certain pre-service costs associated with the E3 Project, the Company deferred $188,000 of costs previously incurred and expensed in 2005.  As a result of this deferral, the amounts recognized in the Company’s income statement declined from 2005 by $376,000. Please refer to the “Regulatory Activities” discussion for further information on this expansion project.

·	Other operating expenses relating to various other items increased by approximately $17,000.

 

Natural Gas Distribution

Gross margin for the Florida distribution operation increased by $395,000 in 2006 compared to 2005. An eight percent growth in residential customers contributed $230,000 of this increase in gross margin. In addition to residential customer growth, new commercial and industrial customers contributed $91,000 to gross margin in 2006. The remaining $74,000 increase in gross margin is attributed to various factors, including turn-on revenue.

The Delmarva distribution operations experienced a decrease of $210,000 in gross margin. Weather significantly affected gross margin in 2006 compared to 2005.  The Company estimates that the warmer temperatures in 2006, which were 18 percent warmer than in 2005, led to a decrease in gross margin of approximately $1.7 million when compared to 2005. This decrease was partially offset by continued residential customer growth. The average number of residential customers on the Delmarva Peninsula increased 3,189, or 9 percent, for 2006 compared to 2005 and the Company estimates that additional residential customers contributed approximately $1.2 million to gross margin. The remaining $190,000 increase in gross margin can be attributed to various factors, including an increase in the number of commercial customers and a decrease in interruptible sales.

Other operating expense for the natural gas distribution operations decreased $814,000 in 2006 compared to 2005. Some of the significant components of the decrease in other operating expenses in 2006, compared to 2005, include the following:

·	Health care costs decreased by $313,000 as a result of the Company changing health care service providers in November 2005 and experiencing lower costs related to claims.

·	Allowance for uncollectible accounts decreased by $289,000 in 2006 compared to 2005 due to increased collection efforts and lower revenues resulting from lower prices and warmer temperatures.

·	Incentive compensation decreased by $177,000 in 2006, reflecting lower than expected earnings.

·	Corporate costs were reduced by $407,000 due to lower payroll and related expenses.

·	Depreciation and amortization expense and asset removal cost increased by $132,000 and $186,000, respectively, as a result of the Company’s continued capital investments.

·	Merchant payment fees increased by $136,000 in 2006 compared to 2005 as the Company experienced more customers making payments with the use of credit cards.

·	In addition, other operating expenses relating to various minor items increased by approximately $55,000.

Natural Gas Marketing

Gross margin for the natural gas marketing operation increased by $75,000 for 2006 compared to 2005. The increase was due primarily to growth in the number of customers to which the operation provided supply management services. Other operating expenses decreased by $78,000 due to lower levels of consulting services, partially offset by an increase in the allowance for uncollectible accounts.

Propane

The propane segment experienced an increase of $2.0 million, or 78 percent, in operating income in 2007 compared to 2006.  Gross margin increased $4.0 million, which was partially offset by an increase in other operating expenses of $2.0 million.  During 2006, operating income for the propane segment decreased by $675,000, or 21 percent, compared to 2005, reflecting a gross margin decrease of $1.1 million, which was partially offset by a decrease in operating expenses of $464,000.

 

Propane (in thousands)
										Increase												Increase
For the Years Ended December 31,		2007				2006				(decrease)				2006				2005				(decrease)
Revenue		$	62,838			$	48,576			$	14,262			$	48,576			$	48,976			$	(400	)
Cost of sales			41,038				30,780				10,258				30,780				30,041				739
Gross margin			21,800				17,796				4,004				17,796				18,935				(1,139	)
Operations & maintenance			14,594				12,823				1,771				12,823				13,355				(532	)
Depreciation & amortization			1,842				1,659				183				1,659				1,574				85
Other taxes			866				780				86				780				797				(17	)
Other operating expenses			17,302				15,262				2,040				15,262				15,726				(464	)
Total Operating Income		$	4,498			$	2,534			$	1,964			$	2,534			$	3,209			$	(675	)

 

Propane Heating Degree-Day (HDD) Analysis — Delmarva
										Increase												Increase
For the Years Ended December 31,		2007				2006				(decrease)				2006				2005				(decrease)
Heating degree-days
Actual			4,504				3,931				573				3,931				4,792				(861	)
10-year average			4,376				4,372				4				4,372				4,436				(64	)
Estimated gross margin per HDD		$	1,974			$	1,743			$	231			$	1,743			$	1,743			$	0

 

2007 Compared to 2006

Operating income for the propane segment increased by $2.0 million to $4.5 million for 2007 compared to 2006. Gross margin in the Delmarva propane distribution operations increased by $3.2 million, compared to 2006, primarily due to increases in retail margin per gallon and colder weather on the Delmarva Peninsula. Gross margin also increased in the Florida propane distribution operation and the Company’s wholesale propane marketing operation by $100,000 and $677,000, respectively.

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Delmarva Propane Distribution

The Delmarva propane distribution operation’s increase in gross margin of $3.2 million, or 22 percent, resulted from the following:

·

Gross margin increased by $1.1 million in 2007, compared to 2006, because of a $0.05 increase in the average gross margin per retail gallon. This increase occurs when market prices of propane are greater than the Company’s average inventory price per gallon. This trend reverses when market prices decrease and move closer to the Company’s inventory price per gallon.  Propane gross margin is also affected by changes in the Company’s pricing of sales to its customers.

·

Temperatures on the Delmarva Peninsula were 15 percent colder in 2007 compared to 2006, which contributed to the increase of 1.7 million retail gallons, or nine percent, sold during 2007. The Company estimates that the colder weather and increased volumes sold contributed $1.1 million to gross margin for the Delmarva propane distribution operation compared to 2006.

·

Non-weather related retail volumes sold in 2007 increased by 1.0 million gallons, or six percent.  This increase in gallons sold contributed approximately $665,000 to gross margin for the Delmarva propane distribution operation compared to 2006.  Contributing to the increase of gallons sold was the continued growth in the average number of CGS customers, which increased by 972 to a total count of 5,330, or a 22 percent increase, compared to 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 7,700 CGS customers, an increase of 145 percent.  With the slowdown in the housing market, however, the Company is unable to predict when construction of systems currently under contract will be completed and in service.

·	Wholesale volumes sold in 2007 increased by 2.9 million gallons, or 70 percent, which contributed approximately $119,000 to gross margin for the Delmarva propane distribution operation compared to 2006.

·	The remaining $216,000 increase in gross margin can be attributed to various other factors, including higher service sales and service fees.

 

Total other operating expenses increased by $1.5 million for the Delmarva propane operations in 2007, compared to the same period in 2006. The significant items contributing to this increase were:

·

Increased operating expenses for 2007 were magnified by the Company’s one-time recovery in 2006 of previously incurred costs of $387,000 from one of its propane suppliers in 2006. 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 nine months of 2006.

·	Incentive compensation increased by $361,000 as a result of the improved operating results in 2007 compared to 2006.

·	Health care costs increased by $119,000 during 2007 compared to the same period in 2006 as the Company experienced a higher cost of claims during the year.

·

The operation incurred an additional $233,000 expense in 2007 for propane tank recertifications and maintenance to maintain compliance with Department of Transportation (“DOT”) standards.  The DOT standards require propane tanks or cylinders to be recertified twelve years from their date of manufacture and every five years after that.

·	Mains fees increased by $100,000 in 2007 compared to 2006 as a result of added CGS customers.  This expenditure will continue to increase as more CGS customers are added.

·	Depreciation and amortization expense increased by $107,000 over the prior year as a result of the Company’s increased capital investments.

·	In addition, other operating expenses relating to various items increased collectively by approximately $193,000.

Florida Propane Distribution

The Florida propane distribution operation experienced an increase in gross margin of $100,000, or nine percent, in 2007 compared to 2006, primarily because of an increase in the average gross margin per retail gallon and higher service margins.  Other operating expenses in 2007, compared to 2006, increased by $223,000, primarily due to increases in payroll costs, insurance and depreciation expense.

 

Propane Wholesale and Marketing

Gross margin for the Company’s propane wholesale marketing operation increased by $677,000, or 40 percent, in 2007 compared to 2006. This increase reflects the larger number of market opportunities that arose in 2007, due to price volatility in the propane wholesale market, which exceeded the level of price fluctuations experienced in 2006. The increase in gross margin was partially offset by higher other operating expenses of $318,000, due primarily to higher incentive compensation based on the increased earnings in 2007.

2006 Compared to 2005

Operating income for the propane segment decreased $675,000, or 21 percent, to $2.5 million for 2006 compared to 2005. This decrease was due primarily to warmer weather on the Delmarva Peninsula in 2006, which resulted in reduced customer consumption. Gross margin in the Delmarva propane distribution operations was $834,000 lower than in 2005, primarily due to warmer weather in 2006. Gross margin also decreased in the Florida propane distribution operation and the Company’s wholesale propane marketing operation by $146,000 and $159,000, respectively.

Delmarva Propane Distribution

The Delmarva propane distribution operation’s decrease in gross margin of $834,000 resulted from the following factors:

·

Volumes sold in 2006 decreased 1.9 million gallons, or eight percent, due primarily to 18 percent warmer temperatures on the Delmarva Peninsula in 2006 than in 2005. The Company estimates that the warmer temperatures resulted in a decrease in gross margin of approximately $1.7 million when compared to 2005.

·	Gross margin increased by $956,000 due to an increase of three cents in the average gross margin per retail gallon in 2006 compared to 2005.

·	Gross margin for the Delmarva CGS activities increased by $155,000 compared to 2005 due primarily to an increase in the average number of customers, which grew by approximately 1,000 to a total count of approximately 3,900, or a 34 percent increase, compared to 2005.

·	Gross margin was adversely affected by a $272,000 write-down of propane inventory, reflecting the lower of cost or market.

·	The remaining gross margin decrease of $29,000 was attributable primarily to customer conservation and changes in the timing of deliveries to customers.

 

Other operating expenses decreased by $335,000 for the Delmarva operations in 2006 compared to 2005. The significant factors contributing to the decrease included:

·

The Company recovered $387,000 in fixed costs from one of its propane suppliers in response to a propane contamination incident that occurred in a previous period when approximately 75,000 gallons of propane that the Company purchased from the supplier contained above-normal levels of petroleum byproducts.

·	Health care costs decreased by $324,000. The Company changed health care service providers in November 2005 and subsequently experienced lower costs related to claims.

·	In addition, there was a decrease of approximately $39,000 in other operating expenses relating to various minor items.

·	These lower costs were partially offset by increased costs of $176,000 for one of the Pennsylvania start-ups, which began operation in July 2005, increased payroll costs of $165,000 and higher costs of $74,000 associated with vehicle fuel.

 

Florida Propane Distribution

In 2006, the Florida propane distribution operation experienced a decrease in gross margin of $146,000, or 12 percent, when compared to 2005. The lower gross margin reflected a decrease of $208,000 for in-house piping sales as the operation exited the house piping service, which was partially offset by an increase in gross margin of $62,000 from propane sales due primarily to an increase in the average gross margin per retail gallon, partially offset by a one percent decrease in the volumes sold in 2006. The Florida propane operation experienced a decrease of $49,000 in other operating expenses in 2006 compared to 2005, attributable to lower payroll and benefits costs related to vacant positions during the year, partially offset by higher expenses related to leak testing and depreciation expense.

 

Propane Wholesale and Marketing

Gross margin for the Company’s propane wholesale marketing operation decreased by $159,000 in 2006 compared to 2005. This decrease from the 2005 results reflects the increased market opportunities that arose in 2005 due to the extreme price volatility in the propane wholesale market following the hurricanes in the Gulf of Mexico area, but did not extend into 2006. The decrease in gross margin was partially offset by lower other operating expenses of $79,000 attributed primarily to lower incentive compensation as a result of lower earnings in 2006.

 

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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 contributed operating income of $836,000 for 2007, $767,000 for 2006, and $1.2 million for 2005.

 

Advanced Information Services (in thousands)
										Increase												Increase
For the Years Ended December 31,		2007				2006				(decrease)				2006				2005				(decrease)
Revenue		$	15,099			$	12,568			$	2,531			$	12,568			$	14,140			$	(1,572	)
Cost of sales			8,260				7,082				1,178				7,082				7,181				(99	)
Gross margin			6,839				5,486				1,353				5,486				6,959				(1,473	)
Operations & maintenance			5,225				4,119				1,106				4,119				5,129				(1,010	)
Depreciation & amortization			144				113				31				113				123				(10	)
Other taxes			634				487				147				487				510				(23	)
Other operating expenses			6,003				4,719				1,284				4,719				5,762				(1,043	)
Total Operating Income		$	836			$	767			$	69			$	767			$	1,197			$	(430	)

2007 Compared to 2006

The advanced information services business experienced gross margin growth of approximately $1.4 million, or 25 percent, and contributed operating income of $836,000 for 2007, an increase of $69,000, or nine percent, compared to 2006.

The period-over-period increase of gross margin resulted primarily from:

·	A strong demand for the segment’s consulting services in 2007 generated an increase of $1.9 million in consulting revenues as the number of billable hours increased by 15 percent; and

·	An increase of $276,000 from Managed Database Administration (“MDBA”) services, first offered in the first quarter of 2006, which provide clients with professional database monitoring and support solutions during business hours or around the clock.

Other operating expenses increased by $1.3 million to $6.0 million in 2007, compared to $4.7 million for 2006. This increase in operating expenses in 2007 is attributable to the following:

·

Payroll, incentive compensation and commissions, payroll taxes, benefit claims, and consulting expense accounted for $937,000 of the period-over-period increase.  These costs increased as a result of improved earnings and increased staffing levels to support the growth and customer demand experienced in 2007.

·	An increase in allowance for uncollectible accounts of $223,000 associated with a customer in the mortgage lending business that had filed for bankruptcy in the third quarter of 2007.

·	In addition, other operating expenses relating to various minor items increased by approximately $140,000.

 

2006 Compared to 2005

Operating income for the advanced information services segment decreased by $430,000 to $767,000 for 2006 compared to $1.2 million in 2005. The greater operating income in 2005 included $993,000 for the LAMPS™ product, which in turn included a $924,000 pre-tax gain on the sale of the product in October 2005 to Fidelity National Information Solutions, Inc., a subsidiary of Fidelity National Financial, Inc.

Revenues for the period decreased $1.6 million compared to 2005, due primarily to elimination of $1.9 million of revenue generated by the LAMPSTM product in 2005. Consulting revenues increased $749,000 in 2006 compared to 2005, primarily from offering MDBA services to its customers in 2006, which accounted for $740,000 of the increase, and an increase of 7.6 percent in the average hourly billing rate, while the number of billable hours remained at the same level attained in 2005.  Partially offsetting the increase in consulting revenues were decreases of $128,000 in training and product sales and $244,000 in other revenues.

Cost of sales for 2006 decreased by $99,000 to $7.08 million, compared to the 2005 cost of sales of $7.18 million, which included $401,000 related to LAMPSTM. After deducting the 2005 cost of sales associated with the LAMPSTM product, cost of sales increased in 2006 compared to 2005 to support the higher 2006 revenues.

 

Other operating expenses decreased $1.0 million in 2006 to $4.7 million compared to 2005. The reduction in expenses primarily reflects expenses of $554,000 in 2005 associated with LAMPSTM and lower benefits costs, rent expense and consulting costs.

Other Operations and Eliminations

Other operations consist primarily of subsidiaries that own real estate leased to other Company subsidiaries. Eliminations are entries required to eliminate activities between business segments from the consolidated results. Other operations and eliminating entries contributed operating income of $295,000 for 2007, $298,000 for 2006, and $279,000 for 2005.

 

Other Operations & Eliminations (in thousands)
										Increase												Increase
For the Years Ended December 31,		2007				2006				(decrease)				2006				2005				(decrease)
Revenue		$	622			$	618			$	4			$	618			$	618			$	0
Cost of sales			-				-				-				-				-				-
Gross margin			622				618				4				618				618				-
Operations & maintenance			109				96				13				96				67				29
Depreciation & amortization			160				163				(3	)			163				220				(57	)
Other taxes			62				65				(3	)			65				81				(16	)
Other operating expenses			331				324				7				324				368				(44	)
Operating Income — Other		$	291			$	294			$	(3	)		$	294			$	250			$	44
Operating Income — Eliminations		$	4				4			$	0			$	4				29			$	(25	)
Total Operating Income		$	295				298			$	(3	)		$	298				279			$	19

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Other Income

Other income for the years 2007, 2006, and 2005, respectively, was $291,000, $189,000, and $383,000, which include interest income, late fees charged to customers and gains or losses from the sale of assets.

 

Interest Expense

Total interest expense for 2007 increased approximately $816,000, or 14 percent, compared to 2006. The higher interest expense was a result of the following developments:

·	As the result of fewer capital projects in 2007 compared to 2006, the Company capitalized $469,000 less interest on debt in 2007 associated with ongoing capital projects.

·

The Company’s average long-term debt balance during 2007 was $76.5 million, with a weighted average interest rate of 6.71 percent, compared to $67.2 million, with a weighted average interest rate of 6.98 percent for 2006. The large year-over-year increase in the average long-term debt balance was the result of a debt placement of $20 million in 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).

·

The average short-term borrowing balance decreased by $6.3 million in 2007 to $20.6 million compared to an average balance of $26.9 million in 2006. The weighted average interest rates for short-term borrowing of 5.46 percent for 2007 and 5.47 percent for 2006, had minimum impact on the change in short-term borrowing expense.

Total interest expense for 2006 increased approximately $642,000, or 12.5 percent, compared to 2005. The increase reflected the following:

·

Average short-term debt balance and short-term interest rates both increased in 2006 compared to 2005. The average short-term borrowing balance increased by $21.2 million in 2006 to $26.9 million compared to $5.7 million in 2005 primarily to finance the $39.3 million of net property, plant, and equipment added in 2006.

·	The weighted average interest rate for short-term borrowing increased from 4.47 percent for 2005 to 5.47 percent for 2006.

·

The average long-term debt balance during 2006 was $67.2 million with a weighted average interest rate of 6.98 percent, compared to $67.4 million with a weighted average interest rate of 7.18 percent for 2005. The Company also capitalized $586,000 of interest as part of capital project costs during 2006.

 

Income Taxes

Income tax expense for 2007 was $8.6 million compared to $7.0 million for 2006. Income taxes increased in 2007 compared to 2006, due primarily to increased taxable income and income taxes increased in 2006 compared to 2005, again due to increased taxable income. The effective federal income tax rate for each of the three years 2007, 2006 and 2005 was 35 percent and the Company realized a benefit of $226,000, $220,000, and $223,000 in those years, respectively, resulting from a change in the tax law allowing tax deductions for dividends paid on Company stock held in Employee Stock Ownership Plans (“ESOP”).

Discontinued Operations

During the quarter ended September 30, 2007, Chesapeake decided to close its distributed energy services company, Chesapeake OnSight Services, LLC (“OnSight”), which experienced operating losses since its inception in 2004.  OnSight was previously reported as part of the Company’s Other Operations business segment.  At December 31, 2007, the results of operations for OnSight have been reclassified to discontinued operations and shown net of tax for all periods presented.  The discontinued operations experienced net losses of $20,000 for 2007, $241,000 for 2006 and $231,000 for 2005.

Liquidity and Capital Resources

Chesapeake’s capital requirements reflect the capital-intensive nature of its business and are principally attributable to investment in new plant and equipment and 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 2007, net cash provided by operating activities was $25.7 million, cash used by investing activities was $31.3 million and cash provided by financing activities was $3.7 million.

During 2006, net cash provided by operating activities was $30.1 million, cash used by investing activities was $48.9 million, and cash provided by financing activities was $20.7 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 December 31, 2007, Chesapeake had five unsecured bank lines of credit with three financial institutions, totaling $90.0 million, none of which requires compensating balances. These bank lines are available to provide funds for the Company’s short-term cash needs to meet seasonal working capital requirements and to fund temporarily portions of its capital expenditures. Three of the bank lines, totaling $25.0 million, are committed. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks.  The outstanding balance of short-term borrowing at December 31, 2007 and 2006 was $45.7 million and $27.6 million, respectively.  The level of short-term debt was reduced in 2006 with funds provided from the placement of $20 million of 5.5 percent Senior Notes in October 2006 and from the proceeds of the issuance of 600,300 shares of common stock in November 2006.

Chesapeake has budgeted $37.5 million for capital expenditures during 2008. This amount includes $17.0 million for natural gas distribution, $13.3 million for natural gas transmission, $5.9 million for propane distribution and wholesale marketing, $290,000 for advanced information services and $887,000 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, to acquire land for a future bulk storage facility, and to replace equipment. The advanced information services expenditures are for computer hardware, software and related equipment. The other category includes general plant, computer software and hardware.  The Company expects to fund the 2008 capital expenditures program 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 changing economic conditions, customer growth in existing areas, regulation, new growth opportunities, acquisition opportunities and availability of capital.

 

Capital Structure

The following presents our capitalization as of December 31, 2007 and 2006:

		December 31,
		2007								2006
		(In thousands, except percentages)
Long-term debt, net of current maturities		$	63,256				35	%		$	71,050				39	%
Stockholders' equity		$	119,576				65	%		$	111,152				61	%
Total capitalization, excluding short-term debt		$	182,832				100	%		$	182,202				100	%

 

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As of December 31, 2007, common equity represented 65 percent of total capitalization, compared to 61 percent at December 31, 2006.

The following presents our capitalization as of December 31, 2007 and 2006, if short-term borrowing and the current portion of long-term debt were included in capitalization:

 

		December 31,
		2007								2006
		(In thousands, except percentages)
Short-term debt		$	45,664				19	%		$	27,554				13	%
Long-term debt, including current maturities		$	70,912				30	%		$	78,706				36	%
Stockholders' equity		$	119,576				51	%		$	111,152				51	%
Total capitalization, including short-term debt		$	236,152				100	%		$	217,412				100	%

 

If short-term borrowing and the current portion of long-term debt were included in capitalization, total capitalization increased by $18.7 million in 2007 compared to 2006. The increased capitalization was primarily used to fund a portion of the $31.3 million of net property, plant, and equipment added in 2007 and for other general working capital. In addition, 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 51 percent at both December 31, 2007 and 2006.

Chesapeake remains committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access the capital markets when required. This commitment, along with adequate and timely rate relief for the Company’s regulated operations, is intended to ensure that Chesapeake will be able to attract capital from outside sources at a reasonable cost. The Company believes that the achievement of these objectives will provide benefits to customers and creditors, as well as its 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. In November 2006, we sold 600,300 shares of common stock, including the underwriter’s exercise of their over-allotment option of 90,045 shares, under this registration statement, generating net proceeds of $19.7 million. The net proceeds from the sale were used for general corporate purposes, including financing of capital expenditures, repayment of short-term debt, and funding working capital requirements. At December 31, 2007 and 2006, the Company had approximately $20.0 million remaining under this registration statement.

Cash Flows Provided by Operating Activities

Our cash flows provided by (used in) operating activities were as follows:

 

For the Years Ended December 31,		2007				2006				2005
Net income		$	13,197,710			$	10,506,525			$	10,467,614
Non-cash adjustments to net income			15,554,639				11,186,418				13,059,678
Changes in working capital			(3,070,465	)			8,424,055				(9,927,351	)
Net cash from operating activties		$	25,681,884			$	30,116,998			$	13,599,941

 

 Period-over-period changes in our cash flows from operating activities are attributable primarily to changes in net income and working capital. Changes in working capital are determined by a variety of factors, including 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.

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

In 2007, our net cash flow provided by operating activities was $25.7 million, a decrease of $4.4 million from 2006.  The 2007 operating cash flows reflect the favorable timing of payments for accounts payable and accrued liabilities, which increased operating cash flow by $22.1 million. In addition, increased net income and favorable non-cash adjustments, primarily depreciation expense, contributed to the increase in operating cash flow. Partially offsetting these increases in operating cash flow was an increase in accounts receivable of $28.2 million associated with increased revenues and the timing of invoicing by our propane wholesale and marketing operation.

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In 2006, our net cash flow provided by operating activities was $30.1 million, an increase of $16.5 million over 2005. This increase was primarily a result of the recovery during 2006 of working capital that was deployed in 2005 due to significantly higher commodity prices and the amount of working capital required for operations. Also, contributing to this increase was a reduction of $6.1 million in natural gas and propane purchased for inventory as a result of mild weather in the prior heating season and therefore higher inventory balances for the current heating season.

 

Cash Flows Used in Investing Activities

Net cash flows used in investing activities totaled $31.3 million, $48.9 million and $33.1 million during fiscal years 2007, 2006, and 2005, respectively.

·

Cash utilized for capital expenditures was $31.3 million, $48.9 million and $33.3 million for 2007, 2006, and 2005, respectively. Additions to property, plant and equipment in 2007 were primarily for natural gas transmission ($9.2 million), natural gas distribution ($15.2 million), propane distribution ($5.2 million), and other operations ($1.7 million).  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.

·	Sales of property, plant, and equipment generated $205,000 of cash in 2007.

·	The Company’s environmental expenditures exceeded amounts recovered through rates charged to customers in 2007 and 2006 by $228,000 and $16,000, respectively; in 2005, the Company recovered from its customers $240,000 in excess of its environmental expenditures for the period.

Cash Flows Provided by Financing Activities

Cash flows provided by financing activities totaled $3.7 million during 2007, $20.7 million during 2006, and $20.4 million during 2005. Significant financing activities included the following:

·	During 2007 and 2005, net borrowing of short-term debt increased by $18.7 million and $29.6 million, respectively, primarily to support our capital investments.  During 2006, the Company reduced it short-term debt by $8.0 million.

 

·	The Company repaid $7.7 million of long-term debt during 2007 compared with $4.9 million during 2006 and $4.8 million during 2005.

 

·

During 2007, the Company paid $7.0 million in cash dividends compared with dividend payments of $6.0 million and $5.8 million for 2006 and 2005, respectively. The increase in dividends paid in 2007 compared to 2006 reflects both growth in the annualized dividend rate, from $1.16 per share during 2006 to $1.18 per share during 2007, and the increase in shares outstanding following the issuance of additional shares of common stock in the fourth quarter of 2006.

 

·	In November 2006, the Company sold 600,300 shares of common stock, including the underwriter’s exercise of their over-allotment option of 90,045 shares, pursuant to a shelf registration statement declared effective in November 2006, generating net proceeds of $19.7 million.

 

·	In October 2006, the Company placed $20.0 million of 5.5 percent Senior Notes (“Notes”) to three institutional investors (The Prudential Insurance Company of America, Prudential Retirement Insurance and Annuity Company and United Omaha Life Insurance Company).

 

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

 

 

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Contractual Obligations

 

We have the following contractual obligations and other commercial commitments as of December 31, 2007:

		Payments Due by Period
Contractual Obligations		Less than 1 year				1 - 3 years				3 - 5 years				More than 5 years				Total
Long-term debt (1)		$	7,656,364			$	13,312,727			$	14,474,545			$	35,468,364			$	70,912,000
Operating leases (2)			790,801				1,211,720				1,166,800				2,252,714				5,422,035
Purchase obligations (3)
Transmission capacity			9,302,772				20,794,882				6,266,171				21,339,713				57,703,538
Storage — Natural Gas			1,553,175				4,210,670				3,015,217				1,838,948				10,618,010
Commodities			13,907,762				63,515				-				-				13,971,277
Forward purchase contracts  — Propane (4)			41,781,709				-				-				-				41,781,709
Unfunded benefits (5)			308,552				628,143				645,350				1,945,895				3,527,940
Funded benefits (6)			73,939				133,864				119,852				1,572,844				1,900,499
Total Contractual Obligations		$	75,375,074			$	40,355,521			$	25,687,935			$	64,418,478			$	205,837,008
(1) Principal payments on long-term debt, see Note H, "Long-Term Debt," in the Notes to the Consolidated Financial Statements for additional discussion of this item. The expected interest payments on long-term debt are $5.2 million, $8.8 million, $6.9 million and $10.0 million, respectively, for the periods indicated above. Expected interest payments for all periods total $ 30.9 million.
(2) See Note J, "Lease Obligations," in the Notes to the Consolidated Financial Statements for additional discussion of this item.
(3) See Note N, "Other Commitments and Contingencies," in the Notes to the Consolidated Financial Statements for further information.
(4) The Company has also entered into forward sale contracts. See "Market Risk" of the Management's Discussion and Analysis for further information.
(5) The Company has recorded long-term liabilities of $4.2 million at December 31, 2006 for unfunded post-retirement benefit plans. The amounts specified in the table are based on expected payments to current retirees and assumes a retirement age of 65 for currently active employees. There are many factors that would cause actual payments to differ from these amounts, including early retirement, future health care costs that differ from past experience and discount rates implicit in calculations.
(6) The Company has recorded long-term liabilities of $2.0 million at December 31, 2006 for funded benefits. These liabilities have been funded using a Rabbi Trust and an asset in the same amount is recorded under Investments on the Balance Sheet. The defined benefit pension plan was closed to new participants on January 1, 1999 and participants in the plan on that date were given the option to leave the plan. See Note K, "Employee Benefit Plans," in the Notes to the Consolidated Financial Statements for further information on the plan. Since the plan modification, no additional funding has been required from the Company and none is expected for the next five years, based on factors in effect at December 31, 2006. However, this is subject to change based on the actual return earned by the plan assets and other actuarial assumptions, such as the discount rate and long-term expected rate of return on plan assets.

 

Off-Balance Sheet Arrangements

The Company has issued corporate guarantees to certain vendors of its propane wholesale marketing subsidiary and its Florida natural gas supply management subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event either subsidiary’s default. Neither of these subsidiaries has ever defaulted in its obligations to pay its suppliers.  The liabilities for these purchases are recorded in the Consolidated Financial Statements when incurred. The aggregate amount guaranteed at December 31, 2007 was $24.2 million, with the guarantees expiring on various dates in 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 under the Company’s various insurance policies.  There have been no draws on this letter of credit as of December 31, 2007.

Regulatory Activities

The Company’s natural gas distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSCs; 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 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 (“2005 Proceeding”). While Chesapeake provides 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 eastern Sussex County targeted for growth by the State of Delaware. In April 2002, Governor Ruth Ann Minner established the Delaware Energy Task Force (“Task Force”), whose mission was to address the State’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 to enhance 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 broader number of prospective customers within eastern Sussex County supports the Task Force recommendation. As the Delaware division included these proposals in its base rate filing made on July 6, 2007, the Delaware division closed the 2005 Proceeding with the intent to continue discussions in the context of the 2007 base rate proceeding.

On September 1, 2006, the Company filed with the Delaware PSC its annual Gas Sales Service Rates (“GSR”) Application, seeking approval 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 disallowances and deferrals 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 among the parties resulting in a complete recovery of the Delaware division’s costs.  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 a program designed to benefit elderly, disabled, and low-income customers of the Delaware division.  In addition, 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.  The settlement also provides for the Delaware division to add $275,000 to the total GSR charges to be collected from customers effective for billings from November 1, 2008 through October 31, 2009.

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.

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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 would ensure 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.  On August 21, 2007, the Delaware PSC authorized the Company to implement charges reflecting the proposed $1,896,000 increase effective September 4, 2007 on a temporary basis and subject to refund, pending the completion of full evidentiary hearings and a final decision by the Delaware PSC.  The Delaware PSC Staff filed testimony recommending a rate decrease of $693,245.  The DPA recommended a rate decrease of $588,670.  Neither party recommended approval of the Delaware division’s other proposals mentioned above.  The Delaware division strongly disagrees with these positions and is currently in the process of drafting its rebuttal position which was filed on February 7, 2008.  The Delaware division anticipates a final decision by the Delaware PSC during the second quarter of 2008.

On September 10, 2007, the Company filed with the Delaware PSC its annual GSR Application, seeking the approval of the Delaware PSC to change its GSR rates effective for service rendered on and after November 1, 2007.  On October 2, 2007, 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 Delaware division anticipates a final decision by the Delaware PSC during the second or third quarter of 2008.

On November 1, 2007, 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, 2007. The Delaware PSC granted approval of the ER rate at its regularly scheduled meeting on November 20, 2007, subject to full evidentiary hearings and a final decision.  The Delaware division anticipates a final decision by the Delaware PSC during the first quarter of 2008.

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. On November 29, 2007 the Maryland PSC approved a settlement agreement for a rate decrease of $132,155, effective December 1, 2007 based on the change in the Company’s depreciation rates.

On December 17, 2007, 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, 2007.  No issues were raised at the hearing.  The Maryland division anticipates a final decision by the Maryland PSC during the first quarter of 2008.

 

Florida. On October 10, 2006, the Florida division filed with the Florida PSC a petition 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 went into effect on July 1, 2007.

 

On November 29, 2006, the Florida division filed with the Florida PSC a petition for authority to modify its energy conservation programs. In this petition, the Florida division sought approval to increase the cash allowances paid within its Residential Homebuilder Program and the Residential Appliance Replacement Program, and to expand the scope of its 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. On September 5, 2007, the Florida PSC issued its audit report in which less than $8,000, or one percent, of the 2006 expenditures were disallowed as non-conservation-related.  The results of the audit were incorporated into the calculation of the 2008 Energy Conservation Cost Recovery Factors, which were filed with the Florida PSC on September 13, 2007, approved on November 6, 2007, and became effective on January 1, 2008.

 

In compliance with the Florida Administrative Code, the Florida division filed its 2007 Depreciation Study (“Study”) with the Florida PSC on May 17, 2007. This study provides the Florida PSC with the opportunity to review and address changes in plant and equipment 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.  The Florida division responded to interrogatories concerning the Study on October 15 and December 24, 2007.  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 second quarter of 2008.

On July 6, 2007, the Company and Peoples Gas Service (“PGS”), another local gas distribution company in Florida, filed a joint petition for Commission action on a territorial agreement for portions of Pasco County, a Master Territorial Agreement and a Gas Transportation Agreement filed as a special contract.  PGS operates a natural gas distribution system in Pasco County but is unable to serve economically certain areas of the county.  The Company entered into negotiations with PGS that would allow the Company to serve these areas by connecting to PGS’ existing distribution system and to extend its facilities into these specific territories to serve primarily residential and commercial consumers.  The negotiations concluded with the execution of a Pasco County Territorial Agreement that provides the Company with two distinct areas as its territory and a Gas Transportation Agreement that specifies the terms, conditions and rates for transportation service across the PGS distribution system.  The Company and PGS have also entered into a Master Territorial Agreement that contains terms and conditions which will govern all existing and potential territorial agreements.  The Florida PSC approved these agreements at its October 9, 2007 agenda conference.

On August 27, 2007, PIPECO, filed with the Florida PSC its petition for approval of a natural gas transmission pipeline tariff in order to establish its operating rules and regulations.  The Florida PSC approved the petition at its December 4, 2007 agenda conference.

 

Eastern Shore. During 2007, FERC regulatory activity regarding the expansion of Eastern Shore’s transmission system included the following:

System Expansion 2006 – 2008   On January 20, 2006, Eastern Shore filed with the FERC an application for a Certificate of Public Convenience and Necessity for its 2006-2008 system expansion project (“the 2006 – 2008 Project”). 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 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 authorizing Eastern Shore to construct and operate the 2006 – 2008 Project as proposed. On November 1, 2006, Eastern Shore completed and placed in service the authorized Phase I facilities.

On July 24, 2007, Eastern Shore requested FERC authorization to commence construction of a portion (approximately 4 miles) of the Phase II facilities. Eastern Shore received the requested FERC authorization on August 11, 2007.  Facilities have been completed and were placed in service on November 1, 2007. These additional facilities provide for 8,300 Dts of additional firm capacity per day and annualized gross margin contribution of $1.2 million, instead of the amounts included in the original filing of 10,300 Dts of additional firm capacity per day and $1.5 million annualized gross margin contribution.

 

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On November 15, 2007 Eastern Shore requested FERC authorization to commence construction of Phase III facilities (approximately 9.2 miles). The FERC granted this authorization on January 7, 2008.  Construction activities are to begin in the first quarter of 2008 and are to be completed and placed in service on November 1, 2008. These Phase III facilities provide for 5,650 Dts of additional firm capacity per day and annualized gross margin contribution of approximately $1.0 million instead of the amounts included in the original filing of 10,850 Dts of additional firm capacity per day and $1.6 million annualized gross margin contribution.

Eastern Shore Energylink Expansion Project (“E3 Project”). In 2006, Eastern Shore proposed to develop, construct and operate approximately 75 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.  Both Chesapeake and Delmarva are parties to existing firm natural gas transportation service agreements with Eastern Shore, and each desires additional firm transportation service under the E3 Project, as evidenced by the Precedent Agreements. Pursuant to the Precedent Agreements, the parties agreed to proceed with the required initiatives to obtain the governmental and regulatory authorizations necessary for Eastern Shore to provide, and for Chesapeake and Delmarva to utilize, additional firm transportation service under the E3 Project.

As part of the Precedent Agreements, Eastern Shore, Chesapeake and Delmarva also entered into Letter Agreements which provide that, if 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, 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.

On April 23, 2007, Eastern Shore submitted to the FERC its request to commence a pre-filing process 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.  As part of this process, Eastern Shore has performed environmental, engineering and cultural surveys and studies in the interest of protecting the environment, minimizing any potential impacts to landowners, and cultural resources. Eastern Shore has also held meetings with federal, state and local permitting/regulatory agencies, non-governmental organizations, landowners, and other interested stakeholders.

As part of an updated engineering study, Eastern Shore received additional construction cost estimates for the E3 project, which indicated substantially higher costs than previously estimated. In an effort to optimize the feasibility of the overall project development plan, Eastern Shore explored all potential construction methods, construction cost mitigation strategies, potential design changes and project schedule changes.  Eastern Shore also held discussions and meetings with several potential new customers, who have expressed an interest in the project that would expand its size and likely have significant impact on the cost, timeline and in-service date.

On December 20, 2007, Eastern Shore withdrew from the pre-filing process as a result of insufficient customer commitments for capacity to make the project economical. Eastern Shore will continue to explore potential construction methods, construction cost mitigation strategies, additional market requests, and potential design changes in its efforts to improve the overall economics of the project.

If Eastern Shore decides to abandon the E3 Project, it will initiate billing of pre-certification costs surcharge in accordance with the terms of the Precedent Agreements executed with two of its customers, which provide for these customers to reimburse Eastern Shore for pre-certification costs incurred in connection with the E3 Project, up to a maximum amount of $2.0 million each over a period of 20 years.  As of December 31, 2007, the Company had incurred $2.97 million of pre-certification costs relating to the E3 Project.

 

During 2007, Eastern Shore also had developments in the following FERC rate matters:

On October 31, 2006, Eastern Shore filed a 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, reflected an annual increase of $5,589,000 in its annual operating revenues based on increases in operating and maintenance expenses, depreciation expense, taxes other than income taxes, and return on existing gas plant facilities and new facilities placed into service by March 31, 2007.

On November 30, 2006 the FERC issued an order suspending the effectiveness of Eastern Shore’s proposed rate increase until May 1, 2007, subject to refund and the outcome of the hearing established in the order. On December 19, 2006, the Presiding Administrative Law Judge (“ALJ”) approved a procedural schedule to govern further proceedings in this case.

Settlement conferences were held on April 17, May 30, and June 6, 2007 at the FERC’s offices in Washington, D.C. On May 14, 2007, Eastern Shore filed a motion, which the FERC granted, to make its suspended rate increase effective on May 15, 2007, subject to refund, pending the ultimate resolution of the rate case. At the June 6, 2007 conference, the parties reached a settlement agreement in principle, and on June 8, 2007, the Chief ALJ suspended the procedural schedule to allow time for the parties to draft a formal Stipulation and Agreement. The negotiated settlement provides for an annual cost of service of $21,536,000, which reflects a pretax return on equity of 13.6 percent and a rate increase of approximately $1.07 million on an annual basis. On September 10, 2007, Eastern Shore submitted its Settlement Offer to the Commission for the ALJ’s review and certification to the full Commission. There were no comments filed objecting to, or in protest of, the Settlement Offer.

Eastern Shore filed concurrently with its Settlement Agreement a Motion to place the settlement rates into effect on September 1, 2007, in order to expedite the implementation of the reduced settlement rates pending final approval of the settlement. The Commission issued an order on September 25, 2007, authorizing Eastern Shore to commence billing its settlement rates effective September 1, 2007.

On October 1, 2007, the Presiding ALJ forwarded to the full Commission an order certifying the uncontested Settlement Agreement as fair, reasonable, and in the public interest. A final Commission Order approving the settlement was issued on January 31, 2008.

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Environmental Matters

The Company continues to work with federal and state environmental agencies to assess the environmental impact and explore corrective action at three environmental sites (see Note M to the Consolidated Financial Statements). The Company believes that future costs associated with these sites will be recoverable in rates or through sharing arrangements with, or contributions by, other responsible parties.

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 (see Note H to the Consolidated Financial Statements for annual maturities of consolidated long-term debt). 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 $70.9 million at December 31, 2007, as compared to a fair value of $75.0 million, based mainly on current market prices or discounted cash flows, using current rates for similar issues with similar terms and remaining maturities. The Company evaluates whether to refinance existing debt or permanently refinance existing short-term borrowing, 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 entering into fixed price contracts for supply. The Company can store up to approximately four million gallons (including leased storage and rail cars) of propane during the winter season to meet its customers’ peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause the value of stored propane to decline. To mitigate the impact of price fluctuations, the Company has adopted a Risk Management Policy that allows the propane distribution operation to enter into fair value hedges of its inventory. Management reviewed the Company’s storage position as of December 31, 2007, and elected not to hedge any of its inventories.  At December 31, 2006, the propane distribution operation had entered into a swap agreement to protect the Company from the impact of price increases on the price-cap plan that we offer to customers. The Company considered this agreement to be an economic hedge that did not qualify for hedge accounting as described in SFAS 133. At the end of 2006, the market price of propane dropped below the unit price within the swap agreement. As a result of the price drop, the Company marked the agreement to market, which resulted in an unrealized loss of $84,000.  The Company did not enter into a similar agreement in 2007.

 

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 by 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 is 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 daily. 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 December 31, 2007 and 2006 is presented in the following tables.

 

At December 31, 2007		Quantity in gallons				Estimated Market Prices				Weighted Average Contract Prices
Forward Contracts
Sale		30,941,400				$0.8925 — $1.6025				$1.3555
Purchase		30,954,000				$0.8700 — $1.6000				$1.3498
Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expire in 2008.

 

Quantity

Estimated

Weighted Average

At December 31, 2006

in gallons

Market Prices

Contract Prices

Forward Contracts

Sale

13,797,000

$0.9250 — $1.2100

$1.0107

Purchase

13,733,800

$0.9250 — $1.2200

$1.0098

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

All contracts expired in 2007.

 

The Company’s natural gas distribution and marketing operations have entered into agreements with natural gas suppliers to purchase natural gas for resale to their customers. Purchases under these contracts either do not meet the definition of derivatives in SFAS No. 133 or are considered “normal purchases and sales” under SFAS No. 138 and are not marked to market.

 

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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 can use fuel oil as an alternative to natural gas. When oil prices decline, these interruptible customers may convert to oil to satisfy their fuel requirements. Lower levels of interruptible sales may 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 sides of this business to compete with the fluctuations in its customers’ alternative fuel prices. 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 bundled transportation and sales service to providing only transportation and contract storage services.

 

The Company’s natural gas distribution operations in Delaware, Maryland and Florida offer unbundled transportation services to certain commercial and industrial customers. In 2002, the Florida operation extended such service to residential customers. With such transportation service available on the Company’s distribution systems, the Company is competing with third-party suppliers to sell gas to industrial customers. With respect to unbundled transportation services, the Company’s competitors include interstate transmission companies, if the distribution customers are located close enough to a transmission company’s pipeline to make connections economically feasible. The customers at risk are usually large volume commercial and industrial customers with the financial resources and capability to bypass 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 such sales service in Delaware.

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 served by natural gas pipeline or distribution systems.

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

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 affect the markets for the products and services offered by these businesses. This segment competes on the basis of technological expertise, reputation and price.

Inflation

Inflation affects the cost of supply, labor, products and services required for operations, maintenance and capital improvements. While the impact of inflation has remained low in recent years, natural gas and propane prices are subject to rapid fluctuations. In the Company’s regulated natural gas distribution operations, 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 and closely monitors 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.

 

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Cautionary Statement

Chesapeake Utilities Corporation has made statements in this Form 10-K 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, inflation, and other matters. It is important to understand that these forward-looking statements are not guarantees, but are subject to certain risks and uncertainties and other important factors that could cause actual results to differ materially from those in the forward-looking statements. 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;

 

·	the 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 regulation 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 or below 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 to a degree that may impair future growth; and

 

·	operating and litigation risks that may not be covered by insurance.

 

 

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

 

Information concerning quantitative and qualitative disclosure about market risk is included in Item 7 under the heading “Management’s Discussion and Analysis — Market Risk.”

 

Item 8. Financial Statements and Supplementary Data.

 

Management’s Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, Chesapeake’s management conducted an evaluation of the effectiveness of its internal control over financial reporting based on the criteria established in a report entitled “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Chesapeake’s management has evaluated and concluded that Chesapeake’s internal control over financial reporting was effective as of December 31, 2007.

 

 

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Report of Independent Registered Public Accounting Firm

________

 

To the Board of Directors and

 

 

Stockholders of Chesapeake Utilities Corporation

 

 

 

 

We have audited the accompanying consolidated balance sheet of Chesapeake Utilities Corporation as of December 31, 2007, and the related consolidated statements of income, stockholders’ equity, comprehensive income, cash flows and income taxes for the year then ended. Chesapeake Utilities Corporation’s management is responsible for these consolidated financial statements. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

 

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

 

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Chesapeake Utilities Corporation and subsidiaries as of December 31, 2007 and the results of their operations and their cash flows for the year ended in conformity with accounting principles generally accepted in the United States of America.

 

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Chesapeake Utilities Corporation’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 10, 2008 expressed an unqualified opinion.

 

 

 

/s/ Beard Miller Company LLP

————————————————

Beard Miller Company LLP

Reading, Pennsylvania

March 10, 2008

 

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Report of Independent Registered Public Accounting Firm

________

To the Board of Directors and Stockholders

of Chesapeake Utilities Corporation

In our opinion, the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, comprehensive income, cash flows, stockholders’ equity and income taxes for each of the two years in the period ended December 31, 2006, before the effects of the adjustments to retrospectively reflect the discontinued operations described in Note B, present fairly, in all material respects, the financial position of Chesapeake Utilities Corporation and its subsidiaries at December 31, 2006, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America (the 2006 financial statements before the effects of the adjustments discussed in Note B are not presented herein).  In addition, in our opinion, the financial statement schedule for the each of the two years in the period ended December 31, 2006, presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements before the effects of the adjustments described above.  These financial statements and financial statement schedule are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.  We conducted our audits, before the effects of the adjustments described above, of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note K to the consolidated financial statements, the Company changed the manner in which it accounts for defined benefit pension and other postretirement plans, effective December 31, 2006.

We were not engaged to audit, review, or apply any procedures to the adjustments to retrospectively reflect the discontinued operations described in Note B and accordingly, we do not express an opinion or any other form of assurance about whether such adjustments are appropriate and have properly applied.  Those adjustments were audited by other auditors.

 

 

/s/ PricewaterhouseCoopers LLP

————————————————

PricewaterhouseCoopers LLP

Boston, MA

March 10, 2007

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Consolidated Statements of Income
  

For the Twelve Months Ended December 31,		2007				2006				2005
Operating Revenues		$	258,286,495			$	231,199,565			$	229,485,352
Operating Expenses
Cost of sales, excluding costs below			170,848,211				155,809,747			$	153,398,723
Operations			42,274,023				36,670,302				39,778,597
Maintenance			2,203,800				2,103,558				1,818,981
Depreciation and amortization			9,060,185				8,243,715			$	7,568,209
Other taxes			5,786,694				5,040,306			$	4,999,963
Total operating expenses			230,172,913				207,867,628				207,564,473
Operating Income			28,113,582				23,331,937				21,920,879
Other income, net of other expenses			291,305				189,093			$	382,610
Interest charges			6,589,639				5,773,993			$	5,132,458
Income Before Income Taxes			21,815,248				17,747,037				17,171,031
Income taxes			8,597,461				6,999,072				6,472,220
Income from Continuing Operations			13,217,787				10,747,965				10,698,811
Loss from discontinued operations, net of
tax benefit of $10,898, $162,510 and $160,204			(20,077	)			(241,440	)			(231,197	)
Net Income		$	13,197,710			$	10,506,525			$	10,467,614
Weighted Average Common Shares Outstanding:
Basic			6,743,041				6,032,462				5,836,463
Diluted			6,854,716				6,155,131				5,992,552
Earnings (Loss) Per Share of Common Stock:
Basic
From continuing operations		$	1.96			$	1.78			$	1.83
From discontinued operations			-			$	(0.04	)			(0.04	)
Net Income		$	1.96			$	1.74			$	1.79
Diluted
From continuing operations		$	1.94			$	1.76			$	1.81
From discontinued operations			-			$	(0.04	)			(0.04	)
Net Income		$	1.94			$	1.72			$	1.77

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

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Consolidated Statements of Cash Flows

 

For the Years Ended December 31,		2007				2006				2005
Operating Activities
Net Income		$	13,197,710			$	10,506,525			$	10,467,614
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization			9,060,185				8,243,715				7,568,209
Depreciation and accretion included in other costs			3,336,506				3,102,066				2,705,620
Deferred income taxes, net			1,831,030				(408,533	)			1,510,777
Gain on sale of assets			(204,882	)			-				-
Unrealized gain (loss) on commodity contracts			(170,465	)			37,110				(227,193	)
Unrealized loss on investments			(122,819	)			(151,952	)			(56,650	)
Employee benefits and compensation			1,825,028				382,608				1,621,607
Other, net			56				(18,596	)			(62,692	)
Changes in assets and liabilities:
Sale (purchase) of investments			229,125				(177,990	)			(1,242,563	)
Accounts receivable and accrued revenue			(28,189,132	)			9,705,860				(16,831,751	)
Propane inventory, storage gas and other inventory			1,193,336				354,764				(5,704,040	)
Regulatory assets			(344,680	)			2,498,954				(1,719,184	)
Prepaid expenses and other current assets			(1,188,481	)			(271,438	)			36,704
Other deferred charges			(2,477,879	)			(231,822	)			(102,561	)
Long-term receivables			83,653				137,101				247,600
Accounts payable and other accrued liabilities			22,130,049				(11,434,370	)			15,569,924
Income taxes receivable (payable)			(158,556	)			1,800,913				(2,006,762	)
Accrued interest			33,112				273,672				(42,376	)
Customer deposits and refunds			2,534,655				2,361,265				462,781
Accrued compensation			1,117,941				(542,512	)			875,342
Regulatory liabilities			2,124,091				2,824,068				144,501
Other liabilities			(157,699	)			1,125,590				385,034
Net cash provided by operating activities			25,681,884				30,116,998				13,599,941
Investing Activities
Property, plant and equipment expenditures			(31,277,390	)			(48,845,828	)			(33,319,613	)
Proceeds from sale of assets			204,882				-				-
Environmental recoveries (expenditures)			(227,979	)			(15,549	)			240,336
Net cash used by investing activities			(31,300,487	)			(48,861,377	)			(33,079,277	)
Financing Activities
Common stock dividends			(7,029,821	)			(5,982,531	)			(5,789,180	)
Issuance of stock for Dividend Reinvestment Plan			299,436				321,865				458,757
Stock issuance			-				19,698,509				-
Cash settlement of warrants			-				(434,782	)			-
Change in cash overdrafts due to outstanding checks			(541,052	)			49,047				874,083
Net borrowing (repayment) under line of credit agreements			18,651,055				(7,977,347	)			29,606,400
Proceeds from issuance of long-term debt			-				20,000,000				-
Repayment of long-term debt			(7,656,580	)			(4,929,674	)			(4,794,827	)
Net cash provided by financing activities			3,723,038				20,745,087				20,355,233
Net Increase (Decrease) in Cash and Cash Equivalents			(1,895,565	)			2,000,708				875,897
Cash and Cash Equivalents — Beginning of Period			4,488,366				2,487,658				1,611,761
Cash and Cash Equivalents — End of Period		$	2,592,801			$	4,488,366			$	2,487,658
Supplemental Disclosures of Non-Cash Investing Activities:
Capital property and equipment acquired on account,
but not paid as of December 31		$	365,890			$	1,490,890			$	1,367,348
Supplemental Disclosure of Cash Flow information
Cash paid for interest		$	5,592,279			$	5,334,477			$	5,052,013
Cash paid for income taxes		$	7,009,206			$	6,285,272			$	6,342,476

 

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

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Consolidated Balance Sheets

  

Assets		December 31, 2007				December 31, 2006
Property, Plant and Equipment
Natural gas		$	289,706,066			$	269,012,516
Propane			48,506,231				44,791,552
Advanced information services			1,157,808				1,054,368
Other plant			8,567,833				9,147,500
Total property, plant and equipment			347,937,938				324,005,936
Less:  Accumulated depreciation and amortization			(92,414,289	)			(85,010,472	)
Plus:  Construction work in progress			4,899,608				1,829,948
Net property, plant and equipment			260,423,257				240,825,412
Investments			1,909,271				2,015,577
Current Assets
Cash and cash equivalents			2,592,801				4,488,366
Accounts receivable (less allowance for uncollectible
accounts of $952,075 and $661,597, respectively)			72,218,191				44,969,182
Accrued revenue			5,265,474				4,325,351
Propane inventory, at average cost			7,629,295				7,187,035
Other inventory, at average cost			1,280,506				1,564,937
Regulatory assets			1,575,072				1,275,653
Storage gas prepayments			6,042,169				7,393,335
Income taxes receivable			1,237,438				1,078,882
Deferred income taxes			2,155,393				1,365,316
Prepaid expenses			3,496,517				2,280,900
Mark-to-market energy assets			7,812,456				1,379,896
Other current assets			146,253				173,388
Total current assets			111,451,565				77,482,241
Deferred Charges and Other Assets
Goodwill			674,451				674,451
Other intangible assets, net			178,073				191,878
Long-term receivables			740,680				824,333
Regulatory assets			2,539,235				1,765,088
Other deferred charges			3,640,480				1,215,004
Total deferred charges and other assets			7,772,919				4,670,754
Total Assets		$	381,557,012			$	324,993,984

 

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

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Consolidated Balance Sheets

 

Capitalization and Liabilities		December 31, 2007				December 31, 2006
Capitalization
Stockholders' equity
Common Stock, par value $0.4867 per share
(authorized 12,000,000 shares)		$	3,298,473			$	3,254,998
Additional paid-in capital			65,591,552				61,960,220
Retained earnings			51,538,194				46,270,884
Accumulated other comprehensive loss			(851,674	)			(334,550	)
Deferred compensation obligation			1,403,922				1,118,509
Treasury stock			(1,403,922	)			(1,118,509	)
Total stockholders' equity			119,576,545				111,151,552
Long-term debt, net of current maturities			63,255,636				71,050,000
Total capitalization			182,832,181				182,201,552
Current Liabilities
Current portion of long-term debt			7,656,364				7,656,364
Short-term borrowing			45,663,944				27,553,941
Accounts payable			54,893,071				33,870,552
Customer deposits and refunds			10,036,920				7,502,265
Accrued interest			865,504				832,392
Dividends payable			1,999,343				1,939,482
Accrued compensation			3,400,112				2,901,053
Regulatory liabilities			6,300,766				4,199,147
Mark-to-market energy liabilities			7,739,261				1,371,379
Other accrued liabilities			2,500,542				2,634,416
Total current liabilities			141,055,827				90,460,991
Deferred Credits and Other Liabilities
Deferred income taxes			28,795,885				26,517,098
Deferred investment tax credits			277,698				328,277
Regulatory liabilities			1,136,071				1,236,254
Environmental liabilities			835,143				211,581
Other pension and benefit costs			2,513,030				1,608,311
Accrued asset removal cost			20,249,948				18,410,992
Other liabilities			3,861,229				4,018,928
Total deferred credits and other liabilities			57,669,004				52,331,441
Other Commitments and Contingencies (Note N)
Total Capitalization and Liabilities		$	381,557,012			$	324,993,984

 

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

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Consolidated Statements of Stockholders’ Equity

   

For the Years Ended December 31,			2007				2006				2005
Common Stock
Balance — beginning of year			$	3,254,998			$	2,863,212			$	2,812,538
Dividend Reinvestment Plan				17,197				18,685				20,038
Retirement Savings Plan				14,388				14,457				10,255
Conversion of debentures				3,945				8,117				11,004
Performance shares and options exercised (1)				7,945				14,536				9,377
Stock issuance				-				335,991				-
Balance — end of year				3,298,473				3,254,998				2,863,212
Additional Paid-in Capital
Balance — beginning of year				61,960,220				39,619,849				36,854,717
Dividend Reinvestment Plan				1,121,190				1,148,100				1,224,874
Retirement Savings Plan				934,295				900,354				682,829
Conversion of debentures				133,839				275,300				373,259
Performance shares and options exercised (1)				498,674				887,426				484,170
Stock-based compensation				943,334				-				-
Stock issuance				-				19,362,518				-
Exercise warrants, net of tax				-				(233,327	)			-
Balance — end of year				65,591,552				61,960,220				39,619,849
Retained Earnings
Balance — beginning of year				46,270,884				42,854,894				39,015,087
Net income				13,197,710				10,506,525				10,467,614
Cash dividends (2)				(7,930,400	)			(7,090,535	)			(6,627,807	)
Balance — end of year				51,538,194				46,270,884				42,854,894
Accumulated Other Comprehensive Income (Loss)
Balance — beginning of year				(334,550	)			(578,151	)			(527,246	)
Minimum pension liability adjustment, net of tax				28,106				74,036				(50,905	)
Gain (Loss) on funded status of Employee Benefit Plans, net of tax				(545,230	)			169,565				-
Balance — end of year				(851,674	)			(334,550	)			(578,151	)
Deferred Compensation Obligation
Balance — beginning of year				1,118,509				794,535				816,044
New deferrals				285,413				323,974				130,426
Payout of deferred compensation				-				-				(151,935	)
Balance — end of year				1,403,922				1,118,509				794,535
Treasury Stock
Balance — beginning of year				(1,118,509	)			(797,156	)			(1,008,696	)
New deferrals related to compensation obligation				(285,413	)			(323,974	)			(130,426	)
Purchase of treasury stock				(29,771	)			(51,572	)			(182,292	)
Sale and distribution of treasury stock				29,771				54,193				524,258
Balance — end of year				(1,403,922	)			(1,118,509	)			(797,156	)
Total Stockholders’ Equity			$	119,576,545			$	111,151,552			$	84,757,183
(1) Includes amounts for shares issued for Directors' compensation.
(2) Cash dividends declared per share for 2007, 2006 and 2005 were $1.18, $1.16 and $1.14, respectively.
Consolidated Statements of Comprehensive Income
Net income			$	13,197,710			$	10,506,525			$	10,467,614
Pension adjustments, net of tax of
$342,320, ($48,889) and $33,615, respectively				(517,124	)			74,036				(50,905	)
Comprehensive Income			$	12,680,586			$	10,580,561			$	10,416,709

 

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

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Consolidated Statements of Income Taxes

      

For the Years Ended December 31,		2007				2006				2005
Current Income Tax Expense
Federal		$	5,512,071			$	5,994,296			$	3,687,800
State			1,223,145				1,424,485				789,233
Investment tax credit adjustments, net			(50,579	)			(54,816	)			(54,816	)
Total current income tax expense			6,684,637				7,363,965				4,422,217
Deferred Income Tax Expense (1)
Property, plant and equipment			2,958,758				1,697,024				1,380,628
Deferred gas costs			(629,228	)			(2,085,066	)			1,064,310
Pensions and other employee benefits			(9,154	)			(97,436	)			(340,987	)
Environmental expenditures			45,872				(5,580	)			(98,229	)
Other			(464,322	)			(36,345	)			(115,923	)
Total deferred income tax expense (benefit)			1,901,926				(527,403	)			1,889,799
Total Income Tax Expense		$	8,586,563			$	6,836,562			$	6,312,016
Reconciliation of Effective Income Tax Rates
Continuing Operations
Federal income tax expense (2)		$	7,635,336			$	6,212,237			$	6,009,861
State income taxes, net of federal benefit			1,086,680			$	829,630			$	732,046
Other			(124,555	)		$	(42,795	)		$	(269,687	)
Total continuing operations		$	8,597,461			$	6,999,072			$	6,472,220
Discontinued operations		$	(10,898	)		$	(162,510	)		$	(160,204	)
Total income tax expense		$	8,586,563			$	6,836,562			$	6,312,016
Effective income tax rate			39.4	%			39.4	%			37.6	%
At December 31,		2007				2006
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment		$	31,058,050			$	27,997,744
Environmental costs			250,021				204,149
Other			860,993				870,424
Total deferred income tax liabilities			32,169,064				29,072,317
Deferred income tax assets:
Pension and other employee benefits			2,581,853				2,225,944
Self insurance			384,009				468,922
Deferred gas costs			1,146,133				528,814
Other			1,416,577				696,855
Total deferred income tax assets			5,528,572				3,920,535
Deferred Income Taxes Per Consolidated Balance Sheet		$	26,640,492			$	25,151,782
(1) Includes $260,000, ($60,000), and $146,000 of deferred state income taxes for the years 2007, 2006, and 2005, respectively.
(2) Federal income taxes were recorded at 35% for each year represented.

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

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A. Summary of Accounting Policies

 

Nature of Business

Chesapeake is engaged in natural gas distribution to 62,852 customers located in central and southern Delaware, Maryland’s Eastern Shore and Florida. The Company’s natural gas transmission subsidiary operates an interstate pipeline from various points in Pennsylvania and northern Delaware to the Company’s Delaware and Maryland distribution divisions as well as other utility and industrial customers in Pennsylvania, Delaware and the Eastern Shore of Maryland. The Company’s propane distribution and wholesale marketing segment provides distribution service to 34,143 customers in central and southern Delaware, the Eastern Shore of Maryland, southeastern Pennsylvania, central Florida and the Eastern Shore of Virginia and markets propane to wholesale customers including large independent oil and petrochemical companies, resellers and propane distribution companies in the southeastern United States. 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.

Principles of Consolidation

The Consolidated Financial Statements include the accounts of the Company and its wholly owned subsidiaries. The Company does not have any ownership interests in investments accounted for using the equity method or any variable interests in a variable interest entity. All intercompany transactions have been eliminated in consolidation.

System of Accounts

The natural gas distribution divisions of the Company located in Delaware, Maryland and Florida are subject to regulation by their respective PSCs with respect to their rates for service, maintenance of their accounting records and various other matters. Eastern Shore is an open access pipeline and is subject to regulation by the FERC. Our financial statements are prepared in accordance with GAAP, which give appropriate recognition to the ratemaking and accounting practices and policies of the various commissions. The propane, advanced information services and other business segments are not subject to regulation with respect to rates or maintenance of accounting records.

 

Property, Plant, Equipment and Depreciation

Utility and non-utility property is stated at original cost. Costs include direct labor, materials and third-party construction contractor costs, allowance for capitalized interest and certain indirect costs related to equipment and employees engaged in construction.  The costs of repairs and minor replacements are charged against income as incurred, and the costs of major renewals and betterments are capitalized. Upon retirement or disposition of non-utility property, the gain or loss, net of salvage value, is charged to income. Upon retirement or disposition of utility property, the gain or loss, net of salvage value, is charged to accumulated depreciation. The provision for depreciation is computed using the straight-line method at rates that amortize the unrecovered cost of depreciable property over the estimated remaining useful life of the asset. Depreciation and amortization expenses are provided at an annual rate for each segment. The three-year average rates were three percent for natural gas distribution and transmission, five percent for propane, eleven percent for advanced information services and six percent for general plant.

 

 

At December 31,	2007	2006	Useful Life (1)
Plant in service
Mains	$166,202,413	$151,890,304	27-41 years
Services — utility	35,127,633	32,334,145	14-33 years
Compressor station equipment	24,959,330	24,921,976	28 years
Liquefied petroleum gas equipment	25,575,213	24,627,398	30-33 years
Meters and meter installations	18,111,466	16,093,737	Propane 10-33 years, Natural gas 26-44 years
Measuring and regulating station equipment	14,067,262	13,272,201	27-54 years
Office furniture and equipment	9,947,881	10,114,101	Non-regulated 3-10 years, Regulated 14-28 years
Transportation equipment	11,194,916	10,686,259	3-11 years
Structures and improvements	10,024,105	9,538,345	10-44 years (2)
Land and land rights	7,404,679	7,386,268	Not depreciable, except certain regulated assets
Propane bulk plants and tanks	5,313,061	5,301,457	15 - 40 years
Various	20,009,979	17,839,745	Various
Total plant in service	347,937,938	324,005,936
Plus construction work in progress	4,899,608	1,829,948
Less accumulated depreciation	(92,414,289)	(85,010,472)
Net property, plant and equipment	$260,423,257	$240,825,412
(1) Certain immaterial account balances may fall outside this range.
The regulated operations compute depreciation in accordance with rates approved by either the state Public Service Commission
or the FERC. These rates are based on depreciation studies and may change periodically upon receiving approval from the
appropriate regulatory body. The depreciation rates shown above are based on the remaining useful lives of the assets at the
time of the depreciation study, rather than their original lives. The depreciation rates are composite, straight-line rates applied
to the average investment for each class of depreciable property and are adjusted for anticipated cost of removal less salvage
value.
The non-regulated operations compute depreciation using the straight-line method over the estimated useful life of the asset.
(2) Includes buildings, structures used in connection with natural gas and propane operations, improvements to those facilities
and leasehold improvements.

 

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Cash and Cash Equivalents

The Company’s policy is to invest cash in excess of operating requirements in overnight income-producing accounts. Such amounts are stated at cost, which approximates market value. Investments with an original maturity of three months or less when purchased are considered cash equivalents.

Inventories

The Company uses the average cost method to value propane and materials and supplies inventory. If market prices drop below cost, inventory balances that are subject to price risk are adjusted to market values.

Regulatory Assets, Liabilities and Expenditures

The Company accounts for its regulated operations in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” This standard includes accounting principles for companies whose rates are determined by independent third-party regulators. When setting rates, regulators often make decisions, the economics of which require companies to defer costs or revenues in different periods than may be appropriate for unregulated enterprises. When this situation occurs, the regulated utility defers the associated costs as assets (regulatory assets) on the balance sheet and records them as expense on the income statement as it collects revenues. Further, regulators can also impose liabilities upon a company for amounts previously collected from customers, and for recovery of costs that are expected to be incurred in the future (regulatory liabilities).

At December 31, 2007 and 2006, the regulated utility operations had recorded the following regulatory assets and liabilities on the Balance Sheets. These assets and liabilities will be recognized as revenues and expenses in future periods as they are reflected in customers’ rates.

    

At December 31,		2007				2006
Regulatory Assets
Current
Underrecovered purchased gas costs		$	1,389,454			$	1,076,921
Conservation cost recovery			-				51,408
PSC Assessment			22,290				22,290
Flex rate asset			107,394				81,926
Other			55,934				43,108
Total current			1,575,072				1,275,653
Non-Current
Income tax related amounts due from customers			1,115,638				1,300,544
Deferred regulatory and other expenses			446,642				188,686
Deferred gas supply			15,201				15,201
Deferred post retirement benefits			111,159				138,949
Environmental regulatory assets and expenditures			850,594				121,708
Total non-current			2,539,234				1,765,088
Total Regulatory Assets		$	4,114,306			$	3,040,741
Regulatory Liabilities
Current
Self insurance — current		$	191,004			$	568,897
Overrecovered purchased gas costs			4,225,845				2,351,553
Shared interruptible margins			11,202				100,355
Conservation cost recovery			395,379				-
Operational flow order penalties			-				7,831
Swing transportation imbalances			1,477,336				1,170,511
Total current			6,300,766				4,199,147
Non-Current
Self insurance — long-term			757,557				600,787
Income tax related amounts due to customers			151,521				285,819
Environmental overcollections			226,993				349,648
Total non-current			1,136,071				1,236,254
Accrued asset removal cost			20,249,948				18,410,992
Total Regulatory Liabilities		$	27,686,785			$	23,846,393

 

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Included in the regulatory assets listed above are $107,000 of which is accruing interest. Of the remaining regulatory assets, $2.6 million will be collected in approximately one to two years, $293,000 will be collected within approximately 3 to 10 years, and $721,000 will be collected within approximately 11 to 15 years.  In addition, there is approximately $466,000 for which the Company is awaiting regulatory approval for recovery, but once approved is expected to be collected within 12 months.

As required by SFAS No. 71, the Company monitors its regulatory and competitive environment to determine whether the recovery of its regulatory assets continues to be probable. If the Company were to determine that recovery of these assets is no longer probable, it would write off the assets against earnings. The Company believes that SFAS No. 71 continues to apply to its regulated operations, and that the recovery of its regulatory assets is probable.

Goodwill and Other Intangible Assets

The Company accounts for its goodwill and other intangibles under SFAS No. 142, “Goodwill and Other Intangible Assets.” Under SFAS No. 142, goodwill is not amortized but is tested for impairment at least annually. In addition, goodwill of a reporting unit is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives. Please refer to Note F “Goodwill and Other Intangible Assets” for additional discussions of this subject.

Other Deferred Charges

Other deferred charges include discount, premium and issuance costs associated with long-term debt. Debt costs are deferred and then are amortized to interest expense over the original lives of the respective debt issuances.

Income Taxes and Investment Tax Credit Adjustments

The Company files a consolidated federal income tax return. Income tax expense allocated to the Company’s subsidiaries is based upon their respective taxable incomes and tax credits.

Deferred tax assets and liabilities are recorded for the tax effect of temporary differences between the financial statements bases and tax bases of assets and liabilities and are measured using the enacted tax rates in effect in the years in which the differences are expected to reverse.  The portions of the Company’s deferred tax liabilities applicable to utility operations, which have not been reflected in current service rates, represent income taxes recoverable through future rates. Deferred tax assets are recorded net of any valuation allowance when it is more likely than not that such tax benefits will be realized.  Investment tax credits on utility property have been deferred and are allocated to income ratably over the lives of the subject property.

The Company adopted the provisions of FIN 48 “Accounting for Uncertainty in Income Taxes,” effective January 1, 2007.  FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a Company’s financial statements in accordance with SFAS 109 “Accounting for Income Taxes.”  FIN 48 requires that an uncertain tax position should be recognized only if it is “more likely than not” that the position is sustainable based on technical merits.  Recognizable tax positions should then be measured to determine the amount of benefit recognized in the financial statements.  The Company’s adoption of FIN 48 did not have an impact on its financial condition or results of operations.

Financial Instruments

Xeron, Inc. (“Xeron”), the Company’s propane wholesale marketing operation, engages in trading activities using forward and futures contracts, which have been accounted for using the mark-to-market method of accounting. Under mark-to-market accounting, the Company’s trading contracts are recorded at fair value, net of future servicing costs. The changes in market price are recognized as gains or losses in revenues on the income statement in the period of change. The resulting unrealized gains and losses are recorded as assets or liabilities, respectively. There were unrealized gains of $179,000 and $8,500 at December 31, 2007 and 2006, respectively. Trading liabilities are recorded in mark-to-market energy liabilities. Trading assets are recorded in mark-to-market energy assets.

 

The Company’s natural gas and propane distribution operations have entered into agreements with natural gas and propane suppliers to purchase gas for resale to their customers. Purchases under these contracts either do not meet the definition of derivatives of SFAS No. 133 or are considered “normal purchases and sales” under SFAS No. 138 and are accounted for on an accrual basis.

The propane distribution operation may enter into a fair value hedge of its inventory in order to mitigate the impact of wholesale price fluctuations. At December 31, 2007, the Company decided not to hedge any of its propane inventories.  At December 31, 2006, the propane distribution operation had entered into a swap agreement to protect the Company from the impact of price increases on the price-cap plan that we offer to customers. The Company considered this agreement to be an economic hedge that did not qualify for hedge accounting as described in SFAS 133. At the end of the 2006, the market price of propane dropped below the unit price within the swap agreement. As a result of the price drop, the Company marked the agreement to market, which resulted in an unrealized loss of $84,000.

 

Earnings Per Share

Chesapeake calculates earnings per share in accordance with SFAS 128 “Earnings per Share.”  The calculations of both basic and diluted earnings per share are presented in the following chart.

   

For the Periods Ended December 31,		2007				2006				2005
Calculation of Basic Earnings Per Share:
Net Income		$	13,197,710			$	10,506,525			$	10,467,614
Weighted average shares outstanding			6,743,041				6,032,462				5,836,463
Basic Earnings Per Share		$	1.96			$	1.74			$	1.79
Calculation of Diluted Earnings  Per Share:
Reconciliation of Numerator:
Net Income		$	13,197,710			$	10,506,525			$	10,467,614
Effect of 8.25% Convertible debentures			95,611				105,024				123,559
Adjusted numerator — Diluted		$	13,293,321			$	10,611,549			$	10,591,173
Reconciliation of Denominator:
Weighted shares outstanding — Basic			6,743,041				6,032,462				5,836,463
Effect of dilutive securities
Warrants			-				-				11,711
8.25% Convertible debentures			111,675				122,669				144,378
Adjusted denominator — Diluted			6,854,716				6,155,131				5,992,552
Diluted Earnings  Per Share		$	1.94			$	1.72			$	1.77

 

 

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Operating Revenues

Revenues for the natural gas distribution operations of the Company are based on rates approved by the PSCs of the jurisdictions in which we operate. The natural gas transmission operation’s revenues are based on rates approved by the FERC. Customers’ base rates may not be changed without formal approval by these commissions. However, the regulatory authorities have granted the Company’s regulated natural gas distribution operations the ability to negotiate rates, based on approved methodologies, with customers that have competitive alternatives. In addition, the natural gas transmission operation can negotiate rates above or below the FERC-approved tariff rates.

 

For regulated deliveries of natural gas, Chesapeake reads meters and bills customers on monthly cycles that do not coincide with the accounting periods used for financial reporting purposes. Chesapeake accrues unbilled revenues for gas that has been delivered, but not yet billed at the end of an accounting period to the extent that they do not coincide. In connection with this accrual, Chesapeake must estimate the amount of gas that has not been accounted for on its delivery system and must estimate the amount of the unbilled revenue by jurisdiction and customer class. A similar computation is made to accrue unbilled revenues for propane customers with meters, such as community gas system customers.

The propane wholesale marketing operation records trading activity, on a net mark-to-market basis in the Company’s income statement, for open contracts. The propane distribution, advanced information services and other segments record revenue in the period the products are delivered and/or services are rendered.

Chesapeake’s natural gas distribution operations in Delaware and Maryland each have a purchased gas cost recovery mechanism.  This mechanism provides the Company with a method of adjusting the billing rates with its customers for changes in the cost of purchased gas included in base rates. The difference between the current cost of gas purchased and the cost of gas recovered in billed rates is deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers. Generally, these deferred amounts are recovered or refunded within one year.

The Company charges flexible rates to the natural gas distribution’s industrial interruptible customers to make them competitive with alternative types of fuel. Based on pricing, these customers can choose natural gas or alternative fuels. Neither the Company nor the interruptible customer is contractually obligated to deliver or receive natural gas.

Allowance for Doubtful Accounts

An allowance for doubtful accounts is recorded against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect based upon our collections experiences and our assessment of our customers’ inability or reluctance to pay. If circumstances change, however, our estimate of the recoverability of accounts receivable may also change. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices and general economic conditions. Accounts are written off once they are deemed to be uncollectible.

Certain Risks and Uncertainties

The Company’s financial statements are prepared in conformity with generally accepted accounting principles that require management to make estimates in measuring assets and liabilities and related revenues and expenses (see Notes M and N to the Consolidated Financial Statements for significant estimates). These estimates involve judgments with respect to, among other things, various future economic factors that are difficult to predict and are beyond the control of the Company; therefore, actual results could differ from those estimates.

The Company records certain assets and liabilities in accordance with SFAS No. 71. If the Company were required to terminate application of SFAS No. 71 for its regulated operations, all such deferred amounts would be recognized in the income statement at that time. This could result in a charge to earnings, net of applicable income taxes, which could be material.

 

FASB Statements and Other Authoritative Pronouncements

In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation (“FIN”) No. 48, “Employers’ Accounting for Uncertainty in Income Taxes.” This interpretation: (i) 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;” (ii) 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; and (iii) provides guidance on derecognition and classification of uncertain tax positions, reporting of interest and penalties, accounting in interim periods, disclosure, and transition.  FIN No.48 is effective for fiscal years beginning after December 15, 2006, and Chesapeake’s adoption of it in the first quarter of 2007 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. Since SFAS No. 157 is effective for financial statements issued within fiscal years beginning after November 15, 2007, Chesapeake will be required to adopt this statement in the first quarter of 2008. The Company does not expect SFAS No. 157 will have a material impact 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 measure at fair value many financial instruments and certain other items 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 does not expect SFAS No. 159 will have a material impact 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 does not expect FSP FIN 39-1 will have a material impact its Consolidated Financial Statements.

Reclassification of Prior Years’ Amounts

The Company reclassified some previously reported amounts to conform to current period classifications.

 

* Management contract or compensatory plan or agreement.

 

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Signatures

 

Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, Chesapeake Utilities Corporation has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Chesapeake Utilities Corporation

By:         /s/ John R. Schimkaitis

  John R. Schimkaitis

  President and Chief Executive Officer

              Date:  March 10, 2008

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

/s/  Ralph J. Adkins                                                                        /s/  John R. Schimkaitis

Ralph J. Adkins, Chairman of the Board                                      John R. Schimkaitis, President,

and Director                                                                                     Chief Executive Officer and Director

Date:  February 20, 2008                                                                 Date:  March 10, 2008

/s/  Michael P. McMasters                                                        /s/  Richard Bernstein

Michael P. McMasters, Senior Vice President                           Richard Bernstein, Director

and Chief Financial Officer                                                            Date:  February 20, 2008

(Principal Financial and Accounting Officer)

Date:  March 10, 2008

/s/  Eugene H. Bayard                                                                   /s/  Thomas J. Bresnan

Eugene H. Bayard, Director                                                           Thomas J. Bresnan, Director

Date:  February 20, 2008                                                                 Date:  March 10, 2008

/s/  Thomas P. Hill, Jr.                                                                  /s/  Walter J. Coleman

Thomas P. Hill, Jr., Director                                                            Walter J. Coleman, Director

Date:  February 20, 2008                                                                  Date:  February 20, 2008

/s/  J. Peter Martin                                                                        /s/  Joseph E. Moore, Esq.

J. Peter Martin, Director                                                                   Joseph E. Moore, Esq., Director

Date:  February 20, 2008                                                                   Date:  February 20, 2008

/s/  Calvert A. Morgan, Jr.

Calvert A. Morgan, Jr., Director

Date:  February 20, 2008

 

 

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Report of Independent Registered Public Accounting Firm

________

 

 

 

To the Board of Directors and

 

 

Stockholders of Chesapeake Utilities Corporation

 

 

 

 

The audit referred to in our report dated March 10, 2008 relating to the consolidated financial statements of Chesapeake Utilities Corporation as of December 31, 2007 and for the year then ended, which is contained in Item 8 of this Form 10-K also included the audit of the financial statement schedules listed in Item 15.  These financial statement schedules are the responsibility of the Chesapeake Utilities Corporation’s management.  Our responsibility is to express an opinion on these financial statement schedules based on our audit.

 

In our opinion such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

/s/ Beard Miller Company LLP

————————————————

Beard Miller Company LLP

Reading, Pennsylvania

March 10, 2008

 

 

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Chesapeake Utilities Corporation and Subsidiaries
Schedule II
Valuation and Qualifying Accounts
						Additions
For the Year Ended December 31,		Balance at Beginning of Year				Charged to Income				Other Accounts (1)				Deductions (2)				Balance at End of Year
Reserve Deducted From Related Assets
Reserve for Uncollectible Accounts
2007		$	661,597			$	818,561			$	26,190			$	(554,273	)		$	952,075
2006		$	861,378			$	381,424			$	65,519			$	(646,724	)		$	661,597
2005		$	610,819			$	632,644			$	158,409			$	(540,494	)		$	861,378
(1)  Recoveries.
(2) Uncollectible accounts charged off.

 

 

 

 

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Upon written request, Chesapeake will provide, free of charge, a copy of any exhibit to the 2007 Annual Report on Form 10-K not included in this document.

 

 

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