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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM 10-Q

 

 

 

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

For the quarterly period ended: March 31, 2012

OR

 

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

For the transition period from             to             

Commission File Number: 001-11590

 

 

CHESAPEAKE UTILITIES CORPORATION

(Exact name of registrant as specified in its charter)

 

 

 

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

909 Silver Lake Boulevard, Dover, Delaware 19904

(Address of principal executive offices, including Zip Code)

(302) 734-6799

(Registrant’s telephone number, including area code)

 

 

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

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

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

 

Large accelerated filer		¨		Accelerated filer		x
Non-accelerated filer		¨		Smaller reporting company		¨

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

Common Stock, par value $0.4867 — 9,578,716 shares outstanding as of April 30, 2012.

 

 

 

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PART I — FINANCIAL INFORMATION			1
ITEM 1. FINANCIAL STATEMENTS			1
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			27
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			42
ITEM 4. CONTROLS AND PROCEDURES			44
PART II — OTHER INFORMATION			45
ITEM 1. LEGAL PROCEEDINGS			45
ITEM 1A. RISK FACTORS			45
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			45
ITEM 3. DEFAULTS UPON SENIOR SECURITIES			45
ITEM 4. MINE SAFETY DISCLOSURES			45
ITEM 5. OTHER INFORMATION			46
ITEM 6. EXHIBITS			46
SIGNATURES			46

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GLOSSARY OF KEY TERMS AND DEFINITIONS

Accounting Principles Generally Accepted in the United States of America (GAAP): A standard framework of accounting rules used to prepare and present financial statements in the United States of America.

Acquisition adjustment: The recovery, through rates, and inclusion in rate base, of the premium (amount in excess of net book value) paid for an acquisition as approved by the state PSCs for the regulated operations.

BravePoint^®, Inc. (BravePoint): An advanced information services subsidiary, headquartered in Norcross, Georgia. BravePoint is a wholly owned subsidiary of Chesapeake Services Company, which is a wholly owned subsidiary of Chesapeake.

Chesapeake Utilities Corporation (Chesapeake or the Company): The Registrant, its divisions, the Registrant and its subsidiaries, or the Registrant’s subsidiaries, as appropriate in the context of the disclosure.

Come-Back filing: The regulatory filing that was required by the Florida PSC within 18 months of the completion of the FPU merger to detail known benefits, synergies, cost savings and cost increases resulting from the merger.

Cooling Degree-Day (CDD): A measure of the variation in weather based on the extent to which the daily average temperature (from 10:00 am to 10:00 am next day) is above 65 degrees Fahrenheit. This measurement is used to determine the impact of hot weather on our electric distribution operation during the cooling season.

Cost of sales: Includes the purchased cost of natural gas, electricity and propane commodities, pipeline capacity costs needed to transport and store natural gas, transmission costs for electricity, transportation costs to transport propane purchases to our storage facilities and the direct cost of labor spent on direct revenue-producing activities.

Dekatherms (Dts): A natural gas unit of measurement that measures heating value. A dekatherm (or 10 therms) of gas contains 10,000 British thermal units of heat, or the energy equivalent of burning approximately 1,000 cubic feet of natural gas under normal conditions.

Delmarva natural gas distribution operation: Chesapeake’s Delaware and Maryland divisions.

Delmarva Peninsula: A peninsula in the east coast of the United States of America that includes Delaware and portions of Maryland and Virginia. Chesapeake provides natural gas distribution, transmission and marketing services and propane distribution service to its customers on the Delmarva Peninsula.

Eastern Shore Natural Gas Company (Eastern Shore): A wholly owned natural gas transmission subsidiary of Chesapeake. Eastern Shore operates an interstate pipeline system that transports natural gas from various points in Pennsylvania to customers in southern Pennsylvania and on the Delmarva Peninsula.

Federal Energy Regulatory Commission (FERC): An independent agency of the Federal government that regulates the interstate transmission of electricity, natural gas, and oil. The FERC also reviews proposals to build liquefied natural gas terminals and interstate natural gas pipelines. Eastern Shore is regulated by the FERC.

Florida natural gas distribution operation: Chesapeake’s Florida division and the natural gas operation of Florida Public Utilities Company, including its Indiantown division.

Florida Public Utilities Company (FPU): A wholly owned subsidiary of Chesapeake as of October 28, 2009, the date we acquired FPU through the merger. FPU provides natural gas, electric and propane distribution services in Florida.

Gross margin: A non-GAAP measure, which Chesapeake uses to evaluate the performance of its business segments. Gross margin is calculated by deducting the cost of sales from operating revenues.

Heating Degree-Day (HDD): A measure of the variation in weather based on the extent to which the daily average temperature (from 10:00 am to 10:00 am next day) is below 65 degrees Fahrenheit. This measurement is used to determine the impact of cold weather on our natural gas, electric and propane distribution operations during the heating season.

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Manufactured Gas Plant (MGP): A site that previously used coal to manufacture gaseous fuel used for industrial, commercial and residential use. Some MGPs are currently undergoing remedial action to remove contamination in the soil and water at or near these sites.

Mark-to-Market: The process of adjusting the carrying value of a position held in our forward contracts and derivative instruments to reflect their current fair value.

Normal Weather: The most recent 10–year average of heating and/or cooling degree-days in a particular geographic area.

Peninsula Pipeline Company, Inc. (Peninsula Pipeline): A wholly owned Florida intrastate pipeline subsidiary of Chesapeake.

Peninsula Energy Services Company, Inc. (PESCO): A wholly owned natural gas marketing subsidiary of Chesapeake. PESCO competes with regulated utilities and other unregulated third-party marketers to sell natural gas supplies directly to commercial and industrial customers through competitively-priced contracts.

ProfitZoom™: A new product developed and launched by BravePoint. ProfitZoom™ is an integrated system encompassing financial, job costing and service management modules, which was designed specifically for the fire protection and specialty contracting industries.

Public Service Commission (PSC): The state agency that regulates the rates and services provided by Chesapeake’s natural gas and electric distribution operations in Delaware, Maryland and Florida. Peninsula Pipeline’s transportation service and rates are also regulated by the Florida PSC.

Remedial Action Plan (RAP): Procedures taken or being considered to remove contaminants from MGPs formerly owned or operated by Chesapeake or FPU.

Xeron, Inc. (Xeron): A wholly owned propane wholesale marketing subsidiary of Chesapeake based in Houston, Texas.

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PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Income (Unaudited)

 

For the Three Months Ended March 31,		2012				2011
(in thousands, except shares and per share data)
Operating Revenues
Regulated energy		$	72,296			$	84,870
Unregulated energy			44,887				58,750
Other			3,731				2,977
Total operating revenues			120,914				146,597
Operating Expenses
Regulated energy cost of sales			35,672				47,990
Unregulated energy and other cost of sales			34,593				44,289
Operations			19,955				19,837
Maintenance			1,976				1,702
Depreciation and amortization			5,761				5,021
Other taxes			2,884				2,919
Total operating expenses			100,841				121,758
Operating Income			20,073				24,839
Other income, net of other expenses			196				22
Interest charges			2,291				2,150
Income Before Income Taxes			17,978				22,711
Income tax expense			7,251				8,964
Net Income		$	10,727			$	13,747
Weighted-Average Common Shares Outstanding:
Basic			9,571,270				9,535,381
Diluted			9,666,885				9,633,796
Earnings Per Share of Common Stock:
Basic		$	1.12			$	1.44
Diluted		$	1.11			$	1.43
Cash Dividends Declared Per Share of Common Stock		$	0.345			$	0.330

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

 

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

 

For the Three Months Ended March 31,		2012				2011
(in thousands)
Net Income		$	10,727			$	13,747
Other Comprehensive Income (Loss), net of tax:
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(6) and $1, respectively			(9	)			2
Net Gain, net of tax of $50 and $211, respectively			76				315
Total other comprehensive income			67				317
Comprehensive Income		$	10,794			$	14,064

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

 

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

 

		March 31,				December 31,
Assets		2012				2011
(in thousands, except shares and per share data)
Property, Plant and Equipment
Regulated energy		$	535,978			$	528,790
Unregulated energy			68,081				67,327
Other			18,086				19,988
Total property, plant and equipment			622,145				616,105
Less: Accumulated depreciation and amortization			(141,189	)			(137,784	)
Plus: Construction work in progress			16,407				9,383
Net property, plant and equipment			497,363				487,704
Current Assets
Cash and cash equivalents			2,047				2,637
Accounts receivable (less allowance for uncollectible accounts of $1,049 and $1,090, respectively)			68,975				76,605
Accrued revenue			8,290				10,403
Propane inventory, at average cost			7,344				9,726
Other inventory, at average cost			3,009				4,785
Regulatory assets			1,166				1,846
Storage gas prepayments			1,724				5,003
Income taxes receivable			5,601				6,998
Deferred income taxes			1,202				2,712
Prepaid expenses			3,511				5,072
Mark-to-market energy assets			261				1,754
Other current assets			219				219
Total current assets			103,349				127,760
Deferred Charges and Other Assets
Goodwill			4,090				4,090
Other intangible assets, net			3,044				3,127
Investments, at fair value			4,264				3,918
Regulatory assets			77,958				79,256
Receivables and other deferred charges			3,059				3,211
Total deferred charges and other assets			92,415				93,602
Total Assets		$	693,127			$	709,066

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

 

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

 

		March 31,				December 31,
Capitalization and Liabilities		2012				2011
(in thousands, except shares and per share data)
Capitalization
Stockholders’ equity
Common stock, par value $0.4867 per share (authorized 25,000,000 shares)		$	4,661			$	4,656
Additional paid-in capital			149,252				149,403
Retained earnings			98,691				91,248
Accumulated other comprehensive loss			(4,460	)			(4,527	)
Deferred compensation obligation			828				817
Treasury stock			(828	)			(817	)
Total stockholders’ equity			248,144				240,780
Long-term debt, net of current maturities			110,236				110,285
Total capitalization			358,380				351,065
Current Liabilities
Current portion of long-term debt			8,196				8,196
Short-term borrowing			15,656				34,707
Accounts payable			48,721				55,581
Customer deposits and refunds			30,509				30,918
Accrued interest			2,927				1,637
Dividends payable			3,304				3,300
Accrued compensation			4,610				6,932
Regulatory liabilities			7,427				6,653
Mark-to-market energy liabilities			131				1,496
Other accrued liabilities			8,381				8,079
Total current liabilities			129,862				157,499
Deferred Credits and Other Liabilities
Deferred income taxes			119,532				115,624
Deferred investment tax credits			156				171
Regulatory liabilities			3,773				3,564
Environmental liabilities			9,437				9,492
Other pension and benefit costs			26,306				26,808
Accrued asset removal cost—Regulatory liability			37,013				36,584
Other liabilities			8,668				8,259
Total deferred credits and other liabilities			204,885				200,502
Other commitments and contingencies (Note 4 and 5)
Total Capitalization and Liabilities		$	693,127			$	709,066

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

 

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

 

For the Three Months Ended March 31,		2012				2011
(in thousands)
Operating Activities
Net Income		$	10,727			$	13,747
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			5,761				5,021
Depreciation and accretion included in other costs			1,398				1,055
Deferred income taxes, net			5,373				8,889
(Gain) loss on sale of assets			(36	)			57
Unrealized (gain) loss on commodity contracts			60				(83	)
Unrealized gain on investments			(317	)			(143	)
Employee benefits			126				444
Share-based compensation			345				329
Other, net			(7	)			(16	)
Changes in assets and liabilities:
Purchase of investments			(29	)			(44	)
Accounts receivable and accrued revenue			9,760				7,466
Propane inventory, storage gas and other inventory			5,830				5,777
Regulatory assets			1,106				488
Prepaid expenses and other current assets			1,452				1,528
Accounts payable and other accrued liabilities			(8,139	)			(11,041	)
Income taxes receivable			1,398				(270	)
Accrued interest			1,290				844
Customer deposits and refunds			(409	)			(2,165	)
Accrued compensation			(2,305	)			(2,009	)
Regulatory liabilities			799				4,372
Other liabilities			367				24
Net cash provided by operating activities			34,550				34,270
Investing Activities
Property, plant and equipment expenditures			(14,744	)			(8,355	)
Proceeds from sales of assets			2,170				299
Purchase of investments			(124	)			—
Environmental expenditures			(55	)			(164	)
Net cash used in investing activities			(12,753	)			(8,220	)
Financing Activities
Common stock dividends			(2,989	)			(2,836	)
Purchase of stock for Dividend Reinvestment Plan			(327	)			(307	)
Change in cash overdrafts due to outstanding checks			(1,550	)			(2,791	)
Net repayment under line of credit agreements			(17,501	)			(19,740	)
Repayment of long-term debt			(20	)			(35	)
Net cash used in financing activities			(22,387	)			(25,709	)
Net Increase (Decrease) in Cash and Cash Equivalents			(590	)			341
Cash and Cash Equivalents—Beginning of Period			2,637				1,643
Cash and Cash Equivalents—End of Period		$	2,047			$	1,984

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

 

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

 

		Common Stock								Additional								Accumulated  Other
(in thousands, except shares and per share data)		Number  of Shares(1)				Par Value				Paid-In Capital				Retained Earnings				Comprehensive Loss				Deferred Compensation				Treasury Stock				Total
Balances at December 31, 2010			9,524,195			$	4,635			$	148,159			$	76,805			$	(3,360	)		$	777			$	(777	)		$	226,239
Net Income															27,622																27,622
Other comprehensive loss																			(1,167	)											(1,167	)
Dividend Reinvestment Plan			—				—				(22	)																			(22	)
Retirement Savings Plan			2,002				1				79																				80
Conversion of debentures			10,680				5				176																				181
Share-based compensation (2) (3)			30,430				15				998																				1,013
Tax benefit on share-based compensation											13																				13
Deferred Compensation Plan																							40				(40	)			—
Purchase of treasury stock			(993	)																							(40	)			(40	)
Sale and distribution of treasury stock			993																								40				40
Dividends on share-based compensation															(129	)															(129	)
Cash dividends (4)															(13,050	)															(13,050	)
Balances at December 31, 2011			9,567,307				4,656				149,403				91,248				(4,527	)			817				(817	)			240,780
Net Income															10,727																10,727
Other comprehensive income																			67												67
Dividend Reinvestment Plan			—				—				(3	)																			(3	)
Conversion of debentures			1,818				1				30																				31
Share-based compensation (2) (3)			8,417				4				(178	)																			(174	)
Deferred Compensation Plan																							11				(11	)			—
Purchase of treasury stock			(243	)																							(11	)			(11	)
Sale and distribution of treasury stock			243																								11				11
Dividends on share-based compensation															20																20
Cash dividends (4)															(3,304	)															(3,304	)
Balances at March 31, 2012			9,577,542			$	4,661			$	149,252			$	98,691			$	(4,460	)		$	828			$	(828	)		$	248,144

 

(1)	Includes 30,840 and 30,597 shares at March 31, 2012 and December 31, 2011, respectively, held in a Rabbi Trust established by the Company relating to the Deferred Compensation Plan.

(2)	Includes amounts for shares issued for Directors' compensation.

(3)	The shares issued under the Performance Incentive Plan (“PIP”) are net of shares withheld for employee taxes. For three months ended March 31, 2012 and for the year ended December 31, 2011, the Company withheld 5,670 and 12,324 shares, respectively, for taxes.

(4)	Cash dividends per share for the periods ended March 31, 2012 and December 31, 2011 were $0.345 and $1.365 respectively.

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

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

1.	Summary of Accounting Policies

Basis of Presentation

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

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and accounting principles generally accepted in the United States of America (“GAAP”). In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 2011, as amended. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

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

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

Reclassifications

We reclassified certain amounts in the condensed consolidated statement of income for the three months ended March 31, 2011 and in the condensed consolidated balance sheet as of December 31, 2011 to conform to the current year’s presentation. We also reclassified certain segment information as of December 31, 2011, and for the three months ended March 31, 2011 to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.

Sale of Assets

In September 2011, Florida Public Utilities Company (“FPU”) entered into an agreement with an unaffiliated entity to sell its office building located in West Palm Beach, Florida for $2.2 million. FPU also entered into a separate agreement to lease office space at a different location in West Palm Beach, which commenced in February 2012. The sale of FPU’s West Palm Beach office building was finalized in February 2012. Some of the approximately 70 employees previously located in the West Palm Beach office building moved into the newly-leased office space, and the remaining employees moved into another nearby operations center, which FPU owns, in West Palm Beach. We treated the West Palm Beach office building as an asset held for sale and it was included in other property, plant and equipment at December 31, 2011 in the accompanying condensed consolidated balance sheet. The West Palm Beach office building had a net carrying value of approximately $1.9 million at the time of the sale. As most of the West Palm Beach office building was considered a property within the regulated businesses, most of the $229,000 gain resulting from the sale was deferred and recorded as a regulatory liability.

 

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Financial Accounting Standards Board (“FASB”) Statements and Other Authoritative Pronouncements

In September 2011, the FASB issued Accounting Standards Update (“ASU”) 2011-08, “Intangibles—Goodwill and Other (Topic 350) Testing Goodwill for Impairment,” which allows an entity to assess qualitatively whether it is necessary to perform step one of the two-step annual goodwill impairment test. Step one would be required if it is more-likely-than-not that a reporting unit’s fair value is less than its carrying amount. This differs from previous guidance, which required entities to perform step one of the test, at least annually, by comparing the fair value of a reporting unit to its carrying amount. An entity may elect to bypass the qualitative assessment and proceed directly to step one, for any reporting unit, in any period. ASU 2011-08 does not change the guidance on when to test goodwill for impairment. The amendments in ASU 2011-08 are effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We adopted the guidance of ASU 2011-08 effective January 1, 2012. Adoption of ASU 2011-08 did not have a material impact on our financial position and results of operations.

In May 2011, the FASB issued ASU No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.” Amendments in the ASU do not extend the use of fair value accounting but provide guidance on how it should be applied where its use is already required or permitted by other standards within International Financial Accounting Standards (“IFRS”) or U.S. GAAP. ASU 2011-04 supersedes most of the guidance in Topic 820, although many of the changes are clarifications of existing guidance or wording changes to align with IFRS. Certain amendments in ASU 2011-04 change a particular principle or requirement for measuring fair value or disclosing information about fair value measurements. The amendments in ASU 2011-04 are effective for public entities for interim and annual periods beginning after December 15, 2011, and should be applied prospectively. We adopted the guidance of ASU 2011-04, effective January 1, 2012, and provided additional disclosures as required. Adoption of ASU 2011-04 did not have a material impact on our financial position and results of operations.

 

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2.	Calculation of Earnings Per Share

 

For the Three Months Ended March 31,		2012				2011
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income		$	10,727			$	13,747
Weighted average shares outstanding			9,571,270				9,535,381
Basic Earnings Per Share		$	1.12			$	1.44
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income		$	10,727			$	13,747
Effect of 8.25% Convertible debentures			14				16
Adjusted numerator—Diluted		$	10,741			$	13,763
Reconciliation of Denominator:
Weighted shares outstanding—Basic			9,571,270				9,535,381
Effect of dilutive securities:
Share-based Compensation			29,931				23,246
8.25% Convertible debentures			65,684				75,169
Adjusted denominator—Diluted			9,666,885				9,633,796
Diluted Earnings Per Share		$	1.11			$	1.43

 

3.	Rates and Other Regulatory Activities

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

Delaware

On September 1, 2011, the Delaware division filed with the Delaware PSC its annual Gas Service Rates (“GSR”) Application, seeking approval to change its GSR, effective November 1, 2011. On September 20, 2011, the Delaware PSC authorized the Delaware division to implement the GSR charges, as filed, on November 1, 2011, on a temporary basis, subject to refund, pending the completion of a full evidentiary hearing and a final decision. We anticipate that the Delaware PSC will render a final decision on the GSR charges in the second or third quarter of 2012.

Maryland

There were no significant regulatory proceedings in Maryland pending during the first quarter.

Florida

“Come-Back” Filing: At the December 6, 2011 agenda conference, the Florida PSC approved, among other things, the inclusion in our rate base in Florida of an acquisition adjustment of $34.2 million and merger-related costs of $2.2 million, to be amortized over a 30-year period and a five-year period, respectively, using the straight-line method beginning in November 2009. The Florida PSC also determined that FPU and Chesapeake’s Florida division did not have any excess earnings in 2010 to be refunded to customers. The Florida PSC issued a consummating order on these matters on January 30, 2012.

 

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The Florida PSC order allows us to classify the acquisition adjustment and merger-related costs as regulatory assets and include them in our investment, or rate base, when determining our Florida natural gas rates. In addition, our rate of return calculation will be based upon this higher level of investment, which enables us to earn a return on this investment. Pursuant to this order, we reclassified to a regulatory asset at December 31, 2011, $31.7 million of the $34.2 million goodwill, which represents the portion of the goodwill allowed to be recovered in future rates after the effective date of the Florida PSC order. We also recorded as a regulatory asset $18.1 million related to the gross-up of the acquisition adjustment for income tax. An amount of $1.3 million of the $2.2 million of merger-related costs, which represent the portion of the merger-related costs allowed to be recovered in future rates after the effective date of the Florida PSC order, had previously been deferred as a regulatory asset. We also recorded as a regulatory asset $349,000 related to the gross-up of the merger-related costs for income tax. Based upon the effective date and outcome of the order, we began reflecting the amortization as an expense in January 2012, and included $588,000 of the amortization expense in depreciation and amortization in the accompanying condensed consolidated statement of income for the three months ended March 31, 2012. We will record $2.4 million ($1.4 million, net of tax) in amortization expense related to these assets in 2012 and 2013, $2.3 million ($1.4 million, net of tax) in 2014 and $1.8 million ($1.1 million, net of tax) annually, thereafter until 2039. These amortization expenses will be non-cash charges, and the net effect of the recovery will be positive cash flow. Over the long-term, inclusion of the acquisition adjustment and merger-related costs in our rate base and the recovery of these regulatory assets through amortization expense will increase our earnings and cash flows above what we would have been able to achieve absent this regulatory authorization.

In FPU’s future rate proceedings, if it is determined that the level of cost savings supporting recovery of the acquisition adjustment no longer exists, the remaining acquisition adjustment may be partially or entirely disallowed by the Florida PSC. In such event, we will have to expense the corresponding amount of the disallowed acquisition adjustment.

Peninsula Pipeline: At its April 10, 2012 agenda conference, the Florida PSC approved the joint territorial agreement between FPU and the Peoples Gas System division of Tampa Electric Company (“Peoples Gas”) and other related agreements among FPU, Peninsula Pipeline and Peoples Gas. These agreements were executed in January 2012 among the parties to enable Peninsula Pipeline and FPU to expand natural gas service into Nassau and Okeechobee Counties, Florida.

One of the agreements provides for the joint construction, ownership and operation of a pipeline extending approximately 16 miles from the Duval/Nassau County line to Amelia Island in Nassau County, Florida. Under the terms of the agreement, Peninsula Pipeline will own approximately 45 percent of this 16-mile pipeline, and its portion of the estimated project cost is expected to be approximately $5.7 million. Peoples Gas will operate the pipeline, and Peninsula Pipeline will be responsible for its portion of the operation and maintenance expenses of the pipeline based on its ownership percentage. The new jointly-owned pipeline is expected to be completed and placed into service in late 2012 or early 2013. Under a separate agreement, Peninsula Pipeline will contract with Peoples Gas for transportation service from the Peoples Gas interconnection point with an unaffiliated upstream interstate pipeline to the new jointly-owned pipeline. Peninsula Pipeline will then utilize the transportation agreement with Peoples Gas and the jointly-owned pipeline capacity to provide transportation service to FPU for its natural gas distribution service in Nassau County.

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

 

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In accordance with the terms of the Franchise Agreement, FPU developed TOU and interruptible rates and on December 14, 2010, FPU filed a petition with the Florida PSC for authority to implement such proposed TOU and interruptible rates on or before February 17, 2011. On February 11, 2011, the Florida PSC issued an order approving FPU’s petition for authority to implement the proposed TOU and interruptible rates, which became effective on February 8, 2011. The City objected to the proposed rates and filed a petition protesting the entry of the Florida PSC’s order. On January 24, 2012, the Florida PSC dismissed with prejudice the protest by the City.

On January 26, 2011, FPU filed a petition with the Florida PSC for approval of an amendment to FPU’s Generation Services Agreement entered into between FPU and Gulf Power. The amendment provides for a reduction in the capacity demand quantity, which generates the savings necessary to support the TOU and interruptible rates approved by the Florida PSC. The amendment also extends the current agreement by two years, with a new expiration date of December 31, 2019. By its order dated June 21, 2011, the Florida PSC approved the amendment. On July 12, 2011, the City filed a protest of this decision and requested a hearing on the amendment. On January 24, 2012, the Florida PSC dismissed with prejudice the protest by the City.

The City filed an appeal with the Florida Supreme Court on March 7, 2012 and with the Florida PSC on March 19, 2012. At this time, the City’s appeal is pending before the Florida Supreme Court.

As disclosed in Note 5, “Other Commitments and Contingencies,” to the Condensed Consolidated Financial Statements, the City, on March 2, 2011, filed a complaint against FPU in the Circuit Court of the Fourteenth Judicial Circuit in and for Jackson County, Florida, alleging breaches of the Franchise Agreement by FPU and seeking a declaratory judgment that the City has the right to exercise its option to purchase FPU’s property in the City in accordance with the terms of the Franchise Agreement. On March 28, 2011, FPU filed its answer to the declaratory action by the City, in which it denied the material allegations by the City and asserted affirmative defenses. The litigation remains pending.

On April 7, 2011, FPU filed a petition for approval of a mid-course reduction to its Northwest Division fuel rates based on two factors: (1) the previously discussed amendment to the Generation Services Agreement with Gulf Power, and (2) a weather-related increase in sales resulting in an accelerated collection of the prior year’s under-recovered costs. Pursuant to its order dated July 5, 2011, the Florida PSC approved the petition, which reduced the fuel rates of FPU’s northwest division, which includes the fuel rates charged to customers in the City.

On February 24, 2012, FPU filed a revised petition for approval of a mid-course reduction to its Northwest Division fuel rates based on a reduction in its supplier’s fuel rates, which would significantly lower purchased power costs for FPU’s Northwest Division in 2012. FPU filed for this mid-course reduction in order to ensure that its customers receive these savings in the most timely manner, and the Florida PSC issued an order on March 27, 2012, approving the mid-course correction reduction in fuel rates, effective April 1, 2012. This further reduced the fuel rates of FPU’s northwest division, which includes the fuel rates charged to customers in the City.

We also had developments in the following regulatory matters in Florida:

On June 21, 2011, FPU, in accordance with the Florida PSC rules, filed its 2011 depreciation study and request for new depreciation rates for its electric distribution operation, effective January 1, 2012. The Florida PSC approved the depreciation study at its January 24, 2012 Agenda Conference. The new approved depreciation rates are expected to reduce annual depreciation expense by approximately $227,000.

 

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On February 3, 2012, FPU’s natural gas distribution operation and the Florida Division of Chesapeake filed a petition with the Florida PSC for approval of a surcharge to customers for a Gas Reliability Infrastructure Program. We are seeking approval to recover costs, inclusive of an appropriate return on investment, associated with accelerating the replacement of qualifying distribution mains and services (defined as any material other than coated steel or plastic (Polyethylene)) in their respective systems. If the petition is approved, we will replace qualifying mains and services over a 10-year period.

On March 21, 2012 FPU filed a Petition with the Florida PSC for approval of a Negotiated Contract for the purchase of renewable energy power between FPU and an unaffiliated company, which is constructing and installing a new Renewable Generating Facility within FPU’s service territory. If constructed and installed, this facility will be capable of interconnecting and selling power to FPU’s northeast electric division. Overall, this contract will provide a significant benefit to FPU’s northeast electric customers, while also promoting the State of Florida’s goal of encouraging energy independence and the growth of renewable energy projects. If the contract is approved, savings will be passed on to customers through lower fuel costs. The Florida PSC is expected to rule on this contract in June 2012.

Eastern Shore

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

Rate Case Filing: On December 30, 2010, Eastern Shore filed with the FERC a base rate proceeding in accordance with the terms of the settlement in its prior base rate proceeding. Conferences involving Eastern Shore, the FERC Staff and other interested parties resulted in a settlement based on an annual cost of service of approximately $29.1 million and a pre-tax return of 13.9 percent. Also included in the settlement is a negotiated rate adjustment, effective November 1, 2011, associated with the phase-in of an additional 15,000 dekatherms (“Dts”) per day of new transportation service on Eastern Shore’s eight-mile extension to interconnect with Texas Eastern Transmission LP’s (“TETLP”) pipeline system. This rate adjustment reduces the rate per Dt of the service on this eight-mile extension by reflecting the increased service of 15,000 Dts per day with no additional revenue. This rate adjustment effectively offsets the increased revenue that would have been generated from the 15,000 Dts per day increase in firm service although Eastern Shore may still collect a commodity charge on the increased volume from the phase-in of service. The settlement also provides a five-year moratorium on the parties’ rights to challenge Eastern Shore’s rates and on Eastern Shore’s right to file a base rate increase but allows Eastern Shore to file for rate adjustments during those five years in the event certain costs related to government-mandated obligations are incurred and Eastern Shore’s pre-tax earnings do not equal or exceed 13.9 percent. The FERC approved the settlement on January 24, 2012.

From July 2011 through October 2011, Eastern Shore adjusted its billing to reflect the rates requested in the base rate proceeding, subject to refund to customers upon the FERC’s approval of the new rates. Commencing in November 2011, Eastern Shore adjusted its billing to reflect the settlement rates, subject to refund to customers upon FERC’s approval of the settlement. At December 31, 2011 Eastern Shore had recorded approximately $1.3 million as a regulatory liability related to the refund due to customers as a result of the settlement; the refund was paid in January and February 2012.

Eastern Shore also had developments in the following FERC matters:

On March 7, 2011, Eastern Shore filed certain tariff sheets to amend the creditworthiness provisions contained in its FERC Gas Tariff. On April 6, 2011, the FERC issued an order accepting and suspending Eastern Shore’s filed tariff revisions, effective April 1, 2011, subject to Eastern Shore submitting certain clarifications with regard to several proposed revisions. Eastern Shore responded with a revised filing on January 13, 2012, which the FERC approved on February 24, 2012.

On March 1, 2012, Eastern Shore filed revised tariff sheets to amend certain provisions contained in the Construction of Facilities and Right of First Refusal sections of its FERC Gas Tariff. On April 6, 2012, the FERC issued an order accepting Eastern Shore’s revised tariff sheet, effective April 1, 2012, subject to Eastern Shore submitting two additional revisions proposed by an intervening party during the review period. Eastern Shore responded with a revised filing on April 16, 2012, which the FERC accepted.

 

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4.	Environmental Commitments and Contingencies

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

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

As of March 31, 2012, we had approximately $11.0 million in environmental liabilities related to all of FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites, representing our estimate of the future costs associated with those sites. FPU has approval to recover up to $14.0 million of its environmental costs related to all of its MGP sites from insurance and from customers through rates. Approximately $8.4 million of FPU’s expected environmental costs have been recovered from insurance and customers through rates as of March 31, 2012. We also had approximately $5.6 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

In addition to the FPU MGP sites, we had $246,000 in environmental liabilities as of March 31, 2012, related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of future costs associated with these sites. As of March 31, 2012, we had approximately $882,000 in regulatory and other assets for future recovery through Chesapeake’s rates.

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

The following discussion provides a brief summary of each MGP site:

West Palm Beach, Florida

Remedial options are being evaluated to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West Palm Beach, Florida, where FPU previously operated an MGP. FPU is currently implementing a remedial plan approved by the Florida Department of Environmental Protection (“FDEP”) for the east parcel of the West Palm Beach site, which includes relocation and removal of structures and installation of monitoring and testing wells. Estimated costs of remediation for the West Palm Beach site range from approximately $4.7 million to $15.8 million, including costs associated with the relocation of FPU’s operations at this site, which may be necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties. We continue to expect that all costs related to these activities will be recoverable from customers through rates.

Sanford, Florida

FPU is the current owner of property in Sanford, Florida, which was a former MGP site that was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of the MGP. In January 2007, FPU and other responsible parties at the Sanford site (collectively with FPU the “Sanford Group”) signed a Third Participation Agreement, which provides for the funding of the final remedy approved by the Environmental Protection Agency (“EPA”) for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13 million, or $650,000. As of March 31, 2012, FPU has paid $650,000 to the Sanford Group escrow account for its share of the funding requirements.

The total cost of the final remedy is now estimated at approximately $18 million, which includes the settlement of claims asserted by two adjacent property owners to resolve damages that the property owners allege they have and will incur as a result of the implementation of the EPA-approved remediation. In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third-party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third-party claims. FPU has advised the other members of the Sanford Group that it is unwilling at this time to agree to pay any sum in excess of the $650,000 committed by FPU in the Third Participation Agreement.

 

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As of March 31, 2012, FPU’s remaining share of remediation expenses, including attorneys’ fees and costs, is estimated to be $24,000. However, we are unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept FPU’s asserted defense to liability for costs exceeding $13.0 million to implement the final remedy for this site or will pursue a claim against FPU for a sum in excess of the $650,000 that FPU has paid under the Third Participation Agreement. No such claims have been made as of March 31, 2012.

Key West, Florida

FPU formerly owned and operated an MGP in Key West, Florida. Field investigations performed in the 1990s identified limited environmental impacts at the site, which is currently owned by an unrelated third party. In 2010, after 17 years of regulatory inactivity, the FDEP observed that some soil and groundwater standards were exceeded and requested implementation of additional soil and groundwater fieldwork. The scope of work is limited to the installation of two additional monitoring wells and periodic monitoring of the new and existing wells. The two new monitoring wells were installed in November 2011, and groundwater monitoring began in December 2011. Prior to completion of the monitoring program, we cannot determine to a reasonable degree of certainty the probable costs to resolve FPU’s liability for the Key West MGP Site, although we do not anticipate the cost to exceed $100,000.

Pensacola, Florida

FPU formerly owned and operated an MGP in Pensacola, Florida, which was subsequently owned by Gulf Power. Portions of the site are now owned by the City of Pensacola and the Florida Department of Transportation (“FDOT”). In October 2009, FDEP informed Gulf Power that FDEP would approve a conditional No Further Action (“NFA”) determination for the site, which must include a requirement for institutional and engineering controls. On December 13, 2011, Gulf Power, the City of Pensacola, FDOT and FPU submitted a draft covenant for institutional and engineering controls for the site to the FDEP. Upon FDEP’s approval and the subsequent recording of the institutional and engineering controls, no further work is expected to be required of the parties. Assuming the FDEP approves the draft institutional and engineering controls, it is anticipated that FPU’s share of remaining legal and cleanup costs will not exceed $5,000.

Salisbury, Maryland

We have substantially completed remediation of a site in Salisbury, Maryland, where it was determined that a former MGP caused localized ground-water contamination. In February 2002, the MDE granted permission to permanently decommission the systems used for remediation and to discontinue all on-site and off-site well monitoring, except for one well, which is being maintained for periodic product monitoring and recovery. We anticipate that the remaining costs of the one remaining monitoring well will not exceed $5,000 annually. We cannot predict at this time when the MDE will grant permission to permanently decommission the one remaining monitoring well.

Winter Haven, Florida

The Winter Haven site is located on the eastern shoreline of Lake Shipp, in Winter Haven, Florida. Pursuant to a Consent Order entered into with the FDEP, we are obligated to assess and remediate environmental impacts at this former MGP site. The recent groundwater sampling results show a continuing reduction in contaminant concentrations from the treatment system, which has been in operation since 2002. Currently, we predict that remedial action objectives could be met in approximately two to three years for the area being treated by the remediation system. The total expected cost of operating and monitoring the system is approximately $46,000.

 

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The current treatment system at the Winter Haven site does not address impacted soils in the southwest corner of the site. In 2010, we obtained a conditional approval from FDEP for a soil excavation plan, and we estimate the cost of this excavation at $250,000; however, this estimate does not include costs associated with dewatering or shoreline stabilization, which would be required to complete the excavation. Because the costs associated with shoreline stabilization and dewatering are likely to be substantial, alternatives to this excavation plan are being evaluated.

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

Other

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

 

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5.	Other Commitments and Contingencies

Litigation

On March 2, 2011, the City of Marianna (the “City”) filed a complaint against FPU in the Circuit Court of the Fourteenth Judicial Circuit in and for Jackson County, Florida. In the complaint, the City alleged three breaches of the Franchise Agreement by FPU: (i) FPU failed to develop and implement TOU and interruptible rates that were mutually agreed to by the City and FPU; (ii) mutually agreed upon TOU and interruptible rates by FPU were not effective or in effect by February 17, 2011; and (iii) FPU did not have such rates available to all of FPU’s customers located within and without the corporate limits of the City. The City is seeking a declaratory judgment allowing it to exercise its option under the Franchise Agreement to purchase FPU’s property (consisting of the electric distribution assets) within the City. Any such purchase would be subject to approval by the Marianna Commission, which would also need to approve the presentation of a referendum to voters in the City related to the purchase and the operation by the City of an electric distribution facility. If the purchase is approved by the Marianna Commission and the referendum is approved by the voters, the closing of the purchase must occur within 12 months after the referendum is approved. On March 28, 2011, FPU filed its answer to the declaratory action by the City, in which it denied the material allegations by the City and asserted several affirmative defenses. On August 3, 2011, the City notified FPU that it was formally exercising its option to purchase FPU’s property. On August 31, 2011, FPU advised the City that it has no right to exercise the purchase option under the Franchise Agreement and that FPU would continue to oppose the effort by the City to purchase FPU’s property. In December 2011, the City filed a motion for summary judgment. FPU opposed the motion. On April 3, 2012, the court conducted a hearing on the City’s motion for summary judgment. The court has not yet ruled on the motion, but stated that a ruling would be forthcoming in advance of a mediation scheduled in this matter for May 11, 2012. Trial is set for July 30, 2012. Unless resolved through the mediation, we anticipate that the case will be tried and intend to defend this lawsuit vigorously. We also intend to oppose the adoption of any proposed referendum to approve the purchase of the FPU property by the City.

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

Natural Gas, Electric and Propane Supply

Our natural gas, electric and propane distribution operations have entered into contractual commitments to purchase gas, electricity and propane from various suppliers. The contracts have various expiration dates. We have a contract with an energy marketing and risk management company to manage a portion of our natural gas transportation and storage capacity. This contract expires on March 31, 2013.

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

In May 2011, PESCO renewed contracts to purchase natural gas from various suppliers. These contracts expire in May 2012. PESCO is currently in the process of obtaining and reviewing proposals from suppliers and anticipates executing agreements before the existing agreements expire.

FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEA (formerly known as Jacksonville Electric Authority) requires FPU to comply with the following ratios based on the results of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 times, and (b) fixed charge coverage ratio greater than 1.5 times. If either ratio is not met by FPU, it has 30 days to cure the default or provide an irrevocable letter of credit if the default is not cured. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken or proposed to be taken to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could result in FPU providing an irrevocable letter of credit. As of March 31, 2012, FPU was in compliance with all of the requirements of its fuel supply contracts.

 

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Corporate Guarantees

The Board of Directors has authorized the Company to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our obligations, including the obligations of our subsidiaries. The maximum authorized liability under such guarantees and letters of credit is $45 million.

We have issued corporate guarantees to certain vendors of our subsidiaries, primarily for our propane wholesale marketing subsidiary and our natural gas marketing subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in the condensed consolidated financial statements when incurred. The aggregate amount guaranteed at March 31, 2012 was $28.6 million, with the guarantees expiring on various dates through February 2013.

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

In addition to the corporate guarantees, we have issued a letter of credit for $1.0 million, which expires on September 12, 2012, related to the electric transmission services for FPU’s northwest electric division. We have also issued a letter of credit to our current primary insurance company for $656,000, which expires on December 2, 2012, as security to satisfy the deductibles under our various outstanding insurance policies. As a result of a change in our primary insurance company in 2010, we renewed the letter of credit for $725,000 to our former primary insurance company, which will expire on June 1, 2012. There have been no draws on these letters of credit as of March 31, 2012. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that the letters of credit will be renewed to the extent necessary in the future.

We provided a letter of credit for $2.5 million to TETLP related to the Precedent Agreement with TETLP, which is further described below.

Agreements for Access to New Natural Gas Supplies

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

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

 

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

The Precedent Agreement requires us to reimburse TETLP for our proportionate share of TETLP’s pre-service costs incurred to date, if we terminate the Precedent Agreement, are unwilling or unable to perform our material duties and obligations thereunder, or take certain other actions whereby TETLP is unable to obtain the authorizations and exemptions required for this project. If such termination were to occur, we estimate that our proportionate share of TETLP’s pre-service costs could be approximately $8.5 million as of March 31, 2012. If we were to terminate the Precedent Agreement after TETLP completed its construction of all facilities, which is expected to be in the fourth quarter of 2012, our proportionate share could be as much as approximately $50 million. The actual amount of our proportionate share of such costs could differ significantly and would ultimately be based on the level of pre-service costs at the time of any potential termination. As our Delaware and Maryland divisions have now executed the required reservation rate agreements with TETLP, we believe that the likelihood of terminating the Precedent Agreement and having to reimburse TETLP for our proportionate share of TETLP’s pre-service costs is remote.

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

On March 17, 2010, our Delaware and Maryland divisions entered into a separate Precedent Agreement with Eastern Shore to extend its mainline by eight miles to interconnect with TETLP at Honey Brook, Pennsylvania. Eastern Shore completed the extension project in December 2010 and commenced the service in January 2011. The rate for the transportation service on this extension is Eastern Shore’s current tariff rate for service in that area.

In November 2011, TETLP obtained the necessary authorizations from the FERC for construction and operation of its portion of the project. Our Delaware and Maryland divisions require no regulatory approvals or exemptions to receive transmission service from TETLP or Eastern Shore.

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

Non-income-based Taxes

From time to time, we are subject to various audits and reviews by the states and other regulatory authorities regarding non-income-based taxes. We are currently undergoing sales tax audits in Florida. As of March 31, 2012 and December 31, 2011, we maintained accruals of $173,000 and $307,000, respectively, related to additional sales taxes and gross receipts taxes that we may owe to various states.

 

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6.	Segment Information

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

 

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

 

•

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

 

•

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

The following table presents information about our reportable segments.

 

For the Three Months Ended March 31,		2012				2011
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy		$	72,018			$	84,683
Unregulated Energy			44,887				58,750
Other			4,009				3,164
Total operating revenues, unaffiliated customers		$	120,914			$	146,597
Intersegment Revenues (1)
Regulated Energy		$	278			$	187
Unregulated Energy			—				—
Other			235				194
Total intersegment revenues		$	513			$	381
Operating Income
Regulated Energy		$	14,798			$	16,233
Unregulated Energy			5,154				8,591
Other and eliminations			121				15
Total operating income			20,073				24,839
Other income, net of other expenses			196				22
Interest			2,291				2,150
Income taxes			7,251				8,964
Net income		$	10,727			$	13,747

 

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

 

		March 31,				December 31,
		2012				2011
(in thousands)
Identifiable Assets
Regulated energy		$	562,945			$	565,563
Unregulated energy			95,012				107,916
Other			35,170				35,587
Total identifiable assets		$	693,127			$	709,066

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

 

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7.	Employee Benefit Plans

Net periodic benefit costs for our pension and post-retirement benefits plans for the three months ended March 31, 2012 and 2011 are set forth in the following table:

 

																										Chesapeake
		Chesapeake								FPU								Chesapeake								Postretirement								FPU
		Pension Plan								Pension Plan								Pension SERP								Plan								Medical Plan
For the Three Months Ended March 31,		2012				2011				2012				2011				2012				2011				2012				2011				2012				2011
(in thousands)
Service cost		$	—			$	—			$	—			$	—			$	—			$	—			$	—			$	—			$	40			$	26
Interest cost			125				130				639				671				23				27				15				15				45				39
Expected return on plan assets			(109	)			(101	)			(658	)			(684	)			—				—				—				—				—				—
Amortization of prior service cost			(1	)			(1	)			—				—				5				5				(20	)			—				—				—
Amortization of net loss			85				39				44				—				11				10				18				—				23				5
Net periodic cost (benefit)			100				67				25				(13	)			39				42				13				15				108				70
Settlement expense			—				217				—				—				—				—				—				—				—				—
Amortization of pre-merger regulatory asset			—				—				190				190				—				—				—				—				2				2
Total periodic cost		$	100			$	284			$	215			$	177			$	39			$	42			$	13			$	15			$	110			$	72

We expect to record pension and postretirement benefit costs of approximately $1.9 million for 2012. Also included in the $1.9 million pension and postretirement benefit costs for 2012 is $769,000 related to continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU’s regulated energy operations of the changes in funded status that occurred but were not recognized as part of net periodic benefit costs prior to the merger. This was deferred as a regulatory asset by FPU prior to the merger to be recovered through rates pursuant to a previous order by the Florida PSC. The unamortized balance of this regulatory asset was $5.7 million and $5.9 million at March 31, 2012 and December 31, 2011, respectively.

During the three months ended March 31, 2012, we contributed $163,000 and $292,000 to the Chesapeake and FPU pension plans, respectively. We expect to contribute $1.3 million and $2.0 million to the Chesapeake and FPU pension plans, respectively, during the year 2012, which includes minimum contribution payments required in 2012 and any additional contribution payments that we plan on making to maintain a certain level of funding in those plans.

The Chesapeake Pension SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake Pension SERP for the three months ended March 31, 2012, were $22,000; we expect to pay additional cash benefits of approximately $88,000 in 2012. Cash benefits paid for the Chesapeake Postretirement Plan, primarily for medical claims for the three months ended March 31, 2012, totaled $13,000 and we have estimated that approximately $87,000 will be paid for such benefits in 2012. Cash benefits paid for the FPU Medical Plan, primarily for medical claims for the three months ended March 31, 2012, totaled $58,000. We have estimated that approximately $193,000 will be paid for such benefits in 2012.

 

8.	Investments

The investment balance at March 31, 2012, represents: (a) a Rabbi Trust associated with our Supplemental Executive Retirement Savings Plan, (b) a Rabbi Trust related to a stay bonus agreement with a former executive, and (c) investments in equity securities. We classify these investments as trading securities and report them at their fair value. We recorded $317,000 for an unrealized gain, net of other expenses, in other income in the consolidated statements of income. We also have recorded an associated liability that is adjusted each month for the gains and losses incurred by the Rabbi Trusts. At March 31, 2012 and December 31, 2011, total investments had a fair value of $4.3 million and $4.0 million, respectively.

 

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9.	Share-Based Compensation

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

The table below presents the amounts included in net income related to share-based compensation expense for the awards granted under the DSCP and the PIP for the three months ended March 31, 2012 and 2011:

 

For the Three Months Ended March 31,		2012				2011
(in thousands)
Directors Stock Compensation Plan		$	111			$	84
Performance Incentive Plan			234				245
Total compensation expense			345				329
Less: tax benefit			138				132
Share-Based Compensation amounts included in net income		$	207			$	197

Directors Stock Compensation Plan

Shares granted under the DSCP are issued in advance of the directors’ service periods and are fully vested as of the date of the grant. We record a prepaid expense of the shares issued and amortize the expense equally over a service period of one year.

At March 31, 2012, there was $37,000 of unrecognized compensation expense related to the DSCP awards. This expense is expected to be recognized over the directors’ remaining service period ending April 30, 2012.

Performance Incentive Plan

The table below presents the summary of the stock activity for the PIP for the three months ended March 31, 2012:

 

						Weighted Average
		Number of Shares				Fair Value
Outstanding — December 31, 2011			87,414			$	34.47
Granted			30,906				38.79
Vested			13,837				29.84
Forfeited (1)			21,600				35.55
Expired			3,038				26.29
Outstanding — March 31, 2012			79,845			$	37.44

 

(1)	Includes shares settled with a cash payment pursuant to the terms of a separation agreement with a former named executive officer.

In January 2012, the Board of Directors granted awards under the PIP for 30,906 shares. The shares granted in January 2012 are multi-year awards that will vest at the end of the three-year service period, or December 31, 2014. These awards are earned based upon the successful achievement of long-term goals, growth and financial results, which comprised both market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the date of the grant. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each market-based award granted.

Effective February 24, 2012, one of our named executive officers, who was a participant in the PIP, resigned. Pursuant to a separation agreement entered into between the Company and the named executive officer, the executive officer received a cash payment of $181,500 and other benefits in lieu of other performance-based compensation, which he might have been entitled to receive.

At March 31, 2012, the aggregate intrinsic value of the PIP awards was $1.2 million.

 

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10.	Derivative Instruments

We use derivative and non-derivative contracts to engage in trading activities and manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane. Our natural gas, electric and propane distribution operations have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to their customers. Purchases under these contracts either do not meet the definition of derivatives or are considered “normal purchases and sales” and are accounted for on an accrual basis. Our propane distribution operation may also enter into fair value hedges of its inventory in order to mitigate the impact of wholesale price fluctuations. As of March 31, 2012, our natural gas and electric distribution operations did not have any outstanding derivative contracts. In August 2011, our propane distribution operation entered into a put option to protect against the decline in propane prices and related potential inventory losses associated with 630,000 gallons purchased for the propane price cap program in the upcoming heating season. This put option was exercised as the propane prices fell below the strike price of $1.445 per gallon in January through March of 2012, and we received $118,000 representing the difference between the market price and the strike price during those months. We had paid $91,000 to purchase the put option, and we accounted for it as a fair value hedge. The change in the fair value of the put option effectively reduced our propane inventory balance until when it was exercised, at which point the proceeds reduced cost of sales. There was no ineffective portion of this fair value hedge.

Xeron, our propane wholesale and marketing subsidiary, engages in trading activities using forward and futures contracts. These contracts are considered derivatives and have been accounted for using the mark-to-market method of accounting. Under the mark-to-market method of accounting, the trading contracts are recorded at fair value, and the changes in fair value of those contracts are recognized as unrealized gains or losses in the statement of income in the period of change. As of March 31, 2012, we had the following outstanding trading contracts which we accounted for as derivatives:

 

		Quantity in				Estimated Market		Weighted Average
At March 31, 2012		Gallons				Prices		Contract Prices
Forward Contracts
Sale			4,936,000			$1.2350 — $1.3775		$	1.2819
Purchase			3,991,000			$1.1950 — $1.3350		$	1.2585

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

All contracts expire by the first quarter of 2013.

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

 

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Fair values of the derivative contracts recorded in the condensed consolidated balance sheet as of March 31, 2012 and December 31, 2011, are as follows:

 

		Asset Derivatives
				Fair Value
(in thousands)		Balance Sheet Location		March 31, 2012				December 31, 2011
Derivatives not designated as hedging instruments
Forward contracts		Mark-to-market energy assets		$	261			$	1,686
Derivatives designated as fair value hedges
Put option (1)		Mark-to-market energy assets			—				68
Total asset derivatives				$	261			$	1,754

 

		Liability Derivatives
				Fair Value
(in thousands)		Balance Sheet Location		March 31, 2012				December 31, 2011
Derivatives not designated as hedging instruments
Forward contracts		Mark-to-market energy liabilities		$	131			$	1,496
Total liability derivatives				$	131			$	1,496

 

(1)	We purchased a put option for the Pro-Cap Plan in August 2011. The put option, which expired in March 2012, had a fair value of $0 at March 31, 2012.

The effects of gains and losses from derivative instruments on the condensed consolidated financial statements are as follows:

 

				Amount of Gain (Loss) on Derivatives:
		Location of Gain		For the Three Months Ended March 31,
(in thousands)		(Loss) on Derivatives		2012				2011
Derivatives not designated as hedging instruments:
Unrealized gain (loss) on forward contracts		Revenue		$	(60	)		$	83
Derivatives designated as fair value hedges:
Put Option		Cost of sales			27				—
Total				$	(33	)		$	83

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

 

		Location in the		Three months ended March 31,
(in thousands)		Statement of Income		2012				2011
Realized gain on forward contracts/put option		Revenue		$	514			$	907
Unrealized gain (loss) on forward contracts		Revenue			(60	)			83
Total				$	454			$	990

 

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11.	Fair Value of Financial Instruments

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

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

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

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

The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy used at March 31, 2012:

 

		Fair Value Measurements Using:
										Significant Other				Significant
						Quoted Prices in				Observable				Unobservable
						Active Markets				Inputs				Inputs
(in thousands)		Fair Value				(Level 1)				(Level 2)				(Level 3)
Assets:
Investments—equity securities		$	2,389			$	2,389			$	—			$	—
Investments—other (1)		$	1,915			$	1,915			$	—			$	—
Mark-to-market energy assets, including put option		$	261			$	—			$	261			$	—
Liabilities:
Mark-to-market energy liabilities		$	131			$	—			$	131			$	—

 

(1)	The current portion of this investment ($40) is included in other current assets in the accompanying consolidated balance sheets.

The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy used at December 31, 2011:

 

						Fair Value Measurements Using:
										Significant Other				Significant
						Quoted Prices in				Observable				Unobservable
						Active Markets				Inputs				Inputs
(in thousands)		Fair Value				(Level 1)				(Level 2)				(Level 3)
Assets:
Investments—equity securities		$	2,224			$	2,224			$	—			$	—
Investments—other(1)		$	1,734			$	1,734			$	—			$	—
Mark-to-market energy assets, including put option		$	1,754			$	—			$	1,754			$	—
Liabilities:
Mark-to-market energy liabilities		$	1,496			$	—			$	1,496			$	—

 

(1)	The current portion of this investment ($40) is included in other current assets in the accompanying consolidated balance sheets.

 

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The following valuation techniques were used to measure fair value assets in the table above on a recurring basis as of March 31, 2012 and December 31, 2011:

Level 1 Fair Value Measurements:

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

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

Level 2 Fair Value Measurements:

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

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

At March 31, 2012, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.

Other Financial Assets and Liabilities

Financial assets with carrying values approximating fair value include cash and cash equivalents and accounts receivable. Financial liabilities with carrying values approximating fair value include accounts payable and other accrued liabilities and short-term debt. The fair value of cash and cash equivalents is measured using the comparable value in the active market and approximates its carrying value (Level 1 measurement). The fair value of short-term debt approximates the carrying value due to its short maturities and because interest rates approximate current market rates (Level 3 measurement).

At March 31, 2012, long-term debt, which includes the current maturities of long-term debt, had a carrying value of $118.4 million, compared to a fair value of $141.1 million, using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, with adjustments for duration, optionality, and risk profile. At December 31, 2011, long-term debt, including the current maturities, had a carrying value of $118.5 million, compared to the estimated fair value of $142.3 million. The valuation technique used to estimate the fair value of long-term debt would be considered Level 3 measurement.

 

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12.	Long-Term Debt

Our outstanding long-term debt is shown below:

 

		March 31,				December 31,
		2012				2011
(in thousands)
FPU secured first mortgage bonds (A):
9.57% bond, due May 1, 2018		$	6,350			$	6,348
10.03% bond, due May 1, 2018			3,492				3,492
9.08% bond, due June 1, 2022			7,959				7,958
Uncollateralized senior notes:
7.83% note, due January 1, 2015			6,000				6,000
6.64% note, due October 31, 2017			16,363				16,363
5.50% note, due October 12, 2020			18,000				18,000
5.93% note, due October 31, 2023			30,000				30,000
5.68% note, due June 30, 2026			29,000				29,000
Convertible debentures:
8.25% due March 1, 2014			1,098				1,134
Promissory note			170				186
Total long-term debt			118,432				118,481
Less: current maturities			(8,196	)			(8,196	)
Total long-term debt, net of current maturities		$	110,236			$	110,285

 

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

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

 

 

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations is designed to provide a reader of the financial statements with a narrative report on our financial condition, results of operations and liquidity. This discussion and analysis should be read in conjunction with the attached unaudited condensed consolidated financial statements and notes thereto and our Annual Report on Form 10-K, as amended, for the year ended December 31, 2011, including the audited consolidated financial statements and notes thereto.

Safe Harbor for Forward-Looking Statements

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

changes in environmental and other laws and regulations to which we are subject and environmental conditions of property that we now or may in the future own or operate;

 

•

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

 

•

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

 

•

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

 

•

growth in opportunities for our business units;

 

•

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

 

•

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

 

•

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

 

•

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

 

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•

the ability to manage, maintain and grow key customer relationships;

 

•

the ability to maintain and establish new key supply sources;

 

•

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

 

•

the effect of competition on our businesses;

 

•

the ability to construct facilities at or below estimated costs;

 

•

changes in technology affecting our advanced information services business; and

 

•

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

Introduction

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

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

enhancing marketing channels to attract new customers;

 

•

providing reliable and responsive customer service to retain existing customers;

 

•

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

 

•

maintaining a consistent and competitive dividend for shareholders; and

 

•

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

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

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

 

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Results of Operations for the Quarter Ended March 31, 2012

Overview and Highlights

Our net income for the quarter ended March 31, 2012 was $10.7 million, or $1.11 per share (diluted). This represents a decrease of $3.0 million, or $0.32 per share (diluted), compared to a net income of $13.7 million, or $1.43 per share (diluted), as reported for the same quarter in 2011.

 

										Increase
For the Three Months Ended March 31,		2012				2011				(decrease)
(in thousands except per share)
Business Segment:
Regulated Energy		$	14,798			$	16,233			$	(1,435	)
Unregulated Energy			5,154				8,591				(3,437	)
Other			121				15				106
Operating Income			20,073				24,839				(4,766	)
Other Income			196				22				174
Interest Charges			2,291				2,150				141
Income Taxes			7,251				8,964				(1,713	)
Net Income		$	10,727			$	13,747			$	(3,020	)
Earnings Per Share of Common Stock
Basic		$	1.12			$	1.44			$	(0.32	)
Diluted		$	1.11			$	1.43			$	(0.32	)

Highlights of our results in the first quarter of 2012 included:

 

•

Lower customer energy consumption directly attributable to warmer weather reduced gross margin by $4.0 million. Propane sales to bulk-delivery customers declined beyond the estimated weather impact due to the timing of deliveries, conservation and other factors, which further reduced gross margin by $587,000.

 

•

Amortization related to the recovery of the acquisition adjustment and merger-related costs in Florida increased other operating expenses by $587,000.

 

•

Growth from new natural gas distribution customers generated $562,000 in additional gross margin.

 

•

New natural gas transportation services generated $553,000 in additional gross margin.

 

•

Other items affecting the Company’s quarter-over-quarter results included:

 

•

$628,000 in additional gross margin generated from higher retail propane margins per gallon as a result of the retail pricing levels and market conditions in Florida;

 

•

A decrease in Xeron’s gross margin of $536,000 as a result of a 34-percent decrease in trading activity;

 

•

The absence in 2012 of two non-recurring items in the first quarter of 2011: a $575,000 gain for the proceeds received from an antitrust litigation settlement with a major propane supplier, partially offset by severance and pension settlement charges totaling $295,000; and

 

•

Additional legal costs of $243,000 related to an electric franchise dispute.

The following is a summary of key factors affecting our businesses and their impacts on our results during the current and future periods.

Weather. Weather affects customer energy consumption, especially the consumption by residential and certain commercial customers during the peak heating and cooling seasons. Natural gas, electricity and propane are all used for heating in our service territories and we use the number of heating degree-days (“HDD”) to analyze the weather impact. Only electricity is used for cooling and we use the number of cooling degree-days (“CDD”) to analyze the weather impact. A degree-day is the measure of the variation in the weather based on the extent to which the average daily temperature (from 10:00 am to 10:00 am next day) falls above or below 65 degrees Fahrenheit. Each degree of temperature above or below 65 degrees Fahrenheit is counted as one CDD or one HDD. We use 10-year historical averages to define the “normal” weather for this analysis.

 

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Our results for the quarter ended March 31, 2012 were negatively affected by significantly warmer weather, as we experienced a 23-percent (565 HDD) decrease in HDD on the Delmarva Peninsula and a 36-percent (185 HDD) decrease in HDD in Florida during the first quarter of 2012, compared to the same quarter in 2011. Comparing first quarter 2012 temperatures to normal, we had 21-percent (496 HDD) fewer HDD on the Delmarva Peninsula and 40-percent (224 HDD) fewer HDD in Florida. The first quarter of 2012 represents the warmest first quarter in the past 10 years on the Delmarva Peninsula and in Florida. We estimate that lower customer energy consumption directly affected by warmer weather reduced our gross margin by $4.0 million in the first quarter of 2012, compared to the same quarter in 2011. Compared to normal, we estimate that weather during the first quarter of 2012 reduced gross margin by $3.8 million.

During the first quarter of 2012, propane sales to bulk-delivery customers declined beyond the estimated weather impact, which reduced gross margin by $587,000. The timing of deliveries, conservation and other factors contributed to this decline.

CDD variations were not a significant factor during the first quarter.

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

Our results in the first quarter of 2012 included $1.1 million in additional gross margin generated by the natural gas distribution and transmission operations, compared to the same quarter in 2011. Most of the increase came from expansions and new services on the Delmarva Peninsula. Our Delmarva natural gas distribution operation generated $446,000 in additional gross margin due to net customer growth, $305,000 of which was related to commercial and industrial customers. Increased gross margin generated from commercial and industrial customers is due primarily to the addition of 12 large commercial and industrial customers since the beginning of 2011. These 12 customers are expected to generate annual gross margin of approximately $1.4 million in 2012, compared to $430,000 recorded in 2011. Two-percent growth in residential customers generated $141,000 in additional gross margin for the Delmarva natural gas distribution operation during the first quarter of 2012.

In response to increased demand for transportation service by its distribution affiliate, Eastern Shore completed mainline system expansion projects and commenced additional transportation services in November 2011 and March 2012. These services added 3,900 Dts per day of capacity, generating $249,000 in additional gross margin in the first quarter of 2012, and are expected to generate additional gross margin of $841,000 during the remainder of 2012.

Eastern Shore also generated $343,000 in additional gross margin as a result of two additional transportation service agreements with an existing industrial customer, one for the period from May 2011 to April 2021 for an additional 3,405 Dts per day and the second for the period from November 2011 to October 2012 for an additional 9,514 Dts per day. These new services are the result of an expansion of this customer’s industrial facility. The 10-year service from May 2011 to April 2021 generated $90,000 of gross margin in the first quarter of 2012 and is expected to generate an additional gross margin of $28,000 over last year in the remainder of 2012. The service associated with the one-year contract from November 2011 to October 2012 generated $253,000 in the first quarter of 2012 and is expected to generate an additional gross margin of $589,000 over last year during the remainder of 2012.

The following information highlights the key natural gas growth initiatives on the Delmarva Peninsula:

 

•

Lewes, Delaware—The Delmarva natural gas distribution operation commenced service to two industrial customers in December 2011. In response to this distribution expansion, Eastern Shore increased its mainline transportation service by 3,250 Dts per day in November 2011. These new distribution and transportation services generated over $376,000 in additional gross margin in the first quarter of 2012 and are expected to generate an additional $949,000 in gross margin during the remainder of 2012. The Delmarva natural gas distribution operation is currently pursuing other opportunities to provide natural gas service to residential and other commercial and industrial customers in the Lewes area.

 

•

Worcester County, Maryland—In August 2011, the Delmarva natural gas distribution operation entered into a new agreement to provide natural gas service to an existing industrial customer at two of its facilities located in southern Delaware. These facilities are in close proximity to Eastern Shore’s transportation mainline that is being constructed to bring natural gas service to Worcester County, Maryland. Distribution service to one of the facilities commenced in late March 2012, and service to the other facility is expected to commence in the second quarter of 2012. These new distribution services are expected to generate estimated annual gross margin equivalent to 415 residential customers. In response to the increased demand in southern Delaware, Eastern Shore increased its transportation service by 650 Dts per day in March 2012. Eastern Shore is currently further expanding its mainline capacity in response to future demand in Worcester County, Maryland. Once the expansion is complete in the second and third quarters of 2012, Eastern Shore is expected to commence additional transportation service for 2,350 Dts per day. These two new distribution and additional transportation services are expected to generate approximately $611,000 of additional gross margin in 2012 and estimated annual gross margin of $991,000 thereafter.

 

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•

Cecil County, Maryland – In November 2011, the Maryland PSC approved a franchise executed between the Company’s Maryland natural gas distribution division and the Board of County Commissioners of Cecil County, Maryland. The Delmarva natural gas distribution operation is expected to begin natural gas service in Cecil County in the latter half of 2012. In response to this anticipated natural gas expansion in Cecil County, Eastern Shore has undertaken a mainline expansion to provide additional transportation service of 4,070 Dts per day. The expansion will generate estimated annual gross margin of $882,000. Transportation service is expected to begin in September 2012 and generate $294,000 in gross margin in 2012.

 

•

Service to an electric generation plant in Dover, Delaware—On December 22, 2011, Eastern Shore entered into a Precedent Agreement with NRG Energy Center Dover LLC (“NRG”) to provide firm natural gas transportation service to NRG’s electric power generation plant in Dover, Delaware. Eastern Shore has previously provided interruptible service to NRG at this plant. To provide the firm service, Eastern Shore will construct new facilities at an estimated cost of $12.5 million to $15.0 million. The Precedent Agreement provides that upon satisfying certain conditions, Eastern Shore and NRG will sign a 15-year firm transportation service agreement for a maximum daily quantity of 13,440 Dts per day. This service is projected to commence in May 2013 and generate estimated annual gross margin of $2.4 to $2.8 million. If the necessary facilities are not operational on or before December 31, 2013, or if Eastern Shore is not able to provide the firm transportation service by utilizing other capacity, either Eastern Shore or NRG may terminate both the Precedent Agreement and the firm transportation service agreement. Eastern Shore and NRG are proceeding with obtaining the necessary governmental and regulatory approvals associated with this service.

Our Florida natural gas distribution operation also generated $116,000 of additional gross margin, primarily as a result of an one-percent growth in commercial and industrial customers. Although not reflected in the first quarter 2012 result, we are expanding natural gas service to Nassau County, Florida. In April 2012, the Florida PSC approved the firm transportation agreement between Peninsula Pipeline, and FPU. Under the firm transportation agreement, Peninsula Pipeline will provide natural gas transportation service to support FPU’s expansion of natural gas distribution service in Nassau County, Florida. Peninsula Pipeline began this service in April 2012 and is expected to generate estimated annual gross margin of $2.1 million, $1.5 million of which is expected to be recorded in 2012.

Rates and Regulatory Matters. In January 2012, the Florida PSC issued an order, approving the recovery of $34.2 million in acquisition adjustment and $2.2 million in merger-related costs in connection with the Company’s acquisition of FPU in 2009. The inclusion of the acquisition adjustment and merger-related costs in our rate base and the recovery of these assets through amortization expense will increase our earnings and cash flows above what FPU would have been able to achieve absent the regulatory approval. The acquisition adjustment and merger-related costs are amortized over 30 years and five years, respectively, beginning in November 2009. Based upon the effective date and outcome of the order, we recorded the amortization as an expense in 2012, which increased amortization expense by $588,000 in the first quarter of 2012. We expect to record $2.4 million ($1.4 million, net of tax) in amortization expense in 2012 and 2013, $2.3 million ($1.4 million, net of tax) in 2014 and $1.8 million ($1.1 million, net of tax) annually thereafter until 2039 related to these assets.

Propane Prices. Propane prices affect both retail and wholesale marketing margins. Our propane distribution operation usually benefits from rising propane prices by selling propane to its distribution customers based upon higher wholesale prices, while its average cost of inventory trails behind. Retail prices generally take into account replacement cost, along with other factors, such as competition and market conditions. When wholesale prices (replacement costs) increase, retail prices generally increase and our margins expand until the current wholesale price is fully reflected in the average cost of inventory. The opposite occurs when propane prices decline. Our propane wholesale marketing operation benefits from price volatility in the propane wholesale market by entering into trading transactions.

Our Delmarva propane distribution operation did not experience a significant variance in retail margins per gallon during the first quarter of 2012, compared to the same quarter of 2011. Our Florida propane distribution operation generated $628,000 in additional gross margin from higher retail margins per gallon as a result of the continued adjustment of its retail pricing in response to market conditions.

A 34-percent decrease in trading volume for Xeron, our propane wholesale marketing subsidiary, during the first quarter of 2012, compared to the same quarter in 2011, decreased gross margin by $536,000. High price volatility in the wholesale propane market during the first quarter of 2011 resulted in higher trading volume and profitability for Xeron. Lower price volatility during the first quarter of 2012, coupled with lower wholesale propane demand, due partially to warmer weather, reduced Xeron’s trading volume and gross margin.

 

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Advanced Information Services. BravePoint^®, Inc. (“BravePoint”), our advanced information services subsidiary, reported operating income of $8,000 in the first quarter of 2012, compared to an operating loss of $95,000 in the same quarter in 2011, due primarily to an increase in consulting activities. BravePoint continues to generate profits from its consulting, application programming and database services and recently executed an agreement to provide Business Intelligence solutions to a large customer, which may potentially generate revenue in excess of $1 million.

BravePoint continues to market its new products, ProfitZoom™ and Application Evolution™. BravePoint generated $293,000 in revenue from the sale of those two products and related services during the first quarter of 2012. To date, BravePoint has successfully implemented ProfitZoom™ for four customers in the fire suppression industry, and one additional customer has executed sales contracts with implementations scheduled in 2012. Application Evolution™ is being marketed to customers both in the fire suppression industry and other unrelated businesses. Ten customers are currently utilizing this product and two additional contracts have been executed for implementation of this product in 2012. These new contracts are expected to generate $546,000 in additional revenue in the remainder of 2012. Several other sales proposals are under consideration by other potential customers.

The following section also provides a more detailed analysis of our results by segment.

 

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Regulated Energy

 

										Increase
For the Three Months Ended March 31,		2012				2011				(decrease)
(in thousands, except degree-day and customer information)
Revenue		$	72,296			$	84,870			$	(12,574	)
Cost of sales			35,672				47,990				(12,318	)
Gross margin			36,624				36,880				(256	)
Operations & maintenance			14,854				14,292				562
Depreciation & amortization			4,810				4,132				678
Other taxes			2,162				2,223				(61	)
Other operating expenses			21,826				20,647				1,179
Operating Income		$	14,798			$	16,233			$	(1,435	)
Weather and Customer Analysis
Delmarva Peninsula
Heating degree-days (“HDD”):
Actual			1,880				2,445				(565	)
10-year average			2,376				2,376				—
Estimated gross margin per HDD		$	2,064			$	1,995			$	69
Per residential customer added:
Estimated gross margin		$	375			$	375			$	0
Estimated other operating expenses		$	113			$	111			$	2
Florida
HDD:
Actual			335				520				(185	)
10-year average			559				564				(5	)
Cooling degree-days:
Actual			185				80				105
10-year average			67				67				—
Residential Customer Information
Average number of customers:
Delmarva natural gas distribution			50,174				49,311				863
Florida natural gas distribution			62,252				61,546				706
Florida electric distribution			23,615				23,589				26
Total			136,041				134,446				1,595

Operating income for the regulated energy segment decreased by approximately $1.4 million, or nine percent, in the first quarter of 2012, compared to the same quarter in 2011. The decline in operating income reflected a decrease in gross margin of $256,000 and an increase in operating expenses of $1.2 million.

 

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Gross Margin

Gross margin for our regulated energy segment decreased by $256,000, or one percent, in the first quarter of 2012, compared to the same quarter in 2011. Warmer weather decreased gross margin by approximately $1.5 million, which was partially offset by additional gross margin generated by growth in our natural gas distribution and transmission operation.

Our Delmarva natural gas distribution operation experienced a decrease in gross margin of $587,000 in the first quarter of 2012, compared to the same quarter in 2011. The factors contributing to this decrease were as follows:

 

•

Warmer weather on the Delmarva Peninsula during the first quarter of 2012, compared to the same quarter in 2011, decreased customer consumption and reduced gross margin by $935,000 as HDD decreased by 565, or 23 percent on the Delmarva Peninsula. In addition, gross margin decreased by $154,000 due to decreased non-weather-related customer energy consumption.

 

•

Our Delmarva natural gas distribution operation generated an increase in gross margin of $446,000 due to customer growth in the first quarter of 2012, compared to the same quarter in 2011. Gross margin from commercial and industrial customers for the Delmarva natural gas distribution operation increased by $305,000 in the first quarter of 2012, due primarily to the addition of 12 large commercial and industrial customers since the beginning of 2011. These 12 customers are expected to generate gross margin of approximately $1.4 million in 2012, compared to $430,000 recorded in 2011. Included in these 12 customers are two industrial customers in Lewes, Delaware and one of the two industrial facilities in southern Delaware (part of the Worcester County expansion) previously discussed as key natural growth initiatives, which are expected to generate total gross margin of $444,000 in 2012. Two-percent growth in residential customers generated an additional $141,000 in gross margin for the Delmarva natural gas distribution operation.

Gross margin for our Florida natural gas distribution operation decreased by $439,000 in the first quarter of 2012, compared to the same quarter in 2011. The factors contributing to this decrease were as follows:

 

•

In Florida, warmer weather during the heating season decreased customer energy consumption and gross margin by $348,000 during the first quarter of 2012, compared to the same quarter in 2011, as HDD decreased by 185 or 36 percent.

 

•

Gross margin decreased by $69,000 in the first quarter of 2012, compared to the same quarter in 2011, due primarily to a decline in non-weather-related customer energy consumption.

 

•

A decline in fees and service revenues decreased gross margin by $86,000.

 

•

Partially offsetting these decreases was $116,000 in additional gross margin which was generated primarily as a result of a one-percent growth in commercial and industrial customers.

Our natural gas transmission operations achieved gross margin growth of $1.0 million in the first quarter of 2012, compared to the same quarter in 2011. The factors contributing to this increase were as follows:

 

•

Eastern Shore generated $343,000 in additional gross margin as a result of two additional transportation service agreements with an existing industrial customer; one for the period from May 2011 to April 2021 for an additional 3,405 Dts per day and the second for the period from November 2011 to October 2012 for an additional 9,514 Dts per day. These new services are the result of an expansion at this customer’s industrial facility. The service associated with the 10-year contract generated $90,000 of gross margin in the first quarter of 2012 and is expected to generate additional gross margin of $28,000 over last year during the remainder of 2012. The service associated with the one-year contract generated $253,000 in the first quarter of 2012 and is expected to generate additional gross margin of $589,000 over last year during the remainder of 2012.

 

•

Other mainline transportation services that commenced in November 2011 and March 2012, as a result of Eastern Shore’s system expansion projects, generated additional gross margin of $249,000. The new system expansion projects are primarily a result of the growth in our Delmarva natural gas distribution operation with new services added in Lewes and southern Delaware and eventually in Worcester County, Maryland, which are two of the key natural gas growth initiatives previously discussed. These expansions added 3,900 Dts per day of capacity and are expected to generate additional gross margin of $841,000 in the remainder of 2012.

 

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•

On January 24, 2012, the FERC approved the rate case settlement for Eastern Shore. Implementation of the new rates, effective July 2011, pursuant to this rate case settlement, generated $277,000 in additional gross margin in the first quarter of 2012, compared to the same quarter in 2011.

 

•

Increased interruptible sales to industrial customers generated an additional $206,000 in the first quarter of 2012, compared to the same quarter in 2011.

Gross margin for our Florida electric distribution operation decreased by $249,000 in the first quarter of 2012, compared to the same quarter in 2011, due primarily to lower energy consumption by customers as a result of warmer weather.

Other Operating Expenses

Other operating expenses for the regulated energy segment increased by $1.2 million, or five percent, in the first quarter of 2012, compared to the same quarter in 2011, due largely to the following factors:

 

•

$588,000 in increased amortization expense associated with FPU’s recovery of the acquisition adjustment and merger-related costs;

 

•

$243,000 in increased legal costs associated with an electric franchise dispute; and

 

•

$137,000 in higher depreciation expense and asset removal costs from capital investments made during 2011.

Unregulated Energy

 

										Increase
For the Three Months Ended March 31,		2012				2011				(decrease)
(in thousands, except degree-day data)
Revenue		$	44,887			$	58,750			$	(13,863	)
Cost of sales			32,724				42,755				(10,031	)
Gross margin			12,163				15,995				(3,832	)
Operations & maintenance			5,684				6,118				(434	)
Depreciation & amortization			838				789				49
Other taxes			487				497				(10	)
Other operating expenses			7,009				7,404				(395	)
Operating Income		$	5,154			$	8,591			($	3,437	)
Weather Analysis—Delmarva Peninsula
Actual HDD			1,880				2,445				(565	)
10-year average HDD			2,376				2,376				—
Estimated gross margin per HDD		$	2,869			$	2,415			$	454

The unregulated energy segment reported operating income of $5.2 million in the first quarter of 2012, a decrease of $3.4 million, or 40 percent, compared to the same quarter in 2011. A decrease in gross margin of $3.8 million was partially offset by a decrease in other operating expenses of $395,000.

Gross Margin

Gross margin for our unregulated energy segment decreased by $3.8 million, or 24 percent, in the first quarter of 2012, compared to the same quarter in 2011. Warmer weather decreased gross margin by approximately $2.5 million.

 

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Our Delmarva propane distribution operation reported a decrease in gross margin of $3.2 million, or 30 percent, in the first quarter of 2012, compared to the same quarter in 2011. The factors contributing to this decrease were as follows:

 

•

Unseasonably warm weather resulted in a decreased gross margin of $2.2 million during the first quarter of 2012, compared to the same quarter in 2011. Average temperatures (as measured by HDD) were 23 percent warmer than the same quarter in 2011, and 21 percent warmer than normal.

 

•

A decrease in propane sales to bulk-delivery customers beyond the weather impact reduced gross margin by $387,000. The timing of propane bulk deliveries, conservation and other factors contributed to this decline. Wholesale volumes decreased 16 percent in the first quarter of 2012, which resulted in a gross margin decrease of $135,000.

 

•

The absence of $575,000 in gross margin recorded in the first quarter of 2011 related to our share of proceeds received from an antitrust litigation settlement with a major propane supplier is reflected as a quarter-over-quarter decrease in gross margins.

The gross margin generated by our Florida propane distribution operation remained substantially unchanged in the first quarter of 2012, compared to 2011. The factors contributing to the recorded decrease of $25,000 were as follows:

 

•

Warm weather during the first quarter of 2012 resulted in a decrease in gross margin of $255,000. A decrease in propane deliveries to certain non-residential customers and wholesale sales also decreased gross margin by $200,000.

 

•

Our Florida propane distribution operation generated additional gross margin of $628,000 in the first quarter of 2012, compared to the same quarter in 2011, due to higher retail margins per gallon as it continued to adjust its retail pricing in response to local market conditions.

 

•

Our Florida propane distribution operation added 1,180 new customers as a result of the purchases of certain propane operating assets in December 2011 and February 2012. These customers generated additional gross margin of $98,000 in the first quarter of 2012. This increase was mostly offset by a decline in the number of existing customers.

 

•

A decrease in fees and service revenues decreased gross margin by $62,000. Lower income generated from a propane rail terminal agreement with a supplier to provide terminal and storage service also decreased gross margin by $71,000.

Xeron’s gross margin decreased by $536,000 in the first quarter of 2012, compared to the same quarter in 2011, as a result of a 34-percent decrease in trading activity. High price volatility in the wholesale propane market during the first quarter of 2011 resulted in higher trading volume and profitability for Xeron. Lower price volatility during the first quarter of 2012, coupled with lower wholesale propane demand, due partially to warmer weather, reduced Xeron’s trading volume and gross margin.

Gross margin generated by PESCO, our natural gas marketing subsidiary, remained substantially unchanged.

Merchandise sales in Florida decreased in the first quarter of 2012, compared to the same quarter in 2011, resulting in lower gross margin of $89,000.

Other Operating Expenses

Other operating expenses for the unregulated energy segment decreased by $395,000 in the quarter ended March 31, 2012, largely due to decreased incentive compensation of $422,000 resulting from lower operating results and vacant positions, and lower payroll costs of $144,000 related to reduced seasonal, temporary and overtime costs in our Delmarva operation. These decreases were partially offset by increased payroll and benefit costs of $95,000 in the Florida propane operation resulting from resources added to serve new territories.

 

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Other

 

										Increase
For the Three Months Ended March 31,		2012				2011				(decrease)
(in thousands)
Revenue		$	3,731			$	2,977			$	754
Cost of sales			1,869				1,534				335
Gross margin			1,862				1,443				419
Operations & maintenance			1,393				1,129				264
Depreciation & amortization			113				100				13
Other taxes			235				199				36
Other operating expenses			1,741				1,428				313
Operating Income—Other			121				15				106
Operating Income—Eliminations			—				—				—
Operating Income		$	121			$	15			$	106

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

Operating income for the “other” segment increased by approximately $106,000 in the first quarter of 2012, compared to the same quarter in 2011, which was attributable to a gross margin increase of $419,000, partially offset by an operating expense increase of $313,000.

Gross margin

Our “other” segment generated gross margin of $1.9 million during the first quarter, compared to $1.4 million for the same quarter of 2011 as a result of increased consulting revenues for BravePoint.

Other Operating expenses

Other operating expenses for our “other” segment increased by $313,000 in the first quarter of 2012, compared to the same quarter in 2011. $334,000 of this increase was recorded by BravePoint resulting from payroll and benefit costs for additional resources required to support consulting engagements.

Interest Expense

Total interest expense for the quarter ended March 31, 2012 increased by approximately $141,000, or seven percent, compared to the same quarter in 2011. The increase in interest expense is attributable primarily to an increase of $299,000 related to the $29 million long-term debt issuance of 5.68 percent unsecured senior notes on June 23, 2011, which were previously financed by Chesapeake’s short-term loan credit facilities. Partially offsetting this increase was a decrease of $169,000 in other long-term interest expense as scheduled repayments decreased the outstanding principal balance.

Income Taxes

Income tax expense was $7.3 million in the first quarter of 2012, compared to $9.0 million in the same quarter in 2011. The decrease in income tax expense was due to lower taxable income. Our effective income tax rate was 40.3 percent and 39.5 percent for the first quarter of 2012 and 2011, respectively.

 

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FINANCIAL POSITION, LIQUIDITY AND CAPITAL RESOURCES

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

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

We have budgeted $88.5 million for capital expenditures during 2012. This amount includes $75.9 million for the regulated energy segment, $3.1 million for the unregulated energy segment and $9.5 million for the “Other” segment. The amount for the regulated energy segment includes estimated capital expenditures for the following: natural gas distribution operations ($32.1 million), natural gas transmission operations ($40.4 million) and electric distribution operation ($3.4 million) for expansion and improvement of facilities. The amount for the unregulated energy segment includes estimated capital expenditures for the propane distribution operations for customer growth and replacement of equipment. The amount for the “Other” segment includes estimated capital expenditures of $515,000 for the advanced information services subsidiary with the remaining balance for improvements of various offices and operations centers, other general plant, computer software and hardware. We expect to fund the 2012 capital expenditures program from short-term borrowings, cash provided by operating activities, and other sources. The capital expenditures program is subject to continuous review and modification. Actual capital requirements may vary from the above estimates due to a number of factors, including changing economic conditions, customer growth in existing areas, regulation, new growth or acquisition opportunities and availability of capital.

Capital Structure

We are committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access capital markets when required. This commitment, along with adequate and timely rate relief for our regulated operations, is intended to ensure our ability to attract capital from outside sources at a reasonable cost. We believe that the achievement of these objectives will provide benefits to our customers, creditors and investors. The following presents our capitalization, excluding and including short-term borrowings, as of March 31, 2012 and December 31, 2011:

 

		March 31,								December 31,
		2012								2011
(in thousands)
Long-term debt, net of current maturities		$	110,236				31	%		$	110,285				31	%
Stockholders’ equity			248,144				69	%			240,780				69	%
Total capitalization, excluding short-term debt		$	358,380				100	%		$	351,065				100	%
		March 31,								December 31,
		2012								2011
(in thousands)
Short-term debt		$	15,656				4	%		$	34,707				9	%
Long-term debt, including current maturities			118,432				31	%			118,481				30	%
Stockholders’ equity			248,144				65	%			240,780				61	%
Total capitalization, including short-term debt		$	382,232				100	%		$	393,968				100	%

 

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Short-term Borrowings

Our outstanding short-term borrowings at March 31, 2012 and December 31, 2011 were $15.7 million and $34.7 million, respectively, at weighted average interest rates of 1.52 percent and 1.57 percent, respectively.

We utilize bank lines of credit to provide funds for our short-term cash needs to meet seasonal working capital requirements and to fund temporarily portions of the capital expenditure program. As of March 31, 2012, we had four unsecured bank lines of credit with two financial institutions for a total of $100.0 million. Two of these unsecured bank lines, totaling $60.0 million, are available under committed lines of credit. None of these unsecured bank lines of credit requires compensating balances. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks. We are currently authorized by our Board of Directors to borrow up to $85.0 million of short-term debt, as required, from these unsecured bank lines of credit.

Our outstanding borrowings under these unsecured bank lines of credit at March 31, 2012 and December 31, 2011 were $13.0 million and $30.5 million, respectively, at weighted average interest rates of 1.52 percent and 1.57 percent, respectively. In addition to the four unsecured bank lines of credit, we entered into a new short-term credit facility for $29.1 million with an existing lender in March 2010 to temporarily finance the early redemption of the 6.85 percent and 4.90 percent series of FPU’s secured first mortgage bonds. On June 23, 2011, we issued $29.0 million of 5.68 percent Chesapeake’s unsecured senior notes to repay the new short-term credit facility and permanently finance the FPU first mortgage bonds.

Cash Flows Provided By Operating Activities

Cash flows provided by operating activities were as follows:

 

For the Three Months Ended March 31,		2012				2011
(in thousands)
Net Income		$	10,727			$	13,747
Non-cash adjustments to net income			12,703				15,553
Changes in assets and liabilities			11,120				4,970
Net cash provided by operating activities		$	34,550			$	34,270

During the three months ended March 31, 2012 and 2011, net cash flow provided by operating activities was $34.6 million and $34.3 million, respectively, a period-over-period increase of $280,000. Significant operating activities reflected in the change in cash flows provided by operating activities were as follows:

 

•

Net income decreased by $3.0 million for the first three months of 2012 compared to the same period in 2011.

 

•

Net cash flows related to income taxes decreased by $1.8 million in the first three months of 2012, compared to the same period in 2011, due primarily to the change in the bonus depreciation rate allowed from 100 percent in 2011 to 50 percent in 2012.

 

•

Net cash flows from the changes in regulatory assets and liabilities decreased by approximately $3.0 million, due primarily to a reduction in fuel costs due and collected from rate payers and a refund of $1.3 million to customers by Eastern Shore as a result of its rate case settlement in January 2012.

 

•

Net cash flows from changes in accounts receivable and accounts payable were due primarily to collections and payments from our natural gas, electric and propane distribution operations. In addition, the timing of trading contracts entered into by our propane wholesale and marketing operation contributed to the changes in accounts receivable and accounts payable.

 

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Cash Flows Used in Investing Activities

Net cash flows used in investing activities totaled $12.8 million and $8.2 million during the three months ended March 31, 2012 and 2011, respectively. Cash utilized for capital expenditures was $14.7 million and $8.4 million for the first three months of 2012 and 2011, respectively.

Cash Flows Used by Financing Activities

Cash flows used in financing activities totaled $22.4 million and $25.7 million for the first three months of 2012 and 2011, respectively. Significant financing activities reflected in the change in cash flows used by financing activities were as follows:

 

•

During the first three months of 2012 we had a net repayment of $17.5 million under our line of credit agreements related to working capital, compared to $19.7 million during the same period in 2011, resulting in a period-over-period net cash increase of $2.2 million. Changes in cash overdrafts decreased by $1.2 million, resulting in a period-over-period net cash increase.

 

•

We paid $3.0 million and $2.8 million in cash dividends for the three months ended March 31, 2012 and 2011, respectively.

Off-Balance Sheet Arrangements

We have issued corporate guarantees to certain vendors of our subsidiaries, primarily the propane wholesale marketing subsidiary and the natural gas marketing subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. None of these subsidiaries has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in our financial statements when incurred. The aggregate amount guaranteed at March 31, 2012 was $28.6 million, with the guarantees expiring on various dates through February 2013.

In addition to the corporate guarantees, we have issued a letter of credit for $1.0 million, which expires on September 12, 2012, related to the electric transmission services for FPU’s northwest electric division. We have also issued a letter of credit to our current primary insurance company for $656,000, which expires on December 2, 2012, as security to satisfy the deductibles under our various insurance policies. Although we changed our primary insurance company, we still have an outstanding letter of credit for $725,000 to our former primary insurance company, which will expire on June 1, 2012. There have been no draws on these letters of credit as of March 31, 2012. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that the letters of credit will be renewed to the extent necessary in the future.

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

 

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Contractual Obligations

There has not been any material change in the contractual obligations presented in our 2011 Annual Report on Form 10-K, as amended, except for commodity purchase obligations and forward contracts entered into in the ordinary course of our business. The following table summarizes the commodity and forward contract obligations at March 31, 2012.

 

						Payments Due by Period
Purchase Obligations		Less than 1 year				1 - 3 years				3 - 5 years				More than 5 years				Total
(in thousands)
Commodities (1)		$	25,658			$	715			$	—			$	—			$	26,373
Propane (2)			10,178				—				—				—				10,178
Total Purchase Obligations		$	35,836			$	715			$	—			$	—			$	36,551

 

(1)

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

(2)	We have also entered into forward sale contracts in the aggregate amount of $6.2 million. See Part I, Item 3, “Quantitative and Qualitative Disclosures about Market Risk,” below, for further information.

Environmental Matters

As more fully described in Note 4, “Environmental Commitments and Contingencies,” to the unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q, we continue to work with federal and state environmental agencies to assess the environmental impact and explore corrective action at seven environmental sites. We believe that future costs associated with these sites will be recoverable in rates or through sharing arrangements with, or contributions by, other responsible parties.

OTHER MATTERS

Rates and Regulatory Matters

Our natural gas distribution operations in Delaware, Maryland and Florida and electric distribution operation in Florida are subject to regulation by their respective PSC; Eastern Shore is subject to regulation by the FERC; and Peninsula Pipeline is subject to regulation by the Florida PSC. At March 31, 2012, we were involved in rate filings and/or regulatory matters in each of the jurisdictions in which we operate. Each of these rate filings and/or regulatory matters is fully described in Note 3, “Rates and Other Regulatory Activities,” to the unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q.

Competition

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

 

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

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

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

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

Inflation

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

Recent Authoritative Pronouncements on Financial Reporting and Accounting

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market risk represents the potential loss arising from adverse changes in market rates and prices. Long-term debt is subject to potential losses based on changes in interest rates. Our long-term debt consists of fixed-rate senior notes, secured debt and convertible debentures. All of our long-term debt is fixed-rate debt and was not entered into for trading purposes. The carrying value of long-term debt, including current maturities, was $118.4 million at March 31, 2012, as compared to a fair value of $141.1 million, using a discounted cash flow methodology that incorporates a market interest rate that is based on published corporate borrowing rates for debt instruments with similar terms and average maturities with adjustments for duration, optionality, credit risk, and risk profile. We evaluate whether to refinance existing debt or permanently refinance existing short-term borrowing, based in part on the fluctuation in interest rates.

 

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Our propane distribution business is exposed to market risk as a result of propane storage activities and entering into fixed price contracts for supply. We can store up to approximately 5.4 million gallons of propane (including leased storage and rail cars) during the winter season to meet our customers’ peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause the value of stored propane to decline. To mitigate the impact of price fluctuations, we have adopted a Risk Management Policy that allows the propane distribution operation to enter into fair value hedges or other economic hedges of our inventory.

In August 2011, our propane distribution operation entered into a put option to protect against the decline in propane prices and related potential inventory losses associated with 630,000 gallons purchased for the propane price cap program in the upcoming heating season. This put option was exercised as the propane prices fell below the strike price of $1.445 per gallon in January through March of 2012, and we received $118,000 representing the difference between the market price and the strike price during those months. We had paid $91,000 to purchase the put option, and we accounted for it as a fair value hedge. The change in the fair value of the put option effectively reduced our propane inventory balance until when it was exercised, at which point the proceeds reduced cost of sales. There was no ineffective portion of this fair value hedge.

Our propane wholesale marketing operation is a party to natural gas liquids forward contracts, primarily propane contracts, with various third parties. These contracts require that the propane wholesale marketing operation purchase or sell natural gas liquids at a fixed price at fixed future dates. At expiration, the contracts are settled by the delivery of natural gas liquids to us or the counter-party or by “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 natural gas liquids deviate from fixed contract settlement prices. Market risk associated with the trading of futures and forward contracts is monitored daily for compliance with our Risk Management Policy, which includes volumetric limits for open positions. To manage exposures to changing market prices, open positions are marked up or down to market prices and reviewed daily by our oversight officials. In addition, the Risk Management Committee reviews periodic reports on markets and the credit risk of counter-parties, approves any exceptions to the Risk Management Policy (within limits established by the Board of Directors) and authorizes the use of any new types of contracts. Quantitative information on forward and futures contracts at March 31, 2012 is presented in the following tables.

 

		Quantity in				Estimated Market		Weighted Average
At March 31, 2012		Gallons				Prices		Contract Prices
Forward Contracts
Sale			4,936,000			$1.2350 — $1.3775		$	1.2819
Purchase			3,991,000			$1.1950 — $1.3350		$	1.2585

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

All contracts expire by the first quarter of 2013.

 

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At March 31, 2012 and December 31, 2011, we marked these forward and other contracts to market, using market transactions in either the listed or OTC markets, which resulted in the following assets and liabilities:

 

		March 31,				December 31,
(in thousands)		2012				2011
Mark-to-market energy assets, including put option		$	261			$	1,754
Mark-to-market energy liabilities		$	131			$	1,496

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Chief Executive Officer and Chief Financial Officer of the Company, with the participation of other Company officials, have evaluated our “disclosure controls and procedures” (as such term is defined under Rules 13a-15(e) and 15d-15(e), promulgated under the Securities Exchange Act of 1934, as amended) as of March 31, 2012. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2012.

Changes in Internal Control over Financial Reporting

During the quarter ended March 31, 2012, there was no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

Our business, operations, and financial condition are subject to various risks and uncertainties. The risk factors described in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K, as amended, for the year ended December 31, 2011, should be carefully considered, together with the other information contained or incorporated by reference in this Quarterly Report on Form 10-Q and in our other filings with the SEC in connection with evaluating the Company, our business and the forward-looking statements contained in this Report. Additional risks and uncertainties not known to us at present, or that we currently deem immaterial also may affect the Company. The occurrence of any of these known or unknown risks could have a material adverse impact on our business, financial condition, and results of operations.

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

 

		Total								Total Number of Shares				Maximum Number of
		Number of				Average				Purchased as Part of				Shares That May Yet Be
		Shares				Price Paid				Publicly Announced Plans				Purchased Under the Plans
Period		Purchased				per Share				or Programs (2)				or Programs (2)
January 1, 2012 through January 31, 2012 (1)			243			$	43.40				—				—
February 1, 2012 through February 29, 2012			—			$	—				—				—
March 1, 2012 through March 31, 2012			—			$	—				—				—
Total			243			$	43.40				—				—

 

(1)

Chesapeake purchased shares of stock on the open market for the purpose of reinvesting the dividend on deferred stock units held in the Rabbi Trust accounts for certain Directors and Senior Executives under the Deferred Compensation Plan. The Deferred Compensation Plan is discussed in detail in Item 8 under the heading "Notes to the Consolidated Financial Statements -Note M, Employee Benefit Plans" in our latest Annual Report on Form 10-K for the year ended December 31, 2011, as amended. During the quarter, 243 shares were purchased through the reinvestment of dividends on deferred stock units.

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

Item 3. Defaults upon Senior Securities

None.

Item 4. Mine Safety Disclosures

None.

 

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Item 5. Other Information

None.

Item 6. Exhibits

 

3.1		Amended and Restated Bylaws of Chesapeake Utilities Corporation, effective May 2, 2012.
31.1		Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, dated May 3, 2012.
31.2		Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, dated May 3, 2012.
32.1		Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated May 3, 2012.
32.2		Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated May 3, 2012.
101.INS*		XBRL Instance Document.
101.SCH*		XBRL Taxonomy Extension Schema Document.
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.

 

*

XBRL (Extensible Business Reporting Language) information is furnished and not filed for purposes of Section 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934. In accordance with Rule 406T of Regulation S-T, the XBRL information in Exhibit 101 of this Form 10-Q shall not be subject to the liability of Section 18 of the Securities Exchange Act of 1934 and shall not be part of any registration statement or other document filed under the Securities Act of 1933 or the Securities Exchange Act of 1934, except as shall be expressly set forth in specific reference in such filing.

 

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SIGNATURES

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

CHESAPEAKE UTILITIES CORPORATION

/S/ BETH W. COOPER

Beth W. Cooper

Senior Vice President and Chief Financial Officer

Date: May 3, 2012

 

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