UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended: December 31, 2007 2009
Commission File Number: 001-11590
Chesapeake Utilities Corporation
(Exact name of registrant as specified in its charter)
| | |
| State of Delaware | | 51-0064146 |
| | |
(State or other jurisdiction of
incorporation or organization) | | (I.R.S. Employer
Identification No.) |
| | |
State of Delaware 51-0064146
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
909 Silver Lake Boulevard, Dover, Delaware 19904
(Address of principal executive offices, including zip code)
302-734-6799
302-734-6799
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
| | |
| Title of each class | | Name of each exchange on which registered |
| | |
| Common Stock — par value per share $.4867 | | New York Stock Exchange, Inc. |
Title of each class Name of each exchange on which registered Common Stock - par value per share $.4867 New York Stock Exchange, Inc.
Securities registered pursuant to Section 12(g) of the Act:
8.25% Convertible Debentures Due 2014
(Title of class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [ ].o. No [X]þ.
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [ ].o. No [X]þ.
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]þ. No [ ].o.
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yeso. Noo.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendments to this Form 10-K. [X]
þ
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 the definitions of “accelerated filer,” “large accelerated filer” and “smaller reporting companycompany” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer [ ] Accelerated filer [X] Non-accelerated filer [ ] Smaller Reporting Company [ ]
| | | | | | |
| Large accelerated filero | | Accelerated filerþ | | Non-accelerated filero | | Smaller Reporting Companyo |
Indicate by a check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes [ ].o. No [X]þ.
The aggregate market value of the common shares held by non-affiliates of Chesapeake Utilities Corporation as of June 30, 2007,2009, the last business day of its most recently completed second fiscal quarter, based on the last trade price on that date, as reported by the New York Stock Exchange, was approximately $230.9$223.5 million.
As of February 29, 2008, 6,806,48728, 2010, 9,436,558 shares of common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the 20082010 Annual Meeting of Stockholders are incorporated by reference in Part III.
Chesapeake Utilities Corporation
Form 10-K
YEAR ENDED DECEMBER 31, 20072009
TABLE OF CONTENTS
GLOSSARY OF KEY TERMS
Frequently used abbreviations, acronyms, or terms used in this report:
Subsidiaries of Chesapeake Utilities Corporation
| | |
| BravePoint | | BravePoint, Inc., a wholly-owned subsidiary of Chesapeake Services Company, which is a wholly-owned subsidiary of Chesapeake |
| Chesapeake | | The Registrant, the Registrant and its subsidiaries, or the Registrant’s subsidiaries, as appropriate in the context of the disclosure |
| Company | | The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries, as appropriate in the context of the disclosure |
| ESNG | | Eastern Shore Natural Gas Company, a wholly-owned subsidiary of Chesapeake |
| FPU | | Florida Public Utilities Company, a new wholly-owned subsidiary of Chesapeake, effective October 28, 2009 |
| OnSight | | Chesapeake OnSight Services, LLC, a wholly-owned subsidiary of Chesapeake |
| PESCO | | Peninsula Energy Services Company, Inc., a wholly-owned subsidiary of Chesapeake |
| PIPECO | | Peninsula Pipeline Company, Inc., a wholly-owned subsidiary of Chesapeake |
| Sharp | | Sharp Energy, Inc., a wholly-owned subsidiary of Chesapeake and Sharp’s subsidiary, Sharpgas, Inc. |
| Xeron | | Xeron, Inc., a wholly-owned subsidiary of Chesapeake |
Regulatory Agencies
| | |
| Delaware PSC | | Delaware Public Service Commission |
| DOT | | United States Department of Transportation |
| EPA | | United States Environmental Protection Agency |
| FASB | | Financial Accounting Standards Board |
| FERC | | Federal Energy Regulatory Commission |
| FDEP | | Florida Department of Environmental Protection |
| Florida PSC | | Florida Public Service Commission |
| IRS | | Internal Revenue Service |
| Maryland PSC | | Maryland Public Service Commission |
| MDE | | Maryland Department of the Environment |
| PSC | | Public Service Commission |
| SEC | | Securities and Exchange Commission |
Chesapeake Utilities Corporation 2009 Form 10-K Page 1
| | |
| AOCI | | Accumulated Other Comprehensive Income |
| DSCP | | Directors Stock Compensation Plan |
| GSR | | Gas sales service rates |
| HDD | | Heating degree-days |
| Mcf | | Thousand Cubic Feet |
| MWH | | Megawatt Hour |
| MGP | | Manufactured Gas Plant |
| NYSE | | New York Stock Exchange |
| PIP | | Performance Incentive Plan |
| S&P 500 Index | | Standard & Poor’s 500 Index |
| SFAS | | Statement of Financial Accounting Standards |
Accounting Standards | | |
| ASC | | FASB Accounting Standards CodificationTM(Codification) |
| ASU | | FASB Accounting Standards Update |
| FSP | | Financial Accounting Standards Board Staff Position |
| GAAP | | Generally Accepted Accounting Principles |
Page 2 Chesapeake Utilities Corporation 2009 Form 10-K
References in this document to “Chesapeake,” “the Company,” “we,” “us” and “our” mean Chesapeake Utilities Corporation and/or its wholly ownedwholly-owned subsidiaries, as appropriate.appropriate in the context of the disclosure.
Safe Harbor for Forward-Looking Statements
Chesapeake Utilities Corporation has madeWe make statements in this Form 10-K that are considereddo not directly or exclusively relate to behistorical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. TheseYou can typically identify forward-looking statements are not mattersby the use of historical fact and are typically identified byforward-looking words, such as but not limited to, “believes,“project,” “expects,“believe,” “intends,“expect,” “plans,“anticipate,” and“intend,” “plan,” “estimate,” “continue,” “potential,” “forecast” or other similar expressions,words, or future or conditional verbs such as “may,” “will,” “should,” “would,” and“would” or “could.” These statements relate to matters such as customer growth, changes in revenues or gross margins, capital expenditures, environmental remediation costs, regulatory trendsrepresent our intentions, plans, expectations, assumptions and decisions, market risks associated with our propane operations, the competitive positionbeliefs about future financial performance, business strategy, projected plans and objectives of the Company and other matters. It is important to understand that these forward-lookingCompany. These statements are not guarantees but are subject to certainmany risks and uncertainties and otheruncertainties. In addition to the risk factors described under Item 1A “Risks Factors,” the following important factors, thatamong others, could cause actual future results to differ materially from those expressed in the forward-looking statements. The factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to those discussed in Item 1A, “Risk Factors.”statements:
| • | | state and federal legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures, and affect the speed at and degree to which competition enters the electric and natural gas industries (including deregulation); |
|
| • | | the outcomes of regulatory, tax, environmental and legal matters, including whether pending matters are resolved within current estimates; |
|
| • | | industrial, commercial and residential growth or contraction in our service territories; |
|
| • | | the weather and other natural phenomena, including the economic, operational and other effects of hurricanes and ice storms; |
|
| • | | the timing and extent of changes in commodity prices and interest rates; |
|
| • | | general economic conditions, including any potential effects arising from terrorist attacks and any consequential hostilities or other hostilities or other external factors over which we have no control; |
|
| • | | changes in environmental and other laws and regulations to which we are subject; |
|
| • | | the results of financing efforts, including our ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings and general economic conditions; |
|
| • | | declines in the market prices of equity securities and resultant cash funding requirements for our defined benefit pension plans; |
|
| • | | the creditworthiness of counterparties with which we are engaged in transactions; |
|
| • | | growth in opportunities for our business units; |
|
| • | | the extent of success in connecting natural gas and electric supplies to transmission systems and in expanding natural gas and electric markets; |
|
| • | | the effect of accounting pronouncements issued periodically by accounting standard-setting bodies; |
|
| • | | conditions of the capital markets and equity markets during the periods covered by the forward-looking statements; |
|
| • | | the ability to successfully execute, manage and integrate merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture; |
|
| • | | the ability to manage and maintain key customer relationships; |
|
| • | | the ability to maintain key supply sources; |
|
| • | | the effect of spot, forward and future market prices on our distribution, wholesale marketing and energy trading businesses; and |
|
| • | | the effect of competition on our businesses. |
Chesapeake Utilities Corporation 2009 Form 10-K Page 3
Item 1. Business.
(a)Overview
Chesapeake isWe are a diversified utility company engaged directly or through subsidiaries in natural gas distribution, transmission and marketing, propane distribution and wholesale marketing, advanced information servicesvarious energy and other related businesses. Chesapeake is a Delaware corporation that was formed in 1947. On October 28, 2009, we completed a merger with Florida Public Utilities Company (“FPU”), pursuant to which FPU became a wholly-owned subsidiary of Chesapeake. We operate in regulated energy businesses through our natural gas distribution divisions in Delaware, Maryland and Florida, natural gas and electric distribution operations in Florida through FPU, and natural gas transmission operations on the Delmarva Peninsula and Florida through our subsidiaries, Eastern Shore Natural Gas Company (“ESNG”) and Peninsula Pipeline Company, Inc. (“PIPECO”), respectively. Our unregulated businesses include natural gas marketing operation through Peninsula Energy Services Company, Inc. (“PESCO”); propane distribution operations through Sharp Energy, Inc. and its subsidiary Sharpgas, Inc. (collectively “Sharp”) and FPU’s propane distribution subsidiary, Flo-Gas Corporation; and propane wholesale marketing operation through Xeron, Inc. (“Xeron”). We also have an advance information services subsidiary, BravePoint, Inc. (“BravePoint”).
(b)Operating Segments
Chesapeake isAs a result of the merger with FPU, we changed our operating segments to better align with how the chief operating decision maker (our Chief Executive Officer) views the various operations of the Company. Our three operating segments are now composed of four operating segments:
the following:
· | • | | Natural Gas.Regulated Energy. The natural gasregulated energy segment includes regulated natural gas distribution, electric distribution and natural gas transmission operations. All operations in this segment are regulated, as to their rates and also a non-regulatedservices, by the Public Service Commission (“PSC”) having jurisdiction in each operating territory or by the Federal Energy Regulatory Commission (“FERC”) in the case of ESNG.
|
| • | | Unregulated Energy.The unregulated energy segment includes natural gas marketing, operation.propane distribution and propane wholesale marketing operations, which are unregulated as to their rates and services. |
· | • | | Propane.Other. The propane segment includes non-regulated propane distribution and wholesale marketing operations.
|
· | Advanced Information Services. The advanced information services segment provides domestic and international clients with information-technology-related business services and solutions for both enterprise and e-business applications.
|
· | Other. The other“Other” segment consists primarily of non-regulated operationsthe advanced information services operation, unregulated subsidiaries that own real estate leased to Chesapeake and certain corporate costs not allocated to other Company subsidiaries.operations.
|
(b) | Financial Information About Business Segments |
Our natural gas segment accounts for approximately 80 percent of Chesapeake’s consolidated operating income and approximately 86 percent of the consolidated net property plant and equipment. The following table shows the size of each of our operating segments based on operating income and net property, plant and equipment.equipment:
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Net Property, Plant | |
| (in thousands) | | Operating Income | | | & Equipment | |
| Regulated Energy | | $ | 26,900 | | | | 80 | % | | $ | 387,022 | | | | 89 | % |
| Unregulated Energy | | | 8,158 | | | | 24 | % | | | 37,900 | | | | 8 | % |
| Other | | | (1,322 | ) | | | -4 | % | | | 11,506 | | | | 3 | % |
| | | | | | | | | | | | | |
| Total | | $ | 33,736 | | | | 100 | % | | $ | 436,428 | | | | 100 | % |
| | | | | | | | | | | | | |
| | | | | | | | | Net Property, Plant | |
| (Thousands) | | Operating Income | | | & Equipment | |
| Natural Gas | | $ | 22,485 | | | | 80 | % | | $ | 224,661 | | | | 86 | % |
| Propane | | | 4,498 | | | | 16 | % | | | 29,363 | | | | 11 | % |
| Advanced information systems | | | 836 | | | | 3 | % | | | 419 | | | | < 1 | % |
| Other & eliminations | | | 295 | | | | 1 | % | | | 5,980 | | | | 2 | % |
| Total | | $ | 28,114 | | | | 100 | % | | $ | 260,423 | | | | 100 | % |
Additional financial information by business segment is included in Item 8 under the heading “Notes to the Consolidated Financial Statements — Note C.C, Segment Information.”
Page 4 Chesapeake Utilities Corporation 2009 Form 10-K
(i)Regulated Energy
(c) | Narrative Description of the Business |
(i)(a) Natural Gas
Chesapeake’s natural gasOur regulated energy segment performs natural gas distribution, transmission and marketing services for its customers. Chesapeake operates itsprovides natural gas distribution services as three divisions:in Delaware, Maryland and Florida, which are basedelectric distribution services in their respective service territories. These threeFlorida and natural gas transmission services in Delaware, Maryland, Pennsylvania and Florida.
Natural Gas Distribution
Our Delaware and Maryland natural gas distribution divisions serve approximately 62,90051,736 residential and commercial customers and 155 industrial customers in central and southern Delaware and Maryland’s Eastern ShoreShore. For the year ended December 31, 2009, operating revenues and parts of Florida. The Company’sdeliveries by customer class for our Delaware and Maryland distribution divisions were as follows:
| | | | | | | | | | | | | | | | | |
| | | Operating Revenues | | | Deliveries | |
| | | (in thousands) | | | (Mcfs) | |
| Residential | | $ | 51,309 | | | | 58 | % | | | 2,747,162 | | | | 36 | % |
| Commercial | | | 31,942 | | | | 36 | % | | | 2,693,724 | | | | 35 | % |
| Industrial | | | 3,696 | | | | 4 | % | | | 1,827,153 | | | | 24 | % |
| | | | | | | | | | | | | |
| Subtotal | | | 86,947 | | | | 98 | % | | | 7,268,039 | | | | 95 | % |
| Interruptible | | | 977 | | | | 1 | % | | | 373,825 | | | | 5 | % |
Other (1) | | | 1,291 | | | | 1 | % | | | — | | | | — | |
| | | | | | | | | | | | | |
| Total | | $ | 89,215 | | | | 100 | % | | | 7,641,864 | | | | 100 | % |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | |
| (1) | | Operating revenues from “Other” sources include unbilled revenue, rental of gas properties, and other miscellaneous charges. |
Chesapeake’s Florida natural gas transmission subsidiary, Eastern Shore distribution division provides unbundled natural gas distribution services (the delivery of natural gas separated from the sale of the commodity) to 13,268 residential and 1,176 commercial and industrial customers in 14 counties in Florida. For the year ended December 31, 2009, operating revenues and deliveries by customer class for our Florida distribution division were as follows:
| | | | | | | | | | | | | | | | | |
| | | Operating Revenues | | | Deliveries | |
| | | (in thousands) | | | (Mcfs) | |
| Residential | | $ | 3,682 | | | | 30 | % | | | 318,420 | | | | 2 | % |
| Commercial | | | 3,043 | | | | 25 | % | �� | | 1,151,071 | | | | 8 | % |
| Industrial | | | 4,260 | | | | 34 | % | | | 13,271,503 | | | | 90 | % |
Other(1) | | | 1,377 | | | | 11 | % | | | — | | | | — | |
| | | | | | | | | | | | | |
| Total | | $ | 12,362 | | | | 100 | % | | | 14,740,994 | | | | 100 | % |
| | | | | | | | | | | | | |
| | |
| (1) | | Operating revenues from “Other” sources include unbilled revenue, conservation revenue, fees for billing services provided to third-parties and other miscellaneous charges. |
Chesapeake Utilities Corporation 2009 Form 10-K Page 5
Our recent merger with FPU provides 51,536 additional residential, commercial and industrial natural gas distribution customers in seven counties in Florida, which have significantly expanded our existing natural gas distribution operations in Florida. For the period from the merger closing (October 28, 2009) to December 31, 2009, operating revenues and deliveries by customer class for these new customers added through the merger were as follows:
| | | | | | | | | | | | | | | | | |
| | | Operating Revenues | | | Deliveries | |
| | | (in thousands) | | | (Mcfs) | |
| Residential | | $ | 3,028 | | | | 27 | % | | | 180,572 | | | | 16 | % |
| Commercial | | | 4,722 | | | | 43 | % | | | 496,183 | | | | 45 | % |
| Industrial | | | 1,346 | | | | 12 | % | | | 320,680 | | | | 29 | % |
| | | | | | | | | | | | | |
| Subtotal | | | 9,096 | | | | 82 | % | | | 997,435 | | | | 90 | % |
Other(1) | | | 2,045 | | | | 18 | % | | | 111,742 | | | | 10 | % |
| | | | | | | | | | | | | |
| Total | | $ | 11,141 | | | | 100 | % | | | 1,109,177 | | | | 100 | % |
| | | | | | | | | | | | | |
| | |
| (1) | | Operating revenues from “Other” sources include unbilled revenue, under (over) recoveries of fuel cost, conservation revenue, other miscellaneous charges and adjustments for pass-through taxes. |
FPU’s total natural gas deliveries in the full calendar year 2009, including deliveries for the period prior to the merger, were 1,157,100 Mcfs, 2,942,800 Mcfs and 1,784,500 Mcfs for residential, commercial and industrial customers, respectively.
Electric Distribution
Electric distribution is a new regulated energy business added to the Company as a result of the FPU merger. FPU distributes electricity to 31,030 customers in five counties in northeast and northwest Florida. For the period from the merger closing (October 28, 2009) to December 31, 2009, operating revenues and deliveries by customer class for FPU’s electric distribution services were as follows:
| | | | | | | | | | | | | | | | | |
| | | Operating Revenues | | | Deliveries | |
| | | (in thousands) | | | (MWHs) | |
| Residential | | $ | 6,140 | | | | 50 | % | | | 43,435 | | | | 41 | % |
| Commercial | | | 6,273 | | | | 52 | % | | | 50,033 | | | | 47 | % |
| Industrial | | | 1,004 | | | | 8 | % | | | 9,700 | | | | 10 | % |
| | | | | | | | | | | | | |
| Subtotal | | | 13,417 | | | | 110 | % | | | 103,168 | | | | 98 | % |
Other(1) | | | (1,174 | ) | | | -10 | % | | | 2,572 | | | | 2 | % |
| | | | | | | | | | | | | |
| Total | | $ | 12,243 | | | | 100 | % | | | 105,740 | | | | 100 | % |
| | | | | | | | | | | | | |
| | |
| (1) | | Operating revenues from “Other” sources include unbilled revenue, under (over) recoveries of fuel cost, conservation revenue, other miscellaneous charges and adjustments for pass-through taxes. |
FPU’s total deliveries of electricity in the full calendar year 2009, including deliveries for the period prior to the merger, were 316,306 MWHs, 316,412 MWHs and 64,950 MWHs for residential, commercial and industrial customers, respectively.
Page 6 Chesapeake Utilities Corporation 2009 Form 10-K
Natural Gas Company (“Eastern Shore” or “ESNG”),Transmission
ESNG operates a 370-mile384-mile interstate pipeline system that transports natural gas from various points in Pennsylvania to the Company’sChesapeake’s Delaware and Maryland natural gas distribution divisions, as well as to other utilities and industrial customers in southern Pennsylvania, Delaware and on the Eastern Shore of Maryland. The Company, through its subsidiary, Peninsula Energy Services Company, Inc. (“PESCO”), also provides natural gas supply and supply management services in the State of Florida.
Natural Gas Distribution
Chesapeake distributes natural gas to residential, commercial and industrial customers in central and southern Delaware, the Salisbury and Cambridge areas on Maryland’s Eastern Shore, and parts of Florida. These activities are conducted through three utility divisions, one in Delaware, another in Maryland and a third in Florida.
Delaware and Maryland. Chesapeake’s Delaware and Maryland distribution divisions serve approximately 48,490 customers, of which approximately 48,290 are residential and commercial customers purchasing gas primarily for heating and cooking use. The remaining 200 customers are industrial. For the year 2007, operating revenues and deliveries by customer class were as follow:
| | | Operating Revenues | | | Deliveries | |
| | | (Thousands) | | | (MMcf's) | |
| Residential | | $ | 49,858 | | | | 47 | % | | | 2,586,517 | | | | 35 | % |
| Commercial | | | 29,430 | | | | 28 | % | | | 2,047,112 | | | | 28 | % |
| Industrial | | | 1,597 | | | | 2 | % | | | 612,631 | | | | 8 | % |
| Subtotal | | $ | 80,885 | | | | 77 | % | | | 5,246,260 | | | | 71 | % |
| Interruptible | | | 7,989 | | | | 7 | % | | | 1,023,866 | | | | 14 | % |
| Off-system | | | 16,819 | | | | 16 | % | | | 1,129,137 | | | | 15 | % |
| Total | | $ | 105,693 | | | | 100 | % | | | 7,399,263 | | | | 100 | % |
Florida. The Florida division distributes natural gas to approximately 14,250 residential and commercial and 100 industrial customers in the 13 Counties of Polk, Osceola, Hillsborough, Gadsden, Gilchrist, Union, Holmes, Jackson, Desoto, Suwannee, Liberty, Washington and Citrus. For the year 2007, operating revenues and deliveries by firm transportation customer class were as follow:
| | | Operating Revenues | | | Deliveries | |
| | | (Thousands) | | | (MMcf's) | |
| Residential | | $ | 3,612 | | | | 32 | % | | | 307,779 | | | | 5 | % |
| Commercial | | | 2,929 | | | | 26 | % | | | 1,067,539 | | | | 18 | % |
| Industrial | | | 4,744 | | | | 42 | % | | | 4,478,921 | | | | 77 | % |
| Total | | $ | 11,285 | | | | 100 | % | | | 5,854,239 | | | | 100 | % |
Natural Gas Transmission
The Company’s wholly-owned transmission subsidiary, Eastern Shore, owns and operates an interstate natural gas pipeline and provides open-access transportation services for affiliated and non-affiliated local distribution companies through an integrated gas pipeline system extending from southeastern Pennsylvania through Delaware to its terminus on the Eastern Shore of Maryland. Eastern ShoreESNG also provides swing transportation service and contract storage services. For the year 2007,ended December 31, 2009, operating revenues and deliveries by customer class for ESNG were as follow:follows:
| | | | | | | | | | | | | | | | | |
| | | Operating Revenues | | | Deliveries | |
| | | (in thousands) | | | (Mcfs) | |
| Local distribution companies | | $ | 19,699 | | | | 76 | % | | | 9,941,436 | | | | 38 | % |
| Industrial | | | 4,907 | | | | 19 | % | | | 14,471,109 | | | | 55 | % |
| Commercial | | | 1,336 | | | | 5 | % | | | 1,809,970 | | | | 7 | % |
Other(1) | | | 35 | | | | 0 | % | | | — | | | | — | |
| | | | | | | | | | | | | |
| Subtotal | | | 25,977 | | | | 100 | % | | | 26,222,515 | | | | 100 | % |
| Less: affiliated local distribution companies | | | (12,709 | ) | | | (49) | % | | | (5,578,918 | ) | | | (21) | % |
| | | | | | | | | | | | | |
| Total non-affiliated | | $ | 13,268 | | | | 51 | % | | | 20,643,597 | | | | 79 | % |
| | | | | | | | | | | | | |
| | |
| (1) | | Operating revenues from “Other” sources are from rental of gas properties. |
| | | Operating Revenues | | | Deliveries | |
| | | (Thousands) | | | (MMcf's) | |
| Local Distribution Companies | | $ | 19,354 | | | | 83 | % | | | 10,011,290 | | | | 52 | % |
| Industrial | | | 3,076 | | | | 13 | % | | | 7,793,128 | | | | 40 | % |
| Commercial | | | 856 | | | | 4 | % | | | 1,542,061 | | | | 8 | % |
| Total | | $ | 23,286 | | | | 100 | % | | | 19,346,479 | | | | 100 | % |
DuringIn 2005, Chesapeakewe formed a wholly-owned subsidiary, Peninsula Pipeline Company, Inc. (“PIPECO”),PIPECO to operate an intrastate pipeline to provide natural gas transportation services to industrial customers in the State of Florida natural gas transportation service as an intrastate pipeline. PIPECO did not have any activity in 2005 and 2006. On August 27,Florida. In December 2007, PIPECO filed with the Florida PSC its petition for approval of aPublic Service Commission (“Florida PSC”) approved PIPECO’s natural gas transmission pipeline tariff, in order to establishwhich established its operating rules and regulations. The Florida PSC approved the petition at its December 4, 2007 agenda conference.In January 2009, PIPECO will begin marketing its services to potential industrial customers in 2008.
Natural Gas Marketing
PESCO, a wholly-owned subsidiary, competes with regulated utilities and other unregulated third-party marketers to sell natural gas supplies directly to commercial and industrial customers in the State of Florida with the objective of earning a profit through competitively-priced contracts. PESCO does not own or operate anybegan providing natural gas transmission or distribution assets. The gas that PESCO sells is deliveredservices to retail customersa customer for a period of 20 years at a fixed monthly charge, through assets owned byan 8-mile pipeline located in Suwanee County, Florida, which PIPECO owns. For the Company’s regulated Florida distribution system and intrastate pipeline and four other regulated utilities’ local distribution systems. PESCO bills its customers through the billing services of the regulated utilities that deliver the gas, or directly, through its own billing capabilities.
Atyear ended December 31, 2007, PESCO served approximately 1,500 commercial2009, PIPECO had $264,000 in operating revenues under the contract.
Supplies, Transmission and industrial natural gas customers, and as of January 2008, PESCO began offering similar services to customers in the State of Delaware.
Storage
Gas Supplies, Firm Transportation and Storage Capacity
The Company believesWe believe that the availability of gas supply and transportation to its Delaware, Marylandtransmission of natural gas and Florida divisionselectricity is adequate under existing arrangements to meet the anticipated needs of their customers. The following discussion provides a summary of the gas supplies
Natural Gas Distribution
Our Delaware and pipeline transportation and storage capacities, stated in dekatherms (“Dts”), available to each of the Company’sMaryland natural gas operations.
The Delaware and Marylanddistribution divisions have both firm and interruptible transportation service contracts with four interstate “open access” pipelines,pipeline companies, including Eastern Shore, a wholly-owned subsidiary. Thethe ESNG pipeline. These divisions are directly interconnected with Eastern Shore,the ESNG pipeline, and are contractedhave contracts with interstate pipelines upstream of Eastern Shore. These interstate pipelines includeESNG, including Transcontinental Gas Pipe Line Corporation (“Transco”), Columbia Gas Transmission Corporation (“Columbia”) and Columbia Gulf Transmission Company (“Gulf”). The Transco and Columbia pipelines are directly interconnected with the ESNG pipeline. The Gulf pipeline is directly interconnected with the Columbia pipeline and indirectly interconnected with the ESNG pipeline. None of the upstream service providerspipelines is owned or operated by an affiliate of the Company. The Delaware and Maryland divisions use their firm transportation supply resources to meet a significant percentage of their projected demand requirements. In order to meet the difference between firm supplyrequirements and firm demand, the divisionsthey purchase natural gas supplies on the spot market from various suppliers.suppliers as needed to match firm supply and demand. This gas is transported by the upstream pipelines and delivered to the divisions’their interconnections with Eastern Shore. TheESNG. These divisions also have the capability to use propane-air peak-shaving to supplement or displace the spot market purchases.
Chesapeake Utilities Corporation 2009 Form 10-K Page 7
The following table shows the firm transmission and storage capacity that the Delaware and Maryland divisions currently have under contract with ESNG and pipelines upstream of the ESNG pipeline, including the respective contract expiration dates.
Delaware.
| | | | | | | | | | | |
| | | Firm transmission | | | | | | |
| | | capacity maximum | | | Firm storage | | | |
| | | peak-day daily | | | capacity maximum | | | |
| | | deliverability | | | peak-day daily | | | |
| Pipeline | | (Mcfs) | | | withdrawal (Mcfs) | | | Expiration |
| Transco | | | 20,699 | | | | 6,190 | | | Various dates between 2010 and 2028 |
| Columbia | | | 17,836 | | | | 7,946 | | | Various dates between 2011 and 2020 |
| Gulf | | | 850 | | | | — | | | Expires in 2014 |
| ESNG | | | 63,482 | | | | 4,006 | | | Various dates between 2010 and 2024 |
| Pipeline | Firm transportation capacity maximum peak-day daily deliverability (Dts) | Firm storage capacity maximum peak-day daily withdrawal (Dts) | Expiration |
| Transco | 11,356 | 6,407 | Various dates between 2008 and 2013 |
| Columbia | 3,460 | 8,224 | Various dates between 2010 and 2020 |
| Gulf | 880 | - | Expries in 2009 |
| Eastern Shore | 57,639 | 4,146 | Various dates between 2008 and 2022 |
| | | | | | | | | | | |
| | | Firm transmission | | | | | | |
| | | capacity maximum | | | Firm storage | | | |
| | | peak-day daily | | | capacity maximum | | | |
| | | deliverability | | | peak-day daily | | | |
| Pipeline | | (Mcfs) | | | withdrawal (Mcfs) | | | Expiration |
| Transco | | | 5,921 | | | | 2,373 | | | Various dates between 2010 and 2012 |
| Columbia | | | 6,473 | | | | 3,539 | | | Various dates between 2011 and 2018 |
| Gulf | | | 570 | | | | — | | | Expires in 2014 |
| ESNG | | | 19,834 | | | | 2,228 | | | Various dates between 2010 and 2023 |
The Delaware divisionand Maryland divisions currently hashave contracts with several suppliers for the purchase of firm natural gas supply in the amount of its capacitytheir capacities on the Transco and Columbia pipelines. The Delaware divisionThey also hashave contracts for firm peaking gas supplies to be delivered to its systemtheir systems in order to meet the differential between their capacities on the Delaware division’s capacity on Eastern ShoreESNG pipeline and capacitycapacities on pipelines upstream of Eastern Shore.ESNG. These supply contracts provide a maximum firm daily entitlement of 44,566 Dts,13,237 Mcfs and 2,029 Mcfs for the Delaware and Maryland divisions, respectively, delivered on the Transco, Columbia, and/or Gulf systems to Eastern ShoreESNG for redelivery to the divisionthese divisions under firm transportationtransmission contracts. These gas supply contracts have various expiration dates, and quantities may vary from day-to-dayday to day and month-to-month.month to month.
Maryland.
| Pipeline | Firm transportation capacity maximum peak-day daily deliverability (Dts) | Firm storage capacity maximum peak-day daily withdrawal (Dts) | Expiration |
| Trancso | 5,866 | 2,456 | Various dates between 2012 and 2013 |
| Columbia | 1,700 | 3,663 | Various dates between 2014 and 2018 |
| Gulf | 590 | - | Expires in 2009 |
| Eastern Shore | 19,428 | 2,306 | Various dates between 2008 and 2022 |
The Maryland division currently has contracts with several suppliers for the purchase of firmChesapeake’s Florida natural gas supply in the amount of its capacity on the Transco and Columbia pipelines. The Maryland division also has contracts for firm peaking gas supplies to be delivered to its system in order to meet the differential between the Maryland division’s capacity on Eastern Shore and capacity on pipelines upstream of Eastern Shore. These supply contracts provide a maximum firm daily entitlement of 12,816 Dts, delivered on the Transco, Columbia, and/or Gulf systems to Eastern Shore for redelivery to the division under firm transportation contracts. These gas supply contracts have various expiration dates, and quantities may vary from day-to-day and month-to-month.
Florida Division
The Floridadistribution division has firm transportationtransmission service contracts with Florida Gas Transmission Company (“FGT”) and Gulfstream Natural Gas System, LLC (“Gulfstream”). Pursuant to a program approved by the Florida Public Service Commission (“Florida PSC”),PSC, all of the capacity under these agreements has been released to various third parties,third-parties, including PESCO. Under the terms of these capacity release agreements, Chesapeake is contingently liable to FGT and Gulfstream, should any party that acquired the capacity through release fail to pay for the service.
Contracts by Chesapeake’s contractsFlorida natural gas distribution division with FGT include: (a) a contract, which expires inon July 31, 2010, for daily firm transportationtransmission capacity of 23,519 Dts22,901 Mcfs for the months of November through April, capacity of 20,123 Dts19,594 Mcfs for the months of May through September, and capacity of 22,105 Dts21,524 Mcfs for October; and (b) a contract for daily firm transportationtransmission capacity of 1,000 Dts974 Mcfs daily, which expires in 2015. Chesapeake’s contract with Gulfstream is for daily firm transportationtransmission capacity of 10,000 Dts9,737 Mcfs and expires in 2022.
Page 8 Chesapeake Utilities Corporation 2009 Form 10-K
FPU has firm transmission service contracts with FGT and firm transportation contracts with Florida City Gas (“FCG”) and Indiantown Gas Company (“IGC”). The additional contracts with FGT include (a) a contract which expires on July 2020, for daily firm transmission capacity of 26,500 Mcfs for the months of November through March, 22,411 Mcfs for the month of April, 9,211 Mcfs for the months of May through September and 9,314 Mcfs for the month of October; (b) a contract which expires in 2015 for daily firm transmission capacity of 10,286 Mcfs for the months of November through April and 4,360 Mcfs for the months of May through October; (c) a contract which expires in July 2020 for daily firm transmission capacity of 2,147 Mcfs for the months of November through March, 1,745 Mcfs for the month of April, 470 Mcfs for the months of May through September, and 896 Mcfs for the month of October; and (d) a contract for daily firm transmission capacity of 1,774 Mcfs with various partial expiration dates between 2016 and 2023. The contract with FCG, which expires in 2013, provides daily firm transportation capacity of 292 Mcfs on its Pioneer Pipeline. The contract with IGC, which expires in 2016, provides daily firm transportation capacity of 487 Mcfs on its distribution system.
Eastern ShoreFPU uses gas marketers and producers to procure all its gas supplies for its natural gas distribution operations. FPU also uses TECO Peoples Gas to provide wholesale gas sales service in areas distant from its interconnections with FGT.
Natural Gas Transmission
Eastern ShoreESNG has three contracts with Transco for a total of 7,292 Dts7,045 Mcfs of firm peak day storage entitlements and total storage capacity of 288,003 Dts,278,264 Mcfs, each of which expireexpires in 2013. Eastern ShoreESNG has retained these firm storage services in order to provide swing transportation service and firm storage service to those customers that have requested such service.service(s).
Electric Distribution
PESCO
PESCO currently has contracts with ConocoPhillips and British Petroleum (“BP”) for the purchase of firm natural gas supplies. The ConocoPhillips contract, which provides a maximum firm daily entitlement of 15,000 MMBtus, and the BP contract, which provides a maximum firm daily entitlement of 10,000 MMBtus, expires in May 2008. PESCO is currently in the process of obtaining and reviewing supply proposals from suppliers and anticipates executing agreements prior to the expiration of the existing contracts.
The Company believes that the availability of gas supply and transportation to its operations is adequate under existing arrangements to meet the anticipated needsOur electric distribution operation through FPU purchases all of its customers.wholesale electricity from two suppliers: Gulf Power Company and JEA (formerly known as Jacksonville Electric Authority). Both of these contracts are all requirements contracts that expire in December 2017. The JEA contract provides generation, transmission and distribution service to northeast Florida. The Gulf Power Company contract provides generation, transmission and distribution service to northwest Florida.
Competition
See discussion onof competition in Item 7 under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Competition.”
Rates and Regulation
Chesapeake’sOur natural gas and electric distribution divisionsoperations are subject to regulation by the Delaware, Maryland and Florida Public Service Commissions (“PSCs”)PSCs with respect to various aspects of their business, including the rates for sales and transportation to all customers in each respective jurisdiction. All of Chesapeake’sour firm distribution sales rates are subject to gasfuel cost recovery mechanisms, which match revenues with gas and electric supply and transportation costs and normally allow full recovery of such costs. Adjustments under these mechanisms, which are limited to such costs, require periodic filings and hearings with the state regulatory authority having jurisdiction.
Eastern ShoreESNG is subject to regulation by the Federal Energy Regulatory Commission (“FERC”) as an interstate pipeline. Thepipeline by the FERC, which regulates the terms and conditions of service and the rates Eastern ShoreESNG can charge for its transportationtransmission and storage services. PIPECO is subject to regulation by the Florida PSC.
Chesapeake Utilities Corporation 2009 Form 10-K Page 9
The following table shows the regulatory jurisdictions under which our regulated energy businesses currently operate, including the effective dates of the most recent full rate proceedings and the rates of return that were authorized therein:
| | | | | | | |
| | Regulatory | | Effective Date of | | Allowed | |
| Regulated Business | | Jurisdiction | | the Current Rates | | Rate of Return | |
| Chesapeake — Delaware Division | | Delaware PSC | | 9/3/2008 | | 10.25 | %(1) |
| Chesapeake — Maryland Division | | Maryland PSC | | 12/1/2007 | | 10.75 | %(1) |
| Chesapeake — Florida Division | | Florida PSC | | 1/14/2010 | | 10.80 | %(1) |
| FPU — Natural Gas | | Florida PSC | | 1/14/2010(3) | | 10.85 | %(1) |
| FPU — Electric | | Florida PSC | | 5/22/2008 | | 11.00 | %(1) |
| ESNG | | FERC | | 9/1/2007 | | 13.60 | %(2) |
| | |
| (1) | | Allowed return on equity. |
|
| (2) | | Allowed overall pre-tax, pre-interest rate of return. |
|
| (3) | | Effective date of the Order approving settlement agreement, which adjusted rates originally approved on June 4, 2009. |
PIPECO, which is regulated by the Florida PSC, currently provides service to one customer at a negotiated rate.
Management monitors the achieved raterates of return of its distribution divisions and Eastern Shoreeach of our regulated energy operations in order to ensure timely filing of rate cases.
Regulatory Proceedings
See discussion of regulatory activities in Item 7 under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Rate Filings and Other Regulatory Activities.”
Seasonality of Natural Gas and Electric Distribution Revenues
Revenues from the Company’sour residential and commercial natural gas distribution activities are affected by seasonal variations in weather conditions. Weather conditions, which directly influence the volume of natural gas sold and delivered. Specifically, customer demand substantially increases during the winter months, when natural gas is used for heating. Accordingly, the volumes sold for this purpose are directly affected by the severity of winter weather and can vary substantially from year to year. Sustained warmer-than-normal temperatures will tend to result in reducedreduce use of natural gas, while sustained colder-than-normal temperatures will tend to result in greater use. The Company measuresincrease consumption. We measure the relative impact of weather by using an accepted degree-day methodology. Degree-day data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature. 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) falls below 65 degrees Fahrenheit. Each degree of temperature below 65 degrees Fahrenheit is counted as one heating degree-day. Normal heating degree-days are based on the most recent 10-year average.
For the electric distribution operations in northeast and northwest Florida, hot summers and cold winters produce year-round electric sales that normally do not have large seasonal fluctuations.
In effortsan effort to stabilize the level of net revenues collected from customers the Company has begun to request Weather Normalization Adjustments (“WNA”) in its rate filings withregardless of weather conditions, we received approval from the Maryland Public Service Commission (“Maryland PSC”) on September 26, 2006 to implement a weather normalization adjustment for our residential heating and Delaware PSCs.smaller commercial heating customers. A WNA mechanismweather normalization adjustment is a billing adjustment mechanism that is designed to eliminate the effect of deviations from average seasonal temperatures on utility net revenues. On September 26, 2006, the Maryland PSC approved the Company’s proposal to implement a revenue normalization mechanism for its residential heating and smaller commercial heating customers. The Company also has a pending rate case application filed with the Delaware PSC, requesting among other things, to implement a WNA billing mechanism. For further discussion of these matters, refer to the discussion of regulatory activities in Item 7 under the heading “Management’s Discussion and Analysis — Regulatory Activities.”
Page 10 Chesapeake Utilities Corporation 2009 Form 10-K
(ii) Unregulated Energy
(i)(b) Propane
Chesapeake’s retailOur unregulated energy segment provides natural gas marketing, propane distribution group consists of: (1) Sharp Energy, Inc. (“Sharp Energy”), a wholly-owned subsidiary of Chesapeake, (2) Sharpgas, Inc. (“Sharpgas”), a wholly-owned subsidiary of Sharp Energy, and (3) Tri-County Gas Co., Inc. (“Tri-County”), a wholly-owned subsidiary of Sharp Energy. The propane wholesale marketing group consistsservices to customers.
Natural Gas Marketing
Our natural gas marketing subsidiary, PESCO, provides natural gas supply and supply management services to 2,123 customers in Florida and 11 customers on the Delmarva Peninsula. It 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. PESCO does not own or operate any natural gas transmission or distribution assets. The gas that PESCO sells is delivered to retail customers through affiliated and non-affiliated local distribution company systems and transmission pipelines. PESCO bills its customers through the billing services of Xeron, Inc.the regulated utilities that deliver the gas, or directly, through its own billing capabilities. For the year ended December 31, 2009, PESCO’s operating revenues and deliveries were as follows:
| | | | | | | | | | | | | | | | | |
| | | Operating Revenues | | | Deliveries | |
| | | (in thousands) | | | (Mcfs) | |
| Florida | | $ | 41,117 | | | | 72 | % | | | 7,066,144 | | | | 71 | % |
| Delmarva | | | 16,386 | | | | 28 | % | | | 2,818,844 | | | | 29 | % |
| | | | | | | | | | | | | |
| Total | | $ | 57,503 | | | | 100 | % | | | 9,884,988 | | | | 100 | % |
| | | | | | | | | | | | | |
PESCO currently has contracts with natural gas production companies for the purchase of firm natural gas supplies. These contracts provide a maximum firm daily entitlement of 35,000 Mcfs, and expire in May of 2010. PESCO is currently in the process of obtaining and reviewing proposals from suppliers and anticipates executing agreements prior to the end of the term of the existing contracts.
Included in PESCO’s operating revenue on the Delmarva Peninsula for 2009 was approximately $10.6 million of various natural gas spot sales and services to Valero Energy Corporation (“Xeron”Valero”), for its Delaware City refinery operation. We previously reported on November 25, 2009 in a wholly-owned subsidiary of Chesapeake.Form 8-K that Valero announced its intention to permanently shut down its Delaware City refinery. Spot sales are not predictable, and, therefore, are not included in our long-term financial plans or forecasts; nor do we anticipate sales to Valero in the future.
Propane is a form of liquefied petroleum gas, which is typically extracted from natural gas or separated during the crude oil refining process. Although propane is a gas at normal pressure, it is easily compressed into liquid form for storage and transportation. Propane is a clean-burning fuel, gaining increased recognition for its environmental superiority, safety, efficiency, transportability and ease of use relative to alternative forms of fossil fuels. Propane is sold primarily in suburban and rural areas, which are not served by natural gas distributors.
Chesapeake Utilities Corporation 2009 Form 10-K Page 11
During 2007,Sharp, our propane distribution operations served approximately 34,100 propanesubsidiary, serves 33,088 customers in central and southernthroughout Delaware, the Eastern Shore of Maryland and Virginia and southeastern Pennsylvania andPennsylvania. Sharp’s Florida operation offers propane distribution services to 1,941 customers in parts of Florida. After the merger with FPU, 1,642 customers previously served by Sharp’s Florida and delivered approximately 29.8 million retail and wholesale gallons of propane. The propane distribution business is affectedoperation are now being served by many factors, such as seasonality, the absence of price regulation, and competition among local providers.
FPU’s propane distribution operation in an effort to integrate operations. For the year 2007,ended December 31, 2009, operating revenues and number of customers for ourtotal gallons sold by Sharp’s Delmarva and Florida propane distribution operations were as follow:follows:
| | | | | | | | | | | | | | | | | |
| | | Operating Revenues | | | Total Gallons Sold | |
| | | (in thousands) | | | (in thousands) | |
| Delmarva | | $ | 54,850 | | | | 96 | % | | | 30,635 | | | | 97 | % |
| Florida | | | 2,357 | | | | 4 | % | | | 853 | | | | 3 | % |
| | | | | | | | | | | | | |
| Total | | $ | 57,207 | | | | 100 | % | | | 31,488 | | | | 100 | % |
| | | | | | | | | | | | | |
FPU has 13,651 propane distribution customers, including the customers previously served by Sharp’s propane distribution operation in Florida as previously discussed, which increased our propane customer base in Florida. For the period from the merger closing (on October 28, 2009) to December 31, 2009, operating revenue and total gallons delivered to these new customers were $3.0 million and 1.1 million gallons. FPU’s total propane deliveries in the full calendar year 2009, including the deliveries for the period prior to the merger, were 5.7 million gallons.
| | Operating Revenues | Total Gallons Sold | Average No. of |
| | (Thousands) | (Thousands) | Customers |
| Delmarva | 57,622 | 95% | 28,665 | 96% | 32,153 | 94% |
| Florida | 2,826 | 5% | 1,120 | 4% | 1,990 | 6% |
| Total | 60,448 | 100% | 29,785 | 100% | 34,143 | 100% |
Propane Wholesale MarketingMarketing.
In May 1998, Chesapeake acquired Xeron, a natural gas liquids trading company located in Houston, Texas. Xeronour propane wholesale marketing operation, markets propane to large, independent petrochemical companies, resellers and retail propane companies in the southeastern United States. The propane wholesale marketing business is affected by the propane wholesale price volatility and supply levels. Additional informationIn 2009, Xeron had operating revenues totaling approximately $2.3 million, net of the associated cost of propane sold. For further discussion on Xeron’s trading and wholesale marketing activities, market risks and the controls that limit and monitor Xeron’s risks, is included insee Item 7 under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk.”
Xeron does not own physical storage facilities or equipment to transport propane; however, it contracts for storage and pipeline capacity to facilitate the sale of propane on a wholesale basis.
The Company’sSupplies, Transportation and Storage
Our propane distribution operations purchase propane primarily from suppliers, including major oil companies, independent producers of natural gas liquids and from Xeron. Supplies of propane from these and other sources are readily available for purchase by the Company.purchase.
The Company’sOur propane distribution operations use trucks and railroad cars to transport propane from refineries, natural gas processing plants or pipeline terminals to itsour bulk storage facilities. The Company’s Delmarva-based propane distribution operation ownsWe own bulk propane storage facilities with an aggregate capacity of approximately 2.43.0 million gallons at 42 plant facilitiesvarious locations in Delaware, Maryland, Pennsylvania, Virginia and Virginia, located on real estate that is either owned or leased. The Company’s Florida-based propane distribution operation owns three bulk propane storage facilities with a total capacity of 66,000 gallons.Florida. From these storage facilities, propane is delivered primarily by “bobtail” trucks, owned and operated by the Company,us, to tanks located at the customers’ premises.
Xeron does not own physical storage facilities or equipment to transport propane; however, it contracts for storage and pipeline capacity to facilitate the sale of propane on a wholesale basis.
Competition
See discussion onof competition in Item 7 under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Competition.”
Rates and Regulation
TheNatural gas marketing, propane distribution and propane wholesale marketing activities are not subject to any federal or state pricing regulation. Transport operations are subject to regulations concerning the transportation of hazardous materials promulgated by the Federal Motor Carrier Safety Administration within the United States Department of Transportation (“DOT”) and enforced by the various states in which such operations take place. Propane distribution operations are also subject to state safety regulations relating to “hook-up” and placement of propane tanks.
Page 12 Chesapeake Utilities Corporation 2009 Form 10-K
The Company’s propane operations are subject to operating hazards normally associated with the handling, storage and transportation of combustible liquids, such as the risk of personal injury and property damage caused by fire. The Company carries general liability insurance in the amount of $35 million, but there is no assurance that such insurance will be adequate.
Seasonality of Propane Revenues
Revenues from the Company’sour propane distribution sales activities are affected by seasonal variations in weather conditions. Weather conditions directly influence the volume of propane sold and delivered to customers; specifically, customers’ demand substantially increases during the winter months when propane is used for heating. Accordingly, the propane volumes sold for this purpose are directly affected by the severity of winter weather and can vary substantially from year to year. Sustained warmer-than-normal temperatures will tend to result in reducedreduce propane use, while sustained colder-than-normal temperatures will tend to result in greater use.
increase consumption.
(iii)Other
(i)(c) Advanced Information Services
Chesapeake’sThe ”Other” segment consists primarily of our advanced information services segment consistssubsidiary, other unregulated subsidiaries that own real estate leased to Chesapeake and its subsidiaries and certain unallocated corporate costs. Certain corporate costs that have not been allocated to different operations consist of merger-related costs that have been expensed and have not been allocated because such costs are not directly attributable to the business unit operations.
Advanced Information Services
Our advanced information services subsidiary, BravePoint, Inc. (“BravePoint”), a wholly-owned subsidiary of the Company. BravePoint,is headquartered in Norcross, Georgia, and provides domestic and international clients with information-technology-related businessinformation technology services and solutions for both enterprise and e-business applications.
Competition
See discussion on competition in Item 7 under the heading “Management’s Discussion and Analysis — Competition.”
(i)(d)Other Subsidiaries
Skipjack, Inc. (“Skipjack”), Eastern Shore Real Estate, Inc. and Chesapeake Investment Company are wholly-owned subsidiaries of Chesapeake Service Company, which is a wholly-owned subsidiary of Chesapeake. Skipjack and Eastern Shore Real Estate, Inc. own and lease office buildings in Delaware and Maryland to affiliates of Chesapeake. Chesapeake Investment Company is an affiliated investment company registered in Delaware. During
(c) Other information about the quarter ended September 30, 2007, Chesapeake decided to close its distributed energy services subsidiary, Chesapeake OnSight Services, LLC.Business
(ii)(i) Capital Budget
A discussion of capital expenditures by business segment and capital expenditures for environmental remediation facilities is included in Item 7 under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”
(iii)(ii) Employees
As of December 31, 2007, Chesapeake2009, we had 445a total of 757 employees, including 185 in natural gas, 134 in propane and 85 in advanced information services. The remaining 41332 employees are considered general and administrative and include officerswho joined the Company as a result of the Company, treasury, accounting, internal audit, information technology, human resourcesrecent merger with FPU, 162 of whom are union employees represented by three labor unions: the International Brotherhood of Electrical Workers, the International Chemical Workers Union and other administrative personnel.United Food and Commercial Workers Union, all of whose collective bargaining agreements expire in 2010.
(iv)(iii) Financial Information about Geographic Areas
All of the Company’sour material operations, customers, and assets occur and are located in the United States.
(d) Available Information
As a public company, Chesapeake fileswe file annual, quarterly and other reports, as well as itsour annual proxy statement and other information, with the Securities and Exchange Commission (“SEC”). The public may read and copy any materials that the Company fileswe file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E.
, Washington, DC 20549-5546; and the public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.
The SEC also maintains an Internet site that contains reports, proxy and information statements and other information regarding the Company. The address of the SEC’s Internet website is www.sec.gov. Chesapeake makesWe make available, free of charge, on the Company’sour Internet website, itsour Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after such reports are electronically filed with or furnished to the SEC. The address of Chesapeake’sour Internet website is www.chpk.com. The content of this website is not part of this report.
Chesapeake hasUtilities Corporation 2009 Form 10-K Page 13
We have a Business Code of Ethics and Conduct applicable to all employees, officers and directors and a Code of Ethics for Financial Officers. Copies of the Business Code of Ethics and Conduct and the Financial Officer Code of Ethics are available on its internetour Internet website. ChesapeakeWe also adopted Corporate Governance Guidelines and Charters for the Audit Committee, Compensation Committee, and Corporate Governance Committee of the Board of Directors, each of which satisfies the regulatory requirements established by the SEC and the New York Stock Exchange (“NYSE”). The Board of Directors has also adopted “CorporateCorporate Governance Guidelines on Director Independence,” which conform to the NYSE listing standards on director independence. Each of these documents also is available on Chesapeake’sour Internet website or may be obtained by writing to: Corporate Secretary; c/o Chesapeake Utilities Corporation;Corporation, 909 Silver Lake Blvd.;, Dover, DE 19904.
If Chesapeake makeswe make any amendment to, or grantsgrant a waiver of, any provision of the Business Code of Ethics and Conduct or the Financial Officer Code of Ethics for Financial Officers applicable to itsour principal executive officer, president, principal financial officer, principal accounting officer or controller, the amendment or waiver will be disclosed within fivefour business days in a press release, by website disclosure, or by filing a current report on Form 8-K with the Company’s Internet website.SEC.
Our Chief Executive Officer certified to the NYSE on June 1, 2009 that, as of that date, he was unaware of any violation by Chesapeake of the NYSE’s corporate governance listing standards.
Item 1A. Risk Factors.
The following is a discussion of the primary financial, operational, regulatory and legal, and environmental risk factors that may affect the operations and/or financial performance of theour regulated and unregulated businesses of Chesapeake.businesses. Refer to the section entitled “Management’s“Management’s Discussion and Analysis of Financial Condition and Results of Operations” under Item 7 of this report for an additional discussion of these and other related factors that affect the Company’sour operations and/or financial performance.
Financial Risks
The financial, operational, regulatoryanticipated benefits of the merger with FPU may not be realized.
We entered into the merger with FPU with the expectation that the merger would result in various benefits, including, among other things, synergies, cost savings and legal,operating efficiencies. Achieving these synergies, cost savings and environmental factors thatoperating efficiencies cannot be assured and failure to achieve these benefits will adversely affect the operations and/or financialexpected future performance of the Company include:Company. In addition, the regulatory agencies that have jurisdiction over our regulated energy businesses and operations may require us to pass on some, or all, of the achieved cost savings to ratepayers.
Instability and volatility in the financial markets could have a negative impact on our growth strategy.
Financial Risks
InabilityOur business strategy includes the continued pursuit of growth, both organically and through acquisitions. To the extent that we do not generate sufficient cash from operations, we may incur additional indebtedness to access capitalfinance our growth. The turmoil experienced in the credit markets in 2008 and 2009 and its potential impact on the liquidity of major financial institutions may impairhave an adverse effect on our future growth.
Wecustomers and our ability to fund our business strategy through borrowings, under either existing or newly created arrangements in the public or private markets on terms we believe to be reasonable. Specifically, we rely on access to both short-term and longer-termlong-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flowflows from our operations. Currently, $65$40 million of the total $90$100 million of short-term lines of credit utilized to satisfy our short-term financing requirements are discretionary, uncommitted lines of credit. We utilize discretionary lines of credit to reduce the cost associated with these short-term financing requirements. We are committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access the capital markets when required. However, if we are not able to access capital at competitive rates, our ability to implement our strategic plan, undertake improvements and make other investments required for our future growth may be limited.
Page 14 Chesapeake Utilities Corporation 2009 Form 10-K
Unsound financial institutions could adversely affect the Company.
Our businesses have exposure to different industries and counterparties, and may periodically execute transactions with counterparties in the financial services industry, including brokers and dealers, commercial banks, investment banks and other institutional clients. These transactions may expose us to credit risk in the event of default of a counterparty or client. There can be no assurance that any such losses or impairments would not materially and adversely affect our businesses and results of operations.
A downgrade in our credit rating could adversely affect our access to capital markets.markets and our cost of capital.
Our ability to obtain adequate and cost effectivecost-effective capital depends on our credit ratings, which are greatly affected by our subsidiaries’ financial performance and the liquidity of financial markets. A downgrade in our current credit ratings could adversely affect our access to capital markets, as well as our cost of capital.
Debt covenantscovenant obligations, if triggered, may impactaffect our financial condition if triggered.condition.
Our long-term debt obligations and committed short-term lines of credit contain financial covenants related to debt-to-capital ratios and interest-coverage ratios. Failure to comply with any of these covenants could result in an event of default which, if not cured or waived, could result in the acceleration of outstanding debt obligations or the inability to borrow under certain credit agreements. Any such acceleration would cause a material adverse change in Chesapeake’sour financial condition.
The continuation of recent economic conditions could adversely affect our customers and negatively impact our financial results.
A changeThe slowdown in the U.S. economy, together with increased unemployment, mortgage and other credit defaults and significant decreases in the values of homes and investment assets, have adversely affected the financial resources of many domestic households. It is unclear whether governmental responses to these conditions will be successful in lessening the severity or duration of the current recession. As a result, our customers may use less natural gas, electricity or propane and it may become more difficult for them to pay their bills. This may slow collections and lead to higher than normal levels of accounts receivable, which in turn, could increase our financing requirements and result in higher bad debt expense.
Further changes in economic conditions and interest rates may adversely affect our results of operations and cash flows.
A continued downturn in the economies of the regions in which we operate which we cannot accurately predict, might adversely affect our ability to increase our customer basesbase and cash flows at the same rates by which they have grown in the recent past.historical rates. Further, an increase in interest rates, without the recovery of the higher cost of debt in the sales and/or transportation rates we charge our utility customers, could adversely affect future earnings. An increase in short-term interest rates would negatively affect our results of operations, which depend on short-term borrowinglines of credit to finance accounts receivable and storage gas inventories, and to temporarily finance capital expenditures.
Inflation may impact our results of operations, cash flows and financial position.
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. To help cope with the effects of inflation on our capital investments and returns, we seek rate reliefincreases from regulatory commissions for regulated operations and closely monitor the returns of our unregulated business operations. There can be no assurance that we will be able to obtain adequate and timely rate reliefincreases to offset the effects of inflation. To compensate for fluctuations in propane gas prices, we adjust our propane selling prices to the extent allowed by the market. However, thereThere can be no assurance, however, that we will be able to increase propane sales prices sufficiently to compensate fully for such fluctuations in the cost of propane gas to us.
Chesapeake Utilities Corporation 2009 Form 10-K Page 15
Our operations are exposed to market risks, beyond our control, which could adversely affect our financial results and capital requirements.
Our natural gas marketing operation and propane wholesale marketing operation are subject to market risks beyond their control, including market liquidity and commodity price volatility. Although we maintain a risk management policy, we may not be able to offset completely the price risk associated with volatile commodity prices, which could lead to volatility in earnings. Physical trading also has price risk on any net open positions at the end of each trading day, as well as volatility resulting from: (i) intra-day fluctuations of natural gas and/or propane prices, and (ii) daily price movements between the time natural gas and/or propane is purchased or sold for future delivery and the time the related purchase or sale is hedged. The determination of our net open position at the end of any trading day requires Xeron to make assumptions as to future circumstances, including the use of natural gas and/or propane by its customers in relation to its anticipated market positions. Because the price risk associated with any net open position at the end of such day may increase if the assumptions are not realized, we review these assumptions daily. Net open positions may increase volatility in our financial condition or results of operations if market prices move in a significantly favorable or unfavorable manner, because the timing of the recognition of profits or losses on the economic hedges for financial accounting purposes usually does not match up with the timing of the economic profits or losses on the item being hedged. This volatility may occur, with a resulting increase or decrease in earnings or losses, even though the expected profit margin is essentially unchanged from the date the transactions were consummated.
Our energy marketing subsidiaries have credit risk and credit requirements that may adversely affect our results of operations, cash flows and financial condition.
Our energy marketing subsidiaries extend credit to counterparties and continually monitor and manage collections aggressively. Each of these subsidiaries is exposed to the risk that it may not be able to collect amounts owed to it. If the counterparty to such a transaction fails to perform, and any underlying collateral is inadequate, we could experience financial losses. These subsidiaries are also dependent upon the availability of credit to buy propane and natural gas for resale or to trade. If financial market conditions decline generally, or the financial condition of these subsidiaries or of the Company declines, then the cost of credit available to these subsidiaries could increase. If credit is not available, or if credit is more costly, our results of operations, cash flows and financial condition may be adversely affected.
Current market conditions have had an adverse impact on the return on plan assets for our pension plans, which may require significant additional funding and adversely affect the Company’s cash flows.
We have pension plans that have been closed to new employees. The costs of providing benefits and related funding requirements of these plans are subject to changes in the market value of the assets that fund the plans. As a result of the extreme volatility and disruption in the domestic and international equity and bond markets in recent years, the asset values of Chesapeake’s and FPU’s pension plans declined by $2.4 million and $2.8 million, respectively, since 2008. The funded status of the plans and the related costs reflected in our financial statements are affected by various factors that are subject to an inherent degree of uncertainty, particularly in the current economic environment. Future losses of asset values may necessitate accelerated funding of the plans in the future to meet minimum federal government requirements. Downward pressure on the asset values of our pension plans may require us to fund obligations earlier than originally planned, which would have an adverse impact on our cash flows from operations, decrease borrowing capacity and increase interest expense.
Operational Risks
We may be unable to successfully integrate operations after the merger.
The merger between Chesapeake and FPU involves the integration of two companies that have previously operated independently. The difficulties of combining the companies’ operations include, among other things:
the necessity of coordinating geographically separated organizations, systems and facilities;
combining the best practices of the two companies, including operations, financial and administrative functions; and
integrating personnel with diverse business backgrounds and different contractual terms and conditions of employment.
Page 16 Chesapeake Utilities Corporation 2009 Form 10-K
The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of one or more of our businesses and the loss of key personnel. We will be subject to employee workforce factors, including loss of employees, availability of qualified personnel, collective bargaining agreements with unions and work stoppages that could affect our business and financial condition. Our management team comprised of key personnel from both Chesapeake and FPU has dedicated substantial efforts to integrating the businesses. Such efforts could divert management’s focus and resources from other strategic opportunities during the integration process. The diversion of management’s attention and any delays or difficulties encountered in connection with the merger and the integration of the two companies’ operations could result in the disruption of our ongoing businesses or inconsistencies in standards, controls, procedures and policies that adversely affect our ability to maintain relationships with customers, suppliers, employees and others with whom we have business dealings.
Fluctuations in weather may adversely affect our results of operations, cash flows and financial condition.
Our utilitynatural gas and propane distribution operations are sensitive to fluctuations in weather and weather conditions, which directly influence the volume of natural gas and propane sold and delivered by our utility and propane distribution operations.delivered. A significant portion of our utilitynatural gas and propane distribution operation revenues is derived from the salesales and deliverydeliveries of natural gas and propane to residential and commercial heating customers during the five-month peak heating season (November through March). If the weather is warmer than normal, we sell and deliver less natural gas and propane to customers, and earn less revenue. In addition, hurricanes or other extreme weather conditions could damage production or transportation facilities, which could result in decreased supplies of natural gas, propane and propane,electricity, increased supply costs and higher prices for customers.
Our electric operations, while generally less weather sensitive than natural gas and propane sales, are also affected by variations in general weather conditions and unusually severe weather.
The amount and availability of natural gas, electricity and propane supplies are difficult to predict; a substantial reduction in available supplies could reduce our earnings in those segments.
Natural gas, electricity and propane production can be affected by factors outside ofbeyond our control, such as weather, closings of generation facilities and refinery closings.refineries. If we are unable to obtain sufficient natural gas, electricity and propane supplies to meet demand, results in those segmentsbusinesses may be adversely affected.
We rely on a limited number of natural gas, electric and propane suppliers, the loss of which could have a materially adverse effect on our financial condition and results of operations.
Our natural gas distribution and marketing operations, electric distribution operation and propane operations have entered into various agreements with suppliers to purchase natural gas, electricity and propane to serve their customers. The loss of any significant suppliers or our inability to renew these contracts at favorable terms upon their expiration could significantly affect our ability to serve our customers and have a material adverse impact on our financial condition and results of operations.
We rely on having access to interstate natural gas pipelines’ transportationtransmission and storage capacity and electric transmission capacity; a substantial disruption or lack of growth in these services may impair our ability to meet customers’ existing and future requirements.
In order to meet existing and future customer demands for natural gas and electricity, we must acquire both sufficient natural gas supplies, and interstate pipeline transmission and storage capacity, and electric transmission capacity to serve such requirements. We must contract for reliable and adequate delivery capacity for our distribution systems while considering the dynamics of the interstate pipeline and storage capacity market,and electric transmission markets, our own on-system resources, as well as the characteristics of our markets. Chesapeake, along with other local natural gas distribution companiesOur financial condition and other participants in the industry, have raised concerns regardingresults of operations would be materially and adversely affected if the future availability of additional upstream interstate pipeline and storage capacity. This is a business issue which we must continuethese capacities were insufficient to manage as ourmeet future customer base grows.
Naturaldemands for natural gas and propane commodityelectricity. Currently, all of FPU’s natural gas is transported through one pipeline system. Any interruption to that system could adversely affect our ability to meet the demands of FPU’s customers and our earnings.
Chesapeake Utilities Corporation 2009 Form 10-K Page 17
Commodity price changes may affect the operating costs and competitive positions of our natural gas, electric and propane distribution operations, which may adversely affect our results of operations, cash flows and financial condition.
Natural Gas. Over the last four years, natural gas costs have increased significantly, due to increased demand, and have become more volatile, due to events such as the hurricane activity in 2005, which reduced the natural gas available from the Gulf Coast region and caused a spike in natural gas prices.Gas/Electric. Higher natural gas prices can result in significant increases insignificantly increase the cost of gas billed to our natural gas customers. Under our regulated gas cost recovery mechanisms, an increaseIncreases in the cost of gas duecoal and other fuels can significantly increase the cost of electricity billed to an increase in the price of the natural gas commodityour electric customers. Such cost increases generally hashave no immediate effect on our revenues and net income.income because of our regulated fuel cost recovery mechanisms. Our net income, however, may be reduced by higher expenses that we may incur for uncollectableuncollectible customer accounts and by lower volumes of natural gas and electricity deliveries as a result ofwhen customers reducingreduce their consumption. Therefore, increases in the price of natural gas, coal and other fuels can affect our operating cash flows and the competitiveness of natural gasgas/electricity as energy sources and consequently have an energy source.adverse effect on our operating cash flows.
Propane. Propane costs are subject to volatile changes as a result of product supply or other market conditions, including weather and economic and political factors affecting crude oil and natural gas supply or pricing. Such cost changes can occur rapidly and can affect profitability. There is no assurance that we will be able to pass on propane cost increases fully or immediately, particularly when propane costs increase rapidly. Therefore, average retail sales prices can vary significantly from year to year as product costs fluctuate in response to propane, fuel oil, crude oil and natural gas commodity market conditions. In addition, in periods of sustained higher commodity prices, declines in retail sales volumes because ofdue to reduced consumption and increased amounts of uncollectible accounts may adversely affect net income.
Our propane inventory is subject to inventory risk, which may adversely affect our results of operations and financial condition.
Our propane distribution operations own bulk propane storage facilities, with an aggregate capacity of approximately 3.0 million gallons. We purchase and store propane based on several factors, including inventory levels and the price outlook. We may purchase large volumes of propane at current market prices during periods of low demand and low prices, which generally occur during the summer months. Propane is a commodity, and, as such, its unit price is subject to volatile fluctuations in response to changes in supply or other market conditions. We have no control over these market conditions. Consequently, the unit price of the propane that we purchase can change rapidly over a short period of time. The market price for propane could fall below the price at which we made the purchases, which would adversely affect our profits or cause sales from that inventory to be unprofitable. In addition, falling propane prices may result in inventory write-downs as required by U.S. generally accepted accounting principles (“GAAP”) if the market price of propane falls below our weighted average cost of inventory, which could adversely affect net income.
Operating events affecting public safety and the reliability of Chesapeake’sour natural gas and electric distribution systemsystems could adversely affect the results of operations, cash flows and financial condition and cash flows.
condition.Chesapeake’sOur business is exposed to operational events, such as major leaks, mechanical problems and accidents, that could affect the public safety and reliability of itsour natural gas distribution and transmission systems, significantly increase costs and cause loss of customer confidence. The occurrence of any such operational events could adversely affect the results of operations, financial condition and cash flows. If Chesapeake iswe are unable to recover from customers, through the regulatory process, all or some of these costs and itsour authorized rate of return on these costs, this also could adversely affect the results of operations, financial condition and cash flows.
Our electric operation is subject to various operational risks, including accidents, outages, equipment breakdowns or failures, or operations below expected levels of performance or efficiency. Problems such as the breakdown or failure of electric equipment or processes and interruptions in service which would result in performance below expected levels of output or efficiency, particularly if extended for prolonged periods of time, could have a materially adverse effect on our financial condition and results of operations.
Page 18 Chesapeake Utilities Corporation 2009 Form 10-K
Because we operate in a competitive environment, we may lose customers to competitors.competitors which could adversely affect our results of operations, cash flows and financial condition.
In ourNatural Gas. Our natural gas marketing business, weoperations compete with third-party suppliers to sell natural gas to commercial and industrial customers. In ourOur natural gas transportationtransmission and distribution operations our competitors includecompete with interstate pipelines when our transmission and/or distribution customers are located close enough to the transmission company’sa competing pipeline to make direct connections economically feasible. Failure to retain and grow our customer base in the natural gas operations would have an adverse effect on our financial condition, cash flows and results of operations.
Electric. While there is active wholesale power sales competition in Florida, our retail electric business through FPU has remained substantially free from direct competition. Changes in the competitive environment caused by legislation, regulation, market conditions or initiatives of other electric power providers, particularly with respect to retail competition, could adversely affect our results of operations, cash flows and financial condition.
Propane.Our propane distribution operations compete with several other propane distributors, primarily on the basis of service and price, emphasizing reliability of service and responsiveness.price. Some of our competitors have significantly greater resources. The retail propane industry is mature, and we foresee modest growth in total demand. Given this limited growth, we expect that year-to-year industry volumes will be principally affected by weather patterns. Therefore, ourOur ability to grow the propane distribution business is contingent upon execution of our community gas systems strategy to capturecapturing additional market share, expanding new service territories, and to employ servicesuccessfully utilizing pricing programs that retain and grow our customer base. Any failureFailure to retain and grow our customer base in our propane gas operations would have an adverse effect on our results.
results of operations, cash flows and financial condition.
TheOur propane wholesale marketing operation competesoperations will compete against various marketers, many of which have significantly greater resources and are able to obtain price or volumetric advantages.
The advanced information services business faces significant competition from a number of larger competitors having substantially greater resources available to them to compete on the basis of technological expertise, reputation and price.
Changes in technology may adversely affect our advanced information services segment’ssubsidiary’s results of operations, cash flows and financial condition.
Our advanced information services segmentBravePoint participates in a market that is characterized by rapidly changing technology and accelerating product introduction cycles. The success of our advanced information services segmentoperation depends upon our ability to address the rapidly changing needs of our customers by developing and supplying high-quality, cost-effective products, product enhancements and services, on a timely basis, and by keeping pace with technological developments and emerging industry standards. There is no assurance that we will be able to keep up with technological advancements to the degree necessary to keep our products and services competitive.
Our energy marketing subsidiaries have credit risk and credit requirements that may adversely affect our results of operations, cash flows and financial condition.
Xeron, our propane wholesale and marketing subsidiary, and PESCO, our natural gas marketing subsidiary, extend credit to counter-parties. While we believe Xeron and PESCO utilize prudent credit policies, each of these subsidiaries is exposed to the risk that it may not be able to collect amounts owed to it. If the counter-party to such a transaction fails to perform, and any underlying collateral is inadequate, we could experience financial losses.
Xeron and PESCO are also dependent upon the availability of credit to buy propane and natural gas for resale or to trade. If financial market conditions decline generally, or the financial condition of these subsidiaries or of the Company, declines, then the cost of credit available to these subsidiaries could increase. If credit is not available, or if credit is more costly, our results of operations, cash flows and financial condition may be adversely affected.
Our use of derivative instruments may adversely affect our results of operations.
Fluctuating commodity prices may affect our earnings and financing costs. Ourcosts because our propane distribution and wholesale marketing segmentsoperations use derivative instruments, including forwards, futures, swaps and puts, to hedge price risk. In addition, we have utilized in the past, and may decide, after further evaluation, to continue to utilize derivative instruments to hedge price risk for our Delaware and Maryland divisions, as well as PESCO.risk. While we have a risk management policy and operating procedures in place to control our exposure to risk, if we purchase derivative instruments that are not properly matched to our exposure, our results of operations, cash flows, and financial conditionscondition may be adversely affected.
Changes in customer growth may affect earnings and cash flows.
Chesapeake’sOur ability to increase its gross margins in itsour regulated energy and unregulated propane distribution businesses is dependent upon growth in the newresidential construction housing market, adding new commercial and industrial customers and conversion of customers to natural gas, electricity or propane from other fuel sources. Slowdowns in these markets couldhave and will continue to adversely affect the Company’sour gross margin in itsour regulated energy or propane distribution businesses, its earnings and cash flows.
Chesapeake’sOur businesses are capital intensive, and the costs of capital projects may be significant.
Chesapeake’sOur businesses are capital intensive and require significant investments in internal infrastructure projects. Our results of operations and financial condition could be adversely affected if we do not pursue or are unable to manage such capital projects effectively or if we do not receive full recovery of such capital costs is not permitted in future regulatory proceedings.
Chesapeake Utilities Corporation 2009 Form 10-K Page 19
Our facilities and operations could be targets of acts of terrorism. Our natural gas and electric distribution, natural gas transmission and propane storage facilities may be targets of terrorist activities that could disrupt our ability to meet customer requirements. Terrorist attacks may also disrupt capital markets and our ability to raise capital. A terrorist attack on our facilities, or those of our suppliers or customers, could result in a significant decrease in revenues or a significant increase in repair costs, which could adversely affect our results of operations, financial position and cash flows.
- The risk of terrorism and political unrest and the current hostilities in the Middle East may adversely affect the economy and the price and availability of propane, refined fuels, electricity and natural gas.
Terrorist attacks, political unrest and the current hostilities in the Middle East may adversely affect the price and availability of propane, refined fuels and natural gas, as well as our results of operations, our ability to raise capital and our future growth. The impact that the foregoing may have on our industry in general, and on us in particular, is not known at this time. An act of terror could result in disruptions of crude oil, electricity or natural gas supplies and markets, and our infrastructure facilities could be direct or indirect targets. Terrorist activity may also hinder our ability to transport/transmit propane, electricity and natural gas if our means of supply transportation, such as rail, power grid or pipeline, become damaged as a result of an attack. A lower level of economic activity following such events could result in a decline in energy consumption, which could adversely affect our revenues or restrict our future growth. Instability in the financial markets as a result of terrorism could also affect our ability to raise capital. Terrorist activity and hostilities in the Middle East could likely lead to increased volatility in prices for propane, refined fuels, electricity and natural gas. We maintain insurance policies with insurers in such amounts and with such coverage and deductibles as we believe are reasonable and prudent. There can be no assurance, however, that such insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that such levels of insurance will be available in the future at economical prices.
Operational interruptions to our natural gas transmission and natural gas and electric distribution activities, caused by accidents, malfunctions, severe weather (such as a major hurricane), a pandemic or acts of terrorism, could adversely impact earnings.
Inherent in natural gas transmission and natural gas and electric distribution activities are a variety of hazards and operational risks, such as leaks, ruptures, fires, explosions and mechanical problems. If they are severe enough or if they lead to operational interruptions, they could cause substantial financial losses. In addition, these risks could result in the loss of human life, significant damage to property, environmental damage and impairment of our operations. The location of pipeline, storage, transmission and distribution facilities near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering places, could increase the level of damages resulting from these risks. The occurrence of any of these events could adversely affect our results of operations, cash flows and financial condition.
Our regulated energy business will be at risk if franchise agreements are not renewed.
Our regulated natural gas and electric distribution operations hold franchises in each of the incorporated municipalities that require franchise agreements in order to provide natural gas and electricity. Our natural gas and electric distribution operations are currently in negotiations for franchises with certain municipalities for new service areas and renewal of some existing franchises. Ongoing financial results would be adversely impacted from the loss of service to certain operating areas within our electric or natural gas territories in the event that franchise agreements were not renewed.
A strike, work stoppage or a labor dispute could adversely affect our results of operation.
We are party to collective bargaining agreements with various labor unions at some of our Florida operations. A strike, work stoppage or a labor dispute with a union or employees represented by a union could cause interruption to our operations. If a strike, work stoppage or other labor dispute were to occur, our results could be adversely affected.
Page 6 - -20 Chesapeake Utilities Corporation 2009 Form 10-K
Regulatory and Legal Risks
Regulation of the Company, including changes in the regulatory environment, may adversely affect our results of operations, cash flows and financial condition.
The Delaware, Maryland and Florida PSCs regulate our natural gas distribution operations; Eastern Shore, our natural gas transmission subsidiary,utility operations in those states. ESNG is regulated by the FERC. These commissions set the rates that we can charge customers for services subject to their regulatory jurisdiction. Our ability to obtain timely future rate increases and rate supplements to maintain current rates of return depends on regulatory approvals, and there can be no assurance that our divisions and Eastern Shoreregulated operations will be able to obtain such approvals or maintain currently authorized rates of return.
We are dependent upon construction of new facilities to support future growth in earnings in our natural gas and electric distribution and interstate pipelinenatural gas transmission operations.
Construction of new facilities required to support future growth is subject to various regulatory and developmental risks, including but not limited to: (a) our ability to obtain necessary approvals and permits byfrom regulatory agencies on a timely basis and on terms that are acceptable to us; (b) potential changes in federal, state and local statutes and regulations, including environmental requirements, that prevent a project from proceeding or increase the anticipated cost of the project; (c) inability to acquire rights-of-way or land rights on a timely basis on terms that are acceptable to us; (d) lack of anticipated future growth in available natural gas and electricity supply; and (e) insufficient customer throughput commitments.
We are subject to operating and litigation risks that may not be fully covered by insurance.
Our operations are subject to the operating hazards and risks normally incidental to handling, storing, transportingtransporting/ transmitting and delivering natural gas, electricity and propane to end users. As a result, we are sometimes a defendant in legal proceedings arising in the ordinary course of business. We maintain insurance policies with insurers in such amounts and with such coverages and deductibles asthe amount of $50 million covering general liabilities of the Company, which we believe are reasonable and prudent. There can be no assurance, however, that such insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that such levels of insurance will be available in the future at economical prices.
We have recorded significant amounts of goodwill and regulatory assets prior to obtaining a rate order. An adverse outcome could result in an impairment of those assets.
The merger with FPU resulted in approximately $33.4 million in purchase premium which is currently recorded as goodwill. We also incurred approximately $3.0 million in merger-related costs, $1.5 million of which was deferred as a regulatory asset. We will be seeking regulatory approval to include these amounts in future rates in Florida. Other utilities in Florida, including Chesapeake and FPU in the past, have been successful in recovering similar costs by demonstrating benefits to customers attributable to the business combination. The ultimate outcome of such regulatory proceedings will depend on various factors, including but not limited to, our ability to achieve the anticipated benefits of the merger, the future regulatory environment in Florida and the future results of our Florida regulated operations. If we are not successful in obtaining regulatory approval to recover these costs in future rates, we will be required to perform impairment tests of goodwill and regulatory assets, the results of which could be an impairment of all or part of the goodwill and/or regulatory assets in the future.
Environmental Risks
Costs of compliance with environmental laws may be significant.
We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These evolving laws and regulations may require expenditures over a long period of time to control environmental effects at current and former operating sites, including former manufactured gas plant (“MGP”) sites that we have acquired from third parties.third-parties. Compliance with these legal obligations requires us to commit capital. If we fail to comply with environmental laws and regulations, even if such failure is caused by factors beyond our control, we may be assessed civil or criminal penalties and fines.
Chesapeake Utilities Corporation 2009 Form 10-K Page 21
To date, we have been able to recover, through regulatory rate mechanisms, the costs associated with the remediation of former manufactured gas plantMGP sites. However, thereThere is no guarantee, however, that we will be able to recover future remediation costs in the same manner or at all. A change in our approved rate mechanisms for recovery of environmental remediation costs at former manufactured gas plantMGP sites could adversely affect our results of operations, cash flows and financial condition.
Further, existing environmental laws and regulations may be revised, or new laws and regulations seeking to protect the environment may be adopted and be applicable to us. Revised or additional laws and regulations could result in additional operating restrictions on our facilities or increased compliance costs, which may not be fully recoverable.
We may be exposed to certain regulatory and financial risks related to climate change.
Climate change is receiving ever increasing attention from scientists, legislators and regulators alike. The debate is ongoing as to the extent to which our climate is changing, the potential causes of this change and its potential impacts. Some attribute global warming to increased levels of greenhouse gases, including carbon dioxide, which has led to significant legislative and regulatory efforts to limit greenhouse gas emissions.
There are a number of legislative and regulatory proposals to address greenhouse gas emissions, which are in various phases of discussion or implementation. The outcome of federal and state actions to address global climate change could result in a variety of regulatory programs, including potential new regulations, additional charges to fund energy efficiency activities, or other regulatory actions. These actions could:
result in increased costs associated with our operations;
increase other costs to our business;
affect the demand for natural gas, electricity and propane; and
impact the prices we charge our customers.
Any action taken by federal or state governments mandating a substantial reduction in greenhouse gas emissions could have far-reaching and significant impacts on the energy industry. We cannot predict the potential impact of such laws or regulations on our future consolidated financial condition, results of operations or cash flows.
Pending environmental matters, particularly with respect to FPU’s site in West Palm Beach, Florida, may have a materially adverse effect on the Company and our results of operations.
We have participated in the investigation, assessment or remediation of environmental matters with respect to certain of our properties and we believe the Company has certain exposures at six former MGP sites. Those sites are located in Salisbury, Maryland, and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the Maryland Department of the Environment (“MDE”) regarding a seventh former MGP site located in Cambridge, Maryland. The Key West, Pensacola, Sanford and West Palm Beach sites are related to FPU, for which we assumed any existing and future contingencies in the merger with FPU.
Pursuant to a consent order that FPU entered into with the Florida Department of Environmental Protection (the “FDEP”) prior to our merger with FPU, FPU is obligated to assess and remediate environmental impacts to soil and groundwater resulting from operation of the former West Palm Beach MGP. Following completion of the assessment task, FPU retained a consultant to perform a feasibility study to evaluate appropriate remedies for the site to respond to the reported environmental impacts. The feasibility study was performed and subsequently revised as a result of additional testing conducted at the site and extensive discussions with FDEP. The revised feasibility study evaluates several alternative remedies for the site. Discussions with FDEP are continuing, regarding selection of an appropriate remedy for the West Palm Beach site. Our current estimate of total remediation costs and expenses, including legal and consulting expenses, for the West Palm Beach site based on the likely remedy we believe will be approved by FDEP is between $7.8 million and $19.4 million; however, actual costs may be higher or lower than such range based upon the final remedy required by FDEP.
Page 22 Chesapeake Utilities Corporation 2009 Form 10-K
As of December 31, 2009, we had recorded $531,000 in environmental liabilities related to Chesapeake’s MGP sites in Maryland and Winter Haven, Florida, representing our estimate of the future costs associated with those sites. We had recorded approximately $1.7 million in assets for future recovery of environmental costs to be received from our customers through our approved rates. As of December 31, 2009, we had recorded approximately $12.3 million in environmental liabilities related to FPU’s MGP sites in Florida, primarily related to the West Palm Beach site. Such amount represents our estimate as of December 31, 2009, of the future costs associated with those sites, although FPU is approved to recover its environmental costs up to $14.0 million from insurance and customers through approved rates. Of the approximately $12.3 million recorded as environmental liabilities related to FPU’s MGP sites in Florida as of December 31, 2009, we have recovered approximately $5.7 million of environmental costs from insurance and customers through rates, and have recorded approximately $6.6 million in assets for future recovery of environmental costs to be received from FPU’s customers through approved rates.
The costs and expenses we incur to address environmental issues at our sites may have a material adverse effect on our results of operations and earnings to the extent that such costs and expenses exceed the amounts we have accrued as environmental reserves or that we are otherwise permitted to recover from customers through rates,. At present, we believe that the amounts accrued as environmental reserves and that we are otherwise permitted to recover from customers through rates are sufficient to fund the pending environmental liabilities described above.
None.
Item 2. PropertiesProperties.
(a)General
The Company ownsWe own offices and operatesoperate facilities in the following locations: Pocomoke, Salisbury, Cambridge and Princess Anne, Maryland; Dover, Seaford, Laurel and Georgetown, Delaware; Lecanto, Virginia; and West Palm Beach, DeBary, Inglis, Marianna, Lantana, Lauderhill, Fernandina Beach and Winter Haven, Florida. Chesapeake rentsWe rent office space in Dover, and Ocean View, and South Bethany, Delaware; Jupiter, Fernandina and Lecanto, Florida; Chincoteague and Belle Haven, Virginia; Easton, and Salisbury, Maryland; Honey Brook and Allentown, Pennsylvania; Houston, Texas; and Norcross, Georgia. In general, the Company believeswe believe that its propertiesour offices and facilities are adequate for the uses for which they are employed.
(b)Natural Gas Distribution
(b) | Natural Gas Distribution |
ChesapeakeOur Delmarva natural gas distribution operation owns over 1,0331,102 miles of natural gas distribution mains (together with related service lines, meters and regulators) located in itsour Delaware and Maryland service areas. Our Florida natural gas distribution operations, including Chesapeake’s Florida division and FPU in its service areas, and 741own 2,404 miles of natural gas distribution mains (and related equipment). Additionally, we have adequate gate stations to handle receipt of the gas in its central Florida service areas. Chesapeakeeach of the distribution systems. We also ownsown facilities in Delaware and Maryland, which it useswe use for propane-air injection during periods of peak demand.
(c)Natural Gas Transmission
(c) | Natural Gas Transmission |
Eastern ShoreESNG owns and operates approximately 370384 miles of transmission pipelines,pipeline, extending from supply interconnects at Parkesburg, Pennsylvania; Daleville, Pennsylvania; and Hockessin, Delaware, to approximately 7880 delivery points in southeastern Pennsylvania, Delaware and the eastern shoreEastern Shore of Maryland.
PIPECO owns and operates approximately eight miles of transmission pipeline in Suwanee County, Florida.
(d) | Propane Distribution and Wholesale Marketing |
(d)Electric DistributionThe company’sCompany’s electric distribution operation owns and operates 20 miles of electric transmission line located in northeast Florida and 1,125 miles of electric distribution line located in northeast and northwest Florida.
Chesapeake Utilities Corporation 2009 Form 10-K Page 23
(e)Propane Distribution and Wholesale Marketing
Our Delmarva-based propane distribution operation owns bulk propane storage facilities, with an aggregate capacity of approximately 2.4 million gallons, at 42 plant facilities in Delaware, Maryland, Pennsylvania and Virginia, located on real estate that is either owned or leased. The Company’sleased by the Company. Our Florida-based propane distribution operation owns three21 bulk propane storage facilities with a total capacity of 66,000642,000 gallons. Xeron does not own physical storage facilities or equipment to transport propane; however, it leases propane storage capacity and pipeline capacity.capacity from non-affiliated third-parties.
(f)Lien
All of the properties owned by FPU are subject to a lien in favor of the holders of its first mortgage bonds securing its indebtedness under its Mortgage Indenture and Deed of Trust. FPU owns offices and operates facilities in the following locations: DeBary, Inglis, Marianna, Lantana, Lauderhill and Fernandina, Florida. FPU’s natural gas distribution operation owns 1,637 miles of natural gas distribution mains (and related equipment) in its service areas. FPU’s electric distribution operation owns and operates 20 miles of electric transmission line located in northeast Florida and 1,125 miles of electric distribution line located in northeast and northwest Florida. FPU’s propane distribution operation owns 18 bulk propane storage facilities with a total capacity of 576,000 gallons located in south and central Florida.
Item 3. Legal ProceedingsProceedings.
The Company and its subsidiaries are currently involved in various legal actions and claims arising in the normal course of business. The Company is also involved in certain administrative proceedings before various governmental or regulatory agencies concerning rates. In the opinion of management, the ultimate disposition of these current proceedings will not have a material effect on ourthe Company’s consolidated financial position.position and results of operations.
See discussion of environmental commitments and contingencies in Item 8 under the heading “Notes to the Consolidated Financial Statements — Note M.O, Environmental Commitments and Contingencies.”
Item 4. Submission of Matters to a Vote of Security Holders.
A special meeting of the shareholders of the Company was held on October 22, 2009, to consider and vote upon the following proposals:
None | (1) | | A proposal related to adoption of the merger agreement and approval of the merger with Florida Public Utilities Company; |
| (2) | | A proposal relating to the issuance of Chesapeake common stock in the merger; and |
| (3) | | A proposal to approve adjournments or postponements of the special meeting, if necessary, to permit further solicitation of proxies if there are not sufficient votes at the end of the time in the special meeting to approve the above proposals. |
The proposals were approved as follows:
| | | | | | | | | | | | | |
| | | Votes | | | Votes Against | | | | |
| | | For | | | or Withheld | | | Abstentions | |
| Adoption of the merger agreement and approval of the merger | | | 5,186,617 | | | | 85,243 | | | | 27,204 | |
| Issuance of Chesapeake common stock in the merger | | | 5,186,617 | | | | 85,243 | | | | 27,204 | |
| Approve adjournment or postponement | | | 4,846,740 | | | | 411,960 | | | | 40,365 | |
There were no broker non-votes.
Page 24 Chesapeake Utilities Corporation 2009 Form 10-K
Item 4A. Executive Officers of the Registrant.
Set forth below are the names, ages, and positions of executive officers of the registrant at December 31, 2007, with their recent business experience. The age of each officer is as of the filing date of filing this report.
| | | | | | |
| Name | | Age | | Position |
| John R. Schimkaitis | | | 62 | | | Vice Chairman and Chief Executive Officer |
| Michael P. McMasters | | | 51 | | | President and Chief Operating Officer |
| Beth W. Cooper | | | 43 | | | Senior Vice President and Chief Financial Officer |
| Stephen C. Thompson | | | 49 | | | Senior Vice President and President, ESNG |
| Joseph Cummiskey | | | 38 | | | Vice President and President, PESCO |
John R. Schimkaitis (age 60) Mr. Schimkaitis is PresidentVice Chairman and Chief Executive Officer of Chesapeake and its subsidiaries. Mr. Schimkaitis assumed the role of Chief Executive Officer on January 1, 1999. He has served as President since 1997. Mr. Schimkaitis previously served as President, and Chief Operating Officer, Executive Vice President, Senior Vice President, Chief Financial Officer, Vice President, Treasurer, Assistant Treasurer and Assistant Secretary of Chesapeake.
Michael P. McMasters (age 49) is President and Chief Operating Officer of Chesapeake. Mr. McMasters isassumed the role of President effective March 1, 2010. He has served as Chief Operating Officer since September of 2008. Prior to these appointments, Mr. McMasters served as Senior Vice President since 2004 and Chief Financial Officer of Chesapeake Utilities Corporation. He was appointed Senior Vice President in 2004 and has served as Chief Financial Officer since December 1996. He has previously held the positions of Vice President, Treasurer, Director of Accounting and Rates, and Controller. From 1992 to May 1994, Mr. McMasters was employed as Director of Operations Planning for Equitable Gas Company.
Stephen C. Thompson (age 47) Mr. Thompson is President of Eastern Shore Natural Gas Company andBeth W. Cooper was appointed as Senior Vice President of Chesapeake Utilities Corporation.and Chief Financial Officer in September 2008 in addition to her duties as Treasurer and Corporate Secretary. Prior to becoming Senior Vice President in 2004, hethis appointment, Ms. Cooper served as Vice President of Chesapeake. He has also served as Vice President, Director of Gas Supply and Marketing, Superintendent of Eastern Shore and Regional Manager for the Florida distribution operations.
Beth W. Cooper (age 41) Ms. Cooper is Vice President, Treasurer and Corporate Secretary of Chesapeake Utilities Corporation. Ms. CooperCorporation since July 2005. She has served as Corporate SecretaryTreasurer of Chesapeake since July 2005.2003. She previously served as Assistant Treasurer and Assistant Secretary, Director of Internal Audit, Director of Strategic Planning, Planning Consultant, Accounting Manager for Non-regulated Operations and Treasury Analyst. Prior to joining Chesapeake, she was employed as an auditor with Ernst & Young’s Entrepreneurial Services Group.
Stephen C. Thompson is Senior Vice President of Chesapeake and President of ESNG. Prior to becoming Senior Vice President in 2004, he served as Vice President of Chesapeake. He has also served as Vice President, Director of Gas Supply and Marketing, Superintendent of ESNG and Regional Manager for the Florida distribution operations.
S. Robert Zola (age 55)Joseph Cummiskey was appointed as Vice President of Chesapeake and President of PESCO in December 2009. Mr. ZolaCummiskey joined Sharp EnergyChesapeake in August 2002December 2005 as President.the Director of Propane Supply and Wholesale Marketing. In 2008 and 2009, he served as the Director of Strategic Planning/Corporate Development and Director of Propane Operations. Prior to joining Sharp Energy,Chesapeake, Mr. Zola most recently servedCummiskey was employed as Northeasta Natural Gas Liquids Regional ManagerDirector for Ferrell North America. In that position, he was responsible for the purchasing and distribution of Synergy Gas, now Cornerstone MLP, in Philadelphia, PA. During his 27-year career in theFerrell’s propane industry, Mr. Zola also started and successfully developed Bluestreak Propane, in Phoenix, AZ, which was ultimately sold to Ferrell Gas.supply.
Chesapeake Utilities Corporation 2009 Form 10-K Page 25
Part II
Part II
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
(a) | Common Stock Price Ranges, Common Stock Dividends and Shareholder Information: |
(a)Common Stock Price Ranges, Common Stock Dividends and Shareholder Information:The Company’s Common Stockcommon stock is listed on the New York Stock Exchange (“NYSE”)NYSE under the symbol “CPK.” The high, low and closing prices of Chesapeake’s Common Stockthe Company’s common stock and dividends declared per share for each calendar quarter during the years 20072009 and 20062008 were as follows:
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Dividends | |
| | | | | | | | | | | | | | | Declared | |
| Quarter Ended | | High | | | Low | | | Close | | | Per Share | |
2009 | | | | | | | | | | | | | | | | |
March 31 | | $ | 32.36 | | | $ | 22.02 | | | $ | 30.48 | | | $ | 0.305 | |
June 30 | | | 34.55 | | | | 27.62 | | | | 32.53 | | | | 0.315 | |
September 30 | | | 35.00 | | | | 29.24 | | | | 30.99 | | | | 0.315 | |
December 31 | | | 32.67 | | | | 29.53 | | | | 32.05 | | | | 0.315 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| 2008 | | | | | | | | | | | | | | | | |
| March 31 | | $ | 33.60 | | | $ | 27.21 | | | $ | 29.64 | | | $ | 0.295 | |
| June 30 | | | 31.88 | | | | 25.02 | | | | 25.72 | | | | 0.305 | |
| September 30 | | | 34.84 | | | | 24.65 | | | | 33.21 | | | | 0.305 | |
| December 31 | | | 34.66 | | | | 21.93 | | | | 31.48 | | | | 0.305 | |
| | | | | | | | | | | | | |
Holders
At December 31, 2009, there were 2,670 holders of record of Chesapeake common stock. | | | | | | | | | | | | | Dividends | |
| | | | | | | | | | | | | Declared | |
| | Quarter Ended | | High | | | Low | | | Close | | | Per Share | |
| 2007 | | | | | | | | | | | | | |
| | March 31 | | $31.10 | | | $28.85 | | | $30.94 | | | $0.290 | |
| | June 30 | | 35.58 | | | 29.92 | | | 34.24 | | | 0.295 | |
| | September 30 | | 37.25 | | | 28.00 | | | 33.94 | | | 0.295 | |
| | December 31 | | 36.38 | | | 29.59 | | | 31.85 | | | 0.295 | |
| | | | | | | | | | | | | | |
| 2006 | | | | | | | | | | | | | |
| | March 31 | | $32.47 | | | $29.97 | | | $31.24 | | | $0.285 | |
| | June 30 | | 31.20 | | | 27.90 | | | 30.08 | | | 0.290 | |
| | September 30 | | 35.65 | | | 29.51 | | | 30.05 | | | 0.290 | |
| | December 31 | | 31.31 | | | 29.10 | | | 30.65 | | | 0.290 | |
| | | | | | | | | | | | | | |
We have paid a cash dividend to common stock shareholders for 49 consecutive years. Dividends are payable at the discretion of our Board of Directors. Future payment of dividends, and the amount of these dividends, will depend on our financial condition, results of operations, capital requirements, and other factors. WeNo securities were sold no securities during the year 20072009 that were not registered under the Securities Act of 1933, as amended.
Indentures to the long-term debt of the Company contain various restrictions. In terms of restrictions which limit the payment of dividends by Chesapeake, each of its Unsecured Senior Notes contains a “Restricted Payments” covenant. The most stringent restrictions staterestrictive covenants of this type are included within the 7.83 percent Senior Notes, due January 1, 2015. The covenant provides that Chesapeake cannot pay or declare any dividends or make any other Restricted Payments (such as dividends) in excess of the sum of $10.0 million plus consolidated net income of the Company must maintain equityaccrued on and after January 1, 2001. As of at least 40 percent of total capitalization and the pro-forma fixed charge coverage ratio must be at least 1.5 times. The Company was in compliance with these restrictions and other debt covenants during 2007.
At December 31, 2007, there were 1,920 shareholders2009, Chesapeake’s cumulative consolidated net income base was $102.8 million, offset by Restricted Payments of record$63.8 million, leaving $39.0 million of cumulative net income free of restrictions.
Page 26 Chesapeake Utilities Corporation 2009 Form 10-K
Each series of FPU’s first mortgage bonds contains a similar restriction that limits the payment of dividends by FPU. The most restrictive covenants of this type are included within the series that is due in 2031, which provided that FPU cannot make dividend or other restricted payments in excess of the Common Stock.sum of $2.5 million plus FPU’s consolidated net income accrued on and after January 1 2001. As of December 31, 2009, FPU had the cumulative net income base of $32.7 million, offset by restricted payments of $22.1 million, leaving $10.6 million of cumulative net income of FPU free of restrictions based on this covenant. In January 2010, this series of first mortgage bonds were redeemed prior to their maturities. The second most restricted covenant of this type is included in the series that is due in 2022, which provided that FPU cannot make dividend or other restricted payments in excess of the sum of $2.5 million plus FPU’s consolidated net income accrued on and after January 1, 1992. This covenant provided FPU with the cumulative net income base of $56.0 million, offset by restricted payments of $37.6 million, leaving $18.4 million of cumulative net income of FPU free of restrictions as of December 31, 2009.
(b) | Purchases of Equity Securities by the Issuer |
(b)Purchases of Equity Securities by the IssuerThe following table sets forth information on purchases by or on behalf of Chesapeake of shares of its Common Stockcommon stock during the quarter ended December 31, 2007.2009.
| | | | | | | | | | | | | | | | | |
| | | Total | | | | | | | Total Number of Shares | | | Maximum Number of | |
| | | Number | | | Average | | | Purchased as Part of | | | Shares That May Yet Be | |
| | | of Shares | | | Price Paid | | | Publicly Announced Plans | | | Purchased Under the Plans | |
| Period | | Purchased | | | per Share | | | or Programs(2) | | | or Programs(2) | |
| October 1, 2009 | | | | | | | | | | | | | | | | |
through October 31, 2009(1) | | | 587 | | | $ | 30.14 | | | | — | | | | — | |
| November 1, 2009 | | | | | | | | | | | | | | | | |
| through November 30, 2009 | | | — | | | | — | | | | — | | | | — | |
| December 1, 2009 | | | | | | | | | | | | | | | | |
| through December 31, 2009 | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | |
| Total | | | 587 | | | $ | 30.14 | | | | — | | | | — | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Period | | Total Number of Shares Purchased | | | Average Price Paid per Share | | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2) | | | Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs (2) | |
| October 1, 2007 | | | | | | | | | | | | |
| through October 31, 2007 (1) | | | 490 | | | $34.10 | | | | 0 | | | | 0 | |
| November 1, 2007 | | | | | | | | | | | | | | | |
| through November 30, 2007 | | | 0 | | | $0.00 | | | | 0 | | | | 0 | |
| December 1, 2007 | | | | | | | | | | | | | | | |
| through December 31, 2007 | | | 0 | | $0.00 | | | | 0 | | | | 0 | |
| Total | | | 490 | | | $34.10 | | | | 0 | | | | 0 | |
| | | | | | | | | | | | | | | | |
(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 Senior Executives under the Deferred Compensation Plan. | |
| The Deferred Compensation Plan is discussed further in Note K to the Consolidated Financial Statements. During the | |
| quarter, 490 shares were purchased through the reinvestment of dividends on deferred stock units. | |
| | | | | | | | | | | | | | | | |
(2) Except for the purpose described in Footnote (1), Chesapeake has no publicly announced plans or programs to | |
| repurchase its shares. | | | | | | | | | | | | | | | |
| | |
| (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 Note N to the Consolidated Financial Statements. During the quarter, 587 shares were purchased through the reinvestment of dividends on deferred stock units. |
|
| (2) | | Except for the purpose described in Footnote (1), Chesapeake has no publicly announced plans or programs to repurchase its shares. |
Discussion of compensation plans of Chesapeake and its subsidiaries, for which shares of Chesapeake common stock are authorized for issuance, is included in the portion of the Proxy Statement captioned “Equity Compensation Plan Information” to be filed notno later than March 31, 2008,2010, in connection with the Company’s Annual Meeting to be held on or about May 1, 2008,5, 2010 and, is incorporated herein by reference.
The chief executive officer’s annual certification regarding the Company’s compliance with the NYSE’s corporate governance listing standards was submitted to the NYSE on May 29, 2007.
(c) | Chesapeake Utilities Corporation Common Stock Performance Graph |
(c)Chesapeake Utilities Corporation Common Stock Performance GraphThe following stock Performance Graph compares cumulative total shareholder return on a hypothetical investment in the Company’sour common stock during the five fiscal years ended December 31, 2007,2009, with the cumulative total shareholder return on a hypothetical investment in both (i) the Standard & Poor’s 500 Index (“S&P 500 IndexIndex”), and (ii) an industry index consisting of 14Chesapeake and 11 of the companies in the current Edward Jones Natural Gas Distribution Group, a published listing of selected gas distribution utilities’ results. The Company’s Performance Graph for the previous year included all but one of these same companies in addition to seventeen other companies. The Company chose to useOur Compensation Committee utilizes the Edward Jones Natural Gas Distribution Group as itsour peer group this yearto which our performance is compared for performance metrics comparison to coincide withpurposes of determining the Compensation Committee’s decision to use this indexlevel of companies to evaluate the Company’s results in connection with issuing long-term awards to executive officers under the new long-term performance plan.
awards earned by our named executives.
The fourteeneleven companies in the Edward Jones Natural Gas Distribution Group industry index include: AGL Resources, Inc., Atmos Energy Corporation, Chesapeake Utilities Corporation, Corning Natural Gas Corporation, Delta Natural Gas Company, Inc., Energy West, Inc., EnergySouth. Inc., The Laclede Group, Inc., New Jersey Resources Corporation, Northwest Natural Gas Company, Piedmont Natural Gas Co., Inc., RGC Resources, Inc., South Jersey Industries, Inc, and WGL Holdings, Inc. The Company excluded SEMCO Energy, Inc. from its comparison due to its recent acquisition by Cap Rock Holding Corporation.
Chesapeake Utilities Corporation 2009 Form 10-K Page 27
The comparison assumes $100 was invested on December 31, 20022004 in the Company’sour common stock and in each of the foregoing indices and assumes reinvested dividends. The comparisons in the graph below are based on historical data and are not intended to forecast the possible future performance of the Company’s Common Stock.our common stock.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2004 | | | 2005 | | | 2006 | | | 2007 | | | 2008 | | | 2009 | |
Chesapeake | | $ | 100 | | | $ | 120 | | | $ | 124 | | | $ | 133 | | | $ | 137 | | | $ | 145 | |
Industry Index | | $ | 100 | | | $ | 105 | | | $ | 125 | | | $ | 129 | | | $ | 139 | | | $ | 143 | |
S&P 500 Index | | $ | 100 | | | $ | 105 | | | $ | 121 | | | $ | 128 | | | $ | 81 | | | $ | 102 | |
Page 28 Chesapeake Utilities Corporation 2009 Form 10-K
| | | | | | | | |
| | 2002 | 2003 | 2004 | 2005 | 2006 | 2007 | |
| Chesapeake | $100 | $148 | $158 | $189 | $196 | $211 | |
| Industry Index | $100 | $120 | $141 | $152 | $180 | $202 | |
| S&P 500 | $100 | $128 | $142 | $149 | $172 | $182 | |
Item 6. Selected Financial Data
| | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2009(3) | | | 2008 | | | 2007 | |
Operating(1)
(in thousands) | | | | | | | | | | | | |
| Revenues | | | | | | | | | | | | |
| Regulated Energy | | $ | 139,099 | | | $ | 116,468 | | | $ | 128,850 | |
| Unregulated Energy | | | 119,973 | | | | 161,290 | | | | 115,190 | |
| Other | | | 9,713 | | | | 13,685 | | | | 14,246 | |
| | | | | | | | | | |
| Total revenues | | $ | 268,785 | | | $ | 291,443 | | | $ | 258,286 | |
| | | | | | | | | | | | | |
| Operating income | | | | | | | | | | | | |
| Regulated Energy | | $ | 26,900 | | | $ | 24,733 | | | $ | 21,809 | |
| Unregulated Energy | | | 8,158 | | | | 3,781 | | | | 5,174 | |
| Other | | | (1,322 | ) | | | (35 | ) | | | 1,131 | |
| | | | | | | | | | |
| Total operating income | | $ | 33,736 | | | $ | 28,479 | | | $ | 28,114 | |
| | | | | | | | | | | | | |
| Net income from continuing operations | | $ | 15,897 | | | $ | 13,607 | | | $ | 13,218 | |
| | | | | | | | | | | | | |
Assets
(in thousands) | | | | | | | | | | | | |
| Gross property, plant and equipment | | $ | 543,746 | | | $ | 381,689 | | | $ | 352,838 | |
Net property, plant and equipment(2) | | $ | 436,428 | | | $ | 280,671 | | | $ | 260,423 | |
Total assets(2) | | $ | 617,102 | | | $ | 385,795 | | | $ | 381,557 | |
Capital expenditures(1) | | $ | 26,294 | | | $ | 30,844 | | | $ | 30,142 | |
| | | | | | | | | | | | | |
Capitalization
(in thousands) | | | | | | | | | | | | |
| Stockholders’ equity | | $ | 209,781 | | | $ | 123,073 | | | $ | 119,576 | |
| Long-term debt, net of current maturities | | | 98,814 | | | | 86,422 | | | | 63,256 | |
| | | | | | | | | | |
| Total capitalization | | $ | 308,595 | | | $ | 209,495 | | | $ | 182,832 | |
| | | | | | | | | | | | | |
| Current portion of long-term debt | | | 35,299 | | | | 6,656 | | | | 7,656 | |
| Short-term debt | | | 30,023 | | | | 33,000 | | | | 45,664 | |
| | | | | | | | | | |
| Total capitalization and short-term financing | | $ | 373,917 | | | $ | 249,151 | | | $ | 236,152 | |
| | | | | | | | | | |
| | |
| (1) | | These amounts exclude the results of distributed energy and water services due to their reclassification to discontinued operations. The Company closed its distributed energy operation in 2007. All assets of all of the water businesses were sold in 2004 and 2003. |
|
| (2) | | SFAS No. 143 (now codified within FASB ASC 360 and 410) was adopted in the year 2001; therefore, it was not applicable for the years prior to 2001. |
|
| (3) | | These amounts include the financial position and results of operation of FPU for the period from the merger (October 28, 2009) to December 31, 2009. These amounts also include the effects of acquisition accounting and issuance of Chesapeake common shares as a result of the merger. These amounts may not be indicative of future results due to the inclusion of merger effects. See Item 8 under the heading “Notes to the Consolidated Financial Statements — Note B, Acquisitions and Dispositions” for addition discussions and presentation of pro forma results. |
|
| (4) | | SFAS No. 123R (now codified within FASB ASC 718, 505 and 260 ) and SFAS No. 158 (codified within FASB ASC 715) were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006. |
Chesapeake Utilities Corporation 2009 Form 10-K Page 29
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2006(4) | | | 2005 | | | 2004 | | | 2003 | | | 2002 | | | 2001 | | | 2000 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| $ | 124,631 | | | $ | 124,563 | | | $ | 98,139 | | | $ | 92,079 | | | $ | 82,098 | | | $ | 87,444 | | | $ | 82,490 | |
| | 94,320 | | | | 90,995 | | | | 67,607 | | | | 59,197 | | | | 40,728 | | | | 56,970 | | | | 50,428 | |
| | 12,249 | | | | 13,927 | | | | 12,209 | | | | 12,292 | | | | 12,430 | | | | 13,992 | | | | 12,259 | |
| | | | | | | | | | | | | | | | | | | | |
| $ | 231,200 | | | $ | 229,485 | | | $ | 177,955 | | | $ | 163,568 | | | $ | 135,256 | | | $ | 158,406 | | | $ | 145,177 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| $ | 18,593 | | | $ | 16,248 | | | $ | 16,258 | | | $ | 16,219 | | | $ | 14,867 | | | $ | 14,060 | | | $ | 12,672 | |
| | 3,675 | | | | 4,197 | | | | 3,197 | | | | 4,310 | | | | 1,158 | | | | 1,259 | | | | 2,261 | |
| | 1,064 | | | | 1,476 | | | | 722 | | | | 1,050 | | | | 580 | | | | 902 | | | | 1,152 | |
| | | | | | | | | | | | | | | | | | | | |
| $ | 23,332 | | | $ | 21,921 | | | $ | 20,177 | | | $ | 21,579 | | | $ | 16,605 | | | $ | 16,221 | | | $ | 16,085 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| $ | 10,748 | | | $ | 10,699 | | | $ | 9,686 | | | $ | 10,079 | | | $ | 7,535 | | | $ | 7,341 | | | $ | 7,665 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| $ | 325,836 | | | $ | 280,345 | | | $ | 250,267 | | | $ | 234,919 | | | $ | 229,128 | | | $ | 216,903 | | | $ | 192,925 | |
| $ | 240,825 | | | $ | 201,504 | | | $ | 177,053 | | | $ | 167,872 | | | $ | 166,846 | | | $ | 161,014 | | | $ | 131,466 | |
| $ | 325,585 | | | $ | 295,980 | | | $ | 241,938 | | | $ | 222,058 | | | $ | 223,721 | | | $ | 222,229 | | | $ | 211,764 | |
| $ | 49,154 | | | $ | 33,423 | | | $ | 17,830 | | | $ | 11,822 | | | $ | 13,836 | | | $ | 26,293 | | | $ | 22,057 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| $ | 111,152 | | | $ | 84,757 | | | $ | 77,962 | | | $ | 72,939 | | | $ | 67,350 | | | $ | 67,517 | | | $ | 64,669 | |
| | 71,050 | | | | 58,991 | | | | 66,190 | | | | 69,416 | | | | 73,408 | | | | 48,409 | | | | 50,921 | |
| | | | | | | | | | | | | | | | | | | | |
| $ | 182,202 | | | $ | 143,748 | | | $ | 144,152 | | | $ | 142,355 | | | $ | 140,758 | | | $ | 115,926 | | | $ | 115,590 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 7,656 | | | | 4,929 | | | | 2,909 | | | | 3,665 | | | | 3,938 | | | | 2,686 | | | | 2,665 | |
| | 27,554 | | | | 35,482 | | | | 5,002 | | | | 3,515 | | | | 10,900 | | | | 42,100 | | | | 25,400 | |
| | | | | | | | | | | | | | | | | | | | |
| $ | 217,412 | | | $ | 184,159 | | | $ | 152,063 | | | $ | 149,535 | | | $ | 155,596 | | | $ | 160,712 | | | $ | 143,655 | |
| | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | 2007 | 2006 (3) | 2005 | 2004 | 2003 |
Operating (in thousands of dollars) (1) | | | | | |
| | Revenues | | | | | |
| | | Natural gas | $181,202 | $170,374 | $166,582 | $124,246 | $110,247 |
| | | Propane | 62,838 | 48,576 | 48,976 | 41,500 | 41,029 |
| | | Advanced informations systems | 15,099 | 12,568 | 14,140 | 12,427 | 12,578 |
| | | Other and eliminations | (853) | (318) | (213) | (218) | (286) |
| | Total revenues | $258,286 | $231,200 | $229,485 | $177,955 | $163,568 |
| | | | | | | | | |
| | Operating income | | | | | |
| | | Natural gas | $22,485 | $19,733 | $17,236 | $17,091 | $16,653 |
| | | Propane | 4,498 | 2,534 | 3,209 | 2,364 | 3,875 |
| | | Advanced informations systems | 836 | 767 | 1,197 | 387 | 692 |
| | | Other and eliminations | 295 | 298 | 279 | 335 | 359 |
| | Total operating income | $28,114 | $23,332 | $21,921 | $20,177 | $21,579 |
| | | | | | | | | |
| | Net income from continuing operations | $13,218 | $10,748 | $10,699 | $9,686 | $10,079 |
| | | | | | | | | |
| | | | | | | | | |
Assets (in thousands of dollars) | | | | | |
| | Gross property, plant and equipment | $352,838 | $325,836 | $280,345 | $250,267 | $234,919 |
| | Net property, plant and equipment (2) | $260,423 | $240,825 | $201,504 | $177,053 | $167,872 |
| | Total assets (2) | $381,557 | $325,585 | $295,980 | $241,938 | $222,058 |
| | Capital expenditures (1) | $30,142 | $49,154 | $33,423 | $17,830 | $11,822 |
| | | | | | | | | |
| | | | | | | | | |
Capitalization (in thousands of dollars) | | | | | |
| | Stockholders' equity | $119,576 | $111,152 | $84,757 | $77,962 | $72,939 |
| | Long-term debt, net of current maturities | 63,256 | 71,050 | 58,991 | 66,190 | 69,416 |
| | Total capitalization | $182,832 | $182,202 | $143,748 | $144,152 | $142,355 |
| | | | | | | | | |
| | Current portion of long-term debt | $7,656 | $7,656 | $4,929 | $2,909 | $3,665 |
| | Short-term debt | 45,664 | 27,554 | 35,482 | 5,002 | 3,515 |
| | Total capitalization and short-term financing | $236,152 | $217,412 | $184,159 | $152,063 | $149,535 |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | (1) These amounts exclude the results of distributed energy and water services due to their reclassification to discontinued operations. The Company |
| | closed its distributed energy operation in 2007. All assets of all of the water businesses were sold in 2004 and 2003. |
| | (2) Statement of Financial Accounting Standard ("SFAS") 143 was adopted in the year 2001; therefore, SFAS 143 was not applicable for the years prior to 2001. |
| | (3) SFAS 123R and SFAS 158 were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006. |
| | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2009(3) | | | 2008 | | | 2007 | |
Common Stock Data and Ratios | | | | | | | | | | | | |
Basic earnings per share from continuing operations(1) | | $ | 2.17 | | | $ | 2.00 | | | $ | 1.96 | |
Diluted earnings per share from continuing operations(1) | | $ | 2.15 | | | $ | 1.98 | | | $ | 1.94 | |
| | | | | | | | | | | | | |
Return on average equity from continuing operations(1) | | | 11.2 | % | | | 11.2 | % | | | 11.5 | % |
| | | | | | | | | | | | | |
| Common equity / total capitalization | | | 68.0 | % | | | 58.7 | % | | | 65.4 | % |
| Common equity / total capitalization and short-term financing | | | 56.1 | % | | | 49.4 | % | | | 50.6 | % |
| | | | | | | | | | | | | |
| Book value per share | | $ | 22.33 | | | $ | 18.03 | | | $ | 17.64 | |
| | | | | | | | | | | | | |
| Market price: | | | | | | | | | | | | |
| High | | $ | 35.000 | | | $ | 34.840 | | | $ | 37.250 | |
| Low | | $ | 22.020 | | | $ | 21.930 | | | $ | 28.000 | |
| Close | | $ | 32.050 | | | $ | 31.480 | | | $ | 31.850 | |
| | | | | | | | | | | | | |
| Average number of shares outstanding | | | 7,313,320 | | | | 6,811,848 | | | | 6,743,041 | |
| Shares outstanding at year-end | | | 9,394,314 | | | | 6,827,121 | | | | 6,777,410 | |
| Registered common shareholders | | | 2,670 | | | | 1,914 | | | | 1,920 | |
| |
| Cash dividends declared per share | | $ | 1.25 | | | $ | 1.21 | | | $ | 1.18 | |
Dividend yield (annualized)(2) | | | 3.9 | % | | | 3.9 | % | | | 3.7 | % |
Payout ratio from continuing operations(1) (4) | | | 57.6 | % | | | 60.5 | % | | | 60.2 | % |
| | | | | | | | | | | | | |
Additional Data | | | | | | | | | | | | |
Customers(5) | | | | | | | | | | | | |
| Natural gas distribution | | | 117,887 | | | | 65,201 | | | | 62,884 | |
| Electric distribution | | | 31,030 | | | | — | | | | — | |
| Propane distribution | | | 48,680 | | | | 34,981 | | | | 34,143 | |
| | | | | | | | | | | | | |
Volumes(6) | | | | | | | | | | | | |
| Natural gas deliveries (in Mcfs) | | | 44,586,158 | | | | 39,778,067 | | | | 34,820,050 | |
| Electric Distribution (in MWHs) | | | 105,739 | | | | — | | | | — | |
| Propane distribution (in thousands of gallons) | | | 32,546 | | | | 27,956 | | | | 29,785 | |
| | | | | | | | | | | | | |
| Heating degree-days (Delmarva Peninsula) | | | | | | | | | | | | |
| Actual HDD | | | 4,729 | | | | 4,431 | | | | 4,504 | |
| 10-year average HDD (normal) | | | 4,462 | | | | 4,401 | | | | 4,376 | |
| | | | | | | | | | | | | |
| Propane bulk storage capacity (in thousands of gallons) | | | 3,042 | | | | 2,471 | | | | 2,441 | |
| | | | | | | | | | | | | |
Total employees(1) (7) | | | 757 | | | | 448 | | | | 445 | |
| | |
| (1) | | These amounts exclude the results of distributed energy and water services due to their reclassification to discontinued operations. The Companyclosed its distributed energy operation in 2007. All assets of all of the water businesses were sold in 2004 and 2003. |
|
| (2) | | Dividend yield (annualized) is calculated by multiplying the fourth quarter dividend by four (4), then dividing that amount by the closing common stock price at December 31. |
|
| (3) | | These amounts include the financial position and results of operation of FPU for the period from the merger closing (October 28, 2009) to December 31, 2009. These amounts also include the effects of acquisition accounting and issuance of Chesapeake common shares as a result of the merger. These amounts may not be indicative of future results due to the inclusion of merger effects. See Item 8 under the heading “Notes to the Consolidated Financial Statements — Note B, Acquisitions and Dispositions” for addition discussions and presentation of pro forma results. |
|
| (4) | | The payout ratio from continuing operations is calculated by dividing cash dividends declared per share (for the year) by basic earnings per share from continuing operations. |
|
| (5) | | Customer data for 2009 includes 51,536, 31,030 and 13,651 of natural gas distribution, electric distribution and propane distribution customers, respectively, from FPU. |
|
| (6) | | Volumes data for 2009 includes 1,109,177 Mcfs, 105,739 MWHs and 1.1 million gallons for natural gas distribution, electric distribution and propane distribution, respectively, delivered by FPU from October 28, 2009 through December 31, 2009. |
|
| (7) | | Total employees for 2009 include 332 FPU employees added to the Company upon the merger, effective October 28, 2009. |
Chesapeake Utilities Corporation 2009 Form 10-K Page 31
- | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2006(8) | | | 2005 | | | 2004 | | | 2003 | | | 2002 | | | 2001 | | | 2000 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| $ | 1.78 | | | $ | 1.83 | | | $ | 1.68 | | | $ | 1.80 | | | $ | 1.37 | | | $ | 1.37 | | | $ | 1.46 | |
| $ | 1.76 | | | $ | 1.81 | | | $ | 1.64 | | | $ | 1.76 | | | $ | 1.37 | | | $ | 1.35 | | | $ | 1.43 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 11.0 | % | | | 13.2 | % | | | 12.8 | % | | | 14.4 | % | | | 11.2 | % | | | 11.1 | % | | | 12.2 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 61.0 | % | | | 59.0 | % | | | 54.1 | % | | | 51.2 | % | | | 47.8 | % | | | 58.2 | % | | | 55.9 | % |
| | 51.1 | % | | | 46.0 | % | | | 51.3 | % | | | 48.8 | % | | | 43.3 | % | | | 42.0 | % | | | 45.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| $ | 16.62 | | | $ | 14.41 | | | $ | 13.49 | | | $ | 12.89 | | | $ | 12.16 | | | $ | 12.45 | | | $ | 12.21 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| $ | 35.650 | | | $ | 35.780 | | | $ | 27.550 | | | $ | 26.700 | | | $ | 21.990 | | | $ | 19.900 | | | $ | 18.875 | |
| $ | 27.900 | | | $ | 23.600 | | | $ | 20.420 | | | $ | 18.400 | | | $ | 16.500 | | | $ | 17.375 | | | $ | 16.250 | |
| $ | 30.650 | | | $ | 30.800 | | | $ | 26.700 | | | $ | 26.050 | | | $ | 18.300 | | | $ | 19.800 | | | $ | 18.625 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 6,032,462 | | | | 5,836,463 | | | | 5,735,405 | | | | 5,610,592 | | | | 5,489,424 | | | | 5,367,433 | | | | 5,249,439 | |
| | 6,688,084 | | | | 5,883,099 | | | | 5,778,976 | | | | 5,660,594 | | | | 5,537,710 | | | | 5,424,962 | | | | 5,297,443 | |
| | 1,978 | | | | 2,026 | | | | 2,026 | | | | 2,069 | | | | 2,130 | | | | 2,171 | | | | 2,166 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| $ | 1.16 | | | $ | 1.14 | | | $ | 1.12 | | | $ | 1.10 | | | $ | 1.10 | | | $ | 1.10 | | | $ | 1.07 | |
| | 3.8 | % | | | 3.7 | % | | | 4.2 | % | | | 4.2 | % | | | 6.0 | % | | | 5.6 | % | | | 5.8 | % |
| | 65.2 | % | | | 62.3 | % | | | 66.7 | % | | | 61.1 | % | | | 80.3 | % | | | 80.3 | % | | | 73.3 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 59,132 | | | | 54,786 | | | | 50,878 | | | | 47,649 | | | | 45,133 | | | | 42,741 | | | | 40,854 | |
| | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| | 33,282 | | | | 32,117 | | | | 34,888 | | | | 34,894 | | | | 34,566 | | | | 35,530 | | | | 35,563 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 34,321,160 | | | | 34,980,939 | | | | 31,429,494 | | | | 29,374,818 | | | | 27,934,715 | | | | 27,263,542 | | | | 30,829,509 | |
| | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| | 24,243 | | | | 26,178 | | | | 24,979 | | | | 25,147 | | | | 21,185 | | | | 23,080 | | | | 28,469 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 3,931 | | | | 4,792 | | | | 4,553 | | | | 4,715 | | | | 4,161 | | | | 4,368 | | | | 4,730 | |
| | 4,372 | | | | 4,436 | | | | 4,389 | | | | 4,409 | | | | 4,393 | | | | 4,446 | | | | 4,356 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2,315 | | | | 2,315 | | | | 2,045 | | | | 2,195 | | | | 2,151 | | | | 1,958 | | | | 1,928 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 437 | | | | 423 | | | | 426 | | | | 439 | | | | 455 | | | | 458 | | | | 471 | |
| | |
| (8) | | SFAS No. 123R (now codified within FASB ASC 718, 505 and 260 ) and SFAS No. 158 (codified within FASB ASC 715) were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006. |
Page 11 - -32 Chesapeake Utilities Corporation 2009 Form 10-K
| For the Years Ended December 31, | 2002 | 2001 | 2000 | 1999 | 1998 |
Operating (in thousands of dollars) (1) | | | | | |
| | Revenues | | | | | |
| | | Natural gas | $93,588 | $107,418 | $101,138 | $75,637 | $68,770 |
| | | Propane | 29,238 | 35,742 | 31,780 | 25,199 | 23,377 |
| | | Advanced informations systems | 12,764 | 14,104 | 12,390 | 13,531 | 10,331 |
| | | Other and eliminations | (334) | (113) | (131) | (14) | (15) |
| | Total revenues | $135,256 | $157,151 | $145,177 | $114,353 | $102,463 |
| | | | | | | | | |
| | Operating income | | | | | |
| | | Natural gas | $14,973 | $14,405 | $12,798 | $10,388 | $8,820 |
| | | Propane | 1,052 | 913 | 2,135 | 2,622 | 965 |
| | | Advanced informations systems | 343 | 517 | 336 | 1,470 | 1,316 |
| | | Other and eliminations | 237 | 386 | 816 | 495 | 485 |
| | Total operating income | $16,605 | $16,221 | $16,085 | $14,975 | $11,586 |
| | | | | | | | | |
| | Net income from continuing operations | $7,535 | $7,341 | $7,665 | $8,372 | $5,329 |
| | | | | | | | | |
| | | | | | | | | |
Assets (in thousands of dollars) | | | | | |
| | Gross property, plant and equipment | $229,128 | $216,903 | $192,925 | $172,068 | $152,991 |
| | Net property, plant and equipment (2) | $166,846 | $161,014 | $131,466 | $117,663 | $104,266 |
| | Total assets (2) | $223,721 | $222,229 | $211,764 | $166,958 | $145,029 |
| | Capital expenditures (1) | $13,836 | $26,293 | $22,057 | $21,365 | $12,516 |
| | | | | | | | | |
| | | | | | | | | |
Capitalization (in thousands of dollars) | | | | | |
| | Stockholders' equity | $67,350 | $67,517 | $64,669 | $60,714 | $56,356 |
| | Long-term debt, net of current maturities | 73,408 | 48,409 | 50,921 | 33,777 | 37,597 |
| | Total capitalization | $140,758 | $115,926 | $115,590 | $94,491 | $93,953 |
| | | | | | | | | |
| | Current portion of long-term debt | $3,938 | $2,686 | $2,665 | $2,665 | $520 |
| | Short-term debt | 10,900 | 42,100 | 25,400 | 23,000 | 11,600 |
| | Total capitalization and short-term financing | $155,596 | $160,712 | $143,655 | $120,156 | $106,073 |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | (1) These amounts exclude the results of distributed energy and water services due to their reclassification to discontinued operations. The Company |
| | closed its distributed energy operation in 2007. All assets of all of the water businesses were sold in 2004 and 2003. |
| | (2) Statement of Financial Accounting Standard ("SFAS") 143 was adopted in the year 2001; therefore, SFAS 143 was not applicable for the years prior to 2001. |
| | (3) SFAS 123R and SFAS 158 were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006. |
| For the Years Ended December 31, | 2007 | 2006 (3) | 2005 | 2004 | 2003 |
| Common Stock Data and Ratios | | | | | |
| | Basic earnings per share from continuing operations (1) | $1.96 | $1.78 | $1.83 | $1.68 | $1.80 |
| | Diluted earnings per share from continuing operations (1) | $1.94 | $1.76 | $1.81 | $1.64 | $1.76 |
| | | | | | | | | |
| | Return on average equity from continuing operations (1) | 11.5% | 11.0% | 13.2% | 12.8% | 14.4% |
| | | | | | | | | |
| | Common equity / total capitalization | 65.4% | 61.0% | 59.0% | 54.1% | 51.2% |
| | Common equity / total capitalization and short-term financing | 50.6% | 51.1% | 46.0% | 51.3% | 48.8% |
| | | | | | | | | |
| | Book value per share | $17.64 | $16.62 | $14.41 | $13.49 | $12.89 |
| | | | | | | | | |
| | | | | | | | | |
| | Market price: | | | | | |
| | | High | $37.250 | $35.650 | $35.780 | $27.550 | $26.700 |
| | | Low | $28.000 | $27.900 | $23.600 | $20.420 | $18.400 |
| | | Close | $31.850 | $30.650 | $30.800 | $26.700 | $26.050 |
| | | | | | | | | |
| | | | | | | | | |
| | Average number of shares outstanding | 6,743,041 | 6,032,462 | 5,836,463 | 5,735,405 | 5,610,592 |
| | Shares outstanding at year-end | 6,777,410 | 6,688,084 | 5,883,099 | 5,778,976 | 5,660,594 |
| | Registered common shareholders | 1,920 | 1,978 | 2,026 | 2,026 | 2,069 |
| | | | | | | | | |
| | Cash dividends declared per share | $1.18 | $1.16 | $1.14 | $1.12 | $1.10 |
| | Dividend yield (annualized) (2) | 3.7% | 3.8% | 3.7% | 4.2% | 4.2% |
| | Payout ratio from continuing operations (1) (4) | 60.2% | 65.2% | 62.3% | 66.7% | 61.1% |
| | | | | | | | | |
| | | | | | | | | |
| Additional Data | | | | | |
| | Customers | | | | | |
| | | Natural gas distribution and transmission | 62,884 | 59,132 | 54,786 | 50,878 | 47,649 |
| | | Propane distribution | 34,143 | 33,282 | 32,117 | 34,888 | 34,894 |
| | | | | | | | | |
| | | | | | | | | |
| | Volumes | | | | | |
| | | Natural gas deliveries (in MMCF) | 34,820 | 34,321 | 34,981 | 31,430 | 29,375 |
| | | Propane distribution (in thousands of gallons) | 29,785 | 24,243 | 26,178 | 24,979 | 25,147 |
| | | | | | | | | |
| | | | | | | | | |
| | Heating degree-days (Delmarva Peninsula) | | | | | |
| | | Actual HDD | 4,504 | 3,931 | 4,792 | 4,553 | 4,715 |
| | | 10 -year average HDD (normal) | 4,376 | 4,372 | 4,436 | 4,389 | 4,409 |
| | | | | | | | | |
| | Propane bulk storage capacity (in thousands of gallons) | 2,441 | 2,315 | 2,315 | 2,045 | 2,195 |
| | | | | | | | | |
| | Total employees (1) | 445 | 437 | 423 | 426 | 439 |
| | | | | | | | | |
| | | | | | | | | |
| | (1) These amounts exclude the results of distributed energy and water services due to their reclassification to discontinued operations. The Company |
| | closed its distributed energy operation in 2007. All assets of all of the water businesses were sold in 2004 and 2003. |
| | (2) Dividend yield (annualized) is calculated by multiplying the fourth quarter dividend by four (4), then |
| | dividing that amount by the closing common stock price at December 31. | | |
| | (3) SFAS 123R and SFAS 158 were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006. |
| | (4) The payout ratio from continuing operations is calculated by dividing cash dividends declared per share |
| | (for the year) by basic earnings per share from continuing operations. | | |
| For the Years Ended December 31, | 2002 | 2001 | 2000 | 1999 | 1998 |
| Common Stock Data and Ratios | | | | | |
| | Basic earnings per share from continuing operations (1) | $1.37 | $1.37 | $1.46 | $1.63 | $1.05 |
| | Diluted earnings per share from continuing operations (1) | $1.37 | $1.35 | $1.43 | $1.59 | $1.04 |
| | | | | | | | | |
| | Return on average equity from continuing operations (1) | 11.2% | 11.1% | 12.2% | 14.3% | 9.7% |
| | | | | | | | | |
| | Common equity / total capitalization | 47.8% | 58.2% | 55.9% | 64.3% | 60.0% |
| | Common equity / total capitalization and short-term financing | 43.3% | 42.0% | 45.0% | 50.5% | 53.1% |
| | | | | | | | | |
| | Book value per share | $12.16 | $12.45 | $12.21 | $11.71 | $11.06 |
| | | | | | | | | |
| | | | | | | | | |
| | Market price: | | | | | |
| | | High | $21.990 | $19.900 | $18.875 | $19.813 | $20.500 |
| | | Low | $16.500 | $17.375 | $16.250 | $14.875 | $16.500 |
| | | Close | $18.300 | $19.800 | $18.625 | $18.375 | $18.313 |
| | | | | | | | | |
| | | | | | | | | |
| | Average number of shares outstanding | 5,489,424 | 5,367,433 | 5,249,439 | 5,144,449 | 5,060,328 |
| | Shares outstanding at year-end | 5,537,710 | 5,424,962 | 5,297,443 | 5,186,546 | 5,093,788 |
| | Registered common shareholders | 2,130 | 2,171 | 2,166 | 2,212 | 2,271 |
| | | | | | | | | |
| | Cash dividends declared per share | $1.10 | $1.10 | $1.07 | $1.03 | $1.00 |
| | Dividend yield (annualized) (2) | 6.0% | 5.6% | 5.8% | 5.7% | 5.5% |
| | Payout ratio from continuing operations (1) (4) | 80.3% | 80.3% | 73.3% | 63.2% | 95.2% |
| | | | | | | | | |
| | | | | | | | | |
| Additional Data | | | | | |
| | Customers | | | | | |
| | | Natural gas distribution and transmission | 45,133 | 42,741 | 40,854 | 39,029 | 37,128 |
| | | Propane distribution | 34,566 | 35,530 | 35,563 | 35,267 | 34,113 |
| | | | | | | | | |
| | | | | | | | | |
| | Volumes | | | | | |
| | | Natural gas deliveries (in MMCF) | 27,935 | 27,264 | 30,830 | 27,383 | 21,400 |
| | | Propane distribution (in thousands of gallons) | 21,185 | 23,080 | 28,469 | 27,788 | 25,979 |
| | | | | | | | | |
| | | | | | | | | |
| | Heating degree-days (Delmarva Peninsula) | | | | | |
| | | Actual HDD | 4,161 | 4,368 | 4,730 | 4,082 | 3,704 |
| | | 10 -year average HDD (normal) | 4,393 | 4,446 | 4,356 | 4,409 | 4,493 |
| | | | | | | | | |
| | Propane bulk storage capacity (in thousands of gallons) | 2,151 | 1,958 | 1,928 | 1,926 | 1,890 |
| | | | | | | | | |
| | Total employees (1) | 455 | 458 | 471 | 466 | 431 |
| | | | | | | | | |
| | | | | | | | | |
| | (1) These amounts exclude the results of distributed energy and water services due to their reclassification to discontinued operations. The Company |
| | closed its distributed energy operation in 2007. All assets of all of the water businesses were sold in 2004 and 2003. |
| | (2) Dividend yield (annualized) is calculated by multiplying the fourth quarter dividend by four (4), then |
| | dividing that amount by the closing common stock price at December 31. | | |
| | (3) SFAS 123R and SFAS 158 were adopted in the year 2006; therefore, they were not applicable for the years prior to 2006. |
| | (4) The payout ratio from continuing operations is calculated by dividing cash dividends declared per share |
| | (for the year) by basic earnings per share from continuing operations. | | |
Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations
INTRODUCTION
This section provides management’s discussion of Chesapeake Utilities Corporation and its consolidated subsidiaries, with specific information on results of operations and liquidity and capital resources.resources, as well as discussion on how certain accounting principles affect our financial statements. It includes management’s interpretation of our financial results of the Company and its operating segments, the factors affecting these results, the major factors expected to affect future operating results, and future investment and financing plans. This discussion should be read in conjunction with our consolidated financial statements and notes thereto.
Several factors exist that could influence our future financial performance, some of which are described in Item 1A above, “Risk Factors.” They should be considered in connection with evaluating forward-looking statements contained in this report, or otherwise made by or on behalf of us, since these factors could cause actual results and conditions to differ materially from those set out in such forward-looking statements.
EXECUTIVE OVERVIEW
Chesapeake is a diversified utility company engaged directly or through subsidiaries in natural gas distribution, transmission and marketing, propane distribution and wholesale marketing, advanced information services and other related businesses.
The Company’s strategy is focused on growing earnings from a stable utility foundation and investing in related businesses and services that provide opportunities for returns greater than traditional utility returns. The key elements of this strategy include:
· | executing a capital investment program in pursuit of organic growth opportunities that generate returns equal to or greater than our cost of capital; |
· | expanding the natural gas distribution and transmission business through expansion into new geographic areas in our current service territories; |
· | expanding the propane distribution business in existing and new markets through leveraging our community gas system services and our bulk delivery capabilities; |
· | utilizing the Company’s expertise across our various businesses to improve overall performance; |
· | enhancing marketing channels to attract new customers; |
· | providing reliable and responsive customer service to retain existing customers; |
· | maintaining a capital structure that enables the Company to access capital as needed; and |
· | maintaining a consistent and competitive dividend for shareholders. |
In 2007, net income increased 26 percent as the Company earned $13.2 million in net income, or $1.94 per share (diluted), when compared to the net income of $10.5 million, or $1.72 per share (diluted), earned in 2006. Overall, operating income in 2007 increased $4.8 million, or 20 percent, from 2006. The increase in operating income was partially offset by an increase of $816,000, or 14 percent, in interest expense and higher income taxes of $1.6 million, or 23 percent.
The following discussions and those later in the document on operating income and segment results include use of the term “gross margin.” Gross margin is determined by deducting the cost of sales from operating revenue. Cost of sales includes the purchased gas cost forof 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 Generally Accepted Accounting Principles (“GAAP”). Chesapeake believesGAAP. 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 non-regulated segments.unregulated natural gas marketing and propane distribution operations. Chesapeake’s management uses gross margin in measuring its business units’ performance and has historically analyzed and reported gross margin information publicly. Other companies may calculate gross margin in a different manner.
In addition, certain information is presented, which excludes for comparison purposes, result of operations of FPU for the period from the merger closing (October 28, 2009) to December 31, 2009 and all merger-related costs incurred in connection with the FPU merger. Although the non-GAAP measures are not intended to replace the GAAP measures for evaluation of Chesapeake’s performance, we believe that the portions of the presentation which excludes FPU’s financial results for the post-merger period and merger-related costs provide a helpful comparative basis for investors to understand Chesapeake’s performance.
(a) Introduction
Chesapeake is 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 through expansion into new geographic areas and providing new services in our current service territories;
Operating Incomeexpanding the propane distribution business in existing and new markets through leveraging our community gas system services and our bulk delivery capabilities;
A strong year-over-year increaseutilizing 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;
Chesapeake Utilities Corporation 2009 Form 10-K Page 33
maintaining a capital structure that enables us to access capital as needed;
maintaining a consistent and competitive dividend for shareholders; and
creating and maintaining diversified customer base, energy portfolio and utility foundation.
(b) Highlights and Recent Developments
On October 28, 2009, we completed the previously announced merger with FPU. As a result of the merger, FPU became a wholly-owned subsidiary of Chesapeake. The merger allowed us to become a larger energy company serving approximately 200,000 customers in operatingthe Mid-Atlantic and Florida markets, which is twice the number of energy customers we served previously. The merger increased our overall presence in Florida by adding approximately 51,000 natural gas distribution customers and 12,000 propane distribution customers to our existing natural gas and propane distribution operations in Florida. It also introduces us to the electric distribution business as it incorporates FPU’s approximately 31,000 electric customers in northwest and northeast Florida.
Total consideration paid by Chesapeake in the merger was approximately $75.7 million, which included approximately $16,000 paid in cash and 2,487,910 shares of common stock issued at a price per share of $30.42. Net fair value of the assets acquired and liabilities assumed in the merger was estimated at $42.3 million. This resulted in a purchase premium of $33.4 million, which was reflected as goodwill. All of the purchase premium paid in the merger was related to the regulated energy segment. Chesapeake also incurred approximately $3.0 million in merger-related costs related to consummating the merger, merger-related litigation costs and costs incurred in integrating operations of the two companies. As we intend to seek recovery through future rates of the premium paid and merger-related costs we incurred, we have deferred approximately $1.5 million of the merger-related costs as a regulatory asset as of December 31, 2009.
Our net income for 20072009 was attained$15.9 million, or $2.15 per share (diluted), compared to $13.6 million, or $1.98 per share (diluted), for 2008. These results include approximately $1.5 million in costs expensed in 2009 and $1.2 million in costs related to our initial merger discussions with FPU, which were terminated in 2008. The 2009 results also include approximately $1.8 million in net income contributed by FPU for the period from the Company’s natural gas, propane,merger closing (October 28, 2009) to December 31, 2009. Excluding these merger-related items and advanced information services business segments.net income contributed by FPU, our net income would have been $15.3 million and $14.3 million, or $2.20 per share (diluted) and $2.08 per share (diluted), in 2009 and 2008, respectively.
| | | | | | | | |
| | | | | | | Percentage | |
| (In thousands) | 2007 | 2006 | Change | | | Change | |
| Natural gas | $22,485 | $19,733 | $2,752 | | | 14% |
| Propane | 4,498 | 2,534 | 1,964 | | | 78% |
| Advanced information services | 836 | 767 | 69 | | | 9% |
| Other & eliminations | 295 | 298 | (3) | | | -1% |
| Total operating income | $28,114 | $23,332 | $4,782 | | | 100% |
The natural gas segment benefited fromfollowing is a summary of key factors affecting our businesses and their impacts on our 2009 results. More detailed discussion and analysis are provided in the additional transportation capacity contracts implemented by Eastern Shore, continued customer growth from the distribution operations, rate increases, and the impact“Results of colder temperatures on the Delmarva Peninsula that were 15 percent colder in 2007 than in 2006. The propane segment benefited from the colder temperatures on the Delmarva Peninsula and also from the volatility in wholesale propane prices experienced in 2007.Operations” section.
Key financial and operational highlights for fiscal year 2007 include the following:
· | New transportation capacity contracts implemented by Eastern Shore• | | Weather. Weather in November 2006 provided for 26,200 Dts of firm transportation capacity per day2009 was seven percent colder than 2008 and six percent colder than normal on the Delmarva Peninsula. We estimate that colder weather contributed $3.1approximately $1.6 million ofin additional gross margin for our regulated energy and unregulated energy operations on the Delmarva Peninsula in 2007.2009 compared to 2008. |
· | On August 11, 2007, Eastern Shore received authorization from• | | Growth. Customer growth continued to be affected by current economic conditions. Despite the FERC to commence construction of a portion ofslowdown in growth in the Phase II facilities (approximately 4 miles) of the 2006-2008 Expansion Project. These additional facilities, which were completedregion, our Delaware and placed in service on November 1, 2007 provide for 8,300 Dts of additional firm capacity per day generating annualized gross margin of $1.2 million. |
· | The base rate increase that the Company received from the Maryland PSC on September 26, 2006, for our Maryland natural gas operations,distribution divisions achieved customer growth in 2009 compared to 2008, which contributed $693,000 of additional$1.2 million in gross margin in 2007. |
· | Effective September 1, 2007,for the FERC authorized Eastern Shore to commence the billing of increased rates agreed to in a settlement with its customers, which the FERC formally approved in January 2008. These increased rates provided for an additional $563,000 of gross margin in 2007. |
· | On August 21, 2007, the Delaware PSC authorized the Company to implement temporary rates with its customers, subject to refund, pending the completion of full evidentiary hearings and a final decision by the Delaware PSC. |
· | Customer growth in the natural gas and propane businesses remained strong, with the Delmarva andyear. Chesapeake’s Florida natural gas distribution operations registering sevendivision experienced a net customer loss in 2009, which resulted in a gross margin decrease of $190,000. A loss of three large industrial customers in Florida in late 2008 and five2009 contributed primarily to this gross margin decrease. Our natural gas transmission subsidiary, ESNG, experienced continued growth in 2009 through new transmission services and new expansion facilities. New firm services to an industrial customer in 2009 contributed $811,000 to ESNG’s gross margin in 2009 and are expected to contribute approximately $1.1 million to its gross margin in 2010. New system expansions in November 2008 and 2009 also contributed $939,000 to its gross margin growth in 2009. |
Page 34 Chesapeake Utilities Corporation 2009 Form 10-K
| • | | Propane Prices. A sharp decline in propane prices in late 2008 resulted in inventory and swap valuation adjustments of $1.8 million in 2008, but allowed our Delmarva propane distribution operation to keep its propane cost low during the first half of 2009. The absence of similar inventory valuation adjustments in 2009 and increased margin generated from the low propane cost during the first half of 2009, coupled with sustained retail prices, contributed to increased gross margin of $3.5 million in 2009 compared to 2008 for the Delmarva propane distribution operation. Overall lack of volatility in wholesale propane prices reduced opportunities for our propane wholesale marketing subsidiary, Xeron, and decreased its trading volume by 57 percent increases in residential customers, respectively,2009 compared to 2008, which reduced its gross margin by approximately $1.0 million. |
| • | | Natural Gas Spot Sale Opportunities. Our unregulated natural gas marketing subsidiary, PESCO, was able to identify various spot sale opportunities in 2009, which contributed significantly to the overall gross margin increase of $1.0 million in 2009. During 2009, PESCO sold natural gas and services of $10.6 million to Valero for its Delaware City refinery operation. Late in 2009, Valero announced its intention to permanently shut down that refinery. While PESCO’s sale to Valero in 2009 represented approximately 19 percent of PESCO’s total revenue for the year, spot sales are not predictable, and, therefore, are not included in our long-term financial plans or forecasts; nor do we anticipate sales to Valero in the future. |
| • | | Rates and Regulatory Matters. In July 2009, Chesapeake’s Florida natural gas distribution division filed with the Florida PSC its petition for a rate increase. In August 2009, the Florida PSC approved an interim rate increase of approximately $418,000. In December 2009, the Florida PSC approved a permanent rate increase of approximately $2.5 million, applicable to all meters read on or after January 14, 2010. In December 2009, FPU’s natural gas distribution operation settled its request for a permanent rate increase, which had been approved by the Florida PSC in May 2009; however in June 2009, certain parts of the order approving the increase were protested by the Office of Public Counsel. The settlement allows an annual rate increase of approximately $8.0 million for FPU’s natural gas distribution operations. |
| • | | Information Technology Spending. The state of the economy continued to affect overall information technology spending in 2009. Our advanced information services subsidiary, BravePoint, continued to experience lower consulting revenues as billable consulting hours declined by 28 percent in 2009 compared to 2008. We implemented cost-containment actions, including layoffs and compensation adjustments, which reduced operating costs in 2009 by $1.0 million. BravePoint’s professional database monitoring and support solution services, added $218,000 to its gross margin in 2009. |
| • | | Interest Rates. We continued to experience low short-term interest rates throughout 2009 as our short-term weighted average interest rate decreased to 1.28 percent in 2009, compared to 2.79 percent in 2008. The level of our short-term borrowings in 2009 was reduced by the placement of $30.0 million of 5.93 percent Unsecured Senior Notes in October 2008 and a decline in working capital requirements due to lower commodity prices, lower trading volume by the propane wholesale marketing subsidiary, lower income tax payments from bonus depreciation and the Delmarva Community Gas Systems (“CGS”) generating a 22 percent increase in propane distribution customers.timing of our capital expenditures. |
· | For the year ended December 31, 2007, the Company generated $25.7 million in operating cash attributed to net income of $13.2 million and $12.5 million in net cash from other operating activities, which includes $9.1 million in depreciation and amortization. |
· | The Company continued to invest in property, plant and equipment to support current and future growth opportunities and utilized $31.3 million of cash in 2007 for such expenditures. |
The Company’s financial performance is discussed in greater detail below in Results of Operations.
(c) Critical Accounting Policies
Chesapeake prepares itsWe prepare our financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”).GAAP. Application of these accounting principles requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingencies during the reporting period. Chesapeake bases itsWe base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. MostSince most of Chesapeake’sour businesses are regulated accordingly,and the accounting methods used by these businesses must comply with the requirements of the regulatory bodies; therefore,bodies, the choices available are limited by these regulatory requirements. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from estimates. Management believes that the following policies require significant estimates or other judgments of matters that are inherently uncertain. These policies and their application have been discussed with Chesapeake’sour Audit Committee.
Chesapeake Utilities Corporation 2009 Form 10-K Page 35
Regulatory Assets and Liabilities
As a result of the ratemaking process, Chesapeake recordswe record certain assets and liabilities in accordance with Statement of FinancialFASB Accounting Standards Codification (“SFAS”ASC”) No. 71 “Accounting for the Effects of Certain Types of Regulation,Topic 980, “Regulated Operations,” and consequently, the accounting principles applied by our regulated utilitiesenergy businesses differ in certain respects from those applied by the unregulated businesses. Costs are deferred when there is a probable expectation that they will be recovered in future revenues as a result of the regulatory process. As more fully described in Note AItem 8 under the heading “Notes to the Consolidated Financial Statements Chesapeake had– Note A, Summary of Accounting Policies,” we have recorded regulatory assets of $4.1$21.1 million and regulatory liabilities of $27.7$46.3 million, at December 31, 2007.2009. If the Companywe were required to terminate application of SFAS No. 71, itthis Topic, we would be required to recognize all such deferred amounts as a charge or a credit to earnings, net of applicable income taxes. Such an adjustment could have a material adverse effect on the Company’sour results of operations.
Valuation of Environmental Assets and Liabilities
As more fully described in Note MItem 8 under the heading “Notes to the Consolidated Financial Statements Chesapeake has– Note O, Environmental Commitments and Contingencies,” we have completed itsour responsibilities related to one environmental site and isare currently participating in the investigation, assessment or remediation of threeseven other former manufactured gas plant sites. Amounts have been recorded as environmental liabilities and associated environmental regulatory assets based on estimates of future costs provided by independent consultants. There is uncertainty in these amounts, because the United States Environmental Protection Agency (“EPA”), or other applicable state environmental authority, may not have selected the final remediation methods. In addition, there is uncertainty with regard to amounts that may be recovered from other potentially responsible parties.
Since the Company’s management believeswe believe that recovery of these expenditures, including any litigation costs, is probable through the regulatory process, the Company haswe have recorded in accordance with SFAS 71, a regulatory asset and corresponding regulatoryenvironmental liability. At December 31, 2007, Chesapeake had2009, we have recorded an environmental regulatory asset of $851,000$7.5 million and a regulatory liability of $227,000 for over-collections and an additional liability of $835,000$12.8 million for environmental costs.
Derivatives
Derivatives
Chesapeake mayWe use derivative and non-derivative instruments to manage the risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane. We also use derivative instruments to manageengage in propane marketing activities. We continually monitor the price risk of its natural gas and propane purchasing activities. The use of these instruments is subject to the Company’sensure compliance with our risk management policies which are continually monitoredand account for compliance. Derivative instruments utilized in connection with these activities and services are accountedthem in accordance with SFAS 133, Accounting for Derivative Instruments and Hedging Activities, under which Chesapeake either recordsappropriate GAAP. If these instruments do not meet the fair valuedefinition of derivatives held as assetsor are considered “normal purchases and liabilities. If the derivative contracts meets the “normal purchase and normal sale” scope exception of SFAS 133, the related activities and servicessales,” they are accounted for on an accrual basis of accounting.
The following is a review of Chesapeake’sour use of derivative activityinstruments at December 31, 20072009 and 2006:2008:
· | The natural gas distribution and marketing operations entered into physical contracts for the purchase and sale of natural gas. These physical contracts qualify for the “normal purchases and normal sales” scope exception under SFAS 133 at December 31, 2007 and 2006 in that they provide for the purchase or sale of natural gas that will be delivered in quantities expected to be used or sold by the Company over a reasonable period of time in the normal course of business. Accordingly, they are not subject to the accounting requirements of SFAS No. 133. |
· | During 2007 and 2006, Chesapeake’s propane distribution operations entered into physical contracts to buy propane supplies. These contracts qualify for the “normal purchases and normal sales” scope exception under SFAS 133 in that they provide for the purchase or sale of propane that will be delivered in quantities expected to be used or sold by the Company over a reasonable period of time in the normal course of business. Accordingly, the related liabilities incurred and assets acquired under these contracts are recorded when title to the underlying commodity passes. |
During 2006,2009 and 2008, our natural gas distribution, electric distribution, propane distribution and natural gas marketing operations entered into physical contracts for purchase or sale of natural gas, electricity and propane. These contracts either did not meet the definition of derivatives as they did not have a minimum requirement to purchase/sell or were considered “normal purchases and sales” as they provided for the purchase or sale of natural gas, electricity or propane to be delivered in quantities expected to be used and sold by our operations over a reasonable period of time in the normal course of business. Accordingly, these contracts were accounted for on the accrual basis of accounting.
During 2008, the propane distribution operation had entered into a swap agreement to protect the Companyit from the impact of price increases on our price-cap planthe Pro-Cap (propane price-cap) Plan that we offer to customers. The Companypropane prices declined significantly in late 2008 and we recorded a mark-to-market adjustment of approximately $939,000, which increased our cost of propane sales in 2008. In January 2009, we terminated this swap agreement. During 2009, we purchased a put option related to the Pro-Cap Plan, which we accounted for on a mark-to-market basis and recorded a loss of $41,000.
Page 36 Chesapeake Utilities Corporation 2009 Form 10-K
Xeron, our propane wholesale marketing subsidiary, enters into forward, futures and other contracts that are considered this agreement to be an economic hedge that did not qualify for hedge accounting as described in SFAS 133. Atderivatives. These contracts are marked-to-market, using prices at the end of each reporting period, and unrealized gains or losses are recorded in the period,Consolidated Statement of Income as revenue or expense. These contracts generally mature within one year and are almost exclusively for propane commodities. For the market priceyears ended December 31, 2009 and 2008, these contracts had net unrealized losses of propane dropped below the unit price within the swap agreement. As a result$1.6 million and net unrealized gains of the price drop, the Company marked the agreement to market, which resulted in an unrealized loss in 2006 of $84,000. The Company did not enter into a similar swap agreement in 2007.
· | Chesapeake’s propane wholesale marketing operation enters into forward and futures contracts that are considered derivatives under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” In accordance with that pronouncement, open positions are marked to market prices at the end of each reporting period and unrealized gains or losses are recorded in the Consolidated Statement of Income as revenue. The contracts all mature within one year and are almost exclusively for propane commodities, with delivery points of Mt. Belvieu, Texas; Conway, Kansas; and Hattiesburg, Mississippi. Management estimates the market valuation based on references to exchange-traded futures prices, historical differentials and actual trading activity at the end of the reporting period. At December 31, 2007, these contracts had net unrealized gains of $179,000 that were recorded in the financial statements. At December 31, 2006, these contracts had net unrealized gains of $8,500 that were recorded in the financial statements. Commodity price volatility may have a significant impact on the gain or loss in any given period. |
$1.4 million, respectively.
Operating Revenues
Revenues for theour natural gas and electric distribution operations of the Company are based on rates approved by the PSCs of the jurisdictions in which we operate. The natural gas transmission operation’s revenues are based on rates approved by the FERC. Customers’ base rates may not be changed without formal approval by these commissions. However, the regulatory authoritiesThe PSCs, however, have granted the Company’sauthorized our regulated natural gas distribution operations the ability to negotiate rates, based on approved methodologies, with customers that have competitive alternatives. In addition, the natural gas transmission operation canThe FERC has also authorized ESNG to negotiate rates above or below the FERC-approved tariffmaximum rates, which customers can elect as a recourse to negotiated rates.
For regulated deliveries of natural gas Chesapeake readsand electricity, we read meters and billsbill customers on monthly cycles that do not coincide with the accounting periods used for financial reporting purposes. Chesapeake accruesWe accrue unbilled revenues for natural gas and electricity that hashave been delivered, but not yet billed, at the end of an accounting period to the extent that they do not coincide. In connection with this accrual, Chesapeakewe must estimate the amountamounts of natural gas and electricity that hashave not been accounted for on itsour delivery systemsystems and must estimate the amount of the unbilled revenue by jurisdiction and customer class. A similar computation is made to accrue unbilled revenues for propane customers with meters, such as community gas system customers.customers, and natural gas marketing customers, whose billing cycles do not coincide with the accounting periods.
The propane wholesale marketing operation records trading activity for open contracts on a net mark-to-market basis in the Company’sour income statement, for open contracts. Thestatement. For certain propane distribution customers without meters and advanced information services and other segmentscustomers, we record revenue in the period the products are delivered and/or services are rendered.
The Company chargesWe charge flexible rates to the natural gas distribution’s industrial interruptible customers to make them competitive with alternative types of fuel. Based on pricing, these customers can chooseour natural gas ordistribution systems to compete with the price of alternative fuels.fuel that they can use. Neither the Company nor theits interruptible customercustomers is contractually obligated to deliver or receive natural gas.gas on a firm service basis.
Allowance for Doubtful Accounts
An allowance for doubtful accounts is recorded against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect based upon our collections experiences, the condition of the overall economy and our assessment of our customers’ inability or reluctance to pay. If circumstances change, however, our estimate of the recoverability of accounts receivable may also change. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas, electricity and propane prices and general economic conditions. Accounts are written off once they are deemed to be uncollectible.
Chesapeake Utilities Corporation 2009 Form 10-K Page 37
Pension and Other Postretirement Benefits
Pension and other postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected returns on plan assets, assumed discount rates, the level of contributions made to the plans, current demographic and actuarial mortality data. The assumed discount rates and the expected returns on plan assets are the assumptions that generally have the most significant impact on the pension costs and liabilities. The assumed discount rates, the assumed health care cost trend rates and the assumed rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities. Additional information is presented in Item 8 under the heading “Notes to the Consolidated Financial Statements – Note M, Employee Benefit Plans,” including plan asset investment allocation, estimated future benefit payments, general descriptions of the plans, significant assumptions, the impact of certain changes in assumptions, and significant changes in estimates.
The total pension and other postretirement benefit costs included in operating income were $892,000, $537,000, and $370,000 in 2009, 2008 and 2007, respectively. The Company expects to record pension and postretirement benefit costs in the range of $900,000 to $1.0 million for 2010 of which $275,000 is attributed to FPU’s pension and medical plans. Actuarial assumptions affecting 2010 include expected long-term rates of return on plan assets of 6.0 percent and 7.0 percent for Chesapeake’s pension plan and FPU’s pension plan, respectively, and discount rates of 5.25 percent and 5.50 percent for Chesapeake’s plan and FPU’s plan, respectively. The discount rate for each plan was determined by management considering high quality corporate bond rates based on Moody’s Aa bond index, the Citigroup yield curve, changes in those rates from the prior year, and other pertinent factors, such as the expected lives of the plans and the lump-sum-payment option.
Acquisition Accounting
The merger with FPU was accounted for under the acquisition method of accounting, with Chesapeake treated as the acquirer. The acquisition method of accounting requires, among other things, that the assets acquired and liabilities assumed in the merger be recognized at their fair value as of the acquisition date. It also establishes that the consideration transferred be measured at the closing date of the merger at the then-current market price. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In addition, market participants are assumed to be buyers and sellers in the principal (or the most advantageous) market for the asset or liability and fair value measures for an asset assume the highest and best use by those market participants, rather than our intended use of those assets. Many of these fair value measurements can be highly subjective and it is also possible that others applying reasonable judgment to the same facts and circumstances could develop and support a range of alternative estimated amounts. In estimating the fair value of the assets and liabilities subject to rate regulation, we considered the nature and impact of regulations on those assets and liabilities as a factor in determining their appropriate fair value. We also considered the existence of a regulatory process that would allow, or sometimes require, regulatory assets and liabilities to be established to offset the fair value adjustment to certain assets and liabilities subject to rate regulation. If a regulatory asset or liability should be established to offset the fair value adjustment based on the current regulatory process, as was the case for fuel contracts and long-term debt, we did not “gross-up” our balance sheet to reflect the fair value adjustment and corresponding regulatory asset/liability, because such “gross-up” would not have resulted in a change to the value of net assets and future earnings of the Company.
Total consideration paid by Chesapeake in the merger was $75.7 million. Net fair value of the assets acquired and liabilities assumed in the merger was estimated to be $42.3 million. This resulted in a purchase premium of $33.4 million, which was reflected as goodwill. Item 8 under the heading “Notes to the Consolidated Financial Statements – Note B, Acquisitions and Dispositions” describes more fully the purchase price allocation.
Page 38 Chesapeake Utilities Corporation 2009 Form 10-K
The acquisition method of accounting also requires acquisition-related costs to be expensed in the period in which those costs are incurred, rather than including them as a component of consideration transferred. It also prohibits an accrual of certain restructuring costs at the time of the merger for the acquiree. As we intend to seek recovery in future rates in Florida of a certain portion of the purchase premium paid and merger-related costs incurred, we also considered the impact of ASC Topic 980, “Regulated Operations,” in determining proper accounting treatment for the merger-related costs. During 2009, we incurred approximately $3.0 million to consummate the merger, including the cost associated with merger-related litigation, and to integrate operations following the merger. We deferred approximately $1.5 million of the total costs incurred as a regulatory asset at December 31, 2009, which represents our best estimate, based on similar proceedings in Florida in the past, of the costs, which we expect to be permitted to recover when we complete the appropriate rate proceedings. The remaining $1.5 million in costs have been expensed in our 2009 results.
(d) Results of Operations
| | | | | | | | | | | | | | | | | | | | | | | | | |
| (in thousands except per share) | | | | | | | | | | Increase | | | | | | | | | | | Increase | |
| For the Years Ended December 31, | | 2009 | | | 2008 | | | (decrease) | | | 2008 | | | 2007 | | | (decrease) | |
Business Segment: | | | | | | | | | | | | | | | | | | | | | | | | |
| Regulated Energy | | $ | 26,900 | | | $ | 24,733 | | | $ | 2,167 | | | $ | 24,733 | | | $ | 21,809 | | | $ | 2,924 | |
| Unregulated Energy | | | 8,158 | | | | 3,781 | | | | 4,377 | | | | 3,781 | | | | 5,174 | | | | (1,393 | ) |
| Other | | | (1,322 | ) | | | (35 | ) | | | (1,287 | ) | | | (35 | ) | | | 1,131 | | | | (1,166 | ) |
| | | | | | | | | | | | | | | | | | | |
Operating Income | | | 33,736 | | | | 28,479 | | | | 5,257 | | | | 28,479 | | | | 28,114 | | | | 365 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Other Income | | | 165 | | | | 103 | | | | 62 | | | | 103 | | | | 291 | | | | (188 | ) |
| Interest Charges | | | 7,086 | | | | 6,158 | | | | 928 | | | | 6,158 | | | | 6,590 | | | | (432 | ) |
| Income Taxes | | | 10,918 | | | | 8,817 | | | | 2,101 | | | | 8,817 | | | | 8,597 | | | | 220 | |
| | | | | | | | | | | | | | | | | | | |
| Net Income from Continuing Operations | | | 15,897 | | | | 13,607 | | | | 2,290 | | | | 13,607 | | | | 13,218 | | | | 389 | |
| Loss from Discontinued Operations | | | — | | | | — | | | | — | | | | — | | | | (20 | ) | | | 20 | |
| | | | | | | | | | | | | | | | | | | |
Net Income | | $ | 15,897 | | | $ | 13,607 | | | $ | 2,290 | | | $ | 13,607 | | | $ | 13,198 | | | $ | 409 | |
| | | | | | | | | | | | | | | | | | | |
Diluted Earnings (Loss) Per Share | | | | | | | | | | | | | | | | | | | | | | | | |
| Continuing operations | | $ | 2.15 | | | $ | 1.98 | | | $ | 0.17 | | | $ | 1.98 | | | $ | 1.94 | | | $ | 0.04 | |
| Discontinued operations | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | |
| Diluted Earnings Per Share | | $ | 2.15 | | | $ | 1.98 | | | $ | 0.17 | | | $ | 1.98 | | | $ | 1.94 | | | $ | 0.04 | |
| | | | | | | | | | | | | | | | | | | |
| Net Income & Diluted Earnings Per Share Summary | | | | | | | | | | |
| | | | | | | | | Increase | | | | | | | | | Increase | |
| For the Years Ended December 31, | | 2007 | | | 2006 | | | (decrease) | | | 2006 | | | 2005 | | | (decrease) | |
| Net Income * | | | | | | | | | | | | | | | | | | |
| Continuing operations | | $ | 13,218 | | | $ | 10,748 | | | $ | 2,470 | | | $ | 10,748 | | | $ | 10,699 | | | $ | 49 | |
| Discontinued operations | | | (20 | ) | | | (241 | ) | | | 221 | | | | (241 | ) | | | (231 | ) | | | (10 | ) |
| Total Net Income | | $ | 13,198 | | | $ | 10,507 | | | $ | 2,691 | | | $ | 10,507 | | | $ | 10,468 | | | $ | 39 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Diluted Earnings (Loss) Per Share | | | | | | | | | | | | | | | | | | | | | |
| Continuing operations | | $ | 1.94 | | | $ | 1.76 | | | $ | 0.18 | | | $ | 1.76 | | | $ | 1.81 | | | $ | (0.05 | ) |
| Discontinued operations | | | - | | | | (0.04 | ) | | | 0.04 | | | | (0.04 | ) | | | (0.04 | ) | | | - | |
| Total Earnings Per Share | | $ | 1.94 | | | $ | 1.72 | | | $ | 0.22 | | | $ | 1.72 | | | $ | 1.77 | | | $ | (0.05 | ) |
| * Dollars in thousands. | | | | | | | | | | | | | | | | | | | | | | | | |
Our net income increased by approximately $2.3 million in 2009 compared to 2008. Net income was $15.9 million, or $2.15 per share (diluted), for 2009, compared to $13.6 million, or $1.98 per share (diluted), for 2008. Our 2009 results include approximately $1.8 million in net income from FPU for the period from the merger closing (October 28, 2009) to December 31, 2009. Our 2009 results also include approximately $1.5 million of merger-related costs expensed by the Company, compared to $1.2 million in merger-related costs expensed in 2008. Absent the effect of the merger and merger-related costs, we estimate that net income would have been $15.3 million, or $2.20 per share (diluted), in 2009, compared to $14.3 million, or $2.08 per share (diluted), in 2008.
During 2009, Chesapeake incurred approximately $3.0 million related to consummating the merger, merger-related litigation costs and costs of integrating operations of the two companies. New accounting standards applicable to acquisitions, which became effective in 2009, require companies to expense merger-related costs in the periods in which they are incurred. Under the previous accounting standards, most of these merger-related costs would have been considered a part of purchase price or liabilities assumed at the merger and thus not expensed. In accounting for our merger-related costs, we also considered the potential impact of the future regulatory process as we intend to seek recovery in future rates of the premium paid and merger-related costs incurred. Similar recovery treatment has been pursued successfully by other regulated utilities. As we account for our regulated operations in accordance with ASC Topic 980, “Regulated Operations,” certain costs that would otherwise have been expensed by unregulated enterprises may be deferred to reflect the potential impact of the regulatory and rate-making actions. With regard to the $3.0 million in merger-related costs incurred in 2009, we deferred approximately $1.5 million as a regulatory asset, which represents our estimate, based on similar proceedings in Florida in the past, of the costs that we expect to be permitted to recover when we complete the appropriate rate proceedings.
Chesapeake Utilities Corporation 2009 Form 10-K Page 39
During 2008, we incurred and expensed approximately $1.2 million in merger-related costs. These costs were related to our initial merger discussions with FPU, which were terminated in the second quarter of 2008.
Our operating income increased by $5.3 million in 2009 compared to 2008. Included in operating income for 2009 and 2008 are the $1.5 million and $1.2 million merger-related costs expensed in 2009 and 2008, respectively, which are included in the “Other” segments. Operating income from our regulated energy segment increased by $2.2 million in 2009. This increase is attributed to $3.0 million of FPU operating income for the period after the merger and an increase in operating income from the natural gas transmission operations through continued growth and new services. Offsetting those increases was a decrease in operating income from Chesapeake’s Florida natural gas distribution operation as a result of lower-than-expected customer growth and loss of industrial customers. Operating income for our unregulated energy segment increased by $4.4 million, which includes $553,000 in operating income from FPU after the merger. The Company’sDelmarva propane distribution operation contributed most of the increase in operating income by this segment. Delmarva propane distribution operation recorded $1.8 million in unfavorable propane inventory and swap valuation adjustments in 2008, which did not recur in 2009. These adjustments to the inventory costs in late 2008 and relatively low propane prices during the first half of 2009 allowed the Delmarva propane distribution operation to maintain low propane inventory costs while sustaining its retail margins. Operating income for the “Other” segment decreased by $1.3 million, primarily due to lower operating results by the advanced information services operation and higher merger-related costs expensed in 2009. The operating results of the advanced information services operation continued to be negatively affected by the lower levels of information technology spending experienced in the economy at large.
During 2009, we recognized increased corporate overhead costs of $1.2 million compared to 2008, which were allocated to all of our segments. Payroll and benefits costs in corporate overhead increased by $961,000 and $225,000, respectively, due to higher incentive compensation based on improved operating results and increased costs associated with filling several key corporate positions in 2008 and 2009. Also contributing to the increase were additional costs associated with investor relations and financial reporting activities and increased pension costs as a result of a decline in the value of pension investments in late 2008.
An increase of $928,000 in interest charges in 2009 compared to 2008 partially offset the increased operating results. This increase reflects primarily the interest expense on FPU’s long-term debt and customer deposits and the placement of the $30 million Unsecured Senior Notes in October 2008.
We continued to invest in property, plant and equipment in 2009 to support current and future growth opportunities, expending $26.3 million for such purposes.
2008 Compared to 2007
Our net income from continuing operations increased $2.5 millionby $389,000 in 2007 when2008 compared to 2006.2007. Net income from continuing operations was $13.22$13.6 million, or $1.98 per share (diluted), for 2008, compared to $13.2 million, or $1.94 per share (diluted), in 2007. Our 2008 results include a charge of $1.2 million for 2007, compared to amerger-related costs that were expensed in the second quarter of 2008 when our initial merger discussions with FPU were terminated. Absent the charge for the unconsummated acquisition, the Company estimates that period-over-period net income from continuing operations of $10.75would have increased by $1.1 million in 2008 to $14.3 million, or $1.76$2.08 per share (diluted) in 2006..
Page 40 Chesapeake Utilities Corporation 2009 Form 10-K
The Company’s net income from continuing operations increased $49,000 in 2006 when compared to 2005. Net income from continuing operations was $10.75 million, or $1.76 per share (diluted), for 2006, compared to a net income from continuing operations of $10.70 million, or $1.81 per share (diluted) in 2005.
During 2007, Chesapeakewe decided to close itsthe distributed energy services company, ChesapkeakeChesapeake OnSight Services, LLC (“OnSight”), which consistently experienced operating losses since 2004. At December 31, 2007, theThe results of operations for OnSight have been reclassifiedwere classified to discontinued operations and shown net of tax for all periods presented. For 2007, thetax. The discontinued operations experienced a net loss of $20,000 for 2007.
Our operating income increased by $365,000 in 2008 compared to a net loss2007, including $1.2 million in merger-related costs expensed in 2008, which are included in the “Other” segment. Operating income from recurring operations increased by $1.5 million in 2008 compared to 2007. Our regulated energy segment achieved an increase of $241,000, or $0.04 per share (diluted), for 2006 and a net loss of $231,000, or $0.04 per share (diluted), for 2005.
| Operating Income Summary (in thousands) | | | | | | | | | | | | | |
| | | | | | | | | Increase | | | | | | | | | Increase | |
| For the Years Ended December 31, | | 2007 | | | 2006 | | | (decrease) | | | 2006 | | | 2005 | | | (decrease) | |
| Business Segment: | | | | | | | | | | | | | | | | | | |
| Natural gas | | $ | 22,485 | | | $ | 19,733 | | | $ | 2,752 | | | $ | 19,733 | | | $ | 17,236 | | | $ | 2,497 | |
| Propane | | | 4,498 | | | | 2,534 | | | | 1,964 | | | | 2,534 | | | | 3,209 | | | | (675 | ) |
| Advanced information services | | | 836 | | | | 767 | | | | 69 | | | | 767 | | | | 1,197 | | | | (430 | ) |
| Other & eliminations | | | 295 | | | | 298 | | | | (3 | ) | | | 298 | | | | 279 | | | | 19 | |
| Operating Income | | $ | 28,114 | | | $ | 23,332 | | | $ | 4,782 | | | $ | 23,332 | | | $ | 21,921 | | | $ | 1,411 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Other Income | | | 291 | | | | 189 | | | | 102 | | | | 189 | | | | 383 | | | | (194 | ) |
| Interest Charges | | | 6,590 | | | | 5,774 | | | | 816 | | | | 5,774 | | | | 5,132 | | | | 642 | |
| Income Taxes | | | 8,597 | | | | 6,999 | | | | 1,598 | | | | 6,999 | | | | 6,472 | | | | 527 | |
| Net Income from Continuing Operations | | $ | 13,218 | | | $ | 10,748 | | | $ | 2,470 | | | $ | 10,748 | | | $ | 10,700 | | | $ | 48 | |
2007 Compared to 2006
Compared to 2006,$2.9 million in operating income in 2007 increasedfrom new services provided by $4.8 million, or 20 percent. Factors affecting this improvement included the following:
· | New transportation capacity contracts implemented for the natural gas transmission operation in November 2006 and November 2007 provided for $3.3 million of additional gross margin in 2007. |
· | Weather on the Delmarva Peninsula was 15 percent colder in 2007 than 2006, which the Company estimates contributed approximately $2.0 million in additional gross margin for its Delmarva natural gas and propane distribution operations. This amount differs from the $2.2 million of additional gross margin that the Company had expected the colder weather to contribute. The variance occurred as a result of the season or month that the heating degree day variance occurred. |
· | Rate increases to customers of the natural gas transmission and distribution operations in Delaware and Maryland added $1.4 million to gross margin in 2007. |
· | Strong period-over-period residential customer growth of seven percent and five percent, respectively, for the Delmarva and Florida natural gas distribution operations in 2007. |
· | The average gross margin per retail gallon sold to customers increased $0.05 in 2007 for the Delmarva propane distribution operations, which contributed $1.1 million to gross margins. |
· | The Delmarva Community Gas Systems continued to experience strong customer growth as the number of customers increased 22 percent in 2007 compared to 2006. |
2006 Compared to 2005
Operating income in 2006 increased $1.4 million, or 6.5 percent, compared to 2005, despite significantly warmer weather in 2006. The improvement in 2006 results of operations compared to 2005 was affected by the following factors:
· | Weather on the Delmarva Peninsula was 18 percent warmer in 2006 than in 2005; as a result, the Company estimates that 2006 gross margin for its Delmarva natural gas and propane distribution operations was approximately $3.4 million less than in 2005. |
· | Strong residential customer growth of nine percent and eight percent, respectively, for the Delmarva and Florida natural gas distribution operations in 2006. |
· | The natural gas transmission operation achieved gross margin growth of $1.8 million, or 11 percent, due to additional capacity contracts that went into effect in November 2005 and November 2006. |
· | A 67 percent increase in the number of customers for the Company’s natural gas marketing operation. |
· | Gross margin for the Delmarva propane distribution operations decreased $834,000, primarily, as a result of the warmer weather in 2006. |
· | The Delmarva Community Gas Systems continued to experience strong customer growth increasing by 34 percent in 2006 compared to 2005. |
· | Operating income for the advanced information services segment decreased $430,000 in 2006. Although revenues from consulting increased $749,000 in 2006, the 2005 results contained $993,000 of operating income for the Lightweight Association Management Processing Systems (“LAMPSTM”) product, which was sold in the fourth quarter 2005. The LAMPSTM product was an internally developed software that was developed and marketed specifically for REALTOR® Associations.
|
Natural Gas
The natural gas segment earned operating income of $22.5 million for 2007, $19.7 million for 2006, and $17.2 million for 2005, resulting in increases of $2.8 million, or 13.9 percent for 2007, and $2.5 million, or 14.5 percent, for 2006.
| Natural Gas (in thousands) | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Increase | | | | | | | | | Increase | |
| For the Years Ended December 31, | | 2007 | | | 2006 | | | (decrease) | | | 2006 | | | 2005 | | | (decrease) | |
| Revenue | | $ | 181,202 | | | $ | 170,374 | | | $ | 10,828 | | | $ | 170,374 | | | $ | 166,582 | | | $ | 3,792 | |
| Cost of gas | | | 121,550 | | | | 117,948 | | | | 3,602 | | | | 117,948 | | | | 116,178 | | | | 1,770 | |
| Gross margin | | | 59,652 | | | | 52,426 | | | | 7,226 | | | | 52,426 | | | | 50,404 | | | | 2,022 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Operations & maintenance | | | 26,024 | | | | 22,673 | | | | 3,351 | | | | 22,673 | | | | 23,874 | | | | (1,201 | ) |
| Depreciation & amortization | | | 6,918 | | | | 6,312 | | | | 606 | | | | 6,312 | | | | 5,682 | | | | 630 | |
| Other taxes | | | 4,225 | | | | 3,708 | | | | 517 | | | | 3,708 | | | | 3,612 | | | | 96 | |
| Other operating expenses | | | 37,167 | | | | 32,693 | | | | 4,474 | | | | 32,693 | | | | 33,168 | | | | (475 | ) |
| Total Operating Income | | $ | 22,485 | | | $ | 19,733 | | | $ | 2,752 | | | $ | 19,733 | | | $ | 17,236 | | | $ | 2,497 | |
| Heating Degree-Day (HDD) and Customer Analysis | | | | | | | | | | | | | |
| | | | | | | | | | | Increase | | | | | | | | | | | Increase | |
| For the Years Ended December 31, | | 2007 | | | 2006 | | | (decrease) | | | 2006 | | | 2005 | | | (decrease) | |
| Heating degree-day data — Delmarva | | | | | | | | | | | | | | | | | |
| Actual HDD | | | 4,504 | | | | 3,931 | | | | 573 | | | | 3,931 | | | | 4,792 | | | | (861 | ) |
| 10-year average HDD | | | 4,376 | | | | 4,372 | | | | 4 | | | | 4,372 | | | | 4,436 | | | | (64 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Estimated gross margin per HDD | | $ | 1,937 | | | $ | 2,013 | | | $ | (76 | ) | | $ | 2,013 | | | $ | 2,234 | | | $ | (221 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Estimated dollars per residential customer added: | | | | | | | | | | | | | |
| Gross margin | | $ | 372 | | | $ | 372 | | | $ | 0 | | | $ | 372 | | | $ | 372 | | | $ | 0 | |
| Other operating expenses | | $ | 106 | | | $ | 111 | | | $ | (5 | ) | | $ | 111 | | | $ | 106 | | | $ | 5 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Average number of residential customers | | | | | | | | | | | | | | | | | |
| Delmarva | | | 43,485 | | | | 40,535 | | | | 2,950 | | | | 40,535 | | | | 37,346 | | | | 3,189 | |
| Florida | | | 13,250 | | | | 12,663 | | | | 587 | | | | 12,663 | | | | 11,717 | | | | 946 | |
| Total | | | 56,735 | | | | 53,198 | | | | 3,537 | | | | 53,198 | | | | 49,063 | | | | 4,135 | |
2007 Compared to 2006
Gross margin for the Company’s natural gas segment increased by $7.2 million, or 14 percent, and other operating expenses increased $4.5 million, or 14 percent, for 2007 compared to 2006. The gross margin increases of $3.9 million for the natural gas transmission operation, $3.4four-percent customer growth for Chesapeake’s natural gas distribution operations and the successful completion of the Delaware rate proceedings. Our unregulated energy segment experienced a decrease in operating income of $1.4 million, primarily as a result of recording $1.8 million in unfavorable propane inventory and swap valuation adjustments for the Delmarva propane distribution operations in the second half of 2008. The propane inventory valuation adjustments were recorded to adjust the value of propane inventory and price swap agreements to current market prices as propane prices declined significantly during the second half of 2008. Operating income for the “Other” segment decreased by $1.2 million due to the merger-related costs.
During 2008, we experienced increased corporate overhead costs, which were allocated to all of our segments. The increase of $519,000 in corporate overhead costs in 2008 compared to 2007 resulted primarily from increased payroll and benefit costs of $132,000 and $83,000, respectively, as several key corporate positions that were vacant in 2007 were filled in 2008 and increased outside services of $263,000 were incurred primarily for consulting costs relating to an independent third-party compensation survey, strategic planning and growth initiatives.
A decrease of $432,000 in interest charges in 2008 compared to 2007 also contributed to the overall increase in net income in 2008. Even though banks were tightening their lending in response to the financial crisis, we were able to firm up our credit lines during this volatile period by increasing our total committed short-term borrowing capacity from $15.0 million to $55.0 million. In addition, on October 31, 2008, we executed a $30.0 million long-term debt placement of 5.93 percent Unsecured Senior Notes.
Chesapeake Utilities Corporation 2009 Form 10-K Page 41
We continued to invest in property, plant and equipment in 2008 to support current and future growth opportunities, expending $30.8 million for such purposes.
Regulated Energy
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Increase | | | | | | | | | | | Increase | |
| For the Years Ended December 31, | | 2009 | | | 2008 | | | (decrease) | | | 2008 | | | 2007 | | | (decrease) | |
| (in thousands) | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Revenue | | $ | 139,099 | | | $ | 116,468 | | | $ | 22,631 | | | $ | 116,468 | | | $ | 128,850 | | | $ | (12,382 | ) |
| Cost of sales | | | 64,803 | | | | 54,789 | | | | 10,014 | | | | 54,789 | | | | 70,861 | | | | (16,072 | ) |
| | | | | | | | | | | | | | | | | | | |
| Gross margin | | | 74,296 | | | | 61,679 | | | | 12,617 | | | | 61,679 | | | | 57,989 | | | | 3,690 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Operations & maintenance | | | 32,569 | | | | 25,369 | | | | 7,200 | | | | 25,369 | | | | 25,061 | | | | 308 | |
| Depreciation & amortization | | | 8,866 | | | | 6,694 | | | | 2,172 | | | | 6,694 | | | | 6,918 | | | | (224 | ) |
| Other taxes | | | 5,961 | | | | 4,883 | | | | 1,078 | | | | 4,883 | | | | 4,201 | | | | 682 | |
| | | | | | | | | | | | | | | | | | | |
| Other operating expenses | | | 47,396 | | | | 36,946 | | | | 10,450 | | | | 36,946 | | | | 36,180 | | | | 766 | |
| | | | | | | | | | | | | | | | | | | |
| |
Operating Income | | $ | 26,900 | | | $ | 24,733 | | | $ | 2,167 | | | $ | 24,733 | | | $ | 21,809 | | | $ | 2,924 | |
| | | | | | | | | | | | | | | | | | | |
Heating Degree-Day (HDD) and Customer Analysis
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Increase | | | | | | | | | | | Increase | |
| For the Years Ended December 31, | | 2009 | | | 2008 | | | (decrease) | | | 2008 | | | 2007 | | | (decrease) | |
| Heating degree-day data — Delmarva | | | | | | | | | | | | | | | | | | | | | | | | |
| Actual HDD | | | 4,729 | | | | 4,431 | | | | 298 | | | | 4,431 | | | | 4,504 | | | | (73 | ) |
| 10-year average HDD | | | 4,462 | | | | 4,401 | | | | 61 | | | | 4,401 | | | | 4,376 | | | | 25 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Estimated gross margin per HDD | | $ | 2,429 | | | $ | 1,937 | | | $ | 492 | | | $ | 1,937 | | | $ | 1,937 | | | $ | 0 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Estimated dollars per residential customer added: | | | | | | | | | | | | | | | | | | | | | | | | |
| Gross margin | | $ | 375 | | | $ | 375 | | | $ | 0 | | | $ | 375 | | | $ | 372 | | | $ | 3 | |
| Other operating expenses | | $ | 100 | | | $ | 103 | | | $ | (3 | ) | | $ | 103 | | | $ | 106 | | | $ | (3 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Average number of residential customers | | | | | | | | | | | | | | | | | | | | | | | | |
| Delmarva | | | 46,717 | | | | 45,570 | | | | 1,147 | | | | 45,570 | | | | 43,485 | | | | 2,085 | |
| Florida | | | 13,268 | | | | 13,373 | | | | (105 | ) | | | 13,373 | | | | 13,250 | | | | 123 | |
| | | | | | | | | | | | | | | | | | | |
| Total | | | 59,985 | | | | 58,943 | | | | 1,042 | | | | 58,943 | | | | 56,735 | | | | 2,208 | |
| | | | | | | | | | | | | | | | | | | |
2009 Compared to 2008
Operating income for the regulated energy segment increased by approximately $2.2 million, or nine percent, in 2009, compared to 2008, which was generated from a gross margin increase of $12.6 million, offset partially by an operating expense increase of $10.4 million.
Gross Margin
Gross margin for our regulated energy segment increased by $12.6 million, or 20 percent. FPU’s natural gas and electric distribution operations had $9.2 million in gross margin for the period from the merger closing (October 28, 2009) to December 31, 2009, which contributed to this increase.
The natural gas distribution operations for the Delmarva Peninsula generated an increase in gross margin of $1.3 million in 2009. The factors contributing to this increase are as follows:
Despite the continued slowdown in the new housing construction and industrial growth in the region, the Delmarva natural gas distribution operations experienced growth in residential, commercial, and $88,000industrial customers, which contributed $471,000, $149,000 and $589,000, respectively, to the gross margin increase. A two-percent residential customer growth experienced by the Delmarva natural gas distribution operation in 2009 was lower than the growth experienced in recent years and we expect that trend to continue in the near future.
Colder weather on the Delmarva Peninsula contributed $449,000 to the increased gross margin, as heating degree days increased by 298, or seven percent, compared to 2008.
Page 42 Chesapeake Utilities Corporation 2009 Form 10-K
The Delaware division’s new rate structure allows collection of miscellaneous service fees of $256,000, which, although not representing additional revenue, had previously been offset against other operating expenses.
Interruptible sales to industrial customers decreased in 2009 due to a reduction in the price of alternative fuels, which reduced gross margin by $355,000.
Non-weather related customer consumption decreased in 2009, which reduced gross margin by $187,000. The decrease in consumption is a result of conservation primarily by residential customers.
Chesapeake’s Florida natural gas distribution operation experienced a decrease in gross margin of $333,000, in 2009. This decrease was attributable to reduced consumption by residential and non-residential customers and loss of three industrial customers, one in 2008 and two in 2009, due to adverse economic conditions in the region. This decrease was partially offset by an increase to gross margin of $99,000 due to implementation of interim rates in the third quarter of 2009.
The natural gas transmission operations achieved gross margin growth of $2.5 million in 2009. The factors contributing to this increase are as follows:
New long-term transmission services implemented by ESNG in November of 2008 and 2009, which provided for an additional 5,459 Mcfs per day and 3,976 Mcfs per day, respectively, added $939,000 to gross margin in 2009.
New firm transmission services provided to an industrial customer for the period of February 6, 2009 through October 31, 2009, provided for an additional 6,957 Mcfs per day and added $574,000 to gross margin. In addition, ESNG entered into two additional firm transmission service agreements with this customer: (1) 6,006 Mcfs per day from November 1, 2009 through November 30, 2009, which added $56,000 to gross margin for 2009; and (2) 9,662 Mcfs per day from November 1, 2009 through October 31, 2012, which added $181,000 to gross margin in 2009 and will contribute $1.1 million in gross margin in 2010.
In April 2009, ESNG changed its rates to recover specific project costs in accordance with the terms of precedent agreements with certain customers. These new rates generated $381,000 in gross margin for 2009 and will contribute $516,000 annually thereafter for a period of 20 years.
During January 2009, PIPECO, our intra-state pipeline subsidiary in Florida, began to provide natural gas transmission service to a customer under a 20 year contract. This agreement contributed $264,000 to gross margin in 2009.
Other Operating Expenses
Other operating expenses for the regulated energy segment increased by $10.4 million, of which $6.2 million was related to other operating expenses of FPU for the period from the merger closing (October 28, 2009) to December 31, 2009. The remaining increase in other operating expenses is due primarily to the following factors:
Depreciation expense, asset removal costs and property taxes, collectively, increased by approximately $1.4 million as a result of our continued capital investments to support customer growth. Depreciation expense for 2008 also includes a $305,000 depreciation credit as a result of the Delaware negotiated rate settlement agreement in the third quarter of 2008, of which $295,000 related to depreciation for the months of October through December 2007.
Salaries and incentive compensation increased by $803,000, due primarily to compensation adjustments implemented on January 1, 2009 for non-executive employees, based on a compensation survey completed in the fourth quarter of 2008, and annual salary increases, coupled with a slight increase in the accrual for incentive compensation.
The allowance for uncollectible accounts in the natural gas operation increased by $176,000 due to growth in customers and the general economic climate.
Benefit costs increased by $373,000, due primarily to higher pension costs as a result of the decline in the value of pension assets in 2008 and other benefit costs relating to increased payroll costs.
Chesapeake Utilities Corporation 2009 Form 10-K Page 43
Increased information technology spending to continuously enhance our information technology infrastructure and level of support generated increased costs of $285,000.
Corporate overhead allocated to the regulated energy segment increased by approximately $722,000 due to the factors previously discussed.
Other Developments
The following developments, which are not discussed above, may affect the future operating results of the regulated energy segment:
ESNG received notice from a customer of its intention not to renew two firm transmission service contracts, one of which expired in October 2009 and the other is expiring in March 2010. If these contracts are not renewed, or equivalent firm service capacity is not contracted to other customers, gross margin could be reduced by approximately $427,000 in 2010. ESNG also received notice from a smaller customer that it does not intend to renew its firm transmission service contract, which expires in April 2010. Revenue from this contract provides annualized gross margin of approximately $54,000.
In December 2009, the Florida PSC approved a permanent rate increase of approximately $2.5 million for Chesapeake’s Florida natural gas distribution division, applicable to all meters read on or after January 14, 2010. Also in December 2009, FPU’s natural gas distribution operation settled its request for a permanent rate increase, which was approved by the Florida PSC in May 2009; however, in June 2009, certain parts of the order were protested by the Office of Public Counsel. The settlement provides for an annual rate increase of approximately $8.0 million. As a result of the settlement, FPU refunded approximately $290,000 to its customers in February 2010, which represents revenues in excess of the amounts provided by the settlement agreement that had been billed to customers from June 4, 2009 to January 13, 2010.
The Delaware division is currently involved in a regulatory proceeding regarding the price it charged for the temporary release of transmission pipeline capacity to our natural gas marketing subsidiary, PESCO. The Hearing Examiner recommended, among others, a refund to our Delaware firm customers, which could be up to approximately $700,000, exclusive of any interest, as of December 31, 2009. We disagree with the Hearing Examiner’s recommendations and filed exceptions to those recommendations. We have not recorded a liability for this contingency based on our current assessment of the case. We anticipate a ruling by the Delaware PSC in March 2010. Item 8 under the heading, “Notes to the Consolidated Financial Statements – Note P, Other Commitments and Contingencies” provides further discussions on this matter.
2008 Compared to 2007
Operating income for the regulated energy segment increased by approximately $2.9 million in 2008 compared to 2007, which was attributable to a gross margin increase of $3.7 million, offset partially by an operating expense increase of $766,000.
Gross Margin
Gross margin for our regulated segment increased by $3.7 million, or six percent, of which $2.0 million was attributable to the natural gas distribution operations and $1.7 million to the natural gas transmission operation.
The Delmarva natural gas distribution operations generated an increase to gross margin of $1.8 million due to the following factors:
The average number of residential customers on the Delmarva Peninsula increased by 2,085, or five percent, for 2008, and we estimate that these additional residential customers contributed approximately $850,000 to gross margin in 2008.
Growth in commercial and industrial customers contributed $473,000 and $89,000, respectively, to gross margin in 2008.
Interruptible services revenue, net of required margin-sharing, increased by $307,000 as customers took advantage of lower natural gas prices compared to prices for alternative fuels.
Page 44 Chesapeake Utilities Corporation 2009 Form 10-K
We estimate that weather contributed $122,000 to gross margin, despite temperatures on the Delmarva Peninsula being two percent warmer in 2008, compared to 2007.
Partially offsetting these increases to gross margin was the negative impact of lower consumption per customer in 2008 compared to 2007. We estimate that lower consumption per customer reduced gross margin by $118,000. The lower consumption reflects customer conservation efforts in light of higher energy costs, more energy-efficient housing, and current economic conditions.
Gross margin for the Florida natural gas distribution operation were partially offsetincreased by a lower$200,000 in 2008, compared to 2007. The higher gross margin of $207,000 for the period was attributable primarily to a one-percent growth in residential customers, an increase in non-residential customer volumes, and higher revenues from third-party natural gas marketing operation, as further explained below.
Natural Gas Transmissionmarketers.
The natural gas transmission operation achieved gross margin growth of $3.9$1.7 million or 22 percent, in 2007 compared to 2006. Of the $3.92008, $1.2 million increase, $3.3 millionof which was attributable to new transportation capacity contracts implemented in November 2006 and 2007. In 2008, the new transportationtransmission capacity contracts implemented in November 2007 are expected to generate an additional annual gross margin of $1.2 million above 2007 gross margins.and 2008. In addition, the implementation of rate case settlement rates, effective September 1, 2007, contributed an additional $563,000$439,000 to gross marginsmargin in 2007. A further discussion of the FERC rate proceeding is provided in detail within the “Regulatory Activities” listed later in this section.2008. The remaining $43,000$61,000 increase to gross margin was attributable primarily to higher interruptible sales revenue, net of required margin-sharing.
Other Operating Expenses
Other operating expenses for the regulated energy segment increased by approximately $766,000, due primarily to the following factors:
Payroll and benefit costs increased by $486,000 and $152,000, respectively, reflecting annual compensation increases and increased staff to support compliance with new federal pipeline integrity regulations and to serve the additional growth.
Depreciation expense and asset removal costs decreased by approximately $1.5 million, primarily as a result of our Delaware distribution operation’s rate proceedings in 2008 and ESNG’s rate settlement in September 2007, iswhich provided for lower depreciation and asset removal cost allowances. Higher depreciation expense from the increased level of capital investment partially offset this decrease in 2008.
Property taxes increased by approximately $609,000 due to the higher level of capital investment and adjusted property assessments by various jurisdictions.
Vehicle-related costs increased by $132,000 due to higher fuel and depreciation charges.
Information technology costs increased by approximately $517,000 as a result of higher spending to improve the infrastructure, including system performance, disaster recovery and support.
Corporate overhead costs allocated to the regulated energy segment increased by approximately $385,000 as previously discussed.
Chesapeake Utilities Corporation 2009 Form 10-K Page 45
Unregulated Energy
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Increase | | | | | | | | | | | Increase | |
| For the Years Ended December 31, | | 2009 | | | 2008 | | | (decrease) | | | 2008 | | | 2007 | | | (decrease) | |
| (in thousands) | | | | | | | | | | | | | | | | | | | | | | | | |
| |
| Revenue | | $ | 119,973 | | | $ | 161,290 | | | $ | (41,317 | ) | | $ | 161,290 | | | $ | 115,190 | | | $ | 46,100 | |
| Cost of sales | | | 90,408 | | | | 138,302 | | | | (47,894 | ) | | | 138,302 | | | | 91,727 | | | | 46,575 | |
| | | | | | | | | | | | | | | | | | | |
| Gross margin | | | 29,565 | | | | 22,988 | | | | 6,577 | | | | 22,988 | | | | 23,463 | | | | (475 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Operations & maintenance | | | 18,016 | | | | 16,322 | | | | 1,694 | | | | 16,322 | | | | 15,559 | | | | 763 | |
| Depreciation & amortization | | | 2,415 | | | | 2,024 | | | | 391 | | | | 2,024 | | | | 1,842 | | | | 182 | |
| Other taxes | | | 976 | | | | 861 | | | | 115 | | | | 861 | | | | 888 | | | | (27 | ) |
| | | | | | | | | | | | | | | | | | | |
| Other operating expenses | | | 21,407 | | | | 19,207 | | | | 2,200 | | | | 19,207 | | | | 18,289 | | | | 918 | |
| | | | | | | | | | | | | | | | | | | |
| |
Operating Income | | $ | 8,158 | | | $ | 3,781 | | | $ | 4,377 | | | $ | 3,781 | | | $ | 5,174 | | | $ | (1,393 | ) |
| | | | | | | | | | | | | | | | | | | |
Propane Heating Degree-Day (HDD) Analysis — Delmarva
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Increase | | | | | | | | | | | Increase | |
| For the Years Ended December 31, | | 2009 | | | 2008 | | | (decrease) | | | 2008 | | | 2007 | | | (decrease) | |
| Heating degree-days | | | | | | | | | | | | | | | | | | | | | | | | |
| Actual | | | 4,729 | | | | 4,431 | | | | 298 | | | | 4,431 | | | | 4,504 | | | | (73 | ) |
| 10-year average | | | 4,462 | | | | 4,401 | | | | 61 | | | | 4,401 | | | | 4,376 | | | | 25 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Estimated gross margin per HDD | | $ | 3,083 | | | $ | 2,465 | | | $ | 618 | | | $ | 2,465 | | | $ | 1,974 | | | $ | 491 | |
2009 compared to 2008
Operating income for the unregulated energy segment increased by approximately $4.4 million in 2009 compared to 2008, which was attributable to other factors, such as higher interruptible sales. Ana gross margin increase of $2.3$6.6 million, offset partially by an operating expense increase of $2.2 million.
Gross Margin
Gross margin for our unregulated energy segment increased by $6.6 million, or 29 percent, in other operating expenses partially offset2009 compared to 2008. FPU’s propane distribution operation contributed $1.8 million to gross margin during the increased gross margin. The factors contributingperiod from the merger closing (October 28, 2009) to the increase in other operating expenses are as follow:December 31, 2009.
· | Payroll and benefit costs increased by $282,000 and $90,000, respectively, as thePESCO, our natural gas marketing operation, increased its staffing levels to comply with new federal pipeline integrity regulations and to serve the additional growth. The new pipeline integrity regulations require the Company to assess the integrity of each covered segment of its line pipe. These regulations require the assessment of at least 50 percent of the covered segments by December 17, 2007 and completion of the baseline assessment of all covered segments by December 17, 2012. |
· | Eastern Shore also incurred an additional $385,000 of third-party costs in 2007 compared to 2006 to comply with the new federal pipeline integrity regulations previously discussed. |
· | The increased level of capital investment caused higher depreciation and asset removal costs of $371,000 and increased property taxes of $188,000. |
· | Corporate costs increased $568,000 as the Company updated its annual corporate cost allocations based on a methodology accepted by the FERC. |
· | The increase in operating expenses for 2007 is magnified by the FERC’s authorization, in July 2006, to defer certain pre-service costs of Eastern Shore’s E3 Project, allowing the Company to treat such costs as a regulatory asset. The deferral of these costs resulted in the reduction of $190,000 in other operating expenses in 2006 for expenses incurred in 2005. Please refer to the “Regulatory Activities” discussion below for further information on the E3 Project. |
· | Other operating expenses relating to various items increased collectively by approximately $226,000. |
Natural Gas Distribution
The Delmarva distribution operations experienced an increase in gross margin of $3.4$1.0 million or 16 percent. The significant items contributingin 2009. PESCO increased its sales volume by 13 percent in 2009 compared to 2008, as it benefited from increased spot sale opportunities on the Delmarva Peninsula during 2009, which contributed significantly to the increase in gross margin includeincrease. Spot sales are opportunistic and unpredictable, and their future availability is highly dependent upon market conditions.
The propane distribution operation, excluding FPU, increased its gross margin by $4.8 million. The absence of inventory valuation adjustments in 2009 and lower propane costs, coupled with sustained retail prices, contributed $3.5 million of the following:
· | Continued residential customer growth contributed to the increase in gross margin. The average number of residential customers on the Delmarva Peninsula increased by 2,950, or seven percent, for 2007 compared to 2006, and the Company estimates that these additional residential customers contributed approximately $1.2 million to gross margin. The Company does not expect to maintain the growth rate of residential customers, which it has experienced in the past few years. The Company has seen a slow-down in the new housing market in 2007 as a result of unfavorable market conditions in the housing industry, which include: (a) increased new and resale home inventory levels, (b) decreased homebuyer demand due to lower consumer confidence in the overall housing market, (c) increased uncertainty in the overall mortgage market, and (d) increased underwriting standards. |
· | Rate increases for both the Delaware and Maryland divisions generated an additional $848,000 in gross margin in 2007 compared to 2006. In October 2006, the Maryland PSC granted the Company a base rate increase, which resulted in a $693,000 period-over-period increase to gross margin in 2007. The Delaware Division received approval from the Delaware PSC to implement temporary rates, subject to refund, which contributed an additional $155,000 to gross margin in 2007. |
· | The Company estimates that weather contributed $819,000 to gross margin in 2007 compared to 2006, as temperatures on the Delmarva Peninsula were 15 percent colder in 2007. This amount differs from the $1.1 million of additional gross margin that the Company had expected the colder weather to contribute. This variance occurred as a result of the season or month that the heating degree day variance occurred. |
· | The colder temperatures did not have a significant impact on the Maryland distribution operation’s gross margin in 2007, because the operation’s approved rate structure now includes a weather normalization adjustment (“WNA”) mechanism, which was implemented in October 2006 and is designed to protect a portion of the Company’s revenues against warmer-than-normal weather, as deviations from normal weather can affect our financial performance. The WNA also serves to offset the impact of colder-than-normal weather on our customers by reducing the amounts the Company can charge them during such periods. |
· | Growth in commercial and industrial customers contributed $224,000 and $102,000, respectively, to gross margin in 2007 compared to 2006. |
· | Increased sales volumes to interruptible customers contributed $224,000 to gross margin in 2007 compared to 2006. |
· | The remaining $31,000 increase in gross margin can be attributed to various other factors. |
gross margin increase. A sharp decline in propane prices in late 2008 resulted in a loss associated with the inventory and swap valuation adjustments of $1.8 million in 2008. These inventory adjustments in 2008 and relatively low propane prices during the first half of 2009 allowed the Delmarva propane distribution operation to keep its propane cost low. Colder weather on the Delmarva Peninsula in 2009 increased gross margin by $1.2 million, as temperatures were seven percent colder in 2009, compared to 2008. Gross margin for the Florida propane distribution operation in 2009 remained unchanged from 2008 as increased margins per retail gallon were offset by a decline in residential and non-residential consumption.
The propane wholesale marketing operation experienced a reduction in gross margin of $1.0 million in 2009. The propane wholesale marketing operation typically capitalizes on price volatility by selling at prices above cost and effectively managing the larger spreads between the market (spot) prices and forward prices. Overall lack of volatility in wholesale propane prices in 2009, compared to 2008, reduced such revenue opportunities and its trading volume by 57 percent.
Page 46 Chesapeake Utilities Corporation 2009 Form 10-K
Other Operating Expenses
Total other operating expenses for the unregulated energy segment increased by $88,000, or one percent,$2.2 million in 20072009, of which $1.2 million was related to other operating expenses of FPU during the period from the merger closing (October 28, 2009) to December 31, 2009. The remaining increase in other operating expenses is due primarily to the following factors:
Payroll costs increased by $301,000 in 2009 compared to 2006. The higher gross margin, which resulted from an increase2008 due to annual salary increases.
Benefit costs increased by $167,000, due primarily to increased pension costs in residential customers, was2009 as a result of the decline in the value of pension plan assets.
Depreciation expense increased by $249,000 as we continued to make capital investments in the propane distribution operations.
Additional costs of approximately $115,000 were incurred in 2009 to maintain propane tanks in compliance with United States Department of Transportation standards.
Corporate overhead allocated to the unregulated energy segment increased by approximately $568,000 as previously discussed.
These increases were partially offset by lower volumesvehicle-related costs of $176,000, primarily due to a decrease in the cost of fuel.
Other Developments
The following developments, which are not discussed above, may affect the future operating results of the unregulated energy segment:
On November 20, 2009, Valero announced that it was permanently shutting down its refinery operation located in Delaware City, Delaware. During 2009, PESCO sold natural gas and services for $10.6 million to industrial customers. The operation experiencedValero. PESCO’s natural gas sales to Valero were on a fivespot sale basis. PESCO’s sale to Valero represented 19 percent growthof its total sales in residential2009. Spot sales are not predictable, and therefore, are not included in our long-term financial plans or forecasts; nor do we anticipate sales to Valero in the future.
In February 2010, Sharp, our Delmarva propane distribution subsidiary, purchased the operating assets of a regional propane distributor serving approximately 1,000 retail customers in Northampton and Accomack, Virginia.
2008 Compared to 2007
Operating income for the unregulated energy segment decreased by approximately $1.4 million, or 27 percent, in 2008 compared to 2006,2007, which provided forwas attributable to a gross margin decline of $475,000 and an additional $142,000operating expense increase of $918,000.
Gross Margin
The period-over-period decrease in gross margin. The Florida distribution operation also experienced a slowdown in the housing market in 2007 attributable to the same unfavorable housing market conditions previously discussed.
Other operating expensemargin of $475,000, or two percent, for the natural gasunregulated energy segment was due to $2.9 million in decreased gross margin for the propane distribution operations, increasedwhich was offset by $2.0 million in 2007 compared 2006. Among the key components of the increase wereto gross margin of $901,000 for the following:
· | Payroll costs increased by $110,000 as vacant positions in 2006 were filled in 2007 and additional positions were added to serve the growth experienced by the operations. |
· | Health care costs increased by $177,000 as a result of the additional personnel and a higher cost of claims in 2007 compared to 2006. |
· | Incentive compensation increased $229,000 in 2007 as the Delmarva operations experienced improved earnings and increased staffing levels. |
· | Depreciation and amortization expense, asset removal cost and property taxes increased by $316,000, $121,000 and $156,000, respectively, as a result of the Company’s continued capital investments. |
· | The Florida distribution operation experienced an increased expense of $227,000 in 2007 compared with 2006 to maintain compliance with the new federal pipeline integrity regulations. |
· | Sales and advertising costs increased $129,000 in 2007 compared to 2006, primarily to promote energy conservation and customer awareness of the availability of natural gas service. |
· | Regulatory expenses increased $113,000 as the Delaware and Maryland operations began expensing costs associated with their respective rate cases. |
· | The allowance for uncollectible accounts increased $183,000 in 2007 compared to 2006 due to increased revenues resulting from customer growth and colder temperatures. |
· | Merchant payment fees decreased by $116,000 as the Company’s Delmarva operation outsourced the processing of credit card payments in April 2007. |
· | Other operating expenses relating to various other items increased by approximately $355,000. |
Natural Gas Marketing
Gross marginpropane wholesale marketing operation and $1.5 million for the natural gas marketing operation decreased by $207,000, or 11 percent, for 2007 compared to 2006. The decline in gross margin was primarily the result of increases in natural gas supply costs that the Company was contractually unable to pass through to its customers. In addition, a shift in the market prevented the Company from selling as much of its available capacity in 2007 as was sold during 2006. Other operating expenses for the marketing operation increased by $258,000 primarily due to increases in payroll and benefit costs, allowance for uncollectible accounts and corporate overhead costs, which were partially offset by lower expenses for consulting services.
2006 Compared to 2005
Gross margin for the Company’s natural gas segment increased $2.0 million, or 4 percent, and other operating expenses decreased $475,000, or 1 percent, in 2006 compared to 2005. The gross margin increases of $1.8 million for the natural gas transmission operation, $395,000 for the Florida natural gas distribution operation and $75,000 for the natural gas marketing operation were partially offset by a lower gross margin of $210,000 for the Delmarva natural gas distribution operations.
Natural Gas Transmission
The natural gas transmission operation achieved gross margin growth of $1.8 million, or 11 percent. Of the $1.8 million increase, $1.1 million was attributable to new transportation capacity contracts implemented in November 2005 and $612,000 due to new transportation capacity contracts implemented in November 2006. An increase of $416,000 in other operating expenses partially offset the increased gross margin. The factors contributing to the increased expenses are as follow:
· | Payroll costs and incentive compensation increased $108,000 to serve the additional growth experienced by the operation. |
· | Depreciation and asset removal costs increased by $558,000 and property taxes by $109,000 due to an increase in the level of capital investment. |
· | As a result of the operation receiving approval from the FERC to recover certain pre-service costs associated with the E3 Project, the Company deferred $188,000 of costs previously incurred and expensed in 2005. As a result of this deferral, the amounts recognized in the Company’s income statement declined from 2005 by $376,000. Please refer to the “Regulatory Activities” discussion for further information on this expansion project. |
· | Other operating expenses relating to various other items increased by approximately $17,000. |
Natural Gas Distribution
Gross margin for the Florida distribution operation increased by $395,000 in 2006 compared to 2005. An eight percent growth in residential customers contributed $230,000 of this increase in gross margin. In addition to residential customer growth, new commercial and industrial customers contributed $91,000 to gross margin in 2006. The remaining $74,000 increase in gross margin is attributed to various factors, including turn-on revenue.
The Delmarva distribution operations experienced a decrease of $210,000 in gross margin. Weather significantly affected gross margin in 2006 compared to 2005. The Company estimates that the warmer temperatures in 2006, which were 18 percent warmer than in 2005, led to a decrease in gross margin of approximately $1.7 million when compared to 2005. This decrease was partially offset by continued residential customer growth. The average number of residential customers on the Delmarva Peninsula increased 3,189, or 9 percent, for 2006 compared to 2005 and the Company estimates that additional residential customers contributed approximately $1.2 million to gross margin. The remaining $190,000 increase in gross margin can be attributed to various factors, including an increase in the number of commercial customers and a decrease in interruptible sales.
Other operating expense for the natural gas distribution operations decreased $814,000 in 2006 compared to 2005. Some of the significant components of the decrease in other operating expenses in 2006, compared to 2005, include the following:
· | Health care costs decreased by $313,000 as a result of the Company changing health care service providers in November 2005 and experiencing lower costs related to claims. |
· | Allowance for uncollectible accounts decreased by $289,000 in 2006 compared to 2005 due to increased collection efforts and lower revenues resulting from lower prices and warmer temperatures. |
· | Incentive compensation decreased by $177,000 in 2006, reflecting lower than expected earnings. |
· | Corporate costs were reduced by $407,000 due to lower payroll and related expenses. |
· | Depreciation and amortization expense and asset removal cost increased by $132,000 and $186,000, respectively, as a result of the Company’s continued capital investments. |
· | Merchant payment fees increased by $136,000 in 2006 compared to 2005 as the Company experienced more customers making payments with the use of credit cards. |
· | In addition, other operating expenses relating to various minor items increased by approximately $55,000. |
Natural Gas Marketing
Gross margin for the natural gas marketing operation increased by $75,000 for 2006 compared to 2005. The increase was due primarily to growth in the number of customers to which the operation provided supply management services. Other operating expenses decreased by $78,000 due to lower levels of consulting services, partially offset by an increase in the allowance for uncollectible accounts.
Propane
The propane segment experienced an increase of $2.0 million, or 78 percent, in operating income in 2007 compared to 2006. Gross margin increased $4.0 million, which was partially offset by an increase in other operating expenses of $2.0 million. During 2006, operating income for the propane segment decreased by $675,000, or 21 percent, compared to 2005, reflecting a gross margin decrease of $1.1 million, which was partially offset by a decrease in operating expenses of $464,000.
| Propane (in thousands) | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Increase | | | | | | | | | Increase | |
| For the Years Ended December 31, | | 2007 | | | 2006 | | | (decrease) | | | 2006 | | | 2005 | | | (decrease) | |
| Revenue | | $ | 62,838 | | | $ | 48,576 | | | $ | 14,262 | | | $ | 48,576 | | | $ | 48,976 | | | $ | (400 | ) |
| Cost of sales | | | 41,038 | | | | 30,780 | | | | 10,258 | | | | 30,780 | | | | 30,041 | | | | 739 | |
| Gross margin | | | 21,800 | | | | 17,796 | | | | 4,004 | | | | 17,796 | | | | 18,935 | | | | (1,139 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Operations & maintenance | | | 14,594 | | | | 12,823 | | | | 1,771 | | | | 12,823 | | | | 13,355 | | | | (532 | ) |
| Depreciation & amortization | | | 1,842 | | | | 1,659 | | | | 183 | | | | 1,659 | | | | 1,574 | | | | 85 | |
| Other taxes | | | 866 | | | | 780 | | | | 86 | | | | 780 | | | | 797 | | | | (17 | ) |
| Other operating expenses | | | 17,302 | | | | 15,262 | | | | 2,040 | | | | 15,262 | | | | 15,726 | | | | (464 | ) |
| Total Operating Income | | $ | 4,498 | | | $ | 2,534 | | | $ | 1,964 | | | $ | 2,534 | | | $ | 3,209 | | | $ | (675 | ) |
| Propane Heating Degree-Day (HDD) Analysis — Delmarva | | | | | | | | | |
| | | | | | | | | | | Increase | | | | | | | | | | | Increase | |
| For the Years Ended December 31, | | 2007 | | | 2006 | | | (decrease) | | | 2006 | | | 2005 | | | (decrease) | |
| Heating degree-days | | | | | | | | | | | | | | | | | | | | | | | | |
| Actual | | | 4,504 | | | | 3,931 | | | | 573 | | | | 3,931 | | | | 4,792 | | | | (861 | ) |
| 10-year average | | | 4,376 | | | | 4,372 | | | | 4 | | | | 4,372 | | | | 4,436 | | | | (64 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Estimated gross margin per HDD | | $ | 1,974 | | | $ | 1,743 | | | $ | 231 | | | $ | 1,743 | | | $ | 1,743 | | | $ | 0 | |
2007 Compared to 2006
Operating income for the propane segment increased by $2.0 million to $4.5 million for 2007 compared to 2006. Gross margin in the Delmarva propane distribution operations increased by $3.2 million, compared to 2006, primarily due to increases in retail margin per gallon and colder weather on the Delmarva Peninsula. Gross margin also increased in the Florida propane distribution operation and the Company’s wholesale propane marketing operation by $100,000 and $677,000, respectively.
Delmarva Propane Distribution
The Delmarva propane distribution operation’s increasedecrease in gross margin of $3.2$3.1 million or 22 percent, resulted from the following:
Gross margin decreased by $1.1 million in 2008, compared to 2007, primarily because of a $0.04 decrease in the average gross margin per retail gallon attributable to inventory write-downs of approximately $800,000 during 2008 in response to market prices below the Company’s inventory price per gallon.
· | Gross margin increased by $1.1 million in 2007, compared to 2006, because of a $0.05 increase in the average gross margin per retail gallon. This increase occurs when market prices of propane are greater than the Company’s average inventory price per gallon. This trend reverses when market prices decrease and move closer to the Company’s inventory price per gallon. Propane gross margin is also affected by changes in the Company’s pricing of sales to its customers. |
Chesapeake Utilities Corporation 2009 Form 10-K Page 47
Wholesale propane prices rose dramatically during the spring of 2008, when they traditionally fall. In efforts to protect the Company from the impact that additional price increases would have on our Pro-Cap (propane price cap) Plan, the propane distribution operation entered into a swap agreement. By the end of the period, the market price of propane had plummeted well below the unit price in the swap agreement. As a result, we marked the agreement relating to the January 2009 and February 2009 gallons to market, which increased cost of sales by $939,000 in 2008. In January 2009, we terminated this swap agreement.
· | Temperatures on the Delmarva Peninsula were 15 percent colder in 2007 compared to 2006, which contributed to the increase of 1.7 million retail gallons, or nine percent, sold during 2007. The Company estimates that the colder weather and increased volumes sold contributed $1.1 million to gross margin for the Delmarva propane distribution operation compared to 2006. |
· | Non-weather related retail volumes sold in 2007 increased by 1.0 million gallons, or six percent. This increase in gallons sold contributed approximately $665,000 to gross margin for the Delmarva propane distribution operation compared to 2006. Contributing to the increase of gallons sold was the continued growth in the average number of CGS customers, which increased by 972 to a total count of 5,330, or a 22 percent increase, compared to 2006. The Company expects the growth of its CGS operation to continue as the number of systems currently under construction or under contract is anticipated to provide an additional 7,700 CGS customers, an increase of 145 percent. With the slowdown in the housing market, however, the Company is unable to predict when construction of systems currently under contract will be completed and in service. |
· | Wholesale volumes sold in 2007 increased by 2.9 million gallons, or 70 percent, which contributed approximately $119,000 to gross margin for the Delmarva propane distribution operation compared to 2006. |
· | The remaining $216,000 increase in gross margin can be attributed to various other factors, including higher service sales and service fees. |
Total other operating expenses increasedNon-weather-related volumes sold in 2008 decreased by $1.51.2 million gallons, or five percent. This decrease in gallons sold reduced gross margin by approximately $867,000 for the Delmarva propane operations in 2007, compared to the same period in 2006. The significant itemsdistribution operation. Factors contributing to this increase were:decrease in gallons sold included customer conservation and the timing of propane deliveries.
Margins per gallon on the Pro-Cap Plan for the last four months of 2008 recovered to a level just $113,000 below the prior year’s levels, despite realizing a charge to cost of sales of $494,000 as the December gallons related to this plan were valued at current market prices.
· | Increased operating expenses for 2007 were magnified by the Company’s one-time recovery in 2006 of previously incurred costs of $387,000 from one of its propane suppliers in 2006. This recovery reimbursed the Company for fixed costs incurred in the removal of above-normal levels of petroleum by-products contained in approximately 75,000 gallons of propane that it purchased from the supplier. The recovery of these costs reduced other operating expenses in the first nine months of 2006. |
Temperatures on the Delmarva Peninsula were two percent warmer in 2008 compared to 2007, which contributed to a decrease of 248,000 gallons sold, or one percent. We estimated that the warmer weather and decreased volumes sold had a negative impact of approximately $180,000 on gross margin for the Delmarva propane distribution operation.
· | Incentive compensation increased by $361,000 as a result of the improved operating results in 2007 compared to 2006. |
Gross margin from miscellaneous fees, including items such as tank and meter rentals and marketing pricing programs, increased by $271,000.
· | Health care costs increased by $119,000 during 2007 compared to the same period in 2006 as the Company experienced a higher cost of claims during the year. |
· | The operation incurred an additional $233,000 expense in 2007 for propane tank recertifications and maintenance to maintain compliance with Department of Transportation (“DOT”) standards. The DOT standards require propane tanks or cylinders to be recertified twelve years from their date of manufacture and every five years after that. |
· | Mains fees increased by $100,000 in 2007 compared to 2006 as a result of added CGS customers. This expenditure will continue to increase as more CGS customers are added. |
· | Depreciation and amortization expense increased by $107,000 over the prior year as a result of the Company’s increased capital investments. |
· | In addition, other operating expenses relating to various items increased collectively by approximately $193,000. |
Florida Propane Distribution
The Florida propane distribution operation experienced an increase in gross margin of $100,000, or nine$181,000 in 2008, compared to 2007. The higher gross margin resulted from increases of four percent and 10 percent in 2007 comparedthe number of gallons sold to 2006, primarily because of an increase in theresidential and commercial customers, respectively, combined with a higher average gross margin per retail gallon and higher service margins. Other operating expenses in 2007, compared to 2006, increased by $223,000, primarily due to increases in payroll costs, insurance and depreciation expense.
Propane Wholesale and Marketinggallon.
Gross margin for the Company’s propane wholesale marketing operation increased by $677,000, or 40 percent,$901,000 in 20072008, compared to 2006.2007. This increase reflects the operation capitalizing on a larger number of market opportunities that arose in 2007,2008 due to price volatility in the propane wholesale market. This volatility created an opportunity for the operation to capture larger price-spreads between sales contracts and purchase contracts in addition to larger spreads between the market which exceeded(spot) prices and forward propane prices.
Gross margin for the level of price fluctuations experienced in 2006.natural gas marketing operation increased by $1.5 million for 2008, compared to 2007. The increase in gross margin was partially offset by higher other operating expenses of $318,000, due primarily to higher incentive compensation based on the increased earnings in 2007.
2006 Compared to 2005
Operating income for the propane segment decreased $675,000, or 21 percent, to $2.5 million for 2006 compared to 2005. This decrease was due primarily to warmer weather on the Delmarva Peninsula in 2006, which resulted in reduced customer consumption. Gross margin in the Delmarva propane distribution operations was $834,000 lower than in 2005, primarily due to warmer weatherenhanced sales contract terms, margins on spot sales of approximately $600,000 and 26-percent growth in 2006. Gross margin also decreasedits customer base. The increased customer base contributed to a 41-percent increase in the Florida propane distribution operation and the Company’s wholesale propane marketing operation by $146,000 and $159,000, respectively.volumes sold in 2008.
Delmarva Propane Distribution
The Delmarva propane distribution operation’s decrease in gross margin of $834,000 resulted from the following factors:
· | Volumes sold in 2006 decreased 1.9 million gallons, or eight percent, due primarily to 18 percent warmer temperatures on the Delmarva Peninsula in 2006 than in 2005. The Company estimates that the warmer temperatures resulted in a decrease in gross margin of approximately $1.7 million when compared to 2005. |
· | Gross margin increased by $956,000 due to an increase of three cents in the average gross margin per retail gallon in 2006 compared to 2005. |
· | Gross margin for the Delmarva CGS activities increased by $155,000 compared to 2005 due primarily to an increase in the average number of customers, which grew by approximately 1,000 to a total count of approximately 3,900, or a 34 percent increase, compared to 2005. |
· | Gross margin was adversely affected by a $272,000 write-down of propane inventory, reflecting the lower of cost or market. |
· | The remaining gross margin decrease of $29,000 was attributable primarily to customer conservation and changes in the timing of deliveries to customers. |
Other Operating Expenses
Other operating expenses decreased by $335,000 for the Delmarva operations in 2006 compared to 2005. The significant factors contributing to the decrease included:
· | The Company recovered $387,000 in fixed costs from one of its propane suppliers in response to a propane contamination incident that occurred in a previous period when approximately 75,000 gallons of propane that the Company purchased from the supplier contained above-normal levels of petroleum byproducts. |
· | Health care costs decreased by $324,000. The Company changed health care service providers in November 2005 and subsequently experienced lower costs related to claims. |
· | In addition, there was a decrease of approximately $39,000 in other operating expenses relating to various minor items. |
· | These lower costs were partially offset byunregulated energy segment increased costs of $176,000 for one of the Pennsylvania start-ups, which began operation in July 2005, increased payroll costs of $165,000 and higher costs of $74,000 associated with vehicle fuel. |
Florida Propane Distribution
In 2006, the Florida propane distribution operation experienced a decrease in gross margin of $146,000, or 12 percent, when compared to 2005. The lower gross margin reflected a decrease of $208,000 for in-house piping sales as the operation exited the house piping service, which was partially offset by an increase in gross margin of $62,000 from propane sales$918,000 due primarily to an increase in the average gross margin per retail gallon, partially offsetfollowing factors:
Payroll and benefit costs decreased by a one percent decrease in the volumes sold in 2006. The Florida propane operation experienced a decrease of $49,000 in other operating expenses in 2006 compared to 2005, attributable$186,000, due primarily to lower payroll and benefits costs related to vacant positions during the year, partially offset by higher expenses related to leak testing and depreciation expense.
Propane Wholesale and Marketing
Gross marginaccrual for the Company’s propane wholesale marketing operation decreased by $159,000 in 2006 compared to 2005. This decrease from the 2005 results reflects the increased market opportunities that arose in 2005 due to the extreme price volatility in the propane wholesale market following the hurricanes in the Gulf of Mexico area, but did not extend into 2006. The decrease in gross margin was partially offset by lower other operating expenses of $79,000 attributed primarily to lower incentive compensation as a result of lower earningsoperating results in 2006.
- Page 21 - -
Vehicle-related costs increased by $207,000 as a result of higher fuel costs and continued maintenance of our delivery trucks.Depreciation and amortization expense increased by $182,000 as a result of an increase in our capital investments, primarily in Community Gas Systems. Advanced The allowance for uncollectible accounts increased by $436,000 due to increased revenue.
Maintenance expense decreased by $193,000, due primarily to additional costs in 2007 associated with propane tank recertifications and maintenance to comply with the Department of Transportation standards.
Information Servicestechnology costs increased by approximately $153,000 as a result of higher spending to improve the infrastructure, including system performance, disaster recovery and support.
Corporate overhead costs increased by approximately $204,000 as previously discussed.
Page 48 Chesapeake Utilities Corporation 2009 Form 10-K
Other
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Increase | | | | | | | | | | | Increase | |
| For the Years Ended December 31, | | 2009 | | | 2008 | | | (decrease) | | | 2008 | | | 2007 | | | (decrease) | |
| (in thousands) | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Revenue | | $ | 11,998 | | | $ | 15,373 | | | $ | (3,375 | ) | | $ | 15,373 | | | $ | 15,721 | | | $ | (348 | ) |
| Cost of sales | | | 6,036 | | | | 8,034 | | | | (1,998 | ) | | | 8,034 | | | | 8,260 | | | | (226 | ) |
| | | | | | | | | | | | | | | | | | | |
| Gross margin | | | 5,962 | | | | 7,339 | | | | (1,377 | ) | | | 7,339 | | | | 7,461 | | | | (122 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Operations & maintenance | | | 4,859 | | | | 5,206 | | | | (347 | ) | | | 5,206 | | | | 5,333 | | | | (127 | ) |
| Transaction-related costs | | | 1,478 | | | | 1,153 | | | | 325 | | | | 1,153 | | | | — | | | | 1,153 | |
| Depreciation & amortization | | | 310 | | | | 290 | | | | 20 | | | | 290 | | | | 304 | | | | (14 | ) |
| Other taxes | | | 640 | | | | 728 | | | | (88 | ) | | | 728 | | | | 697 | | | | 31 | |
| | | | | | | | | | | | | | | | | | | |
| Other operating expenses | | | 7,287 | | | | 7,377 | | | | (90 | ) | | | 7,377 | | | | 6,334 | | | | 1,043 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Income — Other | | | (1,325 | ) | | | (38 | ) | | | (1,287 | ) | | | (38 | ) | | | 1,127 | | | | (1,165 | ) |
| Operating Income — Eliminations | | | 3 | | | | 3 | | | | — | | | | 3 | | | | 4 | | | | (1 | ) |
| | | | | | | | | | | | | | | | | | | |
| |
Operating Income | | $ | (1,322 | ) | | $ | (35 | ) | | $ | (1,287 | ) | | $ | (35 | ) | | $ | 1,131 | | | $ | (1,166 | ) |
| | | | | | | | | | | | | | | | | | | |
2009 compared to 2008
Operating loss for the Other segment increased by approximately $1.3 million in 2009 compared to 2008. The increased loss was attributable primarily to the gross margin decrease of $1.4 million in the advanced information services operation.
Gross margin
The period-over-period decrease in gross margin for the “Other” segment provides domestic and international clients with information-technology-related business services and solutions for both enterprise and e-business applications. Thewas a result of a decrease in consulting revenues by the advanced information services business contributed operating incomeoperation due primarily to a 28-percent decrease in the number of $836,000 for 2007, $767,000 for 2006, and $1.2 million for 2005.
| Advanced Information Services (in thousands) | | | | | | | | | | | | | |
| | | | | | | | | Increase | | | | | | | | | Increase | |
| For the Years Ended December 31, | | 2007 | | | 2006 | | | (decrease) | | | 2006 | | | 2005 | | | (decrease) | |
| Revenue | | $ | 15,099 | | | $ | 12,568 | | | $ | 2,531 | | | $ | 12,568 | | | $ | 14,140 | | | $ | (1,572 | ) |
| Cost of sales | | | 8,260 | | | | 7,082 | | | | 1,178 | | | | 7,082 | | | | 7,181 | | | | (99 | ) |
| Gross margin | | | 6,839 | | | | 5,486 | | | | 1,353 | | | | 5,486 | | | | 6,959 | | | | (1,473 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Operations & maintenance | | | 5,225 | | | | 4,119 | | | | 1,106 | | | | 4,119 | | | | 5,129 | | | | (1,010 | ) |
| Depreciation & amortization | | | 144 | | | | 113 | | | | 31 | | | | 113 | | | | 123 | | | | (10 | ) |
| Other taxes | | | 634 | | | | 487 | | | | 147 | | | | 487 | | | | 510 | | | | (23 | ) |
| Other operating expenses | | | 6,003 | | | | 4,719 | | | | 1,284 | | | | 4,719 | | | | 5,762 | | | | (1,043 | ) |
| Total Operating Income | | $ | 836 | | | $ | 767 | | | $ | 69 | | | $ | 767 | | | $ | 1,197 | | | $ | (430 | ) |
2007 Compared to 2006
billable consulting hours, coupled with a decline in training revenues. The advancedreduction in the number of billable consulting hours is a result of current economic conditions in which information services business experienced gross margin growth of approximately $1.4 million, or 25 percent, and contributed operating income of $836,000 for 2007,technology spending has not rebounded. The decrease in consulting revenues was partially offset with an increase of $69,000, or nine percent, compared$218,000 from BravePoint’s professional database monitoring and support solution services, and increased product sales of $140,000. While there have been some improvement in recent months, we do not expect customers’ information technology spending to 2006.return to historical levels in the foreseeable future given the current economic climate.
The period-over-period increase of gross margin resulted primarily from:
· | A strong demand for the segment’s consulting services in 2007 generated an increase of $1.9 million in consulting revenues as the number of billable hours increased by 15 percent; and |
· | An increase of $276,000 from Managed Database Administration (“MDBA”) services, first offered in the first quarter of 2006, which provide clients with professional database monitoring and support solutions during business hours or around the clock. |
Operating expenses
Other operating expenses increaseddecreased by $1.3 million to $6.0 million$90,000 in 2007, compared to $4.7 million for 2006. This increase2009. The decrease in operating expenses in 2007 iswas attributable primarily to the following:cost containment actions, including layoffs and compensation adjustments, implemented by the advanced information service operation in 2009 to reduce costs to offset the decline in revenues. This decrease was offset by the increased merger-related costs.
· | Payroll, incentive compensation and commissions, payroll taxes, benefit claims, and consulting expense accounted for $937,000 of the period-over-period increase. These costs increased as a result of improved earnings and increased staffing levels to support the growth and customer demand experienced in 2007. |
· | An increase in allowance for uncollectible accounts of $223,000 associated with a customer in the mortgage lending business that had filed for bankruptcy in the third quarter of 2007. |
· | In addition, other operating expenses relating to various minor items increased by approximately $140,000. |
20062008 Compared to 20052007
Operating income for the “Other” segment decreased by approximately $1.2 million in 2008 compared to 2007, which was attributable to a gross margin decrease of $122,000 and an operating expense increase of $1.0 million.
Gross margin
Our advanced information services segment decreased by $430,000 to $767,000 for 2006 compared to $1.2 million in 2005. The greater operating income in 2005 included $993,000operation contributed most of the gross margin for the LAMPS™ product,“Other” segment. Gross margin for our advanced services operation declined by approximately $152,000, which was attributable to a decrease of $610,000 in turn includedconsulting revenues as higher average billing rates were not able to overcome a $924,000 pre-tax gain on the sale of the product in October 2005 to Fidelity National Information Solutions, Inc., a subsidiary of Fidelity National Financial, Inc.
Revenues for the period decreased $1.6 million compared to 2005, due primarily to elimination of $1.9 million of revenue generated by the LAMPSTM product in 2005. Consulting revenues increased $749,000 in 2006 compared to 2005, primarily from offering MDBA services to its customers in 2006, which accounted for $740,000 of the increase, and an increase of 7.6 percentnine-percent decrease in the average hourly billing rate, whilenumber of billable consulting hours. The reduction in the number of billable hours remained at the same level attainedwas a result of economic conditions in 2005. Partially offsetting the increasewhich information technology spending broadly declined. The decrease in consulting revenues were decreases of $128,000 in training andwas partially offset with increased product sales and $244,000training revenues of $403,000 and $47,000, respectively.
Chesapeake Utilities Corporation 2009 Form 10-K Page 49
The increase in other revenues.
Cost of sales for 2006 decreased by $99,000 to $7.08 million, compared to the 2005 cost of sales of $7.18 million, which included $401,000operating expenses in 2008 was primarily related to LAMPSTM. After deducting$1.2 million in merger-related costs in 2008 that were expensed in the 2005 costsecond quarter of sales associated2008 when initial discussions with the LAMPSTM product, cost of sales increased in 2006 compared to 2005 to support the higher 2006 revenues.
FPU regarding a potential merger were terminated. Other operating expenses decreased $1.0 millionfor our advanced information services operation remained relatively unchanged in 2006 to $4.7 million2008 compared to 2005. The reduction in expenses primarily reflects expenses of $554,000 in 2005 associated with LAMPSTM and lower benefits costs, rent expense and consulting costs.2007.
Other Operations and Eliminations
Other operations consist primarily of subsidiaries that own real estate leased to other Company subsidiaries. Eliminations are entries required to eliminate activities between business segments from the consolidated results. Other operations and eliminating entries contributed operating income of $295,000 for 2007, $298,000 for 2006, and $279,000 for 2005.
| Other Operations & Eliminations (in thousands) | | | | | | | | | | |
| | | | | | | | | Increase | | | | | | | | | Increase | |
| For the Years Ended December 31, | | 2007 | | | 2006 | | | (decrease) | | | 2006 | | | 2005 | | | (decrease) | |
| Revenue | | $ | 622 | | | $ | 618 | | | $ | 4 | | | $ | 618 | | | $ | 618 | | | $ | 0 | |
| Cost of sales | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Gross margin | | | 622 | | | | 618 | | | | 4 | | | | 618 | | | | 618 | | | | - | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Operations & maintenance | | | 109 | | | | 96 | | | | 13 | | | | 96 | | | | 67 | | | | 29 | |
| Depreciation & amortization | | | 160 | | | | 163 | | | | (3 | ) | | | 163 | | | | 220 | | | | (57 | ) |
| Other taxes | | | 62 | | | | 65 | | | | (3 | ) | | | 65 | | | | 81 | | | | (16 | ) |
| Other operating expenses | | | 331 | | | | 324 | | | | 7 | | | | 324 | | | | 368 | | | | (44 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Income — Other | | $ | 291 | | | $ | 294 | | | $ | (3 | ) | | $ | 294 | | | $ | 250 | | | $ | 44 | |
| Operating Income — Eliminations | | $ | 4 | | | | 4 | | | $ | 0 | | | $ | 4 | | | | 29 | | | $ | (25 | ) |
| Total Operating Income | | $ | 295 | | | | 298 | | | $ | (3 | ) | | $ | 298 | | | | 279 | | | $ | 19 | |
Other Income
Other income for the years2009, 2008 and 2007 2006,was $163,000, $103,000 and 2005,$291,000, respectively, was $291,000, $189,000, and $383,000, which includeincludes interest income, late fees charged to customers and gains or losses from the sale of assets.
Interest Expense
2009 Compared to 2008
Total interest expense for 20072009 increased by approximately $816,000,$928,000, or 1415 percent, compared to 2006. The higher2008. Total interest expense for 2009 includes approximately $741,000 in FPU’s interest expense for the period from the merger closing (October 28, 2009) to December 31, 2009, which is primarily related to $610,000 in interest on FPU’s long-term debt and $115,000 in interest on customer deposits. FPU’s weighted average interest rate was 7.41 percent for the period from the merger closing to December 31, 2009.
The remaining increase in interest expense in 2009 was attributable to the following factors:
Excluding FPU’s long-term debt, interest expense on long-term debt increased by $990,000 as our average long-term debt balance increased to $92.1 million in 2009 from $76.2 million in 2008. This increase was primarily related to the placement of $30.0 million of 5.93 percent Unsecured Senior Notes in October 2008. The weighted average interest rate on our long-term debt remained unchanged at 6.37 percent in 2009, compared to 6.40 percent in 2008.
Interest expense in short-term borrowing decreased by $852,000 in 2009, compared to 2008, as our average short-term borrowing balance decreased to $13.0 million in 2009 from $38.3 million in 2008. The $30.0 million long-term placement in October 2008 contributed to this decrease as well as a decrease in working capital requirements in 2009, compared to 2008, due to lower capital expenditures, lower income tax payments from bonus depreciation, net tax operating losses carried forward from 2008 and lower commodity costs. The impact from these factors was offset slightly by the increased working capital needs as a result of the following developments:FPU merger. Also contributing to the decrease in interest expense in short-term borrowing was a decrease in the weighted average short-term interest rate to 1.28 percent in 2009 from 2.79 percent in 2008 as we continued to experience low interest rates throughout 2009.
Other interest charges increased by $49,000.
· | As the result of fewer capital projects in 2007 compared to 2006, the Company capitalized $469,000 less interest on debt in 2007 associated with ongoing capital projects. |
In January 2010, we redeemed $28.7 million of the secured first mortgage bonds with a carrying value of $27.2 million to increase financial flexibility by reducing the amount of the FPU secured long-term debt and maintaining compliance with the covenants in our unsecured senior notes.· | The Company’s average long-term debt balance during 2007 was $76.5 million, with a weighted average interest rate of 6.71 percent, compared to $67.2 million, with a weighted average interest rate of 6.98 percent for 2006. The large year-over-year increase in the average long-term debt balance was the result of a debt placement of $20 million in Senior Notes (“Notes”) at 5.5 percent in October 2006 with three institutional investors (The Prudential Insurance Company of America, Prudential Retirement Insurance and Annuity Company and United Omaha Life Insurance Company). |
· | The average short-term borrowing balance decreased by $6.3 million in 2007 to $20.6 million compared to an average balance of $26.9 million in 2006. The weighted average interest rates for short-term borrowing of 5.46 percent for 2007 and 5.47 percent for 2006, had minimum impact on the change in short-term borrowing expense. |
2008 Compared to 2007
Total interest expense for 2006 increased2008 decreased by approximately $642,000,$432,000, or 12.5seven percent, compared to 2005.2007. The increase reflectedlower interest expense is primarily the result of the following:
Interest on long-term debt decreased by $263,000 in 2008, compared to 2007, as we reduced our average long-term debt balance and weighted average interest rate. Our average long-term debt balance during 2008 was $76.2 million, with a weighted average interest rate of 6.40 percent, compared to $76.5 million, with a weighted average interest rate of 6.71 percent, for the same period in 2007.
· | Average short-term debt balance and short-term interest rates both increased in 2006 compared to 2005. The average short-term borrowing balance increased by $21.2 million in 2006 to $26.9 million compared to $5.7 million in 2005 primarily to finance the $39.3 million of net property, plant, and equipment added in 2006. |
Page 50 Chesapeake Utilities Corporation 2009 Form 10-K
Other interest charges decreased by $127,000 as higher amounts of interest capitalized were partially offset by interest accrued on pending customer refunds.
· | The weighted average interest rate for short-term borrowing increased from 4.47 percent for 2005 to 5.47 percent for 2006. |
Interest on short-term borrowings decreased by $42,000 in 2008 compared to 2007, as the weighted average interest rate was nearly 2.7 percentage points lower in 2008 offsetting a $17.7 million increase in our average short-term borrowing balance. Our average short-term borrowing during 2008 was $38.3 million, with a weighted average interest rate of 2.79 percent, compared to $20.6 million, with a weighted average interest rate of 5.46 percent, for 2007.
· | The average long-term debt balance during 2006 was $67.2 million with a weighted average interest rate of 6.98 percent, compared to $67.4 million with a weighted average interest rate of 7.18 percent for 2005. The Company also capitalized $586,000 of interest as part of capital project costs during 2006. |
Income Taxes
2009 Compared to 2008
Income tax expense for 2007 was $8.6$10.9 million in 2009, compared to $7.0$8.8 million in 2008, representing an increase of $2.1 million. During 2009, we expensed approximately $871,000 in merger-related costs that were determined to be non-deductible for 2006. Income taxes increased in 2007 compared to 2006, due primarily to increased taxable income and income taxes increased in 2006 compared to 2005, again due to increased taxable income. Thetax purposes. Excluding the impact of these costs, our effective federal income tax rate for each of the three years 2007, 20062009 and 2005 was 352008 remained primarily unchanged at 39.4 percent and 39.3 percent, respectively. The increase in income tax expense reflects the Company realized a benefitincreased taxable income in 2009.
2008 Compared to 2007
Income tax expense was $8.8 million in 2008, compared to $8.6 million in 2007, representing an increase of $226,000, $220,000,$200,000. Our effective income tax rate for 2008 and $223,0002007 remained primarily unchanged at 39.3 percent and 39.4 percent, respectively. The increase in those years, respectively, resulting from a changeincome tax expense reflects the increased taxable income in the tax law allowing tax deductions for dividends paid on Company stock held in Employee Stock Ownership Plans (“ESOP”).2008.
Discontinued Operations
During the quarter ended September 30, 2007, Chesapeakewe decided to close itsthe distributed energy services company, Chesapeakesubsidiary, OnSight, Services, LLC (“OnSight”), which had experienced operating losses since its inception in 2004. OnSight was previously reported as part of the Company’s Other Operations business segment. At December 31, 2007, theThe results of operations for OnSight have been reclassified to discontinued operations and shown net of tax for all periods presented. The discontinued operations experienced a net lossesloss of $20,000 for 2007, $241,000 for 20062007. We did not have any discontinued operations in 2008 and $231,000 for 2005.2009.
(e) Liquidity and Capital Resources
Chesapeake’sOur capital requirements reflect the capital-intensive nature of itsour business and are principally attributable to investment in new plant and equipment and retirement of outstanding debt. The Company reliesWe rely on cash generated from operations, short-term borrowing, and other sources to meet normal working capital requirements and to finance capital expenditures.
During 2009, net cash provided by operating activities was $45.8 million, cash used in investing activities was $23.1 million, and cash used in financing activities was $21.4 million. Cash provided during 2009 includes approximately $359,000 of net cash acquired in the merger with FPU.
During 2008, net cash provided by operating activities was $28.5 million, cash used by investing activities was $31.2 million, and cash provided by financing activities was $1.7 million.
During 2007, net cash provided by operating activities was $25.7 million, cash used by investing activities was $31.3 million, and cash provided by financing activities was $3.7 million.
Chesapeake Utilities Corporation 2009 Form 10-K Page 51
During 2006, net cash provided by operating activities was $30.1 million, cash used by investing activities was $48.9 million, and cash provided by financing activities was $20.7 million.
The Board of Directors has authorized the Company to borrow up to $55.0 million of short-term debt, as required, from various banks and trust companies under short-term lines of credit. As of December 31, 2007, Chesapeake2009, we had fivefour unsecured bank lines of credit with threetwo financial institutions, totalingfor a total of $90.0 million, none of which requires compensating balances. In January 2010, the total unsecured bank lines of credit increased to $100.0 million, none of which requires compensating balances. These bank lines are available to provide funds for the Company’sour short-term cash needs to meet seasonal working capital requirements and to fund temporarily portions of itsthe capital expenditures. Threeexpenditure program. We are currently authorized by our Board of Directors to borrow up to $85.0 million of short-term debt, as required, from these short-term lines of credit. In response to the instability and volatility of the financial markets during 2008, we solidified our lines of credit by converting $40.0 million of available credit under uncommitted lines to committed lines of credit. Currently, two of the bank lines, totaling $25.0$60.0 million, are committed. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks. The outstanding balance of short-term borrowing at December 31, 20072009 and 20062008 was $45.7$30.0 million and $27.6$33.0 million, respectively. The level of short-term debt was reduced in 2006late 2008 and throughout 2009 with funds provided from the placement of $20$30 million of 5.55.93 percent Unsecured Senior Notes in October 2006 and from2008. This reduction was offset in late 2009 by the proceeds ofincreased working capital requirements after the issuance of 600,300 shares of common stock in November 2006.FPU merger.
Chesapeake hasWe have budgeted $37.5$53.9 million for capital expenditures during 2008.2010. This amount includes $17.0$49.2 million for the regulated energy segment, $3.3 million for the unregulated energy segment and $1.4 million for the “Other” segment. The amount for the regulated energy segment includes estimated capital expenditures for the following: natural gas distribution $13.3 million foroperation ($20.2 million), natural gas transmission $5.9 million for propaneoperation ($25.4 million) and electric distribution and wholesale marketing, $290,000 for advanced information services and $887,000 for other operations. The natural gas distribution and transmission expenditures areoperation ($3.6 million) for expansion and improvement of facilities. The amount for the unregulated energy segment includes estimated capital expenditures for the propane expenditures are to supportdistribution operations for customer growth to acquire landand replacement of equipment. The amount for a future bulk storage facility, and to replace equipment. Thethe “Other” segment includes an estimated capital expenditure of $288,000 for the advanced information services expenditures areoperation with the remaining balance for computer hardware, software and related equipment. The other category includes general plant, computer software and hardware. The Company expectsWe expect to fund the 20082010 capital expenditures program from short-term borrowing, cash provided by operating activities, and other sources. The capital expenditure program is subject to continuous review and modification. Actual capital requirements may vary from the above estimates due to a number of factors, including changing economic conditions, customer growth in existing areas, regulation, new growth opportunities,or acquisition opportunities and availability of capital.
Capital Structure
In consummating the FPU merger, Chesapeake issued 2,487,910 shares of its common stock, valued at approximately $75.7 million, in exchange for all outstanding common stock of FPU. We also became subject to FPU’s long-term debt of $47.8 million as a result of the merger. The following presents our capitalization as of December 31, 2009 and 2008:
| | | | | | | | | | | | | | | | | |
| | | December 31, | | | December 31, | |
| (in thousands) | | 2009 | | | 2008 | |
| | | | | | | | | | | | | | | | | |
| Long-term debt, net of current maturities | | $ | 98,814 | | | | 32 | % | | $ | 86,422 | | | | 41 | % |
| Stockholders��� equity | | | 209,781 | | | | 68 | % | | | 123,073 | | | | 59 | % |
| | | | | | | | | | | | | |
| Total capitalization, excluding short-term debt | | $ | 308,595 | | | | 100 | % | | $ | 209,495 | | | | 100 | % |
| | | | | | | | | | | | | |
As of December 31, 2009, common equity represented 68 percent of total capitalization, compared to 59 percent at December 31, 2008. As of December 31, 2009, we classified as a current portion of long-term debt two series of FPU’s secured first mortgage bonds in the amount of approximately $27.2 million because we redeemed them in January 2010 prior to their stated maturities in order to maintain increased financial flexibility and compliance with the covenants in our Unsecured Senior Notes. We used the short-term borrowing to finance the redemption of these bonds.
Page 52 Chesapeake Utilities Corporation 2009 Form 10-K
The following presents our capitalization as of December 31, 20072009 and 2006:
| | | December 31, | |
| | | 2007 | | | 2006 | |
| | | (In thousands, except percentages) | |
| | | | | | | | | | | | | |
| Long-term debt, net of current maturities | | $ | 63,256 | | | | 35 | % | | $ | 71,050 | | | | 39 | % |
| Stockholders' equity | | $ | 119,576 | | | | 65 | % | | $ | 111,152 | | | | 61 | % |
| Total capitalization, excluding short-term debt | | $ | 182,832 | | | | 100 | % | | $ | 182,202 | | | | 100 | % |
As of December 31, 2007, common equity represented 65 percent of total capitalization, compared to 61 percent at December 31, 2006.
The following presents our capitalization as of December 31, 2007 and 2006,2008, if short-term borrowing and the current portion of long-term debt were included in capitalization:
| | | | | | | | | | | | | | | | | |
| | | December 31, | | | December 31, | |
| (in thousands) | | 2009 | | | 2008 | |
| |
| Short-term debt | | $ | 30,023 | | | | 8 | % | | $ | 33,000 | | | | 13 | % |
| Long-term debt, including current maturities | | | 134,113 | | | | 36 | % | | | 93,078 | | | | 38 | % |
| Stockholders’ equity | | | 209,781 | | | | 56 | % | | | 123,073 | | | | 49 | % |
| | | | | | | | | | | | | |
| Total capitalization, including short-term debt | | $ | 373,917 | | | | 100 | % | | $ | 249,151 | | | | 100 | % |
| | | | | | | | | | | | | |
| | | December 31, | |
| | | 2007 | | | 2006 | |
| | | (In thousands, except percentages) | |
| | | | | | | | | | | | | |
| Short-term debt | | $ | 45,664 | | | | 19 | % | | $ | 27,554 | | | | 13 | % |
| Long-term debt, including current maturities | | $ | 70,912 | | | | 30 | % | | $ | 78,706 | | | | 36 | % |
| Stockholders' equity | | $ | 119,576 | | | | 51 | % | | $ | 111,152 | | | | 51 | % |
| Total capitalization, including short-term debt | | $ | 236,152 | | | | 100 | % | | $ | 217,412 | | | | 100 | % |
If short-term borrowingExcluding $75.7 million of the value of Chesapeake’s common stock issued in the merger and the current portion$47.8 million of FPU’s long-term debt were included in capitalization,our Consolidated Balance Sheet at December 31, 2009, total capitalization increased by $18.7$1.3 million in 2007 compared to 2006. The increased capitalization was primarily used to fund a portion of the $31.3 million of net property, plant, and equipment added in 2007 and for other general working capital. In addition, if short-term borrowing and the current portion of long-term debt were included in total capitalization, the equity component of the Company’s capitalization would have been 51 percent at both December 31, 2007 and 2006.2009.
Chesapeake remainsWe remain committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access the capital markets when required. This commitment, along with adequate and timely rate relief for the Company’sour regulated operations, is intended to ensure that Chesapeake will be ableour ability to attract capital from outside sources at a reasonable cost. The Company believesWe believe that the achievement of these objectives will provide benefits to our customers, and creditors as well as itsand investors.
Shelf Registration
In July 2006, the Company filed a registration statement on Form S-3 with the SEC to issue up to $40.0 million in new common stock and/or debt securities. The registration statement was declared effective by the SEC in November 2006. In November 2006, we sold 600,300 shares of common stock, including the underwriter’s exercise of their over-allotment option of 90,045 shares, under this registration statement, generating net proceeds of $19.7 million. The net proceeds from the sale were used for general corporate purposes, including financing of capital expenditures, repayment of short-term debt, and funding working capital requirements. At December 31, 2007 and 2006, the Company had approximately $20.0 million remaining under this registration statement.
Cash Flows Provided by Operating Activities
Our cash flows provided by (used in) operating activities were as follows:
| | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2009 | | | 2008 | | | 2007 | |
| (in thousands) | | | | | | | | | | | | |
| Net income | | $ | 15,897 | | | $ | 13,607 | | | $ | 13,198 | |
| Non-cash adjustments to net income | | | 28,319 | | | | 22,919 | | | | 15,829 | |
| Changes in assets and liabilities | | | 1,593 | | | | (7,982 | ) | | | (3,346 | ) |
| | | | | | | | | | |
Net cash from operating activities | | $ | 45,809 | | | $ | 28,544 | | | $ | 25,681 | |
| | | | | | | | | | |
| For the Years Ended December 31, | | 2007 | | | 2006 | | | 2005 | |
| Net income | | $ | 13,197,710 | | | $ | 10,506,525 | | | $ | 10,467,614 | |
| Non-cash adjustments to net income | | | 15,554,639 | | | | 11,186,418 | | | | 13,059,678 | |
| Changes in working capital | | | (3,070,465 | ) | | | 8,424,055 | | | | (9,927,351 | ) |
| Net cash from operating activties | | $ | 25,681,884 | | | $ | 30,116,998 | | | $ | 13,599,941 | |
Period-over-period changes in our cash flows from operating activities are attributable primarily to changes in net income, depreciation, deferred taxes and working capital. Changes in working capital are determined by a variety of factors, including weather, the priceprices of natural gas, electricity and propane, the timing of customer collections, payments for purchases of natural gas, electricity and propane, purchases, and deferred gasfuel cost recoveries.
The Company generatesWe generate a large portion of itsour annual net income and subsequent increases in our accounts receivable in the first and fourth quarters of each year due to significant volumes of natural gas and propane delivered by our Delmarva natural gas and propane distribution operations to our customers during the peak heating season. In addition, our natural gas and propane inventories, which usually peak in the fall months, are largely drawn down in the heating season and provide a source of cash as the inventory is used to satisfy winter sales demand.
Chesapeake Utilities Corporation 2009 Form 10-K Page 53
In 2007,2009, our net cash flow provided by operating activities was $25.7$45.8 million, a decreasean increase of $4.4$17.3 million from 2006.compared to 2008. This increase includes $4.7 million in net cash flow provided by the operating activities of FPU after the merger. The 2007 operatingremaining increase was due primarily to the following:
Net cash flows reflectfrom the favorable timing of payments for accounts payablechange in income taxes receivable and accrued liabilities, which increased operating cash flow by $22.1 million. In addition, increased net income and favorable non-cash adjustments primarilyfor deferred income taxes were related to continued higher tax deductions provided by bonus depreciation, expense, contributedwhich resulted in net federal income tax refunds received in 2009 and continued to the increase in operatingcreate higher book-to-tax timing differences;
Net cash flow. Partially offsetting these increases in operating cash flow was an increaseflows from changes in accounts receivable of $28.2 million associated with increased revenues and accounts payable were due primarily to the timing of invoicingcollections and payments of trading contracts entered into by our propane wholesale marketing operation; and marketing
Net cash flows from the increase in regulatory liabilities were due primarily to higher over-collection of purchased gas costs by our Delmarva natural gas distribution operation.
In 2006,2008, our net cash flow provided by operating activities was $30.1$28.5 million, an increase of $16.5$2.9 million over 2005. Thiscompared to 2007. The increase was due primarily a resultto the following:
Net cash flows from changes in accounts receivable and accounts payable were due primarily to the timing of collections and payments of trading contracts entered into by our propane wholesale and marketing operation;
Timing of payments for the recovery during 2006purchase of working capital that was deployed in 2005 due to significantly higher commodity pricespropane inventory, natural gas purchases injected into storage, and the amountrelative decline in the unit price of working capital required for operations. Also, contributing to this increase was a reduction of $6.1 millionthese commodities;
Reduction in regulatory liabilities, which resulted primarily from lower deferred gas cost recoveries in our natural gas and propane purchaseddistribution operations as the price of natural gas declined in the second half of 2008;
Reduced payments for inventoryincome taxes payable as a result of mild weatherhigher tax deductions provided by the 2008 Economic Stimulus Act; and
Cash flows provided by non-cash adjustments for deferred income taxes. The increase in deferred income taxes is the prior heating season and thereforeresult of higher inventory balancesbook-to-tax timing differences during the period that were generated by the Economic Stimulus Act, which authorized bonus depreciation for the current heating season.certain assets.
Cash Flows Used in Investing Activities
NetIn 2009, net cash flows used inby investing activities totaled $23.1 million, a decrease of $8.1 million compared to 2008. In 2008, net cash flows used by investing activities totaled $31.2 million, which remained relatively unchanged from net cash flows used by investing activities of $31.3 million $48.9in 2007.
We acquired $359,000 in cash, net of cash paid, in the merger with FPU in 2009.
We received $3.5 million in proceeds from an investment account related to future environmental costs, which was previously included as a non-current investment, as we transferred the amount to our general account that invests in overnight income-producing securities. Our general account is considered cash equivalent.
Cash utilized for capital expenditures was $26.6 million, $30.8 million and $33.1$31.3 million during fiscal yearsfor 2009, 2008, and 2007, 2006, and 2005, respectively.
Environmental expenditures exceeded amounts recovered through rates charged to customers in 2009, 2008 and 2007 by $418,000, $480,000 and $228,000, respectively.
· | Cash utilized for capital expenditures was $31.3 million, $48.9 million and $33.3 million for 2007, 2006, and 2005, respectively. Additions to property, plant and equipment in 2007 were primarily for natural gas transmission ($9.2 million), natural gas distribution ($15.2 million), propane distribution ($5.2 million), and other operations ($1.7 million). In both 2007 and 2006, the natural gas distribution expenditures were used primarily to fund expansion and facilities improvements. In both periods, the natural gas transmission capital expenditures related primarily to expanding the Company’s transmission system. |
· | Sales of property, plant, and equipment generated $205,000 of cash in 2007. |
· | The Company’s environmental expenditures exceeded amounts recovered through rates charged to customers in 2007 and 2006 by $228,000 and $16,000, respectively; in 2005, the Company recovered from its customers $240,000 in excess of its environmental expenditures for the period. |
Page 54 Chesapeake Utilities Corporation 2009 Form 10-K
Cash Flows Provided by Financing Activities
CashIn 2009, net cash flows used by financing activities totaled $21.4 million, compared to net cash flow provided by financing activities totaledof $1.7 million and $3.7 million duringin 2008 and 2007, $20.7 million during 2006, and $20.4 million during 2005.respectively. Significant financing activities included the following:
· | During 2009 and 2008, we reduced our short-term debt by $3.8 million and $12.0 million, respectively. During 2007, and 2005, net borrowing of short-term debt increased by $18.7 million, and $29.6 million, respectively, primarily to support our capital investments. During 2006, the Company reduced it short-term debt by $8.0 million. |
· | The Company repaid $7.7 million of long-term debt during 2007 compared with $4.9 million during 2006 and $4.8 million during 2005. |
· | During 2007, the Company paid $7.0 million in cash dividends compared with dividend payments of $6.0 million and $5.8 million for 2006 and 2005, respectively. The increase in dividends paid in 2007 compared to 2006 reflects both growth in the annualized dividend rate, from $1.16 per share during 2006 to $1.18 per share during 2007, and the increase in shares outstanding following the issuance of additional shares of common stock in the fourth quarter of 2006. |
· | In November 2006, the Company sold 600,300 shares of common stock, including the underwriter’s exercise of their over-allotment option of 90,045 shares, pursuant to a shelf registration statement declared effective in November 2006, generating net proceeds of $19.7 million. |
· | In October 2006, the Company placed $20.0 million of 5.5 percent Senior Notes (“Notes”) to three institutional investors (The Prudential Insurance Company of America, Prudential Retirement Insurance and Annuity Company and United Omaha Life Insurance Company). |
· | In August 2006, the Company paid cash of $435,000, in lieu of issuing shares of the Company’s common stock for the 30,000 stock warrants outstanding at December 31, 2005. |
- Page 25 - -
In October 2008, we completed the placement of $30.0 million of 5.93 percent Unsecured Senior Notes.We repaid $10.9 million of long-term debt during 2009, compared to $7.7 million of long-term debt repaid during each of 2008 and 2007.
We paid $8.0 million, $7.8 million and $7.0 million in cash dividends in 2009, 2008 and 2007, respectively. An increase in cash dividends paid in each year reflects the growth in the annualized dividend rate.
Contractual Obligations
We have the following contractual obligations and other commercial commitments as of December 31, 2007:2009:
| | | | | | | | | | | | | | | | | | | | | |
| | | Payments Due by Period | |
| | | Less than 1 | | | | | | | | | | | More than 5 | | | | |
| Contractual Obligations | | year | | | 1 - 3 years | | | 3 - 5 years | | | years | | | Total | |
| (in thousands) | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
Long-term debt(1) | | $ | 36,765 | | | $ | 17,293 | | | $ | 20,793 | | | $ | 60,818 | | | $ | 135,669 | |
| | | | | | | | | | | | | | | | | | | | | |
Operating leases(2) | | | 866 | | | | 1,449 | | | | 865 | | | | 2,031 | | | | 5,211 | |
| | | | | | | | | | | | | | | | | | | | | |
Purchase obligations(3) | | | | | | | | | | | | | | | | | | | | |
| Transmission capacity | | | 11,133 | | | | 38,589 | | | | 20,447 | | | | 63,028 | | | | 133,197 | |
| Storage — Natural Gas | | | 530 | | | | 6,600 | | | | 2,001 | | | | 968 | | | | 10,099 | |
| Commodities | | | 54,802 | | | | 341 | | | | — | | | | — | | | | 55,143 | |
| Electric supply | | | 574 | | | | 1,149 | | | | 1,149 | | | | 2,298 | | | | 5,170 | |
Forward purchase contracts — Propane(4) | | | 12,570 | | | | — | | | | — | | | | — | | | | 12,570 | |
| Other | | | 1,557 | | | | 16 | | | | — | | | | — | | | | 1,573 | |
Unfunded benefits(5) | | | 371 | | | | 1,504 | | | | 847 | | | | 4,926 | | | | 7,648 | |
Funded benefits(6) | | | 2,090 | | | | 79 | | | | 670 | | | | 1,170 | | | | 4,009 | |
| | | | | | | | | | | | | | | | |
Total Contractual Obligations | | $ | 121,258 | | | $ | 67,020 | | | $ | 46,772 | | | $ | 135,239 | | | $ | 370,289 | |
| | | | | | | | | | | | | | | | |
| | |
| (1) | | Principal payments on long-term debt, see Item 8 under the heading “Notes to the Consolidated Financial Statements — Note J, Long-Term Debt”, for additional discussion of this item. The expected interest payments on long-term debt are $7.5 million, $12.6 million, $10.1 million and $17.3 million, respectively, for the periods indicated above. Expected interest payments for all periods total $47.6 million. |
|
| (2) | | See Item 8 under the heading “Notes to the Consolidated Financial Statements — Note L, Lease Obligations,” for additional discussion of this item. |
|
| (3) | | See Item 8 under the heading “Notes to the Consolidated Financial statement — Note P, Other Commitments and Contingencies,” in the Notes to the Consolidated Financial Statements for further information. |
|
| (4) | | We have also entered into forward sale contracts. See “Market Risk” of the Management’s Discussion and Analysis for further information. |
|
| (5) | | We have recorded long-term liabilities of $7.6 million at December 31, 2009 for unfunded post-employment and post-retirement benefit plans. The amounts specified in the table are based on expected payments to current retirees and assumes a retirement age of 62 for currently active employees. There are many factors that would cause actual payments to differ from these amounts, including early retirement, future health care costs that differ from past experience and discount rates implicit in calculations. |
|
| (6) | | We have recorded long-term liabilities of $12.7 million at December 31, 2009 for two qualified, defined benefit pension plans. The assets funding these plans are in a separate trust and are not considered assets of the Company or included in the Company’s balance sheets. The Contractual Obligations table above includes $2.0 million, reflecting the expected payments the Company will make to the trust funds in 2010. Additional contributions may be required in future years based on the actual return earned by the plan assets and other actuarial assumptions, such as the discount rate and long-term expected rate of return on plan assets. See Item 8 under the heading “Notes to the Consolidated Financial Statements — Note M, Employee Benefit Plans,” for further information on the plans. Additionally, the Contractual Obligations table includes deferred compensation obligations totaling $2.0 million funded with Rabbi Trust assets in the same amount. The Rabbi Trust assets are recorded under Investments on the Balance Sheet. We assume a retirement age of 65 for purposes of distribution from this account. |
Chesapeake Utilities Corporation 2009 Form 10-K Page 55
| | | Payments Due by Period |
| Contractual Obligations | | Less than 1 year | | | 1 - 3 years | | | 3 - 5 years | | | More than 5 years | | | Total | |
Long-term debt (1) | | $ | 7,656,364 | | | $ | 13,312,727 | | | $ | 14,474,545 | | | $ | 35,468,364 | | | $ | 70,912,000 | |
Operating leases (2) | | | 790,801 | | | | 1,211,720 | | | | 1,166,800 | | | | 2,252,714 | | | | 5,422,035 | |
Purchase obligations (3) | | | | | | | | | | | | | | | | | | | | |
| Transmission capacity | | | 9,302,772 | | | | 20,794,882 | | | | 6,266,171 | | | | 21,339,713 | | | | 57,703,538 | |
| Storage — Natural Gas | | | 1,553,175 | | | | 4,210,670 | | | | 3,015,217 | | | | 1,838,948 | | | | 10,618,010 | |
| Commodities | | | 13,907,762 | | | | 63,515 | | | | - | | | | - | | | | 13,971,277 | |
Forward purchase contracts — Propane (4) | | | 41,781,709 | | | | - | | | | - | | | | - | | | | 41,781,709 | |
Unfunded benefits (5) | | | 308,552 | | | | 628,143 | | | | 645,350 | | | | 1,945,895 | | | | 3,527,940 | |
Funded benefits (6) | | | 73,939 | | | | 133,864 | | | | 119,852 | | | | 1,572,844 | | | | 1,900,499 | |
| Total Contractual Obligations | | $ | 75,375,074 | | | $ | 40,355,521 | | | $ | 25,687,935 | | | $ | 64,418,478 | | | $ | 205,837,008 | |
| | | | | | | | | | | | | | | | | | | | | |
(1) Principal payments on long-term debt, see Note H, "Long-Term Debt," in the Notes to the Consolidated Financial Statements for additional discussion of this item. The expected interest payments on long-term debt are $5.2 million, $8.8 million, $6.9 million and $10.0 million, respectively, for the periods indicated above. Expected interest payments for all periods total $ 30.9 million. | |
(2) See Note J, "Lease Obligations," in the Notes to the Consolidated Financial Statements for additional discussion of this item. | |
(3) See Note N, "Other Commitments and Contingencies," in the Notes to the Consolidated Financial Statements for further information. | |
(4) The Company has also entered into forward sale contracts. See "Market Risk" of the Management's Discussion and Analysis for further information. | |
(5) The Company has recorded long-term liabilities of $4.2 million at December 31, 2006 for unfunded post-retirement benefit plans. The amounts specified in the table are based on expected payments to current retirees and assumes a retirement age of 65 for currently active employees. There are many factors that would cause actual payments to differ from these amounts, including early retirement, future health care costs that differ from past experience and discount rates implicit in calculations. | |
(6) The Company has recorded long-term liabilities of $2.0 million at December 31, 2006 for funded benefits. These liabilities have been funded using a Rabbi Trust and an asset in the same amount is recorded under Investments on the Balance Sheet. The defined benefit pension plan was closed to new participants on January 1, 1999 and participants in the plan on that date were given the option to leave the plan. See Note K, "Employee Benefit Plans," in the Notes to the Consolidated Financial Statements for further information on the plan. Since the plan modification, no additional funding has been required from the Company and none is expected for the next five years, based on factors in effect at December 31, 2006. However, this is subject to change based on the actual return earned by the plan assets and other actuarial assumptions, such as the discount rate and long-term expected rate of return on plan assets. | |
Off-Balance Sheet Arrangements
The Company hasWe have issued corporate guarantees to certain vendors of itsour subsidiaries, primarily the propane wholesale marketing subsidiary and its Floridathe natural gas supply managementmarketing subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event eitherof the respective subsidiary’s default. NeitherNone of these subsidiaries has ever defaulted inon its obligations to pay its suppliers. The liabilities for these purchases are recorded in the Consolidated Financial Statements when incurred. The aggregate amount guaranteed at December 31, 20072009 was $24.2$22.7 million, with the guarantees expiring on various dates in 2008.
2010.
In addition to the corporate guarantees, the Company haswe have issued a letter of credit to itsour primary insurance company for $775,000,$725,000, which expires on MayAugust 31, 2008.2010. The letter of credit is provided as security to satisfy the deductibles under the Company’sour various insurance policies. There have been no draws on this letter of credit as of December 31, 2007.2009.
(f) Rate Filings and Other Regulatory Activities
The Company’sOur natural gas distribution operations in Delaware, Maryland and Florida and electric distribution operation in Florida are subject to regulation by their respective PSCs; Eastern Shore, the Company’s natural gas transmission operation,PSC; ESNG is subject to regulation by the FERC.
Delaware. On September 2, 2005, the Delaware division filed an application with the Delaware PSC requesting approval of an alternative rate designFERC; and rate structure in order to provide natural gas service to prospective customers in eastern Sussex County (“2005 Proceeding”). While Chesapeake provides natural gas service to residents and businesses in portions of Sussex County under the Company’s current tariff, natural gas distribution lines have not been extended to a large portion of eastern Sussex County targeted for growth by the State of Delaware. In April 2002, Governor Ruth Ann Minner established the Delaware Energy Task Force (“Task Force”), whose mission was to address the State’s long-term and short-term energy challenges. In September 2003, the Task Force issued its final report to the Governor that included a strategy to enhance the availability of natural gas within the State by evaluating possible incentives for expanding residential and commercial natural gas service. Chesapeake believes its current proposal to implement a rate design that will enable the Company to provide natural gas as a viable energy choice to a broader number of prospective customers within eastern Sussex County supports the Task Force recommendation. As the Delaware division included these proposals in its base rate filing made on July 6, 2007, the Delaware division closed the 2005 Proceeding with the intent to continue discussions in the context of the 2007 base rate proceeding.
On September 1, 2006, the Company filed with the Delaware PSC its annual Gas Sales Service Rates (“GSR”) Application, seeking approval to change its GSR rates effective for service rendered on and after November 1, 2006. On October 3, 2006, the Delaware PSC authorized the Company to implement the GSR charges on a temporary basis andPIPECO is subject to refund, pending the completion of full evidentiary hearings and a final decision by the Delaware PSC. The Division of the Public Advocate (“DPA”) recommended a cost disallowance of approximately $4.4 million related to the Delaware division’s commodity procurement purchases and a disallowance of approximately $275,000 related to pipeline capacity the Delaware division holds in eastern Sussex County, Delaware. The Delaware PSC Staff recommended a cost disallowance of approximately $2.2 million related to the Delaware division’s commodity procurement purchases and the deferral of approximately $535,000 related to pipeline capacity the Delaware division holds in eastern Sussex County, Delaware. The Company disagreed with these recommendations and opposed the proposed cost disallowances and deferrals in its rebuttal position submitted on April 19, 2007. Under established Delaware law, gas procurement costs, like other normally accepted operating expenses, cannot be disallowed unless it is shown that the costs were the result of an abuse of discretion, bad faith, or waste. Management believes that the Company’s gas procurement practices and pipeline capacity costs were reasonable and that, in no event were the costs at issue incurred as a result of any abuse of discretion, bad faith, or waste on the part of the Company. On July 24, 2007, the Delaware PSC approved a settlement agreement among the parties resulting in a complete recovery of the Delaware division’s costs. As a result of the settlement agreement, the Delaware division has agreed to contribute an amount equal to $37,500 per year for the next three years to a program designed to benefit elderly, disabled, and low-income customers of the Delaware division. In addition, with respect to the allowances for recovery of costs associated with pipeline capacity in eastern Sussex County, the settlement provides for the Delaware division to reduce the total amount of GSR charges to be collected from its customers by $275,000, effective beginning with the billing period from November 1, 2007 through October 31, 2008. The settlement also provides for the Delaware division to add $275,000 to the total GSR charges to be collected from customers effective for billings from November 1, 2008 through October 31, 2009.
On November 1, 2006, the Delaware division filed with the Delaware PSC its annual Environmental Rider (“ER”) rate application to become effective for service rendered on and after December 1, 2006. The Delaware PSC granted approval of the ER rate at its regularly scheduled meeting on November 21, 2006, subject to full evidentiary hearings and a final decision. On January 23, 2007, the Delaware PSC granted final approval of the ER rate as filed.
On November 9, 2006, the Delaware division filed two applications with the Delaware PSC requesting approval for a Town of Millsboro Franchise Fee Rider and a Town of Georgetown Franchise Fee Rider. These Riders will allow the Delaware division to charge all respective natural gas customers within town limits the franchise fee paid by the Delaware division to the Towns of Millsboro and Georgetown as a condition to providing natural gas service. The Delaware PSC granted approval of both Riders on January 23, 2007.
On July 6, 2007, the Company filed with the Delaware PSC an application seeking approval of the following: (i) participation by the Company’s Delaware commercial and industrial customers in transportation buying pools served by third-party natural gas marketers; (ii) a base rate adjustment of $1,896,000 annually that represents approximately a 3.25 percent rate increase on average for the Delaware division’s firm customers; (iii) an alternative rate design for residential customers in a defined expansion area in eastern Sussex County, Delaware; and (iv) a revenue normalization mechanism that reduces the impact of natural gas consumption on both customers and the Company. As an incentive for the Delaware division to make the significant capital investments to serve the growing areas of eastern Sussex County and in supporting Delaware’s Energy Policy, the Company has proposed as part of the filing that the Delaware division be permitted to earn a return on equity up to 15 percent. This level of return would ensure that the Company’s investors are adequately compensated for the increased risk associated with the higher levels of capital investment necessary to provide natural gas in those growing areas. On August 21, 2007, the Delaware PSC authorized the Company to implement charges reflecting the proposed $1,896,000 increase effective September 4, 2007 on a temporary basis and subject to refund, pending the completion of full evidentiary hearings and a final decision by the Delaware PSC. The Delaware PSC Staff filed testimony recommending a rate decrease of $693,245. The DPA recommended a rate decrease of $588,670. Neither party recommended approval of the Delaware division’s other proposals mentioned above. The Delaware division strongly disagrees with these positions and is currently in the process of drafting its rebuttal position which was filed on February 7, 2008. The Delaware division anticipates a final decision by the Delaware PSC during the second quarter of 2008.
On September 10, 2007, the Company filed with the Delaware PSC its annual GSR Application, seeking the approval of the Delaware PSC to change its GSR rates effective for service rendered on and after November 1, 2007. On October 2, 2007, the Delaware PSC authorized the Company to implement the GSR charges on a temporary basis and subject to refund, pending the completion of full evidentiary hearings and a final decision by the Delaware PSC. The Delaware division anticipates a final decision by the Delaware PSC during the second or third quarter of 2008.
On November 1, 2007, the Delaware division filed with the Delaware PSC its annual Environmental Rider (“ER”) rate application to become effective for service rendered on and after December 1, 2007. The Delaware PSC granted approval of the ER rate at its regularly scheduled meeting on November 20, 2007, subject to full evidentiary hearings and a final decision. The Delaware division anticipates a final decision by the Delaware PSC during the first quarter of 2008.
Maryland. On September 26, 2006, the Maryland PSC approved a base rate increase for the Maryland division of approximately $780,000 annually. In a settlement agreement entered into in that proceeding, the Maryland division was required to file a depreciation study, which was filed on April 9, 2007. The Maryland division filed formal testimony on July 10, 2007, initiating a phase II of this proceeding. In this filing, the Maryland division proposed a rate decrease of approximately $80,000 annually, resulting from a change in depreciation expense. On November 29, 2007 the Maryland PSC approved a settlement agreement for a rate decrease of $132,155, effective December 1, 2007 based on the change in the Company’s depreciation rates.
On December 17, 2007, the Maryland PSC held an evidentiary hearing to determine the reasonableness of the Maryland division’s four quarterly gas cost recovery filings during the twelve months ended September 30, 2007. No issues were raised at the hearing. The Maryland division anticipates a final decision by the Maryland PSC during the first quarter of 2008.
Florida. On October 10, 2006, the Florida division filed with the Florida PSC a petition for authority to implement phase two of its experimental transitional transportation service (“TTS”) pilot program, and for approval of a new tariff to reflect the division’s transportation service environment. Phase two of the TTS program for residential and certain small commercial consumers will expand the number of pool managers from one to two and increase the gas supply pricing options available to these consumers. Approved on April 24, 2007regulation by the Florida PSC, phase twoPSC. At December 31, 2009, Chesapeake was involved in rate filings and/or regulatory matters in each of the TTS program went into effect on July 1, 2007.
On November 29, 2006, the Florida division filed with the Florida PSC a petition for authority to modify its energy conservation programs. In this petition, the Florida division sought approval to increase the cash allowances paid within its Residential Homebuilder Program and the Residential Appliance Replacement Program, and to expand the scope of its Residential Water Heater Retention Program to add natural gas heating systems, cooking and clothes drying appliances. The Florida PSC granted approval of the petition in an order dated March 5, 2007. The modifications and new cash allowances became effective on March 30, 2007.
On May 2, 2007, the Florida division filed its summary of activity and true-up calculation for its 2006 Energy Conservation Cost Recovery Program with the Florida PSC. On September 5, 2007, the Florida PSC issued its audit reportjurisdictions in which less than $8,000,it operates. Each of these rate filings or one percent, ofregulatory matters is fully described in Item 8 under the 2006 expenditures were disallowed as non-conservation-related. The results of the audit were incorporated into the calculation of the 2008 Energy Conservation Cost Recovery Factors, which were filed with the Florida PSC on September 13, 2007, approved on November 6, 2007, and became effective on January 1, 2008.
In compliance with the Florida Administrative Code, the Florida division filed its 2007 Depreciation Study (“Study”) with the Florida PSC on May 17, 2007. This study provides the Florida PSC with the opportunity to review and address changes in plant and equipment lives, salvage values, reserves and resulting life depreciation rates since the last study performed in 2002. In its filing, the Florida division has requested that any changesheading “Notes to the depreciation rates be made effective January 1, 2008. The Florida division responded to interrogatories concerning the Study on October 15Consolidated Financial Statements – Note P, Other Commitments and December 24, 2007. While the Company cannot predict the outcome of the Florida PSC’s review at this time, the Company anticipates a final decision regarding the depreciation rates in the second quarter of 2008.Contingencies.”
On July 6, 2007, the Company and Peoples Gas Service (“PGS”), another local gas distribution company in Florida, filed a joint petition for Commission action on a territorial agreement for portions of Pasco County, a Master Territorial Agreement and a Gas Transportation Agreement filed as a special contract. PGS operates a natural gas distribution system in Pasco County but is unable to serve economically certain areas of the county. The Company entered into negotiations with PGS that would allow the Company to serve these areas by connecting to PGS’ existing distribution system and to extend its facilities into these specific territories to serve primarily residential and commercial consumers. The negotiations concluded with the execution of a Pasco County Territorial Agreement that provides the Company with two distinct areas as its territory and a Gas Transportation Agreement that specifies the terms, conditions and rates for transportation service across the PGS distribution system. The Company and PGS have also entered into a Master Territorial Agreement that contains terms and conditions which will govern all existing and potential territorial agreements. The Florida PSC approved these agreements at its October 9, 2007 agenda conference.
On August 27, 2007, PIPECO, filed with the Florida PSC its petition for approval of a natural gas transmission pipeline tariff in order to establish its operating rules and regulations. The Florida PSC approved the petition at its December 4, 2007 agenda conference.
Eastern Shore. During 2007, FERC regulatory activity regarding the expansion of Eastern Shore’s transmission system included the following:
System Expansion 2006 – 2008 On January 20, 2006, Eastern Shore filed with the FERC an application for a Certificate of Public Convenience and Necessity for its 2006-2008 system expansion project (“the 2006 – 2008 Project”). The application requested authority to construct and operate approximately 55 miles of new pipeline facilities and two new metering and regulating station facilities to provide an additional 47,350 dekatherms per day (“Dt/d”) of firm transportation service in accordance with customer requests of 26,200 Dt/d in 2006, 10,300 Dt/d in 2007, and 10,850 Dt/d in 2008, at a total estimated cost of approximately $33.6 million. On June 13, 2006, the FERC issued a certificate authorizing Eastern Shore to construct and operate the 2006 – 2008 Project as proposed. On November 1, 2006, Eastern Shore completed and placed in service the authorized Phase I facilities.
On July 24, 2007, Eastern Shore requested FERC authorization to commence construction of a portion (approximately 4 miles) of the Phase II facilities. Eastern Shore received the requested FERC authorization on August 11, 2007. Facilities have been completed and were placed in service on November 1, 2007. These additional facilities provide for 8,300 Dts of additional firm capacity per day and annualized gross margin contribution of $1.2 million, instead of the amounts included in the original filing of 10,300 Dts of additional firm capacity per day and $1.5 million annualized gross margin contribution.
On November 15, 2007 Eastern Shore requested FERC authorization to commence construction of Phase III facilities (approximately 9.2 miles). The FERC granted this authorization on January 7, 2008. Construction activities are to begin in the first quarter of 2008 and are to be completed and placed in service on November 1, 2008. These Phase III facilities provide for 5,650 Dts of additional firm capacity per day and annualized gross margin contribution of approximately $1.0 million instead of the amounts included in the original filing of 10,850 Dts of additional firm capacity per day and $1.6 million annualized gross margin contribution.
Eastern Shore Energylink Expansion Project (“E3 Project”). In 2006, Eastern Shore proposed to develop, construct and operate approximately 75 miles of new pipeline facilities to transport natural gas from Calvert County, Maryland, crossing under the Chesapeake Bay into Dorchester and Caroline Counties, Maryland, to points on the Delmarva Peninsula where such facilities would interconnect with Eastern Shore’s existing facilities in Sussex County, Delaware.
On May 31, 2006, Eastern Shore entered into Precedent Agreements (the “Precedent Agreements”) with Delmarva Power & Light Company (“Delmarva”) and Chesapeake, through its Delaware and Maryland divisions, to provide additional firm transportation services upon completion of the E3 Project. Both Chesapeake and Delmarva are parties to existing firm natural gas transportation service agreements with Eastern Shore, and each desires additional firm transportation service under the E3 Project, as evidenced by the Precedent Agreements. Pursuant to the Precedent Agreements, the parties agreed to proceed with the required initiatives to obtain the governmental and regulatory authorizations necessary for Eastern Shore to provide, and for Chesapeake and Delmarva to utilize, additional firm transportation service under the E3 Project.
As part of the Precedent Agreements, Eastern Shore, Chesapeake and Delmarva also entered into Letter Agreements which provide that, if the event that the E3 Project is not certificated and placed in service, Chesapeake and Delmarva will each pay their proportionate share of certain pre-certification costs by means of a negotiated surcharge of up to $2 million, over a period of not less than 20 years.
In furtherance of the E3 Project, Eastern Shore submitted a petition to the FERC on June 27, 2006 seeking approval of an uncontested rate-related Settlement Agreement by and between Eastern Shore, Chesapeake and Delmarva (the “Settlement Agreement”). The Settlement Agreement provides Eastern Shore and all customers utilizing Eastern Shore’s system with benefits, including but not limited to the following: (1) advancement of a necessary infrastructure project to meet the growing demand for natural gas on the Delmarva Peninsula; (2) sharing of project development costs by the participating customers in the project; and (3) no development cost risk for non-participating customers. On August 1, 2006, the FERC approved the Settlement Agreement, which was uncontested. On September 6, 2006, Eastern Shore submitted to FERC proposed tariff sheets to implement the provisions of the Settlement Agreement. By Letter Order dated October 6, 2006, the FERC accepted the tariff sheets, effective September 7, 2006.
On April 23, 2007, Eastern Shore submitted to the FERC its request to commence a pre-filing process and on May 15, 2007, the FERC notified Eastern Shore that its request had been approved. The pre-filing process is intended to engage all interested and affected stakeholders early in the process with the intention of resolving all environmental issues prior to the formal certificate application being filed. As part of this process, Eastern Shore has performed environmental, engineering and cultural surveys and studies in the interest of protecting the environment, minimizing any potential impacts to landowners, and cultural resources. Eastern Shore has also held meetings with federal, state and local permitting/regulatory agencies, non-governmental organizations, landowners, and other interested stakeholders.
As part of an updated engineering study, Eastern Shore received additional construction cost estimates for the E3 project, which indicated substantially higher costs than previously estimated. In an effort to optimize the feasibility of the overall project development plan, Eastern Shore explored all potential construction methods, construction cost mitigation strategies, potential design changes and project schedule changes. Eastern Shore also held discussions and meetings with several potential new customers, who have expressed an interest in the project that would expand its size and likely have significant impact on the cost, timeline and in-service date.
On December 20, 2007, Eastern Shore withdrew from the pre-filing process as a result of insufficient customer commitments for capacity to make the project economical. Eastern Shore will continue to explore potential construction methods, construction cost mitigation strategies, additional market requests, and potential design changes in its efforts to improve the overall economics of the project.
If Eastern Shore decides to abandon the E3 Project, it will initiate billing of pre-certification costs surcharge in accordance with the terms of the Precedent Agreements executed with two of its customers, which provide for these customers to reimburse Eastern Shore for pre-certification costs incurred in connection with the E3 Project, up to a maximum amount of $2.0 million each over a period of 20 years. As of December 31, 2007, the Company had incurred $2.97 million of pre-certification costs relating to the E3 Project.
During 2007, Eastern Shore also had developments in the following FERC rate matters:
On October 31, 2006, Eastern Shore filed a base rate proceeding with the FERC in compliance with the settlement approved in its prior base rate proceeding. Eastern Shore’s filed rates, proposed to be effective November 1, 2006, reflected an annual increase of $5,589,000 in its annual operating revenues based on increases in operating and maintenance expenses, depreciation expense, taxes other than income taxes, and return on existing gas plant facilities and new facilities placed into service by March 31, 2007.
On November 30, 2006 the FERC issued an order suspending the effectiveness of Eastern Shore’s proposed rate increase until May 1, 2007, subject to refund and the outcome of the hearing established in the order. On December 19, 2006, the Presiding Administrative Law Judge (“ALJ”) approved a procedural schedule to govern further proceedings in this case.
Settlement conferences were held on April 17, May 30, and June 6, 2007 at the FERC’s offices in Washington, D.C. On May 14, 2007, Eastern Shore filed a motion, which the FERC granted, to make its suspended rate increase effective on May 15, 2007, subject to refund, pending the ultimate resolution of the rate case. At the June 6, 2007 conference, the parties reached a settlement agreement in principle, and on June 8, 2007, the Chief ALJ suspended the procedural schedule to allow time for the parties to draft a formal Stipulation and Agreement. The negotiated settlement provides for an annual cost of service of $21,536,000, which reflects a pretax return on equity of 13.6 percent and a rate increase of approximately $1.07 million on an annual basis. On September 10, 2007, Eastern Shore submitted its Settlement Offer to the Commission for the ALJ’s review and certification to the full Commission. There were no comments filed objecting to, or in protest of, the Settlement Offer.
Eastern Shore filed concurrently with its Settlement Agreement a Motion to place the settlement rates into effect on September 1, 2007, in order to expedite the implementation of the reduced settlement rates pending final approval of the settlement. The Commission issued an order on September 25, 2007, authorizing Eastern Shore to commence billing its settlement rates effective September 1, 2007.
On October 1, 2007, the Presiding ALJ forwarded to the full Commission an order certifying the uncontested Settlement Agreement as fair, reasonable, and in the public interest. A final Commission Order approving the settlement was issued on January 31, 2008.
(g) Environmental Matters
The Company continuesWe continue to work with federal and state environmental agencies to assess the environmental impact and explore corrective action at threeseven environmental sites (see Note MItem 8 under the heading “Notes to the Consolidated Financial Statements)Statements – Note O, Environmental Commitments and Contingencies” for further detail on each site). The Company believesWe believe that future costs associated with these sites will be recoverable in rates or through sharing arrangements with, or contributions by, other responsible parties.
(h) Market Risk
Market risk represents the potential loss arising from adverse changes in market rates and prices. Long-term debt is subject to potential losses based on changes in interest rates. The Company’sOur long-term debt consists of first mortgage bonds, fixed-rate senior notes, secured debt and convertible debentures (see Note HItem 8 under the heading “Notes to the Consolidated Financial Statements — Note J, Long-term Debt” for annual maturities of consolidated long-term debt). All of the Company’sour long-term debt is fixed-rate debt and was not entered into for trading purposes. The carrying value of long-term debt, including current maturities, was $70.9$134.1 million at December 31, 2007,2009, as compared to a fair value of $75.0$145.5 million, based mainly on current market prices ora discounted cash flows, using currentflow methodology that incorporates a market interest rate that is based on published corporate borrowing rates for similar issuesdebt instruments with similar terms and remaining maturities. The Company evaluatesaverage 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.
The Company’sOur propane distribution business is exposed to market risk as a result of propane storage activities and entering into fixed price contracts for supply. The CompanyWe can store up to approximately four million gallons (including leased storage and rail cars) of propane during the winter season to meet itsour customers’ peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause the value of stored propane to decline. To mitigate the impact of price fluctuations, the Company haswe have adopted a Risk Management Policy that allows the propane distribution operation to enter into fair value hedges or other economic hedges of itsour inventory. Management reviewed the Company’s storage position as of December 31, 2007, and elected not to hedge any of its inventories. At December 31, 2006, the propane distribution operation had entered into a swap agreement to protect the Company from the impact of price increases on the price-cap plan that we offer to customers. The Company considered this agreement to be an economic hedge that did not qualify for hedge accounting as described in SFAS 133. At the end of 2006, the market price of propane dropped below the unit price within the swap agreement. As a result of the price drop, the Company marked the agreement to market, which resulted in an unrealized loss of $84,000. The Company did not enter into a similar agreement in 2007.
Page 56 Chesapeake Utilities Corporation 2009 Form 10-K
The Company’sOur propane wholesale marketing operation is a party to natural gas liquids (“NGL”) forward contracts, primarily propane contracts, with various third parties.third-parties. These contracts require that the propane wholesale marketing operation purchase or sell NGLnatural gas liquids at a fixed price at fixed future dates. At expiration, the contracts are settled by the delivery of NGLnatural gas liquids to the Companyus or the counter-party or “booking out” the transaction. Booking out is a procedure for financially settling a contract in lieu of the physical delivery of energy. The propane wholesale marketing operation also enters into futures contracts that are traded on the New York Mercantile Exchange. In certain cases, the futures contracts are settled by the payment or receipt of a net amount equal to the difference between the current market price of the futures contract and the original contract price; however, they may also be settled by physical receipt or delivery of propane.
The forward and futures contracts are entered into for trading and wholesale marketing purposes. The propane wholesale marketing business is subject to commodity price risk on its open positions to the extent that market prices for NGLnatural 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 the Company’sour 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 the Company’sour oversight officials daily.officials. In addition, the Risk Management Committee reviews periodic reports on marketmarkets and the credit risk of counter-parties, approves any exceptions to the Risk Management Policy (within limits established by the Board of Directors) and authorizes the use of any new types of contracts. Quantitative information on forward and futures contracts at December 31, 20072009 and 20062008 is presented in the following tables.
| | | | | | | | | | | |
| | | Quantity in | | | Estimated Market | | Weighted Average | |
| At December 31, 2009 | | gallons | | | Prices | | Contract Prices | |
Forward Contracts | | | | | | | | | | |
| Sale | | | 11,944,800 | | | $0.6900 — $1.3350 | | $ | 1.1264 | |
| Purchase | | | 11,256,000 | | | $0.7275 — $1.3350 | | $ | 1.1367 | |
Other Contract | | | | | | | | | | |
| Put option | | | 1,260,000 | | | $— | | $ | 0.1500 | |
Estimated market prices and weighted average contract prices are in dollars per gallon. | At December 31, 2007 | | Quantity in gallons | | | Estimated Market Prices | | | Weighted Average Contract Prices | |
| Forward Contracts | | | | | | | | | |
| Sale | | 30,941,400 | | | $0.8925 — $1.6025 | | | $1.3555 | |
| Purchase | | 30,954,000 | | | $0.8700 — $1.6000 | | | $1.3498 | |
| | | | | | | | | | | | | |
| Estimated market prices and weighted average contract prices are in dollars per gallon. | |
| All contracts expire in 2008. | | | | | | | | | |
| | | | | | | | | | | |
| | | Quantity in | | | Estimated Market | | Weighted Average | |
| At December 31, 2008 | | gallons | | | Prices | | Contract Prices | |
Forward Contracts | | | | | | | | | | |
| Sale | | | 10,626,000 | | | $0.5450 — $1.9100 | | $ | 0.9984 | |
| Purchase | | | 9,949,800 | | | $0.7000 — $1.9600 | | $ | 1.0233 | |
Estimated market prices and weighted average contract prices are in dollars per gallon.
| | | Quantity | | | Estimated | | | Weighted Average | |
| At December 31, 2006 | | in gallons | | | Market Prices | | | Contract Prices | |
| Forward Contracts | | | | | | | | | |
| Sale | | 13,797,000 | | | $0.9250 — $1.2100 | | | $1.0107 | |
| Purchase | | 13,733,800 | | | $0.9250 — $1.2200 | | | $1.0098 | |
| | | | | | | | | | | | | |
| Estimated market prices and weighted average contract prices are in dollars per gallon. | |
| All contracts expired in 2007. | | | | | | | | | |
| | | | | | | | | |
| | | December 31, | | | December 31, | |
| (in thousands) | | 2009 | | | 2008 | |
| Mark-to-market energy assets | | $ | 2,379 | | | $ | 4,482 | |
| Mark-to-market energy liabilities | | $ | 2,514 | | | $ | 3,052 | |
The Company’sChesapeake Utilities Corporation 2009 Form 10-K Page 57
Our natural gas distribution, electric distribution and natural gas marketing operations have entered into agreements with natural gas and electricity suppliers to purchase natural gas and electricity for resale to their customers. Purchases under these contracts either do not meet the definition of derivatives in SFAS No. 133 or are considered “normal purchases and sales” under SFAS No. 138 and are not marked to market.accounted for on an accrual basis.
(i) Competition
Competition
The Company’sOur natural gas and electric distribution operations and our natural gas transmission operation compete with other forms of energy including natural gas, electricity, oil and propane. The principal competitive factors are price and, to a lesser extent, accessibility. The Company’sOur natural gas distribution operations have several large volumelarge-volume industrial customers that canare 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. Lower levels ofrequirements, and our interruptible sales volumes may occur when oil prices are lower than the price of natural gas.decline. Oil prices, as well as the prices of electricity and other fuels, are subject to fluctuationfluctuate for a variety of reasons; therefore, future competitive conditions are not predictable. To address this uncertainty, the Company useswe use flexible pricing arrangements on both the supply and sales sides of this business to compete with the fluctuations in its customers’ alternative fuel prices.price fluctuations. As a result of the transmission operation’s conversion to open access and theChesapeake’s Florida natural gas distribution division’s restructuring of its services, theirthese businesses have shifted from providing bundled transportation and sales service to providing only transportationtransmission and contract storage services. Our electric distribution operation currently does not face substantial competition as 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.
The Company’sOur natural gas distribution operations in Delaware, Maryland and Florida offer unbundled transportation services to certain commercial and industrial customers. In 2002, theChesapeake’s Florida operationnatural gas distribution division extended such service to residential customers. With such transportation service available on the Company’sour distribution systems, the Company iswe are competing with third-party suppliers to sell gas to industrial customers. With respect to unbundled transportation services, the Company’sour competitors include interstate transmission companies, if the distribution customers are located close enough to a transmission company’s pipeline to make connections economically feasible. The customers at risk are usually large volume commercial and industrial customers with the financial resources and capability to bypass the Company’sour existing distribution operations in this manner. In certain situations, the Company’sour distribution operations may adjust services and rates for these customers to retain their business. The Company expectsWe expect to continue to expand the availability of unbundled transportation service to additional classes of distribution customers in the future. The CompanyWe have also established a natural gas sales and supplymarketing operation in Florida, Delaware and Maryland to compete forprovide such service to customers eligible for unbundled transportation services. The Company also provides such sales service in Delaware.
The Company’sOur propane distribution operations compete with several other propane distributors in their service territories,respective geographic markets, primarily on the basis of service and price, emphasizing reliability of serviceresponsive and responsiveness. Competition isreliable service. Our competitors generally frominclude local outlets of national distribution companiesdistributors and local businesses becauseindependent distributors, located in closewhose proximity to customers incurentails lower costs of providingto 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.
The advanced information services business faces significant competition from a number of larger competitors having substantially greater resources available to them than does the Company. In addition, changes in the advanced information services business are occurring rapidly, whichand 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.
Page 58 Chesapeake Utilities Corporation 2009 Form 10-K
(j) Inflation
Inflation affects the cost of supply, labor, products and services required for operations, maintenance and capital improvements. While the impact of inflation has remained low in recent years, natural gas and propane prices are subject to rapid fluctuations. In the Company’s regulated natural gas and electric distribution operations, fluctuations in natural gas and electricity prices are passed on to customers through the gasfuel cost recovery mechanism in the Company’sour tariffs. To help cope with the effects of inflation on itsour capital investments and returns, the Company seekswe seek rate reliefincreases from regulatory commissions for itsour regulated operations and closely monitorsmonitor the returns of itsour unregulated business operations. To compensate for fluctuations in propane gas prices, the Company adjusts itswe adjust propane selling prices to the extent allowed by the market.
Cautionary Statement
Chesapeake Utilities Corporation has made statements in this Form 10-K that are considered to be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are not matters of historical fact and are typically identified by words such as, but not limited to, “believes,” “expects,” “intends,” “plans,” and similar expressions, or future or conditional verbs such as “may,” “will,” “should,” “would,” and “could.” These statements relate to matters such as customer growth, changes in revenues or gross margins, capital expenditures, environmental remediation costs, regulatory trends and decisions, market risks associated with our propane operations, the competitive position of the Company, inflation, and other matters. It is important to understand that these forward-looking statements are not guarantees, but are subject to certain risks and uncertainties and other important factors that could cause actual results to differ materially from those in the forward-looking statements. The factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to:
· | the temperature sensitivity of the natural gas and propane businesses; |
· | the effects of spot, forward, futures market prices, and the Company’s use of derivative instruments on the Company’s distribution, wholesale marketing and energy trading businesses; |
· | the amount and availability of natural gas and propane supplies; |
· | the access to interstate pipelines’ transportation and storage capacity and the construction of new facilities to support future growth; |
· | the effects of natural gas and propane commodity price changes on the operating costs and competitive positions of our natural gas and propane distribution operations; |
· | third-party competition for the Company’s unregulated and regulated businesses; |
· | changes in federal, state or local regulation and tax requirements, including deregulation; |
· | changes in technology affecting the Company’s advanced information services segment; |
· | changes in credit risk and credit requirements affecting the Company’s energy marketing subsidiaries; |
· | the effects of accounting changes; |
· | changes in benefit plan assumptions; |
· | cost of compliance with environmental regulations or the remediation of environmental damage; |
· | the effects of general economic conditions, including interest rates, on the Company and its customers; |
· | the ability of the Company’s new and planned facilities and acquisitions to generate expected revenues; |
· | the ability of the Company to construct facilities at or below estimated costs; |
· | the Company’s ability to obtain the rate relief and cost recovery requested from utility regulators and the timing of the requested regulatory actions; |
· | the Company’s ability to obtain necessary approvals and permits from regulatory agencies on a timely basis; |
· | impact of inflation on the results of operations, cash flows, financial position and on the Company’s planned capital expenditures; |
· | inability to access the financial markets to a degree that may impair future growth; and |
· | operating and litigation risks that may not be covered by insurance. |
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Information concerning quantitative and qualitative disclosure about market risk is included in Item 7 under the heading “Management’s Discussion and Analysis — Market Risk.”
Item 8. Financial Statements and Supplementary Data.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) of the Exchange Act Rules 13a-15(f).Act. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.GAAP. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles,GAAP, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, Chesapeake’s management conducted an evaluation of the effectiveness of its internal control over financial reporting based on the criteria established in a report entitled “Internal Control — Integrated Framework”Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
On October 28, 2009, the previously announced merger between Chesapeake and FPU was consummated. Chesapeake is in the process of integrating FPU’s operations and has not included FPU’s activity in its evaluation of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. See “Notes to the Consolidated Financial Statements — Note B, Acquisitions and Dispositions” for additional information relating to the FPU merger. FPU’s operations constituted approximately 30 percent of total assets (excluding goodwill and other intangible assets) as of December 31, 2009, and 10 percent of operating revenues for the year then ended. FPU’s operations will be included in Chesapeake’s assessment as of December 31, 2010.
Chesapeake’s management has evaluated and concluded that Chesapeake’s internal control over financial reporting was effective as of December 31, 2007.
2009.Chesapeake Utilities Corporation 2009 Form 10-K Page 59
Report of Independent Registered Public Accounting Firm
________
To the Board of Directors and
Stockholders of Chesapeake Utilities Corporation
We have audited the accompanying consolidated balance sheetsheets of Chesapeake Utilities Corporation as of December 31, 2007,2009 and 2008, and the related consolidated statements of income, stockholders’ equity comprehensive income,and cash flows and income taxes for each of the year then ended.years in the three-year period ended December 31, 2009. Chesapeake Utilities Corporation’s management is responsible for these consolidated financial statements. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.audits.
We conducted our auditaudits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit providesaudits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Chesapeake Utilities Corporation and subsidiaries as of December 31, 20072009 and 2008, and the results of their operations and their cash flows for each of the yearyears in the three-year period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Chesapeake Utilities Corporation’s internal control over financial reporting as of December 31, 2007,2009, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 10, 20088, 2010 expressed an unqualified opinion.
| | |
/s/ ParenteBeard LLCParenteBeard LLC | | |
| Malvern, Pennsylvania | | |
| March 8, 2010 | | |
/s/ Beard Miller Company LLP
————————————————
Beard Miller Company LLP
Reading, Pennsylvania
March 10, 2008
Report of Independent Registered Public Accounting Firm
________
To the Board of Directors and Stockholders
of60 Chesapeake Utilities Corporation 2009 Form 10-K
In our opinion, the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, comprehensive income, cash flows, stockholders’ equity and income taxes for each of the two years in the period ended December 31, 2006, before the effects of the adjustments to retrospectively reflect the discontinued operations described in Note B, present fairly, in all material respects, the financial position of Chesapeake Utilities Corporation and its subsidiaries at December 31, 2006, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America (the 2006 financial statements before the effects of the adjustments discussed in Note B are not presented herein). In addition, in our opinion, the financial statement schedule for the each of the two years in the period ended December 31, 2006, presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements before the effects of the adjustments described above. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits, before the effects of the adjustments described above, of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note K to the consolidated financial statements, the Company changed the manner in which it accounts for defined benefit pension and other postretirement plans, effective December 31, 2006.
We were not engaged to audit, review, or apply any procedures to the adjustments to retrospectively reflect the discontinued operations described in Note B and accordingly, we do not express an opinion or any other form of assurance about whether such adjustments are appropriate and have properly applied. Those adjustments were audited by other auditors.
/s/ PricewaterhouseCoopers LLP
————————————————
PricewaterhouseCoopers LLP
Boston, MA
March 10, 2007
Consolidated Statements of Income
| For the Twelve Months Ended December 31, | | 2007 | | | 2006 | | | 2005 | | |
| | | | | | | | | | | | | | |
| For the Years Ended December 31, | | | 2009 | | 2008 | | 2007 | |
| (in thousands, except shares and per share data) | | |
| | | |
| Operating Revenues | | $ | 258,286,495 | | | $ | 231,199,565 | | | $ | 229,485,352 | | |
| Regulated Energy | | | $ | 139,099 | | $ | 116,468 | | $ | 128,850 | |
| Unregulated Energy | | | 119,973 | | 161,290 | | 115,190 | |
| Other | | | 9,713 | | 13,685 | | 14,246 | |
| | | | | | | | | |
| Total operating revenues | | | 268,785 | | 291,443 | | 258,286 | |
| | | | | | | | | |
| | | |
| Operating Expenses | | | | | | | | | | | | | |
| Cost of sales, excluding costs below | | | 170,848,211 | | | | 155,809,747 | | | $ | 153,398,723 | | |
| Regulated energy cost of sales | | | 64,803 | | 54,789 | | 70,861 | |
| Unregulated energy cost of sales | | | 95,467 | | 145,854 | | 99,987 | |
| Operations | | | 42,274,023 | | | | 36,670,302 | | | | 39,778,597 | | | 50,706 | | 43,476 | | 42,243 | |
| Transaction-related costs | | | 1,478 | | 1,153 | | — | |
| Maintenance | | | 2,203,800 | | | | 2,103,558 | | | | 1,818,981 | | | 3,430 | | 2,215 | | 2,236 | |
| Depreciation and amortization | | | 9,060,185 | | | | 8,243,715 | | | $ | 7,568,209 | | | 11,588 | | 9,005 | | 9,060 | |
| Other taxes | | | 5,786,694 | | | | 5,040,306 | | | $ | 4,999,963 | | | 7,577 | | 6,472 | | 5,785 | |
| | | | | | | | | |
| Total operating expenses | | | 230,172,913 | | | | 207,867,628 | | | | 207,564,473 | | | 235,049 | | 262,964 | | 230,172 | |
| | | | | | | | | |
| | | |
| Operating Income | | | 28,113,582 | | | | 23,331,937 | | | | 21,920,879 | | | 33,736 | | 28,479 | | 28,114 | |
| Other income, net of other expenses | | | 291,305 | | | | 189,093 | | | $ | 382,610 | | | 165 | | 103 | | 291 | |
| Interest charges | | | 6,589,639 | | | | 5,773,993 | | | $ | 5,132,458 | | | 7,086 | | 6,158 | | 6,590 | |
| | | | | | | | | |
| | |
| Income Before Income Taxes | | | 21,815,248 | | | | 17,747,037 | | | | 17,171,031 | | | 26,815 | | 22,424 | | 21,815 | |
| Income taxes | | | 8,597,461 | | | | 6,999,072 | | | | 6,472,220 | | | 10,918 | | 8,817 | | 8,597 | |
| Income from Continuing Operations | | | 13,217,787 | | | | 10,747,965 | | | | 10,698,811 | | |
| Loss from discontinued operations, net of | | | | | | | | | | | | | |
| tax benefit of $10,898, $162,510 and $160,204 | | | (20,077 | ) | | | (241,440 | ) | | | (231,197 | ) | |
| | | | | | | | | |
| | |
Net Income from continuing operations | | | 15,897 | | 13,607 | | 13,218 | |
| Loss from discontinued operations, net of tax benefit of $0, $0 and $11 | | | — | | — | | | (20 | ) |
| | | | | | | | | |
| Net Income | | $ | 13,197,710 | | | $ | 10,506,525 | | | $ | 10,467,614 | | | $ | 15,897 | | $ | 13,607 | | $ | 13,198 | |
| | | | | | | | | |
| | | | | | | | | | | | | | |
| Weighted Average Common Shares Outstanding: | Weighted Average Common Shares Outstanding: | | | | | | | | | | |
| Basic | | | 6,743,041 | | | | 6,032,462 | | | | 5,836,463 | | | 7,313,320 | | 6,811,848 | | 6,743,041 | |
| Diluted | | | 6,854,716 | | | | 6,155,131 | | | | 5,992,552 | | | 7,440,201 | | 6,927,483 | | 6,854,716 | |
| | | | | | | | | | | |
| Earnings (Loss) Per Share of Common Stock: | | | | | | | | | | |
Earnings Per Share of Common Stock: | | |
| Basic | | | | | | | | | | | | | |
| From continuing operations | | $ | 1.96 | | | $ | 1.78 | | | $ | 1.83 | | | $ | 2.17 | | $ | 2.00 | | $ | 1.96 | |
| From discontinued operations | | | - | | | $ | (0.04 | ) | | | (0.04 | ) | | — | | — | | — | |
| | | | | | | | | |
| Net Income | | $ | 1.96 | | | $ | 1.74 | | | $ | 1.79 | | | $ | 2.17 | | $ | 2.00 | | $ | 1.96 | |
| | | | | | | | | | | | | | | | | | | | |
| Diluted | | | | | | | | | | | | | |
| From continuing operations | | $ | 1.94 | | | $ | 1.76 | | | $ | 1.81 | | | $ | 2.15 | | $ | 1.98 | | $ | 1.94 | |
| From discontinued operations | | | - | | | $ | (0.04 | ) | | | (0.04 | ) | | — | | — | | — | |
| | | | | | | | | |
| Net Income | | $ | 1.94 | | | $ | 1.72 | | | $ | 1.77 | | | $ | 2.15 | | $ | 1.98 | | $ | 1.94 | |
| | | | | | | | | |
| | | |
Cash Dividends Declared Per Share of Common Stock | | | $ | 1.250 | | $ | 1.210 | | $ | 1.175 | |
| | | | | | | | | |
The accompanying notes are an integral part of the financial statements.
-Chesapeake Utilities Corporation 2009 Form 10-K Page 35 - -61
Consolidated Statements of Cash Flows
| | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2009 | | | 2008 | | | 2007 | |
| (in thousands) | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Operating Activities | | | | | | | | | | | | |
| Net Income | | $ | 15,897 | | | $ | 13,607 | | | $ | 13,198 | |
| Adjustments to reconcile net income to net operating cash: | | | | | | | | | | | | |
| Depreciation and amortization | | | 11,588 | | | | 9,005 | | | | 9,060 | |
| Depreciation and accretion included in other costs | | | 2,789 | | | | 2,239 | | | | 3,337 | |
| Deferred income taxes, net | | | 10,065 | | | | 11,442 | | | | 1,831 | |
| Gain on sale of assets | | | — | | | | — | | | | (205 | ) |
| Unrealized (gain) loss on commodity contracts | | | 1,606 | | | | (1,252 | ) | | | (65 | ) |
| Unrealized (gain) loss on investments | | | (212 | ) | | | 509 | | | | (123 | ) |
| Employee benefits and compensation | | | 1,217 | | | | 152 | | | | 1,004 | |
| Share based compensation | | | 1,306 | | | | 820 | | | | 990 | |
| Other, net | | | (40 | ) | | | 4 | | | | — | |
| Changes in assets and liabilities: | | | | | | | | | | | | |
| Sale (purchase) of investments | | | (146 | ) | | | (201 | ) | | | 229 | |
| Accounts receivable and accrued revenue | | | (13,652 | ) | | | 19,411 | | | | (28,189 | ) |
| Propane inventory, storage gas and other inventory | | | 2,597 | | | | (1,730 | ) | | | 1,193 | |
| Regulatory assets | | | (1,842 | ) | | | 411 | | | | (345 | ) |
| Prepaid expenses and other current assets | | | (747 | ) | | | (1,182 | ) | | | (1,186 | ) |
| Other deferred charges | | | (83 | ) | | | (153 | ) | | | (2,478 | ) |
| Long-term receivables | | | 191 | | | | 207 | | | | 84 | |
| Accounts payable and other accrued liabilities | | | 10,185 | | | | (15,033 | ) | | | 22,024 | |
| Income taxes receivable | | | 5,020 | | | | (6,155 | ) | | | (159 | ) |
| Accrued interest | | | 66 | | | | 158 | | | | 33 | |
| Customer deposits and refunds | | | (75 | ) | | | (502 | ) | | | 2,535 | |
| Accrued compensation | | | (2,066 | ) | | | (175 | ) | | | 946 | |
| Regulatory liabilities | | | 1,071 | | | | (3,107 | ) | | | 2,124 | |
| Other liabilities | | | 1,074 | | | | 69 | | | | (157 | ) |
| | | | | | | | | | |
| Net cash provided by operating activities | | | 45,809 | | | | 28,544 | | | | 25,681 | |
| | | | | | | | | | |
| |
Investing Activities | | | | | | | | | | | | |
| Property, plant and equipment expenditures | | | (26,603 | ) | | | (30,756 | ) | | | (31,277 | ) |
| Proceeds from sale of assets | | | — | | | | — | | | | 205 | |
| Proceeds from investments | | | 3,519 | | | | — | | | | — | |
| Cash acquired in the merger, net of cash paid | | | 359 | | | | — | | | | — | |
| Environmental expenditures | | | (418 | ) | | | (480 | ) | | | (228 | ) |
| | | | | | | | | | |
| Net cash used by investing activities | | | (23,143 | ) | | | (31,236 | ) | | | (31,300 | ) |
| | | | | | | | | | |
| |
Financing Activities | | | | | | | | | | | | |
| Common stock dividends | | | (7,957 | ) | | | (7,810 | ) | | | (7,030 | ) |
| Issuance of stock for Dividend Reinvestment Plan | | | 392 | | | | (118 | ) | | | 299 | |
| Change in cash overdrafts due to outstanding checks | | | 835 | | | | (684 | ) | | | (541 | ) |
| Net borrowing (repayment) under line of credit agreements | | | (3,812 | ) | | | (11,980 | ) | | | 18,651 | |
| Proceeds from issuance of long-term debt | | | — | | | | 29,961 | | | | — | |
| Repayment of long-term debt | | | (10,907 | ) | | | (7,658 | ) | | | (7,656 | ) |
| | | | | | | | | | |
| Net cash provided by (used in) financing activities | | | (21,449 | ) | | | 1,711 | | | | 3,723 | |
| | | | | | | | | | |
| |
Net Increase (Decrease) in Cash and Cash Equivalents | | | 1,217 | | | | (981 | ) | | | (1,896 | ) |
Cash and Cash Equivalents — Beginning of Period | | | 1,611 | | | | 2,592 | | | | 4,488 | |
| | | | | | | | | | |
Cash and Cash Equivalents — End of Period | | $ | 2,828 | | | $ | 1,611 | | | $ | 2,592 | |
| | | | | | | | | | |
| For the Years Ended December 31, | | 2007 | | | 2006 | | | 2005 | |
| Operating Activities | | | | | | | | | |
| Net Income | | $ | 13,197,710 | | | $ | 10,506,525 | | | $ | 10,467,614 | |
| Adjustments to reconcile net income to net operating cash: | | | | | | | | | | | | |
| Depreciation and amortization | | | 9,060,185 | | | | 8,243,715 | | | | 7,568,209 | |
| Depreciation and accretion included in other costs | | | 3,336,506 | | | | 3,102,066 | | | | 2,705,620 | |
| Deferred income taxes, net | | | 1,831,030 | | | | (408,533 | ) | | | 1,510,777 | |
| Gain on sale of assets | | | (204,882 | ) | | | - | | | | - | |
| Unrealized gain (loss) on commodity contracts | | | (170,465 | ) | | | 37,110 | | | | (227,193 | ) |
| Unrealized loss on investments | | | (122,819 | ) | | | (151,952 | ) | | | (56,650 | ) |
| Employee benefits and compensation | | | 1,825,028 | | | | 382,608 | | | | 1,621,607 | |
| Other, net | | | 56 | | | | (18,596 | ) | | | (62,692 | ) |
| Changes in assets and liabilities: | | | | | | | | | | | | |
| Sale (purchase) of investments | | | 229,125 | | | | (177,990 | ) | | | (1,242,563 | ) |
| Accounts receivable and accrued revenue | | | (28,189,132 | ) | | | 9,705,860 | | | | (16,831,751 | ) |
| Propane inventory, storage gas and other inventory | | | 1,193,336 | | | | 354,764 | | | | (5,704,040 | ) |
| Regulatory assets | | | (344,680 | ) | | | 2,498,954 | | | | (1,719,184 | ) |
| Prepaid expenses and other current assets | | | (1,188,481 | ) | | | (271,438 | ) | | | 36,704 | |
| Other deferred charges | | | (2,477,879 | ) | | | (231,822 | ) | | | (102,561 | ) |
| Long-term receivables | | | 83,653 | | | | 137,101 | | | | 247,600 | |
| Accounts payable and other accrued liabilities | | | 22,130,049 | | | | (11,434,370 | ) | | | 15,569,924 | |
| Income taxes receivable (payable) | | | (158,556 | ) | | | 1,800,913 | | | | (2,006,762 | ) |
| Accrued interest | | | 33,112 | | | | 273,672 | | | | (42,376 | ) |
| Customer deposits and refunds | | | 2,534,655 | | | | 2,361,265 | | | | 462,781 | |
| Accrued compensation | | | 1,117,941 | | | | (542,512 | ) | | | 875,342 | |
| Regulatory liabilities | | | 2,124,091 | | | | 2,824,068 | | | | 144,501 | |
| Other liabilities | | | (157,699 | ) | | | 1,125,590 | | | | 385,034 | |
| Net cash provided by operating activities | | | 25,681,884 | | | | 30,116,998 | | | | 13,599,941 | |
| | | | | | | | | | | | | |
| Investing Activities | | | | | | | | | | | | |
| Property, plant and equipment expenditures | | | (31,277,390 | ) | | | (48,845,828 | ) | | | (33,319,613 | ) |
| Proceeds from sale of assets | | | 204,882 | | | | - | | | | - | |
| Environmental recoveries (expenditures) | | | (227,979 | ) | | | (15,549 | ) | | | 240,336 | |
| Net cash used by investing activities | | | (31,300,487 | ) | | | (48,861,377 | ) | | | (33,079,277 | ) |
| | | | | | | | | | | | | |
| Financing Activities | | | | | | | | | | | | |
| Common stock dividends | | | (7,029,821 | ) | | | (5,982,531 | ) | | | (5,789,180 | ) |
| Issuance of stock for Dividend Reinvestment Plan | | | 299,436 | | | | 321,865 | | | | 458,757 | |
| Stock issuance | | | - | | | | 19,698,509 | | | | - | |
| Cash settlement of warrants | | | - | | | | (434,782 | ) | | | - | |
| Change in cash overdrafts due to outstanding checks | | | (541,052 | ) | | | 49,047 | | | | 874,083 | |
| Net borrowing (repayment) under line of credit agreements | | | 18,651,055 | | | | (7,977,347 | ) | | | 29,606,400 | |
| Proceeds from issuance of long-term debt | | | - | | | | 20,000,000 | | | | - | |
| Repayment of long-term debt | | | (7,656,580 | ) | | | (4,929,674 | ) | | | (4,794,827 | ) |
| Net cash provided by financing activities | | | 3,723,038 | | | | 20,745,087 | | | | 20,355,233 | |
| | | | | | | | | | | | | |
| Net Increase (Decrease) in Cash and Cash Equivalents | | | (1,895,565 | ) | | | 2,000,708 | | | | 875,897 | |
| Cash and Cash Equivalents — Beginning of Period | | | 4,488,366 | | | | 2,487,658 | | | | 1,611,761 | |
| Cash and Cash Equivalents — End of Period | | $ | 2,592,801 | | | $ | 4,488,366 | | | $ | 2,487,658 | |
| | | | | | | | | | | | | |
| Supplemental Disclosures of Non-Cash Investing Activities: | | | | | | | | | | | | |
| Capital property and equipment acquired on account, | | | | | | | | | | | | |
| but not paid as of December 31 | | $ | 365,890 | | | $ | 1,490,890 | | | $ | 1,367,348 | |
| | | | | | | | | | | | | |
| Supplemental Disclosure of Cash Flow information | | | | | | | | | | | | |
| Cash paid for interest | | $ | 5,592,279 | | | $ | 5,334,477 | | | $ | 5,052,013 | |
| Cash paid for income taxes | | $ | 7,009,206 | | | $ | 6,285,272 | | | $ | 6,342,476 | |
The accompanying notes are an integral part of the financial statements.
- Page 36 - -62 Chesapeake Utilities Corporation 2009 Form 10-K
Consolidated Balance Sheets
| | | | | | | | | |
| | | December 31, | | | December 31, | |
| Assets | | 2009 | | | 2008 | |
| (in thousands, except shares and per share data) | |
| |
Property, Plant and Equipment | | | | | | | | |
| Regulated energy | | $ | 463,856 | | | $ | 316,125 | |
| Unregulated energy | | | 61,360 | | | | 51,827 | |
| Other | | | 16,054 | | | | 12,255 | |
| | | | | | | |
| Total property, plant and equipment | | | 541,270 | | | | 380,207 | |
| Less: Accumulated depreciation and amortization | | | (107,318 | ) | | | (101,018 | ) |
| Plus: Construction work in progress | | | 2,476 | | | | 1,482 | |
| | | | | | | |
| Net property, plant and equipment | | | 436,428 | | | | 280,671 | |
| | | | | | | |
| | | | | | | | | |
Investments | | | 1,959 | | | | 1,601 | |
| | | | | | | |
| | | | | | | | | |
Current Assets | | | | | | | | |
| Cash and cash equivalents | | | 2,828 | | | | 1,611 | |
| Accounts receivable (less allowance for uncollectible accounts of $1,609 and $1,159, respectively) | | | 70,029 | | | | 52,905 | |
| Accrued revenue | | | 12,838 | | | | 5,168 | |
| Propane inventory, at average cost | | | 7,901 | | | | 5,711 | |
| Other inventory, at average cost | | | 3,149 | | | | 1,479 | |
| Regulatory assets | | | 1,205 | | | | 826 | |
| Storage gas prepayments | | | 6,144 | | | | 9,492 | |
| Income taxes receivable | | | 2,614 | | | | 7,443 | |
| Deferred income taxes | | | 1,498 | | | | 1,578 | |
| Prepaid expenses | | | 5,843 | | | | 4,679 | |
| Mark-to-market energy assets | | | 2,379 | | | | 4,482 | |
| Other current assets | | | 147 | | | | 147 | |
| | | | | | | |
| Total current assets | | | 116,575 | | | | 95,521 | |
| | | | | | | |
| | | | | | | | | |
Deferred Charges and Other Assets | | | | | | | | |
| Goodwill | | | 34,095 | | | | 674 | |
| Other intangible assets, net | | | 3,951 | | | | 164 | |
| Long-term receivables | | | 343 | | | | 533 | |
| Regulatory assets | | | 19,860 | | | | 2,806 | |
| Other deferred charges | | | 3,891 | | | | 3,825 | |
| | | | | | | |
| Total deferred charges and other assets | | | 62,140 | | | | 8,002 | |
| | | | | | | |
| | | | | | | | | |
Total Assets | | $ | 617,102 | | | $ | 385,795 | |
| | | | | | | |
| Assets | | December 31, 2007 | | | December 31, 2006 | |
| | | | | | | |
| Property, Plant and Equipment | | | | |
| Natural gas | | $ | 289,706,066 | | | $ | 269,012,516 | |
| Propane | | | 48,506,231 | | | | 44,791,552 | |
| Advanced information services | | | 1,157,808 | | | | 1,054,368 | |
| Other plant | | | 8,567,833 | | | | 9,147,500 | |
| Total property, plant and equipment | | | 347,937,938 | | | | 324,005,936 | |
| Less: Accumulated depreciation and amortization | | | (92,414,289 | ) | | | (85,010,472 | ) |
| Plus: Construction work in progress | | | 4,899,608 | | | | 1,829,948 | |
| Net property, plant and equipment | | | 260,423,257 | | | | 240,825,412 | |
| | | | | | | | | |
| Investments | | | 1,909,271 | | | | 2,015,577 | |
| | | | | | | | | |
| Current Assets | | | | | | | | |
| Cash and cash equivalents | | | 2,592,801 | | | | 4,488,366 | |
| Accounts receivable (less allowance for uncollectible | |
| accounts of $952,075 and $661,597, respectively) | | | 72,218,191 | | | | 44,969,182 | |
| Accrued revenue | | | 5,265,474 | | | | 4,325,351 | |
| Propane inventory, at average cost | | | 7,629,295 | | | | 7,187,035 | |
| Other inventory, at average cost | | | 1,280,506 | | | | 1,564,937 | |
| Regulatory assets | | | 1,575,072 | | | | 1,275,653 | |
| Storage gas prepayments | | | 6,042,169 | | | | 7,393,335 | |
| Income taxes receivable | | | 1,237,438 | | | | 1,078,882 | |
| Deferred income taxes | | | 2,155,393 | | | | 1,365,316 | |
| Prepaid expenses | | | 3,496,517 | | | | 2,280,900 | |
| Mark-to-market energy assets | | | 7,812,456 | | | | 1,379,896 | |
| Other current assets | | | 146,253 | | | | 173,388 | |
| Total current assets | | | 111,451,565 | | | | 77,482,241 | |
| | | | | | | | | |
| Deferred Charges and Other Assets | | | | | |
| Goodwill | | | 674,451 | | | | 674,451 | |
| Other intangible assets, net | | | 178,073 | | | | 191,878 | |
| Long-term receivables | | | 740,680 | | | | 824,333 | |
| Regulatory assets | | | 2,539,235 | | | | 1,765,088 | |
| Other deferred charges | | | 3,640,480 | | | | 1,215,004 | |
| Total deferred charges and other assets | | | 7,772,919 | | | | 4,670,754 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Total Assets | | $ | 381,557,012 | | | $ | 324,993,984 | |
The accompanying notes are an integral part of the financial statements.
-Chesapeake Utilities Corporation 2009 Form 10-K Page 37 - -63
Consolidated Balance Sheets
| | | | | | | | | |
| | | December 31, | | | December 31, | |
| Capitalization and Liabilities | | 2009 | | | 2008 | |
| (in thousands, except shares and per share data) | | | | | | | | |
| | | | | | | | | |
Capitalization | | | | | | | | |
| Stockholders’ equity | | | | | | | | |
| Common stock, par value $0.4867 per share (authorized 12,000,000 shares) | | $ | 4,572 | | | $ | 3,323 | |
| Additional paid-in capital | | | 144,502 | | | | 66,681 | |
| Retained earnings | | | 63,231 | | | | 56,817 | |
| Accumulated other comprehensive loss | | | (2,524 | ) | | | (3,748 | ) |
| Deferred compensation obligation | | | 739 | | | | 1,549 | |
| Treasury stock | | | (739 | ) | | | (1,549 | ) |
| | | | | | | |
| Total stockholders’ equity | | | 209,781 | | | | 123,073 | |
| | | | | | | | | |
| Long-term debt, net of current maturities | | | 98,814 | | | | 86,422 | |
| | | | | | | |
| Total capitalization | | | 308,595 | | | | 209,495 | |
| | | | | | | |
| | | | | | | | | |
Current Liabilities | | | | | | | | |
| Current portion of long-term debt | | | 35,299 | | | | 6,656 | |
| Short-term borrowing | | | 30,023 | | | | 33,000 | |
| Accounts payable | | | 51,948 | | | | 40,202 | |
| Customer deposits and refunds | | | 24,960 | | | | 9,534 | |
| Accrued interest | | | 1,887 | | | | 1,024 | |
| Dividends payable | | | 2,959 | | | | 2,082 | |
| Accrued compensation | | | 3,445 | | | | 3,305 | |
| Regulatory liabilities | | | 8,882 | | | | 3,227 | |
| Mark-to-market energy liabilities | | | 2,514 | | | | 3,052 | |
| Other accrued liabilities | | | 8,683 | | | | 2,970 | |
| | | | | | | |
| Total current liabilities | | | 170,600 | | | | 105,052 | |
| | | | | | | |
| | | | | | | | | |
Deferred Credits and Other Liabilities | | | | | | | | |
| Deferred income taxes | | | 66,923 | | | | 37,720 | |
| Deferred investment tax credits | | | 193 | | | | 235 | |
| Regulatory liabilities | | | 4,154 | | | | 875 | |
| Environmental liabilities | | | 11,104 | | | | 511 | |
| Other pension and benefit costs | | | 17,505 | | | | 7,335 | |
| Accrued asset removal cost — Regulatory liability | | | 33,214 | | | | 20,641 | |
| Other liabilities | | | 4,814 | | | | 3,931 | |
| | | | | | | |
| Total deferred credits and other liabilities | | | 137,907 | | | | 71,248 | |
| | | | | | | |
| | | | | | | | | |
| Other commitments and contingencies (Note P) | | | | | | | | |
| | | | | | | | | |
Total Capitalization and Liabilities | | $ | 617,102 | | | $ | 385,795 | |
| | | | | | | |
| Capitalization and Liabilities | | December 31, 2007 | | | December 31, 2006 | |
| | | | | | | |
| Capitalization | | | | | | |
| Stockholders' equity | | | | | | |
| Common Stock, par value $0.4867 per share | |
| (authorized 12,000,000 shares) | | $ | 3,298,473 | | | $ | 3,254,998 | |
| Additional paid-in capital | | | 65,591,552 | | | | 61,960,220 | |
| Retained earnings | | | 51,538,194 | | | | 46,270,884 | |
| Accumulated other comprehensive loss | | | (851,674 | ) | | | (334,550 | ) |
| Deferred compensation obligation | | | 1,403,922 | | | | 1,118,509 | |
| Treasury stock | | | (1,403,922 | ) | | | (1,118,509 | ) |
| Total stockholders' equity | | | 119,576,545 | | | | 111,151,552 | |
| | | | | | | | | |
| Long-term debt, net of current maturities | | | 63,255,636 | | | | 71,050,000 | |
| Total capitalization | | | 182,832,181 | | | | 182,201,552 | |
| | | | | | | | | |
| Current Liabilities | | | | | | | | |
| Current portion of long-term debt | | | 7,656,364 | | | | 7,656,364 | |
| Short-term borrowing | | | 45,663,944 | | | | 27,553,941 | |
| Accounts payable | | | 54,893,071 | | | | 33,870,552 | |
| Customer deposits and refunds | | | 10,036,920 | | | | 7,502,265 | |
| Accrued interest | | | 865,504 | | | | 832,392 | |
| Dividends payable | | | 1,999,343 | | | | 1,939,482 | |
| Accrued compensation | | | 3,400,112 | | | | 2,901,053 | |
| Regulatory liabilities | | | 6,300,766 | | | | 4,199,147 | |
| Mark-to-market energy liabilities | | | 7,739,261 | | | | 1,371,379 | |
| Other accrued liabilities | | | 2,500,542 | | | | 2,634,416 | |
| Total current liabilities | | | 141,055,827 | | | | 90,460,991 | |
| | | | | | | | | |
| Deferred Credits and Other Liabilities | | | | | |
| Deferred income taxes | | | 28,795,885 | | | | 26,517,098 | |
| Deferred investment tax credits | | | 277,698 | | | | 328,277 | |
| Regulatory liabilities | | | 1,136,071 | | | | 1,236,254 | |
| Environmental liabilities | | | 835,143 | | | | 211,581 | |
| Other pension and benefit costs | | | 2,513,030 | | | | 1,608,311 | |
| Accrued asset removal cost | | | 20,249,948 | | | | 18,410,992 | |
| Other liabilities | | | 3,861,229 | | | | 4,018,928 | |
| Total deferred credits and other liabilities | | | 57,669,004 | | | | 52,331,441 | |
| | | | | | | | | |
Other Commitments and Contingencies (Note N) | |
| | | | | | | | | |
| | | | | | | | | |
| Total Capitalization and Liabilities | | $ | 381,557,012 | | | $ | 324,993,984 | |
The accompanying notes are an integral part of the financial statements.
- Page 38 - -64 Chesapeake Utilities Corporation 2009 Form 10-K
Consolidated Statements of Stockholders’ Equity
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Common Stock | | | | | | | | | | | Accumulated Other | | | | | | | | | | |
| | | Number of | | | | | | | Additional Paid-In | | | | | | | Comprehensive | | | Deferred | | | | | | | |
| (in thousands, except per share and share data) | | Shares(7) | | | Par Value | | | Capital | | | Retained Earnings | | | Loss | | | Compensation | | | Treasury Stock | | | Total | |
Balances at December 31, 2006 | | | 6,688,084 | | | $ | 3,255 | | | $ | 61,960 | | | $ | 46,271 | | | $ | (334 | ) | | $ | 1,119 | | | $ | (1,119 | ) | | $ | 111,152 | |
| Net Income | | | | | | | | | | | | | | | 13,198 | | | | | | | | | | | | | | | | 13,198 | |
| Other comprehensive income, net of tax: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Employee Benefit Plans, net of tax: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Amortization of prior service costs(4) | | | | | | | | | | | | | | | | | | | (3 | ) | | | | | | | | | | | (3 | ) |
Net loss(5) | | | | | | | | | | | | | | | | | | | (515 | ) | | | | | | | | | | | (515 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total comprehensive income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 12,680 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Dividend Reinvestment Plan | | | 35,333 | | | | 17 | | | | 1,121 | | | | | | | | | | | | | | | | | | | | 1,138 | |
| Retirement Savings Plan | | | 29,563 | | | | 14 | | | | 935 | | | | | | | | | | | | | | | | | | | | 949 | |
| Conversion of debentures | | | 8,106 | | | | 4 | | | | 135 | | | | | | | | | | | | | | | | | | | | 139 | |
Share based compensation(1) (3) | | | 16,324 | | | | 8 | | | | 1,442 | | | | | | | | | | | | | | | | | | | | 1,450 | |
| Deferred Compensation Plan | | | | | | | | | | | | | | | | | | | | | | | 285 | | | | (285 | ) | | | — | |
| Purchase of treasury stock | | | (971 | ) | | | | | | | | | | | | | | | | | | | | | | | (30 | ) | | | (30 | ) |
| Sale and distribution of treasury stock | | | 971 | | | | | | | | | | | | | | | | | | | | | | | | 30 | | | | 30 | |
Cash dividends(2) | | | | | | | | | | | | | | | (7,931 | ) | | | | | | | | | | | | | | | (7,931 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Balances at December 31, 2007 | | | 6,777,410 | | | | 3,298 | | | | 65,593 | | | | 51,538 | | | | (852 | ) | | | 1,404 | | | | (1,404 | ) | | | 119,577 | |
| Net Income | | | | | | | | | | | | | | | 13,607 | | | | | | | | | | | | | | | | 13,607 | |
| Other comprehensive income, net of tax: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Employee Benefit Plans, net of tax: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Amortization of prior service costs(4) | | | | | | | | | | | | | | | | | | | (71 | ) | | | | | | | | | | | (71 | ) |
Net loss(5) | | | | | | | | | | | | | | | | | | | (2,825 | ) | | | | | | | | | | | (2,825 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total comprehensive income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 10,711 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Dividend Reinvestment Plan | | | 9,060 | | | | 5 | | | | 269 | | | | | | | | | | | | | | | | | | | | 274 | |
| Retirement Savings Plan | | | 5,260 | | | | 3 | | | | 156 | | | | | | | | | | | | | | | | | | | | 159 | |
| Conversion of debentures | | | 10,397 | | | | 5 | | | | 171 | | | | | | | | | | | | | | | | | | | | 176 | |
Share based compensation(1) (3) | | | 24,994 | | | | 12 | | | | 442 | | | | | | | | | | | | | | | | | | | | 454 | |
| Tax benefit on stock warrants | | | | | | | | | | | 50 | | | | | | | | | | | | | | | | | | | | 50 | |
| Deferred Compensation Plan | | | | | | | | | | | | | | | | | | | | | | | 145 | | | | (145 | ) | | | — | |
| Purchase of treasury stock | | | (2,425 | ) | | | | | | | | | | | | | | | | | | | | | | | (72 | ) | | | (72 | ) |
| Sale and distribution of treasury stock | | | 2,425 | | | | | | | | | | | | | | | | | | | | | | | | 72 | | | | 72 | |
| Dividends on stock-based compensation | | | | | | | | | | | | | | | (81 | ) | | | | | | | | | | | | | | | (81 | ) |
Cash dividends(2) | | | | | | | | | | | | | | | (8,247 | ) | | | | | | | | | | | | | | | (8,247 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Balances at December 31, 2008 | | | 6,827,121 | | | | 3,323 | | | | 66,681 | | | | 56,817 | | | | (3,748 | ) | | | 1,549 | | | | (1,549 | ) | | | 123,073 | |
| Net Income | | | | | | | | | | | | | | | 15,897 | | | | | | | | | | | | | | | | 15,897 | |
| Other comprehensive income, net of tax: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Employee Benefit Plans, net of tax: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Amortization of prior service costs(4) | | | | | | | | | | | | | | | | | | | 7 | | | | | | | | | | | | 7 | |
Net Gain(5) | | | | | | | | | | | | | | | | | | | 1,217 | | | | | | | | | | | | 1,217 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total comprehensive income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 17,121 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Dividend Reinvestment Plan | | | 31,607 | | | | 15 | | | | 921 | | | | | | | | | | | | | | | | | | | | 936 | |
| Retirement Savings Plan | | | 32,375 | | | | 16 | | | | 966 | | | | | | | | | | | | | | | | | | | | 982 | |
| Conversion of debentures | | | 7,927 | | | | 4 | | | | 131 | | | | | | | | | | | | | | | | | | | | 135 | |
Share based compensation(1) (3) | | | 7,374 | | | | 3 | | | | 1,332 | | | | | | | | | | | | | | | | | | | | 1,335 | |
Deferred Compensation Plan(6) | | | | | | | | | | | | | | | | | | | | | | | (810 | ) | | | 810 | | | | — | |
| Purchase of treasury stock | | | (2,411 | ) | | | | | | | | | | | | | | | | | | | | | | | (73 | ) | | | (73 | ) |
| Sale and distribution of treasury stock | | | 2,411 | | | | | | | | | | | | | | | | | | | | | | | | 73 | | | | 73 | |
| Common stock issued in the merger | | | 2,487,910 | | | | 1,211 | | | | 74,471 | | | | | | | | | | | | | | | | | | | | 75,682 | |
| Dividends on stock-based compensation | | | | | | | | | | | | | | | (104 | ) | | | | | | | | | | | | | | | (104 | ) |
Cash dividends(2) | | | | | | | | | | | | | | | (9,379 | ) | | | | | | | | | | | | | | | (9,379 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Balances at December 31, 2009 | | | 9,394,314 | | | $ | 4,572 | | | $ | 144,502 | | | $ | 63,231 | | | $ | (2,524 | ) | | $ | 739 | | | $ | (739 | ) | | $ | 209,781 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | Includes amounts for shares issued for Directors’ compensation. |
|
| (2) | | Cash dividends per share for the periods ended December 31, 2009, 2008 and 2007 were $1.250, $1.210 and $1.175 respectively. |
|
| (3) | | The shares issued under the Performance Incentive Plan (“PIP”) are net of shares withheld for employee taxes. For 2008 and 2007, the Company withheld 12,511 and 2,420 respectively shares for taxes. The Company did not issue any shares for the PIP in 2009. |
|
| (4) | | Tax expense (benefit) recognized on the prior service cost component of employees benefit plans for the periods ended December 31, 2009, 2008 and 2007 were approximately $5, ($52) and ($2) respectively. |
|
| (5) | | Tax expense (benefit) recognized on the net gain (loss) component of employees benefit plans for the periods ended December 31, 2009, 2008 and 2007 were $794, ($1,900) and ($340) respectively. |
|
| (6) | | In May and November 2009, certain participants of the Deferred Compensation Plan received distributions totaling $883. There were no distributions in 2008 and 2007. |
|
| (7) | | Includes 28,452, 62,221 and 57, 309 shares at December 31, 2009, 2008 and 2007, respectively, held in a Rabbi Trust established by the Company relating to the Deferred Compensation Plan. |
| For the Years Ended December 31, | | 2007 | | | 2006 | | | 2005 | |
| | | | | | | | | | | |
| Common Stock | | | | | | | | | |
| Balance — beginning of year | | $ | 3,254,998 | | | $ | 2,863,212 | | | $ | 2,812,538 | |
| Dividend Reinvestment Plan | | | 17,197 | | | | 18,685 | | | | 20,038 | |
| Retirement Savings Plan | | | 14,388 | | | | 14,457 | | | | 10,255 | |
| Conversion of debentures | | | 3,945 | | | | 8,117 | | | | 11,004 | |
Performance shares and options exercised (1) | | | 7,945 | | | | 14,536 | | | | 9,377 | |
| Stock issuance | | | - | | | | 335,991 | | | | - | |
| Balance — end of year | | | 3,298,473 | | | | 3,254,998 | | | | 2,863,212 | |
| | | | | | | | | | | | | | |
| Additional Paid-in Capital | | | | | | | | | | | | |
| Balance — beginning of year | | | 61,960,220 | | | | 39,619,849 | | | | 36,854,717 | |
| Dividend Reinvestment Plan | | | 1,121,190 | | | | 1,148,100 | | | | 1,224,874 | |
| Retirement Savings Plan | | | 934,295 | | | | 900,354 | | | | 682,829 | |
| Conversion of debentures | | | 133,839 | | | | 275,300 | | | | 373,259 | |
Performance shares and options exercised (1) | | | 498,674 | | | | 887,426 | | | | 484,170 | |
| Stock-based compensation | | | 943,334 | | | | - | | | | - | |
| Stock issuance | | | - | | | | 19,362,518 | | | | - | |
| Exercise warrants, net of tax | | | - | | | | (233,327 | ) | | | - | |
| Balance — end of year | | | 65,591,552 | | | | 61,960,220 | | | | 39,619,849 | |
| | | | | | | | | | | | | | |
| Retained Earnings | | | | | | | | | | | | |
| Balance — beginning of year | | | 46,270,884 | | | | 42,854,894 | | | | 39,015,087 | |
| Net income | | | 13,197,710 | | | | 10,506,525 | | | | 10,467,614 | |
Cash dividends (2) | | | (7,930,400 | ) | | | (7,090,535 | ) | | | (6,627,807 | ) |
| Balance — end of year | | | 51,538,194 | | | | 46,270,884 | | | | 42,854,894 | |
| | | | | | | | | | | | | | |
| Accumulated Other Comprehensive Income (Loss) | | | | | | | | | | | | |
| Balance — beginning of year | | | (334,550 | ) | | | (578,151 | ) | | | (527,246 | ) |
| Minimum pension liability adjustment, net of tax | | | 28,106 | | | | 74,036 | | | | (50,905 | ) |
| Gain (Loss) on funded status of Employee Benefit Plans, net of tax | | | (545,230 | ) | | | 169,565 | | | | - | |
| Balance — end of year | | | (851,674 | ) | | | (334,550 | ) | | | (578,151 | ) |
| | | | | | | | | | | | | | |
| Deferred Compensation Obligation | | | | | | | | | | | | |
| Balance — beginning of year | | | 1,118,509 | | | | 794,535 | | | | 816,044 | |
| New deferrals | | | 285,413 | | | | 323,974 | | | | 130,426 | |
| Payout of deferred compensation | | | - | | | | - | | | | (151,935 | ) |
| Balance — end of year | | | 1,403,922 | | | | 1,118,509 | | | | 794,535 | |
| | | | | | | | | | | | | | |
| Treasury Stock | | | | | | | | | | | | |
| Balance — beginning of year | | | (1,118,509 | ) | | | (797,156 | ) | | | (1,008,696 | ) |
| New deferrals related to compensation obligation | | | (285,413 | ) | | | (323,974 | ) | | | (130,426 | ) |
| Purchase of treasury stock | | | (29,771 | ) | | | (51,572 | ) | | | (182,292 | ) |
| Sale and distribution of treasury stock | | | 29,771 | | | | 54,193 | | | | 524,258 | |
| Balance — end of year | | | (1,403,922 | ) | | | (1,118,509 | ) | | | (797,156 | ) |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| Total Stockholders’ Equity | | $ | 119,576,545 | | | $ | 111,151,552 | | | $ | 84,757,183 | |
| | | | | | | | | | | | | | |
| (1) Includes amounts for shares issued for Directors' compensation. | | | | | |
| (2) Cash dividends declared per share for 2007, 2006 and 2005 were $1.18, $1.16 and $1.14, respectively. | |
| | | | | | | | | | | | | | |
| Consolidated Statements of Comprehensive Income | | | | | | | | | | | | |
| Net income | | $ | 13,197,710 | | | $ | 10,506,525 | | | $ | 10,467,614 | |
| Pension adjustments, net of tax of | | | | | | | | | | | | |
| $342,320, ($48,889) and $33,615, respectively | | | (517,124 | ) | | | 74,036 | | | | (50,905 | ) |
| Comprehensive Income | | $ | 12,680,586 | | | $ | 10,580,561 | | | $ | 10,416,709 | |
The accompanying notes are an integral part of the financial statements.
-Chesapeake Utilities Corporation 2009 Form 10-K Page 39 - -65
Notes to the Consolidated Financial Statements
Consolidated Statements of Income Taxes
| For the Years Ended December 31, | | 2007 | | | 2006 | | | 2005 | |
| | | | | | | | | | |
| Current Income Tax Expense | | | | | | | | | |
| Federal | | $ | 5,512,071 | | | $ | 5,994,296 | | | $ | 3,687,800 | |
| State | | | 1,223,145 | | | | 1,424,485 | | | | 789,233 | |
| Investment tax credit adjustments, net | | | (50,579 | ) | | | (54,816 | ) | | | (54,816 | ) |
| Total current income tax expense | | | 6,684,637 | | | | 7,363,965 | | | | 4,422,217 | |
| | | | | | | | | | | | | |
Deferred Income Tax Expense (1) | | | | | | | | | | | | |
| Property, plant and equipment | | | 2,958,758 | | | | 1,697,024 | | | | 1,380,628 | |
| Deferred gas costs | | | (629,228 | ) | | | (2,085,066 | ) | | | 1,064,310 | |
| Pensions and other employee benefits | | | (9,154 | ) | | | (97,436 | ) | | | (340,987 | ) |
| Environmental expenditures | | | 45,872 | | | | (5,580 | ) | | | (98,229 | ) |
| Other | | | (464,322 | ) | | | (36,345 | ) | | | (115,923 | ) |
| Total deferred income tax expense (benefit) | | | 1,901,926 | | | | (527,403 | ) | | | 1,889,799 | |
| Total Income Tax Expense | | $ | 8,586,563 | | | $ | 6,836,562 | | | $ | 6,312,016 | |
| | | | | | | | | | | | | |
| Reconciliation of Effective Income Tax Rates | | | | | | | | | | | | |
| Continuing Operations | | | | | | | | | | | | |
Federal income tax expense (2) | | $ | 7,635,336 | | | $ | 6,212,237 | | | $ | 6,009,861 | |
| State income taxes, net of federal benefit | | | 1,086,680 | | | $ | 829,630 | | | $ | 732,046 | |
| Other | | | (124,555 | ) | | $ | (42,795 | ) | | $ | (269,687 | ) |
| Total continuing operations | | $ | 8,597,461 | | | $ | 6,999,072 | | | $ | 6,472,220 | |
| Discontinued operations | | $ | (10,898 | ) | | $ | (162,510 | ) | | $ | (160,204 | ) |
| Total income tax expense | | $ | 8,586,563 | | | $ | 6,836,562 | | | $ | 6,312,016 | |
| | | | | | | | | | | | | |
| Effective income tax rate | | | 39.4 | % | | | 39.4 | % | | | 37.6 | % |
| | | | | | | | | | | | | |
| At December 31, | | 2007 | | | 2006 | | | | | |
| | | | | | | | | | | | | |
| Deferred Income Taxes | | | | | | | | | | | | |
| Deferred income tax liabilities: | | | | | | | | | | | | |
| Property, plant and equipment | | $ | 31,058,050 | | | $ | 27,997,744 | | | | | |
| Environmental costs | | | 250,021 | | | | 204,149 | | | | | |
| Other | | | 860,993 | | | | 870,424 | | | | | |
| Total deferred income tax liabilities | | | 32,169,064 | | | | 29,072,317 | | | | | |
| | | | | | | | | | | | | |
| Deferred income tax assets: | | | | | | | | | | | | |
| Pension and other employee benefits | | | 2,581,853 | | | | 2,225,944 | | | | | |
| Self insurance | | | 384,009 | | | | 468,922 | | | | | |
| Deferred gas costs | | | 1,146,133 | | | | 528,814 | | | | | |
| Other | | | 1,416,577 | | | | 696,855 | | | | | |
| Total deferred income tax assets | | | 5,528,572 | | | | 3,920,535 | | | | | |
| Deferred Income Taxes Per Consolidated Balance Sheet | | $ | 26,640,492 | | | $ | 25,151,782 | | | | | |
| | | | | | | | | | | | | |
| (1) Includes $260,000, ($60,000), and $146,000 of deferred state income taxes for the years 2007, 2006, and 2005, respectively. | |
| (2) Federal income taxes were recorded at 35% for each year represented. | | | | | |
The accompanying notes are an integral part of the financial statements.
A. Summary of Accounting Policies
Nature of Business
Chesapeake, incorporated in 1947 in Delaware, is a diversified utility company engaged in regulated energy, unregulated energy and other unregulated businesses. On October 28, 2009, we completed a merger with FPU, pursuant to which FPU became a wholly-owned subsidiary of Chesapeake. Our regulated energy business delivers natural gas distribution to 62,852approximately 118,000 customers located in central and southern Delaware, Maryland’s Eastern Shore and Florida and electricity to approximately 31,000 customers in northeast and northwest Florida. The Company’sOur regulated energy business also provides natural gas transmission subsidiary operates anservice primarily through a 384-mile interstate pipeline from various points in Pennsylvania and northern Delaware to the Company’sour natural gas distribution affiliates in Delaware and Maryland distribution divisions as well as to other utility and industrial customers in Pennsylvania, Delaware and the Eastern Shore of Maryland. The Company’s
Our unregulated energy business includes natural gas marketing, propane distribution and propane wholesale marketing segmentoperations. The natural gas marketing operation sells natural gas supplies directly to commercial and industrial customers in Florida, Delaware and Maryland. The propane distribution operation provides distribution service to 34,14349,000 customers in central and southern Delaware, the Eastern Shore of Maryland and Virginia, southeastern Pennsylvania central Florida and the Eastern Shore of Virginia andFlorida. The propane wholesale marketing operation markets propane to wholesale customers including large independent oil and petrochemical companies, resellers and propane distribution companies in the southeastern United States. The
We also engage in non-energy businesses, primarily through our advanced information services segmentsubsidiary, which provides domestic and international clients with information-technology-related business services and solutions for both enterprise and e-business applications.
Principles of Consolidation
The Consolidated Financial Statements include the accounts of the Company and its wholly ownedwholly-owned subsidiaries. The Company doesAs a result of the merger with FPU on October 28, 2009, FPU’s financial position, results of operations and cash flows have been consolidated into our results from the effective date of the merger. We do not have any ownership interests in investments accounted for using the equity method or any variable interests in a variable interest entity. All intercompany transactions have been eliminated in consolidation.
System of Accounts
TheOur natural gas and electric distribution divisions of the Company locatedoperations in Delaware, Maryland and Florida are subject to regulation by their respective PSCsPSC with respect to their rates for service, maintenance of their accounting records and various other matters. Eastern ShoreESNG is an open access pipeline and is subject to regulationregulated by the FERC. Our financial statements are prepared in accordance with GAAP, which give appropriate recognition to the ratemaking and accounting practices and policies of the various regulatory commissions. The propane, advanced information servicesunregulated energy and other business segmentsunregulated businesses are not subject to regulation with respect to rates, service or maintenance of accounting records.
Property, Plant, Equipment and Depreciation
UtilityProperty, plant and non-utility propertyequipment is stated at original cost.cost less accumulated depreciation or fair value, if impaired. Property, plant and equipment acquired in the merger were stated at fair value at the time of the merger. Costs include direct labor, materials and third-party construction contractor costs, allowance for capitalized interest and certain indirect costs related to equipment and employees engaged in construction. The costs of repairs and minor replacements are charged against income as incurred, and the costs of major renewals and betterments are capitalized. Upon retirement or disposition of non-utility property of unregulated businesses, the gain or loss, net of salvage value, is charged to income. Upon retirement or disposition of utility property of regulated businesses, the gain or loss, net of salvage value, is charged to accumulated depreciation. The provision for depreciation is computed using the straight-line method at rates that amortize the unrecovered cost of depreciable property over the estimated remaining useful life of the asset. Depreciation and amortization expenses for the regulated energy operations are provided at anvarious annual rate for each segment. The three-year average rates, were three percentas approved by the regulators.
Page 66 Chesapeake Utilities Corporation 2009 Form 10-K
| | | | | | | | | | | | | |
| | | December 31, | | | December 31, | | | | |
| (In thousands) | | 2009 | | | 2008 | | | Useful Life(1) | |
| |
| Plant in service | | | | | | | | | | | | |
| Mains | | $ | 237,133 | | | $ | 184,125 | | | 27-62 years |
| Services — utility | | | 61,803 | | | | 37,947 | | | 12-48 years |
| Compressor station equipment | | | 24,981 | | | | 24,981 | | | 42 years |
| Liquefied petroleum gas equipment | | | 30,211 | | | | 26,304 | | | 5-31 years |
| Meters and meter installations | | | 28,419 | | | | 19,479 | | | Unregulated energy 3-33 years, regulated energy 14-49 years |
| Measuring and regulating station equipment | | | 19,131 | | | | 15,092 | | | 14-54 years |
| Office furniture and equipment | | | 15,587 | | | | 12,536 | | | Unregulated energy 4-7 years, regulated energy14-25 years |
| Transportation equipment | | | 16,805 | | | | 11,267 | | | 1-20 years |
| Structures and improvements | | | 15,007 | | | | 10,602 | | | 3-44 years(2) |
| Land and land rights | | | 12,789 | | | | 7,901 | | | Not depreciable, except certain regulated assets |
| Propane bulk plants and tanks | | | 12,181 | | | | 6,296 | | | 12-40 years |
| Electric transmission lines and transformers | | | 29,736 | | | | — | | | 10-41 years |
| Poles and towers | | | 8,752 | | | | — | | | 21-40 years |
| Various | | | 28,735 | | | | 23,677 | | | Various |
| | | | | | | | | | | |
| Total plant in service | | | 541,270 | | | | 380,207 | | | | | |
| Plus construction work in progress | | | 2,476 | | | | 1,482 | | | | | |
| Less accumulated depreciation | | | (107,318 | ) | | | (101,018 | ) | | | | |
| | | | | | | | | | | |
| Net property, plant and equipment | | $ | 436,428 | | | $ | 280,671 | | | | | |
| | | | | | | | | | | |
| | |
| (1) | | Certain immaterial account balances may fall outside this range. |
|
| | The regulated operations compute depreciation in accordance with rates approved by either the state PSC or the FERC. These rates are based on depreciation studies and may change periodically upon receiving approval from the appropriate regulatory body. The depreciation rates shown above are based on the remaining useful lives of the assets at the time of the depreciation study, rather than their original lives. The depreciation rates are composite, straight-line rates applied to the average investment for each class of depreciable property and are adjusted for anticipated cost of removal less salvage value. |
|
| | The non-regulated operations compute depreciation using the straight-line method over the estimated useful life of the asset. |
|
| (2) | | Includes buildings, structures used in connection with natural gas, electric and propane operations, improvements to those facilities and leasehold improvements. |
Plant in service includes $1.4 million of assets owned by one of our natural gas distributiontransmission subsidiaries, which it uses to provide natural gas transmission service under a contract with a third-party. This contract is accounted for as an operating lease due to exclusive use of the assets by the customer. The service under this contract commenced in January 2009 and transmission, five percentprovides $264,000 in annual revenues for propane, eleven percenta term of 20 years. Accumulated depreciation for advanced information services and six percent for general plant.these assets total $74,000 at December 31, 2009.
| At December 31, | 2007 | 2006 | Useful Life (1) |
| Plant in service | | | |
| Mains | $166,202,413 | $151,890,304 | 27-41 years |
| Services — utility | 35,127,633 | 32,334,145 | 14-33 years |
| Compressor station equipment | 24,959,330 | 24,921,976 | 28 years |
| Liquefied petroleum gas equipment | 25,575,213 | 24,627,398 | 30-33 years |
| Meters and meter installations | 18,111,466 | 16,093,737 | Propane 10-33 years, Natural gas 26-44 years |
| Measuring and regulating station equipment | 14,067,262 | 13,272,201 | 27-54 years |
| Office furniture and equipment | 9,947,881 | 10,114,101 | Non-regulated 3-10 years, Regulated 14-28 years |
| Transportation equipment | 11,194,916 | 10,686,259 | 3-11 years |
| Structures and improvements | 10,024,105 | 9,538,345 | 10-44 years (2) |
| Land and land rights | 7,404,679 | 7,386,268 | Not depreciable, except certain regulated assets |
| Propane bulk plants and tanks | 5,313,061 | 5,301,457 | 15 - 40 years |
| Various | 20,009,979 | 17,839,745 | Various |
| Total plant in service | 347,937,938 | 324,005,936 | |
| Plus construction work in progress | 4,899,608 | 1,829,948 | |
| Less accumulated depreciation | (92,414,289) | (85,010,472) | |
| Net property, plant and equipment | $260,423,257 | $240,825,412 | |
| | | | |
| (1) Certain immaterial account balances may fall outside this range. |
| | | | |
| The regulated operations compute depreciation in accordance with rates approved by either the state Public Service Commission |
| or the FERC. These rates are based on depreciation studies and may change periodically upon receiving approval from the |
| appropriate regulatory body. The depreciation rates shown above are based on the remaining useful lives of the assets at the |
| time of the depreciation study, rather than their original lives. The depreciation rates are composite, straight-line rates applied |
| to the average investment for each class of depreciable property and are adjusted for anticipated cost of removal less salvage |
| value. | | | |
| | | | |
| The non-regulated operations compute depreciation using the straight-line method over the estimated useful life of the asset. |
| | | | |
| (2) Includes buildings, structures used in connection with natural gas and propane operations, improvements to those facilities |
| and leasehold improvements. |
Cash and Cash Equivalents
The Company’sOur policy is to invest cash in excess of operating requirements in overnight income-producing accounts. Such amounts are stated at cost, which approximates market value. Investments with an original maturity of three months or less when purchased are considered cash equivalents.
Chesapeake Utilities Corporation 2009 Form 10-K Page 67
Inventories
Inventories
The Company usesWe use the average cost method to value propane, and materials and supplies, and other merchandise inventory. If market prices drop below cost, inventory balances that are subject to price risk are adjusted to market values.
Regulatory Assets, Liabilities and Expenditures
The Company accountsWe account for itsour regulated operations in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.ASC Topic 980, “Regulated Operations.” This standardTopic includes accounting principles for companies whose rates are determined by independent third-party regulators. When setting rates, regulators often make decisions, the economics of which require companies to defer costs or revenues in different periods than may be appropriate for unregulated enterprises. When this situation occurs, thea regulated utilitycompany defers the associated costs as regulatory assets (regulatory assets) on the balance sheet and records them as expense on the income statement as it collects revenues. Further, regulators can also impose liabilities upon a regulated company for amounts previously collected from customers, and for recovery of costs that are expected to be incurred in the future (regulatory liabilities).
as regulatory liabilities.
At December 31, 20072009 and 2006,2008, the regulated utility operations had recorded the following regulatory assets and liabilities on the Balance Sheets. These assets and liabilities will be recognized as revenues and expenses in future periods as they are reflected in customers’ rates.
| | | | | | | | | |
| | | December 31, | | | December 31, | |
| (in thousands) | | 2009 | | | 2008 | |
| |
Regulatory Assets | | | | | | | | |
| Underrecovered purchased gas costs | | $ | 1,149 | | | $ | 651 | |
| Income tax related amounts due from customers | | | 1,783 | | | | 1,285 | |
| Deferred post retirement benefits | | | 3,636 | | | | 83 | |
| Deferred transaction and transition costs | | | 1,486 | | | | — | |
| Deferred piping and conversion costs | | | 1,061 | | | | — | |
| Deferred development costs | | | 1,698 | | | | — | |
| Environmental regulatory assets and expenditures | | | 7,510 | | | | 779 | |
Acquisition adjustment(1) | | | 795 | | | | — | |
| Loss on reacquired debt | | | 154 | | | | — | |
| Other | | | 1,793 | | | | 834 | |
| | | | | | | |
| Total Regulatory Assets | | $ | 21,065 | | | $ | 3,632 | |
| | | | | | | |
| | | | | | | | | |
Regulatory Liabilities | | | | | | | | |
| Self insurance | | $ | 982 | | | $ | 912 | |
| Overrecovered purchased gas costs | | | 7,304 | | | | 1,542 | |
| Shared interruptible margins | | | 84 | | | | 232 | |
| Conservation cost recovery | | | 1,035 | | | | 744 | |
Rate refund(2) | | | 258 | | | | — | |
| Income tax related amounts due to customers | | | 729 | | | | 125 | |
| Storm reserve | | | 2,554 | | | | — | |
| Accrued asset removal cost | | | 33,214 | | | | 20,641 | |
| Other | | | 90 | | | | 547 | |
| | | | | | | |
| Total Regulatory Liabilities | | $ | 46,250 | | | $ | 24,743 | |
| | | | | | | |
| At December 31, | | 2007 | | | 2006 | |
| Regulatory Assets | | | | | | |
| Current | | | | | | |
| Underrecovered purchased gas costs | | $ | 1,389,454 | | | $ | 1,076,921 | |
| Conservation cost recovery | | | - | | | | 51,408 | |
| PSC Assessment | | | 22,290 | | | | 22,290 | |
| Flex rate asset | | | 107,394 | | | | 81,926 | |
| Other | | | 55,934 | | | | 43,108 | |
| Total current | | | 1,575,072 | | | | 1,275,653 | |
| | | | | | | | | |
| Non-Current | | | | | | | | |
| Income tax related amounts due from customers | | | 1,115,638 | | | | 1,300,544 | |
| Deferred regulatory and other expenses | | | 446,642 | | | | 188,686 | |
| Deferred gas supply | | | 15,201 | | | | 15,201 | |
| Deferred post retirement benefits | | | 111,159 | | | | 138,949 | |
| Environmental regulatory assets and expenditures | | | 850,594 | | | | 121,708 | |
| Total non-current | | | 2,539,234 | | | | 1,765,088 | |
| | | | | | | | | |
| Total Regulatory Assets | | $ | 4,114,306 | | | $ | 3,040,741 | |
| | | | | | | | | |
| Regulatory Liabilities | | | | | | | | |
| Current | | | | | | | | |
| Self insurance — current | | $ | 191,004 | | | $ | 568,897 | |
| Overrecovered purchased gas costs | | | 4,225,845 | | | | 2,351,553 | |
| Shared interruptible margins | | | 11,202 | | | | 100,355 | |
| Conservation cost recovery | | | 395,379 | | | | - | |
| Operational flow order penalties | | | - | | | | 7,831 | |
| Swing transportation imbalances | | | 1,477,336 | | | | 1,170,511 | |
| Total current | | | 6,300,766 | | | | 4,199,147 | |
| | | | | | | | | |
| Non-Current | | | | | | | | |
| Self insurance — long-term | | | 757,557 | | | | 600,787 | |
| Income tax related amounts due to customers | | | 151,521 | | | | 285,819 | |
| Environmental overcollections | | | 226,993 | | | | 349,648 | |
| Total non-current | | | 1,136,071 | | | | 1,236,254 | |
| | | | | | | | | |
| Accrued asset removal cost | | | 20,249,948 | | | | 18,410,992 | |
| | | | | | | | | |
| Total Regulatory Liabilities | | $ | 27,686,785 | | | $ | 23,846,393 | |
| | |
| (1) | | Net carrying value of goodwill from FPU’s previous acquisition that is allowed to be amortized pursuant to a rate order. |
|
| (2) | | Refunded to FPU natural gas customers in February 2010. |
Included in the regulatory assets listed above are $107,000 ofis $1.5 million related to deferred merger-related costs at December 31, 2009 for which is accruing interest. Ofwe intend to seek recovery in future rates in Florida. Also included in the remaining regulatory assets $2.6 million will be collectedlisted above are $838,000 and $711,000 at December 31, 2009 and 2008, respectively, in approximately oneother costs primarily related to two years, $293,000 will be collected within approximately 3 to 10 years, and $721,000 will be collected within approximately 11 to 15 years. In addition, there is approximately $466,000income tax related amounts, for which the Company iswe are awaiting regulatory approval from various jurisdictions for recovery. For certain regulatory assets, such as under-recovered purchased fuel costs, deferred rate case costs and development costs, only recovery but once approvedof the deferred costs is expected to be collected within 12 months.allowed in rates and we do not earn a return on those regulatory assets.
Page 68 Chesapeake Utilities Corporation 2009 Form 10-K
As required by SFAS No. 71, the Company monitors itsWe monitor our regulatory and competitive environment to determine whether the recovery of itsour regulatory assets continues to be probable. If the Companywe were to determine that recovery of these assets is no longer probable, itwe would write off the assets against earnings. The Company believesWe believe that SFAS No. 71 continuesprovisions of ASC Topic 980 “Regulated Operations” continue to apply to itsour regulated operations, and that the recovery of itsour regulatory assets is probable.
Goodwill and Other Intangible Assets
The Company accounts for its goodwill and other intangibles under SFAS No. 142, “Goodwill and Other Intangible Assets.” Under SFAS No. 142, goodwillGoodwill is not amortized but is tested for impairment at least annually. In addition, goodwill of a reporting unit is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives. Please refer to Note FH, “Goodwill and Other Intangible Assets”Assets,” to the Consolidated Financial Statements for additional discussionsdiscussion of this subject.
Other Deferred Charges
Other deferred charges include discount, premium and issuance costs associated with long-term debt. Debt costs are deferred and then are amortized to interest expense over the original lives of the respective debt issuances.
Pension and Other Postretirement Plans
Pension and other postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected returns on plan assets, assumed discount rates, the level of contributions made to the plans, and current demographic and actuarial mortality data. Management annually reviews the estimates and assumptions underlying our pension and other postretirement plan costs and liabilities with the assistance of third-party actuarial firms. The assumed discount rates and the expected returns on plan assets are the assumptions that generally have the most significant impact on our pension costs and liabilities. The assumed discount rates, health care cost trend rates and rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities.
The discount rates are utilized principally in calculating the actuarial present value of our pension and postretirement obligations and net pension and postretirement costs. When establishing its discount rates, we consider high quality corporate bond rates based on Moody’s Aa bond index, the Citigroup yield curve, changes in those rates from the prior year, and other pertinent factors, such as the expected life of each of our plans and their respective payment options.
The expected long-term rates of return on assets are utilized in calculating the expected returns on plan assets component of our annual pension and plan costs. We estimate the expected returns on plan assets of each of our plans by evaluating expected bond returns, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rates of return on assets.
We estimate the assumed health care cost trend rates used in determining our postretirement net expense based upon actual health care cost experience, the effects of recently enacted legislation and general economic conditions. Our assumed rate of retirement is estimated based upon our annual reviews of participant census information as of the measurement date.
Chesapeake Utilities Corporation 2009 Form 10-K Page 69
Income Taxes and Investment Tax Credit Adjustments
The Company files a consolidated federal income tax return. Income tax expense allocated to the Company’s subsidiaries is based upon their respective taxable incomes and tax credits.
Deferred tax assets and liabilities are recorded for the tax effect of temporary differences between the financial statements bases and tax bases of assets and liabilities and are measured using the enacted tax rates in effect in the years in which the differences are expected to reverse. The portions of the Company’sour deferred tax liabilities applicable to utilityregulated energy operations, which have not been reflected in current service rates, represent income taxes recoverable through future rates. Deferred tax assets are recorded net of any valuation allowance when it is more likely than not that such tax benefits will be realized. Investment tax credits on utility property have been deferred and are allocated to income ratably over the lives of the subject property.
The Company adopted the provisions of FIN 48 “Accounting for Uncertainty in Income Taxes,” effective January 1, 2007. FIN 48 clarifies the accountingWe account for uncertainty in income taxes recognized in a Company’sthe financial statements in accordance with SFAS 109 “Accounting for Income Taxes.” FIN 48 requires that an uncertain tax position should be recognized only if it is “more likely than not” that thean uncertain tax position is sustainable based on technical merits. Recognizable tax positions shouldare then be measured to determine the amount of benefit recognized in the financial statements. The Company’s adoption of FIN 48 did not have an impact on its financial condition or results of operations.
Financial Instruments
Xeron, Inc. (“Xeron”), the Company’sour propane wholesale marketing operation, engages in trading activities using forward and futures contracts, which have been accounted for using the mark-to-market method of accounting. Under mark-to-market accounting, the Company’sour trading contracts are recorded at fair value, net of future servicing costs. The changes in market price are recognized as gains or losses in revenues on the consolidated income statement in the period of change. The resulting unrealized gains and losses are recorded as assets or liabilities, respectively. There were unrealized losses of $1.6 million in 2009 and unrealized gains of $179,000 and $8,500 at December 31, 2007 and 2006, respectively.$1.4 million in 2008. Trading liabilities are recorded in mark-to-market energy liabilities. Trading assets are recorded in mark-to-market energy assets.
The Company’sOur natural gas, electric and propane distribution operations have entered into agreements with natural gas and propane 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 of SFAS No. 133 or are considered “normal purchases and sales” under SFAS No. 138 and are accounted for on an accrual basis.
The propane distribution operation may enter into a fair value hedge of its inventory in order to mitigate the impact of wholesale price fluctuations. At December 31, 2007, the Company decided not to hedge any of its propane inventories. At December 31, 2006, the propane distribution operation hadDuring 2008, we entered into a swap agreement to protect the Company from the impact ofthat propane price increases would have on the price-cap planPro-Cap (propane price cap) Plan that the Delmarva propane distribution operation offers to our customers. Propane prices declined significantly in late 2008 and we offer to customers. The Company considered thisrecorded a mark-to-market loss of approximately $939,000 on the swap agreement to be an economic hedge that did not qualify for hedge accounting as described in SFAS 133. At2008, which increased the end of the 2006, the market pricecost of propane dropped below the unit price withinsales. In January 2009, we terminated the swap agreement. AsDuring 2009, we purchased a resultput option related to the Pro-Cap Plan, which we accounted for on a mark-to-market basis, and recorded a loss of $41,000. At December 31, 2009 and 2008, we had $0 in fair value of the price drop,put agreement and $(105,000) in fair value of the Company marked theswap agreement, to market, which resulted in an unrealized loss of $84,000.respectively.
Page 70 Chesapeake Utilities Corporation 2009 Form 10-K
Earnings Per Share
Chesapeake calculatesBasic earnings per share in accordance with SFAS 128 “Earningsare computed by dividing income available for common shareholders by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per Share.”share are computed by dividing income available for common shareholders by the weighted average number of shares of common stock outstanding during the period adjusted for the exercise and/or conversion of all potentially dilutive securities, such as convertible debt and share-based compensation. The calculations of both basic and diluted earnings per share are presented in the following chart.
| | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2009 | | | 2008 | | | 2007 | |
| (in thousands, except shares and per share data) | | | | | | | | | | | | |
| |
Calculation of Basic Earnings Per Share: | | | | | | | | | | | | |
| Net Income | | $ | 15,897 | | | $ | 13,607 | | | $ | 13,198 | |
| Weighted average shares outstanding | | | 7,313,320 | | | | 6,811,848 | | | | 6,743,041 | |
| | | | | | | | | | |
Basic Earnings Per Share | | $ | 2.17 | | | $ | 2.00 | | | $ | 1.96 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Calculation of Diluted Earnings Per Share: | | | | | | | | | | | | |
Reconciliation of Numerator: | | | | | | | | | | | | |
| Net Income | | $ | 15,897 | | | $ | 13,607 | | | $ | 13,198 | |
| Effect of 8.25% Convertible debentures | | | 79 | | | | 89 | | | | 96 | |
| | | | | | | | | | |
| Adjusted numerator — Diluted | | $ | 15,976 | | | $ | 13,696 | | | $ | 13,294 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Reconciliation of Denominator: | | | | | | | | | | | | |
| Weighted shares outstanding — Basic | | | 7,313,320 | | | | 6,811,848 | | | | 6,743,041 | |
| Effect of dilutive securities: | | | | | | | | | | | | |
| Share-based Compensation | | | 34,229 | | | | 12,083 | | | | — | |
| 8.25% Convertible debentures | | | 92,652 | | | | 103,552 | | | | 111,675 | |
| | | | | | | | | | |
| Adjusted denominator — Diluted | | | 7,440,201 | | | | 6,927,483 | | | | 6,854,716 | |
| | | | | | | | | | |
| |
Diluted Earnings Per Share | | $ | 2.15 | | | $ | 1.98 | | | $ | 1.94 | |
| | | | | | | | | | |
| For the Periods Ended December 31, | | 2007 | | | 2006 | | | 2005 | |
| Calculation of Basic Earnings Per Share: | | | | | | | | | |
| Net Income | | $ | 13,197,710 | | | $ | 10,506,525 | | | $ | 10,467,614 | |
| Weighted average shares outstanding | | | 6,743,041 | | | | 6,032,462 | | | | 5,836,463 | |
| Basic Earnings Per Share | | $ | 1.96 | | | $ | 1.74 | | | $ | 1.79 | |
| | | | | | | | | | | | | |
| Calculation of Diluted Earnings Per Share: | | | | | | | | | | | | |
| Reconciliation of Numerator: | | | | | | | | | | | | |
| Net Income | | $ | 13,197,710 | | | $ | 10,506,525 | | | $ | 10,467,614 | |
| Effect of 8.25% Convertible debentures | | | 95,611 | | | | 105,024 | | | | 123,559 | |
| Adjusted numerator — Diluted | | $ | 13,293,321 | | | $ | 10,611,549 | | | $ | 10,591,173 | |
| | | | | | | | | | | | | |
| Reconciliation of Denominator: | | | | | | | | | | | | |
| Weighted shares outstanding — Basic | | | 6,743,041 | | | | 6,032,462 | | | | 5,836,463 | |
Effect of dilutive securities | | | | | | | | | | | | |
| Warrants | | | - | | | | - | | | | 11,711 | |
| 8.25% Convertible debentures | | | 111,675 | | | | 122,669 | | | | 144,378 | |
| Adjusted denominator — Diluted | | | 6,854,716 | | | | 6,155,131 | | | | 5,992,552 | |
| | | | | | | | | | | | | |
| Diluted Earnings Per Share | | $ | 1.94 | | | $ | 1.72 | | | $ | 1.77 | |
Operating Revenues
Revenues for theour natural gas and electric distribution operations of the Company are based on rates approved by the PSCs of the jurisdictionsstates in which wethey operate. The natural gas transmission operation’s revenues are based on rates approved by the FERC. Customers’ base rates may not be changed without formal approval by these commissions. However, the regulatory authoritiesThe PSCs, however, have granted the Company’sauthorized our regulated natural gas distribution operations the ability to negotiate rates, based on approved methodologies, with customers that have competitive alternatives. In addition, the natural gas transmission operation canThe FERC has also authorized ESNG to negotiate rates above or below the FERC-approved tariffmaximum rates, which customers can elect as a recourse to negotiated rates.
For regulated deliveries of natural gas Chesapeake readsand electricity, we read meters and billsbill customers on monthly cycles that do not coincide with the accounting periods used for financial reporting purposes. Chesapeake accruesWe accrue unbilled revenues for natural gas and electricity that hashave been delivered, but not yet billed, at the end of an accounting period to the extent that they do not coincide. In connection with this accrual, Chesapeakewe must estimate the amount of natural gas and electricity that hashave not been accounted for on itsour delivery systemsystems and must estimate the amount of the unbilled revenue by jurisdiction and customer class. A similar computation is made to accrue unbilled revenues for propane customers with meters, such as community gas system customers.customers, and natural gas marketing customers, whose billing cycles do not coincide with the accounting periods.
The propane wholesale marketing operation records trading activity for open contracts on a net mark-to-market basis in the Company’s incomeour consolidated statement for open contracts. Theof income. For propane distribution customers without meters and advanced information services and other segmentscustomers, we record revenue in the period the products are delivered and/or services are rendered.
Chesapeake Utilities Corporation 2009 Form 10-K Page 71
Chesapeake’sEach of our natural gas distribution operations in Delaware and Maryland, each havebundled natural gas distribution service in Florida and electric distribution operation in Florida has a purchased gasfuel cost recovery mechanism. This mechanism provides the Company with a method of adjusting the billing rates with its customers forto reflect changes in the cost of purchased gas included in base rates.fuel. The difference between the current cost of gasfuel purchased and the cost of gasfuel recovered in billed rates is deferred and accounted for as either unrecovered purchased gasfuel costs or amounts payable to customers. Generally, these deferred amounts are recovered or refunded within one year.
The Company chargesWe charge flexible rates to theour natural gas distribution’sdistribution industrial interruptible customers to make them competitivecompete with prices of alternative types of fuel. Based on pricing,fuels, which these customers can choose natural gas or alternative fuels.are able to use. Neither the Company nor theany of its interruptible customercustomers is contractually obligated to deliver or receive natural gas.gas on a firm service basis.
Cost of Sales
Cost of sales includes the direct costs attributable to the products sold or services provided by the Company for its regulated and unregulated energy segments. These costs include primarily the variable 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 for our advanced information services operation.
Operations and Maintenance Expenses
Operations and maintenance expenses are costs associated with the operation and maintenance of our regulated and unregulated operations. Major cost components include operation and maintenance salaries and benefits, materials and supplies, usage of vehicles, tools and equipment, payments to contractors, utility plant maintenance, customer service, professional fees and other outside services, insurance expense, minor amounts of depreciation, accretion of cost of removal for future retirements of utility assets, and other administrative expenses.
Depreciation and Accretion Included in Operations Expenses
Depreciation and accretion included in operations expenses consist of the accretion of the costs of removal for future retirement of utility assets, vehicle depreciation, computer software and hardware depreciation, and other minor amounts of depreciation expense.
Allowance for Doubtful Accounts
An allowance for doubtful accounts is recorded against amounts due to reduce the net receivablereceivables balance to the amount we reasonably expect to collect based upon our collections experiences and ourmanagement’s assessment of our customers’ inability or reluctance to pay. If circumstances change, however, our estimateestimates of the recoverability ofrecoverable accounts receivable may also change. Circumstances which could affect oursuch estimates include, but are not limited to, customer credit issues, the level of natural gas, electricity and propane prices and general economic conditions. Accounts are written off oncewhen they are deemed to be uncollectible.
Certain Risks and Uncertainties
The Company’sOur financial statements are prepared in conformity with generally accepted accounting principles thatGAAP, which require management to make estimates in measuring assets and liabilities and related revenues and expenses (see Notes MNote O, “Environmental Commitments and NContingencies,” and Note P, “Other Commitments and Contingencies,” to the Consolidated Financial Statements for significant estimates). These estimates involve judgments with respect to, among other things, various future economic factors that are difficult to predict and are beyond the control of the Company; therefore, actual results could differ from those estimates.
The Company recordsWe record certain assets and liabilities in accordance with SFAS No. 71.ASC Topic 980, “Regulated Operations.” In applying provisions of this Topic, our regulated operations may defer costs or revenues in different periods than our unregulated operations would recognize, resulting in their being recorded as assets or liabilities on the applicable operation’s balance sheet. If the Companywe were required to terminate the application of SFAS No. 71 for itsthese provisions to our regulated operations, all such deferred amounts would be recognized in the income statement at that time. This couldwould result in a charge to earnings, net of applicable income taxes, which could be material.
Page 72 Chesapeake Utilities Corporation 2009 Form 10-K
Acquisition Accounting
FASBThe merger with FPU was accounted for under the acquisition method of accounting, with Chesapeake treated as the acquirer. The acquisition method of accounting requires, among other things, that the assets acquired and liabilities assumed in the merger be recognized at their fair value as of the acquisition date. It also establishes that the consideration transferred be measured at the closing date of the merger at the then-current market price. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In addition, market participants are assumed to be buyers and sellers in the principal (or the most advantageous) market for the asset or liability and fair value measures for an asset assume the highest and best use by those market participants, rather than the acquirer’s intended use of those assets. Many of these fair value measurements can be highly subjective and it is also possible that others applying reasonable judgment to the same facts and circumstances could develop and support a range of alternative estimated amounts. In estimating the fair value of the assets and liabilities subject to rate regulation, we considered the nature and impact of such regulations on those assets and liabilities as a factor in determining their appropriate fair value. We also considered the existence of a regulatory process that would allow, or sometimes require, regulatory assets and liabilities to be established for fair value adjustment to certain assets and liabilities subject to rate regulation. If a regulatory asset or liability should be established to offset the fair value adjustment based on the current regulatory process, as was the case for fuel contracts and long-term debt, we did not “gross-up” our balance sheet to reflect the fair value adjustment and corresponding regulatory asset/liability, because such “gross-up” would not have resulted in a change to the value of net assets and future earnings of the Company.
Total value of the consideration transferred by Chesapeake in the merger was $75.7 million. Net fair value of the assets acquired and liabilities assumed in the merger was estimated to be $42.3 million. This resulted in a purchase premium of $33.4 million, which was reflected as goodwill. Note B, “Acquisitions and Dispositions,” to the Consolidated Financial Statements describes more fully the purchase price allocation.
The acquisition method of accounting also requires acquisition-related costs to be expensed in the period in which those costs are incurred, rather than including them as a component of considerations transferred. It also prohibits an accrual of certain restructuring costs at the time of the merger for the acquiree. As we intend to seek recovery in future rates in Florida of a certain portion of the purchase premium paid and Other Authoritative Pronouncementsmerger-related costs incurred, we also considered the impact of ASC Topic 980, “Regulated Operations,” in determining proper accounting treatment for the merger-related costs. During 2009, we incurred approximately $3.0 million to consummate the merger, including the cost associated with merger-related litigation, and integrate operations following the merger. We deferred approximately $1.5 million of the total costs incurred as a regulatory asset at December 31, 2009, which represents our estimate, based on similar proceedings in Florida in the past, of the costs which we expect to be permitted to recover when we complete the appropriate rate proceedings.
In June 2006,Subsequent Events
We have assessed and reported on subsequent events through the date of issuance of these Consolidated Financial Statements.
Reclassifications
As a result of the merger with FPU in 2009, we changed our operating segments (see Note C, “Segment Information,” to the Consolidated Financial Statements). We revised the 2008 and 2007 segment information to reflect the new segments. We also revised the 2008 segment information by reclassifying transaction costs, which were previously allocated to all segments, to the “Other” segment. We reclassified certain amounts in the statements of income and cash flows for the years ended December 31, 2008 and 2007, to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our Consolidated Financial Statements.
Chesapeake Utilities Corporation 2009 Form 10-K Page 73
Codification
Beginning in the third quarter of 2009, we adopted the Financial Accounting Standards Board (“FASB”) issued ASC, which is now the single source of authoritative accounting principles in the United States. The adoption of the ASC did not have a material impact on our financial position and results of operations. As a result of this adoption, we updated all references to accounting and reporting standards included in this Form 10-K and in some instances provided references to both pre-and post-Codification standards, as appropriate.
FASB InterpretationStatements and Other Authoritative Pronouncements
Recent Accounting Pronouncements Yet to be Adopted by the Company
In November 2008, the SEC released a proposed roadmap regarding the potential use by U.S. issuers of financial statements prepared in accordance with International Financial Reporting Standards (“FIN”IFRS”) No. 48, “Employers’, a comprehensive series of accounting standards published by the International Accounting for Uncertainty in Income Taxes.” This interpretation: (i) clarifiesStandards Board (“IASB”). Under the accounting for uncertainty in income taxes recognized in an enterprise’sproposed roadmap, we may be required to prepare financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes;IFRS as early as 2014. The SEC will make a determination in 2011 regarding the mandatory adoption of IFRS. In July 2009, the IASB issued an exposure draft of “Rate-regulated Activities,” (ii) prescribes a recognition threshold and measurement attribute forwhich sets out the financial statementscope, recognition and measurement criteria, and accounting disclosures for assets and liabilities that arise in the context of cost-of-service regulation, to which we are subject in our rate-regulated businesses. We will continue to monitor the development of the potential implementation of IFRS.
The FASB has issued ASU 2010-06, “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements.” This ASU requires some new disclosures and clarifies some existing disclosure requirements about fair value measurement as set forth in ASC Subtopic 820-10. The FASB’s objective is to improve these disclosures and, thus, increase the transparency in financial reporting. Specifically, ASU 2010-06 amends ASC Subtopic 820-10 to now require a tax position taken or expectedreporting entity to be takendisclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers; and in the reconciliation for fair value measurements using significant unobservable inputs, a tax return;reporting entity should present separately information about purchases, sales, issuances, and (iii) provides guidance on derecognitionsettlements. In addition, ASU 2010-06 clarifies certain requirements of the existing disclosures. ASU 2010-06 is effective for interim and classificationannual reporting periods beginning after December 15, 2009, except for disclosures about purchases, sales, issuances, and settlements in the roll forward of uncertain tax positions, reporting of interest and penalties, accountingactivity in interim periods, disclosure, and transition. FIN No.48 isLevel 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2006,2010, and Chesapeake’s adoptionfor interim periods within those fiscal years. We are currently assessing the potential impact of itthis pronouncement.
Other Accounting Amendments Adopted by the Company in 2009:
In December 2007, the first quarterFASB issued Statement of 2007 did not haveFinancial Accounting Standard (“SFAS”) No. 141(R), now codified within ASC Topic 805, “Business Combinations.” SFAS No.141(R): (a) defines the acquirer as the entity that obtains control of one or more businesses in a business combination; (b) establishes the acquisition date as the date that the acquirer achieves control; and (c) requires the acquirer to recognize the assets acquired, liabilities assumed and any impact onnon-controlling interests at their fair values as of the Company’sacquisition date. It also requires that acquisition-related costs be expensed as incurred. Provisions of this standard were adopted effective January 1, 2009. The merger with FPU, effective October 28, 2009, was accounted for using provisions of this standard. For further discussion, see Note B, “Acquisition and Dispositions” to the Consolidated Financial Statements.
In September 2006,March 2008, the FASB issued SFAS No. 157, “Fair Value Measurements.” This statement defines fair value, establishes a framework for measuring fair value in GAAP,161, “Disclosures about Derivative Instruments and expands disclosures about fair value measurements. This statement applies under other accounting pronouncements that require or permit fair value measurements, the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, this statement does not require any new fair value measurements. Since SFAS No. 157 is effective for financial statements issued within fiscal years beginning after November 15, 2007, Chesapeake will be required to adopt this statement in the first quarter of 2008. The Company does not expect SFAS No. 157 will have a material impact on its Consolidated Financial Statements.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities-includingHedging Activities, an amendment of FASB Statement No. 115.133.” SFAS No. 159 permits entities161 was codified within ASC Sections 815-10-15 and 65, of the Topic, “Derivatives and Hedging,” and it requires enhanced disclosures for derivative instruments and hedging activities including: (i) how and why a company uses derivative instruments; (ii) how derivative instruments and related hedged items are accounted for under the Derivatives and Hedging Topic, and (iii) how derivative instruments and related hedged items affect a company’s financial position, financial performance and cash flows. Disclosures required by this standard were adopted by the Company, effective January 1, 2009. Adoption of this standard did not have an impact on our consolidated financial position and results of operations. These disclosures are discussed in Note E, “Derivative Instruments,” to the Consolidated Financial Statements.
Page 74 Chesapeake Utilities Corporation 2009 Form 10-K
In April 2008, the FASB issued FASB Staff Position (“FSP”) FAS 142-3, “Determination of the Useful Life of Intangible Assets,” which is codified within ASC Sections 350-30-50, 55 and 65 of the Topic, “Intangibles — Goodwill and Other,” and ASC Section 275-10-50, of the Topic, “Risks and Uncertainties.” It amended factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset. The intent of these provisions is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure atthe fair value manyof the asset. We adopted this standard, effective January 1, 2009. Adoption of this standard did not have an impact on our consolidated financial position and results of operations.
In May 2008, the FASB issued FSP APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement),” which was codified within: (a) ASC Sections 470-20-10, 15, 25, 30, 35, 40, 45, 50, 55 and 65 of the Topic, “Debt,” (b) ASC Section 815-15-55, of the Topic, “Derivatives and Hedging,” and (c) ASC Section 825-10-15, of the Topic, “Financial Instruments.” FSP APB 14-1 clarifies that companies with convertible debt instruments, which may be settled in cash upon either mandatory or optional conversion (including partial cash settlement), should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. We adopted this standard, effective, January 1, 2009. The adoption of this standard did not have an impact on our consolidated financial position and results of operations.
In September 2008, the FASB issued FSP Emerging Issues Task Force 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” This FSP, codified within FASB ASC Sections 260-10-45, 55 and 65, of the Topic, “Earnings Per Share,” clarifies that holders of outstanding unvested share-based payment awards containing rights to nonforfeitable dividends participate with common shareholders in undistributed earnings. Awards of this nature are considered participating securities, and the two-class method of computing basic and diluted earnings per share must be applied. We adopted this standard, effective January 1, 2009. The adoption of this standard did not have an impact on our consolidated financial position and results of operations.
In December 2008, the FASB issued FSP SFAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” This FSP is codified within ASC Section 715-20-65, of the Topic, “Compensation — Retirement Benefits.” It expands the disclosure requirements of a defined benefit pension or other postretirement plan by including the following discussions about plan assets: (i) how investment allocation decisions are made, including the plan’s investment policies and strategies; (ii) the major categories of plan assets; (iii) the inputs and valuation techniques used to measure the fair value of plan assets; (iv) the effect of fair value measurements, using significant unobservable inputs on changes in plan assets for the period; and (v) significant concentrations of risk within plan assets. The disclosures required by this standard are discussed in Note M, “Employee Benefit Plans,” to the Consolidated Financial Statements.
In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” This FSP, codified within ASC Section 825-10-65 of the Topic, “Financial Instruments,” enhances consistency in financial reporting by increasing the frequency of fair value disclosures. The provisions of this standard are effective for interim and annual reporting periods ending after June 15, 2009, and they did not have an impact on our consolidated financial position and results of operations. The disclosures required by this standard are discussed in Note F, “Fair Value of Financial Instruments,” to the Consolidated Financial Statements.
In May 2009, the FASB issued SFAS No. 165, “Subsequent Events,” which we adopted in the second quarter of 2009. The provisions of this standard, now residing in ASC Sections 855-10-05, 15, 25, 45, 50 and 55 of the Topic, “Subsequent Events,” establish general standards of accounting for, and disclosure of, events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The adoption of this standard did not have an impact on our consolidated financial position and results of operations.
Chesapeake Utilities Corporation 2009 Form 10-K Page 75
In August 2009, the FASB issued FASB Accounting Standards Update (“ASU”) No. 2009-05, “Fair Value Measurement and Disclosures — Measuring Liabilities at Fair Value.” This ASU provides clarification that in circumstances in which a quoted price in an active market for an identical liability is not available, a reporting entity is required to measure fair value, using either: (a) a valuation technique that applies the quoted price of the identical liability when traded as an asset or quoted prices for similar liabilities when traded as assets; or (b) another valuation technique that is consistent with the principles of the Topic, “Fair Value Measurements and Disclosures.” We adopted this ASU in the third quarter of 2009, and the adoption of this standard did not have an impact on our consolidated financial position and results of operations.
B. Acquisitions and Dispositions
FPU
On October 28, 2009, we completed the previously announced merger with FPU, pursuant to which FPU became a wholly-owned subsidiary of Chesapeake. The merger was accounted for under the acquisition method of accounting, with Chesapeake treated as the acquirer for accounting purposes.
The merger allowed us to become a larger energy company serving approximately 200,000 customers in the Mid-Atlantic and Florida markets, which is twice the number of energy customers we served previously. The merger increases our overall presence in Florida by adding approximately 51,000 natural gas distribution customers and 12,000 propane distribution customers to our existing operations in Florida. It also introduces us to the electric distribution business as we incorporate FPU’s approximately 31,000 electric customers in northwest and northeast Florida.
In consummating the merger, we issued 2,487,910 shares of Chesapeake common stock at a price per share of $30.42 in exchange for all outstanding common stock of FPU. We also paid approximately $16,000 in lieu of issuing fractional shares in the exchange. There is no contingent consideration in the merger. Total value of considerations transferred by Chesapeake in the merger was approximately $75.7 million.
The assets acquired and liabilities assumed in the merger were recorded at their respective fair values at the completion of the merger. For certain assets acquired and liabilities assumed, such as pension and post-retirement benefit obligations, income taxes and contingencies without readily determinable fair value, for which GAAP provides specific exception to the fair value recognition and measurement, we applied other specified GAAP or accounting treatment as appropriate.
The following table summarizes the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the merger. Estimates of deferred income taxes and certain other itemsaccruals are subject to change, pending the finalization of income tax returns and availability of additional information about the facts and circumstances that are not currently required to be measured at fair value, with unrealized gains and losses related to these financial instruments reported in earnings at each subsequent reporting date. This Statement is effectiveexisted as of the beginningmerger closing. We will complete the purchase price allocation as soon as practicable but no later than one year from the merger closing.
Page 76 Chesapeake Utilities Corporation 2009 Form 10-K
| | | | | |
| (in thousands) | | October 28, 2009 | |
| Purchase price | | $ | 75,699 | |
| | | | |
| | | | | |
| Current assets | | | 26,761 | |
| Property, plant and equipment | | | 141,907 | |
| Regulatory assets | | | 17,918 | |
| Investments and other deferred charges | | | 3,659 | |
| Intangible assets | | | 4,019 | |
| | | | |
| Total assets acquired | | | 194,264 | |
| | | | | |
| Long term debt | | | 47,812 | |
| Borrowings from line of credit | | | 4,249 | |
| Other current liabilities | | | 17,504 | |
| Other regulatory liabilities | | | 19,414 | |
| Pension and post retirement obligations | | | 14,276 | |
| Environmental liabilities | | | 12,414 | |
| Deferred income taxes | | | 20,850 | |
| Customer deposits and other liabilities | | | 15,467 | |
| | | | |
| Total liabilities assumed | | | 151,986 | |
| Net identifiable assets acquired | | | 42,278 | |
| | | | |
| Goodwill | | $ | 33,421 | |
| | | | |
Goodwill of an entity’s first fiscal year that begins after November 15, 2007.$33.4 million was recorded in connection with the merger, none of which is deductible for tax purposes. All of the goodwill recorded in connection with the merger is related to the regulated energy segment. We believe the goodwill recognized is attributable primarily to the strength of FPU’s regulated energy businesses and the synergies and opportunities in the combined company. Intangible assets acquired in connection with the merger are related to propane customer relationships ($3.5 million) and favorable propane contracts ($519,000). The Company does not expect SFAS No. 159intangible value assigned to FPU’s existing propane customer relationships will havebe amortized over a material impact12-year period based on its Consolidated Financial Statements.
In April 2007, the FASB directedexpected duration of benefit arising from the FASB Staffrelationships. The intangible value assigned to issue FSP No. FIN 39-1, “Amendment of FASB Interpretation No. 39” (“FSP FIN 39-1”). FSP FIN 39-1 modifies FIN No. 39, “Offsetting of Amounts Relatedfavorable propane contracts, will be amortized over a period ranging from one to Certain Contracts,14 months based on contractual terms. See Note H, “Goodwill and Other Intangible Assets,” and permits companies to offset cash collateral receivables or payables with net derivative positions under certain circumstances. FSP FIN 39-1 is effective for fiscal years beginning after November 15, 2007, with early adoption permitted. The Company does not expect FSP FIN 39-1 will have a material impact itsthe Consolidated Financial Statements.
Current assets of $26.7 million acquired during the merger include notes receivable of approximately $5.8 million, for which we expect to receive payment in March 2010, and accounts receivable of approximately $3.1 million, $6.0 million and $891,000 for natural gas, electric and propane distribution businesses, respectively.
ReclassificationThe financial position and results of Prior Years’ Amountsoperations and cash flows of FPU from the effective date of the merger are consolidated in our Consolidated Financial Statements in 2009. The revenue and net income from FPU for the post-merger period in 2009 included in our Consolidated Statements of Income were $26.4 million and $1.8 million, respectively. The following table shows pro forma results of operations for the year ended December 31, 2009, as if the merger had been completed at January 1, 2009, as well as pro forma results of operations for the year ended December 31, 2008, as if the merger had been completed at January 1, 2008.
The Company reclassified some previously reported amounts to conform to current period classifications.
Chesapeake Utilities Corporation 2009 Form 10-K Page 77
| | | | | | | | | |
| For the Years Ended December 31, | | 2009 | | | 2008 | |
| (in thousands, except per share data) | | | | | | | | |
| | | | | | | | | |
| Operating revenues | | $ | 394,772 | | | $ | 451,292 | |
| Operating Income | | | 44,382 | | | | 38,468 | |
| Net Income | | | 20,872 | | | | 17,544 | |
| | | | | | | | | |
| Earnings per share — basic | | $ | 2.23 | | | $ | 1.89 | |
| Earnings per share — diluted | | $ | 2.20 | | | $ | 1.86 | |
Pro forma results are presented for informational purposes only, and are not necessarily indicative of what the actual results would have been had the acquisitions actually occurred on January 1, 2009, and January 1, 2008, respectively.
During the quarter ended September 30, 2007, Chesapeakewe decided to close itsour distributed energy services subsidiary, Chesapeake OnSight, Services, LLC (“OnSight”), which hashad experienced operating losses since its inception in 2004. OnSight was previously reported as part of the Company’s Other business segment. At December 31, 2007, theThe results of operations for OnSight have been reclassified to discontinued operations and shown net of tax for all periods presented. For 2007, theThe discontinued operations experienced a net loss of $20,000 compared to a net loss of $241,000 for 20062007. We did not have any discontinued operations in 2008 and a net loss of $231,000 for 2005.
2009.
C. Segment Information
The following table presents information about the Company’s reportable segments. The table excludes financial data related to our distributed energy company, which was reclassed to discontinued operations for each year presented.
| For the Years Ended December 31, | | 2007 | | | 2006 | | | 2005 | |
| Operating Revenues, Unaffiliated Customers | | | | | | | |
| Natural gas distribution, transmission and marketing | | $ | 180,842,699 | | | $ | 170,114,512 | | | $ | 166,388,562 | |
| Propane | | | 62,837,696 | | | | 48,575,976 | | | | 48,975,349 | |
| Advanced information services | | | 14,606,100 | | | | 12,509,077 | | | | 14,121,441 | |
| Other | | | - | | | | - | | | | - | |
| Total operating revenues, unaffiliated customers | | $ | 258,286,495 | | | $ | 231,199,565 | | | $ | 229,485,352 | |
| | | | | | | | | | | | | |
Intersegment Revenues (1) | | | | | | | | | | | | |
| Natural gas distribution, transmission and marketing | | $ | 359,235 | | | $ | 259,970 | | | $ | 193,404 | |
| Propane | | | 406 | | | | - | | | | 668 | |
| Advanced information services | | | 492,840 | | | | 58,532 | | | | 18,123 | |
| Other | | | 622,272 | | | | 618,492 | | | | 618,492 | |
| Total intersegment revenues | | $ | 1,474,753 | | | $ | 936,994 | | | $ | 830,687 | |
| | | | | | | | | | | | | |
| Operating Income | | | | | | | | | | | | |
| Natural gas distribution, transmission and marketing | | $ | 22,485,266 | | | $ | 19,733,487 | | | $ | 17,235,810 | |
| Propane | | | 4,497,843 | | | | 2,534,035 | | | | 3,209,388 | |
| Advanced information services | | | 835,981 | | | | 767,160 | | | | 1,196,545 | |
| Other and eliminations | | | 294,492 | | | | 297,255 | | | | 279,136 | |
| Operating Income | | | 28,113,582 | | | | 23,331,937 | | | | 21,920,879 | |
| Other income | | | 291,305 | | | | 189,093 | | | | 382,610 | |
| Interest charges | | | 6,589,639 | | | | 5,773,993 | | | | 5,132,458 | |
| Income taxes | | | 8,597,461 | | | | 6,999,072 | | | | 6,472,220 | |
| Net income from continuing operations | | $ | 13,217,787 | | | $ | 10,747,965 | | | $ | 10,698,811 | |
| | | | | | | | | | | | | |
| Depreciation and Amortization | | | | | | | | | | | | |
| Natural gas distribution, transmission and marketing | | $ | 6,917,609 | | | $ | 6,312,277 | | | $ | 5,682,137 | |
| Propane | | | 1,842,047 | | | | 1,658,554 | | | | 1,574,357 | |
| Advanced information services | | | 143,706 | | | | 112,729 | | | | 122,569 | |
| Other and eliminations | | | 156,823 | | | | 160,155 | | | | 189,146 | |
| Total depreciation and amortization | | $ | 9,060,185 | | | $ | 8,243,715 | | | $ | 7,568,209 | |
| | | | | | | | | | | | | |
| Capital Expenditures | | | | | | | | | | | | |
| Natural gas distribution, transmission and marketing | | $ | 23,086,713 | | | $ | 43,894,614 | | | $ | 28,433,671 | |
| Propane | | | 5,290,215 | | | | 4,778,891 | | | | 3,955,799 | |
| Advanced information services | | | 174,184 | | | | 159,402 | | | | 294,792 | |
| Other | | | 1,591,272 | | | | 321,204 | | | | 739,079 | |
| Total capital expenditures | | $ | 30,142,384 | | | $ | 49,154,111 | | | $ | 33,423,341 | |
(1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues. | |
| | | | | | | | | | | | | |
| At December 31, | | 2007 | | | 2006 | | | 2005 | |
| Identifiable Assets | | | | | | | | | | | | |
| Natural gas distribution, transmission and marketing | | $ | 273,500,890 | | | $ | 252,292,600 | | | $ | 225,667,049 | |
| Propane | | | 94,966,212 | | | | 60,170,200 | | | | 57,344,859 | |
| Advanced information services | | | 2,507,910 | | | | 2,573,810 | | | | 2,062,902 | |
| Other | | | 10,533,511 | | | | 10,503,804 | | | | 10,911,229 | |
| Total identifiable assets | | $ | 381,508,523 | | | $ | 325,540,414 | | | $ | 295,986,039 | |
Chesapeake usesWe use the management approach to identify operating segments. Chesapeake organizes itsWe 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 Company’s chief operating decision maker (our Chief Executive Officer) in order to make decisions about resources and to assess performance. The segments are evaluated based on their pre-tax operating income.
As a result of the merger with FPU, we changed our operating segments to better align with how the chief operating decision maker views the various operations of the Company. Our three operating segments are now composed of the following:
| • | | Regulated Energy. The regulated energy segment includes natural gas distribution, electric distribution and natural gas transmission operations. All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of ESNG. |
| • | | Unregulated Energy.The unregulated energy segment includes natural gas marketing, propane distribution and propane wholesale marketing operations, which are unregulated as to their rates and services. |
| • | | Other. The “Other” segment consists primarily of the advanced information services operation, unregulated subsidiaries that own real estate leased to Chesapeake and certain corporate costs not allocated to other operations. |
We also reclassified the segment information for 2008 and 2007 to reflect the new segments. During 2009, we also decided not to allocate merger-related transaction costs to different operations for the purpose of reporting their operating profitability because such costs are not directly attributable to their operations. To conform to the current year’s presentation, we revised the 2008 segment information by reclassifying transaction costs, which were previously allocated to all segments, to the “Other” segment.
Page 78 Chesapeake Utilities Corporation 2009 Form 10-K
The Company’sfollowing table presents information about our reportable segments. The table excludes financial data related to its former distributed energy service subsidiary, OnSight, which was reclassified to discontinued operations for 2007.
| | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2009 | | | 2008 | | | 2007 | |
| (in thousands) | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Operating Revenues, Unaffiliated Customers | | | | | | | | | | | | |
| Regulated Energy | | $ | 137,847 | | | $ | 115,544 | | | $ | 128,491 | |
| Unregulated Energy | | | 119,719 | | | | 161,287 | | | | 115,190 | |
| Other | | | 11,219 | | | | 14,612 | | | | 14,606 | |
| | | | | | | | | | |
| Total operating revenues, unaffiliated customers | | $ | 268,785 | | | $ | 291,443 | | | $ | 258,287 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Intersegment Revenues(1) | | | | | | | | | | | | |
| Regulated Energy | | $ | 1,252 | | | $ | 924 | | | $ | 359 | |
| Unregulated Energy | | | 254 | | | | 3 | | | | — | |
| Other | | | 779 | | | | 761 | | | $ | 1,115 | |
| | | | | | | | | | |
| Total intersegment revenues | | $ | 2,285 | | | $ | 1,688 | | | $ | 1,474 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Operating Income | | | | | | | | | | | | |
| Regulated Energy | | $ | 26,900 | | | $ | 24,733 | | | $ | 21,809 | |
| Unregulated Energy | | | 8,158 | | | | 3,781 | | | | 5,174 | |
| Other | | | (1,322 | ) | | | (35 | ) | | | 1,131 | |
| | | | | | | | | | |
| Operating Income | | | 33,736 | | | | 28,479 | | | | 28,114 | |
| | | | | | | | | | | | | |
| Other income | | | 165 | | | | 103 | | | | 291 | |
| Interest charges | | | 7,086 | | | | 6,158 | | | | 6,590 | |
| Income taxes | | | 10,918 | | | | 8,817 | | | | 8,597 | |
| | | | | | | | | | |
| Net income from continuing operations | | $ | 15,897 | | | $ | 13,607 | | | $ | 13,218 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Depreciation and Amortization | | | | | | | | | | | | |
| Regulated Energy | | $ | 8,866 | | | $ | 6,694 | | | $ | 6,918 | |
| Unregulated Energy | | | 2,415 | | | | 2,024 | | | | 1,842 | |
| Other | | | 307 | | | | 287 | | | | 300 | |
| | | | | | | | | | |
| Total depreciation and amortization | | $ | 11,588 | | | $ | 9,005 | | | $ | 9,060 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Capital Expenditures | | | | | | | | | | | | |
| Regulated Energy | | $ | 22,917 | | | $ | 25,386 | | | $ | 23,087 | |
| Unregulated Energy | | | 1,873 | | | | 3,417 | | | | 5,290 | |
| Other | | | 1,504 | | | | 2,041 | | | | 1,765 | |
| | | | | | | | | | |
| Total capital expenditures | | $ | 26,294 | | | $ | 30,844 | | | $ | 30,142 | |
| | | | | | | | | | |
| | |
| (1) | | All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues. |
| | | | | | | | | |
| | | December 31, | | | December 31, | |
| (in thousands) | | 2009 | | | 2008 | |
| | | | | | | | | |
Identifiable Assets | | | | | | | | |
| Regulated Energy | | $ | 480,903 | | | $ | 297,407 | |
| Unregulated Energy | | | 101,437 | | | | 72,955 | |
| Other | | | 34,724 | | | | 15,394 | |
| | | | | | | |
| Total identifiable assets | | $ | 617,064 | | | $ | 385,756 | |
| | | | | | | |
Chesapeake Utilities Corporation 2009 Form 10-K Page 79
Our operations are primarilyalmost entirely domestic. TheOur advanced information services segmentsubsidiary, BravePoint, has infrequent transactions with foreign companies, located primarily in Canada, which are denominated and paid in U.S. dollars. These transactions are immaterial to the consolidated revenues.
D. Supplemental Cash Flow Disclosures
Cash paid for interest and income taxes during the years ended December 31, 2009, 2008, and 2007 were as follows:
D.| | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2009 | | | 2008 | | | 2007 | |
| (in thousands) | | | | | | | | | | | | |
| Cash paid for interest | | $ | 6,703 | | | $ | 5,835 | | | $ | 5,592 | |
| Cash paid for income taxes | | $ | 1,111 | | | $ | 3,885 | | | $ | 7,009 | |
Non-cash investing and financing activities during the years ended December 31, 2009, 2008, and 2007 were as follows:
| | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2009 | | | 2008 | | | 2007 | |
| (in thousands) | | | | | | | | | | | | |
| Capital property and equipment acquired on account, but not paid as of December 31 | | $ | 1,151 | | | $ | 696 | | | $ | 366 | |
| Merger with FPU | | $ | 75,682 | | | $ | — | | | $ | — | |
| Retirement Savings Plan | | $ | 982 | | | $ | 159 | | | $ | 949 | |
| Dividends Reinvestment Plan | | $ | 692 | | | $ | 208 | | | $ | 841 | |
| Conversion of Debentures | | $ | 135 | | | $ | 177 | | | $ | 138 | |
| Performance Incentive Plan | | $ | — | | | $ | 568 | | | $ | 435 | |
| Director Stock Compensation Plan | | $ | 214 | | | $ | 181 | | | $ | 184 | |
| Tax benefit on stock warrants | | $ | — | | | $ | 50 | | | $ | — | |
E. Derivative Instruments
As of December 31, 2009, we had the following outstanding trading contracts which we accounted for as derivatives:
| | | | | | | | | | | | | |
| | | Quantity in | | | Estimated Market | | | Weighted Average | |
| At December 31, 2009 | | gallons | | | Prices | | | Contract Prices | |
Forward Contracts | | | | | | | | | | | | |
| Sale | | | 11,944,800 | | | $ | 0.6900 — $1.3350 | | | $ | 1.1264 | |
| Purchase | | | 11,256,000 | | | $ | 0.7275 — $1.3350 | | | $ | 1.1367 | |
Other Contract | | | | | | | | | | | | |
| Put option | | | 1,260,000 | | | $ | — | | | $ | 0.1500 | |
Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expire in the first quarter of 2010.
Page 80 Chesapeake Utilities Corporation 2009 Form 10-K
The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk-related contingency.
Fair values of the derivative contracts recorded in the Consolidated Balance Sheet as of December 31, 2009 and 2008, are the following:
| | | | | | | | | | | | | |
| | | | | | | Asset Derivatives | |
| | | | | | | Fair Value | |
| (in thousands) | | Balance Sheet Location | | | December 31, 2009 | | | December 31, 2008 | |
Derivatives not designated as fair value hedges: | |
| Forward contracts | | Mark-to-market energy assets | | | $ | 2,379 | | | $ | 4,482 | |
Put option(1) | | Mark-to-market energy assets | | | | — | | | | — | |
| | | | | | | | | | |
| |
| Total asset derivatives | | | | | | $ | 2,379 | | | $ | 4,482 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | Liability Derivatives | |
| | | | | | | Fair Value | |
| (in thousands) | | Balance Sheet Location | | | December 31, 2009 | | | December 31, 2008 | |
| Derivatives designated as fair value hedges: |
Propane swap agreement(2) | | Other current liabilities | | $ | — | | | $ | 105 | |
| | | | | | | | | | | | | |
Derivatives not designated as fair value
hedges: |
| Forward contracts | | Mark-to-market energy liabilities | | | | 2,514 | | | | 3,052 | |
| | | | | | | | | | |
| |
| Total liability derivatives | | | | | | $ | 2,514 | | | $ | 3,157 | |
| | | | | | | | | | |
| | |
| (1) | | We purchased a put option for the Pro-Cap (propane price cap) plan in September 2009. The put option, which expires on March 31, 2010, had a fair value of $0 at December 31, 2009. |
|
| (2) | | Our propane distribution operation entered into a propane swap agreement to protect it from the impact that wholesale propane price increases would have on the Pro-Cap plan that was offered to customers. We terminated this swap agreement in January 2009. |
The effects of gains and losses from derivative instruments on the Consolidated Statement of Income for the years ended December 31, 2009 and 2008, are the following:
| | | | | | | | | | | | | |
| | | Amount of Gain (Loss) on Derivatives: | |
| | | Location of Gain | | For the Years Ended December 31, | |
| (in thousands) | | (Loss) on Derivatives | | 2009 | | | 2008 | |
Derivatives designated as fair value hedges | | | | | | | | | | | | |
Propane swap agreement(1) | | Cost of Sales | | $ | (42 | ) | | $ | 1,476 | |
| |
Derivatives not designated as fair value hedges | | | | | | | | | | | | |
Put Option(2) | | Revenue | | | (41 | ) | | | — | |
| |
Derivatives not designated as fair value hedges | | | | | | | | | | | | |
| Unrealized gains (losses) on forward contracts | | Revenue | | | (1,565 | ) | | | 1,357 | |
| | | | | | | | | | |
| |
| Total | | | | | | $ | (1,648 | ) | | $ | 2,833 | |
| | | | | | | | | | |
| | |
| (1) | | Our propane distribution operation entered into a propane swap agreement to protect it from the impact that wholesale propane price increases would have on the Pro-Cap (propane price cap) Plan that was offered to customers. We terminated this swap agreement in January 2009. |
|
| (2) | | We purchased a put option for the Pro-Cap plan in September 2009. The put option, which expires on March 31, 2010, had a fair value of $0 at December 31, 2009. |
Chesapeake Utilities Corporation 2009 Form 10-K Page 81
The effects of trading activities on the Consolidated Statement of Income for the years ended December 31, 2009 and 2008, are the following:
| | | | | | | | | | | | | |
| | | Amount of Trading Revenue: | |
| | | Location in the | | | For the Years Ended December 31, | |
| (in thousands) | | Statement of Income | | | 2009 | | | 2008 | |
| Realized gains on forward contracts | | Revenue | | $ | 3,830 | | | $ | 1,935 | |
| Unrealized gains (losses) on forward contracts | | Revenue | | | (1,565 | ) | | | 1,357 | |
| | | | | | | | | | |
| Total | | | | | | $ | 2,265 | | | $ | 3,292 | |
| | | | | | | | | | |
F. 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 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;
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 balance sheetfair value hierarchy used at December 31, 2009:
| | | | | | | | | | | | | | | | | |
| | | | | | | 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 | | $ | 1,959 | | | $ | 1,959 | | | $ | — | | | $ | — | |
| Mark-to-market energy assets, including put option | | $ | 2,379 | | | $ | — | | | $ | 2,379 | | | $ | — | |
| | | | | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | | | | |
| Mark-to-market energy liabilities | | $ | 2,514 | | | $ | — | | | $ | 2,514 | | | $ | — | |
Page 82 Chesapeake Utilities Corporation 2009 Form 10-K
The following table summarizes our financial assets and liabilities that are consideredmeasured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy used at December 31, 2008:
| | | | | | | | | | | | | | | | | |
| | | | | | | 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 | | $ | 1,601 | | | $ | 1,601 | | | $ | — | | | $ | — | |
| Mark-to market energy assets | | $ | 4,482 | | | $ | — | | | $ | 4,482 | | | $ | — | |
| | | | | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | | | | |
| Mark-to market energy liabilities | | $ | 3,052 | | | $ | — | | | $ | 3,052 | | | $ | — | |
| Propane swap agreement | | $ | 105 | | | $ | — | | | $ | 105 | | | $ | — | |
The following valuation techniques were used to be financial instruments, because they are cash or are to be settledmeasure fair value assets in cash.the table above on a recurring basis as of December 31, 2009 and 2008:
Level 1 Fair Value Measurements:
Investments— The carryingfair values of these items generally approximate theirtrading securities are recorded at fair value (see Note E to the Consolidated Financial Statements for disclosure of fair value of investments). The Company’s open forward and futures contracts at December 31, 2007 had a gain of $179,000 and at December 31, 2006 had a gain in fair value of $8,500, based on unadjusted quoted prices in active markets for identical securities.
Level 2 Fair Value Measurements:
Mark-to-market energy assets and liabilities —These forward contracts are valued using market rates attransactions in either the respective dates. listed or OTC markets.
Propane price swap agreement and put option —The fair value of the Company’spropane price swap agreement and put option is valued using market transactions for similar assets and liabilities in either the listed or OTC markets.
At December 31, 2009, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.
Other Financial Assets and Liabilities
Financial assets with carrying values approximating fair value include cash and cash equivalents and accounts receivable. Financial liabilities with carrying values approximating fair value include accounts payable and other accrued liabilities and short-term debt. The carrying value of these financial assets and liabilities approximates fair value due to their short maturities and because interest rates approximate current market rates for short-term debt.
At December 31, 2009, long-term debt, is estimatedwhich includes the current maturities of long-term debt, had a carrying value of $134.1 million, compared to a fair value of $145.5 million, using a discounted cash flow methodology. The Company’s long-term debt at December 31, 2007, including current maturities, had an estimated fair value of $75.0 million as compared tomethodology that incorporates a carrying value of $70.9 million. At December 31, 2006, the estimated fair value was approximately $81.4 million as compared to a carrying value of $78.7 million. These estimates aremarket interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities.maturities, with adjustments for duration, optionality, and risk profile. At December 31, 2008, the estimated fair value was approximately $92.3 million, compared to a carrying value of $93.1 million.
E.G. Investments
The investment balances at December 31, 20072009 and 20062008 represent a Rabbi Trust associated with the Company’sour Supplemental Executive Retirement Savings Plan. In accordancePlan and a Rabbi Trust related to a stay bonus agreement with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” the Company classifiesa former executive. We classify these investments as trading securities. As a result of classifyingsecurities and report them as trading securities, the Company is required to report the securities at their fair value, with anyvalue. Any unrealized gains and losses, net of other expenses, are included in other income in the consolidated statements of income. The CompanyWe also hashave an associated liability that is recorded and adjusted each month for the gains and losses incurred by the Trust.Rabbi Trusts. At December 31, 20072009 and 2006,2008, total investments had a fair value of $1.9$2.0 million and $2.0$1.6 million, respectively.
Chesapeake Utilities Corporation 2009 Form 10-K Page 83
F.H. Goodwill and Other Intangible Assets
In accordanceOn October 28, 2009, we completed the merger with SFAS No. 142, goodwill is tested for impairment at least annually. In addition, goodwill of a reporting unit is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. The propane unit had $674,000FPU, which resulted in $33.4 million in goodwill, for the two years endedregulated energy segment. The regulated energy segment did not have goodwill prior to the merger. As of December 31, 20072009 and 2006. Testing2008, the unregulated energy segment reported $674,000 in goodwill. No goodwill was recorded in the unregulated energy segment as a result of the merger with FPU. We test for 2007impairment of goodwill at least annually. The impairment testing for 2009 and 2006 has2008 indicated that no impairment of goodwill.
We intend to seek recovery of the purchase premium related to the regulated operations through future rates in Florida. If and when approval is obtained from the Florida PSC to recover all or part of the purchase premium in future rates from customers, we will reclassify that portion of goodwill, for which recovery has occurred.
been authorized, to a regulatory asset.
The carrying value and accumulated amortization of intangible assets subject to amortization for the years ended December 31, 20072009 and 20062008 are as follow:follows:
| | | | | | | | | | | | | | | | | |
| | | December 31, 2009 | | | December 31, 2008 | |
| | | Gross | | | | | | | Gross | | | | |
| | | Carrying | | | Accumulated | | | Carrying | | | Accumulated | |
| (in thousands) | | amount | | | amortization | | | amount | | | amortization | |
| | | | | | | | | | | | | | | | | |
| Favorable propane contracts | | $ | 519 | | | $ | 169 | | | $ | — | | | $ | — | |
| Customer relationships — FPU | | | 3,500 | | | | 49 | | | | — | | | | — | |
| Customer list | | | 115 | | | | 97 | | | | 115 | | | | 90 | |
| Acquisition costs | | | 264 | | | | 132 | | | | 264 | | | | 125 | |
| | | | | | | | | | | | | |
| | | $ | 4,398 | | | $ | 447 | | | $ | 379 | | | $ | 215 | |
| | | | | | | | | | | | | |
| | | December 31, 2007 | | | December 31, 2006 | |
| | | Gross Carrying Amount | | | Accumulated Amortization | | Gross Carrying Amount | | | Accumulated Amortization | |
| Customer lists | | $ | 115,333 | | | $ | 82,269 | | | $ | 115,333 | | | $ | 75,057 | |
| Acquisition costs | | | 263,659 | | | | 118,649 | | | | 263,659 | | | | 112,057 | |
| Total | | $ | 378,992 | | | $ | 200,918 | | | $ | 378,992 | | | $ | 187,114 | |
Amortization expense of intangible assets was $14,000for 2010 to 2014 is: $655,000 for 2010, $305,000 for 2011, $302,000 for 2012, $298,000 for 2013, and $298,000 for 2014.
Page 84 Chesapeake Utilities Corporation 2009 Form 10-K
I. Income Taxes
We file a consolidated federal income tax return. Income tax expense allocated to our subsidiaries is based upon their respective taxable incomes and tax credits. FPU will be included in our 2009 consolidated federal return for the post-merger period. State income tax returns are filed on a separate company basis in most states where we have operations and/or are required to file. FPU will continue to file a separate state income tax return in Florida.
In September 2008, the IRS completed its examination of our 2005 and 2006 consolidated federal returns and issued its Examination Report. As a result of the examination, we reduced our income tax receivable by $27,000 for the tax liability associated with disallowed expense deductions included on the tax returns. We have amended our 2005 and 2006 federal and state corporate income tax returns to reflect the disallowed expense deductions. We are no longer subject to income tax examinations by the Internal Revenue Service for years endedbefore December 31, 20072006. FPU filed a separate federal income tax return for the period prior to the merger and 2006. The estimated annual amortizationis not subject to income tax examinations by the IRS for years before December 31, 2005.
We generated net operating losses in 2008, for federal income tax purposes, which were generated primarily from increased book-to-tax timing differences authorized by the 2008 American Recovery and Reinvestment Act, which allowed bonus depreciation for certain assets. A federal tax net operating loss of intangibles is $14,000 per year$9,049,132 was carried forward to 2009 and fully offset taxable income for eachthe year. As of December 31, 2009, we have a federal tax net operating loss of $202,000 which expires in 2027. As of December 31, 2009, we also had tax net operating losses from various states totaling $2.7 million, almost all of which expire in 2027. We have recorded a deferred tax asset of $305,000 related to these carry-forwards. We have not recorded a valuation allowance to reduce the future benefit of the years 2008 through 2012.
tax net operating losses because we believe they will all be utilized.
Changes in common stock shares issuedThe tables below provide the following: (a) the components of income tax expense; (b) reconciliation between the statutory federal income tax rate and outstanding are shown in the table below:
| For the Years Ended December 31, | | 2007 | | | 2006 | | | 2005 | |
Common Stock shares issued and outstanding (1) | | | | | | | | | |
| Shares issued — beginning of period balance | | | 6,688,084 | | | | 5,883,099 | | | | 5,778,976 | |
Dividend Reinvestment Plan (2) | | | 35,333 | | | | 38,392 | | | | 41,175 | |
| Retirement Savings Plan | | | 29,563 | | | | 29,705 | | | | 21,071 | |
| Conversion of debentures | | | 8,106 | | | | 16,677 | | | | 22,609 | |
| Employee award plan | | | 350 | | | | 350 | | | | - | |
Performance shares and options exercised (3) | | | 15,974 | | | | 29,516 | | | | 19,268 | |
| Public offering | | | - | | | | 690,345 | | | | - | |
Shares issued — end of period balance (4) | | | 6,777,410 | | | | 6,688,084 | | | | 5,883,099 | |
| | | | | | | | | | | | | |
| Treasury shares — beginning of period balance | | | - | | | | (97 | ) | | | (9,418 | ) |
| Purchases | | | - | | | | - | | | | (4,852 | ) |
| Dividend Reinvestment Plan | | | - | | | | - | | | | 2,142 | |
| Retirement Savings Plan | | | - | | | | - | | | | 12,031 | |
| Other issuances | | | - | | | | 97 | | | | - | |
| Treasury Shares — end of period balance | | | - | | | | - | | | | (97 | ) |
| | | | | | | | | | | | | |
| Total Shares Outstanding | | | 6,777,410 | | | | 6,688,084 | | | | 5,883,002 | |
| | | | | | | | | | | | | |
(1) 12,000,000 shares are authorized at a par value of $0.4867 per share. |
(2) Includes shares purchased with reinvested dividends and optional cash payments. |
(3) Includes shares issued for Directors' compensation. |
(4) Includes 57,309, 48,187, and 37,528 shares at December 31, 2007, 2006 and 2005, respectively, held in a Rabbi Trust established by the Company relating to the Deferred Compensation Plan. |
In 2000effective income tax rate; and 2001,(c) the Company entered into agreements with an investment banker to assist in identifying acquisition candidates. Under the agreements, the Company issued warrants to the investment banker to purchase 15,000 sharescomponents of Chesapeake stock in 2000,accumulated deferred income tax assets and liabilities at an exercise price of $18.00 per share and 15,000 in 2001 at an exercise price of $18.25 per share. In August 2006, the investment banker exercised the 30,000 warrants pursuant to the terms of the agreement at $33.3657 per share. At the request of the investment banker, Chesapeake settled the warrants with a cash payment of $435,000, in lieu of issuing shares of the Company’s common stock. At December 31, 20072009 and 2006, 2008.
Chesapeake did not have any stock warrants outstanding.Utilities Corporation 2009 Form 10-K Page 85
| | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2009 | | | 2008 | | | 2007 | |
| (in thousands) | | | | | | | | | | | | |
Current Income Tax Expense | | | | | | | | | | | | |
| Federal | | $ | — | | | $ | (2,551 | ) | | $ | 5,512 | |
| State | | | 878 | | | | — | | | | 1,223 | |
| Investment tax credit adjustments, net | | | (69 | ) | | | (42 | ) | | | (51 | ) |
| | | | | | | | | | |
| Total current income tax expense (benefit) | | | 809 | | | | (2,593 | ) | | | 6,684 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Deferred Income Tax Expense(1) | | | | | | | | | | | | |
| Property, plant and equipment | | | 7,187 | | | | 10,347 | | | | 2,959 | |
| Deferred gas costs | | | (786 | ) | | | 781 | | | | (629 | ) |
| Pensions and other employee benefits | | | (612 | ) | | | (174 | ) | | | (9 | ) |
| Environmental expenditures | | | 7 | | | | 145 | | | | 46 | |
| Net operating loss carryforwards | | | 4,043 | | | | — | | | | — | |
| Merger related costs | | | 967 | | | | — | | | | — | |
| Reserve for insurance deductibles | | | 518 | | | | 462 | | | | 27 | |
| Other | | | (1,215 | ) | | | (151 | ) | | | (492 | ) |
| | | | | | | | | | |
| Total deferred income tax expense (benefit) | | | 10,109 | | | | 11,410 | | | | 1,902 | |
| | | | | | | | | | |
Total Income Tax Expense | | $ | 10,918 | | | $ | 8,817 | | | $ | 8,586 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2009 | | | 2008 | | | 2007 | |
Reconciliation of Effective Income Tax Rates
(in thousands) | | | | | | | | | | | | |
| Continuing Operations | | | | | | | | | | | | |
Federal income tax expense(2) | | $ | 9,171 | | | $ | 7,863 | | | $ | 7,635 | |
| State income taxes, net of federal benefit | | | 1,490 | | | | 1,162 | | | | 1,087 | |
| Merger related costs | | | 299 | | | | — | | | | — | |
| ESOP dividend deduction | | | (213 | ) | | | (205 | ) | | | (199 | ) |
| Other | | | 171 | | | | (3 | ) | | | 74 | |
| | | | | | | | | | |
| Total continuing operations | | | 10,918 | | | | 8,817 | | | | 8,597 | |
| Discontinued operations | | | — | | | | — | | | | (11 | ) |
| | | | | | | | | | |
Total Income Tax Expense | | $ | 10,918 | | | $ | 8,817 | | | $ | 8,586 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Effective income tax rate | | | 40.72 | % | | | 39.32 | % | | | 39.41 | % |
On November 21, 2006, the Company completed a public offering of 600,300 shares of its common stock at a price per share of $30.10. On November 30, 2006, the Company completed the sale of 90,045 additional shares of its common stock, pursuant to the over-allotment option granted to the Underwriters by the Company. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $19.8 million, which were added to the Company’s general funds and used primarily to repay a portion of the Company’s short-term debt under unsecured lines of credit.| | | | | | | | | |
| At December 31, | | 2009 | | | 2008 | |
| (in thousands) | | | | | | | | |
Deferred Income Taxes | | | | | | | | |
Deferred income tax liabilities: | | | | | | | | |
| Property, plant and equipment | | $ | 75,898 | | | $ | 41,248 | |
| Environmental costs | | | — | | | | 395 | |
| Deferred gas costs | | | 689 | | | | — | |
| Other | | | 3,162 | | | | 2,414 | |
| | | | | | | |
| Total deferred income tax liabilities | | | 79,749 | | | | 44,057 | |
| | | | | | | |
| | | | | | | | | |
Deferred income tax assets: | | | | | | | | |
| Pension and other employee benefits | | | 6,406 | | | | 4,679 | |
| Environmental costs | | | 1,802 | | | | — | |
| Self insurance | | | 1,318 | | | | 370 | |
| Storm reserve liability | | | 985 | | | | — | |
| Deferred gas costs | | | — | | | | 364 | |
| Other | | | 3,813 | | | | 2,502 | |
| | | | | | | |
| Total deferred income tax assets | | | 14,324 | | | | 7,915 | |
| | | | | | | |
Net Deferred Income Taxes Per Consolidated Balance Sheet | | $ | 65,425 | | | $ | 36,142 | |
| | | | | | | |
| | |
| (1) | | Includes $985,000, $1,588,000 and $260,000 of deferred state income taxes for the years 2009, 2008 and 2007, respectively. |
| | |
| (2) | | Federal income taxes were recorded at 35% for each year represented. |
Page 86 Chesapeake Utilities Corporation 2009 Form 10-K
The Company’sOur outstanding long-term debt net of current maturities, is as shown below.
| | | | | | | | | |
| | | December 31, | | | December 31, | |
| (in thousands) | | 2009 | | | 2008 | |
| | | | | | | | |
| Secured first mortgage bonds: | | | | | | | | |
| 9.57% bond, due May 1, 2018 | | $ | 8,156 | | | $ | — | |
| 10.03% bond, due May 1, 2018 | | | 4,486 | | | | — | |
| 9.08% bond, due June 1, 2022 | | | 7,950 | | | | — | |
| 6.85% bond, due October 1, 2031 | | | 14,012 | | | | — | |
| 4.90% bond, due November 1, 2031 | | | 13,222 | | | | — | |
| Uncollateralized senior notes: | | | | | | | | |
| 6.91% note, due October 1, 2010 | | | 909 | | | | 1,818 | |
| 6.85% note, due January 1, 2012 | | | 2,000 | | | | 3,000 | |
| 7.83% note, due January 1, 2015 | | | 10,000 | | | | 12,000 | |
| 6.64% note, due October 31, 2017 | | | 21,818 | | | | 24,545 | |
| 5.50% note, due October 12, 2020 | | | 20,000 | | | | 20,000 | |
| 5.93% note, due October 31, 2023 | | | 30,000 | | | | 30,000 | |
| Convertible debentures: | | | | | | | | |
| 8.25% due March 1, 2014 | | | 1,520 | | | | 1,655 | |
| Promissory note | | | 40 | | | | 60 | |
| | | | | | | |
| Total long-term debt | | | 134,113 | | | | 93,078 | |
| Less: current maturities | | | (35,299 | ) | | | (6,656 | ) |
| | | | | | | |
| Total long-term debt, net of current maturities | | $ | 98,814 | | | $ | 86,422 | |
| | | | | | | |
| At December 31, | 2007 | 2006 |
| Uncollateralized senior notes: | | |
| 7.97% note, due February 1, 2008 | $0 | $1,000,000 |
| 6.91% note, due October 1, 2010 | 1,818,182 | 2,727,273 |
| 6.85% note, due January 1, 2012 | 3,000,000 | 4,000,000 |
| 7.83% note, due January 1, 2015 | 12,000,000 | 14,000,000 |
| 6.64% note, due October 31, 2017 | 24,545,454 | 27,272,727 |
| 5.50% note, due October 12, 2020 | 20,000,000 | 20,000,000 |
| Convertible debentures: | | |
| 8.25% due March 1, 2014 | 1,832,000 | 1,970,000 |
| Promissory note | 60,000 | 80,000 |
| Total Long-Term Debt | $63,255,636 | $71,050,000 |
| | | | | |
| Annual maturities of consolidated long-term debt for the next five years are as follows: $7,656,364 for 2008; |
| $6,656,364 for 2009,$6,656,364 for 2010, $7,747,273 for 2011, $6,727,273 for 2012. |
Secured First Mortgage Bonds
In October 2009, we became subject to the obligations of FPU’s secured first mortgage bonds in connection with the merger. FPU’s secured first mortgage bonds had a carrying value of $47.8 million ($49.3 million in outstanding principal balance). The first mortgage bonds are secured by a lien covering all of FPU’s property. The 9.57 percent bond and 10.03 percent bond require annual sinking fund payments of $909,000 and $500,000, respectively.
In January 2010, we redeemed the 6.85 percent and 4.90 percent series of FPU’s secured first mortgage bonds prior to their respective maturity for $28.7 million, which represented the outstanding principal balance of those bonds. We used short-term borrowing to finance the redemption of these bonds. The difference between the carrying value of those bonds and the amount paid at redemption totaling $1.5 million was deferred as a regulatory asset.
Uncollateralized Senior Notes
On October 31, 2008, we issued $30 million of 5.93 percent uncollateralized senior notes to two institutional investors. The terms of the senior notes require a semi-annual principal repayment of $1.5 million in April and October of each year, commencing on April 30, 2014. The senior notes will mature on October 31, 2023. The proceeds of the sale of the Senior Notes were used to refinance capital expenditures and for general corporate purposes.
Chesapeake Utilities Corporation 2009 Form 10-K Page 87
Convertible Debentures
The convertible debentures may be converted, at the option of the holder, into shares of the Company’sour common stock at a conversion price of $17.01 per share. During 20072009 and 2006,2008, debentures totaling $138,000$135,000 and $284,000,$177,000, respectively, were converted to stock. The debentures are also redeemable for cash at the option of the holder, subject to an annual non-cumulative maximum limitation of $200,000. In 20072009 and 2006,2008, no debentures were redeemed for cash. During 2005, debentures totaling $5,000 were redeemed for cash. At the Company’s option, the debentures may be redeemed at stated amounts.
On October 12, 2006, the Company issued $20 million of 5.5 percent Senior Notes to three institutional investors (The Prudential Insurance Company of America, Prudential Retirement Insurance and Annuity Company and United Omaha Life Insurance Company). The original note agreement was executed on October 18, 2005 and provided for the Company to sell the Notes at any time prior to January 15, 2007. The terms of the Notes require annual principal repayments of $2 million beginning on the fifth anniversary of the issuance of the Notes. The Notes will mature on October 12, 2020. The proceeds from this issuance were used to reduce a portion of the Company’s outstanding short-term debt.
Debt Covenants
Indentures to theour long-term debt of the Company and its subsidiaries contain various restrictions. The most stringent restrictions state that the Companywe must maintain equity of at least 40 percent of total capitalization, and the pro-forma fixed charge coverage ratio must be 1.5at least 1.2 times. TheIn connection with the merger, the uncollateralized senior notes were amended to include an additional covenant requiring the Company isto maintain no more than a 20-percent ratio of secured and subsidiary long-term debt to consolidated tangible net worth by October 2011. Failure to comply with those covenants could result in accelerated due dates and/or termination of the uncollateralized senior note agreements. As of December 31, 2009, we are in compliance with all of itsour debt covenants.covenants and with the redemption of FPU’s 6.85 percent and 4.90 percent secured first mortgage bonds in January 2010, the additional covenant requiring us to maintain no more than a 20-percent ratio of secured and subsidiary long-term debt to consolidated tangible net worth has been met.
I. Short-term Borrowing
Each of Chesapeake’s uncollateralized senior notes contains a “Restricted Payments” covenant as defined in the note agreements. The Boardmost restrictive covenants of Directors has authorizedthis type are included within the 7.83 percent senior notes, due January 1, 2015. The covenant provides that we cannot pay or declare any dividends or make any other Restricted Payments (such as dividends) in excess of the sum of $10.0 million, plus consolidated net income of the Company to borrow up to $55.0 million of short-term debt, as required, from various banksaccrued on and trust companies under short-term lines of credit.after January 1, 2001. As of December 31, 2007,2009, the cumulative consolidated net income base was $102.8 million, offset by Restricted Payments of $63.8 million, leaving $39.0 million of cumulative net income free of restrictions.
Each series of FPU’s first mortgage bonds contains a similar restriction that limits the payment of dividends by FPU. The most restrictive covenants of this type are included within the series that is due in 2031, which provided that FPU cannot make dividend or other restricted payments in excess of the sum of $2.5 million plus FPU’s consolidated net income accrued on and after January 1, 2001. As of December 31, 2009, FPU had the cumulative net income base of $32.7 million, offset by restricted payments of $22.1 million, leaving $10.6 million of cumulative net income of FPU free of restrictions based on this covenant. In January 2010, this series of first mortgage bonds were redeemed prior to their maturities. The second most restrictive covenant of this type is included in the series that is due in 2022, which provided that FPU cannot make dividend or other restricted payments in excess of the sum of $2.5 million plus FPU’s consolidated net income accrued on and after January 1, 1992. This covenant provides FPU with the cumulative net income base of $56.0 million, offset by restricted payments of $37.6 million, leaving $18.4 million of cumulative net income of FPU free of restrictions as of December 31, 2009.
K. Short-term Borrowing
At December 31, 2009 and 2008, the Company had $30.0 million and $33.0 million, respectively, of short-term borrowing outstanding under our bank credit facilities. The annual weighted average interest rates on its short-term borrowing were 1.28 percent and 2.79 percent for 2009 and 2008, respectively. We incurred commitment fees of $79,000 and $16,000 in 2009 and 2008, respectively.
In October 2009 in connection with the FPU merger, we became subject to $4.2 million in outstanding borrowings under FPU’s revolving line of credit. All of the outstanding borrowings were repaid in full in November 2009 and FPU’s revolving line of credit was terminated on November 23, 2009.
Page 88 Chesapeake Utilities Corporation 2009 Form 10-K
As of December 31, 2009, we had fivefour unsecured bank lines of credit with threetwo financial institutions, totaling $90.0 million, none of which requires compensating balances. The unsecured bank lines of credit were increased to $100.0 million in January 2010. These bank lines are available to provide funds for the Company’sour short-term cash needs to meet seasonal working capital requirements and to temporarily fund temporarily portions of itsour capital expenditures. ThreeWe are currently authorized by our Board of the bankDirectors to borrow up to $85.0 million of short-term debt, as required, from these short-term lines totaling $25.0 million, are committed.of credit. We maintain both committed and uncommitted credit facilities. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks. The outstanding balance
Committed credit facilities
As of short-term borrowing at December 31, 20072009 we had two committed revolving credit facilities totaling $55.0 million, which were subsequently increased to $60.0 million in January 2010. The first facility is an unsecured $30.0 million revolving line of credit that bears interest at the respective LIBOR rate, plus 1.25 percent per annum. At December 31, 2009, there was $7.5 million available under this credit facility.
The second facility is a $25.0 million committed revolving line of credit that bears interest at a base rate plus 1.25 percent, if requested and 2006advanced on the same day, or LIBOR for the applicable period plus 1.25 percent if requested three days prior to the advance date. At December 31, 2009, there was $45.7$18.3 million available under this credit facility. In January 2010, the second facility was increased to a $30.0 million committed revolving line of credit with the same terms, resulting in total committed revolving credit facilities of $60.0 million.
The availability of funds under our credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and $27.6 million, respectively. The annual weighted average interest rates on short-term debt were 5.46 percentthe continued accuracy of representations and 5.47 percent for 2007 and 2006, respectively.
warranties contained in these agreements. The Company alsois required by the financial covenants in our revolving credit facilities to maintain, at the end of each fiscal year:
a funded indebtedness ratio of no greater than 65 percent; and
a fixed charge coverage ratio of at least 1.20 to 1.0.
We are in compliance with all of our debt covenants.
Uncommitted credit facilities
As of December 31, 2009, we had two uncommitted lines of credit facilities totaling $35.0 million, which were subsequently increased to $40.0 million in January 2010. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks.
The first facility is an uncommitted $20.0 million line of credit that bears interest at a rate per annum as offered by the bank for the applicable period. At December 31, 2009, the entire borrowing capacity of $20.0 million was available under this credit facility.
The second facility is a $15.0 million uncommitted line of credit that bears interest at a rate per annum as offered by the bank for the applicable period. At December 31, 2009, there was $14.3 million available under this credit facility, which was reduced by $725,000 for a letter of credit outstanding with itsissued to our primary insurance company in the amountcompany. The letter of $775,000credit is provided as security to satisfy the deductibles under the Company’sour various insurance policies. This letter of credit reduced the amounts available under the lines of creditpolicies and is scheduled to expireexpires on MayAugust 31, 2008. The Company does2010. We do not anticipate that this letter of credit will be drawn upon by the counterparty,counter-party and the Company expectswe expect that it will be renewed as necessary.
In January 2010, the second facility was increased to a $20.0 million uncommitted line of credit with the same terms, resulting in total uncommitted revolving credit facilities of $40.0 million.
J.L. Lease Obligations
The Company hasWe have entered into several operating lease arrangements for office space, at various locations, equipment and pipeline facilities. Rent expense related to these leases was $997,000, $880,000 and $736,000 $680,000,for 2009, 2008 and $837,000 for 2007, 2006, and 2005, respectively. Future minimum payments under the Company’sour current lease agreements are $791,000, $668,000, $544,000, $531,000$866,000, $771,000, $677,000, $502,000 and $636,000$364,000 for the years 20082010 through 2012,2014, respectively; and $2.3$2.0 million thereafter, with an aggregate total of $5.4$5.2 million.
Chesapeake Utilities Corporation 2009 Form 10-K Page 89
K.M. Employee Benefit Plans
Retirement Plans
Before 1999, Company employees generally participated in bothWe sponsor a defined benefit pension plan (“DefinedChesapeake Pension Plan”), an unfunded pension supplemental executive retirement plan (“Chesapeake SERP”), and an unfunded postretirement health care and life insurance plan (“Chesapeake Postretirement Plan”). As a result of the merger with FPU, we now sponsor and maintain a separate defined benefit pension plan for FPU (“FPU Pension Plan”) and a Retirement Savings Plan. Effective January 1, 1999,separate unfunded postretirement medical plan for FPU (“FPU Medical Plan”).
We measure the Company restructured its retirement program to compete more effectively with similar businesses. As part of this restructuring, the Company closed the Defined Pension Plan to new participants. Employees who participated in the Defined Pension Plan at that time were given the option of remaining in (and continuing to accrue benefits under) the Defined Pension Plan or receiving an enhanced matching contribution in the Retirement Savings Plan.
Because the Defined Pension Plan was not open to new participants, the number of active participants in that plan decreasedassets and is approaching the minimum number needed for the Defined Pension Plan to maintain its tax-qualified status. To avoid jeopardizing the tax-qualified statusobligations of the Defined Pension Plan, the Company’s Board of Directors amended the Defined Pension Plan on September 24, 2004. To ensure that the Company continues to provide appropriate levels of benefits to the Company’s employees, the Board amended the Defined Pension Plan and the Retirement Savings Plan, effective January 1, 2005, so that Defined Pension Plan participants who were actively employed by the Company on that date: (1) receive two additional years of benefit service credit to be used in calculating their Defined Pension Plan benefit (subject to the Defined Pension Plan’s limit of 35 years of benefit service credit), (2) have the option to receive their Defined Pension Plan benefit in the form of a lump sum at the time they retire, and (3) are eligible to receive the enhanced matching contribution in the Retirement Savings Plan. In addition, effective January 1, 2005, the Board amended the Defined Pension Plan so that participants will not accrue any additional benefits under that plan. These changes were communicated to the Company’s employees during the first week of November 2004.
In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS 158). The Company adopted SFAS 158 prospectively on December 31, 2006. SFAS 158 requires that we recognize all obligations related to defined benefit pensionspension plans and other postretirement benefits. This statement requires that we quantifybenefits plans to determine the plans’ funded status as of the end of the year as an asset or a liability on our consolidated balance sheets.
SFAS 158 requires that we measure the plans’ assets and obligations that determine our funded status as of the end of the fiscal year. The Company is also required to We recognize as a component of accumulated other comprehensive income (“AOCI”)income/loss the changes in funded status that occurred during the year but that are not recognized as part of net periodic benefit cost,costs, except for the portion related to FPU’s regulated energy operations, which is deferred as explaineda regulatory asset to be recovered in SFAS No. 87, “Employers’ Accounting for Pensions,” or SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.”
Atthe future pursuant to a previous order by the Florida PSC. The measurement dates were December 31, 2007, the funded status of the Company’s Defined Pension Plan was a liability of $274,739; at December 31, 2006 it was an asset of $590,560. In order to account for the liability2009 and decrease in the funded status in accordance with FAS 158, the Company took a charge of $568,316, net of tax, to Comprehensive Income. In addition, the funded status of the postretirement health and life insurance plan was a liability of $1.756 million at December 31, 2007 compared to $1.763 million at December 31, 2006. To adjust for the reduced liability for the postretirement health and life insurance plan, as required by FAS 158, the Company recorded income of $23,086, net of tax, to Comprehensive Income.2008.
The amounts in AOCIaccumulated other comprehensive income/loss for the respective retirementour pension and postretirement benefits plans that are expected to be recognized as a component of net benefit cost in 20082010 are set forth in the following table.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Chesapeake | | | FPU | | | | | | | Chesapeake | | | FPU | | | | |
| | | Pension | | | Pension | | | Chesapeake | | | Postretirement | | | Medical | | | | |
| (in thousands) | | Plan | | | Plan | | | SERP | | | Plan | | | Plan | | | Total | |
| Prior service cost (credit) | | $ | (5 | ) | | $ | — | | | $ | 19 | | | $ | — | | | $ | — | | | $ | 14 | |
| Net (gain) loss | | $ | (137 | ) | | $ | — | | | $ | 47 | | | $ | 71 | | | $ | — | | | $ | (19 | ) |
The following table presents the amounts not yet reflected in net periodic benefit cost and included in accumulated other comprehensive income/loss as of December 31, 2009.
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Defined | Executive Excess | Other | | | Chesapeake | | FPU | | Chesapeake | | FPU | | | |
| | Benefit | Defined Benefit | Postretirement | | | Pension | | Pension | | Chesapeake | | Postretirement | | Medical | | | |
| (in thousands) | | | Plan | | Plan | | SERP | | Plan | | Plan | | Total | |
| Prior service cost (credit) | | | $ | (15 | ) | | $ | — | | $ | 102 | | $ | — | | $ | — | | $ | 87 | |
| Net loss (gain) | | | 2,672 | | | (540 | ) | | 673 | | 1,351 | | | (14 | ) | | 4,142 | |
| | Pension | Benefit | | | | | | | | | | | | | | |
| Prior service cost (credit) | $(4,699) | - | - | | |
| Loss (gain) | - | $46,444 | $130,973 | | |
| Subtotal | | | 2,657 | | | (540 | ) | | 775 | | 1,351 | | | (14 | ) | | 4,229 | |
| Tax expense (benefit) | | | | (1,065 | ) | | 208 | | | (311 | ) | | | (542 | ) | | 5 | | | (1,705 | ) |
| | | | | | | | | | | | | | | |
| Accumulated other comprehensive (income) loss | | | $ | 1,592 | | $ | (332 | ) | | $ | 464 | | $ | 809 | | $ | (9 | ) | | $ | 2,524 | |
| | | | | | | | | | | | | | | |
Defined Benefit Pension PlanPlans
As described above,The Chesapeake Pension Plan was closed to new participants effective January 1, 2005, the Defined Pension Plan1999 and was frozen with respect to additional years of service or additional compensation.compensation effective January 1, 2005. Benefits under the planChesapeake Pension Plan were based on each participant’s years of service and highest average compensation, prior to the freeze. freezing of the plan.
The Company’sFPU Pension Plan covers eligible FPU non-union employees hired before January 1, 2005 and union employees hired before the respective union contract expiration dates in 2005 and 2006. Prior to the merger, the FPU Pension Plan was frozen with respect to additional years of service and additional compensation effective December 31, 2009.
Our funding policy provides that payments to the trustee of each plan shall be equal to the minimum funding requirements of the Employee Retirement Income Security Act of 1974. The Company doesWe were not expect to be required to make any funding payments to the DefinedChesapeake Pension Plan in 2008. The measurement dates for2009 or to the FPU Pension Plan were December 31, 2007 and 2006.subsequent to the merger closing in October 2009.
Page 90 Chesapeake Utilities Corporation 2009 Form 10-K
The following schedule summarizes the assets of the DefinedChesapeake Pension Plan, by investment type, at December 31, 2009, 2008 and 2007 2006 and 2005:the assets of the FPU Pension Plan, by investment type, at December 31, 2009:
| At December 31, | | 2007 | | | 2006 | | | 2005 | |
| Asset Category | | | | | | | | | |
| Equity securities | | 49.03 | % | | 77.34 | % | | 76.12 | % |
| Debt securities | | 50.26 | % | | 18.59 | % | | 23.28 | % |
| Other | | 0.71 | % | | 4.07 | % | | 0.60 | % |
| Total | | 100.00 | % | | 100.00 | % | | 100.00 | % |
| | | | | | | | | | | | | | | | | |
| | | Chesapeake | | | FPU | |
| | | Pension Plan | | | Pension Plan | |
| At December 31, | | 2009 | | | 2008 | | | 2007 | | | 2009 | |
Asset Category | | | | | | | | | | | | | | | | |
| Equity securities | | | 66.22 | % | | | 48.70 | % | | | 49.03 | % | | | 63.00 | % |
| Debt securities | | | 33.76 | % | | | 51.24 | % | | | 50.26 | % | | | 29.00 | % |
| Other | | | 0.02 | % | | | 0.06 | % | | | 0.71 | % | | | 8.00 | % |
| | | | | | | | | | | | | |
| Total | | | 100.00 | % | | | 100.00 | % | | | 100.00 | % | | | 100.00 | % |
| | | | | | | | | | | | | |
The asset listed as “Other” in the above table represents monies temporarily held in money market funds. The money market fund investsfunds, which invest at least 80 percent of itstheir total assets in:
United States government obligations; and
· | United States Government obligations; and |
Repurchase agreements that are fully collateralized by such obligations.
· | Repurchase agreements that are fully collateralized by such obligations. |
All of the assets held by the Chesapeake Pension Plan and FPU Pension Plan are classified under Level 1 of the fair value hierarchy and are recorded at fair value based on unadjusted quoted prices in active markets for identical securities.
The investment policy offor the Chesapeake Pension Plan calls for an allocation of assets between equity and debt instruments, with equity being 60 percent and debt at 40 percent, but allowing for a variance of 20 percent in either direction. In addition, as changes are made to holdings, cash, money market funds or United States Treasury Bills may be held temporarily by the fund. Investments in the following are prohibited: options, guaranteed investment contracts, real estate, venture capital, private placements, futures, commodities, limited partnerships and Chesapeake stock; short selling and margin transactions are prohibited as well. Investment allocation decisions are made by the Employee Benefits committee. During 2004, Chesapeake modified its investment policy to allow the Employee Benefits Committee to reallocate investments to better match the expected life of the plan.
The investment policy for the FPU Pension Plan is designed to achieve a long-term rate of return, including investment income and appreciation, sufficient to meet the actuarial requirements of the plan. The plan’s investment strategy is to achieve its return objectives by investing in a diversified portfolio of equity, fixed income and cash securities seeking a balance of growth and stability as well as an adequate level of liquidity for pension distributions as they fall due. Plan assets are constrained such that no more than 10 percent of the portfolio will be invested in any one issue. Investment allocation decisions for the FPU Pension Plan are made by the Pension Committee.
-Chesapeake Utilities Corporation 2009 Form 10-K Page 48 - -91
The following schedule sets forth the funded status of the Defined Pension Plan at December 31, 2007, 20062009 and 2005:2008:
| | | | | | | | | | | | | |
| | | Chesapeake | | | FPU | |
| | | Pension Plan | | | Pension Plan | |
| At December 31, | | 2009 | | | 2008 | | | 2009 | |
| (in thousands) | | | | | | | | | | | | |
Change in benefit obligation: | | | | | | | | | | | | |
Benefit obligation — beginning of year(1) | | $ | 11,593 | | | $ | 11,074 | | | $ | 46,851 | |
| Interest cost | | | 547 | | | | 594 | | | | 418 | |
| Change in assumptions | | | (188 | ) | | | 268 | | | | — | |
| Actuarial loss | | | (307 | ) | | | 84 | | | | (1,544 | ) |
| Benefits paid | | | (518 | ) | | | (427 | ) | | | (305 | ) |
| | | | | | | | | | |
| Benefit obligation — end of year | | | 11,127 | | | | 11,593 | | | | 45,420 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Change in plan assets: | | | | | | | | | | | | |
Fair value of plan assets — beginning of year(1) | | | 6,689 | | | | 10,799 | | | | 35,037 | |
| Actual return on plan assets | | | 1,278 | | | | (3,683 | ) | | | 1,695 | |
| Benefits paid | | | (518 | ) | | | (427 | ) | | | (305 | ) |
| | | | | | | | | | |
| Fair value of plan assets — end of year | | | 7,449 | | | | 6,689 | | | | 36,427 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Reconciliation: | | | | | | | | | | | | |
| Funded status | | | (3,678 | ) | | | (4,904 | ) | | | (8,993 | ) |
| | | | | | | | | | |
Accrued pension cost | | $ | (3,678 | ) | | $ | (4,904 | ) | | $ | (8,993 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Assumptions: | | | | | | | | | | | | |
| Discount rate | | | 5.25 | % | | | 5.25 | % | | | 5.75 | % |
| Expected return on plan assets | | | 6.00 | % | | | 6.00 | % | | | 7.00 | % |
| At December 31, | | 2007 | | | 2006 | | | 2005 | |
| Change in benefit obligation: | | | | | | | | | |
| Benefit obligation — beginning of year | | $ | 11,449,725 | | | $ | 12,399,621 | | | $ | 12,053,063 | |
| Interest cost | | | 622,057 | | | | 635,877 | | | | 645,740 | |
| Change in assumptions | | | - | | | | (301,851 | ) | | | 388,979 | |
| Actuarial loss | | | 282,684 | | | | 607 | | | | 28,895 | |
| Benefits paid | | | (1,280,946 | ) | | | (1,284,529 | ) | | | (717,056 | ) |
| Benefit obligation — end of year | | | 11,073,520 | | | | 11,449,725 | | | | 12,399,621 | |
| | | | | | | | | | | | | |
| Change in plan assets: | | | | | | | | | | | | |
| Fair value of plan assets — beginning of year | | | 12,040,287 | | | | 11,780,866 | | | | 12,097,248 | |
| Actual return on plan assets | | | 39,440 | | | | 1,543,950 | | | | 400,674 | |
| Benefits paid | | | (1,280,946 | ) | | | (1,284,529 | ) | | | (717,056 | ) |
| Fair value of plan assets — end of year | | | 10,798,781 | | | | 12,040,287 | | | | 11,780,866 | |
| | | | | | | | | | | | | |
Reconciliation of funded status: (1) | | | | | | | | | | | | |
| Plan assets in excess (less than) benefit obligation at year-end | | | (274,739 | ) | | | 590,560 | | | | (618,755 | ) |
| Unrecognized prior service cost | | | - | | | | - | | | | (34,259 | ) |
| Unrecognized net actuarial gain | | | - | | | | - | | | | (129,739 | ) |
| Net amount accrued | | $ | (274,739 | ) | | $ | 590,560 | | | $ | (782,753 | ) |
| | | | | | | | | | | | | |
| Assumptions: | | | | | | | | | | | | |
| Discount rate | | | 5.50 | % | | | 5.50 | % | | | 5.25 | % |
| Expected return on plan assets | | | 6.00 | % | | | 6.00 | % | | | 6.00 | % |
| | | | | | | | | | | | | |
| (1) After the adoption of SFAS 158 on December 31, 2006, these amounts are recorded and this reconciliation is no longer required. | |
The Company reviewed the assumptions used for the discount rate to calculate the benefit obligation of the plan and has elected to maintain the rate at 5.50 percent, reflecting relatively no change in the interest rates of high quality bonds and reflecting the expected life of the plan, in light of the lump sum payment option. In addition, the average expected return on plan assets for the Defined Pension Plan remained constant at six percent due to the adoption of a change in the investment policy that allows for a higher level of investment in bonds and a lower level of equity investments. Since the Plan is frozen in regard additional years of service and compensation, the rate of assumed compensation rate increases is not applicable. The accumulated benefit obligation was $11.1 million and $11.4 million at December 31, 2007 and 2006, respectively.
| | |
| (1) | | FPU Pension Plan’s beginning balance reflects the benefit obligations as of the merger date of October 28, 2009. |
Net periodic pension benefitcost (benefit) for the Defined Pension Planplans for 2007, 2006,2009, 2008, and 20052007 include the components as shown below:
| | | | | | | | | | | | | | | | | |
| | | Chesapeake | | | FPU | |
| | Pension Plan | | | Pension Plan(1) | |
| For the Years Ended December 31, | | 2009 | | | 2008 | | | 2007 | | | 2009 | |
| (in thousands) | | | | | | | | | | | | |
Components of net periodic pension cost (benefit): | | | | | | | | | | | | | | | | |
| Interest cost | | $ | 547 | | | $ | 594 | | | $ | 622 | | | $ | 418 | |
| Expected return on assets | | | (362 | ) | | | (629 | ) | | | (696 | ) | | | (396 | ) |
| Amortization of prior service cost | | | (5 | ) | | | (5 | ) | | | (5 | ) | | | — | |
| Amortization of actuarial loss/gain | | | 237 | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | |
Net periodic pension cost (benefit) | | $ | 417 | | | $ | (40 | ) | | $ | (79 | ) | | $ | 22 | |
| | | | | | | | | | | | | |
| |
Assumptions: | | | | | | | | | | | | | | | | |
| Discount rate | | | 5.25 | % | | | 5.50 | % | | | 5.50 | % | | | 5.50 | % |
| Expected return on plan assets | | | 6.00 | % | | | 6.00 | % | | | 6.00 | % | | | 7.00 | % |
| | |
| (1) | | FPU Pension Plan’s net periodic pension cost includes only the cost from the merger closing (October 28, 2009) through December 31, 2009. |
Page 92 Chesapeake Utilities Corporation 2009 Form 10-K
| For the Years Ended December 31, | 2007 | 2006 | 2005 |
| Components of net periodic pension cost: | | | |
| Interest cost | $622,057 | $635,877 | $645,740 |
| Expected return on assets | (696,398) | (690,533) | (703,285) |
| Amortization of: | | | |
| Prior service cost | (4,699) | (4,699) | (4,699) |
| Net periodic pension benefit | ($79,040) | ($59,355) | ($62,244) |
| | | | |
| Assumptions: | | | |
| Discount rate | 5.50% | 5.25% | 5.50% |
| Expected return on plan assets | 6.00% | 6.00% | 6.00% |
Pension Supplemental Executive Excess Defined Benefit PensionRetirement Plan
The Company also provides an unfunded executive excess defined benefit pension plan (“Pension SERP”). As noted above, this planChesapeake SERP was frozen with respect to additional years of service and additional compensation as of December 31, 2004. Benefits under the planChesapeake SERP were based on each participant’s years of service and highest average compensation, prior to the freeze.freezing of the plan. The accumulated benefit obligation for the Chesapeake SERP, which is unfunded, was $2.32 million and $2.29$2.5 million at both December 31, 2009 and 2008.
| | | | | | | | | |
| At December 31, | | 2009 | | | 2008 | |
| (In thousands) | | | | | | | | |
Change in benefit obligation: | | | | | | | | |
| Benefit obligation — beginning of year | | $ | 2,520 | | | $ | 2,326 | |
| Interest cost | | | 129 | | | | 125 | |
| Actuarial (gain) loss | | | (55 | ) | | | 39 | |
| Amendments | | | — | | | | 119 | |
| Benefits paid | | | (89 | ) | | | (89 | ) |
| | | | | | | |
| Benefit obligation — end of year | | | 2,505 | | | | 2,520 | |
| | | | | | | |
| | | | | | | | | |
Change in plan assets: | | | | | | | | |
| Fair value of plan assets — beginning of year | | | — | | | | — | |
| Employer contributions | | | 89 | | | | 89 | |
| Benefits paid | | | (89 | ) | | | (89 | ) |
| | | | | | | |
| Fair value of plan assets — end of year | | | — | | | | — | |
| | | | | | | |
| | | | | | | | | |
Reconciliation: | | | | | | | | |
| Funded status | | | (2,505 | ) | | | (2,520 | ) |
| | | | | | | |
Accrued pension cost | | $ | (2,505 | ) | | $ | (2,520 | ) |
| | | | | | | |
| | | | | | | | | |
Assumptions: | | | | | | | | |
| Discount rate | | | 5.25 | % | | | 5.25 | % |
Net periodic pension costs for the Chesapeake SERP for 2009, 2008, and 2007 and 2006, respectively.include the components shown below:
| | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2009 | | | 2008 | | | 2007 | |
| (in thousands) | | | | | | | | | | | | |
Components of net periodic pension cost: | | | | | | | | | | | | |
| Interest cost | | $ | 130 | | | $ | 125 | | | $ | 123 | |
| Amortization of prior service cost | | | 18 | | | | — | | | | — | |
| Amortization of actuarial loss | | | 54 | | | | 45 | | | | 52 | |
| | | | | | | | | | |
Net periodic pension cost | | $ | 202 | | | $ | 170 | | | $ | 175 | |
| | | | | | | | | | |
| |
Assumptions: | | | | | | | | | | | | |
| Discount rate | | | 5.25 | % | | | 5.50 | % | | | 5.50 | % |
Chesapeake Utilities Corporation 2009 Form 10-K Page 93
Other Postretirement Benefits PlansThe following schedule sets forth the status of other postretirement benefit plans:
| | | | | | | | | | | | | |
| | | Chesapeake | | | FPU | |
| | | Postretiment Plan | | | Medical Plan | |
| At December 31, | | 2009 | | | 2008 | | | 2009 | |
| (in thousands) | | | | | | | | | | | | |
Change in benefit obligation: | | | | | | | | | | | | |
Benefit obligation — beginning of year(1) | | $ | 2,179 | | | $ | 1,756 | | | $ | 2,457 | |
| Service cost | | | 3 | | | | 3 | | | | 18 | |
| Interest cost | | | 131 | | | | 114 | | | | 23 | |
| Plan participants contributions | | | 90 | | | | 104 | | | | 6 | |
| Actuarial (gain) loss | | | 378 | | | | 345 | | | | (71 | ) |
| Benefits paid | | | (196 | ) | | | (143 | ) | | | (16 | ) |
| | | | | | | | | | |
| Benefit obligation — end of year | | | 2,585 | | | | 2,179 | | | | 2,417 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Change in plan assets: | | | | | | | | | | | | |
Fair value of plan assets — beginning of year(1) | | | — | | | | — | | | | — | |
Employer contributions(2) | | | 106 | | | | 39 | | | | 10 | |
| Plan participants contributions | | | 90 | | | | 104 | | | | 6 | |
| Benefits paid | | | (196 | ) | | | (143 | ) | | | (16 | ) |
| | | | | | | | | | |
| Fair value of plan assets — end of year | | | — | | | | — | | | | — | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Reconciliation: | | | | | | | | | | | | |
| Funded status | | | (2,585 | ) | | | (2,179 | ) | | | (2,417 | ) |
| | | | | | | | | | |
Accrued pension cost | | $ | (2,585 | ) | | $ | (2,179 | ) | | $ | (2,417 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Assumptions: | | | | | | | | | | | | |
| Discount rate | | | 5.25 | % | | | 5.25 | % | | | 5.75 | % |
| | |
| (1) | | FPU Medical Plan’s beginning balance reflects the benefit obligation as of the merger date of October 28, 2009. |
|
| (2) | | Chesapeake’s Postretirement Plan does not receive a Medicare Part-D subsidy. The FPU Medical Plan did not receive a significant subsidy for the post-merger period. |
Net periodic postretirement costs for 2009, 2008, and 2007 include the Pension SERP:following components:
| | | | | | | | | | | | | | | | | |
| | | Chesapeake | | | FPU | |
| | | Postretirement Plan | | | Medical Plan(1) | |
| For the Years Ended December 31, | | 2009 | | | 2008 | | | 2007 | | | 2009 | |
| (in thousands) | | | | | | | | | | | | | | | | |
Components of net periodic postretirement cost: | | | | | | | | | | | | | | | | |
| Service cost | | $ | 3 | | | $ | 3 | | | $ | 6 | | | $ | 18 | |
| Interest cost | | | 131 | | | | 114 | | | | 102 | | | | 23 | |
| Amortization of: | | | | | | | | | | | | | | | | |
| Actuarial loss | | | 76 | | | | 290 | | | | 166 | | | | — | |
| | | | | | | | | | | | | |
Net periodic postretirement cost | | $ | 210 | | | $ | 407 | | | $ | 274 | | | $ | 41 | |
| | | | | | | | | | | | | |
| | |
| (1) | | FPU Medical Plan’s net periodic postretiment includes only the cost from the merger date (October 28, 2009) through December 31, 2009. |
Page 94 Chesapeake Utilities Corporation 2009 Form 10-K
| At December 31, | | 2007 | | | 2006 | | | 2005 | |
| Change in benefit obligation: | | | | | | | | | |
| Benefit obligation — beginning of year | | $ | 2,286,970 | | | $ | 2,322,471 | | | $ | 2,162,952 | |
| Interest cost | | | 123,361 | | | | 119,588 | | | | 119,658 | |
| Actuarial (gain) loss | | | 5,123 | | | | (65,886 | ) | | | 133,839 | |
| Benefits paid | | | (89,204 | ) | | | (89,203 | ) | | | (93,978 | ) |
| Benefit obligation — end of year | | | 2,326,250 | | | | 2,286,970 | | | | 2,322,471 | |
| | | | | | | | | | | | | |
| Change in plan assets: | | | | | | | | | | | | |
| Fair value of plan assets — beginning of year | | | - | | | | - | | | | - | |
| Employer contributions | | | 89,204 | | | | 89,203 | | | | 93,978 | |
| Benefits paid | | | (89,204 | ) | | | (89,203 | ) | | | (93,978 | ) |
| Fair value of plan assets — end of year | | | - | | | | - | | | | - | |
| | | | | | | | | | | | | |
| Funded status | | | (2,326,250 | ) | | | (2,286,970 | ) | | | (2,322,471 | ) |
| Unrecognized net actuarial loss | | | - | | | | - | | | | 959,492 | |
Net amount accrued (1) | | $ | (2,326,250 | ) | | $ | (2,286,970 | ) | | $ | (1,362,979 | ) |
| | | | | | | | | | | | | |
| Assumptions: | | | | | | | | | | | | |
| Discount rate | | | 5.50 | % | | | 5.50 | % | | | 5.25 | % |
| | | | | | | | | | | | | |
| (1) After the adoption of SFAS 158 on December 31, 2006, these amounts are recorded and this reconciliation is no longer required. | |
Assumptions
The Company reviewed the assumptions used for the discount rate of the plan to calculate the benefit obligation and has elected to maintainof all the rate at 5.50 percent, reflecting relatively no change inplans were based on the interest rates of high qualityhigh-quality bonds and a reduction in 2009, reflecting the expected life of the plan.plans. In determining the average expected return on plan assets for each applicable plan, various factors, such as historical long-term return experience, investment policy and current and expected allocation, were considered. Since the Chesapeake’s plans and FPU’s plans have a different expected life of the plan and investment policy, particularly in light of the lump-sum-payment option provided in the Chesapeake Pension Plan, isdifferent discount rate and expected return on plan asset assumptions were selected for Chesapeake’s plans and FPU’s plans. Since all of the pension plans are frozen in regardwith respect to additional years of service and compensation, the rate of assumed paycompensation rate increases is not applicable. The measurement dates for the Pension SERP were December 31, 2007 and 2006.
Net periodic pension costs for the Pension SERP for 2007, 2006, and 2005 include the components as shown below:
| For the Years Ended December 31, | 2007 | | 2006 | | 2005 | |
| Components of net periodic pension cost: | | | | | | |
| Service cost | $ | 0 | | $ | 0 | | $ | 0 | |
| Interest cost | | 123,361 | | | 119,588 | | | 119,658 | |
| Amortization of: | | | | | | | | | |
| Actuarial loss | | 51,734 | | | 57,039 | | | 49,319 | |
| Net periodic pension cost | $ | 175,095 | | $ | 176,627 | | $ | 168,977 | |
| | | | | | | | | | |
| Assumptions: | | | | | | | | | |
| Discount rate | | 5.50 | % | | 5.25 | % | | 5.50 | % |
Other Postretirement Benefits
The Company sponsors a defined benefit postretirement health care and life insurance plan that covers substantially all employees. The following schedule sets forth the status of the postretirement health care and life insurance plan:
| At December 31, | | 2007 | | | 2006 | | | 2005 | |
| Change in benefit obligation: | | | | | | | | | |
| Benefit obligation — beginning of year | | $ | 1,763,108 | | | $ | 1,534,684 | | | $ | 1,599,280 | |
| Retirees | | | 56,123 | | | | 264,470 | | | | (59,152 | ) |
| Fully-eligible active employees | | | 21,012 | | | | (114,082 | ) | | | (31,761 | ) |
| Other active | | | (84,679 | ) | | | 78,036 | | | | 26,317 | |
| Benefit obligation — end of year | | $ | 1,755,564 | | | $ | 1,763,108 | | | $ | 1,534,684 | |
| | | | | | | | | | | | | |
| Change in plan assets: | | | | | | | | | | | | |
| Fair value of plan assets — beginning of year | | | - | | | | - | | | | - | |
| Employer contributions | | | 243,660 | | | | 300,360 | | | | 89,238 | |
| Plan participant's contributions | | | 100,863 | | | | 94,914 | | | | 72,866 | |
| Benefits paid | | | (344,523 | ) | | | (395,274 | ) | | | (162,104 | ) |
| Fair value of plan assets — end of year | | | - | | | | - | | | | - | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Funded status | | $ | (1,755,564 | ) | | $ | (1,763,108 | ) | | $ | (1,534,684 | ) |
| Unrecognized transition obligation | | | - | | | | - | | | | 22,282 | |
| Unrecognized net actuarial loss | | | - | | | | - | | | | 751,450 | |
Net amount accrued (1) | | $ | (1,755,564 | ) | | $ | (1,763,108 | ) | | $ | (760,952 | ) |
| | | | | | | | | | | | | |
| Assumptions: | | | | | | | | | | | | |
| Discount rate | | | 5.50 | % | | | 5.50 | % | | | 5.25 | % |
| | | | | | | | | | | | | |
| (1) After the adoption of SFAS 158 on December 31, 2006, these amounts are recorded and this reconciliation is no longer required. | |
Net periodic postretirement costs for 2007, 2006 and 2005 include the following components:
| For the Years Ended December 31, | | 2007 | | | 2006 | | | 2005 | |
| Components of net periodic postretirement cost: | | | | | | | |
| Service cost | | $ | 6,203 | | | $ | 9,194 | | | $ | 6,257 | |
| Interest cost | | | 101,776 | | | | 93,924 | | | | 77,872 | |
| Amortization of: | | | | | | | | | | | | |
| Transition obligation | | | - | | | | 22,282 | | | | 27,859 | |
| Actuarial loss | | | 166,423 | | | | 144,694 | | | | 88,291 | |
| Net periodic postretirement cost | | $ | 274,402 | | | $ | 270,094 | | | $ | 200,279 | |
The health care inflation rate for 20072009 used to calculate the benefit obligation is assumed to be 5.57.50 percent for medical and 78.50 percent for prescription drugs. These rates are projected to decrease to ultimate rates of fivedrugs for the Chesapeake Postretirement Plan; and six10.50 percent respectively, byfor the year 2009.FPU Medical Plan. A one percentageone-percentage point increase in the health care inflation rate from the assumed rate would increase the accumulated postretirement benefit obligation by approximately $242,000$708,000 as of January 1, 2008,2010, and would increase the aggregate of the service cost and interest cost components of the net periodic postretirement benefit cost for 20082009 by approximately $15,000.$30,000. A one percentageone-percentage point decrease in the health care inflation rate from the assumed rate would decrease the accumulated postretirement benefit obligation by approximately $200,000$594,000 as of January 1, 2008,2010, and would decrease the aggregate of the service cost and interest cost components of the net periodic postretirement benefit cost for 20082009 by approximately $12,000. The measurement dates were December 31, 2007 and 2006.$24,000.
Estimated Future Benefit Payments
In 2010, we expect to contribute $450,000 and $1.6 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, and $88,000 to the Chesapeake SERP. We also expect to contribute $115,000 and $144,000 to the Chesapeake Postretirement Plan and FPU Medical Plan, respectively, in 2010. The schedule below shows the estimated future benefit payments for each of the years 2008 through 2012 and the aggregate of the next five years for each of theour plans previously described.described:
| | | | | | | | | | | | | | | | | | | | | |
| | | Chesapeake | | | FPU | | | | | | | Chesapeake | | | FPU | |
| | | Pension | | | Pension | | | Chesapeake | | | Postretirement | | | Medical | |
| (in thousands) | | Plan(1) | | | Plan(1) | | | SERP(2) | | | Plan(2) | | | Plan(2)(3) | |
| 2010 | | $ | 763 | | | $ | 2,176 | | | $ | 88 | | | $ | 115 | | | $ | 144 | |
| 2011 | | | 429 | | | | 2,308 | | | | 797 | | | | 113 | | | | 158 | |
| 2012 | | | 1,228 | | | | 2,452 | | | | 84 | | | | 123 | | | | 181 | |
| 2013 | | | 484 | | | | 2,617 | | | | 82 | | | | 127 | | | | 176 | |
| 2014 | | | 502 | | | | 2,747 | | | | 80 | | | | 137 | | | | 196 | |
| Years 2015 through 2019 | | | 3,649 | | | | 14,914 | | | | 634 | | | | 781 | | | | 1,215 | |
| | |
| (1) | | The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets. |
|
| (2) | | Benefit payments are expected to be paid out of the general funds of the Company. |
|
| (3) | | These amounts are shown net of estimated Medicare Part-D reimbursements of $10,000, $11,000, $11,000, $12,000 and $13,000 for the years 2010 to 2014 and $78,000 for years 2015 through 2019. |
Chesapeake Utilities Corporation 2009 Form 10-K Page 95
| | | Defined Benefit Pension Plan (1) | | | Executive Excess Defined Benefit Pension Plan (2) | | | Other Post-Retirement Benefits (2) | |
| 2008 | | $ | 734,940 | | | $ | 87,959 | | | $ | 196,449 | |
| 2009 | | | 1,363,074 | | | | 86,586 | | | | 199,250 | |
| 2010 | | | 921,490 | | | | 85,081 | | | | 208,938 | |
| 2011 | | | 437,213 | | | | 83,444 | | | | 195,679 | |
| 2012 | | | 1,332,896 | | | | 113,415 | | | | 204,524 | |
| Years 2013 through 2017 | | | 3,755,455 | | | | 835,415 | | | | 1,081,460 | |
| | | | | | | | | | | | | |
(1) The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets. | |
(2) Benefit payments are expected to be paid out of the general funds of the Company. | |
Retirement Savings Plan
The Company sponsors aWe sponsor two 401(k) Retirement Savings Plan, which provides participants a mechanism for making contributions for retirement savings. Each participant may make pre-tax contributions of up to 15 percent of eligible base compensation, subject to Internal Revenue Service limitations. These participants were eligible for the enhanced matching described below, effective January 1, 2005.savings plans and one non-qualified supplemental employee retirement savings plan.
Effective January 1, 1999, the Company began offering an enhancedChesapeake’s 401(k) Planplan is offered to all neweligible employees, as well as existingexcept for those FPU employees, who electedhave the opportunity to no longer participate in the Defined Pension Plan. The Company makesFPU’s 401(k) plan. We make matching contributions ofon up to six percent of each employee'sChesapeake employee’s eligible pre-tax compensation for the year, except for the employees of our Advanced Information Services segment.advanced information services subsidiary, as further explained below. The match is between 100 percent and 200 percent of the employee’s contribution (up to six percent), based on the employee’s age and years of service. The first 100 percent is matched with Chesapeake common stock. Thestock; the remaining match is invested in the Company’sChesapeake’s 401(k) Plan according to each employee’s election options.
Employees are automatically enrolled at a two percent contribution, with the option of opting out, and are eligible for the company match after three months of continuing service, with vesting of 20 percent per year.
Effective July 1, 2006, the Company’sour contribution made on behalf of Advanced Information Services segmentthe advanced information services subsidiary employees, is a 50 percent matching contribution, on up to six percent of theeach employee’s annual compensation.compensation contributed to the plan. The matching contribution is funded in Chesapeake common stock. The Planplan was also amended at the same time to enable it to receive discretionary profit-sharing contributions in the form of employee pre-tax deferrals. The extent to which the Advanced Information Services segmentadvanced information services subsidiary has any dollars available for profit-sharing is dependent upon the extent to which the segment’s actual earnings exceed budgeted earnings. Any profit-sharing dollars made available to employees can be deferred into the Planplan and/or paid out in the form of a bonus.
On December 1, 2001, the Company converted the 401(k) fund holding Chesapeake stock to an Employee Stock Ownership Plan (“ESOP”).
Effective January 1, 1999, the Companywe began offering a non-qualified supplemental employee retirement savings plan (“401(k) SERP”) open to Companyour executives over a specific income threshold. Participants receive cash onlya cash-only matching contribution percentage equivalent to their 401(k) match level. All contributions and matched funds can be invested among the twenty-one mutual funds available for investment. These same funds are available for investment of employee contributions within the Retirement Savings Plan.Chesapeake’s 401(k) plan. All obligations arising under the 401(k) SERP are payable from theour general assets, of Chesapeake, although Chesapeake haswe have established a Rabbi Trust to help pay benefits underfor the 401(k) SERP. As discussed further in Note E –G — “Investments,” to the Consolidated Financial Statements, the assets held in the Rabbi Trust hadincluded a fair value of $1.9 million and $2.0$1.4 million at December 31, 20072009 and 2006, respectively.2008, respectively, related to the 401(k) SERP. The assets of the Rabbi Trust are at all times subject to the claims of Chesapeake’sour general creditors.
We continue to maintain a separate 401(k) retirement savings plan for FPU. FPU’s 401(k) plan provides a matching contribution of 50 percent of an employee’s pre-tax contributions, up to six percent of the employee’s salary, for a maximum company contribution of up to three percent. Beginning in 2007, for non-union employees the plan provides a company match of 100 percent for the first two percent of an employee’s contribution, and a match of 50 percent for the next four percent of an employee’s contribution, for a total company match of up to four percent. Employees are automatically enrolled at three percent contribution, with the option of opting out, and are eligible for the company match after six months of continuous service, with vesting of 100 percent after three years of continuous service.
The Company’sOur contributions to the 401(k) plans totaled $1.48$1.6 million $1.61(including a $10,000 contribution made to FPU’s 401(k) plan after the merger), $1.6 million, and $1.68$1.5 million for the years ended December 31, 2007, 2006,2009, 2008, and 2005,2007, respectively. As of December 31, 2007,2009, there are 47,91610,281 shares reserved to fund future contributions to the Retirement Savings Plan.Chesapeake’s 401(k) plan.
Deferred Compensation Plan
On December 7, 2006, the Board of Directors approved the Chesapeake Utilities Corporation Deferred Compensation Plan (“Deferred Compensation Plan”), as amended, effective January 1, 2007. The Deferred Compensation Plan is a non-qualified, deferred compensation arrangement under which certain executives and members of the Board of Directors are able to defer payment of partall or alla part of certain specified types of compensation, including executive cash bonuses, executive performance shares, and directors'directors’ retainer and fees. At December 31, 2007,2009, the Deferred Compensation Plan consistsconsisted solely of shares of common stock related to the deferral of executive performance shares and directors’ stock retainers.
Page 96 Chesapeake Utilities Corporation 2009 Form 10-K
Participants in the Deferred Compensation Plan are able to elect the payment of benefits to begin on a specified future date after the election is made in the form of a lump sum or annual installments. Deferrals of executive cash bonuses and directors’ cash retainers and fees shall beare paid in cash. All deferrals of executive performance shares and directors’ stock retainers shall beare paid in shares of the Company’sour common stock, except that cash shallis be paid in lieu of fractional shares.
L.N. Share-Based Compensation Plans
The Company accounts for itsOur non-employee directors and key employees are awarded share-based compensation arrangements under SFAS No. 123 (revised 2004), “Share Based Payments”awards through the Company’s Directors Stock Compensation Plan (“SFAS 123R”DSCP”) and the Performance Incentive Plan (“PIP”), which requires companies torespectively. We record these share-based awards as compensation costs for all share-based awards over the respective service period for employeewhich services are received in exchange for an award of equity or equity-based compensation. The compensation cost is based on the fair value of the grant on the date it was awarded. The Company currently has two share-based compensation plans, the Directors Stock Compensation Plan (“DSCP”) and the Performance Incentive Plan (“PIP”), that require accounting under SFAS 123R.
The table below presents the amounts included in net income after tax, related to share-based compensation expense, for the restricted stock awards issued under the DSCP and the PIP.PIP for the years ended December 31, 2009, 2008 and 2007.
| | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2009 | | | 2008 | | | 2007 | |
| (in thousands) | | | | | | | | | | | | |
| Directors Stock Compensation Plan | | $ | 191 | | | $ | 180 | | | $ | 181 | |
| Performance Incentive Plan | | | 1,115 | | | | 640 | | | | 809 | |
| | | | | | | | | | |
| Total compensation expense | | | 1,306 | | | | 820 | | | | 990 | |
| Less: tax benefit | | | 523 | | | | 327 | | | | 386 | |
| | | | | | | | | | |
| Share-Based Compensation amounts included in net income | | $ | 783 | | | $ | 493 | | | $ | 604 | |
| | | | | | | | | | |
| For the year ended December 31, | | 2007 | | | 2006 | | | 2005 | |
| | | | | | | | | | |
| Directors Stock Compensation Plan | | $ | 110,360 | | | $ | 100,860 | | | $ | 83,980 | |
| Performance Incentive Plan | | | 493,510 | | | | 332,110 | | | | 439,580 | |
| | | | | | | | | | | | | |
| Amounts included in net income, after tax | | $ | 603,870 | | | $ | 432,970 | | | $ | 523,560 | |
Stock Options
The CompanyWe did not have any stock options outstanding at December 31, 20072009, 2008 or December 31, 2006,2007, nor were any stock options issued during 20072009, 2008 and 2006.2007.
Directors Stock Compensation Plan
Under the DSCP, each of our non-employee director of the Companydirectors received in 20072009 an annual retainer of 600650 shares of common stock and an additional 150 shares of common stock for servicesserving as a committee chairman.chairperson. For 2009, the Corporate Governance and Compensation Committee Chairperson each received 150 additional shares of common stock and the Audit Committee Chairperson received 250 additional shares of common stock. Shares issuedgranted under the DSCP are issued in advance of the directors’ service period; therefore, these shares are fully vested as of the date of the grant. The Company recordsgrant date. We record a prepaid expense as of the date of the grant equal to the fair value of the shares issued and amortizesamortize the expense equally over a service period of one year.
Chesapeake Utilities Corporation 2009 Form 10-K Page 97
A summary of restricted stock activity under the DSCP for the three years of 2007, 2006, and 2005 is presented below:
| | | | | | | | | |
| | | | | | Weighted Average | |
| | | Number of | | | Grant Date | |
| | | Shares | | | Fair Value | |
| Outstanding — December 31, 2007 | | | — | | | | — | |
| | | | | | | |
Granted | | | 6,161 | | | $ | 29.43 | |
| Vested | | | 6,161 | | | $ | 29.43 | |
| Forfeited | | | — | | | | — | |
| | | | | | | |
| Outstanding — December 31, 2008 | | | — | | | | — | |
| | | | | | | |
Granted(1) | | | 7,174 | | | $ | 29.83 | |
| Vested | | | 7,174 | | | $ | 29.83 | |
| Forfeited | | | — | | | | — | |
| | | | | | | |
| Outstanding — December 31, 2009 | | | — | | | | — | |
| | | | | | | |
| | |
| (1) | | On October 28, 2009, the Company added two new members to its Board of Directors; each new board member was awarded 337 shares of common stock. |
We recorded compensation expense of $191,000, $180,000 and $181,000 related to DSCP awards for the years ended December 31, 2009, 2008 and 2007, respectively.
| | | | | | | |
| | | Number of Restricted Shares | | | Weighted Average Grant Date Fair Value | |
| Outstanding — December 31, 2004 | | | - | | | | |
| Issued — May 5, 2005 | | | 5,850 | | | $ | 24.68 | |
| Vested | | | 5,850 | | | | | |
| Outstanding — December 31, 2005 | | | - | | | | | |
| Issued — May 2, 2006 | | | 5,850 | | | $ | 30.02 | |
| Vested | | | 5,850 | | | | | |
| Outstanding — December 31, 2006 | | | - | | | | | |
| Issued — May 2, 2007 | | | 5,850 | | | $ | 31.38 | |
| Vested | | | 5,850 | | | | | |
| Outstanding — December 31, 2007 | | | - | | | | | |
CompensationThe weighted-average grant-date fair value of DSCP awards granted during 2009 and 2008 was $29.83 and $29.43, per share, respectively. The intrinsic values of the DSCP awards are equal to the fair market value of these awards on the date of grant. At December 31, 2009, there was $64,000 of unrecognized compensation expense related to DSCP awards recorded bythat is expected to be recognized over the Company for the years 2007, 2006, and 2005 is presented in the following table:
| For the year ended December 31, | 2007 | | 2006 | | 2005 |
| | | | | | |
| Compensation expense for DSCP | $ 180,920 | | $ 165,340 | | $ 137,670 |
| | | | | | |
first four months of 2010.
As of December 31, 2007,2009, there were 57,45044,115 shares reserved for issuance under the terms of the Company’s DSCP.
Performance Incentive Plan (“PIP”)
The Company’sOur Compensation Committee of the Board of Directors is authorized to grant key employees of the Company the right to receive awards of shares of the Company’sour common stock, contingent upon the achievement of established performance goals. These awards are subject to certain post-vesting transfer restrictions.
In 2007, the Board of Directors granted each executive officer equity incentive awards, which entitled each to earn shares of common stock to the extent that we achieved pre-established performance goals at the end of a one-year performance period. In 2008, we adopted multi-year performance plans to be used in lieu of the one-year awards. Similar to the one-year plans, the multi-year plans provide incentives based upon the achievement of long-term goals, development and the success of the Company. The long-term goals have both market-based and performance-based conditions or targets.
The shares granted under the PIP in 2007 are fully vested, and the fair value of each share is equal to the market price of the Company’sour common stock on the date of the grant. The shares granted under the 2008 and 2009 long-term plans have not vested as of December 31, 2009, and 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.
- Page 52 - -98 Chesapeake Utilities Corporation 2009 Form 10-K
A summary of restricted stock activity under the PIP for the three years of 2007, 2006, and 2005 is presented below:
| | | | | | | | | |
| | | Number of | | | Weighted Average | |
| | | Shares | | | Fair Value | |
| Outstanding — December 31, 2007 | | | 33,760 | | | $ | 29.90 | |
| | | | | | | |
| Granted | | | 94,200 | | | $ | 27.84 | |
| Vested | | | 31,094 | | | $ | 29.90 | |
| Fortfeited | | | — | | | | — | |
| Expired | | | 2,666 | | | $ | 29.90 | |
| | | | | | | |
| Outstanding — December 31, 2008 | | | 94,200 | | | $ | 27.84 | |
| | | | | | | |
| Granted | | | 28,875 | | | $ | 29.19 | |
| Vested | | | — | | | | — | |
| Fortfeited | | | — | | | | — | |
| Expired | | | — | | | | — | |
| | | | | | | |
| Outstanding — December 31, 2009 | | | 123,075 | | | $ | 28.15 | |
| | | | | | | |
In 2009, no shares under the PIP vested. In 2008, we withheld shares with value equivalent to the employees’ minimum statutory obligation for the applicable income and other employment taxes, and remitted the cash to the appropriate taxing authorities with the executives receiving the net shares. The total number of shares withheld (12,511) for 2008 was based on the value of the PIP shares on their vesting date, determined by the average of the high and low of our stock price. No payments for the employee’s tax obligations were made to taxing authorities in 2009 as no shares vested during this period. Total payments for the employees’ tax obligations to the taxing authorities were approximately $383,000 in 2008.
| | | Number of Restricted Shares | | | Weighted Average Grant Date Fair Value | |
| Outstanding — December 31, 2004 | | | - | | | | |
| Issued — February 24, 2005 | | | 10,130 | | | $ | 27.00 | |
| Vested | | | 10,130 | | | | | |
| Outstanding — December 31, 2005 | | | - | | | | | |
| Issued — February 23, 2006 | | | 23,666 | | | $ | 30.40 | |
| Vested | | | 23,666 | | | | | |
| Outstanding — December 31, 2006 | | | - | | | | | |
| Issued — March 1, 2007 | | | 10,124 | | | $ | 30.89 | |
| Vested | | | 10,124 | | | | | |
| Outstanding — December 31, 2007 | | | - | | | | | |
CompensationWe recorded compensation expense of $1.1 million, $640,000 and $809,000 related to the PIP recorded byfor the Companyyears ended December 31, 2009, 2008, and 2007, respectively.
The weighted-average grant-date fair value of PIP awards granted during 2009, 2008 and 2007 was $29.19, $27.84 and $29.90, per share respectively. The intrinsic value of the three yearsPIP awards was $2.1 million and $1.1 million for 2009 and 2008, respectively. The intrinsic value of the 2007 2006, and 2005 is presented inawards was equal to the following table:
| For the year ended December 31, | 2007 | | 2006 | | 2005 |
| | | | | | |
| Compensation expense for PIP | $ 809,030 | | $ 544,450 | | $ 720,630 |
| | | | | | |
fair market value of these awards on the date of grant.
As of December 31, 2007,2009, there were 389,876371,293 shares reserved for issuance under the terms of the Company’sour PIP.
M.O. Environmental Commitments and Contingencies
Chesapeake isWe are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require the Companyus to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites.
In 2004, Chesapeake received a Certificate of Completion for the remedial work performed at a former manufactured gas plant site located in Dover, Delaware. Chesapeake is also currently participatingWe have participated in the investigation, assessment or remediation of two additionaland have certain exposures at six former manufactured gas plantMGP sites. Those sites are located in Salisbury, Maryland, and Florida. The Company has accrued liabilities for the three sites referred to, respectively, as the Dover Gas Light, Salisbury Town Gas Light and the Winter Haven, Coal Gas sites. The Company hasKey West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the Maryland Department of the Environment (“MDE”)MDE regarding a fourthseventh former manufactured gas plantMGP site located in Cambridge, Maryland. The following discussion provides details of each site.
Dover Gas Light Site
The Dover Gas Light site is a former manufactured gas plant site located in Dover, Delaware. On January 15, 2004, the Company received a Certificate of Completion of Work from the United States Environmental Protection Agency (“EPA”) regarding this site. This concluded Chesapeake’s remedial action obligationKey West, Pensacola, Sanford and West Palm Beach sites are related to this siteFPU, for which we assumed in the merger any existing and relieves future contingencies.
Chesapeake from liabilityUtilities Corporation 2009 Form 10-K Page 99
As of December 31, 2009, we had recorded $531,000 in environmental liabilities related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of the future costs associated with those sites. We had recorded approximately $1.7 million in regulatory and other assets for future remediation at the site, unless previously unknown conditions are discovered at the site, or information previously unknown to the EPA is received that indicates the remedial action that has been taken is not sufficiently protective. These contingencies are standard and are required by the EPA in all liability settlements.
The Company has reviewedrecovery of environmental costs from Chesapeake’s customers through its remediation costs incurred to date for the Dover Gas Light site and has concluded that all costs incurred have been paid. The Company does not expect any future environmental expenditure for this site. Through December 31, 2007, the Company has incurred approximately $9.67 million in costs related to environmental testing and remedial action studies at the site. Approximately $9.96 million has been recovered through December 2007 from other parties or throughapproved rates. As of December 31, 2007, a regulatory liability of2009, we had recorded approximately $294,500, representing$12.3 million in environmental liabilities related to FPU’s MGP sites in Florida, primarily from the over-recovery portionWest Palm Beach site, which represents our estimate of the clean-upfuture costs associated with those sites. FPU is approved to recover its environmental costs up to $14.0 million from insurance and customers through rates. Approximately $5.7 million of FPU’s expected environmental costs has been recorded. recovered from insurance and customers through rates as of December 31, 2009. We also had recorded approximately $6.6 million in regulatory assets for future recovery of environmental costs from FPU’s customers.
The over-recovery is temporary and will be refunded by the Company to customers in future rates.following discussion provides details on each site.
Salisbury, Maryland
Salisbury Town Gas Light Site
In cooperation with the MDE, the Company hasWe have completed remediation of the Salisbury Town Gas Lightthis site located in Salisbury, Maryland, where it was determined that a former manufactured gas plant hadMGP caused localized ground-water contamination. During 1996, the Companywe completed construction and beganof an Air Sparging and Soil-Vapor Extraction (“AS/SVE”) system and began remediation procedures. Chesapeake has been reportingWe have reported the remediation and monitoring results to the MDE on an ongoing basis since 1996. In February 2002, the MDE granted permission to decommission permanently the AS/SVE system and to discontinue all on-site and off-site well monitoring, except for one well thatwhich is being maintained for continued product monitoring and recovery. Chesapeake hasWe have requested and are awaiting a No Further Action determination and is awaiting such a determination from the MDE.
Through December 31, 2007, the Company has2009, we have incurred and paid approximately $2.9 million for remedial actions and environmental studies at the Salisbury Town Gas Light site. Of this amount,site and do not expect to incur any additional costs. We have recovered approximately $1.88$2.1 million has been recovered through insurance proceeds or in rates. On September 26, 2006, the Company received approval from the Maryland Public Service Commission to recover, through its rates charged to customers, the remaining $1.02 millionand have $783,000 of the incurred environmental remediation costs.clean-up costs not yet recovered.
Winter Haven, Coal Gas SiteFlorida
The Winter Haven Coal Gas site is located on the eastern shoreline of Lake Shipp, in Winter Haven, Florida. Chesapeake has been working with the Florida Department of Environmental Protection (“FDEP”) in assessing this coal gas site. In May 1996, the Company filedPursuant to a Consent Order entered into with the FDEP, an AS/SVE Pilot Study Work Plan (the “Work Plan”) for the Winter Haven Coal Gas site. After discussions with the FDEP, the Company filed a modified Work Plan, which contained a description of the scope of workwe are obligated to completeassess and remediate environmental impacts to the site assessment activities andresulting from the former operation of a report describing a limited sediment investigation performed in 1997.MGP on the site. In December 1998, the2001, FDEP approved the modified Work Plan, which the Company completed during the third quarter of 1999. In February 2001, the Company filed a Remedial Action Plan (“RAP”) with the FDEPrequiring construction and operation of a bio-sparge/soil vapor extraction (“BS/SVE”) treatment system to address the contamination of the subsurface soil and ground-water ingroundwater impacts at a portion of the site. The BS/SVE treatment system has been in operation since October 2002. The Fourteenth Semi-Annual RAP Implementation Status Report was submitted to FDEP approvedin January 2010. The groundwater sampling results through October 2009 show, in general, a reduction in contaminant concentrations over prior years, although the RAP on May 4, 2001. Constructionrate of reduction has declined recently. Modifications and upgrades to the BS/SVE treatment system were completed in October 2009. At present, we predict that remedial action objectives may be met for the area being treated by the BS/SVE treatment system in approximately three years.
The BS/SVE treatment system does not address impacted soils in the southwest corner of the AS/SVE system was completed in the fourth quarter of 2002,site. We are currently completing additional soil and the system remains fully operational.
In the third quarter of 2007, the Company performed an updated environmental review ofgroundwater sampling at this site, including a review of any potential liabilities related to the investigation and remediation actions. Based on this review, the Company increased its liability by approximately $700,000location for the updated estimatepurpose of costs to remediatedesigning a remedy for this site. Through December 31, 2007, the Company has incurred approximately $1.8 million of environmental costs associated with this site. At December 31, 2007, the Company had accrued a liability of $835,000 related to this site, offsetting (a) $15,000 collected through rates in excess of costs incurred and (b) a regulatory asset of approximately $851,000, representing the uncollected portion of the estimated clean-up costs. The Company expectssite. Following the completion of this field work, we will submit a soil excavation plan to recover the remaining clean-up costs through rates.FDEP for its review and approval.
The FDEP has indicated that the Companywe may be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the Winter Haven Coal Gas site. Based on studies performed to date, the Company objectswe object to the FDEP’s suggestion that the sediments have been contaminated and will require remediation. The Company’sadversely impacted by the former operations of the MGP. Our early estimates indicate that some of the corrective measures discussed by the FDEP maycould cost as much as $1$1.0 million. GivenWe believe that corrective measures for the Company’s view as to the absence of ecological effects, the Company believes that cost expenditures of this magnitudesediments are unwarrantednot warranted and plansintend to oppose any requirement that itwe undertake corrective measures in the offshore sediments. Chesapeake anticipates that it will be several years before this issue is resolved. At this time, the Company hasWe have not recorded a liability for sediment remediation. The outcomeremediation, as the final resolution of this matter cannot be predicted at this time.
Page 100 Chesapeake Utilities Corporation 2009 Form 10-K
Through December 31, 2009, we have incurred and paid approximately $1.4 million for this site and estimates an additional cost of $531,000 in the future, which has been accrued. We have recovered through rates $1.1 million of the costs and continue to expect that the remaining $885,000, which is included in regulatory assets, will be recoverable from customers through our approved rates.
Key West, Florida
Other
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. FDEP has not required any further work at the site as of this time. Our portion of the consulting/remediation costs which may be incurred at this site is projected to be $93,000.Pensacola, Florida
FPU formerly owned and operated an MGP in Pensacola, Florida. The MGP was also owned by Gulf Power Corporation (“Gulf Power”). Portions of the site are now owned by the City of Pensacola and the Florida Department of Transportation (“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/engineering controls. The group, consisting of Gulf Power, City of Pensacola, FDOT and FPU, is proceeding with preparation of the necessary documentation to submit the NFA justification. Consulting/remediation costs are projected to be $14,000.
Sanford, Florida
FPU is the current owner of property in Sanford, Florida, an MGP which was operated by several other entities before FPU acquired the property. FPU was never an owner/operator of the MGP. In late September 2006, the U.S. Environmental Protection Agency (“EPA”) sent a Special Notice Letter, notifying FPU, and the other responsible parties at the site (Florida Power Corporation, Florida Power & Light Company, Atlanta Gas Light Company, and the City of Sanford, Florida, collectively with FPU, “the Sanford Group”), of EPA’s selection of a final remedy for OU1 (soils), OU2 (groundwater), and OU3 (sediments) for the site. The total estimated remediation costs for this site were projected at the time by EPA to be approximately $12.9 million.
In January 2007, FPU and other members of the Sanford Group signed a Third Participation Agreement, which provides for funding the final remedy approved by EPA for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13 million, or $650,000. As of December 31, 2009, FPU paid $300,000 to the Sanford Group escrow account for its share of funding requirements, and in January 2010, the Company paid the remaining $350,000 of this funding requirement.
The Sanford Group, EPA and the U.S. Department of Justice entered into a Consent Decree in March 2008, which was entered by the federal court in Orlando on January 15, 2009. The Consent Decree obligates the Sanford Group to implement the remedy approved by EPA for the site. The total cost of the final remedy is now estimated at approximately $18 million. FPU has advised the other members of the Sanford Group that it is unwilling at this time to agree to pay any sum in excess of the $650,000 committed by FPU in the Third Participation Agreement.
Several members of the Sanford Group have concluded negotiations with two adjacent property owners to resolve damages that the property owners allege they have/will incur as a result of the implementation of the EPA-approved remediation. In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third party claims.
As of December 31, 2009, FPU’s remaining share of remediation expenses, including attorney’s fees and costs, is estimated to be $401,000, of which $350,000 was paid to the Sanford Group escrow account in January 2010. However, the Company is unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept FPU’s asserted defense to liability for costs exceeding $13 million to implement the final remedy for this site or will pursue a claim against FPU for a sum in excess of the $650,000 that FPU has committed to fund under the Third Participation Agreement.
Chesapeake Utilities Corporation 2009 Form 10-K Page 101
West Palm Beach, Florida
We are currently evaluating remedial options to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West Palm Beach, Florida upon which FPU previously operated an MGP. Pursuant to a Consent Order between FPU and the FDEP, effective April 8, 1991, FPU completed the delineation of soil and groundwater impacts at the site. On June 30, 2008, FPU transmitted a revised feasibility study, evaluating appropriate remedies for the site, to the FDEP. On April 30, 2009, FDEP issued a remedial action order, which it subsequently withdrew. In response to the order and as a condition to its withdrawal, FPU committed to perform additional field work in 2009 and complete an additional engineering evaluation of certain remedial alternatives. The scope of this work has increased in response to FDEP’s demands for additional information.
The feasibility study evaluated a wide range of remedial alternatives based on criteria provided by applicable laws and regulations. Based on the likely acceptability of proven remedial technologies described in the feasibility study and implemented at similar sites, management believes that consulting/remediation costs to address the impacts now characterized at the West Palm Beach site will range from $7.4 million to $18.9 million. This range of costs covers such remedies as in situ solidification for deeper soil impacts, excavation of superficial soil impacts, installation of a barrier wall with a permeable biotreatment zone, monitored natural attenuation of dissolved impacts in groundwater, or some combination of these remedies.
Negotiations between FPU and the FDEP on a final remedy for the site continue. Prior to the conclusion of those negotiations, we are unable to determine, to a reasonable degree of certainty, the full extent or cost of remedial action that may be required. As of December 31, 2009, and subject to the limitations described above, we estimate the remediation expenses, including attorneys’ fees and costs, will range from approximately $7.8 million to $19.4 million for this site.
We continue to expect that all costs related to these activities will be recoverable from customers through rates.
Other
We are in discussions with the MDE regarding a manufactured gas plantan MGP site located in Cambridge, Maryland. The outcome of this matter cannot be determined at this time; therefore, the Company has not recorded an environmental liability for this location.
Rates and Other Regulatory Activities
Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; ESNG, our natural gas transmission operation, is subject to regulation by the FERC. Chesapeake’s Florida natural gas distribution division and FPU’s natural gas and electric operations continue to be subject to regulation by the Florida PSC as separate entities.
Page 102 Chesapeake Utilities Corporation 2009 Form 10-K
Delaware. On September 2, 2008, our Delaware division filed with the Delaware Public Service Commission (“Delaware PSC”) its annual Gas Sales Service Rates (“GSR”) Application, seeking approval to change its GSR, effective November 1, 2008. On September 16, 2008, the Delaware PSC authorized the Delaware division to implement the GSR charges on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. The Delaware division was required by its natural gas tariff to file a revised application if its projected over-collection of gas costs for the determination period of November 2007 through October 2008 exceeded four and one-half percent (4.5 percent) of total firm gas costs. As a result of a significant decrease in the cost of natural gas, the Delaware division, on January 8, 2009, filed with the Delaware PSC a supplemental GSR Application, seeking approval to change its GSR, effective February 1, 2009. On January 29, 2009, the Delaware PSC authorized the Delaware division to implement the revised GSR charges on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. On July 7, 2009, the Delaware PSC granted approval of a settlement agreement presented by the parties in this docket, the Delaware PSC, our Delaware division and the Division of the Public Advocate. Pursuant to the settlement agreement, our Delaware division, commencing in November 2009, adjusted the margin-sharing mechanism related to its Asset Management Agreement to reduce its proportionate share of such margin. We anticipate a net margin reduction of approximately $8,000 per year from this change.
As part of the settlement, the parties also agreed to develop a record in a later proceeding on the price charged by the Delaware division for the temporary release of transmission pipeline capacity to our natural gas marketing subsidiary, PESCO. On January 8, 2010, the Hearing Examiner in this proceeding issued a report of Findings and Recommendations in which he recommended, among other things, that the Delaware PSC require the Delaware division to refund to its firm service customers the difference between what the Delaware division would have received had the capacity released to PESCO been priced at the maximum tariff rates, and the amount actually received by the Delaware division for capacity released to PESCO. We have estimated that, exclusive of any interest, the amount that would have to be refunded if the Hearing Examiner’s recommendation is approved without modification by the Delaware PSC is approximately $700,000 as of December 31, 2009. The Hearing Examiner has also recommended that the Delaware PSC require us to adhere to asymmetrical pricing principles regarding all future capacity releases by the Delaware division to PESCO, if any. Accordingly, if the Hearing Examiner’s recommendation is approved without modification by the Delaware PSC and if the Delaware division temporarily released any capacity to PESCO below the maximum tariff rates, the Delaware division would have to credit to its firm service customers amounts equal to the maximum tariff rates that the Delaware division pays for long-term capacity, even though the temporary releases were made at lower rates based on competitive bidding procedures required by the FERC’s capacity release rules. We disagree with the Hearing Examiner’s recommendations and filed exceptions to those recommendations on February 5, 2010. The hearing on our exceptions took place before the Delaware PSC on February 18, 2010, but no ruling was made by the Delaware PSC. We anticipate a ruling by the Delaware PSC in March 2010. We believe that the Delaware division has been following proper procedures for capacity release established by the FERC and based on a previous settlement approved by the Delaware PSC and therefore, we have not recorded a liability for this contingency.
On December 2, 2008, our Delaware division filed two applications with the Delaware PSC, requesting approval for a Town of Milton Franchise Fee Rider and a City of Seaford Franchise Fee Rider. These Riders allow the division to recover from natural gas customers located within the Town of Milford or the City of Seaford a proportionate share of the franchise fees paid by the division. The Delaware PSC granted approval of both Franchise Fee Riders on January 29, 2009.
On September 4, 2009, our Delaware division filed with the Delaware PSC its annual GSR Application, seeking approval to change its GSR, effective November 1, 2009. On October 6, 2009, the Delaware PSC authorized the Delaware division to implement the GSR charges on November 1, 2009, on a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a final decision. The Delaware division anticipates a final decision by the Delaware PSC on this application in the second quarter of 2010.
On December 17, 2009, our Delaware division filed an application with the Delaware PSC, requesting approval for an Individual Contract Rate for service to be rendered to a potential large industrial customer. On or about October 2, 2009, the Delaware division entered into a negotiated gas service agreement with a potential customer pursuant to which the Delaware division would provide transportation, balancing, and gas delivery service to the customer’s facilities in Delaware. The Delaware division’s obligations under the agreement are subject to several conditions, including the condition that the agreement be approved by the Delaware PSC. The Delaware division and the potential customer consider the specific terms and conditions of the agreement to be confidential and proprietary. The Delaware division anticipates a final decision by the Delaware PSC on this application in the first quarter of 2010.
Chesapeake Utilities Corporation 2009 Form 10-K Page 103
Maryland. On December 16, 2008, the Maryland Public Service Commission (“Maryland PSC”) held an evidentiary hearing to determine the reasonableness of the four quarterly gas cost recovery filings submitted by our Maryland division during the 12 months ended September 30, 2008. No issues were raised at the hearing, and on December 19, 2008, the Hearing Examiner in this proceeding issued a proposed Order approving the division’s four quarterly filings, which became a final Order of the Maryland PSC on January 21, 2009.
On April 24, 2009, the Maryland PSC issued an Order defining utilities’ payment plan parameters and termination procedures that would increase the likelihood that customers could pay their past due amounts to avoid termination of natural gas service. This Order requires our Maryland division to: (a) provide customers in writing, prior to issuing a termination notice, certain details about their past due balance and information about available payment plans, and (b) continue to offer flexible and tailored payment plans. The Maryland division has implemented procedures to comply with this Order.
On December 1, 2009, the Maryland PSC held an evidentiary hearing to determine the reasonableness of the four quarterly gas cost recovery filings submitted by the Company’s Maryland division during the 12 months ended September 30, 2009. No issues were raised at the hearing, and on December 9, 2009, the Hearing Examiner in this proceeding issued a proposed Order approving the division’s four quarterly filings. On January 8, 2010, the Maryland PSC issued an Order affirming the Hearing Examiner’s decisions in the matter, but made certain clarifications and corrections to the text of the proposed Order issued by the Hearing Examiner.
Florida. On July 14, 2009, Chesapeake’s Florida division filed with the Florida PSC its petition for a rate increase and request for interim rate relief. In the application, the Florida division sought approval of: (a) an interim rate increase of $417,555; (b) a permanent rate increase of $2,965,398, which represented an average base rate increase, excluding fuel costs, of approximately 25 percent for the Florida division’s customers; (c) implementation or modification of certain surcharge mechanisms; (d) restructuring of certain rate classifications; and (e) deferral of certain costs and the purchase premium associated with the pending merger with FPU. On August 18, 2009, the Florida PSC approved the full amount of the Florida division’s interim rate request, subject to refund, applicable to all meters read on or after September 1, 2009. On December 15, 2009, the Florida PSC: (a) approved a $2,536,307 permanent rate increase (86 percent of the requested amount) applicable to all meters read on or after January 14, 2010; (b) determined that there is no refund required of the interim rate increase; and (c) ordered Chesapeake’s Florida division and FPU’s natural gas distribution operations to submit data no later than April 29, 2011 (which is 18 months after the merger) that details all known benefits, synergies and cost savings that have resulted from the merger).
Also on December 15, 2009, the Florida PSC approved the settlement agreement for a final natural gas rate increase of $7,969,000 for FPU’s natural gas distribution operation, which represents approximately 80 percent of the requested base rate increase of $9,917,690 filed by FPU in the fourth quarter of 2008. The Florida PSC had approved an annual interim rate increase of $984,054 on February 10, 2009 and approved the permanent rate increase of $8,496,230 in an order issued on May 5, 2009, with the new rates to be effective beginning on June 4, 2009. On June 17, 2009, however, the Office of Public Counsel entered a protest to the Florida PSC’s order and its final natural gas rate increase ruling, which protest required a full hearing to be held within eight months. Subsequent negotiations led to the settlement agreement between the Office of Public Counsel and FPU, which the Florida PSC approved on December 15, 2009. The rates authorized pursuant to the order approving the settlement agreement became effective on January 14, 2010 and in February 2010, FPU refunded to its natural gas customers approximately $290,000 representing revenues in excess of the amount provided by the settlement agreement that had been billed to customers from June 2009 through January 14, 2010.
Page 104 Chesapeake Utilities Corporation 2009 Form 10-K
On September 1, 2009, FPU’s electric distribution operation filed its annual Fuel and Purchased Power Recovery Clause, which seeks final approval of its 2008 fuel-related revenues and expenses and new fuel rates for 2010. On January 4, 2010, the Florida PSC approved the proposed 2010 fuel rates, effective on or after January 1, 2010.
On September 11, 2009, Chesapeake’s Florida division and FPU’s natural gas distribution operation separately filed their respective annual Energy Conservation Cost Recovery Clause, seeking final approval of their 2008 conservation-related revenues and expenses and new conservation surcharge rates for 2010. On November 2, 2009, the Florida PSC approved the proposed 2010 conservation surcharge rates for both the Florida division and FPU, effective for meters read on or after January 1, 2010.
Also on September 11, 2009, FPU’s natural gas distribution operation filed its annual Purchased Gas Adjustment Clause, seeking final approval of its 2008 purchased gas-related revenues and expenses and new purchased gas adjustment cap rate for 2010. On November 4, 2009, the Florida PSC approved the proposed 2010 purchased gas adjustment cap, effective on or after January 1, 2010.
The City of Marianna Commissioners voted on July 7, 2009 to enter into a new ten year franchise agreement with FPU effective February 1, 2010. The agreement provides that new interruptible and time of use rates shall become available for certain customers prior to February 2011 or, at the option of the City, the franchise agreement could be voided nine months after that date. The new franchise agreement contains a provision for the City to purchase the Marianna portion of FPU’s electric system. Should FPU fail to make available the new rates, and if the franchise agreement is then voided by the City and the City elects to purchase the Marianna portion of the distribution system, it would require the city to pay FPU severance/reintegration costs, the fair market value for the system, and an initial investment in the infrastructure to operate this limited facility. If the City purchased the electric system, FPU would have a gain in the year of the disposition; but, ongoing financial results would be negatively impacted from the loss of the Marianna area from its electric operations.
ESNG. The following are regulatory activities involving FERC Orders applicable to ESNG and the expansions of ESNG’s transmission system:
System Expansion 2006 — 2008. In accordance with the requirements in the FERC’s Order Issuing Certificate for the 2006 — 2008 System Expansion, ESNG had until June 13, 2009, to construct the remaining facilities that were authorized in the project filing. On February 3, 2009, ESNG requested authorization to modify the previously required completion date and to commence construction of the facilities, which provide for the remaining 6,957 Mcfs of additional firm service capacity previously approved by the FERC. On March 13, 2009, the FERC granted the requested authorization. On October 30, 2009, ESNG received approval from the FERC to commence services in November 2009 on this remaining portion of the 2006-2008 system expansion, which will permit ESNG to realize an additional annualized gross margin of approximately $1.0 million.
Energylink Expansion Project (“E3 Project”). In 2006, ESNG proposed to develop, construct and operate approximately 75 miles of new pipeline facilities from the existing Cove Point Liquefied Natural Gas terminal in Calvert County, Maryland, crossing under the Chesapeake Bay into Dorchester and Caroline Counties, Maryland, to points on the Delmarva Peninsula, where such facilities would interconnect with ESNG’s existing facilities in Sussex County, Delaware.
In April 2009, ESNG terminated the E3 Project and initiated billing to recover specified project costs in accordance with the terms of the precedent agreements executed with the two participating customers, one of which is Chesapeake, through its Delaware and Maryland divisions. These billings will reimburse ESNG for the $3.17 million of costs incurred in connection with the E3 Project, including the cost of capital, over a period of 20 years.
Chesapeake Utilities Corporation 2009 Form 10-K Page 105
Prior Notice Request. On November 25, 2009 ESNG filed a prior notice request, proposing to construct, own and operate new mainline facilities to deliver additional firm entitlements of 1,594 Mcfs per day of natural gas to Chesapeake’s Delaware division. The FERC published notice of this filing on December 7, 2009 and with no protest during the 60-day period following the notice, the proposed activity became effective on February 6, 2010. ESNG expects to realize an annualized margin of approximately $343,000 upon its completion of the facilities and implementation of the new service.
FERC Order Nos. 712 and 712-A. In June and November 2008, the FERC issued Order Nos. 712 and 712-A, which revised its regulations regarding interstate natural gas pipeline capacity release programs. The Orders: (a) remove the rate ceiling on capacity release transactions of one year or less; (b) facilitate the use of asset management arrangements for certain capacity releases; and (c) facilitate state-approved retail open access programs. The Orders required interstate gas pipeline companies to remove any inconsistent tariff provisions within 180 days of the effective date of the rule. On February 2, 2009, ESNG submitted revised tariff sheets to comply with the requirements set forth in the Orders. Amended tariff sheets were subsequently filed on February 26, 2009, which made minor clarifications and corrections. On March 27, 2009, ESNG received FERC approval of these amended tariff sheets with an effective date of March 1, 2009. Implementation of these amended tariff provisions will have no financial impact on ESNG.
ESNG also had developments in the following FERC matters:
On April 30, 2009, ESNG submitted its annual Interruptible Revenue Sharing Report to the FERC. ESNG reported in this filing that it refunded to its eligible firm customers a total of $245,500, inclusive of interest, in the second quarter of 2009.
On May 29, 2009, ESNG submitted its annual Fuel Retention Percentage (“FRP”) and Cash-Out Surcharge filings to the FERC. In these filings, ESNG proposed to implement an FRP rate of 0.12 percent and a zero rate for its Cash-Out Surcharge. ESNG also proposed to refund a total of $294,540, inclusive of interest, to its eligible customers in the second quarter of 2009 by netting its over-recovered fuel cost against its under-recovered cash-out cost. The FERC approved these proposals, and ESNG refunded $294,540 to customers in July 2009.
On June 1, 2009, ESNG submitted revised tariff sheets to comply with FERC Order No. 587-T, which adopted Version 1.8 of the North American Energy Standards Board Wholesale Gas Quadrant’s standards. FERC found this rule necessary to increase the efficiency of the pipeline grid, make pipelines’ electronic communications more secure and provide consistency with the mandate that agencies provide for electronic disclosure of information. ESNG’s revised tariff sheets were approved on August 11, 2009, by the FERC, which will have no financial impact on ESNG.
On August 21, 2009, ESNG filed revised tariff sheets to reflect an increase in the Annual Charge Adjustment (“ACA”) surcharge from $0.0017 per Dt to $0.0019 per Dt. The ACA surcharge is designed to recover applicable program costs incurred by the FERC. The tariff sheets were accepted as proposed and were made effective on October 1, 2009. As the ACA is passed-through to ESNG’s customers, there will be no financial impact on ESNG.
On December 11, 2009, ESNG filed revised tariff sheets to reflect a new section 42, Consolidation of Service Agreements, to the General Terms and Conditions of its FERC Gas Tariff. Section 42 states that shippers may, at their option and subject to certain conditions, consolidate multiple service agreements under a rate schedule into a new service agreement(s) under that rate schedule. The tariff sheets were accepted by the FERC on January 7, 2010, as proposed and were made effective January 15, 2010. As this new section allows for consolidation of existing service agreements only, there will be no financial impact on ESNG.
Page 106 Chesapeake Utilities Corporation 2009 Form 10-K
Natural Gas, Electric and Propane Supply
The Company’sOur natural gas, electric and propane distribution operations have entered into contractual commitments to purchase gas and electricity from various suppliers. The contracts have various expiration dates. In April 2007, the CompanyMarch 2009, we renewed itsour contract with an energy marketing and risk management company to manage a portion of the Company’sour natural gas transportation and storage capacity. This new contract expires on March 31, 2008. 2012.
PESCO is currently in the process of obtaining and reviewing supply proposals from suppliers and anticipates executing agreements prior tobefore the existing contracts.agreements expire in May 2010.
FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEA requires FPU to comply with the following ratios based on the result of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 and (b) fixed charge coverage greater than 1.5. If either of the ratios 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 agreement with Gulf requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operation interest coverage (minimum of 2 to 1) and (b) total debt to total capital (maximum of 0.65 to 1). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of action taken or proposed to be taken to be compliant. Failure to comply with the ratios specified in the Gulf agreement could result in FPU providing an irrevocable letter of credit. FPU was in compliance with these requirements as of December 31, 2009.
Corporate Guarantees
The Company hasWe have issued corporate guarantees to certain vendors of itsour subsidiaries, the largest portion of which are for the Company’s propane wholesale marketing subsidiary and its Florida natural gas supply managementmarketing subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of eitherthe 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 Consolidated Financial Statements when incurred. The aggregate amount guaranteed at December 31, 2007 totaled $24.22009 was $22.7 million, with the guarantees expiring on various dates in 2008. No guarantees were recorded by the Company in 2007.
2010.
In addition to the corporate guarantees, the Company haswe have issued a letter of credit to itsthe Company’s primary insurance company for $775,000,$725,000, which expires on MayAugust 31, 2008.2010. The letter of credit is provided as security to satisfy the deductibles under the Company’sour various insurance policies. There have been no draws on this letter of credit as of December 31, 2007.
Internal Revenue Service Audit
Other
The Company isWe are involved in certain legal actions and claims arising in the normal course of business. The Company isWe 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 theour consolidated financial position, results of operations or cash flows of the Company.
flows.
Chesapeake Utilities Corporation 2009 Form 10-K Page 107
O.Q. Quarterly Financial Data (Unaudited)
In the opinion of the Company, the quarterly financial information shown below includes all adjustments necessary for a fair presentation of the operations for such periods and to disclose OnSight as a discontinued operation. The quarterly information shown has been adjusted to reflect the reclassification of OnSight’s operations for all periods presented. periods. Due to the seasonal nature of the Company’s business, there are substantial variations in operations reported on a quarterly basis.
| | | | | | | | | | | | | | | | | |
| For the Quarters Ended | | March 31 | | | June 30 | | | September 30 | | | December 31 | |
| (in thousands, except per share amounts) | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
2009(1) | | | | | | | | | | | | | | | | |
| Operating Revenue | | $ | 104,479 | | | $ | 40,834 | | | $ | 31,758 | | | $ | 91,715 | |
| Operating Income | | $ | 15,966 | | | $ | 2,856 | | | $ | 2,257 | | | $ | 12,658 | |
| Net Income (Loss) | | $ | 8,593 | | | $ | 806 | | | $ | 308 | | | $ | 6,190 | |
| Earnings (Loss) per share: | | | | | | | | | | | | | | | | |
| Basic | | $ | 1.26 | | | $ | 0.12 | | | $ | 0.04 | | | $ | 0.71 | |
| Diluted | | $ | 1.24 | | | $ | 0.12 | | | $ | 0.04 | | | $ | 0.71 | |
| | | | | | | | | | | | | | | | | |
2008 | | | | | | | | | | | | | | | | |
| Operating Revenue | | $ | 100,274 | | | $ | 69,057 | | | $ | 49,698 | | | $ | 72,415 | |
| Operating Income | | $ | 14,041 | | | $ | 4,329 | | | $ | 1,170 | | | $ | 8,938 | |
| Net Income (Loss) | | $ | 7,574 | | | $ | 1,819 | | | $ | (198 | ) | | $ | 4,412 | |
| Earnings (Loss) per share: | | | | | | | | | | | | | | | | |
| Basic | | $ | 1.11 | | | $ | 0.27 | | | $ | (0.03 | ) | | $ | 0.65 | |
| Diluted | | $ | 1.10 | | | $ | 0.27 | | | $ | (0.03 | ) | | $ | 0.64 | |
| | |
| (1) | | The quarter ended December 31, 2009 includes the results from the merger with FPU, which became effective on October 28, 2009. |
|
| (2) | | The sum of the four quarters does not equal the total year due to rounding. |
| For the Quarters Ended | | March 31 | | | June 30 | | | September 30 | | | December 31 | |
| 2007 | | | | | | | | | | | | |
| Operating Revenue | | $ | 93,526,891 | | | $ | 52,501,920 | | | $ | 41,418,718 | | | $ | 70,838,968 | |
| Operating Income | | $ | 14,613,572 | | | $ | 3,698,066 | | | $ | 985,634 | | | $ | 8,816,310 | |
| Net Income (Loss) | | $ | 7,991,088 | | | $ | 1,481,791 | | | $ | (355,898 | ) | | $ | 4,080,730 | |
| Earnings per share: | | | | | | | | | | | | | | | | |
| Basic | | $ | 1.19 | | | $ | 0.22 | | | $ | (0.05 | ) | | $ | 0.60 | |
| Diluted | | $ | 1.18 | | | $ | 0.22 | | | $ | (0.05 | ) | | $ | 0.60 | |
| | | | | | | | | | | | | | | | | |
| 2006 | | | | | | | | | | | | | | | | |
| Operating Revenue | | $ | 90,950,160 | | | $ | 44,303,239 | | | $ | 35,141,531 | | | $ | 60,804,636 | |
| Operating Income | | $ | 11,535,195 | | | $ | 3,303,448 | | | $ | 322,672 | | | $ | 8,170,621 | |
| Net Income (Loss) | | $ | 6,096,416 | | | $ | 1,132,509 | | | $ | (656,579 | ) | | $ | 3,934,179 | |
| Earnings per share: | | | | | | | | | | | | | | | | |
| Basic | | $ | 1.03 | | | $ | 0.19 | | | $ | (0.11 | ) | | $ | 0.63 | |
| Diluted | | $ | 1.01 | | | $ | 0.19 | | | $ | (0.11 | ) | | $ | 0.62 | |
| | | | | | | | | | | | | | | | | |
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure.
None.
On March 20, 2007, the Audit Committee of the Board of Directors of Chesapeake Utilities Corporation (the “Company”) dismissed PricewaterhouseCoopers LLP (“PwC”) as the Company's independent registered public accounting firm.
The reports of PwC on the consolidated financial statements of the Company for the years ended December 31, 2006 and 2005 did not contain an adverse opinion or a disclaimer of opinion, nor were they qualified or modified as to uncertainty, audit scope, or accounting principle.
During the years ended December 31, 2006 and 2005 and through March 20, 2007, there have been no (a) disagreements, as described under Item 304(a)(1)(iv) of Regulation S-K, with PwC on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of PwC, would have caused PwC to make reference thereto in their reports on the Company’s consolidated financial statements for such years, or (b) reportable events, as described under Item 304(a)(1)(v) of Regulation S-K.
The Company engaged Beard Miller Company LLP as its new independent registered public accounting firm. During the years ended December 31, 2006 and 2005 and through March 20, 2007, the Company had not consulted with Beard Miller Company LLP on any matters or events described in Item 304(a)(2) (i) and (ii) of Regulation S-K.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
The Chief Executive Officer and Chief Financial Officer of the Company, with the participation of other Company officials, have evaluated the Company’s “disclosure controls and procedures” (as such term is defined under Rule 13a-15(e) and 15d – 15(e)15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended) as of December 31, 2007.2009. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2007.2009.
Changes in Internal Controls
ThereOther than the Chesapeake and FPU merger discussed below, there has been no change in internal control over financial reporting (as such term is defined in Exchange Act Rule 13a-15(f)) that occurred during the quarter ended December 31, 2007,2009, that materially affected, or is reasonably likely to materially affect, internal control over financial reporting.
On October 28, 2009, the previously announced merger between Chesapeake and FPU was consummated. Chesapeake is in the process of integrating FPU’s operations and has not included FPU’s activity in its evaluation of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. See Item 8 under the heading “Notes to the Consolidated Financial Statements — Note B, Acquisitions and Dispositions” for additional information relating to the FPU merger. FPU’s operations constituted approximately 30 percent of total assets (excluding goodwill and other intangible assets) as of December 31, 2009, and 10 percent of operating revenues for the year then ended. FPU’s operations will be included in Chesapeake’s assessment as of December 31, 2010.
Page 108 Chesapeake Utilities Corporation 2009 Form 10-K
CEO and CFO Certifications
The Company’s Chief Executive Officer as well as the Senior Vice President and Chief Financial Officer have filed with the Securities and Exchange CommissionSEC the certifications required by Section 302 of the Sarbanes-Oxley Act of 2002 as Exhibits 31.1 and 31.2 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007.2009. In addition, on May 27, 2007,June 1, 2009 the Company’s CEOChief Executive Officer certified to the New York Stock ExchangeNYSE that he was not aware of any violation by the Company of the NYSE corporate governance listing standards.
Management’s Report on Internal Control Over Financial Reporting
The report of management required under this Item 9A is contained in Item 8 of this Form 10-K under the caption “Management’s Report on Internal Control over Financial Reporting.”
Our independent auditors, Beard Miller Company LLP,ParenteBeard LLC, have audited and issued their report on effectiveness of the Company’sour internal control over financial reporting. That report appears below. in the following page.
Chesapeake Utilities Corporation 2009 Form 10-K Page 109
Report of Independent Registered Public Accounting Firm
________
To the Board of Directors and
Stockholders of Chesapeake Utilities Corporation
We have audited Chesapeake Utilities Corporation’s internal control over financial reporting as of December 31, 2007,2009, based on criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Chesapeake Utilities Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As indicated in the accompanying Management’s Report on Internal Control Over Financial Reporting, the Company completed a merger with Florida Public Utilities Company (“FPU”) in 2009. As permitted by the Securities and Exchange Commission, management excluded the non-integrated FPU operations from its assessment of internal control over financial reporting as of December 31, 2009. Non-integrated FPU operations constituted approximately 30 percent of total assets (excluding goodwill and other intangible assets) as of December 31, 2009, and 10 percent of operating revenue for the year then ended. Our audit of internal control over financial reporting of Chesapeake Utilities Corporation as of December 31, 2009, did not include an evaluation of the internal controls over financial reporting of the non-integrated operations of FPU.
In our opinion, Chesapeake Utilities Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007,2009, based on criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheetsheets of Chesapeake Utilities Corporation as of December 31, 2007,2009 and 2008, and the related consolidated statements of income, stockholders’ equity comprehensive income,and cash flows and income taxes for the year then ended,of Chesapeake Utilities Corporation, and our report dated March 10, 20088, 2010 expressed an unqualified opinion.
| | |
| | |
/s/ ParenteBeard LLC ParenteBeard LLCMalvern, PennsylvaniaMarch 8, 2010 | | |
Page 110 Chesapeake Utilities Corporation 2009 Form 10-K
/s/ Beard Miller Company LLP————————————————
Beard Miller Company LLP
Reading, Pennsylvania
March 10, 2008
Item 9B. Other Information.
None
Part III
Item 10. Directors, Executive Officers of the Registrant and Corporate Governanace.
The information required by this Item is incorporated herein by reference to the portions of the Proxy Statement, captioned “Proposal I – Election“Election of Directors (Proposal 1),” “Information Regarding the Board ofConcerning Nominees and Continuing Directors, and Nominees,” “Corporate Governance, Practices and Stockholder Communications – Nomination of Directors,” “Committees of the Board –— Audit Committee” and “Section 16(a) Beneficial Ownership Reporting Compliance”Compliance,” to be filed not later than March 31, 20082010, in connection with the Company’s Annual Meeting to be held on or about May 1, 2008.
5, 2010.
The information required by this Item with respect to executive officers is, pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, set forth in this report following Item 4, as Item 4A, under the caption “Executive Officers of the Company.”
The Company has adopted a Code of Ethics for Financial Officers, which applies to its principal executive officer, president, principal financial officer, principal accounting officer or controller, or persons performing similar functions. The information set forth under Item 1 hereof concerning the Code of Ethics for Financial Officers is incorporated herein by reference.filed herewith.
Item 11. Executive Compensation.
The information required by this Item is incorporated herein by reference to the portion of the Proxy Statement, captioned “Director Compensation,” “Executive Compensation” and “Compensation Discussion and Analysis” in the Proxy Statement to be filed not later than March 31, 2008,2010, in connection with the Company’s Annual Meeting to be held on or about May 1, 2008.5, 2010.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by this Item is incorporated herein by reference to the portion of the Proxy Statement, captioned “Beneficial“Security Ownership of Chesapeake’s Securities”Certain Beneficial Owners and Management” to be filed not later than March 31, 20082010, in connection with the Company’s Annual Meeting to be held on or about May 1, 2008.
5, 2010.
Chesapeake Utilities Corporation 2009 Form 10-K Page 111
The following table sets forth information, as of December 31, 2007,2009, with respect to compensation plans of Chesapeake and its subsidiaries, under which shares of Chesapeake common stock are authorized for issuance:
| | | | | | | | | | | | |
| | | | | | | | | | (c) | |
| | | | | | | | | | Number of securities | |
| | (a) | | | (b) | | | remaining available for future | |
| | Number of securities to | | | Weighted-average | | | issuance under equity | |
| | be issued upon exercise | | | exercise price | | | compensation plans | |
| | of outstanding options, | | | of outstanding options, | | | (excluding securities | |
| | warrants, and rights | | | warrants, and rights | | | reflected in column (a)) | |
| Equity compensation plans approved by security holders | | | — | | | | — | | | | 439,258 | (1) |
| | | | | | | | | |
| Equity compensation plans not approved by security holders | | | — | | | | — | | | | — | |
| | | | | | | | | |
| Total | | | — | | | | — | | | | 439,258 | |
| | | | | | | | | |
| | |
| (1) | | Includes 371,293 shares under the 2005 Performance Incentive Plan, 44,115 shares available under the 2005 Directors Stock Compensation Plan, and 23,850 shares available under the 2005 Employee Stock Awards Plan. |
| | | | | | | | | | | | | | |
| | | ( a ) | | ( b ) | | ( c ) | |
| | | Number of securities to be issued upon exercise of outstanding options, warrants and rights | | Weighted-average exercise price of outstanding options, warrants and rights | | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a) | |
| Equity compensation plans approved by security holders | | | 0 | | | | (1) | | | | | 471,626 | | | | (2) | |
| | | | | | | | | | | | | | | | | | |
| Equity compensation plans not approved by security holders | | | 0 | | | | (3) | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Total | | | 0 | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| (1) All options to purchase shares under the 1992 Performance Incentive Plan, as amended, were exercised as of 12/31/05. | |
| | | | | | | | | | | | | | | | | | |
| (2) Includes 389,876 shares under the 2005 Performance Incentive Plan, 57,450 shares available under the 2005 Directors Stock Compensation Plan, and 24,300 shares available under the 2005 Employee Stock Awards Plan. | |
| | | | | | | | | | | | | | | | | | |
| (3) All warrants were exercised in 2006. | | | | | | | | | | | | | | |
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required by this Item is incorporated herein by reference to the portion of the Proxy Statement captioned, “Corporate Governance,” to be filed no later than March 31, 2010 in connection with the Company’s Annual Meeting to be held on or about May 5, 2010.
Item 14. Principal Accounting Fees and Services.
The information required by this Item is incorporated herein by reference to the portion of the Proxy Statement, captioned “Fees and Services of the Independent Registered Public Accounting Firm”Firm,” to be filed not later than March 31, 2008,2010, in connection with the Company’s Annual Meeting to be held on or about May 1, 2008.
5, 2010.
Page 112 Chesapeake Utilities Corporation 2009 Form 10-K
Part IV
Item 15. Exhibits, Financial Statement Schedules.
(a) The following documents are filed as part of this report:
1. Financial Statements:
· (a) | Report | The following documents are filed as part of Independent Registered Public Accounting Firm;this report: |
· | Consolidated Statements of Income for each of the three years ended December 31, 2007, 2006 and 2005;1. | | Financial Statements: |
Report of Independent Registered Public Accounting Firm;
· | Consolidated Balance Sheets at December 31, 2007 and December 31, 2006; |
Consolidated Statements of Income for each of the three years ended December 31, 2009, 2008, and 2007;
Consolidated Balance Sheets at December 31, 2009 and December 31, 2008;
· | Consolidated Statements of Cash Flows for each of the three years ended December 31, 2007, 2006, and 2005; |
Consolidated Statements of Cash Flows for each of the three years ended December 31, 2009, 2008, and 2007;
Consolidated Statements of Stockholders’ Equity for each of the three years ended December 31, 2009, 2008, and 2007; and
· | Consolidated Statements of Common Stockholders’ Equity for each of the three years ended December 31, 2007, 2006, and 2005; |
Notes to the Consolidated Financial Statements.
· | Consolidated Statements of Comprehensive Income for each of the three years ended December 31, 2007, 2006, and 2005; |
· | Consolidated Statements of Income Taxes for each of the three years ended December 31,2007, 2006, and 2005; |
· | Notes to the Consolidated Financial Statements. |
| | 2. | | Financial Statement Schedule:Schedules: |
· | Report of Independent Registered Public Accounting Firm; and |
Report of Independent Registered Public Accounting Firm;
Schedule I — Parent Company Condensed Financial Statements; and
· | Schedule II -Schedule II — Valuation and Qualifying Accounts. |
All other schedules are omitted, because they are not required, are inapplicable, or the information is otherwise shown in the financial statements or notes thereto.
3. Exhibits
·
| | | | |
| • | | Exhibit 1.1 | | Underwriting Agreement entered into by Chesapeake Utilities Corporation and Robert W. Baird & Co. Incorporated and A.G. Edwards & Sons, Inc., on November 15, 2007, relating to the sale and issuance of 600,300 shares of the Company’sChesapeake’s common stock, is incorporated herein by reference to Exhibit 1.1 of the Company’sour Current Report on Form 8-K, filed November 16, 2007, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 2.1 | | Agreement and Plan of Merger between Chesapeake Utilities Corporation and Florida Public Utilities Company dated April 17, 2009, is incorporated herein by reference to Exhibit 2.1 of our Current Report on Form 8-K, filed April 20, 2009, File No. 001-11590. |
| | | | |
| • | | Exhibit 3.1 | | Restated Certificate of Incorporation of Chesapeake Utilities Corporation is incorporated herein by reference to Exhibit 3.1 of the Company’sour Quarterly Report on Form 10-Q for the period ended June 30, 1998, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 3.2 | | Amended and Restated Bylaws of Chesapeake Utilities Corporation, effective December 12, 2007, is11, 2008, are incorporated herein by reference to Exhibit 3 of the Company’s Current Report on Form 8-K, filed herewith.December 16, 2008, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 4.1 | | Form of Indenture between the CompanyChesapeake and Boatmen’s Trust Company, Trustee, with respect to the 8 1/4% Convertible Debentures is incorporated herein by reference to Exhibit 4.2 of the Company’sour Registration Statement on Form S-2, Reg. No. 33-26582, filed on January 13, 1989. |
Chesapeake Utilities Corporation 2009 Form 10-K Page 113
·
| | | | |
| • | | Exhibit 4.2 | Note Agreement dated February 9, 1993, by and between the Company and Massachusetts Mutual Life Insurance Company and MML Pension Insurance Company, with respect to $10 million of 7.97% Unsecured Senior Notes due February 1, 2008, is incorporated herein by reference to Exhibit 4 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1992, File No. 0-593. |
· Exhibit 4.3
| Note Purchase Agreement, entered into by the Company on October 2, 1995, pursuant to which the CompanyChesapeake privately placed $10 million of its 6.91% Senior Notes, due in 2010, is not being filed herewith, in accordance with Item 601(b)(4)(iii) of Regulation S-K. The CompanyWe hereby agreesagree to furnish a copy of that agreement to the SEC upon request. |
·
| | | | |
| • | | Exhibit 4.4 4.3 | | Note Purchase Agreement, entered into by the CompanyChesapeake on December 15, 1997, pursuant to which the CompanyChesapeake privately placed $10 million of its 6.85% Senior Notes due in 2012, is not being filed herewith, in accordance with Item 601(b)(4)(iii) of Regulation S-K. The CompanyWe hereby agreesagree to furnish a copy of that agreement to the SEC upon request. |
·
| | | | |
| • | | Exhibit 4.5 4.4 | | Note Purchase Agreement entered into by the CompanyChesapeake on December 27, 2000, pursuant to which the CompanyChesapeake privately placed $20 million of its 7.83% Senior Notes, due in 2015, is not being filed herewith, in accordance with Item 601(b)(4)(iii) of Regulation S-K. The CompanyWe hereby agreesagree to furnish a copy of that agreement to the SEC upon request. |
·
| | | | |
| • | | Exhibit 4.6 4.5 | | Note Agreement entered into by the CompanyChesapeake on October 31, 2002, pursuant to which the CompanyChesapeake privately placed $30 million of its 6.64% Senior Notes, due in 2017, is incorporated herein by reference to Exhibit 2 of the Company’sour Current Report on Form 8-K, filed November 6, 2002, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 4.7 4.6 | | Note Agreement entered into by the CompanyChesapeake on October 18, 2005, pursuant to which the Company,Chesapeake, on October 12, 2006, privately placed $20 million of its 5.5% Senior Notes, due in 2020, with Prudential Investment Management, Inc., is incorporated herein by reference to Exhibit 4.1 of the Company’sour Annual Report on Form 10-K for the year ended December 31, 2005, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 4.7 | | Note Agreement entered into by Chesapeake on October 31, 2008, pursuant to which Chesapeake, on October 31, 2008, privately placed $30 million of its 5.93% Senior Notes, due in 2023, with General American Life Insurance Company and New England Life Insurance Company, is not being filed herewith, in accordance with Item 601(b)(4)(iii) of Regulation S-K. We hereby agree to furnish a copy of that agreement to the SEC upon request. |
| | | | |
| • | | Exhibit 4.8 | | Form of Senior Debt Trust Indenture between Chesapeake Utilities Corporation and the trustee for the debt securities is incorporated herein by reference to Exhibit 4.3.1 of the Company’sour Registration Statement on Form S-3A, Reg. No. 333-135602, dated November 6, 2006. |
·
| | | | |
| • | | Exhibit 4.9 | | Form of Subordinated Debt Trust Indenture between Chesapeake Utilities Corporation and the trustee for the debt securities is incorporated herein by reference to Exhibit 4.3.2 of the Company’sour Registration Statement on Form S-3A, Reg. No. 333-135602, dated November 6, 2006. |
·
| | | | |
| • | | Exhibit 4.10 | | Form of debt securities is incorporated herein by reference to Exhibit 4.4 of the Company’sour Registration Statement on Form S-3A, Reg. No. 333-135602, dated November 6, 2006. |
| | | | |
| • | | Exhibit 4.11 | | Form of Indenture of Mortgage and Deed of Trust between Florida Public Utilities Company and the trustee, dated September 1, 1942 for the First Mortgage Bonds, is incorporated herein by reference to Exhibit 7-A of Florida Public Utilities Company’s Registration No. 2-6087. |
| | | | |
| • | | Exhibit 4.12 | | Fourteenth Supplemental Indenture entered into by Florida Public Utilities Company on September 1, 2001, pursuant to which Florida Public Utilities Company, on September 1, 2001, privately placed $15,000,000 of its 6.85% First Mortgage Bonds, is incorporated herein by reference to Exhibit 4(b) of Florida Public Utilities Company’s Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-10608. |
| | | | |
| • | | Exhibit 4.13 | | Fifteenth Supplemental Indenture entered into by Florida Public Utilities Company on November 1, 2001, pursuant to which Florida Public Utilities Company, on November 1, 2001, privately placed $14,000,000 of its 4.90% First Mortgage Bonds, is incorporated herein by reference to Exhibit 4(c) of Florida Public Utilities Company’s Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-10608 |
Page 114 Chesapeake Utilities Corporation 2009 Form 10-K
·
| | | | |
| • | | Exhibit 4.14 | | Twelfth Supplemental Indenture entered into by Florida Public Utilities on May 1, 1988, pursuant to which Florida Public Utilities Company, on May 1, 1988, privately placed $10,000,000 and $5,000,000 of its 9.57% First Mortgage Bonds and 10.03% First Mortgage Bonds, respectively, are incorporated herein by reference to Exhibit 4 to Florida Public Utilities Company’s Quarterly Report on Form 10-Q for the period ended June 30, 1988. |
| | | | |
| • | | Exhibit 4.15 | | Thirteenth Supplemental Indenture entered into by Florida Public Utilities Company on June 1, 1992, pursuant to which Florida Public Utilities, on May 1, 1992, privately placed $8,000,000 of its 9.08% First Mortgage Bonds, is incorporated herein by reference to Exhibit 4 to Florida Public Utilities Company’s Quarterly Report on Form 10-Q for the period ended June 30, 1992. |
| | | | |
| • | | Exhibit 10.1* | | Chesapeake Utilities Corporation Cash Bonus Incentive Plan, dated January 1, 2005, is incorporated herein by reference to Exhibit 10.3 of the Company’sour Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 10.2* | | Chesapeake Utilities Corporation Directors Stock Compensation Plan, adopted in 2005, is incorporated herein by reference to the Company’sour Proxy Statement dated March 28, 2005, in connection with the Company’sour Annual Meeting held on May 5, 2005, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 10.3* | | Chesapeake Utilities Corporation Employee Stock Award Plan, adopted in 2005, is incorporated herein by reference to the Company’sour Proxy Statement dated March 28, 2005, in connection with the Company’sour Annual Meeting held on May 5, 2005, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 10.4* | | Chesapeake Utilities Corporation Performance Incentive Plan, adopted in 2005, is incorporated herein by reference to the Company’sour Proxy Statement dated March 28, 2005, in connection with the Company’sour Annual Meeting held on May 5, 2005, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 10.5* | | Deferred Compensation Program, (amendedamended and restated as of December 7, 2006)January 1, 2009, is incorporated herein by reference to Exhibit 1010.5 of the Company’s CurrentAnnual Report on Form 8-K, filed10-K for the year ended December 13, 2006,31, 2008, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 10.6* | | Executive Employment Agreement dated December 29, 2006, by and between Chesapeake Utilities Corporation and S. Robert Zola, is incorporated herein by reference to Exhibit 10.7 of our Annual Report on Form 10-K for the year ended December 31, 2006, File No. 001-11590. |
| | | | |
| • | | Exhibit 10.7* | | Amendment to Executive Employment Agreement, effective January 1, 2009, by and between Chesapeake Utilities Corporation and S. Robert Zola, is incorporated herein by reference to Exhibit 10.7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2006,2008, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 10.7* 10.8* | | Executive Employment Agreement dated December 29, 2006,31, 2009, by and between Chesapeake Utilities Corporation and John R. Schimkaitis, is incorporated herein by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed January 7, 2010, File No. 001-11590. |
| | | | |
| • | | Exhibit 10.9* | | Executive Employment Agreement dated December 31, 2009, by and between Chesapeake Utilities Corporation and Michael P. McMasters, is incorporated herein by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed January 7, 2010, File No. 001-11590. |
| | | | |
| • | | Exhibit 10.10* | | Executive Employment Agreement dated December 31, 2009, by and between Chesapeake Utilities Corporation and Stephen C. Thompson, is incorporated herein by reference to Exhibit 10.810.3 of the Company’s AnnualCurrent Report on Form 10-K for the year ended December 31, 2006,8-K, filed January 7, 2010, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 10.8* 10.11* | | Executive Employment Agreement dated December 29, 2006,31, 2009, by and between Chesapeake Utilities Corporation and Beth W. Cooper, is incorporated herein by reference to Exhibit 10.910.4 of the Company’s AnnualCurrent Report on Form 10-K for the year ended December 31, 2006,8-K, filed January 7, 2010, File No. 001-11590. |
Chesapeake Utilities Corporation 2009 Form 10-K Page 115
·
| | | | |
| • | | Exhibit 10.9* 10.12* | | Executive Employment Agreement dated December 29, 2006,31, 2009, by and between Chesapeake Utilities Corporation and Michael P. McMasters,Joseph Cummiskey, is incorporated herein by reference to Exhibit 10.1010.5 of the Company’s AnnualCurrent Report on Form 10-K for the year ended December 31, 2006,8-K, filed January 7, 2010, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 10.10* 10.13* | *Executive Employment Agreement dated December 29, 2006, by and between Chesapeake Utilities Corporation and John R. Schimkaitis, is incorporated herein by reference to Exhibit 10.11 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, File No. 001-11590. |
· Exhibit 10.11*
| Performance Share Agreement dated January 23, 2008 for the period 2008 to 2009, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and John R. Schimkaitis, filed herewith.is incorporated herein by reference to Exhibit 10.11 of our Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 10.12* 10.14* | | Performance Share Agreement dated January 23, 2008 for the period 2008 to 2010, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and John R. Schimkaitis, is filed herewith.incorporated herein by reference to Exhibit 10.12 of our Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 10.13* 10.15* | | Performance Share Agreement dated January 23, 2008 for the period 2008 to 2009, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Michael P. McMasters, is filed herewith.incorporated herein by reference to Exhibit 10.13 of our Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 10.14* 10.16* | | Performance Share Agreement dated January 23, 2008 for the period 2008 to 2010, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Michael P. McMasters, is filed herewith.incorporated herein by reference to Exhibit 10.14 of our Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 10.15* 10.17* | | Performance Share Agreement dated January 23, 2008 for the period 2008 to 2009, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Stephen C. Thompson, is filed herewith.incorporated herein by reference to Exhibit 10.15 of our Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 10.16* 10.18* | | Performance Share Agreement dated January 23, 2008 for the period 2008 to 2010, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Stephen C. Thompson, is filed herewith.incorporated herein by reference to Exhibit 10.16 of our Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 10.17* 10.19* | | Performance Share Agreement dated January 23, 2008 for the period 2008 to 2009, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Beth W. Cooper, is filed herewith.incorporated herein by reference to Exhibit 10.17 of our Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 10.18* 10.20* | | Performance Share Agreement dated January 23, 2008 for the period 2008 to 2010, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Beth W. Cooper, is filed herewith.incorporated herein by reference to Exhibit 10.18 of our Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 10.19* 10.21* | | Performance Share Agreement dated January 23, 2008 for the period 2008 to 2009, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and S. Robert Zola, is filed herewith.incorporated herein by reference to Exhibit 10.19 of our Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590. |
Page 116 Chesapeake Utilities Corporation 2009 Form 10-K
·
| | | | |
| • | | Exhibit 10.20* 10.22* | | Performance Share Agreement dated January 23, 2008 for the period 2008 to 2010, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and S. Robert Zola, is filed herewith.incorporated herein by reference to Exhibit 10.20 of our Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 12 10.23* | Computation | Form of RatioPerformance Share Agreement effective January 7, 2009, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and each of Earning to Fixed Charges is filed herewith. |
· Exhibit 14.1
| Code of Ethics for Financial OfficersJohn R. Schimkaitis, Michael P. McMasters, Beth W. Cooper and Stephen C. Thompson, is incorporated herein by reference to Exhibit 1410.26 on Form 10-K for the year ended December 31, 2008, File No. 001-11590. |
| | | | |
| • | | Exhibit 10.24* | | Form of Performance Share Agreement effective January 6, 2010, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and each of John R. Schimkaitis, Michael P. McMasters, Beth W. Cooper, Stephen C. Thompson, and Joseph Cummiskey is filed herewith. |
| | | | |
| • | | Exhibit 10.25* | | Performance Share Agreement dated January 20, 2010 for the period 2010 to 2011, pursuant to Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation and Joseph Cummiskey is filed herewith. |
| | | | |
| • | | Exhibit 10.26* | | Chesapeake Utilities Corporation Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2009, is incorporated herein by reference to Exhibit 10.28 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2006,2008, File No. 001-11590. |
·
| | | | |
| • | | Exhibit 14.2 10.27* | Business Code of Ethics | Chesapeake Utilities Corporation Supplemental Executive Retirement Savings Plan, as amended and Conduct is filed herewith. |
· Exhibit 16
| Letter Regarding Change in Certifying Accountant is filed herewith. |
· Exhibit 21
| Subsidiaries of the Registrant is filed herewith. |
· Exhibit 22
| Published Report Regarding Matters Submitted to Vote of Security Holdersrestated effective January 1, 2009, is incorporated herein by reference to Part II, Item 4Exhibit 10.29 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-11590. |
| | | | |
| • | | Exhibit 10.28* | | Amended and Restated Electric Service Contract between Florida Public Utilities Company and JEA dated November 6, 2008, is incorporated herein by reference to Exhibit 10.1 of Florida Public Utilities Company’s Current Report on Form 8-K, filed on November 6, 2008, File No. 001-10908. |
| | | | |
| • | | Exhibit 10.29* | | Networking Operating Agreement between Florida Public Utilities Company and Southern Company Services, Inc. dated December 27, 2007 and amended on June 3, 2008, is incorporated herein by reference to Exhibit 10.3 of Florida Public Utilities Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2006,2008, File No. 001-11590.001-10608. |
| | | | |
| • | | Exhibit 10.30* | | Network Integration Transmission Service Agreement between Florida Public Utilities Company and Southern Company Services, Inc. dated December 27, 2007 and amended on June 3, 2008, is incorporated herein by reference to Exhibit 10.4 of Florida Public Utilities Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2008, File No. 001-10608. |
| | | | |
| • | | Exhibit 10.31* | | Form of Service Agreement for Firm Transportation Service between Florida Public Utilities Company and Florida Gas Transmission Company, LLC dated November 1, 2007 for the period November 2007 to February 2016 (Contract No. 107033), is incorporated herein by reference to Exhibit 10.1 of Florida Public Utilities Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2007, File No. 001-10608. |
| | | | |
| • | | Exhibit 10.32* | | Form of Service Agreement for Firm Transportation Service between Florida Public Utilities Company and Florida Gas Transmission Company, LLC dated November 1, 2007 for the period November 2007 to March 2022 (Contract No. 107034), is incorporated herein by reference to Exhibit 10.2 of Florida Public Utilities Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2007, File No. 001-10608. |
Chesapeake Utilities Corporation 2009 Form 10-K Page 117
·
| | | | |
| • | | Exhibit 10.33* | | Form of Service Agreement for Firm Transportation Service between Florida Public Utilities Company and Florida Gas Transmission Company, LLC dated November 1, 2007 for the period November 2007 to February 2022 (Contract No. 107035), is incorporated herein by reference to Exhibit 10.3 of Florida Public Utilities Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2007, File No. 001-10608. |
| | | | |
| • | | Exhibit 12 | | Computation of Ratio of Earning to Fixed Charges is filed herewith. |
| | | | |
| • | | Exhibit 14.1 | | Code of Ethics for Financial Officers is filed herewith. |
| | | | |
| • | | Exhibit 14.2 | | Business Code of Ethics and Conduct is filed herewith. |
| | | | |
| • | | Exhibit 21 | | Subsidiaries of the Registrant is filed herewith. |
| | | | |
| • | | Exhibit 23.1 | | Consent of Independent Registered Public Accounting Firm is filed herewith. |
· Exhibit 23.2
| Consent of Preceding Independent Registered Public Accounting Firm for years 2006 and 2005 is filed herewith. | | | |
· •
| | Exhibit 31.1 | | Certificate of Chief Executive OfficeOfficer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a) and 15d-14(a), dated March 10, 2008,8, 2010, is filed herewith. |
·
| | | | |
| • | | Exhibit 31.2 | | Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a) and 15d-14(a), dated March 10, 2008,8, 2010, is filed herewith. |
·
| | | | |
| • | | Exhibit 32.1 | | Certificate of Chief Executive OfficeOfficer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated March 10, 2008,8, 2010, is filed herewith. |
·
| | | | |
| • | | Exhibit 32.2 | | Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated March 10, 2008,8, 2010, is filed herewith. |
| | |
| * | | Management contract or compensatory plan or agreement. |
Page 118 Chesapeake Utilities Corporation 2009 Form 10-K
* Management contract or compensatory plan or agreement.
Signatures
Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, Chesapeake Utilities Corporation has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Chesapeake Utilities Corporation
By: /s/ John R. Schimkaitis
John R. Schimkaitis
President and Chief Executive Officer
Date: March 10, 2008
| | | | |
| Chesapeake Utilities Corporation
| |
| By: | /s/ John R. Schimkaitis | |
| | John R. Schimkaitis | |
| | Vice Chairman and Chief Executive Officer | |
| Date: March 8, 2010 | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| | | | |
/s/ Ralph J. AdkinsRalph J. Adkins,Chairman of the Board and Director | | /s/ John R. SchimkaitisJohn R. Schimkaitis,
Vice Chairman, Chief Executive Officer and Director | | |
| Date: February 24, 2010 | | Date: March 8, 2010 | | |
| | | | |
/s/ Beth W. CooperBeth W. Cooper, Senior Vice President and Chief Financial Officer(Principal Financial and Accounting Officer)Date: March 8, 2010 | | /s/ Eugene H. BayardEugene H. Bayard, Director
Date: February 24, 2010 | | |
| | | | |
/s/ Richard BernsteinRichard Bernstein, Director | | /s/ Thomas J. BresnanThomas J. Bresnan, Director | | |
| Date: February 24, 2010 | | Date: March 8, 2010 | | |
| | | | |
/s/ Thomas P. Hill, Jr.Thomas P. Hill, Jr., Director | | /s/ Dennis S. Hudson, IIIDennis S. Hudson, III, Director | | |
| Date: February 24, 2010 | | Date: February 24, 2010 | | |
| | | | |
/s/ Paul L. Maddock, Jr.Paul L. Maddock, Jr., Director | | /s/ J. Peter MartinJ. Peter Martin, Director | | |
| Date: February 24, 2010 | | Date: February 24, 2010 | | |
| | | | |
/s/ Michael p. McmastersMichael P. McMasters, President, Chief Operating Officer and DirectorDate: March 8, 2010 | | /s/ Joseph E. Moore, EsqJoseph E. Moore, Esq., Director
Date: February 24, 2010 | | |
| | | | |
/s/ Calvert A. Morgan, JrCalvert A. Morgan, Jr., Director | | /s/ Dianna F. MorganDianna F. Morgan, Director | | |
| Date: February 24, 2010 | | Date: February 24, 2010 | | |
/s/ Ralph J. Adkins /s/ John R. SchimkaitisChesapeake Utilities Corporation 2009 Form 10-K Page 119
Ralph J. Adkins, Chairman of the Board John R. Schimkaitis, President,
and Director Chief Executive Officer and Director
Date: February 20, 2008 Date: March 10, 2008
/s/ Michael P. McMasters /s/ Richard Bernstein
Michael P. McMasters, Senior Vice President Richard Bernstein, Director
and Chief Financial Officer Date: February 20, 2008
(Principal Financial and Accounting Officer)
Date: March 10, 2008
/s/ Eugene H. Bayard /s/ Thomas J. Bresnan
Eugene H. Bayard, Director Thomas J. Bresnan, Director
Date: February 20, 2008 Date: March 10, 2008
/s/ Thomas P. Hill, Jr. /s/ Walter J. Coleman
Thomas P. Hill, Jr., Director Walter J. Coleman, Director
Date: February 20, 2008 Date: February 20, 2008
/s/ J. Peter Martin /s/ Joseph E. Moore, Esq.
J. Peter Martin, Director Joseph E. Moore, Esq., Director
Date: February 20, 2008 Date: February 20, 2008
/s/ Calvert A. Morgan, Jr.
Calvert A. Morgan, Jr., Director
Date: February 20, 2008
Report of Independent Registered Public Accounting Firm
________
To the Board of Directors and
Stockholders of Chesapeake Utilities Corporation
The audit referred to in our report dated March 10, 20088, 2010 relating to the consolidated financial statements of Chesapeake Utilities Corporation as of December 31, 20072009 and 2008 and for each of the year thenyears in the three-year period ended December 31, 2009, which is contained in Item 8 of this Form 10-K also included the auditaudits of the financial statement schedules listed in Item 15.15(a) 2. These financial statement schedules are the responsibility of the Chesapeake Utilities Corporation’s management. Our responsibility is to express an opinion on these financial statement schedules based on our audit.
audits.
In our opinion such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, presentpresents fairly, in all material respects, the information set forth therein.
/s/ Beard Miller Company LLP
————————————————
Beard Miller Company LLP
Reading, Pennsylvania
March 10, 2008
| Chesapeake Utilities Corporation and Subsidiaries | |
| Schedule II | |
| Valuation and Qualifying Accounts | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | Additions | | | | | | | |
| For the Year Ended December 31, | | Balance at Beginning of Year | | | Charged to Income | | | Other Accounts (1) | | | Deductions (2) | | | Balance at End of Year | |
| Reserve Deducted From Related Assets | | | | | | | | | | | | | |
| Reserve for Uncollectible Accounts | | | | | | | | | | | | | | | |
| 2007 | | $ | 661,597 | | | $ | 818,561 | | | $ | 26,190 | | | $ | (554,273 | ) | | $ | 952,075 | |
| 2006 | | $ | 861,378 | | | $ | 381,424 | | | $ | 65,519 | | | $ | (646,724 | ) | | $ | 661,597 | |
| 2005 | | $ | 610,819 | | | $ | 632,644 | | | $ | 158,409 | | | $ | (540,494 | ) | | $ | 861,378 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
(1) Recoveries. | | | | | | | | | | | | | | | | | | | | |
(2) Uncollectible accounts charged off. | | | | | | | | | | | | | | | | | |
| | |
| | |
Upon written request,/s/ ParenteBeard LLCChesapeake will provide, free ofParenteBeard LLC
charge, a copy of any exhibit to
the 2007 Annual Report on
Form 10-K not included
in this document.
| | |
| Malvern, Pennsylvania | | |
| March 8, 2010 | | |
Chesapeake Utilities Corporation and Subsidiaries
Schedule I
Parent Company Condensed Financial Statements Chesapeake Utilities Corporation (Parent)
Condensed Balance Sheets
| | | | | | | | | |
| | | December 31, | | | December 31, | |
| Assets | | 2009 | | | 2008 | |
| (in thousands) | | | | | | | | |
| | | | | | | | | |
| Total property, plant and equipment | | $ | 191,440 | | | $ | 185,416 | |
| Less: Accumulated depreciation and amortization | | | (46,297 | ) | | | (46,158 | ) |
| Plus: Construction work in progress | | | 1,338 | | | | 408 | |
| | | | | | | |
| Net property, plant and equipment | | | 146,481 | | | | 139,666 | |
| | | | | | | |
| | | | | | | | | |
Investments | | | 1,959 | | | | 1,601 | |
Investments in subsidiaries | | | 160,150 | | | | 73,410 | |
| | | | | | | |
| | | | | | | | | |
Current Assets | | | | | | | | |
| Cash and cash equivalents | | | 973 | | | | 1,534 | |
| Accounts receivable (less allowance for uncollectible accounts of $458 and $398, respectively) | | | 9,356 | | | | 11,848 | |
| Accrued revenue | | | 4,936 | | | | 4,721 | |
| Accounts receivable from affiliates | | | 56,587 | | | | 61,139 | |
| Propane inventory, at average cost | | | 624 | | | | 648 | |
| Other inventory, at average cost | | | 971 | | | | 983 | |
| Regulatory assets | | | 1,205 | | | | 824 | |
| Storage gas prepayments | | | 6,144 | | | | 9,492 | |
| Income taxes receivable | | | 822 | | | | 3,547 | |
| Deferred income taxes | | | 1,909 | | | | 1,743 | |
| Prepaid expenses | | | 3,047 | | | | 1,974 | |
| Other current assets | | | 79 | | | | 79 | |
| | | | | | | |
| Total current assets | | | 86,653 | | | | 98,532 | |
| | | | | | | |
| | | | | | | | | |
Deferred Charges and Other Assets | | | | | | | | |
| Long-term receivables | | | 331 | | | | 512 | |
| Regulatory assets | | | 3,610 | | | | 2,060 | |
| Other deferred charges | | | 479 | | | | 453 | |
| | | | | | | |
| Total deferred charges and other assets | | | 4,420 | | | | 3,025 | |
| | | | | | | |
| | | | | | | | | |
Total Assets | | $ | 399,663 | | | $ | 316,234 | |
| | | | | | | |
The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation and Subsidiaries
Schedule I
Parent Company Condensed Financial Statements
Chesapeake Utilities Corporation (Parent)
Condensed Balance Sheets
| | | | | | | | | |
| | | December 31, | | | December 31, | |
| Capitalization and Liabilities | | 2009 | | | 2008 | |
| (in thousands) | | | | | | | | |
| | | | | | | | | |
Capitalization | | | | | | | | |
| Stockholders’ equity | | | | | | | | |
| Common stock, par value $0.4867 per share (authorized 12,000,000 shares) | | $ | 4,572 | | | $ | 3,323 | |
| Additional paid-in capital | | | 144,502 | | | | 66,681 | |
| Retained earnings | | | 63,231 | | | | 56,817 | |
| Accumulated other comprehensive loss | | | (2,865 | ) | | | (3,748 | ) |
| Deferred compensation obligation | | | 739 | | | | 1,549 | |
| Treasury stock | | | (739 | ) | | | (1,549 | ) |
| | | | | | | |
| Total stockholders’ equity | | | 209,440 | | | | 123,073 | |
| |
| Long-term debt, net of current maturities | | | 79,611 | | | | 86,382 | |
| | | | | | | |
| Total capitalization | | | 289,051 | | | | 209,455 | |
| | | | | | | |
| | | | | | | | | |
Current Liabilities | | | | | | | | |
| Current portion of long-term debt | | | 6,636 | | | | 6,636 | |
| Short-term borrowing | | | 30,023 | | | | 33,000 | |
| Accounts payable | | | 9,157 | | | | 9,587 | |
| Customer deposits and refunds | | | 4,410 | | | | 5,558 | |
| Accrued interest | | | 1,003 | | | | 1,023 | |
| Dividends payable | | | 2,959 | | | | 2,082 | |
| Accrued compensation | | | 2,450 | | | | 1,994 | |
| Regulatory liabilities | | | 5,934 | | | | 2,429 | |
| Other accrued liabilities | | | 1,647 | | | | 1,602 | |
| | | | | | | |
| Total current liabilities | | | 64,219 | | | | 63,911 | |
| | | | | | | |
| | | | | | | | | |
Deferred Credits and Other Liabilities | | | | | | | | |
| Deferred income taxes | | | 16,494 | | | | 13,204 | |
| Deferred investment tax credits | | | 157 | | | | 193 | |
| Regulatory liabilities | | | 695 | | | | 598 | |
| Environmental liabilities | | | 531 | | | | 511 | |
| Other pension and benefit costs | | | 5,674 | | | | 6,914 | |
| Accrued asset removal cost | | | 18,248 | | | | 17,740 | |
| Other liabilities | | | 4,594 | | | | 3,708 | |
| | | | | | | |
| Total deferred credits and other liabilities | | | 46,393 | | | | 42,868 | |
| | | | | | | |
| | | | | | | | | |
| Other commitments and contingencies | | | | | | | | |
| | | | | | | | | |
Total Capitalization and Liabilities | | $ | 399,663 | | | $ | 316,234 | |
| | | | | | | |
The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation and Subsidiaries
Schedule I
Parent Company Condensed Financial Statements
Chesapeake Utilities Corporation (Parent)
Condensed Statements of Income
| | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2009 | | | 2008 | | | 2007 | |
| (in thousands) | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Operating Revenues | | $ | 101,577 | | | $ | 103,733 | | | $ | 119,402 | |
| | | | | | | | | | | | | |
Operating Expenses | | | | | | | | | | | | |
| Cost of sales | | | 62,339 | | | | 65,446 | | | | 83,076 | |
| Operations | | | 18,487 | | | | 16,039 | | | | 16,454 | |
| Transaction-related costs | | | 1,478 | | | | 1,153 | | | | — | |
| Maintenance | | | 1,535 | | | | 1,303 | | | | 1,409 | |
| Depreciation and amortization | | | 4,194 | | | | 3,918 | | | | 4,032 | |
| Other taxes | | | 3,564 | | | | 3,380 | | | | 2,989 | |
| | | | | | | | | | |
| Total operating expenses | | | 91,597 | | | | 91,239 | | | | 107,960 | |
| | | | | | | | | | |
Operating Income | | | 9,980 | | | | 12,494 | | | | 11,442 | |
| Income from equity investments | | | 12,042 | | | | 7,781 | | | | 7,679 | |
| Other income (loss), net of other expenses | | | (30 | ) | | | (106 | ) | | | 220 | |
| Interest charges | | | 3,066 | | | | 3,026 | | | | 3,195 | |
| | | | | | | | | | |
Income Before Income Taxes | | | 18,926 | | | | 17,143 | | | | 16,146 | |
| Income taxes | | | 3,029 | | | | 3,536 | | | | 2,948 | |
| | | | | | | | | | |
Net Income | | $ | 15,897 | | | $ | 13,607 | | | $ | 13,198 | |
| | | | | | | | | | |
The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation and Subsidiaries
Schedule I
Parent Company Condensed Financial Statements
Chesapeake Utilities Corporation (Parent)
Condensed Statements of Cash Flows
| | | | | | | | | | | | | |
| For the Years Ended December 31, | | 2009 | | | 2008 | | | 2007 | |
| (in thousands) | | | | | | | | | | | | |
| |
Operating Activities | | | | | | | | | | | | |
| Net Income | | $ | 15,897 | | | $ | 13,607 | | | $ | 13,198 | |
| Adjustments to reconcile net income to net operating cash: | | | | | | | | | | | | |
| Equity earnings in subsidiaries | | | (12,042 | ) | | | (7,781 | ) | | | (7,679 | ) |
| Depreciation and amortization | | | 4,190 | | | | 3,918 | | | | 4,268 | |
| Depreciation and accretion included in other costs | | | 1,773 | | | | 1,389 | | | | 1,646 | |
| Deferred income taxes, net | | | 2,821 | | | | 5,147 | | | | (156 | ) |
| Gain on sale of assets | | | — | | | | — | | | | (205 | ) |
| Unrealized (gain) loss on investments | | | (212 | ) | | | 509 | | | | (123 | ) |
| Employee benefits and compensation | | | 1,217 | | | | 152 | | | | 1,004 | |
| Share based compensation | | | 1,306 | | | | 820 | | | | 990 | |
| Other, net | | | 8 | | | | 11 | | | | 7 | |
| Changes in assets and liabilities: | | | | | | | | | | | | |
| Sale (purchase) of investments | | | (146 | ) | | | (201 | ) | | | 229 | |
| Accounts receivable and accrued revenue | | | (16,770 | ) | | | (3,016 | ) | | | (2,315 | ) |
| Propane inventory, storage gas and other inventory | | | 3,383 | | | | (3,854 | ) | | | 1,427 | |
| Regulatory assets | | | (1,825 | ) | | | 606 | | | | (526 | ) |
| Prepaid expenses and other current assets | | | (1,050 | ) | | | (516 | ) | | | (179 | ) |
| Other deferred charges | | | (72 | ) | | | (8 | ) | | | (61 | ) |
| Long-term receivables | | | 181 | | | | 199 | | | | 76 | |
| Accounts payable and other accrued liabilities | | | 9,832 | | | | 3,323 | | | | (403 | ) |
| Income taxes receivable | | | 2,791 | | | | (3,113 | ) | | | 147 | |
| Accrued interest | | | (20 | ) | | | 158 | | | | 32 | |
| Customer deposits and refunds | | | (1,147 | ) | | | 34 | | | | 1,423 | |
| Accrued compensation | | | 352 | | | | 377 | | | | 326 | |
| Regulatory liabilities | | | 3,603 | | | | (2,379 | ) | | | 1,941 | |
| Other liabilities | | | 886 | | | | (23 | ) | | | (151 | ) |
| | | | | | | | | | |
| Net cash provided by operating activities | | | 14,956 | | | | 9,359 | | | | 14,916 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Investing Activities | | | | | | | | | | | | |
| Property, plant and equipment expenditures | | | (12,615 | ) | | | (16,328 | ) | | | (15,464 | ) |
| Proceeds from sale of assets | | | — | | | | — | | | | 205 | |
| Proceeds from investments | | | 1,000 | | | | 500 | | | | 900 | |
| Cash acquired in the merger, net of cash paid | | | (16 | ) | | | — | | | | — | |
| Environmental expenditures | | | (86 | ) | | | (480 | ) | | | (228 | ) |
| | | | | | | | | | |
| Net cash used by investing activities | | | (11,717 | ) | | | (16,308 | ) | | | (14,587 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Financing Activities | | | | | | | | | | | | |
| Inter-company receivable (payable) | | | 13,379 | | | | 4,302 | | | | (4,331 | ) |
| Common stock dividends | | | (7,957 | ) | | | (7,810 | ) | | | (7,030 | ) |
| Issuance of stock for Dividend Reinvestment Plan | | | 392 | | | | (118 | ) | | | 299 | |
| Change in cash overdrafts due to outstanding checks | | | 835 | | | | (684 | ) | | | (541 | ) |
| Net borrowing (repayment) under line of credit agreements | | | (3,812 | ) | | | (11,980 | ) | | | 18,651 | |
| Proceeds from issuance of long-term debt | | | — | | | | 29,961 | | | | — | |
| Repayment of long-term debt | | | (6,637 | ) | | | (7,637 | ) | | | (7,637 | ) |
| | | | | | | | | | |
| Net cash provided by (used in) financing activities | | | (3,800 | ) | | | 6,034 | | | | (589 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Net Decrease in Cash and Cash Equivalents | | | (561 | ) | | | (915 | ) | | | (260 | ) |
Cash and Cash Equivalents — Beginning of Period | | | 1,534 | | | | 2,449 | | | | 2,709 | |
| | | | | | | | | | |
Cash and Cash Equivalents — End of Period | | $ | 973 | | | $ | 1,534 | | | $ | 2,449 | |
| | | | | | | | | | |
The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation and Subsidiaries
Schedule I
Parent Company Condensed Financial Statements
Notes to Financial Information
These condensed financial statements represent the financial information of Chesapeake Utilities Corporation (parent company).
For information concerning Chesapeake’s debt obligations, see Item 8 under the heading “Notes to the Consolidated Financial Statements — Note J, Long-term Debt, and Note K, Short-term Borrowing.”
For information concerning Chesapeake’s material contingencies and guarantees, see Item 8 under the heading “Notes to the Consolidated Financial Statements — Note O, Environmental Commitments and Contingencies, and Note P, Other Commitments and Contingencies.”
Chesapeake’s wholly-owned subsidiaries are accounted for using the equity method of accounting.
Chesapeake Utilities Corporation and Subsidiaries
Schedule II
Valuation and Qualifying Accounts
| | | | | | | | | | | | | | | | | | | | | |
| | | Balance at | | | Additions | | | | | | | | |
| | | Beginning of | | | Charged to | | | Other | | | | | | | Balance at End | |
| For the Year Ended December 31, | | Year | | | Income | | | Accounts(1) | | | Deductions(2) | | | of Year | |
Reserve Deducted From Related Assets Reserve for Uncollectible Accounts | | | | | | | | | | | | | | | | | | | | |
(In thousands) | | | | | | | | | | | | | | | | | | | | |
2009 | | $ | 1,159 | | | $ | 1,138 | | | $ | 616 | | | $ | (1,304 | ) | | $ | 1,609 | |
| 2008 | | $ | 952 | | | $ | 1,186 | | | $ | 241 | | | $ | (1,220 | ) | | $ | 1,159 | |
| 2007 | | $ | 662 | | | $ | 818 | | | $ | 26 | | | $ | (554 | ) | | $ | 952 | |
| | |
| (1) | | Recoveries. |
|
| (2) | | Uncollectible accounts charged off. |
