Form 10-K
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, 2010
Commission File Number: 001-11590
Chesapeake Utilities Corporation
(Exact name of registrant as specified in its charter)
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State of Delaware
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51-0064146 |
(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.) |
909 Silver Lake Boulevard, Dover, Delaware 19904
(Address of principal executive offices, including zip code)
302-734-6799
(Registrants telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
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Title of each class
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Name of each exchange on which registered |
Common Stock par value per share $0.4867
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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 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 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 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).
Yes o. No o.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§
229.405 of this chapter) is not contained herein, and will not be contained, to the best of
registrants 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. 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 company in Rule 12b-2 of the Exchange Act. (Check
one):
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Large accelerated filer o
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Accelerated filer þ
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Non-accelerated filer o
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Smaller Reporting Company o |
Indicate by a check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Act). Yes o. No þ.
The aggregate market value of the common shares held by non-affiliates of Chesapeake Utilities
Corporation as of June 30, 2010, 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 $297.6 million.
As of
February 28, 2011, 9,529,333 shares of common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the 2011 Annual Meeting of Stockholders are incorporated by
reference in Part II and Part III.
Chesapeake Utilities Corporation
Form 10-K
YEAR ENDED DECEMBER 31, 2010
TABLE OF CONTENTS
GLOSSARY OF KEY TERMS
Frequently used abbreviations, acronyms, or terms used in this report:
Subsidiaries of Chesapeake Utilities Corporation
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BravePoint
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BravePoint®, Inc., a wholly-owned subsidiary of Chesapeake Services Company,
which is a wholly-owned subsidiary of Chesapeake |
Chesapeake
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The Registrant, the Registrant and its subsidiaries, or the Registrants
subsidiaries, as appropriate in the context of the disclosure |
Company
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The Registrant, the Registrant and its subsidiaries or the Registrants
subsidiaries, as appropriate in the context of the disclosure |
ESNG
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Eastern Shore Natural Gas Company, a wholly-owned subsidiary of Chesapeake |
FPU
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Florida Public Utilities Company, a wholly-owned subsidiary of Chesapeake,
effective October 28, 2009 |
PESCO
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Peninsula Energy Services Company, Inc., a wholly-owned subsidiary of Chesapeake |
PIPECO
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Peninsula Pipeline Company, Inc., a wholly-owned subsidiary of Chesapeake |
Sharp
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Sharp Energy, Inc., a wholly-owned subsidiary of Chesapeakes and Sharps
subsidiary, Sharpgas, Inc. |
Xeron
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Xeron, Inc., a wholly-owned subsidiary of Chesapeake |
Regulatory Agencies
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Delaware PSC
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Delaware Public Service Commission |
DOT
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United States Department of Transportation |
EPA
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United States Environmental Protection Agency |
FASB
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Financial Accounting Standards Board |
FERC
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Federal Energy Regulatory Commission |
FDEP
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Florida Department of Environmental Protection |
Florida PSC
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Florida Public Service Commission |
IASB
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International Accounting Standards Board |
IRS
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Internal Revenue Service |
Maryland PSC
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Maryland Public Service Commission |
MDE
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Maryland Department of the Environment |
PSC
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Public Service Commission |
SEC
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Securities and Exchange Commission |
Accounting Standards Related
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ASC
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FASB Accounting Standards Codification TM |
ASU
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FASB Accounting Standards Update |
GAAP
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Generally Accepted Accounting Principles |
IFRS
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International Financial Reporting Standards |
FASB
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Financial Accounting Standards Board |
Other
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AS/SVE
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Air Sparging and Soil/Vapor Extraction |
BS/SVE
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Bio-Sparging and Soil/Vapor Extraction |
CDD
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Cooling Degree-Days |
Columbia
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Columbia Gas Transmission, LLC |
DSCP
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Directors Stock Compensation Plan |
Dts
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Dekatherms |
Dts/d
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Dekatherms per Day |
FCG
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Florida City Gas |
FGT
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Florida Gas Transmission Company |
FRP
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Fuel Retention Percentage |
GSR
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Gas Sales Service Rates |
Gulf
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Columbia Gulf Transmission Company |
Gulf Power
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Gulf Power Company |
Gulfstream
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Gulfstream Natural Gas System, LLC |
HDD
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Heating Degree-Days |
IGC
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Indiantown Gas Company |
Mcf
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Thousand Cubic Feet |
MGP
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Manufactured Gas Plant |
MWH
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Megawatt Hour |
NYSE
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New York Stock Exchange |
PIP
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Performance Incentive Plan |
RAP
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Remedial Action Plan |
S&P 500 Index
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Standard & Poors 500 Index |
Sanford Group
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FPU and Other Responsible Parties involved with the Sanford Environmental Site |
TETLP
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Texas Eastern Transmission, LP |
Transco
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Transcontinental Gas Pipe Line Company, LLC |
Part I
References in this document to Chesapeake, the Company, we, us and our mean
Chesapeake Utilities Corporation and/or its wholly-owned subsidiaries, as appropriate in the
context of the disclosure.
Safe Harbor for Forward-Looking Statements
We make statements in this Form 10-K that do not directly or exclusively relate to historical
facts. Such statements are forward-looking statements within the meaning of the Private
Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by
the use of forward-looking words, such as project, believe, expect, anticipate, intend,
plan, estimate, continue, potential, forecast or other similar words, or future or
conditional verbs such as may, will, should, would or could. These statements represent
our intentions, plans, expectations, assumptions and beliefs about future financial performance,
business strategy, projected plans and objectives of the Company. These statements are subject to
many risks and uncertainties. In addition to the risk factors described under Item 1A Risk
Factors, the following important factors, among others, could cause actual future results to
differ materially from those expressed in the forward-looking statements:
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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); |
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the outcomes of regulatory, tax, environmental and legal matters, including whether
pending matters are resolved within current estimates; |
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industrial, commercial and residential growth or contraction in our service
territories; |
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the weather and other natural phenomena, including the economic, operational and other
effects of hurricanes and ice storms; |
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the timing and extent of changes in commodity prices and interest rates; |
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general economic conditions, including any potential effects arising from terrorist
attacks and any consequential hostilities, other hostilities or other external factors
over which we have no control; |
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changes in environmental and other laws and regulations to which we are subject; |
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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; |
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declines in the market prices of equity securities and resultant cash funding
requirements for our defined benefit pension plans; |
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the creditworthiness of counterparties with which we are engaged in transactions; |
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growth in opportunities for our business units; |
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the extent of success in connecting natural gas and electric supplies to transmission
systems and in expanding natural gas and electric markets; |
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the effect of accounting pronouncements issued periodically by accounting
standard-setting bodies; |
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conditions of the capital markets and equity markets during the periods covered by the
forward-looking statements; |
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the ability to successfully execute, manage and integrate merger, acquisition or
divestiture plans, regulatory or other limitations imposed as a result of a merger,
acquisition or divestiture, and the success of the business following a merger,
acquisition or divestiture; |
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the ability to manage and maintain key customer relationships; |
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the ability to maintain key supply sources; |
Chesapeake Utilities Corporation 2010 Form 10-K Page 1
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the effect of spot, forward and future market prices on our distribution, wholesale
marketing and energy trading businesses; |
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the effect of competition on our businesses; |
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the ability to construct facilities at or below estimated costs; |
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changes in technology affecting our advanced information services business; and |
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operational and litigation risks that may not be covered by insurance. |
Item 1. Business.
(a) |
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Overview |
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We are a diversified utility company engaged in various energy and other 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 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
our 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 FPUs propane distribution subsidiary, Flo-Gas Corporation; and our
propane wholesale marketing operation through Xeron, Inc. (Xeron). We also have an advanced
information services subsidiary, BravePoint®, Inc. (BravePoint). |
(b) |
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Operating Segments |
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We are composed of three operating segments: |
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Regulated Energy. The regulated energy segment includes natural gas distribution,
electric distribution and natural gas transmission operations. All operations in this
segment are regulated, as to their rates and services, by the Public Service Commission
(PSC) having jurisdiction in each operating territory or by the Federal Energy Regulatory
Commission (FERC) in the case of ESNG. |
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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. |
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Other. The other segment consists primarily of the advanced information services
operation, unregulated subsidiaries that own real estate leased to Chesapeake and certain
corporate costs not allocated to other operations. |
The following table shows the size of each of our operating segments based on operating income for 2010
and net property, plant and equipment as of December 31, 2010:
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Net Property, Plant |
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(in thousands) |
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Operating Income |
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& Equipment |
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Regulated Energy |
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$ |
43,509 |
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84 |
% |
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$ |
414,622 |
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90 |
% |
Unregulated Energy |
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7,908 |
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15 |
% |
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35,658 |
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8 |
% |
Other |
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513 |
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1 |
% |
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12,477 |
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2 |
% |
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Total |
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$ |
51,930 |
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100 |
% |
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$ |
462,757 |
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100 |
% |
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Additional financial information by business segment is included in Item 8 under the heading
Notes to the Consolidated Financial Statements Note C, Segment Information.
Chesapeake Utilities Corporation 2010 Form 10-K Page 2
(i) |
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Regulated Energy |
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Our regulated energy segment provides natural gas distribution services in Delaware, Maryland
and Florida, electric distribution services in Florida and natural gas transmission services in
Delaware, Maryland, Pennsylvania and Florida. |
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Natural Gas Distribution |
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Natural gas supplies nearly one-fourth of the energy used in the United States. Due to its
efficiency, cleanliness and reliability, natural gas is growing increasingly popular. With 99
percent of the natural gas consumed in the United States coming from North America, supplies
of natural gas are abundant. Natural gas is delivered to customers through a safe and
efficient underground pipeline system. As the cleanest-burning fossil fuel, increased use of
natural gas can help address various environmental concerns today. |
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Our Delaware and Maryland natural gas distribution divisions serve 52,686 residential and
commercial customers and 177 industrial customers in central and southern Delaware and
Marylands Eastern Shore. For the year ended December 31, 2010, operating revenues and
deliveries by customer class for our Delaware and Maryland distribution divisions were as
follows: |
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Operating Revenues |
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Deliveries |
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(in thousands) |
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(Mcfs) |
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Residential |
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$ |
46,041 |
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57 |
% |
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2,881,073 |
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35 |
% |
Commercial |
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27,896 |
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34 |
% |
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2,145,143 |
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26 |
% |
Industrial |
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3,766 |
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5 |
% |
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3,020,907 |
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36 |
% |
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Subtotal |
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77,703 |
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96 |
% |
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8,047,123 |
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97 |
% |
Interruptible |
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655 |
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1 |
% |
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232,653 |
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3 |
% |
Other (1) |
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2,507 |
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3 |
% |
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Total |
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$ |
80,865 |
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100 |
% |
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8,279,776 |
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100 |
% |
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(1) |
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Operating revenues from other include unbilled revenue, rental of gas
properties, and other miscellaneous charges. |
Our Florida natural gas distribution operations consist of Chesapeakes Florida division
and FPUs natural gas operation, which was acquired in the merger with FPU in October 2009.
In August 2010, FPU added a new division through the purchase of the natural gas operating
assets of Indiantown Gas Company (IGC). On a combined basis, our Florida natural gas
distribution operations serve 61,053 residential customers and 6,314 commercial and industrial
customers in 20 counties in Florida. For the year ended December 31, 2010, operating revenues
and deliveries by customer class for our Florida natural gas distribution operations were as
follows:
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Operating Revenues |
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Deliveries |
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(in thousands) |
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(Mcfs) |
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Residential |
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$ |
27,742 |
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35 |
% |
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1,716,934 |
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8 |
% |
Commercial |
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39,006 |
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48 |
% |
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4,451,414 |
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20 |
% |
Industrial |
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13,043 |
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16 |
% |
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15,582,234 |
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72 |
% |
Other (1) |
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607 |
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1 |
% |
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12,723 |
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Total |
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$ |
80,398 |
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100 |
% |
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21,763,305 |
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100 |
% |
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(1) |
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Operating revenues from other include unbilled revenue, conservation
revenue, fees for billing services provided to third parties and other miscellaneous
charges. |
Chesapeake Utilities Corporation 2010 Form 10-K Page 3
Electric Distribution
Our Florida electric distribution operation, which was acquired in the FPU merger, distributes
electricity to 30,966 customers in four counties in northeast and northwest Florida. For the
year ended December 31, 2010, operating revenues and deliveries by customer class for the FPU
electric distribution operation were as follows:
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Operating Revenues |
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Deliveries |
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(in thousands) |
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(MWHs) |
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Residential |
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$ |
51,498 |
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55 |
% |
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347,040 |
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47 |
% |
Commercial |
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45,332 |
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48 |
% |
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332,322 |
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45 |
% |
Industrial |
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7,705 |
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8 |
% |
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66,580 |
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9 |
% |
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Subtotal |
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104,535 |
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111 |
% |
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745,942 |
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101 |
% |
Other (1) |
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(10,452 |
) |
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(11 |
%) |
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(6,286 |
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(1 |
%) |
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Total |
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$ |
94,083 |
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100 |
% |
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739,656 |
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100 |
% |
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(1) |
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Operating revenues from other include unbilled revenue, under
(over) recoveries of fuel cost, conservation revenue, other miscellaneous charges and
adjustments for pass-through taxes. |
Natural Gas Transmission
ESNG operates a 396-mile interstate pipeline system that transports natural gas from various
points in Pennsylvania to Chesapeakes 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. ESNG also provides swing transportation
service and contract storage services. For the year ended December 31, 2010, operating
revenues and deliveries by customer class for ESNG were as follows:
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Operating Revenues |
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Deliveries |
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(in thousands) |
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(Mcfs) |
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Local distribution companies |
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$ |
20,441 |
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|
76 |
% |
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|
10,848,108 |
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62 |
% |
Industrial |
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|
4,864 |
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18 |
% |
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|
4,794,442 |
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27 |
% |
Commercial |
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|
1,571 |
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6 |
% |
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|
1,962,890 |
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11 |
% |
Other (1) |
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|
41 |
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0 |
% |
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Subtotal |
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26,917 |
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100 |
% |
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|
17,605,440 |
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100 |
% |
Less: affiliated local distribution companies |
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(12,903 |
) |
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(48 |
%) |
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(5,853,083 |
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(33 |
%) |
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Total non-affiliated |
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$ |
14,014 |
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52 |
% |
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|
11,752,357 |
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|
67 |
% |
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(1) |
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Operating revenues from other sources are from rental of gas properties. |
PIPECO currently provides natural gas transportation services to a customer for a period
of 20 years beginning in January 2009 at a fixed monthly charge, through an eight-mile
pipeline located in Suwanee County, Florida, which PIPECO owns. For the year ended December
31, 2010, PIPECO had $264,000 in operating revenues under the contract.
Chesapeake Utilities Corporation 2010 Form 10-K Page 4
Supplies, Transmission and Storage
We believe that the availability of supply and transmission of natural gas and electricity is
adequate under existing arrangements to meet the anticipated needs of customers.
Natural Gas Distribution- Delaware and Maryland
Our Delaware and Maryland natural gas distribution divisions have both firm and interruptible
transportation service contracts with five interstate open access pipeline companies,
including the ESNG pipeline. These divisions are directly interconnected with the ESNG
pipeline, and have contracts with interstate pipelines upstream of ESNG, including
Transcontinental Gas Pipe Line Company LLC (Transco), Columbia Gas Transmission LLC
(Columbia), Columbia Gulf Transmission Company (Gulf) and Texas Eastern Transmission, LP
(TETLP). The Transco, Columbia and TETLP 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 pipelines is owned or operated by
an affiliate of the Company.
On April 8, 2010, our Delaware and Maryland divisions entered into a Precedent Agreement with
TETLP in conjunction with TETLPs new expansion project. Upon satisfaction of certain
conditions provided in the Precedent Agreement, the Delaware and Maryland divisions will execute
two firm transportation service contracts, one for our Delaware division for 28,986 Mcfs per day
and one for our Maryland division for 9,662 Mcfs per day, to be effective on the service
commencement date of the project, which is currently projected to occur in November 2012. The
new firm transportation service contracts between our Delaware and Maryland divisions and TETLP
will provide us with an additional direct interconnection with ESNGs transmission system and
access to new sources of natural gas supplies from other natural gas production regions,
including the Appalachian production region, thereby providing increased reliability and
diversity of supply. They will also provide our Delaware and Maryland divisions with additional
upstream transportation capacity to meet current customer demands and to plan for sustainable
growth. In December 2010, ESNG completed its mainline extension to interconnect with the TETLP
pipeline. Until TETLPs expansion project is completed, our Delaware and Maryland divisions
expect to utilize currently available capacity on a portion of TETLPs existing pipeline. For
the 2010 and 2011 winter season, our Delaware and Maryland divisions have contracted for 14,493 Mcfs
per day and 4,831 Mcfs per day, respectively, from TETLP.
The Delaware and Maryland divisions use their firm transportation supply resources to meet a
significant percentage of their projected demand requirements and they purchase natural gas
supplies on the spot market from various suppliers as needed to match firm supply and demand.
This gas is transported by the upstream pipelines and delivered to their interconnections with
ESNG. These divisions also have the capability to use propane-air peak-shaving to supplement or
displace spot market purchases.
Chesapeake Utilities Corporation 2010 Form 10-K Page 5
The following table shows the firm transportation 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 transportation |
|
|
Firm storage capacity |
|
|
|
|
|
capacity maximum |
|
|
maximum peak-day |
|
|
|
|
|
peak-day daily |
|
|
daily withdrawal |
|
|
|
Pipeline |
|
deliverability (Mcfs) |
|
|
(Mcfs) |
|
|
Expiration |
Transco |
|
|
20,699 |
|
|
|
6,190 |
|
|
Various dates between 2012 and 2028 |
Columbia |
|
|
17,836 |
|
|
|
7,946 |
|
|
Various dates between 2011 and 2020 |
Gulf |
|
|
850 |
|
|
|
|
|
|
Expires in 2014 |
TETLP |
|
|
14,493 |
|
|
|
|
|
|
Expires in 2012 |
ESNG |
|
|
64,602 |
|
|
|
4,006 |
|
|
Various dates between 2011 and 2027 |
Maryland
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm transportation |
|
|
Firm storage capacity |
|
|
|
|
|
capacity maximum |
|
|
maximum peak-day |
|
|
|
|
|
peak-day daily |
|
|
daily withdrawal |
|
|
|
Pipeline |
|
deliverability (Mcfs) |
|
|
(Mcfs) |
|
|
Expiration |
Transco |
|
|
5,921 |
|
|
|
2,909 |
|
|
Various dates between 2012 and 2013 |
Columbia |
|
|
6,473 |
|
|
|
3,539 |
|
|
Various dates between 2011 and 2018 |
Gulf |
|
|
570 |
|
|
|
|
|
|
Expires in 2014 |
TETLP |
|
|
4,831 |
|
|
|
|
|
|
Expires in 2012 |
ESNG |
|
|
21,380 |
|
|
|
2,228 |
|
|
Various dates between 2011 and 2027 |
The Delaware and Maryland divisions currently have contracts with several suppliers for the
purchase of firm natural gas supply in the amount of their capacities on the Transco and
Columbia pipelines.
Natural Gas Distribution- Florida
Chesapeakes Florida natural gas distribution division has firm transportation service contracts
with Florida Gas Transmission Company (FGT) and Gulfstream Natural Gas System, LLC
(Gulfstream). Pursuant to a program approved by the Florida Public Service Commission
(Florida PSC), all of the capacity under these agreements has been released to various
third-parties, including PESCO. Under the terms of these capacity release agreements,
Chesapeake is contingently liable to FGT and Gulfstream, should any party that acquired the
capacity through release fail to pay for the service.
Contracts by Chesapeakes Florida natural gas distribution division with FGT include: (a) a
contract, which expires on July 31, 2012, for daily firm transportation capacity of 17,175 Mcfs
for the months of November through April, capacity of 14,695 Mcfs for the months of May through
September, and 16,143 Mcfs for October; and (b) a contract for daily firm transportation
capacity of 974 Mcfs daily, which expires in 2015. Chesapeakes contract with Gulfstream is for
daily firm transportation capacity of 9,737 Mcfs and expires in 2022.
Chesapeake Utilities Corporation 2010 Form 10-K Page 6
FPU has the following firm transportation contracts with FGT:
(a) two contracts expiring in July 2020 for daily firm transportation capacity of:
|
|
|
|
|
|
|
Daily Firm |
|
|
|
Transportation Capacity |
|
|
|
(in Mcfs) |
|
January March |
|
|
28,647 |
|
April |
|
|
24,156 |
|
May September |
|
|
9,681 |
|
October |
|
|
10,210 |
|
November December |
|
|
28,647 |
|
(b) one contract expiring in February 2015 for daily firm transportation capacity of:
|
|
|
|
|
|
|
Daily Firm |
|
|
|
Transportation Capacity |
|
|
|
(in Mcfs) |
|
January April |
|
|
10,286 |
|
May October |
|
|
4,360 |
|
November December |
|
|
10,286 |
|
(c) one contract for daily firm transportation capacity of 1,774 Mcfs with various
partial expiration dates between 2016 and 2023.
FPU also has a firm transportation contract with Florida City Gas (FCG), expiring in 2013,
which provides daily firm transportation capacity of 292 Mcfs on its Pioneer Pipeline, and a
firm transportation contract with IGC, expiring in 2016, which provides daily firm
transportation capacity of 487 Mcfs on its distribution system.
FPU uses gas marketers and producers to procure all of 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
ESNG has three contracts with Transco for a total of 7,045 Mcfs of firm peak day storage
entitlements and total storage capacity of 278,264 Mcfs, each of which expires in 2013. ESNG
has retained these firm storage services in order to provide swing transportation service and
firm storage service to those customers that have requested such services.
Electric Distribution
Our electric distribution operation through FPU purchases all of its wholesale electricity from
two suppliers: Gulf Power Company (Gulf Power) and JEA (formerly known as Jacksonville
Electric Authority). Both of these contracts are all requirement contracts and they expire in
December 2019 and December 2017, respectively. The JEA contract provides generation,
transmission and distribution service to northeast Florida. The Gulf Power contract
provides generation, transmission and distribution service to northwest Florida.
Chesapeake Utilities Corporation 2010 Form 10-K Page 7
Competition
See discussion of competition in Item 7 under the heading Managements Discussion and Analysis
of Financial Condition and Results of Operations Competition.
Rates and Regulation
Our natural gas and electric distribution operations are subject to regulation by the Delaware,
Maryland and Florida PSCs with respect to various aspects of their business, including rates for
sales and transportation to all customers in each respective jurisdiction. All of our firm
distribution sales rates are subject to fuel cost recovery mechanisms, which match revenues with
natural 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.
ESNG is subject to regulation as an interstate pipeline by the FERC, which regulates the terms
and conditions of service and the rates ESNG can charge for its transportation and storage
services. PIPECO is subject to regulation by the Florida PSC.
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 Currrent Rates |
|
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.
On December 30, 2010, ESNG submitted a base rate filing to the FERC. See discussion of
regulatory activities in Item 7 under the heading Managements Discussion and Analysis of
Financial Condition and Results of Operations Rate Filings and Other Regulatory Activities.
Management monitors the achieved rates of return of each of our regulated energy operations in
order to ensure timely filing of rate cases.
Chesapeake Utilities Corporation 2010 Form 10-K Page 8
Regulatory Proceedings
See discussion of regulatory activities in Item 7 under the heading Managements 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 our residential and commercial natural gas distribution activities are affected by
seasonal variations in 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 reduce use of natural gas, while
sustained colder-than-normal temperatures will tend to increase 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 days 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 an effort to stabilize the level of net revenues collected from customers regardless 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 smaller commercial heating customers. A weather normalization adjustment is a
billing adjustment mechanism that is designed to eliminate the effect of deviations from average
seasonal temperatures on utility net revenues.
Delaware, like many other states, has been looking at ways to enable implementation of energy
efficiency and considering revenue decoupling, which is a mechanism for separating the revenue
needed to recover the fixed cost of delivery from the variable cost that fluctuates with the
amount of natural gas consumed. Since March of 2007, the Delaware Public Service Commission
(Delaware PSC) has been investigating whether to implement a revenue decoupling mechanism for
the natural gas distribution utilities. Recently, the Delaware PSC decided in response to a
decoupling request by another Delaware distribution utility that it would need a further review
of the implementation plan, including more customer education about decoupling and the greater
awareness of energy efficiency programs, prior to approving the request. Our Delaware natural
gas distribution operation is currently evaluating the feasibility of decoupling. In light of
the Delaware PSCs recent actions, it is uncertain as to when our Delaware natural gas
distribution operation will file a request for decoupling or whether it will be required to file
such request by the Delaware PSC.
Our unregulated energy segment provides natural gas marketing, propane distribution and propane
wholesale marketing services to customers.
Chesapeake Utilities Corporation 2010 Form 10-K Page 9
Natural Gas Marketing
Our natural gas marketing subsidiary, PESCO, provides natural gas supply and supply
management services to 2,486 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 the regulated utilities that
deliver the gas, or directly, through its own billing capabilities. For the year ended
December 31, 2010, PESCOs operating revenues and deliveries were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
|
|
Deliveries |
|
State |
|
(in thousands) |
|
|
(Mcfs) |
|
Florida |
|
$ |
47,441 |
|
|
|
86 |
% |
|
|
8,236,014 |
|
|
|
84 |
% |
Delmarva |
|
|
8,006 |
|
|
|
14 |
% |
|
|
1,538,895 |
|
|
|
16 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
55,447 |
|
|
|
100 |
% |
|
|
9,774,909 |
|
|
|
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 2011. 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.
Propane Distribution
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.
Sharp, our propane distribution subsidiary, serves 34,243 customers throughout Delaware, the
Eastern Shore of Maryland and Virginia, and southeastern Pennsylvania. Our Florida propane
distribution subsidiary provides propane distribution services to 13,857 customers in parts
of Florida. For the year ended December 31, 2010, operating revenues and total gallons sold
by our Delmarva and Florida propane distribution operations were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
|
|
Total Gallons Sold |
|
State |
|
(in thousands) |
|
|
(in thousands) |
|
Delmarva |
|
$ |
68,558 |
|
|
|
79 |
% |
|
|
32,617 |
|
|
|
82 |
% |
Florida |
|
|
18,725 |
|
|
|
21 |
% |
|
|
6,995 |
|
|
|
18 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
87,283 |
|
|
|
100 |
% |
|
|
39,612 |
|
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Propane Wholesale Marketing
Xeron, our 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 propane wholesale price
volatility and supply levels. In 2010, Xeron had operating revenues totaling approximately
$1.8 million, net of the associated cost of propane sold. For further discussion of Xerons
trading and wholesale marketing activities, market risks and controls that monitor Xerons
risks, see Item 7 under the heading Managements 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.
Chesapeake Utilities Corporation 2010 Form 10-K Page 10
Supplies, 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.
Our propane distribution operations use trucks and railroad cars to transport propane from
refineries, natural gas processing plants or pipeline terminals to our bulk storage facilities.
We own bulk propane storage facilities with an aggregate capacity of approximately 3.0 million
gallons at various locations in Delaware, Maryland, Pennsylvania, Virginia and Florida. From
these storage facilities, propane is delivered by bobtail trucks, owned and operated by us, to
tanks located at the customers premises.
Competition
See discussion of competition in Item 7 under the heading Managements Discussion and Analysis
of Financial Condition and Results of Operations Competition.
Rates and Regulation
Natural 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.
Seasonality of Propane Revenues
Revenues from our 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 reduce propane use, while
sustained colder-than-normal temperatures will tend to increase consumption.
The other segment consists primarily of our advanced information services subsidiary, 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, is headquartered in Norcross, Georgia,
and provides domestic and international clients with information technology services and
solutions for both enterprise and e-business applications.
Other Subsidiaries
Skipjack, Inc. 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 incorporated in Delaware.
Chesapeake Utilities Corporation 2010 Form 10-K Page 11
(c) |
|
Additional information about the Business |
A discussion of capital expenditures by business segment and capital expenditures for
environmental remediation facilities is included in Item 7 under the heading Managements
Discussion and Analysis of Financial Condition and Results of Operations Liquidity and Capital
Resources.
As of December 31, 2010, we had a total of 734 employees, 160 of whom are union employees
represented by three labor unions: the International Brotherhood of Electrical Workers, the
International Chemical Workers Union and United Food and Commercial Workers Union, all of whose
collective bargaining agreements expire in 2013.
|
(iii) |
|
Financial Information about Geographic Areas |
All of our material operations, customers, and assets are located in the United States.
(d) |
|
Available Information |
As a public company, we file annual, quarterly and other reports, as well as our annual proxy
statement and other information, with the Securities and Exchange Commission (SEC). The public
may read and copy any materials that we file with the SEC at the SECs Public Reference Room at
100 F Street, N.E., Washington, DC 20549-5546; 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 SECs Internet website is
www.sec.gov. We make available, free of charge, on our Internet website, our 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 our Internet website is www.chpk.com. The content of this
website is not part of this report.
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 our Internet website. We 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 Corporate Governance Guidelines on Director Independence, which
conform to the NYSE listing standards on director independence. Each of these documents also is
available on our Internet website or may be obtained by writing to: Corporate Secretary; c/o
Chesapeake Utilities Corporation, 909 Silver Lake Boulevard, Dover, DE 19904.
If we make any amendment to, or grant a waiver of, any provision of the Business Code of Ethics
and Conduct or the Code of Ethics for Financial Officers applicable to our principal executive
officer, president, principal financial officer, principal accounting officer or controller, the
amendment or waiver will be disclosed within four business days in a press release, by website
disclosure, or by filing a current report on Form 8-K with the SEC.
Our Chief Executive Officer certified to the NYSE on June 3, 2010 that, as of that date, he was
unaware of any violation by Chesapeake of the NYSEs corporate governance listing standards.
Chesapeake Utilities Corporation 2010 Form 10-K Page 12
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 our
regulated and unregulated businesses. Refer to the section entitled Managements 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 our operations and/or
financial performance.
Financial Risks
The anticipated 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 operating efficiencies.
Although we have achieved significant synergies, cost savings and operating efficiencies since the
merger, there can be no assurance that these benefits will be sustained in the future, or
additional benefits will be achieved in the future. Failure to sustain these benefits or achieve
additional benefits in the future will adversely affect our expected future performance.
We are currently in discussions
with the Office of Public Counsel of Florida and the Florida PSC staff regarding the benefits
and cost savings of the merger, current and expected earnings level as well as the recovery of
approximately $34.9 million in purchase premium and $2.2 million in merger-related costs.
If we
fail to obtain the necessary approval to earn a return on the purchase premium and merger-related
costs and treat the amortization as allowable operating costs, we may be required to expense the
amortization of these assets without recovery which will adversely
affect our financial performance for the related periods. We may also be required to pass on to ratepayers,
some, or all of the increased earnings generated from cost savings, resulting from the merger.
Instability and volatility in the financial markets could have a negative impact on our growth
strategy.
Our 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 finance our growth. Specifically, we rely on access to both short-term
and long-term capital markets as a significant source of liquidity for capital requirements not
satisfied by the cash flows from our operations. Currently, $40 million of the total $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.
A downgrade in our credit rating could adversely affect our access to capital markets and our cost
of capital.
Our ability to obtain adequate and cost-effective capital depends on our credit ratings, which are
greatly affected by our 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 covenant obligations, if triggered, may affect our financial 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 our financial
condition.
Chesapeake Utilities Corporation 2010 Form 10-K Page 13
The continuation of recent economic conditions could adversely affect our customers and
negatively impact our financial results.
A continued downturn in the economies of the regions in which we operate, 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. These economic conditions have slowed the growth in our customer base and cash flows.
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.
An increase in interest rates may adversely affect our results of operations and cash flows.
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 lines of credit to finance accounts receivable and storage gas inventories, as
well as 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. To help cope with the effects of inflation on our capital
investments and returns, we seek rate increases from regulatory commissions for regulated
operations and closely monitor the returns of our unregulated operations. There can be no
assurance that we will be able to obtain adequate and timely rate increases 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. There 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.
Our operations are exposed to market risks, beyond our control, which could adversely affect our
financial results and capital requirements.
Our natural gas marketing and propane wholesale marketing operations 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 our 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.
Chesapeake Utilities Corporation 2010 Form 10-K Page 14
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 our 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 Chesapeakes and
FPUs pension plans have fluctuated significantly 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. We began the process of integrating operations, both
geographically and organizationally, immediately after the merger and this process is still
on-going today. While significant progress has been made in integration, we continue to combine
and enhance various systems, facilities and personnel deployment. Throughout the integration
process, we are subject to employee workforce factors, including loss of key employees,
availability of qualified personnel, collective bargaining agreements with unions and work
stoppages that could affect our business and financial condition. Continued integration efforts
may divert managements focus and resources from other strategic opportunities. The diversion of
managements attention and any delays or difficulties encountered in connection with continued
integration activities 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 natural gas and propane distribution operations are sensitive to fluctuations in weather
conditions, which directly influence the volume of natural gas and propane sold and delivered. A
significant portion of our natural gas and propane distribution revenues is derived from the sales
and deliveries 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 electricity,
increased supply costs and higher prices for customers.
Our electric operations, while generally less seasonal than natural gas and propane sales as
electricity is used for both heating and cooling in our service areas, 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 beyond our control, such
as weather, closings of generation facilities and refineries. If we are unable to obtain sufficient
natural gas, electricity and propane supplies to meet demand, results in those businesses may be
adversely affected.
Chesapeake Utilities Corporation 2010 Form 10-K Page 15
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 transmission 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 sufficient natural gas supplies, 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 and electric transmission markets, our own on-system resources, as
well as the characteristics of our markets. Our financial condition and results of operations
would be materially and adversely affected if the future availability of these capacities were
insufficient to meet future customer demands for natural gas and electricity. Currently, FPUs
natural gas is transported primarily through one pipeline system. Any interruption to that system
could adversely affect our ability to meet the demands of FPUs customers and our earnings.
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/Electric. Higher natural gas prices can significantly increase the cost of gas
billed to our natural gas customers. Increases in the cost of coal and other fuels can
significantly increase the cost of electricity billed to our electric customers. Such cost
increases generally have no immediate effect on our revenues and net income because of our
regulated fuel cost recovery mechanisms. Our net income, however, may be reduced by higher
expenses that we may incur for uncollectible customer accounts and by lower volumes of natural gas
and electricity deliveries when customers reduce 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 gas and electricity as energy sources and consequently have an 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 due 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.
Chesapeake Utilities Corporation 2010 Form 10-K Page 16
Operating events affecting public safety and the reliability our natural gas and electric
distribution systems could adversely affect the results of operations, cash flows and financial
condition.
Our business is exposed to operational events, such as major leaks, mechanical problems and
accidents, that could affect the public safety and reliability of our 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 we are unable to recover from customers, through the
regulatory process, all or some of these costs and our 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.
Because we operate in a competitive environment, we may lose customers to competitors which could
adversely affect our results of operations, cash flows and financial condition.
Natural Gas. Our natural gas marketing operations compete with third-party suppliers to
sell natural gas to commercial and industrial customers. Our natural gas transmission and
distribution operations compete with interstate pipelines when our transmission and/or distribution
customers are located close enough to a 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 other propane distributors,
primarily on the basis of service and price. Some of our competitors have significantly greater
resources. Our ability to grow the propane distribution business is contingent upon capturing
additional market share, expanding new service territories, and successfully utilizing pricing
programs that retain and grow our customer base. Failure to retain and grow our customer base in
our propane gas operations would have an adverse effect on our results of operations, cash flows
and financial condition.
Our propane wholesale marketing operations compete with various marketers, many of which have
significantly greater resources and are able to obtain price or volumetric advantages.
Changes in technology may adversely affect our advanced information services subsidiarys results
of operations, cash flows and financial condition.
BravePoint participates in a market that is characterized by rapidly changing technology and
accelerating product introduction cycles. The success of our advanced information services
subsidiary 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.
Chesapeake Utilities Corporation 2010 Form 10-K Page 17
Our use of derivative instruments may adversely affect our results of operations.
Fluctuating commodity prices may affect our earnings and financing costs because our propane
distribution and wholesale marketing operations 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. 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 condition may be adversely affected.
Changes in customer growth may affect earnings and cash flows.
Our ability to increase gross margins in our regulated energy and unregulated propane distribution
businesses is dependent upon growth in the residential construction market, adding new commercial
and industrial customers and conversion of customers to natural gas, electricity or propane from
other energy sources. Slowdowns in these markets may adversely affect our gross margin in our
regulated energy or propane distribution businesses, earnings and cash flows.
Our businesses are capital intensive, and the costs of capital projects may be significant.
Our 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 full recovery of such
capital costs is not permitted in future regulatory proceedings.
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. 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. The occurrence of any of these events could
adversely affect our results of operations, cash flows and financial condition.
Chesapeake Utilities Corporation 2010 Form 10-K Page 18
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.
Regulatory and Legal Risks
Regulation of our 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 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 regulated operations will be able to obtain such approvals or maintain
currently authorized rates of return. When our earnings from the regulated utilities exceed the
authorized rate of return, these commissions may require us to refund the excess earnings or reduce
our rates charged to customers in the future.
We are required to detail known benefits, synergies, cost savings and cost increases resulting from
the FPU merger and present the information in the come-back filing to the Florida PSC by April
29, 2011 (within 18 months of the FPU merger). We also intend to seek for the recovery of the
purchase premium and merger-related costs from the FPU merger. We are currently in discussions
with the Office of Public Counsel of Florida regarding the come-back filing and the recovery of
the purchase premium and merger-related costs. The outcome of such discussions or the ultimate
outcome of the come-back filing, are unknown at this time.
We are dependent upon construction of new facilities to support future growth in earnings in our
natural gas and electric distribution and natural 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 from 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, transporting/ 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 the amount of $51 million
covering general liabilities of our 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.
Chesapeake Utilities Corporation 2010 Form 10-K Page 19
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 and the purchase of the operating assets from IGC resulted in approximately
$34.9 million in purchase premium which is currently recorded as goodwill. We intend to seek
regulatory approval to include the purchase premium and approximately $2.2 million in
merger-related costs 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
demonstrate the benefits of the merger, the regulatory environment in Florida and the 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.
We may face certain regulatory and financial risks related to climate change legislation.
A number of proposals to limit greenhouse gas emissions, measured in carbon dioxide equivalent
units, are pending, or at least being considered, at regional, federal and international levels.
These proposals would require us to measure and potentially limit greenhouse gas emissions from our
energy operations and our customers or purchase allowances for such emissions. While we cannot
predict with certainty the extent of these limitations or when they will become effective, these
actions could:
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increase our costs related to operations, energy efficiency activities and compliance; |
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affect the demand for natural gas, electricity and propane; and |
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increase the prices we charge our energy customers. |
The occurrence of any such legislation could adversely affect our results of operations, financial
condition and cash flows. If our regulated energy operations are unable to recover from customers
through the regulatory process all or some of these costs and our authorized rate of return on
these costs, this also could adversely affect our results of operations, financial condition and
cash flows.
We may face certain regulatory and financial risks related to pipeline safety legislation.
A number of proposals to implement increased oversight over pipeline operations and increased
investment in facilities to inspect pipeline facilities, upgrade pipeline facilities, or control
the impact of a breach of such facilities are pending at the federal level. Additional operating
expenses and capital expenditures may be necessary to remain in compliance with the increased
federal oversight resulting from such proposals. While we cannot predict with certainty the extent
of these expenses and expenditures or when they will become effective, the adoption of such
legislation could adversely affect our results of operations, financial conditions and cash flows.
If our regulated natural gas operations are unable to recover from customers through the regulatory
process all or some of these costs and our authorized rate of return on these costs, this also
could adversely affect our results of operations, financial condition and cash flows.
Chesapeake Utilities Corporation 2010 Form 10-K Page 20
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. 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.
To date, we have been able to recover, through regulatory rate mechanisms, the costs associated
with the remediation of former MGP sites. There 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 MGP 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.
Pending environmental matters, particularly with respect to FPUs site in West Palm Beach, Florida,
may have a materially adverse effect on our 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 our 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.
The site with the most potential exposure is the former West Palm Beach MGP. In November 2010, we
presented a new proposed strategy with an aggressive remedial action plan to expedite remediation
of this site, and the Florida Department of Environmental Protection (the FDEP) agreed with the
proposal to implement a phased approach. In February 2011, FDEP approved the interim Remedial
Action Plan (RAP) for the east parcel of this site, contingent upon certain conditions, and we
are currently implementing the plan. Our current estimate of total remediation costs and expenses
for the West Palm Beach site based on the most recently proposed remedial action plan is between
$5.1 million and $13.3 million. This estimate does not include any costs associated with
relocation of our operations from the site, which is necessary to implement the remedial action,
and any potential costs associated with re-development of the properties. Actual costs may also be
higher or lower than the range of current estimate based upon the final remedy required by FDEP.
As of December 31, 2010, we had recorded $358,000 in environmental liabilities related to
Chesapeakes MGP sites in Maryland and Winter Haven, Florida, representing our estimate of the
future costs associated with those sites. We had recorded approximately $1.3 million in assets for
future recovery of environmental costs to be received from our customers through our approved
rates. As of December 31, 2010, we had recorded approximately $11.6 million in environmental
liabilities related to FPUs MGP sites in Florida, primarily related to the West Palm Beach site.
Such amount represents our estimate as of December 31, 2010, 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 $11.6 million recorded as
environmental liabilities related to FPUs MGP sites in Florida as of December 31, 2010, we have
recovered approximately $7.8 million of environmental costs from insurance and customers through
rates, and have recorded approximately $6.2 million in assets for future recovery of environmental
costs to be received from FPUs customers through approved rates.
Chesapeake Utilities Corporation 2010 Form 10-K Page 21
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 previously described.
Item 1B. Unresolved Staff Comments.
None.
Item 2. Properties.
(a) General
We own offices and operate 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, Indiantown, Marianna, Lantana, Lauderhill, Fernandina Beach
and Winter Haven, Florida. We rent office space in Dover, Ocean View, and South Bethany, Delaware;
Fernandina and Lecanto, Florida; Chincoteague and Belle Haven, Virginia; Easton, Maryland; Honey
Brook and Allentown, Pennsylvania; Houston, Texas; and Norcross, Georgia. In general, we believe
that our offices and facilities are adequate for the uses for which they are employed.
(b) Natural Gas Distribution
Our Delmarva natural gas distribution operation owns over 1,127 miles of natural gas distribution
mains (together with related service lines, meters and regulators) located in our Delaware and
Maryland service areas. Our Florida natural gas distribution operations, including Chesapeakes
Florida division and FPU in its service areas, own 2,451 miles of natural gas distribution mains
(and related equipment). In addition, we have adequate gate stations to handle receipt of the
gas in each of the distribution systems. We also own facilities in Delaware and Maryland, which we
use for propane-air injection during periods of peak demand.
(c) Natural Gas Transmission
ESNG owns and operates approximately 396 miles of transmission pipeline, extending from supply
interconnects at Parkesburg, Pennsylvania; Daleville, Pennsylvania; Honey Brook, Pennsylvania; and
Hockessin, Delaware, to approximately 80 delivery points in southeastern Pennsylvania, Delaware and
the Eastern Shore of Maryland.
PIPECO owns and operates approximately eight miles of transmission pipeline in Suwanee County,
Florida.
(d) Electric Distribution
The Companys electric distribution operation owns and operates 20 miles of electric transmission
line located in northeast Florida and 1,128 miles of electric distribution line located in
northeast and northwest Florida.
(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 by our
Company. Our Florida-based propane distribution operation owns 24 bulk propane storage facilities
with a total capacity of 642,000 gallons. Xeron does not own physical storage facilities or
equipment to transport propane; however, it leases propane storage and pipeline capacity from
non-affiliated third-parties.
Chesapeake Utilities Corporation 2010 Form 10-K Page 22
(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: West Palm Beach, DeBary, Inglis,
Indiantown, Marianna, Lantana, Lauderhill and Fernandina Beach, Florida. FPUs natural gas
distribution operation owns 1,659 miles of natural gas distribution mains (and related equipment)
in its service areas. FPUs electric distribution operation owns and operates 20 miles of electric
transmission line located in northeast Florida and 1,128 miles of electric distribution line
located in northeast and northwest Florida. FPUs propane distribution operation owns 24 bulk
propane storage facilities with a total capacity of 642,000 gallons located in south and central
Florida.
Item 3. Legal Proceedings.
(a) General
As disclosed in Item 8 under the heading Notes to the Consolidated Financial Statements Note Q,
Other Commitments and Contingencies, we are involved in various legal actions and claims arising
in the normal course of business. We are 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 our
consolidated financial position, results of operations or cash flows.
(b) Environmental
See discussion of environmental commitments and contingencies in Item 8 under the heading Notes to
the Consolidated Financial Statements Note P, Environmental Commitments and Contingencies.
Item 4. Removed and Reserved
Item 4A. Executive Officers of the Registrant.
Set forth below are the names, ages, and positions of executive officers of the registrant with
their recent business experience. The age of each officer is as of the filing date of this report.
|
|
|
|
|
|
|
Name |
|
|
Age |
|
|
Position |
Michael P. McMasters
|
|
|
52 |
|
|
President and Chief Executive Officer |
Beth W. Cooper
|
|
|
44 |
|
|
Senior Vice President and Chief Financial Officer |
Stephen C. Thompson
|
|
|
50 |
|
|
Senior Vice President and President, ESNG |
Joseph Cummiskey
|
|
|
39 |
|
|
Vice President and President, PESCO |
Elaine B. Bittner
|
|
|
41 |
|
|
Vice President of Strategic Development |
Michael P. McMasters is President and Chief Executive Officer of Chesapeake. Mr.
McMasters assumed the role of Chief Executive Officer effective January 1, 2011 and was
appointed as President on March 1, 2010. Prior to these appointments, Mr. McMasters served as
Chief Operating Officer since 2008, Senior Vice President since 2004 and Chief Financial Officer
of Chesapeake since 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.
Beth W. Cooper was appointed as Senior Vice President and Chief Financial Officer in
September 2008 in addition to her duties as Treasurer and Corporate Secretary. Prior to this
appointment, Ms. Cooper served as Vice President and Corporate Secretary of Chesapeake Utilities
Corporation since July 2005. She has served as Treasurer of Chesapeake since 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 & Youngs Entrepreneurial Services Group.
Chesapeake Utilities Corporation 2010 Form 10-K Page 23
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.
Joseph Cummiskey was appointed as Vice President of Chesapeake and President of PESCO in
December 2009. Mr. Cummiskey joined Chesapeake in December 2005 as 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 Chesapeake,
Mr. Cummiskey was employed as a Natural Gas Liquids Regional Director for Ferrell North America.
In that position, he was responsible for the purchasing and distribution of Ferrells propane
supply.
Elaine B. Bittner was appointed as Vice President of Strategic Development in June 2010.
Prior to this appointment, Ms. Bittner served as Vice President of ESNG since 2005. She
previously served as Director of ESNG, Director of Customer Services and Regulatory Affairs for
ESNG, Director of Environmental Affairs for Chesapeake, Manager of Environmental Affairs and
Environmental Engineer. Prior to joining Chesapeake, Ms. Bittner was a Project Chemist, Client
Consultant and Environmental Lab Chemist in the environmental industry specializing in
environmental analysis and reporting related to volatile organic compounds.
Part II
|
|
|
Item 5. |
|
Market for the Registrants Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities. |
(a) Common Stock Price Ranges, Common Stock Dividends and Shareholder Information:
Our common stock is listed on the NYSE under the symbol CPK. The high, low and closing prices of
our common stock and dividends declared per share for each calendar quarter during the years 2010
and 2009 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Declared |
|
|
|
Quarter Ended |
|
High |
|
|
Low |
|
|
Close |
|
|
Per Share |
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31 |
|
$ |
32.25 |
|
|
$ |
28.22 |
|
|
$ |
29.80 |
|
|
$ |
0.315 |
|
|
|
June 30 |
|
|
32.20 |
|
|
|
28.01 |
|
|
|
31.40 |
|
|
|
0.330 |
|
|
|
September 30 |
|
|
36.93 |
|
|
|
30.24 |
|
|
|
36.22 |
|
|
|
0.330 |
|
|
|
December 31 |
|
|
42.20 |
|
|
|
35.00 |
|
|
|
41.52 |
|
|
|
0.330 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
Holders
At December 31, 2010, there were 2,482 holders of record of Chesapeake common stock.
Chesapeake Utilities Corporation 2010 Form 10-K Page 24
Dividends
We have paid a cash dividend to common stock shareholders for 50 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. We declared quarterly cash dividends on our common stock in 2010
and 2009, totaling $1.305 per share and $1.250 per share, respectively.
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 restrictive 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
accrued on and after January 1, 2001. As of December 31, 2010, Chesapeakes cumulative
consolidated net income base was $128.9 million, offset by Restricted Payments of $76.2 million,
leaving $52.7 million of cumulative net income free of restrictions.
Each series of FPUs 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 2022, which provided that FPU cannot make dividend or other restricted payments in excess
of the sum of $2.5 million plus FPUs consolidated net income accrued on and after January 1, 1992.
As of December 31, 2010, FPU had a cumulative net income base of $65.9 million, offset by
restricted payments of $37.6 million, leaving $28.3 million of cumulative net income of FPU free of
restrictions based on this covenant.
Recent Sales of Unregistered Securities
No securities were sold during the year 2010 that were not registered under the Securities Act of
1933, as amended.
(b) Purchases of Equity Securities by the Issuer
The following table sets forth information on purchases by or on behalf of Chesapeake of shares of
its common stock during the quarter ended December 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2010
through October 31, 2010 (1) |
|
|
258 |
|
|
$ |
37.58 |
|
|
|
|
|
|
|
|
|
November 1, 2010
through November 30, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 1, 2010 through December 31, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
258 |
|
|
$ |
37.58 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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, 258 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 no later than March 31, 2011, in
connection with the Companys Annual Meeting to be held on or about May 4, 2011 and, is
incorporated herein by reference.
Chesapeake Utilities Corporation 2010 Form 10-K Page 25
(c) Chesapeake Utilities Corporation Common Stock Performance Graph
The following Stock Performance graph compares cumulative total shareholder return on a
hypothetical investment in our common stock during the five fiscal years ended December 31, 2010,
with the cumulative total shareholder return on a hypothetical investment in both (i) the Standard
& Poors 500 Index (S&P 500 Index), and (ii) an industry index consisting of Chesapeake and 11 of
the companies in the current Edward Jones Natural Gas Distribution Group, a published listing of
selected gas distribution utilities results. The Compensation Committee utilizes the Edward Jones
Natural Gas Distribution Group as our peer group to which our performance is compared for purposes
of determining the level of long-term performance awards earned by our named executives.
The eleven companies in the Edward Jones Natural Gas Distribution Group industry index include: AGL
Resources, Inc., Atmos Energy Corporation, Delta Natural Gas Company, Inc., Gas Natural, 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 comparison assumes $100 was invested on December 31, 2005 in our 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 our
common stock.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2006 |
|
|
2007 |
|
|
2008 |
|
|
2009 |
|
|
2010 |
|
Chesapeake |
|
$ |
100 |
|
|
$ |
103 |
|
|
$ |
111 |
|
|
$ |
114 |
|
|
$ |
121 |
|
|
$ |
161 |
|
Industry Index |
|
$ |
100 |
|
|
$ |
119 |
|
|
$ |
123 |
|
|
$ |
132 |
|
|
$ |
136 |
|
|
$ |
155 |
|
S&P 500 Index |
|
$ |
100 |
|
|
$ |
116 |
|
|
$ |
122 |
|
|
$ |
77 |
|
|
$ |
97 |
|
|
$ |
112 |
|
Chesapeake Utilities Corporation 2010 Form 10-K Page 26
Item 6. Selected Financial Data
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31, |
|
2010 |
|
|
2009(2) |
|
|
2008 |
|
Operating(1) |
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Regulated Energy |
|
$ |
269,934 |
|
|
$ |
139,099 |
|
|
$ |
116,468 |
|
Unregulated Energy |
|
|
146,793 |
|
|
|
119,973 |
|
|
|
161,290 |
|
Other |
|
|
10,819 |
|
|
|
9,713 |
|
|
|
13,685 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
$ |
427,546 |
|
|
$ |
268,785 |
|
|
$ |
291,443 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
|
|
|
|
|
|
|
|
|
|
Regulated Energy |
|
$ |
43,509 |
|
|
$ |
26,900 |
|
|
$ |
24,733 |
|
Unregulated Energy |
|
|
7,908 |
|
|
|
8,158 |
|
|
|
3,781 |
|
Other |
|
|
513 |
|
|
|
(1,322 |
) |
|
|
(35 |
) |
|
|
|
|
|
|
|
|
|
|
Total operating income |
|
$ |
51,930 |
|
|
$ |
33,736 |
|
|
$ |
28,479 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations |
|
$ |
26,056 |
|
|
$ |
15,897 |
|
|
$ |
13,607 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Gross property, plant and equipment |
|
$ |
584,385 |
|
|
$ |
543,905 |
|
|
$ |
381,689 |
|
Net property, plant and equipment |
|
$ |
462,757 |
|
|
$ |
436,587 |
|
|
$ |
280,671 |
|
Total assets |
|
$ |
670,993 |
|
|
$ |
615,811 |
|
|
$ |
385,795 |
|
Capital expenditures (1) |
|
$ |
46,955 |
|
|
$ |
26,294 |
|
|
$ |
30,844 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalization |
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders equity |
|
$ |
226,239 |
|
|
$ |
209,781 |
|
|
$ |
123,073 |
|
Long-term debt, net of current maturities |
|
|
89,642 |
|
|
|
98,814 |
|
|
|
86,422 |
|
|
|
|
|
|
|
|
|
|
|
Total capitalization |
|
$ |
315,881 |
|
|
$ |
308,595 |
|
|
$ |
209,495 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt |
|
|
9,216 |
|
|
|
35,299 |
|
|
|
6,656 |
|
Short-term debt |
|
|
63,958 |
|
|
|
30,023 |
|
|
|
33,000 |
|
|
|
|
|
|
|
|
|
|
|
Total capitalization and short-term financing |
|
$ |
389,055 |
|
|
$ |
373,917 |
|
|
$ |
249,151 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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) |
|
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 additional discussions and presentation of pro
forma results. |
|
(3) |
|
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 2010 Form 10-K Page 27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 (3) |
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
2002 |
|
|
2001 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
128,850 |
|
|
$ |
124,631 |
|
|
$ |
124,563 |
|
|
$ |
98,139 |
|
|
$ |
92,079 |
|
|
$ |
82,098 |
|
|
$ |
87,444 |
|
|
115,190 |
|
|
|
94,320 |
|
|
|
90,995 |
|
|
|
67,607 |
|
|
|
59,197 |
|
|
|
40,728 |
|
|
|
56,970 |
|
|
14,246 |
|
|
|
12,249 |
|
|
|
13,927 |
|
|
|
12,209 |
|
|
|
12,292 |
|
|
|
12,430 |
|
|
|
13,992 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
258,286 |
|
|
$ |
231,200 |
|
|
$ |
229,485 |
|
|
$ |
177,955 |
|
|
$ |
163,568 |
|
|
$ |
135,256 |
|
|
$ |
158,406 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
21,809 |
|
|
$ |
18,593 |
|
|
$ |
16,248 |
|
|
$ |
16,258 |
|
|
$ |
16,219 |
|
|
$ |
14,867 |
|
|
$ |
14,060 |
|
|
5,174 |
|
|
|
3,675 |
|
|
|
4,197 |
|
|
|
3,197 |
|
|
|
4,310 |
|
|
|
1,158 |
|
|
|
1,259 |
|
|
1,131 |
|
|
|
1,064 |
|
|
|
1,476 |
|
|
|
722 |
|
|
|
1,050 |
|
|
|
580 |
|
|
|
902 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
28,114 |
|
|
$ |
23,332 |
|
|
$ |
21,921 |
|
|
$ |
20,177 |
|
|
$ |
21,579 |
|
|
$ |
16,605 |
|
|
$ |
16,221 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
13,218 |
|
|
$ |
10,748 |
|
|
$ |
10,699 |
|
|
$ |
9,686 |
|
|
$ |
10,079 |
|
|
$ |
7,535 |
|
|
$ |
7,341 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
352,838 |
|
|
$ |
325,836 |
|
|
$ |
280,345 |
|
|
$ |
250,267 |
|
|
$ |
234,919 |
|
|
$ |
229,128 |
|
|
$ |
216,903 |
|
$ |
260,423 |
|
|
$ |
240,825 |
|
|
$ |
201,504 |
|
|
$ |
177,053 |
|
|
$ |
167,872 |
|
|
$ |
166,846 |
|
|
$ |
161,014 |
|
$ |
381,557 |
|
|
$ |
325,585 |
|
|
$ |
295,980 |
|
|
$ |
241,938 |
|
|
$ |
222,058 |
|
|
$ |
223,721 |
|
|
$ |
222,229 |
|
$ |
30,142 |
|
|
$ |
49,154 |
|
|
$ |
33,423 |
|
|
$ |
17,830 |
|
|
$ |
11,822 |
|
|
$ |
13,836 |
|
|
$ |
26,293 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
119,576 |
|
|
$ |
111,152 |
|
|
$ |
84,757 |
|
|
$ |
77,962 |
|
|
$ |
72,939 |
|
|
$ |
67,350 |
|
|
$ |
67,517 |
|
|
63,256 |
|
|
|
71,050 |
|
|
|
58,991 |
|
|
|
66,190 |
|
|
|
69,416 |
|
|
|
73,408 |
|
|
|
48,409 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
182,832 |
|
|
$ |
182,202 |
|
|
$ |
143,748 |
|
|
$ |
144,152 |
|
|
$ |
142,355 |
|
|
$ |
140,758 |
|
|
$ |
115,926 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,656 |
|
|
|
7,656 |
|
|
|
4,929 |
|
|
|
2,909 |
|
|
|
3,665 |
|
|
|
3,938 |
|
|
|
2,686 |
|
|
45,664 |
|
|
|
27,554 |
|
|
|
35,482 |
|
|
|
5,002 |
|
|
|
3,515 |
|
|
|
10,900 |
|
|
|
42,100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
236,152 |
|
|
$ |
217,412 |
|
|
$ |
184,159 |
|
|
$ |
152,063 |
|
|
$ |
149,535 |
|
|
$ |
155,596 |
|
|
$ |
160,712 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chesapeake Utilities Corporation 2010 Form 10-K Page 28
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31, |
|
2010 |
|
|
2009(3) |
|
|
2008 |
|
Common Stock Data and Ratios |
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share from continuing operations (1) |
|
$ |
2.75 |
|
|
$ |
2.17 |
|
|
$ |
2.00 |
|
Diluted earnings per share from continuing operations (1) |
|
$ |
2.73 |
|
|
$ |
2.15 |
|
|
$ |
1.98 |
|
Return on average equity from continuing operations (1) |
|
|
11.6 |
% |
|
|
11.2 |
% |
|
|
11.2 |
% |
Common equity / total capitalization |
|
|
71.6 |
% |
|
|
68.0 |
% |
|
|
58.7 |
% |
Common equity / total capitalization and short-term financing |
|
|
58.2 |
% |
|
|
56.1 |
% |
|
|
49.4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Book value per share |
|
$ |
23.75 |
|
|
$ |
22.33 |
|
|
$ |
18.03 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market price: |
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
$ |
42.200 |
|
|
$ |
35.000 |
|
|
$ |
34.840 |
|
Low |
|
$ |
28.010 |
|
|
$ |
22.020 |
|
|
$ |
21.930 |
|
Close |
|
$ |
41.520 |
|
|
$ |
32.050 |
|
|
$ |
31.480 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average number of shares outstanding |
|
|
9,474,554 |
|
|
|
7,313,320 |
|
|
|
6,811,848 |
|
Shares outstanding at year-end |
|
|
9,524,195 |
|
|
|
9,394,314 |
|
|
|
6,827,121 |
|
Registered common shareholders |
|
|
2,482 |
|
|
|
2,670 |
|
|
|
1,914 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends declared per share |
|
$ |
1.31 |
|
|
$ |
1.25 |
|
|
$ |
1.21 |
|
Dividend yield (annualized) (2) |
|
|
3.2 |
% |
|
|
3.9 |
% |
|
|
3.9 |
% |
Payout ratio from continuing operations (1) (4) |
|
|
47.6 |
% |
|
|
57.6 |
% |
|
|
60.5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional Data |
|
|
|
|
|
|
|
|
|
|
|
|
Customers (5) |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas distribution |
|
|
120,230 |
|
|
|
117,887 |
|
|
|
65,201 |
|
Electric distribution |
|
|
30,966 |
|
|
|
31,030 |
|
|
|
|
|
Propane distribution |
|
|
48,100 |
|
|
|
48,680 |
|
|
|
34,981 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes(6) |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas deliveries (in Mcfs) |
|
|
41,795,438 |
|
|
|
44,586,158 |
|
|
|
39,778,067 |
|
Electric Distribution (in MWHs) |
|
|
739,656 |
|
|
|
105,739 |
|
|
|
|
|
Propane distribution (in thousands of gallons) |
|
|
39,612 |
|
|
|
32,546 |
|
|
|
27,956 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heating degree-days (Delmarva Peninsula) |
|
|
|
|
|
|
|
|
|
|
|
|
Actual HDD |
|
|
4,831 |
|
|
|
4,729 |
|
|
|
4,431 |
|
10-year average HDD (normal) |
|
|
4,528 |
|
|
|
4,462 |
|
|
|
4,401 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Propane bulk storage capacity (in thousands of gallons) |
|
|
3,041 |
|
|
|
3,042 |
|
|
|
2,471 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total employees (1) (7) |
|
|
734 |
|
|
|
757 |
|
|
|
448 |
|
|
|
|
(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) |
|
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 additional 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 2010 Form 10-K Page 29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006(8) |
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
2002 |
|
|
2001 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1.96 |
|
|
$ |
1.78 |
|
|
$ |
1.83 |
|
|
$ |
1.68 |
|
|
$ |
1.80 |
|
|
$ |
1.37 |
|
|
$ |
1.37 |
|
$ |
1.94 |
|
|
$ |
1.76 |
|
|
$ |
1.81 |
|
|
$ |
1.64 |
|
|
$ |
1.76 |
|
|
$ |
1.37 |
|
|
$ |
1.35 |
|
|
11.5 |
% |
|
|
11.0 |
% |
|
|
13.2 |
% |
|
|
12.8 |
% |
|
|
14.4 |
% |
|
|
11.2 |
% |
|
|
11.1 |
% |
|
65.4 |
% |
|
|
61.0 |
% |
|
|
59.0 |
% |
|
|
54.1 |
% |
|
|
51.2 |
% |
|
|
47.8 |
% |
|
|
58.2 |
% |
|
50.6 |
% |
|
|
51.1 |
% |
|
|
46.0 |
% |
|
|
51.3 |
% |
|
|
48.8 |
% |
|
|
43.3 |
% |
|
|
42.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
17.64 |
|
|
$ |
16.62 |
|
|
$ |
14.41 |
|
|
$ |
13.49 |
|
|
$ |
12.89 |
|
|
$ |
12.16 |
|
|
$ |
12.45 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
37.250 |
|
|
$ |
35.650 |
|
|
$ |
35.780 |
|
|
$ |
27.550 |
|
|
$ |
26.700 |
|
|
$ |
21.990 |
|
|
$ |
19.900 |
|
$ |
28.000 |
|
|
$ |
27.900 |
|
|
$ |
23.600 |
|
|
$ |
20.420 |
|
|
$ |
18.400 |
|
|
$ |
16.500 |
|
|
$ |
17.375 |
|
$ |
31.850 |
|
|
$ |
30.650 |
|
|
$ |
30.800 |
|
|
$ |
26.700 |
|
|
$ |
26.050 |
|
|
$ |
18.300 |
|
|
$ |
19.800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,743,041 |
|
|
|
6,032,462 |
|
|
|
5,836,463 |
|
|
|
5,735,405 |
|
|
|
5,610,592 |
|
|
|
5,489,424 |
|
|
|
5,367,433 |
|
|
6,777,410 |
|
|
|
6,688,084 |
|
|
|
5,883,099 |
|
|
|
5,778,976 |
|
|
|
5,660,594 |
|
|
|
5,537,710 |
|
|
|
5,424,962 |
|
|
1,920 |
|
|
|
1,978 |
|
|
|
2,026 |
|
|
|
2,026 |
|
|
|
2,069 |
|
|
|
2,130 |
|
|
|
2,171 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1.18 |
|
|
$ |
1.16 |
|
|
$ |
1.14 |
|
|
$ |
1.12 |
|
|
$ |
1.10 |
|
|
$ |
1.10 |
|
|
$ |
1.10 |
|
|
3.7 |
% |
|
|
3.8 |
% |
|
|
3.7 |
% |
|
|
4.2 |
% |
|
|
4.2 |
% |
|
|
6.0 |
% |
|
|
5.6 |
% |
|
60.2 |
% |
|
|
65.2 |
% |
|
|
62.3 |
% |
|
|
66.7 |
% |
|
|
61.1 |
% |
|
|
80.3 |
% |
|
|
80.3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
62,884 |
|
|
|
59,132 |
|
|
|
54,786 |
|
|
|
50,878 |
|
|
|
47,649 |
|
|
|
45,133 |
|
|
|
42,741 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34,143 |
|
|
|
33,282 |
|
|
|
32,117 |
|
|
|
34,888 |
|
|
|
34,894 |
|
|
|
34,566 |
|
|
|
35,530 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34,820,050 |
|
|
|
34,321,160 |
|
|
|
34,980,939 |
|
|
|
31,429,494 |
|
|
|
29,374,818 |
|
|
|
27,934,715 |
|
|
|
27,263,542 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,785 |
|
|
|
24,243 |
|
|
|
26,178 |
|
|
|
24,979 |
|
|
|
25,147 |
|
|
|
21,185 |
|
|
|
23,080 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,504 |
|
|
|
3,931 |
|
|
|
4,792 |
|
|
|
4,553 |
|
|
|
4,715 |
|
|
|
4,161 |
|
|
|
4,368 |
|
|
4,376 |
|
|
|
4,372 |
|
|
|
4,436 |
|
|
|
4,389 |
|
|
|
4,409 |
|
|
|
4,393 |
|
|
|
4,446 |
|
|
|
|
|
2,441 |
|
|
|
2,315 |
|
|
|
2,315 |
|
|
|
2,045 |
|
|
|
2,195 |
|
|
|
2,151 |
|
|
|
1,958 |
|
|
|
|
|
445 |
|
|
|
437 |
|
|
|
423 |
|
|
|
426 |
|
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439 |
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455 |
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458 |
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(8) |
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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 2010 Form 10-K Page 30
Managements Discussion and Analysis
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Item 7. |
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Managements Discussion and Analysis of Financial Condition and Results of Operations |
This section provides managements discussion of Chesapeake and its consolidated subsidiaries,
with specific information on results of operations, liquidity and capital resources, as well as
discussion on how certain accounting principles affect our financial statements. It includes
managements interpretation of financial results of the Company and its operating segments, the
factors affecting these results, the major factors expected to affect future operating results as
well as 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, Risk Factors. They should be considered in connection with 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.
The following discussions and those later in the document on operating income and segment results
include use of the term gross margin. Gross margin is determined by deducting the cost of sales
from operating revenue. Cost of sales includes the purchased cost of natural gas, electricity and
propane and the cost of labor spent on direct revenue-producing activities. Gross margin should
not be considered an alternative to operating income or net income, which are determined in
accordance with GAAP. We believe that gross margin, although a non-GAAP measure, is useful and
meaningful to investors as a basis for making investment decisions. It provides investors with
information that demonstrates the profitability achieved by the Company under its allowed rates for
regulated energy operations and under its competitive pricing structure for unregulated natural gas
marketing, and propane distribution operations. Chesapeakes 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, for comparison purposes, includes only FPUs
results of operations or exclude FPUs results from the consolidated results of operations for the
periods from the merger closing (October 28, 2009) to December 31, 2009 and in 2010. Certain other
information is presented, which, for comparison purposes, excludes 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 Chesapeakes performance, we believe that the portions
of the presentation which include only the FPU results, or which exclude FPUs financial results
for the post-merger period and merger-related costs provide a helpful comparative basis for
investors to understand Chesapeakes performance.
The
following discussion sometimes refers to legacy
Chesapeake and words of similar import. Such terms and phrases
mean our results, excluding the impacts from the FPU merger and
merger-related costs
(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:
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executing a capital investment program in pursuit of organic growth opportunities that
generate returns equal to or greater than our cost of capital; |
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expanding the regulated energy distribution and transmission businesses into new
geographic areas and providing new services in our current service territories; |
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expanding the propane distribution business in existing and new markets through
leveraging our community gas system services and our bulk delivery capabilities; |
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utilizing our expertise across our various businesses to improve overall performance; |
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enhancing marketing channels to attract new customers; |
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providing reliable and responsive customer service to retain existing customers; |
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maintaining a capital structure that enables us to access capital as needed; |
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maintaining a consistent and competitive dividend for shareholders; and |
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creating and maintaining a diversified customer base, energy portfolio and utility
foundation. |
Chesapeake Utilities Corporation 2010 Form 10-K Page 31
Managements Discussion and Analysis
(b) Highlights and Recent Developments
(in thousands except per share)
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Increase |
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Increase |
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For the Years Ended December 31, |
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2010 |
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2009 |
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(decrease) |
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2009 |
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2008 |
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(decrease) |
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Net income |
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$ |
26,056 |
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$ |
15,897 |
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$ |
10,159 |
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$ |
15,897 |
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$ |
13,607 |
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$ |
2,290 |
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Earnings per common stock diluted |
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$ |
2.73 |
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$ |
2.15 |
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$ |
0.58 |
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$ |
2.15 |
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$ |
1.98 |
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$ |
0.17 |
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Components of net income: |
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Legacy Cheapeake |
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$ |
17,192 |
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$ |
15,303 |
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$ |
1,889 |
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$ |
15,303 |
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$ |
14,299 |
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$ |
1,004 |
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FPU |
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9,339 |
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1,829 |
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7,510 |
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1,829 |
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1,829 |
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Merger-related costs |
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(475 |
) |
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(1,235 |
) |
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760 |
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(1,235 |
) |
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(692 |
) |
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(543 |
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Total |
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$ |
26,056 |
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$ |
15,897 |
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$ |
10,159 |
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$ |
15,897 |
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$ |
13,607 |
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$ |
2,290 |
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Components of EPS diluted |
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Legacy Chesapeake (1) |
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$ |
2.44 |
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$ |
2.20 |
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$ |
0.24 |
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$ |
2.20 |
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$ |
2.08 |
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$ |
0.12 |
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FPU(2) |
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$ |
0.34 |
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$ |
0.12 |
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$ |
0.22 |
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$ |
0.12 |
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$ |
0.00 |
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$ |
0.12 |
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Merger-related costs |
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$ |
(0.05 |
) |
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$ |
(0.17 |
) |
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$ |
0.12 |
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$ |
(0.17 |
) |
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$ |
(0.10 |
) |
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$ |
(0.07 |
) |
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Total |
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$ |
2.73 |
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$ |
2.15 |
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$ |
0.58 |
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$ |
2.15 |
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$ |
1.98 |
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$ |
0.17 |
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(1) |
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Calculated based on weighted average common shares outstanding for the period,
which excludes the shares issued in the FPU merger. |
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(2) |
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Represents the additional EPS generated by FPUs results since the merger. |
On October 28, 2009, we completed a merger with FPU. 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. We also now serve approximately 31,000 electric distribution customers in northwest and
northeast Florida as a result of the merger. FPUs results have been included in our consolidated
results since the completion of the merger.
Excluding the impacts from the FPU merger and merger-related costs, our diluted earnings per
share from legacy Chesapeake businesses increased by 11 percent and six percent in 2010 and 2009,
respectively, compared to the respective prior year.
The following is a summary of key factors affecting our businesses and their impacts on our
results. More detailed discussion and analysis are provided in the Results of Operations
section. Since FPUs results for the period prior to the merger were not included in our results,
the year-over-year variances resulting from the factors described below as they relate to FPU are
limited to the period after the merger.
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Weather. We measure weather based on the number of heating degree-days (HDD) for the
natural gas and propane distribution operations and the number of HDD and the number of
cooling degree-days (CDD) for the electric distribution operation. We use historical averages as the normal weather for this analysis. |
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HDD on the Delmarva Peninsula in 2010 increased by 102, or two percent, compared to 2009,
and by 303, or seven percent, compared to normal. HDD on the Delmarva Peninsula in 2009
increased by 298, or seven percent, compared to 2008, and by 267, or six percent, compared
to normal. We estimate that colder weather contributed approximately $679,000 and $1.6
million in additional gross margin for our Delmarva natural gas and propane distribution
operations in 2010 and 2009, respectively, compared to the respective prior year. We also
estimate that the effect of the colder-than-normal temperatures on the Delmarva Peninsula in
2010 was increased gross margin of $1.6 million for our Delmarva natural gas and propane
distribution operations. |
Chesapeake Utilities Corporation 2010 Form 10-K Page 32
Managements Discussion and Analysis
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The colder temperatures in 2010 in Florida produced average HDD that were 590, or 65
percent, higher than 2009 and 582, or 63 percent, higher than normal. The average HDD in
2009 and 2008 were fairly consistent and did not fluctuate significantly from the normal
weather. The warmer temperatures in the summer of 2010 also produced average CDD for the
year that were 89, or three percent, higher than the prior year and 141, or five percent,
higher than normal. We estimate that colder weather in the winter months and warmer weather
in the summer months contributed approximately $1.4 million in additional gross margin for
our Florida natural gas and electric distribution operations in 2010, compared to 2009. |
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Growth. Despite the continued slowdown in growth and overall economic conditions on the
Delmarva Peninsula, our Delmarva natural gas distribution operations achieved two percent
growth in average residential customers in both 2010 and 2009, compared to the respective
prior year. These growth rates exceeded the industrys growth rates. In addition to the
residential growth, in 2010, our Delmarva natural gas distribution operations added 10
large commercial and industrial customers with total expected annual margin of
$748,000, as they were able to convert these customers to natural gas from other energy
sources due to the pricing advantage of natural gas and its environmentally-friendly
features. In total, customer growth for the Delmarva natural gas distribution operations
generated additional margin of $1.1 million and $1.2 million in 2010 and 2009,
respectively, compared to the respective prior year. The addition of certain industrial
customers in 2010 also positioned us to further extend our natural gas distribution and
transmission infrastructure in southern Delaware to serve other potential customers in the
same area. |
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ESNG continued to expand its infrastructure and add new transportation services. The
additional margin generated from the continued expansions and new services, net of the
expired services, was $1.1 million and $1.8 million in 2010 and 2009, respectively, compared
to the respective prior year. Although not affecting our results in 2010, ESNG completed
the eight-mile mainline extension in December 2010 to interconnect with the TETLP pipeline.
ESNG commenced its new transportation services to Chesapeakes Delaware and Maryland
divisions in January 2011. The new transportation services have a three-year phase-in from
19,324 Mcfs per day to 38,647 Mcfs per day, providing estimated annualized margin of $2.4
million in 2011, $3.9 million in 2012 and $4.3 million thereafter. |
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FPUs natural gas distribution operation experienced growth in commercial and industrial
customers in 2010, which contributed $196,000 in additional margin in 2010. Chesapeakes
Florida natural gas distribution division experienced a slight growth in customers in 2010
after experiencing a net customer loss in 2009, including a loss of three large industrial
customers, in Florida in late 2008 and 2009, which decreased its margin by $190,000 in 2009
compared to 2008. Customer growth in the Florida electric and propane distribution
operations was flat. |
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Rates and Regulatory Matters. On January 14, 2010, new rates for Chesapeakes Florida
natural gas distribution division became effective. The new rates for Chesapeakes Florida
natural gas distribution division represented an annual rate increase of approximately $2.5
million and generated $2.3 million in increased margin in 2010, net of the impact from the
interim rates in 2009, compared to 2009. An annual rate increase of approximately $8.0
million for FPUs natural gas distribution operation pursuant to the settlement agreement
also became effective on January 14, 2010. The Florida PSC previously issued an Order in
May 2009, approving a rate increase for FPUs natural gas distribution operation. The
subsequent protest by the Office of Public Counsel of Florida led to this settlement
agreement between the Office of Public Counsel and FPU, which the Florida PSC approved in
December 2009. |
Chesapeake Utilities Corporation 2010 Form 10-K Page 33
Managements Discussion and Analysis
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The merger with FPU and the purchase of the operating assets of IGC resulted in
approximately $34.9 million in purchase premium, which we intend to seek the recovery
through rates. We also intend to seek the recovery of approximately $2.2 million in
merger-related costs attributed to the natural gas operations.
Our Florida natural gas distribution operations are required to submit to the Florida PSC by
April 29, 2011 data that details benefits, synergies, cost savings and cost increases
resulting from the merger. We are currently in the process of discussing with the Office of
Public Counsel and the Florida PSC staff the benefits and cost savings resulted from the merger, current and expected
operating results of the regulated operations in Florida, and recovery of the purchase
premium and merger-related costs. Our results in 2010 reflect an accrual of $750,000 by
FPUs natural gas distribution operation for the regulatory risk associated
with its earnings, merger benefits and recovery of purchase premium
and merger-related costs. Also reflected in our 2010 results were approximately $75,000 of
the costs associated with these discussions, which were expensed in 2010. |
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Although not affecting our results in 2010, ESNG filed a proposed rate increase with the
FERC on December 30, 2010. ESNG expects this base rate proceeding to be completed in 2011.
ESNG expensed approximately $147,000 in costs associated with this filing in 2010. |
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Propane Prices. A sharp decline in propane prices in the winter months when our
propane inventory is at its highest level exposes us to inventory valuation risk as GAAP
requires us to re-value the propane inventory using the lower-of-cost-or-market approach.
We have implemented various propane supply and inventory strategies to hedge such risk.
In late 2008, a sharp decline in propane prices resulted in inventory and swap valuation
adjustments of $1.8 million in 2008, which lowered the propane inventory cost of our
Delmarva propane distribution operation 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. Retail margins returned to more normal levels in
2010. |
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Continued lack of volatility in wholesale propane prices reduced the opportunities for our
propane wholesale marketing subsidiary, Xeron, and decreased its trading volume by 13
percent and 57 percent in 2010 and 2009, respectively, compared to the respective prior
year. The lower volumes reduced gross margin by approximately $441,000 and $1.0 million for
2010 and 2009, respectively, over the prior year. |
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Natural Gas Spot Sale Opportunities. Our unregulated natural gas marketing subsidiary,
PESCO, entered into spot sales in 2009 with a refinery on the Delmarva Peninsula, which
contributed significantly to PESCOs gross margin increase of $1.0 million in 2009. The
absence of spot sales opportunities to the same customer in 2010 reduced PESCOs margin in
2010, compared to 2010. Spot sales are not predictable, and, therefore, are not included
in our long-term financial plans or forecasts. |
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Interest Rates. We continued to experience low short-term interest rates throughout
2010 and 2009 as our short-term weighted average interest rate approximated 1.77 percent in
2010, 1.28 percent in 2009, and 2.79 percent in 2008. The level of our short-term
borrowings in 2010 increased over 2009 as we used a new short-term term loan facility to
finance the redemption of $29.1 million of FPUs 6.85 percent and 4.90 percent secured
first mortgage bonds prior to their respective maturities. 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 timing of our capital expenditures. |
Chesapeake Utilities Corporation 2010 Form 10-K Page 34
Managements Discussion and Analysis
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Advanced Information Services. Our advanced information services subsidiary, BravePoint,
generated $759,000 in operating income in 2010, compared to an operating loss of $229,000
in 2009. Increased billable consulting hours in 2010 and cost containment actions
implemented throughout 2009 contributed to the increased operating results. |
(c) Critical Accounting Policies
We prepare our financial statements in accordance with 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. We base our estimates on historical experience and on various 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. Since most of our businesses are regulated and the accounting methods used by
these businesses must comply with the requirements of the regulatory 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 our Audit
Committee.
Regulatory Assets and Liabilities
As a result of the ratemaking process, we record certain assets and liabilities in accordance
with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC)
Topic 980, Regulated Operations, consequently, the accounting principles applied by our
regulated energy 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 Item 8
under the heading Notes to the Consolidated Financial Statements Note A, Summary of
Accounting Policies, we have recorded regulatory assets of $23.9 million and regulatory
liabilities of $47.8 million, at December 31, 2010. If we were required to terminate
application of this 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 effect on our results of operations.
Valuation of Environmental Assets and Liabilities
As more fully described in Item 8 under the heading Notes to the Consolidated Financial
Statements Note P, Environmental Commitments and Contingencies, we have completed our
responsibilities related to one environmental site and are currently participating in the
investigation, assessment or remediation of seven other former MGP
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 we believe that recovery of these expenditures, including any litigation costs, is
probable through the regulatory process, we have recorded a regulatory asset and corresponding
environmental liability. At December 31, 2010, we have recorded environmental regulatory and
other assets of $7.5 million and a liability of $12.0 million for environmental costs.
Chesapeake Utilities Corporation 2010 Form 10-K Page 35
Managements Discussion and Analysis
Derivatives
We 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 engage in propane marketing activities. We continually monitor
the use of these instruments to ensure compliance with our risk management policies and account
for them in accordance with appropriate GAAP. If these instruments do not meet the definition
of derivatives or are considered normal purchases and sales, they are accounted for on an
accrual basis of accounting.
The following is a review of our use of derivative instruments at December 31, 2010 and 2009:
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During 2010 and 2009, our natural gas distribution, electric distribution, propane
distribution and natural gas marketing operations entered into physical contracts for the
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 an accrual
basis of accounting. |
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During 2010 and 2009, the propane distribution operation entered into a put option to
protect it from the impact of price decreases on the Pro-Cap (propane price-cap) Plan that
we offer to customers. We accounted for the put option on a mark-to-market basis and
recorded a loss of $168,000 and $41,000, at December 31, 2010 and 2009, respectively. |
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Xeron, our propane wholesale marketing subsidiary, enters into forward, futures and
other contracts that are considered derivatives. These contracts are marked-to-market,
using prices at the end of each reporting period, and unrealized gains or losses are
recorded in the Consolidated Statement of Income as revenue or expense. These contracts
generally mature within one year and are almost exclusively for propane commodities. For
the years ended December 31, 2010 and 2009, these contracts had net unrealized gains of
$284,000 and net unrealized losses of $1.6 million, respectively. |
Operating Revenues
Revenues for our natural gas and electric distribution operations are based on rates approved by
the PSCs of the jurisdictions in which we operate. The natural gas transmission operations
revenues are based on rates approved by the FERC. Customers base rates may not be changed
without formal approval by these commissions. The PSCs, however, have authorized our regulated
operations to negotiate rates, based on approved methodologies, with customers that have
competitive alternatives. The FERC has also authorized ESNG to negotiate rates above or below
the FERC-approved maximum rates, which customers can elect as an alternative to negotiated
rates.
For regulated deliveries of natural gas and electricity, we read meters and bill customers
on monthly cycles that do not coincide with the accounting periods used for financial reporting
purposes. We accrue unbilled revenues for natural gas and electricity that have 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, we must estimate amounts of natural gas and electricity that
have not been accounted for on our delivery systems 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, 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 our statement of income. For certain propane distribution customers
without meters and advanced information services customers, we record revenue in the period the
products are delivered and/or services are rendered.
Chesapeake Utilities Corporation 2010 Form 10-K Page 36
Managements Discussion and Analysis
Each of our natural gas distribution operations in Delaware and Maryland, our bundled natural
gas distribution service in Florida and our electric distribution operation in Florida has a
purchased fuel cost recovery mechanism. This mechanism provides us with a method of adjusting
billing rates to customers to reflect changes in the cost of purchased fuel. The difference
between the current cost of fuel purchased and the cost of fuel recovered in billed rates is
deferred and accounted for as either unrecovered purchased fuel costs or amounts payable to
customers. Generally, these deferred amounts are recovered or refunded within one year.
We charge flexible rates to industrial interruptible customers on our natural gas distribution
systems to compete with the price of alternative fuel that they can use. Neither we nor any of
our interruptible customers is contractually obligated to deliver or receive natural 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.
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, and 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 $2.0
million, $892,000 and $537,000, in 2010, 2009 and 2008, respectively. We expect to record
pension and postretirement benefit costs of approximately $2.0 million for 2011, of which
$455,000 are settlement losses related to lump-sum distributions we expect to make during 2011,
from the Chesapeake Pension Plan and the Chesapeake SERP related to the retirement of our former
Chief Executive Officer, who retired in January 2011. Actuarial assumptions affecting 2011
include expected long-term rates of return on plan assets of 6.0 percent and 7.0 percent for
Chesapeakes pension plan and FPUs pension plan, respectively, and discount rates of 5.00
percent and 5.25 percent for Chesapeakes plans and FPUs plans, respectively. The discount
rate for each plan was determined by management considering high quality corporate bond rates
based on Moodys 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.
Actual changes in the fair value of plan assets and the differences between the actual return on
plan assets and the expected return on plan assets could have a material effect on the amount of
pension and postretirement benefit costs that we ultimately recognize. A 0.25 percent increase
in the discount rate could decrease our pension and postretirement costs by approximately
$98,000 and a decrease of 0.25 percent could increase our pension and postretirement costs by
$123,000. A 0.25 percent increase in the rate of return would decrease our pension cost by
approximately $112,000, and a decrease of 0.25 percent could increase our pension cost by
approximately $117,000 and will not have an impact on postretirement and SERP plans because
these plans are not funded.
Chesapeake Utilities Corporation 2010 Form 10-K Page 37
Managements Discussion and Analysis
Acquisition Accounting
The merger with FPU and other acquisitions were 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. In estimating the fair value of the assets and liabilities
subject to rate regulation, we considered the nature of the assets and liabilities and the
regulatory mechanism for recovery, to which these assets and liabilities are subject, 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 our value of net assets and future earnings.
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. We deferred a certain portion of the total costs
incurred as a regulatory asset, which represents our best estimate of the costs, which we expect
to be permitted to recover when we complete the appropriate rate proceedings based on similar
proceedings in Florida in the past. The remaining costs have been expensed.
(d) |
|
Results of Operations |
(in thousands except per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
|
Increase |
|
For the Years Ended December 31, |
|
2010 |
|
|
2009 |
|
|
(decrease) |
|
|
2009 |
|
|
2008 |
|
|
(decrease) |
|
Business Segment: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated Energy |
|
$ |
43,509 |
|
|
$ |
26,900 |
|
|
$ |
16,609 |
|
|
$ |
26,900 |
|
|
$ |
24,733 |
|
|
$ |
2,167 |
|
Unregulated Energy |
|
|
7,908 |
|
|
|
8,158 |
|
|
|
(250 |
) |
|
|
8,158 |
|
|
|
3,781 |
|
|
|
4,377 |
|
Other |
|
|
513 |
|
|
|
(1,322 |
) |
|
|
1,835 |
|
|
|
(1,322 |
) |
|
|
(35 |
) |
|
|
(1,287 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income |
|
|
51,930 |
|
|
|
33,736 |
|
|
|
18,194 |
|
|
|
33,736 |
|
|
|
28,479 |
|
|
|
5,257 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income |
|
|
195 |
|
|
|
165 |
|
|
|
30 |
|
|
|
165 |
|
|
|
103 |
|
|
|
62 |
|
Interest Charges |
|
|
9,146 |
|
|
|
7,086 |
|
|
|
2,060 |
|
|
|
7,086 |
|
|
|
6,158 |
|
|
|
928 |
|
Income Taxes |
|
|
16,923 |
|
|
|
10,918 |
|
|
|
6,005 |
|
|
|
10,918 |
|
|
|
8,817 |
|
|
|
2,101 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
$ |
26,056 |
|
|
$ |
15,897 |
|
|
$ |
10,159 |
|
|
$ |
15,897 |
|
|
$ |
13,607 |
|
|
$ |
2,290 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Per Share of Common Stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
2.75 |
|
|
$ |
2.17 |
|
|
$ |
0.58 |
|
|
$ |
2.17 |
|
|
$ |
2.00 |
|
|
$ |
0.17 |
|
Diluted |
|
$ |
2.73 |
|
|
$ |
2.15 |
|
|
$ |
0.58 |
|
|
$ |
2.15 |
|
|
$ |
1.98 |
|
|
$ |
0.17 |
|
Chesapeake Utilities Corporation 2010 Form 10-K Page 38
Managements Discussion and Analysis
2010 compared to 2009
Our net income increased by approximately $10.2 million, or $0.58 per share (diluted) in 2010,
compared to 2009. Chesapeakes legacy businesses, which exclude the FPU business and
merger-related costs, generated an increase in net income of $1.9 million, or $0.24 per share
(diluted) in 2010. The $0.24 per share increase in diluted earnings per share by Chesapeakes
legacy businesses in 2010, which is calculated based on weighted average common shares outstanding,
exclusive of the shares issued in the FPU merger, represents 11-percent growth from 2009.
Continued growth and expansions of our natural gas distribution and transmission businesses and
propane distribution business on the Delmarva Peninsula, the rate increase in Chesapeakes Florida
natural gas distribution division, favorable weather impact and improved results in our advanced
information services business contributed to this increase. These increases were partially offset
by a decline in earnings from our natural gas marketing business, due primarily to the absence of
spot sales to one industrial customer, and our propane wholesale marketing business. FPUs
results, which have been included in our consolidated results since the completion of the merger on
October 28, 2009, added $7.5 million to our consolidated net income in 2010, which generated an
increase of $0.22 per share (diluted) in 2010. A decrease in FPU merger-related costs also added
$0.12 per share (diluted) to the increase in 2010.
The following table illustrates the effect of the merger on our results for the year ended December
31, 2010 and December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
|
Chesapeake, |
|
|
|
|
|
|
Chesapeake |
|
|
Chesapeake, |
|
|
|
|
|
|
Chesapeake |
|
For the Years Ended December 31, |
|
excluding FPU |
|
|
FPU |
|
|
Total |
|
|
excluding FPU |
|
|
FPU(1) |
|
|
Total |
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated Energy |
|
$ |
26,711 |
|
|
$ |
16,798 |
|
|
$ |
43,509 |
|
|
$ |
23,908 |
|
|
$ |
2,992 |
|
|
$ |
26,900 |
|
Unregulated Energy |
|
|
6,335 |
|
|
|
1,573 |
|
|
|
7,908 |
|
|
|
7,605 |
|
|
|
553 |
|
|
|
8,158 |
|
Other, including merger-related costs |
|
|
513 |
|
|
|
|
|
|
|
513 |
|
|
|
(1,322 |
) |
|
|
|
|
|
|
(1,322 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income |
|
|
33,559 |
|
|
|
18,371 |
|
|
|
51,930 |
|
|
|
30,191 |
|
|
|
3,545 |
|
|
|
33,736 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income, net of expenses |
|
|
48 |
|
|
|
147 |
|
|
|
195 |
|
|
|
58 |
|
|
|
107 |
|
|
|
165 |
|
Interest Charges |
|
|
5,752 |
|
|
|
3,394 |
|
|
|
9,146 |
|
|
|
6,345 |
|
|
|
741 |
|
|
|
7,086 |
|
Income Taxes |
|
|
11,138 |
|
|
|
5,785 |
|
|
|
16,923 |
|
|
|
9,836 |
|
|
|
1,082 |
|
|
|
10,918 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
$ |
16,717 |
|
|
$ |
9,339 |
|
|
$ |
26,056 |
|
|
$ |
14,068 |
|
|
$ |
1,829 |
|
|
$ |
15,897 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
FPU operating results are for the period from the merger closing (October 28,
2009) to December 31, 2009 |
2009 compared to 2008
Our net income increased by approximately $2.3 million, or $0.17 per share (diluted), in 2009,
compared to 2008. Excluding FPUs results and the merger-related costs, Chesapeakes legacy
businesses generated an increase in net income of $1.0 million, or $0.12 per share (diluted) in
2009. This increase in the diluted earnings per share, which is calculated based on weighted
average common shares outstanding, exclusive of the shares issued in the FPU merger, represents
five-percent growth in 2009. Continued growth and expansions in our natural gas distribution and
transmission businesses on the Delmarva Peninsula, and increased retail margins in the propane
distribution business, favorable weather impact and spot sale opportunities by our natural gas
marketing business contributed to this increase. FPUs net income included in our consolidated
results in 2009, which represents its net income since the completion of the merger, was $1.8
million, generating an additional $0.12 per share (diluted).
Chesapeake Utilities Corporation 2010 Form 10-K Page 39
Managements Discussion and Analysis
The following table illustrates the effect of the merger on our results for the year ended December
31, 2009 and the results in 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
|
Chesapeake, |
|
|
|
|
|
|
Chesapeake |
|
|
Chesapeake, |
|
|
|
|
|
|
Chesapeake |
|
For the Years Ended December 31, |
|
excluding FPU |
|
|
FPU(1) |
|
|
Total |
|
|
excluding FPU |
|
|
FPU |
|
|
Total |
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated Energy |
|
$ |
23,908 |
|
|
$ |
2,992 |
|
|
$ |
26,900 |
|
|
$ |
24,733 |
|
|
$ |
0 |
|
|
$ |
24,733 |
|
Unregulated Energy |
|
|
7,605 |
|
|
|
553 |
|
|
|
8,158 |
|
|
|
3,781 |
|
|
|
|
|
|
|
3,781 |
|
Other |
|
|
(1,322 |
) |
|
|
|
|
|
|
(1,322 |
) |
|
|
(35 |
) |
|
|
|
|
|
|
(35 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income |
|
|
30,191 |
|
|
|
3,545 |
|
|
|
33,736 |
|
|
|
28,479 |
|
|
|
0 |
|
|
|
28,479 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income, net of expenses |
|
|
58 |
|
|
|
107 |
|
|
|
165 |
|
|
|
103 |
|
|
|
|
|
|
|
103 |
|
Interest Charges |
|
|
6,345 |
|
|
|
741 |
|
|
|
7,086 |
|
|
|
6,158 |
|
|
|
|
|
|
|
6,158 |
|
Income Taxes |
|
|
9,836 |
|
|
|
1,082 |
|
|
|
10,918 |
|
|
|
8,817 |
|
|
|
|
|
|
|
8,817 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
$ |
14,068 |
|
|
$ |
1,829 |
|
|
$ |
15,897 |
|
|
$ |
13,607 |
|
|
$ |
0 |
|
|
$ |
13,607 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
FPU operating results are for the period from the merger closing (October 28, 2009)
to December 31, 2009 |
Chesapeake Utilities Corporation 2010 Form 10-K Page 40
Managements Discussion and Analysis
Regulated Energy
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
|
Increase |
|
For the Years Ended December 31, |
|
2010 |
|
|
2009 |
|
|
(decrease) |
|
|
2009 |
|
|
2008 |
|
|
(decrease) |
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
$ |
269,934 |
|
|
$ |
139,099 |
|
|
$ |
130,835 |
|
|
$ |
139,099 |
|
|
$ |
116,468 |
|
|
$ |
22,631 |
|
Cost of sales |
|
|
144,217 |
|
|
|
64,803 |
|
|
|
79,414 |
|
|
|
64,803 |
|
|
|
54,789 |
|
|
|
10,014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin |
|
|
125,717 |
|
|
|
74,296 |
|
|
|
51,421 |
|
|
|
74,296 |
|
|
|
61,679 |
|
|
|
12,617 |
|
|
Operations & maintenance |
|
|
56,338 |
|
|
|
32,569 |
|
|
|
23,769 |
|
|
|
32,569 |
|
|
|
25,369 |
|
|
|
7,200 |
|
Depreciation & amortization |
|
|
17,038 |
|
|
|
8,866 |
|
|
|
8,172 |
|
|
|
8,866 |
|
|
|
6,694 |
|
|
|
2,172 |
|
Other taxes |
|
|
8,832 |
|
|
|
5,961 |
|
|
|
2,871 |
|
|
|
5,961 |
|
|
|
4,883 |
|
|
|
1,078 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other operating expenses |
|
|
82,208 |
|
|
|
47,396 |
|
|
|
34,812 |
|
|
|
47,396 |
|
|
|
36,946 |
|
|
|
10,450 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income |
|
$ |
43,509 |
|
|
$ |
26,900 |
|
|
$ |
16,609 |
|
|
$ |
26,900 |
|
|
$ |
24,733 |
|
|
$ |
2,167 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weather and Customer Analysis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
|
Increase |
|
For the Years Ended December 31, |
|
2010 |
|
|
2009 |
|
|
(decrease) |
|
|
2009 |
|
|
2008 |
|
|
(decrease) |
|
Delmarva Peninsula |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual HDD |
|
|
4,831 |
|
|
|
4,729 |
|
|
|
102 |
|
|
|
4,729 |
|
|
|
4,431 |
|
|
|
298 |
|
10-year average HDD |
|
|
4,528 |
|
|
|
4,462 |
|
|
|
66 |
|
|
|
4,462 |
|
|
|
4,401 |
|
|
|
61 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated gross margin per HDD |
|
$ |
1,995 |
|
|
$ |
2,429 |
|
|
$ |
(434 |
) |
|
$ |
2,429 |
|
|
$ |
1,937 |
|
|
$ |
492 |
|
|
Florida |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual HDD |
|
|
1,501 |
|
|
|
911 |
|
|
|
590 |
|
|
|
911 |
|
|
|
851 |
|
|
|
60 |
|
10-year average HDD |
|
|
919 |
|
|
|
863 |
|
|
|
56 |
|
|
|
863 |
|
|
|
848 |
|
|
|
15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual CDD |
|
|
2,859 |
|
|
|
2,770 |
|
|
|
89 |
|
|
|
2,770 |
|
|
|
2,553 |
|
|
|
217 |
|
10-year average CDD |
|
|
2,718 |
|
|
|
2,694 |
|
|
|
24 |
|
|
|
2,694 |
|
|
|
2,687 |
|
|
|
7 |
|
|
Average number of residential customers |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delmarva natural gas distribution |
|
|
47,638 |
|
|
|
46,717 |
|
|
|
921 |
|
|
|
46,717 |
|
|
|
45,570 |
|
|
|
1,147 |
|
Florida natural gas distribution(1) |
|
|
61,053 |
|
|
|
60,048 |
|
|
|
1,005 |
|
|
|
60,048 |
|
|
|
13,373 |
|
|
|
46,675 |
|
Florida electric distribution (1) |
|
|
23,589 |
|
|
|
23,679 |
|
|
|
(90 |
) |
|
|
23,679 |
|
|
|
|
|
|
|
23,679 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
132,280 |
|
|
|
130,444 |
|
|
|
1,836 |
|
|
|
130,444 |
|
|
|
58,943 |
|
|
|
71,501 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Average number of residential customers for FPU are included in 2010 and
2009. |
2010 Compared to 2009
Operating income for the regulated energy segment increased by approximately $16.6 million, or 62
percent, in 2010, compared to 2009, which was generated from a gross margin increase of $51.4
million, offset partially by an operating expense increase of $34.8 million. Our 2010 results
include 12 months of FPUs results, whereas 2009 includes only two months.
Gross Margin
Gross margin for our regulated energy segment increased by $51.4 million, or 69 percent. Of the
$51.4 million increase, Chesapeakes legacy regulated energy businesses generated $5.2 million of
the increase, or 10 percent. FPUs natural gas and electric distribution operations contributed
$46.2 million of this increase. FPUs results in 2009 have been included in our results since the
completion of the merger on October 28, 2009. Our results for 2010 included FPUs results for the
full year.
Chesapeake Utilities Corporation 2010 Form 10-K Page 41
Managements Discussion and Analysis
The natural gas distribution operations for the Delmarva Peninsula generated an increase in gross
margin of $1.4 million in 2010. The factors contributing to this increase were as follows:
|
|
|
$1.1 million of the gross margin increase was a result of a
two-percent increase in residential customers as well as additional growth
in commercial and industrial customers on the Delmarva Peninsula.
Residential, commercial and industrial growth by our Delaware division
generated $525,000, $163,000 and $313,000, respectively, of the gross margin
increase, and the customer growth by our Maryland division contributed
$97,000 to the gross margin increase. In 2010, our Delmarva natural gas
distribution operations also added 10 large commercial and industrial
customers with total expected annualized margin of $748,000, of which
$196,000 has been reflected in 2010s results. The addition of certain
industrial customers in 2010 also positioned us to further extend our
natural gas distribution and transmission infrastructure in southern
Delaware to serve other potential customers in the same area. |
|
|
|
|
Colder weather on the Delmarva Peninsula generated an
additional $365,000 to gross margin as heating
degree-days increased by 102, or two percent, in
2010, compared to 2009. This increased gross margin
is primarily related to our Delaware division, as
residential heating rates for our Maryland division
are weather-normalized, and we typically do not
experience an impact on gross margin from the weather
for our residential customers in Maryland. |
|
|
|
|
A decline in non-weather-related customer consumption, primarily by
residential customers of our Delaware division, decreased gross margin
by $111,000. |
Our Florida natural gas distribution operations experienced an increase in gross margin of $33.5
million in 2010. The factors contributing to this increase were as follows:
|
|
|
FPUs natural gas distribution operation generated $37.1 million in gross
margin for 2010, which includes $148,000 of gross margin generated by
the purchase of operating assets from IGC whose operating assets were purchased by FPU on August 9, 2010. Included in gross
margin from FPUs natural gas distribution operation in 2009 was $6.4 million. Gross
margin from FPUs natural gas distribution operation in 2010 was positively affected by an
annual rate increase of approximately $8.0 million, effective January 14, 2010, colder
temperatures in Florida and growth in commercial and industrial customers. Included in
gross margin from FPUs natural gas distribution operation was the impact of a $750,000
accrual related to the regulatory risk associated with its earnings, merger
benefits and recovery of purchase premium. FPU is required to detail known
benefits, synergies, cost savings and cost increases resulting from the merger and present
the information in the come-back filing to the Florida PSC by April 29, 2011 (within 18
months of the merger). We are currently in discussions with the Office of Public Counsel
and the Florida PSC staff regarding the benefits and cost savings of the merger, current and expected earnings levels
as well as the recovery of approximately $34.9 million in purchase premium and $2.2 million
in merger-related costs. We recorded this accrual based on our assessment of FPUs current
earnings, the regulatory environment in Florida and progress of the current discussions. |
|
|
|
|
Gross margin from Chesapeakes Florida division increased by $2.9 million,
primarily as a result of an annual rate increase of approximately $2.5 million, which
became effective on January 14, 2010. The colder temperatures in 2010 also generated an
additional $247,000 in gross margin in 2010, compared to 2009. |
Chesapeake Utilities Corporation 2010 Form 10-K Page 42
Managements Discussion and Analysis
The natural gas transmission operations achieved gross margin growth of $952,000 in 2010. The
factors contributing to this increase were as follows:
|
|
|
New transportation services implemented by ESNG in November 2009, May 2010 and
November 2010 as a result of its system expansion projects generated an additional $1.1
million to gross margin in 2010, compared to 2009. These expansion projects added 9,623
Mcfs of service per day with estimated annual gross margin of $1.6 million, of which $1.2
million has been reflected in 2010s results. |
|
|
|
|
New firm transportation service for an industrial customer for the period from
November 2009 to October 2012 provided an additional 9,662 Mcfs per day for the period
January 1, 2010 through February 5, 2010, and an additional 2,705 Mcfs per day for the
period February 6, 2010 through October 31, 2010. These new services added $329,000 to
gross margin for 2010. Partially offsetting the additional gross margin generated by this
new firm transportation service was the margin of $232,000 in 2009 from the temporary
interruptible service provided to the same customer. This temporary increase in service
did not occur in 2010. |
|
|
|
|
ESNG changed its rates effective April 2009 to recover specific project costs
in accordance with the terms of precedent agreements with certain customers. These rates
generated $508,000 and $381,000 in gross margin in 2010 and 2009, respectively. ESNG and
the customers agreed to shorten the recovery period, starting in March 2011. |
|
|
|
|
Offsetting the foregoing increases to gross margin, ESNG received notices from
two customers of their intentions not to renew their firm transportation service contracts,
which expired in November 2009 and April 2010, decreasing gross margin by $341,000 for
2010. |
|
|
|
|
Although not affecting our results in 2010, ESNG completed the eight-mile
mainline extension in December 2010 to interconnect with the TETLP pipeline. ESNG
commenced its new transportation services to Chesapeakes Delaware and Maryland divisions
in January 2011. These new services have a three-year phase-in from 19,324 Mcfs per day to
38,647 Mcfs per day, providing estimated gross margin of $2.4 million in 2011, $3.9 million
in 2012 and $4.3 million thereafter. |
Our Florida electric distribution operation, which was acquired in the FPU merger, generated gross
margin of $18.4 million in 2010, compared to $2.8 million in gross margin generated in 2009. FPUs
results in 2009 were included in our results only after the completion of the merger in 2009.
Gross margin from our electric distribution operation was positively affected by colder
temperatures in the winter months and warmer temperatures in the summer months in 2010.
Other Operating Expenses
Other operating expenses for the regulated energy segment increased by $34.8 million, or 73
percent, in 2010, of which $32.4 million was related to other operating expenses of FPU. The
remaining increase of $2.4 million or a five percent increase from other operating expenses in
2009, exclusive of other operating expenses of FPU, was due primarily
to the following factors:
|
|
|
Payroll and benefits increased by $705,000 due primarily to annual salary
increases and incentive pay as a result of improved performance. |
|
|
|
|
Depreciation and asset removal costs increased by $518,000 as a result of our
increased capital investments made in 2010 and 2009 to support growth. |
|
|
|
|
Regulatory expenses increased by $349,000 due primarily to costs associated with
ESNGs recent rate case filing and ongoing regulatory discussions involving the merger
impact and recovery of the purchase premium in Florida. |
|
|
|
|
Non-income-taxes increased by $63,000 due primarily to increased gross receipt
tax. |
Chesapeake Utilities Corporation 2010 Form 10-K Page 43
Managements Discussion and Analysis
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. FPUs
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 were as follows:
|
|
|
The Delmarva natural gas distribution operations experienced growth in residential,
commercial, and industrial customers, which contributed $471,000, $149,000 and $589,000,
respectively, to the gross margin increase, in spite of the continued slowdown in the new
housing construction and industrial growth in the region. 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. |
|
|
|
|
Colder weather on the Delmarva Peninsula contributed $449,000 to the increased gross
margin, as HDD increased by 298, or seven percent, compared to 2008. |
|
|
|
|
The Delaware divisions new rate structure allows collection of miscellaneous service
fees of $256,000, which, although not representing additional revenue, were previously
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. |
Chesapeakes 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 the 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 in gross margin of $99,000 due to implementation of interim natural gas 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 were 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 for: (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. These services generate annual gross margin of $1.1
million. |
|
|
|
|
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 intrastate 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. |
Chesapeake Utilities Corporation 2010 Form 10-K Page 44
Managements Discussion and Analysis
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 was
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 was 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. |
|
|
|
|
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 overall increase in corporate overhead costs. This increase was
related primarily to increased payroll and benefits and increased costs associated with
investor relations and financial reporting activities. |
Unregulated Energy
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
|
Increase |
|
For the Years Ended December 31, |
|
2010 |
|
|
2009 |
|
|
(decrease) |
|
|
2009 |
|
|
2008 |
|
|
(decrease) |
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
$ |
146,793 |
|
|
$ |
119,973 |
|
|
$ |
26,820 |
|
|
$ |
119,973 |
|
|
$ |
161,290 |
|
|
$ |
(41,317 |
) |
Cost of sales |
|
|
110,680 |
|
|
|
90,408 |
|
|
|
20,272 |
|
|
|
90,408 |
|
|
|
138,302 |
|
|
|
(47,894 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin |
|
|
36,113 |
|
|
|
29,565 |
|
|
|
6,548 |
|
|
|
29,565 |
|
|
|
22,988 |
|
|
|
6,577 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations & maintenance |
|
|
23,140 |
|
|
|
18,016 |
|
|
|
5,124 |
|
|
|
18,016 |
|
|
|
16,322 |
|
|
|
1,694 |
|
Depreciation & amortization |
|
|
3,433 |
|
|
|
2,415 |
|
|
|
1,018 |
|
|
|
2,415 |
|
|
|
2,024 |
|
|
|
391 |
|
Other taxes |
|
|
1,632 |
|
|
|
976 |
|
|
|
656 |
|
|
|
976 |
|
|
|
861 |
|
|
|
115 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other operating expenses |
|
|
28,205 |
|
|
|
21,407 |
|
|
|
6,798 |
|
|
|
21,407 |
|
|
|
19,207 |
|
|
|
2,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income |
|
$ |
7,908 |
|
|
$ |
8,158 |
|
|
$ |
(250 |
) |
|
$ |
8,158 |
|
|
$ |
3,781 |
|
|
$ |
4,377 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weather Analysis Delmarva
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
|
Increase |
|
For the Years Ended December 31, |
|
2010 |
|
|
2009 |
|
|
(decrease) |
|
|
2009 |
|
|
2008 |
|
|
(decrease) |
|
|
Actual HDD |
|
|
4,831 |
|
|
|
4,729 |
|
|
|
102 |
|
|
|
4,729 |
|
|
|
4,431 |
|
|
|
298 |
|
10-year average HDD |
|
|
4,528 |
|
|
|
4,462 |
|
|
|
66 |
|
|
|
4,462 |
|
|
|
4,401 |
|
|
|
61 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated gross margin per HDD |
|
$ |
2,415 |
|
|
$ |
3,083 |
|
|
$ |
(668 |
) |
|
$ |
3,083 |
|
|
$ |
2,465 |
|
|
$ |
618 |
|
Chesapeake Utilities Corporation 2010 Form 10-K Page 45
Managements Discussion and Analysis
2010 Compared to 2009
Operating income for the unregulated energy segment decreased by approximately $250,000, or three
percent, in 2010 compared to 2009, which was attributable to an increase in gross margin of $6.5
million, offset by an increase in other operating expenses of $6.8 million. A decline in
operating income for the unregulated energy segment is largely attributable to the natural gas
marketing business, which experienced a decrease in gross margin due primarily to the absence of
spot sales to one industrial customer.
Gross Margin
Gross margin for our unregulated energy segment increased by $6.5 million, or 22 percent, for 2010,
compared to the same period in 2009.
Our Delmarva propane distribution operation generated a gross margin increase of $1.0 million, as a
result of the following factors:
|
|
|
Retail volumes sold increased by 1.6 million gallons, or seven percent, in 2010, which
generated additional gross margin of $1.1 million. The addition of 436 community gas
system customers and 1,000 other customers acquired in February 2010 as part of the
purchase of the operating assets of a propane distributor serving Northampton and Accomack
Counties in Virginia contributed approximately 38% of this increase.
The two-percent colder weather in 2010, compared to 2009, generated additional margin of
$314,000. Timing of propane deliveries to our bulk customers contributed to the remaining
increase in gross margin due to an increase in retail volumes. |
|
|
|
|
Other fees increased by
$340,000 in 2010 driven by increased customer participation
in various customer pricing programs. |
|
|
|
|
Retail margin per gallon decreased in 2010, compared to 2009, and decreased gross margin
by $399,000. Retail margin during the first half of 2009 benefited from the inventory
valuation adjustment recorded in late 2008 which lowered the propane inventory costs and,
therefore, increased retail margins during the first half of 2009. Retail margins for the
second half of 2010 returned to more normal levels. Retail margins in the second half of
2010 increased from the same period in 2009, partially offsetting the impact of the
decrease in the first half of the year. |
Our Florida propane distribution operation generated $9.4 million in 2010, compared to $3.2 million
in 2009. The 2009 results include FPUs results for the two months after the completion of the
merger. Also included in the gross margin increase for 2010 was approximately $767,000 in
increased merchandise sales from FPU.
Gross margin for Xeron, our propane wholesale marketing operation, decreased by $441,000 in 2010
compared to 2009. Xerons trading volumes decreased by 13 percent in 2010 compared to 2009.
In 2010, gross margin for our unregulated natural gas marketing subsidiary, PESCO, decreased by
$1.0 million. In 2009, PESCO benefited from increased spot sales on the Delmarva Peninsula.
Spot sales decreased in 2010, due primarily to one industrial customer. Spot sales are not predictable
and, therefore, are not included in our long-term financial plans or forecasts.
Other Operating Expenses
Total other operating expenses for the unregulated energy segment increased by $6.8 million in
2010. The Florida distribution operation and FPUs merchandise activities contributed $6.0 million
to this increase. Included in other operating expenses for the Florida propane distribution
operation in 2010 was approximately $370,000 expensed in the third and fourth quarters of 2010 for
the settlement of a class action complaint (See Item 8 under the heading Notes to the Consolidated
Financial Statements Note Q, Other Commitments and Contingencies). The remaining increase of
$771,000 in other operating expenses was due primarily to increased payroll and benefit costs,
higher non-income taxes due to increased sales taxes and increased propane delivery costs,
partially offset by a decrease in bad debt expenses as a result of expanded credit and collection
initiatives by PESCO.
Chesapeake Utilities Corporation 2010 Form 10-K Page 46
Managements Discussion and Analysis
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 a gross margin increase of $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 2009
compared to 2008. FPUs propane distribution operation contributed $1.8 million to gross margin
during the period from the merger closing (October 28, 2009) to December 31, 2009.
PESCO, our natural gas marketing operation, experienced an increase in gross margin of $1.0 million
in 2009. PESCO increased its sales volumes 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 gross margin increase. 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 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 enabled 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.
Other Operating Expenses
Total other operating expenses for the unregulated energy segment increased by $2.2 million in
2009, 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 was due primarily to the following factors:
|
|
|
Payroll costs increased by $301,000 in 2009 compared to 2008 due to annual salary
increases. |
|
|
|
|
Benefit costs increased by $167,000, due primarily to increased pension costs in 2009 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. |
|
|
|
|
Corporate overhead costs allocated to the unregulated energy segment increased by
approximately $568,000 due to the overall increase in administrative payroll and benefits
and increased costs associated with investor relations and financial reporting activities. |
|
|
|
|
These increases were partially offset by lower vehicle-related costs of $176,000, due
primarily to a decrease in the cost of fuel. |
Chesapeake Utilities Corporation 2010 Form 10-K Page 47
Managements Discussion and Analysis
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
|
Increase |
|
For the Years Ended December 31, |
|
2010 |
|
|
2009 |
|
|
(decrease) |
|
|
2009 |
|
|
2008 |
|
|
(decrease) |
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
$ |
13,142 |
|
|
$ |
11,998 |
|
|
$ |
1,144 |
|
|
$ |
11,998 |
|
|
$ |
15,373 |
|
|
$ |
(3,375 |
) |
Cost of sales |
|
|
6,316 |
|
|
|
6,036 |
|
|
|
280 |
|
|
|
6,036 |
|
|
|
8,034 |
|
|
|
(1,998 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin |
|
|
6,826 |
|
|
|
5,962 |
|
|
|
864 |
|
|
|
5,962 |
|
|
|
7,339 |
|
|
|
(1,377 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations & maintenance |
|
|
4,766 |
|
|
|
4,859 |
|
|
|
(93 |
) |
|
|
4,859 |
|
|
|
5,206 |
|
|
|
(347 |
) |
Transaction-related costs |
|
|
660 |
|
|
|
1,478 |
|
|
|
(818 |
) |
|
|
1,478 |
|
|
|
1,153 |
|
|
|
325 |
|
Depreciation & amortization |
|
|
289 |
|
|
|
310 |
|
|
|
(21 |
) |
|
|
310 |
|
|
|
290 |
|
|
|
20 |
|
Other taxes |
|
|
600 |
|
|
|
640 |
|
|
|
(40 |
) |
|
|
640 |
|
|
|
728 |
|
|
|
(88 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other operating expenses |
|
|
6,315 |
|
|
|
7,287 |
|
|
|
(972 |
) |
|
|
7,287 |
|
|
|
7,377 |
|
|
|
(90 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income Other |
|
|
511 |
|
|
|
(1,325 |
) |
|
|
1,836 |
|
|
|
(1,325 |
) |
|
|
(38 |
) |
|
|
(1,287 |
) |
Operating Income Eliminations |
|
|
2 |
|
|
|
3 |
|
|
|
(1 |
) |
|
|
3 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income |
|
$ |
513 |
|
|
$ |
(1,322 |
) |
|
|
1,835 |
|
|
$ |
(1,322 |
) |
|
$ |
(35 |
) |
|
$ |
(1,287 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 Compared to 2009
Operating income for the Other segment increased by approximately $1.8 million in 2010, compared
to 2009. The increase in operating income was attributable to a gross margin increase of $864,000
and a $972,000 decrease in operating expenses.
Gross margin
The period-over-period increase in gross margin of $864,000 for our Other segment was generated
by our advanced information services subsidiarys increase in revenue and gross margin from its
professional database monitoring and support solution services and higher consulting revenues as a
result of a seven-percent increase in the number of billable consulting hours in 2010 compared to
2009.
Operating expenses
Other operating expenses decreased by $972,000 in 2010 compared to 2009. The decrease in operating
expenses was attributable primarily to an $818,000 decrease in merger-related costs expensed in
2010 compared to 2009.
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 was a result of a decrease
in consulting revenues by the advanced information services subsidiary due primarily to a
28-percent decrease in the number of billable consulting hours, coupled with a decline in training
revenues. The reduction in the number of billable consulting hours was a result of economic
conditions. The decrease in consulting revenues was partially offset by an increase of $218,000
from BravePoints professional database monitoring and support solution services, and increased
product sales of $140,000.
Chesapeake Utilities Corporation 2010 Form 10-K Page 48
Managements Discussion and Analysis
Operating expenses
Other operating expenses decreased by $90,000 in 2009. The decrease in operating expenses was
attributable primarily to the cost containment actions, including layoffs and compensation
adjustments, implemented by the advanced information services subsidiary in 2009 to reduce costs to
offset the decline in revenues. This decrease was offset by the increased merger-related costs.
Other Income
Other income for 2010, 2009 and 2008 was $195,000, $165,000, and $103,000, respectively, which
includes interest income, late fees charged to customers and gains or losses from the sale of
assets.
Interest Expense
2010 Compared to 2009
Our
total interest expense for 2010 increased by approximately $2.1 million, or 29 percent, compared
to 2009. The primary drivers of the increased interest expense were related to FPU, including:
|
|
|
An increase in long-term interest expense of $1.3 million was related to interest on
FPUs first mortgage bonds. |
|
|
|
|
Interest expense from a new term loan credit facility during 2010 was $491,000. In
January 2010, we redeemed two series of FPU bonds, the 4.9 percent and 6.85 percent series,
to achieve interest savings and to maintain compliance with the covenants in our unsecured
senior notes. We used $29.1 million of the new term loan facility for the redemptions. |
|
|
|
|
Additional interest expense of $730,000 is related to interest on deposits from FPUs
customers. |
Offsetting the increased interest expense from FPU was lower non-FPU-related interest expense from
Chesapeakes unsecured senior notes, as the principal balances decreased from scheduled payments,
and lower additional short-term borrowings as a result of the timing of our capital expenditures
and reduced working capital requirements, partially due to the increased bonus depreciation in
2010.
2009 Compared to 2008
Total interest expense for 2009 increased by approximately $928,000, or 15 percent, compared to
2008. Total interest expense for 2009 includes approximately $741,000 in FPUs interest expense
for the period from the merger closing (October 28, 2009) to December 31, 2009, which was primarily
related to $610,000 in interest on FPUs long-term debt and $115,000 in interest on customer
deposits. FPUs 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 FPUs 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 fairly constant at 6.37 percent in 2009, compared to 6.40 percent
in 2008. |
|
|
|
|
Interest expense on short-term borrowings 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 in addition to a decline in working capital requirements in 2009, 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 increased working capital needs as a result of the FPU
merger. Also contributing to the decrease in interest expense in short-term borrowings 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. |
Chesapeake Utilities Corporation 2010 Form 10-K Page 49
Managements Discussion and Analysis
Income Taxes
2010 Compared to 2009
Income tax expense was $16.9 million in 2010, compared to $10.9 million in 2009, representing an
increase of $6.0 million, as a result of increased taxable income in 2010. During 2009, we
expensed approximately $871,000 in merger-related costs that we determined to be non-deductible for
income tax purposes. Excluding the impact of these costs, our effective income tax rate for 2010
and 2009 remained unchanged at 39.4 percent.
2009 Compared to 2008
Income tax expense was $10.9 million in 2009, compared to $8.8 million in 2008, representing an
increase of $2.1 million. During 2009, we expensed approximately $871,000 in merger-related costs
that we determined to be non-deductible for income tax purposes. Excluding the impact of these
costs, our effective income tax rate for 2009 and 2008 remained primarily unchanged at 39.4 percent
and 39.3 percent, respectively. The increase in income tax expense reflects the increased taxable
income in 2009.
(e) Liquidity and Capital Resources
Our capital requirements reflect the capital-intensive and seasonal nature of our business and are
principally attributable to investment in new plant and equipment, retirement of outstanding debt
and seasonal variability in working capital. We rely on cash generated from operations, short-term
borrowings, and other sources to meet normal working capital requirements and to finance capital
expenditures.
Our energy businesses are weather sensitive and seasonal. We generate a large portion of our
annual net income and subsequent increases in our accounts receivable in the first and fourth
quarters of each year due to significant volumes of natural gas and propane delivered by our
natural gas and propane distribution operations to customers during the peak heating season. In
addition, our natural gas and propane inventories, which usually peak in the fall months, are
largely drawn down in the heating season and provide a source of cash as the inventory is used to
satisfy winter sales demand.
Capital expenditures are one of our largest capital requirements. During 2010, our capital
expenditures increased to $47.0 million, from $26.3 million and $30.8 million in 2009 and 2008,
respectively, as a result of continued expansions of our natural gas distribution and transmission
systems as well as capital expenditures for FPU of $10.9 million and $1.6 million included in our
capital expenditures in 2010 and 2009 since the completion of the merger. We have budgeted $51.7
million for capital expenditures during 2011. This amount includes $43.6 million for the regulated
energy segment, $3.7 million for the unregulated energy segment and $4.4 million for the Other
segment. The amount for the regulated energy segment includes estimated capital expenditures for
the following: natural gas distribution operation ($25.4 million), natural gas transmission
operation ($12.5 million) and electric distribution operation ($5.7 million) for expansion and
improvement of facilities. The amount for the unregulated energy segment includes estimated
capital expenditures for the propane distribution operations for customer growth and replacement of
equipment. The amount for the Other segment includes estimated capital expenditures of $245,000
for the advanced information services subsidiary with the remaining balance for other general
plant, computer software and hardware. We expect to fund the 2011 capital expenditures program
from short-term borrowings, cash provided by operating activities, and other sources. The capital
expenditures program is subject to continuous review and modification. Actual capital requirements
may vary from the above estimates due to a number of factors, including changing economic
conditions, customer growth in existing areas, regulation, new growth or acquisition opportunities
and availability of capital.
Chesapeake Utilities Corporation 2010 Form 10-K Page 50
Managements Discussion and Analysis
Capital Structure
We are committed to maintaining a sound capital structure and strong credit ratings to provide the
financial flexibility needed to access capital markets when required. This commitment, along with
adequate and timely rate relief for our regulated operations, is intended to ensure our ability to
attract capital from outside sources at a reasonable cost. We believe that the achievement of
these objectives will provide benefits to our customers, creditors and investors. The following
presents our capitalization, excluding and including short-term borrowings, as of December 31, 2010
and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
|
|
|
December 31, |
|
|
|
|
|
(in thousands) |
|
2010 |
|
|
|
|
|
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt, net of current maturities |
|
$ |
89,642 |
|
|
|
28 |
% |
|
$ |
98,814 |
|
|
|
32 |
% |
Stockholders equity |
|
|
226,239 |
|
|
|
72 |
% |
|
|
209,781 |
|
|
|
68 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization, excluding short-term debt |
|
$ |
315,881 |
|
|
|
100 |
% |
|
$ |
308,595 |
|
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
|
|
|
December 31, |
|
|
|
|
|
(in thousands) |
|
2010 |
|
|
|
|
|
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term debt |
|
$ |
63,958 |
|
|
|
17 |
% |
|
$ |
30,023 |
|
|
|
8 |
% |
Long-term debt, including current maturities |
|
|
98,858 |
|
|
|
25 |
% |
|
|
134,113 |
|
|
|
36 |
% |
Stockholders equity |
|
|
226,239 |
|
|
|
58 |
% |
|
|
209,781 |
|
|
|
56 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization, including short-term debt |
|
$ |
389,055 |
|
|
|
100 |
% |
|
$ |
373,917 |
|
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
In consummating the FPU merger, we issued 2,487,910 shares of Chesapeake common stock, valued
at approximately $75.7 million, in exchange for all outstanding common stock of FPU. Our balance
sheet at the time of the merger also reflected FPUs long-term debt of $47.8 million as a result of
the merger.
Since the consummation of the merger, we have redeemed $29.1 million of FPUs long-term debt, which
was held in the form of first mortgage bonds. We will be refinancing these redeemed bonds with new
Chesapeake unsecured senior notes. We have also entered into an arrangement to refinance an
additional $7.0 million of FPUs first mortgage bonds in 2013 with more competitively priced
Chesapeake unsecured senior notes. As a result, only $8.0 million of the original $47.8 million of
FPU debt as of the merger will be outstanding by 2013 in the form of secured first mortgage bonds.
As of December 31, 2010, we did not have any restrictions on our cash balances. Both Chesapeakes
senior notes and FPUs first mortgage bonds contain a restriction that limits the payment of
dividends or other restricted payments in excess of certain pre-determined thresholds. As of
December 31, 2010, $52.7 million of Chesapeakes cumulative consolidated net income and $28.3
million of FPUs cumulated net income were free of such restrictions.
Chesapeake Utilities Corporation 2010 Form 10-K Page 51
Managements Discussion and Analysis
Short-term Borrowings
Our outstanding short-term borrowings at December 31, 2010 and 2009 were $64.0 million and $30.0
million, respectively, at the weighted average interest rates of 1.77 percent and 1.28 percent,
respectively.
We utilize bank lines of credit to provide funds for our short-term cash needs to meet seasonal
working capital requirements and to fund temporarily portions of the capital expenditure program.
As of December 31, 2010, we had four unsecured bank lines of credit with two financial institutions
for a total of $100.0 million. Two of these unsecured bank lines, totaling $60.0 million, are
available under committed lines of credit. None of these unsecured bank lines of credit requires
compensating balances. Advances offered under the uncommitted lines of credit are subject to the
discretion of the banks. We are currently authorized by our Board of Directors to borrow up to
$85.0 million of short-term debt, as required, from these unsecured bank lines of credit.
Our outstanding borrowings under these unsecured bank lines of credit at December 31, 2010 and 2009
were $30.8 million and $30.0 million, respectively. During 2010, 2009 and 2008, the average
borrowings from these unsecured bank lines of credit were
$10.5 million, $13.0 million and $38.3
million, respectively, at weighted average interest rates of
2.40 percent, 1.28 percent and 2.80
percent, respectively. The maximum month-end borrowings from these unsecured bank lines of credit
during 2010, 2009 and 2008 were $64.0 million, $33.0 million and $61.2 million, respectively, which
occurred during the fall and winter months when our working capital requirements were at the
highest level. Also included in our outstanding short-term borrowings at December 31, 2010 was
$4.1 million representing outstanding checks in excess of funds in deposit, which
if presented would be funded through the bank lines of credit.
In addition to the four unsecured bank lines of credit, we entered into a new credit facility for
$29.1 million with an existing lender in March 2010. We borrowed $29.1 million under this new
credit facility to finance the early
redemption of the 6.85 percent and 4.90 percent series of FPUs secured first mortgage bonds. The interest
rate on the borrowing was fixed at 1.88 percent for nine months and on December 16, 2010 the rate was
fixed for three months at 1.55 percent. On November 1, 2010 we extended the maturity of this credit facility from March 15, 2011 until October 31, 2011.
On June 29, 2010, we entered into an agreement with an existing senior note holder to issue up to
$36 million in uncollateralized senior notes. We expect to use $29 million of the uncollateralized
senior notes to permanently finance the early redemption of the 6.85 percent and 4.90 percent
series of FPU bonds previously discussed. If refinanced prior to July 8, 2011, these new
uncollateralized senior notes will be issued at 5.68 percent and result in annual long-term
interest expense of $1.7 million, representing additional interest of $1.2 million, compared to the
interest expense of $491,000 on the new short-term loan facility used in 2010. We also expect to
use the remaining $7 million to redeem additional FPU secured first mortgage bonds in 2013.
Cash Flows Provided by Operating Activities
Our cash flows provided by operating activities were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31, |
|
2010 |
|
|
2009 |
|
|
2008 |
|
Net income |
|
$ |
26,056 |
|
|
$ |
15,897 |
|
|
$ |
13,607 |
|
Non-cash adjustments to net income |
|
|
37,364 |
|
|
|
28,319 |
|
|
|
22,919 |
|
Changes in assets and liabilities |
|
|
(2,415 |
) |
|
|
1,583 |
|
|
|
(7,982 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash from operating activities |
|
$ |
61,005 |
|
|
$ |
45,799 |
|
|
$ |
28,544 |
|
|
|
|
|
|
|
|
|
|
|
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 prices of natural
gas, electricity and propane, the timing of customer collections, payments for purchases of natural
gas, electricity and propane, and deferred fuel cost recoveries.
Chesapeake Utilities Corporation 2010 Form 10-K Page 52
Managements Discussion and Analysis
We generate a large portion of our annual net income and subsequent increases in our accounts
receivable in the first and fourth quarters of each year due to significant volumes of natural gas
and propane delivered by our natural gas and propane distribution operations to customers during
the peak heating season. In addition, our natural gas and propane inventories, which usually peak
in the fall months, are largely drawn down in the heating season and provide a source of cash as
the inventory is used to satisfy winter sales demand.
In 2010, our net cash flow provided by operating activities was $61.1 million, an increase of $15.3
million compared to 2009. The increase was due primarily to the following:
|
|
|
Net cash flows from changes in accounts receivable and accounts payable were due
primarily to the inclusion of FPU and timing of collections and payments of trading
contracts entered into by our propane wholesale and marketing operation; |
|
|
|
|
Net income increased by $10.2 million. A full years results for FPU and organic growth
within Chesapeakes legacy businesses contributed to this increase; |
|
|
|
|
Non-cash adjustments to net income increased by $12.4 million due primarily to higher
depreciation and amortization, changes in deferred income taxes, higher employee benefits
and compensation and an increase in share based compensation. Higher depreciation and
amortization was due to the inclusion of FPU and an increase in capital investments. The
increase in deferred income taxes was a result of bonus depreciation in 2010, which
significantly reduced our income tax payment obligations in 2010; and |
|
|
|
|
The decrease in income tax receivables was due primarily to the receipt of large refunds
in 2009 due to higher tax deductions in 2009 and 2008 and a decrease in taxes payable due
to bonus depreciation in 2010. |
In 2009, our net cash flow provided by operating activities was $45.8 million, an increase of $17.3
million compared to 2008. The increase was due primarily to the following:
|
|
|
Net cash flows from changes in accounts receivable and accounts payable, 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 purchase of propane inventory, natural gas purchases injected
into storage, and the relative decline in the unit price of these commodities; |
|
|
|
|
Reduction in regulatory liabilities, which resulted primarily from lower deferred gas
cost recoveries in our natural gas distribution operations as the price of natural gas
declined in the second half of 2008; |
|
|
|
|
Reduced payments for income taxes payable as a result of higher 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 was the result of higher book-to-tax timing differences during the
period that were generated by the Economic Stimulus Act, which authorized bonus
depreciation for certain assets. |
Chesapeake Utilities Corporation 2010 Form 10-K Page 53
Managements Discussion and Analysis
Cash Flows Used in Investing Activities
In 2010, net cash flows used by investing activities totaled $48.8 million, an increase of $25.7
million compared to 2009. In 2009, net cash flows used by investing activities totaled $23.1
million, a decrease of $8.1 million compared to 2008.
|
|
|
Cash utilized for capital expenditures was $45.4 million, $26.6 million and $30.8
million for 2010, 2009, and 2008, respectively. |
|
|
|
|
We invested $1.6 million in equity securities and paid $1.2 million and $310,000 for the
acquisition of Indiantown Gas Company and Virginia LP, respectively, in 2010. |
|
|
|
|
In 2009, we received $3.5 million in proceeds from an investment account related to
future environmental costs, as we transferred the amount to our general account that
invests in overnight income-producing securities. We also acquired $359,000 in cash, net
of cash paid, in the FPU merger in 2009. |
|
|
|
|
Environmental expenditures exceeded amounts recovered through rates charged to customers
in 2010, 2009 and 2008 by $290,000, $418,000 and $480,000, respectively. |
Cash Flows Provided by/Used in Financing Activities
In 2010 and 2009, net cash flows used by financing activities totaled $13.4 million and $21.4
million, respectively, compared to net cash flows provided by financing activities of $1.7 million
in 2008. Significant financing activities included the following:
|
|
|
During 2010 we entered into a new term loan with an existing lender and we borrowed
$29.1 million under this facility in order to temporarily finance the early redemption of
the 6.85 percent and 4.90 percent series of FPUs secured first mortgage bonds prior to
their respective maturity. |
|
|
|
|
During 2010 we increased our short-term borrowing by $1.6 million primarily to support
our capital expenditures. During 2009 and 2008, we reduced our short-term debt by $3.8
million and $12.0 million, respectively. |
|
|
|
|
We repaid $36.9 million, $10.9 million and $7.7 million of long-term debt during 2010,
2009 and 2008 respectively. |
|
|
|
|
We paid $11.0 million,
$8.0 million and $7.8 million in cash dividends in 2010, 2009
and 2008, respectively. An increase in cash dividends paid in each year reflects the
growth in the annualized dividend rate. 2010 also reflects dividends on a larger number of
shares outstanding, from the FPU shares that were exchanged for Chesapeake shares in the
merger. |
|
|
|
|
In October 2008, we completed the placement of $30.0 million of 5.93 percent Unsecured
Senior Notes. |
Chesapeake Utilities Corporation 2010 Form 10-K Page 54
Managements Discussion and Analysis
Contractual Obligations
We have the following contractual obligations and other commercial commitments as of December 31,
2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period |
|
Contractual Obligations |
|
Less than 1 |
|
|
|
|
|
|
|
|
|
|
More than 5 |
|
|
|
|
(in thousands) |
|
year |
|
|
1 - 3 years |
|
|
3 - 5 years |
|
|
years |
|
|
Total |
|
|
Long-term debt (1) |
|
$ |
9,216 |
|
|
$ |
16,393 |
|
|
$ |
21,656 |
|
|
$ |
51,682 |
|
|
$ |
98,947 |
|
Operating leases (2) |
|
|
803 |
|
|
|
1,234 |
|
|
|
470 |
|
|
|
2,017 |
|
|
|
4,524 |
|
|
Purchase obligations (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transmission capacity |
|
|
35,051 |
|
|
|
59,761 |
|
|
|
37,949 |
|
|
|
70,293 |
|
|
|
203,054 |
|
Storage Natural Gas |
|
|
2,615 |
|
|
|
4,687 |
|
|
|
1,525 |
|
|
|
2,063 |
|
|
|
10,890 |
|
Commodities |
|
|
37,179 |
|
|
|
100 |
|
|
|
|
|
|
|
|
|
|
|
37,279 |
|
Electric supply |
|
|
1,626 |
|
|
|
26,498 |
|
|
|
26,498 |
|
|
|
39,173 |
|
|
|
93,795 |
|
Forward purchase contracts Propane (4) |
|
|
15,618 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,618 |
|
Other |
|
|
144 |
|
|
|
109 |
|
|
|
|
|
|
|
|
|
|
|
253 |
|
Unfunded benefits (5) |
|
|
1,132 |
|
|
|
731 |
|
|
|
870 |
|
|
|
5,706 |
|
|
|
8,439 |
|
Funded benefits (6) |
|
|
2,400 |
|
|
|
150 |
|
|
|
108 |
|
|
|
1,228 |
|
|
|
3,886 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Contractual Obligations |
|
$ |
105,784 |
|
|
$ |
109,663 |
|
|
$ |
89,076 |
|
|
$ |
172,162 |
|
|
$ |
476,685 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 $6.6 million, $11.4 million, $8.6
million and $13.3 million, respectively, for the periods indicated above. Expected interest
payments for all periods total $40.0 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
Q, 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 Managements
Discussion and Analysis for further information. |
|
(5) |
|
We have recorded long-term liabilities of $8.4 million at December 31, 2010 for
unfunded post-employment and post-retirement benefit plans. The amounts specified in the table
are based on expected payments to current retirees and assume 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 $16.3 million at December 31, 2010 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 Companys balance
sheets. The Contractual Obligations table above includes $1.5 million, reflecting the expected
payments the Company will make to the trust funds in 2011. 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 $2.4
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. |
Off-Balance Sheet Arrangements
The Board of Directors has authorized the Company $35 million of corporate guarantees on behalf of our
subsidiaries and for letters of credit. As of March 2, 2011, the Board increased this limit from $35 million to $45 million.
We have issued corporate guarantees to certain vendors of our subsidiaries, primarily the propane
wholesale marketing subsidiary and the natural gas marketing subsidiary. These corporate
guarantees provide for the payment of propane and natural gas purchases in the event of the
respective subsidiarys default. None of these subsidiaries 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, 2010 was $25.6
million, with the guarantees expiring on various dates in 2011.
Chesapeake Utilities Corporation 2010 Form 10-K Page 55
Managements Discussion and Analysis
In addition to the corporate guarantees, we have issued a letter of credit to our primary
insurance company for $440,625 which expires on December 2, 2011. The letter of credit is provided
as security to satisfy the deductibles under our various insurance outstanding policies. As a
result of the recent change in our primary insurance company, we have issued an additional letter
of credit for $725,000 to our former primary insurance company, which will expire on June 1, 2011.
There have been no draws on these letters of credit as of December 31, 2010. We do not anticipate
that the letters of credit will be drawn upon by the counterparties and we expect that the letters
of credit will be renewed to the extent necessary in the future.
We provided a letter of credit for $2.0 million to TETLP related to the Precedent Agreement with
TETLP. The letter of credit is expected to increase quarterly as TETLPs pre-service costs
increases. The letter of credit will not exceed the three-month reservation charge under the firm
transportation service contracts, which we currently estimate to be $2.1 million.
(f) Rate Filings and Other Regulatory Activities
Our natural gas distribution operations in Delaware, Maryland and Florida and electric distribution
operation in Florida are subject to regulation by their respective PSC; ESNG is subject to
regulation by the FERC; and PIPECO is subject to regulation by the Florida PSC. At December 31,
2010, Chesapeake was involved in rate filings and/or regulatory matters in each of the
jurisdictions in which it operates. Each of these rate filings or regulatory matters is fully
described in Item 8 under the heading Notes to the Consolidated Financial Statements Note O,
Rates and Other Regulatory Activities.
(g) Environmental Matters
We continue to work with federal and state environmental agencies to assess the environmental
impact and explore corrective action at seven environmental sites (see Item 8 under the heading
Notes to the Consolidated Financial Statements Note P, Environmental Commitments and
Contingencies for further detail on each site). We believe that future costs associated with
these sites will be recoverable in rates or through sharing arrangements with, or contributions by,
other responsible parties.
(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. Our long-term
debt consists of fixed-rate senior notes, secured debt and convertible debentures (see Item 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 our long-term debt is fixed-rate debt and was
not entered into for trading purposes. The carrying value of long-term debt, including current
maturities, was $98.9 million at December 31, 2010, as compared to a fair value of $113.4 million,
based on a discounted cash flow methodology that incorporates a market interest rate that is based
on published corporate borrowing rates for debt instruments with similar terms and average
maturities with adjustments for duration, optionality, credit risk, and risk profile. We evaluate
whether to refinance existing debt or permanently refinance existing short-term borrowing, based in
part on the fluctuation in interest rates.
Our propane distribution business
is exposed to market risk as a result of propane storage
activities and entering into fixed price contracts for supply. We can store up to approximately
six million gallons (including leased storage and rail cars) of propane during the winter season
to meet our customers peak requirements and to serve metered customers. Decreases in the
wholesale price of propane may cause the value of stored propane to decline. To mitigate the
impact of price fluctuations, we have adopted a Risk Management Policy that allows the propane
distribution operation to enter into fair value hedges or other economic hedges of our inventory.
Our propane wholesale marketing operation is a party to natural gas liquids forward contracts,
primarily propane contracts, with various third-parties. These contracts require that the propane
wholesale marketing operation purchase or sell natural gas liquids at a fixed price at fixed future
dates. At expiration, the contracts are settled by the delivery of natural gas liquids to us or
the counterparty 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.
Chesapeake Utilities Corporation 2010 Form 10-K Page 56
Managements Discussion and Analysis
The forward and futures contracts are entered into for trading and wholesale marketing
purposes. The propane wholesale marketing business is subject to commodity price risk on its open
positions to the extent that market prices for natural gas liquids deviate from fixed contract
settlement prices. Market risk associated with the trading of futures and forward contracts is
monitored daily for compliance with our Risk Management Policy, which includes volumetric limits
for open positions. To manage exposures to changing market prices, open positions are marked up or
down to market prices and reviewed daily by our oversight officials. In addition, the Risk
Management Committee reviews periodic reports on markets and the credit risk of counterparties,
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, 2010 and 2009 is
presented in the following tables:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quantity in |
|
|
Estimated Market |
|
|
Weighted Average |
|
At December 31, 2010 |
|
Gallons |
|
|
Prices |
|
|
Contract Prices |
|
Forward Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
Sale |
|
|
13,523,496 |
|
|
$1.0350 $1.4100 |
|
|
$ |
1.2192 |
|
Purchase |
|
|
12,914,496 |
|
|
$1.0150 $1.3779 |
|
|
$ |
1.2093 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Contract |
|
|
|
|
|
|
|
|
|
|
|
|
Put option |
|
|
1,470,000 |
|
|
$ |
|
|
$ |
0.1150 |
|
Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expire by the end of the second quarter of 2011.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
At December 31, 2010 and 2009, we marked these forward and other contracts to market, using
market transactions in either the listed or OTC markets, which resulted in the following assets and
liabilities:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
Mark-to-market energy assets |
|
$ |
1,642 |
|
|
$ |
2,379 |
|
Mark-to-market energy liabilities |
|
$ |
1,492 |
|
|
$ |
2,514 |
|
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 or are considered normal purchases and sales and are accounted for on
an accrual basis.
Chesapeake Utilities Corporation 2010 Form 10-K Page 57
Managements Discussion and Analysis
(i) Competition
Our natural gas and electric distribution operations and our natural gas transmission operation
compete with other forms of energy including natural gas, electricity, oil and propane. The
principal competitive factors are price and, to a lesser extent, accessibility. Our natural gas
distribution operations have several large-volume industrial customers that are able to use fuel
oil as an alternative to natural gas. When oil prices decline, these interruptible customers may
convert to oil to satisfy their fuel requirements, and our interruptible sales volumes may decline.
Oil prices, as well as the prices of other fuels, fluctuate for a variety of reasons; therefore,
future competitive conditions are not predictable. To address this uncertainty, we use flexible
pricing arrangements on both the supply and sales sides of this business to compete with
alternative fuel price fluctuations. As a result of the transmission operations conversion to
open access and Chesapeakes Florida natural gas distribution divisions restructuring of its
services, these businesses have shifted from providing bundled transportation and sales service to
providing only transmission and contract storage services. Our electric distribution operation
currently does not face substantial competition 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.
Our natural gas distribution operations in Delaware, Maryland and Florida offer unbundled
transportation services to certain commercial and industrial customers. In 2002, Chesapeakes
Florida natural gas distribution division, Central Florida Gas, extended such service to
residential customers. With such transportation service available on our distribution systems, we
are competing with third-party suppliers to sell gas to industrial customers. With respect to
unbundled transportation services, our competitors include interstate transmission companies, if
the distribution customers are located close enough to a transmission companys pipeline to make
connections economically feasible. The customers at risk are usually large volume commercial and
industrial customers with the financial resources and capability to bypass our existing
distribution operations in this manner. In certain situations, our distribution operations may
adjust services and rates for these customers to retain their business. We expect to continue to
expand the availability of unbundled transportation service to additional classes of distribution
customers in the future. We have also established a natural gas marketing operation in Florida,
Delaware and Maryland to provide such service to customers eligible for unbundled transportation
services.
Our propane distribution operations compete with several other propane distributors in their
respective geographic markets, primarily on the basis of service and price, emphasizing responsive
and reliable service. Our competitors generally include local outlets of national distributors and
local independent distributors, whose proximity to customers entails lower costs to provide
service. Propane competes with electricity as an energy source, because it is typically less
expensive than electricity, based on equivalent BTU value. Propane also competes with home heating
oil as an energy source. Since natural gas has historically been less expensive than propane,
propane is generally not distributed in geographic areas served by natural gas pipeline or
distribution systems.
The propane wholesale marketing operation competes against various regional and national marketers,
many of which have significantly greater resources and are able to obtain price or volumetric
advantages.
Our advanced information services subsidiary faces significant competition from a number of larger
competitors having substantially greater resources available to them than does our subsidiary. In
addition, changes in the advanced information services business are occurring rapidly, and could
adversely affect the markets for the products and services offered by these businesses. This
segment competes on the basis of technological expertise, reputation and price.
Chesapeake Utilities Corporation 2010 Form 10-K Page 58
Managements Discussion and Analysis
(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 regulated natural
gas and electric distribution operations, fluctuations in natural gas and electricity prices are
passed on to customers through the fuel cost recovery mechanism in our tariffs. To help cope with
the effects of inflation on our capital investments and returns, we seek rate increases from
regulatory commissions for our regulated operations and closely monitor the returns of our
unregulated business operations.
To compensate for fluctuations in propane gas prices, we adjust propane selling prices to the
extent allowed by the market.
(k) Marianna Franchise
On March 2, 2011, the City of Marianna,
Florida filed a declaratory action against FPU in the
Circuit Court of the Fourteenth Judicial Circuit in and for Jackson County, Florida, alleging that FPU
breached its obligations under its franchise with the city to provide electric service to customers within
and without the city by failing (i) to develop and implement TOU and interruptible rates that were
mutually agreed to by the city and FPU; (ii) to have such mutually agreed upon rates in effect by February 17, 2011;
and (iii) to have such rates available to all of FPUs customers located within and without the
corporate limits of the city. The city is seeking a declaratory judgment to exercise its option under the
franchise agreement to purchase FPUs property (consisting of the electric distribution assets) within the
City of Marianna. Any such purchase would be subject to approval by the Commission which would also
need to approve the presentation of a referendum to voters in the City of Marianna for approval of the
purchase and the operation by the city of an electric distribution facility. If the purchase is approved by
the Commission and the voters in the City of Marianna, the closing of the purchase must occur within 12 months
after the referendum is approved. If the purchase occurs, FPU would have a gain in the year of the disposition.
Additionally, future financial results would be negatively impacted from the loss in earnings generated by FPU
under the franchise agreement, however such impact is anticipated to be immaterial. FPU intends to file a response to the Citys complaint and vigorously
contest this litigation and intends to oppose the passage of any proposed referendum that is
presented to voters to approve the purchase of the FPU property in the City of Marianna.
Chesapeake Utilities Corporation 2010 Form 10-K Page 59
|
|
|
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 Managements Discussion and Analysis Market Risk.
|
|
|
Item 8. |
|
Financial Statements and Supplementary Data. |
Managements 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. A companys 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 GAAP. A companys internal control over financial reporting includes
those policies and procedures that (i) pertain to the maintenance of records which 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 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 companys 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, Chesapeakes management conducted an evaluation of the
effectiveness of its internal control over financial reporting based on the criteria established in
a report entitled Internal Control Integrated Framework, issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Because of its inherent limitations, internal control
over financial reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
On October 28, 2009, the previously announced merger between Chesapeake and FPU was consummated.
FPUs activity is included in Chesapeakes 2010 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 for additional information relating to
the FPU merger.
Chesapeakes management has evaluated and concluded that Chesapeakes internal control over
financial reporting was effective as of December 31, 2010.
Chesapeake Utilities Corporation 2010 Form 10-K Page 60
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 sheets of Chesapeake Utilities Corporation
(the Company) as of December 31, 2010 and 2009, and the related consolidated statements of
income, stockholders equity and cash flows for each of the years in the three-year period ended
December 31, 2010. These consolidated financial statements are the responsibility of the Companys
management. Our responsibility is to express an opinion on these consolidated financial statements
based on our audits.
We conducted our audits 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 audits 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 as of December 31,
2010 and 2009, and the results of their operations and their cash flows for each of the years in
the three-year period ended December 31, 2010, 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 Corporations internal control over financial reporting
as of December 31, 2010, based on criteria established in Internal ControlIntegrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our
report dated March 8, 2011 expressed an unqualified opinion.
|
|
|
/s/ ParenteBeard LLC
ParenteBeard LLC
|
|
|
Malvern, Pennsylvania |
|
|
March 8, 2011 |
|
|
Chesapeake Utilities Corporation 2010 Form 10-K Page 61
Consolidated Statements of Income
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31, |
|
2010 |
|
|
2009 |
|
|
2008 |
|
(in thousands, except shares and per share data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Regulated Energy |
|
$ |
269,934 |
|
|
$ |
139,099 |
|
|
$ |
116,468 |
|
Unregulated Energy |
|
|
146,793 |
|
|
|
119,973 |
|
|
|
161,290 |
|
Other |
|
|
10,819 |
|
|
|
9,713 |
|
|
|
13,685 |
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
|
427,546 |
|
|
|
268,785 |
|
|
|
291,443 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Regulated energy cost of sales |
|
|
144,217 |
|
|
|
64,803 |
|
|
|
54,789 |
|
Unregulated energy and other cost of sales |
|
|
116,098 |
|
|
|
95,467 |
|
|
|
145,854 |
|
Operations |
|
|
75,335 |
|
|
|
50,706 |
|
|
|
43,476 |
|
Transaction-related costs |
|
|
660 |
|
|
|
1,478 |
|
|
|
1,153 |
|
Maintenance |
|
|
7,484 |
|
|
|
3,430 |
|
|
|
2,215 |
|
Depreciation and amortization |
|
|
20,758 |
|
|
|
11,588 |
|
|
|
9,005 |
|
Other taxes |
|
|
11,064 |
|
|
|
7,577 |
|
|
|
6,472 |
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses |
|
|
375,616 |
|
|
|
235,049 |
|
|
|
262,964 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income |
|
|
51,930 |
|
|
|
33,736 |
|
|
|
28,479 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income, net of other expenses |
|
|
195 |
|
|
|
165 |
|
|
|
103 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest charges |
|
|
9,146 |
|
|
|
7,086 |
|
|
|
6,158 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Taxes |
|
|
42,979 |
|
|
|
26,815 |
|
|
|
22,424 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes |
|
|
16,923 |
|
|
|
10,918 |
|
|
|
8,817 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
$ |
26,056 |
|
|
$ |
15,897 |
|
|
$ |
13,607 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Common Shares Outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
9,474,554 |
|
|
|
7,313,320 |
|
|
|
6,811,848 |
|
Diluted |
|
|
9,582,374 |
|
|
|
7,440,201 |
|
|
|
6,927,483 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Per Share of Common Stock: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
2.75 |
|
|
$ |
2.17 |
|
|
$ |
2.00 |
|
Diluted |
|
$ |
2.73 |
|
|
$ |
2.15 |
|
|
$ |
1.98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Dividends Declared Per Share of Common Stock |
|
$ |
1.305 |
|
|
$ |
1.250 |
|
|
$ |
1.210 |
|
The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation 2010 Form 10-K Page 62
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31, |
|
2010 |
|
|
2009 |
|
|
2008 |
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
$ |
26,056 |
|
|
$ |
15,897 |
|
|
$ |
13,607 |
|
Adjustments to reconcile net income to net operating cash: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
20,758 |
|
|
|
11,588 |
|
|
|
9,005 |
|
Depreciation and accretion included in other costs |
|
|
3,133 |
|
|
|
2,789 |
|
|
|
2,239 |
|
Deferred income taxes, net |
|
|
13,389 |
|
|
|
10,065 |
|
|
|
11,442 |
|
Unrealized (gain) loss on commodity contracts |
|
|
(116 |
) |
|
|
1,606 |
|
|
|
(1,252 |
) |
Unrealized (gain) loss on investments |
|
|
(181 |
) |
|
|
(212 |
) |
|
|
509 |
|
Employee benefits and compensation |
|
|
(757 |
) |
|
|
1,217 |
|
|
|
152 |
|
Share based compensation |
|
|
1,155 |
|
|
|
1,306 |
|
|
|
820 |
|
Other, net |
|
|
(17 |
) |
|
|
(40 |
) |
|
|
4 |
|
Changes in assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of investments |
|
|
(297 |
) |
|
|
(146 |
) |
|
|
(201 |
) |
Accounts receivable and accrued revenue |
|
|
(20,467 |
) |
|
|
(13,652 |
) |
|
|
19,411 |
|
Propane inventory, storage gas and other inventory |
|
|
151 |
|
|
|
2,597 |
|
|
|
(1,730 |
) |
Regulatory assets |
|
|
687 |
|
|
|
(1,842 |
) |
|
|
411 |
|
Prepaid expenses and other current assets |
|
|
1,157 |
|
|
|
(757 |
) |
|
|
(1,182 |
) |
Other deferred charges |
|
|
(156 |
) |
|
|
(83 |
) |
|
|
(153 |
) |
Long-term receivables |
|
|
286 |
|
|
|
191 |
|
|
|
207 |
|
Accounts payable and other accrued liabilities |
|
|
15,853 |
|
|
|
10,185 |
|
|
|
(15,033 |
) |
Income taxes receivable |
|
|
(3,761 |
) |
|
|
5,020 |
|
|
|
(6,155 |
) |
Accrued interest |
|
|
(97 |
) |
|
|
66 |
|
|
|
158 |
|
Customer deposits and refunds |
|
|
2,038 |
|
|
|
(75 |
) |
|
|
(502 |
) |
Accrued compensation |
|
|
1,339 |
|
|
|
(2,066 |
) |
|
|
(175 |
) |
Regulatory liabilities |
|
|
665 |
|
|
|
1,071 |
|
|
|
(3,107 |
) |
Other liabilities |
|
|
187 |
|
|
|
1,074 |
|
|
|
69 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
61,005 |
|
|
|
45,799 |
|
|
|
28,544 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment expenditures |
|
|
(45,411 |
) |
|
|
(26,603 |
) |
|
|
(30,756 |
) |
Cash acquired in the merger, net of cash paid |
|
|
|
|
|
|
359 |
|
|
|
|
|
(Purchases of) proceeds from investments |
|
|
(3,108 |
) |
|
|
3,519 |
|
|
|
|
|
Environmental expenditures |
|
|
(290 |
) |
|
|
(418 |
) |
|
|
(480 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities |
|
|
(48,809 |
) |
|
|
(23,143 |
) |
|
|
(31,236 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Common stock dividends |
|
|
(11,013 |
) |
|
|
(7,957 |
) |
|
|
(7,810 |
) |
Issuance of stock for Dividend Reinvestment Plan |
|
|
568 |
|
|
|
392 |
|
|
|
(118 |
) |
Change in cash overdrafts due to outstanding checks |
|
|
3,255 |
|
|
|
835 |
|
|
|
(684 |
) |
Net borrowing (repayment) under line of credit agreements |
|
|
1,579 |
|
|
|
(3,812 |
) |
|
|
(11,980 |
) |
Other short-term borrowing |
|
|
29,100 |
|
|
|
|
|
|
|
29,961 |
|
Repayment of long-term debt |
|
|
(36,860 |
) |
|
|
(10,907 |
) |
|
|
(7,658 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
(13,371 |
) |
|
|
(21,449 |
) |
|
|
1,711 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Cash Equivalents |
|
|
(1,175 |
) |
|
|
1,207 |
|
|
|
(981 |
) |
Cash and Cash Equivalents Beginning of Period |
|
|
2,818 |
|
|
|
1,611 |
|
|
|
2,592 |
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents End of Period |
|
$ |
1,643 |
|
|
$ |
2,818 |
|
|
$ |
1,611 |
|
|
|
|
|
|
|
|
|
|
|
Supplemental Cash Flow Disclosures (see Note D)
The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation 2010 Form 10-K Page 63
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
Assets |
|
2010 |
|
|
2009 |
|
(in thousands, except shares and per share data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment |
|
|
|
|
|
|
|
|
Regulated energy |
|
$ |
500,689 |
|
|
$ |
462,061 |
|
Unregulated energy |
|
|
61,313 |
|
|
|
61,334 |
|
Other |
|
|
16,989 |
|
|
|
16,049 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment |
|
|
578,991 |
|
|
|
539,444 |
|
Less: Accumulated depreciation and amortization |
|
|
(121,628 |
) |
|
|
(107,318 |
) |
Plus: Construction work in progress |
|
|
5,394 |
|
|
|
4,461 |
|
|
|
|
|
|
|
|
Net property, plant and equipment |
|
|
462,757 |
|
|
|
436,587 |
|
|
|
|
|
|
|
|
|
Investments, at fair value |
|
|
4,036 |
|
|
|
1,959 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
1,643 |
|
|
|
2,818 |
|
Accounts receivable (less allowance for uncollectible
accounts of $1,194 and $1,609, respectively) |
|
|
88,074 |
|
|
|
69,773 |
|
Accrued revenue |
|
|
14,978 |
|
|
|
12,838 |
|
Propane inventory, at average cost |
|
|
8,876 |
|
|
|
7,901 |
|
Other inventory, at average cost |
|
|
3,084 |
|
|
|
3,149 |
|
Regulatory assets |
|
|
51 |
|
|
|
448 |
|
Storage gas prepayments |
|
|
5,084 |
|
|
|
6,144 |
|
Income taxes receivable |
|
|
6,748 |
|
|
|
2,614 |
|
Deferred income taxes |
|
|
2,191 |
|
|
|
724 |
|
Prepaid expenses |
|
|
4,613 |
|
|
|
5,853 |
|
Mark-to-market energy assets |
|
|
1,642 |
|
|
|
2,379 |
|
Other current assets |
|
|
245 |
|
|
|
147 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
137,229 |
|
|
|
114,788 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Charges and Other Assets |
|
|
|
|
|
|
|
|
Goodwill |
|
|
35,613 |
|
|
|
34,095 |
|
Other intangible assets, net |
|
|
3,459 |
|
|
|
3,951 |
|
Long-term receivables |
|
|
155 |
|
|
|
440 |
|
Regulatory assets |
|
|
23,884 |
|
|
|
20,100 |
|
Other deferred charges |
|
|
3,860 |
|
|
|
3,891 |
|
|
|
|
|
|
|
|
Total deferred charges and other assets |
|
|
66,971 |
|
|
|
62,477 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
670,993 |
|
|
$ |
615,811 |
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation 2010 Form 10-K Page 64
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
Capitalization and Liabilities |
|
2010 |
|
|
2009 |
|
(in thousands, except shares and per share data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalization |
|
|
|
|
|
|
|
|
Stockholders equity |
|
|
|
|
|
|
|
|
Common stock, par value $0.4867 per share
(authorized 25,000,000 and 12,000,000 shares, respectively) |
|
$ |
4,635 |
|
|
$ |
4,572 |
|
Additional paid-in capital |
|
|
148,159 |
|
|
|
144,502 |
|
Retained earnings |
|
|
76,805 |
|
|
|
63,231 |
|
Accumulated other comprehensive loss |
|
|
(3,360 |
) |
|
|
(2,524 |
) |
Deferred compensation obligation |
|
|
777 |
|
|
|
739 |
|
Treasury stock |
|
|
(777 |
) |
|
|
(739 |
) |
|
|
|
|
|
|
|
Total stockholders equity |
|
|
226,239 |
|
|
|
209,781 |
|
|
Long-term debt, net of current maturities |
|
|
89,642 |
|
|
|
98,814 |
|
|
|
|
|
|
|
|
Total capitalization |
|
|
315,881 |
|
|
|
308,595 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
Current portion of long-term debt |
|
|
9,216 |
|
|
|
35,299 |
|
Short-term borrowing |
|
|
63,958 |
|
|
|
30,023 |
|
Accounts payable |
|
|
65,541 |
|
|
|
51,462 |
|
Customer deposits and refunds |
|
|
26,317 |
|
|
|
25,046 |
|
Accrued interest |
|
|
1,789 |
|
|
|
1,887 |
|
Dividends payable |
|
|
3,143 |
|
|
|
2,959 |
|
Accrued compensation |
|
|
6,784 |
|
|
|
5,341 |
|
Regulatory liabilities |
|
|
9,009 |
|
|
|
8,295 |
|
Mark-to-market energy liabilities |
|
|
1,492 |
|
|
|
2,514 |
|
Other accrued liabilities |
|
|
10,393 |
|
|
|
7,017 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
197,642 |
|
|
|
169,843 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Credits and Other Liabilities |
|
|
|
|
|
|
|
|
Deferred income taxes |
|
|
80,031 |
|
|
|
66,008 |
|
Deferred investment tax credits |
|
|
243 |
|
|
|
335 |
|
Regulatory liabilities |
|
|
3,734 |
|
|
|
4,393 |
|
Environmental liabilities |
|
|
10,587 |
|
|
|
11,104 |
|
Other pension and benefit costs |
|
|
18,199 |
|
|
|
15,088 |
|
Accrued asset removal cost Regulatory liability |
|
|
35,092 |
|
|
|
33,214 |
|
Other liabilities |
|
|
9,584 |
|
|
|
7,231 |
|
|
|
|
|
|
|
|
Total deferred credits and other liabilities |
|
|
157,470 |
|
|
|
137,373 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other commitments and contingencies (Note P and Q) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization and Liabilities |
|
$ |
670,993 |
|
|
$ |
615,811 |
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation 2010 Form 10-K Page 65
Consolidated Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock |
|
|
|
|
|
|
|
|
|
|
Accumulated Other |
|
|
|
|
|
|
|
|
|
|
|
|
Number of |
|
|
|
|
|
|
Additional Paid-In |
|
|
|
|
|
|
Comprehensive |
|
|
Deferred |
|
|
|
|
|
|
|
(in thousands, except shares and per share data) |
|
Shares(7) |
|
|
Par Value |
|
|
Capital |
|
|
Retained Earnings |
|
|
Loss |
|
|
Compensation |
|
|
Treasury Stock |
|
|
Total |
|
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 |
|
Net Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,056 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,056 |
|
Other comprehensive income, net of tax: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee Benefit Plans, net of tax: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of prior service costs (4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
8 |
|
Net loss (5) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(844 |
) |
|
|
|
|
|
|
|
|
|
|
(844 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25,220 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividend Reinvestment Plan |
|
|
53,806 |
|
|
|
26 |
|
|
|
1,699 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,725 |
|
Retirement Savings Plan |
|
|
27,795 |
|
|
|
14 |
|
|
|
889 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
903 |
|
Conversion of debentures |
|
|
11,865 |
|
|
|
6 |
|
|
|
196 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
202 |
|
Tax benefit on share based compensation |
|
|
|
|
|
|
|
|
|
|
253 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
253 |
|
Share based compensation (1) (3) |
|
|
36,415 |
|
|
|
17 |
|
|
|
620 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
637 |
|
Deferred Compensation Plan (6) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38 |
|
|
|
(38 |
) |
|
|
|
|
Purchase of treasury stock |
|
|
1,144 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(38 |
) |
|
|
(38 |
) |
Sale and distribution of treasury stock |
|
|
(1,144 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38 |
|
|
|
38 |
|
Dividends on stock-based compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(103 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(103 |
) |
Cash dividends (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,379 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,379 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2010 |
|
|
9,524,195 |
|
|
$ |
4,635 |
|
|
$ |
148,159 |
|
|
$ |
76,805 |
|
|
$ |
(3,360 |
) |
|
$ |
777 |
|
|
$ |
(777 |
) |
|
$ |
226,239 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes amounts for shares issued for Directors compensation. |
|
(2) |
|
Cash dividends declared per share for the periods ended December 31, 2010, 2009 and
2008 were $1.305, $1.250 and $1.210 respectively. |
|
(3) |
|
The shares issued under the Performance Incentive Plan (PIP) are net of shares
withheld for employee taxes. For 2010 and 2008, the Company withheld 17,695 and 12,511
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, 2010, 2009 and 2008 were approximately $5,
$5 and ($52) respectively. |
|
(5) |
|
Tax expense (benefit) recognized on the net gain (loss) component of employees
benefit plans for the periods ended December 31, 2010, 2009 and
2008 were ($541), $794 and
($1,900) respectively. |
|
(6) |
|
In May and November 2009, certain participants of the Deferred Compensation Plan
received distributions totaling $883. There were no distributions in 2010 and 2008. |
|
(7) |
|
Includes 29,600, 28,452, and 62,221 shares at December 31, 2010, 2009 and 2008,
respectively, held in a Rabbi Trust established by the Company relating to the Deferred
Compensation Plan. |
The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation 2010 Form 10-K Page 66
Notes to the Consolidated 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. Our regulated energy business
delivers natural gas to approximately 120,000 customers located in central and southern Delaware,
Marylands Eastern Shore and Florida and electricity to approximately 31,000 customers in northeast
and northwest Florida. Our regulated energy business also provides natural gas transmission
service primarily through a 396-mile interstate pipeline from various points in Pennsylvania and
northern Delaware to our natural gas distribution affiliates in Delaware and Maryland as well as to
other utility and industrial customers in Pennsylvania, Delaware and the Eastern Shore of Maryland.
Our unregulated energy business includes natural gas marketing, propane distribution and propane
wholesale marketing operations. The natural gas marketing operation sells natural gas supplies
directly to commercial and industrial customers in Florida, Delaware and Maryland. Through our
propane distribution operation, we distribute propane to approximately 48,000 customers in
Delaware, the Eastern Shore of Maryland and Virginia, southeastern Pennsylvania and Florida. 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.
We also engage in non-energy businesses, primarily through our advanced information services
subsidiary, which provides 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 Chesapeake and its wholly-owned
subsidiaries. As a result of the merger with FPU on October 28, 2009, FPUs 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
Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject
to regulation by their respective PSC with respect to their rates for service, maintenance of their
accounting records and various other matters. ESNG is an open access pipeline regulated 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 unregulated energy and other unregulated businesses are not subject to regulation
with respect to rates, service or maintenance of accounting records.
Reclassifications
We reclassified certain amounts in the consolidated balance sheet as of December 31, 2009 and in
the consolidated statements of cash flows for the years ended December 31, 2009 and 2008 to conform
to the current years presentation. These reclassifications are considered immaterial to the
overall presentation of our consolidated financial statements.
Use of Estimates
Our financial statements are prepared in conformity with GAAP, which requires management to make
estimates in measuring assets and liabilities and related revenues and expenses. These estimates
involve judgments with respect to, among other things, various future economic factors that are
difficult to predict and are beyond our control; therefore, actual results could differ from these
estimates.
Chesapeake Utilities Corporation 2010 Form 10-K Page 67
Notes to the Consolidated Financial Statements
Property, Plant, Equipment and Depreciation
Property, plant and equipment is stated at original 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 property owned by the unregulated businesses, the
gain or loss, net of salvage value, is charged to income. Upon retirement or disposition of
property within the 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 various annual rates, as approved by the regulators.
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
|
|
|
|
2010 |
|
|
2009 |
|
|
Useful Life(1) |
(in thousands) |
|
|
|
|
|
|
|
|
Plant in service |
|
|
|
|
|
|
|
|
|
|
Mains |
|
$ |
259,672 |
|
|
$ |
236,352 |
|
|
27-62 years |
Services utility |
|
|
68,349 |
|
|
|
65,070 |
|
|
12-48 years |
Compressor station equipment |
|
|
24,952 |
|
|
|
24,981 |
|
|
42 years |
Liquified petroleum gas equipment |
|
|
27,623 |
|
|
|
28,240 |
|
|
5-31 years |
Meters and meter installations |
|
|
32,850 |
|
|
|
28,419 |
|
|
Unregulated energy 3-33 years, regulated energy 14-49 years |
Measuring and regulating station equipment |
|
|
22,332 |
|
|
|
17,708 |
|
|
14-54 years |
Office furniture and equipment |
|
|
15,796 |
|
|
|
15,532 |
|
|
Unregulated energy 4-7 years, regulated energy 14-25 years |
Transportation equipment |
|
|
17,046 |
|
|
|
16,613 |
|
|
1-20 years |
Structures and improvements |
|
|
16,290 |
|
|
|
15,184 |
|
|
3-44 years (2) |
Land and land rights |
|
|
15,052 |
|
|
|
12,789 |
|
|
Not depreciable, except certain regulated assets |
Propane bulk plants and tanks |
|
|
7,967 |
|
|
|
7,275 |
|
|
12-40 years |
Electric transmission lines and transformers |
|
|
30,669 |
|
|
|
29,024 |
|
|
10-41 years |
Poles and towers |
|
|
9,259 |
|
|
|
8,434 |
|
|
21-40 years |
Other equipment |
|
|
9,189 |
|
|
|
11,147 |
|
|
10-61 years |
Various |
|
|
21,945 |
|
|
|
22,676 |
|
|
Various |
|
|
|
|
|
|
|
|
|
Total plant in service |
|
|
578,991 |
|
|
|
539,444 |
|
|
|
Plus construction work in progress |
|
|
5,394 |
|
|
|
4,461 |
|
|
|
Less accumulated depreciation |
|
|
(121,628 |
) |
|
|
(107,318 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment |
|
$ |
462,757 |
|
|
$ |
436,587 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. |
Chesapeake Utilities Corporation 2010 Form 10-K Page 68
Notes to the Consolidated Financial Statements
Plant in service includes $1.4 million of assets owned by one of our natural gas transmission
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 provides $264,000 in annual revenues for a term of 20 years. Accumulated
depreciation for these assets total $146,000 at December 31, 2010.
Cash and Cash Equivalents
Our policy is to invest cash in excess of operating requirements in overnight income-producing
accounts. Such amounts are stated at cost, which approximates market value. Investments with an
original maturity of three months or less when purchased are considered cash equivalents.
Inventories
We use the average cost method to value propane, 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
We account for our regulated operations in accordance with ASC Topic 980, Regulated Operations.
This Topic 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, a regulated company defers the associated
costs as 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 as regulatory liabilities. If we were to require to terminate the
application of these regulatory provisions to our regulated operations, all such deferred amounts
would be recognized in the statement of income at that time, which could have a material impact to
our financial position, result of operation and cash flows.
Chesapeake Utilities Corporation 2010 Form 10-K Page 69
Notes to the Consolidated Financial Statements
At December 31, 2010 and 2009, 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, |
|
|
|
2010 |
|
|
2009 |
|
(in thousands) |
|
|
|
|
|
|
|
|
Regulatory Assets |
|
|
|
|
|
|
|
|
Underrecovered purchased fuel costs |
|
$ |
|
|
|
$ |
368 |
|
Income tax related amounts due from customers |
|
|
1,897 |
|
|
|
2,022 |
|
Deferred post retirement benefits |
|
|
8,304 |
|
|
|
3,636 |
|
Deferred transaction and transition costs |
|
|
1,264 |
|
|
|
1,486 |
|
Deferred conversion and development costs |
|
|
2,069 |
|
|
|
2,720 |
|
Environmental regulatory assets and expenditures |
|
|
6,826 |
|
|
|
7,510 |
|
Acquisition adjustment (1) |
|
|
764 |
|
|
|
795 |
|
Loss on reacquired debt(3) |
|
|
1,668 |
|
|
|
154 |
|
Other |
|
|
1,143 |
|
|
|
1,857 |
|
|
|
|
|
|
|
|
Total Regulatory Assets |
|
$ |
23,935 |
|
|
$ |
20,548 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory Liabilities |
|
|
|
|
|
|
|
|
Self insurance |
|
$ |
1,265 |
|
|
$ |
1,152 |
|
Overrecovered purchased fuel costs |
|
|
8,159 |
|
|
|
6,523 |
|
Shared interruptible margins |
|
|
|
|
|
|
84 |
|
Conservation cost recovery |
|
|
320 |
|
|
|
1,060 |
|
Rate refund(2) |
|
|
|
|
|
|
258 |
|
Income tax related amounts due to customers |
|
|
48 |
|
|
|
74 |
|
Storm reserve |
|
|
2,682 |
|
|
|
2,554 |
|
Accrued asset removal cost |
|
|
35,092 |
|
|
|
33,214 |
|
Other |
|
|
269 |
|
|
|
983 |
|
|
|
|
|
|
|
|
Total Regulatory Liabilities |
|
$ |
47,835 |
|
|
$ |
45,902 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Net carrying value of goodwill from FPUs previous acquisition that is allowed to be amortized pursuant to a rate order. |
|
(2) |
|
Refunded to FPU natural gas customers in February 2010. |
|
(3) |
|
Gains and losses resulting from the reacquisition of long-term debt, which are
amortized over future periods as adjustments to interest expense in accordance with established regulatory practice. |
We have deferred certain costs as regulatory assets prior to obtaining specific regulatory
approvals. We have deferred $1.3 million and $1.5 million, of FPU merger-related costs at December
31, 2010 and 2009, respectively, as deferred transaction and transition costs above, which
represent our estimate, based on similar proceedings in Florida in the past, of the merger-related
costs which we expect to be permitted to recover when we complete the appropriate proceedings. We
are currently in the process of discussing this recovery with the Office of Public Counsel. Also
included in income tax related amounts due from customers are $1.2 million and $838,000 at December
31, 2010 and 2009, respectively, for which we are currently seeking recovery in the rate case.
With the exception of purchased fuel costs and deferred conversion and development costs, there are
no material regulatory assets for which we have not earned the appropriate rate of return.
We monitor our regulatory and competitive environment to determine whether the recovery of our
regulatory assets continues to be probable. If we were to determine that recovery of these assets
is no longer probable, we would write off the assets against earnings. We believe that provisions
of ASC Topic 980 Regulated Operations continue to apply to our regulated operations and that the
recovery of our regulatory assets is probable.
Chesapeake Utilities Corporation 2010 Form 10-K Page 70
Notes to the Consolidated Financial Statements
Goodwill and Other Intangible Assets
Goodwill is not amortized but is tested for impairment at least annually. In addition, goodwill of
a reporting unit is tested for impairment between annual tests if an event occurs or circumstances
change that would more likely than not reduce the fair value of a reporting unit below its carrying
value. Other intangible assets are amortized on a straight-line basis over their estimated economic
useful lives. Please refer to Note H, Goodwill and Other Intangible Assets, to the Consolidated
Financial Statements for additional discussion 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 the Moodys 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.
Actual changes in the fair value of plan assets and the differences between the actual return on
plan assets and the expected return on plan assets could have a material effect on the amount of
pension and postretirement benefit costs that we ultimately recognize. A 0.25 percent increase in
the discount rate could decrease our pension and postretirement costs by approximately $98,000 and
a decrease of 0.25 percent could increase our pension and postretirement costs by $123,000. A 0.25
percent increase in the rate of return would decrease our pension cost by approximately $112,000,
and a decrease of 0.25 percent could increase our pension cost by approximately $117,000 and will not
have an impact on postretirement and SERP plans because these plans are not funded.
Chesapeake Utilities Corporation 2010 Form 10-K Page 71
Notes to the Consolidated Financial Statements
Income Taxes and Investment Tax Credit Adjustments
Deferred tax assets and liabilities are recorded for the tax effect of temporary differences
between the financial statement 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 our deferred tax liabilities applicable to regulated 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.
We account for uncertainty in income taxes in the financial statements only if it is more likely
than not that an uncertain tax position is sustainable based on technical merits. Recognizable
tax positions are then measured to determine the amount of benefit recognized in the financial
statements.
Financial Instruments
Xeron, our 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, our 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 statements of income in the period of change. There were unrealized gains of $284,000
in 2010 and unrealized losses of $1.6 million in 2009. Trading liabilities are recorded as
mark-to-market energy liabilities. Trading assets are recorded as mark-to-market energy assets.
Our natural gas, electric and propane distribution operations and natural gas marketing operations
have entered into agreements with suppliers to purchase natural gas, electricity and propane for
resale to their customers. Purchases under these contracts either do not meet the definition of
derivatives or are considered normal purchases and sales and are accounted for on an accrual
basis.
The propane distribution operation may enter into a fair value hedge of its inventory in order to
mitigate the impact of wholesale price fluctuations. During 2008, we entered into a swap agreement
to protect the Company from the impact that propane price increases would have on the Pro-Cap
(propane price cap) Plan that the Delmarva propane distribution operation offers to our customers.
Propane prices declined significantly in late 2008 and we recorded a mark-to-market loss of
approximately $939,000 on the swap agreement in 2008, which increased the cost of propane sales.
In January 2009, we terminated the swap agreement. The propane distribution operation may enter
into a fair value hedge of its inventory in order to mitigate the impact of wholesale price
fluctuations. During 2010 and 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 $168,000 and $41,000,
respectively. At both December 31, 2010 and 2009, the fair value of the put options was $0.
Chesapeake Utilities Corporation 2010 Form 10-K Page 72
Notes to the Consolidated Financial Statements
Earnings Per Share
Basic earnings per share are 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 are computed by dividing income available for common stockholders 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, |
|
2010 |
|
|
2009 |
|
|
2008 |
|
(in thousands, except shares and per share data) |
|
|
|
|
|
|
|
|
|
|
|
|
Calculation of Basic Earnings Per Share: |
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
$ |
26,056 |
|
|
$ |
15,897 |
|
|
$ |
13,607 |
|
Weighted average shares outstanding |
|
|
9,474,554 |
|
|
|
7,313,320 |
|
|
|
6,811,848 |
|
|
|
|
|
|
|
|
|
|
|
Basic Earnings Per Share |
|
$ |
2.75 |
|
|
$ |
2.17 |
|
|
$ |
2.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Calculation of Diluted Earnings Per Share: |
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Numerator: |
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
$ |
26,056 |
|
|
$ |
15,897 |
|
|
$ |
13,607 |
|
Effect of 8.25% Convertible debentures |
|
|
73 |
|
|
|
79 |
|
|
|
89 |
|
|
|
|
|
|
|
|
|
|
|
Adjusted numerator Diluted |
|
$ |
26,129 |
|
|
$ |
15,976 |
|
|
$ |
13,696 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Denominator: |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted shares outstanding Basic |
|
|
9,474,554 |
|
|
|
7,313,320 |
|
|
|
6,811,848 |
|
Effect of dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Share-based Compensation |
|
|
22,550 |
|
|
|
34,229 |
|
|
|
12,083 |
|
8.25% Convertible debentures |
|
|
85,270 |
|
|
|
92,652 |
|
|
|
103,552 |
|
|
|
|
|
|
|
|
|
|
|
Adjusted denominator Diluted |
|
|
9,582,374 |
|
|
|
7,440,201 |
|
|
|
6,927,483 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted Earnings Per Share |
|
$ |
2.73 |
|
|
$ |
2.15 |
|
|
$ |
1.98 |
|
|
|
|
|
|
|
|
|
|
|
Common stock issued in connection with the FPU merger (See Note B, Acquisitions, to the
Consolidated Financial Statements) increased weighted average shares outstanding during 2010 and
2009.
Operating Revenues
Revenues for our natural gas and electric distribution operations are based on rates approved by
the PSCs of the states in which they operate. The natural gas transmission operations revenues
are based on rates approved by the FERC. Customers base rates may not be changed without formal
approval by these commissions. The PSCs, however, have authorized our regulated operations to
negotiate rates, based on approved methodologies, with customers that have competitive
alternatives. The FERC has also authorized ESNG to negotiate rates above or below the
FERC-approved maximum rates, which customers can elect as an alternative to negotiated rates.
For regulated deliveries of natural gas and electricity, we read meters and bill customers on
monthly cycles that do not coincide with the accounting periods used for financial reporting
purposes. We accrue unbilled revenues for natural gas and electricity that have 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, we must estimate the amount of natural gas and electricity that have
not been accounted for on our delivery systems 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, and natural gas marketing
customers, whose billing cycles do not coincide with the accounting periods.
Chesapeake Utilities Corporation 2010 Form 10-K Page 73
Notes to the Consolidated Financial Statements
The propane wholesale marketing operation records trading activity for open contracts on a net
mark-to-market basis in our consolidated statement of income. For propane distribution customers
without meters and advanced information services customers, we record revenue in the period the
products are delivered and/or services are rendered.
Each of our natural gas distribution operations in Delaware and Maryland, our FPU natural gas
operation and electric distribution operation in Florida has a purchased fuel cost recovery
mechanism. This mechanism provides a method of adjusting the billing rates to reflect changes in
the cost of purchased fuel. The difference between the current cost of fuel purchased and the cost
of fuel recovered in billed rates is deferred and accounted for as either unrecovered purchased
fuel costs or amounts payable to customers. Generally, these deferred amounts are recovered or
refunded within one year. Chesapeakes Florida natural gas distribution division provides only
unbundled delivery service.
We charge flexible rates to our natural gas distribution industrial interruptible customers to
compete with prices of alternative fuels, which these customers are able to use. Neither we nor
any of our interruptible customers is contractually obligated to deliver or receive natural gas on
a firm service basis.
We report revenue taxes, such as gross receipts taxes, franchise taxes, and sales taxes, on a net
basis.
Cost of Sales
Cost of sales includes the direct costs attributable to the products sold or services we provide
for our 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 retirements 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 receivables
balance to the amount we reasonably expect to collect based upon our collections experiences and
managements assessment of our customers inability or reluctance to pay. If circumstances change,
our estimates of recoverable accounts receivable may also change. Circumstances which could affect
such 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 when they
are deemed to be uncollectible.
Chesapeake Utilities Corporation 2010 Form 10-K Page 74
Notes to the Consolidated Financial Statements
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 the acquirers intended use of those assets. In estimating the fair
value of the assets and liabilities subject to rate regulation, we considered the nature of the
assets and liabilities and the regulatory mechanism for recovery, to which these assets and
liabilities are subject, 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 our value of net assets and future earnings.
Total value of the consideration transferred by Chesapeake in the FPU merger was $75.7 million.
Net fair value of the assets acquired and liabilities assumed in the FPU merger was estimated to be
$41.5 million. This resulted in a purchase premium of $34.2 million, which was reflected as
goodwill. Note B, Acquisitions, to the Consolidated Financial Statements describes more fully
the purchase price allocation.
Subsequent Events
We have assessed and reported on subsequent events through the date of issuance of these
Consolidated Financial Statements.
FASB Statements and Other Authoritative Pronouncements
Recent Accounting Amendments 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
(IFRS), a comprehensive series of accounting standards published by the International Accounting
Standards Board (IASB). Under the proposed roadmap, we may be required to prepare our financial
statements in accordance with IFRS as early as 2015. 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, which sets out the scope, recognition and measurement criteria, and
accounting disclosures for assets and liabilities that arise in the context of cost-of-service
regulation, to which our rate-regulated businesses are subject. Throughout 2010, IASB has
continued its deliberation on the exposure draft and comments received on the overall concept of
the recognition of assets and liabilities arising out of cost-of-service regulation. We will
continue to monitor the development of the potential implementation of IFRS.
Other Accounting Amendments Adopted by the Company in 2010
In January 2010, the FASB issued FASB Accounting Standards Update (ASU) 2010-06, Fair Value
Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements.
This ASU requires certain new disclosures and clarifies certain existing disclosure requirements
about fair value measurement, as set forth in FASB ASC Subtopic 820-10. The FASBs 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 reporting entity to disclose
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 reporting entity should present separate
information about purchases, sales, issuances, and settlements. In addition, ASU 2010-06 clarifies
certain requirements of the existing disclosures. We adopted the disclosures required by this ASU
in the first quarter of 2010, except for disclosures about purchases, sales, issuances, and
settlements in the roll-forward of activity in Level 3 fair value measurements. Those disclosures
are effective for fiscal years beginning after December 15, 2010, and for interim periods within
those fiscal years. We currently do not have any assets or liabilities that would require Level 3
fair value measurements. Adoption of this ASU did not have an impact on our consolidated financial
position and results of operations and cash flows.
Chesapeake Utilities Corporation 2010 Form 10-K Page 75
Notes to the Consolidated Financial Statements
In April 2010, the FASB issued FASB ASU 2010-12 Income Taxes (Topic 740), Accounting for
Certain Tax effects of the 2010 Health Care Reform Acts. This ASU codifies the SEC staff
announcement relating to the accounting for the Health Care and Education Reconciliation Act and
the Patient Protection and Affordable Care Act, which allows the two Acts to be considered together
for accounting purposes. We adopted this ASU in the first quarter of 2010 and have determined that
these Acts did not have a material impact on our income tax accounting (see Note M, Employee
Benefit Plans, to the Consolidated Financial Statements for further discussion).
B. Acquisitions
FPU
On October 28, 2009, we completed a 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 increased our overall presence in Florida by adding approximately 51,000 natural gas
distribution customers and 12,000 propane distribution customers to our existing Florida
operations. As a result of the merger, we also now serve 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 was no contingent
consideration in the merger. The total value of consideration 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 values, for which GAAP provides specific exception to the fair value
recognition and measurement, we applied other specified GAAP or accounting treatment as
appropriate.
Chesapeake Utilities Corporation 2010 Form 10-K Page 76
Notes to the Consolidated Financial Statements
The following table summarizes the final allocation of the purchase price to the assets acquired
and liabilities assumed at the date of the merger.
|
|
|
|
|
|
|
October 28, 2009 |
|
(in thousands) |
|
|
|
|
Purchase price |
|
$ |
75,699 |
|
|
|
|
|
|
Current assets |
|
|
26,761 |
|
Property, plant and equipment |
|
|
139,709 |
|
Regulatory assets |
|
|
19,899 |
|
Investments and other deferred charges |
|
|
3,659 |
|
Intangible assets |
|
|
4,019 |
|
|
|
|
|
Total assets acquired |
|
|
194,047 |
|
|
|
|
|
|
Long term debt |
|
|
47,812 |
|
Borrowings from line of credit |
|
|
4,249 |
|
Other current liabilities |
|
|
17,427 |
|
Pre-merger contingencies |
|
|
923 |
|
Other regulatory liabilities |
|
|
19,414 |
|
Pension and post retirement obligations |
|
|
14,276 |
|
Environmental liabilities |
|
|
12,414 |
|
Deferred income taxes |
|
|
20,559 |
|
Customer deposits and other liabilities |
|
|
15,467 |
|
|
|
|
|
Total liabilities assumed |
|
|
152,541 |
|
|
|
|
|
Net identifiable assets acquired |
|
|
41,506 |
|
|
|
|
|
Goodwill |
|
$ |
34,193 |
|
|
|
|
|
|
|
During 2010, we adjusted the allocation of the purchase price based on additional information
available. The adjustments are related to certain accruals, regulatory assets, deferred and
current income tax assets and liabilities, and pre-merger contingencies (see discussion below).
These adjustments also resulted in a change in fair value of the propane property, plant and
equipment. Goodwill from the merger increased to $34.2 million after incorporating these
adjustments, compared to $33.4 million as previously disclosed at December 31, 2009. |
|
|
None of the $34.2 million in goodwill recorded in connection with the merger 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 to the synergies
and opportunities primarily related to FPUs regulated energy businesses. The intangible assets
acquired in connection with the merger are related to propane customer list ($3.5 million) and
favorable propane supply contracts ($519,000). The intangible value assigned to FPUs existing
propane customer list is being amortized over a 12-year period based on the expected duration of
the benefit arising from the list. The intangible value assigned to FPUs favorable propane
contracts is being amortized over a period ranging from one to 14 months based on contractual
terms. |
|
|
Current assets of $26.8 million acquired during the merger included notes receivable of
approximately $5.8 million, for which we received full payment in March 2010, and accounts
receivable of approximately $3.1 million, $6.0 million and $891,000 for FPUs natural gas,
electric and propane distribution businesses, respectively. |
|
|
The pre-merger contingencies of $923,000 included in the final allocation of the purchase price
are primarily related to a pending settlement agreement for a class action complaint against
FPU from a propane customer, which is further discussed in Note Q, Other Commitments and
Contingencies to the Consolidated Financial Statements. The proposed settlement addresses a
particular charge by FPU to its propane customers during the period from May 27, 2006 to
September 24, 2010, which encompasses both pre-merger and post-merger periods. We used the
ratio of the charges assessed to customers during the pre-merger period to the charges assessed
to customers during the total settlement period to estimate that $835,000 of the total
contingency was related to FPUs operations prior to the merger with Chesapeake. The portion of
the liability related to FPUs operations after the merger with Chesapeake and any increases to
the liability after the measurement date, which totaled to $370,000, was expensed in 2010. Also
included in the pre-merger contingencies are liabilities related to FPUs income taxes for
periods prior to the merger. |
Chesapeake Utilities Corporation 2010 Form 10-K Page 77
Notes to the Consolidated Financial Statements
|
|
The financial position and results of operations and cash flows of FPU from the effective
date of the merger are included in our consolidated financial statements. The revenue from FPU
for the years December 31, 2010 and 2009, included in our consolidated statements of income,
were $180.2 million and $26.4 million, respectively, and the net income from FPU for the years
ended December 31, 2010 and 2009, included in our consolidated statements of income, were $9.3
million and $1.8 million, respectively. |
|
|
The following table shows the actual results of combined operations for the year ended December
31, 2010 and pro forma results of combined operations for the year ended December 31, 2009, as
if the merger had been completed at January 1, 2009. Since the effects of the merger for the
year ended December 31, 2010 were already included in the actual results of our consolidated
operations, there is no pro forma adjustment for the year ended December 31, 2010. |
|
|
|
|
|
|
|
|
|
For the Years Ended December 31, |
|
2010 |
|
|
2009 |
|
(in thousands, except per share data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
427,546 |
|
|
$ |
394,772 |
|
Operating Income |
|
$ |
51,930 |
|
|
$ |
44,382 |
|
Net Income |
|
$ |
26,056 |
|
|
$ |
20,872 |
|
|
|
|
|
|
|
|
|
|
Earnings per share basic |
|
$ |
2.75 |
|
|
$ |
2.23 |
|
Earnings per
share diluted |
|
$ |
2.73 |
|
|
$ |
2.20 |
|
Pro forma results are presented for informational purposes only and are not necessarily
indicative of what the actual results would have been had the acquisition actually occurred on
January 1, 2009.
The acquisition method of accounting 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. 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 the proper accounting treatment for the
merger-related costs. As of December 31, 2010, we incurred approximately $3.3 million in costs to
consummate the merger, including the cost associated with merger-related litigation and integrating
operations following the merger. This includes $369,000 incurred during the year ended December
31, 2010. We deferred approximately $1.3 million of the total costs incurred as a regulatory asset
at December 31, 2010, 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.
Included in the $3.3 million merger-related costs incurred as of December 31, 2010, were
approximately $452,000 of severance and other restructuring charges for our efforts to integrate
the operations of the two companies.
Virginia LP Gas
On February 4, 2010, Sharp Energy, Inc. (Sharp), our propane distribution subsidiary, purchased
the operating assets of Virginia LP Gas, Inc., a propane distributor serving approximately 1,000
retail customers in Northampton and Accomack Counties in Virginia. The total consideration for the
purchase was $600,000, of which $300,000 was paid at the closing and the remaining $300,000 will be
paid over 60 months. Based on our valuation, we allocated $188,000 of the purchase price to
intangible assets, which consist of customer lists and non-compete agreements. These intangible
assets are being amortized over a seven-year period. There was no goodwill recorded in connection
with this acquisition. The revenue and net income from this acquisition which were included in our
consolidated statement of income for the year ended December 31, 2010 were not material.
Chesapeake Utilities Corporation 2010 Form 10-K Page 78
Notes to the Consolidated Financial Statements
Indiantown Gas Company
On August 9, 2010, FPU purchased the natural gas operating assets of IGC, which provides natural
gas distribution services to approximately 700 customers including two large industrial customers
in Indiantown, Florida. FPU paid approximately $1.2 million for these assets. FPU recorded
$742,000 in goodwill in connection with this acquisition, all of which is deductible for income tax
purposes. There was no intangible asset recorded in connection with this acquisition. The revenue
and net income from this acquisition which were included in our consolidated statement of income
for the year ended December 31, 2010 were not material.
C. Segment Information
We use the management approach to identify operating segments. We organize our business
around differences in regulatory environment and/or products or services, and the operating results
of each segment are regularly reviewed by the chief operating decision maker (our Chief Executive
Officer) in order to make decisions about resources and to assess performance. The segments are
evaluated based on their pre-tax operating income. Our operations comprise of three operating
segments:
|
|
|
Regulated Energy. The regulated energy segment includes natural gas distribution,
electric distribution and natural gas transmission operations. All operations in this
segment are regulated, as to their rates and services, by the PSC having jurisdiction in
each operating territory or by the FERC in the case of 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
subsidiary, unregulated subsidiaries that own real estate leased to Chesapeake and certain
corporate costs not allocated to other operations. |
Chesapeake Utilities Corporation 2010 Form 10-K Page 79
Notes to the Consolidated Financial Statements
The following table presents information about our reportable segments.
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31, |
|
2010 |
|
|
2009 |
|
|
2008 |
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues, Unaffiliated Customers |
|
|
|
|
|
|
|
|
|
|
|
|
Regulated Energy |
|
$ |
268,830 |
|
|
$ |
137,847 |
|
|
$ |
115,544 |
|
Unregulated Energy |
|
|
146,430 |
|
|
|
119,719 |
|
|
|
161,287 |
|
Other |
|
|
12,286 |
|
|
|
11,219 |
|
|
|
14,612 |
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues, unaffiliated customers |
|
$ |
427,546 |
|
|
$ |
268,785 |
|
|
$ |
291,443 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment Revenues (1) |
|
|
|
|
|
|
|
|
|
|
|
|
Regulated Energy |
|
$ |
1,104 |
|
|
$ |
1,252 |
|
|
$ |
924 |
|
Unregulated Energy |
|
|
363 |
|
|
|
254 |
|
|
|
3 |
|
Other |
|
|
856 |
|
|
|
779 |
|
|
|
761 |
|
|
|
|
|
|
|
|
|
|
|
Total intersegment revenues |
|
$ |
2,323 |
|
|
$ |
2,285 |
|
|
$ |
1,688 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income |
|
|
|
|
|
|
|
|
|
|
|
|
Regulated Energy |
|
$ |
43,509 |
|
|
$ |
26,900 |
|
|
$ |
24,733 |
|
Unregulated Energy |
|
|
7,908 |
|
|
|
8,158 |
|
|
|
3,781 |
|
Other |
|
|
513 |
|
|
|
(1,322 |
) |
|
|
(35 |
) |
|
|
|
|
|
|
|
|
|
|
Operating Income |
|
|
51,930 |
|
|
|
33,736 |
|
|
|
28,479 |
|
|
Other income |
|
|
195 |
|
|
|
165 |
|
|
|
103 |
|
Interest charges |
|
|
9,146 |
|
|
|
7,086 |
|
|
|
6,158 |
|
Income taxes |
|
|
16,923 |
|
|
|
10,918 |
|
|
|
8,817 |
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations |
|
$ |
26,056 |
|
|
$ |
15,897 |
|
|
$ |
13,607 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and Amortization |
|
|
|
|
|
|
|
|
|
|
|
|
Regulated Energy |
|
$ |
17,038 |
|
|
$ |
8,866 |
|
|
$ |
6,694 |
|
Unregulated Energy |
|
|
3,433 |
|
|
|
2,415 |
|
|
|
2,024 |
|
Other and eliminations |
|
|
287 |
|
|
|
307 |
|
|
|
287 |
|
|
|
|
|
|
|
|
|
|
|
Total depreciation and amortization |
|
$ |
20,758 |
|
|
$ |
11,588 |
|
|
$ |
9,005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
Regulated Energy |
|
$ |
41,898 |
|
|
$ |
22,917 |
|
|
$ |
25,386 |
|
Unregulated Energy |
|
|
2,764 |
|
|
|
1,873 |
|
|
|
3,417 |
|
Other |
|
|
2,293 |
|
|
|
1,504 |
|
|
|
2,041 |
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures |
|
$ |
46,955 |
|
|
$ |
26,294 |
|
|
$ |
30,844 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues. |
|
|
|
|
|
|
|
|
|
At December 31, |
|
2010 |
|
|
2009 |
|
(in thousands) |
|
|
|
|
|
|
|
|
|
Identifiable Assets |
|
|
|
|
|
|
|
|
Regulated Energy |
|
$ |
520,192 |
|
|
$ |
481,606 |
|
Unregulated Energy |
|
|
113,039 |
|
|
|
99,642 |
|
Other |
|
|
37,762 |
|
|
|
34,286 |
|
|
|
|
|
|
|
|
Total identifiable assets |
|
$ |
670,993 |
|
|
$ |
615,534 |
|
|
|
|
|
|
|
|
Chesapeake Utilities Corporation 2010 Form 10-K Page 80
Notes to the Consolidated Financial Statements
Our operations are almost entirely domestic. Our advanced information services subsidiary,
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, 2010, 2009 and
2008 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31, |
|
2010 |
|
|
2009 |
|
|
2008 |
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest |
|
$ |
8,751 |
|
|
$ |
6,703 |
|
|
$ |
5,835 |
|
Cash paid for income taxes |
|
$ |
10,168 |
|
|
$ |
1,111 |
|
|
$ |
3,885 |
|
Non-cash investing and financing activities during the years ended December 31, 2010, 2009,
and 2008 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31, |
|
2010 |
|
|
2009 |
|
|
2008 |
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Capital property and equipment acquired on account,
but not paid as of December 31 |
|
$ |
1,064 |
|
|
$ |
1,151 |
|
|
$ |
696 |
|
Merger/acquisitions |
|
$ |
300 |
|
|
$ |
75,682 |
|
|
$ |
|
|
Retirement Savings Plan |
|
$ |
902 |
|
|
$ |
982 |
|
|
$ |
159 |
|
Dividend Reinvestment Plan |
|
$ |
1,182 |
|
|
$ |
692 |
|
|
$ |
208 |
|
Conversion of Debentures |
|
$ |
202 |
|
|
$ |
135 |
|
|
$ |
177 |
|
Performance Incentive Plan |
|
$ |
719 |
|
|
$ |
|
|
|
$ |
568 |
|
Director Stock Compensation Plan |
|
$ |
297 |
|
|
$ |
214 |
|
|
$ |
181 |
|
Tax benefit on stock warrants and share-based compensation |
|
$ |
253 |
|
|
$ |
|
|
|
$ |
50 |
|
E. Derivative Instruments
We use derivative and non-derivative contracts to engage in trading activities and manage
risks related to obtaining adequate supplies and the price fluctuations of natural gas and propane.
Our natural gas and propane distribution operations have entered into agreements with suppliers to
purchase natural gas and propane for resale to their customers. Purchases under these contracts
either do not meet the definition of derivatives or are considered normal purchases and sales and
are accounted for on an accrual basis. Our propane distribution operation may also enter into fair
value hedges of its inventory in order to mitigate the impact of wholesale price fluctuations. As
of December 31, 2010, our natural gas and propane distribution operations did not have any
outstanding derivative contracts.
Chesapeake Utilities Corporation 2010 Form 10-K Page 81
Notes to the Consolidated Financial Statements
Xeron, our propane wholesale and marketing operation, engages in trading activities using forward
and futures contracts. These contracts are considered derivatives and have been accounted for
using the mark-to-market method of accounting. Under the mark-to-market method of accounting, the
trading contracts are recorded at fair value and the changes in fair value of those contracts are
recognized as unrealized gains or losses in the statement of income in the period of change. As of
December 31, 2010, we had the following outstanding trading contracts which we accounted for as
derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quantity in |
|
|
Estimated Market |
|
|
Weighted Average |
|
At December 31, 2010 |
|
Gallons |
|
|
Prices |
|
|
Contract Prices |
|
Forward Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
Sale |
|
|
13,523,496 |
|
|
$1.0350 $1.4100 |
|
|
$ |
1.2192 |
|
Purchase |
|
|
12,914,496 |
|
|
$1.0150 $1.3779 |
|
|
$ |
1.2093 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Contract |
|
|
|
|
|
|
|
|
|
|
|
|
Put option |
|
|
1,470,000 |
|
|
$ |
|
|
$ |
0.1150 |
|
Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expire by the end of the second quarter of 2011.
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 Sheets as of December
31, 2010 and 2009, are the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives |
|
|
|
|
|
|
|
Fair Value |
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
(in thousands) |
|
Balance Sheet Location |
|
2010 |
|
|
2009 |
|
Derivatives not designated
as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
Forward contracts |
|
Mark-to-market energy assets |
|
$ |
1,642 |
|
|
$ |
2,379 |
|
Put Option(1) (2) |
|
Mark-to-market energy assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total asset derivatives |
|
|
|
|
|
$ |
1,642 |
|
|
$ |
2,379 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liability Derivatives |
|
|
|
|
|
|
|
Fair Value |
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
(in thousands) |
|
Balance Sheet Location |
|
2010 |
|
|
2009 |
|
Derivatives not designated
as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
Forward contracts |
|
Mark-to-market energy liabilities |
|
$ |
1,492 |
|
|
$ |
2,514 |
|
|
|
|
|
|
|
|
|
|
|
|
Total liability derivatives |
|
|
|
|
|
$ |
1,492 |
|
|
$ |
2,514 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
We purchased a put option for the Pro-Cap (propane price cap)
Plan in October 2010. The put option which expires in January and February
2011 had a fair value of $0 at December 31, 2010. |
|
(2) |
|
We purchased a put option for the Pro-Cap Plan in September 2009.
The put option, which expired on March 31, 2010, had a fair value of $0 at
December 31, 2009. |
Chesapeake Utilities Corporation 2010 Form 10-K Page 82
Notes to the Consolidated Financial Statements
The effects of gains and losses from derivative instruments on the Consolidated Statement
of Income are the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain (Loss) on Derivatives: |
|
|
|
Location of Gain |
|
For the Years Ended December 31, |
|
(in thousands) |
|
(Loss) on Derivatives |
|
2010 |
|
|
2009 |
|
|
2008 |
|
Derivatives designated a
fair value hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Propane swap agreement(1) |
|
Cost of Sales |
|
$ |
|
|
|
$ |
(42 |
) |
|
$ |
1,476 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as
hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Put Option(2) |
|
Cost of Sales |
|
|
(168 |
) |
|
|
|
|
|
|
|
|
Put Option(3) |
|
Revenue |
|
|
|
|
|
|
(41 |
) |
|
|
|
|
Unrealized gain (loss) on forward contracts |
|
Revenue |
|
|
284 |
|
|
|
(1,565 |
) |
|
|
1,357 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
$ |
116 |
|
|
$ |
(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 October 2010. The
put option, which expires in January and February 2011, had a fair value of $0
at December 31, 2010. |
|
(3) |
|
We purchased a put option for the Pro-Cap Plan in September 2009.
The put option, which expired on March 31, 2010, had a fair value of $0 at
December 31, 2009. |
The effects of trading activities on the Consolidated Statements of Income are the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Trading Revenue |
|
|
|
Location of Gain |
|
|
For the Years Ended December 31, |
|
(in thousands) |
|
(Loss) on Derivatives |
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Realized gain on forward contracts/put option |
|
Revenue |
|
$ |
1,540 |
|
|
$ |
3,830 |
|
|
$ |
1,935 |
|
Unrealized gain (loss) on forward contracts |
|
Revenue |
|
|
284 |
|
|
|
(1,565 |
) |
|
|
1,357 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
$ |
1,824 |
|
|
$ |
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 1: Unadjusted quoted prices in active markets that are accessible at the measurement date
for identical, unrestricted assets or liabilities; |
|
|
Level 2: Quoted prices in markets that are not active, or inputs which are observable, either
directly or indirectly, for substantially the full term of the asset or liability; and |
|
|
Level 3: Prices or valuation techniques requiring inputs that are both significant to the fair
value measurement and unobservable (i.e. supported by little or no market activity). |
Chesapeake Utilities Corporation 2010 Form 10-K Page 83
Notes to the Consolidated Financial Statements
The following table summarizes our financial assets and liabilities that are measured at fair value
on a recurring basis and the fair value measurements, by level, within the fair value hierarchy
used at December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using: |
|
|
|
|
|
|
|
|
|
|
|
Significant |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
Significant |
|
|
|
|
|
|
|
Quoted Prices in |
|
|
Observable |
|
|
Unobservable |
|
|
|
|
|
|
|
Active Markets |
|
|
Inputs |
|
|
Inputs |
|
(in thousands) |
|
Fair Value |
|
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments |
|
$ |
4,036 |
|
|
$ |
4,036 |
|
|
$ |
|
|
|
$ |
|
|
Mark-to-market energy assets |
|
$ |
1,642 |
|
|
$ |
|
|
|
$ |
1,642 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market energy liabilities |
|
$ |
1,492 |
|
|
$ |
|
|
|
$ |
1,492 |
|
|
$ |
|
|
The following table summarizes our financial assets and liabilities that are measured at fair
value on a recurring basis and the fair value measurements, by level, within the fair value
hierarchy used at December 31, 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 |
|
$ |
2,379 |
|
|
$ |
|
|
|
$ |
2,379 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market energy liabilities |
|
$ |
2,514 |
|
|
$ |
|
|
|
$ |
2,514 |
|
|
$ |
|
|
The following valuation techniques were used to measure fair value assets in the table above
on a recurring basis as of December 31, 2010 and 2009:
|
|
Level 1 Fair Value Measurements: |
|
|
Investments The fair values of these trading securities are recorded at fair
value based on unadjusted quoted prices in active markets for identical securities. |
|
|
Level 2 Fair Value Measurements: |
|
|
Mark-to-market energy assets and liabilities These forward contracts are valued using market
transactions in either the listed or OTC markets. |
|
|
Propane price swap agreement and put option The fair value of the propane 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, 2010, 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.
Chesapeake Utilities Corporation 2010 Form 10-K Page 84
Notes to the Consolidated Financial Statements
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, 2010, long-term debt, which includes the current maturities of long-term debt, had
a carrying value of $98.9 million, compared to a fair value of $113.4 million, using a discounted
cash flow methodology that incorporates a market interest rate based on published corporate
borrowing rates for debt instruments with similar terms and average maturities, with adjustments
for duration, optionality, and risk profile. At December 31, 2009, the estimated fair value was
approximately $145.5 million, compared to a carrying value of $134.1 million.
G. Investments
The investment balance at December 31, 2010, represents: (a) a Rabbi Trust associated with our
Supplemental Executive Retirement Savings Plan; (b) a Rabbi Trust related to a stay bonus agreement
with a former executive; and (c) investments in equity securities. We classify these investments
as trading securities and report them at their fair value. Any unrealized gains and losses, net of
other expenses, are included in other income in the consolidated statements of income. We also
have an associated liability that is recorded and adjusted each month for the gains and losses
incurred by the Rabbi Trusts. At December 31, 2010 and 2009, total investments had a fair value of
$4.0 million and $2.0 million, respectively.
H. Goodwill and Other Intangible Assets
The carrying value of goodwill as of December 31, 2010 and 2009 is as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
|
|
|
Regulated Energy |
|
$ |
34,939 |
|
|
$ |
33,421 |
|
Unregulated Energy |
|
|
674 |
|
|
|
674 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
35,613 |
|
|
$ |
34,095 |
|
|
|
|
|
|
|
|
Goodwill in the regulated energy segment is comprised of $34.2 million from the FPU merger and
$746,000 from the purchase of operating assets from IGC. Goodwill in the unregulated energy
segment is comprised of the premium paid by Sharp in its acquisitions in the late 1980s and 1990s.
We test for impairment of goodwill at least annually. The impairment testing for 2010 and 2009
indicated no impairment of goodwill.
Chesapeake Utilities Corporation 2010 Form 10-K Page 85
Notes to the Consolidated Financial Statements
The carrying value and accumulated amortization of intangible assets subject to amortization as of
December 31, 2010 and 2009 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010 |
|
|
December 31, 2009 |
|
|
|
Gross |
|
|
|
|
|
|
Gross |
|
|
|
|
|
|
Carrying |
|
|
Accumulated |
|
|
Carrying |
|
|
Accumulated |
|
|
|
Amount |
|
|
Amortization |
|
|
Amount |
|
|
Amortization |
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Favorable propane contracts |
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
519 |
|
|
$ |
169 |
|
Customer list |
|
|
3,500 |
|
|
|
340 |
|
|
|
3,500 |
|
|
|
49 |
|
Other |
|
|
566 |
|
|
|
267 |
|
|
|
379 |
|
|
|
229 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
4,066 |
|
|
$ |
607 |
|
|
$ |
4,398 |
|
|
$ |
447 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Favorable propane contracts and customer list were acquired in the FPU merger in October 2009.
All of the favorable propane contracts expired as of December 31, 2010. The propane customer list
is amortized over a 12-year period. Other intangible assets include customer lists and a
non-compete agreement acquired in the purchase of the operating assets of Virginia LP Gas, Inc. in
February 2010 and customer lists and acquisition costs from our acquisitions in the late 1980s and
1990s. These intangible assets are amortized over a period ranging from seven to 40 years.
For the years ended December 31, 2010, 2009 and 2008, amortization expense of intangible assets was
$679,000, $232,000 and $14,000, respectively. Amortization expense of intangible assets for 2011
to 2015 is: $332,000 for 2011, $329,000 for 2012, $325,000 for 2013 2015.
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 has been included
in the Companys consolidated federal return since the completion of the merger on October 28,
2009. 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 Internal Revenue Service (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 IRS for years before December 31, 2006.
FPU filed a separate federal income tax return for the period prior to the merger and is 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, 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
$9,049,132 was carried forward to 2009 and fully offset taxable income for the year. As of
December 31, 2010, we have no remaining carryforward of the 2008 federal tax net operating loss. As of
December 31, 2010, we also had tax net operating losses from various states totaling $16.6 million,
almost all of which will expire in 2027. We have recorded a deferred tax asset of $1.3 million related
to these carry-forwards. We have not recorded a valuation allowance to reduce the future benefit
of the tax net operating losses because we believe they will all be utilized.
Chesapeake Utilities Corporation 2010 Form 10-K Page 86
Notes to the Consolidated Financial Statements
The tables below provide the following: (a) the components of income tax expense; (b)
reconciliation between the statutory federal income tax rate and the effective income tax rate; and
(c) the components of accumulated deferred income tax assets and liabilities at December 31, 2010
and 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31, |
|
2010 |
|
|
2009 |
|
|
2008 |
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Current Income Tax Expense |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
$ |
1,566 |
|
|
$ |
|
|
|
$ |
(2,551 |
) |
State |
|
|
2,116 |
|
|
|
878 |
|
|
|
|
|
Investment tax credit adjustments, net |
|
|
(91 |
) |
|
|
(69 |
) |
|
|
(42 |
) |
|
|
|
|
|
|
|
|
|
|
Total current income tax expense (benefit) |
|
|
3,591 |
|
|
|
809 |
|
|
|
(2,593 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Income Tax Expense (1) |
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
|
16,964 |
|
|
|
7,098 |
|
|
|
10,272 |
|
Deferred gas costs |
|
|
(2,505 |
) |
|
|
(786 |
) |
|
|
781 |
|
Pensions and other employee benefits |
|
|
(402 |
) |
|
|
(612 |
) |
|
|
(174 |
) |
Amortization of intangibles |
|
|
(211 |
) |
|
|
5 |
|
|
|
75 |
|
Environmental expenditures |
|
|
32 |
|
|
|
7 |
|
|
|
145 |
|
Net operating loss carryforwards |
|
|
99 |
|
|
|
4,106 |
|
|
|
|
|
Merger related costs |
|
|
(13 |
) |
|
|
967 |
|
|
|
|
|
Reserve for insurance deductibles |
|
|
(419 |
) |
|
|
518 |
|
|
|
462 |
|
Other |
|
|
(213 |
) |
|
|
(1,194 |
) |
|
|
(151 |
) |
|
|
|
|
|
|
|
|
|
|
Total deferred income tax expense (benefit) |
|
|
13,332 |
|
|
|
10,109 |
|
|
|
11,410 |
|
|
|
|
|
|
|
|
|
|
|
Total Income Tax Expense |
|
$ |
16,923 |
|
|
$ |
10,918 |
|
|
$ |
8,817 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Effective Income Tax Rates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
|
|
|
|
|
|
|
|
|
|
|
|
Federal income tax expense (2) |
|
$ |
15,053 |
|
|
$ |
9,171 |
|
|
$ |
7,863 |
|
State income taxes, net of federal
benefit |
|
|
2,083 |
|
|
|
1,490 |
|
|
|
1,162 |
|
Merger related costs |
|
|
70 |
|
|
|
299 |
|
|
|
|
|
ESOP dividend deduction |
|
|
(266 |
) |
|
|
(213 |
) |
|
|
(205 |
) |
Other |
|
|
(17 |
) |
|
|
171 |
|
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
$ |
16,923 |
|
|
$ |
10,918 |
|
|
$ |
8,817 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective income tax rate |
|
|
39.38 |
% |
|
|
40.72 |
% |
|
|
39.32 |
% |
|
|
|
|
|
|
|
|
|
At December 31, |
|
2010 |
|
|
2009 |
|
(in thousands) |
|
|
|
|
|
|
|
|
Deferred Income Taxes |
|
|
|
|
|
|
|
|
Deferred income tax liabilities: |
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
$ |
89,544 |
|
|
$ |
75,863 |
|
Deferred gas costs |
|
|
|
|
|
|
848 |
|
Loss on reacquired debt |
|
|
643 |
|
|
|
59 |
|
Other |
|
|
2,891 |
|
|
|
2,884 |
|
|
|
|
|
|
|
|
Total deferred income tax liabilities |
|
|
93,078 |
|
|
|
79,654 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax assets: |
|
|
|
|
|
|
|
|
Pension and other employee
benefits |
|
|
7,849 |
|
|
|
7,972 |
|
Environmental costs |
|
|
1,770 |
|
|
|
1,803 |
|
Net operating loss carryforwards |
|
|
1,300 |
|
|
|
305 |
|
Self insurance |
|
|
419 |
|
|
|
464 |
|
Storm reserve liability |
|
|
1,034 |
|
|
|
985 |
|
Other |
|
|
2,866 |
|
|
|
2,841 |
|
|
|
|
|
|
|
|
Total deferred income tax assets |
|
|
15,238 |
|
|
|
14,370 |
|
|
|
|
|
|
|
|
Deferred Income Taxes Per Consolidated Balance Sheet |
|
$ |
77,840 |
|
|
$ |
65,284 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes $1,963,000, $1,588,000 and $260,000 of deferred state income taxes for the years
2010, 2009 and 2008, respectively. |
|
(2) |
|
Federal income taxes were recorded at 35% for each year represented. |
Chesapeake Utilities Corporation 2010 Form 10-K Page 87
Notes to the Consolidated Financial Statements
J. Long-term Debt
Our outstanding long-term debt is as shown below.
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
FPU secured first mortgage bonds: |
|
|
|
|
|
|
|
|
9.57% bond, due May 1, 2018 |
|
$ |
7,248 |
|
|
$ |
8,156 |
|
10.03% bond, due May 1, 2018 |
|
|
3,986 |
|
|
|
4,486 |
|
9.08% bond, due June 1, 2022 |
|
|
7,950 |
|
|
|
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 |
|
6.85% note, due January 1, 2012 |
|
|
1,000 |
|
|
|
2,000 |
|
7.83% note, due January 1, 2015 |
|
|
8,000 |
|
|
|
10,000 |
|
6.64% note, due October 31, 2017 |
|
|
19,091 |
|
|
|
21,818 |
|
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 |
|
|
1,318 |
|
|
|
1,520 |
|
Promissory note |
|
|
265 |
|
|
|
40 |
|
|
|
|
|
|
|
|
Total long-term debt |
|
|
98,858 |
|
|
|
134,113 |
|
Less: current maturities |
|
|
(9,216 |
) |
|
|
(35,299 |
) |
|
|
|
|
|
|
|
Total long-term debt, net of current maturities |
|
$ |
89,642 |
|
|
$ |
98,814 |
|
|
|
|
|
|
|
|
Annual maturities of consolidated long-term debt are as follows: $9,216 for 2011; $8,196 for
2012; $8,196 for 2013; $12,514 for 2014; $9,141 for 2015 and $51,685 thereafter.
Secured First Mortgage Bonds
In October 2009, we became subject to the obligations of FPUs secured first mortgage bonds in
connection with the merger. FPUs secured first mortgage bonds are guaranteed by Chesapeake and
are secured by a lien covering all of FPUs 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 FPUs secured first
mortgage bonds prior to their respective maturities. 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. We are amortizing this difference over the remaining terms of these bonds as adjustments to
interest expense as allowed by the Florida PSC.
Uncollateralized Senior Notes
On June 29, 2010, we entered into an agreement with Metropolitan Life Insurance Company and New
England Life Insurance Company to issue up to $36 million in uncollateralized senior notes. We
expect to use $29 million of the uncollateralized senior notes to permanently finance the
redemption of the 6.85 percent and 4.90 percent series of FPU bonds. The terms of the agreement
require us to issue $29 million of the $36 million in uncollateralized senior notes committed by
the lender on or before July 9, 2012, with a 15-year term at a rate ranging from 5.28 percent to
6.13 percent based on the timing of the issuance. The remaining $7 million will be issued prior to
May 3, 2013, at a rate ranging from 5.28 percent to 6.43 percent based on the timing of the
issuance. These notes, when issued, will have similar covenants and default provisions as the
existing senior notes and will have an annual principal payment beginning in the sixth year after
the issuance.
Chesapeake Utilities Corporation 2010 Form 10-K Page 88
Notes to the Consolidated Financial Statements
Convertible Debentures
The convertible debentures may be converted, at the option of the holder, into shares of our common
stock at a conversion price of $17.01 per share. During 2010 and 2009, debentures totaling
$202,000 and $135,000, 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 2010 and 2009, no debentures were redeemed for cash. At our option, the debentures
may be redeemed at stated amounts.
Debt Covenants
Indentures to our long-term debt contain various restrictions. The most stringent restrictions
state that we must maintain equity of at least 40 percent of total capitalization, and the fixed
charge coverage ratio must be at least 1.2 times. In connection with the merger, the
uncollateralized senior notes were amended to include an additional covenant requiring the Company
to 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, 2010, we are in compliance with all of our debt covenants. With the redemption
of FPUs 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 was met.
Each of Chesapeakes uncollateralized senior notes contains a Restricted Payments covenant as
defined in the note agreements. The most restrictive covenants of this type are included within
the 7.83 percent Unsecured 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 our consolidated net income accrued on and after January 1, 2001.
As of December 31, 2010, the cumulative consolidated net income base was $128.9 million, offset by
Restricted Payments of $76.2 million, leaving $52.7 million of cumulative net income free of
restrictions.
Each series of FPUs 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 2022, which provides that FPU cannot make dividend or other restricted payments in excess
of the sum of $2.5 million plus FPUs consolidated net income accrued on and after January 1, 1992.
As of December 31, 2010, FPUs cumulative net income base was $65.9 million, offset by restricted
payments of $37.6 million, leaving $28.3 million of cumulative net income for FPU free of
restrictions pursuant to this covenant. In January 2010, this series of first mortgage bonds was
redeemed prior to its maturity.
K. Short-term Borrowing
At December 31, 2010 and 2009, we had $64.0 million and $30.0 million, respectively, of
short-term borrowings outstanding. The annual weighted average interest rates on our short-term
borrowings were 1.77 percent and 1.28 percent for 2010 and 2009, respectively. We incurred
commitment fees of $86,000 and $79,000 in 2010 and 2009, respectively.
The outstanding short-term borrowings at December 31, 2010 were composed of $30.8 million in
borrowings from the bank lines of credit, $29.1 million in borrowings from a term loan maturing in
March 2011 and $4.1 million in book overdrafts representing outstanding checks in excess of funds
on deposit, which if presented would be funded through the bank lines of credit. All of the
outstanding short-term borrowings at December 31, 2009 were related to the bank lines of credit.
As of December 31, 2010, we had four unsecured bank lines of credit with two financial
institutions, totaling $100.0 million, none of which requires compensating balances. These bank
lines are available to provide funds for our short-term cash needs to meet seasonal working capital
requirements and to temporarily fund portions of our capital expenditures. We maintain both
committed and uncommitted credit facilities. Advances offered under the uncommitted lines of
credit are subject to the discretion of the banks. We are currently authorized by our Board of
Directors to borrow up to $85.0 million of short-term debt, as required, from these short-term
lines of credit.
Chesapeake Utilities Corporation 2010 Form 10-K Page 89
Notes to the Consolidated Financial Statements
Committed credit facilities
As of December 31, 2010 we had two committed revolving credit facilities totaling $60.0
million. 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, 2010, there
were no available funds under this credit facility.
The second facility is a $30.0 million committed revolving line of credit that bears interest at a
base rate plus 1.25 percent, if requested and advanced 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, 2010,
there was $29.2 million available under this credit facility.
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 the continued accuracy of representations and warranties
contained in these agreements. We are 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, 2010, we had two uncommitted lines of credit facilities totaling $40.0
million. 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, 2010, the entire borrowing
capacity of $20.0 million was available under this credit facility.
The second facility is a $20.0 million uncommitted line of credit that bears interest at a rate per
annum as offered by the bank for the applicable period. We have issued $3.2
million in letters of credit under this credit facility. There have been no draws on these letters
of credit as of December 31, 2010. We do not anticipate that the letters of credit will be drawn
upon by the counterparties and we expect that the letters of credit will be renewed to the extent
necessary in the future. At December 31, 2010, there was $16.8
million available under this credit facility which was reduced by
$3.2 million for letters of credit issued.
In addition to the four unsecured bank lines of credit, we entered into a new term loan for $29.1
million with an existing lender in March 2010. We borrowed $29.1 million under this new credit
facility
related to the early
redemption of the 6.85 percent and 4.90 percent series of FPUs secured first mortgage bonds prior
to their respective maturities.
The interest rate on the borrowing was fixed at 1.88 percent for nine
months and on December 16, 2010 the rate was fixed for three months
at 1.55 percent. On November 1, 2010 we extended the maturity of this
credit facility from March 15, 2011 until October 31, 2011.
We are
subject to the same covenants representations and warranties for this term loan facility as we are
for the $20 million second uncommitted line of credit facility.
In October 2009 in connection with the FPU merger, we became subject to $4.2 million in outstanding
borrowings under FPUs revolving line of credit. All of the outstanding borrowings were repaid in
full in November 2009 and FPUs revolving line of credit was terminated on November 23, 2009.
Chesapeake Utilities Corporation 2010 Form 10-K Page 90
Notes to the Consolidated Financial Statements
L. Lease Obligations
We have entered into several operating lease arrangements for office space, equipment and
pipeline facilities. Rent expense related to these leases was $1.1 million, $997,000 and $880,000
for 2010, 2009 and 2008, respectively. Future minimum payments under our current lease agreements
are $803,000, $717,000, $517,000, $377,000 and $93,000 for the years 2011 through 2015,
respectively; and $2.0 million thereafter, with an aggregate total of $4.5 million.
M. Employee Benefit Plans
Retirement Plans
We sponsor a defined benefit pension plan (Chesapeake 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 also sponsor and maintain a separate defined benefit pension plan for FPU (FPU Pension
Plan) and a separate unfunded postretirement medical plan for FPU (FPU Medical Plan).
We measure the assets and obligations of the defined benefit pension plans and other postretirement
benefits 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. We record as a component of other comprehensive
income/loss or a regulatory asset the changes in funded status that occurred during the year that
are not recognized as part of net periodic benefit costs.
The following table presents the amounts not yet reflected in net periodic benefit cost and
included in accumulated other comprehensive income/loss or as a regulatory asset as of December 31,
2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chesapeake |
|
|
FPU |
|
|
|
|
|
|
Chesapeake |
|
|
FPU |
|
|
|
|
|
|
Pension |
|
|
Pension |
|
|
Chesapeake |
|
|
Postretirement |
|
|
Medical |
|
|
|
|
(in thousands) |
|
Plan |
|
|
Plan |
|
|
SERP |
|
|
Plan |
|
|
Plan |
|
|
Total |
|
Prior service cost (credit) |
|
$ |
(11 |
) |
|
$ |
|
|
|
$ |
83 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
72 |
|
Net loss |
|
|
3,221 |
|
|
|
1,409 |
|
|
|
793 |
|
|
|
1,145 |
|
|
|
531 |
|
|
|
7,099 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total unrecognized cost |
|
$ |
3,210 |
|
|
$ |
1,409 |
|
|
$ |
876 |
|
|
$ |
1,145 |
|
|
$ |
531 |
|
|
$ |
7,171 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other
comprehesive loss
pre-tax(1) |
|
$ |
3,210 |
|
|
$ |
268 |
|
|
$ |
876 |
|
|
$ |
1,145 |
|
|
$ |
101 |
|
|
$ |
5,600 |
|
Regulatory asset post merger |
|
|
|
|
|
|
1,141 |
|
|
|
|
|
|
|
|
|
|
|
430 |
|
|
|
1,571 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal |
|
|
3,210 |
|
|
|
1,409 |
|
|
|
876 |
|
|
|
1,145 |
|
|
|
531 |
|
|
|
7,171 |
|
Regulatory asset pre-merger |
|
|
|
|
|
|
6,631 |
|
|
|
|
|
|
|
|
|
|
|
78 |
|
|
|
6,709 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
3,210 |
|
|
$ |
8,040 |
|
|
$ |
876 |
|
|
$ |
1,145 |
|
|
$ |
609 |
|
|
$ |
13,880 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The total amount of accumulated other comprehensive loss recorded on our
consolidated balance sheets as of December 31, 2010 is net of income tax benefits of $2.2 million. |
The pre-merger regulatory asset of $6.7 million at December 31, 2010 represents the portion
attributable to FPUs regulated energy operations of the changes in the funded status in the FPU
Pension Plan and FPU Medical Plan that occurred but were not recognized as part of the net periodic
benefit costs prior to the merger. This portion was deferred as a regulatory asset prior to the
merger by FPU pursuant to a previous order by the Florida PSC and continues to be amortized over
the remaining service period of the participants at the time of the merger.
Chesapeake Utilities Corporation 2010 Form 10-K Page 91
Notes to the Consolidated Financial Statements
The amounts in accumulated other comprehensive income/loss and regulatory asset for our pension and
postretirement benefits plans that are expected to be recognized as a component of net benefit cost
in 2011 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 |
|
$ |
173 |
|
|
$ |
|
|
|
$ |
43 |
|
|
$ |
58 |
|
|
$ |
22 |
|
|
$ |
296 |
|
Amortization of pre-merger
regulatory asset |
|
$ |
|
|
|
$ |
761 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
8 |
|
|
$ |
769 |
|
In January 2011, our former Chief Executive Officer, John Schimkaitis, retired and received a
lump-sum pension distribution of $844,000 from the Chesapeake Pension Plan. He is also expected to
receive $765,000 in the form of a lump-sum distribution from the Chesapeake SERP in July 2011. In
connection with these lump-sum payment distributions, we expect to record $455,000 in pension
settlement losses which will be recorded in addition to the net benefit cost in 2011. Based upon
the current funding status of the Chesapeake Pension Plan, which does not meet or exceed 110
percent of the benefit obligation as required per the regulations, Mr. Schimkaitis was required to
deposit property equal to 125 percent of the restricted portion of his lump sum distribution into
an escrow. Each year, an amount equal to the value of payments that would have been paid to him if
he had elected the life annuity form of distribution will become unrestricted. Property equal to
the life annuity amount will be returned to him from the escrow account. These same regulations
will apply to the top 20 highest compensated employees taking distributions from the Pension Plan.
Defined Benefit Pension Plans
The Chesapeake Pension Plan was closed to new participants effective January 1, 1999 and was frozen
with respect to additional years of service or additional compensation effective January 1, 2005.
Benefits under the Chesapeake Pension Plan were based on each participants years of service and
highest average compensation, prior to the freezing of the plan.
The FPU 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. We were not required
to make any funding payments to the Chesapeake Pension Plan in 2009 or to the FPU Pension Plan
subsequent to the merger closing in October 2009.
The following schedule summarizes the assets of the Chesapeake Pension Plan, by investment type, at
December 31, 2010, 2009 and 2008 and the assets of the FPU Pension Plan, by investment type, at
December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chesapeake |
|
|
FPU |
|
|
|
Pension Plan |
|
|
Pension Plan |
|
At December 31, |
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
2010 |
|
|
2009 |
|
Asset Category |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities |
|
|
64.33 |
% |
|
|
66.22 |
% |
|
|
48.70 |
% |
|
|
60.00 |
% |
|
|
63.00 |
% |
Debt securities |
|
|
30.60 |
% |
|
|
33.76 |
% |
|
|
51.24 |
% |
|
|
35.00 |
% |
|
|
29.00 |
% |
Other |
|
|
5.07 |
% |
|
|
0.02 |
% |
|
|
0.06 |
% |
|
|
5.00 |
% |
|
|
8.00 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
100.00 |
% |
|
|
100.00 |
% |
|
|
100.00 |
% |
|
|
100.00 |
% |
|
|
100.00 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chesapeake Utilities Corporation 2010 Form 10-K Page 92
Notes to the Consolidated Financial Statements
The asset listed as Other in the above table represents monies temporarily held in money
market funds, which invest at least 80 percent of their total assets in:
|
|
|
United States government obligations; and |
|
|
|
Repurchase agreements that are fully collateralized by such obligations. |
All of the equity securities held by the Chesapeake Pension Plan as of December 31, 2010 and 2009
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. All of the debt securities
and other assets held by the Chesapeake Pension Plan as of December 31, 2010 and 2009 are
classified under Level 2 of the fair value hierarchy and are recorded at fair value based on quoted
market prices in active markets for similar assets or closing prices reported in active markets for
those assets. All of the assets held by the FPU Pension Plan as of December 31, 2010 and 2009 are
also classified under Level 2 of the fair value hierarchy and are recorded at fair value based on
net asset value per unit of those assets.
The investment policy for 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 Chesapeake Pension 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 FPU Pension Plans 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 also made under the
direction of the Employee Benefits Committee.
Chesapeake Utilities Corporation 2010 Form 10-K Page 93
Notes to the Consolidated Financial Statements
The following schedule sets forth the funded status at December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chesapeake |
|
|
FPU |
|
|
|
Pension Plan |
|
|
Pension Plan |
|
At December 31, |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in benefit obligation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation beginning of year (1) |
|
$ |
11,127 |
|
|
$ |
11,593 |
|
|
$ |
45,420 |
|
|
$ |
46,851 |
|
Interest cost |
|
|
570 |
|
|
|
547 |
|
|
|
2,729 |
|
|
|
418 |
|
Change in assumptions |
|
|
(5 |
) |
|
|
(188 |
) |
|
|
|
|
|
|
|
|
Actuarial loss |
|
|
776 |
|
|
|
(307 |
) |
|
|
6,326 |
|
|
|
(1,544 |
) |
Benefits paid |
|
|
(708 |
) |
|
|
(518 |
) |
|
|
(1,997 |
) |
|
|
(305 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation end of year |
|
|
11,760 |
|
|
|
11,127 |
|
|
|
52,478 |
|
|
|
45,420 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets beginning of year (1) |
|
|
7,449 |
|
|
|
6,689 |
|
|
|
36,427 |
|
|
|
35,037 |
|
Actual return on plan assets |
|
|
490 |
|
|
|
1,278 |
|
|
|
4,605 |
|
|
|
1,695 |
|
Employer contributions |
|
|
556 |
|
|
|
|
|
|
|
1,166 |
|
|
|
|
|
Benefits paid |
|
|
(708 |
) |
|
|
(518 |
) |
|
|
(1,997 |
) |
|
|
(305 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets end of year |
|
|
7,787 |
|
|
|
7,449 |
|
|
|
40,201 |
|
|
|
36,427 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded status |
|
|
(3,973 |
) |
|
|
(3,678 |
) |
|
|
(12,277 |
) |
|
|
(8,993 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued pension cost |
|
$ |
(3,973 |
) |
|
$ |
(3,678 |
) |
|
$ |
(12,277 |
) |
|
$ |
(8,993 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assumptions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
|
|
5.00 |
% |
|
|
5.25 |
% |
|
|
5.25 |
% |
|
|
5.75 |
% |
Expected return on plan assets |
|
|
6.00 |
% |
|
|
6.00 |
% |
|
|
7.00 |
% |
|
|
7.00 |
% |
|
|
|
(1) |
|
FPU Pension Plans beginning balance for 2009 reflects the benefit obligations as of
the merger date of October 28, 2009. |
Net periodic pension cost (benefit) for the plans for 2010, 2009, and 2008 include the
components shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chesapeake |
|
|
FPU |
|
For the Years Ended December 31, |
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
2010 |
|
|
2009(1) |
|
(In thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of net periodic pension
cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest cost |
|
$ |
570 |
|
|
$ |
547 |
|
|
$ |
594 |
|
|
$ |
2,729 |
|
|
$ |
418 |
|
Expected return on assets |
|
|
(423 |
) |
|
|
(362 |
) |
|
|
(629 |
) |
|
|
(2,532 |
) |
|
|
(396 |
) |
Amortization of prior service cost |
|
|
(5 |
) |
|
|
(5 |
) |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
Amortization of actuarial loss |
|
|
155 |
|
|
|
237 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic pension benefit |
|
$ |
297 |
|
|
$ |
417 |
|
|
$ |
(40 |
) |
|
$ |
197 |
|
|
$ |
22 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assumptions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
|
|
5.25 |
% |
|
|
5.25 |
% |
|
|
5.50 |
% |
|
|
5.75 |
% |
|
|
5.50 |
% |
Expected return on plan assets |
|
|
6.00 |
% |
|
|
6.00 |
% |
|
|
6.00 |
% |
|
|
7.00 |
% |
|
|
7.00 |
% |
|
|
|
(1) |
|
FPUs net periodic pension cost is from the merger date (October 28, 2009) through December 31, 2009. |
In addition, we recorded $888,000 in expense in 2010 related to continued amortization of
FPUs pre-merger pension regulatory asset.
Chesapeake Utilities Corporation 2010 Form 10-K Page 94
Notes to the Consolidated Financial Statements
Pension Supplemental Executive Retirement Plan
The Chesapeake SERP was frozen with respect to additional years of service and additional
compensation as of December 31, 2004. Benefits under the Chesapeake SERP were based on each
participants years of service and highest average compensation, prior to the freezing of the plan.
The accumulated benefit obligation for the Chesapeake SERP, which is unfunded, was $2.7 million and
$2.5 million, at December 31, 2010 and 2009, respectively.
|
|
|
|
|
|
|
|
|
At December 31, |
|
2010 |
|
|
2009 |
|
(in thousands) |
|
|
|
|
|
|
|
|
Change in benefit obligation: |
|
|
|
|
|
|
|
|
Benefit obligation beginning of year |
|
$ |
2,505 |
|
|
$ |
2,520 |
|
Interest cost |
|
|
136 |
|
|
|
129 |
|
Actuarial (gain) loss |
|
|
179 |
|
|
|
(55 |
) |
Amendments |
|
|
|
|
|
|
|
|
Benefits paid |
|
|
(89 |
) |
|
|
(89 |
) |
|
|
|
|
|
|
|
Benefit obligation end of year |
|
|
2,731 |
|
|
|
2,505 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
(2,731 |
) |
|
|
(2,505 |
) |
|
|
|
|
|
|
|
Accrued pension cost |
|
$ |
(2,731 |
) |
|
$ |
(2,505 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assumptions: |
|
|
|
|
|
|
|
|
Discount rate |
|
|
5.00 |
% |
|
|
5.25 |
% |
Net periodic pension costs for the Chesapeake Pension SERP for 2010, 2009, and 2008 include
the components shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31, |
|
2010 |
|
|
2009 |
|
|
2008 |
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Components of net periodic pension cost: |
|
|
|
|
|
|
|
|
|
|
|
|
Interest cost |
|
$ |
136 |
|
|
$ |
130 |
|
|
$ |
125 |
|
Amortization of prior service cost |
|
|
18 |
|
|
|
18 |
|
|
|
|
|
Amortization of actuarial loss |
|
|
59 |
|
|
|
54 |
|
|
|
45 |
|
|
|
|
|
|
|
|
|
|
|
Net periodic pension cost |
|
$ |
213 |
|
|
$ |
202 |
|
|
$ |
170 |
|
|
|
|
|
|
|
|
|
|
|
Assumptions: |
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
|
|
5.25 |
% |
|
|
5.25 |
% |
|
|
5.50 |
% |
Chesapeake Utilities Corporation 2010 Form 10-K Page 95
Notes to the Consolidated Financial Statements
Other Postretirement Benefits Plans
The following schedule sets forth the status of other postretirement benefit plans:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chesapeake |
|
|
FPU |
|
|
|
Postretirement Plan |
|
|
Medical Plan |
|
At December 31, |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in benefit obligation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation beginning of year (1) |
|
$ |
2,585 |
|
|
$ |
2,179 |
|
|
$ |
2,417 |
|
|
$ |
2,457 |
|
Service cost |
|
|
|
|
|
|
3 |
|
|
|
76 |
|
|
|
18 |
|
Interest cost |
|
|
121 |
|
|
|
131 |
|
|
|
122 |
|
|
|
23 |
|
Plan participants contributions |
|
|
100 |
|
|
|
90 |
|
|
|
|
|
|
|
6 |
|
Actuarial (gain) loss |
|
|
(149 |
) |
|
|
378 |
|
|
|
595 |
|
|
|
(71 |
) |
Benefits paid |
|
|
(183 |
) |
|
|
(196 |
) |
|
|
(112 |
) |
|
|
(16 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation end of year |
|
|
2,474 |
|
|
|
2,585 |
|
|
|
3,098 |
|
|
|
2,417 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets beginning of year (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employer contributions(2) |
|
|
83 |
|
|
|
106 |
|
|
|
112 |
|
|
|
10 |
|
Plan participants contributions |
|
|
100 |
|
|
|
90 |
|
|
|
|
|
|
|
6 |
|
Benefits paid |
|
|
(183 |
) |
|
|
(196 |
) |
|
|
(112 |
) |
|
|
(16 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets end of year |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded status |
|
|
(2,474 |
) |
|
|
(2,585 |
) |
|
|
(3,098 |
) |
|
|
(2,417 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued postretirement cost |
|
$ |
(2,474 |
) |
|
$ |
(2,585 |
) |
|
$ |
(3,098 |
) |
|
$ |
(2,417 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assumptions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
|
|
5.00 |
% |
|
|
5.25 |
% |
|
|
5.25 |
% |
|
|
5.75 |
% |
|
|
|
(1) |
|
FPU Medical Plans beginning balance for 2009 reflects the benefit obligation as of the merger date of October 28, 2009. |
|
(2) |
|
Chesapeakes 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 benefit costs for 2010, 2009, and 2008 include the following
components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chesapeake |
|
|
FPU |
|
|
|
Postretirement Plan |
|
|
Medical Plan |
|
For the Years Ended December 31, |
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
2010 |
|
|
2009(1) |
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of net periodic postretirement cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
|
|
|
$ |
3 |
|
|
$ |
3 |
|
|
$ |
76 |
|
|
$ |
18 |
|
Interest cost |
|
|
122 |
|
|
|
131 |
|
|
|
114 |
|
|
|
123 |
|
|
|
23 |
|
Amortization of: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial (gain) loss |
|
|
57 |
|
|
|
76 |
|
|
|
290 |
|
|
|
(6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic postretirement cost |
|
$ |
179 |
|
|
$ |
210 |
|
|
$ |
407 |
|
|
$ |
193 |
|
|
$ |
41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assumptions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
|
|
5.25 |
% |
|
|
5.25 |
% |
|
|
5.50 |
% |
|
|
5.75 |
% |
|
|
5.50 |
% |
|
|
|
(1) |
|
FPU Medical Plans net periodic cost includes only the cost from the merger date (October 28, 2009) through December 31, 2009. |
Chesapeake Utilities Corporation 2010 Form 10-K Page 96
Notes to the Consolidated Financial Statements
In addition, we recorded $9,000 in expense in 2010 related to continued amortization of FPUs
pre-merger postretirement benefit regulatory asset.
Assumptions
The assumptions used for the discount rate to calculate the benefit obligations of all the plans
were based on the interest rates of high-quality bonds in 2010, reflecting the expected lives of
the 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 Chesapeakes plans and FPUs plans have different
expected lives of the plan and investment policies, particularly in light of the lump-sum-payment
option provided in the Chesapeake Pension Plan, different discount rate and expected return on plan
asset assumptions were selected for Chesapeakes plans and FPUs plans. Since all of the pension
plans are frozen with respect to additional years of service and compensation, the rate of assumed
compensation increases is not applicable.
The health care inflation rate for 2010 used to calculate the benefit obligation is seven percent
for medical and eight percent for prescription drugs for the Chesapeake Postretirement Plan; and
10.50 percent for the FPU Medical Plan. A one-percentage point increase in the health care
inflation rate from the assumed rate would increase the accumulated postretirement benefit
obligation by approximately $787,000 as of January 1, 2010, and would increase the aggregate of the
service cost and interest cost components of the net periodic postretirement benefit cost for 2010
by approximately $48,000. A one-percentage point decrease in the health care inflation rate from
the assumed rate would decrease the accumulated postretirement benefit obligation by approximately
$582,000 as of January 1, 2010, and would decrease the aggregate of the service cost and interest
cost components of the net periodic postretirement benefit cost for 2010 by approximately $40,000.
Estimated Future Benefit Payments
In 2011, we expect to contribute $205,000 and $1.3 million to the Chesapeake Pension Plan and FPU
Pension Plan, respectively, and $853,000 to the Chesapeake SERP. We also expect to
contribute $96,000 and $158,000 to the Chesapeake Postretirement Plan and FPU Medical Plan,
respectively, in 2011. The schedule below shows the estimated future benefit payments for each of
the plans previously described:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chesapeake |
|
|
FPU |
|
|
|
|
|
Chesapeake |
|
|
FPU |
|
|
|
Pension |
|
|
Pension |
|
|
Chesapeake |
|
|
Postretirement |
|
|
Medical |
|
(in thousands) |
|
Plan(1) |
|
|
Plan(1) |
|
|
SERP(2) |
|
|
Plan(2) |
|
|
Plan(2)(3) |
|
2011 |
|
$ |
1,315 |
|
|
$ |
2,324 |
|
|
$ |
853 |
|
|
$ |
96 |
|
|
$ |
158 |
|
2012 |
|
$ |
465 |
|
|
$ |
2,484 |
|
|
$ |
87 |
|
|
$ |
104 |
|
|
$ |
151 |
|
2013 |
|
$ |
533 |
|
|
$ |
2,662 |
|
|
$ |
86 |
|
|
$ |
111 |
|
|
$ |
144 |
|
2014 |
|
$ |
556 |
|
|
$ |
2,815 |
|
|
$ |
84 |
|
|
$ |
119 |
|
|
$ |
169 |
|
2015 |
|
$ |
686 |
|
|
$ |
2,939 |
|
|
$ |
133 |
|
|
$ |
128 |
|
|
$ |
189 |
|
Years 2016 through
2020 |
|
$ |
3,932 |
|
|
$ |
15,974 |
|
|
$ |
672 |
|
|
$ |
703 |
|
|
$ |
1,040 |
|
|
|
|
(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 our general funds. |
|
(3) |
|
These amounts are shown net of estimated Medicare Part-D reimbursements of $9,000,
$10,000, $11,000, $12,000 and $13,000 for the years 2011 to 2015, respectively, and $78,000 for the years 2015 through 2019. |
Chesapeake Utilities Corporation 2010 Form 10-K Page 97
Notes to the Consolidated Financial Statements
On March 23, 2010, the Patient Protection and Affordable Care Act was signed into law. On
March 30, 2010, a companion bill, the Health Care and Education Reconciliation Act of 2010, was
also signed into law. Among other things, these new laws, when taken together, reduce the tax
benefits available to an employer that receives the Medicare Part D subsidy. The deferred tax
effects of the reduced deductibility of the postretirement prescription drug coverage must be
recognized in the period these new laws were enacted. The FPU Medical Plan receives the Medicare
Part D subsidy. We assessed the deferred tax effects on the reduced deductibility as a result of
these new laws and determined that the deferred tax effects were not material to our financial
results.
Retirement Savings Plan
We sponsor two 401(k) retirement savings plans and one non-qualified supplemental employee
retirement savings plan.
Chesapeakes 401(k) plan is offered to all eligible employees, except for those FPU employees, who
have the opportunity to participate in FPUs 401(k) plan. Effective January 1, 2011, we match 100
percent of eligible participants pre-tax contributions to the Chesapeake 401(k) plan up to a
maximum of six percent of the eligible compensation, including pre-tax contributions made by
BravePoint employees. In addition, we may make a supplemental contribution to all participants in
the plan, without regard to whether or not they make pre-tax contributions. Beginning January 1,
2011, the employer matching contribution is made in cash and will be invested based on a
participants investment directions. Any supplemental employer contribution is generally made in
Chesapeake stock. With respect to the employer match and supplemental employer contribution
participants, employees are 100 percent vested after two years of service or have attained an age
of 55 years while still employed by Chesapeake. Employees with one year of service are 20 percent
vested and will become 100 percent vested after two years of service. Employees who do not make an
election to contribute or do not opt out of the Chesapeake 401(k) plan will be automatically
enrolled at a deferral rate of three percent.
Prior to January 1, 2011, we made matching contributions on up to six percent of each Chesapeake
employees eligible pre-tax compensation for the year, except for the employees of our advanced
information services subsidiary, as further explained below. The match was between 100 percent and
200 percent of the employees contribution (up to six percent), based on the employees age and
years of service. The first 100 percent was matched with Chesapeake common stock; the remaining
match was invested in Chesapeakes 401(k) Plan according to each employees investment direction.
Employees were automatically enrolled at a two-percent contribution, with the option of opting out,
and were eligible for the company match after three months of continuing service, with vesting of
20 percent per year.
From July 1, 2006 to December 31, 2010, our contribution made on behalf of BravePoint employees was
a 50 percent matching contribution, for up to six percent of each employees annual compensation
contributed to the plan. The matching contribution was funded in Chesapeake common stock. The
plan 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 subsidiary had funds available for profit-sharing was dependent upon the
extent to which the segments actual earnings exceeded budgeted earnings. Any profit-sharing
dollars made available to employees could be deferred into the plan and/or paid out in the form of
a bonus.
We continue to maintain a separate 401(k) retirement savings plan for FPU. Effective January 1,
2011, we match 100 percent of eligible non-union participants pre-tax contributions to the FPU
401(k) plan up to a maximum of six percent of the eligible compensation. Eligible employees who
have not opted out of the plan are automatically enrolled at the three-percent deferral rate and
the automatic deferral will increase by one percent per year up to a maximum of six percent, unless
an employee elects otherwise, with vesting of 100 percent after two years of service. Employees
with one year of service are 20 percent vested and become 100 percent vested after two years of
service. Also, we may make other supplemental employer contributions to the plan at such time that
we deem appropriate. Supplemental employer contributions may be made to the eligible plan
participants based on the employee compensation for the year. Participants are only eligible for the employer and supplemental
employer contributions if they have worked for at least 501 hours and 1000 hours respectively during the Plan Year.
Chesapeake Utilities Corporation 2010 Form 10-K Page 98
Notes to the Consolidated Financial Statements
Prior to January 1, 2011, FPUs 401(k) plan provided a matching contribution of 50 percent of
an employees pre-tax contributions, up to six percent of the employees salary, for a maximum
company contribution of up to three percent. For non-union employees the plan provided a company
match of 100 percent for the first two percent of an employees contribution, and a match of 50
percent for the next four percent of an employees contribution, for a total company match of up to
four percent. Employees were automatically enrolled at the three percent contribution, with the
option of opting out, and were eligible for the company match after six months of continuous
service, with vesting of 100 percent after three years of continuous service.
Effective January 1, 1999, we began offering a non-qualified supplemental employee retirement
savings plan (401(k) SERP) to our executives over a specific income threshold. Participants
receive a cash-only matching contribution percentage equivalent to
their 401(k) match level. All
contributions and matched funds can be invested among the mutual funds available for investment.
These same funds are available for investment of employee contributions within Chesapeakes 401(k)
plan. All obligations arising under the
401(k) SERP are payable from our general assets, although
we have established a Rabbi Trust for the 401(k) SERP. As discussed further in Note G
Investments, to the Consolidated Financial Statements, the assets held in the Rabbi Trust
included a fair value of $2.4 million and $2.0 million at
December 31, 2010 and 2009, respectively,
related to the 401(k) SERP. The assets of the Rabbi Trust are at all times subject to the claims of
our general creditors.
Contributions to all of our 401(k) plans totaled $1.7 million for the year ended December 31, 2010
and $1.6 million for both years ended December 31, 2009 and 2008. As of December 31, 2010, there
are 582,486 shares reserved to fund future contributions to the 401(k) plans.
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 all or a part
of certain specified types of compensation, including executive cash bonuses, executive performance
shares, and directors retainers and fees. At December 31, 2010, the Deferred Compensation Plan
consisted solely of shares of common stock related to the deferral of executive performance shares
and directors stock retainers.
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 are paid
in cash. All deferrals of executive performance shares and directors stock retainers are paid in
shares of our common stock, except that cash is paid in lieu of fractional shares.
We established a Rabbi Trust in connection with the Deferred Compensation Plan. The value of our
stock held in the Rabbi Trust is classified within the stockholders equity section of the Balance
Sheet and has been accounted for in a manner similar to treasury stock. The amounts recorded under
the Deferred Compensation Plan totaled $777,000 and $739,000 at December 31, 2010 and 2009,
respectively.
Chesapeake Utilities Corporation 2010 Form 10-K Page 99
Notes to the Consolidated Financial Statements
N. Share-Based Compensation Plans
Our non-employee directors and key employees are awarded share-based awards through our
Directors Stock Compensation Plan (DSCP) and the Performance Incentive Plan (PIP),
respectively. We record these share-based awards as compensation costs over the respective service
period for which services are received in exchange for an award of equity or equity-based
compensation. The compensation cost is based on the fair value of the grant on the date it was
granted.
The table below presents the amounts included in net income related to share-based compensation
expense, for the restricted stock awards issued under the DSCP and the PIP for the years ended
December 31, 2010, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31, |
|
2010 |
|
|
2009 |
|
|
2008 |
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Directors Stock Compensation Plan |
|
$ |
283 |
|
|
$ |
191 |
|
|
$ |
180 |
|
Performance Incentive Plan |
|
|
872 |
|
|
|
1,115 |
|
|
|
640 |
|
|
|
|
|
|
|
|
|
|
|
Total compensation expense |
|
|
1,155 |
|
|
|
1,306 |
|
|
|
820 |
|
Less: tax benefit |
|
|
463 |
|
|
|
523 |
|
|
|
327 |
|
|
|
|
|
|
|
|
|
|
|
Share-Based Compensation amounts included in net income |
|
$ |
692 |
|
|
$ |
783 |
|
|
$ |
493 |
|
|
|
|
|
|
|
|
|
|
|
Stock Options
We did not have any stock options outstanding at December 31, 2010 or 2009, nor were any stock
options issued during 2010, 2009 and 2008.
Directors Stock Compensation Plan
Under the DSCP, each of our non-employee directors received in 2010 an annual retainer of 900
shares of common stock. Shares granted under the DSCP are issued in advance of the directors
service period; therefore, these shares are fully vested as of the grant date. We record a prepaid
expense as of the date of the grant equal to the fair value of the shares issued and amortize the
expense equally over a service period of one year.
A summary of stock activity under the DSCP is presented below:
|
|
|
|
|
|
|
|
|
|
|
Number of |
|
|
Weighted Average |
|
|
|
Shares |
|
|
Grant Date Fair Value |
|
Outstanding December 31, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted (1) |
|
|
7,174 |
|
|
$ |
29.83 |
|
Vested |
|
|
7,174 |
|
|
$ |
29.83 |
|
Forfeited |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding December 31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted |
|
|
9,900 |
|
|
$ |
29.99 |
|
Vested |
|
|
9,900 |
|
|
$ |
29.99 |
|
Forfeited |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding December 31, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
On October 28, 2009, we added two new members to our Board of Directors; each new
member was awarded 337 shares of common stock for the prorated portion of their service period. |
We recorded compensation expense of $283,000, $191,000 and $180,000 related to DSCP awards for
the years ended December 31, 2010, 2009 and 2008, respectively.
Chesapeake Utilities Corporation 2010 Form 10-K Page 100
Notes to the Consolidated Financial Statements
The weighted average grant-date fair value of DSCP awards granted during 2010 and 2009 was $29.99
and $29.83, per share, respectively. The intrinsic values of the DSCP awards are equal to the fair
value of these awards on the date of grant. At December 31, 2010, there was $99,000 of
unrecognized compensation expense related to DSCP awards that is expected to be recognized over the
first four months of 2011.
As of December 31, 2010, there were 34,215 shares reserved for issuance under the DSCP.
Performance Incentive Plan (PIP)
Our Compensation Committee is authorized to grant key employees of the Company the right to receive
awards of shares of our 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 successful achievement of long-term goals,
growth, and financial results and they are comprised of both market-based and performance-based
conditions or targets.
A portion of the shares granted under the PIP in 2008 vested in 2010, and the fair value of each
share is equal to the market price of our common stock on the date of the grant. The shares
granted under the 2009 and 2010 long-term plans have not vested as of December 31, 2010, 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.
A summary of stock activity under the PIP is presented below:
|
|
|
|
|
|
|
|
|
|
|
Number of |
|
|
Weighted Average |
|
|
|
Shares |
|
|
Fair Value |
|
Outstanding December 31, 2008 |
|
|
94,200 |
|
|
$ |
27.84 |
|
|
|
|
|
|
|
|
Granted |
|
|
28,875 |
|
|
$ |
29.19 |
|
Vested |
|
|
|
|
|
|
|
|
Fortfeited |
|
|
|
|
|
|
|
|
Expired |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding December 31, 2009 |
|
|
123,075 |
|
|
$ |
28.15 |
|
|
|
|
|
|
|
|
Granted |
|
|
40,875 |
|
|
|
29.38 |
|
Vested |
|
|
43,960 |
|
|
|
27.94 |
|
Fortfeited |
|
|
|
|
|
|
|
|
Expired |
|
|
18,840 |
|
|
|
27.94 |
|
|
|
|
|
|
|
|
Outstanding December 31, 2010 |
|
|
101,150 |
|
|
$ |
28.78 |
|
|
|
|
|
|
|
|
In 2010 and 2008 (in 2009, no shares under the PIP vested), we withheld shares with value at
least 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 17,695 and 12,511 for 2010 and 2008,
respectively, 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 employees 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 $538,000 and $383,000
in 2010 and 2008, respectively.
Chesapeake Utilities Corporation 2010 Form 10-K Page 101
Notes to the Consolidated Financial Statements
We recorded compensation expense of $872,000, $1.1 million and $640,000 related to the PIP for the
years ended December 31, 2010, 2009, and 2008, respectively.
The weighted average grant-date fair value of PIP
awards granted during 2010, 2009 and 2008 was
$29.38, $29.19 and $27.84, per share, respectively. The intrinsic value of the PIP awards was $2.7
million, $2.1 million and $1.1 million for 2010, 2009 and 2008, respectively.
As of December 31, 2010, there were 345,028 shares reserved for issuance under the PIP.
O. 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 subsidiary, is
subject to regulation by the FERC; and PIPECO, our intrastate pipeline subsidiary, is subject to
regulation by the Florida PSC. Chesapeakes Florida natural gas distribution division and FPUs
natural gas and electric operations continue to be subject to regulation by the Florida PSC as
separate entities.
Delaware
On September 2, 2008, our Delaware division filed with the Delaware PSC its annual Gas Sales
Service Rates (GSR) Application, seeking approval to change its GSR, effective November 1, 2008.
On July 7, 2009, the Delaware PSC granted approval of a settlement agreement presented by the
parties in this docket, which included the Delaware PSC, our Delaware division and the Division of
the Public Advocate. As part of the settlement, the parties agreed to develop a record in a later
proceeding on the price charged by the Delaware division for the temporary release of transmission
pipeline capacity to our natural gas marketing subsidiary, PESCO. On January 8, 2010, the Hearing
Examiner in this proceeding issued a report of Findings and Recommendations in which he
recommended, among other things, that the Delaware PSC require the Delaware division to refund to
its firm service customers the difference between what the Delaware division would have received
had the capacity released to PESCO been priced at the maximum tariff rates under asymmetrical
pricing principles and the amount actually received by the Delaware division for capacity released
to PESCO. The Hearing Examiner also recommended that the Delaware PSC require us to adhere to
asymmetrical pricing principles in all future capacity releases by the Delaware division to PESCO,
if any. Accordingly, if the Hearing Examiners refund recommendation for past capacity releases
were approved without modification by the Delaware PSC, the Delaware division would have to credit
to its firm service customers amounts equal to the maximum tariff rates that the Delaware division
pays for long-term capacity, which we estimated to be approximately $700,000, even though the
temporary releases were made at lower rates based on competitive bidding procedures required by the
FERCs capacity release rules. We disagreed with the Hearing Examiners recommendations and filed
exceptions to those recommendations on February 18, 2010.
At the hearing on March 30, 2010, the Delaware PSC agreed with us that the Delaware division had
been releasing capacity based on a previous settlement approved by the Delaware PSC and, therefore,
did not require the Delaware division to issue any refunds for past capacity releases. The
Delaware PSC, however, required the Delaware division to adhere to asymmetrical pricing principles
for future capacity releases to PESCO until a more appropriate pricing methodology is developed and
approved. The Delaware PSC issued an order on May 18, 2010 elaborating its decisions at the March
hearing and directing the parties to reconvene in a separate docket to determine if a pricing
methodology other than asymmetrical pricing principles should apply to future capacity releases by
the Delaware division to PESCO. On June 17, 2010, the Division of the Public Advocate filed an
appeal with the Delaware Superior Court, asking it to overturn the Delaware PSCs decision with
regard to refunds for past capacity releases. On June 28, 2010, the Delaware division filed a
Notice of Cross Appeal with the Delaware Superior Court asking it to overturn the Delaware PSCs
decision with regard to requiring the Delaware division to adhere to asymmetrical pricing
principles for future capacity releases to PESCO. The parties involved filed opening briefs
with the Delaware Superior Court on September 30, 2010, answering briefs on October 20, 2010, and
reply briefs on November 3, 2010. We anticipate that the Court will render a decision sometime in
2011. Due to the ongoing legal proceeding, the parties have not yet opened a separate docket to
determine an alternative pricing methodology for future capacity releases. We did not accrue any
contingent liability related to potential refunds for past capacity releases. Since the Delaware
PSCs Order on May 18, 2010, the Delaware division has not released any capacity to PESCO.
Chesapeake Utilities Corporation 2010 Form 10-K Page 102
Notes to the Consolidated Financial Statements
On September 4, 2009, the 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 evidentiary hearing in this matter was held on May 19, 2010. At the evidentiary
hearing, the parties in this docket, which included the Delaware PSC, the Delaware division and the
Division of the Public Advocate, presented a proposed settlement agreement to resolve all issues
addressed in this docket. The settlement agreement contemplates that the Delaware division will
begin to share interruptible margins with its firm ratepayers when those margins reach a certain
level in each 12-month period ending October 31. Based on the current level of interruptible
margins generated by the Delaware division, we do not anticipate that sharing of future
interruptible margins will have a significant impact on our results. The Delaware PSC approved the
settlement agreement on September 7, 2010.
On December 17, 2009, the 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. The Delaware PSC granted approval of the Individual Contract Rate on February 18, 2010.
On September 1, 2010, the Delaware division filed with the Delaware PSC its annual GSR Application,
seeking approval to change its GSR, effective November 1, 2010. On September 21, 2010, the
Delaware PSC authorized the Delaware division to implement the GSR charges on November 1, 2010, on
a temporary basis, subject to refund, pending the completion of full evidentiary hearings and a
final decision. The Delaware division anticipates a final decision no later than the third quarter
of 2011.
Maryland
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 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 divisions four
quarterly filings. On January 8, 2010, the Maryland PSC issued an Order substantially affirming
the Hearing Examiners decision in the matter.
On December 14, 2010, the Maryland PSC held an evidentiary hearing to determine the reasonableness
of the four quarterly gas cost recovery filings submitted by the Maryland division during the 12
months ended September 30, 2010. No issues were raised at the hearing, and on December 20, 2010,
the Hearing Examiner in this proceeding issued a proposed Order approving the divisions four
quarterly filings. This proposed Order became a final Order of the Maryland PSC on January 20,
2011.
Florida
On July 14, 2009, Chesapeakes 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 divisions 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 then pending merger with FPU. On August 18, 2009, the
Florida PSC approved the full amount of the Florida divisions 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 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 Chesapeakes Florida division and FPUs
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, cost savings and cost increases that
have resulted from the merger.
Chesapeake Utilities Corporation 2010 Form 10-K Page 103
Notes to the Consolidated Financial Statements
Also on December 15, 2009, the Florida PSC approved the settlement agreement for a final natural
gas rate increase of $7,969,000 for FPUs natural gas distribution operation. 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 PSCs order and its final natural gas rate increase ruling.
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. 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.
In 2010, we recorded a $750,000 accrual related to the regulatory risk
for FPUs natural
gas distribution operation associated with its earnings, merger
benefits and recovery of the purchase premium.. We are required to detail known benefits, synergies, cost savings and
cost increases resulting from the merger and present the information in the come-back filing to
the Florida PSC by April 29, 2011 (within 18 months of the merger). We are currently in
discussions with the Office of Public Counsel and the Florida PSC staff regarding the benefits and cost savings of the
merger, current and expected earnings levels as well as the recovery of approximately $34.9 million
in purchase premium and $2.2 million in merger-related costs. We recorded this accrual based on
our assessment of FPUs current earnings, the regulatory environment in Florida and progress of the
current discussions.
On September 1, 2009, FPUs 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, Chesapeakes Florida division and FPUs natural gas distribution operation
separately filed their respective annual Energy Conservation Cost Recovery Clauses, 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, FPUs 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.
On September 1, 2010, FPUs electric distribution operation filed its annual Fuel and Purchased
Power Cost Recovery Clause, which seeks final approval of the levelized fuel adjustment and
purchased power cost recovery factors for 2011. On December 20, 2010, the Florida PSC issued
an order approving the proposed 2011 fuel rates, effective for meters read on and after January
1, 2011.
On September 10, 2010, FPUs electric distribution operation filed its annual Energy Conservation
Cost Recovery (ECCR) Clause, which seeks final approval of the 2009 conservation-related revenues
and expenses and new ECCR recovery factors for 2011. On November 29, 2010, the Florida PSC issued
an order approving the proposed 2011 ECCR recovery factors, effective for meters read on and after
January 1, 2011
On September 13, 2010, Chesapeakes Florida division, FPUs Indiantown division and FPUs natural
gas distribution operation separately filed their annual ECCR Clauses, seeking final approval of
the 2009 conservation-related revenues and expenses and new ECCR recovery factors for 2011. On
November 29, 2010, the Florida PSC issued an order approving all of the proposed 2011 ECCR recovery
factors, effective for meters read on or after January 1, 2011.
Chesapeake Utilities Corporation 2010 Form 10-K Page 104
Notes to the Consolidated Financial Statements
On September 13, 2010, FPUs natural gas distribution operation filed its annual Purchased Gas
Adjustment (PGA) Clause seeking final approval of its 2009 purchased gas-related revenues and
expenses and new PGA cap rate for 2011. On November 29, 2010, the Florida PSC issued an order
approving the proposed 2011 PGA cap rate, effective for meters read on or after January 1, 2011.
On, July 7, 2009, the City of Marianna, Florida
Commission (the Commission) passed an
ordinance granting a franchise to FPU effective February 1, 2010 for a period not to exceed 10 years for
the operation and distribution and/or sale of electric energy (the franchise agreement). The franchise
agreement provides that FPU will develop and implement new time-of-use (TOU) and interruptible
electric power rates that shall be mutually agreed upon by FPU and the city. The franchise agreement
further provides that the TOU and interruptible rates be effective no later than February 17, 2011 and
available to all customers within the corporate limits of the City of Marianna. If the rates are not in effect
by February 17, 2011, the city has the right to give notice to FPU within 180 days thereafter of its intent
to exercise its option to purchase FPUs property (consisting of the electric distribution assets) within the
City of Marianna. Any such purchase would be subject to approval by the Commission which would also
need to approve the presentation of a referendum to voters in the City of Marianna for the approval of the
purchase and the operation by the city of an electric distribution facility. If the purchase is approved by
the Commission and the voters in the City of Marianna, the closing of the purchase must occur within 12 months
after the referendum is approved. If the city elects to purchase the Marianna property, the
agreement requires the city to pay FPU the fair market value for such property as determined by three
qualified appraisers.
In accordance with the terms of the franchise
agreement, FPU developed reasonable TOU and
interruptible rates and on December 14, 2010, filed a petition with the Florida PSC for authority to
implement a demonstration project consisting of such proposed TOU and interruptible rates for approval
and implementation on or before February 17, 2011. The Florida PSC issued an order approving the
proposed TOU and interruptible rates for a four-year period on February 11, 2011. The city has objected
to the proposed rates and has filed a petition protesting the entry of the Florida PSCs order.
As disclosed in Note Q, Other Commitments and Contingencies, on March 2, 2011, the city
filed a declaratory action against FPU in the Circuit Court of the Fourteenth Judicial Circuit in and for Jackson County, Florida,
alleging breaches of the franchise agreement by FPU and seeking a declaratory judgment that the city has
the right to exercise its option to purchase FPUs property in the City of Marianna in accordance with the
terms of the franchise agreement.
Chesapeake Utilities Corporation 2010 Form 10-K Page 105
Notes to the Consolidated Financial Statements
ESNG
The following are regulatory activities involving FERC Orders applicable to ESNG and the expansions
of ESNGs transmission system:
Energylink Expansion 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 ESNGs existing facilities in Sussex County, Delaware. In April 2009, ESNG
terminated this project based on increased construction costs over its original projection and
initiated billing to recover approximately $3.2 million of costs incurred in connection with this
project and the related cost of capital over a period of 20 years in accordance with the terms of
the precedent agreements executed with the two participating customers and approved by the FERC.
One of the two participating customers is Chesapeake, through its Delaware and Maryland divisions.
During 2010, ESNG and the participating customers negotiated to reduce the recovery period of this
cost from 20 years to five years. On January 27, 2011, ESNG filed with the FERC the request to
amend the cost recovery period, which was approved by the FERC on February 14, 2011.
Mainline Extension Project: On November 25, 2009, ESNG filed a notice of its intent under its
blanket certificate to construct, own and operate new mainline facilities to deliver additional
firm service of 1,594 Mcfs per day of natural gas to Chesapeakes Delaware division. The FERC
published the notice of this filing on December 7, 2009. No protest was filed during the 60-day
period following the notice, and ESNG commenced construction on February 6, 2010. The facilities
were completed on April 29, 2010, and ESNG commenced billing for the new service on May 1, 2010.
Mainline Extension and Interconnect Project: On March 5, 2010, ESNG submitted an Application for
Certificate of Public Convenience and Necessity to the FERC related to a proposed mainline
extension and interconnect project that would tie into the interstate pipeline system of TETLP.
ESNGs project involved building and operating an eight-mile mainline extension from ESNGs
existing facility in Parkesburg, Pennsylvania to the interconnection with TETLP at Honey Brook,
Pennsylvania. The estimated capital cost of this project is approximately $19.4 million. On
September 3, 2010, the FERC approved ESNGs application, subject to certain environmental
conditions, some of which had to be met prior to the commencement of construction. ESNG accepted
the Order Issuing Certificate on October 4, 2010. On October 13, 2010, the FERC issued a Notice to
Proceed with the construction of the projects facilities as all conditions that must be met prior
to the commencement of construction were satisfied. The facilities were completed on December 15,
2010, and on December 21, ESNG received FERC approval to place the facilities into service. ESNG
commenced billing for the new service on January 1, 2011.
Rate Case Filing: On December 30, 2010, ESNG filed a base rate proceeding in compliance with the
terms of the settlement in its prior rate base proceeding. ESNGs filed rates, proposed to be
effective February 1, 2011, reflect an annual increase of $6,748,628 over its current rates. The
proposed rate increase reflects increases in operating and maintenance expenses, depreciation
expense, and return on new gas plant facilities that are expected to be placed into service before
June 30, 2011. ESNG proposed a return on equity of 13.5 percent. ESNG expects to reach a
settlement agreement on the filing in 2011.
ESNG also had developments in the following FERC matters:
On April 30, 2010, ESNG submitted its annual Interruptible Revenue Sharing Report to the FERC.
ESNG reported in this filing that its interruptible revenue was in excess of its annual
threshold amount and refunded $90,718, inclusive of interest, in the second quarter of 2010 to
its eligible firm customers.
On May 28, 2010, ESNG submitted its annual Fuel Retention Percentage (FRP) and Cash-Out
Surcharge filings to the FERC. In these filings, ESNG proposed to implement a FRP rate of
0.00 percent and a zero rate for its Cash-Out Surcharge. ESNG also proposed to refund
$310,117, inclusive of interest, to its eligible
customers in the second quarter of 2010 as a result of combining its over-recovered Gas
Required for Operations and its over-recovered Cash-Out Cost. The FERC approved these
proposals on June 29, 2010, and ESNG issued refunds to eligible customers.
Chesapeake Utilities Corporation 2010 Form 10-K Page 106
Notes to the Consolidated Financial Statements
On August 16, 2010, ESNG submitted its compliance filing with regard to the FERCs Order on
Electronic Tariff Filings (Order No. 714). This Order required all natural gas pipelines
subject to FERC jurisdiction to file baseline tariff sheets electronically. All subsequent
rate and tariff-related filings are to be made electronically. On October 13, 2010, the FERC
approved ESNGs compliance filing for this Order.
On September 1, 2010, ESNG submitted its compliance filing with regard to the FERCs most
recent Order adopting Standards for Business Practices for Interstate Natural Gas Pipelines
(Order No. 587-U). With this Order, FERC incorporated by reference into its regulations
Version 1.9 of the North American Energy Standards Board Wholesale Gas Quadrants standards.
On October 13, 2010, FERC approved ESNGs compliance filing.
P. Environmental Commitments and Contingencies
We are subject to federal, state and local laws and regulations governing environmental
quality and pollution control. These laws and regulations require us to remove or remedy the
effect on the environment of the disposal or release of specified substances at current and former
operating sites.
We have participated in the investigation, assessment or remediation and have certain exposures at
six former 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 MDE
regarding a seventh former MGP site located in Cambridge, Maryland. The Key West, Pensacola,
Sanford and West Palm Beach sites are related to FPU, for which we assumed in the merger any
existing and future contingencies.
As of December 31, 2010, we had $358,000 in environmental liabilities related to Chesapeakes MGP
sites in Maryland and Florida, representing our estimate of the future costs associated with those
sites. As of December 31, 2010, we had approximately $1.3 million in regulatory and other assets
for future recovery of environmental costs from Chesapeakes customers through our approved rates.
As of December 31, 2010, we had approximately $11.6 million in environmental liabilities related to
FPUs MGP sites in Florida, primarily from the West Palm Beach site, which represents our estimate
of the future costs associated with those sites. FPU has approval to recover up to $14.0 million
of its environmental costs from insurance and from customers through rates. Approximately $7.8
million of FPUs expected environmental costs have been recovered from insurance and customers
through rates as of December 31, 2010. We also had approximately $6.2 million in regulatory assets
for future recovery of environmental costs from FPUs customers.
The following discussion provides details on each site.
Salisbury, Maryland
We have substantially completed remediation of this site in Salisbury, Maryland, where it was
determined that a former MGP caused localized ground-water contamination. During 1996, we
completed construction of an Air Sparging and Soil-Vapor Extraction (AS/SVE) system and
began remediation procedures. We have reported the remediation and monitoring results to the
MDE on an ongoing basis since 1996. In February 2002, the MDE granted permission to
permanently decommission the AS/SVE system and to discontinue all on-site and off-site well
monitoring, except for one well, which is being maintained for periodic product monitoring and
recovery. We have requested and are awaiting a No Further Action determination from the MDE.
Chesapeake Utilities Corporation 2010 Form 10-K Page 107
Notes to the Consolidated Financial Statements
Through December 31, 2010, we have incurred and paid approximately $2.9 million for remedial
actions and environmental studies. We have recovered approximately $2.2 million through
insurance proceeds or in rates and have $667,000 to be recovered through future rates.
Winter Haven, Florida
The Winter Haven site is located on the eastern shoreline of Lake Shipp, in Winter Haven,
Florida. Pursuant to a Consent Order entered into with the FDEP, we are obligated to assess
and remediate environmental impacts at this former MGP site. In 2001, the FDEP approved a RAP
requiring construction and operation of a Bio-Sparging and Soil/Vapor Extraction (BS/SVE)
treatment system to address soil and groundwater impacts at a portion of the site. The BS/SVE
treatment system has been in operation since October 2002. Modifications and upgrades to the
BS/SVE treatment system were completed in October 2009. The Sixteenth Semi-Annual RAP
Implementation Status Report was submitted to the FDEP in December 2010. The groundwater
sampling results through December 2010 show a continuing reduction in contaminant concentrations
and indicate that the recent treatment system modifications and upgrades have had a beneficial
impact on the rate of reduction. At present, we predict that remedial action objectives may
be met for the area being treated by the BS/SVE treatment system in approximately two to three
years. The cost of operating and monitoring the system is approximately $46,000.
The BS/SVE treatment system does not address impacted soils in the southwest corner of the
site. On April 16, 2010, a soil excavation interim RAP describing the proposed excavation of
approximately 4,000 cubic yards of impacted soils from the southwest corner of the site was
submitted to the FDEP for review. The FDEP provided comments to the soil excavation interim
RAP by letter, dated June 24, 2010. A response letter, dated August 3, 2010, was submitted to
FDEP. A subsequent conditional approval letter, dated August 27, 2010, was issued by FDEP.
The cost to implement this excavation plan has been estimated at $250,000; however, this
estimate does not include costs associated with dewatering or shoreline stabilization, which
would be required to complete the excavation. Because the costs associated with shoreline
stabilization and dewatering (including treatment and discharge of the pumped water) are
likely substantial, alternatives to this excavation plan will to be evaluated. We plan to
perform the excavation in late 2011 or early 2012.
The FDEP has indicated that we may be required to remediate sediments along the shoreline of
Lake Shipp, immediately west of the site. Based on studies performed to date, we object to
FDEPs suggestion that the sediments have been adversely impacted by the former operations of
the MGP. Our early estimates indicate that some of the corrective measures discussed by the
FDEP could cost as much as $1.0 million. We believe that corrective measures for the
sediments are not warranted and intend to oppose any requirement that we undertake corrective
measures in the offshore sediments. We have not recorded a liability for sediment
remediation, as the final resolution of this matter cannot be predicted at this time.
Through December 31, 2010, we have incurred and paid approximately $1.6 million for this site
and estimate an additional cost of $358,000 in the future, which has been accrued. We have
recovered through rates $1.3 million of the costs and continue to expect that the remaining
$658,000, which is included in regulatory assets, will be recoverable from customers through
our approved rates.
Key West, Florida
FPU formerly owned and operated an MGP in Key West, Florida. Field investigations performed in
the 1990s identified limited environmental impacts at the site, which is currently owned by an
unrelated third party, Suburban Propane. In September 2010, FDEP issued a Preliminary
Contamination Assessment Report, for additional soil and groundwater investigation work that
was undertaken by FDEP in November 2009 and January 2010, after 17 years of regulatory
inactivity. Because FDEP observed that some soil and groundwater standards were exceeded,
FDEP is seeking to meet with FPU and the current site owner, Suburban Propane, to discuss
additional field work which the FDEP believes is warranted for the site. Potential costs for
investigation and remediation are projected to be $153,000.
Chesapeake Utilities Corporation 2010 Form 10-K Page 108
Notes to the Consolidated Financial Statements
Pensacola, Florida
FPU formerly owned and operated an MGP in Pensacola, Florida. The MGP was also owned by Gulf
Power. Portions of the site are now owned by the city of Pensacola and the Florida Department
of Transportation (FDOT). In October 2009, FDEP informed Gulf Power that FDEP would approve
a conditional No Further Action (NFA) determination for the site, which must include a
requirement for institutional and engineering controls. On November 9, 2010, an NFA Proposal
was submitted to FDEP, along with a draft restrictive covenant for the property currently
owned by FDOT. At this point, it is anticipated that no further monitoring will be required
on the site. The remaining consulting and remediation costs are projected to be $7,000.
Sanford, Florida
FPU is the current owner of property in Sanford, Florida, a former MGP site which was operated
by several other entities before FPU acquired the property. FPU was never an owner or an
operator of the MGP. In late September 2006, 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 EPAs 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. FPUs
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, 2010, FPU has paid $650,000 to the
Sanford Group escrow account for its share of funding requirements.
The Sanford Group, EPA and the U.S. Department of Justice agreed to a Consent Decree in March
2008, which was entered by the federal court in Orlando, Florida on January 15, 2009. The
Consent Decree obligates the Sanford Group to implement the remedy approved by EPA for the
site. The total cost of the final remedy is now estimated at approximately $18 million. FPU
has advised the other members of the Sanford Group that it is unwilling at this time to agree
to pay any sum in excess of the $650,000 committed by FPU in the Third Participation
Agreement.
Several members of the Sanford Group have concluded negotiations with two adjacent property
owners to resolve damages that the property owners allege they have and will incur as a result
of the implementation of the EPA-approved remediation. In settlement of these claims, members
of the Sanford Group, which in this instance does not include FPU, have agreed to pay
specified sums of money to the parties. FPU has refused to participate in the funding of the
third-party settlement agreements based on its contention that it did not contribute to the
release of hazardous substances at the site giving rise to the third-party claims.
As of December 31, 2010, FPUs remaining share of remediation expenses, including attorneys
fees and costs, is estimated to be $20,000. However, we are unable to determine, to a
reasonable degree of certainty, whether the other members of the Sanford Group will accept
FPUs asserted defense to liability for costs exceeding $13 million to implement the final
remedy for this site or will pursue a claim against FPU for a sum in excess of the $650,000
that FPU has paid under the Third Participation Agreement.
Chesapeake Utilities Corporation 2010 Form 10-K Page 109
Notes to the Consolidated Financial Statements
West Palm Beach, Florida
We are currently evaluating remedial options to respond to environmental impacts to soil and
groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West Palm
Beach, Florida, where FPU previously operated an MGP. Pursuant to a Consent Order between FPU
and the FDEP, effective April 8, 1991, FPU completed the delineation of soil and groundwater
impacts at the site. On June 30, 2008, FPU transmitted a revised feasibility study, evaluating
appropriate remedies for the site, to the FDEP. The revised feasibility study completed in
2008 evaluated a wide range of remedial alternatives based on criteria provided by applicable
laws and regulations. On April 30, 2009, the FDEP issued a remedial action order, which it
subsequently withdrew. In response to the Order and as a condition to its withdrawal, FPU
committed to perform additional field work in 2009 and complete an additional engineering
evaluation of certain remedial alternatives. The scope of this work has increased in response
to FDEPs requests for additional information.
FPU performed additional field work in August 2010, which included the installation of
additional groundwater monitoring wells and performance of a comprehensive groundwater
sampling event. FPU also performed vapor intrusion sampling in October 2010. The results of
the field work were submitted to the FDEP for their review and comment in October 2010. On
November 4, 2010, the FDEP issued its comments on the feasibility study and the proposed
remedy. On November 16, 2010, FPU presented to the FDEP a new proposed strategy for the site
remedy with an aggressive remedial action plan, and the FDEP agreed with the proposal to
implement a phased approach. On December 22, 2010, FPU submitted to the FDEP an interim RAP
to remediate the east parcel of the site, which the FDEP conditionally approved on February 4,
2011.
FPU is currently implementing the interim RAP for the east parcel of the West Palm Beach site,
including the incorporation of FDEPs conditions for approval. We estimate that the updated
costs of remediation will range from approximately $5.1 million to $13.3 million. This
estimate does not include any costs associated with relocation of operations, which is
necessary to implement the remedial plan, and any potential costs associated with
re-development of the properties.
We continue to expect that all costs related to these activities will be recoverable from
customers through rates.
Other
We are in discussions with the MDE regarding a former MGP site located in Cambridge, Maryland.
The outcome of this matter cannot be determined at this time; therefore, we have not recorded
an environmental liability for this location.
Q. Other Commitments and Contingencies
Litigation
In May 2010, a FPU propane customer filed a class action complaint against FPU in Palm Beach
County, Florida, alleging, among other things, that FPU acted in a deceptive and unfair manner
related to a particular charge by FPU on its bills to propane customers and the description of such
charge. The suit sought to certify a class comprised of FPU propane customers to whom such charge
was assessed since May 2006 and requested damages and statutory remedies based on the amounts paid
by FPU customers for such charge. FPU vigorously denies any wrongdoing and maintains that the
particular charge at issue is customary, proper and fair. Without any admission by FPU of any
wrongdoing, validity of the claims or a properly certifiable class for the complaint, FPU entered
into a settlement agreement with the plaintiff in September 2010 to avoid the burden and expenses
of continued litigation. The court approved the final settlement. The
judgement becomes final when the time for appeal expires, which is
expected on March 13, 2011. To date, there has been no notice of
appeal.
Chesapeake Utilities Corporation 2010 Form 10-K Page 110
Notes to the Consolidated Financial Statements
On March 2, 2011, the City of Marianna, Florida filed a declaratory action against FPU
in the Circuit Court of the Fourteenth judicial Circuit in and for Jackson County, Florida, alleging that FPU
breached its obligations under its franchise with the city to provide electric service to customers within
and without the city by failing (i) to develop and implement TOU and interruptible rates that were
mutually agreed to by the city and FPU; (ii) to have such mutually agreed upon rates in effect by February 17,2011;
and (iii) to have such rates available to all of FPUs customers located within and without the
corporate limits of the city. The city is seeking a declaratory judgment to exercise its option under the
franchise agreement to purchase FPUs property (consisting of the electric distribution assets) within the
City of Marianna. Any such purchase would be subject to approval by the Commission which would also
need to approve the presentation of a referendum to voters in the City of Marianna for approval of the
purchase and the operation by the city of an electric distribution facility. If the purchase is approved by
the Commission and the voters in the City of Marianna, the closing of the purchase must occur within 12
months after the referendum is approved. FPU intends to file a response to the Citys complaint and
vigorously contest this litigation and intends to oppose the passage of any proposed referendum that is
presented to voters to approve the purchase of the FPU property in the City of Marianna.
Natural Gas, Electric and Propane Supply
Our natural gas, electric and propane distribution operations have entered into contractual
commitments to purchase gas and electricity from various suppliers. The contracts have various
expiration dates. In March 2009, we renewed our contract with an energy marketing and risk
management company to manage a portion of our natural gas transportation and storage capacity.
This contract expires on March 31, 2012.
Chesapeakes
Florida natural gas distribution division has firm transportation
service contracts with Florida Gas Transmission Company
(FGT) and Gulfstream Natural Gas System, LLC
(Gulfstream). Pursuant to a program approved by the
Florida Public Service Commission (Florida PSC), all of
the capacity under these agreements has been released to various
third-parties, including PESCO. Under the terms of these capacity
release agreements, Chesapeake is contingently liable to FGT and
Gulfstream, should any party that acquired the capacity through
release fail to pay for the service.
PESCO is currently in the process of obtaining and reviewing proposals from suppliers and
anticipates executing agreements before the existing agreements expire in May 2011.
FPUs electric fuel supply contracts require FPU to maintain an acceptable standard of
creditworthiness based on specific financial ratios. FPUs agreement with JEA requires FPU to
comply with the following ratios based on the result of the prior 12 months: (a) total liabilities
to tangible net worth less than 3.75 times and (b) fixed charge coverage ratio greater than 1.5.
If either ratio is not met by FPU, it has 30 days to cure the default or provide an irrevocable
letter of credit if the default is not cured. FPUs agreement with Gulf Power requires FPU to meet
the following ratios based on the average of the prior six quarters: (a) funds from operation
interest coverage ratio (minimum of 2 times) and (b) total debt to total capital (maximum of 65
percent). If FPU fails to meet the requirements, it has to provide the supplier a written
explanation of action taken or proposed to be taken to be compliant. Failure to comply with the
ratios specified in the Gulf Power agreement could result in FPU providing an irrevocable letter of
credit. FPU was in compliance with these requirements as of December 31, 2010.
Corporate Guarantees
The Board of Directors has authorized the Company to issue up to $35 million of corporate
guarantees on behalf of our subsidiaries and for letters of credit. As of March 2, 2011, the Board increased this limit from $35 million to $45 million.
We have issued corporate guarantees to certain vendors of our subsidiaries, primarily the propane
wholesale marketing subsidiary and our natural gas marketing subsidiary. These corporate
guarantees provide for the payment of propane and natural gas purchases in the event of the
respective subsidiarys 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, 2010 was $25.6 million,
with the guarantees expiring on various dates in 2011.
In addition to the corporate guarantees, we have issued a letter of credit to our primary insurance
company for $440,625 which expires on December 2, 2011. The letter of credit is provided as
security to satisfy the deductibles under our various outstanding insurance policies. As a result
of the recent change in our primary insurance company, we have issued an additional letter of
credit for $725,000 to our former primary insurance company, which will expire on June 1, 2011.
There have been no draws on these letters of credit as of December 31, 2010. We do not anticipate
that the letters of credit will be drawn upon by the counterparties and we expect that the letters
of credit will be renewed to the extent necessary in the future.
Chesapeake Utilities Corporation 2010 Form 10-K Page 111
Notes to the Consolidated Financial Statements
We provided a letter of credit for $2.0 million to TETLP related to the Precedent Agreement with
TETLP, which is further described below.
Agreements for Access to New Natural Gas Supplies
On April 8, 2010, our Delaware and Maryland divisions entered into a Precedent Agreement with TETLP
to secure firm transportation service from TETLP in conjunction with its new expansion project,
which is expected to expand TETLPs mainline system by up to 190,000 dekatherms per day (Dts/d).
The Precedent Agreement provides that, upon satisfaction of certain conditions, the parties will
execute two firm transportation service contracts, one for our Delaware division and one for our
Maryland division, for 30,000 and 10,000 Dts/d, respectively, to be effective on the service
commencement date of the project, which is currently projected to occur in November 2012. Each
firm transportation service contract shall, among other things, provide for: (a) the maximum daily
quantity of Dts/d described above; (b) a term of 15 years; (c) a receipt point at Clarington, Ohio;
(d) a delivery point at Honey Brook, Pennsylvania; and (f) certain credit standards and
requirements for security. Commencement of service and TETLPs and our rights and obligations
under the two firm transportation service contracts are subject to satisfaction of various
conditions specified in the Precedent Agreement.
Our Delmarva natural gas supplies are currently received primarily from the Gulf of Mexico natural
gas production region and are transported through three interstate upstream pipelines, two of which
interconnect directly with ESNGs transmission system. The new firm transportation service
contracts between our Delaware and Maryland divisions and TETLP will provide us with an additional
direct interconnection with ESNGs transmission system and access to new sources of natural gas
supplies from other natural gas production regions, including the Appalachian production region,
thereby providing increased reliability and diversity of supply. They will also provide our
Delaware and Maryland divisions additional upstream transportation capacity to meet current
customer demands and to plan for sustainable growth.
The Precedent Agreement provides that the parties shall promptly meet and work in good faith to
negotiate a mutually acceptable reservation rate. Failure to agree upon a mutually acceptable
reservation rate would have enabled either party to terminate the Precedent Agreement, and would
have subjected us to reimburse TETLP for certain pre-construction costs; however, on July 2, 2010,
our Delaware and Maryland divisions executed the required reservation rate agreements with TETLP.
The Precedent Agreement requires us to reimburse TETLP for our proportionate share of TETLPs
pre-service costs incurred to date, if we terminate the Precedent Agreement, are unwilling or
unable to perform our material duties and obligations thereunder, or take certain other actions
whereby TETLP is unable to obtain the authorizations and exemptions required for this project. If
such termination were to occur, we estimate that our proportionate share of TETLPs pre-service
costs could be approximately $4.7 million as of December 31, 2010. If we were to terminate the
Precedent Agreement after TETLP completed its construction of all facilities, which is expected to
be in the fourth quarter of 2011, our proportionate share could be as much as approximately $45
million. The actual amount of our proportionate share of such costs could differ significantly and
would ultimately be based on the level of pre-service costs at the time of any potential
termination. As our Delaware and Maryland divisions have now executed the required reservation
rate agreements with TETLP, we believe that the likelihood of terminating the Precedent Agreement
and having to reimburse TETLP for our proportionate share of TETLPs pre-service costs is remote.
As of December 31, 2010, we provided a letter of credit for $2.0 million under the Precedent
Agreement with TETLP as required. This letter of credit is expected to increase quarterly as
TETLPs pre-service costs increase and will not exceed more than the three-month reservation charge
under the firm transportation service contracts, which we currently estimate to be $2.1 million.
On March 17, 2010, our Delaware and Maryland divisions entered into a separate Precedent Agreement
with ESNG to extend its mainline by eight miles to interconnect with TETLP at Honey Brook,
Pennsylvania. As discussed in Note O, Rates and Other Regulatory Activities, ESNG completed the
extension project in December 2010 and commenced the service in January 2011. The rate for the transportation service on this extension
is ESNGs current tariff rate for service in that area.
Chesapeake Utilities Corporation 2010 Form 10-K Page 112
Notes to the Consolidated Financial Statements
TETLP is proceeding with obtaining the necessary approvals, authorizations or exemptions for
construction and operation of its portion of the project, including, but not limited to, approval
by the FERC. Our Delaware and Maryland divisions require no regulatory approvals or exemptions to
receive transmission service from TETLP or ESNG.
Once the ESNG and TETLP firm transportation services commence, our Delaware and Maryland divisions
will incur costs from those services based on the agreed reservation rates, which will become an
integral component of the costs associated with providing natural gas supplies to our Delaware and
Maryland divisions. The costs from the ESNG and TETLP firm transportation services will be
included in the annual GSR filings for each of our respective divisions.
Non-income-based Taxes
From time to time, we are subject to various audits and reviews by the states and other regulatory
authorities regarding non-income-based taxes. We are currently undergoing a sales tax audit in
Florida. During 2010, we recorded an accrual of $698,000 related to additional sales taxes and
gross receipts taxes owed to various states.
Other
Contingency
In 2010, we recorded a $750,000 accrual related to the
regulatory risk for FPUs natural gas distribution operation associated
with its earnings, merger benefits and recovery of its purchase
premium (See Note O, Rates and Other Regulatory
Activities, to the Consolidated Financial Statements for
further discussion).
R. Quarterly Financial Data
(Unaudited)
In our opinion, the quarterly financial information shown below includes all adjustments
necessary for a fair presentation of the operations for such periods. Due to the seasonal nature
of our 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) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenue |
|
$ |
153,260 |
|
|
$ |
80,061 |
|
|
$ |
76,466 |
|
|
$ |
117,759 |
|
Operating Income |
|
$ |
25,398 |
|
|
$ |
7,761 |
|
|
$ |
4,583 |
|
|
$ |
14,188 |
|
Net Income |
|
$ |
13,974 |
|
|
$ |
3,340 |
|
|
$ |
1,628 |
|
|
$ |
7,113 |
|
Earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
1.48 |
|
|
$ |
0.35 |
|
|
$ |
0.17 |
|
|
$ |
0.75 |
|
Diluted |
|
$ |
1.47 |
|
|
$ |
0.35 |
|
|
$ |
0.17 |
|
|
$ |
0.74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenue |
|
$ |
104,479 |
|
|
$ |
40,834 |
|
|
$ |
31,758 |
|
|
$ |
91,715 |
|
Operating Income |
|
$ |
15,966 |
|
|
$ |
2,856 |
|
|
$ |
2,257 |
|
|
$ |
12,658 |
|
Net Income |
|
$ |
8,593 |
|
|
$ |
806 |
|
|
$ |
308 |
|
|
$ |
6,191 |
|
Earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
1.26 |
|
|
$ |
0.12 |
|
|
$ |
0.04 |
|
|
$ |
0.71 |
|
Diluted |
|
$ |
1.24 |
|
|
$ |
0.12 |
|
|
$ |
0.04 |
|
|
$ |
0.71 |
|
|
|
|
(1) |
|
The quarterly results prior to the completion of the merger with FPU exclude
the result from FPU. The merger became effective on October 28, 2009. |
|
(2) |
|
The sum of the four quarters does not equal the total year due to rounding. |
Chesapeake Utilities Corporation 2010 Form 10-K Page 113
|
|
|
Item 9. |
|
Changes In and Disagreements With Accountants on Accounting and Financial
Disclosure. |
None.
|
|
|
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 Companys disclosure controls and procedures (as such
term is defined under Rule 13a-15(e) and 15d 15(e) promulgated under the Securities Exchange Act
of 1934, as amended) as of December 31, 2010. Based upon their evaluation, the Chief Executive
Officer and Chief Financial Officer concluded that the Companys disclosure controls and procedures
were effective as of December 31, 2010.
Changes in Internal Controls
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, 2010, 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 has included FPUs 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 for additional information
relating to the FPU merger.
CEO and CFO Certifications
The Companys Chief Executive Officer and Chief Financial Officer have filed with the SEC the
certifications required by Section 302 of the Sarbanes-Oxley Act of 2002 as Exhibits 31.1 and 31.2
to the Companys Annual Report on Form 10-K for the fiscal year ended December 31, 2010. In
addition, on June 3, 2010 the Companys Chief Executive Officer certified to the NYSE that he was
not aware of any violation by the Company of the NYSE corporate governance listing standards.
Managements 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 Managements Report on Internal Control over Financial Reporting.
Our independent auditors, ParenteBeard LLC, have audited and issued their report on effectiveness
of our internal control over financial reporting. That report appears on the following page.
Chesapeake
Utilities Corporation 2010 Form 10-K Page 114
Report of Independent Registered Public Accounting Firm
To the Board of Directors and
Stockholders of Chesapeake Utilities Corporation
We have audited Chesapeake Utilities Corporations (the Company) internal control over financial
reporting as of December 31, 2010, based on criteria established in Internal ControlIntegrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Chesapeake Utilities Corporations 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 Managements Report on Internal Control Over
Financial Reporting appearing under Item 8. Our responsibility is to express an opinion on the
Companys 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 companys 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 accounting principles generally accepted in the
United States of America. A companys 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 companys 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.
In our opinion, Chesapeake Utilities Corporation maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2010, based on criteria established in
Internal ControlIntegrated Framework issued 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 sheets of Chesapeake Utilities Corporation as of
December 31, 2010 and 2009, and the related consolidated statements of income, stockholders equity
and cash flows of Chesapeake Utilities Corporation, and our report dated March 8, 2011 expressed an
unqualified opinion.
|
|
|
/s/ ParenteBeard LLC
ParenteBeard LLC
|
|
|
Malvern, Pennsylvania |
|
|
March 8, 2011 |
|
|
Chesapeake
Utilities Corporation 2010 Form 10-K Page 115
|
|
|
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 Election of Directors (Proposal 1), Information Concerning Nominees
and Continuing Directors, Corporate Governance, Committees of the Board Audit Committee and
Section 16(a) Beneficial Ownership Reporting Compliance, to be filed no later than March 31,
2011, in connection with the Companys Annual Meeting to be held on or about May 4, 2011.
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 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 no later than March 31, 2011, in
connection with the Companys Annual Meeting to be held on or about May 4, 2011.
|
|
|
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 Security Ownership of Certain Beneficial Owners and Management to be
filed no later than March 31, 2011, in connection with the Companys Annual Meeting to be held on
or about May 4, 2011.
Chesapeake
Utilities Corporation 2010 Form 10-K Page 116
The following table sets forth information, as of December 31, 2010, with respect to compensation
plans of Chesapeake and its subsidiaries, under which shares of Chesapeake common stock are
authorized for issuance:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
|
(b) |
|
|
(c) |
|
|
|
|
|
|
|
|
|
|
|
Number of securities |
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
402,843 |
(1) |
|
|
|
|
|
|
|
|
|
|
Equity compensation
plans not approved by
security holders |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
|
|
|
|
402,843 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes 345,028 shares under the 2005 Performance Incentive Plan, 34,215 shares
available under the 2005 Directors Stock Compensation Plan, and 23,600 shares available
under the 2005 Employee Stock Awards Plan. |
|
|
|
Item 13. |
|
Certain Relationships and Related Transactions, and Director Independence. |
The information required by this Item is incorporated herein by reference to the portions of the
Proxy Statement captioned, Corporate Governance, to be filed no later than March 31, 2011 in
connection with the Companys Annual Meeting to be held on or about May 4, 2011.
|
|
|
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 Independent Registered Public Accounting Firm, to
be filed not later than March 31, 2011, in connection with the Companys Annual Meeting to be held
on or about May 4, 2011.
Chesapeake Utilities Corporation 2010 Form 10-K Page 117
Part IV
|
|
|
Item 15. |
|
Exhibits, Financial Statement Schedules. |
(a) |
|
The following documents are filed as part of this report: |
|
1. |
|
Financial Statements: |
|
|
|
|
Report of Independent Registered Public Accounting Firm; |
|
|
|
|
Consolidated Statements of Income for each of the three years ended December 31, 2010,
2009, and 2008; |
|
|
|
|
Consolidated Balance Sheets at December 31, 2010 and December 31, 2009; |
|
|
|
|
Consolidated Statements of Cash Flows for each of the three years ended December 31,
2010, 2009, and 2008; |
|
|
|
|
Consolidated Statements of Stockholders Equity for each of the three years ended
December 31, 2010, 2009, and 2008; and |
|
|
|
|
Notes to the Consolidated Financial Statements. |
|
|
2. |
|
Financial Statement Schedules: |
|
|
|
|
Report of Independent Registered Public Accounting Firm; |
|
|
|
|
Schedule I Parent Company Condensed Financial Statements; and |
|
|
|
|
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. |
|
|
|
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, 2006 relating to the sale and issuance of
600,300 shares of Chesapeakes common stock, is incorporated herein by reference to Exhibit 1.1 of our
Current Report on Form 8-K, filed November 16, 2006, 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
|
|
Amended and Restated Certificate of Incorporation of Chesapeake Utilities Corporation is incorporated
herein by reference to Exhibit 3.1 of our Quarterly Report on Form 10-Q for the period ended June 30, 2010,
File No. 001-11590. |
|
|
|
Exhibit 3.2
|
|
Amended and Restated Bylaws of Chesapeake Utilities Corporation, effective April 7, 2010, are incorporated
herein by reference to Exhibit 3 of the Companys Current Report on Form 8-K, filed April 13, 2010, File
No. 001-11590. |
|
|
|
Exhibit 4.1
|
|
Form of Indenture between Chesapeake and Boatmens Trust Company, Trustee, with respect to the 8 1/4%
Convertible Debentures is incorporated herein by reference to Exhibit 4.2 of our Registration Statement on
Form S-2, Reg. No. 33-26582, filed on January 13, 1989. |
|
|
|
Exhibit 4.2
|
|
Note Purchase Agreement, entered into by the Company on October 2, 1995, pursuant to which Chesapeake
privately placed $10 million of its 6.91% Senior Notes, paid off in 2010, 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. |
|
|
|
Chesapeake Utilities Corporation 2010 Form 10-K Page 118
|
|
|
|
|
|
Exhibit 4.3
|
|
Note Purchase Agreement, entered into by Chesapeake on December 15, 1997, pursuant to which Chesapeake
privately placed $10 million of its 6.85% Senior Notes due in 2012, is incorporated by reference to Exhibit
4.3 of our Annual Report on Form 10-K for the year ended December 31, 2009, File No. 001-11590. |
|
|
|
Exhibit 4.4
|
|
Note Purchase Agreement entered into by Chesapeake on December 27, 2000, pursuant to which Chesapeake
privately placed $20 million of its 7.83% Senior Notes, due in 2015, is incorporated by reference to
Exhibit 4.4 of our Annual Report on Form 10-K for the year ended December 31, 2009, File No. 001-11590. |
|
|
|
Exhibit 4.5
|
|
Note Agreement entered into by Chesapeake on October 31, 2002, pursuant to which Chesapeake privately
placed $30 million of its 6.64% Senior Notes, due in 2017, is incorporated herein by reference to Exhibit 2
of our Current Report on Form 8-K, filed November 6, 2002, File No. 001-11590. |
|
|
|
Exhibit 4.6
|
|
Note Agreement entered into by Chesapeake on October 18, 2005, pursuant to which 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 our 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 incorporated by reference to Exhibit 4.7 of
our Annual Report on Form 10-K for the year ended December 31, 2009, File No. 001-11590. |
|
|
|
Exhibit 4.8
|
|
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 Companys Registration No. 2-6087. |
|
|
|
Exhibit 4.9
|
|
Sixteenth Supplemental Indenture entered into by Chesapeake Utilities Corporation and Florida Public
Utilities Company, on December 1, 2009, pursuant to which Chesapeake Utilities Corporation, on December 1,
2009 guaranteed the secured First Mortgage Bonds of Florida Public Utilities Company under the Merger
Agreement, is filed herewith. |
|
|
|
Exhibit 4.10
|
|
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 Companys Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-10608. |
|
|
|
Exhibit 4.11
|
|
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 Companys Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-10608. |
|
|
|
Exhibit 4.12
|
|
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 Companys
Quarterly Report on Form 10-Q for the period ended June 30, 1992. |
|
|
|
Exhibit 4.13
|
|
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 Companys Quarterly Report on Form 10-Q for the period ended June 30,
1988. |
Chesapeake
Utilities Corporation 2010 Form 10-K
Page 119
|
|
|
|
|
|
Exhibit 10.1*
|
|
Chesapeake Utilities Corporation Cash Bonus Incentive Plan, dated January 1, 2005, is incorporated herein
by reference to Exhibit 10.3 of our 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 our Proxy Statement dated March 28, 2005, in connection with our 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 our Proxy Statement dated March 28, 2005, in connection with our 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 our Proxy Statement dated March 28, 2005, in connection with our Annual Meeting held on May 5,
2005, File No. 001-11590. |
|
|
|
Exhibit 10.5*
|
|
Chesapeake Utilities Corporation Deferred Compensation Plan, amended and restated as of January 1, 2009, is
incorporated herein by reference to Exhibit 10.5 of our Annual Report on Form 10-K for the year ended
December 31, 2008, File No. 001-11590. |
|
|
|
Exhibit 10.6
|
|
First Amendment to the Chesapeake Utilities Corporation Deferred Compensation Plan, dated December 28,
2010, is filed herewith. |
|
|
|
Exhibit 10.7*
|
|
Executive Employment Agreement dated December 31, 2009, by and between Chesapeake Utilities Corporation and
John R. Schimkaitis, is incorporated herein by reference to Exhibit 10.1 of our Current Report on Form 8-K,
filed January 7, 2010, File No. 001-11590. |
|
|
|
Exhibit 10.8*
|
|
Consulting Agreement dated January 3, 2011, by and between Chesapeake Utilities Corporation and John R.
Schimkaitis, is filed herewith. |
|
|
|
Exhibit 10.9*
|
|
Executive Employment Agreement dated January 14, 2011, by and between Chesapeake Utilities Corporation and
Michael P. McMasters, is incorporated herein by reference to Exhibit 10.1 of our Current Report on Form
8-K, filed January 21, 2011, 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 10.3 of our Current Report on Form 8-K,
filed January 7, 2010, File No. 001-11590. |
|
|
|
Exhibit 10.11*
|
|
Executive Employment Agreement dated December 31, 2009, by and between Chesapeake Utilities Corporation and
Beth W. Cooper, is incorporated herein by reference to Exhibit 10.4 of our Current Report on Form 8-K,
filed January 7, 2010, File No. 001-11590. |
|
|
|
Exhibit 10.12*
|
|
Executive Employment Agreement dated December 31, 2009, by and between Chesapeake Utilities Corporation and
Joseph Cummiskey, is incorporated herein by reference to Exhibit 10.5 of our Current Report on Form 8-K,
filed January 7, 2010, File No. 001-11590. |
|
|
|
Exhibit 10.13*
|
|
Executive
Employment Agreement dated March 3, 2011, by and between Chesapeake Utilities Corporation and Elaine B.
Bittner, is filed herewith. |
|
|
|
Exhibit 10.14*
|
|
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, 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. |
Chesapeake
Utilities Corporation 2010 Form 10-K
Page 120
|
|
|
|
|
|
Exhibit 10.15*
|
|
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 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 10.16*
|
|
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 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 10.17*
|
|
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 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 10.18*
|
|
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 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 10.19*
|
|
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 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 10.20*
|
|
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 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 10.21*
|
|
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 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 10.22*
|
|
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 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. |
|
|
|
Exhibit 10.23*
|
|
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 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 10.24*
|
|
Form of Performance Share Agreement effective January 7, 2009 for the period 2009 to 2011, 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 and Stephen C. Thompson, is
incorporated herein by reference to Exhibit 10.26 on Form 10-K for the year ended December 31, 2008, File
No. 001-11590. |
Chesapeake
Utilities Corporation 2010 Form 10-K
Page 121
|
|
|
|
|
|
Exhibit 10.25*
|
|
Form of Performance Share Agreement effective January 6, 2010 for the period 2010 to 2012, 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 incorporated herein by reference to Exhibit 10.24 on Form 10-K for the year ended December 31,
2009, File No. 001-11590 |
|
|
|
Exhibit 10.26*
|
|
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 incorporated herein by reference to Exhibit 10.24 on Form 10-K for the year ended December 31,
2009, File No. 001-11590. |
|
|
|
Exhibit 10.27*
|
|
Form of Performance Share Agreement effective January 14, 2011 for the period 2011 to 2013, pursuant to
Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation
and each of Michael P. McMasters, Beth W. Cooper, Stephen C. Thompson, Joseph Cummiskey, and Elaine B.
Bittner, is incorporated herein by reference to Exhibit 10.2 of our Current Report on Form 8-K, filed
January 21, 2011, File No. 001-11590. |
|
|
|
Exhibit 10.28*
|
|
Form of Performance Share Agreement effective January 14, 2011 for the period 2011 to 2012, pursuant to
Chesapeake Utilities Corporation Performance Incentive Plan by and between Chesapeake Utilities Corporation
and each of Michael P. McMasters and Elaine B. Bittner, is filed herewith. |
|
|
|
Exhibit 10.29*
|
|
Chesapeake Utilities Corporation Supplemental Executive Retirement Plan, as amended and restated effective
January 1, 2009, is incorporated herein by reference to Exhibit 10.27 of our Annual Report on Form 10-K for
the year ended December 31, 2008, File No. 001-11590. |
|
|
|
Exhibit 10.30*
|
|
First Amendment to the Chesapeake Utilities Corporation Supplemental Executive Retirement Plan as amended
and restated effective January 1, 2009, is filed herewith. |
|
|
|
Exhibit 10.31*
|
|
Chesapeake Utilities Corporation Supplemental Executive Retirement Savings Plan, as amended and restated
effective January 1, 2009, is incorporated herein by reference to Exhibit 10.28 of our Annual Report on
Form 10-K for the year ended December 31, 2008, File No. 001-11590. |
|
|
|
Exhibit 10.32*
|
|
First Amendment to the Chesapeake Utilities Corporation Supplemental Executive Retirement Savings Plan,
dated October 28, 2010, is incorporated herein by reference to Exhibit 10.1 of our Quarterly Report on Form
10-Q for the period ended September 30, 2010, File No. 001-11590. |
|
|
|
Exhibit 10.33
|
|
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 Companys
Current Report on Form 8-K, filed on November 6, 2008, File No. 001-10908. |
|
|
|
Exhibit 10.34
|
|
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 Companys Quarterly Report on Form 10-Q for the period ended June 30, 2008, File
No. 001-10608. |
|
|
|
Exhibit 10.35
|
|
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 Companys Quarterly Report on Form 10-Q for the
period ended June 30, 2008, File No. 001-10608. |
Chesapeake
Utilities Corporation 2010 Form 10-K
Page 122
|
|
|
|
|
|
Exhibit 10.36
|
|
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
Companys Quarterly Report on Form 10-Q for the period ended September 30, 2007, File No. 001-10608. |
|
|
|
Exhibit 10.37
|
|
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
Companys Quarterly Report on Form 10-Q for the period ended September 30, 2007, File No. 001-10608. |
|
|
|
Exhibit 10.38
|
|
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
Companys Quarterly Report on Form 10-Q for the period ended September 30, 2007, File No. 001-10608. |
|
|
|
Exhibit 10.39
|
|
Term Note Agreement entered into by Chesapeake Utilities Corporation on March 16, 2010, pursuant to the $29
million credit facility with PNC Bank, N.A., is incorporated herein by reference to Exhibit 10.1 of our
Quarterly Report on Form 10-Q for the period ended March 31, 2010, File No. 001-11590. |
|
|
|
Exhibit 10.40
|
|
Precedent Agreement between Chesapeake Utilities Corporation and Texas Eastern Transmission LP, dated April
8, 2010 is incorporated herein by reference to Exhibit 10.2 of our
Quarterly Report on Form 10-Q for the period ended March 31, 2010, File No. 001-11590. |
|
|
|
Exhibit 10.41
|
|
Form
of Franchise Agreement between Florida Public Utilities Company and
the city of Marianna, effective February 1, 2010, is filed herewith. |
|
|
|
Exhibit 10.42
|
|
Form
of Service Agreement for Generation Services entered into by Florida
Public Utilities Company and Gulf Power Company, dated December 28,
2006, effective January 1, 2008 is hereby incorporated by reference
as Exhibit 10(s) on Florida Public Utilities Companys Annual
Report on Form 10-K for the year ended December 31, 2006, file No.
001-10608. |
|
|
|
Exhibit 10.43
|
|
Amendment
to Form of Service Agreement for Generation Services entered into by
Florida Public Utilities Company and Gulf Power Company, effective
January 25, 2011, is filed herewith. |
|
|
|
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 31.1
|
|
Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule
13a-14(a) and 15d 14(a), dated March 8, 2011, 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 8, 2011, is filed herewith. |
|
|
|
Exhibit 32.1
|
|
Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section
1350, dated March 8, 2011, 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 8, 2011, is filed herewith. |
|
|
|
* |
|
Management contract or compensatory plan or agreement. |
Chesapeake
Utilities Corporation 2010 Form 10-K
Page 123
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/ Michael P. Mcmasters
|
|
|
|
Michael P. McMasters, |
|
|
|
President and Chief Executive Officer Date: March 8, 2011 |
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed
below by the following persons on behalf of the registrant and in the capacities and on the dates
indicated.
|
|
|
|
|
/s/ Ralph J. Adkins
Ralph J. Adkins,
|
|
/s/ Michael P. McMasters
Michael P. McMasters,
|
|
|
Chairman of the Board and Director
|
|
President, Chief Executive Officer and Director |
|
|
Date: March 2, 2011
|
|
Date: March 8, 2011 |
|
|
|
|
|
|
|
/s/ Beth W. Cooper
Beth W. Cooper, Senior Vice President
|
|
/s/ Eugene H. Bayard
Eugene H. Bayard, Director
|
|
|
and Chief Financial Officer
|
|
Date: March 2, 2011 |
|
|
(Principal Financial and Accounting Officer) |
|
|
|
|
Date: March 8, 2011 |
|
|
|
|
|
|
|
|
|
/s/ Richard Bernstein
Richard Bernstein, Director
|
|
/s/ Thomas J. Bresnan
Thomas J. Bresnan, Director
|
|
|
Date: March 2, 2011
|
|
Date: March 7, 2011 |
|
|
|
|
|
|
|
/s/ Thomas P. Hill, Jr.
Thomas P. Hill, Jr., Director
|
|
/s/ Dennis S, Hudson, III
Dennis S. Hudson, III, Director
|
|
|
Date: March 2, 2011
|
|
Date: March 2, 2011 |
|
|
|
|
|
|
|
/s/ Paul L. Maddock, Jr.
Paul L. Maddock, Jr., Director
|
|
/s/ J. Peter Martin
J. Peter Martin, Director
|
|
|
Date: March 2, 2011
|
|
Date: March 2, 2011 |
|
|
|
|
|
|
|
/s/ Joseph E. Moore, Esq
Joseph E. Moore, Esq., Director
|
|
/s/
Calvert A. Morgan, Jr
Calvert A. Morgan, Jr., Director
|
|
|
Date: March 2, 2011
|
|
Date: March 2, 2011 |
|
|
|
|
|
|
|
/s/ Dianna F. Morgan
Dianna F. Morgan, Director
|
|
/s/
John Schimkaitis
John R. Schimkaitis
|
|
|
Date: March 2, 2011
|
|
Vice Chairman of the Board and Director
Date: March 2, 2011 |
|
|
Chesapeake
Utilities Corporation 2010 Form 10-K
Page 124
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 8, 2011 relating to the consolidated financial
statements of Chesapeake Utilities Corporation as of December 31, 2010 and 2009 and for each of the
years in the three-year period ended December 31, 2010, which is contained in Item 8 of this Form
10-K also included the audits of the financial statement schedules listed in Item 15(a)2. These
financial statement schedules are the responsibility of the Chesapeake Utilities Corporations
management. Our responsibility is to express an opinion on these financial statement schedules
based on our audits.
In our opinion such financial statement schedules, when considered in relation to the basic
consolidated financial statements taken as a whole, present fairly, in all material respects, the
information set forth therein.
|
|
|
/s/ ParenteBeard LLC
ParenteBeard LLC
|
|
|
Malvern, Pennsylvania |
|
|
March 8, 2011 |
|
|
Chesapeake Utilities Corporation and Subsidiaries
Schedule I
Parent Company Condensed Financial Statements
Chesapeake Utilities Corporation (Parent)
Condensed Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
Assets |
|
2010 |
|
|
2009 |
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment |
|
$ |
202,807 |
|
|
$ |
191,440 |
|
Less: Accumulated depreciation and amortization |
|
|
(49,223 |
) |
|
|
(46,297 |
) |
Plus: Construction work in progress |
|
|
1,492 |
|
|
|
1,338 |
|
|
|
|
|
|
|
|
Net property, plant and equipment |
|
|
155,076 |
|
|
|
146,481 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments, at fair value |
|
|
2,368 |
|
|
|
1,959 |
|
Investments in subsidiaries |
|
|
179,580 |
|
|
|
160,150 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
4,229 |
|
|
|
973 |
|
Accounts receivable (less allowance for uncollectible
accounts of $432 and $458, respectively) |
|
|
11,623 |
|
|
|
9,356 |
|
Accrued revenue |
|
|
6,458 |
|
|
|
4,936 |
|
Accounts receivable from affiliates |
|
|
74,663 |
|
|
|
56,587 |
|
Propane inventory, at average cost |
|
|
635 |
|
|
|
624 |
|
Other inventory, at average cost |
|
|
970 |
|
|
|
971 |
|
Regulatory assets |
|
|
51 |
|
|
|
1,205 |
|
Storage gas prepayments |
|
|
5,084 |
|
|
|
6,144 |
|
Income taxes receivable |
|
|
4,003 |
|
|
|
822 |
|
Deferred income taxes |
|
|
369 |
|
|
|
1,909 |
|
Prepaid expenses |
|
|
2,310 |
|
|
|
3,047 |
|
Other current assets |
|
|
176 |
|
|
|
79 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
110,571 |
|
|
|
86,653 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Charges and Other Assets |
|
|
|
|
|
|
|
|
Long-term receivables |
|
|
133 |
|
|
|
331 |
|
Regulatory assets |
|
|
2,820 |
|
|
|
3,610 |
|
Other deferred charges |
|
|
603 |
|
|
|
479 |
|
|
|
|
|
|
|
|
Total deferred charges and other assets |
|
|
3,556 |
|
|
|
4,420 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
451,151 |
|
|
$ |
399,663 |
|
|
|
|
|
|
|
|
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 |
|
2010 |
|
|
2009 |
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalization |
|
|
|
|
|
|
|
|
Stockholders equity |
|
|
|
|
|
|
|
|
Common stock, par value $0.4867 per share
(authorized 25,000,000 and 12,000,000 shares, respectively) |
|
$ |
4,635 |
|
|
$ |
4,572 |
|
Additional paid-in capital |
|
|
148,159 |
|
|
|
144,502 |
|
Retained earnings |
|
|
76,805 |
|
|
|
63,231 |
|
Accumulated other comprehensive loss |
|
|
(3,134 |
) |
|
|
(2,865 |
) |
Deferred compensation obligation |
|
|
777 |
|
|
|
739 |
|
Treasury stock |
|
|
(777 |
) |
|
|
(739 |
) |
|
|
|
|
|
|
|
Total stockholders equity |
|
|
226,465 |
|
|
|
209,440 |
|
|
Long-term debt, net of current maturities |
|
|
71,682 |
|
|
|
79,611 |
|
|
|
|
|
|
|
|
Total capitalization |
|
|
298,147 |
|
|
|
289,051 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
Current portion of long-term debt |
|
|
7,727 |
|
|
|
6,636 |
|
Short-term borrowing |
|
|
63,958 |
|
|
|
30,023 |
|
Accounts payable |
|
|
10,401 |
|
|
|
9,157 |
|
Customer deposits and refunds |
|
|
7,619 |
|
|
|
4,410 |
|
Accrued interest |
|
|
1,015 |
|
|
|
1,003 |
|
Dividends payable |
|
|
3,143 |
|
|
|
2,959 |
|
Accrued compensation |
|
|
3,377 |
|
|
|
2,450 |
|
Regulatory liabilities |
|
|
2,432 |
|
|
|
5,934 |
|
Other accrued liabilities |
|
|
2,635 |
|
|
|
1,647 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
102,307 |
|
|
|
64,219 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Credits and Other Liabilities |
|
|
|
|
|
|
|
|
Deferred income taxes |
|
|
20,999 |
|
|
|
16,494 |
|
Deferred investment tax credits |
|
|
122 |
|
|
|
157 |
|
Regulatory liabilities |
|
|
709 |
|
|
|
695 |
|
Environmental liabilities |
|
|
358 |
|
|
|
531 |
|
Other pension and benefit costs |
|
|
5,045 |
|
|
|
5,674 |
|
Accrued asset removal cost Regulatory liability |
|
|
18,805 |
|
|
|
18,248 |
|
Other liabilities |
|
|
4,659 |
|
|
|
4,594 |
|
|
|
|
|
|
|
|
Total deferred credits and other liabilities |
|
|
50,697 |
|
|
|
46,393 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other commitments and contingencies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization and Liabilities |
|
$ |
451,151 |
|
|
$ |
399,663 |
|
|
|
|
|
|
|
|
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, |
|
2010 |
|
|
2009 |
|
|
2008 |
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
|
$ |
95,764 |
|
|
$ |
101,577 |
|
|
$ |
103,733 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
52,295 |
|
|
|
62,339 |
|
|
|
65,446 |
|
Operations |
|
|
19,919 |
|
|
|
18,487 |
|
|
|
16,039 |
|
Transaction-related costs |
|
|
660 |
|
|
|
1,478 |
|
|
|
1,153 |
|
Maintenance |
|
|
1,165 |
|
|
|
1,535 |
|
|
|
1,303 |
|
Depreciation and amortization |
|
|
4,365 |
|
|
|
4,194 |
|
|
|
3,918 |
|
Other taxes |
|
|
3,788 |
|
|
|
3,564 |
|
|
|
3,380 |
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses |
|
|
82,192 |
|
|
|
91,597 |
|
|
|
91,239 |
|
|
|
|
|
|
|
|
|
|
|
Operating Income |
|
|
13,572 |
|
|
|
9,980 |
|
|
|
12,494 |
|
Income from equity investments |
|
|
19,430 |
|
|
|
12,042 |
|
|
|
7,781 |
|
Other loss, net of other expenses |
|
|
(30 |
) |
|
|
(30 |
) |
|
|
(106 |
) |
Interest charges |
|
|
2,837 |
|
|
|
3,066 |
|
|
|
3,026 |
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Taxes |
|
|
30,135 |
|
|
|
18,926 |
|
|
|
17,143 |
|
Income taxes |
|
|
4,079 |
|
|
|
3,029 |
|
|
|
3,536 |
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
$ |
26,056 |
|
|
$ |
15,897 |
|
|
$ |
13,607 |
|
|
|
|
|
|
|
|
|
|
|
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 Statement of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31, |
|
2010 |
|
|
2009 |
|
|
2008 |
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
$ |
26,056 |
|
|
$ |
15,897 |
|
|
$ |
13,607 |
|
Adjustments to reconcile net income to net operating cash: |
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings in subsidiaries |
|
|
(19,382 |
) |
|
|
(12,042 |
) |
|
|
(7,781 |
) |
Depreciation and amortization |
|
|
4,366 |
|
|
|
4,190 |
|
|
|
3,918 |
|
Depreciation and accretion included in other costs |
|
|
1,878 |
|
|
|
1,773 |
|
|
|
1,389 |
|
Deferred income taxes, net |
|
|
6,901 |
|
|
|
2,821 |
|
|
|
5,147 |
|
Unrealized (gain) loss on investments |
|
|
(113 |
) |
|
|
(212 |
) |
|
|
509 |
|
Employee benefits and compensation |
|
|
(169 |
) |
|
|
1,217 |
|
|
|
152 |
|
Share based compensation |
|
|
1,155 |
|
|
|
1,306 |
|
|
|
820 |
|
Other, net |
|
|
(46 |
) |
|
|
8 |
|
|
|
11 |
|
Changes in assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of investments |
|
|
(297 |
) |
|
|
(146 |
) |
|
|
(201 |
) |
Accounts receivable and accrued revenue |
|
|
(3,814 |
) |
|
|
(16,770 |
) |
|
|
(3,016 |
) |
Propane inventory, storage gas and other inventory |
|
|
1,050 |
|
|
|
3,383 |
|
|
|
(3,854 |
) |
Regulatory assets |
|
|
1,716 |
|
|
|
(1,825 |
) |
|
|
606 |
|
Prepaid expenses and other current assets |
|
|
653 |
|
|
|
(1,050 |
) |
|
|
(516 |
) |
Other deferred charges |
|
|
(180 |
) |
|
|
(72 |
) |
|
|
(8 |
) |
Long-term receivables |
|
|
198 |
|
|
|
181 |
|
|
|
199 |
|
Accounts payable and other accrued liabilities |
|
|
1,636 |
|
|
|
9,832 |
|
|
|
3,323 |
|
Income taxes receivable |
|
|
(3,858 |
) |
|
|
2,791 |
|
|
|
(3,113 |
) |
Accrued interest |
|
|
12 |
|
|
|
(20 |
) |
|
|
158 |
|
Customer deposits and refunds |
|
|
3,208 |
|
|
|
(1,147 |
) |
|
|
34 |
|
Accrued compensation |
|
|
823 |
|
|
|
352 |
|
|
|
377 |
|
Regulatory liabilities |
|
|
(3,488 |
) |
|
|
3,603 |
|
|
|
(2,379 |
) |
Other liabilities |
|
|
64 |
|
|
|
886 |
|
|
|
(23 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
18,369 |
|
|
|
14,956 |
|
|
|
9,359 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment expenditures |
|
|
(13,969 |
) |
|
|
(12,615 |
) |
|
|
(16,328 |
) |
Proceeds from investments |
|
|
|
|
|
|
1,000 |
|
|
|
500 |
|
Cash acquired in the merger, net of cash paid |
|
|
|
|
|
|
(16 |
) |
|
|
|
|
Environmental expenditures |
|
|
54 |
|
|
|
(86 |
) |
|
|
(480 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(13,915 |
) |
|
|
(11,717 |
) |
|
|
(16,308 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Change in receivable/payable with affiliates |
|
|
(18,051 |
) |
|
|
13,379 |
|
|
|
4,302 |
|
Common stock dividends |
|
|
(11,013 |
) |
|
|
(7,957 |
) |
|
|
(7,810 |
) |
Issuance of stock for Dividend Reinvestment Plan |
|
|
568 |
|
|
|
392 |
|
|
|
(118 |
) |
Change in cash overdrafts due to outstanding checks |
|
|
3,256 |
|
|
|
835 |
|
|
|
(684 |
) |
Net borrowing (repayment) under line of credit agreements |
|
|
1,579 |
|
|
|
(3,812 |
) |
|
|
(11,980 |
) |
Other short-term borrowing |
|
|
29,100 |
|
|
|
|
|
|
|
|
|
Proceeds from issuance of long-term debt |
|
|
|
|
|
|
|
|
|
|
29,961 |
|
Repayment of long-term debt |
|
|
(6,637 |
) |
|
|
(6,637 |
) |
|
|
(7,637 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
(1,198 |
) |
|
|
(3,800 |
) |
|
|
6,034 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Cash Equivalents |
|
|
3,256 |
|
|
|
(561 |
) |
|
|
(915 |
) |
Cash and Cash Equivalents Beginning of Period |
|
|
973 |
|
|
|
1,534 |
|
|
|
2,449 |
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents End of Period |
|
$ |
4,229 |
|
|
$ |
973 |
|
|
$ |
1,534 |
|
|
|
|
|
|
|
|
|
|
|
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 Chesapeakes 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 Chesapeakes material contingencies and guarantees, see Item 8 under the
heading Notes to the Consolidated Financial Statements Note P, Environmental Commitments and
Contingencies and Note Q, Other Commitments and Contingencies.
Chesapeakes 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) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
$ |
1,609 |
|
|
$ |
1,129 |
|
|
$ |
181 |
|
|
$ |
(1,725 |
) |
|
$ |
1,194 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
$ |
1,159 |
|
|
$ |
1,138 |
|
|
$ |
616 |
|
|
$ |
(1,304 |
) |
|
$ |
1,609 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
$ |
952 |
|
|
$ |
1,186 |
|
|
$ |
241 |
|
|
$ |
(1,220 |
) |
|
$ |
1,159 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Recoveries. |
|
(2) |
|
Uncollectible accounts charged off. |
Exhibit 4.9
Exhibit 4.9
FLORIDA PUBLIC UTILITIES COMPANY,
a subsidiary by merger of
CHESAPEAKE UTILITIES CORPORATION
To
U.S. BANK,
CORPORATE TRUST SERVICES,
Trustee
SIXTEENTH SUPPLEMENTAL INDENTURE
Dated as of December 1, 2009
Supplementing and Modifying The
Indenture of Mortgage and Deed of Trust
Dated as of September 1, 1942
This is a Security Agreement covering Personal Property as
well as a Mortgage upon Real Estate and Other Property
This is a Security Agreement covering Personal Property as
well as a Mortgage upon Real Estate and Other Property
SIXTEENTH SUPPLEMENTAL INDENTURE
This Sixteenth Supplemental Indenture, dated for convenience as of December 1, 2009, between
CHESAPEAKE UTILITIES CORPORATION (Chesapeake), as Debtor, a Delaware corporation whose mailing
address is: 909 Silver Lake Boulevard, Dover, DE 19904, FLORIDA PUBLIC UTILITIES COMPANY (Florida
Public Utilities), as Primary Debtor, a Florida corporation whose mailing address is: 410 South
Dixie Highway, West Palm Beach, FL 33401, and U.S. BANK NATIONAL ASSOCIATION (Trustee), a national
banking association whose mailing address is: 225 Water Street, Suite 700, Mail Code EX-FL-WWSJ,
Jacksonville, FL 32202.
WHEREAS, on October 28, 2009, Chesapeake completed an Agreement and Plan of Merger, dated
April 17, 2009 (Merger Agreement) with Florida Public Utilities;
WHEREAS, the Merger was duly noticed and approved by the Board of Directors and the
Stockholders of both Chesapeake and Florida Public Utilities;
WHEREAS, Section 1.4 of the Merger Agreement provides that the merger shall have the effects
specified in the Merger Agreement and the Florida Business Corporations Act, Chapter 607, Florida
Statutes;
WHEREAS, Section 607.1106(1)(c), Florida Statues, provides that Chesapeake, as the parent
company, is responsible for the Indenture liabilities and obligations of Florida Public Utilities
(as Indenture is defined below);
WHEREAS, pursuant to the Merger Agreement, Florida Public Utilities survived the merger as a
wholly owned subsidiary of Chesapeake;
WHEREAS, Florida Public Utilities has heretofore executed and delivered to the Trustee an
Indenture of Mortgage and Deed of Trust dated as of September 1, 1942 (Original Indenture), to
secure, as provided therein, its bonds (in the Original Indenture and herein called the Bonds),
to be designated generally as its First Mortgage Bonds, and to be issued in one or more series as
provided in the Original Indenture; and
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WHEREAS, Florida Public Utilities has heretofore executed and delivered to the Trustee
fifteen indentures supplemental to the Original Indenture as follows: the First
Supplemental Indenture dated as of December 1, 1945 (First Supplemental Indenture), the Second
Supplemental Indenture dated as of March 1, 1948 (Second Supplemental Indenture), the Third
Supplemental Indenture dated as of August 1, 1954 (Third Supplemental Indenture), the Fourth
Supplemental Indenture dated as of August 1, 1956 (Fourth Supplemental Indenture), the Fifth
Supplemental Indenture dated as of September, 1958 (Fifth Supplemental Indenture), the Sixth
Supplemental Indenture dated as of July 1, 1959 (Sixth Supplemental Indenture), the Seventh
Supplemental Indenture dated as of June 1, 1963 (Seventh Supplemental Indenture), the Eighth
Supplemental Indenture dated as of June 1, 1965 (Eighth Supplemental Indenture), the Ninth
Supplemental Indenture dated as of July 1, 1972 (Ninth Supplemental Indenture), the Tenth
Supplemental Indenture dated as of July 1, 1975 (Tenth Supplemental Indenture), the Eleventh
Supplemental Indenture dated as of June 1, 1983 (Eleventh Supplemental Indenture), the Twelfth
Supplemental Indenture dated as of May 1, 1988, (Twelfth Supplemental Indenture), the Thirteenth
Supplemental Indenture dated as of June 1, 1992 (Thirteenth Supplemental Indenture) and the
Fourteenth Supplemental Indenture dated as of September 1, 2001 (Fourteenth Supplemental Indenture)
each of which supplemental indentures provided for the creation of a new series of First Mortgage
Bonds and said First, Second, Sixth, Twelfth, Thirteenth and Fourteenth Supplemental Indentures
modified certain provisions of the Original Indenture and the First Supplemental Indenture; and the
Fifteenth Supplemental Indenture dated as of November 1, 2001, (Fifteenth Supplemental Indenture)
which provided for the issuance of 4.9% First Mortgage Bonds (collectively, the Indenture);
NOW THEREFORE, it is the purpose of this Sixteenth Supplemental Indenture (Sixteenth
Supplemental Indenture) to have Chesapeake acknowledge and confirm its acceptance of the
responsibilities and obligations of Florida Public Utilities under the Merger Agreement and
created by the Original Indenture, as supplemented and modified since first issued.
1. Article 10, Section 10.01 of the Original Indenture provides:
§10.01 Nothing in this Indenture or any of the Bonds contained shall prevent any
merger or consolidation of any other corporation or corporations into or with the
Company, or any merger or consolidation of the Company (either singly or with one
or more other corporations) into or with, or any sale, conveyance, transfer or
lease, subject to the lien of this Indenture and to all the provisions hereof, of
all the mortgage property as, or substantially as, an entirety to, any corporation
lawfully entitled to acquire or lease and operate the same, or prevent successive
similar consolidations, mergers, sales, conveyances, transfers, or
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leases to which
the Company or its successor or assign or any subsequent successor or assign shall be a party; provided, however, and the Company covenants and agrees
that, such consolidation, merger, sale, conveyance, transfer or lease shall be upon
such terms as in no respect to impair the lien and security of this Indenture or any
of the rights or powers of the Trustees or of the bondholders hereunder; and
provided, further, that any such lease shall contain a provision that, if any
default described in §9.01 shall exist when such lease is made, or shall occur which
it is in effect, such lease may be terminated, at any time while such default
exists, by the Trustees or by the purchaser of the property so leased at any sale
hereunder, whether such sale be made under the power of sale hereby conferred or
under judicial proceedings; and provided, further, that in case the Company shall be
merged or consolidated as aforesaid (either singly or with one or more other
corporations) into or with any other corporation, or shall sell, convey or transfer
as aforesaid to another corporation all the mortgaged property as, or substantially
as, an entirety (but not in case of any lease and not in case any other corporation
or corporations shall be merged or consolidated into or with the Company under such
circumstances that the corporate identity of the Company is not changed) the
corporation resulting from such merger or consolidation or into or with which the
Company shall have been merged or consolidated or which shall have received a
conveyance or transfer as aforesaid (such corporation being sometimes in this
Article 10 called the successor corporation) shall, prior to or contemporaneously
with such merger, consolidation, conveyance or transfer, execute, and promptly cause
to be recorded, a supplemental indenture to and with the Trustees, satisfactory to
the Trustees, whereby the successor corporation shall assume and agree to pay duly
and punctually the principal of and interest on the Bonds issued hereunder in
accordance with the provisions of said Bonds and any coupons thereto appertaining
and this Indenture, and shall agree to perform and fulfill all the terms, covenants
and conditions of this Indenture binding the Company.
2. Chesapeake acknowledges and expressly states that nothing in the Merger Agreement shall be
deemed in any manner to impair the lien and security of the Indenture, or any of the rights or
powers of the holders of the Bonds previously issued under the Indenture;
3. Although Florida Public Utilities remains the Primary Debtor as to the obligations created
under the Indenture, in the event Florida Public Utilities is not able to fulfill Indenture
obligations, Chesapeake agrees to assume the due and punctual payment of the principal of, premium,
if any, and interest on, any and all of the Bonds, issued pursuant to the Indenture, and the
performance of every covenant of the Indenture.
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4. This Sixteenth Supplemental Indenture shall be deemed a contract made under the laws of the
state of Florida, and shall be governed and construed in accordance with the laws of Florida.
IN WITNESS WHEREOF, Chesapeake Utilities Corporation and Florida Public Utilities Company has
caused this Sixteenth Supplemental Indenture to be signed in the corporate names and on behalf of
its President or one of its Vice Presidents, and the corporate seals to be affixed and attested by
its Secretary or one of its Assistant Secretaries; and U.S. Bank National Association, in token of
its acceptance of the trust hereby created, has caused this Sixteenth Supplemental Indenture to be
signed in its name and on its behalf by its President or one of its Vice Presidents, and attested
by one of its Trust Officers, in token of its acceptance of the trust; all as of the day and year
first above written.
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CHESAPEAKE
UTILITIES CORPORATION |
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FLORIDA PUBLIC
UTILITIES COMPANY |
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By:
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/s/ Beth Cooper
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By:
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/s/ George Bachman |
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Beth Cooper
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George Bachman
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Chief Financial Officer
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Chief Financial Officer |
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U.S. BANK NATIONAL |
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ASSOCIATION, Trustee |
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By:
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/s/ Stephanie Moore |
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Stephanie Moore
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Vice President |
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STATE OF FLORIDA
COUNTY OF Palm Beach
The foregoing instrument was acknowledged before me this 30 day of December, 2009, by George
Bachman, who is personally Known to me or who has produced ______ as identification and who took an oath.
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Typed or Printed Name: Dina Bellechases
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Dina Bellechases
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My Commission Expires: December 13, 2011
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NOTARY PUBLIC
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STATE OF FLORIDA
COUNTY OF [ILLEGIBLE]
The foregoing instrument was acknowledged before me this 7th day of January, 2009,
by Stephanie Moore, who is personally known to me or who has produced as identification and
who took an oath.
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Typed or Printed Name:
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SARAH BANKER
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My Commission Expires:
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NOTARY PUBLIC
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STATE OF FLORIDA
COUNTY OF
The foregoing instrument was acknowledged before me this day of ,
2009, by , who is personally known to me or who has
produced as identification and who took an oath.
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Typed or Printed Name: |
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My Commission Expires:
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NOTARY PUBLIC
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Exhibit 10.6
Exhibit 10.6
First Amendment to the
CHESAPEAKE UTILITIES CORPORATION
DEFERRED COMPENSATION PLAN
As Amended and Restated as of January 1, 2009
First Amendment to the Chesapeake Utilities Corporation Deferred Compensation Plan
Background Information
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The Plan was amended and restated effective as of January 1, 2009, to comply with the
requirements of Section 409A of the Internal Revenue Code of 1986, as amended (the Code).
From and after January 1, 2005 through December 31, 2008, the Plan was subject to and operated
in accordance with a good faith interpretation of Code Section 409A, including the use of any
applicable transition rules in effect during such period. |
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The Internal Revenue Service, in Notice 2010-6, provided guidance regarding document drafting
failures and ambiguities that may be corrected or clarified without adverse tax implications. |
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Chesapeake Utilities Corporation, as the Plans sponsor, desires to make certain clarifying
amendments to the Plan to ensure its interpretation and operation continue in accordance with
the requirements of Code Section 409A, as permitted by Section IV of Notice 2010-6. |
Amendment
Chesapeake Utilities Corporation hereby amends the Plan as set forth below, effective as of
January 1, 2009:
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Subsection (a) of Section 3.03 of the Plan, Form and Time of Payment, is hereby revised to
read as follows in order to reflect within the Plan document the administrative practice set
forth in Plan election forms of offering Participants the option of electing that payment be
made in a single lump sum or in annual installments over a period of either five or ten years: |
General. Except as provided in Sections 5.03, 5.04, 5.05 and 5.06, an amount
deferred under this Section 3 shall be paid, or commence to be paid, in a lump sum or in
annual installments over a period of five or ten years as of the Valuation Date coincident
with or next following Separation from Service or the date elected by the Participant. A
Participant may elect a different form or time of payment for his deferrals for each Plan
Year, but may not divide his deferrals for a single Plan Year among different forms or times
of payment. If, however, a Participant who is an Eligible Employee elects to receive
payment upon Separation from Service, no amount shall be distributed earlier than six months
after the Valuation Date coincident with or next following the Participants Separation from
Service. Such six month delay shall not apply to a distribution made to a Participant who
is a Director. A Participant may elect to receive his distribution as of the earlier or
later of two dates (including Separation from Service), to the extent permitted by Code
Section 409A. In the event a Participant fails to make a payment election, the default form
of payment shall be a lump sum and the default time
of payment shall be six months after the Valuation Date coincident with or next following
the Participants Separation from Service. Elections regarding the time and form of payment
must be made by or before the election filing deadlines under Section 3.02.
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Subsection (c) of Section 5.02 of the Plan, Installment Payments, is hereby revised to read
as follows in order to reflect the fact that Participants make separate payment elections for
each years deferrals, if any, and that only a portion of any Plan subaccount may be payable
in accordance with an installment payment election: |
Installment Payments. If the Participant receives installment payments, the amount
of the first installment shall be equal to the value of the portion of the Participants
Deferred Cash Subaccount payable in installments, plus the value of the portion of the
Participants DSU Subaccount (determined in accordance with Section 4.05(b)) payable in
installments, determined as of the Valuation Date as of which the installment payments
commence (the applicable Valuation Date) pursuant to Section 5.02(a), divided by five (if
five installments are elected) or ten (if ten installments are elected). The amount of each
succeeding installment shall be equal to the value of the portion of the Participants
Deferred Cash Subaccount payable in installments and the value of the portion of the
Participants DSU Subaccount (determined in accordance with Section 4.05(b)) payable in
installments on the next succeeding anniversary of the applicable Valuation Date, divided by
the remaining number of installments to be paid. The payment medium of each installment
payment shall be determined in accordance with Section 5.02(b).
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Subsection (b) of Section 5.03 of the Plan, Time of Payment, is hereby revised to read as
follows in order to reflect the fact that payment must be made no more than 90 days after the
date of death: |
Time of Payment. A distribution pursuant to this Section 5.03 shall be paid to the
Participants Beneficiary within 30 days after the Valuation Date that is coincident with or
next follows the date of the Participants death, together with any additional information
or documentation that the Committee determines to be necessary or appropriate before it
makes the distribution. Notwithstanding the foregoing, in no event will payment be made
more than 90 days after the date of the Participants death.
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Section 5.05 of the Plan, Disability, is hereby revised to read as follows in order to
reflect the fact that payment must be made no more than 90 days after the date a Disability
occurs: |
Disability. Notwithstanding any election made pursuant to Sections 3.02 and 3.03,
upon the Participants becoming Disabled, the Participant shall be eligible to receive
payment of the amounts credited to his Account commencing as soon as practicable but no more
than 90 days after the Committee has determined the Participant is Disabled. Benefits
payable in accordance with this provision shall be payable in a lump sum to the Participant
equal to the remaining balance of the Participants Account.
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Section 8.01 of the Plan, By the Compensation Committee, is hereby amended by the addition
of the following sentence at the end thereof: The suspension or termination of the Plan
shall not accelerate the obligation to make payments to any person not otherwise currently
entitled to payments under the Plan, unless specifically determined by the Compensation
Committee and permitted by applicable law, including but not limited to Code Section 409A. |
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Section 9.04 of the Plan, Required Information, is hereby amended by the addition of the
following sentence at the end thereof: Notwithstanding the foregoing, the failure to provide
any requested information or proof shall not delay any payment under the Plan, unless
specifically permitted by applicable law, including but not limited to Code Section 409A. |
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CHESAPEAKE UTILITIES CORPORATION
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By: |
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Its: |
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Date: |
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Exhibit 10.8
Exhibit 10.8
CONSULTING AGREEMENT
This Consulting Agreement (this Agreement) is made and entered into as of January 3, 2011,
by and between Chesapeake Utilities Corporation, a Delaware corporation (the Company), and John
R. Schimkaitis (the Executive).
Background Information:
A. Executive is retiring as Chief Executive Officer the Company, but is willing to continue to
provide select services to the Company.
B. The Company desires to obtain for itself the benefit of the Executives services as set
forth in this Agreement.
C. The Company and the Executive desire to set forth in a written agreement the terms and
conditions under which the Executive will render consulting services to the Company after the
termination of his employment.
NOW, THEREFORE, the parties hereto, intending to be legally bound, agree as follows:
1. Effective Date.
This Agreement shall only become effective at the time that the Executive retires from his
position with the Company and his existing employment agreement terminates. Executive acknowledges
that, other than compensation and benefits that have accrued prior to the Executives retirement,
he shall not be entitled to any further compensation, severance or benefits of any kind under the
employment agreement upon the Executives retirement. Notwithstanding the foregoing, the covenants
of Section 9, the indemnification provisions of Section 10 and the arbitration provisions of
Section 14 of the employment agreement shall continue in force and shall survive the termination of
the employment agreement. Further, the date of termination of employment shall be determined as
the first date that the Executive has a separation from service as defined in Treasury
Regulations issued under Section 409A of the Internal Revenue Code of 1986, as amended (Section
409A). It is specifically intended hereunder that the amount of consulting services required by
the Executive under this Agreement be limited in amount such that the termination of the employment
agreement shall constitute a separation from service within the meaning of Section 409A.
2. Consulting Services.
(a) For the period commencing upon the Executives retirement from employment and continuing
for up to 12 months (the Consulting Term), the Company shall engage the Executive as a
consultant, and the Executive shall provide consulting services in accordance with the terms set
forth herein. The Executive shall be available to work for the Company as a consultant for up to
400 hours per year at mutually agreeable times and shall perform such consulting services as shall
be reasonably requested from time to time by the Board of Directors of the Company or its lawfully
designated representative (the Board). The
Company, in its sole discretion shall determine the number of days per month that the
Executive shall provide consulting services. However, the parties agree that the time commitment
from the Executive shall not exceed 20% of the average time devoted to the Executives position as
President and CEO of the Company during the 36 month period prior to the Executives retirement in
order to ensure that the Executives retirement does constitute a separation from service as an
employee under Section 409A. The Company shall provide the Executive with office space at the
Companys principal executive offices for purposes of performing the consulting services, as
necessary. The parties acknowledge and agree that the Executive may perform services for other
entities and that this engagement of Executive is on a non-exclusive basis, subject, however, to
the Executives continuing obligation to comply with the covenants of Section 3, below.
(b) During the Consulting Term, the Company shall (a) pay the Executive a consulting fee of
$10,000.00 per month for each month during the Consulting Term, or portion thereof, that the
Executive provides consulting services, payable at the end of each calendar month, and (b)
reimburse the Executive for all reasonable out of pocket expenses he incurs in connection with
providing the consulting services, provided that such reimbursement payments are made by the end of
the Executives taxable year following the year in which such expenses are incurred and that the
Company shall not be obligated to pay any such reimbursement amount for which Executive fails to
submit an invoice or other documented reimbursement request at least 10 business days before the
end of such calendar year. Such expenses shall be reimbursable only to the extent they were
incurred during the term of this Agreement. In addition, the amount of such reimbursements that
the Company is obligated to pay in any given calendar year shall not affect the amount the Company
is obligated to pay in any other calendar year. In addition, Executive may not liquidate or
exchange the right to reimbursement of such expenses for any other benefits. The Executive shall
not be entitled to the payment of any consulting fee for any month during the Consulting Term for
which no services are provided, nor to any payments or benefits other than those provided under
this Agreement for the consulting services provided hereunder.
(c) With the Executives consent, the Company may extend the Consulting Term for additional
one year consulting assignments. The terms of any extended consulting period shall be the same as
provided herein unless otherwise agreed by the parties in writing.
(d) Notwithstanding anything herein to the contrary, the Consulting Term shall end and this
Agreement shall terminate upon the death or total disability of the Executive, as determined by the
Company in its reasonable discretion.
3. Confidential Information; Non-Solicitation; Noncompetition.
The Executive agrees that the covenants of Section 9 of his employment agreement with the
Company shall continue in effect and shall apply to his performance of services hereunder.
Further, Executive agrees that the Restricted Period as defined therein shall also continue until
one year after the termination of this Agreement.
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4. Independent Contractor.
From and after the Effective Date, the Executive agrees that he shall be an independent
contractor of the Company, not an employee, and that he has no authority to represent himself as an
agent or employee or to assume or create any obligation or responsibility on behalf of or in the
name of the Company, unless specifically authorized by the Company in writing. Executive will bear
sole responsibility to pay any taxes on his compensation and acknowledges that he will receive a
Form 1099 from the Company after the end of each calendar year. Executive also agrees that he
shall not knowingly take any action which would impair the value of the business or assets of the
Company or any affiliated companies, including, without limiting the generality of the foregoing,
interfere with contractual relationships of the Company or any affiliated companies with customers,
suppliers, executives or others, any action which disparages or diminishes the reputation of the
Company or any affiliated companies, or any action which diverts customers of the Company or any
affiliated companies.
5. Injunctive Relief.
The Executive acknowledges and agrees that the Companys remedy at law for any breach of the
Executives obligations under Section 3 or 4 would be inadequate and incomplete and agrees and
consents that temporary and permanent injunctive relief may be granted in any proceeding which may
be brought to enforce any provision of such Sections without the necessity of proof of actual
damage and without any requirement for the posting of any bond.
6. Termination for Cause.
Notwithstanding anything herein to the contrary, this Agreement shall terminate and no payment
of any fee hereunder shall be made to or on behalf of the Executive if the Executive has engaged in
any willful misconduct with respect to his obligations hereunder or is involved in conduct which
violates (excluding immaterial violations of) the Companys Standards of Business Conduct.
7. Assignment.
This Agreement is personal to the Executive, and the Executive may not assign any interest
herein in any manner whatsoever. Any purported assignment by the Executive shall be void. In
addition to assignments by operation of law, the Company shall have the right to assign this
Agreement to any person, firm or corporation, controlling, controlled by or under common control
with the Company (including, without limitation, any of its affiliated companies), or acquiring
substantially all of its assets, but such assignment shall not release the Company from its
obligations under this Agreement. The covenants and agreements of the Executive contained in
Sections 3 and 4 shall survive and remain in full force and effect beyond the term of this
Agreement.
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8. Applicable Law.
This Agreement shall be governed by, and construed in accordance with, the laws of the State
of Delaware, without reference to principles of conflict of laws. The exclusive venue for all
actions involving the enforcement and/or interpretation of this Agreement shall be Dover, Delaware.
Should any action, of any type, be necessary to enforce and/or interpret the terms of this
Agreement, the prevailing party shall be entitled to an award of its/his reasonable attorneys fees
and costs, at all levels including appeals.
9. Notices.
All notices, requests, consents and other communications required or provided under this
Agreement shall be in writing and shall be deemed sufficient if delivered by hand, by facsimile,
nationally recognized overnight courier, or certified or registered mail, return receipt requested,
postage prepaid, and shall be effective upon delivery as follows:
If to the Executive:
Mr. John R. Schimkaitis
4744 Pinnacle Drive
Bradenton, FL 34208
If to the Company:
Chesapeake Utilities Corporation
909 Silver Lake Blvd.
Dover, DE 19904
Attn: President and CEO
Facsimile: (302) 734-6750
Either party may change the address and/or facsimile number to which notices are to be sent to
that party by giving written notice of such change of address to the other party in the same manner
above provided for giving notice.
10. Enforceability.
Any provision of this Agreement finally determined by a court of competent jurisdiction to be
prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective, but
only to the extent of such prohibition or unenforceability, without invalidating the other
provisions hereof or without affecting the validity or unenforceability of such provision in any
other jurisdiction. Moreover, the Executive and the Company hereby agree that such court shall
have jurisdiction to reform this Agreement or any provision hereof so that it is enforceable to the
maximum extent permitted by law, and the parties agree to abide by such courts determination.
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11. Entire Agreement.
This Agreement constitutes the entire agreement of the parties relative to the subject matter
contained herein, superseding, canceling and replacing all prior agreements, with respect thereto.
No promises, covenants or representations of any character or nature other than those expressly
stated herein have been made to induce either party to enter into this Agreement. This Agreement
shall not be amended, modified, waived or discharged except in writing duly signed by each of the
parties or their authorized assignees.
12. Waiver.
The Executives or the Companys failure to insist upon strict compliance with any provision
of, or to assert any right under, this Agreement shall not be deemed to be a waiver of such
provision or right or of any other provision of or right under this Agreement except to the extent
any other party hereto is materially prejudiced by such failure.
13. Headings.
Headings used in this Agreement are provided for convenience only and shall not be used to
construe meaning or intent.
14. Section 409A Compliance.
It is the intention of both the Company and Executive that the benefits and rights to which
Executive could be entitled pursuant to this Agreement be exempt from or, to the extent that the
requirements of Code Section 409A are applicable thereto, comply with Code Section 409A, and the
provisions of this Agreement shall be construed in a manner consistent with that intention. If
Executive or the Company believes, at any time, that any such benefit or right that is subject to
Code Section 409A does not so comply, it shall promptly advise the other and shall negotiate
reasonably and in good faith to amend the terms of such benefits and rights such that they comply
with Section 409A (with the most limited possible economic effect on Executive and on the Company).
IN WITNESS WHEREOF, the Executive has hereunto set his hand and the Company have caused this
Agreement to be executed in their name and on their behalf, all as of the day and year first above
written.
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Executive |
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Chesapeake Utilities Corporation |
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By: |
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Michael P. McMasters
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Its: President and CEO |
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5
Exhibit 10.13
Exhibit 10.13
EXECUTIVE EMPLOYMENT AGREEMENT
This Executive Employment Agreement (the Agreement) dated this 3rd day of March, 2011, is
hereby made by and between Chesapeake Utilities Corporation, a Delaware corporation (the
Company), and Elaine B. Bittner (the Executive).
Recitals
WHEREAS, the Company is currently obtaining the benefit of Executives services as a full-time
executive employee in the capacity of Vice President Strategic Development of the Company;
WHEREAS, the Companys Board of Directors (the Board) has authorized the Company to provide
for the Executives continued employment pursuant to the terms of this Agreement; and
WHEREAS, Executive is willing, in consideration of the covenants and consideration hereinafter
provided, to continue to be employed by the Company in the capacity of Vice President Strategic
Development and to render services incident to such position during the term of this Agreement.
Agreement
In consideration of the mutual promises and covenants contained herein, the Company and
Executive hereby agree as follows:
1. Employment. The Company agrees to employ Executive, and Executive agrees to accept
employment, as an executive officer of the Company in the capacity of Vice President Strategic
Development, with such authority, duties and responsibilities as are customarily assigned to such
position, including such reasonable duties and responsibilities as may be requested of the
Executive by the Board of Directors and which are consistent with the By-laws of the Company as in
effect from time to time including, but not limited to, oversight and coordination of strategic
planning and corporate development, new business opportunities, strategic governmental affairs,
communications and human resources.
2. Term.
(a) Term of Agreement. The term of this Agreement (Term) shall be the Current Term
(as defined in Paragraph 2(b)), and, if applicable, the Extended Term (as defined in Paragraph
2(c)).
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(b) Current Term. Subject to Paragraph 2(c), the Current Term of this Agreement shall
extend for one (1) year commencing on January
, 2011. The Current Term is subject to extension
in accordance with the provisions of Paragraph 15 of this Agreement.
(c) Extended Term. Upon the occurrence of a Change in Control (as defined in
Paragraph 2(d)), the Current Term shall end and the Term of this Agreement shall thereupon
automatically be extended, commencing on the date of such Change in Control, for the shorter of
three (3) years or the period until Executive attains the earliest age, if any, at which her
compulsory retirement is permitted under Section 12(c) of the Age Discrimination in Employment Act
of 1967, as amended, 29 U.S.C. § 631(c), or any successor provision thereto (such extended
three-year or shorter term constituting the Extended Term).
(d) Change In Control. For the purposes of this Agreement, Change in Control shall
mean a change in the control of the Company during the Term of this Agreement, which shall be
deemed to have occurred upon the first of the following events:
(i) any one person, or group of owners of another corporation who acting
together through a merger, consolidation, purchase, acquisition of stock or the like
(a Group), acquires ownership of stock of the Company (or a majority-controlled
subsidiary of the Company) that, together with the stock held by such person or
Group, constitutes more than fifty percent (50%) of the total fair market value or
total voting power of the stock of the Company. However, if such person or Group is
considered to own more than fifty percent (50%) of the total fair market value or
total voting power of the stock of the corporation before this transfer of the
Companys stock, the acquisition of additional stock by the same person or Group
shall not be considered to cause a Change in Control of the Company; or
(ii) any one person or Group acquires (or has acquired during the twelve (12)
month period ending on the date of the most recent acquisition by such person or
persons) ownership of stock of the Company (or a majority-controlled subsidiary of
the Company) possessing thirty-five percent (35%) or more of the total voting power
of the stock of the Company where such person or Group is not merely acquiring
additional control of the Company; or
(iii) a majority of members of the Companys Board (other than the Board of a
majority-controlled subsidiary of the Company) is replaced during any twelve (12)
month period by directors whose appointment or election is not endorsed by a
majority of the members of the Companys Board prior to the date of the appointment
or election; or
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(iv) any one person or Group acquires (or has acquired during the twelve
(12) month period ending on the date of the most recent acquisition by such
person or Group) assets from the Company (or a majority-controlled subsidiary of the
Company) that have a total gross fair market value equal to or more than forty
percent (40%) of the total fair market value of all assets of the Company
immediately prior to such acquisition or acquisitions. For this purpose, gross fair
market value means the value of the assets of the Company, or the value of the
assets being disposed of, determined without regard to any liabilities associated
with such assets. A transfer of assets by the Company will not result in a Change
in Control if the assets are transferred to:
(A) a stockholder of the Company (immediately before the asset transfer) in
exchange for or with respect to its stock;
(B) an entity, fifty percent (50%) or more of the total value or voting power
of which is owned, directly or indirectly, by the Company immediately after the
transfer of assets;
(C) a person or Group that owns, directly or indirectly, fifty percent (50%) or
more of the total value or voting power of all the outstanding stock of the Company;
or
(D) an entity, at least fifty percent (50%) of the total value or voting power
of which is owned directly or indirectly, by a person described in subparagraph
(d)(i), above.
However, no Change in Control shall be deemed to have occurred with respect to the Executive by
reason of (1) any event involving a transaction in which the Executive or a group of persons or
entities with which the Executive acts in concert, acquires, directly or indirectly, more than
thirty percent (30%) of the Common Stock of the business or assets of the Company; (2) any event
involving or arising out of a proceeding under Title 11 of the United States Code (or the
provisions of any future United States bankruptcy law), or an assignment for the benefit of
creditors or an insolvency proceeding under state or local law; or (3) any event constituting
approval by the Companys stockholders of a merger or consolidation if a majority of the group
consisting of the president and vice-presidents of the Company who are parties to agreements
conferring rights upon a Change in Control shall have agreed in writing prior to the approval that
the approval shall not be deemed to constitute a Change in Control.
3. Time. Executive agrees to devote all reasonable full time and best efforts for the
benefit of the Company and any subsidiary of the Company, and not to serve any other business
enterprise or organization in any capacity during the Term of this Agreement without the prior
written consent of the Company, which consent shall not be unreasonably withheld.
4. Office.
(a) Current Term. During the Current Term, the Executive shall serve as the Vice
President Strategic Development of the Company and the parties agree that the Company shall
elect the Executive to this office, on an annual basis if necessary, during the Current Term of
this Agreement.
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(b) Extended Term. During the Extended Term of this Agreement the Executive shall
hold and perform an office with the responsibility, importance and scope within the Company at
least equal to that of the office described and contemplated in Paragraph 1. Further, Executives
office shall be located in Dover, Delaware, and Executive shall not be required, without her
written consent, to change her office location or to be absent therefrom on business for more than
sixty (60) working days in any year.
5. Compensation and Benefits.
(a) Base Compensation; Current Term. The Company shall compensate Executive for her
services hereunder during the Current Term at a rate of $185,000 per annum, or such amount as the
Board may from time to time determine (Base Compensation), payable in installments on the
Companys regular payroll dates for salaried executives. The Base Compensation rate shall be
reviewed annually and may be increased or decreased, from time to time, provided, however, that
Base Compensation shall only be decreased by the Board on a good faith basis and with reasonable
justification for the same, and provided further, that in the event of a Change in Control, Base
Compensation shall not be decreased.
(b) Base Compensation; Extended Term. During the Extended Term, the Company shall
compensate Executive for her services hereunder at a rate per annum, payable in installments on the
Companys regular payroll dates for salaried executives, equal to her Base Compensation at the time
the Extended Term commences, increased, but not decreased:
(i) effective on each anniversary of the date of this Agreement during the
Extended Term by an amount equal to the product of such Base Compensation times the
increase in the preceding calendar year of the Consumer Price Index for Urban Wage
Earners and Clerical Workers for the Philadelphia metropolitan region as reported by
the U.S. Department of Labor (or, if such index is no longer reported, the
corresponding increase in a comparable index); and
(ii) by such additional amounts as the Board may determine from time to time
based, in part, on an annual review of the Executives compensation and performance.
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(c) Incentive Plans. During the Term of this Agreement, Executive shall be entitled
to participate in all bonus, incentive compensation and performance based compensation plans, and
other similar policies, practices, programs and arrangements of the Company, now in effect or
as hereafter amended or established, on a basis that is commensurate with her position and no less
favorable than those generally applicable or made available to other executives of the Company.
The Executives participation shall be in accordance with the terms and provisions of such plans
and programs. Participation shall include, but not be limited to:
(i) Chesapeake Utilities Corporation Performance Incentive Plan.
Executive shall be eligible for an incentive compensation award equal to 3,200
shares of the Companys common stock as granted on an annual basis by the Board
during the Term of this Agreement.
(ii) Chesapeake Utilities Corporation Cash Bonus Incentive Plan.
Executive shall be eligible for a minimum cash bonus award equal to 25 percent (25%)
of Base Compensation as determined on an annual basis by the Board during the Term
of this Agreement.
(d) Retirement Plans. During the Term of this Agreement, Executive shall be entitled
to participate in all profit-sharing, savings and retirement benefit plans, plans that are
supplemental to any tax-qualified savings and retirement plans, and other similar policies,
practices, programs and arrangements of the Company, now in effect or as hereafter amended or
established, on a basis that is commensurate with her position and no less favorable than those
generally applicable or made available to other executives of the Company. The Executives
participation shall be in accordance with the terms and provisions of such plans and programs.
(e) Welfare Benefits. During the Term of this Agreement, Executive, and her family,
as applicable, shall be entitled to participate in all insurance, medical, health and welfare, and
similar plans and arrangements, as well as all vacation and other employee fringe benefit plans,
perquisite plans, and other policies, practices, programs and arrangements of the Company, now in
effect or as hereafter amended or established, on a basis that is commensurate with her position
and no less favorable than those generally applicable or made available to other executives of the
Company. The Executives participation shall be in accordance with the terms and provisions of
such plans.
(f) Other Benefits. During the Term of this Agreement, the Company shall furnish
Executive with a suitable office, necessary administrative support and customary furniture and
furnishings for such office. The Company further agrees that Executive shall have the use of a
Company-owned or Company-leased and Company-maintained automobile, new every three (3) years, of a
kind and model appropriate to her position with the Company.
(g) Expenses. During the Term of this Agreement, the Company shall pay all necessary
and reasonable business expenses incurred by Executive on behalf of the Company in the course of
her employment hereunder, including, without limitation, expenses incurred in the conduct
of the Companys business while away from her domicile and properly substantiated expenses for
travel, meals, lodging, entertainment and related expenses that are for the benefit of the Company.
All expense reimbursements shall comply with applicable rules or guidelines of the Company in
effect at the time the expense is incurred.
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(h) Nothing in this Agreement shall preclude the Company from amending or terminating any
employee benefit plan or practice, but, it being the intent of the parties that the Executive shall
continue to be entitled during the Extended Term to benefits and perquisites as set forth in
Paragraphs 5(a) through 5(g) at least equal to those attached to her position on the date of this
Agreement, nothing in this Agreement shall operate as, or be construed to authorize, a reduction
during the Extended Term without Executives written consent in the level of such benefits or
perquisites as in effect on the date of a Change in Control. If and to the extent that such
benefits or perquisites are not payable or provided to Executive under any such plan or practice by
reason of an amendment thereto or termination thereof during the Extended Term, the Company shall
nevertheless pay or provide such benefits or perquisites to Executive, either directly or through
alternative arrangements.
6. Termination.
(a) Payment Upon Termination During Current Term. In the event that the Company
terminates this Agreement during the Current Term, or elects pursuant to Paragraph 15 not to renew
this Agreement at the end of the Current Term for any reason other than Cause, as defined below, or
the Executives death, the Company shall continue to pay to Executive (or in the event of her death
following such termination, her legal representative) her Base Compensation under Paragraph 5(a),
at the rate in effect immediately prior to the date of such termination (Termination Date), for a
period of one (1) year following the Termination Date. In addition, and notwithstanding the
foregoing provisions of this Paragraph 6(a), to the extent required in order to comply with Section
409A of the Internal Revenue Code of 1986, as amended (the Code), cash amounts that would
otherwise be payable under this Paragraph 6(a) during the six-month period immediately following
the Termination Date shall instead be paid, with interest on any delayed payment at the applicable
federal rate under Code Section 7872(f)(2)(A), on the first business day after the date that is six
(6) months following the Executives separation from service within the meaning of Code Section
409A.
(b) Termination for Cause. This Agreement and Executives employment hereunder may be
terminated by the Company at any time for Cause. In the event of termination for Cause, the
Executive shall not be entitled to any severance benefits under this Agreement. Termination of the
Executives employment shall be deemed to have been for Cause only if it shall have been the
result of:
(i) Executives conviction of a felony under the laws of the United States or a
state in which Executive works or resides;
(ii) a willful or deliberate act or acts of dishonesty by Executive resulting
or intended to result directly or indirectly in material gain to or personal
enrichment of Executive at the Companys expense;
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(iii) a deliberate and intentional refusal by Executive (except by reason of
incapacity due to illness or accident) to comply with the provisions of Paragraph 1,
provided that such breach shall have resulted in demonstrably material injury to the
Company and the Executive shall have failed to remedy such breach within thirty (30)
days after notice from the Secretary of the Company demanding that the Executive
remedy such breach; or
(iv) conduct by Executive that is materially injurious to the Company if such
conduct was undertaken without good faith and the reasonable belief that such
conduct was in the best interest of the Company.
(c) Payment Upon Termination During Extended Term. In the event of a Termination
Without Cause, as defined below, during the Extended Term, the Company shall pay to Executive (or,
in the event of her death following the termination, her legal representative) in cash, within
thirty (30) days after the date of such termination (the Extended Termination Date) the sum of
all accrued but unpaid salary, bonus, vacation pay, expense reimbursements and any other amounts
due, plus the following:
(i) an amount equal to the product of multiplying the monthly rate of Base
Compensation to which Executive was entitled under Paragraph 5(a) on the day
immediately prior to the Extended Termination Date by twenty-four (24) months
(Covered Period);
(ii) an amount equal to the present value of the additional benefits that would
have been paid Executive under the Companys retirement plans (including, but not
limited to, the Chesapeake Utilities Corporation Pension Plan and any related excess
benefit plans) if she had continued to be employed pursuant to this Agreement during
the Covered Period and the retirement plans had continued during such period without
change from the date of the Change in Control;
(iii) an amount equal to the aggregate of the Companys contributions to the
Companys savings plan (including, but not limited to, the Chesapeake Utilities
Corporation Retirement Savings Plan, and any related excess benefit plans) in
respect of Executive that were not vested on the day immediately prior to the
Extended Termination Date but that would have been vested at the end of the Covered
Period if Executive had remained employed by the Company for the duration of that
period; and
(iv) an amount equal to the product of multiplying the average of the annual
aggregate benefits awarded to the Executive under all bonus, incentive
compensation or performance based compensation program(s) of the Company in which
the Executive was a participant, whether annual, short or long term, in each of the
three (3) calendar years immediately preceding the calendar year in which the
Extended Termination Date occurs by two (2) years.
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For purposes of calculating the present value specified in Paragraph 6(c)(ii), the discount rate
shall equal the PBGC interest rate for immediate annuities, as provided in 29 C.F.R. Part 4044,
Appendix B, Table II or its successor, in effect for a valuation date coinciding with the Extended
Termination Date. If that rate should no longer be published, the discount rate shall be such
closely comparable interest rate as the Company may reasonably determine. In addition, the Company
shall continue to provide medical, prescription drug, vision, dental and other Company welfare
benefits to the Executive and her eligible dependents during the Covered Period as if the Executive
remained an active employee of the Company.
(d) Termination Without Cause. For purposes of Paragraph 6(c) above, Termination
Without Cause shall mean:
(i) Termination by the Company of Executives employment without Cause (as
Cause is defined in Paragraph 6(b) above); or
(ii) Termination by Executive of her employment following the occurrence of any
of the following events:
(A) failure to elect or re-elect Executive to, or removal of Executive
from, the office or offices set forth in Paragraph 1, or the Board if
Executive shall have been a member of the Board immediately prior to a Change
in Control of the Company;
(B) Executives good-faith determination that there has been a
significant change in the nature or scope of her authorities, powers,
functions, duties or responsibilities attached to the positions contemplated
in Paragraph 1 or a reduction in her compensation or in the benefits
available to the Executive and her family, as provided in Paragraph 5, which
change or reduction is not remedied within thirty (30) days after notice to
the Company by the Executive;
(C) any other breach by the Company of any provision of this Agreement
(including, without limitation, relocation of the Executive in violation of
Paragraph 4(b)), which breach is not remedied within thirty (30) days after
notice to the Company by Executive; or
(D) the liquidation, dissolution, consolidation or merger of the
Company or transfer of all or a significant portion of its assets unless
a successor or successors (by merger, consolidation or otherwise) to which
all or a significant portion of its assets has been transferred shall have
assumed all duties and obligations of the Company under this Agreement.
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In order to effect a Termination Without Cause in any event set forth in this
Paragraph 6(d)(ii), Executive must elect to terminate her employment under this
Agreement upon not less than forty (40) days and not more than ninety (90) days
written notice to the Board, attention of the Corporate Secretary, given, except in
the case of a continuing breach, within three (3) calendar months after; (1) failure
to be so elected or reelected, or such removal, (2) expiration of the 30-day cure
period with respect to such event, or (3) the closing date of such liquidation,
dissolution, consolidation, merger or transfer of assets.
An election by Executive to terminate her employment under the provisions of this
Paragraph shall not be deemed a voluntary termination of employment by Executive for
the purpose of this Agreement or any plan or practice of the Company. Further, the
death of the Executive during the Extended Term but prior to a Termination Without
Cause, as defined, shall not constitute Cause or be deemed to be a Termination
Without Cause.
7. Maximum Payment Upon Termination.
(a) Determination. Notwithstanding any other provision of this Agreement, if any
payment or distribution (a Payment) by the Company or any other person or entity to or for the
benefit of the Executive is determined to be an excess parachute payment (within the meaning of
Code Section 280G(b)(1) or any successor provision of similar effect), whether paid or payable or
distributed or distributable pursuant to Paragraph 6(c) of this Agreement or otherwise, then the
Executives benefits under this Agreement shall be reduced by the amount necessary so that the
Executives total parachute payment as defined in Code Section 280G(b)(2)(A) under this and all
other agreements will be $1.00 less than the amount that would be a parachute payment. The
determination concerning the application of the reduction shall be made by a nationally-recognized
firm of independent accountants (together with legal counsel of its choosing) selected by the
Company after consultation with the Executive (which may be the Companys independent auditors),
whose determination shall be conclusive and binding on all parties. Any fees and expenses of such
independent accountants and counsel (including counsel for the Executive) shall be borne by the
Company.
(b) Notices. If it is determined that the benefits under this Agreement must be
reduced under this Paragraph, within 10 days of the date of such determination, the Company will
apprise the Executive of the amount of the reduction (Notice of Reduction). Within 10 days of
receiving that information, the Executive may specify how (and against which benefit or payment
source) the reduction is to be applied (Notice of Application). The Company will be
required to implement these directions within 10 days of receiving the Notice of Application. If
the Company has not received a Notice of Application from the Executive within 10 days of the date
of the Notice of Reduction, the Company will apply this Paragraph proportionately based on the
amounts otherwise payable under Paragraph 6(c). If the Company receives a Notice of Application
that does not fully implement the requirements of this Paragraph, the Company will apply this
Paragraph proportionately on the basis of the reductions specified in the Notice of Application
first, then to any remaining reduction based on the amounts otherwise payable under Paragraph 6(c).
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8. Mitigation. Executive shall not be required to mitigate the amount of any payment
provided for in this Agreement either by seeking other employment or otherwise. The amount of any
payment provided for herein shall not be reduced by any remuneration that Executive may earn from
employment with another employer or otherwise following her Termination Date or Extended
Termination Date, as applicable.
9. Covenants.
(a) Introduction. The parties acknowledge that the provisions and covenants contained
in this Paragraph 9 are ancillary and material to this Agreement and that the limitations contained
herein are reasonable in geographic and temporal scope and do not impose a greater restriction or
restraint than is necessary to protect the goodwill and other legitimate business interests of the
Company. The parties also acknowledge and agree that the provisions of this Paragraph 9 do not
adversely affect Executives ability to earn a living in any capacity that does not violate the
covenants contained herein. The parties further acknowledge and agree that the provisions of
Paragraph 19 below are accurate and necessary because (i) Delaware is the headquarters state of the
Company, which has operations in multiple states and a compelling interest in having its employees
treated uniformly, (ii) the use of Delaware law provides certainty to the parties in any covenant
litigation in the United States, and (iii) enforcement of the provisions of this Paragraph 9 would
not violate any fundamental public policy of Delaware or any other jurisdiction.
(b) Confidential Information. Executive shall hold in a fiduciary capacity for the
benefit of the Company, all secret or confidential information, knowledge or data relating to the
Company and its businesses (including, but not limited to, any proprietary and not publicly
available information concerning any processes, methods, trade secrets, costs, names of users or
purchasers of the Companys products or services, business methods, financial affairs, operating
procedures or programs or methods of promotion and sale) that Executive has obtained or obtains
during Executives employment by the Company and that is not public knowledge (other than as a
result of Executives violation of this Paragraph 9(b)) (Confidential Information). For purposes
of this Paragraph 9(b), information shall not be deemed to be publicly available merely because it
is embraced by general disclosures or because individual features or combinations thereof are
publicly available. Executive shall not communicate, divulge or disseminate Confidential
Information at any time during or after Executives employment with the Company except:
(i) to employees or agents of the Company that need the Confidential
Information to perform their duties on behalf of the Company;
(ii) in the performance of Executives duties to the Company;
(iii) as a necessary (and only to the extent necessary) part of any undertaking
by Executive to enforce Executives rights under this Agreement; or
(iv) as otherwise required by law or legal process.
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All confidential records, files, memoranda, reports, customer lists, drawings, plans, documents and
the like that Executive uses, prepares or comes into contact with during the course of Executives
employment shall remain the sole property of the Company and shall be turned over to the Company
upon termination of Executives employment.
(c) Non-solicitation of Company Employees. Executive shall not, at any time during
the Restricted Period (as defined below), without the prior written consent of the Company, engage
in the following conduct (a Solicitation):
(i) directly or indirectly, contact, solicit, recruit or employ (whether as an
employee, officer, director, agent, consultant or independent contractor) any person
who was or is at any time during the previous six months an employee,
representative, officer or director of the Company; or
(ii) take any action to encourage or induce any employee, representative,
officer or director of the Company to cease his or her relationship with the Company
for any reason. A Solicitation does not include any recruitment of employees for
the Company.
The Restricted Period means the period including Executives employment with the Company and one
(1) year following the Termination Date or Extended Termination Date, as applicable, and, if the
Executive has given a notice pursuant to Paragraph 6(d)(ii), for a period of fifteen (15) months
following the giving of such notice.
(d) Non-solicitation of Third Parties. During the Restricted Period, the Executive
shall not (either directly or indirectly or as an officer, agent, employee, partner or director of
any other company or entity) solicit, service, recruit, induce, influence, or accept on behalf of
any competitor of the Company the business of:
(i) any customer of the Company at the time of Executives employment or
Termination Date or Extended Termination Date, as applicable; or
(ii) any potential customer of the Company which Executive knew to be an
identified, prospective purchaser of services or products of the Company.
(e) Non-competition. During the Restricted Period, Executive shall not, directly or
indirectly, accept employment with, act as a consultant to, or otherwise perform services that are
substantially the same or similar to those for which Executive was compensated by the Company (such
comparison to be based on job-related functions and responsibilities and not job title) for any
business that directly competes with any portion of the Company. This restriction applies to any
parent, division, affiliate, newly formed or purchased business(es) and/or successor of a business
that competes with the Company. Further, during the Restricted Period, Executive shall not assist
any individual or entity other than the Company in acquiring any entity with respect to which a
proposal to acquire such entity was presented to the Board during the one (1) year period beginning
prior to Executives Termination Date, Extended Termination Date or notice given by Executive
pursuant to Paragraph 6(d)(ii), as applicable.
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(f) Post-Termination Cooperation. Executive agrees that during and after employment
with the Company and without additional compensation (other than reimbursement for reasonable
associated expenses) to cooperate with the Company in the following areas:
(i) Cooperation with the Company. Executive agrees to:
(A) be reasonably available to answer questions for the Companys
officers regarding any matter, project, initiative or effort for which
Executive was responsible while employed by the Company; and
(B) cooperate with the Company during the course of all third-party
proceedings arising out of the Companys business about which Executive has
knowledge or information.
For purposes of this Agreement, proceeding includes internal investigations,
administrative investigations or proceedings and lawsuits (including pre-trial
discovery and trial testimony) and cooperation includes (1) Executive being
reasonably available for interviews, meetings, depositions, hearings and/or trials
without the need for a subpoena or assurances by the Company, (2) providing any and
all documents in Executives possession that relate to the proceeding, and (3)
providing assistance in locating any and all relevant notes and/or documents.
(ii) Cooperation with Third Parties. Unless compelled to do so by
lawfully-served subpoena or court order, Executive agrees not to communicate with,
or give statements or testimony to, any attorney representing an interest opposed to
the Companys interest (Opposing Attorney), Opposing Attorneys representative
(including a private investigator) or current or former employee relating to any
matter (including pending or threatened lawsuits or administrative investigations)
about which Executive has knowledge or information as a result of employment with
the Company. Executive also agrees to notify the Company immediately after being
contacted by a third party or receiving a subpoena or court order to appear and
testify with respect to any matter that may include a claim opposed to the Companys
interest. However, this Paragraph 9(f)(ii) shall not apply to any effort undertaken
by Executive to enforce Executives rights under this Agreement, but only to the
extent necessary for that purpose.
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(iii) Cooperation with the Media. Executive agrees not to communicate
with, or give statements to, any member of the media (including print, television,
electronic or radio media) relating to any matter (including pending or threatened
lawsuits or administrative investigations) about which Executive has knowledge or
information as a result of employment with the Company. Executive also agrees to
notify the Company immediately after being contacted by any member of the media with
respect to any matter affected by this Paragraph.
(g) Non-Disparagement. Executive and Company shall at all times refrain from taking
actions or making statements, written or verbal, that:
(i) denigrate, disparage or defame the goodwill or reputation of Executive or
the Company, as the case may be, or any of its trustees, officers, security holders,
partners, agents or former or current employees and directors, or
(ii) are intended to, or may be reasonably expected to, adversely affect the
morale of the employees of the Company.
Executive further agrees not to make any negative statements to third parties relating to
Executives employment or any aspect of the business of the Company and not to make any statements
to third parties about the circumstances of the termination of Executives employment, or about the
Company or its trustees, directors, officers, security holders, partners, agents or former or
current employees and directors, except as may be required by a court or governmental body.
(h) Enforcement. The Executive acknowledges and agrees that: (i) the purpose of the
foregoing covenants, including, without limitation, the nonsolicitation and noncompetition
covenants of Paragraphs 9(d) and (e), is to protect the goodwill, trade secrets and other
Confidential Information of the Company; (ii) because of the nature of the business in which the
Company is engaged and because of the nature of the Confidential Information to which the Executive
has access, the Company would suffer irreparable harm and it would be impractical and excessively
difficult to determine the actual damages of the Company in the event the Executive breached any of
the covenants of this Paragraph 9; and (iii) remedies at law (such as monetary damages) for any
breach of
the Executives obligations under this Paragraph 9 would be inadequate. The Executive therefore
agrees and consents that if the Executive commits any breach of a covenant under this Paragraph 9,
or threatens to commit any such breach, the Company shall have the right (in addition to, and not
in lieu of, any other right or remedy that may be available to it) to temporary and permanent
injunctive relief from a court of competent jurisdiction, without posting any bond or other
security and without the necessity of proof of actual damage, and that the arbitration provisions
of Paragraph 14 shall not apply.
10. Indemnification. The Company shall indemnify Executive to the fullest extent
permitted by applicable Delaware law (as may be amended from time to time), including the advance
of expenses permitted herein.
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11. Performance. The failure of either party to this Agreement to insist upon strict
performance of any provision of this Agreement shall not constitute a waiver of its rights
subsequently to insist upon strict performance of such provision or any other provision of this
Agreement.
12. Non-Assignability. Neither party shall have the right to assign this Agreement or
any rights or obligations hereunder without the consent of the other party.
13. Invalidity. If any provisions of this Agreement shall be found to be invalid by
any court of competent jurisdiction, such finding shall not affect the remaining provisions of this
Agreement, all of which shall remain in full force and effect.
14. Arbitration and Legal Fees. In the event of any dispute regarding a refusal or
failure by the Company to make payments or provide benefits hereunder for any reason, Executive
shall have the right, in addition to all other rights and remedies provided by law, to arbitration
of such dispute under the rules of the American Arbitration Association, which right shall be
invoked by serving upon the Company a notice to arbitrate, stating the place of arbitration, within
ninety (90) days of receipt of notice in any form (including, without limitation, failure by the
Company to respond to a notice from Executive within thirty (30) days) that the Company is
withholding or proposes to withhold any payments or the provision of any benefits the Executive, in
good faith, believes are called for hereunder. In the event of any such dispute, whether or not
Executive exercises her right to arbitration, if it shall ultimately be determined that the
Companys refusal or failure to make payments or provide benefits hereunder was wrongful or
otherwise inconsistent with the terms of this Agreement, the Company shall indemnify and hold
harmless Executive from and against any and all expenses incurred in connection with such
determination, including reasonable legal and other fees and expenses. Without limitation of or by
the foregoing, the Company shall, within ten (10) days after notice from Executive, provide
Executive with an irrevocable letter of credit in the amount of $100,000 from a bank satisfactory
to Executive against which Executive may draw to pay legal fees and other fees and expenses in
connection with any attempt by Executive to enforce any of her rights under this Agreement during
the Extended Term. Said letter of credit shall not expire before ten (10) years following the date
of this Agreement.
15. Renewal. If the Current Term of this Agreement expires without there having been
a Change in Control, this Agreement shall be renewed for successive one-year terms, as of the day
following such expiration, unless, during the period beginning ninety (90) days prior and ending
thirty (30) days prior to such day, either the Company or Executive shall have given notice to the
other that this Agreement will not be renewed. If this Agreement is renewed as provided under this
Paragraph, the new Agreement shall be identical to this Agreement (except insofar as the Company
and Executive may otherwise agree in writing) except that the date of the new Agreement shall be as
of the day following the expiration of the Current Term of this Agreement or any subsequent
one-year term.
Initials
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16. Successors. This Agreement shall be binding upon and inure to the benefit of the
Executive (and her personal representative), the Company and any successor organization or
organizations that shall succeed to substantially all of the business and property of the Company
and assume the Companys obligations hereunder, whether by means of merger, consolidation,
acquisition of substantially all of the assets of the Company, or operation of law. The Company
shall require any successor organization or organizations to agree to assume the obligations of
this Agreement.
17. Set-off. The Company shall have no right of set-off or counterclaim in respect of
any claim, debt or obligation against any payments or benefits provided for in this Agreement.
18. Amendments. No Amendment to this Agreement shall be effective unless in writing
and signed by both the Company and Executive. Notwithstanding the foregoing, if any compensation
or benefits provided by this Agreement may result in the application of Code Section 409A, the
Company shall, in consultation with the Executive, modify the Agreement in the least restrictive
manner necessary in order to exclude such compensation from the definition of deferred
compensation within the meaning of Code Section 409A or in order to comply with the provisions of
Code Section 409A, other applicable provisions of the Code and/or any rules, regulations or other
regulatory guidance issued under such statutory provisions, and without any diminution in the value
of the payments to the Executive.
19. Governing Law. This Agreement shall be interpreted and enforced in accordance
with the laws of the State of Delaware. The parties hereto irrevocably agree to submit to the
jurisdiction and venue of the courts of the State of Delaware in any action or proceeding brought
with respect to or in connection with this Agreement except for an action described in Paragraph
14.
20. Code Section 409A. If any compensation or benefits provided by this Agreement may
result in the application of Section 409A of the Code, the Company shall, in consultation with the
Executive, modify the Agreement in the least restrictive manner necessary in order to exclude such
compensation from the definition of deferred compensation within the meaning of Code Section 409A
or in order to comply with the provisions of Section 409A, other applicable provisions of the Code,
and any rules, regulations or other regulatory guidance issued under such statutory provisions and
without any diminution in the value of the payments due to the
Executive.
21. Notices. Unless otherwise stated herein, all notices hereunder shall be in
writing and shall be deemed to be given when personally delivered or mailed by United States
registered or certified mail, postage prepaid, to, if to the Company, 909 Silver Lake Boulevard,
Dover, Delaware 19904, and, if to Executive, the last address therefor shown on the records of the
Company. Either the Company or Executive may, by notice to the other, designate an address other
than the foregoing for the receipt of subsequent notices.
22. Withholding. The Company may withhold from any amounts payable to Executive
hereunder all federal, state, city or other taxes that the Company may reasonably determine are
required to be withheld pursuant to any applicable law or regulation.
Initials
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23. Nature of Payments Upon Termination. All payments to Executive pursuant to
Paragraph 6 of this Agreement shall be considered as liquidated damages or, in the case of certain
payments pursuant to Paragraph 6(c), as severance payments in consideration of Executives past
services to the Company, and no such payment shall be regarded as a penalty to the Company.
24. Prior Agreement. The parties acknowledge and agree that the terms of this
Agreement constitute the entire agreement of the parties with respect to the subject matter and
supersede all prior agreements with respect thereto, including, without limitation, any prior oral
arrangements.
25. Acknowledgment. The parties hereto each acknowledge that each has read this
Agreement and understands the same and that each enters into this Agreement freely and voluntarily.
IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first above
written.
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CHESAPEAKE UTILITIES CORPORATION |
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[CORPORATE SEAL]
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Secretary |
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Initials
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Exhibit 10.28
Exhibit 10.28
PERFORMANCE SHARE AGREEMENT
pursuant to the
CHESAPEAKE UTILITIES CORPORATION
PERFORMANCE INCENTIVE PLAN
On , 20 , (the Grant Date), Chesapeake Utilities Corporation, a Delaware corporation
(the Company), has granted to (the Grantee), who resides at , a
Performance Share Award on the terms and subject to the conditions of this Performance Share
Agreement.
Recitals
WHEREAS, the Chesapeake Utilities Corporation Performance Incentive Plan (the Plan) has been duly
adopted by action of the Companys Board of Directors (the Board) on February 24, 2005, and
approved by the Shareholders of the Company at a meeting held on May 5, 2005; and
WHEREAS, the Plan is effective January 1, 2006; and
WHEREAS, the Committee of the Board of Directors of the Company referred to in the Plan (the
Committee) has determined that it is in the best interests of the Company to grant the
Performance Share Award described herein pursuant to the Plan; and
WHEREAS, the shares of the Common Stock of the Company (Shares) that are subject to this
Agreement, when added to the other shares of Common Stock that are subject to awards granted under
the Plan, do not exceed the total number of shares of Common Stock with respect to which awards are
authorized to be granted under the Plan.
Agreement
It is hereby covenanted and agreed by and between the Company and the Grantee as follows:
Section 1. Performance Share Award and Performance Period
The Company hereby grants to the Grantee a Performance Share Award as of the Grant Date. As more
fully described herein, the Grantee may earn up to Shares upon the Companys achievement of
the performance criteria set forth in Section 2 (the Performance Shares) over the performance
period from January 1, to December 31, (the Performance Period). This Award has been
granted pursuant to the Plan; capitalized terms used in this agreement which are not specifically
defined herein shall have the meanings ascribed to such terms in the Plan.
Section 2. Performance Criteria and Terms of Share Award
(a) The Committee selected and established in writing performance criteria for the Performance
Period, which, if met, may entitle the Grantee to some or all of the Performance Shares under this
Award. If this Award is intended by the Committee to comply with the
exception from Code Section 162(m) for qualified performance-based compensation for Grantees
who are Covered Employees as defined in Code Section 162(m), the performance criteria established
shall be based on one or more Performance Goals selected by the Committee in writing within 90 days
following the first day of the Performance Period (or, if earlier, before 25% of that period has
elapsed), and at a time when the outcome relative to the attainment of the performance criteria is
not substantially certain. As soon as practicable after the Companys independent auditors have
certified the Companys financial statements for each fiscal year of the Company in the Performance
Period, the Committee shall determine for purposes of this Agreement the Companys (1) total
shareholder return, defined as the cumulative total return to shareholders (Shareholder Value),
(2) growth in long-term earnings, defined as the growth in total capital expenditures as a
percentage of total capitalization (Growth) and (3) earnings performance, defined as average
return on equity (RoE), in accordance with procedures established by the Committee. The
Shareholder Value, Growth and RoE (each a Performance Metric and collectively, the Performance
Metrics) shall be determined by the Committee in accordance with the terms of the Plan and this
Agreement based on financial results reported to shareholders in the Companys annual reports and
shall be subject to adjustment by the Committee for extraordinary events during the Performance
Period, as applicable. Both the Shareholder Value and the Growth Performance Metrics will be
compared to those of the peer group consisting of gas utility companies listed in the Edward Jones
Natural Gas Distribution Group (the Peer Group) for the Performance Period and Awards will be
determined according to the schedule in subsection (b) below. For the average RoE Performance
Metric, the Companys performance will be compared to pre-determined RoE thresholds established by
the Committee. At the end of the Performance Period, the Committee shall certify in writing the
extent to which the Performance Goals were met during the Performance Period for Awards for Covered
Employees. If the Performance Goals for the Performance Period are met, Covered Employees shall be
entitled to the Award, subject to the Committees exercise of discretion to reduce any Award to a
Covered Employee based on business objectives established for that Covered Employee or other
factors as determined by the Committee in its sole discretion. The Committee shall promptly notify
the Grantee of its determination.
(b) The Grantee may earn percent or more of the target award of Performance Shares
(the Target Award) up to a maximum number of Performance Shares set forth in Section 1 above (the
Maximum Award) based upon achievement of threshold and target levels of performance against the
Performance Metrics established for the Performance Period. The Committee shall confirm the level
of Award attained for the Performance Period after the Companys independent auditors have
certified the Companys financial statements for each fiscal year of the Company in the Performance
Period.
(c) Once established, the performance criteria identified above normally shall not be changed
during the Performance Period. However, if the Committee determines that external changes or other
unanticipated business conditions have materially affected the fairness of the goals, or that a
change in the business, operations, corporate structure or capital structure of the Company, or the
manner in which it conducts its business, or acquisitions or divestitures of subsidiaries or
business units, or other events or circumstances materially affect the performance criteria or
render the performance criteria unsuitable, then the Committee may approve appropriate adjustments
to the performance criteria (either up or down) during the Performance Period. Notwithstanding the
foregoing, no changes shall be made to an Award intended to satisfy the requirements of Code
Section 162(m) if such changes would affect the qualification of the Award as performance-based
compensation within the meaning of Code Section 162(m).
- 2 -
(d) Performance Shares that are earned by the Grantee pursuant to this Section 2 shall be
issued promptly, without payment of consideration by the Grantee, within 2 1/2 months of the end of
the Performance Period. The Grantee shall have the right to vote the Performance Shares and to
receive the dividends distributable with respect to such Shares on and after, but not before, the
date on which the Grantee is recorded on the Companys ledger as holder of record of the
Performance Shares (the Issue Date). If, however, the Grantee receives Shares as part of any
dividend or other distribution with respect to the Performance Shares, such Shares shall be treated
as if they are Performance Shares, and such Shares shall be subject to all of the terms and
conditions imposed by this Section 2. Notwithstanding the foregoing, the Grantee shall be entitled
to receive an amount in cash, equivalent to the dividends that would have been paid on the awarded
Performance Shares from the Grant Date to the Issue Date for those Performance Shares actually
earned by the Grantee during the applicable Performance Period. Such dividend equivalents shall be
payable at the time such Performance Shares are issued.
(e) The Performance Shares will not be registered for resale under the Securities Act of 1933
or the laws of any state except when and to the extent determined by the Board pursuant to a
resolution. Until a registration statement is filed and becomes effective, however, transfer of
the Performance Shares shall require the availability of an exemption from such registration, and
prior to the issuance of new certificates, the Company shall be entitled to take such measures as
it deems appropriate (including but not limited to obtaining from the Grantee an investment
representation letter and/or further legending the new certificates) to ensure that the Performance
Shares are not transferred in the absence of such exemption.
(f) In the event of a Change in Control, as defined in the Plan, during the Performance
Period, the Grantee shall earn the Maximum Award of Performance Shares set forth in this Section 2,
as if all performance criteria were satisfied, without any pro ration based on the proportion of
the Performance Period that has expired as of the date of such Change in Control.
(g) If, during the Performance Period, the Grantee is separated from employment, Performance
Shares shall be deemed earned or forfeited as follows:
(1) Upon voluntary termination by the Grantee or termination by the Company for failure
of job performance or other just cause as determined by the Committee, all unearned
Performance Shares shall be forfeited immediately;
(2) If the Grantee separates from employment by reason of death or total and permanent
disability (as determined by the Committee), the number of Performance Shares that would
otherwise have been earned at the end of the Performance Period shall be reduced by pro
rating such Performance Shares based on the proportion of the Performance Period during
which the Grantee was employed by the Company, unless the Committee determines that the
Performance Shares shall not be so reduced;
(3) Upon retirement by the Grantee at age 55 or thereafter, all unearned Performance
Shares shall be forfeited immediately.
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(h) The Grantee shall be solely responsible for any federal, state and local taxes of any kind
imposed in connection with the vesting or delivery of the Performance Shares. Prior to the
transfer of any Performance Shares to the Grantee, the Grantee shall remit to the Company an amount
sufficient to satisfy any federal, state, local and other withholding tax requirements.
The Grantee may elect to have all or part of any withholding tax obligation satisfied by
having the Company withhold Shares otherwise deliverable to the Grantee as Performance Shares,
unless the Committee determines otherwise by resolution. If the Grantee fails to make such
payments or election, the Company and its subsidiaries shall, to the extent permitted by law, have
the right to deduct from any payments of any kind otherwise due to the Grantee any taxes required
by law to be withheld with respect to the Performance Shares. In the case of any amounts withheld
for taxes pursuant to this provision in the form of Shares, the amount withheld shall not exceed
the minimum required by applicable law and regulations.
(i) Notwithstanding any other provision of this Agreement, if any payment or distribution (a
Payment) by the Company or any other person or entity to or for the benefit of the Grantee is
determined to be an excess parachute payment (within the meaning of Code Section 280G(b)(1) or
any successor provision of similar effect), whether paid or payable or distributed or distributable
pursuant to this Agreement or otherwise, then the Grantees benefits under this Agreement may,
unless the Grantee elects otherwise pursuant to his employment agreement, be reduced by the amount
necessary so that the Grantees total parachute payment as defined in Code Section 280G(b)(2)(A)
under this and all other agreements will be $1.00 less than the amount that would be a parachute
payment. The payment of any excess parachute payment pursuant to this paragraph shall also
comply with the terms of the Grantees employment agreement.
Section 3. Additional Conditions to Issuance of Shares
Each transfer of Performance Shares shall be subject to the condition that if at any time the
Committee shall determine, in its sole discretion, that it is necessary or desirable as a condition
of, or in connection with, transfer of Performance Shares (i) to satisfy withholding tax or other
withholding liabilities, (ii) to effect the listing, registration or qualification on any
securities exchange or under any state or federal law of any Shares deliverable in connection with
such exercise, or (iii) to obtain the consent or approval of any regulatory body, then in any such
event such transfer shall not be effective unless such withholding, listing, registration,
qualification, consent or approval shall have been effected or obtained free of any conditions not
acceptable to the Company.
Section 4. Adjustment of Shares
(a) If the Company shall become involved in a merger, consolidation or other reorganization,
whether or not the Company is the surviving corporation, any right to earn Performance Shares shall
be deemed a right to earn or to elect to receive the consideration into which the Shares
represented by the Performance Shares would have been converted under the terms of the merger,
consolidation or other reorganization. If the Company is not the surviving corporation, the
surviving corporation (the Successor) shall succeed to the rights and obligations of the Company
under this Agreement.
(b) If any subdivision or combination of Shares or any stock dividend, capital reorganization
or recapitalization occurs after the adoption of the Plan, the Committee shall make such
proportionate adjustments as are appropriate to the number of Performance Shares to be earned in
order to prevent the dilution or enlargement of the rights of the Grantee.
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Section 5. No Right to Employment
Nothing contained in this Agreement shall be deemed by implication or otherwise to confer upon the
Grantee any right to continued employment by the Company or any affiliate of the Company.
Section 6. Notice
Any notice to be given hereunder by the Grantee shall be sent by mail addressed to Chesapeake
Utilities Corporation, 909 Silver Lake Boulevard, Dover, Delaware 19904, for the attention of the
Committee, c/o the Corporate Secretary, and any notice by the Company to the Grantee shall be sent
by mail addressed to the Grantee at the address of the Grantee shown on the first page hereof.
Either party may, by notice given to the other in accordance with the provisions of this Section,
change the address to which subsequent notices shall be sent.
Section 7. Beneficiary Designation
Grantee may designate a beneficiary to receive any Performance Shares to which Grantee is entitled
which vest as a result of Grantees death. Grantee acknowledges that the Company may exercise all
rights under this Agreement and the Plan against Grantee and Grantees estate, heirs, lineal
descendants and personal representatives and shall not be limited to exercising its rights against
Grantees beneficiary.
Section 8. Assumption of Risk
It is expressly understood and agreed that the Grantee assumes all risks incident to any change
hereafter in the applicable laws or regulations or incident to any change in the market value of
the Performance Shares.
Section 9. Terms of Plan
This Agreement is entered into pursuant to the Plan (a copy of which has been delivered to the
Grantee). This Agreement is subject to all of the terms and provisions of the Plan, which are
incorporated into this Agreement by reference, and the actions taken by the Committee pursuant to
the Plan. In the event of a conflict between this Agreement and the Plan, the provisions of the
Plan shall govern. All determinations by the Committee shall be in its sole discretion and shall
be binding on the Company and the Grantee.
Section 10. Governing Law; Amendment
This Agreement shall be governed by, and shall be construed and administered in accordance with,
the laws of the State of Delaware (without regard to its choice of law rules) and the requirements
of any applicable federal law. This Agreement may be modified or amended only by a writing signed
by the parties hereto.
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Section 11. Action by the Committee
The parties agree that the interpretation of this Agreement shall rest exclusively and completely
within the sole discretion of the Committee. The parties agree to be bound by the decisions of the
Committee with regard to the interpretation of this Agreement and with regard to any and all
matters set forth in this Agreement. The Committee may delegate its functions under this
Agreement to an officer of the Company designated by the Committee (hereinafter the Designee).
In fulfilling its responsibilities hereunder, the Committee or its Designee may rely upon
documents, written statements of the parties or such other material as the Committee or its
Designee deems appropriate. The parties agree that there is no right to be heard or to appear
before the Committee or its Designee and that any decision of the Committee or its Designee
relating to this Agreement shall be final and binding unless such decision is arbitrary and
capricious.
Section 12. Terms of Agreement
This Agreement shall remain in full force and effect and shall be binding on the parties hereto for
so long as any Performance Shares issued to the Grantee under this Agreement continue to be held by
the Grantee.
IN WITNESS WHEREOF, the Company has caused this Agreement to be executed in its corporate name, and
the Grantee has executed the same in evidence of the Grantees acceptance hereof, upon the terms
and conditions herein set forth, as of the day and year first above written.
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CHESAPEAKE UTILITIES CORPORATION |
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Exhibit 10.30
Exhibit 10.30
First Amendment to the
CHESAPEAKE UTILITIES CORPORATION
SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN
As Amended and Restated as of January 1, 2009
First Amendment to the Chesapeake Utilities Corporation Supplemental
Executive Retirement Plan
Background Information
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The Plan was amended and restated effective as of January 1, 2009, to comply with the
requirements of Section 409A of the Internal Revenue Code of 1986, as amended (the Code).
From and after January 1, 2005 through December 31, 2008, the Plan, to the extent not
grandfathered, was subject to and operated in accordance with a good faith interpretation of
Code Section 409A, including the use of any applicable transition rules in effect during such
period. |
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The Internal Revenue Service, in Notice 2010-6, provided guidance regarding document drafting
failures and ambiguities that may be corrected or clarified without adverse tax implications. |
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Chesapeake Utilities Corporation, as the Plans sponsor, desires to make certain clarifying
amendments to the Plan to ensure its interpretation and operation continue in accordance with
the requirements of Code Section 409A, as permitted by Section IV of Notice 2010-6. |
Amendment
Chesapeake Utilities Corporation hereby amends the Plan as set forth below, effective as of
January 1, 2009:
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Article IV of the Plan, Termination of Employment, is hereby amended by the addition of new
Section 4.3 to read as follows: |
4.3 General Limitations. Notwithstanding Sections 4.1 and 4.2 above, in no event
will any payments due to be paid to a Group B Executive under the Plan be either delayed or
accelerated as to time of payment or changed as to form of payment in a manner that would
violate Code Section 409A (i) by reason of the applicability of such Sections, or (ii)
during the pendency of any determinations to be made under such Sections. Rather, if either
Section 4.1 or 4.2 is determined to be applicable to a Group B Participant, such Section
shall be enforced against the Group B Participant by causing him or her to forfeit all
remaining future payments due from and after the date of determination of the violation of
either Section 4.1 or 4.2.
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Section 6.5 of the Plan, Benefit Claims Procedure, is hereby amended by the addition of the
following at the end thereof: |
Notwithstanding the foregoing, a Group B Participant shall not be required to file a claim
in order for benefits to commence in accordance with the Participants election of the time
and form of payment. If a Group B Participant is denied a benefit to which the
Participant believes he or she is entitled, the Group B Participant may appeal such benefit
denial in accordance with the procedures for claim appeals under the Pension Plan.
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Exhibit 10.41
Exhibit 10.41
ORDINANCE NO. 981
AN ORDINANCE GRANTING A FRANCHISE TO THE FLORIDA PUBLIC
UTILITIES COMPANY, ITS
SUCCESSORS AND ASSIGNS, IN AND FOR THE CITY OF MARIANNA.
FLORIDA. FOR A PERIOD NOT TO EXCEED TEN (10) YEARS, FOR THE
OPERATION AND DISTRIBUTION AND/OR SALE
OF ELECTRIC ENERGY AND FIXING THE TERM. CONDITIONS AND
LIMITATIONS RELATIVE TO THE OPERATION AND MAINTENANCE OF
ELECTRIC UTILITIES; PROVIDING FOR INDEMNITY AGAINST DAMAGE AND
RESERVING THE RIGHT TO PURCHASE UNDER CERTAIN CONDITIONS.
BE IT ENACTED BY THE CITY COMMISSION OF THE CITY OF MARIANNA, FLORIDA:
SECTION 1. That the City of Marianna, Florida, (herein called the Grantor) hereby grants to
Florida Public Utilities Company, a Florida corporation (herein called the Grantee), its
successors and assigns for a term not to exceed ten (10) years beginning from the date of
acceptance hereof by Grantee except as provided in Section 10, Section 14 and Section 17.
(a) The nonexclusive right, privilege and authority or franchise to construct or otherwise
acquire and to own, maintain, equip and operate plants and works and all necessary or desirable
appurtenances thereto according to the latest edition of the National Electric Safety Code as
prescribed by the Bureau of Standards, for the manufacture, generation, purchase, transmission,
distribution, supply and sale of electric energy and to use and occupy the present and future
streets and other public places including avenues, roads, alleys, lanes, bridges, parks and ways
within the present and any future corporate limits of Grantor or its successors for erecting,
constructing,
installing, maintaining, renewing, replacing, repairing, owning and operation all necessary
facilities including poles, polelines, appendages thereto, used or useful for the purpose of
transmitting electric energy and for distributing, supplying and selling electric energy to
Grantor and its successors and to persons and corporate inhabitants thereof, as well as to persons
and corporations beyond the present or future corporate limits of Grantor.
(b) The Grantor shall have the first option to purchase the property of Grantee within the
City of Marianna at any time the Grantee elects to sell during franchise period.
(c) It is expressly understood and agreed that if any pole or poles erected by Grantee shall
unreasonable interfere with the rights of public or private abutting property owners, that upon due
protest in writing by such owner, the Grantee shall relocate said pole or poles at some
satisfactory point, at its own expense.
SECTION 2. At all time during the term of this franchise. Grantee shall promptly and without
discrimination furnish an adequate supply of electric energy at standard voltage within approved
limits to Grantor and its successors, and to persons and corporate inhabitants thereof who request
the same and agree to abide by Grantees reasonable rules and regulations. Grantee shall use due
care to construct and maintain its facilities in a manner that will not unreasonably interfere
with the proper use by the public of the streets and other public places of the Grantor and shall
use care and caution in making any opening in any of the streets and other public places of
Grantor for the purpose of erecting, repairing and/or maintaining its facilities to prevent injury
to persons and property, and Grantee shall, at its expense, replace and restore all streets and
other public
places so opened to their former conditions as nearly as practicable and within a reasonable time.
No first class streets or any other street that has been built or resurfaced in the last five
years shall be opened for the purpose of installing underground service without written approval
of the City Manager.
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SECTION 3. At all times during the term of this franchise. Grantee shall make promptly such
extensions to existing facilities as may be required by one or more customers, or for the
prospective customers, in accordance with Grantees rules and regulations on file and approved by
the Florida Public Service Commission. Grantee shall not be liable for any interruption of service
of failure of supply of electric energy due to accidents unconnected with negligence on the part
of Grantee, its agents or assigns, or to causes beyond the reasonable control of Grantee and such
interruptions shall not constitute a breach of this franchise, provided Grantee shall use
diligence to restore service within a reasonable time.
SECTION 4. All rates and rules and regulations established by Grantee from time to time shall
at all times be reasonable, and Grantees rates for electricity shall at all times be subject to
such regulation as may be provided by law.
SECTION 5. Without prejudice to any other rights of Grantee, any person who shall willfully
and unlawfully remove or damage any of the property, equipment and/or appliances of Grantee, used
or useful in rendering such public service, shall be fined in the sum of not more than One Thousand
and No/100 ($1000.00) Dollars for such each property or equipment or part thereof so removed or
damaged.
SECTION 6. All rights herein granted and authorized shall he subject to and governed by this
ordinance, the laws of the State of Florida and applicable regulations
and rulings of the Florida Public Service Commission or its successors, provided that Grantor
expressly reserves unto itself all of its police power to adopt general ordinances necessary to
protect the safety and welfare of the general public in relation to the rights hereby granted not
inconsistent with the provisions of this ordinance.
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SECTION 7. Grantee shall save and keep Grantor harmless from any and liability by reason of
damage or injury to any person or property whatsoever on account of the negligence of Grantee in
the installation, maintenance and operation of its facilities; provided, Grantee shall have been
notified by Grantor, in writing, of any claim against Grantor on account thereof, and shall have
ample opportunity to defend same.
SECTION 8. Grantee shall install and maintain meters for measuring electric current and shall
have the right of ingress and egress to the premises of each consumer, from time to time, for the
purpose of reading, repairing, testing and maintaining Grantees meters and appurtenances. Such
meters and appurtenances shall at all times remain the property of the Grantee and shall be
removable at any time.
SECTION 9. Within thirty (30) days after the last day of each month after the approval of
this grant, the Grantee, or its successors or assigns shall pay to the Grantor, or its successors,
at Grantors option, as part of the consideration for the granting of this franchise, a sum equal
to an amount of 6% of the gross sales of electricity within the City of Marianna for the preceding
month.
4
SECTION 10. The Grantor hereby reserves the right at and after expiration or termination of
this grant to purchase the property of Grantee within the City of Marianna, and, as a condition
precedent to the taking effect of this grant, Grantee shall give and grant to Grantor, and, by its
acceptance hereof, Grantee shall conclusively be deemed to
have given and granted to Grantor, the right to purchase so reserved. The purchase price of the
property shall be determined by three (3) qualified appraisers with expertise in arriving at
valuation of electric companies and all of their component parts; one appraiser being appointed by
the City Commission of the City of Marianna, one appraiser appointed by Florida Public Utilities,
and the two thus appointed shall appoint a third appraiser. The final price to be paid for the
system is to be the fair market value decided by the majority vote of the three appraisers. If
either Grantor or Grantee does not appoint an appraiser within sixty (60) days after being
requested to do so, the appraisal shall be made by the appraisal firm appointed by the other, and
their appraisal shall be the purchase price to be paid by the City.
The Grantee shall be responsible for the cost incurred by its appraiser, the Grantor will be
responsible for the cost incurred by its appraiser, and the Grantor and Grantee shall share
equally in the cost of the third appraiser.
The Grantor will notify the Grantee, in writing, at least six (6) months prior to the
expiration date of this franchise, or any extension thereof, of Grantors intent to exercise the
purchase option hereby reserved; Grantor shall thereafter close on such purchase within twenty
four (24) months after referendum to approve purchase of system, or shall be deemed to have waived
its right to so purchase the system unless said delay is due to conduct and actions of Grantee.
The Grantor may at its option exercise its right to purchase Grantees property pursuant to
the above procedure, or pursue condemnation as outlined in Florida Statutes Chapter 73.
5
SECTION 11. Grantee by its acceptance hereof agrees to observe, perform, and keep all of the
agreements, undertakings and conditions hereof to be observed, performed and kept by Grantee.
SECTION 12. In consideration of Grantees undertaking hereunder as evidenced by its
acceptance hereof, Grantor agrees not to engage in the business of distributing and selling
electric energy during the life of this franchise or any extension thereof in competition with
Grantee, its successors and assigns however this provision shall not prohibit the Grantor from
providing electrical energy and capacity for its own use.
SECTION 13. Grantee by the acceptance hereof further agrees to erect and maintain without
cost, except for electric energy to be charged according to the published rates of Grantee (which
rates include a facilities, maintenance and energy charge), such street lights as the Grantor
shall from time to time consider necessary and proper to meet the reasonable needs of the Grantor
for lighting streets and other public ways. It being expressly understood, however, that in the
event said Grantor shall request the erecting or placing of any particular light and shall
subsequently request the discontinuance of said light prior to the expiration of this franchise,
the Grantor shall reimburse the Grantee for its expense in the erection and removing of such
discontinued light. The intention being that the Grantee will make any just and reasonable
extension of its electric light system which may be requested by the Grantor commensurate with a
fair and compensatory return on the fair market value of the property used and useful in
furnishing such extension.
6
SECTION 14. At least twelve (12) months prior to the expiration date of the Generation
Services contract, Grantee will provide Grantor written notice of the
expiration of the contract. Should Grantor desire to participate in the process of securing a new
Generation Services contract, the Grantor will provide notice, in writing, to Grantee. If required,
the Grantee and Grantor shall meet and review the proposals, in accordance with any confidentiality
agreements from prospective bidders, for future contracts. The Grantee may employ a consultant for
the purposes of conducting a bidding process, evaluating all proposals and determining the best
Generation Services supplier.
Prior to entering into any Generation Services contract, Grantee, if requested in writing,
shall provide Grantor with a copy of the consultants report in accordance with any
confidentiality agreements, whereupon Grantor shall have a period of thirty (30) days to review
the same and make its recommendations, if any, to Grantee, which such recommendations the Grantee
shall consider in contracting for Generation Services.
If during the term of an existing generation services contract, any material terms of the
contract are altered, the Grantee shall notify the Grantor and the Grantor shall have the
opportunity to review proposed revisions and advise the Grantee of concerns prior to the
acceptance of the proposed new terms by the Grantee.
Failure to comply with this Section shall constitute a default by the Grantee and the Grantor
shall have the option to terminate this agreement pursuant to terms of Section 10.
7
At least twelve (12) months prior to the expiration date of the Transmission Network
Operating Agreement(s), Network Integration Transmission Service Agreement(s) and Distribution
Facilities Agreement, Grantee will provide Grantor written notice of the expiration of the
contract. Should Grantor desire to participate in the
process of securing a transmission agreements, the Grantor will provide notice, in writing, to
Grantee. If required, the Grantee and Grantor shall meet and review the proposal(s) in accordance
with the Open Access Transmission Tariffs, as approved by the Federal Energy Regulatory
Commission, to ensure compliance of each proposal. The Grantee may employ a consultant for the
purposes of evaluating the proposal(s) in accordance with the Open Access Transmission Tariff and
negotiating and necessary modifications. Grantee will make available the consultants report to the
Grantor in conjunction with the discussions as noted above.
SECTION 15. The Grantor shall have the right at any time to employ an independent auditor to
audit any records of Grantee which applies to expenses and/or rates of electricity in Marianna,
Florida. The Grantee hereby agrees to cooperate in every way possible with an auditor employed by
the Grantor. Any auditor employed by the Grantor shall be a certified public accountant, licensed
in the State of Florida.
SECTION 16. The Grantor has requested Grantee to place all electric facilities underground in
an area of downtown Marianna in order to enhance the appearance of the Marianna Main Street area.
The areas to be included are as follows:
(a) Madison Street between Market St. and Lafayette St.
(b) Green Street between Clinton St. and Lafayette St.
(c) Market Street between Caledonia St. and Madison St.
(d) Streets immediately adjacent to the Jackson County Courthouse.
Facilities will be placed underground by Grantee in conjunction with the City of Mariannas
water system construction project that will be conducted in this area. Grantee will provide all
labor and material including, but not limited to, underground conduit to have a standard
underground type system using padmounted transformers installed in the above-mentioned area. The
following conditions will also apply to the project.
8
(a) Grantees customers will be responsible for making the necessary changes in their
electrical system to accept electricity from an underground system.
(b) Grantor will provide all necessary trenching, backfilling, conduit installation,
padmounted transformer pads and repaving associated with this project. The installation of the
conduit and construction of the padmounted transformer pads will be performed to Grantees
specifications.
(c) The Grantor will work with CenturyTel and Comcast Cable, or their successors, to have
their facilities placed underground during this project. Grantee will not be responsible for any
agreements or associated costs resulting from this aspect of the project.
(d) Grantor will be responsible for placing underground any metered or control circuits used
by Grantor.
(e) Grantees work will be completed within six months of the Grantors installation of the
necessary transformer pads and conduit.
SECTION 17. Concurrent with the approval of this agreement. Grantee will begin development of
Time of Use and Interruptible electric rates or similar electric rates any or all of which
must be mutually agreed to by Grantee and Grantor. Such rates will be available to all of
Grantees customers both within and without the corporate limits of the Grantor and will be
effective no later than February 17, 2011. Grantor will support Grantees efforts during
proceedings before the Florida Public Service Commission in order to gain approval of the new
electric rates. Should the rates not be in effect by February 17, 2011, Grantor may, at any time
within 180 days after that date, give notice to Grantee that Grantor exercises its option to
purchase Grantees system in
accordance with procedures set forth in Section 10 of this franchise except that Grantor must
close the purchase of the system within 12 months of the referendum to approve the purchase. If
Grantor does not give notice within the 180 day time period, this agreement shall remain in effect
and continue according to its terms until its ten year expiration date.
9
SECTION 18. All of the terms, provisions and conditions of this ordinance shall inure to and
be binding upon the respective successors and assigns of Grantor and Grantee, and shall apply to
the present and any future corporate limits of Grantor or its successors.
SECTION 19. In the event Grantee, during the term of this franchise, determines to construct
facilities for the generation of electric energy sold within the City of Marianna, it will give
preference to a site for such facilities within said city if an economical and practical site can
be obtained therein.
SECTION 20. This ordinance shall become effective on February 1, 2010, and shall be in full
force and effect from such time, and upon its acceptance in writing by the Grantee filed with the
City Clerk of the City of Marianna, Florida.
SECTION 21. Should any section or provisions of this ordinance or any portion thereof be
declared by a court of competent jurisdiction to be invalid, such decision shall not affect the
validity of the remainder as a whole or as to any part other than the part declared to be invalid.
10
Presented in open meeting of the City Commission of the City of Marianna, and read in full this the
7th day of July, 2009.
Passed by the City Commission of the City of Marianna, Florida, this 7th day of July,
2009.
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CITY OF MARIANNA |
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BY:
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/s/ [ILLEGIBLE] |
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Mayor
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ATTEST:
The Florida Public Utilities Company accepts the term of said ordinance and does hereby agree to
abide by the terms of the conditions of said ordinance.
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FLORIDA PUBLIC UTILITIES COMPANY |
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BY:
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/s/ C.L. Stein |
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C.L. Stein
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Its: Sr. Vice President, COO |
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Date: 8/28/09 |
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11
Exhibit 10.43
Exhibit 10.43
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EXECUTION VERSION
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CONFIDENTIAL |
AMENDMENT NO. 1
TO THE
AGREEMENT FOR GENERATION SERVICES
BETWEEN
GULF POWER COMPANY
AND
FLORIDA PUBLIC UTILITIES COMPANY
THIS AMENDMENT, effective as of the 25th day of January, 2011 (Amendment No. 1),
amends the Agreement for Generation Services between Gulf Power Company (Gulf Power) and Florida
Public Utilities Company (FPUC) dated as of December 28, 2006 (Agreement). Gulf Power and FPUC
are individually referred to herein as a Party and collectively as the Parties.
WITNESSETH:
WHEREAS, pursuant to the Agreement, Gulf Power has agreed to sell to FPUC, and FPUC has agreed
to purchase from Gulf Power, capacity and energy in order for FPUC to supply the native load
electric requirements of FPUCs Northwest Division;
WHEREAS, the Parties desire to amend the Agreement in order to modify the method for
calculating the amount of capacity to be purchased by FPUC from Gulf Power, subject to the terms
and conditions hereof; and
WHEREAS, the Parties desire to further amend the Agreement in order extend the term of the
Agreement, subject to the terms and conditions hereof.
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EXECUTION VERSION
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CONFIDENTIAL |
NOW, THEREFORE, in consideration of the premises, the mutual promises and agreements contained
herein and other good and valuable consideration, the receipt, sufficiency and adequacy of which
are hereby acknowledged, the Parties each intending to be legally bound hereby agree as follows:
A. Amendments to Agreement.
Subject to the satisfaction of the condition set forth in Section B. 1 of this Amendment No. 1,
the Parties hereby agree to amend and modify the Agreement as follows.
1. In Section 1.1 of the Agreement, the definition of Monthly Capacity Rate is hereby
modified by adding the following capacity rates for the following years to the table within that
definition:
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Year |
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Capacity Rate ($/kW-Mo.) |
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2018 |
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$ |
12.25 |
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2019 |
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$ |
12.80 |
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2. In Section 1.1 of the Agreement, the definition of Term is hereby modified by replacing
the date December 31, 2017 with the date December 31, 2019.
3. Section 2.1 of the Agreement is hereby modified by replacing the reference to December
31, 2017 with December 31, 2019.
4. Appendix A of the Agreement is hereby modified by replacing the reference to the year
2016 in the first paragraph with the year 2018.
5. Appendix A of the Agreement is hereby modified by deleting Section D of that Appendix and
replacing it with the revised Section D set forth in Attachment 1 to this Amendment No. 1.
6. Appendix A of the Agreement is hereby modified by deleting Section E of that Appendix and
replacing it with the revised Section E set forth in Attachment 2 to this Amendment No. 1.
7. Exhibit 1 to Appendix A of the Agreement is hereby modified by: (a) replacing the
words Example Calculation of Capacity Purchase with the words Example Calculation of Capacity
Purchase for Years 2008 through 2010; and (b) adding to that exhibit the contents of Attachment 3
to this Amendment No. 1.
2
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EXECUTION VERSION
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CONFIDENTIAL |
B. Regulatory.
1. By no later than January 31, 2011, FPUC shall make a filing with the FPSC requesting
approval of this Amendment No. 1, without any modification or condition with respect to the
Agreement other than as specifically set forth in Section A of this Amendment No. 1 (Requested
Approval). After making such filing, FPUC shall utilize diligent efforts to obtain a Final Order
that grants the Requested Approval by no later than July 31, 2011 (Approval Deadline). The
amendments and modifications to the Agreement set forth in Section A of this Amendment No. 1 are
expressly conditioned upon the receipt of a Final Order by the Approval Deadline that grants the
Requested Approval. For purposes of this Amendment, a Final Order means an order of the FPSC
that is no longer subject to appeal or further review by a court or other governmental authority.
2. FPUC shall promptly notify Gulf Power when it receives a ruling from the FPSC regarding
the Requested Approval. FPUC shall keep Gulf Power reasonably informed as to the progress of its
efforts to obtain the Requested Approval.
3. In the event that: (i) there is no Final Order by the Approval Deadline that grants the
Requested Approval; or (ii) the FPSC issues an order or issuance denying the Requested Approval or
an order or issuance requiring any modifications or conditions with respect to the Agreement or
this Amendment No. 1 that are not specifically provided for in Section A of this Amendment No. 1,
then in either case of (i) or (ii), this Amendment No. 1 shall immediately terminate and be
rendered null and void, ab initio, without further action of the Parties; provided,
however, Gulf Power shall be entitled to invoice, and FPUC shall pay, amounts as provided
in the penultimate sentence of Section C below. If this Amendment No. 1 so terminates, the Agreement shall continue in full force effect
as it existed prior to the execution by the Parties of this Amendment No. 1.
3
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EXECUTION VERSION
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CONFIDENTIAL |
C. Adjustment of Invoices.
1. Consistent with the Parties intent to modify the method for determining the Capacity
Purchase under Section D of Appendix A of the Agreement, commencing with the payment for capacity
provided for January 2011, Gulf Power shall calculate the Monthly Capacity Payment for each Month
utilizing a Capacity Purchase that is determined in accordance with the revised Section D of
Appendix A under this Amendment No. 1 (each such Month, commencing with January 2011 being referred
to as a Modified Month).
2. Notwithstanding the foregoing, in the event that this Amendment No. 1 terminates under
Section B.3 above, in order for payments to be made in accordance with the original terms of this
Agreement, Gulf Power shall be entitled to retroactively invoice FPUC for the full amount of the
Monthly Capacity Payments for the Modified Months as such payments would have been calculated if
this Amendment No. 1 had never existed (less any amounts previously paid by FPUC as Monthly
Capacity Payments for such Months), plus interest at the Interest Rate. FPUC shall pay such
invoiced amount in accordance with Article 6 of the Agreement.
D. Other Provisions.
1. Unless otherwise specifically provided in this Amendment No. 1, capitalized terms in this
Amendment No. 1 shall have the meaning assigned to such terms in the Agreement.
2. Except as amended hereby, the terms and conditions of the Agreement shall remain in full
force and effect.
3. This Amendment No. 1 may be executed in multiple counterparts (including by facsimile,
electronic mail, or similar electronic transmission device pursuant to which the signature of or
on behalf of each party hereto can be seen), each of which shall be deemed an original and all of
which shall constitute a single instrument.
4
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EXECUTION VERSION
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CONFIDENTIAL |
4. This Amendment No. 1 shall be considered for all purposes as prepared through the joint
efforts of the Parties and shall not be construed against one Party or the other as a result of
the preparation or other event of negotiation, drafting or execution hereof.
5. This Amendment No. 1 (including the attachments hereto) and the terms and conditions hereof
shall constitute Confidential Information of each Party subject to Article 15 of the Agreement. The
Parties agree to seek confidential treatment of this Amendment No. 1 and other Confidential
Information from the FPSC to the maximum extent possible pursuant to Chapter 366.093, Florida
Statutes, and Rule 25-22.006 of the Florida Administrative Code. In the event any Confidential
Information will need to be disclosed in connection with any application for the FPSC approval of
this Amendment No. 1 or the rates to be charged hereunder, FPUC shall consult and cooperate with
Gulf Power prior to such disclosure, including, without limitation, in determining the extent to
which confidential treatment will be sought for such terms, conditions and provisions.
[The next page is the signature page.]
5
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EXECUTION VERSION
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CONFIDENTIAL |
IN WITNESS WHEREOF, the Parties have duly executed this Amendment No. 1 as of the date first
written above.
GULF POWER COMPANY
By and through its agent
Southern Company Services, Inc.
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BY:
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/s/ Murry Weaver
NAME: Murry Weaver
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TITLE: Vice President, Southern Wholesale Energy |
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FLORIDA PUBLIC UTILITIES COMPANY
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BY:
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/s/ Jeff Householder
NAME: Jeff Householder
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TITLE: President |
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6
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EXECUTION VERSION
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CONFIDENTIAL |
ATTACHMENT 1
REVISED SECTION D OF APPENDIX A OF THE AGREEMENT
D. Capacity Purchase.
The Capacity Purchase for the Year following each Calculation Year shall be rounded to the
nearest kilowatt (kW), and shall be determined as follows:
1. Capacity Purchase for Years 2008 through 2010.
For each of the Years 2008, 2009 and 2010, the Capacity Purchase shall be equal to the greater
of:
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(i) |
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the Reserve Requirement plus one (1); multiplied by the |
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(ii) |
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Forecasted Northwest Annual Peak Demand. |
Or
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(i) |
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one and one-hundredth (1.01) plus the Growth Rate; multiplied by the |
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(ii) |
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Capacity Purchase for the Calculation Year. |
Or
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(2) |
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the Capacity Purchase for the Calculation Year. |
Notwithstanding the foregoing, the Capacity Purchase for Year 2008 shall be equal to the
product of: (i) the Reserve Requirement plus one (1); multiplied by (ii) the Forecasted Northwest
Annual Peak Demand.
Page 1 of Attachment 1
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EXECUTION VERSION
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CONFIDENTIAL |
2. Capacity Purchase for Years after 2010.
For each Year of the Service Term after 2010, the Capacity Purchase shall be equal to the
greater of:
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(i) |
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the Reserve Requirement plus one (1); multiplied by the |
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(ii) |
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Forecasted Northwest Annual Peak Demand. |
Or
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(i) |
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one and one-hundredth (1.01) plus the Growth Rate; multiplied by
the |
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(ii) |
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Capacity Purchase for the Calculation Year. |
Or
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(2) |
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91 MW (Capacity Minimum) (subject to reduction for Year 2018
and/or Year 2019 under the circumstances described in Section E.2(b) of this
Appendix A). |
Page 2 of Attachment 1
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EXECUTION VERSION
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CONFIDENTIAL |
ATTACHMENT 2
REVISED SECTION E OF APPENDIX A OF THE AGREEMENT
E. Reductions in Capacity Purchase.
1. Required Purchases from Third Parties.
If in any Year of the Service Term FPUC is required to purchase capacity from a third party
under applicable Law pursuant to Section 3.4(ii) or (iii) and the Parties cannot agree upon
feasible actions (if any) to be taken by either or both Parties such that FPUC can satisfy and/or
comply with such Law for such Year while simultaneously leaving this Agreement in full force and
effect as originally executed, then the Capacity Purchase calculated for such Year (or applicable
portion thereof) pursuant to the provisions of this Appendix A shall be reduced by such amount
necessary for FPUC to comply with applicable Law.
2. Expiration of the Marianna Franchise Agreement.
If during the Service Term, FPUCs franchise agreement with the City of Marianna, Florida
expires and is not renewed, extended or replaced (the date of such expiration being the Marianna
Expiration Date), then the following shall apply as applicable:
(a) If Gulf Power and/or any of its Affiliates sells electric capacity to the City of
Marianna after the Marianna Expiration Date, then for the period of time during the Service
Term that Gulf Power and/or its Affiliates sells capacity to the City of Marianna, the
Capacity Purchase to FPUC shall be reduced by the amount of capacity sold to the City of
Marianna by Gulf Power and/or its Affiliates; provided, however, there shall be no such
reduction if the Capacity Minimum has already been reduced by the Marianna Load Amount
pursuant to subsection (b) below.
Page 1 of Attachment 2
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EXECUTION VERSION
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CONFIDENTIAL |
(b) If neither Gulf Power nor any of its Affiliates sells electric capacity to the City of Marianna
during the period of the Service Term after the Marianna Expiration Date, then commencing with the
later of: (i) Year 2018, or (ii) the Year after the Year in which the Marianna Expiration Date
occurs, the Capacity Minimum under Section D of this Appendix A shall be reduced by the Marianna
Load Amount for purposes of calculating the Capacity Purchase for such Year (but in no event shall
the Capacity Minimum be reduced for purposes of calculating the Capacity Purchase for any Year
prior to 2018).
For purposes hereof, the Marianna Load Amount shall equal:
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(a) |
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the Marianna Load Ratio times the Northwest
Annual Peak Demand, each for the Peak Season of the third Year prior to
the Year in which the Marianna Expiration Date occurs; plus |
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(b) |
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the Marianna Load Ratio times the Northwest
Annual Peak Demand, each for the Peak Season of the second Year prior to
the Year in which the Marianna Expiration Date occurs; plus |
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(c) |
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the Marianna Load Ratio times the Northwest
Annual Peak Demand, each for the Peak Season of the first Year prior to
the Year in which the Marianna Expiration Date occurs. |
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(2) |
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divided by three (3). |
For purposes hereof, the Marianna Load Ratio for a given Peak Season shall equal the
quotient of: (a) the aggregate total of all kWH of energy billed by FPUC for such Peak
Season to retail customers in the City of Marianna franchise area; divided by (b) the
aggregate total of all kWH of energy billed by FPUC for such Peak Season to all Northwest
Division retail customers.
In no event shall a reduction in the Capacity Purchase under Section E.2(a) above and
a reduction in the Capacity Minimum under Section E.2(b) above be effective concurrently.
Page 2 of Attachment 2
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EXECUTION VERSION
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CONFIDENTIAL |
ATTACHMENT 3
ADDITION TO EXHIBIT 1 TO APPENDIX A OF THE AGREEMENT
Example Calculation of Capacity Purchase for Years After 2010
Note: All data is for example purposes only, and is not representative of actual or forecasted
data. Calculation Year = 2010
A. Marianna Annual Peak Demand
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Year |
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Peak Season MW |
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Transmission Loss Factor |
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Peak Season MW (after loss adj.) |
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2007 |
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79.197 |
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2.6 |
% |
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81.311 |
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2008 |
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72.928 |
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2.6 |
% |
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74.875 |
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2009 |
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73.203 |
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2.6 |
% |
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75.157 |
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2010 |
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69.581 |
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2.6 |
% |
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71.438 |
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Peak Season is defined as May through September
B. Growth Rate
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(1)
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(a)
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-7.92 |
% |
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(b)
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0.38 |
% |
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(c)
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+ -4.95
-12.49 |
% % |
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(2) |
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-12.490% / 3 = -4.1600% |
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2011 Capacity Purchase: 91.000 MW
Page 1 of Attachment 3
Exhibit 12
Exhibit 12
Chesapeake Utilities Corporation
Ratio of Earnings to Fixed Charges
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For the Years Ended December 31, |
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2010 |
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2009 (a) |
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2008 |
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2007 |
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2006 |
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(in thousands, except ratio of earnings to fixed charges) |
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Income from continuing operations |
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$ |
26,056 |
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$ |
15,897 |
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$ |
13,607 |
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$ |
13,218 |
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$ |
10,748 |
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Add: |
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Income taxes |
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16,923 |
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10,918 |
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8,817 |
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8,597 |
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6,999 |
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Portion of rents representative of interest factor |
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356 |
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333 |
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294 |
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245 |
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227 |
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Interest on indebtedness |
|
|
9,090 |
|
|
|
7,042 |
|
|
|
6,110 |
|
|
|
6,539 |
|
|
|
5,722 |
|
Amortization of debt discount and expense |
|
|
55 |
|
|
|
43 |
|
|
|
47 |
|
|
|
51 |
|
|
|
52 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings as adjusted |
|
$ |
52,480 |
|
|
$ |
34,233 |
|
|
$ |
28,875 |
|
|
$ |
28,650 |
|
|
$ |
23,748 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Charges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Portion of rents representative of interest factor |
|
$ |
356 |
|
|
$ |
333 |
|
|
$ |
294 |
|
|
$ |
245 |
|
|
$ |
227 |
|
Interest on indebtedness |
|
|
9,090 |
|
|
|
7,042 |
|
|
|
6,110 |
|
|
|
6,539 |
|
|
|
5,722 |
|
Amortization of debt discount and expense |
|
|
55 |
|
|
|
43 |
|
|
|
47 |
|
|
|
51 |
|
|
|
52 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Charges |
|
$ |
9,501 |
|
|
$ |
7,418 |
|
|
$ |
6,451 |
|
|
$ |
6,835 |
|
|
$ |
6,001 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ratio of Earnings to Fixed Charges |
|
|
5.52 |
|
|
|
4.61 |
|
|
|
4.48 |
|
|
|
4.19 |
|
|
|
3.96 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes the results from the merger with Florida Public Utilities Company, which
became effective on October 28, 2009. |
Exhibit 14.1
Exhibit 14.1
CODE OF ETHICS FOR FINANCIAL OFFICERS
Adopted February 24, 2010
This Code of Ethics for Financial Officers has been adopted by the Board of Directors of
Chesapeake Utilities Corporation (Chesapeake) to promote honest and ethical conduct, accurate and
timely disclosure of financial information in Chesapeakes filings with the Securities and Exchange
Commission (SEC), and compliance with all applicable laws, rules and regulations.
Chesapeake expects all of its employees to carry out their responsibilities in accordance with
the highest standards of personal and professional integrity and to abide by the provisions of
Chesapeakes Business Code of Ethics and Conduct and all other policies and procedures that may be
adopted by the Company from time to time governing the conduct of its employees. This Code of
Ethics for Financial Officers supplements the Companys Business Code of Ethics and Conduct as it
relates to the activities of Chesapeakes Chief Executive Officer, President, Chief Financial
Officer, Treasurer, and Corporate Controller, hereafter referred to as the Financial Officers.
Each Financial Officer when performing his or her duties must:
|
|
|
Maintain high standards of honest and ethical conduct, including the ethical handling of
actual or apparent conflicts of interest between personal and professional relationships. |
|
|
|
Take reasonable actions within the scope of his or her responsibilities to ensure that
the disclosures in reports and documents filed by Chesapeake with the SEC and in other
public communications made by Chesapeake are accurate, complete, fairly stated, timely and
understandable. |
|
|
|
Comply with applicable governmental laws, rules and regulations, including the rules,
regulations and policies of public regulatory agencies. |
|
|
|
Act at all times in good faith, responsibly, with due care, and diligence in carrying
out his or her responsibilities. |
|
|
|
Maintain the confidentiality of confidential financial or other information acquired in
the course of employment, except when disclosure is properly authorized or is required by
applicable law or legal process, and not use any such confidential information for personal
advantage. |
|
|
|
Not take any action to coerce, manipulate, mislead or fraudulently influence an
independent accountant or internal auditor engaged in the performance of an audit or review
of Chesapeakes financial statements or accounting books and records, with the purpose of
rendering the financial statements false or misleading. |
|
|
|
Report promptly any violation of this Code of Ethics for Financial Officers either
directly to the Director of Internal Audit or the Chairman of the Audit Committee. |
Any Financial Officer who violates this Code of Ethics for Financial Officers will be subject
to appropriate disciplinary action, including possible termination of employment.
The Audit Committee shall be responsible for overseeing compliance with this Code of Ethics
for Financial Officers and shall direct the investigation of any alleged violation and report its
findings, including any recommended action, to the Board of Directors.
Exhibit 14.2
Exhibit 14.2
BUSINESS CODE OF ETHICS AND CONDUCT
Adopted December 15, 2010
Chesapeake Utilities Corporation (Chesapeake) is committed to conducting its business in
compliance with all applicable laws, rules and regulations and in accordance with the highest
ethical standards. In furtherance of this commitment, the Board of Directors of Chesapeake has
adopted this Business Code of Ethics and Conduct (the Code of Ethics) setting forth the
principles that govern the conduct of all employees, officers and directors of Chesapeake and its
subsidiaries (collectively, the Company).
As used herein, Company official shall mean any officer of the Company. Some provisions of
this Code of Ethics also extend to the family members of employees, officers, directors, or
nominees for director. For this purpose, the term family member shall mean any child, stepchild,
grandchild, parent, stepparent, grandparent, spouse, sibling, mother-in-law, father-in-law,
daughter-in-law, son-in-law, brother-in-law, or sister-in-law, and any person (other than a tenant
or employee) sharing the household of any director, nominee for director, or officer of the
Company. These associations include adoptive relationships.
I. |
|
Compliance with Laws, Rules, Regulations, Policies and Procedures |
Each employee, officer and director is expected to understand and comply with both the letter
and intent of all governmental laws, rules and regulations and with all Company policies and
procedures that apply to matters for which he or she is responsible. All employees and officers
are expected to participate in compliance training and information sessions when offered by the
Company. Any employee or officer who is uncertain as to the meaning or interpretation of any law,
rule, regulation, policy or procedure, or its application to his or her responsibilities, is
expected to seek advice from a supervisor, manager or other appropriate Company official. Any
director who is uncertain as to the meaning or interpretation of any law, rule, regulation, policy
or procedure, or its application to his or her responsibilities, is expected to seek advice from
the Chairman of the Board.
II. |
|
Conflicts of Interest |
In carrying out their responsibilities, all employees, officers and directors have a duty
always to act in the best interests of the Company. The ability of an employee, officer or
director to fulfill this obligation can be compromised if a conflict exists between his or her
personal interests and the interests of the Company. In general, a conflict of interest can arise
whenever the personal interests of an employee, officer or director in a matter (financial or
otherwise) would make it difficult for the individual to perform his or her Company
responsibilities objectively. Even where the outcome of the matter is on terms that are entirely
fair to the Company, the existence of a conflict of interest can create an appearance of
impropriety.
While it is not possible to list all of the situations that could present a conflict of
interest, examples include:
|
|
|
Ownership of a financial interest (other than, in the case of a public company,
the ownership of less than a one percent equity interest) in any business or other
enterprise that does business (whether as a supplier, customer or otherwise), or is
seeking to do business, with the Company. |
|
|
|
Serving as a director, officer or partner of, or in any other managerial role with
respect to, or as a consultant to, any business or other enterprise that does business
(whether as a supplier, customer or otherwise), or is seeking to do business, with the
Company. |
|
|
|
Ownership of a financial interest in (other than, in the case of a public company,
the ownership of less than a one percent equity interest), or serving as a director,
officer or partner of, or in any other managerial role with respect to, or as a
consultant to, any competitor of the Company. |
|
|
|
Acting as a broker, finder or other intermediary for the benefit of a third party
in any transaction involving the Company. |
|
|
|
Any situation where the employee, officer or director will receive any payment of
money, services, loan, guarantee or any other personal benefits from a third party in
anticipation of or as a result of any transaction or business relationship between the
Company and the third party. |
|
|
|
Ownership of a financial interest (other than, in the case of a public company,
the ownership of less than a one percent equity interest) in any business or other
enterprise that does business (whether as a supplier, customer or otherwise), or is
seeking to do business, with any competitor of the Company. |
|
|
|
Serving as a director, officer or partner of, or in any other managerial role with
respect to, or as a consultant to, any business or other enterprise that does business
(whether as a supplier, customer or otherwise), or is seeking to do business, with any
competitor of the Company. |
|
|
|
Taking a public position or making public statements contrary to the best interests
of the Company or that could result in embarrassment to the Company. |
A conflict also can exist where the person doing business, or seeking to do business with the
Company is a family member of an employee, officer or director. However, the acquisition or use by
an employee, officer or director of the Company of products or services obtained from the Company
in the ordinary course of the Companys business will not represent a conflict of interest.
All employees and officers are encouraged to avoid relationships that have the potential for
creating an actual conflict of interest or a perception of a conflict of interest. Employees and
officers must be free of any conflict of interest whenever they act on behalf of the Company,
including engaging in negotiations or recommending or approving a transaction, arrangement or
relationship with an existing or potential customer, supplier, lender or investor. Any officer who
has a conflict of interest with respect to any matter is required to make prompt and full
disclosure of the matter to the Chief Executive Officer or, in the case of the Chief Executive
Officer, to the Audit Committee. All other employees are required to make prompt and full
disclosure of any conflict of interest to the Director of Internal Audit. No employee or officer
is permitted to participate in any matter in which he or she has a conflict of interest unless
authorized by an appropriate Company official and under circumstances that are designed to protect
the interests of the Company and to avoid any appearance of impropriety.
2 of 8
Any officer who has a question as to whether a given situation or relationship might represent
a conflict of interest is required to consult with the Chief Executive Officer. Any other employee
who has a question as to whether a situation or relationship might constitute a conflict is
required to consult with the Director of Internal Audit.
Directors are required to disclose any conflict of interest to the Chairman of the Board of
Directors and to refrain from voting on any matter(s) in which they have a conflict.
III. |
|
Corporate Opportunities |
All business opportunities that are within the existing or reasonably foreseeable scope of the
Companys business, including planned business ventures, are the property of the Company. Without
the prior consent of the Board of Directors, employees, officers and directors are prohibited from:
|
|
|
Taking for themselves personally opportunities that they discovered through the use
of Company property or information or through their position with the Company; |
|
|
|
Using property or information of the Company or their position with the Company for
personal gain; or |
|
|
|
Engaging in any business in competition with the Company. |
Employees, officers, directors and director nominees are required to maintain the
confidentiality of, and not use for personal benefit, confidential information entrusted to them by
the Company, its customers or its suppliers, or otherwise acquired in the course of their
employment by or service to the Company. Disclosure or use of confidential information is permitted
only for a proper business purpose and when specifically authorized by an appropriate Company
official or as required by law or legal proceedings. Confidential information includes all
information protected by law or by an agreement between the Company and a third party, as well as
other non-public information that, if disclosed, might be harmful to the Company or useful to
competitors, including but not limited to:
|
|
|
Trade secrets and other proprietary technical information or data. |
|
|
|
Undisclosed financial and accounting information. |
|
|
|
Strategic information concerning current and future business plans. |
|
|
|
Employee personnel records (e.g., job applications, resumes, performance
evaluations and records, compensation information, notices regarding performance,
termination notices, etc.). |
|
|
|
Research information and records. |
3 of 8
All employees, officers and directors are required to sign a confidentiality statement.
These confidentiality and non-use restrictions continue beyond termination of service for
directors, and termination of employment for employees and officers. Upon termination, employees,
officers and directors are not permitted to take, copy or retain any records or documents of the
Company.
V. |
|
Proper Accounting for Company Transactions |
The maintenance of accurate financial and accounting records is essential in order to enable
the Company to comply with the requirements of the federal securities laws and with its obligations
to its shareholders.
|
A. |
|
Maintenance of Accurate Records |
All Company assets and liabilities and all items of revenue and expense shall be properly
recorded in the Companys regular books and records in accordance with generally accepted
accounting principles. All employees and officers who are responsible for the recording or
reporting of Company property, assets, liabilities, transactions and other activities are required
to provide full, fair, accurate, timely and understandable recording or reporting thereof. Without
limitation of the foregoing:
|
|
|
No undisclosed or unrecorded fund or asset of the Company shall be established or
maintained for any purpose. |
|
|
|
No employee or officer of the Company shall intentionally conceal or fail to record
or report any matter that is required to be recorded or reported. |
|
|
|
No employee or officer of the Company shall improperly record or report any matter,
or improperly alter any record or report of any matter. |
|
B. |
|
Documentation of Disbursement of Funds |
No payment or other disbursement of Company funds shall be made without proper authorization.
No approval shall be granted for the payment or other disbursement of Company funds without
adequate supporting documentation. No payment on behalf of the Company shall be approved or made
with the intention or understanding that any part of such payment is to be used for a purpose other
than that described by the documents supporting the payment.
VI. |
|
Improper Payments and Gifts to Third Parties |
|
A. |
|
Improper Payments and Gifts. |
Except for permitted gifts (as described below), neither the Company nor any employee, officer
or director shall, either directly or indirectly, authorize or make any payment or gift of money or
any other thing of value (including materials, equipment, facilities or services) to any:
|
|
|
Current or prospective customer, supplier or competitor of the Company or to
government officials; or |
4 of 8
|
|
|
Any director, officer, employee, general partner, stockholder or owner of a current or
prospective customer, supplier or competitor, |
if the purpose of the payment or the gift is to induce the current or prospective customer,
supplier, competitor or government official improperly to grant or convey any benefit to, or forgo
any claim against, the Company or any of its employees, officers or directors, or otherwise to
influence a business or other decision of the current or prospective customer, supplier, competitor
or government official.
An employee, officer or director may make gifts, generally in the form of meals, entertainment
or specialty advertising items, to Company customers, suppliers or other third parties engaged, or
that may become engaged, in business with the Company if the gift meets all of the following
criteria:
|
|
|
It is consistent with customary business practices; |
|
|
|
It is not for an improper purpose; |
|
|
|
It is not in contravention of any applicable laws, rules, regulations or ethical
standards; and |
|
|
|
Public disclosure of the full details of the gift would not cause embarrassment to
the Company. |
VII. |
|
Acceptance of Gifts or Other Personal Benefits |
No employee, officer or director shall solicit from any supplier, customer or other person
doing business, or seeking to do business, with the Company any gift of money, products or
services, gratuity, loans or guarantees, or other personal benefits of any kind.
An employee, officer or director, including their family members, may accept an unsolicited
gift or gratuity of nominal value or reasonable business entertainment (including recreation and
attendance of sporting or cultural events) if the gift or gratuity meets all of the following
criteria:
|
|
|
It does not go beyond common courtesies usually associated with accepted business
practices; |
|
|
|
It does not interfere with the recipients independence or judgment in carrying out
his or her responsibilities on behalf of the Company; and |
|
|
|
Public disclosure of the full details of the gift or gratuity would not cause
embarrassment to the Company. |
Any gifts or gratuity that do not meet these requirements must to the extent possible
be returned.
5 of 8
VIII. |
|
Relationships with Customers |
|
|
|
When dealing with customers, the Company is committed to: |
|
|
|
Providing all customers with exceptional service; |
|
|
|
Dealing fairly and ethically with all customers and treating customers with respect; |
|
|
|
Providing customers with accurate and clear information regarding the services
offered by the Company; and |
|
|
|
Investigating promptly and resolving on fair terms all customer complaints and
inquiries. |
Each employee, officer and director has a responsibility to use his or her best efforts to
ensure that these objectives are attained. The Company prohibits manipulation, misrepresentation of
facts, and other forms of unfair dealing with customers.
IX. |
|
Relationships with Suppliers |
When dealing with suppliers of products and services to the Company, all employees, officers
and directors are required at all times to act in the best interests of the Company, while at the
same time adhering to the highest standards of ethical conduct. All unlawful behavior,
manipulation, misrepresentation of facts, or any other forms of unfair dealing are prohibited.
The Company is committed to fair and honest competition. The Company seeks to achieve its
competitive advantage through competitive prices, products and services, and not through illegal or
unethical business practices. All employees, officers and directors are required to adhere to all
laws and regulations regarding fair competition, including antitrust laws. Misappropriation of
trade secrets or other proprietary information, manipulation, misrepresentation of facts and all
other forms of unfair dealing are prohibited.
XI. |
|
Relationships with Employees |
All employees and officers are entitled to work in an environment free of discrimination and
harassment, therefore the Company strives to provide each employee and officer with a workplace
that is free from unlawful discrimination or harassment. It is the policy of the Company to
provide equal employment opportunity to qualified individuals regardless of race, religion, gender,
national origin, age, or their status as disabled veterans or as disabled individuals. Equal
opportunity applies to all aspects of the employment relationship, including initial employment,
promotion, training, wage and salary administration, seniority, retirement, and employee benefits.
6 of 8
XII. |
|
Protection and Proper Use of Company Assets |
Proper protection and proper use of Company assets is the responsibility of each employee,
officer and director. Employees, officers and directors are required to promote the efficient use
of Company assets and to take appropriate security measures to safeguard physical property and
other assets against unauthorized use or removal, as well as against loss by wrongful acts or
negligence. Employees, officers and directors may use Company property only for legitimate
business purposes and strictly in accordance with established Company policies and guidelines.
All employees, officers and directors are required to adhere to the Companys policy entitled
Securities Trades by Company Personnel, which governs trading by employees, officers and
directors in Chesapeake stock.
XIV. |
|
Political Activities |
Employees, officers and directors are free to participate in lawful political activities on
their own time and at their own expense, and to make personal contributions to political parties,
committees or candidates of their choice. However, under no circumstances shall an employee,
officer or director use Company facilities or assets, or be compensated or reimbursed by the
Company, for their personal political activities or contributions.
While employees and officers are encouraged to participate in civic and community activities
during their non-work hours, an employees or officers determination to seek elected or appointed
public office, including membership on a public board or commission (public office), raises
special concerns. Because the Companys business frequently interfaces with many government
branches, employees, officers and directors would have a responsibility to disqualify themselves
from any action in which they know the Company has an interest. In addition, care must be taken
that campaigning for office or fulfilling public responsibilities is not done during work hours.
Accordingly, any employee or officer who wishes to seek or accept public office must provide the
Director of Internal Audit with reasonable advance notice of that intent. In certain cases,
depending on the nature of the office and other surrounding circumstances, the Company may decide
that the employee or officer should not seek or accept such office while remaining in the Companys
employment without a determination by the Companys Chief Executive Officer (or in the case of the
Chief Executive Officer, the Board of Directors) that such activities will be consistent with
Company policies and applicable laws and standards.
XV. |
|
Compliance Procedures |
|
A. |
|
Distribution of this Code of Ethics |
A copy of this Code of Ethics shall be furnished to each employee, officer and director of the
Company and shall be posted on the Companys website
(www.chpk.com). Company officers are required
to ensure that all Company personnel in the departments for which they are responsible receive a
copy.
7 of 8
Any employee who has a question concerning the interpretation or application of any provision
of this Code of Ethics should consult his or her immediate manager, who may, if necessary, refer
the question to the Director of Internal Audit or an appropriate Company official. Alternatively,
any employee, officer or director may contact the Director of Internal Audit directly.
Any employee or officer who has knowledge of a violation by the Company or any employee,
officer or director of any law, rule or regulation or this Code of Ethics, or suspects that such a
violation has occurred, is required to report the matter to an independent third party via a
dedicated toll-free hotline or a secure website, or in written form directly to the Director of
Internal Audit in accordance with the process set forth on the
Companys website (www.chpk.com).
All valid concerns will be investigated under the direction of the Chairman of the Audit Committee.
The Company will make every effort, within the limits allowed by law, to keep confidential the
identity of anyone requesting guidance or reporting a violation or suspected violation. However, it
may not be possible to maintain the confidentiality of the reported person or the reported
information if (i) disclosure is necessary to enable the Company or law enforcement officials to
investigate the matter, (ii) disclosure is required by law or (iii) the person accused of a
violation is entitled to the information as a matter of legal right. All employees, officers and
directors are expected to cooperate, to the extent requested, in any investigation of any violation
of any law, rule or regulation or this Code of Ethics.
No adverse action will be taken against any person who in good faith reports a violation, or a
suspected violation, by the Company, or any employee, officer or director of any law, rule or
regulation or this Code of Ethics. Any such retaliation is also a violation of this Code of Ethics
and will be grounds for disciplinary action against the person or persons who engage in
retaliation. Any employee, officer or director who believes that he or she has been retaliated
against may file a complaint with the Director of Internal Audit, who shall be responsible for the
investigation of the matter.
Any employee, officer or director who fails to comply with any applicable law, rule, or
regulation or with this Code of Ethics is subject to disciplinary action, which could include,
without limitation, a reprimand, probation, suspension, reduction in salary, demotion or dismissal
depending upon the seriousness of the offense.
XVI. |
|
Amendments and Waivers |
The Board of Directors must approve any amendment to this Code of Ethics. No waivers or exceptions
to this Code of Ethics are anticipated; however, any waiver of any provision to this Code of Ethics
for employees, other than executive officers, requires the approval of the Chief Executive Officer.
Any waiver involving an executive officer or director requires the approval of the Board of
Directors or a designated Board Committee and must be promptly disclosed to shareholders within
four business days of such determination in a press release, by website disclosure, or by filing a
current report on Form 8-K with the Securities and Exchange Commission.
8 of 8
Exhibit 21
Exhibit 21
Chesapeake Utilities Corporation
Subsidiaries of the Registrant
|
|
|
Subsidiaries
|
|
State Incorporated |
Eastern Shore Natural Gas Company
|
|
Delaware |
Sharp Energy, Inc.
|
|
Delaware |
Chesapeake Service Company
|
|
Delaware |
Xeron, Inc.
|
|
Mississippi |
Chesapeake OnSight Services, LLC
|
|
Delaware |
Peninsula Energy Services Company, Inc.
|
|
Delaware |
Peninsula Pipeline Company, Inc.
|
|
Delaware |
Florida Public Utilities Company
|
|
Florida |
|
|
|
Subsidiaries of Sharp Energy, Inc.
|
|
State Incorporated |
Sharpgas, Inc.
|
|
Delaware |
|
|
|
Subsidiaries of Florida Public Utilities Company
|
|
State Incorporated |
Flo-Gas Corporation
|
|
Florida |
|
|
|
Subsidiaries of Chesapeake Service Company
|
|
State Incorporated |
Skipjack, Inc.
|
|
Delaware |
BravePoint, Inc.
|
|
Georgia |
Chesapeake Investment Company
|
|
Delaware |
Eastern Shore Real Estate, Inc.
|
|
Delaware |
Exhibit 23.1
Exhibit 23.1
Consent of Independent Registered Public Accounting Firm
Chesapeake Utilities Corporation
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3
(Nos. 333-156192, 333-63381 and 333-121524) and Form S-8 (Nos. 333-01175, 333-94159, 333-124646, 333-124694 and 333-124717) of Chesapeake Utilities Corporation of our reports
dated March 8, 2011, relating to the consolidated financial statements, financial statement schedules, and the effectiveness of Chesapeake Utilities Corporations internal control over financial
reporting, which appear in this Form 10-K.
|
|
|
/s/ ParenteBeard LLC
ParenteBeard LLC
|
|
|
Malvern, Pennsylvania |
|
|
March 8, 2011 |
|
|
Exhibit 31.1
Exhibit 31.1
CERTIFICATE PURSUANT TO RULE 13A-14(A) AND 15D-14(A)
UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Michael P. McMasters, certify that:
1. |
|
I have reviewed this annual report on Form 10-K of Chesapeake Utilities Corporation; |
2. |
|
Based on my knowledge, this report does not contain any untrue statement of a material fact
or omit to state a material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with respect to the period
covered by this report; |
3. |
|
Based on my knowledge, the financial statements, and other financial information included in
this report, fairly present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods presented in this
report; |
4. |
|
The registrants other certifying officer(s) and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a15(e)
and 15d15(e)) and internal control over financial reporting (as defined in Exchange Act
Rules 13a-15(f) and 15d-15(f)) for the registrant and we have: |
|
a) |
|
designed such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure that material
information relating to the registrant, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly during the period in
which this report is being prepared; |
|
|
b) |
|
designed such internal control over financial reporting, or caused such
internal control over financial reporting to be designed under our supervision, 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; |
|
|
c) |
|
evaluated the effectiveness of the registrants disclosure controls and
procedures and presented in this report our conclusions about the effectiveness of the
disclosure controls and procedures, as of the end of the period covered by this report
based on such evaluations; and |
|
|
d) |
|
disclosed in this report any change in the registrants internal control over
financial reporting that occurred during the registrants most recent fiscal quarter
(the registrants fourth fiscal quarter in the case of an annual report) that has
materially affected, or is reasonably likely to materially affect, the registrants
internal control over financial reporting; and |
5. |
|
The registrants other certifying officer(s) and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrants auditors and the
audit committee of the registrants board of directors (or persons performing the equivalent
functions): |
|
a) |
|
all significant deficiencies and material weaknesses in the design or operation
of internal control over financial reporting which are reasonably likely to adversely
affect the registrants ability to record, process, summarize and report financial
information; and |
|
|
b) |
|
any fraud, whether or not material, that involves management or other employees
who have a significant role in the registrants internal control over financial
reporting. |
Date: March 8, 2011
|
|
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/s/ Michael P. McMasters
Michael P. McMasters
|
|
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President and Chief Executive Officer |
|
|
Exhibit 31.2
Exhibit 31.2
CERTIFICATE PURSUANT TO RULE 13A-14(A) AND 15D-14(A)
UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Beth W. Cooper, certify that:
1. |
|
I have reviewed this annual report on Form 10-K of Chesapeake Utilities Corporation; |
2. |
|
Based on my knowledge, this report does not contain any untrue statement of a material fact
or omit to state a material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with respect to the period
covered by this report; |
3. |
|
Based on my knowledge, the financial statements, and other financial information included in
this report, fairly present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods presented in this
report; |
4. |
|
The registrants other certifying officer(s) and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a15(e)
and 15d15(e)) and internal control over financial reporting (as defined in Exchange Act
Rules 13a-15(f) and 15d-15(f)) for the registrant and we have: |
|
a) |
|
designed such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure that material
information relating to the registrant, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly during the period in
which this report is being prepared; |
|
|
b) |
|
designed such internal control over financial reporting, or caused such
internal control over financial reporting to be designed under our supervision, 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; |
|
|
c) |
|
evaluated the effectiveness of the registrants disclosure controls and
procedures and presented in this report our conclusions about the effectiveness of the
disclosure controls and procedures, as of the end of the period covered by this report
based on such evaluations; and |
|
|
d) |
|
disclosed in this report any change in the registrants internal control over
financial reporting that occurred during the registrants most recent fiscal quarter
(the registrants fourth fiscal quarter in the case of an annual report) that has
materially affected, or is reasonably likely to materially affect, the registrants
internal control over financial reporting; and |
5. |
|
The registrants other certifying officer(s) and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrants auditors and the
audit committee of the registrants board of directors (or persons performing the equivalent
functions): |
|
a) |
|
all significant deficiencies and material weaknesses in the design or operation
of internal control over financial reporting which are reasonably likely to adversely
affect the registrants ability to record, process, summarize and report financial
information; and |
|
|
b) |
|
any fraud, whether or not material, that involves management or other employees
who have a significant role in the registrants internal control over financial
reporting. |
Date:
March 8, 2011
|
|
|
/s/ Beth W. Cooper
Beth W. Cooper
|
|
|
Senior Vice President and Chief Financial Officer |
|
|
Exhibit 32.1
Exhibit 32.1
CERTIFICATE OF CHIEF EXECUTIVE OFFICER
OF CHESAPEAKE UTILITIES CORPORATION
PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED
PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
I, Michael, P. McMasters, President and Chief Executive Officer of Chesapeake Utilities
Corporation, certify that, to the best of my knowledge, the Annual Report on Form 10-K of
Chesapeake Utilities Corporation (Chesapeake) for the year ended December 31, 2010, filed with
the Securities and Exchange Commission on the date hereof (i) fully complies with the requirements
of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the
information contained therein fairly presents, in all material respects, the financial condition
and results of operations of Chesapeake.
|
|
|
|
|
|
/s/ Michael P. McMasters
|
|
|
Michael P. McMasters March 8, 2011 |
|
A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of
2002, or other document authenticating, acknowledging, or otherwise adopting the signature that
appears in typed form within the electronic version of this written statement required by Section
906, has been provided to Chesapeake Utilities Corporation and will be retained by Chesapeake
Utilities Corporation and furnished to the Securities and Exchange Commission or its staff upon
request.
Exhibit 32.2
Exhibit 32.2
CERTIFICATE OF CHIEF FINANCIAL OFFICER
OF CHESAPEAKE UTILITIES CORPORATION
PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED
PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
I, Beth W. Cooper, Senior Vice President and Chief Financial Officer of Chesapeake Utilities
Corporation, certify that, to the best of my knowledge, the Annual Report on Form 10-K of
Chesapeake Utilities Corporation (Chesapeake) for the year ended December 31, 2010, filed with
the Securities and Exchange Commission on the date hereof (i) fully complies with the requirements
of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the
information contained therein fairly presents, in all material respects, the financial condition
and results of operations of Chesapeake.
|
|
|
|
|
|
/s/ Beth W. Cooper
|
|
|
Beth W. Cooper March 8, 2011 |
|
A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of
2002, or other document authenticating, acknowledging, or otherwise adopting the signature that
appears in typed form within the electronic version of this written statement required by Section
906, has been provided to Chesapeake Utilities Corporation and will be retained by Chesapeake
Utilities Corporation and furnished to the Securities and Exchange Commission or its staff upon
request.