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 |
% |
|
|
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) |
|
Local distribution companies |
|
$ |
20,441 |
|
|
|
76 |
% |
|
|
10,848,108 |
|
|
|
62 |
% |
Industrial |
|
|
4,864 |
|
|
|
18 |
% |
|
|
4,794,442 |
|
|
|
27 |
% |
Commercial |
|
|
1,571 |
|
|
|
6 |
% |
|
|
1,962,890 |
|
|
|
11 |
% |
Other (1) |
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|
41 |
|
|
|
0 |
% |
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|
|
|
|
|
|
|
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|
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Subtotal |
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|
26,917 |
|
|
|
100 |
% |
|
|
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 |
|
$ |
14,014 |
|
|
|
52 |
% |
|
|
11,752,357 |
|
|
|
67 |
% |
|
|
|
|
|
|
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|
|
|
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|
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|
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|
(1) |
|
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 |
|
|
|
439 |
|
|
|
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 |
< |