Chesapeake Utilities Corporation Annual Report on Form 10-K - FY Ended December
31, 2006
UNITED
STATES
|
SECURITIES
AND EXCHANGE COMMISSION
|
Washington,
D.C. 20549
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|
|
|
FORM
10-K
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|
ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF
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THE
SECURITIES EXCHANGE ACT OF 1934
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For
the Fiscal Year Ended: December 31, 2006
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|
Commission
File Number: 001-11590
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Chesapeake
Utilities Corporation
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(Exact
name of registrant as specified in its
charter)
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State
of Delaware
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51-0064146
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(State
or other jurisdiction of
|
(I.R.S.
Employer
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incorporation
or organization)
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Identification
No.)
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909
Silver Lake Boulevard, Dover, Delaware
19904
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(Address
of principal executive offices, including zip
code)
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302-734-6799
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(Registrant’s
telephone number, including area code)
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|
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
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Common
Stock - par value per share $.4867
|
New
York Stock Exchange, Inc.
|
Securities
registered pursuant to Section 12(g) of the
Act:
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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 [ ]. No
[X].
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 [ ]. No
[X].
Indicate
by check mark whether the registrant (1) has filed all reports required
to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the
preceding 12 months (or for such shorter period that the registrant was
required
to file such reports), and (2) has been subject to such filing requirements
for
the past 90 days. Yes [X]. No [ ].
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the
best
of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendments
to
this Form 10-K. [X]
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of “accelerated
filer
and large accelerated filer”
in Rule 12b-2 of
the Exchange Act. (Check one):
Large
accelerated filer [
]
Accelerated filer
[X]
Non-accelerated filer [ ]
Indicate
by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Act). Yes [ ]. No
[X].
The
aggregate market value of the common shares held by non-affiliates of Chesapeake
Utilities Corporation as of June 30, 2006, 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 $179.2
million.
As
of
March 8, 2007, 6,717,348 shares of common stock were outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions
of the Proxy Statement for the 2007 Annual Meeting of Stockholders are
incorporated by reference in Part III.
Chesapeake
Utilities Corporation
Form
10-K
YEAR
ENDED DECEMBER 31, 2006
TABLE
OF CONTENTS
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Page
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Part I |
1
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Item
1. Business
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1
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Item
1A. Risk Factors
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8
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Item
1B. Unresolved Staff Comments
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12
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Item
2. Properties
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12
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Item
3. Legal Proceedings
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12
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Item
4. Submission of Matters to a Vote of Security Holders
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12
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Part II |
13
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Item
5. Market for the Registrant's Common Equity, Related Stockholder
Matters
and Issuer Purchases of Equity Securities
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13
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Item
6. Selected Financial Data
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16
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Item
7. Management's Discussion and Analysis of Financial Condition
and Results
of Operations
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20
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Item
7A. Quantitative and Qualitative Disclosures About Market Risk
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45
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Item
8. Financial Statements and Supplementary Data
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45
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Item
9. Changes In and Disagreements With Accountants on Accounting
and
Financial Disclosure
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76
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Item
9A. Controls and Procedures
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76
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Item
9B. Other Information
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76
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Part III |
77
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Item
10. Directors, Executive Officers of the Registrant and Corporate
Governance
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77
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Item
11. Executive Compensation
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77
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Item
12. Security Ownership of Certain Beneficial Owners and Management
and
Related Stockholder Matters
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77
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Item
13. Certain Relationships and Related Transactions, and Director
Independence
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78
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Item
14. Principal Accounting Fees and Services
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78
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Part IV |
79
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Item
15. Exhibits, Financial Statement Schedules
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79
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Signatures |
83
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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.
Safe
Harbor for Forward-Looking Statements
Chesapeake
Utilities Corporation has made statements in this Form 10-K that are considered
to be “forward-looking statements” within the meaning of the Private Securities
Litigation Reform Act of 1995. These statements are not matters of historical
fact and are typically identified by words such as, but not limited to,
“believes,” “expects,” “intends,” “plans,” and similar expressions, or future or
conditional verbs such as “may,” “will,” “should,” “would,” and “could”. These
statements relate to matters such as customer growth, changes in revenues or
gross margins, capital expenditures, environmental remediation costs, regulatory
trends and decisions, market risks associated with our propane operations,
the
competitive position of the Company and other matters. It is important to
understand that these forward-looking statements are not guarantees, but are
subject to certain risks and uncertainties and other important factors that
could cause actual results to differ materially from those in the
forward-looking statements. The factors that could cause actual results to
differ materially from the Company’s expectations include, but are not limited
to those discussed in Item 1A “Risk Factors.”
Item
1. Business.
(a) |
General
Development of Business
|
Chesapeake
is a diversified utility company engaged directly or through subsidiaries in
natural gas distribution, transmission and marketing, propane distribution
and
wholesale marketing, advanced information services and other related businesses.
Chesapeake is a Delaware corporation that was formed in 1947.
Chesapeake’s
three natural gas distribution divisions serve approximately 59,100 residential,
commercial and industrial customers in central and southern Delaware, Maryland’s
Eastern Shore and parts of Florida. The Company’s natural gas transmission
subsidiary, Eastern Shore Natural Gas Company (“Eastern Shore” or “ESNG”),
operates a 366-mile interstate pipeline system that transports gas from various
points in Pennsylvania to the Company’s Delaware and Maryland distribution
divisions, as well as to other utilities and industrial customers in southern
Pennsylvania, Delaware and on the Eastern Shore of Maryland. Our propane
distribution operation serves approximately 33,300 customers in central and
southern Delaware, the Eastern Shore of Maryland and Virginia, southeastern
Pennsylvania, and parts of Florida. The advanced information services segment
provides domestic and international clients with information technology related
business services and solutions for both enterprise and e-business
applications.
(b) |
Financial
Information about Industry
Segments
|
Financial
information by business segment is included in Item 8 under the heading “Notes
to Consolidated Financial Statements — Note C.”
(c) |
Narrative
Description of Business
|
Chesapeake
is engaged in three primary business activities: natural gas distribution,
transmission and marketing, propane distribution and wholesale marketing and
advanced information services. In addition to the primary groups, Chesapeake
has
subsidiaries in other related businesses.
(i)
(a) Natural Gas Distribution, Transmission and
Marketing
General
Chesapeake
distributes natural gas to residential, commercial and industrial customers
in
central and southern Delaware, the Salisbury and Cambridge, Maryland areas
on
Maryland’s Eastern Shore and parts of Florida. These activities are conducted
through three utility divisions, one division in Delaware, another in Maryland
and a third division in Florida. The Company also offers natural gas supply
and
supply management services in the state of Florida through its subsidiary,
Peninsula Energy Services Company, Inc. (“PESCO”).
Delaware
and Maryland.
Chesapeake’s Delaware and Maryland utility divisions serve approximately 45,400
customers, of which approximately 45,200 are residential and commercial
customers purchasing gas primarily for heating purposes. The remaining customers
are industrial. For the year 2006, residential and commercial customers
accounted for approximately 77% of the volume delivered by the divisions and
75%
of the divisions’ revenue.
Florida.
The
Florida division distributes natural gas to approximately 13,630 residential
and
commercial and 100 industrial customers in the 13 Counties of Polk, Osceola,
Hillsborough, Gadsden, Gilchrist, Union, Holmes, Jackson, Desoto, Suwannee,
Liberty, Washington and Citrus. Currently, the industrial customers, which
purchase and transport gas on a firm basis, account for approximately 92% of
the
volume delivered by the Florida division and 43% of the revenues. These
customers are primarily engaged in the citrus and phosphate industries and
in
electric cogeneration.
PESCO
provides natural gas supply and supply management services to commercial and
industrial end users in Florida. During 2005, Chesapeake formed a wholly owned
subsidiary, Peninsula Pipeline Company, Inc. to provide natural gas
transportation services to industrial customers by an intra-state pipeline.
Eastern
Shore.
The
Company’s wholly owned transmission subsidiary, Eastern Shore, owns and operates
an interstate natural gas pipeline and provides open access transportation
services for affiliated and non-affiliated companies through an integrated
gas
pipeline extending from southeastern Pennsylvania through Delaware to its
terminus on the Eastern Shore of Maryland. Eastern Shore also provides swing
transportation service and contract storage services. Eastern Shore’s rates and
services are subject to regulation by the Federal Energy Regulatory Commission
(“FERC”).
Adequacy
of Resources
General.
The
Delaware and Maryland divisions have both firm and interruptible contracts
with
four interstate “open access” pipelines including Eastern Shore. The divisions
are directly interconnected with Eastern Shore and services upstream of Eastern
Shore are contracted with Transcontinental Gas Pipeline Corporation (“Transco”),
Columbia Gas Transmission Corporation (“Columbia”) and Columbia Gulf
Transmission Company (“Gulf”). None of the upstream service providers are
affiliates of the Company. The divisions use their firm transportation supply
resources to meet a significant percentage of their projected demand
requirements. In order to meet the difference between firm supply and firm
demand, the divisions purchase natural gas supply on the spot market from
various suppliers. This gas is transported by the upstream pipelines and
delivered to the divisions’ interconnects with Eastern Shore. The divisions also
have the capability to use propane-air peak-shaving to supplement or displace
the spot market purchases. The Company believes that the availability of gas
supply and transportation to the Delaware and Maryland divisions is adequate
under existing arrangements to meet the anticipated needs of their
customers.
Delaware.
The
Delaware division’s contracts with Transco include: (a) firm transportation
capacity of 9,029 dekatherms (“Dt”) per day, with provisions to continue from
year to year, subject to 180 days notice for termination; (b) firm
transportation capacity of 311 Dt per day for December through February, with
provisions to continue such contract on a year to year basis, subject to 180
days notice for termination; (c) firm transportation capacity of 174 Dt per
day,
which expires in 2008; (d) firm transportation capacity of 1,842 Dt, which
expires in 2009; (e) firm storage service, providing a peak day entitlement
of
1,680 Dt and a total capacity of 142,830 Dt, with provisions to continue such
contract on a year to year basis, subject to 180 days notice for termination;
and (f) firm storage service, providing a peak day entitlement of 1,786 Dt
and a
total capacity of 17,967 Dt, which expires in 2013.
The
Delaware division’s contracts with Columbia include: (a) firm transportation
capacity of 880 Dt per day, which expires in 2014; (b) firm transportation
capacity of 1,132 Dt per day, which expires in 2017; (c) firm transportation
capacity of 549 Dt per day, which expires in 2018; (d) firm transportation
capacity of 899 per day, which expires in 2019; (e) firm storage service
providing a peak day entitlement of 6,193 Dt and a total capacity of 298,195
Dt,
which expires in 2015; (f) firm storage service, providing a peak day
entitlement of 635 Dt and a total capacity of 57,139 Dt, which expires in 2018;
(g) firm storage service providing a peak day entitlement of 583 Dt and a total
capacity of 52,460 Dt, which expires in 2019; (h) firm storage service providing
a peak day entitlement of 583 Dt and a total capacity of 52,460 Dt, which
expires in 2020; (i) firm storage service providing a peak day entitlement
of 15
Dt and a total capacity of 1,350 Dt, which expires in 2018; and (j) firm storage
service providing a peak day entitlement of 215 Dt and a total capacity of
10,646 Dt, which expires in 2010. Delaware’s contracts with Columbia for
storage-related transportation provide quantities that are equivalent to the
peak day entitlement for the period of October through March and are equivalent
to fifty percent (50%) of the peak day entitlement for the period of April
through September. The terms of the storage-related transportation contracts
mirror the storage services that they support.
The
Delaware division’s contract with Gulf, which expires in 2009, provides firm
transportation capacity of 880 Dt per day for the period November through March
and 809 Dt per day for the period April through October.
The
Delaware division’s contracts with Eastern Shore include: (a) firm
transportation capacity of 53,637 Dt per day for the period December through
February, 52,415 Dt per day for the months of November, March and April, and
43,339 Dt per day for the period May through October, with various expiration
dates ranging from 2007 to 2017; (b) firm storage capacity providing a peak
day
entitlement of 2,655 Dt and a total capacity of 131,370 Dt, which expires in
2013; (c) firm storage capacity providing a peak day entitlement of 580 Dt
and a
total capacity of 29,000 Dt, which expires in 2013; (d) firm storage capacity
providing a peak day entitlement of 911 Dt and a total capacity of 5,708 Dt,
with provisions to continue such contract on a year to year basis, subject
to
180 days notice for termination.
The
Delaware division currently has contracts for the purchase of firm natural
gas
supply with several suppliers. These supply contracts provide the availability
of a maximum firm daily entitlement of 37,500 Dt and delivered on Transco,
Columbia, and/or Gulf systems to Eastern Shore for redelivery under firm
transportation contracts. The gas purchase contracts have various expiration
dates and daily quantities may vary from day to day and month to
month.
Maryland.
The
Maryland division’s contracts with Transco include: (a) firm transportation
capacity of 4,738 Dt per day, with provisions to continue such contract on
a
year to year basis, subject to 180 days notice for termination; (b) firm
transportation capacity of 155 Dt per day for December through February, with
provisions to continue such contract on a year to year basis, subject to 180
days notice for termination; (c) firm transportation capacity of 973 Dt, which
expires in 2009; (d) firm storage service providing a peak day entitlement
of
390 Dt and a total capacity of 33,120 Dt, with provisions to continue such
contract on a year to year basis, subject to 180 days notice for termination
;
and (e) firm storage service, providing a peak day entitlement of 546 Dt and
a
total capacity of 5,489 Dt, which expires in 2013.
The
Maryland division’s contracts with Columbia include: (a) firm transportation
capacity of 442 Dt per day, which expires in 2014; (b) firm transportation
capacity of 908 Dt per day, which expires in 2017; (c) firm transportation
capacity of 350 Dt per day, which expires in 2018; (d) firm storage service
providing a peak day entitlement of 3,142 Dt and a total capacity of 154,756
Dt,
which expires in 2015; (e) firm storage service providing a peak day entitlement
of 521 Dt and a total capacity of 46,881 Dt, which expires in 2018; and (f)
firm
transportation capacity of 1,832 Dt per day for the period April through
September. The Maryland division’s contracts with Columbia for storage-related
transportation provide quantities that are equivalent to the peak day
entitlement for the period October through March and are equivalent to fifty
percent (50%) of the peak day entitlement for the period April through
September. The terms of the storage-related transportation contracts mirror
the
storage services that they support.
The
Maryland division’s contract with Gulf, which expires in 2009, provides firm
transportation capacity of 590 Dt per day for the period November through March
and 543 Dt per day for the period April through October.
The
Maryland division’s contracts with Eastern Shore include: (a) firm
transportation capacity of 18,982 Dt per day for the period December through
February, 18,254 Dt per day for the months of November, March and April and
13,674 Dt per day for the period May through October, with various expiration
dates ranging from 2007 to 2015; (b) firm storage capacity providing a peak
day
entitlement of 1,428 Dt and a total capacity of 70,665 Dt, which expires in
2013; (c) firm storage capacity providing a peak day entitlement of 309 Dt
and a
total capacity of 15,500 Dt, which expires in 2013; and (d) firm storage
capacity providing a peak day entitlement of 569 Dt and a total capacity of
3,560 Dt, with provisions to continue such contract on a year to year basis,
subject to 180 days notice for termination.
The
Maryland division currently has contracts for the purchase of firm natural
gas
supply with several suppliers. These supply contracts provide the availability
of a maximum form daily entitlement of 11,500 Dt delivered on Transco, Columbia,
and/or Gulf systems to Eastern Shore for redelivery under the Maryland
division’s transportation contracts. The gas purchase contracts have various
expiration dates and daily quantities may vary from day to day and month to
month.
Florida.
The
Florida division receives natural gas from Florida Gas Transmission Company
(“FGT”) and Gulfstream Natural Gas System (“Gulfstream”). The Florida division
has firm transportation agreements with both of these interstate pipelines.
All
of the capacity under these agreements has been released to various third
parties and PESCO, our natural gas marketing subsidiary. Under terms of these
capacity release agreements, Chesapeake is contingently liable to FGT and
Gulfstream should the party that acquired the capacity through release fail
to
pay for the service.
Chesapeake’s
contracts with FGT include transportation service for: (a) daily firm
transportation capacity of 27,519 Dt in November through April; 21,123 Dt in
May
through September, and 27,105 Dt in October, which expires in 2010; and (b)
daily firm transportation capacity of 1,000 Dt daily, which expires in 2015.
Chesapeake’s
contracts with Gulfstream include transportation service for daily firm
transportation capacity of 10,000 Dt daily. The contract with Gulfstream expires
May 31, 2022.
PESCO
currently has contracts with Eagle Energy Partners and Prior Energy for the
purchase of firm natural gas supply. The Eagle Energy Partners’ contract
provides the availability of a maximum firm daily entitlement of 10,000 MMBtus
and has an expiration date of May 2007. The Prior Energy contract provides
the
availability of a maximum firm daily entitlement of 7,500 MMBtus and has an
expiration date of May 2007.
Eastern
Shore.
Eastern
Shore also has contracts with Transco for: (a) 7,046 Mcf of firm peak day
storage entitlements and total storage capacity of 278,264 Mcf, which expires
in
2013.
Eastern
Shore has retained the firm transportation capacity and firm storage services
described above in order to provide swing transportation service and storage
service to those customers that requested such service.
Competition
See
discussion on competition in Item 7 under the heading “Management’s Discussion
and Analysis — Competition.”
Rates
and Regulation
General.
Chesapeake’s
natural gas distribution divisions are subject to regulation by the Delaware,
Maryland and Florida Public Service Commissions with respect to various aspects
of the business, including the rates for sales and transportation to all
customers in each respective jurisdiction. All of Chesapeake’s firm distribution
sales rates are subject to gas cost recovery mechanisms, which match revenues
with gas costs and normally allow eventual full recovery of gas costs.
Adjustments under these mechanisms, which are limited to gas costs, require
periodic filings and hearings with the relevant regulatory
authority.
Eastern
Shore is subject to regulation by the FERC as an interstate pipeline. The FERC
regulates the provision of service, terms and conditions of service, and the
rates Eastern Shore can charge for its transportation and storage services.
Management
monitors the achieved rate of return in each jurisdiction in order to ensure
the
timely filing of rate cases.
Regulatory
Proceedings
See
discussion of regulatory activities in Item 7 under the heading “Management’s
Discussion and Analysis — Regulatory Activities.”
(i)
(b) Propane Distribution and Wholesale Marketing
General
Chesapeake’s
propane distribution group consists of (1) Sharp Energy, Inc. (“Sharp Energy”),
a wholly owned subsidiary of Chesapeake, (2) Sharpgas, Inc. (“Sharpgas”), a
wholly owned subsidiary of Sharp Energy, and (3) Tri-County Gas Co.,
Incorporated (“Tri-County”), a wholly owned subsidiary of Sharp Energy. The
propane wholesale marketing group consists of Xeron, Inc. (“Xeron”), a wholly
owned subsidiary of Chesapeake.
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 energy. Propane is sold primarily in
suburban and rural areas, which are not served by natural gas distributors.
Demand is typically much higher in the winter months and is significantly
affected by seasonal variations, particularly the relative severity of winter
temperatures, because of its use in residential and commercial
heating.
During
2006, our propane distribution operations served approximately 33,300 propane
customers on the Delmarva Peninsula, southeastern Pennsylvania and in Florida
and delivered approximately 24.2 million retail and wholesale gallons of
propane.
In
May
1998, Chesapeake acquired Xeron, a natural gas liquids trading company located
in Houston, Texas. Xeron markets propane to large independent and petrochemical
companies, resellers and southeastern retail propane companies in the United
States. Additional information on Xeron’s trading and wholesale marketing
activities, market risks and the controls that limit and monitor the risks
are
included in Item 7 under the heading “Management’s Discussion and Analysis —
Market Risk.”
The
propane distribution business is affected by many factors, such as seasonality,
the absence of price regulation, and competition among local providers. The
propane wholesale marketing business is affected by wholesale price volatility
and the supply and demand for propane at a wholesale level.
Adequacy
of Resources
The
Company’s propane distribution operations purchase propane primarily from
suppliers, including major oil companies and independent producers of natural
gas liquids. Supplies of propane from these and other sources are readily
available for purchase by the Company. Supply contracts generally include
minimum (not subject to take-or-pay premiums) and maximum purchase
provisions.
The
Company’s propane distribution operations use trucks and railroad cars to
transport propane from refineries, natural gas processing plants or pipeline
terminals to its bulk storage facilities. From these facilities, propane is
delivered primarily by “bobtail” trucks, owned and operated by the Company, to
tanks located at the customer’s premises.
Xeron
does not own physical storage facilities or equipment to transport propane;
however, it contracts for storage and pipeline capacity to facilitate the sale
of propane on a wholesale basis.
Competition
See
discussion on competition in Item 7 under the heading “Management’s Discussion
and Analysis — Competition.”
Rates
and Regulation
The
propane distribution and 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
under the Federal Motor Carrier Safety Act, which is administered by the United
States Department of Transportation 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.
The
Company’s propane operations are subject to all operating hazards normally
associated with the handling, storage and transportation of combustible liquids,
such as the risk of personal injury and property damage caused by fire. The
Company carries general liability insurance in the amount of $35 million, but
there is no assurance that such insurance will be adequate.
(i)
(c) Advanced Information Services
General
Chesapeake’s
advanced information services segment consists of BravePoint, Inc.
(“BravePoint”), a wholly owned subsidiary of the Company. BravePoint,
headquartered in Norcross, Georgia, provides domestic and international clients
with information technology related business services and solutions for both
enterprise and e-business applications.
Competition
See
discussion on competition in Item 7 under the heading “Management’s Discussion
and Analysis — Competition.”
(i)
(d) Other Subsidiaries
Skipjack,
Inc. (“Skipjack”), Eastern Shore Real Estate, Inc. and Chesapeake Investment
Company are wholly owned subsidiaries of Chesapeake Service Company. Skipjack
and Eastern Shore Real Estate, Inc. own and lease office buildings in Delaware
and Maryland to affiliates of Chesapeake. Chesapeake Investment Company is
a
Delaware affiliated investment company. During 2004, Chesapeake formed a new
company, OnSight Energy, LLC (“OnSight”), to provide distributed energy
solutions to customers requiring reliable, uninterrupted energy sources and/or
those wishing to reduce energy costs.
(ii)
Seasonal Nature of Business
Revenues
from the Company’s residential and commercial natural gas sales and from its
propane distribution activities are affected by seasonal variations, since
the
majority of these sales are to customers using the fuels for heating purposes.
Revenues from these customers are accordingly affected by the mildness or
severity of the heating season.
(iii)
Capital Budget
A
discussion of capital expenditures by business segment and capital expenditures
for environmental control facilities are included in Item 7 under the heading
“Management Discussion and Analysis — Liquidity and Capital
Resources.”
(iv)
Employees
As
of
December 31, 2006, Chesapeake had 437 employees, including 193 in natural gas,
142 in propane and 70 in advanced information services. The remaining 32
employees are considered general and administrative and include officers of
the
Company, treasury, accounting, internal audit, information technology, human
resources and other administrative personnel.
(v)
Executive Officers of the Registrant
Information
pertaining to the executive officers of the Company is as follows:
John
R. Schimkaitis
(age 59)
Mr. Schimkaitis is President and Chief Executive Officer of Chesapeake and
its
subsidiaries. Mr. Schimkaitis assumed the role of Chief Executive Officer on
January 1, 1999. He has served as President since 1997. Prior to this, Mr.
Schimkaitis served as President and Chief Operating Officer, Executive Vice
President, Senior Vice President, Chief Financial Officer, Vice President,
Treasurer, Assistant Treasurer and Assistant Secretary of
Chesapeake.
Michael
P. McMasters
(age 48)
Mr. McMasters is Senior Vice President and Chief Financial Officer of Chesapeake
Utilities Corporation. He was appointed Senior Vice President in 2004 and has
served as Chief Financial Officer since December 1996. He has previously held
the positions of Vice President, Treasurer, Director of Accounting and Rates,
and Controller. From 1992 to May 1994, Mr. McMasters was employed as Director
of
Operations Planning for Equitable Gas Company.
Stephen
C. Thompson
(age 46)
Mr. Thompson is President of Eastern Shore Natural Gas Company and Senior Vice
President of Chesapeake Utilities Corporation. Prior to becoming Senior Vice
President in 2004, he served as Vice President of Chesapeake since May 1997.
He
has also served as Vice President, Director of Gas Supply and Marketing,
Superintendent of Eastern Shore and Regional Manager for the Florida
distribution operations.
Beth
W. Cooper
(age 40)
Ms. Cooper is Vice President, Treasurer and Corporate Secretary of Chesapeake
Utilities Corporation. Ms. Cooper has served as Corporate Secretary since July
2005. She previously served as Assistant Treasurer and Assistant Secretary,
Director of Internal Audit, Director of Strategic Planning, Planning Consultant,
Accounting Manager for Non-regulated Operations and Treasury Analyst. Prior
to
joining Chesapeake, she was employed as an auditor with Ernst & Young’s
Entrepreneurial Services Group.
S.
Robert Zola
(age 54)
Mr. Zola joined Sharp Energy in August of 2002 as President. Prior to joining
Sharp Energy, Mr. Zola most recently served as Northeast Regional Manager of
Synergy Gas, now Cornerstone MLP, in Philadelphia, PA. During his 26-year career
in the propane industry, Mr. Zola also started Bluestreak Propane in Phoenix,
AZ, which after successfully developing the business, was sold to Ferrell
Gas.
(vi)
Financial Information about Geographic Areas
All
of
the Company’s material operations, customers, and assets occur and are located
in the United States.
(d) |
Available
Information
|
As
a
public company, Chesapeake files annual, quarterly and other reports, as well
as
its annual proxy statement and other information, with the Securities and
Exchange Commission (“SEC”). The public may read and copy any materials that the
Company files with the SEC at the SEC’s Public Reference Room at 100 F Street,
N.E. Washington,
DC 20549-5546; and the public may obtain information on the operation of the
Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also
maintains an Internet site that contains reports, proxy and information
statements and other information regarding the Company. The address of the
SEC’s
Internet website is www.sec.gov. Chesapeake makes available, free of charge,
on
its Internet website its Annual Report on Form 10-K, Quarterly Reports on Form
10-Q, Current Reports on Form 8-K and amendments to those reports, as soon
as
reasonably practicable after such reports are electronically filed with or
furnished to the SEC. The address of Chesapeake’s Internet website is
www.chpk.com. The content of this website is not part of this
report.
Chesapeake
has a Business Code of Ethics and Conduct applicable to all employees, officers
and directors and a Code of Ethics for Financial Officers. Copies of the
Business Code of Ethics and Conduct and the Financial Officer Code of Ethics
are
available on its internet website. Chesapeake also adopted Corporate Governance
Guidelines and Charters for the Audit Committee, Compensation Committee, and
Governance Committee of the Board of Directors, each of which satisfies the
regulatory requirements established by the Securities and Exchange Commission
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 Chesapeake’s Internet website or may be obtained
by writing to: Corporate Secretary; c/o Chesapeake Utilities Corporation; 909
Silver Lake Blvd.; Dover, DE 19904.
If
Chesapeake makes any amendment to, or grants a waiver of, any provision of
the
Business Code of Ethics and Conduct or the Financial Officer Code of Ethics
applicable to its principal executive officer, principal financial officer,
principal accounting officer or controller, the amendment or waiver will be
disclosed within five business days on the Company’s Internet
website.
Item
1A. Risk Factors.
The
following is a discussion of the primary factors that may affect the operations
and/or financial performance of the regulated and unregulated businesses of
Chesapeake. Refer to the section entitled “Management’s
Discussion and Analysis of Financial Condition and Results of Operations”
under
Item 7 of this report for an additional discussion of these and other related
factors that affect the Company’s operations and/or financial performance.
The
principal business, economic and other factors that affect the operations and/or
financial performance of the Company include:
Fluctuations
in weather have the potential to adversely affect our results of operations,
cash flows and financial condition.
Our
utility and propane distribution operations are sensitive to fluctuations in
weather, and weather conditions directly influence the volume of natural gas
and
propane delivered by our utility and propane distribution operations to
customers. A significant portion of our utility and propane distribution
operations’ revenues are derived from the delivery of natural gas and propane to
residential and commercial heating customers during the five-month peak heating
season of November through March. If the weather is warmer than normal, we
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 and propane, increased supply costs and higher prices for customers.
Regulation
of the Company, including changes in the regulatory environment in general,
may
adversely affect our results of operations, cash flows and financial condition.
The
state
Public Service Commissions of Delaware, Maryland and Florida regulate our
natural gas distribution operations. Eastern Shore, our natural gas transmission
subsidiary, is regulated by the FERC. These regulatory agencies set the rates
in
their respective jurisdictions that we can charge customers for our
rate-regulated services. Changes in these rates, as ordered by regulatory
commissions, affect our financial performance. Our ability to obtain timely
future rate increases and rate supplements to maintain current rates of return
depends on regulatory discretion, and there can be no assurance that our
divisions and Eastern Shore will be able to obtain rate increases or supplements
or continue receiving currently authorized rates of return.
The
amount and availability of natural gas and propane supplies are difficult to
predict, which may reduce our earnings.
Natural
gas and propane production can be impacted by factors outside of our control,
such as weather and refinery closings. If we are unable to obtain sufficient
natural gas and propane supplies to meet demand, our results of operations
may
be negatively impacted.
We
rely on having access to interstate pipelines’ transportation and storage
capacity. If these pipelines or storage facilities were not available, it may
impair our ability to meet our customers’ full requirements.
We
must
acquire both sufficient natural gas supplies and interstate pipeline and storage
capacity to meet customer requirements. We must contract for reliable and
adequate delivery capacity for our distribution system, while considering the
dynamics of the interstate pipeline and storage capacity market, our own
on-system resources, as well as, the characteristics of our customer base.
Local
natural gas distribution companies, including us, and other participants in
the
energy industry, have raised concerns regarding the future availability of
additional upstream interstate pipeline and storage capacity. Additional
available pipeline and storage capacity is a business issue that must be managed
by us, as our customer base grows.
Natural
gas and propane commodity price changes may affect the operating costs and
competitive positions of our natural gas and propane distribution operations,
which may adversely affect our results of operations, cash flows and financial
condition.
Natural
Gas.
Over the
last four years, natural gas costs have increased significantly and become
more
volatile. In addition, the hurricane activity in 2005 reduced the natural gas
available from the Gulf Coast region, further contributing to the volatility
of
natural gas prices. Higher natural gas prices can result in significant
increases in the cost of gas billed to customers during the winter heating
season. Under our regulated gas cost recovery mechanisms, we record cost of
gas
expense equal to the cost of gas recovered in revenues from customers.
Therefore, an increase in the cost of gas due to an increase in the price of
the
natural gas commodity generally has no immediate effect on our revenues and
net
income. However, our net income may be reduced due to higher expenses that
may
be incurred for uncollectible customer accounts, as well as, lower volumes
of
natural gas deliveries to customers due to lower natural gas consumption caused
by customer conservation. Increases in the price of natural gas also can affect
our operating cash flows, as well as the competitiveness of natural gas as
an
energy source.
Propane.
The
level of profitability in the retail propane business is largely dependent
on
the difference between the cost of propane and the revenues derived from our
sale of propane to our customers. Propane costs are subject to volatile changes
as a result of product supply or other market conditions, including economic
and
political factors impacting crude oil and natural gas supply or pricing. Propane
cost changes can occur rapidly over a short period of time and can impact
profitability. There is no assurance that we will be able to pass on propane
cost increases fully or immediately, particularly when propane costs increase
or
decrease rapidly. Therefore, average retail sales prices can vary significantly
from year to year as product costs fluctuate with propane, fuel oil, crude
oil
and natural gas commodity market conditions. In addition, in periods of
sustained higher commodity prices, retail sales volumes may be negatively
impacted by customer conservation efforts and increased amounts of uncollectible
accounts, which may adversely affect net income.
We
compete in a competitive environment and may be faced with losing customers
to a
competitor.
We
compete with third-party suppliers to sell gas to industrial customers. As
it
relates to transportation services, our competitors include the interstate
pipelines if distribution customer is located close enough to the transmission
company’s pipeline to make a connection economically feasible.
Our
propane distribution operations compete with several other propane distributors
in their service territories, primarily on the basis of service and price,
emphasizing reliability of service and responsiveness. Some of our competitors
have significantly greater resources. The retail propane industry is mature,
and
we foresee only modest growth in total demand. Given this limited growth, we
expect that year-to-year industry volumes will be principally affected by
weather patterns. Therefore, our ability to grow the propane distribution
business is contingent upon execution of our community gas systems strategy
to
capture market share and to employ service pricing programs that retain and
grow
our customer base. Any failure to retain and grow our customer base would have
an adverse effect on our results.
The
propane wholesale marketing operation competes against various marketers, many
of which have significantly greater resources and are able to obtain price
or
volumetric advantages.
The
advanced information services business faces significant competition from a
number of larger competitors having substantially greater resources available
to
them to compete on the basis of technological expertise, reputation and price.
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
sites that we have acquired from third parties. Compliance with these legal
requirements requires us to commit capital toward environmental compliance.
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 approved rate mechanisms the costs of
recovery associated with the remediation of former manufactured gas plant sites.
However, there is no guarantee that we will be able to recover future
remediation costs in the same manner or at all. A change in our approved rate
mechanisms for recovery of environmental remediation costs at former
manufactured gas plant 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 or become
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 by us.
A
change in the economic conditions and interest rates may adversely affect our
results of operations and cash flows.
A
downturn in the economies of the regions in which we operate, which we cannot
accurately predict, might adversely affect our ability to increase our customer
base and other businesses at the same rate they have grown in the recent past.
Further, an increase in interest rates, without the recovery of the higher
cost
of debt in the sales and/or transportation rates we charge our utility
customers, could adversely affect future earnings. An increase in short-term
interest rates would negatively affect our results of operations, which depend
on short-term debt to finance accounts receivable, storage gas inventories,
and
to temporarily finance capital expenditures.
Inflation
may impact our results of operations, cash flows and financial position.
Inflation
affects the cost of supply, labor, products and services required for
operations, maintenance and capital improvements. While the impact of inflation
has remained low in recent years, natural gas and propane prices are subject
to
rapid fluctuations. To help cope with the effects of inflation on our capital
investments and returns, we seek rate relief from regulatory commissions for
regulated operations while monitoring the returns of our unregulated business
operations. There can be no assurance that we will be able to obtain adequate
and timely rate relief to offset the effects of inflation. To compensate for
fluctuations in propane gas prices, we adjust our propane selling prices to
the
extent allowed by the market. However, there can be no assurance that we will
be
able to increase propane sales prices sufficiently to fully compensate for
such
fluctuations in the cost of propane gas to us.
Changes
in technology may adversely affect our advanced information services segment’s
results of operations, cash flows and financial condition.
Our
advanced information services segment participates in a market that is
characterized by rapidly changing technology and accelerating product
introduction cycles. The success of our advanced information services segment
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 can be no
assurance that we will be able to keep up with technological advancements
necessary to make our products competitive.
Our
energy marketing subsidiaries have credit risk and credit requirements that
may
adversely affect our results of operations, cash flows and financial condition.
Xeron,
our propane wholesale and marketing subsidiary, and PESCO, our natural gas
marketing subsidiary in Florida, extend credit to counter-parties. While we
believe Xeron and PESCO utilize prudent credit policies, each of these
subsidiaries is exposed to the risk that it may not be able to collect amounts
owed to it. If the counter-party to such a transaction fails to perform and
any
underlying collateral is inadequate, we could experience financial losses.
Xeron
and
PESCO are dependent upon the availability of credit to buy propane and natural
gas for resale or to trade. If the financial condition of these subsidiaries
declines, or if our financial condition declines, then the cost of credit
available to these subsidiaries could increase. If credit is not available,
or
if credit is more costly, our results of operations, cash flows and financial
condition may be adversely affected.
Our
use of derivative instruments may adversely affect our results of operations.
Fluctuating
commodity prices cause our earnings and financing costs to be impacted. Our
propane distribution and wholesale marketing segment uses derivative
instruments, including forwards, swaps and puts, to hedge price risk. In
addition, we have utilized in the past, and may decide, after further
evaluation, to continue to utilize derivative instruments to hedge price risk
for our Delaware and Maryland divisions, as well as PESCO. 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 conditions may
be
adversely impacted.
Inability
to access the capital markets may impair our future growth.
We
rely
on access to both short-term and longer-term capital markets as a significant
source of liquidity for capital requirements not satisfied by the cash flow
from
our operations. Currently, $55 million of the total $80 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.
Construction
of these facilities is subject to various regulatory, development and
operational risks, include but not limited to our
ability to obtain necessary approvals and permits by regulatory agencies on
a
timely basis and on terms that are acceptable to us; 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; impediments on our ability to acquire rights-of-way or
land
rights on a timely basis on terms that are acceptable to us; lack of anticipated
future growth in natural gas supply; and lack of transportation or throughput
commitments.
We
are subject to operating and litigation risks that may not be covered by
insurance.
Our
operations are subject to the operating hazards and risks normally incidental
to
handling, storing, transporting and otherwise providing natural gas and propane
to end users. As a result, we are sometimes a defendant in legal proceedings
and
litigation arising in the ordinary course of business. We maintain insurance
policies with insurers in such amounts and with such coverages 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.
Item
1B. Unresolved Staff Comments.
None.
Item
2. Properties
The
Company owns offices and operates facilities in the following locations:
Pocomoke, Salisbury, Cambridge and Princess Anne, Maryland; Dover, Seaford,
Laurel and Georgetown, Delaware; and Winter Haven, Florida. Chesapeake rents
office space in Dover and Ocean View, Delaware; Jupiter and Lecanto, Florida;
Chincoteague and Belle Haven, Virginia; Easton, and Salisbury, Maryland; Honey
Brook and Allentown, Pennsylvania; Houston, Texas; and Norcross, Georgia. In
general, the Company believes that its properties are adequate for the uses
for
which they are employed. Capacity and utilization of the Company’s facilities
can vary significantly due to the seasonal nature of the natural gas and propane
distribution businesses.
(b) |
Natural
Gas Distribution
|
Chesapeake
owns over 965 miles of natural gas distribution mains (together with related
service lines, meters and regulators) located in its Delaware and Maryland
service areas and 726 miles of natural gas distribution mains (and related
equipment) in its central Florida service areas. Chesapeake also owns facilities
in Delaware and Maryland for propane-air injection during periods of peak
demand.
(c) |
Natural
Gas Transmission
|
Eastern
Shore owns and operates approximately 366 miles of transmission pipelines
extending from supply interconnects at Parkesburg, Pennsylvania; Daleville,
Pennsylvania and Hockessin, Delaware to approximately 75 delivery points in
southeastern Pennsylvania, Delaware and the eastern shore of
Maryland.
(d) |
Propane
Distribution and Wholesale
Marketing
|
The
company’s Delmarva-based propane distribution operation owns bulk propane
storage facilities with an aggregate capacity of approximately 2.0 million
gallons at 42 plant facilities in Delaware, Maryland and Virginia, located
on
real estate that is either owned or leased. The Company’s Florida-based propane
distribution operation owns three bulk propane storage facilities with a total
capacity of 66,000 gallons. Xeron does not own physical storage facilities
or
equipment to transport propane; however, it leases propane storage capacity
and
pipeline capacity.
Item
3. Legal Proceedings
The
Company and its subsidiaries are involved in various legal actions and claims
arising in the normal course of business. The Company is also involved in
certain legal and administrative proceedings before various governmental
agencies concerning rates. In the opinion of management, the ultimate
disposition of these proceedings will not have a material effect on our
consolidated financial position.
See
discussion of environmental commitments and contingencies in Item 8 under the
heading “Notes to Consolidated Financial Statements — Note M.”
Item
4. Submission of Matters to a Vote of Security Holders.
None
Part
II
Item
5. Market for the Registrant’s Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities.
(a) |
Common
Stock Price Ranges, Common Stock Dividends and Shareholder
Information:
|
The
Company’s Common Stock is listed on the New York Stock Exchange under the symbol
“CPK.” The high, low and closing prices of Chesapeake’s Common Stock and
dividends declared per share for each calendar quarter during the years 2006
and
2005 were as follows:
Quarter
Ended
|
|
High
|
|
Low
|
|
Close
|
|
Dividends
Declared Per Share
|
|
2006
|
|
|
|
|
|
|
|
|
|
March
31
|
|
$
|
32.47
|
|
$
|
29.97
|
|
$
|
31.24
|
|
$
|
0.285
|
|
June
30
|
|
|
31.20
|
|
|
27.90
|
|
|
30.08
|
|
$
|
0.290
|
|
September
30
|
|
|
35.65
|
|
|
29.51
|
|
|
30.05
|
|
$
|
0.290
|
|
December
31
|
|
|
31.31
|
|
|
29.10
|
|
|
30.65
|
|
$
|
0.290
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March
31
|
|
$
|
27.59
|
|
$
|
25.83
|
|
$
|
26.60
|
|
$
|
0.280
|
|
June
30
|
|
|
30.95
|
|
|
23.60
|
|
|
30.58
|
|
$
|
0.285
|
|
September
30
|
|
|
35.60
|
|
|
29.50
|
|
|
35.16
|
|
$
|
0.285
|
|
December
31
|
|
|
35.78
|
|
|
30.32
|
|
|
30.80
|
|
$
|
0.285
|
|
Dividend
payments 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
sold no securities during the year 2006 that were not registered under the
Securities Act of 1933, as amended.
Indentures
to the long-term debt of the Company contain various restrictions. The most
stringent restrictions state that the Company must maintain equity of at least
40 percent of total capitalization and the pro-forma fixed charge coverage
ratio
must be at least 1.5 times. The Company was in compliance with these
restrictions and the other debt covenants during 2006.
At
December 31, 2006, there were 1,978 shareholders of record of the Common
Stock.
(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,
2006.
Period
|
|
Total
Number of Shares Purchased
|
|
Average
Price Paid per Share
|
|
Total
Number of Shares Purchased as Part of Publicly Announced Plans
or Programs
(2)
|
|
Maximum
Number of Shares That May Yet Be Purchased Under the Plans or Programs
(2)
|
|
October
1, 2006 through October 31, 2006 (1)
|
|
|
463
|
|
$
|
29.92
|
|
|
0
|
|
|
0
|
|
November
1, 2006 through November 30, 2006
|
|
|
0
|
|
$
|
0.00
|
|
|
0
|
|
|
0
|
|
December
1, 2006 through December 31, 2006
|
|
|
0
|
|
$
|
0.00
|
|
|
0
|
|
|
0
|
|
Total
|
|
|
463
|
|
$
|
29.92
|
|
|
0
|
|
|
0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Chesapeake purchased shares of stock on the open market for the
purpose of
reinvesting the dividend on shares held in Rabbi Trust accounts
for
certain Senior Executives. During the quarter, 463 shares were
purchased
through executive dividend deferrals.
|
|
(2)
Except for the purpose described in Footnote (1), Chesapeake
has no publicly announced plans or programs to repurchase its
shares.
|
|
Discussion
on compensation plans of Chesapeake and its subsidiaries for which shares of
Chesapeake common stock are authorized for issuance is incorporated herein
by
reference to the portion of the Proxy Statement captioned “Equity Compensation
Plan Information” to be filed not later than March 31, 2007 in connection with
the Company’s Annual Meeting to be held on May 2, 2007.
(c) |
Chesapeake
Utilities Corporation Common Stock Performance Graph
|
The
following Performance Graph compares the yearly percentage change in cumulative
total shareholder return on the Company’s common stock during the five fiscal
years ended December 31, 2006, with the cumulative return on (i) the
S&P 500 Index and (ii) an industry index consisting of 30 Natural Gas
Distribution and Integrated Natural Gas Companies as published by C.A Turner
Utility Reports.
The
thirty companies in the C.A. Turner industry index are as follows: AGL
Resources, Inc., Atmos Energy Corporation, Cascade Natural Gas Corporation,
Chesapeake Utilities Corporation, Delta Natural Gas Company, Inc., El Paso
Corporation, Energen Corporation, Energy West, Inc., EnergySouth. Inc.,
Equitable Resources, Inc., KeySpan Corporation, Kinder Morgan, Inc., The Laclede
Group, Inc., National Fuel Gas Company, New Jersey Resources Corporation, NICOR,
Inc., Northwest Natural Gas Company, ONEOK, Inc., Peoples Energy Corporation,
Piedmont Natural Gas Co., Inc., Questar Corporation, RGC Resources, Inc., SEMCO
Energy, Inc., South Jersey Industries, Inc., Southern Union Company, Southwest
Gas Corporation, Southwest Energy Company, UGI Corporation, WGL Holdings, Inc.,
and The Williams Companies, Inc.
The
comparison assumes $100 was invested on December 31, 2001 in the Company’s
common stock and in each of the foregoing indices and assumes reinvested
dividends. The comparisons in the Graph below are based on historical data
and
are not intended to forecast the possible future performance of the Company’s
Common Stock.
|
|
Cumulative
Total Stockholder Return
|
|
|
|
2001
|
|
2002
|
|
2003
|
|
2004
|
|
2005
|
|
2006
|
|
Chesapeake
|
|
$100
|
|
$98
|
|
$145
|
|
$155
|
|
$186
|
|
$192
|
|
Industry
Index
|
|
$100
|
|
$96
|
|
$121
|
|
$156
|
|
$200
|
|
$236
|
|
S
& P 500
|
|
$100
|
|
$78
|
|
$100
|
|
$111
|
|
$116
|
|
$134
|
|
Item
6. Selected Financial Data
For
the Years Ended December 31,
|
|
2006
(3)
|
|
2005
|
|
2004
|
|
2003
|
|
2002
|
|
Operating
(in
thousands of dollars)
(1)
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$
|
170,374
|
|
$
|
166,582
|
|
$
|
124,246
|
|
$
|
110,247
|
|
$
|
93,588
|
|
Propane
|
|
|
48,576
|
|
|
48,976
|
|
|
41,500
|
|
|
41,029
|
|
|
29,238
|
|
Advanced
informations systems
|
|
|
12,568
|
|
|
14,140
|
|
|
12,427
|
|
|
12,578
|
|
|
12,764
|
|
Other
and eliminations
|
|
|
(317
|
)
|
|
(68
|
)
|
|
(218
|
)
|
|
(286
|
)
|
|
(334
|
)
|
Total
revenues
|
|
$
|
231,201
|
|
$
|
229,630
|
|
$
|
177,955
|
|
$
|
163,568
|
|
$
|
135,256
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$
|
19,733
|
|
$
|
17,236
|
|
$
|
17,091
|
|
$
|
16,653
|
|
$
|
14,973
|
|
Propane
|
|
|
2,534
|
|
|
3,209
|
|
|
2,364
|
|
|
3,875
|
|
|
1,052
|
|
Advanced
informations systems
|
|
|
767
|
|
|
1,197
|
|
|
387
|
|
|
692
|
|
|
343
|
|
Other
and eliminations
|
|
|
(103
|
)
|
|
(112
|
)
|
|
128
|
|
|
359
|
|
|
237
|
|
Total
operating income
|
|
$
|
22,931
|
|
$
|
21,530
|
|
$
|
19,970
|
|
$
|
21,579
|
|
$
|
16,605
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income from continuing operations
|
|
$
|
10,507
|
|
$
|
10,468
|
|
$
|
9,550
|
|
$
|
10,079
|
|
$
|
7,535
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
(in thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
property, plant and equipment
|
|
$
|
325,836
|
|
$
|
280,345
|
|
$
|
250,267
|
|
$
|
234,919
|
|
$
|
229,128
|
|
Net
property, plant and equipment (2)
|
|
$
|
240,825
|
|
$
|
201,504
|
|
$
|
177,053
|
|
$
|
167,872
|
|
$
|
166,846
|
|
Total
assets (2)
|
|
$
|
324,994
|
|
$
|
295,980
|
|
$
|
241,938
|
|
$
|
222,058
|
|
$
|
223,721
|
|
Capital
expenditures (1)
|
|
$
|
48,969
|
|
$
|
33,423
|
|
$
|
17,830
|
|
$
|
11,822
|
|
$
|
13,836
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalization
(in thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders'
equity
|
|
$
|
111,152
|
|
$
|
84,757
|
|
$
|
77,962
|
|
$
|
72,939
|
|
$
|
67,350
|
|
Long-term
debt, net of current maturities
|
|
|
71,050
|
|
|
58,991
|
|
|
66,190
|
|
|
69,416
|
|
|
73,408
|
|
Total
capitalization
|
|
$
|
182,202
|
|
$
|
143,748
|
|
$
|
144,152
|
|
$
|
142,355
|
|
$
|
140,758
|
|
Current
portion of long-term debt
|
|
$
|
7,656
|
|
$
|
4,929
|
|
$
|
2,909
|
|
$
|
3,665
|
|
$
|
3,938
|
|
Short-term
debt
|
|
|
27,554
|
|
|
35,482
|
|
|
5,002
|
|
|
3,515
|
|
|
10,900
|
|
Total
capitalization and short-term financing
|
|
$
|
217,412
|
|
$
|
184,159
|
|
$
|
152,063
|
|
$
|
149,535
|
|
$
|
155,596
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
These amounts exclude the results of water services due to their
reclassification to discontinued operations. The assets of all
of the
water businesses were sold in 2004 and 2003.
|
|
(2)
SFAS 143 was adopted in the year 2001; therefore, SFAS 143 was
not
applicable for the years prior to 2001.
|
|
(3)
SFAS 123R and SFAS 158 were adopted in the year 2006; therefore,
they were
not applicable for the years prior to 2006.
|
|
Item
6. Selected Financial Data
For
the Years Ended December 31,
|
|
2001
|
|
2000
|
|
1999
|
|
1998
|
|
1997
|
|
Operating
(in
thousands of dollars)
(1)
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$
|
107,418
|
|
$
|
101,138
|
|
$
|
75,637
|
|
$
|
68,770
|
|
$
|
88,108
|
|
Propane
|
|
|
35,742
|
|
|
31,780
|
|
|
25,199
|
|
|
23,377
|
|
|
28,614
|
|
Advanced
informations systems
|
|
|
14,104
|
|
|
12,390
|
|
|
13,531
|
|
|
10,331
|
|
|
7,786
|
|
Other
and eliminations
|
|
|
(113
|
)
|
|
(131
|
)
|
|
(14
|
)
|
|
(15
|
)
|
|
(182
|
)
|
Total
revenues
|
|
$
|
157,151
|
|
$
|
145,177
|
|
$
|
114,353
|
|
$
|
102,463
|
|
$
|
124,326
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$
|
14,405
|
|
$
|
12,798
|
|
$
|
10,388
|
|
$
|
8,820
|
|
$
|
9,240
|
|
Propane
|
|
|
913
|
|
|
2,135
|
|
|
2,622
|
|
|
965
|
|
|
1,137
|
|
Advanced
informations systems
|
|
|
517
|
|
|
336
|
|
|
1,470
|
|
|
1,316
|
|
|
1,046
|
|
Other
and eliminations
|
|
|
386
|
|
|
816
|
|
|
495
|
|
|
485
|
|
|
558
|
|
Total
operating income
|
|
$
|
16,221
|
|
$
|
16,085
|
|
$
|
14,975
|
|
$
|
11,586
|
|
$
|
11,981
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income from continuing operations
|
|
$
|
7,341
|
|
$
|
7,665
|
|
$
|
8,372
|
|
$
|
5,329
|
|
$
|
5,812
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
(in thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
property, plant and equipment
|
|
$
|
216,903
|
|
$
|
192,925
|
|
$
|
172,068
|
|
$
|
152,991
|
|
$
|
144,251
|
|
Net
property, plant and equipment (2)
|
|
$
|
161,014
|
|
$
|
131,466
|
|
$
|
117,663
|
|
$
|
104,266
|
|
$
|
99,879
|
|
Total
assets (2)
|
|
$
|
222,229
|
|
$
|
211,764
|
|
$
|
166,958
|
|
$
|
145,029
|
|
$
|
145,719
|
|
Capital
expenditures (1)
|
|
$
|
26,293
|
|
$
|
22,057
|
|
$
|
21,365
|
|
$
|
12,516
|
|
$
|
13,471
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalization
(in thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders'
equity
|
|
$
|
67,517
|
|
$
|
64,669
|
|
$
|
60,714
|
|
$
|
56,356
|
|
$
|
53,656
|
|
Long-term
debt, net of current maturities
|
|
|
48,409
|
|
|
50,921
|
|
|
33,777
|
|
|
37,597
|
|
|
38,226
|
|
Total
capitalization
|
|
$
|
115,926
|
|
$
|
115,590
|
|
$
|
94,491
|
|
$
|
93,953
|
|
$
|
91,882
|
|
Current
portion of long-term debt
|
|
$
|
2,686
|
|
$
|
2,665
|
|
$
|
2,665
|
|
$
|
520
|
|
$
|
1,051
|
|
Short-term
debt
|
|
|
42,100
|
|
|
25,400
|
|
|
23,000
|
|
|
11,600
|
|
|
7,600
|
|
Total
capitalization and short-term financing
|
|
$
|
160,712
|
|
$
|
143,655
|
|
$
|
120,156
|
|
$
|
106,073
|
|
$
|
100,533
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
These amounts exclude the results of water services due to their
reclassification to discontinued operations. The assets of all
of the
water businesses were sold in 2004 and 2003.
|
|
(2)
SFAS 143 was adopted in the year 2001; therefore, SFAS 143 was
not
applicable for the years prior to 2001.
|
|
(3)
SFAS 123R and SFAS 158 were adopted in the year 2006; therefore,
they were
not applicable for the years prior to 2006.
|
|
Item
6. Selected Financial Data
For
the Years Ended December 31,
|
|
2006
(3)
|
|
2005
|
|
2004
|
|
2003
|
|
2002
|
|
Common
Stock Data and Ratios
|
|
|
|
|
|
|
|
|
|
|
|
Basic
earnings per share from continuing operations (1)
|
|
$
|
1.74
|
|
$
|
1.79
|
|
$
|
1.66
|
|
$
|
1.80
|
|
$
|
1.37
|
|
Diluted
earnings per share from continuing operations (1)
|
|
$
|
1.72
|
|
$
|
1.77
|
|
$
|
1.64
|
|
$
|
1.76
|
|
$
|
1.37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Return
on average equity from continuing operations (1)
|
|
|
10.7
|
%
|
|
12.9
|
%
|
|
12.7
|
%
|
|
14.4
|
%
|
|
11.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
equity / total capitalization
|
|
|
61.0
|
%
|
|
59.0
|
%
|
|
54.1
|
%
|
|
51.2
|
%
|
|
47.8
|
%
|
Common
equity / total capitalization and short-term financing
|
|
|
51.1
|
%
|
|
46.0
|
%
|
|
51.3
|
%
|
|
48.8
|
%
|
|
43.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Book
value per share
|
|
$
|
16.62
|
|
$
|
14.41
|
|
$
|
13.49
|
|
$
|
12.89
|
|
$
|
12.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market
price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
$
|
35.650
|
|
$
|
35.780
|
|
$
|
27.550
|
|
$
|
26.700
|
|
$
|
21.990
|
|
Low
|
|
$
|
27.900
|
|
$
|
23.600
|
|
$
|
20.420
|
|
$
|
18.400
|
|
$
|
16.500
|
|
Close
|
|
$
|
30.650
|
|
$
|
30.800
|
|
$
|
26.700
|
|
$
|
26.050
|
|
$
|
18.300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
number of shares outstanding
|
|
|
6,032,462
|
|
|
5,836,463
|
|
|
5,735,405
|
|
|
5,610,592
|
|
|
5,489,424
|
|
Shares
outstanding at year-end
|
|
|
6,688,084
|
|
|
5,883,099
|
|
|
5,778,976
|
|
|
5,660,594
|
|
|
5,537,710
|
|
Registered
common shareholders
|
|
|
1,978
|
|
|
2,026
|
|
|
2,026
|
|
|
2,069
|
|
|
2,130
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
dividends declared per share
|
|
$
|
1.16
|
|
$
|
1.14
|
|
$
|
1.12
|
|
$
|
1.10
|
|
$
|
1.10
|
|
Dividend
yield (annualized) (2)
|
|
|
3.8
|
%
|
|
3.7
|
%
|
|
4.2
|
%
|
|
4.2
|
%
|
|
6.0
|
%
|
Payout
ratio from continuing operations (1)
(4)
|
|
|
66.7
|
%
|
|
63.7
|
%
|
|
67.5
|
%
|
|
61.1
|
%
|
|
80.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customers
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas distribution and transmission
|
|
|
59,132
|
|
|
54,786
|
|
|
50,878
|
|
|
47,649
|
|
|
45,133
|
|
Propane
distribution
|
|
|
33,282
|
|
|
32,117
|
|
|
34,888
|
|
|
34,894
|
|
|
34,566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas distribution and transmission deliveries (in MMCF)
|
|
|
34,321
|
|
|
34,981
|
|
|
31,430
|
|
|
29,375
|
|
|
27,935
|
|
Propane
distribution (in thousands of gallons)
|
|
|
24,243
|
|
|
26,178
|
|
|
24,979
|
|
|
25,147
|
|
|
21,185
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heating
degree-days (Delmarva Peninsula)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
HDD
|
|
|
3,931
|
|
|
4,792
|
|
|
4,553
|
|
|
4,715
|
|
|
4,161
|
|
10
-year average HDD (normal)
|
|
|
4,372
|
|
|
4,436
|
|
|
4,389
|
|
|
4,409
|
|
|
4,393
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Propane
bulk storage capacity (in thousands of gallons)
|
|
|
2,315
|
|
|
2,315
|
|
|
2,045
|
|
|
2,195
|
|
|
2,151
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
employees (1)
|
|
|
437
|
|
|
423
|
|
|
426
|
|
|
439
|
|
|
455
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
These amounts exclude the results of water services due to their
reclassification to discontinued operations. The assets of all
of the
water businesses were sold in 2004 and 2003.
|
|
(2)
Dividend yield (annualized) is calculated by multiplying the
fourth
quarter dividend by four (4), then dividing that amount by the
closing
common stock price at December 31.
|
|
(3)
SFAS 123R and SFAS 158 were adopted in the year 2006; therefore,
they were
not applicable for the years prior to 2006.
|
|
(4)
The payout ratio from continuing operations is calculated by
dividing cash
dividends declared per share (for the year) by basic earnings
per share
from continuing operations.
|
|
Item
6. Selected Financial Data
For
the Years Ended December 31,
|
|
2001
|
|
2000
|
|
1999
|
|
1998
|
|
1997
|
|
Common
Stock Data and Ratios
|
|
|
|
|
|
|
|
|
|
|
|
Basic
earnings per share from continuing operations (1)
|
|
$
|
1.37
|
|
$
|
1.46
|
|
$
|
1.63
|
|
$
|
1.05
|
|
$
|
1.17
|
|
Diluted
earnings per share from continuing operations (1)
|
|
$
|
1.35
|
|
$
|
1.43
|
|
$
|
1.59
|
|
$
|
1.04
|
|
$
|
1.15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Return
on average equity from continuing operations (1)
|
|
|
11.1
|
%
|
|
12.2
|
%
|
|
14.3
|
%
|
|
9.7
|
%
|
|
11.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
equity / total capitalization
|
|
|
58.2
|
%
|
|
55.9
|
%
|
|
64.3
|
%
|
|
60.0
|
%
|
|
58.4
|
%
|
Common
equity / total capitalization and short-term financing
|
|
|
42.0
|
%
|
|
45.0
|
%
|
|
50.5
|
%
|
|
53.1
|
%
|
|
53.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Book
value per share
|
|
$
|
12.45
|
|
$
|
12.21
|
|
$
|
11.71
|
|
$
|
11.06
|
|
$
|
10.72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market
price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
$
|
19.900
|
|
$
|
18.875
|
|
$
|
19.813
|
|
$
|
20.500
|
|
$
|
21.750
|
|
Low
|
|
$
|
17.375
|
|
$
|
16.250
|
|
$
|
14.875
|
|
$
|
16.500
|
|
$
|
16.250
|
|
Close
|
|
$
|
19.800
|
|
$
|
18.625
|
|
$
|
18.375
|
|
$
|
18.313
|
|
$
|
20.500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
number of shares outstanding
|
|
|
5,367,433
|
|
|
5,249,439
|
|
|
5,144,449
|
|
|
5,060,328
|
|
|
4,972,086
|
|
Shares
outstanding at year-end
|
|
|
5,424,962
|
|
|
5,297,443
|
|
|
5,186,546
|
|
|
5,093,788
|
|
|
5,004,078
|
|
Registered
common shareholders
|
|
|
2,171
|
|
|
2,166
|
|
|
2,212
|
|
|
2,271
|
|
|
2,178
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
dividends declared per share
|
|
$
|
1.10
|
|
$
|
1.07
|
|
$
|
1.03
|
|
$
|
1.00
|
|
$
|
0.97
|
|
Dividend
yield (annualized) (2)
|
|
|
5.6
|
%
|
|
5.8
|
%
|
|
5.7
|
%
|
|
5.5
|
%
|
|
4.7
|
%
|
Payout
ratio from continuing operations (1)
(4)
|
|
|
80.3
|
%
|
|
73.3
|
%
|
|
63.2
|
%
|
|
95.2
|
%
|
|
82.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customers
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas distribution and transmission
|
|
|
42,741
|
|
|
40,854
|
|
|
39,029
|
|
|
37,128
|
|
|
35,797
|
|
Propane
distribution
|
|
|
35,530
|
|
|
32,117
|
|
|
35,267
|
|
|
34,113
|
|
|
33,123
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas distribution and transmission deliveries (in MMCF)
|
|
|
27,264
|
|
|
30,830
|
|
|
27,383
|
|
|
21,400
|
|
|
23,297
|
|
Propane
distribution (in thousands of gallons)
|
|
|
23,080
|
|
|
28,469
|
|
|
27,788
|
|
|
25,979
|
|
|
26,682
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heating
degree-days (Delmarva Peninsula)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
HDD
|
|
|
4,368
|
|
|
4,730
|
|
|
4,082
|
|
|
3,704
|
|
|
4,430
|
|
10
-year average HDD (normal)
|
|
|
4,446
|
|
|
4,356
|
|
|
4,409
|
|
|
4,493
|
|
|
4,574
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Propane
bulk storage capacity (in thousands of gallons)
|
|
|
1,958
|
|
|
1,928
|
|
|
1,926
|
|
|
1,890
|
|
|
1,866
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
employees (1)
|
|
|
458
|
|
|
471
|
|
|
466
|
|
|
431
|
|
|
397
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
These amounts exclude the results of water services due to their
reclassification to discontinued operations. The assets of all
of the
water businesses were sold in 2004 and 2003.
|
|
(2)
Dividend yield (annualized) is calculated by multiplying the fourth
quarter dividend by four (4), then dividing that amount by the
closing
common stock price at December 31.
|
|
(3)
SFAS 123R and SFAS 158 were adopted in the year 2006; therefore,
they were
not applicable for the years prior to 2006.
|
|
(4)
The payout ratio from continuing operations is calculated by dividing
cash
dividends declared per share (for the year) by basic earnings per
share
from continuing operations.
|
|
Management's
Discussion and Analysis
Item
7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations
INTRODUCTION
This
section provides management’s discussion of Chesapeake Utilities Corporation and
its consolidated subsidiaries with specific information on results of operations
and liquidity and capital resources. It includes management’s interpretation of
our financial results, the factors affecting these results, the major factors
expected to affect future operating results and future investment and financing
plans. This discussion should be read in conjunction with our consolidated
financial statements and notes thereto.
Several
factors exist that could influence our future financial performance, some of
which are described in Item 1A above, “Risk Factors”. They should be
considered in connection with evaluating forward-looking statements contained
in
this report or otherwise made by or on behalf of us since these factors could
cause actual results and conditions to differ materially from those set out
in
such forward-looking statements.
EXECUTIVE
OVERVIEW
Exec
Chesapeake
is a diversified utility company engaged directly or through subsidiaries in
natural gas distribution, transmission and marketing, propane distribution
and
wholesale marketing, advanced information services and other related
businesses.
The
Company’s strategy is focused on growing earnings from a stable utility
foundation and investing in related businesses and services that provide
opportunities for returns greater than traditional utility returns. The key
elements of this strategy include:
· |
Executing
a capital investment program in pursuit of organic growth opportunities
that generate returns equal to or greater than our cost of
capital.
|
· |
Expanding
the natural gas distribution and transmission business through expansion
into new geographic areas in our current service
territories.
|
· |
Expanding
the propane distribution business in existing and new markets through
leveraging our community gas system services and our bulk delivery
capabilities.
|
· |
Utilizing
the Company’s expertise across our various businesses to improve overall
performance.
|
· |
Enhancing
marketing channels to attract new customers and providing reliable
and
responsive customer service to retain existing
customers.
|
· |
Maintaining
a capital structure that enables the Company to access capital as
needed.
|
· |
Maintaining
a consistent and competitive
dividend.
|
In
2006,
the Company earned $10,507,000 in net income, or $1.72 per share (diluted),
in spite of weather that was the second warmest in the last thirty years. In
2005, net income was $10,468,000, or $1.77 per diluted share. Overall,
operating income in 2006 increased $1,401,000, or 6.5 percent from 2005, despite
weather that was 18 percent warmer than in 2005. However, the increase in
operating income was offset by a decline of $194,000, or 51 percent, in other
income, net of other expenses, and increases in interest expense of $644,000,
or
12.5 percent, and income taxes of $525,000, or 8.3 percent. The net result
was
that net income was up by only $39,000, or 0.4 percent.
The
following discussions and those later in the document on operating income and
segment results include use of the term “gross margin.” Gross margin is
determined by deducting the cost of sales from operating revenue. Cost of sales
includes the purchased gas cost for natural gas and propane and the cost of
labor spent on direct revenue-producing activities. Gross margin should not
be
considered an alternative to operating income or net income, which are
determined in accordance with Generally Accepted Accounting Principles (“GAAP”).
Chesapeake believes 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 operations and under its
competitive pricing structure for non-regulated segments. Chesapeake’s
management uses gross margin in measuring its business units’ performance and
has historically analyzed and reported gross margin information publicly. Other
companies may calculate gross margin in a different manner.
Management's
Discussion and Analysis
Operating
Income
The
year
2006 reflects the strong year-over-year operating income growth experienced
by
the Company’s natural gas operations of $2,497,000, or 14.5 percent. This growth
was offset by reductions in operating income from propane and advanced
information services. In 2006, both natural gas and propane segments were
negatively impacted by weather that was 18 percent warmer than in 2005. The
Company estimates that the warmer weather reduced gross margin by $3.4 million
in 2006. The natural gas segment was able to overcome the weather impact and
show an increase in operating income due to its growth and cost containment
efforts. However, as the propane segment is more weather sensitive and is not
experiencing the high level of growth of our natural gas segment, its operating
income declined when compared to 2005.
Advanced
information services experienced a decrease in operating income in 2006 as
compared to the prior year due in part to the gain on the sale of Lightweight
Association Management Processing System (“LAMPSTM”)
during
the fourth quarter of 2005. The
LAMPS
product was internally developed software that was developed and marketed
specifically for REALTOR® Associations.
Key
financial and operational highlights for fiscal year 2006 include the following:
· |
Customer
growth in the natural gas and propane businesses remained strong,
with the
Delmarva and Florida natural gas distribution operations registering
9 and
8 percent increases in residential customers, respectively; and the
Delmarva Community Gas Systems (“CGS”) generating a 34 percent increase in
propane distribution customers.
|
· |
In
June 2006, Eastern Shore Natural Gas announced that it had received
approval from the Federal Energy Regulatory Commission (“FERC”) to expand
its pipeline system in the years 2006, 2007 and 2008. The entire
project
represents an investment of $33.6 million, with expected annualized
revenue of $6.7 million after the full build-out of the
facilities.
|
· |
On
September 26, 2006, the Company received approval for a base rate
increase
from the Maryland Public Service Commission (“PSC”) for our Maryland
natural gas operations, with the new base rates effective October
1, 2006.
The base rate adjustment results in an increase in base rates of
approximately $780,000, which would result in an average increase
in
revenues of approximately 4.5 percent for the Company’s firm residential,
commercial and industrial customers in Maryland. The PSC also approved
the
Company’s proposal to implement a revenue normalization mechanism for its
residential heating and smaller commercial heating customers, reducing
the
Company’s future risk due to weather and usage
changes.
|
· |
In
November 2006, the Company completed a public offering of 600,300
shares
of its common stock at a price per share of $30.10. Additionally,
in
November 2006, the Company completed the sale of 90,045 additional
shares
of its common stock, pursuant to the over-allotment option granted
to the
Underwriters by the Company. The net proceeds of approximately $19.7
million, after the deduction of underwriting commissions and expenses
from
the sale of the common stock, were added to the Company’s general funds
and primarily used to repay a portion of the Company’s short-term debt.
|
· |
Total
capitalization, including short-term borrowing, increased $33.3 million
at
December 31, 2006 compared with December 31, 2005. The increased
capitalization was obtained to fund the $39.3 million increase in
net
plant and for other working capital
needs.
|
· |
For
the year ended December 31, 2006, the Company generated
$30.1 million in operating cash flow compared with $13.6 million
for the year ended December 31, 2005. The higher cost of natural
gas and
propane in 2005 had an adverse impact on working capital in
2005.
|
Management's
Discussion and Analysis
· |
Net
property, plant and equipment increased to $240.8 million at December
31, 2006 from $201.5 million at December 31, 2005, primarily
reflecting continued capital investment to support customer
growth.
|
· |
In
June 2006, Eastern Shore announced the Bay Crossing Project for which
it
plans to develop, construct and operate new pipeline facilities that
would
transport natural gas from Calvert County, Maryland, cross under
the
Chesapeake Bay into Dorchester and Caroline Counties, Maryland, to
points
on the Delmarva Peninsula where such facilities would interconnect
with
its existing facilities in Sussex County, Delaware. If completed,
the
project will expand the capacity of its interstate pipeline system
by
approximately 33 percent. We still have significant obstacles to
overcome
on this project to make it a reality. In 2007, Eastern Shore will
initiate
the processes required to obtain the FERC and other federal, state
and
local permits required to construct the project. Eastern Shore received
approval from the FERC in August 2006 to recover the pre-service
costs
associated with this pipeline project through its rates from two
of its
customers. As of December 31, 2006, the Company had deferred a total
of
$409,000 of pre-service costs associated with the
project.
|
The
Company’s financial performance is discussed in greater detail below in Results
of Operations.
Critical
Accounting Policies
Chesapeake’s
reported financial condition and results of operations are affected by the
accounting methods, assumptions and estimates that are used in the preparation
of the Company’s financial statements. Because most of Chesapeake’s businesses
are regulated, the accounting methods used by Chesapeake must comply with the
requirements of the regulatory bodies; therefore, the choices available are
limited by these regulatory requirements. Management believes that the following
policies require significant estimates or other judgments of matters that are
inherently uncertain. These policies and their application have been discussed
with Chesapeake’s Audit Committee.
Regulatory
Assets and Liabilities
Chesapeake
records certain assets and liabilities in accordance with Statement of Financial
Accounting Standards (“SFAS”) No. 71 “Accounting for the Effects of Certain
Types of Regulation.” Costs are deferred when there is a probable expectation
that they will be recovered in future revenues as a result of the regulatory
process. At December 31, 2006, Chesapeake had recorded regulatory assets of
$3.0
million, including $1.1 million for under-recovered purchased gas costs, $1.3
million for tax-related regulatory assets, $139,000 for defined postretirement
benefits, and $122,000 for environmental cost recovery. The Company has recorded
regulatory liabilities totaling $23.8 million, including $18.4 million for
accrued asset removal cost, $2.4 million for over-recovered purchased gas costs,
$1.2 million for self-insurance, $1.2 million for cash in/cash out, and $349,000
for over-collected environmental costs at December 31, 2006. If the Company
were
required to terminate application of SFAS No. 71, it would be required to
recognize all such deferred amounts as a charge to earnings, net of applicable
income taxes. Such a charge could have a material adverse effect on the
Company’s results of operations.
Valuation
of Environmental Assets and Liabilities
As
more
fully described in Note M to the Financial Statements, Chesapeake has completed
its responsibilities related to one environmental site and is currently
participating in the investigation, assessment or remediation of three other
former manufactured gas plant sites. Amounts have been recorded as environmental
liabilities and associated environmental regulatory assets based on estimates
of
future costs provided by independent consultants. There is uncertainty in these
amounts because the Environmental Protection Agency (“EPA”) or applicable state
environmental authority may not have selected the final remediation methods.
Additionally, there is uncertainty due to the outcome of legal remedies sought
from other potentially responsible parties. At December 31, 2006, Chesapeake
had
recorded environmental regulatory assets of $122,000 and a regulatory liability
of $350,000 for over-collections and an additional liability of $212,000 for
environmental costs.
Management's
Discussion and Analysis
Propane
Wholesale Marketing Contracts
Chesapeake’s
propane wholesale marketing operation enters into forward and futures contracts
that are considered derivatives under SFAS No. 133, “Accounting for Derivative
Instruments and Hedging Activities.” In accordance with the pronouncement, open
positions are marked to market prices at the end of each reporting period and
unrealized gains or losses are recorded in the Consolidated Statement of Income
as revenue. The contracts all mature within one year, and are almost exclusively
for propane commodities with delivery points of Mt. Belvieu, Texas, Conway,
Kansas and Hattiesburg, Mississippi. Management estimates the market valuation
based on references to exchange-traded futures prices, historical differentials
and actual trading activity at the end of the reporting period. At December
31,
2006, these contracts had net unrealized gains of $8,500 that was recorded
in
the financial statements. At December 31, 2005, these contracts had net
unrealized gains of $46,000 that were recorded in the financial
statements.
Operating
Revenues
Revenues
for the natural gas distribution operations of the Company are based on rates
approved by the public service commissions (“PSC”) of the jurisdictions in which
we operate. The natural gas transmission operation’s revenues are based on rates
approved by the FERC. Customers’ base rates may not be changed without formal
approval by these commissions. However, the regulatory authorities have granted
the Company’s regulated natural gas distribution operations the ability to
negotiate rates with customers that have competitive alternatives using approved
methodologies. In addition, the natural gas transmission operation can negotiate
rates above or below the FERC approved tariff rates.
Chesapeake’s
natural gas distribution operations in Delaware and Maryland each have a gas
cost recovery mechanism that provides for the adjustment of rates charged to
customers as gas costs fluctuate. These amounts are collected or refunded
through adjustments to rates in subsequent periods.
The
Company charges flexible rates to the natural gas distribution’s industrial
interruptible customers to make them competitive with alternative types of
fuel.
Based on pricing, these customers can choose natural gas or alternative types
of
supply. Neither the Company nor the interruptible customer is contractually
obligated to deliver or receive natural gas.
The
propane wholesale marketing operation records trading activity, on a net
mark-to-market basis in the Company’s income statement, for open contracts. The
natural gas segment recognizes revenue on an accrual basis. The propane
distribution, advanced information services and other segments record revenue
in
the period the products are delivered and/or services are rendered.
Results
of Operations
Net
Income & Diluted Earnings Per Share Summary
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Years Ended December 31,
|
|
2006
|
|
2005
|
|
Increase
(decrease)
|
|
2005
|
|
2004
|
|
Increase
(decrease)
|
|
Net
Income *
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing
operations
|
|
$
|
10,507
|
|
$
|
10,468
|
|
$
|
39
|
|
$
|
10,468
|
|
$
|
9,550
|
|
$
|
918
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(121
|
)
|
|
121
|
|
Total
Net Income
|
|
$
|
10,507
|
|
$
|
10,468
|
|
$
|
39
|
|
$
|
10,468
|
|
$
|
9,429
|
|
$
|
1,039
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
Earnings Per Share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing
operations
|
|
$
|
1.72
|
|
$
|
1.77
|
|
|
($0.05
|
)
|
$
|
1.77
|
|
$
|
1.64
|
|
$
|
0.13
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(0.02
|
)
|
|
0.02
|
|
Total
Earnings Per Share
|
|
$
|
1.72
|
|
$
|
1.77
|
|
|
($0.05
|
)
|
$
|
1.77
|
|
$
|
1.62
|
|
$
|
0.15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
Dollars in thousands.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Management's
Discussion and Analysis
The
Company’s net income from continuing operations increased $39,000 in 2006 when
compared to 2005. Net income was $10.50 million, or $1.72 per share (diluted),
for 2006, compared to a net income of $10.47 million, or $1.77 per share
(diluted).
The
Company’s net income from continuing operations increased $918,000, or 10
percent, in 2005 compared to 2004. Net income from continuing operations was
$10.5 million, or $1.77 per share (diluted), compared to a net income from
continuing operations of $9.6 million, or $1.64 per share (diluted) for 2004.
During
2003, Chesapeake decided to exit the water services business and had sold the
assets of six of seven dealerships by December 31, 2003. The remaining operation
was sold in 2004. The results of water services were classified as discontinued
operations for year 2004. Discontinued operations experienced losses of $0.02
per share (diluted) for 2004.
Operating
Income Summary (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Years Ended December 31,
|
|
2006
|
|
2005
|
|
Increase
(decrease)
|
|
2005
|
|
2004
|
|
Increase
(decrease)
|
|
Business
Segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$
|
19,733
|
|
$
|
17,236
|
|
$
|
2,497
|
|
$
|
17,236
|
|
$
|
17,091
|
|
$
|
145
|
|
Propane
|
|
|
2,534
|
|
|
3,209
|
|
|
(675
|
)
|
|
3,209
|
|
|
2,364
|
|
|
845
|
|
Advanced
information services
|
|
|
767
|
|
|
1,197
|
|
|
(430
|
)
|
|
1,197
|
|
|
387
|
|
|
810
|
|
Other
& eliminations
|
|
|
(103
|
)
|
|
(112
|
)
|
|
9
|
|
|
(112
|
)
|
|
128
|
|
|
(240
|
)
|
Total
Operating Income
|
|
$
|
22,931
|
|
$
|
21,530
|
|
$
|
1,401
|
|
$
|
21,530
|
|
$
|
19,970
|
|
$
|
1,560
|
|
2006
Compared to 2005
Operating
income in 2006 increased $1.4 million, or 6.5 percent, greater than 2005,
despite adverse weather, which when measured in terms of heating degree-days,
was 18 percent warmer. The improved 2006 results of operations when compared
to
2005 were impacted by:
· |
Weather
on the Delmarva Peninsula was 18 percent warmer in 2006 than 2005,
which
the Company estimates to have cost approximately $3.4 million in
gross
margin for its Delmarva natural gas and propane distribution operations.
|
· |
Strong
residential customer growth of 9 percent and 8 percent, respectively,
for
the Delmarva and Florida natural gas distribution operations in 2006.
|
· |
The
natural gas transmission operation achieved gross margin growth of
$1.8
million, or 11 percent, due to additional capacity contracts that
went
into effect in November 2005 and November 2006.
|
· |
A
67 percent increase in the number of customers for the Company’s natural
gas marketing operation.
|
· |
Gross
margin for the Delmarva propane distribution operations decreased
$834,000, primarily from the warmer weather in
2006.
|
· |
The
Delmarva Community Gas Systems continue to experience strong customer
growth as the number of customers increased 34 percent in 2006 compared
to
2005.
|
· |
Operating
income for the advanced information services segment decreased $430,000
in
2006. Although revenues from consulting increased $749,000 in 2006,
the
2005 results contained $993,000 of operating income for the
LAMPSTM
product,
which was sold in the fourth quarter
2005.
|
2005
Compared to 2004
The
improvement in results for 2005 versus 2004 was primarily driven
by:
· |
The
LAMPS™ product, including the sale of its property rights, contributed
$622,000 to operating income in 2005 for the Company’s advanced
information services segment.
|
· |
The
Delmarva and Florida natural gas distribution operations experienced
strong residential customer growth of 9 percent and 7 percent,
respectively, in 2005.
|
Management's
Discussion and Analysis
· |
Temperatures
on the Delmarva Peninsula were 5 percent colder than 2004, which
led to
increased contributions from the Company’s natural gas and propane
distribution operations. This increase was offset by conservation
efforts
by customers.
|
· |
The
natural gas transmission operation achieved gross margin growth of
9
percent due to additional transportation capacity contracts that
went into
effect in November 2004.
|
· |
A
100 percent increase in the number of customers for the Company’s natural
gas marketing operation.
|
· |
An
increase of 1.1 million gallons sold by the Delmarva propane distribution
operation.
|
Natural
Gas Distribution, Transmission, and Marketing
The
natural gas segment earned operating income of $19.7 million for 2006, $17.2
million for 2005, and $17.1 million for 2004, resulting in increases of $2.5
million, or 14.5 percent, for 2006 and $145,000, or 1.0 percent, for
2005.
Natural
Gas Distribution, Transmission, and Marketing (in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Years Ended December 31,
|
|
2006
|
|
2005
|
|
Increase
(decrease)
|
|
2005
|
|
2004
|
|
Increase
(decrease)
|
|
Revenue
|
|
$
|
170,374
|
|
$
|
166,582
|
|
$
|
3,792
|
|
$
|
166,582
|
|
$
|
124,246
|
|
$
|
42,336
|
|
Cost
of gas
|
|
|
117,948
|
|
|
116,178
|
|
|
1,770
|
|
|
116,178
|
|
|
77,456
|
|
|
38,722
|
|
Gross
margin
|
|
|
52,426
|
|
|
50,404
|
|
|
2,022
|
|
|
50,404
|
|
|
46,790
|
|
|
3,614
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
& maintenance
|
|
|
22,673
|
|
|
23,874
|
|
|
(1,201
|
)
|
|
23,874
|
|
|
21,129
|
|
|
2,745
|
|
Depreciation
& amortization
|
|
|
6,312
|
|
|
5,682
|
|
|
630
|
|
|
5,682
|
|
|
5,418
|
|
|
264
|
|
Other
taxes
|
|
|
3,708
|
|
|
3,612
|
|
|
96
|
|
|
3,612
|
|
|
3,152
|
|
|
460
|
|
Other
operating expenses
|
|
|
32,693
|
|
|
33,168
|
|
|
(475
|
)
|
|
33,168
|
|
|
29,699
|
|
|
3,469
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Operating Income
|
|
$
|
19,733
|
|
$
|
17,236
|
|
$
|
2,497
|
|
$
|
17,236
|
|
$
|
17,091
|
|
$
|
145
|
|
Heating
Degree-Day (HDD) and Customer Analysis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Years Ended December 31,
|
|
2006
|
|
2005
|
|
Increase
(decrease)
|
|
2005
|
|
2004
|
|
Increase
(decrease)
|
|
Heating
degree-day data — Delmarva
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
HDD
|
|
|
3,931
|
|
|
4,792
|
|
|
(861
|
)
|
|
4,792
|
|
|
4,553
|
|
|
239
|
|
10-year
average HDD
|
|
|
4,372
|
|
|
4,436
|
|
|
(64
|
)
|
|
4,436
|
|
|
4,383
|
|
|
53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
gross margin per HDD
|
|
$
|
2,013
|
|
$
|
2,234
|
|
|
($221
|
)
|
$
|
2,234
|
|
$
|
1,800
|
|
$
|
434
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
dollars per residential customer added:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
margin
|
|
$
|
372
|
|
$
|
372
|
|
$
|
0
|
|
$
|
372
|
|
$
|
372
|
|
$
|
0
|
|
Other
operating expenses
|
|
$
|
111
|
|
$
|
106
|
|
$
|
5
|
|
$
|
106
|
|
$
|
104
|
|
$
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
number of residential customers
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delmarva
|
|
|
40,535
|
|
|
37,346
|
|
|
3,189
|
|
|
37,346
|
|
|
34,352
|
|
|
2,994
|
|
Florida
|
|
|
12,663
|
|
|
11,717
|
|
|
946
|
|
|
11,717
|
|
|
10,910
|
|
|
807
|
|
Total
|
|
|
53,198
|
|
|
49,063
|
|
|
4,135
|
|
|
49,063
|
|
|
45,262
|
|
|
3,801
|
|
2006
Compared to 2005
Gross
margin for the Company’s natural gas segment increased $2.0 million, or 4
percent, and other operating expenses decreased $475,000, or 1 percent, in
2006
compared to 2005. The gross margin increases of $1.8 million for the natural
gas
transmission operation, $395,000 for the Florida natural gas distribution
operation and $75,000 for the natural gas marketing operation were partially
offset by lower gross margin of $210,000 for the Delmarva natural gas
distribution operations.
Management's
Discussion and Analysis
Natural
Gas Transmission
The
natural gas transmission operation achieved gross margin growth of $1.8 million,
or 11 percent. Of the $1.8 million increase, $1.1 million was attributed to
new
transportation capacity contracts implemented in November 2005 and $612,000
due
to new transportation capacity contracts implemented in November 2006. In 2007,
the new transportation capacity contracts implemented in November 2006 are
expected to generate an additional gross margin of $3.3 million above and beyond
2006 gross margins. An increase of $416,000 in other operating expenses
partially offset the increased gross margin. The factors contributing to the
increased expenses are as follow:
· |
Payroll
costs and incentive compensation increased $108,000 to serve the
additional growth experienced by the operation.
|
· |
Higher
depreciation and asset removal costs of $558,000 and increased property
taxes of $109,000 due to an increase in the level of capital
investment.
|
· |
A
reduction of $376,000 as a result of the operation receiving approval
from
the FERC to recover certain pre-service costs associated with the
Bay
Crossing Project. Please refer to the Regulatory Matters section
under
Other Matters within Item 2 of the Management’s Discussion and Analysis
for additional details. As a result of this approval, the Company
is
deferring the pre-service costs that it incurs. In 2006, the Company
deferred $188,000 of costs previously incurred and expensed in 2005.
As a
result of this deferral, the amounts recognized in the Company’s income
statement have declined from 2005 by
$376,000.
|
· |
There
was an increase of approximately $17,000 in other operating expenses
relating to various minor items.
|
Natural
Gas Marketing
Gross
margin for the natural gas marketing operation increased $75,000 for 2006
compared to 2005. The increase was attained primarily from an increase in the
number of customers to which it provides supply management services. Other
operating expenses decreased $78,000 for the operation due to lower levels
of
consulting services, partially offset by an increase in the allowance for
uncollectible accounts.
Natural
Gas Distribution
Gross
margin for the Florida distribution operation increased by $395,000. The impact
of an 8 percent growth in residential customers contributed $230,000 to gross
margin. In addition to residential customer growth, new commercial and
industrial customers contributed $91,000 to gross margin in 2006. The remaining
$74,000 increase in gross margin is attributed to various factors, including
turn-on revenue.
The
Delmarva distribution operations experienced a decrease of $210,000 in gross
margin. Weather significantly impacted gross margin in 2006 compared to 2005
as
temperatures on the Delmarva Peninsula were 18 percent warmer in 2006. The
Company estimates that the warmer temperatures in 2006 led to a decrease in
gross margin of approximately $1.7 million when compared to 2005. This decrease
was partially offset by continued residential customer growth. The average
number of residential customers on the Delmarva Peninsula increased 3,189,
or 9
percent, for 2006 compared to 2005 and the Company estimates these additional
residential customers contributed approximately $1.2 million to gross margin.
The remaining $190,000 increase in gross margin can be attributed to various
factors, including an increase in the number of commercial customers and
decrease of interruptible sales.
Other
operating expense for the natural gas distribution operations decreased $814,000
in 2006 compared to 2005. Some of the key components of the decrease in other
operating expenses in 2006, compared to 2005, include the following:
· |
Health
care costs decreased by $313,000 as a result of the Company changing
health care service providers in November 2005 and has subsequently
experienced lower costs related to claims.
|
· |
Allowance
for uncollectible accounts decreased by $289,000 in 2006 compared
to 2005
due to lower revenues and increased collection efforts. Revenues
are down
due to lower prices and warmer
temperatures.
|
· |
Incentive
compensation decreased $177,000 in 2006 to reflect lower than expected
earnings
|
· |
Lower
corporate costs due to lower payroll and related
expenses.
|
· |
Depreciation
and amortization expense and asset removal cost increased $132, 000
and
$186, 000, respectively, as a result of the Company’s continued capital
investments.
|
Management's
Discussion and Analysis
· |
Merchant
payment fees increased $136,000 in 2006 compared to 2005 as the Company
experienced more customers making payments with the use of credit
cards.
|
· |
In
addition, there is an increase of approximately $55,000 in other
operating
expenses relating to various minor
items.
|
2005
Compared to 2004
Gross
margin for the Company’s natural gas segment increased $3.6 million, or 8
percent, which was partially offset by higher other operating expenses of $3.5
million in 2005 compared to 2004. Each of the natural gas operations experienced
year-over-year increases in gross margin in 2005, primarily from customer
growth, colder temperatures, and changes in rate design.
Natural
Gas Transmission
The
natural gas transmission operation achieved gross margin growth of $1.4 million,
or 9 percent, primarily due to additional contracts signed in November 2004
for
transportation capacity provided to its firm customers. In addition, the
Company’s capital investments enabled the natural gas transmission operations to
execute additional transportation capacity contracts in November 2005. An
increase of $980,000 in other operating expenses partially offset the increased
gross margin. The factors contributing to the increased expenses were associated
with continued economic growth, as well as higher depreciation and property
taxes due to an increase in the level of capital investments.
Natural
Gas Marketing
Gross
margin for the natural gas marketing operation increased $506,000, or 39
percent, for 2005 compared to 2004 as the number of customers to which it
provides supply management services increased 100 percent. The increase in
gross
margin was partially offset by an increase of $352,000 in other operating
expenses due to higher levels of staff and other operating costs necessary
to
support the increase in business.
Natural
Gas Distribution
Gross
margin for the Delaware and Maryland distribution divisions increased $1.2
million, as temperatures in 2005 were 5 percent colder than 2004 and the number
of residential customers increased 8.7 percent. An increase in gross margin
from
the colder weather of $534,000 was offset by a decrease of $651,000 in gas
deliveries to customers as a result of conservation efforts in response to
the
higher gas prices.
Gross
margin for the Florida distribution operations increased $579,000, primarily
due
to changes in the customer rate design and a 7.4 percent increase in the number
of residential customers served. The Company estimates the rate design changes
contributed $322,000 in additional gross margin and resulted in the Florida
division collecting a greater percentage of revenues from fixed charges, rather
than variable charges based upon consumption. Other operating expense for the
natural gas distribution operations increased $2.1 million in 2005. Some of
the
key components of the increase in other operating expenses in 2005, compared
to
2004, include the following:
· |
The
incremental operating and maintenance cost of supporting the residential
customers added by the Delmarva and Florida distribution operations
was
approximately $403,000.
|
· |
In
response to higher natural gas prices, the Company increased its
allowance
for uncollectible accounts by
$98,000.
|
· |
The
cost of providing health care for our employees increased $180,000.
|
· |
Costs
of line location activities increased
$177,000.
|
· |
With
the additional capital investments, depreciation expense, asset removal
cost and property taxes increased $225,000, $130,000 and $319,000,
respectively.
|
Management's
Discussion and Analysis
Propane
The
propane segment experienced a decrease of $675,000 in operating income in 2006
compared to 2005, reflecting a gross margin decrease of $1.1 million, which
was
partially offset by a decrease in operating expenses of $464,000.
During
2005, the propane segment increased operating income by $845,000, or 36 percent,
over 2004. Gross margin in 2005 increased $2.6 million over 2004, which more
than offset the increase of $1.7 million of operating expenses.
Propane
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Years Ended December 31,
|
|
2006
|
|
2005
|
|
Increase
(decrease)
|
|
2005
|
|
2004
|
|
Increase
(decrease)
|
|
Revenue
|
|
$
|
48,576
|
|
$
|
48,976
|
|
|
($400
|
)
|
$
|
48,976
|
|
$
|
41,500
|
|
$
|
7,476
|
|
Cost
of sales
|
|
|
30,780
|
|
|
30,041
|
|
|
739
|
|
|
30,041
|
|
|
25,155
|
|
|
4,886
|
|
Gross
margin
|
|
|
17,796
|
|
|
18,935
|
|
|
(1,139
|
)
|
|
18,935
|
|
|
16,345
|
|
|
2,590
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
& maintenance
|
|
|
12,823
|
|
|
13,355
|
|
|
(532
|
)
|
|
13,355
|
|
|
11,718
|
|
|
1,637
|
|
Depreciation
& amortization
|
|
|
1,659
|
|
|
1,574
|
|
|
85
|
|
|
1,574
|
|
|
1,524
|
|
|
50
|
|
Other
taxes
|
|
|
780
|
|
|
797
|
|
|
(17
|
)
|
|
797
|
|
|
739
|
|
|
58
|
|
Other
operating expenses
|
|
|
15,262
|
|
|
15,726
|
|
|
(464
|
)
|
|
15,726
|
|
|
13,981
|
|
|
1,745
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Operating Income
|
|
$
|
2,534
|
|
$
|
3,209
|
|
|
($675
|
)
|
$
|
3,209
|
|
$
|
2,364
|
|
$
|
845
|
|
Propane
Heating Degree-Day (HDD) Analysis — Delmarva
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Years Ended December 31,
|
|
2006
|
|
2005
|
|
Increase
(decrease)
|
|
2005
|
|
2004
|
|
Increase
(decrease)
|
|
Heating
degree-days
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
|
|
|
3,931
|
|
|
4,792
|
|
|
(861
|
)
|
|
4,792
|
|
|
4,553
|
|
|
239
|
|
10-year
average
|
|
|
4,372
|
|
|
4,436
|
|
|
(64
|
)
|
|
4,436
|
|
|
4,383
|
|
|
53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
gross margin per HDD
|
|
$
|
1,743
|
|
$
|
1,743
|
|
$
|
0
|
|
$
|
1,743
|
|
$
|
1,691
|
|
$
|
52
|
|
2006
Compared to 2005
Operating
income for the propane segment decreased $675,000, or 21 percent, to $2.5
million for 2006 compared to 2005. This decrease was due primarily to warmer
weather on the Delmarva Peninsula in 2006, which resulted in reduced customer
consumption. Gross margin in the Delmarva propane distribution operations was
lower when compared to 2005 by $834,000, primarily due to warmer weather. Gross
margin also decreased in the Florida propane distribution operation and the
Company’s wholesale propane marketing operation by $146,000 and $159,000,
respectively.
Delmarva
Propane Distribution
The
Delmarva propane distribution operation’s decrease in gross margin of $834,000
resulted from the following items:
· |
Volumes
sold in 2006 decreased 1.9 million gallons, or 8 percent, primarily
from
temperatures on the Delmarva Peninsula being 18 percent warmer during
2006
when compared to 2005. The Company estimates that the warmer temperatures
resulted in a decrease in gross margin of approximately $1.7 million
when
compared to 2005.
|
· |
Gross
margin increased $956,000 from an increase of $0.0302 in the average
gross
margin per retail gallon in 2006 compared to 2005.
|
· |
Gross
margin for the Delmarva CGS increased $155,000 when compared to the
prior
period, primarily from an increase in the average number of customers.
The
average number of customers increased by approximately 1,000 to a
total
count of approximately 3,900, or a 34 percent increase, when compared
to
2005. The Company expects the growth of its CGS operation to continue
as
the number of systems currently under construction or under contract
is
anticipated to provide for an additional 7,700
customers.
|
· |
Gross
margin was adversely impacted by a $272,000 write-down of propane
inventory to reflect the lower of cost or market.
|
Management's
Discussion and Analysis
· |
The
remaining gross margin decrease of $29,000 is attributed primarily
to
customer conservation and changes in the timing of deliveries to
customers.
|
Other
operating expenses decreased $335,000 for the Delmarva operations in 2006,
compared to 2005. The significant items contributing to the decrease are
explained below.
· |
The
Company recovered $387,000 in fixed costs from one of its propane
suppliers in response to a propane contamination incident that occurred
in
March 2006. The Company identified that approximately 75,000 gallons
of
propane that it purchased from the supplier contained above-normal
levels
of petroleum byproducts.
|
· |
Health
care costs decreased by $324,000. The Company changed health care
service
providers in November 2005 and has subsequently experienced lower
costs
related to claims.
|
· |
In
addition, there is a decrease of approximately $39,000 in other operating
expenses relating to various minor
items.
|
· |
These
lower costs were partially offset by increased costs of $176,000
for one
of the Pennsylvania start-ups, which began operation in July 2005,
increased payroll costs of $165,000 and higher costs of $74,000 associated
with vehicle fuel.
|
Florida
Propane Distribution
The
Florida propane distribution operation experienced a decrease in gross margin
of
$146,000, or 12 percent, when compared to the same period in 2005. The lower
gross margin reflects a decrease of $208,000 for in-house piping sales as the
operation exited the house piping service, which was partially offset by an
increase in gross margin of $62,000 from propane sales. The increase in gross
margin from propane sales was attained primarily from an increase in the average
gross margin per retail gallon, partially offset by a 1 percent decrease in
the
volumes sold in 2006. Florida propane experienced a decrease in other operating
expenses in 2006 compared to 2005 of $49,000 attributed to lower payroll and
benefits costs due to vacant positions during the year, partially offset by
higher expenses related to leak testing and depreciation expense.
Propane
Wholesale and Marketing
Gross
margin for the Company’s propane wholesale marketing operation decreased by
$159,000 in 2006 compared to 2005. This decrease from the 2005 results reflects
the increased market opportunities that rose in 2005 due to the extreme price
volatility in the propane wholesale market from rising propane prices following
the hurricanes in the Gulf of Mexico area. The same level of price fluctuations
was not experienced in 2006. The decrease in gross margin was partially offset
by lower other operating expenses of $79,000 attributed primarily to lower
incentive compensation as a result of the lower earnings in 2006.
2005
Compared to 2004
Operating
income for the propane segment increased $846,000, or 36 percent, to $3.2
million for 2005 compared to 2004. Gross margin in the Delmarva propane
distribution operations was higher when compared to 2004 by $1.8 million,
primarily due to colder weather. Gross margin also increased in the Florida
propane distribution operation and the Company’s wholesale propane marketing
operation by $385,000 and $445,000, respectively.
Delmarva
Propane Distribution
The
gross
margin increase for the propane segment was due primarily to an increase of
$1.8
million for the Delmarva distribution operations. Volumes sold in 2005 increased
1.1 million gallons or 5 percent. Temperatures in 2005 were 5 percent colder
than 2004, causing an estimated gross margin increase of $417,000. Additionally,
the gross margin per retail gallon improved by $0.0342 in 2005 compared to
2004.
Gross margin per gallon increased as a result of market prices rising greater
than the Company’s inventory price per gallon. This trend reverses when market
prices decrease and move closer to the Company’s inventory price per gallon. The
gross margin increase was partially offset by increased other operating expenses
of $1.5 million. The higher other operating costs were attributable to the
Pennsylvania start-up costs and expenses related to higher earnings, such as
incentive compensation and other taxes, employee benefits, insurance, vehicle
fuel and maintenance expenses, and a non-recurring credit of $100,000 for
vehicle insurance audits in 2004. The Pennsylvania start-up costs accounted
for
$722,000, or approximately 49 percent, of the increase in operating expenses.
Management's
Discussion and Analysis
Florida
Propane Distribution
Gross
margin for the Florida propane distribution operations increased $385,000,
or 45
percent, in 2005 compared to 2004. The increase in gross margin was attained
from an increase of 27% in the average number of customers, which contributed
to
the $267,000 in propane sales gross margin, and an increase of $118,000 in
house-piping sales. Florida propane also experienced an increase in other
operating expenses of $147,000 attributed to business growth, such as payroll,
vehicle fuel and maintenance, insurance, and depreciation expense.
Propane
Wholesale and Marketing
The
Company’s propane wholesale marketing operation experienced an increase in gross
margin of $445,000 and an increase of $121,000 in other operating expenses,
leading to an improvement of $323,000 in operating income over 2004. Wholesale
price volatility created trading opportunities during the third and fourth
quarters of the year; however, these were partially offset by reduced trading
activities particularly in the first half of the year when the wholesale
marketing operation followed a conservative marketing strategy, which lowered
risk and earnings, in light of continued high wholesale price
levels.
Advanced
Information Services
The
advanced information services segment provides domestic and international
clients with information technology related business services and solutions
for
both enterprise and e-business applications. The advanced information services
business contributed operating income of $767,000 for 2006, $1.2 million for
2005, and $387,000 for 2004.
Advanced
Information Services (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Years Ended December 31,
|
|
2006
|
|
2005
|
|
Increase
(decrease)
|
|
2005
|
|
2004
|
|
Increase
(decrease)
|
|
Revenue
|
|
$
|
12,568
|
|
$
|
14,140
|
|
|
($1,572
|
)
|
$
|
14,140
|
|
$
|
12,427
|
|
$
|
1,713
|
|
Cost
of sales
|
|
|
7,082
|
|
|
7,181
|
|
|
(99
|
)
|
|
7,181
|
|
|
7,015
|
|
|
166
|
|
Gross
margin
|
|
|
5,486
|
|
|
6,959
|
|
|
(1,473
|
)
|
|
6,959
|
|
|
5,412
|
|
|
1,547
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
& maintenance
|
|
|
4,119
|
|
|
5,129
|
|
|
(1,010
|
)
|
|
5,129
|
|
|
4,405
|
|
|
724
|
|
Depreciation
& amortization
|
|
|
113
|
|
|
123
|
|
|
(10
|
)
|
|
123
|
|
|
138
|
|
|
(15
|
)
|
Other
taxes
|
|
|
487
|
|
|
510
|
|
|
(23
|
)
|
|
510
|
|
|
482
|
|
|
28
|
|
Other
operating expenses
|
|
|
4,719
|
|
|
5,762
|
|
|
(1,043
|
)
|
|
5,762
|
|
|
5,025
|
|
|
737
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Operating Income
|
|
$
|
767
|
|
$
|
1,197
|
|
|
($430
|
)
|
$
|
1,197
|
|
$
|
387
|
|
$
|
810
|
|
2006
Compared to 2005
Operating
income for advanced information services business decreased $430,000 to $767,000
for 2006 compared to $1.2 million in 2005. The operating income for 2005
included operating income of $993,000 for LAMPS™, inclusive of a $924,000
pre-tax gain on the sale of the product. The LAMPSTM
product
was sold to Fidelity National Information Solutions, Inc., a subsidiary of
Fidelity National Financial, Inc., in October 2005.
Revenues
for the period decreased $1.6 million compared to 2005, due primarily to
elimination of $1.9 million of revenue generated by the LAMPSTM
product
in 2005. Consulting revenues increased $749,000 in 2006 when compared to 2005,
primarily from offering a new service, Managed Database Administration (“MDBA”),
to its customers in 2006 and an increase of 7.6 percent in the average hourly
billing rate, while the number of billable hours remained at the same level
of
2005. The MDBA service provides third parties with professional database
monitoring and support solutions during business hours or around the clock.
The
MDBA service contributed $470,000 to consulting revenues. Partially offsetting
the increase in consulting revenues were decreases of $128,000 and $244,000
from
training and product sales and other revenues, respectively.
Management's
Discussion and Analysis
Cost
of
sales for 2006 decreased $99,000 to $7.08 million, compared to 2005. The 2005
cost of sales of $7.18 million included $401,000 related to LAMPSTM.
Absent
the cost of sales associated with the LAMPSTM
product,
cost of sales increased in 2006 compared to 2005 to support the higher revenues.
Other
operating expenses decreased $1.0 million in 2006 to $4.7 million, when compared
to 2005. The reduction in expenses primarily reflects expenses of $554,000
in
2005 associated with LAMPSTM
and
lower benefits costs, rent expense and consulting costs.
2005
Compared to 2004
The
advanced information services segment had operating income of $1.2 million
and
$387,000 for years 2005 and 2004, respectively. The results for 2005 and 2004
include revenues and costs related to the LAMPSTM
product
that was sold in October 2005, which resulted in a $924,000 pre-tax gain.
Revenues
for 2005 increased $1.7 million to $14.1 million compared to revenues of $12.4
million for 2004. The 2005 and 2004 revenue figures include $2.4 million and
$149,000 of revenue relating to the LAMPSTM
product
for those respective years. Decreases in consulting revenues for the eBusiness
group of $793,000 and lower sales of Progress software licenses of $285,000
accounted for the decrease in revenue when compared to 2004. This decrease
was
partially offset by the performance revenue of $238,000 received in the third
quarter 2005 and an increase of $317,000 in consulting revenues for the
Enterprise Solutions group. The performance revenue was related to the sale
of
the webproEX software that took place in 2003. As part of the sale agreement,
Chesapeake received a percentage of revenues after certain annual revenue and
performance targets were reached.
Cost
of
sales for 2005 increased $165,000 to $7.2 million, compared to $7.0 million
for
2004. The increase in cost of sales was attributed to the LAMPSTM
product.
The 2005 and 2004 cost of sales figures included $511,000 and $345,000 of cost
for the LAMPSTM
product.
Other operating expenses increased $738,000 in 2005 to $5.8 million, compared
to
$5.0 million in 2004. The increase in other operating cost was attributed to
the
increase of costs relating to the LAMPSTM
product.
The costs associated with the LAMPSTM
product
for 2005 and 2004 were $1.2 million and $575,000 respectively. The remaining
increase was primarily due to health care claims and office rent, which were
offset by cost containment measures implemented in the second quarter of 2005
to
reduce operating expenses.
Other
Operations and Eliminations
Other
operations consist primarily of subsidiaries that own real estate leased to
other Company subsidiaries and the results of operations for OnSight Energy,
LLC
(“OnSight”). Eliminations are entries required to eliminate activities between
business segments from the consolidated results. Other operations and
eliminating entries generated an operating loss of $103,000 for 2006 compared
to
an operating loss of $112,000 for 2005. The operating loss in both 2006 and
2005
is attributed to results of OnSight.
The
Company formed OnSight in 2004 to provide distributed energy services.
Distributed energy refers to a variety of small, modular power generating
technologies that may be combined with heating and/or cooling systems. For
2006,
OnSight had an operating loss of $401,000 compared to an operating loss of
$390,000 for 2005. The higher operating loss in 2006 when compared to 2005
is
the result of:
· |
In
the third quarter of 2006, actions were taken to reduce operating
expenses
going forward, which resulted in a charge of $65,000 to other operating
expenses associated with staff
reductions.
|
Management's
Discussion and Analysis
· |
The
2005 results of operation includes the impact of OnSight completing
its
first and only contract to date, which occurred in the second quarter
of
2005.
|
Other
Operations & Eliminations (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Years Ended December 31,
|
|
2006
|
|
2005
|
|
Increase
(decrease)
|
|
2005
|
|
2004
|
|
Increase
(decrease)
|
|
Revenue
|
|
$
|
620
|
|
$
|
763
|
|
|
($143
|
)
|
$
|
763
|
|
$
|
647
|
|
$
|
116
|
|
Cost
of sales
|
|
|
1
|
|
|
116
|
|
|
(115
|
)
|
|
116
|
|
|
-
|
|
|
116
|
|
Gross
margin
|
|
|
619
|
|
|
647
|
|
|
(28
|
)
|
|
647
|
|
|
647
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
& maintenance
|
|
|
479
|
|
|
472
|
|
|
7
|
|
|
472
|
|
|
278
|
|
|
194
|
|
Depreciation
& amortization
|
|
|
163
|
|
|
220
|
|
|
(57
|
)
|
|
220
|
|
|
210
|
|
|
10
|
|
Other
taxes
|
|
|
83
|
|
|
97
|
|
|
(14
|
)
|
|
97
|
|
|
63
|
|
|
34
|
|
Other
operating expenses
|
|
|
725
|
|
|
789
|
|
|
(64
|
)
|
|
789
|
|
|
551
|
|
|
238
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income — Other
|
|
|
($106
|
)
|
|
($142
|
)
|
$
|
36
|
|
|
($142
|
)
|
$
|
96
|
|
|
($238
|
)
|
Operating
Income — Eliminations
|
|
$
|
3
|
|
$
|
30
|
|
|
($27
|
)
|
$
|
30
|
|
$
|
32
|
|
|
($2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Operating Income (Loss)
|
|
|
($103
|
)
|
|
($112
|
)
|
$
|
9
|
|
|
($112
|
)
|
$
|
128
|
|
|
($240
|
)
|
Discontinued
Operations
In
2003,
Chesapeake decided to exit the water services business. Six of seven water
dealerships were sold during 2003 and the remaining operation was sold in
October 2004. The results of the water companies’ operations, for all periods
presented in the consolidated income statements, have been reclassified to
discontinued operations and shown net of tax. For 2004, the discontinued
operations experienced a net loss of $121,000. The Company did not have any
discontinued operations in 2006 and 2005.
Income
Taxes
Income
tax expense for 2006 was $6.8 million compared to $6.3 million for 2005. Income
taxes increased in 2006 compared to 2005, due primarily to increased taxable
income. Income taxes increased in 2005 compared to 2004, due to increased
income. The effective current federal income tax rate for 2006 and 2005 was
35
percent, whereas the rate for 2004 was 34 percent. During 2006, 2005, and 2004,
the Company realized benefit of $220,000, $223,000, and $205,000, respectively,
from a change in the tax law that allows tax deductions for dividends paid
on
Company stock held in Employee Stock Ownership Plans (“ESOP”).
Other
Income
Other
income was $189,000, $383,000, and $549,000 for the years 2006, 2005, and 2004,
respectively. The other income amounts for the years 2006 and 2005 consist
of
interest income, compared to interest income and gains from the sale of assets
for the year 2004.
Interest
Expense
Total
interest expense for 2006 increased approximately $644,000, or 12.5 percent,
compared to 2005. The increase reflects the increase in the average short-term
debt balance and higher short-term interest rates in 2006 compared to 2005.
The
average short-term borrowing balance increased $21.2 million in 2006 to $26.9
million compared to $5.7 million in 2005. The large year-over-year increase
in
the average short-term borrowing balance was primarily to finance the $39.3
million of net property, plant, and equipment added in 2006. The weighted
average interest rate for short-term borrowing increased from 4.47 percent
for
2005 to 5.47 percent for 2006. The average long-term debt balance during 2006
was $67.2 million with a weighted average interest rate of 6.98 percent,
compared to $67.4 million with a weighted average interest rate of 7.18 percent
for 2005. The Company also capitalized $586,000 of interest as part of capital
project costs during 2006.
Management's
Discussion and Analysis
Total
interest expense for 2005 decreased approximately $135,000, or 2.6 percent,
compared to 2004. The decrease reflects the decrease in the average long-term
debt balance. The average long-term debt balance during 2005 was $67.4 million
with a weighted average interest rate of 7.18 percent, compared to $71.3 million
with a weighted average interest rate of 7.17 percent in 2004. The average
short-term borrowing balance in 2005 was $5.7 million, an increase from $870,000
in 2004. The weighted average interest rate for short-term borrowing increased
from 3.72 percent for 2004 to 4.47 percent for 2005. The Company also
capitalized $136,000 of interest as part of capital project costs during
2005.
Liquidity
and Capital Resources
Chesapeake’s
capital requirements reflect the capital-intensive nature of its business and
are principally attributable to its investment in new plant and equipment and
the retirement of outstanding debt. The Company relies on cash generated from
operations, short-term borrowing, and other sources to meet normal working
capital requirements and to finance capital expenditures. During 2006, net
cash
provided by operating activities was $30.1 million, cash used by investing
activities was $48.9 million and cash provided by financing activities was
$20.7
million.
During
2005, net cash provided by operating activities was $13.6 million, cash used
by
investing activities was $33.1 million and cash provided by financing activities
was $20.4 million.
As
of
December 31, 2006, the Board of Directors (“Board”) has authorized the Company
to borrow up to $55.0 million of short-term debt from various banks and trust
companies under short-term lines of credit. During 2006, the Board authorized
increases in the Company’s borrowing authority up to $75 million to fund the
2006 capital budget and working capital. The $75 million limit was subsequently
reduced to its current level by the Board on November 7, 2006, following the
placement on October 12, 2006 of $20 million 5.50 percent Senior Notes.
On
December 31, 2006, the Company had four unsecured bank lines of credit with
two
financial institutions, totaling $80.0 million, none of which required
compensating balances. These bank lines provide funds for the Company’s
short-term cash needs to meet seasonal working capital requirements and to
temporarily fund portions of its capital expenditures. Two of the bank lines,
totaling $15.0 million, are committed. The other two lines are subject to the
banks’ availability of funds. The outstanding balances of short-term debt at
December 31, 2006 and 2005 were $27.6 million and $35.5 million, respectively.
The level of short-term debt was reduced with funds provided from the placement
of $20 million of 5.5 percent Senior Notes in October 2006 and from the proceeds
of the issuance of 600,300 shares of common stock in November 2006.
Chesapeake
has budgeted $45.5 million for capital expenditures during 2007. This amount
includes $20.2 million for natural gas distribution, $16.5 million for natural
gas transmission, $7.5 million for propane distribution and wholesale marketing,
$154,000 for advanced information services and $915,000 million for other
operations. The natural gas distribution and transmission expenditures are
for
expansion and improvement of facilities. The propane expenditures are to support
customer growth and for the replacement of equipment. The advanced information
services expenditures are for computer hardware, software and related equipment.
The other category includes general plant, computer software and hardware.
Financing for the 2007 capital expenditure program is expected from short-term
borrowing, cash provided by operating activities, and other sources. The capital
expenditure program is subject to continuous review and modification. Actual
capital requirements may vary from the above estimates due to a number of
factors, including acquisition opportunities, changing economic conditions,
customer growth in existing areas, regulation, new growth opportunities and
availability of capital.
Management's
Discussion and Analysis
Chesapeake
expects to incur approximately $75,000 in 2007 and 2008 for
environmental-related expenditures. Additional expenditures may be required
in
future years (see Note M to the Consolidated Financial Statements). Management
does not expect financing of future environmental-related expenditures to have
a
material adverse effect on the financial position or capital resources of the
Company.
Cash
Flows Provided
by Operating Activities
Our
cash
flows provided by (used in) operating activities were as
follows:
For
the Years Ended December 31,
|
|
2006
|
|
2005
|
|
2004
|
|
Net
income
|
|
$
|
10,506,525
|
|
$
|
10,467,614
|
|
$
|
9,428,767
|
|
Non-cash
adjustments to net income
|
|
|
11,186,418
|
|
|
13,059,678
|
|
|
16,342,116
|
|
Changes
in working capital
|
|
|
8,424,055
|
|
|
(9,927,351
|
)
|
|
(3,767,730
|
)
|
Net
cash from operating activties
|
|
$
|
30,116,998
|
|
$
|
13,599,941
|
|
$
|
22,003,153
|
|
Year-over-year
changes in our cash flows from operating activities are attributable primarily
to net income, depreciation and working capital changes. The changes in working
capital are impacted by weather, the price of natural gas and propane, the
timing of customer collections, payments of natural gas and propane purchases,
and deferred gas cost recoveries.
The
Company generates a large portion of its annual net income and subsequent
increases in our accounts receivable in the first and fourth quarters of each
year due to significant volumes of natural gas and propane delivered by our
Delmarva natural gas and propane distribution operations to our customers during
the peak heating season. In addition, our natural gas and propane inventories,
which usually peak in the fall months, are largely drawn down in the heating
season and provide a source of cash as the inventory is used to satisfy winter
sales demand.
During
this period, our accounts payable increased to reflect payments due to providers
of the natural gas, propane commodities and pipeline capacity. The value of
the
natural gas and propane can vary significantly from one period to the next
as a
result of volatility in the prices of these commodities. Our natural gas costs
and deferred purchased natural gas costs due from, or to, our customers
represent the difference between natural gas costs that we have paid to
suppliers in the past and amounts that we have collected from customers. These
natural gas costs can cause significant variations in cash flows from period
to
period.
In
2006,
our net cash flow provided by operating activities was $30.1 million, an
increase of $16.5 million from the same period of 2005. The increase was
primarily a result of the recovery of working capital during 2006 that was
deployed in 2005 due to the significantly higher commodity prices and the amount
of working capital required for operations. Contributing to this increase was
a
decrease in the amount of natural gas and propane purchased for inventory of
$6.1 million as a result of mild weather in the prior heating season and
therefore higher inventory balances for the current heating season.
In
2005,
our net cash flow provided by operating activities was $13.6 million, a decrease
of $8.4 million from the same period of 2004. The decrease was primarily a
result of increased working capital requirements including increased spending
of
$5.7 million for seasonal natural gas and propane inventories in advance of
the
winter sales demand. We spent more on these inventories in 2005 primarily
because of higher natural gas and propane prices due to the effects of the
hurricanes in the Gulf Coast region. The Company also used
$1.2
million of cash to purchase investments for the
Rabbi
Trust associated with the Company’s Supplemental Executive Retirement Savings
Plan. See Note E on Investments in Item 8 under the heading “Financial
Statements and Supplemental Data.”
Cash
Flows Used in Investing Activities
Net
cash
flows used in investing activities totaled $48.9 million, $33.1 million, and
$15.5 million during fiscal years 2006, 2005, and 2004, respectively. In fiscal
years 2006, 2005, and 2004, $48.8 million, $33.3 million, and $16.4 million,
respectively, of cash were utilized for capital expenditures. Additions
to property, plant and equipment in 2006 were primarily for natural gas
transmission ($28.0 million), natural gas distribution ($16.1 million) and
propane distribution ($4.3 million). In both 2006 and 2005, the natural gas
distribution expenditures were used primarily to fund expansion and facilities
improvements. Natural gas transmission capital expenditures related primarily
to
expanding the Company’s transmission system.
Management's
Discussion and Analysis
Cash
Flows Provided by Financing Activities
Cash
flows provided by financing activities totaled $20.7 million during 2006, $20.4
million during 2005 and cash flows used by financing activities was $8.0 million
for 2004. Our significant financing activities for the years 2006, 2005, and
2004 are summarized as follow:
· |
In
November 2006, the Company sold 600,300 shares of common stock, including
the underwriter’s exercise of their over-allotment option of 90,045
shares, pursuant to a shelf registration statement declared effective
in
November 2006, generating net proceeds of $19.7 million.
|
· |
In
October 2006, the Company placed $20 million of 5.5 percent Senior
Notes
(“Notes”) to three institutional investors (The Prudential Insurance
Company of America, Prudential Retirement Insurance and Annuity Company
and United Omaha Life Insurance Company). The original note agreement
was
executed on October 18, 2005 and provided for the Company to sell
the
Notes at any time prior to January 15,
2007.
|
· |
The
Company repaid $4.9 million of long-term debt during 2006 compared
with
$4.8 million during 2005 and $3.7 million during
2004.
|
· |
During
2006, the Company reduced short-term debt by $8.0 million. During
2005 and
2004, net borrowing of short-term debt increased by $29.6 million
and $1.2
million, respectively, primarily to support our capital
investment.
|
· |
During
2006, the Company paid $6.0 million in cash dividends compared with
dividend payments of $5.8 million and $5.6 million for years 2005
and
2004, respectively. The increase in dividends paid over prior year
reflects the increase in the dividend rate from $1.14 per share during
2005 to $1.16 per share during 2006 and the issuance of additional
shares
of common stock.
|
· |
In
August 2006, the Company paid cash of $435,000, in lieu of issuing
shares
of the Company’s common stock for the 30,000 stock warrants outstanding at
December 31, 2005.
|
Capital
Structure
The
following presents our capitalization as of December 31, 2006 and
2005:
|
|
December
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands, except percentages)
|
|
Long-term
debt, net of current maturities
|
|
$
|
71,050
|
|
|
39
|
%
|
$
|
58,990
|
|
|
41
|
%
|
Shareholders'
equity
|
|
$
|
111,152
|
|
|
61
|
%
|
$
|
84,757
|
|
|
59
|
%
|
Total
capitalization, excluding short-term debt
|
|
$
|
182,202
|
|
|
100
|
%
|
$
|
143,747
|
|
|
100
|
%
|
The
Company increased its capitalization by $38.5 million in 2006 compared to 2005.
The increased capitalization was primarily used to fund the $39.3 million of
net
property, plant, and equipment added in 2006 and for working
capital.
As
of
December 31, 2006, common equity represented 61 percent of total capitalization,
compared to 59 percent in 2005.
Management's
Discussion and Analysis
The
following presents our capitalization as of December 31, 2006 and 2005 if
short-term borrowing and current portion of long-term debt were included in
capitalization:
|
|
December
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands, except percentages)
|
|
Short-term
debt
|
|
$
|
27,554
|
|
|
13
|
%
|
$
|
35,482
|
|
|
19
|
%
|
Long-term
debt, including current maturities
|
|
$
|
78,706
|
|
|
36
|
%
|
$
|
63,919
|
|
|
35
|
%
|
Shareholders'
equity
|
|
$
|
111,152
|
|
|
51
|
%
|
$
|
84,757
|
|
|
46
|
%
|
Total
capitalization, including short-term debt
|
|
$
|
217,412
|
|
|
100
|
%
|
$
|
184,158
|
|
|
100
|
%
|
If
short-term borrowing and current portion of long-term debt were included in
capitalization, total capitalization increased by $33.3 million in 2006 compared
to 2005. The increased capitalization was primarily used to fund a portion
of
the $39.3 million of net property, plant, and equipment added in 2006 and for
other general working capital. In addition, if short-term borrowing and the
current portion of long-term debt were included in total capitalization, the
equity component of the Company’s capitalization would have been 51 percent and
46 percent for 2006 and 2005, respectively.
Total
debt as a percentage of total capitalization, including short-term debt, was
49
percent and 54 percent at December 31, 2006 and 2005, respectively. The decrease
in the debt-to-capitalization ratio in 2006 was primarily attributed to the
following:
· |
The
Company sold 600,300 additional shares of common stock pursuant to
a shelf
registration declared effective by the SEC in November 2006. The
sale of
these additional shares increased total shareholder’s equity by
approximately $19.7 million.
|
· |
The
outstanding long-term debt balance increased $14.8 million. Contributing
to the increase was the placement of $20 million of 5.5 percent Senior
Notes in October 2006, partially offset by scheduled principal
payments.
|
· |
The
outstanding short-term debt balance decreased $7.9 million. The Company
reduced its outstanding short-term debt with funds received from
the sale
of additional shares of common stock and the placement of the Senior
Notes.
|
Chesapeake
remains committed to maintaining a sound capital structure and strong credit
ratings to provide the financial flexibility needed to access the capital
markets when required. This commitment, along with adequate and timely rate
relief for the Company’s regulated operations, is intended to ensure that
Chesapeake will be able to attract capital from outside sources at a reasonable
cost. The Company believes that the achievement of these objectives will provide
benefits to customers and creditors, as well as to the Company’s
investors.
Shelf
Registration
In
July
2006, the Company filed a registration statement on Form S-3 with the SEC to
issue up to $40.0 million in new common stock and/or debt securities. The
registration statement was declared effective by the SEC in November 2006.
In
November 2006, we sold 600,300 shares of common stock, including the
underwriter’s exercise of their over-allotment option of 90,045 shares, under
this registration statement, generating net proceeds of $19.7 million. The
net
proceeds from the sale were used for general corporate purposes, including
financing of capital expenditures, repayment of short-term debt, and general
working capital purposes. At December 31, 2006, the Company had approximately
$20.0 million remaining under this registration statement.
Management's
Discussion and Analysis
Contractual
Obligations
We
have
the following contractual obligations and other commercial commitments as of
December 31, 2006:
|
|
Payments
Due by Period
|
|
Contractual
Obligations
|
|
Less
than 1 year
|
|
1
- 3 years
|
|
3
- 5 years
|
|
More
than 5 years
|
|
Total
|
|
Long-term
debt (1)
|
|
$
|
7,656,364
|
|
$
|
14,312,727
|
|
$
|
14,403,636
|
|
$
|
42,333,636
|
|
$
|
78,706,363
|
|
Operating
leases (2)
|
|
|
649,659
|
|
|
919,216
|
|
|
652,026
|
|
|
3,769,640
|
|
|
5,990,541
|
|
Purchase
obligations (3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transmission
capacity
|
|
|
7,182,746
|
|
|
12,413,145
|
|
|
8,154,556
|
|
|
23,523,355
|
|
|
51,273,802
|
|
Storage
— Natural Gas
|
|
|
1,363,488
|
|
|
2,698,742
|
|
|
2,666,955
|
|
|
5,163,488
|
|
|
11,892,673
|
|
Commodities
|
|
|
17,862,123
|
|
|
|
|
|
|
|
|
|
|
|
17,862,123
|
|
Forward
purchase contracts — Propane (4)
|
|
|
13,868,391
|
|
|
|
|
|
|
|
|
|
|
|
13,868,391
|
|
Unfunded
benefits (5)
|
|
|
292,445
|
|
|
588,705
|
|
|
614,043
|
|
|
2,710,528
|
|
|
4,205,721
|
|
Funded
benefits (6)
|
|
|
323,500
|
|
|
148,364
|
|
|
117,732
|
|
|
1,419,046
|
|
|
2,008,642
|
|
Total
Contractual Obligations
|
|
$
|
49,198,716
|
|
$
|
31,080,899
|
|
$
|
26,608,948
|
|
$
|
78,919,693
|
|
$
|
185,808,256
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Principal payments on long-term debt, see Note H, "Long-Term Debt,"
in the
Notes to the Consolidated Financial Statements for additional discussion
of this item. The expected interest payments on long-term debt
are $5.2
million, $8.8 million, $6.9 million and $10.0 million, respectively,
for
the periods indicated above. Expected interest payments for all
periods
total $ 30.9 million.
|
|
(2)
See Note J, "Lease Obligations," in the Notes to the Consolidated
Financial Statements for additional discussion of this
item.
|
|
(3)
See Note N, "Other Commitments and Contingencies," in the Notes
to the
Consolidated Financial Statements for further information.
|
|
(4)
The Company has also entered into forward sale contracts. See "Market
Risk" of the Management's Discussion and Analysis for further
information.
|
|
(5)
The Company has recorded long-term liabilities of $4.2 million
at December
31, 2006 for unfunded post-retirement benefit plans. The amounts
specified
in the table are based on expected payments to current retirees
and
assumes a retirement age of 65 for currently active employees.
There are
many factors that would cause actual payments to differ from these
amounts, including early retirement, future health care costs that
differ
from past experience and discount rates implicit in
calculations.
|
|
(6)
The Company has recorded long-term liabilities of $2.0 million
at December
31, 2006 for funded benefits. These liabilities have been funded
using a
Rabbi Trust and an asset in the same amount is recorded under Investments
on the Balance Sheet. The defined benefit pension plan was closed
to new
participants on January 1, 1999 and participants in the plan on
that date
were given the option to leave the plan. See Note K, "Employee
Benefit
Plans," in the Notes to the Consolidated Financial Statements for
further
information on the plan. Since the plan modification, no additional
funding has been required from the Company and none is expected
for the
next five years, based on factors in effect at December 31, 2006.
However,
this is subject to change based on the actual return earned by
the plan
assets and other actuarial assumptions, such as the discount rate
and
long-term expected rate of return on plan assets.
|
|
Off-Balance
Sheet Arrangements
The
Company has issued corporate guarantees to certain vendors of its propane
wholesale marketing subsidiary, its natural gas supply and management
subsidiary, and propane distribution subsidiary. These corporate guarantees
provide for the payment of propane and natural gas purchases in the event of
the
subsidiaries’ default. The liabilities for these purchases are recorded in the
Consolidated Financial Statements. The aggregate amount guaranteed at December
31, 2006, totaled $21.4 million, with the guarantees expiring on various dates
in 2007.
In
addition to the corporate guarantees, the Company has issued a letter of credit
to its primary insurance company for $775,000, which expires on May 31, 2007.
The letter of credit is provided as security for claims amounts to satisfy
the
deductibles on the Company’s policies. The current letter of credit was renewed
during the second quarter of 2006 when the insurance policies were renewed.
Regulatory
Activities
The
Company’s natural gas distribution operations are subject to regulation by the
Delaware, Maryland and Florida Public Service Commissions. Eastern Shore Natural
Gas (“Eastern Shore”). The Company’s natural gas transmission operation is
subject to regulation by the FERC.
Management's
Discussion and Analysis
Delaware.
On
September 1, 2006, the Delaware division filed its annual Gas Sales Service
Rates (“GSR”) application that was effective for service rendered on and after
November 1, 2006 with the Delaware Public Service Commission (“Delaware PSC”).
On October 3, 2006, the Delaware PSC approved the GSR charges, subject to full
evidentiary hearings and a final decision. The Delaware division expects a
final
decision during the first half of 2007.
On
September 2, 2005, the Delaware division filed an application with the Delaware
PSC requesting approval of an alternative rate design and rate structure in
order to provide natural gas service to prospective customers in eastern Sussex
County. While Chesapeake does provide natural gas service to residents and
businesses in portions of Sussex County, under the Company’s current tariff,
natural gas distribution lines have not been extended to a large portion of
the
State of Delaware’s recently targeted growth areas in eastern Sussex County. In
April 2002, Governor Ruth Ann Minner established the Delaware Energy Task Force
(“Task Force”), whose mission was to address the State of Delaware’s long-term
and short-term energy challenges. In September 2003, the Task Force issued
its
final report to the Governor that included a strategy related to enhancing
the
availability of natural gas within the State by evaluating possible incentives
for expanding residential and commercial natural gas service. Chesapeake
believes its current proposal to implement a rate design that will enable the
Company to provide natural gas as a viable energy choice to a broad number
of
prospective customers within eastern Sussex County is consistent with the Task
Force recommendation. While the Company cannot predict the outcome of its
application at this time, the Company anticipates a final decision from the
Delaware PSC regarding its application in 2007.
On
October 16, 2006, the Delaware division filed an application with the Delaware
PSC requesting approval for the issuance of up to $40,000,000 of common stock
and/or debt securities as contained in the shelf registration statement filed
with the SEC in July 2006. The Delaware PSC granted approval of the issuance
at
its regularly scheduled meeting on October 31, 2006.
On
November 1, 2006, the Delaware division filed with the Delaware PSC its annual
Environmental Rider (“ER”) rate application to become effective for service
rendered on and after December 1, 2006. The Delaware PSC granted approval of
the
ER rate at its regularly scheduled meeting on November 21, 2006, subject to
full
evidentiary hearings and a final decision. The Delaware PSC granted final
approval of the ER rate at its regulatory scheduled meeting on January 23,
2007.
On
November 9, 2006, the Delaware division filed two applications with the Delaware
PSC requesting approval for a Town of Millsboro Franchise Fee Rider and a Town
of Georgetown Franchise Fee Rider. These Riders will allow the Delaware division
to charge all respective natural gas customers within town limits the franchise
fee paid by the Delaware division to the Towns of Millsboro and Georgetown
as a
condition to providing natural gas service. The Delaware PSC granted approval
of
both of the Riders at its regularly scheduled meeting on January 23,
2007.
On
December 14, 2006, the Delaware division filed an application with the Delaware
PSC requesting approval to change its base delivery service rates in order
to
recover a 1 mill increase in the assessment factor, which had been approved
by
the state legislature. The Delaware PSC granted approval of the application
at
its regularly scheduled meeting on December 19, 2006.
Maryland.
On May
1, 2006, the Maryland division filed a base rate application with the Maryland
Public Service Commission (“Maryland PSC”) requesting an overall increase in
base rates of approximately $1,137,000 annually, based on a proposed overall
rate of return of 9.7 percent and a return on equity of 11.5 percent. On
September 26, 2006, the Maryland PSC approved a base rate increase of
approximately $780,000 annually, based on an overall rate of return of 9.03
percent and a return on equity of 10.75 percent. This increase will result
in an
average increase in revenues of approximately 4.5 percent for the Maryland
division’s firm residential, commercial and industrial customers. The PSC also
approved the Company’s proposal to implement a revenue normalization mechanism
for its residential heating and smaller commercial heating customers, reducing
the Company’s risk due to weather and usage changes.
Management's
Discussion and Analysis
On
December 14, 2006, the Maryland PSC held an evidentiary hearing to determine
the
reasonableness of the Maryland division’s four quarterly gas cost recovery
filings during the twelve months ended September 30, 2006. On December 15,
2006,
the Hearing Examiner issued proposed findings approving the quarterly gas cost
recovery rates as filed by the Maryland division, permitting complete recovery
of its purchased gas costs for the period under review. No appeals or written
exceptions to the proposed findings were made and a final order approving the
quarterly gas cost recovery rates as filed was issued by the Maryland PSC on
January 17, 2007.
Florida.
On March
22, 2006, the Florida division filed a petition with the Florida Public Service
Commission (“Florida PSC”) seeking approval of special contracts to provide
Delivery Point Operator (“DPO”) services. Under the proposed contracts, the DPO
services would be provided to an affiliate company, Peninsula Energy Services
Company, Inc. The Florida PSC approved the petition on July 7, 2006, ordering
that the special contracts be effective June 20, 2006.
On
May
16, 2005, the Florida division filed a request with the Florida PSC for approval
of a Special Contract with the Department of Management Services, an agency
of
the State of Florida, for service to the Washington Correction Institution
(“WCI”). The Florida PSC approved the Company’s request on July 19, 2005, and
service to the existing WCI facility began in February 2006. WCI is located
in
Washington County in the Florida panhandle and is the thirteenth county served
by the Company’s Florida division.
On
September 2, 2005, the Florida division filed a petition for a Declaratory
Statement with the Florida PSC for a determination that Peninsula Pipeline
Company, Inc. (“PPC”), a wholly owned subsidiary of the Company, qualifies as a
natural gas transmission company under the Natural Gas Transmission Pipeline
Intrastate Regulatory Act. The Florida PSC approved this Petition at its
December 20, 2005 agenda conference, and a final order was issued on January
9,
2006. The determination that PPC qualifies as a natural gas transmission company
provides opportunities for investment by PPC to provide natural gas transmission
service to industrial customers in Florida by an intrastate
pipeline.
On
September 15, 2006, the Florida division filed a petition with the Florida
PSC
for approval of its Energy Conservation Cost Recovery Factors for the year
2007.
Approved on November 30th
by the
Florida PSC, the new factors went into effect on January 1, 2007.
On
October 10, 2006, the Florida division filed a petition with the Florida PSC
for
authority to implement phase two of its experimental transitional transportation
service (“TTS”) pilot program, and for approval of a new tariff to reflect the
division’s transportation service environment. When approved, the implementation
of phase two of the TTS program for residential and certain small commercial
consumers will expand the number of pool managers from one to two, and increase
the gas supply pricing options available to these consumers. A decision is
expected from the Florida PSC in March 2007.
On
November 29, 2006, the Florida division filed a petition with the Florida PSC
for authority to modify its energy conservation programs. In this petition the
Florida division is seeking approval to increase the cash allowances paid within
the Residential Homebuilder Program and the Residential Appliance Replacement
Program, and to expand the scope of the Residential Water Heater Retention
Program to add natural gas heating systems, cooking and clothes drying
appliances. A decision is expected from the Florida PSC in March 2007.
Eastern
Shore.
During
October 2002, Eastern Shore filed for recovery of gas supply realignment costs,
which totaled $196,000 (including interest), associated with the implementation
of FERC Order No. 636. At that time, the FERC deferred review of the filing
pending settlement of a related matter concerning another transmission company.
Upon resolution of the issue with the other transmission company, Eastern Shore
resubmitted its filing to the FERC, requesting authorization to recover a total
of $223,000 (including interest) of gas supply realignment costs. FERC approved
Eastern Shore’s filing by letter order dated July 14, 2006.
Management's
Discussion and Analysis
System
Expansion 2006 - 2008.
On
January 20, 2006, Eastern Shore filed an application for a Certificate of Public
Convenience and Necessity for its 2006-2008 system expansion project (the “2006
- 2008 Project”) with the FERC. The application requested authority to construct
and operate approximately 55 miles of new pipeline facilities and two new
metering and regulating station facilities to provide an additional 47,350
dekatherms per day (“dt/d”) of firm transportation service in accordance with
the phased-in customer requests of 26,200 dt/d in 2006, 10,300 dt/d in 2007,
and
10,850 dt/d in 2008, at a total estimated cost of approximately $33.6 million.
The following table provides a breakdown for the additional amounts of firm
capacity per day, the estimated capital investment required, and the estimated
annual gross margin contribution for the new services that will become effective
November 1st
for each
of the respective years of the project:
|
Year
|
|
2006
|
2007
|
2008
|
Additional
firm capacity per day
|
26,200
|
10,300
|
10,850
|
Capital
investment
|
$17
million
|
$8
million
|
$8
million
|
Annualized
gross margin contribution
|
$3,670,000
|
$1,484,000
|
$1,595,000
|
A
Scoping
Meeting was held on March 29, 2006 at which the public and all other interested
stakeholders were invited to attend to review the project. No opposition to
the
project was received. On June 13, 2006, the FERC issued a Certificate to Eastern
Shore authorizing it to construct and operate the 2006-2008 Project as proposed.
Eastern Shore has completed and placed in service the authorized Phase I
facilities. Phase II and Phase III facilities are expected to be constructed
in
2007 and 2008, respectively.
Bay
Crossing Project.
On May
31, 2006, Eastern Shore entered into Precedent Agreements with Delmarva Power
& Light Company (“Delmarva”) and Chesapeake, through its Delaware and
Maryland Divisions to provide additional firm transportation services upon
completion of its latest proposed pipeline project.
Under
the
Bay Crossing Project, Eastern Shore has proposed to develop, construct and
operate approximately 63 miles of new pipeline facilities that would transport
natural gas from Calvert County, Maryland, crossing under the Chesapeake Bay
into Dorchester and Caroline Counties, Maryland, to points on the Delmarva
Peninsula where such facilities would interconnect with its existing facilities
in Sussex County, Delaware.
Chesapeake
and Delmarva are currently parties to existing firm natural gas transportation
service agreements with Eastern Shore and each desires firm transportation
services under the Bay Crossing Project, as evidenced by the May 31 Precedent
Agreements. Pursuant to these Precedent Agreements, the parties have agreed
to
proceed with the required initiatives to obtain the governmental and regulatory
authorizations that are necessary for Eastern Shore to provide, and for
Chesapeake and Delmarva to utilize, such firm transportation services under
the
Bay Crossing Project.
During
the negotiations of the Precedent Agreements, Eastern Shore and each of the
participating customers entered into Letter Agreements which provide that,
in
the event that the Bay Crossing Project is not certified and placed in service,
the participating customers will each pay their proportionate share of certain
pre-certification costs by means of a negotiated surcharge of up to $2 million,
over a period of no less than 20 years.
In
connection with the Bay Crossing Project, on June 27, 2006 Eastern Shore
submitted a petition to the FERC for approval of the uncontested Settlement
Agreement. The Settlement Agreement provides Eastern Shore and all customers
utilizing Eastern Shore’s system with benefits, including but not limited to the
following: (1) advancement of a necessary infrastructure project to meet the
growing demand for natural gas on the Delmarva Peninsula; (2) sharing of project
development costs by the participating customers in the project; and (3) no
development cost risk for non-participating customers. On August 1, 2006, the
FERC granted approval of the uncontested Settlement Agreement. On September
6,
2006, Eastern Shore submitted to FERC proposed tariff sheets to implement the
provisions of the above-referenced Settlement Agreement. By Letter Order dated
October 6, 2006, the FERC accepted the tariff sheets effective September 7,
2006. Eastern Shore anticipates entering into a pre-filing process at the FERC
during the first half of 2007 with the ultimate goal of obtaining FERC approval
to construct the Proposed Project. Eastern Shore will also be required to obtain
permits from other federal, state and local agencies prior to proceeding with
construction. It is not until the Company obtains the appropriate approvals
and
permits that a majority of the total estimated cost of $93 million for the
Bay
Crossing Project is estimated to be spent. This estimated cost will depend
upon
the final size and route of the pipeline, as well as construction materials
and
labor costs.
Management's
Discussion and Analysis
Rate
Matters.
On
September 19, 2006, Eastern Shore submitted its Annual Charge Adjustment (“ACA”)
compliance filing to reflect the most current ACA surcharge rate as established
by the FERC. The compliance filing was accepted by the FERC and the revised
ACA
surcharge rate became effective on October 1, 2006.
On
October 31, 2006 Eastern Shore filed a Section 4 base rate proceeding in
compliance with Article IX of the Stipulation & Agreement approved in its
prior base rate proceeding in Docket No.RP02-34-000. Eastern Shore’s filed
rates, proposed to be effective November 1, 2006, reflect an annual increase
of
$5,589,000 over its current rates. The proposed rate increase reflects increases
in operating and maintenance expenses, depreciation expense, taxes other than
income taxes, and return on new gas plant facilities that are expected to be
placed into service before March 31, 2007. Eastern Shore proposed a return
on
equity of 14.875 percent utilizing a capital structure of 39 percent debt and
61percent equity.
On
November 30, 2006 the FERC issued its Order
Accepting and Suspending Tariff Sheets Subject to Refund and Establishing a
Hearing.
The FERC
accepted and suspended the effectiveness of Eastern Shore’s rate increase until
May 1, 2007, subject to refund and the outcome of the hearing established in
the
order.
On
December 5, 2006 the FERC’s Chief Judge issued an order stating this proceeding
is subject to a Track Three procedural schedule. Track Three denotes an
exceptionally complex case and provides for a total of 63 weeks within which
a
formal hearing will be conducted and an Initial Decision issued. The Chief
Judge’s order also designated the Presiding Administrative Law Judge (“ALJ”).
On
December 19, 2006 the ALJ issued an Order
Establishing Procedural Schedule
as
agreed upon by the participants and the Judge at a pre-hearing conference held
that same day. The procedural schedule specifies that an Initial Decision shall
be issued on February 19, 2008. The ALJ also strongly encouraged the
participants in this proceeding to pursue a negotiated settlement through the
Commission’s settlement process, thus eliminating the need for a formal
hearing.
Environmental
Matters
The
Company continues to work with federal and state environmental agencies to
assess the environmental impact and explore corrective action at three
environmental sites (see Note M to the Consolidated Financial Statements).
The
Company believes that future costs associated with these sites will be
recoverable in rates or through sharing arrangements with, or contributions
by,
other responsible parties.
Market
Risk
Market
risk represents the potential loss arising from adverse changes in market rates
and prices. Long-term debt is subject to potential losses based on the change
in
interest rates. The Company’s long-term debt consists of senior notes and
convertible debentures (see Note H to the Consolidated Financial Statements
for
annual maturities of consolidated long-term debt). All of Chesapeake’s long-term
debt is fixed-rate debt. The carrying value of the Company’s long-term debt,
including current maturities, was $78.7 million at December 31, 2006 as compared
to a fair value of $81.4 million, based mainly on current market prices or
discounted cash flows using current rates for similar issues with similar terms
and remaining maturities. The Company evaluates whether to refinance existing
debt or permanently finance existing short-term borrowing based in part on
the
fluctuation in interest rates.
Management's
Discussion and Analysis
The
Company’s propane distribution business is exposed to market risk as a result of
propane storage activities and entering into fixed price contracts for supply.
The Company can store up to approximately four million gallons of propane
(including leased storage and rail cars) during the winter season to meet its
customers’ peak requirements and to serve metered customers. Decreases in the
wholesale price of propane may cause the value of stored propane to decline.
To
mitigate the impact of price fluctuations, the Company has adopted a Risk
Management Policy that allows the propane distribution operation to enter into
fair value hedges of its inventory. At December 31, 2006, the propane
distribution operation had entered into a swap agreement to protect the Company
from the impact of price increases on our price-cap plan that we offer to
customers. The Company considers this agreement to be an economic hedge and
does
not qualify for hedge accounting as described in SFAS 133. At the end of the
period, the market price of propane dropped below the unit price within the
swap
agreement. As a result of the price drop, the Company marked the agreement
to
market, which resulted in an unrealized loss of $84,000.
The
propane wholesale marketing operation is a party to natural gas liquids (“NGL”)
forward contracts, primarily propane contracts, with various third parties.
These contracts require that the propane wholesale marketing operation purchase
or sell NGL at a fixed price at fixed future dates. At expiration, the contracts
are settled by the delivery of NGL to the Company or the 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 of a net amount equal to the difference between the
current market price of the futures contract and the original contract
price.
The
forward and futures contracts are entered into for trading and wholesale
marketing purposes. The propane wholesale marketing operation is subject to
commodity price risk on its open positions to the extent that market prices
for
NGL deviate from fixed contract settlement amounts. Market risk associated
with
the trading of futures and forward contracts are monitored daily for compliance
with Chesapeake’s Risk Management Policy, which includes volumetric limits for
open positions. To manage exposures to changing market prices, open positions
are marked up or down to market prices and reviewed by oversight officials
on a
daily basis. Additionally, the Risk Management Committee reviews periodic
reports on market and credit risk, approves any exceptions to the Risk
Management Policy (within the limits established by the Board of Directors)
and
authorizes the use of any new types of contracts. Quantitative information
on
the forward and futures contracts at December 31, 2006 and 2005 is shown in
the
following charts.
At
December 31, 2006
|
|
Quantity
in gallons
|
|
Estimated
Market Prices
|
|
Weighted
Average Contract Prices
|
|
Forward
Contracts
|
|
|
|
|
|
|
|
Sale
|
|
13,797,000
|
|
$0.9250
— $1.2100
|
|
$1.0107
|
|
Purchase
|
|
13,733,800
|
|
$0.9250
— $1.2200
|
|
$1.0098
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
market prices and weighted average contract prices are in dollars
per
gallon.
|
|
All
contracts expire in 2007.
|
|
At
December 31, 2005
|
|
Quantity
in gallons
|
|
Estimated
Market Prices
|
|
Weighted
Average Contract Prices
|
|
Forward
Contracts
|
|
|
|
|
|
|
|
Sale
|
|
20,794,200
|
|
$1.0350
— $1.1013
|
|
$1.0718
|
|
Purchase
|
|
20,202,000
|
|
$1.0100
— $1.0450
|
|
$1.0703
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
market prices and weighted average contract prices are in dollars
per
gallon.
|
|
All
contracts expired in 2006.
|
|
The
Company’s natural gas distribution and marketing operations have entered into
agreements with natural gas suppliers to purchase natural gas for resale to
their customers. Purchases under these contracts either do not meet the
definition of derivatives in SFAS No. 133 or are considered “normal purchases
and sales” under SFAS No. 138 and are not marked to market.
Management's
Discussion and Analysis
Competition
The
Company’s natural gas operations compete with other forms of energy including
electricity, oil and propane. The principal competitive factors are price,
and
to a lesser extent, accessibility. The Company’s natural gas distribution
operations have several large volume industrial customers that have the capacity
to use fuel oil as an alternative to natural gas. When oil prices decline,
these
interruptible customers convert to oil to satisfy their fuel requirements.
Lower
levels in interruptible sales occur when oil prices are lower relative to the
price of natural gas. Oil prices, as well as the prices of electricity and
other
fuels, are subject to fluctuation for a variety of reasons; therefore, future
competitive conditions are not predictable. To address this uncertainty, the
Company uses flexible pricing arrangements on both the supply and sales side
of
this business to maximize sales volumes. As a result of the transmission
business’ conversion to open access and the Florida division’s restructuring of
its services, their businesses have shifted from providing competitive sales
service to providing transportation and contract storage services.
The
Company’s natural gas distribution operations located in Delaware, Maryland and
Florida offer transportation services to certain commercial and industrial
customers. In 2002, the Florida operation extended transportation service to
residential customers. With transportation service available on the Company’s
distribution systems, the Company is competing with third-party suppliers to
sell gas to industrial customers. As it relates to transportation services,
the
Company’s competitors include the interstate transmission company if the
distribution customer is located close enough to the transmission company’s
pipeline to make a connection economically feasible. The customers at risk
are
usually large volume commercial and industrial customers with the financial
resources and capability to bypass the distribution operations in this manner.
In certain situations, the distribution operations may adjust services and
rates
for these customers to retain their business. The Company expects to continue
to
expand the availability of transportation service to additional classes of
distribution customers in the future. The Company established a natural gas
sales and supply operation in Florida to compete for customers eligible for
transportation services. The Company also provides sales service in
Delaware.
The
Company’s propane distribution operations compete with several other propane
distributors in their service territories, primarily on the basis of service
and
price, emphasizing reliability of service and responsiveness. Competition is
generally from local outlets of national distribution companies and local
businesses, because distributors located in close proximity to customers incur
lower costs of providing service. Propane competes with electricity as an energy
source, because it is typically less expensive than electricity, based on
equivalent BTU value. Propane also competes with home heating oil as an energy
source. Since natural gas has historically been less expensive than propane,
propane is generally not distributed in geographic areas serviced by natural
gas
pipeline or distribution systems.
The
propane wholesale marketing operation competes against various marketers, many
of which have significantly greater resources and are able to obtain price
or
volumetric advantages.
The
advanced information services business faces significant competition from a
number of larger competitors having substantially greater resources available
to
them than does the Company. In addition, changes in the advanced information
services business are occurring rapidly, which could adversely impact the
markets for the products and services offered by these businesses. This segment
competes on the basis of technological expertise, reputation and price.
Inflation
Inflation
affects the cost of labor, products and services required for operation,
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. Fluctuations in natural gas prices are passed on to customers
through the gas cost recovery mechanism in the Company’s tariffs. To help cope
with the effects of inflation on its capital investments and returns, the
Company seeks rate relief from regulatory commissions for regulated operations
while monitoring the returns of its unregulated business operations. To
compensate for fluctuations in propane gas prices, Chesapeake adjusts its
propane selling prices to the extent allowed by the market.
Management's
Discussion and Analysis
Cautionary
Statement
Chesapeake
has made statements in this report that are considered to be forward-looking
statements. These statements are not matters of historical fact. Sometimes
they
contain words such as “believes,” “expects,” “intends,” “plans,” “will” or
“may,” and other similar words of a predictive nature. These statements relate
to matters such as customer growth, changes in revenues or gross margin, capital
expenditures, environmental remediation costs, regulatory approvals, market
risks associated with the Company’s propane wholesale marketing operation,
competition, inflation and other matters. It is important to understand that
these forward-looking statements are not guarantees but are subject to certain
risks and uncertainties and other important factors that could cause actual
results to differ materially from those in the forward-looking statements.
These
factors include, among other things:
o |
the
temperature sensitivity of the natural gas and propane
businesses;
|
o |
the
effect of spot, forward and futures market prices on the Company’s
distribution, wholesale marketing and energy trading
businesses;
|
o |
amount
and availability of natural gas and propane supplies and the access
to
interstate pipelines’ transportation and storage
capacity;
|
o |
the
effects of natural gas and propane commodity price changes may affect
the
operating costs and competitive positions of our natural gas and
propane
distribution operations;
|
o |
the
effects of competition on the Company’s unregulated and regulated
businesses;
|
o |
the
effect of changes in federal, state or local regulatory and tax
requirements, including
deregulation;
|
o |
the
effect of changes in technology on the Company’s advanced information
services segment;
|
o |
the
effects of credit risk and credit requirements on the Company’s energy
marketing subsidiaries;
|
o |
the
effect of accounting changes;
|
o |
the
effect of changes in benefit plan
assumptions;
|
o |
the
effect of compliance with environmental regulations or the remediation
of
environmental damage;
|
o |
the
effects of general economic conditions and including interest rates
on the
Company and its customers;
|
o |
the
ability of the Company’s new and planned facilities and acquisitions to
generate expected revenues;
|
o |
the
Company’s ability to obtain the rate relief and cost recovery requested
from utility regulators and the timing of the requested regulatory
actions; and
|
o |
the
Company’s ability to obtain necessary approvals and permits by regulatory
agencies on a timely basis.
|
Item
7A. Quantitative and Qualitative Disclosures About Market
Risk.
Information
concerning quantitative and qualitative disclosure about market risk is included
in Item 7 under the heading “Management’s Discussion and Analysis — Market
Risk.”
Item
8. Financial Statements and Supplementary Data.
Management’s
Report on Internal Control Over Financial Reporting
Management
is responsible for establishing and maintaining adequate internal control over
financial reporting, as such term is defined in Exchange Act Rules 13a-15(f).
A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (i) pertain
to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (ii)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors
of
the company; and (iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the financial
statements.
Under
the
supervision and with the participation of management, including the principal
executive officer and principal financial officer, Chesapeake’s management
conducted an evaluation of the effectiveness of its internal control over
financial reporting based on the criteria established in a report entitled
“Internal Control — Integrated Framework” issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Because of its inherent limitations,
internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become inadequate because
of
changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate. Chesapeake’s management has evaluated and concluded
that Chesapeake’s internal control over financial reporting was effective as of
December 31, 2006.
Management’s
assessment of the effectiveness of Chesapeake’s internal control over financial
reporting as of December 31, 2006 has been audited by PricewaterhouseCoopers
LLP, an independent registered public accounting firm, as stated in their report
which is included herein.
Report
of Independent Registered Public Accounting Firm
________
To
the
Board of Directors and Stockholders
of
Chesapeake Utilities Corporation
We
have
completed integrated audits of Chesapeake Utilities Corporation’s consolidated
financial statements and of its internal control over financial reporting as
of
December 31, 2006, in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Our opinions, based on our audits,
are presented below.
Consolidated
financial statements and financial statement schedule
In
our
opinion, the consolidated financial statements listed in the index appearing
under Item 15(a)(1) present fairly, in all material respects, the financial
position of Chesapeake Utilities Corporation and its subsidiaries at December
31, 2006 and 2005, and the results of their operations and their cash flows
for
each of the three years in the period ended December 31, 2006 in conformity
with
accounting principles generally accepted in the United States of America. In
addition, in our opinion, the financial statement schedule listed in the
accompanying index appearing under Item 15(a)(2) presents fairly, in all
material respects, the information set forth therein when read in conjunction
with the related consolidated financial statements. These financial statements
and financial statement schedule are the responsibility of the Company’s
management. Our responsibility is to express an opinion on these financial
statements and financial statement schedule based on our audits. We conducted
our audits of these statements in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require
that
we plan and perform the audit to obtain reasonable assurance about whether
the
financial statements are free of material misstatement. An audit of financial
statements includes examining, on a test basis, evidence supporting the amounts
and disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
As
discussed in Note K to the consolidated financial statements, the Company
changed the manner in which it accounts for defined benefit pension and other
postretirement plans, effective December 31, 2006.
Internal
control over financial reporting
Also,
in
our opinion, management’s assessment, included in Management's Report on
Internal Control Over Financial Reporting appearing under Item 8, that the
Company maintained effective internal control over financial reporting as of
December 31, 2006, based on criteria established in Internal
Control - Integrated Framework
issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO),
is fairly stated, in all material respects, based on those criteria.
Furthermore, in our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2006,
based on criteria established in Internal
Control - Integrated Framework
issued
by the COSO. The Company’s management is responsible for maintaining effective
internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting. Our responsibility
is to express opinions on management’s assessment and on the effectiveness
of the Company’s internal control over financial reporting based on our audit.
We conducted our audit of internal control over financial reporting in
accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit
to
obtain reasonable assurance about whether effective internal control over
financial reporting was maintained in all material respects. An audit of
internal control over financial reporting includes obtaining an understanding
of
internal control over financial reporting, evaluating management’s assessment,
testing and evaluating the design and operating effectiveness of internal
control, and performing such other procedures as we consider necessary in the
circumstances. We believe that our audit provides a reasonable basis for our
opinions.
A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (i) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company;
(ii) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that receipts and expenditures
of
the company are being made only in accordance with authorizations of management
and directors of the company; and (iii) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use,
or
disposition of the company’s assets that could have a material effect on the
financial statements.
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.
/s/
PricewaterhouseCoopers LLP
PricewaterhouseCoopers
LLP
Boston,
MA
March
13,
2007
Consolidated
Statements of Income
|
|
|
|
|
|
|
|
|
|
For
the Years Ended December 31,
|
|
2006
|
|
2005
|
|
2004
|
|
Operating
Revenues
|
|
$
|
231,200,591
|
|
$
|
229,629,736
|
|
$
|
177,955,441
|
|
Operating
Expenses
|
|
|
|
|
|
|
|
|
|
|
Cost
of sales, excluding costs below
|
|
|
155,810,622
|
|
|
153,514,739
|
|
|
109,626,377
|
|
Operations
|
|
|
37,053,223
|
|
|
40,181,648
|
|
|
35,146,595
|
|
Maintenance
|
|
|
2,103,562
|
|
|
1,818,981
|
|
|
1,518,774
|
|
Depreciation
and amortization
|
|
|
8,243,715
|
|
|
7,568,209
|
|
|
7,257,538
|
|
Other
taxes
|
|
|
5,058,158
|
|
|
5,015,660
|
|
|
4,436,411
|
|
Total
operating expenses
|
|
|
208,269,280
|
|
|
208,099,237
|
|
|
157,985,695
|
|
Operating
Income
|
|
|
22,931,311
|
|
|
21,530,499
|
|
|
19,969,746
|
|
Other
income net of other expenses
|
|
|
189,112
|
|
|
382,626
|
|
|
549,156
|
|
Interest
charges
|
|
|
5,777,336
|
|
|
5,133,495
|
|
|
5,268,145
|
|
Income
Before Income Taxes
|
|
|
17,343,087
|
|
|
16,779,630
|
|
|
15,250,757
|
|
Income
taxes
|
|
|
6,836,562
|
|
|
6,312,016
|
|
|
5,701,090
|
|
Net
Income from Continuing Operations
|
|
|
10,506,525
|
|
|
10,467,614
|
|
|
9,549,667
|
|
Loss
from discontinued operations, net of tax benefit of $0, $0 and
$59,751
|
|
|
-
|
|
|
-
|
|
|
(120,900
|
)
|
Net
Income
|
|
$
|
10,506,525
|
|
$
|
10,467,614
|
|
$
|
9,428,767
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
Per Share of Common Stock:
|
|
Basic
|
|
|
|
|
|
|
|
|
|
|
From
continuing operations
|
|
$
|
1.74
|
|
$
|
1.79
|
|
$
|
1.66
|
|
From
discontinued operations
|
|
|
-
|
|
|
-
|
|
|
(0.02
|
)
|
Net
Income
|
|
$
|
1.74
|
|
$
|
1.79
|
|
$
|
1.64
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
|
|
|
|
|
|
|
|
From
continuing operations
|
|
$
|
1.72
|
|
$
|
1.77
|
|
$
|
1.64
|
|
From
discontinued operations
|
|
|
-
|
|
|
-
|
|
|
(0.02
|
)
|
Net
Income
|
|
$
|
1.72
|
|
$
|
1.77
|
|
$
|
1.62
|
|
The
accompanying notes are an integral part of the financial
statements.
Consolidated
Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
For
the Years Ended December 31,
|
|
2006
|
|
2005
|
|
2004
|
|
Operating
Activities
|
|
|
|
|
|
|
|
Net
Income
|
|
$
|
10,506,525
|
|
$
|
10,467,614
|
|
$
|
9,428,767
|
|
Adjustments
to reconcile net income to net operating cash:
|
|
|
|
|
|
|
|
|
|
|
Depreciation
and amortization
|
|
|
8,243,715
|
|
|
7,568,209
|
|
|
7,257,538
|
|
Depreciation
and accretion included in other costs
|
|
|
3,102,066
|
|
|
2,705,620
|
|
|
2,611,779
|
|
Deferred
income taxes, net
|
|
|
(408,533
|
)
|
|
1,510,777
|
|
|
4,559,207
|
|
Unrealized
gain (loss) on commodity contracts
|
|
|
37,110
|
|
|
(227,193
|
)
|
|
353,183
|
|
Unrealized
loss on investments
|
|
|
(151,952
|
)
|
|
(56,650
|
)
|
|
(43,256
|
)
|
Employee
benefits and compensation
|
|
|
382,608
|
|
|
1,621,607
|
|
|
1,536,586
|
|
Other,
net
|
|
|
(18,596
|
)
|
|
(62,692
|
)
|
|
67,079
|
|
Changes
in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
Sale
(purchase) of investments
|
|
|
(177,990
|
)
|
|
(1,242,563
|
)
|
|
43,354
|
|
Accounts
receivable and accrued revenue
|
|
|
9,705,860
|
|
|
(16,831,751
|
)
|
|
(11,723,505
|
)
|
Propane
inventory, storage gas and other inventory
|
|
|
354,764
|
|
|
(5,704,040
|
)
|
|
(1,741,941
|
)
|
Regulatory
assets
|
|
|
2,498,954
|
|
|
(1,719,184
|
)
|
|
428,516
|
|
Prepaid
expenses and other current assets
|
|
|
(271,438
|
)
|
|
36,704
|
|
|
(221,137
|
)
|
Other
deferred charges
|
|
|
(231,822
|
)
|
|
(102,561
|
)
|
|
(168,898
|
)
|
Long-term
receivables
|
|
|
137,101
|
|
|
247,600
|
|
|
428,964
|
|
Accounts
payable and other accrued liabilities
|
|
|
(11,434,370
|
)
|
|
15,569,924
|
|
|
9,731,360
|
|
Income
taxes receivable (payable)
|
|
|
1,800,913
|
|
|
(2,006,762
|
)
|
|
(229,237
|
)
|
Accrued
interest
|
|
|
273,672
|
|
|
(42,376
|
)
|
|
(51,272
|
)
|
Customer
deposits and refunds
|
|
|
2,361,265
|
|
|
462,781
|
|
|
665,549
|
|
Accrued
compensation
|
|
|
(542,512
|
)
|
|
875,342
|
|
|
(794,194
|
)
|
Regulatory
liabilities
|
|
|
2,824,068
|
|
|
144,501
|
|
|
(191,266
|
)
|
Other
liabilities
|
|
|
1,125,590
|
|
|
385,034
|
|
|
55,977
|
|
Net
cash provided by operating activities
|
|
|
30,116,998
|
|
|
13,599,941
|
|
|
22,003,153
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing
Activities
|
|
|
|
|
|
|
|
|
|
|
Property,
plant and equipment expenditures
|
|
|
(48,845,828
|
)
|
|
(33,319,613
|
)
|
|
(16,435,938
|
)
|
Sale
of investments
|
|
|
-
|
|
|
-
|
|
|
135,170
|
|
Sale
of discontinued operations
|
|
|
-
|
|
|
-
|
|
|
415,707
|
|
Environmental
recoveries (expenditures)
|
|
|
(15,549
|
)
|
|
240,336
|
|
|
369,719
|
|
Net
cash used by investing activities
|
|
|
(48,861,377
|
)
|
|
(33,079,277
|
)
|
|
(15,515,342
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Financing
Activities
|
|
|
|
|
|
|
|
|
|
|
Common
stock dividends
|
|
|
(5,982,531
|
)
|
|
(5,789,180
|
)
|
|
(5,560,535
|
)
|
Issuance
of stock for Dividend Reinvestment Plan
|
|
|
321,865
|
|
|
458,757
|
|
|
200,551
|
|
Stock
issuance
|
|
|
19,698,509
|
|
|
-
|
|
|
|
|
Cash
settlement of warrants
|
|
|
(434,782
|
)
|
|
-
|
|
|
-
|
|
Change
in cash overdrafts due to outstanding checks
|
|
|
49,047
|
|
|
874,083
|
|
|
(143,720
|
)
|
Net
borrowing (repayment) under line of credit agreements
|
|
|
(7,977,347
|
)
|
|
29,606,400
|
|
|
1,184,742
|
|
Proceeds
from issuance of long-term debt
|
|
|
20,000,000
|
|
|
-
|
|
|
-
|
|
Repayment
of long-term debt
|
|
|
(4,929,674
|
)
|
|
(4,794,827
|
)
|
|
(3,665,589
|
)
|
Net
cash provided (used) by financing activities
|
|
|
20,745,087
|
|
|
20,355,233
|
|
|
(7,984,551
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash
Equivalents
|
|
|
2,000,708
|
|
|
875,897
|
|
|
(1,496,740
|
)
|
Cash
and Cash Equivalents — Beginning of Period
|
|
|
2,487,658
|
|
|
1,611,761
|
|
|
3,108,501
|
|
Cash
and Cash Equivalents — End of Period
|
|
$
|
4,488,366
|
|
$
|
2,487,658
|
|
$
|
1,611,761
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
Disclosures of Non-Cash Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
Capital
property and equipment acquired on account,
|
|
|
|
|
|
|
|
|
|
|
but
not paid as of December 31
|
|
$
|
1,490,890
|
|
$
|
1,367,348
|
|
$
|
1,678,724
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
Disclosure of Cash Flow information
|
|
|
|
|
|
|
|
|
|
|
Cash
paid for interest
|
|
$
|
5,334,477
|
|
$
|
5,052,013
|
|
$
|
5,280,299
|
|
Cash
paid for income taxes
|
|
$
|
6,285,272
|
|
$
|
6,342,476
|
|
$
|
1,977,223
|
|
The
accompanying notes are an integral part of the financial
statements.
Consolidated
Balance Sheets
|
|
|
|
|
|
|
|
Assets
|
|
At
December 31,
|
|
2006
|
|
2005
|
|
Property,
Plant and Equipment
|
|
|
|
|
|
Natural
gas distribution and transmission
|
|
$
|
269,012,516
|
|
$
|
220,685,461
|
|
Propane
|
|
|
44,791,552
|
|
|
41,563,810
|
|
Advanced
information services
|
|
|
1,054,368
|
|
|
1,221,177
|
|
Other
plant
|
|
|
9,147,500
|
|
|
9,275,729
|
|
Total
property, plant and equipment
|
|
|
324,005,936
|
|
|
272,746,177
|
|
Less:
Accumulated depreciation and amortization
|
|
|
(85,010,472
|
)
|
|
(78,840,413
|
)
|
Plus:
Construction work in progress
|
|
|
1,829,948
|
|
|
7,598,531
|
|
Net
property, plant and equipment
|
|
|
240,825,412
|
|
|
201,504,295
|
|
|
|
|
|
|
|
|
|
Investments
|
|
|
2,015,577
|
|
|
1,685,635
|
|
|
|
|
|
|
|
|
|
Current
Assets
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
|
4,488,366
|
|
|
2,487,658
|
|
Accounts
receivable (less allowance for uncollectible accounts of $661,597
and
$861,378, respectively)
|
|
|
44,969,182
|
|
|
54,284,011
|
|
Accrued
revenue
|
|
|
4,325,351
|
|
|
4,716,383
|
|
Propane
inventory, at average cost
|
|
|
7,187,035
|
|
|
6,332,956
|
|
Other
inventory, at average cost
|
|
|
1,564,937
|
|
|
1,538,936
|
|
Regulatory
assets
|
|
|
1,275,653
|
|
|
4,434,828
|
|
Storage
gas prepayments
|
|
|
7,393,335
|
|
|
8,628,179
|
|
Income
taxes receivable
|
|
|
1,078,882
|
|
|
2,725,840
|
|
Deferred
income taxes
|
|
|
1,365,316
|
|
|
-
|
|
Prepaid
expenses
|
|
|
2,280,900
|
|
|
2,021,164
|
|
Other
current assets
|
|
|
1,553,284
|
|
|
1,596,797
|
|
Total
current assets
|
|
|
77,482,241
|
|
|
88,766,752
|
|
|
|
|
|
|
|
|
|
Deferred
Charges and Other Assets
|
|
|
|
|
|
|
|
Goodwill
|
|
|
674,451
|
|
|
674,451
|
|
Other
intangible assets, net
|
|
|
191,878
|
|
|
205,683
|
|
Long-term
receivables
|
|
|
824,333
|
|
|
961,434
|
|
Other
regulatory assets
|
|
|
1,765,088
|
|
|
1,178,232
|
|
Other
deferred charges
|
|
|
1,215,004
|
|
|
1,003,393
|
|
Total
deferred charges and other assets
|
|
|
4,670,754
|
|
|
4,023,193
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$
|
324,993,984
|
|
$
|
295,979,875
|
|
The
accompanying notes are an integral part of the financial
statements.
Consolidated
Balance Sheets
|
|
|
|
|
|
|
|
Capitalization
and Liabilities
|
|
At
December 31,
|
|
2006
|
|
2005
|
|
Capitalization
|
|
|
|
|
|
Stockholders'
equity
|
|
|
|
|
|
Common
Stock, par value $0.4867 per share (authorized 12,000,000 shares)
(1)
|
|
$
|
3,254,998
|
|
$
|
2,863,212
|
|
Additional
paid-in capital
|
|
|
61,960,220
|
|
|
39,619,849
|
|
Retained
earnings
|
|
|
46,270,884
|
|
|
42,854,894
|
|
Accumulated
other comprehensive income
|
|
|
(334,550
|
)
|
|
(578,151
|
)
|
Deferred
compensation obligation
|
|
|
1,118,509
|
|
|
794,535
|
|
Treasury
stock
|
|
|
(1,118,509
|
)
|
|
(797,156
|
)
|
Total
stockholders' equity
|
|
|
111,151,552
|
|
|
84,757,183
|
|
Long-term
debt, net of current maturities
|
|
|
71,050,000
|
|
|
58,990,363
|
|
Total
capitalization
|
|
|
182,201,552
|
|
|
143,747,546
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
|
|
|
|
|
Current
portion of long-term debt
|
|
|
7,656,364
|
|
|
4,929,091
|
|
Short-term
borrowing
|
|
|
27,553,941
|
|
|
35,482,241
|
|
Accounts
payable
|
|
|
33,870,552
|
|
|
45,645,228
|
|
Customer
deposits and refunds
|
|
|
7,502,265
|
|
|
5,140,999
|
|
Accrued
interest
|
|
|
832,392
|
|
|
558,719
|
|
Dividends
payable
|
|
|
1,939,482
|
|
|
1,676,398
|
|
Deferred
income taxes
|
|
|
-
|
|
|
1,150,828
|
|
Accrued
compensation
|
|
|
2,901,053
|
|
|
3,793,244
|
|
Regulatory
liabilities
|
|
|
4,199,147
|
|
|
550,546
|
|
Other
accrued liabilities
|
|
|
4,005,795
|
|
|
3,560,055
|
|
Total
current liabilities
|
|
|
90,460,991
|
|
|
102,487,349
|
|
|
|
|
|
|
|
|
|
Deferred
Credits and Other Liabilities
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
26,517,098
|
|
|
24,248,624
|
|
Deferred
investment tax credits
|
|
|
328,277
|
|
|
367,085
|
|
Other
regulatory liabilities
|
|
|
1,236,254
|
|
|
2,008,779
|
|
Environmental
liabilities
|
|
|
211,581
|
|
|
352,504
|
|
Accrued
pension costs
|
|
|
1,608,311
|
|
|
3,099,882
|
|
Accrued
asset removal cost
|
|
|
18,410,992
|
|
|
16,727,268
|
|
Other
liabilities
|
|
|
4,018,928
|
|
|
2,940,838
|
|
Total
deferred credits and other liabilities
|
|
|
52,331,441
|
|
|
49,744,980
|
|
|
|
|
|
|
|
|
|
Other
Commitments and Contingencies
(Note N)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Capitalization and Liabilities
|
|
$
|
324,993,984
|
|
$
|
295,979,875
|
|
|
|
|
|
|
|
|
|
(1)
Shares issued were 6,688,084 and 5,883,099 for 2006 and 2005,
respectively.
|
|
Shares
outstanding were 6,688,084 and 5,883,002 for 2006 and 2005,
respectively.
|
|
The
accompanying notes are an integral part of the financial
statements.
Statements
of Stockholders' Equity
|
|
|
|
|
|
|
|
|
|
For
the Years Ended December 31,
|
|
2006
|
|
2005
|
|
2004
|
|
Common
Stock
|
|
|
|
|
|
|
|
Balance
— beginning of year
|
|
$
|
2,863,212
|
|
$
|
2,812,538
|
|
$
|
2,754,748
|
|
Dividend
Reinvestment Plan
|
|
|
18,685
|
|
|
20,038
|
|
|
20,125
|
|
Retirement
Savings Plan
|
|
|
14,457
|
|
|
10,255
|
|
|
19,058
|
|
Conversion
of debentures
|
|
|
8,117
|
|
|
11,004
|
|
|
9,060
|
|
Performance
shares and options exercised (1)
|
|
|
14,536
|
|
|
9,377
|
|
|
9,547
|
|
Stock
issuance
|
|
|
335,991
|
|
|
-
|
|
|
-
|
|
Balance
— end of year
|
|
|
3,254,998
|
|
|
2,863,212
|
|
|
2,812,538
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
Paid-in Capital
|
|
|
|
|
|
|
|
|
|
|
Balance
— beginning of year
|
|
|
39,619,849
|
|
|
36,854,717
|
|
|
34,176,361
|
|
Dividend
Reinvestment Plan
|
|
|
1,148,100
|
|
|
1,224,874
|
|
|
996,715
|
|
Retirement
Savings Plan
|
|
|
900,354
|
|
|
682,829
|
|
|
946,319
|
|
Conversion
of debentures
|
|
|
275,300
|
|
|
373,259
|
|
|
307,940
|
|
Performance
shares and options exercised (1)
|
|
|
887,426
|
|
|
484,170
|
|
|
427,382
|
|
Stock
issuance
|
|
|
19,362,518
|
|
|
-
|
|
|
-
|
|
Exercise
warrants, net of tax
|
|
|
(233,327
|
)
|
|
-
|
|
|
-
|
|
Balance
— end of year
|
|
|
61,960,220
|
|
|
39,619,849
|
|
|
36,854,717
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained
Earnings
|
|
|
|
|
|
|
|
|
|
|
Balance
— beginning of year
|
|
|
42,854,894
|
|
|
39,015,087
|
|
|
36,008,246
|
|
Net
income
|
|
|
10,506,525
|
|
|
10,467,614
|
|
|
9,428,767
|
|
Cash
dividends (2)
|
|
|
(7,090,535
|
)
|
|
(6,627,807
|
)
|
|
(6,403,450
|
)
|
Loss
on issuance of treasury stock
|
|
|
-
|
|
|
-
|
|
|
(18,476
|
)
|
Balance
— end of year
|
|
|
46,270,884
|
|
|
42,854,894
|
|
|
39,015,087
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
Other Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
Balance
— beginning of year
|
|
|
(578,151
|
)
|
|
(527,246
|
)
|
|
-
|
|
Minimum
pension liability adjustment, net of tax
|
|
|
74,036
|
|
|
(50,905
|
)
|
|
(527,246
|
)
|
Gain
on funded status of Employee Benefit Plans, net of tax
|
|
|
169,565
|
|
|
-
|
|
|
-
|
|
Balance
— end of year
|
|
|
(334,550
|
)
|
|
(578,151
|
)
|
|
(527,246
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
Compensation Obligation
|
|
|
|
|
|
|
|
|
|
|
Balance
— beginning of year
|
|
|
794,535
|
|
|
816,044
|
|
|
913,689
|
|
New
deferrals
|
|
|
323,974
|
|
|
130,426
|
|
|
296,790
|
|
Payout
of deferred compensation
|
|
|
-
|
|
|
(151,935
|
)
|
|
(394,435
|
)
|
Balance
— end of year
|
|
|
1,118,509
|
|
|
794,535
|
|
|
816,044
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury
Stock
|
|
|
|
|
|
|
|
|
|
|
Balance
— beginning of year
|
|
|
(797,156
|
)
|
|
(1,008,696
|
)
|
|
(913,689
|
)
|
New
deferrals related to compensation obligation
|
|
|
(323,974
|
)
|
|
(130,426
|
)
|
|
(296,790
|
)
|
Purchase
of treasury stock
|
|
|
(51,572
|
)
|
|
(182,292
|
)
|
|
(344,753
|
)
|
Sale
and distribution of treasury stock
|
|
|
54,193
|
|
|
524,258
|
|
|
546,536
|
|
Balance
— end of year
|
|
|
(1,118,509
|
)
|
|
(797,156
|
)
|
|
(1,008,696
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Stockholders’ Equity
|
|
$
|
111,151,552
|
|
$
|
84,757,183
|
|
$
|
77,962,444
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Includes amounts for shares issued for Directors'
compensation.
|
|
(2)
Cash dividends declared per share for 2006, 2005 and 2004 were
$1.16,
$1.14 and $1.12, respectively.
|
|
Statements
of Comprehensive Income
|
|
|
|
|
|
|
|
|
|
For
the Years Ended December 31,
|
|
2006
|
|
2005
|
|
2004
|
|
Net
income
|
|
$
|
10,506,525
|
|
$
|
10,467,614
|
|
$
|
9,428,767
|
|
Pension
liability adjustment, net of tax of $48,889, $33,615 and $347,726,
respectively
|
|
|
74,036
|
|
|
(50,905
|
)
|
|
(527,246
|
)
|
Comprehensive
Income
|
|
$
|
10,580,561
|
|
$
|
10,416,709
|
|
$
|
8,901,521
|
|
The
accompanying notes are an integral part of the financial
statements.
Consolidated
Statements of Income Taxes
|
|
|
|
|
|
|
|
|
|
For
the Years Ended December 31,
|
|
2006
|
|
2005
|
|
2004
|
|
Current
Income Tax Expense
|
|
|
|
|
|
|
|
Federal
|
|
$
|
5,994,296
|
|
$
|
3,687,800
|
|
$
|
1,221,155
|
|
State
|
|
|
1,424,485
|
|
|
789,233
|
|
|
618,916
|
|
Investment
tax credit adjustments, net
|
|
|
(54,816
|
)
|
|
(54,816
|
)
|
|
(54,816
|
)
|
Total
current income tax expense
|
|
|
7,363,965
|
|
|
4,422,217
|
|
|
1,785,255
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
Income Tax Expense (1)
|
|
|
|
|
|
|
|
|
|
|
Property,
plant and equipment
|
|
|
1,697,024
|
|
|
1,380,628
|
|
|
4,230,650
|
|
Deferred
gas costs
|
|
|
(2,085,066
|
)
|
|
1,064,310
|
|
|
283,547
|
|
Pensions
and other employee benefits
|
|
|
(97,436
|
)
|
|
(340,987
|
)
|
|
(49,620
|
)
|
Environmental
expenditures
|
|
|
(5,580
|
)
|
|
(98,229
|
)
|
|
(150,864
|
)
|
Other
|
|
|
(36,345
|
)
|
|
(115,923
|
)
|
|
(397,878
|
)
|
Total
deferred income tax expense
|
|
|
(527,403
|
)
|
|
1,889,799
|
|
|
3,915,835
|
|
Total
Income Tax Expense
|
|
$
|
6,836,562
|
|
$
|
6,312,016
|
|
$
|
5,701,090
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation
of Effective Income Tax Rates
|
|
|
|
|
|
|
|
|
|
|
Federal
income tax expense (2)
|
|
$
|
6,070,080
|
|
$
|
5,872,871
|
|
$
|
5,185,257
|
|
State
income taxes, net of federal benefit
|
|
|
804,988
|
|
|
708,192
|
|
|
736,176
|
|
Other
|
|
|
(38,506
|
)
|
|
(269,047
|
)
|
|
(220,343
|
)
|
Total
Income Tax Expense
|
|
$
|
6,836,562
|
|
$
|
6,312,016
|
|
$
|
5,701,090
|
|
Effective
income tax rate
|
|
|
39.4
|
%
|
|
37.6
|
%
|
|
37.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
At
December 31,
|
|
|
2006
|
|
|
2005
|
|
|
|
|
Deferred
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
Deferred
income tax liabilities:
|
|
|
|
|
|
|
|
|
|
|
Property,
plant and equipment
|
|
$
|
27,997,744
|
|
$
|
26,795,452
|
|
|
|
|
Environmental
costs
|
|
|
204,149
|
|
|
-
|
|
|
|
|
Deferred
gas costs
|
|
|
-
|
|
|
1,664,252
|
|
|
|
|
Other
|
|
|
870,424
|
|
|
612,943
|
|
|
|
|
Total
deferred income tax liabilities
|
|
|
29,072,317
|
|
|
29,072,647
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
income tax assets:
|
|
|
|
|
|
|
|
|
|
|
Pension
and other employee benefits
|
|
|
2,225,944
|
|
|
2,289,370
|
|
|
|
|
Self
insurance
|
|
|
468,922
|
|
|
575,303
|
|
|
|
|
Environmental
costs
|
|
|
-
|
|
|
181,734
|
|
|
|
|
Deferred
gas costs
|
|
|
528,814
|
|
|
-
|
|
|
|
|
Other
|
|
|
696,855
|
|
|
626,788
|
|
|
|
|
Total
deferred income tax assets
|
|
|
3,920,535
|
|
|
3,673,195
|
|
|
|
|
Deferred
Income Taxes Per Consolidated Balance Sheet
|
|
$
|
25,151,782
|
|
$
|
25,399,452
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Includes ($54,000), $146,000 and $386,000 of deferred state income
taxes
for the years 2006, 2005 and 2004, respectively.
|
|
(2)
Federal income taxes were recorded at 35% for the years 2006 and
2005.
They were recorded at 34% in 2004.
|
|
The
accompanying notes are an integral part of the financial
statements.
Notes
to the Consolidated Financial Statements
A.
Summary of Accounting Policies
Nature
of Business
Chesapeake
Utilities Corporation (“Chesapeake” or “the Company”) is engaged in natural gas
distribution to approximately 59,100 customers located in central and southern
Delaware, Maryland’s Eastern Shore and Florida. The Company’s natural gas
transmission subsidiary operates an intrastate pipeline from various points
in
Pennsylvania and northern Delaware to the Company’s Delaware and Maryland
distribution divisions, as well as other utility and industrial customers in
Pennsylvania, Delaware and the Eastern Shore of Maryland. The Company’s propane
distribution and wholesale marketing segment provides distribution service
to
approximately 33,300 customers in central and southern Delaware, the Eastern
Shore of Maryland, southeastern Pennsylvania, central Florida and the Eastern
Shore of Virginia, and markets propane to wholesale customers including large
independent oil and petrochemical companies, resellers and propane distribution
companies in the southeastern United States. The advanced information services
segment provides domestic and international clients with information technology
related business services and solutions for both enterprise and e-business
applications.
Principles
of Consolidation
The
Consolidated Financial Statements include the accounts of the Company and its
wholly owned subsidiaries. The Company does not have any ownership interests
in
investments accounted for using the equity method or any variable interests
in a
variable interest entity. All intercompany transactions have been eliminated
in
consolidation.
System
of Accounts
The
natural gas distribution divisions of the Company located in Delaware, Maryland
and Florida are subject to regulation by their respective Public Service
Commissions with respect to their rates for service, maintenance of their
accounting records and various other matters. Eastern Shore Natural Gas Company
is an open access pipeline and is subject to regulation by the Federal Energy
Regulatory Commission (“FERC”). Our financial statements are prepared in
accordance with generally accepted accounting principles, which give appropriate
recognition to the ratemaking and accounting practices and policies of the
various commissions. The propane, advanced information services and other
business segments are not subject to regulation with respect to rates or
maintenance of accounting records.
Property,
Plant, Equipment and Depreciation
Utility
and non-utility property is stated at original cost. The costs of repairs and
minor replacements are charged against income as incurred and the costs of
major
renewals and betterments are capitalized. Upon retirement or disposition of
non-utility property, the gain or loss, net of salvage value, is charged to
income. Upon retirement or disposition of utility property, the gain or loss,
net of salvage value, is charged to accumulated depreciation. The provision
for
depreciation is computed using the straight-line method at rates that amortize
the unrecovered cost of depreciable property over the estimated remaining useful
life of the asset. Depreciation and amortization expenses are provided at an
annual rate for each segment. The three-year average rates were 3 percent for
natural gas distribution and transmission, 5 percent for propane, 11 percent
for
advanced information services and 7 percent for general plant.
Notes
to the Consolidated Financial Statements
|
|
|
|
|
|
|
|
At
December 31,
|
|
2006
|
|
2005
|
|
Useful
Life (1)
|
|
Plant
in service
|
|
|
|
|
|
|
|
Mains
|
|
$
|
151,890,304
|
|
$
|
113,111,408
|
|
|
24-37
years
|
|
Services
— utility
|
|
|
32,334,145
|
|
|
29,010,008
|
|
|
14-28
years
|
|
Compressor
station equipment
|
|
|
24,921,976
|
|
|
23,853,871
|
|
|
28
years
|
|
Liquefied
petroleum gas equipment
|
|
|
24,627,398
|
|
|
22,162,867
|
|
|
30-39
years
|
|
Meters
and meter installations
|
|
|
16,093,737
|
|
|
15,165,212
|
|
|
Propane
15-33 years, Natural gas 17-49 years
|
|
Measuring
and regulating station equipment
|
|
|
13,272,201
|
|
|
12,219,964
|
|
|
17-37
years
|
|
Office
furniture and equipment
|
|
|
10,114,101
|
|
|
9,572,926
|
|
|
Non-regulated
3-10 years, Regulated 3-20 years
|
|
Transportation
equipment
|
|
|
10,686,259
|
|
|
9,822,272
|
|
|
2-11
years
|
|
Structures
and improvements
|
|
|
9,538,345
|
|
|
9,161,696
|
|
|
5-44
years(2)
|
|
Land
and land rights
|
|
|
7,386,268
|
|
|
5,646,852
|
|
|
Not
depreciable, except certain regulated assets
|
|
Propane
bulk plants and tanks
|
|
|
5,301,457
|
|
|
6,097,036
|
|
|
15
- 40 years
|
|
Various
|
|
|
17,839,745
|
|
|
16,922,065
|
|
|
Various
|
|
Total
plant in service
|
|
|
324,005,936
|
|
|
272,746,177
|
|
|
|
|
Plus
construction work in progress
|
|
|
1,829,948
|
|
|
7,598,531
|
|
|
|
|
Less
accumulated depreciation
|
|
|
(85,010,472
|
)
|
|
(78,840,413
|
)
|
|
|
|
Net
property, plant and equipment
|
|
$
|
240,825,412
|
|
$
|
201,504,295
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Certain immaterial account balances may fall outside this
range.
|
|
|
|
|
|
|
|
|
|
|
|
|
The
regulated operations compute depreciation in accordance with rates
approved by either the state Public Service Commission or the FERC.
These
rates are based on depreciation studies and may change periodically
upon
receiving approval from the appropriate
regulatory body. The depreciation rates shown above are based on
the
remaining useful lives of the assets at the time of the depreciation
study, rather than their original lives. The depreciation rates
are
composite, straight-line rates applied to
the average investment for each class of depreciable property and
are
adjusted for anticipated cost of removal less salvage
value.
|
|
|
|
|
|
|
|
|
|
|
|
|
The
non-regulated operations compute depreciation using the straight-line
method over the estimated useful life of the asset.
|
|
|
|
|
|
|
|
|
|
|
|
|
(2)
Includes buildings, structures used in connection with natural
gas and
propane operations, improvements to those facilities and leasehold
improvements.
|
|
Cash
and Cash Equivalents
The
Company’s policy is to invest cash in excess of operating requirements in
overnight income producing accounts. Such amounts are stated at cost, which
approximates market value. Investments with an original maturity of three months
or less when purchased are considered cash equivalents.
Inventories
The
Company uses the average cost method to value propane and materials and supplies
inventory. If the market prices drop below cost, inventory balances that are
subject to price risk are adjusted to market values.
Regulatory
Assets, Liabilities and Expenditures
The
Company accounts for its regulated operations in accordance with SFAS No. 71,
“Accounting for the Effects of Certain Types of Regulation.” This standard
includes accounting principles for companies whose rates are determined by
independent third-party regulators. When setting rates, regulators often make
decisions, the economics of which require companies to defer costs or revenues
in different periods than may be appropriate for unregulated enterprises. When
this situation occurs, the regulated utility defers the associated costs as
assets (regulatory assets) on the balance sheet, and records them as expense
on
the income statement as it collects revenues. Further, regulators can also
impose liabilities upon a company for amounts previously collected from
customers, and for recovery of costs that are expected to be incurred in the
future (regulatory liabilities).
At
December 31, 2006 and 2005, 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.
Notes
to the Consolidated Financial Statements
At
December 31,
|
|
2006
|
|
2005
|
|
Regulatory
Assets
|
|
|
|
|
|
Current
|
|
|
|
|
|
Underrecovered
purchased gas costs
|
|
$
|
1,076,921
|
|
$
|
4,016,522
|
|
Conservation
cost recovery
|
|
|
51,408
|
|
|
303,930
|
|
Swing
transportation imbalances
|
|
|
-
|
|
|
454
|
|
PSC
Assessment
|
|
|
22,290
|
|
|
-
|
|
Flex
rate asset
|
|
|
81,926
|
|
|
113,922
|
|
Other
|
|
|
43,108
|
|
|
-
|
|
Total
current
|
|
|
1,275,653
|
|
|
4,434,828
|
|
|
|
|
|
|
|
|
|
Non-Current
|
|
|
|
|
|
|
|
Income
tax related amounts due from customers
|
|
|
1,300,544
|
|
|
711,961
|
|
Deferred
regulatory and other expenses
|
|
|
188,686
|
|
|
89,258
|
|
Deferred
gas supply
|
|
|
15,201
|
|
|
15,201
|
|
Deferred
post retirement benefits
|
|
|
138,949
|
|
|
166,739
|
|
Environmental
regulatory assets and expenditures
|
|
|
121,708
|
|
|
195,073
|
|
Total
non-current
|
|
|
1,765,088
|
|
|
1,178,232
|
|
|
|
|
|
|
|
|
|
Total
Regulatory Assets
|
|
$
|
3,040,741
|
|
$
|
5,613,060
|
|
|
|
|
|
|
|
|
|
Regulatory
Liabilities
|
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
|
|
Self
insurance — current
|
|
$
|
568,897
|
|
$
|
44,221
|
|
Overrecovered
purchased gas costs
|
|
|
2,351,553
|
|
|
-
|
|
Shared
interruptible margins
|
|
|
100,355
|
|
|
3,039
|
|
Operational
flow order penalties
|
|
|
7,831
|
|
|
7,831
|
|
Swing
transportation imbalances
|
|
|
1,170,511
|
|
|
495,455
|
|
Total
current
|
|
|
4,199,147
|
|
|
550,546
|
|
|
|
|
|
|
|
|
|
Non-Current
|
|
|
|
|
|
|
|
Self
insurance — long-term
|
|
|
600,787
|
|
|
1,383,247
|
|
Income
tax related amounts due to customers
|
|
|
285,819
|
|
|
327,893
|
|
Environmental
overcollections
|
|
|
349,648
|
|
|
297,639
|
|
Total
non-current
|
|
|
1,236,254
|
|
|
2,008,779
|
|
|
|
|
|
|
|
|
|
Accrued
asset removal cost
|
|
|
18,410,992
|
|
|
16,727,268
|
|
|
|
|
|
|
|
|
|
Total
Regulatory Liabilities
|
|
$
|
23,846,393
|
|
$
|
19,286,593
|
|
Included
in the regulatory assets listed above are $133,000 of which is accruing
interest. Of the remaining regulatory assets, $1.4 million will be collected
in
approximately one to two years, $310,000 will be collected within approximately
3 to 10 years, and $1.4 million are awaiting regulatory approval for recovery,
but once approved are expected to be collected within 12 months.
As
required by SFAS No. 71, the Company monitors its regulatory and competitive
environment to determine whether the recovery of its regulatory assets continues
to be probable. If the Company were to determine that recovery of these assets
is no longer probable, it would write off the assets against earnings. The
Company believes that SFAS No. 71 continues to apply to its regulated
operations, and that the recovery of its regulatory assets is probable.
Goodwill
and Other Intangible Assets
The
Company accounts for its goodwill and other intangibles under SFAS No. 142,
“Goodwill and Other Intangible Assets.” Under SFAS No. 142, goodwill is not
amortized, but it is tested for impairment at least annually. In addition,
goodwill of a reporting unit is tested for impairment between annual tests
if an
event occurs or circumstances change that would more likely than not reduce
the
fair value of a reporting unit below its carrying value. Other intangible assets
are amortized on a straight-line basis over their estimated economic useful
lives. Please refer to Note F “Goodwill and Other Intangible Assets” for
additional discussions of this area.
Notes
to the Consolidated Financial Statements
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. Deferred
post-employment benefits are adjusted based on current age, the present value
of
the projected annual benefit received and estimated life
expectancy.
Income
Taxes and Investment Tax Credit Adjustments
The
Company files a consolidated federal income tax return. Income tax expense
allocated to the Company’s subsidiaries is based upon their respective taxable
incomes and tax credits.
Deferred
tax assets and liabilities are recorded for the tax effect of temporary
differences between the financial statements bases and tax bases of assets
and
liabilities and are measured using current effective income tax rates. The
portions of the Company’s deferred tax liabilities applicable to utility
operations, which have not been reflected in current service rates, represent
income taxes recoverable through future rates. Investment tax credits on utility
property have been deferred and are allocated to income ratably over the lives
of the subject property.
Financial
Instruments
Xeron,
Inc. (“Xeron”), the Company’s propane wholesale marketing operation, engages in
trading activities using forward and futures contracts which have been accounted
for using the mark-to-market method of accounting. Under mark-to-market
accounting, the Company’s trading contracts are recorded at fair value, net of
future servicing costs. The changes in market price are recognized as gains
or
losses in revenues on the income statement in the period of change. The
resulting unrealized gains and losses are recorded as assets or liabilities,
respectively. There were unrealized gains of $8,500 and $46,000 at December
31,
2006 and 2005, respectively. Trading liabilities are recorded in other accrued
liabilities. Trading assets are recorded in prepaid expenses and other current
assets.
The
Company’s natural gas and propane distribution operations have entered into
agreements with natural gas and propane suppliers to purchase gas for resale
to
their customers. Purchases under these contracts either do not meet the
definition of derivatives in SFAS No. 133 or are considered “normal purchases
and sales” under SFAS No. 138 and are accounted for on an accrual
basis.
The
propane distribution operation has entered into a fair value hedge of its
inventory, in order to mitigate the impact of wholesale price fluctuations.
At
December 31, 2006, the propane distribution operation had entered into a swap
agreement to protect the Company from the impact of price increases on our
price-cap plan that we offer to customers. The Company considers this agreement
to be an economic hedge and does not qualify for hedge accounting as described
in SFAS 133. At the end of the period, the market price of propane dropped
below
the unit price within the swap agreement. As a result of the price drop, the
Company marked the agreement to market, which resulted in an unrealized loss
of
$84,000.
Notes
to the Consolidated Financial Statements
Earnings
Per Share
The
calculations of both basic and diluted earnings per share from continuing
operations are presented in the following chart.
For
the Periods Ended December 31,
|
|
2006
|
|
2005
|
|
2004
|
|
Calculation
of Basic Earnings Per Share:
|
|
|
|
|
|
|
|
Net
Income
|
|
$
|
10,506,525
|
|
$
|
10,467,614
|
|
$
|
9,549,667
|
|
Weighted
average shares outstanding
|
|
|
6,032,462
|
|
|
5,836,463
|
|
|
5,735,405
|
|
Basic
Earnings Per Share
|
|
$
|
1.74
|
|
$
|
1.79
|
|
$
|
1.66
|
|
|
|
|
|
|
|
|
|
|
|
|
Calculation
of Diluted Earnings Per Share:
|
|
|
|
|
|
|
|
|
|
|
Reconciliation
of Numerator:
|
|
|
|
|
|
|
|
|
|
|
Net
Income — Basic
|
|
$
|
10,506,525
|
|
$
|
10,467,614
|
|
$
|
9,549,667
|
|
Effect
of 8.25% Convertible debentures
|
|
|
105,024
|
|
|
123,559
|
|
|
139,097
|
|
Adjusted
numerator — Diluted
|
|
$
|
10,611,549
|
|
$
|
10,591,173
|
|
$
|
9,688,764
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation
of Denominator:
|
|
|
|
|
|
|
|
|
|
|
Weighted
shares outstanding — Basic
|
|
|
6,032,462
|
|
|
5,836,463
|
|
|
5,735,405
|
|
Effect
of dilutive securities
|
|
|
|
|
|
|
|
|
|
|
Stock
options
|
|
|
-
|
|
|
-
|
|
|
1,784
|
|
Warrants
|
|
|
-
|
|
|
11,711
|
|
|
7,900
|
|
8.25%
Convertible debentures
|
|
|
122,669
|
|
|
144,378
|
|
|
162,466
|
|
Adjusted
denominator — Diluted
|
|
|
6,155,131
|
|
|
5,992,552
|
|
|
5,907,555
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
Earnings Per Share
|
|
$
|
1.72
|
|
$
|
1.77
|
|
$
|
1.64
|
|
Operating
Revenues
Revenues
for the natural gas distribution operations of the Company are based on rates
approved by the various public service commissions. The natural gas transmission
operation’s revenues are based on rates approved by the FERC. Customers’ base
rates may not be changed without formal approval by these commissions; however,
the regulatory authorities have granted our regulated natural gas distribution
operations the ability to negotiate rates with customers that have competitive
alternatives using approved methodologies. In addition, the natural gas
transmission operation can negotiate rates above or below the FERC-approved
tariff rates.
Chesapeake’s
Maryland and Delaware natural gas distribution operations each have a gas cost
recovery mechanism that provides for the adjustment of rates charged to
customers as gas costs fluctuate. These amounts are collected or refunded
through adjustments to rates in subsequent periods.
The
Company charges flexible rates to the natural gas distribution’s industrial
interruptible customers to compete with alternative types of fuel. Based on
pricing, these customers can choose natural gas or alternative types of supply.
Neither the Company nor the interruptible customer is contractually obligated
to
deliver or receive natural gas.
The
propane wholesale marketing operation records trading activity net on the
Company’s income statement, on a mark-to-market basis, for open contracts. The
propane distribution, advanced information services and other segments record
revenue in the period the products are delivered and/or services are rendered.
Certain
Risks and Uncertainties
The
financial statements are prepared in conformity with generally accepted
accounting principles that require management to make estimates in measuring
assets and liabilities and related revenues and expenses (see Notes M and N
to
the Consolidated Financial Statements for significant estimates). These
estimates involve judgments with respect to, among other things, various future
economic factors that are difficult to predict and are beyond the control of
the
Company; therefore, actual results could differ from those
estimates.
Notes
to the Consolidated Financial Statements
The
Company records certain assets and liabilities in accordance with SFAS No.
71.
If the Company were required to terminate application of SFAS No. 71 for its
regulated operations, all such deferred amounts would be recognized in the
income statement at that time. This could result in a charge to earnings, net
of
applicable income taxes, which could be material.
FASB
Statements and Other Authoritative Pronouncements
In
December 2004, the Financial Accounting Standards Board (“FASB”) issued
SFAS No. 123 (Revised 2004), “Share-Based Payment” (“SFAS
No. 123(R)”). The Company was required to adopt SFAS
No. 123(R) in the first quarter of 2006. The Company is required to
measure the cost of all employee share-based payments to employees, including
grants of employee stock options, using a fair-value-based method. The pro
forma
disclosures previously permitted under SFAS No. 123 no longer will be an
alternative to financial statement recognition. The adoption of SFAS
No. 123(R) did not have a material impact on the financial
statements
In
May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error
Corrections”.
This
statement applies to all voluntary changes in accounting principle. It also
applies to changes required by an accounting pronouncement in the unusual
instance that the pronouncement does not include specific transition provisions.
When a pronouncement includes specific transition provisions, those provisions
should be followed. This statement requires retrospective application to prior
periods’ financial statements of changes in accounting principle, unless it is
impracticable to determine either the period-specific effects or the cumulative
effect of the change. This statement was effective for accounting changes
and corrections of errors made in fiscal years beginning after December 15,
2005. The Company was required to adopt SFAS No. 154 in the first quarter
of 2006. The implementation of this statement did not have a material impact
on
Chesapeake’s financial statements.
In
September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting
for Defined Benefit Pension and Other Postretirement Plans”.
This
statement improves financial reporting by requiring an employer to recognize
the
over-funded or under-funded status of a defined benefit postretirement plan
as
an asset or liability in its statement of financial position and to recognize
changes in that funded status in the year in which the changes occur through
comprehensive income. The Company is required to initially recognize the funded
status of a defined benefit postretirement plan and to provide the required
disclosures as of the end of the fiscal year ending after December 15,
2006. The Company adopted SFAS No. 158 as of December 31, 2006. Based on
the fair value of plan assets and their related funded status at December 31,
2006, the adoption of SFAS 158 resulted in an increase in total assets by
approximately $282,000, an increase in total liabilities by approximately
$112,000 and an increase to total shareholders equity by approximately $170,000.
Please refer to Note K “Employee Benefit Plans,” for details of each of the
Company’s benefit plans.
In
June 2006, the FASB issued FASB Interpretation (“FIN”) No. 48,
“Employers’ Accounting for Uncertainty in Income Taxes”.
This
interpretation clarifies the accounting for uncertainty in income taxes
recognized in an enterprise’s financial statements in accordance with SFAS
No. 109, “Accounting for Income Taxes”.
This
interpretation prescribes a recognition threshold and measurement attribute
for
the financial statement recognition and measurement of a tax position taken
or
expected to be taken in a tax return. This interpretation also provides guidance
on derecognition, classification, interest and penalties, accounting in interim
periods, disclosure, and transition. This interpretation is effective for fiscal
years beginning after December 15, 2006. Chesapeake is required to adopt
FIN No. 48 in the first quarter of 2007. The Company is currently
evaluating the impact that this interpretation will have on our financial
statements.
Notes
to the Consolidated Financial Statements
In
September 2006, the FASB issued SFAS No. 157, “Fair Value
Measurements”.
This
statement defines fair value, establishes a framework for measuring fair value
in generally accepted accounting principles, and expands disclosures about
fair
value measurements. This statement applies under other accounting pronouncements
that require or permit fair value measurements, the FASB having previously
concluded in those accounting pronouncements that fair value is the relevant
measurement attribute. Accordingly, this statement does not require any new
fair
value measurements. This statement is effective for financial statements issued
for fiscal years beginning after November 15, 2007, and interim periods
within those fiscal years. Chesapeake will be required to adopt SFAS
No. 157 in the first quarter of 2008. The Company has not yet evaluated the
impact that this statement will have on our financial statements.
In
September 2006, the SEC issued Staff Accounting Bulletin No. 108,
which expresses the SEC’s views regarding the process of quantifying financial
statement misstatements. The application of the guidance in this bulletin is
applicable at December 31, 2006. The implementation of this bulletin did not
have any impact on the Company’s financial statements.
Reclassification
of Prior Years’ Amounts
Certain
prior years’ amounts have been reclassified to conform to the current year’s
presentation.
During
2003, Chesapeake decided to exit the water services business and sold six of
its
seven operations. The remaining operation was sold in October 2004. At December
31, 2006, all property and assets of the water subsidiary have been sold. The
results of operations for all water service businesses have been reclassified
to
discontinued operations for all periods presented. Operating revenues for
discontinued operations was $1.1 million and operating losses for discontinued
operations was $94,000 for 2004. A loss of $52,000, net of tax, was recorded
for
2004 on the sale of the water operations. The Company did not have any
discontinued operations in 2006 and 2005.
Notes
to the Consolidated Financial Statements
C.
Segment Information
The
following table presents information about the Company’s reportable segments.
The table excludes discontinued operations.
For
the Years Ended December 31,
|
|
2006
|
|
2005
|
|
2004
|
|
Operating
Revenues, Unaffiliated Customers
|
|
|
|
|
|
|
|
Natural
gas distribution, transmission and marketing
|
|
$
|
170,114,514
|
|
$
|
166,388,562
|
|
$
|
124,073,939
|
|
Propane
|
|
|
48,575,976
|
|
|
48,975,349
|
|
|
41,499,687
|
|
Advanced
information services
|
|
|
12,509,077
|
|
|
14,121,441
|
|
|
12,381,815
|
|
Other
|
|
|
1,024
|
|
|
144,384
|
|
|
-
|
|
Total
operating revenues, unaffiliated customers
|
|
$
|
231,200,591
|
|
$
|
229,629,736
|
|
$
|
177,955,441
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment
Revenues (1)
|
|
|
|
|
|
|
|
|
|
|
Natural
gas distribution, transmission and marketing
|
|
$
|
259,969
|
|
$
|
193,404
|
|
$
|
172,427
|
|
Propane
|
|
|
-
|
|
|
668
|
|
|
-
|
|
Advanced
information services
|
|
|
58,532
|
|
|
18,123
|
|
|
45,266
|
|
Other
|
|
|
618,493
|
|
|
618,492
|
|
|
647,378
|
|
Total
intersegment revenues
|
|
$
|
936,994
|
|
$
|
830,687
|
|
$
|
865,071
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
|
|
|
|
|
|
|
|
Natural
gas distribution, transmission and marketing
|
|
$
|
19,733,487
|
|
$
|
17,235,810
|
|
$
|
17,091,360
|
|
Propane
|
|
|
2,534,035
|
|
|
3,209,388
|
|
|
2,363,884
|
|
Advanced
information services
|
|
|
767,160
|
|
|
1,196,544
|
|
|
387,193
|
|
Other
and eliminations
|
|
|
(103,371
|
)
|
|
(111,243
|
)
|
|
127,309
|
|
Total
operating income
|
|
$
|
22,931,311
|
|
$
|
21,530,499
|
|
$
|
19,969,746
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
|
|
|
|
|
|
|
|
|
|
|
Natural
gas distribution, transmission and marketing
|
|
$
|
6,312,277
|
|
$
|
5,682,137
|
|
$
|
5,418,007
|
|
Propane
|
|
|
1,658,554
|
|
|
1,574,357
|
|
|
1,524,016
|
|
Advanced
information services
|
|
|
112,729
|
|
|
122,569
|
|
|
138,007
|
|
Other
and eliminations
|
|
|
160,155
|
|
|
189,146
|
|
|
177,508
|
|
Total
depreciation and amortization
|
|
$
|
8,243,715
|
|
$
|
7,568,209
|
|
$
|
7,257,538
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
Expenditures
|
|
|
|
|
|
|
|
|
|
|
Natural
gas distribution, transmission and marketing
|
|
$
|
43,894,614
|
|
$
|
28,433,671
|
|
$
|
13,945,214
|
|
Propane
|
|
|
4,778,891
|
|
|
3,955,799
|
|
|
3,395,190
|
|
Advanced
information services
|
|
|
159,402
|
|
|
294,792
|
|
|
84,185
|
|
Other
|
|
|
321,204
|
|
|
739,079
|
|
|
404,941
|
|
Total
capital expenditures
|
|
$
|
49,154,111
|
|
$
|
33,423,341
|
|
$
|
17,829,530
|
|
(1)
All significant intersegment revenues are billed at market rates
and have
been eliminated from consolidated revenues.
|
|
|
|
|
|
|
|
|
|
|
|
|
At
December 31,
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
Identifiable
Assets
|
|
|
|
|
|
|
|
|
|
|
Natural
gas distribution, transmission and marketing
|
|
$
|
252,292,600
|
|
$
|
225,667,049
|
|
$
|
184,412,301
|
|
Propane
|
|
|
60,170,200
|
|
|
57,344,859
|
|
|
47,531,106
|
|
Advanced
information services
|
|
|
2,573,810
|
|
|
2,062,902
|
|
|
2,387,440
|
|
Other
|
|
|
9,957,374
|
|
|
10,905,065
|
|
|
7,379,794
|
|
Total
identifiable assets
|
|
$
|
324,993,984
|
|
$
|
295,979,875
|
|
$
|
241,710,641
|
|
Notes
to the Consolidated Financial Statements
Chesapeake
uses the management approach to identify operating segments. Chesapeake
organizes its business around differences in products or services and the
operating results of each segment are regularly reviewed by the Company’s chief
operating decision maker in order to make decisions about resources and to
assess performance. The segments are evaluated based on their pre-tax operating
income.
The
Company’s operations are all domestic. The advanced information services segment
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.
Fair Value of Financial Instruments
E.
Investments
The
investment balances at December 31, 2006 and 2005 represent a Rabbi Trust (“the
trust”) associated with the Company’s Supplemental Executive Retirement Savings
Plan. In accordance with SFAS No. 115, “Accounting for Certain Investments in
Debt and Equity Securities,” the Company classifies these investments as trading
securities. As a result of classifying them as trading securities, we are
required to report the securities at their fair value, with any unrealized
gains
and losses included in other income. We also have an associated liability that
is recorded and adjusted each month, along with other expense, for the gains
and
losses incurred by the trust. At December 31, 2006 and 2005, total investments
had a fair value of $2.0 million and $1.7 million.
F.
Goodwill and Other Intangible Assets
In
accordance with SFAS No. 142, goodwill is tested for impairment at least
annually. In addition, goodwill of a reporting unit is tested for impairment
between annual tests if an event occurs or circumstances change that would
more
likely than not reduce the fair value of a reporting unit below its carrying
value. The propane unit had $674,000 in goodwill for the two years ended
December 31, 2006 and 2005. Testing for 2006 and 2005 has indicated that no
impairment has occurred.
Notes
to the Consolidated Financial Statements
The
carrying value and accumulated amortization of intangible assets subject to
amortization for the two years ended December 31, 2006 are as
follows:
|
|
December
31, 2006
|
|
December
31, 2005
|
|
|
|
Gross
Carrying Amount
|
|
Accumulated
Amortization
|
|
Gross
Carrying Amount
|
|
Accumulated
Amortization
|
|
Customer
lists
|
|
$
|
115,333
|
|
$
|
75,057
|
|
$
|
115,333
|
|
$
|
67,845
|
|
Acquisition
costs
|
|
|
263,659
|
|
|
112,057
|
|
|
263,659
|
|
|
105,465
|
|
Total
|
|
$
|
378,992
|
|
$
|
187,114
|
|
$
|
378,992
|
|
$
|
173,310
|
|
Amortization
of intangible assets was $14,000 for the years ended December 31, 2006 and
2005,
respectively. The estimated annual amortization of intangibles is $14,000 per
year for each of the years 2007 through 2011, respectively.
The
changes in the common stock shares issued and outstanding are shown in the
table
below:
For
the Years Ended December 31,
|
|
2006
|
|
2005
|
|
2004
|
|
Common
Stock shares issued and outstanding (1)
|
|
|
|
|
|
|
|
Shares
issued — beginning of period balance
|
|
|
5,883,099
|
|
|
5,778,976
|
|
|
5,660,594
|
|
Dividend
Reinvestment Plan (2)
|
|
|
38,392
|
|
|
41,175
|
|
|
40,993
|
|
Retirement
Savings Plan
|
|
|
29,705
|
|
|
21,071
|
|
|
39,157
|
|
Conversion
of debentures
|
|
|
16,677
|
|
|
22,609
|
|
|
18,616
|
|
Employee
award plan
|
|
|
350
|
|
|
-
|
|
|
-
|
|
Performance
shares and options exercised (3)
|
|
|
29,516
|
|
|
19,268
|
|
|
19,616
|
|
Public
offering
|
|
|
690,345
|
|
|
-
|
|
|
-
|
|
Shares
issued — end of period balance (4)
|
|
|
6,688,084
|
|
|
5,883,099
|
|
|
5,778,976
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury
shares — beginning of period balance
|
|
|
(97
|
)
|
|
(9,418
|
)
|
|
-
|
|
Purchases
|
|
|
-
|
|
|
(4,852
|
)
|
|
(15,316
|
)
|
Dividend
Reinvestment Plan
|
|
|
-
|
|
|
2,142
|
|
|
-
|
|
Retirement
Savings Plan
|
|
|
-
|
|
|
12,031
|
|
|
-
|
|
Other
issuances
|
|
|
97
|
|
|
-
|
|
|
5,898
|
|
Treasury
Shares — end of period balance
|
|
|
-
|
|
|
(97
|
)
|
|
(9,418
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total
Shares Outstanding
|
|
|
6,688,084
|
|
|
5,883,002
|
|
|
5,769,558
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
12,000,000 shares are authorized at a par value of $0.4867 per
share.
|
|
(2)
Includes shares purchased with reinvested dividends and optional
cash
payments.
|
|
(3)
Includes shares issued for Directors' compensation.
|
|
(4)
Includes 48,187, 37,528, and 48,175 shares at December 31, 2006,
2005 and
2004, respectively, held in a Rabbi Trust established by the Company
relating to the Executive Deferred Compensation Plan.
|
|
In
2000
and 2001, the Company entered into agreements with an investment banker to
assist in identifying acquisition candidates. Under the agreements, the Company
issued warrants to the investment banker to purchase 15,000 shares of Chesapeake
stock in 2000 at an exercise price of $18.00 per share and 15,000 in 2001 at
an
exercise price of $18.25 per share. In August 2006, the investment banker
exercised the 30,000 warrants pursuant to the terms of the agreement at $33.3657
per share. At the request of the investment banker, Chesapeake settled the
warrants with a cash payment of $435,000, in lieu of issuing shares of the
Company’s common stock. At December 31, 2006, Chesapeake does not have any stock
warrants outstanding.
Notes
to the Consolidated Financial Statements
On
November 21, 2006 the Company completed a public offering of 600,300 shares
of
its common stock at a price per share of $30.10. On
November 30, 2006, the Company completed the sale of 90,045 additional shares
of
its common stock, pursuant to the over-allotment option granted to the
Underwriters by the Company. The net proceeds from the sale of common stock,
after deducting underwriting commissions and expenses, were approximately $19.8
million, which were added to the Company’s general funds and used primarily to
repay a portion of the Company’s short-term debt under unsecured lines of
credit.
The
outstanding long-term debt, net of current maturities, is as shown
below.
At
December 31,
|
|
2006
|
|
2005
|
|
2004
|
|
Uncollateralized
senior notes:
|
|
|
|
|
|
|
|
7.97%
note, due February 1, 2008
|
|
$
|
1,000,000
|
|
$
|
2,000,000
|
|
$
|
3,000,000
|
|
6.91%
note, due October 1, 2010
|
|
|
2,727,273
|
|
|
3,636,363
|
|
|
4,545,454
|
|
6.85%
note, due January 1, 2012
|
|
|
4,000,000
|
|
|
5,000,000
|
|
|
6,000,000
|
|
7.83%
note, due January 1, 2015
|
|
|
14,000,000
|
|
|
16,000,000
|
|
|
20,000,000
|
|
6.64%
note, due October 31, 2017
|
|
|
27,272,727
|
|
|
30,000,000
|
|
|
30,000,000
|
|
5.50%
note, due October 12, 2020
|
|
|
20,000,000
|
|
|
-
|
|
|
-
|
|
Convertible
debentures:
|
|
|
|
|
|
|
|
|
|
|
8.25%
due March 1, 2014
|
|
|
1,970,000
|
|
|
2,254,000
|
|
|
2,644,000
|
|
Promissory
note
|
|
|
80,000
|
|
|
100,000
|
|
|
-
|
|
Total
Long-Term Debt
|
|
$
|
71,050,000
|
|
$
|
58,990,363
|
|
$
|
66,189,454
|
|
|
|
|
|
|
|
|
|
|
|
|
Annual
maturities of consolidated long-term debt for the next five years
are as
follows: $7,656,364 for 2007;$7,656,364 for 2008; $6,656,364 for
2009,$6,656,364 for 2010 and $7,747,273 for 2011.
|
|
The
convertible debentures may be converted, at the option of the holder, into
shares of the Company’s common stock at a conversion price of $17.01 per share.
During 2006 and 2005, debentures totaling $284,000 and $385,000, respectively,
were converted to stock. The debentures are also redeemable for cash at the
option of the holder, subject to an annual non-cumulative maximum limitation
of
$200,000. In 2006, no debentures were redeemed for cash. During 2005, debentures
totaling $5,000 were redeemed for cash. At the Company’s option, the debentures
may be redeemed at stated amounts.
On
October 12, 2006, the Company issued $20 million of 5.5 percent Senior Notes
to
three institutional investors (The Prudential Insurance Company of America,
Prudential Retirement Insurance and Annuity Company and United Omaha Life
Insurance Company). The original note agreement was executed on October 18,
2005
and provided for the Company to sell the Notes at any time prior to January
15,
2007. The terms of the Notes require annual principal repayments of $2 million
beginning on the fifth anniversary of the issuance of the Notes. The Notes
will
mature on October 12, 2020. The proceeds from this issuance were used to reduce
a portion of the Company’s outstanding short-term debt.
Indentures
to the long-term debt of the Company and its subsidiaries contain various
restrictions. The most stringent restrictions state that the Company must
maintain equity of at least 40 percent of total capitalization and the pro-forma
fixed charge coverage ratio must be 1.5 times. The Company is in compliance
with
all of its debt covenants.
I.
Short-term Borrowing
As
of
December 31, 2006, the Board of Directors (“Board”) has authorized the Company
to borrow up to $55.0 million from various banks and trust companies under
short-term lines of credit. During 2006, the Board authorized increases in
the
Company’s borrowing authority up to $75 million to fund the 2006 capital budget
and working capital. The $75 million limit was subsequently reduced to its
current level by the Board on November 7, 2006, following the placement on
October 12, 2006 of $20 million 5.50 percent Senior Notes.
Notes
to the Consolidated Financial Statements
As
of
December 31, 2006, the Company had four unsecured bank lines of credit with
two
financial institutions, totaling $80.0 million, none of which required
compensating balances. These bank lines provide funds for the Company’s
short-term cash needs to meet seasonal working capital requirements and to
temporarily fund portions of its capital expenditures. Two of the bank lines,
totaling $15.0 million, are committed. The other two lines are subject to the
banks’ availability of funds. Under these lines of credit, the outstanding
balances of short-term debt at December 31, 2006 and 2005 were $27.6 million
and
$35.5 million, respectively. The annual weighted average interest rates on
short-term debt were 5.47 percent and 4.47 percent for 2006 and 2005,
respectively. The Company also had a letter of credit outstanding in the amount
of $775,000 that reduced the amounts available under the lines of
credit.
J.
Lease Obligations
The
Company has entered into several operating lease arrangements for office space
at various locations, equipment and pipeline facilities. Rent expense related
to
these leases was $680,000, $837,000, and $934,000 for 2006, 2005 and 2004,
respectively. Future minimum payments under the Company’s current lease
agreements are $650,000, $496,000, $423,000, $331,000 and $321,000 for the
years
2007 through 2011, respectively; and $3.8 million thereafter, totaling $6.0
million.
K.
Employee Benefit Plans
Retirement
Plans
Before
1999, Company employees generally participated in both a defined benefit pension
plan (“Defined Pension Plan”) and a Retirement Savings Plan. Effective January
1, 1999, the Company restructured its retirement program to compete more
effectively with similar businesses. As part of this restructuring, the Company
closed the Defined Pension Plan to new participants. Employees who participated
in the Defined Pension Plan at that time were given the option of remaining
in
(and continuing to accrue benefits under) the Defined Pension Plan or receiving
an enhanced matching contribution in the Retirement Savings Plan.
Because
the Defined Pension Plan was not open to new participants, the number of active
participants in that plan decreased and is approaching the minimum number needed
for the Defined Pension Plan to maintain its tax-qualified status. To avoid
jeopardizing the tax-qualified status of the Defined Pension Plan, the Company’s
Board of Directors amended the Defined Pension Plan on September 24, 2004.
To
ensure that the Company continues to provide appropriate levels of benefits
to
the Company’s employees, the Board amended the Defined Pension Plan and the
Retirement Savings Plan, effective January 1, 2005, so that Defined Pension
Plan
participants who were actively employed by the Company on that date (1) receive
two additional years of benefit service credit to be used in calculating their
Defined Pension Plan benefit (subject to the Defined Pension Plan’s limit of 35
years of benefit service credit), (2) have the option to receive their Defined
Pension Plan benefit in the form of a lump sum at the time they retire, and
(3)
are eligible to receive the enhanced matching contribution in the Retirement
Savings Plan. In addition, effective January 1, 2005, the Board amended the
Defined Pension Plan so that participants will not accrue any additional
benefits under that plan. These changes were communicated to the Company’s
employees during the first week of November 2004. As a result of the amendments
to the Defined Pension Plan, a gain of approximately $172,000 (after tax) was
recorded during 2004.
In
September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined
Benefit Pension and Other Postretirement Plans” (SFAS 158). The Company adopted
SFAS 158 prospectively on December 31, 2006. SFAS 158 requires that we recognize
all obligations related to defined benefit pensions and other postretirement
benefits. This statement requires that we quantify the plans’ funded status as
an asset or a liability on our consolidated balance sheets.
Notes
to the Consolidated Financial Statements
SFAS
158
requires that we measure the plans’ assets and obligations that determine our
funded status as of the end of the fiscal year. The Company is also required
to
recognize as a component of accumulated other comprehensive income (“AOCI”) the
changes in funded status that occurred during the year that are not recognized
as part of net periodic benefit cost as explained in SFAS No. 87, “Employers’
Accounting for Pensions,” or SFAS No. 106, “Employers’ Accounting for
Postretirement Benefits Other Than Pensions.”
Based
on
the funded status of the Company’s defined benefit pension and postretirement
benefit plans as of December 31, 2006, the effects of adopting SFAS 158 on
the
Company’s financial statement is set forth in the following table.
|
|
Pre-SFAS
158
|
|
SFAS
Adoption Adjustments
|
|
Post
SFAS 158
|
|
Asset
(liability) for pension benefits
|
|
|
($3,741,054
|
)
|
$
|
281,538
|
|
|
($3,459,516
|
)
|
Deferred
income tax asset (liability)
|
|
|
1,224,742
|
|
|
(111,973
|
)
|
|
1,112,769
|
|
Accumulated
other comprehensive income
|
|
|
504,115
|
|
|
(169,565
|
)
|
|
334,550
|
|
The
amounts recognized in AOCI as a result of the adoption of SFAS 158 consist
of:
|
|
Defined
Benefit Pension
|
|
Other
Postretirement Benefit
|
|
Total
|
|
Prior
service cost (credit)
|
|
|
($29,560
|
)
|
|
-
|
|
|
($29,560
|
)
|
Loss
(gain)
|
|
|
(1,284,400
|
)
|
|
1,032,422
|
|
|
(251,978
|
)
|
Total
|
|
|
(1,313,960
|
)
|
|
1,032,422
|
|
|
(281,538
|
)
|
Less:
Deferred tax asset (liability)
|
|
|
(522,582
|
)
|
|
410,609
|
|
|
(111,973
|
)
|
Loss
(gain) in AOCI, net of tax
|
|
|
($791,378
|
)
|
$
|
621,813
|
|
|
($169,565
|
)
|
The
amounts in AOCI for the respective retirement plans that are expected to be
recognized as a component of net benefit cost in 2007 is set forth in the
following table.
|
|
Defined
Benefit Pension
|
|
Executive
Excess Defined Benefit
|
|
Total
|
|
Prior
service cost (credit)
|
|
|
($4,699
|
)
|
|
-
|
|
|
-
|
|
Loss
(gain)
|
|
|
(6,846
|
)
|
|
51,279
|
|
|
136,978
|
|
Defined
Benefit Pension Plan
As
described above, effective January 1, 2005, the Defined Pension Plan was frozen
with respect to additional years of service or additional compensation. Benefits
under the plan were based on each participant’s years of service and highest
average compensation, prior to the freeze. The Company’s funding policy provides
that payments to the trustee shall be equal to the minimum funding requirements
of the Employee Retirement Income Security Act of 1974. The Company does not
expect to be required to make any funding payments toward the Defined Pension
Plan in 2007. The measurement dates for the Pension Plan were December 31,
2006
and 2005, respectively.
The
following schedule summarizes the assets of the Defined Pension Plan, by
investment type, at December 31, 2006, 2005 and 2004:
At
December 31,
|
|
2006
|
|
2005
|
|
2004
|
|
Asset
Category
|
|
|
|
|
|
|
|
Equity
securities
|
|
|
77.34
|
%
|
|
76.12
|
%
|
|
72.64
|
%
|
Debt
securities
|
|
|
18.59
|
%
|
|
23.28
|
%
|
|
12.91
|
%
|
Other
|
|
|
4.07
|
%
|
|
0.60
|
%
|
|
14.45
|
%
|
Total
|
|
|
100.00
|
%
|
|
100.00
|
%
|
|
100.00
|
%
|
Notes
to the Consolidated Financial Statements
The
asset
listed as “Other” in the above table represents monies temporarily held in money
market funds. The money market fund invests at least 80 percent of its total
assets in:
· |
United
States Government obligations; and
|
· |
Repurchase
agreements that are fully collateralized by such
obligations.
|
The
investment policy of the Plan calls for an allocation of assets between equity
and debt instruments with equity being 60 percent and debt at 40 percent, but
allowing for a variance of 20 percent in either direction. Additionally, as
changes are made to holdings, cash, money market funds or United States Treasury
Bills may be held temporarily by the fund. Investments in the following are
prohibited: options, guaranteed investment contracts, real estate, venture
capital, private placements, futures, commodities, limited partnerships and
Chesapeake stock. Additionally, short selling and margin transactions are
prohibited. During 2004, Chesapeake modified its investment policy to allow
the
Employee Benefits Committee to reallocate investments to better match the
expected life of the plan.
The
following schedule sets forth the funded status of the Defined Pension Plan
at
December 31, 2006, 2005 and 2004:
At
December 31,
|
|
2006
|
|
2005
|
|
2004
|
|
Change
in benefit obligation:
|
|
|
|
|
|
|
|
Benefit
obligation — beginning of year
|
|
$
|
12,399,621
|
|
$
|
12,053,063
|
|
$
|
11,948,755
|
|
Service
cost
|
|
|
-
|
|
|
-
|
|
|
338,352
|
|
Interest
cost
|
|
|
635,877
|
|
|
645,740
|
|
|
690,620
|
|
Change
in assumptions
|
|
|
(301,851
|
)
|
|
388,979
|
|
|
573,639
|
|
Actuarial
loss
|
|
|
607
|
|
|
28,895
|
|
|
220,842
|
|
Amendments
|
|
|
-
|
|
|
-
|
|
|
883,753
|
|
Effect
of curtailment/settlement
|
|
|
-
|
|
|
-
|
|
|
(2,171,289
|
)
|
Benefits
paid
|
|
|
(1,284,529
|
)
|
|
(717,056
|
)
|
|
(431,609
|
)
|
Benefit
obligation — end of year
|
|
|
11,449,725
|
|
|
12,399,621
|
|
|
12,053,063
|
|
|
|
|
|
|
|
|
|
|
|
|
Change
in plan assets:
|
|
|
|
|
|
|
|
|
|
|
Fair
value of plan assets — beginning of year
|
|
|
11,780,866
|
|
|
12,097,248
|
|
|
11,301,548
|
|
Actual
return on plan assets
|
|
|
1,543,950
|
|
|
400,674
|
|
|
1,227,309
|
|
Benefits
paid
|
|
|
(1,284,529
|
)
|
|
(717,056
|
)
|
|
(431,609
|
)
|
Fair
value of plan assets — end of year
|
|
|
12,040,287
|
|
|
11,780,866
|
|
|
12,097,248
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation
of funded status: (1)
|
|
|
|
|
|
|
|
|
|
|
Plan
assets in excess (less than) benefit obligation at
year-end
|
|
|
590,560
|
|
|
(618,755
|
)
|
|
44,185
|
|
Unrecognized
prior service cost
|
|
|
-
|
|
|
(34,259
|
)
|
|
(38,958
|
)
|
Unrecognized
net actuarial gain
|
|
|
-
|
|
|
(129,739
|
)
|
|
(850,224
|
)
|
Net
amount accrued
|
|
$
|
590,560
|
|
|
($782,753
|
)
|
|
($844,997
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Assumptions:
|
|
|
|
|
|
|
|
|
|
|
Discount
rate
|
|
|
5.50
|
%
|
|
5.25
|
%
|
|
5.50
|
%
|
Expected
return on plan assets
|
|
|
6.00
|
%
|
|
6.00
|
%
|
|
7.88
|
%
|
|
|
|
|
|
|
|
|
|
|
|
(1)
After the adoption of SFAS 158 on December 31, 2006, these amounts
are
recorded and this reconciliation is no longer required.
|
|
Net
periodic pension costs for the defined benefit Pension Plan for 2006, 2005,
and
2004 include the components as shown below:
For
the Years Ended December 31,
|
|
2006
|
|
2005
|
|
2004
|
|
Components
of net periodic pension cost:
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
0
|
|
$
|
0
|
|
$
|
338,352
|
|
Interest
cost
|
|
|
635,877
|
|
|
645,740
|
|
|
690,620
|
|
Expected
return on assets
|
|
|
(690,533
|
)
|
|
(703,285
|
)
|
|
(869,336
|
)
|
Amortization
of:
|
|
|
|
|
|
|
|
|
|
|
Transition
assets
|
|
|
-
|
|
|
-
|
|
|
(11,328
|
)
|
Prior
service cost
|
|
|
(4,699
|
)
|
|
(4,699
|
)
|
|
(4,699
|
)
|
Net
periodic pension cost (benefit)
|
|
|
($59,355
|
)
|
|
($62,244
|
)
|
$
|
143,609
|
|
Notes
to the Consolidated Financial Statements
The
following actuarial assumptions were used in calculating net periodic pension
cost or benefit.
For
the Years Ended December 31,
|
|
2006
|
|
2005
|
|
2004
|
|
Assumptions:
|
|
|
|
|
|
|
|
Discount
rate
|
|
|
5.25
|
%
|
|
5.50
|
%
|
|
5.88
|
%
|
Expected
return on plan assets
|
|
|
6.00
|
%
|
|
6.00
|
%
|
|
7.88
|
%
|
The
assumptions used for the discount rate of the plan were reviewed by the Company
and increased from 5.25 percent to 5.50 percent, reflecting an increase in
the
interest rates of high quality bonds and reflecting the expected life of the
plan, due to the lump sum payment option. Additionally, the average expected
return on plan assets for the qualified plan remained constant at 6 percent
due
to the adoption of a change in the investment policy that allows for a higher
level of investment in bonds and a lower level of equity investments. Since
the
Plan is frozen in regards to additional years of service and compensation,
the
rate of assumed compensation rate increases is not applicable. The accumulated
benefit obligation was $11.4 million and $12.4 million at December 31, 2006
and
2005, respectively.
Executive
Excess Defined Benefit Pension Plan
The
Company also sponsors an unfunded executive excess defined benefit pension
plan.
As noted above, this plan was frozen with respect to additional years of service
and additional compensation as of December 31, 2004. Benefits under the plan
were based on each participant’s years of service and highest average
compensation, prior to the freeze. The accumulated benefit obligation was $2.29
million and $2.32 million at December 31, 2006 and 2005, respectively.
Net
periodic pension costs for the executive excess benefit pension plan for 2006,
2005, and 2004 include the components as shown below:
For
the Years Ended December 31,
|
|
2006
|
|
2005
|
|
2004
|
|
Components
of net periodic pension cost:
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
0
|
|
$
|
0
|
|
$
|
105,913
|
|
Interest
cost
|
|
|
119,588
|
|
|
119,658
|
|
|
87,568
|
|
Amortization
of:
|
|
|
|
|
|
|
|
|
|
|
Prior
service cost
|
|
|
-
|
|
|
-
|
|
|
2,090
|
|
Actuarial
loss
|
|
|
57,039
|
|
|
49,319
|
|
|
21,699
|
|
Net
periodic pension cost
|
|
$
|
176,627
|
|
$
|
168,977
|
|
$
|
217,270
|
|
Notes
to the Consolidated Financial Statements
The
following schedule sets forth the status of the executive excess defined benefit
plan:
At
December 31,
|
|
2006
|
|
2005
|
|
2004
|
|
Change
in benefit obligation:
|
|
|
|
|
|
|
|
Benefit
obligation — beginning of year
|
|
$
|
2,322,471
|
|
$
|
2,162,952
|
|
$
|
1,406,190
|
|
Service
cost
|
|
|
-
|
|
|
-
|
|
|
105,913
|
|
Interest
cost
|
|
|
119,588
|
|
|
119,658
|
|
|
87,568
|
|
Actuarial
(gain) loss
|
|
|
(65,886
|
)
|
|
133,839
|
|
|
713,225
|
|
Amendments
|
|
|
-
|
|
|
-
|
|
|
60,000
|
|
Effect
of curtailment/settlement
|
|
|
-
|
|
|
-
|
|
|
(184,844
|
)
|
Benefits
paid
|
|
|
(89,203
|
)
|
|
(93,978
|
)
|
|
(25,100
|
)
|
Benefit
obligation — end of year
|
|
|
2,286,970
|
|
|
2,322,471
|
|
|
2,162,952
|
|
|
|
|
|
|
|
|
|
|
|
|
Change
in plan assets:
|
|
|
|
|
|
|
|
|
|
|
Fair
value of plan assets — beginning of year
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Employer
contributions
|
|
|
89,203
|
|
|
93,978
|
|
|
25,100
|
|
Benefits
paid
|
|
|
(89,203
|
)
|
|
(93,978
|
)
|
|
(25,100
|
)
|
Fair
value of plan assets — end of year
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded
status
|
|
|
(2,286,970
|
)
|
|
(2,322,471
|
)
|
|
(2,162,952
|
)
|
Unrecognized
net actuarial loss
|
|
|
-
|
|
|
959,492
|
|
|
874,972
|
|
Net
amount accrued (1)
|
|
|
($2,286,970
|
)
|
|
($1,362,979
|
)
|
|
($1,287,980
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Assumptions:
|
|
|
|
|
|
|
|
|
|
|
Discount
rate
|
|
|
5.50
|
%
|
|
5.25
|
%
|
|
5.50
|
%
|
|
|
|
|
|
|
|
|
|
|
|
(1)
After the adoption of SFAS 158 on December 31, 2006, these amounts
are
recorded and this reconciliation is no longer required.
|
|
The
assumptions used for the discount rate of the plan were reviewed by the Company
and increased from 5.25 percent to 5.50 percent, reflecting an increase in
the
interest rates of high quality bonds and a reduction in the expected life of
the
plan. Since the Plan is frozen in regards to additional years of service and
compensation, the rate of assumed pay rate increases is not applicable. The
measurement dates for the executive excess benefit plan were December 31, 2006
and 2005, respectively.
Other
Postretirement Benefits
The
Company sponsors a defined benefit postretirement health care and life insurance
plan that covers substantially all employees.
Net
periodic postretirement costs for 2006, 2005 and 2004 include the following
components:
For
the Years Ended December 31,
|
|
2006
|
|
2005
|
|
2004
|
|
Components
of net periodic postretirement cost:
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
9,194
|
|
$
|
6,257
|
|
$
|
5,354
|
|
Interest
cost
|
|
|
93,924
|
|
|
77,872
|
|
|
86,883
|
|
Amortization
of:
|
|
|
|
|
|
|
|
|
|
|
Transition
obligation
|
|
|
22,282
|
|
|
27,859
|
|
|
27,859
|
|
Actuarial
loss
|
|
|
144,694
|
|
|
88,291
|
|
|
78,900
|
|
Net
periodic postretirement cost
|
|
$
|
270,094
|
|
$
|
200,279
|
|
$
|
198,996
|
|
Notes
to the Consolidated Financial Statements
The
following schedule sets forth the status of the postretirement health care
and
life insurance plan:
At
December 31,
|
|
2006
|
|
2005
|
|
2004
|
|
Change
in benefit obligation:
|
|
|
|
|
|
|
|
Benefit
obligation — beginning of year
|
|
$
|
1,534,684
|
|
$
|
1,599,280
|
|
$
|
1,471,664
|
|
Retirees
|
|
|
264,470
|
|
|
(59,152
|
)
|
|
91,747
|
|
Fully-eligible
active employees
|
|
|
(114,082
|
)
|
|
(31,761
|
)
|
|
22,071
|
|
Other
active
|
|
|
78,036
|
|
|
26,317
|
|
|
13,798
|
|
Benefit
obligation — end of year
|
|
$
|
1,763,108
|
|
$
|
1,534,684
|
|
$
|
1,599,280
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded
status
|
|
|
($1,763,108
|
)
|
|
($1,534,684
|
)
|
|
($1,599,280
|
)
|
Unrecognized
transition obligation
|
|
|
-
|
|
|
22,282
|
|
|
50,141
|
|
Unrecognized
net actuarial loss
|
|
|
-
|
|
|
751,450
|
|
|
899,228
|
|
Net
amount accrued (1)
|
|
|
($1,763,108
|
)
|
|
($760,952
|
)
|
|
($649,911
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Assumptions:
|
|
|
|
|
|
|
|
|
|
|
Discount
rate
|
|
|
5.50
|
%
|
|
5.25
|
%
|
|
5.50
|
%
|
|
|
|
|
|
|
|
|
|
|
|
(1)
After the adoption of SFAS 158 on December 31, 2006, these amounts
are
recorded and this reconciliation is no longer required.
|
|
The
health care inflation rate for 2006 is assumed to be 6 percent for medical
and 8
percent for prescription drugs. These rates are projected to gradually decrease
to ultimate rates of 5 and 6 percent, respectively, by the year 2009. A one
percentage point increase in the health care inflation rate from the assumed
rate would increase the accumulated postretirement benefit obligation by
approximately $250,000 as of January 1, 2007, and would increase the aggregate
of the service cost and interest cost components of the net periodic
postretirement benefit cost for 2007 by approximately $15,000. A one percentage
point decrease in the health care inflation rate from the assumed rate would
decrease the accumulated postretirement benefit obligation by approximately
$207,000 as of January 1, 2007, and would decrease the aggregate of the service
cost and interest cost components of the net periodic postretirement benefit
cost for 2007 by approximately $13,000. The measurement dates were December
31,
2006 and 2005, respectively.
Estimated
Future Benefit Payments
The
schedule below shows the estimated future benefit payments for each of the
years
2007 through 2011 and the aggregate of the next five years for each of the
plans
previously described.
|
|
Defined
Benefit Pension Plan (1)
|
|
Executive
Excess Defined Benefit Pension Plan (2)
|
|
Other
Post-Retirement Benefits (2)
|
|
2007
|
|
$
|
721,575
|
|
$
|
88,096
|
|
$
|
180,205
|
|
2008
|
|
|
713,699
|
|
|
86,868
|
|
|
182,977
|
|
2009
|
|
|
1,447,370
|
|
|
85,513
|
|
|
185,059
|
|
2010
|
|
|
898,179
|
|
|
84,026
|
|
|
204,870
|
|
2011
|
|
|
460,335
|
|
|
82,411
|
|
|
194,448
|
|
Years
2012 through 2016
|
|
|
4,714,092
|
|
|
758,013
|
|
|
1,010,982
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
The pension plan is funded; therefore, benefit payments are expected
to be
paid out of the plan assets.
|
|
(2)
Benefit payments are expected to be paid out of the general funds
of the
Company.
|
|
Retirement
Savings Plan
The
Company sponsors a 401(k) Retirement Savings Plan, which provides participants
a
mechanism for making contributions for retirement savings. Each participant
may
make pre-tax contributions of up to 15 percent of eligible base compensation,
subject to Internal Revenue Service limitations. These participants were
eligible for the enhanced matching described below effective January 1, 2005.
Effective
January 1, 1999, the Company began offering an enhanced 401(k) Plan to all
new
employees, as well as existing employees that elected to no longer participate
in the Defined Benefit Plan. The Company makes matching contributions on a
basis
of up to six percent of each employee's pre-tax compensation for the year for
all of the Company’s employees, except the employees for our Advanced
Information Services segment. The match is between 100 percent and 200 percent,
based on a combination of the employee’s age and years of service. The first 100
percent of the funds are matched with Chesapeake common stock. The remaining
match is invested in the Company’s 401(k) Plan according to each employee’s
election options.
Notes
to the Consolidated Financial Statements
Effective
July 1, 2006, the matching contribution made on behalf of Advanced Information
Services segment employees, is a 50 percent matching contribution, up to six
percent of the employee’s annual compensation. The matching contribution is
funded in Chesapeake common stock. The Plan was also amended at the same time
to
enable it to receive discretionary profit-sharing contributions in the form
of
employee pre-tax deferrals. The extent, to which the Advanced Information
Services segment has any dollars available for profit-sharing, is dependent
upon
the extent to which actual earnings exceed budgeted earnings. Any profit-sharing
dollars made available to employees can be deferred into the Plan and/or paid
out in the form of a bonus.
On
December 1, 2001, the Company converted the 401(k) fund holding Chesapeake
stock
to an Employee Stock Ownership Plan (“ESOP”).
Effective
January 1, 1999, the Company began offering a non-qualified supplemental
employee retirement savings plan open to Company executives over a specific
income threshold. Participants receive a cash only matching contribution
percentage equivalent to their 401(k) match level. All contributions and matched
funds can be invested among the twenty-one mutual funds available for
investment. These same funds are available for investment of employee
contributions within the Retirement Savings Plan.
The
Company’s contributions to the 401(k) plans totaled $1,612,000, $1,681,000 and
$1,497,000 for the years ended December 31, 2006, 2005, and 2004, respectively.
As of December 31, 2006, there are 77,479 shares reserved to fund future
contributions to the Retirement Savings Plan.
L.
Share-Based Compensation Plans
Effective
January 1, 2006, the Company adopted SFAS No. 123R, “Share-Based Payment,” which
establishes accounting for equity instruments exchanged for employee services.
Prior to January 1, 2006, the Company accounted for share-based compensation
to
employees in accordance with Accounting Principles Board Opinion (“APB”) No. 25,
“Accounting for Stock Issued to Employees,” and related interpretations. The
Company also followed the disclosure requirements of SFAS No. 123, “Accounting
for Stock-Based Compensation,” as amended by SFAS No. 148, “Accounting for
Stock-Based Compensation — Transition and Disclosure.” Commencing January 1,
2006, the Company elected to adopt the modified prospective method as provided
by SFAS No. 123R and, accordingly, financial statement amounts for the prior
periods presented have not been retrospectively adjusted to reflect the fair
value of expensing stock-based compensation.
Stock
Options
The
Company did not have any stock options outstanding at December 31, 2006 or
December 31, 2005, nor were any stock options issued during 2006.
Director
Stock Compensation Plan (“DSCP”)
Under
the
Company’s DSCP, each non-employee director receives an annual retainer of 600
shares of common stock and an additional 150 shares of common stock for services
as a committee chairman, subject to adjustment in future years consistent with
the terms of the DSCP. Shares issued under the DSCP are fully vested as of
the
date of the grant. At the date of grant, the Company records a prepaid expense
equal to the fair value of the shares issued and amortizes the expense equally
over the service period of one year. Compensation expense recorded by the
Company relating to the DSCP awards was $165,000 and $140,000 for 2006 and
2005,
respectively.
Notes
to the Consolidated Financial Statements
A
summary
of restricted stock activity for the DSCP as of December 31, 2006 is presented
below:
|
|
Number
of Restricted Shares
|
|
Weighted
Average Grant Date Fair Value
|
|
Outstanding
— December 31, 2005
|
|
-
|
|
|
|
Issued
— May 2, 2006
|
|
|
5,850
|
|
$
|
30.02
|
|
Vested
|
|
|
5,850
|
|
|
|
|
Outstanding
— September 30, 2006
|
|
|
-
|
|
|
|
|
As
of
December 31, 2006, there were 63,300 shares reserved for issuance under the
terms of the Company’s Director’s Stock Compensation Plan.
Performance
Incentive Plans (“PIP”)
The
Company’s Compensation Committee of the Board of Directors is authorized to
grant to key employees of the Company the rights to receive awards of shares
of
the Company’s common stock, contingent upon the achievement of established
performance goals. These goals consist of annual or three-year performance
targets. The awards are made pursuant to the Company’s Performance Incentive
Plan, subject to certain post-vesting transfer restrictions, and are granted
in
the first quarter of each year and are issued based upon the performance
achieved in the previous fiscal year or three-year award period. In the first
quarters of 2006 and 2005, the Company issued 23,666 and 10,130 shares,
respectively, to key employees as PIP stock awards for each of the preceding
fiscal years. Please note that 2005 concluded the three-year performance period
and these awards were issued in the first quarter of 2006 and included in the
23,666 stock awards.
The
Company accrues an expense each month of the fiscal year representing an
estimate of the value of the stock awards granted for the current fiscal year.
This accrual process matches the compensation expense with the employees’
service period rather than recognizing the expense on the issue date, which
occurs in the first quarter of the subsequent year. The shares issued under
the
PIP are fully vested and the fair value of each share is equal to the estimated
market price of the Company’s stock on the date issued. Compensation expense
recorded by the Company in 2006 and 2005 relating to the PIP was $544,000 and
$721,000, respectively.
A
summary
of restricted stock activity for the PIP for 2006 is presented
below:
|
|
Number
of Restricted Shares
|
|
Weighted
Average Grant Date Fair Value
|
|
Outstanding
— December 31, 2005
|
|
-
|
|
|
|
Issued
— February 23, 2006
|
|
|
23,666
|
|
$
|
30.3999
|
|
Vested
|
|
|
23,666
|
|
|
|
|
Outstanding
— September 30, 2006
|
|
|
-
|
|
|
|
|
As
of
December 31, 2006, there were 293,480 shares reserved for issuance under the
terms of the Company’s Performance Incentive Plan.
M.
Environmental Commitments and Contingencies
Chesapeake
is subject to federal, state and local laws and regulations governing
environmental quality and pollution control. These laws and regulations require
the Company to remove or remedy the effect on the environment of the disposal
or
release of specified substances at current and former operating
sites.
In
2004,
Chesapeake received a Certificate of Completion for the remedial work performed
at a former gas manufacturing plant site located in Dover, Delaware. Chesapeake
is also currently participating in the investigation, assessment or remediation
of two additional former gas manufacturing plant sites located in Maryland
and
Florida. The Company has accrued liabilities for the three sites referred to,
respectively, as the Dover Gas Light, Salisbury Town Gas Light and the Winter
Haven Coal Gas sites. The Company has been in discussions with the Maryland
Department of the Environment (“MDE”) regarding a fourth former gas
manufacturing plant site located in Cambridge, Maryland. The following provides
details of each site.
Notes
to the Consolidated Financial Statements
Dover
Gas Light Site
The
Dover
Gas Light site is a former manufactured gas plant site located in Dover,
Delaware. On January 15, 2004, the Company received a Certificate of Completion
of Work from the United States Environmental Protection Agency (“EPA”) regarding
this site. This concluded Chesapeake’s remedial action obligation related to
this site and relieves Chesapeake from liability for future remediation at
the
site, unless previously unknown conditions are discovered at the site, or
information previously unknown to the EPA is received that indicates the
remedial action that has been taken is not sufficiently protective. These
contingencies are standard and are required by the United States in all
liability settlements.
The
Company has reviewed its remediation costs incurred to date for the Dover Gas
Light site and has concluded that all costs incurred have been paid. The Company
does not expect any future environmental expenditure for this site. Through
December 31, 2006, the Company has incurred approximately $9.67 million in
costs
related to environmental testing and remedial action studies at the site.
Approximately $9.96 million has been recovered through December 2006 from other
parties or through rates. As of December 31, 2006, a regulatory liability of
approximately $294,500, representing the over-recovery portion of the clean-up
costs, has been recorded. The over-recovery is temporary and will be refunded
by
the Company to customers in future rates.
Salisbury
Town Gas Light Site
In
cooperation with the MDE, the Company has completed remediation of the Salisbury
Town Gas Light site, located in Salisbury, Maryland, where it was determined
that a former manufactured gas plant had caused localized ground-water
contamination. During 1996, the Company completed construction and began Air
Sparging and Soil-Vapor Extraction (“AS/SVE”) remediation procedures. Chesapeake
has been reporting the remediation and monitoring results to the MDE on an
ongoing basis since 1996. In February 2002, the MDE granted permission to
permanently decommission the AS/SVE system and to discontinue all on-site and
off-site well monitoring, except for one well that is being maintained for
continued product monitoring and recovery. In November 2002, Chesapeake
submitted a letter to the MDE requesting a No Further Action determination.
The
Company has been in discussions with the MDE regarding such request and is
awaiting a determination from the MDE.
Through
December 31, 2006, the Company has incurred approximately $2.9 million for
remedial actions and environmental studies at the Salisbury Town Gas Light
site.
Of this amount, approximately $1.8 million has been recovered through insurance
proceeds or in rates. On
September 26, 2006, the Company received approval from the Maryland Public
Service Commission to recover through its rates charged to customers the
remaining $1.1 million of the incurred environmental remediation costs.
Winter
Haven Coal Gas Site
The
Winter Haven Coal Gas site is located in Winter Haven, Florida. Chesapeake
has
been working with the Florida Department of Environmental Protection (“FDEP”) in
assessing this coal gas site. In May 1996, the Company filed an AS/SVE Pilot
Study Work Plan (the “Work Plan”) for the Winter Haven site with the FDEP. The
Work Plan described the Company’s proposal to undertake an AS/SVE pilot study to
evaluate the site. After discussions with the FDEP, the Company filed a modified
Work Plan, the description of the scope of work to complete the site assessment
activities and a report describing a limited sediment investigation performed
in
1997. In December 1998, the FDEP approved the modified Work Plan, which the
Company completed during the third quarter of 1999. In February 2001, the
Company filed a Remedial Action Plan (“RAP”) with the FDEP to address the
contamination of the subsurface soil and ground-water in a portion of the site.
The FDEP approved the RAP on May 4, 2001. Construction of the AS/SVE system
was
completed in the fourth quarter of 2002 and the system remains fully
operational.
Notes
to the Consolidated Financial Statements
The
Company has accrued a liability of $212,000 as of December 31, 2006 for the
Winter Haven Coal Gas site. Through December 31, 2006, the Company has incurred
approximately $1.7 million of environmental costs associated with this site.
At
December 31, 2006, the Company had collected $90,000 through rates in excess
of
costs incurred. A regulatory asset of approximately $122,000, representing
the
uncollected portion of the estimated clean-up costs, has also been recorded.
The
Company expects to recover the remaining costs through rates.
The
FDEP
has indicated that the Company may be required to remediate sediments along
the
shoreline of Lake Shipp, immediately west of the Winter Haven site. Based on
studies performed to date, the Company objects to the FDEP’s suggestion that the
sediments have been contaminated and will require remediation. The Company’s
early estimates indicate that some of the corrective measures discussed by
the
FDEP may cost as much as $1 million. Given the Company’s view as to the absence
of ecological effects, the Company believes that cost expenditures of this
magnitude are unwarranted and plans to oppose any requirements that it undertake
corrective measures in the offshore sediments. Chesapeake anticipates that
it
will be several years before this issue is resolved. At this time, the Company
has not recorded a liability for sediment remediation. The outcome of this
matter cannot be predicted at this time.
Other
The
Company is in discussions with the MDE regarding a gas manufacturing plant
site
located in Cambridge, Maryland. The outcome of this matter cannot be determined
at this time; therefore, the Company has not recorded an environmental liability
for this location.
Natural
Gas and Propane Supply
The
Company’s natural gas and propane distribution operations have entered into
contractual commitments for gas from various suppliers. The contracts have
various expiration dates. In November 2004, the Company renewed its contract
with an energy marketing and risk management company to manage a portion of
the
Company’s natural gas transportation and storage capacity. The contract expires
March 31, 2007.
Corporate
Guarantees
The
Company has issued corporate guarantees to certain vendors of its propane
wholesale marketing subsidiary, its Florida natural gas supply and management
subsidiary, and Delmarva propane distribution subsidiary. These corporate
guarantees provide for the payment of propane and natural gas purchases in
the
event of the subsidiaries’ default. The liabilities for these purchases are
recorded in the Consolidated Financial Statements. The aggregate amount
guaranteed at December 31, 2006 totaled $21.4 million, with the guarantees
expiring on various dates in 2007.
In
addition to the corporate guarantees, the Company has issued a letter of credit
to its primary insurance company for $775,000, which expires on May 31, 2007.
The letter of credit is provided as security for claims amounts to satisfy
the
deductibles on the Company’s policies. The current letter of credit was renewed
during the second quarter of 2006 when the insurance policies were renewed.
Other
The
Company is involved in certain legal actions and claims arising in the normal
course of business. The Company is also involved in certain legal and
administrative proceedings before various governmental agencies concerning
rates. In the opinion of management, the ultimate disposition of these
proceedings will not have a material effect on the consolidated financial
position, results of operations or cash flows of the Company.
Notes
to the Consolidated Financial Statements
O.
Quarterly Financial Data
(Unaudited)
In
the
opinion of the Company, the quarterly financial information shown below includes
all adjustments necessary for a fair presentation of the operations for such
periods. Due to the seasonal nature of the Company’s business, there are
substantial variations in operations reported on a quarterly basis.
For
the Quarters Ended
|
|
March
31
|
|
June
30
|
|
September
30
|
|
December
31
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
Operating
Revenue
|
|
$
|
90,950,672
|
|
$
|
44,303,752
|
|
$
|
35,141,531
|
|
$
|
60,804,636
|
|
Operating
Income
|
|
$
|
11,437,228
|
|
$
|
3,205,368
|
|
$
|
162,137
|
|
$
|
8,126,578
|
|
Net
Income (Loss)
|
|
$
|
6,096,416
|
|
$
|
1,132,509
|
|
|
($656,579
|
)
|
$
|
3,934,179
|
|
Earnings
per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.03
|
|
$
|
0.19
|
|
|
($0.11
|
)
|
$
|
0.63
|
|
Diluted
|
|
$
|
1.01
|
|
$
|
0.19
|
|
|
($0.11
|
)
|
$
|
0.62
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Revenue
|
|
$
|
77,845,248
|
|
$
|
42,220,377
|
|
$
|
35,155,121
|
|
$
|
74,408,990
|
|
Operating
Income (Loss)
|
|
$
|
11,504,343
|
|
$
|
2,324,945
|
|
|
($99,149
|
)
|
$
|
7,800,360
|
|
Net
Income (Loss)
|
|
$
|
6,232,796
|
|
$
|
795,924
|
|
|
($693,774
|
)
|
$
|
4,132,668
|
|
Earnings
per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.08
|
|
$
|
0.14
|
|
|
($0.12
|
)
|
$
|
0.70
|
|
Diluted
|
|
$
|
1.05
|
|
$
|
0.14
|
|
|
($0.12
|
)
|
$
|
0.69
|
|
Item
9. Changes In and Disagreements With Accountants on Accounting and Financial
Disclosure.
None
Item
9A. Controls and Procedures.
Evaluation
of Disclosure Controls and Procedures
The
Chief
Executive Officer and Chief Financial Officer of the Company, with the
participation of other Company officials, have evaluated the Company’s
“disclosure controls and procedures” (as such term is defined under Rule
13a-15(e) and 15d - 15(e) promulgated under the Securities Exchange Act of
1934,
as amended) as of December 31, 2006. Based upon their evaluation, the Chief
Executive Officer and Chief Financial Officer concluded that the Company’s
disclosure controls and procedures were effective as of December 31,
2006.
Changes
in Internal Controls
During
the quarter ended December 31, 2006, there was no change in the Company’s
internal control over financial reporting that has materially affected, or
is
reasonably likely to materially affect, the Company’s internal control over
financial reporting.
Management’s
Report on Internal Control Over Financial Reporting
See
Management’s Report on Internal Control Over Financial Reporting in Item 8,
“Financial Statements and Supplemental Data.”
CEO
and CFO Certifications
The
Company’s Chief Executive Officer as well as the Senior Vice President and Chief
Financial Officer have filed with the Securities and Exchange Commission the
certifications required by Section 302 of the Sarbanes-Oxley Act of 2002 as
Exhibits 31.1 and 31.2 to the Company’s Annual Report on Form 10-K for the
fiscal year ended December 31, 2006. In addition, on May 26, 2006 the
Company’s CEO certified to the New York Stock Exchange that he was not aware of
any violation
by the Company of the NYSE corporate governance listing standards.
Item
9B. Other Information.
The
Company filed a Current Report on Form 8-K, dated November 29, 2006, discussing
the Compensation Committee’s (the “Committee”) actions on that date, including
their approval of the compensation arrangements relating to the executive
officers of the Company for 2007.
On
November 29, 2006, the Committee approved awards under the Company’s Performance
Incentive Plan to John R. Schimkaitis, President and Chief Executive Officer
and
Michael P. McMasters, Senior Vice President and Chief Financial Officer.
According to the terms of the awards, each executive officer is entitled to
earn
up to a specified number of shares of the Company’s common stock (“Contingent
Performance Shares”) depending on the extent to which pre-established
performance goals (the “Performance Goals”) are achieved during the year ended
December 31, 2007 (the “2007 Award Year”).
On
November 29, 2006, the Compensation Committee also approved awards under the
Company’s Performance Incentive Plan to (i) Stephen C. Thompson, Senior Vice
President, and (ii) S. Robert Zola, President of Sharp Energy, Inc., a Company
subsidiary, for the three-year period ending December 31, 2008. For a
performance period beginning January 1, 2007 and ending December 31, 2007,
each
executive officer is entitled to earn, in the form of shares of restricted
stock, up to 30 percent of the annual award of Contingent Performance Shares
if
the Company achieves certain Performance Goals. The second component consists
of
performance awards pursuant to which the remaining 70 percent of the annual
award of Contingent Performance Shares will be earned, if certain Performance
Goals for the three-year period ending December 31, 2008 for each of the
respective business units for which they are individually responsible, are
achieved.
Part
III
Item
10. Directors, Executive Officers of the Registrant and Corporate
Governance.
The
information required by this Item is incorporated herein by reference to the
portions of the Proxy Statement, captioned “Proposal I - Election of Directors,”
“Information Regarding the Board of Directors and Nominees,” “Corporate
Governance Practices and Stockholder Communications - Nomination of Directors,”
“Committees of the Board - Audit Committee” and “Section 16(a) Beneficial
Ownership Reporting Compliance” to be filed not later than March 31, 2007 in
connection with the Company’s Annual Meeting to be held on May 2,
2007.
The
information required by this Item with respect to executive officers is,
pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, set
forth in Part I of this Form 10-K under “Executive Officers of the
Registrant.”
The
Company has adopted a Code of Ethics for Financial Officers, which applies
to
its principal executive officer, principal financial officer, principal
accounting officer or controller, or persons performing similar functions.
The
information set forth under Item 1 hereof concerning the Code of Ethics for
Financial Officers is incorporated herein by reference.
Item
11. Executive Compensation.
The
information required by this Item is incorporated herein by reference to the
portion of the Proxy Statement captioned “Director Compensation,” “Executive
Compensation” and “Compensation Discussion and Analysis” in the Proxy Statement
to be filed not later than March 31, 2007, in connection with the Company’s
Annual Meeting to be held on May 2, 2007.
Item
12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters.
The
information required by this Item is incorporated herein by reference to the
portion of the Proxy Statement captioned “Beneficial Ownership of Chesapeake’s
Securities” to be filed not later than March 31, 2007 in connection with the
Company’s Annual Meeting to be held on May 2, 2007.
The
following table sets forth information as of December 31, 2006, with respect
to
compensation plans of Chesapeake and its subsidiaries under which shares of
Chesapeake common stock are authorized for issuance:
|
|
(a)
|
|
(b)
|
|
(c)
|
|
|
Number
of securities to be issued upon exercise of outstanding options,
warrants
and rights
|
|
Weighted
average exercise price of outstanding options, warrants and
rights
|
|
Number
of securities remaining available for future issuance under equity
compensation plans (excluding securities reflected in column
(a))
|
Equity
compensation plans approved by security holders
|
|
|
0
|
(1)
|
|
|
|
|
381,431
|
(2) |
|
Equity
compensation plans not approved by security holders
|
|
|
0
|
(3) |
|
|
N/A
|
|
0
|
|
|
Total
|
|
|
0
|
|
|
|
|
|
381,481
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
All options to purchase shares under the 1992 Performance Incentive
Plan,
as amended, were exercised as of 12/31/05.
|
|
(2)
Includes 293,481 shares under the 2005 Performance Incentive
Plan, 63,300
shares available under the 2005 Directors Stock Compensation
Plan, and
24,650 shares available under the 2005 Employee Stock Awards
Plan.
|
|
(3)
All warrants were exercised in 2006.
|
|
Item
13. Certain Relationships and Related Transactions, and Director
Independence.
Item
14. Principal Accounting Fees and Services.
The
information required by this Item is incorporated herein by reference to the
portion of the Proxy Statement captioned “Fees and Services of
PricewaterhouseCoopers LLP” to be filed not later than March 31, 2007, in
connection with the Company’s Annual Meeting to be held on May 2, 2007.
Part
IV
Item
15. Exhibits, Financial Statement Schedules.
(a) The
following documents are filed as part of this report:
1. Financial
Statements:
· |
Report
of Independent Registered Public Accounting
Firm
|
· |
Consolidated
Statements of Income for each of the three years ended December 31,
2006,
2005 and 2004
|
· |
Consolidated
Balance Sheets at December 31, 2006 and December 31,
2005
|
· |
Consolidated
Statements of Cash Flows for each of the three years ended December
31,
2006, 2005 and 2004
|
· |
Consolidated
Statements of Common Stockholders’ Equity for each of the three years
ended December 31, 2006, 2005 and 2004
|
· |
Consolidated
Statements of Comprehensive Income for each of the three years ended
December 31, 2006, 2005 and 2004
|
· |
Consolidated
Statements of Income Taxes for each of the three years ended December
31,
2006, 2005 and 2004
|
· |
Notes
to Consolidated Financial Statements
|
2. Financial
Statement Schedule — Schedule II - Valuation and Qualifying
Accounts
All
other
schedules are omitted because they are not required, are inapplicable or
the
information is otherwise shown in the financial statements or notes
thereto.
3. Exhibits
·
Exhibit
1 |
Underwriting
Agreement entered into by Chesapeake Utilities Corporation and Robert
W.
Baird & Co. Incorporated and A.G. Edwards & Sons, Inc., on
November 15, 2007, relating to the sale and issuance of 600,300 shares
of
the Company’s common stock, is incorporated herein by reference to Exhibit
1.1 of the Company’s Current Report on Form 8-K, filed November 16, 2007,
File No. 001-11590.
|
· Exhibit
3.1
|
Amended
Certificate of Incorporation of Chesapeake Utilities Corporation
is
incorporated herein by reference to Exhibit 3.1 of the Company’s Quarterly
Report on Form 10-Q for the period ended June 30, 1998, File No.
001-11590.
|
· Exhibit
3.2
|
Amended
Bylaws of Chesapeake Utilities Corporation, effective February 24,
2005,
is incorporated herein by reference to Exhibit 3 of the Company’s Annual
Report on Form 10-K for the year ended December 31, 2004, File No.
001-11590.
|
· Exhibit
4.1
|
Form
of Indenture between the Company and Boatmen’s Trust Company, Trustee,
with respect to the 8 1/4% Convertible Debentures is incorporated
herein
by reference to Exhibit 4.2 of the Company’s Registration Statement on
Form S-2, Reg. No. 33-26582, filed on January 13,
1989.
|
· Exhibit
4.2
|
Note
Agreement dated February 9, 1993, by and between the Company and
Massachusetts Mutual Life Insurance Company and MML Pension Insurance
Company, with respect to $10 million of 7.97% Unsecured Senior Notes
due
February 1, 2008, is incorporated herein by reference to Exhibit
4 to the
Company’s Annual Report on Form 10-K for the year ended December 31, 1992,
File No. 0-593.
|
· Exhibit
4.3
|
Note
Purchase Agreement entered into by the Company on October 2, 1995,
pursuant to which the Company privately placed $10 million of its
6.91%
Senior Notes due in 2010, is not being filed herewith, in accordance
with
Item 601(b)(4)(iii) of Regulation S-K. The Company hereby agrees
to
furnish a copy of that agreement to the SEC upon
request.
|
· Exhibit
4.4
|
Note
Purchase Agreement entered into by the Company on December 15, 1997,
pursuant to which the Company privately placed $10 million of its
6.85%
Senior Notes due 2012, is not being filed herewith, in accordance
with
Item 601(b)(4)(iii) of Regulation S-K. The Company hereby agrees
to
furnish a copy of that agreement to the SEC upon
request.
|
· Exhibit
4.5
|
Note
Purchase Agreement entered into by the Company on December 27, 2000,
pursuant to which the Company privately placed $20 million of its
7.83%
Senior Notes due 2015, is not being filed herewith, in accordance
with
Item 601(b)(4)(iii) of Regulation S-K. The Company hereby agrees
to
furnish a copy of that agreement to the SEC upon
request.
|
· Exhibit
4.6
|
Note
Agreement entered into by the Company on October 31, 2002, pursuant
to
which the Company privately placed $30 million of its 6.64% Senior
Notes
due 2017, is incorporated herein by reference to Exhibit 2 of the
Company’s Current Report on Form 8-K, filed November 6, 2002, File No.
001-11590.
|
· Exhibit
4.7
|
Note
Agreement entered into by the Company on October 18, 2005, pursuant
to
which the Company, on October 12, 2006, privately placed $20 million
of
its 5.5% Senior Notes, due 2020, with Prudential Investment Management,
Inc., is incorporated herein by reference to Exhibit 4.1 of the Company’s
Annual Report on Form 10-K for the year ended December 31, 2005,
File No.
001-11590.
|
· Exhibit
4.8
|
Form
of Senior Debt Trust Indenture between Chesapeake Utilities Corporation
and the trustee for the debt securities is incorporated herein by
reference to Exhibit 4.3.1 of the Company’s Registration Statement on Form
S-3A, Reg. No. 333-135602, dated November 6,
2006.
|
· Exhibit
4.9
|
Form
of Subordinated Debt Trust Indenture between Chesapeake Utilities
Corporation and the trustee for the debt securities is incorporated
herein
by reference to Exhibit 4.3.2 of the Company’s Registration Statement on
Form S-3A, Reg. No. 333-135602, dated November 6,
2006.
|
· Exhibit
4.10
|
Form
of debt securities is incorporated herein by reference to Exhibit
4.4 of
the Company’s Registration Statement on Form S-3A, Reg. No. 333-135602,
dated November 6, 2006.
|
· Exhibit
5.1
|
Opinion
of Baker & Hostetler LLP is incorporated herein by reference to
Exhibit 5.1 of the Company’s Registration Statement on Form S-3, Reg. No.
333-135602, dated July 5, 2006.
|
· Exhibit
5.2
|
Opinion
of Baker & Hostetler LLP is incorporated herein by reference to
Exhibit 5.1 of the Company’s Registration Statement on Form S-3A, Reg. No.
333-135602, dated November 6, 2006.
|
· Exhibit
10.1*
|
Non-Employee
Director Compensation Arrangements, incorporated herein by reference
to
Exhibit 10.5 of the Company’s Annual Report on Form 10-K for the year
ended December 31, 2004, File No.
001-11590.
|
· Exhibit
10.2*
|
Chesapeake
Utilities Corporation Cash Bonus Incentive Plan dated January 1,
2005, is
incorporated herein by reference to Exhibit 10.3 of the Company’s Annual
Report on Form 10-K for the year ended December 31, 2004, File No.
001-11590.
|
· Exhibit
10.3*
|
Chesapeake
Utilities Corporation Directors Stock Compensation Plan, adopted
in 2005,
is incorporated herein by reference to the Company’s Proxy Statement dated
March 28, 2005 in connection with the Company’s Annual Meeting held on May
5, 2005, File No. 001-11590.
|
· Exhibit
10.4*
|
Chesapeake
Utilities Corporation Employee Stock Award Plan, adopted in 2005,
is
incorporated herein by reference to the Company’s Proxy Statement dated
March 28, 2005 in connection with the Company’s Annual Meeting held on May
5, 2005, File No. 001-11590.
|
· Exhibit
10.5*
|
Chesapeake
Utilities Corporation Performance Incentive Plan, adopted in 2005,
is
incorporated herein by reference to the Company’s Proxy Statement dated
March 28, 2005 in connection with the Company’s Annual Meeting held on May
5, 2005, File No. 001-11590.
|
· Exhibit
10.6*
|
Deferred
Compensation Program (as amended and restated as of December 7, 2006)
is
incorporated herein by reference to Exhibit 10 of the Company’s Current
Report on Form 8-K, filed December 13, 2006, File No.
001-11590.
|
· Exhibit
10.7*
|
Executive
Employment Agreement dated December 29, 2006, by and between Chesapeake
Utilities Corporation and S. Robert Zola, is filed
herewith.
|
· Exhibit
10.8*
|
Executive
Employment Agreement dated December 29, 2006, by and between Chesapeake
Utilities Corporation and Stephen C. Thompson, is filed
herewith.
|
· Exhibit
10.9*
|
Executive
Employment Agreement dated December 29, 2006, by and between Chesapeake
Utilities Corporation and Beth W. Cooper, is filed
herewith.
|
· Exhibit
10.10* |
Executive
Employment Agreement dated December 29, 2006, by and between Chesapeake
Utilities Corporation and Michael P. McMasters, is filed
herewith.
|
· Exhibit
10.11* |
Executive
Employment Agreement dated December 29, 2006, by and between Chesapeake
Utilities Corporation and John R. Schimkaitis, is filed
herewith.
|
· Exhibit
10.12* |
Performance
Share Agreement dated December 15, 2006, pursuant to Chesapeake Utilities
Corporation Performance Incentive Plan by and between Chesapeake
Utilities
Corporation and S. Robert Zola, is filed
herewith.
|
· Exhibit
10.13* |
Performance
Share Agreement dated December 23, 2006, pursuant to Chesapeake Utilities
Corporation Performance Incentive Plan by and between Chesapeake
Utilities
Corporation and Stephen C. Thompson, is filed
herewith.
|
· Exhibit
10.14* |
Performance
Share Agreement dated December 27, 2006, pursuant to Chesapeake Utilities
Corporation Performance Incentive Plan by and between Chesapeake
Utilities
Corporation and Beth W. Cooper, is filed
herewith.
|
· Exhibit
10.15* |
Performance
Share Agreement dated December 29, 2006, pursuant to Chesapeake Utilities
Corporation Performance Incentive Plan by and between Chesapeake
Utilities
Corporation and Michael P. McMasters, is filed
herewith.
|
· Exhibit
10.16* |
Performance
Share Agreement dated December 29, 2006, pursuant to Chesapeake Utilities
Corporation Performance Incentive Plan by and between Chesapeake
Utilities
Corporation and John R. Schimkaitis, is filed
herewith.
|
· Exhibit
12
|
Computation
of Ratio of Earning to Fixed Charges, filed
herewith.
|
· Exhibit
14
|
Code
of Ethics for Financial Officers, filed
herewith.
|
· Exhibit
21
|
Subsidiaries
of the Registrant, filed herewith.
|
· Exhibit
23.1
|
Consent
of Independent Registered Public Accounting Firm is incorporated
herein by
reference to Exhibit 23.1 to the Company’s Registration Statement on Form
S-3, Reg. No. 333-135602, dated July 5,
2006.
|
· Exhibit
23.2
|
Consent
of Independent Registered Public Accounting Firm is incorporated
herein by
reference to Exhibit 23.1 to the Company’s Registration Statement on Form
S-3A, Reg. No. 333-135602, dated November 6,
2006.
|
· Exhibit
23.3
|
Consent
of Baker & Hostetler LLP (included in Exhibit
5.1).
|
· Exhibit
23.4
|
Consent
of Baker & Hostetler LLP (included in Exhibit
5.2).
|
· Exhibit
23.5
|
Consent
of Independent Registered Public Accounting Firm, filed
herewith.
|
· Exhibit
24
|
Power
of Attorney is incorporated herein by reference to Exhibit 24.1 of
the
Company’s Registration Statement on Form S-3, Reg. No. 333-135602, dated
July 5, 2006.
|
· Exhibit
31.1
|
Certificate
of Chief Executive Office of Chesapeake Utilities Corporation pursuant
to
Exchange Act Rule 13a-14(a), dated March 13, 2007, filed
herewith.
|
· Exhibit
31.2
|
Certificate
of Chief Financial Officer of Chesapeake Utilities Corporation pursuant
to
Exchange Act Rule 13a-14(a), dated March 13, 2007, filed
herewith.
|
· Exhibit
32.1
|
Certificate
of Chief Executive Office of Chesapeake Utilities Corporation pursuant
to
18 U.S.C. Section 1350, dated March 13, 2007, filed
herewith.
|
· Exhibit
32.2
|
Certificate
of Chief Financial Officer of Chesapeake Utilities Corporation pursuant
to
18 U.S.C. Section 1350, dated March 13, 2007, filed
herewith.
|
*
Management contract or compensatory plan or agreement.
Signatures
Pursuant
to the requirements of Section 13 or 15 (d) of the Securities Exchange Act
of
1934, Chesapeake Utilities Corporation has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
Chesapeake
Utilities Corporation
By: /s/
John R. Schimkaitis
John
R.
Schimkaitis
President
and Chief Executive Officer
Date: March
13, 2007
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has
been
signed below by the following persons on behalf of the registrant and in the
capacities and on the dates indicated.
/s/
Ralph J. Adkins
|
/s/
John R. Schimkaitis
|
Ralph
J. Adkins, Chairman of the Board
|
John
R. Schimkaitis, President,
|
and
Director
|
Chief
Executive Officer and Director
|
Date:
February 21, 2007
|
Date:
March 13, 2007
|
|
|
/s/
Michael P. McMasters
|
/s/
Richard Bernstein
|
Michael
P. McMasters, Senior Vice President
|
Richard
Bernstein, Director
|
and
Chief Financial Officer
|
Date:
February 21, 2007
|
(Principal
Financial and Accounting Officer)
|
|
Date:
March 13, 2007
|
|
|
|
/s/
Eugene H. Bayard
|
/s/
Thomas J. Bresnan
|
Eugene
H. Bayard, Director
|
Thomas
J. Bresnan, Director
|
Date:
February 21, 2007
|
Date:
March 13, 2007
|
|
|
/s/
Thomas P. Hill
|
/s/
Walter J. Coleman
|
Thomas
P. Hill, Director
|
Walter
J. Coleman, Director
|
Date:
February 21, 2007
|
Date:
February 21, 2007
|
|
|
/s/
J. Peter Martin
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/s/
Joseph E. Moore, Esq.
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J.
Peter Martin, Director
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Joseph
E. Moore, Esq., Director
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Date:
February 21, 2007
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Date:
February 21, 2007
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/s/
Calvert A. Morgan, Jr.,
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Calvert
A. Morgan, Jr., Director
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Date:
February 21, 2007
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Chesapeake
Utilities Corporation and Subsidiaries
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Schedule
II
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Valuation
and Qualifying Accounts
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Additions
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For
the Year Ended December 31,
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Balance
at Beginning of Year
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Charged
to Income
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Other
Accounts (1)
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Deductions (2)
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Balance
at End of Year
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Reserve
Deducted From Related Assets
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Reserve
for Uncollectible Accounts
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2006
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$
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861,378
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$
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381,424
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$
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65,519
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($646,724
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)
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$
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661,597
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2005
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$
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610,819
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$
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632,644
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$
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158,409
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($540,494
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)
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$
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861,378
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2004
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$
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682,002
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$
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505,595
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$
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103,020
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($679,798
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)
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$
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610,819
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(1)
Recoveries.
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(2)
Uncollectible accounts charged off.
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Upon
written request, Chesapeake will provide, free of charge,
a copy of any Exhibit to the 2006 Annual Report on Form 10-K not included in
this document.