Chesapeake
Utilities Corporation and Subsidiaries
|
|
|
|
|
|
|
|
|
Condensed
Consolidated Statements of Stockholders' Equity
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Six
Months
Ended
June
30, 2008
|
For
the Twelve
Months
Ended
December
31, 2007
|
|
|
|
|
|
|
|
Common
Stock
|
|
|
|
Balance
— beginning of period
|
$3,298,473
|
$3,254,998
|
|
|
Dividend
Reinvestment Plan
|
3,541
|
17,197
|
|
|
Retirement
Savings Plan
|
1,073
|
14,388
|
|
|
Conversion
of debentures
|
1,573
|
3,945
|
|
|
Stock-based Compensation
|
11,965
|
7,945
|
|
Balance
— end of period
|
$3,316,625
|
$3,298,473
|
|
|
|
|
|
|
|
Additional
Paid-in Capital
|
|
|
|
Balance
— beginning of period
|
$65,591,552
|
$61,960,220
|
|
|
Dividend
Reinvestment Plan
|
219,034
|
1,121,190
|
|
|
Retirement
Savings Plan
|
66,704
|
934,295
|
|
|
Conversion
of debentures
|
53,355
|
133,839
|
|
|
Stock-based
compensation
|
179,624
|
1,442,008
|
|
|
Tax
benefit of warrants
|
50,244
|
-
|
|
Balance
— end of period
|
$66,160,513
|
$65,591,552
|
|
|
|
|
|
|
|
Retained
Earnings
|
|
|
|
Balance
— beginning of period
|
$51,538,194
|
$46,270,884
|
|
|
Net
income
|
9,393,266
|
13,197,710
|
|
|
Cash
dividends declared
|
(4,086,399)
|
(7,930,400)
|
|
Balance
— end of period
|
$56,845,061
|
$51,538,194
|
|
|
|
|
|
|
|
Accumulated
Other Comprehensive Loss
|
|
|
Balance
— beginning of period
|
($851,674)
|
($334,550)
|
|
|
Loss
on funded status of Employee Benefit Plans, net of tax
|
-
|
(517,124)
|
|
Balance
— end of period
|
($851,674)
|
($851,674)
|
|
|
|
|
|
|
|
Deferred
Compensation Obligation
|
|
|
|
Balance
— beginning of period
|
$1,403,922
|
$1,118,509
|
|
|
New
deferrals
|
107,228
|
285,413
|
|
Balance
— end of period
|
$1,511,150
|
$1,403,922
|
|
|
|
|
|
|
|
Treasury
Stock
|
|
|
|
Balance
— beginning of period
|
($1,403,922)
|
($1,118,509)
|
|
|
New
deferrals related to compensation obligation
|
(107,228)
|
(285,413)
|
|
|
Purchase
of treasury stock (1)
|
(34,328)
|
(29,771)
|
|
|
Sale
and distribution of treasury stock (2)
|
34,328
|
29,771
|
|
Balance
— end of period
|
($1,511,150)
|
($1,403,922)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Stockholders’ Equity
|
$125,470,525
|
$119,576,545
|
|
|
|
|
|
|
|
(1)
|
Amount
includes shares purchased in the open market for the Company's Rabbi Trust
to secure its
|
|
obligations
under the Company's Deferred Compensation Plan.
|
(2)
|
Amount
includes shares issued to the Company's Rabbi Trust as an obligation under
the Deferred
|
|
Compensation
Plan.
|
|
|
The
accompanying notes are an integral part of these financial
statements.
Chesapeake
Utilities Corporation and Subsidiaries
|
|
|
|
|
|
|
|
|
Condensed
Consolidated Balance Sheets (Unaudited)
|
|
|
|
|
|
|
|
|
Assets
|
|
June
30,
2008
|
|
|
December
31, 2007
|
|
|
|
|
|
|
|
|
Property,
Plant and Equipment
|
|
|
|
|
Natural
gas
|
|
$ |
296,681,205 |
|
|
$ |
289,706,066 |
|
Propane
|
|
|
49,647,049 |
|
|
|
48,506,231 |
|
Advanced
information services
|
|
|
1,234,107 |
|
|
|
1,157,808 |
|
Other
plant
|
|
|
10,486,075 |
|
|
|
8,567,833 |
|
Total
property, plant and equipment
|
|
|
358,048,436 |
|
|
|
347,937,938 |
|
Less: Accumulated
depreciation and amortization
|
|
|
(96,835,370 |
) |
|
|
(92,414,289 |
) |
Plus: Construction
work in progress
|
|
|
9,749,213 |
|
|
|
4,899,608 |
|
Net
property, plant and equipment
|
|
|
270,962,279 |
|
|
|
260,423,257 |
|
|
|
|
|
|
|
|
|
|
Investments
|
|
|
1,911,100 |
|
|
|
1,909,271 |
|
|
|
|
|
|
|
|
|
|
Current
Assets
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
|
3,183,671 |
|
|
|
2,592,801 |
|
Accounts
receivable (less allowance for uncollectible
|
|
accounts
of $944,898 and $952,075, respectively)
|
|
|
86,639,996 |
|
|
|
72,218,191 |
|
Accrued
revenue
|
|
|
2,476,445 |
|
|
|
5,265,474 |
|
Propane
inventory, at average cost
|
|
|
8,143,492 |
|
|
|
7,629,295 |
|
Other
inventory, at average cost
|
|
|
1,131,474 |
|
|
|
1,280,506 |
|
Regulatory
assets
|
|
|
1,018,750 |
|
|
|
1,575,072 |
|
Storage
gas prepayments
|
|
|
5,906,504 |
|
|
|
6,042,169 |
|
Income
taxes receivable
|
|
|
150,836 |
|
|
|
1,237,438 |
|
Deferred
income taxes
|
|
|
1,920,098 |
|
|
|
2,155,393 |
|
Prepaid
expenses
|
|
|
1,917,178 |
|
|
|
3,496,517 |
|
Mark-to-market
energy assets
|
|
|
7,014,698 |
|
|
|
7,812,456 |
|
Other
current assets
|
|
|
146,603 |
|
|
|
146,253 |
|
Total
current assets
|
|
|
119,649,745 |
|
|
|
111,451,565 |
|
|
|
|
|
|
|
|
|
|
Deferred
Charges and Other Assets
|
|
|
|
|
|
Goodwill
|
|
|
674,451 |
|
|
|
674,451 |
|
Other
intangible assets, net
|
|
|
171,171 |
|
|
|
178,073 |
|
Long-term
receivables
|
|
|
617,934 |
|
|
|
740,680 |
|
Regulatory
assets
|
|
|
2,778,159 |
|
|
|
2,539,235 |
|
Other
deferred charges
|
|
|
4,146,654 |
|
|
|
3,640,480 |
|
Total
deferred charges and other assets
|
|
|
8,388,369 |
|
|
|
7,772,919 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$ |
400,911,493 |
|
|
$ |
381,557,012 |
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these financial
statements.
Capitalization
and Liabilities
|
|
June
30,
2008
|
|
|
December
31, 2007
|
|
|
|
|
|
|
|
|
Capitalization
|
|
|
|
|
|
|
Stockholders'
equity
|
|
|
|
|
|
|
Common
Stock, par value $0.4867 per share
|
|
(authorized
12,000,000 shares)
|
|
$ |
3,316,625 |
|
|
$ |
3,298,473 |
|
Additional
paid-in capital
|
|
|
66,160,513 |
|
|
|
65,591,552 |
|
Retained
earnings
|
|
|
56,845,061 |
|
|
|
51,538,194 |
|
Accumulated
other comprehensive loss
|
|
|
(851,674 |
) |
|
|
(851,674 |
) |
Deferred
compensation obligation
|
|
|
1,511,150 |
|
|
|
1,403,922 |
|
Treasury
stock
|
|
|
(1,511,150 |
) |
|
|
(1,403,922 |
) |
Total
stockholders' equity
|
|
|
125,470,525 |
|
|
|
119,576,545 |
|
|
|
|
|
|
|
|
|
|
Long-term
debt, net of current maturities
|
|
|
63,180,636 |
|
|
|
63,255,636 |
|
Total
capitalization
|
|
|
188,651,161 |
|
|
|
182,832,181 |
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
|
|
|
|
|
|
Current
portion of long-term debt
|
|
|
6,656,364 |
|
|
|
7,656,364 |
|
Short-term
borrowing
|
|
|
57,055,153 |
|
|
|
45,663,944 |
|
Accounts
payable
|
|
|
58,826,720 |
|
|
|
54,893,071 |
|
Customer
deposits and refunds
|
|
|
9,033,699 |
|
|
|
10,036,920 |
|
Accrued
interest
|
|
|
1,581,687 |
|
|
|
865,504 |
|
Dividends
payable
|
|
|
2,078,518 |
|
|
|
1,999,343 |
|
Accrued
compensation
|
|
|
2,358,031 |
|
|
|
3,400,112 |
|
Regulatory
liabilities
|
|
|
5,929,229 |
|
|
|
6,300,766 |
|
Mark-to-market
energy liabilities
|
|
|
6,477,672 |
|
|
|
7,739,261 |
|
Other
accrued liabilities
|
|
|
2,706,335 |
|
|
|
2,500,542 |
|
Total
current liabilities
|
|
|
152,703,408 |
|
|
|
141,055,827 |
|
|
|
|
|
|
|
|
|
|
Deferred
Credits and Other Liabilities
|
|
|
|
|
|
Deferred
income taxes
|
|
|
30,723,340 |
|
|
|
28,795,885 |
|
Deferred
investment tax credits
|
|
|
256,560 |
|
|
|
277,698 |
|
Regulatory
liabilities
|
|
|
973,185 |
|
|
|
1,136,071 |
|
Environmental
liabilities
|
|
|
750,596 |
|
|
|
835,143 |
|
Other
pension and benefit costs
|
|
|
2,535,976 |
|
|
|
2,513,030 |
|
Accrued
asset removal cost
|
|
|
20,366,122 |
|
|
|
20,249,948 |
|
Other
liabilities
|
|
|
3,951,145 |
|
|
|
3,861,229 |
|
Total
deferred credits and other liabilities
|
|
|
59,556,924 |
|
|
|
57,669,004 |
|
|
|
|
|
|
|
|
|
|
Other
Commitments and Contingencies (Note
4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Capitalization and Liabilities
|
|
$ |
400,911,493 |
|
|
$ |
381,557,012 |
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these financial
statements.
Notes
to Condensed Consolidated Financial Statements
References
in this document to “the Company,” “Chesapeake,” “we,” “us” and “our” are
intended to mean Chesapeake Utilities Corporation and its
subsidiaries.
The
accompanying unaudited condensed consolidated financial statements have been
prepared in compliance with the rules and regulations of the Securities and
Exchange Commission (“SEC”) and United States of America Generally Accepted
Accounting Principles (“GAAP”). In accordance with these rules and regulations,
certain information and disclosures normally required for audited financial
statements have been condensed or omitted. These financial statements should be
read in conjunction with the consolidated financial statements and notes
thereto, included in the Company’s latest Annual Report on Form 10-K filed with
the SEC on March 10, 2008. In the opinion of management, these statements
reflect normal recurring adjustments that are necessary for a fair presentation
of the Company’s results of operations, financial position and cash flows for
the interim periods presented.
Comprehensive
income contains items that are excluded from net income and recorded directly to
stockholders’ equity. For the first six months of 2008 and 2007, Chesapeake did
not have any adjustments to comprehensive income that are required to be
reported by Financial Accounting Standards Board (“FASB”) Statement of Financial
Accounting Standards (“SFAS”) No. 130, “Reporting Comprehensive Income.”
Accumulated other comprehensive loss was $851,674 at June 30, 2008 and December
31, 2007.
3.
|
Calculation
of Earnings Per Share
|
|
Three
Months Ednded
|
|
Six
Months Ednded
|
For
the Periods Ended June 30,
|
2008
|
2007
|
|
2008
|
2007
|
|
|
|
|
|
|
Calculation
of Basic Earnings Per Share:
|
|
|
|
|
|
Net
Income
|
$1,818,924
|
$1,481,790
|
|
$9,393,266
|
$9,472,878
|
Weighted
average shares outstanding
|
6,812,474
|
6,737,384
|
|
6,803,892
|
6,721,694
|
Basic
Earnings Per Share
|
$0.27
|
$0.22
|
|
$1.38
|
$1.41
|
|
|
|
|
|
|
Calculation
of Diluted Earnings Per Share:
|
|
|
|
|
|
Reconciliation
of Numerator:
|
|
|
|
|
|
Net
Income
|
$1,818,924
|
$1,481,790
|
|
$9,393,266
|
$9,472,878
|
Effect
of 8.25% Convertible debentures (1)
|
22,306
|
24,015
|
|
45,114
|
48,214
|
Adjusted
numerator — Diluted
|
$1,841,230
|
$1,505,805
|
|
$9,438,380
|
$9,521,092
|
|
|
|
|
|
|
Reconciliation
of Denominator:
|
|
|
|
|
|
Weighted
shares outstanding — Basic
|
6,812,474
|
6,737,384
|
|
6,803,892
|
6,721,694
|
Effect
of dilutive securities (1):
|
|
|
|
|
|
Restricted
Stock
|
2,780
|
-
|
|
7,449
|
-
|
8.25%
Convertible debentures
|
104,788
|
112,506
|
|
105,967
|
113,563
|
Adjusted
denominator — Diluted
|
6,920,042
|
6,849,890
|
|
6,917,308
|
6,835,257
|
|
|
|
|
|
|
Diluted
Earnings Per Share
|
$0.27
|
$0.22
|
|
$1.36
|
$1.39
|
|
|
|
|
|
|
(1)
Amounts associated with conversion of securities that result in an
anti-dilutive effect
|
|
on
earnings per share are not included in this calculation.
|
|
|
|
|
4.
|
Commitments
and Contingencies
|
Rates
and Regulatory Matters
The
Company’s natural gas distribution operations in Delaware, Maryland and Florida
are subject to regulation by their respective state Public Service Commissions
(“PSC’s”). Eastern Shore Natural Gas Company (“Eastern Shore”), the Company’s
natural gas transmission operation, is subject to regulation by the Federal
Energy Regulatory Commission (“FERC”).
Delaware. On
July 6, 2007, the Company filed with the Delaware PSC an application seeking
approval of the following: (i) participation by the Company’s Delaware
commercial and industrial customers in gas supply buying pools served by
third-party natural gas marketers; (ii) an annual base rate adjustment of
$1,896,000 that represents approximately a 3.25 percent rate increase on average
for the Delaware division’s firm customers; (iii) an alternative rate design for
residential customers in a defined expansion area in eastern Sussex County,
Delaware; and (iv) a revenue normalization mechanism that mitigates the price
and revenue impacts of seasonal natural gas consumption patterns on both
customers and the Company. As part of that filing, the Company also proposed
that the Delaware division be permitted to earn a return on equity of up to
fifteen percent (15%) as an incentive to make the significant capital
investments to serve the growing areas of eastern Sussex County, in support of
Delaware’s Energy Policy, and to ensure that the Company’s investors are
adequately compensated for the increased risk associated with the higher levels
of capital investment necessary to provide natural gas in those
areas. On August 21, 2007, the Delaware PSC authorized the Company to
implement charges reflecting the proposed $1,896,000 increase effective
September 4, 2007, on a temporary basis and subject to refund, pending the
completion of full evidentiary hearings and a final decision by the Delaware
PSC. The Delaware PSC Staff filed testimony recommending a rate decrease of
$693,245. The Delaware Public Advocate (“DPA”) recommended a rate decrease of
$588,670. Neither party recommended approval of the Delaware division’s other
proposals mentioned above. The Delaware division disagreed with these positions
in its rebuttal, which was filed on February 7, 2008. At an
evidentiary hearing on July 9, 2008, the parties presented a proposed settlement
agreement that would effectively resolve all issues in this
docket. The major components of the proposed settlement include the
following: (i) a rate increase for the Delaware division of $325,000,
including miscellaneous fees; (ii) an overall rate of return of 8.91% and a
return on equity of 10.25%; (iii) a change in depreciation rates that results in
a reduction in depreciation expense of approximately $897,000; (iv) the Delaware
division would be permitted to retain 100% of all interruptible margins, there
would be a minimum usage threshold for interruptible service of 10,000 Mcf per
year, and all interruptible customers would be required to transport; (v) the
Delaware division would continue to share any margins received from its Asset
Manager and any off-system sales on an 80%/20% basis, with 80% being returned to
the firm customers through the GSR mechanism; (vi) the residential service rate
schedule would be divided into two separate schedules based on annual volumetric
levels; (vii) individual customers with multiple meters would be able to
aggregate meters in order to qualify for transportation service; and (viii) the
Delaware division would have the ability to aggregate main extension projects
over 500 feet at the time of its next base rate proceeding to determine rate
base treatment. The Delaware division anticipates a final decision by
the Delaware PSC during the third quarter of 2008.
On
September 10, 2007, the Company filed with the Delaware PSC its annual Gas
Service Revenue (“GSR”) Application, seeking approval to change its GSR rates
effective for service rendered on and after November 1, 2007. On October 2,
2007, the Delaware PSC authorized the Company to implement the GSR charges on a
temporary basis, subject to refund, pending the completion of full evidentiary
hearings and a final decision. The Company is required by its natural
gas tariff to file a revised application if its projected under-collection of
gas costs for the determination period of November through October exceeds six
percent (6%) of total firm gas costs. As a result of continued
increases in the cost of natural gas, on July 1, 2008, the Company filed with
the Delaware PSC a supplemental GSR Application, seeking approval to change its
GSR rates effective for service rendered on and after August 1,
2008. On July 8, 2008, the Delaware PSC authorized the Company to
implement the revised GSR charges on a temporary basis, subject to refund,
pending the completion of full evidentiary hearings and a final
decision. The Delaware division anticipates a final decision by the
Delaware PSC on both filings during the fourth quarter of 2008.
On
November 1, 2007, the Delaware division filed with the Delaware PSC its annual
Environmental Rider (“ER”) rate application to become effective for service
rendered on and after December 1, 2007. The Delaware PSC granted approval of the
ER rate at its regularly scheduled meeting on November 20, 2007, subject to full
evidentiary hearings and a final decision. On February 5, 2008, the Delaware PSC
granted final approval of the ER rates as filed. Since all of the division’s
environmental expenses, which are subject to recovery pursuant to the ER
recovery mechanism, will have been collected by the end of the determination
period, no further ER rate applications will be filed by the Delaware division,
and ER charges will cease to appear on the Delaware division’s customers’ bills
as of November 30, 2008.
Maryland. On
September 26, 2006, the Maryland PSC approved a base rate increase for the
Maryland division of approximately $780,000 annually. In a settlement agreement
entered into in that proceeding, the Maryland division was required to file a
depreciation study, which was filed on April 9, 2007. The Maryland division
filed formal testimony on July 10, 2007, initiating a Phase II of this
proceeding. In this filing, the Maryland division proposed a rate decrease of
approximately $80,000 annually, resulting from a change in depreciation expense.
On November 29, 2007, the Maryland PSC approved a settlement agreement for a
rate decrease of $132,155, effective December 1, 2007, based on the change in
the Company’s depreciation rates. Under the settlement, the Maryland
division has reduced its depreciation expense by approximately $119,000 and its
cost of removal by approximately $167,000. The difference between the
decrease in depreciation expense and the decrease in delivery service rates is
due to an increase in rate case expense amortization and an increase to offset
the loss of margin from a large customer in Maryland.
On
December 17, 2007, the Maryland PSC held an evidentiary hearing to determine the
reasonableness of the Maryland division’s four quarterly gas cost recovery
filings during the twelve months ended September 30, 2007. No issues were raised
at the hearing, and on February 7, 2008, the Maryland PSC approved, without
exception, the Maryland division’s four quarterly gas cost recovery
filings.
Florida. In
compliance with state law, the Florida division filed its 2007 Depreciation
Study (“Study”) with the Florida PSC on May 17, 2007. This study, which
supersedes the last study performed in 2002, provides the Florida PSC the
opportunity to review and address changes in plant and equipment lives, salvage
values, reserves and resulting life depreciation rates. The Florida division
responded to interrogatories concerning the Study on October 15, 2007, December
24, 2007, and February 7, 2008. Based on the recommendation
issued by the Florida PSC Staff, the Commission, at its May 20, 2008 agenda
conference, approved certain revisions to the Florida division’s utility plant
remaining lives, net salvage values, depreciation reserves, and depreciation
rates, effective January 1, 2008. These changes were not material to
the financial results of the Florida division. The Florida PSC issued
an order on June 27, 2008, which closes this docket.
Eastern Shore.
Eastern Shore had the following regulatory activity with the FERC regarding the
expansion of its transmission system:
System Expansion 2006 –
2008. On November 15, 2007, Eastern Shore requested FERC
authorization to commence construction of facilities (approximately 9.2 miles)
included in the third phase of the 2006-08 System Expansion. The FERC granted
this authorization on January 7, 2008. Construction began in the first quarter
of 2008, and the facilities are to be completed and placed in service by
November 1, 2008. These Phase III facilities will provide 5,650 Dekatherms
(“Dts”) of additional firm service capacity per day and annualized gross margin
contribution of approximately $1.0 million.
Eastern Shore Energylink
Expansion Project (“E3 Project”). In 2006, Eastern Shore proposed to
develop, construct and operate approximately 75 miles of new pipeline facilities
to transport natural gas from the existing Cove Point liquefied natural gas
(“LNG”) terminal located in Calvert County, Maryland, crossing under the
Chesapeake Bay into Dorchester and Caroline Counties, Maryland, to points on the
Delmarva Peninsula, where such facilities would interconnect with Eastern
Shore’s existing facilities in Sussex County, Delaware.
On May
31, 2006, Eastern Shore entered into Precedent Agreements (the “Precedent
Agreements”) with Delmarva Power & Light Company (“Delmarva”) and
Chesapeake, through its Delaware and Maryland divisions, to provide additional
firm transportation services upon completion of the E3 Project. Both Chesapeake
and Delmarva are parties to existing firm natural gas transportation service
agreements with Eastern Shore, and each desired additional firm transportation
service under the E3 Project, as evidenced by the Precedent Agreements. Pursuant
to the Precedent Agreements, the parties agreed to proceed with the required
initiatives to obtain the governmental and regulatory authorizations necessary
for Eastern Shore to provide, and for Chesapeake and Delmarva to utilize,
additional firm transportation service under the E3 Project.
As part
of the Precedent Agreements, Eastern Shore, Chesapeake and Delmarva also entered
into Letter Agreements which provide that, if the E3 Project is not certificated
and placed in service, Chesapeake and Delmarva will each pay its proportionate
share of certain pre-certification costs by means of a negotiated surcharge over
a period of not less than 20 years.
In
furtherance of the E3 Project, Eastern Shore submitted a petition to the FERC on
June 27, 2006, seeking approval of the pre-construction cost agreements as part
of a rate-related Settlement Agreement (the “Settlement Agreement”), which would
provide benefits to Eastern Shore and its customers, including but not limited
to: (1) advancement of a necessary infrastructure project to meet the growing
demand for natural gas on the Delmarva Peninsula; (2) sharing of project
development costs by the participating customers in the project; and (3) no
development cost risk for non-participating customers. On August 1, 2006, the
FERC approved the Settlement Agreement. On September 6, 2006, Eastern Shore
submitted to FERC proposed tariff sheets to implement the provisions of the
Settlement Agreement. By Letter Order dated October 6, 2006, the FERC accepted
the tariff sheets, effective September 7, 2006.
On April
23, 2007, Eastern Shore submitted to the FERC its request to commence a
pre-filing process, and on May 15, 2007, the FERC notified Eastern Shore that
its request had been approved. The pre-filing process was intended to engage all
interested and affected stakeholders early in the process with the intention of
resolving all environmental issues prior to the formal certificate application
being filed. As part of this process, Eastern Shore performed
environmental, engineering and cultural surveys and studies in the interest of
protecting the environment, minimizing any potential impacts to landowners, and
cultural resources. Eastern Shore also held meetings with federal, state and
local permitting/regulatory agencies, non-governmental organizations,
landowners, and other interested stakeholders.
As part
of an updated engineering study, Eastern Shore received additional construction
cost estimates for the E3 project, which indicated substantially higher costs
than previously estimated. In an effort to optimize the feasibility of the
overall project development plan, Eastern Shore explored all potential
construction methods, construction cost mitigation strategies, potential design
changes and project schedule changes. Eastern Shore also held discussions and
meetings with several potential new customers, who expressed interest in the
project, but elected not to participate.
On
December 20, 2007, Eastern Shore withdrew from the pre-filing process as a
result of insufficient customer commitments for capacity to make the project
economical. Eastern Shore will continue to explore potential construction
methods, construction cost mitigation strategies, additional market requests,
and potential design changes in its efforts to improve the overall economics of
the project.
If
Eastern Shore decides to abandon the E3 Project, it will initiate billing of a
pre-certification costs surcharge in accordance with the terms of the Precedent
Agreements executed with two of its customers, which provide for these customers
to reimburse Eastern Shore for pre-certification costs incurred in connection
with the E3 Project, up to a maximum amount of $2.0 million each, with interest,
over a period of 20 years. As of June 30, 2008, the Company had incurred $3.18
million of pre-certification costs relating to the E3 Project.
Eastern
Shore also had developments in the following FERC rate and certificate
matters:
On June
6, 2007, Eastern Shore and interested parties reached a settlement agreement in
principle on its base rate proceeding filed with the FERC on October 31,
2006. The negotiated settlement provides for an annual cost of
service of $21,536,000, which reflects a pretax rate of return of
13.6 percent and a rate increase of approximately $1.07 million on an annual
basis. On September 10, 2007, Eastern Shore submitted its Settlement Offer to
the Presiding Administrative Law Judge (“ALJ”) for review and certification to
the full Commission.
Eastern
Shore filed concurrently with its Settlement Agreement a Motion to place the
settlement rates into effect on September 1, 2007, in order to expedite the
implementation of the reduced settlement rates pending final approval of the
settlement. The Commission issued an order on September 25, 2007, authorizing
Eastern Shore to commence billing its settlement rates, effective September 1,
2007.
On
October 1, 2007, the Presiding ALJ forwarded to the full Commission an order
certifying the uncontested Settlement Agreement as fair, reasonable, and in the
public interest. A final Commission Order approving the settlement was issued on
January 31, 2008. In compliance with the Settlement Agreement,
refunds, inclusive of interest, totaling $1.26 million, based on the higher
interim rates that were effective for the period from May 15, 2007 through
August 31, 2007, were distributed to Eastern Shore’s customers on February 1,
2008.
On May
15, 2008, Eastern Shore submitted its annual Interruptible Revenue Sharing
Report to the FERC. Eastern Shore reported in this filing that its
interruptible revenue was in excess of its annual threshold amount and refunded
a total of $63,675 in the second quarter of 2008 to its eligible firm
customers.
On June
24, 2008, Eastern Shore submitted its annual Fuel Retention Percentage (“FRP”)
and Cash-Out Surcharge filings to the FERC. In these filings, Eastern Shore
proposed to retain its current FRP rate of zero percent and also a zero rate for
its Cash-Out Surcharge. Eastern Shore also proposed to refund a total
of $ 412,013, including interest, to its eligible customers in the third quarter
of 2008 as a result of netting its over-recovered Gas Required for Operations
against its under-recovered Cash-Out Cost. The FERC approved these
proposals on July 11, 2008.
Environmental
Matters
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 manufactured gas plant site located in Dover, Delaware. Chesapeake
is also currently participating in the investigation, assessment or remediation
of two additional former manufactured gas 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 manufactured gas
plant site located in Cambridge, Maryland. The following discussion provides
details on each site.
Dover
Gas Light Site
The Dover
Gas Light site is a former manufactured gas plant site located in Dover,
Delaware. On January 15, 2004, the Company received a Certificate of Completion
of Work from the United States Environmental Protection Agency (“EPA”) regarding
this site. This concluded Chesapeake’s remedial action 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 EPA 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 June
30, 2008, the Company has incurred approximately $9.67 million in costs related
to environmental testing and remedial action studies at the site. Approximately
$9.73 million has been recovered through June 2008 from other parties or through
rates. As of June 30, 2008, a regulatory liability of approximately $68,000,
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
decommission permanently 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. Chesapeake has requested a No Further
Action determination and is awaiting such a determination from the
MDE.
Through
June 30, 2008, 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 $1.94 million has been recovered through insurance
proceeds or in rates. On September 26, 2006, the Company received
approval from the Maryland PSC to recover, through its rates charged to
customers, $1.02 million of incurred environmental remediation
costs. As of June 30, 2008, a regulatory asset of approximately
$956,000 has been recorded to represent the remaining under-recovery portion of
the clean-up 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 with the FDEP an
AS/SVE Pilot Study Work Plan (the “Work Plan”) for the Winter Haven Coal Gas
site. After discussions with the FDEP, the Company filed a modified Work Plan,
which contained a description of the scope of 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.
Through
June 30, 2008, the Company has incurred approximately $1.8 million of
environmental costs associated with this site. At June 30, 2008, the Company had
accrued a liability of $751,000 related to this site, offsetting: (a) $64,000
collected through rates in excess of costs incurred and (b) a regulatory asset
of approximately $815,000, representing the uncollected portion of the estimated
clean-up costs. The Company expects to recover the remaining clean-up 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 Coal Gas 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
requirement 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 manufactured gas 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 to purchase gas from various suppliers. The contracts
have various expiration dates. In March 2008, 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. This new contract
expires on March 31, 2009.
Corporate
Guarantees
The
Company has issued corporate guarantees to certain vendors of its propane
wholesale marketing subsidiary and its Florida natural gas supply management
subsidiary. These corporate guarantees provide for the payment of propane and
natural gas purchases in the event of either subsidiary’s default. Neither of
these subsidiaries has ever defaulted on its obligations to pay its suppliers.
The liabilities for these purchases are recorded in the Consolidated Financial
Statements when incurred. The aggregate amount guaranteed at June 30,
2008 was $24.2 million, with the guarantees expiring on various dates in 2008
and the first six months of 2009.
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, 2009.
The letter of credit is provided as security to satisfy the deductibles under
the Company’s various insurance policies. There have been no draws on this
letter of credit as of June 30, 2008.
Internal
Revenue Service Audit
Application
of SFAS No. 71
Certain
assets and liabilities of the Company are accounted for in accordance with SFAS
No. 71 ¾
“Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71
provides guidance for public utilities and other regulated operations where the
rates (prices) charged to customers are subject to regulatory review and
approval. Regulators sometimes include allowable costs in a period other than
the period in which the costs would be charged to expense by an unregulated
enterprise. That procedure can create assets, reduce assets, or create
liabilities for the regulated enterprise. For financial reporting, an incurred
cost for which a regulator permits recovery in a future period is accounted for
like an incurred cost that is reimbursable under a cost-reimbursement type
contract. The Company believes that all regulatory assets as of June 30, 2008
are probable of recovery through rates. If the Company were required to
terminate the application of SFAS No. 71 to its regulated operations, all such
deferred amounts would be recognized in the income statement at that time. This
would result in a charge to earnings, net of applicable income taxes, which
could be material.
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.
5.
|
Recent
Authoritative Pronouncements on Financial Reporting and
Accounting
|
Recent
accounting pronouncements:
In
December 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial
Accounting Standards No. 141 (revised 2007) “Business Combinations” (“SFAS
141(R)”). SFAS 141(R) retains the fundamental requirements of the original
pronouncement requiring that the purchase method be used for all business
combinations. SFAS 141(R) defines the acquirer as the entity that obtains
control of one or more businesses in the business combination, establishes the
acquisition date as the date that the acquirer achieves control and requires the
acquirer to recognize the assets acquired, liabilities assumed and any
non-controlling interest at their fair values as of the acquisition date. SFAS
141(R) also requires that acquisition-related costs be expensed as incurred.
SFAS 141(R) is effective for fiscal years beginning after December 15, 2008. The
Company does not expect the adoption of SFAS 141(R) to have a material impact on
its current consolidated financial position and results of operations. However,
depending upon the size, nature and complexity of future acquisition
transactions, the adoption of SFAS 141(R) could materially affect the Company’s
consolidated financial statements.
In
December 2007, the FASB issued FASB Statement No. 160, “Noncontrolling
Interests in Consolidated Financial Statements,” an amendment of ARB No. 51
(“SFAS 160”). SFAS 160 changes the accounting and reporting for minority
interests, which will be recharacterized as noncontrolling interests and
classified as a component of equity. This new consolidation method significantly
changes the accounting for transactions with minority interest holders. SFAS 160
is effective for fiscal years beginning after December 15, 2008. No other entity
has a minority interest in any of the Company’s subsidiaries; therefore, the
Company does not expect the adoption of SFAS 160 to have an impact on its
current consolidated financial position and results of operations.
In April
2008, the FASB issued FASB Staff Position (“FSP”) FAS 142-3, “Determination of
the Useful Life of Intangible Assets.” This FSP amends the factors
that should be considered in developing renewal or extension assumptions used to
determine the useful life of a recognized intangible asset under FASB Statement
No. 142, “Goodwill and Other Intangible Assets” (“SFAS
142”). The intent of this FSP is to improve the consistency between
the useful life of a recognized intangible asset under SFAS 142 and the
period of expected cash flows used to measure the fair value of the asset under
SFAS 141R, and other GAAP. This FSP is effective for financial
statements issued for fiscal years beginning after December 15, 2008, and
interim periods within those fiscal years. Early adoption is
prohibited. The Company is currently evaluating the potential impact
the new pronouncement will have on its consolidated financial
statements.
In
May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally
Accepted Accounting Principles.” This standard is intended to improve
financial reporting by identifying a consistent framework, or hierarchy, for
selecting accounting principles to be used in preparing financial statements
that are presented in conformity with generally accepted accounting principles
in the United States for non-governmental entities. SFAS No. 162 is
effective 60 days following approval by the U.S. Securities and Exchange
Commission of the Public Company Accounting Oversight Board’s amendments to AU
Section 411, “The Meaning of Present Fairly in Conformity with Generally
Accepted Accounting Principles.” We do not expect SFAS No. 162 to have a
material impact on the preparation of our consolidated financial
statements.
In
May 2008, the FASB issued FASB Staff Position (“FSP”) APB 14-1, “Accounting
for Convertible Debt Instruments That May Be Settled in Cash upon
Conversion (Including Partial Cash Settlement).” FSP APB 14-1
clarifies that convertible debt instruments that may be settled in cash upon
either mandatory or optional conversion (including partial cash settlement) are
not addressed by paragraph 12 of APB Opinion No. 14, “Accounting for
Convertible Debt and Debt issued with Stock Purchase Warrants.” In
addition, FSP APB 14-1 specifies that issuers of such instruments should
separately account for the liability and equity components in a manner that will
reflect the entity’s nonconvertible debt borrowing rate when interest cost is
recognized in subsequent periods. FSP APB 14-1 is effective for financial
statements issued for fiscal years beginning after December 15, 2008, and
interim periods within those fiscal years. The Company is assessing the
potential impact that the adoption of FSP APB 14-1 may have on its financial
statements.
In June
2008, the FASB issued FASB Staff Position (FSP) EITF 03-6-1, “Determining
Whether Instruments Granted in Share-Based Payment Transactions Are
Participating Securities.” This FSP clarifies that all outstanding
unvested share-based payment awards that contain rights to nonforfeitable
dividends participate in undistributed earnings with common
shareholders. Awards of this nature are considered participating
securities and the two-class method of computing basic and diluted earnings per
share must be applied. This FSP is effective for fiscal years
beginning after December 15, 2008. The Company is currently
evaluating the potential impact the new pronouncement will have on its
consolidated financial statements.
In June
2008, the FASB ratified EITF Issue No. 07-5, “Determining Whether an Instrument
(or an Embedded Feature) Is Indexed to an Entity’s Own Stock” (EITF
07-5). EITF 07-5 provides that an entity should use a two step
approach to evaluate whether an equity-linked financial instrument (or embedded
feature) is indexed to its own stock, including evaluating the instrument’s
contingent exercise and settlement provisions. It also clarifies the
impact of foreign currency denominated strike prices and market-based employee
stock option valuation instruments on the evaluation. EITF 07-5 is
effective for fiscal years beginning after December 15, 2008. The
Company is currently evaluating the potential impact the new pronouncement will
have on its consolidated financial statements.
In June
2008, the FASB ratified EITF Issue No. 08-3, “Accounting for Lessees for
Maintenance Deposits Under Lease Arrangements” (EITF 08-3). EITF 08-3 provides
guidance for accounting for nonrefundable maintenance deposits. It
also provides revenue recognition accounting guidance for the
lessor. EITF 08-3 is effective for fiscal years beginning after
December 15, 2008. The Company is currently evaluating the potential
impact the new pronouncement will have on its consolidated financial
statements.
During
the first six months of 2008, the Company adopted the following accounting
standards:
Effective
January 1, 2008, Chesapeake adopted FSP No. FIN 39-1, “Amendment of FASB
Interpretation No. 39” (“FSP FIN 39-1”). FSP FIN 39-1 modifies FIN No. 39,
“Offsetting of Amounts Related to Certain Contracts,” and permits companies to
offset cash collateral receivables or payables with net derivative positions
under certain circumstances. Based on the derivative
contracts entered into to date, the adoption of this FSP did not have a material
effect on our consolidated financial statements.
In
September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.”
SFAS No. 157 provides guidance for using fair value to measure assets and
liabilities. It also responds to investors’ requests for expanded information
about the extent to which companies’ measure assets and liabilities at fair
value, the information used to measure fair value, and the effect of fair value
measurements on earnings. SFAS No. 157 applies whenever other standards
require (or permit) assets or liabilities to be measured at fair value and does
not expand the use of fair value in any new circumstances. In February 2008, the
FASB issued FASB Staff Position 157-1, “Application of FASB Statement
No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements
That Address Fair Value Measurements for Purposes of Lease Classification or
Measurement under Statement 13” (“FSP 157-1”) and FSP 157-2, “Effective Date of
FASB Statement No. 157” (“FSP 157-2”). FSP 157-1 amends SFAS No. 157
to remove certain leasing transactions from its scope. FSP 157-2 delays the
effective date of SFAS No. 157 until fiscal years beginning after November
15, 2009 for all non-financial assets and non-financial liabilities, except for
items that are recognized or disclosed at fair value in the financial statements
on a recurring basis. These nonfinancial items include assets and liabilities
such as reporting units measured at fair value in a goodwill impairment test and
nonfinancial assets acquired and liabilities assumed in a business combination.
SFAS No. 157 was effective for financial statements issued for fiscal years
beginning after November 15, 2007 and was adopted by the Company, as it
applies to its financial instruments, effective January 1, 2008. The
adoption of SFAS No. 157 did not have any financial impact on the Company’s
consolidated financial statements. The disclosures required by SFAS
157 are discussed in Note 11 – Fair Value of Financial Instruments of the
unaudited Condensed Consolidated Financial Statements.
In
February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for
Financial Assets and Financial Liabilities – Including an amendment of FASB
Statement No. 115,” which permits entities to elect to measure at fair
value many financial instruments and certain other items that are not currently
required to be measured at fair value. This election is irrevocable. SFAS
No. 159 was effective in the first quarter of fiscal 2008. The Company has
not elected to apply the fair value option to any of its financial
instruments.
Chesapeake
uses the management approach to identify operating segments. The Company
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 the allocation of
resources and to assess performance. The following table presents information
about the Company’s reportable segments. The table excludes financial data
related to our distributed energy company, which was reclassified to
discontinued operations for each period presented. The impact of
discontinued operations is discussed within Note 12 “Discontinued Operations” of
the unaudited Condensed Consolidated Financial Statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
For
the Periods Ended June 30,
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Operating
Revenues, Unaffiliated Customers
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$ |
53,773,960 |
|
|
$ |
39,287,667 |
|
|
$ |
122,596,489 |
|
|
$ |
104,719,271 |
|
Propane
|
|
|
11,488,807 |
|
|
|
9,494,170 |
|
|
|
39,296,608 |
|
|
|
34,416,570 |
|
Advanced
information services
|
|
|
3,794,192 |
|
|
|
3,720,083 |
|
|
|
7,437,362 |
|
|
|
6,892,971 |
|
Other
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
operating revenues, unaffiliated customers
|
|
$ |
69,056,959 |
|
|
$ |
52,501,920 |
|
|
$ |
169,330,459 |
|
|
$ |
146,028,812 |
|
Intersegment
Revenues (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$ |
104,519 |
|
|
$ |
78,087 |
|
|
$ |
210,372 |
|
|
$ |
156,150 |
|
Propane
|
|
|
- |
|
|
|
- |
|
|
|
1,349 |
|
|
|
406 |
|
Advanced
information services
|
|
|
28,083 |
|
|
|
95,991 |
|
|
|
36,051 |
|
|
|
228,226 |
|
Other
|
|
|
163,073 |
|
|
|
154,623 |
|
|
|
326,148 |
|
|
|
309,246 |
|
Total
intersegment revenues
|
|
$ |
295,675 |
|
|
$ |
328,701 |
|
|
$ |
573,920 |
|
|
$ |
694,028 |
|
Operating
Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$ |
4,736,363 |
|
|
$ |
3,992,282 |
|
|
$ |
15,205,387 |
|
|
$ |
13,608,264 |
|
Propane
|
|
|
(624,699 |
) |
|
|
(545,898 |
) |
|
|
2,819,436 |
|
|
|
4,327,658 |
|
Advanced
information services
|
|
|
137,077 |
|
|
|
178,708 |
|
|
|
174,941 |
|
|
|
227,528 |
|
Other
and eliminations
|
|
|
80,698 |
|
|
|
72,973 |
|
|
|
170,390 |
|
|
|
148,188 |
|
Total
operating income
|
|
$ |
4,329,439 |
|
|
$ |
3,698,065 |
|
|
$ |
18,370,154 |
|
|
$ |
18,311,638 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income
|
|
|
63,507 |
|
|
|
234,194 |
|
|
|
81,097 |
|
|
|
290,675 |
|
Interest
Charges
|
|
|
1,388,735 |
|
|
|
1,594,701 |
|
|
|
2,982,106 |
|
|
|
3,193,951 |
|
Income
Taxes
|
|
|
1,185,287 |
|
|
|
849,877 |
|
|
|
6,075,879 |
|
|
|
5,909,199 |
|
Net
income from continuing operations
|
|
$ |
1,818,924 |
|
|
$ |
1,487,681 |
|
|
$ |
9,393,266 |
|
|
$ |
9,499,163 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) All
significant intersegment revenues are billed at market rates and have
been
|
|
|
|
|
|
eliminated
from consolidated revenues.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June
30,
|
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
Identifiable
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$ |
276,404,244 |
|
|
$ |
273,500,890 |
|
|
|
|
|
|
|
|
|
Propane
|
|
|
108,722,729 |
|
|
|
94,966,212 |
|
|
|
|
|
|
|
|
|
Advanced
information services
|
|
|
2,820,065 |
|
|
|
2,507,910 |
|
|
|
|
|
|
|
|
|
Other
|
|
|
12,915,716 |
|
|
|
10,533,511 |
|
|
|
|
|
|
|
|
|
Total
identifiable assets
|
|
$ |
400,862,754 |
|
|
$ |
381,508,523 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
Company’s operations are primarily 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.
7.
|
Employee
Benefit Plans
|
Net
periodic benefit costs for the defined benefit pension plan, the executive
excess benefit plan and other post-retirement benefits are shown
below:
|
|
Defined
Benefit
|
|
|
Executive
Excess Defined
|
|
Other
Post-Retirement
|
|
|
|
Pension
Plan
|
|
|
Benefit
Pension Plan
|
|
|
Benefits
|
|
For
the Three Months Ended June 30,
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Service
Cost
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
896 |
|
|
$ |
2,529 |
|
Interest
Cost
|
|
|
148,431 |
|
|
|
155,514 |
|
|
|
31,382 |
|
|
|
30,841 |
|
|
|
27,565 |
|
|
|
23,233 |
|
Expected
return on plan assets
|
|
|
(156,475 |
) |
|
|
(174,100 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Amortization
of prior service cost
|
|
|
(1,175 |
) |
|
|
(1,175 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Amortization
of net loss
|
|
|
- |
|
|
|
- |
|
|
|
11,611 |
|
|
|
12,933 |
|
|
|
46,215 |
|
|
|
41,640 |
|
Net
periodic (benefit) cost
|
|
$ |
(9,219 |
) |
|
$ |
(19,761 |
) |
|
$ |
42,993 |
|
|
$ |
43,774 |
|
|
$ |
74,676 |
|
|
$ |
67,402 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined
Benefit
|
|
|
Executive
Excess Defined
|
|
Other
Post-Retirement
|
|
|
|
Pension
Plan
|
|
|
Benefit
Pension Plan
|
|
|
Benefits
|
|
For
the Six Months Ended June 30,
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Service
Cost
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
1,792 |
|
|
$ |
5,057 |
|
Interest
Cost
|
|
|
296,862 |
|
|
|
311,029 |
|
|
|
62,763 |
|
|
|
61,681 |
|
|
|
55,129 |
|
|
|
46,467 |
|
Expected
return on plan assets
|
|
|
(312,950 |
) |
|
|
(348,199 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Amortization
of prior service cost
|
|
|
(2,350 |
) |
|
|
(2,350 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Amortization
of net loss
|
|
|
- |
|
|
|
- |
|
|
|
23,222 |
|
|
|
25,867 |
|
|
|
92,430 |
|
|
|
83,280 |
|
Net
periodic (benefit) cost
|
|
$ |
(18,438 |
) |
|
$ |
(39,520 |
) |
|
$ |
85,985 |
|
|
$ |
87,548 |
|
|
$ |
149,351 |
|
|
$ |
134,804 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As
disclosed in the December 31, 2007 financial statements, no contributions are
expected to be required in 2008 for the defined benefit pension plan. The cost
of the executive excess retirement benefit plan and the other post-retirement
benefit plans are unfunded and are expected to be paid out of the general funds
of the Company. Cash benefits paid under the executive excess retirement benefit
plan for the three months and six months ended June 30, 2008 were $22,300 and
$44,600, respectively; for the year 2008, such benefits paid are expected to be
$89,200. The Company incurred a credit of $8,500 for post-retirement benefits
for medical claims for the three months ended June 30, 2008 compared
to cash benefits paid of $17,000 for the first six months of
2008; for the year 2008, the Company has estimated that such benefits
to be paid are $196,000. The credit incurred in the second quarter of
2008 is the result of being reimbursed for claims that were previously paid in
2007.
The
investment balance at June 30, 2008 represents a Rabbi 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, the Company is required to report the securities at their fair value,
with any unrealized gains and losses included in other income. The Company also
has an associated liability that is recorded and adjusted each month for the
gains and losses incurred by the Trust. At June 30, 2008, total
investments had a fair value of $1.9 million.
9.
|
Share-Based
Compensation
|
The
Company accounts for its share-based compensation arrangements under SFAS No.
123 (revised 2004), “Share Based Payments” (“SFAS 123R”), which requires
companies to record compensation costs for all share-based awards over the
respective service period for which employee services are received in exchange
for an award of equity or equity-based compensation. The compensation cost is
based on the fair value of the grant on the date it was awarded. The Company
currently has two share-based compensation plans, the Directors Stock
Compensation Plan (“DSCP”) and the Performance Incentive Plan (“PIP”), that
require accounting under SFAS 123R.
The table
below presents the amounts included in net income related to share-based
compensation expense for the restricted stock awards issued under the DSCP and
the PIP for the three and six months ended June 30, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
For
the periods ended June 30,
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Directors
Stock Compensation Plan
|
|
$ |
45,893 |
|
|
$ |
45,230 |
|
|
$ |
91,786 |
|
|
$ |
89,134 |
|
Performance
Incentive Plan
|
|
|
198,984 |
|
|
|
214,373 |
|
|
|
384,342 |
|
|
|
416,308 |
|
Total
compensation expense
|
|
|
244,877 |
|
|
|
259,603 |
|
|
|
476,128 |
|
|
|
505,442 |
|
Less:
tax benefit
|
|
|
97,507 |
|
|
|
101,245 |
|
|
|
189,588 |
|
|
|
197,122 |
|
SFAS
123R amounts included in net income
|
|
$ |
147,370 |
|
|
$ |
158,358 |
|
|
$ |
286,540 |
|
|
$ |
308,320 |
|
The
changes in common stock shares issued and outstanding are shown
below:
11.
|
Fair
Value of Financial Instruments
|
The
Company adopted SFAS No. 157 effective January 1, 2008 for financial assets
and liabilities measured on a recurring basis. SFAS No. 157 applies to all
financial assets and financial liabilities that are being measured and reported
on a fair value basis. There was no impact from adoption of SFAS No. 157 to
the unaudited condensed consolidated balance sheets and statements of
income. The primary effect of SFAS No. 157 on the Company was to
expand the required disclosures pertaining to the methods used to determine fair
values.
SFAS
No. 157 establishes a fair value hierarchy that prioritizes the inputs to
valuation methods used to measure fair value. The hierarchy gives the
highest priority to unadjusted quoted prices in active markets for identical
assets or liabilities (Level 1 measurements) and the lowest priority to
unobservable inputs (Level 3 measurements). The three levels of the
fair value hierarchy under SFAS 157 are as follows:
Level 1:
Unadjusted quoted prices in active markets that are accessible at the
measurement date for identical, unrestricted assets or liabilities;
Level 2:
Quoted prices in markets that are not active, or inputs which are observable,
either directly or indirectly, for substantially the full term of the asset or
liability; and
Level 3:
Prices or valuation techniques that require inputs that are both significant to
the fair value measurement and unobservable (i.e. supported by little or no
market activity).
The
following table summarizes the Company’s financial assets and liabilities that
are measured at fair value on a recurring basis and the fair value measurements
by level within the fair value hierarchy used at June 30, 2008:
|
|
|
|
|
Fair
Value Measurements Using:
|
|
(in
thousands)
|
|
Fair
Value
|
|
|
Quoted
Prices
in
Active Markets
(Level
1)
|
|
|
Significant
Other Observable Inputs
(Level
2)
|
|
|
Significant
Unobservable Inputs
(Level
3)
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments
|
|
|
$1,911 |
|
|
|
$1,911 |
|
|
|
$- |
|
|
|
$- |
|
Mark-to-market
energy assets
|
|
|
7,015 |
|
|
|
- |
|
|
|
7,015 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market
energy liabilities
|
|
|
6,478 |
|
|
|
- |
|
|
|
6,478 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
following valuation techniques were used to measure fair value assets in the
table above on a recurring basis as of June 30, 2008:
Level 1 Fair Value
Measurements:
Investments - The fair
values of these available-for-sale securities are recorded at fair value based
on unadjusted quoted prices in active markets for identical
securities.
Level 2 Fair Value
Measurements:
Mark-to-market energy assets and
liabilities - These forward contracts are valued using broker or dealer
quotations, or market transactions in either the listed or OTC
markets.
The
Company’s adoption of SFAS No. 157 applies only to its financial
instruments. The adoption did not apply to those non-financial assets and
non-financial liabilities delayed under FSP No. 157-2, which will be implemented
for the fiscal years beginning after November 15, 2009.
12.
|
Discontinued
Operations
|
During
the quarter ended September 30, 2007, the Company decided to close its
distributed energy services subsidiary, OnSight Energy, LLC (“OnSight”), as it
had experienced operating losses since its inception in 2004. As a
result of these actions, the financial data related to OnSight is presented as
discontinued operations for all periods presented. The discontinued operations
did not have any impact on the Company’s condensed consolidated financial
statements during the three and six months ended June 30, 2008 compared to net
losses of $6,000 and $26,000 for the three and six months ended June 30,
2007.
Item
2. Management’s Discussion and Analysis of Financial Condition and Results
of Operations
Management’s
Discussion and Analysis of Financial Condition and Results of Operations
(“MD&A”) is designed to provide a reader of the financial statements with a
narrative report on the Company’s financial condition, results of operations and
liquidity. This discussion and analysis should be read in conjunction with the
attached unaudited condensed consolidated financial statements and notes thereto
and Chesapeake’s Annual Report on Form 10-K for the year ended December 31,
2007, including the audited consolidated financial statements and notes
contained in the Form 10-K.
Safe
Harbor for Forward-Looking Statements
Chesapeake
Utilities Corporation has made statements in this Form 10-Q 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:
·
|
the
temperature sensitivity of the natural gas and propane
businesses;
|
·
|
the
effects of spot, forward, futures market prices, and the Company’s use of
derivative instruments on the Company’s distribution, wholesale marketing
and energy trading businesses;
|
·
|
the
amount and availability of natural gas and propane
supplies;
|
·
|
the
access to interstate pipelines’ transportation and storage capacity and
the construction of new facilities to support future
growth;
|
·
|
the
effects of natural gas and propane commodity price changes on the
operating costs and competitive positions of our natural gas and propane
distribution operations;
|
·
|
third-party
competition for the Company’s unregulated and regulated
businesses;
|
·
|
changes
in federal, state or local regulation and tax requirements, including
deregulation;
|
·
|
changes
in technology affecting the Company’s advanced information services
segment;
|
·
|
changes
in credit risk and credit requirements affecting the Company’s energy
marketing subsidiaries;
|
·
|
the
effects of accounting changes;
|
·
|
changes
in benefit plan assumptions;
|
·
|
the
cost of compliance with environmental regulations or the remediation of
environmental damage;
|
·
|
the
effects of general economic conditions, including interest rates, on the
Company and its customers;
|
·
|
the
ability of the Company’s new and planned facilities and acquisitions to
generate expected revenues;
|
·
|
the
ability of the Company to construct facilities at or below estimated
costs;
|
·
|
the
Company’s ability to obtain the rate relief and cost recovery requested
from regulators and the timing of the requested regulatory
actions;
|
·
|
the
Company’s ability to obtain necessary approvals and permits from
regulatory agencies on a timely
basis;
|
·
|
the
impact of inflation on the results of operations, cash flows, financial
position and on the Company’s planned capital
expenditures;
|
·
|
inability
to access financial markets to a degree that may impair future growth;
and
|
·
|
operating
and litigation risks that may not be covered by
insurance.
|
Overview
Chesapeake
is a diversified utility company engaged, directly or through subsidiaries, in
natural gas distribution, transmission and marketing, propane distribution and
wholesale marketing, advanced information services and other related businesses.
For additional information regarding segments, refer to Note 6, Segment
Information, of the Notes to the Condensed Consolidated Financial Statements in
this Quarterly Report on Form 10-Q.
The
Company’s strategy is focused on growing the earnings produced 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 by
leveraging our community gas system services and our bulk delivery
capabilities;
|
·
|
utilizing
the Company’s expertise across our various businesses to improve overall
performance;
|
·
|
enhancing
marketing channels to attract new
customers;
|
·
|
providing
reliable and responsive customer service to retain existing
customers;
|
·
|
maintaining
a capital structure that enables the Company to access capital as needed;
and
|
·
|
maintaining
a consistent and competitive dividend for
shareholders.
|
Due to
the seasonality of the Company’s business, results for interim periods are not
necessarily indicative of results for the entire fiscal year. Revenue and
earnings are typically greater during the Company’s first and fourth quarters,
when consumption of natural gas and propane is highest due to colder
temperatures.
Results
of Operations for the Quarter Ended June 30, 2008
The
following discussions on operating income and segment results for the three
months ended June 30, 2008 and 2007 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 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 performance of its business units and has historically analyzed and
reported gross margin information publicly. Other companies may calculate gross
margin in a different manner.
Consolidated
Overview
The
Company’s net income for the quarter ended June 30, 2008 increased $337,000, or
23 percent, compared to the same period in 2007. The Company earned a net income
of approximately $1.8 million, or $0.27 per share (diluted) during the quarter
compared to a net income of approximately $1.5 million, or $0.22 per share
(diluted) during the same quarter in 2007.
|
|
|
|
|
|
|
|
|
|
For
the Three Months Ended June 30,
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
Net
Income (Loss)
|
|
|
|
|
|
|
|
|
|
Continuing
operations
|
|
$ |
1,818,924 |
|
|
$ |
1,487,681 |
|
|
$ |
331,243 |
|
Discontinued
operations
|
|
|
- |
|
|
|
(5,891 |
) |
|
|
5,891 |
|
Total
Net Income
|
|
$ |
1,818,924 |
|
|
$ |
1,481,790 |
|
|
$ |
337,134 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
Earnings Per Share
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing
operations
|
|
$ |
0.27 |
|
|
$ |
0.22 |
|
|
$ |
0.05 |
|
Discontinued
operations
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
Diluted Earnings Per Share
|
|
$ |
0.27 |
|
|
$ |
0.22 |
|
|
$ |
0.05 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
When
compared to the second quarter of 2007, the Company was able to increase net
income for the second quarter of 2008 by $337,000, despite taking a charge of
$1.2 million to other operating expense in 2008 for costs relating to an
unconsummated acquisition. The Company initiated discussions in the
third quarter of 2007 with a potential acquisition target. These
discussions continued through the first part of the second quarter of 2008, at
which time, we determined that we would not be able to complete the acquisition.
In the course of these negotiations, the Company incurred certain accounting,
legal and other professional fees and expenses, which were expensed in the
second quarter of 2008 in accordance with SFAS 141 “Business
Combinations.” Absent the charge for the unconsummated acquisition,
the Company estimates that net income would have increased by $1.1 million in
the second quarter to $2.6 million, or $0.37 per share (diluted), compared to
the same period in 2007.
The
period-over-period increase in net income reflects higher operating income from
the Company’s natural gas segment and lower interest expense, partially offset
by a decrease in other income.
|
|
|
|
|
|
|
|
|
|
For
the Three Months Ended June 30,
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
Operating
Income
|
|
|
|
|
|
|
|
|
|
Natural
Gas
|
|
$ |
4,736,363 |
|
|
$ |
3,992,282 |
|
|
$ |
744,081 |
|
Propane
|
|
|
(624,699 |
) |
|
|
(545,898 |
) |
|
|
(78,801 |
) |
Advanced
Information Services
|
|
|
137,077 |
|
|
|
178,708 |
|
|
|
(41,631 |
) |
Other
& Eliminations
|
|
|
80,698 |
|
|
|
72,973 |
|
|
|
7,725 |
|
Operating
Income
|
|
|
4,329,439 |
|
|
|
3,698,065 |
|
|
|
631,374 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income
|
|
|
63,507 |
|
|
|
234,194 |
|
|
|
(170,687 |
) |
Interest
Charges
|
|
|
1,388,735 |
|
|
|
1,594,701 |
|
|
|
(205,966 |
) |
Income
Taxes
|
|
|
1,185,287 |
|
|
|
849,877 |
|
|
|
335,410 |
|
Net
Income from Continuing Operations
|
|
$ |
1,818,924 |
|
|
$ |
1,487,681 |
|
|
$ |
331,243 |
|
The
period-over-period increase in operating income resulted primarily from the
following:
·
|
Growth
in the number of customers and improved supply management techniques
produced a period-over-period increase of 96 percent in gross margin for
the Company’s natural gas marketing
operation.
|
·
|
Rate
increases, lower depreciation allowances and lower asset removal cost
allowances, approved in rate proceedings for the Company’s Delmarva
natural gas distribution and natural gas transmission operations,
contributed $653,000 to operating income for the natural gas segment in
the second quarter of 2008
|
·
|
The
Company’s natural gas transmission and Delmarva natural gas distribution
operations experienced a combined increase in interruptible service
revenue of $392,000, net of required margin-sharing, in the second quarter
of 2008 compared to the same period in
2007.
|
·
|
New
transportation capacity contracts implemented for the natural gas
transmission operation in November 2007 provided $299,000 of additional
gross margin in the second quarter of
2008.
|
·
|
Despite
a slowdown in the new housing market as a result of the unfavorable
economic conditions in that market, the Delmarva natural gas distribution
operations continued to experience strong period-over-period customer
growth with a five-percent increase in residential customers over the
second quarter of 2007. In addition, the Delmarva natural gas
distribution operations have been able to offset partially this slowdown
with growth in commercial customers. Overall, these growth
factors contributed $290,000 to the increase in gross margins for the
Delmarva natural gas distribution operations in the second quarter of
2008. .
|
·
|
The
average gross margin per retail gallon sold to customers increased $0.10
in the second quarter of 2008 for the Delmarva propane distribution
operations, which contributed $307,000 to gross margins. This
increase was partially offset by a decrease to gross margin of $222,000 as
the Delmarva propane distribution operations experienced lower volumes
delivered to customers during the second quarter of 2008 compared to the
same period in 2007.
|
·
|
Volatile
wholesale propane prices in the second quarter of 2008 contributed to the
gross margin increase of $207,000 for the Company’s propane wholesale and
marketing operation.
|
Natural
Gas
The
natural gas segment earned operating income of $4.7 million for the second
quarter in 2008 compared to $4.0 million for the corresponding quarter in 2007,
an increase of $744,000, or 19 percent.
For
the Three Months Ended June 30,
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
Revenue
|
|
$ |
53,878,479 |
|
|
$ |
39,365,754 |
|
|
$ |
14,512,725 |
|
Cost
of sales
|
|
|
38,945,802 |
|
|
|
26,130,962 |
|
|
|
12,814,840 |
|
Gross
margin
|
|
|
14,932,677 |
|
|
|
13,234,792 |
|
|
|
1,697,885 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
& maintenance
|
|
|
6,524,529 |
|
|
|
6,440,171 |
|
|
|
84,358 |
|
Terminated
acquisition costs
|
|
|
890,053 |
|
|
|
- |
|
|
|
890,053 |
|
Depreciation
& amortization
|
|
|
1,654,980 |
|
|
|
1,834,712 |
|
|
|
(179,732 |
) |
Other
taxes
|
|
|
1,126,752 |
|
|
|
967,627 |
|
|
|
159,125 |
|
Other
operating expenses
|
|
|
10,196,314 |
|
|
|
9,242,510 |
|
|
|
953,804 |
|
Total
Operating Income
|
|
$ |
4,736,363 |
|
|
$ |
3,992,282 |
|
|
$ |
744,081 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statistical
Data — Delmarva Peninsula
|
|
|
|
|
|
|
|
|
|
Heating
degree-days ("HDD"):
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
|
|
|
481 |
|
|
|
527 |
|
|
|
(46 |
) |
10-year
average (normal)
|
|
|
490 |
|
|
|
496 |
|
|
|
(6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
gross margin per HDD
|
|
$ |
1,937 |
|
|
$ |
2,283 |
|
|
$ |
(346 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Per
residential customer added:
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
gross margin
|
|
$ |
372 |
|
|
$ |
372 |
|
|
$ |
0 |
|
Estimated
other operating expenses
|
|
$ |
106 |
|
|
$ |
106 |
|
|
$ |
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
Customer Information
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
number of customers:
|
|
|
|
|
|
|
|
|
|
|
|
|
Delmarva
|
|
|
45,540 |
|
|
|
43,331 |
|
|
|
2,209 |
|
Florida
|
|
|
13,463 |
|
|
|
13,361 |
|
|
|
102 |
|
Total
|
|
|
59,003 |
|
|
|
56,692 |
|
|
|
2,311 |
|
Gross
margin for the Company’s natural gas segment increased by $1.7 million, or 13
percent, and other operating expenses increased by $954,000, or 10 percent, for
the second quarter in 2008 compared to the same period in 2007. The gross margin
increases of $683,000 for the natural gas transmission operation, $556,000 for
the natural gas distribution operations and $459,000 for the natural gas
marketing operation are further explained below.
Natural Gas
Transmission
The
natural gas transmission operation achieved gross margin growth of $683,000, or
13 percent, in the second quarter of 2008 compared to the same period in
2007. The significant items contributing to the increase in gross
margin include the following:
·
|
New
transportation capacity contracts implemented in November 2007 contributed
$299,000 to gross margin in the second quarter of 2008 and are expected to
generate a total annual increase in gross margin of $1.2 million above
2007 gross margin.
|
·
|
Interruptible
revenue, net of required margin-sharing, increased $324,000 in the second
quarter of 2008 compared to the same period in
2007. Interruptible customers include large industrial
customers whose service can be temporarily interrupted when necessary to
meet the needs of firm customers. For the remainder of 2008,
however, the Company expects its natural gas transmission operation to
report a decrease of $192,000 in interruptible services revenue, compared
to the corresponding period in 2007, because the operation reached its
margin-sharing threshold in the second quarter of 2008; in 2007, it
reached the threshold in the fourth quarter. Currently
effective settlements in rate proceedings require the Company, upon
reaching the margin-sharing threshold, to share 90% of its interruptible
natural gas transmission revenues with its
customers.
|
·
|
The
implementation of rate case settlement rates, effective September 1, 2007,
contributed an additional $42,000 to gross margins in the second quarter
of 2008 compared to the same period in 2007. The
period-over-period increase in gross margin would have been larger, but
for temporary implementation in May 2007 of rates, which were subject to
refund, when the settled rates became effective on September 1,
2007. A further discussion of the FERC rate proceeding is
provided within the “Rates and Regulatory” section of Note 4, “Commitments
and Contingencies,” to these unaudited Condensed Consolidated Financial
Statements.
|
·
|
The
remaining $18,000 increase in gross margin in the second quarter of 2008
is attributable to other various minor
factors.
|
An
increase of $372,000 in other operating expenses partially offset the increased
gross margin. The factors contributing to the increase in other operating
expenses are as follow:
·
|
Corporate
costs allocated to the natural gas transmission operation increased
$411,000 as a result of: (1) $341,000 for the allocation of a portion of
the terminated acquisition costs previously discussed, and (2) the Company
updating its annual corporate cost
allocations.
|
·
|
Incentive
compensation costs increased by $61,000 as a result of the improved
operating results in 2008 compared to
2007.
|
·
|
Rent
and utility expenses increased $44,000 and $18,000, respectively, as
Eastern Shore began incurring additional rental expense in January 2008
for a new office building.
|
·
|
The
increased level of capital investment caused increased property taxes of
$75,000.
|
·
|
Partially
offsetting the previously mentioned increases was a decrease of $118,000
in depreciation expense and a decrease of $61,000 in regulatory
expense. Both of these lower expenses are a result of the 2007
rate case. As part of the rate case settlement that became
effective September 1, 2007, the FERC approved a reduction in depreciation
rates for Eastern Shore. Also, the Company incurred regulatory expenses
in the second quarter of 2007 associated with the FERC rate
proceeding.
|
·
|
Other
operating expenses relating to various items decreased collectively by
approximately $58,000.
|
Natural Gas
Distribution
Gross
margin for the Company’s natural gas distribution operations increased by
$556,000, or seven percent, for the second quarter in 2008 compared to the same
period in 2007. The gross margin increases of $481,000 for the Delmarva natural
gas distribution operations and $75,000 for the Florida natural gas distribution
operations are further explained below.
The
Delmarva distribution operations experienced an increase of $481,000, or 10
percent, in gross margin. The significant items contributing to the increase in
gross margin include the following:
·
|
Continued
residential and commercial customer growth contributed to increases in
gross margin. Although the Company continues to see a slowdown
in the new housing market as a result of the unfavorable market conditions
in the housing market, the average number of residential customers on the
Delmarva Peninsula increased by 2,209, or five percent, for the second
quarter of 2008 compared to the same period in 2007, and the Company
estimates that these additional residential customers contributed
approximately $180,000 to gross margin during the second quarter of
2008. The
Company further estimates that a two percent growth in the number of its
commercial customers during the second quarter of 2008 compared to the
same period in 2007 contributed approximately $93,000 to gross margin
during the second quarter of
2008.
|
·
|
The
Company’s estimate for unbilled revenue for the second quarter of 2008
contributed $263,000 more to gross margin than normal, partially due to
the warmer weather experienced during the first quarter of
2008.
|
|
Interruptible
sales revenue, net of required margin-sharing, increased $68,000 in the
second quarter of 2008 compared to the same period in 2007, as customers
took advantage of lower natural gas prices in comparison to prices for
alternative fuels.
|
·
|
Partially
offsetting these increases to gross margin was the negative impact of
lower
consumption per customer that reflects customer conservation efforts in
light of higher energy costs and more energy-efficient
housing. The Company estimates that lower consumption
reduced margins by $56,000 in the second quarter of
2008.
|
·
|
The
remaining $61,000 net increase in gross margin can be attributed to
various factors, including the implementation of temporary rates by the
Delaware division and lower industrial
volumes.
|
Gross
margin for the Florida distribution operation increased by $75,000, or three
percent, in the second quarter of 2008 compared to the same period in
2007. This increase in gross margin is primarily due to higher
volumes sold to non-residential customers and higher revenues from third-party
natural gas marketers.
Other
operating expense for the natural gas distribution operations increased by
$582,000 in the second quarter of 2008 compared to the same period in 2007.
Among the key components of the increase were the following:
·
|
Corporate
costs allocated to the natural gas distribution operations increased
$678,000 primarily due to $533,000 for the allocation of a portion of the
terminated acquisition costs previously
discussed.
|
·
|
Incentive
compensation increased $121,000 in the second quarter of 2008 as the
Delmarva operations experienced improved earnings compared to the prior
year.
|
·
|
Property
taxes increased by $57,000 as a result of the Company’s continued capital
investments.
|
·
|
The
allowance for uncollectible accounts increased $86,000 in 2008 compared to
2007 as a result of the adjustments to the reserve balances for historical
collection practices.
|
·
|
Depreciation
expense and asset removal costs decreased $58,000 and $357,000,
respectively, in the second quarter of 2008 compared to the same period in
2007, primarily as a result of the Delmarva operations’s rate
proceedings. These rate proceedings provided for lower
depreciation allowances and lower asset removal cost allowances, which
resulted in reductions of $95,000 and $409,000 in depreciation expense and
asset removal costs during the second quarter of 2008. A portion of this
reduction, or $77,000, represents adjustments to the amount reserved for
refund as of March 31, 2008 based on the depreciation and asset removal
cost allowances contained in the negotiated settlement
agreements. As part of the Delaware division’s rate
case, the Delaware PSC granted the Company permission to lower the
depreciation and asset removal costs for its
assets.
|
·
|
In
addition, other operating expenses relating to various minor items
increased by approximately $55,000.
|
Natural Gas
Marketing
Gross
margin for the natural gas marketing operation increased by $459,000, or 96
percent, for the second quarter of 2008 compared to the same period in 2007. The
increase in gross margin was primarily the result of growth in the number of
customers to which it provides supply management services and improved gas
supply management techniques. Other operating expenses decreased
slightly by $2,000 for the marketing operation; this decrease is attributable to
lower payroll-related costs and benefits, which was partially offset by higher
incentive compensation and higher corporate costs as $16,000 was allocated to
the operation for a portion the terminated acquisition costs.
Propane
The
propane segment experienced a decrease of $79,000, or 14 percent, in operating
income for the second quarter of 2008 compared to the same period in 2007. Gross
margin increased by $390,000, which was more than offset by an increase in other
operating expenses of $469,000. Absent the terminated acquisition
costs of $273,000 allocated to the propane segment, it would have reduced its
operating loss by $194,000, or 35 percent, for the second quarter of 2008
compared to the same period in 2007.
For
the Three Months Ended June 30,
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
Revenue
|
|
$ |
11,488,807 |
|
|
$ |
9,494,170 |
|
|
$ |
1,994,637 |
|
Cost
of sales
|
|
|
7,534,539 |
|
|
|
5,930,398 |
|
|
|
1,604,141 |
|
Gross
margin
|
|
|
3,954,268 |
|
|
|
3,563,772 |
|
|
|
390,496 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
& maintenance
|
|
|
3,624,049 |
|
|
|
3,463,047 |
|
|
|
161,002 |
|
Terminated
acquisition costs
|
|
|
272,718 |
|
|
|
- |
|
|
|
272,718 |
|
Depreciation
& amortization
|
|
|
503,929 |
|
|
|
458,788 |
|
|
|
45,141 |
|
Other
taxes
|
|
|
178,271 |
|
|
|
187,835 |
|
|
|
(9,564 |
) |
Other
operating expenses
|
|
|
4,578,967 |
|
|
|
4,109,670 |
|
|
|
469,297 |
|
Total
Operating Loss
|
|
$ |
(624,699 |
) |
|
$ |
(545,898 |
) |
|
$ |
(78,801 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statistical
Data — Delmarva Peninsula
|
|
|
|
|
|
|
|
|
|
Heating
degree-days ("HDD"):
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
|
|
|
481 |
|
|
|
527 |
|
|
|
(46 |
) |
10-year
average (normal)
|
|
|
490 |
|
|
|
496 |
|
|
|
(6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
gross margin per HDD
|
|
$ |
2,465 |
|
|
$ |
1,974 |
|
|
$ |
491 |
|
The
period-over-period decrease in operating income was due to higher other
operating expenses, which resulted from the allocation of a portion of the
terminated acquisition costs in the second quarter of 2008. Absent
these costs, the propane segment would have earned a period-over-period increase
in operating income of $194,000. The gross margin increases of
$182,000 for the Delmarva propane distribution operations, $2,000 for the
Florida propane distribution operations and $207,000 for the propane wholesale
and marketing operation, are further explained below.
Delmarva Propane
Distribution
The
Delmarva propane distribution operation’s increase in gross margin of $182,000
resulted from the following:
·
|
Gross
margin increased by $307,000 in the second quarter of 2008, compared to
the same period in 2007, because of a $0.10 increase in the average gross
margin per retail gallon. This increase occurs when market prices rise at
a greater rate than the Company’s inventory price per gallon. This trend
reverses, as it did in the first quarter of 2008, when market prices of
propane decrease and move closer to the Company’s average inventory price
per gallon.
|
·
|
Temperatures
on the Delmarva Peninsula were nine percent warmer in the second quarter
of 2008 compared to the same period in 2007, which contributed to a
decrease of 156,000 gallons, or five percent, sold during this period in
2008 compared to the same period in 2007. The Company estimates that the
warmer weather and decreased volumes sold had a negative impact of
approximately $113,000 for the Delmarva propane distribution operation
compared to the second quarter of
2007.
|
·
|
Non-weather-related
volumes sold in the second quarter of 2008 decreased by 176,000 gallons,
or five percent. This decrease in gallons sold reduced gross
margin by approximately $109,000 for the Delmarva propane distribution
operation compared to the second quarter of 2007. Contributing
to this decrease in gallons sold was customer conservation, a reduced
number of customers and the timing of propane
deliveries.
|
·
|
The
remaining $97,000 increase in gross margin can be attributed to various
other factors, such as higher tank and meter rental
fees.
|
Total
other operating expenses increased by $358,000 for the Delmarva propane
operations in the second quarter of 2008, compared to the same period in 2007.
The significant items contributing to this increase are explained
below:
·
|
Corporate
costs allocable to the propane distribution operations increased $338,000
as a result of: (1) $227,000 for the allocation of a portion of the
terminated acquisition costs previously discussed, and (2) the Company
updating its annual corporate cost
allocations.
|
·
|
Vehicle
fuel increased $53,000 as a result of rising gasoline and diesel fuel
costs.
|
·
|
The
allowance for uncollectable accounts increased $31,000 due to increased
revenues resulting from the higher cost of
propane.
|
·
|
Customer charges
increased by $26,000 in the second quarter 2008 compared to the same
period 2007 as a result of added Community Gas Systems (“CGS”) customers.
This expenditure will continue to increase as more CGS customers are
added.
|
·
|
Depreciation
and amortization expense increased by $19,000 as a result of the Company’s
increase in capital investments over the prior
year.
|
·
|
The
operation experienced lower expenses of $121,000 in the second quarter of
2008 compared to the same period in 2007 for propane tank recertifications
and maintenance. The Company incurred these costs in 2007 to
maintain compliance with U.S. Department of Transportation (“DOT”)
standards, which requires propane tanks or cylinders to be recertified
twelve years from their date of manufacture and every five years after
that.
|
·
|
In
addition, other operating expenses relating to various items increased
collectively by approximately
$12,000.
|
Florida Propane
Distribution
The
Florida propane distribution operation experienced a slight increase in gross
margin of $2,000, or one percent, in the second quarter of 2008 compared to the
same period in 2007. The higher gross margin is attributable to an
increase of $15,000 based upon a higher average gross margin per retail gallon,
which was partially offset by a decrease of $13,000 in service
sales. Other operating expenses in the second quarter of 2008,
compared to the same period in 2007, increased by $65,000, primarily due to
increases in depreciation expense, allowance for uncollectible accounts and
increased corporate costs as $20,000 was allocated to the operations for a
portion of the terminated acquisition costs.
Propane Wholesale and
Marketing
Gross
margin for the Company’s propane wholesale marketing operation increased by
$207,000, or 35 percent, in the second quarter of 2008 compared to the same
period in 2007. This increase reflects the larger number of market opportunities
that arose in the second quarter of 2008 due to price volatility in the propane
wholesale market, which exceeded the level of price fluctuations experienced in
2007. The increase in gross margin was partially offset by higher
other operating expenses of $46,000, due primarily to higher payroll costs,
including incentive compensation, and increased corporate costs as $26,000 was
allocated to the operation for a portion of the terminated acquisition
costs.
Advanced
Information Services
The
advanced information services segment experienced gross margin growth of
approximately $114,000, or seven percent, and contributed operating income of
$137,000 for the second quarter of 2008, a decrease of $42,000 compared to the
same period in 2007. Absent the terminated acquisition costs of
$64,000 allocated to the advanced information segment, it would have increased
its operating income by $22,000, or 13 percent, for the second quarter of 2008
compared to the same period in 2007.
|
|
|
|
|
|
|
|
|
|
For
the Three Months Ended June 30,
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
Revenue
|
|
$ |
3,822,274 |
|
|
$ |
3,816,074 |
|
|
$ |
6,200 |
|
Cost
of sales
|
|
|
2,059,375 |
|
|
|
2,166,963 |
|
|
|
(107,588 |
) |
Gross
margin
|
|
|
1,762,899 |
|
|
|
1,649,111 |
|
|
|
113,788 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
& maintenance
|
|
|
1,363,082 |
|
|
|
1,273,239 |
|
|
|
89,843 |
|
Terminated
acquisition costs
|
|
|
64,461 |
|
|
|
- |
|
|
|
64,461 |
|
Depreciation
& amortization
|
|
|
38,583 |
|
|
|
35,248 |
|
|
|
3,335 |
|
Other
taxes
|
|
|
159,696 |
|
|
|
161,916 |
|
|
|
(2,220 |
) |
Other
operating expenses
|
|
|
1,625,822 |
|
|
|
1,470,403 |
|
|
|
155,419 |
|
Total
Operating Income
|
|
$ |
137,077 |
|
|
$ |
178,708 |
|
|
$ |
(41,631 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
The
period-over-period increase in gross margin was attributable to lower cost of
sales. Cost of sales decreased by $108,000 as the number of billable
employees was reduced. Also, lower reimbursable expenses contributed
to the reduction in cost of sales as employees performed less travel during the
period.
Other
operating expenses increased by $155,000 in the second quarter of 2008, compared
to the same period in 2007. This increase in operating expenses is attributable
to payroll costs, payroll taxes, and increased corporate costs as $64,000 was
allocated to the segment for a portion of the terminated acquisition costs.
Payroll costs increased as a result of the increase in non-billable staffing
levels added to support future growth.
Other
Business Operations and Eliminations
Other
operations, consisting primarily of subsidiaries that own real estate leased to
other Company subsidiaries, generated an operating income of approximately
$81,000 for the second quarter of 2008 compared to an operating income of
approximately $73,000 for the same period in 2007.
|
|
|
|
|
|
|
|
|
|
For
the Three Months Ended June 30,
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
Revenue
|
|
$ |
163,074 |
|
|
$ |
154,623 |
|
|
$ |
8,451 |
|
Cost
of sales
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Gross
margin
|
|
|
163,074 |
|
|
|
154,623 |
|
|
|
8,451 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
& maintenance
|
|
|
29,784 |
|
|
|
28,004 |
|
|
|
1,780 |
|
Terminated
acquisition costs
|
|
|
12,396 |
|
|
|
- |
|
|
|
12,396 |
|
Depreciation
& amortization
|
|
|
28,622 |
|
|
|
39,545 |
|
|
|
(10,923 |
) |
Other
taxes
|
|
|
12,344 |
|
|
|
14,871 |
|
|
|
(2,527 |
) |
Other
operating expenses
|
|
|
83,146 |
|
|
|
82,420 |
|
|
|
726 |
|
Operating
Income - Other
|
|
|
79,928 |
|
|
|
72,203 |
|
|
|
7,725 |
|
Operating Income -
Eliminations
(1)
|
|
|
770 |
|
|
|
770 |
|
|
|
- |
|
Total
Operating Income
|
|
$ |
80,698 |
|
|
$ |
72,973 |
|
|
$ |
7,725 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Eliminations are entries required to eliminate activities between segments from
the consolidated results.
Interest
Expense
Total
interest expense for the second quarter of 2008 decreased by approximately
$206,000, or approximately 13 percent, compared to the same period in 2007. The
lower interest expense is a result of the following developments:
·
|
Interest
on short-term borrowings increased $44,000 in the second quarter of 2008
compared to the same period in 2007, based upon an increase of $21.2
million in the Company’s average short-term borrowing
balance. The impact of the higher borrowing was partially
offset by a lower weighted average interest rate that was nearly three
percentage points lower in 2008 and the amount of interest capitalized
during the period. The Company’s average short-term borrowing during the
second quarter of 2008 was $35.3 million with a weighted average interest
rate of 2.51 percent, compared to $14.1 million with a weighted average
interest rate of 5.74 percent for the same period in
2007.
|
·
|
Interest
on long-term debt decreased $141,000 in the second quarter of 2008
compared to the same period in 2007 as the Company reduced its average
long-term debt balance by $7.8 million. The Company’s average
long-term debt during the second quarter of 2008 was $69.8 million with a
weighted average interest rate of 6.61 percent, compared to $77.6 million
with a weighted average interest rate of 6.67 percent for the same period
in 2007.
|
·
|
Interest
expense for other items, such as interest on refunds to customers and
meter deposits, increased $31,000 in the second quarter of 2008 compared
to the corresponding period in
2007.
|
Income
Taxes
Income
tax expense for the second quarter of 2008 was $1.2 million compared to $850,000
for the second quarter of 2007. The increase in income tax expense primarily
reflects the higher earnings for the period and an increase of $50,000 to our
tax accrual for uncertain tax positions as defined by FIN 48,” related to our
2005 tax return that is currently under audit by the IRS. The effective tax rate
for the second quarter of 2008 is 39.5 percent compared to an effective tax rate
of 36.4 percent for the second quarter of 2007.
Results
of Operations for the Six Months Ended June 30, 2008
The
following discussions on operating income and segment results for the six months
ended June 30, 2008 and 2007 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 is
determined in accordance with 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
performance of its business units and has historically analyzed and reported
gross margin information publicly. Other companies may calculate gross margin in
a different manner.
Consolidated
Overview
The
Company experienced a slight decrease of $80,000, or less than one percent, in
net income for the six months ended June 30, 2008, compared to the same period
in 2007. Earnings per share decreased by $0.03 per share (diluted) in
the first six months of 2008 to $1.36 per share (diluted), compared to $1.39 per
share (diluted) in 2007, due to an increased number of shares outstanding in
2008.
For
the Six Months Ended June 30,
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
Net
Income
|
|
|
|
|
|
|
|
|
|
Continuing
operations
|
|
$ |
9,393,266 |
|
|
$ |
9,499,162 |
|
|
$ |
(105,896 |
) |
Discontinued
operations
|
|
|
- |
|
|
|
(26,284 |
) |
|
|
26,284 |
|
Total
Net Income
|
|
$ |
9,393,266 |
|
|
$ |
9,472,878 |
|
|
$ |
(79,612 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
Earnings (Loss) Per Share
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing
operations
|
|
$ |
1.36 |
|
|
$ |
1.39 |
|
|
$ |
(0.03 |
) |
Discontinued
operations
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
Diluted Earnings Per Share
|
|
$ |
1.36 |
|
|
$ |
1.39 |
|
|
$ |
(0.03 |
) |
The
period-over-period decreases in net income reflects higher income taxes and
lower other income, which were partially offset by a slight increase in
operating income and a decrease in interest expense. Operating income
increased by $59,000 to $18.4 million for the first six months of 2008 compared
to $18.3 million for the same period in 2007, as the gross margin increase of
$1.9 million, or four percent, was almost completely offset by an increase in
other operating expenses. The increase in gross margin was driven
primarily by continued growth, increased interruptible services revenue, and
increased rates for the natural gas segment, partially offset by warmer weather
on the Delmarva Peninsula and lower non-weather-related sales volumes and margin
per gallon for the propane segment. Contributing to the higher
operating expenses in 2008 was the $1.2 million of costs associated with the
unconsummated acquisition in the second quarter of 2008.
|
|
|
|
|
|
|
|
|
|
For
the Six Months Ended June 30,
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
Operating
Income
|
|
|
|
|
|
|
|
|
|
Natural
Gas
|
|
$ |
15,205,387 |
|
|
$ |
13,608,264 |
|
|
$ |
1,597,123 |
|
Propane
|
|
|
2,819,436 |
|
|
|
4,327,658 |
|
|
|
(1,508,222 |
) |
Advanced
Information Services
|
|
|
174,941 |
|
|
|
227,528 |
|
|
|
(52,587 |
) |
Other
& Eliminations
|
|
|
170,390 |
|
|
|
148,187 |
|
|
|
22,203 |
|
Operating
Income
|
|
|
18,370,154 |
|
|
|
18,311,637 |
|
|
|
58,517 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income
|
|
|
81,097 |
|
|
|
290,675 |
|
|
|
(209,578 |
) |
Interest
Charges
|
|
|
2,982,106 |
|
|
|
3,193,951 |
|
|
|
(211,845 |
) |
Income
Taxes
|
|
|
6,075,879 |
|
|
|
5,909,199 |
|
|
|
166,680 |
|
Net
Income from Continuing Operations
|
|
$ |
9,393,266 |
|
|
$ |
9,499,162 |
|
|
$ |
(105,896 |
) |
The
period-over-period increase in operating income resulted primarily from the
following:
·
|
Growth
in the number of customers, improved supply management techniques and
favorable imbalance resolutions with interstate pipelines produced a
higher gross margin of $618,000 for the Company’s natural gas marketing
operation.
|
·
|
The
Company’s natural gas transmission and Delmarva natural gas distribution
operations experienced a combined increased in interruptible services
revenue, net of required margin-sharing, of $610,000 in the first six
months of 2008 compared to the same period in
2007.
|
·
|
New
transportation capacity contracts implemented for the natural gas
transmission operation in November 2007 provided for $591,000 of
additional gross margin in the first six months of
2008.
|
·
|
Period-over-period
residential and commercial customer growth of five percent and two
percent, respectively, for the Delmarva natural gas distribution
operations in 2008.
|
·
|
Rate
increases, lower depreciation allowances and lower asset removal cost
allowances contributed $1.7 million to operating income for the natural
gas segment in the first six months of 2008 as a result of rate
proceedings for the Company’s Delmarva natural gas distribution and
natural gas transmission
operations.
|
·
|
Partially
offsetting these increases in gross margin was the negative impact that
warmer weather on the Delmarva Peninsula had on gross margin for the
Delmarva natural gas and propane distribution operations. In
addition, gross margin from the propane segment decreased as the Delmarva
distribution operations experienced lower non-weather related sales
volumes and decreases in the average gross margin per retail
gallon.
|
Natural
Gas
The
natural gas segment earned operating income of $15.2 million for the first six
months in 2008 compared to $13.6 million for the corresponding period in 2007,
an increase of $1.6 million, or 12 percent.
For
the Six Months Ended June 30,
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
Revenue
|
|
$ |
122,806,861 |
|
|
$ |
104,875,421 |
|
|
$ |
17,931,440 |
|
Cost
of sales
|
|
|
88,263,342 |
|
|
|
72,899,708 |
|
|
|
15,363,634 |
|
Gross
margin
|
|
|
34,543,519 |
|
|
|
31,975,713 |
|
|
|
2,567,806 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
& maintenance
|
|
|
12,790,761 |
|
|
|
12,703,572 |
|
|
|
87,189 |
|
Terminated
acquisition costs
|
|
|
890,053 |
|
|
|
- |
|
|
|
890,053 |
|
Depreciation
& amortization
|
|
|
3,294,659 |
|
|
|
3,630,193 |
|
|
|
(335,534 |
) |
Other
taxes
|
|
|
2,362,659 |
|
|
|
2,033,684 |
|
|
|
328,975 |
|
Other
operating expenses
|
|
|
19,338,132 |
|
|
|
18,367,449 |
|
|
|
970,683 |
|
Total
Operating Income
|
|
$ |
15,205,387 |
|
|
$ |
13,608,264 |
|
|
$ |
1,597,123 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statistical
Data — Delmarva Peninsula
|
|
|
|
|
|
|
|
|
|
|
|
|
Heating
degree-days ("HDD"):
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
|
|
|
2,703 |
|
|
|
2,966 |
|
|
|
(263 |
) |
10-year
average (normal)
|
|
|
2,760 |
|
|
|
2,737 |
|
|
|
23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
gross margin per HDD
|
|
$ |
1,937 |
|
|
$ |
2,283 |
|
|
$ |
(346 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Per
residential customer added:
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
gross margin
|
|
$ |
372 |
|
|
$ |
372 |
|
|
$ |
0 |
|
Estimated
other operating expenses
|
|
$ |
106 |
|
|
$ |
106 |
|
|
$ |
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
Customer Information
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
number of customers:
|
|
|
|
|
|
|
|
|
|
|
|
|
Delmarva
|
|
|
45,778 |
|
|
|
43,471 |
|
|
|
2,307 |
|
Florida
|
|
|
13,517 |
|
|
|
13,311 |
|
|
|
206 |
|
Total
|
|
|
59,295 |
|
|
|
56,782 |
|
|
|
2,513 |
|
Gross
margin for the Company’s natural gas segment increased by $2.6 million, or eight
percent, and other operating expenses increased by $971,000, or five percent,
for the first six months of 2008 compared to the same period in 2007. The gross
margin increases of $1.3 million for the natural gas transmission operation,
$667,000 for the natural gas distribution operations and $618,000 for the
natural gas marketing operation, are further explained below.
Natural Gas
Transmission
The
natural gas transmission operation achieved gross margin growth of $1.3 million,
or 12 percent, in the first six months of 2008 compared to the same period in
2007. The significant items contributing to the increase in gross
margin include the following:
·
|
New
transportation capacity contracts implemented in November 2007 contributed
$591,000 to gross margin in the first six months of 2008. In 2008, these
new transportation capacity contracts are expected to generate an
additional annual gross margin of $1.2 million above 2007 gross
margin.
|
·
|
Interruptible
sales revenue, net of required margin-sharing, increased $328,000 in the
first six months of 2008 compared to the same period in
2007. Interruptible customers include large industrial
customers whose service can be temporarily interrupted when necessary to
meet the needs of firm customers. For the remainder of 2008,
however, the Company expects its natural gas transmission operation to
report a decrease of $192,000 in interruptible services revenue, compared
to the corresponding period in 2007, because the operation reached its
margin-sharing threshold in the second quarter of 2008; in 2007, it
reached the threshold in the fourth quarter. Currently
effective settlements in rate proceedings require the Company, upon
reaching the margin-sharing threshold, to share 90% of its interruptible
natural gas transmission revenues with its
customers.
|
·
|
The
implementation of rate case settlement rates, effective September 1, 2007,
contributed an additional $315,000 to gross margins in the first six
months of 2008 compared to the same period in 2007. A further
discussion of the FERC rate proceeding is provided within the “Rates and
Regulatory” section of Note 4, “Commitments and Contingencies,” to the
unaudited Condensed Consolidated Financial
Statements.
|
·
|
The
remaining $50,000 increase to gross margin is attributable to various
other items.
|
An
increase of $602,000 in other operating expenses partially offset the increased
gross margin. The factors contributing to the increase in other operating
expenses include the following:
·
|
Corporate
costs allocated to the natural gas transmission operation increased
$543,000 as a result of: (1) $341,000 for the allocation of a portion of
the terminated acquisition costs previously discussed, and (2) the Company
updating its annual corporate cost
allocations.
|
·
|
Incentive
compensation costs increased by $49,000 as a result of the improved
operating results in 2008 compared to
2007.
|
·
|
Rent
and utility expenses increased $88,000 and $39,000, respectively, as
Eastern Shore began incurring additional rental expense in January 2008
for a new office building.
|
·
|
The
increased level of capital investment caused increased property taxes of
$148,000.
|
·
|
Eastern
Shore experienced increased costs of $40,000 for line locating in the
first six months of 2008 compared to the same period in
2007.
|
·
|
Other
operating expenses relating to various items increased collectively by
approximately $45,000.
|
·
|
Partially
offsetting the previously mentioned increases was a decrease of $230,000
in depreciation expense and a decrease of $120,000 in regulatory
expense. Both of these lower expenses are a result of the 2007
rate case. As part of the rate case settlement that became
effective September 1, 2007, the FERC approved a reduction in depreciation
rates for Eastern Shore. Also, the Company incurred regulatory expenses
in the first six months of 2007 associated with the FERC rate
proceeding.
|
Natural Gas
Distribution
Gross
margin for the Company’s natural gas distribution operations increased by
$667,000, or three percent, for the first six months of 2008 compared to the
same period in 2007. The gross margin increases of $565,000 for the Delmarva
natural gas distribution operations and $102,000 for the Florida natural gas
distribution operations are further explained below.
The
Delmarva distribution operations experienced an increase of $565,000, or four
percent, in gross margin. The significant items contributing to the increase in
gross margin include the following:
·
|
Continued
residential and commercial customer growth contributed to increases in
gross margin. Although the Company continues to
see a slowdown in the new housing market as a result of unfavorable market
conditions in the housing industry, the average number of
residential customers on the Delmarva Peninsula increased by 2,307, or
five percent, for the first six months of 2008 compared to the same period
in 2007, and the Company estimates that these additional residential
customers contributed approximately $518,000 to gross margin during the
first six months of 2008. The Company further
estimates that a two percent growth in the number of the Company’s
commercial customers during the first six months of 2008 in comparison to
the same period in 2007 contributed approximately $221,000 to gross margin
during the first six months of
2008.
|
·
|
Interruptible
services revenue, net of required margin-sharing, increased $282,000 in
the second quarter of 2008 compared to the same period in 2007 as
customers took advantage of lower natural gas prices in comparison to
prices for alternative fuels.
|
·
|
Partially
offsetting these increases to gross margin was the negative impact of
warmer weather and lower consumption
per customer in the first six months of 2008 compared to the same period
in 2007. The Company estimates that warmer weather reduced gross
margin by approximately $464,000 as temperatures on the Delmarva Peninsula
were nine percent warmer in the first six months of 2008 compared to the
same period in 2007. In addition, the Company
estimates that lower consumption per customer reduced margins by
approximately $73,000 in 2008.
|
·
|
The
remaining $81,000 net increase in gross margin can be attributed to
various factors, including the implementation of temporary rates by the
Delaware division and lower industrial
volumes.
|
Gross
margin for the Florida distribution operation increased by $102,000, or two
percent, in the first six months of 2008 compared to the same period in
2007. The higher gross margin for the period is primarily attributed
to the increase in customers as the operation experienced a two percent growth
in residential customers, an increase in non-residential customer volumes, and
higher revenues from third-party natural gas marketers.
Other
operating expense for the natural gas distribution operations increased by
$429,000 in the first six months of 2008 compared to the same period in 2007.
Among the key components producing this net increase were the
following:
·
|
Corporate
costs allocable to the natural gas distribution operations increased
$927,000 as a result of (1) $533,000 for the allocation of a portion of
the terminated acquisition costs previously discussed, and (2) the Company
updating its annual corporate cost
allocations.
|
·
|
Incentive
compensation increased $295,000 in the first six months of 2008 as the
Delmarva and Florida operations experienced improved earnings compared to
the prior year.
|
·
|
The
Florida distribution operation experienced higher expense of $113,000 for
outside services as the operation incurred additional costs for meter
reading services and higher commissions to a third-party
marketer.
|
·
|
Property
taxes increased by $114,000 as a result of the Company’s continued capital
investments.
|
·
|
Vehicle
fuel increased $47,000 in the first six months of 2008 as a result of
higher gasoline and diesel prices.
|
·
|
Depreciation
expense and asset removal costs decreased $105,000 and $836,000,
respectively, in the first six months of 2008 compared to the same period
in 2007, primarily as a result of the Delmarva operations’s rate
proceedings. These rate proceedings provided for lower
depreciation allowances and lower asset removal cost allowances, which
resulted in reductions of $179,000 and $937,000 in depreciation expense
and asset removal costs, respectively, during the first six months of
2008.
|
·
|
Maintenance
costs for the Florida operation decreased $108,000 during the first six
months of 2008 compared with the same period in 2007 due to the timing of
compliance costs with the new federal pipeline integrity regulations,
which were incurred in 2007.
|
·
|
Merchant
payment fees decreased by $97,000 primarily from the Company’s Delmarva
operations outsourcing the processing of credit card payments in April of
2007.
|
·
|
In
addition, other operating expenses relating to various other items
increased by approximately $79,000.
|
Natural Gas
Marketing
Gross
margin for the natural gas marketing operation increased by $618,000, or 61
percent, for the first six months of 2008 compared to the same period in 2007.
The increase in gross margin was primarily the result of a higher number of
customers to which it provides supply management services, improved gas supply
management techniques, and favorable imbalance resolutions with interstate
pipelines. Other operating expenses decreased by $60,000 for the
marketing operation; this decrease is attributable to lower payroll-related
costs, benefits, and allowance for uncollectible accounts. These
lower costs were partially offset by higher incentive compensation incurred as a
result of the improved operating results and higher corporate costs as $16,000
was allocated to the operation for a portion the terminated acquisition
costs.
Propane
The
propane segment earned operating income of $2.8 million for the first six months
of 2008 compared to $4.3 million for the corresponding quarter in 2007, a
decrease of $1.5 million, or 35 percent.
|
|
|
|
|
|
|
|
|
|
For
the Six Months Ended June 30,
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
Revenue
|
|
$ |
39,297,957 |
|
|
$ |
34,416,976 |
|
|
$ |
4,880,981 |
|
Cost
of sales
|
|
|
27,256,857 |
|
|
|
21,263,372 |
|
|
|
5,993,485 |
|
Gross
margin
|
|
|
12,041,100 |
|
|
|
13,153,604 |
|
|
|
(1,112,504 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
& maintenance
|
|
|
7,457,009 |
|
|
|
7,459,990 |
|
|
|
(2,981 |
) |
Terminated
acquisition costs
|
|
|
272,718 |
|
|
|
- |
|
|
|
272,718 |
|
Depreciation
& amortization
|
|
|
1,001,808 |
|
|
|
904,368 |
|
|
|
97,440 |
|
Other
taxes
|
|
|
490,129 |
|
|
|
461,588 |
|
|
|
28,541 |
|
Other
operating expenses
|
|
|
9,221,664 |
|
|
|
8,825,946 |
|
|
|
395,718 |
|
Total
Operating Income
|
|
$ |
2,819,436 |
|
|
$ |
4,327,658 |
|
|
$ |
(1,508,222 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statistical
Data — Delmarva Peninsula
|
|
|
|
|
|
|
|
|
|
|
|
|
Heating
degree-days ("HDD"):
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
|
|
|
2,703 |
|
|
|
2,966 |
|
|
|
(263 |
) |
10-year
average (normal)
|
|
|
2,760 |
|
|
|
2,737 |
|
|
|
23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
gross margin per HDD
|
|
$ |
2,465 |
|
|
$ |
1,974 |
|
|
$ |
491 |
|
The
period-over-period decrease in operating income was due primarily to the
Delmarva propane distribution operation, which experienced a lower gross margin
from warmer weather on the Delmarva Peninsula, a lower margin per retail gallon
and lower sales volumes in the first six months of 2008.
The gross
margin decreases of $1.3 million for the Delmarva propane distribution
operations and $14,000 for the Florida propane distribution operations, which
were partially offset by a higher gross margin of $170,000 for the propane
wholesale and marketing operation, are further explained below.
Delmarva Propane
Distribution
The
Delmarva propane distribution operation’s decrease in gross margin of $1.3
million resulted from the following:
·
|
Temperatures
on the Delmarva Peninsula were nine percent warmer in the first six months
of 2008 compared to the same period in 2007, which contributed to a
decrease of 891,000 gallons, or six percent, sold during this period in
2008 compared to the same period in 2007. The Company estimates that the
warmer weather and decreased volumes sold had a negative impact of
approximately $648,000 for the Delmarva propane distribution operation
compared to the first six months of
2007.
|
·
|
Non-weather-related
volumes sold in the first six months of 2008 decreased by 766,000 gallons,
or six percent. This decrease in gallons sold reduced gross
margin by approximately $567,000 for the Delmarva propane distribution
operation compared to the first six months of 2007. Factors
contributing to this decrease in gallons sold included: customer
conservation, a reduced number of customers and the timing of propane
deliveries.
|
·
|
Gross
margin decreased by $213,000 in the first six months of 2008, compared to
the same period in 2007, because of a $0.02 decrease in the average gross
margin per retail gallon. This decrease occur when market prices decrease
and move closer to the Company’s inventory price per gallon and the trend
reverses when market prices of propane are greater than the Company’s
average inventory price per gallon.
|
·
|
Revenues
from miscellaneous fees, including items such as tank and meter rentals
increased by $108,000 during the first six months of 2008 compared to the
same period in 2007.
|
·
|
The
remaining $52,000 net increase in gross margin can be attributed to
various factors, including service
revenue.
|
Total
other operating expenses increased by $258,000 for the Delmarva propane
operations in the first six months of 2008, compared to the same period in 2007.
The significant items contributing to this increase are explained
below:
·
|
Corporate
costs allocable to the propane distribution operations increased $415,000
as a result of (1) $227,000 for the allocation of a portion of the
terminated acquisition costs previously discussed, and (2) the Company
updating its annual corporate cost
allocations.
|
·
|
Vehicle
fuel increased $106,000 as a result of rising gasoline and diesel fuel
costs.
|
·
|
The
allowance for uncollectible accounts increased $62,000 due to increased
revenues resulting from the higher cost of
propane.
|
·
|
Mains
fees increased by $51,000 in the first six months of 2008 compared to the
same period in 2007 as a result of added CGS customers. This expenditure
will continue to increase as more CGS customers are
added.
|
·
|
Depreciation
and amortization expense increased by $41,000 as a result of an increase
in the Company’s capital investments compared to the prior
year.
|
·
|
The
operations experienced lower expenses of $174,000 in the first six months
of 2008 compared to the same period in 2007 for propane tank
recertifications and maintenance. The Company incurred these
costs in 2007 to maintain compliance with U.S. Department of
Transportation (“DOT”) standards, which require propane tanks or cylinders
to be recertified twelve years from their date of manufacture and every
five years thereafter.
|
·
|
Incentive
compensation and commissions costs decreased by $239,000 as a result of
the lower operating results in 2008 compared to
2007.
|
·
|
Other
operating expenses relating to various items decreased collectively by
approximately $4,000.
|
Florida Propane
Distribution
The
Florida propane distribution operation experienced a decrease in gross margin of
$14,000, or two percent, in the first six months of 2008 compared to the same
period in 2007. The lower gross margin is attributable to a decrease
of $25,000 in service sales as the operation exits this portion of the business,
which was partially offset by an increase of $12,000 based upon a higher average
gross margin per retail gallon. Other operating expenses in the first
six months of 2008, compared to the same period in 2007, increased by $77,000,
primarily due to increased depreciation expense and increased corporate costs as
$20,000 was allocated to the operations for a portion of the terminated
acquisition costs.
Propane Wholesale and
Marketing
Gross
margin for the Company’s propane wholesale marketing operation increased by
$170,000, or 13 percent, in the first six months of 2008 compared to the same
period in 2007. This increase reflects the larger number of market opportunities
that arose in the first six months of 2008 due to price volatility in the
propane wholesale market, which exceeded the level of price fluctuations
experienced in 2007. The increase in gross margin was partially
offset by higher other operating expenses of $61,000, due primarily to higher
payroll costs and increased corporate costs as $26,000 was allocated to the
operation for a portion of the terminated acquisition costs. The
higher period-over-period payroll cost is the result of a position vacant during
2007 being filled in 2008.
Advanced
Information Services
The
advanced information services business experienced gross margin growth of
approximately $352,000, or 11 percent, and contributed operating income of
$175,000 for the second quarter of 2008, a decrease of $53,000 compared to the
same period in 2007. Absent the terminated acquisition costs of
$64,000 allocated to the advanced information segment in the second quarter of
2008, the segment would have experienced a slight increase in its operating
income of $11,000 for the first six months of 2008 compared to the same period
in 2007.
|
|
|
|
|
|
|
|
|
|
For
the Six Months Ended June 30,
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
Revenue
|
|
$ |
7,473,413 |
|
|
$ |
7,121,197 |
|
|
$ |
352,216 |
|
Cost
of sales
|
|
|
4,000,948 |
|
|
|
4,001,111 |
|
|
|
(163 |
) |
Gross
margin
|
|
|
3,472,465 |
|
|
|
3,120,086 |
|
|
|
352,379 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
& maintenance
|
|
|
2,766,947 |
|
|
|
2,464,659 |
|
|
|
302,288 |
|
Terminated
acquisition costs
|
|
|
64,461 |
|
|
|
- |
|
|
|
64,461 |
|
Depreciation
& amortization
|
|
|
75,838 |
|
|
|
69,485 |
|
|
|
6,353 |
|
Other
taxes
|
|
|
390,278 |
|
|
|
358,414 |
|
|
|
31,864 |
|
Other
operating expenses
|
|
|
3,297,524 |
|
|
|
2,892,558 |
|
|
|
404,966 |
|
Total
Operating Income
|
|
$ |
174,941 |
|
|
$ |
227,528 |
|
|
$ |
(52,587 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
The
increase of revenues in the first six months of 2008 resulted primarily from the
following:
·
|
Product
sales increased by $204,000 as the operation enlarged its marketing and
sales force.
|
·
|
Consulting
revenues increased by $87,000 as higher average billing rates overcame a
two-percent decrease in the number of billable
hours;
|
·
|
Managed
Database Administration (“MDBA”) services, which provide clients with
professional database monitoring and support solutions during business
hours or around the clock increased by $75,000;
and
|
·
|
Revenues
from other products and services decreased collectively by approximately
$14,000.
|
Cost of
sales remained relatively unchanged from period-to-period. An
increase in cost of sales to provide services for the additional revenue earned
in 2008 was offset by a reduction in cost of sales for billable employees that
transferred to non-billable positions. Also, lower reimbursable
expenses contributed to the reduction in cost of sales as employees performed
less travel during the period.
Other
operating expenses increased by $405,000 in the first six months of 2008,
compared to the same period in 2007. This increase in operating expenses is
attributable to payroll costs, payroll taxes, and higher corporate costs as
$64,000 was allocated to the segment for a portion of the terminated acquisition
costs. Payroll costs increased as a result of the increase in non-billable
staffing levels previously discussed.
Other
Business Operations and Eliminations
Other
operations, consisting primarily of subsidiaries that own real estate leased to
other Company subsidiaries, generated an operating income of approximately
$170,000 for the first six months of 2008 compared to an operating income of
approximately $148,000 for the same period in 2007.
|
|
|
|
|
|
|
|
|
|
For
the Six Months Ended June 30,
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
Revenue
|
|
$ |
326,148 |
|
|
$ |
309,246 |
|
|
$ |
16,902 |
|
Cost
of sales
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Gross
margin
|
|
|
326,148 |
|
|
|
309,246 |
|
|
|
16,902 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
& maintenance
|
|
|
58,716 |
|
|
|
51,475 |
|
|
|
7,241 |
|
Terminated
acquisition costs
|
|
|
12,396 |
|
|
|
- |
|
|
|
12,396 |
|
Depreciation
& amortization
|
|
|
57,244 |
|
|
|
80,813 |
|
|
|
(23,569 |
) |
Other
taxes
|
|
|
28,941 |
|
|
|
30,310 |
|
|
|
(1,369 |
) |
Other
operating expenses
|
|
|
157,297 |
|
|
|
162,598 |
|
|
|
(5,301 |
) |
Operating
Income - Other
|
|
|
168,851 |
|
|
|
146,648 |
|
|
|
22,203 |
|
Operating Income -
Eliminations
(1)
|
|
|
1,539 |
|
|
|
1,539 |
|
|
|
- |
|
Total
Operating Income
|
|
$ |
170,390 |
|
|
$ |
148,187 |
|
|
$ |
22,203 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Eliminations
are entries required to eliminate activities between business segments
from the
|
|
the
consolidated results.
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Expense
Total
interest expense for the first six months of 2008 decreased by approximately
$212,000, or seven percent, compared to the same period in 2007. The lower
interest expense is a result of the following developments:
·
|
Interest
on short-term borrowings increased by $130,000 in the first six months of
2008 compared to the same period in 2007, based upon an increase of $19.8
million in the Company’s average short-term borrowing
balance. The impact of the higher borrowing was partially
offset by a weighted average interest rate that was nearly 2.6 percentage
points lower in 2008 and interest that was capitalized during the period.
The Company’s average short-term borrowing during the first six months of
2008 was $35.6 million, with a weighted average interest rate of 3.14
percent, compared to $15.8 million, with a weighted average interest rate
of 5.72 percent for the same period in
2007.
|
·
|
Interest
on long-term debt decreased by $282,000 in the first six months of 2008
compared to the same period in 2007 as the Company reduced its average
long-term debt balance by $7.9 million. The Company’s average
long-term debt during the first six months of 2008 was $69.9 million, with
a weighted average interest rate of 6.63 percent, compared to $77.8
million, with a weighted average interest rate of 6.68 percent for the
same period in 2007.
|
·
|
Interest
expense for customer refunds increased by $210,000 in the first six months
of 2008 due to the timing of regulatory filings and the settlement of rate
cases.
|
·
|
Interest
expense for other items, such as interest on refunds and meter deposits,
increased by $27,000 in the first six months of 2008 compared to the
corresponding period in 2007.
|
Income
Taxes
Income
tax expense for the first six months of 2008 was $6.1 million compared to $5.9
million for the same period in 2007. The increase in income tax expense
primarily reflects the higher earnings for the period and an increase of $50,000
to our tax accrual for uncertain tax positions as defined in FIN 48 related to
our 2005 tax return that is currently under audit by the IRS. The effective tax
rate for the first six months of 2008 is 39.3 percent compared to an effective
tax rate of 38.4 percent for the same period in 2007.
Financial
Position, 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 the first six
months of 2008, net cash provided by operating activities was $9.6 million, cash
used by investing activities was $15.6 million, and cash provided by financing
activities was $6.6 million.
By
comparison, during the first six months of 2007, net cash provided by operating
activities was $20.6 million, cash used by investing activities was $15.9
million, and cash used by financing activities was $8.3 million.
As of
February 20, 2008, the Board of Directors has authorized the Company to borrow
up to $70.0 million of short-term debt, as required, from various banks and
trust companies under short-term lines of credit. As of June 30, 2008,
Chesapeake had five unsecured bank lines of credit with three financial
institutions, totaling $90.0 million, none of which requires compensating
balances. These bank lines are available to provide funds for the Company’s
short-term cash needs, to meet seasonal working capital requirements and to fund
temporarily portions of its capital expenditures. Two of the bank lines,
totaling $15.0 million, are committed. Advances offered under the uncommitted
lines of credit are subject to the discretion of the banks. The Company’s
outstanding balance of short-term borrowing at June 30, 2008 and December 31,
2007 was $57.1 million and $45.7 million, respectively.
Chesapeake
has budgeted $37.5 million for capital expenditures during 2008. This amount
includes $17.0 million for natural gas distribution, $13.3 million for natural
gas transmission, $5.9 million for propane distribution and wholesale marketing,
$290,000 for advanced information services and $887,000 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, to acquire land for a future bulk storage facility, and to replace
equipment. The advanced information services expenditures are for computer
hardware, software and related equipment. The other operations category includes
general plant, computer software and hardware. The Company expects to fund the
2008 capital expenditures program from short-term borrowing, cash provided by
operating activities, and other sources. The capital expenditure program is
subject to continuous review and modification. Actual capital requirements may
vary from the above estimates due to a number of factors, including changing
economic conditions, customer growth in existing areas, regulation, new growth
opportunities, acquisition opportunities and availability of
capital.
Capital
Structure
The
following presents the Company’s capitalization as of June 30, 2008 and December
31, 2007:
|
|
June 30, 2008
|
|
|
December 31, 2007
|
|
|
|
(In
thousands, except percentages)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt, net of current maturities
|
|
$ |
63,181 |
|
|
|
33 |
% |
|
$ |
63,255 |
|
|
|
35 |
% |
Stockholders'
equity
|
|
$ |
125,470 |
|
|
|
67 |
% |
|
$ |
119,577 |
|
|
|
65 |
% |
Total
capitalization, excluding short-term debt
|
|
$ |
188,651 |
|
|
|
100 |
% |
|
$ |
182,832 |
|
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of
June 30, 2008, common equity represented 67 percent of total capitalization,
compared to 65 percent at December 31, 2007. 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 50 percent at
June 30, 2008, compared to 49 percent at December 31, 2007. Chesapeake remains
committed to maintaining a sound capital structure and strong credit ratings to
provide the financial flexibility needed to access capital markets when
required. This commitment, along with adequate and timely rate relief for 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
the fourth quarter of 2006, the Company 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. At June 30, 2008, the Company had approximately $20.0
million remaining under this registration statement.
Cash
Flows Provided By Operating Activities
Cash
flows provided by operating activities were as follow:
|
|
|
|
|
|
|
|
|
|
For
the Six Months Ended June 30,
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
Net
Income
|
|
$ |
9,393,266 |
|
|
$ |
9,472,879 |
|
|
$ |
(79,613 |
) |
Non-cash
adjustments to net income
|
|
|
7,505,849 |
|
|
|
8,186,431 |
|
|
|
(680,582 |
) |
Changes
in working capital
|
|
|
(7,256,462 |
) |
|
|
2,958,748 |
|
|
|
(10,215,210 |
) |
Net
cash provided by operating activties
|
|
$ |
9,642,653 |
|
|
$ |
20,618,058 |
|
|
$ |
(10,975,405 |
) |
Period-over-period
changes in our cash flows from operating activities are attributable primarily
to net income, non-cash adjustments, such as depreciation and deferred income
taxes, and changes in our working capital. The changes in working capital are
affected 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.
For the first six months
of 2008, net cash flow provided by operating activities was $9.6 million, a
reduction of $11.0 million compared to the same period of 2007. The
decrease was due primarily to an increase in accounts receivable, which was
partially offset by an increase in accounts payable. These increases
are due to the timing of collections and payments of trading contracts entered
into by the Company’s propane wholesale and marketing operation. Also
contributing to the decrease in net cash flows provided by operating activities,
was a reduction in regulatory liabilities, which resulted primarily from
environmental expenditures and refunds to customers.
Cash
Flows Used in Investing Activities
Net cash
flows used in investing activities totaled $15.6 million and $15.9 million
during the six months ended June 30, 2008 and 2007, respectively.
·
|
Cash
utilized for capital expenditures was $15.4 million and $16.0 million for
the first six months of 2008 and 2007, respectively. Additions to
property, plant and equipment in the first six months of 2008 were
primarily for natural gas transmission ($5.9 million), natural gas
distribution ($7.0 million), propane distribution ($1.6 million), and
other operations ($889,000).
|
·
|
The
Company’s environmental expenditures exceeded amounts recovered through
rates charged to customers in the first six months of 2008 and 2007 by
$199,000 and $136,000,
respectively.
|
Cash
Flows Provided by Financing Activities
Cash
flows provided by financing activities totaled $6.6 million for the first six
months of 2008 compared to $8.3 million of cash used for the first six months of
2007. Significant financing activities included the following:
·
|
During
the first six months of 2008, the Company had net borrowings from
short-term debt of $11.5 million compared to a net repayment of $4.8
million in the first six months of
2007.
|
·
|
During
the first six months of 2008, the Company paid $3.8 million in cash
dividends compared with dividend payments of $3.5 million for the same
time period in 2007. The increase in dividends paid in the first six
months of 2008 compared to 2007 reflects both growth in the annualized
dividend rate and the increase in the number of shares
outstanding.
|
·
|
The
Company repaid $1.0 million of long-term debt during the first six months
of 2008 and 2007, respectively.
|
Off-Balance
Sheet Arrangements
The
Company has issued corporate guarantees to certain vendors of its propane
wholesale marketing subsidiary and its Florida natural gas supply management
subsidiary. These corporate guarantees provide for the payment of propane and
natural gas purchases in the event of either subsidiary’s default. Neither
subsidiary has ever defaulted on its obligations to pay suppliers. The
liabilities for these purchases are recorded in the Consolidated Financial
Statements when incurred. The aggregate amount guaranteed at June 30, 2008 was
$24.2 million, with the guarantees expiring on various dates in 2008 and the
first six months of 2009.
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, 2009.
The letter of credit is provided as security to satisfy the deductibles under
the Company’s various insurance policies. There have been no draws on this
letter of credit as of June 30, 2008.
Contractual
Obligations
There has
not been any material change in the contractual obligations presented in the
Company’s 2007 Annual Report on Form 10-K, except for commodity purchase
obligations and forward contracts entered into in the ordinary course of the
Company’s business. Below is a summary of the commodity and forward contract
obligations at June 30, 2008.
|
|
Payments
Due by Period
|
|
Purchase
Obligations
|
|
Less
than 1 year
|
|
|
1
- 3 years
|
|
|
3
- 5 years
|
|
|
More
than 5 years
|
|
|
Total
|
|
Commodities
(1)
|
|
$ |
20,342,267 |
|
|
$ |
1,329,764 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
21,672,031 |
|
Propane
(2)
|
|
|
66,118,237 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
66,118,237 |
|
Total
Purchase Obligations
|
|
$ |
86,460,504 |
|
|
$ |
1,329,764 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
87,790,268 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
In
addition to the obligations noted above, the natural gas distribution and
propane distribution operations have agreements with commodity suppliers
that have provisions allowing the Company to reduce or eliminate the
quantities purchased. There are no monetary penalties for reducing the
amounts purchased; however, the propane contracts allow the suppliers to
reduce the amounts available in the winter season if the Company does not
purchase specified amounts during the summer season. Under these
contracts, the commodity prices will fluctuate as market prices
fluctuate.
|
(2)
|
The
Company has also entered into forward sale contracts in the aggregate
amount of $68.6 million. See Part I, Item 3, “Quantitative and Qualitative
Disclosures about Market Risk,” below for further
information.
|
Environmental
Matters
As more
fully described in Note 4, “Commitments and Contingencies,” to the Unaudited
Condensed Consolidated Financial Statements, Chesapeake has incurred costs
relating to the completed or ongoing environmental remediation at three former
manufactured gas plant sites. In addition, Chesapeake is currently participating
in discussions regarding possible responsibility of the Company for remediation
of a fourth former manufactured gas plant site located in Cambridge, Maryland.
Chesapeake believes that future costs associated with these sites will be
recoverable in rates or through sharing arrangements with, or contributions by,
other responsible parties.
Other
Matters
Rates
and Regulatory Matters
The
Company’s natural gas distribution operations in Delaware, Maryland and Florida
are subject to regulation by their respective state PSCs. Eastern Shore is
subject to regulation by the FERC. At June 30, 2008, Chesapeake was
involved in rates and/or regulatory matters in each of the jurisdictions in
which it operates. Each of these rates or regulatory matters is
fully described in Note 4, “Commitments and Contingencies,” to the Unaudited
Condensed Consolidated Financial Statements.
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 may convert to oil to satisfy their fuel requirements.
Oil prices, as well as the prices of electricity and other fuels, which are
normally lower than the price of natural gas, 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 sides of this business to compete with
the fluctuations in its customers’ alternative fuel prices. As a result of the
transmission operation’s conversion to open access and the Florida gas
distribution division’s restructuring of its services, these businesses have
shifted from providing competitive sales service to providing transportation and
contract storage services.
The
Company’s natural gas distribution operations in Delaware, Maryland and Florida
offer transportation services to certain commercial and industrial customers. In
2002, the Florida operation extended such 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. With respect to unbundled transportation services, the Company’s
competitors include interstate transmission companies if distribution customers
are located close enough to a 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 Company’s distribution operations in this manner. In certain
situations, the Company’s 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 such 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 propane 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. In addition, changes in the advanced information services industry are
occurring rapidly, which could adversely impact the markets for the products and
services offered by such businesses. This segment of the Company
competes on the basis of technological expertise, service reputation and
price.
Inflation
Inflation
affects the cost of supply, labor, products and services required for
operations, maintenance and capital improvements. While the impact of inflation
has remained low in recent years, natural gas and propane prices are subject to
rapid fluctuations. In the Company’s regulated natural gas distribution
operations, 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 its regulated
operations and closely monitors the returns of its unregulated business
operations. To compensate for fluctuations in propane gas prices, the Company
adjusts its propane selling prices to the extent allowed by the
market.
Recent
Authoritative Pronouncements on Financial Reporting and Accounting
Recent
accounting developments and their impact on our financial position, results of
operations and cash flows are described in Note 5, “Recent Authoritative
Pronouncements on Financial Reporting and Accounting,” to the unaudited
Condensed Consolidated Financial Statements.
Item
3. Quantitative and Qualitative Disclosures about Market Risk
Market
risk represents the potential loss arising from adverse changes in market rates
and prices. Long-term debt is subject to potential losses based on changes in
interest rates. The Company’s long-term debt consists of first mortgage bonds,
fixed-rate senior notes and convertible debentures. All of the Company’s
long-term debt is fixed-rate debt and was not entered into for trading purposes.
The carrying value of long-term debt, including current maturities, was $69.8
million at June 30, 2008, as compared to a fair value of $72.9 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 refinance existing
short-term borrowing, based in part on the fluctuation in interest
rates.
The
Company’s propane distribution business is exposed to market risk as a result of
propane storage activities and when it enters into fixed-price contracts for
supply. The Company can store up to approximately four million gallons
(including leased storage and rail cars) of propane 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. Management reviewed the Company’s
storage position as of June 30, 2008 and elected not to hedge any of its
inventories.
The
Company’s propane wholesale marketing operation is a party to natural gas
liquids (“NGLs”) forward contracts, primarily propane contracts, with various
third parties. These contracts require that the propane wholesale marketing
operation purchase or sell NGLs at a fixed price at fixed future dates. At
expiration, the contracts are settled by the delivery of NGLs to the Company or
the counter-party or booking out the transaction. Booking out is a
procedure for financially settling a contract in lieu of the physical delivery
of energy. The propane wholesale marketing operation also enters into futures
contracts that are traded on the New York Mercantile Exchange. In certain cases,
the futures contracts are settled by the payment or receipt of a net amount
equal to the difference between the current market price of the futures contract
and the original contract price; however, they may also be settled for physical
receipt or delivery of propane.
The
forward and futures contracts are entered into for trading and wholesale
marketing purposes. The propane wholesale marketing business is subject to
commodity price risk on its open positions to the extent that market prices for
NGLs deviate from fixed contract settlement prices. Market risk associated with
the trading of futures and forward contracts are monitored daily for compliance
with the Company’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 the Company’s oversight
officials daily. In addition, the Risk Management Committee reviews periodic
reports on market and the credit risk of counter-parties, approves any
exceptions to the Risk Management Policy (within limits established by the Board
of Directors) and authorizes the use of any new types of contracts. Quantitative
information on forward and futures contracts at June 30, 2008 is presented in
the following table.
|
|
|
|
At
June 30, 2008
|
Quantity
in
gallons
|
Estimated
Market
Prices
|
Weighted
Average
Contract
Prices
|
Forward
Contracts
|
|
|
|
Sale
|
38,472,000
|
$1.3550
— $1.9200
|
$1.7837
|
Purchase
|
37,379,982
|
$1.3650
— $1.9250
|
$1.7688
|
|
|
|
|
Estimated
market prices and weighted average contract prices are in dollars per
gallon.
|
All
contracts expire in 2008 or in the first quarter of 2009.
|
|
Item
4. Controls and Procedures
Evaluation
of Disclosure Controls and Procedures
The Chief
Executive Officer and Chief Financial Officer of the Company, with the
participation of other Company officials, have evaluated the Company’s
“disclosure controls and procedures” (as such term is defined under Rules
13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934,
as amended) as of June 30, 2008. 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 June 30,
2008.
Changes
in Internal Control Over Financial Reporting
During
the quarter ended June 30, 2008, 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.
|
PART
II — OTHER INFORMATION
|
Item
1. Legal
Proceedings
As
disclosed in Note 4, “Commitments and Contingencies,” of the unaudited Condensed
Consolidated Financial Statements, 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
government agencies concerning rates. In the opinion of management, the ultimate
disposition of these proceedings and claims will not have a material effect on
the consolidated financial position, results of operations or cash flows of the
Company.
Item
1A. Risk
Factors
In
addition to the other information set forth in this Form 10-Q, including the
risks and uncertainties described under Item 2 of Part I of this Form 10-Q, in
the section entitled “Safe Harbor and Forward Looking Statements,” consideration
should be given to the factors discussed under Item 1A. “Risk Factors,” in the
Company’s Form 10-K for the fiscal year ended December 31, 2007. These risks
could affect the operations and/or financial performance of the Company. The
risks described in the Form 10-K and this Form 10-Q are not the only risks that
the Company faces. The Company’s operations and/or financial performance could
also be affected by additional factors that at present are not known to it or
that the Company considers immaterial to its operations and/or financial
performance.
Item
2. Unregistered
Sales of Equity Securities and Use of Proceeds
|
|
|
|
|
|
Period
|
Total
Number
of
Shares
Purchased
|
Average
Price
Paid
per
Share
|
Total
Number of Shares
Purchased
as Part of
Publicly
Announced
Plans
or Programs
|
Maximum
Number of
Shares
That May Yet Be
Purchased
Under the
Plans
or Programs
|
|
April
1, 2008
|
|
|
|
|
|
through
April 30, 2008 (1)
|
557
|
$30.99
|
-
|
-
|
|
May
1, 2008
|
|
|
|
|
|
through
May 30, 2008
|
-
|
-
|
-
|
-
|
|
June
1, 2008
|
|
|
|
|
|
through
June 30, 2008
|
-
|
-
|
-
|
-
|
|
|
|
|
|
|
Total
|
557
|
$30.99
|
-
|
-
|
|
|
|
|
|
|
(1) Chesapeake
purchased shares of stock on the open market for the purpose of
reinvesting the dividend on deferred
|
stock
units held in the Rabbi Trust accounts for certain Senior Executives under
the Deferred Compensation Plan.
|
The
Deferred Compensation Plan is discussed in detail in Note K to the
Consolidated Financial Statements of the
|
Company's
Form 10-K filed with the Securities Exchange Commission on March 10,
2008. During the quarter,
|
557
shares were purchased through the reinvestment of dividends on deferred
stock units.
|
|
Item
3. Defaults
upon Senior Securities
None
Item
4. Submission
of Matters to a Vote of Security Holders
The
Annual Meeting of the Stockholders of Chesapeake Utilities Corporation was held
on May 1, 2008. The items set forth below were submitted to a vote of
security holders. Proxies for the meeting were solicited in
accordance with Regulation 14A under the Securities Exchange Act of 1934, as
amended.
The
stockholders elected three nominees to the Company’s Board of Directors to serve
as Class III directors for three-year terms ending in 2011, and until their
successors are elected and qualify. The following shows the separate
tabulation of votes for each nominee:
Name
|
Votes
For
|
Votes
Withheld
|
Thomas
J. Bresnan
|
6,357,555
|
182,717
|
Joseph
E. Moore
|
6,308,808
|
231,464
|
John
R. Schimkaitis
|
6,354,089
|
186,183
|
The terms
of the following directors were not subject to vote (or election) and they
remained in office after the meeting:
Class
I Directors (Terms Expire in 2009)
|
Class
II Directors (Terms Expire in 2010)
|
Calvert
A. Morgan, Jr.
|
Ralph
J. Adkins
|
Eugene
H. Bayard
|
Richard
Bernstein
|
Thomas
P. Hill, Jr.
|
J.
Peter Martin
|
The
stockholders approved the ratification of the appointment of Beard Miller
Company LLP as the Company’s independent registered public accounting firm for
the fiscal year ending December 31, 2008. There were 6,473,303 affirmative
votes, 35,107 negative votes, and 31,862 abstentions. There were no
broker non-votes for this matter.
The
stockholders did not approve a shareholder proposal requesting that the Board of
Directors take the steps necessary to eliminate classification of terms of the
Board of Directors. The Board of Directors opposed this
proposal. There were 2,418,582 affirmative votes, 2,635,724 negative
votes, 71,889 abstentions, and 1,414,077 broker non-votes.
As of the
Record Date, March 14, 2008, 6,806,487 shares of common stock of the Company,
the only class of voting or equity securities of the Company, were
outstanding.
Item
5. Other
Information
None
Item
6. Exhibits
Exhibit
|
Description
|
31.1
|
Certificate
of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to
Rule 13a-14(a) under the Securities Exchange Act of 1934, dated August 11,
2008.
|
|
|
31.2
|
Certificate
of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to
Rule 13a-14(a) under the Securities Exchange Act of 1934, dated August 11,
2008.
|
|
|
32.1
|
Certificate
of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to
18 U.S.C. Section 1350, dated August 11, 2008.
|
|
|
32.2
|
Certificate
of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to
18 U.S.C. Section 1350, dated August 11,
2008.
|
Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
Chesapeake
Utilities Corporation
/s/ Michael P.
McMasters
Michael
P. McMasters
Senior
Vice President and Chief Financial Officer
Date:
August 11, 2008