PART
I — FINANCIAL INFORMATION
Item
1. Financial
Statements
Chesapeake
Utilities Corporation and Subsidiaries
|
|
|
|
|
|
|
|
Condensed
Consolidated Statements of Income (Unaudited)
|
|
|
|
|
|
|
|
For
the Three Months Ended September 30,
|
|
2006
|
|
2005
|
|
Operating
Revenues
|
|
$
|
35,141,530
|
|
$
|
35,155,121
|
|
|
|
|
|
|
|
|
|
Operating
Expenses
|
|
|
|
|
|
|
|
Cost
of sales, excluding costs below
|
|
|
21,758,558
|
|
|
21,957,971
|
|
Operations
|
|
|
9,446,616
|
|
|
9,815,819
|
|
Maintenance
|
|
|
513,356
|
|
|
461,586
|
|
Depreciation
and amortization
|
|
|
2,044,179
|
|
|
1,889,266
|
|
Other
taxes
|
|
|
1,216,684
|
|
|
1,129,628
|
|
Total
operating expenses
|
|
|
34,979,393
|
|
|
35,254,270
|
|
Operating
Income (Loss)
|
|
|
162,137
|
|
|
(99,149
|
)
|
Other
income (loss) net of other expenses
|
|
|
(12,091
|
)
|
|
19,493
|
|
Interest
charges
|
|
|
1,340,879
|
|
|
1,272,196
|
|
Loss
Before Income Taxes
|
|
|
(1,190,833
|
)
|
|
(1,351,852
|
)
|
Income
taxes
|
|
|
(534,254
|
)
|
|
(658,078
|
)
|
Net
Loss
|
|
|
($656,579
|
)
|
|
($693,774
|
)
|
|
|
|
|
|
|
|
|
Earnings
Per Share of Common Stock:
|
|
|
|
|
|
|
|
Basic
|
|
|
($0.11
|
)
|
|
($0.12
|
)
|
Diluted
|
|
|
($0.11
|
)
|
|
($0.12
|
)
|
Basic
weighted average shares outstanding
|
|
|
5,973,149
|
|
|
5,851,926
|
|
Diluted
weighted average shares outstanding
|
|
|
5,973,149
|
|
|
5,851,926
|
|
|
|
|
|
|
|
|
|
Cash
Dividends Declared Per Share of Common Stock:
|
|
$
|
0.290
|
|
$
|
0.285
|
|
The
accompanying notes are an integral part of these financial
statements.
Chesapeake
Utilities Corporation and Subsidiaries
|
|
|
|
|
|
|
|
Condensed
Consolidated Statements of Income (Unaudited)
|
|
|
|
|
|
|
|
For
the Nine Months Ended September 30,
|
|
2006
|
|
2005
|
|
Operating
Revenues
|
|
$
|
170,395,955
|
|
$
|
155,220,745
|
|
|
|
|
|
|
|
|
|
Operating
Expenses
|
|
|
|
|
|
|
|
Cost
of sales, excluding costs below
|
|
|
116,188,846
|
|
|
101,453,132
|
|
Operations
|
|
|
27,899,729
|
|
|
29,325,623
|
|
Maintenance
|
|
|
1,540,963
|
|
|
1,279,820
|
|
Depreciation
and amortization
|
|
|
6,058,529
|
|
|
5,701,357
|
|
Other
taxes
|
|
|
3,903,155
|
|
|
3,730,674
|
|
Total
operating expenses
|
|
|
155,591,222
|
|
|
141,490,606
|
|
Operating
Income
|
|
|
14,804,733
|
|
|
13,730,139
|
|
Other
income net of other expenses
|
|
|
130,208
|
|
|
330,354
|
|
Interest
charges
|
|
|
4,335,568
|
|
|
3,823,140
|
|
Income
Before Income Taxes
|
|
|
10,599,373
|
|
|
10,237,353
|
|
Income
taxes
|
|
|
4,027,027
|
|
|
3,902,407
|
|
Net
Income
|
|
$
|
6,572,346
|
|
$
|
6,334,946
|
|
|
|
|
|
|
|
|
|
Earnings
Per Share of Common Stock:
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.11
|
|
$
|
1.09
|
|
Diluted
|
|
$
|
1.10
|
|
$
|
1.07
|
|
Basic
weighted average shares outstanding
|
|
|
5,945,119
|
|
|
5,823,144
|
|
Diluted
weighted average shares outstanding
|
|
|
6,069,893
|
|
|
5,982,303
|
|
|
|
|
|
|
|
|
|
Cash
Dividends Declared Per Share of Common Stock:
|
|
$
|
0.865
|
|
$
|
0.850
|
|
The
accompanying notes are an integral part of these financial
statements.
Chesapeake
Utilities Corporation and Subsidiaries
|
|
|
|
|
|
|
|
Condensed
Consolidated Statements of Cash Flows (Unaudited)
|
|
|
|
|
|
|
|
For
the Nine Months Ended September 30,
|
|
2006
|
|
2005
|
|
Operating
Activities
|
|
|
|
|
|
Net
Income
|
|
$
|
6,572,346
|
|
$
|
6,334,946
|
|
Adjustments
to reconcile net income to net operating cash:
|
|
|
|
|
|
|
|
Depreciation
and amortization
|
|
|
6,058,529
|
|
|
5,701,357
|
|
Depreciation
and accretion included in other costs
|
|
|
2,288,509
|
|
|
2,006,726
|
|
Deferred
income taxes, net
|
|
|
(2,304,070
|
)
|
|
(922,437
|
)
|
Unrealized
loss on commodity contracts
|
|
|
(708,915
|
)
|
|
(630,560
|
)
|
Unrealized
loss on investments
|
|
|
(65,810
|
)
|
|
(18,866
|
)
|
Employee
benefits and compensation
|
|
|
1,344,924
|
|
|
1,333,363
|
|
Other,
net
|
|
|
(3,085
|
)
|
|
(2,508
|
)
|
Changes
in assets and liabilities:
|
|
|
|
|
|
|
|
Purchase
of investments
|
|
|
(120,476
|
)
|
|
(1,183,889
|
)
|
Accounts
receivable and accrued revenue
|
|
|
17,284,220
|
|
|
4,828,374
|
|
Propane
inventory, storage gas and other inventory
|
|
|
(1,477,854
|
)
|
|
(5,432,158
|
)
|
Regulatory
assets
|
|
|
3,729,326
|
|
|
686,281
|
|
Prepaid
expenses and other current assets
|
|
|
(770,470
|
)
|
|
(478,960
|
)
|
Other
deferred charges
|
|
|
35,101
|
|
|
(40,790
|
)
|
Long-term
receivables
|
|
|
108,608
|
|
|
141,221
|
|
Accounts
payable and other accrued liabilities
|
|
|
(19,769,594
|
)
|
|
3,077,798
|
|
Income
taxes receivable
|
|
|
3,123,440
|
|
|
92,961
|
|
Accrued
interest
|
|
|
1,024,865
|
|
|
897,341
|
|
Customer
deposits and refunds
|
|
|
767,474
|
|
|
305,828
|
|
Accrued
compensation
|
|
|
(842,766
|
)
|
|
108,798
|
|
Regulatory
liabilities
|
|
|
2,785,999
|
|
|
1,999,921
|
|
Other
liabilities
|
|
|
(85,854
|
)
|
|
148,823
|
|
Net
cash provided by operating activities
|
|
|
18,974,447
|
|
|
18,953,570
|
|
|
|
|
|
|
|
|
|
Investing
Activities
|
|
|
|
|
|
|
|
Property,
plant and equipment expenditures
|
|
|
(28,335,269
|
)
|
|
(19,940,043
|
)
|
Environmental
recoveries (expenditures)
|
|
|
(9,625
|
)
|
|
205,689
|
|
Net
cash used by investing activities
|
|
|
(28,344,894
|
)
|
|
(19,734,354
|
)
|
|
|
|
|
|
|
|
|
Financing
Activities
|
|
|
|
|
|
|
|
Common
stock dividends
|
|
|
(4,462,307
|
)
|
|
(4,334,573
|
)
|
Issuance
of stock for Dividend Reinvestment Plan
|
|
|
228,352
|
|
|
282,453
|
|
Cash
settlement of warrants
|
|
|
(434,782
|
)
|
|
-
|
|
Change
in cash overdrafts due to outstanding checks
|
|
|
1,042,051
|
|
|
842,674
|
|
Net
borrowing under line of credit agreements
|
|
|
14,790,072
|
|
|
4,779,169
|
|
Repayment
of long-term debt
|
|
|
(1,929,619
|
)
|
|
(1,794,596
|
)
|
Net
cash provided (used) by financing activities
|
|
|
9,233,767
|
|
|
(224,873
|
)
|
|
|
|
|
|
|
|
|
Net Decrease
in Cash and Cash Equivalents
|
|
|
(136,680
|
)
|
|
(1,005,657
|
)
|
Cash
and Cash Equivalents — Beginning of Period
|
|
|
2,487,658
|
|
|
1,611,761
|
|
Cash
and Cash Equivalents — End of Period
|
|
$
|
2,350,978
|
|
$
|
606,104
|
|
|
|
|
|
|
|
|
|
Supplemental
Disclosures of Non-Cash Investing Activities:
|
|
|
|
|
|
|
|
Capital
property and equipment acquired on account, but not paid
as of September
30
|
|
$
|
4,291,387
|
|
$
|
68,504
|
|
The
accompanying notes are an integral part of these financial
statements.
Chesapeake
Utilities Corporation and Subsidiaries
|
|
|
|
|
|
|
|
Condensed
Consolidated Balance Sheets (Unaudited)
|
|
|
|
|
|
|
|
Assets
|
|
September
30, 2006
|
|
December
31, 2005
|
|
Property,
Plant and Equipment
|
|
|
|
|
|
Natural
gas distribution and transmission
|
|
$
|
238,607,537
|
|
$
|
220,685,461
|
|
Propane
|
|
|
43,174,349
|
|
|
41,563,810
|
|
Advanced
information services
|
|
|
951,500
|
|
|
1,221,177
|
|
Other
plant
|
|
|
9,110,426
|
|
|
9,275,729
|
|
Total
property, plant and equipment
|
|
|
291,843,812
|
|
|
272,746,177
|
|
Less:
Accumulated depreciation and amortization
|
|
|
(83,605,340
|
)
|
|
(78,840,413
|
)
|
Plus:
Construction work in progress
|
|
|
17,711,608
|
|
|
7,598,531
|
|
Net
property, plant and equipment
|
|
|
225,950,080
|
|
|
201,504,295
|
|
|
|
|
|
|
|
|
|
Investments
|
|
|
1,871,921
|
|
|
1,685,635
|
|
|
|
|
|
|
|
|
|
Current
Assets
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
|
2,350,978
|
|
|
2,487,658
|
|
Accounts
receivable (less allowance for uncollectible accounts of $849,292
and
$861,378, respectively)
|
|
|
39,638,501
|
|
|
54,284,011
|
|
Accrued
revenue
|
|
|
2,077,674
|
|
|
4,716,383
|
|
Propane
inventory, at average cost
|
|
|
7,462,209
|
|
|
6,332,956
|
|
Other
inventory, at average cost
|
|
|
1,580,509
|
|
|
1,538,936
|
|
Regulatory
assets
|
|
|
633,663
|
|
|
4,434,828
|
|
Storage
gas prepayments
|
|
|
8,935,207
|
|
|
8,628,179
|
|
Income
taxes receivable
|
|
|
-
|
|
|
2,725,840
|
|
Deferred
income taxes
|
|
|
1,643,394
|
|
|
-
|
|
Prepaid
expenses
|
|
|
2,780,135
|
|
|
2,021,164
|
|
Other
current assets
|
|
|
3,189,770
|
|
|
1,596,797
|
|
Total
current assets
|
|
|
70,292,040
|
|
|
88,766,752
|
|
|
|
|
|
|
|
|
|
Deferred
Charges and Other Assets
|
|
|
|
|
|
|
|
Goodwill
|
|
|
674,451
|
|
|
674,451
|
|
Other
intangible assets, net
|
|
|
195,329
|
|
|
205,683
|
|
Long-term
receivables
|
|
|
852,826
|
|
|
961,434
|
|
Other
regulatory assets
|
|
|
1,194,483
|
|
|
1,178,232
|
|
Other
deferred charges
|
|
|
930,265
|
|
|
1,003,393
|
|
Total
deferred charges and other assets
|
|
|
3,847,354
|
|
|
4,023,193
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$
|
301,961,395
|
|
$
|
295,979,875
|
|
The
accompanying notes are an integral part of these financial
statements.
Chesapeake
Utilities Corporation and Subsidiaries
|
|
|
|
|
|
|
|
Condensed
Consolidated Balance Sheets (Unaudited)
|
|
|
|
|
|
|
|
Capitalization
and Liabilities
|
|
September
30, 2006
|
|
December
31, 2005
|
|
Capitalization
|
|
|
|
|
|
Stockholders'
equity
|
|
|
|
|
|
Common
Stock, par value $0.4867 per share (authorized 12,000,000 shares)
(1)
|
|
$
|
2,910,261
|
|
$
|
2,863,212
|
|
Additional
paid-in capital
|
|
|
41,927,856
|
|
|
39,619,849
|
|
Retained
earnings
|
|
|
44,276,164
|
|
|
42,854,894
|
|
Accumulated
other comprehensive income
|
|
|
(578,151
|
)
|
|
(578,151
|
)
|
Deferred
compensation obligation
|
|
|
1,104,670
|
|
|
794,535
|
|
Treasury
stock
|
|
|
(1,104,670
|
)
|
|
(797,156
|
)
|
Total
stockholders' equity
|
|
|
88,536,130
|
|
|
84,757,183
|
|
|
|
|
|
|
|
|
|
Long-term
debt, net of current maturities
|
|
|
56,792,273
|
|
|
58,990,363
|
|
Total
capitalization
|
|
|
145,328,403
|
|
|
143,747,546
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
|
|
|
|
|
Current
portion of long-term debt
|
|
|
4,929,091
|
|
|
4,929,091
|
|
Short-term
borrowing
|
|
|
51,314,364
|
|
|
35,482,241
|
|
Accounts
payable
|
|
|
27,994,213
|
|
|
45,645,228
|
|
Customer
deposits and refunds
|
|
|
5,908,474
|
|
|
5,140,999
|
|
Accrued
interest
|
|
|
1,583,586
|
|
|
558,719
|
|
Dividends
payable
|
|
|
1,733,280
|
|
|
1,676,398
|
|
Income
taxes payable
|
|
|
397,600
|
|
|
-
|
|
Deferred
income taxes
|
|
|
-
|
|
|
1,150,828
|
|
Accrued
compensation
|
|
|
2,652,758
|
|
|
3,793,244
|
|
Regulatory
liabilities
|
|
|
3,801,066
|
|
|
550,546
|
|
Other
accrued liabilities
|
|
|
5,431,341
|
|
|
3,560,055
|
|
Total
current liabilities
|
|
|
105,745,773
|
|
|
102,487,349
|
|
|
|
|
|
|
|
|
|
Deferred
Credits and Other Liabilities
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
24,738,777
|
|
|
24,248,624
|
|
Deferred
investment tax credits
|
|
|
325,973
|
|
|
367,085
|
|
Other
regulatory liabilities
|
|
|
1,590,010
|
|
|
2,008,779
|
|
Environmental
liabilities
|
|
|
241,538
|
|
|
352,504
|
|
Accrued
pension costs
|
|
|
3,126,275
|
|
|
3,099,882
|
|
Accrued
asset removal cost
|
|
|
18,057,163
|
|
|
16,727,268
|
|
Other
liabilities
|
|
|
2,807,483
|
|
|
2,940,838
|
|
Total
deferred credits and other liabilities
|
|
|
50,887,219
|
|
|
49,744,980
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies
(Note 4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Capitalization and Liabilities
|
|
$
|
301,961,395
|
|
$
|
295,979,875
|
|
|
|
|
|
|
|
|
|
(1)
Shares issued were 5,979,769 and 5,883,099 for 2006 and 2005,
respectively.
|
|
Shares
outstanding were 5,979,769 and 5,883,002 for 2006 and 2005,
respectively.
|
|
The
accompanying notes are an integral part of these financial
statements.
Chesapeake
Utilities Corporation and Subsidiaries
|
|
|
|
|
|
|
|
Condensed
Consolidated Statements of Stockholders' Equity (Unaudited)
|
|
|
|
|
|
|
|
|
|
For
the Nine Months Ended September 30, 2006
|
|
For
the Twelve Months Ended December 31, 2005
|
|
Common
Stock
|
|
|
|
|
|
Balance
— beginning of period
|
|
$
|
2,863,212
|
|
$
|
2,812,538
|
|
Dividend
Reinvestment Plan
|
|
|
13,664
|
|
|
20,038
|
|
Retirement
Savings Plan
|
|
|
11,161
|
|
|
10,255
|
|
Conversion
of debentures
|
|
|
7,688
|
|
|
11,004
|
|
Performance
shares and options exercised
|
|
|
14,536
|
|
|
9,377
|
|
Balance
— end of period
|
|
$
|
2,910,261
|
|
$
|
2,863,212
|
|
|
|
|
|
|
|
|
|
Additional
Paid-in Capital
|
|
|
|
|
|
|
|
Balance
— beginning of period
|
|
$
|
39,619,849
|
|
$
|
36,854,717
|
|
Dividend
Reinvestment Plan
|
|
|
846,573
|
|
|
1,224,874
|
|
Retirement
Savings Plan
|
|
|
700,506
|
|
|
682,829
|
|
Conversion
of debentures
|
|
|
260,784
|
|
|
373,259
|
|
Performance
shares and options exercised
|
|
|
887,426
|
|
|
484,170
|
|
Exercise
of warrants
|
|
|
(387,282
|
)
|
|
-
|
|
Balance
— end of period
|
|
$
|
41,927,856
|
|
$
|
39,619,849
|
|
|
|
|
|
|
|
|
|
Retained
Earnings
|
|
|
|
|
|
|
|
Balance
— beginning of period
|
|
$
|
42,854,894
|
|
$
|
39,015,087
|
|
Net
income
|
|
|
6,572,346
|
|
|
10,467,614
|
|
Cash
dividends declared
|
|
|
(5,151,076
|
)
|
|
(6,627,807
|
)
|
Balance
— end of period
|
|
$
|
44,276,164
|
|
$
|
42,854,894
|
|
|
|
|
|
|
|
|
|
Accumulated
Other Comprehensive Income
|
|
|
|
|
|
|
|
Balance
— beginning of period
|
|
|
($578,151
|
)
|
|
(527,246
|
)
|
Minimum
pension liability adjustment, net of tax
|
|
|
-
|
|
|
(50,905
|
)
|
Balance
— end of period
|
|
|
($578,151
|
)
|
|
($578,151
|
)
|
|
|
|
|
|
|
|
|
Deferred
Compensation Obligation
|
|
|
|
|
|
|
|
Balance
— beginning of period
|
|
$
|
794,535
|
|
$
|
816,044
|
|
New
deferrals
|
|
|
310,135
|
|
|
130,426
|
|
Payout
of deferred compensation
|
|
|
-
|
|
|
(151,935
|
)
|
Balance
— end of period
|
|
$
|
1,104,670
|
|
$
|
794,535
|
|
|
|
|
|
|
|
|
|
Treasury
Stock
|
|
|
|
|
|
|
|
Balance
— beginning of period
|
|
|
($797,156
|
)
|
|
($1,008,696
|
)
|
New
deferrals related to compensation obligation
|
|
|
(310,135
|
)
|
|
(130,426
|
)
|
Purchase
of treasury stock (1)
|
|
|
(37,719
|
)
|
|
(182,292
|
)
|
Sale
and distribution of treasury stock (2)
|
|
|
40,340
|
|
|
524,258
|
|
Balance
— end of period
|
|
|
($1,104,670
|
)
|
|
($797,156
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Stockholders’ Equity
|
|
$
|
88,536,130
|
|
$
|
84,757,183
|
|
|
|
|
|
|
|
|
|
(1)
Amount includes shares purchased in the open market for the
Company’s
Rabbi
Trust to secure it's obligations under the Company’s
Supplemental Executive Retirement Savings Plan (“SERP
plan”).
|
|
(2)
Amount includes shares issued to the Company’s
Rabbi
Trust as obligation under the SERP plan. |
|
The
accompanying notes are an integral part of these financial
statements.
Chesapeake
Utilities Corporation and Subsidiaries
|
|
|
|
|
|
|
|
Condensed
Consolidated Statements of Comprehensive Income (Unaudited)
|
|
|
|
|
|
|
|
|
|
For
the Nine Months Ended September 30, 2006
|
|
For
the Twelve Months Ended December 31, 2005
|
|
Net
income
|
|
$
|
6,572,346
|
|
$
|
10,467,614
|
|
Minimum
pension liability adjustment, net of tax benefit of
$33,615
|
|
|
-
|
|
|
(50,905
|
)
|
Comprehensive
Income
|
|
$
|
6,572,346
|
|
$
|
10,416,709
|
|
The
accompanying notes are an integral part of these financial
statements.
Notes
to the 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 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 for the year ended
December 31, 2005 filed on March 7, 2006. 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.
2. |
Comprehensive
Income (Loss)
|
Comprehensive
income contains items that are excluded from “net income (loss)” and recorded
directly to stockholders’ equity. Chesapeake did not have any adjustments to the
components of 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,” for the three and nine
months ended September 30 2006 and 2005. Accumulated other comprehensive
income
was ($578,151) at September 30, 2006 and December 31, 2005 and ($527,246)
at
September 30, 2005 and December 31, 2004.
3. |
Calculation
of Earnings Per Share
(“EPS”)
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
For
the Periods Ended September 30,
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
Calculation
of Basic Earnings Per Share:
|
|
|
|
|
|
|
|
|
|
Net
Income (Loss)
|
|
|
($656,579
|
)
|
|
($693,774
|
)
|
$
|
6,572,346
|
|
$
|
6,334,946
|
|
Weighted
average shares outstanding
|
|
|
5,973,149
|
|
|
5,851,926
|
|
|
5,945,119
|
|
|
5,823,144
|
|
Basic
Earnings Per Share
|
|
|
($0.11
|
)
|
|
($0.12
|
)
|
$
|
1.11
|
|
$
|
1.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Calculation
of Diluted Earnings Per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation
of Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income (Loss)
|
|
|
($656,579
|
)
|
|
($693,774
|
)
|
$
|
6,572,346
|
|
$
|
6,334,946
|
|
Effect
of 8.25% Convertible debentures
(1)
|
|
|
-
|
|
|
-
|
|
|
79,900
|
|
|
94,441
|
|
Adjusted
numerator — Diluted
|
|
|
($656,579
|
)
|
|
($693,774
|
)
|
$
|
6,652,246
|
|
$
|
6,429,387
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation
of Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
shares outstanding — Basic
|
|
|
5,973,149
|
|
|
5,851,926
|
|
|
5,945,119
|
|
|
5,823,144
|
|
Effect
of dilutive securities (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
options
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
371
|
|
Warrants
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
11,262
|
|
8.25%
Convertible debentures
|
|
|
-
|
|
|
-
|
|
|
124,774
|
|
|
147,526
|
|
Adjusted
denominator — Diluted
|
|
|
5,973,149
|
|
|
5,851,926
|
|
|
6,069,893
|
|
|
5,982,303
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
Earnings per Share
|
|
|
($0.11
|
)
|
|
($0.12
|
)
|
$
|
1.10
|
|
$
|
1.07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
The amount of interest accumulated, per common share, for the
three-month
periods ended September 30, 2006 and 2005, obtainable from
the 8.25%
Convertible Debentures exceeds Basic EPS. The inclusion of
these
securities would therefore have an anti-dilutive effect on
EPS for the
three-month periods presented and, accordingly, have been omitted
from
this calculation for the quarter. The Company did not have
any outstanding
stock options or warrants at September 30, 2006.
|
|
4. |
Commitments
and Contingencies
|
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 gas manufacturing plant site located in Dover, Delaware. Chesapeake
is also currently participating in the investigation, assessment or remediation
of two additional former gas manufacturing plant sites located in Maryland
and
Florida. The Company has accrued liabilities for the three sites referred
to
respectively as the Dover Gas Light, Salisbury Town Gas Light and the Winter
Haven Coal Gas sites. The Company has been in discussions with the Maryland
Department of the Environment (“MDE”) regarding a fourth former gas
manufacturing plant site located in Cambridge, Maryland. The following provides
details of each site.
Dover
Gas Light Site
The
Dover
Gas Light site is a former manufactured gas plant site located in Dover,
Delaware. On January 15, 2004, the Company received a Certificate of Completion
of Work from the United States Environmental Protection Agency (“EPA”) regarding
this site. This concluded Chesapeake’s remedial action obligation related to
this site and relieves Chesapeake from liability for future remediation at
the
site, unless previously unknown conditions are discovered at the site, or
information previously unknown to the EPA is received that indicates the
remedial action that has been taken is not sufficiently protective. These
contingencies are standard and are required by the United States in all
liability settlements.
The
Company has reviewed its remediation costs incurred to date for the Dover
Gas
Light site and has concluded that all costs incurred have been paid. The
Company
does not expect any future environmental expenditures for this site. Through
September 30, 2006, the Company has incurred approximately $9.7 million in
costs
related to environmental testing and remedial action studies at the site.
Approximately $10.0 million has been recovered through September 2006 from
other
parties or through rates. As of September 30, 2006, a regulatory liability
of
approximately $343,000, 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
permanently decommission the AS/SVE system and to discontinue all on-site
and
off-site well monitoring, except for one well that is being maintained for
continued product monitoring and recovery. In November 2002, Chesapeake
submitted a letter to the MDE requesting a No Further Action determination.
The
Company has been in discussions with the MDE regarding such request and is
awaiting a determination from the MDE.
Through
September 30, 2006, the Company has incurred approximately $2.9 million for
remedial actions and environmental studies at the Salisbury Town Gas Light
site.
Of this amount, approximately $1.8 million has been recovered through insurance
proceeds or in rates. On
September 26, 2006, the Company received approval from the Maryland Public
Service Commission to recover through its rates charged to customers the
remaining $1.1 million of the incurred environmental remediation costs.
Winter
Haven Coal Gas Site
The
Winter Haven Coal Gas site is located in Winter Haven, Florida. Chesapeake
has
been working with the Florida Department of Environmental Protection (“FDEP”) in
assessing this coal gas site. In May 1996, the Company filed an AS/SVE Pilot
Study Work Plan (the “Work Plan”) for the Winter Haven site with the FDEP. The
Work Plan described the Company’s proposal to undertake an AS/SVE pilot study to
evaluate the site. After discussions with the FDEP, the Company filed a modified
Work Plan, the description of the scope of work to complete the site assessment
activities and a report describing a limited sediment investigation performed
in
1997. In December 1998, the FDEP approved the modified Work Plan, which the
Company completed during the third quarter of 1999. In February 2001, the
Company filed a Remedial Action Plan (“RAP”) with the FDEP to address the
contamination of the subsurface soil and ground-water in a portion of the
site.
The FDEP approved the RAP on May 4, 2001. Construction of the AS/SVE system
was
completed in the fourth quarter of 2002 and the system remains fully
operational.
The
Company has accrued a liability of $242,000 as of September 30, 2006 for
the
Winter Haven Coal Gas site. Through September 30, 2006, the Company has incurred
approximately $1.6 million of environmental costs associated with this site.
At
September 30, 2006, the Company had collected $102,000 through rates in excess
of costs incurred. A regulatory asset of approximately $140,000, representing
the uncollected portion of the estimated clean-up costs, has also been recorded.
The Company expects to recover the remaining costs through rates.
The
FDEP
has indicated that the Company may be required to remediate sediments along
the
shoreline of Lake Shipp, immediately west of the Winter Haven site. Based
on
studies performed to date, the Company objects to the FDEP’s suggestion that the
sediments have been contaminated and will require remediation. The Company’s
early estimates indicate that some of the corrective measures discussed by
the
FDEP may cost as much as $1 million. Given the Company’s view as to the absence
of ecological effects, the Company believes that cost expenditures of this
magnitude are unwarranted and plans to oppose any requirements that it undertake
corrective measures in the offshore sediments. Chesapeake anticipates that
it
will be several years before this issue is resolved. At this time, the Company
has not recorded a liability for sediment remediation. The outcome of this
matter cannot be predicted at this time.
Other
The
Company is in discussions with the MDE regarding a gas manufacturing plant
site
located in Cambridge, Maryland. The outcome of this matter cannot be determined
at this time; therefore, the Company has not recorded an environmental liability
for this location.
Natural
Gas and Propane Supply
The
Company’s natural gas and propane distribution operations have entered into
contractual commitments to purchase gas from various suppliers. The contracts
have various expiration dates. In November 2004, the Company renewed its
contract with an energy marketing and risk management company to manage a
portion of the Company’s natural gas transportation and storage capacity. The
contract expires March 31, 2007.
Corporate
Guarantees
The
Company has issued corporate guarantees to certain vendors of its propane
wholesale marketing subsidiary, its Florida natural gas marketing subsidiary,
and Delmarva propane distribution subsidiary. These corporate guarantees
provide
for the payment of propane and natural gas purchases in the event of the
subsidiaries’ default. The liabilities for these purchases are recorded in the
Consolidated Financial Statements. The aggregate amount guaranteed at September
30, 2006, totaled $18.9 million, with the guarantees expiring on various
dates
in 2006 and 2007.
In
addition to the corporate guarantees, the Company has issued a letter of
credit
to its primary insurance company for $775,000, which expires on May 31, 2007.
The letter of credit is provided as security for claims amounts to satisfy
the
deductibles on the Company’s policies. The current letter of credit was renewed
during the second quarter of 2006 when the insurance policies were renewed.
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 September 30, 2006 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, that 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
|
In
December 2004, the FASB released a revision (“Share-Based Payment”) to SFAS No.
123, “Accounting for Stock-Based Compensation,” referred to as SFAS No. 123R.
SFAS 123R establishes financial accounting and reporting standards for
stock-based employee compensation plans. Those plans include all arrangements
by
which employees receive shares of stock or other equity instruments of the
employer or the employer incurs liabilities to employees in amounts based
on the
price of the employer’s stock. Examples are stock purchase plans, stock options,
restricted stock and stock appreciation rights. The impact of the Company’s
adoption of this pronouncement is disclosed in Note 9 to the financial
statements entitled “Share Based Compensation.”
In
July
2006, the FASB issued FASB Interpretation 48, “Accounting for Income Tax
Uncertainties,” (“FIN 48”). FIN 48 defines the threshold for recognizing the
benefits of tax return positions in the financial statements as
“more-likely-than-not” to be sustained by the taxing authority. The recently
issued literature also provides guidance on the derecognition, measurement
and
classification of income tax uncertainties, along with any related interest
and
penalties. FIN 48 also includes guidance concerning accounting for income
tax
uncertainties in interim periods and increases the level of disclosures
associated with any recorded income tax uncertainties. FIN 48 is effective
for
fiscal years beginning after December 15, 2006. The differences between the
amounts recognized in the statements of financial position prior to the adoption
of FIN 48 and the amounts reported after adoption will be accounted for as
a
cumulative-effect adjustment recorded in retained earnings. The Company is
continuing to evaluate the impact of this new standard, if any, on the Company’s
financial statements.
In
September 2006, the FASB issued Statement No. 157, “Fair Value Measurements
”
(“SFAS
No. 157”), which clarifies that the term fair value is intended to mean a
market-based measure, not an entity-specific measure and gives the highest
priority to quoted prices in active markets in determining fair value. SFAS
No.
157 requires disclosures about (1) the extent to which companies measure
assets
and liabilities at fair value, (2) the methods and assumptions used to measure
fair value, and (3) the effect of fair value measures on earnings. SFAS No.
157
is effective for fiscal years beginning after November 15, 2007. The
Company is continuing to evaluate the impact of this new standard, if any,
on
the Company’s financial statements.
In
September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined
Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements
No. 87, 88, 106 and 132(R).” This statement would require a company to (a)
recognize in its statement of financial position an asset for a plan’s
overfunded status or a liability for a plan’s underfunded status, (b) measure a
plan’s assets and its obligations that determine its funded status as of the end
of the employer’s fiscal year, and (c) recognize changes in the funded status of
a defined postretirement plan in the year in which the changes occur and
to
report the changes as adjustments to comprehensive income. The requirement
to
recognize the funded status of a benefit plan and the disclosure requirements
are effective as of the end of the fiscal year ending after December 15,
2006.
The requirement to measure the plan assets and benefit obligations as of
the
date of the employer’s fiscal year-end statement of financial position is
effective for fiscal years ending after December 15, 2006. The
Company does not anticipate that the adoption of SFAS No. 158 will have a
material impact on the Company’s financial position, and anticipates no impact
to the statements of income or cash flows.
Chesapeake
uses the management approach to identify operating segments. Chesapeake
organizes its business around differences in products or services and the
operating results of each segment are regularly reviewed by the Company’s chief
operating decision maker in order to make decisions about resources and to
assess performance. The following table presents information about the Company’s
reportable segments.
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
For
the Periods Ended September 30,
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
Operating
Revenues, Unaffiliated Customers
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$
|
25,949,067
|
|
$
|
26,085,513
|
|
$
|
126,855,572
|
|
$
|
112,336,037
|
|
Propane
|
|
|
5,850,616
|
|
|
5,913,760
|
|
|
34,338,931
|
|
|
33,399,579
|
|
Advanced
information services
|
|
|
3,341,847
|
|
|
3,151,372
|
|
|
9,200,427
|
|
|
9,341,258
|
|
Other
|
|
|
-
|
|
|
4,476
|
|
|
1,025
|
|
|
143,871
|
|
Total
operating revenues, unaffiliated customers
|
|
$
|
35,141,530
|
|
$
|
35,155,121
|
|
$
|
170,395,955
|
|
$
|
155,220,745
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment
Revenues (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$
|
66,214
|
|
$
|
57,466
|
|
$
|
183,930
|
|
$
|
141,483
|
|
Propane
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
668
|
|
Advanced
information services
|
|
|
12,475
|
|
|
2,624
|
|
|
33,988
|
|
|
13,433
|
|
Other
|
|
|
154,623
|
|
|
154,623
|
|
|
463,869
|
|
|
463,869
|
|
Total
intersegment revenues
|
|
$
|
233,312
|
|
$
|
214,713
|
|
$
|
681,787
|
|
$
|
619,453
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$
|
1,760,552
|
|
$
|
1,130,620
|
|
$
|
13,256,385
|
|
$
|
12,116,857
|
|
Propane
|
|
|
(1,826,353
|
)
|
|
(1,425,028
|
)
|
|
1,165,748
|
|
|
1,814,135
|
|
Advanced
information services
|
|
|
321,528
|
|
|
186,425
|
|
|
509,898
|
|
|
(77,165
|
)
|
Other
and eliminations
|
|
|
(93,590
|
)
|
|
8,834
|
|
|
(127,298
|
)
|
|
(123,688
|
)
|
Total
operating income
|
|
$
|
162,137
|
|
|
($99,149
|
)
|
$
|
14,804,733
|
|
$
|
13,730,139
|
|
(1)
All significant intersegment revenues are billed at market
rates and have
been eliminated from consolidated revenues.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30, 2006
|
|
|
December
31, 2005
|
|
|
|
|
|
|
|
Identifiable
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$
|
224,192,686
|
|
$
|
225,667,049
|
|
|
|
|
|
|
|
Propane
|
|
|
64,449,789
|
|
|
57,344,859
|
|
|
|
|
|
|
|
Advanced
information services
|
|
|
2,701,590
|
|
|
2,062,902
|
|
|
|
|
|
|
|
Other
|
|
|
10,617,330
|
|
|
10,905,065
|
|
|
|
|
|
|
|
Total
identifiable assets
|
|
$
|
301,961,395
|
|
$
|
295,979,875
|
|
|
|
|
|
|
|
The
Company’s operations are all domestic. The advanced information services
segment, headquartered in Norcross, Georgia, provides domestic and international
clients with information technology related business services and solutions.
These transactions with foreign companies 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 retirement benefit plan and other post-retirement benefits are shown
below:
|
|
Defined
Benefit Pension Plan
|
|
Executive
Excess Retirement Benefit Plan
|
|
Other
Post-Retirement Benefits
|
|
For
the Three Months Ended September 30,
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
Service
Cost
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
$
|
1,564
|
|
$
|
1,564
|
|
Interest
Cost
|
|
|
161,212
|
|
|
161,435
|
|
|
29,897
|
|
|
29,915
|
|
|
19,468
|
|
|
19,468
|
|
Expected
return on plan assets
|
|
|
(174,191
|
)
|
|
(175,821
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Amortization
of transition amount
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
6,964
|
|
|
6,964
|
|
Amortization
of prior service cost
|
|
|
(1,174
|
)
|
|
(1,174
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Amortization
of net loss (gain)
|
|
|
-
|
|
|
-
|
|
|
14,259
|
|
|
12,329
|
|
|
22,072
|
|
|
22,072
|
|
Net
periodic (benefit) cost
|
|
|
($14,153
|
)
|
|
($15,560
|
)
|
$
|
44,156
|
|
$
|
42,244
|
|
$
|
50,068
|
|
$
|
50,068
|
|
|
|
Defined
Benefit Pension Plan
|
|
Executive
Excess Retirement Benefit Plan
|
|
Other
Post-Retirement Benefits
|
|
For
the Nine Months Ended September 30,
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
Service
Cost
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
$
|
4,693
|
|
$
|
4,693
|
|
Interest
Cost
|
|
|
474,664
|
|
|
484,305
|
|
|
89,691
|
|
|
89,744
|
|
|
58,404
|
|
|
58,404
|
|
Expected
return on plan assets
|
|
|
(516,343
|
)
|
|
(527,464
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Amortization
of transition amount
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
20,894
|
|
|
20,894
|
|
Amortization
of prior service cost
|
|
|
(3,524
|
)
|
|
(3,524
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Amortization
of net loss (gain)
|
|
|
-
|
|
|
-
|
|
|
42,779
|
|
|
36,989
|
|
|
66,218
|
|
|
66,218
|
|
Net
periodic (benefit) cost
|
|
|
($45,203
|
)
|
|
($46,683
|
)
|
$
|
132,470
|
|
$
|
126,733
|
|
$
|
150,209
|
|
$
|
150,209
|
|
As
disclosed in the December 31, 2005 financial statements, no contributions
are
expected to be required in 2006 for the defined benefit pension plan. The
Company maintains a Rabbi Trust to cover the costs of the executive excess
retirement benefit plan (Note 8); however, the other post-retirement benefit
plans are unfunded. Cash benefits paid under the executive excess retirement
benefit plan for the first nine months of 2006 were $73,000, and for the
year
2006, benefits paid are expected to be $100,000. Net benefits paid for other
post-retirement benefits are primarily for medical claims and were $121,000
for
the first nine months of 2006. For the year 2006, the Company has estimated
that
the benefits to be paid are $215,000.
The
Company maintains investments in a Rabbi Trust to cover the cost of the
Company’s Supplemental Executive Retirement Savings Plan. In accordance with
SFAS No. 115, “Accounting for Certain Investments in Debt and Equity
Securities,” and based on the Company’s intentions regarding these instruments,
the Company classifies all investments in equity securities as trading
securities. As a result of classifying them as trading securities, the Company
is required to report the securities at their fair value, with any unrealized
gains and losses included in earnings. At the end of September 2006, total
investments had a fair value of $1.9 million.
9. |
Share-Based
Compensation
|
Effective
January 1, 2006, the Company adopted SFAS No. 123R, “Share-Based Payment,” which
establishes accounting for equity instruments exchanged for employee services.
Prior to January 1, 2006, the Company accounted for share-based compensation
to
employees in accordance with Accounting Principles Board Opinion (“APB”) No. 25,
“Accounting for Stock Issued to Employees,” and related interpretations. The
Company also followed the disclosure requirements of SFAS No. 123, “Accounting
for Stock-Based Compensation,” as amended by SFAS No. 148, “Accounting for
Stock-Based Compensation — Transition and Disclosure.” Commencing January 1,
2006, the Company elected to adopt the modified prospective method as provided
by SFAS No. 123R and, accordingly, financial statement amounts for the prior
periods presented in this Form 10-Q have not been restated to reflect the
fair
value of expensing stock-based compensation.
For
the
three months ended September 30, 2006 and 2005, included in net income are
expense amounts of $173,000 and $206,000, after-tax, respectively, related
to
stock-based compensation expense from restricted stock awards issued under
the
Company’s Director’s Stock Compensation and Performance Incentive Plans. For the
first nine months of 2006 and 2005, included in net income are expense amounts
of $437,000 and $465,000, after-tax, respectively, related to stock-based
compensation expense from restricted stock awards issued under the Company’s
Director’s Stock Compensation and Performance Incentive Plans.
Stock
Options
The
Company did not have any stock options outstanding at September 30, 2006
or
December 31, 2005, nor were any stock options issued during the nine months
ended September 30, 2006.
Director’s
Stock Compensation Plan (“DSCP”)
Under
the
Company’s DSCP, each non-employee director receives an annual retainer of 600
shares of common stock and an additional 150 shares of common stock for services
as a committee chairman, subject to adjustment in future years consistent
with
the terms of the DSCP. Shares issued under the DSCP are fully vested as of
the
date of the grant. At the date of grant, the Company records a prepaid expense
equal to the fair value of the shares issued and amortizes the expense equally
over the service period of one year. Compensation
expense recorded by the Company relating to the DSCP awards was $44,000 and
$36,000 for the three-month periods ended September 30, 2006 and 2005,
respectively, and $121,000 and $104,000 for the first nine months of 2006
and
2005, respectively.
A
summary
of restricted stock activity for the DSCP as of September 30, 2006, and changes
during the nine months then ended, is presented below:
|
|
Number
of Restricted Shares
|
|
Weighted
Average Grant Date Fair Value
|
|
Outstanding
— December 31, 2005
|
|
|
-
|
|
|
|
|
Issued
— May 2, 2006
|
|
|
5,850
|
|
$
|
30.02
|
|
Vested
|
|
|
5,850
|
|
|
|
|
Outstanding
— September 30, 2006
|
|
|
-
|
|
|
|
|
Performance
Incentive Plans (“PIP”)
The
Company’s Compensation Committee of the Board of Directors is authorized to
grant to key employees of the Company the rights to receive awards of shares
of
the Company’s common stock, contingent upon the achievement of established
performance goals. These awards are made pursuant to the Company’s Performance
Incentive Plan, subject to certain post-vesting transfer restrictions, and
are
granted in the first quarter of each year based upon the performance achieved
in
the previous fiscal year. In the first quarters of 2006 and 2005, the Company
granted 23,666 and 10,130 shares, respectively, to key employees as PIP stock
awards for each of the preceding fiscal years.
The
Company accrues an expense each month of the fiscal year, preceding the date
of
grant, representing an estimate of the value of the stock awards to be granted
for the current fiscal year. This accrual process matches the compensation
expense with the employees’ service period rather than recognizing the expense
on the grant date, which occurs in the first quarter of the subsequent year.
The
shares granted under the PIP are fully vested and the fair value of each
share
is equal to the market price of the Company’s stock on the date of grant.
Compensation
expense recorded by the Company relating to the PIP was $239,000 and $302,000
for the three-month periods ended September 30, 2006 and 2005, respectively,
and
$596,000 and $659,000 for the first nine months of 2006 and 2005,
respectively.
A
summary
of restricted stock activity for the PIP as of September 30, 2006, and changes
during the nine months then ended, is presented below:
|
|
Number
of Restricted Shares
|
|
Weighted
Average Grant Date Fair Value
|
|
Outstanding
— December 31, 2005
|
|
|
-
|
|
|
|
|
Issued
— February 23, 2006
|
|
|
23,666
|
|
$
|
30.3999
|
|
Vested
|
|
|
23,666
|
|
|
|
|
Outstanding
— September 30, 2006
|
|
|
-
|
|
|
|
|
10.
Stockholders’ Equity
The
changes in common stock shares issued and outstanding are shown
below:
|
|
For
the Nine Months Ended September 30, 2006
|
|
For
the Twelve Months Ended December 31, 2005
|
|
Common
Stock shares issued and outstanding (1)
|
|
|
|
|
|
Shares
issued — beginning of period balance
|
|
|
5,883,099
|
|
|
5,778,976
|
|
Dividend
Reinvestment Plan (2)
|
|
|
28,075
|
|
|
41,175
|
|
Retirement
Savings Plan
|
|
|
22,932
|
|
|
21,071
|
|
Conversion
of debentures
|
|
|
15,797
|
|
|
22,609
|
|
Employee
award plan
|
|
|
350
|
|
|
-
|
|
Performance
shares and options exercised (3)
|
|
|
29,516
|
|
|
19,268
|
|
Shares
issued — end of period balance (4)
|
|
|
5,979,769
|
|
|
5,883,099
|
|
|
|
|
|
|
|
|
|
Treasury
shares — beginning of period balance
|
|
|
(97
|
)
|
|
(9,418
|
)
|
Purchases
|
|
|
-
|
|
|
(4,852
|
)
|
Dividend
Reinvestment Plan
|
|
|
-
|
|
|
2,142
|
|
Retirement
Savings Plan
|
|
|
-
|
|
|
12,031
|
|
Other
issuances
|
|
|
97
|
|
|
-
|
|
Treasury
Shares — end of period balance
|
|
|
-
|
|
|
(97
|
)
|
|
|
|
|
|
|
|
|
Total
Shares Outstanding
|
|
|
5,979,769
|
|
|
5,883,002
|
|
|
|
|
|
|
|
|
|
(1)
12,000,000 shares are authorized at a par value of $0.4867
per
share.
|
|
(2)
Includes shares purchased with reinvested dividends and optional
cash
payments.
|
|
(3)
Includes shares issued for Directors' compensation.
|
|
(4)
Includes 47,721 and 37,528 shares at September 30, 2006 and
December 31,
2005, respectively, held
in a Rabbi Trust established by the Company relating to the
Supplemental
Executive Retirement
Savings Plan.
|
|
In
2000
and 2001, the Company entered into agreements with an investment banker to
assist in identifying acquisition candidates. Under the agreements, the Company
issued warrants to the investment banker to purchase 15,000 share of Chesapeake
stock in 2000 at an exercise price of $18.00 per share and 15,000 shares
in 2001
at an exercise price of $18.25 per share.
In
August
2006, the investment banker exercised the 30,000 warrants pursuant to the
terms
of the agreement at $33.3657 per share. At the request of the investment
banker,
Chesapeake settled the warrants with a cash payment of $434,782, in lieu
of
issuing shares of the Company’s common stock. Chesapeake does not have any other
stock warrants outstanding at September 30, 2006.
11.
Other
Event
In
March
2006, the Company’s propane distribution subsidiary, Sharp Energy, Inc.
(“Sharp”), identified that approximately 75,000 gallons of propane that it
purchased contained above-normal levels of petroleum byproducts. The supplier’s
testing identified above-normal concentration levels of the petroleum byproduct
benzene. Benzene, which may be found in trace amounts in propane, is used
to
make plastics, resins, nylon, synthetic fibers, detergents, lubricants, drugs,
dyes and pesticides. It is also routinely found in crude oil and gasoline.
The
supplier has conducted modeling and testing of the propane in combustion
situations and has stated that they have found no health or safety concerns.
Sharp
replaced the propane for each of the approximately 600 customers impacted
by
this event at no cost to the customers. Sharp also replaced any remaining
propane contained at its storage facilities. The propane that the Company
retrieved from customers and Sharp’s storage facilities was returned to the
supplier.
The
supplier indicated that it would reimburse Sharp for all damages, costs and
expenses incurred by Sharp or the Company in connection with this matter.
As a
result of the supplier’s commitment, Sharp invoiced the supplier $734,000 for
costs relating to this incident through September 2006. The supplier has
paid
the entire amount and no amounts remain outstanding at September 30, 2006.
The
Company does not anticipate any additional costs in relation to the incident
and
does not believe that the event will ultimately have a material adverse effect
on the Company or its business, results of operations or long-term financial
condition.
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 on the Company’s financial condition, results of operations and
liquidity. The Company’s MD&A is presented in nine sections: Overview,
Results of Operations, Liquidity and Capital Resources, Off-Balance Sheet
Arrangements, Contractual Obligations, Environmental Matters, Other Matters,
Competition, and Recent Accounting Pronouncements. This discussion and analysis
should be read in conjunction with the attached unaudited consolidated financial
statements and notes thereto and Chesapeake’s 2005 Annual Report on Form 10-K,
including the audited consolidated financial statements and notes contained
in
the 2005 Annual Report on Form 10-K.
Overview
Chesapeake
Utilities Corporation (the “Company” or “Chesapeake”) is a diversified utility
company engaged 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 to grow earnings from a stable utility foundation by
investing in related businesses and services that provide opportunities for
higher, unregulated returns. This growth strategy includes acquisitions and
investments in unregulated businesses, as well as the continued investment
and
expansion of the Company’s utility operations that provide the stable base of
earnings. The Company continually reevaluates its investments to ensure that
they are consistent with its strategy and the goal of enhancing shareholder
value. The Company’s unregulated businesses and services currently include
natural gas marketing, propane distribution and wholesale marketing, advanced
information services and other related businesses.
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 natural gas and propane consumption is highest due to colder
temperatures.
The
principal business, economic and other factors that affect the operations
and/or
financial performance of the Company include:
· |
weather
conditions and weather patterns;
|
· |
regulatory
environment and regulatory decisions;
|
· |
availability
of natural gas and propane supplies;
|
· |
natural
gas and propane production levels;
|
· |
interstate
pipeline transportation and storage
capacity;
|
· |
natural
gas and propane prices and the prices of competing fuels, such as
oil and
electricity;
|
· |
changes
in natural gas and propane usage resulting from customer conservation,
including improved appliance
efficiencies;
|
· |
the
level of capital expenditures for adding new customers and replacing
facilities worn beyond economic repair;
|
· |
use
of derivative instruments;
|
· |
changes
in credit risk;
|
· |
competitive
environment;
|
· |
economic
conditions and interest rates;
|
· |
changes
in technology; and
|
· |
changes
in accounting principles.
|
Results
of Operations for the Three Months Ended September 30,
2006
Consolidated
Overview
The
Company’s operating income increased by $261,000 for the quarter ended September
30, 2006 compared to the same period in 2005. The Company’s seasonal net loss
for the quarter ended September 30, 2006 decreased $37,000, or 5 percent,
compared to the same period in 2005. The Company experienced a net loss of
$657,000, or $0.11 per share (diluted) — a decrease of $0.01 in the loss per
share when compared to 2005. The Company’s Delmarva natural gas distribution and
propane distribution operations typically experience seasonal losses during
the
third quarter, because heating customers do not require gas in the summer
months.
For
the Three Months Ended September 30,
|
|
2006
|
|
2005
|
|
Change
|
|
Operating
Income
|
|
|
|
|
|
|
|
Natural
Gas
|
|
$
|
1,760,552
|
|
$
|
1,130,620
|
|
$
|
629,932
|
|
Propane
|
|
|
(1,826,353
|
)
|
|
(1,425,028
|
)
|
|
(401,325
|
)
|
Advanced
Information Services
|
|
|
321,528
|
|
|
186,425
|
|
|
135,103
|
|
Other
& eliminations
|
|
|
(93,590
|
)
|
|
8,834
|
|
|
(102,424
|
)
|
Operating
Income
|
|
|
162,137
|
|
|
(99,149
|
)
|
|
261,286
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Loss)
|
|
|
(12,091
|
)
|
|
19,493
|
|
|
(31,584
|
)
|
Interest
Charges
|
|
|
1,340,879
|
|
|
1,272,196
|
|
|
68,683
|
|
Income
Taxes
|
|
|
(534,254
|
)
|
|
(658,078
|
)
|
|
123,824
|
|
Net
Loss
|
|
|
($656,579
|
)
|
|
($693,774
|
)
|
$
|
37,195
|
|
Diluted
Earnings Per Share
|
|
|
($0.11
|
)
|
|
($0.12
|
)
|
$
|
0.01
|
|
The
following discussions for the three months ended September 30, 2006 of segment
results include use of the term “gross margin”. Gross margin is determined by
deducting the cost of sales from operating revenue. Cost of sales includes
the
purchased gas cost for the natural gas and propane segments and the cost
of
labor spent on direct revenue-producing activities. Gross margin should not
be
considered an alternative to operating income or net income, which are
determined in accordance with Generally Accepted Accounting Principles (“GAAP”).
Chesapeake believes that gross margin, although a non-GAAP measure, is useful
and meaningful to investors as a basis for making investment decisions. It
provides investors with information that demonstrates the profitability achieved
by the Company under its allowed rates for regulated operations and under
its
competitive pricing structure for unregulated segments. Chesapeake’s management
uses gross margin in measuring its business units’ performance and has
historically analyzed and reported gross margin information publicly. Other
companies may calculate gross margin in a different manner.
Natural
Gas
The
natural gas segment earned operating income of $1.8 million for the third
quarter of 2006 compared to $1.1 million for the corresponding period last
year,
an increase of $630,000 or 56 percent. Gross margin increased by $706,000,
or 8
percent, while other operating expenses increased $76,000, or 1 percent.
For
the Three Months Ended September 30,
|
|
2006
|
|
2005
|
|
Change
|
|
Revenue
|
|
$
|
26,015,281
|
|
$
|
26,142,979
|
|
|
($127,698
|
)
|
Cost
of gas
|
|
|
15,982,581
|
|
|
16,816,684
|
|
|
(834,103
|
)
|
Gross
margin
|
|
|
10,032,700
|
|
|
9,326,295
|
|
|
706,405
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
& maintenance
|
|
|
5,800,783
|
|
|
5,946,564
|
|
|
(145,781
|
)
|
Depreciation
& amortization
|
|
|
1,562,522
|
|
|
1,416,664
|
|
|
145,858
|
|
Other
taxes
|
|
|
908,843
|
|
|
832,447
|
|
|
76,396
|
|
Other
operating expenses
|
|
|
8,272,148
|
|
|
8,195,675
|
|
|
76,473
|
|
Total
Operating Income
|
|
$
|
1,760,552
|
|
$
|
1,130,620
|
|
$
|
629,932
|
|
|
|
|
|
|
|
|
|
|
|
|
Statistical
Data — Delmarva Peninsula
|
|
|
|
|
|
|
|
|
|
|
Heating
degree-days (“HDD”)
|
|
|
|
|
|
|
|
|
|
|
Actual
|
|
|
45
|
|
|
31
|
|
|
14
|
|
10-year
average (normal)
|
|
|
60
|
|
|
60
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
gross margin per HDD
|
|
$
|
2,234
|
|
$
|
2,234
|
|
$
|
0
|
|
|
|
|
|
|
|
|
|
|
|
|
Per
residential customer added:
|
|
|
|
|
|
|
|
|
|
|
Estimated
gross margin
|
|
$
|
372
|
|
$
|
372
|
|
$
|
0
|
|
Estimated
other operating expenses
|
|
$
|
111
|
|
$
|
106
|
|
$
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
Customer Information
|
|
|
|
|
|
|
|
|
|
|
Average
number of customers
|
|
|
|
|
|
|
|
|
|
|
Delmarva
|
|
|
40,086
|
|
|
36,803
|
|
|
3,283
|
|
Florida
|
|
|
12,695
|
|
|
11,599
|
|
|
1,096
|
|
Total
|
|
|
52,781
|
|
|
48,402
|
|
|
4,379
|
|
Gross
margin for the Company’s natural gas segment increased $706,000 in the third
quarter of 2006 compared to the same period in 2005.
· |
The
Delmarva distribution operations experienced an increase of $121,000
in
gross margin. The Company added an average of 3,283 residential customers
in Delmarva, an increase of 9 percent, over 2005. The Company estimates
that these additional customers added $165,000 to gross margin, which
was
partially offset by lower volumes sold to existing customers and
lower
off-system sales.
|
· |
The
natural gas transmission operation achieved gross margin growth of
$486,000, or 14 percent. The increase was attributed to new transportation
services implemented in November 2005 and an increase in interruptible
revenues. The Company estimates that its annual gross margin for
its
natural gas transmission operation will be $1.7 million higher in
2006
than in 2005.
|
· |
Gross
margin for the Florida natural gas distribution and the unregulated
natural gas marketing operations increased $85,000 and $14,000,
respectively. The increases were attained primarily from continued
growth,
including a 9 percent increase in the average number of residential
customers.
|
Other
operating expenses for the natural gas operations increased $76,000, or 1
percent, in the third quarter of 2006 compared to the same period in 2005.
Items
contributing to the increase include:
· |
Due
to the additional capital investments by the Company, depreciation
and
amortization expense, asset removal cost, and property taxes increased
$146,000, $60,000, and $82,000, respectively.
|
· |
Payroll
costs decreased $137,000 primarily due to a decrease of $69,000 in
amounts
recognized in respect of incentive compensation reflecting the lower
than
expected earnings as a result of warmer weather. Also contributing
to the
reduction in payroll costs are other factors such as vacant positions
and
lower sales commissions.
|
· |
Health
care costs decreased by $101,000 for the natural gas segment during
the
third quarter of 2006. The Company changed health care service providers
in November 2005 and has subsequently experienced lower cost of claims.
|
Propane
The
seasonal operating loss for the propane segment increased $401,000, or 28
percent in the third quarter of 2006 compared to the same period in 2005.
This
segment typically experiences a loss during the third quarter, as heating
customers do not require propane during the summer months. The operating
loss
for the third quarter of 2006 was $1.8 million compared to an operating loss
of
$1.4 million for the same period in 2005.
For
the Three Months Ended September 30,
|
|
2006
|
|
2005
|
|
Change
|
|
Revenue
|
|
$
|
5,850,616
|
|
$
|
5,913,760
|
|
|
($63,144
|
)
|
Cost
of sales
|
|
|
3,967,428
|
|
|
3,427,896
|
|
|
539,532
|
|
Gross
margin
|
|
|
1,883,188
|
|
|
2,485,864
|
|
|
(602,676
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Operations
& maintenance
|
|
|
3,123,666
|
|
|
3,349,367
|
|
|
(225,701
|
)
|
Depreciation
& amortization
|
|
|
415,982
|
|
|
394,317
|
|
|
21,665
|
|
Other
taxes
|
|
|
169,893
|
|
|
167,208
|
|
|
2,685
|
|
Other
operating expenses
|
|
|
3,709,541
|
|
|
3,910,892
|
|
|
(201,351
|
)
|
Total
Operating Loss
|
|
|
($1,826,353
|
)
|
|
($1,425,028
|
)
|
|
($401,325
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Statistical
Data — Delmarva Peninsula
|
|
|
|
|
|
|
|
|
|
|
Heating
degree-days (“HDD”)
|
|
|
|
|
|
|
|
|
|
|
Actual
|
|
|
45
|
|
|
31
|
|
|
14
|
|
10-year
average (normal)
|
|
|
60
|
|
|
60
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
gross margin per HDD
|
|
$
|
1,743
|
|
$
|
1,743
|
|
$
|
0
|
|
The
Company’s propane segment experienced a decrease of $603,000 in gross margin in
the third quarter of 2006 compared to the same period in 2005, primarily
from a
decrease of $357,000 for the Delmarva propane distribution operation, a decrease
of $206,000 for the propane wholesale and marketing operation and a decrease
of
$39,000 for the Florida propane distribution operation.
· |
During
the third quarter of 2006, the Delmarva propane distribution operation
experienced a decrease in gross margin of $357,000. The reduction
in gross
margin is primarily attributed to a reduction in the average gross
margin
per retail gallon and lower service sales. The average gross margin
per
retail gallon decreased $0.13 in the third quarter of 2006 compared
to the
same period in 2005, which negatively affected gross margin by $244,000.
The decrease in gross margin per retail gallon was principally the
result
of a $175,000 write-down of propane inventory to reflect the lower
of cost
or market. The remaining $113,000 decrease of gross margin is from
a
combination of miscellaneous items, including lower service sales,
partially offset by an increase in fuel surcharges and other various
fees.
|
· |
Gross
margin for the Company’s propane wholesale marketing operation decreased
by $206,000 in the third quarter of 2006 compared to the same period
in
2005. The decrease is primarily due to the decrease of wholesale
propane
prices experienced in the third quarter of 2006, in contrast to the
rising
prices experienced in the third quarter of 2005 in response to the
hurricanes in the Gulf of Mexico area.
|
· |
The
Florida propane distribution operation experienced a decrease of
$39,000
in gross margin for the third quarter of 2006 compared to the same
period
in 2005. The lower gross margin reflects a decrease of $70,000 in
house-piping sales as the operation is exiting the house-piping service.
This was partially offset by an increase in propane margins of $34,000.
|
Other
operating expenses decreased for the three months ended September 30, 2006
by
$201,000, compared to the same period in 2005. Items contributing to the
decrease include payroll and health care costs:
· |
Payroll
costs decreased $94,000 primarily due to a decrease of $116,000 in
amounts
recognized with respect to incentive compensation reflecting the
lower
than expected earnings.
|
· |
Health
care costs decreased by $104,000 for the third quarter of 2006. The
Company changed health care service providers in November 2005 and
has
subsequently experienced lower cost of claims.
|
Advanced
Information Services
Operating
income for the Company’s advanced information services business increased
$135,000 for the three months ended September 30, 2006 compared to the same
period in 2005. Operating income for the third quarter was $322,000 compared
to
$186,000 for the same period in 2005. Negatively affecting operating income
in
the third quarter of 2005 was an operating loss of $111,000 for the Lightweight
Association Management Processing Systems (“LAMPS™”) product. LAMPS™ is an
internet-based membership management software tool specifically developed
for
REALTOR® Associations, which provides real time integration with the National
Association of REALTOR® Database System. The LAMPSTM
product
was sold to Fidelity National Information Solutions, Inc., a subsidiary of
Fidelity National Financial, Inc. in October 2005.
For
the Three Months Ended September 30,
|
|
2006
|
|
2005
|
|
Change
|
|
Revenue
|
|
$
|
3,354,322
|
|
$
|
3,153,996
|
|
$
|
200,326
|
|
Cost
of sales
|
|
|
1,808,549
|
|
|
1,710,440
|
|
|
98,109
|
|
Gross
margin
|
|
|
1,545,773
|
|
|
1,443,556
|
|
|
102,217
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
& maintenance
|
|
|
1,081,606
|
|
|
1,114,599
|
|
|
(32,993
|
)
|
Depreciation
& amortization
|
|
|
25,325
|
|
|
31,038
|
|
|
(5,713
|
)
|
Other
taxes
|
|
|
117,314
|
|
|
111,494
|
|
|
5,820
|
|
Other
operating expenses
|
|
|
1,224,245
|
|
|
1,257,131
|
|
|
(32,886
|
)
|
Total
Operating Income
|
|
$
|
321,528
|
|
$
|
186,425
|
|
$
|
135,103
|
|
The
Company’s advanced information services segment increased gross margin by
$102,000 to $1.5 million, compared to the same period in 2005. Revenues for
the
period increased $200,000 to $3.4 million in the third quarter 2006 compared
to
2005, due primarily to an increase of $373,000 in consulting revenues. The
number of billable hours and the average hourly billing rate both increased
15
percent for the quarter ended September 30, 2006 compared to the same period
in
2005. Included in the 2005 revenue is $92,000 of revenue generated by the
LAMPSTM
product.
Cost
of
sales for the three months ended September 30, 2006 increased $98,000 to
$1.8
million, compared to the same period in 2005. The 2005 cost of sales of $1.7
million includes $116,000 related to LAMPSTM.
The
higher cost of sales in 2006 is related directly to the increased
revenues.
Other
operating expenses decreased $33,000 for the three months ended September
30,
2006 to $1.2 million, when compared to same period in 2005. The reduction
in
other operating expenses is primarily attributed to the following:
· |
The
elimination of $87,000 of expenses in the third quarter of 2005 associated
with the LAMPSTM
product.
|
· |
Payroll
and benefit costs were lower by $63,000 and $43,000,
respectively.
|
· |
Lower
rental expense of $60,000 as the operation eliminated unnecessary
office
space.
|
· |
Incentive
compensation and commissions increased $137,000 and $50,000, respectively,
to reflect the improved earnings.
|
Effective
July 1, 2006, the Company changed the retirement savings, or 401(k), plan
for
the employees of its advanced information services segment and implemented
a
profit sharing plan. The net effect of the change is to reduce the Company’s
costs during those years when the segment is not meeting its earnings targets
in
exchange for higher compensation to the employees when the segment exceeds
its
targets.
Other
Business Operations and Eliminations
Other
operations consist primarily of subsidiaries that own real estate leased
to
other Company subsidiaries and the results of operations for OnSight Energy,
LLC
(“OnSight”). Eliminations are entries required to eliminate activities between
business segments from the consolidated results. Other operations and
eliminating entries resulted in an operating loss of $94,000 for the third
quarter of 2006 compared to operating income of $9,000 for the same period
in
2005. The loss in 2006 is attributed primarily to the OnSight
operation.
The
Company formed OnSight in 2004 to provide distributed energy services.
Distributed energy refers to a variety of small, modular power generating
technologies that may be combined with heating and/or cooling systems. For
the
third quarter of 2006, OnSight had an operating loss of $160,000 compared
to an
operating loss of $63,000 for the same period in 2005. OnSight has taken
action
to reduce costs going forward, which has caused a one-time charge of $65,000
to
other operating expense in the month of September 2006.
For
the Three Months Ended September 30,
|
|
2006
|
|
2005
|
|
Change
|
|
Revenue
|
|
$
|
154,623
|
|
$
|
159,099
|
|
|
($4,476
|
)
|
Cost
of sales
|
|
|
-
|
|
|
2,951
|
|
|
(2,951
|
)
|
Gross
margin
|
|
|
154,623
|
|
|
156,148
|
|
|
(1,525
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Operations
& maintenance
|
|
|
187,229
|
|
|
81,589
|
|
|
105,640
|
|
Depreciation
& amortization
|
|
|
41,120
|
|
|
54,448
|
|
|
(13,328
|
)
|
Other
taxes
|
|
|
20,633
|
|
|
18,479
|
|
|
2,154
|
|
Other
operating expenses
|
|
|
248,982
|
|
|
154,516
|
|
|
94,466
|
|
Operating
Income (Loss) - Other
|
|
|
(94,359
|
)
|
|
1,632
|
|
|
(95,991
|
)
|
Operating
Income - Eliminations
|
|
|
769
|
|
|
7,202
|
|
|
(6,433
|
)
|
Total
Operating Income (Loss)
|
|
|
($93,590
|
)
|
$
|
8,834
|
|
|
($102,424
|
)
|
Interest
Expense
Interest
expense for the third quarter of 2006 increased approximately $69,000, or
5
percent, to $1.34 million compared to $1.27 million for the same period in
2005.
The higher interest expense is attributed to the following:
· |
The
Company’s outstanding average short-term borrowing balance was $30.0
million for the quarter ended September 30, 2006 compared to $1.5
million
outstanding for the quarter ended September 30, 2005. The increased
borrowing, resulting in higher interest expense, is related to the
Company’s capital investments made in the 12 months ended September 30,
2006 and higher working capital due to the rising costs of natural
gas and
propane.
|
· |
The
average interest rate on short-term borrowing increased from 4.30%
in the
third quarter of 2005, to 5.73% for the same period in
2006.
|
· |
The
increase in interest expense on short-term borrowing was partially
offset
by a decrease in interest expense on long-term debt. The Company’s average
long-term debt balance declined from $68.1 million in the third quarter
of
2005 to $62.7 million for the third quarter of 2006, which lowered
interest expense for the period by
$94,000.
|
Income
Taxes
Due
to
the seasonal loss, Chesapeake had an income tax benefit of $534,000 for the
three months ended September 30, 2006 compared to a benefit of $658,000 for
the
three months ended September 30, 2005. The effective tax rate for the third
quarter of 2006 is 44.8 percent compared to an effective tax rate of 48.7
percent for the same period in 2005. The seasonality of the Company’s business
segments impacts the effective tax rate on interim reporting
periods.
Results
of Operations for the Nine
Months Ended September 30, 2006
Consolidated
Overview
Net
income for the Company increased $237,000, or 4 percent, for the nine months
ended September 30, 2006 when compared to the same period in 2005, despite
temperatures on the Delmarva Peninsula being 20 percent warmer in 2006. The
Company estimates that the warmer weather reduced net income by $1.5 million,
or
$0.25 per share, and reduced gross margin by $2.5 million in the first nine
months of 2006. The warmer weather was more than offset by the increase from
the
growth experienced by the natural gas operations, the improved results from
advanced information services and continued cost management. Net income was
$6.6
million, or $1.10 per share (diluted), for the nine months ended September
30,
2006 compared to $6.3 million, or $1.07 per share (diluted), for the same
period
in 2005.
For
the Nine Months Ended September 30,
|
|
2006
|
|
2005
|
|
Change
|
|
Operating
Income
|
|
|
|
|
|
|
|
Natural
Gas
|
|
$
|
13,256,385
|
|
$
|
12,116,857
|
|
$
|
1,139,528
|
|
Propane
|
|
|
1,165,748
|
|
|
1,814,135
|
|
|
(648,387
|
)
|
Advanced
Information Services
|
|
|
509,898
|
|
|
(77,165
|
)
|
|
587,063
|
|
Other
& eliminations
|
|
|
(127,298
|
)
|
|
(123,688
|
)
|
|
(3,610
|
)
|
Operating
Income
|
|
|
14,804,733
|
|
|
13,730,139
|
|
|
1,074,594
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income
|
|
|
130,208
|
|
|
330,354
|
|
|
(200,146
|
)
|
Interest
Charges
|
|
|
4,335,568
|
|
|
3,823,140
|
|
|
512,428
|
|
Income
Taxes
|
|
|
4,027,027
|
|
|
3,902,407
|
|
|
124,620
|
|
Net
Income
|
|
$
|
6,572,346
|
|
$
|
6,334,946
|
|
$
|
237,400
|
|
Diluted
Earnings Per Share
|
|
$
|
1.10
|
|
$
|
1.07
|
|
$
|
0.03
|
|
The
following discussions for the nine months ended September 30, 2006 of segment
results include use of the term “gross margin”. Gross margin is determined by
deducting the cost of sales from operating revenue. Cost of sales includes
the
purchased gas cost for the natural gas and propane segments 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 Generally Accepted Accounting Principles (“GAAP”). Chesapeake
believes that gross margin, although a non-GAAP measure, is useful and
meaningful to investors as a basis for making investment decisions. It provides
investors with information that demonstrates the profitability achieved by
the
Company under its allowed rates for regulated operations and under its
competitive pricing structure for unregulated segments. Chesapeake’s management
uses gross margin in measuring its business units’ performance and has
historically analyzed and reported gross margin information publicly. Other
companies may calculate gross margin in a different manner.
Natural
Gas
The
natural gas segment earned an operating income of $13.3 million for the first
nine months of 2006 compared to $12.1 million for the corresponding period
in
2005, an increase of $1.1 million, or 9 percent.
For
the Nine Months Ended September 30,
|
|
2006
|
|
2005
|
|
Change
|
|
Revenue
|
|
$
|
127,039,502
|
|
$
|
112,477,520
|
|
$
|
14,561,982
|
|
Cost
of gas
|
|
|
89,149,159
|
|
|
75,830,911
|
|
|
13,318,248
|
|
Gross
margin
|
|
|
37,890,343
|
|
|
36,646,609
|
|
|
1,243,734
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
& maintenance
|
|
|
17,168,706
|
|
|
17,612,547
|
|
|
(443,841
|
)
|
Depreciation
& amortization
|
|
|
4,615,605
|
|
|
4,262,737
|
|
|
352,868
|
|
Other
taxes
|
|
|
2,849,647
|
|
|
2,654,468
|
|
|
195,179
|
|
Other
operating expenses
|
|
|
24,633,958
|
|
|
24,529,752
|
|
|
104,206
|
|
Total
Operating Income
|
|
$
|
13,256,385
|
|
$
|
12,116,857
|
|
$
|
1,139,528
|
|
|
|
|
|
|
|
|
|
|
|
|
Statistical
Data — Delmarva Peninsula
|
|
|
|
|
|
|
|
|
|
|
Heating
degree-days (“HDD”)
|
|
|
|
|
|
|
|
|
|
|
Actual
|
|
|
2,502
|
|
|
3,138
|
|
|
(636
|
)
|
10-year
average (normal)
|
|
|
2,797
|
|
|
2,853
|
|
|
(56
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
gross margin per HDD
|
|
$
|
2,234
|
|
$
|
2,234
|
|
$
|
0
|
|
|
|
|
|
|
|
|
|
|
|
|
Per
residential customer added:
|
|
|
|
|
|
|
|
|
|
|
Estimated
gross margin
|
|
$
|
372
|
|
$
|
372
|
|
$
|
0
|
|
Estimated
other operating expenses
|
|
$
|
111
|
|
$
|
106
|
|
$
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
Customer Information
|
|
|
|
|
|
|
|
|
|
|
Average
number of customers
|
|
|
|
|
|
|
|
|
|
|
Delmarva
|
|
|
40,112
|
|
|
37,023
|
|
|
3,089
|
|
Florida
|
|
|
12,545
|
|
|
11,643
|
|
|
902
|
|
Total
|
|
|
52,657
|
|
|
48,666
|
|
|
3,991
|
|
Gross
margin for the Company’s natural gas segment increased $1.2 million in the first
nine months of 2006 compared to the same period in 2005. The gross margin
for
the Delmarva natural gas distribution operations was lower when compared
to the
same period in 2005 by $516,000, primarily due to warmer weather. However,
this
decline was offset by increased gross margin in the natural gas transmission
operation of $1.1 million, increased gross margin in the natural gas marketing
operation of $417,000 and increased gross margin for the Florida natural
gas
distribution operation of $197,000.
· |
The
Delmarva distribution operations experienced a decrease of $516,000
in
gross margin. Temperatures on the Delmarva Peninsula were 20 percent
warmer during the first nine months of 2006 compared to same period
in
2005. The Company estimates that the warmer temperatures led to a
decrease
in gross margin of approximately $1.4 million when compared to 2005.
This
decrease was partially offset by the continued residential customer
growth
in the Delmarva Peninsula. The average number of residential customers
increased 3,089, or 8 percent, for the first nine months of 2006
compared
to the same period in 2005. The Company estimates these new residential
customers contributed approximately $885,000 to gross margin.
|
· |
The
natural gas transmission operation achieved gross margin growth of
$1.1
million, or 10 percent. The increase was attributed primarily to
the new
transportation services implemented in November 2005. The Company
estimates that its annual gross margin for its natural gas transmission
operation will be $1.7 million higher in 2006 than in
2005.
|
· |
Gross
margin for the natural gas marketing operation increased $417,000,
or 35
percent. The increase was attained primarily from an increase in
the
number of customers to which the operation provides supply management
services and the operation’s ability to sell excess
capacity.
|
· |
Gross
margin for the Florida distribution operation increased by $197,000.
The
impact of an 8 percent growth in residential customers more than
offset
the decrease in gross margin from lower volumes sold to commercial
and
industrial customers.
|
Other
operating expenses for the natural gas operations increased $104,000 for
the
nine months ended September 30, 2006 compared to the same period in 2005.
The
significant items contributing to the increase are explained below. In addition,
there is a decrease of approximately $49,000 in other operating expenses
relating to various immaterial items.
· |
Depreciation
and amortization expense, asset removal cost, and property taxes
increased
$353,000, $173,000, and $171,000, respectively, as a result of the
Company’s continued capital investments.
|
· |
Payroll
costs increased $164,000 as the Company increased its staff to support
strong customer growth. This increase was offset by a decrease of
$280,000
in incentive compensation to reflect lower than expected earnings,
primarily from the Delmarva distribution operations, as weather was
warmer
than normal.
|
· |
Health
care costs decreased by $240,000 for the natural gas segment during
the
first nine months of 2006. The Company changed health care service
providers in November 2005 and has subsequently experienced lower
costs
related to claims.
|
· |
On
August 1, 2006, the Company’s interstate pipeline subsidiary, Eastern
Shore Natural Gas Company, (“Eastern Shore”) received approval from the
FERC to recover the pre-service costs associated with a future pipeline
project through its rates with two of its customers. Please refer
to the
Regulatory Matters section under Other Matters within Item 2 of the
Management’s Discussion and Analysis for additional details. As a result
of the FERC’s recent approval, the Company deferred these costs by
recording a regulatory asset. Of the costs deferred as a regulatory
asset,
$188,000 had been previously recorded as other operating expense
in 2005
prior to the receipt of the FERC’s approval to
defer.
|
Propane
Operating
income for the propane segment decreased $648,000, or 36 percent, to $1.2
million for the first nine months of 2006 compared to the same period in
2005.
This decrease was due primarily to warmer weather in the first nine months
of
2006, resulting in reduced customer consumption.
For
the Nine Months Ended September 30,
|
|
2006
|
|
2005
|
|
Change
|
|
Revenue
|
|
$
|
34,338,931
|
|
$
|
33,400,247
|
|
$
|
938,684
|
|
Cost
of sales
|
|
|
21,845,239
|
|
|
19,968,448
|
|
|
1,876,791
|
|
Gross
margin
|
|
|
12,493,692
|
|
|
13,431,799
|
|
|
(938,107
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Operations
& maintenance
|
|
|
9,488,865
|
|
|
9,830,244
|
|
|
(341,379
|
)
|
Depreciation
& amortization
|
|
|
1,235,366
|
|
|
1,194,644
|
|
|
40,722
|
|
Other
taxes
|
|
|
603,713
|
|
|
592,776
|
|
|
10,937
|
|
Other
operating expenses
|
|
|
11,327,944
|
|
|
11,617,664
|
|
|
(289,720
|
)
|
Total
Operating Income
|
|
$
|
1,165,748
|
|
$
|
1,814,135
|
|
|
($648,387
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Statistical
Data — Delmarva Peninsula
|
|
|
|
|
|
|
|
|
|
|
Heating
degree-days (“HDD”)
|
|
|
|
|
|
|
|
|
|
|
Actual
|
|
|
2,502
|
|
|
3,138
|
|
|
(636
|
)
|
10-year
average (normal)
|
|
|
2,797
|
|
|
2,853
|
|
|
(56
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
gross margin per HDD
|
|
$
|
1,743
|
|
$
|
1,743
|
|
$
|
0
|
|
The
Company’s propane segment experienced a decrease of approximately $938,000 in
gross margin in the first nine months of 2006 compared to the same period
in
2005. Gross margin in the Delmarva propane distribution operations was lower
when compared to the same period in 2005 by $933,000, primarily due to warmer
weather. Gross margin also decreased in the Florida propane operation by
$151,000. The negative impact of the warmer weather experienced by the Delmarva
propane distribution operation was partially offset by increased gross margin
from Community Gas Systems (“CGS”) of $60,000 and increased gross margin from
the Company’s wholesale propane marketing operation of $86,000.
· |
The
Delmarva propane distribution operation experienced a decrease in
gross
margin of $933,000. Volumes sold in 2006 decreased 1.9 million gallons,
or
12 percent. Temperatures on the Delmarva Peninsula were 20 percent
warmer
during the first nine months of 2006 compared to 2005. The Company
estimates that the warmer temperatures resulted in a decrease in
gross
margin of approximately $1.1 million when compared to 2005. Partially
offsetting the weather impact is an increase of $434,000 in gross
margin
from an increase in the average gross margin per retail gallon of
$0.017
in 2006 compared to 2005. The remaining gross margin decrease of
$267,000
can be attributed to such items as customer conservation and changes
in
the timing of deliveries to customers.
|
· |
Gross
margin for the CGS increased $60,000 when compared to the prior period,
primarily from an increase in the number of customers. The average
number
of customers increased 1,038, or 35 percent, to 4,010 for the first
nine
months of 2006, compared to the same period in 2005. The Company
expects
the growth of its CGS operation to continue as the number of systems
currently under construction or under contract is anticipated to
provide
for an additional 8,000 customers.
|
· |
The
Florida propane distribution operation experienced a decrease in
gross
margin of $151,000 when compared to the same period in 2005. The
lower
gross margin reflects a decrease of $321,000 for in-house piping
sales as
the operation exits the house piping service, which was partially
offset
by an increase in gross margin of $107,000 from propane sales.
|
· |
Gross
margin for the Company’s propane wholesale marketing operation increased
by $86,000 in the first nine months of 2006 compared to the same
period in
2005. The increase is primarily due to the increase in volatility
of
wholesale propane prices that occurred during the nine.
|
Other
operating expenses of the propane segment decreased for the first nine months
of
2006 by $290,000, compared to the same period in 2005. The decrease is primarily
attributed to a decrease of $267,000 in other operating expenses for the
Delmarva propane distribution operation, including CGS. The decreased costs
for
the Delmarva operations were due to $387,000 in fixed costs being recovered
in
the first quarter of 2006 from a propane supplier as a result of the delivery
of
propane to the Company that contained above normal levels of petroleum
by-products, as well as, a decrease of $207,000 in health insurance costs.
Please refer to Note 11, “Other Event”, for more information on the event
relating to the delivery of the product containing above normal levels of
petroleum by-product. These lower costs were partially offset by increased
costs
of $176,000 for one of the Pennsylvania start-ups, which began operation
in July
2005, and increased payroll costs of $109,000 and higher costs of $84,000
associated with vehicle fuel.
Advanced
Information Services
Operating
income for advanced information services business increased $587,000 for
the
nine months ended September 30, 2006 compared to the same period in 2005.
Operating income for the first nine months was $510,000 compared to an operating
loss of $77,000 for the same period in 2005. Contributing to the operating
loss
in 2005 was an operating loss of $461,000 for LAMPS™. The LAMPSTM
product
was sold to Fidelity National Information Solutions, Inc., a subsidiary of
Fidelity National Financial, Inc. in October 2005.
For
the Nine Months Ended September 30,
|
|
2006
|
|
2005
|
|
Change
|
|
Revenue
|
|
$
|
9,234,415
|
|
$
|
9,354,691
|
|
|
($120,276
|
)
|
Cost
of sales
|
|
|
5,193,574
|
|
|
5,538,195
|
|
|
(344,621
|
)
|
Gross
margin
|
|
|
4,040,841
|
|
|
3,816,496
|
|
|
224,345
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
& maintenance
|
|
|
3,054,288
|
|
|
3,392,482
|
|
|
(338,194
|
)
|
Depreciation
& amortization
|
|
|
87,264
|
|
|
91,167
|
|
|
(3,903
|
)
|
Other
taxes
|
|
|
389,391
|
|
|
410,012
|
|
|
(20,621
|
)
|
Other
operating expenses
|
|
|
3,530,943
|
|
|
3,893,661
|
|
|
(362,718
|
)
|
Total
Operating Income (Loss)
|
|
$
|
509,898
|
|
|
($77,165
|
)
|
$
|
587,063
|
|
The
Company’s advanced information services segment increased gross margin by
$224,000 to $4.0 million for the first nine months of 2006, compared to the
same
period in 2005. Revenues for the period decreased $120,000 compared to 2005,
due
primarily to decreases of $355,000 and $109,000 in product sales and training
revenues, respectively, which were partially offset by an increase of $376,000
in consulting revenues. The number of billable hours and average hourly billing
rate increased 1 and 7 percents, respectively, for the nine months ended
September 30, 2006 compared to the same period in 2005. Included in the 2005
revenue is $308,000 of revenue generated by the LAMPSTM
product.
Cost
of
sales for the nine months ended September 30, 2006 decreased $345,000 to
$5.2
million, compared to the same period in 2005. The 2005 cost of sales of $5.5
million includes $372,000 related to LAMPSTM.
Absent
the cost of sales associated with the LAMPSTM
product,
cost of sales remained consistent in first nine months of 2006 compared to
the
first nine months of 2005.
Other
operating expenses decreased $363,000 for the nine months ended September
30,
2006 to $3.5 million, when compared to same period in 2005. The reduction
in
expenses primarily reflects expenses of $397,000 in the nine months ended
September 2005 associated with LAMPSTM,
partially offset by an increase in incentive compensation to reflect the
improved earnings.
Other
Business Operations and Eliminations
Other
operations consist primarily of subsidiaries that own real estate leased
to
other Company subsidiaries and the results of operations for OnSight.
Eliminations are entries required to eliminate activities between business
segments from the consolidated results. Other operations and eliminating
entries
resulted in an operating loss of $127,000 for the first nine months of 2006
compared to an operating loss of $124,000 for the same period in 2005. The
losses in 2006 and 2005 are primarily attributed to the OnSight operation.
For
the first nine months of 2006, OnSight had an operating loss of $357,000
compared to an operating loss of $318,000 for the same period in 2005.
For
the Nine Months Ended September 30,
|
|
2006
|
|
2005
|
|
Change
|
|
Revenue
|
|
$
|
464,894
|
|
$
|
607,740
|
|
|
($142,846
|
)
|
Cost
of sales
|
|
|
874
|
|
|
115,578
|
|
|
(114,704
|
)
|
Gross
margin
|
|
|
464,020
|
|
|
492,162
|
|
|
(28,142
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Operations
& maintenance
|
|
|
410,620
|
|
|
389,623
|
|
|
20,997
|
|
Depreciation
& amortization
|
|
|
122,604
|
|
|
176,089
|
|
|
(53,485
|
)
|
Other
taxes
|
|
|
60,404
|
|
|
73,418
|
|
|
(13,014
|
)
|
Other
operating expenses
|
|
|
593,628
|
|
|
639,130
|
|
|
(45,502
|
)
|
Operating
Loss - Other
|
|
|
(129,608
|
)
|
|
(146,968
|
)
|
|
17,360
|
|
Operating
Income - Eliminations
|
|
|
2,310
|
|
|
23,280
|
|
|
(20,970
|
)
|
Total
Operating Loss
|
|
|
($127,298
|
)
|
|
($123,688
|
)
|
|
($3,610
|
)
|
Interest
Expense
Interest
expense for the first nine months of 2006 increased approximately $512,000,
or
13 percent, to $4.3 million compared to $3.8 million for the same period
in
2005. The higher interest expense is attributed to the following:
· |
Interest
on short-term debt increased $1.1 million during the first nine months
of
2006, compared to the same period during 2005, as a result of an
increase
in the average balance of short-term debt outstanding increased from
$1.2
million for the first nine months of 2005 to $27.7 million for the
first
nine months of 2006.
|
· |
The
average interest rate on short-term borrowing increased from 3.66
percent
for the first nine months of 2005, to 5.39 percent for the same period
in
2006.
|
· |
The
increase in interest expense on short-term borrowing was partially
offset
by a decrease in interest expense on long-term debt. Interest on
long-term
debt decreased $291,000 as a result of the average long-term debt
balance
declining from $67.9 million in the first nine months of 2005 to
$62.8
million for the first nine months of 2006 due to scheduled
principal repayments.
|
Income
Taxes
Income
tax expense for the nine-month periods ended September 30, 2006 was $4.0
million
compared to $3.9 million for the nine months ended September 30, 2005. The
effective tax rate for the first nine months of 2006 is 38.0 percent compared
to
an effective tax rate of 38.1 percent for the same period in 2005.
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 and short-term borrowing to meet normal working capital requirements
and to temporarily finance capital expenditures. During the first nine months
of
2006, net cash provided by operating activities was $19.0 million, cash used
by
investing activities was $28.3 million and cash generated by financing
activities was $9.2 million.
During
the first nine months of 2005, net cash provided by operating activities
was
$19.0 million, cash used by investing activities was $19.7 million and cash
used
by financing activities was $225,000.
At
the
Company’s meeting of the Board of Directors (“the Board”) on August 8, 2006, the
Board increased the Company’s authority to borrow short-term debt from $60.0
million to $75.0 million. Chesapeake currently has four unsecured bank lines
of
credit with two financial institutions, totaling $80.0 million. These bank
lines
will provide funds for the Company’s short-term cash needs to meet seasonal
working capital requirements and to temporarily fund portions of its capital
expenditures. Two of the bank lines, totaling $15.0 million, are committed.
The
other two lines are subject to the banks’ availability of funds. The outstanding
balance of short-term borrowing at September 30, 2006 and 2005 was $51.3
million
and $10.6 million, respectively.
On
October 12, 2006, the Company issued $20 million of 5.5 percent Senior Notes
(“Notes”) to three institutional investors (The Prudential Insurance Company of
America, Prudential Retirement Insurance and Annuity Company and United Omaha
Life Insurance Company). The original note agreement was executed on October
18,
2005 and provided for the Company to sell the Notes at any time prior to
January
15, 2007. The terms of the Notes require annual principal repayments of $2
million beginning on the fifth anniversary of the issuance of the Notes.
The
Notes will mature on October 12, 2020.
Chesapeake
has budgeted $54.4 million for capital expenditures during 2006. This amount
includes $20.8 million for natural gas distribution, $26.7 million for natural
gas transmission, $5.7 million for propane distribution and wholesale marketing,
$178,000 for advanced information services and $1.0 million for other
operations. The natural gas distribution and transmission expenditures are
for
expansion and improvement of facilities. The propane expenditures are to
support
customer growth and for the replacement of equipment. The advanced information
services expenditures are for computer hardware, software and related equipment.
The other operations category includes general plant, computer software and
hardware. Financing for the 2006 capital expenditure program is expected
to be
provided from short-term borrowing, cash provided by operating activities
and
other sources to be determined from a shelf registration of the Company’s equity
and debt securities. The capital expenditure program is subject to continuous
review and modification. Actual capital requirements may vary from the above
estimates due to a number of factors, including acquisition opportunities,
changing economic conditions, customer growth in existing areas, regulation,
new
growth opportunities and availability of capital.
Chesapeake
has budgeted to incur approximately $300,000 in 2006 and $25,000 in 2007
for
environmental-related expenditures. Additional expenditures may be required
in
future years. Management does not expect financing of future
environmental-related expenditures to have a material adverse effect on the
financial position or capital resources of the Company.
Capital
Structure
As
of
September 30, 2006, common equity represented 60.9 percent of total
capitalization, compared to 56.8 percent in 2005. 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 43.9 percent
and 51.2 percent at September 30, 2006 and September 30, 2005, respectively.
The
decrease in the capitalization percent is from the increase of $40.7 million
in
net short-term borrowing in 2006. Chesapeake remains committed to maintaining
a
sound capital structure and strong credit ratings to provide the financial
flexibility needed to access the capital markets when required. This commitment,
along with adequate and timely rate relief for the Company’s regulated
operations, is intended to ensure that Chesapeake will be able to attract
capital from outside sources at a reasonable cost. The Company believes that
the
achievement of these objectives will provide benefits to customers and
creditors, as well as to the Company’s investors.
Cash
Flows from Operating Activities
The
primary drivers for the Company’s operating cash flows are cash payments
received from gas customers, offset by payments made by the Company for gas
costs, operation and maintenance expenses, taxes and interest
costs.
Net
cash
provided by operating activities totaled $18.97 million and $18.95 million
for
the nine months ended September 30, 2006 and 2005, respectively. Certain
material changes in working capital are listed below for the first nine months
of 2006:
· |
Accounts
receivable and accrued revenue decreased $17.3 million, which generated
an
increase in cash. The
decrease in accounts receivable was primarily as a result of the
seasonality of the Company’s business as it collects balances outstanding
at December 31, 2005 and it experiences the warmer summer
months.
|
· |
Accounts
payable and other accrued liabilities decreased $19.9 million, which
resulted in a decrease in cash.
The decreases in accounts payable and accrued liabilities primarily
resulted from the lower cost of natural gas and propane in first
nine
months of 2006 compared to December 2005. In addition, the payment
of
invoices for capital expenditures in the first nine months of 2006
and
those outstanding at December 31, 2005 contributed to the
decrease.
|
· |
Income
taxes receivable decreased $3.1 million, which resulted in an increase
of
cash. This decrease in the receivable was the result of the Company
being
in a refund status of $2.7 million at December 31, 2005 and applying
the
refunds to the current year’s tax
liability.
|
Certain
material changes in working capital are listed below for the first nine months
of 2005:
· |
Accounts
receivable and accrued revenue decreased $4.8 million due to the
seasonality of the Company’s business as it collects balances outstanding
at December 31, 2004.
|
· |
Propane
inventory, storage gas and other inventory increased $5.4 million
resulting in a reduction in cash. The increase in the inventory levels
is
attributed to the higher cost of natural gas and propane resulting
from
the hurricanes that hit the Gulf of Mexico.
|
· |
Accounts
payable and other accrued liabilities increased $3.0 million.
The increase in accounts payable and accrued liabilities primarily
resulted from an increase of propane payables outstanding by the
Company’s
wholesale propane and marketing operation at the end of September
compared
to December 31, 2004.
|
Cash
Flows Used in Investing Activities
Net
cash
flows used in investing activities totaled $28.3 million and $19.7 million
during the nine months ended September 30, 2006 and 2005, respectively. Cash
utilized for capital expenditures was $28.2 million and $19.9 million for
the
first nine months of 2006 and 2005, respectively. Additions to property,
plant
and equipment in the first nine months of 2006 and 2005 were primarily for
natural gas transmission, natural gas distribution and propane distribution.
In
both periods in 2006 and 2005, the natural gas distribution expenditures
were
used primarily to fund expansion and facilities improvements. In both periods,
the natural gas transmission capital expenditures related primarily to expanding
the Company’s transmission system. Additionally, net cash of $10,000 was paid in
the first nine months ended September 2006 and net cash of $206,000 was received
during the first nine months ended September 30, 2005 for recovery of
environmental costs through rates charged to customers.
Cash
Flows from Financing Activities
Cash
flows generated from financing activities totaled $9.2 million for the nine
months ended September 30, 2006 and cash flows used in the nine months ended
September 30, 2005 totaled $225,000. During the first nine months of 2006,
the
Company:
· |
borrowed
$14.8 million under its short-term line of credit
agreements;
|
· |
paid
common stock dividends totaling $4.5
million;
|
· |
reduced
its outstanding long-term notes payable balance by $1.9 million;
and
|
· |
paid
cash of $435,000 in lieu of issuing shares of the Company’s common stock
for the 30,000 stock warrants outstanding at December 31, 2005. The
stock
warrants were exercised in the third quarter of
2006.
|
During
the first nine months of 2005, the Company borrowed $4.8 million under its
short-term line of credit agreements. Additionally, the Company paid common
stock dividends totaling $4.3 million and reduced its outstanding long-term
notes payable balance by $1.8 million.
Shelf
Registration
On
July
5, 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. Under
this
registration statement, Chesapeake may sell common stock and/or debt securities
in one or more separate offerings with the size, price and terms to be
determined at the time of sale. The
net
proceeds from the sale of common stock and/or debt securities will be added
to
the Company’s general corporate funds and may be used for general corporate
purposes including, but not limited to, financing of capital expenditures,
repayment of short-term debt, funding share repurchases, financing acquisitions,
investing in subsidiaries and general working capital purposes.
Off-Balance
Sheet Arrangements
As
noted
in the Company’s 2005 Annual Report on Form 10-K, the Company has issued
corporate guarantees to certain vendors of its propane wholesale marketing
subsidiary, its Delmarva propane distribution subsidiary, and its natural
gas
marketing subsidiary in Florida. These corporate guarantees provide for the
payment of propane and natural gas purchases in the event of the subsidiaries’
default. The liabilities for these purchases are recorded in the Consolidated
Financial Statements in this Quarterly Report on Form 10-Q. The aggregate
amount
guaranteed at September 30, 2006, totaled $18.9 million, with the guarantees
expiring on various dates in 2006 and 2007.
In
addition to the corporate guarantees, the Company has issued a letter of
credit
to its primary insurance company for $775,000, which expires on May 31, 2007.
The letter of credit is provided as security for claim amounts to satisfy
the
deductibles on the Company’s policies. The current letter of credit was renewed
during the second quarter of 2006 when the insurance policies were renewed.
Contractual
Obligations
There
have been no material changes in the contractual obligations presented in
the
Company’s 2005 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 September 30, 2006:
|
|
Payments
Due by Period
|
Purchase
Obligations
|
|
Less
than 1 year
|
|
1
- 3 years
|
|
3
- 5 years
|
|
More
than 5 years
|
|
Total
|
|
Commodities
(1)
|
|
$
|
24,174,050
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
$
|
24,174,050
|
|
Propane
(2)
|
|
|
25,151,543
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
25,151,543
|
|
Total
Purchase Obligations
|
|
$
|
49,325,593
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
$
|
49,325,593
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
In
addition to the obligations noted above, the natural gas distribution
and
propane distribution operations have agreements with commodity
suppliers
that have provisions that allow 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 $27.8 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 to the Condensed Consolidated Financial Statements
in
this Quarterly Report on Form 10-Q, Chesapeake has incurred costs relating
to
the completed or ongoing environmental remediation at three former gas
manufacturing plant sites. In addition, Chesapeake is currently participating
in
discussions regarding the possible responsibilities of the Company for
remediation of a fourth former gas manufacturing 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
Regulatory
Matters
The
Company’s natural gas distribution operations are subject to regulation by the
Delaware, Maryland and Florida Public Service Commissions. Eastern Shore
Natural
Gas Company (“Eastern Shore”), the Company’s natural gas transmission operation,
is subject to regulation by the FERC.
Eastern
Shore.
During
October 2002, Eastern Shore filed for recovery of gas supply realignment
costs,
which totaled $196,000 (including interest), associated with the implementation
of FERC Order No. 636. At that time, the FERC deferred review of the filing
pending settlement of a related matter concerning another transmission company.
Chesapeake understands that the other matter has now been resolved. Eastern
Shore updated its gas supply realignment filing and entered into pre-filing
discussions with customers potentially impacted by the filing before re-filing
its application with the FERC. Discussions with customers were completed
during
the first quarter of 2006. Eastern Shore resubmitted its filing to the FERC
on
June 22, 2006, requesting authorization to recover a total of $222,848
(including interest) of gas supply realignment costs.
On
December 9, 2005, Eastern Shore filed revised tariff sheets to replace its
existing fixed price penalties with penalties that are the higher of a fixed
price or a multiple of a daily index price. The revised penalties are applicable
to customers who violate Operational Flow Orders and customers who take
unauthorized overrun quantities that could threaten the operational integrity
of
the pipeline, or to Eastern Shore’s ability to render reliable service. By
letter order dated January 6, 2006, the FERC accepted Eastern Shore’s proposed
changes, effective December 21, 2005.
On
January 20, 2006, Eastern Shore filed an application for a Certificate of
Public
Convenience and Necessity for its 2006-2008 system expansion project with
the
FERC. The proposed expansion application requests authority to construct
and
operate approximately 55 miles of new pipeline facilities and two new metering
and regulating station facilities to provide an additional 47,350 dekatherms
per
day (“dt/d”) of firm transportation service in accordance with the phased-in
customer requests of 26,200 dt/d in 2006, 10,300 dt/d in 2007, and 10,850
dt/d
in 2008, at a total estimated cost of approximately $33.6 million. The following
table provides a breakdown for the additional amounts of firm capacity per
day,
the estimated capital investment required, and the estimated annual gross
margin
contribution for the new services that will become effective November
1st
for each
of the respective years of the project:
|
Year
|
|
2006
|
2007
|
2008
|
Additional
firm capacity per day
|
26,200
|
10,300
|
10,850
|
Capital
investment
|
$17
million
|
$8
million
|
$8
million
|
Annualized
Gross Margin contribution
|
$3,670,256
|
$1,484,146
|
$1,594,785
|
A
Scoping
Meeting was held on March 29, 2006 at which the public and all other interested
stakeholders were invited to attend to review the project. No opposition
to the
project was received. On June 13, 2006, the FERC issued an Order Issuing
Certificate to Eastern Shore authorizing it to construct and operate the
2006-2008 system expansion project. Eastern Shore has commenced construction
of
certain Phase I facilities. Phase II and Phase III facilities are expected
to be
constructed in 2007 and 2008, respectively.
On
May
31, 2006, Eastern Shore entered into Precedent Agreements with Chesapeake,
through its Delaware and Maryland Divisions, and Delmarva Power & Light
Company (“Delmarva”) to provide additional firm transportation services upon
completion of its latest proposed pipeline project (the “Proposed
Project”).
Eastern
Shore has proposed to develop, construct and operate new pipeline facilities
that would transport natural gas from Calvert County, Maryland, through
Dorchester and Caroline Counties, Maryland, to points on the Delmarva Peninsula
where such facilities would interconnect with its existing facilities in
Sussex
County, Delaware. The total cost of the Proposed Project is estimated at
$93
million, depending upon the final size and route of the pipeline, as well
as
construction materials and labor costs.
Chesapeake
and Delmarva are currently parties to existing firm natural gas transportation
service agreements with Eastern Shore and each desires firm transportation
services under the Proposed Project. Pursuant to these agreements (“Precedent
Agreements”), the parties have agreed to proceed with the required initiatives
to obtain the governmental and regulatory authorizations that are necessary
for
Eastern Shore to provide, and for Chesapeake and Delmarva to utilize, such
firm
transportation services under the Proposed Project.
During
the negotiations of the Precedent Agreements, Eastern Shore and each of the
customers entered into Letter Agreements, which provide that, in the event
that
the Proposed Project is not certified and placed in service, the customers
will
pay their proportionate share of certain pre-certification costs by means
of a
negotiated surcharge of up to $2 million, over a period of no less than 20
years.
In
connection with the Proposed Project, on June 27, 2006, Eastern Shore submitted
a petition to the FERC for approval of an uncontested Settlement Agreement,
to
implement the rate-related Settlement Agreement to address the development
costs
of the Proposed Project. The filed Settlement Agreement was entered into
by
Eastern Shore and its firm customers. The Settlement Agreement provides Eastern
Shore and all customers utilizing Eastern Shore’s system with benefits,
including but not limited to the following: (1) advancement of a necessary
infrastructure project to meet the growing demand for natural gas on the
Delmarva Peninsula; (2) sharing of project development costs by the
participating customers in the project; and (3) no development cost risk
for
non-participating customers. On August 1, 2006, the FERC granted approval
of the
uncontested Settlement Agreement. On September 6, 2006, Eastern Shore submitted
to FERC proposed revised tariff sheets to implement the provisions of the
above-referenced Settlement Agreement. By Letter Order dated October 6, 2006,
the FERC accepted the tariff sheets effective September 7, 2006.
On
September 19, 2006, Eastern Shore submitted its Annual Charge Adjustment
(“ACA”)
compliance filing to reflect the most current ACA surcharge rate as established
by the FERC. The revised ACA surcharge, proposed to be effective October
1,
2006, is currently pending before the FERC.
Delaware.
On
October 3, 2005, the Delaware division filed its annual Gas Sales Service
Rates
(“GSR”) application that was effective for service rendered on and after
November 1, 2005 with the Delaware Public Service Commission (“Delaware PSC”).
On February 23, 2006, the Delaware division filed a supplemental GSR application
with the Delaware PSC that was consolidated with the previously filed
application. In its supplemental application, the Delaware division proposed
reduced GSR charges to be effective March 15, 2006. On September 19, 2006,
the
Delaware PSC granted final approval of both GSR applications.
On
September 1, 2006, the Delaware division filed its annual GSR application
to be
effective for service rendered on and after November 1, 2006 with the Delaware
PSC. On October 3, 2006, the Delaware PSC approved the GSR charges, subject
to
full evidentiary hearings and a final decision. The Delaware division expects
a
final decision during the first half of 2007.
On
November 1, 2005, 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, 2005. The Delaware PSC granted approval
of the
ER rate at its regularly scheduled meeting on November 8, 2005, subject to
full
evidentiary hearings and a final decision. An evidentiary hearing was held
on
April 5, 2006, which was uncontested. The Delaware PSC granted final approval
of
the ER rate at its regularly scheduled meeting on May 9, 2006.
On
September 2, 2005, the Delaware division filed an application with the Delaware
PSC requesting approval of an alternative rate design and rate structure
in
order to provide natural gas service to prospective customers in eastern
Sussex
County. While Chesapeake does provide natural gas service to residents and
businesses in portions of Sussex County, under the Company’s current tariff and
traditional ratemaking processes, natural gas has not been extended to the
State
of Delaware’s recently targeted growth areas in eastern Sussex County. In April
2002, Governor Ruth Ann Minner established the Delaware Energy Task Force
(“Task
Force”), whose mission was to address the State of Delaware’s long-term and
short-term energy challenges. In September 2003, the Task Force issued its
final
report to the Governor that included a strategy related to enhancing the
availability of natural gas within the State by evaluating possible incentives
for expanding residential and commercial natural gas service. Chesapeake
believes its current proposal to implement a rate design that will enable
the
Company to provide natural gas as a viable energy choice to a broad number
of
prospective customers within eastern Sussex County is consistent with the
Task
Force recommendation. While the Company cannot predict the outcome of its
application at this time, the Company anticipates a final decision from the
Delaware PSC regarding its application in late 2006 or the first half of
2007.
Maryland.
On May
1, 2006, the Maryland division filed a base rate application with the Maryland
Public Service Commission (“Maryland PSC”) requesting an overall increase in
base rates of approximately $1,137,000 annually, based on a proposed overall
rate of return of 9.7 percent and a return on equity of 11.5 percent. On
September 26, 2006, the Maryland PSC approved a base rate increase of
approximately $780,000 annually, based on an overall rate of return of 9.03
percent and a return on equity of 10.75 percent. This increase would result
in
an average increase in revenues of approximately 4.5 percent for the Maryland
division’s firm residential, commercial and industrial customers. The PSC also
approved the Company’s proposal to implement a revenue normalization mechanism
for its residential heating and smaller commercial heating customers, reducing
the Company’s risk due to weather and usage changes.
On
December 14, 2006, the Maryland PSC will be holding an evidentiary hearing
to
determine the reasonableness of the Maryland division’s four quarterly gas cost
recovery filings during the twelve months ended September 30, 2006. While
the
Company cannot predict the outcome of this proceeding at this time, the Company
anticipates a final decision from the Maryland PSC during the first quarter
of
2007.
Florida.
On March
22, 2006, the Florida division filed a petition with the Florida Public Service
Commission (“Florida PSC”) seeking approval of special contracts to provide
Delivery Point Operator (“DPO”) services. Under the proposed contracts, the DPO
services would be provided to an affiliate company, Peninsula Energy Services
Company, Inc. The Florida PSC approved the petition on July 7, 2006, ordering
that the special contracts be effective June 20, 2006.
On
May
16, 2005, the Florida division filed a request with the Florida PSC for approval
of a Special Contract with the Department of Management Services, an agency
of
the State of Florida, for service to the Washington Correction Institution
(“WCI”). The Florida PSC approved the Company’s request on July 19, 2005, and
service to the existing WCI facility began in February 2006. WCI is located
in
Washington County in the Florida panhandle and is the thirteenth county served
by the Company’s Florida division.
On
September 2, 2005, the Florida division filed a petition for a Declaratory
Statement with the Florida PSC for a determination that Peninsula Pipeline
Company, Inc. (“PPC”), a wholly owned subsidiary of the Company, qualifies as a
natural gas transmission company under the Natural Gas Transmission Pipeline
Intrastate Regulatory Act. The Florida PSC approved this Petition at its
December 20, 2005 agenda conference, and a final order was issued on January
9,
2006. The determination that PPC qualifies as a natural gas transmission
company
provides opportunities for investment by PPC to deliver natural gas transmission
service to industrial customers in Florida by an intra-state
pipeline.
On
September 15, 2006, the Florida division filed a petition for approval of
its
Energy Conservation Cost Recovery Factors for the year 2007 with the Florida
PSC. When approved, the new factors will go into effect on January 1,
2007.
Competition
The
Company’s natural gas operations compete with other forms of energy including
electricity, oil and propane. The principal competitive factors are price
and,
to a lesser extent, accessibility. The Company’s natural gas distribution
operations have several large-volume industrial customers that have the capacity
to use fuel oil as an alternative to natural gas. When oil prices decline,
these
interruptible customers convert to oil to satisfy their fuel requirements.
Lower
levels in interruptible sales occur when oil prices are lower relative to
the
price of natural gas. Oil prices, as well as the prices of electricity and
other
fuels are subject to fluctuation for a variety of reasons; therefore, future
competitive conditions are not predictable. To address this uncertainty,
the
Company uses flexible pricing arrangements on both the supply and sales sides
of
its business to maximize sales volumes. As a result of the transmission
business’ conversion to open access, this business has shifted from providing
competitive sales service to providing transportation and contract storage
services.
The
Company’s natural gas distribution operations located in Delaware, Maryland and
Florida offer transportation services to certain industrial customers. The
Florida operation extended transportation service to commercial customers
in
2001 and to residential customers in 2002. With transportation service available
on the Company’s distribution systems, the Company is competing with third-party
suppliers to sell gas to certain customers. As it relates to transportation
services, the Company’s competitors include interstate transmission companies
that are in close proximity to the Company’s pipeline. 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
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 operates a natural
gas marketing operation in Florida to compete for customers eligible for
transportation services.
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 primarily with electricity
and heating oil as energy sources. Since natural gas has historically been
less
expensive than propane, propane is generally not distributed in geographic
areas
serviced by natural gas pipeline or distribution systems.
The
propane wholesale marketing operation competes against various marketers,
many
of which have significantly greater resources and are able to obtain price
or
volumetric advantages.
The
advanced information services business faces significant competition from
a
number of larger competitors having substantially greater resources available
to
them than does the Company. In addition, changes in the advanced information
services business are occurring rapidly, which could adversely impact the
markets for the products and services offered by these businesses. This segment
competes on the basis of technological expertise, reputation and
price.
Recent
Pronouncements
In
December 2004, the FASB released a revision (“Share-Based Payment”) to SFAS No.
123, “Accounting for Stock-Based Compensation,” referred to as SFAS No. 123R.
SFAS 123R establishes financial accounting and reporting standards for
stock-based employee compensation plans. Those plans include all arrangements
by
which employees receive shares of stock or other equity instruments of the
employer or the employer incurs liabilities to employees in amounts based
on the
price of the employer’s stock. Examples are stock purchase plans, stock options,
restricted stock and stock appreciation rights. The impact of the Company’s
adoption of this pronouncement is disclosed in Note 9 to the financial
statements entitled “Share Based Compensation.”
In
July
2006, the FASB issued FASB Interpretation 48, “Accounting for Income Tax
Uncertainties,” (“FIN 48”). FIN 48 defines the threshold for recognizing the
benefits of tax return positions in the financial statements as
“more-likely-than-not” to be sustained by the taxing authority. The recently
issued literature also provides guidance on the derecognition, measurement
and
classification of income tax uncertainties, along with any related interest
and
penalties. FIN 48 also includes guidance concerning accounting for income
tax
uncertainties in interim periods and increases the level of disclosures
associated with any recorded income tax uncertainties. FIN 48 is effective
for
fiscal years beginning after December 15, 2006. The differences between the
amounts recognized in the statements of financial position prior to the adoption
of FIN 48 and the amounts reported after adoption will be accounted for as
a
cumulative-effect adjustment recorded in retained earnings. The Company is
continuing to evaluate the impact of this new standard, if any, on the Company’s
financial statements.
In
September 2006, the FASB issued Statement No. 157, “Fair Value Measurements
”
(“SFAS
No. 157”), which clarifies that the term fair value is intended to mean a
market-based measure, not an entity-specific measure and gives the highest
priority to quoted prices in active markets in determining fair value. SFAS
No.
157 requires disclosures about (1) the extent to which companies measure
assets
and liabilities at fair value, (2) the methods and assumptions used to measure
fair value, and (3) the effect of fair value measures on earnings. SFAS No.
157
is effective for fiscal years beginning after November 15, 2007. The
Company is continuing to evaluate the impact of this new standard, if any,
on
the Company’s financial statements.
In
September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined
Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements
No. 87, 88, 106 and 132(R).” This statement would require a company to (a)
recognize in its statement of financial position an asset for a plan’s
overfunded status or a liability for a plan’s underfunded status, (b) measure a
plan’s assets and its obligations that determine its funded status as of the end
of the employer’s fiscal year, and (c) recognize changes in the funded status of
a defined postretirement plan in the year in which the changes occur and
to
report the changes as adjustments to comprehensive income. The requirement
to
recognize the funded status of a benefit plan and the disclosure requirements
are effective as of the end of the fiscal year ending after December 15,
2006.
The requirement to measure the plan assets and benefit obligations as of
the
date of the employer’s fiscal year-end statement of financial position is
effective for fiscal years ending after December 15, 2006. The
Company does not anticipate that the adoption of SFAS No. 158 will have a
material impact on the Company’s financial position, and expects no impact to
the statements of income or cash flows.
In
September 2006, the Securities and Exchange Commission issued Staff Accounting
Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when
Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”),
which provides interpretive guidance on the consideration of the effects
of
prior year misstatements in quantifying current year misstatements for the
purpose of a materiality assessment. SAB 108 is effective as of the end of
our
2006 fiscal year, allowing a one-time transitional cumulative effect adjustment
to beginning retained earnings as of January 1, 2006, for errors that were
not previously deemed material, but are material under the guidance in SAB
108.
We do not anticipate that the adoption of SAB 108 will have a material impact
on
the Company’s Consolidated Financial Statements.
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. Fluctuations in natural gas prices are passed on to
customers through the gas cost recovery mechanism in the Company’s tariffs. To
help cope with the effects of inflation on its capital investments and returns,
the Company seeks rate relief from regulatory commissions for regulated
operations while monitoring the returns of its unregulated business operations.
To compensate for fluctuations in propane gas prices, the Company adjusts
its
propane selling prices to the extent allowed by the market.
Cautionary
Statement
Chesapeake
has made statements in this report that are considered to be forward-looking
statements. These statements are not matters of historical fact. Sometimes
they
contain words such as “believes,” “expects,” “intends,” “plans,” “will,” or
“may,” and other similar words of a predictive nature. These statements relate
to matters such as customer growth, changes in revenues or gross margins,
capital expenditures, environmental remediation costs, regulatory approvals,
market risks associated with the Company’s propane wholesale marketing
operation, competition, inflation and other matters. It is important to
understand that these forward-looking statements are not guarantees, but
are
subject to certain risks and uncertainties and other important factors that
could cause actual results to differ materially from those in the
forward-looking statements. These factors include, among other
things:
o |
the
temperature sensitivity of the natural gas and propane
businesses;
|
o |
the
effect of spot, forward and futures market prices on the Company’s
distribution, wholesale marketing and energy trading
businesses;
|
o |
the
effects of competition on the Company’s unregulated and regulated
businesses;
|
o |
the
effect of changes in federal, state or local regulatory and tax
requirements, including deregulation;
|
o |
the
effect of accounting changes;
|
o |
the
effect of compliance with environmental regulations or the remediation
of
environmental damage;
|
o |
the
effects of general economic conditions on the Company and its
customers;
|
o |
the
ability of the Company’s new and planned facilities and acquisitions to
generate expected revenues; and
|
o |
the
Company’s ability to obtain the rate relief and cost recovery requested
from utility regulators and the timing of the requested regulatory
actions.
|
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 the change
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 $61.7
million at September 30, 2006, as compared to a fair value of $65.0 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 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 entering 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. As of September 30, 2006 management reviewed
the Company’s storage position and several hedging strategies and elected not to
hedge any of its inventories.
The
Company’s propane wholesale marketing operation is a party to natural gas
liquids (“NGL”) forward contracts, primarily propane contracts, with various
third parties. These contracts require that the propane wholesale marketing
operation purchase or sell NGL at a fixed price at fixed future dates. At
expiration, the contracts are settled by the delivery of NGL to the Company
or
the 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
NGL 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 oversight officials
on a
daily basis. Additionally, 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 September 30, 2006 is presented
in the following table.
At
September 30, 2006
|
|
Quantity
in gallons
|
|
Estimated
Market Prices
|
|
Weighted
Average Contract Prices
|
|
Forward
Contracts
|
|
|
|
|
|
|
|
Sale
|
|
25,337,550
|
|
$0.93750
— $1.22375
|
|
$1.09770
|
|
Purchase
|
|
23,541,000
|
|
$0.93750
— $1.22000
|
|
$1.06840
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
market prices and weighted average contract prices are in dollars
per
gallon.
|
|
All
contracts expire in 2006 or the first quarter of 2007.
|
|
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 September 30, 2006. Based upon their evaluation, the Chief
Executive Officer and Chief Financial Officer concluded that the Company’s
disclosure controls and procedures are effective.
Changes
in Internal Control
Over Financial Reporting
During
the quarter ended September 30, 2006, there was no change in the Company’s
internal control over financial reporting that has materially affected, or
is
reasonably likely to materially affect, the Company’s internal control over
financial reporting.
PART
II — OTHER INFORMATION
Item
1. Legal
Proceedings
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
The
following is a discussion of the primary factors that may affect the operations
and/or financial performance of the regulated and/or unregulated businesses
of
Chesapeake. These risk factors include:
Fluctuations
in weather have the potential to adversely affect our results of operations,
cash flows, and financial condition.
Our
utility and propane distribution operations are sensitive to fluctuations
in
weather, and weather conditions directly influence the volume of natural
gas and
propane delivered by our utility and propane distribution operations to
customers. A significant portion of our utility and propane distribution
operations’ revenues are derived from the delivery of natural gas and propane to
residential and commercial heating customers during the five-month peak heating
season of November through March. If the weather is warmer than normal, we
deliver less natural gas and propane to customers, and earn less revenue.
In
addition, hurricanes or other extreme weather conditions could damage production
or transportation facilities, which could result in decreased supplies of
natural gas and propane, increased supply costs and higher prices for customers.
Regulation
of the Company, including changes in the regulatory environment in general,
may
adversely affect our results of operations, cash flows and financial condition.
The
state
Public Service Commissions of Delaware, Maryland and Florida regulate our
natural gas distribution operations. ESNG, our natural gas transmission
subsidiary, is regulated by the FERC. These regulatory commissions set the
rates
in their respective jurisdictions that we can charge customers for our
rate-regulated services. Changes in these rates, as ordered by regulatory
commissions, affect our
financial performance. Our ability to obtain timely future rate increases
and
rate supplements to maintain current rates of return depends on regulatory
discretion, and there can be no assurance that our divisions and ESNG will
be
able to obtain rate increases or supplements or continue receiving currently
authorized rates of return.
The
amount and availability of natural gas and propane supplies are difficult
to
predict, which may reduce our earnings.
Natural
gas and propane production can be impacted by factors outside of our control,
such as weather and refinery closings. If we are unable to obtain sufficient
natural gas and propane supplies to meet demand, our results of operation
may be
negatively impacted.
We
rely on having access to interstate pipelines’ transportation and storage
capacity. If these pipelines or storage facilities were not available, it
may
impair our ability to meet our customers’ full requirements.
We
must
acquire both sufficient natural gas supplies and interstate pipeline and
storage
capacity to meet customer requirements. We must contract for reliable and
adequate delivery capacity for our distribution system, while considering
the
dynamics of the interstate pipeline and storage capacity market, our own
on-system resources, as well as the characteristics of our customer base.
Local
natural gas distribution companies, including us, and other participants
in the
energy industry, have raised concerns regarding the future availability of
additional upstream interstate pipeline and storage capacity. Additional
available pipeline and storage capacity is a business issue that must be
managed
by us, as our customer base grows.
Natural
gas and propane commodity price changes may affect the operating costs and
competitive positions of our natural gas and propane distribution operations,
which may adversely affect our results of operations, cash flows and financial
condition.
Natural
Gas. Over
the
last four years, natural gas costs have increased significantly and become
more
volatile. In addition, the hurricane activity in 2005 reduced the natural
gas
available from the Gulf Coast region, further contributing to the volatility
of
natural gas prices. Higher natural gas prices can result in significant
increases in the cost of gas billed to customers during the winter heating
season. Under our regulated gas cost recovery mechanisms, we record cost
of gas
expense equal to the cost of gas recovered in revenues from customers.
Therefore, an increase in the cost of gas due to an increase in the price
of the
natural gas commodity generally has no direct effect on our revenues and
net
income. However, our net income may be reduced due to higher expenses that
may
be incurred for uncollectible customer accounts, as well as lower volumes
of
natural gas deliveries to customers due to lower natural gas consumption
caused
by customer conservation. Increases in the price of natural gas also can
affect
our operating cash flows, as well as the competitiveness of natural gas as
an
energy source.
Propane.
The
level of profitability in the retail propane business is largely dependent
on
the difference between the cost of propane and the revenues derived from
our
sale of propane to our customers. Propane costs are subject to volatile changes
as a result of product supply or other market conditions, including, economic
and political factors impacting crude oil and natural gas supply or pricing.
Propane cost changes can occur rapidly over a short period of time and can
impact profitability. There is no assurance that we will be able to pass
on
propane cost increases fully or immediately, particularly when propane costs
increase or decrease rapidly. Therefore, average retail sales prices can
vary
significantly from year to year as product costs fluctuate with propane,
fuel
oil, crude oil and natural gas commodity market conditions. In addition,
in
periods of sustained higher commodity prices, retail sales volumes may be
negatively impacted by customer conservation efforts and increased amounts
of
uncollectible accounts.
We
compete in a competitive environment and may be faced with losing customers
to a
competitor.
We
compete with third-party suppliers to sell gas to industrial customers. As
it
relates to transportation services, our competitors include the interstate
transmission company if the distribution customer is located close enough
to the
transmission company’s pipeline to make a connection economically feasible.
Our
propane distribution operations compete with several other propane distributors
in their service territories, primarily on the basis of service and price,
emphasizing reliability of service and responsiveness. Some of our competitors
have significantly greater resources. The retail propane industry is mature,
and
we foresee only modest growth in total demand. Given this limited growth,
we
expect that year-to-year industry volumes will be principally affected by
weather patterns. Therefore, our ability to grow the propane distribution
business is contingent upon execution of our community gas systems strategy
to
capture market share and to employ pricing programs that retain and grow
our
customer base. Any failure to retain and grow our customer base would have
an
adverse effect on our results.
The
propane wholesale marketing operation competes against various marketers,
many
of which have significantly greater resources and are able to obtain price
or
volumetric advantages.
The
advanced information services business faces significant competition from
a
number of larger competitors having substantially greater resources available
to
them to compete on the basis of technological expertise, reputation and price.
Costs
of compliance with environmental laws may be
significant.
We
are
subject to federal, state and local laws and regulations governing environmental
quality and pollution control. These evolving laws and regulations may require
expenditures over a long timeframe to control environmental effects at current
and former operating sites, including former gas manufactured sites that
we have
acquired from third parties. Compliance with these legal requirements requires
us to commit capital toward environmental compliance. If we fail to comply
with
environmental laws and regulations, even if such failure is caused by factors
beyond our control, we may be assessed civil or criminal penalties and fines.
To
date,
we have been able to recover through approved rate mechanisms the costs of
recovery associated with the remediation of former gas manufactured sites.
However, there is no guarantee that we will be able to recover future
remediation costs in the same manner or at all. A change in our approved
rate
mechanisms for recovery of environmental remediation costs at former
manufacturer gas sites could adversely affect our results of operations,
cash
flows and financial condition.
Further,
existing environmental laws and regulations may be revised or new laws and
regulations seeking to protect the environment may be adopted or become
applicable to us. Revised or additional laws and regulations could result
in
additional operating restrictions on our facilities or increased compliance
costs which may not be fully recoverable by us.
A
change in the economic conditions and interest rates may adversely affect
our
results of operations and cash flows.
A
downturn in the economies of the regions in which we operate, which we cannot
accurately predict, might adversely affect our ability to grow our customer
base
and other businesses at the same rate they have grown in the recent past.
Further, an increase in interest rates without the recovery of the higher
cost
of debt in the sales and/or transportation rates we charge our utility
customers, could adversely affect future earnings. An increase in short-term
interest rates would negatively affect our results of operations, which depend
on short-term debt to finance accounts receivable, storage gas inventories,
and
to temporarily finance capital expenditures.
Inflation
may impact our results of operations, cash flows and financial position.
Inflation
affects the cost of supply, labor, products and services required for
operations, maintenance and capital improvements. While the impact of inflation
has remained low in recent years, natural gas and propane prices are subject
to
rapid fluctuations. To help cope with the effects of inflation on our capital
investments and returns, we seek rate relief from regulatory commissions
for
regulated operations while monitoring the returns of our unregulated business
operations. There can be no assurance that we will be able to obtain adequate
and timely rate relief to offset the effects of inflation. To compensate
for
fluctuations in propane gas prices, we adjust our propane selling prices
to the
extent allowed by the market. However, there can be no assurance that we
will be
able to increase propane sales prices sufficiently to fully compensate for
such
fluctuations in the cost of propane gas to us.
Changes
in technology may adversely affect our advanced information services segment’s
results of operations, cash flows and financial
condition.
Our
advanced information services segment participates in a market that is
characterized by rapidly changing technology and accelerating product
introduction cycles. The success of our advanced information services segment
depends upon our ability to address the rapidly changing needs of our customers
by developing and supplying high-quality, cost-effective products, product
enhancements and services on a timely basis, and by keeping pace with
technological developments and emerging industry standards. There can be
no
assurance that we will be able to keep up with technological advancements
necessary to make our products competitive.
Our
energy marketing subsidiaries have credit risk and credit requirements that
may
adversely affect our results of operations, cash flows and financial
condition.
Xeron,
our propane wholesale and marketing subsidiary, and PESCO, our natural gas
marketing subsidiary in Florida, extend credit to counter-parties. While
we
believe Xeron and PESCO utilize prudent credit policies, each of these
subsidiaries is exposed to the risk that it may not be able to collect amounts
owed to it. If the counter-party to such a transaction fails to perform and
any
underlying collateral is inadequate, we could experience financial losses.
Our
subsidiaries Xeron and PESCO are dependent upon the availability of credit
to
buy propane and natural gas for resale or to trade. If the financial condition
of these subsidiaries declines, or if our financial condition declines, then
the
cost of credit available to these subsidiaries could increase. If credit
is not
available, or if credit is more costly, our results of operations, cash flows
and financial condition may be adversely affected.
Our
use of derivative instruments may adversely affect our results of
operations.
Fluctuating
commodity prices cause our earnings and financing costs to be impacted. Our
propane distribution and wholesale marketing segment uses derivative
instruments, including forwards, swaps and puts, to hedge price risk. In
addition, we may decide, after further evaluation, to utilize derivative
instruments to hedge price risk for our Delaware and Maryland divisions,
as well
as PESCO. While we have a risk policy and operating procedures in place to
control our exposure to risk, if we purchase derivative instruments that
are not
properly matched to our exposure, our results of operations, cash flows,
and
financial conditions may be adversely impacted.
Inability
to access the capital markets may impair our future growth.
We
rely
on access to both short-term and longer-term capital markets as a significant
source of liquidity for capital requirements not satisfied by the cash flow
from
our operations. Currently, $65 million of the total $80 million of short-term
lines of credit utilized to satisfy our short-term financing requirements
are
discretionary, uncommitted lines of credit. We utilize discretionary lines
of
credit to reduce the cost associated with these short-term financing
requirements. We are committed to maintaining a sound capital structure and
strong credit ratings to provide the financial flexibility needed to access
the
capital markets when required. However, if we are not able to access capital
at
competitive rates, our ability to implement our strategic plan, undertake
improvements and make other investments required for our future growth may
be
limited.
We
are subject to operating and litigation risks that may not be covered by
insurance.
Our
operations are subject to the operating hazards and risks normally incidental
to
handling, storing, transporting and otherwise providing natural gas and propane
to end users. As a result, we are sometimes a defendant in legal proceedings
and
litigation arising in the ordinary course of business. We maintain insurance
policies with insurers in such amounts and with such coverages and deductibles
as we believe are reasonable and prudent. There can be no assurance, however,
that such insurance will be adequate to protect us from all material expenses
related to potential future claims for personal injury and property damage
or
that such levels of insurance will be available in the future at economical
prices.
Item
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
(2)
|
|
Maximum
Number of Shares That May Yet Be Purchased Under the Plans
or Programs
(2)
|
|
July
1, 2006 through July 31, 2006 (1)
|
|
|
446
|
|
$
|
30.72
|
|
|
0
|
|
|
0
|
|
August
1, 2006 through August 31, 2006
|
|
|
0
|
|
$
|
0.00
|
|
|
0
|
|
|
0
|
|
September
1, 2006 through September 30, 2006
|
|
|
0
|
|
$
|
0.00
|
|
|
0
|
|
|
0
|
|
Total
|
|
|
446
|
|
$
|
30.72
|
|
|
0
|
|
|
0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Chesapeake purchases shares of stock on the open market for
the
reinvestment of the dividend on shares held in a Rabbi Trust
to secure its
obligations under the Company’s Supplemental Executive Retirement Savings
Plan (“SERP plan”). During the quarter, 446 shares were purchased for this
purpose.
|
|
(2)
Chesapeake has no publicly announced plans or programs to repurchase
its
shares.
|
|
Item
3. Defaults
upon Senior Securities
None
Item
4. Submission
of Matters to a Vote of Security Holders
None
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
November
9, 2006
|
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
November
9, 2006
|
32.1
|
Certificate
of Chief Executive Officer of Chesapeake Utilities Corporation
pursuant to
18 U.S.C. Section 1350, dated November 9, 2006
|
32.2
|
Certificate
of Chief Financial Officer of Chesapeake Utilities Corporation
pursuant to
18 U.S.C. Section 1350, dated November 9,
2006
|
SIGNATURES
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:
November 9, 2006