þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Delaware | 51-0064146 | |
(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) |
Large accelerated filer o | Accelerated filer þ | Non-accelerated filer o | Smaller reporting company o |
1 | ||||||||
1 | ||||||||
26 | ||||||||
40 | ||||||||
42 | ||||||||
43 | ||||||||
43 | ||||||||
43 | ||||||||
44 | ||||||||
44 | ||||||||
44 | ||||||||
45 | ||||||||
46 | ||||||||
Exhibit 10.1 | ||||||||
Exhibit 10.2 | ||||||||
Exhibit 31.1 | ||||||||
Exhibit 31.2 | ||||||||
Exhibit 32.1 | ||||||||
Exhibit 32.2 |
BravePoint
|
BravePoint, Inc. is a wholly-owned subsidiary of Chesapeake Services company, which is a wholly-owned subsidiary of Chesapeake | |
Chesapeake
|
The Registrant, the Registrant and its subsidiaries, or the Registrants subsidiaries, as appropriate in the context of the disclosure | |
Company
|
The Registrant, the Registrant and its subsidiaries, or the Registrants subsidiaries, as appropriate in the context of the disclosure | |
ESNG
|
Eastern Shore Natural Gas Company, a wholly-owned subsidiary of Chesapeake | |
FPU
|
Florida Public Utilities Company, a wholly-owned subsidiary of Chesapeake, effective October 28, 2009 | |
PESCO
|
Peninsula Energy Services Company, Inc., a wholly-owned subsidiary of Chesapeake | |
PIPECO
|
Peninsula Pipeline Company, Inc., a wholly-owned subsidiary of Chesapeake | |
Sharp
|
Sharp Energy, Inc., a wholly-owned subsidiary of Chesapeakes and Sharps subsidiary, Sharpgas, Inc. | |
Xeron
|
Xeron, Inc. a wholly-owned subsidiary of Chesapeake |
Delaware PSC
|
Delaware Public Service Commission | |
EPA
|
United States Environmental Protection Agency | |
FASB
|
Financial Accounting Standards Board | |
FERC
|
Federal Energy Regulatory Commission | |
FDEP
|
Florida Department of Environmental Protection | |
Florida PSC
|
Florida Public Service Commission | |
IASB
|
International Accounting Standards Board | |
Maryland PSC
|
Maryland Public Service Commission | |
MDE
|
Maryland Department of the Environment | |
PSC
|
Public Service Commission | |
SEC
|
Securities and Exchange Commission |
AS/SVE
|
Air Sparging and Soil/Vapor Extraction | |
BS/SVE
|
Bio-Sparging and Soil/Vapor Extraction | |
CGS
|
Community Gas Systems | |
DSCP
|
Directors Stock Compensation Plan | |
Dts
|
Dekatherms | |
Dts/d
|
Dekatherms per day | |
GSR
|
Gas Sales Service Rates | |
HDD
|
Heating Degree-Days | |
Mcf
|
Thousand Cubic Feet | |
MWH
|
Megawatt Hour | |
MGP
|
Manufactured Gas Plant | |
NYSE
|
New York Stock Exchange | |
PIP
|
Performance Incentive Plan | |
RAP
|
Remedial Action Plan |
ASC
|
FASB Accounting Standards CodificationTM (Codification) | |
ASU
|
FASB Accounting Standards Update | |
GAAP
|
Generally Accepted Accounting Principles | |
IFRS
|
International Financial Reporting Standards |
Item 1. | Financial Statements |
For the Three Months Ended March 31, | 2010 | 2009 | ||||||
(in thousands, except shares and per share data) | ||||||||
Operating Revenues |
||||||||
Regulated Energy |
$ | 91,626 | $ | 52,181 | ||||
Unregulated Energy |
59,269 | 49,394 | ||||||
Other |
2,365 | 2,904 | ||||||
Total operating revenues |
153,260 | 104,479 | ||||||
Operating Expenses |
||||||||
Regulated energy cost of sales |
53,768 | 32,513 | ||||||
Unregulated energy and other cost of sales |
45,091 | 38,709 | ||||||
Operations |
18,695 | 12,245 | ||||||
Transaction-related costs |
19 | 114 | ||||||
Maintenance |
1,700 | 615 | ||||||
Depreciation and amortization |
5,623 | 2,384 | ||||||
Other taxes |
2,966 | 1,933 | ||||||
Total operating expenses |
127,862 | 88,513 | ||||||
Operating Income |
25,398 | 15,966 | ||||||
Other income, net of expenses |
115 | 33 | ||||||
Interest charges |
2,363 | 1,642 | ||||||
Income Before Income Taxes |
23,150 | 14,357 | ||||||
Income tax expense |
9,176 | 5,764 | ||||||
Net Income |
$ | 13,974 | $ | 8,593 | ||||
Weighted-Average Common Shares Outstanding: |
||||||||
Basic |
9,419,932 | 6,832,675 | ||||||
Diluted |
9,524,298 | 6,943,129 | ||||||
Earnings Per Share of Common Stock: |
||||||||
Basic |
$ | 1.48 | $ | 1.26 | ||||
Diluted |
$ | 1.47 | $ | 1.24 | ||||
Cash Dividends Declared Per Share of Common
Stock |
$ | 0.315 | $ | 0.305 |
- 1 -
For the Three Months Ended March 31, | 2010 | 2009 | ||||||
(in thousands) | ||||||||
Operating Activities |
||||||||
Net Income |
$ | 13,974 | $ | 8,593 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
Depreciation and amortization |
5,623 | 2,384 | ||||||
Depreciation and accretion included in other costs |
861 | 664 | ||||||
Deferred income taxes, net |
369 | (790 | ) | |||||
Unrealized loss (gain) on commodity contracts |
(215 | ) | 1,294 | |||||
Unrealized loss (gain) on investments |
(51 | ) | 94 | |||||
Employee benefits |
(272 | ) | 412 | |||||
Share-based compensation |
333 | 241 | ||||||
Other, net |
41 | | ||||||
Changes in assets and liabilities: |
||||||||
Sale (purchase) of investments |
(30 | ) | 34 | |||||
Accounts receivable and accrued revenue |
15,800 | 9,217 | ||||||
Propane inventory, storage gas and other inventory |
6,155 | 8,527 | ||||||
Regulatory assets |
1,669 | 604 | ||||||
Prepaid expenses and other current assets |
1,923 | 1,360 | ||||||
Accounts payable and other accrued liabilities |
(12,741 | ) | (10,940 | ) | ||||
Income taxes receivable |
8,580 | 6,345 | ||||||
Accrued interest |
949 | 1,140 | ||||||
Customer deposits and refunds |
604 | (1,854 | ) | |||||
Accrued compensation |
(980 | ) | (1,608 | ) | ||||
Regulatory liabilities |
3,314 | 5,357 | ||||||
Other liabilities |
503 | (38 | ) | |||||
Net cash provided by operating activities |
46,409 | 31,036 | ||||||
Investing Activities |
||||||||
Property, plant and equipment expenditures |
(6,099 | ) | (4,124 | ) | ||||
Purchase of investments |
(310 | ) | | |||||
Environmental expenditures |
(367 | ) | (8 | ) | ||||
Net cash used in investing activities |
(6,776 | ) | (4,132 | ) | ||||
Financing Activities |
||||||||
Common stock dividends |
(2,683 | ) | (1,791 | ) | ||||
Issuance (purchase) of stock for Dividend Reinvestment Plan |
152 | (227 | ) | |||||
Change in cash overdrafts due to outstanding checks |
(834 | ) | | |||||
Net repayment under line of credit agreements |
(88 | ) | (23,200 | ) | ||||
Repayment of long-term debt |
(28,858 | ) | (20 | ) | ||||
Net cash used in financing activities |
(32,311 | ) | (25,238 | ) | ||||
Net Increase in Cash and Cash Equivalents |
7,322 | 1,666 | ||||||
Cash and Cash Equivalents Beginning of Period |
2,828 | 1,611 | ||||||
Cash and Cash Equivalents End of Period |
$ | 10,150 | $ | 3,277 | ||||
- 2 -
March 31, | December 31, | |||||||
Assets | 2010 | 2009 | ||||||
(in thousands, except shares and per share data) | ||||||||
Property, Plant and Equipment |
||||||||
Regulated energy |
$ | 467,147 | $ | 463,856 | ||||
Unregulated energy |
59,066 | 61,360 | ||||||
Other |
16,073 | 16,054 | ||||||
Total property, plant and equipment |
542,286 | 541,270 | ||||||
Less: Accumulated depreciation and amortization |
(111,497 | ) | (107,318 | ) | ||||
Plus: Construction work in progress |
3,720 | 2,476 | ||||||
Net property, plant and equipment |
434,509 | 436,428 | ||||||
Investments |
2,040 | 1,959 | ||||||
Current Assets |
||||||||
Cash and cash equivalents |
10,150 | 2,828 | ||||||
Accounts receivable (less allowance for uncollectible
accounts of $1,460 and $1,609, respectively) |
55,165 | 70,029 | ||||||
Accrued revenue |
11,877 | 12,838 | ||||||
Propane inventory, at average cost |
6,142 | 7,901 | ||||||
Other inventory, at average cost |
3,331 | 3,149 | ||||||
Regulatory assets |
66 | 1,205 | ||||||
Storage gas prepayments |
1,566 | 6,144 | ||||||
Income taxes receivable |
| 2,614 | ||||||
Deferred income taxes |
3,324 | 1,498 | ||||||
Prepaid expenses |
3,857 | 5,843 | ||||||
Mark-to-market energy assets |
198 | 2,379 | ||||||
Other current assets |
146 | 147 | ||||||
Total current assets |
95,822 | 116,575 | ||||||
Deferred Charges and Other Assets |
||||||||
Goodwill |
34,782 | 34,095 | ||||||
Other intangible assets, net |
3,809 | 3,951 | ||||||
Long-term receivables |
247 | 343 | ||||||
Regulatory assets |
21,936 | 19,860 | ||||||
Other deferred charges |
3,799 | 3,891 | ||||||
Total deferred charges and other assets |
64,573 | 62,140 | ||||||
Total Assets |
$ | 596,944 | $ | 617,102 | ||||
- 3 -
March 31, | December 31, | |||||||
Capitalization and Liabilities | 2010 | 2009 | ||||||
(in thousands, except shares and per share data) | ||||||||
Capitalization |
||||||||
Stockholders equity |
||||||||
Common stock, par value $0.4867 per share
(authorized 12,000,000 shares) |
$ | 4,594 | $ | 4,572 | ||||
Additional paid-in capital |
144,866 | 144,502 | ||||||
Retained earnings |
74,205 | 63,231 | ||||||
Accumulated other comprehensive loss |
(2,484 | ) | (2,524 | ) | ||||
Deferred compensation obligation |
748 | 739 | ||||||
Treasury stock |
(748 | ) | (739 | ) | ||||
Total stockholders equity |
221,181 | 209,781 | ||||||
Long-term debt, net of current maturities |
98,988 | 98,814 | ||||||
Total capitalization |
320,169 | 308,595 | ||||||
Current Liabilities |
||||||||
Current portion of long-term debt |
8,125 | 35,299 | ||||||
Short-term borrowing |
29,100 | 30,023 | ||||||
Accounts payable |
37,809 | 51,948 | ||||||
Customer deposits and refunds |
25,650 | 24,960 | ||||||
Accrued interest |
2,836 | 1,887 | ||||||
Dividends payable |
2,974 | 2,959 | ||||||
Income taxes payable |
5,901 | | ||||||
Accrued compensation |
2,493 | 3,445 | ||||||
Regulatory liabilities |
12,171 | 8,882 | ||||||
Mark-to-market energy liabilities |
118 | 2,514 | ||||||
Other accrued liabilities |
10,543 | 8,683 | ||||||
Total current liabilities |
137,720 | 170,600 | ||||||
Deferred Credits and Other Liabilities |
||||||||
Deferred income taxes |
68,666 | 66,923 | ||||||
Deferred investment tax credits |
170 | 193 | ||||||
Regulatory liabilities |
4,179 | 4,154 | ||||||
Environmental liabilities |
10,066 | 11,104 | ||||||
Other pension and benefit costs |
17,212 | 17,505 | ||||||
Accrued asset removal cost Regulatory liability |
33,731 | 33,214 | ||||||
Other liabilities |
5,031 | 4,814 | ||||||
Total deferred credits and other liabilities |
139,055 | 137,907 | ||||||
Total Capitalization and Liabilities |
$ | 596,944 | $ | 617,102 | ||||
- 4 -
Common Stock | Additional | Accumulated Other | ||||||||||||||||||||||||||||||
Number of | Paid-In | Retained | Comprehensive | Deferred | Treasury | |||||||||||||||||||||||||||
(in thousands, except per share and share data) | Shares(7) | Par Value | Capital | Earnings | Loss | Compensation | Stock | Total | ||||||||||||||||||||||||
Balances at December 31, 2008 |
6,827,121 | $ | 3,323 | $ | 66,681 | $ | 56,817 | $ | (3,748 | ) | $ | 1,549 | $ | (1,549 | ) | $ | 123,073 | |||||||||||||||
Net Income |
15,897 | 15,897 | ||||||||||||||||||||||||||||||
Other comprehensive income, net of tax: |
||||||||||||||||||||||||||||||||
Employee Benefit Plans, net of tax: |
||||||||||||||||||||||||||||||||
Amortization of prior service costs (4) |
7 | 7 | ||||||||||||||||||||||||||||||
Net Gain (5) |
1,217 | 1,217 | ||||||||||||||||||||||||||||||
Total comprehensive income |
$ | 17,121 | ||||||||||||||||||||||||||||||
Dividend Reinvestment Plan |
31,607 | 15 | 921 | 936 | ||||||||||||||||||||||||||||
Retirement Savings Plan |
32,375 | 16 | 966 | 982 | ||||||||||||||||||||||||||||
Conversion of debentures |
7,927 | 4 | 131 | 135 | ||||||||||||||||||||||||||||
Share based compensation (1) (3) |
7,374 | 3 | 1,332 | 1,335 | ||||||||||||||||||||||||||||
Deferred Compensation Plan (6) |
(810 | ) | 810 | | ||||||||||||||||||||||||||||
Purchase of treasury stock |
(2,411 | ) | (73 | ) | (73 | ) | ||||||||||||||||||||||||||
Sale and distribution of treasury stock |
2,411 | 73 | 73 | |||||||||||||||||||||||||||||
Common stock issued in the merger |
2,487,910 | 1,211 | 74,471 | 75,682 | ||||||||||||||||||||||||||||
Dividends on stock-based compensation |
(104 | ) | (104 | ) | ||||||||||||||||||||||||||||
Cash dividends (2) |
(9,379 | ) | (9,379 | ) | ||||||||||||||||||||||||||||
Balances at December 31, 2009 |
9,394,314 | 4,572 | 144,502 | 63,231 | (2,524 | ) | 739 | (739 | ) | 209,781 | ||||||||||||||||||||||
Net Income |
13,974 | 13,974 | ||||||||||||||||||||||||||||||
Other comprehensive income, net of tax: |
||||||||||||||||||||||||||||||||
Employee Benefit Plans, net of tax: |
||||||||||||||||||||||||||||||||
Amortization of prior service costs (4) |
2 | 2 | ||||||||||||||||||||||||||||||
Net Gain (5) |
38 | 38 | ||||||||||||||||||||||||||||||
Total comprehensive income |
$ | 14,014 | ||||||||||||||||||||||||||||||
Dividend Reinvestment Plan |
13,714 | 6 | 416 | 422 | ||||||||||||||||||||||||||||
Retirement Savings Plan |
3,539 | 2 | 111 | 113 | ||||||||||||||||||||||||||||
Conversion of debentures |
2,173 | 1 | 36 | 37 | ||||||||||||||||||||||||||||
Tax benefit on share based compensation |
75 | 75 | ||||||||||||||||||||||||||||||
Share based compensation (1) (3) |
26,515 | 13 | (274 | ) | (261 | ) | ||||||||||||||||||||||||||
Deferred Compensation Plan (6) |
9 | (9 | ) | | ||||||||||||||||||||||||||||
Purchase of treasury stock |
(279 | ) | (9 | ) | (9 | ) | ||||||||||||||||||||||||||
Sale and distribution of treasury stock |
279 | 9 | 9 | |||||||||||||||||||||||||||||
Dividends on stock-based compensation |
(26 | ) | (26 | ) | ||||||||||||||||||||||||||||
Cash dividends (2) |
(2,974 | ) | (2,974 | ) | ||||||||||||||||||||||||||||
Balances at March 31, 2010 |
9,440,255 | $ | 4,594 | $ | 144,866 | $ | 74,205 | $ | (2,484 | ) | $ | 748 | $ | (748 | ) | $ | 221,181 | |||||||||||||||
(1) | Includes amounts for shares issued for Directors compensation. |
|
(2) | Cash dividends per share for the periods ended March 31, 2010 and December 31, 2009 were $0.315 and $1.250, respectively. |
|
(3) | The shares issued under the Performance Incentive Plan (PIP) are net of shares withheld for employee taxes. For the period ended March 31, 2010, the Company withheld 17,695 shares for taxes.
We did not issue any shares under PIP in 2009. |
|
(4) | Tax expense recognized on the prior service cost component of employees benefit plans for the periods ended March 31, 2010 and December 31, 2009 were approximately $1 and $5, respectively. |
|
(5) | Tax expense recognized on the net gain (loss) component of employees benefit plans for the periods ended March 31, 2010 and December 31, 2009 were $26 and $794, respectively. |
|
(6) | In May and November 2009, certain participants of the Deferred Compensation Plan received distributions totaling $883. There were no distributions in the first quarter of 2010. |
|
(7) | Includes 28,731 and 28,452 shares at March 31, 2010 and December 31, 2009, respectively, held in a Rabbi Trust established by the Company relating to the Deferred Compensation Plan. |
- 5 -
1. | Summary of Accounting Policies |
Basis of Presentation |
References in this document to the Company, Chesapeake, we, us and our are intended to
mean the Registrant and its subsidiaries, or the Registrants subsidiaries, as appropriate in
the context of the disclosure. |
The accompanying unaudited condensed consolidated financial statements have been prepared in
compliance with the rules and regulations of the Securities and Exchange Commission (SEC) and
United States of America Generally Accepted Accounting Principles (GAAP). In accordance with
these rules and regulations, certain information and disclosures normally required for audited
financial statements have been condensed or omitted. These financial statements should be read
in conjunction with the consolidated financial statements and notes thereto, included in our
latest Annual Report on Form 10-K filed with the SEC on March 8, 2010. In the opinion of
management, these financial statements reflect normal recurring adjustments that are necessary
for a fair presentation of our results of operations, financial position and cash flows for the
interim periods presented. |
As a result of the merger with Florida Public Utilities Company (FPU) in October 2009, we
changed our operating segments (see Note 5, Segment Information, for further discussion). We
revised the segment information as of and for the three months ended March 31, 2009, to reflect
the new segments. We also revised certain presentations and reclassified certain amounts
reported in the condensed consolidated statements of income and cash flows for the three months
ended March 31, 2009 to conform to current period presentations and classifications. These
reclassifications are considered immaterial to the overall presentation of our condensed
consolidated financial statements. |
Due to the seasonality of our business, results for interim periods are not necessarily
indicative of results for the entire fiscal year. Revenue and earnings are typically greater
during the first and fourth quarters, when consumption of energy is highest due to colder
temperatures. |
We have assessed and reported on subsequent events through the date of issuance of these
condensed consolidated financial statements. |
Recent Accounting Amendments Yet to be Adopted by the Company |
In November 2008, the SEC released a proposed roadmap regarding the potential use by U.S.
issuers of financial statements prepared in accordance with International Financial Reporting
Standards (IFRS), a comprehensive series of accounting standards published by the
International Accounting Standards Board (IASB). Under the proposed roadmap, we may be
required to prepare our financial statements in accordance with IFRS as early as 2014. The SEC
will make a determination in 2011 regarding the mandatory adoption of IFRS. In July 2009, the
IASB issued an exposure draft of Rate-regulated Activities, which sets out the scope,
recognition and measurement criteria, and accounting disclosures for assets and liabilities that
arise in the context of cost-of-service regulation, to which our rate-regulated businesses are
subject. We will continue to monitor the development of the potential implementation of IFRS. |
Other Accounting Amendments Adopted by the Company during the first quarter of 2010 |
In January 2010, the Financial Accounting Standards Board (FASB) issued FASB Accounting
Standards Update (ASU) 2010-06, Fair Value Measurements and Disclosures (Topic 820):
Improving Disclosures about Fair Value Measurements. This ASU requires certain new disclosures
and clarifies certain existing disclosure requirements about fair value measurement, as set
forth in FASB Accounting Standards Codification (ASC) Subtopic 820-10. The FASBs objective is
to improve these disclosures and, thus, increase the transparency in financial reporting.
Specifically, ASU 2010-06 amends ASC Subtopic 820-10 to now require a reporting entity to
disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair
value measurements and describe the reasons for the transfers; and, in the reconciliation for
fair value measurements using significant unobservable inputs, a reporting entity should present
separate information about purchases, sales, issuances, and settlements. In addition, ASU
2010-06 clarifies certain requirements of the existing disclosures. We adopted the disclosures
required by this ASU in the first quarter of 2010, except for disclosures about purchases,
sales, issuances, and settlements in the roll-forward of activity in Level 3 fair
value measurements. Those disclosures are effective for fiscal years beginning after December
15, 2010, and for interim periods within those fiscal years. We currently do not have any assets
or liabilities that would require Level 3 fair value measurements. Adoption of this ASU did not
have an impact on our condensed consolidated financial position and results of operations. |
- 6 -
In April 2010, the FASB issued FASB ASU 2010-12 Income Taxes (Topic 740), Accounting for
Certain Tax effects of the 2010 Health Care Reform Acts. This ASU codifies the SEC staff
announcement relating to the accounting for the Health Care and Education Reconciliation Act and
the Patient Protection and Affordable Care Act, which allows the two Acts to be considered
together for accounting purposes. We adopted this ASU in the first quarter of 2010 and have
determined that these Acts did not have a material impact on our income tax accounting (see Note
6, Employee Benefits, to these unaudited condensed consolidated financial statements for
further discussion). |
2. | Acquisitions |
FPU |
On October 28, 2009, we completed the previously announced merger with FPU, pursuant to which
FPU became a wholly-owned subsidiary of Chesapeake. The merger was accounted for under the
acquisition method of accounting, with Chesapeake treated as the acquirer for accounting
purposes. |
The merger allowed us to become a larger energy company serving approximately 200,000 customers
in the Mid-Atlantic and Florida markets, which is twice the number of energy customers we served
previously. The merger increased our overall presence in Florida by adding approximately 51,000
natural gas distribution customers and 12,000 propane distribution customers to our existing
Florida operations. It also introduced us to the electric distribution business as we
incorporated FPUs approximately 31,000 electric customers in northwest and northeast Florida. |
In consummating the merger, we issued 2,487,910 shares of Chesapeake common stock at a price per
share of $30.42 in exchange for all outstanding common stock of FPU. We also paid approximately
$16,000 in lieu of issuing fractional shares in the exchange. There is no contingent
consideration in the merger. Total value of considerations transferred by Chesapeake in the
merger was approximately $75.7 million. |
The assets acquired and liabilities assumed in the merger were recorded at their respective fair
values at the completion of the merger. For certain assets acquired and liabilities assumed,
such as pension and post-retirement benefit obligations, income taxes and contingencies without
readily determinable fair value, for which GAAP provides specific exception to the fair value
recognition and measurement, we applied other specified GAAP or accounting treatment as
appropriate. |
- 7 -
The following table summarizes an adjusted allocation of the purchase price to the assets
acquired and liabilities assumed at the date of the merger. Estimates of deferred income taxes,
recovery of certain regulatory assets, and certain accruals are subject to change, pending the
finalization of income tax returns and availability of additional information about the facts
and circumstances that existed as of the merger closing. We will complete the purchase price
allocation as soon as practicable but no later than one year from the merger closing. |
(In thousands) | October 28, 2009 | |||
Purchase price |
$ | 75,699 | ||
Current assets |
26,761 | |||
Property, plant and equipment |
138,998 | |||
Regulatory assets |
19,584 | |||
Investments and other deferred charges |
3,659 | |||
Intangible assets |
4,019 | |||
Total assets acquired |
193,021 | |||
Long term debt |
47,812 | |||
Borrowings from line of credit |
4,249 | |||
Other current liabilities |
17,427 | |||
Other regulatory liabilities |
19,414 | |||
Pension and post retirement obligations |
14,276 | |||
Environmental liabilities |
12,414 | |||
Deferred income taxes |
20,371 | |||
Customer deposits and other liabilities |
15,467 | |||
Total liabilities assumed |
151,430 | |||
Net identifiable assets acquired |
41,591 | |||
Goodwill |
$ | 34,108 | ||
During the first quarter of 2010, we adjusted the allocation of purchase price based on
additional information available. The adjustments are related to certain accruals, regulatory
assets and deferred tax assets. These adjustments also resulted in a change in fair value of
propane property, plant and equipment. Goodwill from the merger increased to $34.1 million
after incorporating these adjustments, compared to $33.4 million prior to the adjustments. |
None of the $34.1 million in goodwill recorded in connection with the merger is deductible for
tax purposes. All of the goodwill recorded in connection with the merger is related to the
regulated energy segment. We believe the goodwill recognized is attributable primarily to the
strength of FPUs regulated energy businesses and the synergies and opportunities in the
combined company. The intangible assets acquired in connection with the merger are related to
propane customer relationships ($3.5 million) and favorable propane contracts ($519,000). The
intangible value assigned to FPUs existing propane customer relationships will be amortized
over a 12-year period based on the expected duration of benefit arising from the relationships.
The intangible value assigned to FPUs favorable propane contracts will be amortized over a
period ranging from one to 14 months based on contractual terms. |
Current assets of $26.8 million acquired during the merger include notes receivable of
approximately $5.8 million, for which we received payment in March 2010, and accounts receivable
of approximately $3.1 million, $6.0 million and $891,000 for FPUs natural gas, electric and
propane distribution businesses, respectively. |
- 8 -
The financial position and results of operations and cash flows of FPU from the effective date
of the merger are included in our consolidated financial statements. The revenue and net income
from FPU for the three months ended March 31, 2010, included in our condensed consolidated
statements of income, were $54.2 million and $4.5 million, respectively. The following table shows the actual results of combined operations for the three months ended March 31, 2010 and pro forma results of combined operations for the three months ended March 31, 2009, as if the merger had been completed at January 1, 2009. Since the effects of the merger for the three months ended March 31, 2010 were already included in the actual results of our consolidated operations, there is no pro forma adjustment for the three months ended March 31, 2010. |
For the Three Months Ended March 31, | 2010 | 2009 | ||||||
(in thousands, except per share data) | ||||||||
Operating Revenues |
$ | 153,260 | $ | 147,672 | ||||
Operating Income |
25,398 | 18,344 | ||||||
Net income |
13,974 | 9,556 | ||||||
Earnings per share basic |
$ | 1.48 | $ | 1.03 | ||||
Earnings per share diluted |
$ | 1.47 | $ | 1.01 |
Pro forma results are presented for informational purposes only, and are not necessarily
indicative of what the actual results would have been had the acquisition actually occurred on
January 1, 2009. |
The acquisition method of accounting requires acquisition-related costs to be expensed in the
period in which those costs are incurred, rather than including them as a component of
consideration transferred. It also prohibits an accrual of certain restructuring costs at the
time of the merger. As we intend to seek recovery in future rates in Florida of a certain
portion of the purchase premium paid and merger-related costs incurred, we also considered the
impact of ASC Topic 980, Regulated Operations, in determining the proper accounting treatment
for the merger-related costs. As of March 31, 2010, we incurred approximately $3.0 million in
costs to consummate the merger, including the cost associated with merger-related litigation,
and integrating operations following the merger. This includes $40,000 incurred during the
three months ended March 31, 2010. We deferred approximately $1.5 million of the total costs
incurred as a regulatory asset at March 31, 2010, which represents our estimate, based on
similar proceedings in Florida in the past, of the costs which we expect to be permitted to
recover when we complete the appropriate rate proceedings. |
Included in the $3.0 million merger-related costs incurred as of March 31, 2010 were
approximately $28,000 of severance and other restructuring charges for our efforts to integrate
the operations of the two companies. We expect to incur an additional $300,000 in severance and
other restructuring costs related to that effort during the second quarter of 2010. |
Virginia LP Gas |
On February 4, 2010, Sharp Energy, Inc. (Sharp), our propane distribution subsidiary,
purchased the operating assets of Virginia LP Gas, Inc., a regional propane distributor serving
approximately 1,000 retail customers in Northampton and Accomack Counties in Virginia. The
total consideration for the purchase was $600,000, of which $300,000 was paid at the closing and
the remaining $300,000 will be paid over 60 months. Based on our preliminary valuation, we
allocated $412,000 of the purchase price to property, plant and equipment and the remaining
$188,000 to intangible assets. There was no goodwill recorded in connection with this
acquisition. The intangible assets acquired include customer relationships ($85,000) and
non-compete agreements ($103,000), which will both be amortized over a seven-year period. The
revenue and net income from this acquisition that are included in our condensed consolidated
statement of income for the three months ended March 31, 2010 were not material. The allocation
of purchase price is preliminary and we will complete the purchase price allocation as soon as
practicable but no later than one year from the purchase of the assets. |
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3. | Calculation of Earnings Per Share |
For the Three Months Ended March 31, | 2010 | 2009 | ||||||
(in thousands, except Shares and Per Share Data) | ||||||||
Calculation of Basic Earnings Per Share: |
||||||||
Net Income |
$ | 13,974 | $ | 8,593 | ||||
Weighted average shares outstanding |
9,419,932 | 6,832,675 | ||||||
Basic Earnings Per Share |
$ | 1.48 | $ | 1.26 | ||||
Calculation of Diluted Earnings Per Share: |
||||||||
Reconciliation of Numerator: |
||||||||
Net Income |
$ | 13,974 | $ | 8,593 | ||||
Effect of 8.25% Convertible debentures |
19 | 20 | ||||||
Adjusted numerator Diluted |
$ | 13,993 | $ | 8,613 | ||||
Reconciliation of Denominator: |
||||||||
Weighted shares outstanding Basic |
9,419,932 | 6,832,675 | ||||||
Effect of dilutive securities: |
||||||||
Share-based Compensation |
16,090 | 14,246 | ||||||
8.25% Convertible debentures |
88,276 | 96,208 | ||||||
Adjusted denominator Diluted |
9,524,298 | 6,943,129 | ||||||
Diluted Earnings Per Share |
$ | 1.47 | $ | 1.24 | ||||
4. | Commitments and Contingencies |
Rates and Other Regulatory Activities |
Our natural gas and electric distribution operations in Delaware, Maryland and Florida are
subject to regulation by their respective Public Service Commission (PSC); Eastern Shore
Natural Gas Company (ESNG), our natural gas transmission operation, is subject to regulation
by the Federal Energy Regulatory Commission (FERC). Chesapeakes Florida natural gas
distribution division and FPUs natural gas and electric operations continue to be subject to
regulation by the Florida Public Service Commission (Florida PSC) as separate entities. |
Delaware. On September 2, 2008, our Delaware division filed with the Delaware Public
Service Commission (Delaware PSC) its annual Gas Sales Service Rates (GSR) Application,
seeking approval to change its GSR, effective November 1, 2008. On July 7, 2009, the Delaware
PSC granted approval of a settlement agreement presented by the parties in this docket, which
included the Delaware PSC, our Delaware division and the Division of the Public Advocate. As
part of the settlement, the parties agreed to develop a record in a later proceeding on the
price charged by the Delaware division for the temporary release of transmission pipeline
capacity to our natural gas marketing subsidiary, Peninsula Energy Services Company, Inc.
(PESCO). On January 8, 2010, the Hearing Examiner in this proceeding issued a report of
Findings and Recommendations in which he recommended, among other things, that the Delaware PSC
require the Delaware division to refund to its firm service customers the difference between
what the Delaware division would have received had the capacity released to PESCO been priced at
the maximum tariff rates under asymmetrical pricing principles, and the amount actually received
by the Delaware division for capacity released to PESCO. The Hearing Examiner has also
recommended |
- 10 -
that the Delaware PSC require us to adhere to asymmetrical pricing principles by applying the maximum tariff rates regarding all future capacity releases by the Delaware
division to PESCO, if any. Accordingly, if the Hearing Examiners recommendation were approved
without modification by the Delaware PSC and if the Delaware division temporarily released any
capacity to PESCO, the Delaware division would have to credit to its firm service customers
amounts equal to the maximum tariff rates that the Delaware division pays for long-term
capacity, even though the temporary releases were made at lower rates based on competitive
bidding procedures required by the FERCs capacity release rules. We disagreed with the Hearing
Examiners recommendations and filed exceptions to those recommendations on February 18, 2010.
At the hearing on March 30, 2010, the Delaware PSC agreed with us that the Delaware division had
been releasing capacity based on a previous settlement approved by the Delaware PSC and
therefore, did not require the Delaware division to issue any refunds for past capacity
releases. The Delaware PSC, however, required the Delaware division to adhere to asymmetrical
pricing principles for future capacity releases to PESCO until a more appropriate pricing
methodology is developed and approved. We expect the Delaware PSC to issue an order in May 2010
outlining its decisions at the March hearing. The Delaware PSCs decision with regard to future
capacity releases to PESCO contemplates that the parties will reconvene in a separate docket to
determine if a pricing methodology other than asymmetrical pricing principles should apply to
future capacity release by the Delaware division to PESCO. |
On September 4, 2009, our Delaware division filed with the Delaware PSC its annual GSR
Application, seeking approval to change its GSR, effective November 1, 2009. On October 6,
2009, the Delaware PSC authorized the Delaware division to implement the GSR charges on November
1, 2009, on a temporary basis, subject to refund, pending the completion of full evidentiary
hearings and a final decision. The first evidentiary hearing in this matter is scheduled for
May 19, 2010. The Delaware division anticipates a final decision by the Delaware PSC on this
application late in the second quarter or early in the third quarter of 2010. |
On December 17, 2009, our Delaware division filed an application with the Delaware PSC,
requesting approval for an Individual Contract Rate for service to be rendered to a potential
large industrial customer. The Delaware PSC granted approval of the Individual Contract Rate on
February 18, 2010. |
Maryland. On December 1, 2009, the Maryland Public Service Commission (Maryland PSC)
held an evidentiary hearing to determine the reasonableness of the four quarterly gas cost
recovery filings submitted by our Maryland division during the 12 months ended September 30,
2009. No issues were raised at the hearing, and on December 9, 2009, the Hearing Examiner in
this proceeding issued a proposed Order approving the divisions four quarterly filings. On
January 8, 2010, the Maryland PSC issued an Order substantially affirming the Hearing Examiners
decision in the matter. |
Florida. On July 14, 2009, Chesapeakes Florida division filed with the Florida PSC its
petition for a rate increase and request for interim rate relief. In the application, the
Florida division sought approval of: (a) an interim rate increase of $417,555; (b) a permanent
rate increase of $2,965,398, which represented an average base rate increase, excluding fuel
costs, of approximately 25 percent for the Florida divisions customers; (c) implementation or
modification of certain surcharge mechanisms; (d) restructuring of certain rate classifications;
and (e) deferral of certain costs and the purchase premium associated with the then pending
merger with FPU. On August 18, 2009, the Florida PSC approved the full amount of the Florida
divisions interim rate request, subject to refund, applicable to all meters read on or after
September 1, 2009. On December 15, 2009, the Florida PSC: (a) approved a $2,536,307 permanent
rate increase (86 percent of the requested amount) applicable to all meters read on or after
January 14, 2010; (b) determined that there is no refund required of the interim rate increase;
and (c) ordered Chesapeakes Florida division and FPUs natural gas distribution operations to
submit data no later than April 29, 2011 (which is 18 months after the merger) that details all
known benefits, synergies and cost savings and cost increases that have resulted from the
merger. |
Also on December 15, 2009, the Florida PSC approved the settlement agreement for a final natural
gas rate increase of $7,969,000 for FPUs natural gas distribution operation, which represents
approximately 80 percent of the requested base rate increase of $9,917,690 filed by FPU in the
fourth quarter of 2008. The Florida PSC had approved an annual interim rate increase of
$984,054 on February 10, 2009 and approved the permanent rate increase of $8,496,230 in an order
issued on May 5, 2009, with the new rates to be effective beginning on June 4, 2009. On June
17, 2009, however, the Office of Public Counsel entered a protest to the Florida PSCs order and
its final natural gas rate increase ruling, which the protest required a full hearing to be held
within eight months. Subsequent negotiations led to the settlement agreement between the Office
of Public Counsel and FPU, which the Florida PSC approved on December 15, 2009. The rates
authorized pursuant to the order
approving the settlement agreement became effective on January 14, 2010. In February 2010, FPU
refunded to its natural gas customers approximately $290,000, representing revenues in excess of
the amount provided by the settlement agreement that had been billed to customers from June 2009
through January 14, 2010. |
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On September 1, 2009, FPUs electric distribution operation filed its annual Fuel and Purchased
Power Recovery Clause, which seeks final approval of its 2008 fuel-related revenues and expenses
and new fuel rates for 2010. On January 4, 2010, the Florida PSC approved the proposed 2010
fuel rates, effective on or after January 1, 2010. |
On September 11, 2009, Chesapeakes Florida division and FPUs natural gas distribution
operation separately filed their respective annual Energy Conservation Cost Recovery Clauses,
seeking final approval of their 2008 conservation-related revenues and expenses and new
conservation surcharge rates for 2010. On November 2, 2009, the Florida PSC approved the
proposed 2010 conservation surcharge rates for both the Florida division and FPU, effective for
meters read on or after January 1, 2010. |
Also on September 11, 2009, FPUs natural gas distribution operation filed its annual Purchased
Gas Adjustment Clause, seeking final approval of its 2008 purchased gas-related revenues and
expenses and new purchased gas adjustment cap rate for 2010. On November 4, 2009, the Florida
PSC approved the proposed 2010 purchased gas adjustment cap, effective on or after January 1,
2010. |
The City of Marianna Commissioners voted on July 7, 2009 to enter into a new 10-year franchise
agreement with FPU, effective February 1, 2010. The agreement provides that new interruptible
and time-of-use rates shall become available for certain customers prior to February 2011, or,
at the option of the City, the franchise agreement could be voided nine months after that date.
The new franchise agreement contains a provision that permits the City to purchase the Marianna
portion of FPUs electric system. Should FPU fail to make available the new interruptible and
time-of-use rates, and if the franchise agreement is then voided by the City and the City elects
to purchase the Marianna portion of the distribution system, the agreement would require the
City to pay FPU severance/reintegration costs, the fair market value for the system, and an
initial investment in the infrastructure to operate this limited facility. If the City
purchased the electric system, FPU would have a gain in the year of the disposition; but,
ongoing financial results would be negatively impacted from the loss of the Marianna area from
its electric operations. |
ESNG. The following are regulatory activities involving FERC Orders applicable to ESNG
and the expansions of ESNGs transmission system: |
Energylink Expansion Project: In 2006, ESNG proposed to develop, construct and operate
approximately 75 miles of new pipeline facilities from the existing Cove Point Liquefied Natural
Gas terminal in Calvert County, Maryland, crossing under the Chesapeake Bay into Dorchester and
Caroline Counties, Maryland, to points on the Delmarva Peninsula, where such facilities would
interconnect with ESNGs existing facilities in Sussex County, Delaware. In April 2009, ESNG
terminated this project based on inadequate market support and initiated billing to recover
approximately $3.2 million of costs incurred in connection with this project and the related
cost of capital over a period of 20 years in accordance with the terms of the precedent
agreements executed with the two participating customers and approved by the FERC. One of the
two participating customers is Chesapeake, through its Delaware and Maryland divisions. |
Prior Notice Request: On November 25, 2009, ESNG filed a prior notice request, proposing to
construct, own and operate new mainline facilities to deliver additional firm entitlements of
1,594 Mcfs per day of natural gas to Chesapeakes Delaware division. The FERC published the
notice of this filing on December 7, 2009 and with no protest having been filed during the
60-day period following the notice, the proposed activity became effective on February 6, 2010.
ESNG expects to realize an annualized margin of approximately $343,000 upon its completion of
the facilities and implementation of the new service, which is expected in May 2010. |
Mainline Extension Interconnect Project: On March 5, 2010, ESNG submitted an Application for
Certificate of Public Convenience and Necessity to the FERC related to its mainline extension
interconnect project that would tie into the new expansion project undertaken by Texas Eastern
Transmission, LP (TETLP). ESNGs project
involves building and operating the eight-mile mainline extension from Honey Brook, Pennsylvania
to ESNGs existing facility in Parkesburg, Pennsylvania. The estimated capital costs associated
with construction of the mainline extension by ESNG is approximately $19.4 million. FERC
noticed the application on March 15, 2010 and the comment period ended on April 5, 2010. There
were three protests to this application. ESNG filed an answer to the protests on April 28,
2010. |
- 12 -
On December 11, 2009, ESNG filed revised tariff sheets to reflect a new section 42,
Consolidation of Service Agreements, to the General Terms and Conditions of its FERC Gas Tariff.
Section 42 states that shippers may, at their option and subject to certain conditions,
consolidate multiple service agreements under a rate schedule into a new service agreement(s)
under that rate schedule. The tariff sheets were accepted by the FERC on January 7, 2010, as
proposed and were made effective January 15, 2010. As this new section allows for consolidation
of existing service agreements only, there will be no financial impact on ESNG. |
Environmental Commitments and Contingencies |
We are subject to federal, state and local laws and regulations governing environmental quality
and pollution control. These laws and regulations require us to remove or remedy the effect on
the environment of the disposal or release of specified substances at current and former
operating sites. |
We have participated in the investigation, assessment or remediation and have certain exposures
at six former Manufactured Gas Plant (MGP) sites. Those sites are located in Salisbury,
Maryland, and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We have
also been in discussions with the Maryland Department of the Environment (MDE) regarding a
seventh former MGP site located in Cambridge, Maryland. The Key West, Pensacola, Sanford and
West Palm Beach sites are related to FPU, for which we assumed in the merger any existing and
future contingencies. |
As of March 31, 2010, we had recorded $468,000 in environmental liabilities related to
Chesapeakes MGP sites in Maryland and Florida, representing our estimate of the future costs
associated with those sites. As of March 31, 2010, we have recorded approximately $1.6 million
in regulatory and other assets for future recovery of environmental costs from Chesapeakes
customers through its approved rates. As of March 31, 2010, we had recorded approximately $11.9
million in environmental liabilities related to FPUs MGP sites in Florida, primarily from the
West Palm Beach site, which represents our estimate of the future costs associated with those
sites. FPU is approved to recover its environmental costs up to $14.0 million from insurance
and customers through rates. Approximately $7.5 million of FPUs expected environmental costs
have been recovered from insurance and customers through rates as of March 31, 2010. We also
had recorded approximately $6.5 million in regulatory assets for future recovery of
environmental costs from FPUs customers. |
The following discussion provides details on each site. |
Salisbury, Maryland |
We have completed remediation of this site in Salisbury, Maryland, where it was determined
that a former MGP caused localized ground-water contamination. During 1996, we completed
construction of an Air Sparging and Soil-Vapor Extraction (AS/SVE) system and began
remediation procedures. We have reported the remediation and monitoring results to the MDE
on an ongoing basis since 1996. In February 2002, the MDE granted permission to permanently
decommission the AS/SVE system and to discontinue all on-site and off-site well monitoring,
except for one well, which is being maintained for continued product monitoring and
recovery. We have requested and are awaiting a No Further Action determination from the MDE. |
Through March 31, 2010, we have incurred and paid approximately $2.9 million for remedial
actions and environmental studies at this site and do not expect to incur any additional
costs. We have recovered approximately $2.1 million through insurance proceeds or in rates
and have $754,000 of the clean-up costs not yet recovered. |
- 13 -
Winter Haven, Florida |
The Winter Haven site is located on the eastern shoreline of Lake Shipp, in Winter Haven,
Florida. Pursuant to a Consent Order entered into with the Florida Department of
Environmental Protection (FDEP), we are obligated to assess and remediate environmental
impacts at this former MGP site. In 2001, the FDEP approved a Remedial Action Plan (RAP)
requiring construction and operation of a bio-sparge/soil vapor extraction (BS/SVE)
treatment system to address soil and groundwater impacts at a portion of the site. The
BS/SVE treatment system has been in operation since October 2002. The Fourteenth
Semi-Annual RAP Implementation Status Report was submitted to the FDEP in January 2010. The
groundwater sampling results through October 2009 show, in general, a reduction in
contaminant concentrations, although the rate of reduction has declined recently.
Modifications and upgrades to the BS/SVE treatment system were completed in October 2009.
At present, we predict that remedial action objectives may be met for the area being treated
by the BS/SVE treatment system in approximately three years. |
The BS/SVE treatment system does not address impacted soils in the southwest corner of the
site. We are currently completing additional soil and groundwater sampling at this location
for the purpose of designing a remedy for this portion of the site. Following the
completion of this field work, we will submit a soil excavation plan to the FDEP for its
review and approval. |
The FDEP has indicated that we may be required to remediate sediments along the shoreline of
Lake Shipp, immediately west of the site. Based on studies performed to date, we object to
FDEPs suggestion that the sediments have been adversely impacted by the former operations
of the MGP. Our early estimates indicate that some of the corrective measures discussed by
the FDEP could cost as much as $1.0 million. We believe that corrective measures for the
sediments are not warranted and intend to oppose any requirement that we undertake
corrective measures in the offshore sediments. We have not recorded a liability for
sediment remediation, as the final resolution of this matter cannot be predicted at this
time. |
Through March 31, 2010, we have incurred and paid approximately $1.5 million for this site
and estimate an additional cost of $468,000 in the future, which has been accrued. We have
recovered through rates $1.1 million of the costs and continue to expect that the remaining
$829,000, which is included in regulatory assets, will be recoverable from customers through
our approved rates. |
Key West, Florida |
FPU formerly owned and operated an MGP in Key West, Florida. Field investigations performed
in the 1990s identified limited environmental impacts at the site, which is currently owned
by an unrelated third party. The FDEP has not required any further work at the site as of
this time. Our portion of the consulting/remediation costs which may be incurred at this
site is projected to be $93,000. |
Pensacola, Florida |
FPU formerly owned and operated an MGP in Pensacola, Florida. The MGP was also owned by
Gulf Power Corporation (Gulf Power). Portions of the site are now owned by the City of
Pensacola and the Florida Department of Transportation. In October 2009, the FDEP informed
Gulf Power that FDEP would approve a conditional No Further Action determination for the
site, which must include a requirement for institutional/engineering controls. The group,
consisting of Gulf Power, City of Pensacola, Florida Department of Transportation and FPU,
is proceeding with preparation of the necessary documentation to submit the No Further
Action justification. Consulting/remediation costs are projected to be $13,000. |
Sanford, Florida |
FPU is the current owner of property in Sanford, Florida, a former MGP site which was
operated by several other entities before FPU acquired the property. FPU was never an
owner/operator of the MGP. In late September 2006, the U.S. Environmental Protection Agency
(EPA) sent a Special Notice Letter, notifying FPU, and the other responsible parties at
the site (Florida Power Corporation, Florida Power & Light Company, Atlanta Gas Light
Company, and the City of Sanford, Florida, collectively with FPU, the Sanford Group), of
EPAs selection of a final remedy for OU1 (soils), OU2 (groundwater), and OU3
(sediments) for the site. The total estimated remediation costs for this site were
projected at the time by EPA to be approximately $12.9 million. |
- 14 -
In January 2007, FPU and other members of the Sanford Group signed a Third Participation
Agreement, which provides for funding the final remedy approved by EPA for the site. FPUs
share of remediation costs under the Third Participation Agreement is set at five percent of
a maximum of $13 million, or $650,000. As of March 31, 2010, FPU has paid $650,000 to the
Sanford Group escrow account for its share of funding requirements. |
The Sanford Group, EPA and the U.S. Department of Justice agreed to a Consent Decree in
March 2008, which was entered by the federal court in Orlando on January 15, 2009. The
Consent Decree obligates the Sanford Group to implement the remedy approved by EPA for the
site. The total cost of the final remedy is now estimated at approximately $18 million. FPU
has advised the other members of the Sanford Group that it is unwilling at this time to
agree to pay any sum in excess of the $650,000 committed by FPU in the Third Participation
Agreement. |
Several members of the Sanford Group have concluded negotiations with two adjacent property
owners to resolve damages that the property owners allege they have/will incur as a result
of the implementation of the EPA-approved remediation. In settlement of these claims,
members of the Sanford Group, which in this instance does not include FPU, have agreed to
pay specified sums of money to the parties. FPU has refused to participate in the funding
of the third-party settlement agreements based on its contention that it did not contribute
to the release of hazardous substances at the site giving rise to the third-party claims. |
As of March 31, 2010, FPUs remaining share of remediation expenses, including attorneys
fees and costs, is estimated to be $36,000. However, we are unable to determine, to a
reasonable degree of certainty, whether the other members of the Sanford Group will accept
FPUs asserted defense to liability for costs exceeding $13 million to implement the final
remedy for this site or will pursue a claim against FPU for a sum in excess of the $650,000
that FPU has funded under the Third Participation Agreement. |
West Palm Beach, Florida |
We are currently evaluating remedial options to respond to environmental impacts to soil and
groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West
Palm Beach, Florida, where FPU previously operated an MGP. Pursuant to a Consent Order
between FPU and the FDEP, effective April 8, 1991, FPU completed the delineation of soil and
groundwater impacts at the site. On June 30, 2008, FPU transmitted a revised feasibility
study, evaluating appropriate remedies for the site, to the FDEP. On April 30, 2009, the
FDEP issued a remedial action order, which it subsequently withdrew. In response to the
order and as a condition to its withdrawal, FPU committed to perform additional field work
in 2009 and complete an additional engineering evaluation of certain remedial alternatives.
The scope of this work has increased in response to FDEPs demands for additional
information. The total projected cost of this work is approximately $763,000. |
The feasibility study evaluated a wide range of remedial alternatives based on criteria
provided by applicable laws and regulations. Based on the likely acceptability of proven
remedial technologies described in the feasibility study and implemented at similar sites,
management believes that consulting and remediation costs to address the impacts now
characterized at the West Palm Beach site will range from $7.4 million to $18.9 million.
This range of costs covers such remedies as in situ solidification for deeper soil impacts,
excavation of superficial soil impacts, installation of a barrier wall with a permeable
biotreatment zone, monitored natural attenuation of dissolved impacts in groundwater, or
some combination of these remedies. |
- 15 -
Negotiations between FPU and the FDEP on a final remedy for the site continue. Prior to the
conclusion of those negotiations, we are unable to determine, to a reasonable degree of
certainty, the full extent or cost of remedial action that may be required. As of March 31,
2010, and subject to the limitations described above,
we estimate the remediation expenses, including attorneys fees and costs, will range from
approximately $7.8 million to $19.4 million for this site. |
We continue to expect that all costs related to these activities will be recoverable from
customers through rates. |
Other |
We are in discussions with the MDE regarding a former MGP site located in Cambridge,
Maryland. The outcome of this matter cannot be determined at this time; therefore, we have
not recorded an environmental liability for this location. |
Other Commitments and Contingencies |
Natural Gas, Electric and Propane Supply |
Our natural gas, electric and propane distribution operations have entered into contractual
commitments to purchase gas, electricity and propane from various suppliers. The contracts
have various expiration dates. We have a contract with an energy marketing and risk
management company to manage a portion of our natural gas transportation and storage
capacity. This contract expires on March 31, 2012. |
PESCO is currently in the process of obtaining and reviewing proposals from suppliers and
anticipates executing agreements before the existing agreements expire in May 2010. |
FPUs electric fuel supply contracts require FPU to maintain an acceptable standard of
creditworthiness based on specific financial ratios. FPUs agreement with JEA (formerly
known as Jacksonville Electric Authority) requires FPU to comply with the following ratios
based on the result of the prior 12 months: (a) total liabilities to tangible net worth less
than 3.75; and (b) fixed charge coverage greater than 1.5. If either of the ratios is not
met by FPU, we have 30 days to cure the default or provide an irrevocable letter of credit
if the default is not cured. FPUs agreement with Gulf Power Company requires FPU to meet
the following ratios based on the average of the prior six quarters: (a) funds from
operation interest coverage (minimum of 2 to 1); and (b) total debt to total capital
(maximum of 0.65 to 1). If FPU fails to meet the requirements, we have to provide the
supplier a written explanation of action taken or proposed to be taken to be compliant.
Failure to comply with the ratios specified in the agreement with Gulf Power Company could
result in FPU having to provide an irrevocable letter of credit. FPU was in compliance with
these requirements as of March 31, 2010. |
Corporate Guarantees |
We have issued corporate guarantees to certain vendors of our subsidiaries, the largest
portion of which are for our propane wholesale marketing subsidiary and our natural gas
marketing subsidiary. These corporate guarantees provide for the payment of propane and
natural gas purchases in the event of the respective subsidiarys default. Neither
subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for
these purchases are recorded in our financial statements when incurred. The aggregate amount
guaranteed at March 31, 2010 was $24.2 million, with the guarantees expiring on various
dates through 2011. |
In addition to the corporate guarantees, we have issued a letter of credit to our primary
insurance company for $725,000, which expires on August 31, 2010. The letter of credit is
provided as security to satisfy the deductibles under our various insurance policies. There
have been no draws on this letter of credit as of March 31, 2010. We do not anticipate that
this letter of credit will be drawn upon by the counterparty, and we expect that it will be
renewed to the extent necessary in the future. |
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Agreements for Access to New Natural Gas Supplies |
On April 8, 2010, our Delaware and Maryland divisions entered into a Precedent Agreement
with TETLP to secure firm transportation service from TETLP in conjunction with its new
expansion project, which is expected to expand TETLPs mainline system by up to 190,000
dekatherms per day (Dts/d). The Precedent Agreement provides that, upon satisfaction of
certain conditions, the parties will execute two firm transportation service contracts, one
for our Delaware Division and one for our Maryland Division, for 30,000 and 10,000 Dts/d,
respectively, to be effective on the service commencement date of the project, which is
currently projected to occur in November 2012. Each firm transportation service contract
shall,
among other things, provide for: (a) the maximum daily quantity of Dts/d described above;
(b) a term of 15 years; (c) a receipt point at Clarington, Ohio; (d) a delivery point at
Honey Brook, Pennsylvania; and (f) certain credit standards and requirements for security.
Commencement of service and TETLPs and our rights and obligations under the two firm
transportation service contracts are subject to satisfaction of various conditions specified
in the Precedent Agreement. |
Our present sources of natural gas supplies are received primarily from the Gulf of Mexico
natural gas production region and transported through two interstate upstream pipelines,
which interconnect with the ESNG pipeline. These new contracts will provide our Delaware
and Maryland divisions with access to new supplies of natural gas, providing increased
reliability and diversity. They will also provide our Delaware and Maryland divisions
additional upstream transportation capacity, which is essential to meet their current
customer demands and to plan for sustainable growth. |
On March 17, 2010, our Delaware and Maryland divisions entered into a separate Precedent
Agreement with our natural gas transmission subsidiary, ESNG, to extend ESNGs mainline by
eight miles to interconnect with TETLP at Honey Brook, Pennsylvania. The estimated capital
costs associated with construction of the mainline extension by ESNG is approximately $19.4
million, and the proposed rate for transmission service on this extension is ESNGs current
tariff rate for service in that area. |
ESNG and TETLP are proceeding with obtaining the necessary approvals, authorizations or
exemptions for construction and operation of their respective projects, including, but not
limited to, approval by the FERC. Our Delaware and Maryland divisions require no regulatory
approvals or exemptions to receive transmission service from TETLP or ESNG. |
As the final scope of TETLPs expansion facilities is not known at this time, the
reservation rates for service under the firm transportation service contracts were not
specified in the Precedent Agreement with TETLP. TETLP is required to provide our Delaware
and Maryland divisions a good faith estimate of the reservation rate by no later than June
30, 2010. |
Once the TETLP firm transportation service contracts commence, our Delaware and Maryland
divisions will incur costs from those services based on the agreed reservation rate, which
will become an integral component of the costs associated with providing natural gas
supplies to our Delaware and Maryland divisions. The costs from the TETLP firm
transportation service contracts will be included in the annual GSR filings for each of our
respective divisions. |
If the reservation rate provided by TETLP in June 2010 is higher than the range of rates
included in the TETLP Precedent Agreement, and we determine that the higher rate causes the
value of service to be uneconomic to us, the Precedent Agreement provides that the parties
shall promptly meet and work in good faith to negotiate a mutually acceptable reservation
rate. If, however, the parties are unable to agree upon a mutually acceptable reservation
rate, either party may terminate the Precedent Agreement and the related firm transportation
service contracts. In the unlikely event of such termination, we may be required to
reimburse TETLP for our proportionate share (prorated based on our total commitment of
40,000 Dts/d and the project total of 190,000 Dts/d) of TETLPs pre-service costs incurred
as of the date of the termination. We estimate that our proportionate share could be
approximately $363,000 upon such termination. |
After our Delaware and Maryland divisions execute the negotiated rate agreements with TETLP,
we would only be required to reimburse TETLP for our proportionate share of TETLPs
pre-service costs incurred to date, if we terminate the Precedent Agreement, are unwilling
or unable to perform our material duties and obligations thereunder, or take certain other
actions whereby TETLP is unable to obtain the authorizations and exemptions required for
this project. We believe that the likelihood of our Delaware and Maryland divisions
terminating the Precedent Agreement after executing the negotiated rate agreements and
having to reimburse TETLP for our proportionate share of TETLPs pre-service costs is
remote. If such termination were to occur, we estimate that our proportionate share of
TETLPs pre-service costs could be approximately $4.7 million by December 31, 2010. If we
were to terminate the Precedent Agreement after TETLP completed its construction of all
facilities, which is expected to be in the fourth quarter of 2011, our proportionate share
could be as much as approximately $45 million. The actual amount of our proportionate share
of such costs could differ significantly and would ultimately be based on the level of
pre-service costs at the time of any potential termination. |
- 17 -
We provided a letter of credit for $363,000 under the Precedent Agreement with TETLP in
April 2010 as required. The letter of credit is expected to increase quarterly as TETLPs
pre-service costs increases. The letter of credit will not exceed more than the three-month
reservation charge under the firm transportation service contracts, which we currently
estimate to be $2.1 million. |
Other |
We are involved in certain legal actions and claims arising in the normal course of
business. We are also involved in certain legal proceedings and administrative proceedings
before various governmental agencies concerning rates. In the opinion of management, the
ultimate disposition of these proceedings will not have a material effect on our
consolidated financial position, results of operations or cash flows. |
5. | Segment Information |
We use the management approach to identify operating segments, and we organize our business
around differences in regulatory environment and/or products or services. The operating
results of each segment are regularly reviewed by the chief operating decision maker (our
Chief Executive Officer) in order to make decisions about resources and to assess
performance. The segments are evaluated based on their pre-tax operating income. |
As a result of the merger with FPU in October 2009, we changed our operating segments to
better reflect how the chief operating decision maker reviews the various operations of our
Company. Our three operating segments are now composed of the following: |
| Regulated Energy. The regulated energy segment includes natural gas
distribution, electric distribution and natural gas transmission operations. All
operations in this segment are regulated, as to their rates and services, by the
PSC having jurisdiction in each operating territory or by the FERC in the case of
ESNG. |
| Unregulated Energy. The unregulated energy segment includes natural gas
marketing, propane distribution and propane wholesale marketing operations, which
are unregulated as to their rates and services. |
| Other. The Other segment consists primarily of the advanced information
services operation, unregulated subsidiaries that own real estate leased to
Chesapeake and certain corporate costs not allocated to other operations. |
- 18 -
The following table presents information about our reportable segments. |
For the Three Months Ended March 31, | 2010 | 2009 | ||||||
(in thousands) | ||||||||
Operating Revenues, Unaffiliated Customers |
||||||||
Regulated Energy |
$ | 91,300 | $ | 51,793 | ||||
Unregulated Energy |
59,027 | 49,392 | ||||||
Other |
2,933 | 3,294 | ||||||
Total operating revenues, unaffiliated customers |
$ | 153,260 | $ | 104,479 | ||||
Intersegment Revenues (1) |
||||||||
Regulated Energy |
$ | 326 | $ | 388 | ||||
Unregulated Energy |
242 | 2 | ||||||
Other |
187 | 183 | ||||||
Total intersegment revenues |
$ | 755 | $ | 573 | ||||
Operating Income (Loss) |
||||||||
Regulated Energy |
$ | 17,516 | $ | 9,497 | ||||
Unregulated Energy |
7,760 | 6,592 | ||||||
Other and eliminations |
122 | (123 | ) | |||||
Total operating income |
25,398 | 15,966 | ||||||
Other income, net of other expenses |
115 | 33 | ||||||
Interest |
2,363 | 1,642 | ||||||
Income taxes |
9,176 | 5,764 | ||||||
Net income |
$ | 13,974 | $ | 8,593 | ||||
(1) | All significant intersegment revenues are billed at market rates and have been eliminated from
consolidated operating revenues. |
March 31, | December 31, | |||||||
(in thousands) | 2010 | 2009 | ||||||
Identifiable Assets |
||||||||
Regulated energy |
$ | 482,955 | $ | 480,903 | ||||
Unregulated energy |
76,725 | 101,437 | ||||||
Other |
37,264 | 34,724 | ||||||
Total identifiable assets |
$ | 596,944 | $ | 617,064 | ||||
Our operations are almost entirely domestic. Our advanced information services subsidiary,
BravePoint, has infrequent transactions in foreign countries, primarily Canada, which are
denominated and paid in U.S. dollars. These transactions are immaterial to the consolidated
revenues. |
6. | Employee Benefit Plans |
Net periodic benefit costs for our pension and post-retirement benefits plans for the three
months ended March 31, 2010 and 2009 are set forth in the following table: |
Chesapeake | ||||||||||||||||||||||||||||||||
Chesapeake | FPU | Chesapeake | Postretirement | FPU | ||||||||||||||||||||||||||||
Pension Plan | Pension Plan | SERP | Plan | Medical Plan | ||||||||||||||||||||||||||||
For the Three Months Ended March 31, | 2010 | 2009 | 2010 | 2010 | 2009 | 2010 | 2009 | 2010 | ||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||
Service Cost |
$ | | $ | | $ | | $ | | $ | | $ | | $ | | $ | 28 | ||||||||||||||||
Interest Cost |
145 | 140 | 638 | 34 | 32 | 30 | 27 | 34 | ||||||||||||||||||||||||
Expected return on plan assets |
(106 | ) | (86 | ) | (619 | ) | | | | | | |||||||||||||||||||||
Amortization of prior service cost |
(1 | ) | (1 | ) | | 5 | 3 | | | | ||||||||||||||||||||||
Amortization of net loss |
39 | 68 | | 16 | 15 | 15 | 40 | | ||||||||||||||||||||||||
Net periodic cost |
$ | 77 | $ | 121 | $ | 19 | $ | 55 | $ | 50 | $ | 45 | $ | 67 | $ | 62 | ||||||||||||||||
- 19 -
We expect to record pension and postretirement benefit costs of approximately $1.0 million
for 2010 of which $320,000 is attributable to FPUs pension and medical plans. In addition, we
expect to contribute $450,000 and $1.6 million to the Chesapeake and FPU pension plans,
respectively, in 2010, of which $377,000 has been contributed for the FPU pension plan during
the three months ended March 31, 2010. The Chesapeake SERP, the Chesapeake Postretirement Plan
and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash
benefits paid under the Chesapeake SERP for the three months ended March 31, 2010, were $22,000;
for the year 2010, such benefits paid are expected to be approximately $88,000. Cash benefits
paid for the Chesapeake Postretirement Plan and the FPU Medical Plan, primarily for medical
claims, for the three months ended March 31, 2010, totaled $17,000 and $20,000, respectively;
for the year 2010, we have estimated that approximately $115,000 and $144,000, respectively,
will be paid for such benefits. |
On March 23, 2010, the Patient Protection and Affordable Care Act was signed into law. On March
30, 2010, a companion bill, the Health Care and Education Reconciliation Act of 2010, was also
signed into law. Among other things, these new laws, when taken together, reduce the tax
benefits available to an employer that receives the Medicare Part D subsidy. The deferred tax
effects of the reduced deductibility of the postretirement prescription drug coverage must be
recognized in the period these new laws were enacted. The FPU Medical Plan receives the
Medicare Part D subsidy. We assessed the deferred tax effects on the reduced deductibility as a
result of these new laws during the three months ended March 31, 2010 and determined that the
deferred tax effects were not material to our financial results. |
7. | Investments |
The investment balance at March 31, 2010 represents a Rabbi Trust associated with our
Supplemental Executive Retirement Savings Plan and a Rabbi Trust related to a stay bonus
agreement with a former executive. We classify these investments as trading securities and
report them at their fair value. Any unrealized gains and losses, net of other expenses, are
included in other income in the condensed consolidated statements of income. We also have an
associated liability that is recorded and adjusted each month for the gains and losses incurred
by the Rabbi Trusts. At March 31, 2010 and December 31, 2009, total investments had a fair value
of $2.0 million. |
8. | Share-Based Compensation |
Our non-employee directors and key employees are awarded share-based awards through our
Directors Stock Compensation Plan (DSCP) and the Performance Incentive Plan (PIP),
respectively. We record these share-based awards as compensation costs over the respective
service period for which services are received in exchange for an award of equity or
equity-based compensation. The compensation cost is based on the fair value of the grant on the
date it was awarded. |
The table below presents the amounts included in net income related to share-based compensation
expense for the awards granted under the DSCP and the PIP for the three months ended March 31,
2010 and 2009. |
For the Three Months Ended March 31, | 2010 | 2009 | ||||||
(in thousands) | ||||||||
Directors Stock Compensation Plan |
$ | 64 | $ | 47 | ||||
Performance Incentive Plan |
269 | 194 | ||||||
Total compensation expense |
333 | 241 | ||||||
Less: tax benefit |
134 | 97 | ||||||
Share-Based Compensation amounts included in net income |
$ | 199 | $ | 144 | ||||
Directors Stock Compensation Plan |
Shares granted under the DSCP are issued in advance of the directors service periods and are
fully vested as of the date of the grant. We record a prepaid expense of the shares issued and
amortize the expense equally over a service period of one year. No additional shares were
granted under the DSCP during the three months ended March 31, 2010. |
- 20 -
Performance Incentive Plan |
The table below presents the summary of the stock activity for the PIP for the three months
ended March 31, 2010: |
Weighted Average | ||||||||
Number of Shares | Fair Value | |||||||
Outstanding December 31, 2009 |
123,075 | $ | 28.15 | |||||
Granted |
40,875 | $ | 28.83 | |||||
Vested |
43,960 | 27.94 | ||||||
Fortfeited |
| | ||||||
Expired |
18,840 | 27.94 | ||||||
Outstanding March 31, 2010 |
101,150 | $ | 28.56 | |||||
In January 2010, the Board of Directors granted awards under the PIP for 40,875 shares.
The shares granted in January 2010 are multi-year awards, 8,000 shares of which will vest at the
end of the two-year service period, or December 31, 2011. The remaining 32,875 shares will vest
at the end of the three-year service period, or December 31, 2012. These awards are based upon
the achievement of long-term goals, development and our success, and they comprise both
market-based and performance-based conditions or targets. The fair value of each
performance-based condition or target is equal to the market price of our common stock on the
date of the grant. For the market-based conditions, we used the Monte-Carlo pricing model to
estimate the fair value of each market-based award granted. |
At March 31, 2010, the aggregate intrinsic value of the PIP awards was $1.5 million. |
9. | Derivative Instruments |
We use derivative and non-derivative contracts to engage in trading activities and manage risks
related to obtaining adequate supplies and the price fluctuations of natural gas and propane.
Our natural gas and propane distribution operations have entered into agreements with suppliers
to purchase natural gas and propane for resale to their customers. Purchases under these
contracts either do not meet the definition of derivatives or are considered normal purchases
and sales and are accounted for on an accrual basis. Our propane distribution operation may
also enter into fair value hedges of its inventory in order to mitigate the impact of wholesale
price fluctuations. As of March 31, 2010, our natural gas and propane distribution operations
did not have any outstanding derivative contracts. |
Xeron, our propane wholesale and marketing operation, engages in trading activities using
forward and futures contracts. These contracts are considered derivatives and have been
accounted for using the mark-to-market method of accounting. Under the mark-to-market method of
accounting, the trading contracts are recorded at fair value, net of future servicing costs, and
the changes in fair value of those contracts are recognized as unrealized gains or losses in the
statement of income in the period of change. As of March 31, 2010, we had the following
outstanding trading contracts which we accounted for as derivatives: |
Quantity in | Estimated Market | Weighted Average | ||||||||||
At March 31, 2010 | gallons | Prices | Contract Prices | |||||||||
Forward Contracts |
||||||||||||
Sale |
9,870,000 | $ | 1.0900 $1.19250 | $ | 1.1235 | |||||||
Purchase |
10,374,000 | $ | 1.0675 $1.19093 | $ | 1.1169 |
- 21 -
We did not have any derivative contracts with a credit-risk-related contingency. |
Fair values of the derivative contracts recorded in the condensed consolidated balance sheet as
of March 31, 2010 and December 31, 2009, are the following: |
Asset Derivatives | ||||||||||
Fair Value | ||||||||||
(in thousands) | Balance Sheet Location | March 31, 2010 | December 31, 2009 | |||||||
Derivatives not designated as
hedging instruments |
||||||||||
Forward contracts |
Mark-to-market energy assets | $ | 198 | $ | 2,379 | |||||
Put option (1) |
Mark-to-market energy assets | | | |||||||
Total asset derivatives |
$ | 198 | $ | 2,379 | ||||||
Liability Derivatives | ||||||||||
Fair Value | ||||||||||
(in thousands) | Balance Sheet Location | March 31, 2010 | December 31, 2009 | |||||||
Derivatives not designated
as hedging instruments |
||||||||||
Forward contracts |
Mark-to-market energy liabilities | $ | 118 | $ | 2,514 | |||||
Total liability derivatives |
$ | 118 | $ | 2,514 | ||||||
(1) | We purchased a put option for the Pro-Cap (propane price cap)
plan in September 2009. The put option expired on March 31, 2010. The put
option had a fair value of $0 at December 31, 2009. |
The effects of gains and losses from derivative instruments on the condensed
consolidated statements of income for the three months ended March 31, 2010 and 2009, are
the following: |
Amount of Gain (Loss) on Derivatives: | ||||||||||
Location of Gain | For the Three Months Ended March 31, | |||||||||
(in thousands) | (Loss) on Derivatives | 2010 | 2009 | |||||||
Derivatives designated as fair value hedges |
||||||||||
Propane swap agreement (1) |
Cost of Sales | $ | | $ | (42 | ) | ||||
Derivatives not designated as fair value hedges |
||||||||||
Unrealized gains (losses) on forward contracts |
Revenue | 215 | (1,294 | ) | ||||||
Total |
$ | 215 | $ | (1,336 | ) | |||||
(1) | Our propane distribution operation entered into a propane swap
agreement to protect it from the impact that wholesale
propane price increases would have on the Pro-Cap (propane price cap) Plan that
was offered to customers. We terminated this swap agreement in January 2009. |
- 22 -
The effects of trading activities on the condensed consolidated statements of income
for the three months ended March 31, 2010 and 2009, are the following: |
Amount of Trading Revenue: | ||||||||||
Location in the | For the Three Months Ended March 31, | |||||||||
(in thousands) | Statement of Income | 2010 | 2009 | |||||||
Realized gains on forward contracts |
Revenue | $ | 677 | $ | 1,782 | |||||
Unrealized gains (losses) on forward contracts |
Revenue | 215 | (1,294 | ) | ||||||
Total |
$ | 892 | $ | 488 | ||||||
10. | Fair Value of Financial Instruments |
GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to
measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in
active markets for identical assets or liabilities (Level 1 measurements) and the lowest
priority to unobservable inputs (Level 3 measurements). The three levels of the fair value
hierarchy are the following: |
The following table summarizes our financial assets and liabilities that are measured at fair
value on a recurring basis and the fair value measurements, by level, within the fair value
hierarchy used at March 31, 2010: |
Fair Value Measurements Using: | ||||||||||||||||
Significant Other | Significant | |||||||||||||||
Quoted Prices in | Observable | Unobservable | ||||||||||||||
Active Markets | Inputs | Inputs | ||||||||||||||
(in thousands) | Fair Value | (Level 1) | (Level 2) | (Level 3) | ||||||||||||
Assets: |
||||||||||||||||
Investments |
$ | 2,040 | $ | 2,040 | $ | | $ | | ||||||||
Mark-to-market energy assets |
$ | 198 | $ | | $ | 198 | $ | | ||||||||
Liabilities: |
||||||||||||||||
Mark-to-market energy
liabilities |
$ | 118 | $ | | $ | 118 | $ | | ||||||||
- 23 -
The following table summarizes our financial assets and liabilities that are measured at fair
value on a recurring basis and the fair value measurements, by level, within the fair value
hierarchy used at December 31, 2009: |
Fair Value Measurements Using: | ||||||||||||||||
Significant Other | Significant | |||||||||||||||
Quoted Prices in | Observable | Unobservable | ||||||||||||||
Active Markets | Inputs | Inputs | ||||||||||||||
(in thousands) | Fair Value | (Level 1) | (Level 2) | (Level 3) | ||||||||||||
Assets: |
||||||||||||||||
Investments |
$ | 1,959 | $ | 1,959 | $ | | $ | | ||||||||
Mark-to-market energy assets,
including put option |
$ | 2,379 | $ | | $ | 2,379 | $ | | ||||||||
Liabilities: |
||||||||||||||||
Mark-to-market energy
liabilities |
$ | 2,514 | $ | | $ | 2,514 | $ | |
The following valuation techniques were used to measure fair value assets in the table above on
a recurring basis as of March 31, 2010 and December 31, 2009: |
Level 1 Fair Value Measurements: |
Investments The fair values of these trading securities are recorded at fair value based on unadjusted quoted prices in active markets for identical securities. |
Level 2 Fair Value Measurements: |
Mark-to-market energy assets and liabilities These forward contracts are valued using market transactions in either the listed or OTC markets. |
Propane put option The fair value of the propane put option is valued using market transactions for similar assets and liabilities in either the listed or OTC markets. |
At March 31, 2010, there were no non-financial assets or liabilities required to be
reported at fair value. We review our non-financial assets for impairment at least on an annual
basis, as required. |
Other Financial Assets and Liabilities |
Financial assets with carrying values approximating fair value include cash and cash equivalents
and accounts receivable. Financial liabilities with carrying values approximating fair value
include accounts payable and other accrued liabilities and short-term debt. The carrying value
of these financial assets and liabilities approximates fair value due to their short maturities
and because interest rates approximate current market rates for short-term debt. |
At March 31, 2010, long-term debt, which includes the current maturities of long-term debt, had
a carrying value of $107.1 million, compared to a fair value of $119.6 million, using a
discounted cash flow methodology that incorporates a market interest rate based on published
corporate borrowing rates for debt instruments with similar terms and average maturities, with
adjustments for duration, optionality, and risk profile. At December 31, 2009, long-term debt,
including the current maturities, had a carrying value of $134.1 million, compared to the
estimated fair value of $145.5 million. |
- 24 -
11. | Long Term Debt |
Our outstanding long-term debt is shown below: |
March 31, | December 31, | |||||||
(in thousands) | 2010 | 2009 | ||||||
Secured first mortgage bonds: |
||||||||
9.57% bond, due May 1, 2018 |
$ | 8,156 | $ | 8,156 | ||||
10.03% bond, due May 1, 2018 |
4,486 | 4,486 | ||||||
9.08% bond, due June 1, 2022 |
7,950 | 7,950 | ||||||
6.85% bond, due October 1, 2031 |
| 14,012 | ||||||
4.90% bond, due November 1, 2031 |
| 13,222 | ||||||
Uncollateralized senior notes: |
||||||||
6.91% note, due October 1, 2010 |
909 | 909 | ||||||
6.85% note, due January 1, 2012 |
2,000 | 2,000 | ||||||
7.83% note, due January 1, 2015 |
10,000 | 10,000 | ||||||
6.64% note, due October 31, 2017 |
21,818 | 21,818 | ||||||
5.50% note, due October 12, 2020 |
20,000 | 20,000 | ||||||
5.93% note, due October 31, 2023 |
30,000 | 30,000 | ||||||
Convertible debentures: |
||||||||
8.25% due March 1, 2014 |
1,484 | 1,520 | ||||||
Promissory notes |
310 | 40 | ||||||
Total long-term debt |
107,113 | 134,113 | ||||||
Less: current maturities |
(8,125 | ) | (35,299 | ) | ||||
Total long-term debt, net of current maturities |
$ | 98,988 | $ | 98,814 | ||||
In January 2010, we redeemed the 6.85 percent and 4.90 percent series of FPUs secured
first mortgage bonds prior to their respective maturity for $29.1 million, which included the
outstanding principal balances, interest accrued, premium and fees. We used short-term
borrowing to finance the redemption of these bonds. The difference between the carrying value
of those bonds and the amount paid at redemption, totaling $1.5 million, was deferred as a
regulatory asset as allowed by the Florida PSC. |
We initially used our existing short-term borrowing facilities to finance the redemption of
those bonds. On March 16, 2010, we entered into a new $29.1 million term loan credit facility
with an existing lender to continue to finance the redemption. We borrowed $29.1 million for a
nine-month period under this new facility, which bears interest at 1.88 percent per annum. We
are currently in discussions with an existing noteholder for the long-term financing of the
redeemed bonds. |
- 25 -
Item 2. | Managements Discussion and Analysis of Financial Condition and Results of Operations |
| state and federal legislative and regulatory initiatives that affect cost and
investment recovery, have an impact on rate structures, and affect the speed at and degree
to which competition enters the electric and natural gas industries (including
deregulation); |
||
| the outcomes of regulatory, tax, environmental and legal matters, including whether
pending matters are resolved within current estimates; |
||
| industrial, commercial and residential growth or contraction in our service
territories; |
||
| the weather and other natural phenomena, including the economic, operational and other
effects of hurricanes and ice storms; |
||
| the timing and extent of changes in commodity prices and interest rates; |
||
| general economic conditions, including any potential effects arising from terrorist
attacks and any consequential hostilities or other hostilities or other external factors
over which we have no control; |
||
| changes in environmental and other laws and regulations to which we are subject; |
||
| the results of financing efforts, including our ability to obtain financing on
favorable terms, which can be affected by various factors, including credit ratings and
general economic conditions; |
||
| declines in the market prices of equity securities and resultant cash funding
requirements for our defined benefit pension plans; |
||
| the creditworthiness of counterparties with which we are engaged in transactions; |
||
| growth in opportunities for our business units; |
||
| the extent of success in connecting natural gas and electric supplies to transmission
systems and in expanding natural gas and electric markets; |
||
| the effect of accounting pronouncements issued periodically by accounting
standard-setting bodies; |
||
| conditions of the capital markets and equity markets during the periods covered by the
forward-looking statements; |
||
| the ability to successfully execute, manage and integrate merger, acquisition or
divestiture plans, regulatory or other limitations imposed as a result of a merger,
acquisition or divestiture, and the success of the business following a merger,
acquisition or divestiture; |
||
| the ability to manage and maintain key customer relationships; |
||
| the ability to maintain key supply sources; |
- 26 -
| the effect of spot, forward and future market prices on our distribution, wholesale
marketing and energy trading businesses; |
||
| the effect of competition on our businesses; |
||
| the ability to construct facilities at or below estimated costs; |
||
| changes in technology affecting our advanced information services business; and |
||
| operating and litigation risks that may not be covered by insurance. |
| executing a capital investment program in pursuit of organic growth opportunities that
generate returns equal to or greater than our cost of capital; |
| expanding the regulated energy distribution and transmission businesses through
expansion into new geographic areas and providing new services in our current service
territories; |
||
| expanding the propane distribution business in existing and new markets through
leveraging our community gas system services and our bulk delivery capabilities; |
||
| utilizing our expertise across our various businesses to improve overall performance; |
||
| enhancing marketing channels to attract new customers; |
||
| providing reliable and responsive customer service to retain existing customers; |
||
| maintaining a capital structure that enables us to access capital as needed; |
||
| maintaining a consistent and competitive dividend for shareholders; and |
||
| creating and maintaining a diversified customer base, energy portfolio and utility
foundation. |
- 27 -
| Regulated Energy. The regulated energy segment includes natural gas distribution,
electric distribution and natural gas transmission operations. All operations in this
segment are regulated, as to their rates and services, by the PSC having jurisdiction in
each operating territory or by the FERC in the case of ESNG. |
||
| Unregulated Energy. The unregulated energy segment includes natural gas marketing,
propane distribution and propane wholesale marketing operations, which are unregulated as to
their rates and services. |
||
| Other. The Other segment consists primarily of the advanced information services
operation, unregulated subsidiaries that own real estate leased to Chesapeake and certain
corporate costs not allocated to other operations. |
For the Three Months Ended March 31, | 2010 | 2009 | Change | |||||||||
(in thousands) | ||||||||||||
Operating Income (Loss): |
||||||||||||
Regulated Energy |
$ | 17,516 | $ | 9,497 | $ | 8,019 | ||||||
Unregulated Energy |
7,760 | 6,592 | 1,168 | |||||||||
Other & eliminations |
122 | (123 | ) | 245 | ||||||||
Operating Income |
25,398 | 15,966 | 9,432 | |||||||||
Other Income, net of expenses |
115 | 33 | 82 | |||||||||
Interest Charges |
2,363 | 1,642 | 721 | |||||||||
Income Taxes |
9,176 | 5,764 | 3,412 | |||||||||
Net Income |
$ | 13,974 | $ | 8,593 | $ | 5,381 | ||||||
- 28 -
For the Three Months Ended March 31, 2010 | ||||
(in thousands) | ||||
Operating Income: |
||||
Regulated Energy |
$ | 6,690 | ||
Unregulated Energy |
1,362 | |||
Operating Income |
8,052 | |||
Other Income, net of expenses |
59 | |||
Interest Charges |
893 | |||
Income Taxes |
2,756 | |||
Net Income |
$ | 4,462 | ||
Heating degree-days (HDD): |
||||
Actual |
933 | |||
10-year average (normal) |
564 |
Regulated Energy | Unregulated Energy | |||||||||||||||
For the Three Months Ended March 31, 2010 | Natural Gas | Electric | Propane | Other | ||||||||||||
(in thousands) | ||||||||||||||||
Revenue |
$ | 23,163 | $ | 24,255 | $ | 6,228 | $ | 581 | ||||||||
Cost of fuel |
11,332 | 19,628 | 2,991 | 339 | ||||||||||||
Gross margin |
11,831 | 4,627 | 3,237 | 242 | ||||||||||||
Other operating expenses |
6,389 | 3,379 | 2,018 | 99 | ||||||||||||
Operating Income |
$ | 5,442 | $ | 1,248 | $ | 1,219 | $ | 143 | ||||||||
Average number of residential customers |
52,071 | 30,916 | 13,742 | | ||||||||||||
| Weather. Temperatures on the Delmarva Peninsula during the first quarter of 2010 were
four-percent colder than the same period in 2009 and nine-percent colder than normal
(10-year average). The colder weather on the Delmarva Peninsula generated approximately
$300,000 in additional gross margin in the
first quarter of 2010 compared to the same period in 2009. The colder weather throughout
Florida in the first quarter of 2010 also positively affected gross margins from the Florida
operations. |
- 29 -
| Growth. Our Delmarva natural gas distribution operation experienced two-percent
residential customer growth in the first quarter of 2010. Including the increase in
commercial and industrial customers, growth in our Delmarva natural gas distribution
operation contributed approximately $443,000 in period-over-period additional gross margin.
New transmission services and new expansion facilities placed in service during 2009 by
our natural gas transmission subsidiary, ESNG, contributed an additional gross margin of
$323,000 in the first quarter of 2010 compared to the same period in 2009. Chesapeakes
Florida natural gas distribution division experienced a period-over-period net customer
loss, primarily from the loss of several large industrial customers in 2009 due to economic
conditions in the region, which decreased gross margin by $34,000. |
||
| Rates and Regulatory Matters. In December 2009, the Florida PSC approved a permanent
rate increase of approximately $2.5 million, applicable to all meters read on or after
January 14, 2010, for Chesapeakes Florida natural gas distribution division. The rate
increase contributed an additional gross margin of $600,000 in the first quarter of 2010
compared to the same period in 2009. |
||
| Propane Prices. During the first half of 2009, our Delmarva propane distribution
operation benefited from increased margin generated from the lower propane costs, largely
attributable to inventory valuation adjustments in late 2008. The average propane cost in
the first quarter of 2010 was 28 percent higher than the average propane cost in the same
period in 2009, which decreased gross margin by $614,000. Increased volatility in
wholesale propane prices provided opportunities for our propane wholesale marketing
subsidiary, Xeron, as its trading volume increased by 12 percent in the first quarter of
2010 compared to the same period in 2009, increasing its gross margin by $405,000. |
||
| Natural Gas Spot Sale Opportunities. During the first quarter of 2009, our unregulated
natural gas marketing subsidiary, PESCO, benefited from increased spot sales on the
Delmarva Peninsula. Although PESCO continued to identify spot sale opportunities on the
Delmarva Peninsula during the first quarter of 2010, the decreased spot sales, largely due
to reduced sales to one industrial customer, resulted in a decrease in gross margin of
$599,000 in the first quarter of 2010 compared to the same period in 2009. Spot sales are
not predictable, and, therefore, are not included in our long-term financial plans or
forecasts. |
||
| Other Operating Expenses. Our other operating expenses, excluding expenses reported by
FPU, decreased by $175,000 in the first quarter of 2010 compared to the same period in
2009. Lower expenses related to collection and allowance for doubtful accounts receivable
and cost containment measures implemented throughout 2009 for the advanced information
services operation more than fully offset the increases in other operating expenses related
to increased compensation and increased costs associated with increased capital
investments. |
- 30 -
For the Three Months Ended March 31, | 2010 | 2009 | Change | |||||||||
(in thousands) | ||||||||||||
Revenue |
$ | 91,626 | $ | 52,181 | $ | 39,445 | ||||||
Cost of sales |
53,768 | 32,513 | 21,255 | |||||||||
Gross margin |
37,858 | 19,668 | 18,190 | |||||||||
Operations & maintenance |
13,531 | 6,951 | 6,580 | |||||||||
Depreciation & amortization |
4,504 | 1,792 | 2,712 | |||||||||
Other taxes |
2,307 | 1,428 | 879 | |||||||||
Other operating expenses |
20,342 | 10,171 | 10,171 | |||||||||
Operating Income |
$ | 17,516 | $ | 9,497 | $ | 8,019 | ||||||
Statistical Data Delmarva Peninsula |
||||||||||||
Heating degree-days (HDD) (1): |
||||||||||||
Actual |
2,543 | 2,453 | 90 | |||||||||
10-year average (normal) |
2,336 | 2,306 | 30 | |||||||||
Estimated gross margin per HDD |
$ | 2,429 | $ | 1,937 | $ | 492 | ||||||
Per residential customer added: |
||||||||||||
Estimated gross margin |
$ | 375 | $ | 375 | $ | | ||||||
Estimated other operating expenses |
$ | 105 | $ | 103 | $ | 2 | ||||||
Residential Customer Information |
||||||||||||
Average number of customers (1): |
||||||||||||
Delmarva |
48,184 | 47,379 | 805 | |||||||||
Florida Chesapeake |
13,465 | 13,473 | (8 | ) | ||||||||
Total |
61,649 | 60,852 | 797 | |||||||||
(1) | Heating degree-days and average number of residential customers for FPU are included in
the discussions of FPUs results on page 29. |
- 31 -
| The Delmarva natural gas distribution operations experienced growth in residential,
commercial and industrial customers, which contributed $443,000 to the gross margin
increase. Residential, commercial and industrial growth by our Delaware division
contributed $219,000, $76,000 and $51,000, respectively, to the gross margin increase, and
commercial growth by our Maryland division contributed $104,000, to the gross margin
increase. We experienced a two-percent increase in residential customers by the Delmarva
natural gas distribution operation during the first quarter, and we expect that growth rate
to continue in the near future. |
||
| Colder weather on the Delmarva Peninsula generated an additional $200,000 to the gross
margin as heating degree-days increased by four percent over the previous first quarter.
Residential heating rates for the Maryland division are weather-normalized, and we
typically do not experience an impact on gross margin from the weather for our residential
customers in Maryland. |
||
| Increases in gross margin were partially offset by a net decrease of $128,000 as a
result of changes in customer rates and rate classes. Rates and rate classes for a
commercial and an industrial customer in Maryland and certain residential customers in
Delaware were revised in late 2009 and in the first quarter of 2010, based upon our review
of their consumption, the prices of alternative fuels and a corresponding change in their
rate, which led to this decrease. |
||
| In addition, a decrease of $101,000 in gross margin was attributable to the decline in
non-weather related customer consumption. The decrease in consumption is a result of
conservation primarily by residential customers. |
| New long-term transmission services implemented by ESNG in November 2009 as a result of
the completion of its latest expansion program provided for an additional 6,957 Mcfs per
day and added $254,000 to gross margin in the first quarter of 2010. |
||
| New long-term firm transmission service agreements with an industrial customer for the
period from November 2009 to October 2012 provided for an additional 9,662 Mcfs per day
for the period January 1, 2010 through February 5, 2010, and an additional 2,705 Mcfs per
day for the period February 6, 2010 through March 31, 2010. They added $153,000 to gross
margin in the first quarter of 2010. |
||
| In April 2009, ESNG changed its rates to recover specific project costs in accordance
with the terms of precedent agreements with certain customers. These new rates generated
$127,000 in gross margin in the first quarter of 2010. ESNG is currently in discussions
with those customers to potentially reduce the period over which ESNG will recover its
specific project costs in accordance with the terms of the precedent agreements. |
||
| ESNG received notice from a customer of its intention not to renew two firm
transmission service contracts, which expired in October 2009 and March 2010,
respectively, which decreased its gross margin by $84,000 in the first quarter of 2010. |
- 32 -
| Deprecation, asset removal costs and property taxes increased by $244,000 as a result of
our increased capital investments made in 2009 and 2010 to support growth. |
||
| Payroll and benefits increased by $166,000 due primarily to annual salary increases and
increased incentive pay as a result of improved performance. |
||
| Consulting expenses related to various regulatory proceedings involving our natural gas
distribution operations increased by $107,000 during the quarter. |
| On March 15, 2010, we announced the signing of an agreement with an industrial customer
to provide natural gas service to its poultry plant in southern Delaware. The anticipated
annual margin from this agreement equates to approximately 850 average residential heating
customers. The service is expected to begin in early 2011. This also provides us with an
opportunity to extend our natural gas distribution and transmission infrastructures to
serve other potential customers in the same area. |
||
| On April 8, 2010, we entered into a Precedent Agreement with TETLP to secure firm
transportation service from TETLP in conjunction with its new expansion project. The
Precedent Agreement provides that, upon satisfaction of certain conditions, the parties
will execute two firm transportation service contracts, one for our Delaware division and
one for our Maryland division, for 30,000 and 10,000 Dts/d, respectively, to be effective
on the service commencement date of the project, currently projected to occur in
November 2012. Commencement of service and TETLPs and our rights and obligations under
the two firm transportation service contracts are subject to satisfaction of various
conditions specified in the Precedent Agreement. As a result of this new service, our
Delaware and Maryland divisions will have access to new supplies of natural gas, providing
increased reliability and diversity. This will also provide them additional upstream
transportation capacity, which is essential to meet their current customer demands and to
plan for sustainable growth. The Precedent Agreement with TETLP is fully described in Note
4, Commitments and Contingencies, to these unaudited condensed consolidated financial
statements. |
For the Three Months Ended March 31, | 2010 | 2009 | Change | |||||||||
(in thousands) | ||||||||||||
Revenue |
$ | 59,269 | $ | 49,394 | $ | 9,875 | ||||||
Cost of sales |
43,958 | 37,088 | 6,870 | |||||||||
Gross margin |
15,311 | 12,306 | 3,005 | |||||||||
Operations & maintenance |
6,026 | 4,905 | 1,121 | |||||||||
Depreciation & amortization |
1,046 | 514 | 532 | |||||||||
Other taxes |
479 | 295 | 184 | |||||||||
Other operating expenses |
7,551 | 5,714 | 1,837 | |||||||||
Operating Income |
$ | 7,760 | $ | 6,592 | $ | 1,168 | ||||||
Statistical Data Delmarva Peninsula |
||||||||||||
Heating degree-days (HDD): |
||||||||||||
Actual |
2,543 | 2,453 | 90 | |||||||||
10-year average (normal) |
2,336 | 2,306 | 30 | |||||||||
Estimated gross margin per HDD |
$ | 3,083 | $ | 2,465 | $ | 618 |
- 33 -
| Temperatures on the Delmarva Peninsula were four-percent colder in the first quarter of
2010, compared to the same period in 2009, which generated an additional $100,000 of gross
margin. |
||
| Non-weather related volumes sold in the first quarter of 2010 increased by 1.1 million
gallons, or eight percent, and provided for an increase in gross margin of approximately
$497,000. The increase in non-weather related volumes was related to the addition of 390
community gas system customers and 1,000 additional retail customers acquired in February
2010 as part of the purchase of the operating assets of a regional propane distributor
serving the Northampton and Accomack Counties in Virginia areas, which contributed $131,000
and $92,000 in gross margins during the quarter, respectively. Also contributing to the
increase was $274,000 in additional gross margins related to the timing of propane
deliveries to certain customers. |
||
| Other fees contributed $127,000 due primarily to the continued growth and successful
implementation of various customer loyalty programs. |
||
| Partially offsetting the increases described above was a decline in propane margin per
gallon. During the first quarter, our propane distribution operations experienced a
decreased margin generated by higher propane costs, which were 28-percent higher than the
average propane cost in the same period of 2009. This increase in the propane cost per
gallon decreased margin by $614,000 during the first quarter. |
- 34 -
For the Three Months Ended March 31, | 2010 | 2009 | Change | |||||||||
(in thousands) | ||||||||||||
Revenue |
$ | 2,365 | $ | 2,904 | $ | (539 | ) | |||||
Cost of sales |
1,133 | 1,621 | (488 | ) | ||||||||
Gross margin |
1,232 | 1,283 | (51 | ) | ||||||||
Operations & maintenance |
838 | 1,004 | (166 | ) | ||||||||
Transaction-related costs |
19 | 114 | (95 | ) | ||||||||
Depreciation & amortization |
73 | 78 | (5 | ) | ||||||||
Other taxes |
180 | 210 | (30 | ) | ||||||||
Other operating expenses |
1,110 | 1,406 | (296 | ) | ||||||||
Operating Income (Loss) |
$ | 122 | $ | (123 | ) | $ | 245 | |||||
Note: | Eliminations are entries required to eliminate activities between business segments from the consolidated results. |
- 35 -
| An increase of long-term interest expense of $622,000 is related to interest on FPUs
first mortgage bonds. |
||
| Two of the FPU series of bonds, 4.9 percent and 6.85 percent series, were redeemed by
using a new short-term term loan facility at the end of January 2010. Interest expense
from this short-term term loan facility during the first quarter of 2010 was $46,000. |
||
| Additional interest expense of $173,000 is related to interest on deposits from FPUs
customers. |
- 36 -
March 31, | December 31, | |||||||||||||||
(in thousands) | 2010 | 2009 | ||||||||||||||
Long-term debt, net of current maturities |
$ | 98,988 | 31 | % | $ | 98,814 | 32 | % | ||||||||
Stockholders equity |
221,181 | 69 | % | 209,781 | 68 | % | ||||||||||
Total capitalization, excluding short-term debt |
$ | 320,169 | 100 | % | $ | 308,595 | 100 | % | ||||||||
For the Three Months Ended March 31, | 2010 | 2009 | ||||||
(in thousands) | ||||||||
Net Income |
$ | 13,974 | $ | 8,593 | ||||
Non-cash adjustments to net income |
6,689 | 4,299 | ||||||
Changes in assets and liabilities |
25,746 | 18,144 | ||||||
Net cash
provided by operating activities |
$ | 46,409 | $ | 31,036 | ||||
| Non-cash adjustment reflecting unrealized losses on commodity contracts decreased by
approximately $1.5 million. |
||
| Net cash flows from the changes in regulatory liabilities decreased by approximately
$3.9 million as we experienced lower over-collection of gas costs from rate-payers for
Delmarva natural gas distribution operations. |
- 37 -
| Net cash flows from changes in inventory decreased by approximately $2.4 million due
primarily to increased commodity costs. |
||
| Offsetting these decreases partially were: (a) increased net cash flows from customer
deposits and refunds by approximately $2.3 million due to a new industrial customer for our
Delmarva natural gas distribution operations requiring a large deposit and (b) higher net
income by $920,000. |
| During the first three months of 2010, we repaid approximately $30.0 million of our
short-term borrowings related to working capital, compared to net repayments of $23.2
million in the first three months of 2009, as we generated higher amounts of cash from
operating activities. |
||
| In January 2010, we borrowed $29.1 million from our short-term credit facilities to
redeem two series of FPUs secured first mortgage bonds prior to their respective
maturities. We paid $28.9 million, including fees and penalties, related to the
redemption. |
||
| We paid $2.7 million and $1.8 million in cash dividends for the three months ended March
31, 2010 and 2009, respectively. Dividends paid in the first quarter of 2010 increased as
a result of growth in the annualized dividend rate and in the number of shares outstanding. |
- 38 -
Purchase Obligations (in thousands) | Less than 1 year | 1 - 3 years | 3 - 5 years | More than 5 years | Total | |||||||||||||||
Commodities (1) (3) |
$ | 40,894 | $ | 173 | $ | | $ | | $ | 41,067 | ||||||||||
Propane (2) |
11,586 | | | | 11,586 | |||||||||||||||
Total Purchase Obligations |
$ | 52,480 | $ | 173 | $ | | $ | | $ | 52,653 | ||||||||||
(1) | In addition to the obligations noted above, the natural gas
distribution, the electric distribution and propane distribution operations
have agreements with commodity suppliers that have provisions with no
minimum purchase requirements. 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 we do not purchase
specified amounts during the summer season. Under these contracts, the
commodity prices will fluctuate as market prices fluctuate. |
|
(2) | We have also entered into forward sale contracts in the aggregate
amount of $11.1 million. See Part I, Item 3, Quantitative and Qualitative
Disclosures about Market Risk, below, for further information. |
|
(3) | In March 2009, we renewed our contract with an energy marketing
and risk management company to manage a portion of our natural gas
transportation and storage capacity. There were no material changes to the
contracts terms, as reported in our 2009 Annual Report on Form 10-K. |
- 39 -
Item 3. | Quantitative and Qualitative Disclosures about Market Risk |
- 40 -
Quantity in | Estimated Market | Weighted Average | ||||||||||
At March 31, 2010 | gallons | Prices | Contract Prices | |||||||||
Forward Contracts |
||||||||||||
Sale |
9,870,000 | $ | 1.0900 $1.19250 | $ | 1.1235 | |||||||
Purchase |
10,374,000 | $ | 1.0675 $1.19093 | $ | 1.1169 |
March 31, | December 31, | |||||||
(in thousands) | 2010 | 2009 | ||||||
Mark-to-market energy assets |
$ | 198 | $ | 2,379 | ||||
Mark-to-market energy liabilities |
$ | 118 | $ | 2,514 |
- 41 -
Item 4. | Controls and Procedures |
- 42 -
Item 1. | Legal Proceedings |
Item 1A. | Risk Factors |
- 43 -
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds |
Total | Total Number of Shares | Maximum Number of | ||||||||||||||
Number of | Average | Purchased as Part of | Shares That May Yet Be | |||||||||||||
Shares | Price Paid | Publicly Announced Plans | Purchased Under the Plans | |||||||||||||
Period | Purchased | per Share | or Programs (2) | or Programs(2) | ||||||||||||
January 1, 2010
through January 31, 2010 (1) |
279 | $ | 32.12 | | | |||||||||||
February 1, 2010
through February 28, 2010 |
| $ | | | | |||||||||||
March 1, 2010
through March 31, 2010 |
| $ | | | | |||||||||||
Total |
279 | $ | 32.12 | | | |||||||||||
(1) | Chesapeake purchased shares of stock on the open market for the purpose of reinvesting the dividend on deferred stock units
held in the Rabbi Trust accounts for certain Directors and Senior Executives under the Deferred Compensation Plan. The
Deferred Compensation Plan is discussed in detail in Item 8 under the heading Notes to the Consolidated Financial Statements -
Note M, Employee Benefit Plans of our Form 10-K filed with the Securities and Exchange Commission on March 8, 2010.
During the quarter, 279 shares were purchased through the reinvestment of dividends on deferred stock units. |
|
(2) | Except for the purposes described in Footnote (1), Chesapeake has no publicly announced plans or programs to
repurchase its shares. |
Item 3. | Defaults upon Senior Securities |
Item 5. | Other Information |
- 44 -
Item 6. | Exhibits |
3.1 | Amended and Restated Bylaws of Chesapeake
Utilities Corporation, effective April 7, 2010, are incorporated herein by reference to
Exhibit 3 of the Companys Current Report on Form 8-K, filed April
13, 2010, File No. 001-11590. |
|||
10.1 | Term Note Agreement entered into by Chesapeake Utilities Corporation
on March 16, 2010, pursuant to the $29.1 million credit facility with
PNC Bank, N.A., is filed
herewith. |
|||
10.2 |
Precedent Agreement between Chesapeake Utilities Corporation and
Texas Eastern Transmission, LP, dated April 8, 2010, is filed
herewith.1 |
|||
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 May 7, 2010. |
|||
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 May 7, 2010. |
|||
32.1 | Certificate of Chief Executive Officer of Chesapeake Utilities
Corporation pursuant to 18 U.S.C. Section 1350, dated May 7, 2010. |
|||
32.2 | Certificate of Chief Financial Officer of Chesapeake Utilities
Corporation pursuant to 18 U.S.C. Section 1350, dated May 7, 2010. |
- 45 -
Chesapeake Utilities Corporation |
||||
/s/ Beth W. Cooper | ||||
Beth W. Cooper | ||||
Senior Vice President and Chief Financial Officer |
- 46 -