Attached files
file | filename |
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EX-31.2 - EXHIBIT 31.2 - CHESAPEAKE UTILITIES CORP | c91883exv31w2.htm |
EX-32.2 - EXHIBIT 32.2 - CHESAPEAKE UTILITIES CORP | c91883exv32w2.htm |
EX-31.1 - EXHIBIT 31.1 - CHESAPEAKE UTILITIES CORP | c91883exv31w1.htm |
EX-32.1 - EXHIBIT 32.1 - CHESAPEAKE UTILITIES CORP | c91883exv32w1.htm |
Table of Contents
United States
Securities and Exchange Commission
Securities and Exchange Commission
Washington, D.C. 20549
FORM 10-Q
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended: September 30, 2009
OR
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number: 001-11590
Chesapeake Utilities Corporation
(Exact name of registrant as specified in its charter)
Delaware | 51-0064146 | |
(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) |
909 Silver Lake Boulevard, Dover, Delaware 19904
(Address of principal executive offices, including Zip Code)
(Address of principal executive offices, including Zip Code)
(302) 734-6799
(Registrants telephone number, including area code)
(Registrants telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files).
Yes o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer or a smaller reporting company. See definitions of large accelerated filer,
accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o | Accelerated filer þ | Non-accelerated filer o | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
Common Stock, par value $0.4867
6,900,124(1) shares outstanding as of October 31, 2009.
(1) | The number of shares
outstanding does not include shares issuable for the merger with
Florida Public Utilities Company, which became effective on
October 28, 2009. |
Table of Contents
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22 | ||||||||
44 | ||||||||
45 | ||||||||
46 | ||||||||
46 | ||||||||
46 | ||||||||
46 | ||||||||
46 | ||||||||
46 | ||||||||
46 | ||||||||
47 | ||||||||
48 | ||||||||
Exhibit 31.1 | ||||||||
Exhibit 31.2 | ||||||||
Exhibit 32.1 | ||||||||
Exhibit 32.2 |
Table of Contents
Frequently used abbreviations, acronyms, or terms used in this report:
Subsidiaries of Chesapeake Utilities Corporation
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 | |
PESCO
|
Peninsula Energy Services Company, Inc., a wholly-owned subsidiary of Chesapeake | |
PIPECO
|
Peninsula Pipeline Company, Inc., a wholly-owned subsidiary of Chesapeake | |
Xeron
|
Xeron, Inc, a wholly-owned subsidiary of Chesapeake |
Regulatory Agencies
Delaware PSC
|
Delaware Public Service Commission | |
FASB
|
Financial Accounting Standards Board | |
FERC
|
Federal Energy Regulatory Commission | |
FDEP
|
Florida Department of Environmental Protection | |
Maryland PSC
|
Maryland Public Service Commission | |
MDE
|
Maryland Department of the Environment | |
SEC
|
Securities and Exchange Commission |
Other
AS/SVE
|
Air Sparging and Soil/Vapor Extraction | |
ASC
|
FASB Accounting Standards CodificationTM (Codification) | |
ASU
|
FASB Accounting Standards Update | |
CGS
|
Community Gas Systems | |
DSCP
|
Directors Stock Compensation Plan | |
Dts
|
Dekatherms | |
E3 Project
|
ESNG Energylink Expansion Project | |
Florida PSC
|
Florida Public Service Commission | |
FPU
|
Florida Public Utilities Company | |
FSP
|
Financial Accounting Standards Board Staff Position | |
GAAP
|
Generally Accepted Accounting Principles | |
GSR
|
Gas Sales Service Rates | |
HDD
|
Heating Degree-Days | |
PIP
|
Performance Incentive Plan | |
RAP
|
Remedial Action Plan | |
SFAS
|
Statement of Financial Accounting Standards |
Table of Contents
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Table of Contents
PART I FINANCIAL INFORMATION
Item 1. | Financial Statements |
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Income (Unaudited)
(in Thousands, Except Shares and Per Share Data)
(in Thousands, Except Shares and Per Share Data)
For the Three Months Ended September 30, | 2009 | 2008 | ||||||
Operating Revenues |
$ | 31,758 | $ | 49,698 | ||||
Operating Expenses |
||||||||
Cost of sales, excluding costs below |
14,416 | 33,651 | ||||||
Operations |
11,001 | 10,341 | ||||||
Transaction-related costs |
(675 | ) | | |||||
Maintenance |
600 | 656 | ||||||
Depreciation and amortization |
2,437 | 2,267 | ||||||
Other taxes |
1,722 | 1,613 | ||||||
Total operating expenses |
29,501 | 48,528 | ||||||
Operating Income |
2,257 | 1,170 | ||||||
Other loss, net of other income |
(26 | ) | (91 | ) | ||||
Interest charges |
1,540 | 1,488 | ||||||
Income (Loss) Before Income Taxes |
691 | (409 | ) | |||||
Income tax expense (benefits) |
383 | (211 | ) | |||||
Net Income (Loss) |
$ | 308 | $ | (198 | ) | |||
Weighted-Average Common Shares Outstanding: |
||||||||
Basic |
6,883,070 | 6,815,886 | ||||||
Diluted |
6,888,024 | 6,815,886 | ||||||
Earnings (Loss) Per Share of Common Stock: |
||||||||
Basic |
$ | 0.04 | $ | (0.03 | ) | |||
Diluted |
$ | 0.04 | $ | (0.03 | ) | |||
Cash Dividends Declared Per Share of Common Stock |
$ | 0.315 | $ | 0.305 |
The accompanying notes are an integral part of these financial statements.
- 1 -
Table of Contents
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Income (Unaudited)
(in Thousands, Except Shares and Per Share Data)
(in Thousands, Except Shares and Per Share Data)
For the Nine Months Ended September 30, | 2009 | 2008 | ||||||
Operating Revenues |
$ | 177,071 | $ | 219,028 | ||||
Operating Expenses |
||||||||
Cost of sales, excluding costs below |
106,105 | 153,170 | ||||||
Operations |
34,820 | 31,853 | ||||||
Transaction-related costs |
530 | 1,240 | ||||||
Maintenance |
1,932 | 1,644 | ||||||
Depreciation and amortization |
7,235 | 6,695 | ||||||
Other taxes |
5,371 | 4,885 | ||||||
Total operating expenses |
155,993 | 199,487 | ||||||
Operating Income |
21,078 | 19,541 | ||||||
Other income (loss), net of other expenses |
19 | (11 | ) | |||||
Interest charges |
4,755 | 4,470 | ||||||
Income Before Income Taxes |
16,342 | 15,060 | ||||||
Income taxes |
6,636 | 5,865 | ||||||
Net Income |
$ | 9,706 | $ | 9,195 | ||||
Weighted Average Common Shares Outstanding: |
||||||||
Basic |
6,859,516 | 6,807,919 | ||||||
Diluted |
6,981,010 | 6,922,105 | ||||||
Earnings Per Share of Common Stock: |
||||||||
Basic |
$ | 1.41 | $ | 1.35 | ||||
Diluted |
$ | 1.40 | $ | 1.34 | ||||
Cash Dividends Declared Per Share of Common Stock |
$ | 0.935 | $ | 0.905 |
The accompanying notes are an integral part of these financial statements.
- 2 -
Table of Contents
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)
(in Thousands)
(in Thousands)
For the Nine Months Ended September 30, | 2009 | 2008 | ||||||
Operating Activities |
||||||||
Net Income |
$ | 9,706 | $ | 9,195 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
Depreciation and amortization |
7,235 | 6,695 | ||||||
Depreciation and accretion included in other costs |
1,987 | 1,636 | ||||||
Deferred income taxes, net |
5,575 | 6,102 | ||||||
Unrealized loss on commodity contracts |
1,382 | 33 | ||||||
Unrealized loss (gain) on investments |
(161 | ) | 227 | |||||
Employee benefits |
1,396 | 114 | ||||||
Share-based compensation |
897 | 621 | ||||||
Changes in assets and liabilities: |
||||||||
Accounts receivable and accrued revenue |
25,513 | 18,551 | ||||||
Propane inventory, storage gas and other inventory |
2,071 | (7,270 | ) | |||||
Regulatory assets |
(1,182 | ) | 223 | |||||
Prepaid expenses and other current assets |
480 | (8,200 | ) | |||||
Other deferred charges |
70 | (371 | ) | |||||
Accounts payable and other accrued liabilities |
(13,409 | ) | (6,989 | ) | ||||
Income taxes receivable |
3,543 | (3,237 | ) | |||||
Accrued interest |
1,160 | 842 | ||||||
Customer deposits and refunds |
(1,027 | ) | (1,236 | ) | ||||
Accrued compensation |
(280 | ) | (685 | ) | ||||
Regulatory liabilities |
2,179 | (2,842 | ) | |||||
Other liabilities |
317 | 15 | ||||||
Net cash provided by operating activities |
47,452 | 13,424 | ||||||
Investing Activities |
||||||||
Property, plant and equipment expenditures |
(19,674 | ) | (23,724 | ) | ||||
Environmental expenditures |
(33 | ) | (403 | ) | ||||
Net cash used by investing activities |
(19,707 | ) | (24,127 | ) | ||||
Financing Activities |
||||||||
Common stock dividends |
(5,878 | ) | (5,878 | ) | ||||
Issuance of stock for Dividend Reinvestment Plan |
186 | 15 | ||||||
Change in cash overdrafts due to outstanding checks |
471 | 1,419 | ||||||
Net borrowing (repayment) under line of credit agreements |
(23,387 | ) | 16,193 | |||||
Repayment of long-term debt |
(20 | ) | (1,020 | ) | ||||
Net cash provided (used) by financing activities |
(28,628 | ) | 10,729 | |||||
Net Increase (Decrease) in Cash and Cash Equivalents |
(883 | ) | 26 | |||||
Cash and Cash Equivalents Beginning of Period |
1,611 | 2,593 | ||||||
Cash and Cash Equivalents End of Period |
$ | 728 | $ | 2,619 | ||||
The accompanying notes are an integral part of these financial statements.
- 3 -
Table of Contents
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
(in Thousands, Except Shares and Per Share Data)
(in Thousands, Except Shares and Per Share Data)
September 30, | December 31, | |||||||
Assets | 2009 | 2008 | ||||||
Property, Plant and Equipment |
||||||||
Natural gas |
$ | 322,527 | $ | 316,125 | ||||
Propane |
52,588 | 51,827 | ||||||
Advanced information services |
1,434 | 1,439 | ||||||
Other plant |
10,911 | 10,816 | ||||||
Total property, plant and equipment |
387,460 | 380,207 | ||||||
Less: Accumulated depreciation and amortization |
(104,822 | ) | (101,018 | ) | ||||
Plus: Construction work in progress |
8,889 | 1,482 | ||||||
Net property, plant and equipment |
291,527 | 280,671 | ||||||
Investments |
1,834 | 1,601 | ||||||
Current Assets |
||||||||
Cash and cash equivalents |
728 | 1,611 | ||||||
Accounts receivable (less allowance for uncollectible
accounts of $1,246 and $1,159, respectively) |
30,757 | 52,905 | ||||||
Accrued revenue |
1,803 | 5,168 | ||||||
Propane inventory, at average cost |
5,355 | 5,711 | ||||||
Other inventory, at average cost |
1,542 | 1,479 | ||||||
Regulatory assets |
671 | 826 | ||||||
Storage gas prepayments |
7,713 | 9,492 | ||||||
Income taxes receivable |
677 | 7,443 | ||||||
Deferred income taxes |
2,591 | 1,578 | ||||||
Prepaid expenses |
4,250 | 4,679 | ||||||
Mark-to-market energy assets |
1,532 | 4,482 | ||||||
Other current assets |
148 | 147 | ||||||
Total current assets |
57,767 | 95,521 | ||||||
Deferred Charges and Other Assets |
||||||||
Goodwill |
674 | 674 | ||||||
Other intangible assets, net |
154 | 164 | ||||||
Long-term receivables |
390 | 533 | ||||||
Regulatory assets |
4,090 | 2,806 | ||||||
Other deferred charges |
3,798 | 3,825 | ||||||
Total deferred charges and other assets |
9,106 | 8,002 | ||||||
Total Assets |
$ | 360,234 | $ | 385,795 | ||||
The accompanying notes are an integral part of these financial statements.
- 4 -
Table of Contents
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
(in Thousands, Except Shares and Per Share Data)
(in Thousands, Except Shares and Per Share Data)
September 30, | December 31, | |||||||
Capitalization and Liabilities | 2009 | 2008 | ||||||
Capitalization |
||||||||
Stockholders equity |
||||||||
Common stock, par value $0.4867
per share
(authorized 12,000,000
shares) |
$ | 3,352 | $ | 3,323 | ||||
Additional paid-in capital |
69,138 | 66,681 | ||||||
Retained earnings |
60,043 | 56,817 | ||||||
Accumulated other comprehensive
loss |
(3,526 | ) | (3,748 | ) | ||||
Deferred compensation obligation |
1,333 | 1,549 | ||||||
Treasury stock |
(1,333 | ) | (1,549 | ) | ||||
Total stockholders equity |
129,007 | 123,073 | ||||||
Long-term debt, net of current
maturities |
86,282 | 86,422 | ||||||
Total capitalization |
215,289 | 209,495 | ||||||
Current Liabilities |
||||||||
Current portion of long-term debt |
6,656 | 6,656 | ||||||
Short-term borrowing |
10,084 | 33,000 | ||||||
Accounts payable |
26,355 | 40,202 | ||||||
Customer deposits and refunds |
8,508 | 9,534 | ||||||
Accrued interest |
2,184 | 1,024 | ||||||
Dividends payable |
2,170 | 2,082 | ||||||
Accrued compensation |
3,087 | 3,305 | ||||||
Regulatory liabilities |
5,451 | 3,227 | ||||||
Mark-to-market energy liabilities |
1,484 | 3,052 | ||||||
Other accrued liabilities |
3,125 | 2,970 | ||||||
Total current liabilities |
69,104 | 105,052 | ||||||
Deferred Credits and Other Liabilities |
||||||||
Deferred income taxes |
41,234 | 37,720 | ||||||
Deferred investment tax credits |
204 | 235 | ||||||
Regulatory liabilities |
831 | 875 | ||||||
Environmental liabilities |
425 | 511 | ||||||
Other pension and benefit costs |
7,585 | 7,335 | ||||||
Accrued asset removal cost |
21,317 | 20,641 | ||||||
Other liabilities |
4,245 | 3,931 | ||||||
Total deferred credits and other
liabilities |
75,841 | 71,248 | ||||||
Total Capitalization and Liabilities |
$ | 360,234 | $ | 385,795 | ||||
The accompanying notes are an integral part of these financial statements.
- 5 -
Table of Contents
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Stockholders Equity (Unaudited)
(in Thousands, Except Shares and Per Share Data)
(in Thousands, Except Shares and Per Share Data)
Common Stock | Accumulated Other | |||||||||||||||||||||||||||||||
Number of | Additional Paid-In | Comprehensive | Deferred | |||||||||||||||||||||||||||||
Shares | Par Value | Capital | Retained Earnings | Loss | Compensation | Treasury Stock | Total | |||||||||||||||||||||||||
Balances at December 31, 2007 |
6,777,410 | $ | 3,298 | $ | 65,592 | $ | 51,538 | $ | (852 | ) | $ | 1,404 | $ | (1,404 | ) | $ | 119,576 | |||||||||||||||
Net earnings |
13,607 | 13,607 | ||||||||||||||||||||||||||||||
Other comprehensive income, net of tax: |
||||||||||||||||||||||||||||||||
Employee Benefit Plans, net of tax: |
||||||||||||||||||||||||||||||||
Amortization of prior service costs (4) |
(71 | ) | (71 | ) | ||||||||||||||||||||||||||||
Net loss (5) |
(2,825 | ) | (2,825 | ) | ||||||||||||||||||||||||||||
Total comprehensive income |
10,711 | |||||||||||||||||||||||||||||||
Dividend Reinvestment Plan |
9,060 | 5 | 269 | 274 | ||||||||||||||||||||||||||||
Retirement Savings Plan |
5,260 | 3 | 156 | 159 | ||||||||||||||||||||||||||||
Conversion of debentures |
10,397 | 5 | 172 | 177 | ||||||||||||||||||||||||||||
Share based compensation (1) (3) |
24,994 | 12 | 442 | 454 | ||||||||||||||||||||||||||||
Tax benefit on stock warrants |
50 | 50 | ||||||||||||||||||||||||||||||
Deferred Compensation Plan |
145 | (145 | ) | | ||||||||||||||||||||||||||||
Purchase of treasury stock |
(2,425 | ) | (72 | ) | (72 | ) | ||||||||||||||||||||||||||
Sale and distribution of treasury stock |
2,425 | 72 | 72 | |||||||||||||||||||||||||||||
Dividends on stock-based compensation |
(81 | ) | (81 | ) | ||||||||||||||||||||||||||||
Cash dividends (2) |
(8,247 | ) | (8,247 | ) | ||||||||||||||||||||||||||||
Balances at December 31, 2008 |
6,827,121 | 3,323 | 66,681 | 56,817 | (3,748 | ) | 1,549 | (1,549 | ) | 123,073 | ||||||||||||||||||||||
Net earnings |
9,706 | 9,706 | ||||||||||||||||||||||||||||||
Other comprehensive income, net of tax: |
||||||||||||||||||||||||||||||||
Employee Benefit Plans, net of tax: |
||||||||||||||||||||||||||||||||
Amortization of prior service costs (4) |
4 | 4 | ||||||||||||||||||||||||||||||
Net Gain (5) |
218 | 218 | ||||||||||||||||||||||||||||||
Total comprehensive income |
9,928 | |||||||||||||||||||||||||||||||
Dividend Reinvestment Plan |
21,745 | 11 | 636 | 647 | ||||||||||||||||||||||||||||
Retirement Savings Plan |
25,521 | 12 | 755 | 767 | ||||||||||||||||||||||||||||
Conversion of debentures |
7,047 | 3 | 116 | 119 | ||||||||||||||||||||||||||||
Share based compensation (1) (3) |
6,700 | 3 | 950 | 953 | ||||||||||||||||||||||||||||
Deferred Compensation Plan (6) |
(216 | ) | 216 | | ||||||||||||||||||||||||||||
Purchase of treasury stock |
(1,824 | ) | (56 | ) | (56 | ) | ||||||||||||||||||||||||||
Sale and distribution of treasury stock |
1,824 | 56 | 56 | |||||||||||||||||||||||||||||
Dividends on stock-based compensation |
(62 | ) | (62 | ) | ||||||||||||||||||||||||||||
Cash dividends (2) |
(6,418 | ) | (6,418 | ) | ||||||||||||||||||||||||||||
Balances at September 30, 2009 |
6,888,134 | $ | 3,352 | $ | 69,138 | $ | 60,043 | $ | (3,526 | ) | $ | 1,333 | $ | (1,333 | ) | $ | 129,007 | |||||||||||||||
(1) | Includes amounts for shares issued for Directors compensation. |
|
(2) | Cash dividends per share for the periods ended September 30, 2009 and December
31, 2008 were $0.935 and $1.21, respectively. |
|
(3) | The shares issued under the Performance Incentive Plan (PIP) are net of shares
withheld for employee taxes. For 2008, the Company withheld 12,511 shares for taxes. The Company
did not issue any shares for the PIP in 2009. |
|
(4) | Tax expense (benefit) recognized on the prior service cost component of
employees benefit plans for the periods ended September 30, 2009 and December 31, 2008 were approximately $3 and ($52), respectively. |
|
(5) | Tax expense (benefit) recognized on the net gain (loss) component of
employees benefit plans for the periods ended September 30, 2009 and December 31, 2008 were $146 and
($1,900), respectively. |
|
(6) | In May 2009, certain participants of the
Deferred Compensation Plan received distributions totaling $271. |
The accompanying notes are an integral part of these financial statements.
- 6 -
Table of Contents
Notes to Condensed Consolidated Financial Statements
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 the
Companys latest Annual Report on Form 10-K filed with the SEC on March 9, 2009. In the opinion
of management, these financial statements reflect normal recurring adjustments that are
necessary for a fair presentation of the Companys results of operations, financial position
and cash flows for the interim periods presented. |
The Company reclassified certain amounts reported in the statement of cash flows for the nine
months ended September 30, 2008 to conform to current period classifications. In addition, the
Company revised its 2008 segment information by reclassifying transaction costs, which were
previously allocated to the natural gas, propane and advanced information services segments, to
the other and eliminations segment. These reclassifications are considered immaterial to the
overall presentation of the Companys condensed consolidated financial statements. |
The Company has assessed and reported on subsequent events through November 6, 2009, the date
of issuance of these condensed consolidated financial statements. |
Beginning in this third quarter 2009 Form 10-Q, the Company adopted the Financial Accounting
Standards Board (FASB) Accounting Standards CodificationTM (Codification), which
is now the single source of authoritative accounting principles recognized by the FASB. The
adoption of the Codification did not have a material impact on the Companys financial position
and results of operations. As a result of this adoption, the Company updated all references to
accounting and reporting standards included in this Form 10-Q and in some instances provided
references to both pre-and post-Codification standards, as appropriate. |
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, the Company may
be required to prepare 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 the Company is subject to in
its rate-regulated businesses. The Company will continue to monitor the development of the
potential implementation of IFRS. |
In December 2008, the FASB issued FASB Staff Position (FSP) on Statement of Financial
Accounting Standard (SFAS) 132(R)-1, Employers Disclosures about Postretirement Benefit
Plan Assets. This FSP is codified within FASB Accounting Standards CodificationTM
(ASC) Section 715-20-65, of the Topic, Compensation Retirement Benefits. It expands the
disclosure requirements of a defined benefit pension or other postretirement plan by including
the following discussions about plan assets: (i) how investment allocation decisions are made,
including the plans investment policies and strategies; (ii) the major categories of plan
assets; (iii) the inputs and valuation techniques used to measure the fair value of plan
assets; (iv) the effect of fair value measurements, using significant unobservable inputs on
changes in plan assets for the period; and (v) significant concentrations of risk within plan
assets. The Company will comply with the required disclosures, which are effective for the
fiscal years ending after December 15, 2009. |
- 7 -
Table of Contents
Other Accounting Amendments Adopted by the Company During the First Nine Months of 2009: |
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and
Hedging Activities, an amendment of FASB Statement No. 133 (SFAS No. 161). SFAS No. 161 was
codified within FASB ASC Sections 815-10-15 and 65, of the
Topic, Derivatives and Hedging,
and it requires enhanced disclosures for derivative instruments and hedging activities about:
(i) how and why a company uses derivative instruments; (ii) how derivative instruments and
related hedged items are accounted for under the Derivatives and Hedging Topic, and (iii) how
derivative instruments and related hedged items affect a companys financial position,
financial performance and cash flows. Disclosures required by this standard were adopted by
the Company, effective January 1, 2009. Adoption of this standard did not have an impact on the
Companys condensed consolidated financial position and results of operations. These
disclosures are discussed in Note 9, Derivative Instruments, to the condensed consolidated
financial statements. |
In April 2008, the FASB issued FSP FAS 142-3, Determination of the Useful Life of Intangible
Assets, which is codified within FASB ASC Sections 350-30-50, 55 and 65 of the Topic,
Intangibles Goodwill and Other, and FASB ASC Section 275-10-50, of the Topic, Risks and
Uncertainties. It amended factors that should be considered in developing renewal or
extension assumptions used to determine the useful life of a recognized intangible asset. The
intent of these provisions is to improve the consistency between the useful life of a
recognized intangible asset and the period of expected cash flows used to measure the fair
value of the asset. This standard was adopted by the Company, effective January 1, 2009.
Adoption of this standard did not have an impact on the Companys condensed consolidated
financial position and results of operations. |
In May 2008, the FASB issued FSP APB 14-1, Accounting for Convertible Debt Instruments That
May Be Settled in Cash upon Conversion (Including Partial Cash Settlement), FSP APB 14-1 was
codified within: (i) FASB ASC Sections 470-20-10, 15, 25, 30, 35, 40, 45, 50, 55 and 65 of the
Topic, Debt, (ii) FASB ASC Section 815-15-55, of the Topic, Derivatives and Hedging, (iii)
FASB ASC Section 825-10-15, of the Topic, Financial Instruments. It clarifies that
convertible debt instruments, which may be settled in cash upon either mandatory or optional
conversion (including partial cash settlement), should separately account for the liability and
equity components in a manner that will reflect the entitys nonconvertible debt borrowing rate
when interest cost is recognized in subsequent periods. This standard was adopted by the
Company effective, January 1, 2009. The adoption of this standard did not have an impact on the
Companys condensed consolidated financial position and results of operations. |
In September 2008, the FASB issued FSP Emerging Issues Task Force 03-6-1, Determining Whether
Instruments Granted in Share-Based Payment Transactions Are Participating Securities. This
FSP, codified within FASB ASC Sections 260-10-45, 55 and 65, of the Topic, Earnings Per
Share, clarifies that holders of outstanding unvested share-based payment awards containing
rights to nonforfeitable dividends participate with common shareholders in undistributed
earnings. Awards of this nature are considered participating securities, and the two-class
method of computing basic and diluted earnings per share must be applied. This standard was
adopted by the Company, effective January 1, 2009. The adoption of this standard did not have
an impact on the Companys condensed consolidated financial position and results of operations. |
In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair
Value of Financial Instruments. This FSP, codified within FASB ASC Section 825-10-65, of the
Topic, Financial Instruments, enhances consistency in financial reporting by increasing the
frequency of fair value disclosures. The provisions of this standard are effective for interim
and annual reporting periods ending after June 15, 2009, and they did not have an impact on the
Companys condensed consolidated financial position and results of operations. The disclosures
required by this standard are discussed in Note 10, Fair Value of Financial Instruments, to
the condensed consolidated financial statements. |
In May 2009, the FASB issued SFAS No. 165, Subsequent Events, which the Company adopted in
the second quarter of 2009. The provisions of this standard, now residing in FASB ASC Sections
855-10-05, 15, 25, 45, 50 and 55, of the Topic, Subsequent Events, establish general
standards of accounting for, and disclosure of, events that occur after the balance sheet date
but before financial statements are issued or are available to be issued. The adoption of this
standard did not have an impact on the Companys condensed consolidated financial position and
results of operations. |
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In August 2009, the FASB issued FASB Accounting Standards Update (ASU) No. 2009-05, Fair
Value Measurement and Disclosures Measuring Liabilities at Fair Value. The ASU provides
clarification that in circumstances in which a quoted price in an active market for an
identical liability is not available, a reporting entity is required to measure fair value,
using: (i) a valuation technique that uses the quoted price of the identical liability when
traded as an asset or quoted prices for similar liabilities when traded as assets; or (ii)
another valuation technique that is consistent with the principles of the Topic, Fair Value
Measurements and Disclosures. This ASU, adopted by the Company in the third quarter of 2009,
did not have an impact on the Companys condensed consolidated financial position and results
of operations. |
2. | Merger with Florida Public Utilities Company |
On April 20, 2009, Chesapeake and Florida Public Utilities Company (FPU) announced a
definitive merger agreement, pursuant to which FPU will merge with a wholly-owned subsidiary of
Chesapeake, with FPU being the surviving corporation and operating as a wholly-owned subsidiary
of Chesapeake after the merger. On October 22, 2009, shareholders of both Chesapeake and FPU
approved the merger, which became effective on October 28, 2009 and each outstanding share of
FPU common stock was converted into a 0.405 share of Chesapeakes common stock. At closing,
FPU had 6,140,592 common shares outstanding, and Chesapeakes common stock was valued at $30.42
per share, which resulted in total consideration of approximately $75.7 million paid by
Chesapeake. The total consideration is based upon the closing price of Chesapeakes common
stock on October 27, 2009, the last trading day prior to the effective date of the merger.
Immediately after the merger, Chesapeakes stockholders owned approximately 73.5 percent of the
combined company, and FPUs stockholders owned approximately 26.5 percent of the combined
company. |
On September 29, 2009, a putative class action lawsuit, which had been filed on May 8, 2009 in
Palm Beach County, Florida, challenging the merger, purportedly on behalf of the shareholders
of FPU, against FPU, each member of FPUs board of directors and Chesapeake, was dismissed
without prejudice. |
The merger is intended to qualify as a reorganization, within the meaning of Section 368(a) of
the Internal Revenue Code of 1986, as amended, and is accounted for under the acquisition
method of accounting under GAAP, with Chesapeake being treated as the acquirer. Under this
method, the assets acquired and liabilities assumed are recorded at their respective fair
values and added to those of Chesapeake. Chesapeake is in the process of finalizing its
evaluation of the tangible and intangible assets acquired and liabilities assumed, as well as
the initial purchase price allocation as of the acquisition date, including the determination
of any resulting goodwill. Therefore, this information cannot be provided at this time. |
In connection with the merger, Chesapeake has incurred $1.9 million in transaction-related
costs during the nine months ended September 30, 2009. Chesapeake has begun the process of
seeking regulatory approval to defer a portion of these costs related to regulated operations
for future rate recovery. Based on precedents established by the Florida Public Service
Commission (Florida PSC) in previous business combinations involving natural gas utilities in
Florida, the Company determined that future rate recovery of the acquisition-related
transaction costs for regulated operations is probable and deferred $1.4 million of the
transaction-related costs as a regulatory asset as of September 30, 2009. This regulatory
asset of $1.4 million includes deferrals of $89,000 and $850,000 incurred during the first and
second quarters of 2009, respectively, that were previously accounted for as expenses. The
reversal of these amounts is presented as a credit to transaction-related costs in the
accompanying condensed and consolidated statement of income for the three months ended
September 30, 2009. Transaction-related costs not subject to future rate recovery ($265,000 and
$530,000 for the three and nine months ended September 30, 2009, respectively), are also
included in transaction-related costs in the accompanying condensed and consolidated statements
of income. Future regulatory developments may require Chesapeake to re-assess the probability
of future rate recovery with regard to the costs deferred as a regulatory asset. |
FPU distributes natural gas, propane and electricity to residential, commercial and industrial
customers in Florida. FPU also sells merchandise and other service-related products as a
complement to its natural gas and propane operations. FPU serves approximately 96,000
customers, employs 348 people and generated $168.5 million in revenues for 2008. |
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3. | Calculation of Earnings Per Share |
For the Periods Ended September 30, | Three Months | Nine Months | ||||||||||||||
(in Thousands, except Shares and Per Share Data) | 2009 | 2008 | 2009 | 2008 | ||||||||||||
Calculation of Basic Earnings Per Share: |
||||||||||||||||
Net Income (Loss) |
$ | 308 | $ | (198 | ) | $ | 9,706 | $ | 9,195 | |||||||
Weighted average shares outstanding |
6,883,070 | 6,815,886 | 6,859,516 | 6,807,919 | ||||||||||||
Basic Earnings (Loss) Per Share |
$ | 0.04 | $ | (0.03 | ) | $ | 1.41 | $ | 1.35 | |||||||
Calculation of Diluted Earnings Per Share: |
||||||||||||||||
Reconciliation of Numerator: |
||||||||||||||||
Net Income (Loss) |
$ | 308 | $ | (198 | ) | $ | 9,706 | $ | 9,195 | |||||||
Effect of 8.25% Convertible debentures (1) |
| | 60 | 67 | ||||||||||||
Adjusted numerator Diluted |
$ | 308 | $ | (198 | ) | $ | 9,766 | $ | 9,262 | |||||||
Reconciliation of Denominator: |
||||||||||||||||
Weighted shares outstanding Basic |
6,883,070 | 6,815,886 | 6,859,516 | 6,807,919 | ||||||||||||
Effect of dilutive
securities: (1) |
||||||||||||||||
Share-based Compensation |
4,954 | | 27,838 | 9,099 | ||||||||||||
8.25% Convertible
debentures |
| | 93,656 | 105,087 | ||||||||||||
Adjusted denominator
Diluted |
6,888,024 | 6,815,886 | 6,981,010 | 6,922,105 | ||||||||||||
Diluted Earnings (Loss) Per Share |
$ | 0.04 | $ | (0.03 | ) | $ | 1.40 | $ | 1.34 | |||||||
4. | Commitments and Contingencies |
Rates and Regulatory Matters |
The Companys natural gas distribution operations in Delaware, Maryland and Florida are subject
to regulation by their respective Public Service Commission; Eastern Shore Natural Gas Company
(ESNG), the Companys natural gas transmission operation, is subject to regulation by the
Federal Energy Regulatory Commission (FERC). |
Delaware. On September 2, 2008, the Companys 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 September 16,
2008, the Delaware PSC authorized the Delaware division to implement the GSR charges on a
temporary basis, subject to refund, pending the completion of full evidentiary hearings and a
final decision. The Delaware division was required by its natural gas tariff to file a revised
application if its projected over-collection of gas costs for the determination period of
November 2007 through October 2008 exceeded four and one-half percent (4.5 percent) of total
firm gas costs. As a result of a significant decrease in the cost of natural gas, on January
8, 2009, the Delaware division filed with the Delaware PSC a supplemental GSR Application,
seeking approval to change its GSR, effective February 1, 2009. On January 29, 2009, the
Delaware PSC authorized the Delaware division to implement the revised GSR charges on a
temporary basis, subject to refund, pending the completion of full evidentiary hearings and a
final decision. On July 7, 2009, the Delaware PSC granted approval of a settlement agreement
presented by the parties in this docket, the Delaware PSC, the Companys Delaware division and
the Division of the Public Advocate. Pursuant to the settlement agreement, the Companys
Delaware division, commencing in November 2009, will adjust the margin-sharing mechanism
related to its Asset Management Agreement to reduce its proportionate share of such margin.
The Company anticipates a net margin reduction of approximately $8,000 per year from this
change. As part of the settlement, the parties also 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 the Companys natural gas marketing subsidiary, Peninsula
Energy Services Company (PESCO). This later proceeding may be completed by the end of 2009.
An unfavorable outcome of this later proceeding may affect PESCOs spot-sale opportunities and
profitability on the Delmarva Peninsula in the future. |
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On December 2, 2008, the Companys Delaware division filed two applications with the Delaware
PSC, requesting approval for a Town of Milton Franchise Fee Rider and a City of Seaford
Franchise Fee Rider. These Riders allow the division to recover from natural gas customers
located within the Town of Milford or the City of Seaford a proportionate share of the
franchise fees paid by the division. The Delaware PSC granted approval of both Franchise Fee
Riders on January 29, 2009. |
On September 4, 2009, the Companys 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 Delaware division anticipates a final decision
by the Delaware PSC on this application in the second quarter of 2010. |
Maryland. On December 16, 2008, 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 the Companys Maryland division during the twelve months ended September 30, 2008.
No issues were raised at the hearing, and on December 19, 2008, the Hearing Examiner in this
proceeding issued a proposed Order approving the divisions four quarterly filings, which
became a final Order of the Maryland PSC on January 21, 2009. |
On April 24, 2009, the Maryland PSC issued an Order defining utilities payment plan parameters
and termination procedures that would increase the likelihood that customers could pay their
past due amounts to avoid termination of natural gas service. This Order requires the
Companys Maryland division to: (a) provide customers in writing, prior to issuing a
termination notice, certain details about their past due balance and information about
available payment plans, and (b) continue to offer flexible and tailored payment plans. The
Companys Maryland division has implemented procedures to comply with this Order. |
Florida. On July 14, 2009, the Companys 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 seeks approval of: (a) an interim rate increase of $417,555; (b) a permanent
rate increase of $2,965,398, which represents an average base rate increase, excluding fuel
costs, of approximately twenty-five 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 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. A final decision on the permanent rate increase is
expected during the fourth quarter of 2009, as the docket is tentatively scheduled on December
15, 2009 agenda for the Florida PSC. |
On September 11, 2009, the Florida division filed its annual Energy Conservation Cost Recovery
Clause, which seeks final approval of the divisions 2008 conservation-related revenues and
expenses and new conservation surcharge rates for 2010. A final decision by the Florida PSC on
the proposed 2010 conservation surcharge rates is expected in November 2009. |
ESNG. The following activities related to certain FERC Orders and the expansions of its
transmission system were undertaken by ESNG: |
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System Expansion 2006 2008. In accordance with the requirements in the FERCs
Order Issuing Certificate for the 2006 2008 System Expansion, ESNG had until June 13,
2009, to construct the remaining facilities that were authorized in the project filing. On
February 3, 2009, ESNG requested authorization to modify the previously required completion
date and to commence construction of the facilities, which provide for the remaining 7,200
dekatherms (Dts) of additional firm service capacity previously approved by the FERC. On
March 13, 2009, the FERC granted the requested authorization. On October 30, 2009, ESNG
received approval from the FERC to commence services on these expansion facilities in
November 2009, which will permit ESNG to realize an additional annualized gross margin of
approximately $1.0 million. |
Energylink Expansion Project (E3 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 the E3 Project and initiated billing to recover specified
project costs in accordance with the terms of the precedent agreements executed with the
two participating customers, one of which is Chesapeake, through its
Delaware and Maryland divisions. These billings
will reimburse ESNG for the $3.17 million of costs incurred in connection with the E3
Project, including the cost of capital, over a period of 20 years. |
FERC Order Nos. 712 and 712-A. In June and November 2008, the FERC issued Order
Nos. 712 and 712-A, which revised its regulations regarding interstate natural gas pipeline
capacity release programs. The Orders: (a) remove the rate ceiling on capacity release
transactions of one year or less; (b) facilitate the use of asset management arrangements
for certain capacity releases; and (c) facilitate state-approved retail open access
programs. The Orders required interstate gas pipeline companies to remove any inconsistent
tariff provisions within 180 days of the effective date of the rule. On February 2, 2009,
ESNG submitted revised tariff sheets to comply with the requirements set forth in the
Orders. Amended tariff sheets were subsequently filed on February 26, 2009, which made
minor clarifications and corrections. On March 27, 2009, ESNG received FERC approval of
these amended tariff sheets with an effective date of March 1, 2009. |
ESNG also had developments in the following FERC matters:
On April 30, 2009, ESNG submitted its annual Interruptible Revenue Sharing Report to the
FERC. ESNG reported in this filing that it refunded a total of $245,500, inclusive of
interest, in the second quarter of 2009 to its eligible firm customers. |
On May 29, 2009, ESNG submitted its annual Fuel Retention Percentage (FRP) and Cash-Out
Surcharge filings to the FERC. In these filings, ESNG proposed to implement an FRP rate of
0.12 percent and a zero rate for its Cash-Out Surcharge. ESNG also proposed to refund a
total of $294,540, inclusive of interest, to its eligible customers in the second quarter
of 2009 by netting its over-recovered fuel cost against its under-recovered cash-out cost.
The FERC approved these proposals, and ESNG refunded $294,540 to customers in July 2009. |
On June 1, 2009, ESNG submitted revised tariff sheets to comply with FERC Order No. 587-T,
which adopted Version 1.8 of the North American Energy Standards Board Wholesale Gas
Quadrants standards. FERC found this rule necessary to increase the efficiency of the
pipeline grid, make pipelines electronic communications more secure and provide
consistency with the mandate that agencies provide for electronic disclosure of
information. ESNGs revised tariff sheets were approved on August 11, 2009, by the FERC,
which will have no financial impact on ESNG. |
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On August 21, 2009, ESNG filed revised tariff sheets to reflect an increase in the Annual
Charge Adjustment (ACA) surcharge from $0.0017 per Dt to $0.0019 per Dt. The ACA
surcharge is designed to recover applicable program costs incurred by the FERC. The tariff
sheets were accepted as proposed and were made effective on October 1, 2009. As the ACA is
passed-through to ESNGs customers, there will be no financial impact on ESNG. |
Environmental Commitments and Contingencies
Chesapeake is subject to federal, state and local laws and regulations governing environmental
quality and pollution control. These laws and regulations require the Company to remove or
remedy the effect on the environment of the disposal or release of specified substances at
current and former operating sites.
Chesapeake has participated in the investigation, assessment or remediation, and has accrued
liabilities, at two former manufactured gas plant sites located in Maryland and Florida,
referred to, respectively, as the Salisbury Town Gas Light Site and the Winter Haven Coal Gas
Site. The Company has also been in discussions with the Maryland Department of the Environment
(MDE) regarding a third former manufactured gas plant site located in Cambridge, Maryland.
The following discussion provides details on each site.
Salisbury Town Gas Light Site |
In cooperation with the MDE, the Company has completed remediation of the Salisbury Town
Gas Light site, located in Salisbury, Maryland, where it was determined that a former
manufactured gas plant had caused localized ground-water contamination. During 1996, the
Company completed construction of an Air Sparging and Soil-Vapor Extraction (AS/SVE)
system and began remediation procedures. Chesapeake has reported the remediation and
monitoring results to the MDE on an ongoing basis since 1996. In February 2002, the MDE
granted permission to decommission permanently the AS/SVE system and to discontinue all
on-site and off-site well monitoring, except for one well, which is being maintained for
continued product monitoring and recovery. On November 4, 2002, Chesapeake requested, and
is awaiting, a No Further Action determination from the MDE. |
Through September 30, 2009, the Company has incurred and paid approximately $2.9 million
for remedial actions and environmental studies at the Salisbury Town Gas Light site. Of
this amount, approximately $2.1 million has been recovered through insurance proceeds or in
rates pursuant to an Order from the Maryland PSC issued on September 26, 2006. As of
September 30, 2009, a regulatory asset of approximately $812,000 has been recorded to
represent the portion of the clean-up costs not yet recovered. |
Winter Haven Coal Gas Site |
The Winter Haven Coal Gas site is located in Winter Haven, Florida. Chesapeake has been
working with the Florida Department of Environmental Protection (FDEP) in assessing this
coal gas site. In May 1996, the Company filed with the FDEP an AS/SVE Pilot Study Work Plan
(the Work Plan) for the Winter Haven Coal Gas site. After discussions with the FDEP, the
Company filed a modified Work Plan, which contained a description of the scope of work to
complete the site assessment activities and a report describing a limited sediment
investigation performed in 1997. In December 1998, the FDEP approved the modified Work
Plan, which the Company completed during the third quarter of 1999. In February 2001, the
Company filed a Remedial Action Plan (RAP) with the FDEP to address the contamination of
the subsurface soil and ground-water in a portion of the site. The FDEP approved the RAP on
May 4, 2001. Construction of the AS/SVE system was completed in the fourth quarter of 2002,
and the system remains fully operational. |
Through September 30, 2009, the Company has accrued $1.8 million of environmental costs
associated with this site. At September 30, 2009, the Company had accrued a liability of
$425,000 related to this site, offsetting: (a) a regulatory asset of approximately
$726,000, representing the uncollected portion of the estimated clean-up costs, and (b)
approximately $301,000 collected through rates in excess of costs incurred. The Company
expects to recover the remaining clean-up costs through rates. |
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The FDEP has indicated that the Company may be required to remediate sediments along the
shoreline of Lake Shipp, immediately west of the Winter Haven Coal Gas site. Based on
studies performed to date, the Company objects to the FDEPs suggestion that the sediments
have been contaminated and will require remediation. The Companys early estimates indicate
that some of the corrective measures discussed by the FDEP could cost as much as $1.0
million. Given the Companys view as to the absence of ecological effects, the Company
believes that cost expenditures of this magnitude are unwarranted and intends to oppose any
requirement that it undertake corrective measures in the offshore sediments. The Company
anticipates that it will be several years before this issue is resolved. At this time, the
Company has not recorded a liability for sediment remediation. The outcome of this matter
cannot be predicted at this time. |
Other |
During 1999, the MDE queried with the Company regarding a manufactured gas plant site
located in Cambridge, Maryland. The Company responded, and no further discussions ensued.
The outcome of this matter cannot be determined at this time; therefore, the Company has
not recorded an environmental liability for this location. |
Other Commitments and Contingencies
Natural Gas and Propane Supply |
The Companys natural gas and propane distribution operations have entered into contractual
commitments to purchase natural gas and propane from various suppliers. The contracts have
various expiration dates. In March 2009, the Company renewed its contract with an energy
marketing and risk management company to manage a portion of the Companys natural gas
transportation and storage capacity. This contract expires on March 31, 2012. |
In May 2009, the Companys natural gas marketing subsidiary, PESCO, renewed contracts to
purchase natural gas from various suppliers. These contracts expire on May 31, 2010. |
Corporate Guarantees |
The Company has issued corporate guarantees to certain vendors of its subsidiaries,
primarily its propane wholesale marketing subsidiary, Xeron, and its natural gas marketing
subsidiary, PESCO. These corporate guarantees provide for the payment of propane and
natural gas purchases in the event of either subsidiarys default. Neither subsidiary has
ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases
are recorded in the condensed consolidated financial statements when incurred. The
aggregate amount guaranteed at September 30, 2009 was $22.4 million, with the guarantees
expiring on various dates in 2009 and 2010. |
In addition to the corporate guarantees, the Company has issued a letter of credit to its
primary insurance company for $775,000, which expires on May 31, 2010. The letter of credit
is provided as security to satisfy the deductibles under the Companys various insurance
policies. There have been no draws on this letter of credit as of September 30, 2009, and
the Company does not anticipate that this letter of credit will be drawn upon by the
counterparty in the future. |
Accounting for Regulated Operations |
The Company accounts for its regulated operations in accordance with the FASB ASC 980,
Regulated Operations. In applying provisions of this Topic, the Companys regulated
operations may defer costs or revenues in different periods than its unregulated operations
would recognize, resulting in assets or liabilities on the balance sheet. If the Company
were required to terminate the application of these provisions to its regulated operations,
all such deferred amounts would be recognized in the income statement at that time. This
would result in a charge to earnings, net of applicable income taxes, which could be
material. |
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Other
The Company is involved in certain legal actions and claims arising in the normal course of
business. The Company is also involved in certain legal and administrative proceedings
before various governmental agencies concerning rates. In the opinion of management, the
ultimate disposition of these proceedings will not have a material effect on the condensed
consolidated financial position, results of operations or cash flows of the Company.
5. | Segment Information |
The Company uses the management approach to identify operating segments. The Company organizes
its business around differences in products or services, and the operating results of each
segment are regularly reviewed by the Companys chief operating decision-maker in order to make
decisions about the allocation of resources and to assess performance. |
During 2009, the Company revised the 2008 segment information by reclassifying transaction
costs, previously allocated to the natural gas, propane and advanced information services
segments, to the other and eliminations segment. These costs, related to an unconsummated
acquisition in 2008, were not directly attributable to operations of the Companys natural gas,
propane and advanced information services segments, but were allocated to those segments as
corporate overhead costs in 2008. In conjunction with the merger in 2009 and related
acquisition costs (see Note 2), the Company reassessed its previous practice of allocating
transaction costs that are not attributable to operations to each of its reportable segments and
decided not to allocate those costs for the purpose of analyzing segment profitability. As a
result of this change, $890,000, $273,000 and $64,000 of transaction costs allocated to the
natural gas, propane and advanced information services segments, respectively, in the nine
months ended September 30, 2008, were reclassified to the other and eliminations segment. |
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The following table presents information about the Companys reportable segments. |
Three Months Ended | Nine Months Ended | |||||||||||||||
For the Periods Ended September 30, | 2009 | 2008 | 2009 | 2008 | ||||||||||||
(in Thousands) | (in Thousands) | |||||||||||||||
Operating Revenues, Unaffiliated Customers |
||||||||||||||||
Natural gas |
$ | 22,949 | $ | 37,245 | $ | 127,120 | $ | 159,840 | ||||||||
Propane |
6,198 | 8,759 | 41,429 | 48,056 | ||||||||||||
Advanced information services |
2,611 | 3,694 | 8,522 | 11,132 | ||||||||||||
Total operating revenues, unaffiliated customers |
$ | 31,758 | $ | 49,698 | $ | 177,071 | $ | 219,028 | ||||||||
Intersegment Revenues (1) |
||||||||||||||||
Natural gas |
$ | 140 | $ | 114 | $ | 412 | $ | 324 | ||||||||
Propane |
| | 254 | 1 | ||||||||||||
Advanced information services |
36 | 48 | 70 | 84 | ||||||||||||
Other |
173 | 163 | 517 | 489 | ||||||||||||
Total intersegment revenues |
$ | 349 | $ | 325 | $ | 1,253 | $ | 898 | ||||||||
Operating Income (Loss) |
||||||||||||||||
Natural gas |
$ | 3,181 | $ | 2,938 | $ | 18,432 | $ | 19,034 | ||||||||
Propane |
(1,570 | ) | (2,135 | ) | 3,354 | 957 | ||||||||||
Advanced information services |
(103 | ) | 277 | (448 | ) | 516 | ||||||||||
Other and eliminations (2) |
749 | 90 | (260 | ) | (966 | ) | ||||||||||
Total operating income |
$ | 2,257 | $ | 1,170 | $ | 21,078 | $ | 19,541 | ||||||||
Other income (loss), net of other expenses |
(26 | ) | (91 | ) | 19 | (11 | ) | |||||||||
Interest |
1,540 | 1,488 | 4,755 | 4,470 | ||||||||||||
Income taxes (benefits) |
383 | (211 | ) | 6,636 | 5,865 | |||||||||||
Net income (loss) |
$ | 308 | ( $198 | ) | $ | 9,706 | $ | 9,195 | ||||||||
(1) | All significant intersegment revenues are billed at market rates and have been
eliminated from consolidated operating revenues. |
|
(2) | Other and eliminations includes transaction-related costs (credit) of ($675,000) and
$0 for the three months ended September 30, 2009 and 2008, respectively, and $530,000 and $1.2
million for the nine months ended September 30, 2009 and 2008, respectively. |
September 30, | December 31, | |||||||
2009 | 2008 | |||||||
(in Thousands) | ||||||||
Identifiable Assets |
||||||||
Natural gas |
$ | 286,481 | $ | 297,407 | ||||
Propane |
57,379 | 72,955 | ||||||
Advanced information services |
3,716 | 3,545 | ||||||
Other |
12,620 | 11,849 | ||||||
Total identifiable assets |
$ | 360,196 | $ | 385,756 | ||||
The Companys operations are primarily domestic. The advanced information services segment
has infrequent transactions with foreign companies, located primarily in Canada, which are
denominated and paid in U.S. dollars. These transactions are immaterial to the consolidated
operating revenues. |
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6. | Employee Benefit Plans |
Net periodic benefit costs for the defined benefit pension plan, the pension supplemental
executive retirement plan and other post-retirement benefits are shown below: |
Defined Benefit | Pension Supplemental | Other Post-Retirement | ||||||||||||||||||||||
Pension Plan | Executive Retirement Plan | Benefits | ||||||||||||||||||||||
For the Three Months Ended September 30, | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||
(in Thousands) | ||||||||||||||||||||||||
Service Cost |
$ | | $ | | $ | | $ | | $ | | $ | 1 | ||||||||||||
Interest Cost |
140 | 148 | 33 | 31 | 27 | 28 | ||||||||||||||||||
Expected return on plan assets |
(86 | ) | (156 | ) | | | | | ||||||||||||||||
Amortization of prior service cost |
(2 | ) | (1 | ) | 3 | | | | ||||||||||||||||
Amortization of net loss |
68 | | 14 | 12 | 40 | 46 | ||||||||||||||||||
Net periodic (benefit) cost |
$ | 120 | $ | (9 | ) | $ | 50 | $ | 43 | $ | 67 | $ | 75 | |||||||||||
Defined Benefit | Pension Supplemental | Other Post-Retirement | ||||||||||||||||||||||
Pension Plan | Executive Retirement Plan | Benefits | ||||||||||||||||||||||
For the Nine Months Ended September 30, | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||
(in Thousands) | ||||||||||||||||||||||||
Service Cost |
$ | | $ | | $ | | $ | | $ | 1 | $ | 3 | ||||||||||||
Interest Cost |
420 | 445 | 97 | 94 | 81 | 83 | ||||||||||||||||||
Expected return on plan assets |
(259 | ) | (469 | ) | | | | | ||||||||||||||||
Amortization of prior service cost |
(4 | ) | (4 | ) | 10 | | | | ||||||||||||||||
Amortization of net loss |
205 | | 44 | 35 | 119 | 138 | ||||||||||||||||||
Net periodic (benefit) cost |
$ | 362 | $ | (28 | ) | $ | 151 | $ | 129 | $ | 201 | $ | 224 | |||||||||||
The Company expects to recognize increased pension costs of approximately $483,000 in 2009
as a result of the decline in market values of the defined pension plan assets during 2008. In
addition, the Company expects to contribute $450,000 to the defined benefit pension plan during
the fourth quarter of 2009. The pension supplemental executive retirement plan and the other
post-retirement benefit plan are unfunded and are expected to be paid out of the general funds
of the Company. Cash benefits paid under the pension supplemental executive retirement plan for
the three months and nine months ended September 30, 2009, were $22,000 and $67,000,
respectively; for the year 2009, such benefits paid are expected to be approximately
$88,000. Cash benefits paid for other post-retirement benefits, primarily for medical claims,
for the three and nine months ended September 30, 2009, totaled $57,000 and $91,000,
respectively. Based on actuarial assumptions and historical data, the Company has estimated that
approximately $225,000 will be paid for such benefits during 2009. |
7. | Investments |
The investment balance at September 30, 2009, represents a Rabbi Trust associated with the
Companys Supplemental Executive Retirement Savings Plan. The Company classifies these
investments as trading securities and reports 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. The Company also has an associated liability that is recorded and
adjusted each month for the gains and losses incurred by the Rabbi Trust. At September 30,
2009, total investments had a fair value of $1.8 million. |
8. | Share-Based Compensation |
The Companys non-employee directors and key employees are awarded share-based awards through
the Companys Directors Stock Compensation Plan (DSCP) and the Performance Incentive Plan
(PIP), respectively. The Company records 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. |
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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 and nine months ended
September 30, 2009 and 2008. |
(in Thousands) | Three Months Ended | Nine Months Ended | ||||||||||||||
For the periods ended September 30, | 2009 | 2008 | 2009 | 2008 | ||||||||||||
Directors Stock Compensation Plan |
$ | 48 | $ | 40 | $ | 143 | $ | 132 | ||||||||
Performance Incentive Plan |
264 | 104 | 754 | 489 | ||||||||||||
Total compensation expense |
312 | 144 | 897 | 621 | ||||||||||||
Less: tax benefit |
125 | 57 | 359 | 247 | ||||||||||||
Share-Based Compensation amounts included in net income |
$ | 187 | $ | 87 | $ | 538 | $ | 374 | ||||||||
Directors Stock Compensation Plan |
Shares granted under the DSCP are issued in advance of the directors service period and are
fully vested as of the date of the grant. The Company records a prepaid expense of the shares
issued and amortizes the expense equally over a service period of one year. In May 2009, 6,500
shares were granted to the directors of the Company. A summary of stock activity under the DSCP
for the nine months ended September 30, 2009, is presented below: |
Weighted Averagee | ||||||||
Number of Shares | Fair Value | |||||||
Outstanding December 31, 2008 |
| |||||||
Granted |
6,500 | $ | 29.76 | |||||
Vested |
6,500 | $ | 29.76 | |||||
Forfeited |
| | ||||||
Expired |
| | ||||||
Outstanding September 30, 2009 |
| |||||||
At September 30, 2009, there was $113,000 of unrecognized compensation expense related to
the DSCP awards that is expected to be recognized over the remaining seven months of the
directors service period ending April 30, 2010. |
Performance Incentive Plan |
In January 2009, the Companys Board of Directors granted 28,875 share-based awards under the
PIP. The table below presents the summary of the stock activity for the PIP for the nine months
ended September 30, 2009: |
Weighted Average | ||||||||
Number of Shares | Fair Value | |||||||
Outstanding December 31, 2008 |
94,200 | $ | 27.71 | |||||
Granted |
28,875 | $ | 29.19 | |||||
Vested |
| | ||||||
Forfeited |
| | ||||||
Expired |
| | ||||||
Outstanding September 30, 2009 |
123,075 | $ | 28.15 | |||||
The shares granted in January 2009 are multi-year awards that will vest at the end of the
three-year service period, or December 31, 2011. These awards are based upon the achievement of
long-term goals, development and success of the Company, 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 the Companys common stock on the date of the grant. For
the market-based conditions, the Company used the Monte-Carlo pricing model to estimate the fair
value of each market-based award granted. |
At September 30, 2009, the aggregate intrinsic value of the PIP awards was $1.9 million. |
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9. | Derivative Instruments |
The Company uses derivative and non-derivative contracts to engage in trading activities and
manage the risks related to obtaining adequate supplies and the price fluctuations of natural
gas and propane. The Companys 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. The
Companys 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 September 30, 2009, the
Companys natural gas and propane distribution operations did not have any outstanding
derivative contracts. |
Xeron, the Companys propane wholesale and marketing subsidiary, 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 Companys trading contracts are recorded at fair value, net of future servicing
costs, and the changes in fair value of those contracts are recognized as gains or losses in the
statement of income in the period of change. As of September 30, 2009, the Company had the
following outstanding trading contracts: |
Quantity in | Estimated Market | Weighted Average | ||||||||||
At September 30, 2009 | Gallons | Prices | Contract Prices | |||||||||
Forward Contracts |
||||||||||||
Sale |
26,098,800 | $ | 0.6900 $0.9950 | $ | 0.8962 | |||||||
Purchase |
26,590,200 | $ | 0.6650 $0.9975 | $ | 0.8946 |
The following tables present information about the fair value and related gains and losses
of the Companys derivative contracts. The Company did not have any derivative contracts with a
credit-risk-related contingency. |
Fair values of the derivative contracts recorded in the Balance Sheet as of September 30, 2009
and December 31, 2008, are the following: |
Asset Derivatives | ||||||||||||
Fair Value | ||||||||||||
(in Thousands) | Balance Sheet Location | September 30, 2009 | December 31, 2008 | |||||||||
Derivatives not designated as fair value hedges: | ||||||||||||
Forward contracts |
Mark-to-market energy assets | $ | 1,532 | $ | 4,482 | |||||||
Total asset derivatives |
$ | 1,532 | $ | 4,482 | ||||||||
Liability Derivatives | ||||||||||||
Fair Value | ||||||||||||
(in Thousands) | Balance Sheet Location | September 30, 2009 | December 31, 2008 | |||||||||
Derivatives designated as fair value hedges: | ||||||||||||
Propane swap agreement (1) |
Other current liabilities | $ | | $ | 105 | |||||||
Derivatives not designated as fair value hedges: | ||||||||||||
Forward contracts |
Mark-to-market energy liabilities | $ | 1,484 | $ | 3,052 | |||||||
Total liability derivatives |
$ | 1,484 | $ | 3,157 | ||||||||
(1) | The Companys propane distribution operation entered into a propane swap agreement to protect the Company from the impact
that wholesale propane price increases would have on the Pro-Cap (propane price cap) Plan that was offered to customers.
The Company terminated this swap agreement in January 2009. |
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The effects of gains and losses from derivative instruments on the Statement of Income for the three
and nine months ended September 30, 2009 and 2008, are the following:
Amount of Gain (Loss) on Derivatives: | ||||||||||||||||||||
Location of Gain | Three months ended September 30, | Nine months ended September 30, | ||||||||||||||||||
(in Thousands) | (Loss) on Derivatives | 2009 | 2008 | 2009 | 2008 | |||||||||||||||
Derivatives designated as fair value hedges: |
||||||||||||||||||||
Propane swap agreement (1) |
Cost of Sales | $ | | $ | 475 | $ | (42 | ) | $ | 475 | ||||||||||
Derivatives not designated as fair value hedges: |
||||||||||||||||||||
Unrealized gains (losses) on forward contracts |
Revenue | $ | (246 | ) | $ | 84 | $ | (1,382 | ) | $ | 548 | |||||||||
Total |
$ | (246 | ) | $ | 559 | $ | (1,424 | ) | $ | 1,023 | ||||||||||
(1) | The Companys propane distribution operation entered into a
propane swap agreement to protect the Company from the impact that wholesale
propane price increases would have on the Pro-Cap (propane price cap) Plan
that was offered to customers. The Company terminated this swap agreement in
January 2009. |
The effects of trading activities on the Statement of Income for the three and nine months ended
September 30, 2009 and 2008, are the following: |
Amount of Trading Revenue: | ||||||||||||||||||||
Location in the | Three months ended September 30, | Nine months ended September 30, | ||||||||||||||||||
(in Thousands) | Statement of Income | 2009 | 2008 | 2009 | 2008 | |||||||||||||||
Realized gains on forward contracts |
Revenue | $ | 915 | $ | 678 | $ | 2,984 | $ | 1,714 | |||||||||||
Changes in mark-to-market energy assets |
Revenue | (246 | ) | 84 | (1,382 | ) | 548 | |||||||||||||
Total |
$ | 669 | $ | 762 | $ | 1,602 | $ | 2,262 | ||||||||||||
10. | Fair Value of Financial Instruments |
FASB ASC 820, Fair Value Measurements and Disclosures, 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: |
Level 1: Unadjusted, quoted prices in active markets that are accessible at the measurement
date for identical, unrestricted assets or liabilities;
Level 2: Quoted prices in markets that are not active, or inputs which are observable,
either directly or indirectly, for substantially the full term of the asset or liability;
and
Level 3: Prices or valuation techniques, which require inputs that are both significant to
the fair value measurement and unobservable (i.e. supported by little or no market
activity).
- 20 -
Table of Contents
The following table summarizes the Companys 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 September 30, 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 |
$ | 1,834 | $ | 1,834 | ||||||||||||
Mark-to market energy assets |
$ | 1,532 | | $ | 1,532 | | ||||||||||
Liabilities: |
||||||||||||||||
Mark-to-market energy liabilities |
$ | 1,484 | | $ | 1,484 | |
The following table summarizes the Companys 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, 2008: |
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 |
$ | 1,601 | $ | 1,601 | | | ||||||||||
Mark-to market energy assets |
$ | 4,482 | | $ | 4,482 | | ||||||||||
Liabilities: |
||||||||||||||||
Mark-to market energy liabilities |
$ | 3,052 | | $ | 3,052 | | ||||||||||
Propane swap agreement |
$ | 105 | | $ | 105 | |
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The following valuation techniques were used to measure fair value assets in the tables above
on a recurring basis as of September 30, 2009, and December 31, 2008:
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 from OTC markets for similar assets and liabilities.
Propane swap agreement The fair value of the propane price swap agreement is valued using
market transactions for similar assets and liabilities from OTC markets.
At September 30, 2009, there were no non-financial assets or liabilities required to be reported
at fair value. The Company reviews its 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 September 30, 2009, long-term debt, which includes the current maturities of long-term debt,
had a carrying value of $93.0 million, compared to a fair value of $96.0 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. |
Item 2. | Managements Discussion and Analysis of Financial Condition and Results of Operations |
Managements Discussion and Analysis of Financial Condition and Results of Operations is designed
to provide a reader of the financial statements with a narrative report on the Companys financial
condition, results of operations and liquidity. This discussion and analysis should be read in
conjunction with the attached unaudited condensed consolidated financial statements and notes
thereto and Chesapeakes Annual Report on Form 10-K for the year ended December 31, 2008, including
the audited consolidated financial statements and notes contained in the Annual Report on Form
10-K.
Safe Harbor for Forward-Looking Statements
The Company has made statements in this Quarterly Report on Form 10-Q that are considered to be
forward-looking statements within the meaning of the Private Securities Litigation Reform Act of
1995. These statements are not matters of historical fact and are typically identified by words
such as, but not limited to, believes, expects, intends, plans, and similar expressions, or
future or conditional verbs such as may, will, should, would, and could. These statements
relate to matters such as customer growth, changes in revenues or gross margins, capital
expenditures, environmental remediation costs, regulatory trends and decisions, market risks
associated with our propane operations, the competitive position of the Company, mergers,
inflation, and other matters. It is important to understand that these forward-looking statements
are not guarantees; rather, they are subject to certain risks, uncertainties and other important
factors that could cause actual results to differ materially from those in the forward-looking
statements. Such factors include, but are not limited to:
| the weather or temperature sensitivity of the natural gas and propane businesses; |
||
| the effects of spot, forward, futures market prices, and the Companys
use of derivative instruments on the Companys distribution, wholesale
marketing and energy trading businesses; |
- 22 -
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| the amount and availability of natural gas and propane supplies; |
||
| access to interstate pipelines transportation and storage capacity
and the construction of new facilities to support future growth; |
||
| the effects of natural gas and propane commodity price changes on the
operating costs and competitive positions of our natural gas and
propane distribution operations; |
||
| the impact that declining propane prices may have on the valuation of our propane inventory; |
||
| third-party competition for the Companys unregulated and regulated businesses; |
||
| changes in federal, state or local regulation and tax requirements, including deregulation; |
||
| changes in technology affecting the Companys advanced information services segment; |
||
| changes in credit risk and credit requirements affecting the Companys energy marketing subsidiaries; |
||
| the effects of accounting changes and new accounting pronouncements; |
||
| changes in benefit plan assumptions, return on plan assets, and funding requirements; |
||
| cost of compliance with environmental regulations or the remediation of environmental damage; |
||
| the effects of general economic conditions, including interest rates, on the Company and its customers; |
||
| the impact of the volatility in the financial and credit markets on the Companys ability to access credit; |
||
| the ability of the Companys new and planned facilities and acquisitions to generate expected revenues; |
||
| the ability of the Company to construct facilities at or below estimated costs; |
||
| the Companys ability to obtain the rate relief and cost recovery
requested from utility regulators and the timing of the requested
regulatory actions; |
||
| the Companys ability to obtain necessary approvals and permits from regulatory agencies on a timely basis; |
||
| the impact of inflation on the results of operations, cash flows,
financial position and on the Companys planned capital expenditures; |
||
| inability to access the financial markets to a degree that may impair future growth; and |
||
| operating and litigation risks that may not be covered by insurance. |
Certain of the forward-looking statements in this report relate to the merger with FPU and include
statements regarding the tax treatment of the proposed merger, the benefits of the proposed merger
and the expectation that earnings will be neutral or slightly accretive in 2010 and meaningfully
accretive in 2011, and certain merger-related costs will be allowed to be recovered through rates.
There are a number of risks and uncertainties that could cause actual results to differ materially
from the forward-looking statements included in this report. These risks and uncertainties include
the following: problems which may arise in successfully integrating the businesses of the companies
and may result in the combined company not operating as effectively and efficiently as expected;
the combined company may be unable to achieve cost-cutting synergies, or it may take longer than
expected to achieve those synergies; the transaction may involve unexpected costs or unexpected
liabilities, or the accounting for the transaction may be different from the Companys
expectations; the natural gas and electric industries may be subject to future regulatory or
legislative actions that could adversely affect the combined company; and the combined company may
be adversely affected by other economic, business, and/or competitive factors.
- 23 -
Table of Contents
Overview
Chesapeake is a diversified utility company engaged, directly or through subsidiaries, in natural
gas distribution, transmission and marketing, propane distribution and wholesale marketing,
advanced information services and other related businesses. For additional information regarding
segments, refer to Note 5, Segment Information, of the Notes to the condensed consolidated
financial statements in this Quarterly Report on Form 10-Q.
The Companys strategy is focused on growing earnings from a stable utility foundation and
investing in related businesses and services that provide opportunities for returns greater than
traditional utility returns. The key elements of this strategy include:
| executing a capital investment program in pursuit of organic growth opportunities that
generate returns equal to or greater than our cost of capital; |
| expanding the natural gas distribution and transmission business through expansion into
new geographic areas in our current and potentially new service territories; |
| expanding the propane distribution business in existing and new markets by leveraging
our community gas system services and our bulk delivery capabilities; |
| utilizing the Companys expertise across our various businesses to improve overall
performance; |
| enhancing marketing channels to attract new customers; |
| providing reliable and responsive service to retain existing customers; |
| maintaining a capital structure that enables the Company to access capital as needed;
and |
| maintaining a consistent and competitive dividend for shareholders. |
Due to the seasonality of the Companys business, results for interim periods are not necessarily
indicative of results for the entire fiscal year. Revenue and earnings are typically greater during
the Companys first and fourth quarters, when consumption of natural gas and propane is highest due
to colder temperatures.
Merger with Florida Public Utilities Company
On April 20, 2009, Chesapeake and Florida Public Utilities Company (FPU) announced a definitive
merger agreement, pursuant to which FPU would merge with a wholly-owned subsidiary of Chesapeake,
with FPU being the surviving corporation and operating as a wholly-owned subsidiary of Chesapeake
after the merger. On October 22, 2009, shareholders of both Chesapeake and FPU approved the
merger, which became effective on October 28, 2009 and each outstanding share of FPU common stock
was converted into 0.405 share of Chesapeakes common stock. At closing, FPU had 6,140,592 common
shares outstanding and Chesapeakes common stock was valued at $30.42 per share, which resulted in
total consideration paid by Chesapeake of approximately $75.7 million. The total consideration is
based upon the closing price of Chesapeakes common stock on October 27, 2009, the last trading day
prior to the effective date of the merger. Immediately after the merger, Chesapeakes stockholders
owned approximately 73.5 percent of the combined company, and FPUs stockholders owned
approximately 26.5 percent of the combined company.
On September 29, 2009, a putative class action lawsuit, which had been filed on May 8, 2009 in Palm
Beach County, Florida, challenging the merger, purportedly on behalf of the shareholders of FPU,
against FPU, each member of FPUs board of directors and Chesapeake was dismissed without
prejudice.
The merger is intended to qualify as a reorganization within the meaning of Section 368(a) of the
Internal Revenue Code of 1986, as amended, and will be accounted for under the acquisition method
of GAAP, with Chesapeake being treated as the acquirer. Under this method, the assets acquired and
liabilities assumed are recorded at their respective fair values and added to those of Chesapeake.
Chesapeake is in the process of finalizing its evaluation of the tangible and intangible assets
acquired and liabilities assumed, as well as the initial purchase price allocation as of the
acquisition date, including the determination of any resulting goodwill. Therefore, this
information cannot be provided at this time.
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Table of Contents
In connection with the merger, Chesapeake has incurred $1.9 million in transaction-related costs
during the nine months ended September 30, 2009. Chesapeake has begun the process of seeking
regulatory approval to defer a
portion of these costs related to regulated operations for future rate recovery. Based on
precedents established by the Florida PSC in previous business combinations involving natural gas
utilities in Florida, Chesapeake determined that future rate recovery of the acquisition-related
transaction costs for regulated operations is probable and deferred a portion of these costs as a
regulatory asset as of September 30, 2009. This regulatory asset includes deferrals of
merger-related costs incurred during the first and second quarters of 2009, respectively, that were
previously accounted for as expenses. The reversal of these amounts is presented as a credit to
Chesapeakes operating expenses for the three months ended September 30, 2009. Future regulatory
developments may require Chesapeake to re-assess the probability of future rate recovery with
regard to the costs deferred as a regulatory asset.
FPU distributes natural gas, propane and electricity to residential, commercial and industrial
customers in Florida. FPU also sells merchandise and other service-related products as a
complement to its natural gas and propane operations. FPU serves approximately 96,000 customers
and employs 348 people. The merger will create a combined energy company serving approximately
200,000 customers (117,000 natural gas, 48,000 propane and 31,000 electric customers) in the
Mid-Atlantic and Florida markets with assets totaling $595 million. The Company and FPU recognized
$291.4 million and $168.5 million in revenues, respectively, and $13.6 million and $3.5 million in
net income, respectively, for 2008. Chesapeakes management expects the transaction to be earnings
neutral or slightly accretive in 2010 and meaningfully accretive in 2011.
Results of Operations for the Quarter Ended September 30, 2009
The following discussions on operating income and segment results for the three months ended
September 30, 2009 and 2008, include use of the term gross margin, which is determined by
deducting the cost of sales from operating revenue. Cost of sales includes the purchased gas cost
for natural gas and propane and the cost of labor spent on direct revenue-producing activities.
Gross margin should not be considered an alternative to operating income or net income, which are
determined in accordance with Generally Accepted Accounting Principles (GAAP). Chesapeake
believes that gross margin, although a non-GAAP measure, is useful and meaningful to investors as a
basis for making investment decisions. It provides investors with information that demonstrates the
profitability achieved by Chesapeake under its allowed rates for regulated operations and under its
competitive pricing structure for non-regulated segments. Chesapeakes management uses gross margin
in measuring the performance of its business units and has historically analyzed and reported gross
margin information publicly. Other companies may calculate gross margin in a different manner. In
addition, certain information is presented, which excludes for comparison purposes, all
merger-related transaction costs incurred in connection with the FPU merger. Although the non-GAAP
measures are not intended to replace the GAAP measures for evaluation of Chesapeakes performance,
Chesapeake believes that the portions of the presentation which exclude merger-related transaction
costs are helpful on a comparative basis for investors to understand Chesapeakes performance.
- 25 -
Table of Contents
Consolidated Overview
The Companys net income for the quarter ended September 30, 2009 was $308,000, or $0.04 per share
(diluted). This represents an increase of $506,000, compared to a net loss of $198,000, or $0.03
per share (diluted), reported in the same period in 2008. The Companys Delmarva natural gas
distribution and propane distribution operations typically experience seasonal losses or reduced
earnings during the third quarter, because customers do not require natural gas or propane for
heating purposes during the summer months. Net income for the quarter ended September 30, 2009,
included the effect of deferring as a regulatory asset certain merger-related transaction costs,
which the Company will seek to recover in subsequent rate proceedings. Absent the effects of the
merger-related costs and related income taxes, the Company would have generated net income of
$78,000, or $0.01 per share (diluted), for the quarter ended September 30, 2009.
For the Three Months Ended September 30, | 2009 | 2008 | Change | |||||||||
(in Thousands) | ||||||||||||
Operating Income (Loss): |
||||||||||||
Natural Gas |
$ | 3,181 | $ | 2,938 | $ | 243 | ||||||
Propane |
(1,570 | ) | (2,135 | ) | 565 | |||||||
Advanced Information Services |
(103 | ) | 277 | (380 | ) | |||||||
Other & eliminations |
749 | 90 | 659 | |||||||||
Operating Income |
2,257 | 1,170 | 1,087 | |||||||||
Other Loss, Net of Other Income |
(26 | ) | (91 | ) | 65 | |||||||
Interest Charges |
1,540 | 1,488 | 52 | |||||||||
Income Taxes (Benefit) |
383 | (211 | ) | 594 | ||||||||
Net Income (Loss) |
$ | 308 | $ | (198 | ) | $ | 506 | |||||
The Companys period-over-period operating results reflect an increase of $1.3 million, or
eight percent, in gross margin and an increase of other operating expenses of $208,000. Customer
growth in the Delmarva natural gas distribution operations and new transportation services placed
into service by the natural gas transmission operation positively impacted gross margin during the
third quarter of 2009. The Delmarva natural gas distribution operations contributed to the gross
margin increase from the implementation of new rate structures in October 2008, which allows
collection of a greater portion of revenue through non-volume-based charges. Absent the costs
related to inventory valuation adjustments, including a mark-to-market loss on a price swap
agreement, by the propane distribution operations totaling $975,000 in the third quarter of 2008,
which did not recur in the same period in 2009, also contributed to the increase in gross margin.
These increases were partially offset by the advanced information services segments gross margin
decrease, a result of current economic conditions in which information technology spending has
broadly declined. The Company has taken actions in the first and third quarters to reduce costs
within the advanced information services segment to offset the decline in revenues.
The increase of $208,000 in other operating expenses includes the effects of a credit of $939,000
associated with the deferral of previously expensed merger-related costs and additional
merger-related costs, of $265,000 in the third quarter of 2009, which are not subject to recovery
through rates. Exclusive of the net effects of merger-related transaction costs, the increase in
other operating expenses was $883,000, which is due to: (i) increased compensation costs of
$608,000, attributable primarily to payroll adjustments that commenced on January 1, 2009, pursuant
to the results of a salary survey conducted during the fourth quarter of 2008; (ii) increased
accruals for incentive compensation due to improved non-merger related operating results; and (iii)
increased pension costs of $195,000 due to the decline in the value of pension plan assets in
2008.
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Natural Gas
The natural gas segment reported operating income of $3.2 million for the third quarter of 2009, an
increase of $243,000, or eight percent, compared to operating income of $2.9 million reported in
the third quarter of 2008.
For the Three Months Ended September 30, | 2009 | 2008 | Change | |||||||||
(in Thousands) | ||||||||||||
Revenue |
$ | 23,091 | $ | 37,359 | $ | (14,268 | ) | |||||
Cost of sales |
9,545 | 24,867 | (15,322 | ) | ||||||||
Gross margin |
13,546 | 12,492 | 1,054 | |||||||||
Operations & maintenance |
7,170 | 6,599 | 571 | |||||||||
Depreciation & amortization |
1,841 | 1,683 | 158 | |||||||||
Other taxes |
1,354 | 1,272 | 82 | |||||||||
Other operating expenses |
10,365 | 9,554 | 811 | |||||||||
Operating Income |
$ | 3,181 | $ | 2,938 | $ | 243 | ||||||
Statistical Data Delmarva Peninsula |
||||||||||||
Heating degree-days (HDD): |
||||||||||||
Actual |
80 | 69 | 11 | |||||||||
10-year average (normal) |
58 | 55 | 3 | |||||||||
Estimated gross margin per HDD |
$ | 1,937 | $ | 1,937 | | |||||||
Per residential customer added: |
||||||||||||
Estimated gross margin |
$ | 375 | $ | 375 | | |||||||
Estimated other operating expenses |
$ | 103 | $ | 103 | | |||||||
Residential Customer Information |
||||||||||||
Average number of customers: |
||||||||||||
Delmarva |
45,871 | 44,726 | 1,145 | |||||||||
Florida |
13,059 | 13,221 | (162 | ) | ||||||||
Total |
58,930 | 57,947 | 983 | |||||||||
Operating income for the natural gas segment increased by $243,000 as the result of a gross
margin increase of $1.1 million, or eight percent, which was partially offset by increased other
operating expenses of $811,000, or eight percent, for the third quarter in 2009 compared to the
same period in 2008.
Gross Margin
Gross margin increases of $707,000 for the natural gas transmission operation and $552,000 for the
natural gas distribution operations were partially offset by decreased gross margin of $205,000 for
the natural gas marketing operations.
The natural gas transmission operation achieved gross margin growth of $707,000 in the third
quarter of 2009, an increase of 14 percent over the same period in 2008, due primarily to the
implementation of the following new transportation services:
| New long-term transportation services, implemented by ESNG in November 2008, which
provided for an additional 5,650 Dts per day, generated $247,000 of gross margin in the
third quarter of 2009. These new services are expected to generate approximately $988,000
of annualized gross margin. |
| New transportation services provided to an industrial customer for the period of
February 6, 2009 through October 31, 2009, provided for an additional 7,200 Dts per day.
For the third quarter of 2009, this service provided $195,000 of additional gross margin
and is expected to generate approximately $573,000 of gross margin for 2009. In addition,
ESNG entered into two other firm transportation service agreements with this customer for
the period of (i) November 1, 2009 through October 31, 2012, for 10,000 Dts per day, and
(ii) November 1, 2009 through November 30, 2009, for 3,131 Dts per day. Although there was
no impact from these contracts in the third quarter of 2009, they are expected to increase
gross margin by approximately $209,000 in the fourth quarter of 2009 and by $1.1 million
in 2010. |
| ESNG changed its rates effective April 2009 to recover specified project costs in
accordance with the terms of precedent agreements with certain customers. These rates
generated $129,000 in gross margin for the third quarter of 2009 and will contribute
$387,000 of annualized gross margin in 2009 and $516,000 annually thereafter for a period
of 20 years. |
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Table of Contents
Although the following had no impact in the third quarter of 2009, they could affect future results
for the natural gas transmission operation:
| The remaining facilities included in ESNGs most recent multi-year system expansion to
be placed into service in November 2009, and will provide for 7,200 Dts of firm service
capacity per day. For the years 2009 and 2010, these facilities are expected to contribute
$169,000 and $1.0 million, respectively, to gross margin. |
| ESNG received notice from a customer of its intention not to renew two firm
transportation service contracts, one expiring in October 2009 and the other in March 2010.
If these contracts are not renewed, or equivalent firm service capacity is not subscribed
to by other customers, gross margin could be reduced by approximately $56,000 in 2009 and
approximately $427,000 in 2010. ESNG also received notice from a smaller customer that it
does not intend to renew its firm transportation service contract, which expires in April
2010. This contract provides for annualized gross margin of approximately $54,000. |
The natural gas distribution operations for the Delmarva Peninsula generated an increase in gross
margin of $682,000 for the third quarter of 2009, compared to the same period in 2008. The new
rate structure in Delaware, implemented in October of 2008, contributed $323,000 of the increased
gross margin. This new rate structure allows a greater portion of the revenue requirements to be
collected through non-volume-based charges and reduces volatility in gross margin based on weather
changes. The new rate structure also allows collection of miscellaneous service fees of $74,000,
which, although not representing additional revenue, had previously been offset against other
operating expenses. Despite the continued slowdown in the new housing market and industrial growth
in the region, the Delmarva natural gas distribution operations experienced growth in residential,
commercial, and industrial customers, which contributed $300,000 to the increased gross margin. The
aforementioned increases to gross margin overcame the negative impact of decreased interruptible
sales to industrial customers, due to a reduction in the price of alternative fuels, which reduced
gross margin by $133,000.
The Florida natural gas distribution operation experienced a decrease in gross margin of $130,000
in the third quarter of 2009, due primarily to reduced customer consumption and loss of three
industrial customers, one in October 2008 and two in the third quarter of 2009, all attributable to
adverse economic conditions in the region. On July 14, 2009, the division filed with the Florida
PSC a petition for a rate increase of approximately $3.0 million, which represents a twenty-five
percent base rate increase on average for the Florida operations customers. In the same filing,
the Company sought an increase of approximately $418,000 in its interim rates, which was approved
by the Florida PSC on August 18, 2009. The Company began billing the increased interim rates,
subject to refund, on September 17, 2009.
The Companys natural gas marketing operation experienced a decrease in gross margin of $205,000
for the third quarter of 2009, as prior years gross margin included favorable imbalance
resolutions with interstate pipelines that did not recur during the third quarter of 2009, and as a
result of a four-percent decrease in customer consumption in the current quarter.
Other Operating Expenses
The factors contributing to the increase in other operating expenses by $811,000 for the natural
gas segment are as follows:
| Salaries and incentive compensation increased by $370,000, due primarily to compensation
adjustments for non-executive employees that were made effective January 1, 2009, pursuant
to the results of a compensation survey completed in the fourth quarter of 2008, and an
increase in accruals for incentive compensation as a result of improved operating results.
Benefit costs increased by $149,000, due primarily to higher pension costs resulting from
the decline in the value of pension assets in 2008 and other benefit costs relating to
increased payroll costs. |
| Partially offsetting the increases in operating expenses was a decrease of $108,000 in
allowance for doubtful accounts attributable to lower energy prices in the current quarter. |
| Depreciation expense, asset removal costs and property taxes, collectively, increased by
approximately $197,000 as a result of the Companys continued capital investments to
support customer growth. |
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Table of Contents
Propane
The propane segment experienced a seasonal operating loss of $1.6 million for the third quarter of
2009, a reduction of $565,000, or twenty-six percent, compared to an operating loss of $2.1 million
in the third quarter of 2008.
For the Three Months Ended September 30, | 2009 | 2008 | Change | |||||||||
(in Thousands) | ||||||||||||
Revenue |
$ | 6,198 | $ | 8,759 | $ | (2,561 | ) | |||||
Cost of sales |
3,416 | 6,642 | (3,226 | ) | ||||||||
Gross margin |
2,782 | 2,117 | 665 | |||||||||
Operations & maintenance |
3,619 | 3,573 | 46 | |||||||||
Depreciation & amortization |
521 | 509 | 12 | |||||||||
Other taxes |
212 | 170 | 42 | |||||||||
Other operating expenses |
4,352 | 4,252 | 100 | |||||||||
Operating Loss |
$ | (1,570 | ) | $ | (2,135 | ) | $ | 565 | ||||
Statistical Data Delmarva Peninsula |
||||||||||||
Heating degree-days (HDD): |
||||||||||||
Actual |
80 | 69 | 11 | |||||||||
10-year average (normal) |
58 | 55 | 3 | |||||||||
Estimated gross margin per HDD |
$ | 2,465 | $ | 2,465 | |
The propane segment experienced a decreased operating loss, which resulted from an increase of
$665,000, or thirty-one percent, in gross margin, partially offset by increased other operating
expenses of $100,000.
Gross Margin
A gross margin increase of $779,000 for the Delmarva propane distribution operations was slightly
offset by reduced gross margin of $21,000 for the Florida propane distribution operations and
$93,000 for the propane wholesale and marketing operation.
The Delmarva propane distribution operations increase in gross margin of $779,000 resulted
primarily from the absence of $975,000 in inventory valuation adjustments, including a
mark-to-market loss on a price swap agreement, incurred in the third quarter of 2008, as a result
of the sharp decline in propane prices, which did not recur in the third quarter of 2009.
Gross margin for the Florida propane distribution operation decreased by $21,000 in the third
quarter of 2009, compared to the same period in the prior year, as a decline in residential and
non-residential consumption was partially offset by an increase in margin per gallon.
The propane wholesale marketing operation experienced a decrease in gross margin of $93,000 in the
third quarter of 2009. This operation typically capitalizes on price volatility in the wholesale
propane market by selling at prices above cost and effectively managing the larger spreads between
market (spot) prices and forward prices. Overall lack of volatility in wholesale propane prices
during the third quarter of 2009, compared to the same period in 2008, reduced opportunities and
decreased trading volumes by thirteen percent.
- 29 -
Table of Contents
Other Operating Expenses
Total other operating expenses for the propane segment increased by $100,000 for the quarter ended
September 30, 2009, compared to the same period in 2008, due primarily to: (i) higher payroll
costs of $83,000 reflecting annual salary increases, (ii) an increase of $69,000 in benefit costs
resulting from the significant decline in the value of pension plan assets during 2008, and (iii)
additional costs of approximately $21,000 to maintain propane tanks in compliance with United
States Department of Transportation standards during the current period. These increases were
offset by lower vehicle-related costs of $101,000 due primarily to a decrease in the cost of fuel.
Advanced Information Services
The advanced information services business experienced an operating loss of $103,000 for the
quarter ended September 30, 2009, a decrease of $380,000 compared to operating income of $277,000
achieved during the same period in 2008.
For the Three Months Ended September 30, | 2009 | 2008 | Change | |||||||||
(in Thousands) | ||||||||||||
Revenue |
$ | 2,647 | $ | 3,742 | $ | (1,095 | ) | |||||
Cost of sales |
1,454 | 2,142 | (688 | ) | ||||||||
Gross margin |
1,193 | 1,600 | (407 | ) | ||||||||
Operations & maintenance |
1,111 | 1,121 | (10 | ) | ||||||||
Depreciation & amortization |
47 | 48 | (1 | ) | ||||||||
Other taxes |
138 | 154 | (16 | ) | ||||||||
Other operating expenses |
1,296 | 1,323 | (27 | ) | ||||||||
Operating Income (Loss) |
$ | (103 | ) | $ | 277 | $ | (380 | ) | ||||
The decrease in operating income is the result of lower gross margin of $407,000, or
twenty-five percent, partially offset by lower other operating expenses of $27,000.
Gross Margin
The period-over-period decrease in gross margin is due primarily to a decrease of $980,000 in
consulting revenues, as the number of billable hours declined by twenty-seven percent in the
current quarter compared to the same period last year. The reduction in the number of billable
hours is a result of current economic conditions in which information technology spending has
broadly declined.
Other Operating Expenses
Other operating expenses decreased by $27,000, or two percent, to $1.3 million in the third quarter
of 2009. The Company implemented cost-containment actions, including layoffs and compensation
adjustments, in March, September and October to reduce costs to offset the decline in revenues.
The September cost-containment actions resulted in a one-time charge of $38,000 in the third
quarter of 2009. Other operating expenses for the third quarter of 2008 reflected a reversal of
accruals for incentive compensation of $179,000, which resulted in lower other operating expenses
during that period. Absent these cost adjustments, other operating expenses would have decreased
by $244,000 in the third quarter of 2009. The aforementioned cost-containment actions, net of
severance packages, are expected to further reduce operating costs by $392,000 in the fourth
quarter of 2009 and return the advanced information segment to an operating profit.
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Table of Contents
Other and Eliminations
The other and eliminations segment, which primarily reflects the revenues and expenses of
subsidiaries that own real estate leased to other Company subsidiaries and the merger-related
costs, which have not been deferred and are not subject to future rate recovery, experienced an
operating income of approximately $749,000 for the third quarter of 2009, an increase of $659,000
compared to operating income of $90,000 for the same period in 2008. The operating income
experienced in the third quarter of 2009 was due primarily to the aforementioned net effects of the
merger-related costs.
For the Three Months Ended September 30, | 2009 | 2008 | Change | |||||||||
(in Thousands) | ||||||||||||
Revenue |
$ | (178 | ) | $ | (162 | ) | $ | (16 | ) | |||
Cost of sales |
1 | | 1 | |||||||||
Gross margin |
(179 | ) | (162 | ) | (17 | ) | ||||||
Operations & maintenance |
(299 | ) | (296 | ) | (3 | ) | ||||||
Non-recoverable transaction and other legal costs |
(675 | ) | | (675 | ) | |||||||
Depreciation & amortization |
28 | 27 | 1 | |||||||||
Other taxes |
18 | 17 | 1 | |||||||||
Other operating expenses |
(928 | ) | (252 | ) | (676 | ) | ||||||
Operating Income |
$ | 749 | $ | 90 | $ | 659 | ||||||
Note: | Eliminations are entries required to eliminate activities between business segments from the consolidated results. |
Interest Expense
Total interest expense for the third quarter of 2009 increased by approximately $52,000, or three
percent, compared to the same period in 2008. The increase in the interest expense is attributable
primarily to the following:
| Interest on long-term debt increased by $323,000 in the third quarter of 2009, compared
to the same period in 2008, as the Company increased its average long-term debt balance by
$23.1 million. The Companys weighted average interest rate decreased to 6.36 percent
during the third quarter of 2009, compared to 6.61 percent for the same period in 2008. The
change in the average long-term debt balance and weighted average interest rate is a result
of the placement of $30.0 million of 5.93 percent Unsecured Senior Notes in October 2008. |
| Interest on short-term borrowings decreased by $260,000 in the third quarter of 2009,
compared to the same period in 2008, based upon a decrease of $38.5 million in the
Companys average short-term
borrowing balance partially offset with a higher weighted average interest rate. The
Companys average short-term borrowing during the third quarter of 2009 was $5.1 million,
with a weighted average interest rate of 3.01 percent, compared to $43.5 million, with a
weighted average interest rate of 2.69 percent, for the same period in 2008. |
Income Taxes
The Company recorded an income tax expense of $383,000 for the three months ended September 30,
2009, compared to an income tax benefit of $211,000 for the three months ended September 30, 2008.
Exclusive of the tax effects of the merger-related costs, a portion of which are non-deductible for
income tax purposes, resulted in a tax benefit of $63,000 for the three months ended September 30,
2009. The decreased income tax benefit is primarily a function of higher earnings for the period.
- 31 -
Table of Contents
Results of Operations for the Nine Months Ended September 30, 2009
The following discussions on operating income and segment results for the nine months ended
September 30, 2009 and 2008, include use of the term gross margin. Gross margin is determined by
deducting the cost of sales from operating revenue. Cost of sales includes the purchased gas cost
for natural gas and propane and the cost of labor spent on direct revenue-producing activities.
Gross margin should not be considered an alternative to operating income or net income, which are
determined in accordance with GAAP. Chesapeake believes that gross margin, although a non-GAAP
measure, is useful and meaningful to investors as a basis for making investment decisions. It
provides investors with information that demonstrates the profitability achieved by the Company
under its allowed rates for regulated operations and under its competitive pricing structure for
non-regulated segments. Chesapeakes management uses gross margin in measuring the performance of
its business units and has historically analyzed and reported gross margin information publicly.
Other companies may calculate gross margin in a different manner. In addition, certain information
is presented, which excludes for comparison purposes, all merger-related transaction costs incurred
in connection with the FPU merger. Although the non-GAAP measures are not intended to replace the
GAAP measures for evaluation of Chesapeakes performance, Chesapeake believes that the portions of
the presentation which exclude the merger-related transaction costs are helpful on a comparative
basis for investors to understand Chesapeakes performance.
Consolidated Overview
The Companys net income for the nine months ended September 30, 2009, increased by $511,000,
compared to the same period in 2008. The Company reported net income of approximately $9.7 million,
or $1.40 per share (diluted), for the nine months ended September 30, 2009. This includes $530,000
in merger-related costs that are not subject to recovery through future rates. Net income of $9.2
million, or $1.34 per share (diluted), for the nine months ended September 30, 2008, also includes
$1.2 million in merger-related costs. Excluding the effects of merger-related costs and related
income taxes, net income for the nine months ended September 30, 2009, would have been $10.2
million, or $1.46 per share (diluted), compared to $9.9 million, or $1.44 per share (diluted), for
the same period in 2008.
For the Nine Months Ended September 30, | 2009 | 2008 | Change | |||||||||
(in Thousands) | ||||||||||||
Operating Income (Loss): |
||||||||||||
Natural Gas |
$ | 18,432 | $ | 19,034 | $ | (602 | ) | |||||
Propane |
3,354 | 957 | 2,397 | |||||||||
Advanced Information Services |
(448 | ) | 516 | (964 | ) | |||||||
Other & eliminations |
(260 | ) | (966 | ) | 706 | |||||||
Operating Income |
21,078 | 19,541 | 1,537 | |||||||||
Other Income, Net of Other Expenses |
19 | (11 | ) | 30 | ||||||||
Interest Charges |
4,755 | 4,470 | 285 | |||||||||
Income Taxes |
6,636 | 5,865 | 771 | |||||||||
Net Income |
$ | 9,706 | $ | 9,195 | $ | 511 | ||||||
The Companys period-over-period operating results reflect an increase of $5.1 million, or eight
percent, in gross margin and an increase of other operating expenses of $3.6 million, which
includes the impact of the decreased merger-related costs. Colder than normal temperatures on the
Delmarva Peninsula, customer growth in the natural gas and propane distribution operations, new
transportation services placed into service by the natural gas transmission operation, increased
retail margins by the propane distribution operations and spot sale opportunities executed by the
natural gas marketing operations all contributed to the gross margin increase. The Companys
propane distribution operations recorded $975,000 in expenses related to inventory valuation
adjustments, including a mark-to-market loss on a price swap agreement, in the third quarter of
2008, which did not recur in 2009. These positive achievements offset the gross margin impact of
lower demand and adverse market conditions faced by the advanced information services and propane
wholesale marketing operations.
Other operating expenses, exclusive of merger-related costs, increased by $4.3 million, or nine
percent, which reflects the rising costs associated with supporting growth of the Companys
businesses. Other operating expenses for the first nine months of 2009 also reflect certain
effects of the economic slowdown, including a $350,000 increase in allowance for uncollectible
accounts and $397,000 in higher pension costs attributable to declining pension plan assets in
2008. Also contributing to the increase was the reduction in depreciation expenses of $305,000
related to the Delaware rate case, in the third quarter of 2008 that did not recur in 2009.
- 32 -
Table of Contents
During 2009, the Company decided not to allocate merger-related costs to its natural gas, propane,
and advanced information services segments for the purpose of reporting their operating
profitability, because such costs are not directly attributable to their operations. Consequently,
all of the $530,000 in merger-related costs for the nine months ended September 30, 2009, that are
not subject to recovery through future rates, was allocated to the other and eliminations
segment. The Company also revised the 2008 segment information to reclassify the $1.2 million of
such costs to the other and eliminations segment ($890,000, $273,000, and $64,000 were
reclassified from natural gas, propane and advanced information services, respectively, to the
other and eliminations segment).
Natural Gas
The natural gas segment generated an operating income of $18.4 million for the first nine months of
2009, compared to $19.0 million for the corresponding period in 2008, representing a decrease of
$602,000, or three percent.
For the Nine Months Ended September 30, | 2009 | 2008 | Change | |||||||||
(in Thousands) | ||||||||||||
Revenue |
$ | 127,534 | $ | 160,166 | $ | (32,632 | ) | |||||
Cost of sales |
77,266 | 113,131 | (35,865 | ) | ||||||||
Gross margin |
50,268 | 47,035 | 3,233 | |||||||||
Operations & maintenance |
22,225 | 19,389 | 2,836 | |||||||||
Depreciation & amortization |
5,453 | 4,977 | 476 | |||||||||
Other taxes |
4,158 | 3,635 | 523 | |||||||||
Other operating expenses |
31,836 | 28,001 | 3,835 | |||||||||
Total Operating Income |
$ | 18,432 | $ | 19,034 | $ | (602 | ) | |||||
Statistical Data Delmarva Peninsula |
||||||||||||
Heating degree-days (HDD): |
||||||||||||
Actual |
3,003 | 2,772 | 231 | |||||||||
10-year average (normal) |
2,889 | 2,855 | 34 | |||||||||
Estimated gross margin per HDD |
$ | 1,937 | $ | 1,937 | | |||||||
Per residential customer added: |
||||||||||||
Estimated gross margin |
$ | 375 | $ | 375 | | |||||||
Estimated other operating expenses |
$ | 103 | $ | 103 | | |||||||
Residential Customer Information |
||||||||||||
Average number of customers: |
||||||||||||
Delmarva |
46,669 | 45,427 | 1,242 | |||||||||
Florida |
13,291 | 13,418 | (127 | ) | ||||||||
Total |
59,960 | 58,845 | 1,115 | |||||||||
Operating income for the natural gas segment decreased by $602,000 as the increase of $3.2
million, or seven percent, in gross margin was more than offset by increased other operating
expenses of $3.8 million, or fourteen percent, for the first nine months of 2009, compared to the
same period in 2008.
Gross Margin
Gross margin increased by $3.2 million for the natural gas segment for the first nine months of
2009, which was derived from increases of $1.7 million for the natural gas transmission operation,
$929,000 for the natural gas distribution operations and $627,000 for the natural gas marketing
operation.
The natural gas transmission operation achieved gross margin growth of $1.7 million, or ten
percent, for the nine months ended September 30, 2009, compared to the same period in 2008, due to
the following new transportation services on the Delmarva Peninsula and in Florida:
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Table of Contents
| New long-term transportation services implemented by ESNG in November 2008, which
provided for an additional 5,650 Dts per day, generated $743,000 of gross margin for the
nine months ended September 30, 2009. These new services are expected to generate
approximately $988,000 of annualized gross margin in 2009. |
||
| New firm transportation services provided to an industrial customer for the period of
February 6, 2009 through October 31, 2009, provided for an additional 7,200 Dts per day.
For the nine months ended September 30, 2009, this service provided $508,000 of gross
margin, and is expected to contribute $573,000 of annualized gross margin in 2009. In
addition, ESNG entered into two additional firm transportation service agreements with
this customer: (1) 10,000 Dts per day from November 1, 2009 through October 31, 2012, and
(2) 3,131 Dts per day from November 1, 2009 through November 31 2009. Although there
contracts had no gross margin impact during the nine months ended September 30, 2009, they
are expected to contribute approximately $209,000 in the fourth quarter of 2009 and $1.1
million in 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
$258,000 in gross margin for ESNG during the first nine months of 2009 and will contribute
$387,000 of annualized gross margin to ESNG in 2009 and $516,000 annually thereafter for a
period of 20 years. |
||
| During January 2009, Peninsula Pipeline Company, Inc., the Companys intra-state
pipeline subsidiary in Florida, entered into its first contract to provide natural gas
transportation service to a customer for a period of 20 years. For the first nine months
of 2009, this agreement contributed $198,000 to gross margin and is expected to contribute
$264,000 in annualized gross margin. |
Although the following developments had no impact in the first nine months of 2009, they could
affect future results for the natural gas transmission operation:
| The remaining facilities included in its most recent multi-year system expansion project
to be placed into service in November 2009, and will provide an additional 7,200 Dts of
firm service capacity per day. For the years 2009 and 2010, these facilities are expected
to contribute $169,000 and $1.0 million, respectively, to gross margin. |
||
| ESNG received notice from a customer of its intention not to renew two firm
transportation service contracts, one expiring in October 2009 and the other in March 2010.
If these contracts are not renewed, or equivalent firm service capacity is not subscribed
to by other customers, gross margin will be reduced by approximately $56,000 in 2009 and
approximately $427,000 in 2010. ESNG also received notice from a smaller customer that it
does not intend to renew its firm transportation service contract, which expires in April
2010. This contract provides for annualized gross margin of approximately $54,000. |
The natural gas distribution operations for the Delmarva Peninsula generated an increase in gross
margin of $1.2 million for the first nine months of 2009, compared to the same period in 2008. In
spite of the continued slowdown in the new housing market and industrial growth in the region, the
Delmarva natural gas distribution operations experienced growth in residential, commercial, and
industrial customers, which contributed $875,000 to the gross margin increase. The Delaware and
Maryland divisions have experienced slower customer growth in 2009 than in recent years and expect
that trend to continue in the near future. Colder weather on the Delmarva Peninsula contributed
$266,000 to the increased gross margin, as temperatures were eight percent colder in the first nine
months of 2009 compared to the same period in 2008. In addition, Delaware divisions new rate
structure allows collection of miscellaneous service fees of $260,000, which, although not
representing additional revenue, had previously been offset against other operating expenses. The
aforementioned increases to gross margin overcame the negative impact of decreased interruptible
sales to industrial customers due to a reduction in the price of alternative fuels, which reduced
gross margin by $310,000.
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The Florida natural gas distribution operation experienced a decrease in gross margin of $269,000,
in the first nine months of 2009, due primarily to reduced consumption by customers and loss of
three industrial customers, one in October 2008 and two in the third quarter of 2009, all
attributable to adverse economic conditions in the region. On July 14, 2009, the Florida natural
gas distribution operation filed with the Florida PSC a petition for a rate increase of
approximately $3.0 million, which represents a twenty-five percent base rate increase on average
for the Florida divisions customers. In the same filing, the Company sought an increase in the interim rates of
approximately $418,000, which was approved by the Florida PSC on August 18, 2009, subject to
refund, and the Company began billing customers the approved interim rates on September 17, 2009.
The Companys natural gas marketing operation experienced an increase in gross margin of $627,000
during the first nine months of 2009, as it benefited from increased spot sales. Most of the gross
margin increases from spot sales were generated from two industrial customers located on the
Delmarva Peninsula. Such sales are opportunistic and unpredictable, and their future availability
is highly dependent upon market conditions.
Other Operating Expenses
Other operating expenses for the natural gas segment increased by $3.8 million, due primarily to
the following factors:
| Depreciation expense, asset removal costs and property taxes, collectively, increased by
approximately $1.2 million as a result of the Companys continued capital investments to
support customer growth. The increased depreciation expense also reflects a $305,000
depreciation credit as a result of the Delaware negotiated rate settlement agreement in the
third quarter of 2008, of which $295,000 related to depreciation for the months of October
through December 2007. |
||
| Salaries and incentive compensation increased by $566,000, due primarily to January 1,
2009 compensation adjustments for non-executive employees, based on a compensation survey
completed in the fourth quarter of 2008, and annual salary increases, coupled with a slight
increase in the accrual for incentive compensation as a result of improved operating
results. |
||
| The allowance for uncollectible accounts in the natural gas segment increased by
$405,000 due to growth in customers and the general economic climate. |
||
| Benefit costs increased by $326,000, due primarily to higher pension costs as a result
of the decline in the value of pension assets in 2008 and other benefit costs relating to
increased payroll costs. |
||
| Increased information technology spending to improve the infrastructure and information
technology support generated increased costs of $274,000. |
||
| ESNG incurred expenses of $107,000 related to pipeline integrity projects in 2009 to
maintain compliance with various regulations. |
||
| The increases in operating expenses were partially offset by a decrease of $132,000 in
vehicle expenses due primarily to a decrease in the cost of fuel. |
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Propane
Operating income for the propane segment increased by $2.4 million, or 250 percent, to $3.4 million
for the first nine months of 2009, compared to $957,000 for the corresponding period in 2008.
For the Nine Months Ended September 30, | 2009 | 2008 | Change | |||||||||
(in Thousands) | ||||||||||||
Revenue |
$ | 41,683 | $ | 48,057 | $ | (6,374 | ) | |||||
Cost of sales |
24,379 | 33,899 | (9,520 | ) | ||||||||
Gross margin |
17,304 | 14,158 | 3,146 | |||||||||
Operations & maintenance |
11,708 | 11,030 | 678 | |||||||||
Depreciation & amortization |
1,552 | 1,511 | 41 | |||||||||
Other taxes |
690 | 660 | 30 | |||||||||
Other operating expenses |
13,950 | 13,201 | 749 | |||||||||
Total Operating Income |
$ | 3,354 | $ | 957 | $ | 2,397 | ||||||
Statistical Data Delmarva Peninsula |
||||||||||||
Heating degree-days (HDD): |
||||||||||||
Actual |
3,003 | 2,772 | 231 | |||||||||
10-year average (normal) |
2,889 | 2,855 | 34 | |||||||||
Estimated gross margin per HDD |
$ | 2,465 | $ | 2,465 | |
Operating income for the propane segment increased by $2.4 million, as the increase of $3.1
million, or 22 percent, in gross margin was partially offset by increased other operating expenses
of $749,000, or six percent, for the first nine months of 2009, compared to the same period in
2008.
Gross Margin
The gross margin increase of $3.1 million for the propane segment in the first nine months of 2009
was derived from increases of $3.6 million for the Delmarva propane distribution operations and
$225,000 for the Florida propane distribution operations, partially offset by a lower gross margin
of $660,000 for the propane wholesale and marketing operation.
The Delmarva propane distribution operations benefited from higher retail margins, increased
non-weather-related volumes sold and colder weather on the Delmarva Peninsula in 2009. The gross
margin increase of $3.6 million is attributable to the following:
| The Delmarva propane distribution operations generated $2.2 million of gross margin
from higher retail margins as a result of sustaining retail prices and lower propane
costs. The absence of inventory valuation adjustments, including a mark-to-market loss on
a price swap agreement, during the third and fourth quarters of 2008 ($975,000 and
$300,000, respectively), which did not recur in 2009, contributed to relatively low
propane inventory costs in 2009 for the Delmarva propane operations. |
||
| Non-weather-related volumes sold in the first nine months of 2009 increased by 1.0
million gallons, or seven percent, compared to the same period in 2008. This increase in
gallons sold, which provided for an increase in gross margin of approximately $639,000,
was driven primarily by the timing of propane deliveries to certain customers, increased
participation in retention programs targeted to low consumption customers, and the
addition of approximately 167 Community Gas Systems (CGS) customers served, an increase
of three percent. The Company expects the growth of its CGS operation to continue,
although at a slower pace, given the current economic climate. |
||
| Colder weather on the Delmarva Peninsula in the first nine months of 2009 increased the
volumes sold during the period by 804,000 gallons, or six percent, compared to the same
period in 2008, as temperatures were eight percent colder during this period in 2009. The
Company estimates that colder weather contributed an additional $584,000 of gross margin. |
||
| Wholesale volumes increased by 2.0 million gallons in the first nine months of 2009,
which resulted in a gross margin increase of $168,000 compared to the same period in 2008. |
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Table of Contents
The Florida propane distribution operation also benefited from higher retail margins resulting from
a sharp decline in propane costs in late 2008 and early 2009, which contributed to the $225,000
increase in gross margin in the first nine months of 2009.
The propane wholesale marketing operation experienced a decrease in gross margin of $660,000 in the
first nine months of 2009 compared to the same period in 2008. The propane wholesale marketing
operation typically capitalizes on price volatility by selling at prices above cost and effectively
managing the larger spreads between the market (spot) prices and forward prices. Overall lack of
volatility in wholesale propane prices during the first nine months of 2009 compared to the same
period in 2008, reduced such revenue opportunities.
Other Operating Expenses
Other operating expenses increased by $749,000 for the propane segment for the nine months ended
September 30, 2009, compared to the same period in 2008, due primarily to: (i) higher payroll costs
of $514,000 resulting from increased accruals for incentive compensation based on increased
operating results; (ii) increased costs to maintain propane tanks in compliance with United States
Department of Transportation standards of $118,000; (iii) higher benefit costs of $103,000 as a
result of the significant decline in the value of pension plan assets; and (iv) increased customer
charges of $74,000. These increases were partially offset by lower vehicle-related expenses of
$248,000 due to decrease in the price of fuel.
Advanced Information Services
The advanced information services business experienced an operating loss of $448,000 for the nine
months ended September 30, 2009, a decrease of $964,000, compared to the operating income of
$516,000 that was achieved
during the same period in 2008.
For the Nine Months Ended September 30, | 2009 | 2008 | Change | |||||||||
(in Thousands) | ||||||||||||
Revenue |
$ | 8,592 | $ | 11,216 | $ | (2,624 | ) | |||||
Cost of sales |
4,711 | 6,143 | (1,432 | ) | ||||||||
Gross margin |
3,881 | 5,073 | (1,192 | ) | ||||||||
Operations & maintenance |
3,707 | 3,889 | (182 | ) | ||||||||
Depreciation & amortization |
146 | 124 | 22 | |||||||||
Other taxes |
476 | 544 | (68 | ) | ||||||||
Other operating expenses |
4,329 | 4,557 | (228 | ) | ||||||||
Total Operating Income (Loss) |
$ | (448 | ) | $ | 516 | $ | (964 | ) | ||||
The change from operating income to operating loss is the results of lower gross margin of
$1.2 million, partially offset by lower other operating expenses of $228,000.
Gross Margin
The period-over-period decrease in gross margin is due to a decrease of $2.5 million in consulting
revenues, as the number of billable hours declined by thirty percent for the nine months ended
September 30, 2009, compared to the same period in 2008. The reduction in the number of billable
hours is a result of current economic conditions in which information technology spending has
broadly declined.
Other Operating Expenses
Other operating expenses decreased by $228,000 to $4.3 million in the first nine months of 2009
compared to $4.6 million for the same period in 2008. This decrease was attained from layoffs and
other cost containment actions and lower accruals for incentive compensation due to the lower
operating results. In March, September and October 2009, the Company instituted layoffs,
compensation adjustments and other cost-containment actions that are estimated to offset the
decline in revenues and are expected to reduce costs by $392,000, respectively, for the remainder
of 2009. These cost-containment actions are expected to return the advanced information segment to
an operating profit.
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Other and Eliminations
The other and eliminations segment, which reflects primarily the revenues and expenses of
subsidiaries that own real estate leased to other Company subsidiaries and merger-related costs
that are not subject to future rate recovery, experienced an operating loss of approximately
$260,000 for the first nine months of 2009, compared to an operating loss of approximately $966,000
for the same period in 2008. The operating losses experienced in the first nine months of 2009 and
2008 were due primarily to merger-related costs.
For the Nine Months Ended September 30, | 2009 | 2008 | Change | |||||||||
(in Thousands) | ||||||||||||
Revenue |
$ | (738 | ) | $ | (411 | ) | $ | (327 | ) | |||
Cost of sales |
(251 | ) | (3 | ) | (248 | ) | ||||||
Gross margin |
(487 | ) | (408 | ) | (79 | ) | ||||||
Operations & maintenance |
(888 | ) | (811 | ) | (77 | ) | ||||||
Non-recoverable transaction and legal costs |
530 | 1,240 | (710 | ) | ||||||||
Depreciation & amortization |
84 | 83 | 1 | |||||||||
Other taxes |
47 | 46 | 1 | |||||||||
Other operating expenses |
(227 | ) | 558 | (785 | ) | |||||||
Total Operating Loss |
$ | (260 | ) | $ | (966 | ) | $ | 706 | ||||
Note: | Eliminations are entries required to eliminate activities between business segments from the consolidated results. |
Interest Expense
Total interest expense for the first nine months of 2009 increased by approximately $285,000, or
six percent, compared to the same period in 2008. The higher interest expense is primarily
attributable to the following:
| Interest on long-term debt increased by $963,000 in the first nine months of 2009,
compared to the same period in 2008, as the Company increased its average long-term debt
balance by $23.1 million. The Companys weighted average interest rate decreased to 6.36
percent during the first nine months of 2009, compared to 6.63 percent for the same period
in 2008. The change in the average long-term debt balance and weighted average interest
rate is a result of the placement of $30.0 million of 5.93 percent Unsecured Senior Notes
in October 2008. |
||
| Interest on short-term borrowings decreased by $735,000 in the first nine months of
2009, compared to the same period in 2008, based upon a decrease of $28.1 million in the
Companys average short-term borrowing balance coupled with a lower weighted average
interest rate. The Companys average short-term borrowing during the first nine months of
2009 was $10.2 million, with a weighted average interest rate of 1.96 percent, compared to
$38.3 million, with a weighted average interest rate of 3.04 percent, for the same period
in 2008. |
Income Taxes
Income tax expense for the first nine months of 2009 was $6.6 million, compared to $5.9 million for
the same period in 2008. The effective income tax rate for the first nine months of 2009 is 40.6
percent, compared to an effective tax rate of 38.9 percent for the first nine months of 2008. The
Company estimates that $455,000 of merger-related costs in the nine months ended September 30,
2009, would not be tax-deductible, based on the nature and timing of those costs. The effective
income tax rate, excluding the effects of non-deductible merger-related costs, for the first nine
months of 2009 would have been 39.5 percent. The slight increase in effective income tax rate,
excluding the effect of non-deductible merger-related costs, is the result of a greater portion of
the Companys pre-tax income being generated from entities in states with higher income tax rates.
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Table of Contents
Financial Position, Liquidity and Capital Resources
Chesapeakes capital requirements reflect the capital-intensive nature of its business and are
principally attributable to its investments in new plant and equipment and the retirement of
outstanding debt. The Company relies on cash generated from operations, short-term borrowing and
other sources to meet normal working capital requirements and to finance capital expenditures.
During the first nine months of 2009, net cash provided by operating activities was $47.5 million,
cash used by investing activities was $19.7 million, and cash used by financing activities was
$28.6 million. By comparison, during the first nine months of 2008, net cash provided by operating
activities was $13.4 million, cash used by investing activities was $24.1 million, and cash
provided by financing activities was $10.7 million.
The Board of Directors has authorized the Company to borrow up to $65.0 million of short-term debt,
as required, from various banks and trust companies under short-term lines of credit. As of
September 30, 2009, Chesapeake had four unsecured bank lines of credit with two financial
institutions, totaling $90.0 million, none of which requires compensating balances. These bank
lines are available to provide funds for the Companys short-term cash needs to meet seasonal
working capital requirements and to fund temporarily portions of its capital expenditures. Two of
the bank lines, totaling $55.0 million, are committed. Advances offered under the uncommitted lines
of credit are subject to the discretion of the banks. The Companys outstanding balance of
short-term borrowing at September 30, 2009 and December 31, 2008, was $10.1 million and $33.0
million, respectively. The large decrease in the Companys outstanding balance of short-term
borrowing during the first nine months of 2009 is due primarily to a larger increase in net cash
provided by operating activities and seasonal factors.
Chesapeake budgeted $34.8 million for capital expenditures during 2009. This amount includes $30.5
million for the natural gas segment, $3.6 million for the propane segment, $250,000 for the
advanced information services segment and $447,000 for the other operations segment. The natural
gas expenditures are for expansion and improvement of facilities. The propane expenditures are to
support customer growth and replace equipment. The advanced information services expenditures are
for computer hardware, software and related equipment. The other operations category includes
general plant, computer software and hardware. As a result of the continued slowdown in the new
housing market and industrial growth, the Company reduced its 2009 capital spending projections by
$3.4 million primarily for amounts budgeted for the natural gas segment. At September 30, 2009,
the Company had invested $19.1 million of the revised capital budget. The Company expects to fund
the remaining 2009 capital expenditures program from short-term borrowing, cash provided by
operating activities, and other sources. The capital expenditure program is subject to continuous
review and modification. Actual capital requirements may vary from the above estimates due to a
number of factors, including changing economic conditions, customer growth in existing areas,
regulation, new growth or acquisition opportunities and the availability of capital.
Capital Structure
The following presents the Companys capitalization, excluding short-term borrowing, as of
September 30, 2009 and December 31, 2008:
September 30, 2009 | December 31, 2008 | |||||||||||||||
(in Thousands, except percentages) | ||||||||||||||||
Long-term debt, net of current maturities |
$ | 86,282 | 40 | % | $ | 86,422 | 41 | % | ||||||||
Stockholders equity |
$ | 129,007 | 60 | % | $ | 123,073 | 59 | % | ||||||||
Total capitalization, excluding short-term debt |
$ | 215,289 | 100 | % | $ | 209,495 | 100 | % | ||||||||
As of September 30, 2009, common equity represented 60 percent of total capitalization,
excluding short-term borrowing, compared to 59 percent at December 31, 2008. If short-term
borrowing and the current portion of long-term debt were included in total capitalization, the
equity component of the Companys capitalization would have been 56 percent at September 30, 2009,
compared to 49 percent at December 31, 2008.
Chesapeake remains committed to maintaining a sound capital structure and strong credit ratings to
provide the financial flexibility needed to access capital markets when required. This commitment,
along with adequate and timely rate relief for the Companys regulated operations, is intended to
ensure that Chesapeake will be able to attract capital from outside sources at a reasonable cost.
The Company believes that the achievement of these objectives will provide benefits to its
customers and creditors, as well as its investors.
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Shelf Registration
In July 2006, the Company filed a registration statement on Form S-3 with the SEC to issue up to
$40.0 million in new common stock and/or debt securities. The registration statement was declared
effective by the SEC in November 2006. In the fourth quarter of 2006, the Company sold 690,345
shares of common stock, including the underwriters exercise of an over-allotment option of 90,045
shares, under this registration statement, generating net proceeds of $19.7 million. At September
30, 2009, the Company had approximately $20.0 million remaining under this registration statement.
Cash Flows Provided By Operating Activities
Cash flows provided by operating activities were as follows:
For the Nine Months Ended September 30, | 2009 | 2008 | Change | |||||||||
Net Income |
$ | 9,706 | $ | 9,195 | $ | 511 | ||||||
Non-cash adjustments to net income |
18,311 | 15,428 | 2,883 | |||||||||
Changes in assets and liabilities |
19,435 | (11,199 | ) | 30,634 | ||||||||
Net cash provided by operating activties |
$ | 47,451 | $ | 13,424 | $ | 34,028 | ||||||
Period-over-period changes in the Companys cash flows from operating activities are attributable
primarily to changes in net income, changes in non-cash adjustments to net income, such as
depreciation and deferred income taxes, and changes in working capital. Changes in working capital
are determined by a variety of factors, including weather, the price of natural gas and propane,
the timing of customer collections, payments of natural gas and propane purchases, payments of
income taxes and deferred gas cost recoveries.
For the first nine months of 2009, net cash flow provided by operating activities was $47.5
million, an increase of $34.0 million, compared to the same period in 2008. The increase was due
primarily to the following developments:
| Net cash flows from changes in accounts receivable and accounts payable were due
primarily to collections and payments from the Companys natural gas and propane
distribution operations coupled with lower commodity prices. |
||
| The timing of trading contracts entered into by the Companys propane wholesale and
marketing operation contributed to the net cash flows from changes in accounts receivable,
accounts payable, and prepaid expenses. |
||
| The net cash flows provided by natural gas and propane inventories were the result of
lower commodity prices. |
||
| Net cash flows generated by income tax receivables were due primarily to the receipt of
the Companys refund of federal income taxes for the year ended December 31, 2008, and
increased book-to-tax timing differences associated with depreciation, which are lowering
the Companys current taxes payable. |
||
| Net cash flows from changes in regulatory liabilities are related to an increase in
over-collected gas costs from rate-payers for Delmarva natural gas distribution operations,
which will be refunded in future periods. |
||
| Non-cash adjustments reflected unrealized losses on commodity contracts, as there were
fewer opportunities in the propane wholesale trading market during the first nine months of
the year. |
||
| The net cash flows used by non-cash adjustments for deferred income taxes are primarily
the result of the timing of the Companys regulatory filings for its gas cost recovery
mechanisms, partially offset by higher book-to-tax timing differences generated by the 2009
American Recovery and Reinvestment Act, which authorized bonus depreciation for certain
assets. |
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Table of Contents
Cash Flows Used in Investing Activities
Net cash flows used in investing activities totaled $19.7 million and $24.1 million during the nine
months ended September 30, 2009 and 2008, respectively. Cash utilized for capital expenditures was
$19.6 million and $23.7 million for the first nine months of 2009 and 2008, respectively. Additions
to property, plant and equipment in the first nine months of 2009 were primarily for the natural
gas segment ($17.4 million), the propane segment ($1.3 million), the advanced information services
segment ($408,000), and the other operations segment ($487,000).
Cash Flows Used by Financing Activities
Cash flows used by financing activities totaled $28.6 million for the first nine months of 2009,
compared to cash provided of $10.7 million for the same period in 2008. Significant financing
activities included the following:
| During the first nine months of 2009, the Company had a net repayment of short-term debt
of $23.4 million, compared to net borrowings of $16.2 million in the first nine months of
2008, as it generated higher amounts of cash from operating activities. |
||
| The Company paid $5.9 million in cash dividends for the nine months ended September 30,
2009 and 2008. Dividends paid in the first nine months of 2009 increased as a result of
growth in the annualized dividend rate and in the number of shares outstanding. These
increases were offset by an increased number of shares issued from reserve balances in lieu of cash dividend payments pursuant to the Companys
Dividend Reinvestment Plan. |
||
| The Company repaid $20,000 of long-term debt during the first nine months of 2009,
compared to $1.0 million in the first nine months of 2008, in accordance with its repayment
schedules. |
Off-Balance Sheet Arrangements
The Company has issued corporate guarantees to certain vendors of its subsidiaries, primarily its
propane wholesale and marketing subsidiary, Xeron, and its natural gas supply management
subsidiary, PESCO. These corporate guarantees provide for the payment of propane and natural gas
purchases in the event of either subsidiarys default. Neither subsidiary has ever defaulted on its
obligations to pay suppliers. The liabilities for these purchases are recorded in the condensed
consolidated financial statements when incurred. The aggregate amount guaranteed at September 30,
2009, was $22.4 million, with the guarantees expiring on various dates in 2009 and 2010.
In addition to the corporate guarantees, the Company has issued a letter of credit to its primary
insurance company for $775,000, which expires on May 31, 2010. The letter of credit is provided as
security to satisfy the deductibles under the Companys various insurance policies. There have been
no draws on this letter of credit as of September 30, 2009, and the Company does not anticipate
that this letter of credit will be drawn upon by the counterparty in the future.
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Table of Contents
Contractual Obligations
There have not been any material changes in the contractual obligations presented in the Companys
2008 Annual Report on Form 10-K, except for commodity purchase obligations and forward contracts
entered into in the ordinary course of the Companys business. The following table summarizes the
commodity and forward contract obligations at September 30, 2009.
Payments Due by Period | ||||||||||||||||||||
Purchase Obligations (in Thousands) | Less than 1 year | 1 - 3 years | 3 - 5 years | More than 5 years | Total | |||||||||||||||
Commodities (1) (3) |
$ | 20,954 | $ | 320 | | | $ | 21,274 | ||||||||||||
Propane (2) |
23,787 | | | | 23,787 | |||||||||||||||
Total Purchase Obligations |
$ | 44,741 | $ | 320 | | | $ | 45,061 | ||||||||||||
(1) | In addition to the obligations noted above, the natural gas
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 the Company does not purchase
specified amounts during the summer season. Under these contracts, the
commodity prices will fluctuate as market prices fluctuate. |
|
(2) | The Company has also entered into forward sale contracts in the
aggregate amount of $23.4 million. See Part I, Item 3, Quantitative and
Qualitative Disclosures about Market Risk, below, for further information. |
|
(3) | In March 2009, the Company renewed its contract with an energy
marketing and risk management company to manage a portion of the Companys
natural gas transportation and storage capacity. There were no material
changes to the contracts terms, as reported in the Companys 2008 Annual
Report on Form 10-K. |
|
(4) | The Company expects to contribute $450,000 to the defined benefit
pension plan during the fourth quarter of 2009. The above table does not
reflect this payment, because it is a voluntary contribution to the defined
benefit pension plan. |
Environmental Matters
As more fully described in Note 4, Commitments and Contingencies, to these unaudited condensed
consolidated financial statements in this Quarterly Report on Form 10-Q, Chesapeake has incurred
costs relating to the completed or ongoing environmental remediation at two former manufactured gas
plant sites. In addition, Chesapeake is currently participating in discussions regarding possible
responsibility for remediation of a third former manufactured gas plant site located in Cambridge,
Maryland. Chesapeake believes that future costs associated with these sites will be recoverable in
rates or through sharing arrangements with, or contributions by, other responsible parties.
Other Matters
Rates and Regulatory Matters
The Companys natural gas distribution operations in Delaware, Maryland and Florida are regulated
by their respective state PSCs. ESNG is subject to regulation by the FERC. At September 30, 2009,
Chesapeake was involved in rates and/or regulatory matters in each of the jurisdictions in which it
operates. Each of these rates or regulatory matters is fully described in Note 4, Commitments and
Contingencies, to these unaudited condensed consolidated financial statements in this Quarterly
Report on Form 10-Q.
Competition
The Companys natural gas operations compete with other forms of energy, including electricity, oil
and propane. The principal competitive factors are price and, to a lesser extent, accessibility.
The Companys natural gas distribution operations have several large-volume industrial customers
that have the capacity to use fuel oil as an alternative to natural gas. When oil prices decline,
these interruptible customers may convert to oil to satisfy their fuel requirements, and our
interruptible sales volumes may decline because oil prices are lower than the price of natural gas.
Oil prices, as well as the prices of electricity and other fuels, fluctuate for a variety of
reasons; therefore, future competitive conditions are not predictable. To address this uncertainty, the Company uses
flexible pricing arrangements on both the supply and sales sides of this business to compete with
alternative fuel price fluctuations. As a result of the transmission operations conversion to open
access and the Florida natural gas distribution divisions restructuring of its services, these
businesses have shifted from providing competitive sales service to providing only transportation
and contract storage services.
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Table of Contents
The Companys natural gas distribution operations in Delaware, Maryland and Florida offer unbundled
transportation services to certain commercial and industrial customers. In 2002, the Florida
operation extended such service to residential customers. With such transportation service
available on the Companys distribution systems, the Company is competing with third-party
suppliers to sell gas to industrial customers. With respect to unbundled transportation services,
the Companys competitors include interstate transmission companies, if the distribution customers
are located close enough to a transmission companys pipeline to make connections economically
feasible. The customers at risk are usually large-volume commercial and industrial customers with
the financial resources and capability to bypass the Companys distribution operations. In certain
situations, the Companys distribution operations may adjust services and rates for these customers
to retain their business. The Company expects to continue to expand the availability of unbundled
transportation service to additional classes of distribution customers in the future. The Company
established a natural gas sales and supply operation in Florida, Delaware and Maryland to provide
such service to customers eligible for unbundled transportation services.
The Companys propane distribution operations compete with several other propane distributors in
their service territories, primarily on the basis of service and price, emphasizing responsive and
reliable service. Our competitors generally include local outlets of national distributors and
local independent distributors, whose proximity to customers entails lower costs to provide
service. Propane competes with electricity as an energy source, because it is typically less
expensive than electricity, based on equivalent BTU value. Propane also competes with home heating
oil as an energy source. Since natural gas has historically been less expensive than propane,
propane is generally not distributed in geographic areas serviced by natural gas pipeline or
distribution systems.
The propane wholesale marketing operation competes against various regional and national marketers,
many of which have significantly greater resources and are able to obtain price or volumetric
advantages.
The advanced information services business faces significant competition from a number of larger
competitors having substantially greater resources available to them than does the Company. In
addition, changes in the advanced information services industry are occurring rapidly, and could
adversely impact the markets for the products and services offered by these businesses. This
segment of the Company competes on the basis of technological expertise, reputation and price.
Inflation
Inflation affects the cost of supply, labor, products and services required for operations,
maintenance and capital improvements. While the impact of inflation has remained low in recent
years, natural gas and propane prices are subject to rapid fluctuations. In the Companys regulated
natural gas distribution operations, fluctuations in natural gas prices are passed on to customers
through the gas cost recovery mechanisms in the Companys tariffs. To help cope with the effects of
inflation on its capital investments and returns, the Company seeks rate relief from regulatory
commissions for its regulated operations and closely monitors the returns of its unregulated
business operations. To compensate for fluctuations in propane gas prices, the Company adjusts its
propane selling prices to the extent allowed by the market.
Recent Authoritative Pronouncements on Financial Reporting and Accounting
Recent accounting developments and their impact on our financial position, results of operations
and cash flows are described in the Recent Accounting Pronouncements section of Note 1, Summary of
Accounting Policies, to these unaudited condensed consolidated financial statements in this
Quarterly Report on Form 10-Q.
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Item 3. | Quantitative and Qualitative Disclosures about Market Risk |
Market risk represents the potential loss arising from adverse changes in market rates and prices.
Long-term debt is subject to potential losses based on changes in interest rates. The Companys
long-term debt consists of fixed-rate senior notes and convertible debentures. All of the Companys
long-term debt is fixed-rate debt and was not entered into for trading purposes. The carrying value
of long-term debt, including current maturities, was $93.0 million at September 30, 2009, compared
to a fair value of $96.0 million, based on 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. The
Company evaluates whether to refinance existing debt or permanently refinance existing short-term
borrowing, based in part on the fluctuation in interest rates.
The Companys propane distribution business is exposed to market risk as a result of propane
storage activities and fixed-price contracts for supply. The Company can store up to approximately
four million gallons (including leased storage and rail cars) of propane during the winter season
to meet its customers peak requirements and to serve metered customers. Decreases in the wholesale
price of propane may cause the value of stored propane to decline. To mitigate the impact of price
fluctuations, the Company has adopted a Risk Management Policy that allows the propane distribution
operation to enter into fair value hedges of its inventory. At July 31, 2009, the propane
distribution operation had entered into a put agreement to protect the Company from the impact of
price decreases on our price-cap plan that the Company offers to customers. The Company considered
this put agreement an economic hedge that did not qualify for hedge accounting. As of September 30,
2009, the Company marked the put agreement to market, which resulted in an unrealized loss of
$76,000.
The Companys propane wholesale marketing operation is a party to natural gas liquids (NGLs)
forward contracts, primarily propane contracts, with various third parties. These contracts require
that the propane wholesale marketing operation purchase or sell NGLs at a fixed price at fixed
future dates. At expiration, the contracts are settled by the delivery of NGLs to the Company or
the counter-party, or by booking out the transaction. Booking out is a procedure for financially
settling a contract in lieu of the physical delivery of energy. The propane wholesale marketing
operation also enters into futures contracts that are traded on the New York Mercantile Exchange.
In certain cases, the futures contracts are settled by the payment or receipt of a net amount equal
to the difference between the current market price of the futures contract and the original
contract price; however, they may also be settled for physical receipt or delivery of propane.
The forward and futures contracts are entered into for trading and wholesale marketing purposes.
The propane wholesale marketing business is subject to commodity price risk on its open positions
to the extent that market prices for NGLs deviate from fixed contract settlement prices. Market
risk associated with the trading of futures and forward contracts is monitored daily for compliance
with the Companys Risk Management Policy, which includes volumetric limits for open positions. To
manage exposure to changing market prices, open positions are marked up or down to market prices
and reviewed by the Companys oversight officials daily. In addition, the Risk Management Committee
reviews periodic reports on markets and the credit risk of counter-parties, approves any exceptions
to the Risk Management Policy (within limits established by the Board of Directors) and authorizes
the use of any new types of contracts. Quantitative information on forward and futures contracts at
September 30, 2009, is presented in the following table.
Quantity in | Estimated Market | Weighted Average | ||||||||||
At September 30, 2009 | Gallons | Prices | Contract Prices | |||||||||
Forward Contracts |
||||||||||||
Sale |
26,098,800 | $ | 0.6900 $0.9950 | $ | 0.8962 | |||||||
Purchase |
26,590,200 | $ | 0.6650 $0.9975 | $ | 0.8946 |
Estimated market prices and weighted average contract prices are in dollars per gallon.
All contracts expire in 2009 or in the first quarter of 2010.
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At September 30, 2009 and December 31, 2008, the Company marked these forward contracts to market,
using broker or dealer quotations, or market transactions in either the listed or OTC markets,
which resulted in the following assets and liabilities:
September 30, | December 31, | |||||||
(in thousands) | 2009 | 2008 | ||||||
Mark-to-market energy assets |
$ | 1,532 | $ | 4,482 | ||||
Mark-to-market energy liabilities |
$ | 1,484 | $ | 3,052 |
Item 4. | Controls and Procedures |
Evaluation of Disclosure Controls and Procedures
The Chief Executive Officer and Chief Financial Officer of the Company, with the participation of
other Company officials, have evaluated the Companys disclosure controls and procedures (as such
term is defined under Rules 13a-15(e) and 15d-15(e), promulgated under the Securities Exchange Act
of 1934, as amended) as of September 30, 2009. Based upon their evaluation, the Chief Executive
Officer and Chief Financial Officer concluded that the Companys disclosure controls and procedures
were effective as of September 30, 2009.
Changes in Internal Control Over Financial Reporting
During the quarter ended September 30, 2009, there was no change in the Companys internal control
over financial reporting that has materially affected, or is reasonably likely to materially
affect, the Companys internal control over financial reporting.
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PART II OTHER INFORMATION
Item 1. | Legal Proceedings |
As disclosed in Note 4, Commitments and Contingencies, of these unaudited condensed
consolidated financial statements in this Quarterly Report on Form 10-Q, the Company is
involved in certain legal actions and claims arising in the normal course of business.
The Company is also involved in certain legal and administrative proceedings before
various government agencies concerning rates. In the opinion of management, the ultimate
disposition of these proceedings and claims will not have a material effect on the
condensed consolidated financial position, results of operations or cash flows of the
Company.
On September 29, 2009, a putative class action lawsuit, which had been filed on May 8,
2009 in Palm Beach County, Florida, challenging the merger, purportedly on behalf of the
shareholders of FPU, against FPU, each member of FPUs board of directors and Chesapeake
was dismissed without prejudice.
Item 1A. | Risk Factors |
There have not been any material changes in the risk factors previously disclosed by the
Company in its Annual Report on Form 10-K for the year ended December 31, 2008.
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) | ||||||||||||
July 1, 2009
through July 31, 2009 (1) |
527 | $ | 33.30 | | | |||||||||||
August 1, 2009
through August 31, 2009 |
| $ | | | | |||||||||||
September 1, 2009
through September 30, 2009 |
| $ | | | | |||||||||||
Total |
527 | $ | 33.30 | | | |||||||||||
(1) | Chesapeake purchased shares of stock on the open market for the purpose of
reinvesting the dividend on deferred stock units
held in the Rabbi Trust accounts for certain Directors and Senior Executives under the
Deferred Compensation Plan. The
Deferred Compensation Plan is discussed in detail in Note L to the Consolidated Financial
Statements of the Companys Form
10-K filed with the Securities Exchange Commission on March 9, 2009. During the quarter, 527 shares were purchased through
the reinvestment of dividends on deferred stock units. |
|
(2) | Except for the purposes described in Footnote (1), Chesapeake has not publicly
announced plans or programs to
repurchase its shares. |
Item 3. | Defaults upon Senior Securities |
None.
Item 4. | Submission of Matters to a Vote of Security Holders |
None.
Item 5. | Other Information |
None.
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Item 6. | Exhibits |
2.1 | Agreement and Plan of Merger between Chesapeake Utilities Corporation
and Florida Public Utilities Company dated April 17, 2009, is
incorporated herein by reference to Exhibit 2.1 of the Companys
Current Report on Form 8-K, filed April 20, 2009, File No. 001-11590. |
|||
31.1 | Certificate of Chief Executive Officer of Chesapeake Utilities
Corporation pursuant to Rule 13a-14(a) under the Securities Exchange
Act of 1934, dated November 6, 2009. |
|||
31.2 | Certificate of Chief Financial Officer of Chesapeake Utilities
Corporation pursuant to Rule 13a-14(a) under the Securities Exchange
Act of 1934, dated November 6, 2009. |
|||
32.1 | Certificate of Chief Executive Officer of Chesapeake Utilities
Corporation pursuant to 18 U.S.C. Section 1350, dated November 6,
2009. |
|||
32.2 | Certificate of Chief Financial Officer of Chesapeake Utilities
Corporation pursuant to 18 U.S.C. Section 1350, dated November 6,
2009. |
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Chesapeake Utilities Corporation
/s/ Beth W. Cooper
|
||
Senior Vice President and Chief Financial Officer |
Date: November 6, 2009
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EXHIBIT INDEX
Exhibit No. | Description | |||
31.1 | Certificate of Chief Executive Officer of Chesapeake Utilities
Corporation pursuant to Rule 13a-14(a) under the Securities
Exchange Act of 1934, dated November 6, 2009. |
|||
31.2 | Certificate of Chief Financial Officer of Chesapeake Utilities
Corporation pursuant to Rule 13a-14(a) under the Securities
Exchange Act of 1934, dated November 6, 2009. |
|||
32.1 | Certificate of Chief Executive Officer of Chesapeake Utilities
Corporation pursuant to 18 U.S.C. Section 1350, dated November
6, 2009. |
|||
32.2 | Certificate of Chief Financial Officer of Chesapeake Utilities
Corporation pursuant to 18 U.S.C. Section 1350, dated November
6, 2009. |
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