Piedmont Natural Gas Company, Inc.
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
(Mark One)
|
|
|
þ |
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 |
For the quarterly period ended April 30, 2006
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 1-6196
Piedmont Natural Gas Company, Inc.
(Exact name of registrant as specified in its charter)
|
|
|
North Carolina
|
|
56-0556998 |
|
(State or other jurisdiction of
|
|
(I.R.S. Employer |
incorporation or organization)
|
|
Identification No.) |
|
|
|
4720 Piedmont Row Drive, Charlotte, North Carolina
|
|
28210 |
|
(Address of principal executive offices)
|
|
(Zip Code) |
Registrants telephone number, including area code (704) 364-3120
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 is a large accelerated filer, an accelerated filer,
or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in
Rule 12b-2 of the Exchange Act. (Check One):
|
|
|
|
|
Large Accelerated Filer þ
|
|
Accelerated Filer o
|
|
Non-accelerated Filer 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
Indicate the number of shares outstanding of each of the issuers classes of common stock, as of
the latest practicable date.
|
|
|
Class
|
|
Outstanding at June 2, 2006 |
|
Common Stock, no par value
|
|
75,277,520 |
PART 1. FINANCIAL INFORMATION
Item 1. Financial Statements
Piedmont Natural Gas Company, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
April 30, |
|
|
October 31, |
|
|
|
2006 |
|
|
2005 |
|
ASSETS |
|
|
|
|
|
|
|
|
Utility Plant, at original cost |
|
$ |
2,699,460 |
|
|
$ |
2,611,577 |
|
Less accumulated depreciation |
|
|
700,299 |
|
|
|
672,502 |
|
|
|
|
|
|
|
|
Utility plant, net |
|
|
1,999,161 |
|
|
|
1,939,075 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Physical Property (net of accumulated depreciation of $1,969 in 2006
and $1,888 in 2005) |
|
|
727 |
|
|
|
731 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
20,330 |
|
|
|
7,065 |
|
Restricted cash |
|
|
|
|
|
|
13,108 |
|
Trade accounts receivable (less allowance for doubtful accounts of $4,815 in 2006
and $1,188 in 2005) |
|
|
182,027 |
|
|
|
107,535 |
|
Income taxes receivable |
|
|
13,318 |
|
|
|
21,570 |
|
Other receivables |
|
|
1,532 |
|
|
|
12,102 |
|
Unbilled utility revenues |
|
|
27,598 |
|
|
|
48,414 |
|
Gas in storage |
|
|
107,902 |
|
|
|
151,865 |
|
Gas purchase options, at fair value |
|
|
1,471 |
|
|
|
22,843 |
|
Amounts due from customers |
|
|
68,501 |
|
|
|
52,161 |
|
Prepayments |
|
|
24,009 |
|
|
|
62,821 |
|
Other |
|
|
5,346 |
|
|
|
5,427 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
452,034 |
|
|
|
504,911 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments, Deferred Charges and Other Assets: |
|
|
|
|
|
|
|
|
Equity method investments in non-utility activities |
|
|
80,331 |
|
|
|
71,520 |
|
Goodwill |
|
|
47,383 |
|
|
|
47,383 |
|
Unamortized debt expense |
|
|
4,973 |
|
|
|
4,822 |
|
Other |
|
|
31,666 |
|
|
|
34,048 |
|
|
|
|
|
|
|
|
Total investments, deferred charges and other assets |
|
|
164,353 |
|
|
|
157,773 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
2,616,275 |
|
|
$ |
2,602,490 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES |
|
|
|
|
|
|
|
|
Capitalization: |
|
|
|
|
|
|
|
|
Stockholders equity: |
|
|
|
|
|
|
|
|
Common stock, no par value, shares authorized: 200,000 in 2006 and 100,000
in 2005; outstanding: 75,255 in 2006 and 76,698 in 2005 |
|
$ |
528,082 |
|
|
$ |
562,880 |
|
Retained earnings |
|
|
403,411 |
|
|
|
323,565 |
|
Accumulated other comprehensive income (loss) |
|
|
(956 |
) |
|
|
(2,253 |
) |
|
|
|
|
|
|
|
Total stockholders equity |
|
|
930,537 |
|
|
|
884,192 |
|
Long-term debt |
|
|
625,000 |
|
|
|
625,000 |
|
|
|
|
|
|
|
|
Total capitalization |
|
|
1,555,537 |
|
|
|
1,509,192 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities: |
|
|
|
|
|
|
|
|
Current maturities of long-term debt |
|
|
35,000 |
|
|
|
35,000 |
|
Notes payable |
|
|
252,000 |
|
|
|
158,500 |
|
Trade accounts payable |
|
|
73,710 |
|
|
|
182,847 |
|
Other accounts payable |
|
|
28,118 |
|
|
|
45,325 |
|
Income taxes accrued |
|
|
|
|
|
|
6,201 |
|
Deferred income taxes |
|
|
38,182 |
|
|
|
23,128 |
|
General taxes accrued |
|
|
7,906 |
|
|
|
16,450 |
|
Amounts due to customers |
|
|
1,614 |
|
|
|
17,124 |
|
Other |
|
|
47,139 |
|
|
|
43,989 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
483,669 |
|
|
|
528,564 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Credits and Other Liabilities: |
|
|
|
|
|
|
|
|
Deferred income taxes |
|
|
217,273 |
|
|
|
213,050 |
|
Unamortized federal investment tax credits |
|
|
3,682 |
|
|
|
3,951 |
|
Regulatory cost of removal obligations |
|
|
300,249 |
|
|
|
288,989 |
|
Other |
|
|
55,865 |
|
|
|
58,744 |
|
|
|
|
|
|
|
|
Total deferred credits and other liabilities |
|
|
577,069 |
|
|
|
564,734 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
2,616,275 |
|
|
$ |
2,602,490 |
|
|
|
|
|
|
|
|
See notes to condensed consolidated financial statements.
2
Piedmont Natural Gas Company, Inc. and Subsidiaries
Condensed Consolidated Statements of Income (Unaudited)
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Six Months |
|
|
|
Ended |
|
|
Ended |
|
|
|
April 30 |
|
|
April 30 |
|
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Operating Revenues |
|
$ |
483,198 |
|
|
$ |
508,035 |
|
|
$ |
1,404,545 |
|
|
$ |
1,188,591 |
|
Cost of Gas |
|
|
329,188 |
|
|
|
367,378 |
|
|
|
1,041,163 |
|
|
|
845,314 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Margin |
|
|
154,010 |
|
|
|
140,657 |
|
|
|
363,382 |
|
|
|
343,277 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenance |
|
|
59,720 |
|
|
|
52,324 |
|
|
|
112,942 |
|
|
|
102,577 |
|
Depreciation |
|
|
21,758 |
|
|
|
20,989 |
|
|
|
43,645 |
|
|
|
41,737 |
|
General taxes |
|
|
8,061 |
|
|
|
7,332 |
|
|
|
16,771 |
|
|
|
15,773 |
|
Income taxes |
|
|
20,271 |
|
|
|
19,098 |
|
|
|
64,663 |
|
|
|
63,357 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses |
|
|
109,810 |
|
|
|
99,743 |
|
|
|
238,021 |
|
|
|
223,444 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income |
|
|
44,200 |
|
|
|
40,914 |
|
|
|
125,361 |
|
|
|
119,833 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from equity method investments |
|
|
20,165 |
|
|
|
14,647 |
|
|
|
25,916 |
|
|
|
20,460 |
|
Gain on sale of marketable securities |
|
|
|
|
|
|
1,525 |
|
|
|
|
|
|
|
1,525 |
|
Allowance for equity funds used during construction |
|
|
|
|
|
|
359 |
|
|
|
|
|
|
|
616 |
|
Non-operating income |
|
|
266 |
|
|
|
106 |
|
|
|
285 |
|
|
|
521 |
|
Non-operating expense |
|
|
(115 |
) |
|
|
(233 |
) |
|
|
(182 |
) |
|
|
(337 |
) |
Income taxes |
|
|
(7,900 |
) |
|
|
(6,387 |
) |
|
|
(10,125 |
) |
|
|
(8,704 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense) |
|
|
12,416 |
|
|
|
10,017 |
|
|
|
15,894 |
|
|
|
14,081 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility Interest Charges |
|
|
12,874 |
|
|
|
11,201 |
|
|
|
25,516 |
|
|
|
23,006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Minority Interest in Income of Consolidated
Subsidiary |
|
|
43,742 |
|
|
|
39,730 |
|
|
|
115,739 |
|
|
|
110,908 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less Minority Interest in Income (Loss) of Consolidated Subsidiary |
|
|
|
|
|
|
98 |
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
$ |
43,742 |
|
|
$ |
39,632 |
|
|
$ |
115,739 |
|
|
$ |
110,909 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Shares of Common Stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
76,133 |
|
|
|
76,703 |
|
|
|
76,413 |
|
|
|
76,706 |
|
Diluted |
|
|
76,371 |
|
|
|
76,915 |
|
|
|
76,651 |
|
|
|
76,920 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Per Share of Common Stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.57 |
|
|
$ |
0.52 |
|
|
$ |
1.51 |
|
|
$ |
1.45 |
|
Diluted |
|
$ |
0.57 |
|
|
$ |
0.52 |
|
|
$ |
1.51 |
|
|
$ |
1.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Dividends Per Share of Common Stock |
|
$ |
0.24 |
|
|
$ |
0.23 |
|
|
$ |
0.47 |
|
|
$ |
0.445 |
|
See notes to condensed consolidated financial statements.
3
Piedmont Natural Gas Company, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
April 30 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
|
(As Restated- |
|
|
|
|
|
|
|
See Note 15) |
|
Cash Flows from Operating Activities: |
|
|
|
|
|
|
|
|
Net income |
|
$ |
115,739 |
|
|
$ |
110,909 |
|
Adjustments to reconcile net income to net
cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
45,717 |
|
|
|
44,365 |
|
Amortization of investment tax credits |
|
|
(269 |
) |
|
|
(272 |
) |
Allowance for doubtful accounts |
|
|
3,627 |
|
|
|
5,997 |
|
Allowance for funds used during construction |
|
|
(1,498 |
) |
|
|
(1,704 |
) |
Earnings from equity method investments |
|
|
(25,916 |
) |
|
|
(20,460 |
) |
Distributions of earnings from equity method investments |
|
|
24,473 |
|
|
|
21,164 |
|
Gain on sale of marketable securities |
|
|
|
|
|
|
(1,525 |
) |
Deferred income taxes |
|
|
18,448 |
|
|
|
20,582 |
|
Change in assets and liabilities |
|
|
(109,120 |
) |
|
|
40,477 |
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
71,201 |
|
|
|
219,533 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities: |
|
|
|
|
|
|
|
|
Utility construction expenditures |
|
|
(100,753 |
) |
|
|
(84,399 |
) |
Reimbursements from bond fund |
|
|
13,134 |
|
|
|
19,283 |
|
Contributions to equity method investments |
|
|
(5,569 |
) |
|
|
(319 |
) |
Distributions of capital from equity method investments |
|
|
158 |
|
|
|
794 |
|
Decrease (increase) in restricted cash |
|
|
13,108 |
|
|
|
(147 |
) |
Proceeds from sale of marketable securities |
|
|
|
|
|
|
2,394 |
|
Other |
|
|
1,280 |
|
|
|
700 |
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(78,642 |
) |
|
|
(61,694 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities: |
|
|
|
|
|
|
|
|
Increase (decrease) in notes payable, net of expenses of $370 in 2006 |
|
|
93,130 |
|
|
|
(109,500 |
) |
Issuance of common stock through dividend
reinvestment and employee stock plans |
|
|
10,312 |
|
|
|
13,083 |
|
Repurchases of common stock |
|
|
(46,779 |
) |
|
|
(12,979 |
) |
Dividends paid |
|
|
(35,957 |
) |
|
|
(34,120 |
) |
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
20,706 |
|
|
|
(143,516 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase in Cash and Cash Equivalents |
|
|
13,265 |
|
|
|
14,323 |
|
Cash and Cash Equivalents at Beginning of Period |
|
|
7,065 |
|
|
|
5,676 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents at End of Period |
|
$ |
20,330 |
|
|
$ |
19,999 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncash Investing and Financing Activities: |
|
|
|
|
|
|
|
|
Utility construction expenditures |
|
$ |
(5,150 |
) |
|
$ |
(1,701 |
) |
|
|
|
|
|
|
|
See notes to condensed consolidated financial statements.
4
Piedmont Natural Gas Company, Inc. and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Six Months |
|
|
|
Ended April 30 |
|
|
Ended April 30 |
|
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Net Income |
|
$ |
43,742 |
|
|
$ |
39,632 |
|
|
$ |
115,739 |
|
|
$ |
110,909 |
|
Other Comprehensive Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minimum pension liability adjustment, net of tax of ($1,778) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,748 |
) |
Reclassification adjustment of realized gain on marketable securities included in
net income, net of tax of ($611) |
|
|
|
|
|
|
(945 |
) |
|
|
|
|
|
|
(945 |
) |
Unrealized gain on marketable securities, net of tax of $220 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
348 |
|
Unrealized gain from hedging activities of equity method investments, net of tax of
$664 and $492 for the three months ended April 30, 2006 and 2005, respectively,
and $2,088 and $1,433 for the six months ended April 30, 2006 and 2005,
respectively |
|
|
1,042 |
|
|
|
730 |
|
|
|
3,283 |
|
|
|
2,229 |
|
Reclassification adjustment of realized gain from hedging activities of equity method
investments included in net income, net of tax of ($1,049) and ($912) for the
three months ended April 30, 2006 and 2005, respectively, and ($1,260) and
($1,129) for the six months ended April 30, 2006 and 2005 |
|
|
(1,653 |
) |
|
|
(1,418 |
) |
|
|
(1,986 |
) |
|
|
(1,689 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Comprehensive Income |
|
$ |
43,131 |
|
|
$ |
37,999 |
|
|
$ |
117,036 |
|
|
$ |
108,104 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to condensed consolidated financial statements.
5
Piedmont Natural Gas Company, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Unaudited)
1. The condensed consolidated financial statements have not been audited. These financial
statements should be read in conjunction with the Consolidated Financial Statements and Notes
included in our Form 10-K for the year ended October 31, 2005.
2. In our opinion, the unaudited condensed consolidated financial statements include all normal
recurring adjustments necessary for a fair statement of financial position at April 30, 2006 and
October 31, 2005, the results of operations for the three months and six months ended April 30,
2006 and 2005, and cash flows for the six months ended April 30, 2006 and 2005. Our business is
seasonal in nature. The results of operations for the three months and six months ended April 30,
2006, do not necessarily reflect the results to be expected for the full year.
We make estimates and assumptions when preparing the condensed consolidated financial statements.
These estimates and assumptions affect the reported amounts of assets and liabilities and the
disclosure of contingent assets and liabilities at the date of the condensed consolidated financial
statements and the reported amounts of revenues and expenses during the reporting period. Actual
results could differ from estimates.
3. We follow Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the
Effects of Certain Types of Regulation (Statement 71). Statement 71 provides that rate-regulated
public utilities account for and report assets and liabilities consistent with the economic effect
of the manner in which independent third-party regulators establish rates. In applying Statement
71, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively,
in order to provide for recovery from or refund to utility customers in future periods. The
amounts recorded as regulatory assets in the condensed consolidated balance sheets as of April 30,
2006 and October 31, 2005, were $100.2 million and $85.8 million, respectively. The amounts
recorded as regulatory liabilities in the condensed consolidated balance sheets as of April 30,
2006 and October 31, 2005, were $327.9 million and $333.3 million, respectively.
Significant inter-company transactions have been eliminated in consolidation where appropriate;
however, we have not eliminated inter-company profit on sales to affiliates and costs from
affiliates in accordance with Statement 71. See Note 9 for information on related party
transactions.
4. On November 3, 2005, the North Carolina Utilities Commission (NCUC) issued an order in a general
rate case proceeding approving, among other things, an annual increase in margin of $20.2 million
and authorizing new rates effective November 1, 2005. The order provided for the elimination of
the weather normalization adjustment (WNA) mechanism in North Carolina and the establishment of a
Customer Utilization Tracker (CUT). The CUT is experimental and can be effective for no more than
three years, subject to review and approval in a future general rate case proceeding. The CUT
provides for the recovery of our approved margin per customer independent of weather or other usage
and consumption patterns of residential and commercial customers. The CUT tracks our margin earned
monthly and will result in semi-annual rate adjustments to refund any over-collection or recover
any under-collection. On March 17, 2006, we made our first rate adjustment filing to collect,
beginning April 1, $11.8 million attributable to the period ended January 31, 2006.
On January 3, 2006, the North Carolina Office of the Attorney General filed a notice of appeal in
the general rate case proceeding challenging the lawfulness of the NCUCs authorization and
approval of the CUT. On April 6, the Attorney General filed a Notice of Appeal and Exceptions to
the NCUCs March 28, 2006, order approving the first adjustment filing under the CUT. This appeal
is not substantively different from the appeal
6
of the CUT mechanism. We believe the CUT is lawful, just and reasonable and reflects good public
policy, and we intend to vigorously defend the NCUCs action authorizing and approving the CUT.
We have entered into settlement negotiations with the Attorney Generals office. We are unable to
predict the outcome of the appeals, the settlement discussions or any potential impact to our
rates, charges or terms and conditions of service should the NCUC orders be reversed or remanded.
5. On April 7, 2006, we entered into an accelerated share repurchase program whereby we purchased
and retired 1 million shares of our common stock from an investment bank at the closing price that
day of $23.87 per share. Total consideration paid to purchase the shares of $23.9 million,
including $30,000 in commissions and other fees, was recorded in Stockholders Equity as a
reduction in Common Stock.
As part of the accelerated share repurchase, we simultaneously entered into a forward sale contract
with the investment bank that was expected to mature in approximately 50 trading days. Under the
terms of the forward sale contract, the investment bank is required to purchase, in the open
market, 1 million shares of our common stock during the term of the contract to fulfill its
obligation related to the shares it borrowed from third parties and sold to us. At settlement, we,
at our option, are required to either pay cash or issue registered or unregistered shares of our
common stock to the investment bank if the investment banks weighted average purchase price is
higher than the April 7, 2006, closing price. The investment bank is required to pay us either
cash or shares of our common stock, at our option, if the investment banks weighted average price
for the shares purchased is lower than the April 7, 2006, closing price. The amount of the payment
is the difference between the investment banks weighted average price per share and $23.87 per
share multiplied by 1 million shares.
We accounted for the forward sale contract as an equity instrument under the provisions of Emerging
Issues Task Force (EITF) Issue No. 00-19, Accounting for Derivative Financial Instruments Indexed
to, and Potentially Settled in, a Companys Own Stock. As the fair value of the forward sale
contract at inception was zero, no accounting for the forward sale contract is required until
settlement, as long as the forward sale continues to meet the requirements for classification as an
equity instrument. As of April 30, 2006, the investment bank had purchased 386,100 shares at a
cumulative weighted average price of $24.32 per share. Subsequent to the quarter ended April 30,
2006, the investment bank purchased the remaining 613,900 shares which resulted in a cumulative
weighted average price of $24.26 per share. At settlement on June 6, we paid cash of $.4 million
to the investment bank, recorded in Common Stock in Stockholders Equity, since the weighted
average purchase price was higher than the April 7, 2006, closing price of $23.87.
6. We compute basic earnings per share using the weighted average number of shares of common stock
outstanding during each period. A reconciliation of basic and diluted earnings per share for the
three months and six months ended April 30, 2006 and 2005, is presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Six Months |
|
In thousands except per share amounts |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Net Income |
|
$ |
43,742 |
|
|
$ |
39,632 |
|
|
$ |
115,739 |
|
|
$ |
110,909 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average shares of common stock outstanding for
basic earnings per share |
|
|
76,133 |
|
|
|
76,703 |
|
|
|
76,413 |
|
|
|
76,706 |
|
Contingently issuable shares: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Incentive Plan |
|
|
234 |
|
|
|
212 |
|
|
|
236 |
|
|
|
214 |
|
Accelerated Share Repurchase Program |
|
|
4 |
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average shares of dilutive stock |
|
|
76,371 |
|
|
|
76,915 |
|
|
|
76,651 |
|
|
|
76,920 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Per Share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
.57 |
|
|
$ |
.52 |
|
|
$ |
1.51 |
|
|
$ |
1.45 |
|
Diluted |
|
$ |
.57 |
|
|
$ |
.52 |
|
|
$ |
1.51 |
|
|
$ |
1.44 |
|
7
7. Components of the net periodic benefit cost for our defined-benefit pension plans and our
postretirement health care and life insurance benefits plan for the three months and six months
ended April 30, 2006 and 2005, are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
Other Benefits |
|
In thousands |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Three Months |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
3,149 |
|
|
$ |
2,312 |
|
|
$ |
409 |
|
|
$ |
311 |
|
Interest cost |
|
|
3,971 |
|
|
|
2,628 |
|
|
|
629 |
|
|
|
480 |
|
Expected return on plan assets |
|
|
(4,987 |
) |
|
|
(3,402 |
) |
|
|
(421 |
) |
|
|
(230 |
) |
Amortization of transition obligation |
|
|
|
|
|
|
|
|
|
|
240 |
|
|
|
196 |
|
Amortization of prior-service cost |
|
|
268 |
|
|
|
191 |
|
|
|
|
|
|
|
287 |
|
Amortization of actuarial (gain) loss |
|
|
224 |
|
|
|
78 |
|
|
|
(82 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost |
|
$ |
2,625 |
|
|
$ |
1,807 |
|
|
$ |
775 |
|
|
$ |
1,044 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
6,298 |
|
|
$ |
4,624 |
|
|
$ |
818 |
|
|
$ |
622 |
|
Interest cost |
|
|
7,942 |
|
|
|
5,256 |
|
|
|
1,258 |
|
|
|
960 |
|
Expected return on plan assets |
|
|
(9,974 |
) |
|
|
(6,804 |
) |
|
|
(842 |
) |
|
|
(460 |
) |
Amortization of transition obligation |
|
|
|
|
|
|
|
|
|
|
480 |
|
|
|
392 |
|
Amortization of prior-service cost |
|
|
536 |
|
|
|
382 |
|
|
|
|
|
|
|
574 |
|
Amortization of actuarial (gain) loss |
|
|
448 |
|
|
|
156 |
|
|
|
(164 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost |
|
$ |
5,250 |
|
|
$ |
3,614 |
|
|
$ |
1,550 |
|
|
$ |
2,088 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We estimate that we will contribute $15 million to the pension plans and $2.6 million to the
other postretirement benefits plan in 2006.
8. We have two reportable business segments, regulated utility and non-utility activities. These
segments were identified based on products and services, regulatory environments and our corporate
organization and business decision-making activities. Operations of our regulated utility segment
are conducted by the parent company. Operations of our non-utility activities segment are
comprised of our equity method investments in joint ventures.
Operations of the regulated utility segment are reflected in operating income in the condensed
consolidated statements of income. Operations of the non-utility activities segment are included
in the condensed consolidated statements of income in Income from equity method investments.
We evaluate the performance of the regulated utility segment based on operating income. We
evaluate the performance of the non-utility activities segment based on earnings from the ventures.
The basis of segmentation and the basis of the measurement of segment profit or loss are the same
as reported in the consolidated financial statements for the year ended October 31, 2005.
8
Operations by segment for the three months and six months ended April 30, 2006 and 2005, are
presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated |
|
Non-utility |
|
|
|
|
Utility |
|
Activities |
|
Total |
In thousands |
|
2006 |
|
2005 |
|
2006 |
|
2005 |
|
2006 |
|
2005 |
Three Months |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers |
|
$ |
483,198 |
|
|
$ |
508,035 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
483,198 |
|
|
$ |
508,035 |
|
Operating income (loss) |
|
|
64,471 |
|
|
|
60,012 |
|
|
|
(33 |
) |
|
|
(124 |
) |
|
|
64,438 |
|
|
|
59,888 |
|
Income from equity method investments |
|
|
|
|
|
|
|
|
|
|
20,165 |
|
|
|
14,647 |
|
|
|
20,165 |
|
|
|
14,647 |
|
Income before income taxes and
minority interest |
|
|
51,882 |
|
|
|
49,232 |
|
|
|
20,031 |
|
|
|
15,983 |
|
|
|
71,913 |
|
|
|
65,215 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers |
|
$ |
1,404,545 |
|
|
$ |
1,188,591 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
1,404,545 |
|
|
$ |
1,188,591 |
|
Operating income (loss) |
|
|
190,024 |
|
|
|
183,190 |
|
|
|
(205 |
) |
|
|
(258 |
) |
|
|
189,819 |
|
|
|
182,932 |
|
Income from equity method investments |
|
|
|
|
|
|
|
|
|
|
25,916 |
|
|
|
20,460 |
|
|
|
25,916 |
|
|
|
20,460 |
|
Income before income taxes and
minority interest |
|
|
165,023 |
|
|
|
161,378 |
|
|
|
25,504 |
|
|
|
21,591 |
|
|
|
190,527 |
|
|
|
182,969 |
|
Reconciliations to the condensed consolidated statements of income for the three months and
six months ended April 30, 2006 and 2005, are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Six Months |
|
In thousands |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Operating Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
$ |
64,438 |
|
|
$ |
59,888 |
|
|
$ |
189,819 |
|
|
$ |
182,932 |
|
Utility income taxes |
|
|
(20,271 |
) |
|
|
(19,098 |
) |
|
|
(64,663 |
) |
|
|
(63,357 |
) |
Non-utility activities |
|
|
33 |
|
|
|
124 |
|
|
|
205 |
|
|
|
258 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
44,200 |
|
|
$ |
40,914 |
|
|
$ |
125,361 |
|
|
$ |
119,833 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes and minority interest
for reportable segments |
|
$ |
71,913 |
|
|
$ |
65,215 |
|
|
$ |
190,527 |
|
|
$ |
182,969 |
|
Income taxes |
|
|
(28,171 |
) |
|
|
(25,485 |
) |
|
|
(74,788 |
) |
|
|
(72,061 |
) |
Less minority interest |
|
|
|
|
|
|
98 |
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
43,742 |
|
|
$ |
39,632 |
|
|
$ |
115,739 |
|
|
$ |
110,909 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9. The condensed consolidated financial statements include the accounts of wholly owned
subsidiaries whose investments in joint venture, energy-related businesses are accounted for under
the equity method. Our ownership interest in each entity is included in Equity method investments
in non-utility activities in the condensed consolidated balance sheets. Earnings or losses from
equity method investments are included in Income from equity method investments in the condensed
consolidated statements of income.
We own 21.49% of the membership interests in Cardinal Pipeline Company, L.L.C., a North Carolina
limited liability company. Cardinal owns and operates an intrastate natural gas pipeline in North
Carolina and is regulated by the NCUC. We have related party transactions as a transportation
customer of Cardinal, and we record in cost of gas the transportation costs charged by Cardinal.
These gas costs for the three months and six months ended April 30, 2006 and 2005, are presented
below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Six Months |
|
In thousands |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Transportation Costs |
|
$ |
1,142 |
|
|
$ |
1,142 |
|
|
$ |
2,323 |
|
|
$ |
2,323 |
|
9
As of April 30, 2006 and October 31, 2005, we owed Cardinal $.4 million.
We own 40% of the membership interests in Pine Needle LNG Company, L.L.C., a North Carolina limited
liability company. Pine Needle owns an interstate liquefied natural gas (LNG) storage facility in
North Carolina and is regulated by the Federal Energy Regulatory Commission (FERC). We have
related party transactions as a customer of Pine Needle, and we record in cost of gas the storage
costs charged by Pine Needle. These gas costs for the three months and six months ended April 30,
2006 and 2005, are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Six Months |
|
In thousands |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Storage Costs |
|
$ |
3,059 |
|
|
$ |
3,011 |
|
|
$ |
6,222 |
|
|
$ |
6,114 |
|
As of April 30, 2006 and October 31, 2005, we owed Pine Needle $1 million and $1.1 million,
respectively.
We own 30% of the membership interests in SouthStar Energy Services LLC, a Delaware limited
liability company. Under the terms of an amended and restated limited liability company operating
agreement effective January 1, 2004, earnings and losses are allocated 25% to us and 75% to the
other member. SouthStar sells natural gas to residential, commercial and industrial customers in
the southeastern United States; however, SouthStar conducts most of its business in the unregulated
retail gas market in Georgia. We have related party transactions as we sell wholesale gas supplies
to SouthStar, and we record in operating revenues the amounts billed to SouthStar. Our operating
revenues from these sales for the three months and six months ended April 30, 2006 and 2005, are
presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Six Months |
|
In thousands |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Operating Revenues |
|
$ |
7,346 |
|
|
$ |
2,485 |
|
|
$ |
15,913 |
|
|
$ |
6,009 |
|
As of April 30, 2006 and October 31, 2005, SouthStar owed us $1.5 million and $.9 million,
respectively.
10. We have purchased and sold financial options for natural gas in all three states for our gas
purchase portfolios. The gains or losses on financial derivatives utilized in the regulated
utility segment ultimately will be included in our rates to customers. Current period changes in
the assets and liabilities from these risk management activities are recorded as a component of gas
costs in amounts due to/from customers in accordance with Statement 71. Accordingly, there is no
earnings impact on the regulated utility segment as a result of the use of these financial
derivatives. The fair value of gas purchase options decreased from $22.8 million as of October 31,
2005, to $1.5 million as of April 30, 2006, primarily due to options being exercised or options
expiring during the period and being replaced with options having lower market values.
11. On April 24, 2006, we replaced our expiring $250 million 364-day committed lines of
credit with a syndicated five-year revolving credit facility that includes annual renewal
options. The credit facility has aggregate commitments totaling $350 million, which may
be increased up to $600 million. This facility includes letters of credit. We pay an
annual fee of $35,000 plus six basis points for any unused amount up to $350 million. Outstanding short-term borrowings
increased from $158.5 million as of October 31, 2005, to $252 million as of April 30,
2006, as cash requirements during the period resulted in higher outstanding borrowings.
During the three months ended April 30, 2006, short-term borrowings ranged from $140
million to $333 million, and interest rates ranged from 4.72% to 5.29% (weighted average
of 4.98%). During the six months ended April 30, 2006, short-term borrowings ranged
from $115 million to $378.5 million, and interest
10
rates ranged from 4.07% to 5.29% (weighted average of 4.76%). Our credit facilitys
financial covenants require us to maintain a ratio of total debt to total capitalization of no
greater than 70%.
12. On April 13, 2006, we announced plans to restructure our management group. The restructuring
plans are part of an ongoing, larger effort aimed at streamlining business processes, capturing
operational and organizational efficiencies and improving customer service. The restructuring
began with an offer of early retirement for 23 employees in our management group, and will
eventually include the further consolidation and reorganization of management positions and
functions. The programs cost is estimated to be $7 to 8 million.
During the quarter ended April 30, 2006, we recognized a liability and an expense of $4.4 million
which was included in operations and maintenance expense for the cost of the early retirement
program. Due to the short discount period, the liability for the program was recorded at its gross
value. Additional costs will be accrued in the third quarter ending July 31 as the restructuring
effort is completed for all management positions.
13. At our annual meeting of shareholders held March 3, 2006, shareholders approved the Piedmont
Natural Gas Company, Inc. Incentive Compensation Plan (Plan) effective November 1, 2005. The Plan
permits the grant of annual incentive awards, performance awards, restricted stock, stock options
and stock appreciation rights to eligible employees and members of the Board of Directors. As of
April 30, 2006, no awards have been granted under the Plan.
14. In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47,
Accounting for Conditional Asset Retirement Obligations (FIN 47), to clarify the term
conditional asset retirement as used in SFAS No. 143, Accounting for Asset Retirement
Obligations. FIN 47 requires that a liability be recognized for the fair value of a conditional
asset retirement obligation when incurred, if the fair value of the liability can be reasonably
estimated. Uncertainty about the timing or method of settlement of a conditional asset retirement
obligation would be factored into the measurement of the liability when sufficient information
exists. This interpretation is effective no later than the end of fiscal years ending after
December 15, 2005. Accordingly, we will adopt FIN 47 no later than our fourth fiscal quarter in
2006. We are currently assessing the impact FIN 47 may have on our consolidated balance sheet;
however, we believe the adoption of FIN 47 will not have a material impact on our financial
position, results of operations or cash flows.
In April 2006, the FASB issued FASB Staff Position No. FIN 46(R)-6, Determining the Variability to
Be Considered in Applying FASB Interpretation No. 46(R) (FIN 46(R)-6). FIN 46(R)-6 addresses how
a reporting enterprise should determine the variability to be considered in applying FASB
Interpretation No. 46(R) (revised December 2003), Consolidation of Variable Interest Entities
(VIEs) (FIN 46(R)), by evaluating the entitys design. FIN 46(R)-6 provides guidance regarding how
contracts or arrangements that create or reduce variability should be considered when determining
whether entities qualify as VIEs. This interpretation addresses consolidation by business
enterprises of entities in which equity investors do not have the characteristics of a controlling
financial interest or do not have sufficient equity at risk for the entity to finance its
activities without additional subordinated financial support from other parties. Under FIN
46(R)-6, consolidation of a VIE by the primary beneficiary is required if it is determined that the
VIE does not effectively disperse risks among the parties involved. The primary beneficiary is the
party that has either a majority of the expected losses or a majority of the expected residual
returns of such entity, as defined. The guidance of FIN 46(R)-6 must be applied on a prospective
basis in reporting periods beginning after June 15, 2006, which would be our fourth fiscal quarter.
The new requirements do not need to be applied to existing entities unless a reconsideration event
occurs. We are currently evaluating the impact of adopting FIN 46(R)-6.
15. Subsequent to the issuance of our condensed consolidated financial statements for the period
ended April 30, 2005, management identified errors in the condensed consolidated statement of cash
flows relating to
11
distributions of earnings received from equity method investees, changes in
restricted cash and the amounts
reported as construction expenditures. As a result, the accompanying condensed consolidated
statement of cash flows for the six months ended April 30, 2005, has been restated from the amounts
previously reported to correct the presentation of these items. The restatement did not affect
previously reported operating income, net income, earnings per share or stockholders equity.
A summary of the significant effects of the restatement of the condensed consolidated statement of
cash flows for the six months ended April 30, 2005, is as follows:
|
|
|
|
|
|
|
|
|
|
|
As Previously |
|
|
In thousands |
|
Reported |
|
As Restated |
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
Distributions of earnings from equity method investments |
|
$ |
|
|
|
$ |
21,164 |
|
Net cash provided by operating activities |
|
|
196,521 |
|
|
|
219,533 |
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Distributions of capital from equity method investments |
|
|
21,958 |
|
|
|
794 |
|
Decrease (increase) in restricted cash |
|
|
|
|
|
|
(147 |
) |
Net cash used in investing activities |
|
|
(38,682 |
) |
|
|
(61,694 |
) |
Item 2. Managements Discussion and Analysis of Financial Condition and Results of
Operations
The following discussion gives effect to the restatement of the condensed consolidated statement of
cash flows discussed in Note 15 to the condensed consolidated financial statements.
Overview
Piedmont Natural Gas Company is an energy services company primarily engaged in the distribution of
natural gas to residential, commercial and industrial customers in portions of North Carolina,
South Carolina and Tennessee. We also have equity method investments in joint venture,
energy-related businesses. Our operations are comprised of two business segments.
The regulated utility segment is the largest segment of our business with approximately 95% of our
consolidated assets. This segment is regulated by three state regulatory commissions that approve
rates and tariffs that are designed to give us the opportunity to generate revenues to cover our
gas and non-gas costs and to earn a fair rate of return for our shareholders. Factors critical to
the success of the regulated utility include a safe, reliable natural gas distribution system and
the ability to recover the costs and expenses of the business in rates charged to customers. For
the six months ended April 30, 2006, 87% of our earnings before taxes came from our regulated
utility segment.
The non-utility activities segment consists of our equity method investments in joint venture,
energy-related businesses that are involved in unregulated retail natural gas marketing, interstate
natural gas storage and intrastate natural gas transportation. We invest in joint ventures that
are aligned with our business strategies to complement or supplement income from utility
operations. We continually monitor performance of these ventures against expectations.
Weather conditions directly influence the volumes of natural gas delivered by the regulated
utility. Significant portions of our revenues are generated during the winter season. During warm
winters or unevenly cold winters, heating customers may significantly reduce their consumption of
natural gas. Through October 31, 2005, we had weather normalization adjustment (WNA) mechanisms in
all states that are designed to protect a portion of our revenues against warmer-than-normal
weather as deviations from normal weather can affect our
12
financial performance and liquidity. The
WNA also serves to offset the impact of colder-than-normal weather
by reducing the amounts we can charge our customers. In a general rate case proceeding during
2005, the NCUC ordered the establishment of a Customer Utilization Tracker (CUT) and the
elimination of the WNA effective November 1, 2005. The CUT provides for the recovery of our
approved margin per customer independent of weather or other usage and consumption patterns of
residential and commercial customers. For further information, see Our Business in Managements
Discussion and Analysis of Financial Condition and Results of Operations.
Over the past few years, there have been significant increases in the wholesale cost of natural
gas. The relationship between supply and demand has the greatest impact on wholesale gas prices.
Increased prices of natural gas are being driven by increased demand that is exceeding the growth
in accessible supply. Continued high gas prices could shift our customers preference away from
natural gas toward other energy sources, particularly in the industrial market. High gas prices
could also affect consumption levels as customers react to high bills. We expect that the
wholesale price of natural gas will remain high and volatile until natural gas supply and demand
are in better balance.
The majority of our natural gas supplies come from the Gulf Coast region. We believe that
diversification of our supply portfolio is in our customers best interest. We have a firm
transportation contract pending for additional pipeline capacity that will provide access to
Canadian and Rocky Mountain gas supplies via the Chicago hub, primarily to serve our Tennessee
markets. It is anticipated that this new capacity will be available for the 2006-2007 winter. We
have also executed an agreement with Hardy Storage Company LLC for market-area storage capacity in
West Virginia with an anticipated in-service date in 2007.
Although we have been operating in a relatively low-interest-rate environment for both short- and
long-term debt financing during the past few years, the federal funds rate has steadily increased
and is the highest it has been in over four years. As interest rates rise, we will continue to see
increases in rates on our borrowings.
Part of our strategic plan is to manage our gas distribution business through sound rate and
regulatory initiatives, control of our operating costs and implementation of new technologies. We
are working to enhance the value and growth of our utility assets by good management of capital
spending, including improvements for current customers and the pursuit of customer growth
opportunities in our service areas. We strive for quality customer service by investing in
systems, processes and people. We work with our state regulators to maintain fair rates of return
and balance the interests of our customers and shareholders.
Our strategic plan includes a focus on maintaining a debt-to-capitalization ratio within a range of
45 to 50%. We will continue to stress the importance of maintaining a strong balance sheet and
investment-grade credit ratings to support our operating and investment needs.
As part of an ongoing, larger effort aimed at streamlining business processes, capturing
operational and organizational efficiencies and improving customer service, we announced plans to
restructure our management group on April 13, 2006. We expect the restructuring to generate
savings of $5 to 6 million annually beginning in fiscal 2007. For further information, see Note 12
to the condensed consolidated financial statements.
Results of Operations
Operating Revenues
Operating revenues decreased $24.8 million for the three months ended April 30, 2006, compared with
the similar period in 2005 primarily due to the following:
13
|
|
|
$43.2 million decrease resulting from a 12% decrease, 7.2 million dekatherms, in volumes
delivered primarily due to warmer weather and customer conservation. |
|
|
|
|
$16 million increase from the CUT mechanism. |
|
|
|
|
$6.1 million reduction in WNA credits from the similar prior period. |
Operating revenues increased $216 million for the six months ended April 30, 2006, compared with
the similar period in 2005 primarily due to the following increases:
|
|
|
$268.8 million from increased commodity gas costs passed through to customers. |
|
|
|
|
$20.1 million from rate design changes in North Carolina and South Carolina effective
November 1, 2005. |
|
|
|
|
$25.6 million net increase in North Carolina resulting from $29.3 million from the CUT
mechanism compared with $3.7 million of WNA surcharges for the similar prior period. For
further discussion of the regulatory mechanisms effective November 1, 2005, see Our
Business in Managements Discussion and Analysis of Financial Condition and Results of
Operations. |
These increases were partially offset by a decrease of $113.3 million resulting from a 10%
decrease, 12.8 million dekatherms, in volumes delivered primarily due to warmer weather and
customer conservation.
Cost of Gas
Cost of gas decreased $38.2 million for the three months ended April 30, 2006, compared with the
similar period in 2005 primarily due to decreases of $31.4 million resulting from a decrease in
volumes delivered of 7.2 million dekatherms and $3.2 million from secondary market transactions.
These decreases were partially offset by an increase of $2 million from increased commodity gas
costs.
Cost of gas increased $195.8 million for the six months ended April 30, 2006, compared with the
similar period in 2005 primarily due to increases of $268.8 million from increased commodity gas
costs and $9.3 million from secondary market transactions. These increases were partially offset
by a decrease of $88.2 million resulting from a decrease in volumes delivered of 12.8 million
dekatherms.
Under purchased gas adjustment (PGA) procedures in all three states, we revise rates periodically
without formal rate proceedings to reflect changes in the wholesale cost of gas. Charges to cost
of gas are based on the amount recoverable under approved rate schedules. The net of any over- or
under-recoveries of gas costs are added to or deducted from cost of gas and included in Amounts
due from customers or Amounts due to customers in the condensed consolidated balance sheets.
In North Carolina and South Carolina, recoveries of gas costs are subject to annual gas cost
recovery proceedings to determine the prudence of our gas purchases. We have been found prudent in
all such past proceedings.
Margin
Margin increased $13.4 million for the three months ended April 30, 2006, and $20.1 million for the
six months ended April 30, 2006, compared with the similar periods in 2005 primarily due to growth
in the residential and commercial customer base and the impact of changes in rate design and
regulatory mechanisms effective November 1, 2005. These increases were partially offset by
decreased consumption primarily due to warmer weather and customer conservation. Implementation of
the CUT has partially mitigated both these factors in North Carolina.
14
Operations and Maintenance Expenses
Operations and maintenance expenses increased $7.4 million for the three months ended April 30,
2006, compared with the similar period in 2005 primarily due to the following increases:
|
|
|
$4.4 million in restructuring costs associated with the early retirement program. |
|
|
|
|
$2 million in outside services for the customer service contact center. |
|
|
|
|
$.9 million in payroll costs due to an increase in the costs associated with customer
service and accrued long-term incentive plan liability. |
|
|
|
|
$.7 million in employee benefits expense primarily due to increases in pension and group
health insurance costs, partially offset by decreases in postretirement health care and
life insurance costs. |
|
|
|
|
$.6 million in rents and leases due to the new corporate office space and telecommunications costs. |
|
|
|
|
$.4 million in conservation programs ordered by the NCUC. |
These increases were partially offset by a decrease of $1.3 million in the provision for
uncollectibles. Effective November 1, 2005, the NCUC approved the recovery of all uncollected gas
costs through the gas cost deferred account. As a result, only the portion of accounts written off
relating to non-gas costs, or margin, is included in base rates and, accordingly, only this portion
is included in the provision for uncollectibles expense. A similar mechanism has been in place for
our Tennessee operations since March 2004 whereby uncollected gas costs in excess of, or less than,
those allowed in base rates are recovered from, or refunded to, customers through PGA procedures.
Operations and maintenance expenses increased $10.4 million for the six months ended April 30,
2006, compared with the similar period in 2005 primarily due to the following increases:
|
|
|
$4.4 million in restructuring costs associated with the early retirement program. |
|
|
|
|
$2.6 million in outside services for the customer service contact center and for the
move to the new corporate office building. |
|
|
|
|
$1.5 million in payroll costs due to an increase in the costs associated with customer
service and accrued long-term incentive plan liability. |
|
|
|
|
$1.5 million in employee benefits expense primarily due to increases in pension and
group health insurance costs, partially offset by decreases in postretirement health care
and life insurance costs. |
|
|
|
|
$1.4 million in rents and leases due to the new corporate office space and telecommunications costs. |
|
|
|
|
$.4 million in conservation programs ordered by the NCUC. |
|
|
|
|
$.5 million in regulatory expense primarily due to fees to our state regulatory
commissions that are based on revenues. |
These increases were partially offset by a decrease of $2.1 million in the provision for
uncollectibles.
Depreciation
Depreciation expense increased $.8 million for the three months ended April 30, 2006, and $1.9
million for the six months ended April 30, 2006, compared with the similar periods in 2005
primarily due to increases in plant in service.
General Taxes
General taxes increased $.7 million for the three months ended April 30, 2006, and $1 million for
the six months ended April 30, 2006, compared with the similar periods in 2005 primarily due to increases in property
15
taxes resulting from higher tax values and tax rates.
Other Income (Expense)
Income from equity method investments increased $5.5 million for the three months and six months
ended April 30, 2006, compared with the similar periods in 2005 primarily due to increases in
earnings from SouthStar.
Gain on Sale of Marketable Securities
For the three months and six months ended April 30, 2005, the gain on sale of marketable securities
resulted from the sale in February 2005 of 37,244 common units of Energy Transfer Partners, L.P.,
which we acquired in connection with the sale of our propane interests in January 2004. Total
proceeds from the sale were $2.4 million and resulted in a before-tax gain of $1.5 million.
Utility Interest Charges
Utility interest charges increased $1.7 million for the three months ended April 30, 2006, compared
with the similar period in 2005 primarily due to the following:
|
|
|
$2.4 million increase in interest on short-term debt due to higher balances outstanding
at interest rates that were approximately two percentage points higher in the current
period. See further discussion in Financial Condition and Liquidity. |
|
|
|
|
$.6 million decrease in net interest expense on amounts due to/from customers due to
higher net receivables in 2006. |
Utility interest charges increased $2.5 million for the six months ended April 30, 2006, compared
with the similar period in 2005 primarily due to the following:
|
|
|
$4.2 million increase in interest on short-term debt due to higher balances outstanding
at interest rates that were approximately two percentage points higher in the current
period. |
|
|
|
|
$1.4 million decrease in net interest expense on amounts due to/from customers due to
higher net receivables in 2006. |
Our Business
Piedmont Natural Gas Company, Inc., is an energy services company primarily engaged in the
distribution of natural gas to 990,000 residential, commercial and industrial customers in portions
of North Carolina, South Carolina and Tennessee, including 61,000 customers served by
municipalities who are our wholesale customers. We are invested in joint venture, energy-related
businesses, including unregulated retail natural gas marketing, interstate natural gas storage and
intrastate natural gas transportation.
We continually assess the nature of our business and explore alternatives to traditional utility
regulation. Non-traditional ratemaking initiatives and market-based pricing of products and
services provide additional challenges and opportunities for us. We also regularly evaluate
opportunities for obtaining natural gas supplies from different production regions and supply
sources to maximize our natural gas portfolio flexibility and reliability, including the
diversification of our supply portfolio through pipeline capacity arrangements that access new
sources of supply and market-area storage and that diversify supply concentration away from the
Gulf Coast region. We have a firm transportation contract pending with Midwestern Gas Transmission
Company for 120,000 dekatherms per day of additional pipeline capacity that will provide access to
Canadian
16
and Rocky Mountain gas supplies via the Chicago hub, primarily to serve our Tennessee
markets. It is anticipated to be in-service for the 2006-2007 winter. We have also executed an
agreement with Hardy
Storage Company LLC for market-area storage capacity in West Virginia with an anticipated
in-service date in 2007. We have a 50% equity interest in this project.
We have two reportable business segments, regulated utility and non-utility activities. For
further information on business segments, see Note 8 to the condensed consolidated financial
statements.
Our utility operations are regulated by the NCUC, the Public Service Commission of South Carolina
and the Tennessee Regulatory Authority as to rates, service area, adequacy of service, safety
standards, extensions and abandonment of facilities, accounting and depreciation. We are also
regulated by the NCUC as to the issuance of securities. We are also subject to or affected by
various federal regulations. These federal regulations include regulations that are particular to
the natural gas industry, such as regulations of the FERC that affect the availability of and the
prices paid for the interstate transportation of natural gas, regulations of the Department of
Transportation that affect the construction, operation, maintenance, integrity and safety of
natural gas distribution systems and regulations of the Environmental Protection Agency relating to
the use and release into the environment of hazardous wastes. In addition, we are subject to
numerous regulations, such as those relating to employment practices, which are generally
applicable to companies doing business in the United States of America.
In the Carolinas, our service area is comprised of numerous cities, towns and communities including
Anderson, Greenville and Spartanburg in South Carolina and Charlotte, Salisbury, Greensboro,
Winston-Salem, High Point, Burlington, Hickory, Spruce Pine, Reidsville, Fayetteville, New Bern,
Wilmington, Tarboro, Elizabeth City, Rockingham and Goldsboro in North Carolina. In North
Carolina, we also provide wholesale natural gas service to Greenville, Monroe, Rocky Mount and
Wilson. In Tennessee, our service area is the metropolitan area of Nashville, including wholesale
natural gas service to Gallatin and Smyrna.
Our regulatory commissions approve rates and tariffs that are designed to give us the opportunity
to generate revenues to cover our gas and non-gas costs and to earn a fair rate of return for our
shareholders. Through October 31, 2005, we had WNA mechanisms in all three states that partially
offset the impact of unusually cold or warm weather on bills rendered during the months of November
through March for weather-sensitive customers. The WNA formula calculates the actual weather
variance from normal, using 30 years of history, which results in an increase in revenues when
weather is warmer than normal and a decrease in revenues when weather is colder than normal. The
gas cost portion of our costs is recoverable through PGA procedures and is not affected by the WNA.
Effective November 1, 2005, the WNA was eliminated in North Carolina and replaced with the CUT
that provides for the recovery of our approved margin per customer independent of weather or other
usage and consumption patterns of residential and commercial customers. The CUT tracks our margin
earned monthly and will result in semi-annual rate adjustments to refund any over-collection or
recover any under-collection.
On January 3, 2006, the North Carolina Office of the Attorney General filed a notice of appeal in
the general rate case proceeding challenging the lawfulness of the NCUCs authorization and
approval of the CUT. On April 6, the Attorney General filed a Notice of Appeal and Exceptions to
the NCUCs March 28, 2006, order approving the first adjustment filing under the CUT. This appeal
is not substantively different from the appeal of the CUT mechanism. We believe the CUT is lawful,
just and reasonable and reflects good public policy, and we intend to vigorously defend the NCUCs
action authorizing and approving the CUT. We have entered into settlement negotiations with the
Attorney Generals office. We are unable to predict the outcome of the appeals, the settlement
discussions or any potential impact to our rates, charges or terms and conditions of service should
the NCUC orders be reversed or remanded.
17
We invest in joint ventures to complement or supplement income from our regulated utility
operations. If an opportunity aligns with our overall business strategies, we analyze and evaluate
the project with a major factor
being a projected rate of return greater than the returns allowed in our utility operations, due to
the higher risk of such projects. We participate in the governance of the venture by having a
management representative on the governing board of the venture. We monitor actual performance
against expectations. Decisions regarding exiting joint ventures are based on many factors,
including performance results and continued alignment with our business strategies.
Financial Condition and Liquidity
To meet our capital and liquidity requirements, we rely on certain resources that are available to
us, including cash flows from operating activities, access to capital markets, cash generated from
our investments in joint ventures and short-term bank borrowings. We believe that these sources
will continue to allow us to meet our needs for working capital, construction expenditures,
anticipated debt redemptions and dividend payments.
Cash Flows from Operating Activities. The natural gas business is seasonal in nature.
Operating cash flows may fluctuate significantly during the year and from year to year due to
working capital changes within our utility and non-utility operations resulting from such factors
as weather, natural gas purchases and prices, gas inventory storage activity, collections from
customers and deferred gas cost recoveries. We rely on operating cash flows and short-term bank
borrowings to meet seasonal working capital needs. During our first and second quarters, we
generally experience overall positive cash flows from the sale of flowing gas and gas in storage
and the collection of amounts billed to customers during the peak heating season (November through
March). Cash requirements generally increase during the third and fourth quarters due to increases
in natural gas purchases for storage and decreases in receipts from customers.
During the peak heating season, our accounts payable increase to reflect amounts due to our natural
gas suppliers for commodity and pipeline capacity. The value of the gas can vary significantly
from period to period due to volatility in the price of natural gas. Our natural gas costs and
amounts due to/from customers represent the difference between natural gas costs that we have paid
to suppliers and amounts that we have collected from customers. These natural gas costs can cause
cash flows to vary significantly from period to period.
Cash flows from operations are impacted by weather, which affects gas purchases and sales. Warmer
weather can lead to lower revenues from fewer volumes of natural gas sold or transported. Colder
weather can increase volumes sold to weather-sensitive customers, but may lead to conservation by
customers in order to reduce their consumption. Temperatures above normal can lead to reduced
operating cash flows, thereby increasing the need for short-term borrowings to meet current cash
requirements.
Net cash provided by operating activities was $71.2 million and $219.5 million for the six months
ended April 30, 2006 and 2005, respectively. Our cash needs for working capital have increased
substantially as a result of significant increases in the wholesale prices of natural gas. Net
cash provided by operating activities reflects a $4.8 million increase in net income for the six
months ended April 30, 2006, compared with the similar 2005 period, as well as changes in working
capital as described below:
|
|
|
Trade accounts receivable and unbilled utility revenues increased $19.4 million,
primarily due to higher commodity gas costs in the 2005-2006 winter heating season even
though the current winter period was 9% warmer than normal and 5% warmer than the similar
prior period. |
|
|
|
|
Inventories decreased $10 million primarily due to reduced withdrawals as warmer weather
was experienced during the current period. |
|
|
|
|
Trade accounts payable generated a use of cash of $104 million in the current period
compared with a source of cash of $16.6 million in the prior period primarily due to an
increase in wholesale natural gas prices.
|
18
The financial condition of the natural gas marketers and pipelines that supply and deliver natural
gas to our distribution system can increase our exposure to supply and price fluctuations. We
believe our risk exposure to the financial condition of the marketers and pipelines is not
significant based on our receipt of the products and services prior to payment and the availability
of other marketers of natural gas to meet our firm supply needs if necessary. We currently have
petitions before our regulatory commissions that would place further credit requirements on the
retail natural gas marketers using our system.
The regulated utility competes with other energy products, such as electricity and propane, in the
residential and commercial customer markets. The most significant product competition is with
electricity for space heating, water heating and cooking. Numerous factors can influence customer
demand for natural gas, such as price volatility, the availability of natural gas in relation to
other energy forms, general economic conditions, weather, energy conservation, the ability to
convert from natural gas to other energy sources, and legislation. Increases in the price of
natural gas can negatively impact our competitive position by decreasing the price benefits of
natural gas to the consumer. This can impact our cash needs if customer growth slows, resulting in
reduced capital expenditures, or if customers conserve, resulting in reduced gas purchases and
customer billings.
In the industrial market, many of our customers are capable of burning a fuel other than natural
gas, with fuel oil being the most significant competing energy alternative. Our ability to
maintain industrial market share is largely dependent on price. The relationship between supply
and demand has the greatest impact on the price of natural gas. With a tighter balance between
domestic supply and demand, the cost of natural gas from non-domestic sources may play a greater
role in establishing the future market price of natural gas. The price of oil depends upon a
number of factors beyond our control, including the relationship between supply and demand and the
policies of foreign and domestic governments and organizations. Our liquidity could be impacted,
either positively or negatively, as a result of alternate fuel decisions made by industrial
customers.
Cash Flows from Investing Activities. Net cash used in investing activities was $78.6
million and $61.7 million for the six months ended April 30, 2006 and 2005, respectively. Net cash
used in investing activities was primarily for utility construction expenditures. Gross utility
construction expenditures for the six months ended April 30, 2006, were $100.8 million, a 19%
increase over the $84.4 million in 2005, primarily due to expenditures for the automated meter
reading project. Reimbursements from the bond fund decreased $6.1 million from 2005 as
construction of gas infrastructure in eastern North Carolina is nearing completion. Due to
projected growth in our service areas, significant utility construction expenditures are expected
to continue and are a part of our long-range forecasts that are prepared at least annually and
typically cover a forecast period of five years.
During the six months ended April 30, 2006, we contributed $5.6 million to Hardy Storage Company
LLC, an investee of one of our subsidiaries, for construction of the storage facility. We will
make an additional cash contribution in the third quarter of 2006 of $18.1 million.
During the six months ended April 30, 2006, the restrictions on cash totaling $13.1 million were
removed in connection with implementing the NCUC order in the general rate proceeding discussed in
Note 4 to the condensed consolidated financial statements. As ordered by the NCUC, such cash had
been held in an expansion fund to extend natural gas service to unserved areas of the state.
Cash Flows from Financing Activities. Net cash provided by (used in) financing activities
was $20.7 million and ($143.5) million for the six months ended April 30, 2006 and 2005,
respectively. Funds are primarily provided from bank borrowings and the issuance of common stock
through dividend reinvestment and employee stock plans, net of purchases under the common stock
repurchase program. We sell common stock
19
and long-term debt to cover cash requirements when market
and other conditions favor such long-term financing.
As of April 30, 2006, we had committed lines of credit of $350 million with the ability to expand
up to $600 million. Outstanding short-term borrowings increased from $158.5 million as of October
31, 2005, to $252 million as of April 30, 2006, as working capital needs during the period resulted
in higher outstanding borrowings under our short-term lines of credit. During the six months ended
April 30, 2006, short-term borrowings ranged from $115 million to $378.5 million, and interest
rates ranged from 4.07% to 5.29% (weighted average of 4.76%).
As of April 30, 2006, we had a line of credit for letters of credit of $5 million under our new
syndicated five-year revolving credit facility, of which $1.2 million were issued and outstanding.
These letters of credit are used to guarantee claims from self-insurance under our general
liability policies.
The level of short-term borrowings can vary significantly due to changes in the wholesale prices of
natural gas and to the level of purchases of natural gas supplies to serve customer demand and for
storage. Short-term debt may increase when wholesale prices for natural gas increase because we
must pay suppliers for the gas before we collect our costs from customers through their monthly
bills. Gas prices could continue to increase and fluctuate. If wholesale gas prices remain high,
we may incur more short-term debt to pay for natural gas supplies and other operating costs since
collections from customers could be slower and some customers may not be able to pay their gas
bills on a timely basis.
During the six months ended April 30, 2006, we issued $10.3 million of common stock through
dividend reinvestment and stock purchase plans. On April 7, 2006, we entered into an accelerated
share repurchase (ASR) program and repurchased and retired 1 million shares of common stock for
$23.9 million. Through the ASR program, we will repurchase and subsequently retire approximately
four million shares of common stock over a four-year period, including the 1 million shares
repurchased in April 2006. These repurchases are in addition to shares that are repurchased on a
normal basis through the open market program. Under the Common Stock Open Market Purchase Program,
we paid $46.8 million during the six months ended April 30, 2006, for 2 million shares of common
stock, including the shares under the ASR, that are available for reissuance to these plans.
During the six months ended April 30, 2005, .6 million shares were repurchased for $13 million.
We have paid quarterly dividends on our common stock since 1956. The amount of cash dividends that
may be paid is restricted by provisions contained in certain note agreements under which long-term
debt was issued. As of April 30, 2006, none of our retained earnings was restricted. On June 7,
2006, the Board of Directors declared a quarterly dividend on common stock of $.24 per share,
payable July 14 to shareholders of record at the close of business on June 22.
As of April 30, 2006, our capitalization, including current maturities of long-term debt, consisted
of 41% in long-term debt and 59% in common equity. Our long-term targeted capitalization ratio is
45-50% in long-term debt and 50-55% in common equity.
In July 2006, we expect to make the scheduled payment of $35 million on the 9.44% senior notes.
Depending upon our needs for long-term financing and current market conditions, we expect to issue
approximately $200 million of long-term debt in our fiscal third quarter in 2006 under a shelf
registration which has a remaining balance of $309.4 million.
Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such
financings. In determining our credit ratings, the rating agencies consider a number of
quantitative factors, including debt
20
to total capitalization, operating cash flows relative to
outstanding debt, operating cash flow coverage of interest and pension liabilities and funding
status. Rating agencies also consider qualitative factors, such as the
consistency of our earnings over time, the quality of management and business strategy, the risks
associated with our utility and non-utility businesses and the regulatory commissions that
establish rates in the states where we operate.
As of April 30, 2006, all of our long-term debt was unsecured. Our long-term debt is rated A by
Standard & Poors Ratings Services and A3 by Moodys Investors. Currently, with respect to our
long-term debt, the credit agencies maintain their stable outlook. There is no guarantee that a
rating will remain in effect for any given period of time or that a rating will not be lowered or
withdrawn by a rating agency if, in its judgment, circumstances warrant a change.
We are subject to default provisions related to our long-term debt and short-term borrowings.
Failure to satisfy any of the default provisions would result in total outstanding issues of debt
becoming due. There are cross-default provisions in all our debt agreements. As of April 30,
2006, we are in compliance with all default provisions.
Estimated Future Contractual Obligations
During the three months ended April 30, 2006, there were no material changes to our estimated
future contractual obligations that were disclosed in our Form 10-K for the year ended October 31,
2005, in Managements Discussion and Analysis of Financial Condition and Results of Operations.
Off-balance Sheet Arrangements
Piedmont has no off-balance sheet arrangements other than operating leases that were discussed in
Note 7 to the consolidated financial statements in our Form 10-K for the year ended October 31,
2005.
Critical Accounting Policies and Estimates
We prepare the consolidated financial statements in conformity with accounting principles generally
accepted in the United States of America. We make estimates and assumptions that affect the
reported amounts of assets and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the periods reported. Actual results may differ
significantly from these estimates and assumptions. We base our estimates on historical
experience, where applicable, and other relevant factors that we believe are reasonable under the
circumstances. On an ongoing basis, we evaluate estimates and assumptions and make adjustments in
subsequent periods to reflect more current information if we determine that modifications in
assumptions and estimates are warranted.
Management considers an accounting estimate to be critical if it requires assumptions to be made
that were uncertain at the time the estimate was made and changes in the estimate or a different
estimate that could have been used would have had a material impact on our financial condition or
results of operations. We consider regulatory accounting, revenue recognition, goodwill and
pension and postretirement benefits to be our critical accounting estimates. Management is
responsible for the selection of the critical accounting estimates presented in our Form 10-K for
the year ended October 31, 2005, in Managements Discussion and Analysis of Financial Condition
and Results of Operations. Management has discussed these critical accounting estimates with the
Audit Committee of the Board of Directors. There have been no changes in our critical accounting
policies and estimates since October 31, 2005.
21
Recent Accounting Pronouncements
In March 2005, the FASB issued Interpretation No. 47, Accounting for Conditional Asset Retirement
Obligations (FIN 47), to clarify the term conditional asset retirement as used in SFAS No. 143,
Accounting for Asset Retirement Obligations. FIN 47 requires that a liability be recognized for
the fair value of a conditional asset retirement obligation when incurred, if the fair value of the
liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a
conditional asset retirement obligation would be factored into the measurement of the liability
when sufficient information exists. This interpretation is effective no later than the end of
fiscal years ending after December 15, 2005. Accordingly, we will adopt FIN 47 no later than our
fourth fiscal quarter in 2006. We are currently assessing the impact FIN 47 may have on our
consolidated balance sheet; however, we believe the adoption of FIN 47 will not have a material
impact on our financial position, results of operations or cash flows.
In April 2006, the FASB issued FASB Staff Position No. FIN 46(R)-6, Determining the Variability to
Be Considered in Applying FASB Interpretation No. 46(R) (FIN 46(R)-6). FIN 46(R)-6 addresses how
a reporting enterprise should determine the variability to be considered in applying FASB
Interpretation No. 46(R) (revised December 2003), Consolidation of Variable Interest Entities
(VIEs) (FIN 46(R)), by evaluating the entitys design. FIN 46(R)-6 provides guidance regarding how
contracts or arrangements that create or reduce variability should be considered when determining
whether entities qualify as VIEs. This interpretation addresses consolidation by business
enterprises of entities in which equity investors do not have the characteristics of a controlling
financial interest or do not have sufficient equity at risk for the entity to finance its
activities without additional subordinated financial support from other parties. Under FIN
46(R)-6, consolidation of a VIE by the primary beneficiary is required if it is determined that the
VIE does not effectively disperse risks among the parties involved. The primary beneficiary is the
party that has either a majority of the expected losses or a majority of the expected residual
returns of such entity, as defined. The guidance of FIN 46(R)-6 must be applied on a prospective
basis in reporting periods beginning after June 15, 2006, which would be our fourth fiscal quarter.
The new requirements do not need to be applied to existing entities unless a reconsideration event
occurs. We are currently evaluating the impact of adopting FIN 46(R)-6.
Recent Developments
In May 2006, the Internal Revenue Service began an audit of the Companys income tax return for the
tax years ended October 31, 2003 and 2004. We are unable to predict the impact that the audit may
have on our financial position or results of operations.
Forward-Looking Statements
Documents we file with the SEC may contain forward-looking statements. In addition, our senior
management and other authorized spokespersons may make forward-looking statements in print or
orally to analysts, investors, the media and others. These statements are based on managements
current expectations and information currently available and are believed to be reasonable and are
made in good faith. However, the forward-looking statements are subject to risks and uncertainties
that could cause actual results to differ materially from those projected in the statements.
Factors that may make the actual results differ from anticipated results include, but are not
limited to:
|
|
|
Regulatory issues, including those that affect allowed rates of return, terms and
conditions of service, rate structures and financings. We monitor our effectiveness in
achieving the allowed rates of return and initiate rate proceedings or operating changes
as needed. In addition, we purchase natural gas transportation and storage services from
interstate and intrastate pipeline companies whose rates and services are regulated. |
22
|
|
|
Residential, commercial and industrial growth in our service areas. The ability to
grow our customer base and the pace of that growth are impacted by general business and
economic conditions such as interest rates, inflation, fluctuations in the capital markets
and the overall strength of the economy in our service areas and the country, and
fluctuations in the wholesale prices of natural gas and competitive energy sources. |
|
|
|
|
Deregulation, regulatory restructuring and competition in the energy industry. We face
competition from electric companies and energy marketing and trading companies, and we
expect this highly competitive environment to continue. We must be able to adapt to the
changing environments and the competition. |
|
|
|
|
The potential loss of large-volume industrial customers to alternate fuels or to
bypass, or the shift by such customers to special competitive contracts at lower per-unit
margins. |
|
|
|
|
Regulatory issues, customer growth, deregulation, economic and capital market
conditions, the cost and availability of natural gas and weather conditions can impact our
ability to meet internal performance goals. |
|
|
|
|
The capital-intensive nature of our business. In order to maintain growth, we must add
to our natural gas distribution system each year. The cost of this construction may be
affected by the cost of obtaining governmental approvals, compliance with federal and
state pipeline safety and integrity regulations, development project delays and changes in
project costs. Weather, general economic conditions and the cost of funds to finance our
capital projects can materially alter the cost of a project. Our internally generated
cash flows are not adequate to finance the full cost of this construction. As a result,
we rely on access to both short-term and long-term capital markets as a significant source
of liquidity for capital requirements not satisfied by cash flows from operations. |
|
|
|
|
Changes in the availability and cost of natural gas. To meet firm customer
requirements, we must acquire sufficient gas supplies and pipeline capacity to ensure
delivery to our distribution system while also ensuring that our supply and capacity
contracts allow us to remain competitive. Natural gas is an unregulated commodity market
subject to supply and demand and price volatility. Producers, marketers and pipelines are
subject to operating and financial risks associated with exploring, drilling, producing,
gathering, marketing and transporting natural gas and have risks that increase our
exposure to supply and price fluctuations. |
|
|
|
|
Changes in weather conditions. Weather conditions and other natural phenomena can have
a material impact on our earnings. Severe weather conditions, including destructive
weather patterns such as hurricanes, can impact our suppliers and the pipelines that
deliver gas to our distribution system. Weather conditions directly influence the supply
of, demand for and the cost of natural gas. |
|
|
|
|
Changes in environmental, safety and system integrity regulations and the cost of
compliance. We are subject to extensive federal, state and local regulations. Compliance
with such regulations may result in increased capital or operating costs. |
|
|
|
|
Ability to retain and attract professional and technical employees. To provide quality
service to our customers and meet regulatory requirements, we are dependent on our ability
to recruit, train, motivate and retain qualified employees. |
|
|
|
|
Changes in accounting regulations and practices. We are subject to accounting
regulations and practices issued periodically by accounting standard-setting bodies. New
accounting standards may be issued that could change the way we record revenues, expenses,
assets and liabilities. Future changes in accounting standards could affect our reported
earnings or increase our liabilities. |
|
|
|
|
Earnings from our equity method investments. We invest in companies that have risks
that are inherent in their businesses and we assume such risks as an equity investor. |
All of these factors are difficult to predict and some of them are beyond our control. For these
reasons, you should not rely on these forward-looking statements when making investment decisions.
When used in our documents or oral presentations, the words expect, believe, project,
anticipate, intend, should,
23
could, will, assume, can, estimate, forecast, future, indicate, outlook, plan,
predict, seek, target, would and variations of such words and similar expressions are
intended to identify forward-looking statements.
Factors relating to regulation and management also may be described or incorporated by reference in
future filings with the SEC. Some of the factors that may cause actual results to differ have been
described above. Others may be described elsewhere in this report. There may also be other
factors besides those described above that could cause actual conditions, events or results to
differ from those in the forward-looking statements.
Forward-looking statements are only as of the date they are made and we do not undertake any
obligation to update publicly any forward-looking statement either as a result of new information,
future events or otherwise except as required by applicable laws and regulations. Please reference
our web site at www.piedmontng.com for current information. Our reports on Form 10-K, Form 10-Q
and Form 8-K and amendments to these reports are available at no cost on our web site as soon as
reasonably practicable after the report is filed with or furnished to the SEC.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
We hold all financial instruments discussed in this item for purposes other than trading. We are
potentially exposed to market risk due to changes in interest rates and the cost of gas. Our
exposure to interest rate changes relates primarily to short-term debt. We are exposed to
interest rate changes to long-term debt when we are in the market to issue long-term debt. As of
April 30, 2006, all of our long-term debt was at fixed rates. Exposure to gas cost variations
relates to the wholesale supply, demand and price of natural gas.
Interest Rate Risk
We have short-term borrowing arrangements to provide working capital and general corporate funds.
The level of borrowings under such arrangements varies from period to period depending upon many
factors, including our investments in capital projects. Future short-term interest expense and
payments will be impacted by both short-term interest rates and borrowing levels.
As of April 30, 2006, we had $252 million of short-term debt outstanding. A change of 100 basis
points in the underlying interest rate for our short-term debt would have caused a change in
interest expense of approximately $1.3 million during the six months ended April 30, 2006.
As of April 30, 2006, all of our long-term debt was at fixed interest rates and, therefore, not
subject to interest rate risk.
Commodity Price Risk
In the normal course of business, we utilize exchange-traded contracts of various duration for the
forward sale and purchase of a portion of our natural gas requirements. We manage our gas supply
costs through a portfolio of short- and long-term procurement contracts with various suppliers.
Due to cost-based rate regulation in our utility operations, we have limited financial exposure to
changes in commodity prices as historically we have recovered all changes in purchased gas costs
and the costs of hedging our gas supplies are passed on to customers through PGA procedures.
Additional information concerning market risk is set forth in Financial Condition and Liquidity
in
24
Managements Discussion and Analysis of Financial Condition and Results of Operations in Item 2 of
this Form 10-Q.
Item 4. Controls and Procedures
Our management, including the President and Chief Executive Officer and the Senior Vice President
and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and
procedures as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of the
period covered by this Form 10-Q. Based on such evaluation, our Chief Executive Officer and Chief
Financial Officer concluded that, as of the end of the period covered by this Form 10-Q, our
disclosure controls and procedures were effective in that they provide reasonable assurances that
the information we are required to disclose in the reports we file or submit under the Exchange Act
is recorded, processed, summarized and reported within the time periods required by the United
States Securities and Exchange Commissions rules and forms.
We routinely review our internal control over financial reporting and from time to time make
changes intended to enhance the effectiveness of our internal control over financial reporting.
There were no changes to our internal control over financial reporting as such term is defined in
Rules 13a-15(f) and 15d-15(f) under the Exchange Act during the second quarter of fiscal 2006 that
materially affected, or are reasonably likely to materially affect, our internal control over
financial reporting.
25
Part II. Other Information
Item 1. Legal Proceedings
In addition to the appeals to two NCUC orders filed by the North Carolina Office of the Attorney
General discussed in Note 4 to the condensed consolidated financial statements, we have only
routine litigation in the normal course of business. We do not expect the outcomes to such routine
litigation to have any material impact on our financial position, results of operations or cash
flows.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
c) Issuer Purchases of Equity Securities.
The following table provides information with respect to purchases of common stock under the
Common Stock Open Market Purchase Program during the three months ended April 30, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
Average |
|
Total Number of |
|
Maximum Number of |
|
|
Number |
|
Price |
|
Shares Purchased |
|
Shares that May |
|
|
of Shares |
|
Paid Per |
|
As Part of Publicly |
|
Yet be Purchased |
Period |
|
Purchased |
|
Share |
|
Announced Program |
|
Under the Program |
Beginning of the period |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,386,474 |
|
February 2006 |
|
|
382,400 |
|
|
$ |
23.96 |
|
|
|
382,400 |
|
|
|
8,004,074 |
|
March 2006 |
|
|
70,000 |
|
|
|
23.38 |
|
|
|
70,000 |
|
|
|
7,934,074 |
|
April 2006 |
|
|
1,203,000 |
|
|
|
23.91 |
|
|
|
1,203,000 |
|
|
|
6,731,074 |
|
Total |
|
|
1,655,400 |
|
|
|
23.90 |
|
|
|
1,655,400 |
|
|
|
|
|
The Common Stock Open Market Purchase Program was announced on June 4, 2004, to purchase up to
three million shares of common stock for reissuance under our dividend reinvestment, stock purchase
and incentive compensation plans. On December 16, 2005, the Board of Directors approved an
increase in the number of shares in this program from three million to six million to reflect the
two-for-one stock split in 2004. The Board also approved the purchase of up to four million
additional shares of common stock and amended the program to provide for purchases to maintain our
debt-to-equity capitalization ratios at target levels. These combined actions increased the total
authorized share repurchases from three million to ten million shares. Included in the shares
purchased in April 2006 are 1 million shares purchased under our ASR as described in Note 5 to the
condensed consolidated financial statements.
The amount of cash dividends that may be paid is restricted by provisions contained in certain
note agreements under which long-term debt was issued. As of April 30, 2006, none of our retained
earnings was restricted.
Item 4. Submission of Matters to a Vote of Security Holders
We held our Annual Meeting of Shareholders on March 3, 2006, to elect three directors, to ratify
the selection of our independent registered public accounting firm, to amend our Articles of
Incorporation to increase the number of authorized shares and to approve the Incentive Compensation
Plan effective as of November 1, 2005. The record date for determining the shareholders entitled
to receive notice of and to vote at the meeting was January 10, 2006. We solicited proxies for the
meeting according to section 14(a) of the Securities and Exchange Act of 1934. There was no
solicitation in opposition to managements solicitations.
26
Shareholders elected all of the nominees for director as listed in the proxy statement by the
following votes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares |
|
Shares |
|
Shares |
|
|
Voted |
|
Voted |
|
NOT |
|
|
FOR |
|
WITHHELD |
|
VOTED |
For terms expiring in 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
John W. Harris |
|
|
63,467,254 |
|
|
|
2,514,304 |
|
|
|
10,631,127 |
|
Aubrey B. Harwell, Jr. |
|
|
65,266,914 |
|
|
|
714,644 |
|
|
|
10,631,127 |
|
David E. Shi |
|
|
65,267,043 |
|
|
|
714,515 |
|
|
|
10,631,127 |
|
The current terms of directors Jerry W. Amos, D. Hayes Clement and Thomas E. Skains will expire at
our annual meeting in 2007. The current terms of directors Malcolm E. Everett III, Muriel W.
Helms, Frank B. Holding, Jr., and Minor M. Shaw will expire at our annual meeting in 2008.
Shareholders ratified the selection by the Board of Directors of the firm of Deloitte & Touche LLP
as our independent registered public accounting firm for the fiscal year ending October 31, 2006,
by the following vote:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares |
|
Shares |
|
Shares |
|
Broker |
|
Shares |
Voted |
|
Voted |
|
Voted |
|
Non- |
|
NOT |
FOR |
|
AGAINST |
|
ABSTAINING |
|
Votes |
|
VOTED |
65,123,220 |
|
|
584,617 |
|
|
|
273,721 |
|
|
|
|
|
|
|
10,631,127 |
|
Shareholders approved an amendment to Article 3 of our Articles of Incorporation to increase the
number of authorized shares of common stock from 100 million to 200 million shares.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares |
|
Shares |
|
Shares |
|
Broker |
|
Shares |
Voted |
|
Voted |
|
Voted |
|
Non- |
|
NOT |
FOR |
|
AGAINST |
|
ABSTAINING |
|
Votes |
|
VOTED |
61,288,917 |
|
|
4,078,458 |
|
|
|
614,167 |
|
|
|
16 |
|
|
|
10,631,127 |
|
Shareholders approved the Incentive Compensation Plan effective as of November 1, 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares |
|
Shares |
|
Shares |
|
Broker |
|
Shares |
Voted |
|
Voted |
|
Voted |
|
Non- |
|
NOT |
FOR |
|
AGAINST |
|
ABSTAINING |
|
Votes |
|
VOTED |
39,134,264 |
|
|
4,869,328 |
|
|
|
1,784,183 |
|
|
|
20,193,783 |
|
|
|
10,631,127 |
|
27
Item 6. Exhibits
|
3.1 |
|
Articles of Incorporation of the Company, as amended (Exhibit 4.1,
Form S-8 Registration Statement No. 333-132738). |
Exhibits 10.1 through 10.7 are management contracts or compensatory plans, contracts or
arrangements.
|
10.1 |
|
Employment Agreement dated as of May 1, 2006, between Piedmont
Natural Gas Company, Inc. and Michael H. Yount. |
|
|
10.2 |
|
Employment Agreement dated as of May 1, 2006, between Piedmont
Natural Gas Company, Inc. and Kevin M. OHara. |
|
|
10.3 |
|
Severance Agreement dated as of May 1, 2006, between Piedmont Natural
Gas Company, Inc. and Michael H. Yount. |
|
|
10.4 |
|
Severance Agreement dated as of May 1, 2006, between Piedmont Natural
Gas Company, Inc. and Kevin M. OHara. |
|
|
10.5 |
|
Severance Agreement dated as of May 1, 2006, between Piedmont Natural
Gas Company, Inc. and June B. Moore. |
|
|
10.6 |
|
Severance Agreement dated as of May 1, 2006, between Piedmont Natural
Gas Company, Inc. and Jane R. Lewis-Raymond. |
|
|
10.7 |
|
Piedmont Natural Gas Company, Inc. Incentive Compensation Plan
(Exhibit 10.1, Form 8-K dated March 3, 2006). |
|
|
31.1 |
|
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the
Chief Executive Officer. |
|
|
31.2 |
|
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the
Chief Financial Officer. |
|
|
32.1 |
|
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to
Section
906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer. |
|
|
32.2 |
|
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to
Section
906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer. |
28
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.
|
|
|
|
|
|
|
Piedmont Natural Gas Company, Inc. |
|
|
|
|
(Registrant) |
|
|
|
|
|
|
|
Date June 9, 2006
|
|
/s/ David J. Dzuricky
David J. Dzuricky
|
|
|
|
Senior Vice President and Chief Financial Officer |
|
|
|
|
(Principal Financial Officer) |
|
|
|
|
|
|
|
Date June 9, 2006
|
|
/s/ Barry L. Guy
|
|
|
|
Barry L. Guy |
|
|
|
|
Vice President and Controller |
|
|
|
|
(Principal Accounting Officer) |
|
|
29
Piedmont Natural Gas Company, Inc.
Form 10-Q
For the Quarter Ended April 30, 2006
Exhibits
10.1 |
|
Employment Agreement dated as of May 1, 2006, between Piedmont
Natural Gas Company, Inc., and Michael H. Yount |
|
10.2 |
|
Employment Agreement dated as of May 1, 2006, between Piedmont
Natural Gas Company, Inc., and Kevin M. OHara |
|
10.3 |
|
Severence Agreement dated as of May 1, 2006, between Piedmont Natural
Gas Company, Inc., and Michael H. Yount |
|
10.4 |
|
Severence Agreement dated as of May 1, 2006, between Piedmont Natural
Gas Company, Inc., and Kevin M. OHara |
|
10.5 |
|
Severence Agreement dated as of May 1, 2006, between Piedmont Natural
Gas Company, Inc., and June B. Moore |
|
10.6 |
|
Severence Agreement dated as of May 1, 2006, between Piedmont Natural
Gas Company, Inc., and Jane R. Lewis-Raymond |
|
31.1 |
|
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002 of the Chief Executive Officer |
|
31.2 |
|
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002 of the Chief Financial Officer |
|
32.1 |
|
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the
Chief Executive Officer |
|
32.2 |
|
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the
Chief Financial Officer |