e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
(Mark
One)
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended April 30, 2011
or
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o |
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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)
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North Carolina
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56-0556998 |
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.) |
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4720 Piedmont Row Drive, Charlotte, North Carolina
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28210 |
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(Address of principal executive offices)
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(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. þ Yes o No
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). þ Yes
o No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated
filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if a smaller reporting company) |
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange
Act). o Yes þ No
Indicate the number of shares outstanding of each of the issuers classes of common stock, as of
the latest practicable date.
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Class |
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Outstanding at May 31, 2011 |
Common Stock, no par value
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71,977,343 |
Piedmont Natural Gas Company, Inc.
Form 10-Q
for
April 30, 2011
TABLE OF CONTENTS
Part I. Financial Information
Item 1.
Financial Statements
Piedmont Natural Gas Company, Inc. and Subsidiaries
Consolidated Balance Sheets
(Unaudited)
(In thousands)
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April 30, |
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October 31, |
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2011 |
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2010 |
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ASSETS
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Utility Plant: |
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Utility plant in service |
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$ |
3,332,302 |
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$ |
3,176,312 |
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Less accumulated depreciation |
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948,926 |
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917,300 |
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Utility plant in service, net |
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2,383,376 |
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2,259,012 |
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Construction work in progress |
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94,724 |
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171,901 |
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Plant held for future use |
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6,751 |
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6,751 |
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Total utility plant, net |
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2,484,851 |
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2,437,664 |
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Other Physical Property, at cost (net of accumulated
depreciation of $768 in 2011 and $729 in 2010) |
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490 |
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528 |
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Current Assets: |
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Cash and cash equivalents |
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9,326 |
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5,619 |
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Trade accounts receivable (less allowance for doubtful
accounts of $4,696 in 2011 and $929 in 2010) |
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112,450 |
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62,370 |
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Income taxes receivable |
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24,856 |
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Other receivables |
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2,344 |
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2,289 |
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Unbilled utility revenues |
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21,588 |
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21,337 |
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Inventories: |
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Gas in storage |
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79,615 |
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101,734 |
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Materials, supplies and merchandise |
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2,807 |
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4,547 |
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Gas purchase derivative assets, at fair value |
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5,599 |
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2,819 |
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Amounts due from customers |
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1,834 |
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62,336 |
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Prepayments |
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15,228 |
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39,832 |
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Other current assets |
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103 |
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101 |
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Total current assets |
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250,894 |
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327,840 |
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Noncurrent Assets: |
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Equity method investments in non-utility activities |
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83,097 |
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80,287 |
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Goodwill |
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48,852 |
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48,852 |
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Marketable securities, at fair value |
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1,571 |
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997 |
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Overfunded postretirement asset |
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39,792 |
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17,342 |
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Regulatory asset for postretirement benefits |
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63,961 |
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64,775 |
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Unamortized debt expense |
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10,262 |
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8,576 |
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Regulatory cost of removal asset |
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18,571 |
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17,825 |
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Other noncurrent assets |
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55,459 |
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48,589 |
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Total noncurrent assets |
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321,565 |
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287,243 |
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Total |
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$ |
3,057,800 |
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$ |
3,053,275 |
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See notes to consolidated financial statements.
1
Piedmont Natural Gas Company, Inc. and Subsidiaries
Consolidated Balance Sheets (Unaudited)
(In thousands)
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April 30, |
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October 31, |
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2011 |
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2010 |
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CAPITALIZATION AND LIABILITIES
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Capitalization: |
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Stockholders equity: |
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Cumulative preferred stock no par value 175 shares
authorized |
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$ |
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$ |
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Common stock no par value shares authorized: 200,000;
shares outstanding: 71,961 in 2011 and 72,282 in 2010 |
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436,293 |
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445,640 |
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Retained earnings |
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610,620 |
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519,831 |
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Accumulated other comprehensive income (loss) |
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31 |
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(530 |
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Total stockholders equity |
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1,046,944 |
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964,941 |
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Long-term debt |
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475,000 |
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671,922 |
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Total capitalization |
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1,521,944 |
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1,636,863 |
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Current Liabilities: |
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Current maturities of long-term debt |
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256,843 |
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60,000 |
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Bank debt |
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103,500 |
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242,000 |
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Trade accounts payable |
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63,965 |
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66,019 |
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Other accounts payable |
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32,283 |
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49,645 |
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Income taxes accrued |
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15,989 |
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Accrued interest |
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20,494 |
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20,134 |
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Customers deposits |
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28,118 |
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25,631 |
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Deferred income taxes |
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124 |
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4,933 |
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General taxes accrued |
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9,815 |
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20,100 |
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Amounts due to customers |
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18,733 |
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Other current liabilities |
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5,696 |
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10,098 |
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Total current liabilities |
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555,560 |
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498,560 |
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Noncurrent Liabilities: |
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Deferred income taxes |
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477,270 |
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429,225 |
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Unamortized federal investment tax credits |
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1,960 |
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2,145 |
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Accumulated provision for postretirement benefits |
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15,190 |
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14,805 |
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Cost of removal obligations |
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449,800 |
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436,072 |
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Other noncurrent liabilities |
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36,076 |
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35,605 |
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Total noncurrent liabilities |
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980,296 |
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917,852 |
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Commitments and Contingencies (Note 14) |
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Total |
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$ |
3,057,800 |
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$ |
3,053,275 |
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See notes to consolidated financial statements.
2
Piedmont Natural Gas Company, Inc. and Subsidiaries
Consolidated Statements of Income
(Unaudited)
(In thousands except per share amounts)
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Three Months Ended |
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Six Months Ended |
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April 30 |
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April 30 |
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2011 |
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2010 |
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2011 |
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2010 |
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Operating Revenues |
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$ |
392,567 |
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$ |
472,846 |
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$ |
1,044,623 |
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$ |
1,146,582 |
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Cost of Gas |
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219,636 |
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304,168 |
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641,686 |
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754,962 |
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Margin |
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172,931 |
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168,678 |
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402,937 |
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391,620 |
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Operating Expenses: |
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Operations and maintenance |
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58,936 |
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57,503 |
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109,994 |
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109,542 |
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Depreciation |
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25,425 |
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24,483 |
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50,472 |
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48,838 |
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General taxes |
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9,464 |
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8,758 |
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20,561 |
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17,343 |
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Utility income taxes |
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26,179 |
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25,709 |
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78,114 |
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75,871 |
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Total operating expenses |
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120,004 |
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116,453 |
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259,141 |
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251,594 |
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Operating Income |
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52,927 |
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|
52,225 |
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143,796 |
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|
140,026 |
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Other Income (Expense): |
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|
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Income from equity method investments |
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12,384 |
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|
13,309 |
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20,140 |
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25,142 |
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Gain on sale of interest in equity method investment |
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49,674 |
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Non-operating income |
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|
470 |
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221 |
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|
638 |
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|
315 |
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Non-operating expense |
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(794 |
) |
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(1,013 |
) |
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(1,179 |
) |
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(1,376 |
) |
Income taxes |
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(4,716 |
) |
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(4,906 |
) |
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(7,667 |
) |
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(28,892 |
) |
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Total other income (expense) |
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7,344 |
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7,611 |
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11,932 |
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44,863 |
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Utility Interest Charges: |
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Interest on long-term debt |
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12,071 |
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13,251 |
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24,171 |
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|
26,526 |
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Allowance for borrowed funds used during
construction |
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(1,341 |
) |
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(782 |
) |
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(3,675 |
) |
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(1,302 |
) |
Other |
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2,133 |
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|
542 |
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3,384 |
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(909 |
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Total utility interest charges |
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12,863 |
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13,011 |
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23,880 |
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24,315 |
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Net Income |
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$ |
47,408 |
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$ |
46,825 |
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$ |
131,848 |
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$ |
160,574 |
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Average Shares of Common Stock: |
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Basic |
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71,824 |
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|
71,788 |
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72,012 |
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|
72,492 |
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Diluted |
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|
72,061 |
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|
72,118 |
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|
72,279 |
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|
72,842 |
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Earnings Per Share of Common Stock: |
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Basic |
|
$ |
0.66 |
|
|
$ |
0.65 |
|
|
$ |
1.83 |
|
|
$ |
2.22 |
|
Diluted |
|
$ |
0.66 |
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|
$ |
0.65 |
|
|
$ |
1.82 |
|
|
$ |
2.20 |
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Cash Dividends Per Share of Common Stock |
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$ |
0.29 |
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$ |
0.28 |
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|
$ |
0.57 |
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$ |
0.55 |
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|
|
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|
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|
|
|
|
|
|
|
|
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|
See notes to consolidated financial statements.
3
Piedmont Natural Gas Company, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(Unaudited)
(In thousands)
|
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|
|
|
|
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|
|
|
Six Months Ended |
|
|
|
April 30 |
|
|
|
2011 |
|
|
2010 |
|
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|
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|
|
|
Cash Flows from Operating Activities: |
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|
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Net income |
|
$ |
131,848 |
|
|
$ |
160,574 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
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|
|
|
|
|
|
Depreciation and amortization |
|
|
52,481 |
|
|
|
51,231 |
|
Amortization of investment tax credits |
|
|
(185 |
) |
|
|
(181 |
) |
Allowance for doubtful accounts |
|
|
3,767 |
|
|
|
3,912 |
|
Gain on sale of interest in equity method investment, net of tax |
|
|
|
|
|
|
(30,222 |
) |
Net gain on sale of property |
|
|
|
|
|
|
(133 |
) |
Income from equity method investments |
|
|
(20,140 |
) |
|
|
(25,142 |
) |
Distributions of earnings from equity method investments |
|
|
13,177 |
|
|
|
27,433 |
|
Deferred income taxes |
|
|
42,873 |
|
|
|
(4,447 |
) |
Changes in assets and liabilities: |
|
|
|
|
|
|
|
|
Gas purchase derivatives, at fair value |
|
|
(2,780 |
) |
|
|
(7,736 |
) |
Receivables |
|
|
(54,276 |
) |
|
|
(52,561 |
) |
Inventories |
|
|
23,859 |
|
|
|
20,902 |
|
Amounts due from/to customers |
|
|
79,235 |
|
|
|
147,575 |
|
Settlement of legal asset retirement obligations |
|
|
(1,113 |
) |
|
|
(634 |
) |
Overfunded postretirement asset |
|
|
(22,450 |
) |
|
|
(10,598 |
) |
Regulatory asset for postretirement benefits |
|
|
814 |
|
|
|
466 |
|
Other assets |
|
|
43,825 |
|
|
|
71,578 |
|
Accounts payable |
|
|
(14,374 |
) |
|
|
(18,610 |
) |
Provision for postretirement benefits |
|
|
385 |
|
|
|
(10,493 |
) |
Other liabilities |
|
|
7,903 |
|
|
|
37,664 |
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
284,849 |
|
|
|
360,578 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities: |
|
|
|
|
|
|
|
|
Utility construction expenditures |
|
|
(89,428 |
) |
|
|
(70,039 |
) |
Allowance for funds used during construction |
|
|
(3,675 |
) |
|
|
(1,302 |
) |
Contributions to equity method investments |
|
|
(3,892 |
) |
|
|
|
|
Distributions of capital from equity method investments |
|
|
8,968 |
|
|
|
701 |
|
Proceeds from sale of interest in equity method investment |
|
|
|
|
|
|
57,500 |
|
Proceeds from sale of property |
|
|
765 |
|
|
|
1,210 |
|
Investments in marketable securities |
|
|
(450 |
) |
|
|
(468 |
) |
Other |
|
|
992 |
|
|
|
204 |
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(86,720 |
) |
|
|
(12,194 |
) |
|
|
|
|
|
|
|
4
Piedmont Natural Gas Company, Inc. and Subsidiaries
Consolidated Statements of Cash Flows (Unaudited)
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
April 30 |
|
|
|
2011 |
|
|
2010 |
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities: |
|
|
|
|
|
|
|
|
Borrowings under bank debt |
|
$ |
944,000 |
|
|
$ |
558,000 |
|
Repayments under bank debt |
|
|
(1,082,500 |
) |
|
|
(828,500 |
) |
Retirement of long-term debt |
|
|
(79 |
) |
|
|
(384 |
) |
Expenses related to issuance of credit facility |
|
|
(2,155 |
) |
|
|
|
|
Issuance of common stock through dividend reinvestment and employee
stock plans |
|
|
10,426 |
|
|
|
9,817 |
|
Repurchases of common stock |
|
|
(23,004 |
) |
|
|
(47,282 |
) |
Dividends paid |
|
|
(41,104 |
) |
|
|
(39,909 |
) |
Other |
|
|
(6 |
) |
|
|
(694 |
) |
|
|
|
|
|
|
|
Net cash used in financing activities |
|
|
(194,422 |
) |
|
|
(348,952 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Cash Equivalents |
|
|
3,707 |
|
|
|
(568 |
) |
Cash and Cash Equivalents at Beginning of Period |
|
|
5,619 |
|
|
|
7,558 |
|
|
|
|
|
|
|
|
Cash and Cash Equivalents at End of Period |
|
$ |
9,326 |
|
|
$ |
6,990 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncash Investing and Financing Activities: |
|
|
|
|
|
|
|
|
Accrued construction expenditures |
|
$ |
5,045 |
|
|
$ |
819 |
|
Guaranty |
|
|
|
|
|
|
1,234 |
|
See notes to consolidated financial statements.
5
Piedmont Natural Gas Company, Inc. and Subsidiaries
Consolidated Statements of Comprehensive Income
(Unaudited)
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
April 30 |
|
|
April 30 |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
$ |
47,408 |
|
|
$ |
46,825 |
|
|
$ |
131,848 |
|
|
$ |
160,574 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gain (loss) from hedging activities of equity method
investments, net of tax of ($66) and ($540) for the three
months ended April 30, 2011 and 2010, respectively, and
$55 and ($171) for the six months ended April 30, 2011
and 2010, respectively |
|
|
(104 |
) |
|
|
(838 |
) |
|
|
81 |
|
|
|
(265 |
) |
Reclassification adjustment from hedging activities of equity method
investments included in net income, net of tax of $56 and
$456 for the three months ended April 30, 2011 and 2010,
respectively, and $308 and $884 for the six months ended
April 30, 2011 and 2010, respectively |
|
|
87 |
|
|
|
708 |
|
|
|
480 |
|
|
|
1,372 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Comprehensive Income |
|
$ |
47,391 |
|
|
$ |
46,695 |
|
|
$ |
132,409 |
|
|
$ |
161,681 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements.
6
Piedmont Natural Gas Company, Inc. and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
1. Summary of Significant Accounting Policies
Unaudited Interim Financial Information
The consolidated financial statements have not been audited. We have prepared the unaudited
consolidated financial statements under the rules of the Securities and Exchange Commission (SEC).
Therefore, certain financial information and note disclosures normally included in annual financial
statements prepared in conformity with generally accepted accounting principles (GAAP) in the
United States of America are omitted in this interim report under these SEC rules and regulations.
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, 2010.
Seasonality and Use of Estimates
The unaudited consolidated financial statements include all normal recurring adjustments necessary
for a fair statement of financial position at April 30, 2011 and October 31, 2010, the results of
operations for the three months and six months ended April 30, 2011 and 2010, and cash flows for
the six months ended April 30, 2011 and 2010. Our business is seasonal in nature. The results of
operations for the three months and six months ended April 30, 2011 do not necessarily reflect the
results to be expected for the full year.
We make estimates and assumptions when preparing the consolidated financial statements. These
estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure
of contingent assets and liabilities as of the date of the consolidated financial statements and
the reported amounts of revenues and expenses during the reporting period. Actual results could
differ from estimates.
Significant Accounting Policies
Our accounting policies are described in Note 1 to the consolidated financial statements in our
Form 10-K for the year ended October 31, 2010. There were no significant changes to those
accounting policies during the six months ended April 30, 2011.
Rate-Regulated Basis of Accounting
Our utility operations are subject to regulation with respect to rates, service area, accounting
and various other matters by the regulatory commissions in the states in which we operate. The
accounting regulations provide 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 these regulations, 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.
Our regulatory assets are recoverable through either base rates or rate riders specifically
authorized by a state regulatory commission. Base rates are designed to provide both a recovery of
cost and a return on investment during the period the rates are in effect. As such, all of our
regulatory assets are subject to review by the respective state regulatory commission during any
future rate proceedings. In the event that accounting for the effects of regulation were no longer
applicable, we would recognize a write-off of the regulatory assets and regulatory liabilities that
would result in an adjustment to net income. Our utility operations continue to recover their
costs through cost-based rates established by the state regulatory commissions. As a result, we
believe that the accounting prescribed under rate-based regulation remains appropriate. It is our
opinion that all of our
7
recorded regulatory assets are recoverable in current rates or future rate proceedings.
Regulatory assets and liabilities in the consolidated balance sheets as of April 30, 2011 and
October 31, 2010 are as follows.
|
|
|
|
|
|
|
|
|
|
|
April 30, |
|
October 31, |
In thousands |
|
2011 |
|
2010 |
|
|
|
|
|
|
|
|
|
Regulatory assets |
|
$ |
141,810 |
|
|
$ |
197,772 |
|
Regulatory liabilities |
|
|
470,654 |
|
|
|
439,075 |
|
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 accounting regulations prescribed under rate-based regulation. For information on
related party transactions, see Note 8 to the consolidated financial statements in this Form 10-Q.
Fair Value Measurements
The carrying value of cash and cash equivalents, receivables, bank debt, accounts payable and
accrued interest approximates fair value. Our financial assets and liabilities are recorded at
fair value and consist primarily of derivatives that are recorded in the consolidated balance
sheets in accordance with derivative accounting standards.
We utilize market data or assumptions about risk and the risks inherent in the inputs to the
valuation technique. These inputs can be readily observable, market corroborated or generally
observable. We primarily apply the market approach for recurring fair value measurements and
endeavor to utilize the best available information. Accordingly, we use valuation techniques that
maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value
of our financial assets and liabilities are subject to potentially significant volatility based on
changes in market prices, the portfolio valuation of our contracts, as well as the maturity and
settlement of those contracts, and subsequent newly originated transactions, each of which directly
affects the estimated fair value of our financial instruments. We are able to classify fair value
balances based on the observance of those inputs into the fair value hierarchy levels as
set forth in the fair value guidance.
For the fair value measurements of our derivatives and marketable securities, see Note 10 to the
consolidated financial statements in this Form 10-Q. For the fair value measurements of our
benefit plan assets, see Note 8 to our Form 10-K for the year ended October 31, 2010. For further
information on our fair value methodologies, see Note 1.F to our Form 10-K for the year ended
October 31, 2010. There were no significant changes to these fair value methodologies during the
three months ended April 30, 2011.
Financing Receivables
We originate and subsequently own installment loans made to our natural gas customers under our
Third Party Financing Program. Under the Third Party Financing Program, we offer financing to
qualifying customers for the purchase and installation of gas appliances and HVAC equipment. The
quality of these loans is comparable to the quality of our natural gas receivables. We perform
credit evaluations of our customers and maintain reserves for estimated credit losses based on
historical experience and the aging of the loan balances. As of April 30, 2011, we do not have
loans that are impaired. We recognize interest revenue on these loans using the simple add-on
interest method. The loans outstanding under the Third Party Financing Program are presented
below.
8
|
|
|
|
|
|
|
April 30, |
|
In thousands |
|
2011 |
|
|
|
|
|
|
Third party financing program loans outstanding |
|
$ |
6,432 |
|
|
|
|
|
The reconciliation of activity in the reserve
related to the Third Party Financing Program
is presented below.
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended |
|
In thousands |
|
April 30, 2011 |
|
|
|
|
|
|
Balance at beginning of period |
|
$ |
187 |
|
Additions charged to uncollectibles expense |
|
|
56 |
|
Accounts written off, net of recoveries |
|
|
(3 |
) |
|
|
|
|
Balance at end of period |
|
$ |
240 |
|
|
|
|
|
Recently Issued Accounting Guidance
In January 2010, the Financial Accounting Standards Board (FASB) issued accounting guidance to
require separate disclosures about purchases, sales, issuances and settlements relating to Level 3
fair value measurements. The guidance will be effective for interim periods for fiscal years
beginning after December 15, 2010. We will adopt the guidance for Level 3 disclosure for recurring
and non-recurring items covered under the fair value guidance for the first quarter of our fiscal
year ending October 31, 2012. Since the guidance addresses only disclosures related to fair value
measurements under Level 3, we do not expect the adoption of this guidance to have a material
impact on our financial position, results of operations or cash flows.
In July 2010, the FASB issued accounting guidance to improve disclosures about the credit quality
of an entitys financing receivables and the reserves held against them. End of reporting period
disclosures are required for the reporting period ending on or after December 15, 2010. The
disclosures about activity that occurred during a reporting period were effective for interim and
annual periods beginning on or after December 15, 2010. We adopted the guidance for the end of
period disclosures as of January 31, 2011, and the guidance for the disclosures related to activity
in the reporting period during our fiscal second quarter beginning February 1, 2011. The
disclosure is set forth above in Financing Receivables. Since the guidance addresses only
disclosures related to credit quality of financing receivables and the allowance for credit losses,
the adoption of this guidance did not have a material impact on our financial position, results of
operations or cash flows.
In May 2011, the FASB issued accounting guidance to improve the comparability of fair value
measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP
and International Financial Reporting Standards (IFRS). The amendments are not intended to change
the application of the current fair value requirements, but to clarify the application of existing
requirements. The guidance does change particular principles or requirements for measuring fair
value or disclosing information about fair value measurements. To improve consistency, language
has been changed to ensure that U.S. GAAP and IFRS fair value measurement and disclosure
requirements are described in the same way. The guidance will be effective for interim and annual
periods beginning after December 15, 2011. We will adopt the amended fair value guidance for the
second quarter of our fiscal year ending October 31, 2012. We do not expect the adoption of this
guidance to have a material impact on our financial position, results of operations or cash flows.
9
2. Regulatory Matters
On February 26, 2010, we filed a petition with the Tennessee Regulatory Authority (TRA) to adjust
the applicable rate for the collection of the Nashville franchise fee from certain customers. The
proposed rate adjustment was calculated to recover the net $2.9 million of under-collected
Nashville franchise fee payments as of May 31, 2009. On April 12, 2010, the TRA passed a motion
approving a new Nashville franchise fee rate designed to recover only the net under-collections
that have accrued since June 1, 2005, which would deny recovery of $1.5 million for us. Once the
TRA issues its order on this matter, we intend to seek their reconsideration. We are unable to
predict the outcome of this proceeding at this time. However, we do not believe this matter will
have a material effect on our financial position, results of operations or cash flows.
On September 9, 2010, we filed an annual report with the TRA reflecting the shared gas cost savings
from gains and losses derived from gas purchase benchmarking and secondary market transactions for
the twelve months ended June 30, 2010 under the Tennessee Incentive Plan (TIP). On April 20, 2011,
the TRA staff filed their compliance audit report that recommended approval of our TIP account
balances. On May 9, 2011, the TRA passed a motion approving the findings and recommendations of
the TRA staffs compliance audit report.
On December 6, 2010, we filed our report for the eighteen months ended June 30, 2010 with the TRA
that reflected the transactions in the deferred gas cost account for the Actual Cost Adjustment
(ACA) mechanism. This one-time eighteen month audit period is designed to synchronize the ACA
audit year with the TIP plan year in order to facilitate the audit process for future periods. We
are unable to predict the outcome of this proceeding at this time. However, we do not believe this
matter will have a material effect on our financial position, results of operations or cash flows.
On February 15, 2011, the Public Service Commission of South Carolina (PSCSC) set a hearing date of
July 13, 2011 for our annual review of purchased gas costs and gas purchasing policies for the
twelve months ended March 31, 2011. We are unable to predict the outcome of this proceeding at
this time.
On February 24, 2011, the Office of Regulatory Staff requested that the PSCSC suspend the
commission-approved gas hedging programs operated by the regulated gas utilities in South Carolina
due to more moderate market conditions currently existing for the cost of natural gas. This
suspension of the hedging program is requested to be effective prospectively upon the issuance of
an order by the PSCSC. All existing hedges would continue to be managed under the current approved
hedging programs as gas costs in purchased gas adjustment (PGA) proceedings. On March 4, 2011, we
filed a letter with the PSCSC stating that we believe that it is reasonable and prudent to continue
our current hedging program to provide some degree of high gas price protection for natural gas
consumers. We believe that some price volatility will continue to exist in the market due to
unpredictable events. Oral arguments and informational briefings on this matter were heard by the
PSCSC on April 21, 2011. On May 25, 2011, the PSCSC voted to open a new, generic docket on this
issue to expand the discussion to include the states regulated electric utilities as well. We are
unable to predict the outcome of this proceeding at this time. However, we do not believe this
matter will have a material effect on our financial position, results of operations or cash flows.
3. Earnings per Share
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, 2011 and 2010 is presented below.
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Six Months |
|
In thousands except per share amounts |
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
$ |
47,408 |
|
|
$ |
46,825 |
|
|
$ |
131,848 |
|
|
$ |
160,574 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average shares of common stock outstanding for
basic earnings per share |
|
|
71,824 |
|
|
|
71,788 |
|
|
|
72,012 |
|
|
|
72,492 |
|
Contingently issuable shares under incentive
compensation plans |
|
|
237 |
|
|
|
330 |
|
|
|
267 |
|
|
|
350 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average shares of dilutive stock |
|
|
72,061 |
|
|
|
72,118 |
|
|
|
72,279 |
|
|
|
72,842 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Per Share of Common Stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.66 |
|
|
$ |
0.65 |
|
|
$ |
1.83 |
|
|
$ |
2.22 |
|
Diluted |
|
$ |
0.66 |
|
|
$ |
0.65 |
|
|
$ |
1.82 |
|
|
$ |
2.20 |
|
4. Marketable Securities
We have marketable securities that are invested in money market and mutual funds that are liquid
and actively traded on the exchanges. These securities are assets that are held in a rabbi trust
established for our deferred compensation plans that became effective on January 1, 2009. For
further information on the deferred compensation plans, see Note 6 to the consolidated financial
statements in this Form 10-Q.
The money market investments in the trust approximate fair value due to the short period of time to
maturity. The fair values of the equity securities are based on the quoted market prices as traded
on the exchanges. We have matched the current portion of the deferred compensation liability with
the current asset and the noncurrent deferred compensation liability with the noncurrent asset; the
current portion has been included in Other current assets in the consolidated balance sheets.
The composition of these securities as of April 30, 2011 and October 31, 2010 is as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April 30, 2011 |
|
|
October 31, 2010 |
|
|
|
|
|
|
|
Fair |
|
|
|
|
|
|
Fair |
|
In thousands |
|
Cost |
|
|
Value |
|
|
Cost |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current trading securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money markets |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Mutual funds |
|
|
6 |
|
|
|
7 |
|
|
|
4 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current trading securities |
|
|
6 |
|
|
|
7 |
|
|
|
4 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent trading securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money markets |
|
|
218 |
|
|
|
218 |
|
|
|
254 |
|
|
|
254 |
|
Mutual funds |
|
|
1,105 |
|
|
|
1,353 |
|
|
|
618 |
|
|
|
743 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total noncurrent trading securities |
|
|
1,323 |
|
|
|
1,571 |
|
|
|
872 |
|
|
|
997 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total trading securities |
|
$ |
1,329 |
|
|
$ |
1,578 |
|
|
$ |
876 |
|
|
$ |
1,002 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11
5. Capital Stock
On January 10, 2011, we entered into an accelerated share repurchase (ASR) agreement where we
purchased 800,000 shares of our common stock from an investment bank at the closing price that day
of $27.79 per share. The settlement and retirement of those shares occurred on January 11, 2011.
Total consideration paid to purchase the shares of $22.2 million was recorded in Stockholders
equity as a reduction in Common stock.
As part of the ASR, we simultaneously entered into a forward sale contract with the investment bank
that was expected to mature in approximately 48 trading days, or March 18, 2011. Under the terms
of the forward sale contract, the investment bank was required to purchase, in the open market,
800,000 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, were 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, less a $.10
discount, was higher than the initial purchase closing price. The investment bank was required to
pay us either cash or shares of our common stock, at our option, if the investment banks weighted
average price, less a $.10 discount, for the shares purchased was lower than the initial purchase
closing price. At settlement on March 21, 2011, we paid cash of $.8 million to the investment bank
and recorded this amount in Stockholders equity as a reduction of Common Stock in the
consolidated balance sheets. The $.8 million was the difference between the investment banks
weighted average purchase price of $28.8551 less a discount of $.10 for a settlement price of
$28.7551 and the initial purchase closing price of $27.79 per share multiplied by 800,000 shares.
6. Employee Benefit Plans
Components of the net periodic benefit cost for our defined benefit pension plans and our other
postretirement employee benefits (OPEB) plan for the three months ended April 30, 2011 and 2010 are
presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified Pension |
|
|
Nonqualified Pension |
|
|
Other Benefits |
|
In thousands |
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
2,225 |
|
|
$ |
2,100 |
|
|
$ |
11 |
|
|
$ |
10 |
|
|
$ |
350 |
|
|
$ |
334 |
|
Interest cost |
|
|
2,700 |
|
|
|
2,850 |
|
|
|
52 |
|
|
|
61 |
|
|
|
374 |
|
|
|
476 |
|
Expected return
on plan assets |
|
|
(5,150 |
) |
|
|
(4,775 |
) |
|
|
|
|
|
|
|
|
|
|
(384 |
) |
|
|
(345 |
) |
Amortization of
transition obligation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
167 |
|
|
|
167 |
|
Amortization of prior
service (credit) cost |
|
|
(550 |
) |
|
|
(550 |
) |
|
|
5 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
Amortization of actuarial
loss |
|
|
775 |
|
|
|
550 |
|
|
|
11 |
|
|
|
2 |
|
|
|
|
|
|
|
59 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
|
|
|
$ |
175 |
|
|
$ |
79 |
|
|
$ |
78 |
|
|
$ |
507 |
|
|
$ |
691 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of the net periodic benefit cost for our defined benefit pension plans and our OPEB plan
for the six months ended April 30, 2011 and 2010 are presented below.
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified Pension |
|
|
Nonqualified Pension |
|
|
Other Benefits |
|
In thousands |
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
4,450 |
|
|
$ |
4,200 |
|
|
$ |
23 |
|
|
$ |
19 |
|
|
$ |
699 |
|
|
$ |
669 |
|
Interest cost |
|
|
5,400 |
|
|
|
5,700 |
|
|
|
104 |
|
|
|
121 |
|
|
|
747 |
|
|
|
953 |
|
Expected return
on plan assets |
|
|
(10,300 |
) |
|
|
(9,550 |
) |
|
|
|
|
|
|
|
|
|
|
(767 |
) |
|
|
(691 |
) |
Amortization of
transition obligation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
334 |
|
|
|
334 |
|
Amortization of prior
service (credit) cost |
|
|
(1,100 |
) |
|
|
(1,100 |
) |
|
|
10 |
|
|
|
10 |
|
|
|
|
|
|
|
|
|
Amortization of actuarial
loss |
|
|
1,550 |
|
|
|
1,100 |
|
|
|
21 |
|
|
|
5 |
|
|
|
|
|
|
|
118 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
|
|
|
$ |
350 |
|
|
$ |
158 |
|
|
$ |
155 |
|
|
$ |
1,013 |
|
|
$ |
1,383 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In November 2010, we contributed $22 million to the qualified pension plan, and in January 2011, we
contributed $.3 million to the money purchase pension plan. We anticipate that we will contribute
the following amounts to our other plans in 2011.
|
|
|
|
|
In thousands |
|
|
|
|
|
|
|
|
|
Nonqualified pension plan |
|
$ |
517 |
|
OPEB plan |
|
|
1,400 |
|
We have a defined contribution restoration (DCR) plan that we fund annually and that covers all
officers at the vice president level and above. For the six months ended April 30, 2011, we
contributed $.4 million to this plan. Participants may not contribute to the DCR plan. We have a
voluntary deferral plan for the benefit of all director-level employees and officers; we make no
contributions to this plan. Both deferred compensation plans are funded through a rabbi trust with
a bank as the trustee. As of April 30, 2011, we have a liability of $1.7 million for these plans.
See Note 4 and Note 10 to the consolidated financial statements in this Form 10-Q for information
on the investments in marketable securities that are held in the trust.
7. Business Segments
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 current
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 that are held by our
wholly owned subsidiaries.
Operations of the regulated utility segment are reflected in Operating Income in the consolidated
statements of income. Operations of the non-utility activities segment are included in the
consolidated statements of income in Income from equity method investments and Non-operating
income.
We evaluate the performance of the regulated utility segment based on margin, operations and
maintenance expenses and 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 in our Form 10-K for the year ended October 31, 2010.
13
Operations by segment for the three months and six months ended April 30, 2011 and 2010 are
presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated |
|
Non-utility |
|
|
In thousands |
|
Utility |
|
Activities |
|
Total |
|
|
2011 |
|
2010 |
|
2011 |
|
2010 |
|
2011 |
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers |
|
$ |
392,567 |
|
|
$ |
472,846 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
392,567 |
|
|
$ |
472,846 |
|
Margin |
|
|
172,931 |
|
|
|
168,678 |
|
|
|
|
|
|
|
|
|
|
|
172,931 |
|
|
|
168,678 |
|
Operations and maintenance expenses |
|
|
58,936 |
|
|
|
57,503 |
|
|
|
17 |
|
|
|
111 |
|
|
|
58,953 |
|
|
|
57,614 |
|
Gain from sale of interest in equity
method investment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from equity method investments |
|
|
|
|
|
|
|
|
|
|
12,384 |
|
|
|
13,309 |
|
|
|
12,384 |
|
|
|
13,309 |
|
Operating income (loss) before income taxes |
|
|
79,106 |
|
|
|
77,934 |
|
|
|
(24 |
) |
|
|
(118 |
) |
|
|
79,082 |
|
|
|
77,816 |
|
Income before income taxes |
|
|
65,932 |
|
|
|
64,250 |
|
|
|
12,371 |
|
|
|
13,190 |
|
|
|
78,303 |
|
|
|
77,440 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers |
|
$ |
1,044,623 |
|
|
$ |
1,146,582 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
1,044,623 |
|
|
$ |
1,146,582 |
|
Margin |
|
|
402,937 |
|
|
|
391,620 |
|
|
|
|
|
|
|
|
|
|
|
402,937 |
|
|
|
391,620 |
|
Operations and maintenance expenses |
|
|
109,994 |
|
|
|
109,542 |
|
|
|
47 |
|
|
|
234 |
|
|
|
110,041 |
|
|
|
109,776 |
|
Gain from sale of interest in equity
method investment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49,674 |
|
|
|
|
|
|
|
49,674 |
|
Income from equity method investments |
|
|
|
|
|
|
|
|
|
|
20,140 |
|
|
|
25,142 |
|
|
|
20,140 |
|
|
|
25,142 |
|
Operating income (loss) before income taxes |
|
|
221,910 |
|
|
|
215,897 |
|
|
|
(143 |
) |
|
|
(330 |
) |
|
|
221,767 |
|
|
|
215,567 |
|
Income before income taxes |
|
|
197,621 |
|
|
|
190,849 |
|
|
|
20,008 |
|
|
|
74,488 |
|
|
|
217,629 |
|
|
|
265,337 |
|
Reconciliations to the consolidated statements of income for the three months and six months ended April 30, 2011 and 2010 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Six Months |
|
In thousands |
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income before
income taxes |
|
$ |
79,082 |
|
|
$ |
77,816 |
|
|
$ |
221,767 |
|
|
$ |
215,567 |
|
Utility income taxes |
|
|
(26,179 |
) |
|
|
(25,709 |
) |
|
|
(78,114 |
) |
|
|
(75,871 |
) |
Non-utility activities before income taxes |
|
|
24 |
|
|
|
118 |
|
|
|
143 |
|
|
|
330 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
52,927 |
|
|
$ |
52,225 |
|
|
$ |
143,796 |
|
|
$ |
140,026 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes for
reportable segments |
|
$ |
78,303 |
|
|
$ |
77,440 |
|
|
$ |
217,629 |
|
|
$ |
265,337 |
|
Income taxes |
|
|
(30,895 |
) |
|
|
(30,615 |
) |
|
|
(85,781 |
) |
|
|
(104,763 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
47,408 |
|
|
$ |
46,825 |
|
|
$ |
131,848 |
|
|
$ |
160,574 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8. Equity Method Investments
The 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 consolidated balance sheets. Earnings or losses from equity method investments
are included in Income from equity method investments in the consolidated statements of income.
14
We own 21.49% of the membership interests in Cardinal Pipeline Company, L.L.C. (Cardinal), a North
Carolina limited liability company. Cardinal owns and operates an intrastate natural gas pipeline
in North Carolina and is regulated by the North Carolina Utilities Commission (NCUC).
On October 22, 2009, we reached an agreement with Progress Energy Carolinas, Inc. to provide
natural gas delivery service to a power generation facility to be built at their Wayne County,
North Carolina site. To provide the additional delivery service, we have executed an agreement
with Cardinal, which was approved by the NCUC in May 2010, to expand our firm capacity requirement
by 149,000 dekatherms per day to serve Progress Energy Carolinas. This will require Cardinal to
spend as much as $53.1 million for a new compressor station and expanded meter stations in order to
increase the capacity of its system by up to 199,000 dekatherms per day of firm capacity for us and
another customer. As an equity venture partner of Cardinal, we will invest as much as $11.4
million in Cardinals system expansion. Capital contributions related to this system expansion
began in January 2011 and will continue on a periodic basis through September 2012. As of April
30, 2011, our contributions to date related to this expansion were $3.9 million.
The members capital will be replaced with permanent financing with a target overall capital
structure of 45-50% debt and 50-55% equity after the project is placed into service, scheduled to
be July 1, 2012. In addition, our service subscription to Cardinals capacity following the system
expansion will increase from approximately 37% to approximately 53%. The NCUC issued a formal
certificate order for Progress Energy Carolinas for their Wayne County generation project in
October 2009.
We have related party transactions as a transportation customer of Cardinal, and we record in cost
of gas the transportation costs charged by Cardinal. For each period of the three months and six
months ended April 30, 2011 and 2010, these transportation costs and the amounts we owed Cardinal
as of April 30, 2011 and October 31, 2010 are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
Six Months |
In thousands |
|
2011 |
|
2010 |
|
2011 |
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation costs |
|
$ |
1,001 |
|
|
$ |
1,001 |
|
|
$ |
2,035 |
|
|
$ |
2,035 |
|
|
|
|
|
|
|
|
|
|
|
|
April 30, |
|
October 31, |
|
|
2011 |
|
2010 |
|
|
|
|
|
|
|
|
|
Trade accounts payable |
|
$ |
337 |
|
|
$ |
349 |
|
We own 40% of the membership interests in Pine Needle LNG Company, L.L.C. (Pine Needle), 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. For each period of the three months and six months ended
April 30, 2011 and 2010, these gas storage costs and the amounts we owed Pine Needle as of April
30, 2011 and October 31, 2010 are as follows.
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
Six Months |
In thousands |
|
2011 |
|
2010 |
|
2011 |
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas storage costs |
|
$ |
2,714 |
|
|
$ |
3,104 |
|
|
$ |
5,641 |
|
|
$ |
6,313 |
|
|
|
|
|
|
|
|
|
|
|
|
April 30, |
|
October 31, |
|
|
2011 |
|
2010 |
|
|
|
|
|
|
|
|
|
Trade accounts payable |
|
$ |
840 |
|
|
$ |
985 |
|
We own 15% of the membership interests in SouthStar Energy Services LLC (SouthStar), a Delaware
limited liability company. The other member is Georgia Natural Gas Company (GNGC), a wholly-owned
subsidiary of AGL Resources, Inc. SouthStar primarily sells natural gas to residential, commercial
and industrial customers in the southeastern United States and Ohio with most of its business being
conducted in the unregulated retail gas market in Georgia. On January 1, 2010, we sold half of our
30% membership interest in SouthStar to GNGC and retained a 15% earnings and membership share in
SouthStar after the sale. At closing, we received $57.5 million from GNGC, who has no further
rights to acquire our remaining 15% interest. We continue to account for our 15% membership
interest in SouthStar using the equity method, as we retain board representation with voting rights
equal to GNGC on significant governance matters and policy decisions, and thus, exercise
significant influence over the operations of SouthStar.
We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record in
operating revenues the amounts billed to SouthStar. For each period of the three months and six
months ended April 30, 2011 and 2010, our operating revenues from these sales and the amounts
SouthStar owed us as of April 30, 2011 and October 31, 2010 are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
Six Months |
In thousands |
|
2011 |
|
2010 |
|
2011 |
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
666 |
|
|
$ |
1,124 |
|
|
$ |
635 |
|
|
$ |
1,061 |
|
|
|
|
|
|
|
|
|
|
|
|
April 30, |
|
October 31, |
|
|
2011 |
|
2010 |
|
|
|
|
|
|
|
|
|
Trade accounts receivable |
|
$ |
744 |
|
|
$ |
713 |
|
Piedmont Hardy Storage Company, LLC, a wholly owned subsidiary of Piedmont, owns 50% of the
membership interests in Hardy Storage Company, LLC (Hardy Storage), a West Virginia limited
liability company. The other owner is a subsidiary of Columbia Gas Transmission Corporation, a
subsidiary of NiSource Inc. Hardy Storage owns and operates an underground interstate natural gas
storage facility located in Hardy and Hampshire Counties, West Virginia that is regulated by the
FERC.
We have related party transactions as a customer of Hardy Storage and record in cost of gas the
storage costs charged by Hardy Storage. For each period of the three months and six months ended
April 30, 2011 and 2010, these gas storage costs and the amounts we owed Hardy Storage as of April
30, 2011 and October 31, 2010 are as follows.
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
Six Months |
In thousands |
|
2011 |
|
2010 |
|
2011 |
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas storage costs |
|
$ |
2,425 |
|
|
$ |
2,300 |
|
|
$ |
4,851 |
|
|
$ |
4,535 |
|
|
|
|
|
|
|
|
|
|
|
|
April 30, |
|
October 31, |
|
|
2011 |
|
2010 |
|
|
|
|
|
|
|
|
|
Trade accounts payable |
|
$ |
780 |
|
|
$ |
808 |
|
9. Variable Interest Entities
Effective November 1, 2010, we adopted the guidance that requires us to evaluate our variable
interest in a variable interest entity (VIE) to qualitatively assess whether we have a controlling
financial interest, and if so, determine whether we are the primary beneficiary. Under accounting
guidance, a VIE is a legal entity that conducts a business or holds property whose equity, by
design, has any of the following characteristics: an insufficient amount of equity at risk to
finance its activities, equity owners who do not have the power to direct the significant
activities of the entity (or have voting rights that are disproportionate to their ownership
interest), or where equity owners do not receive expected losses or returns. An entity may have an
interest in a VIE through ownership or other contractual rights or obligations and that interest
changes as the entitys net assets change. The consolidating investor is the entity that has the
power to direct the activities of a VIE that most significantly impact the VIEs economic
performance, and the obligation to absorb losses of the entity that could potentially be
significant to the VIE or the right to receive benefits from the VIE that could potentially be
significant to the VIE.
As of April 30, 2011, we have determined that we are not the primary beneficiary, as defined by the
authoritative guidance related to consolidations, in any of our equity method investments, which
are discussed in Note 8. Based on our involvement in these investments, we do not have the power
to direct the activities of these investments that most significantly impact the VIEs economic
performance.
Our investments in joint ventures, as discussed in Note 8, are currently accounted for under the
equity method. We will continue to account for these investments under this method, as we
determined we are not the consolidating investor. As of April 30, 2011, our maximum loss exposure
related to these equity method investments is limited to our equity investment in each entity. Our
investment balances are as follows.
|
|
|
|
|
|
|
|
|
|
|
April 30, |
|
|
October 31, |
|
In thousands |
|
2011 |
|
|
2010 |
|
|
|
|
|
|
|
|
|
|
Cardinal |
|
$ |
15,770 |
|
|
$ |
11,837 |
|
Pine Needle |
|
|
19,263 |
|
|
|
21,810 |
|
SouthStar |
|
|
17,919 |
|
|
|
17,146 |
|
Hardy Storage |
|
|
30,145 |
|
|
|
29,494 |
|
|
|
|
|
|
|
|
Total equity method investments in non-utility activities |
|
$ |
83,097 |
|
|
$ |
80,287 |
|
|
|
|
|
|
|
|
We have also reviewed various lease arrangements, contracts to purchase, sell or deliver natural
gas and other agreements in which we hold a variable interest. The adoption of this guidance on
November 1, 2010 for these arrangements, contracts and other agreements did not have a material
impact on our financial position, results of operations or cash flows.
17
10. Financial Instruments and Related Fair Value
Derivative Assets and Liabilities under Master Netting Arrangements
We maintain brokerage accounts to facilitate transactions that support our gas cost hedging plans.
The accounting guidance related to derivatives and hedging requires that we use a gross
presentation, based on our election, for the fair value amounts for our derivative instruments and
the fair value of the right to reclaim cash collateral. We use long position gas purchase options
to provide some level of protection for our customers in the event of significant commodity price
increases. As of April 30, 2011 and October 31, 2010, we had long gas purchase options providing
total coverage of 26.5 million dekatherms and 33.5 million dekatherms, respectively. The long gas
purchase options held at April 30, 2011 are for the period from June 2011 through April 2012.
Fair Value Measurements
In developing our fair value measurements of our financial instruments, we utilize market data or
assumptions about risk and the risks inherent in the inputs to the valuation technique. Fair value
refers to the price that would be received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants in the market in which the entity transacts. We
classify fair value balances based on the observance of those inputs into the fair value hierarchy
levels as set forth in the fair value accounting guidance and fully described in Note 1.F to the
consolidated financial statements in our Form 10-K for the year ended October 31, 2010.
The following table sets forth, by level of the fair value hierarchy, our financial assets and
liabilities that were accounted for at fair value on a recurring basis as of April 30, 2011 and
October 31, 2010. Financial assets and liabilities are classified in their entirety based on the
lowest level of input that is significant to the fair value measurement. Our assessment of the
significance of a particular input to the fair value measurement requires judgment and may affect
the valuation of fair value assets and liabilities and their consideration within the fair value
hierarchy levels. We have had no transfers between any level during the three months ended April
30, 2011 and 2010.
Recurring Fair Value Measurements as of April 30, 2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Significant |
|
|
|
|
|
|
|
|
|
Quoted Prices |
|
|
Other |
|
|
Significant |
|
|
|
|
|
|
in Active |
|
|
Observable |
|
|
Unobservable |
|
|
Total |
|
|
|
Markets |
|
|
Inputs |
|
|
Inputs |
|
|
Carrying |
|
In thousands |
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives held for distribution operations |
|
$ |
5,599 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
5,599 |
|
Debt and equity securities held as trading securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money markets |
|
|
218 |
|
|
|
|
|
|
|
|
|
|
|
218 |
|
Mutual funds |
|
|
1,360 |
|
|
|
|
|
|
|
|
|
|
|
1,360 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total fair value assets |
|
$ |
7,177 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
7,177 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
Recurring Fair Value Measurements as of October 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Significant |
|
|
|
|
|
|
|
|
|
Quoted Prices |
|
|
Other |
|
|
Significant |
|
|
|
|
|
|
in Active |
|
|
Observable |
|
|
Unobservable |
|
|
Total |
|
|
|
Markets |
|
|
Inputs |
|
|
Inputs |
|
|
Carrying |
|
In thousands |
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives held for distribution operations |
|
$ |
2,819 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
2,819 |
|
Debt and equity securities held as trading securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money markets |
|
|
254 |
|
|
|
|
|
|
|
|
|
|
|
254 |
|
Mutual funds |
|
|
748 |
|
|
|
|
|
|
|
|
|
|
|
748 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total fair value assets |
|
$ |
3,821 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
3,821 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our utility segment derivative instruments are used in accordance with programs filed with or
approved by the NCUC, the PSCSC and the TRA to hedge the impact of market fluctuations in natural
gas prices. These derivative instruments are accounted for at fair value each reporting period.
In accordance with regulatory requirements, the net costs and the gains and losses related to these
derivatives are reflected in purchased gas costs and ultimately passed through to customers through
our PGA procedures. In accordance with accounting provisions for rate-regulated activities, the
unrecovered amounts related to these instruments are reflected as a regulatory asset or liability,
as appropriate, in Amounts due from customers or Amounts due to customers in the consolidated
balance sheets. These derivative instruments include exchange-traded derivative contracts.
Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and are
classified within Level 1.
Trading securities include assets in a rabbi trust established for our deferred compensation plans
and are included in Marketable securities, at fair value in the consolidated balance sheets.
Securities classified within Level 1 include funds held in money market and mutual funds, which are
highly liquid and are actively traded on the exchanges.
In developing the fair value of our long-term debt, we use a discounted cash flow technique,
consistently applied, that incorporates a developed discount rate using long-term debt similarly
rated by credit rating agencies combined with the U.S. Treasury bench mark with consideration given
to maturities, redemption terms and credit ratings similar to our debt issuances. The carrying
amount and fair value of our long-term debt, including the current portion, are shown below.
|
|
|
|
|
|
|
|
|
|
|
Carrying |
|
|
In thousands |
|
Amount |
|
Fair Value |
|
|
|
|
|
|
|
|
|
As of April 30, 2011 |
|
$ |
731,843 |
|
|
$ |
828,297 |
|
As of October 31, 2010 |
|
|
731,922 |
|
|
|
890,277 |
|
Quantitative and Qualitative Disclosures
The costs of our financial price hedging options for natural gas and all other costs related to
hedging activities of our regulated gas costs are recorded in accordance with our regulatory
tariffs approved by our state regulatory commissions, and thus are not accounted for as hedging
instruments under derivative accounting standards. As required by the accounting guidance, the
fair value amounts are presented on a gross basis and do
19
not reflect any netting of asset and
liability amounts or cash collateral amounts under master netting arrangements.
The following table presents the fair value and balance sheet classification of our financial
options for natural gas as of April 30, 2011 and October 31, 2010.
Fair Value of Derivative Instruments
|
|
|
|
|
|
|
|
|
|
|
Fair Value |
|
|
Fair Value |
|
In thousands |
|
April 30, 2011 |
|
|
October 31, 2010 |
|
|
|
|
|
|
|
|
|
|
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards: |
|
|
|
|
|
|
|
|
Asset Financial Instruments: |
|
|
|
|
|
|
|
|
Current Assets Gas purchase derivative assets (June 2011-April 2012) |
|
$ |
5,599 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets Gas purchase derivative assets (December 2010-November 2011) |
|
|
|
|
|
$ |
2,819 |
|
|
|
|
|
|
|
|
|
We purchase natural gas for our regulated operations for resale under tariffs approved by state
regulatory commissions. We recover the cost of gas purchased for regulated operations through PGA
procedures. Our risk management policies allow us to use financial instruments to hedge commodity
price risks, but not for speculative trading. The strategy and objective of our hedging programs
is to use these financial instruments to provide protection against significant price increases.
Accordingly, the operation of the hedging programs on the regulated utility segment as a result of
the use of these financial derivatives generally has no earnings impact.
The following table presents the impact that financial instruments not designated as hedging
instruments under derivative accounting standards would have had on our consolidated statements of
income for the three months and six months ended April 30, 2011 and 2010, absent the regulatory
treatment under our approved PGA procedures.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Location of Loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recognized through |
|
|
Amount of Loss Recognized on Derivatives and Deferred Under PGA Procedures |
|
PGA Procedures |
|
|
Three Months Ended |
|
Six Months Ended |
|
|
|
|
April 30 |
|
April 30 |
|
|
In thousands |
|
2011 |
|
2010 |
|
2011 |
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas purchase options |
|
$ |
1,903 |
|
|
$ |
17,126 |
|
|
$ |
6,125 |
|
|
$ |
33,776 |
|
|
Cost of Gas |
In Tennessee, the cost of gas purchase options and all other costs related to hedging activities up
to 1% of total annual gas costs are approved for recovery under the terms and conditions of our TIP
approved by the TRA. In South Carolina, the costs of gas purchase options are pre-approved by the
PSCSC for recovery from customers subject to the terms and conditions of our gas hedging plan
approved by the PSCSC. In North Carolina, the costs associated with our hedging program are not
pre-approved by the NCUC but are treated as gas costs subject to an annual cost review proceeding
by the NCUC.
Risk Management
Our financial derivative instruments do not contain material credit-risk-related or other
contingent features that could require us to make accelerated payments.
We seek to identify, assess, monitor and manage risk in accordance with defined policies and
procedures under
20
an Enterprise Risk Management program. In addition, we have an Energy Price Risk
Management Committee (EPRMC) that monitors compliance with our hedging programs, policies and
procedures.
11. Long-Term Debt Instruments
During the six months ended April 30, 2011 and 2010, we paid principal amounts of $.1 million and
$.4 million, respectively, to noteholders of the 6.25% insured quarterly notes. These notes have a
redemption right upon the death of the owner of the notes, within specified limitations.
On April 25, 2011, at our direction, the Trustee notified the noteholders of the 6.25% insured
quarterly notes that we will redeem all of the notes on June 1, 2011, which have an aggregate
principal balance of $196.8 million. As we have notified the noteholders of the redemption, we
have reclassified the principal balance to Current maturities of long-term debt in the
consolidated balance sheets.
On June 6, 2011, we intend to issue five-year $40 million notes at an interest rate of 2.92% and
ten-year $160 million notes at an interest rate of 4.24%. For information on the issuance of this
debt, see Note 15 to the consolidated financial statements in this Form 10-Q.
12. Short-Term Debt Instruments
We have a $650 million three-year unsecured revolving syndicated credit facility that expires in
January 2014. The facility has an option to expand up to $850 million. We pay an annual fee of
$30,000 plus fifteen basis points for any unused amount up to $650 million. This facility provides
a line of credit for letters of credit of $10 million, of which $3.5 million was issued and
outstanding at April 30, 2011. The five-year credit facility in place prior to January 25, 2011
provided a line of credit for letters of credit of $5 million, of which $2.7 million was issued and
outstanding at October 31, 2010. These letters of credit are used to guarantee claims from
self-insurance under our general and automobile liability policies. The credit facility bears
interest based on the 30-day LIBOR rate plus from 65 to 150 basis points, based on our credit
ratings. Amounts borrowed remain outstanding until repaid and such amounts do not mature daily.
Due to the seasonal nature of our business, amounts borrowed can vary significantly during the
year.
Our outstanding short-term bank borrowings, as included in Bank debt in the consolidated balance
sheets, were $103.5 million, as of April 30, 2011 under our syndicated three-year credit facility
and $242 million, as of October 31, 2010 under our syndicated five-year credit facility, in LIBOR
cost-plus loans. During the three months ended April 30, 2011, short-term bank borrowings ranged
from $87 million to $306 million, and interest rates ranged from 1.12% to 1.17% (weighted average
of 1.16%). During the six months ended April 30, 2011, short-term bank borrowings ranged from $87
million to $426 million, and interest rates ranged from .51% to 1.17% (weighted average of .78%).
Our syndicated three-year revolving credit facilitys financial covenants require us to maintain a
ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 45% at
April 30, 2011.
13. Employee Share-Based Plans
Under our shareholder approved incentive compensation plan, eligible officers and other
participants are awarded units that pay out depending upon the level of performance achieved by
Piedmont during three-year incentive plan performance periods. Distribution of those awards may be
made in the form of shares of common stock and withholdings for payment of applicable taxes on the
compensation. These plans require that a minimum threshold performance level be achieved in order
for any award to be distributed. For the three months and six months ended April 30, 2011 and
2010, we recorded compensation expense, and as of April 30, 2011 and October 31, 2010, we have
accrued a liability for these awards based on the fair market value of our stock at the end of each
quarter. The liability is re-measured to market value at the settlement date.
21
In December 2010, a long-term retention award under the incentive compensation plan was
approved for eligible officers and other participants. This is a retention award that will be
distributed to participants who have met the retention requirements at the end of a three-year
period ending in December 2013 in the form of shares of common stock and withholdings for payment
of applicable taxes on the compensation. For the three months and six months ended April 30, 2011,
we recorded compensation expense, and as of April 30, 2011, we have accrued a liability for these
awards based on the fair market value of our stock at the end of the quarter. The liability is
re-measured to market value at the settlement date.
Also under our approved incentive plan, 65,000 unvested shares of our common stock were granted to
our President and Chief Executive Officer in September 2006. During the five-year vesting period,
any dividends paid on these shares are accrued and converted into additional shares at the closing
price on the date of the dividend payment. In accordance with the vesting schedule, 20% and 30% of
the shares vested on September 1, 2009 and 2010, respectively. The remaining 50% of the shares
will vest on September 1, 2011. For the three months and six months ended April 30, 2011 and 2010,
we recorded compensation expense, and as of April 30, 2011 and October 31, 2010, we have accrued a
liability for the award based on the fair market value of our stock at the end of each quarter.
The liability is re-measured to market value at the settlement date.
The compensation expense related to the incentive compensation plans for the three months and six
months ended April 30, 2011 and 2010, and the amounts recorded as liabilities as of April 30, 2011
and October 31, 2010 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
Six Months |
In thousands |
|
2011 |
|
2010 |
|
2011 |
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Compensation expense |
|
$ |
1,244 |
|
|
$ |
1,955 |
|
|
$ |
2,166 |
|
|
$ |
4,729 |
|
|
|
|
|
|
|
|
|
|
|
|
April 30, |
|
October 31, |
|
|
2011 |
|
2010 |
|
|
|
|
|
|
|
|
|
Liability |
|
$ |
5,932 |
|
|
$ |
9,914 |
|
On a quarterly basis, we issue shares of common stock under the employee stock purchase plan
(ESPP) and have accounted for the issuance as an equity transaction. The exercise price is
calculated as 95% of the fair market value on the purchase date of each quarter where fair market
value is determined by calculating the mean average of the high and low trading prices on the
purchase date.
Currently, it is our policy to issue new shares for share-based awards. Shares of common stock to
be issued under approved incentive compensation plans are contingently issuable shares and are
included in our calculation of fully diluted earnings per share.
14. Commitments and Contingent Liabilities
Long-term contracts
We routinely enter into long-term gas supply commodity and capacity commitments and other
agreements that commit future cash flows to acquire services we need in our business. These
commitments include pipeline and storage capacity contracts and gas supply contracts to provide
service to our customers and telecommunication and information technology contracts and other
purchase obligations. The time periods for pipeline and storage
22
capacity contracts range from one
to 21 years. The time periods for gas supply contracts range from one to two
years. The time periods for the telecommunications and technology outsourcing contracts,
maintenance fees for hardware and software applications, usage fees, local and long-distance costs
and wireless service range from one to four years. Other purchase obligations consist primarily of
commitments for pipeline products, vehicles and contractors.
Certain storage and pipeline capacity contracts require the payment of demand charges that are
based on rates approved by the FERC in order to maintain our right to access the natural gas
storage or the pipeline capacity on a firm basis during the contract term. The demand charges that
are incurred in each period are recognized in the consolidated statements of income as part of gas
purchases and included in cost of gas.
Leases
We lease certain buildings, land and equipment for use in our operations under noncancelable
operating leases.
Legal
We have only routine litigation in the normal course of business.
Letters of Credit
We use letters of credit to guarantee claims from self-insurance under our general liability
policies. We had $3.5 million in letters of credit that were issued and outstanding at April 30,
2011. Additional information concerning letters of credit is included in Note 12 to the
consolidated financial statements in this Form 10-Q.
Environmental Matters
Our three regulatory commissions have authorized us to utilize deferral accounting in connection
with environmental costs. Accordingly, we have established regulatory assets for actual
environmental costs incurred and for estimated environmental liabilities recorded.
In October 1997, we entered into a settlement with a third party with respect to nine manufactured
gas plant (MGP) sites that we have owned, leased or operated and paid $5.3 million, charged to the
estimated environmental liability, that released us from any investigation and remediation
liability. Although no such claims are pending or, to our knowledge, threatened, the settlement
did not cover any third-party claims for personal injury, death, property damage and diminution of
property value or natural resources.
There are three other MGP sites located in Hickory, North Carolina, Nashville, Tennessee and
Anderson, South Carolina that we have owned, leased or operated. In addition to these sites, we
acquired the liability for an MGP site located in Reidsville, North Carolina, in connection with
the acquisition in 2002 of certain assets and liabilities of North Carolina Services, a division of
NUI Utilities, Inc.
As part of a voluntary agreement with the North Carolina Department of Environment and Natural
Resources (NCDENR), we conducted and completed the soil and groundwater remediation for the
Hickory, North Carolina MGP site. Although the soil and groundwater remediation report was
approved by NCDENR, we will continue to and are currently conducting periodic groundwater
monitoring at this site. We have incurred $1.4 million on this site through April 30, 2011.
In September 2009, the NCDENR requested an investigation plan for the Reidsville, North Carolina
MGP site. In June 2010, we conducted our initial investigation which consisted of digging test
pits and completing soil and groundwater contamination testing. The site investigations are now
complete and a draft remediation plan has
23
been
submitted to the NCDENR for review. Our estimate of
the total cost to remediate the Reidsville site is $.8
million for which we have recorded a liability.
In November 2008, we submitted our final report of the remediation of the Nashville MGP holding
tank site to the Tennessee Department of Environment and Conservation (TDEC). Remediation has been
completed, and a consent order imposing usage restrictions on the property was approved and signed
by the TDEC in June 2010. The public comment period has ended and we are currently conducting
periodic groundwater monitoring at the site per the final consent order. We have incurred $1.5
million through April 30, 2011 for this remediation.
In connection with the 2003 North Carolina Natural Gas Corporation (NCNG) acquisition, several MGP
sites owned by NCNG were transferred to a wholly owned subsidiary of Progress Energy, Inc.
(Progress) prior to closing. Progress has complete responsibility for performing all of NCNGs
remediation obligations to conduct testing and clean-up at these sites, including both the costs of
such testing and clean-up and the implementation of any affirmative remediation obligations that
NCNG has related to the sites. Progress responsibility does not include any third-party claims
for personal injury, death, property damage, and diminution of property value or natural resources.
We know of no such pending or threatened claims.
At our Huntersville LNG facility, we are continuing to address the remaining remediation issues,
including monitoring groundwater contamination and removing lead-based paint, with the latter
scheduled to be finished in our fiscal year 2011. As of April 30, 2011, our estimate of the total
cost to remediate the property is $3.1 million and we have incurred $2.9 million through April 30,
2011.
During the six months ended April 30, 2011, we assessed the cost to remove lead-based paint at our
Nashville LNG facility, and we increased our reserve by $.5 million. The removal of lead-based
paint at our Nashville LNG facility is scheduled to be completed in fiscal 2011.
We are transitioning away from owning and maintaining our own petroleum underground storage tanks
(USTs). Only our districts in Charlotte, North Carolina and Greenville, South Carolina continue to
operate USTs. Our Greenville district has begun plans to have its USTs removed in our third fiscal
quarter 2011. As of April 30, 2011, our undiscounted environmental liability for USTs for which we
retain remediation responsibility is $.4 million.
One of our operating districts has coatings containing asbestos on some of their pipelines. We
have educated our employees on the hazards of asbestos and implemented procedures for removing
these coatings from our pipelines when we must excavate and expose small portions of the pipeline.
Lead-based paint is being removed at multiple LNG facilities that we own. Employees have been
trained on the hazards of lead exposure, and we have engaged independent environmental contractors
to remove and dispose of the lead-based paint at these facilities. Based on information we have to
date, we believe that the ultimate resolution of these matters will not have a material adverse
effect on our financial position, results of operations or cash flows.
As of April 30, 2011, our undiscounted environmental liability totaled $2.3 million, and consisted
of $1.5 million for the four MGP sites for which we retain remediation responsibility, $.4 million
for the LNG facilities and $.4 million for the USTs not yet remediated. Further evaluation of the
MGP sites, the UST sites and removal of lead-based paint could significantly affect recorded
amounts; however, we believe that the ultimate resolution of these matters will not have a material
adverse effect on our financial position, results of operations or cash flows.
Additional information concerning commitments and contingencies is set forth in Note 7 to the
consolidated financial statements of our Form 10-K for the year ended October 31, 2010.
24
15. Subsequent Events
We monitor significant events occurring after the balance sheet date and prior to the issuance of
the financial statements to determine the impacts, if any, of events on the financial statements to
be issued. All subsequent events of which we are aware have been evaluated. For information on
subsequent event disclosure related to regulatory matters, see Note 2 to the consolidated financial
statements in this Form 10-Q.
On June 1, 2011, we redeemed all of the 6.25% insured quarterly notes with an aggregate principal
balance of $196.8 million. We financed the debt redemption with short-term bank borrowings under
the revolving syndicated credit facility.
On June 6, 2011, we issued $40 million unsecured senior notes maturing in 2016 that bear an
interest rate of 2.92% and $160 million unsecured senior notes maturing in 2021 that bear an
interest rate of 4.24%. We used the proceeds from the sale of the senior notes to reduce our
short-term borrowings as well as for other general corporate purposes and working capital needs.
Item 2. Managements Discussion and Analysis of Financial Condition and Results of
Operations
Forward-Looking Statements
This report, as well as other 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 affecting us and those from whom we purchase natural gas
transportation and storage service, including those that affect allowed rates of return,
terms and conditions of service, rate structures and financings. We monitor our ability
to earn appropriate rates of return and initiate general rate proceedings as needed. |
|
|
|
Residential, commercial, industrial and power generation growth and energy
consumption in our service areas. The ability to retain and grow our customer base, the
pace of that growth and the levels of energy consumption 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 competitive environment to continue. |
|
|
|
The potential loss of large-volume industrial customers to alternate fuels or to
bypass, or the shift by such customers to special competitive contracts or to tariff
rates that are at lower per-unit margins than that customers existing rate. |
|
|
|
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 and the ability to
complete these capital projects may be affected by the ability to obtain and the cost of
obtaining governmental approvals, compliance with federal and state pipeline safety and
integrity regulations, cost and timing of project |
25
|
|
|
development-related contracts, project development delays, federal and state tax
policies, and the cost and availability of labor and materials. Weather, general
economic conditions and the cost of funds to finance our capital projects can materially
alter the cost and timing of a project. |
|
|
|
Access to capital markets. Our internally generated cash flows are not adequate to
finance the full cost of capital expenditures. 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
capital markets, in our financial condition or in the financial condition of our lenders
or investors could affect access to and cost of capital. |
|
|
|
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, regulatory 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. Since such
risks may affect the availability and cost of natural gas, they also may affect the
competitive position of natural gas relative to other energy sources. |
|
|
|
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, tornadoes and floods, can impact our
customers, our suppliers and the pipelines that deliver gas to our distribution system
and our distribution and transmission assets. Weather conditions directly influence the
supply, demand, distribution and cost of natural gas. |
|
|
|
Changes in environmental, safety, system integrity, tax and other laws and
regulations, including those related to carbon regulations, and the cost of compliance.
We are subject to extensive federal, state and local laws and regulations. Compliance
with such laws and regulations could increase capital or operating costs, affect our
reported earnings or cash flows, increase our liabilities or change the way our business
is conducted. |
|
|
|
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, and 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 these risks may negatively affect our
earnings from those companies. |
|
|
|
Changes in outstanding shares. The number of outstanding shares may fluctuate due to
new issuances or repurchases under our Common Stock Open Market Purchase Program. |
Other factors may be described elsewhere in this report. All of these factors are difficult to
predict and many 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, 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.
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 website at www.piedmontng.com
26
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 website as soon as reasonably practicable after the report
is filed with or furnished to the SEC.
Executive Overview
Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company
whose principal business is the distribution of natural gas to over one million residential,
commercial, industrial and power generation customers in portions of North Carolina, South Carolina
and Tennessee, including 53,000 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.
In 1994, our predecessor, which was incorporated in 1950 under the same name, was merged into a
newly formed North Carolina corporation for the purpose of changing our state of incorporation to
North Carolina.
In the Carolinas, our service area is comprised of numerous cities, towns and communities. We
provide service to Anderson, Gaffney, Greenville and Spartanburg in South Carolina and Charlotte,
Salisbury, Greensboro, Winston-Salem, High Point, Burlington, Hickory, Indian Trail, 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 the cities
of Greenville, Rocky Mount and Wilson. In Tennessee, our service area is the metropolitan area of
Nashville, including wholesale natural gas service to the cities of Gallatin and Smyrna.
We have two reportable business segments, regulated utility and non-utility activities. The
regulated utility segment is the largest segment of our business with approximately 97% of our
consolidated assets. Factors critical to the success of the regulated segment include operating a
safe, reliable natural gas distribution system and the ability to recover the costs and expenses of
the business in the rates charged to customers. For the six months ended April 30, 2011, 91% 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 and regulated interstate natural gas
storage and intrastate natural gas transportation. For the six months ended April 30, 2011, 9% of
our earnings before taxes came from our non-utility activities segment, which consists of 2% from
regulated non-utility activities and 7% from unregulated non-utility activities.
For further information on business segments, see Note 7 to the consolidated financial statements
in this Form 10-Q. For information about our equity method investments, see Note 8 to the
consolidated financial statements in this Form 10-Q.
Our utility operations are regulated by the NCUC, the PSCSC and the TRA as to rates, service area,
adequacy of service, safety standards, extensions and abandonment of facilities, accounting and
depreciation. The NCUC also regulates us 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 purchase
and sale of and the prices paid for the interstate transportation and storage of natural gas,
regulations of the U.S. Department of Transportation (DOT) that affect the design, construction,
operation, maintenance, integrity, safety and security of natural gas distribution and transmission
systems, and regulations of the Environmental Protection Agency relating to the environment. 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.
Our regulatory commissions approve rates and tariffs that are designed to give us the opportunity
to generate
27
revenues to cover our gas and non-gas costs and to earn a fair rate of return on invested capital
for our shareholders. Our ability to earn our authorized rates of return is based primarily on our
ability to reduce or eliminate regulatory lag and also by improved rate designs that decouple the
recovery of our approved margins from customer usage patterns impacted by seasonal weather patterns
and customer conservation.
In North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin
from residential and commercial customers independent of consumption patterns. The margin
decoupling mechanism results in semi-annual rate adjustments to refund any over-collection of
margin or recover any under-collection of margin. We have weather normalization adjustment (WNA)
mechanisms in South Carolina and Tennessee that partially offset the impact of colder- or
warmer-than-normal winter weather on bills rendered during the months of November through March for
residential and commercial customers. The WNA formula calculates the actual weather variance from
normal, using 30 years of history, which increases revenues when weather is warmer than normal and
decreases 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 margin decoupling mechanism or the
WNA.
We continually assess alternative rate structures and cost recovery mechanisms that are more
appropriate to the changing energy economy. We have been pursuing alternatives to the traditional
utility rate design that provide for the collection of margin revenue based on volumetric
throughput with new rate designs and incentives that allow utilities to encourage energy efficiency
and conservation. By breaking the link between energy consumption and margin revenues, or
decoupling as we say, our interests are aligned with our customers interests on conservation and
energy efficiency. In North Carolina, we have decoupled residential and commercial rates. In
South Carolina, we operate under a rate stabilization mechanism that achieves the objectives of
margin decoupling for residential and commercial customers with a one year lag. We are evaluating
our current rate structures in Tennessee. For the fiscal year ended October 31, 2010, these rate
designs stabilized our gas utility margin by providing fixed recovery of 71% of our utility
margins, including margin decoupling in North Carolina, facilities charges to our customers and
fixed-rate contracts; semi-fixed recovery of 18% of our utility margins, including the rate
stabilization mechanism in South Carolina and WNA in South Carolina and Tennessee; and volumetric
or periodic renegotiation of 11% of our utility margins. For the six months ended April 30, 2011,
the margin decoupling mechanism in North Carolina reduced margin by $16.2 million, and the WNA in
South Carolina and Tennessee reduced margin by $4.7 million.
Our strategic focus is on our core business of providing safe, reliable and quality natural gas
distribution service to our customers in the growing Southeast market area. Part of our strategic
plan is to responsibly manage our gas distribution business through control of our operating costs,
implementation of new technologies and sound rate and regulatory initiatives. To enhance the value
and growth of our utility assets, we focus on the sound management of our capital spending, looking
at projects and initiatives that will improve service for current customers and provide profitable
customer growth opportunities in our service areas with an appropriate return on invested capital.
We work with our state regulators to maintain fair rates of return and balance the interests of our
customers and shareholders. Our goal is to develop, integrate, consolidate and streamline
operations and support our employees with new processes and technology to better serve our
customers and to add value for our shareholders.
Our capital plan includes maintaining a long-term debt-to-capitalization ratio within a range of
45% to 50%. We also seek to maintain a strong balance sheet and investment-grade credit ratings to
support our operating and investment needs.
We continue to work toward a business model that positions us for long-term success in a lower
carbon energy economy with a focus on future growth opportunities that support new clean energy
technologies. We are seeking opportunities for regulatory innovation and strategic alliances to
advance our customers interests in
28
energy conservation and efficiency and environmental stewardship. We are continually reviewing our
business processes for quality and efficiency with a concentration on customer-oriented process
improvements.
We will continue our efforts to promote the direct use of natural gas in more homes, businesses,
industries and vehicles. We continue to believe that the expanded use of domestic natural gas with
its relatively low emissions can help revitalize our economy, reduce both overall greenhouse gas
emissions and energy consumption and enhance our national energy security. Price moderation and
stability of natural gas continues, which has made natural gas more competitive against other
fuels.
The continued safety of our system, the public and our employees is a critical component to our
ongoing success as a company. We are subject to DOT and state regulation of our pipeline and
related facilities, and for example, have historically inspected our system for corrosion and
leaks. Given an increased interest in pipeline safety and integrity in the wake of several serious
pipeline incidents in the United States, we anticipate federal legislative and regulatory
enactments that will likely add further requirements to our already active pipeline safety and
integrity program. Currently, for example, and as one part of a holistic federal and state
regulatory regime, we are on track to meet an August 2011 deadline to evaluate any risks to our
distribution pipeline system (such as corrosion, leak detection) and create an action plan to
address those risks. Additionally, we have transmission pipeline integrity programs composed of
standard procedures and programs for pipeline safety that include leak detection surveys, periodic
valve maintenance, periodic corrosion and atmospheric corrosion inspections, cathodic protection
and hydrostatic and compressed air pressure testings and other evaluation methods. We will
continue our efforts to educate the public about our pipeline system in an effort to decrease third
party excavation damage, by far our greatest cause of any pipeline incidents on our system. We
welcome focused efforts to improve the safety of our industry as a whole.
We have completed two projects to date in fiscal year 2011 to provide long-term gas transportation
service to power generation projects in our market area. We have three projects under construction
for two electric utilities in North Carolina to provide natural gas delivery service to power
generation facilities currently under construction with targeted in service dates of November 2011,
June 2012 and June 2013. We do not believe the planned merger of these two electric utilities will
affect these projects. In addition to the environmental benefits of using natural gas at these new
plants instead of coal, the construction of the natural gas pipelines for these projects will also
add to our natural gas infrastructure in the eastern part of North Carolina and enhance future
opportunities for economic growth and development. See the discussion of our anticipated capital
investment related to the construction of the natural gas pipelines and compressor stations to
serve these new power generation facilities in Cash Flows from Investing Activities in
Managements Discussion and Analysis of Financial Condition and Results of Operations in Item 2 in
this Form 10-Q.
We continue to see challenging economic conditions in our market area as evidenced by high rates of
unemployment, a depressed housing market, significantly reduced new home construction and slower
new commercial development. As discussed above, we are positioning ourselves to capitalize on new
opportunities as the economy slowly improves, and continue to focus on customer conversions to
natural gas and power generation gas delivery service opportunities. As we seek to expand the use
of natural gas, we continue to emphasize natural gas as the fuel of choice for customers, including
the comfort, affordability, reliability and efficiency of natural gas, as well as remind our
customers of our reliability and safety as a company. We forecast gross customer addition growth
for fiscal 2011 of approximately 1%.
We invest in joint ventures to complement or supplement income from our regulated utility
operations if an opportunity aligns with our overall business strategies and allows us to leverage
our core competencies. We analyze and evaluate potential projects with a major factor being a
projected rate of return greater than the returns allowed in our utility operations based on the
risk of such projects. We participate in the governance of our ventures by having management
representatives on the governing boards. We monitor actual performance
29
against expectations, and any decision to exit an existing joint venture would be based on many
factors, including performance results and continued alignment with our business strategies.
Several new laws were enacted in 2010 for health care reform and the regulation of U.S. financial
markets. We continue to follow the progress of new regulations that will be issued by various
regulatory agencies. While we are not able to assess the full impact of these laws until the
implementing regulations have been adopted, based on the information available to us at this time,
we do not expect these laws to have a material adverse impact on our financial position, results of
operations or cash flows.
Also, the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010, enacted
in December 2010, extends the 50% bonus depreciation that expired December 31, 2009 and
temporarily increases bonus depreciation for federal income tax purposes to 100% for certain
qualified investments. These provisions will affect our fiscal year tax returns for 2010-2014.
The Internal Revenue Service has issued regulations that are intended to provide guidance in
interpreting the law. We are in the process of assessing the full impact of this law, but our
initial assessment is that there will be a $130-$170 million benefit through 2014. We anticipate
that the bonus depreciation allowance will have a material favorable impact on our cash flows in
the near term by reducing cash needed to pay federal income taxes.
Results of Operations
We reported net income of $47.4 million for the three months ended April 30, 2011 as compared to
$46.8 million for the same period in 2010. The following table sets forth a comparison of the
components of our consolidated statements of income for the three months ended April 30, 2011 as
compared with the three months ended April 30, 2010.
Income Statement Components
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended April 30 |
|
|
|
|
|
|
|
In thousands, except per share amounts |
|
2011 |
|
|
2010 |
|
|
Variance |
|
|
Percent Change |
|
Operating Revenues |
|
$ |
392,567 |
|
|
$ |
472,846 |
|
|
$ |
(80,279 |
) |
|
|
(17.0 |
)% |
Cost of Gas |
|
|
219,636 |
|
|
|
304,168 |
|
|
|
(84,532 |
) |
|
|
(27.8 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Margin |
|
|
172,931 |
|
|
|
168,678 |
|
|
|
4,253 |
|
|
|
2.5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and Maintenance |
|
|
58,936 |
|
|
|
57,503 |
|
|
|
1,433 |
|
|
|
2.5 |
% |
Depreciation |
|
|
25,425 |
|
|
|
24,483 |
|
|
|
942 |
|
|
|
3.8 |
% |
General Taxes |
|
|
9,464 |
|
|
|
8,758 |
|
|
|
706 |
|
|
|
8.1 |
% |
Utility Income Taxes |
|
|
26,179 |
|
|
|
25,709 |
|
|
|
470 |
|
|
|
1.8 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Expenses |
|
|
120,004 |
|
|
|
116,453 |
|
|
|
3,551 |
|
|
|
3.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income |
|
|
52,927 |
|
|
|
52,225 |
|
|
|
702 |
|
|
|
1.3 |
% |
Other Income (Expense), net of tax |
|
|
7,344 |
|
|
|
7,611 |
|
|
|
(267 |
) |
|
|
(3.5 |
)% |
Utility Interest Charges |
|
|
12,863 |
|
|
|
13,011 |
|
|
|
(148 |
) |
|
|
(1.1 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
$ |
47,408 |
|
|
$ |
46,825 |
|
|
$ |
583 |
|
|
|
1.2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Shares of Common Stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
71,824 |
|
|
|
71,788 |
|
|
|
36 |
|
|
|
0.1 |
% |
Diluted |
|
|
72,061 |
|
|
|
72,118 |
|
|
|
(57 |
) |
|
|
(0.1 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Per Share of Common Stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.66 |
|
|
$ |
0.65 |
|
|
$ |
0.01 |
|
|
|
1.5 |
% |
Diluted |
|
$ |
0.66 |
|
|
$ |
0.65 |
|
|
$ |
0.01 |
|
|
|
1.5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
We reported a net income of $131.8 million for the six months ended April 30, 2011 as compared
to $160.6 million for the same period in 2010. The following table sets forth a comparison of the
components of our
30
consolidated statements of income for the six months ended April 30, 2011 as compared with the six
months ended April 30, 2010.
Income Statement Components
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended April 30 |
|
|
|
|
|
|
|
In thousands, except per share amounts |
|
2011 |
|
|
2010 |
|
|
Variance |
|
|
Percent Change |
|
Operating Revenues |
|
$ |
1,044,623 |
|
|
$ |
1,146,582 |
|
|
$ |
(101,959 |
) |
|
|
(8.9 |
)% |
Cost of Gas |
|
|
641,686 |
|
|
|
754,962 |
|
|
|
(113,276 |
) |
|
|
(15.0 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Margin |
|
|
402,937 |
|
|
|
391,620 |
|
|
|
11,317 |
|
|
|
2.9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and Maintenance |
|
|
109,994 |
|
|
|
109,542 |
|
|
|
452 |
|
|
|
0.4 |
% |
Depreciation |
|
|
50,472 |
|
|
|
48,838 |
|
|
|
1,634 |
|
|
|
3.3 |
% |
General Taxes |
|
|
20,561 |
|
|
|
17,343 |
|
|
|
3,218 |
|
|
|
18.6 |
% |
Utility Income Taxes |
|
|
78,114 |
|
|
|
75,871 |
|
|
|
2,243 |
|
|
|
3.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Expenses |
|
|
259,141 |
|
|
|
251,594 |
|
|
|
7,547 |
|
|
|
3.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income |
|
|
143,796 |
|
|
|
140,026 |
|
|
|
3,770 |
|
|
|
2.7 |
% |
Other Income (Expense), net of tax |
|
|
11,932 |
|
|
|
44,863 |
|
|
|
(32,931 |
) |
|
|
(73.4 |
)% |
Utility Interest Charges |
|
|
23,880 |
|
|
|
24,315 |
|
|
|
(435 |
) |
|
|
(1.8 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
$ |
131,848 |
|
|
$ |
160,574 |
|
|
$ |
(28,726 |
) |
|
|
(17.9 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Shares of Common Stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
72,012 |
|
|
|
72,492 |
|
|
|
(480 |
) |
|
|
(0.7 |
)% |
Diluted |
|
|
72,279 |
|
|
|
72,842 |
|
|
|
(563 |
) |
|
|
(0.8 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Per Share of Common Stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
1.83 |
|
|
$ |
2.22 |
|
|
$ |
(0.39 |
) |
|
|
(17.6 |
)% |
Diluted |
|
$ |
1.82 |
|
|
$ |
2.20 |
|
|
$ |
(0.38 |
) |
|
|
(17.3 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Key statistics are shown in the table below for the three months ended April 30, 2011 and 2010.
Gas Deliveries, Customers, Weather Statistics and Number of Employees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
|
|
|
April 30 |
|
|
|
|
|
|
2011 |
|
2010 |
|
Variance |
|
Percent Change |
|
Deliveries in Dekatherms (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Volumes |
|
|
28,763 |
|
|
|
38,249 |
|
|
|
(9,486 |
) |
|
|
(24.8 |
)% |
Transportation Volumes |
|
|
36,814 |
|
|
|
28,438 |
|
|
|
8,376 |
|
|
|
29.5 |
% |
|
Throughput |
|
|
65,577 |
|
|
|
66,687 |
|
|
|
(1,110 |
) |
|
|
(1.7 |
)% |
|
Secondary Market Volumes |
|
|
10,976 |
|
|
|
9,817 |
|
|
|
1,159 |
|
|
|
11.8 |
% |
|
Customers Billed (at period end) |
|
|
978,469 |
|
|
|
972,440 |
|
|
|
6,029 |
|
|
|
0.6 |
% |
Gross Customer Additions |
|
|
2,141 |
|
|
|
2,362 |
|
|
|
(221 |
) |
|
|
(9.4 |
)% |
|
Degree Days |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual |
|
|
1,074 |
|
|
|
1,319 |
|
|
|
(245 |
) |
|
|
(18.6 |
)% |
Normal |
|
|
1,200 |
|
|
|
1,207 |
|
|
|
(7 |
) |
|
|
(0.6 |
)% |
Percent (warmer) colder than normal |
|
|
(10.5 |
)% |
|
|
9.3 |
% |
|
|
n/a |
|
|
|
n/a |
|
|
Number of Employees (at period end) |
|
|
1,787 |
|
|
|
1,806 |
|
|
|
(19 |
) |
|
|
(1.1 |
)% |
|
31
Key statistics are shown in the table below for the six months ended April 30, 2011 and 2010.
Gas Deliveries, Customers, Weather Statistics and Number of Employees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
|
|
|
April 30 |
|
|
|
|
|
|
2011 |
|
2010 |
|
Variance |
|
Percent Change |
|
Deliveries in Dekatherms (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Volumes |
|
|
84,939 |
|
|
|
93,616 |
|
|
|
(8,677 |
) |
|
|
(9.3 |
)% |
Transportation Volumes |
|
|
78,481 |
|
|
|
57,793 |
|
|
|
20,688 |
|
|
|
35.8 |
% |
|
Throughput |
|
|
163,420 |
|
|
|
151,409 |
|
|
|
12,011 |
|
|
|
7.9 |
% |
|
Secondary Market Volumes |
|
|
25,262 |
|
|
|
20,341 |
|
|
|
4,921 |
|
|
|
24.2 |
% |
|
Customers Billed (at period end) |
|
|
978,469 |
|
|
|
972,440 |
|
|
|
6,029 |
|
|
|
0.6 |
% |
Gross Customer Additions |
|
|
4,998 |
|
|
|
5,428 |
|
|
|
(430 |
) |
|
|
(7.9 |
)% |
|
Degree Days |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual |
|
|
3,352 |
|
|
|
3,369 |
|
|
|
(17 |
) |
|
|
(0.5 |
)% |
Normal |
|
|
3,065 |
|
|
|
3,065 |
|
|
|
|
|
|
|
|
% |
Percent colder than normal |
|
|
9.4 |
% |
|
|
9.9 |
% |
|
|
n/a |
|
|
|
n/a |
|
|
Number of Employees (at period end) |
|
|
1,787 |
|
|
|
1,806 |
|
|
|
(19 |
) |
|
|
(1.1 |
)% |
|
Operating Revenues
Operating revenues decreased $80.3 million for the three months ended April 30, 2011 compared with
the same period in 2010 primarily due to $106.3 million of lower gas costs passed through to sales
customers.
This decrease was partially offset by the following:
|
|
|
$14.4 million from increased revenues under the margin decoupling mechanism. |
|
|
|
$8 million from increased revenues under the WNA in South Carolina and Tennessee. |
|
|
|
$1.7 million from increased volumes delivered to transportation customers. |
|
|
|
$1.4 million from revenues in secondary market transactions due to increased activity
and margins. |
Operating revenues decreased $102 million for the six months ended April 30, 2011 compared with the
same period in 2010 primarily due to $145.2 million of lower gas costs passed through to sales
customers.
This decrease was partially offset by the following:
|
|
|
$34.3 million from revenues in secondary market transactions due to increased activity
and margin. |
|
|
|
$4.5 million from increased revenues under the WNA in South Carolina and Tennessee. |
|
|
|
$2.4 million from increased volumes delivered to transportation customers. |
|
|
|
$2 million from increased revenues under the margin decoupling mechanism. |
Cost of Gas
Cost of gas decreased $84.5 million for the three months ended April 30, 2011 compared with the
same period in 2010 primarily due to the following:
|
|
|
$30.1 million of decreased costs due to approved gas cost mechanisms. |
32
|
|
|
$58.1 million of decreased commodity gas costs primarily from lower volumes sold
and lower gas costs passed through to sales customers. |
These decreases were partially offset by the following:
|
|
|
$2.8 million from increased demand charges primarily due to year-to-year changes in
contractual payment schedules for asset manager agreements, slightly offset by an increase
in capacity release credits. |
|
|
|
|
$.9 million increase in commodity gas costs in secondary marketing transactions due to
increased activity and margins. |
Cost of gas decreased $113.3 million for the six months ended April 30, 2011 compared with the same
period in 2010 primarily due to the following:
|
|
|
$84.9 million of decreased costs due to approved gas cost mechanisms. |
|
|
|
|
$72 million of decreased commodity gas costs primarily from lower gas costs passed
through to sales customers. |
These decreases were partially offset by the following:
|
|
|
$28.8 million increase in commodity gas costs in secondary marketing transactions due to
increased activity and margins. |
|
|
|
|
$14.8 million from increased demand charges primarily due to year-to-year changes in
contractual payment schedules for asset manager agreements, slightly offset by an increase
in capacity release credits. |
In all three states, we are authorized to recover from customers all prudently incurred gas costs.
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 reflected in a regulatory deferred account and
are added to or deducted from cost of gas and are included in Amounts due from customers or
Amounts due to customers in the consolidated balance sheets.
Margin
Margin increased $4.3 million for the three months ended April 30, 2011 compared with the same
period in 2010 primarily due to the following:
|
|
|
$2 million from increases in volumes and services to industrial and power generation
customers. |
|
|
|
|
$1.1 million from residential customer growth. |
|
|
|
|
$.8 million in net gas cost adjustments. |
|
|
|
|
$.5 million from increased secondary market activity and margins. |
Margin increased $11.3 million for the six months ended April 30, 2011 compared with the same
period in 2010 primarily due to the following:
|
|
|
$4.7 million from increased secondary market activity and margins. |
|
|
|
|
$3.7 million from increases in volumes and services to industrial and power generation
customers. |
|
|
|
|
$2.9 million from residential and commercial markets, primarily due to growth in
residential customers. |
33
Our utility margin is defined as natural gas revenues less natural gas commodity purchases and
fixed gas costs for transportation and storage capacity. Margin, rather than revenues, is used by
management to evaluate utility operations due to the passthrough of changes in wholesale commodity
prices, which accounted for 47% of revenues for the six months ended April 30, 2011, and
transportation and storage costs, which accounted for 7%.
In general rate proceedings, state regulatory commissions authorize us to recover a margin, which
is the applicable billing rate less cost of gas, on each unit of gas delivered. The commissions
also authorize us to recover margin losses resulting from negotiating lower rates to industrial
customers when necessary to remain competitive. The ability to recover such negotiated margin
reductions is subject to continuing regulatory approvals.
Our utility margin is also impacted by certain regulatory mechanisms as defined elsewhere in this
document and in our Form 10-K for the year ended October 31, 2010. These include WNA in Tennessee
and South Carolina, the Natural Gas Rate Stabilization in South Carolina, secondary market activity
in North Carolina and South Carolina, TIP in Tennessee, margin decoupling mechanism in North
Carolina and negotiated loss treatment and the collection of uncollectible gas costs in all three
jurisdictions. We retain 25% of secondary market margins generated through off-system sales and
capacity release activity in all jurisdictions, with 75% credited to customers through the
incentive plans.
Operations and Maintenance Expenses
Operations and maintenance expenses increased $1.4 million for the three months ended April 30,
2011 compared with the same period in 2010 primarily due to increases in contracted services and
transportation related expenses, partially offset by lower utility expenses.
Operations and maintenance expenses increased $.5 million for the six months ended April 30, 2011
compared with the same period in 2010 primarily due to increases in contracted services and
transportation related expenses, partially offset by lower utility expenses and regulatory
amortization and fee expenses.
Depreciation
Depreciation expense increased $.9 million and $1.6 million for the three months and six months
ended April 30, 2011, respectively, compared with the same periods in 2010 primarily due to
increases in plant in service.
General Taxes
General taxes increased $.7 million and $3.2 million for the three months and six months ended
April 30, 2011, respectively, compared with the same periods in 2010 primarily due to the accrual
of an estimated liability for sales tax on certain customer accounts that may not qualify as exempt
from sales tax.
Other Income (Expense)
Other Income (Expense) is comprised of income from equity method investments, gain on sale of
interest in equity method investment, non-operating income, non-operating expense and income taxes
related to these items. Non-operating income includes non-regulated merchandising and service
work, home warranty programs, subsidiary operations, interest income and other miscellaneous
income. Non-operating expense is comprised of charitable contributions and other miscellaneous
expenses.
The primary changes to Other Income (Expense) for the three months and six months ended April 30,
2011 compared with the same periods in 2010 were in income from equity method investments and the
gain on the
34
sale of half of our ownership interest in SouthStar in the prior six month period. All other
changes were insignificant for the period.
On January 1, 2010, we sold half of our 30% membership interest in SouthStar to the other member of
the joint venture and retained a 15% earnings and membership interest after the sale. The pre-tax
gain on the sale was $49.7 million.
Income from equity method investments decreased $.9 million for the three months ended April 30,
2011 compared with the same period in 2010 due to a $.9 million decrease in earnings from South
Star primarily due to lower average customer usage due to warmer weather and SouthStars customer
portfolio and pricing plan mix. Income from equity method investments decreased $5 million for the
six months ended April 30, 2011 compared with the same period in 2010 due to a $5.2 million
decrease in earnings from SouthStar primarily due to recording earnings at the new 15% ownership
interest as of January 1, 2010, and SouthStars customer portfolio and pricing plan mix, partially
offset by higher retail price spreads.
Utility Interest Charges
Utility interest charges decreased $.1 million for the three months and $.4 million for the six
months ended April 30, 2011 compared with the same period in 2010 primarily due to a decrease in
interest expense on long-term debt due to lower amounts of debt outstanding and an increase in the
borrowed allowance for funds used during construction from increased construction expenditures,
partially offset by an increase in interest related to North Carolina deferred income taxes and
interest related to Tennessee sales taxes, and for the six month period, a net decrease in interest
charged on amounts due to/from customers as those balances were lower in the current period.
Financial Condition and Liquidity
To meet our capital and liquidity requirements, we rely on certain resources, including cash flows
from operating activities, access to capital markets, cash generated from our investments in joint
ventures and short-term bank borrowings. Our capital market strategy has continued to focus on
maintaining a strong balance sheet, ensuring sufficient cash resources and daily liquidity,
accessing capital markets at favorable times when needed, managing critical business risks, and
maintaining a balanced capital structure through the issuance of equity or long-term debt
securities or the repurchase of our equity securities.
We believe the amounts available to us under our credit facility and the issuance of debt and
equity securities, together with cash provided by operating activities, will continue to allow us
to meet our needs for working capital, construction expenditures, investments in joint ventures,
anticipated debt redemptions, dividend payments, pension plan contributions, common share
repurchases and other cash needs.
Short-Term Borrowings. We have a $650 million three-year unsecured revolving syndicated
credit facility. The facility expires in January 2014 and has an option to expand up to $850
million. We pay an annual fee of $30,000 plus fifteen basis points for any unused amount up to
$650 million. During the three months ended April 30, 2011, short-term bank borrowings ranged from
$87 million to $306 million, and interest rates ranged from 1.12% to 1.17%. During the six months
ended April 30, 2011, short-term bank borrowings ranged from $87 million to $426 million, and
interest rates ranged from .51% to 1.17%.
Our short-term borrowings, which consist only of the revolving syndicated credit facility, are
vital in order to meet working capital needs, such as our seasonal requirements for gas supply
procurement and energy price risk management programs, general corporate liquidity, capital
expenditures and approved investments. We rely on short-term borrowings along with long-term
capital markets to provide a significant source of liquidity to meet operating requirements that
are not satisfied by internally generated cash flows. Currently, cash flows from
35
operations are not adequate to finance the full cost of planned capital expenditures, which are
fundamental to support our system infrastructure and the growth in our customer base. Our
revolving syndicated credit facility will allow us to meet the increased capital requirements
anticipated of $392.8-$442.8 million to be spent over the next three years on the construction of
facilities to provide natural gas service to various electric utility power generation customers in
our service area.
Bank Borrowings
As of April 30, 2011
|
|
|
|
|
In thousands |
|
|
|
|
|
|
|
|
|
End of period: |
|
|
|
|
Amount outstanding |
|
$ |
103,500 |
|
Weighted average interest rate |
|
|
1.12 |
% |
|
During the period: |
|
|
|
|
Average amount outstanding |
|
$ |
164,500 |
|
Weighted average interest rate |
|
|
1.16 |
% |
|
Maximum amount outstanding: |
|
|
|
|
February |
|
$ |
305,500 |
|
March |
|
|
214,500 |
|
April |
|
|
138,500 |
|
The level of short-term bank borrowings can vary significantly due to changes in the wholesale cost
of natural gas and the level of purchases of natural gas supplies for storage to serve customer
demand. We pay our suppliers for natural gas purchases before we collect our costs from customers
through their monthly bills. If wholesale gas prices increase, we may incur more short-term debt
for natural gas inventory 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.
As of April 30, 2011, we had $10 million available for letters of credit under our three-year
revolving syndicated credit facility, of which $3.5 million were issued and outstanding. The
letters of credit are used to guarantee claims from self-insurance under our general and automobile
liability policies. As of April 30, 2011, unused lines of credit available under our three-year
revolving syndicated credit facility, including the issuance of the letters of credit, totaled $543
million.
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. The major factors that
affect our working capital are weather, natural gas purchases and prices, natural gas 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 November through
March winter heating season. Cash requirements generally increase during the third and fourth
quarters due to increases in natural gas purchases for storage, seasonal construction activity and
decreases in receipts from customers.
36
During the winter heating season, our accounts payable increase to reflect amounts due to our
natural gas suppliers for commodity and pipeline capacity. The cost of the natural gas can vary
significantly from period to period due to changes in the price of natural gas, which is a function
of market fluctuations in the commodity cost of natural gas along with our changing requirements
for storage volumes. Differences between natural gas costs that we have paid to suppliers and
amounts that we have collected from customers are included in regulatory deferred accounts in
amounts due to or from customers. These natural gas costs can cause cash flows to vary
significantly from period to period along with variations in the timing of collections from
customers under our gas cost recovery mechanisms.
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 heating bills. Warmer-than-normal weather can lead to reduced
operating cash flows, thereby increasing the need for short-term bank borrowings to meet current
cash requirements.
Because of the weak economy, including continued high unemployment, we may incur additional bad
debt expense as well as experience increased customer conservation. We may incur more short-term
debt to pay for gas supplies and other operating costs since collections from customers could be
slower and some customers may not be able to pay their bills. Regulatory margin stabilizing and
cost recovery mechanisms, such as those that allow us to recover the gas cost portion of bad debt
expense, will significantly mitigate the impact these factors may have on our results of
operations.
Net cash provided by operating activities was $284.8 million and $360.6 million for the six months
ended April 30, 2011 and 2010, respectively. Net cash provided by operating activities reflects a
$28.7 million decrease in net income for 2011 compared with 2010, which included the gain on the
sale of half of our interest in SouthStar as discussed in Results of Operations above. The
effect of changes in working capital on net cash provided by operating activities is described
below:
|
|
|
Trade accounts receivable and unbilled utility revenues increased $54.1 million in the
current period primarily due to total throughput which increased 12 million dekatherms as
compared with the same prior period, largely from the transportation of gas for industrial
customers and for power generation. Volumes sold to residential and commercial customers
decreased 1.2 million dekatherms due to weather that was warmer in the current period than
the prior period, offset slightly by customer growth. |
|
|
|
|
Net amounts due from customers decreased $79.2 million primarily due to the collection
of deferred gas costs through rates. |
|
|
|
|
Gas in storage decreased $22.1 million in the current period due to withdrawals from gas
in storage and a decrease in the average cost of gas in storage. |
|
|
|
|
Prepaid gas costs decreased $25.1 million in the current period primarily due to gas
being made available for sale during the period. Under some gas supply contracts, prepaid
gas costs incurred during the summer months represent purchases of gas that are not
available for sale, and therefore not recorded in inventory, until the start of the winter
heating season. |
|
|
|
|
Trade accounts payable increased $3 million in the current period primarily due to an
increase in the cost of gas. |
Our three state regulatory commissions approve rates that are designed to give us the opportunity
to generate revenues to cover our gas costs, fixed and variable non-gas costs and earn a fair
return for our shareholders. We have a WNA mechanism in South Carolina and Tennessee that
partially offsets the impact of colder- or warmer-than-normal weather on bills rendered in November
through March for residential and commercial customers. The WNA in South Carolina and Tennessee
generated credits to customers of $4.7 million and $9.2 million in the six months ended April 30,
2011 and 2010, respectively. In Tennessee, adjustments are made
37
directly to individual customer bills. In South Carolina, the adjustments are calculated at the
individual customer level but are recorded in Amounts due from customers or Amounts due to
customers in the consolidated balance sheets for subsequent collection from or refund to all
customers in the class. The margin decoupling mechanism in North Carolina provides for the
collection of our approved margin from residential and commercial customers independent of
consumption patterns. The margin decoupling mechanism reduced margin by $16.2 million and $18.2
million in the six months ended April 30, 2011 and 2010, respectively. Our gas costs are
recoverable through PGA procedures and are not affected by the WNA or the margin decoupling
mechanism.
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 have regulatory
commission approval in North Carolina, South Carolina and Tennessee that places tighter credit
requirements on the retail natural gas marketers that schedule gas for transportation service on
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, including price, value, availability, environmental attributes, reliability
and energy efficiency. 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. The price of oil depends upon a
number of factors beyond our control, including the relationship between worldwide supply and
demand and the policies of foreign and domestic governments and organizations, as well as the value
of the US dollar versus other currencies. Our liquidity could be impacted, either positively or
negatively, as a result of alternate fuel decisions made by industrial customers.
In an effort to keep customer rates competitive and to maximize earnings, we continue to implement
business process improvement and operations and maintenance cost management programs to capture
operational efficiencies while improving customer service and maintaining a safe and reliable
system.
Cash Flows from Investing Activities. Net cash used in investing activities was $86.7
million and $12.2 million for the six months ended April 30, 2011 and 2010, respectively. Net cash
used in investing activities was primarily for utility construction expenditures. Gross utility
construction expenditures for the six months ended April 30, 2011 were $89.4 million as compared to
$70 million in the same prior period primarily due to expending $23 million for the construction of
power generation projects in 2011 as compared with $5.9 million expended for these projects in the
same prior period.
We have a substantial capital expansion program for construction of distribution facilities,
purchase of equipment and other general improvements. This program primarily supports our system
infrastructure and the growth in our customer base. Significant utility construction expenditures
are expected to meet long-term growth, including the power generation market, and are part of our
long-range forecasts that are prepared at least annually and typically cover a forecast period of
five years. We are not contractually obligated to expend capital until the work is completed.
38
In October 2009, we reached an agreement with Progress Energy Carolinas to provide natural gas
delivery service to a power generation facility to be built at their Wayne County, North Carolina
site. The agreement, approved by the NCUC in May 2010, calls for us to construct 38 miles of
20-inch transmission pipeline along with compression facilities to provide natural gas delivery
service to the plant by June 2012; we began construction in February 2010. Our investment in the
pipeline and compression facilities is currently estimated at $110-$125 million and is supported by
a long-term service agreement. We have incurred $11.9 million on this project as of April 30,
2011. To provide the additional delivery service, we have executed an agreement with Cardinal to
expand our firm capacity requirement by 149,000 dekatherms per day to serve this facility. This
will require Cardinal to spend as much as $53.1 million to expand its system. As a 21.49% equity
venture partner of Cardinal, we will invest as much as $11.4 million in Cardinals system
expansion. Capital contributions related to this system expansion began in January 2011 and will
continue on a periodic basis through September 2012. As of April 30, 2011, our contributions to
date related to this system expansion were $3.9 million. For further information regarding this
agreement, see Note 8 to the consolidated financial statements.
In April 2010, we reached another agreement with Progress Energy Carolinas to provide natural gas
delivery service to a power generation facility to be built at their existing Sutton site near
Wilmington, North Carolina. The agreement, also approved by the NCUC in May 2010, calls for us to
construct approximately 130 miles of transmission pipeline along with compression facilities to
provide natural gas delivery service to the plant by June 2013; we began construction in May 2010.
Our investment in the pipeline and compression facilities is currently estimated at $300-$335
million, and our service to Progress Energy Carolinas is supported by a long-term service
agreement. A portion of the cost of this project will serve our other customers and will be
included in our rate base. We have incurred $11.5 million on this project as of April 30, 2011.
The estimated increases on both projects are primarily caused by increases in contract labor,
steel, fuel and environmental costs compared to our original estimates, which were based on 2009
costs.
The Sutton facilities will also create cost effective expansion capacity that we will use to help
serve the growing natural gas requirements of our customers in the eastern part of North Carolina.
At the present time with the timing and design scope of the Sutton facilities, there is no current
need to proceed with our previously announced Robeson LNG peak storage project. The timing and
design scope of the expansion of our facilities in Robeson County will be determined as our system
infrastructure and market supply growth requirements in North Carolina dictate.
During the first quarter of fiscal 2011, we placed into service natural gas delivery pipeline and
compression facilities that will provide natural gas delivery service to a Progress Energy
Carolinas power generation facility located in Richmond County, North Carolina. As of April 30,
2011, we have incurred $24.9 million on this project and expect to incur an additional $.1 million.
During the first quarter of fiscal 2011, we also placed into service natural gas delivery pipeline
facilities for natural gas delivery service to a Duke Energy Carolinas power generation facility
located in Rowan County, North Carolina. As of April 30, 2011, we have incurred $29.4 million on
this project and expect to incur an additional $.2 million on this project. We have a second
agreement with Duke Energy Carolinas to construct natural gas delivery pipeline facilities to
provide delivery service to their Rockingham County, North Carolina power generation facility
scheduled for service in November 2011. As of April 30, 2011, we have incurred $.4 million on this
project and expect to incur an additional $5.9 million to complete it.
On January 1, 2010, we sold half of our 30% membership interest in SouthStar to GNGC and retained a
15% earnings and membership share in SouthStar after the sale. At closing, we received $57.5
million from GNGC. For further information regarding the sale, see Note 8 to the consolidated
financial statements.
39
Cash Flows from Financing Activities. Net cash used in financing activities was $194.4
million and $349 million for the six months ended April 30, 2011 and 2010, respectively. Funds are
primarily provided from bank borrowings and the issuance of common stock through our dividend
reinvestment and stock purchase plan (DRIP) and our ESPP, net of purchases under the common stock
repurchase program. We may sell common stock and long-term debt when market and other conditions
favor such long-term financing. Funds are primarily used to pay down outstanding short-term bank
borrowings, to repurchase common stock under the common stock repurchase program and to pay
quarterly dividends on our common stock. As of April 30, 2011, our current assets were $250.9
million and our current liabilities were $555.6 million primarily due to seasonal requirements as
discussed above and the reclassification of long-term debt to current liabilities as discussed
below.
Outstanding short-term bank borrowings decreased from $242 million as of October 31, 2010 to $103.5
million as of April 30, 2011 primarily due to lower commodity gas costs. For further information
on bank borrowings, see the previous discussion of Short-Term Borrowings in Financial Condition
and Liquidity.
On June 1, 2011, we redeemed all of the 6.25% insured quarterly notes with an aggregate principal
balance of $196.8 million with short-term bank borrowings under the revolving syndicated credit
facility. On June 6, 2011, we issued $40 million of unsecured senior notes maturing in 2016 at an
interest rate of 2.92% and $160 million of unsecured senior notes maturing in 2021 at an interest
rate of 4.24%. We used the proceeds from the sale of the senior notes to reduce our short-term
borrowings as well as for other general corporate purposes and working capital needs. The
replacement of this higher rate debt with lower rate debt will provide annual interest savings of
$4.3 million.
We do not anticipate issuing any other long-term debt in fiscal 2011. We may issue $225 million of
long-term debt in our fiscal year 2012 for general corporate purposes, including power generation
projects. We continually monitor customer growth trends in our markets along with the economic
recovery of our service area for the timing of any infrastructure investments that would require
the need for additional long-term debt.
The balance of $60 million of our 6.55% medium-term notes becomes due in September 2011 and will be
paid from working capital and short-term borrowings.
During the six months ended April 30, 2011 and 2010, we issued $10.4 million and $9.8 million,
respectively, of common stock through DRIP and ESPP. From time to time, we have repurchased shares
of common stock under our Common Stock Open Market Purchase Program as described in Part II, Item 2
in this Form 10-Q. Upon repurchase, such shares are cancelled and become authorized shares
available for issuance. On January 11, 2011, through an ASR agreement with an investment bank, we
repurchased and retired .8 million shares for $22.2 million, leaving a balance of 3,710,074 shares
available in our Common Stock Open Market Purchase Program. On March 21, 2011, final settlement of
the transaction occurred, and we paid $.8 million to the investment bank. During the six months
ended April 30, 2010, we repurchased 1.8 million shares for $47.3 million under our Common Stock
Open Market Purchase Program.
We have paid quarterly dividends on our common stock since 1956. Provisions contained in certain
note agreements under which long-term debt was issued restrict the amount of cash dividends that
may be paid. As of April 30, 2011, our retained earnings were not restricted. On June 3, 2011,
the Board of Directors declared a quarterly dividend on common stock of $.29 per share, payable
July 15, 2011 to shareholders of record at the close of business on June 24, 2011.
Our long-term targeted capitalization ratio is 45-50% in long-term debt and 50-55% in common
equity. Accomplishing this capital structure objective and maintaining sufficient cash flow are
necessary to maintain attractive credit ratings. As of April 30, 2011, our capitalization,
including current maturities of long-term debt, consisted of 41% in long-term debt and 59% in
common equity, which is outside of our target capitalization.
40
This is a result of a reclassification of the 6.25% insured quarterly notes principal balance to
Current maturities of long-term debt in the consolidated balance sheets as of April 30, 2011 as
we notified the noteholders on April 25, 2011 of the June 1 redemption. We anticipate our
capitalization ratios to return to our targeted ranges in future periods with the redemption of the
6.25% notes and the issuance of $200 million of unsecured senior notes.
The components of our total debt outstanding (short-term debt and long-term debt) to our total
capitalization as of April 30, 2011 and 2010 and October 31, 2010 are summarized in the table
below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April 30 |
|
|
October 31 |
|
|
April 30 |
|
In thousands |
|
2011 |
|
|
Percentage |
|
|
2010 |
|
|
Percentage |
|
|
2010 |
|
|
Percentage |
|
Short-term debt |
|
$ |
103,500 |
|
|
|
5 |
% |
|
$ |
242,000 |
|
|
|
12 |
% |
|
$ |
35,500 |
|
|
|
2 |
% |
Current portion of
long-term debt |
|
|
256,843 |
|
|
|
14 |
% |
|
|
60,000 |
|
|
|
3 |
% |
|
|
60,000 |
|
|
|
3 |
% |
Long-term debt |
|
|
475,000 |
|
|
|
25 |
% |
|
|
671,922 |
|
|
|
35 |
% |
|
|
732,128 |
|
|
|
40 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt |
|
|
835,343 |
|
|
|
44 |
% |
|
|
973,922 |
|
|
|
50 |
% |
|
|
827,628 |
|
|
|
45 |
% |
Common
stockholders
equity |
|
|
1,046,944 |
|
|
|
56 |
% |
|
|
964,941 |
|
|
|
50 |
% |
|
|
1,013,521 |
|
|
|
55 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
capitalization
(including
short-term debt) |
|
$ |
1,882,287 |
|
|
|
100 |
% |
|
$ |
1,938,863 |
|
|
|
100 |
% |
|
$ |
1,841,149 |
|
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Credit ratings impact our ability to obtain short-term and long-term financing and the cost of
such financings. We believe our credit ratings will allow us to continue to have access to the
capital markets, as and when needed, at a reasonable cost of funds. In determining our credit
ratings, the rating agencies consider a number of quantitative factors, including debt to total
capitalization, operating cash flows relative to average total debt, net cash flow to capital
expenditures, pre-tax interest coverage, 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 business strategy and management, corporate
governance guidelines and practices, stability of regulation in the jurisdictions in which we
operate, risks and controls inherent in the distribution of natural gas, industry position,
predictability of cash flows and contingencies.
As of April 30, 2011, 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 Service. Currently, with respect
to our long-term debt, the credit agencies maintain their stable outlook. A significant decline in
our operating performance or a significant reduction in our liquidity could trigger a negative
change in our ratings outlook or even a reduction in our credit ratings by our rating agencies.
This would mean more limited access to the private and public credit markets and an increase in the
costs of such borrowings. 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 bank borrowings.
Failure to satisfy any of the default provisions may result in total outstanding issues of debt
becoming due. There are cross-default provisions in all of our debt agreements. As of April 30,
2011, there has been no event of default giving rise to acceleration of our debt.
Estimated Future Contractual Obligations
During the three months ended April 30, 2011, there were no material changes to our estimated
future contractual obligations in Managements Discussion and Analysis in this Form 10-Q compared
to what we disclosed in our Form 10-K for the year ended October 31, 2010.
Off-balance Sheet Arrangements
We have no off-balance sheet arrangements other than letters of credit and operating leases. The
letters of
41
credit and operating leases were discussed in Note 4 and Note 7, respectively, to the
consolidated financial statements in our Form 10-K for the year ended October 31, 2010.
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, and pension and
postretirement benefits to be our critical accounting estimates. Management is responsible for the
selection of these critical accounting estimates presented in our Form 10-K for the year ended
October 31, 2010 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, 2010.
Accounting Guidance
For information regarding recently issued accounting guidance, see Note 1 to the consolidated
financial statements in this Form 10-Q.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to various forms of market risk, including the credit risk of our suppliers and our
customers, interest rate risk, commodity price risk and weather risk. We seek to identify, assess,
monitor and manage market risk and credit risk in accordance with defined policies and procedures
under an Enterprise Risk Management program and with the direction of the EPRMC. Risk management
is guided by senior management with Board of Directors oversight, and senior management takes an
active role in the development of policies and procedures.
During the six months ended April 30, 2011, there were no material changes in the way that we
monitor and manage market risk and credit risk in accordance with our policies and procedures. Our
exposure to and management of interest rate risk, commodity price risk and weather risk has
remained the same during the six months ended April 30, 2011. Our annual discussion of market risk
was set forth in Item 7A of our Form 10-K as of October 31, 2010.
Additional information concerning market risk is set forth in Financial Condition and Liquidity
in Managements Discussion and Analysis of Financial Condition and Results of Operations in Item 2
in this Form 10-Q.
As of April 30, 2011, we had $103.5 million of bank debt outstanding under our syndicated revolving
credit facility at an interest rate of 1.12%. The carrying amount of our bank debt approximates fair
value. A change
42
of 100 basis points in the underlying average interest rate for our bank debt
would have caused a change in interest expense of approximately $1.1 million during the six months
ended April 30, 2011.
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. Such disclosure controls and procedures are designed to provide
reasonable assurance 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 and
that such information is accumulated and communicated to our management, including our Chief
Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding
required disclosure. Based on such evaluation, the President and Chief Executive Officer and the
Senior Vice President 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 at the reasonable
assurance level.
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 2011 that
materially affected, or are reasonably likely to materially affect, our internal control over
financial reporting.
Part II. Other Information
Item 1. Legal Proceedings
We have only routine litigation in the normal course of business.
Item 1A. Risk Factors
During the six months ended April 30, 2011, there were no material changes to our risk factors that
were disclosed in our Form 10-K for the year ended October 31, 2010.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
|
a) Sale of Unregistered Equity Securities. |
|
|
|
None. |
|
|
c) Issuer Purchases of Equity Securities. |
The following table provides information with respect to repurchases of our common stock under
the Common Stock Open Market Purchase Program during the three months ended April 30, 2011.
43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Number of |
|
Maximum Number |
|
|
Total Number |
|
|
|
|
|
Shares Purchased |
|
of Shares that May |
|
|
of Shares |
|
Average Price |
|
as Part of Publicly |
|
Yet be Purchased |
Period |
|
Purchased |
|
Paid Per Share |
|
Announced Program |
|
Under the Program (1) |
Beginning of the period |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,710,074 |
|
02/01/11 - 02/28/11 |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
3,710,074 |
|
03/01/11 - 03/31/11 |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
3,710,074 |
|
04/01/11 - 04/30/11 |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
3,710,074 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The Common Stock Open Market Purchase Program was approved by the Board of Directors
and announced on June 4, 2004 to purchase up to three million shares of common stock for
reissuance under our dividend reinvestment and stock purchase, employee 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 on that date an
amendment of the Common Stock Open Market Purchase Program to provide for the purchase of
up to four million additional shares of common stock to maintain our debt-to-equity
capitalization ratios at target levels. The additional four million shares were referred
to as our accelerated share repurchase (ASR) program. On March 6, 2009, the Board of
Directors authorized the repurchase of up to an additional four million shares under the
Common Stock Open Market Purchase Program and the ASR program, which were consolidated. |
The amount of cash dividends that may be paid on common stock is restricted by provisions
contained in certain note agreements under which long-term debt was issued, with those for the
senior notes being the most restrictive. We cannot pay or declare any dividends or make any other
distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary
to do any of the above (all of the foregoing being restricted payments) except out of net
earnings available for restricted payments. As of April 30, 2011, net earnings available for
restricted payments were greater than retained earnings; therefore, our retained earnings were not
restricted.
Item 6. Exhibits
Compensatory Contracts:
|
|
|
10.1
|
|
Piedmont Natural Gas Company, Inc. Incentive Compensation Plan as
Amended and Restated Effective December 15, 2010 |
|
|
|
Other Contracts: |
|
|
|
|
|
10.2
|
|
Amendment No. 1 to Credit Agreement dated as of March 21, 2011 by
and among Piedmont Natural Gas Company, Inc., Bank of America,
N.A., as Administrative Agent, Swing Line Lender and L/C Issuer,
and the Lenders thereunder |
|
|
|
10.3
|
|
Amendment to September 1992 Note Agreement dated as of April 15,
2011 by and between Piedmont Natural Gas Company, Inc., and
Provident Life and Accident Insurance Company |
44
|
|
|
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 |
|
|
|
101.INS
|
|
XBRL Instance Document (1) |
|
|
|
101.SCH
|
|
XBRL Taxonomy Extension Schema (1) |
|
|
|
101.CAL
|
|
XBRL Taxonomy Calculation Linkbase (1) |
|
|
|
101.LAB
|
|
XBRL Taxonomy Extension Label Linkbase (1) |
|
|
|
101.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase (1) |
|
|
|
(1) |
|
Furnished, not filed. |
Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in
extensible business reporting language (XBRL): (1) Document and Entity Information; (2)
Consolidated Balance Sheets at April 30, 2011 and October 31, 2010; (3) Consolidated Statements of
Income for the three months and six months ended April 30, 2011 and 2010; (4) Consolidated
Statements of Cash Flows for the six months ended April 30, 2011 and 2010; (5) Consolidated
Statements of Comprehensive Income for the three months and six months ended April 30, 2011 and
2010; and (6) Notes to Consolidated Financial Statements.
Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed as part
of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act
of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise not subject to
liability. We also make available on our web site the Interactive Data Files submitted as Exhibit
101 to this Quarterly Report.
45
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 8, 2011 |
/s/ David J. Dzuricky
|
|
|
David J. Dzuricky |
|
|
Senior Vice President and Chief Financial Officer
(Principal Financial Officer) |
|
|
|
|
|
Date June 8, 2011 |
/s/ Jose M. Simon
|
|
|
Jose M. Simon |
|
|
Vice President and Controller
(Principal Accounting Officer) |
|
|
46
Piedmont Natural Gas Company, Inc.
Form 10-Q
For the Quarter Ended April 30, 2011
Exhibits
Compensatory Contracts:
|
10.1 |
|
Piedmont Natural Gas Company, Inc. Incentive Compensation Plan as
Amended and Restated Effective December 15, 2010 |
Other Contracts:
|
10.2 |
|
Amendment No. 1 to Credit Agreement dated as of March 21, 2011 by and
among Piedmont Natural Gas Company, Inc., Bank of America, N.A., as
Administrative Agent, Swing Line Lender and L/C Issuer, and the
Lenders thereunder |
|
|
10.3 |
|
Amendment to September 1992 Note Agreement dated as of April 15, 2011
by and between Piedmont Natural Gas Company, Inc., and Provident Life
and Accident Insurance Company |
|
|
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 |