Piedmont Natural Gas Company, Inc.
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 January 31, 2007
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. Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in
Rule 12b-2 of the Exchange Act. (Check One):
Large accelerated filer þ Accelerated filer o Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
Indicate the number of shares outstanding of each of the issuers classes of common stock, as of
the latest practicable date.
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Class |
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Outstanding at March 2, 2007 |
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Common Stock, no par value |
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74,599,552 |
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TABLE OF CONTENTS
Part
I. Financial Information
Item. 1. Financial Statements
Piedmont Natural Gas Company, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
(In thousands)
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January 31, |
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October 31, |
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2007 |
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2006 |
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ASSETS |
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Utility Plant, at original cost |
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$ |
2,798,695 |
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$ |
2,808,992 |
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Less accumulated depreciation |
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712,307 |
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733,682 |
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Utility plant, net |
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2,086,388 |
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2,075,310 |
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Other Physical Property, at cost (net of accumulated
depreciation of $2,079 in 2007 and $2,040 in 2006) |
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1,119 |
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1,154 |
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Current Assets: |
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Cash and cash equivalents |
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17,952 |
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8,886 |
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Trade accounts receivable (less allowance for
doubtful
accounts of $3,058 in 2007 and $1,239 in 2006) |
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222,684 |
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90,493 |
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Income taxes receivable |
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12,756 |
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30,849 |
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Other receivables |
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260 |
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160 |
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Unbilled utility revenues |
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123,490 |
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45,938 |
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Gas in storage |
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142,776 |
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138,183 |
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Gas purchase options, at fair value |
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9,965 |
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3,147 |
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Amounts due from customers |
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62,244 |
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89,635 |
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Prepayments |
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18,859 |
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62,356 |
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Other |
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5,408 |
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6,317 |
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Total current assets |
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616,394 |
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475,964 |
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Investments, Deferred Charges and Other Assets: |
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Equity method investments in non-utility
activities |
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80,977 |
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75,330 |
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Goodwill |
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47,383 |
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47,383 |
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Unamortized debt expense |
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11,125 |
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11,306 |
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Regulatory cost of removal asset |
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12,404 |
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12,086 |
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Other |
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33,781 |
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35,406 |
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Total investments, deferred charges and
other assets |
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185,670 |
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181,511 |
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Total |
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$ |
2,889,571 |
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$ |
2,733,939 |
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See notes to condensed consolidated financial
statements.
2
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January 31, |
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October 31, |
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(In thousands) |
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2007 |
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2006 |
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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 in 2007 and
in 2006; shares outstanding: 74,585 in
2007 and 75,464 in 2006 |
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508,587 |
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532,764 |
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Paid-in capital |
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142 |
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56 |
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Retained earnings |
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401,600 |
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348,765 |
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Accumulated other comprehensive income |
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1,684 |
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1,340 |
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Total stockholders equity |
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912,013 |
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882,925 |
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Long-term debt |
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825,000 |
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825,000 |
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Total capitalization |
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1,737,013 |
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1,707,925 |
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Current Liabilities: |
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Notes payable |
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232,500 |
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170,000 |
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Trade accounts payable |
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128,520 |
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80,304 |
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Other accounts payable |
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44,602 |
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50,935 |
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Income taxes accrued |
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2,028 |
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1,184 |
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Accrued interest |
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11,691 |
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21,273 |
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Customers deposits |
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25,360 |
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22,308 |
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Deferred income taxes |
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50,084 |
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25,085 |
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General taxes accrued |
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7,772 |
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18,522 |
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Amounts due to customers |
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14 |
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123 |
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Other |
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14,464 |
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10,655 |
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Total current liabilities |
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517,035 |
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400,389 |
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Deferred Credits and Other Liabilities: |
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Deferred income taxes |
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238,513 |
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235,411 |
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Unamortized federal investment tax credits |
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3,284 |
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3,417 |
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Cost of removal obligations |
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335,604 |
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330,104 |
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Other |
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58,122 |
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56,693 |
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Total deferred credits and other liabilities |
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635,523 |
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625,625 |
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Total |
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$ |
2,889,571 |
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$ |
2,733,939 |
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See notes to condensed consolidated financial
statements.
3
Piedmont Natural Gas Company, Inc. and Subsidiaries
Condensed Consolidated Statements of Income (Unaudited)
(In thousands except per share amounts)
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Three Months Ended |
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January 31 |
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2007 |
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2006 |
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Operating Revenues |
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$ |
677,241 |
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$ |
921,347 |
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Cost of Gas |
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468,756 |
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711,975 |
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Margin |
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208,485 |
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209,372 |
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Operating Expenses: |
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Operations and maintenance |
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52,210 |
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53,222 |
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Depreciation |
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21,611 |
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21,887 |
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General taxes |
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9,259 |
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8,710 |
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Income taxes |
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43,708 |
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44,392 |
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Total operating expenses |
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126,788 |
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128,211 |
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Operating Income |
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81,697 |
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81,161 |
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Other Income (Expense): |
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Income from equity method investments |
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5,543 |
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5,751 |
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Non-operating income |
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131 |
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19 |
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Non-operating expense |
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(152 |
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(67 |
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Income taxes |
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(2,165 |
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(2,225 |
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Total other income (expense) |
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3,357 |
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3,478 |
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Utility Interest Charges |
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14,338 |
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12,642 |
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Net Income |
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$ |
70,716 |
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$ |
71,997 |
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Average Shares of Common Stock: |
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Basic |
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74,619 |
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76,685 |
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Diluted |
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74,938 |
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76,928 |
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Earnings Per Share of Common Stock: |
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Basic |
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$ |
0.95 |
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$ |
0.94 |
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Diluted |
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$ |
0.94 |
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$ |
0.94 |
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Cash Dividends Per Share of Common Stock |
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$ |
0.24 |
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$ |
0.23 |
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See notes to condensed consolidated financial statements.
4
Piedmont Natural Gas Company, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)
(In thousands)
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Three Months Ended |
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January 31 |
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2007 |
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2006 |
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Cash Flows from Operating Activities: |
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Net income |
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$ |
70,716 |
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$ |
71,997 |
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Adjustments to reconcile net income to
net cash used in operating activities: |
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Depreciation and amortization |
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22,785 |
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22,885 |
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Amortization of investment tax
credits |
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(132 |
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(134 |
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Allowance for doubtful accounts |
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1,820 |
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2,965 |
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Allowance for funds used during
construction |
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(634 |
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Earnings from equity method
investments |
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(5,543 |
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(5,751 |
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Distributions of earnings from
equity method investments |
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1,196 |
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1,277 |
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Deferred income taxes |
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27,880 |
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13,219 |
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Change in assets and liabilities |
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(96,851 |
) |
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(224,663 |
) |
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Net cash provided by (used
in) operating activities |
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21,871 |
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(118,839 |
) |
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Cash Flows from Investing Activities: |
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Utility construction expenditures |
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(29,485 |
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(51,102 |
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Allowance for funds used during
construction |
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(1,340 |
) |
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Reimbursements from bond fund |
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8,034 |
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Distributions of capital from equity
method investments |
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138 |
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Decrease in restricted cash |
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13,103 |
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Other |
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732 |
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(227 |
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Net cash used in investing
activities |
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(29,955 |
) |
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(30,192 |
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Cash Flows from Financing Activities: |
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Increase in notes payable |
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62,500 |
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191,500 |
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Expenses related to issuance of
long-term debt |
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(5 |
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Issuance of common stock through dividend
reinvestment and employee stock plans |
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3,955 |
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4,916 |
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Repurchases of common stock |
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(31,395 |
) |
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(7,223 |
) |
Dividends paid |
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(17,905 |
) |
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(17,630 |
) |
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Net cash provided by
financing activities |
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17,150 |
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171,563 |
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Net Increase in Cash and Cash Equivalents |
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9,066 |
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|
22,532 |
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Cash and Cash Equivalents at Beginning of
Period |
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8,886 |
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|
7,065 |
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Cash and Cash Equivalents at End of Period |
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$ |
17,952 |
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$ |
29,597 |
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Noncash Investing and Financing Activities: |
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Accrued construction expenditures |
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$ |
(2,680 |
) |
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$ |
(4,316 |
) |
Guaranty |
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$ |
961 |
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5
Piedmont Natural Gas Company, Inc. and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
(In thousands)
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Three Months |
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Ended January 31, |
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In thousands except per share amounts |
|
2007 |
|
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2006 |
|
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|
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|
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Net Income |
|
$ |
70,716 |
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|
$ |
71,997 |
|
Other Comprehensive Income: |
|
|
|
|
|
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|
|
Unrealized gain from hedging
activities of equity method
investments net of tax of $10 in 2007
and $1,424 in 2006 |
|
|
16 |
|
|
|
2,241 |
|
Reclassification adjustment from
hedging activities of
equity method investments
included in net income, net
of tax of $211 in 2007 and
($211) in 2006 |
|
|
328 |
|
|
|
(333 |
) |
|
|
|
|
|
|
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Total Comprehensive Income |
|
$ |
71,060 |
|
|
$ |
73,905 |
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|
|
|
|
|
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|
See notes to condensed consolidated
financial statements.
6
Piedmont Natural Gas Company, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Unaudited)
1. Unaudited Interim Financial Information.
The condensed consolidated financial statements have not been audited. These financial statements
should be read in conjunction with the Consolidated Financial Statements and Notes included in our
Form 10-K for the year ended October 31, 2006.
Seasonality and Use of Estimates.
In our opinion, the unaudited condensed consolidated financial statements include all normal
recurring adjustments necessary for a fair statement of financial position at January 31, 2007 and
October 31, 2006, the results of operations for the three months ended January 31, 2007 and 2006,
and cash flows for the three months ended January 31, 2007 and 2006. Our business is seasonal in
nature. The results of operations for the three months ended January 31, 2007 do not necessarily
reflect the results to be expected for the full year.
We make estimates and assumptions when preparing the condensed consolidated financial statements.
These estimates and assumptions affect the reported amounts of assets and liabilities and the
disclosure of contingent assets and liabilities at the date of the condensed consolidated financial
statements and the reported amounts of revenues and expenses during the reporting period. Actual
results could differ from estimates.
Significant Accounting Policies.
Our accounting policies are described in Note 1 to our Annual Report on Form 10-K for the year
ended October 31, 2006. There were no significant changes to those accounting policies during the
three months ended January 31, 2007.
Rate-Regulated Basis of Accounting.
We follow Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of
Certain Types of Regulation (Statement 71). Statement 71 provides that rate-regulated public
utilities account for and report assets and liabilities consistent with the economic effect of the
manner in which independent third-party regulators establish rates. In applying Statement 71, we
capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order
to provide for recovery from or refund to utility customers in future periods. The amounts
recorded as regulatory assets in the condensed consolidated balance sheets as of January 31, 2007
and October 31, 2006, were $115.1 million and $143.5 million, respectively. The amounts recorded as
regulatory liabilities in the condensed consolidated balance sheets as of January 31, 2007 and
October 31, 2006, were $341.9 million and $337 million, respectively.
Significant inter-company transactions have been eliminated in consolidation where appropriate;
however, we have not eliminated inter-company profit on sales to affiliates and costs from
affiliates in accordance with Statement 71. See Note 7 for information on related party
transactions.
Accounting Pronouncements.
In June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation 48, Accounting
for Uncertainty in Income Taxes (FIN 48), to clarify the accounting for uncertain tax positions in
accordance with SFAS 109, Accounting for Income Taxes. FIN 48 defines a minimum recognition
threshold that a tax
7
position must meet to be recognized in an enterprises financial statements. Additionally, FIN 48
provides guidance on derecognition, measurement, classification, interim period accounting,
disclosure and transition requirements in accounting for uncertain tax positions. This
interpretation is effective the beginning of the first annual period beginning after December 15,
2006. Accordingly, we will adopt FIN 48 in our fiscal year 2008. We are currently assessing the
impact FIN 48 may have on our consolidated financial statements; however, we believe the adoption
of FIN 48 will not have a material impact on our financial position, results of operations or cash
flows.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (Statement 157).
Statement 157 provides enhanced guidance for using fair value to measure assets and liabilities and
applies whenever other standards require (or permit) the measurement of assets or liabilities at
fair value, but does not expand the use of fair value measurement to any new circumstances.
Statement 157 establishes a fair value hierarchy that prioritizes the information used to develop
those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active
markets and the lowest priority to unobservable data, for example, the reporting entitys own data.
Under Statement 157, fair value measurements would be separately disclosed by level within the
fair value hierarchy. Statement 157 is effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods within those fiscal years, with earlier
application encouraged. Accordingly, we will adopt Statement 157 no later than our first fiscal
quarter in 2009. We believe the adoption of Statement 157 will not have a material impact on our
financial position, results of operations or cash flows.
In September 2006, the FASB issued SFAS No. 158, Employers Accounting for Defined Benefit Pension
and Other Postretirement Plans (Statement 158). Statement 158 requires an employer to fully
recognize the obligations associated with single-employer defined benefit pension, retiree
healthcare and other postretirement plans in the financial statements by recognizing in its
statement of financial position an asset for a plans overfunded status or a liability for a plans
underfunded status rather than only disclosing the funded status in the footnotes to the financial
statements. Statement 158 requires employers to recognize changes in the funded status of a
defined benefit postretirement plan in the year in which the changes occur. Under Statement 158,
gains and losses, prior service costs and credits, and any remaining transition amounts that have
not yet been recognized through net periodic benefit cost will be recognized in accumulated other
comprehensive income (OCI), net of tax effects, until they are amortized as a component of net
periodic cost. Statement 158 also requires that the company measure a plans assets and its
obligations that determine its funded status as of the end of the employers fiscal year. We are
already in compliance with this requirement as our pension plans measurement dates are already the
same as our fiscal year end date.
The requirement to recognize the funded status of a benefit plan and the related disclosure
requirements initially will apply as of the end of the fiscal year ending after December 15, 2006.
Accordingly, we will adopt the funded status portion of Statement 158 as of October 31, 2007. We
believe the adoption of Statement 158 will not have a material effect on our financial position,
results of operations or cash flows.
Based on a preliminary assessment of prior regulatory treatment of postretirement benefits,
management believes that regulatory asset or liability treatment will be afforded to any amounts
that would otherwise be recorded in accumulated OCI resulting from the implementation of Statement
158. We intend to meet with our regulators in fiscal year 2007 to discuss the regulatory
accounting and rate treatment of the impact of the adoption of Statement 158. Assuming regulatory
treatment, if Statement 158 had been adopted for the fiscal year ended October 31, 2006, the effect
on the consolidated balance sheets would have been the recognition of $25.6 million as a regulatory
asset, $16.7 million of deferred income taxes, $14.6 million decrease to prepaid pension and $27.7
million increase in accrued postretirement benefits. The actual impact at October 31, 2007 could
be substantially different depending on the discount rate, asset returns and plan population at
that date.
8
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and
Financial Liabilities (Statement 159). Statement 159 provides companies with an option to report
selected financial assets and liabilities at fair value. Its objective is to reduce the complexity
in accounting for financial instruments and to mitigate the volatility in earnings caused by
measuring related assets and liabilities differently. Although Statement 159 does not eliminate
disclosure requirements included in other accounting standards, it does establish additional
presentation and disclosure requirements designed to facilitate comparisons between companies that
choose different measurement attributes for similar types of assets and liabilities. Statement 159
is effective for financial statements issued for fiscal years beginning after November 15, 2007,
with early adoption permitted for an entity that has elected also to apply Statement 157 early.
Accordingly, we will adopt Statement 159 no later than our first fiscal quarter in 2009. We
believe the adoption of Statement 159 will not have a material impact on our financial position,
results of operations or cash flows.
2. Regulatory Matters.
In North Carolina and South Carolina, recoveries of gas costs are subject to annual gas cost
recovery proceedings to determine the prudence of our gas purchases. We have been found prudent in
all such past proceedings. We are currently undergoing our annual review of gas costs covering the
period from June 2005 through May 2006 in North Carolina. A hearing date has been scheduled for
April 10, 2007.
3. Accelerated Share Repurchase Program.
On November 3, 2006, we entered into an accelerated share repurchase (ASR) agreement. On November
7, 2006, we purchased and retired 1 million shares of our common stock from an investment bank at
the closing price that day of $26.48 per share. Total consideration paid to purchase the shares of
$26.6 million, including $118,800 in commissions and other fees, was recorded in Stockholders
equity as a reduction in Common stock.
As part of the accelerated share repurchase, we simultaneously entered into a forward sale contract
with the investment bank that was expected to mature in approximately 50 trading days. Under the
terms of the forward sale contract, the investment bank was required to purchase, in the open
market, 1 million shares of our common stock during the term of the contract to fulfill its
obligation related to the shares it borrowed from third parties and sold to us. At settlement, we,
at our option, 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 was
higher than the November 7, 2006, 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
for the shares purchased was lower than the November 7, 2006, closing price. At settlement on
January 19, 2007, we paid cash of $.8 million to the investment bank and recorded this amount in
Stockholders equity as a reduction in Common stock. The $.8 million was the difference
between the investment banks weighted average purchase price of $27.3234 and the November 7, 2006,
closing price of $26.48 per share multiplied by 1 million shares.
4. 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 ended January 31, 2007 and 2006 is presented below.
9
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
In thousands except per share amounts |
|
2007 |
|
|
2006 |
|
|
|
|
|
|
|
|
|
|
Net Income |
|
$ |
70,716 |
|
|
$ |
71,997 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average shares of common stock outstanding for
basic earnings per share |
|
|
74,619 |
|
|
|
76,685 |
|
Contingently issuable shares under the Executive
Long-Term Incentive Plan (LTIP) and Incentive
Compensation Plan |
|
|
319 |
|
|
|
243 |
|
|
|
|
|
|
|
|
Average shares of dilutive stock |
|
|
74,938 |
|
|
|
76,928 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Per Share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.95 |
|
|
$ |
0.94 |
|
Diluted |
|
$ |
0.94 |
|
|
$ |
0.94 |
|
5. Employee Benefit Plans.
Components of the net periodic benefit cost for our defined-benefit pension plans and our
postretirement health care and life insurance benefits (OPEB) plan for the three months ended
January 31, 2007 and 2006 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
In thousands |
|
Qualified Pension |
|
|
Nonqualified Pension |
|
|
Other Benefits |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
2,938 |
|
|
$ |
3,149 |
|
|
$ |
15 |
|
|
$ |
16 |
|
|
$ |
330 |
|
|
$ |
409 |
|
Interest cost |
|
|
3,286 |
|
|
|
3,971 |
|
|
|
69 |
|
|
|
72 |
|
|
|
471 |
|
|
|
629 |
|
Expected return
on plan assets |
|
|
(4,368 |
) |
|
|
(4,987 |
) |
|
|
|
|
|
|
|
|
|
|
(318 |
) |
|
|
(421 |
) |
Amortization of
transition
obligation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
167 |
|
|
|
240 |
|
Amortization of
prior service
cost |
|
|
148 |
|
|
|
268 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of
actuarial
(gain) loss |
|
|
246 |
|
|
|
224 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(82 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
2,250 |
|
|
$ |
2,625 |
|
|
$ |
84 |
|
|
$ |
88 |
|
|
$ |
650 |
|
|
$ |
775 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We estimate that we will contribute $16.5 million to the qualified pension plans, $.6 million
to the nonqualified pension plans and $3 million to the OPEB plan in 2007.
6. 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 corporate
organization and business decision-making activities. Operations of our regulated utility segment
are conducted by the parent company. Operations of our non-utility activities segment are
comprised of our equity method investments in joint ventures.
Operations of the regulated utility segment are reflected in operating income in the condensed
consolidated statements of income. Operations of the non-utility activities segment are included
in the condensed consolidated statements of income in Income from equity method investments.
We evaluate the performance of the regulated utility segment based on margin, operations and
maintenance
10
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 for the year ended October 31, 2006.
Operations by segment for the three months ended January 31, 2007 and 2006 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated |
|
Non-Utility |
|
|
In thousands |
|
Utility |
|
Activities |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers |
|
$ |
677,241 |
|
|
$ |
|
|
|
$ |
677,241 |
|
Margin |
|
|
208,485 |
|
|
|
|
|
|
|
208,485 |
|
Operations and maintenance
expenses |
|
|
52,210 |
|
|
|
135 |
|
|
|
52,345 |
|
Income from equity method
investments |
|
|
|
|
|
|
5,543 |
|
|
|
5,543 |
|
Operating income (loss) before
income taxes |
|
|
125,405 |
|
|
|
(236 |
) |
|
|
125,169 |
|
Income before income taxes |
|
|
111,371 |
|
|
|
5,218 |
|
|
|
116,589 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers |
|
$ |
921,347 |
|
|
$ |
|
|
|
$ |
921,347 |
|
Margin |
|
|
209,372 |
|
|
|
|
|
|
|
209,372 |
|
Operations and maintenance
expenses |
|
|
53,222 |
|
|
|
43 |
|
|
|
53,265 |
|
Income from equity method
investments |
|
|
|
|
|
|
5,751 |
|
|
|
5,751 |
|
Operating income (loss) before
income taxes |
|
|
125,553 |
|
|
|
(172 |
) |
|
|
125,381 |
|
Income before income taxes |
|
|
113,141 |
|
|
|
5,473 |
|
|
|
118,614 |
|
Reconciliations to the condensed consolidated statements of income for the three months ended
January 31, 2007 and 2006 are presented below.
|
|
|
|
|
|
|
|
|
In thousands |
|
2007 |
|
|
2006 |
|
|
|
|
|
|
|
|
|
|
Operating Income: |
|
|
|
|
|
|
|
|
Segment operating
income before income
taxes |
|
$ |
125,169 |
|
|
$ |
125,381 |
|
Utility income taxes |
|
|
(43,708 |
) |
|
|
(44,392 |
) |
Non-utility
activities before
income taxes |
|
|
236 |
|
|
|
172 |
|
|
|
|
|
|
|
|
Operating Income |
|
$ |
81,697 |
|
|
$ |
81,161 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income: |
|
|
|
|
|
|
|
|
Income before income
taxes for reportable
segments |
|
$ |
116,589 |
|
|
$ |
118,614 |
|
Income taxes |
|
|
(45,873 |
) |
|
|
(46,617 |
) |
|
|
|
|
|
|
|
Net Income |
|
$ |
70,716 |
|
|
$ |
71,997 |
|
|
|
|
|
|
|
|
7. Equity Method Investments.
The condensed consolidated financial statements include the accounts of wholly-owned subsidiaries
whose investments in joint venture, energy-related businesses are accounted for under the equity
method. Our ownership interest in each entity is included in Equity method investments in
non-utility activities in the condensed consolidated balance sheets. Earnings or losses from
equity method investments are included in Income from equity method investments in the condensed
consolidated statements of operations.
We own 21.49% of the membership interests in Cardinal Pipeline Company, L.L.C., a North Carolina
limited liability company. Cardinal owns and operates an intrastate natural gas pipeline in North
Carolina and is regulated by the North Carolina Utilities Commission (NCUC). We have related party transactions as a transportation
customer of Cardinal, and we
11
record in cost of gas the transportation costs charged by Cardinal.
For each period of three months ended January 31, 2007 and 2006, these gas costs were $1.2 million.
As of January 31, 2007 and October 31, 2006, we owed Cardinal $.4 million and $.1 million,
respectively.
We own 40% of the membership interests in Pine Needle LNG Company, L.L.C., a North Carolina limited
liability company. Pine Needle owns an interstate liquefied natural gas 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 three months ended January 31, 2007 and 2006, these gas
costs were $3.2 million. As of January 31, 2007 and October 31, 2006, we owed Pine Needle $.8
million and $1.1 million, respectively.
We own 30% of the membership interests in SouthStar Energy Services LLC, a Delaware limited
liability company. Under the terms of the Amended and Restated Limited Liability Company Agreement
(Restated Agreement), earnings and losses are allocated 25% to us and 75% to the other member,
Georgia Natural Gas Company (GNGC), a subsidiary of AGL Resources, Inc., with the exception of
earnings and losses in the
Ohio and Florida markets, which are allocated to us at our ownership percentage of 30%. SouthStar
primarily sells natural gas to residential, commercial and industrial customers in the southeastern
United States, with most of its business in the unregulated retail gas market in Georgia. We have
related party transactions as we sell wholesale gas supplies to SouthStar, and we record in
operating revenues the amounts billed to SouthStar. For the three months ended January 31, 2007
and 2006, these gas revenues were $2.7 million and $8.6 million, respectively. As of January 31,
2007 and October 31, 2006, SouthStar owed us $2.1 million and $.8 million, respectively.
Contained in the SouthStar Restated Agreement mentioned above between us and GNGC, there are
provisions providing for the disposition of ownership interests between members, including a
provision granting three options to GNGC to purchase our ownership interest in SouthStar. By
notice no later than November 1, 2007, with the option effective on January 1, 2008 (2008 option),
GNGC has the option to purchase one-third of our 30% interest in SouthStar. With the same notice
in the following years, GNGC has the option to purchase 50% of our interest to be effective on
January 1, 2009 (2009 option), and 100% of our interest to be effective on January 1, 2010. The
purchase price would be based on the market value of SouthStar as defined in the Restated
Agreement.
If GNGC exercises either the 2008 option or the 2009 option, we, at our discretion, may cause GNGC
to purchase our entire ownership interest.
For further information on this provision, please see the Restated Agreement that was filed with
the Securities and Exchange Commission (SEC) as Exhibit 10.1 in our Form 10-Q for the quarter ended
April 30, 2004.
Piedmont Hardy Storage Company, LLC (Piedmont Hardy), 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 is constructing an underground interstate
natural gas storage facility located in Hardy and Hampshire Counties, West Virginia, that it
intends to own and operate. The storage facility is expected to be in service in April 2007. On
June 29, 2006, Hardy Storage signed a note purchase agreement for interim notes and a revolving
equity bridge facility for up to a total of $173.1 million for funding during the construction
period. Once in service, and after the satisfaction of certain conditions in the note purchase
agreement, the two members of Hardy Storage will pay off 30% of the construction financing with
their equity contributions and the remaining 70% debt will convert to a fifteen-year mortgage-style
debt instrument without recourse to the members. The other member of Hardy Storage will contribute
assets and cash as part of its share of the 30% owner contributions, and we will contribute cash as
our share.
12
The members of Hardy Storage have each agreed to guarantee 50% of the construction financing. The
guaranty was executed by Piedmont Energy Partners, Inc. (PEP), a wholly-owned subsidiary of
Piedmont and a sister company of Piedmont Hardy. Our share of the guaranty is capped at $111.5
million. Depending upon the facilitys performance over the first three years after the in-service
date, there could be additional construction expenditures of up to $10 million, of which PEP will
guarantee 50%.
Securing PEPs guaranty is a pledge of intercompany notes issued by Piedmont held by non-utility
subsidiaries of PEP. Should Hardy Storage be unable to perform its payment obligation under the
construction financing, PEP will call on Piedmont for the payment of the notes, plus accrued
interest, for the amount of the guaranty. Also pledged is our membership interests in Hardy
Storage.
As we are in the formation stage of the joint venture, we are recording a liability at fair value
for this guaranty based on the present value of 50% of the construction financing outstanding at
the end of each quarter, with a corresponding increase to our investment account in the venture.
As our risk in the project changes, the fair
value of the guaranty is adjusted accordingly through a quarterly evaluation.
On October 26, 2006, Hardy Storage filed an application with the FERC, for an amendment to its
certificate of public convenience and necessity for approval of a settlement that establishes
revised initial rates based on updated cost estimates. The estimated cost of the project as
refiled with the FERC was $164 million, an increase of $43 million from the original application of
$121 million, due to higher costs for skilled labor, material and equipment for the project.
As of January 31, 2007, $89.5 million was outstanding under the construction loan, and we have
recorded a guaranty liability of $2.8 million. Subsequent to the end of the quarter, an additional
$19.7 million became outstanding under the construction financing.
8. Financial Instruments.
We have a syndicated five-year revolving credit facility with aggregate commitments totaling $350
million, which may be increased up to $600 million that includes annual renewal options. This
facility includes letters of credit. We pay an annual fee of $35,000 plus six basis points for any
unused amount up to $350 million. The facility provides a line of credit for letters of credit of
$5 million. The credit facility bears interest based on the 30-day LIBOR rate plus from .15% to
..35%, based on our credit ratings. At January 31, 2007 and October 31, 2006, outstanding
short-term borrowings under the line as included in Notes payable in the condensed consolidated
balance sheets were $232.5 million and $170 million, respectively. During the three months ended
January 31, 2007, short-term borrowings ranged from $139.5 million to $280.5 million, and when
borrowing, interest rates ranged from 5.57% to 5.6% (weighted average of 5.58%). Our 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 54% at January 31, 2007.
We have purchased and sold financial derivative instruments for natural gas in all three states for
our gas purchase portfolios. The gains or losses on financial derivatives utilized in the
regulated utility segment ultimately will be included in our rates to customers. Current period
changes in the assets and liabilities from these risk management activities are recorded as a
component of gas costs in amounts due customers in accordance with Statement 71. Accordingly,
there is no earnings impact on the regulated utility segment as a result of the use of these
financial derivatives. The fair value of gas purchase options increased from $3.1 million as of
October 31, 2006, to $10 million as of January 31, 2007, primarily due to options being exercised
or options expiring during the period and an increase in the market values of the financial
derivative instruments held at January 31, 2007.
13
9. Restructuring.
On April 13, 2006, we announced plans to restructure our management group at an estimated one-time
cost of $7 to $8 million. The restructuring plans are part of an ongoing, larger effort aimed at
streamlining business processes, capturing operational and organizational efficiencies and
improving customer service. The restructuring began with an offer of early retirement for 23
employees in our management group, and eventually included the further consolidation and
reorganization of management positions and functions that was completed in July 2006.
Since April 2006, we have recognized a liability and expense of $7.8 million, which was included in
operations and maintenance expense for the cost of the restructuring program. This liability
included early retirement for 22 employees of the management group and severance for 17 additional
employees through further consolidation. Due to the short discount period, the liability for the
program was recorded at its gross value.
A reconciliation of activity to the liability during the quarter ended January 31, 2007 is as
follows:
|
|
|
|
|
In thousands |
|
|
|
|
|
|
|
|
|
Beginning liability, October 31, 2006 |
|
$ |
1,155 |
|
Costs paid during the quarter |
|
|
(1,006 |
) |
Adustments to accruals |
|
|
(66 |
) |
|
|
|
|
Ending liability, January 31, 2007 |
|
$ |
83 |
|
|
|
|
|
10. Share-Based Payments.
At our annual meeting of shareholders, held March 3, 2006, shareholders approved the Piedmont
Natural Gas Company, Inc. Incentive Compensation Plan (ICP) effective November 1, 2005. The ICP
permits the grant of annual incentive awards, performance awards, restricted stock, stock options
and stock appreciation rights to eligible employees and members of the Board of Directors.
Under our ICP, 65,000 restricted shares of our common stock with a value at the date of grant of
$1.7 million were granted to our President and Chief Executive Officer on September 1, 2006.
During the vesting period, any dividends paid on these shares will be accrued and converted into
additional shares at the closing price on the date of the dividend payment. The restricted shares
and any additional shares accrued through dividends will vest over a five-year period only if he is
an employee on each vesting date. For the three months ended January 31, 2007, we have recorded
$.08 million as compensation expense. We are recording compensation under the ICP on the
straight-line method.
Under the LTIP and ICP, the Board of Directors has awarded units to eligible officers and other
participants. Depending upon the levels of performance targets achieved by Piedmont during
multi-year performance periods, distribution of those awards may be made in the form of shares of
common stock and cash withheld for payment of applicable taxes on the compensation. The LTIP and
ICP require that a minimum threshold performance be achieved in order for any award to be
distributed. For the three months ended January 31, 2007 and 2006, we recorded compensation
expense for the LTIP and ICP of $1 million and $1.4 million, respectively. Shares of common stock
to be issued under the LTIP and ICP are contingently issuable shares and are included in our
calculation of fully diluted earnings per share.
As of January 31, 2007 and October 31, 2006, we have accrued $6 million and $11.4 million for these
14
awards. The accrual is based on the fair market value of our stock at the end each quarter. The
liability is re-measured to market value at the settlement date.
11. Legal Obligations.
From time to time, we conduct business with unaffiliated third party marketers who act as agents
for various industrial customers of ours or who purchase natural gas directly for their own
account. We previously had such an arrangement with National Gas Distributors LLC (NGD), which
filed a voluntary bankruptcy petition on January 20, 2006. The bankruptcy trustee for this
petition claimed that certain amounts paid by NGD to us for gas supply constituted preference
payments, and sought their return. We disputed these claims and vigorously defended our position
on the matter. In October 2006, we agreed to settle with the NGD bankruptcy trustee in order to
avoid protracted litigation and the expense thereof. During the fourth quarter,
we recorded our estimated liability under the settlement. In January 2007, the bankruptcy court
approved the settlement. The settlement did not have a material adverse impact on our financial
position, results of operations or cash flows.
Otherwise, we have only routine litigation in the normal course of business.
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:
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|
Regulatory issues, including those that affect allowed rates of return, terms and
conditions of service, rate structures and financings. We monitor our effectiveness in
achieving the allowed rates of return and initiate rate proceedings or operating changes
as needed. In addition, we purchase natural gas transportation and storage services from
interstate and intrastate pipeline companies whose rates and services are regulated. |
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|
Residential, commercial and industrial growth in our service areas. The ability to
grow our customer base and the pace of that growth are impacted by general business and
economic conditions, such as interest rates, inflation, fluctuations in the capital
markets and the overall strength of the economy in our service areas and the country, and
fluctuations in the wholesale prices of natural gas and competitive energy sources. |
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|
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. We must be able to adapt to the changing
environments and the competition. |
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|
The potential loss of large-volume industrial customers to alternate fuels or to
bypass, or the shift by such customers to special competitive contracts at lower per-unit
margins. |
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|
Regulatory issues, customer growth, deregulation, economic and capital market
conditions, the cost and availability of natural gas and weather conditions can impact our
ability to meet internal performance goals.
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15
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|
The capital-intensive nature of our business. In order to maintain growth, we must add
to our natural gas distribution system each year. The cost of this construction may be
affected by the cost of obtaining governmental approvals, compliance with federal and
state pipeline safety and integrity regulations, development project delays and changes in
project costs. Weather, general economic conditions and the cost of funds to finance our
capital projects can materially alter the cost of a project. |
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Capital market conditions. 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
could affect access to and cost of capital. |
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|
Changes in the availability and cost of natural gas. To meet firm customer
requirements, we must acquire sufficient gas supplies and pipeline capacity to ensure
delivery to our distribution system
while also ensuring that our supply and capacity contracts allow us to remain competitive.
Natural gas is an unregulated commodity market subject to supply and demand and price
volatility. Producers, marketers and pipelines are subject to operating and financial
risks associated with exploring, drilling, producing, gathering, marketing and transporting
natural gas and have risks that increase our exposure to supply and price fluctuations. |
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|
Changes in weather conditions. Weather conditions and other natural phenomena can have
a material impact on our earnings. Severe weather conditions, including destructive
weather patterns such as hurricanes, can impact our suppliers and the pipelines that
deliver gas to our distribution system. Weather conditions directly influence the supply
of, demand for and the cost of natural gas. |
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Changes in environmental, safety and system integrity regulations and the cost of
compliance. We are subject to extensive federal, state and local regulations. Compliance
with such regulations may result in increased capital or operating costs. |
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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. |
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|
Changes in accounting regulations and practices. We are subject to accounting
regulations and practices issued periodically by accounting standard-setting bodies. New
accounting standards may be issued that could change the way we record revenues, expenses,
assets and liabilities. Future changes in accounting standards could affect our reported
earnings or increase our liabilities. |
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Earnings from our equity method investments. We invest in companies that have risks
that are inherent in their businesses, and we assume such risks as an equity investor. |
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 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.
16
Overview
Piedmont Natural Gas Company is an energy services company primarily engaged in the distribution of
natural gas to residential, commercial and industrial customers in portions of North Carolina,
South Carolina and Tennessee. We also have equity method investments in joint venture,
energy-related businesses. Our operations are comprised of two business segments ___
the regulated utility segment and the non-utility activities segment.
The regulated utility segment is the largest segment of our business with approximately 97% of our
consolidated assets. This segment is regulated by three state regulatory commissions that approve
rates and tariffs that are designed to give us the opportunity to generate revenues to cover our
gas and non-gas costs and to earn a fair rate of return for our shareholders. Factors critical to
the success of the regulated utility include
a safe, reliable natural gas distribution system and the ability to recover the costs and expenses
of the business in rates charged to customers. For the three months ended January 31, 2007, 96% of
our earnings before taxes came from our regulated utility segment.
The non-utility activities segment consists of our equity method investments in joint venture,
energy-related businesses that are involved in unregulated retail natural gas marketing, interstate
natural gas storage and intrastate natural gas transportation. We invest in joint ventures that
are aligned with our business strategies to complement or supplement income from utility
operations. We continually monitor performance of these ventures against expectations.
Weather conditions directly influence the volumes of natural gas delivered by the regulated
utility. Significant portions of our revenues are generated during the winter season. During warm
winters or unevenly cold winters, heating customers may significantly reduce their consumption of
natural gas. In South Carolina and Tennessee, we have weather normalization adjustment (WNA)
mechanisms that are designed to protect a portion of our revenues against warmer-than-normal
weather as deviations from normal weather can affect our financial performance and liquidity. The
WNA also serves to offset the impact of colder-than-normal weather by reducing the amounts we can
charge our customers. In North Carolina, a Customer Utilization
Tracker (CUT) provides for the recovery of our approved margin
per customer independent of both weather and other consumption patterns of residential and
commercial customers. For further information, see Our Business in Managements Discussion and
Analysis of Financial Condition and Results of Operations.
Over the past few years, there have been significant increases in the wholesale cost of natural
gas. The relationship between supply and demand has the greatest impact on wholesale gas prices.
Increased wholesale prices for natural gas are being driven by increased demand that is exceeding
the growth in accessible supply. Continued high gas prices could shift our customers preference
away from natural gas toward other energy sources, particularly in the industrial market. High gas
prices could also affect consumption levels as customers react to high bills. We expect that the
wholesale price of natural gas will remain high and volatile until natural gas supply and demand
are in better balance.
The majority of our natural gas supplies come from the Gulf Coast region. We believe that
diversification of our supply portfolio is in our customers best interest. We have a firm
transportation contract pending with Midwestern Gas Transmission Company for additional pipeline
capacity that will provide access to Canadian and Rocky Mountain gas supplies via the Chicago hub,
primarily to serve our Tennessee markets. Due to regulatory delays impacting the commencement of
construction for service during the winter of 2006-2007, Midwestern has only been able to provide a
portion of the original contracted capacity. It is anticipated that the entire capacity will be
available during the 2007-2008 winter. We have also executed an agreement with Hardy Storage
Company, LLC for market-area storage capacity in West Virginia with an anticipated in-service date
in April 2007.
17
Part of our strategic plan is to manage our gas distribution business through control of our
operating costs, implementation of new technologies and sound rate and regulatory initiatives. We
are working to enhance the value and growth of our utility assets by good management of capital
spending, including improvements for current customers and the pursuit of customer growth
opportunities in our service areas. We strive for quality customer service by investing in
technology, processes and people. We work with our state regulators to maintain fair rates of
return and balance the interests of our customers and shareholders.
Our strategic plan includes a focus on maintaining a long-term debt-to-capitalization ratio within
a range of 45 to 50%. We will continue to stress the importance of maintaining a strong balance
sheet and investment-grade credit ratings to support our operating and investment needs.
Results of Operations
We reported net income of $70.7 million for the three months ended January 31, 2007, as compared to
$72 million for the similar period in 2006. The following table sets forth a comparison of the
components of our income statement for the three months ended January 31, 2007, as compared with
the three months ended January 31, 2006.
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|
Percent |
|
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|
Three Months Ended January 31 |
|
|
|
|
|
|
Increase |
|
In thousands, except per share amounts |
|
2007 |
|
|
2006 |
|
|
Change |
|
|
(Decrease) |
|
Operating Revenues |
|
$ |
677,241 |
|
|
$ |
921,347 |
|
|
$ |
(244,106 |
) |
|
|
(26.5 |
)% |
Cost of Gas |
|
|
468,756 |
|
|
|
711,975 |
|
|
|
(243,219 |
) |
|
|
(34.2 |
)% |
Margin |
|
|
208,485 |
|
|
|
209,372 |
|
|
|
(887 |
) |
|
|
(0.4 |
)% |
Operating Expenses |
|
|
126,788 |
|
|
|
128,211 |
|
|
|
(1,423 |
) |
|
|
(1.1 |
)% |
Operating Income |
|
|
81,697 |
|
|
|
81,161 |
|
|
|
536 |
|
|
|
0.7 |
% |
Other Income (Expense) |
|
|
3,357 |
|
|
|
3,478 |
|
|
|
(121 |
) |
|
|
(3.5 |
)% |
Utility Interest Charges |
|
|
14,338 |
|
|
|
12,642 |
|
|
|
1,696 |
|
|
|
13.4 |
% |
Net Income |
|
$ |
70,716 |
|
|
$ |
71,997 |
|
|
$ |
(1,281 |
) |
|
|
(1.8 |
)% |
|
|
|
|
|
|
|
|
|
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|
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|
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|
Average Shares of
Common Stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
74,619 |
|
|
|
76,685 |
|
|
|
(2,066 |
) |
|
|
(2.7 |
)% |
Diluted |
|
|
74,938 |
|
|
|
76,928 |
|
|
|
(1,990 |
) |
|
|
(2.6 |
)% |
|
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|
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|
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|
Earnings Per Share of
Common Stock: |
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.95 |
|
|
$ |
0.94 |
|
|
$ |
0.01 |
|
|
|
1.1 |
% |
Diluted |
|
$ |
0.94 |
|
|
$ |
0.94 |
|
|
$ |
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% |
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18
Key statistics are shown in the table below for the three months ended January 31, 2007 and
2006.
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Gas Deliveries, Customers, Weather Statistics and Number of Employees |
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Three Months Ended |
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Percent |
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|
January 31 |
|
|
|
|
|
Increase |
Gas Sales and Deliveries in Dekatherms (in thousands) |
|
2007 |
|
2006 |
|
Variance |
|
(Decrease) |
|
Sales Volumes |
|
|
45,432 |
|
|
|
48,146 |
|
|
|
(2,714 |
) |
|
|
(5.6 |
)% |
Transportation Volumes |
|
|
21,481 |
|
|
|
18,033 |
|
|
|
3,448 |
|
|
|
19.1 |
% |
|
Throughput |
|
|
66,913 |
|
|
|
66,179 |
|
|
|
734 |
|
|
|
1.1 |
% |
|
Secondary Market Volumes |
|
|
9,660 |
|
|
|
8,826 |
|
|
|
834 |
|
|
|
9.4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Customers Billed (at period end) |
|
|
939,509 |
|
|
|
918,879 |
|
|
|
20,630 |
|
|
|
2.2 |
% |
Gross Customer Additions |
|
|
8,927 |
|
|
|
9,368 |
|
|
|
(441 |
) |
|
|
(4.7 |
)% |
|
Degree Days |
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|
|
|
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|
|
|
|
|
|
|
|
Actual |
|
|
1,615 |
|
|
|
1,723 |
|
|
|
(108 |
) |
|
|
(6.3 |
)% |
Normal |
|
|
1,900 |
|
|
|
1,906 |
|
|
|
(6 |
) |
|
|
(0.3 |
)% |
Percent colder (warmer) than normal |
|
|
(15.0 |
)% |
|
|
(9.6 |
)% |
|
|
n/a |
|
|
|
n/a |
|
|
Number of Employees |
|
|
1,967 |
|
|
|
2,107 |
|
|
|
(140 |
) |
|
|
(6.6 |
)% |
|
Operating Revenues
Operating revenues decreased $244.1 million for the three months ended January 31, 2007, compared
with the similar period in 2006 primarily due to the following decreases:
|
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|
$185.2 million from decreased commodity gas costs passed through to sales customers. |
|
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|
$33.9 million from decreased volumes to sales customers. |
|
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|
$29.8 million from decreased commodity gas costs in secondary market activity.
Secondary market transactions consist of off-system sales and capacity release
arrangements. |
These decreases were partially offset by the following increases:
|
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|
$6.1 million increase from the CUT mechanism amount in 2007 compared to the 2006 CUT
amount. As discussed in Financial Condition and Liquidity below, the CUT mechanism
became effective November 1, 2005 in North Carolina to offset the impact of conservation
and unusually cold or warm weather on residential and commercial customer billings and
margin. |
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|
$5 million from increased transportation volumes. |
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|
$2.8 million increase from the WNA surcharged in 2007 compared to the 2006 WNA
surcharged. As discussed in Financial Condition and Liquidity below, we had a WNA in
South Carolina and Tennessee to offset the impact of unusually cold or warm weather on
residential and commercial customer billings and margin. |
Cost of Gas
Cost of gas decreased $243.2 million for the three months ended January 31, 2007, compared with the
similar period in 2006 primarily due to the following decreases:
|
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|
$185.2 million from lower commodity gas costs passed through to customers. |
|
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|
$33.9 million from decreased volumes to sales customers. |
|
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|
$30.2 million from lower commodity gas costs in secondary market activity. |
19
Under purchased gas adjustment (PGA) procedures in all three states, we revise rates periodically
without formal rate proceedings to reflect changes in the wholesale cost of gas. Charges to cost
of gas are based on the amount recoverable under approved rate schedules. The net of any over- or
under-recoveries of gas costs are added to or deducted from cost of gas and included in Amounts
due from customers or Amounts due to customers in the condensed consolidated balance sheets.
Margin
Margin decreased $.9 million for the three months ended January 31, 2007, compared with the similar
period in 2006, primarily due to $1.5 million of gas cost accounting adjustments related to lost
and unaccounted for gas and interest charges related to gas purchases, $.75 million of annual
adjustments under the CUT settlement and warmer weather, which were partially offset by growth in
the residential and commercial customer base.
Our utility margin is defined as natural gas revenues less natural gas commodity purchases and
fixed gas costs for upstream capacity. Margin, rather than revenues, is used by management to
evaluate utility operations due to the impact of volatile wholesale commodity prices, which account
for approximately 70% of revenues.
Our utility margin is impacted also by certain regulatory mechanisms as defined elsewhere in this
document or in our Form 10-K for the year ended October 31, 2006. These include WNA in Tennessee
and South Carolina, the Natural Gas Rate Stabilization in South Carolina, Gas Purchase Incentive
Plan in Tennessee, CUT in North Carolina, negotiated loss treatment in all three jurisdictions and
the collection of uncollectible gas costs in all three jurisdictions.
We retain 25% of margins generated through off-system sales and capacity release activity related
to North Carolina and South Carolina, with 75% credited to the customers through the PGA mechanism.
Operations and Maintenance Expenses
Operations and maintenance expenses decreased $1 million for the three months ended January 31,
2007, compared with the similar period in 2006 primarily due to the following decreases:
|
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|
$1.5 million in payroll primarily related to the 2006 management restructuring program,
including impacts on short-term and long-term incentive plan accruals. |
|
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|
$.6 million in the provision for uncollectibles due to a change in methodology approved
by the Public Service Commission of South Carolina (PSCSC) and lower charge-offs.
Effective November 1, 2006, the PSCSC authorized the recovery of all uncollected gas costs
through the gas deferred account. As a result, only the portion of accounts written off
relating to non-gas costs, or margin, is included in base rates and accordingly, only this
portion is included in the provision for uncollectibles expense. A similar mechanism has
been in place for our North Carolina operations since November 2005 and for our Tennessee
operations since March 2004. |
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|
$.5 million in materials primarily due to less maintenance activity during the period. |
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|
$.3 million in regulatory expense primarily due to lower regulatory fees, which are
calculated on revenues, which are lower as a result of a decrease in the commodity cost of
gas. |
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|
$.2 million in transportation costs primarily due to a decrease in the cost of fuel and
the impact of fewer vehicles being used as a result of the automated meter reading
initiative. |
These decreases were partially offset by the following increases:
|
|
|
$1.2 million in outside services primarily due to enhanced customer service initiative
activities. |
20
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|
|
$.7 million in other corporate expense primarily due to the funding of conservation
programs under our CUT settlement. |
Depreciation
Depreciation expense decreased $.3 million for the three months ended January 31, 2007 compared
with the similar period in 2006 primarily due to asset retirements, in the normal course of
business, of personal computers whose depreciable lives were reduced from six years to four years.
General Taxes
General taxes increased $.5 million for the three months ended January 31, 2007 as compared with
the similar period in 2006 primarily due to increases in gross receipts taxes and state franchise
taxes.
Other Income (Expense)
Income from equity method investments includes our earnings from joint venture investments.
Non-operating income is comprised of non-regulated merchandising and service work, subsidiary
operations, interest income and other miscellaneous income. Non-operating expense is comprised of
charitable contributions and other miscellaneous expenses.
The changes in Other Income (Expense) are not significant.
Utility Interest Charges
Utility interest charges increased $1.7 million for the three months ended January 31, 2007,
compared with the similar period in 2006 primarily due to the following:
|
|
|
$2.3 million increase in interest on long-term debt due to the issuance on June 20, 2006
of $200 million of insured quarterly notes due June 1, 2036. |
|
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|
|
$.3 million increase in interest expense on regulatory treatment of certain components
of deferred income taxes. |
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|
|
$.7 million decrease due to an increase in the allowance for funds used during
construction allocated to debt. |
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|
|
$.3 million decrease in net interest expense on amounts due to/from customers due to
higher net receivables in 2007. |
Our Business
Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company
primarily engaged in the distribution of natural gas to 1,016,000 residential, commercial and
industrial customers in portions of North Carolina, South Carolina and Tennessee, including 62,000
customers served by municipalities who are our wholesale customers. We are invested in joint
venture, energy-related businesses, including unregulated retail natural gas marketing, interstate
natural gas storage and intrastate natural gas transportation.
We continually assess the nature of our business and explore alternatives to traditional utility
regulation. Non-traditional ratemaking initiatives and market-based pricing of products and
services provide additional challenges and opportunities for us. We also regularly evaluate
opportunities for obtaining natural gas supplies from different production regions and supply
sources to maximize our natural gas portfolio
21
flexibility and reliability, including the diversification of our supply portfolio through pipeline
capacity arrangements that access new sources of supply and market-area storage and that diversify
supply concentration away from the Gulf Coast region. We have a firm transportation contract
pending with Midwestern Gas Transmission Company for 120,000 dekatherms per day of additional
pipeline capacity that will provide access to Canadian and Rocky Mountain gas supplies via the
Chicago hub, primarily to serve our Tennessee markets. Due to regulatory delays impacting
commencement of construction, we have only contracted for 40,000 of the total 120,000 dekatherms
per day of capacity for the winter of 2006-2007 with the difference being covered by short-term
firm winter arrangements. It is anticipated that the entire capacity will be available during the
2007-2008 winter. We have also executed an agreement with Hardy Storage Company, LLC for
market-area storage capacity in West Virginia with an anticipated in-service date in April 2007.
We have two reportable business segments, regulated utility and non-utility activities. For
further information on business segments, see Note 6 to the condensed consolidated financial
statements.
Our
utility operations are regulated by the NCUC, PSCSC and the Tennessee
Regulatory Authority as to rates, service area,
adequacy of service, safety standards, extensions and abandonment of facilities, accounting and
depreciation. We are also regulated by the NCUC as to the issuance of securities. We are also
subject to or affected by various federal regulations. These federal regulations include
regulations that are particular to the natural gas industry, such as regulations of the FERC that
affect the availability of and the prices paid for the interstate transportation and storage of
natural gas, regulations of the Department of Transportation that affect the construction,
operation, maintenance, integrity and safety of natural gas distribution and transmission systems,
and regulations of the Environmental Protection Agency relating to the use and release into the
environment of hazardous wastes. In addition, we are subject to numerous regulations, such as
those relating to employment practices, which are generally applicable to companies doing business
in the United States of America.
In the Carolinas, our service area is comprised of numerous cities, towns and communities. We
maintain service offices in 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 Greenville, Monroe, Rocky Mount and Wilson. In Tennessee, our service area is the metropolitan
area of Nashville, including wholesale natural gas service to Gallatin and Smyrna.
Our regulatory commissions approve rates and tariffs that are designed to give us the opportunity
to generate revenues to cover our gas and non-gas costs and to earn a fair rate of return for our
shareholders. Through October 31, 2005, we had WNA mechanisms in all three states that partially
offset the impact of unusually cold or warm weather on bills rendered during the months of November
through March for weather-sensitive customers. The WNA formula calculates the actual weather
variance from normal, using 30 years of history, which results in an increase in revenues when
weather is warmer than normal and a decrease in revenues when weather is colder than normal. The
gas cost portion of our costs is recoverable through PGA procedures and is not affected by the WNA.
Effective November 1, 2005, the WNA was eliminated in North Carolina and replaced with the CUT
that provides for the recovery of our approved margin per customer independent of both weather or
other consumption patterns of residential and commercial customers. The CUT tracks our margin
earned monthly and will result in semi-annual rate adjustments to refund any over-collection or
recover any under-collection. The WNA mechanism remains in effect for our South Carolina and
Tennessee operations.
We invest in joint ventures to complement or supplement income from our regulated utility
operations. If an opportunity aligns with our overall business strategies, we analyze and evaluate
the project with a major
22
factor being a projected rate of return greater than the returns allowed in our utility operations, due
to the higher risk of such projects. We participate in the governance of the venture by having a
management representative on the governing board of the venture. We monitor actual performance
against expectations. Decisions regarding exiting joint ventures are based on many factors,
including performance results and continued alignment with our business strategies.
Financial Condition and Liquidity
To meet our capital and liquidity requirements, we rely on certain resources, including cash flows
from operating activities, access to capital markets, cash generated from our investments in joint
ventures and short-term bank borrowings. We believe that these sources will continue to allow us
to meet our needs for working capital, construction expenditures, anticipated debt redemptions and
dividend payments.
Cash Flows from Operating Activities. The natural gas business is seasonal in nature.
Operating cash flows may fluctuate significantly during the year and from year to year due to
working capital changes within our utility and non-utility operations resulting from such factors
as weather, natural gas purchases and prices, gas inventory storage activity, collections from
customers and deferred gas cost recoveries. We rely on operating cash flows and short-term bank
borrowings to meet seasonal working capital needs. During our first and second quarters, we
generally experience overall positive cash flows from the sale of flowing gas and gas in storage
and the collection of amounts billed to customers during the peak heating season (November through
March). Cash requirements generally increase during the third and fourth quarters due to increases
in natural gas purchases for storage, paying down short-term debt and decreases in receipts from
customers.
During the peak heating season, our accounts payable increase to reflect amounts due to our natural
gas suppliers for commodity and pipeline capacity. The value of the gas can vary significantly
from period to period due to volatility in the price of natural gas, which is a function of market
fluctuations in the price of natural gas, along with our changing requirements for storage volumes.
Our natural gas costs and amounts due to/from customers represent the difference between natural
gas costs that we have paid to suppliers and amounts that we have collected from customers. These
natural gas costs can cause cash flows to vary significantly from period to period along with
variations in the timing of collections of gas costs 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 consumption. Temperatures above normal can lead to reduced
operating cash flows, thereby increasing the need for short-term borrowings to meet current cash
requirements.
Net cash
provided by (used in) operating activities was $21.9 million and $(118.8) million for the
three months ended January 31, 2007 and 2006, respectively. Net cash provided by operating
activities reflects a $1.3 million decrease in net income for 2007, compared with 2006, as well as
changes in working capital as described below:
|
|
|
Trade accounts receivable and unbilled utility revenues decreased $211.6 million in the
current period primarily due to the current winter period being 15% warmer than normal and
6% warmer than the similar prior period, and amounts billed to customers reflected lower
gas costs in 2007 as compared with 2006. Volumes sold to residential and commercial
customers decreased 2.5 million dekatherms as compared with the prior year period primarily
due to the warmer weather. |
|
|
|
|
Amounts due to/from customers increased $27.3 million in the current period from the
deferral of gas costs yet to be billed and collected from customers. |
23
|
|
|
Gas in storage decreased $4.6 million in the current period primarily due to decreases
in the average gas costs. |
|
|
|
|
Prepaid gas costs decreased $41.5 million in the current period as compared with a
decrease of $48.2 million in the prior period. Under asset management agreements, prepaid
gas costs during the summer months represent purchases of gas that are not available for
sale, and therefore not recorded in inventory, until November 1, the beginning of the
winter period. |
|
|
|
|
Trade accounts payable increased $50.9 million in the current period primarily due to
gas purchases to meet customer demand during the winter months. |
Our regulatory commissions approve rates that are designed to give us the opportunity to generate
revenues, assuming normal weather, to cover our gas costs and fixed and variable non-gas costs and
to earn a fair return for our shareholders. We have had a WNA mechanism in South Carolina and
Tennessee that partially offsets the impact of unusually cold or warm weather on bills rendered in
November through March for weather-sensitive customers. The WNA in South Carolina and Tennessee
generated charges to customers of $7.9 million in the three months ended January 31, 2007 and
charges to customers of $5.1 million in the three months ended January 31, 2006. In Tennessee,
adjustments are made directly to the customers bills. In South Carolina, the adjustments are
calculated at the individual customer level and recorded in a deferred account for subsequent
collection from or refund to all customers in the class. The CUT mechanism in North Carolina
provides for any over- or under-collection of approved margin per customer that operates
independently of both weather and consumption patterns of residential and commercial customers.
The CUT mechanism provided margin of $19.5 million and $13.4 million in the three months ended
January 31, 2007 and 2006, respectively. Our gas costs are recoverable through PGA procedures and
are not affected by the WNA or the CUT.
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 commission approval in North Carolina, South Carolina and Tennessee that places additional
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, such as price volatility, the availability of natural gas in relation to
other energy forms, general economic conditions, weather, energy conservation and the ability to
convert from natural gas to other energy sources. Increases in the price of natural gas can
negatively impact our competitive position by decreasing the price benefits of natural gas to the
consumer. This can impact our cash needs if customer growth slows, resulting in reduced capital
expenditures, or if customers conserve, resulting in reduced gas purchases and customer billings.
In the industrial market, many of our customers are capable of burning a fuel other than natural
gas, with fuel oil being the most significant competing energy alternative. Our ability to
maintain industrial market share is largely dependent on price. The relationship between supply
and demand has the greatest impact on the price of natural gas. With a tighter balance between
domestic supply and demand, the cost of natural gas from non-domestic sources may play a greater
role in establishing the future market price of natural gas. The price of oil depends upon a
number of factors beyond our control, including the relationship between supply and demand and the
policies of foreign and domestic governments and organizations. Our liquidity could be impacted,
either positively or negatively, as a result of alternate fuel decisions made by industrial
customers.
24
Cash Flows from Investing Activities. Net cash used in investing activities was $30
million and $30.2 million for the three months ended January 31, 2007 and 2006, respectively. Net
cash used in investing activities was primarily for utility construction expenditures. Gross utility
construction expenditures for the three months ended January 31, 2007, were $29.5 million as
compared to $51.1 million in the similar prior period. The decrease was primarily due to several
large projects in 2006, such as automated meter reading, certain revenue-producing projects in the districts
and enterprise telephony that are now complete or nearing completion. Reimbursements from the bond fund
decreased $8 million from 2006 as construction of gas infrastructure in eastern North Carolina is complete.
During the three months ended January 31, 2006, the restrictions on cash totaling $13.1 million
were removed in connection with implementing the NCUC order in a general rate proceeding. As
ordered by the NCUC, such cash had been held in an expansion fund to extend natural gas service to
unserved areas of the state.
We have a substantial capital expansion program for construction of distribution facilities,
purchase of equipment and other general improvements. This program primarily supports the growth
in our customer base. Gross utility construction expenditures totaling $144.8 million, primarily
to serve customer growth, are budgeted for fiscal year 2007; however, we are not contractually
obligated to expend capital until work is completed. Due to projected growth in our service areas,
significant utility construction expenditures are expected to continue and are a part of our
long-range forecasts that are prepared at least annually and typically cover a forecast period of
five years.
Cash Flows from Financing Activities. Net cash provided by financing activities was $17.2
million and $171.6 million for the three months ended January 31, 2007 and 2006, respectively.
Funds are primarily provided from bank borrowings and the issuance of common stock through dividend
reinvestment and employee stock plans, net of purchases under the common stock repurchase program.
When required, we sell common stock and long-term debt to cover cash requirements when market and
other conditions favor such long-term financing. As of January 31, 2007, our current assets were
$616.4 million and our current liabilities were $517 million, primarily due to seasonal
requirements as discussed above.
As of January 31, 2007, we had committed lines of credit under our senior credit facility
effective April 24, 2006, of $350 million with the ability to expand up to $600 million, for which
we pay an annual fee of $35,000 plus six basis points for any unused amount up to $350 million.
Outstanding short-term borrowings increased from $170 million as of October 31, 2006, to $232.5
million as of January 31, 2007, primarily due to the purchase of shares under the ASR program,
payments in January 2007 for interest on long-term debt and property taxes and payments to
suppliers for the winter heating season. During the three months ended January 31, 2007,
short-term borrowings ranged from $139.5 million to $280.5 million, and when borrowing, interest
rates ranged from 5.57% to 5.6% (weighted average of 5.58%).
As of January 31, 2007, under our credit facility, we had available letters of credit of $5 million
of which $1.4 million was issued and outstanding. The letters of credit are used to guarantee
claims from self-insurance under our general liability policies. As of January 31, 2007, unused
lines of credit available under our senior credit facility, including the issuance of the letters
of credit, totaled $116.1 million.
The level of short-term borrowings can vary significantly due to changes in the wholesale prices of
natural gas and to the level of purchases of natural gas supplies to serve customer demand and for
storage. Short-term debt may increase when wholesale prices for natural gas increase because we
must pay suppliers for the gas before we collect our costs from customers through their monthly
bills. Gas prices could continue to increase and fluctuate. If wholesale gas prices remain high,
we may incur more short-term debt to pay for natural gas supplies and other operating costs since
collections from customers could be slower and some
25
customers may not be able to pay their gas bills on a timely basis.
During the three months ended January 31, 2007, we issued $4 million of common stock through
dividend reinvestment and stock purchase plans. On November 7, 2006, through an ASR agreement, we
repurchased and retired 1 million shares of common stock for $26.6 million. On January 19, 2007,
we settled the transaction and paid an additional $.8 million. Under the Common Stock Open Market
Purchase Program, as described in Part II, Item 2, we paid $31.4 million during the three months
ended January 31, 2007 for 1.2 million shares of common stock that are available for reissuance to
these plans.
Through the ASR program, we may repurchase and subsequently retire up to approximately four million
shares of common stock by no later than December 31, 2010, including the 1 million shares
repurchased in April 2006 and the 1 million shares repurchased in November 2006. These shares are
in addition to shares that are repurchased on a normal basis through the open market program.
We have paid quarterly dividends on our common stock since 1956. The amount of cash dividends that
may be paid is restricted by provisions contained in certain note agreements under which long-term
debt was issued. As of January 31, 2007, our retained earnings were not restricted. On March 7,
2007, the Board of Directors declared a quarterly dividend on common stock of $.25 per share,
payable April 13 to shareholders of record at the close of business on March 23.
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.
The components of our total debt outstanding to our total capitalization as of January 31, 2007 and
2006, and October 31, 2006, are summarized in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 31 |
|
|
October 31 |
|
|
January 31 |
|
In thousands |
|
2007 |
|
|
Percentage |
|
|
2006 |
|
|
Percentage |
|
|
2006 |
|
|
Percentage |
|
Short-term debt |
|
$ |
232,500 |
|
|
|
12 |
% |
|
$ |
170,000 |
|
|
|
9 |
% |
|
$ |
350,000 |
|
|
|
18 |
% |
Current portion of long-term debt |
|
|
|
|
|
|
0 |
% |
|
|
|
|
|
|
0 |
% |
|
|
35,000 |
|
|
|
2 |
% |
Long-term debt |
|
|
825,000 |
|
|
|
42 |
% |
|
|
825,000 |
|
|
|
44 |
% |
|
|
625,000 |
|
|
|
32 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt |
|
|
1,057,500 |
|
|
|
54 |
% |
|
|
995,000 |
|
|
|
53 |
% |
|
|
1,010,000 |
|
|
|
52 |
% |
Common
stockholders equity |
|
|
912,013 |
|
|
|
46 |
% |
|
|
882,925 |
|
|
|
47 |
% |
|
|
939,862 |
|
|
|
48 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization (including short-term debt) |
|
$ |
1,969,513 |
|
|
|
100 |
% |
|
$ |
1,877,925 |
|
|
|
100 |
% |
|
$ |
1,949,862 |
|
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Credit ratings impact our ability to obtain short-term and long-term financing and the cost of
such financings. In determining our credit ratings, the rating agencies consider a number of
quantitative factors, including debt to total capitalization, operating cash flows relative to
outstanding debt, operating cash flow coverage of interest and pension liabilities and funding
status. Rating agencies also consider qualitative factors, such as the consistency of our earnings
over time, the quality of management and business strategy, the risks associated with our utility
and non-utility businesses and the regulatory commissions that establish rates in the states where
we operate.
As of January 31, 2007, all of our long-term debt was unsecured. Our long-term debt is rated A
by Standard & Poors Ratings Services and A3 by Moodys Investors. Currently, with respect to
our long-term debt, the credit agencies maintain their stable outlook. There is no guarantee that
a rating will remain in effect for any given period of time or that a rating will not be lowered or
withdrawn by a rating agency if, in its judgment, circumstances warrant a change.
26
We are subject to default provisions related to our long-term debt and short-term borrowings.
Failure to satisfy any of the default provisions would result in total outstanding issues of debt
becoming due. There are cross-default provisions in all our debt agreements. As of January 31,
2007, we are in compliance with all default provisions.
Estimated Future Contractual Obligations
During the three months ended January 31, 2007, there were no material changes to our estimated
future contractual obligations that were disclosed in our Form 10-K for the year ended October 31,
2006, in Managements Discussion and Analysis of Financial
Condition and Results of Operations.
Off-balance Sheet Arrangements
We have no off-balance sheet arrangements other than operating leases that were discussed in Note 7
to the consolidated financial statements in our Form 10-K for the year ended October 31, 2006.
Piedmont Energy Partners, Inc., a wholly-owned subsidiary of Piedmont, has entered into a guaranty
in the normal course of business. The guaranty involves levels of performance and credit risk that
are not included on our condensed consolidated balance sheets. The possibility of having to
perform on the guaranty is largely dependent upon the future operations of the joint venture, third
parties or the occurrence of certain future events. For further information on this guaranty, see
Note 7 to the condensed consolidated financial statements.
Critical Accounting Policies and Estimates
We prepare the condensed consolidated financial statements in conformity with accounting principles
generally accepted in the United States of America. We make estimates and assumptions that affect
the reported amounts of assets and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the periods reported. Actual results may differ
significantly from these estimates and assumptions. We base our estimates on historical
experience, where applicable, and other relevant factors that we believe are reasonable under the
circumstances. On an ongoing basis, we evaluate estimates and assumptions and make adjustments in
subsequent periods to reflect more current information if we determine that modifications in
assumptions and estimates are warranted.
Management considers an accounting estimate to be critical if it requires assumptions to be made
that were uncertain at the time the estimate was made and changes in the estimate or a different
estimate that could have been used would have had a material impact on our financial condition or
results of operations. We consider regulatory accounting, revenue recognition, goodwill and
pension and postretirement benefits to be our critical accounting estimates. Management is
responsible for the selection of the critical accounting estimates presented in our Form 10-K for
the year ended October 31, 2006, 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, 2006.
Recent Accounting Pronouncements
In June 2006, the FASB issued Interpretation 48, Accounting for Uncertainty in Income Taxes (FIN
48), to clarify the accounting for uncertain tax positions in accordance with SFAS 109, Accounting
for Income Taxes. FIN 48 defines a minimum recognition threshold that a tax position must meet to
be recognized in an enterprises financial statements. Additionally, FIN 48 provides guidance on
derecognition, measurement,
27
classification, interim period accounting, disclosure and transition
requirements in accounting for uncertain tax positions. This interpretation is effective the beginning
of the first annual period beginning after December 15, 2006. Accordingly, we will adopt FIN 48 in our fiscal
year 2008. We are currently assessing the impact FIN 48 may have on our consolidated financial statements; however,
we believe the adoption of FIN 48 will not have a material impact on our financial position,
results of operations or cash flows.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (Statement 157).
Statement 157 provides enhanced guidance for using fair value to measure assets and liabilities and
applies whenever other standards require (or permit) the measurement of assets or liabilities at
fair value, but does not expand the use of fair value measurement to any new circumstances.
Statement 157 establishes a fair value hierarchy that prioritizes the information used to develop
those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active
markets and the lowest priority to unobservable data, for example, the reporting entitys own data.
Under Statement 157, fair value measurements would be separately disclosed by level within the
fair value hierarchy. Statement 157 is effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods within those fiscal years, with earlier
application encouraged. Accordingly, we will adopt Statement 157 no later than our first fiscal
quarter in 2009. We believe the adoption of Statement 157 will not have a material impact on our
financial position, results of operations or cash flows.
In September 2006, the FASB issued SFAS No. 158, Employers Accounting for Defined Benefit Pension
and Other Postretirement Plans (Statement 158). Statement 158 requires an employer to fully
recognize the obligations associated with single-employer defined benefit pension, retiree
healthcare and other postretirement plans in the financial statements by recognizing in its
statement of financial position an asset for a plans overfunded status or a liability for a plans
underfunded status rather than only disclosing the funded status in the footnotes to the financial
statements. Statement 158 requires employers to recognize changes in the funded status of a
defined benefit postretirement plan in the year in which the changes occur. Under Statement 158,
gains and losses, prior service costs and credits, and any remaining transition amounts that have
not yet been recognized through net periodic benefit cost will be recognized in accumulated other
comprehensive income (OCI), net of tax effects, until they are amortized as a component of net
periodic cost. Statement 158 also requires that the company measure a plans assets and its
obligations that determine its funded status as of the end of the employers fiscal year. We are
already in compliance with this requirement as our pension plans measurement dates are already the
same as our fiscal year end date.
The requirement to recognize the funded status of a benefit plan and the related disclosure
requirements initially will apply as of the end of the fiscal year ending after December 15, 2006.
Accordingly, we will adopt the funded status portion of Statement 158 as of October 31, 2007. We
believe the adoption of Statement 158 will not have a material effect on our financial position,
results of operations or cash flows.
Based on a preliminary assessment of prior regulatory treatment of postretirement benefits,
management believes that regulatory asset or liability treatment will be afforded to any amounts
that would otherwise be recorded in accumulated OCI resulting from the implementation of Statement
158. We intend to meet with our regulators in fiscal year 2007 to discuss the regulatory
accounting and rate treatment of the impact of the adoption of Statement 158. Assuming regulatory
treatment, if Statement 158 had been adopted for the fiscal year ended October 31, 2006, the effect
on the consolidated balance sheets would have been the recognition of $25.6 million as a regulatory
asset, $16.7 million of deferred income taxes, $14.6 million decrease to prepaid pension and $27.7
million increase in accrued postretirement benefits. The actual impact at October 31, 2007 could
be substantially different depending on the discount rate, asset returns and plan population at
that date.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and
Financial Liabilities (Statement 159). Statement 159 provides companies with an option to report
selected
28
financial assets and liabilities at fair value. Its objective is to reduce the complexity
in accounting for financial instruments and to mitigate the volatility in earnings caused by measuring related assets
and liabilities differently. Although Statement 159 does not eliminate disclosure requirements
included in other accounting standards, it does establish additional presentation and disclosure
requirements designed to facilitate comparisons between companies that choose different measurement
attributes for similar types of assets and liabilities. Statement 159 is effective for financial
statements issued for fiscal years beginning after November 15, 2007, with early adoption permitted
for an entity that has elected also to apply Statement 157 early. Accordingly, we will adopt
Statement 159 no later than our first fiscal quarter in 2009. We believe the adoption of Statement
159 will not have a material impact on our financial position, results of operations or cash flows.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
We hold all financial instruments discussed in this item for purposes other than trading. We are
potentially exposed to market risk due to changes in interest rates and the cost of gas. Our
exposure to interest rate changes relates primarily to short-term debt. We are exposed to
interest rate changes to long-term debt when we are in the market to issue long-term debt. As of
January 31, 2007, all of our long-term debt was issued at fixed rates. Exposure to gas cost
variations relates to the wholesale supply, demand and price of natural gas.
Interest Rate Risk
We have short-term borrowing arrangements to provide working capital and general corporate funds.
The level of borrowings under such arrangements varies from period to period depending upon many
factors, including our investments in capital projects. Future short-term interest expense and
payments will be impacted by both short-term interest rates and borrowing levels.
As of January 31, 2007, we had $232.5 million of short-term debt outstanding under committed bank
lines of credit at a weighted average interest rate of 5.58%. The carrying amount of our
short-term debt approximates fair value. A change of 100 basis points in the underlying average
interest rate for our short-term debt would have caused a change in interest expense of
approximately $1.7 million during the three months ended January 31, 2007.
As of January 31, 2007, all of our long-term debt was at fixed interest rates and, therefore, not
subject to interest rate risk.
Commodity Price Risk
In the normal course of business, we utilize exchange-traded contracts of various durations for the
forward sale and purchase of a portion of our natural gas requirements. We manage our gas supply
costs through a portfolio of short- and long-term procurement contracts with various suppliers.
Due to cost-based rate regulation in our utility operations, we recover prudently incurred
purchased gas costs, and the costs of hedging our gas supplies are passed on to customers through
PGA procedures.
Additional information concerning market risk is set forth in Financial Condition and Liquidity
in Managements Discussion and Analysis of Financial Condition and Results of Operations in Item 2
of this Form 10-Q.
29
Item 4. Controls and Procedures
Our management, including the President and Chief Executive Officer and the Senior Vice President
and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and
procedures as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of the
period covered by this Form 10-Q. Based on such evaluation, 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 in
that they provide reasonable assurances that the information we are required to disclose in the
reports we file or submit under the Exchange Act is recorded, processed, summarized and reported
within the time periods required by the United States Securities and Exchange Commissions rules
and forms.
We routinely review our internal control over financial reporting and from time to time make
changes intended to enhance the effectiveness of our internal control over financial reporting.
There were no changes to our internal control over financial reporting as such term is defined in
Rules 13a-15(f) and 15d-15(f) under the Exchange Act during the first quarter of fiscal 2007 that
materially affected, or are reasonably likely to materially affect, our internal control over
financial reporting.
Part II. Other Information
Item 1. Legal Proceedings
From time to time, we conduct business with unaffiliated third party marketers who act as agents
for various industrial customers of ours or who purchase natural gas directly for their own
account. We previously had such an arrangement with NGD, which filed a voluntary bankruptcy
petition on January 20, 2006. The bankruptcy trustee for this petition claimed that certain
amounts paid by NGD to us for gas supply constituted preference payments, and sought their return.
We disputed these claims and vigorously defended our position on the matter. In October 2006, we
agreed to settle with the NGD bankruptcy trustee in order to avoid protracted litigation and the
expense thereof. During the fourth quarter, we recorded our estimated liability under the
settlement. In January 2007, the bankruptcy court approved the settlement. The settlement did not
have a material adverse impact on our financial position, results of operations or cash flows.
Otherwise, we have only routine litigation in the normal course of business.
Item 1A. Risk Factors
During the three months ended January 31, 2007, there were no material changes to our risk factors
that were disclosed in our Form 10-K for the year ended October 31, 2006.
30
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
c) Issuer Purchases of Equity Securities.
The following table provides information with respect to purchases of common stock under the
Common Stock Open Market Purchase Program during the three months ended January 31, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
Beginning of the
period |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,612,074 |
|
11/1/06 11/30/06 |
|
|
1,000,000 |
|
|
$ |
27.44 |
|
|
|
1,000,000 |
|
|
|
5,612,074 |
|
12/1/06 12/31/06 |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
5,612,074 |
|
01/1/07 01/31/07 |
|
|
150,000 |
|
|
$ |
26.35 |
|
|
|
150,000 |
|
|
|
5,462,074 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
1,150,000 |
|
|
$ |
27.30 |
|
|
|
1,150,000 |
|
|
|
|
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The Common Stock Open Market Purchase Program was announced on June 4, 2004, to purchase up to
three million shares of common stock for reissuance under our dividend reinvestment, stock purchase
and incentive compensation plans. On December 16, 2005, the Board of Directors approved an
increase in the number of shares in this program from three million to six million to reflect the
two-for-one stock split in 2004. The Board also approved 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.
These combined actions increased the total authorized share repurchases from three million to ten
million shares. The additional four million shares are referred to as our accelerated share
repurchase program and have an expiration date of December 31, 2010.
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 January 31, 2007, net earnings available for restricted
payments were greater than retained earnings; therefore, our retained earnings were not restricted.
Item 6. Exhibits
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31.1 |
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Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer. |
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31.2 |
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Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer. |
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32.1 |
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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. |
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32.2 |
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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. |
31
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.
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Piedmont Natural Gas Company, Inc.
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(Registrant) |
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Date March 9, 2007 |
/s/ David J. Dzuricky
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David J. Dzuricky |
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Senior Vice President and Chief Financial Officer
(Principal Financial Officer) |
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Date March 9, 2007 |
/s/ Jose M. Simon
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Jose M. Simon |
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Vice President and Controller
(Principal Accounting Officer) |
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32
Piedmont Natural Gas Company, Inc.
Form 10-Q
For the Quarter Ended January 31, 2007
Exhibits
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31.1 |
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Certification Pursuant to Section
302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer |
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31.2 |
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Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer |
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32.1 |
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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 |
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32.2 |
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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 |