FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended December 31, 2004
Commission file number: 1-7196
CASCADE NATURAL GAS CORPORATION
(Exact name of Registrant as specified in its charter)
Washington |
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91-0599090 |
(State or other jurisdiction of |
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(I.R.S. Employer |
incorporation or organization) |
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Identification No.) |
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222 Fairview Avenue North, Seattle, WA |
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98109 |
(Address of principal executive offices) |
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(Zip code) |
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(Registrants telephone number including area code) |
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(206) 624-3900 |
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 ý No o
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 23b-2 of the Exchange Act). Yes ý No o
Indicate the number of shares outstanding of each of the registrants classes of common stock, as of the latest practicable date.
Title |
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Outstanding |
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Common Stock, Par Value $1 per Share |
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11,293,156 as of January 24, 2005 |
CASCADE NATURAL GAS CORPORATION
Index
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Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations |
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Item 3. Quantitative and Qualitative Disclosures about Market Risk |
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2
CASCADE NATURAL GAS CORPORATION
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
(unaudited)
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THREE MONTHS ENDED |
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Dec 31, 2004 |
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Dec 31, 2003 |
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(thousands except per share data) |
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Operating revenues |
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$ |
104,613 |
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$ |
104,884 |
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Less: Gas purchases |
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69,122 |
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67,525 |
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Revenue taxes |
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6,569 |
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6,666 |
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Operating margin |
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28,922 |
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30,693 |
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Cost of operations: |
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Operating expenses |
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10,420 |
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10,278 |
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Depreciation and amortization |
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4,205 |
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3,921 |
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Property and miscellaneous taxes |
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959 |
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930 |
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15,584 |
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15,129 |
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Income from operations |
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13,338 |
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15,564 |
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Less interest and other deductions - net |
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2,894 |
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3,116 |
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Income before income taxes |
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10,444 |
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12,448 |
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Income taxes |
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3,812 |
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4,543 |
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Net Income |
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$ |
6,632 |
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$ |
7,905 |
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Weighted average common shares outstanding |
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11,279 |
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11,158 |
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Net earnings per common share |
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Basic |
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$ |
0.59 |
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$ |
0.71 |
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Diluted |
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$ |
0.59 |
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$ |
0.71 |
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Cash dividends per share |
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$ |
0.24 |
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$ |
0.24 |
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The accompanying notes are an integral part of these financial statements
3
CASCADE NATURAL GAS CORPORATION
CONSOLIDATED CONDENSED BALANCE SHEETS
(Dollars in Thousands)
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Dec 31, 2004 |
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Sep 30, 2004 |
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(Unaudited) |
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ASSETS |
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Utility Plant, net of accumulated depreciation of $246,843 and $242,691 |
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$ |
330,552 |
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$ |
327,345 |
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Construction work in progress |
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7,196 |
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7,229 |
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337,748 |
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334,574 |
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Other Assets: |
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Investments in non-utility property |
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202 |
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202 |
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Notes receivable, less current maturities |
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46 |
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43 |
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248 |
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245 |
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Current Assets: |
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Cash and cash equivalents |
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2,447 |
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499 |
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Accounts receivable and current maturities of notes receivable, less allowance of $943 and $1,028 for doubtful accounts |
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50,764 |
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15,001 |
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Prepaid expenses and other assets |
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17,728 |
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18,674 |
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Derivative instrument assets - energy commodity |
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1,330 |
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17,983 |
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Materials, supplies and inventories |
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12,773 |
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13,268 |
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Deferred income taxes |
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982 |
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955 |
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86,024 |
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66,380 |
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Deferred Charges and Other |
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Gas cost changes |
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10,395 |
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12,288 |
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Derivative instrument assets - energy commodity |
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2,292 |
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3,952 |
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Other |
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5,316 |
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5,183 |
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18,003 |
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21,423 |
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$ |
442,023 |
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$ |
422,622 |
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4
CASCADE NATURAL GAS CORPORATION
CONSOLIDATED CONDENSED BALANCE SHEETS (Continued)
(Dollars in Thousands)
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Dec 31, 2004 |
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Sep 30, 2004 |
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(Unaudited) |
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COMMON SHAREHOLDERS EQUITY AND LIABILITIES |
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Common Shareholders Equity: |
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Common stock, par value $1 per share, authorized 15,000,000 shares, issued and outstanding 11,292,120 and 11,268,069 shares |
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$ |
11,292 |
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$ |
11,268 |
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Additional paid-in capital |
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101,834 |
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101,354 |
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Accumulated other comprehensive income (loss) |
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(12,608 |
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(12,608 |
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Retained earnings |
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22,422 |
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18,500 |
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122,940 |
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118,514 |
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Long-term Debt |
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128,900 |
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128,900 |
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Current Liabilities: |
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Notes payable and commercial paper |
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45,000 |
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33,500 |
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Current maturities of long-term debt |
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10,000 |
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14,000 |
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Accounts payable |
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34,214 |
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12,923 |
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Property, payroll and excise taxes |
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8,167 |
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5,287 |
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Dividends and interest payable |
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5,049 |
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7,125 |
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Regulatory liabilities |
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1,330 |
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17,209 |
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Other current liabilities |
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11,858 |
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8,972 |
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115,618 |
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99,016 |
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Deferred Credits and Other Non-current Liabilities |
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Deferred income taxes and investment tax credits |
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38,836 |
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38,392 |
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Retirement plan obligations |
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20,658 |
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20,780 |
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Regulatory liabilities |
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8,845 |
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10,515 |
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Other |
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6,226 |
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6,505 |
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74,565 |
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76,192 |
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Commitments and Contingencies |
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$ |
442,023 |
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$ |
422,622 |
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The accompanying notes are an integral part of these financial statements
5
CASCADE NATURAL GAS CORPORATION
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
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THREE MONTHS ENDED |
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(dollars in thousands) |
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Dec 31, 2004 |
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Dec 31, 2003 |
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Operating Activities |
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Net income |
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$ |
6,632 |
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$ |
7,905 |
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Adjustments to reconcile net income to net cash provided by operating activities: |
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Depreciation and amortization |
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4,205 |
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3,921 |
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Deferrals of gas cost changes |
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100 |
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(752 |
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Amortization of gas cost changes |
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1,794 |
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1,774 |
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Other deferrals and amortizations |
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(154 |
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321 |
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Deferred income taxes and tax credits - net |
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418 |
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1,367 |
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Change in current assets and liabilities |
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(8,571 |
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(7,488 |
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Net cash provided by operating activities |
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4,424 |
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7,048 |
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Investing Activities |
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Capital expenditures |
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(8,180 |
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(10,456 |
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Customer contributions in aid of construction |
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410 |
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240 |
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Net cash used by investing activities |
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(7,770 |
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(10,216 |
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Financing Activities |
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Proceeds from issuance of common stock |
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504 |
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842 |
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Repayment of long-term debt |
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(4,000 |
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Changes in notes payable and commercial paper, net |
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11,500 |
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(1,300 |
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Dividends paid |
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(2,710 |
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(2,687 |
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Net cash provided (used) by financing activities |
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5,294 |
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(3,145 |
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Net Increase (Decrease) in Cash and Cash Equivalents |
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1,948 |
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(6,313 |
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Cash and Cash Equivalents |
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Beginning of year |
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499 |
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7,452 |
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End of period |
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$ |
2,447 |
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$ |
1,139 |
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The accompanying notes are an integral part of these financial statements
6
CASCADE NATURAL GAS CORPORATION
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
The preceding statements were taken from the books and records of the Company and reflect all adjustments which are, in the opinion of management, necessary for a fair statement of the results for the interim periods. All adjustments were of a normal and recurring nature. Because of the highly seasonal nature of the natural gas distribution business, earnings or loss for any portion of the year are disproportionate in relation to the full year.
Reference is directed to the Notes to Consolidated Financial Statements contained in the 2004 Annual Report on Form 10-K for the fiscal year ended September 30, 2004, and comments included therein under Managements Discussion and Analysis of Financial Condition and Results of Operations.
Note 1. Earnings Per Share
The following table sets forth the calculation of earnings per share.
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Three Months Ended December 31 |
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2004 |
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2003 |
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(in thousands except per-share data) |
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Net income (loss) |
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$ |
6,632 |
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$ |
7,905 |
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Weighted average shares outstanding |
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11,279 |
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11,158 |
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Basic earnings (loss) per share |
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$ |
0.59 |
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$ |
0.71 |
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Weighted average shares outstanding |
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11,279 |
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11,158 |
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Plus: Issued on assumed exercise of stock options |
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13 |
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14 |
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Weighted average shares outstanding assuming dilution |
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11,292 |
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11,172 |
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Diluted earnings (loss) per share |
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$ |
0.59 |
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$ |
0.71 |
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7
Note 2. Retirement Plan Information
The following table sets forth the components of net periodic benefit costs recognized in the three-month periods ended December 31, 2004 and 2003.
Net Periodic Benefits Cost
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Three Months Ended |
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Dec 31, 2004 |
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Dec 31, 2003 |
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(Thousands of Dollars) |
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DEFINED BENEFIT PENSION PLANS |
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Service cost |
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$ |
197 |
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$ |
192 |
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Interest cost |
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961 |
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932 |
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Expected return on plan assets |
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(1,041 |
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(978 |
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Recognized gains or losses |
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386 |
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349 |
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Prior service cost |
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46 |
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57 |
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Net Periodic Benefit Cost Recognized |
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$ |
549 |
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$ |
552 |
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POSTRETIREMENT BENEFITS OTHER THAN PENSIONS |
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Service cost |
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$ |
35 |
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$ |
44 |
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Interest cost |
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275 |
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348 |
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Expected return on plan assets |
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(211 |
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(213 |
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Recognized gains or losses |
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187 |
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308 |
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Prior service cost |
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(330 |
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(330 |
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Net Periodic Benefit Cost Recognized |
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$ |
(44 |
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$ |
157 |
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DEFINED CONTRIBUTION PENSION PLAN |
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Net Periodic Benefit Cost Recognized |
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$ |
243 |
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$ |
242 |
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Retirement Plan Funding
For the three months ended December 31, 2004, $625,000 of contributions have been made to the Companys defined benefit pension plans. The Company presently anticipates contributing an additional $2,900,000 to fund its pension plans for a total of $3,525,000 in fiscal 2005.
The Company follows the disclosure-only provisions of FAS No. 123, Accounting for Stock-Based Compensation. Accordingly, employee stock options are accounted for under Accounting Principle Board Opinion (APB) No. 25, Accounting for Stock Issued to Employees. Stock options are granted at exercise prices not less than the fair value of common stock on the date of grant. Under APB No. 25, no compensation expense is recognized related to the Companys stock option plans. If compensation expense for the Companys stock option plans were determined consistent with SFAS No. 123, net income and earnings per common share would have been the following pro forma amounts for the three-month periods ended December 31:
8
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Three Months Ended |
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Dec 31, 2004 |
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Dec 31, 2003 |
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(in thousands except per-share data) |
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Net income |
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As reported |
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$ |
6,632 |
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$ |
7,905 |
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Less total stock-based employee compensation expense determined under the fair value method, net of tax |
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$ |
13 |
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13 |
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Pro forma net income |
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$ |
6,619 |
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$ |
7,892 |
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Earnings per share, basic and diluted |
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As reported |
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$ |
0.59 |
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$ |
0.71 |
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Pro forma |
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$ |
0.59 |
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$ |
0.71 |
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Note 4. Commitments and Contingencies
There are two claims against the Company for as yet unknown costs for cleanup of alleged environmental contamination related to manufactured gas plant sites that were previously operated by companies which were subsequently merged into Cascade.
The first claim was received in 1995 and relates to a site in Oregon. An investigation has shown that contamination does exist, but there is currently not enough information available to estimate the potential liability associated with this claim. It is expected that other parties will participate in the cleanup costs. Through the end of the quarter the amounts spent, primarily on investigation and containment, have been immaterial.
The second claim was received in 1997 and relates to a site in Washington. An investigation has determined there is evidence of contamination at the site, but there is also evidence of an oil line crossing the property, operated by an unrelated party, which may have also contributed to the contamination. There is currently not enough information available to estimate the potential liability associated with this claim. The party who originally made this claim has not been actively pursuing it.
Management intends to pursue reimbursement from its insurance carriers, and recovery from its customers through increased rates, for any remediation costs for which the Company is determined to be liable. There is precedent for such recovery through increased rates, as both the Washington Utilities and Transportation Commission (WUTC) and the Oregon Public Utilities Commission (OPUC) have previously allowed regulated utilities to increase customer rates to recover similar costs.
Various lawsuits, claims, and contingent liabilities may arise from time to time from the conduct of the Companys business. No other claims now pending, in the opinion of management, are expected to have a material effect on the Companys financial position, results of operations, or liquidity.
9
The following is managements assessment of the Companys financial condition and a discussion of the principal factors that affected consolidated results of operations and cash flows for the three-month periods ended December 31, 2004 and December 31, 2003.
OVERVIEW
The Company is a local distribution company (LDC) serving approximately 225,000 customers in the States of Washington and Oregon. Our service area consists primarily of relatively small cities and rural communities rather than larger urban areas. The Companys primary source of revenue and operating margin is the distribution of natural gas to end-use residential, commercial, industrial, and institutional customers. Revenues are also derived from providing gas management and other services to some of its large industrial and commercial customers. The Companys rates and practices are regulated by the WUTC and the OPUC.
Key elements of the Companys strategy include:
Remain focused on the natural gas distribution business.
Achieve earnings growth through and minimize the need to seek rate increases by:
Expanding our customer base
Increasing operating efficiencies
Exploit opportunities to expand our service offerings inside and outside our service territory
Opportunities and Challenges
The Company operates in a diverse service territory over a wide geographic area relative to its overall size and number of customers. The economies of various parts of the service area are supported by a variety of industries, and are affected by the conditions that impact those industries.
Management believes there are growth opportunities in the Companys service area. Factors contributing to these opportunities include low market penetration in many of the towns served, and general population growth in the service area, including some areas of rapid growth.
Rates charged by the Company for its utility services are regulated by the WUTC and the OPUC. The Companys basic business strategy is to minimize reliance on rate increases for earnings growth. However, realization of risks affecting earnings could require the Company to seek approval of higher rates. The results of such rate requests are subject to uncertainties associated with the regulatory process.
The Company earns more than one third of its operating margin from industrial and electric generation customers. Loss of major industrial customers, or unfavorable conditions affecting an industry segment, could have a detrimental impact on the Companys earnings. Many external factors over which the Company has no control can significantly impact the amount of gas consumed by industrial and electric generation customers, and consequently the margins earned by the Company.
Revenues and margins from the Companys residential and small commercial customers are highly weather sensitive. In a cold year, the Companys earnings are boosted by the effects of the weather, and conversely in a warm year, the Companys earnings suffer. The Company continues to explore alternatives such as weather normalization mechanisms that utility regulators in many jurisdictions have approved, to reduce weather related volatility in earnings and in customers bills.
10
Overall revenues and margins are also negatively impacted by customers taking measures to reduce energy usage. The increasing cost of energy in recent years, including the wholesale cost of natural gas, continues to encourage such measures.
Prospects for continuing strong residential and commercial customer growth are excellent. The pace of new home and commercial construction remains steady in our communities. Good potential also exists for converting homes and businesses located on or near our current lines to gas from other fuels, as well as for expanding our system into adjacent areas.
The Companys net income was $6,632,000, or $0.59 per share, basic and diluted, for the fiscal 2005 first quarter (quarter ended December 31, 2004), compared to $7,905,000, or $0.71 per share, basic and diluted, for the quarter ended December 31, 2003. Primary factors influencing the quarterly comparisons were:
Unfavorable non-core mark-to-market valuations in fiscal 2005 compared to favorable valuations in fiscal 2004 ($0.06) per share
Decline in margin from gas management services ($0.04) per share
Decline in residential and commercial per-customer gas consumption ($0.05) per share
Increase in margin from new residential and commercial customers - $0.06 per share
Operating margins by customer category for the first quarter of fiscal years 2005 and 2004 are set forth in the following tables:
Residential and Commercial Margin
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First Quarter of Fiscal |
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Percent |
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2005 |
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2004 |
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Change |
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(dollars in thousands) |
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|
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Degree Days |
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Actual |
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1,945 |
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2,106 |
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-7.6 |
% |
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5-Year Average |
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2,091 |
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2,044 |
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Average Number of Customers Billed |
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Residential |
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191,100 |
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182,397 |
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4.8 |
% |
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Commercial |
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29,840 |
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29,131 |
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2.4 |
% |
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Average Therm Usage per Customer |
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Residential |
|
251 |
|
272 |
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-7.7 |
% |
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Commercial |
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1,161 |
|
1,252 |
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-7.3 |
% |
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Operating Margin |
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Residential |
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$ |
14,225 |
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$ |
14,056 |
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1.2 |
% |
Commercial |
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$ |
7,461 |
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$ |
7,538 |
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-1.0 |
% |
Margin from sales to residential and commercial customers increased by $92,000 on an aggregate basis, and the net increase was influenced by two primary factors. An overall increase of 9,412 in the number of residential and commercial customers, assuming the same average consumption per customer as last year, contributed $990,000 in additional margin. The combined growth rate for residential and commercial customers was 4.4%, more than two times the national average for natural gas distribution companies. However, the decrease in average gas usage per customer largely offset the contribution from
11
new customers, resulting in the net increase of $92,000. The primary use of gas by residential customers is for space and water heating, therefore average consumption per customer is very sensitive to weather, particularly during the Companys first and second fiscal quarters. Consumption by commercial customers is also sensitive to weather. The sensitivity is more difficult to isolate and measure than for residential customers because of a variety of uses in addition to space and water heating.
Industrial and Other Margin
|
|
First Quarter of Fiscal |
|
Percent |
|
||||
|
|
2005 |
|
2004 |
|
Change |
|
||
|
|
(dollars in thousands) |
|
|
|
||||
Average Number of Customers |
|
|
|
|
|
|
|
||
Electric Generation |
|
14 |
|
14 |
|
0.0 |
% |
||
Industrial |
|
736 |
|
744 |
|
-1.1 |
% |
||
|
|
750 |
|
758 |
|
-1.1 |
% |
||
Therms Delivered (thousands) |
|
|
|
|
|
|
|
||
Electric Generation |
|
117,365 |
|
145,145 |
|
-19.1 |
% |
||
Industrial |
|
110,414 |
|
115,742 |
|
-4.6 |
% |
||
|
|
227,779 |
|
260,887 |
|
-12.7 |
% |
||
Operating Margin ($ thousands) |
|
|
|
|
|
|
|
||
Electric Generation |
|
$ |
2,007 |
|
$ |
2,241 |
|
-10.4 |
% |
Industrial |
|
5,306 |
|
5,432 |
|
-2.3 |
% |
||
Gas Management Services |
|
391 |
|
1,132 |
|
-65.5 |
% |
||
Mark-to-Market Valuations |
|
(668 |
) |
406 |
|
-264.5 |
% |
||
Other |
|
200 |
|
139 |
|
43.9 |
% |
||
|
|
$ |
7,236 |
|
$ |
9,350 |
|
-22.6 |
% |
Electric Generation: The decline in margin from electric generation customers is attributed to adequate supplies of lower cost hydroelectric power and weaker demand resulting, in part, from the high wholesale price of natural gas. Looking ahead, gas usage by generation customers will continue to depend on regional demand for power, availability of hydro resources, and the relationship between the market price of electricity and the cost of gas.
Gas Management Services: The $741,000 decline in margin from gas management services is attributed to fewer gas management customers and lower per-therm margin on gas supply sales compared to last year. The re-emergence of energy marketers, an industry segment that all but disappeared in the wake of the Enron failure, has resulted in stiff competition for gas supply sales to larger gas customers. Cascade has lost some customers to such marketers, and margins that are available for any sales are smaller than in the past. We will continue to provide gas supply services to customers to facilitate their use of gas, but expect revenues from the activity to be limited.
Mark-to-Market Valuations: These valuations result from periodic changes in the fair value of the derivative instruments used to hedge the cost of supplies for gas management customers. The hedging instruments are in place to effectively fix the price of those supplies. As market prices of natural gas forward contracts increase, the value of the instruments increases. Conversely, when market prices decrease, the value of the instruments also decreases. During the fiscal 2005 first quarter, forward natural gas prices decreased from the beginning of the quarter to the end of the quarter, hence the $668,000 charge for the quarter. During the first quarter last year, these prices increased, resulting in the $406,000 credit. These hedging instruments are for fixed periods that correspond to the periods of the physical supply contracts to serve these customers. The hedged volumes also correspond to the volumes expected to be purchased under these contracts. At the end of the life of the hedging instruments the cumulative income statement effects of the mark-to-market valuations will net to zero. But market fluctuations in interim periods do result in mark-to-market valuation effects in those periods income statements.
12
Oregon Earnings Sharing: In addition to the above described margin differences, the comparison of first quarter 2005 versus 2004 is affected by accruals of estimated liability for Oregon Earnings Sharing. In the first quarter of 2004 we accrued $250,000 as an estimate of a liability to be paid back to Oregon customers. No additional amount was accrued in the first quarter of fiscal 2005.
Cost of Operations
Compared to last year, overall Cost of Operations was $455,000 higher for the quarter. Within Cost of Operations, notable changes in Operating Expenses included a $347,000 increase in labor expense, including normal annual wage and salary increases and $151,000 in severance pay, stemming primarily from planned staffing reductions in connection with implementation of a new customer service call center in the second quarter of fiscal 2005. Included in operating expense is a $120,000 accrual for a penalty proposed by the staff of the Washington Utilities and Transportation Commission for pipeline safety audit weaknesses. Also reflected in operating expense changes for the quarter was a $480,000 reduction in employee benefits expense, reflecting the full impact of benefit plan changes initiated in 2003. Various smaller increases and decreases in other categories of expense, in the aggregate, accounted for the remainder of the change in Operating Expenses for the quarter.
The $284,000 increase in Depreciation and Amortization is related to the approximately $38 million increase in Utility Plant compared to a year ago. Included in the increased plant balance is approximately $15 million in equipment installed for our automated meter reading system.
The $222,000 reduction in Interest and Other Deductions-Net is a result of repayment of long-term debt and temporarily replacing that debt with lower cost short-term borrowing under our bank line of credit.
LIQUIDITY AND CAPITAL RESOURCES
The seasonal nature of the Companys business creates short-term cash requirements to finance customer accounts receivable and construction expenditures. To provide working capital for these requirements, the Company has a $60,000,000 bank revolving credit commitment. This agreement has a variable commitment fee, and a term that expires in October 2007. As of December 31, 2004, there was $45,000,000 outstanding debt under this credit line.
To provide longer-term financing the Company filed an omnibus registration statement in 2001, under the Securities Act of 1933, which provided the ability to issue up to $150,000,000 of new debt and equity securities. Of that amount, the Company had $110,000,000 remaining available for issuance, as of December 31, 2004, subject to market conditions and other factors. On January 25, 2005, the Company issued $30,000,000 of 30-year 5.25% Insured Quarterly Notes under this registration statement, leaving $80,000,000 available for future issuance of securities. The proceeds were used to pay down the debt under the revolving credit line. In the remainder of fiscal 2005, the Company will repay $10,000,000 in current maturities of long-term debt, beginning with $5,000,000 in January. The Company expects to fund these repayments primarily through use of its bank credit lines, cash from operating activities, and long-term capital sources.
Because of the availability of short-term credit and the ability to issue long-term debt and additional equity, management believes it has adequate financial flexibility to meet its anticipated cash needs, including cash requirements for investing and financing activities described in the following paragraphs.
Cash provided by operating activities for the first quarter of fiscal 2005 declined $2,624,000 compared to last year. Other than net lower income, a significant contributing factor was higher current income tax. As a component of net income, this higher current income tax expense is offset by lower deferred income tax expense. Deferred income taxes represent a non-cash charge to expense, and effectively
13
offset lower cash payments for income taxes in the current period. Current Income Taxes were lower last year primarily from the effect of a temporary provision in the federal tax code that allowed a first-year bonus depreciation deduction in the amount of 50% of the cost of new assets placed in service. This provision expires in fiscal 2005. For the full year of fiscal 2004, current income taxes were lower by approximately $7 million resulting from first-year bonus depreciation..
Investing Activities
Net capital expenditures of $7,770,000 for the first quarter of fiscal 2005 were approximately 24% less than first quarter last year. The decrease is primarily attributable to approximately $2.9 million expended last year on the installation of electronic devices on all the Companys customer meters to allow for automated meter reading (AMR). The AMR project was completed in 2004.
Other than the payment of dividends, the Companys primary financing activities during the first quarter of fiscal 2005 were the repayment of $4,000,000 in long-term debt and increasing its borrowing under its bank credit line by $11,500,000.
In January 2005 the Company began operation of a customer-service call center at our existing district office in Bellingham, Washington. This call center will consolidate in one location the customer service function, which has been spread through fifteen local offices. The new call center is expected to reduce expenses through the elimination of sixteen full time equivalent positions, and to allow for more specialization, increased efficiency, and improved service quality. Activation of the call center is being phased in, and we plan for the center to be fully operational in March 2005.
The Companys financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). In following GAAP, management exercises judgment in selection and application of accounting principles. Management considers Critical Accounting Policies to be those where different assumptions regarding application could result in material differences in financial statements.
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The Company has used estimates in measuring certain deferred charges and deferred credits related to items subject to approval of the WUTC and the OPUC. Estimates are also used in the development of discount rates and trend rates related to the measurement of retirement benefit obligations and accrual amounts, allowances for doubtful accounts, unbilled revenue, valuation of derivative instruments, and in the determination of depreciable lives of utility plant. On an ongoing basis, management evaluates the estimates used, based on historical experience, current conditions and on various other assumptions believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions.
14
The Companys accounting policies and practices are generally the same as used by unregulated companies for financial reporting under GAAP. However, Statement of Financial Accounting Standards (FAS) No. 71, Accounting for the Effects of Certain Types of Regulation, requires regulated companies to apply accounting treatment intended to reflect the financial impact of regulation. For example, in establishing the rates to be charged to the Companys retail customers, the WUTC and the OPUC may not allow the Company to charge its customers for recovery of certain expenses in the same period they are incurred. Instead, rates are expected to be established to recover costs that were incurred in a prior period. In this situation, following FAS No. 71 requires the Company to defer these costs and include them as regulatory assets on the balance sheet. In the subsequent period when these costs are recovered from customers, the Company then amortizes these costs as expense in the income statement, in an amount equivalent to the amounts recovered. Similarly, certain revenue items, or cost reductions may be deferred as regulatory liabilities, which are later amortized to the income statement as customer rates are reduced. In order to apply the provisions of FAS No. 71, the following conditions must apply:
An independent regulator approves the companys customer rates.
The rates are designed to recover the companys costs of providing the regulated services or products.
There is sufficient demand for the regulated service to reasonably assure that rates can be set at a level to recover the costs.
The Company periodically assesses whether conditions merit the continued applicability of FAS No. 71. In the event the Company should determine in the future that all or a portion of its regulatory assets and liabilities no longer meet the above criteria, it would be required to write off the related balances of its regulatory assets and liabilities, and reflect the write off in its income statement.
The Company has a defined benefit pension plan covering substantially all employees over 21 years of age with one year of service. The Company also provides executive officers with supplemental retirement, death and disability benefits. These plans were amended in fiscal 2003, so that subsequent to September 30, 2003, benefits under these plans no longer accrue to non-bargaining-unit employees and officers. The pension plan remains substantially unchanged for bargaining-unit employees at this time.
The Companys pension costs for these plans are affected by the amount of cash contributions to the plans, the return on plan assets, and by employee demographics, including age, compensation, and length of service. Actuarial formulas are used in the determination of pension costs and are affected by actual plan experience and assumptions of future experience. Key actuarial assumptions include the expected return on plan assets, the discount rate used in determining the projected benefit obligation and pension costs, and the assumed rate of increase in employee compensation. Changes in these assumptions may significantly affect pension costs. Changes to the provisions of the plans may also impact current and future pension costs. Changes in pension plan obligations resulting from these factors may not be immediately recognized as pension costs, but generally are recognized in future years over the remaining average service period of pension plan participants.
The Companys funding policy is to contribute amounts equal to or greater than the minimum amounts required to be funded under the Employee Retirement Income Security Act, and not more than the maximum amounts currently deductible for income tax purposes. The Company contributed $3,843,000 in 2004 to the pension and supplemental executive retirement plans, and expects to contribute $3,525,000 in 2005.
15
The discount rate the Company selects is based on the average of the 20 year and above Aa debt rates published by Moodys. These are rates considered to be consistent with the expected term of pension benefits. At September 30, 2004, the Company used a discount rate of 6.00%. This same rate is used in the development of pension expense for fiscal 2005. A reduction in the discount rate results in increases in projected benefit obligation, pension liability, and pension costs.
In selecting an assumed long-term rate of return on plan assets, the Company considers past performance and economic forecasts for the types of investments held by the plan. In 2004 and 2005 the Companys assumed rate of return on plan assets is 8.25%. A reduction in the assumed rate of return would result in increases in pension liability and pension costs.
The Company accounts for derivative transactions according to the provisions of FAS No. 133, as amended by FAS No. 138 and by FAS No. 149. These standards require that the fair value of all derivative financial instruments be recognized as either assets or liabilities on the Companys balance sheet and the recognition of unrealized gains and losses.
Most of the Companys contracts for purchase and sale of natural gas qualify for the normal purchase and normal sales exception under FAS No. 133 and are not required to be recorded as derivative assets and liabilities. Accordingly, the Company recognizes revenues and expenses on an accrual basis, based on physical delivery of natural gas. The Company applies mark-to-market accounting to financial derivative contracts. Periodic changes in fair market value of derivatives associated with supplies for non-core customers are recognized in earnings. The differences in accounting for purchases and sales contracts versus financial contracts do not change the underlying economics of the transactions, but could result in increased quarterly earnings volatility. The Company applies FAS No. 71 to periodic changes in fair market value of derivatives associated with supplies for core customers and records an offset in regulatory asset and regulatory liability accounts.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Cascade has evaluated its risk related to financial instruments whose values are subject to market sensitivity. The Company has fixed-rate debt obligations, but does not have derivative financial instruments subject to interest rate risk. Cascade makes interest and principal payments on these obligations in the normal course of its business, and does not plan to redeem these obligations prior to normal maturities.
The Companys natural gas purchase commodity prices are subject to fluctuations resulting from weather, congestion on interstate pipelines, and other unpredictable factors. The Companys Purchased Gas Cost Adjustment (PGA) mechanisms assure the recovery in customer rates of prudently incurred wholesale cost of gas purchased for the core market. The Company utilizes fixed price contracts and financial derivatives to manage risk associated with wholesale costs of gas purchased for customers.
With respect to derivative arrangements covering gas supplies for core customers, periodic changes in fair market value are recorded in regulatory asset or regulatory liability accounts, pursuant to authority granted by the WUTC and OPUC recognizing that settlements of these arrangements will be recovered through the PGA mechanism.
For derivative arrangements related to supplies for non-core customers, which are not covered by a PGA mechanism, periodic changes in fair market value are recognized in earnings.
Item 4. Controls and Procedures
The Company maintains controls and procedures designed to provide reasonable assurance that required disclosure information in the reports the Company files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time period specified
16
in the rules and forms of the Securities and Exchange Commission. Based upon their evaluation of those controls and procedures as of the end of the quarter covered by this report, the Chief Executive Officer and Chief Financial Officer of the Company concluded that the Companys disclosure controls and procedures were effective.
In response to the changes in the filing requirements for Current Reports on Form 8-K effective August 23, 2004, the Company implemented additional controls and procedures designed to provide reasonable assurance that required disclosures under such new requirements will be made in a timely manner. During the period covered by this report, we identified two material contracts for which we determined reports on Form 8-K had not been filed within the required four business days. The Company has since filed the required reports, and has adopted additional procedures to correct these deficiencies. We did not make any other changes in our internal control over financial reporting during the quarter ended December 31, 2004 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Statements contained in this report that are not historical in nature are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are subject to risks and uncertainties that may cause actual future results to differ materially. Such risks and uncertainties with respect to the Company include, among others, its ability to successfully implement internal performance goals, competition from alternative forms of energy and other sellers of energy, consolidation in the energy industry, performance issues with key natural gas suppliers, the capital-intensive nature of the Companys business, regulatory issues, including the need for adequate and timely rate relief to recover capital and operating costs and to sustain dividend levels, the weather, increasing competition brought on by deregulation initiatives at the federal and state regulatory levels, the potential loss of large volume industrial customers due to bypass or the shift by such customers to special competitive contracts at lower per unit margins, exposure to environmental cleanup requirements, and economic conditions, particularly in the Companys service area.
a)
b) There have been no changes in the Companys procedures by which security holders may recommend nominees to the Companys Board of Directors.
No. |
|
Description |
|
|
|
10.1 |
|
Agreement and General Release between the Registrant and J.D. Wessling, Chief Financial Officer |
|
|
|
12 |
|
Computation of Ratio of Earnings to Fixed Charges |
|
|
|
31 |
|
Certification Accompanying Periodic Report Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
|
|
|
32 |
|
Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
17
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.
CASCADE NATURAL GAS CORPORATION |
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
By: |
/s/ J. D. Wessling |
. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
J. D. Wessling |
|
|
|
|
|
Chief Financial Officer |
|
|
|
|
|
(Principal Financial Officer) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Date: |
February 7, 2005 |
. |
|
|
|
18