SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
| x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2005
March 31, 2006
OR
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Transition period from to
Commission File No. 1-15973
NORTHWEST NATURAL GAS COMPANY
(Exact name of registrant as specified in its charter)
| Oregon | 93-0256722 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
220 N.W. Second Avenue, Portland, Oregon 97209
(Address of principal executive offices) (Zip Code)
Registrant’s Telephone Number, including area code: (503) 226-4211
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 x No ¨
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.
Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨
Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes x No ¨
Indicate by check mark whether the Registrantregistrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
At October 31, 2005, 27,549,733April 28, 2006, 27,576,846 shares of the registrant’s Common Stock, $3-1/6 par value (the only class of Common Stock) were outstanding.
For the Quarterly Period Ended September 30, 2005March 31, 2006
PART I. FINANCIAL INFORMATION
Page
| ||||
Item 1. | Consolidated Financial Statements | |||
| Consolidated Statements of Income for the three-month | 3 | |||
| Consolidated Balance Sheets at | 4 | |||
| Consolidated Statements of Cash Flows for the | 6 | |||
| Consolidated Statements of Capitalization at | 7 | |||
| Notes to Consolidated Financial Statements | 8 | |||
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |||
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | |||
Item 4. | Controls and Procedures | |||
| PART II. OTHER INFORMATION | ||||
Item 1. | Legal Proceedings | |||
Item 1A. | Risk Factors | 38 | ||
| Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | |||
Item 6. | Exhibits | |||
| Signature | ||||
PART I. FINANCIAL INFORMATION
Consolidated Statements of Income
(Unaudited)
| Three Months Ended Sept. 30, | Nine Months Ended Sept. 30, | |||||||||||||
Thousands, except per share amounts | 2005 | 2004 | 2005 | 2004 | ||||||||||
Operating revenues: | ||||||||||||||
Gross operating revenues | $ | 106,667 | $ | 81,441 | $ | 569,111 | $ | 445,550 | ||||||
Cost of sales | 62,231 | 41,958 | 335,264 | 241,404 | ||||||||||
Net operating revenues | 44,436 | 39,483 | 233,847 | 204,146 | ||||||||||
Operating expenses: | ||||||||||||||
Operations and maintenance | 25,988 | 24,507 | 80,164 | 74,324 | ||||||||||
Taxes other than income taxes | 8,411 | 7,268 | 31,167 | 27,252 | ||||||||||
Depreciation and amortization | 15,452 | 14,212 | 45,959 | 42,031 | ||||||||||
Total operating expenses | 49,851 | 45,987 | 157,290 | 143,607 | ||||||||||
Income (loss) from operations | (5,415 | ) | (6,504 | ) | 76,557 | 60,539 | ||||||||
Other income and expense - net | 550 | 1,644 | 1,020 | 2,109 | ||||||||||
Interest charges - net of amounts capitalized | 9,253 | 8,774 | 27,287 | 26,482 | ||||||||||
Income (loss) before income taxes | (14,118 | ) | (13,634 | ) | 50,290 | 36,166 | ||||||||
Income tax expense (benefit) | (5,447 | ) | (5,349 | ) | 17,934 | 12,555 | ||||||||
Net income (loss) | $ | (8,671 | ) | $ | (8,285 | ) | $ | 32,356 | $ | 23,611 | ||||
Average common shares outstanding: | ||||||||||||||
Basic | 27,560 | 27,373 | 27,564 | 26,868 | ||||||||||
Diluted | 27,630 | 27,688 | 27,626 | 27,187 | ||||||||||
Earnings (loss) per share of common stock: | ||||||||||||||
Basic | $ | (0.31 | ) | $ | (0.30 | ) | $ | 1.17 | $ | 0.88 | ||||
Diluted | $ | (0.31 | ) | $ | (0.30 | ) | $ | 1.17 | $ | 0.88 | ||||
| Three Months Ended March 31, | ||||||
Thousands, except per share amounts | 2006 | 2005 | ||||
Operating revenues: | ||||||
Gross operating revenues | $ | 390,391 | $ | 308,777 | ||
Less: Cost of sales | 255,399 | 180,608 | ||||
Revenue taxes | 9,528 | 7,183 | ||||
Net operating revenues | 125,464 | 120,986 | ||||
Operating expenses: | ||||||
Operations and maintenance | 28,247 | 27,195 | ||||
General taxes | 7,573 | 6,770 | ||||
Depreciation and amortization | 15,830 | 15,195 | ||||
Total operating expenses | 51,650 | 49,160 | ||||
Income from operations | 73,814 | 71,826 | ||||
Other income and expense - net | 518 | 65 | ||||
Interest charges - net of amounts capitalized | 9,855 | 9,128 | ||||
Income before income taxes | 64,477 | 62,763 | ||||
Income tax expense | 23,444 | 22,876 | ||||
Net income | $ | 41,033 | $ | 39,887 | ||
Average common shares outstanding: | ||||||
Basic | 27,584 | 27,578 | ||||
Diluted | 27,632 | 27,863 | ||||
Earnings per share of common stock: | ||||||
Basic | $ | 1.49 | $ | 1.45 | ||
Diluted | $ | 1.48 | $ | 1.43 | ||
See Notes to Consolidated Financial Statements
PART I. FINANCIAL INFORMATION
Consolidated Balance Sheets
Thousands | Sept. 30, 2005 | Sept. 30, 2004 | Dec. 31, 2004 | |||||||||
Assets: | ||||||||||||
Plant and property: | ||||||||||||
Utility plant | $ | 1,857,053 | $ | 1,765,461 | $ | 1,794,972 | ||||||
Less accumulated depreciation | 532,667 | 498,286 | 505,286 | |||||||||
Utility plant - net | 1,324,386 | 1,267,175 | 1,289,686 | |||||||||
Non-utility property | 39,450 | 27,151 | 33,963 | |||||||||
Less accumulated depreciation and amortization | 5,755 | 5,118 | 5,244 | |||||||||
Non-utility property - net | 33,695 | 22,033 | 28,719 | |||||||||
Total plant and property | 1,358,081 | 1,289,208 | 1,318,405 | |||||||||
Other investments | 57,939 | 76,368 | 60,618 | |||||||||
Current assets: | ||||||||||||
Cash and cash equivalents | 3,408 | 4,064 | 5,248 | |||||||||
Accounts receivable | 30,518 | 31,807 | 63,109 | |||||||||
Allowance for uncollectible accounts | (1,553 | ) | (1,189 | ) | (2,434 | ) | ||||||
Accrued unbilled revenue | 16,787 | 13,958 | 64,401 | |||||||||
Gas inventories | 90,961 | 62,131 | 58,015 | |||||||||
Materials and supplies inventories | 7,855 | 7,804 | 8,462 | |||||||||
Income tax receivable | 21,145 | 8,812 | 15,970 | |||||||||
Prepayments and other current assets | 36,106 | 13,956 | 24,346 | |||||||||
Total current assets | 205,227 | 141,343 | 237,117 | |||||||||
Regulatory assets: | ||||||||||||
Income tax asset | 65,622 | 64,475 | 64,734 | |||||||||
Deferred environmental costs | 17,456 | 3,441 | 6,325 | |||||||||
Deferred gas costs receivable | 5,414 | 9,130 | 9,551 | |||||||||
Unamortized costs on debt redemptions | 6,987 | 7,450 | 7,332 | |||||||||
Other | 4,182 | 3,999 | 3,321 | |||||||||
Total regulatory assets | 99,661 | 88,495 | 91,263 | |||||||||
Other assets: | ||||||||||||
Fair value of non-trading derivatives | 346,158 | 70,079 | 16,399 | |||||||||
Other | 8,748 | 9,160 | 8,393 | |||||||||
Total other assets | 354,906 | 79,239 | 24,792 | |||||||||
Total assets | $ | 2,075,814 | $ | 1,674,653 | $ | 1,732,195 | ||||||
Thousands | March 31, 2006 (Unaudited) | March 31, 2005 (Unaudited) | Dec. 31, 2005 | |||||||||
Assets: | ||||||||||||
Plant and property: | ||||||||||||
Utility plant | $ | 1,890,633 | $ | 1,814,991 | $ | 1,875,444 | ||||||
Less accumulated depreciation | 547,635 | 514,785 | 536,867 | |||||||||
Utility plant - net | 1,342,998 | 1,300,206 | 1,338,577 | |||||||||
Non-utility property | 40,953 | 34,157 | 40,836 | |||||||||
Less accumulated depreciation and amortization | 6,221 | 5,408 | 5,990 | |||||||||
Non-utility property - net | 34,732 | 28,749 | 34,846 | |||||||||
Total plant and property | 1,377,730 | 1,328,955 | 1,373,423 | |||||||||
Other investments | 54,432 | 57,198 | 58,451 | |||||||||
Current assets: | ||||||||||||
Cash and cash equivalents | 7,522 | 2,740 | 7,143 | |||||||||
Accounts receivable | 97,859 | 73,776 | 84,418 | |||||||||
Accrued unbilled revenue | 47,764 | 38,880 | 81,512 | |||||||||
Allowance for uncollectible accounts | (4,526 | ) | (3,499 | ) | (3,067 | ) | ||||||
Gas inventory | 35,906 | 23,139 | 77,256 | |||||||||
Materials and supplies inventory | 9,808 | 8,262 | 8,905 | |||||||||
Income taxes receivable | — | — | 13,234 | |||||||||
Prepayments and other current assets | 57,330 | 21,429 | 54,309 | |||||||||
Total current assets | 251,663 | 164,727 | 323,710 | |||||||||
Regulatory assets: | ||||||||||||
Income tax asset | 66,757 | 65,622 | 65,843 | |||||||||
Deferred environmental costs | 19,196 | 7,231 | 18,880 | |||||||||
Deferred gas costs receivable | 13,522 | 12,978 | 6,974 | |||||||||
Unamortized costs on debt redemptions | 6,776 | 7,215 | 6,881 | |||||||||
Other | — | 6,732 | — | |||||||||
Total regulatory assets | 106,251 | 99,778 | 98,578 | |||||||||
Other assets: | ||||||||||||
Fair value of non-trading derivatives | 40,879 | 88,634 | 178,653 | |||||||||
Other | 9,102 | 7,305 | 9,216 | |||||||||
Total other assets | 49,981 | 95,939 | 187,869 | |||||||||
Total assets | $ | 1,840,057 | $ | 1,746,597 | $ | 2,042,031 | ||||||
See Notes to Consolidated Financial Statements
NORTHWEST NATURAL GAS COMPANY
PART I. FINANCIAL INFORMATION
Consolidated Balance Sheets
Thousands | Sept. 30, 2005 (Unaudited) | Sept. 30, 2004 (Unaudited) | Dec. 31, 2004 | |||||||||
Capitalization and liabilities: | ||||||||||||
Capitalization: | ||||||||||||
Common stock | $ | 87,230 | $ | 86,816 | $ | 87,231 | ||||||
Premium on common stock | 296,376 | 297,625 | 300,034 | |||||||||
Earnings invested in the business | 189,417 | 165,893 | 183,932 | |||||||||
Unearned stock compensation | (703 | ) | (994 | ) | (862 | ) | ||||||
Accumulated other comprehensive income (loss) | (1,818 | ) | (1,016 | ) | (1,818 | ) | ||||||
Total common stock equity | 570,502 | 548,324 | 568,517 | |||||||||
Long-term debt | 521,500 | 484,906 | 484,027 | |||||||||
Total capitalization | 1,092,002 | 1,033,230 | 1,052,544 | |||||||||
Current liabilities: | ||||||||||||
Notes payable | 72,500 | 82,700 | 102,500 | |||||||||
Long-term debt due within one year | 8,000 | 15,000 | 15,000 | |||||||||
Accounts payable | 81,711 | 60,844 | 102,478 | |||||||||
Taxes accrued | 10,867 | 8,706 | 10,242 | |||||||||
Interest accrued | 11,493 | 11,166 | 2,897 | |||||||||
Other current and accrued liabilities | 33,928 | 30,565 | 34,168 | |||||||||
Total current liabilities | 218,499 | 208,981 | 267,285 | |||||||||
Regulatory liabilities: | ||||||||||||
Accrued asset removal costs | 165,917 | 146,176 | 153,258 | |||||||||
Customer advances | 1,733 | 1,463 | 1,529 | |||||||||
Unrealized gain on non-trading derivatives - net | 338,667 | 70,079 | 10,912 | |||||||||
Total regulatory liabilities | 506,317 | 217,718 | 165,699 | |||||||||
Other liabilities: | ||||||||||||
Deferred income taxes | 213,126 | 187,352 | 211,080 | |||||||||
Deferred investment tax credits | 5,415 | 6,501 | 5,660 | |||||||||
Fair value of non-trading derivatives | 7,491 | — | 5,487 | |||||||||
Other | 32,964 | 20,871 | 24,440 | |||||||||
Total other liabilities | 258,996 | 214,724 | 246,667 | |||||||||
Commitments and contingencies (see Note 7) | — | — | — | |||||||||
Total capitalization and liabilities | $ | 2,075,814 | $ | 1,674,653 | $ | 1,732,195 | ||||||
Thousands | March 31, 2006 (Unaudited) | March 31, 2005 (Unaudited) | Dec. 31, 2005 | |||||||||
Capitalization and liabilities: | ||||||||||||
Capitalization: | ||||||||||||
Common stock | $ | 87,335 | $ | 87,244 | $ | 87,334 | ||||||
Premium on common stock | 296,281 | 299,900 | 296,471 | |||||||||
Earnings invested in the business | 237,205 | 214,864 | 205,687 | |||||||||
Unearned stock compensation | — | (809 | ) | (650 | ) | |||||||
Accumulated other comprehensive income (loss) | (1,911 | ) | (1,818 | ) | (1,911 | ) | ||||||
Total common stock equity | 618,910 | 599,381 | 586,931 | |||||||||
Long-term debt | 501,500 | 483,875 | 521,500 | |||||||||
Total capitalization | 1,120,410 | 1,083,256 | 1,108,431 | |||||||||
Current liabilities: | ||||||||||||
Notes payable | 50,400 | 10,500 | 126,700 | |||||||||
Long-term debt due within one year | 28,000 | 15,000 | 8,000 | |||||||||
Accounts payable | 91,185 | 84,693 | 135,287 | |||||||||
Taxes accrued | 25,876 | 22,074 | 12,725 | |||||||||
Interest accrued | 11,623 | 11,171 | 2,918 | |||||||||
Other current and accrued liabilities | 38,703 | 34,320 | 40,935 | |||||||||
Total current liabilities | 245,787 | 177,758 | 326,565 | |||||||||
Regulatory liabilities: | ||||||||||||
Accrued asset removal costs | 173,936 | 157,975 | 169,927 | |||||||||
Unrealized gain on non-trading derivatives, net | 23,937 | 78,205 | 171,777 | |||||||||
Customer advances | 1,924 | 1,592 | 1,847 | |||||||||
Other | 4,283 | — | 661 | |||||||||
Total regulatory liabilities | 204,080 | 237,772 | 344,212 | |||||||||
Other liabilities: | ||||||||||||
Deferred income taxes | 220,568 | 206,651 | 222,331 | |||||||||
Deferred investment tax credits | 4,479 | 5,155 | 5,069 | |||||||||
Fair value of non-trading derivatives | 17,586 | 10,429 | 6,876 | |||||||||
Other | 27,147 | 25,576 | 28,547 | |||||||||
Total other liabilities | 269,780 | 247,811 | 262,823 | |||||||||
Commitments and contingencies (see Note 7) | — | — | — | |||||||||
Total capitalization and liabilities | $ | 1,840,057 | $ | 1,746,597 | $ | 2,042,031 | ||||||
See Notes to Consolidated Financial Statements
PART I. FINANCIAL INFORMATION
Consolidated Statements of Cash Flows
(Unaudited)
Nine Months Ended Sept. 30, | ||||||||
Thousands | 2005 | 2004 | ||||||
Operating activities: | ||||||||
Net income | $ | 32,356 | $ | 23,611 | ||||
Adjustments to reconcile net income to cash provided by operations: | ||||||||
Depreciation and amortization | 45,959 | 42,031 | ||||||
Deferred income taxes and investment tax credits | 1,801 | 15,111 | ||||||
Undistributed earnings from equity investments | (139 | ) | (849 | ) | ||||
Allowance for funds used during construction | (351 | ) | (1,340 | ) | ||||
Deferred gas costs - net | 4,137 | (14,757 | ) | |||||
Qualified pension plan expense | 3,576 | 3,464 | ||||||
Qualified pension plan contributions | (20,000 | ) | (2,919 | ) | ||||
Deferred environmental costs | (2,128 | ) | (1,499 | ) | ||||
Gain on sale of non-utility investments | (12 | ) | — | |||||
Income from investment in life insurance | (1,410 | ) | (1,974 | ) | ||||
Other | (1,876 | ) | 2,279 | |||||
Changes in working capital: | ||||||||
Accounts receivable - net of allowance for uncollectible accounts | 31,710 | 17,881 | ||||||
Accrued unbilled revenue | 47,614 | 45,151 | ||||||
Inventories of gas, materials and supplies | (32,339 | ) | (19,076 | ) | ||||
Income tax receivable | (5,175 | ) | 174 | |||||
Prepayments and other current assets | 2,730 | 7,044 | ||||||
Accounts payable | (20,767 | ) | (25,185 | ) | ||||
Accrued interest and other taxes | 9,221 | 8,269 | ||||||
Other current and accrued liabilities | (240 | ) | (1,024 | ) | ||||
Cash provided by operating activities | 94,667 | 96,392 | ||||||
Investing activities: | ||||||||
Acquisition and construction of utility plant assets | (65,226 | ) | (110,232 | ) | ||||
Investment in non-utility property | (5,465 | ) | (3,756 | ) | ||||
Proceeds from sale of non-utility investments | 3,001 | — | ||||||
Proceeds from life insurance | 296 | 1,343 | ||||||
Other investments | 944 | (138 | ) | |||||
Cash used in investing activities | (66,450 | ) | (112,783 | ) | ||||
Financing activities: | ||||||||
Common stock issued, net of expenses | 6,169 | 44,601 | ||||||
Common stock purchased | (13,827 | ) | (159 | ) | ||||
Long-term debt issued | 50,000 | — | ||||||
Long-term debt redeemed | (15,528 | ) | — | |||||
Change in short-term debt | (30,000 | ) | (2,500 | ) | ||||
Dividend payments on common stock | (26,871 | ) | (26,193 | ) | ||||
Cash (used in) provided by financing activities | (30,057 | ) | 15,749 | |||||
Decrease in cash and cash equivalents | (1,840 | ) | (642 | ) | ||||
Cash and cash equivalents - beginning of period | 5,248 | 4,706 | ||||||
Cash and cash equivalents - end of period | $ | 3,408 | $ | 4,064 | ||||
Supplemental disclosure of cash flow information: | ||||||||
Cash paid during the period for: | ||||||||
Interest | $ | 18,414 | $ | 18,538 | ||||
Income taxes | $ | 21,939 | $ | 2,500 | ||||
Supplemental disclosure of non-cash financing activities: | ||||||||
Conversions to common stock: | ||||||||
7-1/4 % Series of Convertible Debentures | $ | 3,999 | $ | 413 | ||||
Three Months Ended March 31, | ||||||||
Thousands | 2006 | 2005 | ||||||
Operating activities: | ||||||||
Net income | $ | 41,033 | $ | 39,887 | ||||
Adjustments to reconcile net income to cash provided by operations: | ||||||||
Depreciation and amortization | 15,830 | 15,195 | ||||||
Deferred income taxes and investment tax credits | (3,267 | ) | (5,822 | ) | ||||
Undistributed earnings from equity investments | 50 | 137 | ||||||
Allowance for funds used during construction | (133 | ) | (86 | ) | ||||
Deferred gas costs - net | (6,548 | ) | (3,427 | ) | ||||
Contributions to qualified defined benefit pension plans | — | — | ||||||
Non-cash expenses related to qualified defined benefit pension plans | 1,441 | 1,159 | ||||||
Deferred environmental costs | (2,014 | ) | (230 | ) | ||||
Income from life insurance investments | (1,383 | ) | (452 | ) | ||||
Other | 4,673 | (1,790 | ) | |||||
Changes in working capital: | ||||||||
Accounts receivable - net | (11,982 | ) | (12,077 | ) | ||||
Accrued unbilled revenue - net | 33,748 | 25,521 | ||||||
Inventories of gas, materials and supplies | 40,447 | 35,076 | ||||||
Income taxes receivable | 13,234 | 15,970 | ||||||
Prepayments and other current assets | (2,249 | ) | 3,644 | |||||
Accounts payable | (44,102 | ) | (17,785 | ) | ||||
Accrued interest and taxes | 21,856 | 20,106 | ||||||
Other current and accrued liabilities | (2,231 | ) | 152 | |||||
Cash provided by operating activities | 98,403 | 115,178 | ||||||
Investing activities: | ||||||||
Investment in utility plant | (15,002 | ) | (19,958 | ) | ||||
Investment in non-utility property | (106 | ) | (194 | ) | ||||
Proceeds from sale of non-utility investments | — | 3,001 | ||||||
Proceeds from life insurance | 964 | — | ||||||
Other | 1,475 | 746 | ||||||
Cash used in investing activities | (12,669 | ) | (16,405 | ) | ||||
Financing activities: | ||||||||
Common stock issued, net of expenses | 859 | 2,569 | ||||||
Common stock purchased | (398 | ) | (2,895 | ) | ||||
Change in short-term debt | (76,300 | ) | (92,000 | ) | ||||
Cash dividend payments on common stock | (9,516 | ) | (8,955 | ) | ||||
Cash used in financing activities | (85,355 | ) | (101,281 | ) | ||||
Increase (decrease) in cash and cash equivalents | 379 | (2,508 | ) | |||||
Cash and cash equivalents - beginning of period | 7,143 | 5,248 | ||||||
Cash and cash equivalents - end of period | $ | 7,522 | $ | 2,740 | ||||
Supplemental disclosure of cash flow information: | ||||||||
Interest paid | $ | 970 | $ | 970 | ||||
Income taxes paid | $ | — | $ | — | ||||
Supplemental disclosure of non-cash financing activities: | ||||||||
Conversions to common stock: | ||||||||
7-1/4% Series of Convertible Debentures | $ | — | $ | 152 | ||||
See Notes to Consolidated Financial Statements
PART I. FINANCIAL INFORMATION
Consolidated Statements of Capitalization
| Sept. 30, 2005 (Unaudited) | Sept. 30, 2004 (Unaudited) | Dec. 31, 2004 | |||||||||||||||||||
Common stock equity: | |||||||||||||||||||||
Common stock | $ | 87,230 | $ | 86,816 | $ | 87,231 | |||||||||||||||
Premium on common stock | 296,376 | 297,625 | 300,034 | ||||||||||||||||||
Earnings invested in the business | 189,417 | 165,893 | 183,932 | ||||||||||||||||||
Unearned compensation | (703 | ) | (994 | ) | (862 | ) | |||||||||||||||
Accumulated other comprehensive income (loss) | (1,818 | ) | (1,016 | ) | (1,818 | ) | |||||||||||||||
Total common stock equity | 570,502 | 52 | % | 548,324 | 53 | % | 568,517 | 54 | % | ||||||||||||
Long-term debt: | |||||||||||||||||||||
Medium-Term Notes | |||||||||||||||||||||
First Mortgage Bonds: | |||||||||||||||||||||
6.340% Series B due 2005 | — | 5,000 | 5,000 | ||||||||||||||||||
6.380% Series B due 2005 | — | 5,000 | 5,000 | ||||||||||||||||||
6.450% Series B due 2005 | — | 5,000 | 5,000 | ||||||||||||||||||
6.050% Series B due 2006 | 8,000 | 8,000 | 8,000 | ||||||||||||||||||
6.310% Series B due 2007 | 20,000 | 20,000 | 20,000 | ||||||||||||||||||
6.800% Series B due 2007 | 9,500 | 9,500 | 9,500 | ||||||||||||||||||
6.500% Series B due 2008 | 5,000 | 5,000 | 5,000 | ||||||||||||||||||
4.110% Series B due 2010 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||
7.450% Series B due 2010 | 25,000 | 25,000 | 25,000 | ||||||||||||||||||
6.665% Series B due 2011 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||
7.130% Series B due 2012 | 40,000 | 40,000 | 40,000 | ||||||||||||||||||
8.260% Series B due 2014 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||
4.700% Series B due 2015 | 40,000 | — | — | ||||||||||||||||||
7.000% Series B due 2017 | 40,000 | 40,000 | 40,000 | ||||||||||||||||||
6.600% Series B due 2018 | 22,000 | 22,000 | 22,000 | ||||||||||||||||||
8.310% Series B due 2019 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||
7.630% Series B due 2019 | 20,000 | 20,000 | 20,000 | ||||||||||||||||||
9.050% Series A due 2021 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||
5.620% Series B due 2023 | 40,000 | 40,000 | 40,000 | ||||||||||||||||||
7.720% Series B due 2025 | 20,000 | 20,000 | 20,000 | ||||||||||||||||||
6.520% Series B due 2025 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||
7.050% Series B due 2026 | 20,000 | 20,000 | 20,000 | ||||||||||||||||||
7.000% Series B due 2027 | 20,000 | 20,000 | 20,000 | ||||||||||||||||||
6.650% Series B due 2027 | 20,000 | 20,000 | 20,000 | ||||||||||||||||||
6.650% Series B due 2028 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||
7.740% Series B due 2030 | 20,000 | 20,000 | 20,000 | ||||||||||||||||||
7.850% Series B due 2030 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||
5.820% Series B due 2032 | 30,000 | 30,000 | 30,000 | ||||||||||||||||||
5.660% Series B due 2033 | 40,000 | 40,000 | 40,000 | ||||||||||||||||||
5.250% Series B due 2035 | 10,000 | — | — | ||||||||||||||||||
Convertible Debentures | |||||||||||||||||||||
7-1/4% Series due 2012 | — | 5,406 | 4,527 | ||||||||||||||||||
| 529,500 | 499,906 | 499,027 | |||||||||||||||||||
Less long-term debt due within one year | 8,000 | 15,000 | 15,000 | ||||||||||||||||||
Total long-term debt | 521,500 | 48 | % | 484,906 | 47 | % | 484,027 | 46 | % | ||||||||||||
Total capitalization | $ | 1,092,002 | 100 | % | $ | 1,033,230 | 100 | % | $ | 1,052,544 | 100 | % | |||||||||
Thousands | March 31, 2006 (Unaudited) | March 31, 2005 (Unaudited) | Dec. 31, 2005 | ||||||||||||||||||
Common stock equity: | |||||||||||||||||||||
Common stock | $ | 87,335 | $ | 87,244 | $ | 87,334 | |||||||||||||||
Premium on common stock | 296,281 | 299,900 | 296,471 | ||||||||||||||||||
Earnings invested in the business | 237,205 | 214,864 | 205,687 | ||||||||||||||||||
Unearned compensation | — | (809 | ) | (650 | ) | ||||||||||||||||
Accumulated other comprehensive income (loss) | (1,911 | ) | (1,818 | ) | (1,911 | ) | |||||||||||||||
Total common stock equity | 618,910 | 55 | % | 599,381 | 55 | % | 586,931 | 53 | % | ||||||||||||
Long-term debt: | |||||||||||||||||||||
Medium-Term Notes | |||||||||||||||||||||
First Mortgage Bonds: | |||||||||||||||||||||
6.340% Series B due 2005 | — | 5,000 | — | ||||||||||||||||||
6.380% Series B due 2005 | — | 5,000 | — | ||||||||||||||||||
6.450% Series B due 2005 | — | 5,000 | — | ||||||||||||||||||
6.050% Series B due 2006 | 8,000 | 8,000 | 8,000 | ||||||||||||||||||
6.310% Series B due 2007 | 20,000 | 20,000 | 20,000 | ||||||||||||||||||
6.800% Series B due 2007 | 9,500 | 9,500 | 9,500 | ||||||||||||||||||
6.500% Series B due 2008 | 5,000 | 5,000 | 5,000 | ||||||||||||||||||
4.110% Series B due 2010 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||
7.450% Series B due 2010 | 25,000 | 25,000 | 25,000 | ||||||||||||||||||
6.665% Series B due 2011 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||
7.130% Series B due 2012 | 40,000 | 40,000 | 40,000 | ||||||||||||||||||
8.260% Series B due 2014 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||
4.700% Series B due 2015 | 40,000 | — | 40,000 | ||||||||||||||||||
7.000% Series B due 2017 | 40,000 | 40,000 | 40,000 | ||||||||||||||||||
6.600% Series B due 2018 | 22,000 | 22,000 | 22,000 | ||||||||||||||||||
8.310% Series B due 2019 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||
7.630% Series B due 2019 | 20,000 | 20,000 | 20,000 | ||||||||||||||||||
9.050% Series A due 2021 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||
5.620% Series B due 2023 | 40,000 | 40,000 | 40,000 | ||||||||||||||||||
7.720% Series B due 2025 | 20,000 | 20,000 | 20,000 | ||||||||||||||||||
6.520% Series B due 2025 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||
7.050% Series B due 2026 | 20,000 | 20,000 | 20,000 | ||||||||||||||||||
7.000% Series B due 2027 | 20,000 | 20,000 | 20,000 | ||||||||||||||||||
6.650% Series B due 2027 | 20,000 | 20,000 | 20,000 | ||||||||||||||||||
6.650% Series B due 2028 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||
7.740% Series B due 2030 | 20,000 | 20,000 | 20,000 | ||||||||||||||||||
7.850% Series B due 2030 | 10,000 | 10,000 | 10,000 | ||||||||||||||||||
5.820% Series B due 2032 | 30,000 | 30,000 | 30,000 | ||||||||||||||||||
5.660% Series B due 2033 | 40,000 | 40,000 | 40,000 | ||||||||||||||||||
5.250% Series B due 2035 | 10,000 | — | 10,000 | ||||||||||||||||||
Convertible Debentures | |||||||||||||||||||||
7-1/4% Series due 2012 | — | 4,375 | — | ||||||||||||||||||
| 529,500 | 498,875 | 529,500 | |||||||||||||||||||
Less long-term debt due within one year | 28,000 | 15,000 | 8,000 | ||||||||||||||||||
Total long-term debt | 501,500 | 45 | % | 483,875 | 45 | % | 521,500 | 47 | % | ||||||||||||
Total capitalization | $ | 1,120,410 | 100 | % | $ | 1,083,256 | 100 | % | $ | 1,108,431 | 100 | % | |||||||||
See Notes to Consolidated Financial Statements
PART I. FINANCIAL INFORMATION
Notes to Consolidated Financial Statements
(Unaudited)
| 1. | Basis of Financial Statements |
The consolidated financial statements include the accounts of Northwest Natural Gas Company (NW Natural), a regulated utility, and its non-regulated wholly-owned subsidiary businesses,business, NNG Financial Corporation (Financial Corporation) and Northwest Energy Corporation. Together these businesses are referred to as the “Company.”
.
The information presented in the interim consolidated financial statements is unaudited, but includes all material adjustments, including normal recurring accruals, that the management of the Company considers necessary for a fair statement of the results for each period reported. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes included in the Company’s 20042005 Annual Report on Form 10-K (2004(2005 Form 10-K). A significant part of the business of the Company is of a seasonal nature; therefore, results of operations for interim periods are not necessarily indicative of the results for a full year.
Certain amounts from prior periodsyears have been reclassified to conform, for comparison purposes, towith the current financial statement presentation. TheseThe current year’s presentation of the Consolidated Statements of Income includes the reclassification of revenue taxes as a component of net operating revenues. Revenue taxes are expenses primarily related to the utility’s franchise agreements and are based on gross operating revenues. Since revenue taxes are a direct cost of utility sales, the financial statement classification was changed to improve the presentation of net operating revenues and operating expenses. In prior years, revenue taxes were included under operating expenses as part of other taxes. The reclassifications had no impact on prior period consolidatedyears’ income from operations or net income.
| 2. | New Accounting Standards |
Adopted Standards
Medicare Prescription Drug, Improvement and Modernization Act.Share Based Payment. In May 2004, the Financial Accounting Standards Board (FASB) issued Staff Position (FSP) No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (the Act). FSP No. FAS 106-2 provides specific guidance on accounting for the effects of the Act for employers that sponsor postretirement health care plans that provide prescription drug benefits. The Company has previously determined that the Act has no material impact on cash flows, accumulated postretirement benefit obligations, or net periodic postretirement benefit costs under the current plan design.
Inventory Costs. In November 2004, the FASB issuedEffective Jan. 1, 2006, we adopted Statement of Financial Accounting Standards (SFAS) No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4.” SFAS No. 151 amends the guidance on inventory pricing to require that abnormal amounts of idle facility expense, freight, handling costs and wasted material be charged to current period expense rather than capitalized as inventory costs. SFAS No. 151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The Company is evaluating the effect of the adoption and implementation of SFAS No. 151, which is not expected to have a material impact upon the Company’s financial condition, results of operations or cash flows.
Share Based Payments. In December 2004, the FASB issued SFAS No. 123 (revised 2004),123R, “Share Based Payment” (SFAS No. 123R), that requires companies to expense the fair value of employee stock options and similar awards. Under SFAS No. 123R, share based payment awards will be measured at fair value on the date of grant based on the estimated number of awards expected to vest. The estimated fair value will be recognized as compensation expense over the period an employee is required to provide service in exchange for the award, usually referred to as the vesting period. The expense would be adjusted for actual forfeitures that occur before vesting, but would not be adjusted for awards that expire or terminate after vesting. The Company is evaluating different option-pricing models to determine the most appropriate measure of fair value under the new standard. Estimated fair value and compensation expense are currently calculatedPayment,” using the Black-Scholes option pricing model, and its corresponding impact on the financial statements is provided in Note 3 below and in Part II, Item 8., Note 4,Modified Prospective Application method without restatement of the 2004 Form 10-K. The Company is requiredprior periods. Prior to adopt SFAS No. 123R in the first quarter of 2006. The Company is evaluating the effect of the adoption and implementation of SFAS No. 123R, which is notthe Company accounted for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123R requires companies to recognize compensation expense for all equity-based compensation awards issued to employees that are expected to vest. Under this method, the Company began to amortize compensation cost for the remaining portion of outstanding awards for which the requisite service was not yet rendered at Jan. 1, 2006. Compensation cost for these awards was based on the fair value of the awards at the grant date as determined under the intrinsic value method. The Company will determine the fair value of and account for awards that are granted, modified or settled after Jan. 1, 2006 in accordance with SFAS No. 123R. The adoption of SFAS No. 123R did not have a material impact on the Company’s financial condition, results of operations or cash flows.
Non-monetary Transactions. In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets – An Amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions,” which redefines the types of non-monetary exchanges that require fair value measurement. The Company is required to adopt SFAS No. 153 for non-monetary transactions entered into after June 30, 2005. Adoption of this new standard did not have a material impact on the Company’s financial condition or results of operations.
Conditional Asset Retirement Obligations. In March 2005, the FASB issued FASB Interpretation No. (FIN) 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143.” FIN 47 clarifies that an entity is required to recognize a liability See Note 3 for a legal obligation to perform an asset retirement activity if the fair value can be reasonably estimated even though the timing and/or methoddetailed discussion of settlement are conditional on a future event. FIN 47 is required to be adopted for annual reporting periods ending after Dec. 15, 2005. The Company isstock-based compensation.
evaluating the effect of the adoption and implementation of FIN 47, which is not expected to have a material impact on its financial condition, results of operations or cash flows.
Accounting for Changes and Error Corrections.In May 2005, the FASB issuedEffective Jan. 1, 2006, we adopted SFAS No. 154, “Accounting for Changes and Error Corrections – a replacement of APB Opinion No. 20 and FASB Statement No. 3,” which provides guidance on the accounting for and reporting of accounting changes and error corrections. The statement requires retrospective application to prior periods’ financial statements of changes in accounting principles, unless it is impracticable to determine the period-specific effects or the cumulative effect of the change. The guidance provided in Accounting Principles Board (APB)APB Opinion No. 20 for reporting the correction of an error in previously issued financial statements remains unchanged and requires the restatement of previously issued financial statements. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after DecemberDec. 15, 2005. The adoption of SFAS No. 154 did not have a material impact upon the Company’s financial condition, results of operation or cash flows.
Inventory Costs. Effective Jan. 1, 2006, we adopted SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4,” which amends the guidance on inventory pricing to require that abnormal amounts of idle facility expense, freight, handling costs and wasted material be charged to current period expense rather than capitalized as inventory costs. The adoption of SFAS No. 151 did not have a material impact upon the Company’s financial condition, results of operations or cash flows.
Recent Accounting Pronouncements
Purchases and Sales of Inventory with the Same Counterparty. In September 2005, the Financial Accounting Standards Board’s (FASB) Emerging Issues Task Force (EITF) reached a final consensus on Issue 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty”.Counterparty.” EITF 04-13 requires that two or more legally separate exchange transactions with the same counterparty be combined and considered a single arrangement for purposes of applying APB Opinion No. 29, “Accounting for Nonmonetary Transactions” (APB 29),Transactions,” when the transactions are entered into in contemplation of one another. EITF 04-13 is effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. The Company is evaluating the effectAdoption of the adoption of EITF 04-13, whichthis standard is not expected to have a material impact on the Company’s financial condition, results of operations or cash flows.
Accounting for Certain Hybrid Instruments.In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Instruments,” which amends SFAS Nos. 133 and 140. SFAS No. 155 allows financial instruments that have embedded derivatives to be accounted for as a whole if the holder elects to account for the whole instrument on a fair value basis. The statement is effective for all financial instruments acquired or issued after Jan. 1, 2007. The Company is in the process of evaluating the effect of the adoption and implementation of SFAS No. 155, which is not expected to have a material impact on its financial condition, results of operation or cash flows.
Variable Interest Entities.In April 2006, the FASB issued a staff position (FSP) interpreting variable interest entities (VIE) under FASB Interpretation No. (FIN) 46(R)-6, “Determining the Variability to be Considered in Applying FIN 46(R)-6.” This staff position emphasizes that preparers should use a “by design” approach in determining whether an interest is variable. A “by design” approach includes evaluating whether an interest is variable based on a thorough understanding of the design of the potential VIE, including the nature of the risks that the potential VIE was designed to create and pass along to interest holders in the entity. FSP No. FIN 46(R)-6 must be applied prospectively to all entities with which the Company first becomes involved and to all entities previously required to be analyzed under FIN 46(R) when a reconsideration event has occurred effective on or after July 1, 2006. The Company is in the process of evaluating the effect of adoption and implementation of FSP No. FIN 46(R)-6, which is not expected to have a material impact on its financial condition, results of operations or cash flows.
| 3. | Stock-Based Compensation |
NW Natural’sEffective Jan. 1, 2006, we adopted SFAS No. 123R, “Share Based Payment,” to account for all stock-based compensation plans. Our stock-based compensation plans consist of the Long-Term Incentive Plan (LTIP), the Restated Stock Option Plan (Restated SOP), the Employee Stock Purchase Plan (ESPP) and the Non-Employee Directors Stock Compensation Plan (NEDSCP). These plans are designed to promote stock ownership in NW Natural by employees and officers, and, in the case of the NEDSCP, non-employee directors. See Part II, Item 8., Note 4, in the 20042005 Form 10-K for a discussion of the Company’s stock-based compensation plans.
Long-Term Incentive Plan. A total of 500,000 shares of the Company’s common stock has been authorized for awards under the terms of the LTIP as stock bonus, restricted stock or performance-based stock awards. At Sept. 30, 2005,March 31, 2006, performance-based awards on 105,000 shares, based on target, were outstanding, a restricted stock award for 5,000 shares was outstanding, and the remaining 390,000 shares are available for future grants.
Performance-based Stock Awards.At March 31, 2006, the aggregate number of performance-based shares eligible to be awarded and outstanding under the Company’s LTIP at the threshold, target and maximum levels were as follows:
| No. of Performance Shares Awarded | ||||||||
Year Awarded | Performance Period | Threshold | Target | Maximum | ||||
2003 | 2003-05 | 6,250 | 25,000 | 50,000 | ||||
2004 | 2004-06 | 6,750 | 27,000 | 54,000 | ||||
2005 | 2005-07 | 8,750 | 35,000 | 70,000 | ||||
| Total | 21,750 | 87,000 | 174,000 | |||||
Year Awarded | Performance Period | Threshold | Target | Maximum | ||||
2004 | 2004-06 | 6,750 | 27,000 | 54,000 | ||||
2005 | 2005-07 | 8,750 | 35,000 | 70,000 | ||||
2006 | 2006-08 | 10,750 | 43,000 | 86,000 | ||||
| Total | 26,250 | 105,000 | 210,000 | |||||
For the 2003-05 performance period, a serieseach of performance targets were established based on the Company’s average annual return on equity (ROE) for the performance period corresponding to award opportunities ranging from 0 percent to 200 percent of the target awards. No awards are payable unless the threshold annual average ROE level, tied to the Company’s authorized ROE, is achieved during the award period. The maximum awards are payable only upon the achievement of an average annual ROE that is 200 basis pointsperiods shown above, the Company’s regulatory authorized ROE. For the 2004-06 and 2005-07 performance periods, awards will be based on total shareholder return relative to a peer group of gas distribution companies over the three-year performance period and on performance milestonesresults relative to the Company’s core and non-core strategies. During the performance period,For awards granted prior to Jan. 1, 2006, the Company will recognizerecognizes compensation expense and liability for the LTIP awards based on performance levels achieved, and expected to be achieved, and the estimated market value of the common stock as of the distribution date. For awards granted on or after Jan. 1, 2006, the Company recognizes compensation expense in accordance with SFAS No. 123R, based on performance levels achieved and an estimated fair value using a lattice valuation model. For the quarter ended March 31, 2006, the amount accrued and nine months ended Sept. 30, 2005, no amountsexpensed as compensation under the three LTIP grants was negligible. On a cumulative basis, $0.7 million, $0.6 million and a negligible amount have been accrued as compensation expense under the LTIP for the 2003-05 performance period, and $0.2 million and $1.3 million were accrued as compensation expense under the LTIP for the 2004-06, 2005-07 and 2005-072006-08 performance periods, respectively.
Restricted Stock Awards.Restricted stock awards also have been granted under the LTIP. A restricted stock award consisting of 5,000 shares was granted in 2004, which will vest ratably over the period 2005-09.
Restated Stock Option Plan. UnderThe Company has reserved a total of 2,400,000 shares of Common Stock for issuance under the Restated SOP,SOP. At March 31, 2006 options on 1,232,8001,132,600 shares were available for grant and options to purchase 310,716393,700 shares were outstanding at Sept. 30, 2005.March 31, 2006. Options generallyare granted with an exercise price equal to the market value of the common stock at the date of grant, have 10-year terms and vest ratably over a three-yearthree or four-year period following the date of grant. Options to purchase 6,000 shares of common stock, at an exercise price of $38.30, were granted in the first nine months of 2005. The exercise price is equal to the market price of the common stock on the date of grant.
The Company has adopted the disclosure requirements of SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure—An Amendment of FASB Statement No. 123.” However, it continues to account for stock-based compensation using the intrinsic value method prescribed in APB Opinion No. 25, “Accounting for Stock Issued to Employees.” In accordance with APB Opinion No. 25, no compensation expense is recognized for options granted under the Restated SOP. For a further discussion of expense recognition for stock-based compensation, see Note 2, Share Based Payments, above.
If compensation expense for awardsShares issued under the Restated SOP and for shares issued underupon the ESPP had been recognized during the three- and nine-month periods ended Sept. 30, 2005 and 2004 based onexercise of stock options are original issue shares. The fair value onof the Company’s stock-based awards were estimated as of the date of grant using the Black-Scholes option pricing model based on the following weighted-average assumptions:
| 2006 | 2005 | |||||
Risk-free interest rate | 4.5 | % | 4.2 | % | ||
Expected life (in years) | 6.2 | 7.0 | ||||
Expected market price volatility factor | 22.8 | % | 24.6 | % | ||
Expected dividend yield | 4.0 | % | 3.6 | % |
The simplified formula for “plain vanilla” options was utilized to determine the expected life as defined and permitted by Staff Accounting Bulletin No. 107. The risk-free interest rate was based on the implied yield currently available on U.S. Treasury zero-coupon issues with a life equal to the expected life of the options. Historical data was employed in order to estimate the volatility factor, measured on a daily basis, for a period equal to the duration of the expected life of the option awards. The dividend yield was based on management’s current estimate for dividend payout at the time of grant. A forfeiture rate of 3 percent was applied to the calculation of compensation expense.
The following table presents the effect on net income and earnings per share would have resulted infor outstanding stock options and stock awards prior to the pro forma amounts shown below:
| Pro Forma Effect of Stock-Based Options and ESPP: | Three Months Ended Sept. 30, | Nine Months Ended Sept. 30, | ||||||||||||||
Thousands, except per share amounts | 2005 | 2004 | 2005 | 2004 | ||||||||||||
Net income (loss) as reported | $ | (8,671 | ) | $ | (8,285 | ) | $ | 32,356 | $ | 23,611 | ||||||
Pro forma stock-based compensation expense determined under the fair value based method - net of tax | (84 | ) | (109 | ) | (247 | ) | (315 | ) | ||||||||
Pro forma net income (loss) - basic | (8,755 | ) | (8,394 | ) | 32,109 | 23,296 | ||||||||||
Debenture interest - net of tax | — | 60 | — | 179 | ||||||||||||
Pro-forma net income (loss) - diluted | $ | (8,755 | ) | $ | (8,334 | ) | $ | 32,109 | $ | 23,475 | ||||||
Basic earnings (loss) per share | ||||||||||||||||
As reported | $ | (0.31 | ) | $ | (0.30 | ) | $ | 1.17 | $ | 0.88 | ||||||
Pro forma | $ | (0.32 | ) | $ | (0.31 | ) | $ | 1.16 | $ | 0.87 | ||||||
Diluted earnings (loss) per share | ||||||||||||||||
As reported | $ | (0.31 | ) | $ | (0.30 | ) | $ | 1.17 | $ | 0.88 | ||||||
Pro forma | $ | (0.32 | ) | $ | (0.31 | ) | $ | 1.16 | $ | 0.86 | ||||||
The Company will adoptadoption of SFAS No. 123R for expensing employeethe quarter ended March 31, 2005 in addition to the impact on reported earnings in the quarter ended March 31, 2006:
Pro Forma Effect of Stock-Based Options and ESPP: Thousands, except per share amounts | Three Months Ended March 31, | |||||||
| 2006 | 2005 | |||||||
Net income as reported | $ | 41,033 | $ | 39,887 | ||||
Add: Actual stock-based compensation expense included in reported net income under SFAS No. 123R, net of related tax effects | 193 | — | ||||||
Deduct: Pro forma stock-based compensation expense determined under the fair value based method, net of related tax effects | (193 | ) | (92 | ) | ||||
Pro forma earnings applicable to common stock - basic | 41,033 | 39,795 | ||||||
Debenture interest less taxes | — | 48 | ||||||
Pro-forma earnings applicable to common stock - diluted | $ | 41,033 | $ | 39,843 | ||||
Basic earnings per share | ||||||||
As reported | $ | 1.49 | $ | 1.45 | ||||
Pro forma | $ | 1.49 | $ | 1.44 | ||||
Diluted earnings per share | ||||||||
As reported | $ | 1.48 | $ | 1.43 | ||||
Pro forma | $ | 1.48 | $ | 1.43 | ||||
Summarized information for stock options and other share based compensation beginning in 2006 (see Note 2),option grants is as required. For purposes of the pro forma disclosures above, the estimatedfollows:
| Price per Share | |||||||||
Option Shares | Range | Weighted-Average Exercise Price | |||||||
Balance Outstanding, Dec. 31, 2004 | 431,470 | $ | 20.25-32.02 | $ | 28.38 | ||||
Granted | 9,000 | 34.95-38.30 | 37.18 | ||||||
Exercised | (121,170 | ) | 20.25-31.34 | 26.59 | |||||
Expired | (10,800 | ) | 27.60-31.34 | 30.79 | |||||
Balance Outstanding, Dec. 31, 2005 | 308,500 | $ | 20.25-38.30 | $ | 29.26 | ||||
Granted | 97,800 | 34.29 | 34.29 | ||||||
Exercised | (12,000 | ) | 20.25-31.34 | 24.55 | |||||
Expired | (600 | ) | 31.34 | 31.34 | |||||
Balance Outstanding, Mar. 31, 2006 | 393,700 | $ | 20.25-38.30 | $ | 30.65 | ||||
Exercisable, Dec. 31, 2005 | 189,500 | $ | 20.25-32.02 | $ | 27.63 | ||||
Exercisable, Mar. 31, 2006 | 232,850 | $ | 20.25-32.02 | $ | 28.67 | ||||
The weighted-average grant-date fair value of equity awards granted during 2005 and 2006 was $7.85 and $6.29, respectively. By Dec. 31, 2006, an additional 3,000 shares will vest for a total of 235,850 exercisable shares at year-end.
During the first quarter of 2006, $0.2 million of pre-tax compensation expense related to options granted under the Restated SOP was recognized in income under the fair value method in accordance with SFAS No. 123R. In addition, less than $0.1 million of pre-tax compensation expense related to the Employee Stock Purchase Plan was recognized. As of March 31, 2006 there was $0.8 million of unrecognized compensation cost related to the unvested portion of outstanding stock option awards expected to be recognized over a period extending through 2009.
In the first quarter of 2006, 12,000 options were exercised with a total intrinsic value of $0.1 million. Cash of $0.3 million was received for these exercises, and a negligible related tax benefit was realized. The total intrinsic value of options exercised in the first quarter of 2005 was $0.6 million, and the total fair value of options that vested in the first quarters of 2006 and 2005 was $0.3 million and $0.4 million, respectively.
The following table summarizes additional information about stock options is amortized to expense over the vesting period.outstanding and exercisable at March 31, 2006:
| Outstanding | Exercisable | ||||||||||||||
Range of Exercise Prices | Stock Options | (In millions) Aggregate Intrinsic Value | Stock Options | (In millions) Aggregate Intrinsic Value | Weighted- Exercise Price | Weighted- Remaining Life in Years | |||||||||
$20.25 - $38.30 | 393,700 | $ | 1.7 | 232,850 | $ | 1.4 | $ | 28.67 | 6.3 | ||||||
| 4. | Use of Derivative Instruments |
NW Natural enters into forward contracts and other related financial transactions for the purchase of natural gas that qualify as derivative instruments under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149 (collectively referred to as SFAS No. 133). NW Natural utilizes derivative financial instruments to manage commodity prices related to natural gas supply requirements. See Part II, Item 8., Notes 1 and 11, in the 2004 Form 10-K.
In the normal course of business, NW Natural enters into forward natural gas commodity purchase (gas supply) contracts to meet the requirements of core utility customers. In the first nine months of 2005, NW Natural entered into a series of exchange transactions with an unaffiliated energy marketing company which resulted in a change in the Company’s accounting treatment for its forward gas supply contracts under SFAS No. 133. SFAS No. 133 requires that derivative instruments be recorded on the balance sheet at fair value. Prior to March 31, 2005, the Company’s forward gas supply contracts were excluded from the fair value measurement requirement of SFAS No. 133 because these contracts were eligible for the normal purchases and normal sales exception. These contracts are now accounted for as derivative instruments and marked-to-market based on fair value pursuant to SFAS No. 133. These contracts include 29 index-based contracts and one fixed-price contract. The mark-to-market adjustment for the forward gas supply contracts at Sept. 30, 2005 is an unrealized loss of $2.1 million, consisting of an unrealized loss of $5.3 million on index-based contracts and a $3.2 million unrealized gain on a fixed-price contract. The net unrealized loss is recorded as a liability with an offsetting entry to a regulatory asset based on regulatory deferral accounting under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (see Part II, Item 8., Note 1, “Industry Regulation,”11, in the 20042005 Form 10-K).
Due to the forward gas supply contracts being classified as derivatives for accounting purposes, the corresponding derivative financial contracts originally designated as cash flow hedges no longer qualify for hedge accounting under SFAS No. 133, even though these contracts continue to hedge the financial risk exposure of the forward gas supply
contracts. However, due to regulatory deferral accounting under SFAS No. 71, the accounting change had no impact on the Company’s financial condition, results of operations or cash flows. The mark-to-market adjustment at Sept. 30,At March 31, 2006 and 2005, for the fixed-price financial swap contracts is an unrealized gain of $321.1 million.
Fixed-price financial call options are purchased to hedge the Company’s forecasted purchases of swing supplies or spot gas. The mark-to-market adjustment at Sept. 30, 2005 is an unrealized gain of $19.4 million. These unrealized gains and losses are subject to regulatory deferral and, as such, are recorded as a non-trading derivative asset or liability which is offset by recording a corresponding amount to a deferred asset or liability account.
Foreign currency forward contracts are used to hedge the fluctuation in foreign currency exchange rates for NW Natural’s commodity and commodity-related demand charges paid in Canadian dollars. These forward contracts qualify for cash flow hedge accounting treatment under SFAS No. 133. The mark-to-market adjustment at Sept. 30, 2005 is an unrealized gain of $0.3 million. These unrealized gains and losses are subject to regulatory deferral and, as such, are recorded as a derivative asset or liability which is offset by recording a corresponding amount to a regulatory asset or regulatory liability account.
At Sept. 30, 2005 and 2004 and Dec. 31, 2004, unrealized gains or losses from mark-to-market valuations of the Company’s derivative instruments were not recognized in current income, but wereprimarily reported as regulatory liabilities or regulatory assets because regulatory mechanisms provide for the realized gains or losses at settlement to be included in utility gas costs subject to regulatory deferral treatment. The estimated fair values (unrealizedfor unrealized gains and losses) oflosses on derivative instruments outstanding, determined using a discounted cash flow model for financial swaps and physical derivatives, were as follows:
| Fair Value Gains (Losses) | Fair Value Gains (Losses) | ||||||||||||||||||||||
| Sept. 30, | Dec. 31, 2004 | March 31, | Dec. 31, | ||||||||||||||||||||
Thousands | 2005 | 2004 | 2006 | 2005 | 2005 | ||||||||||||||||||
Fair Value Gain (Loss) | |||||||||||||||||||||||
Natural gas commodity-based derivative instruments: | |||||||||||||||||||||||
Fixed-price financial swaps | $ | 321,119 | $ | 67,422 | $ | 12,641 | $ | 26,405 | $ | 87,995 | $ | 173,790 | |||||||||||
Fixed-price financial call options | 19,394 | 1,878 | (2,195 | ) | — | — | 1,871 | ||||||||||||||||
Indexed-price physical supply | (5,281 | ) | — | — | (3,079 | ) | (8,483 | ) | (5,454 | ) | |||||||||||||
Fixed-price physical supply | 3,158 | — | 24 | — | (1,429 | ) | 820 | ||||||||||||||||
Physical supply contracts with embedded options | — | 550 | — | 566 | — | 567 | |||||||||||||||||
Foreign currency forward purchases | 277 | 229 | 442 | 45 | 122 | 183 | |||||||||||||||||
Total | $ | 338,667 | $ | 70,079 | $ | 10,912 | $ | 23,937 | $ | 78,205 | $ | 171,777 | |||||||||||
In the first quarter of 2006, NW Natural realized net gains of $17.5 million from the settlement of natural gas commodity swap and call option contracts, which were recorded as decreases to the cost of gas. The currency exchange rate in all foreign currency forward purchase contracts is included in our cost of gas at settlement; therefore, no gain or loss was recorded from the settlement of those contracts.
As of March 31, 2006, all natural gas commodity price swap contracts mature no later than Oct. 31, 2008.
| 5. | Segment Information |
The Company principally operates in aCompany’s primary business segment, of business, “Utility,” consistingconsists of the distribution and sale of natural gas. Another segment, “Interstate Gas Storage,” represents natural gas storage services provided to interstate and intrastate customers and asset optimization services under a contract withactivities performed by an unaffiliated energy marketing company usingprimarily through the use of commodity transactions and releases of temporarily unused portions of NW Natural’s upstream pipeline transportation capacity and gas storage capacity (see Part II, Item 8., Note 2, in the 20042005 Form 10-K). The remaining segment, “Other,” primarily consists of non-utility operating activities and non-regulated investments.
The following table presents information about the reportable segments for the three- and nine-monththree-month periods ended Sept. 30, 2005March 31, 2006 and 2004.2005. Inter-segment transactions are insignificant.
| Three Months Ended Sept. 30, | Nine Months Ended Sept. 30, | |||||||||||||||||||||||||||
Thousands | Utility | Interstate Gas Storage | Other | Total | Utility | Interstate Gas Storage | Other | Total | ||||||||||||||||||||
2005 | ||||||||||||||||||||||||||||
Net operating revenues | $ | 41,261 | $ | 3,126 | $ | 49 | $ | 44,436 | $ | 226,649 | $ | 7,107 | $ | 91 | $ | 233,847 | ||||||||||||
Depreciation and amortization | 15,289 | 163 | — | 15,452 | 45,469 | 490 | — | 45,959 | ||||||||||||||||||||
Other operating expenses | 34,169 | 197 | 33 | 34,399 | 110,650 | 571 | 110 | 111,331 | ||||||||||||||||||||
Income (loss) from operations | (8,196 | ) | 2,766 | 15 | (5,415 | ) | 70,531 | 6,046 | (20 | ) | 76,557 | |||||||||||||||||
Income from financial investments | 436 | — | 68 | 504 | 1,410 | — | 139 | 1,549 | ||||||||||||||||||||
Net income (loss) | (10,473 | ) | 1,571 | 231 | (8,671 | ) | 28,383 | 3,313 | 660 | 32,356 | ||||||||||||||||||
Total assets at Sept. 30, 2005 | 2,028,389 | 34,697 | 12,728 | 2,075,814 | 2,028,389 | 34,697 | 12,728 | 2,075,814 | ||||||||||||||||||||
2004 | ||||||||||||||||||||||||||||
Net operating revenues | $ | 38,114 | $ | 1,326 | $ | 43 | $ | 39,483 | $ | 199,307 | $ | 4,713 | $ | 126 | $ | 204,146 | ||||||||||||
Depreciation and amortization | 14,093 | 119 | — | 14,212 | 41,684 | 347 | — | 42,031 | ||||||||||||||||||||
Other operating expenses | 31,554 | 177 | 44 | 31,775 | 100,902 | 546 | 128 | 101,576 | ||||||||||||||||||||
Income (loss) from operations | (7,532 | ) | 1,030 | (2 | ) | (6,504 | ) | 56,722 | 3,820 | (3 | ) | 60,539 | ||||||||||||||||
Income from financial investments | 549 | — | 898 | 1,447 | 1,974 | — | 849 | 2,823 | ||||||||||||||||||||
Net income (loss) | (9,355 | ) | 582 | 488 | (8,285 | ) | 20,764 | 2,077 | 770 | 23,611 | ||||||||||||||||||
Total assets at Sept. 30, 2004 | 1,633,850 | 22,611 | 18,192 | 1,674,653 | 1,633,850 | 22,611 | 18,192 | 1,674,653 | ||||||||||||||||||||
| Three Months Ended March 31, | |||||||||||||
Thousands | Utility | Interstate Gas Storage | Other | Total | |||||||||
2006 | |||||||||||||
Net operating revenues | $ | 122,344 | $ | 3,079 | $ | 41 | $ | 125,464 | |||||
Depreciation and amortization | 15,610 | 220 | — | 15,830 | |||||||||
Income from operations | 71,122 | 2,684 | 8 | 73,814 | |||||||||
Income (loss) from financial investments | 1,383 | — | (50 | ) | 1,333 | ||||||||
Net income | 39,452 | 1,449 | 132 | 41,033 | |||||||||
Total assets at March 31, 2006 | 1,792,955 | 35,533 | 11,569 | 1,840,057 | |||||||||
2005 | |||||||||||||
Net operating revenues | $ | 118,936 | $ | 2,029 | $ | 21 | $ | 120,986 | |||||
Depreciation and amortization | 15,031 | 164 | — | 15,195 | |||||||||
Income (loss) from operations | 70,168 | 1,693 | (35 | ) | 71,826 | ||||||||
Income (loss) from financial investments | 468 | — | (137 | ) | 331 | ||||||||
Net income | 38,844 | 898 | 145 | 39,887 | |||||||||
Total assets at March 31, 2005 | 1,707,832 | 28,331 | 10,434 | 1,746,597 | |||||||||
| 6. | Pension and Other Postretirement Benefits |
Net Periodic Benefit Cost
The following table provides the components of net periodic benefit cost for the qualified and non-qualified pension plans and other postretirement benefit plans for the three-three months ended March 31, 2006 and nine-month periods ended Sept. 30, 2005 and 2004.2005. See Part II, Item 8., Note 7, in the 20042005 Form 10-K for a discussion of the assumptions used in measuring these costs and benefit obligations.
Thousands | Pension Benefits | Other Postretirement Benefits | ||||||||||||
| Three Months Ended Sept. 30, | ||||||||||||||
| 2005 | 2004 | 2005 | 2004 | |||||||||||
Service cost | $ | 1,564 | $ | 1,409 | $ | 114 | $ | 132 | ||||||
Interest cost | 3,377 | 3,199 | 308 | 364 | ||||||||||
Special termination benefits | 63 | — | — | — | ||||||||||
Expected return on plan assets | (3,776 | ) | (3,309 | ) | — | — | ||||||||
Amortization of transition obligation | — | — | 103 | 103 | ||||||||||
Amortization of prior service cost | 361 | 274 | — | — | ||||||||||
Recognized actuarial loss | 599 | 436 | 72 | 118 | ||||||||||
Net periodic benefit cost | $ | 2,188 | $ | 2,009 | $ | 597 | $ | 717 | ||||||
Thousands | Pension Benefits | Other Postretirement Benefits | ||||||||||||
| Nine Months Ended Sept. 30, | ||||||||||||||
| 2005 | 2004 | 2005 | 2004 | |||||||||||
Service cost | $ | 4,742 | $ | 4,227 | $ | 343 | $ | 396 | ||||||
Interest cost | 9,902 | 9,597 | 924 | 1,092 | ||||||||||
Special termination benefits | 189 | — | — | — | ||||||||||
Expected return on plan assets | (10,837 | ) | (9,927 | ) | — | — | ||||||||
Amortization of transition obligation | — | — | 308 | 309 | ||||||||||
Amortization of prior service cost | 807 | 822 | — | — | ||||||||||
Recognized actuarial loss | 1,561 | 1,308 | 216 | 356 | ||||||||||
Net periodic benefit cost | $ | 6,365 | $ | 6,027 | $ | 1,791 | $ | 2,153 | ||||||
Thousands | Pension Benefits | Other Postretirement Benefits | ||||||||||||
| Three Months Ended March 31, | ||||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||
Service cost | $ | 1,961 | $ | 1,589 | $ | 137 | $ | 114 | ||||||
Interest cost | 3,758 | 3,263 | 283 | 308 | ||||||||||
Special termination benefits | — | 63 | — | — | ||||||||||
Expected return on plan assets | (4,403 | ) | (3,530 | ) | — | — | ||||||||
Amortization of transition obligation | — | — | 103 | 103 | ||||||||||
Amortization of prior service cost | 245 | 223 | 49 | — | ||||||||||
Recognized actuarial loss | 916 | 481 | — | 72 | ||||||||||
Net periodic benefit cost | $ | 2,477 | $ | 2,089 | $ | 572 | $ | 597 | ||||||
Employer Contributions
The Company makesis not required to make cash contributions to its qualified non-contributory defined benefit pension plans based on actuarial assumptions and estimates, tax regulations and funding requirements under federal law. Generally, it is the Company’s policy to contribute at least the minimum amount required by the Employee Retirement Income Security Act of 1974. It is also the Company’s intent to contribute additional amounts as are sufficient on an actuarial basis to maintain funding targets and provide for the payment of future benefits under the plans.
In 2004, the Company contributed $5.3 million to the Retirement Plan for Non-Bargaining Unit Employees (NBU Plan) for the 2004 plan year, of which $1.0 million represented the minimum required funding. Although the Company was not required to make additionalin 2006, but cash contributions to these plans in 2005 based on minimum funding requirements, during the quarter ended Sept. 30, 2005, the Company contributed an additional $20 million to its two qualified defined benefit pension plans for the plan year 2004, consisting of $13 million to the NBU Plan and $7 million to the Retirement Plan for Bargaining Unit Employees.
The Company continues to evaluate its qualified plans’ funding status based on projected benefit obligations, expected returns on plan assets and anticipated changes in actuarial assumptions to determine if any contributions will be made prior to Dec. 31, 2005 for the 2005 plan year. In addition, the Company will continue to make cash contributions during 2005 in the form of ongoing benefit payments aswill be required for its unfunded non-qualified supplemental pension plans and other postretirement benefit plans.plans in 2006. See Part II, Item 8., Note 7, in the 20042005 Form 10-K.
| 7. | Commitments and Contingencies |
Environmental Matters
NW Natural owns, or has previously owned, properties that may require environmental remediation or action. NW Natural accrues all material loss contingencies relating to these properties that it believes to be probable of assertion and reasonably estimable. The Company continues to study the extent of its potential environmental liabilities, but due to the numerous uncertainties surrounding the course of environmental remediation and the preliminary nature of several environmental site investigations, the range of potential loss beyond the amounts currently accrued, and the probabilities thereof, cannot be reasonably estimated. NW Natural regularly reviews its remediation liability for each site where it may be exposed to remediation responsibilities. The costs of environmental remediation are difficult to estimate. A number of steps are involved in each environmental remediation effort, including site investigations, remediation, operations and maintenance, monitoring and site closure. Each of these steps may, over time, involve a number of alternative actions, each of which can change the course of the effort. In certain cases, in addition to NW Natural, there are a number of other potentially responsible parties, each of which, in proceedings and negotiations with other potentially responsible parties and regulators, may influence the course of the remediation effort. The allocation of liabilities among the potentially responsible parties is often subject to dispute and highly uncertain. The events giving rise to environmental liabilities often occurred many decades ago, which complicates the determination of allocating liabilities among potentially responsible
parties. Site investigations and remediation efforts often develop slowly over many years. To the extent reasonably estimable, NW Natural estimates the costs of environmental liabilities using current technology, enacted laws and regulations, industry experience gained at similar sites and an assessment of the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a better estimate within this range of probable cost, NW Natural records the liability at the lower end of this range. It is likely that changes in these estimates will occur throughout the remediation process for each of these sites due to uncertainty concerning NW Natural’s responsibility, the complexity of environmental laws and regulations and the selection of compliance alternatives. The status of each of the sites currently under investigation is provided below. Also, see Part II, Item 8., Note 12, in the 20042005 Form 10-K for a description of these properties and further discussion.
Gasco site. NW Natural owns property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 (the Gasco site). The Gasco site has been under investigation by NW Natural for environmental contamination under the Oregon Department of Environmental Quality’s (ODEQ) Voluntary Clean-Up Program. In June 2003, the Company filed a Feasibility Scoping Plan and an Ecological and Human Health Risk Assessment with the ODEQ, which outlined a range of remedial alternatives for the most contaminated portion of the Gasco site. The Company estimates its rangeIn the first quarter of remaining potential liability2006, NW Natural accrued an additional $0.2 million for this site, including the estimated cost of investigation, from among feasible alternatives, at between $1.5wells to be used as part of a pilot study for source control. The liability of $1.1 million and $7 million. NW Natural has accrued a liability for the Gasco site is at the low end of the range because no amount within the range is considered to be more likely than another.another and the high end of the range cannot be estimated.
Siltronic (formerly Wacker) site. NW Natural previously owned property adjacent to the Gasco site that now is the location of a manufacturing plant owned by Siltronic Corporation (formerly Wacker Siltronic Corporation) (the Siltronic site). During the first nine months of 2005, the estimatedThe liability balance for this site increased due to new information regarding required additional storm-water pollution work and indoor air quality studies, resulting in an additional accrual of less than $0.1 million. The amount of the additional accrual was deferred to a regulatory asset account pursuant to an order of the Public Utility Commission of Oregon (OPUC)at March 31, 2006 is negligible (see “Regulatory and Insurance Recovery for Environmental Matters,” below).
Portland Harbor site. In 1998, the ODEQ and the U.S. Environmental Protection Agency (EPA) completed a study of sediments in a 5.5-mile segment of the Willamette River (the Portland Harbor) that includes the area adjacent to the Gasco site and the Siltronic site. The Portland Harbor was listed by the EPA as a Superfund site in 2000 and the Company was notified that it is a potentially responsible party. Subsequently, the EPA approved a Programmatic Work Plan, Field Sampling Plan and Quality Assurance Project Plan for the Portland Harbor Remedial Investigation/Feasibility Study (RI/FS). NW Natural’s share of the original cost estimate for the RI/FS work, which was expected to be completed in 2007, was $1.6 million. However, as a result of the EPA’s indication that further study will be required, an additional accrual of $1.3 million was recorded in the third quarter of 2005 for the additional studies and related legal costs. Current information is not sufficient to reasonably estimate additional liabilities, if any, or the range of potential liabilities, for environmental remediation and monitoring after the RI/FS work plan is completed, except for the early action removal of a tar deposit in the river sediments discussed below.
In April 2004 the Company entered into an Administrative Order on Consent providing for early action removal of a deposit of tar in the river sediments adjacent to the Gasco site. In July 2004, the EPA approved an initial work plan for the early action removal. NW Natural is expected to completecompleted the removal of the tar deposit in the Portland Harbor in November 2005. AdditionalOctober 2005 and on Nov. 5, 2005 the EPA approved the completed project. The estimated cost for the removal, including technical work, oversight, consultants, legal fees and ongoing monitoring is $10 million. To-date, NW Natural has spent $8.1 million for work related to the removal of the tar deposit with a remaining estimated liability of $1.9 million.
Oregon Steel Mills site. See “Legal Proceedings,” below.
Regulatory and Insurance Recovery for Environmental Matters. In May 2003, the Oregon Public Utility Commission (OPUC) approved NW Natural’s request for deferral of environmental costs associated with specific sites, including the Gasco, Siltronic and Portland Harbor sites. The authorization, which has been extended through January 2007 and expanded to include the Oregon Steel Mills site, allows NW Natural to defer and seek recovery of unreimbursed environmental costs in a future general rate case. In April 2006, the OPUC authorized NW Natural to accrue interest on deferred balances effective Jan. 27, 2006, subject to an annual demonstration to the OPUC that the Company has maximized its insurance recovery or made substantial progress in securing insurance recovery for unrecovered environmental expenses. As of March 31, 2006, the Company has paid a cumulative total of $14.4 million relating to the named sites since the effective date of the deferral authorization.
On a cumulative basis, NW Natural has recognized a total of $24.0 million for environmental costs, including legal, investigation, monitoring and remediation costs. Of this total, $19.3 million has been spent to-date and $4.7 million is reported as an outstanding liability. At March 31, 2006, the Company had a regulatory asset of $19.1 million which includes $14.4 million of total expenditures to date and accruals for additional estimated costs of $5.3$4.7 million. The Company believes the recovery of these costs is probable through the regulatory process after first pursuing recovery of costs from insurance. The Company also has an insurance receivable of $1.1 million, and $1.6 million were recordedwhich is not included in the secondregulatory asset amount. The Company intends to pursue recovery of these environmental costs from its general liability insurance policies, and the regulatory asset will be reduced by the amount of any corresponding insurance recoveries. The Company considers insurance recovery probable based on a combination of factors, including a review of the terms of its insurance policies, the financial condition of the insurance companies providing coverage, a review of successful claims filed by other utilities with similar gas manufacturing facilities, and recent Oregon legislation that allows an insured party to seek recovery of “all sums” from one insurance company. The Company has not filed claims for insurance recovery nor have the insurance companies approved or denied coverage of these claims.
Legal Proceedings
The Company is subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings, including the matters described below and in Part II, Item 8., Note 12, in the 2005 Form 10-K, cannot be predicted with certainty, the Company does not expect that the ultimate disposition of these matters will have a materially adverse effect on the Company’s financial condition, results of operations or cash flows.
Industrial Customers Switching from Transportation to Sales Service.In the fourth quarter of 2005, the Company settled a dispute with some large industrial customers related to gas costs charged to such customers upon electing to receive gas commodity under sales service instead of arranging for their own supplies through independent third quarters ofparties. Two formal complaints filed with the OPUC in connection with this matter have been dismissed by the OPUC. The OPUC has also closed the investigation it opened to determine whether the Company had provided adequate information about rates to the industrial customers.
On Feb. 3, 2006, Georgia-Pacific Corporation filed suit against NW Natural (Georgia-Pacific Corporation v. Northwest Natural Gas Company, Case No. CV06-151-PK, United States District Court, District of Oregon), alleging that NW Natural offered to sell natural gas to Georgia-Pacific under the interruptible sales service provisions of the Company’s Rate Schedule 32 at a commodity rate set at the Company’s Weighted Average Cost of Gas (WACOG). Georgia-Pacific further alleged that it accepted this offer and that the Company failed to perform as promised when, in October 2005, respectively, basedNW Natural notified Georgia-Pacific that it would have to charge Georgia-Pacific the incremental costs of acquiring gas on revised estimatesthe open market. Georgia-Pacific also alleges breach of remediation workcontract, promissory estoppel, fraudulent misrepresentation and ongoing monitoring.breach of the duty of good faith and fair dealing. As a result, Georgia-Pacific is seeking damages in an amount to be determined at trial but which they expect to be at least $235,000, plus consequential damages in an amount to be determined at trial. Georgia-Pacific further alleges that by failing to sell gas to Georgia-Pacific at the agreed upon price, NW Natural violated Oregon state laws that regulate utility operations, thereby entitling Georgia-Pacific to treble damages and attorney fees.
Prior to the Georgia-Pacific federal lawsuit being filed, on Jan. 5, 2006, NW Natural sought a declaratory judgment in the Circuit Court for the State of Oregon (NW Natural Gas Company v. Georgia-Pacific Corporation, Case No. 0601-00116, Multnomah County) declaring that, due to the rapid rise in the cost of natural gas after hurricanes Katrina and Rita, the Company acted in accordance with its tariffs and all applicable laws when it informed Georgia-Pacific that it would not sell Georgia-Pacific natural gas at its WACOG price. When Georgia-Pacific responded by filing the federal lawsuit described above, and removing the declaratory judgment action to the federal court on Feb. 2, 2006, NW Natural voluntarily dismissed its suit for declaratory relief, and now all matters between the parties are before the federal court. NW Natural will vigorously contest the claims of Georgia-Pacific.
Independent Backhoe Operator Action.Since May 2004 five lawsuits have been filed against the Company by 11 independent backhoe operators who performed backhoe services for the Company under contract. These five lawsuits have been consolidated into one consolidated case, Law and Zuehlke, et. al. v. Northwest Natural Gas Co., CV-04-728-KI. The remainingconsolidated case consolidates the following cases previously reported:Kerry Law and Arnold Zuehlke, on behalf of themselves and all other similarly situated v. Northwest Natural Gas Company (Filed May 28, 2004 U.S. Dist. Ct. D. Or. Case No. CV-04-728-KI),Ike Whittlesey, C.G. Nick Courtney, Mark Parrish, John J. Shooter, Roger Whittlesey and Philip Courtney v. Northwest Natural (Filed February 18, 2005 U.S. Dist. Ct. D. Or. Case No. CV-05-241-KI),Phillip Courtney v. Northwest Natural(Filed April 12, 2005 U.S. Dist. Ct. D. Or., Case No. CV-05-507-BR), andKenneth Holtmann et. al. v. Northwest Natural(Filed May 20, 2005 U.S. Dist. Ct. D. Or. Case No. 05-CV-00724-BR). The consolidated case also includes a fifth lawsuit filed on January 23, 2006,Larry L. Luethe v. Northwest Natural (U.S. Dist. Ct. D. Or. Case No. CV-06-098-MO).
Plaintiffs in the consolidated case are or have been independent backhoe operators who performed services for the Company under contract. Plaintiffs allege violation of the Fair Labor Standards Act for failure to pay overtime and also assert state wage and hour claims. Plaintiffs claim that they should have been considered “employees,” and seek overtime wages and interest in amounts to be determined, liquidated damages equal to the overtime award, civil penalties and attorneys’ fees and costs. Additionally, with the exception of the plaintiff inLarry L. Luethe v. Northwest Natural,plaintiffs allege that the failure to classify them as employees constituted a breach of contract and a tort under and with respect to certain unspecified employee benefits plans, programs and agreements. With the exception of the plaintiff inLarry L. Luethe v. Northwest Natural,plaintiffs seek an unspecified amount of damages for the value of what they would have received under these employee benefit plans if they had been classified as employees. The Company expects that the plaintiff inLarry L. Luethe v. Northwest Naturalwill amend his complaint to include these breach of contract and tort claims for unspecified damages.
In October 2005, the court granted the Company’s motion to stay plaintiffs’ claims pending exhaustion of the administrative review process with regard to each of the plans under which plaintiffs allege that they would have been eligible to receive benefits. The litigation is still stayed pending plaintiffs’ exhaustion of the administrative review process. There is insufficient information at this time to reasonably estimate the range of liability, forif any, from these claims. NW Natural will vigorously contest these claims and does not expect the outcome of this work is $9.2 million at Sept. 30, 2005.
litigation to have a material effect on its results of operations or financial condition.
Oregon Steel Mills site. In 2004, the Company was served with a third-party complaint by the Port of Portland (Port) in a Multnomah County Circuit Court case,Oregon Steel Mills, Inc. v. The Port of Portland.Portland. The Port alleges that in the 1940s and 1950s petroleum wastes generated by the Company’s predecessor, Portland Gas & Coke Company, and ten other third-party defendants were disposed of in a waste oil disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by Oregon Steel Mills. The Port’s complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future remedial action costs. In March 2005, motions to dismiss by the Company and other third-party defendants were denied on the basis that the failure of the Port to plead and prove that the Company was in violation of law was an affirmative defense that may be asserted at trial, but did not provide a sufficient basis for dismissal of the Port’s claim. No date has been set for trial and discovery is ongoing. The Company does not expect that the ultimate disposition of this matter will have a materially adverse affect on the Company’s financial condition, results of operations or cash flows.
Regulatory and Insurance Recovery for Environmental Matters. In May 2003, the OPUC approved NW Natural’s request for deferral of environmental costs associated with specific sites, including the Gasco, Siltronic, and Portland Harbor sites. The authorization, which has been extended through January 2006 and expanded to include the Oregon Steel Mills site, allows NW Natural to defer and seek recovery of unreimbursed environmental costs in a future general rate case. Through Sept. 30, 2005, the Company has paid a cumulative total of $5.4 million relating to the named sites since the effective date of the deferral authorization.
On a cumulative basis, NW Natural has recognized a total of $22.2 million for environmental costs, including legal, investigation, monitoring and remediation costs. Of this total, $10.2 million has been spent to-date and $12.0 million is reported as an outstanding liability. At Sept. 30, 2005, the Company had a regulatory asset of $17.4 million which includes $5.4 million of total expenditures to date and accruals for an additional estimated cost of $12.0 million. The Company believes the recovery of these costs is probable through the regulatory process. The Company also has an insurance receivable of $1.1 million, which is not included in the regulatory asset amount. The Company intends to pursue recovery of these environmental costs from its general liability insurance policies, and the regulatory asset will be reduced by the amount of any corresponding insurance recoveries. The Company considers insurance recovery probable based on a combination of factors, including a review of the terms of its insurance policies, the financial condition of the insurance companies providing coverage, a review of successful claims filed by other utilities with similar gas manufacturing facilities, and recent Oregon legislation that allows an insured party to seek recovery of “all sums” from one insurance company. The Company has not filed claims for insurance recovery nor have the insurance companies approved or denied coverage of these claims.
Legal Proceedings
The Company is subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings, including the matters described below, cannot be predicted with certainty, the Company does not expect that the ultimate disposition of these matters will have a materially adverse effect on the Company’s financial condition, results of operations or cash flows.
Independent Backhoe Operator Action.The Company previously reported the lawsuits filed against it in the consolidated cases ofKerry Law and Arnold Zuehlke, on behalf of themselves and all others similarly situated v. Northwest Natural Gas Company (U.S. Dist. Ct. D. Or. Case No. CV-04-728-KI),Ike Whittlesey, C.G. Nick Courtney, Mark Parrish, John J. Shooter, Roger Whittlesey and Philip Courtney v. Northwest Natural (U.S. Dist. Ct. D. Or. Case No. CV-05-241-KI), andKen Holtmann and Jeffrey Carl O’Neal v. Northwest Natural (U.S. Dist. Ct. D. Or. Case No. CV-05-724-KI). Ten plaintiffs remain in this consolidated case. The claims are more fully described in Part II, Item 8., Note 12, “Legal Proceedings,” in the 2004 Form 10-K.
Plaintiffs in the consolidated case are or have been independent backhoe operators who performed services for the Company under contract. Plaintiffs allege violation of the Fair Labor Standards Act for failure to pay overtime and also assert state wage and hour claims. Plaintiffs claim that they should have been considered “employees” of the Company, and seek overtime and interest to be proven, liquidated damages equal to the overtime award, civil penalties and attorneys’ fees and costs. Additionally, plaintiffs allege that the failure to classify them as employees constituted a breach of contract and a tort under and with respect to certain unspecified Company employee benefits plans. Plaintiffs seek an unspecified amount of damages for the value of what they would have received under these employee benefit plans if they had been classified as employees.
In October 2005, the court granted the Company’s motion to stay plaintiffs’ claims pending exhaustion of the administrative review process with regard to each of the plans under which plaintiffs allege that they would have been
eligible to receive benefits. There is insufficient information at this time to reasonably estimate the range of liability, if any, from these claims.
Industrial Customers Switching from Transportation to Sales Service
High natural gas prices have resulted in several of NW Natural’s large industrial transportation customers electing to receive gas commodity under sales service from NW Natural instead of arranging for their own supplies through independent third parties. Since these customers are electing the transfer to sales service after commodity rates were set in the annual PGA, the Company believes its tariff requires it to charge these customers the incremental cost of gas supply incurred by the Company to serve those customers. The Company has notified these customers that they will be charged the incremental gas costs, if any. Certain of these customers have notified the Company that they expected to be charged gas costs at the Company’s weighted average cost of gas price. The Company is working with the OPUC and customer groups to resolve the matter. If it is determined by the OPUC that NW Natural is not allowed to charge these customers its incremental costs, or if customers file suit and are awarded damages in future litigation, then the potential impact could be material to the Company’s financial results in 2005 and 2006, depending on the price and volume of incremental gas purchases.
| 8. | Comprehensive Income |
For the ninethree months ended Sept. 30,March 31, 2006 and 2005, and 2004, reported net income was equivalent to total comprehensive income (loss).income. Items that are excluded from net income and charged directly to common stock equity are accumulated in other comprehensive income (loss), net of tax. The amount of accumulated other comprehensive loss is $1.8$1.9 million at Sept. 30, 2005,March 31, 2006, which is included in common stock equity (see the accompanying Consolidated“Consolidated Statements of Capitalization,” above).
In September 2005, NW Natural entered into an agreement for unsecured lines of credit totaling $200 million with five commercial banks, replacing the existing $150 million credit facilities. The new bank lines of credit (bank lines) are available and committed for a term of five years, beginning Oct. 1, 2005 and expiring on Sept. 30, 2010. NW Natural’s bank lines are used primarily as back-up support for the notes payable under the Company’s commercial paper borrowing program. Commercial paper borrowing provides the liquidity to meet the working capital and external financing requirements of NW Natural. The Company received regulatory authorization for the new bank lines in October 2005.
Under the terms of these bank lines, NW Natural pays upfront fees and annual commitment fees but is not required to maintain compensating bank balances. The interest rates on outstanding loans, if any, under these bank lines are based on then-current market interest rates. All principal and unpaid interest under the bank lines is due and payable on Sept. 30, 2010.
The bank lines require that NW Natural maintain credit ratings with Standard & Poor’s and Moody’s Investors Service and to notify the banks of any change in its senior unsecured debt ratings by such rating agencies. A change in NW Natural’s credit rating is not an event of default, nor is the maintenance of a specific minimum level of credit rating a condition of drawing upon the bank lines. However, interest rates on any loans outstanding under these bank lines are tied to credit ratings, which would increase or decrease the cost of any loans under the bank lines when ratings are changed.
The bank lines also require the Company to maintain an indebtedness to total capitalization ratio of 65 percent or less. Failure to comply with this covenant would entitle the banks to terminate their lending commitments and to accelerate the maturity of all amounts outstanding. NW Natural was in compliance with an equivalent covenant in the prior year’s bank lines at Sept. 30, 2005, with an indebtedness to total capitalization ratio of 51.4 percent.
In June 2005, the Company issued and sold $50 million in principal amount of secured Medium Term Notes (MTNs), consisting of $40 million of the 4.70% Series B due 2015 and $10 million of the 5.25% Series B due 2035. Proceeds from these sales were used, in part, to redeem $15 million of maturing MTNs in July 2005 (see below), and the balance was applied to the Company’s ongoing utility construction program and the repayment of short-term debt.
In July 2005, the Company redeemed three series of its maturing MTNs aggregating $15 million in principal amount. The series redeemed were the 6.34% Series B, the 6.38% Series B and the 6.45% Series B, each with a principal
balance outstanding of $5 million due in July 2005. The MTNs were redeemed with proceeds from the sales of $50 million in principal amount of MTNs in June 2005 (see above).
In August, the Company redeemed all of its outstanding Convertible Debentures, 7-1/4% Series due 2012 (the Debentures), at 100% of the principal amount outstanding plus accrued unpaid interest to Aug. 31, 2005 (the redemption date). All but $0.5 million of the Debentures were converted into shares of the Company’s Common Stock on or before the redemption date at the rate of 50.25 shares for each $1,000 principal amount of Debentures. The Debentures were redeemed with cash from operations and proceeds from the sale of commercial paper.
PART I. FINANCIAL INFORMATION
| Item 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Northwest Natural Gas Company (NW Natural) is a natural gas services company primarily engaged in the distribution of natural gas to residential, commercial and industrial customers, operating as a regulated utility business in Oregon and southwest Washington. NW Natural also is engaged in the delivery of interstate and intrastate gas storage services, operating as a non-utility business segment principally regulated by the Federal Energy Regulatory Commission (FERC). The utility is our largest business segment with approximately 98 percent of consolidated total assets. Factors critical to the success of the utility include maintaining a safe and reliable distribution system, acquiring and distributing natural gas supplies and services at a competitive price, and being able to recover the operating and capital costs in the rates charged to customers.
The interstate gas storage segment represents approximately 2 percent of consolidated total assets. This business segment provides services to large customers using storage and transportation capacity and asset optimization services provided under an agreement with an independent energy marketing company. Factors critical to the success of our interstate gas storage segment include being able to develop additional interstate storage capacity at competitive market prices and being able to continue asset optimization services using core utility assets under a regulatory sharing agreement.
In addition to the utility and interstate gas storage business segments, the consolidated financial statements include the accounts of a wholly-owned subsidiary business, NNG Financial Corporation (Financial Corporation), and other non-regulated activities, which together are referred to in this report as our Other business segment (see Note 2).
The following is management’s assessment of Northwest Natural Gas Company’sNW Natural’s financial condition including the principal factors that affect our results of operations. The discussion refers to theour consolidated activities of the Company for the three and nine months ended Sept. 30, 2005March 31, 2006 and 2004. Unless otherwise indicated, references2005. References in this discussion to Notes“Notes” are to the notes to the accompanying consolidated financial statements.
The consolidated financial statements include the regulated parent company, Northwest Natural Gas Company (NW Natural), and its non-regulated wholly-owned subsidiaries:
Together these businesses are referred to herein as the “Company.” Inin this report, the term “utility” is used to describe the Company’s regulated gas distribution business and the term “non-utility” is used to describe its interstate gas storage business and other non-regulated activities (see Note 5).
report. In addition to presenting results of operations and earnings amounts in total, certain measures are expressed in cents per share. These amounts reflect factors that directly impact earnings. The Company believesWe believe this per share information is useful because it enables readers to better understand the impact of these factors on earnings. All references in this report to earnings per share in this report are on the basis of diluted shares, except where noted otherwise noted. See(see Part II, Item 8., Note 1, “Earnings Per Share,” in the Company’s 2004 Annual Report on Form 10-K (20042005 Form 10-K).
Issues and Challenges
There are a number of factors that directly affect our consolidated financial condition and results of operations. The most significant factor we face in the near term is the impact of higher gas prices. While wholesale gas prices have declined in recent months, the current forward market price for natural gas remains higher than the levels we currently have embedded in our utility customers’ rates, which means our customers’ rates are likely to increase this fall. The gas supply market tightened last year when hurricanes hit parts of the United States, and they remain tight early this year. We believe we have sufficient supplies of natural gas under contract to meet the needs of our firm customers, but further price increases could change our competitive advantage and our customers’ preference for natural gas. If higher gas prices persist, it could affect our ability to add residential and commercial customers and could result in industrial customers shifting their businesses’ energy needs to alternative fuel sources.
Other issues and challenges we could face in the future include unpredictable weather conditions, adverse regulatory actions or policy changes, managing gas supplies, storage and transportation capacity, managing customer growth, maintaining a competitive advantage, managing
environmental risks, and managing interest rate and credit risks. For a more complete discussion of these and other risks, see Part II, Item 7., “Issues, Challenges and Performance Measures,” and Part I, Item 1A., “Risk Factors,” in the 2005 Form 10-K.
Application of Critical Accounting Policies and Estimates
In preparing the Company’sour financial statements using generally accepted accounting principles in the United States of America (GAAP), management exercises judgment in the selection and application of accounting principles, including making estimates and assumptions that affect reported amounts of assets, liabilities, revenues, expenses and related disclosures in the financial statements. Management considers itsour critical accounting policies to be those thatwhich are most important to the representation of the Company’sour financial condition and results of operations and thatwhich require management’s most difficult and subjective or complex judgments, including accounting estimates that could result in materially different amounts if the Companywe reported under different conditions or using different assumptions.
The Company’sOur most critical estimates or judgments involve regulatory cost recovery, unbilled revenues, derivative instruments, pension assumptions, income taxes and environmental and other contingencies (see Part II, Item 7., “Application of Critical Accounting Policies and Estimates,” in the 20042005 Form 10-K). There have been no material changes to the information provided in the Company’s 2004our 2005 Form 10-K with respect to the application of critical accounting policies and estimates, except as indicated below under “Accounting for Derivative Instruments and Hedging Activities” and “Accounting for Contingencies.”estimates. Management has discussed its estimates and judgments used in the application of critical accounting policies with the Audit Committee of the Board.
Accounting for Derivatives InstrumentsWithin the context of our critical accounting policies and Hedging Activities
In the normal course of business, NW Natural enters into natural gas commodity purchase and sale contracts using physical assets owned or contractually obligated to the utility, including gas storage and pipeline transportation capacity. Prior to 2005, these contracts qualified for the normal purchase and normal sale exception as defined by Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149 (collectively referred to as SFAS No. 133) (see Note 4). In 2005, NW Natural entered into an agreement providing for natural gas commodity exchange transactions with an unaffiliated energy marketing company, which involved gas purchases by NW Natural originally intended for gas sales to utility customers. These exchanges resulted in the Company’s natural gas purchase contracts no longer qualifying for the normal purchase and normal sale exception under SFAS No. 133. As a result, these contracts are accounted for as derivative instruments and marked-to-market based on fair value pursuant to SFAS No. 133, effective March 31, 2005. The mark-to-market adjustment at Sept. 30, 2005 resulted in a net unrealized loss of $2.1 million, which was recorded on the balance sheet at fair value. Generally, these physical gas purchases are subject to regulatory deferral, and, as such, any unrealized gain or loss in the fair valueestimates, management is not recognized in current income but is recorded as a regulatory asset or regulatory liability pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (see Part II, Item 8., Note 1, in the 2004 Form 10-K) and included in cost of gas in annual rate changes under
the Company’s Purchased Gas Adjustment (PGA) tariffs. The Company’s estimate of fair value is determined by internal modeling based on natural gas index prices that are subject to market volatility and an evaluation of counterparty credit risk (see Item 3., “Quantitative and Qualitative Disclosures About Market Risk”). For estimated fair values (unrealized gains and losses) at Sept. 30, 2005 and 2004 and Dec. 31, 2004, see Note 4. As a result of these forward gas purchase contracts being classified as derivatives for accounting purposes, any related financial derivative instruments (e.g., financial swaps and call options) previously designated as hedge instruments against the physical gas purchase contracts, no longer qualify for hedge accounting under SFAS No. 133. Therefore, the financial swap and call option contracts are no longer designated as cash flow hedges although they continue to economically hedge the financial risk exposure of the underlying physical gas purchase contracts. The change from hedge accounting treatment had no income statement effect due to the application of SFAS No. 71 for unrealized gains and losses on hedge contracts expected to be included in the determination of future gas rates.
Accounting for Contingencies
Loss contingencies are recorded as liabilities when it is probable that a liability has been incurred and the amount of the loss is reasonably estimable in accordance with SFAS No. 5, “Accounting for Contingencies.” NW Natural updates its estimates of loss contingencies and related disclosures when new information becomes available. Estimating probable losses requires an analysis of uncertainties that often depend upon judgments about potential actions by third parties, and NW Natural records accruals for loss contingencies based on an analysis of potential results, developed in consultation with outside counsel and consultants when appropriate. When information is sufficient to estimate only a range of potential liabilities, and no point within the range is more likely than any other, the Company recognizes an accrued liability at the lower end of the range and discloses the range (see “Contingencies,” below.) It is possible, however, that the range of potential liabilities could be significantly different than amounts currently accrued and disclosed, and the Company’s financial condition and results of operations could be materially affected by changes in assumptions or estimates related to these contingencies.
With respect to its environmental liabilities and related costs, NW Natural develops estimates based on currently available information, existing technology and environmental regulations. NW Natural received regulatory approval to defer and seek recovery of costs related to certain sites and believes the recoveryaware of any costs not recovered under its general liability insurance policies is probable through the regulatory process (see Note 7). In accordance with SFAS No. 71, the Company has recorded a regulatory asset for the amount expected to be recovered. The Company intends to pursue recovery for these environmental costs from its general liability insurance policies, and the regulatory asset will be reduced by the amount of any corresponding insurance recoveries. At Sept. 30, 2005, $17.4 millionreasonably likely events or circumstances that would result in environmental costs have been recorded as a regulatory asset, including $5.4 million of costs paid to-date and $12.0 million has been accrued for estimated future environmental costs. If it is determined that both the insurance recovery and future rate recovery of such costs are not probable, then the costs will be charged to expense in the period such determination is made.
materially different amounts being reported.
Earnings and Dividends
Three months ended Sept. 30, 2005 compared to Sept. 30, 2004
The Company incurred a consolidated loss of $8.7Net income was $41.0 million, or 31 cents$1.48 a share, for the three months ended Sept. 30, 2005,March 31, 2006, as compared to a loss of $8.3$39.9 million, or 30 cents a share, for the third quarter of 2004. The third quarter loss for both years was attributable to the Company’s utility operations, which recorded losses of $10.5 million and $9.4 million for the three months ended Sept. 30, 2005 and 2004, respectively. A loss from utility operations is typical during the third quarter due to the lower summertime use of natural gas. With respect to the Company’s non-utility operating results, the interstate gas storage business recorded net income of $1.6 million for the three months ended Sept. 30. 2005, compared to net income of $0.6 million for the same period last year, and other non-regulated business activities earned $0.2 million in the 2005 period compared to $0.5 million in 2004.
The increase in third quarter consolidated net loss was primarily due to:
an increase in the utility’s net operating revenues (margin) of $3.1 million or 8 percent, largely offsetting the increase in utility operating expenses (see above), due to general rate increases in Oregon in 2003 and 2004 and in Washington in 2004 to recover the higher cost of service for new plant
|
Nine months ended Sept. 30, 2005 compared to Sept. 30, 2004
Consolidated net income was $32.4 million, or $1.17 a share, for the nine months ended Sept. 30, 2005, compared to $23.6 million, or $0.88$1.43 a share, for the same period of 2004.last year. The increase in net income was attributable to improved results from our regulated utility and interstate gas storage segments. In the nine months ended Sept. 30, 2005, the Companyfirst quarter of 2006, we earned $28.4$39.5 million, or $1.43 a share, from utility operations $3.3representing an increase of $0.7 million, or 3 cents a share, over the prior year; and we earned $1.4 million, or 5 cents a share, from interstate gas storage operations and $0.7 million from other non-regulated activities compared, respectively, to $20.8 million, $2.1 million and $0.8 million in the nine months ended Sept. 30, 2004.
The increase in year-to-date consolidated net income was primarily due to:
First quarter of 2006 compared to first quarter of 2005:
Primary factors affecting first quarter earnings this year over last year primarily due to rate increases for new plant investments, and to customer growth and improved industrial margins;
a positive margin contribution of $1.8 million this year, representing a sharing of utility gas cost savings as comparedunder the Purchased Gas Adjustment (PGA) incentive mechanism, was equivalent to thelast
year’s contribution from gas cost savings, with commodity prices for the two periods mostly hedged and included in customer rates through the annual PGA; |
Dividends paid on common stock were largely covered by revenue increases approved34.5 cents and 32.5 cents a share in the most recent general rate cases in Oregon and Washington.
The Company paid dividends on its common stock of 32.5 cents per share in each of the three monththree-month periods ended Sept. 30,March 31, 2006 and 2005, and 2004, and paid dividends of 97.5 cents per share in each ofrespectively. In April 2006, the nine month periods ended Sept. 30, 2005 and 2004. On Oct. 12, 2005, theCompany’s Board of Directors declared a quarterly dividend of 34.5 cents per share, an increase of 2 cents pera share on the Company’s common stock, payable Nov.May 15, 2005.2006, to shareholders of record on April 28, 2006. The newcurrent indicated annual dividend rate is $1.38 pera share.
Results of Operations
Regulatory Developments
NW Natural providesWe provide gas utility service in Oregon and Washington, with Oregon representing over 90 percent of its revenues and cash flows.our utility revenues. Future earnings and cash flows from utility operations will be determined by, among other factors, the Company’sour ability to obtain reasonable and timely regulatory ratemaking treatment for its operating expenses and investments in utility plant. See Part II, Item 7., “Results of Operations—Operations– Regulatory Matters,” in the 20042005 Form 10-K.
Rate Mechanisms
Weather Normalization. In November 2003, the Oregon Public Utility Commission (OPUC) authorized, and NW Natural implemented, a weather normalization mechanism in Oregon that helps stabilize utility margins by adjusting customer billings based on temperature variances from average weather. The weather normalization mechanism applies only to Oregon residential and commercial customers, and the adjustment is in effect on customer bills from Nov. 15 to May 15 of each heating season. See “Comparison of Gas Distribution Operations (Utility),” below and Part II, Item 7., “Results of Operations—Regulatory Matters—Weather Normalization,” in the 2004 Form 10-K.
As part of the approval of NW Natural’s weather normalization mechanism, NW Natural was required to file a report reviewing the first two years of the mechanism’s operation. On Oct. 19, 2005, the Company filed the required report, which reviewed weather normalization programs in other states, analyzed the weather sensitivity of NW Natural customers, simulated program outcomes, discussed the financial effects of using incorrect normal weather definitions, reviewed service quality issues and assessed the opt-out provision. The report concluded that the weather normalization mechanism operated to benefit the Company and its customers. The weather normalization mechanism is effective through September 2008.
Purchased Gas Adjustment.Rate changes are applied each year under the PGA mechanisms in NW Natural’sour tariffs in Oregon and Washington to reflect changes in the costs of natural gas commodity purchased under contracts with gas producers, the application of temporary rate adjustments to amortize balances in deferred regulatory asset and liability accounts and the removal of temporary rate adjustments effective for the previous year. The OPUC
Under the current PGA mechanisms, we collect an amount for purchased gas costs based on estimates included in rates. If the actual purchased gas costs are higher than the amounts included in rates, we are not allowed to charge customers immediately for the higher costs but defer the costs and collect them in the Washington Utilitiesfuture. Similarly, when the actual purchased gas costs are lower than the amounts included in rates, the gas cost savings are not immediately returned to customers but are deferred and Transportation Commission (WUTC) approved rate increases on Sept. 22, 2005 and Sept. 28, 2005, respectively, effective Oct. 1, 2005. Inrefunded to customers in future periods. As part of an incentive mechanism in Oregon, the combined effectwe charge 33 percent of the rate change ishigher cost of gas sold, or credit 33 percent of the lower cost, to increase the average monthly bills of residential and commercial sales customers by 15.2 percent and 16.6 percent, respectively.earnings. In Washington, the combined effectPGA is currently based on pass-through of 100 percent of the rate change is to increase the average monthly billsactual cost of residentialgas sold.
Regulatory and commercial sales customers by 12.0 percent and 12.1 percent, respectively.
Insurance Recovery for Environmental Matters.In the fourth quarter of 2004, the staff ofMay 2003, the OPUC initiated a reviewapproved NW Natural’s request for deferral of gas purchasing strategies for all three local gas distribution companies serving Oregon customers,environmental costs associated with specific sites, including the Gasco, Siltronic and a report was issued by the OPUC in June 2005.Portland Harbor sites. The OPUC reviewedauthorization, which has been extended through January 2007 and acknowledged the report and accepted the OPUC staff’s proposed administrative recommendations. Although the report did not result in any change in the Company’s gas purchasing strategies, as a result of the OPUC’s review and the 2005 PGA increase, the OPUC staff has initiated a series of informal workshopsexpanded to discussinclude the Oregon PGA mechanism design. Workshops are scheduledSteel Mills site, allows NW Natural to begindefer and seek recovery of unreimbursed environmental costs in November and conclude in mid-January 2006. Management believes it is likely that a formal proceeding will be established to determine if changes to the current PGA mechanism are warranted.
Conservation Tariff.future general rate case. In October 2002,April 2006, the OPUC authorized NW Natural to implementaccrue interest on deferred balances effective Jan. 27, 2006, subject to an annual demonstration to the OPUC that we have maximized our insurance recovery or made substantial progress in securing insurance recovery for unrecovered environmental expenses. As of March 31, 2006, we have paid a “conservation tariff,”cumulative total of $14.4 million relating to the named sites since the effective date of the deferral authorization.
On a cumulative basis, NW Natural has recognized a total of $24.0 million for environmental costs, including legal, investigation, monitoring and remediation costs. Of this total, $19.3 million has been spent to-date and $4.7 million is reported as an outstanding liability. At March 31, 2006, we had a regulatory asset of $19.1 million which includes $14.4 million of total expenditures to date and accruals for additional estimated costs of $4.7 million. We believe the recovery of these costs is probable through the regulatory process after first pursuing recovery of costs from insurance. We also have an insurance receivable of $1.1 million, which is a mechanism designed to adjust margin revenues to compensate the utility for declining usage due to residential and commercial customers’ conservation efforts. The tariff was a partial decoupling mechanism that was intended to break the link between the Company’s earnings and the quantity of energy consumed by its customers, so the Company does not have an incentive to discourage customers from taking measures to reduce energy use. On average, residential and commercial customers have continued to reduce energy consumption over the past several years in response to the impact of higher energy prices on their utility bills and increased awareness of energy efficiency programs.
The conservation tariff included two components. The first component was a price elasticity adjustment, which adjusts for anticipated increases or decreases in consumption attributable to annual changes in commodity costs or periodic changes in the Company’s general rates. The second component was a conservation adjustment calculated on a monthly basis to account for deviations between actual and expected volumes (decoupling adjustment). Additional charges or credits to customers resulting from the decoupling adjustment are recorded to a deferral account, which is included in the next year’s annual PGA. Baseline consumption was determinedregulatory asset amount. We intend to pursue recovery of these environmental costs from our general liability insurance policies, and the regulatory asset will be reduced by customer consumption data used in the 2003 Oregon general rate case, adjusted for added consumption resulting from new customers. See “Comparisonamount of Gas Distribution Operations (Utility),” below and Part II, Item 7., “Results of Operations—Regulatory Matters—Conservation Tariff,” in the 2004 Form 10-K.
The conservation tariff was scheduled to expire at the end of September 2005, unless the OPUC approved an extensionany corresponding insurance recoveries. We consider insurance recovery probable based on the resultsa combination of an independent study to measure the mechanism’s effectiveness. The independent study was completed earlier this year, andfactors, including a report was submitted to the OPUC on March 31, 2005 along with a request by the Company to open an investigation to determine whether the conservation tariff should be continued, modified or eliminated. The independent study report recommended continuationreview of the conservation tariffterms of our insurance policies, the financial condition of the insurance companies providing coverage, a review of successful claims filed by other utilities with minor modifications.similar gas manufacturing facilities, and recent Oregon legislation that allows an insured party to seek recovery of “all sums” from one insurance company. We have not filed claims for insurance recovery nor have the insurance companies approved or denied coverage of these claims.
On July 26, 2005, the Company and several parties to the proceeding agreed toGeo-hazard Program. We entered into a stipulation to support the continuation of the conservation tariff for an additional four years, through Sept. 30, 2009, and to increase the mechanism’s
coverage from a partial decoupling of 90 percent of residential and commercial gas usage to a full decoupling of 100 percent. The stipulation was approved by the OPUC on Aug. 25, 2005.
OPUC Audit
In 2004, the OPUC approved a stipulation among NW Natural, the OPUC staff and two parties in NW Natural’s 2003 Oregon general rate case. The stipulation provided for the settlement of issues in an investigation initiated bywith the OPUC in 2003 relating2001 for an enhanced pipeline safety program that included an accelerated bare steel replacement program and a geo-hazard safety program. The geo-hazard safety program included the identification, assessment and remediation of risks to NW Natural’s transactionspiping infrastructure created by landslides, washouts, earthquakes or interests in certain properties in the vicinity of the Company’s headquarters building in downtown Portland, and the use of some of these properties for employee parking.similar occurrences. The stipulation allowed NW Natural agreed into receive deferred accounting rate treatment commencing Oct. 1, 2002, for costs associated with the stipulation to undergo an audit in 2005 funded by the Company. The audit commenced in August 2005 and is focused on financial hedging transactions, deferred taxes, tax credits, the Coos Bay distribution system project, securities issuances, the calculation of allowance for funds used during construction (AFUDC), and affiliated interest transactions. The consultant conducting the audit on behalf of the OPUC staff is expected to issue a report to the OPUC in the fourth quarter of 2005.
Oregon Billing Service Quality Measure
On Sept. 22, 2005, the OPUC approved a new billing service quality measure for Oregon customers. The measure requires billing accuracy, after certain exclusions, of 99.4 percent each month. If billing accuracy falls below 99.4 percent, a remedy of $50,000 per month may be imposed, up to a maximum of $0.3programs exceeding $3 million per year. The quality measure becomes effective Jan. 1,authority to defer expenses for costs associated with the geo-hazard program expires on Dec. 31, 2006. The Company does not expect the billing service quality measure to have a material effect on the Company’s financial condition, results of operations or cash flows.
Income TaxUtility Regulation Legislation
On Aug. 1,During 2005, the Oregon legislature passed and Oregon’s Governor signed into law Senate Bill (SB) 408, effective for taxes collected on or after Jan. 1, 2006, which2006. This legislation requires the OPUC to establish an annual tax adjustment to ensure that Oregon utilities do not collect in rates more income taxes than they actually pay to government entities. The bill, which was signed into law on Sept. 2,See Part I, Item 1., “Regulation and Rates—Utility Regulation Legislation,” Part IA., “Risk Factors,” and Part II, Item 7., “Results of Operations—Regulatory Matters—Utility Regulation Legislation,” in the 2005 requires that the OPUC interpret the bill’s provisions to determine how the tax adjustment will be applied.Form 10-K. The OPUC has issued temporary rules and, on Oct. 14, 2005, NW Natural filed with the OPUC its first three-year tax report showing the amount of taxes NW Natural paid (accordingcontinues to the definitions in SB 408) compared with the amount of taxes it was authorized to collect in rates for each of the calendar years 2002, 2003 and 2004. NW Natural’s report concluded that, based on the calculations required by the temporary rules, the Company paid more in taxes than the amount of taxes it was authorized to collect in rates. This report was not required for the purpose of determining rate adjustments, and these results are not necessarily indicative of future calculations. The report, as well as reports submitted by other utilities, is intended to help the OPUC develop rules required to implement SB 408.408 and draft rules are expected to be filed by the OPUC staff in July 2006, with final adoption of rules scheduled for September 2006. Due to themany uncertainties related to the OPUC’s interpretations and rule making with respect to the application of the bill’s provisions, the Company iswe are not able to determine at this time what impact, if any, the new legislation will have on the Company’sour financial condition, results of operations or cash flows.flows, but the impact may be material.
Comparison of Gas Distribution Operations (Utility)
The following tables summarizetable summarizes the composition of utility volumes, operating revenues and revenuesmargin for the three and nine months ended Sept. 30:March 31:
Three Months Ended September 30, | ||||||||||||||
(Thousands, except customer count and degree day data) | 2005 | 2004 | ||||||||||||
| Utility volumes - therms: | ||||||||||||||
Residential and commercial sales | 53,182 | 29 | % | 52,762 | 28 | % | ||||||||
Industrial sales and transportation | 128,231 | 71 | % | 132,409 | 72 | % | ||||||||
Total utility volumes sold and delivered | 181,413 | 100 | % | 185,171 | 100 | % | ||||||||
| Utility operating revenues - dollars: | ||||||||||||||
Residential and commercial sales | $ | 67,248 | 64 | % | $ | 57,301 | 72 | % | ||||||
Industrial sales and transportation | 36,767 | 36 | % | 23,615 | 29 | % | ||||||||
Other revenues | (513 | ) | 0 | % | (858 | ) | (1 | %) | ||||||
Total utility operating revenues | $ | 103,502 | 100 | % | $ | 80,058 | 100 | % | ||||||
Cost of gas sold | 62,241 | 41,944 | ||||||||||||
Utility net operating revenues (margin) | $ | 41,261 | $ | 38,114 | ||||||||||
| Margin | ||||||||||||||
Residential and commercial sales | $ | 38,888 | 94 | % | $ | 35,788 | 94 | % | ||||||
Industrial sales and transportation | 11,146 | 27 | % | 10,064 | 26 | % | ||||||||
Miscellaneous revenues | 927 | 2 | % | 717 | 2 | % | ||||||||
Other margin adjustments | (8,887 | ) | (22 | %) | (7,439 | ) | (20 | %) | ||||||
Margin before weather normalization and decoupling | 42,074 | 101 | % | 39,130 | 102 | % | ||||||||
Weather normalization adjustment | (2 | ) | 0 | % | (2 | ) | 0 | % | ||||||
Conservation decoupling adjustment | (811 | ) | (1 | %) | (1,014 | ) | (2 | %) | ||||||
Margin | $ | 41,261 | 100 | % | $ | 38,114 | 100 | % | ||||||
Total number of customers (end of period) | 602,486 | 582,457 | ||||||||||||
Actual degree days | 101 | 76 | ||||||||||||
Percent colder (warmer) than normal | (1 | %) | (16 | %) | ||||||||||
Thousands, except degree day and customer data | 2006 | 2005 | |||||||||||
Utility volumes - therms: | |||||||||||||
Residential and commercial sales | 253,899 | 62 | % | 230,683 | 62 | % | |||||||
Industrial sales and transportation | 154,037 | 38 | % | 138,487 | 38 | % | |||||||
Total utility volumes sold and delivered | 407,936 | 100 | % | 369,170 | 100 | % | |||||||
Utility operating revenues - dollars: | |||||||||||||
Residential and commercial sales | $ | 326,785 | 84 | % | $ | 258,542 | 84 | % | |||||
Industrial sales and transportation | 61,911 | 16 | % | 42,991 | 14 | % | |||||||
Other revenues | (1,440 | ) | — | % | 5,153 | 2 | % | ||||||
Total utility operating revenues | $ | 387,256 | 100 | % | $ | 306,686 | 100 | % | |||||
Cost of gas sold | 255,384 | 180,567 | |||||||||||
Revenue taxes | 9,528 | 7,183 | |||||||||||
Utility net operating revenues (margin) | $ | 122,344 | $ | 118,936 | |||||||||
Utility margin:(1) | |||||||||||||
Residential sales | $ | 78,348 | 64 | % | $ | 70,055 | 59 | % | |||||
Commercial sales | 31,777 | 26 | % | 27,675 | 23 | % | |||||||
Industrial - firm sales and transportation | 3,608 | 3 | % | 3,741 | 3 | % | |||||||
Industrial - interruptible sales and transportation | 4,878 | 4 | % | 5,058 | 4 | % | |||||||
Miscellaneous revenues | 1,503 | 1 | % | 1,898 | 2 | % | |||||||
Other margin adjustments | 1,440 | 1 | % | 2,465 | 2 | % | |||||||
Margin before regulatory mechanism adjustments | 121,554 | 99 | % | 110,892 | 93 | % | |||||||
Weather normalization mechanism | 1,842 | 2 | % | 3,246 | 3 | % | |||||||
Decoupling mechanism | (1,052 | ) | (1 | %) | 4,798 | 4 | % | ||||||
Utility margin | $ | 122,344 | 100 | % | $ | 118,936 | 100 | % | |||||
Total number of customers (end of period) | 624,297 | 603,330 | |||||||||||
Actual degree days | 1,814 | 1,769 | |||||||||||
Percent colder (warmer) than average | (3%) | (5%) | |||||||||||
| (1) | Amounts reported as margin for each category of customer is net of demand charges and revenue taxes. In prior years, customer margin by category did not reflect these costs but have been revised to be consistent with the current year’s presentation. We believe the current presentation is a better representation of the margin earned from each class of customer. |
Nine Months Ended September 30, (Thousands, except degree day data) Utility volumes - therms: Residential and commercial sales Industrial sales and transportation Total utility volumes sold and delivered Utility operating revenues - dollars: Residential and commercial sales Industrial sales and transportation Other revenues Total utility operating revenues Cost of gas sold Utility net operating revenues (margin) Margin Residential and commercial sales Industrial sales and transportation Miscellaneous revenues Other margin adjustments Margin before weather normalization and decoupling Weather normalization adjustment Conservation decoupling adjustment Margin Actual degree days Percent colder (warmer) than normal 2005 2004 382,610 48 % 378,199 48 % 407,713 52 % 413,999 52 % 790,323 100 % 792,198 100 % 439,213 78 % $ 363,251 82 % 117,409 21 % 74,654 17 % 5,213 1 % 2,762 1 % $ 561,835 100 % $ 440,667 100 % 335,186 241,360 $ 226,649 $ 199,307 $ 232,999 103 % $ 212,339 107 % 34,381 15 % 30,498 15 % 4,047 2 % 2,900 1 % (49,310 ) (22 %) (51,222 ) (26 %) 222,117 98 % 194,515 97 % 2,516 1 % 5,418 3 % 2,016 1 % (626 ) 0 % $ 226,649 100 % $ 199,307 100 % 2,522 2,352
(25-year average degree days is used as normal) (5 %) (10 %)
Total utility volumes sold and delivered in the three- and nine-month periods ended Sept. 30, 2005 decreased 2 percent and less than 1 percent, respectively, compared to the corresponding 2004 periods, primarily reflecting lower volumes delivered to large industrial customers under special contracts.
NW Natural’s customer base continued to increase, with a net increase of 20,029 customers since Sept. 30, 2004, for a growth rate of 3.4 percent. In the three years ended Dec. 31, 2004, more than 55,000 customers were added to the system, representing an annual growth rate of 3.4 percent.
NW Natural’sOur utility results are affected, among other things, by customer growth and by changes in weather and customer consumption patterns, with a significant portion of itsour earnings being derived from natural gas sales to residential and commercial customers. In 2002,order to offset the potential volatility in utility earnings caused by these factors, we obtained OPUC approvedapproval of a conservation tariff that
adjusts margin up or down based on changes in residential and commercial customer consumption;consumption and in 2003, the OPUC approved a weather normalization mechanism that adjusts customer bills, and Companyour margin, based on above- or below-average temperatures during the winter heating season (see Part II, Item 7., “Results of Operations—Regulatory Developments—Matters—Rate Mechanisms,” above). Both mechanisms are designed to reducein the volatility2005 Form 10-K).
Total utility volumes sold and delivered in the first quarter of the Company’s utility earnings.
Three months ended Sept. 30, 20052006 increased 11 percent compared to Sept. 30, 2004
the first quarter of 2005. In the three months ended Sept. 30,March 31, 2006, weather was 3 percent colder than the comparable period in 2005, weather, although 1but 3 percent warmer than normal, was 33 percent colder than last year, largely contributingaverage.
Customer growth has continued to remain strong, with a 9 percentnet increase in margin from residential and commercial sales. The weather normalization mechanism covers customer bills during the period from November 15 to May 15 of each year and therefore does not cover volume fluctuations due to weather in the third quarter. The conservation tariff’s decoupling mechanism, which adjusts margin after the20,967 customers since March 31, 2005, or an annual Oregon PGA mechanism is set based on expected volume changes due to price elasticity, reduced margin by $0.8 million in the third quartergrowth rate of 2005 compared to a reduction of $1.0 million in the third quarter of 2004.
Other margin adjustments, which include pipeline demand charges, unaccounted-for gas charges and other regulatory gas cost and revenue adjustments, reduced margin by $8.9 million in the third quarter of 2005 compared to a margin reduction of $7.4 million in 2004. The increase in net deductions from other margin adjustments was primarily due to lower pipeline demand charge deferrals resulting from increased industrial firm sales volumes and to higher unaccounted-for gas charges as compared to last year’s third quarter.
Nine months ended Sept. 30, 2005 compared to Sept. 30, 2004
3.5 percent. In the nine monthsthree years ended Sept. 30,Dec. 31, 2005, weather was 7 percent coldermore than last year, which contributed largely to a 10 percent increase in margin from residential and commercial sales. The weather normalization mechanism covers most57,000 customers were added, representing an average annual growth rate of the temperature variances during the first nine months of the calendar year because most of the heating degree days in the period occur between January 1 and May 15, a period in which the weather in 2005 was 5 percent warmer than normal. As a result, the weather normalization mechanism contributed $2.5 million to margin in the nine months ended Sept. 30, 2005, and contributed $5.4 million to margin in the same period of 2004 based on weather that was 10 percent warmer than normal. The decoupling mechanism contributed $2.0 million to margin in the first nine months of 2005, after adjusting for price elasticity in the annual Oregon PGA, compared to a reduction of $0.6 million in 2004.
Other margin adjustments, which include pipeline demand charges, unaccounted-for gas charges and other regulatory gas cost and revenue adjustments, reduced margin by $49.3 million in the first nine months of 2005 compared to $51.2 million in 2004. The decrease in net deductions from other margin adjustments was primarily due to higher cost of gas savings in the current year-to-date period as compared to last year.
3.3 percent.
Residential and Commercial Sales
Results of operations in the residential and commercial sales markets are largely impacted by seasonal weather patterns, energy prices, competition from alternative energy sources and economic conditions in our service areas. The following table summarizes the utility volumes and utility operating revenues in the residential and commercial markets. The primary factors that impactmarkets for the results of operations in these markets are seasonal weather, energy prices, competition and economic conditions in the Company’s service areas.three months ended March 31:
Three Months Ended Sept. 30, | Nine Months Ended Sept. 30, | ||||||||||||||
(Thousands, except customers) | 2005 | 2004 | 2005 | 2004 | |||||||||||
Utility volumes - therms: | |||||||||||||||
Residential sales | 27,877 | 26,198 | 258,377 | 260,012 | |||||||||||
Commercial sales | 25,574 | 24,106 | 166,431 | 168,071 | |||||||||||
Change in unbilled sales | (269 | ) | 2,458 | (42,198 | ) | (49,884 | ) | ||||||||
Total weather-sensitive utility volumes | 53,182 | 52,762 | 382,610 | 378,199 | |||||||||||
Utility operating revenues - dollars: | |||||||||||||||
Residential sales | $ | 40,324 | $ | 33,256 | $ | 316,463 | $ | 267,186 | |||||||
Commercial sales | 27,372 | 22,044 | 169,598 | 141,546 | |||||||||||
Change in unbilled sales | (448 | ) | 2,001 | (46,848 | ) | (45,481 | ) | ||||||||
Total weather-sensitive utility revenues | $ | 67,248 | $ | 57,301 | $ | 439,213 | $ | 363,251 | |||||||
Total number of customers (end of period) | 601,543 | 581,526 | 601,543 | 581,526 | |||||||||||
Thousands, except customers Utility volumes - therms: Residential sales Commercial sales Change in unbilled sales Total weather-sensitive utility volumes Utility operating revenues - dollars: Residential sales Commercial sales Change in unbilled sales Total weather-sensitive utility revenues Total number of customers (end of period) 2006 2005 176,111 158,931 103,316 93,349 (25,528 ) (21,597 ) 253,899 230,683 $ 238,383 $ 189,252 121,700 94,422 (33,298 ) (25,132 ) $ 326,785 $ 258,542 623,353 602,388
Three months ended Sept. 30, 2005First quarter of 2006 compared to Sept. 30, 2004first quarter of 2005:
The primary factors affecting residential and commercial volumes and operating revenues in the three months ended Sept. 30, 2005 compared to the corresponding period in 2004 were:first quarter this year over last year include:
Nine months ended Sept. 30, 2005 compared to Sept. 30, 2004
The primary factors affecting residential and commercial volumes and operating revenues in the nine months ended Sept. 30, 2005 compared to the corresponding period in 2004 were:
Typically, 80 percent or more of annual utility operating revenues are derived from gas sales to weather-sensitive residential and commercial customers. Although variations in temperatures between periods will affect the volumes of gas sold to these customers, the effect on margin and net income
is significantly reduced withdue to the weather normalization mechanism andin Oregon. This mechanism applies to approximately 92 percent of our Oregon customers. In Washington, our customers are not covered by a weather normalization mechanism, where approximately 10 percent of our customers are served. So the conservation tariff (see “Comparisonmechanism does not fully insulate us from utility earnings volatility due to weather. The mechanism contributed a net $1.8 million of Gas Distribution Operations (Utility),” above.
margin on weather that was 3 percent warmer than normal in the three month period ended March 31, 2006, compared to $3.2 million on weather that was 5 percent warmer than normal in the first three months of 2005.
Total utility operating revenues include accruals for gasunbilled revenues (gas delivered but not yet billed to customers (unbilled revenues)customers) based on estimates of gas deliveries from that month’s meter reading dates to month end. Amounts reported as unbilled revenues reflect the increase or decrease in the balance of accrued unbilled revenues compared to the prior year-end. Weather conditions, rate changes and customer billing dates affect the balance of accrued unbilled revenuerevenues at the end of each month. At Sept. 30, 2005,March 31, 2006 accrued unbilled revenue was $16.8$47.8 million compared to $14.0$38.9 million at Sept. 30, 2004.March 31, 2005.
Industrial Sales and Transportation
The following table summarizes the delivered volumes and utility operating revenues in the industrial sales and transportation market:market for the three months ended March 31:
| Three Months Ended Sept. 30, | Nine Months Ended Sept. 30, | |||||||||||||||||
(Thousands, except customers) | 2005 | 2004 | 2005 | 2004 | ||||||||||||||
Utility volumes - therms: | ||||||||||||||||||
Thousands, except customers | 2006 | 2005 | ||||||||||||||||
Utility volumes - therms: | ||||||||||||||||||
Industrial - firm sales | 14,855 | 13,191 | 53,416 | 45,858 | 24,151 | 21,738 | ||||||||||||
Industrial - firm transportation | 33,398 | 43,723 | 99,710 | 135,838 | 29,743 | 29,097 | ||||||||||||
Industrial - interruptible sales | 35,303 | 23,299 | 106,751 | 70,655 | 43,188 | 36,318 | ||||||||||||
Industrial - interruptible transportation | 44,675 | 52,196 | 147,836 | 161,648 | 56,955 | 51,334 | ||||||||||||
Total utility volumes | 128,231 | 132,409 | 407,713 | 413,999 | 154,037 | 138,487 | ||||||||||||
Utility operating revenues - dollars: | ||||||||||||||||||
Utility operating revenues - dollars: | ||||||||||||||||||
Industrial - firm sales | $ | 12,238 | $ | 9,049 | $ | 43,285 | $ | 30,602 | $ | 23,752 | $ | 17,544 | ||||||
Industrial - firm transportation | 941 | 1,236 | 3,055 | 3,782 | 948 | 1,087 | ||||||||||||
Industrial - interruptible sales | 21,846 | 11,437 | 65,835 | 34,472 | 35,352 | 22,613 | ||||||||||||
Industrial - interruptible transportation | 1,742 | 1,893 | 5,234 | 5,798 | 1,859 | 1,747 | ||||||||||||
Total utility operating revenues | $ | 36,767 | $ | 23,615 | $ | 117,409 | $ | 74,654 | $ | 61,911 | $ | 42,991 | ||||||
Total number of customers (end of period) | 943 | 931 | 943 | 931 | 944 | 942 | ||||||||||||
Three months ended Sept. 30, 2005 comparedTotal volumes delivered to Sept. 30, 2004
The primary factors affecting industrial sales and transportation volumes and operating revenuescustomers were up 15.6 million therms, or 11 percent, in the three months ended Sept. 30, 2005first quarter of 2006 as compared to the same period in 2004 include:
Nine months ended Sept. 30, 2005 compared to Sept. 30, 2004
The primary factors affecting industrial sales and transportation volumes and operating revenues in the nine months ended Sept. 30,customers decreased by $0.3 million, or 4 percent, over 2005, compared to the same period in 2004 include:
57 percent higher operating revenues due to increases in customer rates, which include the higher commodity prices passed througha mark-to-market loss related to customers in the annual PGA (see “Costa temporary valuation of Gas Sold,” below), and toa gas sale contract.
|
High natural gas prices have resulted in a number of NW Natural’s large industrial customers switching from transportation service, where they arranged for their own supplies through independent third parties, to receiving gas commodity under sales service from NW Natural. The Company’s tariff requires it to charge these customers the incremental cost of gas supply incurred by the Company to serve those customers. See Note 7.
Other Revenues
Other revenues include miscellaneous fee income as well as utility revenue adjustments reflecting deferrals to, or amortizations from, regulatory asset or liability accounts other than deferrals relating to gas costs (see Part II, Item 8., Note 1, “Industry Regulation,”Regulation”, in the 20042005 Form 10-K). Other revenues decreased net operating revenues by $0.5$1.4 million in the thirdfirst quarter of 20052006, compared to a reductionan increase of $0.9$5.2 million in the thirdfirst quarter of 2004. Other revenues increased net operating revenues by $5.2 million and $2.8 million for the first nine months of 2005 and 2004, respectively.2005. The following table summarizes other revenues by primary category:category for the three months ended March 31:
| Three Months Ended Sept. 30, | Nine Months Ended Sept. 30, | |||||||||||||||
(Thousands) | 2005 | 2004 | 2005 | 2004 | ||||||||||||
Revenue adjustments: | ||||||||||||||||
Current deferrals: | ||||||||||||||||
Conservation decoupling | $ | (811 | ) | $ | (1,013 | ) | $ | 2,016 | $ | (625 | ) | |||||
South Mist pipeline extension | (129 | ) | 195 | 164 | 1,475 | |||||||||||
Coos Bay distribution system | 111 | — | 814 | — | ||||||||||||
OPUC investigation | — | (107 | ) | — | (1,065 | ) | ||||||||||
Other | (3 | ) | — | (36 | ) | — | ||||||||||
Current amortizations: | ||||||||||||||||
Interstate gas storage credits | — | — | 2,714 | 5,324 | ||||||||||||
Conservation decoupling | (180 | ) | (275 | ) | (1,416 | ) | (2,410 | ) | ||||||||
South Mist pipeline extension | (221 | ) | — | (1,789 | ) | — | ||||||||||
Conservation programs | (222 | ) | (303 | ) | (1,551 | ) | (2,256 | ) | ||||||||
Year 2000 technology costs | (113 | ) | (109 | ) | (852 | ) | (983 | ) | ||||||||
Other | 129 | 37 | 1,103 | 402 | ||||||||||||
Net revenue adjustments | (1,439 | ) | (1,575 | ) | 1,167 | (138 | ) | |||||||||
Miscellaneous revenues: | ||||||||||||||||
Customer fees | 509 | 633 | 3,530 | 2,541 | ||||||||||||
Other | 417 | 84 | 516 | 359 | ||||||||||||
Total miscellaneous revenues | 926 | 717 | 4,046 | 2,900 | ||||||||||||
Total other revenues | $ | (513 | ) | $ | (858 | ) | $ | 5,213 | $ | 2,762 | ||||||
Three months ended Sept. 30, 2005 compared to Sept. 30, 2004
Thousands | 2006 | 2005 | ||||||
Revenue adjustments: | ||||||||
Current regulatory deferrals: | ||||||||
Decoupling mechanism | $ | (1,052 | ) | $ | 4,798 | |||
Weather normalization mechanism | 1,569 | 472 | ||||||
South Mist pipeline extension | — | 81 | ||||||
Coos Bay distribution system | — | 605 | ||||||
Current regulatory amortizations: | ||||||||
Decoupling mechanism | (2,688 | ) | (839 | ) | ||||
South Mist pipeline extension | (36 | ) | (1,069 | ) | ||||
Coos Bay distribution system | (480 | ) | — | |||||
Conservation programs | (674 | ) | (888 | ) | ||||
Year 2000 technology costs | 230 | (496 | ) | |||||
Other | (3 | ) | 656 | |||||
Net revenue adjustments | (3,134 | ) | 3,320 | |||||
Miscellaneous revenues: | ||||||||
Customer fees | 1,645 | 1,770 | ||||||
Other | 49 | 63 | ||||||
Total miscellaneous revenues | 1,694 | 1,833 | ||||||
Total other revenues | $ | (1,440 | ) | $ | 5,153 | |||
Other revenues in the three months ended Sept. 30, 2005March 31, 2006 were $0.3$6.6 million higherlower than the comparable period in 2004 primarily because of an increase in the current decoupling deferrals andthree months ended March 31, 2005 primarily due to a decrease in deferrals under the amortization of prior period decoupling deferralsmechanism ($0.3 million), offset by a decrease in customer fees ($0.1 million).
Nine months ended Sept. 30, 2005 compared to Sept. 30, 2004
Other revenues in the nine months ended Sept. 30, 2005 were $2.5 million higher than in the comparable period in 2004 primarily due to an increase in the current decoupling deferrals and a decrease in the amortization of prior period decoupling deferrals ($3.65.9 million) and an increase in customer feesthe amortization of the decoupling deferral balances ($1.01.8 million), partially offset by a decreasean increase in the
interstate gas storage credits to customers weather normalization adjustments ($2.61.1 million) due to lower net income from storage operations. See Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms,” in calendar year 2004 compared to 2003.
the 2005 Form 10-K.
Cost of Gas Sold
Natural gas commodity prices have increased significantly in recent periods. During the third quarter and the first nine months of 2005,periods, with the cost per therm of gas sold was 28 percent and 27 percent higher respectively, than in the comparable 2004 periods, primarily due to higher natural gas prices.first quarter of 2006 than the first quarter of 2005. The cost per therm sold includes current gas purchases, gas withdrawn from storage inventory, gains and losses from financial commodity hedges,price hedge contracts, margin from off-system gas sales, demand cost balancing adjustments, regulatory deferrals and company use (see Part II, Item 7., “Results of Operations—Comparison of Gas Distribution Operations—Cost of Gas Sold,” in the 20042005 Form 10-K).
NW Natural usesWe utilize a natural gas commodity-price hedge program under the terms of itsour Derivatives Policy to help manage itsour floating price gas commodity contracts (see “Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities,” above, and Note 4). NW NaturalWe realized net financial hedge gains of $20.5 million and $30.3$17.5 million from this program during the three- and nine-month periods ended Sept. 30, 2005, respectively,first quarter of 2006, compared to net hedge gainslosses of $10.2$1.5 million and $27.9 million duringin the same periodsfirst three months of 2004.2005. Gains and losses relating to the financial hedging of utility gas purchasesprices are included in cost of gas, which is factored into NW Natural’sour PGA deferrals and annual rate changes, and therefore have no material impact on net income.
Under NW Natural’sour PGA tariff in Oregon, net income from Oregon operations is affected within defined limits by changes in purchased gas costs (see Part II, Item 7., “Results of Operations—Comparison of Gas Operations,Operations—Cost of Gas Sold,” in the 20042005 Form 10-K). NW Natural’sOur purchased gas costs in the third quarterfirst quarters of both 2006 and 2005 were slightly higherlower than the costs embedded in rates, which, decreasedunder the PGA sharing mechanism, increased margin by a negligible amount. For the third quarter of 2004, NW Natural’s gas costs were$1.8 million and $1.5 million, respectively.
We are also higher than those embedded in rates, which decreased margin by $0.1 million. In the first nine months of 2005, NW Natural’s share of gas cost savings from amounts embedded in rates contributed $1.9 million of margin, compared to net savings and a contribution to margin of $0.4 million in the comparable 2004 period.
NW Natural is able to use surplus gas supplies under contract but not required for delivery to core market (residential, commercial and industrial firm) customers, due to warmer weather and other factors, to make off-system sales. Under the PGA tariff in Oregon, NW Natural retainswe retain 33 percent of the margins realized from itsour off-system gas sales and recordsdefer the remaining 67 percent asto a deferred regulatory asset or liability account for recovery from, or refund to, customers in future rates. NW Natural’sOur share of margin from off-system gas sales in the thirdfirst quarter of 20052006 was a negligible lossgain compared to a lossgain of $0.2$0.4 million for the same period in 2004. In the first nine months of 2005, NW Natural’s share of margin from off-system gas sales contributed $0.3 million of margin, compared to a nominal loss for the same period in 2004.
Commodity Cost
The Company’s weighted average cost of gas (WACOG) is annually adjusted in rates to reflect changes in the cost of gas purchased by the Company from its natural gas suppliers, including the costs of purchasing financial derivative products to limit customers’ exposure to gas cost volatility, and changes in the cost of pipeline and storage capacity under contract with the Company’s pipeline transporters (see “Regulatory Developments—Rate Mechanisms,” above). The Company’s WACOG compares favorably to current market prices. Gas prices across the country have been affected significantly by a number of factors including hurricane activity in the Gulf of Mexico. Current price quotes for the 2006-2007 gas purchasing year indicate a continuing trend of price increases. If gas prices remain high and the Company is required to purchase gas on the spot market to serve its load, which in large part depends upon weather and other factors, the difference between the Company’s WACOG in rates and actual gas costs on the small unhedged portion of the Company’s portfolio (typically less than 10 percent) could result in significant losses, with two-thirds of the variance deferred to a regulatory account and one-third recorded to income (see Part II, Item 7., “Results of Operations—Comparison of Gas Operations—Cost of Gas Sold,” in the 2004 Form 10-K).
2005.
Business Segments Other than Gas Distribution Operations
Interstate Gas Storage
NW NaturalWe earned net income of $1.6 million after regulatory sharing and income taxes from itsour non-utility interstate gas storage business segment in the three months ended Sept. 30, 2005.March 31, 2006 of $1.4 million, after regulatory sharing and income taxes, or 5 cents a share. This compares to net income of $0.6$0.9 million or 3 cents a share in the three months ended Sept. 30, 2004. ForMarch 31, 2005. The increase was primarily due to additional interstate storage capacity brought on line during 2006, plus an increase in revenues from our asset optimization program with an unaffiliated energy marketing company (see Part II, Item 7., “Results of Operations—Business Segments Other Than Local Gas Distribution—Interstate Gas Storage,” in the nine months ended Sept. 30, 2005 results from thisForm 10-K). The segment were net income of $3.3 million, compared to $2.1 million for the comparable periodalso began providing intrastate services in 2004.February 2006.
The Company’sOur third-party optimization activities are provided under a contract with an unaffiliated energy marketing company, which optimizes the value of NW Natural’sour assets by engaging in marketing activities primarily through the use of commodity transactions and releases of temporarily unused portions of off-
systemour upstream pipeline transportation capacity and gas storage capacity. In addition, in the first quarter of 2005, NW Natural entered into a series of exchange transactions with this company, which resulted in a change in the Company’s accounting treatment for its forward gas supply contracts under SFAS No. 133. SFAS No. 133 requires that derivative instruments be recorded on the balance sheet at fair value. Prior to March 31, 2005, the Company’s forward gas supply contracts were excluded from the fair value measurement requirement of SFAS No. 133 because these contracts were eligible for the normal purchases and normal sales exception. These contracts are now accounted for as derivative instruments and marked-to-market based on fair value pursuant to SFAS No. 133 (see Note 4).
In Oregon, NW Natural retainswe retain 80 percent of the pre-tax income from interstate gas storage services and optimization of utility storage and pipeline transportation capacity when the costs of such capacity have not been included in utility rates, and retains 33 percent of the pre-tax income from such optimization when the capacity costs have been included in utility rates. The remaining 20 percent and 67 percent, respectively, are credited to a deferred regulatory account for refunddistribution to NW Natural’sour utility customers. NW Natural hasWe have a similar sharing mechanism in Washington for pre-tax income derived from interstate storage services and third partythird-party optimization.
Other
Subsidiary –The Other business segment primarily consists of Northwest Natural’s wholly-owned subsidiary, Financial Corporation
(see Part II, Item 8., Note 2, “Consolidated Subsidiary Operations and Segment Information,” in the 2005 Form 10-K). Financial Corporation’s operating results for the three months ended Sept. 30, 2005 were net income of $0.1 million compared to net income of $0.4 millionnegligible losses in the third quarterfirst quarters of 2004. For the first nine months of 2005, net income was $0.2 million compared to net income of $0.5 million for the same period in 2004.both 2006 and 2005.
The Company’sOur net investment balances attributed toin Financial Corporation at Sept. 30,March 31, 2006 and 2005 were $3.6 and 2004 were $3.0 and $6.0$2.8 million, respectively. The lower investment balance reflects the sale of interests$0.8 million increase was primarily due to higher temporary cash investments, partially offset by a decline in the solar electric generation projects in January 2005 and a dividend paid by Financial Corporation to the parent, NW Natural, in the first quartercarrying value of 2005.long-term investments.
Operating Expenses
Operations and Maintenance
Operations and maintenance expenses in third quarter of 2005 were $26.0 million, 6 percent higher than in the third quarter of 2004. The $1.5 million increase was primarily due to:
Operations and maintenance expenses in the first nine monthsquarter of 20052006 were $80.2$28.2 million, 84 percent higher than in the first nine monthsquarter of 2004.2005. The $5.8following summarizes the major factors that contributed to the $1.1 million increase was primarily due to:in operations and maintenance expense:
Taxes Other than IncomeGeneral Taxes
Taxes other than incomeGeneral taxes, which are principally comprised of franchise, property, and payroll taxes and regulatory fees, increased $1.1$0.8 million, or 16 percent, and $3.9 million, or 1412 percent, in the three- and nine-month periods ended Sept. 30, 2005, respectively, compared tofirst quarter of 2006 over the same periodsperiod in 2004. For the three- and nine-month periods ended Sept. 30, 2005, franchise taxes, which are based on gross revenues, increased $0.5 million and $2.6 million, respectively, reflecting higher gross revenues primarily due to higher rates. For the three- and nine-month periods ended Sept. 30, 2005, property2005. Property taxes increased $0.4$0.3 million, and $1.0 million, respectively,or 8 percent, due to utility plant additions in 20042006 and 2005. Regulatory fees increased $0.5 million, or 28 percent, due to increased gross operating revenues over the prior year.
Depreciation and Amortization
Depreciation and amortization expense increased by $1.2$0.6 million, or 9 percent, and $3.9 million, or 94 percent, in the three- and nine-month periodsthree-month period ended Sept. 30, 2005,March 31, 2006 compared to the same periodsperiod in 2004.2005. The increased expense is primarily due to depreciation on additional investments in utility property that were made to meet continuing customer growth, including the largest component of the Company’s investment in South Mist Pipeline Extension (SMPE) which was put into service in September 2004 (see “Financial Condition—Cash Flows—Investing Activities,” below).
growth.
Other Income and Expense – Net
The following table summarizes other income and expense-net by primary components for the three and nine months ended Sept. 30, 2005 and 2004:March 31:
Three Months Ended Sept. 30, | Nine Months Ended Sept. 30, | |||||||||||||||
(Thousands) | 2005 | 2004 | 2005 | 2004 | ||||||||||||
Other income (expense): | ||||||||||||||||
Gains from Company-owned life insurance | $ | 436 | $ | 549 | $ | 1,410 | $ | 1,974 | ||||||||
Allowance for funds used during construction—equity | — | 355 | — | 544 | ||||||||||||
Interest income | 180 | 21 | 409 | 138 | ||||||||||||
Other non-operating expense | (202 | ) | (291 | ) | (1,061 | ) | (1,225 | ) | ||||||||
Interest income (charges) on deferred regulatory account balances | 99 | 112 | 123 | (171 | ) | |||||||||||
Earnings from equity investments of Financial Corporation | 37 | 898 | 139 | 849 | ||||||||||||
Total other income | $ | 550 | $ | 1,644 | $ | 1,020 | $ | 2,109 | ||||||||
Thousands | 2006 | 2005 | ||||||
Gains from company-owned life insurance | $ | 1,383 | $ | 468 | ||||
Interest income | 84 | 46 | ||||||
Other non-operating expense | (603 | ) | (313 | ) | ||||
Interest income (charges) on deferred regulatory accounts | (296 | ) | 1 | |||||
Earnings from equity investments of Financial Corporation | (50 | ) | (137 | ) | ||||
Total other income and expense – net | $ | 518 | $ | 65 | ||||
Other income decreased $1.1and expense – net was $0.5 million higher in both the three- and nine-month periods ended Sept. 30, 2005, respectively,first quarter of 2006 compared to the same periods in 2004.first quarter of 2005. The decreaseincrease was due to realized gains in the three-month period ended Sept. 30, 2005 was primarily due to lower earningsquarter from equity investments of Financial Corporation ($0.9 million) and the absence of the equity component of AFUDC ($0.4 million) reflecting lower construction work in progress balances. The decrease in the nine-month period ended Sept. 30, 2005 was primarily due to lower earnings from equity investments of Financial Corporation ($0.7 million) and the absence of the equity component of AFUDC ($0.5 million), reflecting lower construction work in progress balances and lower gains from Company-ownedcompany-owned life insurance, ($0.6 million), partially offset by higher interest income ($0.3 million)non-operating expense and higher interest charges on deferred regulatory account balances ($0.3 million).accounts.
Interest Charges – Net of Amounts Capitalized
Interest charges – netcharges-net of amounts capitalized increased by $0.5in the first quarter of 2006 was $0.7 million, or 51 percent, and $0.8 million, or 3 percent,higher than in the three- and nine-month periodsthree months ended Sept. 30, 2005, respectively, compared to the same periods in 2004.March 31, 2005. The increase in interest charges is2006 was due to an increase in the average balancehigher balances of debt outstanding during the period,and higher interest rates on short-term debt, and lower interest credits allocated toduring the debt component for AFUDC (see Part II, Item 7., “Results of Operations—Interest Charges—Net of Amounts Capitalized,” in the 2004 Form 10-K).
period.
Income Taxes
The effective corporate income tax rate from operations was 35.736.4 percent for each of the nine-month periodthree-month periods ended Sept. 30, 2005, compared to 34.7 percent for the nine-month period ended Sept. 30, 2004. The increase in the effective income tax rate reflected the effect of higher federalMarch 31, 2006 and state income taxes attributed to a $14.1 million dollar increase in pre-tax income.2005.
Financial Condition
Capital Structure
The Company’sOur goal is to maintain a target capital structure comprised of 45 to 50 percent common stock equity and 50 to 55 percent long-term and short-term debt. When additional capital is required, debt or equity securities are issued depending upon both the target capital structure and market conditions. These sources also are used to meet long-term debt redemption requirements and short-term commercial paper maturities (see “Liquidity and Capital Resources,” below). In addition, the Company may use its common stock repurchase program to maintain its target capital structure (see “Financing Activities,” below).
The Company’sOur consolidated capital structure at Sept. 30,March 31, 2006 and 2005 and 2004 and at Dec. 31, 2004,2005, including short-term debt, was as follows:
| Sept. 30, | Dec. 31, 2004 | March 31, | Dec. 31, 2005 | |||||||||||||||
| 2005 | 2004 | 2006 | 2005 | |||||||||||||||
Common stock equity | 48.7 | % | 48.5 | % | 48.6 | % | 51.6 | % | 54.0 | % | 47.2 | % | ||||||
Long-term debt | 44.5 | % | 42.9 | % | 41.4 | % | 41.8 | % | 43.7 | % | 42.0 | % | ||||||
Short-term debt, including current maturities of long-term debt | 6.8 | % | 8.6 | % | 10.0 | % | 6.6 | % | 2.3 | % | 10.8 | % | ||||||
Total | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | ||||||
The Company believes that achievingAchieving the target capital structure and maintaining sufficient liquidity contributeare necessary to maintainingmaintain attractive credit ratings and havinghave access to capital markets at reasonable costs.
On May 25, 2000, we announced a program to repurchase up to 2 million shares, or up to $35 million in value, of NW Natural’s common stock through a repurchase program that has been extended annually. The purchases are made in the open market or through privately negotiated transactions. Since the program’s inception, we have repurchased 777,300 shares of common stock at a total cost of $23.5 million. In April 2006, NW Natural’s Board of Directors extended the share repurchase program through May 31, 2007 and increased the authorization from 2 million shares to 2.6 million shares and increased the dollar limit from $35 million to $85 million (see “Financing Activities,” below).
Liquidity and Capital Resources
At Sept. 30, 2005, the CompanyMarch 31, 2006, we had $3.4$7.5 million of cash and cash equivalents compared to $4.1$2.7 million at Sept. 30, 2004March 31, 2005 and $5.2$7.1 million at Dec. 31, 2004. During the third quarter of 2005, cash and cash equivalents decreased by $36.9 million, from $40.3 million at June 30, 2005 to $3.4 million at Sept. 30, 2005, which reflected cash primarily being used to redeem the maturities of long-term debt and to fund the ongoing utility construction program. See Note 10 and “Cash Flows—Financing Activities,” below.
2005. Short-term liquidity is provided by cash from operations and from the sale of commercial paper notes, which are supported by committed bank lines of credit. The Company had available through Sept. 30, 2005 committed lines of credit totaling $150 million with several commercial banks, which were replaced with new lines of credit totaling $200 million effective Oct. 1, 2005through Sept. 30, 2010 (see Note 9 and “Lines of Credit,” below)below, and Part II, Item 8., Note 6, in the 2005 Form 10-K). Short-term debt balances are typically higher at the end of the third and fourth quartersDecember each year due to seasonal working capital requirements, which reflect the financing of accounts receivable and natural gas inventories during the winter heating season. Short-term debt balances are significantly lower at the end of March as receivables and accounts receivable.
Capital expendituresinventories are primarily for utility construction requirements relating to customer growth and system improvements (see “Cash Flows—Investing Activities,” below). Certain contractual commitments under capital leases, operating leases and gas supply purchase and other contracts require an adequate source of funding. These capital and contractual expenditures are financed throughconverted into cash, from operations and from the issuance of short-term debt, which is periodically refinanced through the sale of long-term debt or equity securities.used to reduce short-term debt.
Neither NW Natural’sour Mortgage and Deed of Trust nor the indentures under which other long-term debt is issued contain credit rating triggers or stock price provisions that require the acceleration of debt repayment. Also, there are no rating triggers or stock price provisions contained in contracts or other agreements with third parties, except for agreements with certain counter-partiescounterparties under NW Natural’sour Derivatives Policy which require the affected party to provide substitute collateral such as cash, guaranty or letter of credit if credit ratings are lowered to non-investment grade, or in some cases if the mark-to-market value exceeds a certain threshold.
Based on the availability of short-term credit facilities and the ability to issue long-term debt and equity securities, the Company believes it haswe believe we have sufficient liquidity to satisfy itsour anticipated near-term cash requirements, including the contractual obligations and investing and financing activities discussed below.
Off-Balance Sheet Arrangements
Except for certain lease and purchase commitments (see “Contractual Obligations,” below), the Company haswe have no material off-balance sheet financing arrangements.
Contractual Obligations
During the nine months ended Sept. 30,Since Dec. 31, 2005, there were no material changes to the Company’s estimated future contractual obligations other than an increasewe entered into a new contract in the amount of existing gas$12.4 million for the purchase obligations due to rising gas commodity prices (see table below), the $50 millionand installation of secured long-term debt issued in June 2005 as described in Note 10, aautomated meter reading equipment. Other than this contract for environmental clean-up related to the removal of a tar deposit at the Portland Harbor site as described in Note 7 and obligationscontracts entered into in the ordinary course of business. The Company’sbusiness, there were no material changes to our estimated future contractual obligations during the three months ended March 31, 2006. Our contractual obligations at Dec. 31, 2004 were2005 are described in Part II, Item 7., “Financial Condition—Liquidity and Capital Resources—Contractual Obligations,” in the 20042005 Form 10-K.
The Company’s contractual obligations under existing gas purchase contracts are as follows:
| Payments Due | ||||||||||||||||||||||
(Thousands) Gas purchase obligations (1) | Up to 1 Year | 1-2 Years | 2-3 Years | 3-4 Years | 4-5 Years | Thereafter | Total | |||||||||||||||
At Sept. 30, 2005 | $ | 517,169 | $ | 253,124 | $ | 239,625 | $ | 127,732 | $ | 63,620 | $ | 122,617 | $ | 1,323,887 | ||||||||
At Dec. 31, 2004 | 277,371 | 184,572 | 167,093 | 150,898 | 62,155 | 112,684 | 954,773 | |||||||||||||||
Net increase (decrease) | $ | 239,798 | $ | 68,552 | $ | 72,532 | $ | (23,166 | ) | $ | 1,465 | $ | 9,933 | $ | 369,114 | |||||||
Commercial Paper
The Company’sOur primary source of short-term funds is from the sale of commercial paper notes payable. In addition to issuing commercial paper to meet seasonal working capital requirements, including the financing of gas purchases and accounts receivable, short-term debt is used to temporarily fund capital expenditure requirements. Commercial paper is periodically refinanced through the sale of long-term debt or equity securities. NW Natural’sOur outstanding commercial paper, which is sold under agency agreements withthrough two commercial banks under an issuing and paying agency agreement, is supported by our committed bank lines of credit (see “Lines of Credit,” below, Note 9, and Part II, Item 8., Note 6, in the 20042005 Form 10-K). NW NaturalWe had $72.5$50.4 million in commercial paper notes outstanding at Sept. 30, 2005,March 31, 2006, compared to $82.7$10.5 million outstanding at Sept. 30, 2004March 31, 2005 and $102.5$126.7 million outstanding at Dec. 31, 2004.
2005. Commercial paper balances are typically lower at the end of the first quarter compared to year-end due to collections from higher sales and the withdrawal of gas inventories from storage during the winter heating season.
Lines of Credit
In September 2005, NW Natural entered intoWe have an agreement for unsecured lines of credit totaling $200 million with five commercial banks, replacing the existing $150 million credit facilities.banks. The new bank lines of credit (bank lines) are available and committed for a term of five years from Oct. 1, 2005 to Sept. 30, 2010. NW Natural’s bank lines are used primarily as back-up support for the notes payable under the Company’s commercial paper borrowing program. Commercial paper borrowing provides the liquidity to meet the working capital and external financing requirements of NW Natural. The Company received regulatory authorization for the new bank lines in October 2005.
Under the terms of these bank lines, NW Natural payswe pay upfront fees and annual commitment fees but isare not required to maintain compensating bank balances. The interest rates on outstanding loans, if any, under these bank lines are based on then-current market interest rates. All principal and unpaid interest under the bank lines is due and payable on Sept. 30, 2010.
The bank There were no outstanding balances on these lines require that NW Natural maintain credit ratings with Standard & Poor’s and Moody’s Investor Services and to notify the banks of any change in its senior unsecured debt ratings by such rating agencies. A change in NW Natural’s credit rating is not an event of default, nor is the maintenance of a specific minimum level of credit rating a condition of drawing upon the bank lines. However, interest rates on any loans outstanding under these bank lines are tied to credit ratings, which would increaseat March 31, 2006 or decrease the cost of any loans under the bank lines when ratings are changed.2005, or at Dec. 31, 2005.
The bank lines also require the Company to maintain an indebtedness to total capitalization ratio of 65 percent or less. Failure to comply with this covenant would entitle the banks to terminate their lending commitments and to accelerate the maturity of all amounts outstanding. NW Natural was in compliance with an equivalent covenant in the prior year’s bank lines at Sept. 30, 2005.
Credit Ratings
The table below summarizes NW Natural’s currentour credit ratings and ratings outlook from three rating agencies, Standard and Poor’s Rating Services (S&P), Moody’s Investors Service (Moody’s) and Fitch Ratings (Fitch).
| S&P | Moody’s | Fitch | |||
Commercial paper (short-term debt) | P-1 | F1 | ||||
Senior secured (long-term debt) | A2 | A+ | ||||
Senior unsecured (long-term debt) | A3 | A | ||||
Ratings outlook | Stable | Stable | Stable |
Each of the rating agencies has assigned us an investment grade rating. These credit ratings are dependent upon a number of factors, both qualitative and quantitative, and are subject to change at any time. The disclosure of these credit ratings is not a recommendation to buy, sell or hold the Company’sour securities. Each rating should be evaluated independently of any other rating.
Redemptions of Long-Term Debt
In July 2005, the Company redeemed three series of its maturing Medium-Term Notes (MTNs) aggregating $15 million in principal amount. The series redeemed were the 6.34% Series B, the 6.38% Series B and the 6.45% Series B, each due in July 2005. The MTNs were redeemed with proceeds from the sales of $50 million in principal amount of MTNs in June 2005 (see “Cash Flows—Financing Activities,” below).
In August 2005, the Company redeemed all of its outstanding Convertible Debentures, 7-1/4% Series due 2012 (the Debentures) at 100% of their principal amount plus accrued interest to the date of redemption. All but $0.5 million of the Debentures were converted into shares of the Company’s common stock on or prior to the redemption date at the rate of 50.25 shares for each $1,000 principal amount of Debentures (see Note 10).
Cash Flows
Operating Activities
Year-over-year changes in the Company’sour operating cash flows are primarily affected by net income, non-cash adjustments to net income primarily from depreciation, deferred income taxesgas prices and deferred gas costs, and changes in working capital. In the first nine months of 2005, net income increased $8.7 million, non-cash adjustments decreased $10.0 million andother changes in working capital increased $0.4 million comparedrequirements, regulatory deferrals and other cash and non-cash adjustments to the same period in 2004.
The following table summarizes cash provided by operating activities for the nine-month periods ended Sept. 30, 2005 and 2004:
| Nine Months Ended Sept. 30, | ||||||
Thousands | 2005 | 2004 | ||||
Net income | $ | 32,356 | $ | 23,611 | ||
Non-cash adjustments to net income | 29,557 | 39,547 | ||||
Changes in working capital | 32,754 | 33,234 | ||||
Cash provided by operating activities | $ | 94,667 | $ | 96,392 | ||
Nine months ended Sept. 30, 2005 compared to Sept. 30, 2004
results. The overall change in cash flow from operating activities infor the first ninethree months of 2005ended March 31, 2006 compared to 2004the same period in 2005 was a decrease of $1.7$16.8 million, primarily due to a decrease in cash from working capital changes of $21.9 million. The significant factors contributing to the cash flow changes between periodsin the first quarter of 2006 compared to first quarter of 2005 are as follows:
The Company hasWe have lease and purchase commitments relating to itsour operating activities that are financed with cash flows from operations (see “Liquidity and Capital Resources,” above, and Part II, Item 8., Note 12, in the 20042005 Form 10-K).
Investing Activities
Cash requirements for investing activities in the first ninethree months of 20052006 totaled $66.5$12.7 million, down from $112.8$16.4 million in the same period of 2004.2005. Cash requirements for the acquisition and construction of utility plant totaled $65.2$15.0 million, down from $110.2$20.0 million in the same period of 2004. The decrease in utility construction in the first nine months of 2005 reflects the completion in 2004 of NW Natural’s SMPE project, which extended the pipeline from the Mist gas storage field to serve growing portions of NW Natural’s service area. The total cost of the project was approximately $108 million, which includes amounts reflected in investing activities over the past few years. The cost of service associated with the SMPE project, net of deferred tax benefits, was included in utility customer rates beginning in the fourth quarter of 2004.
2005.
Investments in non-utility property during the first ninethree months of 20052006 totaled $5.5$0.1 million, updown from $3.8$0.2 million during the first ninethree months of 2004. The higher investments in 2005 were primarily for improvements to the Company’s interstate gas storage facilities.
2005.
In January 2005, Financial Corporation received proceeds from the sale of its limited partnership interests in three solar electric generation projects totaling $3.0 million.
Financing Activities
Cash used in financing activities in the first ninethree months of 20052006 totaled $30.1$85.4 million, compared to cash provided of $15.7down from $101.3 million in the same period of 2004. Factors2005. The primary factor contributing to the $45.8$15.9 million decrease were a larger reduction inwas the repayment of $76.3 million of short-term debt in the first nine monthsquarter of 2005 ($30.0 million)2006 compared to the first nine months of 2004 ($2.5 million), the redemption of long term debt and convertible debentures$92.0 million in 2005 ($15.5 million), the repurchase of common stock in 2005 ($13.8 million) compared to the same period in 2004 ($0.2 million) and the lower amount of equity financing in 2005 ($6.2 million) compared to 2004 ($44.6 million), partially offset by the issuance of $50.0 million in MTNs during the first nine months of 2005.
In June 2005, NW Natural sold $40 million of its 4.70% Series B secured MTNs due 2015 and $10 million of its 5.25% Series B secured MTNs due 2035 and used the proceeds, together with internally generated cash, to reduce short-term debt.
In April 2004, the Company sold 1,290,000 shares of its common stock in an underwritten public offering, and used the net proceeds of $38.5 million from the offering to reduce short-term indebtedness by about $29 million and to fund, in part, NW Natural’s utility construction program (see Part II, Item 7., “Financial Condition—Liquidity and Capital Resources,” in the 2004 Form 10-K).
In 2000, NW Naturalwe commenced a program to repurchase up to 2 million shares or up to $35 million in value, of itsour common stock through a repurchase program that in April 2005, washas been extended through May 2006. The purchases are made in the open market or through privately negotiated transactions. The Company2007 (see “Capital Structure,” above). We purchased 377,90015,600 shares in the first nine monthsquarter of 20052006 at a cost of $13.8 million. No$0.5 million, compared to 80,500 shares were purchased pursuant to the program in 2004. Since
the program’s inception, the Company has repurchased 733,300 shares of common stock at a total cost of $22.0$2.9 million (see Part II, Item 2., “Unregistered Sales of Equity Securities and Use of Proceeds,” below).
Pension Funding Status
The Company’s pension funding status is determined by actuarial valuations. The Company makes contributions to its qualified non-contributory defined benefit pension (DBP) plans based on actuarial assumptions and estimates, tax regulations and funding requirements under federal law. The Company is not required to make additional cash contributions to its qualified DBP plans in 2005 based on minimum funding requirements, but elected to contribute an additional $20.0 million on Sept. 15, 2005 for the 2004 plan year. The Company will continue to evaluate its qualified DBP plans’ funding status based on expected returns on plan assets and anticipated changes in actuarial assumptions to determine if an additional contribution will be made prior to year-end. In addition, the Company will continue to make cash contributions during 2005 in the formfirst quarter of ongoing benefit payments as required for its unfunded non-qualified supplemental pension plans and other postretirement benefit plans. See Part II, Item 8., Note 7, in the 2004 Form 10-K for a discussion of estimated future payments.
2005.
Ratios of Earnings to Fixed Charges
For the ninethree months and 12 months ended Sept. 30, 2005March 31, 2006 and the 12 months ended Dec. 31, 2004, the Company’s2005, our ratios of earnings to fixed charges, computed using the Securities and Exchange Commission method, were 2.76, 3.377.23, 3.33 and 3.02,3.32, respectively. For this purpose, earnings consist of net income before taxes plus fixed charges, and fixed charges consist of interest on all indebtedness, the amortization of debt expense and discount or premium and the estimated interest portion of rentals charged to income.
Because a significant part of our business is of a seasonal nature, the ratio for the interim period is not necessarily indicative of the results for a full year.
Contingencies
Loss contingencies are recorded as liabilities when it is probable that a liability has been incurred and the amount of the loss is reasonably estimable in accordance with SFAS No. 5, “Accounting for Contingencies.” NW Natural updates itsWe update our estimates of loss contingencies and related disclosures when new information becomes available. Estimating probable losses requires an analysis of uncertainties that often depend upon judgments about potential actions by third parties, and NW Natural recordswe record accruals for loss contingencies based on an analysis of potential results, developed in consultation with outside counsel and consultants when appropriate. When information is sufficient to estimate only a range of potential liabilities, and no point within the range is more likely than any other, the Company recognizeswe recognize an accrued liability at the lower end of the range and disclosesdisclose the range (see Note 7). It is possible, however, that the range of potential liabilities could be significantly different than amounts currently accrued and disclosed, and the Company’sour financial condition and results of operations could be materially affected by changes in assumptions or estimates related to these contingencies.
With respect to itsWe develop estimates of environmental liabilities and related costs NW Natural develops estimates based on currently available information, existing technology and environmental regulations. These costs include investigation, monitoring, and remediation. NW NaturalWe received regulatory approval to defer and seek recovery of costs related to certain sites and believesbelieve the recovery of these costs is probable through the regulatory process.
process (see “Results of Operations—Regulatory Developments—Rate Mechanisms,” above). In accordance with SFAS No. 71, the Company haswe have recorded a regulatory asset for the amount expected to be recovered. The Company intendsWe intend to pursue recovery of these environmental costs from itsour general liability insurance policies, and the regulatory asset will be reduced by the amount of any corresponding insurance recoveries. At Sept. 30, 2005,March 31, 2006, a cumulative $17.4$19.1 million in environmental costs has been recorded as a regulatory asset, including $5.4$14.4 million of costs paid to-date and $12.0$4.7 million of accrued estimated future environmental costs. If it is determined that both the insurance recovery and future customer rate recovery of such costs is not probable, then the costs will be charged to expense in the period such determination is made. See Note 7.
Industrial Customers Switching from Transportation to Sales Service
High natural gas prices have resulted in severalIn the fourth quarter of NW Natural’s2005, we settled a dispute with some large industrial transportation customers related to gas costs charged to such customers upon electing to receive gas commodity under sales service from NW Natural instead of arranging for their own supplies through independent third parties. Since these customers are electing the transfer to sales service after commodity rates were set in the annual PGA, the Company believes its tariff requires it to charge these customers the incremental cost of gas supply incurred by the Company to serve those customers. The Company has notified these customers that they will be charged the incremental gas costs, if any. Certain of these customers have notified the Company that they expected to be charged gas costs at the Company’s WACOG price. The Company is workingTwo formal complaints filed with the OPUC and customer groups to resolve the matter. If it is determinedin connection with this matter have been dismissed by the OPUC. The OPUC that NW Natural is not allowedhas also closed the investigation it opened to charge these customers its incremental costs, or customers are awarded damages through litigation, then the potential impact could be materialdetermine whether we had provided adequate information about rates to the Company’s financial resultsindustrial customers. We continue to contest claims of Georgia-Pacific Corporation in 2005 and 2006, depending on the price and volume of incremental gas purchases.a related lawsuit more fully described in Note 7.
Forward-Looking Statements
This report and other presentations made by the Companyus from time to time may contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and other statements that are other than statements of historical facts. The Company’sOur expectations, beliefs and projections are expressed in good faith and are believed to have a reasonable basis. However, each such forward-looking statement involves uncertainties and is qualified in its entirety by reference to the following important factors, among others, that could cause theour actual results of the Company to differ materially from those projected, in such forward-looking statements, including:
All subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company,NW Natural, also are expressly qualified by these cautionary statements. Any forward-looking statement speaks only as of the date on which such statement is made, and the Company undertakeswe undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for the Companyus to predict all such factors,
nor can itwe assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.
| Item 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
The Company isWe are exposed to various forms of market risk including commodity supply risk, weather risk, and interest rate risk (seerisk. The following describes our exposure to these risks.
Commodity Supply Risk
We enter into short-term, medium-term and long-term natural gas supply contracts, along with associated short-, medium- and long-term transportation capacity contracts. Historically, we have taken physical delivery of at least the minimum quantities specified in our natural gas supply contracts. These contracts are primarily index-based and subject to annual re-pricing, a process that is intended to reflect anticipated market price trends during the next year. Our PGA mechanisms in Oregon and Washington provide for the recovery from customers of actual commodity costs, except that, for Oregon customers, we absorb 33 percent of the higher cost of gas sold, or retain 33 percent of the lower cost, in either case as compared to the annual PGA price built into customer rates.
Market risks related to potential adverse changes in commodity prices, foreign exchange rates or counterparty credit quality in relation to these financial and physical contracts are discussed in Part II, Item 7A., “Quantitative and Qualitative Disclosures About Market Risk,” in the 20042005 Form 10-K). In addition, the Company is exposed to credit risk relating to receivables from its customers10-K and financial derivative counterparties, particularly when gas prices increase substantially as they have recently.
below. Also see Note 4, above.
Commodity SupplyCredit Risk with Unaffiliated Energy Marketing Company. There have been no material changes to the information relating to market risk provided in the Company’s 2004 Form 10-K. However, in the first nine months of 2005, NW Natural entered into a series of exchange transactions with an unaffiliated energy marketing company, which resulted in the Company’s accounting for its forward gas purchase contracts as derivative instruments under SFAS No. 133. SFAS No. 133 requires that derivative instruments be recorded on the balance sheet at fair value. The mark-to-market adjustment at Sept. 30, 2005 on contracts that were previously accounted for as normal purchase normal sale is an unrealized loss of $2.1 million, which is recorded as a liability with an offsetting entry to a regulatory asset account based on regulatory deferral accounting treatment under SFAS No. 71. The Company’s forward gas supply contracts were previously excluded from the provisions of SFAS No. 133 under the normal purchases and normal sales exception that is allowed for contracts that are probable of delivery in the normal course of business. These exchange transactions are intended and designed to reduce commodity prices, with the derivatives decreasing the Company’s net exposures to market risk. These derivatives are used for managing business risks and not for trading purposes.
In the exchange transactions referred to above, NW Natural continues to receive the same physical deliveries of natural gas volumes at the entry point into its distribution system, while the unaffiliated energy marketing company seeks to use the equivalent physical commodity volumes at an upstream delivery point. Under the optimization agreement with this company, NW Natural receives a fixed fee plus a share of any gains above the fixed fee. NW Natural’s exchange transaction is consistent with its policies on physical gas purchases and derivative instruments, which govern the use of commodity supply contracts and financial derivatives in order to manage the Company’s commodity supply and related price risk. These policies provide for the use of only those contracts, volumes and instrument types that are needed in the normal course of business, that help to manage gas supply costs and that have a close volume or price correlation to the Company’s assets, liabilities or forecasted transactions, thereby ensuring that such instruments will be used for hedging business risks and not for trading purposes.
Credit Exposure to Financial Derivative Counterparties.Increases in natural gas prices raised the Company’s credit exposure to its financial derivative counterparties and customers. During the third quarter of 2005, the Company’s. Based on estimated fair value, our credit exposure to financial derivative counterparties relating to commodity swap and call options, based on estimated fair value, increased by $278.0 million, from $62.5contracts was $26.4 million at June 30, 2005 to $340.5 million at Sept. 30, 2005. Of this increase, $192.1 million was attributable to existing contracts at June 30, 2005 and $85.9 million was due to new contracts entered into during the third quarter. The Company’sMarch 31, 2006. Our Derivatives Policy (the Policy) requires derivative counterparties to have a minimum investment-grade credit rating at the time the derivative instrument is entered into, and the Policypolicy specifies certain limits on the contract amount and duration based on each counterparty’s credit quality.rating. There were no credit rating downgrades for any of NW Natural’sour counterparties during the third quarter of 2005.quarter.
The following table summarizes the Company’sour credit exposure, based on estimated fair value, and the corresponding counterparty credit ratings. The table uses credit ratings from Standard & Poor’s Rating Services (S&P)S&P and Moody’s, Investors Service (Moody’s), reflecting the higher of the S&P or Moody’s rating:rating, or a middle rating if the entity is split rated with more than one rating level difference:
| Financial Derivative Exposures by Credit Rating | ||||||||||
Thousands | Fair Value Gains (Losses) | |||||||||
| Sept. 30, 2005 | Sept. 30, 2004 | Dec. 31, 2004 | ||||||||
AAA/Aaa | $ | 29,092 | $ | 1,974 | $ | (1,206 | ) | |||
AA/Aa | 287,940 | 64,560 | 13,105 | |||||||
A | — | 198 | — | |||||||
BBB/Baa | 23,481 | 2,567 | (1,453 | ) | ||||||
Total | $ | 340,513 | $ | 69,300 | $ | 10,446 | ||||
Dec. 31, 2005 Thousands AAA/Aaa AA/Aa BBB/Baa Total Financial Derivative Exposure by Credit Rating
Unrealized Fair Value Gain March 31, 2006 2005 $ 940 $ — $ — 25,465 86,376 172,315 — 1,619 3,346 $ 26,405 $ 87,995 $ 175,661
Credit Exposureexposure to Customers.customers.Increases in the market price of natural gas are expected to increase the Company’sour credit exposure to customers. Also, higher gas prices have resulted in some of NW Natural’s largeour largest industrial customers changingswitching from transportation service to sales service. Under transportation service, the customer is purchasing its commodity supplies from an independent third party, with NW Naturalwhile we only providing aprovide the transportation service for the delivery of that gas to the customer’s premise. Under sales service, the customer is purchasing both its gas commodity supply and transportation service from NW Natural.us. With higher natural gas commodity prices, NW Natural’sour credit exposure to large industrial sales customers is expected to increasehas increased significantly. NW Natural monitorsWe monitor and managesmanage the credit exposure of itsour industrial sales customers through credit policies and
procedures, which are designed to reduce credit risk. These policies and procedures include an ongoing review of credit risks, including changes in the services provided to industrial customers as well as changes in market conditions and customers’ credit quality. Changes in credit risk may require NW Naturalus to obtain additional assurance, such as deposits, letters of credit, guarantees and prepayments to reduce itsour credit exposure.
NW NaturalWe also monitorsmonitor and managesmanage the credit exposure of itsour residential and commercial customers. This credit risk is largely mitigated by the nature of the Company’sour regulated business and reasonably short collection terms, as well as by the consistent application of credit policies and procedures.
| Item 4. | CONTROLS AND PROCEDURES |
| (a) | Evaluation of Disclosure Controls and Procedures |
As of Sept. 30, 2005,March 31, 2006, the principal executive officer and principal financial officer of the Company have evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (Exchange Act)). Based upon that evaluation, the principal executive officer and principal financial officer of the Company have concluded that such disclosure controls and procedures are effective in timely alerting them to any material information relating to the Company and its consolidated subsidiaries required to be included in the Company’s reports filed with or furnished to the Securities and Exchange Commission under the Exchange Act.
| (b) | Changes in Internal Control Over Financial Reporting |
There has been no change in the Company’s internal control over financial reporting that occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
PART II. OTHER INFORMATION
| Item 1. | LEGAL PROCEEDINGS |
Litigation
For a discussion of certain pending legal proceedings, see Note 7, above.
| Item 1A. | RISK FACTORS |
There are no material changes in risk factors in the first quarter of 2006. For a discussion of risk factors, see Part I, Item 1.1A., Note 7, to the accompanying consolidated financial statements, above.
The Company is subject to other claims and litigation arising“Risk Factors,” in the ordinary course of business. Although the final outcome of any of these legal proceedings cannot be predicted with certainty, the Company does not expect that the ultimate disposition of these matters will have a materially adverse effect on the Company’s financial condition, results of operations or cash flows.2005 Form 10-K.
| Item 2. | UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
The following table provides information about purchases by the Companyus during the quarter ended Sept. 30, 2005March 31, 2006 of equity securities that are registered by the Company pursuant to Section 12 of the Exchange Act:
ISSUER PURCHASES OF EQUITY SECURITIES
Period | (a) Total Number of Shares Purchased (1) | (b) Average Price Paid per Share | (c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(2) | (d) Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs | (a) Total Number of Shares Purchased(1) | (b) Average Price Paid per Share | (c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(2) | (d) Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs | ||||||||||||||
Balance forward | 490,200 | $ | 21,938,837 | 765,600 | $ | 11,870,463 | ||||||||||||||||
07/01/05-07/31/05 | — | — | — | — | ||||||||||||||||||
08/01/05-08/31/05 | — | — | 243,100 | (8,950,729 | ) | |||||||||||||||||
09/01/05-09/30/05 | 5,141 | $ | 37.41 | — | — | |||||||||||||||||
01/01/06- 01/31/06 | 1,630 | $ | 35.95 | — | — | |||||||||||||||||
02/01/06- 02/28/06 | 26,040 | $ | 34.48 | — | — | |||||||||||||||||
03/01/06- 03/31/06 | 2,789 | $ | 33.94 | 11,700 | (398,001 | ) | ||||||||||||||||
Total | 5,141 | $ | 37.41 | 733,300 | $ | 12,988,108 | 30,459 | $ | 34.51 | 777,300 | $ | 11,472,462 | ||||||||||
| (1) | During the quarter ended March 31, 2006, 29,462 shares of our common stock were purchased in the open market to meet the requirements of our Dividend Reinvestment and Direct Stock Purchase Plan (DSPP). Prior to December 2005, the requirements of the DSPP were met by issuing original issue shares of common stock. In addition, 997 shares of our common stock were purchased in the open market during the quarter under equity-based programs. During the three months ended |
| (2) | On May 25, 2000, |
| Item 6. |
See Exhibit Index attached hereto.
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.
NORTHWEST NATURAL GAS COMPANY | ||||
(Registrant) | ||||
Dated: | /s/ Stephen P. Feltz | |||
Stephen P. Feltz | ||||
Principal Accounting Officer | ||||
Treasurer and Controller | ||||
NORTHWEST NATURAL GAS COMPANY
EXHIBIT INDEX
To
Quarterly Report on Form 10-Q
For Quarter Ended
Sept. 30, 2005March 31, 2006
Document | Exhibit Number | |
Statement re: Computation of Per Share Earnings | 11 | |
Computation of Ratio of Earnings to Fixed Charges | 12 | |
Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002 | 31.1 | |
Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002 | 31.2 | |
Certification of Principal Executive Officer and Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | 32.1 | |
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