UNITED STATES
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, 2006March 31, 2007
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. Yesx 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 filerx Accelerated filer¨ Non-accelerated filer¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes¨ Nox
At October 31, 2006, 27,504,896April 30, 2007, 26,987,803 shares of the registrant’s Common Stock (the only class of Common Stock) were outstanding.
NORTHWEST NATURAL GAS COMPANY
For the Quarterly Period Ended September 30, 2006March 31, 2007
Page Number | ||||
| ||||
Item 1. | Consolidated Financial Statements | |||
1 | ||||
2 | ||||
4 | ||||
5 | ||||
Item 2. | ||||
| Management’s Discussion and Analysis of Financial Condition and Results of Operations | |||
Item 3. | ||||
Item 4. | ||||
PART II. OTHER INFORMATION | ||||
Item 1. | ||||
Item 1A. | ||||
Item 2. | ||||
Item 6. | ||||
PART I. FINANCIAL INFORMATION
Consolidated Statements of Income
(Unaudited)
Three Months Ended Sept. 30, | Nine Months Ended Sept. 30, | Three Months Ended March 31, | ||||||||||||||||||
Thousands, except per share amounts | 2006 | 2005 | 2006 | 2005 | 2007 | 2006 | ||||||||||||||
Operating revenues: | ||||||||||||||||||||
Gross operating revenues | $ | 114,914 | $ | 106,667 | $ | 676,284 | $ | 569,111 | $ | 394,091 | $ | 390,391 | ||||||||
Less: Cost of sales | 70,634 | 62,231 | 431,069 | 335,264 | 245,469 | 255,399 | ||||||||||||||
Revenue taxes | 2,939 | 2,496 | 16,663 | 13,272 | 9,614 | 9,528 | ||||||||||||||
Net operating revenues | 41,341 | 41,940 | 228,552 | 220,575 | 139,008 | 125,464 | ||||||||||||||
Operating expenses: | ||||||||||||||||||||
Operations and maintenance | 25,640 | 25,988 | 81,796 | 80,164 | 28,839 | 28,247 | ||||||||||||||
General taxes | 5,595 | 5,915 | 19,234 | 17,895 | 7,817 | 7,573 | ||||||||||||||
Depreciation and amortization | 16,196 | 15,452 | 47,988 | 45,959 | 16,785 | 15,830 | ||||||||||||||
Total operating expenses | 47,431 | 47,355 | 149,018 | 144,018 | 53,441 | 51,650 | ||||||||||||||
Income (loss) from operations | (6,090 | ) | (5,415 | ) | 79,534 | 76,557 | ||||||||||||||
Other income and expense - net | 314 | 550 | 1,242 | 1,020 | ||||||||||||||||
Interest charges - net of amounts capitalized | 9,781 | 9,253 | 28,820 | 27,287 | ||||||||||||||||
Income from operations | 85,567 | 73,814 | ||||||||||||||||||
Other income and expense—net | 538 | 518 | ||||||||||||||||||
Interest charges—net of amounts capitalized | 9,567 | 9,855 | ||||||||||||||||||
Income (loss) before income taxes | (15,557 | ) | (14,118 | ) | 51,956 | 50,290 | ||||||||||||||
Income tax expense (benefit) | (5,833 | ) | (5,447 | ) | 18,653 | 17,934 | ||||||||||||||
Income before income taxes | 76,538 | 64,477 | ||||||||||||||||||
Income tax expense | 28,463 | 23,444 | ||||||||||||||||||
Net income (loss) | $ | (9,724 | ) | $ | (8,671 | ) | $ | 33,303 | $ | 32,356 | ||||||||||
Net income | $ | 48,075 | $ | 41,033 | ||||||||||||||||
Average common shares outstanding: | ||||||||||||||||||||
Basic | 27,556 | 27,560 | 27,568 | 27,564 | 27,229 | 27,584 | ||||||||||||||
Diluted | 27,669 | 27,630 | 27,686 | 27,626 | 27,385 | 27,632 | ||||||||||||||
Earnings (loss) per share of common stock: | ||||||||||||||||||||
Earnings per share of common stock: | ||||||||||||||||||||
Basic | $ | (0.35 | ) | $ | (0.31 | ) | $ | 1.21 | $ | 1.17 | $ | 1.77 | $ | 1.49 | ||||||
Diluted | $ | (0.35 | ) | $ | (0.31 | ) | $ | 1.20 | $ | 1.17 | $ | 1.76 | $ | 1.48 |
See Notes to Consolidated Financial StatementsStatements.
PART I. FINANCIAL INFORMATION
Thousands | Sept. 30, 2006 (Unaudited) | Sept. 30, 2005 (Unaudited) | Dec. 31, 2005 | March 31, 2007 (Unaudited) | March 31, 2006 (Unaudited) | Dec. 31, 2006 | ||||||||||||||||||
Assets: | ||||||||||||||||||||||||
Plant and property: | ||||||||||||||||||||||||
Utility plant | $ | 1,939,673 | $ | 1,857,053 | $ | 1,875,444 | $ | 1,981,639 | $ | 1,890,633 | $ | 1,963,498 | ||||||||||||
Less accumulated depreciation | 566,972 | 532,667 | 536,867 | 585,008 | 547,635 | 574,093 | ||||||||||||||||||
Utility plant - net | 1,372,701 | 1,324,386 | 1,338,577 | 1,396,631 | 1,342,998 | 1,389,405 | ||||||||||||||||||
Non-utility property | 41,662 | 39,450 | 40,836 | 45,767 | 40,953 | 42,652 | ||||||||||||||||||
Less accumulated depreciation and amortization | 6,684 | 5,755 | 5,990 | 7,149 | 6,221 | 6,916 | ||||||||||||||||||
Non-utility property - net | 34,978 | 33,695 | 34,846 | 38,618 | 34,732 | 35,736 | ||||||||||||||||||
Total plant and property | 1,407,679 | 1,358,081 | 1,373,423 | 1,435,249 | 1,377,730 | 1,425,141 | ||||||||||||||||||
Other investments | 55,695 | 57,939 | 58,451 | |||||||||||||||||||||
Current assets: | ||||||||||||||||||||||||
Cash and cash equivalents | 5,685 | 3,408 | 7,143 | 5,094 | 7,522 | 5,767 | ||||||||||||||||||
Accounts receivable | 31,791 | 30,518 | 84,418 | 89,489 | 97,859 | 82,070 | ||||||||||||||||||
Accrued unbilled revenue | 19,316 | 16,787 | 81,512 | 43,468 | 47,764 | 87,548 | ||||||||||||||||||
Allowance for uncollectible accounts | (2,060 | ) | (1,553 | ) | (3,067 | ) | (4,235 | ) | (4,526 | ) | (3,033 | ) | ||||||||||||
Gas inventory | 94,808 | 90,961 | 77,256 | |||||||||||||||||||||
Materials and supplies inventory | 9,723 | 7,855 | 8,905 | |||||||||||||||||||||
Income taxes receivable | 12,052 | 21,145 | 13,234 | |||||||||||||||||||||
Regulatory assets | 10,135 | 25,556 | 31,509 | |||||||||||||||||||||
Fair value of non-trading derivatives | 13,698 | 16,317 | 5,109 | |||||||||||||||||||||
Inventories: | ||||||||||||||||||||||||
Gas | 41,828 | 35,906 | 68,576 | |||||||||||||||||||||
Materials and supplies | 9,501 | 9,808 | 9,552 | |||||||||||||||||||||
Prepayments and other current assets | 44,125 | 36,106 | 54,309 | 14,761 | 57,330 | 21,695 | ||||||||||||||||||
Total current assets | 215,440 | 205,227 | 323,710 | 223,739 | 293,536 | 308,793 | ||||||||||||||||||
Regulatory assets: | ||||||||||||||||||||||||
Income tax asset | 66,757 | 65,622 | 65,843 | |||||||||||||||||||||
Deferred environmental costs | 22,836 | 17,456 | 18,880 | |||||||||||||||||||||
Deferred gas costs receivable | 5,183 | 5,414 | 6,974 | |||||||||||||||||||||
Unamortized costs on debt redemptions | 6,564 | 6,987 | 6,881 | |||||||||||||||||||||
Unrealized loss on non-trading derivatives | 31,317 | — | — | |||||||||||||||||||||
Investments, deferred charges and other assets: | ||||||||||||||||||||||||
Regulatory assets | 158,864 | 100,361 | 164,771 | |||||||||||||||||||||
Fair value of non-trading derivatives | 3,734 | 27,284 | 1,448 | |||||||||||||||||||||
Other investments | 48,247 | 54,432 | 47,985 | |||||||||||||||||||||
Other | — | 4,182 | — | 8,526 | 9,102 | 8,718 | ||||||||||||||||||
Total regulatory assets | 132,657 | 99,661 | 98,578 | |||||||||||||||||||||
Other assets: | ||||||||||||||||||||||||
Fair value of non-trading derivatives | 11,164 | 346,158 | 178,653 | |||||||||||||||||||||
Other | 8,781 | 8,748 | 9,216 | |||||||||||||||||||||
Total other assets | 19,945 | 354,906 | 187,869 | |||||||||||||||||||||
Total investments, deferred charges and other assets | 219,371 | 191,179 | 222,922 | |||||||||||||||||||||
Total assets | $ | 1,831,416 | $ | 2,075,814 | $ | 2,042,031 | $ | 1,878,359 | $ | 1,862,445 | $ | 1,956,856 | ||||||||||||
See Notes to Consolidated Financial StatementsStatements.
NORTHWEST NATURAL GAS COMPANY
PART I. FINANCIAL INFORMATION
Consolidated Balance Sheets
Thousands | Sept. 30, 2006 (Unaudited) | Sept. 30, 2005 (Unaudited) | Dec. 31, 2005 | March 31, 2007 (Unaudited) | March 31, 2006 (Unaudited) | Dec. 31, 2006 | ||||||||||||||||||
Capitalization and liabilities: | ||||||||||||||||||||||||
Capitalization: | ||||||||||||||||||||||||
Common stock | $ | 383,897 | $ | 87,230 | $ | 87,334 | $ | 363,519 | $ | 87,335 | $ | 371,127 | ||||||||||||
Premium on common stock | — | 296,376 | 296,471 | — | 296,281 | — | ||||||||||||||||||
Earnings invested in the business | 210,457 | 189,417 | 205,687 | 269,172 | 237,205 | 230,774 | ||||||||||||||||||
Unearned stock compensation | — | (703 | ) | (650 | ) | |||||||||||||||||||
Accumulated other comprehensive income (loss) | (1,911 | ) | (1,818 | ) | (1,911 | ) | (2,324 | ) | (1,911 | ) | (2,356 | ) | ||||||||||||
Total common stock equity | 592,443 | 570,502 | 586,931 | 630,367 | 618,910 | 599,545 | ||||||||||||||||||
Long-term debt | 492,000 | 521,500 | 521,500 | 517,000 | 501,500 | 517,000 | ||||||||||||||||||
Total capitalization | 1,084,443 | 1,092,002 | 1,108,431 | 1,147,367 | 1,120,410 | 1,116,545 | ||||||||||||||||||
Current liabilities: | ||||||||||||||||||||||||
Notes payable | 103,300 | 72,500 | 126,700 | 5,500 | 50,400 | 100,100 | ||||||||||||||||||
Long-term debt due within one year | 29,500 | 8,000 | 8,000 | 9,500 | 28,000 | 29,500 | ||||||||||||||||||
Accounts payable | 64,511 | 81,711 | 135,287 | 92,185 | 91,185 | 113,579 | ||||||||||||||||||
Taxes accrued | 12,071 | 10,867 | 12,725 | 43,116 | 25,876 | 21,230 | ||||||||||||||||||
Interest accrued | 11,454 | 11,493 | 2,918 | 11,409 | 11,623 | 2,924 | ||||||||||||||||||
Regulatory liabilities | 41,888 | 20,502 | 11,919 | |||||||||||||||||||||
Fair value of non-trading derivatives | 9,447 | 16,739 | 38,772 | |||||||||||||||||||||
Other current and accrued liabilities | 35,065 | 33,928 | 40,935 | 22,832 | 20,432 | 21,455 | ||||||||||||||||||
Total current liabilities | 255,901 | 218,499 | 326,565 | 235,877 | 264,757 | 339,479 | ||||||||||||||||||
Regulatory liabilities: | ||||||||||||||||||||||||
Accrued asset removal costs | 182,725 | 165,917 | 169,927 | |||||||||||||||||||||
Unrealized gain on non-trading derivatives - net | — | 338,667 | 171,777 | |||||||||||||||||||||
Customer advances | 2,245 | 1,733 | 1,847 | |||||||||||||||||||||
Other | 10,054 | — | 661 | |||||||||||||||||||||
Total regulatory liabilities | 195,024 | 506,317 | 344,212 | |||||||||||||||||||||
Other liabilities: | ||||||||||||||||||||||||
Deferred income taxes | 221,265 | 213,126 | 222,331 | |||||||||||||||||||||
Deferred investment tax credits | 4,527 | 5,415 | 5,069 | |||||||||||||||||||||
Deferred credits and other liabilities: | ||||||||||||||||||||||||
Deferred income taxes and investment tax credits | 207,648 | 225,047 | 210,084 | |||||||||||||||||||||
Regulatory liabilities | 208,333 | 203,244 | 202,982 | |||||||||||||||||||||
Pension and other postretirement benefit liabilities | 54,117 | 17,693 | 52,690 | |||||||||||||||||||||
Fair value of non-trading derivatives | 41,469 | 7,491 | 6,876 | 3,108 | 3,569 | 11,031 | ||||||||||||||||||
Other | 28,787 | 32,964 | 28,547 | 21,909 | 27,725 | 24,045 | ||||||||||||||||||
Total other liabilities | 296,048 | 258,996 | 262,823 | |||||||||||||||||||||
Total deferred credits and other liabilities | 495,115 | 477,278 | 500,832 | |||||||||||||||||||||
Commitments and contingencies (see Note 9) | — | — | — | |||||||||||||||||||||
Commitments and contingencies (see Note 10) | — | — | — | |||||||||||||||||||||
Total capitalization and liabilities | $ | 1,831,416 | $ | 2,075,814 | $ | 2,042,031 | $ | 1,878,359 | $ | 1,862,445 | $ | 1,956,856 | ||||||||||||
See Notes to Consolidated Financial StatementsStatements.
PART I. FINANCIAL INFORMATION
Consolidated Statements of Cash Flows
(Unaudited)
Nine Months Ended Sept. 30, | Three Months Ended March 31, | |||||||||||||||
Thousands | 2006 | 2005 | 2007 | 2006 | ||||||||||||
Operating activities: | ||||||||||||||||
Net income | $ | 33,303 | $ | 32,356 | $ | 48,075 | $ | 41,033 | ||||||||
Adjustments to reconcile net income to cash provided by operations: | ||||||||||||||||
Depreciation and amortization | 47,988 | 45,959 | 16,785 | 15,830 | ||||||||||||
Deferred income taxes and investment tax credits | (2,522 | ) | 1,801 | (3,381 | ) | (3,267 | ) | |||||||||
Undistributed earnings from equity investments | (314 | ) | (139 | ) | 78 | 50 | ||||||||||
Allowance for funds used during construction | (546 | ) | (351 | ) | ||||||||||||
Deferred gas costs - net | 1,791 | 4,137 | ||||||||||||||
Gain on sale of non-utility investments | — | (12 | ) | |||||||||||||
Contributions to qualified defined benefit pension plans | — | (20,000 | ) | |||||||||||||
Deferred gas savings (costs)—net | 14,242 | (6,548 | ) | |||||||||||||
Non-cash expenses related to qualified defined benefit pension plans | 4,122 | 3,576 | 1,064 | 1,441 | ||||||||||||
Deferred environmental costs | (4,700 | ) | (2,128 | ) | (2,800 | ) | (2,014 | ) | ||||||||
Income from life insurance investments | (2,196 | ) | (1,410 | ) | (480 | ) | (1,383 | ) | ||||||||
Other | 9,940 | (1,876 | ) | (2,940 | ) | 4,512 | ||||||||||
Changes in working capital: | ||||||||||||||||
Accounts receivable and accrued unbilled revenue - net | 113,816 | 79,324 | ||||||||||||||
Accounts receivable and accrued unbilled revenue—net | 37,997 | 21,766 | ||||||||||||||
Inventories of gas, materials and supplies | (18,370 | ) | (32,339 | ) | 26,799 | 40,447 | ||||||||||
Income taxes receivable | 1,182 | (5,175 | ) | — | 13,234 | |||||||||||
Prepayments and other current assets | 7,421 | 2,730 | 4,280 | 1,112 | ||||||||||||
Accounts payable | (70,776 | ) | (20,767 | ) | (21,394 | ) | (44,102 | ) | ||||||||
Accrued interest and taxes | 7,882 | 9,221 | 30,371 | 21,856 | ||||||||||||
Other current and accrued liabilities | (5,870 | ) | (240 | ) | 1,141 | (2,231 | ) | |||||||||
Cash provided by operating activities | 122,151 | 94,667 | 149,837 | 101,736 | ||||||||||||
Investing activities: | ||||||||||||||||
Investment in utility plant | (67,390 | ) | (65,226 | ) | (18,609 | ) | (16,997 | ) | ||||||||
Investment in non-utility property | (793 | ) | (5,465 | ) | (3,104 | ) | (106 | ) | ||||||||
Proceeds from sale of non-utility investments | — | 3,001 | ||||||||||||||
Proceeds from life insurance | 3,930 | 296 | — | 964 | ||||||||||||
Other | (164 | ) | 944 | 2,660 | (25 | ) | ||||||||||
Cash used in investing activities | (64,417 | ) | (66,450 | ) | (19,053 | ) | (16,164 | ) | ||||||||
Financing activities: | ||||||||||||||||
Common stock issued, net of expenses | 2,350 | 6,169 | 1,737 | 859 | ||||||||||||
Common stock repurchased | (1,608 | ) | (13,827 | ) | (9,017 | ) | (398 | ) | ||||||||
Long-term debt issued | — | 50,000 | ||||||||||||||
Long-term debt retired | (8,000 | ) | (15,528 | ) | (20,000 | ) | — | |||||||||
Change in short-term debt | (23,400 | ) | (30,000 | ) | (94,600 | ) | (76,300 | ) | ||||||||
Cash dividend payments on common stock | (28,534 | ) | (26,871 | ) | (9,677 | ) | (9,516 | ) | ||||||||
Other | 100 | 162 | ||||||||||||||
Cash used in financing activities | (59,192 | ) | (30,057 | ) | (131,457 | ) | (85,193 | ) | ||||||||
Decrease in cash and cash equivalents | (1,458 | ) | (1,840 | ) | ||||||||||||
Cash and cash equivalents - beginning of period | 7,143 | 5,248 | ||||||||||||||
Increase (decrease) in cash and cash equivalents | (673 | ) | 379 | |||||||||||||
Cash and cash equivalents—beginning of period | 5,767 | 7,143 | ||||||||||||||
Cash and cash equivalents - end of period | $ | 5,685 | $ | 3,408 | ||||||||||||
Cash and cash equivalents—end of period | $ | 5,094 | $ | 7,522 | ||||||||||||
Supplemental disclosure of cash flow information: | ||||||||||||||||
Interest paid | $ | 20,293 | $ | 18,414 | $ | 1,101 | $ | 970 | ||||||||
Income taxes paid | $ | 20,020 | $ | 21,939 | $ | 9,000 | $ | — | ||||||||
Supplemental disclosure of non-cash financing activities: | ||||||||||||||||
Conversions to common stock: | ||||||||||||||||
7-1/4 % Series of Convertible Debentures | $ | — | $ | 3,999 |
See Notes to Consolidated Financial Statements
PART I. FINANCIAL INFORMATION
Consolidated Statements of Capitalization
Thousands | Sept. 30, 2006 (Unaudited) | Sept. 30, 2005 (Unaudited) | Dec. 31, 2005 | ||||||||||||||||||
Common stock equity: | |||||||||||||||||||||
Common stock | $ | 383,897 | $ | 87,230 | $ | 87,334 | |||||||||||||||
Premium on common stock | — | 296,376 | 296,471 | ||||||||||||||||||
Earnings invested in the business | 210,457 | 189,417 | 205,687 | ||||||||||||||||||
Unearned compensation | — | (703 | ) | (650 | ) | ||||||||||||||||
Accumulated other comprehensive income (loss) | (1,911 | ) | (1,818 | ) | (1,911 | ) | |||||||||||||||
Total common stock equity | 592,443 | 55 | % | 570,502 | 52 | % | 586,931 | 53 | % | ||||||||||||
Long-term debt: | |||||||||||||||||||||
Medium-Term Notes | |||||||||||||||||||||
First Mortgage Bonds: | |||||||||||||||||||||
6.050% Series B due 2006 | — | 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 | 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 | 10,000 | ||||||||||||||||||
521,500 | 529,500 | 529,500 | |||||||||||||||||||
Less long-term debt due within one year | 29,500 | 8,000 | 8,000 | ||||||||||||||||||
Total long-term debt | 492,000 | 45 | % | 521,500 | 48 | % | 521,500 | 47 | % | ||||||||||||
Total capitalization | $ | 1,084,443 | 100 | % | $ | 1,092,002 | 100 | % | $ | 1,108,431 | 100 | % | |||||||||
See Notes to Consolidated Financial StatementsStatements.
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), aour regulated utility,gas distribution business and our regulated gas storage business, and its non-regulated wholly-owned subsidiary business, NNG Financial Corporation (Financial Corporation).
The information presented in the interim consolidated financial statements is unaudited, but includes all material adjustments, including normal recurring accruals, that management 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 our 20052006 Annual Report on Form 10-K (2005(2006 Form 10-K). A significant part of our business 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 yearsyear balances on our consolidated balance sheet have been reclassified to conform for comparison purposes, towith the current financial statement presentation. The 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 taxes other than income taxes. TheThese reclassifications had no impact on theour prior year’s income fromconsolidated results of operations and no material impact on financial condition or net income.cash flows.
2. | New Accounting Standards |
Adopted Standards
Share Based Payment.Accounting for Uncertainty in Income Taxes. Effective Jan.On January 1, 2006,2007, we adopted Statement of Financial Accounting Standards (SFAS)Board (FASB) Interpretation No. 123R, “Share Based Payment,48 (FIN 48), “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109,” usingwhich provides guidance for the Modified Prospective Application method without restatementrecognition and measurement of prior periods. Priora tax position taken or expected to be taken in a tax return. As a result of the implementation of SFAS No. 123R,FIN 48, we accountedrecognized no change in our recorded assets or liabilities for stock-based compensation usingunrecognized income tax benefits. Based on our analysis of all material tax positions taken, management believes the intrinsic value method prescribed in Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123Rtechnical merits of these positions are justified and expects that the full amount of the deductions taken and associated tax benefits will be allowed.
FIN 48 requires companies to recognize compensation expense for all equity-based compensation awards issued to employeesthe evaluation of a tax position as a two-step process. We must determine whether it is more likely than not that are expected to vest. Under this method, we began to amortize compensation cost fora tax position will be sustained upon examination, including the remaining portionresolution of outstanding awards for which the requisite service was not yet rendered at Jan. 1, 2006. Compensation cost for these awards wasany related appeals or litigation processes, based on the fair valuetechnical merits of the awardsposition. If the tax position meets the “more likely than not” recognition threshold, then the tax benefit is measured and recorded at the grant date which was determined under the intrinsic value method. We determine the fair valuelargest amount that is greater than 50 percent likely of and account for awards that are granted, modified or settled after Jan. 1, 2006being realized upon ultimate settlement. The re-assessment of our tax positions in accordance with SFAS No. 123R. The adoption of SFAS No. 123RFIN 48 did not have aresult in any material impact onchange to our financial condition, results of operations or cash flows. See Note 4 for a discussionFor additional information regarding income taxes, see Part II, Item 7., “Application of stock-based compensation.
Critical Accounting Policies and Estimates—Accounting for ChangesIncome Taxes,” and Error Corrections.Effective Jan. 1,Part II, Item 8., Note 8, in the 2006 we adopted SFAS No. 154, “AccountingForm 10-K.
We are subject to U.S. federal income taxes as well as several state and local income taxes. All of our U.S. federal income tax matters audited by the Internal Revenue Service through the 2004 tax year were concluded during 2006 with no material adjustments. Also, substantially all material state and local income tax matters are closed 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 changesyears through 2002. Based upon our assessment in accounting principles, unless it is impracticable
to determineconnection with the period-specific effects or the cumulative effect of the change. The guidance provided in 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 Dec. 15, 2005. The adoption of SFAS No. 154 didFIN 48, we do not believe there are any tax positions taken that would not be fully sustained upon audit.
We have also assessed the classification of interest and penalties, if any, related to income tax matters. Pursuant to the application of FIN 48, we have made an accounting election to treat interest and penalties related to income tax matters, if any, as a material impact upon our financial condition, resultscomponent of operations 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 periodincome tax expense rather than capitalized as inventory costs. The adoption of SFAS No. 151 did not have a material impact on our financial condition, results of operations or cash flows.other operating expenses.
Purchases and Sales of Inventory with the Same Counterparty. In September 2005, the Financial Accounting Standards Board (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.” 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,” 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. Adoption of this standard did not have a material impact on our financial condition, results of operations 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).” This FSP 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. Consolidation of a VIE by the primary beneficiary is required if it is determined that the VIE does not effectively disperse risks among the parties involved. 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. Adoption and implementation of FSP No. FIN 46(R)-6 did not have a material impact on our financial condition, results of operations or cash flows.
Recent Accounting Pronouncements
Accounting for Certain Hybrid Instruments.In February 2006, the FASB issued SFASStatement of Financial Accounting Standards (SFAS) No. 155, “Accounting for Certain Hybrid Instruments,” which amendsamended SFAS Nos.No. 133, “Accounting for Derivative Instruments and 140.Hedging Activities,” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities-a replacement of FASB Statement No. 125.” 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 statementSFAS No. 155 is effective for all financial instruments acquired or issued after Jan.January 1, 2007. We are in the process of evaluating the effect of theThe adoption and implementation of SFAS No. 155 which isdid not expected to have a materialan impact on our financial condition, results of operations or cash flows.
Recent Accounting for Uncertainty in Income Taxes.In July 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken in a tax return. Preparers must determinePronouncements
whether it is “more-likely-than-not” that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. Once it is determined that a position meets the more-likely-than-not recognition threshold, the position is measured to determine the amount of benefit to recognize in the financial statements. FIN 48 applies to all tax positions related to income taxes subject to SFAS No. 109, “Accounting for Income Taxes.” FIN 48 is effective for fiscal years beginning after Dec. 15, 2006. We do not anticipate that the adoption of this statement will have a material effect on our financial condition, results of operations or cash flows.
Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which provides a common definition for the measurement of fair value for use in applying generally accepted accounting principles in the United States (GAAP)of America and in preparing financial statement disclosures. SFAS No. 157 is effective for fiscal years beginning after Nov.November 15, 2007. We are in the process of evaluating the effect of the adoption and implementation of SFAS No. 157, which is not expected to have a material impact on our financial condition, results of operations or cash flows.
Employers’ AccountingFair Value Option for Defined Benefit PensionFinancial Assets and Other Postretirement Plans.Liabilities.In September 2006,February 2007, the FASB issued SFAS No. 158, “Employers’ Accounting159, “The Fair Value Option for Defined Benefit PensionFinancial Assets and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106Financial Liabilities,” which permits entities to choose to measure many financial instruments and 132(R).”certain other items at fair value. SFAS No. 158 requires balance sheet recognition of the overfunded or underfunded status of pension and other postretirement benefit plans. For pension plans, the liability will be based on the projected benefit obligation (PBO). Under SFAS No. 158, any actuarial gains and losses, prior service costs and transition assets or obligations that were not recognized under previous accounting standards must be recognized in accumulated other comprehensive income (AOCI) under common stock equity, net of tax, until they are amortized as a component of net periodic benefit cost. In addition, the measurement date, which is the date when plan assets and the benefit obligations are measured, is required to be the company’s fiscal year end. This measurement date change will have no effect on our plan assets or benefit liabilities because we have been using our fiscal year end, December 31, as our measurement date. SFAS No. 158159 is effective for us for the fiscal years endingbeginning after Dec.November 15, 2006.
2007. We are evaluating the effect of the adoption and implementation of SFAS No. 158. We intend to request regulatory deferral approval from our state commissions for deferred asset recognition of AOCI related to the funded status of certain plans under SFAS No. 71, “Accounting for Certain Types of Regulation.” If regulatory asset deferral of AOCI is approved, then we will recognize the change in actuarial gains and losses, prior service costs and transition assets or obligations each year as an adjustment to the regulatory AOCI asset or liability account as these amounts are recognized as components of net periodic pension costs each year. In prior years, regulatory deferral recognition was not necessary for us because we had maintained plan assets in excess of accumulated benefit obligations (ABO) for certain plans, and under the previous accounting standards the recognition of the unfunded status was not required based on PBO. Based on our unfunded obligations as of Dec. 31, 2005, the adoption of SFAS No. 158 would increase pension and postretirement liabilities by approximately $41 million, decrease deferred income tax liabilities by approximately $31 million, reduce prepayments and other current assets related to the elimination of our $37 million prepaid pension asset and decrease total common stock equity by approximately $47 million. Alternatively, if regulatory deferral is approved, our regulatory AOCI assets would increase by $47 million and total common stock equity would decrease by a negligible amount. The adoption of SFAS No. 158159, which is not expected to have a material impact on our financial condition, results of operations or cash flows. We also do not expect adoption
3. | Earnings Per Share |
Basic earnings per share are computed based on the weighted average number of SFAS No. 158 to effect our ability to meet financial debt covenants. Bycommon shares outstanding during each period presented. Diluted earnings per share reflect the timepotential effects of adoption at Dec.the exercise of stock options. Diluted earnings are calculated as follows:
Three Months Ended March 31, | ||||||
2007 | 2006 | |||||
Net income | $ | 48,075 | $ | 41,033 | ||
Average common shares outstanding—basic | 27,229 | 27,584 | ||||
Additional shares for stock-based compensation plans | 156 | 48 | ||||
Average common shares outstanding—diluted | 27,385 | 27,632 | ||||
Earnings per share of common stock—basic | $ | 1.77 | $ | 1.49 | ||
Earnings per share of common stock—diluted | $ | 1.76 | $ | 1.48 | ||
For the three month period ended March 31, 2006, actual plan performance and actuarial assumptions could9,000 common shares were excluded from the calculation of diluted earnings per share because the effect would have a material impact on the actual amounts recorded.been antidilutive.
Capital Stock |
In connection with the restatement ofan amendment to NW Natural’s Restated Articles of Incorporation effective May 31, 2006, the par value of NW Natural’s common stock was eliminated. As a result, NW Natural’s “common stock” and “premium on common stock” account balances are now reflected on the balance sheet as “common stock.” At March 31, 2007, we had 60,000,000 common shares authorized and 27,109,891 common shares outstanding.
We have in place a Board approved repurchase program for our common stock. During the three months ended March 31, 2007, 206,700 shares of our common stock were purchased pursuant to this program. In April 2007, the Board extended the program through May 31, 2008, further increased the authorization from 2.6 million shares to 2.8 million shares and further increased the dollar limit from $85 million to $100 million.
Stock-Based Compensation |
Effective 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 by employees and officers and, in the case of the NEDSCP, non-employee directors (seedirectors. For additional information on our stock-based compensation, see Part II, Item 8., Note 4, in the 2006 Form 10-K.
In November 2005, Form 10-K)the FASB issued FASB Staff Position No. SFAS 123(R)-3 (FSP 123(R)), “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards.” FSP 123(R) provides an elective alternative transition method for calculating the pool of excess tax benefits available to absorb tax deficiencies recognized subsequent to the adoption of FAS 123(R). Companies may take up to one year from the effective date of FSP 123(R) to evaluate the available transition alternatives and make a one-time election as to which method to adopt. We have adopted the long-form method for calculating the pool of excess tax benefits.
Long-Term Incentive Plan. A total of 500,000 shares of NW Natural’s common stock hashave been authorized for awards under the terms of the LTIP as stock bonus, restricted stock or performance-based stock awards. At Sept. 30, 2006, performance-based awards on 99,994 shares, based on meeting target performance levels, and restricted stock awards on 11,500 shares, including 10,500 shares subject to vesting requirements, were outstanding, withDuring the remaining 388,506 shares available for future grants.
Performance-based Stock Awards.At Sept. 30, 2006, the aggregate number ofquarter ended March 31, 2007, 42,000 performance-based shares awarded and outstanding under our LTIP at the threshold, target and maximum levels were as follows:
Year Awarded | Performance Period | Threshold | Target | Maximum | ||||
2004 | 2004-06 | 5,130 | 27,000 | 54,000 | ||||
2005 | 2005-07 | 6,333 | 33,332 | 66,664 | ||||
2006 | 2006-08 | 7,536 | 39,662 | 79,324 | ||||
Total | 18,999 | 99,994 | 199,988 | |||||
For each of the performance periods shown above, 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 results relative to our core and non-core strategies. For awards granted prior to Jan. 1, 2006, we recognize 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, we recognize compensation expense in accordance with SFAS No. 123R, based on performance levels achieved and an estimated fair value using a binomial model. For the quarter and nine months ended Sept. 30, 2006, the amount accrued and expensed as compensation under the three LTIP grants was $0.6 million. On a cumulative basis, $0.9 million, $1.0 million and $0.1 million have been accrued for the 2004-06, 2005-07 and 2006-08 performance periods, respectively.
Restricted Stock Awards.Restricted stock awards also have been granted under the LTIP. A restricted stock award consistingLTIP, based on target-level awards, with a weighted-average grant date fair value of 5,000 shares was granted in 2004, which vests ratably over the period 2005-09. On July 26, 2006, a restricted stock award was granted consisting of 6,500 shares, which will vest ratably over the period 2007-09.$33.29 per share.
Restated Stock Option Plan.Plan We have reserved a total of 2,400,000 shares of common. In February 2007, we granted 100,600 stock for issuanceoptions under the Restated SOP. At Sept. 30, 2006, options on 1,134,400 shares were available for grant and options to purchase 369,600 shares were outstanding. Options are grantedSOP, with an exercise price equal to the closing market price of theour common stock on the day preceding the date of grant, have 10-year terms and vest ratablyvesting over a three- orthe four-year period following the date of grant. Shares issued under the Restated SOP upon the exercisegrant and a term of stock options are original issue shares.10 years and 7 days. The fair value of our stock-based awards was 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 | % |
Risk-free interest rate | 4.7 | % | |
Expected life (in years) | 6.2 | ||
Expected market price volatility factor | 17.2 | % | |
Expected dividend yield | 3.2 | % | |
Forfeiture rate | 4.36 | % |
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 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 based on historical experience.
During 2006, we implemented SFAS No. 123R and, therefore, the pro forma effect of stock-based options and ESPP is as reported. However, the following table presents the effect on net income and earnings per share of outstanding stock options and stock awards for the 2005 periods:
Pro Forma Effect of Stock-Based Options and ESPP: Thousands, except per share amounts | Three Months | Nine Months | ||||||
Ended Sept. 30, 2005 | ||||||||
Net income (loss) as reported | $ | (8,671 | ) | $ | 32,356 | |||
Deduct: Pro forma stock-based compensation expense determined under the fair value based method - net of related tax effects | (84 | ) | (247 | ) | ||||
Pro forma net income (loss) - basic and diluted | $ | (8,755 | ) | $ | 32,109 | |||
Basic earnings (loss) per share | ||||||||
As reported | $ | (0.31 | ) | $ | 1.17 | |||
Pro forma | $ | (0.32 | ) | $ | 1.16 | |||
Diluted earnings (loss) per share | ||||||||
As reported | $ | (0.31 | ) | $ | 1.17 | |||
Pro forma | $ | (0.32 | ) | $ | 1.16 |
Summarized information for stock option grants is as follows:
Option Shares | Price per Share | ||||||||
Range | Weighted-Average Exercise Price | ||||||||
Balance Outstanding at Dec. 31, 2005 | 308,500 | $ | 20.25-38.30 | $ | 29.26 | ||||
Granted | 97,800 | 34.29 | 34.29 | ||||||
Exercised | (34,300 | ) | 20.25-31.34 | 27.20 | |||||
Expired | (2,400 | ) | 31.34-34.29 | 32.82 | |||||
Balance Outstanding at Sept. 30, 2006 | 369,600 | $ | 20.25-38.30 | $ | 30.76 | ||||
Exercisable at Dec. 31, 2005 | 189,500 | $ | 20.25-32.02 | $ | 27.63 | ||||
Exercisable at Sept. 30, 2006 | 213,700 | $ | 20.25-38.30 | $ | 28.80 | ||||
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 1,000 options will vest for a total of 214,700 exercisable options at year-end, assuming no additional option exercises or forfeitures.
During the three and nine months ended Sept. 30, 2006, pre-tax compensation expense amounted to $0.1 million and $0.5 million, respectively, relating to options granted under the Restated SOP. This expense was recognized in operations and maintenance expense under the fair value method in accordance with SFAS No. 123R. In addition, $0.1 million of pre-tax compensation expense related to the ESPP was recognized for the nine months ended Sept. 30, 2006. As of Sept. 30, 2006,March 31, 2007, there was $0.5$0.9 million of unrecognized compensation cost related to the unvested portion of outstanding stock option awards expected to be recognized over a period extending through 2009.2010.
In the nine months ended Sept. 30, 2006, 34,300 option shares were exercised with a total intrinsic value of $0.3 million. Cash of $1.1 million was received for these exercises and a $0.1 million related tax benefit was realized. The total intrinsic value of options exercised in the first nine months of 2005 was $1.2 million, and the total fair value of options that vested in the first nine months of 2006 and 2005 was $0.3 million and $0.5 million, respectively.
The following table summarizes additional information about stock options outstanding and exercisable at Sept. 30, 2006:
Outstanding | Exercisable | ||||||||||||||
Range of Exercise Prices | Stock Options | (In millions) Intrinsic Value | Stock Options | (In millions) Intrinsic Value | Weighted- Average Exercise Price | Weighted- Average Remaining Life in Years | |||||||||
$20.25 -38.30 | 369,600 | $ | 3.1 | 213,700 | $ | 2.2 | $ | 28.80 | 5.8 |
Long-Term Debt |
In JuneAt March 31, 2007 and 2006 and December 31, 2006, we redeemed $8.0 million of secured 6.05% Series B Medium-Term Notes at maturity.
Thousands | March 31, 2007 (Unaudited) | March 31, 2006 (Unaudited) | Dec. 31, 2006 | ||||||
Medium-Term Notes | |||||||||
First Mortgage Bonds: | |||||||||
6.05 % Series B due 2006(1) | $ | — | $ | 8,000 | $ | — | |||
6.31 % Series B due 2007(2) | — | 20,000 | 20,000 | ||||||
6.80 % Series B due 2007 | 9,500 | 9,500 | 9,500 | ||||||
6.50 % Series B due 2008 | 5,000 | 5,000 | 5,000 | ||||||
4.11 % Series B due 2010 | 10,000 | 10,000 | 10,000 | ||||||
7.45 % Series B due 2010 | 25,000 | 25,000 | 25,000 | ||||||
6.665% Series B due 2011 | 10,000 | 10,000 | 10,000 | ||||||
7.13 % Series B due 2012 | 40,000 | 40,000 | 40,000 | ||||||
8.26 % Series B due 2014 | 10,000 | 10,000 | 10,000 | ||||||
4.70 % Series B due 2015 | 40,000 | 40,000 | 40,000 | ||||||
5.15 % Series B due 2016 | 25,000 | — | 25,000 | ||||||
7.00 % Series B due 2017 | 40,000 | 40,000 | 40,000 | ||||||
6.60 % Series B due 2018 | 22,000 | 22,000 | 22,000 | ||||||
8.31 % Series B due 2019 | 10,000 | 10,000 | 10,000 | ||||||
7.63 % Series B due 2019 | 20,000 | 20,000 | 20,000 | ||||||
9.05 % Series A due 2021 | 10,000 | 10,000 | 10,000 | ||||||
5.62 % Series B due 2023 | 40,000 | 40,000 | 40,000 | ||||||
7.72 % Series B due 2025 | 20,000 | 20,000 | 20,000 | ||||||
6.52 % Series B due 2025 | 10,000 | 10,000 | 10,000 | ||||||
7.05 % Series B due 2026 | 20,000 | 20,000 | 20,000 | ||||||
7.00 % Series B due 2027 | 20,000 | 20,000 | 20,000 | ||||||
6.65 % Series B due 2027 | 20,000 | 20,000 | 20,000 | ||||||
6.65 % Series B due 2028 | 10,000 | 10,000 | 10,000 | ||||||
7.74 % Series B due 2030 | 20,000 | 20,000 | 20,000 | ||||||
7.85 % Series B due 2030 | 10,000 | 10,000 | 10,000 | ||||||
5.82 % Series B due 2032 | 30,000 | 30,000 | 30,000 | ||||||
5.66 % Series B due 2033 | 40,000 | 40,000 | 40,000 | ||||||
5.25 % Series B due 2035 | 10,000 | 10,000 | 10,000 | ||||||
526,500 | 529,500 | 546,500 | |||||||
Less long-term debt due within one year | 9,500 | 28,000 | 29,500 | ||||||
Total long-term debt | $ | 517,000 | $ | 501,500 | $ | 517,000 | |||
(1) | Redeemed at maturity in June 2006. |
(2) | Redeemed at maturity in March 2007. |
7. | Use of |
We enter 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
(collectively referred to as SFAS No. 133). We primarily utilize derivative financial instruments primarily to manage commodity prices related to natural gas supply requirements (see Part II, Item 8., Note 11, in the 20052006 Form 10-K).
At Sept. 30,March 31, 2007 and 2006, and 2005, unrealized gains orand losses from mark-to-market valuations of our derivative instruments were primarily reported as regulatory liabilities or regulatory assets because the realized gains or losses at settlement are included in utility gas costs, pursuant to our regulatory Purchased Gas Adjustment (PGA) deferral mechanisms.mechanism. The estimated fair valuesvalue of unrealized gains and losses on derivative instruments outstanding, determined using a discounted cash flow model for swaps and indexed-price contracts and a Black-Scholes option pricing model for options, were as follows:
Sept. 30, | Dec. 31, | |||||||||||||||||||||||||||||||||||
Thousands | 2006 | 2005 | 2005 | March 31, 2007 | March 31, 2006 | Dec. 31, 2006 | ||||||||||||||||||||||||||||||
Current | Non- Current | Current | Non- Current | Current | Non- Current | |||||||||||||||||||||||||||||||
Fair Value Gain (Loss): | ||||||||||||||||||||||||||||||||||||
Natural gas commodity-based derivative instruments: | ||||||||||||||||||||||||||||||||||||
Fixed-price financial swaps | $ | (29,122 | ) | $ | 321,119 | $ | 173,790 | $ | 6,034 | $ | 1,536 | $ | 1,063 | $ | 25,342 | $ | (33,965 | ) | $ | (6,312 | ) | |||||||||||||||
Fixed-price financial call options | — | 19,394 | 1,871 | (494 | ) | — | — | — | (678 | ) | — | |||||||||||||||||||||||||
Indexed-price physical supply | (2,342 | ) | (5,281 | ) | (5,454 | ) | (1,258 | ) | (910 | ) | (2,096 | ) | (1,627 | ) | 1,115 | (3,271 | ) | |||||||||||||||||||
Fixed-price physical supply | — | 3,158 | 820 | |||||||||||||||||||||||||||||||||
Physical supply contracts with embedded options | 43 | — | 567 | |||||||||||||||||||||||||||||||||
Physical supply contracts | — | — | 566 | — | — | — | ||||||||||||||||||||||||||||||
Foreign currency forward purchases | 104 | 277 | 183 | (31 | ) | — | 45 | — | (135 | ) | — | |||||||||||||||||||||||||
Total | $ | (31,317 | ) | $ | 338,667 | $ | 171,777 | $ | 4,251 | $ | 626 | $ | (422 | ) | $ | 23,715 | $ | (33,663 | ) | $ | (9,583 | ) | ||||||||||||||
In the thirdfirst quarter of 2006,2007, we realized net losses of $12.4$7.6 million from the settlement of fixed-price financial swap contracts which were recorded as increases to the cost of gas, compared to net gaingains of $20.5$17.5 million in 2005.the same period of 2006. Realized losses from financial contracts in 2007 were more than offset by lower gas purchase costs from the underlying hedged floating rate physical supply contracts. The foreign exchangecurrency gain or loss on foreign currency forward contracts is included in cost of gas at settlement; therefore, no gain or loss was recorded from the settlement of those contracts.settlement.
As of Sept. 30, 2006,March 31, 2007, all non-current natural gas commodity price swapcommodity-based derivative contracts mature no later than Oct.October 31, 2008.
Segment Information |
Our primarycore business is the local gas distribution segment, “Utility,also referred to as the “utility,” consists ofwhich involves the distribution and sale of natural gas. Another business segment, “Interstate Gas Storage,“gas storage,” represents natural gas storage services provided to interstateintrastate and intrastateinterstate customers and includes asset optimization activities performed byservices under a contract with an unaffiliatedindependent energy marketing company primarily through the use of commodity transactions and temporary releases of portions of NW Natural’s upstream pipeline transportation capacity and gas storage capacity (see Part II, Item 8., Note 2, in the 2005 Form 10-K).company. The remaining business segment, “Other,“other,” primarily consists of non-utility operating activitiesnon-regulated investments in alternative energy projects in California, a Boeing 737-300 aircraft leased to Continental Airlines and non-regulated investments.low-income housing units in Portland, Oregon. Our net investment in the aircraft was reclassified to current assets as of December 31, 2006, with the original lease term expiring in September 2007.
The following table presents information about the reportable segments. 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 | ||||||||||||||||||||
2006 | ||||||||||||||||||||||||||||
Net operating revenues | $ | 38,085 | $ | 3,211 | $ | 45 | $ | 41,341 | $ | 218,476 | $ | 9,961 | $ | 115 | $ | 228,552 | ||||||||||||
Depreciation and amortization | 15,975 | 221 | — | 16,196 | 47,327 | 661 | — | 47,988 | ||||||||||||||||||||
Income (loss) from operations | (8,634 | ) | 2,720 | (176 | ) | (6,090 | ) | 71,480 | 8,653 | (599 | ) | 79,534 | ||||||||||||||||
Income from financial investments | 399 | — | 255 | 654 | 2,196 | — | 314 | 2,510 | ||||||||||||||||||||
Net income (loss) | (11,408 | ) | 1,496 | 188 | (9,724 | ) | 28,258 | 4,762 | 283 | 33,303 | ||||||||||||||||||
Total assets at Sept. 30, 2006 | 1,784,762 | 35,844 | 10,810 | 1,831,416 | 1,784,762 | 35,844 | 10,810 | 1,831,416 | ||||||||||||||||||||
2005 | ||||||||||||||||||||||||||||
Net operating revenues | $ | 38,765 | $ | 3,126 | $ | 49 | $ | 41,940 | $ | 213,377 | $ | 7,107 | $ | 91 | $ | 220,575 | ||||||||||||
Depreciation and amortization | 15,289 | 163 | — | 15,452 | 45,469 | 490 | — | 45,959 | ||||||||||||||||||||
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 |
Three Months Ended March 31, | |||||||||||||
Thousands | Utility | Gas Storage | Other | Total | |||||||||
2007 | |||||||||||||
Net operating revenues | $ | 135,549 | $ | 3,410 | $ | 49 | $ | 139,008 | |||||
Depreciation and amortization | 16,563 | 222 | — | 16,785 | |||||||||
Income from operations | 82,595 | 2,941 | 31 | 85,567 | |||||||||
Income (loss) from financial investments | 480 | — | (78 | ) | 402 | ||||||||
Net income | 46,108 | 1,795 | 172 | 48,075 | |||||||||
Total assets at March 31, 2007 | $ | 1,831,806 | $ | 39,004 | $ | 7,549 | $ | 1,878,359 | |||||
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 | 39,463 | 1,449 | 121 | 41,033 | |||||||||
Total assets at March 31, 2006 | $ | 1,815,343 | $ | 35,533 | $ | 11,569 | $ | 1,862,445 |
Pension and Other Postretirement Benefits |
NW Natural maintains two qualified non-contributory defined benefit pension plans covering all regular employees with more than one year of service. In July 2006, the Board of Directors approved changes to the defined benefit pension plan covering non-bargaining unit employees, closing participation to any new employees hired on or after Jan. 1, 2007. For affected employees, we will provide an enhanced benefit under our existing Retirement K Savings Plan, which is a defined contribution plan under Internal Revenue Code Section 401(k).
Net Periodic Benefit Cost
The following table provides the components of net periodic benefit cost for theour qualified and non-qualified defined benefit pension plans and other postretirement benefit plans (seeplans:
Thousands | Three Months Ended March 31, | |||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
2007 | 2006 | 2007 | 2006 | |||||||||||||
Service cost | $ | 2,159 | $ | 1,961 | $ | 148 | $ | 137 | ||||||||
Interest cost | 3,995 | 3,758 | 320 | 283 | ||||||||||||
Expected return on plan assets | (4,636 | ) | (4,403 | ) | — | — | ||||||||||
Amortization of loss | 539 | 916 | 1 | — | ||||||||||||
Amortization of prior service cost | 245 | 245 | 49 | 49 | ||||||||||||
Amortization of transition obligation | — | — | 103 | 103 | ||||||||||||
Net periodic benefit cost | 2,302 | 2,477 | 621 | 572 | ||||||||||||
Amount allocated to construction | (515 | ) | (700 | ) | (202 | ) | (187 | ) | ||||||||
Net amount charged to expense | $ | 1,787 | $ | 1,777 | $ | 419 | $ | 385 | ||||||||
See Part II, Item 8., Note 7, in the 20052006 Form 10-K for a discussion of the assumptions used in measuring these costsmore information about our pension and other postretirement benefit obligations).plans.
Thousands Other Postretirement Benefits Service cost Interest cost Special termination benefits Expected return on plan assets Amortization of transition obligation Amortization of prior service cost Recognized actuarial loss Net periodic benefit cost Thousands Other Postretirement Benefits Service cost Interest cost Special termination benefits Expected return on plan assets Amortization of transition obligation Amortization of prior service cost Recognized actuarial loss Net periodic benefit cost Pension Benefits Three Months Ended Sept. 30, 2006 2005 2006 2005 $ 1,784 $ 1,564 $ 142 $ 114 3,761 3,377 322 308 — 63 — — (4,403 ) (3,776 ) — — — — 103 103 245 361 48 — 805 599 — 72 $ 2,192 $ 2,188 $ 615 $ 597 Pension Benefits Nine Months Ended Sept. 30, 2006 2005 2006 2005 $ 5,706 $ 4,741 $ 417 $ 342 11,277 9,903 888 924 — 189 — — (13,210 ) (10,837 ) — — — — 309 309 735 807 146 — 2,638 1,562 — 216 $ 7,146 $ 6,365 $ 1,760 $ 1,791
Employer Contributions
We areDuring the three months ended March 31, 2007, we did not make and were not required to make cash contributions to our qualified non-contributory defined benefit plans, in 2006, but cash contributions in the form of ongoing benefit payments will be requiredof $0.6 million were made for theour unfunded, non-qualified supplemental pension plans and other postretirement benefit plans in 2006.plans. See Part II, Item 8., Note 7, in the 20052006 Form 10-K for a discussion of future payments.
Commitments and Contingencies |
Environmental Matters
We own, or have previously owned, properties that may require environmental remediation or action. We accrue all material loss contingencies relating to these properties that we believe to be probable of assertion and reasonably estimable. We continue to study the extent of our 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. We regularly review our remediation liability for each site where we 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 and associated cost estimates. 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, we estimate 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 more likely estimate within this range of probable cost, we record 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 our 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, seeSee Part II, Item 8., Note 12, in the 20052006 Form 10-K for a description10-K. The status of these properties and further discussion.each site currently under investigation is provided below.
Gasco site. We own property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 (the Gasco site). We haveThe Gasco site has been investigating the Gasco siteunder investigation by us for environmental contamination under the Oregon Department of Environmental Quality’s (ODEQ) Voluntary Clean-Up Program. In June 2003, we 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. In the thirdfirst quarter of 2006, we accrued an additional $0.32007, the estimated liability for this site increased $0.5 million related to be usedestimated liabilities for the upgradedevelopment of the water treatment system in conjunction withproposed studies of in-water source control replacementand completion of those studies. We have accrued a well, ongoing consultant and investigation fees for in-river groundwater and source control studies and to cover cost estimatesliability of remedial alternatives identified in the Feasibility Scoping Plan and Ecological and Human Health Risk Assessment$6.2 million at March 31, 2007 for the most contaminated portion of the site. The liability balance at Sept. 30, 2006 is $2.7 million,Gasco site, which is at the low end of the probablerange because no amount within the range is considered to be more likely than another and reasonably estimable liability range. We are not able to estimate the high end of a liability range.the range cannot be estimated.
Siltronic site. We previously owned property adjacent to the Gasco site that is now is the location of a manufacturing plant owned by Siltronic Corporation (the Siltronic site). We had previously agreed to an addendum to the Voluntary Clean-up Agreementare currently working with the ODEQ which will require additional investigationto develop a study of potential manufactured gas plant wastes on the Siltronicuplands portion of this site. Since the scope of work is unknown, there is not enough information to reasonably estimate the additional liability. The additional amount accruedSee “Regulatory and Insurance Recovery for this work in the third quarter of 2006 was negligible.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(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 we were notified that we are a potentially responsible party. We then joined with other potentially responsible parties, referred to as the Lower Willamette Group, to fund environmental studies in the Portland Harbor. 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). In the third quarter of 2006, we accrued an additional $0.7 million to reflect our current estimate of liability of $1.9 million related to the RI/FS for consultant fees, technical work and other costs. InformationCurrent 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, we entered into an Administrative Order on Consent providing for early action removal of a deposit of tar in the Willamette Riverriver sediments adjacent to the Gasco site. TheWe completed the removal of the tar deposit in the Portland Harbor was completed in October 2005, and in November 2005,which was approved by the EPA approved the completed project. In the third quarterEPA. The total cost of 2006, we accrued an additional $0.1 million to reflect our current estimate of liability of $0.9 million for costs related to the tar deposit,removal, including technical work, oversight, consultant andfees, legal fees and ongoing monitoring.monitoring, was about $10.3 million. To date $9.4we have paid $9.3 million has been spent foron work related to the removal of the tar deposit.deposit with a remaining liability estimate of $1.0 million.
Central Gas Storage Tanks.On Sept. 22,In September 2006, we received notice from the ODEQ that our Central Service Center has beenin southeast Portland (the Central Service Center site) was assigned a high priority for further environmental investigation. Previously there were three manufactured gas storage tanks on the premises. The ODEQ believes there could be site contamination associated with releases of condensate from stored manufactured gas, or through historic gas handling practices. In the early 1990s, we excavated waste piles and much of the contaminated
surface soils and removed accessible waste from some of the abandoned piping. A negligibleWe initially recorded a small accrual was recorded in September 2006 for the ODEQ site assessment and legal and technical costs to investigate and determine the appropriate action needed to be taken, if any. In early 2007, we received notice that the site has been added to the ODEQ’s list of sites where releases of hazardous substances have been confirmed and its list where additional investigation or cleanup is necessary. Additional costs are not currently estimable. We intend to seekreceived regulatory authorization from the OPUC for the deferral of environmental costs related to this site (see “Regulatory and Insurance Recovery for Environmental Matters,” below).
Oregon Steel Mills site. See “Legal Proceedings,” below.
Regulatory and Insurance Recovery for Environmental Matters. In May 2003, the Oregon Public Utility Commission (OPUC)OPUC approved our request for deferral of environmental costs associated with specific sites, including the Gasco, Siltronic and Portland Harbor sites. The authorization, which has beenwas extended through January 2007,2008 and expanded to include the Oregon Steel Mills site (discussed below) and the Central Service Center site (discussed above), allows us to defer and seek recovery of unreimbursed environmental costs in a future general rate case. In AprilBeginning in 2006, the OPUC authorized us to accrue 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 Sept. 30, 2006, we have paid a cumulative total of $17.1 million relating to the covered sites since the effective date of the deferral authorization.
On a cumulative basis, we have recognized a total of $27.7$33.2 million for environmental costs, including legal, investigation, monitoring and remediation costs. Of this total, $22.0$26.8 million has been spent to-dateto date and $5.7$6.4 million is reported as an outstanding liability. During the third quarterAt March 31, 2007, we had a regulatory asset of 2006, we increased regulatory assets by $1.1$28.3 million, which includes $21.9 million for paid expenditures and interest plus $6.4 million for additional environmental cost estimates relatedaccruals expected to sites authorized for deferral treatment, and at Sept. 30, 2006 we had a total environmental regulatory asset of $22.8 million, which includes $17.1 million of total expenditures to date and additional accruals of $5.7 million.be paid in the future. We believe the recovery of these costsdeferred charges is probable through the regulatory process after first pursuing recovery of costs from insurance.process. We also have an insurance receivable of $1.1 million, which is not included in the regulatory asset amount. We intend to pursue recovery of thesethis insurance receivable and environmental costsregulatory deferrals from our general liability insurance policies, and the regulatory asset will be reduced by the amount of any corresponding insurance recoveries. We consider insurance recovery of some portion of our environmental costs probable based on a combination of factors, including a review of the terms of our 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 Oregon law, whichlegislation that allows an insured party to seek recovery of “all sums” from one insurance company. We have notifiedinitiated settlement discussions with a majority of our insurers but continue to anticipate that our overall insurance recovery effort will extend over several years.
The following table summarizes the insurance companies but have not yet filed claims for recovery, nor have the insurance companies approved or denied coverage of these claims.regulatory assets and accrued liabilities relating to environmental matters at March 31, 2007 and 2006 and December 31, 2006:
Non-Current Regulatory Assets | Non-Current Liabilities | |||||||||||||||||
March 31, | Dec. 31, | March 31, | Dec. 31, | |||||||||||||||
Millions | 2007 | 2006 | 2006 | 2007 | 2006 | 2006 | ||||||||||||
Gasco site | $ | 10.8 | $ | 3.4 | $ | 10.3 | $ | 6.2 | $ | 1.0 | $ | 6.6 | ||||||
Siltronic site | 0.5 | 0.3 | 0.5 | 0.1 | — | 0.1 | ||||||||||||
Portland Harbor site | 16.8 | 15.2 | 16.8 | 1.7 | 3.5 | 3.1 | ||||||||||||
Oregon Steel Mills site | 0.2 | 0.2 | 0.2 | 0.2 | 0.2 | 0.2 | ||||||||||||
Total | $ | 28.3 | $ | 19.1 | $ | 27.8 | $ | 8.2 | $ | 4.7 | $ | 10.0 | ||||||
Legal Proceedings
We are 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, we do not expect that the ultimate disposition of these matters will have a material adverse effect on our financial condition, results of operations or cash flows.
Georgia-Pacific Corporation vs. Northwest Natural Gas Company.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 we offered to sell natural gas to Georgia-Pacific under the interruptible sales service provisions of Rate Schedule 32 at a commodity rate set at our Weighted Average Cost of Gas. Georgia-Pacific further alleged that it accepted this offer and that we failed to perform as promised when, in October 2005, we notified Georgia-Pacific that we would have to charge Georgia-Pacific the incremental costs of acquiring gas on the open market. Georgia-Pacific also alleged breach of contract, promissory estoppel, fraudulent misrepresentation and breach of the duty of good faith and fair dealing.
On Feb. 23, 2006, we filed a motion for summary judgment on all claims. On June 30, 2006, an order was issued by the U.S. District Court for the District of Oregon dismissing the lawsuit with prejudice and denying all pending motions, if any, as moot. On July 27, 2006, Georgia-Pacific appealed this ruling to the Ninth Circuit Court of Appeals. We do not expect the outcome of this appeal to have a material adverse effect on our financial condition, results of operations or cash flows.
Independent Backhoe Operator Action.Since May 2004, five lawsuits have been filed against NW Natural by 11 independent backhoe operators who performed backhoe services for NW Natural under contract. These five lawsuits have been consolidated into one case, in which 10 plaintiffs remain (Law and Zuehlke, et. al. v. Northwest Natural Gas Co.,CV-04-728-KI, United States District Court, District of Oregon). 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 one exception, plaintiffs allegealleged that the failure to classify them as employees constituted a breach of contract and a tort under and with respect to certain employee benefits plans, programs and agreements. With the one exception, plaintiffs seekPlaintiffs sought 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. We expect thatIn May 2007, the remaining plaintiff will amend his complaint to includeDistrict Court granted our motion for Summary Judgment on plaintiffs’ breach of contract and tortbenefits claims. The ruling leaves only the overtime and wage and hour claims for unspecified damages.
In October 2005,in the court granted NW Natural’s motion to stay plaintiffs’ claims pending exhaustioncase. Our estimate 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 ofremaining liability, if any, from these claims.is not material. We will continue to vigorously contest these claims andtherefore do not expect that the outcome of this litigation willto have a material adverse effect on our financial condition, results of operations or cash flows.
Oregon Steel Mills site. In 2004, we wereNW Natural 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. The Port alleges that in the 1940s and 1950s petroleum wastes generated by NW
Natural’sour predecessor, Portland Gas & Coke Company, and ten10 other third-party defendants were disposed of in a waste oil in a 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 NW Naturalourselves and other third-party defendants were denied on the basis that the failure of the Port to plead and prove that we were 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. We received regulatory authorization from the OPUC for the deferral of environmental costs related to this site (see “Regulatory and Insurance Recovery for Environmental Matters,” above). We do not expect that the ultimate disposition of this matter will have a material adverse effect on our financial condition, results of operations or cash flows.
Pipeline Safety Inspection.On Sept. 22, 2006, the Washington Utilities and Transportation Commission (WUTC) issued a Standard Natural Gas Pipeline Safety Inspection report on our facilities in Clark County, Washington. Based on the findings of the inspection report and regulatory action taken with other gas distribution companies, enforcement action is expected. We are in the process of taking corrective action and do not expect the impact of this action to have a material adverse effect on our financial condition, results of operations or cash flows.
Comprehensive Income |
For the three and nine months ended Sept. 30, 2006 and 2005, reported net income was equivalent to total comprehensive income. Items that are excluded from net income and charged directly to common stock equity are included in accumulated other comprehensive income (loss), net of tax. The amount of accumulated other comprehensive loss in total common stock equity is $1.9$2.3 million at Sept. 30, 2006,March 31, 2007, which is related to our minimum pension liability (see “Consolidated Statementsemployee benefit plan liabilities. The following table provides a reconciliation of Capitalization,” above).net income to total comprehensive income for the three months ended March 31, 2007 and 2006.
Three Months Ended March 31, | ||||||
Thousands | 2007 | 2006 | ||||
Net income | $ | 48,075 | $ | 41,033 | ||
Amortization of employee benefit plan liability, net of tax | 32 | — | ||||
Total comprehensive income | $ | 48,107 | $ | 41,033 | ||
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. 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.
We are also engaged in the delivery of interstate and intrastate gas storage services, operating as a non-utility business segment with the interstate service subject to Federal Energy Regulatory Commission (FERC) regulation. This segment, which represents approximately 2 percent of consolidated total assets, provides services to large customers using Mist storage and our transportation capacity. Asset optimization transactions are also entered into pursuant to an agreement with an independent energy marketing company. Factors critical to the ongoing success of this segment include being able to develop additional storage capacity in advance of core utility customers’ requirements at competitive market prices and being able to continue to optimize the value of our assets, with both storage and optimization being subject to state regulatory sharing agreements.
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 business activities, which together are referred to in this report as our Other business segment (see Note 7).
The following is management’s assessment of ourNorthwest Natural Gas Company’s financial condition, including the principal factors that affect our results of operations. The discussion refers to our consolidated activities for the three and nine months ended Sept. 30, 2006March 31, 2007 and 2005.2006. Unless otherwise indicated, references in this discussion to “Notes” are to the notesNotes to theConsolidated Financial Statements in this report.
The consolidated financial statements ininclude the accounts of Northwest Natural Gas Company, which principally consists of our regulated local gas distribution business, our regulated gas storage business, and our other non-regulated businesses, which includes our wholly-owned subsidiary business, NNG Financial Corporation (Financial Corporation). In this report. report, the term “utility” is used to describe our regulated gas distribution business, and the term “non-utility” is used to describe our gas storage business segment (gas storage) and our other non-regulated activities (other) (see Note 8).
Certain prior year balances on our consolidated balance sheet have been reclassified to conform with the current presentation. These reclassifications had no impact on our prior year’s consolidated results of operations, and no material impact on financial condition or cash flows.
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. We 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 section to earnings per share in this report are on the basis of diluted shares except where noted otherwise (see Part II, Item 8., Note 1, “Earnings Per Share,” in the 20052006 Form 10-K).
Executive Summary
Our strategy in 2007 is to remain focused on profitably growing our regulated gas utility and gas storage businesses. The gas utility is our largest business segment with approximately 98 percent of consolidated total assets, which contributed 90 percent of consolidated net income in 2006. Factors critical to the success of the utility include maintaining a safe and reliable distribution system, acquiring an adequate supply of gas, providing distribution services at a competitive price, and being able to recover the operating and capital costs of the utility in the rates charged to customers. The utility is regulated by two state commissions, the Oregon Public Utility Commission (OPUC) and the Washington Utilities and Transportation Commission (WUTC).
Our gas storage segment represents approximately 2 percent of consolidated total assets, which contributed 9 percent of consolidated net income in 2006. This business unit primarily provides firm and interruptible gas storage at our Mist underground storage facility to large interstate and intrastate customers using storage and related transportation capacity that is in excess of our utility’s core (residential, commercial and industrial firm) customer requirements. Asset optimization is also part of our gas storage segment, with optimization services provided for the utility under an agreement with an independent energy marketing company. Factors critical to the success of our gas storage business segment include the ability to: develop additional storage capacity at competitive market prices; plan for the replacement of capacity that is expected to be recalled by the utility to serve its core customers in the future; and obtain timely and reasonable rate recovery for operating and capital costs.
Highlights from the first quarter of 2007 include:
Net income increased 17 percent during the first quarter of 2007 compared to the same period in 2006, from $41.0 million to $48.1 million;
Solid growth in net operating revenues from our regulated utility and gas storage businesses were major drivers to increased earnings in the first quarter of 2007, with an 11 percent increase in net operating revenues at both our utility and gas storage;
Operations and maintenance expense increased 2 percent in the first quarter of 2007, including incremental costs for seasonal employees and employee bonus accruals tied to improved financial results, which were largely offset by cost reductions from business process redesign initiatives that we began implementing in 2006;
Cash flow from operations increased 47 percent to $149.8 million, reflecting stronger operating results and an increase in cash flows from lower gas costs; and
Total debt decreased by $114.6 million in the first quarter of 2007, reflecting a $20 million redemption of long-term debt at maturity and a $94.6 million decrease in notes payable.
Issues, Challenges and ChallengesPerformance Measures
There are a number of issues and challenges that directly affect our consolidatedoperations and financial condition and results of operations.performance. The most significant challenge we face in the near term iscontinues to be managing the impactutility business in a period of volatilehigh gas prices.prices, increased demand and increased market volatility. Our gas acquisition policy and strategy has been to secure sufficient supplies of natural gas to meet the needs of our utility’s firm customers, but equally important is our strategy to hedge gas prices for a significant portion of the utility’sour annual purchase requirements based onupon the market outlook and theour core utility’s load forecast. We generally manageIn 2005, we hedged about 90 percent of our winter supplies prior to when the hurricanes hit, which helped us avoid much of the spike in gas prices usingthat fall and winter. In 2006, we hedged at a combination of hedge strategies, including:
The majority ofthan in the past few years, with higher gas prices already reflected in our gas supplies come from Alberta and British Columbia, whilecustomers’ bills for the remainder comes from the U.S. Rocky Mountain region.current Purchased Gas Adjustment (PGA) period which extends through October 2007. We believe we have sufficient supplies of natural gas under contract to meet the needs of our firm customers, but futurefurther price increases could change our competitive advantageearnings outlook and our customers’ preference for natural gas. Highercompetitive advantage. If high gas prices persist, it could significantly 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 To address these competitive issues, we are continually developing new gas acquisition strategies to manage gas prices and challengesmeet market demands, and we could face inare working on initiatives intended to improve operational efficiencies throughout the future include unpredictable weather conditions, adverse regulatory actions or policy changes, managing gas supplies, storage and transportation capacity, managing customer growth, maintainingcompany through a competitive advantage and managing environmental, interest rate and credit riskscomprehensive business process redesign effort (see Part II, Item 7., “Issues,“Executive Summary—Issues, Challenges and Performance Measures,” Part I, Item 1A., “Risk Factors,” in the 20052006 Form 10-K and Part II, Item 1A., “Risk Factors,” below)10-K).
To address some of the challenges, we recently initiated a company-wide restructuring of operations with the goal of significantly improving work processes, reducing operating expenses and capital costs and continuing to strive for excellence in customer service. Our focus has been on developing initiatives to achieve long-term strategic targets. The new operations model is expected to be implemented over the next several years and to include workforce reductions. These reductions are expected to be accomplished by primarily focusing on a combination of normal attrition and voluntary severance packages. We expect to incur costs of approximately $1.5 million to $2.0 million in the fourth quarter of 2006 related to a workforce reduction of an estimated 50-100 people, which we expect to be largely offset this year by a combination of cost reductions and gains from non-core asset sales.
Strategic Opportunities
Business Process Redesign. During 2006, we initiated a project to evaluate our business processes and costs against our peers and to redesign those processes where long-term efficiencies could be gained. We identified a number of areas where we could restructure our business to gain efficiencies, including more centralization, an increased focus on process orientation, and more standardized processes. As an example, in 2007 we will be developing the first phase of a new enterprise resource planning system to support our new business processes in a more standardized and automated environment. For more information regarding our redesign efforts, see Part II, Item 7., “Strategic Opportunities,” in the 2006 Form 10-K.
Pipeline Diversity.In September 2006, we announced that we arewere evaluating making an investment in a potential pipeline project that would connect TransCanada’s Gas Transmission Northwest (GTN) interstate transmission line to our local gas distribution system. We have commenced a processare continuing to determine if there is sufficient interest by potential customers to justify construction of the pipeline. Ifevaluate the project, is determined to be viable, we would formand a partnership with GTN to build and own the pipeline. We would anticipate being a large customer of the proposed pipeline and GTN would be its operator. The pipeline would be intended to provide our utility and GTN’s customers with a source for more diversified delivery of gas supplies from the interstate system and enhance reliability. The decision on whether to proceed with the development planning and permitting of the
pipeline is expected to be made in early 2007.later this year. No material contractual obligations related to the pipeline have been incurred as of Sept. 30, 2006.March 31, 2007. If constructed, we expect commercial operation couldof the pipeline to commence byin 2011.
Application of Critical Accounting Policies and Estimates
In preparing our 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 our critical accounting policies to be those which are most important to the representation of our financial condition and results of operations and which require management’s most difficult and subjective or complex judgments, including accounting estimates that could result in materially different amounts if we reported under different conditions or usingused different assumptions.
Our most critical estimates or judgments involve regulatory cost recovery, unbilled revenues,revenue recognition, 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 20052006 Form 10-K). There have been no material changes to the information provided in our 2005the 2006 Form 10-K with respect to the application of critical accounting policies and estimates. Management has discussed itsthe estimates and judgments used in the application of critical accounting policies with the Audit Committee of the Board.
Within the context of our critical accounting policies and estimates, management is not currently aware of any reasonably likely events or circumstances that would result in materially different amounts being reported.
Earnings and Dividends
Three months ended Sept. 30, 2006 compared to Sept. 30, 2005:
Net income was $48.1 million, or $1.76 a share, for the three months ended Sept. 30, 2006 was a loss of $9.7March 31, 2007, compared to $41.0 million, or 35 cents per$1.48 a share, compared to a loss of $8.7 million, or 31 cents per share, infor the same period in 2005. The loss was primarily due to results from our utility segment, which contributed a losslast year.
First quarter of $11.4 million, or 41 cents per share, to the 2006 third quarter results,2007 compared to a loss of $10.5 million, or 38 cents per share in 2005. Net income from utility operations is typically a loss during the third quarter due2006:
Positive factors contributing to the reduced use of natural gas in the summer. Interstate gas storage operations contributed $1.5 million toincreased earnings in the third quarter of 2006, or 5 cents per share, compared to $1.6 million, or 6 cents per share, in the same period in 2005. Other non-utility business activities resulted in net income for the quarter of $0.2 million, or 1 cent per share, in both 2006 and in 2005.
Primary factors affecting third quarter earnings this year over last year include:were:
increased utility marginvolumes and net operating revenues (margin) from sales to residential and commercial customers of $0.8 million, primarily resulting from annualdue to 2.8 percent customer growth, plus weather that was 2 percent colder than the first quarter of 3.4 percent, or 20,722 customers, largely offset by the change2006 (see “Results of Operations—Comparison of Gas Distribution Operations,” below);
increased margin from regulatory sharing of gas cost savings, from $1.8 million in the regulatory decoupling deferralfirst quarter of 2006 to $9.8 million in 2007, and a $2.7 million gain from the reversal of a temporary loss taken in the fourth quarter of 2006 related to derivative contracts that settle in 2007; and
decreased interest costs due to higher than expected average use per customer;lower short-term debt balances.
Partially offsetting the above positive factors were:
Nine months ended Sept. 30, 2006 compared to Sept. 30, 2005:
For the nine months ended Sept. 30, 2006, net income increased 3 percent to $33.3 million, or $1.20 per share, compared to $32.4 million, or $1.17 per share, in the same period in 2005. Our utility operations contributed $28.2 million, or $1.02 per share, to earnings in the first nine months of 2006, compared to $28.4 million, or $1.03 per share, in 2005. Interstate gas storage operations contributed $4.8 million in the current period, or 17 cents per share, compared to $3.3 million, or 12 cents per share, in 2005. Other non-utility activities resulted in net income of $0.3 million, or 1 cent per share, compared to net income of $0.7 million, or 2 cents per share, in 2005.
Primary factors affecting year-to-date earnings this year over last year include:
Dividends paid on our common stock were 35.5 cents a share and 34.5 cents and 32.5 cents pera share in the three-monththree month periods ended Sept. 30,March 31, 2007 and 2006, and 2005, respectively, and $1.035 and $0.975 per share in the nine-month periods ended Sept. 30, 2006 and 2005, respectively. In October 2006,April 2007, the Board of Directors declared a quarterly dividend on our common stock dividend rate was increased by 3 percent toof 35.5 cents per share payable Nov.May 15, 20062007 to shareholders of record on Oct. 31, 2006.April 30, 2007. The current indicated annual dividend rate is $1.42 per share.
Results of Operations
Regulatory DevelopmentsMatters
Regulation and Rates
We provide gas utility service in Oregonare subject to regulation with respect to, among other matters, rates, systems of accounts and Washington, with Oregon representing overissuance of securities by the OPUC and the WUTC. Typically, about 90 percent of our utility revenues.gas deliveries and operating revenues are derived from Oregon customers and the balance from Washington customers. Future earnings and cash flows from utility operations will be determined largely by among other factors,the pace of continued growth in the residential and commercial markets and by our ability to remain price competitive, control expenses, and obtain reasonable and timely regulatory treatmentrecovery for our utility gas costs, operating expensesand maintenance costs and investments made in utility plant (seeplant. See Part II, Item 7., “Results of Operations– Operations—Regulatory Matters,” in the 20052006 Form 10-K.
At March 31, 2007 and 2006, the amounts deferred as regulatory assets and liabilities were as follows:
Current | |||||||||
March 31, | Dec. 31, 2006 | ||||||||
Thousands | 2007 | 2006 | |||||||
Regulatory assets: | |||||||||
Gas costs receivable | $ | — | $ | 8,747 | $ | — | |||
Unrealized loss on non-trading derivatives1 | 9,233 | 16,096 | 30,798 | ||||||
Other | 902 | 713 | 711 | ||||||
Total regulatory assets | $ | 10,135 | $ | 25,556 | $ | 31,509 | |||
Regulatory liabilities: | |||||||||
Gas costs payable | $ | 17,666 | $ | — | $ | 737 | |||
Unrealized gain on non-trading derivatives1 | 13,698 | 16,317 | — | ||||||
Other | 10,524 | 4,185 | 11,182 | ||||||
Total regulatory liabilities | $ | 41,888 | $ | 20,502 | $ | 11,919 | |||
Non-Current | |||||||||
March 31, | Dec. 31, 2006 | ||||||||
Thousands | 2007 | 2006 | |||||||
Regulatory assets: | |||||||||
Gas costs receivable | $ | — | $ | 4,775 | $ | — | |||
Unrealized loss on non-trading derivatives1 | 3,108 | 3,569 | 9,584 | ||||||
Income tax asset | 68,086 | 66,757 | 67,141 | ||||||
Pension and other postretirement benefit obligations2 | 53,540 | — | 54,425 | ||||||
Environmental costs—paid3 | 21,912 | 14,453 | 19,113 | ||||||
Environmental costs—accrued but not yet paid3 | 6,462 | 4,743 | 8,760 | ||||||
Other | 5,756 | 6,064 | 5,748 | ||||||
Total regulatory assets | $ | 158,864 | $ | 100,361 | $ | 164,771 | |||
Regulatory liabilities: | |||||||||
Gas costs payable | $ | 10,354 | $ | — | $ | 13,041 | |||
Unrealized gain on non-trading derivatives1 | 3,734 | 27,285 | — | ||||||
Accrued asset removal costs | 191,886 | 173,936 | 187,422 | ||||||
Other | 2,359 | 2,023 | 2,519 | ||||||
Total regulatory liabilities | $ | 208,333 | $ | 203,244 | $ | 202,982 | |||
1 | Unrealized gains or losses on non-trading derivatives do not earn a rate of return or a carrying charge. These amounts, when realized at settlement, are recoverable through utility rates as part of our PGA mechanism. |
2 | Pension and other postretirement costs are approved for regulatory deferral based on SFAS No. 87 and SFAS No. 106 expense included in customer rates from the 2003 Oregon and 2004 Washington general rate cases (see Part II, Item 8., Note 7 in the 2006 Form 10-K). |
3 | Environmental costs are related to sites that are approved for regulatory deferral. We earn an authorized rate of return as a carrying charge on amounts paid; however, amounts accrued but not yet paid do not earn a rate of return or a carrying charge until expended. |
Rate Mechanisms
Purchased Gas Adjustment.Rate changes are applied each year under the PGA tariff mechanisms in Oregon and Washington to reflect changes in the costsexpected cost of natural gas commodity purchased under contractspurchases, including contractual arrangements to hedge the purchase price with gas producers,financial derivatives (see
“Comparison of Gas Distribution Operations—Cost of Gas Sold,” below), interstate pipeline demand charges, the application of temporary rate adjustments to amortize balances in deferred regulatory accounts and the removal of temporary rate adjustments effective for the previous year. The Public Utility Commission of Oregon (OPUC) and the Washington Utilities and Transportation Commission (WUTC) approved rate increases on Oct. 25, 2006 that became effective on November 1, compared to October 1 in the prior year. The effect of the rate change is to increase the average monthly bills of Oregon residential sales customers by 3.5 percent and those of Washington residential customers by 3.0 percent.
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 thandiffer from the estimated amounts included in rates, then we are required to defer a predetermined percentage of the higher coststhat difference and collect them in future rates. Similarly, when the actual purchased gas costs are lower than the amounts included in rates, the gas cost savings are not immediately returnedpass it on to customers but a predetermined percentage is deferred and creditedas an adjustment to customers in future periods.rates. As part of an incentive mechanism in Oregon, only 67 percent of the difference is deferred such that the impact on current earnings is either a charge to expense for 33 percent of the higher cost of gas sold, or a credit to expense for 33 percent of the lower cost of gas sold. In Washington, the PGA deferral is 100 percent of the higher or lower actual cost of gas sold.
In October 2006, theThe OPUC approvedis currently conducting a modification to our PGA tariff, effective Nov. 1, 2006, which provides that we will use actual recoveries of gas costs in revenues billed (instead of using estimated gas costs incorporated in rates) compared to actual purchased gas costs to determine our PGA deferral. The effectformal review of the new methodPGA process used by local distribution companies covering gas portfolio requirements, incentive sharing levels and filing requirements among other items. The investigation is expected to be completed in early 2008. Implementation of using actual recoveries of gas costs in amounts billed will be that any changes in line loss expense due to increases or decreases in unaccounted for gas volumes will be covered by the annual PGA mechanism such that these increases and decreases willis expected to be reflected in the PGA deferral amounts, However, consistent with our prior PGA sharing mechanism, 67 percent of any cost of gas price differences for Oregon volumes will be deferred for refund or recovery in customer rates in subsequent periods,effective with the remaining 33 percent being included in current earnings.
Also in October 2006, the OPUC’s annual formal reviewExcess Earnings Test. The OPUC has a formalized process to test for excess utility earnings was disconnected from our annual PGA filings, so that our ability to pass through 100 percent of prudently incurred gas costs into rates would not be dependent upon a determination of any excess earnings.annually. We will continue to be subject to the same excess earnings test requirement as before, in which we are allowedauthorized to retain all of our earnings up to a threshold level equal to our authorized return on equity of 10.2 percent plus 300 basis points. Revenues equivalent to 33 percentOne-third of any earnings above the threshold are required tothat level will be refunded to customers. The excess earnings threshold is subject to adjustment up or down each year baseddepending on movements in long-term interest rates.
Weather Normalization and Conservation Tariffs. In October 2006, the OPUC authorizedthreshold after adjustment was 13.44 percent. We do not expect that any amounts will be required to be refunded to customers as a change inresult of the annual start date for applying the weather normalization adjustment to customer bills. Previously, the start date was November 15 of each year. Now, the mechanism2006 earnings test, which will start on December 1 and end on May 15 of each heating season. Also in October 2006,be reviewed by the OPUC authorized a change induring the conservation tariff, which includes a decoupling mechanism designedsecond quarter of 2007. In Washington, we are not subject to adjust margin revenues up or down to offset changes in average residentialan annual excess earnings test and commercial100 percent of all prudently incurred gas costs are passed through into customer usage due to conservation efforts. This change, in combination with the change in our weather normalization mechanism, effectively extends the period for full decoupling from June through November of each year. Previously, full decoupling was in effect only from June through September of each year. For the remaining months of each year the decoupling mechanism is in effect but is applied only after revenues are weather normalized. These changes to our weather normalization and conservation tariffs provide for greater mitigation of our risk exposures due to variations in weather and customer consumption patterns.rates.
Geo-hazard Program.Integrated Resource Planning We entered into. The OPUC and WUTC have implemented integrated resource planning (IRP) processes under which utilities develop plans defining alternative growth scenarios and resource acquisition strategies. On March 28, 2007, we filed a stipulationdraft IRP with the WUTC and are required to file a final IRP with the OPUC in 2001 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 piping infrastructure created by landslides, washouts, earthquakes or similar occurrences. The stipulation allowed us to receive deferred accounting rate treatment for all costs associated with the geo-hazard program. Although the authority to defer expenses for costs associated with this geo-hazard program is scheduled to expire on Dec. 31, 2006, we received approval from the OPUC to defer up to $2.5 million in 2007 related to a specific project.
Industrial Tariffs. In August 2006, the OPUC and WUTC approved tariff changes to the service options for our major industrial accounts. The changes set out additional parameters that give us more certainty in the level of gas supplies we will need to acquire to serve this customer group. The parameters include an annual election period, special pricing provisions for out-of-cycle changes and the requirement that customers on our annual weighted average cost of gas tariff complete the term of their service election.15, 2007.
Interstate Pipeline Rate Cases
On June 30, 2006, the two interstate pipeline companies that provide natural gas transportation to our distribution system filed for general rate increase casesincreases with FERC. Northwest Pipeline Corporation (Northwest Pipeline) filed for an overall cost of service increase of approximately $119.0 million (a 41 percent increase), including an increase in the firm transportation rate of approximately 45 percent. If approved as filed, our firm gas transportation rates would increase by approximately $17.8 million annually. The major components in the increase relate to a significant capacity replacement project, other capacity displacement projects, increased rate of return and operation and maintenance expenses, and costs associated with accounting changes to expense pipeline integrity assessment costs. FERC has accepted Northwest Pipeline’s revised tariff sheets to become effective on January 1, 2007, subject to refund pending the outcome of further proceedings in the case.
GTN’s rate case proposes, among other things, an approximately 71 percent increase in firm transportation rates. If approved as filed, our transportation rates on that pipeline would increase by approximately $3.1 million. The primary reason for GTN’s filing was unsubscribed capacity on the
system due to significant capacity turnback and shipper defaults. FERC has accepted and suspended the GTN rates and tariff sheets to become effective on January 1, 2007, subject to refund pending further proceedings in the case.
IncreasesFederal Energy Regulatory Commission (FERC). Changes in interstate pipeline transportation expensescharges are subject to our PGA deferral mechanism and are 100 percent passed-through to customers in both Oregon and Washington. Both of the filed general rate increases were reflected in our 2006 PGA filings. In March 2007, FERC approved Northwest Pipeline’s settlement proposal, resulting in a lower than expected increase to our pipeline transportation rates. Amounts currently being collected from our customers in excess of this amount will be deferred and returned to customers, which will reduce gross revenues and costs of sales but will have no impact on our net results of operations. See Part II, Item 7., “Results of Operations—Regulatory Matters—Interstate Pipeline Rate Cases,” in the 2006 Form 10-K.
Utility Regulation Legislation
During 2005,Under Oregon regulatory law, we are required to file a report in October each year that calculates the Oregon legislature passed Senate Bill (SB) 408 relatingdifference between the amount of income taxes paid to governmental entities compared to the amount of taxes we collected by utilities in rates on or after Jan. 1, 2006. This legislation requiresin the OPUC to establish an annual tax adjustment to ensure that Oregon utilities do not collect in ratesprevious year. For more income taxes than they actually pay to government entities (see Part I, Item 1., “Regulation and Rates—Utility Regulation Legislation,” Part 1A., “Risk Factors,” andinformation regarding this requirement, see Part II, Item 7., “Results of Operations—Regulatory Matters—Utility Regulation Legislation,” in the 20052006 Form 10-K). In September 2006,10-K.
Based on our assessment of the OPUC approved final rules requireddeveloped to implement SB 408. In October,the law, we filed a required informational tax report comparing “taxes paid” to “authorized to collect in rates”estimate that our 2007 Tax Report for the fiscal years 2003, 2004 and 2005. Based on2006 tax year will reflect a surcharge of about $1.6 million; that is, the calculations required by the final rules, our “taxes paid” exceededamount of income taxes paid to government entities will exceed the amount of taxes the utility collected in rates, thus creating a rate adjustment that requires a reimbursement from customers. It is anticipated that any
amounts due from customers for the 2006 tax year would not be realized until after June 1, 2008, pending a review by the OPUC. We have estimated that our 2008 Tax Report for the 2007 tax year will also reflect a surcharge. Based on results through March 31, 2007, we were “authorizedestimate the surcharge related to collect in rates” by $0.6 million in 2003, $1.2 million in 2004 and $3.0 million in 2005. Becauseour first quarter to be about $2.8 million. We have determined that the recognition of this regulatory surcharge is uncertain because the OPUC has not completed its review of how the final rules only apply to taxes collected on or after Jan. 1, 2006, there will be no adjustmentapplied to our rates as2006 and 2007 financial results, our request for a result of this informational tax report. AlthoughPrivate Letter Ruling from the Internal Revenue Service is not complete and there are ongoing efforts in the current Oregon legislative session that could potentially change certain aspectsprovisions of the final rules relatedlaw. Due to federal income tax rules are yet to be determined, we expect to file our tax report for the calendar yearregulatory uncertainty, recovery in rates of the 2006 in Octoberand estimated 2007 with any adjustment expected to occur in the second quarter of 2008. Based onsurcharge is not considered probable at this time and these amounts have been reserved. Given our current corporate structure and level of non-utility investments and activities, we do not expect that ongoing compliance with SB 408 tothis law, as currently interpreted, will not have a material adverse effect on our financial condition, results of operations or cash flows.
Comparison of Gas Distribution Operations
The following tables summarize the composition of utility volumes, operating revenues and margin:
Three Months Ended Sept. 30, | ||||||||||||||
Thousands, except degree day and customer data | 2006 | 2005 | ||||||||||||
Utility volumes - therms: | ||||||||||||||
Residential and commercial sales | 54,525 | 29 | % | 52,553 | 29 | % | ||||||||
Industrial sales and transportation | 131,533 | 71 | % | 128,860 | 71 | % | ||||||||
Total utility volumes sold and delivered | 186,058 | 100 | % | 181,413 | 100 | % | ||||||||
Utility operating revenues - dollars: | ||||||||||||||
Residential and commercial sales | $ | 78,619 | 70 | % | $ | 66,696 | 64 | % | ||||||
Industrial sales and transportation | 34,196 | 31 | % | 37,319 | 36 | % | ||||||||
Other revenues | (1,168 | ) | (1 | %) | (513 | ) | — | |||||||
Total utility operating revenues | 111,647 | 100 | % | 103,502 | 100 | % | ||||||||
Cost of gas sold | 70,623 | 62,241 | ||||||||||||
Revenue taxes | 2,939 | 2,496 | ||||||||||||
Utility net operating revenues (margin) | $ | 38,085 | $ | 38,765 | ||||||||||
Utility margin:(1) | ||||||||||||||
Residential sales | $ | 21,618 | 57 | % | $ | 20,944 | 54 | % | ||||||
Commercial sales | 10,293 | 27 | % | 10,182 | 26 | % | ||||||||
Industrial - sales and transportation | 7,682 | 20 | % | 8,078 | 21 | % | ||||||||
Miscellaneous revenues | 695 | 2 | % | 926 | 2 | % | ||||||||
Other margin adjustments | (738 | ) | (2 | %) | (552 | ) | (1 | %) | ||||||
Margin before weather normalization and decoupling | 39,550 | 104 | % | 39,578 | 102 | % | ||||||||
Weather normalization mechanism | — | — | (2 | ) | — | |||||||||
Decoupling mechanism | (1,465 | ) | (4 | %) | (811 | ) | (2 | %) | ||||||
Utility margin | $ | 38,085 | 100 | % | $ | 38,765 | 100 | % | ||||||
Customers - end of period: | ||||||||||||||
Residential customers | 562,752 | 543,118 | ||||||||||||
Commercial customers | 59,519 | 58,425 | ||||||||||||
Industrial customers | 937 | 943 | ||||||||||||
Total number of customers - end of period | 623,208 | 602,486 | ||||||||||||
Actual degree days | 79 | 101 | ||||||||||||
Percent colder (warmer) than average (2) | (23 | %) | (1 | %) | ||||||||||
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 Revenue taxes Utility net operating revenues (margin) Utility margin:(1) Residential sales Commercial sales Industrial - sales and transportation Miscellaneous revenues Other margin adjustments Margin before weather normalization and decoupling Weather normalization mechanism Decoupling mechanism Utility margin Actual degree days Percent colder (warmer) than average(2) Nine Months Ended Sept. 30, 2006 2005 404,259 49 % 382,958 48 % 419,313 51 % 407,365 52 % 823,572 100 % 790,323 100 % $ 533,584 80 % $ 439,497 78 % 133,775 20 % 117,125 21 % (1,206 ) 0 % 5,213 1 % 666,153 100 % 561,835 100 % 431,014 335,186 16,663 13,272 $ 218,476 $ 213,377 $ 133,522 61 % $ 125,356 59 % 55,769 26 % 52,374 24 % 23,872 11 % 24,605 12 % 3,343 2 % 4,046 2 % 2,684 1 % 2,464 1 % 219,190 101 % 208,845 98 % 2,686 1 % 2,516 1 % (3,400 ) (2 %) 2,016 1 % $ 218,476 100 % $ 213,377 100 % 2,465 2,522 (7 %) (5 %)
Three months ended March 31, | Favorable/ | |||||||||||
Thousands, except degree day and customer data | 2007 | 2006 | ||||||||||
Utility volumes—therms: | ||||||||||||
Residential sales | 162,897 | 159,312 | 3,585 | |||||||||
Commercial sales | 96,804 | 95,325 | 1,479 | |||||||||
Industrial—firm sales | 15,917 | 24,038 | (8,121 | ) | ||||||||
Industrial—firm transportation | 43,471 | 29,742 | 13,729 | |||||||||
Industrial—interruptible sales | 25,664 | 42,564 | (16,900 | ) | ||||||||
Industrial—interruptible transportation | 67,738 | 56,955 | 10,783 | |||||||||
Total utility volumes sold and delivered | 412,491 | 407,936 | 4,555 | |||||||||
Utility operating revenues—dollars: | ||||||||||||
Residential sales | $ | 227,138 | $ | 214,314 | $ | 12,824 | ||||||
Commercial sales | 118,042 | 113,047 | 4,995 | |||||||||
Industrial—firm sales | 16,655 | 23,176 | (6,521 | ) | ||||||||
Industrial—firm transportation | 1,498 | 948 | 550 | |||||||||
Industrial—interruptible sales | 22,131 | 35,352 | (13,221 | ) | ||||||||
Industrial—interruptible transportation | 2,093 | 1,859 | 234 | |||||||||
Other revenues | 3,068 | (1,440 | ) | 4,508 | ||||||||
Total utility operating revenues | 390,625 | 387,256 | 3,369 | |||||||||
Cost of gas sold | 245,462 | 255,384 | 9,922 | |||||||||
Revenue taxes | 9,614 | 9,528 | (86 | ) | ||||||||
Utility net operating revenues (margin) | $ | 135,549 | $ | 122,344 | $ | 13,205 | ||||||
Utility margin: | ||||||||||||
Residential sales | $ | 81,036 | $ | 78,348 | $ | 2,688 | ||||||
Commercial sales | 32,338 | 31,777 | 561 | |||||||||
Industrial—sales and transportation | 8,379 | 8,486 | (107 | ) | ||||||||
Miscellaneous revenues | 1,639 | 1,503 | 136 | |||||||||
Other margin adjustments | 10,951 | 1,440 | 9,511 | |||||||||
Margin before regulatory adjustments | 134,343 | 121,554 | 12,789 | |||||||||
Weather normalization mechanism | 108 | 1,842 | (1,734 | ) | ||||||||
Decoupling mechanism | 1,098 | (1,052 | ) | 2,150 | ||||||||
Utility margin | $ | 135,549 | $ | 122,344 | $ | 13,205 | ||||||
Customers—end of period: | ||||||||||||
Residential customers | 579,746 | 563,178 | 16,568 | |||||||||
Commercial customers | 60,987 | 60,175 | 812 | |||||||||
Industrial customers | 953 | 944 | 9 | |||||||||
Total number of customers—end of period | 641,686 | 624,297 | 17,389 | |||||||||
Actual degree days | 1,852 | 1,814 | ||||||||||
Percent colder (warmer) than average(1) | (1 | )% | (3 | )% | ||||||||
(1) |
Average weather represents the 25-year average degree days, as |
Certain amounts in prior years have been reclassified to conform to the current year presentation. These reclassifications had no impact on prior year results of operations.
Our utility results are affected by, among other things, customer growth and changes in weather and customer consumption patterns, with a significant portion of our earnings being derived from natural gas sales to residential and commercial customers. In order to offset the potential volatility in utility earnings caused by these factors,weather and declining consumption due to conservation, we obtained OPUC approval of a conservation tariff that adjusts margin up or down based on changes in residential and commercial customer consumption and a weather normalization mechanism that adjusts customer bills, and our margin, based on above- or below-average temperatures during the winter heating season (see “Regulatory Developments – Developments—Rate Mechanisms,” above, and Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms,” in the 20052006 Form 10-K).
Three months and nine months ended Sept. 30, 2006 compared to Sept. 30, 2005:
Total utility volumes sold and delivered in the thirdfirst quarter this year increased by 3 percent over last year, while total utility margin decreased by 2 percent. Total utility volumes sold and delivered in the first nine months of this year increased by 41 percent over last year, while total utility margin increased by 211 percent. Volume increasesThe volume increase in both the current three- and nine-month periods werequarter was due mainly to industrial usageresidential and commercial customer growth, which has continued to remainremained strong with a net increase of 20,72217,389 customers since Sept. 30, 2005,March 31, 2006, or an annual growth rate of 2.8 percent. Our growth rate remains well above the national average for local gas distribution companies, despite recent economic conditions that have moderately decreased the level of new construction in our service territory. In the three years ended December 31, 2006, more than 58,400 customers were added, representing an average annual growth rate of 3.4 percent. Margin changesThe margin increase in the current three- and nine-month periods were belowquarter was driven primarily by a decrease in the volume increases, primarily due to lower industrial marginscost of gas (see “Industrial Sales and Transportation,“Cost of Gas Sold,” below).
Residential and Commercial Sales
Residential and commercial sales markets are impacted by seasonal weather patterns, energy prices, competition from alternative energy sources and economic conditions in our service areas. Typically, 80 percent or more of our annual utility operating revenues are derived from gas sales to weather-sensitive residential and commercial customers. Although variations in temperatures between periods will affect volumes of gas sold to these customers, the effect on margin and net income is significantly reduced due to the weather normalization mechanismsmechanism in Oregon where about 90 percent of our customers are served. Approximately 10 percent of our eligible Oregon customers have opted out of the mechanism. In Oregon, we also have a conservation decoupling mechanism that is intended to break the link between our earnings and the quantity of gas consumed by our customers, so that we do not have an incentive to discourage customers from conserving energy. In Washington, where the remaining 10 percent of our customers are served, we do not have a weather normalization or a conservation decoupling mechanism. As a result, the mechanisms do not fully insulate the utility from earnings volatility due to weather.weather and conservation. See the tablestable above for the adjustments to utility margin revenues from the weather normalization and decoupling mechanisms for the three-quarters ended March 31, 2007 and nine- month periods ended Sept. 30, 2006 and 2005.
The following table summarizes the utility volumes and utility operating revenues in the residential and commercial markets:
Three Months Ended Sept. 30, | Nine Months Ended Sept. 30, | ||||||||||||||
Thousands | 2006 | 2005 | 2006 | 2005 | |||||||||||
Utility volumes - therms: | |||||||||||||||
Residential sales | 27,348 | 27,877 | 275,506 | 258,377 | |||||||||||
Commercial sales | 25,535 | 25,574 | 177,146 | 166,431 | |||||||||||
Change in unbilled sales | 1,642 | (898 | ) | (48,393 | ) | (41,850 | ) | ||||||||
Total weather-sensitive utility volumes | 54,525 | 52,553 | 404,259 | 382,958 | |||||||||||
Utility operating revenues - dollars: | |||||||||||||||
Residential sales | $ | 44,954 | $ | 40,324 | $ | 384,145 | $ | 316,463 | |||||||
Commercial sales | 31,926 | 27,372 | 210,489 | 169,598 | |||||||||||
Change in unbilled sales | 1,739 | (1,000 | ) | (61,050 | ) | (46,564 | ) | ||||||||
Total weather-sensitive utility revenues | $ | 78,619 | $ | 66,696 | $ | 533,584 | $ | 439,497 | |||||||
Three months ended Sept. 30, 2006 compared to Sept. 30, 2005:2006.
The primary factors affecting residential and commercial volumes and operating revenues in the thirdfirst quarter this year over last year include:
sales volumes were 42 percent higher as a result of customer growth and slightly higher average use per customer;2 percent colder weather than last year; and
operating revenues were 185 percent higher due to higher sales volumes and higher billing rates, which reflect the higher gas costs in the PGA effective Oct.November 1, 20052006 (see Part II, Item 7., “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” in the 20052006 Form 10-K).
Nine months ended Sept. 30, 2006 compared to Sept. 30, 2005:
The primary factors affecting residential and commercial volumes and operating revenues year-to-date this year over last year include:
Total utility operating revenues include accruals for unbilled revenues (gas delivered but not yet billed to 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 period end. Weather conditions, rate changes and customer billing dates affect the balance of accrued unbilled revenues at the end of each month. At Sept. 30, 2006,March 31, 2007, accrued unbilled revenue was $19.3$43.5 million, compared to $16.8$47.8 million at Sept. 30, 2005.March 31, 2006, with the decrease primarily reflecting warmer weather toward the end of the first quarter of 2007 as compared to 2006. Accrued unbilled revenue was $87.5 million at December 31, 2006.
Industrial Sales and Transportation
The following table summarizes the delivered volumes and utility operating revenues in the industrial market:
Three Months Ended Sept. 30, | Nine Months Ended Sept. 30, | |||||||||||||
Thousands | 2006 | 2005 | 2006 | 2005 | ||||||||||
Utility volumes - therms: | ||||||||||||||
Industrial - firm sales | 12,211 | 14,855 | 52,286 | 53,416 | ||||||||||
Industrial - firm transportation | 39,391 | 33,398 | 104,482 | 99,710 | ||||||||||
Industrial - interruptible sales | 21,340 | 35,303 | 89,784 | 106,751 | ||||||||||
Industrial - interruptible transportation | 57,872 | 44,675 | 173,185 | 147,836 | ||||||||||
Change in unbilled sales | 719 | 629 | (424 | ) | (348 | ) | ||||||||
Total utility volumes | 131,533 | 128,860 | 419,313 | 407,365 | ||||||||||
Utility operating revenues - dollars: | ||||||||||||||
Industrial - firm sales | $ | 12,269 | $ | 12,238 | $ | 51,425 | $ | 43,285 | ||||||
Industrial - firm transportation | 1,328 | 941 | 3,445 | 3,055 | ||||||||||
Industrial - interruptible sales | 17,691 | 21,846 | 73,427 | 65,835 | ||||||||||
Industrial - interruptible transportation | 2,020 | 1,742 | 5,747 | 5,234 | ||||||||||
Change in unbilled sales | 888 | 552 | (269 | ) | (284 | ) | ||||||||
Total utility operating revenues | $ | 34,196 | $ | 37,319 | $ | 133,775 | $ | 117,125 | ||||||
Three months ended Sept. 30, 2006 compared to Sept. 30, 2005:
Total volumes delivered to industrial sales and transportation customers were up 2.7down 0.5 million therms, or 2less than 1 percent, in the thirdfirst quarter of 20062007 as compared to the same period in 2005.2006. Utility operating revenues related to these customers were down $3.1$19.0 million, or 831 percent, over last year. The lower operating revenues primarily reflect the transfer of a few large customers from sales service last year to transportation service this year, with the cost of gas sold to these customers includeda larger component in salesoperating revenues last year but not this year, and a higher percentage of volumes in lower margin rate schedules in 2006as compared to 2005.
Nine months ended Sept. 30, 2006this year. On a year-to-year basis, margin is a better indication of performance for the industrial sector due to the shift from sales to transportation. In 2007, utility margin decreased $0.1 million, or about 1 percent, compared to Sept. 30, 2005:
Total2006 on lower volumes delivered to industrial sales and transportation customers were up 11.9 million therms, or 3 percent, in the nine months ended Sept. 30, 2006, compared to the same period in 2005. Utility operating revenues were up $16.7 million, or 14 percent, over last year. The higher revenues primarily reflect the higher volumes delivered and the higher billing rates to industrial sales customers due to increased gas costs, partially offset by the transfer of a few large customers from sales service last year to transportation service this year. The margin contribution from industrial sales and transportation decreased by $0.7 million, or 3 percent, over 2005, primarily due to customers switching to lower margin contracts or rate schedules and a temporary $0.2 million net loss mark-to-market adjustment related to the valuation of a gas sales contract, partially offset by higher delivered volumes.delivered.
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 deferred gas costs (see Part II, Item 8., Note 1, “Industry Regulation,” in the 20052006 Form 10-K). Other revenues
decreased net operating revenues by $1.2 million in the third quarter of 2006, compared to a decrease of $0.5 million in the third quarter of 2005. In the first nine months of 2006, other revenues decreased net operating revenues by $1.2 million, compared to an increase of $5.2 were $3.1 million in the first nine monthsquarter of 2005. The following table summarizes other revenues by major category:
Three Months Ended Sept. 30, | Nine Months Ended Sept. 30, | |||||||||||||||
Thousands | 2006 | 2005 | 2006 | 2005 | ||||||||||||
Revenue adjustments: | ||||||||||||||||
Current regulatory deferrals: | ||||||||||||||||
Decoupling mechanism | $ | (1,465 | ) | $ | (811 | ) | $ | (3,400 | ) | $ | 2,016 | |||||
Weather normalization mechanism | — | (3 | ) | 234 | (36 | ) | ||||||||||
South Mist pipeline extension | — | (129 | ) | — | 164 | |||||||||||
Coos Bay distribution system | — | 111 | — | 814 | ||||||||||||
Current regulatory amortizations: | ||||||||||||||||
Interstate gas storage credits | — | — | 4,051 | 2,714 | ||||||||||||
Decoupling mechanism | (475 | ) | (180 | ) | (4,304 | ) | (1,416 | ) | ||||||||
South Mist pipeline extension | (7 | ) | (221 | ) | (58 | ) | (1,789 | ) | ||||||||
Coos Bay distribution system | (101 | ) | — | (794 | ) | — | ||||||||||
Conservation programs | (146 | ) | (222 | ) | (1,124 | ) | (1,551 | ) | ||||||||
Other | 46 | 16 | 370 | 251 | ||||||||||||
Net revenue adjustments | (2,148 | ) | (1,439 | ) | (5,025 | ) | 1,167 | |||||||||
Miscellaneous revenues: | ||||||||||||||||
Customer fees | 306 | 509 | 3,027 | 3,530 | ||||||||||||
Other | 674 | 417 | 792 | 516 | ||||||||||||
Total miscellaneous revenues | 980 | 926 | 3,819 | 4,046 | ||||||||||||
Total other revenues | $ | (1,168 | ) | $ | (513 | ) | $ | (1,206 | ) | $ | 5,213 | |||||
Three months ended Sept. 30, 20062007, compared to Sept. 30, 2005:
Other revenuesa net expense of $1.4 million in the three months ended Sept. 30,first quarter of 2006, were $0.7 million lower than in the three months ended Sept. 30, 2005 primarily due to a $0.7 million change in the currentcustomer fees and decoupling deferral.regulatory deferrals and amortization.
Nine months ended Sept. 30, 2006Cost of Gas Sold
Natural gas commodity prices have risen significantly in recent years. The effects of higher commodity prices and price volatility on core utility customers are mitigated, in part, through our use of underground storage facilities, fixed-price commodity hedge contracts and short term sales of excess gas supply and transportation capacity to off-system customers in periods when core utility customers do not require the full amount of contract gas supplies or firm pipeline capacity.
The total cost of gas sold was $245.5 million in the first quarter of 2007, a decrease of $9.9 million or 4 percent compared to Sept. 30, 2005:the first quarter of 2006. The cost per therm of gas sold includes current gas purchases, gas drawn from storage inventory, gains and losses from commodity hedges, margin from off-system gas sales, pipeline demand charges, seasonal demand cost balancing adjustments, regulatory gas cost deferrals and company gas use.
Other revenuesUnder the PGA tariff in the nine months ended Sept. 30, 2006 were $6.4 million lower than in the nine months ended Sept. 30, 2005 primarily due to a $5.4 million change in current decoupling deferral, a $2.9 million change in the amortization of decoupling deferral balances and a $0.8 million change in the amortization of Coos Bay distribution system deferrals, partially offsetOregon, our net income is affected by a $1.3 million changesharing mechanism based on increases or decreases in interstatepurchased gas storage credits and a $1.7 million changecosts as compared to estimated gas costs included in amortization expense related to deferrals for the South Mist pipeline extensioncustomer rates (see Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms,Mechanisms—Purchased Gas Adjustment,” in the 20052006 Form 10-K for further discussion of regulatory revenue adjustments)10-K).
Cost of Gas Sold
Although natural gas commodity prices have increased significantly over the last few years, prices have begun to decline recently, allowing more opportunity to purchase lower-priced spot market gas. During the third quarter and In the first nine monthsquarter of 2006, the cost per therm2007, our share of gas sold was
33 percentcost savings contributed $9.8 million to margin, compared to net savings and 28 percent higher, respectively, thana contribution to margin of $1.8 million in the comparable 2005 periods.2006 period. The net benefit to utility customers from aggregate gas cost per therm of gas sold primarily includes current gas purchases, gas withdrawn from storage inventory and net gains and losses from financial commodity hedge contracts. Priorsavings amounted to the last heating season, we locked in gas prices for approximately 90 percent of our commodity purchases before the disruptions caused by hurricanes Katrina and Rita, thereby avoiding a significant amount of the run-up in gas prices last fall and winter. Our rate increases last fall were much lower than those in other regions of the country due to our significant hedge position, but gas prices overall were still higher than in prior years, which accounted$21.7 million for the higher cost per therm of gas sold this year as compared to last year.three months ended March 31, 2007.
We use a natural gas commodity-price hedge program under the terms of our Financial Derivatives Policy to help manage our variableexposure to floating price risk on gas purchases. Duringpurchase contracts (see Part II, Item 7., “Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities,” in the three months ended Sept. 30, 2006 we recorded aForm 10-K, and Note 7, above). We realized net losslosses of $7.6 million from our financial hedge contractshedges in the first quarter of $12.4 million,2007, compared to a net gaingains of $20.5$17.5 million duringin the same period in 2005. Duringof 2006. Gains and losses from the nine months ended Sept. 30, 2006, we recorded a net lossfinancial hedging of $5.4 million from hedge contracts compared a gain of $30.3 million during the same period in 2005. Because our financial hedge contracts are directly related to variable-price risks in physical supply contracts which are included in PGA deferrals and annual regulatory rate changes, the resulting gains and lossesutility gas purchases generally are included in cost of gas, as an offset to the higher or lower actual physical gas purchase costs. For the most part, financial hedge contract gains and losseswhich are factored into our PGA deferrals and annual rate changes, but to the extent that any utility gas hedge is entered into after the annual PGA adjustmentfiling, then the gains and have no material impact on net income.
Under our PGA tariff in Oregon, if the cost of gas purchased is higher or lower than the cost embedded in rates, net income is charged or credited for 33 percent of the difference and the remaining 67 percent is deferred for pass through to customers in future rates. Our gas purchases in the third quarter of 2006 were slightly lower than the costs embedded in rates, and our share of the lower costs increased margin by $0.2 million. For the third quarter of 2005, our gas costs were also lower than the gas costs embedded in rates, and our share of the lower costs increased margin by $0.2 million. In the first nine months of 2006, our share of gas cost savings contributed $3.7 million to margin, compared to net savings and a contribution to margin of $1.9 million in the comparable 2005 period. The net benefit to customers from these gas cost savings amounted to $0.3 million and $7.4 million for the three and nine months ended Sept. 30, 2006, respectively.
Based on our ongoing assessment of gas prices and market risks, we began moderating our hedge position earlier this year as compared to prior years. Typically, by the time we file for our annual PGA rate change, we have a high percentage of the next gas contract year’s estimated gas purchase requirements hedged. However, this year we went into the PGA with a lower than normal but still significant percentage of gas purchases hedged based on market conditions and gas price outlook. As gas prices began to decline in late August and early September, we increased our hedge positions, adding both to our storage levels with spot gas purchases and to our fixed-price financial swap portfolio to lock in gas prices on forward purchases. Our current overall hedge position for the upcoming gas contract year is below where we have been hedged over the past few years, and this may subject us to greater purchased gas cost variability in the future as compared to previous years (see Part II, Item 1A., “Risk Factors,” below). Variations in gas costslosses are subject to our PGA mechanismsincentive sharing mechanism with 67 percent deferred and 33 percent recorded to current income. We recorded a $2.7 million credit to the cost of gas in the first quarter of 2007 related to the reversal of an unrealized loss on financial derivative contracts that were entered into during the fourth quarter of 2006, which was after the 2006 PGA filing (see “ResultsPart II, Item 7., “Application of Operations—Rate Mechanisms,Critical
Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities,” above)in the 2006 Form 10-K). The fourth quarter 2006 temporary loss was largely reversed in the first quarter of 2007 as a majority of these derivative contracts settled.
Business Segments Other than Gas Distribution Operations
Interstate Gas Storage
Net income from our interstate gas storage business segment in the three and nine months ended Sept. 30, 2006March 31, 2007 was $1.5$1.8 million and $4.8 million, respectively, after regulatory sharing and income taxes, or 5 cents and 177 cents per share, respectively. This comparescompared to net income of $1.6$1.4 million, or 6 cents per share, and $3.3 million, or 125 cents per share, in the three and nine months ended Sept. 30, 2005, respectively. TheMarch 31, 2006. This increase in the nine month results was primarily due to interstateincreased firm storage capacity added during mid-year 2005services revenues and an increase in revenues from our asset optimization arrangement with an
unaffiliated independent energy marketing company (see Part II, Item 7., “Results of Operations—Business Segments Other Than Local Gas Distribution—Interstate Gas Storage,” in the 20052006 Form 10-K). The segment also began providing intrastate services in February 2006. The total working gas capacity of the Mist underground gas storage facility has been revised from 13.9 Bcf to 14.0 Bcf to reflect reservoir performance and incremental growth in certain reservoir pools.
Third-party optimization is provided pursuant to a contract with an unaffiliatedindependent energy marketing company, which assists in the optimization of the value of our assets primarily through the use of commodity transactions. In Oregon, we retain 80 percent of the pre-tax income from interstate storage services and optimization activities when the costs of the capacity used have not been included in utility rates, or 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 crediting to our core utility customers. We have a similar sharing mechanism in Washington for pre-tax income derived from interstate storage services and third-party optimization.
Other
The other business segment primarily consists of a wholly-owned subsidiary, Financial Corporation, as well as various other non-utility investments, including an investment in a leveraged aircraft lease (see Part II, Item 8., Note 2, “Consolidated Subsidiary Operations and Segment Information,” in the 20052006 Form 10-K). Operating results from this segment for both the three months ended Sept. 30, 2006 and 2005March 31, 2007 were net income of $0.2 million. Formillion, compared to $0.1 million for the ninethree months ended Sept. 30, 2006 and 2005 net income was $0.3 million and $0.7 million, respectively.March 31, 2006.
Our net investment balancesbalance in Financial Corporation at Sept. 30,March 31, 2007 and 2006 was $2.7 million and 2005 were $2.7 and $3.2$3.6 million, respectively. The $0.5$0.9 million decrease primarily reflects lower cash investments due to a cash dividend paid to NW Natural in the second quarter of 2006. Our net investment balance in the leveraged aircraft lease at Sept. 30,March 31, 2007 and 2006 and 2005 was $7.2$4.7 million and $6.9$7.0 million, respectively, with the increasedecrease primarily due to recognitionthe receipt in March 2007 of earnedthe final payment due under the terms of the lease revenues.agreement.
Operating Expenses
Operations and Maintenance
Operations and maintenance expenses in the thirdfirst quarter of 20062007 were $25.6$28.8 million, representing a $0.3 million, or 1 percent, decrease over the third quarter of 2005. The following summarizes the major factors that contributed to the decrease in operations and maintenance expense:
Operations and maintenance expenses in the first nine months of 2006 increased $1.6$0.6 million, or 2 percent, compared toincrease over the first nine monthsquarter of 2005.2006. The following summarizes the major factors that contributed to the increase in operations and maintenance expense:
a $1.5$0.5 million increase in payroll-related expenses resulting from pay increasesother contract work primarily due to seasonal staffing for the call center; and higher benefit costs;
a $0.6$0.5 million increase in bad debt expense related to increases in gross revenuesbenefit expenses for non-qualified pension plan costs and delinquencies resulting from higher natural gas prices;for stock-based compensation;
General Taxes
General taxes, which are principally comprised of property taxes, payroll taxes and regulatory fees, decreased $0.3increased $0.2 million, or 53 percent, in the three months ended Sept. 30, 2006March 31, 2007 over the same period in 2005, but2006. Regulatory fees increased $1.3$0.2 million, or 711 percent, in the nine months ended Sept. 30,first quarter of 2007 compared to the first quarter of 2006 over the same period in 2005. Property taxes increased $0.1 million, or 2 percent, and $0.7 million, or 6 percent, in the three- and nine-month periods ended Sept. 30, 2006, respectively, over the same periods in 2005, due to utility plant additions in 2006 and 2005. Regulatory fees increased $0.6 million in the nine months ended Sept. 30, 2006 over the same period in 2005, reflecting increased gross operating revenues, but these fees decreased by $0.4 millionrevenues. The change in property and payroll taxes was negligible in the three months ended Sept. 30, 2006 overfirst quarter of 2007 compared to the same period in 2005 primarily due to timing differences between this year and last year.first quarter of 2006.
Depreciation and Amortization
Depreciation and amortization expense increased by $0.7$1.0 million, or 5 percent, and $2.0 million, or 46 percent, in the three- and nine-month periodsthree-month period ended Sept. 30, 2006, respectively,March 31, 2007, compared to the same periodsperiod in 2005.2006. The increased expense reflects ongoing capital expenditures for utility plant that were made primarily to meet continuing customer growth and to upgrade operating facilities.
Other Income and Expense – Net
The following table summarizes other income and expense – net by primary components:
Three Months Ended Sept. 30, | Nine Months Ended Sept. 30, | |||||||||||||||
Thousands | 2006 | 2005 | 2006 | 2005 | ||||||||||||
Other income (expense): | ||||||||||||||||
Gains from Company-owned life insurance | $ | 399 | $ | 436 | $ | 2,196 | $ | 1,410 | ||||||||
Interest income | 31 | 180 | 306 | 409 | ||||||||||||
Other non-operating expense | (262 | ) | (202 | ) | (1,080 | ) | (1,061 | ) | ||||||||
Net interest on deferred regulatory accounts | (109 | ) | 99 | (494 | ) | 123 | ||||||||||
Earnings from equity investments of Financial Corporation | 255 | 37 | 314 | 139 | ||||||||||||
Total other income | $ | 314 | $ | 550 | $ | 1,242 | $ | 1,020 | ||||||||
Three Months Ended March 31, | ||||||||
Thousands | 2007 | 2006 | ||||||
Other income and expense—net: | ||||||||
Gains from company-owned life insurance | $ | 480 | $ | 1,383 | ||||
Interest income | 152 | 84 | ||||||
Other non-operating expense | (274 | ) | (603 | ) | ||||
Net interest income (expense) on deferred regulatory accounts | 258 | (296 | ) | |||||
Loss from equity investments of Financial Corporation | (78 | ) | (50 | ) | ||||
Total other income and expense—net | $ | 538 | $ | 518 | ||||
OtherThe negligible increase in other income and expense – net was $0.2 million lower in the thirdfirst quarter of 20062007 compared to the same period in 2005, and $0.2 million higher in the nine months ended Sept. 30, 2006 compared to the same period in 2005. The increase in the nine-month period was primarily due to realizedinterest on deferred regulatory accounts that were higher because of increases in deferred environmental costs, and a decrease in other non-operating expenses, largely offset by reduced life insurance benefits from company-owned policies and earnings from non-utility equity investments, which were partially offset by interest charges on net regulatory liability account balances, as compared to interest income on net regulatory asset balances last year, and lower interest income on a reduced level of temporary cash investments.policies.
Interest Charges – Net of Amounts Capitalized
Interest charges – net of amounts capitalized increased $0.5decreased $0.3 million, or 6 percent, and $1.5 million, or 63 percent, in the three- and nine-month periodsquarter ended Sept. 30,March 31, 2007 compared to the same period in 2006, and 2005, respectively, primarily due to higherlower balances of total debt outstanding and higher interest rates on short-term debt borrowing.resulting from cash flows tied to gas cost savings.
Income Taxes
Income tax expense totaled $28.5 million in the first quarter of 2007 compared to $23.4 million in the first quarter of 2006. The effective corporatetax rate was 37.2 percent in the first quarter of 2007 compared to 36.4 percent in the first quarter of 2006. The higher income tax rate onexpense in 2007 is due primarily to pre-tax book income from operations was 35.9 percentof $76.5 million compared to $64.5 million for the nine-monthsame period ended Sept. 30,in 2006, comparedresulting in higher income tax expenses. The increase in effective tax rate in 2007 was largely due to 35.7 percent for the nine-month period ended Sept. 30, 2005.a decrease in tax benefits from a $0.9 million decrease in non-taxable gains on life insurance.
Financial Condition
Capital Structure
Our 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”Resources,” below). Our consolidated capital structure at Sept. 30, 2006 and 2005 and at Dec. 31, 2005, including short-term debt, was as follows:
Sept. 30, | Dec. 31, 2005 | ||||||||
2006 | 2005 | ||||||||
Common stock equity | 48.7 | % | 48.7 | % | 47.2 | % | |||
Long-term debt | 40.4 | % | 44.5 | % | 42.0 | % | |||
Short-term debt, including current maturities of long-term debt | 10.9 | % | 6.8 | % | 10.8 | % | |||
Total | 100.0 | % | 100.0 | % | 100.0 | % | |||
The increase in the common stock equity percentage in September 2006 compared to December 2005 is primarily due to increased earnings and strong cash flows, which has reduced the need to issue debt to fund capital expenditures. Achieving the target capital structure and maintaining sufficient liquidity are necessary to maintain attractive credit ratings and have access to capital markets at reasonable costs. Our consolidated capital structure at March 31, 2007 and 2006 and at December 31, 2006, including short-term debt, was as follows:
March 31, | Dec. 31, 2006 | ||||||||
2007 | 2006 | ||||||||
Common stock equity | 54.2 | % | 51.6 | % | 48.1 | % | |||
Long-term debt | 44.5 | % | 41.8 | % | 41.5 | % | |||
Short-term debt, including current maturities of long-term debt | 1.3 | % | 6.6 | % | 10.4 | % | |||
Total | 100.0 | % | 100.0 | % | 100.0 | % | |||
The common stock equity percentages in March 2007 and March 2006 were higher as compared to December 2006 primarily due to seasonal earnings and cash flows that reduced the combined long-term and short-term debt percentages.
In April 2007, the Board has approved aauthorized an increase to the share repurchase program forof our common stock, now aggregating up to 2.8 million shares, or up to $100 million in value, from the repurchaseprevious authorized levels of up to 2.6 million shares or up to $85 million in value, of our common stock.value. Purchases under this program are made in the open market or through privately negotiated transactions. Since the program’s inception in 2000, we have repurchased 812,700 shares of common stock at a total cost of $24.7 million, including 47,100 shares at a total cost of $1.6 million in the first nine months of 2006 (seeSee “Financing Activities,” and Part II, Item 2., “Unregistered Sales of Equity Securities and Use of Proceeds,” below) . The Board also approved a 3 percent increase in the common stock dividend rate, from 34.5 cents to 35.5 cents per share, effective Nov. 15, 2006.below.
Liquidity and Capital Resources
At Sept. 30, 2006,March 31, 2007, we had $5.7$5.1 million of cash and cash equivalents compared to $3.4$7.5 million at Sept. 30, 2005.March 31, 2006 and $5.8 million at December 31, 2006. 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 totaling $200 million
which and are available through Sept.September 30, 2010 (see “Lines of Credit,” below, and Part II, Item 8., Note 6, in the 20052006 Form 10-K). Proceeds from the issuance of long-term debt are used to finance capital expenditures and refinance maturing short-term or long-term debt.
Neither our Mortgage and Deed of Trust nor the indenture under which 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 counterparties under our Financial Derivatives Policy, whichPolicy. These agreements 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, we believe we have sufficient liquidity to satisfy our anticipated 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”Obligations,” below), we have no material off-balance sheet financing arrangements.
Contractual Obligations
Since Dec.December 31, 2005, we entered into2006, our estimated future contractual obligations have increased by about $10 million primarily due to contracts to outsource a new contract in the amountportion of $12.4 millionour construction work, including mains and services and locating services as well as for the purchase and installation of automated meter reading (AMR) equipment. Besides this contract and other contracts entered intoconsulting on our low income energy efficiency programs, which are all in the ordinary course of business, there were no material changes to our estimated future contractual obligations during the nine months ended Sept. 30, 2006.business. Our contractual obligations at Dec.December 31, 20052006 are described in Part II, Item 7., “Financial Condition—Liquidity and Capital Resources—Contractual Obligations,” in the 20052006 Form 10-K.
Commercial Paper
Our 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 requirements. Commercial paper is periodically refinanced through the sale of long-term debt or equity securities. Our outstanding commercial paper, which is sold through two commercial banks under an issuing and paying agency agreement, is supported by committed bank lines of credit (see “Lines of Credit,” below, and Part II, Item 8., Note 6, in the 20052006 Form 10-K). We had $103.3$5.5 million in commercial paper notes outstanding at Sept. 30, 2006,March 31, 2007, compared to $72.5$50.4 million outstanding at Sept. 30, 2005March 31, 2006 and $126.7$100.1 million outstanding at Dec.December 31, 2005.2006. Commercial paper balances are typically lower at the end of the thirdfirst quarter compared to year-end because year-end working capital balances tenddue to include increases in customer receivablescollections from higher sales and the withdrawal of gas inventories from storage during the winter heating season, and this year’s outstanding balances were lower than last year primarily due to seasonality.the gas cost savings discussed above in “Results of Operations—Comparison of Gas Distribution Operations—Cost of Gas Sold.”
Lines of Credit
We have agreements for unsecured lines of credit totaling $200 million with five commercial banks. The bank lines of credit (bank lines) are available and committed for a term of five years, from Oct.October 1, 2005 to Sept.September 30, 2010. There were no outstanding balances on these bank lines of credit at Sept. 30,March 31, 2007 or 2006, or 2005, or at Dec.December 31, 2005.2006.
The bank lines require us 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 any amounts outstanding. We were in compliance with this covenant at Sept. 30,March 31, 2007 and 2006 and at Dec.December 31, 2005, and with the equivalent covenant in the prior year’s lines of credit at Sept. 30, 2005. We also expect to be in compliance with this debt covenant at the end of this year, after including the effect of adopting Statement of Financial Accounting Standards (SFAS) No. 158 for the recognition of underfunded pension and postretirement benefit obligations (see Note 2).2006.
Credit Ratings
The table below summarizes our debt credit ratings from two rating agencies, Standard and Poor’s Rating Services (S&P) and Moody’s Investors Service (Moody’s).
S&P | Moody’s | |||
Commercial paper (short-term debt) | A-1+ | P-1 | ||
Senior secured (long-term debt) | AA- | A2 | ||
Senior unsecured (long-term debt) | A+ | A3 | ||
Ratings outlook | Stable | Stable |
Both rating agencies have assigned NW Natural 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 NW Natural securities. Each rating should be evaluated independently of any other rating.
Redemptions of Long-Term Debt
In March 2007, we redeemed $20.0 million of secured 6.31% Series B Medium Term Notes at maturity. In June 2006, we redeemed $8.0 million of secured 6.05% Series B Medium-Term Notes at maturity.
Cash Flows
Operating Activities
Year-over-year changes in our operating cash flows are primarily affected by net income, gas prices, deferred income taxes, changes in working capital requirements, regulatory deferrals and other cash and non-cash adjustments to operating results. The overall change in cash flow from operating activities for the ninethree months ended Sept. 30, 2006March 31, 2007 compared to the same period in 20052006 was an increase of $27.5 million, primarily due to a $20.0 million contribution to the qualified defined benefit pension plans in September 2005.$48.1 million. The major factors contributing to the cash flow changes in the first ninethree months of 20062007 compared to the first ninethree months of 20052006 are as follows:
an increase in net income added $0.9$7.0 million to cash flow;
deferred gas costs, primarily related to gas cost savings realized in the first quarter of 2007, increased cash by $20.8 million with the regulatory liability account increasing in the first quarter of 2007 compared to the regulatory receivable increasing in the first quarter of 2006; this current liability balance is expected to reverse when those costs are reflected in utility rates under our PGA tariff to be effective later in 2007;
a decrease of $13.6 million in cash resulting from an increase in gas inventory balances reduced cash flow by $18.4 million, primarily reflecting a net increasebalance in gas storage volumes and higher gas prices,2007 compared to 2006;
an inventory increase of $32.3$16.1 million during 2005;
a decrease of $13.2 million in 2005,2007 compared to 2006 due to the collectionrealization of higher year-end balances, reflecting higher rates and colder weather;income taxes receivable in 2006;
a decreasereduction in accounts payable reducedincreased cash flow by $70.8$22.7 million in 2006 compared to a $20.8 million reduction in 2005,2007 primarily due to the payment of higher year-end balances, primarily reflecting higherlower gas invoice prices for December 2005 compared to December 2004;around year end 2006; and
We have lease and purchase commitments relating to 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 2005 Form 10-K).
Investing Activities
Cash requirements for investing activities in the first ninethree months of 20062007 totaled $64.4$19.1 million, downup from $66.5$16.2 million in the same period of 2005.2006. Cash requirements for the acquisition and construction of utility plant totaled $67.4$18.6 million, up from $65.2$17.0 million in the first ninethree months of 2005. The2007, with the increase in utility plant spending in 2006 was primarily related to the AMR project and pipeline integrity costs in 2006 (see “Contractual Obligations,” above), which wereour automated meter reading project. This increase was partially offset by lower capital spending under our bare steel replacement program.on new residential and commercial services.
Investments in non-utility property during the first ninethree months of 20062007 totaled $0.8$3.1 million, downup from $5.5$0.1 million during the first ninethree months of 20052006, due primarily to amounts related to the capital improvements toand expansion development at our interstate gas storage facilities in 2005.2007. In 2007, we also received a $2.7 million payment due under the airplane leveraged lease agreement.
In January 2005, Financial Corporation received proceeds from the sale of its limited partnership interestsOur utility and non utility capital expenditures are now expected to total about $120 million in three solar electric generation projects totaling $3.0 million.
In September 2006, we announced that we are evaluating a potential pipeline project that would connect GTN’s interstate transmission line to our2007, which includes estimates for an enterprise resource planning system and additional gas distribution system. If the project is determined to be viable, we would form a partnership with GTN to build and own the pipeline, which would require a material investment. However, the project’s status will not be confirmed until 2007, and no material contractual obligations have been committed as of Sept. 30, 2006. If it is determined to be viable, the project could potentially be operating by 2011 (see “Strategic Opportunities,” above).storage related capital expenditures.
Financing Activities
Cash used in financing activities in the first ninethree months of 20062007 totaled $59.2$131.5 million, up from $30.1$85.2 million in the same period of 2005.2006. The primary factors contributing to the $29.1$46.3 million increase
were differences in debt financings and increased common stock repurchases. Common stock repurchases in 2006 totaled $1.6 million compared to $13.8 million in 2005.repurchase activity. Debt financing activity consisted of a net $31.4decrease of $114.6 million ofin short-term and long-term debt redemptionsoutstanding in 2006,the first three months of 2007, compared to $45.5a net decrease of $76.3 million in 2005, and $50.0 million of new long-term debt issuance proceeds in 2005, compared to no new financing in 2006.
Under our common stock repurchase program, we have purchased 47,100206,700 shares at a total cost of $1.6$9.0 million in the first nine monthsquarter of 2006,2007, compared to 377,90011,700 shares at a total cost of $13.8$0.4 million in the first nine monthsquarter of 2005.2006.
Pension Funding Status
In September 2006,Our policy is to fund the Financial Accounting Standards Board issued SFAS No. 158 related to accounting for pension and other postretirement benefits (see Note 2, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”). SFAS No. 158 is effective for years ending after Dec. 15, 2006 and will require us to recognize the overfunded or underfunded status of ourqualified defined benefit postretirement plans as an asset or liability on the balance sheet. The issues surrounding the measurement of postretirement
benefit obligations are complex, including factors relating to expectations about the future. Under previous accounting rules, if the fair value of plan assets exceeded the accumulated benefit obligation (ABO), which is defined as the value of employee benefits accrued for services rendered based on current and past compensation levels, then a liability was not required to be recognized on the balance sheet. However, under new accounting rules the pension benefit obligation is required to be recognized based on the projected benefit obligation, which is defined as the value of employee benefits accrued for service rendered based on future wage increases, including an assumption that the plan will continue in effect. We are in the process of evaluating the obligation amount that will be required to be recognized as a liability on the balance sheet at the end of this year. Based on the funded status of our benefit obligations at the end of last year, we would increase pension and postretirement liabilities by approximately $41 million.
It is our policy to continue making contributions to the qualified pension plans, as needed, based on tax regulations and funding requirements under federal law, including funding the amounts required by the Employee Retirement Income Security Act of 1974. In addition, it is our intent to contribute sufficient amounts as are needed on an actuarial basis to maintain funding targets which generally provide for the fair value of plan assets to be equal to or greater than the plan’s ABO, and to provide for the timely payment of future benefits under these plans. For more information on the funding status of our qualified retirement plans and other postretirement benefits, see Part II, Item 7., “Pension Cost and Funding Status of Qualified Retirement Plans,” and Part II, Item 8., Note 7, “Pension and Other Postretirement Benefits,” in the 2006 Form 10-K.
ContingenciesContingent Liabilities
Loss contingencies are recorded as liabilities when it is probable that a liability has been incurred and the amount of loss is reasonably estimable in accordance with SFAS No. 5, “Accounting for Contingencies.” We 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 we record accruals for loss contingencies based on an analysis of potential results, developedFor further discussion, see Part I, Item 7., “Contingent Liabilities,” 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, we recognize an accrued liability at the lower end of the range and disclose the range (see Note 9). It is possible, however, that the range of potential liabilities could be significantly different than amounts currently accrued and disclosed, and our financial condition and results of operations could be materially affected by changes in assumptions or estimates related to these contingencies.2006 Form 10-K.
We develop estimates of environmental liabilities and related costs based on currently available information, existing technology and environmental regulations. These costs include investigation, monitoring, and remediation. We received regulatory approval to defer and seek recovery of costs related to certain sites and believe the recovery of these costs is probable through the regulatory process. In accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” we have recorded a regulatory asset for the amount expected to be recovered. We intend to pursue recovery of these environmental costs from our general liability insurance policies, and the regulatory asset will be reduced by the amount of any corresponding insurance recoveries. At Sept. 30, 2006,March 31, 2007, a cumulative $22.8$28.3 million in environmental cost deferrals has been recorded as a regulatory asset, consisting of $17.1$21.9 million of costs paid to-date and $5.7$6.4 million of accrued estimated future environmental expenditures. If it is determined that both the insurance recovery and future customer rate recovery of such costs are not probable, then the costs will be charged to expense in the period such determination is made. Seemade (see Note 9.10, above).
Ratios of Earnings to Fixed Charges
For the nine monthsthree- and 12 months12-months ended Sept. 30, 2006March 31, 2007 and the 12 months12-months ended Dec.December 31, 2005,2006, our ratios of earnings to fixed charges, computed using the Securities and Exchange Commission method, were 2.77, 3.328.86, 3.73 and 3.32,3.40, 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.
Forward-Looking Statements
This report and other presentations made by us from time to time may contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended.amended (Exchange Act.) 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. Our expectations, beliefs and projections are expressed in good faith and are believed to have a reasonable basis. However, each forward-looking statement involves uncertainties and is qualified in its entirety by reference to the following important factors, among others, that could cause our actual results to differ materially from those projected, including:
prevailing state and federal governmental policies and regulatory actions, including those of the OPUC and the WUTC, with respect to allowed rates of return, industry and rate structure, purchased gas cost and investment recovery, acquisitions and dispositions of assets and facilities, operation and construction of plant facilities, present or prospective wholesale and retail competition, changes in tax laws and policies related to recovery of taxes in rates and changes in and compliance with environmental and safety laws, and regulations, policies and orders, and laws, regulations and orders with respect to the maintenance of pipeline integrity;
implementation by the OPUC of final rules interpreting Oregon legislation intended to ensure that utilities do not collect more income taxes in rates than they actually pay to government entities;
weather conditions, pandemic events and other natural phenomena, including earthquakes or other geo-hazardgeohazard events;
unanticipated population growth or decline and changes in market demand caused by changes in demographic or customer consumption patterns;
competition for retail and wholesale customers;
market conditions and pricing of natural gas relative to other energy sources;
risks relating to the creditworthiness of customers, suppliers and financial derivative counterparties;
risks relating to our dependence on a single pipeline transportation provider for natural gas supply;
risks relating to property damage associated with a pipeline safety incident, as well as risks resulting from uninsured damage to our property, intentional or otherwise;
unanticipated changes that may affect our liquidity or access to capital markets;
risks relating to the execution of our business process redesign;
our ability to maintain effective internal controls over financial reporting;reporting in compliance with Section 404 of the Sarbanes-Oxley Act of 2002;
economic factors that could cause a severe downturn in certain key industries, thus affecting demand for natural gas;
unanticipated changes in operating expenses and capital expenditures;
unanticipated changes in future liabilities relating to employee benefit plans, including changes in key assumptions;
capital market conditions, including their effect on the fair value of pension assets and on pension and other postretirement benefit costs;
potential inability to obtain permits, rights of way, easements, leases or other interests or other necessary authority to construct pipelines, develop storage or complete other system expansions; and
legal and administrative proceedings and settlements.
All subsequent forward-looking statements, whether written or oral and whether made by or on behalf of 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 we 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 us to predict all such factors, nor can we 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 |
We are exposed to various forms of market risk including commodity supply risk, weather risk, and interest rate risk (see Item 7A. in the 20052006 Form 10-K, and below, and see Note 6, above, and Part II, Item 1A., “Risk Factors,” below).
Commodity SupplyPrice Risk
We enter intoNatural gas commodity prices are subject to fluctuations due to unpredictable factors including weather, pipeline transportation congestion and other factors that affect short-term medium-termsupply and long-termdemand. Commodity-price financial swap and option contracts (financial hedge contracts) are used to convert certain 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.from floating prices to fixed or capped prices. These financial hedge contracts are primarily index-based. Our PGA mechanismsgenerally included 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.
Based on our ongoing assessment of gas prices and market risks, we began moderating our hedge position earlier this year as compared to prior years. Typically, by the time we file for our annual PGA rate change, we havefiling, subject to a high percentageregulatory prudence review. At March 31, 2007 and 2006, notional amounts under these financial hedge contracts totaled $249.8 million and $418.1 million, respectively. If all of the financial hedge contracts had been settled on March 31, 2007, a gain of about $7.1 million would have been realized and recorded to a deferred regulatory account (see Note 7). We monitor the liquidity of our financial hedge contracts. Based on the existing open interest in the contracts held, we believe existing contracts to be liquid. All of our financial hedge contracts settle by October 31, 2008. The $7.1 million unrealized gain is an estimate of future cash flows that are expected to be paid as follows: $5.6 million in the next gas contract year’s estimated gas purchase requirements hedged. However, this year we went intotwelve months and $1.5 million during the PGA with a lower than normal but still significant percentage of gas purchases hedgedsecond twelve months. The amount realized will change based on market conditions and gas price outlook. As gas prices began to decline in late August and early September, we increased our hedge positions, adding both to our storage levels with spot gas purchases and to our fixed-price financial swap portfolio to lock in gas prices on forward purchases. Our current overall hedge position forat the upcoming gastime contract year is below where we have been hedged over the past few years, and this may subject us to greater purchased gas cost variability in the future as compared to previous years (see Part II, Item 1A., “Risk Factors,” below). Variations in gas costssettlements are subject to our PGA mechanisms (see “Results of Operations—Rate Mechanisms,” above).fixed.
Credit Risk
Credit exposure to financial derivative counterparties. Based on estimated fair value, our credit exposure to financial derivative counterparties relating to commodity swaphedge contracts was $29.1$7.3 million at Sept. 30, 2006.March 31, 2007. Our Financial Derivatives Policy requires counterparties to have a minimum investment-grade credit rating at the time the derivative instrument is entered into, and the policy specifies limits on the contract amount and duration based on each counterparty’s credit rating. There were no credit rating downgrades for any of our counterparties during the quarter.
The following table summarizes our credit exposure, based on estimated fair value, and the corresponding counterparty credit ratings. The table uses credit ratings from S&P and Moody’s, reflecting the higher of the S&P or Moody’s rating or a middle rating if the entity is split-rated with more than one rating level difference:
Financial Derivative Position by Credit Rating Unrealized Fair Value Gain (Loss) | ||||||||||
Sept. 30, | Dec. 31, | |||||||||
Thousands | 2006 | 2005 | 2005 | |||||||
AA/Aa | (29,122 | ) | 317,032 | 172,315 | ||||||
BBB/Baa | — | 23,481 | 3,346 | |||||||
Total | $ | (29,122 | ) | $ | 340,513 | $ | 175,661 | |||
Credit exposure to customers.Rate increases effective Nov. 1, 2006 are expected to increase our credit exposure to customers. We monitor and manage the credit exposure of our customers through the consistent application of 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 market conditions and customers’ payment patterns. Changes in credit risk may require us to obtain additional assurance, such as deposits, letters of credit, guarantees or prepayments to reduce our credit exposure.
Financial Derivative Position by Credit Rating Unrealized Fair Value Gain (Loss) | ||||||||||
Thousands | March 31, 2007 | March 31, 2006 | Dec. 31, 2006 | |||||||
AAA/Aaa | $ | 3,695 | $ | 940 | $ | — | ||||
AA/Aa | 3,381 | 25,465 | (40,955 | ) | ||||||
A/A | — | — | — | |||||||
BBB/Baa | — | — | — | |||||||
Total | $ | 7,076 | $ | 26,405 | $ | (40,955 | ) | |||
Item 4. | CONTROLS AND PROCEDURES |
(a) | Evaluation of Disclosure Controls and Procedures |
As of Sept. 30, 2006,March 31, 2007, the principal executive officer and principal financial officer of NWNorthwest Natural Gas Company (NW Natural) have evaluated the effectiveness of the design and operation of NW Natural’sour 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 NW Natural
have concluded that such disclosure controls and procedures are effective to ensure that information required to be disclosed by NW Naturalus and included in NW Natural’sour reports filed with the Securities and Exchange Commission (Commission) under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms and are also effective to ensure that information required to be disclosed by us and included in our reports filed with or furnished to the Securities and Exchange Commission under the Exchange Act is accumulated and communicated to NW Natural’sour management as appropriate to allow timely decisions regarding required disclosure.
(b) | Changes in Internal Control Over Financial Reporting |
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in the Exchange Act Rule 13a-15(f). There hashave been no changechanges in NW Natural’sour internal control over financial reporting that occurred during NW Natural’sour most recent fiscal quarter that hashave materially affected, or isare reasonably likely to materially affect, NW Natural’sour internal control over financial reporting.
The statements contained in Exhibit 31.1 and Exhibit 31.2 should be considered in light of, and read together with, the information set forth in this Item 4.
Item 1. | LEGAL PROCEEDINGS |
Litigation
For a discussion of certain pending legal proceedings, see Note 9,10, above.
Item 1A. | RISK FACTORS |
In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors,” in our Annual Report on Form 10-K for the year ended Dec.December 31, 2005 and the updates to certain of those risk factors described below,2006 which could materially affect our business, financial condition or results of operations. The risks described in our Annual Report onthe 2006 Form 10-K as updated below, are not the only risks facing our company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our financial condition, results of operations or cash flows.
Higher natural gas commodity prices and fluctuations in the price of gas may adversely affect our earnings.
In recent years, natural gas commodity prices have increased dramatically due to growing demand, especially for power generation, and stagnant North American gas production. In Oregon, the utility has a Purchased Gas Adjustment (PGA) tariff which provides for annual revisions in rates resulting from changes in the cost of purchased gas. The PGA tariff provides that 33 percent of any difference between the actual purchased gas costs and the actual recoveries of gas costs in revenues will be recognized as current income or expense. Accordingly, higher gas costs than those assumed in setting rates can adversely affect our results of operations.
Notwithstanding our current rate structure, higher gas costs could result in increased pressure on the Public Utility Commission of Oregon (OPUC) or the Washington Utilities and Transportation Commission (WUTC) to seek other means to reduce rates to a level that could adversely affect our financial condition, results of operations or cash flows.
Our results of operations may be negatively affected by warmer than average weather.
A large portion of the utility’s margin is derived from sales to space heating residential and commercial customers during each winter heating season. Current rates are based on an assumption of average weather. In Oregon, the effects of warmer or colder weather on utility margin are reduced through the operation of our weather normalization mechanism and conservation tariff. From June 1 through November 30, the operation of the conservation tariff largely offsets the risk of warmer weather and declining consumption. From December 1 through May 15, the weather normalization mechanism adjusts for the effects of weather in Oregon. However, 10 percent of eligible customers elected not to be covered by the mechanism. Also, approximately 10 percent of our residential and commercial customers are in Washington where we do not have a weather normalization mechanism or conservation tariff. As a result, we are not fully protected against warmer than average weather, which may have an adverse affect on our financial condition, results of operations or cash flows.
Item 2. | UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
The following table provides information about purchases by us during the quarter ended Sept. 30, 2006March 31, 2007 of equity securities that are registered 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) 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(2) | ||||||
Balance forward | 812,700 | $ | 60,260,697 | |||||||
07/01/06 - 07/31/06 | 2,109 | $ | 36.30 | — | — | |||||
08/01/06 - 08/31/06 | 23,859 | $ | 37.99 | — | — | |||||
09/01/06 - 09/30/06 | 1,864 | $ | 38.96 | — | — | |||||
Total | 27,832 | $ | 37.93 | 812,700 | $ | 60,260,697 | ||||
Period | (a) Total Number | (b) Average Price Paid per Share | (c) Total Number of Shares | (d) Maximum Dollar Value of | |||||||
Balance forward | 1,161,100 | $ | 45,899,916 | ||||||||
01/01/07—01/31/07 | 689 | $ | 41.51 | 35,000 | (1,505,208 | ) | |||||
02/01/07—02/28/07 | 23,132 | $ | 42.26 | 2,500 | (109,941 | ) | |||||
03/01/07—03/31/07 | 28,362 | $ | 43.82 | 169,200 | (7,402,423 | ) | |||||
Total | 52,183 | $ | 43.10 | 1,367,800 | $ | 36,882,344 | |||||
(1) | During the quarter ended |
(2) | 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. |
On Sept.March 29, 2006,2007, we entered into a Stock Purchase Plan Engagement Agreement with our broker in order to establish a trading plan for our repurchase program that qualifies for the safe harbors provided by Rule 10b-18 and Rule 10b5-1 under the Securities Exchange ActAct. The agreement expires on May 31, 2007, but management may elect to enter into new agreements in the future to achieve the objectives of 1934,our repurchase program.
On February 27, 2007, we commenced a voluntary oddlot program through Georgeson Inc. which offered shareholders holding accounts with less than 100 shares of common stock the opportunity to either sell their shares or purchase an additional number of shares to round up to 100 shares of common stock in the account at the average closing price of our common stock over the offering period. As of the end of the initial offering period on March 30, 2007, a net of 7,363 shares were made available for repurchase by us at the average closing price of $44.54 per share. These amounts are not reflected in the above table as amended.the settlement date occurred on April 19, 2007. The extension period under the program expired on April 25, 2007.
Item 6. | EXHIBITS |
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
September 30, 2006March 31, 2007
Document | Exhibit
| |
| ||
| ||
| ||
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 |