form10q.htm
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 June 30, 2011
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition period from _______ to _______
Commission File No. 1-15973
NORTHWEST NATURAL GAS COMPANY
(Exact name of registrant as specified in its charter)
Oregon
|
93-0256722
|
(State or other jurisdiction of
incorporation or organization)
|
(I.R.S. Employer
Identification No.)
|
220 N.W. Second Avenue, Portland, Oregon 97209
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (503) 226-4211
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [ X ] No [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [ X ] No [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
|
|
Large accelerated filer [ X ]
|
Accelerated filer [ ]
|
Non-accelerated filer [ ]
|
Smaller reporting company [ ]
|
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [ ] No [ X ]
At July 29, 2011, 26,674,187 shares of the registrant’s Common Stock (the only class of Common Stock) were outstanding.
NORTHWEST NATURAL GAS COMPANY
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PART I. FINANCIAL INFORMATION
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Page Number
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1
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2
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3
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5
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6
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23
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45
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45
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PART II. OTHER INFORMATION
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46
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46
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46
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46
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47
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This report contains “forward-looking statements” within the meaning of the U.S. Private Securities Litigation Reform Act of 1995. Forward-looking statements can be identified by words such as “anticipates,” “intends,” “plans,” “seeks,” “believes,” “estimates,” “expects” and similar references to future periods. Examples of forward-looking statements include, but are not limited to, statements regarding the following:
·
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future events or performance;
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·
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earnings and dividends;
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·
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operational performance and costs;
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·
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liquidity and financial positions;
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·
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project development and expansion;
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·
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storage levels, and values;
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·
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procurement, development and production levels of gas supplies and reserves;
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·
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estimated expenditures and investments;
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·
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potential efficiencies;
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·
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impacts of laws, rules and regulations;
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·
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tax liabilities or refunds;
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·
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outcomes and effects of litigation, regulatory actions, and other administrative matters;
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·
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projected status and obligations under retirement plans;
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·
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adequacy of, and shift in mix of, gas supplies;
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·
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approval and adequacy of regulatory deferrals; and
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·
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costs and recovery related to environmental, regulatory, litigation and insurance.
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Forward-looking statements are based on our current expectations and assumptions regarding our business, the economy and other future conditions. Because forward-looking statements relate to the future, they are subject to inherent uncertainties, risks, and changes in circumstances that are difficult to predict. Our actual results may differ materially from those contemplated by the forward-looking statements. We therefore caution you against relying on any of these forward-looking statements. They are neither statements of historical fact nor guarantees or assurances of future performance. Important factors that could cause actual results to differ materially from those in the forward-looking statements are discussed in our 2010 Annual Report on Form 10-K, Part I, Item 1A. “Risk Factors” and Part II, Item 7. and Item 7A., “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures about Market Risk,” and in Part I, Items 2 and 3, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures About Market Risk,” and Part II, Item 1A, “Risk Factors,” herein.
Any forward-looking statement made by us in this report speaks only as of the date on which it is made. Factors or events that could cause our actual results to differ may emerge from time to time, and it is not possible for us to predict all of them. We undertake no obligation to publicly update any forward-looking statement, whether as a result of new information, future developments or otherwise, except as may be required by law.
NORTHWEST NATURAL GAS COMPANY
PART I. FINANCIAL INFORMATION
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(Unaudited)
|
|
|
|
|
|
|
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|
|
|
|
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|
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Three Months Ended
|
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Six Months Ended
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June 30,
|
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June 30,
|
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Thousands, except per share amounts
|
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2011
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2010
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2011
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2010
|
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Operating revenues:
|
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|
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Gross operating revenues
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$ |
161,197 |
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$ |
162,365 |
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$ |
484,285 |
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$ |
448,894 |
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Less: Cost of sales
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90,122 |
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86,301 |
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270,747 |
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234,862 |
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Revenue taxes
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|
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3,843 |
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3,871 |
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11,798 |
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10,913 |
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Net operating revenues
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67,232 |
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72,193 |
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201,740 |
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203,119 |
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Operating expenses:
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|
|
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|
|
|
|
|
|
|
|
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Operations and maintenance
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30,374 |
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28,406 |
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61,546 |
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|
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59,072 |
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General taxes
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6,659 |
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7,543 |
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14,824 |
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10,792 |
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Depreciation and amortization
|
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17,546 |
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|
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16,026 |
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34,855 |
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31,927 |
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Total operating expenses
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54,579 |
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51,975 |
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111,225 |
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101,791 |
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Income from operations
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12,653 |
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20,218 |
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90,515 |
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|
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101,328 |
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Other income and expense - net
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1,122 |
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1,613 |
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2,336 |
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4,636 |
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Interest expense - net
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10,266 |
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10,617 |
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20,715 |
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21,106 |
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Income before income taxes
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3,509 |
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11,214 |
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72,136 |
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84,858 |
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Income tax expense
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|
|
1,316 |
|
|
|
4,326 |
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|
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29,170 |
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|
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34,362 |
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Net income
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$ |
2,193 |
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$ |
6,888 |
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$ |
42,966 |
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$ |
50,496 |
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Average common shares outstanding:
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Basic
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26,673 |
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26,569 |
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26,671 |
|
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26,553 |
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Diluted
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26,727 |
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26,641 |
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26,725 |
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26,621 |
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Earnings per share of common stock:
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Basic
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$ |
0.08 |
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$ |
0.26 |
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$ |
1.61 |
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$ |
1.90 |
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Diluted
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$ |
0.08 |
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$ |
0.26 |
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$ |
1.61 |
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$ |
1.90 |
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Dividends declared per share of common stock
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$ |
0.435 |
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$ |
0.415 |
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$ |
0.870 |
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$ |
0.830 |
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See Notes to Consolidated Financial Statements.
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NORTHWEST NATURAL GAS COMPANY
PART I. FINANCIAL INFORMATION
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(Unaudited)
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June 30,
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June 30,
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December 31,
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Thousands
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2011
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2010
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2010
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Assets:
|
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Current assets:
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Cash and cash equivalents
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$ |
3,700 |
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$ |
7,142 |
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$ |
3,457 |
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Restricted cash
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|
925 |
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929 |
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|
924 |
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Accounts receivable
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39,104 |
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42,781 |
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67,969 |
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Accrued unbilled revenue
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15,031 |
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|
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16,419 |
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64,803 |
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Allowance for uncollectible accounts
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(2,824 |
) |
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(2,577 |
) |
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|
(2,950 |
) |
Regulatory assets
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59,766 |
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56,804 |
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52,714 |
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Derivative instruments
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4,433 |
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1,495 |
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2,245 |
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Inventories:
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Gas
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61,318 |
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68,735 |
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70,672 |
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Materials and supplies
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9,911 |
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8,714 |
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9,713 |
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Gas reserves
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|
749 |
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|
- |
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- |
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Income taxes receivable
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|
26,285 |
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|
- |
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|
41,066 |
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Other current assets
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9,496 |
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9,823 |
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|
|
19,652 |
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Total current assets
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227,894 |
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|
|
210,265 |
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|
|
330,265 |
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Non-current assets:
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Property, plant and equipment
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|
2,612,147 |
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2,482,826 |
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2,576,402 |
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Less: Accumulated depreciation
|
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|
744,929 |
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|
710,732 |
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|
722,239 |
|
Total property, plant and equipment - net
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|
1,867,218 |
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1,772,094 |
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1,854,163 |
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Gas reserves
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|
15,403 |
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|
|
- |
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|
|
- |
|
Regulatory assets
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|
326,081 |
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|
|
329,197 |
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|
|
348,897 |
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Derivative instruments
|
|
|
1,042 |
|
|
|
453 |
|
|
|
628 |
|
Other investments
|
|
|
68,576 |
|
|
|
68,393 |
|
|
|
69,094 |
|
Other non-current assets
|
|
|
15,780 |
|
|
|
15,159 |
|
|
|
13,569 |
|
Total non-current assets
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|
|
2,294,100 |
|
|
|
2,185,296 |
|
|
|
2,286,351 |
|
Total assets
|
|
$ |
2,521,994 |
|
|
$ |
2,395,561 |
|
|
$ |
2,616,616 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
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NORTHWEST NATURAL GAS COMPANY
PART I. FINANCIAL INFORMATION
Consolidated Balance Sheets
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(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
December 31,
|
|
Thousands
|
|
2011
|
|
|
2010
|
|
|
2010
|
|
Capitalization and liabilities:
|
|
|
|
|
|
|
|
|
|
Capitalization:
|
|
|
|
|
|
|
|
|
|
Common stock - no par value; authorized 100,000 shares; issued and outstanding 26,673, 26,576, and 26,668 at June 30, 2011 and 2010 and December 31, 2010, respectively
|
|
$ |
344,451 |
|
|
$ |
339,394 |
|
|
$ |
342,978 |
|
Retained earnings
|
|
|
376,489 |
|
|
|
357,173 |
|
|
|
356,727 |
|
Accumulated other comprehensive income (loss)
|
|
|
(6,312 |
) |
|
|
(5,772 |
) |
|
|
(6,604 |
) |
Total common stock equity
|
|
|
714,628 |
|
|
|
690,795 |
|
|
|
693,101 |
|
Long-term debt
|
|
|
551,700 |
|
|
|
591,700 |
|
|
|
591,700 |
|
Total capitalization
|
|
|
1,266,328 |
|
|
|
1,282,495 |
|
|
|
1,284,801 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term debt
|
|
|
185,400 |
|
|
|
106,875 |
|
|
|
257,435 |
|
Current maturities of long-term debt
|
|
|
40,000 |
|
|
|
45,000 |
|
|
|
10,000 |
|
Accounts payable
|
|
|
54,148 |
|
|
|
81,675 |
|
|
|
93,243 |
|
Taxes accrued
|
|
|
6,805 |
|
|
|
13,008 |
|
|
|
10,579 |
|
Interest accrued
|
|
|
5,127 |
|
|
|
5,397 |
|
|
|
5,182 |
|
Regulatory liabilities
|
|
|
25,784 |
|
|
|
29,524 |
|
|
|
17,828 |
|
Derivative instruments
|
|
|
25,986 |
|
|
|
34,463 |
|
|
|
38,437 |
|
Other current liabilities
|
|
|
37,574 |
|
|
|
31,900 |
|
|
|
35,457 |
|
Total current liabilities
|
|
|
380,824 |
|
|
|
347,842 |
|
|
|
468,161 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred credits and other non-current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities
|
|
|
398,825 |
|
|
|
316,152 |
|
|
|
373,409 |
|
Regulatory liabilities
|
|
|
265,703 |
|
|
|
251,585 |
|
|
|
258,031 |
|
Pension and other postretirement benefit liabilities
|
|
|
130,985 |
|
|
|
120,185 |
|
|
|
144,250 |
|
Derivative instruments
|
|
|
9,202 |
|
|
|
16,917 |
|
|
|
17,022 |
|
Other non-current liabilities
|
|
|
70,127 |
|
|
|
60,385 |
|
|
|
70,942 |
|
Total deferred credits and other non-current liabilities
|
|
|
874,842 |
|
|
|
765,224 |
|
|
|
863,654 |
|
Commitments and contingencies (see Note 14)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total capitalization and liabilities
|
|
$ |
2,521,994 |
|
|
$ |
2,395,561 |
|
|
$ |
2,616,616 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
|
|
NORTHWEST NATURAL GAS COMPANY
PART I. FINANCIAL INFORMATION
Consolidated Statements of Cash Flows
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
Thousands
|
|
2011
|
|
|
2010
|
|
Operating activities:
|
|
|
|
|
|
|
Net income
|
|
$ |
42,966 |
|
|
$ |
50,496 |
|
Adjustments to reconcile net income to cash provided by operations:
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
34,855 |
|
|
|
31,927 |
|
Undistributed (earnings) losses from equity investments
|
|
|
353 |
|
|
|
(728 |
) |
Non-cash expenses related to qualified defined benefit pension plans
|
|
|
3,655 |
|
|
|
4,131 |
|
Contributions to qualified defined benefit pension plans
|
|
|
(16,445 |
) |
|
|
(10,000 |
) |
Deferred environmental expenditures
|
|
|
(1,770 |
) |
|
|
(4,286 |
) |
Other
|
|
|
(1,172 |
) |
|
|
(1,264 |
) |
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
79,711 |
|
|
|
88,920 |
|
Inventories
|
|
|
9,156 |
|
|
|
3,508 |
|
Taxes accrued
|
|
|
11,007 |
|
|
|
(8,029 |
) |
Accounts payable
|
|
|
(30,052 |
) |
|
|
(39,323 |
) |
Interest accrued
|
|
|
(55 |
) |
|
|
(38 |
) |
Deferred gas costs
|
|
|
2,682 |
|
|
|
(18,336 |
) |
Deferred tax liabilities
|
|
|
27,516 |
|
|
|
15,979 |
|
Other - net
|
|
|
6,328 |
|
|
|
(8,694 |
) |
Cash provided by operating activities
|
|
|
168,735 |
|
|
|
104,263 |
|
Investing activities:
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(47,815 |
) |
|
|
(125,966 |
) |
Utility gas reserves
|
|
|
(16,152 |
) |
|
|
- |
|
Restricted cash
|
|
|
(1 |
) |
|
|
34,614 |
|
Other
|
|
|
68 |
|
|
|
964 |
|
Cash used in investing activities
|
|
|
(63,900 |
) |
|
|
(90,388 |
) |
Financing activities:
|
|
|
|
|
|
|
|
|
Common stock issued (purchased) - net, including common stock expense
|
|
|
(70 |
) |
|
|
1,613 |
|
Long-term debt retired
|
|
|
(10,000 |
) |
|
|
- |
|
Change in short-term debt
|
|
|
(72,035 |
) |
|
|
4,875 |
|
Cash dividend payments on common stock
|
|
|
(23,204 |
) |
|
|
(22,035 |
) |
Other
|
|
|
717 |
|
|
|
382 |
|
Cash used in financing activities
|
|
|
(104,592 |
) |
|
|
(15,165 |
) |
Increase (decrease) in cash and cash equivalents
|
|
|
243 |
|
|
|
(1,290 |
) |
Cash and cash equivalents - beginning of period
|
|
|
3,457 |
|
|
|
8,432 |
|
Cash and cash equivalents - end of period
|
|
$ |
3,700 |
|
|
$ |
7,142 |
|
|
|
|
|
|
|
|
|
|
Supplemental disclosure of cash flow information:
|
|
|
|
|
|
|
|
|
Interest paid
|
|
$ |
20,770 |
|
|
$ |
20,370 |
|
Income taxes paid
|
|
$ |
1,522 |
|
|
$ |
21,100 |
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements.
|
|
NORTHWEST NATURAL GAS COMPANY
PART I. FINANCIAL INFORMATION
Notes to Consolidated Financial Statements
(Unaudited)
The accompanying consolidated financial statements represent the consolidation of Northwest Natural Gas Company (NW Natural) and all companies that we directly or indirectly control, either through majority ownership or otherwise. Our direct and indirect wholly-owned subsidiaries include Gill Ranch Storage, LLC (Gill Ranch), NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), and NNG Financial Corporation (NNG Financial). Investments in corporate joint ventures and partnerships that we do not directly or indirectly control, and for which we are not the primary beneficiary, are accounted for under the equity method or the cost method, which includes NWN Energy’s investment in Palomar Gas Holdings, LLC (PGH). NW Natural and its affiliated companies are collectively referred to herein as “NW Natural.” The consolidated financial statements are presented after elimination of all significant intercompany balances and transactions, except for amounts required to be included under regulatory accounting standards to reflect the effect of such regulation. In this 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 and other non-utility investments and business activities (see Note 4).
Information presented in these interim consolidated financial statements is unaudited, but includes all material adjustments that management considers necessary for a fair statement of the results for each period reported including normal recurring accruals. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes included in our 2010 Annual Report on Form 10-K (2010 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.
Our significant accounting policies are described in Note 2 of the 2010 Form 10-K. There were no material changes to those accounting policies during the six months ended June 30, 2011, except for a change in the application of our accounting policy with respect to revenue recognition of the regulatory adjustment for income taxes paid and the recognition of pension expense under regulatory deferred accounting. For further discussion of this change in significant accounting policies and the impact of new accounting standards, see Note 2 below. We do not have any subsequent events to report.
2. Significant Accounting Policies Update
Industry Regulation
In applying regulatory accounting principles, we capitalize or defer certain costs and revenues as regulatory assets and liabilities. At June 30, 2011 and 2010 and at December 31, 2010, the amounts deferred as regulatory assets and liabilities were as follows:
|
|
Regulatory Assets
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
December 31,
|
|
Thousands
|
|
2011
|
|
|
2010
|
|
|
2010
|
|
Current:
|
|
|
|
|
|
|
|
|
|
Unrealized loss on derivatives(1)
|
|
$ |
25,986 |
|
|
$ |
34,463 |
|
|
$ |
38,437 |
|
Pension and other postretirement benefit liabilities(2)
|
|
|
10,988 |
|
|
|
7,502 |
|
|
|
10,988 |
|
Other(3)
|
|
|
22,792 |
|
|
|
14,839 |
|
|
|
3,289 |
|
Total current
|
|
$ |
59,766 |
|
|
$ |
56,804 |
|
|
$ |
52,714 |
|
Non-current:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized loss on derivatives(1)
|
|
$ |
9,202 |
|
|
$ |
16,917 |
|
|
$ |
17,022 |
|
Income tax asset
|
|
|
70,241 |
|
|
|
75,515 |
|
|
|
72,341 |
|
Pension and other postretirement benefit liabilities(2)
|
|
|
112,743 |
|
|
|
106,089 |
|
|
|
118,248 |
|
Environmental costs(4)
|
|
|
120,285 |
|
|
|
109,324 |
|
|
|
114,311 |
|
Other(3)
|
|
|
13,610 |
|
|
|
21,352 |
|
|
|
26,975 |
|
Total non-current
|
|
$ |
326,081 |
|
|
$ |
329,197 |
|
|
$ |
348,897 |
|
|
|
Regulatory Liabilities
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
December 31,
|
|
Thousands
|
|
2011
|
|
|
2010
|
|
|
2010
|
|
Current:
|
|
|
|
|
|
|
|
|
|
Gas costs payable
|
|
$ |
17,538 |
|
|
$ |
23,416 |
|
|
$ |
15,583 |
|
Unrealized gain on derivatives(1)
|
|
|
4,433 |
|
|
|
1,495 |
|
|
|
2,245 |
|
Other(3)
|
|
|
3,813 |
|
|
|
4,613 |
|
|
|
- |
|
Total current
|
|
$ |
25,784 |
|
|
$ |
29,524 |
|
|
$ |
17,828 |
|
Non-current:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas costs payable
|
|
$ |
3,023 |
|
|
$ |
2,218 |
|
|
$ |
2,297 |
|
Unrealized gain on derivatives(1)
|
|
|
1,042 |
|
|
|
453 |
|
|
|
628 |
|
Accrued asset removal costs
|
|
|
259,593 |
|
|
|
246,839 |
|
|
|
252,941 |
|
Other(3)
|
|
|
2,045 |
|
|
|
2,075 |
|
|
|
2,165 |
|
Total non-current
|
|
$ |
265,703 |
|
|
$ |
251,585 |
|
|
$ |
258,031 |
|
(1)
|
Unrealized gain or loss on derivatives does not earn a rate of return or a carrying charge. These amounts are recoverable through utility rates as part of the Purchased Gas Adjustment mechanism when realized at settlement.
|
(2)
|
Certain pension and other postretirement benefit liabilities of the utility are approved for regulatory deferral, including the approval of a pension cost balancing account to defer the effects of higher and lower pension expenses in future years. Such amounts are recoverable in rates, including an interest component, when recognized in pension expense or net periodic benefit cost (see Note 9).
|
(3)
|
Other primarily consists of deferrals and amortizations under other approved regulatory mechanisms. The accounts being amortized typically earn a rate of return or carrying charge.
|
(4)
|
Environmental costs are related to certain utility sites that are approved for regulatory deferral. In Oregon we earn the utility’s authorized rate of return as a deferred carrying charge on deferred account balances.
|
Revenue Recognition
Utility and non-utility revenues, which are derived primarily from the sale, transportation or storage of natural gas, are recognized upon the delivery of gas commodity or service to customers. Since 2007, utility net operating revenues have also included the recognition of a regulatory adjustment for income taxes paid pursuant to a legislative rule (commonly referred to as SB 408) in effect for certain gas and electric utilities in Oregon. Under SB 408, we were required to automatically implement a rate refund, or a rate surcharge, to utility customers on an annual basis. The refund or surcharge amount was based on the difference between income taxes paid and income taxes authorized to be collected in customer rates. We recorded the refund, or surcharge, each quarter from 2007 through 2010 based on the annual amount to be recognized. However, on May 24, 2011, SB 408 was repealed when the Oregon Governor signed Senate Bill 967 (SB 967) into law. SB 967, requires utilities to eliminate amounts accrued under SB 408 for the 2010 and 2011 tax years, thereby denying recovery by NW Natural of the surcharge related to 2010, which resulted in a one-time pre-tax charge of $7.4 million (or 17 cents per share) in the second quarter of 2011. With respect to the first quarter of 2011, there was substantial uncertainty surrounding the continuation of the legal requirements of SB 408 as of March 31, 2011, and accordingly we did not record an accrual for the estimated refund or surcharge so no amounts were required to be written off for 2011.
Net periodic pension cost consists of service costs, interest costs, the expected returns on plan assets, and the amortization of actuarial gains and losses. Effective January 1, 2011, we began deferring a portion of our net periodic pension cost to a regulatory account on the balance sheet pursuant to OPUC approval of to defer certain pension expenses above or below the amount set in rates. See Note 9 for further information. As of June 30, 2011, the total amount deferred was $2.7 million.
New Accounting Standards
Adopted Standards
Fair Value Disclosures. In January 2010, the Financial Accounting Standards Board (FASB) issued authoritative guidance on new fair value measurements and disclosures. This guidance requires additional disclosures for fair value measurements that use significant assumptions not observable in active markets (i.e. level 3 valuations), including a rollforward schedule. These changes were effective for periods beginning after December 15, 2010; however, we elected to early adopt these disclosure requirements, as shown in Note 9 in our 2010 Form 10-K. The adoption of this standard did not have a material effect on our financial statement disclosures.
Recent Accounting Pronouncements
Fair Value Measurement. In May 2011, the FASB issued amendments to the authoritative guidance on fair value measurement. The amendments are primarily related to disclosure requirements, which go into effect for periods beginning after December 15, 2011. Early implementation is not allowed and we are currently assessing the impact on our financial statement disclosures.
Comprehensive Income. In June 2011, the FASB issued authoritative guidance on the presentation of comprehensive income within the financial statements. An entity can elect to present items of net income and other comprehensive income in one continuous statement — referred to as the statement of comprehensive income — or in two separate, but consecutive, statements. These changes are effective for periods beginning after December 15, 2011 and early implementation is not permitted. We intend to present net income and other comprehensive income in one continuous statement.
Basic earnings per share are computed using the weighted average number of common shares outstanding during each period presented. Diluted earnings per share are computed using the weighted average number of common shares outstanding plus the potential effects of the assumed exercise of stock options, and payment of estimated stock awards from other stock-based compensation plans that are outstanding, at the end of each period presented. Diluted earnings per share are calculated as follows:
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
Thousands, except per share amounts
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
Net income
|
|
$ |
2,193 |
|
|
$ |
6,888 |
|
|
$ |
42,966 |
|
|
$ |
50,496 |
|
Average common shares outstanding - basic
|
|
|
26,673 |
|
|
|
26,569 |
|
|
|
26,671 |
|
|
|
26,553 |
|
Additional shares for stock-based compensation plans
|
|
|
54 |
|
|
|
72 |
|
|
|
54 |
|
|
|
68 |
|
Average common shares outstanding - diluted
|
|
|
26,727 |
|
|
|
26,641 |
|
|
|
26,725 |
|
|
|
26,621 |
|
Earnings per share of common stock - basic
|
|
$ |
0.08 |
|
|
$ |
0.26 |
|
|
$ |
1.61 |
|
|
$ |
1.90 |
|
Earnings per share of common stock - diluted
|
|
$ |
0.08 |
|
|
$ |
0.26 |
|
|
$ |
1.61 |
|
|
$ |
1.90 |
|
For the three months ended June 30, 2011 and 2010, 8,946 and 5,052 common share equivalents, respectively, were excluded from the calculation of diluted earnings per share because the effect of these additional shares on the net income for both periods would have been anti-dilutive. For the six months ended June 30, 2011 and 2010, 3,883 and 1,364 common share equivalents, respectively, were excluded from the calculation of diluted earnings per share because the effect of these shares would have been anti-dilutive.
We operate in two primary reportable business segments, local gas distribution and gas storage. We also have other investments and business activities not specifically related to one of these two reporting segments, which we aggregate and report as “other.” We refer to our local gas distribution business as the “utility,” and our “gas storage” and “other” business segments as “non-utility.” Our gas storage segment includes NWN Gas Storage, a wholly-owned subsidiary of NWN Energy, Gill Ranch, a wholly-owned subsidiary of NWN Gas Storage, the non-utility portion of our Mist underground storage facility in Oregon (Mist) and third-party optimization services. Our “other” segment includes NNG Financial and our equity investment in PGH which is pursuing development of the Palomar pipeline project. For further discussion of our segments, see Note 4 in our 2010 Form 10-K.
The following table presents summary financial information about the reportable segments for the three and six months ended June 30, 2011 and 2010. Inter-segment transactions were insignificant.
|
Three Months Ended June 30,
|
|
|
|
|
|
Non-Utility
|
|
|
|
|
Thousands
|
|
Utility
|
|
|
Gas Storage
|
|
|
Other
|
|
|
Total
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
Net operating revenues
|
|
$ |
60,048 |
|
|
$ |
7,197 |
|
|
$ |
(13 |
) |
|
$ |
67,232 |
|
Depreciation and amortization
|
|
|
15,946 |
|
|
|
1,600 |
|
|
|
- |
|
|
|
17,546 |
|
Income from operations
|
|
|
9,667 |
|
|
|
3,017 |
|
|
|
(31 |
) |
|
|
12,653 |
|
Net income (loss)
|
|
|
1,090 |
|
|
|
1,315 |
|
|
|
(212 |
) |
|
|
2,193 |
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net operating revenues
|
|
$ |
66,939 |
|
|
$ |
5,206 |
|
|
$ |
48 |
|
|
$ |
72,193 |
|
Depreciation and amortization
|
|
|
15,691 |
|
|
|
335 |
|
|
|
- |
|
|
|
16,026 |
|
Income from operations
|
|
|
16,271 |
|
|
|
3,925 |
|
|
|
22 |
|
|
|
20,218 |
|
Net income
|
|
|
4,641 |
|
|
|
2,122 |
|
|
|
125 |
|
|
|
6,888 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
|
|
|
Non-Utility
|
|
|
|
|
|
Thousands
|
|
Utility
|
|
|
Gas Storage
|
|
|
Other
|
|
|
Total
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net operating revenues
|
|
$ |
189,210 |
|
|
$ |
12,501 |
|
|
$ |
29 |
|
|
$ |
201,740 |
|
Depreciation and amortization
|
|
|
31,860 |
|
|
|
2,995 |
|
|
|
- |
|
|
|
34,855 |
|
Income from operations
|
|
|
85,791 |
|
|
|
4,733 |
|
|
|
(9 |
) |
|
|
90,515 |
|
Net income (loss)
|
|
|
41,220 |
|
|
|
2,003 |
|
|
|
(257 |
) |
|
|
42,966 |
|
Total assets at June 30, 2011
|
|
|
2,247,349 |
|
|
|
252,393 |
|
|
|
22,252 |
|
|
|
2,521,994 |
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net operating revenues
|
|
$ |
192,412 |
|
|
$ |
10,617 |
|
|
$ |
90 |
|
|
$ |
203,119 |
|
Depreciation and amortization
|
|
|
31,257 |
|
|
|
670 |
|
|
|
- |
|
|
|
31,927 |
|
Income from operations
|
|
|
92,853 |
|
|
|
8,436 |
|
|
|
39 |
|
|
|
101,328 |
|
Net income
|
|
|
45,533 |
|
|
|
4,623 |
|
|
|
340 |
|
|
|
50,496 |
|
Total assets at June 30, 2010
|
|
|
2,143,138 |
|
|
|
229,919 |
|
|
|
22,504 |
|
|
|
2,395,561 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets at December 31, 2010
|
|
$ |
2,310,388 |
|
|
$ |
282,945 |
|
|
$ |
23,283 |
|
|
$ |
2,616,616 |
|
We have a share repurchase program for our common stock under which we purchase shares on the open market or through privately negotiated transactions. We currently have Board authorization through May 2012 to repurchase up to an aggregate of 2.8 million shares, or up to $100 million. No shares of common stock were repurchased pursuant to this program during the six months ended June 30, 2011, but since inception in 2000 a total of 2.1 million shares have been repurchased at a total cost of $83.3 million.
6.
|
Stock-Based Compensation
|
We have several stock-based compensation plans, including a Long-Term Incentive Plan (LTIP), a Restated Stock Option Plan (Restated SOP) and an Employee Stock Purchase Plan. These plans are designed to promote stock ownership in NW Natural by employees and officers. For additional information on our stock-based compensation plans, see Part II, Item 8., Note 6, in the 2010 Form 10-K and current updates provided below.
Long-Term Incentive Plan. On February 23, 2011, 37,950 performance-based shares were granted under the LTIP, which include a market condition, based on target-level awards and a weighted-average grant date fair value of $25.25 per share. Fair value was estimated as of the date of grant using a Monte-Carlo option pricing model based on the following assumptions:
Stock price on valuation date
|
|
$ |
45.74 |
|
Performance term (in years)
|
|
|
3.0 |
|
Quarterly dividends paid per share
|
|
$ |
0.435 |
|
Expected dividend yield
|
|
|
3.7 |
% |
Dividend discount factor
|
|
|
0.8930 |
|
Restated Stock Option Plan. On February 23, 2011, options to purchase 122,700 shares were granted under the Restated SOP, with an exercise price equal to the closing market price of $45.74 per share on the date of grant, vesting over a four-year period following the date of grant and a term of 10 years and 7 days. The weighted-average grant date fair value was $6.73 per share. Fair value was estimated as of the date of grant using the Black-Scholes option pricing model based on the following assumptions:
Risk-free interest rate
|
|
|
2.0 |
% |
Expected life (in years)
|
|
|
4.5 |
|
Expected market price volatility factor
|
|
|
24.5 |
% |
Expected dividend yield
|
|
|
3.8 |
% |
Forfeiture rate
|
|
|
3.1 |
% |
As of June 30, 2011, there was $1.2 million of unrecognized compensation cost related to the unvested portion of outstanding Restated SOP awards expected to be recognized over a period extending through 2014.
|
7. |
|
Cost and Fair Value Basis of Long-Term Debt
|
Cost of Long-Term Debt
Our long-term debt consists of secured medium-term notes (MTNs) with maturity dates from 2012 through 2035, interest rates ranging from 3.95 percent to 9.05 percent, and a weighted-average coupon rate of 6.16 percent. For the six months ended June 30, 2011, we redeemed $10 million of MTNs. For more detail on our outstanding long-term debt, see Note 7 in our 2010 Form 10-K.
Fair Value of Long-Term Debt
The following table provides an estimate of the fair value of our long-term debt, including current maturities of long-term debt, using market prices in effect on the valuation date. Because our debt outstanding does not trade in active markets, we used interest rates of other companies outstanding debt issues that actively trade and have similar credit ratings, terms and remaining maturities to estimate fair value of our long-term debt issues. These are significant other observable inputs, or level 2 inputs, in the fair value hierarchy.
|
|
June 30,
|
|
|
December 31,
|
|
Thousands
|
|
2011
|
|
|
2010
|
|
|
2010
|
|
Carrying amount
|
|
$ |
591,700 |
|
|
$ |
636,700 |
|
|
$ |
601,700 |
|
Estimated fair value
|
|
$ |
678,281 |
|
|
$ |
728,172 |
|
|
$ |
690,126 |
|
Items excluded from net income and charged directly to stockholders’ equity are included in accumulated other comprehensive income (loss), net of tax. The amount of accumulated other comprehensive loss in stockholders’ equity is $6.3 million and $5.8 million as of June 30, 2011 and 2010, respectively, which is related to employee benefit plan liabilities. The following table provides a reconciliation of net income to total comprehensive income for the six months ended June 30, 2011 and 2010.
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
Thousands
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
Net income
|
|
$ |
2,193 |
|
|
$ |
6,888 |
|
|
$ |
42,966 |
|
|
$ |
50,496 |
|
Amortization of employee benefit plan liability, net of tax
|
|
|
146 |
|
|
|
98 |
|
|
|
292 |
|
|
|
196 |
|
Total comprehensive income
|
|
$ |
2,339 |
|
|
$ |
6,986 |
|
|
$ |
43,258 |
|
|
$ |
50,692 |
|
9.
|
Pension and Other Postretirement Benefit Costs
|
The following tables provide the components of net periodic benefit cost for our company-sponsored qualified and non-qualified defined benefit pension plans and other postretirement benefit plans:
|
Three Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
Other Postretirement
|
|
|
|
Pension Benefits
|
|
|
Benefits
|
|
Thousands
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
Service cost
|
|
$ |
1,900 |
|
|
$ |
1,773 |
|
|
$ |
168 |
|
|
$ |
156 |
|
Interest cost
|
|
|
4,526 |
|
|
|
4,492 |
|
|
|
343 |
|
|
|
342 |
|
Expected return on plan assets
|
|
|
(4,456 |
) |
|
|
(4,563 |
) |
|
|
- |
|
|
|
- |
|
Amortization of net actuarial loss
|
|
|
2,692 |
|
|
|
1,768 |
|
|
|
68 |
|
|
|
8 |
|
Amortization of prior service costs
|
|
|
88 |
|
|
|
204 |
|
|
|
49 |
|
|
|
49 |
|
Amortization of transition obligations
|
|
|
- |
|
|
|
- |
|
|
|
103 |
|
|
|
103 |
|
Net periodic benefit cost
|
|
|
4,750 |
|
|
|
3,674 |
|
|
|
731 |
|
|
|
658 |
|
Amount allocated to construction
|
|
|
(1,251 |
) |
|
|
(947 |
) |
|
|
(229 |
) |
|
|
(207 |
) |
Amount deferred to regulatory balancing account(1)
|
|
|
(1,329 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
Net amount charged to expense
|
|
$ |
2,170 |
|
|
$ |
2,727 |
|
|
$ |
502 |
|
|
$ |
451 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement
|
|
|
|
Pension Benefits
|
|
|
Benefits
|
|
Thousands
|
|
|
2011 |
|
|
|
2010 |
|
|
|
2011 |
|
|
|
2010 |
|
Service cost
|
|
$ |
3,799 |
|
|
$ |
3,546 |
|
|
$ |
336 |
|
|
$ |
312 |
|
Interest cost
|
|
|
9,053 |
|
|
|
8,983 |
|
|
|
687 |
|
|
|
685 |
|
Expected return on plan assets
|
|
|
(8,912 |
) |
|
|
(9,127 |
) |
|
|
- |
|
|
|
- |
|
Amortization of net actuarial loss
|
|
|
5,384 |
|
|
|
3,536 |
|
|
|
136 |
|
|
|
15 |
|
Amortization of prior service costs
|
|
|
176 |
|
|
|
410 |
|
|
|
98 |
|
|
|
98 |
|
Amortization of transition obligations
|
|
|
- |
|
|
|
- |
|
|
|
206 |
|
|
|
206 |
|
Net periodic benefit cost
|
|
|
9,500 |
|
|
|
7,348 |
|
|
|
1,463 |
|
|
|
1,316 |
|
Amount allocated to construction
|
|
|
(2,486 |
) |
|
|
(1,900 |
) |
|
|
(455 |
) |
|
|
(415 |
) |
Amount deferred to regulatory balancing account(1)
|
|
|
(2,659 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
Net amount charged to expense
|
|
$ |
4,355 |
|
|
$ |
5,448 |
|
|
$ |
1,008 |
|
|
$ |
901 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Effective January 1, 2011, the OPUC approved the deferral of certain pension expenses above or below the amount set in rates, with recovery of these deferred amounts through the implementation of a balancing account, which includes the expectation of lower pension expenses in future years. Our recovery of deferred pension expense balances includes accrued interest at the utility’s authorized rate of return.
|
|
See Part II, Item 8., Note 9, in the 2010 Form 10-K for more information about our pension and other postretirement benefit plans.
In addition to the company-sponsored defined benefit plans referred to above, we contribute to a multiemployer pension plan for our bargaining unit employees in accordance with our collective bargaining agreement, known as the Western States Office and Professional Employees International Union Pension Fund (Western States Plan). The cost of this plan is in addition to pension expense in the table above. The Western States Plan has reported an accumulated funding deficit for the current plan year and remains in critical status. The Western States Plan trustees adopted a rehabilitation plan that reduced benefit accrual rates and adjustable benefits for active employee participants and increased future employer contribution rates. These changes are expected to improve the funding status of the plan. We made contributions totaling $0.2 million to the Western States Plan for both the six months ended June 30, 2011 and 2010. If we withdraw and the plan is underfunded, we could be assessed a withdrawal liability which is not currently recognized on the balance sheet in accordance with accounting rules for multiemployer plans. Currently, we have no intent to withdraw from the plan, so we have not recorded a withdrawal liability.
Employer Pension Contributions
In the six months ended June 30, 2011, we made cash contributions totaling $16.4 million to our qualified defined benefit pension plans. We also expect to make additional contributions of between $5 million and $7 million to these qualified plans over the last six months of 2011, plus we expect to make ongoing benefit payments under our unfunded, non-qualified pension plans and other postretirement benefit plans. For more information see Part II, Item 8., Note 9, in the 2010 Form 10-K.
10. Income Tax
The effective income tax rate for the six months ended June 30, 2011 and 2010 varied from the combined federal and state statutory tax rates principally due to the following:
|
|
June 30,
|
|
|
|
2011
|
|
|
2010
|
|
Federal statutory tax rate
|
|
|
35.0 |
% |
|
|
35.0 |
% |
Increase (decrease):
|
|
|
|
|
|
|
|
|
Current state income tax, net of federal tax benefit
|
|
|
4.5 |
% |
|
|
4.8 |
% |
Amortization of investment and energy tax credits
|
|
|
(0.4 |
) % |
|
|
(0.4 |
) % |
Differences required to be flowed-through by regulatory commissions
|
|
|
1.6 |
% |
|
|
1.4 |
% |
Gains on company and trust-owned life insurance
|
|
|
(0.6 |
) % |
|
|
(0.4 |
) % |
Other - net
|
|
|
0.3 |
% |
|
|
0.1 |
% |
Effective income tax rate
|
|
|
40.4 |
% |
|
|
40.5 |
% |
The decrease in our effective tax rate for the six months ended June 30, 2011 compared to the same period in 2010 was negligible and primarily due to a change in state income tax rates. See Note 10 in our 2010 Form 10-K.
11.
|
Property, Plant and Equipment
|
The following table sets forth the major classifications of our property, plant and equipment and accumulated depreciation as of June 30, 2011 and 2010 and December 31, 2010:
|
|
June 30,
|
|
|
December 31,
|
|
Thousands
|
|
2011
|
|
|
2010
|
|
|
2010
|
|
Utility plant in service
|
|
$ |
2,281,407 |
|
|
$ |
2,218,660 |
|
|
$ |
2,247,952 |
|
Utility construction work in progress
|
|
|
32,814 |
|
|
|
30,086 |
|
|
|
29,324 |
|
Less: Accumulated depreciation
|
|
|
730,199 |
|
|
|
700,202 |
|
|
|
710,214 |
|
Utility plant-net
|
|
|
1,584,022 |
|
|
|
1,548,544 |
|
|
|
1,567,062 |
|
Non-utility plant in service
|
|
|
290,035 |
|
|
|
66,862 |
|
|
|
290,038 |
|
Non-utility construction work in progress
|
|
|
7,891 |
|
|
|
167,218 |
|
|
|
9,088 |
|
Less: Accumulated depreciation
|
|
|
14,730 |
|
|
|
10,530 |
|
|
|
12,025 |
|
Non-utility plant-net
|
|
$ |
283,196 |
|
|
$ |
223,550 |
|
|
$ |
287,101 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
$ |
1,867,218 |
|
|
$ |
1,772,094 |
|
|
$ |
1,854,163 |
|
12. Gas Reserves and Other Investments
Our gas reserves are stated at cost, net of regulatory amortization, with the associated deferred tax benefits recorded as liabilities on the balance sheet. Other investments include financial investments in life insurance policies, which are accounted for at fair value, and equity investments in certain partnerships and limited liability companies, which are accounted for under the equity or cost methods. See Part II, Item 8., Note 12, in the 2010 Form 10-K for more detail on our investments.
Gas Reserves
We signed agreements with Encana Oil & Gas (USA) Inc. (Encana) to develop physical gas reserves that are expected to supply a portion of our utility customers’ requirements over the next 30 years. The volume of gas produced and allocated to NW Natural under the agreements will increase in the early years as we continue to invest in drilling, with volumes expected to peak at about 13 percent of our utility’s gas supply requirement in gas year 2015-2016. Over the first 10 years of the agreement (2011-2020), volumes are expected to average approximately 8 to 10 percent of the annual requirements of our utility customers. Under the agreements, we expect to invest approximately $45 million to $55 million per year for five years, and our total investment is expected to be about $250 million.
In approving the agreements, the OPUC determined that our Company’s costs under the agreements will be recovered on an ongoing basis through its annual Purchased Gas Adjustment (PGA) mechanism, including the deferral and incentive sharing process for the commodity cost of gas. Annually, we will forecast the amounts related to gas reserve costs and volumes expected, and variances between forecast and actual up to $10 million will be subject to the normal PGA incentive sharing mechanism, which currently is set at 10 percent of the variance amount that would be recognized in earnings. Variances in excess of $10 million, both negative and positive, will be entirely deferred and passed through to customer rates. As part of the decision by the OPUC to approve the agreements, we have agreed to file a general rate case in Oregon no later than December 31, 2011.
Encana began drilling in May 2011 under our agreements, and we are currently receiving gas from our interests in a section of the gas field. Our net investment at June 30, 2011 is $12.1 million, net of deferred taxes totaling $4 million.
Variable Interest Entity Analysis. As of June 30, 2011, we have determined that the arrangements with Encana qualify as a VIE and that we are not the primary beneficiary of these activities as defined by the authoritative guidance related to consolidations. We account for our investment in the VIE on the cost basis and it is included under gas reserves on our balance sheet. Our maximum loss exposure related to the VIE is limited to our investment balance.
Palomar
PGH is a development stage variable interest entity. Palomar, a wholly-owned subsidiary of PGH, is pursuing the development of a new gas transmission pipeline that would provide an interconnection with our utility distribution system. PGH is owned 50 percent by NWN Energy and 50 percent by TransCanada American Investments Ltd., an indirect wholly-owned subsidiary of TransCanada Corporation.
Variable Interest Entity Analysis. As of June 30, 2011, we updated our VIE analysis and determined that we are not the primary beneficiary of PGH’s activities as defined by the authoritative guidance related to consolidations. Therefore, we account for our investment in PGH and the Palomar project under the equity method, which is included in other investments on our balance sheet. Our maximum loss exposure related to PGH is limited to our equity investment balance, less our share of any cash or other assets available to us as a 50 percent owner.
Impairment Analysis. Our investments in nonconsolidated entities accounted for under the equity method are reviewed for impairment when circumstances or events indicate a potential loss in value may have occurred, and on an annual basis following updates to our corporate planning assumptions. When it is determined that a loss in value is other than temporary, an impairment charge is recognized for the difference between the investment’s carrying value and its estimated fair value. Fair value is based on quoted market prices when available, or on the present value of expected discounted future cash flows. Differing assumptions could affect the timing and amount of an impairment recorded in any period.
In March 2011, our investment in PGH was reviewed for impairment when Palomar withdrew its original application with the Federal Energy Regulatory Commission (FERC) for a proposed natural gas pipeline in Oregon. At the same time, Palomar informed FERC that it intended to re-file an application later this year or in 2012 to reflect changes in the project scope, which was expected to eliminate the western portion of the proposed pipeline and align the revised project with the region’s current and future gas infrastructure needs. Palomar is working with customers in the Pacific Northwest to further understand their gas transportation needs. Palomar expects to obtain commercial support for its revised pipeline proposal, and then file a new FERC certificate application by the end of next year.
During the second quarter of 2011, we re-assessed our equity investment in Palomar assets related to the western portion of the pipeline and determined that these costs were impaired, and as a result we recorded a pre-tax charge of $0.3 million for our share of the project. Our remaining investment balance in Palomar consists of costs related to the east zone, of which the investment balance at June 30, 2011 is $14.4 million. We reviewed these east zone costs for impairment based on the current status of the project, including Palomar’s plans to conduct an open season and re-file a revised application with FERC later this year or in 2012. Based on our review, we determined that our remaining equity investment was not impaired because the fair value of expected cash flows from planned development of the eastern portion of the pipeline project exceeds our equity investment. However, if we learn later that the project is not viable or will not go forward, then we could be required to recognize an impairment charge of up to approximately $14.2 million based on the current amount of our equity investment net of cash and working capital at Palomar. We will continue to monitor and update our impairment analysis as needed.
13.
|
Derivative Instruments
|
We enter into swap, option and various option combinations for the purpose of hedging natural gas. We primarily use these derivative financial instruments to manage commodity prices related to our natural gas purchase requirements. A small portion of the derivatives are also related to foreign currency exchange transactions.
In the normal course of business, we enter into indexed-price physical forward natural gas commodity purchase (gas supply) contracts to meet the requirements of core utility customers. We also enter into financial derivatives, up to prescribed limits, to hedge price variability related to the physical gas supply contracts. Derivatives entered into prudently for future gas years prior to our annual PGA filing receive regulatory deferred accounting treatment. Derivative contracts entered into after the annual PGA rate was set on November 1, 2010 that are for the current gas contract year are subject to our PGA incentive sharing mechanism, which, during the current PGA year, provides for a 90 percent deferral of any gains and losses as regulatory assets or liabilities, with the remaining 10 percent recognized on the income statement. Most of our commodity hedging for the upcoming gas year is completed prior to the start of each gas year, and these hedge prices are included in our annual PGA filing.
The following table discloses the income statement presentation for the unrealized gains and losses from our derivative instruments for the six months ended June 30, 2011 and 2010. All of our currently outstanding derivative instruments are related to regulated utility operations as illustrated by the derivative gains and losses being deferred to the balance sheet accounts in accordance with regulatory accounting.
|
|
Three Months Ended
|
|
|
|
June 30, 2011
|
|
June 30, 2010
|
|
Thousands
|
|
Natural gas commodity(1)
|
|
|
Foreign currency (2)
|
|
|
Natural gas commodity(1)
|
|
|
Foreign currency (2)
|
|
Cost of sales
|
|
$ |
3,631 |
|
|
$ |
- |
|
|
$ |
8,471 |
|
|
$ |
- |
|
Other comprehensive income (loss)
|
|
|
- |
|
|
|
(196 |
) |
|
|
- |
|
|
|
(356 |
) |
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts deferred to regulatory accounts on balance sheet
|
|
|
(3,631 |
) |
|
|
196 |
|
|
|
(8,471 |
) |
|
|
356 |
|
|
Total impact on earnings
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
June 30, 2011
|
|
June 30, 2010
|
|
Thousands
|
|
Natural gas commodity(1)
|
|
|
Foreign currency (2)
|
|
|
Natural gas commodity(1)
|
|
|
Foreign currency (2)
|
|
Cost of sales
|
|
$ |
(30,119 |
) |
|
$ |
- |
|
|
$ |
(49,093 |
) |
|
$ |
- |
|
Other comprehensive income (loss)
|
|
|
- |
|
|
|
406 |
|
|
|
- |
|
|
|
(339 |
) |
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts deferred to regulatory accounts on balance sheet
|
|
|
30,119 |
|
|
|
(406 |
) |
|
|
49,093 |
|
|
|
339 |
|
|
Total impact on earnings
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Unrealized gain (loss) from natural gas commodity hedge contracts is recorded in cost of sales and reclassified to regulatory deferral accounts on the balance sheet.
|
|
(2)
|
Unrealized gain (loss) from foreign currency exchange contracts is recorded in other comprehensive income, and reclassified to regulatory deferral accounts on the balance sheet.
|
|
We had no collateral posted with our counterparties as of June 30, 2011 or 2010. We attempt to minimize the potential exposure to collateral calls by our counterparties to manage our liquidity risk. Based on our current credit ratings, most counterparties allow us credit limits ranging from $25 million to $50 million before collateral postings are required. Our collateral call exposure is set forth under credit support agreements, which generally contain credit limits. We also could be subject to collateral call exposure where we have agreed to provide adequate assurance, which is not specific as to the amount of credit limit allowed, but could potentially require additional collateral in the event of a material adverse change. Based upon current contracts outstanding, which reflect unrealized losses of $29.7 million at June 30, 2011, we have estimated the level of collateral demands, with and without potential adequate assurance calls, using current gas prices and various downgrade credit rating scenarios for NW Natural as follows:
|
|
|
|
|
Credit Rating Downgrade Scenarios
|
|
Thousands
|
|
(Current Ratings) A+/A3
|
|
|
BBB+/Baa1
|
|
|
BBB/Baa2
|
|
|
BBB-/Baa3
|
|
|
Speculative
|
|
With Adequate Assurance Calls
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
1,966 |
|
|
$ |
16,900 |
|
Without Adequate Assurance Calls
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
1,966 |
|
|
$ |
13,892 |
|
In the three and six months ended June 30, 2011, we realized net losses of $8.7 million and $29.6 million, respectively, from the settlement of natural gas hedge contracts at maturity, which were recorded as increases to the cost of gas, compared to net losses of $14.6 million and $20.8 million, respectively, for the three and six months ended June 30, 2010. The exchange rate in all foreign currency forward purchase contracts is included in our purchased cost of gas at settlement; therefore, no gain or loss is recorded from the settlement of those contracts.
We are exposed to derivative credit and liquidity risk primarily through securing fixed price natural gas commodity swaps to hedge the risk of price increases for our natural gas purchases made on behalf of our customers. For more information on our derivative instruments, see Note 13 in our 2010 Form 10-K.
Fair Value
In accordance with fair value accounting, we include nonperformance risk in calculating fair value adjustments. This includes a credit risk adjustment based on the credit spreads of our counterparties when we are in an unrealized gain position, or on our own credit spread when we are in an unrealized loss position. Our assessment of non-performance risk is generally derived from the credit default swap market and from bond market credit spreads. The impact of the credit risk adjustments for all outstanding derivatives was immaterial to the fair value calculation at June 30, 2011. As of June 30, 2011 and 2010 and December 31, 2010, the fair value was $29.7 million, $49.4 million and $52.6 million, respectively, using significant other observable, or level 2, inputs. We have used no level 3 inputs in our derivative valuations. We also did not have any transfers between level 1 or level 2 during the six months ended June 30, 2011 and 2010.
14.
|
Commitments and Contingencies
|
Environmental Matters
We own, or 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 and evaluate 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 site investigations, in some cases, we may not be able to reasonably estimate the high end of the range of possible loss. In those cases we have disclosed the nature of the potential loss and the fact that the high end of the range cannot be reasonably estimated.
We regularly review our environmental 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 and scope of the effort. Many of these steps are dependent upon the approval and direction of federal and state environmental regulators. The policies, determinations and directions of the regulators may develop and change over time and different regulators may take different positions on the various steps, creating further uncertainty as to the timing and scope of remediation activities. In certain cases, in addition to us, 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 and scope of the remediation effort. The allocation of liabilities among the potentially responsible parties is often subject to dispute and can be 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. In addition, disputes may arise between potentially responsible parties and regulators as to the severity of particular environmental matters and what remediation efforts are appropriate. These disputes could lead to adversarial administrative proceedings or litigation, with uncertain outcomes.
We estimate the range of loss for 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 an estimate within this range of possible losses that is more likely than other cost estimates, we record the liability at the lower end of this range. It is likely that changes in these estimates and ranges 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.
Gasco site. We own property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 (Gasco site). The Gasco site has been under 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 which outlined a range of remedial alternatives for the most contaminated portion of the Gasco site. In December 2004, we submitted an Ecological and Human Health Risk Assessment to ODEQ, and in May 2007 we completed a revised Remedial Investigation Report and submitted it to DEQ for review.
In 2007, we also submitted a Focused Feasibility Study (FFS) for the groundwater source control portion of the Gasco site, which ODEQ conditionally approved in March 2008, subject to the submission of additional information. We provided that information to ODEQ and are now working with the agency on the final design for the source control system. Based on the information currently available for groundwater source control at the Gasco site and our current assumptions regarding remediation, we have estimated a range of liability between $11 million and $30 million, for which we have recorded an accrued liability of $11.8 million at June 30, 2011. The estimated range of liability will be reassessed when ODEQ makes a final source control design decision.
In addition to groundwater source control, we signed a joint Order on Consent with the Environmental Protection Agency (EPA), which requires the design of remedial action for sediments from the Gasco site. This design project is underway. We also have other investigation and clean-up work, including work on the uplands portion of the Gasco site, that we expect to be required. For the sediments project and the other investigation and clean-up work, we have recorded an additional accrued liability of $37.8 million, which reflects the low end of the range of potential liability. We accrued at the low end because no amount within the range is considered to be more likely than another, and the high end of the range cannot reasonably be estimated.
Siltronic site. We previously owned property adjacent to the Gasco site that now is the location of a manufacturing plant owned by Siltronic Corporation (the Siltronic site). We are currently conducting an investigation of manufactured gas plant wastes on the uplands at this site for the ODEQ. The liability accrued at June 30, 2011 for the Siltronic site is $0.9 million, which is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another, and the high end of the range cannot reasonably be estimated.
Portland Harbor site. In 1998, the ODEQ and the EPA completed a study of sediments in a 5.5-mile segment of the Willamette River (Portland Harbor) that includes an area adjacent to the Gasco and Siltronic sites. 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), completion of which is scheduled for 2011. The EPA and the Lower Willamette Group are conducting focused studies on approximately nine miles of the lower Willamette River, including the 5.5-mile segment previously studied by the EPA. In August 2008, we signed a cooperative agreement to participate in a phased natural resource damage assessment, with the intent to identify what, if any, additional information is necessary to estimate further liabilities sufficient to support an early restoration-based settlement of natural resource damage claims. As of June 30, 2011, we have a liability accrued of $7.6 million for this site, which is at the low end of the range of the potential liability because no amount within the range is considered to be more likely than another, and the high end of the range cannot reasonably be estimated.
Central Service Center site. In 2006, we received notice from the ODEQ that our Central Service Center in southeast Portland (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 as a result of 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. In early 2008, we received notice that this site was added to the ODEQ’s list of sites where releases of hazardous substances have been confirmed and to its list where additional investigation or cleanup is necessary. We are currently performing an environmental investigation of the property with the ODEQ’s Independent Cleanup Pathway. As of June 30, 2011, we have a liability accrued of $0.5 million for investigation at this site. The estimate is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.
Front Street site. The Front Street site was the former location of a gas manufacturing plant we operated. It is near but outside the geographic scope of the current Portland Harbor site sediment studies. The EPA directed the Lower Willamette Group to collect a series of surface and subsurface sediment samples off the river bank adjacent to where that facility was located. Based on the results of that sampling, the EPA notified the Lower Willamette Group that additional sampling would be required. As the Front Street site is upstream from the Portland Harbor site, the EPA agreed that it could be managed separately from the Portland Harbor site under ODEQ authority. Work plans for source control investigation and a historical report were submitted to ODEQ and initial studies were completed. In 2010, ODEQ required additional studies which are underway. As of June 30, 2011, we have an estimated liability accrued of $0.8 million for the study of the sediments and riverbank groundwater and soils at the site. The estimate is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.
Oregon Steel Mills site. See “Legal Proceedings,” below.
Accrued Liabilities Relating to Environmental Sites. The following table summarizes the accrued liabilities relating to environmental sites at June 30, 2011 and 2010 and December 31 2010:
|
|
Current Liabilities
|
|
|
Non-Current Liabilities
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
Dec. 31,
|
|
|
June 30,
|
|
|
June 30,
|
|
|
Dec. 31,
|
|
Thousands
|
|
2011
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
2010
|
|
Gasco site
|
|
$ |
10,593 |
|
|
$ |
7,996 |
|
|
$ |
11,366 |
|
|
$ |
38,965 |
|
|
$ |
43,522 |
|
|
$ |
38,921 |
|
Siltronic site
|
|
|
836 |
|
|
|
724 |
|
|
|
720 |
|
|
|
71 |
|
|
|
358 |
|
|
|
201 |
|
Portland Harbor site
|
|
|
2,161 |
|
|
|
1,836 |
|
|
|
2,304 |
|
|
|
5,426 |
|
|
|
6,875 |
|
|
|
5,784 |
|
Central Service Center site
|
|
|
5 |
|
|
|
5 |
|
|
|
5 |
|
|
|
543 |
|
|
|
510 |
|
|
|
510 |
|
Front Street site
|
|
|
- |
|
|
|
72 |
|
|
|
1 |
|
|
|
823 |
|
|
|
166 |
|
|
|
1,097 |
|
Other sites
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
132 |
|
|
|
117 |
|
|
|
108 |
|
Total
|
|
$ |
13,595 |
|
|
$ |
10,633 |
|
|
$ |
14,396 |
|
|
$ |
45,960 |
|
|
$ |
51,548 |
|
|
$ |
46,621 |
|
Regulatory and Insurance Recovery for Environmental Costs. In May 2003, the Public Utility Commission of Oregon (OPUC) approved our request to defer unreimbursed environmental costs associated with certain named sites, including those described above. Beginning in 2006, the OPUC granted us additional authorization to accrue interest on deferred environmental cost balances, subject to an annual demonstration that we have maximized our insurance recovery or made substantial progress in securing insurance recovery for unrecovered environmental expenses. Through a series of extensions, the authorized cost deferral and interest accrual was extended through January 2010. We have filed a request with the OPUC to extend this deferral, and that request is still pending. In addition, we filed a request with the Washington Utilities and Transportation Commission (WUTC) in January 2011 to defer certain environmental costs associated with services provided to Washington customers. We received an order from the WUTC on June 30, 2011 granting that request. Environmental costs related to Washington will be deferred starting January 26, 2011, with cost recovery to be determined in a future rate case.
On a cumulative basis, we have recognized a total of $107.2 million for environmental costs, including legal, investigation, monitoring and remediation costs, including $4.9 million paid and expensed prior to regulatory deferral order approval. At June 30, 2011, we had a regulatory asset of $120.3 million, which includes $49.4 million of total paid expenditures to date, $59.6 million for additional environmental costs expected to be paid in the future and accrued interest of $16.7 million, partially offset by $5.4 million of environmental costs expensed in prior years. See table below.
In December 2010, NW Natural commenced litigation against certain of its historical liability insurers in Multnomah County Circuit Court, State of Oregon, Case Number 1012-17532. The defendants include Associated Electric & Gas Insurance Services Limited, Allianz Global Risk US Insurance Company, Certain Underwriters at Lloyd's, London, certain London market insurance companies and other insurance companies. In the suit, NW Natural alleges that the defendant insurance companies issued third party liability insurance policies to NW Natural and that the defendants have breached the terms of those policies by failing to indemnify NW Natural for liabilities arising from environmental contamination at certain sites caused or alleged to be caused by its historical operations. NW Natural seeks damages for the losses it has incurred to date, as well as declaratory relief for additional losses it expects to incur in the future. In addition to seeking recovery of our environmental costs from our insurers, we believe recovery of the remainder of our deferred charges, if any, is probable through the regulatory process. Our regulatory asset will be reduced by the amount of any corresponding insurance recoveries. We continue to anticipate that our overall insurance recovery effort will extend over several years.
Our regulatory recovery of environmental cost deferrals may be initiated in the next general rate case; however, we do not expect to have concluded our insurance recovery efforts by that point, so we are not currently able to estimate the amount of recovery expected through the implementation of new rates from the upcoming general rate proceeding. We will reclassify a portion of the deferred environmental costs to current when we anticipate insurance recovery or recovery of costs in rates within the next 12 months. The following table summarizes the non-current regulatory assets relating to environmental sites at June 30, 2011 and 2010 and December 31, 2010:
|
|
Non-Current Regulatory Assets
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
December 31,
|
|
Thousands
|
|
2011
|
|
|
2010
|
|
|
2010
|
|
Gasco site
|
|
$ |
78,270 |
|
|
$ |
71,531 |
|
|
$ |
74,205 |
|
Siltronic site
|
|
|
3,502 |
|
|
|
3,068 |
|
|
|
3,174 |
|
Portland Harbor site
|
|
|
35,379 |
|
|
|
32,712 |
|
|
|
33,940 |
|
Central Service Center site
|
|
|
612 |
|
|
|
551 |
|
|
|
553 |
|
Front Street site
|
|
|
2,067 |
|
|
|
1,056 |
|
|
|
2,020 |
|
Other sites
|
|
|
455 |
|
|
|
406 |
|
|
|
420 |
|
Total
|
|
$ |
120,285 |
|
|
$ |
109,324 |
|
|
$ |
114,312 |
|
We are subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings cannot be predicted with certainty, including the matter described below, we do not expect that the ultimate disposition of any of these matters will have a material effect on our financial condition, results of operations or cash flows.
Oregon Steel Mills site. In 2004, NW 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 our predecessor, Portland Gas & Coke Company, and 10 other third-party defendants were disposed of in a waste oil disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by Oregon Steel Mills. The 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. No date has been set for trial and discovery is ongoing. Although the final outcome of this proceeding cannot be predicted with certainty, we do not expect that the ultimate disposition of this matter will have a material effect on our financial condition, results of operations or cash flows.
ITEM 2.
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
The following is management’s assessment of Northwest Natural Gas Company’s (NW Natural) financial condition, including the principal factors that affect results of operations. The discussion refers to our consolidated activities for the three and six months ended June 30, 2011 and 2010. Unless otherwise indicated, references in this discussion to “Notes” are to the Notes to Consolidated Financial Statements in this report. This discussion should be read in conjunction with our 2010 Annual Report on Form 10-K (2010 Form 10-K).
The consolidated financial statements include the accounts of NW Natural and its direct and indirect wholly-owned subsidiaries which include: Gill Ranch Storage, LLC (Gill Ranch), NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), and NNG Financial Corporation (NNG Financial). These statements also include accounts related to an equity investment in Palomar Gas Holdings, LLC (PGH), which is pursuing the development of a proposed natural gas pipeline through its wholly-owned subsidiary Palomar Gas Transmission LLC (Palomar). These accounts make up our regulated local gas distribution business, our regulated gas storage businesses, and other regulated and non-regulated investments primarily engaged in energy-related businesses. In this report, the term “utility” is used to describe our regulated gas distribution business (local distribution company), and the term “non-utility” is used to describe our regulated gas storage businesses (gas storage) as well as our other regulated and non-regulated investments and business activities (other). For a further discussion of our business segments, see Note 4.
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 consolidated earnings. All references in this section to earnings per share are on the basis of diluted shares (see Part II, Item 8., Note 3, “Earnings Per Share,” in our 2010 Form 10-K). We use such non-GAAP (i.e. non-generally accepted accounting principles) measures in analyzing out financial performance and believe that they provide useful information to our investors and creditors in evaluating our financial condition and results of operations.
Executive Summary
Highlights of consolidated results for the second quarter of 2011 as compared to the same period in 2010 include:
·
|
Consolidated earnings of $2.2 million or 8 cents per share in the second quarter of 2011, as compared to $6.9 million and 26 cents in the second quarter of 2010;
|
·
|
Net income from utility operations decreased $3.6 million, from $4.6 million in 2010 to $1.1 million in 2011, largely due to a $7.4 million pre-tax charge related to a legislative change in Oregon that repealed Senate Bill (SB) 408;
|
·
|
Net income from gas storage operations decreased $0.8 million, from $2.1 million in 2010 to $1.3 million in 2011, primarily reflecting the weak market values for contract storage and optimization services;
|
·
|
Net operating revenues (margin) decreased $5.0 million or 7 percent over 2010, with utility margin down $6.9 million due to the one-time SB 408 charge and gas storage margin up $2.0 million from Gill Ranch first year costs including depreciation;
|
·
|
Operating expenses increased $2.6 million or 5 percent over 2010, which was largely attributed to increases in Gill Ranch’s operations and maintenance and depreciation and amortization;
|
·
|
Income tax expense decreased $3.0 million in 2011 compared to 2010, primarily due to lower pre-tax consolidated earnings;
|
·
|
Cash flow from operating activities in 2011 was $168.7 million, for an increase of $64.5 million or 62 percent over 2010;
|
·
|
Utility customers increased by approximately 5,600 over the last 12 months, for an annual growth rate of 0.8 percent compared to 1.0 percent a year ago; and
|
·
|
The utility business began investing in long-term gas reserves as a part of its gas purchasing strategy.
|
Issues, Challenges and Performance Measures
Economic Environment. Weakness in the local, national and global economies has continued to impact utility customer growth, the demand for natural gas, and the value of natural gas storage services. Our utility’s annual customer growth rate was 0.8 percent at June 30, 2011, as compared to 0.9 percent at March 31, 2011 and 1.0 percent at June 30, 2010. Although total delivered volumes to utility customers in the second quarter of 2011 increased 4 percent, we are still faced with unemployment rates around 10 percent in our service territories of Oregon and southwest Washington and a sluggish business environment. Despite these challenges, we believe we are well positioned to continue adding utility customers due to lower natural gas prices, a relatively low market penetration rate, our ongoing efforts to convert homes to natural gas, and the potential for environmental initiatives that could favor natural gas use in our region.
Managing Gas Prices and Supplies. Our gas acquisition strategy is regularly updated to secure sufficient supplies of natural gas to meet the needs of our utility customers and to hedge gas prices so that we can effectively manage costs, reduce price volatility and maintain a competitive advantage. With recent developments in drilling technologies and substantial access to supplies from shale gas formations around the U.S. and in Canada, the supply outlook for North American natural gas has increased dramatically, which is contributing to lower and more stable gas prices. The Purchased Gas Adjustment (PGA) mechanisms in Oregon and Washington, along with our own gas price hedging strategies and gas supplies in storage, enable us to reduce earnings risk exposure for the company and secure lower gas costs for our customers. These lower gas prices, can help strengthen natural gas’ competitive advantage compared to other fuels. See discussion of Utility Investment in Gas Reserves below under Strategic Opportunities.
We typically hedge approximately 75 percent of our anticipated year-round sales volumes based on normal weather. We entered the 2010-11 gas year (November 1, 2010 – October 31, 2011) hedged at a level of approximately 77 percent of our forecasted volumes, including 62 percent financially hedged and 15 percent physically hedged with gas in storage.
We recently entered into an agreement with Encana to invest in gas reserves, which will increase our physical gas hedge position in future gas years. Including estimates of gas to be produced from this investment, we are currently hedged at a level of approximately 68 percent for the 2011-12 gas year, reflecting 48 percent financially hedged and 20 percent physically hedged with storage and gas reserves. The 20 percent physically hedged is comprised of 17 percent for normal storage levels going into the winter heating season (including anticipated summer purchases), plus 3 percent for estimated production from gas reserves.
Additionally, we are currently hedged at a level of approximately 30 percent for the 2012-13 gas year, including 8 percent financially hedged and 22 percent physically hedged with storage and gas reserves. The 22 percent physically hedged is comprised of 16 percent for normal storage levels plus 6 percent for gas reserves. Our current hedge levels for the next two gas years are estimates and subject to change based on actual load volumes that are dependent on weather and economic conditions. Also, our storage levels may increase or decrease based on storage expansion or storage recall by the utility. As for gas reserve levels, these are estimates of production and are subject to change based on possible unforeseen events that could impact the speed of drilling and the volume of production.
Although stable gas prices provide opportunities to manage costs for our utility customers, they also present challenges for our gas storage business by lowering the value of, and reducing the demand for, storage services thus affecting our ability to sign customer contracts for longer terms at favorable prices.
Environmental Costs. We accrue material environmental loss contingencies related to our properties that require environmental investigation or remediation. Due to numerous uncertainties surrounding the preliminary nature of investigations or the developing nature of remediation requirements, actual costs could vary significantly from our loss estimates. As a regulated utility, we are allowed to defer certain costs pursuant to regulatory decisions. In 2010 and prior years, we were authorized by the Public Utility Commission of Oregon (OPUC) to defer certain environmental costs, and to seek recovery of those amounts in future rates to customers. For 2011, we have a request pending before the OPUC to approve an extension of the deferral order for certain environmental costs. The Company is also seeking recovery of these costs under insurance policies. Any amounts collected from insurance are expected to offset amounts that may otherwise be collected from customers. Ultimate recovery of environmental costs, either from regulated utility rates or from insurance, will depend on our ability to effectively manage these costs and demonstrate they were prudently incurred. Recovery may vary significantly from amounts currently recorded as regulatory assets, and amounts not recovered would be required to be charged to income in the period they were deemed to be unrecoverable. See Results of Operations—Regulatory Matters—Rate Mechanisms—Regulatory Recovery for Environmental Costs below, Note 14 in this report and Note 15 in our 2010 Form 10-K.
Climate Change. See Part II, Item 7., “Executive Summary - Issues, Challenges and Performance Measures—Climate change,” in our 2010 Form 10-K for a discussion of the effect of climate change on our business.
Performance Measures. In order to deal with the challenges affecting our businesses, we annually review and update our strategic plan to map our course over the next several years. Our plan includes strategies for: further improving our utility gas distribution services and operations; growing our non-utility gas storage business; investing in natural gas infrastructure when necessary to support the needs of our region; and maintaining a leadership role within the gas utility industry by addressing long-term energy policies and pursuing business opportunities that support clean energy technologies. We intend to measure our performance and monitor progress on certain metrics including, but not limited to: earnings per share growth; total shareholder return; return on invested capital; utility return on equity; utility customer satisfaction; utility margin; utility capital and operations and maintenance expense per customer; and non-utility earnings before interest, taxes, depreciation and amortization (non-utility EBITDA).
Strategic Opportunities
Business Process Improvements. To address the current economic and competitive challenges, we continue to evaluate and implement business strategies to improve efficiencies. Our goal is to develop, integrate, consolidate and streamline operations and support our employees with new technology tools.
Gas Storage Operations. The Company has developed gas storage facilities in Oregon and California. In California, Gill Ranch began operating during the fourth quarter of 2010, offering storage services to the California market at market-based rates, subject to California Public Utilities Commission (CPUC) regulation including, but not limited to, service terms and conditions, tariff regulations, and security issuances. Gill Ranch currently is designed as a 20 Bcf facility, of which 75 percent is owned by NW Natural, but is expandable to a total capacity of 40 Bcf of which NW Natural would own 50 percent. Due to increasing supplies and price stability of natural gas in North America, and declining demand for natural gas due to current economic conditions, storage values are expected to remain low in the near term, which will likely affect the prices at which Gill Ranch is able to contract and the timing of future storage expansions. For more information, see Note 4 in this report and Part II, Item 7., “2011 Outlook—Strategic Opportunities,” in our 2010 Form 10-K.
In Oregon, we own storage facilities at Mist which serve the Pacific Northwest storage markets. These markets also are negatively impacted by lower gas prices and lack of gas price volatility, but less so than in California and many other markets around the country because of limited availability of storage capacity in the Northwest. In 2011 and 2012, we expect to continue planning for possible expansion at our gas storage facilities near Mist in anticipation of increased demand for electric generation in the Pacific Northwest. Currently we do not have a set timeline for the next expansion at Mist, but we believe the timeframe for completion would be no earlier than 2013 or 2014. In the meantime, we will continue to monitor the market demand and work on preliminary design and project planning, which will ultimately require the development of storage wells, potentially a second compression station and additional pipeline gathering facilities that could enable future storage expansions.
Pipeline Diversification. Currently, our utility and Mist gas storage operations depend on a single bi-directional interstate transmission pipeline to ship gas supplies. Palomar, a wholly-owned subsidiary of PGH, is pursuing the development of a new gas transmission pipeline that would provide an interconnection with our utility distribution system. PGH is owned 50 percent by NWN Energy and 50 percent by TransCanada American Investments Ltd., an indirect wholly-owned subsidiary of TransCanada Corporation. The Palomar pipeline was originally proposed with an east and a west segment, but Palomar currently plans to design an east-only pipeline to serve our utility customers as well as the growing natural gas markets in Oregon and other parts of the Pacific Northwest. The proposed pipeline would be regulated by the Federal Energy Regulatory Commission (FERC).
In March 2011, Palomar withdrew its original application with FERC for a natural gas pipeline in Oregon, but at the same time informed FERC that it intends to file a new application later this year or in 2012, after it has conducted an open season and obtained commercial support for the east segment pipeline, which is approximately 110 miles long.
Utility Investment in Gas Reserves. In addition to hedging gas prices with financial derivative contracts over the next few years, we recently signed an agreement with Encana Oil & Gas (USA) Inc. (Encana) to develop physical gas supplies that are expected to supply a portion of our utility customers’ requirements over a period of about 30 years. During the first 10 years of the agreements, we forecast the volumes of gas received under the Encana agreements to provide approximately 8 to 10 percent of the average annual requirements of our utility customers. Under the agreements, we expect to invest approximately $45 million to $55 million per year for five years, with our total investment expected to be about $250 million. Encana will assign to us a working interest in leases to certain sections of the Jonah gas field, located near Rock Springs, Wyoming. The sections include both future and currently producing wells. Operation of the wells will be governed by a joint operating agreement under which Encana will be the operator and we will pay our proportionate share of operating costs.
On April 28, 2011, the OPUC issued an order approving the Encana gas reserve investment, which provides for the recovery of the costs plus a rate base return on our investment through the annual PGA mechanism, including the deferral process for the commodity cost of gas. See Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment below. Annually, a forecast will be established for the amounts related to costs and volumes expected, and variances between forecasted and actual will be subject to the PGA incentive sharing in Oregon, up to a maximum variance of $10 million (for a discussion of the incentive sharing provision, see “Results of Operations – Regulatory Matters – Rate Mechanisms” below). Any variances in excess of $10 million, both negative and positive, will be deferred and passed through to customers in future rates at 100 percent. As part of the decision by the OPUC, we agreed to file a general rate case in Oregon no later than December 31, 2011.
Consolidated Earnings and Dividends
Three months ended June 30, 2011 compared to June 30, 2010:
For the three months ended June 30, 2011, we had net income of $2.2 million, or 8 cents per share, compared to net income of $6.9 million, or 26 cents per share, for the same period last year.
The primary factors contributing to decreased second quarter consolidated net income were:
·
|
an $8.5 million decrease related to the regulatory adjustment of income taxes paid, which consisted of a one-time $7.4 million write-off in the second quarter of 2011 related to the amount accrued for 2010, plus the $1.1 million amount accrued in the second quarter of 2010 while the SB 408 rules were still in effect. See “Results of Operations - Business Segments - Utility Operations - Regulatory Adjustment for Income Taxes Paid,” below for further discussion; and
|
·
|
a $0.9 million decrease in income from operations related to non-utility storage at Mist and Gill Ranch.
|
Partially offsetting the above factors were:
·
|
a $3.0 million decrease in income tax expense due to lower taxable income; and
|
·
|
a $1.6 million increase in utility net operating revenues (margin), including the affects of our weather normalization and decoupling mechanisms, primarily due to colder weather and customer growth.
|
Six months ended June 30, 2011 compared to June 30, 2010:
Net income was $43 million, or $1.61 per share, for the six months ended June 30, 2011, compared to $50.5 million, or $1.90 per share, for the same period last year.
The primary factors contributing to the $7.5 million decrease in net income were:
·
|
a $6.1 million decrease related to a refund of property taxes in 2010, which is reflected by an operating expense increase of $5.2 million under general taxes and a $1.9 million decrease in interest income under other income partially offset by a decrease of $1.0 million under operations and maintenance;
|
·
|
an $11.2 million decrease related to the effects of the 2010 regulatory adjustment of income taxes paid and the write-off in 2011 due to new legislation (see “Results of Operations - Business Segments - Utility Operations - Regulatory Adjustment for Income Taxes Paid,” below); and
|
·
|
a $3.7 million decrease in income from operations related to our gas storage segment, primarily reflecting low contract storage values at Gill Ranch, decreased third party optimization revenue, and relatively lower contract storage values at Mist.
|
Partially offsetting the above factors were:
·
|
a $7.7 million increase in utility margin attributable to an increase in residential and commercial customer use, which reflect gains from colder weather and customer growth; and
|
·
|
a $5.2 million decrease in income tax expense due to lower taxable income.
|
Dividends paid on our common stock were 43.5 cents per share in the second quarter of 2011, compared to 41.5 cents per share in the second quarter of 2010. The Board of Directors declared a quarterly dividend on our common stock of 43.5 cents per share, payable on August 15, 2011, to shareholders of record on July 29, 2011. The current indicated annual dividend rate is $1.74 per share.
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 used different assumptions. Our most critical estimates and judgments include accounting for:
·
|
regulatory cost recovery and amortizations;
|
·
|
derivative instruments and hedging activities;
|
·
|
pensions and postretirement benefits;
|
·
|
environmental contingencies.
|
There have been no material changes to the information provided in the 2010 Form 10-K with respect to the application of critical accounting policies and estimates (see Part II, Item 7., “Application of Critical Accounting Policies and Estimates,” in the 2010 Form 10-K), except as indicated below under Revenue Recognition and Pension Expense.
Revenue Recognition
Utility and non-utility revenues, which are derived primarily from the sale, transportation or storage of natural gas, are recognized upon the delivery of gas commodity or service to customers. Since 2007, utility revenues have included the recognition of a regulatory adjustment for income taxes paid pursuant to a legislative rule (commonly referred to as SB 408) in effect for certain gas and electric utilities in Oregon. Under SB 408, we were required to automatically implement a rate refund, or a rate surcharge, to utility customers on an annual basis. The refund or surcharge amount was based on the difference between income taxes paid and income taxes authorized to be collected in customer rates. We recorded the refund, or surcharge, each quarter since 2007 based on the annual amount to be recognized. On May 24, 2011 the Oregon Governor signed Senate Bill 967 (SB 967), which in effect repealed SB 408 and the change was effective immediately. The new law requires utilities in Oregon, to reverse amounts accrued for the 2010 and 2011 tax years. For the tax year 2010, the Company recorded a one-time pre-tax charge to earnings in the second quarter of 2011 in the amount of $7.4 million ($4.4 million or 17 cents after tax). For the tax year 2011, there was substantial uncertainty surrounding the continuation of the legal requirements of SB 408, and accordingly the Company had not recognized any additional revenues in 2011. See “Results of Operations—Business Segments - Utility Operations—Regulatory Adjustment for Income Taxes Paid,” below for a further discussion.
Pension Expense
Net periodic benefit cost consists of service costs, interest costs, the expected returns on plan assets, and the amortization of actuarial gains and losses. Effective January 1, 2011, we began deferring a portion of our net periodic pension cost to a regulatory account on the balance sheet pursuant to OPUC approval of annual pension expenses above or below the amount set in rates. See Note 9 for further information. As of June 30, 2011, the total amount deferred was $2.7 million.
Management has discussed its current 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 aware of any reasonably likely events or circumstances that would result in materially different amounts being reported, except for the item discussed above under Revenue Recognition. For a description of recent accounting pronouncements that could have an impact on our financial condition, results of operations or cash flows, see Note 2.
Results of Operations
Regulatory Matters
Regulation and Rates
We are subject to regulation with respect to, among other matters, rates and systems of accounts set by the OPUC, Washington Utilities and Transportation Commission (WUTC), FERC, and with respect to Gill Ranch, the CPUC. The OPUC, WUTC and CPUC also regulate our issuance of securities. In 2011, approximately 90 percent of our utility gas volumes were delivered to, and utility operating revenues were derived from, Oregon customers, and the balance was from Washington customers. Future earnings and cash flows from utility operations will be determined largely by the Oregon and Washington economies in general, by the pace of growth in the residential and commercial markets in particular, and by our ability to remain price competitive, control expenses, and obtain reasonable and timely regulatory recovery for our utility gas costs, primarily operating and maintenance expenses and investment costs made in utility plant. See Part II, Item 7., “Results of Operations—Regulatory Matters,” in the 2010 Form 10-K.
Rate Mechanisms
Purchased Gas Adjustment. Rate changes are established for the utility each year under PGA mechanisms in Oregon and Washington to reflect changes in the expected cost of natural gas commodity purchases, including contract gas purchase prices, gas prices hedged with financial derivatives or physical gas reserves, gas inventory prices, interstate pipeline demand costs, 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.
In October 2010, the OPUC and WUTC approved PGA rate changes effective on November 1, 2010. The effect of these rate changes was to decrease the average monthly bills of Oregon and Washington residential customers by 2 percent. This was our second consecutive year of rate decreases.
Under the current PGA mechanism in Oregon, there is an incentive sharing provision whereby we are required to select each year either an 80 percent deferral or a 90 percent deferral of higher or lower actual gas costs compared to estimated PGA prices, such that the impact on current earnings from the incentive sharing is either 20 percent or 10 percent of the difference between actual and estimated gas costs, respectively. In addition to the gas cost incentive sharing mechanism, we are subject to an annual earnings review to determine if the utility is earning above its allowed return on equity (ROE) threshold. If utility earnings exceed a specific ROE level, then 33 percent of the amount above that level are required to be deferred for refund to customers. Under this provision, if we select the 80 percent deferral option, then we retain all of our earnings up to 150 basis points above the currently authorized ROE. If we select the 90 percent deferral option, then we retain all of our earnings up to 100 basis points above the currently authorized ROE. We selected the 90 percent deferral option for both the 2009-2010 and the 2010-2011 PGA years. The ROE threshold is subject to adjustment annually based on movements in long-term interest rates. For calendar years 2009 and 2010, the ROE threshold after adjustment for long-term interest rates was 11.5 percent and 11.02 percent, respectively. No amounts were required to be refunded to customers as a result of the 2009 utility earnings review, but based upon utility results for 2010 and the first two quarters of 2011, we accrued approximately $0.5 million and $0.4 million, respectively, for refund to customers in future rates.
In Oregon, we are subject to an annual earnings review to determine if the utility’s earnings are above a certain ROE threshold. If utility earnings exceed that threshold, then 33 percent of the amount above that level is deferred for refund to customers.
In the OPUC proceeding through which our earnings for 2010 are determined for purposes of the annual earnings review, OPUC Staff and other parties are disputing our determination of amounts that must to be deferred and refunded to customers. Specifically, they are challenging our determination that amounts received in 2010 from a refund of property tax expense related to prior years should be removed from the 2010 test period under normalization requirements established by the OPUC. Although we believe it is probable that the OPUC will rule in our favor on this dispute, the financial impact of an adverse ruling could increase the estimated refund to customers by up to $3 million, which we would be required to record as an additional charge to earnings.
There has been no change to the Washington PGA mechanism under which we defer 100 percent of the higher or lower actual gas costs and pass that difference through to customers as an adjustment to future rates.
Regulatory Recovery for Environmental Costs. The OPUC has authorized us to defer environmental costs associated with certain named sites and to accrue interest on environmental cost balances, subject to an annual demonstration that we have maximized our insurance recovery or made substantial progress in securing insurance recovery for unrecovered environmental expenses. We have filed a request for an extension of this deferral and expect to receive this authorization during the next couple of months. See Note 14. In January 2011, we filed a request with the WUTC to defer environmental costs, if any, that are incurred in connection with services provided to Washington customers. On June 30, 2011 we received an order granting approval of that request effective January 26, 2011. Cost recovery of deferred amounts will be determined in a future rate case.
Pension Deferral. Effective January 1, 2011, the OPUC approved our request to defer annual pension expenses above the amount set in rates, with recovery of these deferred amounts through the implementation of a balancing account, which includes the expectation of lower pension expenses in future years. Our recovery of deferred balances includes accrued interest on the account balance at the utility’s authorized rate of return. The estimated reduction to operations and maintenance expense for 2011 is estimated to be in the range of $4 to $5 million, with $2.7 million being deferred through June 30, 2011. Future years’ deferrals will depend on changes in plan assets and projected benefit liabilities, as well as our pension contributions.
For a discussion of other rate mechanisms, see Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms” in our 2010 Form 10-K.
Business Segments - Utility Operations
Our utility margin results are largely affected by customer growth and to a certain extent by changes in weather and customers’ gas usage patterns, with a significant portion of our earnings being derived from natural gas sales to residential and commercial customers. In Oregon, we have a conservation tariff that adjusts margin revenues to offset changes resulting from increases or decreases in residential and commercial customers’ gas usage. We also have a weather normalization mechanism in Oregon that adjusts customer bills up or down to offset changes in margin resulting from above- or below-average temperatures during the winter heating season. Both mechanisms are designed to reduce the volatility of our utility earnings and customer charges. For more information on our weather mechanism, see Regulatory Matters—Rate Mechanisms—Weather Normalization in our 2010 Form 10-K.
Three months ended June 30, 2011 compared to June 30, 2010:
Utility operations resulted in net income of $1.1 million, or 4 cents per share, in the second quarter of 2011 compared to net income of $4.6 million, or 17 cents per share, in the second quarter of 2010. The increase in utility margin from colder weather during the second quarter of 2011 was more than offset by a reduction in margin of $8.5 million in the second quarter of 2011 for the repeal of the regulatory adjustment for income taxes paid, including the $1.0 million of margin recorded in the second quarter of 2010. Total utility volumes sold and delivered in the second quarter of this year increased by 4 percent over last year.
Our weather normalization mechanism adjusted residential and commercial margins down by $4.8 million for the second quarter of 2011 based on temperatures that were 10 percent colder than last year and 38 percent colder than average, compared to a margin decrease of $1.9 million for the second quarter of 2010 when temperatures were 25 percent colder than average. Our decoupling mechanism adjusted residential and commercial margins up by $2.2 million in the second quarter of 2011, compared to a margin increase of $1.1 million in 2010.
Six months ended June 30, 2011 compared to June 30, 2010:
In the six months ended June 30, 2011, utility operations contributed net income of $41.2 million or $1.54 per share, compared to $45.5 million or $1.71 per share in 2010. Total utility volumes sold and delivered in the six months ended June 30, 2011 increased by 14 percent over last year primarily due to 17 percent colder weather, while total utility margin decreased by $3.2 million, or 2 percent, primarily due to a reduction in margin in the six months ended 2011 for the repeal of the regulatory adjustment for income taxes paid, compared to $4.0 million of increased margin recorded a year earlier for the impact of SB 408 in effect during 2010. The decrease in utility margin was partially offset by a $7.7 million increase in residential and commercial margins, after weather and decoupling mechanism adjustments, primarily related to the benefits of colder weather in the first six months of this year and customer growth (see “Residential and Commercial Sales,” below).
During the six months ended June 30, 2011 our weather normalization mechanism adjusted residential and commercial margins down by $10.6 million based on temperatures that were 17 percent colder than last year and 14 percent colder than average, compared to a margin increase of $11.6 million last year when temperatures were 3 percent warmer than average. Our decoupling mechanism adjusted residential and commercial margins up by $10.9 million in the six months ended June 30, 2011, compared to a margin increase of $9.0 million in the six months ended June 30, 2010.
The following tables summarize the composition of gas utility volumes, revenues and margin:
|
|
Three Months Ended
|
|
|
Favorable/
|
|
|
|
June 30,
|
|
|
(Unfavorable)
|
|
Thousands, except degree day and customer data
|
|
2011
|
|
|
2010
|
|
|
2011 vs. 2010
|
|
Utility volumes - therms:
|
|
|
|
|
|
|
|
|
|
Residential sales
|
|
|
78,377 |
|
|
|
72,094 |
|
|
|
6,283 |
|
Commercial sales
|
|
|
51,608 |
|
|
|
47,837 |
|
|
|
3,771 |
|
Industrial - firm sales
|
|
|
8,476 |
|
|
|
8,625 |
|
|
|
(149 |
) |
Industrial - firm transportation
|
|
|
31,906 |
|
|
|
31,156 |
|
|
|
750 |
|
Industrial - interruptible sales
|
|
|
14,519 |
|
|
|
13,924 |
|
|
|
595 |
|
Industrial - interruptible transportation
|
|
|
57,866 |
|
|
|
59,751 |
|
|
|
(1,885 |
) |
Total utility volumes sold and delivered
|
|
|
242,752 |
|
|
|
233,387 |
|
|
|
9,365 |
|
Utility operating revenues - dollars:
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential sales
|
|
$ |
86,628 |
|
|
$ |
84,002 |
|
|
$ |
2,626 |
|
Commercial sales
|
|
|
45,176 |
|
|
|
44,126 |
|
|
|
1,050 |
|
Industrial - firm sales
|
|
|
6,382 |
|
|
|
6,782 |
|
|
|
(400 |
) |
Industrial - firm transportation
|
|
|
1,520 |
|
|
|
1,382 |
|
|
|
138 |
|
Industrial - interruptible sales
|
|
|
8,027 |
|
|
|
8,196 |
|
|
|
(169 |
) |
Industrial - interruptible transportation
|
|
|
2,278 |
|
|
|
1,981 |
|
|
|
297 |
|
Regulatory adjustment for income taxes paid(1)
|
|
|
(7,451 |
) |
|
|
1,034 |
|
|
|
(8,485 |
) |
Other revenues
|
|
|
11,385 |
|
|
|
9,599 |
|
|
|
1,786 |
|
Total utility operating revenues
|
|
|
153,945 |
|
|
|
157,102 |
|
|
|
(3,157 |
) |
Cost of gas sold
|
|
|
90,054 |
|
|
|
86,292 |
|
|
|
(3,762 |
) |
Revenue taxes
|
|
|
3,843 |
|
|
|
3,871 |
|
|
|
28 |
|
Utility margin
|
|
$ |
60,048 |
|
|
$ |
66,939 |
|
|
$ |
(6,891 |
) |
Utility margin:(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential sales
|
|
$ |
43,766 |
|
|
$ |
41,098 |
|
|
$ |
2,668 |
|
Commercial sales
|
|
|
17,230 |
|
|
|
16,552 |
|
|
|
678 |
|
Industrial - sales and transportation
|
|
|
6,840 |
|
|
|
7,119 |
|
|
|
(279 |
) |
Miscellaneous revenues
|
|
|
1,526 |
|
|
|
1,303 |
|
|
|
223 |
|
Gain (loss) from gas cost incentive sharing
|
|
|
87 |
|
|
|
496 |
|
|
|
(409 |
) |
Other margin adjustments
|
|
|
632 |
|
|
|
105 |
|
|
|
527 |
|
Margin before regulatory adjustments
|
|
|
70,081 |
|
|
|
66,673 |
|
|
|
3,408 |
|
Weather normalization adjustment
|
|
|
(4,751 |
) |
|
|
(1,901 |
) |
|
|
(2,850 |
) |
Decoupling adjustment
|
|
|
2,169 |
|
|
|
1,133 |
|
|
|
1,036 |
|
Regulatory adjustment for income taxes paid(1)
|
|
|
(7,451 |
) |
|
|
1,034 |
|
|
|
(8,485 |
) |
Utility margin
|
|
$ |
60,048 |
|
|
$ |
66,939 |
|
|
$ |
(6,891 |
) |
Customers - end of period:
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential customers
|
|
|
611,564 |
|
|
|
606,323 |
|
|
|
5,241 |
|
Commercial customers
|
|
|
62,532 |
|
|
|
62,171 |
|
|
|
361 |
|
Industrial customers
|
|
|
906 |
|
|
|
911 |
|
|
|
(5 |
) |
Total number of customers - end of period
|
|
|
675,002 |
|
|
|
669,405 |
|
|
|
5,597 |
|
Actual degree days
|
|
|
944 |
|
|
|
857 |
|
|
|
|
|
Percent colder (warmer) than average weather(3)
|
|
|
38 |
% |
|
|
25 |
% |
|
|
|
|
|
|
|
Six Months Ended
|
|
|
Favorable/
|
|
|
|
|
June 30,
|
|
|
(Unfavorable)
|
|
Thousands, except degree day and customer data
|
|
2011
|
|
|
2010
|
|
|
2011 vs. 2010
|
|
Utility volumes - therms:
|
|
|
|
|
|
|
|
|
|
Residential sales
|
|
|
253,307 |
|
|
|
205,954 |
|
|
|
47,353 |
|
Commercial sales
|
|
|
151,575 |
|
|
|
126,693 |
|
|
|
24,882 |
|
Industrial - firm sales
|
|
|
19,113 |
|
|
|
18,778 |
|
|
|
335 |
|
Industrial - firm transportation
|
|
|
67,596 |
|
|
|
63,767 |
|
|
|
3,829 |
|
Industrial - interruptible sales
|
|
|
31,758 |
|
|
|
30,248 |
|
|
|
1,510 |
|
Industrial - interruptible transportation
|
|
|
120,817 |
|
|
|
121,350 |
|
|
|
(533 |
) |
|
Total utility volumes sold and delivered
|
|
|
644,166 |
|
|
|
566,790 |
|
|
|
77,376 |
|
Utility operating revenues - dollars:
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential sales
|
|
$ |
285,402 |
|
|
$ |
253,611 |
|
|
$ |
31,791 |
|
Commercial sales
|
|
|
140,489 |
|
|
|
124,201 |
|
|
|
16,288 |
|
Industrial - firm sales
|
|
|
15,338 |
|
|
|
15,400 |
|
|
|
(62 |
) |
Industrial - firm transportation
|
|
|
3,111 |
|
|
|
2,818 |
|
|
|
293 |
|
Industrial - interruptible sales
|
|
|
18,510 |
|
|
|
18,577 |
|
|
|
(67 |
) |
Industrial - interruptible transportation
|
|
|
4,588 |
|
|
|
3,900 |
|
|
|
688 |
|
Regulatory adjustment for income taxes paid(1)
|
|
|
(7,165 |
) |
|
|
4,018 |
|
|
|
(11,183 |
) |
Other revenues
|
|
|
11,399 |
|
|
|
15,640 |
|
|
|
(4,241 |
) |
|
Total utility operating revenues
|
|
|
471,672 |
|
|
|
438,165 |
|
|
|
33,507 |
|
Cost of gas sold
|
|
|
270,664 |
|
|
|
234,840 |
|
|
|
(35,824 |
) |
Revenue taxes
|
|
|
11,798 |
|