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Northwest Natural Gas Company 10-Q 2011
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 September 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 October 31, 2011, 26,702,926 shares of the registrant’s Common Stock (the only class of Common Stock) were outstanding.

 
 

 

NORTHWEST NATURAL GAS COMPANY
 
For the Quarterly Period Ended September 30, 2011
 
 
     
   
   
Page Number
 
1
     
 
     
 
2
     
 
3
     
 
5
     
 
6
     
23
     
45
     
45
     
 
PART II.  OTHER INFORMATION
 
     
46
     
46
     
46
     
46
     
 
47
 

 
 

 

 
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: 
·  
plans;
·  
objectives;
·  
goals;
·  
strategies;
·  
future events or performance;
·  
trends;
·  
cyclicality;
·  
earnings and dividends;
·  
growth;
·  
customer rates;
·  
commodity costs;
·  
operational performance and costs;
·  
liquidity and financial positions;
·  
project development and expansion;
·  
competition;
·  
storage levels, and values;
·  
procurement, development and production levels of gas supplies and reserves;
·  
estimated expenditures and investments;
·  
costs of compliance;
·  
credit exposures;
·  
potential efficiencies;
·  
impacts of laws, rules and regulations;
·  
tax liabilities or refunds;
·  
outcomes and effects of litigation, regulatory actions, and other administrative matters;
·  
projected status and obligations under retirement plans;
·  
adequacy of, and shift in mix of, gas supplies;
·  
approval and adequacy of regulatory deferrals; and
·  
costs and recovery related to environmental, regulatory, litigation and insurance.

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.

 
1

NORTHWEST NATURAL GAS COMPANY
PART I.  FINANCIAL INFORMATION

(Unaudited)
 
                             
     
Three Months Ended
   
Nine Months Ended
     
September 30,
   
September 30,
Thousands, except per share amounts
   
2011
   
2010
   
2011
   
2010
Operating revenues:
                       
 
Gross operating revenues
 
$
 93,313
 
$
 95,067
 
$
 577,598
 
$
 543,961
 
Less: Cost of sales
   
 43,133
   
 46,359
   
 313,880
   
 281,221
 
         Revenue taxes
   
 2,397
   
 2,497
   
 14,195
   
 13,410
   
Net operating revenues
   
 47,783
   
 46,211
   
 249,523
   
 249,330
Operating expenses:
                       
 
Operations and maintenance
   
 28,372
   
 26,913
   
 89,918
   
 85,985
 
General taxes
   
 7,514
   
 6,659
   
 22,338
   
 17,451
 
Depreciation and amortization
   
 17,449
   
 16,003
   
 52,304
   
 47,930
   
Total operating expenses
   
 53,335
   
 49,575
   
 164,560
   
 151,366
Income (loss) from operations
   
 (5,552)
   
 (3,364)
   
 84,963
   
 97,964
Other income and expense - net
   
 1,781
   
 1,333
   
 4,117
   
 5,969
Interest expense - net
   
 10,241
   
 10,632
   
 30,956
   
 31,738
Income (loss) before income taxes
   
 (14,012)
   
 (12,663)
   
 58,124
   
 72,195
Income tax expense (benefit)
   
 (5,700)
   
 (5,243)
   
 23,470
   
 29,119
Net income (loss)
 
$
 (8,312)
 
$
 (7,420)
 
$
 34,654
 
$
 43,076
Average common shares outstanding:
                       
 
Basic
   
 26,686
   
 26,606
   
 26,676
   
 26,571
 
Diluted
   
 26,686
   
 26,606
   
 26,730
   
 26,641
Earnings (loss) per share of common stock:
                       
 
Basic
 
$
 (0.31)
 
$
 (0.28)
 
$
 1.30
 
$
 1.62
 
Diluted
 
$
 (0.31)
 
$
 (0.28)
 
$
 1.30
 
$
 1.62
Dividends declared per share of common stock
 
$
 0.435
 
$
 0.415
 
$
 1.305
 
$
 1.245
                             
See Notes to Consolidated Financial Statements.

 
2

NORTHWEST NATURAL GAS COMPANY
PART I.  FINANCIAL INFORMATION

 
(Unaudited)
 
   
                   
                   
   
September 30,
   
September 30,
   
December 31,
 
Thousands
 
2011
   
2010
   
2010
 
Assets:
                 
Current assets:
                 
Cash and cash equivalents
  $ 25,862     $ 2,501     $ 3,457  
Restricted cash
    -       924       924  
Accounts receivable
    25,628       28,503       67,969  
Accrued unbilled revenue
    14,287       15,399       64,803  
Allowance for uncollectible accounts
    (1,733 )     (1,736 )     (2,950 )
Regulatory assets
    76,734       83,545       52,714  
Derivative instruments
    3,932       1,864       2,245  
Inventories:
                       
Gas
    73,572       80,955       70,672  
Materials and supplies
    10,009       8,668       9,713  
Gas reserves
    2,366       -       -  
Income taxes receivable
    5,019       6,762       41,066  
Other current assets
    14,871       11,282       19,652  
Total current assets
    250,547       238,667       330,265  
Non-current assets:
                       
Property, plant and equipment
    2,632,498       2,528,703       2,576,402  
Less: Accumulated depreciation
    756,592       711,046       722,239  
Total property, plant and equipment - net
    1,875,906       1,817,657       1,854,163  
Gas reserves
    28,125       -       -  
Regulatory assets
    328,757       339,786       348,897  
Derivative instruments
    227       518       628  
Other investments
    69,022       68,851       69,094  
Other non-current assets
    15,256       15,898       13,569  
Total non-current assets
    2,317,293       2,242,710       2,286,351  
Total assets
  $ 2,567,840     $ 2,481,377     $ 2,616,616  
                         
See Notes to Consolidated Financial Statements.
 

 
3

NORTHWEST NATURAL GAS COMPANY
PART I.  FINANCIAL INFORMATION


Consolidated Balance Sheets
 
(Unaudited)
 
                   
                   
                   
   
September 30,
   
September 30,
   
December 31,
 
Thousands
 
2011
   
2010
   
2010
 
Capitalization and liabilities:
                 
Capitalization:
                 
Common stock - no par value; authorized 100,000 shares; issued and outstanding 26,703, 26,640, and 26,668 at September 30, 2011 and 2010 and December 31, 2010, respectively
  $ 346,197     $ 342,271     $ 342,978  
Retained earnings
    356,574       338,725       356,727  
Accumulated other comprehensive income (loss)
    (6,166 )     (5,675 )     (6,604 )
Total common stock equity
    696,605       675,321       693,101  
Long-term debt
    601,700       591,700       591,700  
Total capitalization
    1,298,305       1,267,021       1,284,801  
                         
Current liabilities:
                       
Short-term debt
    181,200       159,875       257,435  
Current maturities of long-term debt
    40,000       45,000       10,000  
Accounts payable
    50,117       79,629       93,243  
Taxes accrued
    11,117       10,601       10,579  
Interest accrued
    11,321       12,220       5,182  
Regulatory liabilities
    28,593       31,502       17,828  
Derivative instruments
    46,651       59,898       38,437  
Other current liabilities
    33,609       28,074       35,457  
Total current liabilities
    402,608       426,799       468,161  
                         
Deferred credits and other non-current liabilities:
                       
Deferred tax liabilities
    394,217       324,166       373,409  
Regulatory liabilities
    266,907       252,425       258,031  
Pension and other postretirement benefit liabilities
    129,669       121,686       144,250  
Derivative instruments
    7,429       27,211       17,022  
Other non-current liabilities
    68,705       62,069       70,942  
Total deferred credits and other non-current liabilities
    866,927       787,557       863,654  
Commitments and contingencies (see Note 14)
    -       -       -  
Total capitalization and liabilities
  $ 2,567,840     $ 2,481,377     $ 2,616,616  
                         
See Notes to Consolidated Financial Statements.
 

 
4

NORTHWEST NATURAL GAS COMPANY
PART I.  FINANCIAL INFORMATION

 
(Unaudited)
 
             
   
Nine Months Ended
 
   
September 30,
 
Thousands
 
2011
   
2010
 
Operating activities:
           
Net income
  $ 34,654     $ 43,076  
Adjustments to reconcile net income to cash provided by operations:
               
Depreciation and amortization
    52,304       47,930  
Undistributed (earnings) losses from equity investments
    354       (576 )
Non-cash expenses related to qualified defined benefit pension plans
    5,491       5,758  
Contributions to qualified defined benefit pension plans
    (19,245 )     (10,000 )
Deferred environmental expenditures
    (7,018 )     (5,153 )
Other
    (969 )     (1,863 )
Changes in assets and liabilities:
               
Receivables
    92,840       103,377  
Inventories
    (3,196 )     (8,666 )
Taxes accrued
    36,585       (17,198 )
Accounts payable
    (33,369 )     (39,985 )
Interest accrued
    6,139       6,785  
Deferred gas costs
    370       (22,582 )
Deferred tax liabilities
    22,908       23,993  
Other - net
    3,440       (10,372 )
Cash provided by operating activities
    191,288       114,524  
Investing activities:
               
Capital expenditures
    (70,036 )     (185,651 )
Utility gas reserves
    (30,917 )     -  
Restricted cash
    924       34,619  
Other
    (192 )     953  
Cash used in investing activities
    (100,221 )     (150,079 )
Financing activities:
               
Common stock issued (purchased) - net, including common stock expense
    1,320       4,129  
Long-term debt issued
    50,000       -  
Long-term debt retired
    (10,000 )     -  
Change in short-term debt
    (76,235 )     57,875  
Cash dividend payments on common stock
    (34,807 )     (33,063 )
Other
    1,060       683  
Cash provided by (used in) financing activities
    (68,662 )     29,624  
Increase (decrease) in cash and cash equivalents
    22,405       (5,931 )
Cash and cash equivalents - beginning of period
    3,457       8,432  
Cash and cash equivalents - end of period
  $ 25,862     $ 2,501  
                 
Supplemental disclosure of cash flow information:
               
Interest paid
  $ 24,817     $ 23,796  
Income taxes paid
  $ 1,522     $ 21,100  
                 
See Notes to Consolidated Financial Statements.
 

 
5

NORTHWEST NATURAL GAS COMPANY
PART I.  FINANCIAL INFORMATION

(Unaudited)
 
1.
Organization and Principles of Consolidation

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 nine months ended September 30, 2011, except for changes in the application of our accounting policies with respect to revenue recognition for the regulatory adjustment of income taxes paid and to expense recognition for pension costs under a regulatory deferred accounting order.  For further discussion of these changes in significant accounting policies and the impact of new accounting standards, see Note 2 below.  We do not have any subsequent events to report.


 
6

NORTHWEST NATURAL GAS COMPANY
PART I.  FINANCIAL INFORMATION

2.           Significant Accounting Policies Update

Industry Regulation
 
In applying regulatory accounting principles in accordance with U.S. GAAP, we capitalize or defer certain costs and revenues as regulatory assets and liabilities.  At September 30, 2011 and 2010 and at December 31, 2010, the amounts deferred as regulatory assets and liabilities were as follows:

   
Regulatory Assets
 
   
September 30,
   
September 30,
   
December 31,
 
Thousands
 
2011
   
2010
   
2010
 
Current:
                 
Unrealized loss on derivatives(1)
  $ 46,651     $ 59,898     $ 38,437  
Pension and other postretirement benefit liabilities(2)
    10,988       7,502       10,988  
Other(3)
    19,095       16,145       3,289  
Total current
  $ 76,734     $ 83,545     $ 52,714  
Non-current:
                       
Unrealized loss on derivatives(1)
  $ 7,429     $ 27,211     $ 17,022  
Income tax asset
    70,241       75,515       72,341  
Pension and other postretirement benefit liabilities(2)
    110,007       104,327       118,248  
Environmental costs(4)
    122,454       111,931       114,311  
Other(3)
    18,626       20,802       26,975  
Total non-current
  $ 328,757     $ 339,786     $ 348,897  

   
Regulatory Liabilities
 
   
September 30,
   
September 30,
   
December 31,
 
Thousands
 
2011
   
2010
   
2010
 
Current:
                 
Gas costs payable
  $ 16,991     $ 20,487     $ 15,583  
Unrealized gain on derivatives(1)
    3,932       1,864       2,245  
Other(3)
    7,670       9,151       -  
Total current
  $ 28,593     $ 31,502     $ 17,828  
Non-current:
                       
Gas costs payable
  $ 1,250     $ 900     $ 2,297  
Unrealized gain on derivatives(1)
    227       518       628  
Accrued asset removal costs
    263,123       248,920       252,941  
Other(3)
    2,307       2,087       2,165  
Total non-current
  $ 266,907     $ 252,425     $ 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 amounts recorded to the pension cost balancing account to defer the effects of higher and lower pension expenses.  Such amounts are recoverable in rates, including an interest component.
(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.  Environmental costs related to Washington are being deferred starting January 26, 2011 with cost recovery to be determined in a future proceeding.


 
 
7

NORTHWEST NATURAL GAS COMPANY
PART I.  FINANCIAL INFORMATION
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 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 and replaced by Senate Bill 967.  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 2011, there was substantial uncertainty surrounding the continuation of the legal requirements of SB 408 as of March 31, 2011, and accordingly, we changed our revenue recognition policy effective January 1, 2011 and did not record an accrual for the regulatory adjustment of income taxes paid pursuant to SB 408.

Pension Expense

Net periodic pension costs consist 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 costs to a regulatory account on the balance sheet pursuant to Public Utility Commission of Oregon (OPUC) approval to defer certain pension expenses above or below the amount set in rates.  As of September 30, 2011, the total amount deferred was $4.0 million.  See Note 9 for further information.

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 roll-forward 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. We intend to present net income and other comprehensive income in one continuous statement starting January 1, 2012.

Multiemployer Pension Plans.> In September 2011, the FASB issued authoritative guidance regarding multiemployer pension plan disclosures.  The revised standard is intended to provide more information about an employer’s financial obligations to a multiemployer pension plan and, therefore, help financial statement users better understand the financial health of all significant plans in which the employer participates. This standard is effective for periods ending after December 15, 2011.  We are currently assessing the impact on our financial statement disclosures.

 
8

NORTHWEST NATURAL GAS COMPANY
PART I.  FINANCIAL INFORMATION

3.
Earnings Per Share
 
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
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
Thousands, except per share amounts
 
2011
   
2010
   
2011
   
2010
 
Net income (loss)
  $ (8,312 )   $ (7,420 )   $ 34,654     $ 43,076  
Average common shares outstanding - basic
    26,686       26,606       26,676       26,571  
Additional shares for stock-based compensation plans
    -       -       54       70  
Average common shares outstanding - diluted
    26,686       26,606       26,730       26,641  
Earnings (loss) per share of common stock - basic
  $ (0.31 )   $ (0.28 )   $ 1.30     $ 1.62  
Earnings (loss) per share of common stock - diluted
  $ (0.31 )   $ (0.28 )   $ 1.30     $ 1.62  

For the three months ended September 30, 2011 and 2010, 63,263 and 76,088 common share equivalents, respectively, were excluded from the calculation of diluted earnings per share because the effect of these additional shares on the net loss for both periods would have been anti-dilutive.  For the nine months ended September 30, 2011 and 2010, 3,436 and 427 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.

4.
Segment Information

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, which is a wholly-owned subsidiary of NWN Energy, Gill Ranch, which is 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.


 
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The following table presents summary financial information about the reportable segments for the three and nine months ended September 30, 2011 and 2010.  Inter-segment transactions were insignificant.

 
Three Months Ended September 30,
 
       
Non-Utility
       
Thousands
 
Utility
   
Gas Storage
   
Other
   
Total
 
2011
                       
Net operating revenues
  $ 41,034     $ 6,710     $ 39     $ 47,783  
Depreciation and amortization
    15,875       1,574       -       17,449  
Income (loss) from operations
    (8,029 )     2,458       19       (5,552 )
Net income (loss)
    (9,518 )     1,160       46       (8,312 )
2010
                               
Net operating revenues
  $ 41,258     $ 4,906     $ 47     $ 46,211  
Depreciation and amortization
    15,668       335       -       16,003  
Income (loss) from operations
    (6,858 )     3,474       20       (3,364 )
Net income (loss)
    (9,123 )     1,782       (79 )     (7,420 )
                                 
 
Nine Months Ended September 30,
 
         
Non-Utility
         
Thousands
 
Utility
   
Gas Storage
   
Other
   
Total
 
2011
                               
Net operating revenues
  $ 230,244     $ 19,211     $ 68     $ 249,523  
Depreciation and amortization
    47,735       4,569       -       52,304  
Income from operations
    77,762       7,191       10       84,963  
Net income (loss)
    31,702       3,163       (211 )     34,654  
Total assets at September 30, 2011
    2,291,531       253,478       22,831       2,567,840  
2010
                               
Net operating revenues
  $ 233,670     $ 15,523     $ 137     $ 249,330  
Depreciation and amortization
    46,925       1,005       -       47,930  
Income from operations
    85,995       11,910       59       97,964  
Net income
    36,410       6,405       261       43,076  
Total assets at September 30, 2010
    2,192,557       266,022       22,798       2,481,377  
                                 
Total assets at December 31, 2010
  $ 2,310,388     $ 282,945     $ 23,283     $ 2,616,616  

5.
Common Stock
 
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, but not to exceed $100 million. No shares of common stock were repurchased pursuant to this program during the nine months ended September 30, 2011.  Since inception in 2000, a total of 2.1 million shares have been repurchased at a total cost of $83.3 million.


 
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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 September 30, 2011, there was $1.0 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
 
New Issuance of Long-Term Debt

On September 12, 2011, we issued $50 million of secured medium-term notes (MTNs) with an interest rate of 3.176 percent and a maturity date of September 15, 2021.

Cost of Long-Term Debt

Our long-term debt consists of secured MTNs with maturity dates from 2012 through 2035, interest rates ranging from 3.176 percent to 9.05 percent, and a weighted-average coupon rate of 5.93 percent.  For the nine months ended September 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 and new issuance of long-term debt above.


 
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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.

   
September 30,
   
December 31,
 
Thousands
 
2011
   
2010
   
2010
 
Carrying amount
  $ 641,700     $ 636,700     $ 601,700  
Estimated fair value
  $ 774,186     $ 740,731     $ 690,126  

8.
Comprehensive Income
 
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 $6.2 million and $5.7 million as of September 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 nine months ended September 30, 2011 and 2010.

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
Thousands
 
2011
   
2010
   
2011
   
2010
 
Net income (loss)
  $ (8,312 )   $ (7,420 )   $ 34,654     $ 43,076  
Amortization of employee benefit plan liability, net of tax
    146       97       438       293  
Total comprehensive income (loss)
  $ (8,166 )   $ (7,323 )   $ 35,092     $ 43,369  


 
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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 September 30,
 
               
Other Postretirement
 
   
Pension Benefits
   
Benefits
 
 Thousands
 
2011
   
2010
   
2011
   
2010
 
 Service cost
  $ 1,839     $ 1,435     $ 168     $ 156  
 Interest cost
    4,503       4,517       344       343  
 Expected return on plan assets
    (4,455 )     (4,528 )     -       -  
 Amortization of net actuarial loss
    2,683       2,028       68       7  
 Amortization of prior service costs
    88       (270 )     50       50  
 Amortization of transition obligations
    -       -       103       103  
Net periodic benefit cost
    4,658       3,182       733       659  
 Amount allocated to construction
    (1,279 )     (897 )     (234 )     (231 )
 Amount deferred to regulatory balancing account(1)
    (1,330 )     -       -       -  
Net amount charged to expense
  $ 2,049     $ 2,285     $ 499     $ 428  
                                 
 
Nine Months Ended September 30,
 
                   
Other Postretirement
 
   
Pension Benefits
   
Benefits
 
 Thousands
    2011       2010       2011       2010  
 Service cost
  $ 5,638     $ 4,981     $ 504     $ 468  
 Interest cost
    13,556       13,500       1,031       1,028  
 Expected return on plan assets
    (13,367 )     (13,655 )     -       -  
 Amortization of net actuarial loss
    8,067       5,564       204       22  
 Amortization of prior service costs
    264       140       148       148  
 Amortization of transition obligations
    -       -       309       309  
Net periodic benefit cost
    14,158       10,530       2,196       1,975  
 Amount allocated to construction
    (3,765 )     (2,797 )     (689 )     (646 )
 Amount deferred to regulatory balancing account(1)
    (3,989 )     -       -       -  
Net amount charged to expense
  $ 6,404     $ 7,733     $ 1,507     $ 1,329  
                                 
(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.
 
 
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In addition to the company-sponsored defined benefit plans referred to above, in accordance with our collective bargaining agreement, we contribute to a multiemployer pension plan for our bargaining unit employees 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 is managed by a board of trustees that includes equal representation from participating employers and labor unions. Contribution rates are established by collective bargaining agreements, and benefit levels are set by the board of trustees based on the advice of an independent actuary regarding the level of benefits that agreed-upon contributions are expected to support.  The Western States Plan has reported an accumulated funding deficit for the current plan year and remains in critical status.  A plan is considered to be in critical status if its funded status is 65 percent or less. Federal law requires pension plans in critical status to adopt a rehabilitation plan designed to restore the financial health of the plan. Rehabilitation plans may specify benefit reductions, contribution surcharges, or a combination of the two.  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 $0.3 million to the Western States Plan for both the nine months ended September 30, 2011 and 2010.  This amount includes the 10 percent contribution surcharge.  Contribution surcharges above the current 10 percent rate will be assessed to employer participants, but these higher surcharges will not go into effect for NW Natural until its next collective bargaining agreement, which is expected to be no earlier than June 1, 2014. Under the terms of our current collective bargaining agreement, which became effective in July 2009, we can withdraw from the Western States Plan at any time. However, if we withdraw and the plan is underfunded, we could be assessed a withdrawal liability.  In accordance with accounting rules for multiemployer plans, we have not currently recognized these potential withdrawal liabilities on the balance sheet.  Currently, we have no intent to withdraw from the plan, so we have not recorded a withdrawal liability.

Employer Pension Contributions
 
In the nine months ended September 30, 2011, we made cash contributions totaling $19.2 million to our qualified defined benefit pension plans.  We also expect to make additional contributions of up to $4 million to these qualified plans over the last three 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 nine months ended September 30, 2011 and 2010 varied from the combined federal and state statutory tax rates principally due to the following:

   
September 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
    1.5 %     1.2 %
Gains on company and trust-owned life insurance
    (0.9 ) %     (0.8 ) %
Other - net
    0.7 %     0.5 %
Effective income tax rate
    40.4 %     40.3 %

The increase in our effective tax rate for the nine months ended September 30, 2011 compared to the same period in 2010 was negligible. See Note 10 in our 2010 Form 10-K.


 
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11.
Property, Plant and Equipment

The following table sets forth the major classifications of our property, plant and equipment and accumulated depreciation as of September 30, 2011 and 2010 and December 31, 2010:

   
September 30,
   
December 31,
 
Thousands
 
2011
   
2010
   
2010
 
Utility plant in service
  $ 2,296,788     $ 2,222,222     $ 2,247,952  
Utility construction work in progress
    36,459       33,359       29,324  
Less: Accumulated depreciation
    740,378       700,193       710,214  
Utility plant-net
    1,592,869       1,555,388       1,567,062  
Non-utility plant in service
    290,075       66,299       290,038  
Non-utility construction work in progress
    9,176       206,823       9,088  
Less: Accumulated depreciation
    16,214       10,853       12,025  
Non-utility plant-net
  $ 283,037     $ 262,269     $ 287,101  
                         
Total property, plant and equipment
  $ 1,875,906     $ 1,817,657     $ 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 entered into an agreement with Encana Oil & Gas (USA) Inc. (Encana) to develop physical gas reserves that are expected to supply a portion of NW Natural’s utility customers’ requirements over the next 30 years.  The volume of gas produced and allocated to NW Natural under the agreement 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 gas purchase requirements of our utility customers.  Under the agreement, 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.

Upon reviewing the transaction, the OPUC determined that our Company’s costs under the agreement will be recovered on an ongoing basis through its annual Purchased Gas Adjustment (PGA) mechanism, including the regulatory deferral and incentive sharing process for the commodity cost of gas.  Annually, a forecast will be established for the amounts related to costs and volumes expected, and any variances between forecasted and actual will be subject to the PGA incentive sharing in Oregon, up to a maximum variance of $10 million of which 10 percent (or $1 million maximum) would be recognized in current income. 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.

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 September 30, 2011 is $20.4 million, with deferred taxes totaling $10.1 million.

Variable Interest Entity (VIE) Analysis. >We concluded that the arrangements with Encana qualify as a VIE, but 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.

 
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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 September 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.

Earlier in 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 and determine the commercial support for a revised pipeline proposal.  We expect to file a new FERC certificate application to reflect a revised scope based on regional needs.

During the second quarter of 2011, we re-evaluated 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 September 30, 2011 is $14.4 million.  We continue to review the 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 thereafter.  Based on our current 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 a maximum impairment charge of up to approximately $14.1 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.

 

 
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13.
Derivative Instruments
 
We enter into swap, option and combinations of option contracts 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 our derivative hedging strategy involves foreign currency exchange transactions related to purchases on natural gas from Canadian suppliers.
 
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 these 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 is set for the current gas contract year are subject to our PGA incentive sharing mechanism, which, provides for either an 80 or a 90 percent deferral of any gains and losses as regulatory assets or liabilities, with the remaining 10 or 20 percent recognized in current  income.  All of our commodity hedging for the 2011-12 gas year was completed prior to the start of the gas year, and these hedge prices were included in our PGA filing.  

The following table reflects the income statement presentation for the unrealized gains and losses from our derivative instruments for the nine months ended September 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 balance sheet accounts in accordance with regulatory accounting standards.

   
Three Months Ended
   
September 30, 2011
 
September 30, 2010
Thousands
 
Natural gas commodity(1)
   
Foreign currency (2)
   
Natural gas commodity(1)
   
Foreign currency (2)
Cost of sales
$
 (18,987)
 
$
 - 
 
$
 (35,744)
 
$
 - 
Other comprehensive income (loss)
 
 - 
   
 (1,221)
   
 - 
   
 449
Less:
                     
Amounts deferred to regulatory accounts on balance sheet
 
 18,987
   
 1,221
   
 35,744
   
 (449)
 
Total impact on earnings
$
 - 
 
$
 - 
 
$
 - 
 
$
 - 
                         
   
Nine Months Ended
   
September 30, 2011
 
September 30, 2010
Thousands
 
Natural gas commodity(1)
   
Foreign currency (2)
   
Natural gas commodity(1)
   
Foreign currency (2)
Cost of sales
$
 (49,106)
 
$
 - 
 
$
 (84,837)
 
$
 - 
Other comprehensive income (loss)
 
 - 
   
 (815)
   
 - 
   
 110
Less:
                     
Amounts deferred to regulatory accounts on balance sheet
 
 49,106
   
 815
   
 84,837
   
 (110)
 
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.

 
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PART I.  FINANCIAL INFORMATION

No collateral was posted with or by our counterparties as of September 30, 2011 or 2010.  We attempt to minimize the potential exposure to collateral calls by counterparties to manage our liquidity risk.  Counterparties generally allow a certain credit limit threshold before requiring us to post collateral against loss positions. Given our counterparty credit limits and diversification, we have not been subject to collateral calls in 2010 or 2011.  Our collateral call exposure is set forth under credit support agreements, which generally contain credit limits. We could also 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 $49.9 million at September 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
  $ -     $ -     $ -     $ 5,609     $ 37,171  
Without Adequate Assurance Calls
  $ -     $ -     $ -     $ 4,581     $ 31,143  

In the three and nine months ended September 30, 2011, we realized net losses of $6.6 million and $36.2 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 $12.6 million and $33.3 million, respectively, for the three and nine months ended September 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 September 30, 2011.  As of September 30, 2011 and 2010 and December 31, 2010, the fair value was $49.9 million, $84.7 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 nine months ended September 30, 2011 and 2010.

 
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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 a range of possible losses that is more likely than other cost estimates within that range, 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.
 

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 September 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.  For the sediments project and the other investigation and clean-up work, we have recorded an additional accrued liability of $36.6 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.
 
 
 
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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 (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) under the plan. The draft FS is scheduled for submittal in 2012. 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, other information is necessary to estimate additional liabilities to support an early restoration-based settlement of natural resource damage claims.  As of September 30, 2011, we have an accrued liability of $7.3 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 under the ODEQ’s Independent Cleanup Pathway.  As of September 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 September 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 September 30, 2011 and 2010 and December 31, 2010:

   
Current Liabilities
   
Non-Current Liabilities
 
   
Sept. 30,
   
Sept. 30,
   
Dec. 31,
   
Sept. 30,
   
Sept. 30,
   
Dec. 31,
 
Thousands
 
2011
   
2010
   
2010
   
2011
   
2010
   
2010
 
Gasco site
  $ 10,389     $ 7,738     $ 11,366     $ 38,051     $ 43,597     $ 38,921  
Siltronic site
    721       746       720       114       275       201  
Portland Harbor site
    2,174       2,712       2,304       5,122       5,594       5,784  
Central Service Center site
    5       5       5       530       510       510  
Front Street site
    -       72       1       765       1,039       1,097  
Other sites
    -       -       -       129       110       108  
Total
  $ 13,289     $ 11,273     $ 14,396     $ 44,711     $ 51,125     $ 46,621  


 
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Regulatory and Insurance Recovery for Environmental Costs.>  In May 2003, the 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 has been extended through January 2012.  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 are being deferred as of January 26, 2011 with cost recovery to be determined in a future proceeding.

On a cumulative basis, we have recognized a total of $107.7 million for environmental costs, including legal, investigation, monitoring and remediation costs, and $4.9 million paid and expensed prior to regulatory deferral order approval.  At September 30, 2011, we had a regulatory asset of $122.5 million, which includes $51.8 million of total paid expenditures to date, $58 million for additional environmental costs expected to be paid in the future and accrued interest of $18.1 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 could extend over several years, and may include settlements from time to time with one or more of the defendant insurance companies.
 
Our regulatory recovery of environmental cost deferrals may be initiated in the Oregon 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.  The following table summarizes the non-current regulatory assets relating to environmental sites at September 30, 2011 and 2010 and December 31, 2010:

   
Non-Current Regulatory Assets
 
   
September 30,
   
September 30,
   
December 31,
 
Thousands
 
2011
   
2010
   
2010
 
Gasco site
  $ 79,823     $ 72,531     $ 74,205  
Siltronic site
    3,535       3,120       3,174  
Portland Harbor site
    35,889       33,316       33,940  
Central Service Center site
    610       551       553  
Front Street site
    2,130       2,000       2,020  
Other sites
    467       413       420  
Total
  $ 122,454     $ 111,931     $ 114,312  


 
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PART I.  FINANCIAL INFORMATION

Legal Proceedings
 
We are subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings 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 as we would expect to receive insurance recovery or rate recovery.
 
Oregon Steel Mills site.> In 2004, NW Natural was served with a third-party complaint by the Port of Portland (the 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. 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 disclosures contained in this report refer to our consolidated activities for the three and nine months ended September 30, 2011 and 2010. A significant portion of our business results are seasonal in nature, and as such the results of operations for the three and nine month periods are not necessarily indicative of expected fiscal year results. Therefore, this discussion should be read in conjunction with our 2010 Annual Report on Form 10-K (2010 Form 10-K) as well as our Quarterly Reports on Form 10-Q for the first and second quarters of 2011. Unless otherwise indicated, references below to “Notes” are to the Notes to Consolidated Financial Statements in this report.
 
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 our 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 our 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 third quarter of 2011 as compared to the same period in 2010 include:
 
 
·  
Consolidated earnings decreased $0.9 million, from a net loss of $7.4 million or 28 cents per share in the third quarter of 2010 to a net loss of $8.3 million or 31 cents per share in the third quarter of 2011;
·  
Net loss from utility operations increased $0.4 million, from $9.1 million in 2010 to $9.5 million in 2011;
·  
Net income from gas storage operations decreased $0.6 million, from $1.8 million in 2010 to $1.2 million in 2011, primarily reflecting current market values for contract storage and optimization services;
·  
Net operating revenues (margin) increased $1.6 million or 3 percent over 2010, with utility margin down $0.2 million and gas storage margin up $1.8 million;
·  
Operating expenses increased $3.8 million or 8 percent over 2010, primarily due to increases attributed to Gill Ranch’s first-year expenses for operations, maintenance, depreciation and amortization;
·  
Income tax benefit increased $0.5 million in 2011 compared to 2010, primarily due to a higher pre-tax loss;
·  
Cash flow from operating activities on a year-to-date basis was $191.3 million, for an increase of $76.8 million or 67 percent over the same year-to-date period in 2010;
·  
Utility customers increased by approximately 5,400 over the last 12 months, for an annual growth rate of 0.8 percent compared to slightly above 1 percent a year ago.



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 September 30, 2011, as compared to 0.8 percent at June 30, 2011 and 1.2 percent at September 30, 2010.  Total delivered volumes to utility customers in the third quarter of 2011 decreased 3 percent, with unemployment rates remaining around 10 percent throughout our service territories in Oregon and southwest Washington and business conditions remaining sluggish as well.  Despite these challenges, we believe our utility is well positioned to continue adding customers due to low natural gas prices, an ability to increase market share in residential and commercial sectors, ongoing programs 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, gas reserves, 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, coupled with our focus on customer service and cost-effective energy efficiency programs, can help strengthen natural gas’ competitive advantage over other energy sources in key markets.  See discussion of Investments in Gas Reserves below under Strategic Opportunities.

We typically hedge approximately 75 percent of our anticipated year-round sales volumes based on normal weather.  For the 2011-12 gas year (November 1, 2011 – October 31, 2012), we are currently hedged at a level of approximately 75 percent of our forecasted sales volumes, including 51 percent financially hedged and 24 percent physically hedged with gas inventories in storage, local production from the Mist area, and expected production of gas reserves.  The gas reserves are related to a recent transaction whereby we agreed to purchase working interests in producing wells from Encana Oil & Gas (USA) Inc. (Encana). For further discussion of gas reserves, see Investments in Gas Reserves under Strategic Opportunities below.

Additionally, we are currently hedged at approximately 30 percent for the 2012-13 gas year and between 9 and 13 percent hedged for annual requirements over the following five gas years.  Our hedge levels are subject to change based on actual load volumes, which depend to a certain extent 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 reserves, these levels are estimates of production, which are subject to change based on possible unforeseen events that include the impact from 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, consequently affecting our ability to sign long-term customer contracts 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.  We are authorized by the Public Utility Commission of Oregon (OPUC) and the Washington Utilities and Transportation Commission (WUTC) to defer certain environmental costs, and to seek recovery of those amounts in future rates to customers.  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.  Recovery of environmental costs from regulated utility rates will depend on our ability to effectively manage these costs and demonstrate that 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 system, 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 relevant metrics such as: 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
 
 
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 and offers storage services to the California market at market-based rates.  Gill Ranch is 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 estimated 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 to a lesser extent than in California and other markets around the country because of limited availability of storage capacity in the Northwest.  In 2012, we expect to continue planning for possible expansion at our Mist gas storage facilities in anticipation of increased demand for electric generation in the Pacific Northwest.  We do not have an established timeline for the next expansion at Mist, but we believe expansion could be as early as 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.


 
Investments 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 to develop physical gas supplies to supply a portion of our utility customers’ requirements over a period of about 30 years.  During the first 10 years of the agreement, we forecast the volumes of gas received under the Encana agreement to provide approximately 8 to 10 percent of the average annual requirements of our utility customers.  Under the agreement, 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.  These 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.

Upon reviewing the transaction, the OPUC determined that our Company’s costs under the agreement will be recovered on an ongoing basis through our annual PGA mechanism, including the regulatory deferral and incentive sharing 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 any variances between forecasted and actual will be subject to our PGA incentive sharing in Oregon, up to a maximum variance of $10 million of which 10 percent (or $1 million maximum) would be recognized in current income. 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 September 30, 2011 compared to September 30, 2010:

For the three months ended September 30, 2011, we reported a net loss of $8.3 million, or 31 cents per share, compared to a net loss of $7.4 million, or 28 cents per share, for the same period last year.
 
The primary factors contributing to the increased third quarter consolidated net loss were:
 
·  
a $1.5 million increase in operations and maintenance expense primarily related to first-year expenses related to storage operations at Gill Ranch; and
·  
a $1.4 million increase in depreciation and amortization also primarily related to first-year storage operations at Gill Ranch.

Partially offsetting the above factors were:

·  
a $1.6 million increase in net operating revenues primarily related to storage operations at Gill Ranch.

Nine months ended September 30, 2011 compared to September 30, 2010:
 
Net income was $34.7 million, or $ 1.30 per share, for the nine months ended September 30, 2011, compared to $43.1 million, or $ 1.62 per share, for the same period last year.
 
The primary factors contributing to the $8.4 million decrease in net income were:

·  
a $12.1 million reduction in utility net operating revenues (margin), representing a $7.4 million write-off taken in 2011 plus $5.0 million of revenues accrued in the first nine months of 2010, related to the repealed Oregon legislative rule on utility income taxes paid.  See “Results of Operations - Business Segments - Utility Operations - Regulatory Adjustment for Income Taxes Paid,” below for further explanation;
·  
a $3.9 million increase in operations and maintenance expense, primarily due to a $4.4 million increase at Gill Ranch reflecting first-year operating expenses;
·  
a $4.9 million increase in general taxes, primarily due to a $5.2 million refund of utility property taxes in 2010, partially offset by a $1.1 million decrease in other taxes, and a $0.8 million increase in property and other taxes at Gill Ranch, which reflect first-year operating expenses; and
·  
a $4.4 million increase in depreciation and amortization expense, due to a $0.8 million increase at the utility and a $3.6 million increase at Gill Ranch.

Partially offsetting the above factors were:

·  
an $8.1 million increase in utility margin attributable to an increase in residential and commercial customer use, reflecting gains from colder weather and customer growth; and
·  
a $5.6 million decrease in income tax expense related to lower taxable income.

Dividends paid on our common stock were 43.5 cents per share in the third quarter of 2011, compared to 41.5 cents per share in the third quarter of 2010.  The Board of Directors declared a quarterly common stock dividend of 44.5 cents per share, payable on November 15, 2011, to shareholders of record on October 31, 2011, thereby increasing the indicated annual dividend rate by more than 2 percent from $1.74 to $1.78 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;
·  
revenue recognition;
·  
derivative instruments and hedging activities;
·  
pensions and postretirement benefits;
·  
income taxes; and
·  
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.  From 2007 through 2010, utility revenues included the recognition of a regulatory adjustment for income taxes paid pursuant to a legislative rule (commonly referred to as SB 408), which applied to 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 based on the annual amount to be recognized. On May 24, 2011 the Oregon Governor signed Senate Bill 967 (SB 967), which repealed SB 408. The new law requires utilities in Oregon, to reverse amounts accrued for the 2010 and 2011 tax years, which resulted in us recording a one-time pre-tax charge to earnings in the second quarter of 2011 in the amount of $7.4 million ($4.4 million after-tax or 17 cents per share).  See “Results of Operations—Business Segments - Utility Operations—Regulatory Adjustment for Income Taxes Paid,” below for a further discussion.