form10_q.htm

 

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549

Form 10-Q

[X]           QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2009

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).     Yes [   ]           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.
   
Large accelerated filer [ X ]
                 Accelerated filer [    ]
  Non-accelerated filer [     ]
 Smaller reporting company [    ]

  Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes [   ] No  [ X ]

At July 31, 2009, 26,513,188 shares of the registrant’s Common Stock (the only class of Common Stock) were outstanding.

 
 

 
 


NORTHWEST NATURAL GAS COMPANY

For the Quarterly Period Ended June 30, 2009





     
 
PART I.  FINANCIAL INFORMATION
 
   
Page Number
 
1
     
Item 1.
 
     
 
3
     
 
4
     
 
6
     
 
7
     
Item 2.
22
     
Item 3.
43
     
Item 4.
44
     
 
PART II.  OTHER INFORMATION
 
     
Item 1.
45
     
Item 1A.
45
     
Item 2.
45
     
Item 4.
46
     
Item 5.
46
     
Item 6.
46
     
 
47


 
 


Forward-Looking Statements
 
Statements and information included in this report that are not purely historical are forward-looking statements within the “safe harbor” provisions and meaning of Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act). Forward-looking statements include any statement other than a statement of purely historical fact, but are not limited to, statements concerning plans, objectives, goals, business and financial strategies, future events or performance or operational efficiencies, trends, cyclicality and the seasonality of our business, growth, capitalization, company ratings, development of projects, future cost of gas or our ability to manage such costs, customer rates, gains or losses from our share of gas costs that are less than or more than the gas costs embedded in customer rates, acquisition of new gas supplies, workforce levels, cost reduction efforts, estimated expenditures, budgets, capital and construction costs, and future cash flows, costs of compliance, impact of accounting policies and standards, potential efficiencies, impacts of new laws and regulations, projected obligations and liabilities under retirement plans, adequacy of and shift in mix of gas supplies, and adequacy of accruals and regulatory deferrals.  Such statements are expressed in good faith and we believe have a reasonable basis; however, each forward-looking statement involves uncertainties and is qualified in its entirety by reference to the following important factors, among others, that could cause our actual results to differ materially from those projected, including:
 
 
·
prevailing state and federal governmental policies and regulatory actions with respect to allowed rates of return, industry and rate structure, timely and adequate regulatory recovery of deferred costs, including, but not limited to, purchased gas cost and investment recovery, acquisitions and dispositions of assets and facilities, operation and construction of plant facilities, present or prospective wholesale and retail competition, changes in laws and regulations including but not limited to tax laws and policies, changes in and compliance with environmental and safety laws, regulations, policies and orders, and laws, regulations and orders with respect to the maintenance of pipeline integrity, including regulatory allowance or disallowance of costs based on regulatory prudency reviews;
 
 
 
·
economic factors that could cause a severe downturn in the economy, in particular the economies of Oregon and Washington, thus affecting demand for natural gas;
 
 
 
·
unanticipated customer growth or decline and changes in market demand caused by changes in demographic or customer consumption patterns;
 
 
 
·
the creditworthiness of customers, suppliers and financial derivative counterparties;
 
 
 
·
market conditions and pricing of natural gas relative to other energy sources;
 
 
 
·
sufficiency of our liquidity position and unanticipated changes that may affect our liquidity or access to capital markets, including volatility in the credit markets and financial services sector;
 
 
 
·
capital market conditions, including their effect on financing costs, the fair value of pension assets and pension and other postretirement benefit costs;
 
 
 
·
application of the Oregon Public Utility Commission rules interpreting Oregon legislation intended to ensure that utilities do not collect more income taxes in rates than they actually pay to government entities;
 
 
 
·
weather conditions, natural phenomena including earthquakes or other geohazard events, and other pandemic events;
 
 
 
·
competition for retail and wholesale customers and our ability to remain price competitive;
 
 
 
·
our ability to access sufficient gas supplies and our dependence on a single pipeline transportation company for natural gas transmission;
 
 
 
·
property damage associated with a pipeline safety incident, as well as risks resulting from uninsured damage to our property, intentional or otherwise;
 
 

 
1


 
·
financial and operational risks, estimates and projections relating to business development and investment activities, including the Gill Ranch underground gas storage facility and Palomar pipeline;
 
 
·
unanticipated changes in interest rates, foreign currency exchange rates or in rates of inflation;
 
 
 
·
changes in estimates of potential liabilities relating to environmental contingencies or in timely and adequate regulatory or insurance recovery for such liabilities;
 
 
 
·
unanticipated changes in future liabilities and legislation relating to employee benefit plans, including changes in key assumptions;
 
 
 
·
our ability to transfer knowledge of our aging workforce and maintain a satisfactory relationship with the union that represents a majority of our workers;
 
 
 
·
potential inability to obtain permits, rights of way, easements, leases or other interests or other necessary authority to construct pipelines, develop storage or complete other system expansions and the timing of such projects;
 
 
 
·
federal, state or other regulatory actions related to climate change; and
 
 
 
·
legal and administrative proceedings and settlements.

These forward-looking statements involve risks and uncertainties.  We may make other forward-looking statements from time to time, including statements in press releases and public conference calls and webcasts.  All forward-looking statements made by us are based on information available to us at the time the statements are made and speak only as of the date on which such statement is made.  We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for us to predict all such factors, nor can we assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. Some of these risks and uncertainties are discussed in our 2008 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,” respectively.
 


 
2



NORTHWEST NATURAL GAS COMPANY
PART I.  FINANCIAL INFORMATION
Consolidated Statements of Income
(Unaudited)
 
 
 
   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
Thousands, except per share amounts
 
2009
   
2008
   
2009
   
2008
 
Operating revenues:
                       
Gross operating revenues
  $ 149,060     $ 191,254     $ 586,415     $ 578,948  
Less:   Cost of sales
    79,388       124,010       363,562       369,930  
 Revenue taxes
    3,753       4,672       14,295       14,023  
Net operating revenues
    65,919       62,572       208,558       194,995  
Operating expenses:
                               
Operations and maintenance
    30,171       25,840       64,126       54,298  
General taxes
    6,572       6,722       15,063       14,856  
Depreciation and amortization
    15,365       17,957       30,887       35,662  
Total operating expenses
    52,108       50,519       110,076       104,816  
Income from operations
    13,811       12,053       98,482       90,179  
Other income and expense - net
    732       1,940       1,622       2,113  
Interest charges - net of amounts capitalized
    10,006       8,933       19,376       18,363  
Income before income taxes
    4,537       5,060       80,728       73,929  
Income tax expense
    1,451       1,763       30,279       27,464  
Net income
  $ 3,086     $ 3,297     $ 50,449     $ 46,465  
Average common shares outstanding:
                               
Basic
    26,506       26,421       26,504       26,415  
Diluted
    26,607       26,571       26,603       26,564  
Earnings per share of common stock:
                               
Basic
  $ 0.12     $ 0.12     $ 1.90     $ 1.76  
Diluted
  $ 0.12     $ 0.12     $ 1.90     $ 1.75  
 
 
See Notes to Consolidated Financial Statements.
 

 
3


 
NORTHWEST NATURAL GAS COMPANY
PART I.  FINANCIAL INFORMATION
Consolidated Balance Sheets
(Unaudited)
 
 
 
                   
   
June 30,
   
June 30,
   
Dec. 31,
 
Thousands
 
2009
   
2008
   
2008
 
Assets:
                 
Plant and property:
                 
Utility plant
  $ 2,178,629     $ 2,091,092     $ 2,142,988  
Less accumulated depreciation
    670,128       637,680       659,123  
 Utility plant - net
    1,508,501       1,453,412       1,483,865  
Non-utility property
    84,696       72,242       74,506  
Less accumulated depreciation
    9,849       8,537       9,314  
 Non-utility property - net
    74,847       63,705       65,192  
 Total plant and property
    1,583,348       1,517,117       1,549,057  
                         
Current assets:
                       
Cash and cash equivalents
    31,107       5,242       6,916  
Accounts receivable
    26,779       43,718       81,288  
Accrued unbilled revenue
    18,122       19,685       102,688  
Allowance for uncollectible accounts
    (3,520 )     (3,013 )     (2,927 )
Regulatory assets
    89,179       5,748       147,319  
Fair value of non-trading derivatives
    5,293       54,867       4,592  
Inventories:
                       
 Gas
    69,183       32,910       86,134  
 Materials and supplies
    9,681       9,959       9,933  
Income taxes receivable
    -       -       20,811  
Prepayments and other current assets
    26,588       11,516       24,216  
 Total current assets
    272,412       180,632       480,970  
                         
Investments, deferred charges and other assets:
                       
Regulatory assets
    270,044       173,321       288,470  
Fair value of non-trading derivatives
    289       9,218       146  
Other investments
    62,315       64,276       54,132  
Other
    16,103       11,417       5,377  
 Total investments, deferred charges and other assets
    348,751       258,232       348,125  
 Total assets
  $ 2,204,511     $ 1,955,981     $ 2,378,152  
 
 
See Notes to Consolidated Financial Statements.
 

 
4


 
NORTHWEST NATURAL GAS COMPANY
PART I.  FINANCIAL INFORMATION
Consolidated Balance Sheets
(Unaudited)
 
 
                   
   
June 30,
   
June 30,
   
Dec. 31,
 
Thousands
 
2009
   
2008
   
2008
 
Capitalization and liabilities:
                 
Capitalization:
                 
Common stock
  $ 336,001     $ 333,619     $ 336,754  
Earnings invested in the business
    325,506       293,313       296,005  
Accumulated other comprehensive income (loss)
    (4,260 )     (2,483 )     (4,386 )
Total common stock equity
    657,247       624,449       628,373  
Long-term debt
    587,000       512,000       512,000  
Total capitalization
    1,244,247       1,136,449       1,140,373  
                         
Current liabilities:
                       
Notes payable
    90,610       67,700       248,000  
Long-term debt due within one year
    -       5,000       -  
Accounts payable
    50,055       75,786       94,422  
Taxes accrued
    10,807       8,727       12,455  
Interest accrued
    3,876       2,837       2,785  
Regulatory liabilities
    30,789       84,370       20,456  
Fair value of non-trading derivatives
    70,052       2,792       136,735  
Other current and accrued liabilities
    33,343       32,251       36,467  
Total current liabilities
    289,532       279,463       551,320  
                         
Deferred credits and other liabilities:
                       
Deferred income taxes and investment tax credits
    273,384       221,266       257,831  
Regulatory liabilities
    238,264       227,076       228,157  
Pension and other postretirement benefit liabilities
    116,844       43,513       138,229  
Fair value of non-trading derivatives
    8,844       2,732       21,646  
Other
    33,396       45,482       40,596  
Total deferred credits and other liabilities
    670,732       540,069       686,459  
Commitments and contingencies (see Note 11)
    -       -       -  
Total capitalization and liabilities
  $ 2,204,511     $ 1,955,981     $ 2,378,152  
 
See Notes to Consolidated Financial Statements.
 

 
5


 
NORTHWEST NATURAL GAS COMPANY
PART I.  FINANCIAL INFORMATION
Consolidated Statements of Cash Flows
(Unaudited)
 

 
   
Six Months Ended
 
   
June 30,
 
Thousands
 
2009
   
2008
 
           
Net income
  $ 50,449     $ 46,465  
Adjustments to reconcile net income to cash provided by operations:
               
Depreciation and amortization
    30,887       35,662  
Deferred income taxes and investment tax credits
    15,405       14,028  
Undistributed gains from equity investments
    (734 )     (346 )
Deferred gas savings - net
    15,616       (26,873 )
Gain on sale of non-utility investments
    -       (1,737 )
Non-cash expenses related to qualified defined benefit pension plans
    4,848       1,530  
Contributions to qualified defined benefit pension plans
    (25,000 )     -  
Deferred environmental costs
    (5,227 )     (4,131 )
Income from life insurance investments
    (2,002 )     (978 )
Settlement of interest rate hedge
    (10,096 )     -  
Deferred regulatory and other
    (14,123 )     (6,466 )
Changes in working capital:
               
Accounts receivable and accrued unbilled revenue - net
    141,173       84,224  
Inventories of gas, materials and supplies
    17,203       37,075  
Income taxes receivable
    20,811       -  
Prepayments and other current assets
    8,428       7,083  
Accounts payable
    (44,177 )     (45,684 )
Accrued interest and taxes
    (557 )     (4,400 )
Other current and accrued liabilities
    (3,091 )     2,634  
Cash provided by operating activities
    199,813       138,086  
Investing activities:
               
Investment in utility plant
    (44,098 )     (41,338 )
Investment in non-utility property
    (10,330 )     (5,110 )
Proceeds from sale of non-utility investments
    -       6,845  
Proceeds from life insurance
    761       208  
Other
    (4,977 )     (7,286 )
Cash used in investing activities
    (58,644 )     (46,681 )
Financing activities:
               
Common stock issued (purchased) - net
    (720 )     2,589  
Long-term debt issued
    75,000       -  
Change in short-term debt
    (170,241 )     (75,400 )
Cash dividend payments on common stock
    (20,937 )     (19,808 )
Other
    (80 )     349  
Cash used in financing activities
    (116,978 )     (92,270 )
Increase (decrease) in cash and cash equivalents
    24,191       (865 )
Cash and cash equivalents - beginning of period
    6,916       6,107  
Cash and cash equivalents - end of period
  $ 31,107     $ 5,242  
                 
Supplemental disclosure of cash flow information:
               
Interest paid
  $ 17,828     $ 18,424  
Income taxes paid
  $ 1,500     $ 14,800  
 
See Notes to Consolidated Financial Statements.
 

 
6


 
NORTHWEST NATURAL GAS COMPANY
PART I.  FINANCIAL INFORMATION
Notes to Consolidated Financial Statements
(Unaudited)
 
  1.
Basis of Financial Statements and Accounting Policies
 
The consolidated financial statements include the accounts of Northwest Natural Gas Company (NW Natural), which consist of our regulated gas distribution business, our regulated gas storage businesses, which include our wholly-owned subsidiary Gill Ranch Storage, LLC (Gill Ranch), and other investments and business activities, which include our wholly-owned subsidiary NNG Financial Corporation (Financial Corporation) and an equity investment in a proposed natural gas transmission pipeline (Palomar) (see Note 2).
 
In this report, the term “utility” is used to describe the gas distribution business and the term “non-utility” is used to describe the gas storage businesses and other non-utility investments and business activities.  Intercompany accounts and transactions have been eliminated, except for transactions required by regulatory accounting not to be eliminated under Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.”
 
The information presented in the interim consolidated financial statements is unaudited, but includes all material adjustments, including normal recurring accruals, that management considers necessary for a fair statement of the results for each period reported.  These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes included in our 2008 Annual Report on Form 10-K (2008 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.
 
Investments in corporate joint ventures and partnerships in which our ownership interest is 50 percent or less and over which we do not exercise control are accounted for by the equity method or the cost method.
 
Our accounting policies are described in Note 1 of the 2008 Form 10-K.  There were no significant changes to those accounting policies during the three and six months ended June 30, 2009.  See below for a further discussion of newly adopted standards and recent accounting pronouncements.
 
Newly Adopted Standards
 
Business Combinations. Effective January 1, 2009, we adopted SFAS No. 141R, “Business Combinations.” This statement amends the principles and requirements for how an acquiror accounts for and discloses its business combinations.  The adoption of SFAS No. 141R did not have a material effect on our financial condition, results of operations or cash flows.
 
Noncontrolling Interests.  Effective January 1, 2009, we adopted SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements.”  This statement amends the reporting requirements of Accounting Research Bulletin No. 51 for noncontrolling interests in subsidiaries to improve the relevance, comparability and transparency of the financial information disclosed. The adoption of SFAS No. 160 did not have a material effect on our financial condition, results of operations or cash flows.
 
Derivative Instruments and Hedging Activities.  Effective January 1, 2009, we adopted SFAS No. 161, “Disclosures About Derivative Instruments and Hedging Activities--an Amendment of FASB Statement No. 133,” which requires enhanced disclosures of derivative instruments and hedging activities.  SFAS No. 161 expands disclosures by adding qualitative disclosures about our hedging objectives and strategies, fair value gains and losses, and credit-risk-related contingent features in derivative agreements.  The disclosures are intended to provide an enhanced understanding of:
 
·  
how and why we use derivative instruments;
·  
how derivative instruments and related hedge items are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and its related interpretations; and
·  
how derivative instruments and related hedged items affect our financial condition, results of operations and cash flows.
 
The adoption and implementation of this statement did not have, and is not expected to have a material effect on our financial statement disclosures.  The required disclosures are included in Note 10, below.
 
 
7

 
Determining Whether Share-Based Payment Transactions are Participating Securities.  Effective January 1, 2009, we adopted Financial Accounting Standards Board (FASB) Staff Position (FSP) No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities.”  This statement requires nonforfeitable rights to dividends or dividend equivalents on unvested share-awards to be included in the computation of earnings per share under the two-class method.  The adoption of FSP No. EITF 03-6-1 did not have, and is not expected to have, a material effect on our financial condition, results of operations or cash flows.
 
Interim Disclosures about Financial Instruments.  Effective for periods ending after June 15, 2009, we adopted FSP SFAS No. 107-1 and Accounting Principles Board (APB) Opinion No. 28-1, “Interim Disclosures about Fair Value of Financial Instruments.”  This statement requires disclosures about the fair value of financial instruments to be made in interim reporting periods where summarized financial information is issued.  The adoption of this statement did not have a material effect on our disclosures.  See Note 5 and Note 10, below.
 
Fair Value Considerations.  Effective for periods ending after June 15, 2009, we adopted FSP SFAS No. 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly.”  This pronouncement provides an outline and required disclosures, if necessary, to determine if the market for measuring our financial instruments has significantly decreased in volume and level of activity.  The adoption of this statement did not have a material effect on our financial statement disclosures.  
 
Subsequent Events. Effective June 15, 2009, we adopted SFAS No. 165, “Subsequent Events.”  This statement establishes principles and disclosure requirements for events or transactions that occur after the balance sheet date but before the financial statements are issued. As of August 6, 2009, we have evaluated events subsequent to the balance sheet date. For subsequent event footnote, see Note 12.
 
Recent Accounting Pronouncements
 
Pensions. In December 2008, the FASB issued SFAS No. 132R-1, “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” which requires enhanced disclosures of plan assets in an employer’s defined benefit pension or other postretirement benefit plans.  SFAS No. 132R-1 is effective for reporting periods ending after December 15, 2009.  The disclosures are intended to provide an enhanced understanding of:
 
·  
how investment allocation decisions are made;
·  
the major categories of plan assets;
·  
the inputs and valuation techniques used to measure the fair value of plan assets;
·  
the effect of fair value measurements using significant unobservable inputs (Level 3 input from SFAS No. 157, “Fair Value Measurements”) on changes in plan assets for the period; and
·  
significant concentration or risk within plan assets.
 
The adoption of SFAS No. 132R-1 is not expected to have a material effect on our financial statement disclosures.
 
Variable Interest Entity.  In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R).” This pronouncement amends FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities,” and requires an analysis to determine whether our variable interest provides us with a controlling financial interest in the variable interest entity. It defines the primary beneficiary of the variable interest entity as the entity having:
 
·  
power to control the activities that most significantly impact the performance; and
·  
the obligation to absorb losses or right to receive benefits from the entity that could potentially be significant to the variable interest entity.
 
SFAS No. 167 is effective for the first annual reporting period that begins after November 15, 2009.  We are evaluating the impact the adoption of SFAS No. 167 will have on our investments in variable interest entities.  If consolidated, our variable interest entities could have a material impact on our balance sheet, but it is not expected to materially impact our results of operations or cash flows.
 
 
8

 
  2.
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 either 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 Gill Ranch in California and a portion of the Mist underground storage facility in Oregon, and our “other” segment includes an equity investment in Palomar and Financial Corporation.
 
The following tables present information about the reportable segments for the three and six months ended June 30, 2009 and 2008.  Inter-segment transactions are insignificant.
 
   
Three Months Ended June 30,
 
Thousands
 
Utility
   
Gas Storage
   
Other
   
Total
 
2009
                       
Net operating revenues
  $ 60,066     $ 5,825     $ 28     $ 65,919  
Depreciation and amortization
    15,029       336       -       15,365  
Income from operations
    8,955       4,852       4       13,811  
Net income (loss)
    439       2,734       (87 )     3,086  
2008
                               
Net operating revenues
  $ 57,183     $ 5,339     $ 50     $ 62,572  
Depreciation and amortization
    17,633       324       -       17,957  
Income (loss) from operations
    7,451       4,907       (305 )     12,053  
Net income (loss)
    (743 )     2,488       1,552       3,297  
                                 
   
Six Months Ended June 30,
 
Thousands
 
Utility
   
Gas Storage
   
Other
   
Total
 
2009
                               
Net operating revenues
  $ 198,160     $ 10,325     $ 73     $ 208,558  
Depreciation and amortization
    30,212       675       -       30,887  
Income from operations
    89,849       8,597       36       98,482  
Net income (loss)
    45,743       4,766       (60 )     50,449  
Total assets at June 30, 2009
    2,092,788       96,711       15,012       2,204,511  
2008
                               
Net operating revenues
  $ 184,562     $ 10,336     $ 97     $ 194,995  
Depreciation and amortization
    35,012       650       -       35,662  
Income from operations
    81,328       8,750       101       90,179  
Net income
    39,799       4,841       1,825       46,465  
Total assets at June 30, 2008
    1,877,199       67,198       11,584       1,955,981  
Total assets at Dec. 31, 2008
    2,289,601       72,073       16,478       2,378,152  
 
 
 
9


Included in total assets at June 30, 2009 and 2008, our major non-utility investments were as follows:
 
·  
Mist gas storage (excluding amounts allocated to our utility) was $57.0 million and $53.6 million, respectively;
·  
Gill Ranch storage was $23.9 million and $7.8 million, respectively;
·  
Palomar was $10.6 million and $9.3 million, respectively; and
·  
Financial Corporation was $1.0 million for both periods.
 
In April 2008, we sold our investment in a Boeing 737-300 aircraft for approximately $6.2 million cash, plus accrued rents.  As a result of the sale, we recognized an after-tax gain of $1.1 million in the second quarter of 2008, which was recorded in our other segment.
 
In March 2009, Gill Ranch entered into a cash collateralized credit facility for up to $40 million that expires on September 30, 2009.  As of June 30, 2009, Gill Ranch had $10.8 million of borrowings outstanding included under notes payable on the balance sheet, with a corresponding cash collateral included in prepayments and other current assets on the balance sheet. The effective interest rate on Gill Ranch’s credit facility is 0.8 percent.
 
Palomar has precedent agreements whereby a significant majority of the pipeline capacity is committed to one shipper.  In April 2009, Palomar and that majority shipper replaced the prior precedent agreement with a new agreement and Palomar received cash proceeds of $15.8 million which had supported the shipper's obligations under the prior agreement. The new agreement is for the same amount of capacity as the prior agreement. Our maximum loss exposure related to Palomar as of June 30, 2009 is limited to our net investment balance of $10.6 million.  Our loss exposure would be reduced by any credit support recovered from third parties should they default on current agreements.
 
  3.
Capital Stock
 
As of June 30, 2009, our common shares authorized were 100,000,000 and our outstanding shares were 26,513,188.
 
We have a common share repurchase program under which we may purchase shares on the open market or through privately negotiated transactions.  Since inception of the repurchase program in 2000, the Board has authorized repurchases through May 31, 2010 up to an aggregate 2.8 million shares or $100 million. No shares were repurchased under this program during the six months ended June 30, 2009.  To date, a total of 2.1 million shares have been repurchased at a total cost of $83.3 million.
 
  4.
Stock-Based Compensation
 
Our stock-based compensation plans consist of the Long-Term Incentive Plan (LTIP), the Restated Stock Option Plan (Restated SOP) and the Employee Stock Purchase Plan (ESPP).  These plans are designed to promote stock ownership by employees and officers.  For additional information on our stock-based compensation plans, see Part II, Item 8., Note 4, in the 2008 Form 10-K and current updates provided below.
 
Long-Term Incentive Plan.  On February 25, 2009, 39,000 performance-based shares were granted under the LTIP based on target-level awards, which include a market condition and a weighted-average grant date fair value of $9.59 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
 
 $41.15
 Performance term (in years)
 
3.0
 Quarterly dividends paid per share
 
 $0.395
 Expected dividend yield
 
3.8%
 Dividend discount factor
 
 0.8927
 

 
10


In February 2009, the Board approved a payout of performance-based stock awards for the 2006-08 award period.  Shares of common stock were purchased on the open market to satisfy the approved awards.
 
Restated Stock Option Plan.  On February 25, 2009, options to purchase 111,750 shares were granted under the Restated SOP, with an exercise price equal to the closing market price of $41.15 per share on the date of grant, vesting over a four-year period following the date of grant and with a term of 10 years and 7 days. The weighted-average grant date fair value was $5.46 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)
 
4.7
 Expected market price volatility factor
 
22.5%
 Expected dividend yield
 
3.8%
 Forfeiture rate
 
3.7%
 
As of June 30, 2009, there was $1.0 million of unrecognized compensation cost related to the unvested portion of outstanding stock option awards expected to be recognized over a period extending through 2012.  For the six months ended June 30, 2009 and 2008, the expense recognized based on the fair value of stock options was $0.3 million and $0.4 million, respectively.
 
  5.
Cost and Fair Value Basis of Long-Term Debt
 
In March 2009, we issued $75 million of 5.37 percent secured medium-term notes (MTNs) due February 1, 2020.   Proceeds from these MTNs were used to redeem short-term debt of the utility and for general corporate purposes, including funding utility capital expenditures and working capital needs.  On July 9, 2009, we issued another $50 million of secured MTNs with an interest rate of 3.95 percent and a due date of July 15, 2014.  Proceeds from these MTNs will be used to fund utility capital expenditures as well as to redeem short-term debt.
 

 
11


At June 30, 2009 and 2008 and December 31, 2008, we had outstanding long-term debt as follows:
   
June 30,
   
June 30,
   
Dec. 31,
 
Thousands
 
2009
   
2008
   
2008
 
Medium-Term Notes
                 
First Mortgage Bonds:
                 
6.50 % Series B due 2008(1)
  $ -     $ 5,000     $ -  
4.11 % Series B due 2010
    10,000       10,000       10,000  
7.45 % Series B due 2010
    25,000       25,000       25,000  
6.665% Series B due 2011
    10,000       10,000       10,000  
7.13 % Series B due 2012
    40,000       40,000       40,000  
8.26 % Series B due 2014
    10,000       10,000       10,000  
4.70 % Series B due 2015
    40,000       40,000       40,000  
5.15 % Series B due 2016
    25,000       25,000       25,000  
7.00 % Series B due 2017
    40,000       40,000       40,000  
6.60 % Series B due 2018
    22,000       22,000       22,000  
8.31 % Series B due 2019
    10,000       10,000       10,000  
7.63 % Series B due 2019
    20,000       20,000       20,000  
5.37 % Series B due 2020(2)
    75,000       -       -  
9.05 % Series A due 2021
    10,000       10,000       10,000  
5.62 % Series B due 2023
    40,000       40,000       40,000  
7.72 % Series B due 2025
    20,000       20,000       20,000  
6.52 % Series B due 2025
    10,000       10,000       10,000  
7.05 % Series B due 2026
    20,000       20,000       20,000  
7.00 % Series B due 2027
    20,000       20,000       20,000  
6.65 % Series B due 2027
    20,000       20,000       20,000  
6.65 % Series B due 2028
    10,000       10,000       10,000  
7.74 % Series B due 2030
    20,000       20,000       20,000  
7.85 % Series B due 2030
    10,000       10,000       10,000  
5.82 % Series B due 2032
    30,000       30,000       30,000  
5.66 % Series B due 2033
    40,000       40,000       40,000  
5.25 % Series B due 2035
    10,000       10,000       10,000  
      587,000       517,000       512,000  
Less long-term debt due within one year
    -       5,000       -  
Total long-term debt
  $ 587,000     $ 512,000     $ 512,000  
 
(1)             Redeemed at maturity in July 2008.
(2)             Issued in March 2009.
 
The following table provides an estimate of the fair value of our long-term debt as of June 30, 2009 and December 31, 2008, using market prices in effect on the valuation dates. The fair value of our long-term debt issues was estimated using marketable debt securities with similar credit ratings, terms and remaining maturities.

 
   
June 30, 2009
   
Dec. 31, 2008
 
   
Carrying
   
Estimated
   
Carrying
   
Estimated
 
Thousands
 
Amount
   
Fair Value (1)
   
Amount
   
Fair Value (1)
 
Long-term debt including amounts due
                       
within one year
  $ 587,000     $ 612,931     $ 512,000     $ 505,828  
 
(1)             This estimate is calculated net of commission fees.

 
12


  6.           Earnings Per Share
 
Basic earnings per share are computed using the weighted average number of common shares outstanding during each period presented.  The diluted earnings per share calculation includes common shares outstanding and the potential effects of the assumed exercise of stock options outstanding and estimated stock awards from our other stock-based compensation plans.  Diluted earnings per share are calculated as follows:
 
   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
Thousands, except per share amounts
 
2009
   
2008
   
2009
   
2008
 
Net income
  $ 3,086     $ 3,297     $ 50,449     $ 46,465  
Average common shares outstanding - basic
    26,506       26,421       26,504       26,415  
Additional shares for stock-based compensation plans
    101       150       99       149  
Average common shares outstanding - diluted
    26,607       26,571       26,603       26,564  
Earnings per share of common stock - basic
  $ 0.12     $ 0.12     $ 1.90     $ 1.76  
Earnings per share of common stock - diluted
  $ 0.12     $ 0.12     $ 1.90     $ 1.75  
 
For the three and six months ended June 30, 2009, a total of 6,228 and 5,143 common shares, respectively, were excluded from the calculation of diluted earnings per share because the effect of these additional shares would have been anti-dilutive.  For the three and six months ended June 30, 2008, no common share equivalents were excluded from the calculation of diluted earnings per share because all common share equivalents were dilutive.

 
13

 
  7.
Pension and Other Postretirement Benefits
 
The following tables provide the components of net periodic benefit cost for our company-sponsored qualified and non-qualified defined benefit pension plans and other postretirement benefit plans:
 
   
Three Months Ended June 30,
 
               
Other Postretirement
 
   
Pension Benefits
   
Benefits
 
Thousands
 
2009
   
2008
   
2009
   
2008
 
Service cost
  $ 1,664     $ 1,653     $ 148     $ 132  
Interest cost
    4,492       4,303       407       349  
Expected return on plan assets
    (3,994 )     (4,777 )     -       -  
Amortization of loss
    1,658       96       4       -  
Amortization of prior service cost
    305       313       49       50  
Amortization of transition obligation
    -       -       103       103  
     Net periodic benefit cost
    4,125       1,588       711       634  
Amount allocated to construction
    (1,178 )     (409 )     (232 )     (224 )
    Net amount charged to expense
  $ 2,947     $ 1,179     $ 479     $ 410  
                                 
   
Six Months Ended June 30,
 
                   
Other Postretirement
 
   
Pension Benefits
   
Benefits
 
Thousands
 
2009
   
2008
   
2009
   
2008
 
Service cost
  $ 3,327     $ 3,308     $ 295     $ 265  
Interest cost
    8,984       8,604       813       698  
Expected return on plan assets
    (7,989 )     (9,554 )     -       -  
Amortization of loss
    3,317       192       8       -  
Amortization of prior service cost
    611       627       98       99  
Amortization of transition obligation
    -       -       206       206  
     Net periodic benefit cost
    8,250       3,177       1,420       1,268  
Amount allocated to construction
    (2,356 )     (788 )     (464 )     (431 )
    Net amount charged to expense
  $ 5,894     $ 2,389     $ 956     $ 837  
 
See Part II, Item 8., Note 7, in the 2008 Form 10-K for more information about our pension and other postretirement benefit plans.
 
In addition to the company-sponsored defined benefit plans referred to above, we contribute to a multiemployer pension plan for our bargaining unit employees in accordance with our collective bargaining agreement, known as the Western States Office and Professional Employees International Union Pension Fund (Western States Plan).  The 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 currently has an accumulated funding deficiency (i.e., a failure to satisfy the minimum funding requirements) for the current plan year and remains in “critical status.” 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. Our total contribution to the Western States Plan in 2008 amounted to $0.4 million.  We made contributions totaling $0.2 million to the Western States Plan for both the six months ended June 30, 2009 and 2008.   We expect the Western States Plan board of trustees to impose a 5 percent surcharge on participating employers, including NW Natural, beginning in 2009 with a 10 percent contribution surcharge for years thereafter.  We also expect the trustees to reduced benefit accrual rates and adjustable benefits for active employee participants.  These changes are expected as part of a rehabilitation plan to improve funding status of the plan. 

 
14


Surcharges above 10 percent may be assessed to employer participants in future years, 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 collective bargaining agreement, which became effective July 13, 2009, we can withdraw from the Western States Plan at any time.  If we withdraw and the plan is underfunded, we could be assessed a withdrawal liability.  We have no current intent to withdraw from the plan, so we have not recorded a withdrawal liability.
 
Employer Contributions
 
We make contributions periodically to our single-employer qualified defined benefit pension plans based on actuarial assumptions and estimates, tax regulations and funding requirements under federal law. In April 2009, we made an aggregate $25 million cash contribution for the 2008 plan year. In addition, we made cash contributions for our unfunded, non-qualified pension plans and other postretirement benefit plans in the form of ongoing benefit payments of $1.7 million and $1.4 million during the six months ended June 30, 2009 and 2008, respectively.   For more information see Part II, Item 8., Note 7, in the 2008 Form 10-K.
 
  8.
Comprehensive Income
 
Items excluded from net income and charged directly to common stock equity are included in accumulated other comprehensive income (loss), net of tax.  The amount of accumulated other comprehensive loss in common stock equity is $4.3 million, $2.5 million and $4.4 million at June 30, 2009 and 2008 and December 31, 2008, respectively, which is related to employee benefit plan liabilities and unrealized gains or losses from derivatives not included under regulatory assets and liabilities (see Note 10, below).  The following table provides a reconciliation of net income to total comprehensive income for the three and six months ended June 30, 2009 and 2008.
 
   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
Thousands
 
2009
   
2008
   
2009
   
2008
 
Net income
  $ 3,086     $ 3,297     $ 50,449     $ 46,465  
Amortization of employee benefit plan liability, net of tax
    63       55       126       110  
Change in unrealized loss from derivatives, net of tax
    -       304       -       908  
Total comprehensive income
  $ 3,149     $ 3,656     $ 50,575     $ 47,483  
 
  9.
Fair Value of Financial Instruments
 
We use fair value measurements to record adjustments to certain financial instruments and to determine fair value disclosures.  As of June 30, 2009 and 2008 and December 31, 2008, we recorded our derivatives at fair value according to SFAS No. 157.
 
In accordance with SFAS No. 157, we use the following fair value hierarchy for determining our derivative fair value measurements:
 
·  
Level 1: Valuation is based upon quoted prices for identical instruments traded in active markets;
·  
Level 2: Valuation is based upon quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-based valuation techniques for which all significant assumptions are observable in the market; and
·  
Level 3: Valuation is generated from model-based techniques that use significant assumptions not observable in the market. These unobservable assumptions reflect our own estimates of the assumptions we believe market participants would use in valuing the asset or liability.
 
When developing fair value measurements, it is our policy to use quoted market prices whenever available, or to maximize the use of observable inputs and minimize the use of unobservable inputs when quoted market prices are not available. Derivative contracts outstanding at June 30, 2009 and 2008 and December 31, 2008 were measured at fair value using models or other market accepted valuation methodologies derived from observable market data.  These models are primarily industry-standard models that consider various inputs including: (a) quoted future prices for commodities; (b) forward currency prices; (c) time value; (d) volatility factors; (e) current market and contractual prices for underlying instruments; (f) market interest rates and yield curves; and (g) credit spreads, as well as other relevant economic measures.
 
In accordance with SFAS No. 157, 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 nonperformance risk is generally derived from the credit default swap market or from bond market credit spreads. The impact of the credit risk adjustments for all outstanding derivatives was immaterial to the fair value calculation at June 30, 2009 and 2008 and December 31, 2008.
 
15

 
The following table provides the fair value measurements for our derivative assets and liabilities as of June 30, 2009 and 2008 and December 31, 2008 in accordance with the fair value hierarchy under SFAS No. 157:
 
     
June 30,
   
June 30,
   
Dec. 31,
 
Thousands
Description of Derivative Inputs
 
2009
   
2008
   
2008
 
Level 1
Quoted prices in active markets
  $ -     $ -     $ -  
Level 2
Significant other observable inputs
    (73,314 )     58,561       (153,643 )
Level 3
Significant unobservable inputs
    -       -       -  
      $ (73,314 )   $ 58,561     $ (153,643 )
 
  10.
Derivative Instruments
 
We enter into forward contracts and other related financial transactions that qualify as derivative instruments under SFAS No. 133, “Accounting for Derivatives,” as amended by SFAS No. 138 and SFAS No. 149 (collectively referred to as SFAS No. 133).  We utilize derivative financial instruments primarily to manage commodity prices related to natural gas supply requirements and interest rates related to existing or anticipated debt issuances.
 
As in the prior two gas years, our strategy entering the 2008-09 gas year (November 1, 2008 – October 31, 2009) was to hedge up to a targeted level of approximately 75 percent of our anticipated year-round sales volumes based on normal weather.  We do most of our hedging for the upcoming gas year prior to the start of that gas year and include the hedge prices in our annual purchased gas adjustment filing.  
 
The volumes hedged with financial contracts at June 30, 2009 totaled 482 million therms.  These amounts include hedged volumes for the current and future gas years.  At June 30, 2009, we were 60 to 70 percent hedged for the remainder of the 2008-09 gas year and approximately 40 percent hedged with financial contracts for the 2009-10 gas year based on anticipated sales volumes, with approximately an additional 8 percent hedged with physical supplies in gas storage for the 2009-10 gas year.
 
In accordance with SFAS No. 161, the following table discloses the balance sheet presentation of our derivative instruments outstanding as of June 30, 2009 and 2008 and December 31, 2008:  
 
   
Fair Value of Derivative Instruments
 
   
June 30, 2009
   
June 30, 2008
   
Dec. 31, 2008
 
Thousands
 
Current
   
Non-Current
   
Current
   
Non-Current
   
Current
   
Non-Current
 
Assets: (1)
                                   
Natural gas commodity
  $ 5,293     $ 289     $ 54,867     $ 9,218     $ 4,592     $ 146  
Total
  $ 5,293     $ 289     $ 54,867     $ 9,218     $ 4,592     $ 146  
Liabilities: (2)
                                               
Natural gas commodity
  $ 69,999     $ 8,844     $ 2,755     $ 1,374     $ 136,290     $ 9,734  
Interest rate
    -       -       -       1,358       -       11,912  
Foreign exchange
    53       -       37       -       445       -  
Total
  $ 70,052     $ 8,844     $ 2,792     $ 2,732     $ 136,735     $ 21,646  
 
 
(1)     Unrealized fair value gains are classified under current- or non-current assets as fair value of non-trading derivatives.
 
(2)     Unrealized fair value losses are classified under current- or non-current liabilities as fair value of non-trading derivatives.
 
 
 
 
16

In accordance with SFAS No. 161, the following table discloses the income statement presentation for the unrealized gains and losses from our derivative instruments outstanding for the three and six months ended June 30, 2009 and 2008.  It also illustrates that all of our derivative instruments are related to regulated utility operations and are deferred to balance sheet accounts in accordance with regulatory accounting under SFAS No. 71.  
 
   
Three Months Ended
 
   
June 30, 2009
    June 30, 2008
Thousands
 
Natural gas commodity (1)
   
Foreign exchange (3)
   
Natural gas commodity (1)
   
Interest rate (2)
   
Foreign exchange (3)
 
Cost of sales
  $ 44,446     $ -     $ 28,398     $ -     $ -  
Other comprehensive income
    -       101       (303 )     2,255       71  
Less:
                                       
Amounts deferred to regulatory accounts on balance sheet
    (44,446 )     (101 )     (28,095 )     (2,255 )     (71 )
Total impact on earnings
  $ -     $ -     $ -     $ -     $ -  
                                         
   
Six Months Ended
 
   
June 30, 2009
    June 30, 2008
Thousands
 
Natural gas commodity (1)
   
Foreign exchange (3)
   
Natural gas commodity (1)
   
Interest rate (2)
   
Foreign exchange (3)
 
Cost of sales
  $ (73,261 )   $ -     $ 60,823     $ -     $ -  
Other comprehensive income
    -       (53 )     (867 )     (1,358 )     (37 )
Less:
                                       
Amounts deferred to regulatory accounts on balance sheet
    73,261       53       (59,956 )     1,358       37  
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 in accordance with SFAS No. 71.
  (2)  
Unrealized gain (loss) from interest rate hedge contracts is recorded in other comprehensive income (loss) and reclassified to regulatory deferral accounts on the balance sheet in accordance with SFAS No. 71.
  (3)  
Unrealized gain (loss) from foreign exchange forward purchase contracts is recorded in other comprehensive income, and reclassified to regulatory deferral accounts on the balance sheet in accordance with SFAS No. 71.
 

 
17

 
In accordance with SFAS No. 161, the gross derivative liability excludes the netting of collateral.  We had no collateral posted during the six months ended June 30, 2009.  We attempt to minimize our potential exposure to collateral calls by our counterparties to manage our liquidity risk.  Based on our current credit rating, most counterparties allow us credit limits that range from $15 million to $25 million before we become obligated to post collateral.  We measure our collateral call exposure as contractually required under collateral support agreements. We also measure our collateral call exposure with calls for adequate assurance, which is not specific as to amount of credit limit allowed, but could potentially arise if we were to be exposed to a material adverse change.  Based upon the current unrealized loss of $72.9 million, the fair value associated with estimated collateral calls is included in the table below.  The following table discloses the estimates with and without expected adequate assurance calls, using outstanding derivative instruments at June 30, 2009, based on current gas prices and with various credit rating scenarios for NW Natural.

Thousands
 
(Current Ratings) A+/A3
   
BBB+/Baa1
   
BBB/Baa2
   
BBB-/Baa3
   
Speculative
 
With Adequate Assurance Calls
  $ -     $ -     $ 889     $ 13,679     $ 53,304  
Without Adequate Assurance Calls
  $ -     $ -     $ -     $ 10,290     $ 44,915  
 
In the three and six months ended June 30, 2009, we realized net losses of $42.4 million and $121.7 million, respectively, from the settlement of natural gas hedge contracts, which were recorded as increases to the cost of gas, compared to net gains of $17.0 million and $21.3 million, respectively, for the three and six months ended June 30, 2008, which were recorded as decreases to the cost of gas.  The currency exchange rate in all foreign currency forward purchase contracts is included in our purchased cost of gas at settlement; therefore, no gain or loss is recorded from the settlement of those contracts.  We settled our $50 million interest rate swap in March 2009 concurrent with our issuance of the underlying long-term debt and realized a $10.1 million effective hedge loss, which will be amortized to interest expense over the term of the debt.
 
We are exposed to derivative credit risk primarily through securing pay-fixed natural gas commodity swaps to hedge the risk of price increases for our natural gas purchases on behalf of customers.  We utilize master netting arrangements through International Swaps and Derivatives Association contracts to minimize this risk along with collateral support agreements with counterparties based on their credit ratings.  In certain cases we require guarantees or letters of credit in order for a counterparty to meet our credit requirements.
 
Our financial derivatives policy requires counterparties to have a certain investment-grade credit rating at the time the derivative instrument is entered into, and the policy specifies limits on the contract amount and duration based on each counterparty’s credit rating.  We do not speculate on derivatives.  We utilize derivatives to hedge our exposure above risk tolerance limits.  Any increase in market risk created by the use of derivatives should be offset by the exposures they modify.
 
We actively monitor our derivative credit exposure and place counterparties on hold for trading purposes or require other forms of credit assurance, such as letters of credit, cash collateral or guarantees as circumstances warrant. Our ongoing assessment of counterparty credit risk includes consideration of credit ratings, credit default swap spreads, bond market credit spreads, financial condition, government actions and market news. We utilize a Monte-Carlo simulation model to estimate the change in credit and liquidity risk from the volatility of natural gas prices.  We use the results of the model to establish at-risk trading limits.  The duration of our credit risk for all outstanding derivatives currently does not extend beyond October 31, 2012.
 
We could become materially exposed to credit risk with one or more of our counterparties if natural gas prices experience a significant increase.  If a counterparty were to become insolvent or fail to perform on its obligations, we could suffer a material loss, but we would expect such loss to be eligible for regulatory deferral and rate recovery, subject to prudency review.  All of our existing counterparties currently have investment-grade credit ratings.
 
As of June 30, 2009, all outstanding natural gas hedge contracts were scheduled to mature on or before October 31, 2012.
 
  11.
Commitments and Contingencies
 
Environmental Matters
 
We own, or have previously owned, properties that are likely to 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 at each identified site.  Due to the numerous uncertainties surrounding the course of environmental remediation and the preliminary nature of several environmental site investigations, the amount or range of potential loss beyond the amounts currently accrued, and the probabilities thereof, cannot currently be reasonably estimated.  See Part II, Item 8., Note 12, in the 2008 Form 10-K.  

 
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The status of each site currently under investigation is provided below.
 
Gasco site. We own property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 (the Gasco site). The Gasco site has been under investigation by us for environmental contamination under the Oregon Department of Environmental Quality’s (ODEQ) Voluntary Clean-Up Program. In June 2003, we filed a Feasibility Scoping Plan and an Ecological and Human Health Risk Assessment with the ODEQ, which outlined a range of remedial alternatives for the most contaminated portion of the Gasco site. In May 2007, we completed a revised Upland Remediation Investigation Report and submitted it to the ODEQ for review.  In November 2007, we submitted a Focused Feasibility Study for groundwater source control which ODEQ conditionally approved in March 2008.  Source control design is underway. We have a net liability balance of $19.0 million at June 30, 2009 for the Gasco site, which is estimated 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.
 
Siltronic site. We previously owned property adjacent to the Gasco site that now is the location of a manufacturing plant owned by Siltronic Corporation (the Siltronic site). In 2005, ODEQ directed NW Natural to complete a Remedial Investigation/Feasibility Study (RI/FS) for manufactured gas plant wastes on the uplands at this site.  ODEQ approved NW Natural’s investigation work plan, and field work for the investigation is ongoing.  The net liability balance at June 30, 2009 for the Siltronic site is $0.9 million, which is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.
 
Portland Harbor site. In 1998, the ODEQ and the U.S. Environmental Protection Agency (EPA) completed a study of sediments in a 5.5-mile segment of the Willamette River (Portland Harbor) that includes the area adjacent to the Gasco and Siltronic sites. The Portland Harbor was listed by the EPA as a Superfund site in 2000 and we were notified that we are a potentially responsible party. We then joined with other potentially responsible parties, referred to as the Lower Willamette Group, to fund environmental studies in the Portland Harbor. Subsequently, the EPA approved a Programmatic Work Plan, Field Sampling Plan and Quality Assurance Project Plan for the Portland Harbor RI/FS.  The submittal of the Remedial Investigation Report to the EPA is expected in 2009, with the submittal of the Feasibility Study to the EPA anticipated in 2010.  The EPA and the Lower Willamette Group are conducting focused studies on approximately eleven miles of the lower Willamette River, including the 5.5-mile segment previously studied by the EPA. We continue to receive estimates of additional expenditures related to our RI/FS development and environmental remediation. In August 2008, we signed a cooperative agreement to participate in a phased natural resource damage assessment, with the intent to identify what, if any, additional information is necessary to estimate further liabilities sufficient to support an early restoration-based settlement of natural resource damage claims.  
 
In November 2007, the EPA invited all parties to whom it had then sent notices of potential liability for the Portland Harbor site to a meeting to discuss EPA Region 10’s expectation of a comprehensive settlement offer regarding implementation of the Portland Harbor record of decision, shortly after it issues such decision.  Additional potentially responsible parties were subsequently invited to participate in discussions concerning a settlement process.  To date, 72 of these parties have executed an initial agreement to participate in a non-judicial allocation process intended to resolve the parties’ liabilities, if any, to the EPA and to one another.  As of June 30, 2009, we have accrued a net balance of $12.8 million for this site, which is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.
 
In April 2004 we entered into an Administrative Order on Consent providing for early action removal of a specific deposit of tar in the river sediments adjacent to the Gasco site. We completed this removal of the tar deposit in the Portland Harbor in October 2005, and on November 5, 2005 the EPA approved the completed project. The total cost of removal, including technical work, oversight, consultant fees, legal fees and ongoing monitoring, was about $10.8 million. To date, we have paid $10.2 million on work related to the removal of the tar deposit. As of June 30, 2009, we have a remaining net liability balance of $0.6 million for our estimate of ongoing costs related to this tar deposit removal.
 
 
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Central Service Center site. In 2006, we received notice from the ODEQ that our Central Service Center in southeast Portland (the Central Service Center site) was assigned a high priority for further environmental investigation. Previously there were three manufactured gas storage tanks on the premises. The ODEQ believes there could be site contamination associated with releases of condensate from stored manufactured gas 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 2007, we received notice that this site was added to the ODEQ’s list of sites where releases of hazardous substances have been confirmed and to its list where additional investigation or cleanup is necessary. We are currently performing an environmental investigation of the property with the ODEQ’s Independent Cleanup Pathway.  As of June 30, 2009, we have a net liability balance of $0.5 million accrued 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. Although 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 sediment investigation and a historical report have been submitted to ODEQ.  ODEQ approval of the sediment investigation work plan is pending.  As of June 30, 2009, we have an estimated net liability balance of $0.2 million for the study of the site, which will include investigation of sediments and providing the report of historical upland activities.  The estimate is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.
 
Oregon Steel Mills site. See “Legal Proceedings,” below.
 
Accrued Liabilities Relating to Environmental Sites. The following table summarizes the accrued liabilities relating to environmental sites at June 30, 2009 and 2008 and December 31, 2008:
 
 
   
Current Liabilities
   
Non-Current Liabilities
 
   
June 30,
   
June 30,
   
Dec. 31,
   
June 30,
   
June 30,
   
Dec. 31,
 
Thousands
 
2009
   
2008
   
2008
   
2009
   
2008
   
2008
 
Gasco site
  $ 11,373     $ 8,122     $ 6,012     $ 7,615     $ 12,406     $ 14,071  
Siltronic site
    722       1,211       682       179       -       332  
Portland Harbor site
    -       1,348       277       13,401       12,864       13,642  
Central Service Center site
    -       -       -       523       529       526  
Front Street site
    221       -       -       -       -       294  
Other sites
    -       -       -       90       83       80  
Total
  $ 12,316     $ 10,681     $ 6,971     $ 21,808     $ 25,882     $ 28,945  
 
 
Regulatory and Insurance Recovery for Environmental Costs.  In May 2003, the Oregon Public Utility Commission (OPUC) approved our request to defer and seek recovery of unreimbursed environmental costs associated with certain named sites, including those described above.  Also, beginning in 2006 the OPUC authorized us 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, these authorizations have been extended through January 25, 2010.  
 
On a cumulative basis, we have recognized a total of $72.6 million for environmental costs, including legal, investigation, monitoring and remediation costs.  Of this total, $38.5 million has been spent to date and $34.1 million is reported as an outstanding liability.  At June 30, 2009, we had a regulatory asset of $70.1 million, which includes $33.7 million of total paid expenditures to date, $28.7 million for additional environmental costs expected to be paid in the future and accrued interest of $7.7 million.  We believe the recovery of these deferred charges is probable through the regulatory process.  We intend to pursue recovery of an insurance receivable and environmental regulatory deferrals from insurance carriers under our general liability insurance policies, and the regulatory asset will be reduced by the amount of any corresponding insurance recoveries. We consider insurance recovery of most of our environmental costs to date probable based on a combination of factors including: a review of the terms of our insurance policies; the financial condition of the insurance companies providing coverage; a review of successful claims filed by other utilities with similar gas manufacturing facilities; and Oregon law that allows an insured party to seek recovery of “all sums” from one insurance company.  We have initiated settlement discussions with a majority of our insurers but continue to anticipate that our overall insurance recovery effort will extend over several years.
 
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We anticipate that our regulatory recovery of environmental cost deferrals will not be initiated within the next 12 months because we do not expect to have completed our insurance recovery efforts during that time period. As such we have classified our regulatory assets for environmental cost deferrals as non-current.  The following table summarizes the non-current regulatory assets relating to environmental sites at June 30, 2009 and 2008 and December 31, 2008:
 
   
Non-Current Regulatory Assets
 
   
June 30,
   
June 30,
   
Dec. 31,
 
Thousands
 
2009
   
2008
   
2008
 
Gasco site
  $ 32,688     $ 29,898     $ 30,707  
Siltronic site
    2,367       2,247       2,327  
Portland Harbor site
    33,727       31,092       31,791  
Central Service Center site
    548       545       545  
Front Street site
    350       11       338  
Other sites
    371       366       396  
Total
  $ 70,051