10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 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 number 1-15973

NORTHWEST NATURAL GAS COMPANY

(Exact name of registrant as specified in its charter)

Oregon	93-0256722
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class                                                                                   Name of each exchange on which registered

Common Stock                                                                                             New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:  None.

     Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes  [ X ]    No  [    ]

     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes  [   ]    No  [ X ]

     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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ X ]

     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 [    ]

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes  [   ]    No  [ X ]

     As of June 30, 2011, the registrant had 26,672,812 shares of its Common Stock outstanding.  The aggregate market value of these shares of Common Stock (based upon the closing price of these shares on the New York Stock Exchange on that date) held by non-affiliates was $1,189,774,420.

     At February 24, 2012, 26,791,793 shares of the registrant’s Common Stock (the only class of Common Stock) were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement of the registrant, to be filed in connection with the 2012 Annual Meeting of Shareholders, are incorporated by reference in Part III.

NORTHWEST NATURAL GAS COMPANY

Annual Report to Securities and Exchange Commission

on Form 10-K

For the Fiscal Year Ended December 31, 2011

Table of Contents

PART I				Page
	Glossary of Terms			1
	Forward-Looking Statements			2
Item 1.	Business			3
		Overview		3
		Business Segments		3
			Local Gas Distribution	3
			Gas Storage	12
			Other	15
		Environmental Issues		16
		Employees		17
		Additions to Infrastructure		17
		Executive Officers of the Registrant		17
		Available Information		17
Item 1A.	Risk Factors			18
Item 1B.	Unresolved Staff Comments			28
Item 2.	Properties			28
Item 3.	Legal Proceedings			29
Item 4.	Mine Safety Disclosures			29
PART II
Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer
		Purchases of Equity Securities		30
Item 6.	Selected Financial Data			32
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			33
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk			65
Item 8.	Financial Statements and Supplementary Data			68
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			113
Item 9A.	Controls and Procedures			113
Item 9B.	Other Information			113
PART III
Item 10.	Directors, Executive Officers and Corporate Governance			114
Item 11.	Executive Compensation			115
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			115
Item 13.	Certain Relationships and Related Transactions, and Director Independence			116
Item 14.	Principal Accountant Fees and Services			116
PART IV
Item 15.	Exhibits and Financial Statement Schedules			117
SIGNATURES				118

GLOSSARY OF TERMS
Average weather: equal to the 25-year average degree days based on temperatures established in our last Oregon general rate case.	Interruptible service: natural gas service offered to customers (usually large commercial or industrial users) under contracts or rate schedules that allow for interruptions when necessary to meet the needs of firm service customers.
Bcf: one billion cubic feet, a volumetric measure of natural gas, roughly equal to 10 million therms or one trillion Btu’s.
	Liquefied natural gas (LNG): the cryogenic liquid form of natural gas. To reach a liquid form at atmospheric pressure, natural gas must be cooled to approximately -260 degrees Fahrenheit.
Btu: British thermal unit, a basic unit of thermal energy measurement. One Btu equals the energy required to raise one pound of water one degree Fahrenheit at atmospheric pressure and 60 degrees Fahrenheit. One hundred thousand Btu’s equal one therm.
	Purchased gas adjustment (PGA): a regulatory mechanism for adjusting customer rates to reflect changes in the expected cost to acquire and deliver natural gas supplies.
Core utility customers: residential, commercial and industrial customers receiving firm service from the utility.
	Return on equity (ROE): a measure of corporate profitability, calculated as net income divided by average common stock equity. Authorized ROE refers to the equity rate approved by a regulatory agency for utility investments funded by common stock equity.
Cost of gas sold: the delivered cost of natural gas sold to customers, including the cost of gas purchased or withdrawn/produced from storage inventory or reserves, gains and losses from gas commodity hedges, pipeline demand costs, seasonal demand cost balancing adjustments, regulatory gas cost deferrals and company gas use.
	Sales service: service provided whereby a customer purchases both natural gas commodity supply and transportation from the utility.
Decoupling: a rate mechanism, also referred to as our conservation tariff, which is designed to break the link between earnings and the quantity of natural gas consumed by customers. The design is intended to allow the utility to encourage customers to conserve energy while not adversely affecting its earnings due to reductions in sales volumes.
	Therm: the basic unit of natural gas measurement, equal to 100,000 Btu’s.
Degree days: units of measure that reflect temperature-sensitive consumption of natural gas, calculated by subtracting the average of a day’s high and low temperatures from 65 degrees Fahrenheit.	Transportation service: service provided whereby a customer purchases natural gas commodity directly from a supplier but pays the utility to transport the gas over its distribution system to the customer’s facility.
Demand cost: a component in core utility customer rates that covers the cost of securing firm pipeline capacity to meet peak demand, whether that capacity is used or not.	Utility margin: utility gross revenues less the associated cost of gas sold, including regulatory adjustments and applicable revenue taxes. Also referred to as utility net operating revenues.
Firm service: natural gas service offered to customers under contracts or rate schedules that will not be disrupted to meet the needs of other customers, particularly during cold weather.	Weather normalization: a rate mechanism applied to residential and commercial customers’ bills to adjust residential and commercial customer billings based on temperature variances from average weather, with rate decreases when the weather is colder than average and rate increases when the weather is warmer than average.
General rate case: a periodic filing with state or federal regulators to establish equitable rates and balance the interests of all classes of customers and our shareholders.

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Forward-Looking Statements

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;

·   assumptions and estimates;

·   future events or performance;

·   trends;

·   cyclicality;

·   earnings and dividends;

·   growth;

·   customer rates;

·   commodity costs;

·   gas reserves;

·   operational performance and costs;

·   liquidity and financial positions;

·   project development and expansion;

·   competition;

·   procurement and development of new gas supplies;

·   estimated expenditures;

·   costs of compliance;

·   credit exposures;

·   potential efficiencies;

·   rate case;

·   impacts of laws, rules and regulations;

·   tax liabilities or refunds;

·   outcomes and effects of litigation, regulatory actions, and other administrative matters;

·   projected obligations under retirement plans;

·   adequacy of, and shift in mix of, gas supplies;

·   approval and adequacy of regulatory deferrals; and

·   environmental, regulatory, litigation and insurance costs and recoveries.

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 at Item 1A., “Risk Factors” of Part I and 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, of Part II of this report.

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.

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NORTHWEST NATURAL GAS COMPANY

PART I

ITEM 1. BUSINESS

Overview

Northwest Natural Gas Company (NW Natural) was incorporated under the laws of Oregon in 1910.  Our company and its predecessors have supplied gas service to the public since 1859, and we have been doing business as NW Natural since 1997. We maintain operations in Oregon, Washington and California and conduct businesses through NW Natural, its subsidiaries and joint ventures.  A reference to NW Natural (“we,” “us” or “our”) in this report means NW Natural and its subsidiaries and joint ventures unless otherwise noted.

Business Segments

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 that we aggregate and report as Other.

Local Gas Distribution

We are principally engaged in the distribution of natural gas in Oregon and southwest Washington.  We refer to this business segment as our local gas distribution segment or utility.  Our local gas distribution segment involves building and maintaining a safe and reliable pipeline distribution system, purchasing gas from producers and marketers, contracting for the transportation of gas over pipelines from regional supply basins to our service territory, and reselling the gas to customers subject to rates, terms and conditions approved by the Public Utility Commission of Oregon (OPUC) or by the Washington Utilities and Transportation Commission (WUTC).  Local gas distribution also includes transporting gas owned by customers from an interstate pipeline connection, or city gate, to the customers’ facilities for a fee, also approved by the OPUC or WUTC.  Approximately 90 percent of our consolidated assets and consolidated net income have been related to the local gas distribution segment over the last few years.  The OPUC has allocated to us as our exclusive service area a major portion of western Oregon, including the Portland metropolitan area, most of the Willamette Valley and the coastal area from Astoria to Coos Bay.  We also hold certificates from the WUTC granting us exclusive rights to serve portions of three southwest Washington counties bordering the Columbia River.  We provide gas service in 124 cities and neighboring communities in 15 Oregon counties, as well as in 16 cities and neighboring communities in three Washington counties.  The city of Portland is the principal retail and manufacturing center in the Columbia River Basin, and is a major port for trade with Asia.

See Note 4 to the Consolidated Financial Statements for information on local gas distribution assets and results of operations for the years ended December 31, 2011, 2010 and 2009.

Regulation and Rates

Our utility segment is subject to regulation with respect to, among other matters, rates and systems of accounts by the OPUC, the WUTC, and Federal Energy Regulatory Commission (FERC).  The OPUC and WUTC also regulate NW Natural’s issuance of securities.  In 2011, approximately 90 percent of our utility gas volumes were delivered to, and utility operating revenues were derived from, Oregon customers and the balance from Washington customers.  .  The OPUC and the WUTC generally require the natural gas commodity cost to be billed to customers at the same cost incurred or expected to be incurred by the utility.   We have not historically earned a profit or incurred a loss on gas commodity purchases; however, in Oregon we have an incentive sharing provision whereby we can either increase or decrease margin revenues from gas cost variances as compared to gas costs embedded in the PGA.  Under this provision, our net income is affected by differences between actual and expected purchased gas costs, which occur primarily because of market fluctuations and volatility affecting unhedged gas purchases.  In addition, we recently entered into a regulatory agreement where we receive a rate base return on our investment in gas reserves.  See Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment and Results of Operations—Regulatory Matters—Rate Mechanisms—Gas Reserves”. 

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We file general rate case and rate tariff requests periodically with the OPUC, WUTC and FERC to change the rates we charge our utility and storage customers.  On December 30, 2011, we filed an application for a general rate increase at the OPUC.  We requested an increase in authorized annual Oregon jurisdictional revenues of $43.7 million, or 6.2 percent, with an overall rate of return on capital of 8.28 percent, including a return on common equity of 10.3 percent, and an authorized equity to capitalization ratio of 50 percent.  We also requested the establishment of a rate mechanism through which deferred costs related to our environmental liabilities will be recovered through rates.  The new rates are requested to be effective by November 1, 2012.  We expect the OPUC to make a decision on this rate case by the end of October 2012.

Our most recent general rate case in Washington was approved in December 2008, and new rates were effective on January 1, 2009 (see Part II, Item 7., “Results of Operations—Regulatory Matters—General Rate Cases,” below). 

 We are required under our Mist interstate storage certificate authority to file with FERC every five years either a petition for rate approval or a cost and revenue study to change or justify maintaining the existing rates for the interstate storage service.   For further information, see Part II, Item 7., “Results of Operations—Regulatory Matters,” and “Business Segments—Gas Storage,” below.

Gas Supply

 Our gas supply strategy is based on forecasted customer requirements, which considers estimated load growth by type of customer, attrition, conservation, distribution system constraints, interstate pipeline capacity and contractual limitations and the forecasted transfer of large customers between sales service and transportation-only service.  We perform sensitivity analyses based on factors such as weather variations and price elasticity effects.  We have a diverse portfolio of short-, medium- and long-term firm gas supply contracts that are supplemented during periods of peak demand with gas from storage facilities either owned by or contractually committed to us.

To achieve our gas supply strategy, we employ a gas purchasing strategy that emphasizes a diversity of supply sources; a diverse portfolio of contract types and durations; strategic uses of gas storage facilities and capacity recall agreements; a variety of gas cost management strategies; and physical acquisition of gas supplies.

We purchase our gas supplies at liquid trading points to facilitate competition and price transparency.  These trading points include the NOVA Inventory Transfer (NIT) point in Alberta (also referred to as AECO), Huntingdon/Sumas and Station 2 in British Columbia, and multiple receipt points in the U.S. Rocky Mountains.

Diversity of Supply Sources

We purchase natural gas for our core utility customers from three supply basins located between western Canada and the U.S. Rocky Mountain areas. Currently, about 65 percent of our supply comes from Canada, with the balance coming primarily from the U.S. Rocky Mountain region.   We believe that gas supplies available in the western United States and Canada are adequate to serve our core utility requirements for the foreseeable future, but we continue to evaluate our long-term supply mix based on projections of gas production and pricing in the U.S. Rocky Mountain regions as well as other regions in North America.  We believe that the cost of natural gas coming from western Canada and the U.S. Rocky Mountain regions will continue to track the broader U.S. market prices.  Additionally, we expect increased availability of gas supplies throughout North America as a result of the extraction of shale gas resources and the building of new transmission pipeline projects to increase capacity out of the U.S. Rocky Mountain region.

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Diverse Supply Portfolio of Contract Types and Durations

We maintain a diverse portfolio of short-, medium-, and long-term firm gas supply contracts.  We typically enter into gas purchase contracts for:

·   year-round baseload supply;

·   additional baseload supply for the winter heating season;

·   winter heating season contracts where we have the option to call on all or some of the supplies on a daily basis; and

·   spot purchases, taking into account forecasted customer requirements, storage injections and withdrawals and seasonal weather fluctuations.

At December 31, 2011, we have contracts with gas suppliers for deliveries ranging from three months to four years, which provide for a maximum of 2.0 million therms of firm gas per day during the winter heating season and 0.7 million therms per day year-round. These contracts have a variety of pricing structures and purchase obligations. In addition, we have another 1.3 million therms per day of firm gas supplies whereby we can purchase supplies for delivery to our system during the winter heating season.  During 2011, we purchased a total of 808 million therms of gas under contracts with durations outlined in the chart below.

	Percent of
Contract Duration (primary term)	Purchases
Long-term (one year or longer)		29
Short-term (more than one month, less than one year)		26
Spot (one month or less)		45
Total		100

We typically renew or replace our gas supply contracts with new agreements from existing and new suppliers. Aside from the asset management of our core utility gas supplies by the independent energy marketing company (see “Gas Cost Management Strategy—Asset management,” below), no individual supplier generally provides more than 10 percent of our supply requirements. In 2011, one supplier provided 11 percent of our supply requirements. Firm year-round supply contracts have remaining terms ranging from one to four years.  Currently, all firm gas supply contracts use price formulas tied to monthly index prices.

In addition to our year-round contracts, we continue to contract in advance for firm gas supplies to be delivered only during the winter heating season primarily under short-term contracts.  During 2011, new short-term purchase contracts were entered into with 17 suppliers, which in addition to our year- round contracts provide for a total of up to 2.0 million therms per day.  We intend to enter into new purchase contracts during 2012 for roughly the same volume of gas with existing or new suppliers, as needed, to replace contracts that will expire in 2012.

We also buy gas on the spot market as needed to meet utility customer demand. We have flexibility under the terms of some firm supply contracts, to purchase spot gas in lieu of the firm contract volumes thereby allowing us to take advantage of more favorable pricing on the spot market from time to time.

We continue to purchase a small amount of gas from a non-affiliated producer in the Mist gas field in Oregon.  The production area is situated near our underground gas storage facilities. Current production supplies are less than 2 percent of our total annual purchase requirements. Production from these wells varies as existing wells are depleted and new wells are drilled.

In 2011, 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 our utility customers’ requirements over the next 30 years.  The volume of gas produced and allocated to us 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.  In 2011, volumes from gas reserves were less than one percent of our annual gas purchases.

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Strategic Use of Gas Storage and Capacity Recall

We supplement our firm gas supply purchases with gas withdrawals from storage facilities we own or that are contractually committed to us. Gas is generally purchased and injected into storage during periods of low demand so that it can be withdrawn for use at a later time during periods of peak demand. In addition to enabling us to meet our peak demand, these facilities make it possible to lower the annual average cost of gas by allowing us to minimize our pipeline capacity demand costs and to purchase gas for storage during the summer months when gas prices are generally lower.

Underground storage.  A portion of our daily and seasonal peaking supplies to core utility customers are from our underground gas storage facility in the Mist gas storage field.  This facility has a maximum daily deliverability of 5.2 million therms and a total working gas capacity of about 16 Bcf, which includes the capacity reserved for core utility customers as well as the capacity used for non-utility service.  Under our regulatory agreement with the OPUC, non-utility gas storage at Mist can be developed in advance of core utility customer needs, but it is subject to recall by the utility when needed to serve utility customers as utility demand increases.  Storage capacity recalled by the utility is added to utility rate base at net book value and tracked into utility rates in the annual PGA filing immediately following the recall, so there is minimal regulatory lag in cost recovery.  In May 2011, a total of 100,000 therms per day of Mist storage capacity that had previously been available for non-utility gas storage services was recalled and committed to use for core utility customers. There was no Mist recall in 2010, but 100,000 therms per day were recalled in May 2009.    The core utility currently has 2.6 million therms per day of deliverability and approximately 9.5 Bcf of working gas capacity available at the Mist storage facility.

We also have contracts with Northwest Pipeline (Northwest Pipeline), a subsidiary of The Williams Companies, for firm gas storage from an underground facility at Jackson Prairie near Chehalis, Washington, that provides us with daily firm deliverability of about 0.5 million therms and total seasonal capacity of about 11.2 million therms. Separate contracts with Northwest Pipeline provide for the transportation of these storage supplies to our service territory.  All of these contracts have reached the end of their primary terms, but we have exercised our renewal rights that allow for annual extensions at our option.

We also contract for storage service in Alberta for amounts totaling just under 20 million therms.  This supply will displace equivalent volumes of spot purchases in Alberta as it uses the same pipeline transportation for delivery from Alberta to our local gas distribution system.  While this supply helps manage price risks, it does not add to our total peak day resources.

LNG storage.  We own and operate two LNG storage facilities in our Oregon service territory that liquefy gas for storage during the summer months so that it is available for withdrawal during periods of peak demand in the winter heating season. These two facilities provide a maximum combined daily deliverability of 1.8 million therms and a total seasonal capacity of 16 million therms.  In addition, we have a contract for firm gas storage from an LNG facility in Plymouth, Washington, which provides us with daily firm deliverability of about 0.6 million therms and total seasonal capacity of about 4.8 million therms.

Capacity recall from transportation customers.  We also have contracts with one electric generator and two industrial customers that together provide 390,000 therms per day of recallable pipeline capacity and supply.

Gas Cost Management Strategy

The cost of gas sold to core utility customers primarily consists of the purchase price paid to suppliers (including the cost to acquire supplies in the form of gas reserves), charges paid to pipeline companies to store and transport gas to our distribution system, and gains or losses related to gas commodity hedge contracts entered into in connection with the purchase of gas for core utility customers.

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While volatility in natural gas commodity prices has ebbed and flowed over the last several years due to a number of factors, recent success in new drilling technologies and substantial new supplies from shale gas formations around the U.S. and Canada have resulted in increased North American supplies of natural gas and lower gas prices.  At the same time, pipeline transportation rates charged by Canadian pipelines and U.S. interstate pipeline transportation service providers have been relatively stable over the last several years, due in part to a 2006 rate case settlement for the U.S. interstate pipelines.  These rates periodically change when the Canadian pipelines and U.S. interstate pipelines file for rate change approval from the Canadian National Energy Board or FERC, as applicable.  Pipeline transportation rate increases or decreases are generally passed on to our customers through annual PGA updates.

We engage in a number of strategies to mitigate the cost of gas sold to utility customers.Our primary strategies for managing gas commodity price risk include:

·   negotiating fixed prices directly with gas suppliers;

·   negotiating financial derivative instruments that effectively convert the floating index price in a physical gas supply contract to a fixed price (referred to as commodity price swaps);

·   negotiating financial derivative instruments that effectively set a ceiling or floor price, or both, on a floating price physical supply contract (referred to as commodity price options such as calls, puts, and collars);

·   buying gas and injecting it into storage;

·   buying a physical supply of gas reserves for longer term price stability; and

·   using an asset management service provider to produce revenues that reduce our utility’s net cost of gas sold;

Fixed-price contracts.  We negotiate fixed price contracts directly with gas suppliers for a portion of our gas purchases.  When we enter into these fixed-price contracts with our suppliers, the price is typically set based on the prevailing index price plus or minus a spread based on the forward price curve of natural gas at that time.

Financial derivative instruments.   We hedge a majority of our firm year-round supply contracts each year using financial derivative instruments as a key component of our gas purchasing strategy.  Our financial hedge contracts make up a majority of our commodity price hedging activity, and these contracts are with a variety of investment-grade credit counterparties, typically with credit ratings of AA- or higher.  See Part II, Item 7A., “Quantitative and Qualitative Disclosures About Market Risk—Credit Risk—Credit exposure to financial derivative counterparties.”  Under our financial hedge policy, we enter into commodity swaps, puts, calls and collars with terms generally ranging anywhere from one month to five years.

Storage supplies.  We seek to mitigate the effects of higher gas commodity prices and price volatility on core utility customers by using our underground gas storage facilities, LNG facilities and other methods of gas storage strategically in an attempt to manage the cost of gas commodity purchases. We purchase and inject gas into storage during the summer months when demand and gas prices are generally lower.  About 19 percent of our annual gas supply requirements is stored for withdrawal during the winter months in five different market-area storage facilities and one contract for supply-basin storage.  We are able to draw on these supplies during peak demand, thereby reducing the need for higher-priced spot gas purchases.

Gas reserves.   In addition to hedging gas prices with financial derivative instruments and gas storage, we recently signed an agreement with Encana to acquire physical gas supplies to provide a portion of our core utility customers’ requirements over 30 years.  During the first 10 years of the agreement, we believe the volumes of gas received under the Encana agreement will provide approximately 8 to 10 percent of the average annual requirements of our utility customers.

Asset management.  We use our gas supply, storage and transportation flexibility to capture opportunities that emerge during the course of the year for gas purchases, sales, exchanges or other means to manage net gas costs.  In particular, our Mist underground storage facility provides flexibility in this regard.  In addition to maximizing the value of our gas storage and pipeline capacity, we contract with an independent energy marketing company that manages our unused capacity when those assets are not serving the needs of our core utility customers.  Our asset management provides cost savings that reduces our utility’s cost of gas sold, and generates incremental revenues from a regulatory incentive-sharing mechanism that are included in our gas storage business segment.

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Gas Distribution Operations

The goals of our gas distribution operations for core utility customers are:

·   Safety—Building and maintaining a safe pipeline distribution system;

·   Reliability—Ensuring a gas resource portfolio that is sufficient to satisfy core utility customer requirements under extremely cold weather conditions;

·   Lowest reasonable cost—Applying strategies to acquire gas supplies at the lowest reasonable cost for utility customers;

·   Price stability—Making the best use of physical assets and financial instruments to manage commodity price volatility;  and

·   Cost recovery—Managing gas purchase costs prudently to minimize the risks associated with regulatory review and recovery of gas acquisition costs.

Safety

Safety and protection of our employees, our customers and the public at large is and will remain a top priority.  We monitor and maintain our pipeline distribution system and storage operations with the goal of ensuring that natural gas is stored and delivered safely, reliably and efficiently.  We have had various system integrity programs since 2004 and currently have a program which integrates the company’s bare steel replacement, transmission pipeline integrity management and distribution pipeline integrity management programs into a single program.  In response to the recent pipeline incidents involving other companies, natural gas distribution businesses are likely to be subject to even greater federal and state regulatory oversight of the safety of their operations.  The “Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011” signed into law in early 2012,  requires several new safety initiatives including an analysis of the appropriateness of automatic or remote shut-off valves on new and replaced gas transmission lines, an evaluation of the benefits of expanding transmission integrity management regulations to additional pipelines, requirements for operators to reverify the maximum allowable operating pressures for transmission pipelines, and other requirements.  We intend to work diligently with industry associations and federal and state regulators to comply with all new laws and regulations.  We expect that costs associated with compliance with federal, state and local rules would be recoverable in rates.

Reliability

The effectiveness of our gas distribution program ultimately rests on whether we provide reliable service at a reasonable cost to our core utility customers.  For this purpose, we develop a composite design year and include a three day design peak event that is based on the most severe cold weather experienced during the last 20 years in our service territory.  We also assume that all usage by interruptible customers will be curtailed on the design day.  Our projected sources of delivery for design day firm utility customer sendout total approximately 9.2 million therms.  Of this total, we are currently capable of meeting nearly 60 percent of our maximum design day requirements with gas from storage located within or adjacent to our service territory, while the remaining supply requirements would be met by gas purchases under firm and recall gas purchase contracts.  Optimal utilization of storage on our design day reduces the cost and dependency on firm interstate pipeline transportation.  On January 5, 2004, we experienced our current record firm customer sendout of 7.2 million therms, and a total sendout of 8.9 million therms, on a day that was approximately 9 degrees Fahrenheit warmer than the design day temperature.  That January 2004 cold weather event lasted about 10 days, and the actual firm customer sendout each day provided data that confirmed our load forecasting models with little re-calibration.  Similar cold temperatures experienced in December 2008 and December 2009 produced very high sendout days, but firm sendout in those years was still at least 3 percent below our 2004 record.  Accordingly, we believe that our supplies would be sufficient to meet existing firm customer demand if we were to experience maximum design day weather conditions.  We will continue to evaluate and update our forecasted requirements and incorporate changes in our integrated resource plan (IRP) process (see further discussion of IRP below).

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The following table shows the sources of supply that are projected to be used to satisfy the design day sendout for the 2011-2012 winter heating season:

Projected Sources of Utility Supply for Design Day Sendout
	Therms
Sources of Utility Supply	(in millions)		Percent
Firm supply purchases		3.3		36
Mist underground storage (utility only)		2.6		28
Company-owned LNG storage		1.8		20
Off-system firm storage contracts		1.1		12
Recall agreements		0.4		4
Total		9.2		100

The OPUC and WUTC have IRP processes in which utilities define different growth scenarios and corresponding resource acquisition strategies in an effort to evaluate supply and demand resources, consider uncertainties in the planning process and the need for flexibility to respond to changes, and establish a plan for getting reliable service at the “least cost.”

In general, the IRP is filed biannually with both the OPUC and the WUTC.  An annual update is filed in Oregon in the off year.  The OPUC acknowledges receipt of the IRP; whereas the WUTC provides notice that our IRP met the requirements of the Washington Administrative Code.  Commission acknowledgment of the IRP does not constitute ratemaking approval of any specific resource acquisition strategy or expenditure. However, the OPUC generally indicates that it would give considerable weight in prudency reviews to utility actions that are consistent with acknowledged plans. The WUTC has indicated that the IRP process is one factor it will consider in a prudency review.  We filed our 2011 IRP with Oregon in January 2011, and with Washington in March 2011.  Subsequent to these filings, we filed a modified IRP in both states on September 1, 2011 to address new assumptions about the schedule for the east segment of the Palomar pipeline (see Part II, Item 7., “2012 Outlook-Strategic Opportunities-Pipeline Diversification,” below).  The OPUC review of our 2011 IRP filing is in process.

Lowest Reasonable Cost

We apply cost management strategies, including fixed-price contracts, financial derivative instruments, storage supplies, gas reserve purchases and asset management, in seeking to acquire gas supplies at the lowest reasonable cost for utility customers (see “Gas Supply—Gas Cost Management Strategy” above).

Price Stability

 We use physical assets and financial instruments to manage commodity price volatility.  Our gas storage facilities make it possible to lower the annual average cost of gas by allowing us to minimize our pipeline capacity demand costs and to purchase gas for storage during the summer months when gas prices are generally lower.  (See “Strategic Use of Gas Storage and Capacity Recall” above).  In addition, we recently signed an agreement with Encana to acquire physical gas supplies to provide a portion of our core utility customers’ requirements over 30 years.  During the first 10 years of the agreement, we believe the volumes of gas received under the Encana agreement will provide approximately 8-10 percent of the average annual requirements of our utility customers.  (see “Diverse Supply Portfolio of Contract Types and Durations” above).  We also mitigate year-to-year commodity price volatility through financial hedge contracts such as commodity price swaps and options.  (see “Gas Cost Management Strategy—Financial derivatives instruments” above and Part II, Item 7A., “Quantitative and Qualitative Disclosures About Market Risk—Credit Risk—Credit exposure to financial derivative counterparties.”)

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Cost Recovery

Mechanisms for gas cost recovery are designed to be fair and to balance the interests of our customers and shareholders.  In general, utility rates are designed to recover the cost of, but not earn a return on, the gas commodity sold.  We attempt to minimize risks associated with gas cost recovery through:

·   re-setting customer rates annually for changes in forecasted gas costs and recovery of customer deferrals of prior year’s actual versus forecasted gas costs (see Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment”);

·   aligning customer and shareholder interests, such as through the use of our PGA incentive sharing mechanism, weather normalization, conservation, and gas storage sharing mechanisms (see Part II, Item 7., “Results of Operations—Regulatory Matters”); and

·   periodic review of regulatory deferrals with state regulatory commissions and key customer groups.

Customers

At year-end 2011, we had approximately 680,000 utility customers, consisting of approximately 616,000 residential, 63,000 commercial and 1,000industrial customers.  Approximately 90 percent of our utility customers are located in Oregon, and 10 percent are located in Washington.  Industries we serve include: pulp, paper and other forest products; the manufacture of electronic, electrochemical and electrometallurgical products; the processing of farm and food products; the production of various mineral products; metal fabrication and casting; the production of machine tools, machinery and textiles; the manufacture of asphalt, concrete and rubber; printing and publishing; nurseries; government and educational institutions; and electric generation.  No individual customer or industry accounts for a significant portion of our utility revenues.

Competition and Marketing

Competition with Other Energy Products

We have no direct competition in our service area from other natural gas distributors. However, for residential customers we compete primarily with electricity, fuel oil, propane and renewable energy providers.  We also compete with electricity, fuel oil and renewable energy for commercial applications.  In the industrial market, we compete with all forms of energy, including competition from third-party sellers of natural gas commodity. Competition among energy suppliers is based on price, efficiency, reliability, performance, market conditions, technology, legislative policy, and environmental impact.  Whether or not we provide the gas supplies to serve our transportation-eligible customers, our net margins are not materially affected because we generally do not make any margin on the commodity sold to our utility customers (see “Industrial Markets,” below and “Regulation and Rates” above).

Residential and Commercial Markets

The relatively low market saturation of natural gas in residential single-family dwellings in our service territory, estimated at less than 60 percent, and our operating convenience and environmental advantage over fuel oil, provides the potential for continuing growth from residential and commercial conversions.  In 2011, the net increase in residential customers was 5,072 primarily from single- and multi-family new construction, and from the conversion of existing homes from oil, electric and propane.  The net increase of all new customers added in 2011 was 5,546.  This represents a 12-month growth rate of 0.8 percent, which is down slightly from 2010 and well below historical growth rates due to the slow economic recovery and weak job market.  

On an annual basis, residential and commercial customers typically account for about 55 to 60 percent of our utility’s total volumes delivered and about 85 to 90 percent of gross operating revenues, while industrial customers account for about 40 to 45 percent of volumes and about 10 percent of gross operating revenues.  The remaining gross operating revenues are derived from miscellaneous services and other regulatory revenues.

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Industrial Markets

Competition to serve the industrial and large commercial market in the Pacific Northwest has been relatively unchanged since the early 1990s in terms of numbers and types of competitors.  Competitors consist of gas marketers, oil/propane sellers and electric utilities.

The OPUC and WUTC have approved transportation tariffs under which we may contract with customers to deliver customer-owned gas.  Transportation tariffs are priced at our sales service rate less the commodity cost included in that rate.  Therefore, our transportation margins (i.e. sales minus the cost of gas sold) are generally unaffected financially if industrial customers buy commodity supplies directly from producers or marketers rather than purchasing gas from us, as long as they remain on a tariff or contract with the same level of service.  Other than our incentive sharing arrangements and rate base return on gas reserves, we do not generally make any margin on the sale of the gas commodity.  However, industrial customers may select between firm and interruptible service as well as other levels of service, and these choices can positively or negatively affect margin.  Firm service schedules have a higher profit margin than interruptible service.  The relative level and volatility of prices in the natural gas commodity markets, along with the availability of pipeline capacity to ship customer-owned gas, are among the primary factors that have caused some industrial customers to alternate between sales and transportation service or between higher and lower levels of service.  See “Regulation and Rates” above for a full discussion on incentive sharing agreements.

Our industrial tariffs include terms which are intended to give us more certainty in the level of gas supplies we will need to purchase in order to serve this customer group.  The terms include an annual election cycle period, special pricing provisions for out-of-cycle changes, and the requirement that industrial customers on our annual weighted average PGA tariff must complete the agreed upon term of their service before switching to a new service schedule.  In the case of customers switching out-of-cycle from transportation to sales service, the customer will be charged the incremental cost of gas supply in accordance with our regulatory tariff.

We have designed custom transportation service agreements with several of our largest industrial customers.  These agreements are primarily designed to provide transportation rates that are competitive with the customer’s alternative capital and operating costs of installing direct pipeline connections to Northwest Pipeline’s interstate pipeline system, which would allow them to bypass our local gas distribution system.  These agreements generally prohibit bypass during their terms.  Due to the cost pressures that confront a number of our largest customers competing in global markets, bypass continues to be a competitive threat.  Although we do not expect a significant number of our large customers to bypass our system in the foreseeable future, we may experience further deterioration of margin associated with customers transferring to special contracts where pricing is specifically designed to be competitive with their bypass alternative.

Transportation of Gas Supplies

Single transportation pipeline

Our local gas distribution system is reliant on a single, bi-directional interstate transmission pipeline, to bring gas supplies into our distribution system.  Although we are dependent on a single pipeline, the pipeline’s gas flows into the Portland metropolitan market from two directions: (1) the north, which brings supplies from the British Columbia and Alberta supply basins; and (2) the east, which brings supplies from Alberta as well as the U.S. Rocky Mountain supply basins.  In 2003 a federal order requiring Northwest Pipeline to replace its 26-inch mainline from the Canadian border to our service territory underscored the potential need for pipeline transportation diversity.  That replacement project was completed by Northwest Pipeline in November 2006.  We are pursuing other options to further diversify our pipeline transportation paths.  Specifically, we are jointly developing plans to build a pipeline (Palomar pipeline) that would connect TransCanada Pipelines Limited’s (TransCanada) Gas Transmission Northwest (GTN) interstate transmission line to our local gas distribution system.  We entered into an agreement with GTN for the purpose of jointly developing, owning and operating this proposed pipeline.  Additionally, we entered into precedent agreements to become a shipper on the Palomar pipeline. If constructed, this pipeline would provide another transportation path for gas purchases from Alberta and the U.S. Rocky Mountains in addition to the one that currently moves gas through the Northwest Pipeline system (See Part II, Item 7., “2012 Outlook—Strategic Opportunities—Pipeline Diversification”).

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           Pipeline transportation agreements  

We incur monthly demand charges related to the following firm pipeline contracts.  The largest of our transportation agreements with Northwest Pipeline extends through September 2018 and provides for firm transportation capacity of up to 2.1 million therms per day.  This agreement provides access to natural gas supplies in British Columbia and the U.S. Rocky Mountains.

Our second largest transportation agreement with Northwest Pipeline extends through November 2016. It provides up to 1.0 million therms per day of firm transportation capacity from the point of interconnection with Northwest Pipeline and GTN systems in eastern Oregon to our service territory.  GTN’s pipeline runs from the U.S./Canadian border through northern Idaho, southeastern Washington and central Oregon to the California/Oregon border.  We have firm long-term capacity on GTN’s pipeline and two upstream pipelines in Canada, which match the amount of Northwest Pipeline capacity northward into Alberta, Canada.

We also have an agreement with Northwest Pipeline that extends into 2044 for approximately 350,000 therms per day of firm transportation capacity from the U.S. Rocky Mountain region.  Additionally, in 2008 we executed an agreement with a third party to take assignment of their firm transportation contract starting January 1, 2017, with the term extending through 2046.  This contract consists of 120,000 therms per day on Northwest Pipeline from the U.S. Rocky Mountain region.

In addition, we have firm long-term pipeline transportation contracts with two other major transporters located in Canada.  One contract extends through October 2014 and provides approximately 580,000 therms per day of firm gas transportation from Station 2 in northern British Columbia to the Huntingdon/Sumas connection with Northwest Pipeline at the U.S./Canadian border.  Another contract extends through October 2020 and provides approximately 480,000 therms per day of firm transportation from southeastern British Columbia to the same Huntingdon/Sumas connection with Northwest Pipeline.  Our capacity on this second contract is matched with companion contracts for pipeline capacity on the TransCanada systems in British Columbia and Alberta, allowing purchases to be made from the gas fields of Alberta, Canada.

Rates governing transportation of gas supplies

FERC establishes rates for interstate pipeline transportation service under long-term agreements within the U.S., and Canadian authorities establish rates for service under agreements with the Canadian pipelines over which we ship gas.

Gas Storage

Our gas storage segment primarily consists of two underground natural gas storage facilities, including the non-utility portion of our Mist gas storage facility near Mist, Oregon and our 75 percent ownership share of the Gill Ranch gas storage facility near Fresno, California.  Because transmission pipeline capacity and natural gas production are relatively constant over the course of a year compared to the demand for natural gas, which fluctuates daily and seasonally, natural gas storage facilities are needed to manage the flow and availability of gas supplies during periods of low demand so these supplies can be stored and delivered into markets during periods of high demand.  We capitalize on the imbalance of supply and demand for natural gas by providing our gas storage customers with the ability to store gas for resale or use in a higher value period.  Our natural gas storage facilities allow us to offer customers “multi-cycle” storage service, which permits them to inject and withdraw natural gas multiple times a year, providing more flexibility to capture market opportunities.  See Note 4 for more information on gas storage assets and results of operations for the three years ended December 31, 2011.

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Regulation and Rates

Our gas storage segment is subject to regulation with respect to, among other matters, rates, terms of services, and system of accounts established by the OPUC, WUTC and FERC with respect to the Mist facilities, and by the California Public Utilities Commission (CPUC) with respect to Gill Ranch.  Gill Ranch has a tariff on file with the CPUC authorizing it to charge market-based rates for the storage services offered.  FERC has approved maximum cost-based rates under our Mist interstate storage certificate, and at least every five years we are required to file with FERC either a petition for rate approval or a cost and revenue study to change or justify maintaining the existing rates for the interstate storage service.  For further information, See Part II, Item 7., “results of Operations – Regulatory Matters,” below.

Facilities

Mist Storage Facility. We provide gas storage services to customers in the interstate and intrastate markets from our Mist gas storage facilities located in Columbia County, Oregon, near the town of Mist.  The Mist field was converted to storage operations for our core local gas distribution customers.  Since 2001, we have made gas storage capacity at Mist available to interstate customers by developing new incremental capacity in advance of core utility customer requirements to meet the demands for interstate storage service.  These interstate storage services are offered under a limited jurisdiction blanket certificate issued by FERC. In addition, since 2005 we have offered firm storage services in Oregon under an OPUC-approved rate schedule as an optional service to eligible non-residential utility customers.  Currently, the Mist facilities consist of seven depleted natural gas reservoirs with a combined working gas capacity of approximately 16 Bcf, a combined deliverability of approximately 0.5 Bcf per day, a central compression facility, gathering pipelines and other related facilities.

In addition to earning revenue from storage contracts, we also contract with an independent energy marketing company to provide asset management services using our utility and non-utility storage and transportation capacity, the results of which are included in the gas storage business segment.  Pre-tax income from gas storage at Mist and third-party management services using our utility’s storage or transportation capacity is subject to revenue sharing with core utility customers.  In Oregon, 80 percent of the pre-tax income is retained by the gas storage segment when the costs of the capacity used have not been included in utility rates, and 33 percent of the pre-tax income is retained when the capacity costs have been included in utility rates. The remaining 20 percent and 67 percent of pre-tax income in each case are credited to a deferred regulatory account for refund to core utility customers. We have a similar sharing mechanism in Washington for pre-tax income derived from gas storage services and third-party asset management activities.

Gill Ranch Storage Facility. Gill Ranch Storage, LLC (Gill Ranch), our subsidiary, has a joint project agreement with Pacific Gas and Electric Company (PG&E) to develop and own the Gill Ranch underground natural gas storage facility near Fresno, California.  Currently, Gill Ranch owns a 75 percent undivided interest in this facility and is the sole operator of the facility.  The Gill Ranch facility began operations in the fourth quarter of 2010.

The Gill Ranch facility currently consists of three depleted natural gas reservoirs, twelve injection and withdrawal wells, a compressor station, dehydration and control equipment, gathering lines, an electric substation, a natural gas transmission pipeline extending 27 miles from the storage field to an interconnection with the PG&E transmission system, and other related facilities.  Gill Ranch owns the rights to 75 percent of the available storage capacity at the facility.  Gill Ranch’s share is designed to provide 15 Bcf of working gas capacity, which we expect to be in full use by the end of 2012.

Gill Ranch is offering storage services to the California market at market-based rates, subject to regulation by the CPUC for certain activities including, but not limited to, service terms and operating conditions.

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Assets.The following table highlights certain important design information about the Company’s non-utility gas storage assets.

	Storage			Withdrawal		Injection
	Capacity (Bcf)			(MMcf/day) 3		(MMcf/day) 3
Mist Storage1		6			258		103
Gill Ranch Storage		15	2		488		240

1.   Approximately 6 Bcf of a total 16 Bcf at Mist is currently available to our gas storage segment.  The remaining 10 Bcf is used to provide gas storage for our local distribution business and its utility customers. All storage capacity and daily deliverability currently developed for the gas storage segment at Mist is available for recall by the utility.

2.   Our share of the Gill Ranch facility is currently designed to provide 15 Bcf out of a total of 20 Bcf.

3.   Our share of the expected daily maximum injection and withdrawal rates.

Gas Storage Operations

Asset management.  With respect to the Mist gas storage facility, we contract with an independent energy marketing company to provide asset management services for our utility pipeline transportation contracts, our utility gas supplies and our unused utility and non-utility storage assets, primarily through the use of commodity transactions and pipeline capacity release transactions (see “Facilities—Mist Gas Storage Facility,” above).  Similarly, we contract with an independent energy marketing company to manage the value of our unused storage assets at the Gill Ranch gas storage facility (see “Facilities—Gill Ranch Gas Storage Facility,” above).  The results of asset management services at both facilities are included in the gas storage business segment, except for amounts allocated to our utility pursuant to regulatory sharing agreements involving the use of utility assets.

Seasonality of business.Generally, Mist gas storage revenues do not follow seasonal patterns similar to those experienced by the utility because most of the storage capacity is contracted with customers for firm service, and rates for firm service are primarily in the form of fixed monthly reservation charges and not affected by customer usage.  However, there is seasonal variation from the management of available surplus storage capacity and related transportation capacity.  Temporary surplus capacity is quite often available during the spring and summer months when the demand for gas by utility customers is low.

Although we expect much of the storage revenue at Gill Ranch to be in the form of fixed monthly demand charges, total cash flows from the Gill Ranch storage facility could be more seasonal in nature than the Mist storage facility.  A significant portion of operating costs at Gill Ranch is related to compression.  Because compression is used primarily for the injection of gas rather than for withdrawal, we expect power costs to be incurred disproportionately during the injection season.

Gas storage customers.For our Mist interstate storage services, firm service agreements with customers are entered into with terms typically ranging from 1 to 10 years.  Currently, our gas storage revenues from Mist are derived primarily from firm storage service customers who provide energy related services, including natural gas production or distribution, electric generation and energy marketing.  Three storage customers currently account for over 90 percent of our existing non-utility gas storage capacity at Mist, with the largest customer accounting for about half of total capacity.  These three customers have contracts that expire at various dates through April 2017.

Customer contracts for firm storage capacity at Gill Ranch are as long as 28 years in duration, but we expect Gill Ranch in the early years of operation to contract for terms mostly ranging from one to five years due to current market conditions.  Gill Ranch currently has several storage customers, with the largest single contract accounting for approximately 13 percent of the facility’s design capacity. The California market served by Gill Ranch is larger, and has a greater diversity of prospective customers, than the Pacific Northwest market served by Mist.  As such, we expect there to be less sensitivity to any single customer or group of customers for capacity at Gill Ranch. Current Gill Ranch customers provide energy related services, including natural gas production, marketing and electric generation.

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Competitive conditions.Our Mist gas storage facility benefits from limited competition from other Pacific Northwest storage facilities primarily because of its geographic location.  However, competition from other storage providers in the Pacific Northwest region and Canada, as well as competition for interstate pipeline capacity, does exist.  In the future, we could face increased competition from new or expanded gas storage facilities as well as from new natural gas pipelines, marketers and alternative energy sources.

The Gill Ranch storage facility competes with a number of other storage providers, including local integrated gas companies and other independent storage operators in the northern California market.  There is also ongoing expansions and proposed new construction of storage capacity in northern California that could increase competition for Gill Ranch.

Interstate gas storage.  The Mist gas storage facility currently provides firm and interruptible gas storage services with related transportation services on the utility’s system to and from Mist to interstate pipeline interconnections in order to serve customers in interstate commerce.  The interstate storage services, and maximum rates for these services, are authorized and regulated by the FERC.  The storage capacity used by this business segment has been developed as a non-utility investment by NW Natural in advance of core utility customers’ requirements.

Gill Ranch storage facility is not currently authorized to provide interstate gas storage services.

Intrastate gas storage.  The Mist gas storage facility provides intrastate gas storage services in Oregon under an OPUC-approved rate schedule that includes service eligibility and site-specific qualifications. The firm storage service rates, terms and conditions mirror our firm interstate storage service regulated by FERC, except that these customers are located and served in Oregon.

Gill Ranch provides intrastate storage services in California at market-based rates under a CPUC-approved tariff that includes firm storage service, interruptible storage service and park and loan storage services.

Storage Expansions.

Mist Storage Facility.  While the Pacific Northwest storage markets have been negatively impacted by lower gas prices and lack of price volatility, albeit less so than in California, we continue to plan for future expansion at Mist.  We believe the earliest timeframe for completing the next expansion is 2016.  In the meantime, we expect to continue working on preliminary design and project scope, which will likely include the development of storage wells, potentially a second compression station, and additional pipeline gathering facilities that would enable more storage expansions in the future.

Gill Ranch Storage Facility.  Subject to market demand, project execution, available financing, receipt of future permits, and other rights, Gill Ranch can be expanded beyond the current combined permitted capacity of 20 Bcf without further expansion of the takeaway pipeline system.  Taking these considerations into account and with certain infrastructure modifications, we currently estimate that the Gill Ranch storage facility could support an aggregate storage capacity of at least 40 Bcf, of which Gill Ranch would have the rights to an aggregate of 20 Bcf or 50 percent of total estimated storage capacity.

Other

We have non-utility investments and other business activities which are aggregated and reported as a business segment called “Other.” Although in the aggregate these investments and activities are not material, we identify and report them as a stand-alone segment because these investments and activities are not specifically related to our utility or gas storage segments.  This segment primarily consists of: an equity method investment in a joint venture to build and operate a gas transmission pipeline in Oregon (see Part II, Item 7., “2012 Outlook—Strategic Opportunities—Pipeline Diversification,” below); a minority interest in other pipeline assets held by our wholly-owned subsidiary NNG Financial; and other operating and non-operating expenses of the parent company that are not included in utility or gas storage operations.  Less than 1 percent of our consolidated assets and consolidated net income are related to activities in the “Other” business segment.  This pipeline is regulated by FERC.  See Note 4 for summary information on this Other segment’s assets and results of operations for the three years ended December 31, 2011.

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Environmental Issues

Properties and Facilities

We have properties and facilities that are subject to federal, state and local laws and regulations related to environmental matters.  These laws and regulations may require expenditures over a long timeframe to address certain environmental impacts.  Estimates of liabilities for environmental response costs are difficult to determine with precision because of the various factors that can affect their ultimate disposition.  These factors include, but are not limited to, the following:

·   the complexity of the site;

·   changes in environmental laws and regulations at the federal, state and local levels;

·   the number of regulatory agencies or other parties involved;

·   new technology that renders previous technology obsolete, or experience with existing technology that proves ineffective;

·   the ultimate selection of a particular technology;

·   the level of remediation required; and

·   variations between the estimated and actual period of time that must be dedicated to respond to an environmentally-contaminated site.

We own, or previously owned, properties currently being investigated that may require environmental response.  Based on our current assessment of regulatory and insurance recovery of environmental costs, we do not expect that the ultimate resolution of these matters will have a material adverse effect on our financial condition, results of operations or cash flows; however, if it is determined that both the insurance recovery and future rate recovery of such costs are not probable, then the costs not expected to be recovered will be charged to expense in the period such determination is made and could have a material impact on our financial condition or results of operations.  See Note 15 for a further discussion of potential environmental responses, related costs and regulatory and insurance recovery.

Greenhouse Gas Issues

We recognize that our businesses are likely to be impacted by carbon constraints. A variety of legislative and regulatory measures to address greenhouse gas emissions are in various phases of discussion or implementation. These include proposed international standards, proposed federal legislation, proposed or enacted federal regulations, and proposed or enacted state actions to develop statewide or regional programs, each of which has imposed or would impose measures to achieve reductions in greenhouse gas emissions. For example, in December 2009, the EPA published its findings that concentrations of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and the environment as drivers of climate change, and that emissions from motor vehicles contribute to that threat.  Based on these findings by the EPA, the agency proceeded with the adoption and implementation of regulations to regulate emissions of greenhouse gas starting in January 2011 from new motor vehicles and from stationary sources of air pollution such as power plants and oil refineries.  One of these new regulations, which the EPA refers to as the “Tailoring Rule,” requires that permits held by larger sources of air pollution address greenhouse gases, and also requires additional permitting and implementation of best available control technology for limiting greenhouse gas emissions at certain new facilities and at existing facilities when they implement modifications that increase emissions of greenhouse gas above threshold levels.  Lawsuits have been filed challenging the EPA’s regulation of greenhouse gas emissions, and members of the U.S. Congress have discussed proposing legislation that would limit the EPA’s ability to regulate greenhouse gas emissions.

In September 2009, the EPA issued a final rule requiring the annual reporting of greenhouse gas emissions from certain industries, specified large greenhouse gas emission sources, and facilities that emit 25,000 metric tons or more of CO2 equivalents per year.  The first reports were due on March 31, 2011 for emissions occurring on or after January 1, 2010.   Under this reporting rule, local gas distribution companies like NW Natural are required to report system throughput to the EPA on an annual basis.  The EPA also issued additional greenhouse gas reporting regulations requiring the annual reporting of fugitive emissions from our operations.  The first report under these more recent regulations is due by March 31, 2012. 

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The outcome of these and other international, federal and state climate change initiatives cannot be determined at this time, but these initiatives could produce a number of results including potential new regulations, legal actions, additional charges to fund energy efficiency activities, or other regulatory actions.  The adoption and implementation of any regulations limiting emissions of greenhouse gas from our operations could require us to incur costs to reduce emissions of greenhouse gas associated with our operations, which could result in an increase in the prices we charge our customers or a decline in the demand for natural gas.  On the other hand, because natural gas is a fossil fuel with relatively low carbon content, it is also possible that future carbon constraints could create additional demand for natural gas for electric generation, direct use of natural gas in homes and businesses, and as a reliable and relatively low-emission back-up fuel source for alternative energy sources.  Requirements to reduce greenhouse gas emissions from the transportation sector, such as those in Oregon’s low carbon fuel standard passed in 2009, could also result in additional demand for natural gas for use in vehicles.

We continue to take steps to address future greenhouse gas emission issues, including actively participating in policy development through participation on various Oregon taskforces and, at the federal level, within the American Gas Association.  We continue to engage in policy development and in identifying ways to reduce greenhouse gas emissions associated with our operations and our customers’ gas use, including offering the Smart Energy program, which allows customers to voluntarily contribute funds to projects such as biodigesters on dairy farms that offset the greenhouse gases produced from their natural gas use.

Employees

At December 31, 2011, the utility workforce consisted of 598 members of the Office and Professional Employees International Union (OPEIU) Local No. 11, AFL-CIO, and 452 non-union employees.  Our labor agreement with members of OPEIU that covers wages, benefits and working conditions extends to May 31, 2014, and thereafter from year to year unless either party serves notice of its intent to negotiate modifications to the collective bargaining agreement.

At December 31, 2011, our subsidiaries had a combined workforce of 21 non-union employees.  Our subsidiaries receive certain services from centralized operations at the utility, and as such the utility is reimbursed for those services pursuant to a Shared Services Agreement.

Additions to Infrastructure

We make capital expenditures in order to maintain and enhance the safety and integrity of our pipelines, terminals, storage facilities and related assets, to expand the reach or capacity of those assets, or improve the efficiency of our operations to pursue new business opportunities. We expect to make a significant level of capital expenditures for additions to utility and gas storage infrastructure over the next five years, reflecting continued investments in customer growth, technology, distribution system improvements and gas storage facilities.  In 2012, utility capital expenditures are estimated to be between $145 and $160 million, and non-utility capital investments are estimated to be between $10 and $15 million.  For the five-year period ending in 2016, capital expenditures for the utility are estimated to be between $400 and $500 million, while the amount for gas storage and other investments after 2012 will depend largely on future decisions about potential expansion opportunities in gas storage and pipeline projects.

Executive Officers of the Registrant

For information concerning our executive officers, see Part III, Item 10.

Available Information

We file annual, quarterly and special reports and other information with the Securities and Exchange Commission (SEC). Reports, proxy statements and other information filed by us can be read and copied at the Public Reference Room of the SEC, 100 F Street, N.E., Washington, D.C. 20549. You can obtain additional information about the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website (http://www.sec.gov) that contains reports, proxy and information statements and other information that we file electronically. In addition, we make available on our website (http://www.nwnatural.com), our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) and proxy materials filed under Section 14 of the Securities Exchange Act of 1934, as amended (Exchange Act), as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

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We have adopted a Code of Ethics for all employees and officers that is available on our website. We intend to disclose amendments to, and any waivers from the Code of Ethics on our website.  Our Corporate Governance Standards, Director Independence Standards, charters of each of the committees of the Board of Directors and additional information about us are also available at the website. Copies of these documents may be requested, at no cost, by writing or calling Shareholder Services, NW Natural, One Pacific Square, 220 N.W. Second Avenue, Portland, Oregon 97209, telephone 503-226-4211 ext. 3412.

ITEM 1A. RISK FACTORS

Our business and financial results are subject to a number of risks and uncertainties, many of which are not within our control.  When considering any investment in our securities, investors should carefully consider the following information, as well as information contained in the caption “Forward-Looking Statements,” Item 7A., and other documents we file with the SEC.   This list is not exhaustive and the order of presentation does not reflect management’s determination of priority or likelihood.  Additionally, our listing of risk factors that primarily affect one of our business segments does not indicate that such risk factor is inapplicable to our other business segments.

Risks Related to our Business Generally

Regulatory risk.  Regulation of our businesses, including changes in the regulatory environment in general, and failure of regulatory authorities to approve rates which provide for timely recovery of our costs and an adequate return on invested capital in particular, or an unfavorable outcome in ratemaking proceedings may adversely impact our financial condition and results of operations.

The OPUC and WUTC have general regulatory authority over our utility business in Oregon and Washington, respectively, including the rates charged to customers, authorized rates of return on capital invested, the amounts and types of securities we may issue, services we provide, facilities we own or operate, terms of customer services, system of accounts, the nature of investments we may make, safety standards, deferral and recovery of  various expenses, including, but not limited to, pipeline replacement and environmental remediation costs, transactions with affiliated interests, actions investors may take with respect to our company and other matters.  Similarly, in our gas storage business FERC has regulatory authority over interstate storage services, and the CPUC has regulatory authority over our Gill Ranch storage operations.

The prices that the OPUC and WUTC allow us to charge for retail service, and the tariff rate that the Federal Energy Regulatory Commission permits us to charge for transmission, are the most significant factors affecting our financial position, results of operations and liquidity.  The OPUC and WUTC have the authority to disallow recovery of any costs they consider unreasonable or imprudently incurred, and the rates allowed by the FERC may be insufficient for recovery of costs incurred.  For example, we expect to continue to make expenditures to expand, improve and operate our utility distribution and gas storage systems.  Regulators can deny such expansions or improvements or recovery of expenditures we make if they find that such expenditures were not prudently incurred according to their regulatory standards.  Additionally, while the OPUC and WUTC have established through the ratemaking process an authorized rate of return for our utility, the regulatory process does not provide assurance that we will be able to achieve the earnings level authorized.

Moreover, in the normal course of business we may place assets in service or incur higher than expected levels of operating expense before rate cases can be filed to recover those costs—this is commonly referred to as “regulatory lag.”  The failure of any regulatory commission to approve requested rate increases on a timely basis to recover increased costs or to allow an adequate return could adversely impact our financial condition and results of operations.

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We filed a general rate case in Oregon on December 30, 2011.  While the OPUC is required to establish rates that are fair, just and reasonable, they have significant discretion in applying this standard.  The ratemaking process typically involves multiple parties, including governmental agencies, consumer advocacy groups, and others who are impacted by the use of natural gas.  Each party has differing concerns, but all generally have the same common objective of limiting rate increases or even reducing rates.  Our rate case proposes to establish rates based on forecasted operating and capital expenditures that rely on many assumptions concerning future conditions and operating results.  In the ratemaking process, regulators and interveners can challenge these assumptions and may assert different assumptions or apply different interpretations to the data.  We cannot predict the ultimate outcome of any ratemaking proceeding, including the extent to which certain costs, such as significant capital projects, are recoverable; what rates of return will be allowed; and whether, or in what form, our regulatory mechanisms, such as our weather normalization mechanism or conservation tariff, will be renewed.  Additionally, we may agree to conditions as part of a settlement or regulatory proceeding, or there may be determinations made in regulatory investigations, that reduce our earnings and liquidity, all of which could adversely affect our results of operations and financial condition.

Economic risk.  Changes in the economy and in the financial markets may have a negative impact on our financial condition and results of operations.

Changes in economic activity in our markets and in global financial markets can result in a decline in or sustained lower levels of energy consumption, which could have a negative effect on our financial condition and results of operations.  In recent years, the U.S. and world economies have slowed, credit markets have tightened, unemployment rates and mortgage defaults have risen, and the value of homes and other personal as well as business investments have declined, which has adversely affected the income and financial resources of many domestic households and businesses.  It is unclear whether the federal responses, as well as international, to these conditions will lessen the severity or duration of this economic downturn, or could possibly trigger inflationary conditions.  Our operations and financial results are affected by these economic conditions.  Less new housing construction, fewer conversions to natural gas, fewer customer additions, higher levels of residential foreclosures and vacancies, tighter lending restrictions, higher levels of personal and business bankruptcies or reduced spending could all result in a decline in or sustained lower levels of energy consumption and customer growth, a slowing of collections from our customers, and higher levels of delinquent accounts receivable and bad debts, all of which could have a negative effect on our financial condition and results of operations.

Environmental liability risk.  Certain of our properties and facilities may pose environmental risks requiring remediation, the cost of which could adversely affect our financial condition, results of operations and cash flows.

We own, or previously owned, properties that require environmental remediation or other action.  We accrue all material loss contingencies relating to these properties.  A regulatory asset at the utility has already been recorded for estimated costs pursuant to a deferral order from the OPUC and WUTC. To the extent we are unable to recover these deferred costs in utility customer rates or through insurance, we would be required to reduce our regulatory asset which would result in a charge to current year earnings.  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.  

We cannot predict with certainty the amount or timing of future expenditures related to environmental investigation and remediation that may be required, or disputes arising in relation thereto or the outcomes of those disputes, because of the difficulty of estimating such costs.  There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liabilities on all potentially responsible parties.  This uncertainty and disputes arising therefrom could lead to adversarial administrative proceedings or litigation, with associated costs and uncertain outcomes, all of which could adversely affect our financial condition, results of operations and cash flows.

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      Business development risk. The development, construction, startup and operation of our business development projects may involve unanticipated changes or delays that could negatively impact our costs as well as our financial condition, results of operations and cash flows.

 Business development projects involve many risks.  We are currently engaged in several business development projects, including, but not limited to, the early planning and development stage on the Palomar gas transmission pipeline in Oregon.  We may also engage in other business development projects in the future, including expansion of our gas storage facilities at Mist or Gill Ranch, or the investment in additional long-term gas reserves.  With respect to these projects, we may not be able to obtain required governmental permits and approvals, or financing, to complete our projects in a cost-efficient or timely manner.  If we do not obtain the necessary regulatory approvals in a timely manner, development projects may be delayed or abandoned.  There also may be startup and construction delays, construction cost overruns, inability to negotiate acceptable agreements such as rights-of-way, easements, construction, gas supply or other material contracts, changes in customer demand or commitment, public opposition to projects, changes in market prices, and operating cost increases.   Additionally, natural gas storage and transportation markets are highly competitive, both within the natural gas industry and with alternative sources of energy.  To fund our business development projects, we will need to secure financing from willing investors at reasonable costs.  We may be unable to finance our business development projects at acceptable interest rates or within a scheduled timeframe for completing the project.   One or more of these events could result in the project becoming impaired, and such impairment could have an adverse effect on our financial condition and results of operations.

Joint partner risk.  Investing in business development projects through partnerships, joint ventures or other business arrangements affects our ability to manage certain risks and could adversely impact our financial condition, results of operations and cash flows.

We use joint ventures and other business arrangements to manage and diversify the risks of certain utility and non-utility development projects, including Palomar pipeline, Gill Ranch storage and Encana gas reserves.  Also, we may acquire or develop part-ownership interests in other similar projects in the future.  Under these types of business arrangements, we may not be able to fully direct the management and policies of the business relationships, and other participants in those relationships may take action contrary to our interests including making operational decisions that could affect our costs and liabilities related to a project.  In addition, other participants may withdraw from the project, become financially distressed or bankrupt, or have economic or other business interests or goals that are inconsistent with ours.  With respect to our gas reserves venture, the drilling of new wells for gas may not produce the expected volumes of gas, or any gas. Additionally, environmental regulations may require operational improvements to mitigate potential environmental damage, increasing operating costs to us.  Although we have contractual and other legal remedies to mitigate these risks and enforce our interests, dry wells, increased operational costs, or a participant in one of these business arrangements acting contrary to our interests, it could adversely impact the project as well as our financial condition, results of operations and cash flows.

Global climate change risk. Future legislation may impose carbon constraints to address global climate change, exposing us to regulatory and financial risk.  Additionally, certain properties and facilities may be subject to physical risks associated with climate change.

There are a number of new international, federal and state legislative and regulatory initiatives being proposed and adopted in an attempt to measure, control or limit the effects of global warming and overall climate change, including greenhouse gas emissions such as carbon dioxide.  The adoption of current or future proposed legislation by the U.S. Congress or similar legislation by states, or the adoption of related regulations by federal or state regulatory bodies such as the EPA, imposing reporting obligations on, or limiting emissions of greenhouse gases from our equipment or operations could have far-reaching and significant impacts on our business as well as the broader energy industry.  Such current or future legislation or regulation could also impose on us operational requirements or restrictions or additional charges to fund energy efficiency initiatives.  Such initiatives could result in us incurring additional costs to comply with the imposed restrictions, provide a cost advantage to energy sources other than natural gas, reduce demand for natural gas, impose costs or restrictions on end users of natural gas, impact the prices we charge our customers, impose on us increased costs associated with the adoption of new infrastructure and technology to respond to such requirements,  and may impact cultural perception of our service or products negatively, diminishing the value of our brand, all of which could adversely affect our business practices, financial condition and results of operations.

Climate change may cause physical risks, including an increase in sea level, intensified storms, water scarcity and changes in weather conditions, such as changes in precipitation, average temperatures and extreme wind or other climate conditions.  A significant portion of the nation’s gas infrastructure is located in areas susceptible to storm damage that could be aggravated by wetland and barrier island erosion, which could give rise to gas supply interruptions and price spikes.

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These and other physical changes could result in changes in customer demand, increased costs associated with repairing and maintaining distribution systems resulting in increased maintenance and capital costs, increased financing needs, limits on our ability to meet peak customer demand, increased regulatory oversight, and lower customer satisfaction.  Also, to the extent that climate change adversely impacts the economic health of our region, it may adversely impact customer demand and revenues.  Such physical risks could have an adverse effect on our financial condition, results of operations, and cash flows.

Operating risk.  Transporting and storing natural gas involves numerous risks that may result in accidents and other operating risks and costs, some or all of which may not be fully covered by insurance, and which could adversely affect our financial condition, results of operations and cash flows.

Our operations are subject to all of the risks and hazards inherent in the businesses of local gas distribution and storage, including:

Ÿearthquakes, floods, storms, landslides and other adverse weather conditions and hazards;

Ÿ  leaks or other losses of natural gas or other hydrocarbons as a result of the malfunction of equipment or facilities;

Ÿdamages from third parties, including construction, farm and utility equipment or other surface users;

Ÿoperator errors;

Ÿ       negative unpredicted performance by our storage reservoirs that could cause us to fail to meet expected or forecasted operational levels or contractual commitments to our customers;

Ÿ       problems maintaining, or the malfunction of, pipelines, wellbores and related equipment and facilities that form a part of the infrastructure that is critical to the operation of our gas distribution and storage facilities;

Ÿcollapse of underground storage caverns;

Ÿ       migration of natural gas through faults in the rock or to some area of the reservoir where existing wells cannot drain the gas effectively;

Ÿblowouts (uncontrolled escapes of gas from a pipeline or well) or other accidents, fires and explosions; and

Ÿ       risks and hazards inherent in the drilling operations associated with the development of the gas storage facilities and/or wells.

These risks could result in personal injury or loss of human life, damage to and destruction of property and equipment, pollution or other environmental damage, breaches of our contractual commitments, and may result in curtailment or suspension of our operations, which in turn could lead to significant costs and lost revenues.  Further, because our pipeline, storage and distribution facilities are in or near populated areas, including residential areas, commercial business centers, and industrial sites, any loss of human life or adverse financial outcome resulting from such events could be significant.  Natural gas that moves outside of the effective drainage area through migration could be permanently lost and would need to be replaced.  Additionally, we may not be able to obtain the level or types of insurance we desire, and the insurance coverage we do obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses.  The occurrence of any operating risks not covered by insurance could adversely affect our financial condition, results of operations and cash flows.

Business continuity risk.  We may be adversely impacted by local or national disasters, pandemic illness, terrorist activities and other extreme events to which we may not able to promptly respond.

Local or national disasters, pandemic illness, terrorist activities and other extreme events are a threat to our assets and operations.  Companies in our industry may face a heightened risk due to exposure to acts of terrorism that could target or impact our natural gas distribution, transmission or storage facilities and result in a disruption in our operations and ability to meet customer requirements.  In addition, the threat of terrorist activities could lead to increased economic instability and volatility in the price of natural gas that could affect our operations.  Threatened or actual national disasters or terrorist activities may also disrupt capital markets and our ability to raise capital, or impact our suppliers or our customers directly.  Local disaster or pandemic illness could result in part of our workforce being unable to operate or maintain our infrastructure or perform other tasks necessary to conduct our business.  We maintain emergency planning and training programs to remain ready to respond to events that could cause business interruption.  However, a slow or inadequate response to events may have an adverse impact on operations and earnings.  We may not be able to obtain sufficient insurance to cover all risks associated with local and national disasters, pandemic illness, terrorist activities and other events, which could increase the risk that an event could adversely affect our operations or financial results.

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Employee benefit risk.The cost of providing pension and postretirement healthcare benefits is subject to changes in pension assets and liabilities, changing employee demographics and changing actuarial assumptions, which may have an adverse effect on our financial condition, results of operations and cash flows.

We provide pension plans and postretirement healthcare benefits to most eligible full-time employees and retirees. Our cost of providing such benefits is subject to changes in the market value of our pension assets, changes in employee demographics including longer life expectancies, increases in healthcare costs, current and future legislative changes including but not limited to the Health Care Reform Act in 2010, and various actuarial calculations and assumptions. The actuarial assumptions used to calculate our future pension and postretirement healthcare expense may differ materially from actual results due to significant market fluctuations and changing withdrawal rates, wage rates, interest rates and other factors. These differences may result in an adverse impact on the amount of pension contributions, pension expense or other postretirement benefit costs recorded in future periods.  Sustained declines in equity markets and reductions in bond rates may have a material adverse effect on the value of our pension fund assets. In these circumstances, we may be required to recognize increased contributions and pension expense earlier than we had planned to the extent that the value of pension assets is less than the total anticipated liability under the plans, which could have a negative impact on financial condition, results of operations and cash flows.

Workforce risk.  Our business is heavily dependent on being able to attract and retain qualified employees and maintain a competitive cost structure with market-based salaries and employee benefits, and workforce disruptions could adversely affect our operations and results.

Our ability to implement business strategy and serve our customers is dependent upon our continuing ability to attract and retain talented professionals and a technically skilled workforce, and being able to transfer the knowledge and expertise of our workforce to new employees as our aging employees retire.  Without an appropriately skilled workforce, our ability to provide quality service and meet our regulatory requirements will be challenged and this could negatively impact our earnings.  Additionally, within our utility segment a majority of our workers are represented by the Office and Professional Employees International Union Local No.11 AFL-CIO (the Union), and are covered by a collective bargaining agreement that extends to May 31, 2014.  Disputes with the Union over terms and conditions of the agreement could result in instability in our labor relationship and work stoppages that could impact the timely delivery of gas and other services from our utility and Mist gas storage, which could strain relationships with customers and state regulators and cause a loss of revenues.  Our collective bargaining agreement may also increase the cost of employing our Union workforce, affect our ability to continue offering market-based salaries and employee benefits, limit our flexibility in dealing with our workforce, and limit our ability to change work rules and practices and implement other efficiency-related improvements to successfully compete in today’s challenging marketplace, which may negatively affect our financial condition and results of operations.

Legislative and taxing authority risk.  We are subject to governmental regulation, and compliance with local, state and federal requirements, including taxing requirements, and unforeseen changes in or interpretations of such requirements could affect our financial condition and results of operations.

We are subject to regulation by federal, state and local governmental authorities.  We are required to comply with a variety of laws and regulations and to obtain authorizations, permits, approvals and certificates from governmental agencies in various aspects of our business.  We cannot predict with certainty the impact of any future revisions or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to them.  Changes in regulations or the imposition of additional regulations could negatively influence our operating environment and results of operations.  

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Additionally, changes in federal, state or local tax laws and their related regulations, or differing interpretation or enforcement of applicable law by a federal, state or local taxing authority, could result in substantial cost to us and negatively affect our results of operations.  Tax law and its related regulations and case law are inherently complex and dynamic.  Disputes over interpretations of tax laws may be settled with the taxing authority in examination, upon appeal or through litigation.  Our judgments may include reserves for potential adverse outcomes regarding tax positions that have been taken that may be subject to challenge by taxing authorities.  Changes in laws, regulations or adverse judgments may negatively affect our financial condition and results of operations.

Environmental regulation risk.  We are subject to environmental regulations which could adversely affect our operations or financial results.

We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local governmental authorities relating to protection of the environment and health and safety matters, including those legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and waste, the clean-up of contaminated sites, groundwater quality and availability, plant and wildlife protection, as well as work practices related to employee health and safety.  Revised environmental regulations which result in increased compliance costs or additional operating restrictions could have an adverse effect on our financial condition and results of operations, particularly if those costs are not fully recoverable from insurance or through utility customer rates.

Environmental legislation also requires that our facilities, sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities.  Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties or interruptions in our operations that could adversely affect our financial results.

Safety regulation risk. We may experience increased federal, state and local regulation of the safety of our systems and operations, which could adversely affect our operating costs and financial results.

The safety and protection of the public, our customers and our employees is and will remain our top priority.  We are committed to consistently monitoring and maintaining our distribution system and storage operations to ensure that natural gas is acquired, stored and delivered safely, reliably and efficiently.  However, we anticipate companies in the natural gas distribution business may be subjected to even greater federal, state and local regulatory oversight over the safety of their operations.  We intend to work diligently with industry associations and federal and state regulators to ensure compliance with the new laws, such as the “Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011” signed into law in early 2012.  Although we believe these costs will ultimately be recoverable through our rates to customers, the costs of complying with such increased regulation could have at least a short-term negative impact on our operating costs and financial results.

Hedging risk.  Our risk management policies and hedging activities cannot eliminate the risk of commodity price movements and other financial market risks, and our hedging activities may expose us to additional liabilities for which rate recovery may be disallowed, which could result in an adverse impact on our operating revenues, costs, derivative assets and liabilities and operating cash flows.

In our utility segment, our gas purchasing requirements expose us to risks of commodity price movements, while our use of debt and equity financing exposes us to interest rate, liquidity and other financial market risks. We attempt to manage these exposures and mitigate our risks through adherence to established risk limits and risk management procedures, including hedging activities that are in accordance with our policy guidelines. We use both financial and physical hedging mechanisms, including our recent gas reserve transaction in which we are acquiring long-term gas reserves through an investment with Encana Oil & Gas (USA).  These risk limits and risk management procedures may not always work as planned and cannot entirely eliminate the risks associated with hedging.  Additionally, our hedging activities may cause us to incur additional expenses which could adversely impact our financial condition, results of operations, and cash flows.

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     We do not hedge our entire interest rate or commodity cost exposure, and the unhedged exposure will vary over time. Gains or losses experienced through hedging activities, including carrying costs, generally flow through the PGA mechanism or are recovered in future general rate cases, thereby limiting our exposure to earnings volatility on a year-to-year basis.  However, the hedge transactions we enter into for the utility are subject to a prudency review by the OPUC and WUTC, and, if deemed imprudent, those expenses may be disallowed, which could have an adverse effect on our financial condition and results of operations.  In addition, actual business requirements and available resources may vary from forecasts, which are used as the basis for our hedging decisions, and could cause our exposure to be more or less than we anticipated.  Moreover, if our derivative instruments and hedging transactions do not qualify for hedge accounting under generally accepted accounting standards, our hedges may not be effective and our results of operations and financial condition could be adversely affected.

We also have credit-related exposure to derivative counterparties.  In general, we require our counterparties to have an investment-grade credit rating at the time the derivative instrument is entered into, and we specify limits on the contract amount and duration based on each counterparty’s credit rating.  Nevertheless, counterparties owing us money or physical natural gas commodities could breach their obligations.  Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements to meet our normal business requirements.  In that event, our financial results could be adversely affected.  Although our valuations take into account the expected probability of default and the potential loss due to a default by our counterparties, an actual default by a particular counterparty could have a greater impact than we estimate.  Additionally, under most of our hedging arrangements, any downgrade of our senior unsecured long-term debt credit rating could allow our counterparties to require us to post cash, a letter of credit or other form of collateral, which would expose us to additional costs and may trigger significant increases in borrowing from our credit facilities if the credit rating downgrade is below investment grade.

Inability to access capital market risk.  Our inability to access capital, or significant increases in the cost of capital, could adversely affect our financial condition and results of operations.

Our ability to obtain adequate and cost effective short-term and long-term financing depends on maintaining investment grade credit ratings as well as the existence of liquid and stable financial markets.  Our businesses rely on access to capital markets, including commercial paper, bond and equity markets, to finance our operations, construction expenditures and other business requirements, and to refund maturing debt that cannot be funded entirely by internal cash flows.  Disruptions in the capital markets could adversely affect our ability to access short-term and long-term financing.  Our access to funds under committed short-term credit facilities, which are currently provided by a number of banks, is dependent on the ability of the participating banks to meet their funding commitments.  Those banks may not be able to meet their funding commitments if they experience shortages of capital and liquidity.  Disruptions in the bank or capital financing markets as a result of economic uncertainty, changing or increased regulation of the financial sector, or failure of major financial institutions could adversely affect our access to capital and negatively impact our ability to run our business and make strategic investments.

A negative change in our current credit ratings, particularly below investment grade, could adversely affect our cost of borrowing and access to sources of liquidity and capital.  Such a downgrade could further limit our access to borrowing under available credit lines.  Additionally, downgrades in our current credit ratings below investment grade could cause additional delays in accessing the capital markets by the utility while we seek supplemental state regulatory approval, which could hamper our ability to access credit markets on a timely basis.  A credit downgrade could also require additional support in the form of letters of credit, cash or other forms of collateral and otherwise adversely affect our financial condition and results of operations.

Changes in accounting standards.  Changes in accounting standards may adversely impact our financial condition and results of operations.

Our business is currently subject to accounting standards issued by the Financial Accounting Standards Board. Changes in these standards could adversely impact our financial condition or results of operations. Recently, the SEC has been considering whether issuers in the United States should be required to prepare financial statements in accordance with International Financial Reporting Standards (IFRS) instead of the current generally accepted accounting principles (GAAP) in the United States. IFRS is a comprehensive set of accounting standards promulgated by the International Accounting Standards Board (IASB), which are currently in effect for most other countries in the world.  If the SEC decides to adopt IFRS, we expect that U.S. companies would not be required to report under these new standards until 2015 or 2016 at the earliest. Unlike U.S. GAAP, IFRS does not currently provide an industry accounting standard for rate-regulated activities. As such, if IFRS were adopted in its current state, we may be precluded from applying certain regulatory accounting principles, including the recognition of certain regulatory assets and regulatory liabilities. The potential issues associated with rate-regulated accounting, along with other potential changes associated with the adoption of IFRS, may have a significant impact on our financial condition and results of operations.  Also, the U.S. Financial Accounting Standards Board is considering several changes to U.S. GAAP, some of which may be significant, as part of a joint effort with the IASB to converge accounting standards over the next several years. If approved, adoption of these changes may adversely impact our financial condition and results of operations.

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Risks Related Primarily to Our Local Utility Business

Gas price risk.  Higher natural gas commodity prices and volatility in the price of gas may adversely affect our results of operations and cash flows.

The cost of natural gas is affected by a variety of factors, including weather, changes in demand, the level of production and availability of natural gas supplies, imports and exports of natural gas, transportation constraints, availability of pipeline capacity, transportation capacity cost increases, federal and state energy and environmental regulation and legislation, the degree of market liquidity, supply disruption, natural disasters, wars and other catastrophic events, national and worldwide economic and political conditions, and the price and availability of alternative fuels.  In our utility segment, the cost we pay for natural gas at the utility is generally passed through to our customers through an annual PGA rate adjustment.  Recent years have seen a substantial decline in natural gas prices as new drilling technologies have been employed to produce abundant U.S. supplies of natural gas.  If this trend in commodity prices were to reverse and thereby result in significant increases in the commodity price of natural gas, it would raise the cost of energy to our utility customers, potentially causing those customers to conserve or switch to alternate sources of energy.  Significant price increases could also cause new home builders and commercial developers to select heating systems other than natural gas.  Decreases in the volume of gas we sell could reduce our earnings in the absence of decoupled rate structures, and a decline in customers could slow growth in our future earnings.

Higher gas prices may also cause us to experience an increase in short-term debt and temporarily reduce liquidity because we pay suppliers for gas when it is purchased, which can be several months or even a year in advance of when these costs are recovered through rates.  Significant increases in the price of gas can also slow our collection efforts as customers experience increased difficulty in paying their higher energy bills, leading to higher than normal delinquent accounts receivable.  This could contribute to higher short-term debt levels, greater expense associated with collection efforts and increased bad debt expense.

In Oregon and Washington, our utility has PGA tariffs which provide for annual revisions in rates resulting from changes in the cost of purchased gas including the expected impact on bad debt expense.  The Oregon PGA tariff provides an incentive to the Company to achieve lower gas costs such that a small percentage, set annually, of any cost savings (i.e. the difference between the estimated average PGA gas cost in rates and the actual average gas cost incurred) be recognized as current income or expense.  Accordingly, higher average gas costs than those assumed in setting rates can adversely affect our operating cash flows, liquidity and results of operations. Notwithstanding our current rate structure, higher gas costs could result in increased pressure on the OPUC or the WUTC to seek other means to reduce rates, which also could adversely affect our results of operations and cash flows.

Customer growth risk.  Our utility margin, earnings and cash flow may be negatively affected if we are unable to sustain customer growth rates in our local gas distribution segment.

Our utility margins and earnings growth have largely depended upon the sustained growth of our residential and commercial customer base due, in part, to the new construction housing market, conversions of customers to natural gas from other fuel sources and growing commercial use of natural gas.  Continued weakness in the residential new construction and conversion markets, and continued decline in average use of natural gas by our residential and commercial customers, could result in an adverse long-term impact on our utility margin, earnings and cash flows.

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Risk of competition.  Our gas distribution business is subject to increased competition which could negatively affect our results of operations.

In the residential market, our gas distribution business competes primarily with suppliers of electricity, fuel oil, propane, and renewable energy providers. We also compete with suppliers of electricity, fuel oil and renewable energy providers for commercial applications. In the industrial market, we compete with suppliers of all forms of energy, including oil, electricity, renewable energy providers and, as it relates to sources of energy for electric power plants, coal and hydro. Competition among these forms of energy is based on price, efficiency, reliability, performance, market conditions, technology, environmental impacts and public perception.

Higher natural gas prices have at times eroded, or in some cases eliminated, the competitive price advantage of natural gas over other energy sources.  Technological improvements in other energy sources such as heat pumps could also erode our competitive advantage.  If natural gas prices rise relative to other energy sources, or if the cost or environmental impact of other energy sources improves relative to natural gas, it may negatively affect our ability to attract new customers or retain our existing residential, commercial and industrial customers, which could have a negative impact on our customer growth rate and results of operations.

Reliance on third parties to supply natural gas risk.  We rely on third parties to supply substantially all of the natural gas in our distribution segment, and limitations on our ability to obtain supplies, or failure to receive expected supplies for which we have contracted, could have an adverse impact on our financial results.

Our ability to secure natural gas for current and future sales depends upon our ability to purchase and receive delivery of supplies of natural gas from third parties, as well as our ability to acquire supplies directly from new sources.  Certain factors including the following may affect our ability to acquire and deliver natural gas to our current and future customers: suppliers’ or other third parties’ control over drilling of new wells and operating facilities to transport natural gas to our distribution system; competition for the acquisition of natural gas; priority allocations on transmission pipelines; impact of severe weather disruptions to natural gas supplies; failure of third parties to deliver gas for which we have contracted; the regulatory and pricing policies of federal, state and local government agencies; and the availability of Canadian reserves for export to the United States.  If we are unable to obtain, or are limited in our ability to obtain, natural gas from our current suppliers or new sources, our financial results could be adversely impacted.

Single transportation pipeline risk.  We rely on a single pipeline company for the transportation of gas to our service territory, a disruption of which could adversely impact our ability to meet our customers’ gas requirements.

Our distribution system is directly connected to a single interstate pipeline, which is owned and operated by Northwest Pipeline.  The pipeline’s gas flows are bi-directional, transporting gas into the Portland metropolitan market from two directions: (1) the north, which brings supplies from the British Columbia and Alberta supply basins; and (2) the east, which brings supplies from the Alberta and the U.S. Rocky Mountain supply basins.  If there is a rupture or inadequate capacity in the pipeline, we may not be able to meet our customers’ gas requirements and we would likely incur costs associated with actions necessary to mitigate service disruptions, both of which could significantly and negatively impact our results of operations.

Weather risk.  Warmer than average weather or a failure to renew our weather normalization mechanism may have a negative impact on our revenues and results of operations.

We are exposed to weather risk primarily in our utility segment.  A majority of our volume is driven by gas sales to space heating residential and commercial customers during the winter heating season. Current utility rates are based on an assumption of average weather.  Warmer than average weather typically results in lower gas sales.  Colder weather typically results in higher gas sales.  Although the effects of warmer or colder weather on utility margin in Oregon are expected to be mitigated through the operation of our weather normalization mechanism, weather variations from normal could adversely affect utility margin because we may be required to purchase more or less gas at spot rates, which may be higher or lower than the rates assumed in our PGA.  Also, approximately 9 percent of our Oregon residential and commercial customers have opted out of the weather normalization mechanism, and 10 percent of our customers are located in Washington where we do not have a weather normalization mechanism.  Furthermore, continuation of the weather normalization mechanism in Oregon after October 2012 is subject to regulatory approval.  As a result, we may not be fully protected against warmer than average or colder than average weather, both of which may have an adverse effect on our financial condition, results of operations and cash flows.

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     Customer conservation risk.  Customers’ conservation efforts or a failure to renew our conservation tariff may have a negative impact on our revenues.

An increasing national focus on energy conservation, including improved building practices and appliance efficiencies, may result in increased energy conservation by customers, which can decrease our sales of natural gas and adversely affect our results of operations.  In Oregon, we have a conservation tariff which is designed to recover lost margin due to declines in residential and commercial customers’ consumption.  The conservation tariff is scheduled to expire in October 2012.  The failure of the OPUC to extend the conservation tariff in the future could adversely affect our financial condition, results of operations and cash flows.  We do not have a conservation tariff in Washington, so our results of operations are negatively affected by increasing conservation efforts.

Business improvements risk.  Our efforts to integrate, consolidate and streamline our operations have resulted in increased reliance on technology, the failure or security breach of which could adversely affect our financial condition and results of operations.

Over the last several years we have undertaken a variety of initiatives to integrate, standardize, centralize and streamline our operations.  These efforts have resulted in greater reliance on technological tools such as:  an enterprise resource planning system, which provides an integrated suite of business application software; an automated dispatch system, which provides integrated planning, scheduling and dispatching of field resources; an automated meter reading system, which allows for electronic reading of customers meters; a customer information system, which allows us to calculate and bill customers for gas service including adjustments such as the weather normalization impact; and other similar technological tools and initiatives.  The failure of any of these or other similarly important technologies, or our inability to have these technologies supported, updated, expanded or integrated into other technologies, could adversely impact our operations. Although we have, when possible, developed alternative sources of technology and built redundancy into our computer networks and tools, there can be no assurance that these efforts to date would protect us against all potential issues or disaster occurrences related to the loss of any such technologies or their use.

Furthermore, our operations are subject to cyber-security risks related to breaches in technologies that are used in our natural gas distribution and storage operations and other business processes.Additionally, our utility is subject to breaches of security pertaining to sensitive customer, employee and vendor information maintained by the utility in the normal course of business.  Although we have preventive and detective measures in place to reduce the risk of such security breaches, they could occur and result in a loss of confidential or proprietary data or security breaches of other technology business tools, which could adversely affect the utility’s reputation, diminish customer confidence, disrupt operations, and subject us to possible financial liability or increased regulation or litigation, any of which could adversely affect our financial condition and results of operations.

Risks Related Primarily to Our Gas Storage Business

Long-term stabilization of gas price risk. Any significant stabilization of natural gas prices could have a negative impact on the demand for our natural gas storage services, which could adversely affect our financial results.

Storage businesses benefit from price volatility, which impacts the level of demand for services and the rates that can be charged for storage services. On a system-wide basis, natural gas is typically injected into storage between April and October when natural gas prices are generally lower and withdrawn during the winter months of November through March when natural gas prices are typically higher. However, the market for natural gas may not continue to experience volatility and seasonal price sensitivity in the future at the levels previously seen. Largely due to the abundant supply of natural gas made available by hydraulic fracturing techniques, natural gas prices have dropped significantly to levels that are near a 10-year low.  If prices and volatility remain low or decline further, then the demand for storage services, and the prices that we will be able to charge for those services, may decline or be depressed for a prolonged period of time.  A sustained decline in these prices could have an adverse impact on our financial condition, results of operations and cash flows.

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Natural gas storage competition risk.Increasing competition in the natural gas storage business could reduce the demand for our storage services and  drive prices down for storage, which could adversely affect our financial condition, results of operation and cash flows.

Our natural gas storage segment competes primarily with other storage facilities and pipelines.   Natural gas storage is an increasingly competitive business, with ongoing expansions and proposed construction of new storage capacity in California, the U.S. Rocky Mountains and elsewhere in the United States and Canada.   Increased competition in the natural gas storage business could reduce the demand for our natural gas storage services, drive prices down for our storage business, and adversely affect our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows, which could adversely affect our financial condition, results of operations and cash flows.

Third-party pipeline risk.  Our gas storage business depends on third-party pipelines that connect our storage facilities to interstate pipelines, the failure or unavailability of which could adversely affect our financial condition, results of operations and cash flows.

Our gas storage facilities are reliant on the continued operation of a third-party pipeline and other facilities that provide delivery options to and from our storage facilities.  Because we do not own all of these pipelines, their operation is not within our control.  If the  third-party pipeline to which we are connected were to become unavailable for current or future withdrawals or injections of natural gas due to repairs, damage to the infrastructure, lack of capacity or other reason, our ability to operate efficiently and satisfy our customers’ needs could be compromised, thereby potentially could have an adverse impact on our financial condition, results of operations and cash flows.

Operations at new storage facility risk.  Operations at our new Gill Ranch storage facility involves numerous operational risks that may result in a failure to meet expectations or contractual obligations, additional or unexpected costs and other business risks that could adversely impact our financial condition, results of operations and cash flows.

In October 2010, we commenced operations at our Gill Ranch storage facility.  Operations at a new storage facility involve many risks.  Although we believe that Gill Ranch has been successfully completed to meet our contractual obligations and project specifications with respect to injection, withdrawal and gas specifications, the facility is new, has a limited operating history, and is not expected to reach full design capacity until the end of 2012.  If we fail to achieve design capacity, inject or withdraw natural gas at the levels we expect or at contracted rates, or cannot deliver natural gas consistent with our expectations or contractual specifications, or otherwise operate as expected, or if operating costs are substantially higher than we expect or if we fail to control those costs, we may not be able to contract for storage at the levels and on the terms we expect, and we could incur higher than expected costs to satisfy our contractual obligations under contracts we obtain, and this could adversely impact our financial condition, results of operations and cash flows.  

ITEM 1B.  UNRESOLVED STAFF COMMENTS

We have no unresolved comments.

ITEM 2.  PROPERTIES

Utility Properties

Our natural gas pipeline system consists of approximately 13,900 miles of distribution and transmission mains located in our service territory in Oregon and Washington.  In addition, the piping system includes service pipelines, meters and regulators, and gas regulating and metering stations. Pipeline mains are located in municipal streets or alleys pursuant to valid franchise or occupation ordinances, in county roads or state highways pursuant to valid agreements or permits granted pursuant to statute, or on lands of others pursuant to valid easements obtained from the owners of such lands. We also hold all necessary permits for the crossing of numerous navigable waterways and smaller tributaries throughout our entire service territory.

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We own service building facilities in Portland, as well as various satellite service centers, garages, warehouses and other buildings necessary and useful in the conduct of our business.  We also lease office space in Portland for our corporate headquarters, which expires on May 31, 2018. Resource centers are maintained on owned or leased premises at convenient points in the distribution system to provide service within our utility service territory.  We also own LNG storage facilities in Portland and near Newport, Oregon.

In order to reduce risks associated with gas leakage in older parts of our system, we undertook an accelerated pipe replacement program under which we removed and replaced 100 percent of our cast iron mains by the end of 2000.  In 2001, we initiated an accelerated pipe replacement program under which we expect to eliminate all bare steel mains and services in the system by 2021.

Gas Storage Properties

We hold leases and other property interests in approximately 11,300 net acres of underground natural gas storage in Oregon and approximately 5,000 net acres of underground natural gas storage in California, and easements and other property interests related to pipelines associates with those facilities.  We own rights to depleted gas reservoirs near Mist, Oregon, that are continuing to be developed and operated as underground gas storage facilities. We also hold an option to purchase future storage rights in certain other areas of the Mist gas field in Oregon, as well as in California related to the Gill Ranch storage project.

We consider all of our properties currently used in our operations, both owned and leased, to be well maintained, in good operating condition, and, along with planned additions, adequate for our present and foreseeable future needs.

Our Mortgage and Deed of Trust is a first mortgage lien on substantially all of the property constituting our utility plant.

ITEM 3.  LEGAL PROCEEDINGS

Other than the proceedings disclosed in Note 15 and as discussed below, we have only nonmaterial litigation in the ordinary course of business.

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 10 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 reimburse and 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 in excess of $50 million in losses it has incurred to date, as well as declaratory relief for additional losses it expects to incur in the future.  In December 2011, NW Natural reached a settlement with Associated Electric & Gas Insurance Services Limited and dismissed that insurer from the litigation.

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

(A)           Our common stock is listed and trades on the New York Stock Exchange under the symbol “NWN.”

The high and low trades for our common stock during the past two years were as follows:

	2011				2010
Quarter Ended	High		Low		High		Low
March 31	$	48.72	$	43.92	$	47.54	$	41.05
June 30		46.40		43.57		49.18		41.90
September 30		46.77		39.63		49.00		42.63
December 31		48.98		42.52		50.86		44.02

The closing quotations for our common stock on December 31, 2011 and 2010 were $47.93 and $46.47, respectively.

(B)           As of December 31, 2011, there were 6,745 holders of record of our common stock.

(C)           We have paid quarterly dividends on our common stock in each year since the stock first was issued to the public in 1951.  Annual common dividend payments per share, adjusted for stock splits, have increased each year since 1956.  Dividends per share paid during the past two years were as follows:

Payment Date	2011		2010
February 15	$	0.435	$	0.415
May 15		0.435		0.415
August 15		0.435		0.415
November 15		0.445		0.435
Total per share	$	1.750	$	1.680

The amount and timing of dividends payable on our common stock are within the sole discretion of our Board of Directors.  Subject to Board approval, we expect to continue paying cash dividends on our common stock on a quarterly basis.  However, the declaration and amount of future dividends depend upon our earnings, cash flows, financial condition and other factors.

(D)           The following table provides information about purchases of our equity securities that are registered pursuant to Section 12 of the Securities Exchange Act of 1934 during the quarter ended December 2011:

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ISSUER PURCHASES OF EQUITY SECURITIES

					(c)		(d)
	(a)		(b)		Total Number of Shares		Maximum Dollar Value of
	Total Number		Average		Purchased as Part of		Shares that May Yet Be
	of Shares		Price Paid		Publicly Announced		Purchased Under the
Period	Purchased(1)		per Share		Plans or Programs(2)		Plans or Programs(2)
Balance forward						2,124,528	$	16,732,648
10/01/11 - 10/31/11		-	$	-		-		-
11/01/11 - 11/30/11		3,262	$	47.00		-		-
12/01/11 - 12/31/11		-	$	-		-		-
Total		3,262	$	47.00		2,124,528	$	16,732,648

  (1)  During the quarter ended December 31, 2011, 3,262 shares of our common stock were purchased on the open market to meet the requirements of our deferred compensation programs.  During the quarter ended December 31, 2011, no shares of our common stock were accepted as payment for stock option exercises pursuant to our Restated Stock Option Plan.

  (2)  We have a share repurchase program under which we purchase NWN common stock on the open market or through privately negotiated transactions.  The program is currently authorized by the Board through May 31, 2012, with approval to repurchase up to an aggregate of 2.8 million shares or up to an aggregate of $100 million.  During the quarter ended December 31, 2011, no shares of our common stock were repurchased pursuant to this program. Since the program’s inception in 2000, we have repurchased approximately 2.1 million shares of common stock at a total cost of approximately $83.3 million.

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ITEM 6.  SELECTED FINANCIAL DATA
	For the year ended December 31,
Thousands, except per share amounts	2011		2010		2009		2008		2007
Net operating revenues	$	369,433	$	367,581	$	376,887	$	356,215	$	369,042
Net income		63,898		72,667		75,122		69,525		74,497
Earnings per share of common stock:
Basic		2.39		2.73		2.83		2.63		2.78
Diluted		2.39		2.73		2.83		2.61		2.76
Dividends paid per share of common stock		1.75		1.68		1.60		1.52		1.44
Total assets - at end of period		2,746,574		2,616,616		2,399,252		2,378,152		2,014,061
Common stock equity		714,488		693,101		660,105		628,373		594,751
Long-term debt		641,700		591,700		601,700		512,000		512,000

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ITEM 7.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is management’s assessment of Northwest Natural Gas Company’s (NW Natural) financial condition, including the principal factors that affect results of operations. The discussion refers to our consolidated activities for the years ended December 31, 2011, 2010, and 2009. Unless otherwise indicated, references in this discussion 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 an equity investment in Palomar Gas Holdings, LLC (PGH), which is pursuing the development of a proposed natural gas pipeline through its wholly-owned subsidiary Palomar Gas Transmission, LLC (Palomar). These accounts make up our regulated local gas distribution business, our regulated gas storage businesses, and other regulated and non-regulated investments primarily in energy-related businesses. In this report, the term “utility” is used to describe our regulated local 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.  We also present free cash flow as we believe this supplemental information enables the reader of the financial statements to better understand our cash generating ability and to benefit from seeing cash flow results from management’s perspective in addition to the traditional GAAP presentation (see “Cash Flows – Financing Activities,” below).  We use such non-GAAP (i.e. non-generally accepted accounting principles) measures in analyzing our financial performance because we believe that they provide useful information to our investors and creditors in evaluating NW Natural’s financial condition and results of operations.

Executive Summary

Highlights of 2011 include:

·   Consolidated earnings of $63.9 million and $2.39 per share in 2011, compared to $72.7 million and $2.73 in 2010;

·   Net income from utility operations decreased $5.7 million, from $66.3 million in 2010 to $60.5 million in 2011;

·   Net income from gas storage operations decreased $2.0 million, from $6.1 million in 2010 to $4.1 million in 2011;

·   Net operating revenues (margin) increased 1 percent, from $367.6 million in 2010 to $369.4 million in 2011;

·   Total operating expenses increased 7 percent, from $210.0 million in 2010 to $224.6 million in 2011;

·   Cash flow from operations increased $107.0 million, from $126.5 million in 2010 to $233.5 million in 2011;

·   Utility customer growth rate was 0.8 percent in 2011, compared to 0.9 percent in 2010; and

·   Dividends paid increased 4 percent, from $1.68 per share in 2010 to $1.75 in 2011, reflecting the 56th consecutive year of dividend increases to shareholders.

Our primary businesses consist of regulated utility and gas storage operations.  Factors critical to the success of the utility include: maintaining a safe and reliable distribution system; acquiring an adequate supply of natural gas; providing distribution services at competitive prices; and being able to recover our operating and capital costs in the rates charged to customers in a reasonable and timely manner. Our utility business is regulated by two state commissions, the Public Utility Commission of Oregon (OPUC) and the Washington Utilities and Transportation Commission (WUTC).  Factors critical to the success of our gas storage business include: developing and operating storage capacity at competitive market prices; retaining customers and successfully marketing available storage capacity to new customers; planning for the replacement of capacity that is expected to be recalled by the utility to serve growing demands of its core customers; charging adequate rates to recover investment and operating costs; and being able to obtain financing to fund expansions and working capital requirements.  Our gas storage businesses are, in part, regulated by the California Public Utilities Commission (CPUC), the Federal Energy Regulatory Commission (FERC) and the OPUC.

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2012 Outlook

In 2012, we will be focused on strengthening our core businesses, enhancing our strategic position, advancing key business projects, and leveraging our organizational resources.

Strengthen Core Businesses.  Our core businesses are local gas distribution (utility) and gas storage. In the utility, we will continue our efforts to develop, integrate, consolidate and streamline our operations using new technologies, which are expected to include a workforce scheduling system, a procurement system, and an automated dispatching system.  In our storage business, we will focus on maximizing our storage capacity and optimizing our revenue opportunities.  We believe that investing in operating efficiencies and in marketing opportunities for our core businesses positions us well for growth now and into the future as the economy recovers.

Enhance Strategic Position.  We believe our core businesses are positioned strategically and competitively. The decline in gas prices and the abundance of shale gas supplies creates opportunities for both core businesses. Specifically, it creates opportunities for us to expand our market share in the utility by leveraging our natural gas’ competitive price advantage.  Moreover, our gas storage facilities strategically position us to quickly respond to market demand with storage capacity when gas prices increase or become more volatile.  Together, our businesses competitively position us to meet market demands when the economy recovers.

Advance Key Projects.  We seek to create shareholder value by innovatively addressing the needs of our customers, employees and the communities we serve while addressing economic, regulatory and environmental challenges. To that end, we are advancing key business projects such as acquiring long-term gas reserves on behalf of our utility customers, pursuing future storage opportunities at Mist, and improving our operations at Gill Ranch.  We also continue to pursue regional solutions for reliable and safe energy needs through our investment in natural gas infrastructure, such as the Palomar pipeline.

Leverage Resources.  Our employees are our most valued resource.  To support and leverage this valuable resource, we will continue to invest in new technologies and improve our facilities. We believe this will allow us to maintain a positive and safe work environment, to provide on-going training and workforce development, and also to gain greater operational efficiency.

Issues, Challenges and Performance Measures

Economic weakness.  Weakness in local, national and global economies continues to impact utility customer growth, business demand for natural gas and market prices for gas storage.  Our utility’s customer growth rate remained relatively flat for the third year in a row at 0.8 percent, compared to 0.9 percent in 2010 and 0.8 percent in 2009.  The local economy is beginning to show signs of a slow recovery as unemployment rates in Oregon and southwest Washington dropped from approximately 10 percent in 2010 to about 9 percent at the end of 2011, and industrial demand for natural gas increased in 2011 by 1 percent over 2010.  We believe our utility is well positioned to add customers as the economy recovers because of low and stable natural gas prices, our relatively low market penetration, our ongoing focus on converting homes and businesses 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 is strong, which is contributing to lower and more stable gas prices.  

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The Purchased Gas Adjustment (PGA) mechanisms in Oregon and Washington, along with our gas price hedging strategies, including gas reserves and storage supplies, enable us to reduce earnings 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.  

We typically hedge gas prices on 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 entered the gas year hedged at a level of approximately 75 percent of our forecasted sales volumes, including 51 percent financially hedged and 24 percent physically hedged with a combination of gas inventories in storage, local production from the Mist area, and production of gas reserves from our investment with Encana Oil & Gas (USA) Inc. (Encana).  The production of gas reserves is related to a new investment we made beginning in 2011 to hold working interests in leases related to both currently producing and new wells in Encana’s Jonah gas field located in Rock Springs, Wyoming. For further discussion of gas reserves, see Investments in Gas Reserves under Strategic Opportunities below and Gas Reserves under Rate Mechanisms below.

In addition to the amount of gas hedged for the current gas contract year, we are also hedged at approximately 32 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. Stable natural gas prices may reduce the pricing for storage services. We are focused on improving the results from our gas storage businesses.

Environmental costs.We accrue all 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 currently have regulatory approval to defer certain environmental costs, and to seek recovery of these amounts in future rates to customers. However, we are expected to pursue recovery from insurance policies and only seek recovery from customers for amounts not covered by insurance.  Ultimate recovery of environmental costs, either from regulated utility rates or from insurance, will depend on our ability to effectively manage costs and demonstrate that costs 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 Note 15.

Climate change.  We recognize that our businesses are likely to be impacted by future carbon constraints, and we are seeking clean energy growth opportunities that position us for long-term success in a lower carbon energy economy and to advance our customers’ interests in energy conservation, efficiency and environmental stewardship.  A variety of federal, state, local and international climate change initiatives, including new regulations, are underway, but we cannot determine the impact of these initiatives at this time.  For example, an array of Environmental Protection Agency (EPA) rules impacting coal plants may cause some coal plants to shut down early although the EPA is not mandating coal plant closures.  Coal plant shut downs could increase the demand for natural gas as a lower carbon emission fuel and create opportunities for us.  Similarly, because natural gas has a relatively low carbon content, it is also possible that future carbon constraints could create additional demand for natural gas for base load electric generation, direct use in homes and businesses, backing up intermittent renewable resources and as a transportation fuel to displace gasoline and diesel. Under EPA’s greenhouse gas reporting rules adopted in 2009, we report system throughput to the EPA on an annual basis.  The first report under these provisions was due to EPA in September 2011. EPA also issued additional greenhouse gas reporting regulations in 2010, which required mandatory reporting of unintended greenhouse gas releases from petroleum and natural gas facilities. The first report is due under these rules in September 2012. While our CO2 equivalent emission levels are relatively small, the adoption and implementation of any regulations imposing reporting obligations, or limiting emissions of greenhouse gases associated with our operations, could result in an increase in the prices we charge our customers or a decline in the demand for natural gas.

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Performance measures. In order to deal with the challenges affecting our businesses, we annually review and update our strategic plan to map out a course for the next several years.  Our plan includes strategies for: further improving our utility gas distribution system; enhancing utility services and operations; optimizing and growing our non-utility gas storage businesses; investing in natural gas infrastructure projects when necessary to support the energy 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 new clean energy technologies.  We intend to measure our performance and monitor progress on relevant metrics including, but not limited to: earnings per share growth; total shareholder return; return on invested capital; utility return on equity; utility customer satisfaction ratings; utility margin; utility capital and operations and maintenance expense per customer; and earnings before interest, taxes, depreciation and amortization and (EBITDA).

Strategic Opportunities

Business Process Improvements.We continue to evaluate, develop and implement business strategies to improve operational efficiencies and respond to economic and competitive challenges. Over the last few years, our efforts have been to develop, integrate, consolidate and streamline operations, while supporting our employees with training and new technology tools.

From 2006 through 2010, we reduced staffing levels in response to work load declines related to the low customer growth environment and efficiency improvements, resulting in a reduction of full-time, utility positions from over 1,300 in early 2006 to about 1,050 at the end of 2011. Technology investments, workforce reductions and other initiatives have contributed to a significant increase in productivity.  The number of utility customers served per operating employee increased by 32 percent, from 738 at the end of 2005 to 976 at the end of 2011. These efforts are expected to contribute to long-term operational efficiencies and lower operating and capital costs throughout NW Natural. However, we continue to look for new ways to improve our business as service demands and system safety requirements increase and we remain committed to increasing shareholder value.

Gas Storage Development. We own and operate two underground gas storage facilities—the Mist facility in Oregon and the Gill Ranch facility in Fresno, California.  Our wholly-owned subsidiary, Gill Ranch, holds a 75 percent undivided ownership interest in the Gill Ranch facility, with Pacific Gas and Electric Company (PG&E) owning the other 25 percent interest. The initial development of Gill Ranch was designed to provide us with 15 Bcf of gas storage capacity by the end of 2012, with pipeline capacity on 27 miles of gas transmission pipeline connecting the Gill Ranch facility to an interconnect on PG&E’s transmission system.  See Note 4.

Due to an abundant supply of natural gas and lower, more stable prices in North America, current 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. Gas prices have hit a 10-year low and this has resulted in certain natural gas producers reducing their levels of exploration and production. At the same time, we expect these lower gas prices to increase demand for natural gas as the pricing provides a competitive advantage over alternative fuel sources including potential demand for exporting natural gas. Combined, these forces may ultimately result in upward pressure on gas prices and return some price volatility to natural gas markets.

Our storage facilities help position us to capitalize on rising demand, increasing gas prices or greater market volatility because storage operations benefit from seasonal swings in commodity pricing and market volatility. Additionally, if market demand increases and we are able to obtain financing and regulatory permits, we have the ability to expand the Gill Ranch facility beyond its current capacity without further expansion of our gas transmission pipeline.  We estimate that the current Gill Ranch storage facility could support an aggregate storage capacity of around 40 Bcf with certain infrastructure modifications, of which we would have the rights to 50 percent of the total.

The Pacific Northwest storage markets also are impacted by lower gas prices and lack of gas price volatility, although less than California markets primarily because of fewer regional competitors. Nevertheless, we continue to plan for expansion of our gas storage facilities at Mist in anticipation of increased natural gas demand for electric generation in the Pacific Northwest.  Currently we do not have a set timeline for development, but we believe the earliest timeframe for completing the next Mist expansion is 2016.  In the meantime, we expect to continue working on preliminary design and project scope, which will most likely include the development of storage wells, a second compression station and additional pipeline gathering facilities that would enable future storage expansions.

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Pipeline Diversification. Currently, our utility operations and gas storage operations at Mist 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 our NWN Energy subsidiary 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 and develop an east-only pipeline to serve our utility customers as well as growing natural gas markets in Oregon and other parts of the Pacific Northwest.  In the second quarter of 2011, Palomar determined it should discontinue efforts to develop the west segment of the pipeline after the supporting shipper declared bankruptcy.  As a result, we recorded a charge of $0.3 million for our portion of the unrecovered costs related to the west segment.

Regarding the proposed east pipeline segment, Palomar negotiated a non-binding memorandum of understanding with The Williams Companies’ Northwest Pipeline (Northwest Pipeline), which contemplates Northwest Pipeline becoming a part owner in the Palomar project.  This joint agreement would consolidate the region’s efforts to develop a cross-Cascades pipeline around the use of the Palomar route.  Northwest Pipeline owns and operates the single bi-directional pipeline that connects to NW Natural’s utility distribution system.

The proposed east segment pipeline would be regulated by FERC.  In March 2011, Palomar withdrew its original application with FERC for the proposed pipeline in Oregon, but at the same time informed FERC that it intends to file a new application with a modified scope that excludes the west segment, after it has conducted a new open season to obtain commercial support for the east segment. The timing for when the Palomar pipeline is expected to be built and placed into service will be dependent upon regulatory permits and commercial support from shippers.

In the fourth quarter of 2011, we recorded a charge of $1.0 million related to the investment in the east segment of the project. This charge was for costs that were determined to be less than probable of recovery in a FERC rate making proceeding because they might be deemed outdated when we refile with FERC. Our investment balance in Palomar at December 31, 2011 after the charge was $13.5 million, which represents our share of Palomar’s development costs related to the east segment.  See Note 12 and see also "Financial Condition—Cash Flows—Investing Activities," below for further discussion on the status of Palomar.

Gas Reserves. In addition to hedging gas prices with financial derivative contracts, we recently signed an agreement with Encana to acquire physical gas supplies to meet a portion of our Oregon utility customers’ requirements over 30 years.  During the first 10 years, 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.  We pay a fixed portion of drilling costs per well.  Encana assigns to us working interests in leases to certain sections of the Jonah gas field, located near Rock Springs, Wyoming.  These sections include both future and currently producing wells.  The working interests will entitle us to receive a portion of the gas produced in these sections.  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.  See Results of Operations—Regulatory Matters—Rate Mechanisms—Gas Reserves below and 2012 Outlook—Issues, Challenges and Performance Measures—Managing gas prices and supplies above.

Consolidated Earnings and Dividends

Consolidated net income was $63.9 million, or $2.39 per share, for the year ended December 31, 2011, compared to $72.7 million, or $2.73 per share, and $75.1 million, or $2.83 per share, for the years ended December 31, 2010 and 2009, respectively.  Consolidated earnings decreased in fiscal year 2011 primarily due to the loss of income from the repeal of Oregon’s legislative rule on utility income tax true up, a refund of utility property taxes in 2010, and a lower earnings contribution from our gas storage segment, which includes the first full year of operations for subsidiaries Gill Ranch and NWN Gas Storage. These decreases were partially offset by increased margin results from sales and transportation revenues reported by our utility gas distribution business. Consolidated returns on average stockholders’ equity for these three years were 9.1 percent, 10.7 percent and 11.7 percent, respectively.  See “Application of Critical Accounting Policies and Estimates—Regulatory Accounting” for a discussion of the legislative rule.

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2011 compared to 2010:

The most significant factors contributing to the $8.8 million decrease in consolidated net income were:

·   a $7.2 million net charge against utility margin taken in 2011, plus the $7.7 million of margin revenues accrued in 2010, related to the repeal of Oregon’s legislative rule on utility income taxes.  See “Results of Operations—Business Segments—Utility Operations—Regulatory Adjustment for Income Taxes Paid,” below for further explanation;

·   a $5.4 million increase in general taxes, primarily due to a $5.2 million refund of utility property taxes received in 2010, partially offset by a $0.9 million decrease in other taxes at the utility, and a $1.3 million increase in property and other taxes at Gill Ranch;

·   a $4.9 million increase in depreciation and amortization expense, due to a $1.2 million increase at the utility and a $3.7 million increase at Gill Ranch; and

·   a $4.3 million increase in operations and maintenance expense, primarily due to a $3.2 million increase at Gill Ranch reflecting first-year operating expenses.

Partially offsetting the above factors were:

·   an $11.3 million increase in utility margin attributable to an increase in customers gas use, reflecting gains from colder weather, customer growth and a slight increase in industrial demand; and

·   a $6.1 million decrease in income tax expense related to lower taxable income.

2010 compared to 2009:

The most significant factors contributing to the $2.4 million decrease in consolidated net income were:

·   a $13.5 million decrease in utility margin from the regulatory gas cost incentive sharing mechanism, which reflects gains of $15.1 million in 2009 compared to gains of $1.6 million in 2010;

·   a $2.9 million net loss from Gill Ranch, and a $0.6 million net loss from NWN Gas Storage, primarily reflecting higher operating expenses related to start-up activities;

·   a $2.8 million increase in income tax expense primarily reflecting higher taxable income from the utility, including higher amortization of regulatory tax balances related to pre-1981 assets which are offset by increased revenues collected in utility margin; and

·   a $1.9 million increase in interest expense primarily reflecting the full year effect of lower-rate short-term debt refinanced with higher-rate long-term debt during 2009 and higher balances of total debt outstanding.

Partially offsetting the above factors were:

·   a $14.3 million decrease in utility operating expenses primarily due to lower property tax, payroll, bad debt, and employee benefit costs;

·   a $5.0 million increase in utility margin from residential and commercial customers, after adjustments for weather and decoupling mechanisms, primarily due to colder weather benefits in the second quarter of 2010 when weather normalization was not in effect, customer growth and the rate recovery of higher income tax expenses related to an increase in Oregon tax rates and the accelerated amortization of regulatory tax assets; and

·   a $3.4 million increase in other income primarily due to higher carrying costs from utility deferred regulatory account balances and interest income from a utility property tax refund, partially offset by a decrease in non-utility gains from company-owned life insurance.

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Dividends paid on our common stock were $1.75 per share in 2011, compared to $1.68 per share in 2010 and $1.60 per share in 2009.  The Board of Directors declared a quarterly dividend on our common stock of 44.5 cents per share, payable on February 15, 2012, increasing the indicated annual dividend rate 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 (U.S. 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.

Management has discussed its current estimates and judgments used in the application of critical accounting policies with the Audit Committee of the Board.   Within the context of our critical accounting policies and estimates, management is not aware of any reasonably likely events or circumstances that would result in materially different amounts being reported.  For a description of recent accounting pronouncements that could have an impact on our financial condition, results of operations or cash flows, see Note 2.

Regulatory Accounting

    Our utility is regulated by the OPUC and WUTC, which establish the rates and rules governing utility services provided to customers, and, to a certain extent, set forth special accounting treatment for certain regulatory transactions.  In general, we use the same accounting principles as non-regulated companies reporting under U.S. GAAP.  However, authoritative guidance for regulated operations (regulatory accounting) require different accounting treatment for regulated companies to show the effects of such regulation.  For example, we account for the cost of gas using a PGA deferral and cost recovery mechanism, which is submitted for approval annually to the OPUC and WUTC (see “Results of Operations—Regulatory Matters—Rate Mechanisms,” below).  There are other expenses and revenues that the OPUC or WUTC may require us to defer for recovery or refund in future periods.  Regulatory accounting requires us to account for these types of deferred expenses (or deferred revenues) as regulatory assets (or regulatory liabilities) on the balance sheet.  When we are allowed to recover these expenses from, or are required to refund them to, customers, we recognize the expense or revenue on the income statement at the same time we realize the adjustment to amounts included in utility rates charged to customers.

    The conditions we must satisfy to adopt the accounting policies and practices of regulatory accounting, which are applicable to regulated companies, include:

·   an independent regulator sets rates;

·   the regulator sets the rates to cover specific costs of delivering service; and

·   the service territory lacks competitive pressures to reduce rates below the rates set by the regulator.

    Because our utility satisfies all three conditions, we continue to apply regulatory accounting to our utility operations.  Future accounting changes, regulatory changes or changes in the competitive environment could require us to discontinue the application of regulatory accounting for some or all of our regulated businesses.  This would require the write-off of those regulatory assets and liabilities that would no longer be probable of recovery from or refund to customers.  Based on current accounting, regulatory and competitive conditions, we believe that it is reasonable to expect continued application of regulatory accounting for our utility activities, and that all of our regulatory assets and liabilities at December 31, 2011 and 2010 are recoverable or refundable through future customer rates. The net balance in regulatory asset and liability accounts as of December 31, 2011 and 2010 was $156.6 million and $125.8 million, of assets, respectively.  See “Industry Regulation” in Note 2.

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Revenue Recognition

Utility and non-utility revenues, which are derived primarily from the sale, transportation and storage of natural gas, are recognized upon the delivery of gas commodity or services rendered to customers.  Revenues are accrued for gas delivered and services rendered to customers, but not yet billed, based on estimates from the last meter reading date to month end (accrued unbilled revenues).  Accrued unbilled revenues are primarily based on a percentage estimate of amounts unbilled each month, which is dependent upon a number of factors, some of which require management’s judgment.  These factors include total gas receipts and deliveries, customer meter reading dates, customer usage patterns and weather. Accrued unbilled revenue estimates are reversed the following month when actual billings occur.  Estimated unbilled revenues at December 31, 2011 and 2010 were $61.9 million and $64.8 million, respectively.  The decrease in accrued unbilled revenues at year-end 2011 was primarily due to lower volumes in December 2011, reflecting warmer weather late in the month, and lower customer billing rates.  If the estimated percentage of unbilled volume at December 31, 2011 was adjusted up or down by 1 percent, then unbilled revenues, net operating revenues and net income would have increased or decreased by an estimated $1.9 million, $0.5 million and $0.6 million, respectively.

From 2007 through 2010, utility revenues included the recognition of a regulatory adjustment for income taxes paid (commonly referred to as SB 408).  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 estimated differences between income taxes paid and income taxes 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 required 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).  For further discussion, see “Results of Operations—Business Segments—Utility Operations—Regulatory Adjustment for Income Taxes Paid,” below.

    Non-utility revenues, derived primarily from our gas storage business segment, are recognized upon delivery of service to customers.  Revenues from our asset management partner are recognized as earned based on multiple revenue elements, which is generally over the period of each asset management deal, except for contracts with a guaranteed amount which are amortized pro-rata over the life of the contract.

Accounting for Derivative Instruments and Hedging Activities

Our gas acquisition and hedging policies set forth guidelines for using financial derivative instruments to support prudent risk management strategies. These policies specifically prohibit the use of derivatives for trading or speculative purposes. The accounting rules for determining whether a contract meets the definition of a derivative instrument or qualifies for hedge accounting treatment are complex.  The contracts that meet the definition of a derivative instrument are recorded on our balance sheet at fair value.  If certain regulatory conditions are met, then the derivative instrument fair value is recorded together with an offsetting entry to a regulatory asset or liability account pursuant to regulatory accounting (see Note 2, “Industry Regulation”), and no unrealized gain or loss is recognized in current income.  The gain or loss from the fair value of a derivative instrument subject to regulatory deferral is included in the recovery from, or refund to, utility customers in future periods (see “Regulatory Accounting,” above).  If a derivative contract is not subject to regulatory deferral, then the accounting treatment for unrealized gains and losses is recorded in accordance with accounting standards for derivatives and hedging (see Note 2, “Derivatives” and “Industry Regulation”) which is either in current income or in accumulated other comprehensive income under common stock equity on the balance sheet. Our derivative contracts outstanding at December 31, 2011 were measured at fair value using models or other market accepted valuation methodologies derived from observable market data.  Our estimate of fair value may change significantly from period-to-period depending on market conditions and prices.  These changes may have an impact on our results of operations, but the impact would largely be mitigated due to the majority of our derivatives activities being subject to regulatory deferral treatment.  For estimated fair value of unrealized gains and losses at December 31, 2011 and 2010, see Note 13.

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Commodity-based derivative contracts entered into by the utility after our annual PGA filing for the current gas contract period are subject to a regulatory incentive sharing mechanism in Oregon (see “Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” below).  The portion not deferred to a regulatory account pursuant to that sharing agreement is recognized either in current income for contracts not qualifying for hedge accounting or in accumulated other comprehensive income for contracts qualifying for hedge accounting.

Derivative contracts not qualifying for regulatory deferral are subject to a hedge effectiveness test to determine the financial statement treatment of each specific derivative.  As of December 31, 2011, all of our derivatives were effective economic hedges and either qualified or were expected to qualify for regulatory deferral or hedge accounting treatment.  We use the hypothetical derivative method under accounting standards for derivatives and hedging to determine the hedge effectiveness for our interest rate swaps and the dollar offset method for other derivative contracts under accounting standards for derivatives and hedging.  The effectiveness test applied to financial derivatives is dependent on the type of derivative and its use.

The following table summarizes the amount of gains and losses realized from commodity price, interest rate and currency hedge transactions for the last three years:

Thousands	2011			2010			2009
Net gain (loss) on commodity-price swaps - utility	$	(53,834	)	$	(60,362	)	$	(172,089	)
Net gain (loss) on commodity-price options - utility		(2,695	)		(610	)		(5,809	)
Net gain (loss) on interest rate swap - utility		-			-			(10,096	)
Subtotal - utility		(56,529	)		(60,972	)		(187,994	)
Net gain (loss) on foreign currency forward purchases - utility		(52	)		72			88
Total net gain (loss) realized	$	(56,581	)	$	(60,900	)	$	(187,906	)

Realized gains (losses) from commodity hedges and foreign currency forward purchase contracts are recorded as reductions (increases) to the cost of gas and are included in the calculation of annual PGA rate changes. Realized gains (losses) from interest rate hedges are recorded as reductions (increases) to interest charges over the term of the underlying debt issuances.  Unrealized gains and losses from commodity hedges, foreign currency hedges and interest rate hedges, which reflect quarterly mark-to-market valuations, are generally not recognized in current income or accumulated other comprehensive income, but are recorded as regulatory liabilities or regulatory assets, and are offset by a corresponding balance in derivative instruments (see Note 13).

Accounting for Pensions and Postretirement Benefits

We maintain two qualified non-contributory defined benefit pension plans covering a majority of our regular employees with more than one year of service, several non-qualified supplemental pension plans for eligible executive officers and certain key employees, and other postretirement employee benefit plans.  We also have a qualified defined contribution plan (Retirement K Savings Plan) for all eligible employees.  Only the two qualified defined benefit pension plans and Retirement K Savings Plan have plan assets, which are held in qualified trusts to fund the respective retirement benefits. Effective January 1, 2007 and 2010, the qualified defined benefit retirement plans for non-union employees and for union employees, respectively, were closed to new participants.  These plans were not available to employees at any of our subsidiary companies.  Non-union and union employees hired or re-hired after December 31, 2006 and 2009, respectively, and our subsidiary employees, are provided an enhanced Retirement K Savings Plan benefit. Also, effective January 1, 2007 the postretirement Welfare Benefit Plan for Non-Bargaining Unit Employees was closed to new participants after December 31, 2006.

Net periodic pension and postretirement benefit costs (retirement benefit costs) and projected benefit obligations (benefit obligations) are determined in accordance with accounting standards for compensation and retirement benefits using a number of key assumptions including discount rates, rate of compensation increases, retirement ages, mortality rates and an expected long-term return on plan assets (see Note 9).  These key assumptions have a significant impact on the pension amounts recorded and disclosed.  Retirement benefit costs consist of service costs, interest costs, the amortization of actuarial gains, losses and prior service costs, the expected returns on plan assets and, in part, on a market-related valuation of assets, if applicable.  The market-related asset valuation reflects differences between expected returns and actual investment returns, which we recognize over a three-year period or less from the year in which they occur, thereby reducing year-to-year volatility in retirement benefit costs.

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Accounting standards also require balance sheet recognition of the overfunded or underfunded status of pension and postretirement benefit plans in accumulated other comprehensive income (AOCI), net of tax, based on the fair value of plan assets compared to the actuarial value of future benefit obligations.  However, the retirement benefit costs relating to our qualified defined benefit pension and postretirement benefit plans are generally recovered in utility rates which are set based on accounting standards for pensions and postretirement benefits, and as such we received approval from the OPUC pursuant to regulatory accounting to recognize the overfunded or underfunded status as a regulatory asset or regulatory liability based on expected rate recovery, rather than including it as AOCI under common equity (see “Regulatory Accounting”, above, and Note 2, “Industry Regulation”).

The retirement benefit cost for pensions consists of service costs, interest costs, the expected returns on plan assets, and the amortization of actuarial gains and losses.  Effective January 1, 2011, we began deferring a portion of our pension expense to a regulatory account on the balance sheet pursuant to OPUC approval of pension expenses above or below the amount set in rates.  In 2011, the cumulative amount deferred for future pension cost recovery was $6.0 million. The regulatory asset account earns a carrying cost at the authorized cost of capital rate set by the OPUC.

A number of factors are considered in developing pension and postretirement assumptions, including evaluations of relevant discount rates, an evaluation of expected long-term investment returns based on asset classes and target asset allocations, expected changes in salaries and wages, analyses of past retirement plan experience and current market conditions and input from actuaries and other consultants.  For the December 31, 2011 measurement date, we reviewed and updated:

·   our weighted-average discount rate assumptions for pensions and other postretirement benefits, which went from 5.49 percent to 4.51 percent and from 5.16 percent to 4.33 percent, respectively.  The new rate assumptions were determined for each plan based on a matching of benchmark interest rates to the estimated cash flows, which reflects the timing and amount of future benefit payments.  Benchmark interest rates are drawn from the Citigroup Above Median Curve, which consists of high quality bonds rated AA- or higher by Standard & Poor’s (S&P) or Aa3 or higher by Moody’s Investors Service (Moody’s);

·   our expected annual rate of future compensation increases, which  remained unchanged at a range of 3.25 to 5.0 percent;

·   our expected long-term return on qualified defined benefit plan assets, which was reduced to 8.00 percent from 8.25 percent; and

·   other key assumptions, which were based on actual experience and actuarial recommendations.

At December 31, 2011, our net pension liability (benefit obligations less market value of plan assets) for the two qualified defined benefit plans increased $51.5 million compared to 2010.  The increase in our net pension liability is primarily due to the $48.4 million increase in our pension obligation.  The liability for non-qualified plans increased $3.3 million and the liability for other postretirement benefits increased $2.4 million in 2011.

We determine the expected long-term rate of return on plan assets by averaging the expected earnings for the target asset portfolio.  In developing our expected return, we evaluate an analysis of historical actual performance and long-term return projections, which gives consideration to the current asset mix and our target asset allocation. As of December 31, 2011, the actual annualized returns on plan assets, net of management fees, for the past one-year, five-years, 10-years and since inception were 2.4 percent, 0.2 percent, 4.8 percent and 9.9 percent, respectively.

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     We believe our pension assumptions to be appropriate based on plan design and an assessment of market conditions.  However, the following shows the sensitivity of our retirement benefit costs and benefit obligations to future changes in certain actuarial assumptions:

				Impact on 2011		Impact on Retirement
	Change in			Retirement		Benefit Obligations
Thousands, except percent	Assumption			Benefit Costs		at Dec. 31, 2011
Discount rate:		(0.25	%)
Qualified defined benefit plans				$	1,162	$	11,796
Non-qualified plans					8		53
Other postretirement benefits					54		754
Expected long-term return on plan assets:		(0.25	%)
Qualified defined benefit plans					580		N/A

Accounting for Income Taxes

We account for income taxes in accordance with accounting standards that require the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between financial statement carrying amount and tax basis of assets and liabilities.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.  At December 31, 2011 and 2010, our net long-term deferred tax liability totaled $413.2 million and $373.4 million, respectively. After application of the federal statutory tax rate to book income, judgment is required with respect to the timing and deductibility of expense in our tax returns. For state income tax and local income taxes, judgment is also required with respect to the apportionment among the various jurisdictions. A valuation allowance is recorded if we expect that it is “more likely than not” that our deferred tax assets will not be realized. At December 31, 2011, we did not have a valuation allowance due to our expectation that all of these assets and liabilities will be realized.

These accounting standards also require the recognition of deferred income tax assets and liabilities for temporary differences where regulators require us to flow through deferred income tax benefits or expenses in the ratemaking process of the regulated utility (regulatory tax assets and liabilities). This is consistent with the ratemaking policies of the OPUC and WUTC. Regulatory tax assets and liabilities are recorded to the extent we believe they will be recoverable from, or refunded to, customers in future rates. At December 31, 2011 and 2010, we had regulatory assets representing differences between book and tax basis related to pre-1981 property of $68.5 million and $72.3 million, respectively, and recorded an offsetting deferred tax liability. We received authorization from the OPUC and WUTC in 2009 to accelerate the recovery of these pre-1981 regulatory assets through future utility rates.  See Notes 2 and 10.

Uncertain tax positions are accounted for in accordance with accounting standards that require management’s assessment of the expected treatment of a tax position taken in a filed tax return, or planned to be taken in a future tax return, that has not been reflected in measuring income tax expense for financial reporting purposes. Until such positions are sustained by the taxing authorities, we would not recognize the tax benefits resulting from such positions and would report the tax effect as a liability in the Company’s consolidated balance sheet. As of December 31, 2011, we had no uncertain tax positions.

The IRS completed its examination of the 2006 through 2008 tax years in 2011.  The examination resulted in payments of $1.5 million of tax and $0.2 million of interest.  The Oregon Department of Revenue (ODOR) completed its field examination of our 2006 through 2009 consolidated Oregon income tax returns and issued preliminary assessments.  If sustained by the ODOR, these assessments would result in an additional state tax liability of approximately $0.8 million, including interest and penalties.  The Company is engaged in discussions with ODOR to resolve these issues; however, uncertainty exists with respect to the outcome of the audit as a result of information not yet fully considered by the ODOR.  Resolution is expected to be reached within the next 12 months, and we have determined that it is more-likely-than-not that we will prevail on these issues.  As such, no amounts have been recorded in our financial statements as of December 31, 2011 related to this matter.

Interest and penalties related to any future income tax deficiencies are recorded in income tax expense in our consolidated statements of income.

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Accounting for Contingencies

Loss contingencies are recorded as liabilities when it is probable that a liability has been incurred and the amount of the loss is reasonably estimable in accordance with accounting standards for contingencies. Estimates of loss contingencies, including estimates of legal costs when such costs are probable of being incurred and are reasonably estimable and related disclosures are updated when new information becomes available. Estimating probable losses requires an analysis of uncertainties that often depend upon judgments about potential actions by third parties. Accruals for loss contingencies are recorded based on an analysis of potential results. When information is sufficient to estimate only a range of potential liabilities, and no point within the range is more likely than any other, we recognize an accrued liability at the low end of the range and disclose the range (see “Contingent Liabilities,” below).  It is possible, however, that the range of potential liabilities could be significantly different than amounts currently accrued and disclosed, with the result that our financial condition and results of operations could be materially affected by changes in the assumptions or estimates related to these contingencies.

With respect to environmental liabilities and related costs, we develop estimates based on a review of information available from numerous sources, including completed studies and site specific negotiations. Using sampling data, feasibility studies, existing technology and enacted laws and regulations, we estimate that the total future expenditures for environmental investigation, monitoring and remediation are $72.7 million as of December 31, 2011.  It is our policy to accrue the full amount of such liability when information is sufficient to reasonably estimate the amount of probable liability. When information is not available to reasonably estimate the probable liability, or when only the range of probable liabilities can be estimated and no amount within the range is more likely than another, then it is our policy to accrue at the lower end of the range. Accordingly, due to 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 will continue to seek recovery of such costs through insurance and through customer rates, and we believe recovery of these costs is probable. If it is determined that both the insurance recovery and future rate recovery of such costs are not probable, the costs will be charged to expense in the period such determination is made.  See Note 15.

Results of Operations

Regulatory Matters

Regulation and Rates

Utility. We are subject to regulation with respect to, among other matters, rates and systems of accounts set by the OPUC, WUTC, and FERC.  The OPUC and WUTC also regulate our issuance of securities by the utility. In 2011, approximately 90 percent of our utility gas volumes and revenues were derived from Oregon customers and approximately 10 percent from Washington customers.  Future earnings and cash flows from utility operations will be determined by the Oregon and Washington economies in general, by the pace of growth in the residential and commercial markets in particular, and by our ability to remain price competitive, control expenses, and obtain reasonable and timely regulatory recovery for our utility gas costs, including operating and maintenance expenses and investment costs made in utility plant and other regulatory assets.

Gas Storage. Our gas storage business is subject to regulation with respect to, among other matters, issuance of securities and systems of accounts set by the OPUC, FERC, and the CPUC.  The CPUC regulates Gill Ranch under a market based rates model which allows for the price for storage services to be set by market conditions.  The OPUC and FERC regulate intrastate and interstate storage services, respectively, under a maximum cost of service model which allows for storage prices to be set at or below the cost of service as set in the last approved regulatory filing for each agency. In 2011, approximately 65 percent of our storage revenues were derived from FERC and Oregon approved rates to customers and approximately 35 percent from California approved rates to customers.

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General Rate Cases

Oregon. On December 30, 2011, we filed an application for a general rate increase at the OPUC.  In the filing, we have requested an increase in authorized annual Oregon jurisdictional revenues of $43.7 million, equivalent to a rate increase of 6.2 percent.  The amount and percent of this rate increase includes an estimated $15.1 million that represents the cumulative effect of declining use per customer.  This cost is already included in customers’ current rates through the operation of the Company’s conservation tariff, which has been in place since 2003.  The increase also includes costs related to pension contributions and additional utility services.  The filing also requests an authorized overall rate of return on capital of 8.28 percent, with a return on common stock equity (ROE) of 10.3 percent and a capital structure of 50 percent common equity.  In addition, we have requested the establishment of rate recovery mechanisms for deferred costs related to our environmental liabilities.  The filing also requests rate redesign for residential customers with a higher fixed fee, which would effectively combine and incorporate the effects of the weather normalization and decoupling tariffs in the new fixed fee amount.  The new rates are requested to be effective by November 1, 2012.  We are unable to predict the outcome of this rate proceeding.

Our most recent general rate case in Oregon was effective September 2003. The OPUC authorized rates to customers based on an ROE of 10.2 percent.  In 2007, in connection with the renewal of our conservation tariff and weather normalization rate mechanism, the OPUC approved a stipulation that restricted us from filing a general rate case in Oregon prior to September 2011.  However, in 2011 the OPUC approved our gas reserve acquisition (see “Rate Mechanisms—Gas Reserves” below) with a condition that we file a general rate case by the end of 2011.  These agreements did not impact our requirement to file annual rate adjustments to reflect changes in gas purchase costs under the PGA mechanism or our ability to collect or refund prior year’s gas cost deferrals.  See “Rate Mechanisms—Purchased Gas Adjustment,” below.

Washington. Our most recent general rate case in Washington was in 2008, and in it the WUTC authorized rates to customers based on an ROE of 10.1 percent and an overall rate of return of 8.4 percent.  These customer rates went into effect on January 1, 2009, with annual revenue requirements increased by $2.7 million or 3 percent.

FERC Jurisdiction.We are required under our Mist interstate storage certificate authority and rate approval orders to file every five years either a petition for rate approval or a cost and revenue study to change or justify maintaining the existing rates for our interstate storage services.  Our most recent filing of a cost and revenue study was in April 2008.  As a result of that proceeding, the current maximum cost-based rates for our interstate gas storage services were approved by FERC, with maximum rates unchanged from prior levels approved by FERC in 2005.  In addition, we made a filing in December 2008 to obtain FERC approval to revise the depreciation rates associated with Mist assets used to derive the cost-based interstate storage rates.  These new depreciation rates were designed to match the depreciation rates for the same type of assets approved under state regulation.  We did not make any changes to the previously approved maximum rates, and FERC approved the depreciation rate filing in May 2009.  We are required to make our next cost and revenue study filing at FERC on or before December 11, 2013.

California.  Gill Ranch is authorized by the CPUC to charge market-based rates for the intrastate storage services offered to customers in California.

Rate Mechanisms

Purchased Gas Adjustment.  Rate changes are established for the utility each year under PGA mechanisms in Oregon and Washington to reflect changes in the expected cost of natural gas commodity purchases, including contract gas purchase prices, gas prices hedged with financial derivatives or physical gas reserves, gas inventory prices, interstate pipeline demand costs, the application of temporary rate adjustments to amortize balances in deferred regulatory accounts and the removal of temporary rate adjustments effective for the previous year.

In October 2011, the OPUC and WUTC approved PGA rate changes effective November 1, 2011.  The effect of these rate changes was to decrease the average monthly bills of Oregon and Washington residential customers by about 2 percent.  This was our third consecutive year of PGA rate decreases, and cumulatively our average utility residential customer bills declined 20 percent in Oregon and 26 percent in Washington since 2008.

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Under the current PGA mechanism in Oregon, there is an incentive sharing provision whereby we are required to select each year either an 80 percent or 90 percent deferral of higher or lower actual gas costs compared to estimated PGA prices, such that the impact on current earnings from the incentive sharing is either 20 percent or 10 percent of the difference between actual and estimated gas costs, respectively.  In addition to the gas cost incentive sharing mechanism, we are subject to an annual earnings test to determine if the utility is earning above its authorized ROE threshold. If utility earnings exceed a specific ROE level, then 33 percent of the amount above that level is required to be deferred for refund to customers.  Under this provision, if we select the 80 percent deferral option, then we retain all of our earnings up to 150 basis points above the currently authorized ROE.  If we select the 90 percent deferral option, then we retain all of our earnings up to 100 basis points above the currently authorized ROE. We selected the 90 percent deferral option for the 2009-10, the 2010-2011 and the 2011-2012 PGA years.  The ROE threshold is subject to adjustment annually based on movements in long-term interest rates.  For calendar years 2009 and 2010, the ROE threshold after adjustment for long-term interest rates was 11.5 percent and 11.02 percent, respectively.  No amounts were required to be refunded to customers as a result of the 2009 utility earnings test, while we are refunding $0.2 million to customers in the current PGA for the 2010 utility earnings test.  For 2011, we accrued an estimated $1.5 million for potential refund to customers in the next PGA.

There has been no change to the Washington PGA mechanism under which we defer 100 percent of the higher or lower actual gas costs, with those cost differences passed on to customers through an adjustment to future rates.

Gas Reserves.  In April, 2011 the OPUC approved the Encana gas reserve transaction for utility customers and determined that the Company’s costs under the agreement will be recovered, plus a rate base return on our investment, on an ongoing basis through our annual 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 results 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.

Conservation Tariff.  In October 2002, the OPUC authorized the implementation of a “conservation tariff” to adjust utility margin for changes in consumption patterns due to residential and commercial customers’ conservation efforts.  The conservation tariff is a decoupling mechanism that is intended to break the link between utility earnings and the quantity of gas consumed by customers, removing any financial incentive by the utility to discourage customers’ efforts to conserve energy. In Washington, customer use is not covered by a conservation or decoupling tariff, and as such our utility earnings are affected by increases and decreases in usage based on customers’ conservation efforts.  Washington customers account for about 10 percent of our utility volumes and revenues.

The Oregon conservation tariff includes two components:  (1) an annual price elasticity adjustment, which adjusts rates for increases or decreases from expected customer volumes due to changes in commodity costs or changes in our general rates; and (2) a monthly conservation adjustment, which adjusts margin revenues to account for the difference between actual and expected customer volumes (also referred to as the decoupling adjustment).  The margin adjustment resulting from differences between actual and expected volumes under the decoupling component is recorded to a deferral account, which is included in the next annual PGA filing.  Baseline consumption was determined by customer consumption data used in the 2003 Oregon general rate case and is adjusted annually for customer growth and the effect of the price elasticity adjustment discussed above.  From 2003 to 2011, we have experienced approximately 14 percent decline in average use per residential customer and approximately 8 percent decline in average use per commercial customer. As a result of these declines, customers have paid surcharges related to a decoupling adjustment in seven of the past nine heating seasons. See “Business Segments - Utility Operations,” below.

In 2005, an independent study was commissioned to measure the effectiveness of Oregon’s conservation tariff mechanism. The results of this study recommended continuation of the tariff with minor modifications. The tariff modifications were approved by the OPUC, and the mechanism was extended through October 2012.

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Weather Normalization Tariff.  In Oregon, we have an approved weather normalization mechanism applied to residential and commercial customer bills. This mechanism is designed to help stabilize the collection of fixed costs by adjusting residential and commercial customer billings based on temperature variances from average weather, with rate decreases when the weather is colder than average and rate increases when the weather is warmer than average. The mechanism is applied to bills between December 1 and May 15 of each heating season. The mechanism adjusts the margin component of customers’ rates to reflect average weather, which uses the 25-year average temperature for each day of the billing period.  Daily average temperatures and 25-year average temperatures are based on a set point temperature of 59 degrees Fahrenheit for residential customers and 58 degrees Fahrenheit for commercial customers (see “Business Segments - Utility Operations,” below).  The weather normalization mechanism for Oregon utility operations is approved through October 2012.  Customers in Oregon are allowed to opt out of the weather normalization mechanism, and as of December 31, 2011, 9 percent had opted out. We do not have a weather normalization mechanism approved for Washington customers, which account for about 10 percent of our utility volumes and revenues.

Industrial Tariffs.  The OPUC and WUTC approve tariffs covering utility service to our major industrial customers, including terms which are intended to give us certainty in the level of gas supplies we need to acquire to serve this customer group.  The terms include, among other things, an annual election period, special pricing provisions for out-of-cycle changes, and a requirement that industrial customers under our annual PGA tariff complete the term of their service election.

System Integrity Program.  Since 2002, various laws requiring minimum standards for integrity management programs and system integrity programs (SIP) for natural gas distribution pipelines have been enacted. Most recently, in January 2012 the “Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011” was signed into law and requires increased civil penalties for pipeline safety violations, improvements in prevention programs for pipelines, and additional review and analysis of various aspects of gas transmission lines. We are working diligently with industry associations and federal and state regulators to ensure NW Natural’s compliance with the provisions of this new law. 

The OPUC has approved specific accounting treatment and cost recovery for our transmission pipeline integrity management program, SIP, and the related rules adopted by the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA).  We record the costs related to the integrity management program as either capital expenditures or regulatory assets, accumulate the costs over each 12-month period, and recover the revenue requirement associated with the costs, subject to audit, through rate changes effective with the annual PGA in Oregon.  Our SIP costs are tracked into rates annually, with rate recovery after the first $3.3 million of capital costs. An annual cap for expenditures has been set at $12 million, but extraordinary costs above the cap may be approved with written consent of the OPUC staff and other interested parties and approval of the OPUC.  The SIP allows recovery of costs incurred in Oregon during the period from October 2008 through the effective date of our next general rate case.  We do not have any special accounting or rate treatment for our SIP costs incurred in the state of Washington.

Environmental Costs.  The OPUC has authorized us to defer environmental costs associated with certain named sites and to accrue a carrying cost on environmental costs paid, 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 accrual of carrying costs was extended through January 2012.  In January 2012, we filed a request with the OPUC to continue our deferral of these environmental costs.  See Note 15 for further discussion of our regulatory and insurance recovery of environmental costs.

The WUTC has also authorized the deferral of environmental costs, if any, that are incurred in connection with services provided to Washington customers.  The order granting approval of that request was effective January 26, 2011.

Pension Deferral.  Effective January 1, 2011, the OPUC approved our request to defer annual pension expenses above the amount set in rates in our last general rate case, with recovery of these deferred amounts through the implementation of a balancing account, which includes the expectation of higher and lower pension expenses in future years.  Our recovery of these deferred balances includes accrued interest on the account balance at the utility’s authorized rate of return, which is currently 8.62 percent.  The reduction to operations and maintenance expense for 2011 was $6.0 million.  Future years’ deferrals will depend on changes in plan assets and projected benefit liabilities using a number of key assumptions, as well as our pension contributions. We estimate deferrals totaling $8 million to $9 million in 2012.  See “Application of Critical Accounting Policies and Estimates,” above.

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Customer Credits for Gas Storage Sharing.  In June 2011, $12.5 million was credited to Oregon utility customers from our regulatory incentive sharing mechanism related to gas storage and asset management services of pipeline capacity and gas storage at Mist (see “Gas Storage,” below).  In June 2010, we credited $11.0 million to customers under the same regulatory sharing mechanism. Our Washington utility customers receive their respective share of this credit as part of the annual PGA filing.  In November 2011, a $0.9 million credit was placed in Washington utility customer rates for these activities, compared to a $1.2 million credit to Washington customers in November 2010.

Business Segments - Utility Operations

Utility net operating revenues (margins) are affected by customer growth, and to a certain extent, by changes in volume due to weather and customer consumption patterns because a significant portion of our revenues are derived from natural gas sales to residential and commercial customers.  In Oregon, we have a conservation tariff, which adjusts revenues to offset changes in margin resulting from increases or decreases in average use by residential and commercial customers, and a weather normalization tariff, which adjusts to offset changes in margin resulting from above- or below-average temperatures during the winter heating season (see “Results of Operations—Regulatory Matters—Rate Mechanisms,” above).  Both the conservation and weather normalization mechanisms have the effect of reducing the volatility of our utility earnings. We also have other regulatory mechanisms, which increase or decrease utility margins to account for other costs and revenues approved by the OPUC or WUTC. See “Results of Operations—Regulatory Matters—Rate Mechanisms,” below.

2011 compared to 2010:

Our utility segment in 2011 earned $60.5 million, or $2.26 per share, compared to $66.3 million, or $2.49 per share in 2010. The major factors contributing to the change was a $14.9 million reduction in utility margins related to the repealed Oregon legislative rule on utility income taxes paid, including of a $7.4 million write-off in 2011 plus a $7.7 million revenue accrual recognized in 2010, and a net gain of $6.1 million recognized in 2010 related to a refund of property taxes plus accrued interest from a favorable tax ruling. These were partially offset by increases in residential and commercial customer margins of $11.3 million, including the effects of weather normalization and decoupling mechanisms, a slight gain in industrial customer margins of $0.2 million, and an increase in gas cost incentive sharing of $0.5 million.  Total utility volumes sold and delivered in 2011 increased 9 percent over last year primarily due to the impact of colder weather on residential and commercial use. 

Our weather normalization mechanism adjusted residential and commercial margins down by $13.1 million for the year ended December 31, 2011 based on weather that was 9 percent colder than average, compared to a margin increase of $14.0 million for the year ended December 31, 2010 when weather was 2 percent warmer than average.  Our decoupling mechanism adjusted residential and commercial margins up by $19.3 million in 2011, after adjusting for expected price elasticity impacts from lower PGA prices effective November 1, 2010, compared to margin adjustments up by $15.5 million in 2010.

2010 compared to 2009:

Our utility segment in 2010 earned $66.3 million, or $2.49 per share, compared to $66.0 million, or $2.48 per share in 2009. The major factors contributing to the change were reduced operating expenses largely offset by lower utility margins. The lower margins consisted of a $13.5 million decrease from the prior year’s gas cost incentive sharing, partially offset by a net $5 million increase from residential and commercial customers, including the effects of the weather normalization and decoupling mechanisms, and a $0.7 million increase in industrial margin.  Total utility volumes sold and delivered in 2010 decreased by 6 percent over last year due to the effects of warmer weather on residential and commercial use and the lingering effects of a weak economy on commercial and industrial use. The regulatory adjustment for income taxes paid increased margin by $1.8 million compared to 2009.

Our weather normalization mechanism adjusted residential and commercial margins up by $14.0 million for the year ended December 31, 2010 based on weather that was 2 percent warmer than average, compared to a margin reduction of $15.2 million for the year ended December 31, 2009 when weather was 3 percent colder than average.  Our decoupling mechanism adjusted residential and commercial margins up by $15.5 million in 2010, after adjusting for expected price elasticity impacts from lower PGA prices effective November 1, 2009, compared to margin adjustments totaling $11.6 million in 2009.

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 The following table summarizes the composition of gas utility volumes and revenues for the years ended December 31, 2011, 2010 and 2009:

											Favorable/(Unfavorable)
Thousands, except degree day and customer data		2011			2010			2009			2011 vs. 2010			2010 vs. 2009
Utility volumes - therms:
Residential sales			425,139			368,682			412,867			56,457			(44,185	)
Commercial sales			259,675			230,196			255,593			29,479			(25,397	)
Industrial - firm sales			37,344			37,085			39,447			259			(2,362	)
Industrial - firm transportation			129,898			127,796			124,218			2,102			3,578
Industrial - interruptible sales			59,308			58,387			72,525			921			(14,138	)
Industrial - interruptible transportation			240,990			239,823			226,715			1,167			13,108
	Total utility volumes sold and delivered		1,152,354			1,061,969			1,131,365			90,385			(69,396	)
Utility operating revenues - dollars:
Residential sales		$	492,490		$	456,174		$	555,844		$	36,316		$	(99,670	)
Commercial sales			244,922			227,994			292,697			16,928			(64,703	)
Industrial - firm sales			30,455			30,830			41,407			(375	)		(10,577	)
Industrial - firm transportation			6,250			5,702			5,671			548			31
Industrial - interruptible sales			34,961			36,164			62,116			(1,203	)		(25,952	)
Industrial - interruptible transportation			9,169			8,131			7,964			1,038			167
Regulatory adjustment for income taxes paid(1)			(7,162	)		7,721			5,884			(14,883	)		1,837
Other revenues			11,134			17,917			21,166			(6,783	)		(3,249	)
	Total utility operating revenues		822,219			790,633			992,749			31,586			(202,116	)
Cost of gas sold			458,508			424,494			611,088			(34,014	)		186,594
Revenue taxes			20,741			19,991			24,656			(750	)		4,665
	Utility margin	$	342,970		$	346,148		$	357,005		$	(3,178	)	$	(10,857	)
Utility margin:(2)
Residential sales		$	222,526		$	197,045		$	217,124		$	25,481		$	(20,079	)
Commercial sales			86,971			77,831			85,850			9,140			(8,019	)
Industrial - sales and transportation			28,635			28,451			27,713			184			738
Miscellaneous revenues			4,875			4,658			6,670			217			(2,012	)
Gain (loss) from gas cost incentive sharing			2,107			1,594			15,064			513			(13,470	)
Other margin adjustments			(1,173	)		(647	)		2,308			(526	)		(2,955	)
	Margin before regulatory adjustments		343,941			308,932			354,729			35,009			(45,797	)
Weather normalization adjustment			(13,106	)		13,996			(15,236	)		(27,102	)		29,232
Decoupling adjustment			19,297			15,499			11,628			3,798			3,871
Regulatory adjustment for income taxes paid(1)			(7,162	)		7,721			5,884			(14,883	)		1,837
	Utility margin	$	342,970		$	346,148		$	357,005		$	(3,178	)	$	(10,857	)
Customers - end of period:
Residential customers			615,670			610,598			604,692			5,072			5,906
Commercial customers			62,948			62,489			62,169			459			320
Industrial customers			925			910			933			15			(23	)
	Total number of customers - end of period		679,543			673,997			667,794			5,546			6,203
Actual degree days			4,652			4,171			4,383
Percent colder (warmer) than average weather(3)			9	%		(2	) %		3	%
(1)	Regulatory adjustment for income taxes paid is described below.
(2)	Amounts reported as margin for each category of customers are net of cost of gas sold and revenue taxes.
(3)	Average weather represents the 25-year average degree days, as determined in our last Oregon general rate case.

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Residential and Commercial Sales

The primary factors that impact results of operations in the residential and commercial markets are customer growth, seasonal weather patterns, energy prices, competition from other energy sources and economic conditions in our service areas.  Typically, 80 percent or more of our annual utility operating revenues are derived from gas sales to weather-sensitive residential and commercial customers.  Although variations in temperatures between periods will affect volumes of gas sold to these customers, the effect on margin and net income is significantly reduced due to our weather normalization mechanism in Oregon where about 90 percent of our customers are served.  For more information on our weather mechanism, see “Regulatory Matters—Rate Mechanisms—Weather Normalization,” above.

The primary changes that impacted margin from residential and commercial sales were as follows:

2011 compared to 2010:

·   utility volumes were 14 percent higher, primarily reflecting 12 percent colder weather; sales volumes to core utility customers are sensitive to weather variations especially in the winter-heating season;

·   utility operating revenues increased $53.2 million or 8 percent primarily due to the 14 percent volume increase;

·   utility margin increased $11.3 million or 4 percent primarily due to customer growth of 0.8 percent and colder weather, with colder weather benefits partially offset by weather normalization adjustments that reduce customer bills and Company margins when weather is colder than average.

2010 compared to 2009:

·   utility volumes were 10 percent lower, primarily reflecting 5 percent warmer weather, conservation efforts and weak economic conditions;

·   utility operating revenues decreased $164.4 million or 19 percent primarily due to the 10 percent volume decline and customer rate decreases of 16 and 22 percent in Oregon and Washington, respectively, effective November 1, 2009; and

·   utility margin increased $5 million or 2 percent primarily due to customer growth of 0.9 percent and the colder weather in the spring of 2010 that was not entirely offset by Oregon’s weather normalization mechanism.

Industrial Sales and Transportation

Operating revenues from industrial customers include the commodity cost component of gas sold under sales service but not under transportation service. Therefore, operating revenues from industrial customers can increase or decrease when customers switch between sales service and transportation service, but generally our margins from these customers are unaffected by these changes because we do not generally include a profit mark-up for the cost of gas. As such, we believe volumes delivered and margins are better measures of performance for the industrial sector. The primary changes that impacted margin from industrial sales and transportation were as follows:

2011 compared to 2010:

·   volumes delivered to industrial customers increased 4.4 million therms, or 1 percent, reflecting increased energy demand, with the majority of the increased volume attributable to the manufacturing sector; and

·   margins increased $0.2 million, or 1 percent.

2010 compared to 2009:

·   volumes delivered to industrial customers increased 0.2 million therms; and

·   margin increased $0.7 million, or 3 percent.

The slight margin increases in 2011 and 2010 were primarily due to an increase in industrial use of natural gas as a result of higher costs for oil and propane fuels, which caused some customers to switch to natural gas. Partially offsetting this trend was the loss of a few large industrial customers due to the economy.

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     Regulatory Adjustment for Income Taxes Paid

From 2007 through 2010, Oregon law required the Company and certain regulated natural gas and electric utilities to annually review the amount of income taxes collected in rates from utility operations and compare it to the amount the utility actually pays to taxing authorities.  Under this law, if the amount paid for income taxes related to utility operations is less than the amount collected from Oregon utility customers, then we were required to refund the excess to Oregon utility customers.  Conversely, if the amount paid in income taxes was more than the amount collected from Oregon utility customers, then we were required to collect a surcharge from Oregon utility customers.

The Company’s income tax review resulted in a surcharge to customers each year SB 408 was in effect.  For 2009, the OPUC approved the Company’s recovery of $5.1 million plus interest from customers.  For the 2010 tax year, we originally estimated and accrued $7.1 million.  However, when SB 967 was signed into law in May of 2011, it effectively repealed the regulatory adjustment for income taxes paid for the 2010 tax year and all years thereafter, thus resulting in the Company recording a $7.4 million write-off in the second quarter of 2011 to write-off the amount from SB 408, plus interest, related to 2010 tax year. Results related to SB 408 for 2011 were a pre-tax loss of $7.4 million, compared to pre-tax gains of $7.7 million in 2010 and $5.9 million in 2009.

SB 967 requires the OPUC to make decisions in future ratemaking proceedings on the amounts of income taxes to be recovered in customer rates. For additional information, see “Revenue Recognition” above under Application of Critical Accounting Policies and Estimates.

      Other Revenues

Other revenues include miscellaneous fee income as well as regulatory revenue adjustments, which reflect current period deferrals to and prior year amortizations from, regulatory asset and liability accounts, except for gas cost deferrals which flow through cost of gas sold.  Other revenues increased utility margins by $11.1 million in 2011, compared to $17.9 million in 2010 and $21.2 million in 2009.

2011 compared to 2010:

Other revenues decreased $6.8 to $11.1 million in 2011 primarily reflecting a decrease in the amortization of decoupling adjustments totaling $5.9 million and a decrease in other regulatory amortizations of $4.6 million, partially offset by a $1.0 million increase in the refund to utility customers related to gas storage incentive sharing mechanism and an increase in the current decoupling deferral of $3.8 million.

Decoupling amortizations and other regulatory amortizations from prior year deferrals are included in current or future revenues from residential, commercial and industrial firm customers.

2010 compared to 2009:

Other revenues decreased $3.2 to $17.9 in 2010 primarily reflecting an increase in the amortization of decoupling adjustments totaling $7.9 million, partially offset by a $4.0 million increase in the refund to utility customers related to gas storage incentive sharing mechanism.

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Cost of Gas Sold

The cost of gas sold includes gas purchases, gas drawn from storage inventory, gains and losses from commodity hedges, pipeline demand costs, seasonal demand cost balancing adjustments, regulatory gas cost deferrals, production from gas reserves, and company gas use.   The OPUC and the WUTC generally require the natural gas commodity costs to be billed to customers at the same cost incurred or expected to be incurred by the utility.  We have not historically earned a profit or incurred a loss on gas commodity purchases; however, in Oregon we have an incentive sharing provision whereby we can either increase or decrease margin revenues from gas cost variances as compared to gas costs embedded in the PGA.  Under this provision, our net income can be affected by differences between actual and expected purchased gas costs, which occur primarily because of market fluctuations and volatility affecting unhedged gas purchases. In addition, we recently entered into a regulatory agreement where we receive a rate base return on our investment in gas reserves. (see “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment and Regulatory Matters—Rate Mechanisms—Gas Reserves,” above).  We use natural gas commodity-based hedge contracts (derivatives), primarily fixed-price commodity swaps, consistent with our financial derivatives policies to help manage our exposure to rising gas prices.  Gains and losses from financial hedge contracts are generally included in our PGA prices and normally do not impact net income because the hedge prices are usually 100 percent passed through to customers in annual rate changes, subject to a regulatory prudency review. However, utility hedge contracts entered into after the annual PGA rates are set in Oregon can impact net income because we would be required to share in any gains or losses compared to the corresponding commodity prices included in rates in the PGA. In Washington, 100 percent of the actual gas costs, including hedge gains and losses allocated to Washington gas sales, are passed through in customer rates (see “Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities,” and “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” above, and Note 15).  The following summarizes the major factors that contributed to changes in cost of gas sold:

2011 compared to 2010:

·   total cost of gas sold increased $34 million, or 8 percent, due to an 9 percent increase in total sales volumes partially offset by a 4 percent decrease in the average cost of gas sold per therm;

·   the average gas cost collected through rates decreased from 61 cents per therm in 2010 to 59 cents per therm in 2011, primarily reflecting lower commodity prices that were passed through to PGA rate decreases effective November 1, 2010 and 2011; and

·   hedge losses totaling $56.5 million were realized and included in cost of gas sold for the year ended December 31, 2011, compared to $61.0 million of hedge losses in the same period of 2010.

2010 compared to 2009:

·   total cost of gas sold decreased $186.6 million, or 31 percent, due to a 6 percent decrease in total sales volumes and a 22 percent decrease in the average cost of gas sold per therm;

·   the average gas cost collected through rates decreased from 78 cents per therm in 2009 to 61 cents per therm in 2010, primarily reflecting lower commodity prices that were passed through to PGA rate decreases effective November 1, 2009 and 2010; and

·   hedge losses totaling $61.0 million were realized and included in cost of gas sold for the year ended December 31, 2010, compared to $187.9 million of hedge losses in the same period of 2009.

Actual gas costs in both 2011 and 2010 were slightly below those embedded in rates, while in 2009 actual gas costs were significantly lower. The effect on shareholders from the gas cost incentive sharing mechanism was a contribution to margin of $2.1 million in 2011, $1.6 million in 2010 and $15.1 million in 2009.  For a discussion of our gas cost incentive sharing mechanism, see “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” above.

Gas Storage

Our gas storage segment consists of the non-utility portion of our Mist underground storage facility and our 75 percent ownership interest in the Gill Ranch facility. For the year ended December 31, 2011, we earned $4.1 million, or 15 cents per share, from gas storage compared to $6.1 million, or 23 cents per share, for 2010.  The primary reason for the decline was lower storage pricing driven by lower, more stable gas costs.

At Mist, we provide gas storage services to customers in the interstate and intrastate markets primarily using storage capacity that has been developed in advance of core utility customers’ requirements.  Under a regulatory incentive sharing mechanism in Oregon, we retain 80 percent of pre-tax income from Mist gas storage services, and from asset management services, when the underlying costs of the capacity being used are not included in our utility rates, and 33 percent of pre-tax income from such storage and asset management services when the capacity being used is included in utility rates.  The remaining 20 percent and 67 percent, respectively, are credited to a deferred regulatory account for credit to our core utility customers. We have a similar sharing mechanism in Washington for pre-tax income derived from gas storage and asset management services.  

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            Our 75 percent undivided ownership interest in the Gill Ranch facility is held by our wholly-owned subsidiary Gill Ranch, which is also the operator of the project.  Our portion of the facility is currently designed to provide 15 Bcf of gas storage capacity by the end of 2012.  Gill Ranch commenced operations at the end of October 2010 and had approximately 13 Bcf of storage capacity available for contracting to customers beginning April 1, 2011, which was the beginning of the first full storage injection season at Gill Ranch, after a partial injection season, which commenced in October 2010.  See Note 4.

Other

Our other business segment consists of NNG Financial, an investment in PGH, and other non-utility investments and business activities.  NNG Financial had total assets of $1.1 million as of both December 31, 2011 and 2010 primarily reflecting a non-controlling minority interest in the Kelso-Beaver interstate gas transmission pipeline.  Our equity investment in PGH as of December 31, 2011 and 2010 was $13.5 million and $14.8 million, respectively.  Total earnings from our other business segment as of December 31, 2011 and 2010 was a net loss of $0.7 million and net income of $0.3 million, respectively. The loss for 2011 was primarily due to approximately $1.3 million of charges on our investment in PGH. See Note 4.

Consolidated Operations

Operations and Maintenance

Operations and maintenance expense was $125.3 million in 2011, compared to $121.0 million in 2010, an increase of $4.3 million or 4 percent. The following summarizes the major factors that contributed to changes in operations and maintenance expense:

2011 compared to 2010:

·   a $3.2 million increase in operating expenses at Gill Ranch related to the first full year of operations;

·   a $2.3 million increase in utility payroll expense related to additional field support staff and general pay increases;

·   a $1.2 million increase in utility health care costs and other related employee benefit expense (see further discussion below);

·   a $1.5 million increase in other non-payroll expense at the utility for costs related to the general rate case of $0.7 million, storage leases of $0.3 million, and pipeline integrity and corporate ethics initiatives of $0.2 million; and

·   a $0.2 million increase in utility bad debt expense (see further discussion below).

Partially offsetting the above factors were:

·   a $1.8 million decrease in performance bonuses at the utility based on below-target results compared to last year;

·   a $1.5 million decrease in pension expense due to the regulatory deferral of costs above the amount net in rates (see further discussion below); and

·   a $1.0 million decrease in specific consulting and legal fees which were incurred by the utility in 2010 related to our successful property tax appeal.

2010 compared to 2009:

·    a $5.6 million decrease in utility payroll expense related to a reduced number of employees.  There was a reduction of 105 employees or 9 percent over the two year period beginning January 2009;

·   a $2.4 million decrease in utility bad debt expense (see further discussion below);

·   a $1.9 million decrease in pension expense, due to the increase in market value of plan investments from contributions in 2009 and 2010;

·   a $1.5 million decrease in health care and other employee benefit expense due to reduced employee count, offset by an increase in healthcare premiums (see further discussion below); and

·   a $0.2 million decrease in damage claims in 2010.

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     Partially offsetting the above increases were:

·    a $4.9 million increase in gas storage expenses, primarily related to start-up costs including salaries and benefits, power costs, legal fees and investment bank consulting costs; and

·   a $1.0 million increase for consulting and legal fees at the utility related to a successful property tax appeal.

Our bad debt expense as a percent of revenues was 0.23 percent for the year ended December 31, 2011, compared to 0.21 percent for the same period last year. The comparative increase in our bad debt expense ratio was largely due to lower than normal expense ratio in 2010 due to improved collections and higher recoveries of delinquent account balances.  Despite the modest increase, we believe bad debt losses are comparable to last year and credit risks remain elevated due to the weak economy and high unemployment rates.  Higher customer usage from colder weather these past few months may increase our exposure to credit losses in the near term, but we expect bad debt expense over the long term to remain below 0.5 percent of revenues.

Overall national healthcare spending has slowed as a result of the weak economy; however, healthcare trends for the cost of the services provided are forecasted to continue to rise at around 10 percent to 11 percent year over year. Initial projections for increases to employer paid premiums for 2012 are estimated to be between 7 percent and 9 percent.  Based on our actual premium increase for 2012, NW Natural’s employer paid portion of health premiums (medical, dental, vision) are expected to increase 6 percent.

In addition, total pension costs are expected to increase in 2012.  However, effective January 1, 2011 the OPUC approved the deferral of utility pension expense above the amount recovered in rates, which was set in our last general rate case. The pension expense deferral is recorded to a regulatory balancing account, which reduced operations and maintenance expense by $6.0 million for 2011, and we expect additional cost deferrals to the pension balancing account in 2012 at or above the levels of 2011.  For further explanation of the pension balancing account, see “Regulatory Matters—Rate Mechanisms—Pension Deferral,” above.

                General Taxes

General taxes, which are principally comprised of property and payroll taxes and regulatory fees, increased $5.4 million, or 23 percent, in 2011 compared to 2010, and decreased $4.4 million, or 16 percent, in 2010 compared to 2009.  The major factors that contributed to changes in general taxes are:

2011 compared to 2010:

·   a  $5.2 million increase due to the refund of property taxes in 2010 pursuant to a favorable ruling from the Oregon Supreme Court regarding taxation of utility gas inventory held for sale (see further discussion below); and

·   a $1.3 million increase in property taxes at Gill Ranch as a result of the first full year of operations.

2010 compared to 2009:

·    a $5.2 million decrease due to the refund of property taxes received in 2010, as mentioned above, partially offset by an increase in property taxes related to a 2 percent increase in net utility plant balances.

Prior to 2011, we had been involved for a number of years in litigation with the ODOR over whether inventories held for sale were required to be taxed as personal property.   In January 2010, the Oregon Supreme Court unanimously ruled in our favor, stating that these inventories were exempt from property tax.  As a result of this ruling, we were entitled to a refund of approximately $5.2 million, plus accrued interest, for property taxes paid on inventories beginning with the 2002-03 tax year.  We recognized a net $6.1 million increase in pre-tax income in the first quarter of 2010, which consisted of $5.2 million for the refund of property taxes, $1.9 million for accrued interest income, and $1.0 million of increased operations and maintenance expense for legal and consulting services.  We received all of the property tax refunds in 2010.

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Depreciation and Amortization

Total depreciation and amortization expense in 2011 increased by $4.9 million, or 7 percent, as compared to a $2.3 million or 4 percent increase in 2010 over 2009. The increased expense in 2011 was primarily related to an increase of $3.7 million in Gill Ranch’s depreciation, plus additional depreciation on investments in utility plant for customer growth and system improvements. The increased expense in 2010 was primarily related to $1.1 million of depreciation at Gill Ranch as they went into service in the fourth quarter of 2010, plus additional depreciation on investments in utility plant.   

Other Income and Expense – Net

      The following table provides details on other income and expense – net for the last three years:

Thousands	2011			2010			2009
Gains from company-owned life insurance	$	2,247		$	2,042		$	3,416
Interest income		50			2,024			211
Income (loss) from equity investments		(1,641	)		588			1,329
Net interest on deferred regulatory accounts		5,999			4,692			2,051
Gain (loss) on sale of investments		(96	)		223			45
Other non-operating		(2,036	)		(2,467	)		(3,338	)
Total other income and expense - net	$	4,523		$	7,102		$	3,714

2011 compared to 2010:

Other income and expense – net decreased $2.6 million, primarily due to $1.9 million of interest income received from the property tax refund in 2010 which did not occur in 2011, a $1.4 million loss from equity investments due to Palomar charges (see Note 12), partially offset by a $1.3 million increase in interest and carrying costs from regulatory account balances largely due to smaller balances in gas costs between 2011 and 2010. See discussion of Palomar in “Strategic Opportunities—Pipeline Diversification” above.

2010 compared to 2009:

Other income and expense – net increased $3.4 million, primarily due to $1.9 million of interest income related to property tax refund plus a $2.6 million increase in interest from regulatory account balances largely due to smaller balances in gas costs between 2010 and 2009, partially offset by a $1.4 million decrease in income from life insurance due to higher policy gains realized in 2009.

Interest Expense – Net

Interest expense—net of amounts capitalized in 2011 decreased by $0.5 million, or 1 percent, compared to 2010, and increased in 2010 by $1.9 million, or 5 percent, compared to 2009.  The current year decrease was primarily due to a $1.9 million savings from interest expense on long-term debt as a result of bonds that were redeemed in 2010, partially offset by a $1.1 million increase for gas storage interest expense related to the Gill Ranch base gas agreement, as well as the issuance of $50 million of 3.176 percent medium term notes (MTN’s) in September 2011 and the issuance of $40 million of subsidiary senior secured notes with an average interest rate of 7.38 percent for Gill Ranch in November 2011. The increases in 2010 compared to 2009 reflect the issuance of long-term debt during 2009, which included $75 million of 5.37 percent MTN’s issued in March 2009 and $50 million of 3.95 percent MTN’s issued in July 2009, and higher short-term debt balances.  Interest expense also reflects a lower average interest rate used in calculating the allowance for funds used during construction, which is referred to as AFUDC.  AFUDC rates, comprised of short-term and long-term capital costs as appropriate, were 0.5 percent in 2011, 0.6 percent in 2010 and 1.0 percent in 2009.

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Income Tax Expense

The decrease in income tax expense of $6.1 million, or 12 percent, compared to 2010 was primarily due to lower pre-tax consolidated earnings. Effective tax rate for 2011 and 2010 was 40.4 percent, compared to 40.5 percent in 2010 and 38.3 percent in 2009.  Income tax expense increased $2.8 million, or 6 percent, for the year ended December 31, 2010 compared to 2009, primarily due to higher pre-tax consolidated earnings and a slightly higher effective tax rate.  

For the 2011 tax year, the lower effective tax rate was primarily due to a decrease in state tax expense (see further discussion below). For the 2010 tax year, the higher effective tax rate was primarily the result of increased amortization of our regulatory tax account on pre-1981 utility plant assets (see “Regulatory Matters—Rate Mechanisms,” above) and a lower non-taxable gain on company-owned life insurance. For more information on our income taxes, including a reconciliation between the statutory federal and state income tax rates and the effective rate, see Note 2 and Note 10.

In July 2009, the governor of Oregon signed House Bill 3405 establishing increases in the state income tax rate for corporations, and Oregon voters approved this legislation in January 2010.  The corporate income tax rate in Oregon increased from 6.6 percent to 7.9 percent for tax years 2009 and 2010 when taxable income was greater than $250,000.  For tax years 2011 and 2012, the state income tax rate decreased to 7.6 percent, and for years after 2012 the tax rate will return to 6.6 percent, except for corporations with taxable income over $10 million the tax rate will remain at 7.6 percent.  Following existing accounting guidance on income taxes, we re-measured our deferred income tax assets and liabilities, resulting in an adjustment to increase the balance by $3.6 million in 2009.  Approximately $3.5 million of the adjustment was attributed to our utility operations.  As we anticipate future recovery in rates, we recorded a regulatory asset for the grossed up revenue requirement.  With respect to our non-utility business segments, a $0.1 million adjustment was charged to income tax expense in 2009.  In 2010 we decreased the deferred income tax liability by $0.8 million as a result of the decrease from 7.9 percent to 7.6 percent.  This decrease was almost entirely attributable to the utility business.

Financial Condition

Capital Structure

One of our long-term goals is to maintain a strong consolidated capital structure, generally consisting of 45 to 50 percent common stock equity and 50 to 55 percent long-term and short-term debt.  When additional capital is required, debt or equity securities are issued depending upon both the target capital structure and market conditions. These sources of financing are also used to fund long-term debt redemptions and short-term commercial paper maturities (see “Liquidity and Capital Resources,” below, and Notes 7 and 8).  Achieving the target capital structure and maintaining sufficient liquidity to meet operating requirements are necessary to maintain attractive credit ratings and have access to capital markets at reasonable costs.  Our consolidated capital structure was as follows for the years ended December 31, 2011 and 2010:

	December 31,
	2011			2010
Common stock equity		46.5	%		44.7	%
Long-term debt		41.7	%		38.1	%
Short-term debt, including current maturities of long-term debt		11.8	%		17.2	%
Total		100	%		100	%

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Liquidity and Capital Resources

At December 31, 2011, we had $5.8 million of cash and cash equivalents, compared to $3.5 million at December 31, 2010. We also had $4.0 million in restricted cash at Gill Ranch as of December 31, 2011, which is being held as collateral for long-term debt outstanding, compared to $0.9 million as of December 31, 2010, which was being held as collateral for equipment purchase contracts and construction loans.  In order to maintain sufficient liquidity during periods of volatile capital markets, at times we will maintain higher cash balances, add short-term borrowing capacity, and potentially pre-fund utility capital expenditures when long-term fixed rate environments are attractive.  As a regulated entity, our issuance of equity securities and most forms of debt securities are subject to approval by the OPUC and WUTC, and our use of proceeds from utility specific issuances are restricted to certain utility purposes.  Our use of retained earnings is not subject to those same restrictions.

For the utility segment, our short-term liquidity is supported by cash balances, internal cash flow from operations, proceeds from the sale of commercial paper notes, borrowings from multi-year credit facilities, cash available from surrender value in company-owned life insurance policies, and proceeds from the sale of long-term debt. We use utility long-term debt proceeds to finance utility capital expenditures, refinance maturing debt of the utility and provide for general corporate purposes of the utility.  

Capital markets over the past few years, including the commercial paper market, experienced significant volatility and tight credit conditions, but conditions have been improving as reflected by tighter credit spreads and increased access to new financing for investment grade issuers. With our current debt ratings (see “Credit Ratings,” below), we have been able to issue commercial paper and MTNs at attractive rates and have not needed to borrow from our back-up credit facilities. In the event that we are not able to issue new debt due to market conditions, we expect that our near term liquidity needs can be met by using cash balances or, for the utility segment, drawing upon our committed credit facilities. We also have a universal shelf registration filed with the SEC for the issuance of secured and unsecured debt or equity securities, subject to market conditions and regulatory approvals.  As of December 31, 2011, we have OPUC approval to issue up to $125 million of additional MTNs under the existing shelf registration for approved purposes.

In the event that our senior unsecured long-term debt credit ratings are downgraded, or our outstanding derivative position exceeds a certain credit threshold, our counterparties under derivative contracts could require us to post cash, a letter of credit or other form of collateral, which could expose us to additional cash requirements and may trigger significant increases in short-term borrowings.  If the credit risk-related contingent features underlying these contracts were triggered on December 31, 2011, we could have been required to post up to $45.9 million of collateral to our counterparties, but that assumes our long-term debt ratings were downgraded to non-investment grade levels, which would be a very significant change from current rating levels for NW Natural (see Note 13 and “Credit Ratings,” below).

Additionally, in July 2010, the U.S. Congress passed and President Obama signed into law the “Wall Street Reform and Consumer Protection Act.” The legislation requires additional government regulation of derivative and over-the-counter transactions, and could expand collateral requirements.  While we continue to evaluate the legislation to determine its impact, if any, on our hedging procedures, results of operations, financial position and liquidity, we do not expect to know the full impact of the legislation until final regulations implementing the legislation are issued.

Recent developments that may have a significant impact on our liquidity and capital resources include pension contribution requirements, tax benefits, and environmental expenditures and insurance recoveries.  With respect to pension requirements, we expect to make significant contributions over the next seven years until we are fully funded under the Pension Protection Act rules (see “Pension Cost and Funding Status of Qualified Retirement Plans,” below).  With respect to federal income tax liabilities, an extension was granted that allows us to take 100 percent bonus depreciation on qualified expenditures during 2011, and 50 percent bonus depreciation on a majority of our capital expenditures in 2012, which will significantly reduce our tax liability for the 2011 and 2012 tax years thereby providing cash flow benefits in late 2012 and 2013 (see “Cash Flows—Operating Activities,” below).  With respect to environmental liabilities, we expect to continue using cash resources to fund our environmental liabilities, but we also anticipate recovering amounts through insurance or utility rates over the next several years, although the amount and timing of these expenditures and recoveries is uncertain (see Note 15).

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Our storage segment’s short-term liquidity is supported by cash balances, internal cash flow from operations, external financing, and to a certain extent on funding from its parent company.  Gill Ranch has a limited operational history, having begun operations in October 2010.  Although we anticipate operating cash flows to be sufficient for liquidity purposes, the amount and timing of these cash flows are uncertain.  In November 2011, Gill Ranch issued $40 million of senior secured notes, with fixed interest rate component on $20 million and a variable interest rate on the remaining $20 million. The average combined interest rate on the notes was 7.38 percent per annum in 2011.  These notes are secured by our membership interest in Gill Ranch Storage, LLC, and are nonrecourse to NW Natural.  The maturity date of these notes is November 30, 2016.

Under the note agreements, Gill Ranch is subject to certain covenants and restrictions, including but not limited to, a financial covenant that requires Gill Ranch to maintain minimum adjusted EBITDA at various levels over the term of the notes. The minimum adjusted EBITDA increases incrementally over the first few years, reaching its highest level in the 12-month period beginning April 1, 2015. Under the agreements, Gill Ranch is also subject to a debt service reserve requirement of 10 percent of the outstanding principal amount, initially $4 million, certain prepayment penalties, restrictions on dividends out of Gill Ranch unless certain earnings ratios are met, and restrictions on incurrence of additional debt.

Based on several factors, including our current credit ratings, our commercial paper program, current cash reserves, committed credit facilities, and our expected ability to issue long-term debt under our universal shelf registration, we believe our liquidity is sufficient to meet anticipated near-term cash requirements, including all contractual obligations and investing and financing activities discussed below.

Dividend Policy

We have paid quarterly dividends on our common stock each year since the stock was first issued to the public in 1951. Annual common stock dividend payments per share, adjusted for stock splits, have increased each year since 1956.  The amount and timing of dividends payable on our common stock is within the sole discretion of our Board of Directors. Subject to Board approval, we expect to continue paying quarterly cash dividends on common stock.  However, the declarations and amount of future dividends will depend upon our earnings, cash flows, financial condition and other factors including Board approval.

Off-Balance Sheet Arrangements

Except for certain lease and purchase commitments (see “Contractual Obligations,” below), we have no material off-balance sheet financing arrangements.

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Contractual Obligations

The following table shows our contractual obligations at December 31, 2011 by maturity and type of obligation.

	Payments Due in Years Ending December 31,
Thousands	2012		2013		2014		2015		2016		Thereafter		Total
Commercial paper	$	141,600	$	-	$	-	$	-	$	-	$	-	$	141,600
Long-term debt maturities		40,000		-		60,000		40,000		65,000		476,700		681,700
Interest on long-term debt		39,056		38,145		37,984		36,489		33,518		228,311		413,503
Postretirement benefit payments(1)		21,430		21,703		22,245		22,789		23,482		133,978		245,627
Capital leases		443		313		118		23		-		-		897
Operating leases		4,929		4,841		5,078		5,042		5,018		24,659		49,567
Gas purchases(2)		98,534		18,331		15,290		5,651		-		-		137,806
Gas pipeline commitments		94,491		87,983		82,898		72,316		61,358		287,541		686,587
Gas reserves(3)		59,040		51,660		49,200		41,820		-		-		201,720
Other purchase commitments		-		157		82		37		-		13,559		13,835
Total	$	499,523	$	223,133	$	272,895	$	224,167	$	188,376	$	1,164,748	$	2,572,842

(1)   The majority of postretirement benefit payments are related to our qualified defined benefit pension plans, which are funded by plan assets and future cash contributions.  See Note 9.

(2)   Gas purchases include contracts which use price formulas tied to monthly index prices, plus hedged derivative liabilities. Commitment amounts are based on futures prices as of December 31, 2011.  For a summary of derivatives/liabilities, see Note 13. For a summary of gas purchase commitments, see Note 15.

(3)   Gas reserves contracts include provisions for cancelation, under which further payment would not be required.

Other purchase commitments primarily consist of remaining balances under existing purchase orders. These and other contractual obligations are financed with cash from operations and from issuance of short-term debt, which is periodically refinanced through the sale of long-term debt or equity securities.

At December 31, 2011, 598 of our utility employees were members of the Office and Professional Employees International Union Local No. 11.  In July 2009, these union employees and the Company agreed to a new five-year labor agreement called the Joint Accord.  The Joint Accord provides for a one percent automatic wage increase each year, plus the potential for us to an additional two percent based on wage inflation and other factors. It also provides competitive health benefits while limiting the cost increases for these benefits to the same level as the annual wage increases.  The term of the new Joint Accord extends to May 31, 2014, and thereafter from year to year unless either party serves notice of its intent to negotiate modifications to the collective bargaining agreement.

Short-Term Debt

Our primary source of utility short-term liquidity is from internal cash flows and the sale of commercial paper.  In addition to issuing commercial paper to meet working capital requirements, including seasonal requirements to finance gas inventories and accounts receivable, short-term debt may also be used to temporarily fund utility capital requirements.  Commercial paper is periodically refinanced through the sale of long-term debt or equity securities.  Our outstanding commercial paper, which is sold through two commercial banks under an issuing and paying agency agreement, is supported by one or more unsecured revolving credit facilities (see “Credit Agreements,” below).  Our commercial paper program did not experience any liquidity disruptions as a result of the credit problems that affected issuers of asset-backed commercial paper and certain other commercial paper programs over the last several years.  At December 31, 2011 and 2010, our utility had commercial paper outstanding of $141.6 million and $257.4 million, respectively.  The effective interest rate on the utility’s commercial paper outstanding at December 31, 2011 and 2010 was 0.3 percent and 0.4 percent, respectively.

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In March 2009, Gill Ranch entered into a cash collateralized credit facility for up to $40 million, which was extended through September 30, 2010.  In June 2010, Gill Ranch repaid its $40 million bank loan outstanding using the proceeds from its cash collateralized account.  The effective interest rate on the Gill Ranch credit facility was 0.8 percent during 2010.

Credit Agreements

We have a syndicated multi-year credit agreement for unsecured revolving loans totaling $250 million. The original term of this credit agreement was extended through May 31, 2013.  All lenders under our syndicated agreement are major financial institutions with committed balances and investment grade credit ratings as of December 31, 2011 (see table below).  We also had three bilateral credit agreements totaling $50 million in effect from November 30, 2010 through March 31, 2011 for seasonal working capital needs.

		Loan Commitment          (In Thousands)
		Syndicated
Lender rating, by category		Facility
AAA/Aaa		$	-
AA/Aa			230,000
A/A			20,000
BBB/Baa			-
	Total	$	250,000

Based on credit market conditions, it is possible that one or more lending commitments could be unavailable to us if the lender defaulted due to lack of funds or insolvency.  However, based on our current assessment of our lenders’ creditworthiness, including a review of capital ratios, credit default swap spreads and credit ratings, we believe the risk of lender default is minimal.

As discussed above, we extended commitments with all of our lenders under the $250 million syndicated agreement through May 31, 2013.  This syndicated agreement also allows us to request increases in the total commitment amount from time to time, up to a maximum amount of $400 million. This syndicated agreement also permits the issuance of letters of credit in an aggregate amount up to the applicable total borrowing commitment.

Any principal and unpaid interest amounts owed on borrowings under the credit agreements are due and payable on or before the maturity date. There were no outstanding balances under these credit agreements at December 31, 2011 and 2010.  These agreements require us to maintain a consolidated indebtedness to total capitalization ratio of 70 percent or less. Failure to comply with this covenant would entitle the lenders to terminate their lending commitments and accelerate the maturity of all amounts outstanding. We were in compliance with this covenant at December 31, 2011 and 2010, with consolidated indebtedness to total capitalization ratios of 53.5 percent and 55.4 percent, respectively.

The syndicated agreement also requires that we maintain credit ratings with S&P and Moody’s and notify the lenders of any change in our senior unsecured debt ratings by such rating agencies.  A change in our debt ratings by S&P or by Moody’s is not an event of default, nor is the maintenance of a specific minimum level of debt rating a condition of drawing upon the credit agreement. However, a change in our debt rating below BBB- by S&P or Baa3 by Moody’s would require additional approval from the OPUC prior to issuance of utility debt, and interest rates on any loans outstanding under the credit agreements are tied to debt ratings, which would increase or decrease the cost of any loans under the credit agreements when ratings are changed (see “Credit Ratings,” below).

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Credit Ratings

Our debt credit ratings are a factor in our liquidity, affecting our access to the capital markets, including the commercial paper market.  Our debt credit ratings also have an impact on the cost of funds and the need to post collateral under derivative contracts.  A change in our ratings below BBB- by S&P or Baa3 by Moody’s would require additional approval from the OPUC prior to our issuing additional long-term debt.

The following table summarizes our NW Natural debt ratings from S&P and Moody’s at December 31, 2011:

	S&P	Moody’s
Commercial paper (short-term debt)	A-1	P-1
Senior secured (long-term debt)	A+	A1
Senior unsecured (long-term debt)	n/a	A3
Corporate credit rating	A+	n/a
Ratings outlook	Stable	Stable

The above credit ratings are dependent upon a number of factors, both qualitative and quantitative, and are subject to change at any time.  The disclosure of these credit ratings is not a recommendation to buy, sell or hold NW Natural securities.  Each rating should be evaluated independently of any other rating.

Redemptions of Long-Term Debt

We redeemed MTN’s during 2011, 2010 and 2009 as follows:

	Amounts Redeemed
Thousands (Years ended December 31)	2011		2010		2009
Medium-Term Notes
6.65% Series B due 2027 (1)	$	-	$	-	$	300
4.11% Series B due 2010		-		10,000		-
7.45% Series B due 2010		-		25,000		-
6.665% Series B due 2011		10,000		-		-
	$	10,000	$	35,000	$	300
(1) In November 2009, $0.3 million of our 6.65 percent secured MTNs due 2027 were redeemed pursuant to a one-time put option. This one-time put option has now expired, and the $19.7 million remaining principal outstanding is expected to be paid at maturity in November 2027.

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Cash Flows

Operating Activities

2011 compared to 2010:

For the year ended December 31, 2011, cash flow from operating activities totaled $233.5 million compared to $126.5 million in 2010 and $240.3 million in 2009.  The significant factors contributing to changes in operating cash flow in 2011 compared to 2010 are as follows:

·   an increase of $85.7 million from accrued taxes, primarily related to bonus depreciation which resulted in federal tax refunds of $36.6 in 2011 and a net operating loss (NOL) carryforward;

·   an increase of $34.7 million from changes in deferred gas costs, which reflects a higher level of gas cost savings which will be refunded to utility customers in subsequent years’ PGA;

·   an increase of $33.4 million from insurance recoveries for environmental claims, net of deferred environmental expenditures in 2011;

·   an increase of $12.0 million from changes in accounts payable due to decreased construction activity at Gill Ranch;

·   a decrease of $29.5 million from changes in deferred tax liabilities primarily reflecting higher tax benefits in 2010 compared to 2011, largely driven by utility and Gill Ranch bonus depreciation for investments placed in service during 2010;

·   a decrease of $22.1 million from changes in receivables primarily due to higher balances at the end of 2009, which benefitted cash flows during 2010; and

·   a decrease of $12.0 million from higher pension contributions due to a decline in interest rates and asset values, which increased pension funding requirements.

In September 2010, Congress passed the Unemployment Insurance, Reauthorization and Job Creation Act of 2010 (the Jobs Act) and the legislation was signed into law by President Obama.  The Jobs Act extended for one year the temporary bonus depreciation rules first enacted in the Economic Stimulus Act of 2008 and subsequently renewed in the American Recovery and Reinvestment Act of 2009.  Under the bonus depreciation provision, and additional first-year tax deduction was allowed for depreciation equal to 50 percent of the adjusted basis of qualified property through September 8, 2010, in the year the property was placed in service, with the remaining percentage recovered under the normal depreciation rules.  In addition, on December 17, 2010, President Barack Obama signed into law the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (the Tax Relief Act), which allows 100 percent bonus depreciation  for qualified property placed in service between September 9, 2010 through December 31, 2011.  It also extended the 50 percent bonus depreciation deduction to qualifying property placed in service in 2012.  As a result of this legislation, we generated a tax net operating loss in 2010 which was carried back to the tax year 2009, resulting in a federal income tax refund of $22.3 million which we received in 2011.  We also recognized an increase in our cash flow by reducing our current tax liabilities for the 2011 and 2012 tax years.  As of December 31, 2011, we have a federal and state income tax receivable balance of $7.0 million, which we expect to realize in cash flows during 2012.

2010 compared to 2009:

·   an increase of $39.6 million from deferred income taxes, primarily reflecting higher tax benefits from bonus depreciation taken in 2010 related to Gill Ranch capital investments placed in service;

·   an increase of $15.0 million from a smaller pension contribution in 2010 compared to 2009;

·   an increase of $10.1 million from the 2009 settlement of an interest rate hedge;

·   a decrease of $75 million from accrued taxes, primarily related to 2010 benefits that will be refunded in 2011, and due to tax refunds received in 2009 related to a change in tax accounting method for repairs and maintenance costs;

·   a decrease of $62.9 million from changes in deferred gas cost regulatory account which reflects actual gas prices compared to estimated gas prices embedded in customer rates;

·   a decrease of $19.7 million from changes in receivables primarily due to higher balances at the end of 2008, which benefitted cash flows during 2009;

·   a decrease of $14.5 million from changes in inventories primarily due to higher price of gas in inventory at the end of 2008, which benefitted cash flows during 2009 as higher cost inventories were recovered through utility rates; and

·   a decrease of $13.0 million in accounts payable due to decreased Gill Ranch construction activity at the end of 2010 compared to the end of 2009.

We have lease and purchase commitments relating to our operating activities that are financed with cash flows from operations.  For information on cash flow requirements related to leases and other purchase commitments, see “Contractual Obligations,” above and Note 15.

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Investing Activities

Cash used in investing activities for the year ended December 31, 2011 totaled $153.1 million, down from $212.9 million for the same period in 2010.  Our capital expenditures were $100.5 million in the year ended December 31, 2011, down from $248.5 million for the same period in 2010.  Capital expenditures decreased in non-utility construction activity in 2011, which were largely due to Gill Ranch construction expenditures in 2010.  We also invested $50.6 million in utility gas reserves in 2011 under the agreement with Encana discussed earlier.  

Restricted cash decreased $37.7 million compared to 2010, due to settling our $40 million cash collateralized loan in June 2010, partially offset by a $4 million restricted cash collateral requirement imposed under the new Gill Ranch debt issued in 2011 (see Financing Activities, below).  

Over the five-year period 2012 through 2016, total utility capital expenditures are estimated to be between $400 and $500 million and utility expenditures for gas reserves are estimated to be $200 million.  The estimated level of utility capital expenditures over the next five years reflects assumptions for customer growth, storage development for the utility, technology investments and utility distribution improvements, including requirements under current pipeline safety programs.  Most of the required funds are expected to be internally generated over the five-year period, and any remaining funding will be obtained through the issuance of long-term debt or equity securities, with short-term debt providing liquidity and bridge financing.

In 2012, we expect to spend less than $15 million on non-utility development projects, including the storage businesses and Palomar.  Storage business capital expenditures in 2012 are expected to be paid primarily from working capital, and potentially with additional funds from NW Natural.  Palomar expects to continue working on revised plans for the east pipeline segment, including plans to conduct an open season to re-evaluate regional needs. The initial planning and permitting costs have been financed with equity funds from NW Natural and our partner, TransCanada American Investments Ltd.   For more information, see Note 12 and “Strategic Opportunities—Pipeline Diversification,” above.

Financing Activities

Cash used in financing activities for the year ended December 31, 2011 totaled $78.0 million, down significantly from cash provided of $81.4 million for the same period in 2010.  Our short-term debt balances decreased $115.8 million for the year ended December 31, 2011, compared to an increase of $155.4 million for the same period in 2010. We also redeemed $10 million of long-term debt in June of 2011.  This was offset by long-term debt issuances of $50 million in September 2011 by the utility and $40 million in November 2011 by Gill Ranch. We continue to use long-term debt proceeds primarily to finance capital expenditures, refinance short-term and long-term debt maturities as well as for general corporate purposes.  

We have a repurchase program approved through May 2011 which provides authorization to repurchase up to 2.8 million shares of NW Natural common stock or up to $100 million.  The purchases are made in the open market or through privately negotiated transactions.  No repurchases were made in 2011, 2010 or 2009 under the program.  Since the program’s inception, we have repurchased an aggregate 2.1 million shares of common stock at a total cost of $83.3 million, at the average price of $39.19 per share (see Part II, Item 5, “Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities,” above).

Free Cash Flow

Free cash flow is the amount of cash remaining after the payment of all cash expenses, capital expenditures and investment activities, and dividends.  Free cash flow is a non-GAAP financial measure, but we believe this supplemental information enables the reader of the financial statements to better understand our cash generating ability of the Company and to benefit from seeing cash flow results from management’s perspective in addition to the traditional GAAP presentation.  We monitor free cash flow as one measure of our return on investments.  

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Provided below is a reconciliation from cash provided by operations (GAAP basis) to our non-GAAP free cash flow.

Thousands	2011			2010			2009
Cash provided by operating activities	$	233,462		$	126,469		$	240,335
Cash used in investing activities		(153,065	)		(212,871	)		(162,141	)
Cash dividend payments on common stock		(46,690	)		(44,652	)		(42,415	)
Free cash flow	$	33,707		$	(131,054	)	$	35,779

The free cash flow information presented above is not intended to be a substitute for, nor is it meant to be a better measure of, cash flow results prepared in accordance with GAAP.  In addition, the non-GAAP measure we provide may be calculated differently by other companies that present a similar non-GAAP financial measure for cash flow.

Pension Cost and Funding Status of Qualified Retirement Plans

Pension costs are determined in accordance with accounting standards for compensation and retirement benefits (see “Application of Critical Accounting Policies and Estimates – Accounting for Pensions and Postretirement Benefits,” above).  Pension costs for our two qualified defined benefit plans, which are allocated between operation and maintenance expenses, capital expenditures and the deferred regulatory balancing account totaled $16.3 million in 2011, an increase of $4.9 million from 2010.  See Note 9 for additional details.

The fair market value of pension assets in these two plans decreased to $216.0 million at December 31, 2011 from $219.0 million at December 31, 2010.  The decrease was due to a negative return on plan assets of $6.7 million and benefit payments of $16.6 million, offset by $20.2 million in employer contributions.

We make contributions to company-sponsored qualified defined benefit pension plans based on actuarial assumptions and estimates, tax regulations and funding requirements under federal law. Our qualified defined benefit pension plans were underfunded by $146.9 million at December 31, 2011.  We plan to make contributions during 2012 of approximately $28 million. For more information on the funding status of our qualified retirement plans and other postretirement benefits, see Note 9.

We also contribute to a multiemployer pension plan for our employees (the Union Plan, or otherwise known as Western States Plan) pursuant to our collective bargaining agreement.  We made contributions totaling $0.4 million to the Union Plan in both 2011 and 2010.   See Note 9 for further disclosures.

Ratios of Earnings to Fixed Charges

For the years ended December 31, 2011, 2010 and 2009, our ratios of earnings to fixed charges, computed using the Securities and Exchange Commission method, were  3.41,  3.73, and 3.86, respectively. For this purpose, earnings consist of net income before taxes plus fixed charges, and fixed charges consist of interest on all indebtedness, the amortization of debt expense and discount or premium and the estimated interest portion of rentals charged to income.  See Exhibit 12.

Contingent Liabilities

Loss contingencies are recorded as liabilities when it is probable that a liability has been incurred and the amount of the loss is reasonably estimable in accordance with accounting standards for contingencies (see “Application of Critical Accounting Policies and Estimates,” above).  At December 31, 2011, we had a regulatory asset of $105.7 million for deferred environmental costs.  If it is determined that both the insurance recovery and future customer rate recovery of such costs are not probable, then the costs will be charged to expense in the period such determination is made.  For further discussion of contingent liabilities, see Note 15.

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New Accounting Pronouncements

For a description of recent accounting pronouncements that may have an impact on our financial condition, results of operations or cash flows, see Note 2.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various forms of market risk including commodity supply risk, commodity price risk, interest rate risk, foreign currency risk, credit risk and weather risk.  The following describes our exposure to these risks.

Commodity Supply Risk

We enter into spot, short-term and long-term natural gas supply contracts, along with associated pipeline transportation contracts, to manage our commodity supply risk.  Historically, we have arranged for physical delivery of an adequate supply of gas, including gas in our Mist storage facility, to meet the expected requirements of our core utility customers. Our gas purchase contracts are primarily index-based and subject to monthly re-pricing, a strategy that is intended to reflect market price trends during the upcoming year.

Commodity Price and Storage Value Risk

Natural gas commodity prices and storage values are subject to market fluctuations due to unpredictable factors including weather, pipeline transportation congestion, drilling technologies, potential market speculation and other factors that affect short-term supply and demand. In addition to managing storage positions through a combination of short- and long-term fixed price contracts, we use commodity-price financial swap and option contracts (financial hedge contracts) to convert certain natural gas supply contracts from floating prices to fixed or capped prices, and physical gas reserves from a long-term investment with Encana, for utility gas purchase requirements. These financial hedge contracts and gas reserve volumes are generally included in our annual PGA filing for recovery, subject to a regulatory prudence review.  We also regularly monitor and manage the financial exposure and liquidity risk of our storage position.

Interest Rate Risk

We are exposed to interest rate risk primarily associated with new debt financing needed to fund capital requirements, including future contractual obligations and maturities of long-term and short-term debt.  Interest rate risk is primarily managed through the issuance of fixed-rate debt with varying maturities.  We may also enter into financial derivative instruments, including interest rate swaps, options and other hedging instruments, to manage and mitigate interest rate exposure.

Foreign Currency Risk

The costs of certain natural gas commodity supplies and certain pipeline services purchased from Canadian suppliers are subject to changes in the value of the Canadian currency in relation to the U.S. currency.  Foreign currency forward contracts are used to hedge against fluctuations in exchange rates for our commodity and commodity related demand charges paid in Canadian dollars.  At December 31, 2011 and 2010, notional amounts under foreign currency forward contracts totaled $12.3 million and $13.9 million, respectively.  As of December 31, 2011 , all foreign currency forward contracts mature within one year.  If all of the foreign currency forward contracts had been settled on December 31, 2011, a loss of $0.2 million would have been realized (see Note 13).

Credit Risk

Credit exposure to suppliers.  Certain suppliers that sell us gas have either relatively low credit ratings or are not rated by major credit rating agencies.  To manage this supply risk, we purchase gas from a number of different suppliers at liquid exchange points.  We evaluate and monitor suppliers’ creditworthiness and maintain the ability to require additional financial assurances, including deposits, letters of credit or surety bonds, in case a supplier defaults.  In the event of a supplier’s failure to deliver contracted volumes of gas, the regulated utility would need to replace those volumes at prevailing market prices, which may be higher or lower than the original transaction prices.  We believe these costs would be subject to the PGA sharing mechanism discussed above.   Since most of our commodity supply contracts are priced at the monthly market index price tied to liquid exchange points, and we have significant storage flexibility, we believe that it is unlikely that a supplier default would have an adverse effect on our financial condition or results of operations.

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Credit exposure to financial derivative counterparties.  Based on estimated fair value at December 31, 2011, our overall credit exposure relating to commodity hedge contracts is considered to be immaterial as it reflects amounts we owed to our financial derivative counterparties totaling $63.5 million.  However, changes in natural gas prices could result in counterparties owing us money. Therefore our financial derivatives policy requires counterparties to have at least an investment-grade credit rating at the time the derivative instrument is entered into, and specific limits on the contract amount and duration based on each counterparty’s credit rating.  Due to potential changes in market conditions and credit concerns, we continue to enforce strong credit requirements. We actively monitor and manage our derivative credit exposure and place counterparties on hold for trading purposes or require cash collateral, letters of credit or guarantees as circumstances warrant.  As of December 31, 2011, we do not have any actual derivative credit risk exposure, which reflects amounts that financial derivative counterparties owe to us.

The following table summarizes our overall credit exposure, based on estimated fair value, and the corresponding counterparty credit ratings. The table uses credit ratings from S&P and Moody’s, reflecting the higher of the S&P or Moody’s rating or a middle rating if the entity is split-rated with more than one rating level difference:

			Financial Derivative Position by Credit Rating
			Unrealized Fair Value Gain (Loss)
Thousands		2011		2010
AAA/Aaa		$	-	$	-
AA/Aa			(57,542)		(43,656)
A/A			(5,924)		(9,017)
BBB/Baa			-		-
	Total	$	(63,466)	$	(52,673)

In most cases, we also mitigate the credit risk of financial derivatives by having master netting arrangements with our counterparties which provide for making or receiving net cash settlements.  Generally, transactions of the same type in the same currency that have a settlement on the same day with a single counterparty are netted and a single payment is delivered or received depending on which party is due funds.

Additionally we have master contracts in place with each of our derivative counterparties that include provisions for posting or calling for collateral.  Generally we can obtain cash or marketable securities as collateral with one day’s notice.  We use various collateral management strategies to reduce liquidity risk. The collateral provisions vary by counterparty but are not expected to result in the significant posting of collateral, if any.  We have performed stress tests on the portfolio and concluded that the liquidity risk from collateral calls is not material. Our derivative credit exposure is primarily with investment grade counterparties rated AA-/Aa3 or higher.  Contracts are diversified across counterparties to reduce credit and liquidity risk.

Credit exposure to insurance companies for environmental damage claims. We regularly monitor the financial condition of insurance companies who provide or provided general liability insurance policy coverage to NW Natural and its predecessors with respect to environmental damage claims.  We have filed claims for our environmental costs with a number of insurance companies.  The majority of these companies have credit ratings of A- or better from A.M. Best Co. (AM Best). AM Best is a global independent credit rating agency who has provided quantitative and qualitative analysis of insurance company balance sheet strength for over 100 years.  AM Best uses a rating scale that ranges from A++ (“Superior” financial strength) to F (“In Liquidation”), with a rating of A- considered “Excellent.” A strong credit rating from AM Best is not a guarantee that an insurance company will be able to meet its contractual obligations.  The remaining insurance companies who do not have credit ratings of A- or better are expected to have sufficient funds in reserves to cover these claims.  Our credit exposure to insurance companies for environmental claims, which reflects amounts we believe are owed to us, could be material. In the event we are unable to recover environmental expenses from these insurance policies, we will seek recovery of unreimbursed amounts through customer rates.

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Weather Risk

We are exposed to weather risk primarily from our regulated utility business.  A large percentage of our utility margin is volume driven, and current rates are based on an assumption of average weather. In 2003, the OPUC approved a weather normalization mechanism for residential and commercial customers. This mechanism affects customer bills between December 1 through May 15 of each winter heating season, increasing or decreasing the margin component of customers’ rates to reflect gas usage based on “average” weather using the 25-year average temperature for each day of the billing period. The mechanism is intended to stabilize the recovery of our utility’s fixed costs and reduce fluctuations in customers’ bills due to colder or warmer than average weather.  Customers in Oregon are allowed to opt out of the weather normalization mechanism. As of December 31, 2011, approximately 9 percent of our Oregon customers had opted out. In addition to the Oregon customers opting out, our Washington residential and commercial customers account for approximately 10 percent of our total customer base and are not covered by weather normalization. The combination of Oregon and Washington customers not covered by a weather normalization mechanism is less than 20 percent of all residential and commercial customers.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Table of Contents

		Page
1.	Management’s Report on Internal Control Over Financial Reporting	69
2.	Report of Independent Registered Public Accounting Firm	70
3.	Consolidated Financial Statements:
	Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2011, 2010 and 2009	71
	Consolidated Balance Sheets at December 31, 2011 and 2010	72
	Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2011, 2010 and 2009	74
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009	75
	Notes to Consolidated Financial Statements	76
4.	Quarterly Financial Information (unaudited)	111
5.	Supplementary Data for the Years Ended December 31, 2011, 2010 and 2009:
	Financial Statement Schedule
	Schedule II – Valuation and Qualifying Accounts and Reserves	112
	Supplemental Schedules Omitted
	All other schedules are omitted because of the absence of the conditions under which they are required or because the required information is included elsewhere in the financial statements

68

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America (GAAP). Our internal control over financial reporting includes those policies and procedures that:

(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions involving company assets;

(ii) provide reasonable assurance that transactions are recorded as necessary to permit the preparation of financial statements in accordance with GAAP, and that receipts and expenditures are being made only in accordance with authorizations of management and the Board of Directors; and

(iii) provide reasonable assurance regarding prevention or timely detection of the unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements or fraud. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2011.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.

Based on our assessment and those criteria, management has concluded that we maintained effective internal control over financial reporting as of December 31, 2011.

The effectiveness of internal control over financial reporting as of December 31, 2011 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears in this annual report.

/s/ Gregg S. Kantor        

Gregg S. Kantor

President and Chief Executive Officer

/s/ David H. Anderson   

David H. Anderson

Senior Vice President and Chief Financial Officer

February 28, 2012

69

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Northwest Natural Gas Company:

In our opinion, the consolidated financial statements listed in the accompanying table of contents present fairly, in all material respects, the financial position of Northwest Natural Gas Company and its subsidiaries at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011in conformity with accounting principles generally accepted in the United States of America.  In addition, in our opinion, the financial statement schedule listed in the accompanying table of contentspresents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidatedfinancial statements.  Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting.  Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits.  We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Portland, Oregon

February 28, 2012

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NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Thousands, except per share amounts (year ended December 31)	2011			2010			2009
Operating revenues:
Gross operating revenues	$	848,796		$	812,106		$	1,012,711
Less: Cost of sales		458,622			424,534			611,168
Revenue taxes		20,741			19,991			24,656
Net operating revenues		369,433			367,581			376,887
Operating expenses:
Operations and maintenance		125,303			120,980			127,104
General taxes		29,281			23,872			28,253
Depreciation and amortization		70,004			65,124			62,814
Total operating expenses		224,588			209,976			218,171
Income from operations		144,845			157,605			158,716
Other income and expense - net		4,523			7,102			3,714
Interest expense - net		42,088			42,578			40,637
Income before income taxes		107,280			122,129			121,793
Income tax expense		43,382			49,462			46,671
Net income		63,898			72,667			75,122
Other comprehensive income:
Change in employee benefit plan liability, net of taxes of $1,161 for 2011, $674 for 2010 and $1,273 for 2009		(1,779	)		(1,027	)		(1,936	)
Amortization of non-qualified employee benefit plan liability, net of taxes of ($383) for 2011, ($257) for 2010 and ($58) for 2009		583			391			354
Comprehensive income	$	62,702		$	72,031		$	73,540
Average common shares outstanding:
Basic		26,687			26,589			26,511
Diluted		26,744			26,657			26,576
Earnings per share of common stock:
Basic	$	2.39		$	2.73		$	2.83
Diluted	$	2.39		$	2.73		$	2.83
Dividends declared per share of common stock	$	1.75		$	1.68		$	1.60
See Notes to Consolidated Financial Statements

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NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Thousands (December 31)	2011			2010
Assets:
Current assets:
Cash and cash equivalents	$	5,833		$	3,457
Restricted cash		-			924
Accounts receivable		77,449			67,969
Accrued unbilled revenue		61,925			64,803
Allowance for uncollectible accounts		(2,895	)		(2,950	)
Regulatory assets		94,673			52,714
Derivative instruments		2,853			2,245
Inventories		74,363			80,385
Gas reserves		4,463			-
Income taxes receivable		7,045			41,066
Other current assets		22,980			19,652
Total current assets		348,689			330,265
Non-current assets:
Property, plant and equipment		2,661,102			2,576,402
Less accumulated depreciation		767,226			722,239
Total property, plant and equipment - net		1,893,876			1,854,163
Gas reserves		47,451			-
Regulatory assets		371,392			348,897
Derivative instruments		-			628
Other investments		68,263			69,094
Restricted cash		4,000			-
Other non-current assets		12,903			13,569
Total non-current assets		2,397,885			2,286,351
Total assets	$	2,746,574		$	2,616,616
See Notes to Consolidated Financial Statements

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NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Thousands (December 31)	2011			2010
Capitalization and liabilities:
Capitalization:
Common stock - no par value; authorized 100,000 shares; issued and outstanding 26,756 and 26,668 at December 31, 2011 and 2010, respectively	$	348,383		$	342,978
Retained earnings		373,905			356,727
Accumulated other comprehensive loss		(7,800	)		(6,604	)
Total common stock equity		714,488			693,101
Long-term debt		641,700			591,700
Total capitalization		1,356,188			1,284,801
Current liabilities:
Short-term debt		141,600			257,435
Current maturities of long-term debt		40,000			10,000
Accounts payable		86,300			93,243
Taxes accrued		10,747			10,579
Interest accrued		5,857			5,182
Regulatory liabilities		31,046			17,828
Derivative instruments		57,317			38,437
Other current liabilities		41,597			35,457
Total current liabilities		414,464			468,161
Deferred credits and other non-current liabilities:
Deferred tax liabilities		413,209			373,409
Regulatory liabilities		278,382			258,031
Pension and other postretirement benefit liabilities		201,530			144,250
Derivative instruments		6,536			17,022
Other non-current liabilities		76,265			70,942
Total deferred credits and other non-current liabilities		975,922			863,654
Commitments and contingencies (see Note 15)		-			-
Total capitalization and liabilities	$	2,746,574		$	2,616,616
See Notes to Consolidated Financial Statements

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NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
							Accumulated
							Other
	Common			Retained			Comprehensive			Total
Thousands	Stock			Earnings			Income (Loss)			Equity
Balance at Dec. 31, 2008	$	336,754		$	296,005		$	(4,386	)	$	628,373
Comprehensive income		-			75,122			(1,582	)		73,540
Restricted stock amortizations		39			-			-			39
Dividends paid on common stock		-			(42,415	)		-			(42,415	)
Tax benefits from employee stock option plan		229			-			-			229
Stock-based compensation		(776	)		-			-			(776	)
Issuance of common stock		1,115			-			-			1,115
Balance at Dec. 31, 2009		337,361			328,712			(5,968	)		660,105
Comprehensive income		-			72,667			(636	)		72,031
Dividends paid on common stock		-			(44,652	)		-			(44,652	)
Tax expense from employee stock option plan		(125	)		-			-			(125	)
Stock-based compensation		554			-			-			554
Issuance of common stock		5,188			-			-			5,188
Balance at Dec. 31, 2010		342,978			356,727			(6,604	)		693,101
Comprehensive income		-			63,898			(1,196	)		62,702
Dividends paid on common stock		-			(46,690	)		-			(46,690	)
Tax expense from employee stock option plan		(26	)		-			-			(26	)
Stock-based compensation		1,769			-			-			1,769
Issuance of common stock		3,632			-			-			3,632
Common stock expense		30			(30	)		-			-
Balance at Dec. 31, 2011	$	348,383		$	373,905		$	(7,800	)	$	714,488
See Notes to Consolidated Financial Statements

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NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Thousands (year ended December 31)	2011			2010			2009
Operating activities:
Net income	$	63,898		$	72,667		$	75,122
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization		70,004			65,124			62,814
Undistributed earnings from equity investments		1,329			(588	)		(1,329	)
Non-cash expenses related to qualified defined benefit pension plans		7,191			8,009			9,914
Contributions to qualified defined benefit pension plans		(22,045	)		(10,000	)		(25,000	)
Deferred environmental expenditures, net of recoveries		25,586			(7,826	)		(10,069	)
Settlement of interest rate hedge		-			-			(10,096	)
Other		(1,049	)		(2,265	)		(3,461	)
Changes in assets and liabilities:
Receivables		(6,246	)		15,830			35,506
Inventories		6,022			572			15,110
Taxes accrued		34,189			(51,524	)		23,461
Accounts payable		148			(11,846	)		1,188
Interest accrued		675			(253	)		8,582
Deferred gas costs		8,565			(26,090	)		36,819
Deferred tax liabilities		46,877			76,410			36,775
Other - net		(1,682	)		(1,751	)		(15,001	)
Cash provided by operating activities		233,462			126,469			240,335
Investing activities:
Capital expenditures		(100,534	)		(248,505	)		(135,124	)
Utility gas reserves		(50,597	)		-			-
Restricted cash		(3,076	)		34,619			(30,524	)
Other		1,142			1,015			3,507
Cash used in investing activities		(153,065	)		(212,871	)		(162,141	)
Financing activities:
Common stock issued - net		3,040			4,598			(375	)
Long-term debt issued		90,000			-			125,000
Long-term debt retired		(10,000	)		(35,000	)		(300	)
Change in short-term debt		(115,835	)		155,435			(158,851	)
Cash dividend payments on common stock		(46,690	)		(44,652	)		(42,415	)
Other		1,464			1,046			263
Cash provided by (used in) financing activities		(78,021	)		81,427			(76,678	)
Increase (decrease) in cash and cash equivalents		2,376			(4,975	)		1,516
Cash and cash equivalents - beginning of period		3,457			8,432			6,916
Cash and cash equivalents - end of period	$	5,833		$	3,457		$	8,432
Supplemental disclosure of cash flow information:
Interest paid	$	41,413		$	41,037		$	36,762
Income taxes paid	$	1,756		$	22,600		$	10,000
See Notes to Consolidated Financial Statements

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NORTHWEST NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Certain prior year balances in our consolidated financial statements have been combined to conform with the current presentation.  These changes had no impact on our prior year’s consolidated results of operations, financial condition or cash flows.

2.           Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America (U.S. GAAP) requires management to make estimates and assumptions that affect reported amounts in the consolidated financial statements and accompanying notes.  Actual amounts could differ from those estimates, and changes would most likely be reported in future periods.  Management believes that the estimates and assumptions used are reasonable.

Industry Regulation

Our principal businesses are the distribution of natural gas, which is regulated by the Public Utility Commission of Oregon (OPUC) and Washington Utilities and Transportation Commission (WUTC), and natural gas storage services, which are regulated by either the Federal Energy Regulatory Commission (FERC) or the California Public Utilities Commission (CPUC), and to a certain extent by the OPUC.  Accounting records and practices of our regulated businesses conform to the requirements and uniform system of accounts prescribed by these regulatory authorities in accordance with U.S. GAAP.  Our businesses regulated by the OPUC, WUTC and FERC earn a reasonable return on invested capital from approved cost-based rates, while our business regulated by the CPUC earns a return to the extent we are able to charge competitive prices above our costs (i.e. market-based rates).

In applying regulatory accounting principles, we capitalize or defer certain costs and revenues as regulatory assets and liabilities pursuant to orders of the OPUC or WUTC, which provides for the recovery of revenues or expenses from, or refunds to, utility customers in future periods, including a return or a carrying charge in most cases.

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At December 31, 2011 and 2010, the amounts deferred as regulatory assets and liabilities were as follows:

	Regulatory Assets
Thousands	2011		2010
Current:
Unrealized loss on derivatives(1)	$	57,317	$	38,437
Pension and other postretirement benefit liabilities(2)		15,491		10,988
Other(3)		21,865		3,289
Total current	$	94,673	$	52,714
Non-current:
Unrealized loss on derivatives(1)	$	6,536	$	17,022
Income tax asset		65,264		72,341
Pension and other postretirement benefit liabilities(2)		170,512		118,248
Environmental costs(4)		105,670		114,311
Other(3)		23,410		26,975
Total non-current	$	371,392	$	348,897

	Regulatory Liabilities
Thousands	2011		2010
Current:
Gas costs	$	17,994	$	15,583
Unrealized gain on derivatives(1)		2,853		2,245
Other(3)		10,199		-
Total current	$	31,046	$	17,828
Non-current:
Gas costs	$	8,420	$	2,297
Unrealized gain on derivatives(1)		-		628
Accrued asset removal costs		267,355		252,941
Other(3)		2,607		2,165
Total non-current	$	278,382	$	258,031

(1)   An 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 annual 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 include an interest component when recognized in net periodic benefit costs or earn a rate of return or carrying charge (see Note 9).

(3)   Other primarily consists of deferrals and amortizations under other approved regulatory mechanisms.  The accounts being amortized typically earn a rate of return or carrying charge.

(4)   Environmental costs are related to those sites that are approved for regulatory deferral.  In Oregon, we earn a rate of return on amounts paid, whereas amounts accrued but not yet paid do not earn a rate of return or a carrying charge until expended. Environmental costs related to Washington were deferred beginning in 2011, with cost recovery and carrying charge to be determined in a future proceeding.

The amortization period for our regulatory assets and liabilities ranges from less than one year to an undeterminable period.  Our regulatory deferrals for gas costs payable are generally amortized over 12 months beginning each

November 1 following the gas contract year during which the deferred gas costs are realized.  Similarly, most of our regulatory deferred accounts are amortized over 12 months.  However, certain regulatory account balances, such as income taxes, environmental costs, pension liabilities and accrued asset removal costs, are large and tend to be amortized over longer periods once we have agreed upon an amortization period with the respective regulatory agency.

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We believe that continued application of regulatory accounting for these activities is appropriate and consistent with the current regulatory environment, and that all regulated assets and liabilities at December 31, 2011 and 2010 will be recoverable or refundable through future rate making decisions.  We annually review all regulatory assets and liabilities for recoverability and more often if circumstances warrant.  If we should determine that all or a portion of these regulatory assets or liabilities no longer meet the criteria for continued application of regulatory accounting, then we would be required to write off the net unrecoverable balances against earnings.

New Accounting Standards

Adopted Standards

Fair Value Disclosures. In January 2011, 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.  The adoption of this standard did not have a material effect 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 have elected to early adopt this standard and present net income and other comprehensive income in one continuous statement.

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 has been adopted as shown in Note 9.

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.

Balance Sheet Offsetting. In December 2011, the FASB issued authoritative guidance regarding the offsetting of assets and liabilities on the balance sheet.  The revised standard is intended to provide more comparable guidance between the U.S. GAAP and international accounting standards by requiring entities to disclose both gross and net amounts for assets and liabilities offset on the balance sheet as well as other disclosures concerning their enforceable master netting arrangements.   This guidance is effective for annual reporting periods beginning after January 1, 2013 and we are currently assessing the impact on our financial statement disclosures.

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Plant, Property and Accrued Asset Removal Costs

Plant and property are stated at cost, including capitalized labor, materials and overhead (see Note 11).  In accordance with regulatory accounting standards, the cost of acquiring and constructing long-lived plant and property generally includes an allowance for funds used during construction (AFUDC) or capitalized interest.  AFUDC represents the regulatory financing cost incurred when debt and equity funds are used for construction (see “Allowance for Funds Used During Construction,” below).  When constructed assets are subject to market-based rates rather than cost-based rates, then the financing cost incurred during construction are included in capitalized interest in accordance with U.S. GAAP, not regulatory financing cost under AFUDC.

In accordance with long-standing regulatory treatment, our depreciation rates are comprised of three components: one based on the average service life of the asset, a second based on the estimated salvage value of the asset, and a third based on the asset’s cost of removal. We collect, through rates, the estimated cost of removal on certain regulated properties through depreciation expense, with a corresponding offset to accumulated depreciation.  These removal costs are non-legal obligations as defined by regulatory accounting guidance. Therefore, we have included these costs in non-current regulatory liabilities on our consolidated balance sheets.  In the rate setting process, the liability for the removal costs is treated as a reduction to the net rate base upon which the regulated utility has the opportunity to earn its allowed rate of return.

Our provision for depreciation of utility plant and property is computed under the straight-line method in accordance with engineering studies approved by regulatory authorities. The weighted average depreciation rate for utility assets in service was approximately 2.8 percent in 2011 and 2010, and 2.9 percent in 2009 reflecting the approximate average economic life of the property.  This includes 2011 weighted average depreciation rates for the following asset categories: 2.7 percent for transmission and distribution plant, 2.2 percent for gas storage facilities, 4.6 percent for general plant, and 5.1 percent for intangible and other fixed assets.

Allowance for Funds Used During Construction

Certain additions to utility plant include AFUDC, which represents the net cost of debt and equity funds used during construction. AFUDC is calculated using actual interest rates for debt and authorized rates for return on equity, if applicable. If short-term debt balances are less than the total balance of construction work in progress, then a composite AFUDC rate is used to represent interest on all debt funds, shown as a reduction to interest charges, and a return on equity funds, shown as other income. While cash is not immediately recognized from recording AFUDC, it is realized in future years through rate recovery resulting from the higher utility cost of service. Our composite AFUDC rates were 0.5 percent in 2011, 0.6 percent in 2010 and 1.0 percent in 2009.

Cash and Cash Equivalents

For purposes of reporting cash flows, cash and cash equivalents include cash on hand plus highly liquid investment accounts with maturity dates of three months or less. At December 31, 2011, outstanding checks of approximately $3.9 million were included in accounts payable.

Revenue Recognition and Accrued Unbilled Revenues

Utility revenues, derived primarily from the sale and transportation of natural gas, are recognized upon delivery of gas commodity or service to customers.  Revenues include accruals for gas delivered but not yet billed to customers based on estimates of deliveries from meter reading dates to month end (accrued unbilled revenues). Accrued unbilled revenues are dependent upon a number of factors that require management’s judgment, including total gas receipts and deliveries, customer use by billing cycle and weather factors.  Accrued unbilled revenues are reversed the following month when actual billings occur. Our accrued unbilled revenues at December 31, 2011 and 2010 were $61.9 million and $64.8 million, respectively.

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From 2007 through 2010, 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 based on estimates of the annual amount to be recognized. On May 24, 2011, SB 408 was repealed and replaced by Senate Bill 967.  SB 967 required utilities to eliminate amounts accrued under SB 408 for the 2010 and 2011 tax years, thereby denying recovery by NW Natural of the surcharge accrued for 2010, which resulted in a one-time pre-tax charge of $7.4 million in the second quarter of 2011.  Pursuant to SB 967, we changed our revenue recognition policy effective January 1, 2011 and no longer recognize a regulatory adjustment for income taxes for SB 408.

Non-utility revenues are derived primarily from the gas storage business segment.  At Mist, revenues are recognized upon delivery of services to customers.  Revenues from our asset management partner are recognized over the life of the asset management contract for guaranteed amounts, if any, and are recognized as earned for amounts above the guaranteed amount. At Gill Ranch, firm storage services resulting from short-term and long-term contracts are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized.  Asset management revenue is recognized using a straight-line, pro rata methodology over the term of each contract and provides us with 80 percent of the pre-tax income from our independent energy marketing company.  See Note 4.

Accounts Receivable and Allowance for Uncollectible Accounts

Accounts receivable consist primarily of amounts due for natural gas sales and transportation services to core utility customers, plus amounts due for gas storage services.  With respect to these trade receivables, including accrued unbilled revenues, we establish an allowance for uncollectible accounts (allowance) based on the aging of receivables, collection experience of past due account balances including payment plans, and historical trends of write-offs as a percent of revenues.  With respect to large individual customer receivables, a specific allowance is established and added to the general allowance when amounts are identified as unlikely to be partially or fully recovered.  Inactive accounts are written-off against the allowance after they are 120 days past due or when deemed to be uncollectible.  Differences between our estimated allowance and actual write-offs will occur based on a number of factors, including changes in economic conditions, customer credit worthiness and the level of natural gas prices.  Each quarter the allowance for uncollectible accounts is adjusted, as necessary, based on information currently available.

Inventories

Utility gas inventories, which consist of natural gas in storage for the utility, are generally stated at the lower of average cost or net realizable value. The regulatory treatment of utility gas inventories provides for cost recovery in customer rates.  Utility gas inventories that are injected into storage are priced into inventory based on actual purchase costs. Utility gas inventories that are withdrawn from storage are charged to cost of gas during the current period at the weighted average inventory cost.

Gas Storage inventories, which primarily represent inventories at Gill Ranch, exclude cushion gas and consist of natural gas that we received as fuel-in-kind from storage customers.  Gas Storage inventories are valued at the lower of average cost or net realizable value.  Cushion gas is recorded at original cost and classified as long-term assets.

Material and supplies inventories, which consist of both utility and non-utility inventories, are stated at the lower of average cost or net realizable value.

Our utility and gas storage inventories totaled $65.6 million and $70.7 million at December 31, 2011 and 2010, respectively, and our materials and supplies inventories totaled $8.8 million and $9.7 million at December 31, 2011 and 2010, respectively.

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Gas Reserves

Our gas reserves are stated at cost, adjusted for regulatory amortization, with the associated deferred tax benefits recorded as liabilities on the balance sheet. Transactional costs to enter into the agreement (see Note 12) and payments by NW Natural to Encana Oil & Gas (USA) Inc. (Encana) are recognized as gas reserves on the balance sheet.  The current portion is calculated based on expected gas deliveries within the next fiscal year.  We recognize regulatory amortization of this asset on a volumetric basis and calculate using the proven reserves and the therms extracted and sold each month.  The amortization of gas reserves is recorded as an adjustment to the cost of gas.

Derivatives

In accordance with accounting for derivatives and hedges, we measure derivatives at fair value and recognize them as either assets or liabilities on the balance sheet.  Accounting for derivatives requires that changes in the fair value be recognized currently in earnings unless specific hedge accounting criteria are met.  Accounting for derivatives and hedges provides an exception for contracts intended for normal purchases and normal sales for which physical delivery is probable.  In addition, certain derivative contracts are approved by regulatory authorities for recovery or refund through customer rates.  Accordingly, the changes in fair value of these approved contracts are deferred as regulatory assets or liabilities pursuant to regulatory accounting principles.  Derivative contracts entered into for core utility customer requirements after the annual purchased gas adjustment (PGA) rate has been set are subject to the PGA incentive sharing mechanism. Effective November 1, 2008, Oregon approved a PGA sharing mechanism under which we are required to select either an 80 percent deferral or 90 percent deferral of higher or lower gas costs such that the impact on current earnings from the gas cost sharing is either 20 percent or 10 percent of gas cost differences compared to PGA prices, respectively. For the PGA years in Oregon beginning November 1, 2011, 2010 and 2009, we selected a 90 percent deferral of gas cost differences.  In Washington, 100 percent of our gas cost differences are deferred.  See Note 13.

Our financial derivatives policy sets forth the guidelines for using selected derivative products to support prudent risk management strategies within designated parameters.  Our objective for using derivatives is to decrease the volatility of gas prices, earnings and cash flows and to prevent speculative risk. The use of derivatives is permitted only after the risk exposures have been identified, are determined to exceed acceptable tolerance levels and are necessary to support normal business activities.  We do not enter into derivative instruments for trading purposes and we believe that any increase in market risk created by holding derivatives should be offset by the exposures they modify.

Fair Value

In accordance with fair value accounting, we use the following fair value hierarchy for determining inputs for our debt, pension plan assets and 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 assumptions that 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. Fair values are primarily developed using 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; (g) credit spreads; (h) and other relevant economic measures.

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Revenue Taxes

We account for revenue-based taxes as a separate cost item collected from customers.  Therefore, revenue taxes are accounted for as a cost of sale and presented separately on the income statement.

Income Tax Expense

NW Natural and its wholly-owned subsidiaries file consolidated federal and state income tax returns. Current income taxes are allocated based on each entity’s respective taxable income or loss and tax credits as if each entity filed a separate return. We account for income taxes in accordance with accounting standards for income taxes. Accounting for income taxes requires recognition of deferred tax liabilities and assets for the future tax consequences of events that have been included in the consolidated financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse (see Note 10).

Accounting for income taxes also requires recognition of deferred income tax assets and liabilities for temporary differences where regulators prohibit deferred income tax treatment for ratemaking purposes.  We have recorded a deferred tax liability equivalent of $68.5 million and $72.3 million at December 31, 2011 and 2010, respectively, to recognize future taxes payable resulting from transactions that have previously been reflected in the financial statements for these temporary differences.  Regulatory assets or liabilities corresponding to such additional deferred income tax assets or liabilities may be recorded to the extent we believe they will be recoverable from or payable to customers through the ratemaking process.  Pursuant to regulatory accounting principles, a corresponding regulatory asset has been recorded which represents the probable future revenue that will result from inclusion in rates charged to customers of taxes which will be paid in the future.  The probable future revenue to be recorded takes into consideration the additional future taxes which will be generated by that revenue.  Amounts applicable to income taxes due from customers primarily represent differences between the book and tax basis of net utility plant in service and actual removal costs incurred.

Deferred investment tax credits on utility plant additions, which reduce income taxes payable, are deferred for financial statement purposes and amortized over the life of the related plant or lease.

Subsequent Events

We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. We do not have any subsequent events to report.

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3. Earnings Per Share

Basic earnings per share are computed using net income and the weighted average number of common shares outstanding for each period presented.  Diluted earnings per share are computed in the same manner, except it uses the weighted average number of common shares outstanding plus the effects of the assumed exercise of stock options and the 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:

Thousands, except per share amounts	2011		2010		2009
Net income	$	63,898	$	72,667	$	75,122
Average common shares outstanding - basic		26,687		26,589		26,511
Additional shares for stock-based compensation plans		57		68		65
Average common shares outstanding - diluted		26,744		26,657		26,576
Earnings per share of common stock - basic	$	2.39	$	2.73	$	2.83
Earnings per share of common stock - diluted	$	2.39	$	2.73	$	2.83
Additional information:
Antidilutive shares not included in net income per diluted
common share calculation		2,101		743		2,142

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 asset management services. Our “other” segment includes NNG Financial and our equity investment in PGH, which is pursuing development of the Palomar pipeline project (see Other, below).

Local Gas Distribution

Our local gas distribution segment is a regulated utility principally engaged in the purchase, sale and delivery of natural gas and related services to customers in Oregon and southwest Washington. As a regulated utility, we are responsible for building and maintaining a safe and reliable pipeline distribution system, purchasing sufficient gas supplies from producers and marketers, contracting for firm and interruptible transportation of gas over interstate pipelines to bring gas from the supply basins into our service territory, and re-selling the gas to customers subject to rates, terms and conditions approved by the OPUC or WUTC.  Gas distribution also includes taking customer-owned gas and transporting it from interstate pipeline connections, or city gates, to the customers’ end-use facilities for a fee, which is approved by the OPUC or WUTC.  Approximately 90 percent of our customers are located in Oregon and 10 percent in Washington. On an annual basis, residential and commercial customers typically account for 50 to 60 percent of our utility’s total volumes delivered and 80 to 90 percent of our utility’s margin. Industrial customers account for the remaining 40 to 50 percent of volumes and 5 to 15 percent of margin.  The remaining 10 percent or less of margin is derived from miscellaneous services, gains or losses from an incentive gas cost sharing mechanism and other fees.

Industrial customers we serve include: pulp, paper and other forest products; the manufacture of electronic, electrochemical and electrometallurgical products; the processing of farm and food products; the production of various mineral products; metal fabrication and casting; the production of machine tools, machinery and textiles; the manufacture of asphalt, concrete and rubber; printing and publishing; nurseries; government and educational institutions; and electric generation.  No individual customer or industry group accounts for a significant portion of our utility revenues or margins.

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Gas Storage

Our gas storage business segment includes natural gas storage services provided to customers primarily from two underground natural gas storage facilities, our Gill Ranch gas storage facility, which commenced commercial operations in October 2010, and the non-utility portion of our Mist gas storage facility.  In addition to earning revenue from customer storage contracts, we also use an independent energy marketing company to provide asset management services for utility and non-utility capacity under contractual arrangement, the results of which are included in this business segment.   For the years ended December 31, 2011, 2010 and 2009, this business segment derived a majority of its revenues from asset management services and from firm and interruptible gas storage contracts.  

Mist Gas Storage Facility.Earnings from non-utility assets at the Mist facility are primarily related to firm storage capacity revenues. Earnings for the gas storage segment include revenues, net of amounts shared with core utility customers, from management of utility assets at Mist and upstream capacity when not needed to serve core utility customers. In Oregon, the gas storage segment retains 80 percent of the pre-tax income from these services when the costs of the capacity have not been included in utility rates, or 33 percent of the pre-tax income when the costs have been included in utility rates. The remaining 20 percent and 67 percent, respectively, are credited to a deferred regulatory account for crediting back to core utility customers.  We have a similar sharing mechanism in Washington for revenue derived from storage and third party asset management services.

Gill Ranch Gas Storage Facility.Gill Ranch has a joint project agreement with Pacific Gas and Electric Company (PG&E) to own the Gill Ranch underground natural gas storage facility near Fresno, California.  Gill Ranch has a 75 percent undivided ownership interest in the facility, which offers storage services to the California market at market-based rates, subject to CPUC regulation including, but not limited to, service terms and conditions and tariff regulations.

Other

We have non-utility investments and other business activities which are aggregated and reported as a business segment called “other.”  Although in the aggregate these investments and activities are currently not material to consolidated operations, we identify and report them as a stand-alone segment based on our organizational structure and decision-making process because these business investments and activities are not specifically related to our utility or gas storage segments.  This segment primarily consists of an equity method investment in a joint venture to build and operate an interstate gas transmission pipeline in Oregon (Palomar) and other pipeline assets in NNG Financial.  For more on information on Palomar, see Note 12.  This segment also includes some operating and non-operating revenues and expenses of the parent company that cannot be allocated to utility operations.

NNG Financial holds certain non-utility financial investments, but its assets primarily consist of an active, wholly-owned subsidiary which owns a 10 percent interest in an 18-mile interstate natural gas pipeline. NNG Financial’s total assets were $1.1 million at both December 31, 2011 and 2010.

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Segment Information Summary

The following table presents summary financial information about the reportable segments for the years ended 2011, 2010 and 2009.  Inter-segment transactions are insignificant.

Thousands	Utility		Gas Storage		Other			Total
2011
Net operating revenues	$	342,970	$	26,354	$	109		$	369,433
Depreciation and amortization		63,843		6,161		-			70,004
Income from operations		135,722		9,090		33			144,845
Net income		60,527		4,101		(730	)		63,898
Total assets at December 31, 2011		2,435,888		294,637		16,049			2,746,574
2010
Net operating revenues	$	346,148	$	21,249	$	184		$	367,581
Depreciation and amortization		62,661		2,463		-			65,124
Income from operations		145,688		11,855		62			157,605
Net income		66,262		6,110		295			72,667
Total assets at December 31, 2010		2,310,388		282,945		23,283			2,616,616
2009
Net operating revenues	$	357,005	$	19,738	$	144		$	376,887
Depreciation and amortization		61,472		1,342		-			62,814
Income from operations		142,228		16,442		46			158,716
Net income		65,960		8,923		239			75,122

5. Common Stock

Common Stock

As of December 31, 2011 and 2010, our common shares authorized were 100,000,000.  As of December 31, 2011, we had reserved for issuances 155,955 shares of common stock under the Employee Stock Purchase Plan (ESPP), 293,246 shares under our Dividend Reinvestment and Direct Stock Purchase Plan and 1,159,875 shares under our Restated Stock Option Plan (Restated SOP).

Stock Repurchase Program

We have a share repurchase program for our common stock under which we purchase shares on the open market or through privately negotiated transactions.  We currently have Board authorization through May 2012 to repurchase up to an aggregate of 2.8 million shares, or up to $100 million. No shares of common stock were repurchased pursuant to this program in 2011, 2010 or 2009.  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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Summary of Changes in Common Stock

The following table shows the changes in the number of shares of our common stock issued and outstanding for the years 2011, 2010 and 2009:

Thousands	Shares
Balance, December 31, 2008		26,501
Sales to employees under ESPP		9
Exercise of stock options under Restated SOP - net		23
Balance, December 31, 2009		26,533
Sales to employees under ESPP		24
Exercise of stock options under Restated SOP - net		111
Balance, December 31, 2010		26,668
Sales to employees under ESPP		15
Exercise of stock options under Restated SOP - net		24
Sales to shareholders under DRPP		49
Balance, December 31, 2011		26,756

6. Stock-Based Compensation

We have several stock-based compensation plans, including the Long-Term Incentive Plan (LTIP), the Restated SOP and the ESPP. These plans are designed to promote stock ownership in NW Natural by employees and officers.

Long-Term Incentive Plan

The LTIP is intended to provide a flexible, competitive compensation program for eligible officers and key employees.  An aggregate of 600,000 shares of common stock was authorized for grants under the LTIP as stock bonus, restricted stock or performance-based stock awards.  Shares awarded under the LTIP may be purchased on the open market or issued as new shares.

At December 31, 2011, 337,788 shares of common stock were available for award under the LTIP, assuming that performance based grants currently outstanding are awarded at the target level.  The LTIP stock awards are compensatory awards for which compensation expense is based on the fair value of stock awards, with expense being recognized over the performance and vesting period for the outstanding awards.

Performance-based Stock Awards.Since the LTIP’s inception in 2001, performance-based stock awards have been granted annually based on three-year performance periods.  At December 31, 2011, certain performance-based stock award measures had been achieved for the 2009-11 award period.  Accordingly, participants are estimated to receive 8,428 shares of common stock and a dividend equivalent cash payment equal to the number of shares of common stock received on the award payout multiplied by the aggregate cash dividends paid per share during the performance period. At December 31, 2010 and 2009, we awarded 8,007 and 15,900 shares of common stock, respectively, for the 2008-10 and 2007-09 award periods, plus a dividend equivalent cash payment equal to the number of shares of common stock received on the award payout multiplied by the aggregate cash dividends paid per share during the performance period. In 2010 and 2009, we expensed $0.2 million and $0.5 million respectively for both the 2008-10 and 2007-09 performance-based stock award periods, and on a cumulative basis we accrued a total of $0.7 million and $1.5 million, respectively, related to the 2008-10 and 2007-09 performance periods.

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At December 31, 2011, the aggregate number of performance-based shares granted and outstanding at the threshold, target and maximum levels were as follows:

Performance		Performance Share Awards Outstanding							2011			Cumulative Expense
Period		Threshold			Target		Maximum		Expense			At Dec. 31, 2011
	2009-11		7,410			39,000		78,000		$	353		$	763
	2010-12		n/a	(1)		41,500		83,000			430			718
	2011-13		n/a	(1)		37,950		75,900			276		$	276
Total						118,450		236,900		$	1,059
(1)The threshold requirement was modified and is no longer applicable beginning in the 2010-12 performance period.

The threshold level estimates future payout assuming the minimum award payable is achieved for each component of the formula in the LTIP.  For each of these performance periods, awards will be based on total shareholder return relative to a peer group of gas distribution companies over the three-year performance period and on performance results achieved relative to specific core and non-core strategies.  Compensation expense is recognized in accordance with the accounting standard for stock compensation based on performance levels achieved and an estimated fair value using a Black-Scholes or binomial model.  The weighted-average grant date fair value of unvested shares at December 31, 2011 and 2010 was $25.06 and $23.10 per share, respectively.  The weighted-average grant date fair value of shares vested during the year was $22.35 per share and granted during the year was $19.38 per share.  

Restricted Stock Units.  A new form of restricted stock awards was approved by the Board in 2011.  Restricted Stock Units (RSUs) are expected to be used instead of the Restated SOP starting in February of 2012.  The LTIP plan was amended to allow RSUs to be granted under the plan. RSUs are expected to include a performance based threshold and a vesting period of four years from the grant date.  An RSU obligates the Company upon vesting to issue the RSU holder one share of common stock plus a cash payment equal to the total amount of dividends paid per share between the grant date and vesting date of the RSU.

Restated Stock Option Plan

A total of 2,400,000 shares of common stock were reserved for issuance under the Restated SOP with 580,650 available for grant as of December 31, 2011.  Options under the Restated SOP may be granted only to officers and key employees designated by a committee of our Board of Directors.  All options are granted at an option price equal to the closing market price on the date of grant and may be exercised for a period up to 10 years and 7 days from the date of grant.  Option holders may exchange shares they have owned for at least six months, at the current market price, to purchase shares at the option price.

The fair value of each stock option is estimated on the grant date using the Black-Scholes option pricing model with the following weighted average assumptions and outcomes:

	2011			2010			2009
Risk-free interest rate		2.0	%		2.3	%		2.0	%
Expected life (in years)		4.5			4.7			4.7
Expected market price volatility factor		24.5	%		23.2	%		22.5	%
Expected dividend yield		3.8	%		3.8	%		3.8	%
Forfeiture rate		3.1	%		3.2	%		3.7	%
Weighted average grant date fair value	$	6.73		$	6.36		$	5.46

The expected life of our grants was calculated based on our actual experience with previously exercised option grants.  The risk-free interest rate was based on the implied yield currently available on U.S. Treasury zero-coupon issues with a life equal to the expected life of the options.  Historical data was used to estimate the volatility factor, measured on a daily basis, for a period equal to the duration of the expected life of the option awards.  The dividend yield was based on management’s current estimate for future dividend payouts at the time of grant.  We expense the total cost of stock option awards granted to retirement eligible employees at the date of grant in accordance with stock option accounting guidance and the retirement vesting provisions of our option agreements.

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Information regarding the Restated SOP activity for the three years ended December 31, 2011 is summarized as follows:

				Weighted -		Intrinsic
	Option			Average		Value
	Shares			Price Per Share		(In millions)
Balance outstanding, Dec. 31, 2008		396,410		$	38.62	$	2.3
Granted		111,750			41.15		n/a
Exercised		(23,225	)		30.92		0.3
Balance outstanding, Dec. 31, 2009		484,935			39.57		2.7
Granted		119,750			44.25		n/a
Exercised		(111,525	)		39.01		0.9
Forfeited		(2,700	)		43.00		n/a
Balance outstanding, Dec. 31, 2010		490,460			40.82		2.8
Granted		122,700			45.74		n/a
Exercised		(24,185	)		33.88		0.3
Forfeited		(9,750	)		44.38		n/a
Balance outstanding, Dec. 31, 2011		579,225		$	42.09	$	3.4
Exercisable, Dec. 31, 2011		311,951		$	40.20	$	2.4

In the year ended December 31, 2011, cash of $0.8 million was received for option shares exercised and a $26,000 thousand related tax benefit was realized.  For the 12 months ended December 31, 2011, 2010 and 2009, the total fair value of options that vested was $0.6 million, $0.5 million and $0.4 million, respectively.  The weighted average remaining life of options exercisable and outstanding at December 31, 2011 was 5.5 years and 6.8 years, respectively.  As of December 31, 2011, 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 2014.

Employee Stock Purchase Plan

The ESPP allows employees to purchase common stock at 85 percent of the closing price on the trading day immediately preceding the initial offering date, which is set annually.  Each eligible employee may purchase up to $21,210 worth of stock through payroll deductions over a 12-month period.

In accordance with accounting for stock compensation, stock-based compensation expense is recognized as operations and maintenance expense or is capitalized as part of construction overhead.  The following table summarizes the financial statement impact of stock-based compensation under our LTIP, Restated SOP and ESPP:

Thousands	2011			2010			2009
Operations and maintenance expense, for stock-based compensation	$	1,477		$	1,032		$	1,434
Income tax benefit		(597	)		(418	)		(559	)
Net stock-based compensation effect on net income	$	880		$	614		$	875
Amounts capitalized for stock-based compensation	$	261		$	182		$	229

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7.           Cost and Fair Value Basis of Long-Term Debt

Cost of Long-Term Debt

The issuance of first mortgage debt, including secured medium-term notes (MTNs), under the Mortgage and Deed of Trust (Mortgage) is limited by eligible property, adjusted net earnings and other provisions of the Mortgage.  The Mortgage constitutes a first mortgage lien on substantially all of our utility property. In addition, our Gill Ranch subsidiary senior secured notes are secured by all of the membership interests in Gill Ranch Storage, LLC as well as Gill Ranch’s debt service reserve account.

The maturities on the long-term debt outstanding for each of the 12-month periods through December 31, 2016 amount to: $40 million in 2012; none in 2013; $60 million in 2014; $40 million in 2015; and $65 million in 2016.

Thousands	2011		2010		2009
Utility Medium-Term Notes:
First Mortgage Bonds:
4.11 % Series B due 2010	$	-	$	-	$	10,000
7.45 % Series B due 2010		-		-		25,000
6.665% Series B due 2011		-		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
3.95 % Series B due 2014		50,000		50,000		50,000
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		75,000		75,000		75,000
9.05 % Series A due 2021		10,000		10,000		10,000
3.176 % Series A due 2021		50,000		-		-
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		19,700		19,700		19,700
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
		641,700		601,700		636,700
Subsidiary Senior Secured Notes:
Gill Ranch Notes due 2016(1)		40,000		-		-
		681,700		601,700		636,700
Less current maturities of long-term debt		40,000		10,000		35,000
Total long-term debt	$	641,700	$	591,700	$	601,700

(1)   In November 2011, Gill Ranch issued senior secured notes consisting of $20 million of fixed rate notes with an interest rate of 7.75 percent and $20 million of variable interest rate notes with an interest rate of LIBOR plus 5.50, or a minimum of 7.00 percent.  Currently, the variable interest rate is 7.00 percent.

Utility Medium-Term Notes

In March 2009, the utility issued $75 million of 5.37 percent secured MTNs due February 1, 2020, and in July 2009 issued another $50 million of 3.95 percent secured MTNs due July 15, 2014.  The utility also issued $50 million of MTNs in September 2011 with an interest rate of 3.176 percent and a maturity date of September 15, 2021.

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Subsidiary Senior Secured Notes

In November 2011, Gill Ranch issued $40 million of subsidiary senior secured notes with an interest rate of 7.75 percent on the fixed portion and a 7.00 percent interest rate currently on the variable portion. The notes are secured by all of the membership interests in Gill Ranch Storage, LLC, and are nonrecourse notes to NW Natural.  The maturity date of these notes is November 30, 2016.

Under the note agreements, Gill Ranch is subject to certain covenants and restrictions, including but not limited to, a financial covenant that requires Gill Ranch to maintain minimum adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) at various levels over the term of the notes. The minimum adjusted EBITDA increases incrementally over the first few years, reaching its highest level in the 12-month period beginning April 1, 2015.  Under the note agreements, Gill Ranch is also subject to a debt service reserve requirement of 10 percent of the outstanding principal amount, initially $4 million, certain prepayment penalties, restrictions on dividends out of Gill Ranch unless certain earnings ratios are met, and restrictions on incurrence of additional debt.

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 for outstanding debt issues that actively trade and have similar characteristics such as size, credit ratings, financial terms and remaining maturities to estimate fair value for our long-term debt issues.

	December 31,
Thousands	2011		2010
Carrying amount	$	681,700	$	601,700
Estimated fair value	$	808,724	$	690,126

8.           Short-term Debt and Credit Facilities

Our primary source of short-term funds is from the sale of commercial paper and bank loans.  In addition to issuing commercial paper or bank loans to meet seasonal working capital requirements, short-term debt is used temporarily to fund capital requirements.  Commercial paper and bank loans are periodically refinanced through the sale of long-term debt or equity securities.  Our commercial paper program is supported by one or more committed credit facilities.  At December 31, 2011 and 2010, the amounts and average interest rates of commercial paper debt outstanding were $141.6 million at  0.3 percent and $257.4 million at 0.4 percent, respectively. There were no bank loans outstanding at December 31, 2011 or 2010.

At NW Natural, we have a multi-year $250 million syndicated credit agreement, pursuant to which we may extend commitments for additional one-year periods subject to lender approval. We extended commitments under this syndicated agreement to May 31, 2013.  The syndicated agreement allows us to request increases in the total commitment amount from time to time, up to a maximum amount of $400 million, and to replace any lenders who decline to extend the terms of the agreement. The syndicated agreement also permits the issuance of letters of credit in an aggregate amount up to the applicable total borrowing commitment. Any principal and unpaid interest owed on borrowings under the syndicated agreement are due and payable on or before the expiration date.  There were no outstanding balances under the syndicated credit agreement and no letters of credit issued or outstanding at December 31, 2011 and 2010.

The syndicated credit agreement requires that we maintain credit ratings with Standard & Poor’s (S&P) and Moody’s Investors Service, Inc. (Moody’s) and notify the lenders of any change in our senior unsecured debt ratings by such rating agencies. A change in our debt ratings is not an event of default, nor is the maintenance of a specific minimum level of debt rating a condition of drawing upon the credit facility. However, interest rates on any loans outstanding under the credit facility are tied to debt ratings, which would increase or decrease the cost of any loans under the credit facility when ratings are changed.  There were no changes in our credit ratings during 2011.

The syndicated credit agreement also requires us to maintain a consolidated indebtedness to total capitalization ratio of 70 percent or less. Failure to comply with this covenant would entitle the lenders to terminate their lending commitments and accelerate the maturity of all amounts outstanding. We were in compliance with this covenant at December 31, 2011 and 2010.

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9. Pension and Other Postretirement Benefits

We maintain two qualified non-contributory defined benefit pension plans covering a majority of our regular NW Natural employees with more than one year of service, several non-qualified supplemental pension plans for eligible executive officers and certain key employees and other postretirement employee benefit plans.  We also have a qualified defined contribution plan (Retirement K Savings Plan) for all eligible employees.  Only the two qualified defined benefit pension plans and Retirement K Savings Plan have plan assets, which are held in a qualified trust to fund retirement benefits.  Effective January 1, 2007 and 2010, the qualified defined benefit retirement plans and postretirement benefits for non-union employees and for union employees, respectively, were closed to new participants.  These plans were not available to employees of our NW Natural subsidiaries.  Non-union and union employees hired or re-hired after December 31, 2006 and 2009, respectively, and employees of NW Natural subsidiaries are provided an enhanced Retirement K Savings Plan benefit. Also, effective January 1, 2007, the postretirement Welfare Benefit Plan for Non-Bargaining Unit Employees was closed to new participants after December 31, 2006.

The following table provides a reconciliation of the changes in benefit obligations and fair value of plan assets, as applicable, for the pension and other postretirement benefit plans, excluding the Retirement K Savings Plan, for the years ended December 31, 2011, 2010, and 2009, and a summary of the funded status and amounts recognized in the consolidated balance sheets using measurement dates as of December 31, 2011, 2010 and 2009:

	Postretirement Benefit Plans
	Pension Benefits									Other Benefits
Thousands	2011			2010			2009			2011			2010			2009
Reconciliation of change in benefit obligation:
Obligation at January 1	$	339,338		$	307,991		$	281,127		$	27,676		$	24,741		$	23,863
Service cost		7,122			6,688			6,402			614			588			522
Interest cost		18,134			18,029			17,948			1,404			1,436			1,568
Net actuarial (gain) or loss		44,802			25,275			23,584			2,225			2,387			216
Benefits paid		(18,269	)		(18,645	)		(17,149	)		(1,870	)		(1,476	)		(1,428	)
Plan amendments		-			-			(3,921	)		-			-			-
Obligation at December 31	$	391,127		$	339,338		$	307,991		$	30,049		$	27,676		$	24,741
Reconciliation of change in plan assets:
Fair value of plan assets at January 1	$	219,014		$	201,312		$	163,115		$	-		$	-		$	-
Actual return on plan assets		(6,684	)		24,651			28,641			-			-			-
Employer contributions		21,909			11,696			26,705			1,870			1,476			1,428
Benefits paid		(18,269	)		(18,645	)		(17,149	)		(1,870	)		(1,476	)		(1,428	)
Fair value of plan assets at December 31	$	215,970		$	219,014		$	201,312		$	-		$	-		$	-
Funded status at December 31	$	(175,157	)	$	(120,324	)	$	(106,679	)	$	(30,049	)	$	(27,676	)	$	(24,741	)

Our qualified defined benefit pension plans had an aggregate projected benefit obligation of $362.9 million, $314.5 million and $285.2 million at December 31, 2011, 2010, and 2009, respectively, and the fair value of plan assets was $216.0 million, $219.0 million and $201.3 million, respectively.  Changes in certain pension assumptions impact our projected benefit obligations. Benefit obligations at December 31, 2011 increased $40.3 million due to decreases in our discount rate assumptions and increased by $0.9 million due to changes in other assumptions.  The projected benefit obligations at December 31, 2010 increased $17.9 million over the prior year due to decreases in our discount rate assumptions and increased by $6.5 million due to changes in other assumptions.  

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The following table provides amounts amortized from accumulated other comprehensive income (AOCI) or regulatory assets to net periodic benefit cost during 2011, 2010, and 2009:

	Regulatory Asset Amortization												AOCI Amortization
	Pension Benefits						Other Postretirement Benefits						Pension Benefits
Thousands	2011		2010		2009		2011		2010		2009		2011		2010			2009
Net periodic benefit costs:
Actuarial loss	$	10,731	$	6,740	$	6,189	$	289	$	131	$	17	$	854	$	707		$	449
Prior service cost		230		230		1,260		197		197		197		122		(43	)		(37	)
Transition obligation		-		-		-		411		411		411		-		-			-
Total	$	10,961	$	6,970	$	7,449	$	897	$	739	$	625	$	976	$	664		$	412

In 2012, an estimated $15.5 million will be amortized from regulatory assets to net periodic benefit costs, consisting of $14.7 million of actuarial losses, $0.4 million of prior service costs and $0.4 million of transition obligations, and $1.0 million will be amortized from AOCI to earnings related to actuarial losses.

Our assumed discount rate was determined independently for each pension plan and other postretirement benefit plan based on the Citigroup Above Median Curve (discount rate curve) using high quality bonds (i.e. rated AA- or higher by S&P or Aa3 or higher by Moody’s).  The discount rate curve was then applied to match the estimated cash flows in each plan to reflect the timing and amount of expected future benefit payments for these plans.

The assumption for expected long-term rate of return on plan assets was developed as a weighted average of the expected earnings for the target asset portfolio.  In developing the expected long-term rate of return assumption, consideration was given to the historical performance of each asset class in which the plans’ assets are invested and the target asset allocation for plan assets.

Our investment strategy and policies for the qualified pension plan assets held in the Retirement Trust Fund were approved by our retirement committee, which is composed of senior management employees with the assistance of an investment consultant.  The policies set forth the guidelines and objectives governing the investment of plan assets.  Plan assets are invested for total return with appropriate consideration for liquidity and portfolio risk.  All investments are expected to satisfy the requirements of the rule of prudent investments as set forth under the Employee Retirement Income Security Act of 1974.  The approved asset classes include cash and short-term investments, fixed income, common stock and convertible securities, absolute and real return strategies, real estate and investments in our common stock.  Plan assets may be invested in separately managed accounts or in commingled or mutual funds.  Investment re-balancing takes place periodically as needed, or when significant cash flows occur, in order to maintain the allocation of assets within the stated target ranges.  Our expected long-term rate of return is based upon historical index returns by asset class, adjusted by a factor based on our historical return experience, diversified asset allocation and active portfolio management by professional investment managers.  The Retirement Trust Fund is not currently invested in any NW Natural securities.

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The following is our pension plan asset target allocation at December 31, 2011:

	Target
Asset Category	Allocation
U.S. large cap equity		15.0	%
U.S. small/mid cap equity		10.0	%
Non-U.S. equity		14.5	%
Emerging markets equity		3.5	%
Long government/credit		24.0	%
High yield		5.0	%
Emerging market debt		5.0	%
Real estate funds		5.8	%
Absolute return strategy		12.0	%
Real return strategy		5.2	%

Our non-qualified supplemental defined benefit pension benefit obligations were $28.2 million, $24.9 million and $22.8 million at December 31, 2011, 2010 and 2009, respectively.  These plans are not subject to regulatory deferral and the changes in actuarial gains and losses, prior service costs and transition assets or obligations are recognized in AOCI under common stock equity, net of tax, until they are amortized as a component of net periodic benefit cost.  Although these are unfunded plans with no plan assets due to their nature as non-qualified plans, we indirectly fund a portion of our obligations with company- and trust-owned life insurance.

Our plans for providing postretirement benefits other than pensions also are unfunded plans, but are subject to regulatory deferral.  The gains and losses, prior service costs and transition assets or obligations for these plans were recognized as a regulatory asset. 

Net periodic benefit cost consists of service costs, interest costs, the amortization of actuarial gains and losses, the expected returns on plan assets and, in part, on a market-related valuation of assets.  The market-related valuation reflects differences between expected returns and actual investment returns, which are recognized over a three-year period or less from the year in which they occur, thereby reducing year-to-year net periodic benefit cost volatility.

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The following tables provide the components of net periodic benefit cost for the qualified and non-qualified pension and other postretirement benefit plans for the years ended December 31, 2011, 2010 and 2009 and the assumptions used in measuring these costs and benefit obligations:

	Pension Benefits									Other Postretirement Benefits
Thousands	2011			2010			2009			2011			2010			2009
Service cost	$	7,122		$	6,688		$	6,402		$	614		$	588		$	522
Interest cost		18,134			18,029			17,948			1,404			1,436			1,568
Expected return on plan assets		(17,867	)		(18,207	)		(15,696	)		-			-			-
Amortization of transition
obligations		-			-			-			411			411			411
Amortization of prior service costs		352			187			1,223			197			197			197
Amortization of net actuarial loss		11,584			7,447			6,810			289			131			-
Net periodic benefit cost		19,325			14,144			16,687			2,915			2,763			2,698
Amount allocated to construction		(4,905	)		(3,729	)		(4,636	)		(878	)		(904	)		(858	)
Amount deferred to regulatory
balancing account		(6,008	)		-			-			-			-			-
Net amount charged to expense	$	8,412		$	10,415		$	12,051		$	2,037		$	1,859		$	1,840

	Pension Benefits			Other Postretirement Benefits
	2011	2010	2009	2011	2010	2009
Assumptions for net periodic benefit
cost:
Weighted-average discount rate	5.49%	6.01%	6.60%	5.16%	5.78%	7.12%
Rate of increase in compensation	3.25-5.0%	3.25-5.0%	3.25-5.0%	n/a	n/a	n/a
Expected long-term rate of return	8.25%	8.25%	8.25%	n/a	n/a	n/a
Assumptions for funded status:
Weighted-average discount rate	4.51%	5.49%	6.01%	4.33%	5.16%	5.78%
Rate of increase in compensation	3.25-5.0%	3.25-5.0%	3.25-5.0%	n/a	n/a	n/a
Expected long-term rate of return	8.00%	8.25%	8.25%	n/a	n/a	n/a

The assumed annual increase in health care cost trend rates used in measuring other postretirement benefits as of December 31, 2011 were 8.0 percent for medical and 10.0 percent for prescription drugs.  Medical costs and prescription drugs are assumed to decrease gradually each year to a rate of 5.0 percent by 2021.

Assumed health care cost trend rates can have a significant effect on the amounts reported for the health care plans.  A one percentage point change in assumed health care cost trend rates would have the following effects:

Thousands	1% Increase		1% Decrease
Effect on net periodic postretirement health care benefit cost	$	67	$	(60	)
Effect on the accumulated postretirement benefit obligation	$	678	$	(613	)

The impact of a change in retirement benefit costs on operating results would be less than the amounts shown above because 30 to 40 percent of these amounts would be capitalized to construction accounts as payroll overhead and included in utility plant, and a certain amount of increases or decreases could be recorded to the regulatory balancing account for pensions, with the remaining amount recognized in current earnings.

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The following table provides information regarding employer contributions and benefit payments for the two qualified pension plans, non-qualified pension plans and other postretirement benefit plans for the years ended December 31, 2011 and 2010, and estimated future contributions and payments:

Thousands
Employer Contributions	Pension Benefits		Other Benefits
2010	$	12,088	$	1,476
2011		22,325		1,870
2012 (estimated)		30,109		2,056
Benefit Payments
2009		17,149		1,428
2010		18,645		1,476
2011		18,269		1,870
Estimated Future Payments
2012		19,374		2,056
2013		19,620		2,083
2014		20,107		2,138
2015		20,640		2,149
2016		21,284		2,198
2017-2021		122,680		11,298

We make contributions to our qualified defined benefit pension plans based on actuarial assumptions and estimates, tax regulations and funding requirements under federal law. The Pension Protection Act of 2006 (the Act) established new funding requirements for defined benefit plans.  The Act establishes a 100 percent funding target over seven years for plan years beginning after December 31, 2008.  Our qualified defined benefit pension plans are currently underfunded by $146.9 million at December 31, 2011, and we expect to make contributions during 2012 of approximately $28 million.

The Retirement K Savings Plan provided to our employees is a qualified defined contribution plan under Internal Revenue Code Section 401(k).  Our contributions to this plan totaled $2.4 million 2011 and $2.1 million in 2010 and 2009.  The Retirement K Savings Plan includes an Employee Stock Ownership Plan. 

The supplemental deferred compensation plans for eligible officers and senior managers are non-qualified plans.  These plans are designed to enhance the retirement savings of employees and to assist them in strengthening their financial security by providing an incentive to save and invest regularly.  

In addition to the company-sponsored defined benefit plans referred to above, 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) in accordance with our collective bargaining agreement.  The employer identification number of the plan is 94-6076144.  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 funded status of the plan.  Our contributions to the Western States Plan amounted to $0.4 million in 2011, 2010 and 2009 which is greater than 5 percent of the total contributions to the plan by all participants.

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 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.

Fair Value

Following is a description of the valuation methodologies used for assets measured at fair value. In cases where the pension plan is invested through a collective trust fund or mutual fund, our custodian uses the fund’s market value.  The custodian also provides the market values for investments directly owned.

U.S. large cap equity:  These are level 1 assets valued at the closing price reported on the active market on which the individual security is traded.  This asset class includes investments primarily in U.S. common stocks.

U.S. small/mid cap equity:  These are level 2 assets valued based on information provided by the plan’s investment custodians. The financial statements of the commingled fund are audited annually by independent accountants. Values for such funds are stated at estimated fair values, which have been determined based on the unit values of the funds. Unit values are determined by the bank sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the valuation date.  This asset class includes investments primarily in U.S. common stocks.

Non-U.S. equity:  These are level 1 and 2 assets.  Level 1 assets are valued at the closing price reported on the active market on which the individual security is traded.  Level 2 assets are valued based on information provided by the plan’s investment custodians. The financial statements of the commingled fund are audited annually by independent accountants. Values for such funds are stated at estimated fair values, which have been determined based on the unit values of the funds. Unit values are determined by the bank sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the valuation date.  This asset class includes investments primarily in foreign equity common stocks.

Emerging market equity:  These are level 1 assets valued at the net asset value of the shares held by the plan at the valuation date.  This asset class includes investments primarily in common stocks in emerging markets.

Fixed income:  These are level 1 assets valued at the net asset value of the shares held by the plan at the valuation date.  This asset class includes investments primarily in investment grade debt and fixed income securities. 

Long Government/Credit:  These are level 2 assets whose values are determined by closing values if available and by matrix pricing for illiquid securities.  This asset class includes long duration fixed income investments primarily in U.S. treasuries, U.S. government agencies, municipal securities, mortgage-backed securities, asset-backed securities, as well as U.S. and international investment-grade corporate bonds.

Real estate funds: These are level 3 assets valued based on the interest held by the plan, for which fair values of the underlying investments are subject to appraisal as directed by the funds’ management.  This asset class includes a real estate fund that invests directly in real estate.  The underlying properties held in the funds are appraised utilizing the following approaches: the cost approach (the current cost of replacing the real estate less deterioration and functional and economic obsolescence); the income approach (the ability of the underlying properties to generate net rental income); and the comparable sales approach (recent sales of comparable real estate in the same market). The plan's ability to redeem these investments is subject to certain restrictions and cash availability.

Absolute return strategy: These are level 2 assets valued based on information provided by the plan’s investment custodians. The financial statements of the partnerships are audited annually by independent accountants, with the value of the underlying investments based on the estimated fair value of the various holdings in the portfolio as reported in the financial statements at net asset value.  This asset class includes a hedge fund.  Our investment normally provides for a quarterly distribution subject to 95 days advance notice of withdrawal.  Currently there are no restrictions on withdrawal requests, and as of December 31, 2011 we have not submitted a withdrawal request.

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Real return strategy:  These are level 1 assets valued at the net asset value of the shares held by the plan at the valuation date.  This asset class includes an investment in a broad range of assets and strategies primarily including fixed income and equity securities, along with commodities.

Cash and cash equivalents:  These are level 2 assets valued at the net asset value of the shares held by the plan at the valuation date.  This asset class primarily includes a money market mutual fund.

The preceding valuation methods may produce a fair value calculation that is not indicative of net realizable value or reflective of future fair values. Although we believe these valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.

Investment securities are exposed to various financial risks including interest rate, market and credit risks.  Due to the level of risk associated with certain investment securities, it is reasonably possible that changes in the values of our investment securities will occur in the near term and that such changes could materially affect our investment account balances and the amounts reported as plan assets available for benefits payments.

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The following table presents the fair value of plan assets, including outstanding receivables and liabilities, of the Retirement Trust Fund as of December 31, 2011 and 2010:

	December 31, 2011
Investments, in thousands		Level 1		Level 2			Level 3		Total
U.S. large cap equity		$	36,236	$	-		$	-	$	36,236
U.S. small/mid cap equity			-		27,310			-		27,310
Non-U.S. equity			22,158		11,587			-		33,745
Emerging markets equity			10,208		-			-		10,208
Fixed income			19,121		-			-		19,121
Long government/credit			-		18,897			-		18,897
Real estate funds			-		-			15,317		15,317
Absolute return strategy			-		30,475			-		30,475
Real return strategy			15,475		-			-		15,475
Cash and cash equivalents			-		9,290			-		9,290
Total investments		$	103,198	$	97,559		$	15,317	$	216,074
	December 31, 2010
Investments, in thousands		Level 1		Level 2			Level 3		Total
U.S. large cap equity		$	37,231	$	-		$	-	$	37,231
U.S. small/mid cap equity			-		27,864			-		27,864
Non-U.S. equity			24,630		14,549			-		39,179
Emerging markets equity			11,476		-			-		11,476
Fixed income			36,429		-			-		36,429
Real estate funds			-		-			14,721		14,721
Absolute return strategy			-		32,378			-		32,378
Real return strategy			15,452		-			-		15,452
Cash and cash equivalents			-		3,629			-		3,629
Total investments		$	125,218	$	78,420		$	14,721	$	218,359
						December 31,
Receivables								2011		2010
Accrued interest and dividend income							$	414	$	249
Due from broker for securities sold								321		448
Total receivables							$	735	$	697
Liabilities
Due to broker for securities purchased							$	839	$	42
Total investment in retirement trust							$	215,970	$	219,014

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Level 3 Investments

The following table presents the beginning balance, activity and ending balance of Level 3 investments that have their fair values established using significant unobservable inputs as of December 31, 2011: 

	Level 3 Assets
Thousands	Real estate Funds
January 1, 2011 balance	$	14,721
Total gains or (losses):
Included in earnings (or changes in net assets)		596
December 31, 2011 balance	$	15,317

10.           Income Tax

A reconciliation between income taxes calculated at the statutory federal tax rate and the provision for income taxes reflected in the consolidated financial statements is as follows:

Thousands, except percentages	2011			2010			2009
Income taxes at federal statutory rate	$	37,550		$	42,745		$	42,627
Increase (decrease):
Current state income tax, net of federal tax benefit		4,945			5,803			5,568
Amortization of investment and energy tax credits		(442	)		(525	)		(593	)
Differences required to be flowed-through by
regulatory commissions		1,647			1,647			(116	)
Gains on company and trust-owned life insurance		(786	)		(715	)		(1,195	)
Other - net		468			507			380
Total provision for income taxes	$	43,382		$	49,462		$	46,671
Effective tax rate		40.4	%		40.5	%		38.3	%

The provision (benefit) for current and deferred income taxes consists of the following:

Thousands	2011			2010			2009
Current
Federal	$	130		$	(28,592	)	$	6,221
State		(929	)		1,441			2,300
		(799	)		(27,151	)		8,521
Deferred
Federal		35,481			69,159			31,937
State		8,700			7,454			6,213
		44,181			76,613			38,150
Total provision for income taxes	$	43,382		$	49,462		$	46,671
Total income taxes paid	$	1,756		$	22,600		$	10,000

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The following table summarizes the total provision (benefit) for income taxes for the regulated utility and non-utility business segments for the three years ended December 31:

Thousands	2011			2010			2009
Regulated utility:
Current	$	(4,646	)	$	(1,464	)	$	871
Deferred		50,152			47,741			40,829
Deferred investment and energy tax credits		(422	)		(525	)		(593	)
		45,084			45,752			41,107
Non-utility business segments:
Current		3,846			(25,687	)		7,650
Deferred		(5,548	)		29,397			(2,086	)
		(1,702	)		3,710			5,564
Total provision for income taxes	$	43,382		$	49,462		$	46,671

The following table summarizes the tax effect of significant items comprising our deferred income tax accounts for the two years ended December 31:

Thousands	2011			2010
Deferred tax liabilities:
Plant and property	$	292,235		$	255,471
Regulatory adjustment for income taxes paid		2,106			5,272
Regulatory income tax assets		65,755			68,822
Regulatory liabilities		35,638			23,159
Non-regulated deferred tax liabilities		43,373			34,544
Total	$	439,107		$	387,268
Deferred tax assets:
Regulatory assets		(4,727	)		(1,402	)
Unfunded pension and postretirement obligations		(5,119	)		(4,342	)
Non-regulated deferred tax assets		(1,161	)		(772	)
Alternative minimum tax credit carryforward		(1,626	)		(1,702	)
Loss and credit carryforwards		(14,255	)		(7,071	)
Total		(26,888	)		(15,289	)
Deferred income tax liabilities - net		412,219			371,979
Deferred investment tax credits		990			1,430
Deferred income taxes and investment tax credits	$	413,209		$	373,409

We have determined that we are more likely than not to realize all recorded deferred tax assets as of December 31, 2011.

We calculate our deferred tax assets and liabilities according to accounting guidance on income taxes, whereby deferred income taxes are generally determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect in the years in which the differences are expected to reverse. Deferred tax provisions are not recorded in the income statement for certain temporary differences where regulators require that we flow through deferred income tax benefits or expenses in the utility ratemaking process.

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     In September 2010, Congress passed the Unemployment Insurance, Reauthorization and Job Creation Act of 2010 (the Act) and the legislation was signed into law by President Obama.  The Act extended for one year the temporary bonus depreciation rules first enacted in the Economic Stimulus Act of 2008 and subsequently renewed in the American Recovery and Reinvestment Act of 2009.  Under the bonus depreciation provision, an additional first-year tax deduction was allowed for depreciation equal to 50 percent of the adjusted basis of qualified property through September 8, 2010, in the year the property was placed in service, with the remaining percentage recovered under the normal depreciation rules.  In addition, on December 17, 2010, President Barack Obama signed into law the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act), which allows 100 percent bonus depreciation  for qualified property placed in service between September 9, 2010 through December 31, 2011.  It also extended the 50% bonus depreciation deduction to qualifying property placed in service through 2012.

In 2011 the Company received a tax refund of $14.4 million for tax year 2010.  In addition, the company carried back a portion of its 2010 net operating loss to tax year 2009 and received a refund of $22.3 million. In 2011 we filed an amended federal income tax return for 2009, primarily to report a deduction for repairs expense consistent with a change in accounting method approved by the IRS and in conformity with the deduction allowed by the IRS in its examination of years 2006-2008.  The Company then amended its net operating loss carryback to tax year 2009.  The result of the amended federal tax return for tax year 2009 and the amended net operating loss carryback is a federal income tax refund receivable of $3.5 million at December 31, 2011.  The company estimates that it has a consolidated net operating loss carryforward to 2012 of $33.7 million. The net operating loss carryforward will be carried forward to reduce our current tax liability in future years.  We anticipate that we will be able to utilize the entire net operating loss carryforward before its expiration in twenty years.

For the year ended December 31, 2010, we reported taxable income for Oregon purposes due to lack of federal-state conformity with respect to the accelerated depreciation effects cited above.  The Company recorded a current receivable of $3.5 million to reflect the excess of payments applied to year 2010 over the amount owed.  The Company received this refund in the first quarter of 2012.  As of January 1, 2011, Oregon conformed to federal rules including bonus depreciation.  As a result, we anticipate generating an NOL for state purposes in 2011.  Oregon does not allow NOL carrybacks, but allows NOLs to be carried forward for fifteen years.  We expect to fully utilize the estimated NOL generated in 2011.

Uncertain tax positions are accounted for in accordance with accounting standards that require management’s assessment of the expected treatment of a tax position taken in a filed tax return, or planned to be taken in a future tax return, that has not been reflected in measuring income tax expense for financial reporting purposes. Until such positions are sustained by the taxing authorities, we would not recognize the tax benefits resulting from such positions and would report the tax effect as a liability in the Company’s consolidated balance sheet. As of December 31, 2011, we had no uncertain tax positions.

The IRS completed its examination of the 2006 through 2008 tax years in 2011.  The examination resulted in payments of $1.5 million of tax and $0.2 million of interest.  The Oregon Department of Revenue (ODOR) completed its field examination of our 2006 through 2009 consolidated Oregon income tax returns and issued preliminary assessments.  If sustained by the ODOR, these assessments would result in an additional state tax liability of approximately $0.8 million, including interest and penalties.  The Company is engaged in discussions with ODOR to resolve these issues; however, uncertainty exists with respect to the outcome of the audit as a result of information not yet fully considered by the ODOR.  Resolution is expected to be reached within the next 12 months, and we have determined that it is more-likely-than-not that we will prevail on these issues.  As such, no amounts have been recorded in our financial statements as of December 31, 2011 related to this matter.

Interest and penalties related to any future income tax deficiencies are recorded within income tax expense in the consolidated statements of income.

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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 at December 31:

Thousands	2011		2010
Utility plant in service	$	2,323,467	$	2,247,952
Utility construction work in progress		36,051		29,324
Less accumulated depreciation		749,603		710,214
Utility plant-net		1,609,915		1,567,062
Non-utility plant in service		293,205		290,038
Non-utility construction work in progress		8,379		9,088
Less accumulated depreciation		17,623		12,025
Non-utility plant-net		283,961		287,101
Total property plant and equipment	$	1,893,876	$	1,854,163

The weighted average depreciation rate for utility assets was 2.8 percent in 2011 and 2010.  The weighted average depreciation rate for non-utility assets was 2.2 percent in 2011 and 2.5 percent in 2010.

Accumulated depreciation does not include the accumulated provision for asset removal costs of $267.4 million and $252.9 million at December 31, 2011 and 2010, respectively.  These accrued asset removal costs are reflected on the balance sheets as regulatory liabilities (see Note 2, “Plant, Property and Accrued Asset Removal Costs”).

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. The following table summarizes our other investments at December 31:

Thousands	2011		2010
Investments in life insurance policies	$	51,911	$	51,090
Investments in gas pipeline joint ventures		14,340		15,742
Other		2,012		2,262
Total other investments	$	68,263	$	69,094

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Gas Reserves

We entered into an agreement with Encana to develop physical gas reserves that are expected to supply a portion of our utility customers’ requirements over the next 30 years.  The volume of gas produced and allocated to us 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 approximately $250 million.

Upon reviewing the transaction, the OPUC determined that our costs under the agreement will be recovered on an ongoing basis through its annual 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 the agreements referred to above, and we are currently receiving gas from our interests in a section of the gas field.  In 2011, volumes from gas reserves were less than one percent of our total gas purchases.  Our net investment at December 31, 2011 is $36.3 million, including deferred tax liabilities totaling $15.6 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 due to the fact that our interest represents a minor portion of total extraction activities.  We account for our investment in this VIE on the cost basis, and it is included under gas reserves on our balance sheet.  Our maximum loss exposure related to this VIE is limited to our investment balance.

Palomar

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.  PGH is a development stage variable interest entity.

Variable Interest Entity (VIE) Analysis.As of December 31, 2011, we updated our VIE analysis and reconfirmed that we are not the primary beneficiary of PGH’s activities as defined by the authoritative guidance related to consolidations due to the fact that we have a 50 percent share and there are no stipulations that allow disproportionate influence over the entity.  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 at each reporting period, and following updates to our corporate planning assumptions.  When it is determined that a loss in value is other than temporary, a 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 future cash flows. Differing assumptions could affect the timing and amount of a charge recorded in any period.

In 2011, our investment in PGH was reviewed for impairment when Palomar withdrew its original application with the FERC for a proposed natural gas pipeline in Oregon.  At the same time, Palomar informed FERC that it intended to re-file an application 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.

The evaluation of assets related to the west portion of the Palomar pipeline 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.  An evaluation of the assets related to the east portion was also performed in 2011, and a charge of $1.0 million was recorded.  The east segment charge was related to costs that would potentially be outdated and, if so, would need to be redone for the refiled application.  Our remaining investment balance in Palomar was $13.5 million at December 31, 2011, which consists of costs related to the east segment.  We also 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 charge of up to approximately $13.2 million based on the current amount of our equity investment net of cash and working capital at Palomar.  We will continue to monitor and update our impairment analysis as required.

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Investment in Life Insurance Policies

We have invested in key person life insurance contracts to provide an indirect funding vehicle for certain long-term employee and director benefit plan liabilities.  The amount in the above table is reported as cash surrender value, net of policy loans.

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 of 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.  

Certain natural gas purchases from Canadian suppliers are payable in Canadian dollars, including both commodity and demand charges, which expose us to adverse changes in foreign currency rates.  Foreign currency forward contracts are used to hedge the fluctuation in foreign currency exchange rates for our commodity and commodity-related demand charges paid in Canadian dollars.  Foreign currency contracts for commodity costs are purchased on a month-to-month basis because the Canadian cost is priced at the average noon-day exchange rate for each month.  Foreign currency contracts for demand costs have terms ranging up to 12 months.  The gains and losses on the shorter-term currency contracts for commodity costs are recognized immediately in cost of gas.  The gains and losses on the currency contracts for demand charges are not recognized in current income because they are subject to a regulatory deferral tariff and, as such, are recorded as a regulatory asset or liability.  The mark-to-market adjustment at December 31, 2011 was an unrealized loss of $0.2 million.  This unrealized gain is subject to regulatory deferral and, as such, was recorded as a derivative instrument, which is offset by recording a corresponding amount to a regulatory liability account.

Derivative hedge contracts are subject to a hedge effectiveness test to determine the financial statement treatment of each specific derivative.  As of December 31, 2011, all of our derivatives were effective economic hedges and either qualified or were expected to qualify for regulatory deferral or hedge accounting treatment.   The effectiveness test applied to financial derivatives is dependent on the type of derivative and its use. We use the hypothetical derivative method under accounting standards for derivatives and hedging to determine the hedge effectiveness for our interest rate swaps and the dollar offset method for other derivative contracts under accounting standards for derivatives and hedging.  All derivatives were effective as of December 31, 2011.

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The following table reflects the income statement presentation for the unrealized gains and losses from our derivative instruments for the year ended December 31, 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.

	2011								2010
Thousands	Natural gas commodity(1)				Foreign exchange (2)				Natural gas commodity(1)				Foreign exchange (2)
Cost of sales		$	(60,799	)		$	-			$	(52,677	)		$	-
Other comprehensive income (loss)			-				(201	)			-				91
Less:
Amounts deferred to regulatory accounts on balance sheet			60,799				201				52,677				(91	)
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 exchange forward purchase contracts is recorded in other comprehensive income, and reclassified to regulatory deferral accounts on the balance sheet.

No collateral was posted with or by our counterparties as of December 31, 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 $63.5 million at December 31, 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	$	-	$	-	$	2,013	$	9,585	$	45,869
Without Adequate Assurance Calls	$	-	$	-	$	851	$	5,923	$	37,206

As of December 31, 2011 and 2010, we realized net losses of $56.5 million and $61.0 million, respectively, from the settlement of natural gas hedge contracts at maturity, which were recorded as increases 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 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 from counterparties in order for them to meet our minimum credit requirement standards.

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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; instead 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 earnings-at-risk trading limits.  Our credit risk for all outstanding derivatives at December 31, 2011 currently does not extend beyond October 2013.

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.

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 December 31, 2011.  As of December 31, 2011 and 2010, the fair value was a liability of $61.0 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 years ended December 31, 2011 and 2010.

14.           Leases

We lease land, buildings and equipment under agreements that expire in various years through 2095. Rental expense under operating leases was $5.4 million, $5.1 million and $5.3 million for the years ended December 31, 2011, 2010 and 2009, respectively.  The table below reflects the future minimum lease payments due under non-cancelable leases at December 31, 2011.  These commitments relate principally to the lease of our office headquarters, underground gas storage facilities, vehicles and computer equipment.

											Later
Thousands	2012		2013		2014		2015		2016		years		Total
Operating leases	$	4,929	$	4,841	$	5,078	$	5,042	$	5,018	$	24,659	$	49,567
Capital leases		443		313		118		23		-		-		897
Minimum lease payments	$	5,372	$	5,154	$	5,196	$	5,065	$	5,018	$	24,659	$	50,464

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15. Commitments and Contingencies

Gas Purchase and Pipeline Capacity Purchase and Release Commitments

We have signed agreements providing for the reservation of firm pipeline capacity under which we are required to make fixed monthly payments for contracted capacity.  The pricing component of the monthly payment is established, subject to change, by U.S. or Canadian regulatory bodies.  In addition, we have entered into long-term sale agreements to release firm pipeline capacity.  We also enter into short-term and long-term gas purchase agreements.  The aggregate amounts of these agreements were as follows at December 31, 2011:

			Pipeline		Pipeline
	Gas		Capacity		Capacity
	Purchase		Purchase		Release
Thousands	Agreements		Agreements		Agreements
2012	$	98,534	$	91,027	$	3,464
2013		18,331		87,983		-
2014		15,290		82,898		-
2015		5,651		72,316		-
2016		-		61,358		-
Thereafter		-		287,541		-
Total		137,806		683,123		3,464
Less:  Amount representing interest		682		99,252		2
Total at present value	$	137,124	$	583,871	$	3,462

Our total payments for fixed charges under capacity purchase agreements in 2011, 2010 and 2009 were $94.2 million, $91.4 million and $84.6 million, respectively.  Included in the amounts were reductions for capacity release sales of $3.1 million for 2011 and $4.2 million for 2010 and 2009.  In addition, per-unit charges are required to be paid based on the actual quantities shipped under the agreements.  In certain take-or-pay purchase commitments, annual deficiencies may be offset by prepayments subject to recovery over a longer term if future purchases exceed the minimum annual requirements.

Environmental Matters

We own, or previously owned, properties that may require environmental remediation or action.  We recognize an environmental liability when it is probable the liability exists and the amount is reasonably estimable.  We estimate the duration and extent of our remediation obligations based upon reports of outside consultants; internal analyses of clean-up costs and ongoing monitoring costs; communications with regulatory agencies; and changes in environmental law. If we were to determine that our estimates of the duration or extent of our environmental obligations were no longer accurate, we would adjust our environmental liabilities accordingly in the period that such determination is made. Estimated future expenditures for environmental remediation are not discounted to their present value. Accrued environmental liabilities are not reduced by potential insurance reimbursements. 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 which could be material. 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 estimate the range of loss for environmental liabilities using current technology, enacted laws and regulations, industry experience gained at similar sites and an assessment of the probable level of involvement and financial condition of other potentially responsible parties.  Unless there is an estimate within this range of possible losses that is more likely than other cost estimates, we record the liability at the lower end of this range.  It is likely that changes in these estimates and ranges will occur throughout the remediation process for each of these sites due to uncertainty concerning our responsibility, the complexity of environmental laws and regulations and the selection of potentially compliant remediation alternatives.  The status of each of the sites currently under investigation is provided below.

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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.

Gasco site. We own property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 (Gasco site). The Gasco site has been under investigation by us for environmental contamination under the Oregon Department of Environmental Quality’s (ODEQ) Voluntary Clean-Up Program. In June 2003, we filed a Feasibility Scoping Plan and an Ecological and Human Health Risk Assessment with the ODEQ, which outlined a range of compliant remedial alternatives for the most contaminated portion of the Gasco site. In May 2007, we completed a revised Remediation Investigation Report and submitted it to the ODEQ for review.  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 of 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 $12 million at December 31, 2011.  The range of liability will be reassessed when ODEQ makes a final source control design decision, expected later this year.

In addition to groundwater source control, we signed a joint Order on Consent with the Environmental Protection Agency (EPA), which requires us to design remedial action for sediments from the Gasco site. This design project is underway.  We also have other investigation and clean-up work, including potential work on the uplands portion of the Gasco site. For the sediments project and upland work, we have recorded an additional accrued liability of $49.2 million, which reflects the low end of the range of potential liability.  We have accrued at the low end of the range of potential liability for the work at the Gasco site 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.  However, during 2012, we expect EPA to complete a feasibility study that will provide additional cost information about the sediment cleanup work.

Siltronic site.We previously owned property adjacent to the Gasco site that now is the location of a manufacturing plant owned by Siltronic Corporation (Siltronic site). We are currently conducting an investigation of manufactured gas plant wastes on the uplands at this site for the ODEQ.  The liability accrued at December 31, 2011 for the Siltronic site is $1.0 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.

108

Portland Harbor site. In 1998, the ODEQ and the EPA completed a study of sediments in a 5.5-mile segment of the Willamette River (Portland Harbor) that includes an area adjacent to the Gasco and Siltronic sites. The Portland Harbor was listed by the EPA as a Superfund site in 2000 and we were notified that we are a potentially responsible party. We then joined with other potentially responsible parties, referred to as the Lower Willamette Group, to fund environmental studies in the Portland Harbor to allow the EPA to develop a feasibility study. Subsequently, the EPA approved a Programmatic Work Plan, Field Sampling Plan and Quality Assurance Project Plan for the Portland Harbor Remedial Investigation/Feasibility Study (RI/FS), completion of which is scheduled for 2012. The EPA and the Lower Willamette Group are conducting more focused studies on approximately nine miles of the lower Willamette River, including the 5.5-mile segment previously studied by the EPA.  Further, in August 2008, we signed a cooperative agreement with the Portland Harbor Natural Resource Trustee Council to participate in a phased natural resource damage (NRD) assessment.  The NRD assessment is intended to identify additional information necessary to estimate further liabilities to support an early restoration-based settlement of natural resource damage claims.  During 2012, the Lower Willamette Group will submit a draft feasibility study for this site to EPA, resulting in more information regarding the scope of potential costs.  We expect that the feasibility study will allow us to estimate a range of potential liability and that the range may include significant estimates of potential liability.  As of December 31, 2011,  we have a liability accrued of $8.2 million for this site, which is at the low end of the range of the potential liability because no amount within the range is considered to be more likely than another, and the high end of the range cannot reasonably be estimated.

Central Service Center site. In 2006, we received notice from the ODEQ that our Central Service Center in southeast Portland (Central Service Center site) was assigned a high priority for further environmental investigation. Previously there were three manufactured gas storage tanks on the premises. The ODEQ believes there could be site contamination associated with releases of condensate from stored manufactured gas as a result of historic gas handling practices. In the early 1990s, we excavated waste piles and much of the contaminated surface soils and removed accessible waste from some of the abandoned piping. In early 2008, we received notice that this site was added to the ODEQ’s list of sites where releases of hazardous substances have been confirmed and to its list where additional investigation or cleanup is necessary. We are currently performing an environmental investigation of the property with the ODEQ’s Independent Cleanup Pathway.  As of December 31, 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 we could manage the site separately from the Portland Harbor site under ODEQ authority.  We submitted work plans for source control investigation and a historical report to ODEQ and completed initial studies.  In 2010, ODEQ required additional studies which are underway.  As of December 31, 2011, we have an estimated liability accrued of $1.7 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 “Other Legal Proceedings,” below.

109

Accrued Liabilities Relating to Environmental Sites. The following table summarizes the accrued liabilities relating to environmental sites at December 31, 2011 and 2010:

	Current Liabilities				Non-Current Liabilities
Thousands	2011		2010		2011		2010
Gasco site	$	16,510	$	11,366	$	44,697	$	38,921
Siltronic site		887		720		128		201
Portland Harbor site		1,089		2,304		7,066		5,784
Central Service Center site		-		5		495		510
Front Street site		1,697		1		-		1,097
Other sites		-		-		120		108
Total	$	20,183	$	14,396	$	52,506	$	46,621

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 carrying costs 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 carrying cost accrual was extended through January 2012.  We have filed a request with the OPUC to reauthorize this deferral and expect reauthorization during the first half of 2012.  In addition, we filed a request with the 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 20, 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 $124.8 million for environmental costs, including legal, investigation, monitoring and remediation costs, including $4.9 million accrued and paid prior to regulatory deferral order approval. At December 31, 2011, we had a regulatory asset of $105.7 million for deferred environmental costs.

In December 2010, NW Natural commenced litigation against certain of its historical liability insurers in Multnomah County Circuit Court, State of Oregon (see Item 3. Legal Proceedings).  NW Natural seeks damages in excess of $50 million in losses it has incurred to date, as well as declaratory relief for additional losses it expects to incur in the future.  In December 2011, NW Natural reached a settlement with Associated Electric & Gas Insurance Services Limited and dismissed that insurer from the litigation.

Other Legal Proceedings

We are subject to claims and litigation arising in the ordinary course of business. We do not expect that the ultimate disposition of any of these matters, including the matter described below, will have a material effect on our financial condition, results of operations or cash flows.

Oregon Steel Mills site.In 2004, NW Natural was served with a third-party complaint by the Port of Portland (Port) in a Multnomah County Circuit Court case, Oregon Steel Mills, Inc. v. The Port of Portland. The Port alleges that in the 1940s and 1950s petroleum wastes generated by our predecessor, Portland Gas & Coke Company, and 10 other third-party defendants were disposed of in a waste oil disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by Oregon Steel Mills. The complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future remedial action costs. No date has been set for trial. 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.

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NORTHWEST NATURAL GAS COMPANY
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
		Quarter ended
Thousands, except per share amounts		March 31		June 30		Sept. 30			Dec. 31		Total
2011
Operating revenues		$	323,088	$	161,197	$	93,313		$	271,198	$	848,796
Net operating revenues			134,508		67,232		47,783			119,910		369,433
Net income (loss)			40,773		2,193		(8,312	)		29,244		63,898
Basic earnings (loss) per share			1.53		0.08		(0.31	)		1.09		2.39	(1)
Diluted earnings (loss) per share			1.53		0.08		(0.31	)		1.09		2.39	(1)
2010
Operating revenues		$	286,529	$	162,365	$	95,067		$	268,145	$	812,106
Net operating revenues			130,926		72,193		46,211			118,251		367,581
Net income (loss)			43,608		6,888		(7,420	)		29,591		72,667
Basic earnings (loss) per share			1.64		0.26		(0.28	)		1.11		2.73	(1)
Diluted earnings (loss) per share			1.64		0.26		(0.28	)		1.11		2.73	(1)
(1)	Quarterly earnings (loss) per share are based upon the average number of common shares outstanding during each quarter. Because the average number of shares outstanding has changed in each quarter shown, the sum of quarterly earnings (loss) per share may not equal earnings per share for the year. Variations in earnings between quarterly periods are due primarily to the seasonal nature of our business.

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NORTHWEST NATURAL GAS COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
COLUMN A	COLUMN B			COLUMN C						COLUMN D			COLUMN E
				Additions						Deductions
	Balance at			Charged to			Charged to						Balance at
	beginning			costs and			other			Net			end of
Thousands (year ended Dec. 31)	of period			expenses			accounts			Write-offs			period
2011
Reserves deducted in balance sheet from assets to which they apply:
Allowance for uncollectible accounts		$	2,950		$	1,919		$	-		$	1,974		$	2,895
2010
Reserves deducted in balance sheet from assets to which they apply:
Allowance for uncollectible accounts		$	3,125		$	1,717		$	-		$	1,892		$	2,950
2009
Reserves deducted in balance sheet from assets to which they apply:
Allowance for uncollectible accounts		$	2,927		$	4,201		$	-		$	4,003		$	3,125

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Item 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 9A.                        CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

Our management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has completed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)).  Based upon this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us and included in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

(b) Changes in Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in the Exchange Act Rule 13a-15(f).

There have been no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.  The statements contained in Exhibit 31.1 and Exhibit 31.2 should be considered in light of, and read together with, the information set forth in this Item 9(a).

Item 9B.                        OTHER INFORMATION

None.

113

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information concerning our Board of Directors, its Committees and the Audit Committee financial expert contained in NW Natural’s definitive Proxy Statement for the May 24, 2012 Annual Meeting of Shareholders is hereby incorporated by reference.  The information concerning “Section 16(a) Beneficial Ownership Reporting Compliance” and “Corporate Governance” contained in our definitive Proxy Statement for the May 24, 2012 Annual Meeting of Shareholders is hereby incorporated by reference.

	Age at
Name	Dec. 31, 2011		Positions held during last five years
Gregg S. Kantor		54	President and Chief Executive Officer (2009-   ); President and Chief Operating Officer (2007 - 2008); Executive Vice President (2006 -2007); Senior Vice President, Public and Regulatory Affairs (2003-2006).
David H. Anderson		50	Senior Vice President and Chief Financial Officer (2004-  ).
Margaret D. Kirkpatrick		57	Vice President and General Counsel (2005-  ); Partner in the law firm of Stoel Rives LLP (1991- 2005).
Lea Anne Doolittle		56	Senior Vice President (2008-   ); Vice President, Human Resources (2000-2007).
J. Keith White		58	Vice President, Business Development and Energy Supply/Chief Strategic Officer (2007-  ); Managing Director, Gas Operations and Wholesale Services (2005-2006); Managing Director and Chief Strategic Officer (2003-2005).
David R. Williams		58	Vice President, Utility Services (2007-  ); Director of Utility Operations, Districts and managed Labor Relations (2004-2006).
Grant M. Yoshihara		56	Vice President, Utility Operations (2007-   ); Managing Director, Utility Services (2005-2006); Director, Utility Services (2004-2005).
C. Alex Miller		54	Vice President, Finance and Regulation (2009-  ); Assistant Treasurer (2008-  ); General Manager of Rates and Regulatory Affairs (2002-2009).
Stephen P. Feltz		56	Assistant Secretary (2007- ); Treasurer and Controller (1999-  ).
MardiLyn Saathoff		55	Deputy General Counsel (2010- ); Chief Governance Officer and Corporate Secretary (2008-  ); Chief Compliance Officer and Assistant General Counsel, Tektronix, Inc. (2005-2008); General Counsel to Oregon Governor Kulongoski and Business and Economic Development Advisor (2003-2005).
David A. Weber		52	President and Chief Executive Officer, NW Natural Gas Storage, LLC and Gill Ranch Storage, LLC (2012 -);  Interim President and Chief Executive Officer, NW Natural Gas Storage LLC, and Gill Ranch Storage, LLC (2011-2012); Chief Operating Officer NW Natural Gas Storage, LLC and Gill Ranch Storage LLC (November 2010 - January 2011); Managing Director of Information Services and Chief Information Officer (2005 - 2011); Director of Information Services and Chief Information Officer (2001-2005).

     Each executive officer serves successive annual terms; present terms end on May 24, 2012. There are no family relationships among our executive officers, directors or any person chosen to become one of our officers or directors.

NW Natural has adopted a Code of Ethics (Code) applicable to all employees and officers that is available on our website at www.nwnatural.com.  We intend to disclose on our website at www.nwnatural.com any amendments to the Code or waivers of the Code for executive officers.

114

ITEM 11.                      EXECUTIVE COMPENSATION

The information concerning “Executive Compensation” and “Report of the Organization and Executive Compensation Committee” contained in our definitive Proxy Statement for the May 24, 2012 Annual Meeting of Shareholders is hereby incorporated by reference.  Information related to Executive Officers as of December 31, 2011 is reflected in Part III, Item 10, above.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth information regarding compensation plans under which equity securities of NW Natural are authorized for issuance as of December 31, 2011 (see Note 6 to the Consolidated Financial Statements):

	(a)		(b)		(c)
Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders:
Long-Term Incentive Plan (LTIP) (Target Award)(1)		118,617		n/a		337,788
Restated Stock Option Plan		579,225	$	42.09		580,650
Employee Stock Purchase Plan		19,917	$	39.72		136,038
Equity compensation plans not approved by security holders:
Executive Deferred Compensation Plan (EDCP)(2)		3,723		n/a		n/a
Directors Deferred Compensation Plan (DDCP)(2)		62,831		n/a		n/a
Deferred Compensation Plan for Directors and Executives (DCP)(3)		120,028		n/a		n/a
Total		904,341				1,054,476

115

The information captioned “Beneficial Ownership of Common Stock by Directors and Executive Officers” contained in our definitive Proxy Statement for the May 24, 2012 Annual Meeting of Shareholders is incorporated herein by reference.

(1)   Shares issued pursuant to the LTIP do not include an exercise price, but are payable when the award criteria are satisfied.  If the maximum awards were paid pursuant to the performance-based awards outstanding at December 31, 2011, the number of shares shown in column (a) would increase by 118,617 shares and the number of shares shown in column (c) would decrease by the same amount of shares.

(2)   Prior to January 1, 2005, deferred amounts were credited, at the participant’s election, to either a “cash account” or a “stock account.”  If deferred amounts were credited to stock accounts, such accounts were credited with a number of shares of NW Natural common stock based on the purchase price of the common stock on the next purchase date under our Dividend Reinvestment and Direct Stock Purchase Plan, and such accounts were credited with additional shares based on the deemed reinvestment of dividends.  Cash accounts are credited quarterly with interest at a rate equal to Moody’s Average Corporate Bond Yield plus two percentage points, subject to a six percent minimum rate.  At the election of the participant, deferred balances in the stock accounts are payable after termination of Board service or employment in a lump sum, in installments over a period not to exceed 10 years in the case of the DDCP, or 15 years in the case of the EDCP, or in a combination of lump sum and installments.  We have contributed common stock to the trustee of the Umbrella Trusts such that the Umbrella Trusts hold approximately the number of shares of common stock equal to the number of shares credited to all participants’ stock accounts.

(3)   Effective January 1, 2005, the EDCP and DDCP were closed to new participants and replaced with the DCP.  The DCP continues the basic provisions of the EDCP and DDCP under which deferred amounts are credited to either a “cash account” or a “stock account.”  Stock accounts represent a right to receive shares of NW Natural common stock on a deferred basis, and such accounts are credited with additional shares based on the deemed reinvestment of dividends. Effective January 1, 2007, cash accounts are credited quarterly with interest at a rate equal to Moody’s Average Corporate Bond Yield.  Our obligation to pay deferred compensation in accordance with the terms of the DCP will generally become due on retirement, death, or other termination of service, and will be paid in a lump sum or in installments of five or 10 years as elected by the participant in accordance with the terms of the DCP. We have contributed common stock to the trustee of the Supplemental Trust such that this trust holds approximately the number of common shares equal to the number of shares credited to all participants stock accounts.   The right of each participant in the DCP is that of a general, unsecured creditor of the Company.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information captioned “Transactions with Related Persons” and “Corporate Governance” in the Company’s definitive Proxy Statement for the May 24, 2012 Annual Meeting of Shareholders is hereby incorporated by reference.

ITEM 14.                PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information captioned “2011 and 2010 Audit Firm Fees” in the Company’s definitive Proxy Statement for the May 24, 2012 Annual Meeting of Shareholders is hereby incorporated by reference.

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PART IV

ITEM 15.                EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)   The following documents are filed as part of this report:

1.   A list of all Financial Statements and Supplemental Schedules is incorporated by reference to Item 8.

2.   List of Exhibits filed:

Reference is made to the Exhibit Index commencing on page 120.

117

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

NORTHWEST NATURAL GAS COMPANY

Date:  February 28, 2012                                                                By:    /s/ Gregg S. Kantor            

Gregg S. Kantor

President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

SIGNATURE	TITLE		DATE
/s/ Gregg S. Kantor	Principal Executive Officer and Director		February 28, 2012
Gregg S. Kantor
President and Chief Executive Officer
/s/ David H. Anderson	Principal Financial Officer		February 28, 2012
David H. Anderson
Senior Vice President and Chief Financial Officer
/s/ Stephen P. Feltz	Principal Accounting Officer		February 28, 2012
Stephen P. Feltz
Treasurer and Controller
/s/ Timothy P. Boyle	Director )
Timothy P. Boyle		)
		)
/s/Martha L. Byorum	Director   )
Martha L. Byorum		)
		)
/s/ John D. Carter	Director   )
John D. Carter		)
		)
/s/ Mark S. Dodson	Director   )
Mark S. Dodson		)
		)
/s/ C. Scott Gibson	Director   )
C. Scott Gibson		)
		)	February 28, 2012
/s/ Tod R. Hamachek	Director   )
Tod R. Hamachek		)
		)
/s/ Jane L. Peverett	Director   )
Jane L. Peverett		)
		)
/s/ George J. Puentes	Director   )
George J. Puentes		)
		)
/s/ Kenneth Thrasher	Director   )
Kenneth Thrasher		)
		)
/s/ Russell F. Tromley	Director   )
Russell F. Tromley		)

118

NORTHWEST NATURAL GAS COMPANY

EXHIBIT INDEX

To

Annual Report on Form 10-K

For Fiscal Year Ended

December 31, 2011

Exhibit Number                                                        Document

*3a.	Restated Articles of Incorporation, as filed and effective May 31, 2006 and amended June 3, 2008 (incorporated herein by reference to Exhibit 3a. to Form 10-K for 2006, File No. 1-15973).
*3b.	Bylaws as amended May 24, 2007 (incorporated herein by reference to Exhibit 3.1 to Form 8-K dated May 29, 2007, File No. 1-15973).
*4a.	Copy of Mortgage and Deed of Trust, dated as of July 1, 1946, to Bankers Trust and R. G. Page (to whom Stanley Burg is now successor), Trustees (incorporated herein by reference to Exhibit 7(j) in File No. 2-6494); and copies of Supplemental Indentures Nos. 1 through 14 to the Mortgage and Deed of Trust, dated respectively, as of June 1, 1949, March 1, 1954, April 1, 1956, February 1, 1959, July 1, 1961, January 1, 1964, March 1, 1966, December 1, 1969, April 1, 1971, January 1, 1975, December 1, 1975, July 1, 1981, June 1, 1985 and November 1, 1985 (incorporated herein by reference to Exhibit 4(d) in File No. 33-1929); Supplemental Indenture No. 15 to the Mortgage and Deed of Trust, dated as of July 1, 1986 (filed as Exhibit 4(c) in File No. 33-24168); Supplemental Indentures Nos. 16, 17 and 18 to the Mortgage and Deed of Trust, dated, respectively, as of November 1, 1988, October 1, 1989 and July 1, 1990 (incorporated herein by reference to Exhibit 4(c) in File No. 33-40482); Supplemental Indenture No. 19 to the Mortgage and Deed of Trust, dated as of June 1, 1991 (incorporated herein by reference to Exhibit 4(c) in File No. 33-64014); and Supplemental Indenture No. 20 to the Mortgage and Deed of Trust, dated as of June 1, 1993 (incorporated herein by reference to Exhibit 4(c) in File No. 33-53795).
*4b.	Copy of Indenture, dated as of June 1, 1991, between the Company and Bankers Trust Company, Trustee, relating to the Company’s Unsecured Medium-Term Notes (incorporated herein by reference to Exhibit 4(e) in File No. 33-64014).
*4c.	Officers’ Certificate dated June 12, 1991 creating Series A of the Company’s Unsecured Medium-Term Notes (incorporated herein by reference to Exhibit 4e. to Form 10-K for 1993, File No. 0-994).
*4d.	Officers’ Certificate dated June 18, 1993 creating Series B of the Company’s Unsecured Medium-Term Notes (incorporated herein by reference to Exhibit 4f. to Form 10-K for 1993, File No. 0-994).
*4e.	Officers’ Certificate dated January 17, 2003 relating to Series B of the Company’s Unsecured Medium-Term Notes and supplementing the Officers’ Certificate dated June 18, 1993 (incorporated herein by reference to Exhibit 4f.(1) to Form 10-K for 2002, File No. 0-994).

*4f.	Form of Credit Agreement between Northwest Natural Gas Company and the banks that are party thereto, with JPMorgan Chase Bank, N.A., as administrative agent and Bank of America, N.A., as syndication agent, dated as of May 31, 2007, including Form of Note (incorporated herein by reference to Exhibit 4 to Form 10-Q dated November 5, 2010, File No. 1-15973).
*4g.	Form of Letter Agreement, between each of JPMorgan Chase Bank, N.A., Bank of America, N.A., U.S. Bank National Association, UBS Loan Finance LLC, Wells Fargo Bank, N.A., Merrill Lynch Bank USA, dated as of April 29, 2008, extending the Credit Agreement between Northwest Natural Gas Company and each financial institution with JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to Exhibit 4i.(1) to Form 10-K for 2008, File No. 1-15973).
*4h.	Form of Secured Medium-Term Notes, Series B (incorporated herein by reference to Exhibit 4.1 to Form 8-K dated October 4, 2004, File No. 1-15973).
*4i.	Letter Agreement among the Company, JPMorgan Chase Bank, N.A., Bank of America, N.A., U.S. Bank National Association, Wachovia Bank, National Association, Wells Fargo Bank, N.A., Bank of America, N.A., Successor by merger to Merrill Lynch Bank USA, and UBS Loan Finance LLC, dated October 29, 2009 (incorporated herein by reference to Exhibit 4i. to Form 10-K for 2009, File No. 1-15973).
*4j.	Distribution Agreement, dated March 18, 2009, among Banc of America Securities LLC, UBS Securities LLC, J.P. Morgan Securities Inc., and Piper Jaffray and Co. (Incorporated herein by reference to Exhibit 1.1 to Form 8-K dated March 23, 2009, File No. 1-15973).
*4k.	Form of Letter Agreement, dated August 24, 2009, among Banc of America Securities, LLC, UBS Securities LLC, J.P. Morgan Securities Inc., Piper Jaffray & Co. and Wells Fargo Securities, LLC (incorporated herein by reference to Exhibit 4k. to Form 10-K for 2009, File No. 1-15973).
*4l.	Form of Unsecured Medium-Term Notes, Series B (incorporated herein by reference to Exhibit 4.2 to Form 8-K dated October 4, 2004, File No. 1-15973).
4m.	Gill Ranch Note Purchase Agreement, dated November 30, 2011, among Gill Ranch Storage, LLC and the parties listed thereto.
12	Statement re computation of ratios of earnings to fixed charges.
21	Subsidiaries of Northwest Natural Gas Company.
23	Consent of PricewaterhouseCoopers LLP.
31.1	Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Principal Executive Officer and Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Executive Compensation Plans and Arrangements:
*10b.	Executive Supplemental Retirement Income Plan 2010 Restatement (incorporated herein by reference to Exhibit 10b. to Form 10-K for 2009, File No. 1-15973).
*10c.	Supplemental Executive Retirement Plan, effective September 1, 2004 restated 2011 (incorporated herein by reference to Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2011, File No. 1-15973).
*10d.	Northwest Natural Gas Company Supplemental Trust, effective January 1, 2005, restated as of December 15, 2005 (incorporated herein by reference to Exhibit 10.7 to Form 8-K dated December 16, 2005, File No. 1-15973).
*10e.	Northwest Natural Gas Company Umbrella Trust for Directors, effective January 1, 1991, restated as of December 15, 2005 (incorporated herein by reference to Exhibit 10.5 to Form 8-K dated December 16, 2005, File No. 1-15973).
*10f.	Northwest Natural Gas Company Umbrella Trust for Executives, effective January 1, 1988, restated as of December 15, 2005 (incorporated herein by reference to Exhibit 10.6 to Form 8-K dated December 16, 2005, File No. 1-15973).
*10g.	Restated Stock Option Plan, as amended effective December 14, 2006 (incorporated herein by reference to Exhibit 10c. to Form 10-K for 2006, File No. 1-15973).
*10h.	Form of Restated Stock Option Plan Agreement (incorporated herein by reference to Exhibit 10h. to Form 10-K for 2009, File No. 1-15973).
*10i.	Executive Deferred Compensation Plan, effective as of January 1, 1987, restated as of February 26, 2009 (incorporated herein by reference to Exhibit 10(e). to Form 10-K for 2008, File No. 1-15973).
*10j.	Directors Deferred Compensation Plan, effective June 1, 1981, restated as of February 26, 2009 (incorporated herein by reference to Exhibit 10(f). to Form 10-K for 2008, File No. 1-15973).
10k.	Deferred Compensation Plan for Directors and Executives effective January 1, 2005, restated as of January 1, 2012.
*10l.	Form of Indemnity Agreement as entered into between the Company and each director and certain executive officers (incorporated herein by reference to Exhibit 10l. to Form 10-K for 2009, File No. 1-15973).
*10l.(1)	Form of Indemnity Agreement as entered into between the Company and certain executive officers (incorporated herein by reference to Exhibit 10l.(1) to Form 10-K for 2009, File No. 1-15973).
*10m.	Non-Employee Directors Stock Compensation Plan, as amended effective December 15, 2005 (incorporated herein by reference to Exhibit 10.2 to Form 8-K dated December 16, 2005, File No. 1-15973).
10n.	Executive Annual Incentive Plan, effective February 23, 2012.
*10o.	Form of Agreement to Recoupment Provisions of Executive Annual Incentive Plan, effective as of January 1, 2010 (incorporated herein by reference to Exhibit 10o. to Form 10-K for 2009, File No. 1-15973).
*10p.	Form of Change in Control Severance Agreement between the Company and each executive officer (incorporated herein by reference to Exhibit 10o. to Form 10-K for 2008, File No. 1-15973).
*10q.	Severance agreement dated December 19, 2008 between the Company and Gregg S. Kantor (incorporated herein by reference to Exhibit 10.1 to Form 8-K dated December 23, 2008, File No. 1-15973).
*10r.	Northwest Natural Gas Company Long-Term Incentive Plan, as amended and restated effective December 15, 2011 (incorporated herein by reference to Exhibit 10.2 to Form 8-K dated December 14, 2011, File No. 1-15973).
10s.	Form of Long-Term Incentive Award Agreement under the Long-Term Incentive Plan.
10t.	Form of Long-Term Incentive Award Agreement under the Long-Term Incentive Plan.
10u.	Form of Long-Term Incentive Award Agreement under the Long-Term Incentive Plan.
10v.	Form of Long-Term Incentive Award Agreement under the Long-Term Incentive Plan.
*10w.	Form of Restricted Stock Bonus Agreement under the Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.9 to Form 8-K dated December 16, 2005, File No. 1-15973).
*10x.	Form of Consent dated December 14, 2006 entered into by each executive officer (incorporated herein by reference to Exhibit 10.1 to Form 8-K dated December 19, 2006, File No. 1-15973).
*10y.	Consent to Amendment of Deferred Compensation Plan for Directors and Executives, dated February 28, 2008 entered into by each executive officer (incorporated herein by reference to Exhibit 10bb to Form 10-K for 2007, File No. 1-15973).
*10z.	Form of Long-Term Incentive Award Agreement under the Long-Term Incentive Plan relating to a special award to an executive officer (incorporated herein by reference to Exhibit 10z. to Form 10-K for 2009, File No. 1-15973).
*10bb.	Form of Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to Form 8-K dated December 14, 2011, File No. 1-15973).
101.	**The following materials from Northwest Natural Gas Company Annual Report on Form 10-K for the fiscal year ended December 31, 2011, formatted in Extensible Business Reporting Language (XBRL): (i)Consolidated Statements of Income; (ii)Consolidated Balance Sheets; (iii)Consolidated Statements of Cash Flows; and (iv)Related notes.

** In accordance with Rule 406T of Regulation S-T, the XBRL-related information in Exhibit 101 to this Annual Report on Form 10-K is deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act, is deemed not filed for purposes of Section 18 of the Exchange Act and otherwise is not subject to liability under these sections

____________________________________________

*Incorporated herein by reference as indicated

119

EX-4.M

EXECUTION COPY

GILL RANCH STORAGE, LLC

$20,000,000

7.75% Senior Secured Notes due November 30, 2016

$20,000,000

Floating-Rate Senior Secured Notes due November 30, 2016

______________

NOTE PURCHASE AGREEMENT

______________

Dated November 30, 2011

See Section 17.1 for additional condition relating to joinder of Parent for amendments to this document.

HOU03:1282704

TABLE OF CONTENTS

SECTION                                                             HEADING PAGE

SECTION 1. AUTHORIZATION OF NOTES. 

SECTION 2. SALE AND PURCHASE OF NOTES. 

SECTION 3. CLOSING. 

SECTION 4. CONDITIONS TO CLOSING. 

Section 4.1.                      Representations and Warranties. 

Section 4.2.                      Performance; No Default.

Section 4.3.                      Officer’s Certificates. 

Section 4.4.                      Opinions of Counsel. 

Section 4.5.                      Purchase Permitted By Applicable Law, Etc. 

Section 4.6.                      Sale of Other Notes. 

Section 4.7.                      Payment of Special Counsel and Other Fees and Expenses. 

Section 4.8.                      Private Placement Number. 

Section 4.9.                      Changes in Corporate Structure. 

Section 4.10.                      Funding Instructions. 

Section 4.11.                      Proceedings and Certain Documents. 

Section 4.12.                      Security Agreement and other Security Documents. 

Section 4.13.                      Debt Service Reserve Account. 

Section 4.14.                      Insurance. 

Section 4.15.                      Financial Statements. 

Section 4.16.                      No Material Adverse Effect. 

SECTION 5. REPRESENTATIONS AND WARRANTIES OF THE COMPANY. 

Section 5.1.                      Organization; Power and Authority. 

Section 5.2.                      Authorization, Etc. 

Section 5.3.                      Disclosure. 

Section 5.4.                      Affiliates; Directors; No Subsidiaries. 

Section 5.5.                      Financial Statements; Material Liabilities.

Section 5.6.                      Compliance with Laws, Other Instruments, Etc. 

Section 5.7.                      Governmental Authorizations, Etc. 

Section 5.8.                      Litigation; Observance of Agreements, Statutes and Orders. 

Section 5.9.                      Taxes. 

Section 5.10.                      Title to Property; Leases.

Section 5.11.                      Licenses, Permits, Etc. 

Section 5.12.                      Compliance with ERISA. 

Section 5.13.                      Private Offering by the Company. 

Section 5.14.                      Use of Proceeds; Margin Regulations. 

Section 5.15.                      Existing Indebtedness; Future Liens. 

Section 5.16.                      Foreign Assets Control Regulations, Etc. 

Section 5.17.                      Status under Certain Statutes. 

Section 5.18.                      Environmental Matters. 

Section 5.19.                      Project Documents. 

SECTION 6. REPRESENTATIONS OF THE PURCHASERS. 

Section 6.1.                      Purchase for Investment. 

Section 6.2.                      Source of Funds. 

SECTION 7. INFORMATION AS TO COMPANY. 

Section 7.1.                      Financial and Business Information. 

Section 7.2.                      Officer’s Certificate. 

Section 7.3.                      Visitation. 

SECTION 8. PAYMENT AND PREPAYMENT OF THE NOTES; FLOATING RATE PROVISIONS. 

Section 8.1.                      Maturity. 

Section 8.2.                      Optional Prepayments. 

Section 8.3.                      Offer to Prepay Notes in the Event of a Change in Control. 

Section 8.4.                      Allocation of Partial Prepayments. 

Section 8.5.                      Maturity; Surrender, Etc. 

Section 8.6.                      Purchase of Notes. 

Section 8.7.                      Make-Whole Amount. 

Section 8.8.                      Additional Floating Rate Provisions. 

SECTION 9. AFFIRMATIVE COVENANTS. 

Section 9.1.                      Compliance with Laws. 

Section 9.2.                      Insurance. 

Section 9.3.                      Maintenance of Properties. 

Section 9.4.                      Payment of Taxes and Claims. 

Section 9.5.                      Existence. 

Section 9.6.                      Books and Records. 

Section 9.7.                      Environmental Matters. 

Section 9.8.                      Further Assurances. 

Section 9.9.                      Project Documents. 

Section 9.10.                      Debt Service Reserve Account. 

Section 9.11.                      Covenant to Secure Notes Equally.

SECTION 10. NEGATIVE COVENANTS. 

Section 10.1.                      Financial Covenants. 

Section 10.2.                      Restricted Payments. 

Section 10.3.                      Liens. 

Section 10.4.                      Sale of Assets, Etc. 

Section 10.5.                      Merger, Consolidation, Etc. 

Section 10.6.                      Loans, Advances, Investments and Contingent Liabilities. 

Section 10.7.                      Sale-and-Leasebacks. 

Section 10.8.                      Sale or Discount of Receivables. 

Section 10.9.                      Transactions with Affiliates. 

Section 10.10.                                                                                                                                       Line of Business.

Section 10.11.                                                                                                                                       Subsidiaries.

Section 10.12.                                                                                                                                       Terrorism Sanctions Regulations.

Section 10.13.                                                                                                                                       Most Favored Lender Status.

Section 10.14.                                                                                                                                       Restrictions on Amendments to Certain Agreements.

SECTION 11. EVENTS OF DEFAULT. 

SECTION 12. REMEDIES ON DEFAULT, ETC. 

Section 12.1.                      Acceleration. 

Section 12.2.                      Other Remedies. 

Section 12.3.                      Rescission.

Section 12.4.                      No Waivers or Election of Remedies, Expenses, Etc.

SECTION 13. REGISTRATION; EXCHANGE; SUBSTITUTION OF NOTES. 

Section 13.1.                      Registration of Notes. 

Section 13.2.                      Transfer and Exchange of Notes.

Section 13.3.                      Replacement of Notes.

SECTION 14. PAYMENTS ON NOTES. 

Section 14.1.                      Place of Payment. 

Section 14.2.                      Home Office Payment.

SECTION 15. EXPENSES, ETC. 

Section 15.1.                      Transaction Expenses. 

Section 15.2.                      Indemnification.

Section 15.3.                      Survival.

SECTION 16. SURVIVAL OF REPRESENTATIONS AND WARRANTIES; ENTIRE AGREEMENT. 

SECTION 17. AMENDMENT AND WAIVER. 

Section 17.1.                      Requirements.

Section 17.2.                      Solicitation of Holders of Notes.

Section 17.3.                      Binding Effect, etc.

Section 17.4.                      Notes Held by Company, etc.

Section 17.5.                      Expansion of the Facility.

SECTION 18. NOTICES. 

SECTION 19. REPRODUCTION OF DOCUMENTS. 

SECTION 20. CONFIDENTIAL INFORMATION. 

SECTION 21. SUBSTITUTION OF PURCHASER. 

SECTION 22. MISCELLANEOUS. 

Section 22.1.                      Successors and Assigns.

Section 22.2.                      Payments Due on Non-Business Days. 

Section 22.3.                      Accounting Terms.

Section 22.4.                      Severability.

Section 22.5.                      Construction, etc.

Section 22.6.                      Counterparts.

Section 22.7.                      Governing Law.

Section 22.8.                      Jurisdiction and Process; Waiver of Jury Trial.

Section 22.9.                      Transaction References.

HOU03:1282704                                                                     

SCHEDULE A-1                       —           INFORMATION RELATING TO PURCHASERS

SCHEDULE A-2                       —           INFORMATION RELATING TO COMPANY

SCHEDULE B                           —           DEFINED TERMS

SCHEDULE 5.3                         —           Disclosure Materials

SCHEDULE 5.4                         —           Affiliates of the Company; Directors

SCHEDULE 5.5                                —           Financial Statements

SCHEDULE 5.11                                —           Licenses, Permits, Etc.

SCHEDULE 5.15                                —           Existing Indebtedness

SCHEDULE 5.19                                —           Material Customer Contracts

SCHEDULE 10.9                                —           Existing Affiliate Contracts

EXHIBIT A-1                                           —           Form of 7.75% Senior Secured Note due November 30, 2016

EXHIBIT A-2                                           —           Form of Floating-Rate Senior Secured Note due November 30,2016

EXHIBIT 4.4(a)                                           Composite Form of Opinion of Counsel for the Company

EXHIBIT B                                —           Form of Security Agreement

EXHIBIT C                                —           Form of Control Agreement

EXHIBIT D                                —           Form of Collateral Agency Agreement

EXHIBIT E                                —           Form of Pledge Agreement

HOU03:1282704                                                                     

GILL RANCH STORAGE, LLC

220 NW Second Avenue

Portland, OR 87209

$20,000,000 7.75% Senior Secured Notes due November 30, 2016

$20,000,000 Floating-Rate Senior Secured Notes due November 30, 2016

November 30, 2011

TO EACH OF THE PURCHASERS LISTED IN

SCHEDULE A-1 HERETO:

Ladies and Gentlemen:

Gill Ranch Storage, LLC, an Oregon limited liability company (the “Company”), agrees with each of the purchasers whose names appear at the end hereof (each, a “Purchaser” and, collectively, the “Purchasers”) as follows:

SECTION 1.   AUTHORIZATION OF NOTES.

The Company will authorize the issue and sale of (a) $20,000,000 aggregate principal amount of its 7.75% Senior Secured Notes due November 30, 2016 (the “Fixed-Rate Notes”,such term to include any such notes issued in substitution therefor pursuant to Section 13) and (b) $20,000,000 aggregate principal amount of its Floating-Rate Senior Secured Notes due November 30, 2016 (the “Floating-Rate Notes”,such term to include any such notes issued in substitution therefor pursuant to Section 13) and together with the Fixed Rate Notes, the “Notes”).  The Fixed-Rate Notes shall be substantially in the form set out in Exhibit A-1.  The Floating-Rate Notes shall be substantially in the form set out in Exhibit A-2.  Certain capitalized and other terms used in this Agreement are defined in Schedule B; and references to a “Schedule” or an “Exhibit” are, unless otherwise specified, to a Schedule or an Exhibit attached to this Agreement.

SECTION 2.   SALE AND PURCHASE OF NOTES.

Subject to the terms and conditions of this Agreement, the Company will issue and sell to each Purchaser and each Purchaser will purchase from the Company, at the Closing provided for in Section 3, Fixed-Rate Notes in the principal amount specified opposite such Purchaser’s name in Schedule A-1 and Floating-Rate Notes in the principal amount specified opposite such Purchaser’s name in Schedule A-1, in each case at the purchase price of 100% of the principal amount thereof.  The Purchasers’ obligations hereunder are several and not joint obligations, and no Purchaser shall have any liability to any Person for the performance or non-performance of any obligation by any other Purchaser hereunder.

SECTION 3.   CLOSING.

The sale and purchase of the Notes to be purchased by each Purchaser shall occur at the offices of Baker Botts L.L.P., 2001 Ross Avenue, Dallas, Texas 75201, at 10:00 a.m., Central time, at a closing (the “Closing”) on November 30, 2011 or on such other Business Day thereafter on or prior to December 14, 2011 as may be agreed upon by the Company and the Purchasers.  At the Closing the Company will deliver to each Purchaser the Notes to be purchased by such Purchaser in the form of a single Note (or such greater number of Notes in denominations of at least $100,000 as such Purchaser may request) dated the date of the Closing and registered in such Purchaser’s name (or in the name of its nominee), against delivery by such Purchaser to the Company or its order of immediately available funds in the amount of the purchase price therefor by wire transfer of immediately available funds for the account of the Company to the account set forth on attached Schedule A-2.  If at the Closing the Company shall fail to tender such Notes to any Purchaser as provided above in this Section 3, or any of the conditions specified in Section 4 shall not have been fulfilled to such Purchaser’s satisfaction, such Purchaser shall, at its election, be relieved of all further obligations under this Agreement, without thereby waiving any rights such Purchaser may have by reason of such failure or such non-fulfillment.

SECTION 4.   CONDITIONS TO CLOSING.

Each Purchaser’s obligation to purchase and pay for the Notes to be sold to such Purchaser at the Closing is subject to the fulfillment to such Purchaser’s satisfaction, prior to or at the Closing, of the following conditions:

Section 4.1.Representations and Warranties.  The representations and warranties of the Company and the Parent in the Financing Documents shall be correct when made and at the time of the Closing.

Section 4.2.Performance; No Default.  The Company shall have performed and complied with all agreements and conditions contained in this Agreement required to be performed or complied with by it prior to or at the Closing, and after giving effect to the issue and sale of the Notes (and the application of the proceeds thereof as contemplated by Section 5.14), no Default or Event of Default shall have occurred and be continuing.  The Company shall not have entered into any transaction since September 30, 2011 that would have been prohibited by Sections 10.1 through 10.14 had such Sections applied since such date.

Section 4.3.Officer’s Certificates.

(a)The Company shall have delivered to such Purchaser an Officer’s Certificate, dated the date of the Closing, certifying that the conditions specified in Sections 4.1, 4.2 and 4.9 have been fulfilled as to the Company.

(b)The Parent shall have delivered to such Purchaser an Officer’s Certificate, dated the date of the Closing, certifying that the conditions specified in Sections 4.1 and 4.9 have been fulfilled as to the Parent.

Section 4.4.Opinions of Counsel.  Such Purchaser shall have received an opinion, in form and substance satisfactory to such Purchaser, dated the date of the Closing, (a) from Stoel Rives LLP, counsel for the Company and the Parent, covering the matters set forth in Exhibit 4.4(a) and covering such other matters incident to the transactions contemplated hereby as such Purchaser or its counsel may reasonably request (and the Company hereby instructs its counsel to deliver such opinion to the Purchasers), and (b) from Baker Botts L.L.P., the Purchasers’ special counsel in connection with such transactions, covering such matters incident to such transactions as such Purchaser may reasonably request.

Section 4.5.Purchase Permitted By Applicable Law, Etc.  On the date of the Closing such Purchaser’s purchase of Notes shall (a) be permitted by the laws and regulations of each jurisdiction to which such Purchaser is subject, without recourse to provisions (such as section 1405(a)(8) of the New York Insurance Law) permitting limited investments by insurance companies without restriction as to the character of the particular investment, (b) not violate any applicable law or regulation (including, without limitation, Regulation T, U or X of the Board of Governors of the Federal Reserve System) and (c) not subject such Purchaser to any tax, penalty or liability under or pursuant to any applicable law or regulation, which law or regulation was not in effect on the date hereof.  If requested by such Purchaser, such Purchaser shall have received an Officer’s Certificate certifying as to such matters of fact as such Purchaser may reasonably specify to enable such Purchaser to determine whether such purchase is so permitted.

Section 4.6.Sale of Other Notes.  Contemporaneously with the Closing the Company shall sell to each other Purchaser and each other Purchaser shall purchase the Notes to be purchased by it at the Closing as specified in Schedule A-1.

Section 4.7.Payment of Special Counsel and Other Fees and Expenses.  Without limiting the provisions of Section 15.1, the Company shall have paid on or before the Closing (a) the fees, charges and disbursements of the Purchasers’ special counsel referred to in Section 4.4 and local counsel to the extent reflected in a statement of such counsel rendered to the Company at least one Business Day prior to the Closing; and (b) the structuring fee equal to 0.75% of the aggregate principal amount of Notes sold to the Purchasers on the Closing Date, ratably to the Purchasers, and reasonable out-of-pocket costs and expenses, and other compensation contemplated hereby or by the other Financing Documents, or pursuant to separate letter agreements, payable to or for the benefit of the Purchasers or the Collateral Agent on or before Closing, in each case, to the extent reflected in a statement rendered to the Company at least one Business Day prior to the Closing.

Section 4.8.Private Placement Number.  Private Placement Numbers issued by Standard & Poor’s CUSIP Service Bureau (in cooperation with the SVO) shall have been obtained for the Fixed-Rate Notes and the Floating-Rate Notes.

Section 4.9.Changes in Corporate Structure.  Neither the Company nor the Parent shall have changed its jurisdiction of formation or been a party to any merger or consolidation or succeeded to all or any substantial part of the liabilities of any other entity, at any time following the date of the most recent financial statements referred to in Schedule 5.5.

Section 4.10.Funding Instructions.  At least three Business Days prior to the date of the Closing, each Purchaser shall have received written instructions signed by a Responsible Officer on letterhead of the Company confirming the information specified in Section 3 including (i) the name and address of the transferee bank, (ii) such transferee bank’s ABA number and (iii) the account name and number into which the purchase price for the Notes is to be deposited.

Section 4.11.Proceedings and Certain Documents.  All limited liability company and other proceedings in connection with the transactions contemplated by this Agreement and all documents and instruments incident to such transactions shall be satisfactory to such Purchaser and its special counsel, and such Purchaser and its special counsel shall have received all such counterpart originals or certified or other copies of such documents as such Purchaser or such special counsel may reasonably request.  Each Purchaser shall have received the following, each to be (i) dated the date of Closing unless otherwise indicated, and (ii) in form and substance satisfactory to such Purchaser:

(a)the Note or Notes to be purchased by such Purchaser;

(b)(i) this Agreement and each other Financing Document (including those Security Documents more fully set forth in Section 4.12), and (ii) copies of each PG&E Contract and the Base Gas Lease and any amendments or supplements thereto, in each case, duly authorized, executed and delivered by each party thereto, and in the case of the PG&E Contracts and the Base Gas Lease, certified by a Responsible Officer as being true, correct and complete and in full force and effect on the date of Closing;

(c)the certificate of formation or other charter document of each of the Company and the Parent, together with any amendments thereto, certified as of a recent date by the Secretary of State of the state of its formation and by such Person’s secretary;

(d)with respect to the Company and the Parent, a certificate of the secretary of each of the Company and the Parent attaching resolutions of the board of directors, management committee or other governing body of such Person evidencing approval of the transactions contemplated by this Agreement and the other Financing Documents to which such Person is a party and, with respect to the Company, the issuance of the Notes, and in each case, the execution, delivery and performance thereof, and authorizing certain officers to execute and deliver the same, and certifying that such resolutions were duly and validly adopted and have not since been amended, revoked or rescinded;

(e)the limited liability company agreement, operating agreement or similar documents of each of the Company and the Parent, together with any amendments thereto, certified by such Person’s secretary;

(f)with respect to each of the Company and the Parent, an incumbency certificate signed by the secretary and one other officer of such Person, certifying as to the names, titles and true signatures of the officers of such Person authorized to sign this Agreement, the Notes, the other Financing Documents and the other documents to be delivered hereunder to which such Person is a party;

(g)certificates of valid existence as to each of the Company and the Parent from their respective jurisdictions of formation as of a recent date;

(h)a certificate of qualification of the Company to transact business in the State of California;

(i)evidence that the Company shall have received authority (or an exemption) from the CPUC under Section 818 of the California Public Utilities Code authorizing the Company to issue the Notes and to incur the Indebtedness evidenced thereby, and the Purchasers shall have received certification from the Company that said authority is in full force and effect and all rehearing, appeal and judicial review periods with respect thereto have expired or terminated; and

(j)such additional documents or certificates with respect to such legal matters or limited liability company or other proceedings related to the transactions contemplated hereby as may be reasonably requested by such Purchaser.

Section 4.12.Security Agreement and other Security Documents.  The Obligations shall be secured by a perfected first priority security interest in the Collateral in favor of the Collateral Agent, for the benefit of the Secured Parties, and in that connection the Company will deliver or cause to be delivered to the Collateral Agent and such Purchaser on the date of Closing, the following each of which shall be in full force and effect:

(a)a Security Agreement in the form of Exhibit B, duly executed by the Company in favor of the Collateral Agent for the benefit of the Secured Parties (the “Security Agreement”);

(b)a Securities Account Control Agreement in the form of Exhibit C, duly executed by the Company, the Collateral Agent and the Securities Intermediary (the “Control Agreement”);

(c)an Intercreditor and Collateral Agency Agreement in the form of Exhibit D duly executed by the Company, the Parent, the Collateral Agent and the Purchasers (the “Collateral Agency Agreement”);

(d)a Pledge Agreement in the form of Exhibit E, duly executed by the Parent in favor of the Collateral Agent for the benefit of the Secured Parties (the “Pledge Agreement”);

(e)UCC-1 financing statements under the Uniform Commercial Code with respect to the Company and the Parent in each jurisdiction in which financing statements are necessary to perfect the Liens created under the Security Documents and copies of Uniform Commercial Code search reports and tax lien, judgment and litigation search reports with respect to the Company and the Parent, and all other instruments to be recorded or filed or delivered in connection with the Security Documents;

(f)evidence that all filing, recordation, subscription and inscription fees and all recording and other similar fees, and all recording, stamp and other taxes and other expenses related to such filings, registrations and recordings necessary for the consummation of the transactions contemplated hereby and by the other Financing Documents have been paid in full by or on behalf of the Company;

(g)certificates and instruments representing the Pledged Membership Interests, together with instruments of transfer or assignment, duly executed in blank, in form and substance reasonably satisfactory to the Collateral Agent, and evidence of Parent’s unrevoked election that such Pledged Membership Interests are governed as “securities” under Chapter 8 of the Oregon Uniform Commercial Code; and

(h)such other documents, instruments and agreements as the Collateral Agent or any Purchasers may reasonably request to grant to the Collateral Agent first priority perfected Liens in the Collateral.

Section 4.13.Debt Service Reserve Account.  The Company shall have established the Debt Service Reserve Account as set forth in Section9.10.

Section 4.14.Insurance.  The Company shall have delivered to such Purchaser evidence of insurance in effect in such amounts and meeting such requirements as are set forth in Section 9.2.

Section 4.15.Financial Statements.  The Company shall have delivered to such Purchaser the financial statements listed in Schedule 5.5.

Section 4.16.No Material Adverse Effect.  Since September 30, 2011, no event, occurrence or condition that has had, or could reasonably be expected to have, a Material Adverse Effect shall have occurred and be continuing, and a Responsible Officer of the Company shall have delivered a certificate to such Purchaser, dated as of the date of Closing, to such effect.

SECTION 5.   REPRESENTATIONS AND WARRANTIES OF THE COMPANY.

The Company represents and warrants to each Purchaser that:

Section 5.1.Organization; Power and Authority.  The Company is a limited liability company duly formed and validly existing under the laws of the State of Oregon, and is duly qualified to do business as a foreign limited liability company in the State of California and in each other jurisdiction in which such qualification is required by law, other than those other jurisdictions as to which the failure to be so qualified or in good standing could not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect.  The Company has the limited liability company power and authority to own or hold under lease the properties it purports to own or hold under lease, to transact the business it transacts and proposes to transact, to execute and deliver this Agreement, the Notes and the other Transaction Documents and to perform the provisions hereof and thereof.

Section 5.2.Authorization, Etc.  The execution, delivery and performance by the Company of each of the Transaction Documents to which it is a party have been duly authorized by all necessary limited liability company action on the part of the Company.  Each of the Transaction Documents to which the Company is a party has been duly executed and delivered by the Company and is in full force and effect and constitutes the legal, valid and binding obligation of the Company, enforceable against the Company in accordance with its terms, except as such enforceability may be limited by (i) applicable bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting the enforcement of creditors’ rights generally and (ii) general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

Section 5.3.Disclosure.  This Agreement, the other Transaction Documents and the documents, certificates or other writings delivered to the Purchasers by or on behalf of the Company in connection with the transactions contemplated hereby and identified in Schedule 5.3, and the financial statements listed in Schedule 5.5 (this Agreement, the other Transaction Documents and such documents, certificates or other writings and such financial statements delivered to each Purchaserbeing referred to, collectively, as the “Disclosure Documents”), taken as a whole, do not contain any untrue statement of a material fact or omit to state any material fact necessary to make the statements therein not misleading in light of the circumstances under which they were made; provided that with respect to any projected financial information, forecasts, estimates, or forward-looking information, the Company represents only that such information was prepared in good faith based upon assumptions believed to be reasonable, and the best information available to the Company, at the time, and the Company makes no representation as to the actual attainability of any such items listed in this sentence.  Since June 30, 2011, there has been no change in the financial condition, operations, business, properties or prospects of the Company or the Parent except changes that individually or in the aggregate could not reasonably be expected to have a Material Adverse Effect.  As of the date of Closing, there is no fact known to the Company that could reasonably be expected to have a Material Adverse Effect that has not been set forth herein or in the Disclosure Documents.

Section 5.4.Affiliates; Directors; No Subsidiaries.  Schedule 5.4 contains (except as noted therein) complete and correct lists of the Company’s Affiliates and the Company’s directors.  As of the date of Closing, the Company has no Subsidiaries.

Section 5.5.Financial Statements; Material Liabilities.  The Company has delivered to each Purchaser copies of the financial statements of the Company listed on Schedule 5.5.  All of said financial statements (including in each case the related schedules and notes) fairly present in all material respects the financial position of the Company as of the respective dates specified in such Schedule and the results of its operations and cash flows for the respective periods so specified and have been prepared in accordance with GAAP consistently applied throughout the periods involved except as set forth in the notes thereto (subject, in the case of any interim financial statements, to normal year-end adjustments).  The Company does not have any Material liabilities that are not disclosed on such financial statements or otherwise disclosed in the Disclosure Documents.

Section 5.6.Compliance with Laws, Other Instruments, Etc.  The execution, delivery and performance by the Company of this Agreement, the Notes and the other Transaction Documents to which it is a party will not (i) contravene, result in any breach of, or constitute a default under, or result in the creation of any Lien in respect of any property of the Company under, (a) any indenture, mortgage, deed of trust, loan, purchase or credit agreement, lease, or corporate charter or by-laws or (b) any other agreement or instrument to which the Company is bound or by which the Company or any of its properties may be bound or affected, that, individually or in the aggregate, could reasonably be expected to have a Material Adverse Effect, (ii) violate, conflict with or result in a breach of any of the terms, conditions or provisions of any order, judgment, decree or ruling of any court, arbitrator or Governmental Authority applicable to the Company or the Facility or (iii) violate any provision of any statute or other rule or regulation of any Governmental Authority applicable to the Company or the Facility.

Section 5.7.Governmental Authorizations, Etc.  All consents, approvals or authorizations of, or registrations, filings or declarations with, Governmental Authorities material for the ownership of the Project and operation and maintenance of the Facility and required to be held by the Company have been duly obtained and validly issued, are in full force and effect, are not the subject of any pending or threatened appeal, are held in the name of the Company and are free from conditions or requirements that would adversely affect the ability of the Company to execute, deliver and perform its obligations under the Financing Documents or materially adversely affect its ability to own its undivided interest in the Facility and to operate the Facility.  Other than the approval requirement under Section 818 of the California Public Utilities Code, from which an exemption has been obtained, no consent, approval or authorization of, or registration, filing or declaration with, any Governmental Authority is required in connection with the execution, delivery or performance by the Company of this Agreement, the Notes or any other Financing Document to which it is a party, other than the filing of the financing statements to perfect, or to continue the perfection of, the security interests granted under the Security Documents.

Section 5.8.Litigation; Observance of Agreements, Statutes and Orders.  (a) There are no actions, suits, investigations or proceedings pending or, to the knowledge of the Company, threatened against or affecting the Company or the Facility or any property of the Company in any court or before any arbitrator of any kind or before or by any Governmental Authority that, individually or in the aggregate, could reasonably be expected to have a Material Adverse Effect.

(b)The Company is not (i) in default under any term of any agreement or instrument to which it is a party or by which it is bound, (ii) in violation of any order, judgment, decree or ruling of any court, arbitrator or Governmental Authority or (iii) in violation of any applicable law, ordinance, rule or regulation of any Governmental Authority (including, without limitation, Environmental Laws, the USA PATRIOT Act or any of the other laws and regulations that are referred to in Section 5.16), which default or violation, individually or in the aggregate, could reasonably be expected to have a Material Adverse Effect.

Section 5.9.Taxes.  The Company has filed or caused to be filed all tax returns that are required to be filed in any jurisdiction, and have paid all taxes shown to be due and payable on such returns and all other taxes and assessments levied upon it or its properties, assets, income or franchises, to the extent such taxes and assessments have become due and payable and before they have become delinquent, except for any taxes and assessments (i) the amount of which is not individually or in the aggregate Material or (ii) the amount, applicability or validity of which is currently being contested in good faith by appropriate proceedings and with respect to which the Company has established adequate reserves in accordance with GAAP.  The Company knows of no basis for any other tax or assessment that could reasonably be expected to have a Material Adverse Effect.  The charges, accruals and reserves on the books of the Company in respect of U.S. federal, state or other taxes for all fiscal periods are adequate.

Section 5.10.Title to Property; Leases.  The Company has good and sufficient title to such property it purports to own that individually or in the aggregate is Material, including all such properties reflected in the most recent audited balance sheet referred to in Section 5.5 or purported to have been acquired by the Company after said date (except as sold or otherwise disposed of in the ordinary course of business), in each case free and clear of Liens prohibited by this Agreement.  All leases that individually or in the aggregate are Material are valid and subsisting and are in full force and effect in all material respects.

Section 5.11.Licenses, Permits, Etc.  (a)  All authorizations, consents, licenses, permits and certifications of or from all Governmental Authorities required for the ownership of the Project and operation and maintenance of the Facility are set forth in Schedule 5.11, and all such authorizations, consents, licenses, permits and certifications have been duly obtained, were validly issued and are in full force and effect and not subject to any appeal or further proceeding.

(b)The Company owns or possesses all licenses, permits, franchises, authorizations, patents, copyrights, proprietary software, service marks, trademarks and trade names, or rights thereto, that individually or in the aggregate are Material, without known conflict with the rights of others.

(c)To the best knowledge of the Company, no product or service of the Company infringes in any material respect any license, permit, franchise, authorization, patent, copyright, proprietary software, service mark, trademark, trade name or other right owned by any other Person.

(d)To the best knowledge of the Company, there is no Material violation by any Person of any right of the Company with respect to any patent, copyright, proprietary software, service mark, trademark, trade name or other right owned or used by the Company.

Section 5.12.Compliance with ERISA.  (a)  The Company and each ERISA Affiliate have operated and administered each Plan in compliance with all applicable laws except for such instances of noncompliance as have not resulted in and could not reasonably be expected to result in a Material Adverse Effect.  Neither the Company nor any ERISA Affiliate has incurred any liability pursuant to Title I or IV of ERISA, other than for premiums payable to the PBGC in the regular course and benefit accruals that are (or are reasonably expected to be) funded in a timely manner and in accordance with the minimum funding standard requirements under section 430 of the Code and section 303 of ERISA (and in accordance with Plan terms), or the penalty or excise tax provisions of the Code relating to employee benefit plans (as defined in section 3 of ERISA), and no event, transaction or condition has occurred or exists that could reasonably be expected to result in the incurrence of any such liability by the Company or any ERISA Affiliate, or in the imposition of any Lien on any of the rights, properties or assets of the Company or any ERISA Affiliate, in either case pursuant to Title I or IV of ERISA or to section 430(k) of the Code or to any such penalty or excise tax provisions under the Code or Federal law or section 4068 of ERISA or by the granting of a security interest in connection with the amendment of a Plan, other than such liabilities or Liens as would not be individually or in the aggregate Material.

(b)The present value of the aggregate benefit liabilities under each of the Plans (other than Multiemployer Plans), determined as of the beginning of such Plan’s current plan year on the basis of the actuarial assumptions specified for funding purposes in such Plan’s most recent actuarial valuation report, did not exceed the aggregate current value of the assets of such Plan allocable to such benefit liabilities by more than $25,000,000 in the case of any single Plan and by more than $44,000,000 in the aggregate for all Plans.  The term “benefit liabilities” has the meaning specified in section 4001 of ERISA and the terms “current value” and “present value” have the meaning specified in section 3 of ERISA.

(c)The Company and its ERISA Affiliates have not incurred withdrawal liabilities (and are not subject to contingent withdrawal liabilities) under section 4201 or 4204 of ERISA in respect of Multiemployer Plans that individually or in the aggregate are Material.

(d)The expected postretirement benefit obligation (determined as of the last day of the Company’s most recently ended fiscal year in accordance with Financial Accounting Standards Board Statement No. 106, without regard to liabilities attributable to continuation coverage mandated by section 4980B of the Code) of the Company and its Subsidiaries is not Material.

(e)The execution and delivery of this Agreement and the issuance and sale of the Notes hereunder will not involve any transaction that is subject to the prohibitions of section 406 of ERISA or in connection with which a tax could be imposed pursuant to section 4975(c)(1)(A)-(D) of the Code.  The representation by the Company to each Purchaser in the first sentence of this Section 5.12(e) is made in reliance upon and subject to the accuracy of such Purchaser’s representation in Section 6.2 as to the sources of the funds used to pay the purchase price of the Notes to be purchased by such Purchaser.

Section 5.13.Private Offering by the Company.  Neither the Company nor anyone acting on its behalf has offered the Notes or any similar Securities for sale to, or solicited any offer to buy any of the same from, or otherwise approached or negotiated in respect thereof with, any Person other than the Purchasers and not more than five other Institutional Investors, each of which has been offered the Notes at a private sale for investment.  Neither the Company nor anyone acting on its behalf has taken, or will take, any action that would subject the issuance or sale of the Notes to the registration requirements of section 5 of the Securities Act or to the registration requirements of any securities or blue sky laws of any applicable jurisdiction.

Section 5.14.Use of Proceeds; Margin Regulations.  The Company will apply the proceeds of the sale of the Notes (i) to fund the Debt Service Reserve Account in accordance with the terms of the Security Agreement, and (ii) to make distributions, from time to time, after the Closing to the Parent for further distribution to the Ultimate Parent an aggregate amount not to exceed $40,000,000 (the “Permitted Closing Distributions”).  No part of the proceeds from the sale of the Notes hereunder will be used, directly or indirectly, for the purpose of buying or carrying any margin stock within the meaning of Regulation U of the Board of Governors of the Federal Reserve System (12 CFR 221), or for the purpose of buying or carrying or trading in any Securities under such circumstances as to involve the Company in a violation of Regulation X of said Board (12 CFR 224) or to involve any broker or dealer in a violation of Regulation T of said Board (12 CFR 220).  Margin stock does not constitute more than 2.00% of the value of the assets of the Company and the Company does not have any present intention that margin stock will constitute more than 2.00% of the value of such assets.  As used in this Section, the terms “margin stock” and “purpose of buying or carrying” shall have the meanings assigned to them in said Regulation U.

Section 5.15.Existing Indebtedness; Future Liens.  (a) Except as described therein, Schedule 5.15 sets forth a complete and correct list of all outstanding Indebtedness of the Company as of the date of Closing (including a description of the obligors and obligees, principal amount outstanding and collateral therefor, if any, and Guaranty thereof, if any).  The Company is not in default and no waiver of default is currently in effect, in the payment of any principal or interest on any Indebtedness of the Company and no event or condition exists with respect to any Indebtedness of the Company that would permit (or that with notice or the lapse of time, or both, would permit) one or more Persons to cause such Indebtedness to become due and payable before its stated maturity or before its regularly scheduled dates of payment.

(b)The Company has not agreed or consented to cause or permit in the future (upon the happening of a contingency or otherwise) any of its property, whether now owned or hereafter acquired, to be subject to a Lien not permitted by Section 10.3.

(c)The Company is not a party to, or otherwise subject to any provision contained in, any instrument evidencing Indebtedness of the Company, any agreement relating thereto or any other agreement (including, but not limited to, its charter or other organizational document) which limits the amount of, or otherwise imposes restrictions on the incurring of, Indebtedness of the Company.

Section 5.16.Foreign Assets Control Regulations, Etc.  (a)  Neither the Company nor any Controlled Affiliate is (i) a Person whose name appears on the list of Specially Designated Nationals and Blocked Persons published by the Office of Foreign Assets Control, U.S. Department of Treasury (“OFAC”) (an “OFAC Listed Person”) or (ii) a department, agency or instrumentality of, or is otherwise controlled by or acting on behalf of, directly or indirectly, (x) any OFAC Listed Person or (y) any Person, entity, organization, foreign country or regime that is subject to any OFAC Sanctions Program (each OFAC Listed Person and each other Person, entity, organization and government of a country described in clause (ii), a “Blocked Person”).

(b)No part of the proceeds from the sale of the Notes hereunder constitutes or will constitute funds obtained on behalf of any Blocked Person or will otherwise be used, directly by the Company or indirectly through any Controlled Entity, in connection with any investment in, or any transactions or dealings with, any Blocked Person.

(c)To the Company’s actual knowledge after making due inquiry, neither the Company nor any Controlled Entity (i) is under investigation by any Governmental Authority for, nor been charged with, or convicted of, money laundering, drug trafficking, terrorist-related activities or other money laundering predicate crimes under any applicable law (collectively, “Anti-Money Laundering Laws”), (ii) has been assessed civil penalties under any Anti-Money Laundering Laws and (iii) has had any of its funds seized or forfeited in an action under any Anti-Money Laundering Laws. The Company has taken reasonable measures appropriate to the circumstances (in any event as required by applicable law) to ensure that the Company and each Controlled Entity is and will continue to be in compliance with all applicable current and future Anti-Money Laundering Laws.

(d)No part of the proceeds from the sale of the Notes hereunder will be used, directly or indirectly, for any improper payments to any governmental official or employee, political party, official of a political party, candidate for political office, official of any public international organization or anyone else acting in an official capacity, in order to obtain, retain or direct business or obtain any improper advantage.  The Company has taken reasonable measures appropriate to the circumstances (in any event as required by applicable law) to ensure that the Company and each Controlled Entity is and will continue to be in compliance with all applicable current and future anti-corruption laws and regulations.

Section 5.17.Status under Certain Statutes.  The Company is not subject to regulation under the Investment Company Act of 1940, as amended, the Public Utility Holding Company Act of 2005, as amended, the ICC Termination Act of 1995, as amended, or the Federal Power Act, as amended.  The Company is not a “gas utility company” under the Public Utility Holding Company Act of 2005, as amended.  None of the Purchasers or the Collateral Agent, solely by virtue of the execution, delivery and performance of, or its consummation of the transactions contemplated by or the enforcement of its rights and remedies under, the Financing Documents shall be or become a “natural-gas company” as such term is defined in the NGA or (except for the potential requirement of CPUC approval under Cal. PUC. Code § 854 to the transfer of the membership interests of the Parent in the Company) subject to regulation pursuant to the NGA or the CPUC.

Section 5.18.Environmental Matters.  (a) The Company has no knowledge of any claim nor has it received any notice of any claim, and no proceeding has been instituted raising any claim against the Facility or the Company or any of its real properties now or formerly owned, leased or operated by it or other assets, alleging any damage to the environment or violation of any Environmental Laws, except, in each case, such as could not reasonably be expected to result in a Material Adverse Effect.

(b)The Company has no knowledge of any facts which would give rise to any claim, public or private, of violation of Environmental Laws or damage to the environment emanating from, occurring on or in any way related to the Facility or to real properties now or formerly owned, leased or operated by it or to other assets or their use, except, in each case, such as could not reasonably be expected to result in a Material Adverse Effect.

(c)The Company has not stored any Hazardous Materials at the Facility or on real properties now or formerly owned, leased or operated by it and has not disposed of any Hazardous Materials in a manner contrary to any Environmental Laws in each case in any manner that could reasonably be expected to result in a Material Adverse Effect.

(d)All buildings on all real properties now owned, leased or operated by the Company are in compliance with applicable Environmental Laws, except where failure to comply could not reasonably be expected to result in a Material Adverse Effect.

Section 5.19.Project Documents.  As of the date of Closing, each Material Customer Contract and each amendment, modification or supplement thereto is set forth on Schedule 5.19.  All Material Project Documents are in full force and effect, and all conditions precedent to the obligations of the Company under such Material Project Documents have been satisfied or waived except for such conditions precedent which need not and cannot be satisfied until a later time.  The Company has not given or received a notice of default under any Material Project Document, any of the Facility’s ground leases or any Other Project Document except those which could not reasonably be expected to have a Material Adverse Effect, and, to the Company’s knowledge, no other Person party to any Project Document is in default of any material covenant or material obligation set forth in any such Project Document, and no condition has occurred that would become such a default with the giving of notice or lapse of time, except those conditions which could not reasonably be expected to have a Material Adverse Effect.

SECTION 6.   REPRESENTATIONS OF THE PURCHASERS.

Section 6.1.Purchase for Investment.  Each Purchaser severally represents that it is purchasing the Notes for its own account or for one or more separate accounts maintained by such Purchaser or for the account of one or more pension or trust funds and not with a view to the distribution thereof, provided that the disposition of such Purchaser’s or such fund’s property shall at all times be within such Purchaser’s or such fund’s control.  Each Purchaser understands that the Notes have not been registered under the Securities Act and may be resold only if registered pursuant to the provisions of the Securities Act or if an exemption from registration is available, except under circumstances where neither such registration nor such an exemption is required by law, and that the Company is not required to register the Notes.

Section 6.2.Source of Funds.  Each Purchaser severally represents that at least one of the following statements is an accurate representation as to each source of funds (a “Source”) to be used by such Purchaser to pay the purchase price of the Notes to be purchased by such Purchaser hereunder:

(a)the Source is an “insurance company general account” (as the term is defined in the United States Department of Labor’s Prohibited Transaction Exemption (“PTE”) 95-60, as amended) in respect of which the reserves and liabilities (as defined by the annual statement for life insurance companies approved by the NAIC (the “NAIC Annual Statement”)) for the general account contract(s) held by or on behalf of any employee benefit plan together with the amount of the reserves and liabilities for the general account contract(s) held by or on behalf of any other employee benefit plans maintained by the same employer (or affiliate thereof as defined in PTE 95-60) or by the same employee organization in the general account do not exceed 10% of the total reserves and liabilities of the general account (exclusive of separate account liabilities) plus surplus as set forth in the NAIC Annual Statement filed with such Purchaser’s state of domicile; or

(b)the Source is a separate account that is maintained solely in connection with such Purchaser’s fixed contractual obligations under which the amounts payable, or credited, to any employee benefit plan (or its related trust) that has any interest in such separate account (or to any participant or beneficiary of such plan (including any annuitant)) are not affected in any manner by the investment performance of the separate account; or

(c)the Source is either (i) an insurance company pooled separate account, within the meaning of PTE 90-1 or (ii) a bank collective investment fund, within the meaning of the PTE 91-38 and, except as disclosed by such Purchaser to the Company in writing pursuant to this clause (c), no employee benefit plan or group of plans maintained by the same employer or employee organization beneficially owns more than 10% of all assets allocated to such pooled separate account or collective investment fund; or

(d)the Source constitutes assets of an “investment fund” (within the meaning of Part VI of PTE 84-14, as amended (the “QPAM Exemption”)) managed by a “qualified professional asset manager” or “QPAM” (within the meaning of Part VI of the QPAM Exemption), no employee benefit plan’s assets that are managed by the QPAM in such investment fund, when combined with the assets of all other employee benefit plans established or maintained by the same employer or by an affiliate (within the meaning of Part VI(c)(1) of the QPAM Exemption) of such employer or by the same employee organization and managed by such QPAM, represent more than 20% of the total client assets managed by such QPAM, the conditions of Part I(c) and (g) of the QPAM Exemption are satisfied, neither the QPAM nor a person controlling or controlled by the QPAM maintains an ownership interest in the Company that would cause the QPAM and the Company to be “related” within the meaning of Part VI(h) of the QPAM Exemption and (i) the identity of such QPAM and (ii) the names of any employee benefit plans whose assets in the investment fund, when combined with the assets of all other employee benefit plans established or maintained by the same employer or by an affiliate (within the meaning of Part VI(c)(1) of the QPAM Exemption) of such employer or by the same employee organization, represent 10% or more of the assets of such investment fund, have been disclosed to the Company in writing pursuant to this clause (d); or

(e)the Source constitutes assets of a “plan(s)” (within the meaning of section IV of PTE 96-23, as amended (the “INHAM Exemption”)) managed by an “in-house asset manager” or “INHAM” (within the meaning of Part IV of the INHAM Exemption), the conditions of Part I(a), (g) and (h) of the INHAM Exemption are satisfied, neither the INHAM nor a person controlling or controlled by the INHAM (applying the definition of “control” in section IV(d) of the INHAM Exemption) owns a 5% or more interest in the Company and (i) the identity of such INHAM and (ii) the name(s) of the employee benefit plan(s) whose assets constitute the Source have been disclosed to the Company in writing pursuant to this clause (e); or

(f)the Source is a governmental plan; or

(g)the Source is one or more employee benefit plans, or a separate account or trust fund comprised of one or more employee benefit plans, each of which has been identified to the Company in writing pursuant to this clause (g); or

(h)the Source does not include assets of any employee benefit plan, other than a plan exempt from the coverage of ERISA.

As used in this Section 6.2, the terms “employee benefit plan,” “governmental plan,” and “separate account” shall have the respective meanings assigned to such terms in section 3 of ERISA.

SECTION 7.   INFORMATION AS TO COMPANY.

Section 7.1.Financial and Business Information.  The Company shall deliver to each Purchaser and each holder of a Note that is an Institutional Investor:

(a)Quarterly Statements — within 45 days after the end of each quarterly fiscal period in each fiscal year of the Company (other than the last quarterly fiscal period of each such fiscal year), duplicate copies of,

(i)the balance sheet of the Company as of the end of such quarter, and

(ii)statements of income, changes in members’ equity and cash flows of the Company, for such quarter and (in the case of the second and third quarters) for the portion of the fiscal year ending with such quarter,

setting forth in each case, in comparative form, the figures for the corresponding periods in the previous fiscal year, all in reasonable detail, prepared in accordance with GAAP applicable to quarterly financial statements generally, and certified by a Senior Financial Officer as fairly presenting, in all material respects, the financial position of the Company and its results of operations and cash flows, subject to changes resulting from year-end adjustments;

(b)Annual Statements — within 120 days after the end of each fiscal year of the Company, duplicate copies of,

(i)the balance sheet of the Company as of the end of such year, and

(ii)statements of income, changes in members’ equity and cash flows of the Company for such year,

setting forth in each case in comparative form the figures for the previous fiscal year, all in reasonable detail, prepared in accordance with GAAP, and accompanied by an opinion thereon (without any qualification or exception as to the scope of the audit on which such opinion is based) of independent public accountants of recognized national standing, which opinion shall state that such financial statements present fairly, in all material respects, the financial position of the companies being reported upon and their results of operations and cash flows and have been prepared in conformity with GAAP, and that the examination of such accountants in connection with such financial statements has been made in accordance with generally accepted auditing standards, and that such audit provides a reasonable basis for such opinion in the circumstances;

(c)SEC and Other Reports — promptly upon their becoming available (unless otherwise already publicly available through a website maintained by or on behalf of the Company or the Parent and the Company has given each holder of a Note that is an Institutional Investor prompt notice of such availability), one copy of (i) each financial statement, report, notice or proxy statement sent by the Company to its principal lending banks as a whole (excluding information sent to such banks in the ordinary course of administration of a bank facility, such as information relating to pricing and borrowing availability) or to its public Securities holders generally, and (ii) each regular or periodic report, each registration statement (without exhibits except as expressly requested by such Purchaser or holder), and each prospectus and all amendments thereto filed by the Company or the Parent with the SEC and of all press releases and other statements made available generally by the Company or the Parent to the public concerning developments that are Material;

(d)Notice of Default or Event of Default — promptly, and in any event within five Business Days after a Responsible Officer becoming aware of the existence of any Default or Event of Default or that any Person has given any notice or taken any action with respect to a claimed default hereunder or that any Person has given any notice or taken any action with respect to a claimed default of the type referred to in Section 11(f), a written notice specifying the nature and period of existence thereof and what action the Company is taking or proposes to take with respect thereto;

(e)Notice of Casualty, Litigation, Proceedings, Etc. — as soon as practicable and in any event, unless otherwise specified, within five days after a Responsible Officer of the Company obtains actual knowledge of any of the following: (i) the occurrence of any casualty, loss or damage, or condemnation or eminent domain taking, with respect to the Facility in excess of $2,000,000 in value or any series of such events or circumstances during any 12-month period in excess of $5,000,000 in value in the aggregate or (ii) any litigation or similar proceeding affecting the Facility or the Company in which the amount involved is in excess of $5,000,000;

(f)Notices Under Project Documents — promptly upon delivery by the Company to another Person party to (i) any Material Project Document, any notice of default under such Material Project Document or (ii) any Other Project Document Material to the operation and maintenance of the Facility, any notice of Material default under such Other Project Document;

(g)ERISA Matters — promptly, and in any event within five days after a Responsible Officer becoming aware of any of the following, a written notice setting forth the nature thereof and the action, if any, that the Company or an ERISA Affiliate proposes to take with respect thereto:

(i)with respect to any Plan, any reportable event, as defined in section 4043(c) of ERISA and the regulations thereunder, for which notice thereof has not been waived pursuant to such regulations as in effect on the date hereof; or

(ii)the taking by the PBGC of steps to institute, or the threatening by the PBGC of the institution of, proceedings under section 4042 of ERISA for the termination of, or the appointment of a trustee to administer, any Plan, or the receipt by the Company or any ERISA Affiliate of a notice from a Multiemployer Plan that such action has been taken by the PBGC with respect to such Multiemployer Plan; or

(iii)any event, transaction or condition that could result in the incurrence of any liability by the Company or any ERISA Affiliate pursuant to Title IV of ERISA or the penalty or excise tax provisions of the Code relating to employee benefit plans, or in the imposition of any Lien on any of the rights, properties or assets of the Company or any ERISA Affiliate pursuant to Title I or IV of ERISA or such penalty or excise tax provisions, if such liability or Lien, taken together with any other such liabilities or Liens then existing, could reasonably be expected to have a Material Adverse Effect;

(h)Notices from Governmental Authority — promptly, and in any event within 30 days of receipt thereof, copies of any notice to the Company from any federal or state Governmental Authority relating to any order, ruling, dispute, litigation, investigation, proceeding, statute or other law or regulation that could reasonably be expected to have a Material Adverse Effect; and

(i)Information Required by Rule 144A(d)(4) — upon the request of such Purchaser or holder of a Note, such financial and other information (which the Company also shall deliver to any qualified institutional buyer designated by such holder) as such holder may reasonably determine to be necessary in order to permit compliance with the information requirements of Rule 144A(d)(4) under the Securities Act in connection with the resale of Notes, except at such times as the Company is subject to the reporting requirements of section 13 or 15(d) of the Exchange Act (for the purpose of this Section 7.1(i), the term “qualified institutional buyer” shall have the meaning specified in Rule 144A under the Securities Act); and

(j)Requested Information — with reasonable promptness, such other data and information relating to the business, operations, affairs, financial condition, assets or properties of the Company or relating to the ability of the Company to perform its obligations hereunder and under the Notes and the other Transaction Documents as from time to time may be reasonably requested by any such Purchaser or holder of a Note.

Section 7.2.Officer’s Certificate.  Each set of financial statements delivered to a Purchaser or a holder of a Note pursuant to Section 7.1(a) or Section 7.1(b) shall be accompanied by a certificate of a Senior Financial Officer:

(a)Covenant Compliance — setting forth the information (including detailed calculations) required in order to establish whether the Company was in compliance with the requirements of Section 10.1 and Section 10.2, inclusive, during the period covered by the statements then being furnished (including with respect to each such Section, where applicable, the calculations of the maximum or minimum amount, ratio or percentage, as the case may be, permissible under the terms of such Sections, and the calculation of the amount, ratio or percentage then in existence); and

(b)Event of Default — certifying that such Senior Financial Officer has reviewed the relevant terms hereof and has made, or caused to be made, under his or her supervision, a review of the transactions and conditions of the Company from the beginning of the quarterly or annual period covered by the statements then being furnished to the date of the certificate and that such review shall not have disclosed the existence during such period of any condition or event that constitutes a Default or an Event of Default or, if any such condition or event existed or exists (including, without limitation, any such event or condition resulting from the failure of the Company to comply with any Environmental Law), specifying the nature and period of existence thereof and what action the Company shall have taken or proposes to take with respect thereto.

Section 7.3.Visitation.  The Company shall permit the representatives of each Purchaser and each holder of a Note that is an Institutional Investor:

(a)No Default — if no Default or Event of Default then exists, at the expense of such Purchaser or holder and upon reasonable prior notice to the Company, to visit the principal executive office of the Company, to discuss the affairs, finances and accounts of the Company with the Company’s officers, and (with the consent of the Company, which consent will not be unreasonably withheld) its independent public accountants, and (with the consent of the Company, which consent will not be unreasonably withheld) to visit the other offices and properties of the Company, all at such reasonable times (during normal business hours) and as often as may be reasonably requested in writing; provided that each such Purchaser and holder making such visits shall use their best efforts to minimize disruption of the normal business operations of the Company; and

(b)Default — if a Default or Event of Default then exists, at the expense of the Company and upon reasonable prior notice to the Company, which shall in no event be more than five Business Days, to visit and inspect any of the offices or properties of the Company, to examine all their respective books of account, records, reports and other papers, to make copies and extracts therefrom, and to discuss their respective affairs, finances and accounts with their respective officers and independent public accountants (and by this provision the Company authorizes said accountants to discuss the affairs, finances and accounts of the Company), during normal business hours and as often as may be requested; provided that each such Purchaser and holder making such visits shall use their best efforts to minimize disruption of the normal business operations of the Company.

SECTION 8.   PAYMENT AND PREPAYMENT OF THE NOTES; FLOATING RATE PROVISIONS.

Section 8.1.Maturity.  As provided therein, the entire unpaid principal balance of the Notes shall be due and payable on the stated maturity date thereof.

Section 8.2.Optional Prepayments.

(a)Fixed-Rate Notes with Make-Whole Amount — The Company may, at its option, upon notice as provided in clause (c) below, prepay at any time all, or from time to time any part of, the Fixed-Rate Notes, in an amount not less than $1,000,000 and integral multiples of $100,000 in excess thereof in the case of a partial prepayment, at 100% of the principal amount so prepaid, and the Make-Whole Amount determined for the prepayment date with respect to such principal amount.

(b)Floating-Rate Notes — From and after November 30, 2012, the Company may, at its option, upon notice as provided in clause (c) below, prepay at any time all, or from time to time any part of, the Floating-Rate Notes, in an amount not less than $1,000,000 and integral multiples of $100,000 in excess thereof in the case of a partial prepayment, and the Premium determined for the prepayment date with respect to such principal amount; provided that if any Floating-Rate Notes are prepaid pursuant to this Section 8.2(b) on any day other than the last day of the applicable Interest Period, then such prepayment will be subject to Section 8.8(b) and any Breakage Cost Obligation payable thereunder.

(c)Notice of Optional Prepayments — The Company will give each holder of Fixed-Rate Notes or Floating-Rate Notes, as applicable, written notice of each optional prepayment under this Section 8.2 not less than 10 days and not more than 60 days prior to the date fixed for such prepayment.  Each such notice shall specify such date (which shall be a Business Day), the aggregate principal amount of the Notes to be prepaid on such date, the principal amount of each Note held by such holder to be prepaid (determined in accordance with Section 8.4), and the interest to be paid on the prepayment date with respect to such principal amount being prepaid, and, in the case of a prepayment of Fixed-Rate Notes, shall be accompanied by a certificate of a Senior Financial Officer as to the estimated Make-Whole Amount due in connection with such prepayment (calculated as if the date of such notice were the date of the prepayment), setting forth the details of such computation.  Two Business Days prior to such prepayment of Fixed-Rate Notes, the Company shall deliver to each holder of Fixed-Rate Notes a certificate of a Senior Financial Officer specifying the calculation of such Make-Whole Amount as of the specified prepayment date.

Section 8.3.Offer to Prepay Notes in the Event of a Change in Control.

(a)Notice of Change in Control — The Company will, within five Business Days after any Responsible Officer has actual knowledge of the occurrence of any Change in Control, give written notice of such Change in Control to each holder of Notes unless notice in respect of such Change in Control shall have been given pursuant to Section 8.3(b).  If a Change in Control has occurred, such notice shall contain and constitute an offer by the Company to prepay the Notes as described in Section 8.3(c) and shall be accompanied by the certificate described in Section 8.3(f).  The Company shall, on or before the day on which it gives such written notice of such Change in Control, give telephonic notice thereof to each holder that shall have designated a recipient of such notices in Schedule A-1 attached hereto or by notice in writing to the Company.

(b)Condition to Ultimate Parent’s Action — The Company will use reasonable best efforts to cause the Ultimate Parent, the Parent and their other Affiliates to refrain from taking or permitting any action that consummates or finalizes a Change in Control unless at least 15 days prior to such action the Company shall have given to each holder of Notes written notice of such impending Change in Control, which notice shall contain and constitute an offer by the Company to prepay the Notes as described in Section 8.3(c) and shall be accompanied by the certificate described in Section 8.3(f).  The Company shall, on or before the day on which it gives such written notice of such impending Change in Control, give telephonic notice thereof to each holder which shall have designated a recipient of such notices in Schedule A-1 attached hereto or by notice in writing to the Company.

(c)Offer to Prepay Notes — The offer to prepay Notes contemplated by Section 8.3(a) or (b) shall be an offer to prepay, in accordance with and subject to this Section 8.3, all, but not less than all, the Notes held by each holder (in this case only, “holder” in respect of any Note registered in the name of a nominee for a disclosed beneficial owner shall mean such beneficial owner) on a date specified in such offer (the “Proposed Change in Control Prepayment Date”).  Such Proposed Change in Control Prepayment Date shall be not less than 10 days and not more than 30 days after the date of such offer (if the Proposed Prepayment Date shall not be specified in such offer, the Proposed Change in Control Prepayment Date shall be the 20th day after the date of such offer); provided that if any amounts outstanding under the Floating-Rate Notes are LIBOR Loans with an Interest Period (or Interest Periods) ending on or before the 30th day after the date of such offer, the Proposed Change in Control Prepayment Date with respect to such Floating-Rate Notes shall be the last day of the Interest Period (or, if more than one such Interest Period is in effect, the last day of all such Interest Periods then in effect).

(d)Acceptance; Rejection — The Company shall, on or before the seventh day prior to the Proposed Change in Control Prepayment Date, give telephonic renotification and confirmation thereof to each holder which shall have designated a recipient of such notices in the Schedule A-1 attached hereto or by notice in writing to the Company.  A holder of Notes may accept or reject the offer to prepay made pursuant to this Section 8.3 by causing a notice of such acceptance or rejection to be delivered to the Company on or before the fifth day prior to the Proposed Change in Control Prepayment Date.  A failure by a holder of Notes to respond to an offer to prepay made pursuant to this Section 8.3 on or before such date shall be deemed to constitute an acceptance of such offer by such holder.

(e)Prepayment — Prepayment of the Notes to be prepaid pursuant to this Section 8.3 shall be at 100% of the principal amount of such Notes, together with interest accrued to the date of prepayment and (i) in the case of Fixed-Rate Notes, the Make-Whole Amount, if any, (ii) in the case of Floating-Rate Notes, the Premium, if any, and (iii) in the case of Floating-Rate Notes prepaid on any day other than the last day of the applicable Interest Period, any Breakage Cost Obligation payable under Section 8.8(b).  The prepayment shall be made on the Proposed Change in Control Prepayment Date.

(f)Officer’s Certificate — Each offer to prepay the Notes pursuant to this Section 8.3 shall be accompanied by a certificate, executed by a Senior Financial Officer of the Company and dated the date of such offer, specifying: (a) the Proposed Change in Control Prepayment Date; (b) that such offer is made pursuant to this Section 8.3; (c) the principal amount of each Note offered to be prepaid; (d) the interest that would be due on each Note offered to be prepaid, accrued to the Proposed Change in Control Prepayment Date and the estimated Make-Whole Amount, Premium or Breakage Cost Obligation, as applicable, due in connection with such prepayment; (e) that the conditions of this Section 8.3 have been fulfilled; and (f) in reasonable detail, the nature and date of the Change in Control.

Section 8.4.Allocation of Partial Prepayments.  In the case of each partial prepayment of the Fixed-Rate Notes pursuant to Section 8.2(a), the principal amount of the Fixed-Rate Notes to be prepaid shall be allocated among all of the Fixed-Rate Notes at the time outstanding in proportion, as nearly as practicable, to the respective unpaid principal amounts thereof not theretofore called for prepayment.  In the case of each partial prepayment of the Floating-Rate Notes pursuant to Section 8.2(b), the principal amount of the Floating-Rate Notes to be prepaid shall be allocated among all of the Floating-Rate Notes at the time outstanding in proportion, as nearly as practicable, to the respective unpaid principal amounts thereof not theretofore called for prepayment.  Upon any prepayment of Notes pursuant to Section 8.3, the principal amount so prepaid shall be allocated to all Notes at the time outstanding held by holders of Notes who have accepted the Company’s offer of prepayment made pursuant to Section 8.3 in proportion to the respective outstanding principal amounts thereof.

Section 8.5.Maturity; Surrender, Etc.  In the case of each prepayment of Notes pursuant to this Section 8, the principal amount of each Note to be prepaid shall mature and become due and payable on the date fixed for such prepayment, together with interest on such principal amount accrued to such date and, in the case of prepayments of Fixed-Rate Notes, the applicable Make-Whole Amount, if any, and in the case of prepayments of Floating-Rate Notes, the applicable Premium and Breakage Cost Obligation, if any.  From and after such date, unless the Company shall fail to pay such principal amount when so due and payable, together with the interest and Make-Whole Amount, Premium or Breakage Cost Obligation, if any, as aforesaid, interest on such principal amount shall cease to accrue.  Any Note paid or prepaid in full shall be surrendered to the Company and cancelled and shall not be reissued, and no Note shall be issued in lieu of any prepaid principal amount of any Note.

Section 8.6.Purchase of Notes.  The Company will not and will not permit any Affiliate to purchase, redeem, prepay or otherwise acquire, directly or indirectly, any of the outstanding Notes except upon the payment or prepayment of the Notes in accordance with the terms of this Agreement and the Notes.  The Company will promptly cancel all Notes acquired by it or any Affiliate pursuant to any payment or prepayment of Notes pursuant to any provision of this Agreement and no Notes may be issued in substitution or exchange for any such Notes.

Section 8.7.Make-Whole Amount.

“Make-Whole Amount” means, with respect to any Fixed-Rate Note, an amount equal to the excess, if any, of the Discounted Value of the Remaining Scheduled Payments with respect to the Called Principal of such Fixed-Rate Note over the amount of such Called Principal, provided that the Make-Whole Amount may in no event be less than zero.  For the purposes of determining the Make-Whole Amount, the following terms have the following meanings:

“Called Principal” means, with respect to any Fixed-Rate Note, the principal of such Fixed-Rate Note that is to be prepaid pursuant to Section 8.2(a) or Section 8.3(e) or has become or is declared to be immediately due and payable pursuant to Section 12.1, as the context requires.

“Discounted Value” means, with respect to the Called Principal of any Fixed-Rate Note, the amount obtained by (i) discounting to present value all Remaining Scheduled Payments with respect to such Called Principal from their respective scheduled due dates to the Settlement Date with respect to such Called Principal in accordance with accepted financial practice and at a discount factor (applied on the same periodic basis as that on which interest on the Fixed-Rate Notes is payable) equal to the Reinvestment Yield with respect to such Called Principal.

“Reinvestment Yield” means, with respect to the Called Principal of any Fixed-Rate Note, 0.50% over the yield to maturity implied by yield(s) reported as of 10:00 a.m. (New York City time) on the second Business Day preceding the Settlement Date with respect to such Called Principal, on the display designated as “Page PX1” (or such other display as may replace Page PX1) on Bloomberg Financial Markets for the most recently issued non-callable actively traded on-the-run U.S. Treasury securities (“Reported”) having a maturity equal to the Remaining Average Life of such Called Principal as of such Settlement Date.  If there are no such U.S. Treasury securities Reported having a maturity equal to such Remaining Average Life, then such implied yield to maturity will be determined by (a) converting U.S. Treasury bill quotations to bond equivalent yields in accordance with accepted financial practice and (b) interpolating linearly between the yields Reported for the applicable most recently issued actively traded on-the-run U.S. Treasury securities with the maturities (1) closest to and greater than such Remaining Average Life and (2) closest to and less than such Remaining Average Life.  The Reinvestment Yield shall be rounded to the number of decimal places as appears in the interest rate of the applicable Fixed-Rate Note.

If such yields are not Reported or the yields Reported as of such time are not ascertainable (including by way of interpolation), then “Reinvestment Yield” means, with respect to the Called Principal of any Fixed-Rate Note, 0.50% over the yield to maturity implied by the U.S. Treasury constant maturity yields reported, for the latest day for which such yields have been so reported as of the second Business Day preceding the Settlement Date with respect to such Called Principal, in Federal Reserve Statistical Release H.15 (or any comparable successor publication) for the U.S. Treasury constant maturity having a term equal to the Remaining Average Life of such Called Principal as of such Settlement Date.  If there is no such U.S. Treasury constant maturity having a term equal to such Remaining Average Life, such implied yield to maturity will be determined by interpolating linearly between (1) the U.S. Treasury constant maturity so reported with the term closest to and greater than such Remaining Average Life and (2) the U.S. Treasury constant maturity so reported with the term closest to and less than such Remaining Average Life.  The Reinvestment Yield shall be rounded to the number of decimal places as appears in the interest rate of the applicable Fixed-Rate Note.

“Remaining Average Life” means, with respect to any Called Principal, the number of years obtained by dividing (i) such Called Principal into (ii) the sum of the products obtained by multiplying (a) the principal component of each Remaining Scheduled Payment with respect to such Called Principal by (b) the number of years, computed on the basis of a 360-day year composed of twelve 30-day months, that will elapse between the Settlement Date with respect to such Called Principal and the scheduled due date of such Remaining Scheduled Payment.

“Remaining Scheduled Payments” means, with respect to the Called Principal of any Fixed-Rate Note, all payments of such Called Principal and interest thereon that would be due after the Settlement Date with respect to such Called Principal if no payment of such Called Principal were made prior to its scheduled due date, provided that if such Settlement Date is not a date on which interest payments are due to be made under the terms of the Fixed-Rate Notes, then the amount of the next succeeding scheduled interest payment will be reduced by the amount of interest accrued to such Settlement Date and required to be paid on such Settlement Date pursuant to Section 8.2(a), Section 8.3(e) or Section 12.1.

“Settlement Date” means, with respect to the Called Principal of any Fixed-Rate Note, the date on which such Called Principal is to be prepaid pursuant to Section 8.2(a) or Section 8.3(e) or has become or is declared to be immediately due and payable pursuant to Section 12.1, as the context requires.

Section 8.8.Additional Floating Rate Provisions.

(a)Floating Rate Interest Procedures; Floating Rate Interest on Notes.

(i)In an irrevocable telephonic notice (confirmed by written notice received within one day after such telephonic notice) to each holder of Floating-Rate Notes no later than 11:00 a.m. New York City time on the Business Day immediately preceding the first day of an Interest Period, in the case of Prime Loans, or the third Business Day prior to the first day of an Interest Period, in the case of LIBOR Loans, the Company shall elect (A) whether the Loans are to be LIBOR Loans or Prime Loans and (B) if the Loans are to be LIBOR Loans, the applicable Interest Period or Interest Periods; provided that (X) no more than five Interest Periods may be in effect at any time, and (Y) in no event shall the aggregate principal amount of Loans for any Interest Period be less than $100,000.

(ii)Subject to the terms and conditions hereof, the Company may elect from time to time to convert LIBOR Loans to Prime Loans or Prime Loans to LIBOR Loans by giving an irrevocable telephonic notice (confirmed by written notice received within one day after such telephonic notice) to each holder of Floating-Rate Notes no later than 11:00 a.m. New York City time on the third Business Day prior to the effective date of such election, which effective date shall be the last day of the applicable Interest Period for such Loans.  Any such notice concerning conversions to LIBOR Loans shall specify the length of the initial Interest Period or Interest Periods therefor.

(iii)If the Company has failed to elect a new Loan Type and Interest Period or Interest Periods for the Loans in a timely manner, the Company shall be deemed to have elected (A) to continue LIBOR Loans as LIBOR Loans having an Interest Period or Interest Periods equal to that of the Interest Period or Interest Periods immediately preceding such new Interest Period or Interest Periods, and (B) to continue Prime Loans as Prime Loans.  All Interest Periods for the Loans shall be deemed to end on the earlier of (X) the stated maturity date of the Floating-Rate Notes, (Y) the date the Loans become due and payable pursuant to Section 12.1 or (Z) the Proposed Prepayment Date, with respect to Notes prepaid pursuant to Section 8.3.

(iv)Notwithstanding any of the foregoing, if an Event of Default has occurred and is continuing as of the end of any Interest Period, then the Company shall be deemed to have elected (a) to convert LIBOR Loans to Prime Loans and (b) to continue Prime Loans as Prime Loans.

(v)Interest on the Floating-Rate Notes shall: (A) be payable (I) on the last day of each Interest Period, which, except as otherwise provided in the definition of “Interest Period”, shall be, (1) with respect to any LIBOR Loan, the day numerically corresponding to the commencement date of such LIBOR Loan in the calendar month that is one or three months thereafter, in each case as the Company may specify or be deemed to specify, and (2) with respect to any Prime Loan, the last day of each March, June, September or December next succeeding the commencement date of such Prime Loan, (II) on the date of any prepayment (on the amount prepaid), (III) at maturity (whether by acceleration or otherwise) and, (IV) after such maturity, on demand; and (B) be computed on the actual number of days elapsed over, in the case of any LIBOR Loan, a year of 360 days and, in the case of any Prime Loan, a year of 365 or 366 days, as the case may be.

(b)Breakage Cost Indemnity.

(i)The Company agrees to indemnify each holder of Floating-Rate Notes for, and to pay promptly to such holder upon written request, any amounts required to compensate such holder for any losses, costs or expenses sustained or incurred by such holder (including, without limitation, any loss (including loss of anticipated profits), cost or expense sustained or incurred by reason of the liquidation or reemployment of deposits or other funds acquired to fund or maintain any LIBOR Loan) as a consequence of (a) any event (including any prepayment of Floating-Rate Notes pursuant to Section 8.2(b) or Section 8.3, any conversion from LIBOR Loans to Prime Loans under Section 8.8(d) or any acceleration of Notes in accordance with Section 12.1) which results in (I) such holder receiving any amount on account of the principal of any LIBOR Loan prior to the end of the Interest Period in effect therefor or (II) in the case of any LIBOR Loan the conversion of the Interest Period, other than on the last day of the Interest Period in effect therefor, or (b) any default in the making of any payment or prepayment required to be made in respect of any LIBOR Loans (such amount being the “Breakage Cost Obligation”).

(ii)A certificate of any holder of Floating-Rate Notes setting forth any amount or amounts which such holder is entitled to receive pursuant to this Section 8.8(b), together with calculations in reasonable detail reflecting the basis for such amount or amounts, shall be delivered to the Company and shall be conclusive absent manifest error.  The Company agrees to pay such holder the amount shown as due on any such certificate within 10 days after its receipt of the same.

(iii)The provisions of this Section 8.8(b) shall remain operative and in full force and effect regardless of the expiration of the term of this Agreement, the consummation of the transactions contemplated hereby, the repayment of any of the Loans, the invalidity or unenforceability of any term or provision of this Agreement or any Floating-Rate Note, or any investigation made by or on behalf of any holder of Floating-Rate Notes.

(iv)For purposes of calculating amounts payable by the Company to the holders of the Floating-Rate Notes under this Section 8.8(b), each holder shall be deemed to have funded each LIBOR Loan made by it at the LIBO Rate for such Loan by a matching deposit or other borrowing in the applicable offshore Dollar interbank market for a comparable amount and for a comparable period, whether or not such LIBOR Loan was in fact so funded.

(c)Reserve Requirements; Change in Circumstance.

(i)Notwithstanding any other provision of this Agreement, if after the date of this Agreement any change in applicable law or regulation or in the interpretation or administration thereof by any Governmental Authority charged with the interpretation or administration thereof (whether or not having the force of law) shall impose, modify or deem applicable any reserve, special deposit or similar requirement against assets of, deposits with or for the account of, or credit extended by, any holder of Notes or shall impose on such holder or the London interbank market any other condition affecting this Agreement or LIBOR Loans made by such holder and the result of any of the foregoing shall be to increase the cost to such holder of making or maintaining any LIBOR Loan or to reduce the amount of any payment received or receivable by such holder hereunder or under any of the Floating-Rate Notes (whether of principal, interest or otherwise), then the Company will pay to such holder upon demand such additional amount or amounts as will compensate such holder for such additional costs incurred or reduction suffered.

(ii)If any holder of a Floating-Rate Note shall have determined that the adoption after the date hereof of any law, rule, regulation, agreement or guideline regarding capital adequacy, or any change after the date hereof in any such law, rule, regulation, agreement or guideline (whether such law, rule, regulation, agreement or guideline has been adopted before or after the date hereof) or in the interpretation or administration thereof by any Governmental Authority charged with the interpretation or administration thereof, or compliance by such holder with any request or directive regarding capital adequacy (whether or not having the force of law) of any Governmental Authority has or would have the effect of reducing the rate of return on such holder’s capital as a consequence of Loans made pursuant hereto to a level below that which such holder could have achieved but for such applicability, adoption, change or compliance (taking into consideration such holder’s policies with respect to capital adequacy) by an amount deemed by such holder to be material, then from time to time the Company agrees to pay to such holder such additional amount or amounts as will compensate such holder for any such reduction suffered.

(iii)A certificate of any holder of Floating-Rate Notes setting forth the amount or amounts necessary to compensate such holder as specified in clause (i) or (ii) above shall be delivered to the Company and shall be conclusive absent manifest error.  The Company agrees to pay such holder the amount shown as due on any such certificate within ten days after its receipt of the same.

(iv)Failure or delay on the part of any holder of Floating-Rate Notes to demand compensation for any increased costs or reduction in amounts received or receivable or reduction in return on capital shall not constitute a waiver of such holder’s right to demand such compensation with respect to such period or any other period; provided that the Company shall not be required to compensate a holder pursuant to this Section 8.8(c) for any increased costs or reduction incurred more than six months prior to the date on which such holder notifies the Company of the event giving rise to such increased costs or reduction and of that holder’s intention to claim compensation for those circumstances; provided further that, if the event giving rise to such increased costs or reduction is retroactive, then the six-month period referred to above shall be extended to include that period of retroactive effect.  The protection of this paragraph shall be available to any such holder regardless of any possible contention of the invalidity or inapplicability of the law, rule, regulation, agreement, guideline or other change or condition that shall have occurred or been imposed.

(v)The provisions of this Section 8.8(c) shall remain operative and in full force and effect regardless of the expiration of the term of this Agreement, the consummation of the transactions contemplated hereby, the repayment of any of the Loans, the invalidity or unenforceability of any term or provision of this Agreement or any Floating-Rate Note, or any investigation made by or on behalf of any holder of Floating-Rate Notes.

(d)Illegality.

(i)Notwithstanding any other provision of this Agreement, if, after the date hereof, any change in any law or regulation or in the interpretation thereof by any Governmental Authority charged with the administration or interpretation thereof shall make it unlawful for any holder of Floating-Rate Notes to make or maintain any LIBOR Loan or to give effect to its obligations as contemplated hereby with respect to any LIBOR Loan, then (a) such holder shall promptly notify the Company in writing of such circumstances (which notice shall be withdrawn when such holder determines that such circumstances no longer exist), (b) the obligation of such holder to make LIBOR Loans, to continue LIBOR Loans as LIBOR Loans and to convert Prime Loans to LIBOR Loans shall forthwith be canceled and, until such time as it shall no longer be unlawful for such holder to make or maintain LIBOR Loans, such holder shall then be obligated only to make Prime Loans and (c) such holder may require that all LIBOR Loans made by it be converted to Prime Loans, in which event all such LIBOR Loans shall be automatically converted to Prime Loans as of the effective date of such notice as provided in clause (ii) below.

(ii)For purposes of this Section 8.8(d), a notice to the Company by any holder of Floating-Rate Notes shall be effective as to LIBOR Loans made by such holder, if lawful, on the last day of the Interest Period or Interest Periods currently applicable to such LIBOR Loans; in all other cases such notice shall be effective on the date of receipt by the Company.  If any such conversion of a LIBOR Loan occurs on a day which is not the last day of the then current Interest Period with respect thereto, the Company shall pay to such holder such amounts, if any, as may be required pursuant to Section 8.8(b).

(e)Inability to Determine Interest Rate — If prior to the first day of any Interest Period for any LIBOR Loan, any holder of Floating-Rate Notes shall have determined (which determination shall be conclusive and binding upon the Company) that, by reason of circumstances affecting the London interbank market, adequate and reasonable means do not exist for ascertaining the LIBO Rate for such Interest Period, such holder shall give notice thereof to the Company as soon as practicable thereafter.  If such notice is given, (i) any LIBOR Loans requested to be made on the first day of such Interest Period shall be made as Prime Loans, (ii) any Loans that were to have been converted on the first day of such Interest Period to or continued as LIBOR Loans shall be converted to or continued as Prime Loans and (iii) any outstanding LIBOR Loans shall be converted, at the end of the then applicable Interest Period, to Prime Loans.  Until such notice has been withdrawn by such holder, no further LIBOR Loans shall be made or continued as such, nor shall the Company have the right to convert Prime Loans to LIBOR Loans.

SECTION 9.   AFFIRMATIVE COVENANTS.

The Company covenants that so long as any of the Notes are outstanding:

Section 9.1.Compliance with Laws.  Without limiting Section 10.12, the Company will comply with all laws, ordinances or governmental rules or regulations to which it is subject, including, without limitation, ERISA, Environmental Laws, the USA PATRIOT Act and the other laws and regulations that are referred to in Section 5.16, and will obtain and maintain in effect all licenses, certificates, permits, franchises and other governmental authorizations necessary to the ownership of its properties, including the Project, or to the conduct of its business, in each case to the extent necessary to ensure that non-compliance with such laws, ordinances or governmental rules or regulations or failures to obtain or maintain in effect such licenses, certificates, permits, franchises and other governmental authorizations could not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect.

Section 9.2.Insurance.  The Company will maintain, directly or through its Parent, with financially sound and reputable insurers, insurance with respect to the Company’s properties, including the Project, and businesses against such casualties and contingencies, of such types, on such terms and in such amounts (including deductibles, co-insurance and self-insurance, if adequate reserves are maintained with respect thereto) as is customary in the case of entities of established reputations engaged in the same or a similar business and similarly situated and is reasonably satisfactory to the holders of the Notes (it being understood that, for the avoidance of doubt, as of the date of the Closing, the insurance the evidence of which shall have been provided pursuant to Section 4.14 is reasonably satisfactory to the holders of the Notes).

Section 9.3.Maintenance of Properties.  The Company shall (a) maintain and preserve the Project and all of its other material properties necessary or useful in the proper conduct of its business in good working order and condition (ordinary wear and tear excepted), in accordance with Prudent Industry Practices and the Material Project Documents, and (b) operate (or cause to be operated) the Facility in accordance with Prudent Industry Practices and the Material Project Documents.

Section 9.4.Payment of Taxes and Claims.  The Company will, or will use reasonable best efforts to cause the Ultimate Parent or the Parent to, file all tax returns required to be filed in any jurisdiction and to pay and discharge all taxes shown to be due and payable on such returns and all other taxes, assessments, governmental charges, or levies imposed on the Company or any of its properties, assets, income or franchises, to the extent the same have become due and payable and before they have become delinquent and all claims for which sums have become due and payable that have or might become a Lien on properties or assets of the Company, provided that the Company need not pay any such tax, assessment, charge, levy or claim if (i) the amount, applicability or validity thereof is contested by the Company on a timely basis in good faith and in appropriate proceedings, and the Company has established adequate reserves therefor in accordance with GAAP on the books of the Company or (ii) the nonpayment of all such taxes, assessments, charges, levies and claims in the aggregate could not reasonably be expected to have a Material Adverse Effect.

Section 9.5.Existence. Subject to Section 10.5, the Company will at all times preserve and keep in full force and effect its legal existence as a Oregon limited liability company.  The Company will at all times preserve and keep in full force and effect all rights and franchises of the Company unless, in the good faith judgment of the Company, the termination of or failure to preserve and keep in full force and effect such limited liability company existence, right or franchise could not, individually or in the aggregate, have a Material Adverse Effect.

Section 9.6.Books and Records.  The Company will maintain proper books of record and account in conformity with GAAP and all applicable requirements of any Governmental Authority having legal or regulatory jurisdiction over the Company.

Section 9.7.Environmental Matters.  The Company shall (a) comply in all material respects with all Environmental Laws, including, without limitation, any consents, permits, licenses, certifications or authorizations required under any Environmental Laws, and (b) conduct and complete any investigation, study, sampling and testing, and undertake any corrective, cleanup, removal, response, remedial or other action necessary to identify, report, remove and clean up all Hazardous Materials released at, on, in, under or from the Facility, to the extent required by and in accordance with the material requirements of all applicable Environmental Laws in full force and effect at such time.

Section 9.8.Further Assurances.  Without limiting the provisions contained in the Security Documents, (i) the Company shall take all actions necessary to insure that the Collateral Agent, on behalf of the Secured Parties, has and continues to have in all relevant jurisdictions duly and validly created, attached, perfected and enforceable first priority Liens on the Collateral described in the Security Documents (including after-acquired Collateral), subject to no Liens and (ii) the Company shall cause the Obligations to constitute direct senior secured obligations of the Company and to rank pari passu in priority of payment with all other permitted senior Indebtedness of the Company except for Permitted Indebtedness.

Section 9.9.Project Documents.  The Company shall at all times (i) perform and observe all of the covenants under the Material Project Documents and all Other Project Documents that are Material to the operation and maintenance of the Facility, (ii) take reasonable actions to enforce all rights and obligations thereunder, and (iii) maintain such Project Documents in full force and effect.

Section 9.10.Debt Service Reserve Account.  The Company shall establish and maintain the Debt Service Reserve Account with the Securities Intermediary, in accordance with the Security Agreement and the Control Agreement, and shall fund the Debt Service Reserve Account as required in the Security Agreement.  All amounts held in the Debt Service Reserve Account shall be held in cash or in Cash Equivalents.  If, in accordance with the provisions of the Security Agreement, the Collateral Agent instructs the Securities Intermediary to withdraw amounts credited to the Debt Service Reserve Account in respect of Debt Service payments, the Company shall replenish such amounts in accordance with the provisions of the Security Agreement.

Section 9.11.Covenant to Secure Notes Equally.  The Company will, if it shall create or assume any Lien upon any of its property or assets, whether now owned or hereafter acquired, other than Liens permitted by the provisions of Section 10.3 (unless prior written consent to the creation or assumption thereof shall have been obtained pursuant to Section 17.1), make or cause to be made effective provision whereby the Notes will be secured by such Lien equally and ratably with any and all other Indebtedness thereby secured pursuant to such agreements and instruments as shall be approved by the Required Holder(s), and the Company will cause to be delivered to each holder an opinion of independent counsel to the effect that such instruments and agreements are enforceable in accordance with their terms and that the Notes are equally and ratably secured with such other Indebtedness; provided that the creation and maintenance of such equal and ratable Lien shall not in any way limit or modify the right of the holders of the Notes to enforce the provisions of Section 10.3.

SECTION 10.   NEGATIVE COVENANTS.

The Company covenants that so long as any of the Notes are outstanding:

Section 10.1.Financial Covenants.

(a)Indebtedness.  The Company will not create, incur, assume or otherwise become liable with respect to any Indebtedness (other than Permitted Indebtedness) after the date of Closing and prior to April 1, 2013.The Company will not create, incur, assume or otherwise become liable with respect to any Indebtedness on or after April 1, 2013 (other than Permitted Indebtedness) unless on the date the Company becomes liable with respect to any such Indebtedness and immediately after giving effect thereto:

(i)no Default or Event of Default exists or would exist, and

(ii)the ratio of (A) the total amount of Indebtedness of the Company then outstanding to (B) Adjusted EBITDA for the period of four consecutive fiscal quarters most recently ended, would be less than or equal to the following ratios for the indicated periods:

Period                                                                           Ratio

April 1, 2013 through March 31, 2015                                                                           5.50 to 1.00

April 1, 2015 and thereafter                                                                                      5.00 to 1.00.

(b)Minimum Adjusted EBITDA.

(i)The Company will not permit, at the end of any fiscal quarter, Adjusted EBITDA for such fiscal quarter to be less than the amounts set forth below:

Period                                                                           Minimum Adjusted EBITDA

January 1, 2012 through March 31, 2013                                                                                      as set forth in clause (ii)below

April 1, 2013 through March 31, 2014                                                                           $750,000

April 1, 2014 through March 31, 2015                                                                           $1,000,000

April 1, 2015 and thereafter                                                                                      $1,250,000

(ii)The Company will not permit, at the end of any fiscal period set forth below, EBITDA for such period to be less than the amounts set forth below:

Period                                                                           Minimum Adjusted EBITDA

January 1, 2012 through March 31, 2012                                                                                     $0

January 1, 2012 through June 30, 2012                                                                           $1,000,000

January 1, 2012 through September 30, 2012                                                                                     $1,500,000

January 1, 2012 through December 31, 2012                                                                                     $2,000,000

March 31, 2012 through March 31, 2013                                                                                     $2,000,000

(iii)Notwithstanding the foregoing, the minimum Adjusted EBITDA thresholds set forth in this Section 10.1(b) for fiscal quarters ending after December 31, 2013 shall be reduced by 75% of (A) the amount of all Indebtedness of the Company prepaid during such period (and, in the case of Indebtedness outstanding under a revolving credit or similar facility, only to the extent that the commitment of the lender or lenders under such facility is permanently reduced in connection with such prepayment), divided by (B) the total amount of Indebtedness of the Company outstanding immediately prior to such prepayment.

Section 10.2.Restricted Payments.  The Company will not at any time declare or make, or become obligated to declare or make, any Restricted Payment; provided that:

(a)so long as no Default or Event of Default shall have occurred and be continuing or would result therefrom, with respect to each fiscal year of the Company, commencing with the fiscal year ending December 31, 2011, the Company may make Restricted Payments to the Ultimate Parent, the Parent and their Affiliates within 15 days prior to the time that federal and state income taxes (or estimated federal and state income taxes) are due and payable by the Ultimate Parent, the Parent and their Affiliates (up to and including October 15 of the succeeding calendar year), in an aggregate amount not to exceed the amount required to be distributed by the Company to its members for the payment of taxes with respect to income of the Company; and

(b)so long as no Default or Event of Default shall have occurred and be continuing or would result therefrom, the Company shall be permitted to make Restricted Payments on the 15th day following the delivery by the Company of the financial statements and related deliverables pursuant to Sections 7.1(a) or 7.1(b), as the case may be, in respect of the most recently ended fiscal quarter or fiscal year, as the case may be, of the Company (each such payment date, a “Restricted Payment Date”), subject to the following conditions:

(i)the ratio of (A) Adjusted EBITDA to (B) Interest Expense plus Capital Expenditures for the period of four consecutive fiscal quarters most recently ended, is greater than 1.50 to 1.00; and

(ii)for each of the preceding eight consecutive fiscal quarters, Adjusted EBITDA for the period of four consecutive fiscal quarters ending on the last day of each of such preceding fiscal quarter is greater than $5,000,000.

(c)Notwithstanding the foregoing, nothing contained in this Section 10.2 shall prohibit the Company from making, or shall take into account, the Permitted Closing Distributions.

Section 10.3.Liens.  The Company will not directly or indirectly create, incur, assume or permit to exist (upon the happening of a contingency or otherwise) any Lien on or with respect to any property or asset (including, without limitation, any document or instrument in respect of goods or accounts receivable) of the Company, whether now owned or held or hereafter acquired, or any income or profits therefrom, or assign or otherwise convey any right to receive income or profits, except:

(a)Liens created by the Financing Documents on the Collateral;

(b)Liens for taxes, assessments or other governmental charges which are not yet due and payable or the payment of which is not at the time required by Section 9.4;

(c)statutory Liens of landlords, banks (and rights of set-off), of carriers, warehousemen, mechanics, repairmen, workmen and materialmen, and other Liens imposed by law, in each case incurred in the ordinary course of business (i) for amounts not yet overdue or (ii) for amounts that are overdue and that are being contested in good faith by appropriate proceedings, so long as such reserves or other appropriate provisions, if any, as shall be required by GAAP shall have been made for any such contested amounts;

(d)Liens (other than any Lien imposed by ERISA) incurred, or deposits made, in the ordinary course of business (i) in connection with workers’ compensation, unemployment insurance and other types of social security or retirement benefits, or (ii) to secure (or to obtain letters of credit that secure) the performance of tenders, statutory obligations, surety bonds, appeal bonds (not in excess of $1,000,000), bids, leases (other than Capital Leases), purchase, construction or sales contracts and other similar obligations, in each case not incurred or made in connection with the borrowing of money, the obtaining of advances or credit or the payment of the deferred purchase price of property;

(e)any attachment or judgment Lien, unless the judgment it secures (i) shall not, within 30 days after the entry thereof, have been discharged or execution thereof stayed pending appeal, or shall not have been discharged within 30 days after the expiration of any such stay or (ii) excess of $1,000,000;

(f)minor defects, easements, rights-of-way, minor survey exceptions, restrictions and other similar charges or encumbrances, in each case incidental to, and not interfering with, the ordinary conduct of the business of the Company; provided that such Liens do not, in the aggregate, materially detract from the value of the property or assets so encumbered or materially impair the use thereof in the operation of the business of the Company;

(g)any interest or title or other reservation or right of, or restriction by, a lessor or sublessor under any lease; provided that such reservations, rights or restrictions do not, in the aggregate, materially detract from the value of the property or assets so encumbered or materially impair the use thereof in the operation of the business of the Company;

(h)Liens constituting rights of any lessee, easement or license holder (or a holder of similar rights) under any lease, easement or license (or similar instrument) granted by the Company not in violation of the terms of any Financing Document; provided that such Liens do not, in the aggregate, materially detract from the value of the property or assets so encumbered or materially impair the use thereof in the operation of the business of the Company;

(i)purported Liens evidenced by the filing of precautionary UCC financing statements relating solely to operating leases of personal property entered into in the ordinary course of business;

(j)any zoning or similar law or right reserved to or vested in any governmental office or agency to control or regulate the use of any real property; provided that such rights do not, in the aggregate, materially detract from the value of the property or assets so encumbered or materially impair the use thereof in the operation of the business of the Company;

(k)Liens securing Permitted Indebtedness; provided that any such Lien shall encumber only the asset acquired with the proceeds of such Indebtedness; and

(l)with respect to the Pledged Collateral, restrictions on the transfer of such Collateral under the Security Act or any applicable state “blue sky” laws.

Section 10.4.Sale of Assets, Etc.  Except for transactions permitted by Section 10.5, the Company will not sell, exchange, convey, lease or otherwise transfer or dispose (or agree or otherwise commit to do any of the foregoing with respect to) any of its assets, except:

(a)the sale of inventory in the ordinary course of business;

(b)the transfer or disposition of assets that are surplus, worn out or obsolete or are no longer necessary or productive in the ordinary course of the Company’s business; and

(c)sales, leases or other transfers of other assets for aggregate consideration of less than (i) $100,000 in any twelve-month period and (ii) $300,000 in the aggregate after the date of Closing.

Section 10.5.Merger, Consolidation, Etc.  The Company will not consolidate with or merge with any other Person or convey, transfer or lease all or substantially all of its assets in a single transaction or series of transactions to any Person unless:

(a)the successor (the “Successor Company”) formed by such consolidation or the survivor of such merger or the Person that acquires by conveyance, transfer or lease all or substantially all of the assets of the Company as an entirety, as the case may be, shall be a Solvent corporation or limited liability company organized and existing under the laws of the United States or any state thereof (including the District of Columbia), and, if the Company is not the Successor Company, (i) such Successor Company shall have executed and delivered to each holder of any Notes its assumption of the due and punctual performance and observance of each covenant and condition of this Agreement, the Notes and each other Financing Document to which the Company is a party and (ii) such corporation or limited liability company shall have caused to be delivered to each holder of any Notes an opinion of nationally recognized independent counsel, or other independent counsel reasonably satisfactory to the Required Holders, to the effect that all agreements or instruments effecting such assumption are enforceable in accordance with their terms and comply with the terms hereof;

(b)immediately before and immediately after giving effect to such transaction, no Default or Event of Default shall have occurred and be continuing; and

(c)the Tangible Net Worth of the Successor Company shall be at least as great as the Tangible Net Worth of the Company immediately prior to such consolidation, merger, conveyance, transfer or lease.

No such conveyance, transfer or lease of substantially all of the assets of the Company shall have the effect of releasing the Company or any Successor Company that shall theretofore have become such in the manner prescribed in this Section 10.5 from its liability under this Agreement, the Notes or any other Financing Document to which the Company or such Successor Company is a party.

Section 10.6.Loans, Advances, Investments and Contingent Liabilities.  The Company will not make or permit to remain outstanding any loan or advance to, or extend credit other than credit extended in the ordinary course of business to, any Person, or own, purchase or acquire any stock, obligations or securities of, or any other interest in, or make any capital contribution to, any Person, or commit to do any of the foregoing, except Permitted Investments.

Section 10.7.Sale-and-Leasebacks.  The Company will not enter into any Sale-and-Leaseback Transaction.

Section 10.8.Sale or Discount of Receivables.  The Company will not sell with recourse, or discount or otherwise sell for less than the face value thereof, any of its notes or accounts receivable.

Section 10.9.Transactions with Affiliates.  Except as set forth in Schedule 10.9, the Company will not enter into directly or indirectly any transaction or group of related transactions (including without limitation the purchase, lease, sale or exchange of properties of any kind or the rendering of any service) with any Affiliate, except pursuant to the reasonable requirements of the Company’s business and upon fair and reasonable terms no less favorable to the Company than would be obtainable in a comparable arm’s-length transaction with a Person not an Affiliate.

Section 10.10.Line of Business.  The Company will not engage in any business other than the ownership of the Project, the operation of the Facility, the sale of gas storage and other Facility related services.

Section 10.11.Subsidiaries.  The Company will not create or acquire any Subsidiary of the Company.

Section 10.12.Terrorism Sanctions Regulations.  The Company will not and will not permit any Controlled Entity to (a) become a Blocked Person or (b) have any investments in or engage in any dealings or transactions with any Blocked Person if such investments, dealings or transactions would cause any holder of a Note to be in violation of any laws or regulations that are applicable to such holder.

Section 10.13.Most Favored Lender Status.  The Company will not enter into, assume or otherwise be bound or obligated under any agreement creating or evidencing Indebtedness in excess of $1,000,000 containing one or more Additional Covenants (other than those in existence on the date hereof) or Additional Defaults (other than those in existence on the date hereof), unless prior written notice of such agreement shall have been provided to the holders of the Notes.  Unless the Company shall enter into, assume or otherwise become bound by or obligated under any such agreement with the prior written waiver by the Required Holders of the application of this Section 10.13, the terms of this Agreement shall, without any further action on the part of the Company or any of the holders of the Notes, be deemed to be amended automatically to include each Additional Covenant and each Additional Default contained in such agreement.  The Company further covenants to promptly execute and deliver at its expense (including the reasonable fees and expenses of counsel for the holders of the Notes) an amendment to this Agreement in form and substance satisfactory to the Required Holders evidencing the amendment of this Agreement to include such Additional Covenants and Additional Defaults, provided that the execution and delivery of such amendment shall not be a precondition to the effectiveness of such amendment as provided for in this Section 10.13, but shall merely be for the convenience of the parties hereto.

Section 10.14.Restrictions on Amendments to Certain Agreements.  The Company will not amend or modify (a) the Base Gas Lease in any material respect or (b) any PG&E Contract in any manner that could reasonably be expected to have a Material Adverse Effect.

SECTION 11.   EVENTS OF DEFAULT.

An “Event of Default” shall exist if any of the following conditions or events shall occur and be continuing:

(a)the Company defaults in the payment of any principal or Make-Whole Amount. Premium or Breakage Cost Obligation, if any, on any Note when the same becomes due and payable, whether at maturity or at a date fixed for prepayment or by declaration or otherwise; or

(b)the Company defaults in the payment of any interest on any Note for more than five days after the same becomes due and payable; or

(c)the Company defaults in the performance of or compliance with any term contained in Sections 7.1(d), 9.2, 9.10 or Section 10; or

(d)the Company defaults in the performance of or compliance with any term contained herein (other than those referred to in Sections 11(a), (b) and (c)), or the Company or the Parent defaults in the performance of or compliance with any term contained in any other Financing Document, and in either case such default is not remedied within 30 days after the earlier of (i) a Responsible Officer obtaining actual knowledge of such default and (ii) the Company receiving written notice of such default from the Collateral Agent or any holder of a Note (any such written notice to be identified as a “notice of default” and to refer specifically to this Section 11(d)); or

(e)any representation or warranty made in writing by or on behalf of the Company or the Parent, or by any officer of the Company or the Parent, in this Agreement or any other Financing Documents or in any writing furnished in connection with the transactions contemplated hereby proves to have been false or incorrect in any material respect on the date as of which made; or

(f)(i) the Company is in default (as principal or as guarantor or other surety) in the payment of any principal of or premium or make-whole amount or interest on any Indebtedness that is outstanding in an aggregate principal amount of at least $500,000 beyond any period of grace provided with respect thereto, or (ii) the Company is in default in the performance of or compliance with any term of any evidence of any Indebtedness in an aggregate outstanding principal amount of at least $500,000 or of any mortgage, indenture or other agreement relating thereto or any other condition exists, and as a consequence of such default or condition such Indebtedness has become, or has been declared (or one or more Persons are entitled to declare such Indebtedness to be), due and payable before its stated maturity or before its regularly scheduled dates of payment, or (iii) as a consequence of the occurrence or continuation of any event or condition (other than the passage of time or the right of the holder of Indebtedness to convert such Indebtedness into equity interests), (x) the Company or an Affiliate has become obligated to purchase or repay Indebtedness before its regular maturity or before its regularly scheduled dates of payment in an aggregate outstanding principal amount of at least $500,000, or (y) one or more Persons have the right to require the Company or an Affiliate so to purchase or repay such Indebtedness; or

(g)the Company or the Parent(i) is generally not paying, or admits in writing its inability to pay, its debts as they become due, (ii) files, or consents by answer or otherwise to the filing against it of, a petition for relief or reorganization or arrangement or any other petition in bankruptcy, for liquidation or to take advantage of any bankruptcy, insolvency, reorganization, moratorium or other similar law of any jurisdiction, (iii) makes an assignment for the benefit of its creditors, (iv) consents to the appointment of a custodian, receiver, trustee or other officer with similar powers with respect to it or with respect to any substantial part of its property, (v) is adjudicated as insolvent or to be liquidated, or (vi) takes limited liability company action for the purpose of any of the foregoing; or

(h)a court or Governmental Authority of competent jurisdiction enters an order appointing, without consent by the Company or the Parent, a custodian, receiver, trustee or other officer with similar powers with respect to it or with respect to any substantial part of its property, or constituting an order for relief or approving a petition for relief or reorganization or any other petition in bankruptcy or for liquidation or to take advantage of any bankruptcy or insolvency law of any jurisdiction, or ordering the dissolution, winding-up or liquidation of the Company, or any such petition shall be filed against the Company and such petition shall not be dismissed within 60 days; or

(i)a final judgment or judgments for the payment of money aggregating in excess of $500,000 are rendered against the Company and which judgments are not, within 30 days after entry thereof, bonded, discharged or stayed pending appeal, or are not discharged within 30 days after the expiration of such stay; or

(j)any Lien granted to the Collateral Agent pursuant to any of the Financing Documents on any of the Collateral is invalid, void, unenforceable or unperfected or ceases to have first priority, or any Person commences any proceeding or takes any other action to render any such Lien invalid, or to avoid any such Lien or to render any such Lien unenforceable or unperfected or to challenge the priority of such Lien; or

(k)an Event of Abandonment occurs; or

(l)any Financing Document, at any time after its execution and delivery and for any reason other than as expressly permitted hereunder or thereunder or satisfaction in full of all obligations of the Company or the Parent, as the case may be, hereunder and under any of the other Financing Documents, ceases to be in full force and effect; or the Company, the Parent or any other Person contests in any manner the validity or enforceability of any Financing Document; or the Company or the Parent party to any of the Financing Documents denies that it has any or further liability or obligation under any Financing Document, or purports to revoke, terminate or rescind any Financing Document; or

(m)if (i) any Plan shall fail to satisfy the minimum funding standards of ERISA or the Code for any plan year or part thereof or a waiver of such standards or extension of any amortization period is sought or granted under section 412 or 431 of the Code, as applicable, (ii) a notice of intent to terminate any Plan that is subject to Title IV of ERISA shall have been or is reasonably expected to be filed with the PBGC or the PBGC shall have instituted proceedings under ERISA section 4042 to terminate or appoint a trustee to administer any Plan or the PBGC shall have notified the Company or any ERISA Affiliate that a Plan may become a subject of any such proceedings, (iii) the present value of the aggregate benefit liabilities under all Plans (except any Multiemployer Plan) exceeds the current value of the assets of such Plans by more than the applicable amount set forth in Section 5.12(b), as determined in accordance with Section 5.12(b), (iv) the Company or any ERISA Affiliate shall have incurred or is reasonably expected to incur any liability pursuant to Title IV of ERISA or the penalty or excise tax provisions of the Code relating to employee benefit plans, (v) the Company or any ERISA Affiliate withdraws from any Multiemployer Plan, or (vi) the Company establishes or amends any employee welfare benefit plan that provides post-employment welfare benefits in a manner that would increase the liability of the Company thereunder; and any such event or events described in clauses (i) through (vi) above, either individually or together with any other such event or events, could reasonably be expected to have a Material Adverse Effect.

As used in Section 11(m), the terms “employee benefit plan” and “employee welfare benefit plan” shall have the respective meanings assigned to such terms in section 3 of ERISA.

SECTION 12.   REMEDIES ON DEFAULT, ETC.

Section 12.1.Acceleration.

(a)If an Event of Default with respect to the Company described in Section 11(g) or (h) (other than an Event of Default described in clause (i) of Section 11(g) or described in clause (vi) of Section 11(g) by virtue of the fact that such clause encompasses clause (i) of Section 11(g)) has occurred, all the Notes then outstanding shall automatically become immediately due and payable.

(b)If any other Event of Default has occurred and is continuing, any holder or holders of more than 51% in principal amount of the Notes at the time outstanding may at any time at its or their option, by notice or notices to the Company, declare all the Notes then outstanding to be immediately due and payable.

(c)If any Event of Default described in Section 11(a) or (b) has occurred and is continuing, any holder or holders of Notes at the time outstanding affected by such Event of Default may at any time, at its or their option, by notice or notices to the Company, declare all the Notes held by it or them to be immediately due and payable.

Upon any Notes becoming due and payable under Section 12.1(a) or Section 12.1(b), whether automatically or by declaration, such Notes will forthwith mature and the entire unpaid principal amount of such Notes, plus (x) all accrued and unpaid interest thereon (including, but not limited to, interest accrued thereon at the Default Rate), (y) any Make-Whole Amount determined in respect of such principal amount of Fixed-Rate Notes (to the full extent permitted by applicable law) and (z) any Breakage Cost Obligations and any Premium determined in respect of such principal amount of Floating-Rate Notes (to the full extent permitted by applicable law), shall all be immediately due and payable, in each and every case without presentment, demand, protest or further notice, all of which are hereby waived, and the Required Holders may instruct the Collateral Agent to exercise rights and remedies available to it under applicable law and the Security Documents.  The Company acknowledges, and the parties hereto agree, that each holder of a Note has the right to maintain its investment in the Notes free from repayment by the Company (except as herein specifically provided for) and that the provision for payment of a Make-Whole Amount or a Premium by the Company in the event that the Notes are prepaid or are accelerated as a result of an Event of Default, is intended to provide compensation for the deprivation of such right under such circumstances.

Upon any Notes becoming due and payable under Section 12.1(c), such Notes will forthwith mature and the entire unpaid principal amount of such Notes plus all accrued and unpaid interest thereon (including, but not limited to, interest accrued thereon at the Default Rate, but excluding any Make-Whole Amount or a Premium) shall be immediately due and payable, in each and every case without presentment, demand, protest or further notice, all of which are hereby waived.

Section 12.2.Other Remedies.  If any Default or Event of Default has occurred and is continuing, and irrespective of whether any Notes have become or have been declared immediately due and payable under Section 12.1, the holder of any Note at the time outstanding may proceed to protect and enforce the rights of such holder by an action at law, suit in equity or other appropriate proceeding, whether for the specific performance of any agreement contained herein or in any Note, or for an injunction against a violation of any of the terms hereof or thereof, or in aid of the exercise of any power granted hereby or thereby or by law or otherwise.

Section 12.3.Rescission.  At any time after any Notes have been declared due and payable pursuant to Section 12.1(b) or (c), the holders of not less than 51%in principal amount of the Notes then outstanding, by written notice to the Company, may rescind and annul any such declaration and its consequences if (a) the Company has paid all overdue interest on the Notes, all principal of and any Make-Whole Amount, Premium or Breakage Cost Obligation on any Notes that are due and payable and are unpaid other than by reason of such declaration, and all interest on such overdue principal and any Make-Whole Amount, Premium or Breakage Cost Obligation and (to the extent permitted by applicable law) any overdue interest in respect of the Notes, at the Default Rate, (b) neither the Company nor any other Person shall have paid any amounts which have become due solely by reason of such declaration, (c) all Events of Default and Defaults, other than non-payment of amounts that have become due solely by reason of such declaration, have been cured or have been waived pursuant to Section 17, and (d) no judgment or decree has been entered for the payment of any monies due pursuant hereto or to the Notes.  No rescission and annulment under this Section 12.3 will extend to or affect any subsequent Event of Default or Default or impair any right consequent thereon.

Section 12.4.No Waivers or Election of Remedies, Expenses, Etc.  No course of dealing and no delay on the part of any holder of any Note in exercising any right, power or remedy shall operate as a waiver thereof or otherwise prejudice such holder’s rights, powers or remedies.  No right, power or remedy conferred by this Agreement or by any Note upon any holder thereof shall be exclusive of any other right, power or remedy referred to herein or therein or now or hereafter available at law, in equity, by statute or otherwise.  Without limiting the obligations of the Company under Section 15, the Company will pay to the holder of each Note on demand such further amount as shall be sufficient to cover all costs and expenses of such holder incurred in any enforcement or collection under this Section 12, including, without limitation, reasonable attorneys’ fees, expenses and disbursements.

SECTION 13.   REGISTRATION; EXCHANGE; SUBSTITUTION OF NOTES.

Section 13.1.Registration of Notes.  The Company shall keep at its principal executive office a register for the registration and registration of transfers of Notes.  The name and address of each holder of one or more Notes, each transfer thereof and the name and address of each transferee of one or more Notes shall be registered in such register.  If any holder of one or more Notes is a nominee, then the name and address of the beneficial owner of such Note or Notes shall also be registered in such register as an owner and holder thereof.  Prior to due presentment for registration of transfer, the Person(s) in whose name any Note(s) shall be registered shall be deemed and treated as the owner and holder thereof for all purposes hereof, and the Company shall not be affected by any notice or knowledge to the contrary.  The Company shall give to any holder of a Note that is an Institutional Investor promptly upon request therefor, a complete and correct copy of the names and addresses of all registered holders of Notes.

Section 13.2.Transfer and Exchange of Notes.  Upon surrender of any Note to the Company at the address and to the attention of the designated officer (all as specified in Section 18(iii)), for registration of transfer or exchange (and in the case of a surrender for registration of transfer accompanied by a written instrument of transfer duly executed by the registered holder of such Note or such holder’s attorney duly authorized in writing and accompanied by the relevant name, address and other information for notices of each transferee of such Note or part thereof), within ten Business Days thereafter, the Company shall execute and deliver, at the Company’s expense (except as provided below), one or more new Notes (as requested by the holder thereof) in exchange therefor, in an aggregate principal amount equal to the unpaid principal amount of the surrendered Note.  Each such new Note shall be payable to such Person as such holder may request and shall be substantially in the form of Exhibit A-1 (if the surrendered Note is a Fixed-Rate Note) or Exhibit A-2 (if the surrendered Note is a Floating-Rate Note).  Each such new Note shall be dated and bear interest from the date to which interest shall have been paid on the surrendered Note or dated the date of the surrendered Note if no interest shall have been paid thereon.  The Company may require payment of a sum sufficient to cover any stamp tax or governmental charge imposed in respect of any such transfer of Notes.  Notes shall not be transferred in denominations of less than $100,000, provided that if necessary to enable the registration of transfer by a holder of its entire holding of Notes, one Note may be in a denomination of less than $100,000.  Any transferee, by its acceptance of a Note registered in its name (or the name of its nominee), shall be deemed to have made the representation set forth in Section 6.2.

Section 13.3.Replacement of Notes.  Upon receipt by the Company at the address and to the attention of the designated officer (all as specified in Section 18(iii)) of evidence reasonably satisfactory to it of the ownership of and the loss, theft, destruction or mutilation of any Note (which evidence shall be, in the case of an Institutional Investor, notice from such Institutional Investor of such ownership and such loss, theft, destruction or mutilation), and

(a)in the case of loss, theft or destruction, of indemnity reasonably satisfactory to it (provided that if the holder of such Note is, or is a nominee for, an original Purchaser or another holder of a Note with a minimum net worth of at least $100,000,000or a Qualified Institutional Buyer, such Person’s own unsecured agreement of indemnity shall be deemed to be satisfactory), or

(b)in the case of mutilation, upon surrender and cancellation thereof,

within ten Business Days thereafter, the Company at its own expense shall execute and deliver, in lieu thereof, a new Note, dated and bearing interest from the date to which interest shall have been paid on such lost, stolen, destroyed or mutilated Note or dated the date of such lost, stolen, destroyed or mutilated Note if no interest shall have been paid thereon.

SECTION 14.   PAYMENTS ON NOTES.

Section 14.1.Place of Payment.  Subject to Section 14.2, payments of principal, any Make-Whole Amount, any Premium, any Breakage Cost Obligation and interest becoming due and payable on the Notes shall be made in New York, New York at the principal office of JPMorgan Chase Bank, N.A. in such jurisdiction.  The Company may at any time, by notice to each holder of a Note, change the place of payment of the Notes so long as such place of payment shall be either the principal office of the Company in such jurisdiction or the principal office of a bank or trust company in such jurisdiction.

Section 14.2.Home Office Payment.  So long as any Purchaser or its nominee shall be the holder of any Note, and notwithstanding anything contained in Section 14.1 or in such Note to the contrary, the Company will pay all sums becoming due on such Note for principal, Make-Whole Amount, Premium or Breakage Cost Obligation, as applicable, and interest by the method and at the address specified for such purpose below such Purchaser’s name in Schedule A-1, or by such other method or at such other address as such Purchaser shall have from time to time specified to the Company in writing for such purpose, without the presentation or surrender of such Note or the making of any notation thereon, except that upon written request of the Company made concurrently with or reasonably promptly after payment or prepayment in full of any Note, such Purchaser shall surrender such Note for cancellation, reasonably promptly after any such request, to the Company at its principal executive office or at the place of payment most recently designated by the Company pursuant to Section 14.1.  Prior to any sale or other disposition of any Note held by a Purchaser or its nominee, such Purchaser will, at its election, either endorse thereon the amount of principal paid thereon and the last date to which interest has been paid thereon or surrender such Note to the Company in exchange for a new Note or Notes pursuant to Section 13.2.  The Company will afford the benefits of this Section 14.2 to any Institutional Investor that is the direct or indirect transferee of any Note purchased by a Purchaser under this Agreement and that has made the same agreement relating to such Note as the Purchasers have made in this Section 14.2.

SECTION 15.   EXPENSES, ETC.

Section 15.1.Transaction Expenses.  Whether or not the transactions contemplated hereby are consummated, the Company will pay all reasonable costs and expenses (including reasonable attorneys’ fees of a special counsel and, if reasonably required by the Required Holders, local or special regulatory counsel, which, in each case, shall be no more than one law firm) incurred by the Collateral Agent, the Purchasers and each other holder of a Note in connection with such transactions and in connection with any amendments, waivers or consents requested by the Company under or in respect of this Agreement, the Notes or any other Financing Document (whether or not such amendment, waiver or consent becomes effective), including, without limitation: (a) the costs and expenses reasonably incurred in enforcing or defending (or determining whether or how to enforce or defend) any rights under this Agreement , the Notes or any other Financing Document or in responding to any subpoena or other legal process or informal investigative demand issued in connection with this Agreement, the Notes or any other Financing Document, or by reason of being a holder of any Note, (b) the costs and expenses, including financial advisors’ fees, incurred in connection with the insolvency or bankruptcy of the Company or the Parent or in connection with any work-out or restructuring of the transactions contemplated hereby and by the Notes and (c) the costs and expenses incurred in connection with the initial filing of this Agreement and all related documents and financial information with the SVO provided, that such costs and expenses under this clause (c) shall not exceed $7,500.  The Company will pay, and will save each Purchaser and each other holder of a Note harmless from, all claims in respect of any fees, costs or expenses, if any, of brokers and finders (other than those, if any, retained by a Purchaser or other holder in connection with its purchase of the Notes).

Section 15.2.Indemnification.  The Company agrees:

(i)TO INDEMNIFY THE COLLATERAL AGENT, THE PURCHASERS, EACH OTHER HOLDER OF A NOTE AND EACH OF THEIR AFFILIATES, SUCCESSORS, ASSIGNS OR TRANSFEREES AND EACH OF THEIR OFFICERS, DIRECTORS, EMPLOYEES, SHAREHOLDERS, REPRESENTATIVES, CONSULTANTS, AGENTS, ATTORNEYS, CONTRACTORS, PARTNERS, ACCOUNTANTS AND EXPERTS (“INDEMNIFIED PARTIES”) FROM, HOLD EACH OF THEM HARMLESS AGAINST AND PROMPTLY UPON DEMAND PAY OR REIMBURSE EACH OF THEM FOR, ANY AND ALL LIABILITIES, OBLIGATIONS, LOSSES, DAMAGES, PENALTIES, ACTIONS, JUDGMENTS, SUITS, CLAIMS, REASONABLE COSTS, REASONABLE EXPENSES AND DISBURSEMENTS OF ANY KIND OR NATURE WHATSOEVER (INCLUDING THE REASONABLE FEES AND DISBURSEMENTS OF COUNSEL, IN CONNECTION WITH ANY INVESTIGATIVE, ADMINISTRATIVE OR JUDICIAL PROCEEDING COMMENCED OR THREATENED) WHICH MAY BE INCURRED BY OR ASSERTED AGAINST OR INVOLVE ANY OF THEM (WHETHER OR NOT ANY OF THEM IS DESIGNATED A PARTY THERETO) AS A RESULT OF, ARISING OUT OF OR IN ANY WAY RELATED TO (A) ANY ACTUAL OR PROPOSED USE BY THE COMPANY OF THE PROCEEDS OF THE NOTES, (B) THE EXECUTION, DELIVERY AND PERFORMANCE OF THIS AGREEMENT AND THE OTHER FINANCING DOCUMENTS, (C) THE OPERATIONS OF THE BUSINESS OF THE COMPANY, (D) THE FAILURE OF THE COMPANY OR THE PARENT TO COMPLY WITH THE TERMS OF THIS AGREEMENT OR ANY OF THE OTHER FINANCING DOCUMENTS OR WITH ANY REQUIREMENT OF ANY GOVERNMENTAL AUTHORITY, (E) ANY INACCURACY OF ANY REPRESENTATION OR ANY BREACH OF ANY WARRANTY OF THE COMPANY OR THE PARENT SET FORTH IN THIS AGREEMENT OR ANY OTHER FINANCING DOCUMENT, (F) ANY ASSERTION THAT THE COMPANY WAS NOT ENTITLED TO RECEIVE THE PROCEEDS RECEIVED PURSUANT TO THIS AGREEMENT AND THE OTHER FINANCING DOCUMENTS OR (G) ANY OTHER ASPECT OF THE FINANCING DOCUMENTS, INCLUDING, WITHOUT LIMITATION, THE REASONABLE FEES AND DISBURSEMENTS OF COUNSEL AND ALL OTHER EXPENSES INCURRED IN CONNECTION WITH INVESTIGATING, DEFENDING OR PREPARING TO DEFEND ANY SUCH ACTION, SUIT, PROCEEDING (INCLUDING ANY INVESTIGATIONS, LITIGATIONS OR INQUIRIES) OR CLAIM AND INCLUDING ALL INDEMNITY MATTERS ARISING BY REASON OF THE NEGLIGENCE OF ANY INDEMNIFIED PARTY (EXCEPT TO THE EXTENT ANY SUCH INDEMNITY MATTERS HAVE BEEN CAUSED BY THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF SUCH INDEMNIFIED PARTY), IT BEING THE INTENT OF THE PARTIES THAT EACH INDEMNIFIED PARTY SHALL BE INDEMNIFIED FROM INDEMNITY MATTERS CAUSED BY THE NEGLIGENCE (OTHER THAN THE GROSS NEGLIGENCE), WHETHER SOLE, JOINT, CONCURRENT, CONTRIBUTORY, ACTIVE OR PASSIVE, OF SUCH INDEMNIFIED PARTY).

(ii)THE FOREGOING INDEMNITIES SHALL EXTEND TO THE INDEMNIFIED PARTIES NOTWITHSTANDING THE NEGLIGENCE OF EVERY KIND OR CHARACTER WHATSOEVER (OTHER THAN GROSS NEGLIGENCE), WHETHER ACTIVE OR PASSIVE, WHETHER AN AFFIRMATIVE ACT OR AN OMISSION, INCLUDING, WITHOUT LIMITATION, ALL TYPES OF NEGLIGENT CONDUCT (OTHER THAN GROSS NEGLIGENCE) IDENTIFIED IN THE RESTATEMENT (SECOND) OF TORTS OF ONE OR MORE OF THE INDEMNIFIED PARTIES OR BY REASON OF STRICT LIABILITY IMPOSED WITHOUT FAULT ON ANY ONE OR MORE OF THE INDEMNIFIED PARTIES.  TO THE EXTENT THAT AN INDEMNIFIED PARTY COMMITTED AN ACT OF GROSS NEGLIGENCE OR WILLFUL MISCONDUCT, THIS CONTRACTUAL OBLIGATION OF INDEMNIFICATION SHALL CONTINUE BUT SHALL ONLY EXTEND TO THE PORTION OF THE CLAIM THAT IS DEEMED TO HAVE OCCURRED BY REASON OF EVENTS OTHER THAN THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF THE INDEMNIFIED PARTY.

(iii)THE PARTIES HERETO AGREE THAT THEY SHALL NOT ASSERT ANY CLAIM AGAINST THE OTHER PARTIES ON ANY THEORY OF LIABILITY, FOR SPECIAL, INDIRECT, CONSEQUENTIAL OR PUNITIVE DAMAGES ARISING OUT OF OR OTHERWISE RELATING TO THE FINANCING DOCUMENTS, ANY OF THE TRANSACTIONS CONTEMPLATED HEREIN OR THEREIN OR THE ACTUAL OR PROPOSED USE OF THE PROCEEDS OF THE NOTES; PROVIDED, HOWEVER, THAT THE FOREGOING SHALL IN NO WAY LIMIT THE COMPANY’S PAYMENT OBLIGATIONS UNDER THE FINANCING DOCUMENTS, INCLUDING, WITHOUT LIMITATION, THE OBLIGATIONS TO PAY PRINCIPAL OF, INTEREST ON AND ANY MAKE-WHOLE AMOUNTS, PREMIUM OR BREAKAGE COST OBLIGATIONS DUE WITH RESPECT TO THE NOTES, ANY COSTS AND EXPENSES UNDER SECTION 15.1 AND THE INDEMNIFIED LIABILITIES SET FORTH IN CLAUSES (I) AND (II) ABOVE.

Section 15.3.Survival.  The obligations of the Company under this Section 15 will survive the payment or transfer of any Note, the enforcement, amendment or waiver of any provision of this Agreement, the Notes or the other Financing Documents, and the termination of this Agreement or any of the other Financing Documents.

SECTION 16.   SURVIVAL OF REPRESENTATIONS AND WARRANTIES; ENTIRE AGREEMENT.

All representations and warranties contained herein or in any other Financing Document shall survive the execution and delivery of this Agreement and the Notes, the purchase or transfer by any Purchaser of any Note or portion thereof or interest therein and the payment of any Note, and may be relied upon by any subsequent holder of a Note, regardless of any investigation made at any time by or on behalf of such Purchaser or any other holder of a Note.  All statements contained in any certificate or other instrument delivered by or on behalf of the Company pursuant to this Agreement or any other Financing Document shall be deemed representations and warranties of the Company under this Agreement.  Subject to the preceding sentence, this Agreement, the Notes and the other Financing Documents embody the entire agreement and understanding between each Purchaser and the Company and supersede all prior agreements and understandings relating to the subject matter hereof.

SECTION 17.   AMENDMENT AND WAIVER.

Section 17.1.Requirements.  This Agreement and the Notes may be amended, and the observance of any term hereof or of the Notes may be waived (either retroactively or prospectively), with (and only with) the written consent of the Company and the Required Holders, except that:

(a)no amendment or waiver of any of the provisions of Section 1, 2, 3, 4, 5, 6 or 21 hereof, or any defined term (as it is used therein), will be effective as to any Purchaser unless consented to by such Purchaser in writing; and

(b)no amendment or waiver may, without the written consent of the holder of each Note at the time outstanding, (i) subject to the provisions of Section 12 relating to acceleration or rescission, change the amount or time of any prepayment or payment of principal of, or reduce the rate or change the time of payment or method of computation of interest or of the Make-Whole Amount, Premium or Breakage Cost Obligation on the Notes, (ii) change the percentage of the principal amount of the Notes the holders of which are required to consent to any amendment or waiver or (iii) amend any of Section 8, 11(b), 12, 17 or 20.

In addition, if the Required Holders so request, the Parent shall be joined in any such amendment or waiver; provided that such joinder shall not be required for the effectiveness thereof.

Section 17.2.Solicitation of Holders of Notes.

(a)Solicitation.  The Company will provide each holder of the Notes with sufficient information, sufficiently far in advance of the date a decision is required, to enable such holder to make an informed and considered decision with respect to any proposed amendment, waiver or consent in respect of any of the provisions hereof or of the Notes.  The Company will deliver executed or true and correct copies of each amendment, waiver or consent effected pursuant to the provisions of this Section 17 to each holder of outstanding Notes promptly following the date on which it is executed and delivered by, or receives the consent or approval of, the requisite holders of Notes.

(b)Payment.  The Company will not directly or indirectly pay or cause to be paid any remuneration, whether by way of supplemental or additional interest, fee or otherwise, or grant any security or provide other credit support, to any holder of Notes as consideration for or as an inducement to the entering into by any holder of Notes of any waiver or amendment of any of the terms and provisions hereof unless such remuneration is concurrently paid, or security is concurrently granted or other credit support concurrently provided, on the same terms, ratably to each holder of Notes then outstanding even if such holder did not consent to such waiver or amendment.  For the avoidance of doubt, the foregoing shall not apply to reimbursement of expenses.

Section 17.3.Binding Effect, etc.  Any amendment or waiver consented to as provided in this Section 17 applies equally to all holders of Notes and is binding upon them and upon each future holder of any Note and upon the Company without regard to whether such Note has been marked to indicate such amendment or waiver.  No such amendment or waiver will extend to or affect any obligation, covenant, agreement, Default or Event of Default not expressly amended or waived or impair any right consequent thereon.  No course of dealing between the Company and the holder of any Note nor any delay in exercising any rights hereunder or under any Note shall operate as a waiver of any rights of any holder of such Note.

Section 17.4.Notes Held by Company, etc.  Solely for the purpose of determining whether the holders of the requisite percentage of the aggregate principal amount of Notes then outstanding approved or consented to any amendment, waiver or consent to be given under this Agreement or the Notes, or have directed the taking of any action provided herein or in the Notes to be taken upon the direction of the holders of a specified percentage of the aggregate principal amount of Notes then outstanding, Notes directly or indirectly owned by the Company or any of its Affiliates shall be deemed not to be outstanding.

Section 17.5.Expansion of the Facility.  The Joint Project Agreement contemplates that the Company and PG&E, either jointly or separately, may expand the Facility (subject to applicable regulatory requirements) beyond the current capacity of 20 Bcf through the development of another discrete formation of the storage field (the “Expansion Facility”).  The overall ownership interest of each of Gill Ranch and PG&E in the Facility and the Expansion Facility may be adjusted based on the revised allocation of the aggregate working capacity of the Facility and the Expansion Facility upon the commercial operation of the Expansion Facility.  The Company’s 75% interest in the 20 Bcf of the storage capacity of the Facility and the associated costs and revenues shall not be affected, unless the total storage capacity of the Facility is expanded, in which case its interest will be increased or diluted based on whether the Company elects to participate in the Expansion Facility and only if additional capacity is added.  Based upon the foregoing, the Purchasers agree that, in the event an Expansion Facility is commenced, the Company may provide for the execution of a common facilities agreement or other similar arrangement with an affiliate seeking to develop the Expansion Facility; provided that any Indebtedness incurred in connection with the development of the Expansion Facility shall be subject to the requirements of Sections 9.11, 10.1 and 10.3 hereof.

SECTION 18.   NOTICES.

All notices and communications provided for hereunder shall be in writing and sent (a) by telecopy if the sender on the same day sends a confirming copy of such notice by an internationally recognized overnight delivery service (charges prepaid), or (b) by registered or certified mail with return receipt requested (postage prepaid), or (c) by an internationally recognized overnight delivery service (with charges prepaid).  Any such notice must be sent:

(i)if to any Purchaser or its nominee, to such Purchaser or nominee at the address specified for such communications in Schedule A-1, or at such other address as such Purchaser or nominee shall have specified to the Company in writing,

(ii)if to any other holder of any Note, to such holder at such address as such other holder shall have specified to the Company in writing, or

(iii)if to the Company, to the Company at its address specified for such communications in Schedule A-2, or at such other address as the Company shall have specified to the holder of each Note in writing.

Notices under this Section 18 will be deemed given only when actually received.

SECTION 19.   REPRODUCTION OF DOCUMENTS.

This Agreement and all documents relating thereto, including, without limitation, (a) consents, waivers and modifications that may hereafter be executed, (b) documents received by any Purchaser at the Closing (except the Notes themselves), and (c) financial statements, certificates and other information previously or hereafter furnished to any Purchaser, may be reproduced by such Purchaser by any photographic, photostatic, electronic, digital, or other similar process and such Purchaser may destroy any original document so reproduced.  The Company agrees and stipulates that, to the extent permitted by applicable law, any such reproduction shall be admissible in evidence as the original itself in any judicial or administrative proceeding (whether or not the original is in existence and whether or not such reproduction was made by such Purchaser in the regular course of business) and any enlargement, facsimile or further reproduction of such reproduction shall likewise be admissible in evidence.  This Section 19 shall not prohibit the Company or any other holder of Notes from contesting any such reproduction to the same extent that it could contest the original, or from introducing evidence to demonstrate the inaccuracy of any such reproduction.

SECTION 20.   CONFIDENTIAL INFORMATION.

For the purposes of this Section 20, “Confidential Information” means information delivered to any Purchaser by or on behalf of the Company in connection with the transactions contemplated by or otherwise pursuant to this Agreement that is proprietary in nature whether or not marked or labeled or otherwise identified when received by such Purchaser as being confidential information of the Company, provided that such term does not include information that (a) was publicly known or otherwise known to such Purchaser prior to the time of such disclosure, (b) subsequently becomes publicly known through no act or omission by such Purchaser or any Person acting on such Purchaser’s behalf or (c) otherwise becomes known to such Purchaser other than through disclosure by the Company, or from a source actually known by such Purchaser to be bound by a confidentiality agreement with respect to such information.  Each Purchaser will maintain the confidentiality of such Confidential Information in accordance with procedures adopted by such Purchaser in good faith to protect confidential information of third parties delivered to such Purchaser, provided that such Purchaser may deliver or disclose Confidential Information to (i) its directors, officers, employees, agents, attorneys, trustees and affiliates (to the extent such disclosure reasonably relates to the administration of the investment represented by its Notes), in each case who agree to hold confidential the Confidential Information substantially in accordance with the terms of this Section 20, (ii) its auditors, financial advisors and other professional advisors who agree to hold confidential the Confidential Information substantially in accordance with the terms of this Section 20, (iii) any other holder of any Note, (iv) any Institutional Investor to which it sells or offers to sell such Note or any part thereof or any participation therein (if such Person has agreed in writing prior to its receipt of such Confidential Information to be bound by the provisions of this Section 20), (v) any Person from which it offers to purchase any Security of the Company (if such Person has agreed in writing prior to its receipt of such Confidential Information to be bound by the provisions of this Section 20), (vi) any federal or state regulatory authority having jurisdiction over such Purchaser, (vii) the NAIC or the SVO or, in each case, any similar organization, or any nationally recognized rating agency that requires access to information about such Purchaser’s investment portfolio, or (viii) any other Person to which such delivery or disclosure may be necessary or appropriate (w) to effect compliance with any law, rule, regulation or order applicable to such Purchaser, (x) in response to any subpoena or other legal process, (y) in connection with any litigation to which such Purchaser is a party or (z) if an Event of Default has occurred and is continuing, to the extent such Purchaser may reasonably determine such delivery and disclosure to be necessary or appropriate in the enforcement or for the protection of the rights and remedies under such Purchaser’s Notes and this Agreement.  Each holder of a Note, by its acceptance of a Note, will be deemed to have agreed to be bound by and to be entitled to the benefits of this Section 20 as though it were a party to this Agreement.  On reasonable request by the Company in connection with the delivery to any holder of a Note of information required to be delivered to such holder under this Agreement or requested by such holder (other than a holder that is a party to this Agreement or its nominee), such holder will enter into an agreement with the Company embodying the provisions of this Section 20.  In the event any Purchaser is requested or required to disclose any Confidential Information in connection with foregoing clause (viii) (other than subclause (viii)(z)), such Purchaser shall, unless prohibited by law, rule or regulation, provide the Company with notice of any such request or requirement so that the Company may seek a protective order or other appropriate remedy.  In the event such protective order or other remedy is not obtained and upon the Company’s written request, such Purchaser will use reasonable efforts to obtain assurances that confidential treatment will be accorded to such information and shall disclose only that portion of the Confidential Information that they are legally compelled to disclose; provided,however, that all legal fees and costs and any other expense incurred in connection with such efforts shall be paid by the Company.

In the event that as a condition to receiving access to information relating to the Company or its Affiliates in connection with the transactions contemplated by or otherwise pursuant to this Agreement, any Purchaser is required to agree to a confidentiality undertaking (whether through Intralinks or otherwise) which is different from the terms of this Section 20, the terms of this Section 20 shall, as between such Purchaser and the Company, supersede the terms of any such other confidentiality undertaking.

SECTION 21.   SUBSTITUTION OF PURCHASER.

Each Purchaser shall have the right to substitute any one of its Affiliates as the purchaser of the Notes that it has agreed to purchase hereunder, by written notice to the Company, which notice shall be signed by both such Purchaser and such Affiliate, shall contain such Affiliate’s agreement to be bound by this Agreement and shall contain a confirmation by such Affiliate of the accuracy with respect to it of the representations set forth in Section 6.  Upon receipt of such notice, any reference to such Purchaser in this Agreement (other than in this Section 21), shall be deemed to refer to such Affiliate in lieu of such original Purchaser.  In the event that such Affiliate is so substituted as a Purchaser hereunder and such Affiliate thereafter transfers to such original Purchaser all of the Notes then held by such Affiliate, upon receipt by the Company of notice of such transfer, any reference to such Affiliate as a “Purchaser” in this Agreement (other than in this Section 21), shall no longer be deemed to refer to such Affiliate, but shall refer to such original Purchaser, and such original Purchaser shall again have all the rights of an original holder of the Notes under this Agreement.

SECTION 22.   MISCELLANEOUS.

Section 22.1.Successors and Assigns.  All covenants and other agreements contained in this Agreement by or on behalf of any of the parties hereto bind and inure to the benefit of their respective successors and assigns (including, without limitation, any subsequent holder of a Note) whether so expressed or not.

Section 22.2.Payments Due on Non-Business Days.  Anything in this Agreement or the Notes to the contrary notwithstanding, except as specified in the definition of Interest Period, any payment of principal of, Make-Whole Amount, Premium, Breakage Cost Obligation or interest on or in respect of any Note that is due on a date other than a Business Day shall be made on the next succeeding Business Day without including the additional days elapsed in the computation of the interest payable on such next succeeding Business Day; provided that if the maturity date of any Note is a date other than a Business Day, the payment otherwise due on such maturity date shall be made on the next succeeding Business Day and shall include the additional days elapsed in the computation of interest payable on such next succeeding Business Day.

Section 22.3.Accounting Terms.  All accounting terms used herein which are not expressly defined in this Agreement have the meanings respectively given to them in accordance with GAAP.  Except as otherwise specifically provided herein, (i) all computations made pursuant to this Agreement shall be made in accordance with GAAP, and (ii) all financial statements shall be prepared in accordance with GAAP; provided that, if the Company notifies the holders of the Notes that the Company requests an amendment to any provision hereof to eliminate the effect of any change occurring after the date hereof in GAAP or in the application thereof on the operation of such provision (or if the Required Holders notify the Company that the Required Holders request an amendment to any provision hereof for such purpose), regardless of whether any such notice is given before or after such change in GAAP or in the application thereof, then such provision shall be interpreted on the basis of GAAP as in effect and applied immediately before such change shall have become effective until such notice shall have been withdrawn or such provision amended in accordance with Section 17.  For purposes of determining compliance with the financial covenants contained in this Agreement, any election by the Company to measure an item of Indebtedness using fair value (as permitted by Accounting Standard Codification Topic No. 825-10-25 - Fair Value Option or any similar accounting standard) shall be disregarded and such determination shall be made as if such election had not been made.

Section 22.4.Severability.  Any provision of this Agreement that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall (to the full extent permitted by law) not invalidate or render unenforceable such provision in any other jurisdiction.

Section 22.5.Construction, etc.  Each covenant contained herein shall be construed (absent express provision to the contrary) as being independent of each other covenant contained herein, so that compliance with any one covenant shall not (absent such an express contrary provision) be deemed to excuse compliance with any other covenant.  Where any provision herein refers to action to be taken by any Person, or which such Person is prohibited from taking, such provision shall be applicable whether such action is taken directly or indirectly by such Person.

For the avoidance of doubt, all Schedules and Exhibits attached to this Agreement shall be deemed to be a part hereof.

Section 22.6.Counterparts.  This Agreement may be executed in any number of counterparts, each of which shall be an original but all of which together shall constitute one instrument.  Each counterpart may consist of a number of copies hereof, each signed by less than all, but together signed by all, of the parties hereto.

Section 22.7.Governing Law.  This Agreement shall be construed and enforced in accordance with, and the rights of the parties shall be governed by, the law of the State of New York without regard to conflict of law principles other than Section 5-1401 of the New York General Obligations Law.

Section 22.8.Jurisdiction and Process; Waiver of Jury Trial.  (a) The Company irrevocably submits to the non-exclusive jurisdiction of any New York State or federal court sitting in the Borough of Manhattan, The City of New York, over any suit, action or proceeding arising out of or relating to this Agreement, the Notes or any other Financing Document.  To the fullest extent permitted by applicable law, the Company irrevocably waives and agrees not to assert, by way of motion, as a defense or otherwise, any claim that it is not subject to the jurisdiction of any such court, any objection that it may now or hereafter have to the laying of the venue of any such suit, action or proceeding brought in any such court and any claim that any such suit, action or proceeding brought in any such court has been brought in an inconvenient forum.

(b)The Company consents to process being served by or on behalf of any holder of Notes in any suit, action or proceeding of the nature referred to in Section 22.8(a) by mailing a copy thereof by registered or certified mail (or any substantially similar form of mail), postage prepaid, return receipt requested, to it at its address specified in Section 18 or at such other address of which such holder shall then have been notified pursuant to said Section.  The Company agrees that such service upon receipt (i) shall be deemed in every respect effective service of process upon it in any such suit, action or proceeding and (ii) shall, to the fullest extent permitted by applicable law, be taken and held to be valid personal service upon and personal delivery to it.  Notices hereunder shall be conclusively presumed received as evidenced by a delivery receipt furnished by the United States Postal Service or any reputable commercial delivery service.

(c)Nothing in this Section 22.8 shall affect the right of any holder of a Note to serve process in any manner permitted by law, or limit any right that the holders of any of the Notes may have to bring proceedings against the Company in the courts of any appropriate jurisdiction or to enforce in any lawful manner a judgment obtained in one jurisdiction in any other jurisdiction.

(d)THE PARTIES HERETO HEREBY WAIVE TRIAL BY JURY IN ANY ACTION BROUGHT ON OR WITH RESPECT TO THIS AGREEMENT, THE NOTES, ANY OTHER FINANCING DOCUMENT OR ANY OTHER DOCUMENT EXECUTED IN CONNECTION HEREWITH OR THEREWITH.

Section 22.9.Transaction References.  The Company agrees that Prudential Investment Management, Inc. may (a) refer to its role in originating the purchase of the Notes from the Company, as well as the identity of the Company and the Parent, the aggregate principal amount of the Notes and issue date of the Notes, on its internet site or in marketing materials, press releases, published “tombstone” announcements or any other print or electronic medium and (b) display the Company’s corporate logo in conjunction with any such reference.

*    *    *    *    *

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If you are in agreement with the foregoing, please sign the form of agreement on a counterpart of this Agreement and return it to the Company, whereupon this Agreement shall become a binding agreement between you and the Company.

Very truly yours,

GILL RANCH STORAGE, LLC

By                                                                           

Name: David A. Weber

Title: President and Chief Executive Officer

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Signature Page to Note Purchase Agreement

This Agreement is hereby

accepted and agreed to as

of the date hereof.

THE PRUDENTIAL INSURANCE COMPANY

  OF AMERICA

By:  ___________________________________

Vice President

PRUCO LIFE INSURANCE COMPANY

By:  ___________________________________

Assistant Vice President

PRUCO LIFE INSURANCE COMPANY OF

  NEW JERSEY

By:  ___________________________________

Assistant Vice President

PRUDENTIAL RETIREMENT INSURANCE

  AND ANNUITY COMPANY

By:           Prudential Investment Management, Inc.,

as investment manager

By:______________________________

Vice President

PRUDENTIAL ANNUITIES LIFE

   ASSURANCE CORPORATION

By:           Prudential Investment Management, Inc.,

as investment manager

By:______________________________

Vice President

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Signature Page to Note Purchase Agreement

INFORMATION RELATING TO PURCHASERS

PURCHASER SCHEDULE

Gill Ranch Storage, LLC

7.75% Senior Secured Notes due 2016

		Aggregate Principal Amount of Notes to be Purchased	Note Denomination(s)
	THE PRUDENTIAL INSURANCE COMPANY OF AMERICA	$10,000,000	$10,000,000
(1)	All payments on account of Notes held by such purchaser shall be made by wire transfer of immediately available funds for credit to:
	JPMorgan Chase Bank New York, NY ABA No.:  021-000-021 Account Name:  Privest Plus Account No.:  P86288 (please do not include spaces)
	Each such wire transfer shall set forth the name of the Company, a reference to "7.75% Senior Secured Notes due 2016, Security No. INV11435, PPN 37569# AB7" and the due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
(2)	Address for all notices relating to payments:
	The Prudential Insurance Company of America c/o Investment Operations Group Gateway Center Two, 10th Floor 100 Mulberry Street Newark, NJ 07102-4077 Attention:  Manager, Billings and Collections
(3)	Address for all other communications and notices:
	The Prudential Insurance Company of America c/o Prudential Capital Group 2200 Ross Avenue, Suite 4200E Dallas, TX 75201 Attention:  Managing Director, Energy and Corporate Finance
(4)	Recipient of telephonic prepayment notices:
	Manager, Trade Management Group Telephone:  (973) 367-3141 Facsimile:   (888) 889-3832
(5)	Address for Delivery of Notes:
	Send physical security by nationwide overnight delivery service to: Prudential Capital Group 2200 Ross Avenue, Suite 4200E Dallas, TX 75201 Attention:  Thomas P. Donahue Telephone:  (214) 720-6202
(6)	Tax Identification No.:  22-1211670

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		Aggregate Principal Amount of Notes to be Purchased	Note Denomination(s)
	PRUCO LIFE INSURANCE COMPANY	$1,130,000	$1,130,000
(1)	All payments on account of Notes held by such purchaser shall be made by wire transfer of immediately available funds for credit to:
	JPMorgan Chase Bank New York, NY ABA No.:  021-000-021 Account No.:  P86192 (please do not include spaces) Account Name:  Pruco Life Private Placement
	Each such wire transfer shall set forth the name of the Company, a reference to "7.75% Senior Secured Notes due 2016, Security No. INV11435, PPN 37569# AB7", and the due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
(2)	Address for all notices relating to payments:
	Pruco Life Insurance Company c/o The Prudential Insurance Company of America c/o Investment Operations Group Gateway Center Two, 10th Floor 100 Mulberry Street Newark, NJ 07102-4077 Attention:  Manager, Billings and Collections
(3)	Address for all other communications and notices:
	Pruco Life Insurance Company c/o Prudential Capital Group 2200 Ross Avenue, Suite 4200E Dallas, TX 75201 Attention:  Managing Director, Energy and Corporate Finance
(4)	Recipient of telephonic prepayment notices:
	Manager, Trade Management Group Telephone:  (973) 367-3141 Facsimile:   (888) 889-3832
(5)	Address for Delivery of Notes:
	Send physical security by nationwide overnight delivery service to: Prudential Capital Group 2200 Ross Avenue, Suite 4200E Dallas, TX 75201 Attention:  Thomas P. Donahue Telephone:  (214) 720-6202
(6)	Tax Identification No.:  22-1944557

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		Aggregate Principal Amount of Notes to be Purchased	Note Denomination(s)
	PRUCO LIFE INSURANCE COMPANY OF NEW JERSEY	$3,870,000	$3,870,000
(1)	All payments on account of Notes held by such purchaser shall be made by wire transfer of immediately available funds for credit to:
	JPMorgan Chase Bank New York, NY ABA No.:  021-000-021 Account No.:  P86202 (please do not include spaces) Account Name:  Pruco Life of New Jersey Private Placement
	Each such wire transfer shall set forth the name of the Company, a reference to "7.75% Senior Secured Notes due 2016, Security No. INV11435, PPN 37569# AB7", and the due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
(2)	Address for all notices relating to payments:
	Pruco Life Insurance Company of New Jersey c/o The Prudential Insurance Company of America c/o Investment Operations Group Gateway Center Two, 10th Floor 100 Mulberry Street Newark, NJ 07102-4077 Attention:  Manager, Billings and Collections
(3)	Address for all other communications and notices:
	Pruco Life Insurance Company of New Jersey c/o Prudential Capital Group 2200 Ross Avenue, Suite 4200E Dallas, TX 75201 Attention:  Managing Director, Energy and Corporate Finance
(4)	Recipient of telephonic prepayment notices:
	Manager, Trade Management Group Telephone:  (973) 367-3141 Facsimile:   (888) 889-3832
(5)	Address for Delivery of Notes:
	Send physical security by nationwide overnight delivery service to: Prudential Capital Group 2200 Ross Avenue, Suite 4200E Dallas, TX 75201 Attention:  Thomas P. Donahue Telephone:  (214) 720-6202
(6)	Tax Identification No.:  22-2426091

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		Aggregate Principal Amount of Notes to be Purchased	Note Denomination(s)
	PRUDENTIAL ANNUITIES LIFE ASSURANCE CORPORATION	$5,000,000	$5,000,000
(1)	All payments on account of Notes held by such purchaser shall be made by wire transfer of immediately available funds for credit to:
	JPMorgan Chase Bank New York, NY ABA No.:  021-000-021 Account Name:  Prudential Annuities Life Assurance Corporation Account No.:  P01309 (please do not include spaces)
	Each such wire transfer shall set forth the name of the Company, a reference to "7.75% Senior Secured Notes due 2016, Security No. INV11435, PPN 37569# AB7" and the due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
(2)	Address for all notices relating to payments:
	Prudential Annuities Life Assurance Corporation c/o The Prudential Insurance Company of America c/o Investment Operations Group Gateway Center Two, 10th Floor 100 Mulberry Street Newark, NJ 07102-4077 Attention:  Manager, Billings and Collections
(3)	Address for all other communications and notices:
	Prudential Annuities Life Assurance Corporation c/o Prudential Capital Group 2200 Ross Avenue, Suite 4200E Dallas, TX 75201 Attention:  Managing Director, Energy and Corporate Finance
(4)	Recipient of telephonic prepayment notices:
	Manager, Trade Management Group Telephone:  (973) 367-3141 Facsimile:   (888) 889-3832
(5)	Address for Delivery of Notes:
	Send physical security by nationwide overnight delivery service to: Prudential Capital Group 2200 Ross Avenue, Suite 4200E Dallas, TX 75201 Attention:  Thomas P. Donahue Telephone:  (214) 720-6202
(6)	Tax Identification No.:  06-1241288

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PURCHASER SCHEDULE

Gill Ranch Storage LLC

Floating Rate Senior Secured Notes due 2016

		Aggregate Principal Amount of Notes to be Purchased	Note Denomination(s)
	THE PRUDENTIAL INSURANCE COMPANY OF AMERICA	$17,020,000	$11,630,000
			$  5,390,000
(1)	All payments on account of Notes held by such purchaser shall be made by wire transfer of immediately available funds for credit to:
	JPMorgan Chase Bank New York, NY ABA No.:  021-000-021
	Account Name:  Prudential Managed Portfolio Account No.:  P86188 (please do not include spaces) (in the case of payments on account of the Note originally issued in the principal amount of $11,630,000)
	Account Name:  Privest Plus Account No.:  P86288 (please do not include spaces) (in the case of payments on account of the Note originally issued in the principal amount of $5,390,000)
	Each such wire transfer shall set forth the name of the Company, a reference to "Floating Rate Senior Secured Notes due 2016, Security No. INV11435, PPN 37569# AA9" and the due date and application (as among principal, interest, Breakage Cost Obligation and Premium) of the payment being made.
(2)	Address for all notices relating to payments:
	The Prudential Insurance Company of America c/o Investment Operations Group Gateway Center Two, 10th Floor 100 Mulberry Street Newark, NJ 07102-4077 Attention:  Manager, Billings and Collections
(3)	Address for all other communications and notices:
	The Prudential Insurance Company of America c/o Prudential Capital Group 2200 Ross Avenue, Suite 4200E Dallas, TX 75201 Attention:  Managing Director, Energy and Corporate Finance
(4)	Recipient of telephonic prepayment notices:
	Manager, Trade Management Group Telephone:  (973) 367-3141 Facsimile:   (888) 889-3832
(5)	Address for Delivery of Notes:
	Send physical security by nationwide overnight delivery service to: Prudential Capital Group 2200 Ross Avenue, Suite 4200E Dallas, TX 75201 Attention:  Thomas P. Donahue Telephone:  (214) 720-6202
(6)	Tax Identification No.:  22-1211670

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		Aggregate Principal Amount of Notes to be Purchased	Note Denomination(s)
	PRUCO LIFE INSURANCE COMPANY	$1,770,000	$1,770,000
(1)	All payments on account of Notes held by such purchaser shall be made by wire transfer of immediately available funds for credit to:
	JPMorgan Chase Bank New York, NY ABA No.:  021-000-021 Account No.:  P86192 (please do not include spaces) Account Name:  Pruco Life Private Placement
	Each such wire transfer shall set forth the name of the Company, a reference to "Floating Rate Senior Secured Notes due 2016, Security No. INV11435, PPN 37569# AA9", and the due date and application (as among principal, interest, Breakage Cost Obligation and Premium) of the payment being made.
(2)	Address for all notices relating to payments:
	Pruco Life Insurance Company c/o The Prudential Insurance Company of America c/o Investment Operations Group Gateway Center Two, 10th Floor 100 Mulberry Street Newark, NJ 07102-4077
	Attention:  Manager, Billings and Collections
(3)	Address for all other communications and notices:
	Pruco Life Insurance Company c/o Prudential Capital Group 2200 Ross Avenue, Suite 4200E Dallas, TX 75201 Attention:  Managing Director, Energy and Corporate Finance
(4)	Recipient of telephonic prepayment notices:
	Manager, Trade Management Group Telephone:  (973) 367-3141 Facsimile:   (888) 889-3832
(5)	Address for Delivery of Notes:
	Send physical security by nationwide overnight delivery service to: Prudential Capital Group 2200 Ross Avenue, Suite 4200E Dallas, TX 75201 Attention:  Thomas P. Donahue Telephone:  (214) 720-6202
(6)	Tax Identification No.:  22-1944557

HOU03:1282704

		Aggregate Principal Amount of Notes to be Purchased	Note Denomination(s)
	PRUDENTIAL RETIREMENT INSURANCE AND ANNUITY COMPANY	$1,210,000	$1,210,000
(1)	All payments on account of Notes held by such purchaser shall be made by wire transfer of immediately available funds for credit to:
	JP Morgan Chase Bank New York, NY ABA No. 021000021 Account Name:  PRIAC Account No. P86329 (please do not include spaces)
	Each such wire transfer shall set forth the name of the Company, a reference to "Floating Rate Senior Secured Notes due 2016, Security No. INV11435, PPN 37569# AA9" and the due date and application (as among principal, interest, Breakage Cost Obligation and Premium) of the payment being made.
(2)	Address for all notices relating to payments:
	Prudential Retirement Insurance and Annuity Company c/o Prudential Investment Management, Inc. Private Placement Trade Management PRIAC Administration Gateway Center Four, 7th Floor 100 Mulberry Street Newark, NJ 07102 Telephone:  (973) 802-8107 Facsimile:   (888) 889-3832
(3)	Address for all other communications and notices:
	Prudential Retirement Insurance and Annuity Company c/o Prudential Capital Group 2200 Ross Avenue, Suite 4200E Dallas, TX 75201 Attention:  Managing Director, Energy and Corporate Finance
(4)	Address for Delivery of Notes:
	Send physical security by nationwide overnight delivery service to: Prudential Capital Group 2200 Ross Avenue, Suite 4200E Dallas, TX 75201 Attention:  Thomas P. Donahue Telephone:  (214) 720-6202
(5)	Tax Identification No.:  06-1050034

HOU03:1282704

GILL RANCH STORAGE, LLC

220 NW Second Avenue, Portland, OR 87209

INFORMATION RELATING TO COMPANY

(1)	All payments by wire transfer of immediately availablefunds to: Gill Ranch Storage, LLC Account: 4121648042 Routing: 121000248 Wells Fargo Bank 1300 SW Fifth Avenue Portland, OR  97201
(2)	All notices of payments and written confirmations ofsuch wire transfers: Gill Ranch Storage, LLC David A. Weber, Chief Executive Officer and President 220 NW Second Avenue 9th Floor Portland, Oregon  97209-3991 Phone:                      (503) 226-5580 Fax:           (503) 220-2584 Email:           dave.weber@nwnatural.com
(3)	All other communications: Gill Ranch Storage, LLC David A. Weber, Chief Executive Officer and President 220 NW Second Avenue 9th Floor Portland, Oregon  97209-3991 Phone:                      (503) 226-5580 Fax:           (503) 220-2584 Email:           dave.weber@nwnatural.com With a copy to: Northwest Natural Gas Company 220 NW Second Avenue 13th Floor Portland, Oregon  97209-3991 Attn:  MardiLyn Saathoff, Chief Governance Officer and Corporate Secretary Phone:                      (503) 220-2410 Fax:           (503) 721-2156 Email:           mys@nwnatural.com

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DEFINED TERMS

As used herein, the following terms have the respective meanings set forth below or set forth in the Section hereof following such term:

“Additional Covenant” means any affirmative or negative covenant or similar restriction applicable to the Company (regardless of whether such provision is labeled or otherwise characterized as a covenant) the subject matter of which either (i) is similar to that of any covenant in Section 9 or 10 of this Agreement, or related definitions in Schedule B of this Agreement, but contains one or more percentages, amounts or formulas that is more restrictive than those set forth herein or more beneficial to the holder or holders of the Indebtedness created or evidenced by the document in which such covenant or similar restriction is contained (and such covenant or similar restriction shall be deemed an Additional Covenant only to the extent that it is more restrictive or more beneficial) or (ii) is different from the subject matter of any covenant in Section 9 or 10 of this Agreement, or related definitions in Schedule B of this Agreement.

“Additional Default” means any provision contained in any document or instrument creating or evidencing Indebtedness of the Company which permits the holder or holders of Indebtedness to accelerate (with the passage of time or giving of notice or both) the maturity thereof or otherwise requires the Company to purchase such Indebtedness prior to the stated maturity thereof and which either (i) is similar to any Default or Event of Default contained in Section 11 of this Agreement, or related definitions in Schedule B of this Agreement, but contains one or more percentages, amounts or formulas that is more restrictive or has a shorter grace period than those set forth herein or is more beneficial to the holders of such other Indebtedness (and such provision shall be deemed an Additional Default only to the extent that it is more restrictive, has a shorter grace period or is more beneficial) or (ii) is different from the subject matter of any Default or Event of Default contained in Section 11 of this Agreement, or related definitions in Schedule B of this Agreement.

“Adjusted EBITDA” means, for any period, EBITDA minus Base Gas Lease Expense.

“Affiliate” means, at any time, and with respect to any Person, any other Person that at such time directly or indirectly through one or more intermediaries Controls, or is Controlled by, or is under common Control with, such first Person, and, with respect to the Company, shall include any Person beneficially owning or holding, directly or indirectly, 10% or more of any class of voting or equity interests of the Company or any Person of which the Company beneficially owns or holds, directly or indirectly, 10% or more of any class of voting or equity interests.  As used in this definition, “Control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person, whether through the ownership of voting securities, by contract or otherwise. Unless the context otherwise clearly requires, any reference to an “Affiliate” is a reference to an Affiliate of the Company.

“Agreement” means this Agreement as it may be amended or supplemented from time to time.

“Anti-Money Laundering Laws” is defined in Section 5.16(c).

“Base Gas Lease” means the Natural Gas Lease Agreement between Redding Electric Utility and the Company, dated August 28, 2009, as amended by certain letter agreements dated October 22, 2010 and June 30, 2010.

“Base Gas Lease Expense” shall mean, for any period, all expenses, interest, prepayment charges and fees incurred under or in respect of the Bas Gas Lease.

“Blocked Person” is defined in Section 5.16(a).

“Breakage Cost Obligation” is defined in Section 8.8(b).

“Business Day” means (a) for the purposes of any payment provisions of this Agreement only, any day other than a Saturday, a Sunday or a day on which commercial banks in New York City are required or authorized to be closed, and (b) for the purposes of any other provision of this Agreement, any day other than a Saturday, a Sunday or a day on which commercial banks in New York, New York or Portland, Oregon are required or authorized to be closed; provided that, when used in connection with a LIBOR Loan, the term “Business Day” shall also exclude any day on which banks are not open for dealings in dollar deposits in the London interbank market.

“Capital Expenditures” of any Person means any expenditure for fixed assets or improvements, replacements, substitutions or additions thereto that have a useful life of more than one year that is treated asa capital expenditure under GAAP (whether or not capitalized on the books of such Person), including obligations under Capitalized Leases that would appear as liabilities on a balance sheet of such Person in accordance with GAAP.

“Capital Lease” means, at any time, a lease with respect to which the lessee is required concurrently to recognize the acquisition of an asset and the incurrence of a liability in accordance with GAAP.

“Cash Equivalents” means (a) marketable direct obligations issued or unconditionally guaranteed by the United States government or issued by any agency thereof and backed by the full faith and credit of the United States of America, in each case maturing within one year from the date of acquisition thereof; (b) commercial paper maturing within one year from the date of acquisition thereof and, at the time of acquisition, having a rating of at least A-1 from S&P or at least P1 from Moody’s or an equivalent rating by any other credit rating agency of recognized national standing; (c) certificates of deposit, bankers’ acceptances and time deposits maturing within one year from the date of acquisition thereof issued by any commercial bank organized under the laws of the United States of America or any State thereof or the District of Columbia having combined capital and surplus of not less than $500,000,000 (d) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (a), (b) and (c) above entered into with any commercial bank meeting the qualifications specified in clause (c) above; (e) securities with maturities of one year or less from the date of acquisition issued or fully guaranteed by any State of the United States of America or the District of Columbia, or by any political subdivision or taxing authority of any such State or the District of Columbia, the securities of which State, the District of Columbia, political subdivision or taxing authority (as the case may be) are rated at least AA by S&P or Aa2 by Moody’s or an equivalent rating by any other credit rating agency of recognized national standing; and (f) shares of money market mutual or similar funds having assets in excess of $500,000,000 and that invest primarily in assets satisfying the requirements of clauses (a) through (e) above.

“Change in Control” means the failure of the Ultimate Parent or a wholly-owned Subsidiary of the Ultimate Parent to own and control at least 51% of the economic and voting interests in the Company.

“Closing” is defined in Section 3.

“Code” means the Internal Revenue Code of 1986, as amended from time to time, and the rules and regulations promulgated thereunder from time to time.

“Collateral” means, collectively the property in which a Lien is granted under the Security Documents.

“Collateral Agency Agreement” is defined in Section 4.12(c).

“Collateral Agent” means The Prudential Insurance Company of America, acting in its capacity as collateral agent for itself and the other Secured Parties under the Financing Documents, or its successor in such capacity appointed pursuant to the terms of the Collateral Agency Agreement.

“Company” means Gill Ranch Storage, LLC, an Oregon limited liability company, or any successor that becomes such in the manner prescribed in Section 10.5.

“Confidential Information” is defined in Section 20.

“Control Agreement” is defined in Section 4.12(b).

“Controlled Entity” means any of the Company’s Controlled Affiliates. As used in this definition, “Control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person, whether through the ownership of voting securities, by contract or otherwise.

“CPUC” means the California Public Utilities Commission or any successor thereto having jurisdiction over the storage of natural gas at the Facility.

“Debt Service” is defined in the Security Agreement.

“Debt Service Reserve Account” is defined in the Security Agreement.

“Default” means an event or condition the occurrence or existence of which would, with the lapse of time or the giving of notice or both, become an Event of Default.

“Default Rate” means, at any time upon the occurrence of an Event of Default and until such Event of Default has been cured or waived in writing, (A) in the case of the Fixed-Rate Notes, that rate of interest from time to time equal to the lesser of (i) the maximum rate permitted by applicable law and (ii) that rate that is the greater of (x) 2.00% per annum above the rate of interest stated in clause (a) of the first paragraph of the Fixed-Rate Notes and (y) 2.00% over the Prime Rate, and (B) in the case of the Floating-Rate Notes, that rate of interest from time equal to the lesser of (i) the maximum rate permitted by applicable law and (ii) 2.00% per annum above the rate of interest stated in clause (a)(i) of the first paragraph of the Floating-Rate Notes with respect to Prime Loans.

“Disclosure Documents” is defined in Section 5.3.

“EBITDA” means, for any period, the sum of Net Income plus, to the extent deducted in the determination of Net Income, (i) all provisions for federal, state and other income tax of the Company, (ii) Interest Expense and (iii) provisions for depreciation and amortization; provided that there shall be excluded, without duplication, (a) any gains in excess of losses resulting from the sale, conversion or other disposition of capital assets (i.e., assets other than current assets), (b) any non-cash gains or losses resulting from the write-up or write-down of assets, (c) any earnings or losses of any Person acquired by the Company through purchase, merger or consolidation or otherwise for any period prior to the date of acquisition, (d) any gains from the acquisition of securities or the retirement or extinguishment of Indebtedness of the Company, (e) any gains on collections from the proceeds of insurance policies or settlements, (f) any restoration to income of any contingency reserve, except to the extent that provision for such reserve was made out of income accrued during such period, (g) any income or gain during such period from any change in accounting principles, from any discontinued operations or the disposition thereof, from any extraordinary items or from any prior period adjustments, or (h) any equity of the Company in the undistributed earnings (or losses) of a Person which is not a Subsidiary of the Company, which amounts referred to in the foregoing clauses (a) through (h) in the aggregate will be deducted only to the extent they are positive, in each case adjusted for Minority Interests, if any.

“Environmental Laws” means any and all federal, state, local, and foreign statutes, laws, regulations, ordinances, rules, judgments, orders, decrees, permits, licenses, agreements or governmental restrictions relating to pollution and the protection of the environment or the release of any materials into the environment, including but not limited to those related to Hazardous Materials.

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended from time to time, and the rules and regulations promulgated thereunder from time to time in effect.

“ERISA Affiliate” means any trade or business  (whether or not incorporated) that is treated as a single employer together with the Company under section 414 of the Code.

“Event of Abandonment” means: (a) a formal, public announcement by the Company of a decision to abandon or indefinitely defer the operation of the Facility for any reason, (b) the Company shall make any filing with the CPUC giving notice of the intent or requesting authority to abandon the operation of the Facility for any reason, or (c) the Company and the other owner or owners shall abandon the Facility for more than 30 days; provided, however, that any suspension in operation of the Facility caused by a force majeure event as defined in any Project Document shall not constitute an “Event of Abandonment” so long as the Company is diligently attempting to restart the operation of the Facility.

“Event of Default” is defined in Section 11.

“Exchange Act” shall mean the Securities Exchange Act of 1934, as amended from time to time.

“Facility” means the Gill Ranch natural gas storage facility and appurtenant easements located near Mendota, California in Fresno County, California.

“Financing Documents” means, collectively, this Agreement, the Notes, the Security Documents, the Collateral Agency Agreement, and any other documents, agreements or instruments entered into in connection with any of the foregoing.

“Fixed-Rate Note” is defined in Section 1.

“Floating-Rate Note” is defined in Section 1.

“GAAP” means generally accepted accounting principles as in effect from time to time in the United States of America.

“Governmental Authority” means

(a)           the government of

(i) the United States of America or any state or other political subdivision thereof, or

(ii) any other jurisdiction in which the Company conducts all or any part of its business, or which asserts jurisdiction over any properties of the Company, or

(b) any entity exercising executive, legislative, judicial, regulatory or administrative functions of, or pertaining to, any such government.

“Guaranty” means, with respect to any Person, any obligation (except the endorsement in the ordinary course of business of negotiable instruments for deposit or collection) of such Person guaranteeing or in effect guaranteeing any indebtedness, dividend or other obligation of any other Person in any manner, whether directly or indirectly, including (without limitation) obligations incurred through an agreement, contingent or otherwise, by such Person:

(a) to purchase such indebtedness or obligation or any property constituting security therefor;

(b) to advance or supply funds (i) for the purchase or payment of such indebtedness or obligation, or (ii) to maintain any working capital or other balance sheet condition or any income statement condition of any other Person or otherwise to advance or make available funds for the purchase or payment of such indebtedness or obligation;

(c) to lease properties or to purchase properties or services primarily for the purpose of assuring the owner of such indebtedness or obligation of the ability of any other Person to make payment of the indebtedness or obligation; or

(d) otherwise to assure the owner of such indebtedness or obligation against loss in respect thereof.

In any computation of the indebtedness or other liabilities of the obligor under any Guaranty, the indebtedness or other obligations that are the subject of such Guaranty shall be assumed to be direct obligations of such obligor.

“Hazardous Material” means: (a) any petroleum or petroleum products, flammable materials, explosives, radioactive materials, friable asbestos, urea formaldehyde foam insulation and polychlorinated biphenyls (PCBs), (b) any chemicals, other materials, substances or wastes which are now or hereafter become defined as or included in the definition of “hazardous substances”, “hazardous wastes”, “hazardous materials”, “extremely hazardous wastes”, “restricted hazardous wastes”, “toxic substances”, “toxic pollutants”, “contaminants”, “pollutants” or words of similar import under any Environmental Law and (c) any other chemical, material, substance or waste which is now or hereafter regulated under or with respect to which liability or standards of conduct are imposed under any Environmental Law.

“holder” means, with respect to any Note, the Person in whose name such Note is registered in the register maintained by the Company pursuant to Section 13.1, provided, however, that if such Person is a nominee, then for the purposes of Sections 7, 12, 17.2 and 18 and any related definitions in this Schedule B, “holder” shall mean the beneficial owner of such Note whose name and address appears in such register.

“Indebtedness” with respect to any Person means, at any time, without duplication,

(a) its liabilities for borrowed money, including those evidenced by notes, bonds, debentures and similar instruments, and its redemption obligations in respect of mandatorily redeemable Preferred Stock;

(b) its liabilities for the deferred purchase price of property acquired by such Person (including all liabilities created or arising under any conditional sale or other title retention agreement with respect to any such property but excluding accounts payable arising in the ordinary course of business);

(c) (i) all liabilities appearing on its balance sheet in accordance with GAAP in respect of Capital Leases and (ii) all liabilities which would appear on its balance sheet in accordance with GAAP in respect of Synthetic Leases assuming such Synthetic Leases were accounted for as Capital Leases; provided that Base Gas Lease Expense shall not be considered Indebtedness;

(d) all liabilities for borrowed money secured by any Lien with respect to any property owned by such Person (whether or not it has assumed or otherwise become liable for such liabilities);

(e) all its liabilities in respect of letters of credit or instruments serving a similar function issued or accepted for its account by banks and other financial institutions (whether or not representing obligations for borrowed money);

(f) the aggregate Swap Termination Value of all Swap Contracts of such Person; and

(g) any Guaranty of such Person with respect to liabilities of a type described in any of clauses (a) through (f) hereof.

Indebtedness of any Person shall include all obligations of such Person of the character described in clauses (a) through (g) to the extent such Person remains legally liable in respect thereof notwithstanding that any such obligation is deemed to be extinguished under GAAP.

“Indemnified Parties” is defined in Section 15.2.

“INHAM Exemption” is defined in Section 6.2(e).

“Institutional Investor” means (a) any Purchaser of a Note, (b) any holder of a Note holding (together with one or more of its affiliates) more than 5% of the aggregate principal amount of the Notes then outstanding, (c) any bank, trust company, savings and loan association or other financial institution, any pension plan, any investment company, any insurance company, any broker or dealer, or any other similar financial institution or entity, regardless of legal form, and (d) any Related Fund of any holder of any Note.

“Interest Expense” shall mean, for any period, the sum (without duplication) of (i) all interest, prepayment charges and fees incurred (whether paid or accrued) in respect of any Indebtedness of the Company (including imputed interest in respect of obligations under Capital Leases, net costs of Swap Contract transactions and all fees, commissions and discounts owed with respect to letters of credit and bankers’ acceptance financing) deducted in determining Net Income for such period, together with all interest capitalized or deferred during such period and not deducted in determining Net Income for such period, plus (ii) all debt discount and expense amortized or required to be amortized in the determination of Net Income for such period plus (iii) dividends in respect of mandatorily redeemable Preferred Stock required to be paid in cash.  For the avoidance of doubt, Interest Expense includes Base Gas Lease Expense.

“Interest Period” shall mean, (i) as to any LIBOR Loan, the period commencing on the date of such LIBOR Loan or on the last day of the immediately preceding Interest Period applicable thereto, as the case may be, and ending on the numerically corresponding day (or, if there is no numerically corresponding day, on the last day) in the calendar month that is one or three months thereafter, in each case as the Company may specify or be deemed to specify, and (ii) as to any Prime Loan, the period commencing on the date of such Prime Loan or on the last day of the immediately preceding Interest Period applicable thereto, as the case may be, and ending on the earlier of (a) the March 31, June 30, September 30 and December 31, as applicable, next succeeding such commencement date and (b) the date, if any, that such Prime Loan is converted to a LIBOR Loan or LIBOR Loans; provided, however, that (x) if any Interest Period pertaining to a LIBOR Loan would end on a day other than a Business Day, such Interest Period shall be extended to the next succeeding Business Day unless such next succeeding Business Day would fall in the next calendar month, in which case such Interest Period shall end on the next preceding Business Day, and (y) if any Interest Period pertaining to a Prime Loan would end on a day other than a Business Day, such Interest Period shall be extended to the next succeeding Business Day.  Interest shall accrue from and including the first day of an Interest Period to but excluding the earlier of (1) the last day of such Interest Period and (2) the day on which the applicable Loan is repaid or prepaid in full.

“Investment” means, for any Person: (a) the acquisition (whether for cash, property of such Person, services or securities or otherwise) of capital stock, bonds, notes, debentures, partnership or other ownership interests or other securities of any other Person or any agreement to make any such acquisition (including any “short sale” or any other sale of any securities at a time when such securities are not owned by the Person entering into such sale), (b) the making of any deposit with, or advance, loan or other extension of credit to, any other Person (including the purchase of property from another Person subject to an understanding or agreement, contingent or otherwise, to resell such property to such Person, but excluding any such advance, loan or extension of credit having a term not exceeding 90 days representing the purchase price of inventory or supplies sold in the ordinary course of business) and (c) the entering into of any guarantee of, or other contingent obligation with respect to, Indebtedness or other liability of any other Person.

“Joint Project Agreement” means the Joint Project Agreement, dated as of January 31, 2008, between the Company and PG&E, as amended as of February 29, 2008, as further amended as of March 31, 2008, as further amended as of August 20, 2010 and as further amended, restated, supplemented or otherwise modified from time to time

“LIBO Rate” shall mean for each Interest Period for any LIBOR Loan, the greater of (i)(a) the interest rate per annum for deposits in U.S. dollars with a maturity most nearly comparable to the applicable Interest Period which appears on the display designated as “Page BBAM1” on Bloomberg Financial Markets (or such other display as may replace Page BBAM1 on Bloomberg Financial Markets) as of 11:00 a.m. (London time), two Business Days prior to the commencement of such Interest Period, or (b) if such rate ceases to be reported in accordance with the above definition on Bloomberg Financial Markets, the arithmetic mean of the rates per annum at which deposits in U.S. dollars are offered by the principal London offices of the Reference Banks at approximately 11:00 a.m. (London time), on the day that is two Business Days before the first day of such Interest Period to prime banks in the London interbank market for a period equal to such Interest Period, commencing on the first day of such Interest Period, and in an amount comparable to such Loan and (ii) 1.50% per annum.  This arithmetic mean shall be determined on the basis of the quotations of the applicable rate requested of each of the Reference Banks by, and furnished to, the holders of Notes, provided that if fewer than two quotations are provided as requested, the rate per annum shall equal the arithmetic mean of the rates quoted by major banks in New York City, selected by the Purchasers, at approximately 11:00 a.m. (New York City time) on the first day of the Interest Period for loans in U.S. dollars to leading European banks for a period equal to such Interest Period, commencing on the first day of such Interest Period, and in an amount comparable to such Loan.

“LIBOR Loan” shall mean a principal amount outstanding from time to time under any Floating-Rate Note that bears interest at the LIBO Rate.

“Lien” means, with respect to any Person, any mortgage, pledge, security interest, encumbrance, minimum or compensating deposit arrangement, lien (statutory or otherwise) or charge of any kind (including any agreement to give any of the foregoing, any conditional sale or other title retention agreement, any lease in the nature thereof (including Capital Leases), and the filing of or agreement to give any financing statement under the Uniform Commercial Code of any jurisdiction) or any other type of preferential arrangement for the purpose, or having the effect, of protecting a creditor against loss or securing the payment or performance of an obligation.

“Loan” means a LIBOR Loan or a Prime Loan.

“Loan Type” means, as to any Loan, its character as a LIBOR Loan or a Prime Loan.

“Make-Whole Amount” is defined in Section 8.7.

“Material” means material in relation to the business, operations, affairs, financial condition, assets, properties, or prospects of the Company.

“Material Customer Contract” means any contract or agreement between the Company and a third party providing for the sale of natural gas storage in consideration of payments of amounts in excess of $1,000,000 per year.

“Material Adverse Effect” means a material adverse effect on (a) the business, operations, affairs, financial condition, assets or properties of the Company, (b) the ability of the Company or the Parent to perform their respective obligations under the Financing Documents to which each is a party, (c) the validity or enforceability against the Company or the Parent of the Financing Documents to which each is a party or (d) the rights and remedies of the Collateral Agent or the holders under the Financing Documents.

“Material Project Documents” means, collectively, the PG&E Contracts, the Base Gas Lease and the Material Customer Contracts.

“Minimum Debt Service Reserve Requirement” shall mean $4,000,000, as of the Closing.  After the Closing, the Minimum Debt Service Reserve Requirement shall be reduced by an amount equal to 10% of the principal amount of any prepayments of the Notes pursuant to Section 8.

“Minority Interests” shall mean any capital Securities of a Subsidiary (other than directors’ qualifying shares as required by law) that are not owned by the Company or a wholly owned Subsidiary of the Company.

“Moody’s” means Moody’s Investor Service, Inc. and its successors.

“Multiemployer Plan” means any Plan that is a “multiemployer plan” (as such term is defined in section 4001(a)(3) of ERISA).

“NAIC” means the National Association of Insurance Commissioners or any successor thereto.

“Net Income” means for any period the net income of the Company after tax as recorded on the financial statements of the Company and determined in accordance with GAAP.

“Net Worth” means an amount equal to the consolidated equity of the Company.

“Notes” is defined in Section 1.

“NGA” means the Natural Gas Act, as heretofore and hereafter amended, and codified at 15 U.S.C. §717 et seq.

“Obligation” means any loan, advance, debt, liability, and obligation of performance, howsoever arising, owed by the Company to the Collateral Agent or the holders of the Notes, of any kind or description (whether or not evidenced by any note or instrument and whether or not for the payment of money), direct or indirect, absolute or contingent, due or to become due, now existing or hereafter arising, pursuant to the terms of the Agreement, any Note or any of the other Financing Documents, including all principal, interest, Make-Whole Amounts, Premiums, Breakage Cost Obligations, fees, charges, expenses, attorneys’ fees, consultants’ fees  and accountants’ fees payable or reimbursable by the Company under this Agreement or any of the other Financing Documents.

“OFAC” is defined in Section 5.16(a).

“OFAC Listed Person” is defined in Section 5.16(a).

“OFAC Sanctions Program” means any economic or trade sanction that OFAC is responsible for administering and enforcing.  A list of OFAC Sanctions Programs may be found at http://www.ustreas.gov/offices/enforcement/ofac/programs/.

“Officer’s Certificate” means a certificate, on behalf of the Company, executed by a Senior Financial Officer or of any other officer of the Company whose responsibilities extend to the subject matter of such certificate.

“Other Project Documents” means any contracts or agreements, other than the Material Project Documents, entered into by the Company from time to time relating to the operation and maintenance of the Facility.

“Parent” means NW Natural Gas Storage, LLC, an Oregon limited liability company.

“PBGC” means the Pension Benefit Guaranty Corporation referred to and defined in ERISA or any successor thereto.

“Permitted Closing Distributions” is defined in Section 5.14(ii).

“Permitted Indebtedness” means:

(a)Indebtedness listed on Schedule 5.15; and

(b)Indebtedness (including Capital Leases) incurred to finance (as purchase money or otherwise) the acquisition of property; provided that the aggregate amount of such Indebtedness (including Capital Leases) shall not exceed $2,000,000.

“Permitted Investments” means:

(a)           Investments in property to be used in the ordinary course of business of the Company;

(b)           Investments in current assets arising from the sale of goods or services in the ordinary course of business of the Company; and

(c)           any Investment in cash or Cash Equivalents.

“Person” means an individual, partnership, corporation, limited liability company, association, trust, unincorporated organization, business entity or Governmental Authority.

“PG&E” means Pacific Gas and Electric Company.

“PG&E Contracts” means, collectively, (i) the Joint Project Agreement, (ii) the Operator Agreement, dated as of January 31, 2008, between the Company and PG&E, as amended as of August 20, 2010 and as further amended, restated, supplemented or otherwise modified from time to time and (iii) the Operating and Balancing Agreement, dated as of February 2, 2009, between the Company and PG&E, as amended, restated, supplemented or otherwise modified from time to time.

“Plan” means an “employee benefit plan” (as defined in section 3(3) of ERISA) subject to Title I of ERISA that is or, within the preceding five years, has been established or maintained, or to which contributions are or, within the preceding five years, have been made or required to be made, by the Company or any ERISA Affiliate or with respect to which the Company or any ERISA Affiliate may have any liability.

“Pledge Agreement” is defined in Section 4.12(d).

“Pledged Collateral” is defined in the Pledge Agreement.

“Pledged Membership Interests” is defined in the Pledge Agreement.

“Preferred Stock” means any class of capital stock of a Person that is preferred over any other class of capital stock (or similar equity interests) of such Person as to the payment of dividends or the payment of any amount upon liquidation or dissolution of such Person.

“Premium” means, with respect to any Floating-Rate Note (a) that has become or is declared to be immediately due and payable pursuant to Section 12.1 (i) on or before November 30, 2012, an amount equal to 4.00% of the principal of such Note, (ii) after November 30, 2012 and on or before November 30, 2013, an amount equal to 2.00% of the principal of such Note and (iii) after November 30, 2013 and on or before November 30, 2014, an amount equal to 1.00% of the principal of such Note, or (b) that is being prepaid pursuant to Section 8.2(b) or Section 8.3(e) (i) after November 30, 2012 and on or before November 30, 2013, an amount equal to 2.00% of the principal of such Note being prepaid, and (ii) after November 30, 2013 and on or before November 30, 2014, an amount equal to 1.00% of the principal of such Note being prepaid.

“Prime Loan” shall mean a principal amount outstanding from time to time under any Floating-Rate Note that bears interest at the Prime Rate.

“Prime Rate” shall mean, with respect to any Prime Loan, a fluctuating rate per annum (based on a year of 365 or 366 days, as the case may be, and actual days elapsed) equal on any given day to the greater of (i) the rate of interest most recently announced in New York City by JPMorgan Chase Bank, N.A. (or if such rate of interests shall not be available from JPMorgan Chase Bank, N.A., then Bank of America, N.A.) as its U.S. dollar prime commercial lending rate (the “Reference Rate”) and (ii) 2.50%.  The Prime Rate shall automatically fluctuate, without special notice to the Company or any other Person, upward and downward as and in the amount by which the Reference Rate shall fluctuate.  The Reference Rate is set by JPMorgan Chase Bank, N.A. or Bank or America, N.A., as applicable, as a general reference rate of interest, taking into account such factors as JPMorgan Chase Bank, N.A. or Bank or America, N.A., as applicable,  may deem appropriate.  The Reference Rate is not necessarily the lowest or best rate actually charged to any customer, and such rate may not correspond with future increases or decreases in interest rates charged by other lenders or market rates in general.  JPMorgan Chase Bank, N.A. or Bank or America, N.A., as applicable, may make various business or other loans at rates of interest having no relationship to the Reference Rate.  Without notice to the Company or any other Person, the Reference Rate shall change automatically from time to time, as determined by JPMorgan Chase Bank, N.A. or Bank of America, N.A., as applicable.

“Project” means the Company’s 75% undivided interest in the Facility.

“Project Documents” means, collectively, the Material Project Documents and the Other Project Documents.

“property” or “properties” means, unless otherwise specifically limited, real or personal property of any kind, tangible or intangible, choate or inchoate.

“Proposed Change in Control Prepayment Date” is defined in Section 8.3(c).

“Prudent Industry Practice” means any of the practices, methods, and acts engaged in or approved by a significant portion of the natural gas storage facilities in the United States of America of a type and size similar to the Facility during the relevant period of time or that, at a particular time, in the exercise of reasonable judgment in light of the facts known or that should reasonably have been known at the time a decision was made, would have reasonably been expected to accomplish the desired result consistent with good business practices, reliability, safety and expedition.  “Prudent Industry Practice” is not intended to be limited to the optimum practices, methods, equipment specifications or acts to the exclusion of all others, but rather is intended to encompass a range of acceptable practices, methods and standards generally accepted within the industry and used by natural gas storage facilities in the United States of America of a type and size similar to the Facility during the relevant period of time to accomplish the desired results, having due regard for, among other things, manufacturers’ warranties, contractual obligations, the requirements or guidance of any Governmental Authority, Governmental Rule and applicable operating guidelines and rules of the CPUC.

“PTE” is defined in Section 6.2(a).

“Purchaser” is defined in the first paragraph of this Agreement.

“Qualified Institutional Buyer” means any Person who is a “qualified institutional buyer” within the meaning of such term as set forth in Rule 144A(a)(1) under the Securities Act.

“Reference Banks” means four major banks in the London interbank market selected by the Required Holders.

“Regulation T”, “Regulation U” and “Regulation X” mean, respectively, Regulation T, Regulation U and Regulation X of the Board of Governors of the Federal Reserve System.

“Related Fund” means, with respect to any holder of any Note, any fund or entity that (i) invests in Securities or bank loans, and (ii) is advised or managed by such holder, the same investment advisor as such holder or by an affiliate of such holder or such investment advisor.

“Required Holders” means the holders of at least 51% in principal amount of the Notes at the time outstanding (exclusive of Notes then owned by the Company or any of its Affiliates).

“Responsible Officer” means any Senior Financial Officer and any other officer of the Company with responsibility for the administration of the relevant portion of this Agreement.

“Restricted Payment” means (i) the declaration or payment of any distribution or dividend on, or the incurrence of any liability to make any other payment or distribution in respect of equity of the Company or (ii) any distribution on account of the purchase, redemption or other retirement of any such equity; provided that the Permitted Closing Distributions shall not constitute Restricted Payments.

“Restricted Payment Date” is defined in Section 10.2(b).

“S&P” means Standard & Poor’s Rating Services and its successors.

“Sale-and-Leaseback Transaction” means a transaction or series of transactions pursuant to which the Company shall sell or transfer to any Person any property, whether now owned or hereafter acquired, and, as part of the same transaction or series of transactions, the Company shall rent or leases as lessee (other than pursuant to a Capital Lease), or similarly acquire the right to possession or use of, such property or one or more properties which it intends to use for the same purpose or purposes as such property.

“SEC” means the Securities and Exchange Commission of the United States, or any successor thereto.

“Secured Parties” means, collectively, the holders from time to time and the Collateral Agent.

“Securities” or “Security” shall have the meaning specified in section 2(1) of the Securities Act.

“Securities Act” means the Securities Act of 1933, as amended from time to time, and the rules and regulations promulgated thereunder from time to time in effect.

“Securities Intermediary” is defined in the Security Agreement.

“Security Documents” means the Security Agreement, the Control Agreement, the Pledge Agreement and any other security documents, financing statements and the like filed or recorded in connection with the foregoing.

“Senior Financial Officer” means the chief executive officer, the president, the chief financial officer, principal accounting officer or vice president and treasurer of the Company.

“Source” is defined in Section 6.2.

“Solvent” means, with respect to any Person as of the date of any determination, that on such date (i) the fair value of the property of such Person (both at fair valuation and at present fair saleable value) is greater than the total amount of liabilities, including, without limitation, contingent liabilities, of such Person, (ii) the present fair saleable value of the assets of such Person is not less than the amount that will be required to pay the probable liability of such Person on its debts as they become absolute and matured, (iii) such Person is able to realize upon its assets and pay its debts and other liabilities, contingent obligations and other commitments as they mature in the normal course of business, (iv) such Person does not intend to, and does not believe that it will, incur debts or liabilities beyond such Person’s ability to pay as such debts and liabilities mature and (v) such Person is not engaged in business or a transaction, and is not about to engage in business or a transaction, for which such Person’s property would constitute unreasonably small capital after giving due consideration to current and anticipated future capital requirements and current and anticipated future business conduct and the prevailing practice in the industry in which such Person is engaged.  In computing the amount of contingent liabilities at any time, such liabilities shall be computed at the amount which, in light of the facts and circumstances existing at such time, represents the amount that can reasonably be expected to become an actual or matured liability.

“Subsidiary” means, as to any Person, any other Person in which such first Person or one or more of its Subsidiaries or such first Person and one or more of its Subsidiaries owns sufficient equity or voting interests to enable it or them (as a group) ordinarily, in the absence of contingencies, to elect a majority of the directors (or Persons performing similar functions) of such second Person, and any partnership or joint venture if more than a 50% interest in the profits or capital thereof is owned by such first Person or one or more of its Subsidiaries or such first Person and one or more of its Subsidiaries (unless such partnership or joint venture can and does ordinarily take major business actions without the prior approval of such Person or one or more of its Subsidiaries).

“Successor Company” is defined in Section 10.5(a).

“SVO” means the Securities Valuation Office of the NAIC or any successor to such Office.

“Swap Contract” means (a) any and all interest rate swap transactions, basis swap transactions, basis swaps, credit derivative transactions, forward rate transactions, commodity swaps, commodity options, forward commodity contracts, equity or equity index swaps or options, bond or bond price or bond index swaps or options or forward foreign exchange transactions, cap transactions, floor transactions, currency options, spot contracts or any other similar transactions or any of the foregoing (including, but without limitation, any options to enter into any of the foregoing), and (b) any and all transactions of any kind, and the related confirmations, which are subject to the terms and conditions of, or governed by, any form of master agreement published by the International Swaps and Derivatives Association, Inc., any International Foreign Exchange Master Agreement.

“Swap Termination Value” means, in respect of any one or more Swap Contracts, after taking into account the effect of any legally enforceable netting agreement relating to such Swap Contracts, (a) for any date on or after the date such Swap Contracts have been closed out and termination value(s) determined in accordance therewith, such termination value(s), and (b) for any date prior to the date referenced in clause (a), the amounts(s) determined as the mark-to-market values(s) for such Swap Contracts, as determined based upon one or more mid-market or other readily available quotations provided by any recognized dealer in such Swap Contracts.

“Synthetic Lease” means, at any time, any lease (including leases that may be terminated by the lessee at any time) of any property (a) that is accounted for as an operating lease under GAAP and (b) in respect of which the lessee retains or obtains ownership of the property so leased for United States federal income tax purposes, other than any such lease under which such Person is the lessor.

“Tangible Net Worth” means Net Worth less, without duplication, (i) all intangible items, including, without limitation, goodwill, licenses, organizational expense, unamortized debt discount and expense carried as an asset and any write-up in the book value of assets, (ii) net gains or losses attributed to cumulative translation adjustments and (iii) Minority Interests.

“Transaction Documents” means, collectively, the Financing Documents and the Material Project Documents.

“Ultimate Parent” means Northwest Natural Gas Company, an Oregon corporation.

“USA PATRIOT Act” means United States Public Law 107-56, Uniting and Strengthening America by Providing Appropriate Tools Required to Intercept and Obstruct Terrorism (USA PATRIOT ACT) Act of 2001, as amended from time to time, and the rules and regulations promulgated thereunder from time to time in effect.

HOU03:1282704                                                             Schedule B

(to Note Purchase Agreement)

EXHIBIT A-1

[FORM OF FIXED-RATE NOTE]

GILL RANCH STORAGE, LLC

7.75% SENIOR SECURED NOTE DUE NOVEMBER 30, 2016

No. RA-[_____]                                                                                                                               [Date]

$ [_______]                                                                                                                 PPN 37569# AB7

FOR VALUE RECEIVED, the undersigned, GILL RANCH STORAGE, LLC (herein called the “Company”), a limited liability company organized and existing under the laws of the State of Oregon, hereby promises to pay to [____________], or registered assigns, the principal sum of [_____________________] DOLLARS (or so much thereof as shall not have been prepaid) on November 30, 2016 (the “Maturity Date”), with interest (computed on the basis of a 360-day year of twelve 30 day months) (a) on the unpaid balance hereof at the rate of 7.75% per annum from the date hereof, payable quarterly, on the last day of February, May, August and November in each year, commencing with the last day of February, May, August or November next succeeding the date hereof, and on the Maturity Date, until the principal hereof shall have become due and payable, and (b) to the extent permitted by law, on any overdue payment of interest and, during the continuance of an Event of Default, on such unpaid balance and on any overdue payment of any Make-Whole Amount, at the Default Rate, payable quarterly as aforesaid (or, at the option of the registered holder hereof, on demand).

Payments of principal of, interest on and any Make-Whole Amount with respect to this Note are to be made in lawful money of the United States of America at the main office of JPMorgan Chase Bank, N.A. in New York City or at such other place as the Company shall have designated by written notice to the holder of this Note as provided in the Note Purchase Agreement referred to below.

This Note is one of a series of 7.75% Senior Secured Notes (herein called the “Notes”) issued pursuant to the Note Purchase Agreement, dated as of November 30, 2011 (as from time to time amended, the “Note Purchase Agreement”), between the Company and the respective Purchasers named therein and is entitled to the benefits thereof.  Each holder of this Note will be deemed, by its acceptance hereof, to have (i) agreed to the confidentiality provisions set forth in Section 20 of the Note Purchase Agreement and (ii) made the representation set forth in Section 6.2 of the Note Purchase Agreement.  Unless otherwise indicated, capitalized terms used in this Note shall have the respective meanings ascribed to such terms in the Note Purchase Agreement.

This Note is a registered Note and, as provided in the Note Purchase Agreement, upon surrender of this Note for registration of transfer accompanied by a written instrument of transfer duly executed, by the registered holder hereof or such holder’s attorney duly authorized in writing, a new Note for a like principal amount will be issued to, and registered in the name of, the transferee.  Prior to due presentment for registration of transfer, the Company may treat the person in whose name this Note is registered as the owner hereof for the purpose of receiving payment and for all other purposes, and the Company will not be affected by any notice to the contrary.

This Note is subject to optional and mandatory prepayment, in whole or from time to time in part, at the times and on the terms specified in the Note Purchase Agreement, but not otherwise.  This Note is secured by the Security Documents and is entitled to the benefits thereof.

If an Event of Default occurs and is continuing, the principal of this Note may be declared or otherwise become due and payable in the manner, at the price (including any applicable Make-Whole Amount) and with the effect provided in the Note Purchase Agreement.

This Note shall be construed and enforced in accordance with, and the rights of the Company and the holder of this Note shall be governed by, the law of the State of New York excluding choice-of-law principles of the law of such State that would permit the application of the laws of a jurisdiction other than such State.

GILL RANCH STORAGE, LLC

By                                                                           

Name:

Title:

HOU03:1282704                                                           Exhibit A-1-1

EXHIBIT A-2

[FORM OF FLOATING-RATE NOTE]

GILL RANCH STORAGE, LLC

FLOATING-RATE SENIOR SECURED NOTE DUE NOVEMBER 30, 2016

No. RB-[_____]                                                                                                                               [Date]

$ [_______]                                                                                                                PPN 37569# AA9

FOR VALUE RECEIVED, the undersigned, GILL RANCH STORAGE, LLC (herein called the “Company”), a limited liability company organized and existing under the laws of the State of Oregon, hereby promises to pay to [____________], or registered assigns, the principal sum of [_____________________]DOLLARS (or so much thereof as shall not have been prepaid) on November 30, 2016, with interest (computed on the basis of (x) a year of 360 days for the actual number of days elapsed with respect to LIBOR Loans and (y) a year of 365 or 366 days for the actual number of days elapsed with respect to Prime Loans) payable in arrears on the last day of each applicable Interest Period and as otherwise provided in the Note Purchase Agreement referred to below, until the principal hereof shall have become due and payable (a) on the unpaid balance hereof at the rate of (i) with respect to Prime Loans, the Prime Rate plus 4.50% and (ii) with respect to LIBOR Loans, the LIBO Rate plus 5.50% and (b) to the extent permitted by law, on any overdue payment of interest and, during the continuance of an Event of Default, on the principal balance hereof and any overdue payment of any Premium and Breakage Cost Obligations at the Default Rate, payable on the last day of each applicable Interest Period as aforesaid (or, at the option of the registered holder hereof, on demand).

Payments of principal of, interest on and any Premium and Breakage Cost Obligations with respect to this Note are to be made in lawful money of the United States of America at the main office of JPMorgan Chase Bank, N.A. in New York City or at such other place as the Company shall have designated by written notice to the holder of this Note as provided in the Note Purchase Agreement referred to below.

This Note is one of a series of Floating-Rate Senior Secured Notes (herein called the "Notes"), issued pursuant to the Note Purchase Agreement, dated as of November 30, 2011 (as from time to time amended, the "Note Purchase Agreement"), between the Company and the respective Purchasers named therein and is entitled to the benefits thereof.  Each holder of this Note will be deemed, by its acceptance hereof, to have (i) agreed to the confidentiality provisions set forth in Section 20 of the Note Purchase Agreement and (ii) made the representation set forth in Section 6.2 of the Note Purchase Agreement.  Unless otherwise indicated, capitalized terms used in this Note shall have the respective meanings ascribed to such terms in the Note Purchase Agreement.

This Note is a registered Note and, as provided in the Note Purchase Agreement, upon surrender of this Note for registration of transfer accompanied by a written instrument of transfer duly executed, by the registered holder hereof or such holder's attorney duly authorized in writing, a new Note for a like principal amount will be issued to, and registered in the name of, the transferee.  Prior to due presentment for registration of transfer, the Company may treat the person in whose name this Note is registered as the owner hereof for the purpose of receiving payment and for all other purposes, and the Company will not be affected by any notice to the contrary.

This Note is subject to optional and mandatory prepayment, in whole or from time to time in part, at the times and on the terms specified in the Note Purchase Agreement, but not otherwise.  This Note is secured by the Security Documents and is entitled to the benefits thereof.

If an Event of Default occurs and is continuing, the principal of this Note may be declared or otherwise become due and payable in the manner, at the price (including any applicable Premium and Breakage Cost Obligation) and with the effect provided in the Note Purchase Agreement.

This Note shall be construed and enforced in accordance with, and the rights of the Company and the holder of this Note shall be governed by, the law of the State of New York excluding choice-of-law principles of the law of such State that would permit the application of the laws of a jurisdiction other than such State.

GILL RANCH STORAGE, LLC

By                                                                           

Name:

Title:

HOU03:1282704                                                           Exhibit A-2-1

EXHIBIT 4.4(a)

FORM OF COMPOSITE OPINION OF COMPANY COUNSEL

Matters To Be Covered in

Opinion of Counsel to the Company and the Parent

As used herein, “Opinion Parties” means, collectively, the Company and the Parent.

The Opinion Parties being limited liability companies validly existing under the laws of the State of Oregon.

The Company having requisite power and authority as a limited liability company to issue and sell the Notes and to execute, deliver and perform this Agreement, the Notes and each other Financing Documents to which it is a party.

TheParent having requisite power and authority as a limited liability company to execute, deliver and perform the Collateral Agency Agreement and the Pledge Agreement.

TheCompany being of active status and registered to transact intrastate business as a foreign limited liability company in appropriate jurisdictions, including in the State of California.

Dueauthorization, execution, delivery and performance by the Opinion Parties of the Financing Documents to which each is a party and such documents being legal, valid, binding and enforceable in accordance with its terms under the laws of the State of New York and applicable federal law.

A state or federal court sitting in either (i) the State of California and applying California choice of law rules or (ii) the State of Oregon and applying Oregon choice of law rules, would give effect to the provisions of the Financing Documents selecting the laws of New York as governing law.  If, notwithstanding the opinion expressed in the preceding sentence, the substantive laws of the State of California or the State of Oregon were to govern the validity, construction and enforceability of the Financing Documents, the Financing Documents would constitute valid obligations of the Opinion Party that is a party thereto, legally binding upon and enforceable against such Opinion Party in accordance with their respective terms.  If, notwithstanding the opinion expressed in the first sentence of this paragraph, the Uniform Commercial Code of the State of California or the Uniform Commercial Code of the State of Oregon were to govern the creation of security interests under any of the Security Documents, such Security Document would create valid security interests in that portion of the Collateral in which a security interest can be created under the Uniform Commercial Code as in effect in the State of California or the State of Oregon, as the case may be.

Execution and delivery of the Financing Documents and the consummation by the Opinion Parties of transactions contemplated thereby not violating or constituting a default under certificates of formation, limited liability company agreements, laws, rules, regulations or other material agreements.

All consents, approvals, waivers, licenses, authorizations or actions by or filing with any Governmental Authority (including, without limitation, the CPUC and any other California utility regulatory authority) or any third party required (i) for the Company to issue and sell the Notes, (ii) for the Opinion Parties to execute and deliver the Financing Documents and to close the transactions contemplated thereby and (iii) for the transfer of the membership interests of the Parent in the Company in the event of the exercise by the Collateral Agent of remedies in respect of the Pledged Collateral under the Pledge Agreement (except as may be required in connection with such disposition by laws affecting the offering and sale of securities generally), having been obtained.

Perfection of security interests in Uniform Commercial Code-governed Collateral under the Security Documents.

The Notes not requiring registration under the Securities Act of 1933, as amended; no need to qualify an indenture under the Trust Indenture Act of 1939, as amended.

No violation of Regulations T, U or X of the Federal Reserve Board.

No Opinion Party being an “investment company”, or a company “controlled” by an “investment company”, under the Investment Company Act of 1940, as amended.

The opinion shall expressly state that it is delivered at the request of the Opinion Parties pursuant to Section 4.4(a) of the Agreement with the understanding that the Purchasers are purchasing the Notes in reliance thereon and may be relied upon by each subsequent holder of Notes that is an Institutional Investor.

HOU03:1282704                                                          Exhibit 4.4(A)

FORM OF SECURITY AGREEMENT

HOU03:1282704                                                              Exhibit B

EXECUTION COPY

SECURITY AGREEMENT

THIS SECURITY AGREEMENT (this “Agreement”), dated as of November 30, 2011, is made by GILL RANCH STORAGE, LLC, an Oregon limited liability company (the “Grantor”), to THE PRUDENTIAL INSURANCE COMPANY OF AMERICA, as collateral agent (in such capacity, together with its successors and assigns, the “Collateral Agent”) for the benefit of itself in such capacity and of the Noteholders (as hereinafter defined) under that certain Intercreditor and Collateral Agency Agreement, dated as of even date herewith (as the same may be amended, restated, supplemented or otherwise modified from time to time, the “Collateral Agency Agreement”), among the Collateral Agent, the Noteholders, the Grantor and the Parent (as defined therein).

RECITALS

A.           The Grantor, The Prudential Insurance Company of America and any other Purchasers (defined therein) party thereto are entering into a Note Purchase Agreement, dated as of even date herewith (as the same may be modified, amended, supplemented, joined or restated in accordance with its terms, including any extensions, renewals, increases and replacements thereof, the “Note Agreement”), pursuant to which the Grantor will issue and the Purchasers (the Purchasers and their respective successors and assigns, and any other holders from time to time of the Notes described below are referred to herein as the “Noteholders”) will purchase the 7.75% Senior Secured Notes due November 30, 2016 and the Floating-Rate Senior Secured Notes due November 30, 2016 in the aggregate principal amount of $40,000,000 (together with any notes given in substitution, or exchange, or in modification, renewal, rearrangement or extension, in whole or in part, for the notes described in the foregoing, the “Notes”).

B.           It is a condition precedent to the agreement of the Noteholders to accept and purchase the Notes that this Agreement shall have been executed and delivered by the Grantor and shall be in full force and effect.

C.           The Grantor has determined that the execution, delivery and performance of this Agreement to be in the best interests of the Grantor.

NOW, THEREFORE, in consideration of the premises and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, and in order to induce the Noteholders to enter into the Note Agreement and to accept and purchase the Notes to be issued to the Noteholders thereunder on the date hereof, the Grantor hereby covenants and agrees with the Collateral Agent as follows:

Section 1.Defined Terms and Related Matters.

(a)Capitalized terms used and not otherwise defined herein that are defined in the Note Agreement shall have the respective meanings specified therein.  Terms defined in the singular include the plural and terms defined in the plural include the singular.

(b)The words “hereof,” “herein” and “hereunder” and words of similar import when used in this Agreement shall refer to this Agreement as a whole and not to any particular provision of this Agreement.

(c)Unless otherwise defined herein or in the Note Agreement, the terms defined in Articles 8 and 9 of the Uniform Commercial Code as enacted in the State of New York as in effect from time to time (the “UCC”), are used herein as therein defined.

(d)Should any Event of Default under the Note Agreement occur and be continuing, the same shall constitute an Event of Default under this Agreement (an “Event of Default”).

(e)“Control Agreement” means the securities account control agreement, dated as of the date hereof, among the Grantor, Wells Fargo Securities, LLC, as the Securities Intermediary (in such capacity, the “Securities Intermediary”), and the Collateral Agent, in respect of the Debt Service Reserve Account, in form and substance reasonably satisfactory to the Collateral Agent.

(f)“Debt Service”means, for any period, all payments (including optional and mandatory prepayments) of principal, interest, fees, expenses or other charges, including any Make-Whole Amounts, Premiums or Breakage Cost Obligations, due and payable, or projected to be due and payable, by the Grantor in respect of all Obligations in such period.

(g)“Debt Service Reserve Account” means the securities account established in the name of the Grantor at the Securities Intermediary with securities account number 13013305.

(h)“Disbursement Requisition” means a requisition in the form attached as Exhibit A executed by a Senior Financial Officer of the Grantor.

(i)“Permitted Investment” means any (a) marketable direct obligations issued or unconditionally guaranteed by the United States government or issued by any agency thereof and backed by the full faith and credit of the United States of America, in each case maturing within one year from the date of acquisition thereof; (b) commercial paper maturing within one year from the date of acquisition thereof and, at the time of acquisition, having a rating of at least A-1 from S&P or at least P1 from Moody’s or an equivalent rating by any other credit rating agency of recognized national standing; (c) certificates of deposit, bankers’ acceptances and time deposits maturing within one year from the date of acquisition thereof issued by any commercial bank organized under the laws of the United States of America or any State thereof or the District of Columbia having combined capital and surplus of not less than $500,000,000; (d) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (a), (b) and (c) above entered into with any commercial bank meeting the qualifications specified in clause (c) above; (e) securities with maturities of one year or less from the date of acquisition issued or fully guaranteed by any State of the United States of America or the District of Columbia, or by any political subdivision or taxing authority of any such State or the District of Columbia, the securities of which State, the District of Columbia, political subdivision or taxing authority (as the case may be) are rated at least AA by S&P or Aa2 by Moody’s or an equivalent rating by any other credit rating agency of recognized national standing; and (f) shares of money market mutual or similar funds having assets in excess of $500,000,000 and that invest primarily in assets satisfying the requirements of clauses (a) through (e) above.

Section 2.Security Interest.  The Grantor hereby grants to the Collateral Agent a lien on and security interest in all of the Grantor’s rights, titles, interests and privileges in and to (a) the Debt Service Reserve Account, (b) all financial assets credited to the Debt Service Reserve Account, (c) all security entitlements with respect to the financial assets credited to the Debt Service Reserve Account, (d) any and all other investment property or assets from time to time maintained or recorded in the Debt Service Reserve Account and (e) all replacements or substitutions for, and proceeds of the sale or other disposition of, any of the foregoing, including without limitation, cash proceeds (collectively, “Collateral”)

Section 3.Security for Obligations.  The lien and security interest granted in this Agreement secure: (a) the full and prompt payment of the principal of, any Make-Whole Amounts, Premium or Breakage Cost Obligations, and interest on, and all other amounts due with respect to the Notes from time to time outstanding, as and when such amounts shall become due and payable in accordance with the Note Agreement, whether by lapse of time, upon redemption, prepayment or purchase, by extension or by acceleration or declaration or otherwise (including, without limitation, (i) interest due at the Default Rate on any amount due hereunder and as provided under the Note Agreement or under any other Financing Document and (ii) interest accruing after the filing of any petition in bankruptcy, or the commencement of any insolvency, reorganization or like proceeding, whether or not a claim for post-filing or post-petition interest is allowed in such proceeding); (b) the full and prompt payment, performance and observance by the Grantor and any other Person (other than the Noteholders or the Collateral Agent or their respective agents or representatives) of all obligations, covenants, indemnifications, conditions and agreements contained in any of the Financing Documents; and (c) the full and prompt payment of the indemnities of the Grantor contained in each of the Financing Documents and of all costs and expenses due and payable pursuant to Section 15.1 of the Note Agreement (all such obligations, covenants, conditions and agreements described in the foregoing clauses (a), (b) and (c) being hereinafter collectively referred to as the “Secured Obligations”).

Section 4.Formalities.

(a)The Grantor and the Collateral Agent shall, concurrently with entry into this Agreement, enter into the Control Agreement with the Securities Intermediary, pursuant to which Collateral Agent shall be entitled, in accordance with the terms hereof and of the Collateral Agency Agreement, at any time to give the Securities Intermediary instructions as to the withdrawal or disposition of funds or other Collateral from time to time credited to or carried in the Debt Service Reserve Account, or as to any other matters relating to the Debt Service Reserve Account or the Collateral, without the further consent of the Grantor, and the Grantor shall not be entitled to give any such instructions, except with respect to Permitted Investments held in the Debt Service Reserve Account in accordance with Section 7(b).

(b)In addition to clause (a) above, the Grantor shall promptly take all actions required to perfect the security interest of the Collateral Agent in the Collateral (whether now owned or hereafter acquired) under applicable law (including, in any event,under the provisions of Article 8 or 9 of the UCC, as applicable) and agrees to take such actions as the Collateral Agent reasonably deems necessary to effect the foregoing and to permit the Collateral Agent to exercise any of its rights and remedies hereunder.

(c)The Grantor shall take all actions required to maintain at all times the Debt Service Reserve Account as a securities account and to cause the Securities Intermediary to treat all assets credited to or carried in the Debt Service Reserve Account as financial assets.

(d)The Grantor hereby authorizes the Collateral Agent to file one or more financing or continuation statements, and amendments thereto, relating to all or any part of the Collateral without the signature of the Grantor where permitted by law.  A photocopy or other reproduction of this Agreement or any financing statement covering the Collateral or any part thereof shall be sufficient as a financing statement where permitted by law.  For the avoidance of doubt, it shall be the primary responsibility of the Grantor to perfect and to maintain the perfection of the security interest in the Collateral.

Section 5.Representations, Warranties and Covenants.  The Grantor represents, warrants and covenants as of the date hereof (and as to Collateral hereafter acquired, as of the date of each such acquisition) as follows:

(a)The Grantor is the legal and beneficial owner of the Collateral, free and clear of any Lien (except the Liens created hereunder), and the Grantor has not sold, granted any option with respect to, assigned, transferred or otherwise disposed of any of its rights or interests in or to the Collateral, nor has the Grantor entered into any securities account control agreement pursuant to which the Securities Intermediary is required to comply with instructions or entitlement orders from any other Person as to the disposition of funds from the Debt Service Reserve Account or other dealings with the Collateral, other than from the Collateral Agent as contemplated herein and in the Control Agreement.

(b)Upon the filing of a UCC-1 financing statement in the governmental office(s) set forth on Schedule A attached hereto, all filings, registrations and recordings necessary to create, preserve, protect and perfect the security interest granted by the Grantor to the Collateral Agent hereby in respect of the Collateral will have been accomplished, and the security interest granted to the Collateral Agent pursuant to this Agreement in and to the Collateral will constitute a perfected security interest therein superior and prior to the rights of all other Persons therein and subject to no other Liens or adverse claims, and will be entitled to all the rights, priorities and benefits afforded by the Uniform Commercial Code, or other relevant law as enacted in any relevant jurisdiction, to perfected security interests.

(c)This Agreement creates a valid and continuing lien on, and security interest in, the Collateral, including, without limitation, the Grantor’s interest in all after-acquired property included in the Collateral and acquired after the date hereof, securing the Secured Obligations.

(d)No consent, authorization, approval or other action by, and no notice to or filing with, any Governmental Authority or any other Person (other than in the case of clause (iii) below, the Securities Intermediary) is required: (i) for the valid execution, delivery and performance by the Grantor of this Agreement; (ii) for the pledge by the Grantor of a security interest in the Collateral; or (iii) for the exercise by the Collateral Agent of the rights provided for in this Agreement or the remedies in respect of the Collateral pursuant to this Agreement (except as may be required in connection with such disposition by laws affecting the offering and sale of securities generally).

(e)The execution, delivery and performance by the Grantor of this Agreement has been duly authorized by all necessary limited liability company action on the part of the Grantor.  This Agreement has been duly executed and delivered by the Grantor and constitutes a legal, valid and binding obligation of the Grantor, enforceable against the Grantor in accordance with its terms except as such enforceability may be limited by (i) applicable bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting the enforcement of creditors’ rights generally and (ii) general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

(f)The Grantor covenants and agrees that it will defend the Collateral Agent’s right, title and security interest in and to the Collateral and the proceeds thereof against the claims and demands of all persons whomsoever; and the Grantor covenants and agrees that it will have like title to and right to pledge any other property at any time hereafter pledged to the Collateral Agent as Collateral hereunder and will likewise defend the right thereto and security interest therein of the Collateral Agent.

(g)No portion of the Collateral is subject to any defense, offset or counterclaim, nor have any of the foregoing been asserted or alleged against the Grantor by any Person with respect thereto.

(h)The Grantor will not sell, assign, or otherwise dispose of, grant any option with respect to, or pledge, grant a security interest in or otherwise encumber any of the Collateral or any interest therein, or enter into any securities account control agreement pursuant to which the Securities Intermediary is required to comply with instructions or entitlement orders from any Person other than the Collateral Agent as to the disposition of funds from the Debt Service Reserve Account or other dealings with the Collateral (except with respect to Permitted Investments held in the Debt Service Reserve Account in accordance with Section 7(b)) or suffer any of the same to exist; and any sale, assignment, option, pledge, security interest or other encumbrance or securities account control agreement or disposition of any nature whatsoever made in violation of this covenant shall be a nullity and of no force and effect, and upon demand of the Collateral Agent, shall forthwith be canceled or satisfied by an appropriate instrument in writing.

(i)There are no currently effective financing statements covering any property which is now or hereafter may be included in the Collateral, and the Grantor will not, without the prior written consent of the Collateral Agent, authorize or authenticate any such financing statements after the date hereof, and there will not ever be on file in any public office, any financing statement or statements covering any or all of the Collateral, except financing statements filed or to be filed in favor of the Collateral Agent.

(j)The Grantor shall give the Collateral Agent prompt notice of any claim relating to the Collateral.  The Grantor shall deliver to the Collateral Agent a copy of each written demand, notice or document received by it which may adversely affect the Collateral Agent’s interest in the Collateral promptly upon, but in any event within five Business Days after, the Grantor’s receipt thereof.

(k)The principal place of business of the Grantor and the sole location where the records of the Grantor with respect to the Collateral are kept are located at the address set forth for the Grantor on Schedule B attached hereto.

(l)The jurisdiction of organization and organizational number of the Grantor is as set forth on Schedule B attached hereto.  As of the date hereof, the Grantor does not have or operate under, nor has it had or operated under, in any jurisdiction at any time within 5 years prior to the Closing, any name except its legal name as set forth on the signature pages hereto or such other names specified on Schedule B attached hereto, nor has the Grantor ever been organized under the laws of any jurisdiction other than the jurisdiction specified on Schedule B attached hereto.  The Grantor shall not change its legal name, assume or operate in any jurisdiction under any trade, fictitious or other name or change its jurisdiction of organization unless (i) it shall have given to the Collateral Agent not less than 30 days’ prior written notice of its commencing to do so, clearly describing such new name and the jurisdictions in which such new name shall be used or such new jurisdiction of organization and providing such other information in connection therewith as the Collateral Agent may reasonably request and (ii) with respect to such new name or jurisdiction of organization, it shall have taken all reasonable action, reasonably satisfactory to the Collateral Agent, to maintain the security interest of the Collateral Agent in the Collateral intended to be granted hereby at all times fully perfected and in full force and effect.

The representations and warranties set forth in this Section 5 shall survive the execution and delivery of this Agreement.

Section 6.Further Assurances; Supplements.

(a)The Grantor agrees that at any time and from time to time, at the expense of the Grantor, the Grantor will promptly execute and deliver all further instruments and documents (including, without limitation, financing or continuation statements, or amendments thereto), and take all further action that may be reasonably necessary or that the Collateral Agent or the Required Holders may reasonably request, in order to perfect and protect any Lien or security interest granted or purported to be granted by the Grantor under this Agreement, including, without limitation, with respect to any additional Collateral acquired hereafter by the Grantor or to enable the Collateral Agent to exercise and enforce rights and remedies hereunder.  The Grantor hereby authorizes the Collateral Agent, at the expense of the Grantor (including the reasonable fees and expenses of counsel to the Collateral Agent), to file one or more financing or continuation statements, and amendments thereto, relating to all or any part of the Collateral, in such form and in such filing offices as the Collateral Agent shall determine to be appropriate, without the signature of the Grantor where permitted by law.  A photocopy or other reproduction of this Agreement or any financing statement covering the Collateral or any part thereof shall be sufficient as a financing statement where permitted by law.  The Grantor agrees, with respect to any financing statement, to file (at the expense of the Grantor, including the reasonable fees and expenses of counsel to the Collateral Agent) all continuation statements or amendments where failure to so file could reasonably be expected to result in the lapse of such financing statement at any time.

(b)The Grantor will defend the title to the Collateral and the Liens of the Collateral Agent thereon against the claim of any Person and will maintain and preserve such Liens at all times hereafter.

Section 7.The Debt Service Reserve Account.

(a)Deposits into the Debt Service Reserve Account.  On the date of the Closing, the Grantor will deposit the Minimum Debt Service Reserve Requirement into the Debt Service Reserve Account.  Thereafter, (i) on each date on which Debt Service other than in respect of payments of interest is due and owing and on which the Collateral Agent instructs the Securities Intermediary to make a withdrawal from the Debt Service Reserve Account in accordance with Section 7(c)(i), (ii) within five days of the date on which Debt Service in respect of payments of interest is due and owing and on which the Collateral Agent instructs the Securities Intermediary to make a withdrawal from the Debt Service Reserve Account in accordance with Section 7(c)(i) or (iii) on any other date on which the balance in the Debt Service Reserve Account is less than the Minimum Debt Service Reserve Requirement as a result of any loss, fee, tax or other charge resulting from any Permitted Investments held in the Debt Service Reserve Account in accordance with Section 7(b), the Grantor shall deposit into the Debt Service Reserve Account any funds necessary to cause the amount credited to the Debt Service Reserve Account to equal the then applicable Minimum Debt Service Reserve Requirement.  For the avoidance of doubt, if the Grantor complies with the provisions of clauses (i) and (ii) above, the payment to the Noteholders of Debt Service due and owing from withdrawals from the Debt Service Reserve Account will not result in an Default or Event of Default under either the Note Purchase Agreement or this Agreement.

(b)Permitted Investments.  The Grantor may instruct the Securities Intermediary to invest property from time to time credited to the Debt Service Reserve Account in Permitted Investments, in accordance with the procedures set forth in the Control Agreement.  For purposes of any income tax payable on account of income or gain on Permitted Investments, such income or gain will be for the account of the Grantor.  All earnings and losses on any investments shall be credited or debited, as applicable, to the Debt Service Reserve Account.  The Collateral Agent will not be liable or responsible for any loss or diminution in value in connection with or relating to the Permitted Investments.

(c)Withdrawals from the Debt Service Reserve Account.

(i)On each date on which Debt Service is due and owing, to the extent not otherwise paid to the Noteholders on such date, the Collateral Agent shall instruct (at the written direction of the Required Holders), the Securities Intermediary to withdraw from the Debt Service Reserve Account and transfer to the Noteholders any remaining Debt Service then due and owing to such Noteholders, such transfer to such Noteholders to be on a basis consistent with the second and third clauses of Section 2.6 of the Collateral Agency Agreement.

(ii)At any time when an Event of Default has occurred and is continuing, the Collateral Agent shall instruct (in accordance with the directions of the Required Holders) the Securities Intermediary as to the disposition or investment of the amount credited to the Debt Service Reserve Account.

(iii)Unless a Default or Event of Default exists or would result from the payment requested in a Disbursement Requisition contemplated herein, to the extent the amount credited to the Debt Service Reserve Account on any date exceeds the Minimum Debt Service Reserve Requirement as a result of (x) any reductions in the Minimum Debt Service Reserve Requirement due to any prepayment of the principal amount of the Notes pursuant to Section 8 of the Note Agreement or (y) any income or gain on any Permitted Investment held in the Debt Service Reserve Account in accordance with Section 7(b), the Grantor may deliver a Disbursement Requisition to the Collateral Agent, with a copy to the Noteholders, and upon the determination of the Required Holders that no Default or Event of Default exists at such time or will result from the payment requested in such Disbursement Requisition (or at such later time when any such Default or Event of Default shall have been cured, waived or is no longer continuing), the Collateral Agent shall instruct the Securities Intermediary to withdraw from the Debt Service Reserve Account the amount requested in such Disbursement Requisition (or such lesser amount as the Required Holders may determine) and to deposit such withdrawn amount as requested in such Disbursement Requisition.

(iv)Any Disbursement Requisition delivered by the Grantor to the Collateral Agent must (A) be delivered to the Collateral Agent (c/o Prudential Capital Group, at 2200 Ross Avenue, Suite 4200E, Dallas, Texas 75201, Attention: Managing Director, Energy and Corporate Finance), with a copy to the Noteholders at such addresses specified in Section 18 of the Note Agreement, at least three Business Days prior to the date specified therein for a requested withdrawal and transfer of funds and (B) be in the form of Exhibit A attached hereto and contain all information requested in such form.

Section 8.Collateral Agent Appointed Attorney-in-Fact.  The Grantor hereby irrevocably designates, makes, constitutes and appoints the Collateral Agent the Grantor’s attorney-in-fact, with full authority in the place and stead of the Grantor and in the name of the Grantor or otherwise, from time to time in the Collateral Agent’s discretion, to take any action and to execute any instrument which the Collateral Agent may deem necessary or advisable to accomplish the purposes of this Agreement, including, without limitation:

(a)upon the occurrence and during the continuance of an Event of Default, to ask, demand, collect, sue for, recover, compromise, receive and give acquittance and receipts for monies due and to become due under or in connection with the Collateral;

(b)upon the occurrence and during the continuance of an Event of Default, to receive, indorse and collect any drafts or other instruments, documents and chattel paper, in connection therewith; and

(c)upon the occurrence and during the continuance of an Event of Default, to file any claims or take any action or institute any proceedings which the Collateral Agent may deem necessary or desirable for the collection of any of the Collateral or otherwise to enforce compliance with the terms and conditions of any contract or agreement included in the Collateral or the rights of the Collateral Agent with respect to any of the Collateral.

Section 9.Collateral Agent May Perform.  If the Grantor fails to perform any agreement contained herein, the Collateral Agent may, but shall not be required to, itself perform, or cause performance of, such agreement, and the expenses of the Collateral Agent incurred in connection therewith shall be payable by the Grantor, together with interest thereon at the Default Rate, to the Collateral Agent on demand and shall constitute obligations secured hereby.

Section 10.Collateral Agent’s Duties.  The powers conferred on the Collateral Agent hereunder are solely to protect its interest in the Collateral and shall not impose any duty upon it to exercise any such powers.  The Collateral Agent shall have no duty as to any Collateral or as to the taking of any necessary steps to preserve rights against prior parties or any other rights pertaining to any Collateral.

Section 11.Remedies.  If any Event of Default shall have occurred and be continuing:

(a)Upon the instruction of the Required Holders, in accordance with the provisions of the Collateral Agency Agreement, the Collateral Agent may exercise in respect of the Collateral, in addition to other rights and remedies provided for herein or in the Collateral Agency Agreement or otherwise available to it, all the rights and remedies of a secured party upon default under the UCC (whether or not the UCC applies to the affected Collateral), or under the laws of any other applicable jurisdiction.  The Grantor confirms that the Collateral of the types described in clauses (a) through (d) of the definition of “Collateral” in Section 2 hereof, other than deposit account collateral, is of a type customarily sold on a recognized broker’s board or recognized securities exchange.  Accordingly, the Collateral Agent may also, without notice, sell the Collateral or any part thereof in one or more parcels at any recognized broker’s board or on any recognized securities exchange, for cash, on credit or for future delivery, or in any other commercially reasonable manner.  The Collateral Agent shall not be obligated to make any sale of Collateral.

(b)Any cash held by the Collateral Agent as Collateral and all cash proceeds received by the Collateral Agent in respect of any sale of, collection from, or other realization upon all or any part of the Collateral may, in the discretion of the Collateral Agent, be held by the Collateral Agent as collateral for, and/or then or at any time thereafter be applied (after payment of any amounts payable to the Collateral Agent pursuant to the Collateral Agency Agreement) in whole or in part by the Collateral Agent against all or any part of the Secured Obligations pursuant to the Collateral Agency Agreement.  Upon receipt by the Collateral Agent of written instructions (including wiring instructions), any surplus of such cash or cash proceeds held by the Collateral Agent and remaining after payment in full of all the Secured Obligations shall be paid over to the Grantor or to whomsoever may be lawfully entitled to receive such surplus.

(c)All rights and remedies of the Collateral Agent expressed herein are in addition to all other rights and remedies possessed by the Collateral Agent in the other Security Documents or any other agreement or instrument relating to the Secured Obligations at law, in equity or otherwise.

Section 12.Amendments, Etc.  No amendment or waiver of any provision of this Agreement nor consent to any departure by the Grantor herefrom shall in any event be effective unless the same shall be in writing and signed by the Collateral Agent and the Grantor in accordance with the Collateral Agency Agreement, and then such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given.

Section 13.Addresses for Notices.  All notices and other communications provided for hereunder shall be in writing and sent by first-class mail or nationwide overnight delivery service (with charges prepaid), and (i) if to a Noteholder, addressed to it at the address specified for such communications in Section 18 of the Note Agreement, or at such other address as such Noteholder shall have specified to the Grantor and the Collateral Agent in writing; (ii) if to the Collateral Agent addressed to it in such capacity at The Prudential Insurance Company of America, c/o Prudential Capital Group, at 2200 Ross Avenue, Suite 4200E, Dallas, Texas 75201, Attention: Managing Director, Energy and Corporate Finance, or at such other address as the Collateral Agent shall have specified to each Noteholder and the Grantor in writing; and (iii) if to the Grantor, addressed to it at Gill Ranch Storage, LLC, at 220 N.W. Second Avenue, 9th Floor, Portland, Oregon 97209, Attention: President and Chief Executive Officer, with a copy to Northwest Natural Gas Company, 220 NW Second Avenue, 13th Floor, Portland, Oregon  97209-3991, Attn:  MardiLyn Saathoff, Chief Governance Officer and Corporate Secretary, or at such other address as the Grantor shall have specified to each Noteholder and the Collateral Agent in writing.

Section 14.Lien and Security Interest Absolute. All rights of the Collateral Agent and the pledge, assignment, lien and security interest hereunder, and all obligations of the Grantor hereunder, shall be absolute and unconditional, irrespective of:

(a)any lack of validity or enforceability of the Note Agreement, the Notes or any other Financing Document;

(b)any change in the time, manner or place of payment of, or in any other term of, all or any of the Secured Obligations, or any other amendment or waiver of or any consent to any departure from the Note Agreement, the Notes or any other Financing Document;

(c)any taking, exchange, release or non-perfection of any other collateral, or any taking, release or amendment or waiver of or consent to departure from any guaranty of all or any of the Secured Obligations;

(d)any manner of application of Collateral, or proceeds thereof, to all or any of the Secured Obligations, or any manner of sale or other disposition of any Collateral for all or any of the Secured Obligations or any other assets of the Grantor or any other Person;

(e)any change, restructuring or termination of the limited liability company or other organizational structure or existence of the Parent, any of its Subsidiaries (including the Grantor), the Collateral Agent or any Noteholder; or

(f)any other circumstance which might otherwise constitute a defense available to, or a discharge of, the Grantor or any other grantor of a security interest.

Section 15.Continuing Lien and Security Interest.

(a)This Agreement shall create a continuing lien on and security interest in the Collateral and shall: (i) remain in full force and effect until the payment in full in cash and performance in full of the Secured Obligations; (ii) be binding upon the Grantor and its successors and assigns; and (iii) inure to the benefit of, and be enforceable by, the Collateral Agent and its successors, transferees and assigns, under the terms of the Collateral Agency Agreement or otherwise.  Without limiting the generality of the foregoing clause (iii), the Collateral Agent may assign or otherwise transfer all or any portion of its rights and obligations under this Agreement to any co-agent, co-trustee, additional or substitute agent or trustee appointed in accordance with the provisions of the Collateral Agency Agreement, and such Person shall thereupon become vested with all the benefits in respect thereof granted herein or otherwise to the Collateral Agent.  Upon the payment in full in cash and performance in full of the Secured Obligations, the Grantor shall be entitled to the termination of the Control Agreement, upon its request and at its expense.  Upon any such request by the Grantor, the Collateral Agent will execute and deliver to the Grantor such documents as the Grantor shall reasonably request to evidence such termination and to effect the release of the security interest in the Collateral granted hereby.

(b)The Grantor agrees that to the extent that, after payment in full of the Secured Obligations, such payment or any part thereof is subsequently invalidated, voided, declared to be fraudulent or preferential, set aside, recovered, rescinded or is required to be retained by or repaid to a trustee, receiver, or any other Person under any bankruptcy code, common law, or equitable cause, then the Lien and security interest in the Collateral created hereunder shall be revived, reinstated and continued in full force and effect, as if said payment had not been made.  The Lien and security interest in the Collateral created hereunder shall not be released or discharged by any payment to any Noteholder from any source that is thereafter paid, returned or refunded in whole or in part by reason of the assertion of a claim of any kind relating thereto, including, but not limited to, any claim for breach of contract, breach of warranty, preference, illegality, invalidity, or fraud asserted by any account debtor or by any other Person.

Section 16.Waiver of Marshalling.  All rights of marshalling of assets of the Grantor, including, without limitation, any such right with respect to the Collateral, are hereby waived by the Grantor.

Section 17.Severability.  Any provision of this Agreement which is prohibited or unenforceable in any applicable jurisdiction shall not invalidate the remaining provisions hereof, and any such prohibition or unenforceability in any applicable jurisdiction shall not invalidate or render unenforceable such provision in any other applicable jurisdiction.  Should any clause, sentence, paragraph, subsection or Section of this Agreement be judicially declared to be invalid, unenforceable or void, such decision will not have the effect of invalidating or voiding the remainder of this Agreement, and the parties hereto agree that the part or parts of this Agreement so held to be invalid, unenforceable or void will be deemed to have been stricken herefrom by the parties hereto, and the remainder will have the same force and effectiveness as if such stricken part or parts had never been included herein.

Section 18.Captions.  The captions in this Agreement have been inserted for convenience only and shall be given no substantive meaning or significance whatever in construing the terms and provisions of this Agreement.

Section 19.No Waiver; Remedies.  No failure on the part of the Collateral Agent or the Noteholders to exercise, and no delay in exercising, any right hereunder shall operate as a waiver thereof; nor shall any single or partial exercise of any right hereunder preclude any other or further exercise thereof or the exercise of any other right.  The remedies herein provided are cumulative and not exclusive of any remedies provided by law.

Section 20.GOVERNING LAW.  THIS AGREEMENT SHALL BE CONSTRUED AND ENFORCED IN ACCORDANCE WITH, AND THE RIGHTS OF THE PARTIES SHALL BE GOVERNED BY, THE LAW OF THE STATE OF NEW YORK WITHOUT REGARD TO CONFLICT OF LAW PRINCIPLES OTHER THAN SECTION 5-1401 OF THE NEW YORK GENERAL OBLIGATIONS LAW.  This Agreement may not be changed orally, but (subject to the provisions of Section 12) only by an agreement in writing signed by the party against whom enforcement of any waiver, change, modification or discharge is sought.

Section 21.WAIVER OF JURY TRIAL; Consent to Jurisdiction; Waiver of Immunities.

(a)WAIVER OF JURY TRIAL.  THE GRANTOR AND THE COLLATERAL AGENT AGREE TO WAIVE THEIR RESPECTIVE RIGHTS TO A JURY TRIAL OF ANY CLAIM OR CAUSE OF ACTION BASED UPON OR ARISING OUT OF THIS AGREEMENT, ANY OTHER FINANCING DOCUMENT OR ANY DEALINGS BETWEEN THEM RELATING TO THE SUBJECT MATTER OF THIS TRANSACTION.  THE SCOPE OF THIS WAIVER IS INTENDED TO BE ALL-ENCOMPASSING OF ANY AND ALL DISPUTES THAT MAY BE FILED IN ANY COURT AND THAT RELATE TO THE SUBJECT MATTER OF THIS TRANSACTION, INCLUDING WITHOUT LIMITATION, CONTRACT CLAIMS, TORT CLAIMS, BREACH OF DUTY CLAIMS, AND ALL OTHER COMMON LAW AND STATUTORY CLAIMS.  THE GRANTOR AND THE COLLATERAL AGENT EACH ACKNOWLEDGE THAT THIS WAIVER IS A MATERIAL INDUCEMENT TO ENTER INTO THIS BUSINESS RELATIONSHIP, THAT EACH HAS ALREADY RELIED ON THE WAIVER IN ENTERING INTO OR ACCEPTING THIS AGREEMENT, AND THAT EACH WILL CONTINUE TO RELY ON THE WAIVER IN THEIR RELATED FUTURE DEALINGS.  THE GRANTOR AND THE COLLATERAL AGENT FURTHER WARRANT AND REPRESENT THAT EACH HAS REVIEWED THIS WAIVER WITH ITS LEGAL COUNSEL, AND THAT EACH KNOWINGLY AND VOLUNTARILY WAIVES ITS JURY TRIAL RIGHTS FOLLOWING CONSULTATION WITH LEGAL COUNSEL.  IN THE EVENT OF LITIGATION, THIS AGREEMENT MAY BE FILED AS A WRITTEN CONSENT TO A TRIAL BY THE COURT.

(b)Consent to Jurisdiction; Waiver of Immunities.  The Grantor hereby irrevocably submits to the non-exclusive jurisdiction of the courts of the State of New York, in and for the County of New York, or of the United States of America for the Southern District of New York in any action or proceeding arising out of or relating to this Agreement or any other Financing Document, and the Grantor hereby irrevocably agrees that all claims in respect of such action or proceeding may be heard and determined in New York state or Federal court.  The Grantor hereby irrevocably waives, to the fullest extent it may effectively do so, the defense of an inconvenient forum to the maintenance of such action or proceeding.  The Grantor agrees and irrevocably consents to the service of any and all process in any such action or proceeding by the mailing, by registered or certified U.S. mail (or any substantially similar form of mail), postage prepaid, return receipt requested, to it at its address specified in Section 13 hereof or at such other address as the Grantor shall have specified to each Noteholder and to the Collateral Agent in writing.  The Grantor agrees that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law.  Nothing in this Section 21 shall affect the right of any Noteholder or the Collateral Agent to serve legal process in any other manner permitted by law or affect the right of any Noteholder or the Collateral Agent to bring any action or proceeding against the Grantor or its property in the courts of any other jurisdiction.  To the extent that the Grantor has or hereafter may acquire immunity from jurisdiction of any court or from any legal process (whether through service of notice, attachment prior to judgment, attachment in aid of execution, execution or otherwise) with respect to itself or its property, the Grantor hereby irrevocably waives such immunity in respect of its obligations under this agreement.

 [Remainder of Page Intentionally Blank; Signature Page Follows]

HOU03:1285802

GILL RANCH STORAGE, LLC

By:

David A. Weber

President and Chief Executive Officer

Notice address:

Gill Ranch Storage, LLC

220 N.W. Second Avenue

Portland, Oregon 97209

Attn:  Treasurer

Fax:  503-220-2579

with a copy to:

Northwest Natural Gas Company

220 NW Second Avenue, 13th Floor

Portland, Oregon  97209-3991

Attn:  MardiLyn Saathoff, Chief Governance                                                                           Officer and Corporate Secretary

Fax:           (503)721-2156

HOU03:1285802                                       Signature Page to Security Agreement

Accepted and agreed to by:

THE PRUDENTIAL INSURANCE COMPANY OF AMERICA, as Collateral Agent

By:  ___________________________________

Vice President

Notice address:

The Prudential Insurance Company of America

c/o Prudential Capital Group

2200 Ross Avenue

Suite 4200E

Dallas, TX 75201

Attn:  Managing Director, Energy and Corporate Finance

Fax:  (214) 720-6299

HOU03:1285802                                       Signature Page to Security Agreement

Schedule A

Governmental Offices for Filings

Oregon Secretary of State

HOU03:1285802                                                             Schedule A

Schedule B

Chief Executive Office; Principal Places of Business; Locations of Collateral;

Jurisdictions of Organization; Organizational Number; and Other Names

1.           Chief Executive Office

Gill Ranch Storage, LLC

220 N.W. Second Avenue, 9th Floor

Portland, Oregon 97209

2.           Principal Place of Business

Gill Ranch Storage, LLC

220 N.W. Second Avenue, 9th Floor

Portland, Oregon 97209

3.           Jurisdiction of Organization

State of Oregon

4.           Organizational Number

Gill Ranch Storage, LLC: 461529-97

5.           Other Names

Gill Ranch Storage

GRS

6.           Other Jurisdictions

Qualified as a foreign corporation in California

HOU03:1285802                                                              Exhibit A

Exhibit A

FORM OF DISBURSEMENT REQUISITION

Collateral Agent:                                                                                                                                [Date]

The Prudential Insurance Company of America

c/o Prudential Capital Group

2200 Ross Avenue

Suite 4200E

Dallas, TX 75201-2758

Attn:  Managing Director, Energy and Corporate Finance

The Noteholders referenced below

Re:           Disbursement Requisition - Gill Ranch Storage, LLC

Ladies and Gentlemen:

Capitalized terms used herein and not otherwise defined have the meanings assigned to them in the Security Agreement dated as of November 30, 2011, among (i) Gill Ranch Storage, LLC, an Oregon limited liability company (the “Grantor”) and (ii)The Prudential Insurance Company of America, as the collateral agent (together with its successors and assigns in that capacity, the “Collateral Agent”), for the benefit of the Noteholders (as defined therein).

The undersigned, a Senior Financial Officer of the Grantor, hereby certifies that as of the date hereof, the stated amount credited to the Debt Service Reserve Account exceeds the Minimum Debt Service Reserve Requirement by $_____________.

The Grantor hereby requests that the Collateral Agent instruct the Securities Intermediary to transfer from the Debt Service Reserve Account on ___________, 20__, the amount of $_____________ to the following operating deposit account[s] of the Grantor:

[specify account[s] and wire instructions].

The undersigned further hereby certifies that:

(a) immediately before and after giving effect to the payments requested hereby, no Event of Default exists or will result therefrom; and

(b) the representations and warranties of the Grantor and the Parent in the Financing Documents are true and correct on and as of the date hereof.

HOU03:1285802                                                              Exhibit A

The Grantor has caused this Disbursement Requisition to be executed and delivered on behalf of the Grantor by its duly authorized signatory this ____ day of _________, 20__.

GILL RANCH STORAGE, LLC

By                                                                           

Name:

Title:

HOU03:1285802                                                              Exhibit A

EXHIBIT C

FORM OF SECURITIES ACCOUNT CONTROL AGREEMENT

SECURITIES ACCOUNT CONTROL AGREEMENT (Wells Fargo Securities, LLC Custody) (Trading Prohibited)

THIS SECURITIES ACCOUNT CONTROL AGREEMENT (this “Agreement”) is entered into as of by and among Gill Ranch Storage, LLC, an Oregon limited liability company (“Customer”), WELLS FARGO SECURITIES, LLC (“Intermediary”), and The Prudential Insurance Company of America, as collateral agent (“Secured Party”).

RECITALS

A.Customer maintains that certain Account no.  13013305, and may now or hereafter maintain sub-accounts thereunder or consolidated therewith (the “Securities Account”) with Intermediary pursuant to an agreement between Intermediary and Customer dated as of March 3, 2008, (the “Account Agreement”), and Customer has granted to Secured Party a security interest in the Securities Account and all financial assets and other property now or at any time hereafter held in the Securities Account.

B.Secured Party, Customer and Intermediary have agreed to enter into this Agreement to perfect Secured Party’s security interests in the Collateral, as defined below.

NOW, THEREFORE, in consideration of their mutual covenants and promises, the parties agree as follows:

1.          DEFINITIONS.  As used herein:

(a)the term “Collateral” shall mean: (i) the Securities Account; (ii) all financial assets credited to the Securities Account; (iii) all security entitlements with respect to the financial assets credited to the Securities Account; (iv) any and all other investment property or assets maintained or recorded in the Securities Account; and (v) all replacements or substitutions for, and proceeds of the sale or other disposition of, any of the foregoing, including without limitation, cash proceeds;

(b)the term “Permitted Investments” shall mean: any (a) marketable direct obligations issued or unconditionally guaranteed by the United States government or issued by any agency thereof and backed by the full faith and credit of the United States of America, in each case maturing within one year from the date of acquisition thereof; (b) commercial paper maturing within one year from the date of acquisition thereof and, at the time of acquisition, having a rating of at least A-1 from Standard & Poor’s Rating Services and its successors (“S&P”) or at least P I from Moody’s Investor Service, Inc.  and its successors (“Moody’s”) or an equivalent rating by any other credit rating agency of recognized national standing; certificates of deposit, bankers’ acceptances and time deposits maturing within one year from the date of acquisition thereof issued by any commercial bank organized under the laws of the United States of America or any State thereof or the District of Columbia having combined capital and surplus of not less than $500,000,000; (d) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (a), (b) and (c) above entered into with any commercial bank meeting the qualifications specified in clause (c) above; (e) securities with maturities of one year or less from the date of acquisition issued or fully guaranteed by any State of the United States of America or the District of Columbia, or by

HOU03:1283630                                                                     

SECURITIES ACCOUNT CONTROL AGREEMENT (Wells Fargo Securities, LLC Custody) (Trading Prohibited)

any political subdivision or taxing authority of any such State or the District of Columbia, the securities of which State, the District of Columbia, political subdivision or taxing authority (as the case may be) are rated at least AA by S&P or Aa2 by Moody’s or an equivalent rating by any other credit rating agency of recognized national standing; and (f) shares of money market mutual or similar funds having assets in excess of $500,000,000 and that invest primarily in assets satisfying the requirements of clauses (a) through (e) above; and

(c)          the terms “investment property,” “entitlement order,” “financial asset” and

“security entitlement” shall have the respective meanings set forth in the New York Uniform Commercial Code.  The parties hereby expressly agree that all property, including without limitation, cash, certificates of deposit and mutual funds, at any time held in the Securities Account is to be treated as a “financial asset.”

2.          AGREEMENT FOR CONTROL.  Intermediary is authorized by Customer and

agrees to comply with all entitlement orders originated by Secured Party with respect to the Securities Account, and all other requests or instructions from Secured Party regarding disposition and/or delivery of the Collateral, without further consent or direction from Customer or any other party.

3.          CUSTOMER’S RIGHTS WITH RESPECT TO THE COLLATERAL.

(a)Customer, or any party authorized by Customer to act with respect to the Securities Account, may give trading instructions to Intermediary with respect to the Collateral in the Securities Account solely for the purposes of instructing as to trades in Permitted Investments.

(b)Without Secured Party’s prior written consent: (i) neither Customer nor any party other than Secured Party may withdraw any Collateral from the Securities Account; and (ii) Intermediary will not comply with any entitlement order or request to withdraw any Collateral from the Securities Account given by any party other than Secured Party.

4.  INTERMEDIARY’S REPRESENTATIONS AND WARRANTIES.  Intermediary represents and warrants to Secured Party that:

(a)The Securities Account is maintained with Intermediary solely in Customer’s name.

(b)Intermediary has no knowledge of any claim to, security interest in or lien upon any of the Collateral, except: (i) the security interests in favor of Secured Party; and (ii) Intermediary’s liens securing fees and charges, or payment for open trade commitments, as described in the last paragraph of this Section.

(c)Any claim to, security interest in or lien upon any of the Collateral which Intermediary now has or at any time hereafter acquires shall be junior and subordinate to the security interests of Secured Party in the Collateral, except for Intermediary’s liens securing: (i) fees and charges owed by Customer with respect to the operation of the Securities Account; and

HOU03:1283630                                                                     

SECURITIES ACCOUNT CONTROL AGREEMENT (Wells Fargo Securities, LLC Custody) (Trading Prohibited)

(ii) payment owed to Intermediary for open trade commitments for purchases in and for the Securities Account.

5.AGREEMENTS OF INTERMEDIARY AND CUSTOMER.  Intermediary and

Customer agree that:

(a)Intermediary shall flag its books, records and systems to reflect Secured Party’s

security interests in the Collateral, and shall provide notice thereof to any party making inquiry as to Customer’s accounts with Intermediary to whom or which Intermediary is legally required or permitted to provide information.

(b)Intermediary shall send copies of all statements relating to the Securities Account simultaneously to Customer and Secured Party.

(c)Intermediary shall promptly notify Secured Party if any other party asserts any

claim to, security interest in or lien upon any of the Collateral, and Intermediary shall not enter into any control, custodial or other similar agreement with any other party that would create or acknowledge the existence of any such other claim, security interest or lien.

(d)Without Secured Party’s prior written consent, Intermediary and Customer shall not amend or modify the Account Agreement, other than: (i) amendments to reflect ordinary and reasonable changes in Intermediary’s fees and charges for handling the Securities Account; and (ii) operational changes initiated by Intermediary as long as they do not alter any of Secured Party’s rights hereunder.

(e)Intermediary shall not terminate the Account Agreement without giving thirty (30) days’ prior written notice to Secured Party.  Customer may not terminate this Agreement without the prior written consent of Secured Party.

6.          RESPONSIBILITY OF INTERMEDIARY. Intermediary shall have no

responsibility or liability to Secured Party except for accepting trading instructions or permitting a withdrawal in violation of Section 3(b) or in violation of Section 3(c) after Intermediary receives notice from Secured Party pursuant to Section 3(c).  Intermediary shall have no responsibility or liability to Customer for complying with a notice pursuant to Section 3(c) or complying with entitlement orders received from Secured Party.  Intermediary shall comply with entitlement orders received from Secured Party without any duty to investigate or determine their validity.  This Agreement does not impose or create any obligation or duty of Intermediary other than those expressly set forth herein.

7. INDEMNIFICATION.  Customer agrees to indemnify and hold harmless

Intermediary, its officers, directors, employees and agents, against claims, liabilities or expenses (including reasonable attorneys’ fees) arising out of Intermediary’s compliance with any instructions from Customer or Secured Party with respect to the Collateral, except if such claims, liabilities or expenses are caused by Intermediary’s gross negligence or willful misconduct.  Secured Party agrees to indemnify and hold harmless Intermediary, its officers, directors, employees and agents, against claims, liabilities or expenses (including reasonable attorneys’

HOU03:1283630                                                                     

SECURITIES ACCOUNT CONTROL AGREEMENT (Wells Fargo Securities, LLC Custody) (Trading Prohibited)

fees) arising out of Intermediary’s compliance with any instructions from Secured Party with respect to the Collateral, except if such claims, liabilities or expenses are caused by Intermediary’s gross negligence or willful misconduct; provided, however, that any such obligation to indemnify or hold Intermediary harmless shall (a) be an obligation of Secured Party solely in its capacity as Collateral Agent under the Intercreditor and Collateral Agency Agreement, by and between, among others, Secured Party and Customer; (b) limited solely to funds available under such Intercreditor and Collateral Agency Agreement at any point in time; and (c) not limit in any way Secured Party’s right to reimbursement of such amounts from Customer in accordance with the terms of such Intercreditor and Collateral Agency Agreement.

8.          MISCELLANEOUS.

(a)This Agreement shall not create any obligation or duty of Intermediary except as expressly set forth herein.

(b)As to the matters specifically the subject of this Agreement, in the event of any conflict between this Agreement and the Account Agreement or any other agreement between Intermediary and Customer, the terms of this Agreement shall control.

(c)All notices, requests and demands which any party is required or may desire to give to any other party under any provision of this Agreement must be in writing (unless otherwise specifically provided) and delivered to each party at the address or facsimile number set forth below its signature, or to such other address or facsimile number as any party may designate by written notice to all other parties.  Each such notice, request and demand shall be deemed given or made as follows: (i) if sent by hand delivery, upon delivery; (ii) if sent by facsimile, upon receipt; and (iii) if sent by mail, upon the earlier of the date of receipt or three (3) days after deposit in the U.S.  mail, first class and postage prepaid.

(d)This Agreement shall be binding upon and inure to the benefit of the heirs, executors, administrators, legal representatives, successors and assigns of the parties; provided however, that Intermediary may not assign its obligations hereunder without Secured Party’s prior written consent.  This Agreement may be amended or modified only in writing signed by all parties hereto.

(e)This Agreement shall terminate upon: (i) Intermediary’s receipt of written notice from Secured Party expressly stating that Secured Party no longer claims any security interest in the Collateral; or (ii) termination of the Account Agreement pursuant to the terms hereof and Intermediary’s delivery of all Collateral to Secured Party or its designee in accordance with Secured Party’s written instructions.

This Agreement shall be governed by and construed in accordance with the laws of the State of New York.  The State of New York is, and will continue to be, Intermediary’s jurisdiction for purposes of Section 8-110(e) of the UCC so long as this Agreement shall remain in effect.

HOU03:1283630                                                                     

HOUO3:1286180                                                                                                                                  5

SECURITIES ACCOUNT CONTROL AGREEMENT (Wells Fargo Securities, LLC Custody) (Trading Prohibited)

IN WITNESS WHEREOF, the parties have executed this Agreement as of the date first set forth above.

CUSTOMER:

GILL RANCH STORAGE, LLC

By:

Name: David A.  Weber

Title:              President and Chief Executive Officer

Address: 220 NW Second Ave., 9th Floor, Portland, Oregon 97209

FAX No: (503) 721-2490

SECURED PARTY:

THE PRUDENTIAL INSURANCE COMPANY OF AMERICA, as collateral agent

By:

Name: Brian E.  Lemons

Title:              Vice President

Address: 2200 Ross Avenue, Suite 4200E, Dallas, TX 75201

FAX No: (214) 720-6299

INTERMEDIARY:

WELLS FARGO SECURITIES, LLC

By: Name:

Title:            Operations Officer

Address: 608 2nd Avenue South, Suite 500, Minneapolis, MN 55402

FAX No: (855) 838-5722

Please send the original agreement to the Pledge Desk at MAC #N9303-054.

Wells Fargo Securities is the trade name for certain capital markets and investment banking services of Wells Fargo & Company and its subsidiaries, including Wells Fargo securities, LLC, a member of NYSE, FINRA and SIPC, and Wells Fargo Institutional securities, LLC, a member of FINRA and SIPC, and Wells Fargo Bank, National Association.  Wells Fargo Securities, LLC carries and provides clearing services for Wells Fargo Institutional Securities, LLC customer accounts.

EXHIBIT D

FORM OF INTERCREDITOR AND COLLATERAL AGENCY AGREEMENT

HOU03:1282704                                                              Exhibit D

EXECUTION COPY

INTERCREDITOR AND COLLATERAL AGENCY AGREEMENT

THIS INTERCREDITOR AND COLLATERAL AGENCY AGREEMENT (this “Agreement”), dated as of November 30, 2011, is (x) made by and between the NOTEHOLDERS (as hereinafter defined), THE PRUDENTIAL INSURANCE COMPANY OF AMERICA, in both its individual capacity (in such capacity, “Prudential”) and in its capacity as agent as more specifically set forth in Article IV hereof (in such capacity, and together with its successors and assigns, the “Collateral Agent”) for the Noteholders from time to time parties hereto and (y) consented and agreed to by the hereinafter defined Company and Parent (each as hereinafter defined).

PRELIMINARY STATEMENTS

A. GIll ranch storage, LLC, an Oregon limited liability company (the “Company”), Prudential and the other initial purchasers, if any, party thereto are entering into a Note Purchase Agreement, dated as of even date herewith (as the same may be modified, amended, supplemented, joined or restated in accordance with its terms, including any extensions, renewals, increases and replacements thereof, the “Note Agreement”), pursuant to which the Company will issue and such purchasers (the purchasers and their respective successors and assigns, and any other holders from time to time of the Notes described below are referred to herein as the “Noteholders”) will purchase the 7.75% Senior Secured Notes due November 30, 2016 and the Floating-Rate Senior Secured Notes due November 30, 2016 in the aggregate principal amount of $40,000,000 (together with any notes given in substitution, or exchange, or in modification, renewal, rearrangement or extension, in whole or in part, for the notes described in the foregoing, the “Notes”).

B. The Company and NW Natural Gas Storage, LLC, an Oregon limited liability company (the “Parent”), as applicable, have executed and delivered the Security Documents (as defined in the Note Agreement), providing liens and security interests in favor of the Collateral Agent in the property described in such Security Documents in order to ratably secure the obligations under and in respect of the Notes, the Note Agreement and the other Financing Documents (as defined in the Note Agreement).

C. Under applicable law, the Noteholders may be entitled to set off indebtedness owing by the Noteholders to or for the credit of the Company, against and on account of liabilities of the Company under the Note Agreement (collectively, the “Set-Off Rights”).

D. It is a condition precedent to the effectiveness of the Note Agreement that this Agreement shall have been executed and delivered in order to (i) set forth certain responsibilities and obligations of the Collateral Agent and (ii) establish among the Noteholders their respective rights with respect to certain payments that may be received (1) by the Collateral Agent in respect of the Collateral (as defined in the Note Agreement) and (2) otherwise by any of the Noteholders pursuant to any Set-Off Rights.

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NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows:

ARTICLE I DEFINITIONS

SECTION 1.1. Uniform Definitions; Cross-references. The capitalized terms used herein and defined in the Note Agreement but not otherwise defined in this Agreement are used herein with the meaning therein specified. Each reference to a particular section paragraph or other provision of the Note Agreement is a reference to such section, paragraph or other provision.

SECTION 1.2. Additional Definitions. The following terms, as used herein, have the following meanings:

“Acceleration” shall mean the earlier of (a) the acceleration of the maturity of any amount outstanding under the Note Agreement and the Notes and (b) a Bankruptcy Event.

“Acceleration Date” shall mean the earliest date on which an Acceleration occurs.

“Agreement” shall have the meaning specified in the preamble to this Agreement.

“Assignee” shall mean any assignee or other transferee of any portion of the right, title or interest of any Noteholders to the extent permitted under the Note Agreement, except for any such transferee that becomes a Noteholder for purposes hereof in accordance with Section 6.2 hereof.

“Bankruptcy Event” shall mean an event with respect to the Company or the Parent specified in Sections 11(g) or 11(h) of the Note Agreement.

“Breakage Costs” shall mean, at any time, amounts then payable by the Company under Section 8.8(b) of the Note Agreement.

“Collateral Agent” shall have the meaning specified in the preamble hereto.

“Company” shall have the meaning specified in Preliminary Statement A hereof.

“Dollars” shall mean lawful currency of the United States of America.

“Event of Default” shall mean an “Event of Default” as defined in the Note Agreement.

“Financial Obligations” shall mean, with respect to any Noteholder, such Noteholder’s Funded Obligations and Other Obligations under the Note Agreement and the Notes.

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“Funded Obligations” shall mean, with respect to any Noteholder, the aggregate amount payable (whether or not then due) to such Noteholder under the Note Agreement and the Notes in respect of principal, interest (determined in accordance with the applicable provisions of the Note Agreement and the Notes, but only to the extent accrued through the applicable determination date) or any Make-Whole Amounts, Premium or Breakage Costs.

“Note Agreement” shall have the meaning specified in Preliminary Statement A hereof.

“Noteholders” shall have the meaning specified in the preamble hereto.

“Notes” shall have the meaning specified in Preliminary Statement A hereof.

“Other Obligations” shall mean, with respect to any Noteholder, the aggregate amount payable (whether or not then due) to such Noteholder under the Note Agreement and the Notes other than its Funded Obligations thereunder, including, without limitation, fees, costs and expenses.

“Parent” shall have the meaning specified in Preliminary Statement B hereof.

“Paying Noteholder” shall have the meaning specified in Section 2.3(a) hereof.

“Prudential” shall have the meaning specified in the preamble hereto.

“Purchaser” shall have the meaning specified in Section 6.2 hereof.

“Repaying Noteholder” shall have the meaning specified in Section 2.4 hereof.

“Required Holders” shall have the meaning ascribed thereto in the Note Agreement.

“Set-Off Rights” shall have the meaning specified in Preliminary Statement C of this Agreement.

“Sharing Noteholder” shall have the meaning specified in Section 2.3 hereto.

“Sharing Notice” shall mean a notice given by the Collateral Agent pursuant to Section 2.1 hereof.

“Sharing Percentage” shall mean, as to any Noteholder at any time, with respect to any payment or other amount received by the Collateral Agent or any Noteholder at any time after the Acceleration Date, the percentage equivalent of a fraction of which (a) the numerator is such Noteholder’s Funded Obligations and (b) the denominator is the Total Funded Obligations, in each case as of the Acceleration Date.

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“Total Funded Obligations” shall mean, at any time, the aggregate of all Funded Obligations of all Noteholders then outstanding under the Note Agreement and Notes.

ARTICLE II SHARING AMONG NOTEHOLDERS

SECTION 2.1. Sharing Notice. Upon an Acceleration each Noteholder (if any) causing such Acceleration shall immediately notify the Collateral Agent of such Acceleration and, promptly upon the earlier of receipt of such notice or gaining actual knowledge of such Acceleration, the Collateral Agent shall give notice (a “Sharing Notice”) to each of the Noteholders informing them that the provisions of this Article II are to be implemented and requiring each Noteholder to provide it with all necessary information to enable it to calculate (a) such Noteholder’s Funded Obligations and Financial Obligations (including, without limitation, an itemization of all principal, interest, Make-Whole Amounts, Premiums, Breakage Costs, fees, costs and expenses owing to such Noteholder) as of the Acceleration Date and (b) the Sharing Percentage of each Noteholder. Any Sharing Notice shall be effective as of the date it is sent by the Collateral Agent and shall remain effective until all the Noteholders agree that such Sharing Notice is no longer in effect. If any necessary information is not received by the Collateral Agent within three days after the Collateral Agent delivers the Sharing Notice, the Collateral Agent may request such information from the Company or any other Noteholder. If any such necessary information has not been provided to the Collateral Agent within two days after the Collateral Agent makes such supplemental request, the Collateral Agent may proceed with its calculations based upon the other information available to it and which it reasonably and in good faith believes to be correct. Once the Collateral Agent has either received such necessary information or has determined to proceed based upon such other information available to it, the Collateral Agent shall calculate and promptly notify the Noteholders as to the Funded Obligations and Financial Obligations of each Noteholder as of the Acceleration Date and as to the Sharing Percentage of each Noteholder, which notice shall demonstrate such calculations in reasonable detail. If the Collateral Agent thereafter receives information which demonstrates that the Collateral Agent’s prior calculations were erroneous, the Collateral Agent shall recalculate each Noteholder’s Funded Obligations and Financial Obligations with respect to the Note Agreement and the Notes and each Noteholder’s Sharing Percentage, and shall promptly notify all Noteholders of such recalculations and, if any payments pursuant to Section 2.2 have been made based upon such erroneous prior calculations, the amount to be repaid by or to such Noteholder as a result of such recalculations. Each Noteholder that has received an excess payment as a result of such erroneous prior calculations shall promptly (and in any event within five Business Days after its receipt of the Collateral Agent’s recalculations) repay to the Collateral Agent for the account of the other appropriate Noteholders the excess portion of any payments previously received by it.

SECTION 2.2. Payments.

(a) If at any time after the Acceleration Date any Noteholder (or any Assignee of any Noteholder) obtains any payment or other amount (whether by way of voluntary or involuntary payment or prepayment, by virtue of the exercise of any Set-Off Rights or otherwise

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by virtue of the application of any provision of any of the Financing Documents or in any other manner except pursuant to this Agreement) in respect of the Note Agreement or the Notes, such Noteholder, after receipt of a Sharing Notice, shall forthwith notify the Collateral Agent of its (or such Assignee’s) obtaining the same and shall pay to the Collateral Agent for the account of the Noteholders (other than the paying Noteholder) pro rata in accordance with their respective Sharing Percentages an amount equal to such payment or other amount received less such Noteholder’s Sharing Percentage of such payment or other amount, as applicable. Upon receipt of any such payment or other amount the Collateral Agent shall distribute the same to the Noteholders, other than the Noteholder so paying the same, pro rata in accordance with their respective Sharing Percentages.

(b) Upon any distribution made pursuant to clause (a), the Noteholder making such payment shall be deemed to have purchased from each other Noteholder a participation in the Financial Obligations of such other Noteholder; provided, however, that such participation shall be deemed to be of the same class of obligations (i.e., Funded Obligations or Other Obligations) for purposes of this Agreement as the class of obligations to which the payment or other amount received related. The Company and the Parent agree that any Noteholder so purchasing a participation from another Noteholder pursuant to this Section 2.2 may, to the fullest extent permitted by applicable law, exercise all its rights of payment (including, without limitation, any Set-Off Rights) with respect to such participation as fully as if such Noteholder were the direct creditor of the Company or the Parent, as the case may be, in the amount of such participation.

SECTION 2.3. Preferences, etc. If

(a) any Noteholder or its Assignee (a “Paying Noteholder”) makes any payment pursuant to Section 2.2; and

(b) the amount obtained by the Paying Noteholder which gave rise to such payment or any part thereof (the “Relevant Amount”) is required to be repaid, and is repaid, by the Paying Noteholder to the Company or any other Person, then the Collateral Agent (if it shall then hold the same) and each of the other Noteholders which has received any part thereof (each, a “Sharing Noteholder”) shall promptly (and in any event within five Business Days after its receipt of notification from the Collateral Agent requiring such repayment, which notification the Collateral Agent shall dispatch promptly upon its determining the amount of the repayment required from the relevant Sharing Noteholder) repay the portion of the Relevant Amount received by the Collateral Agent or such Sharing Noteholder, as the case may be, to the Paying Noteholder, together with such amount as is equal to the appropriate portion of the interest, if any (in respect of the period during which the Collateral Agent or such Sharing Noteholder (as the case may be) held such portion of the relevant amount), the Paying Noteholder shall have repaid when repaying such relevant amount.

SECTION 2.4. Adjustments to Sharing Percentages. If, at any time after the date of a Sharing Notice, a Noteholder or its Assignee (a “Repaying Noteholder”) is required to repay to the Company or any other Person all or any portion of an amount received on or prior to the

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Acceleration Date, with the result that the Repaying Noteholder’s Funded Obligations are increased, then, after such repayment has been made and the Repaying Noteholder has notified the Collateral Agent thereof, the Sharing Percentages of the Noteholders shall be adjusted on the first Business Day following the Collateral Agent’s receipt of such notification to reflect such increase (and the resultant decrease in the Sharing Percentages of the Noteholders other than the Repaying Noteholder), and each other Noteholder shall promptly (and in any event within five Business Days after its receipt of notification from the Collateral Agent requiring such repayment, which notification the Collateral Agent shall dispatch promptly upon its determining the amount of the repayment required from each such other Noteholder) repay to the Collateral Agent for the account of the Repaying Noteholder the portion of any payments previously received by it under Section 2.2 in excess of its Sharing Percentage as so redetermined, together with such amount (if any) as is equal to the appropriate portion of any interest (in respect of the period during which such other Noteholder held such amount) the Repaying Noteholder shall have repaid when repaying such amount as aforesaid.

SECTION 2.5. Pro Rata Treatment. The Noteholders hereby agree that until payment in full of all Financial Obligations owed to all Noteholders, the Noteholders will receive pro rata treatment, in accordance with their respective Sharing Percentages, in connection with all payments, distributions, collections, recoveries and other matters relating to the Collateral under the Security Documents.

SECTION 2.6. Application of Proceeds. The net proceeds of any sale, enforcement or other disposition of any of the Collateral or other distribution in respect of the Collateral, following an Acceleration, and the net proceeds of any distributions received by the Noteholders or the Collateral Agent following any marshaling of the assets of the Company or the Parent (whether in bankruptcy, reorganization, winding up proceedings or similar proceedings, or otherwise) or following confirmation of a plan of arrangement or plan of reorganization of the Company or the Parent, shall be applied by the Noteholders and the Collateral Agent in the following order:

first, to the payment of all reasonable costs and expenses incurred by the Collateral Agent in connection with the collection or enforcement of the Financial Obligations of the Noteholders or the preservation of, or realization upon, the Collateral under the Security Documents, including, without limitation, reasonable costs and expenses incurred by the Collateral Agent in connection with the defense of any claim, suit, action or proceeding against the Collateral Agent, as provided below in Section 4.7;

second, to the payment of the Funded Obligations of the Noteholders, which payment shall be shared by the Noteholders according to their respective Sharing Percentages;

third, to the payment of the Other Obligations of the Noteholders, which payment shall be shared by the Noteholders according to their respective Sharing Percentages; and

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fourth, to the payment to the Company or the Parent or their respective successors or assigns, or as a court of competent jurisdiction may direct, or otherwise as required by law, if any surplus is then remaining from such proceeds.

ARTICLE III COOPERATION AMONG NOTEHOLDERS

SECTION 3.1. Cooperation. Each Noteholder agrees with each of the other Noteholders and the Collateral Agent that:

(a) it will (and will cause each of its Assignees to) from time to time provide such information to the Collateral Agent as may be necessary to enable the Collateral Agent to make any calculation as referred to in Section 2.1 of this Agreement or otherwise required for any other purpose hereof and to notify the Collateral Agent of any Acceleration;

(b) it will (and will cause each of its Assignees to) from time to time consult with the Collateral Agent and the other Noteholders in good faith regarding the enforcement of its and each of its Assignee’s rights with a view to recovering amounts due under the Note Agreement and the Notes;

(c) it will (and will cause each of its Assignees to), in the case of any Default with respect to which it shall have received notice from, or provided notice to, the Company, give each other Noteholder and the Collateral Agent immediate notice, and if such notice is oral, confirmed in writing, of such Default; and

(d) it will (and will cause each of its Assignees to) give the Collateral Agent and each other Noteholder immediate written notice of any acceleration of any of its or its Assignee’s Financial Obligations.

ARTICLE IV COLLATERAL AGENT

SECTION 4.1. Appointment and Authority of Collateral Agent. In order to expedite the enforcement of the rights and remedies set forth in the Security Documents, the Collateral Agent is hereby appointed to act as agent for the Noteholders hereunder and thereunder. The Collateral Agent is hereby authorized and directed to take such action on behalf of the Noteholders under the terms and provisions of the Security Documents and to exercise such rights and remedies hereunder and thereunder as are specifically delegated to or required of the Collateral Agent under the terms and provisions hereof and thereof. The Collateral Agent is hereby expressly authorized as Collateral Agent on behalf of the Noteholders, without hereby limiting the foregoing, and subject to, and in accordance with, the terms and conditions of this Agreement:

(a) to receive on behalf of each of the Noteholders any payment of monies paid to the Collateral Agent in accordance with the Security Documents, and to distribute to each

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Noteholder its respective portion of all payments so received in accordance with the terms of this Agreement;

(b) to receive, directly or through agents acting on its behalf, all documents and items to be furnished under the Security Documents;

(c) to maintain, directly or through agents acting on its behalf, physical possession of any of the Collateral as contemplated in any of the Security Documents;

(d) to act, directly or through agents acting on its behalf, on behalf of the Noteholders in and under the Security Documents;

(e) to execute and deliver, directly or through agents acting on its behalf, to the Company, the Parent and other Persons requests, demands, notices, approvals, consents and other communications received from the Noteholders in connection with the Security Documents, subject to the terms and conditions set forth herein and therein;

(f) to the extent permitted by this Agreement, the Note Agreement and the Security Documents, to exercise on behalf of each Noteholder all remedies of the Noteholders under any of the Security Documents upon the occurrence and during the continuance of any Event of Default; and

(g) to take such other actions, directly or through agents acting on its behalf, as may be requested by the Required Holders or as are reasonably incident to any powers granted to the Collateral Agent hereunder and not in conflict with applicable law or regulation or any Financing Document.

SECTION 4.2. Non-Reliance on Collateral Agent and Other Noteholders. Each Noteholder agrees that it has, independently and without reliance on the Collateral Agent or any other Noteholder, and based upon such documents and information as it has deemed appropriate, made its own credit analysis of the Company and the Collateral, and its independent decision to enter into this Agreement and the Security Documents, and that it will, independently and without reliance upon the Collateral Agent or any other Noteholder, and based on such documents and information as it shall deem appropriate at the time, continue to make its own analysis and decisions in taking or not taking action under this Agreement and the Security Documents. The Collateral Agent shall not be required to keep the Noteholders informed as to the performance or observance by the Company or the Parent of the Note Agreement, the Security Documents or any other document, instrument or agreement, referred to or provided for therein or to inspect the properties or books of the Company or the Parent. The Collateral Agent shall not have any duty, responsibility or liability to provide any Noteholder with any credit or other information concerning the affairs, financial condition or business of the Company which may come into the possession of the Collateral Agent; provided, however, the Collateral Agent shall send to the Noteholders written notice of any Default or Event of Default of which the Collateral Agent (in its capacity as such) has knowledge or of which it has been given notice, and all payments and repayments of amounts required hereunder to be paid to the Noteholders

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received by the Collateral Agent under or in connection with the Security Documents or this Agreement; and the Collateral Agent shall provide each Noteholder with a schedule of all costs and expenses which the Collateral Agent has paid or proposes to pay from the proceeds of such payments or repayments as permitted hereunder.

SECTION 4.3. Collateral Agent and Affiliates. Prudential and any successor Collateral Agent, in its capacity as a Noteholder, shall have the same rights and powers under the Financing Documents and may exercise or refrain from exercising the same as though it were not the Collateral Agent hereunder, and such Noteholder and its affiliates may lend money to and generally engage in any kind of lending, investment, trust, hedging or other business with or for any Noteholder, the Company or the Parent, or any of their respective affiliates, as if it were not acting as Collateral Agent hereunder, provided that any payments made by the Company or the Parent, or any other Person during the continuance of an Event of Default to any Noteholder on any loans or other extensions of credit made to the Company or the Parent (including interest rate swaps, caps, collars and other derivative instruments) other than under the Note Agreement and the Notes shall be deemed by the Noteholder receiving such payments to be payments under the Note Agreement and the Notes and shall be applied by such Noteholder to its Financial Obligations, unless such payments shall be accompanied by clear instructions from the Company or any such other Person that such payments be applied to such other loan or extension of credit, until all of the Financial Obligations shall be satisfied in full, and any payments received by such Noteholder from the Company or any such other Person in contravention of the immediately preceding clause shall be deemed to be payments received by such Noteholder under Section 2.2 and treated accordingly.

SECTION 4.4. Action by Collateral Agent. The obligations of the Collateral Agent hereunder and under the Financing Documents are only those expressly set forth herein and therein. Notwithstanding anything contained herein or in any Financing Document to the contrary, the Collateral Agent shall not be required to take any action with respect to any Default or Event of Default, except as expressly provided herein and therein.

SECTION 4.5. Consultation with Experts. The Collateral Agent may consult with legal counsel, independent public accountants and any other experts selected by it and shall not be liable for any action taken or omitted to be taken by it in good faith in accordance with the advice of such counsel, accountants or experts.

SECTION 4.6. Liability of Collateral Agent. The Collateral Agent shall be entitled to rely on any communication or document believed by it to be genuine and correct and to have been communicated or signed by the person by whom it purports to be communicated or signed and shall not be liable to any Noteholder for any of the consequences of such reliance. Neither the Collateral Agent nor any director, officer, employee or agent of the Collateral Agent shall be liable for any action taken or not taken by it or them under, or in connection with, this Agreement or any of the Financing Documents in the absence of its or their gross negligence or willful misconduct. As to any matters not expressly provided for herein or in the Financing Documents, the Collateral Agent shall act or refrain from acting in accordance with written instructions from the Required Holders or, in the absence of such instructions, in accordance with

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its discretion, taking into account the interests of all Noteholders. The Collateral Agent shall not be obligated to follow any such written directions to the extent that it shall determine that such directions are in conflict with any provision hereof or of any applicable law or regulation or any Financing Document. Neither the Collateral Agent nor any director, officer, employee or agent of the Collateral Agent shall be responsible for or have any duty to ascertain, inquire into or verify (a) any statement, warranty or representation made in connection with any of the Financing Documents or any payment thereunder; (b) the performance or observance of any of the covenants or agreements of the Company, the Parent or any Noteholder under any of the Financing Documents; (c) the validity, effectiveness or genuineness of the Financing Documents or any other instrument or writing furnished in connection therewith; or (d) the existence, genuineness or value of any of the Collateral or the validity, effectiveness, perfection, priority or enforceability of the security interests in or liens on any of the Collateral.

SECTION 4.7. Indemnification of Collateral Agent; Defense of Claims.

(a) Each Noteholder hereby agrees to indemnify the Collateral Agent and each of the Collateral Agent’s directors, officers, affiliates, representatives and agents (as used in this Section 4.7 “Collateral Agent” shall mean all of the foregoing) against all loss, cost, liability and expense (to the extent not paid by the Company or the Parent, and not arising out of or as a result of gross negligence or willful misconduct on the part of the Collateral Agent), including reasonable attorneys’ fees, resulting from any action taken or to be taken by it as Collateral Agent on behalf of the Noteholders within the scope of its authority as provided in this Agreement or any of the Security Documents, to the extent of such Noteholder’s pro rata share (based upon its pro rata percentage of the Total Funded Obligations) of any such loss, cost, liability and expense.

(b) The Collateral Agent shall notify each Noteholder as promptly as is reasonably practicable of the written assertion of, or the commencement of, any claim, suit, action or proceeding filed against the Collateral Agent arising out of, or in connection with, the acceptance or administration of the duties imposed upon the Collateral Agent hereunder or under any of the Financing Documents or any action or omission taken or made within the scope of the rights or powers conferred upon the Collateral Agent hereunder or under the Financing Documents promptly after the Collateral Agent shall have received the written assertion or have been served with the summons or other first legal process giving information as to the nature and basis of the lawsuit. Each Noteholder shall be entitled to participate in and assume, at its own expense, the defense of any such claim, suit, action or proceeding, and such defense shall be conducted by counsel chosen by such Noteholder and reasonably satisfactory to the Collateral Agent, provided, however, that (i) if any Noteholder has not assumed the defense of such claim, suit, action or proceeding, (ii) if the attorneys handling the defense are not reasonably satisfactory to the Collateral Agent, or (iii) if the defendants in any such action include both the Collateral Agent and the Noteholders and the Collateral Agent shall have been advised by its counsel that there may be legal defenses available to it that are different from or additional to those available to the Noteholders which in the reasonable opinion of such counsel are sufficient to make it undesirable for the same counsel to represent both the Noteholders and the Collateral Agent, the Collateral Agent shall have the right to employ its own counsel in all such instances described in

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(i), (ii) or (iii) above, and shall be entitled to recover from any proceeds received pursuant to Section 2.6 all reasonable fees of such counsel. If more than one Noteholder gives notice of assumption of defense, the matter shall be presented to all the Noteholders and, unless the Collateral Agent receives notice from the Required Holders specifying the Noteholder that is to assume the defense, the Collateral Agent shall proceed itself with the defense. Except as provided above, the Collateral Agent’s right to recover its reasonable counsel fees from proceeds received pursuant to Section 2.6 shall cease upon any Noteholder’s assumption of the defense of the claim, suit, action or proceeding. Each Noteholder and the Collateral Agent is always entitled to defend itself at its own expense. Neither the Noteholders nor the Collateral Agent shall be bound by any settlement entered into by the other parties without such party’s consent.

SECTION 4.8. Resignation or Removal of Collateral Agent. Subject to the appointment and acceptance of a successor Collateral Agent as provided below, the Collateral Agent may resign at any time by giving notice thereof to each Noteholder and the Company. Upon any such resignation, a successor Collateral Agent may be appointed by the Required Holders and, so long as no Event of Default has occurred and is continuing, subject to the approval of the Company (which approval by the Company should not be unreasonably withheld, conditioned or delayed). If no successor Collateral Agent shall have been appointed as aforesaid and shall have accepted such appointment within 30 days after the retiring Collateral Agent’s giving of notice of resignation, then the retiring Collateral Agent may, on behalf of the Noteholders, appoint a successor Collateral Agent which shall be a depository institution with capital and surplus greater than $250,000,000 and which shall be qualified to perform its duties hereunder and under the Security Documents and which, so long as no Event of Default has occurred and is continuing, shall be reasonably satisfactory to the Company (not to be unreasonably withheld, conditioned or delayed).

If the Collateral Agent shall fail or refuse to perform or commence performing any act set forth in written instructions delivered pursuant to, and in accordance with the terms and conditions of, this Agreement (other than where such nonperformance is beyond the control of the Collateral Agent or where such performance would entail a violation of applicable law or conflict with the provisions of this Agreement or any Financing Document), and such failure continues for a period of 15 days from the date of receipt of said written instructions, the Collateral Agent may be removed by any Noteholder directing the action which the Collateral Agent failed or refused to take. Any such Noteholder shall also have the right to appoint a successor Collateral Agent with the consent of the other Noteholders (other than the Noteholder so removed as Collateral Agent) and, so long as no Event of Default has occurred and is continuing, the approval of the Company (which approval by the Company should not be unreasonably withheld, conditioned or delayed), and if no successor Collateral Agent shall have been so appointed and shall have accepted such appointment within five Business Days after removal, then any Noteholder which directed the action which the Collateral Agent failed or refused to take may, on behalf of Noteholders, appoint a successor Collateral Agent which shall be a depository institution with capital and surplus greater than $250,000,000 and which shall be qualified to perform its duties hereunder and under the Security Documents and which, so long

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as no Event of Default has occurred and is continuing, shall be reasonably satisfactory to the Company (not to be unreasonably withheld, conditioned or delayed).

Upon the acceptance of any appointment as Collateral Agent hereunder by a successor Collateral Agent, such successor Collateral Agent shall thereupon succeed to and become vested with all the rights, powers, privileges and duties of the retiring Collateral Agent, and the retiring Collateral Agent shall be discharged from its duties and obligations hereunder, except to the extent provided above for acts or omissions prior to the resignation or termination. After any retiring Collateral Agent’s resignation or removal hereunder as Collateral Agent, (a) the provisions of Sections 4.6 and 4.7 shall continue in effect for its benefit in respect of any actions taken or omitted to be taken by it while it was acting as Collateral Agent, (b) any Collateral held in possession of the retiring Collateral Agent shall be delivered to the successor Collateral Agent, and (c) the retiring Collateral Agent shall assign all of its rights as secured party, mortgagee, assignee, deed of trust beneficiary or other similar position with respect to all of the Collateral to the successor Collateral Agent for the pro rata benefit of the Noteholders.

SECTION 4.9. Appointment of Co-Agents. At any time or times, in order to comply with any legal requirement in any jurisdiction, the Collateral Agent may appoint a bank or trust company or one or more other persons, either to act as co-agent or co-agents, jointly with the Collateral Agent, or to act as separate agent or agents on behalf of the Noteholders with such power and authority as may be necessary for the effectual operation of the provisions hereof and may be specified in the instrument of appointment (which may, in the discretion of the Collateral Agent, include provisions for the protection of such co-agent or separate agent similar to the provisions of this Article IV).

SECTION 4.10. Compensation of Collateral Agent; Expenses. The Collateral Agent agrees to serve hereunder without compensation. Any successor Collateral Agent appointed pursuant to Section 4.8 shall be compensated by the Company on a scheduled basis which shall be approved by the Required Holders and the Company (which approval by the Company should not be unreasonably withheld, conditioned or delayed). Such compensation paid to any successor Collateral Agent and all reasonable out-of-pocket expenses incurred by the Collateral Agent or such successor Collateral Agent on behalf of the Noteholders incident to the exercise or enforcement of any terms or provisions of the Security Documents shall be indebtedness to the Collateral Agent or such successor Collateral Agent, secured by the Collateral. Upon the request of the Collateral Agent or such successor Collateral Agent, however, the Noteholders will reimburse the Collateral Agent or such successor Collateral Agent, to the extent not paid by the Company or the Parent, for any such expenses (but in no event any fees) in accordance with each Noteholder’s pro rata percentage of the Total Funded Obligations.

SECTION 4.11. Release of Collateral. The Company may from time to time request the Collateral Agent in writing, with copies thereof delivered simultaneously to all Noteholders, to instruct the Securities Intermediary (as defined in the Security Agreement) to withdraw a portion of the Collateral held in the Debt Service Reserve Account (as defined in the Security Agreement), if and to the extent such Collateral exceeds the Minimum Debt Service

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Reserve Requirement. Promptly after the Collateral Agent receives such written request from the Company and the Required Holders have determined that no Default or Event of Default exists or would result from such withdrawal (or at such later time when any such Default or Event of Default shall have been cured, waived or is no longer continuing), the Collateral Agent shall instruct the Securities Intermediary to withdraw and transfer such Collateral in accordance with the provisions in the Security Agreement and the Control Agreement.

ARTICLE V ENFORCEMENT OF REMEDIES

SECTION 5.1. Waivers of Rights. Except as otherwise expressly set forth herein, so long as the Financial Obligations remain unpaid, the Noteholders hereby agree to refrain from exercising any and all rights each may individually (i.e., other than through the Collateral Agent) now or hereafter have to exercise any right pursuant to the Security Documents, the Uniform Commercial Code as in effect in any applicable jurisdiction, or under similar provisions of the laws of any jurisdiction or in equity or otherwise to dispose of or retain any of the Collateral. The Noteholders hereby agree not to take any action whatsoever to enforce any term or provision of the Security Documents or to enforce any right with respect to the Collateral, in conflict with this Agreement or the terms and provisions of the Security Documents.

SECTION 5.2. [Omitted.]

SECTION 5.3. Right to Instruct Collateral Agent. Upon Acceleration under the Note Agreement, the Required Holders may instruct the Collateral Agent to liquidate the Collateral in the manner described in the Security Documents.

SECTION 5.4. Suits by the Noteholders. The Noteholders shall have no right to institute any action, suit or proceeding at law or in equity or otherwise for foreclosure upon the Collateral, for the appointment of a receiver, for the enforcement of any other remedy hereunder or for the execution of any other power or right hereunder, unless:

(a) the Required Holders shall have made written request to the Collateral Agent either to institute such action, suit or proceeding in its own name or to proceed to execute any other powers or trusts herein granted to the Collateral Agent and shall have afforded to the Collateral Agent opportunity to do so and shall have offered to the Collateral Agent reasonable security and indemnity reasonably satisfactory to the Collateral Agent against the costs, expenses and other charges to be incurred therein or thereby (including, without limitation, reasonable attorneys’ fees and expenses); and

(b) the Collateral Agent shall have refused or neglected to act on such request within a reasonable time;

and such notification, request, offer of security and indemnity and refusal or neglect are hereby declared to be conditions precedent to the enforcement by the Noteholders of any action or cause of action for foreclosure or for the appointment of a receiver or for any other remedy hereunder

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or to the execution by the Noteholders of any other powers or rights under this Agreement; it being understood and intended that the Noteholders shall not have any right in any manner whatsoever hereunder or under the Notes, the Note Agreement, this Agreement or the other Note Documents, by its action or their action to affect, disturb or prejudice the Lien created under this Agreement or to enforce any right hereunder, except in the manner herein provided, and that all proceedings hereunder, at law or in equity or otherwise, shall be instituted, had and maintained in the manner herein provided to the Collateral Agent and for the benefit of the Noteholders; provided that nothing contained in this Agreement or in the Notes, the Note Agreement, or the other Note Documents shall affect or impair the obligation of the Company, which is absolute and unconditional, to pay the principal of, Make-Whole Amounts, Premium or Breakage Costs, if any, and interest on, and any amount due under the Notes or the other Note Documents (and interest accruing after the filing of any petition in bankruptcy, or the commencement of any insolvency, reorganization or like proceeding, whether or not a claim for post-filing or post-petition interest is allowed in such proceeding) at the time and place, from the source and in the manner expressed herein and in the Notes, the Note Agreement and the other Note Documents or affect or impair the right, which is also absolute and unconditional, of the Noteholders to enforce by action at law the payment thereof in accordance with the respective terms thereof.

SECTION 5.5. Other Rights. Nothing contained in this Agreement shall affect or impair the right, if any, that any Noteholder may have to accelerate and demand repayment of such indebtedness as provided in the Note Agreement. Each Noteholder retains the right to exercise freely its rights and remedies against the Company or the Parent in accordance with applicable law and subject to the terms of the Note Documents, including without limitation the right to file a lawsuit and obtain a judgment in connection therewith against the Company or the Parent and to enforce such judgment against any assets of the Company or the Parent.

ARTICLE VI SUCCESSORS AND ASSIGNS

SECTION 6.1. Assignees. No provision of this Agreement shall restrict in any manner the assignment, participation or other transfer by any Noteholder of all or any part of its right, title or interest under the Note Agreement and the Notes; provided that, unless the transferee becomes a Noteholder for purposes hereof in accordance with Section 6.2, the transferor Noteholder shall remain responsible for performance of this Agreement with respect to the interest transferred, all as more fully set forth herein, and the Collateral Agent shall have no responsibilities to and need not acknowledge the interests of such transferee.

SECTION 6.2. Additional Noteholders. In connection with an assignment of all, or of a proportionate part of all, of its right, title and interest under the Note Agreement and the Notes to any insurance company, bank or other financial institution (a “Purchaser”), all in accordance with the applicable provisions of the Note Agreement and the Notes, such Purchaser shall become a Noteholder hereunder only upon (a) the written agreement of such transferor Noteholder and such Purchaser and (b) the receipt by the Collateral Agent of a Supplement to Intercreditor and Collateral Agency Agreement substantially in the form of Attachment A hereto executed and delivered by such Purchaser.

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ARTICLE VII MISCELLANEOUS

SECTION 7.1. No Partnership or Joint Venture. Nothing contained in this Agreement, and no action taken by the Collateral Agent or the Noteholders (or any of them) pursuant hereto, is intended to constitute or shall be deemed to constitute the Noteholders a partnership, association, joint venture or other entity.

SECTION 7.2. Notices. Unless otherwise specified herein, all notices, requests and other communications to any party hereunder shall be in writing (including overnight delivery service, facsimile copy or similar writing) and shall be given to such party at its address or facsimile number specified pursuant to the Note Agreement, on the signature pages hereof, or such other address or facsimile number as such party may hereafter specify for the purpose by notice to the Collateral Agent. All such notices and other communications shall, when mailed, delivered by overnight delivery service or transmitted by facsimile, be effective three (3) days after being deposited in the mails, one (1) day after being delivered to the overnight delivery service or when transmitted by telecopier with receipt confirmed, respectively.

SECTION 7.3. Amendments and Waivers. Any provision of this Agreement may be amended or waived if, and only if, such amendment or waiver is in writing and signed by each of the Noteholders (and, if the rights or duties of a Collateral Agent are affected thereby, by such Collateral Agent); provided that any amendment of Article I, Sections 2.2(b), 2.6, 4.6, 4.8, 4.9, 4.10, 4.11, Article V, 7.2, 7.3, 7.4, 7.5, 7.7 or 7.8 must be approved in writing by the Company).

SECTION 7.4. Payments. All payments hereunder shall be made in Dollars in immediately available funds. All payments to the Collateral Agent shall be made to it at such office or account as it may specify for the purpose by notice to the Noteholders. All payments to any Noteholder shall be made to it, to the extent practicable, in accordance with the provisions of the Note Agreement and the Notes.

SECTION 7.5. Counterparts; Effectiveness. This Agreement may be signed in any number of counterparts, each of which shall be an original, and all of which taken together shall constitute a single agreement, with the same effect as if the signatures thereto and hereto were upon the same instrument. This Agreement shall become effective when (a) the Collateral Agent shall have received counterparts hereof executed by each of the parties listed on the signature pages hereof and (b) the Note Agreement shall have become effective.

SECTION 7.6. Benefits. All covenants and other agreements in this Agreement contained by or on behalf of any of the parties hereto shall bind and inure to the benefit of the respective successors and permitted assigns of the parties hereto (in accordance with the provisions of Section 6.2 hereof, as applicable), whether so expressed or not.

SECTION 7.7. Term. This Agreement shall remain in effect until all the Financial Obligations are paid in full.

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SECTION 7.8. Governing Law. This Agreement shall be construed and enforced in accordance with, and the rights of the parties shall be governed by, the law of the State of New York WITHOUT REGARD TO CONFLICT OF LAW principles OTHER THAN SECTION 5-1401 OF THE NEW YORK GENERAL OBLIGATIONS LAW.

[Remainder of Page Intentionally Left Blank; Signature Pages Follow]

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IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed by their respective officers hereunto duly authorized as of the date first above set forth.

COLLATERAL AGENT:

THE PRUDENTIAL INSURANCE COMPANY OF

AMERICA

By:

Title: Vice President:

Address:

The Prudential Insurance Company of America

c/o Prudential Capital Group

2200 Ross Avenue

Suite 4200E

Dallas, TX 75201

Attention: Managing Director, Energy and Corporate Finance

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NOTEHOLDERS:

THE PRUDENTIAL INSURANCE COMPANY OF

AMERICA

By:

Title: Vice President:

Address:

The Prudential Insurance Company of America

c/o Prudential Capital Group

2200 Ross Avenue

Suite 4200E

Dallas, TX 75201

Attention: Managing Director, Energy and Corporate Finance

PRUCO LIFE INSURANCE COMPANY

By:

Title: Assistant Vice President:

Address:

Pruco Life Insurance Company

c/o Prudential Capital Group

2200 Ross Avenue

Suite 4200E

Dallas, TX 75201

Attention: Managing Director, Energy and Corporate Finance

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PRUCO LIFE INSURANCE COMPANY OF NEW JERSEY

By:

Title: Assistant Vice President:

Address:

Pruco Life Insurance Company of New Jersey

c/o Prudential Capital Group

2200 Ross Avenue

Suite 4200E

Dallas, TX 75201

Attention: Managing Director, Energy and Corporate Finance

PRUDENTIAL RETIREMENT INSURANCE AND ANNUITY COMPANY

By: Prudential Investment Management, Inc.,

as investment manager

By:______________________________

Title: Vice President

Address:

Prudential Retirement Insurance and Annuity Company

c/o Prudential Capital Group

2200 Ross Avenue

Suite 4200E

Dallas, TX 75201

Attention: Managing Director, Energy and Corporate Finance

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PRUDENTIAL ANNUITIES LIFE ASSURANCE CORPORATION

By:

Title: Assistant Vice President:

Address:

Prudential Annuities Life Assurance Corporation

c/o Prudential Capital Group

2200 Ross Avenue

Suite 4200E

Dallas, TX 75201

Attention: Managing Director, Energy and Corporate Finance

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CONSENTED AND AGREED TO AS OF THE DATE FIRST ABOVE SET FORTH:

GILL RANCH STORAGE, LLC

By:

Name: David A. Weber

Title: President and Chief Executive Officer

NW NATURAL GAS STORAGE, LLC

By:

Name: David A. Weber

Title: President and Chief Executive Officer

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HOU03:1283630                                                        Attachment A - 2

Attachment A

SUPPLEMENT TO INTERCREDITOR AND COLLATERAL AGENCY AGREEMENT

(SUCCESSOR NOTEHOLDERS)

[Date]

Re: Intercreditor and Collateral Agency Agreement dated as of November 30, 2011 (the “Collateral Agency Agreement”) made by and between the financial institutions listed under the caption “Noteholders” on the signature pages thereto (collectively, with the other holders from time to time of the hereinafter described Notes who become a party thereto in accordance with Article VI thereof, and together with their successors and assigns, the “Noteholders”) and The Prudential Insurance Company of America (“Prudential”), as Collateral Agent for itself and the other Noteholders; capitalized terms used herein and not otherwise defined herein shall have the meaning provided in the Collateral Agency Agreement.

Ladies and Gentlemen:

We acknowledge that we have received a copy of the Collateral Agency Agreement and we refer to Section 6.2 thereof.

Upon your receipt of this Supplement, we (a) shall have all the rights and benefits of a “Noteholder” under the Collateral Agency Agreement as if we were an original signatory thereto, and (b) agree to be bound by the terms and conditions set forth in the Collateral Agency Agreement and to be obligated thereunder as if we were an original signatory thereto.

We hereby advise you that we have succeeded to [[________]% of] the interest of [applicable Noteholder] under the Note Agreement [as the holder of Fixed-Rate/Floating-Rate Notes] and have assumed the obligations of [applicable Noteholder] thereunder.

We hereby advise you of the following administrative details:

Address:

Facsimile:

Telephone:

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HOU03:1283630                                                        Attachment A - 2

IN WITNESS WHEREOF, the undersigned has caused this Supplement to be duly executed by its proper officer hereunto duly authorized.

[NEW NOTEHOLDER]

By:

Name:

Title:

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EXHIBIT E

FORM OF PLEDGE AGREEMENT

HOU03:1282704                                                              Exhibit E

EXECUTION COPY

PLEDGE AGREEMENT

THIS PLEDGE AGREEMENT (this “Agreement”), dated as of November 30, 2011, is made by NW NATURAL GAS STORAGE, LLC, an Oregon limited liability company (the “Pledgor”), to THE PRUDENTIAL INSURANCE COMPANY OF AMERICA, as collateral agent (in such capacity, together with its successors and assigns, the “Collateral Agent”) for the benefit of itself in such capacity and of the Noteholders (as hereinafter defined) under that certain Intercreditor and Collateral Agency Agreement, dated as of even date herewith (as the same may be amended, restated, supplemented or otherwise modified from time to time, the “Collateral Agency Agreement”), among the Collateral Agent, the Noteholders, the Company (as hereinafter defined) and the Pledgor.

RECITALS

A. Gill Ranch Storage, LLC, an Oregon limited liability company (the “Company”), The Prudential Insurance Company of America and any other Purchasers (defined therein) party thereto are entering into a Note Purchase Agreement, dated as of even date herewith (as the same may be modified, amended, supplemented, joined or restated in accordance with its terms, including any extensions, renewals, increases and replacements thereof, the “Note Agreement”), pursuant to which the Company will issue and the Purchasers (the Purchasers and their respective successors and assigns, and any other holders from time to time of the Notes described below are referred to herein as the “Noteholders”) will purchase the 7.75% Senior Secured Notes due November 30, 2016 and the Floating-Rate Senior Secured Notes due November 30, 2016 in the aggregate principal amount of $40,000,000 (together with any notes given in substitution, or exchange, or in modification, renewal, rearrangement or extension, in whole or in part, for the notes described in the foregoing, the “Notes”).

B. It is a condition precedent to the agreement of the Noteholders to accept and purchase the Notes that this Agreement shall have been executed and delivered by the Pledgor and shall be in full force and effect.

C. The Pledgor has determined that the execution, delivery and performance of this Agreement may reasonably be expected to provide substantial benefit to the Pledgor, directly or indirectly, and to be in the best interests of the Pledgor.

NOW, THEREFORE, in consideration of the premises and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, and in order to induce the Noteholders to enter into the Note Agreement and to accept and purchase the Notes to be issued to the Noteholders thereunder on the date hereof, the Pledgor hereby covenants and agrees with the Collateral Agent as follows:

Section 1. Defined Terms and Related Matters.

(a) Capitalized terms used and not otherwise defined herein that are defined in the Note Agreement shall have the respective meanings specified therein. Terms defined in the singular include the plural and terms defined in the plural include the singular.

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(b) The words “hereof,” “herein” and “hereunder” and words of similar import when used in this Agreement shall refer to this Agreement as a whole and not to any particular provision of this Agreement.

(c) Unless otherwise defined herein or in the Note Agreement, the terms defined in Articles 8 and 9 of the Uniform Commercial Code as enacted in the State of New York as in effect from time to time (the “UCC”), are used herein as therein defined.

(d) Should any Event of Default under the Note Agreement occur and be continuing, the same shall constitute an Event of Default under this Agreement (an “Event of Default”).

(e) “Pledged Membership Interests” shall mean, with respect to the Pledgor, all interests of the Pledgor, now owned or hereafter acquired, in the Company and the certificates, if any, representing such interests and any interest of the Pledgor on the books and records of the Company or on the books and records of any Securities Intermediary pertaining to such interests and all dividends and distributions (except as contemplated under Section 7(a)(ii) below) cash, warrants, rights, options, instruments, securities, equity interests and other property or proceeds from time to time received, receivable or otherwise distributed in respect of or in exchange for any or all of such interests including, without limitation, the interests identified on Schedule A hereto as Pledged Collateral, as such Schedule A may be updated and supplemented from time to time in accordance with Section 6(c) hereof.

Section 2. Security Interest. The Pledgor hereby grants to the Collateral Agent a lien on and security interest in all of the Pledgor’s rights, titles, interests and privileges in and to the Pledged Membership Interests, whether now owned or hereafter acquired, including, without limitation: (a) all certificates or instruments, if any, representing the Pledged Membership Interests and all proceeds, income and profits thereon, and all interest, dividends and other payments, property and distributions with respect thereto except as contemplated under Section 7(a)(ii) below); (b) all proceeds received or receivable by the Pledgor in cash, equity interests or otherwise, from any recapitalization, reclassification, merger, dissolution, liquidation or other termination of the existence of the Company; and (c) all other proceeds or assets received or receivable by the Pledgor in respect of its status as a limited liability company member of the Company (collectively, the “Pledged Collateral”); provided, that the inclusion of proceeds in this Agreement does not authorize the Pledgor to sell, dispose of or otherwise use the Pledged Collateral in any manner not specifically authorized hereby or by the Note Agreement.

Section 3. Security for Obligations. The lien and security interest granted in this Agreement secure: (a) the full and prompt payment of the principal of, any Make-Whole Amounts, Premium or Breakage Cost Obligations, and interest on, and all other amounts due with respect to the Notes from time to time outstanding, as and when such amounts shall become due and payable in accordance with the Note Agreement, whether by lapse of time, upon redemption, prepayment or purchase, by extension or by acceleration or declaration or otherwise (including, without limitation, (i) interest due at the Default Rate on any amount due hereunder and as provided under the Note Agreement or under any other Financing Document and (ii) interest accruing after the filing of any petition in bankruptcy, or the commencement of any insolvency, reorganization or like proceeding, whether or not a claim for post-filing or post-petition interest is allowed in such proceeding); (b) the full and prompt payment, performance

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and observance by the Pledgor and any other Person (other than the Noteholders or the Collateral Agent or their respective agents or representatives) of all obligations, covenants, indemnifications, conditions and agreements contained in any of the Financing Documents; and (c) the full and prompt payment of the indemnities of the Pledgor contained in each of the Financing Documents and of all costs and expenses due and payable pursuant to Section 15.1 of the Note Agreement (all such obligations, covenants, conditions and agreements described in the foregoing clauses (a), (b) and (c) being hereinafter collectively referred to as the “Secured Obligations”).

Section 4. Formalities.

(a) All certificates and instruments representing the Pledged Membership Interests have been, or, in the case of all Pledged Membership Interests hereafter acquired, immediately upon acquisition shall be, delivered to and shall be held by or on behalf of the Collateral Agent pursuant hereto in suitable form for transfer by delivery, or accompanied by instruments of transfer or assignment, duly executed in blank, all in form and substance reasonably satisfactory to the Collateral Agent, together with evidence of the Pledgor’s unrevoked election that such Pledged Membership Interests are governed as “securities” under Chapter 8 of the Oregon Uniform Commercial Code.

(b) Notwithstanding anything to the contrary contained in clause (a) above, the Pledgor shall promptly take all actions required to perfect the security interest of the Collateral Agent in the Pledged Collateral (whether now owned or hereafter acquired) under applicable law (including, in any event, under the provisions of Article 8 or 9 of the UCC, as applicable) and the Pledgor agrees to execute and deliver to the Collateral Agent a Pledge Instruction in substantially the form attached hereto as Annex B. The Pledgor further agrees to take such actions as the Collateral Agent reasonably deems necessary to effect the foregoing and to permit the Collateral Agent to exercise any of its rights and remedies hereunder.

(c) The Collateral Agent shall have the right, at any time in its reasonable discretion and without notice to the Pledgor, (i) to transfer to any of its nominees any or all of the Pledged Collateral, subject only to the revocable rights specified in Section 7(a) of this Agreement and to applicable law, and (ii) so long as an Event of Default shall have occurred and be continuing, to record on the books and records of the Company or otherwise register any or all of the Pledged Collateral in its own name or the name of its nominee. In addition, the Collateral Agent shall have the right at any time to exchange any certificates or instruments representing any portion of the Pledged Collateral for certificates or instruments of smaller or larger denominations.

(d) The Pledgor hereby authorizes the Collateral Agent to file one or more financing or continuation statements, and amendments thereto, relating to all or any part of the Pledged Collateral without the signature of the Pledgor where permitted by law. A photocopy or other reproduction of this Agreement or any financing statement covering the Pledged Collateral or any part thereof shall be sufficient as a financing statement where permitted by law. For the avoidance of doubt, it shall be the primary responsibility of the Pledgor to perfect and to maintain the perfection of the security interest in the Pledged Collateral.

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Section 5. Representations, Warranties and Covenants. The Pledgor represents, warrants and covenants as of the date hereof (and as to Pledged Collateral hereafter acquired, as of the date of each such acquisition) as follows:

(a) The Pledged Collateral: (i) is described in Schedule A hereto; (ii) has been duly and validly issued, if applicable, and all contributions required to be made by the Pledgor under any applicable operating agreement or other governing document relating to the Pledged Collateral have been made; and (iii) is not subject to any options, warrants, calls or other similar arrangements of any character whatsoever relating thereto other than, depending upon the proposed transferee of the Pledged Collateral, the right of first refusal contemplated under Section 10.4 of the Joint Project Agreement.

(b) All limited liability company transfer powers or other instruments of transfer or assignment relating to certificates representing or evidencing the Pledged Membership Interests, executed in blank and delivered by the Pledgor to the Collateral Agent herewith, have been duly executed by the Pledgor and vest in the Collateral Agent the authority that they purport to confer.

(c) The Pledgor is the legal and beneficial owner of the Pledged Collateral, free and clear of any Lien (except the Liens created hereunder), and the Pledgor has not sold, granted any option with respect to, assigned, transferred or otherwise disposed of any of its rights or interests in or to the Pledged Collateral other than, depending upon the proposed transferee of the Pledged Collateral, the right of first refusal contemplated under Section 10.4 of the Joint Project Agreement.

(d) Upon (i) the pledge, assignment and delivery to the Collateral Agent pursuant to this Agreement by the Pledgor of the Pledged Collateral evidenced by a certificate and (ii) the filing of a UCC-1 financing statement in the governmental office(s) set forth on Schedule B attached hereto, all filings, registrations and recordings necessary to create, preserve, protect and perfect the security interest granted by the Pledgor to the Collateral Agent hereby in respect of the Pledged Collateral will have been accomplished, and the security interest granted to the Collateral Agent pursuant to this Agreement in and to the Pledged Collateral will constitute a perfected security interest therein superior and prior to the rights of all other Persons therein and subject to no other Liens or adverse claims (other than, depending upon the proposed transferee of the Pledged Collateral, the right of first refusal contemplated under Section 10.4 of the Joint Project Agreement), and will be entitled to all the rights, priorities and benefits afforded by the Uniform Commercial Code, or other relevant law as enacted in any relevant jurisdiction, to perfected security interests.

(e) The Pledgor is a limited liability company duly formed, validly existing and in good standing under the laws of the State of Oregon, and is duly qualified in each other jurisdiction in which such qualification is required by law, other than those other jurisdictions as to which the failure to be so qualified or in good standing could not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect. The Pledgor has the limited liability company power and authority to own or hold under lease the properties it purports to own or hold under lease, to transact the business it transacts and proposes to transact, to execute and deliver this Agreement and the other Transaction Documents to which it is a party and to perform the provisions hereof and thereof.

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(f) No consent, authorization, approval or other action by, and no notice to or filing with, any Governmental Authority or any other Person is required: (i) for the valid execution, delivery and performance by the Pledgor of this Agreement; (ii) for the pledge by the Pledgor of a security interest in the Pledged Collateral; or (iii) except with respect to any required authorizations or approvals of or filings with the CPUC (and, depending upon the proposed transferee of the Pledged Collateral, the right of first refusal contemplated under Section 10.4 of the Joint Project Agreement), for the exercise by the Collateral Agent of the voting or other rights provided for in this Agreement or the remedies in respect of the Pledged Collateral pursuant to this Agreement (except as may be required in connection with such disposition by laws affecting the offering and sale of securities generally).

(g) The execution, delivery and performance by the Pledgor of this Agreement and each of the Transaction Documents to which it is a party have been duly authorized by all necessary limited liability company action on the part of the Pledgor. This Agreement has been duly executed and delivered by the Pledgor and constitutes a legal, valid and binding obligation of the Pledgor, enforceable against the Pledgor in accordance with its terms except as such enforceability may be limited by (i) applicable bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting the enforcement of creditors’ rights generally and (ii) general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

(h) The execution, delivery and performance by the Pledgor of this Agreement and the other Transaction Documents to which it is a party will not (i) contravene, result in any breach of, or constitute a default under, or result in the creation of any Lien in respect of any property of the Pledgor under, any indenture, mortgage, deed of trust, loan, purchase or credit agreement, lease, corporate charter or by-laws, or any other agreement or instrument to which the Pledgor is bound or by which the Pledgor or any of its properties may be bound or affected, (ii) violate, conflict with or result in a breach of any of the terms, conditions or provisions of any order, judgment, decree or ruling of any court, arbitrator or Governmental Authority applicable to the Pledgor or the Pledged Collateral or (iii) violate any provision of any statute or other rule or regulation of any Governmental Authority applicable to the Pledgor or the Pledged Collateral.

(i) The Pledgor will comply with all laws, ordinances or governmental rules or regulations to which it is subject, including, without limitation, ERISA, Environmental Laws, the USA PATRIOT Act and the other laws and regulations that are referred to in Section 5.16 of the Note Agreement, and will obtain and maintain in effect all licenses, certificates, permits, franchises and other governmental authorizations necessary to the ownership of its properties, including the Pledged Collateral, or to the conduct of its business, in each case to the extent necessary to ensure that non-compliance with such laws, ordinances or governmental rules or regulations or failures to obtain or maintain in effect such licenses, certificates, permits, franchises and other governmental authorizations could not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect.

(j) The Pledgor will, directly or through the Ultimate Parent, file all tax returns required to be filed in any jurisdiction and to pay and discharge all taxes shown to be due and payable on such returns and all other taxes, assessments, governmental charges, or levies imposed on the Pledgor or any of its properties, assets, income or franchises, to the extent the

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same have become due and payable and before they have become delinquent and all claims for which sums have become due and payable that have or might become a Lien on properties or assets of the Pledgor, provided that the Pledgor need not pay any such tax, assessment, charge, levy or claim if (i) the amount, applicability or validity thereof is contested by the Pledgor on a timely basis in good faith and in appropriate proceedings, and the Pledgor has established adequate reserves therefor in accordance with GAAP on the books of the Pledgor or (ii) the nonpayment of all such taxes, assessments, charges, levies and claims in the aggregate could not reasonably be expected to have a Material Adverse Effect.

(k) The Pledgor covenants and agrees that it will defend the Collateral Agent’s right, title and security interest in and to the Pledged Collateral and the proceeds thereof against the claims and demands of all persons whomsoever; and the Pledgor covenants and agrees that it will have like title to and right to pledge any other property at any time hereafter pledged to the Collateral Agent as Pledged Collateral hereunder and will likewise defend the right thereto and security interest therein of the Collateral Agent.

(l) No portion of the Pledged Collateral is subject to any defense, offset or counterclaim, nor have any of the foregoing been asserted or alleged against the Pledgor by any Person with respect thereto. As of the date of this Agreement, all certificates, instruments, documents or other writings that evidence any ownership interest in the Company and identified on Schedule A hereto.

(m) The Pledged Membership Interests are “securities” within the meaning of Chapter 8 of the Oregon Uniform Commercial Code, are governed by Chapter 8 of the Oregon Uniform Commercial Code and shall at all times hereafter continue to be such a security. The Pledgor shall cause the Pledged Collateral related to an ownership interest in the Company to be represented by a certificate or other instrument at all times.

(n) The Pledgor will not sell, assign, or otherwise dispose of, grant any option with respect to, or pledge, grant a security interest in or otherwise encumber any of the Pledged Collateral or any interest therein, or suffer any of the same to exist; and any sale, assignment, option, pledge, security interest or other encumbrance or disposition of any nature whatsoever made in violation of this covenant shall be a nullity and of no force and effect, and upon demand of the Collateral Agent, shall forthwith be canceled or satisfied by an appropriate instrument in writing.

(o) There are no currently effective financing statements covering any property which is now or hereafter may be included in the Pledged Collateral, and the Pledgor will not, without the prior written consent of the Collateral Agent, authorize or authenticate any such financing statements after the date hereof, and there will not ever be on file in any public office, any financing statement or statements covering any or all of the Pledged Collateral, except financing statements filed or to be filed in favor of the Collateral Agent.

(p) The Pledgor shall give the Collateral Agent prompt notice of any claim relating to the Pledged Collateral. The Pledgor shall deliver to the Collateral Agent a copy of each written demand, notice or document received by it which may adversely affect the Collateral Agent’s

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interest in the Pledged Collateral promptly upon, but in any event within five days after, the Pledgor’s receipt thereof.

(q) The principal place of business of the Pledgor and the sole location where the records of the Pledgor with respect to the Pledged Collateral are kept are located at the address set forth for the Pledgor on Schedule C attached hereto.

(r) The jurisdiction of organization and organizational number of the Pledgor is as set forth on Schedule C attached hereto. As of the date hereof, the Pledgor does not have or operate under, nor has it had or operated under, in any jurisdiction at any time within 5 years prior to the Closing, any name except its legal name as set forth on the signature pages hereto or such other names specified on Schedule C attached hereto, nor has the Pledgor ever been organized under the laws of any jurisdiction other than the jurisdiction specified on Schedule C attached hereto. The Pledgor shall not change its legal name, assume or operate in any jurisdiction under any trade, fictitious or other name or change its jurisdiction of organization unless (i) it shall have given to the Collateral Agent not less than 30 days’ prior written notice of its commencing to do so, clearly describing such new name and the jurisdictions in which such new name shall be used or such new jurisdiction of organization and providing such other information in connection therewith as the Collateral Agent may reasonably request and (ii) with respect to such new name or jurisdiction of organization, it shall have taken all reasonable action, reasonably satisfactory to the Collateral Agent, to maintain the security interest of the Collateral Agent in the Pledged Collateral intended to be granted hereby at all times fully perfected and in full force and effect.

(s) Subject to Section 5(r), the Pledgor will at all times preserve and keep in full force and effect its legal existence as a Oregon limited liability company. The Pledgor will at all times preserve and keep in full force and effect all rights and franchises of the Pledgor unless, in the good faith judgment of the Pledgor, the termination of or failure to preserve and keep in full force and effect such limited liability company existence, right or franchise could not, individually or in the aggregate, have a Material Adverse Effect.

The representations and warranties set forth in this Section 5 shall survive the execution and delivery of this Agreement.

Section 6. Further Assurances; Supplements.

(a) The Pledgor agrees that at any time and from time to time, at the expense of the Pledgor, the Pledgor will promptly execute and deliver all further instruments and documents (including, without limitation, financing or continuation statements, or amendments thereto), and take all further action that may be reasonably necessary or that the Collateral Agent or the Required Holders may reasonably request, in order to perfect and protect any Lien or security interest granted or purported to be granted by the Pledgor under this Agreement, including, without limitation, with respect to any additional Pledged Collateral acquired hereafter by the Pledgor or to enable the Collateral Agent to exercise and enforce rights and remedies hereunder. The Pledgor hereby authorizes the Collateral Agent, at the expense of the Pledgor (including the fees and expenses of counsel to the Collateral Agent), to file one or more financing or continuation statements, and amendments thereto, relating to all or any part of the Pledged Collateral, in such form and in such filing offices as the Collateral Agent shall determine to be

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appropriate, without the signature of the Pledgor where permitted by law. A photocopy or other reproduction of this Agreement or any financing statement covering the Pledged Collateral or any part thereof shall be sufficient as a financing statement where permitted by law. The Pledgor agrees, with respect to any financing statement, to file (at the expense of the Pledgor, including the fees and expenses of counsel to the Collateral Agent) all continuation statements or amendments where failure to so file could reasonably be expected to result in the lapse of such financing statement at any time.

(b) The Pledgor will defend the title to the Pledged Collateral and the Liens of the Collateral Agent thereon against the claim of any Person and will maintain and preserve such Liens at all times hereafter.

(c) In addition to performing its obligations under Section 4(a) and Section 4(b) above, the Pledgor will, upon acquiring any additional Pledged Collateral, promptly (and in any event within 10 days) deliver to the Collateral Agent (i) a Supplement to Pledge Agreement, duly executed by the Pledgor, in substantially the form of Annex A hereto (each, a “Supplement to Pledge Agreement”), identifying such additional Pledged Collateral and (ii) if applicable, a Pledge Instruction in substantially the form of Annex B hereto. The Pledgor hereby authorizes the Collateral Agent to attach each Supplement to Pledge Agreement to this Agreement and agrees that all additional Pledged Collateral listed on any Supplement to Pledge Agreement (including any schedules(s) thereto) delivered to the Collateral Agent shall for all purposes hereunder constitute Pledged Collateral. The Pledgor will, at the request of the Collateral Agent, deliver an opinion of counsel, in form and substance reasonably satisfactory to the Collateral Agent, as to the validity and perfection of the security interest granted in the Pledged Collateral identified in any Supplement to Pledge Agreement (including any schedule(s) thereto) and the proceeds thereof.

Section 7. Voting Rights; Distributions; Etc.

(a) So long as no Event of Default shall have occurred and be continuing:

(i) The Pledgor shall be entitled to exercise any and all voting and other consensual rights (including, without limitation, the right to give consents, waivers and notifications in respect of the Pledged Collateral) pertaining to the Pledged Collateral or any part thereof; provided, however, that no vote shall be cast or consent, waiver or ratification given or action taken that would be inconsistent with or violate any provision of this Agreement or any other Financing Document; and

(ii) Notwithstanding Section 2 hereof, the Pledgor shall be entitled to receive, retain and use any and all dividends, distributions and other payments paid in respect of the Pledged Collateral to the extent not otherwise prohibited by the Note Agreement or the other Financing Documents (including without limitation, the Permitted Closing Distribution and Restricted Payments permitted under Section 10.2 of the Note Agreement); provided, however, that any and all

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(A) dividends, distributions and other amounts paid or payable other than in cash in respect of, and instruments and other property received, receivable or otherwise distributed in respect of, or in exchange for, any Pledged Collateral;

(B) dividends or distributions hereafter paid or payable in cash in respect of any Pledged Collateral in connection with a partial or total liquidation or dissolution; and

(C) cash paid, payable or otherwise distributed in redemption of, or in exchange for, any Pledged Collateral;

shall be, and shall be forthwith delivered to the Collateral Agent to hold as, Pledged Collateral and shall, if received by the Pledgor, be received in trust for the benefit of the Collateral Agent, be segregated from the other property or funds of the Pledgor and be forthwith delivered to the Collateral Agent as Pledged Collateral in the same form as so received (with any necessary endorsement).

(b) Upon the occurrence and during the continuance of an Event of Default:

(i) Upon the instruction of the Required Holders, in accordance with the provisions of the Collateral Agency Agreement, and after any required authorizations or approvals of the CPUC are obtained, the Collateral Agent shall, without notice to the Pledgor, transfer or register in the name of the Collateral Agent or any of its nominees all certificates representing the Pledged Collateral held by the Collateral Agent hereunder, and the Collateral Agent or its nominee may thereafter, after delivery of notice to the Pledgor, exercise all voting and membership rights with respect to the Pledged Collateral (whether exercisable at any meeting of the Pledgor or by written consent or otherwise) and any and all rights of conversion, exchange, subscription or any other rights, privileges or options pertaining to any of the Pledged Collateral, as if it were the absolute owner thereof, including, without limitation, the right to exchange at its discretion any and all of the Pledged Collateral upon the merger, consolidation, reorganization, recapitalization or other readjustment of the Pledgor or upon the exercise by the Pledgor or the Collateral Agent of any right, privilege or option pertaining to all certificates of the Pledged Collateral, and in connection therewith, deposit and deliver all of the Pledged Collateral with any committee, depositary, transfer agent, registrar or other designated agency upon such terms and conditions as it may determine, all without liability except to account for property actually received by it, but the Collateral Agent shall have no duty to exercise any of the aforesaid rights, privileges or options, and the Collateral Agent shall not be responsible for any failure to do so or delay in so doing, except as a result of its gross negligence, bad faith or willful misconduct.

(ii) After any required authorizations or approvals of the CPUC are obtained, all rights of the Pledgor to exercise the voting and other consensual rights which it would otherwise be entitled to exercise pursuant to Section 7(a)(i) hereof shall cease, and all such rights shall thereupon become vested in the Collateral Agent which shall thereupon have the sole right to exercise such voting and other consensual rights.

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(iii) All rights of the Pledgor to receive the dividends, distributions and other payments which it would otherwise be authorized to receive and retain pursuant to Section 7(a)(ii) hereof shall cease, and all such rights shall thereupon become vested in the Collateral Agent which shall thereupon have the sole right to exercise such voting and other consensual rights (subject to any required authorizations or approvals of the CPUC) and to receive and hold as Pledged Collateral such dividends, distributions and other payments.

(iv) All dividends, distributions or other payments which are received by the Pledgor contrary to the provisions of Section 7(b)(iii) hereof shall be received in trust for the benefit of the Collateral Agent, shall be segregated from other funds of the Pledgor, and shall be forthwith paid over to the Collateral Agent as Pledged Collateral in the same form as so received (with any necessary endorsement).

(v) The Pledgor shall execute and deliver (or cause to be executed and delivered) to the Collateral Agent all such instruments as the Collateral Agent or the Noteholders may reasonably request for the purpose of enabling the Collateral Agent to exercise the voting and other rights which it is entitled to exercise pursuant to Section 7(b)(ii) hereof and to receive the dividends, distributions or other payments which it is entitled to receive and retain pursuant to Section 7(b)(iii) and (iv) hereof.

Section 8. Transfers and Other Liens. The Pledgor shall not sell, assign, exchange, pledge, or otherwise dispose of, or grant any option with respect to, any of the Pledged Collateral or any interest therein, or create or permit to exist any Lien upon or with respect to any of the Pledged Collateral or any interest therein, except for the Liens created hereunder, except that this Section 8 shall not be construed to prohibit the Pledgor from the use of cash permitted to be received by the Pledgor pursuant to Section 7(a)(ii).

Section 9. Collateral Agent Appointed Attorney-in-Fact. The Pledgor hereby irrevocably designates, makes, constitutes and appoints the Collateral Agent the Pledgor’s attorney-in-fact, with full authority in the place and stead of the Pledgor and in the name of the Pledgor or otherwise, from time to time in the Collateral Agent’s discretion, to take any action and to execute any instrument which the Collateral Agent may deem necessary or advisable to accomplish the purposes of this Agreement, including, without limitation:

(a) upon the occurrence and during the continuance of an Event of Default, to ask, demand, collect, sue for, recover, compromise, receive and give acquittance and receipts for monies due and to become due under or in connection with the Pledged Collateral;

(b) upon the occurrence and during the continuance of an Event of Default, to receive, indorse and collect any drafts or other instruments, documents and chattel paper, in connection therewith; and

(c) upon the occurrence and during the continuance of an Event of Default, to file any claims or take any action or institute any proceedings which the Collateral Agent may deem necessary or desirable for the collection of any of the Pledged Collateral or otherwise to enforce compliance with the terms and conditions of any contract or agreement included in the Pledged Collateral or the rights of the Collateral Agent with respect to any of the Pledged Collateral.

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Section 10. Collateral Agent May Perform. If the Pledgor fails to perform any agreement contained herein, the Collateral Agent may, but shall not be required to, itself perform, or cause performance of, such agreement, and the expenses of the Collateral Agent incurred in connection therewith shall be payable by the Pledgor, together with interest thereon at the Default Rate, to the Collateral Agent on demand and shall constitute obligations secured hereby.

Section 11. Possession; Reasonable Care. The Collateral Agent shall hold in its possession all Pledged Collateral, if any, that is in tangible form and is pledged, assigned or transferred hereunder, except as from time to time any documents or instruments may be required for recordation or for the purpose of enforcing or realizing upon any right or value thereby represented. The Collateral Agent may, from time to time, in its sole discretion, appoint one or more agents (which in no case shall be the Pledgor or an Affiliate of the Pledgor) to hold physical custody, for the account of the Collateral Agent, of any or all of the Pledged Collateral. The Collateral Agent shall be deemed to have exercised reasonable care in the custody and preservation of the Pledged Collateral in its possession if the Pledged Collateral is accorded treatment substantially equal to that which the Collateral Agent accords its own property, it being understood that the Collateral Agent shall not have any responsibility for (a) ascertaining or taking action with respect to calls, conversions, exchanges, maturities, tenders or other matters relative to any Pledged Collateral, whether or not the Collateral Agent has or is deemed to have knowledge of such matters, or (b) taking any necessary steps to preserve rights against any parties with respect to any Pledged Collateral.

Section 12. Remedies. If any Event of Default shall have occurred and be continuing:

(a) Upon the instruction of the Required Holders, in accordance with the provisions of the Collateral Agency Agreement, and after any required authorizations or approvals of the CPUC are obtained with respect to the Pledged Membership Interests (and, depending upon the proposed transferee of the Pledged Collateral, subject to the right of first refusal contemplated under Section 10.4 of the Joint Project Agreement), the Collateral Agent may exercise in respect of the Pledged Collateral, in addition to other rights and remedies provided for herein or in the Collateral Agency Agreement or otherwise available to it, all the rights and remedies of a secured party upon default under the UCC (whether or not the UCC applies to the affected Pledged Collateral), or under the laws of any other applicable jurisdiction, and the Collateral Agent may also, without notice except as specified below, sell the Pledged Collateral or any part thereof in one or more parcels at public or private sale, at any of the Collateral Agent’s offices or elsewhere, for cash, on credit or for future delivery, and upon such other terms as the Collateral Agent may deem commercially reasonable. The Pledgor agrees that at least 10 days’ notice to the Pledgor of the time and place of any public sale or the time after which any private sale is to be made shall constitute reasonable notification. The Collateral Agent shall not be obligated to make any sale of Pledged Collateral regardless of notice of sale having been given. The Collateral Agent may adjourn any public or private sale from time to time by announcement at the time and place fixed therefor, and such sale may, without further notice, be made at the time and place to which it was so adjourned.

(b) Any cash held by the Collateral Agent as Pledged Collateral and all cash proceeds received by the Collateral Agent in respect of any sale of, collection from, or other realization

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upon all or any part of the Pledged Collateral may, in the discretion of the Collateral Agent, be held by the Collateral Agent as collateral for, and/or then or at any time thereafter be applied (after payment of any amounts payable to the Collateral Agent pursuant to the Collateral Agency Agreement) in whole or in part by the Collateral Agent against all or any part of the Secured Obligations pursuant to the Collateral Agency Agreement. Upon receipt by the Collateral Agent of written instructions (including wiring instructions), any surplus of such cash or cash proceeds held by the Collateral Agent and remaining after payment in full of all the Secured Obligations shall be paid over to the Pledgor or to whomsoever may be lawfully entitled to receive such surplus.

(c) All rights and remedies of the Collateral Agent expressed herein are in addition to all other rights and remedies possessed by the Collateral Agent in the other Security Documents or any other agreement or instrument relating to the Secured Obligations at law, in equity or otherwise.

Section 13. Private Sales, Etc.

(a) The Pledgor recognizes that the Collateral Agent may be unable to effect a public sale of any or all of the Pledged Collateral by reason of certain prohibitions contained in the laws of any jurisdiction outside the United States of America or in the Securities Act and applicable state securities laws, but may be compelled to resort to one or more private sales thereof to a restricted group of purchasers who will be obliged to agree, among other things, to acquire such Pledged Collateral for their own account for investment and not with a view to the distribution or resale thereof. The Pledgor acknowledges and agrees that any such private sale may result in prices and other terms less favorable to the seller than if such sale were a public sale and, notwithstanding such circumstances, agrees that no such private sale shall be deemed to have been made in a commercially unreasonable manner for the reason that it was made at a private sale rather than a public sale. The Collateral Agent shall not be under any obligation to delay a sale of any of the Pledged Collateral for the period of time necessary to permit the Pledgor to register such securities under the laws of any jurisdiction outside the United States of America, under the Securities Act or under any applicable state securities laws, even if the Pledgor would agree to do so.

(b) The Pledgor further agrees to do or cause to be done, at the Pledgor’s expense and to the extent that the Pledgor may legally do so, all such other acts and things as may be reasonably necessary to make such sales or resales of any portion or all of the Pledged Collateral valid and binding and in compliance with any and all applicable laws, regulations, orders, writs, injunctions, decrees or awards of any and all courts, arbitrators or governmental instrumentalities, domestic or foreign, having jurisdiction over any such sale or sales, including, without limitation, effecting such sales or resales under any applicable exemption from registration under the Securities Act. The Pledgor further agrees that a breach of any of the covenants contained in this Section 13 will cause irreparable injury to the Collateral Agent and that the Collateral Agent has no adequate remedy at law in respect of such breach and, as a consequence, agrees that each and every covenant contained in this Section 13 shall be specifically enforceable against the Pledgor, and the Pledgor hereby waives and agrees not to assert as a defense against an action for specific performance of such covenants that (i) the Pledgor’s failure to perform such covenants will not cause irreparable injury to the Collateral

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Agent or (ii) the Collateral Agent has an adequate remedy at law in respect of such breach. The Pledgor agrees that any and all costs and expenses (including, without limitation, reasonable attorneys’ fees and expenses) incurred by the Collateral Agent or the Noteholders in connection with any such action for specific performance brought by the Collateral Agent or the Noteholders under this Section 13(b) shall be paid by the Pledgor.

Section 14. Amendments, Etc. No amendment or waiver of any provision of this Agreement nor consent to any departure by the Pledgor herefrom shall in any event be effective unless the same shall be in writing and signed by the Collateral Agent and the Pledgor in accordance with the Collateral Agency Agreement, and then such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given.

Section 15. Addresses for Notices. All notices and other communications provided for hereunder shall be in writing and sent by first-class mail or nationwide overnight delivery service (with charges prepaid), and (i) if to a Noteholder, addressed to it at the address specified for such communications in Section 18 of the Note Agreement, or at such other address as such Noteholder shall have specified to the Pledgor and the Collateral Agent in writing; (ii) if to the Collateral Agent addressed to it in such capacity at The Prudential Insurance Company of America, c/o Prudential Capital Group, at 2200 Ross Avenue, Suite 4200E, Dallas, Texas 75201, Attention: Managing Director, Energy and Corporate Finance, or at such other address as the Collateral Agent shall have specified to each Noteholder and the Pledgor in writing; and (iii) if to the Pledgor, addressed to NW Natural Gas Storage, LLC, 220 NW Second Ave., 9th Floor, Portland, Oregon 97209, Attention: President and Chief Executive Officer, with a copy to Northwest Natural Gas Company, 220 NW Second Avenue, 13th Floor, Portland, Oregon 97209-3991, Attn: MardiLyn Saathoff, Chief Governance Officer and Corporate Secretary, or at such other address as the Pledgor shall have specified to each Noteholder and the Collateral Agent in writing.

Section 16. Lien and Security Interest Absolute. All rights of the Collateral Agent and the pledge, assignment, lien and security interest hereunder, and all obligations of the Pledgor hereunder, shall be absolute and unconditional, irrespective of:

(a) any lack of validity or enforceability of the Note Agreement, the Notes or any other Financing Document;

(b) any change in the time, manner or place of payment of, or in any other term of, all or any of the Secured Obligations, or any other amendment or waiver of or any consent to any departure from the Note Agreement, the Notes or any other Financing Document;

(c) any taking, exchange, release or non-perfection of any other collateral, or any taking, release or amendment or waiver of or consent to departure from any guaranty of all or any of the Secured Obligations;

(d) any manner of application of collateral, or proceeds thereof, to all or any of the Secured Obligations, or any manner of sale or other disposition of any collateral for all or any of the Secured Obligations or any other assets of the Pledgor or any other Person;

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(e) any change, restructuring or termination of the limited liability company or other organizational structure or existence of the Pledgor, any of its Subsidiaries (including the Company), the Collateral Agent or any Noteholder; or

(f) any other circumstance which might otherwise constitute a defense available to, or a discharge of, the Pledgor or any other grantor of a security interest.

Section 17. Continuing Lien and Security Interest.

(a) This Agreement and, if applicable, the delivery of the Pledged Collateral to the Collateral Agent shall create a continuing lien on and security interest in the Pledged Collateral and shall: (i) remain in full force and effect until the payment in full in cash and performance in full of the Secured Obligations; (ii) be binding upon the Pledgor and its successors and assigns; and (iii) inure to the benefit of, and be enforceable by, the Collateral Agent and its successors, transferees and assigns, under the terms of the Collateral Agency Agreement or otherwise. Without limiting the generality of the foregoing clause (iii), the Collateral Agent may assign or otherwise transfer all or any portion of its rights and obligations under this Agreement to any co-agent, co-trustee, additional or substitute agent or trustee appointed in accordance with the provisions of the Collateral Agency Agreement, and such Person shall thereupon become vested with all the benefits in respect thereof granted herein or otherwise to the Collateral Agent. Upon the payment in full in cash and performance in full of the Secured Obligations, the Pledgor shall be entitled to the release and/or return, as applicable, upon its request and at its expense, of such of the Pledged Collateral as shall not have been sold or otherwise applied pursuant to the terms hereof.

(b) The Pledgor agrees that to the extent that, after payment in full of the Secured Obligations, such payment or any part thereof is subsequently invalidated, voided, declared to be fraudulent or preferential, set aside, recovered, rescinded or is required to be retained by or repaid to a trustee, receiver, or any other Person under any bankruptcy code, common law, or equitable cause, then the Lien and security interest in the Pledged Collateral created hereunder shall be revived, reinstated and continued in full force and effect, as if said payment had not been made. The Lien and security interest in the Pledged Collateral created hereunder shall not be released or discharged by any payment to any Noteholder from any source that is thereafter paid, returned or refunded in whole or in part by reason of the assertion of a claim of any kind relating thereto, including, but not limited to, any claim for breach of contract, breach of warranty, preference, illegality, invalidity, or fraud asserted by any account debtor or by any other Person.

Section 18. Waiver of Marshalling. All rights of marshalling of assets of the Pledgor, including, without limitation, any such right with respect to the Pledged Collateral, are hereby waived by the Pledgor.

Section 19. Severability. Any provision of this Agreement which is prohibited or unenforceable in any applicable jurisdiction shall not invalidate the remaining provisions hereof, and any such prohibition or unenforceability in any applicable jurisdiction shall not invalidate or render unenforceable such provision in any other applicable jurisdiction. Should any clause, sentence, paragraph, subsection or Section of this Agreement be judicially declared to be invalid, unenforceable or void, such decision will not have the effect of invalidating or voiding the

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remainder of this Agreement, and the parties hereto agree that the part or parts of this Agreement so held to be invalid, unenforceable or void will be deemed to have been stricken herefrom by the parties hereto, and the remainder will have the same force and effectiveness as if such stricken part or parts had never been included herein.

Section 20. Captions. The captions in this Agreement have been inserted for convenience only and shall be given no substantive meaning or significance whatever in construing the terms and provisions of this Agreement.

Section 21. No Waiver; Remedies. No failure on the part of the Collateral Agent or the Noteholders to exercise, and no delay in exercising, any right hereunder shall operate as a waiver thereof; nor shall any single or partial exercise of any right hereunder preclude any other or further exercise thereof or the exercise of any other right. The remedies herein provided are cumulative and not exclusive of any remedies provided by law.

Section 22. GOVERNING LAW. THIS AGREEMENT SHALL BE CONSTRUED AND ENFORCED IN ACCORDANCE WITH, AND THE RIGHTS OF THE PARTIES SHALL BE GOVERNED BY, THE LAW OF THE STATE OF NEW YORK WITHOUT REGARD TO CONFLICT OF LAW PRINCIPLES OTHER THAN SECTION 5-1401 OF THE NEW YORK GENERAL OBLIGATIONS LAW. This Agreement may not be changed orally, but (subject to the provisions of Section 14) only by an agreement in writing signed by the party against whom enforcement of any waiver, change, modification or discharge is sought.

Section 23. WAIVER OF JURY TRIAL; Consent to Jurisdiction; Waiver of Immunities.

(a) WAIVER OF JURY TRIAL. THE PLEDGOR AND THE COLLATERAL AGENT AGREE TO WAIVE THEIR RESPECTIVE RIGHTS TO A JURY TRIAL OF ANY CLAIM OR CAUSE OF ACTION BASED UPON OR ARISING OUT OF THIS AGREEMENT, ANY OTHER FINANCING DOCUMENT OR ANY DEALINGS BETWEEN THEM RELATING TO THE SUBJECT MATTER OF THIS TRANSACTION. THE SCOPE OF THIS WAIVER IS INTENDED TO BE ALL-ENCOMPASSING OF ANY AND ALL DISPUTES THAT MAY BE FILED IN ANY COURT AND THAT RELATE TO THE SUBJECT MATTER OF THIS TRANSACTION, INCLUDING WITHOUT LIMITATION, CONTRACT CLAIMS, TORT CLAIMS, BREACH OF DUTY CLAIMS, AND ALL OTHER COMMON LAW AND STATUTORY CLAIMS. THE PLEDGOR AND THE COLLATERAL AGENT EACH ACKNOWLEDGE THAT THIS WAIVER IS A MATERIAL INDUCEMENT TO ENTER INTO THIS BUSINESS RELATIONSHIP, THAT EACH HAS ALREADY RELIED ON THE WAIVER IN ENTERING INTO OR ACCEPTING THIS AGREEMENT, AND THAT EACH WILL CONTINUE TO RELY ON THE WAIVER IN THEIR RELATED FUTURE DEALINGS. THE PLEDGOR AND THE COLLATERAL AGENT FURTHER WARRANT AND REPRESENT THAT EACH HAS REVIEWED THIS WAIVER WITH ITS LEGAL COUNSEL, AND THAT EACH KNOWINGLY AND VOLUNTARILY WAIVES ITS JURY TRIAL RIGHTS FOLLOWING CONSULTATION WITH LEGAL COUNSEL. IN THE EVENT OF LITIGATION, THIS AGREEMENT MAY BE FILED AS A WRITTEN CONSENT TO A TRIAL BY THE COURT.

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HOU03:1283569                                Signature Page to Pledge Agreement

(b) Consent to Jurisdiction; Waiver of Immunities. The Pledgor hereby irrevocably submits to the non-exclusive jurisdiction of the courts of the State of New York, in and for the County of New York, or of the United States of America for the Southern District of New York in any action or proceeding arising out of or relating to this Agreement or any other Financing Document, and the Pledgor hereby irrevocably agrees that all claims in respect of such action or proceeding may be heard and determined in New York state or Federal court. The Pledgor hereby irrevocably waives, to the fullest extent it may effectively do so, the defense of an inconvenient forum to the maintenance of such action or proceeding. The Pledgor agrees and irrevocably consents to the service of any and all process in any such action or proceeding by the mailing, by registered or certified U.S. mail (or any substantially similar form of mail), postage prepaid, return receipt requested, to it at its address specified in Section 15 hereof or at such other address as the Pledgor shall have specified to each Noteholder and to the Collateral Agent in writing. The Pledgor agrees that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law. Nothing in this Section 23 shall affect the right of any Noteholder or the Collateral Agent to serve legal process in any other manner permitted by law or affect the right of any Noteholder or the Collateral Agent to bring any action or proceeding against the Pledgor or its property in the courts of any other jurisdiction. To the extent that the Pledgor has or hereafter may acquire immunity from jurisdiction of any court or from any legal process (whether through service of notice, attachment prior to judgment, attachment in aid of execution, execution or otherwise) with respect to itself or its property, the Pledgor hereby irrevocably waives such immunity in respect of its obligations under this agreement.

Section 24. No Liability of Pledgor. The Pledgor shall not have any liability for any obligations of the Company under the Note Agreement, the Notes or the other Financing Documents and no deficiency judgment (whether under Section 9-608(a) of the UCC or otherwise) under this Agreement or any other Financing Document shall be taken against the Pledgor, for the purpose of obtaining satisfaction and payment of such obligations of the Company, from any property of Pledgor other than the Pledged Collateral.

[Remainder of Page Intentionally Blank; Signature Page Follows]

HOU03:1283569                                Signature Page to Pledge Agreement

NW NATURAL GAS STORAGE, LLC

By:

David A. Weber:

President and Chief Executive Officer

Notice address:

220 N.W. Second Avenue, 9th Floor

Portland, OR 97209 Attn: President and Chief Executive Officer

Fax: 503-220-2584

With a copy to:

Northwest Natural Gas Company

220 NW Second Avenue, 13th Floor

Portland, Oregon 97209-3991

Attn: MardiLyn Saathoff, Chief Governance Officer and Corporate Secretary

Fax: (503) 721-2156

Email: mys@nwnatural.com

HOU03:1283569                                Signature Page to Pledge Agreement

Accepted and agreed to by:

THE PRUDENTIAL INSURANCE COMPANY OF AMERICA, as Collateral Agent

By: ___________________________________

Vice President

Notice address:

The Prudential Insurance Company of America

c/o Prudential Capital Group

2200 Ross Avenue

Suite 4200E

Dallas, TX 75201

Attn: Managing Director, Energy and Corporate Finance

Fax: (214) 720-6299

HOU03:1283569                                Signature Page to Pledge Agreement

HOU03:1283569                                Schedule A

Schedule A

Pledged Collateral Pledgor	Interest Issuer	Interest Certificate No(s).	Percentage of Ownership
NW NATURAL GAS STORAGE, LLC	Gill Ranch Storage, LLC	1	100% Limited Liability Company Membership Interest

HOU03:1283569                                Schedule A

Schedule B

Governmental Offices for Filings

Oregon Secretary of State

HOU03:1283569                                Schedule B

HOU03:1283569                                Schedule C

Schedule C

Chief Executive Office; Principal Places of Business; Locations of Pledged Collateral;

Jurisdictions of Organization; Organizational Number; and Other Names

1. Chief Executive Office

NW Natural Gas Storage, LLC

220 N.W. Second Avenue, 9th Floor

Portland, OR 97209

2. Principal Place of Business

NW Natural Gas Storage, LLC

220 N.W. Second Avenue, 9th Floor

Portland, OR 97209

3. Locations of Pledged Collateral

NW Natural Gas Storage, LLC

220 N.W. Second Avenue, 9th Floor

Portland, OR 97209

4. Jurisdiction of Organization

State of Oregon

5. Organizational Number

NW Natural Gas Storage, LLC: 620452-90

6. Other Names

N/A

7. Other Jurisdictions

N/A

HOU03:1283569                                Schedule C

HOU03:1283569                                Annex A

Annex A

SUPPLEMENT TO PLEDGE AGREEMENT

This Supplement to Pledge Agreement, dated as of ______________ ___ ____, is delivered pursuant to Section 6 of the Pledge Agreement referred to below.

RECITALS:

A. NW NATURAL GAS STORAGE, LLC (the “Pledgor”) has executed and delivered that certain Pledge Agreement, dated as of November 30, 2011, in favor of The Prudential Insurance Company of America, as collateral agent (as the same may be amended, restated, supplemented or otherwise modified from time to time, including without limitation by this and any other Supplements to Pledge Agreement executed from time to time, the “Agreement”). Capitalized terms used but not defined herein have the meanings assigned to such terms in the Agreement.

B. Pursuant to Section 6 of the Agreement, the Pledgor has agreed to, upon obtaining any additional Pledged Collateral, promptly execute and deliver a Supplement to Pledge Agreement in order to identify such additional Pledged Collateral which have been pledged pursuant to the Agreement.

C. The undersigned desires to execute and deliver this Supplement to Pledge Agreement to satisfy such requirement.

NOW, THEREFORE, IT IS AGREED:

1. Pledged Collateral. The undersigned agrees that the equity interests listed on Schedule A attached hereto are part of the Pledged Collateral and are subject to the pledge and security interest created by the Agreement.

2. Representations and Warranties. The undersigned hereby certifies that the representations and warranties set forth in Section 5 of the Agreement are true and correct as to the Pledged Collateral listed on Schedule A hereto on and as of the date hereof.

HOU03:1283569                                Annex A

HOU03:1283569                                Schedule A to Annex A

NW NATURAL GAS STORAGE, LLC

By:

Name:

Title:

HOU03:1283569                                Schedule A to Annex A

SCHEDULE A TO SUPPLEMENT TO PLEDGE AGREEMENT

Pledged Collateral Pledgor	Interest Issuer	Interest Certificate No(s).	Percentage of Ownership	Number Of Units
NW NATURAL GAS STORAGE, LLC

HOU03:1283569                                Schedule A to Annex A

Annex B

PLEDGE INSTRUCTION

BY THIS PLEDGE INSTRUCTION, dated November 30, 2011, NW NATURAL GAS STORAGE, LLC, an Oregon limited liability company (the “Parent”), hereby instructs Gill Ranch Storage, LLC, an Oregon limited liability company (the “Pledged Company”), to register a security interest in favor of The Prudential Insurance Company of America, as collateral agent (in such capacity, together with its successors and assigns, the “Collateral Agent”) for the benefit of the Noteholders (as defined in the Collateral Agency Agreement referenced below) under that certain Intercreditor and Collateral Agency Agreement, dated as of November 30, 2011 (as the same may be amended, restated, supplemented or otherwise modified from time to time, the “Collateral Agency Agreement”), among the Collateral Agent, the Noteholders, the Pledged Company and the Parent, of all of the Parent’s, right, title and interest in and to the Pledged Collateral (as defined in the Pledge Agreement referenced below), whether now owned or hereafter acquired by the Parent (the “Membership Interests”).

Capitalized terms used and not otherwise defined herein shall have the respective meanings specified in that certain Pledge Agreement, dated as of November 30, 2011 (the “Pledge Agreement”), made by the Parent in favor of the Collateral Agent.

1. PLEDGE INSTRUCTIONS. The Pledged Company is hereby instructed by the Parent to register all of the Parent’s right, title and interest in and to all of the Membership Interests as subject, pursuant to the Pledge Agreement, to a security interest in favor of the Collateral Agent who, upon such registration, shall become the registered pledgee of the Membership Interests with all rights incident thereto.

2. INITIAL TRANSACTION STATEMENT. The Pledged Company is further instructed by the Parent to promptly inform the Collateral Agent of the registration of the pledge by sending the initial transaction statement, in the form attached hereto as Exhibit A, to the Collateral Agent at The Prudential Insurance Company of America, c/o Prudential Capital Group, at 2200 Ross Avenue, Suite 4200E, Dallas, Texas 75201, Attention: Managing Director, Energy and Corporate Finance.

3. WARRANTIES OF THE PARENT. The Parent hereby warrants that the Parent is an appropriate person to originate this instruction.

HOU03:1283569                                Annex B

HOU03:1283569                                Signature Page to Annex B

IN WITNESS WHEREOF, the Parent has caused this Pledge Instruction to be duly signed and delivered as of the date first above written.

PARENT:

NW NATURAL GAS STORAGE, LLC,

an Oregon limited liability company

By:

David A. Weber

President and Chief Executive Officer

Address:

NW Natural Gas Storage, LLC

220 N.W. Second Avenue, 9th Floor

Portland, OR 97209

Attn: President and Chief Executive Officer

Fax: 503-220-2584

With a copy to:

Northwest Natural Gas Company

220 NW Second Avenue, 13th Floor

Portland, Oregon 97209-3991

Attn: MardiLyn Saathoff, Chief Governance Officer and Corporate Secretary

Fax: (503) 721-2156

Email: mys@nwnatural.com

HOU03:1283569                                Signature Page to Annex B

HOU03:1283569                                Exhibit A to Annex B

EXHIBIT A

to

Pledge Instruction Form of Initial Transaction Statement

The Prudential Insurance Company of America, as Collateral Agent The Prudential Insurance Company of America, c/o Prudential Capital Group

2200 Ross Avenue

Suite 4200E

Dallas, TX 75201

Attn: Managing Director, Energy and Corporate Finance

Fax: (214) 720-6299

On November 30, 2011, the undersigned, Gill Ranch Storage, LLC, an Oregon limited liability company (the “Pledged Company”), caused the pledge of 100% of the interests in the Pledged Company (the “Membership Interests”) owned by NW Natural Gas Storage, LLC, an Oregon limited liability company, in favor of The Prudential Insurance Company of America, as collateral agent (the “Collateral Agent”), to be registered on the books and records of the Pledged Company. Except for the terms and conditions contained in the Amended and Restated Operating Agreement of the Pledged Company and the pledge of the Membership Interests in favor of the Collateral Agent, the undersigned has no knowledge of any liens, restrictions or adverse claims to which the Membership Interests are or may be subject, as of the date hereof.

GILL RANCH STORAGE, LLC

By:

David A. Weber

President and Chief Financial Officer

HOU03:1283569                                Exhibit A to Annex B

EX-12

														EXHIBIT 12
NORTHWEST NATURAL GAS COMPANY
Ratio of Earnings to Fixed Charges
Thousands, except per share amount
(Unaudited)
	Year Ended December 31,
	2011			2010			2009			2008			2007
Fixed Charges, as defined:
Interest on Long-Term Debt		$	37,515		$	39,198		$	37,447		$	33,605		$	34,294
Other Interest			2,976			1,587			1,937			4,022			4,116
Amortization of Debt Discount and Expense			1,729			1,766			1,503			700			711
Interest Portion of Rentals			2,213			2,130			1,735			1,551			1,523
Total Fixed Charges, as defined		$	44,433		$	44,681		$	42,622		$	39,878		$	40,644
Earnings, as defined:
Net Income		$	63,898		$	72,667		$	75,122		$	69,525		$	74,497
Taxes on Income			43,382			49,462			46,671			40,678			44,060
Fixed Charges, as above			44,433			44,681			42,622			39,878			40,644
Total Earnings, as defined		$	151,713		$	166,810		$	164,415		$	150,081		$	159,201
Ratio of Earnings to Fixed Charges			3.41			3.73			3.86			3.76			3.92

EX-21

Name of Subsidiary	Jurisdiction Organized
Gill Ranch Storage, LLC	Oregon
NW Natural Energy, LLC	Oregon
NW Natural Gas Storage, LLC	Oregon
NNG Financial Corporation	Oregon
Palomar Gas Holdings, LLC	Delaware
Palomar Gas Transmission, LLC	Delaware
BL Credit Holdings, LLC	Delaware
Northwest Biogas, LLC	Oregon
KB Pipeline Company	Oregon
Northwest Energy Corporation	Oregon
Northwest Energy Sub Corporation	Oregon

EX-23

EXHIBIT 23

Consent of Independent Registered Public Accounting Firm

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-70218, 333-100885, 333-120955, 333-134973 and 333-139819) and in the Registration Statement on Form S-3 (No. 333-171596) of Northwest Natural Gas Company of our report dated February 28, 2012 relating to the consolidated financial statements, financial statement schedule and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Portland, Oregon

February 28, 2012

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Gregg S. Kantor, certify that:

1.           I have reviewed this annual report on Form 10-K of Northwest Natural Gas Company;

2.           Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.           Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.           The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.           The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:           February 28, 2012

/s/ Gregg S. Kantor                                                      

Gregg S. Kantor

President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, David H. Anderson, certify that:

1.           I have reviewed this annual report on Form 10-K of Northwest Natural Gas Company;

2.           Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.           Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.           The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.           The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:           February 28, 2012

/s/ David H. Anderson                                                                

David H. Anderson

Senior Vice President and Chief Financial Officer

EX-32.1

EXHIBIT 32.1

NORTHWEST NATURAL GAS COMPANY

Certificate Pursuant to Section 906

of Sarbanes – Oxley Act of 2002

Each of the undersigned, GREGG S. KANTOR, the President and Chief Executive Officer, and DAVID H. ANDERSON, the Senior Vice President and Chief Financial Officer, of NORTHWEST NATURAL GAS COMPANY (the Company), DOES HEREBY CERTIFY that:

1.           The Company’s Annual Report on Form 10-K for the year ended December 31, 2011 (the Report) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.           Information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

             IN WITNESS WHEREOF, each of the undersigned has caused this instrument to be executed this 28th day of February 2012.

/s/ Gregg S. Kantor                                                      

Gregg S. Kantor

President and Chief Executive Officer

/s/ David H. Anderson                                                 

David H. Anderson

Senior Vice President and

Chief Financial Officer

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002 has been provided to Northwest Natural Gas Company and will be retained by Northwest Natural Gas Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-10.K

NORTHWEST NATURAL GAS COMPANY

DEFERRED COMPENSATION PLAN FOR DIRECTORS AND EXECUTIVES

EFFECTIVE JANUARY 1, 2005

RESTATED EFFECTIVE DECEMBER 15, 2011

TABLE OF CONTENTS

 Page

1.           Purpose; Effective Date                                                                                                                        1

2.           Eligibility                                                                                                                            1

3.           Deferral Elections                                                                                                                        1

4.           Company Contributions for Executives                                                                             1

5.           FICA Withholding on Executives                                                                                                 2

6.           Accounts                                                                                                                                          2

7.           Payment of Benefits                                                                                                                              2

8.           Supplemental Retirement Benefit                                                                                                  3

9.           Administration                                                                                                                            4

10.           Claims Procedure                                                                                                                           4

11.           Amendment and Termination of the Plan                                                                             4

12.           Miscellaneous                                                                                                                           4

NORTHWEST NATURAL GAS COMPANY

DEFERRED COMPENSATION PLAN FOR DIRECTORS AND EXECUTIVES

1.Purpose; Effective Date; Restatement.  The Board of Directors (the “Board”) of Northwest Natural Gas Company (the “Company”) adopts this Deferred Compensation Plan for Directors and Executives (the “Plan”) for the purpose of providing an unfunded nonqualified deferred compensation plan for directors and a select group of top management personnel.  The Plan was effective as of January 1, 2005, although initial deferral elections under the Plan could have been submitted at any time after November 30, 2004.  The Plan was previously restated effective January 1, 2007, December 20, 2007 and January 1, 2010, and was restated effective as of February 28, 2008, except that the changes to Section 6(b) made by that restatement do not apply to deferral allocations made in Participation Agreements that were irrevocable on or prior to December 31, 2006.  The Plan is further amended by this restatement on and effective as of December 15, 2011.

2.Eligibility.  Persons eligible to defer compensation under the Plan shall consist of (a) all directors of the Company (“Directors”), and (b) a select group of management or highly compensated employees of the Company, which shall consist of all executive officers of the Company and such other employees of the Company as may be designated in writing by the Chief Executive Officer of the Company as eligible to defer compensation under the Plan for the applicable calendar year (“Executives”).  Any person who is both a Director and an Executive at any time shall be considered an Executive, and not a Director, at such time.  For all purposes of this Plan, a person who is an employee of a subsidiary of the Company shall be considered an employee of the Company.

3.Deferral Elections.  A Director or Executive may elect to defer compensation under the Plan by submitting a “Participation Agreement” to the Company on a form specified by the Company no later than the applicable deferral deadline.  The minimum annual aggregate deferral for all forms of compensation specified in a Participation Agreement shall be $2,000.  Any Director or Executive who has submitted a Participation Agreement is hereafter referred to as a “Participant.”  A Participation Agreement submitted by a Participant shall automatically continue from year to year and shall be irrevocable with respect to compensation once the deferral deadline for that compensation has passed, but the Participant may modify or terminate a Participation Agreement for compensation payable in any year by submitting a revised Participation Agreement or otherwise giving written notice to the Company at any time on or prior to the deferral deadline for that compensation.

(a)Elections by Directors.

(i)Fees.  A Director may elect to defer receipt of all or any whole percentage of the annual retainer, meeting fees and any other cash fees payable for service as a director (“Fees”).  The deferral deadline for an election to defer Fees for services performed in any calendar year shall be the last day of the prior calendar year.

(ii)NEDSCP Shares.  A Director may elect to defer receipt of all or any whole percentage of the unvested shares (“NEDSCP Shares”) of common stock of the Company (“Common Stock”) awarded to the Director under the Company’s Non-Employee Directors Stock Compensation Plan (“NEDSCP”).  The deferral deadline for an election to defer NEDSCP Shares scheduled to vest in any calendar year shall be the last day of the prior calendar year, except that the deferral deadline for an election to defer NEDSCP Shares scheduled to vest on January 1 in any calendar year shall be the last day of the second preceding calendar year.  No deferral shall be allowed of NEDSCP Shares as to which a Director has made an election under Section 83(b) of the Internal Revenue Code.

(b)Elections by Executives.

(i)Salary.  An Executive may elect to defer receipt of any whole percentage (up to a maximum of 50 percent) of the Executive’s base annual salary, specifically excluding other forms of compensation referred to below as well as commissions and any non-cash compensation (“Salary”).  The deferral deadline for an election to defer Salary for services performed in any calendar year shall be the last day of the prior calendar year.

(ii)Bonus.  An Executive may elect to defer receipt of all or any whole percentage of the Executive’s annual bonus payable under the Company’s Executive Annual Incentive Plan or other similar annual incentive plan (“Bonus”).  Payments under the Key Goals program shall not be considered Bonus and shall not be eligible for deferral under the Plan.  The deferral deadline for an election to defer Bonus earned with respect to the Executive’s or the Company’s performance in any calendar year shall be the last day of the prior calendar year.

(iii)LTIP Compensation.  An Executive may elect to defer receipt of all or any whole percentage of compensation payable to the Executive pursuant to an award under the Company’s Long Term Incentive Plan (“LTIP Compensation”); provided, however, that (1) a stock option shall not be considered LTIP Compensation eligible for deferral under the Plan, and (2) no election shall be permitted after December 31, 2008 to defer receipt of an award that consists of shares of Common Stock issued subject to forfeiture if vesting conditions are not satisfied (“Unvested LTIP Shares”).  The deferral deadline for an election to defer LTIP Compensation shall be (x) the last day of the calendar year prior to the commencement of the performance period if a performance period is specified in the award, or (y) the last day of the calendar year prior to the grant date of the award if no performance period is specified; provided, however, that for any award of LTIP Compensation for which the performance period ends on or before December 31, 2008, the deferral deadline shall be the last day of the calendar year prior to the last year of the performance period, and for any award of LTIP Compensation for which the performance period ends on December 31, 2009 or December 31, 2010, the deferral deadline shall be December 31, 2008.  If an Executive elects to defer less than 100 percent of an award of LTIP Compensation that becomes payable in increments over time, the deferral percentage elected by the Executive shall be applied uniformly to each increment.

(iv)2012 RSU Grants.  An Executive may elect to defer receipt of all or any whole percentage of LTIP Compensation payable to the Executive pursuant to a restricted stock unit award granted in February 2012 (a “2012 RSU”); provided, however, that:

(1)the portion of the Executive’s 2012 RSU that is scheduled to vest before March 31, 2013 (the “First Installment”) shall not be eligible for deferral;

(2)as a precondition to any deferral election under this subparagraph (b)(iv), the Executive must agree to a modification of the terms of the Executive’s 2012 RSU under which all of the 2012 RSU other than the First Installment shall be forfeited if the Executive’s employment terminates before the first anniversary of the grant date of the 2012 RSU other than (x) as a result of death or disability (as defined in Treasury Regulations §1.409A-3(i)(4)) or (y) in circumstances that result in accelerated vesting of the 2012 RSU due to the occurrence of a change in control event (as defined in Treasury Regulations §1.409A-3(i)(5)); and

(3)a deferral election under this subparagraph (b)(iv) shall be void and have no effect if the Executive’s employment terminates before the first anniversary of the grant date of the 2012 RSU either (x) as a result of death or disability (as defined in Treasury Regulations §1.409A-3(i)(4)) or (y) in circumstances that result in accelerated vesting of the 2012 RSU due to the occurrence of a change in control event (as defined in Treasury Regulations §1.409A-3(i)(5)).

The deferral deadline for an election to defer LTIP Compensation payable under a 2012 RSU shall be 30 days after the grant date of the 2012 RSU.  If an Executive elects to defer less than 100 percent of the Executive’s 2012 RSU, the deferral percentage elected by the Executive shall be applied uniformly to each installment of the 2012 RSU that vests over time, excluding the First Installment.  LTIP Compensation payable pursuant to restricted stock unit awards granted after 2012 shall be eligible for deferral under subparagraph (b)(iii).

(c)New Directors and Executives.  A person who first becomes a Director or Executive during a calendar year may elect to defer any of the types of compensation referred to in paragraphs (a) and (b) above that is payable solely for services performed after submission of the Participation Agreement, subject to all of the provisions of paragraphs (a) and (b), except that the deferral deadline for any such election shall be 30 days after the date the person becomes eligible under the Plan.

4.Company Contributions for Executives.

(a)Matching Contributions.  The Company shall credit a “Matching Contribution” to a participating Executive’s Cash Account (as defined below) each year based on the Executive’s total Salary and Bonus and the amount of Salary and Bonus deferred under the Plan by the Executive during that year; provided, however, that no Matching Contribution shall be made with respect to any Salary or Bonus deferred under the Plan at a time when the Executive is not a participant in the Company’s Retirement K Savings Plan.  The amount of the Matching Contribution shall be equal to the excess of (i) the lesser of (1) sixty percent (60%) of the total amount of Executive’s Salary and Bonus deferred under the Plan and the Retirement K Savings Plan during the calendar year, or (2) three and six-tenths percent (3.6%) of the Executive’s total Salary and Bonus during such calendar year, over (ii) the amount the Company would have contributed for such calendar year as a matching contribution for the Executive under the Retirement K Savings Plan if the Executive had deferred into the Retirement K Savings Plan the maximum amount of compensation permitted under that plan and applicable tax law for the year.  Matching Contributions shall be credited to the Executive’s Account no later than January 31 of the year immediately following the calendar year in which the Matching Contribution was earned, and shall be fully vested at all times.

(b)Supplemental Contributions.  For any Executive who is hired after December 31, 2006 and is therefore eligible to receive non-contributory employer contributions under Section 4.05 of the Retirement K Savings Plan, the Company shall credit a “Supplemental Contribution” to the Executive’s Cash Account each year in an amount equal to five percent (5%) of the greater of (i) the Executive’s Salary and Bonus deferred under the Plan during the calendar year, or (ii) the excess, if any, of the Executive’s total Salary and Bonus during such calendar year over the limit provided by Section 401(a)(17) of the Internal Revenue Code on compensation counted under the Retirement K Savings Plan for that year.  A Supplemental Contribution shall be credited for an Executive whose total Salary and Bonus exceeds the Section 401(a)(17) limit whether or not the Executive defers compensation under the Plan.  Supplemental Contributions shall be credited to the Executive’s Account no later than January 31 of the year immediately following the calendar year in which the Supplemental Contribution was earned.  Supplemental Contributions for an Executive shall be vested if non-contributory employer contributions for the Executive made for the same year would be vested under the terms of the Retirement K Savings Plan.  Upon termination of an Executive’s employment, any unvested Supplemental Contributions, as well as any dividends or interest credited thereon, shall be forfeited and deducted from the Executive’s Accounts.

5.FICA Withholding on Executives.  Under current law, all compensation, Matching Contributions and vested Supplemental Contributions credited to an Executive’s Accounts will be treated as wages subject to FICA tax, and the Company will be required to withhold FICA tax from the Executive.  The amount required to be withheld for FICA tax with respect to any amount of deferred compensation or related Matching Contribution or Supplemental Contribution shall be withheld from the non-deferred portion, if any, of the same compensation; provided, however, that if the non-deferred portion of the compensation is insufficient to cover the full required withholding, the Company shall withhold the remaining amount from other non-deferred compensation payable to the Executive unless the Executive otherwise pays such remaining amount to the Company.

6.Accounts.

(a)Accounts.  The Company shall establish on its books one or two separate accounts (individually, an “Account” and collectively, the “Accounts”) for each Participant:  a Company Stock Account, which shall be denominated in shares of Common Stock, including fractional shares, and a Cash Account, which shall be denominated in U.S. dollars.

(b)Allocation of Deferrals Among Accounts.  The number of NEDSCP Shares deferred by a Director shall be credited to the Company Stock Account.  All LTIP Compensation payable in shares of Common Stock that is deferred by an Executive shall be credited to the Company Stock Account.  All other compensation deferred by a Participant shall be credited to the Cash Account.

(c)Crediting of Deferrals.  The credits for deferred Salary, Bonus and Fees shall be entered on the Company’s books of account at the time that such compensation would otherwise be paid.  The credit for deferred NEDSCP Shares shall be entered on the Company’s books of account as soon as practicable after January 1 of the first year in which such deferral is irrevocable.  The credit for any LTIP Compensation deferred by an Executive consisting of Unvested LTIP Shares shall be entered on the Company’s books of account as soon as practicable after such deferral is irrevocable.  The credit for any other deferred LTIP Compensation shall be entered on the Company’s books of account at the time that such compensation would otherwise be paid.

(d)Transfers Among Accounts.  Participants may elect in writing to transfer amounts previously credited to the Cash Account to the Company Stock Account, but shall be limited to four such transfers per calendar year.  No transfers may be made out of a Company Stock Account unless otherwise permitted under Section 6(i)(iv).  The Committee may require that designated fees be deducted from amounts transferred to or from Company Stock Accounts.

(e)Valuation of Stock; Dividend Credits.  Any dollar amount transferred or credited to a Company Stock Account shall be deemed to increase the number of shares of Common Stock recorded as the balance of that Account based on the closing market price of the Common Stock reported for the day of the transfer or credit or, if such day is not a trading day, the next trading day.  As of each date for payment of dividends on the Common Stock, each Company Stock Account shall be credited with the amount of dividends that would be paid on the number of shares recorded as the balance of that Account as of the record date for such dividend.

(f)Cash Account Interest.  Interest shall be credited to the Cash Account of each Participant as of the last day of each calendar quarter.  The rate of interest to be applied at the end of each calendar quarter shall be the quarterly equivalent of an annual yield that is equal to the annual yield on Moody’s Average Corporate Bond Yield for the preceding quarter, as published by the Moody’s Investors Service, Inc. (or any successor thereto), or if such index is no longer published, a substantially similar index selected by the Board.  Interest shall be calculated for each calendar quarter based upon the average daily balance of the Participant’s Cash Account during the quarter.

(g)Forfeitures.  If any NEDSCP Shares deferred by a Director under this Plan are forfeited under the terms of the NEDSCP, the Director’s Company Stock Account shall be reduced by the number of shares so forfeited.  If any Unvested LTIP Shares deferred by an Executive under this Plan are forfeited under the terms of the Executive’s applicable award agreement, the Executive’s Company Stock Account shall be reduced by the number of shares so forfeited.

(h)Statement of Account.  At the end of each calendar quarter, a report shall be issued by the Company to each Participant setting forth the balances of the Participant’s Accounts under the Plan.

(i)Effect of Corporate Transaction on Company Stock Accounts.  At the time of consummation of a Corporate Transaction (as defined below), if any, the amount credited to a Participant’s Company Stock Account shall be converted into a credit for cash or common stock of the acquiring company (“Acquiror Stock”) based on the consideration received by shareholders of the Company in the Corporate Transaction, as follows:

(i)Stock Transaction.  If holders of Common Stock receive Acquiror Stock in the Corporate Transaction, then (1) the amount credited to each Participant’s Company Stock Account shall be converted into a credit for the number of shares of Acquiror Stock that the Participant would have received as a result of the Corporate Transaction if the Participant had actually held the Common Stock credited to his or her Company Stock Account immediately prior to the consummation of the Corporate Transaction, and (2) Company Stock Accounts will thereafter be denominated in shares of Acquiror Stock and ongoing deferrals into Company Stock Accounts, if any, shall continue to be made in accordance with outstanding deferral elections into the Company Stock Accounts as so denominated.

(ii)Cash or Other Property Transaction.  If holders of Common Stock receive cash or other property in the Corporate Transaction, then the amount credited to a Participant’s Company Stock Account shall be transferred to the Participant’s Cash Account and converted into a cash credit for the amount of cash or the value of the property that the Participant would have received as a result of the Corporate Transaction if the Participant had actually held the Common Stock credited to his or her Company Stock Account immediately prior to the consummation of the Corporate Transaction.

(iii)Combination Transaction.  If holders of Common Stock receive Acquiror Stock and cash or other property in the Corporate Transaction, then (1) the amount credited to each Participant’s Company Stock Account shall be converted in part into a credit for Acquiror Stock under Section 6(i)(i) and in part into a credit for cash under Section 6(i)(ii) in the same proportion as such consideration is received by shareholders, and (2) ongoing deferrals into Company Stock Accounts, if any, shall continue to be made in accordance with outstanding deferral elections into Company Stock Accounts in accordance with Section 6(i)(i).

(iv)Election Following Stock Transaction.  For a period of 12 months following the consummation of any Corporate Transaction which results in Participants having Company Stock Accounts denominated in Acquiror Stock, each Participant shall have a one-time right to elect to transfer the entire amount in the Participant’s Company Stock Account into the Participant’s Cash Account; provided, however, that this election shall not be available if the Corporate Transaction results in holders of Common Stock becoming holders of all of the outstanding common stock of a parent corporation of the Company.  Such election shall be made by written notice to the Company and shall be effective on the date received by the Company.  If such an election is made, the amount of cash to be credited to the Participant’s Cash Account shall be determined by multiplying the number of shares of Acquiror Stock in the Participant’s Company Stock Account by the closing market price of the Acquiror Stock reported for the effective date of the election or, if such day is not a trading day, the next trading day.

(v)For purposes of this Plan, a “Corporate Transaction” shall mean any of the following:

(1)           any consolidation, merger or plan of share exchange involving the Company (a “Merger”) pursuant to which shares of Common Stock would be converted into cash, securities or other property;

(2)           any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, the assets of the Company; or

(3)           the adoption of any plan or proposal for the liquidation or dissolution of the Company.

7.Payment of Benefits.

(a)Plan Benefits.  The Company shall pay Plan benefits to each Participant equal to the Participant’s Accounts.  Each Participation Agreement shall include an election by the Participant as to the term of benefit payments with respect to amounts deferred under the Participation Agreement, and Participation Agreements from Executives shall also include an election as to the commencement of benefit payments.  The payment elections in a Participation Agreement shall also apply to Matching Contributions and Supplemental Contributions credited as a result of Salary or Bonus during the deferral period covered by the Participation Agreement, and shall also apply to any dividends or interest credited with respect to amounts deferred under the Participation Agreement and such Matching Contributions and Supplemental Contributions.  If a Supplemental Contribution is credited to an Executive’s Account for a year that is not covered by a Participation Agreement, the Executive shall be deemed to have elected a single lump sum payment following Separation from Service as permitted by Sections 7(b) and 7(c) below with respect to benefits resulting from such Supplemental Contribution.  Except as otherwise provided in this Section 7, payment elections shall be irrevocable with respect to compensation once the deferral deadline for that compensation has passed.  Participants may make different payment elections with respect to subsequent deferrals of compensation, but no Participant may at any time have compensation deferred under the Plan payable under more than three different payment elections.

(b)Commencement of Payments.  Payment of benefits to Directors shall commence in January of the year following the Director’s Separation from Service (as defined below) with the Company.  Payment of benefits to Executives shall commence in the later of (i) January of the year following the Executive’s Separation from Service with the Company, or (ii) the seventh month following the month of the Executive’s Separation from Service with the Company; provided, however, that Executives may elect in their Participation Agreements to have benefits from their Accounts commence in January of a year specified by the Executive if such year is earlier than the year following the Executive’s Separation from Service with the Company.  When used in this Plan, the term “Separation from Service” shall have the meaning ascribed to such term in Treasury Regulations §1.409A-1(h).

(c)Term of Payments.  Participants may elect in their Participation Agreements to have benefits from their Accounts paid in (i) annual installments over 5, 10 or 15 years, (ii) a single lump sum payment, or (iii) a combination of a partial lump sum payment (expressed as a percentage) and the remainder in installments over 5, 10 or 15 years.

(d)Form of Payments.  Benefits payable to a Participant from a Company Stock Account shall be paid as a distribution of Common Stock plus cash for fractional shares.  Benefits payable to a Participant from a Cash Account shall be paid in cash.

(e)Payment Timing and Valuation.  All lump sum payments or installment payments due under the Plan in any year shall be paid on a date in January determined by the Company, except that if Section 7(b) requires benefits to commence in a month other than January, the initial payment shall be paid on a date in that month determined by the Company.  All payments shall be based on Account balances as of the close of business on the last trading day of the immediately preceding month.  Each partial lump sum payment and installment payment to a Participant shall be paid in the same proportion from each of the Accounts of the Participant subject to the applicable payment election.  The amount of each installment payment from each Account shall be determined by dividing the Account balance by the number of remaining installments, including the current installment to be paid.

(f)Modification of Payment Elections.

(i)An Executive who has elected to have any benefit commence in a specified year prior to termination of employment as permitted in Section 7(b) may elect (after such election has otherwise become irrevocable) to specify a later year for commencement of such benefit, provided that for any such election submitted after December 31, 2008, (1) such election is made in writing delivered to the Company no later than, and becoming irrevocable on, the last day of the second year preceding the previously specified year, and (2) the later year so specified is at least 5 years later than the previously specified year.

(ii)After a Participant’s election under Section 7(c) regarding the term of any benefit payments has otherwise become irrevocable, the Participant may elect to change such term of payments, provided (1) the choice of annual installments over 15 years shall not be available for a change election under this subsection, (2) the term of any particular payments may be changed only once under this subsection, (3) such election must be made in writing delivered to the Company no later than, and becoming irrevocable on, the last day of the second year preceding the year in which the payments otherwise would have commenced (and shall not be effective if a Separation from Service occurs on or before the date the election becomes irrevocable), and (4) the commencement of the affected payments shall be delayed for 5 years after the date the payments would have commenced under the terms of the previous payment election.  Accordingly, for a Director who elects to change the term of any benefit payments, the commencement of those payments will be delayed until January of the year following the fifth anniversary of the Director’s Separation from Service.  Notwithstanding the foregoing, a Participant may elect on or prior to December 31, 2008 to change the term of any benefit payments that have not commenced as of that date without application of any of the limitations or restrictions set forth in this Section 7(f)(ii).

(g)Unforeseeable Emergency.  Notwithstanding the foregoing provisions of this Section 7, an accelerated payment from a Participant’s Accounts may be made to the Participant in the sole discretion of the Committee based upon a finding that the Participant has suffered an Unforeseeable Emergency.  For this purpose, “Unforeseeable Emergency” means a severe financial hardship to the Participant resulting from an illness or accident of the Participant, the Participant’s spouse or a dependent of the Participant, loss of the Participant’s property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant.  Unforeseeable Emergency shall be determined by the Committee on the basis of information supplied by the Participant in accordance with uniform guidelines promulgated from time to time by the Committee.  The amount of any accelerated payment under this Section 7(g) shall be limited to the amount reasonably necessary to meet the Participant’s needs resulting from the Unforeseeable Emergency, after taking into account insurance and other potential sources of funds to meet such needs, plus the amount reasonably necessary to cover income and withholding taxes on the accelerated payment.  Any such accelerated payment shall be paid as promptly as practicable following approval by the Committee and shall be paid pro-rata from the Participant’s Accounts based on the account balances as of the close of business on the day prior to the payment date.

(h)Designation of Beneficiaries; Death.

(i)Each Participant shall have the right, at any time, to designate any person or persons as the Participant’s beneficiary or beneficiaries (both primary as well as secondary) to whom benefits under this Plan shall be paid in the event of the Participant’s death prior to complete distribution of the benefits due under the Plan.  If greater than fifty percent (50%) of the benefit is designated to a beneficiary other than the Participant’s spouse, such beneficiary designation shall be consented to by the Participant’s spouse.  Each beneficiary designation shall be in written form prescribed by the Company and will be effective only if filed with the Company during the Participant’s lifetime.  Such designation may be changed by the Participant at any time without the consent of a beneficiary, subject to the spousal consent requirement above.  If no designated beneficiary survives the Participant, the balance of the Participant’s benefits shall be paid to the Participant’s surviving spouse or, if no spouse survives, to the Participant’s estate.

(ii)Upon the death of a Participant, notwithstanding any contrary provisions of Section 7(b) or 7(f), benefit payments to the Participant’s beneficiary shall commence no later than January of the year following the Participant’s death.  Any benefits payable after the death of a Participant shall otherwise be paid in accordance with the payment elections for such benefits that would have applied if the Participant had not died.

(i)Payment to Guardian.  If a benefit under the Plan is payable to a minor or a person declared incompetent or to a person incapable of handling the disposition of his property, the Committee may direct payment of such Plan benefit to the guardian, legal representative or person responsible for the care and custody of such minor, incompetent or person.  The Committee may require proof of incompetence, minority, incapacity or guardianship as it may deem appropriate prior to distribution of the Plan benefit.  Such distribution shall completely discharge the Committee and the Company from all liability with respect to such benefit.

(j)Withholding; Payroll Taxes.  The Company shall withhold from payments made hereunder any taxes required to be withheld from such payments under federal, state or local law.

8.Supplemental Retirement Benefit.  Any Executive who elects to defer compensation under this Plan and who also satisfies the eligibility requirements for payment of any benefit under the Company’s Retirement Plan for Non-Bargaining Unit Employees (the “Retirement Plan”) shall qualify for further payment by the Company of supplemental retirement benefits payable as a monthly annuity under this Plan, as provided below:

(a)           Commencement.

(i)           If the Executive is eligible to receive normal retirement benefits under the Retirement Plan based on having reached age 62 at the time of Separation from Service, the annuity shall commence with the first month following the Executive’s Separation from Service.

(ii)           If the Executive is eligible to receive early retirement benefits under the Retirement Plan based on having satisfied the Rule of 70 at the time of Separation from Service, the annuity shall commence with the first month following the later of the Executive’s 55th birthday or the Executive’s Separation from Service.

(iii)           If the Executive is not eligible to receive normal retirement benefits or early retirement benefits as referred to in Section 8(a)(i) or (ii), but is eligible to receive vested benefits under the Retirement Plan, the annuity shall commence with the first month following the Executive’s 62nd birthday.

(iv)           If the Executive’s surviving spouse is eligible to receive death benefits under the Retirement Plan as a result of the Executive’s death before commencement of benefits under this Section 8, the annuity shall commence in the month that benefits would have commenced as provided in this Section 8(a) if the Executive had a Separation from Service on the date of death (or on the Executive’s actual Separation from Service, if earlier) and then survived until benefits had commenced.

(b)           Form of Benefit.

(i)           Annuity Form.  If the Executive elects a form of annuity benefit under the Retirement Plan at least 30 days prior to the first day of the month in which the benefit under this Section 8 is required to commence, the benefit under this Section 8 shall be paid in the same annuity form as selected under the Retirement Plan.  If the Executive’s benefit under this Section 8 commences earlier than the Executive’s benefit under the Retirement Plan, the Executive may, at least 30 days prior to the first day of the month in which the benefit under this Section 8 is required to commence and otherwise in accordance with the rules of the Retirement Plan, elect any of the standard or optional annuity forms of benefit described in 6.01 and 6.02 of the Retirement Plan, other than a joint and survivor annuity upon marriage or remarriage after the annuity starting date.  If the Executive does not make a timely election under this Section 8(b), the benefit under this Section 8 shall be paid in the default annuity form applicable to the Executive under the Retirement Plan.

(ii)           Small Benefit Cash Out.  If the actuarial equivalent lump sum present value of the Executive’s benefit under this Section 8, based on the actuarial assumptions used for determining equivalent benefits under the Retirement Plan at the time of the Executive’s commencement of benefits, is no more than the applicable dollar amount under Internal Revenue Code section 402(g)(1)(B) (which is $16,500 in 2011), the benefit shall be paid as a lump sum in such amount at the time annuity payments would have otherwise commenced under Section 8(a).

(c)           Amount.  The amount payable by the Company each month to the Executive or Executive’s beneficiaries under the Retirement Plan shall be:

(i)           The amount that would be payable at such time under the Retirement Plan assuming that (1) benefits had commenced on the date specified in Section 8(a), (2) benefits were payable in the annuity benefit form determined under Section 8(b), (3) all accrued benefits under the Retirement Plan were payable only in the annuity form as provided in Section 8(d), and (4) all Salary and Bonus deferred by the Executive under this Plan and under the Company’s former Executive Deferred Compensation Plan (the “Prior Plan”) had been “paid” to or “received” by Executive in the year when the deferral was made, provided that all such deferred amounts shall be subject to the other applicable definitions and rules of the Retirement Plan relating to benefit determination; plus

(ii)           The reduction, if any, in the amount of the monthly Social Security benefit payable to the Executive, provided that such reduction results from the fact that compensation deferred under this Plan causes the primary Social Security Benefit payable to the Executive to be reduced, with the amount under this Section 8(c)(ii) calculated assuming commencement of Social Security benefits at the earliest possible time, no earnings after Separation from Service and no projected increases in the national average wage index or cost of living between Separation from Service and commencement of benefits; minus

(iii)           The amount that would actually be payable at such time under the Retirement Plan assuming that (1) benefits had commenced on the date specified in Section 8(a), (2) benefits were payable in the annuity benefit form determined under Section 8(b), and (3) all accrued benefits under the Retirement Plan were payable only in the annuity form as provided in Section 8(d).

(d)           Retirement Plan Lump Sum Election Ignored.  Notwithstanding any election by an Executive to receive a portion of Executive’s Retirement Plan benefit as a lump sum, the amount of the supplemental retirement benefit as determined under Section 8(c) shall be calculated and determined as if Executive were to receive Executive’s entire Retirement Plan accrued benefit in the annuity form determined under Section 8(b).

(e)           Six-Month Minimum Delay.  Notwithstanding the foregoing, no supplemental retirement benefit payments under this Section 8 shall be paid to any Executive until the seventh month following the month of the Executive’s Separation from Service with the Company.  Any payments that would have been paid if not for this Section 8(e) shall be accumulated and paid in full in the seventh month following the month of the Executive’s Separation from Service with the Company together with interest from the date each payment otherwise would have been payable until the date actually paid.  Interest for any period will be paid at the same rate applicable for that period under Section 6(f).

(f)           Waiver of Comparable Benefits Under Prior Plan.  Because amounts deferred under the Prior Plan are taken into account in calculating the benefits payable under this Section 8, acceptance of the benefits under this Section 8 shall be deemed to be a waiver of the comparable benefits set forth in Section 5.7 of the Prior Plan.

9.Administration.

(a)Committee Duties.  This Plan shall be administered by the Organization and Executive Compensation Committee of the Board (the “Committee”).  The Committee shall have responsibility for the general administration of the Plan and for carrying out its intent and provisions.  The Committee shall interpret the Plan and have such powers and duties as may be necessary to discharge its responsibilities.  The Committee may, from time to time, employ other agents and delegate to them such administrative duties as it sees fit, and may from time to time consult with counsel who may be counsel to the Company.

(b)Tax Law Compliance.  The Committee shall have the authority to cancel any Participation Agreement in whole or in part, and immediately distribute any compensation deferred under such Participation Agreement, but only to the extent the Committee determines that deferral of compensation in accordance with such Participation Agreement has or will violate Section 409A of the Internal Revenue Code and therefore has or will require immediate inclusion of such compensation in the income of the Participant.

(c)Binding Effect of Decisions.  The decision or action of the Committee in respect of any question arising out of or in connection with the administration, interpretation and application of the Plan and the rules and regulations promulgated hereunder shall be final and conclusive and binding upon all persons having any interest in the Plan.

10.Claims Procedure.

(a)Claim.  Any person claiming a benefit, requesting an interpretation or ruling under the Plan, or requesting information under the Plan shall present the request in writing to the Committee, which shall respond in writing as soon as practicable.

(b)Denial of Claim.  If the claim or request is denied, the written notice of denial shall state:

(i)The reasons for denial, with specific reference to the Plan provisions on which the denial is based;

(ii)A description of any additional material or information required and an explanation of why it is necessary; and

(iii)An explanation of the Plan’s claim review procedure.

(c)Review of Claim.  Any person whose claim or request is denied or who has not received a response within thirty (30) days may request review by notice given in writing to the Committee.  The claim or request shall be reviewed by the Committee who may, but shall not be required to, grant the claimant a hearing.  On review, the claimant may have representation, examine pertinent documents, and submit issues and comments in writing.

(d)Final Decision.  The decision on review shall normally be made within sixty (60) days.  If an extension of time is required for a hearing or other special circumstances, the claimant shall be notified and the time limit shall be one hundred twenty (120) days.  The decision shall be in writing and shall state the reasons and the relevant Plan provisions.  All decisions on review shall be final and bind all parties concerned.

11.Amendment and Termination of the Plan.

(a)Amendment.  The Board may at any time amend the Plan in whole or in part; provided, however, that no amendment shall without the consent of each affected Participant (i) decrease or restrict the amount credited to any Account maintained under the Plan as of the date of amendment, or (ii) accelerate or decelerate the payment of benefits with respect to amounts credited to any Account as of the date of the amendment.

(b)Termination.  The Board may at any time partially or completely terminate the Plan if, in its judgment, the tax, accounting, or other effects of the continuance of the Plan, or potential payments thereunder, would not be in the best interests of the Company.

(i)Partial Termination.  The Board may partially terminate the Plan by instructing the Committee not to accept any additional Participation Agreements and terminating deferrals under all existing Participation Agreements.  In the event of such a partial termination, the Plan shall continue to operate and be effective with regard to all compensation deferred prior to the effective date of such partial termination.

(ii)Complete Termination.  The Board may completely terminate the Plan, provided such termination is covered by an exception (set forth in regulations or other guidance of the Internal Revenue Service) to the prohibition on acceleration of deferred compensation.  In that event, on the effective date of the complete termination, the Plan shall cease to operate and the Company shall determine the balance of each Participant’s Accounts as of the close of business on such effective date.  The Company shall pay out such Account balances to the Participants in a single lump sum payment as soon as practicable after such effective date.

12.Miscellaneous.

(a)Unsecured General Creditor.  The Accounts shall be established solely for the purpose of measuring the amounts owed to Participants or beneficiaries under the Plan.  Participants and their beneficiaries, heirs, successors and assigns shall have no legal or equitable rights, interest or claims in any property or assets of the Company, nor shall they be beneficiaries of, or have any rights, claims or interests in any mutual funds, other investment products or the proceeds therefrom owned or which may be acquired by the Company.  Except as may be provided in Section 12(b), such mutual funds, other investment products or other assets of the Company shall not be held under any trust for the benefit of the Participants, their beneficiaries, heirs, successors or assigns, or held in any way as collateral security for the fulfilling of the obligations of the Company under this Plan.  Any and all of the Company’s assets shall be, and remain, the general, unpledged, unrestricted assets of the Company.  The Company’s obligation under the Plan shall be that of an unfunded and unsecured promise to pay money in the future, and the rights of Participants and beneficiaries shall be no greater than those of unsecured general creditors of the Company.

(b)Trust Fund.  The Company shall be responsible for the payment of all benefits provided under the Plan.  The Company shall establish one or more trusts, with such trustees as the Board may approve, for the purpose of providing for the payment of such benefits, but the Company shall have no obligation to contribute to such trusts except as specifically provided in the applicable trust documents.  Such trust or trusts shall be irrevocable, but the assets thereof shall be subject to the claims of the Company’s creditors.  To the extent any benefits provided under the Plan are actually paid from any such trust, the Company shall have no further obligation with respect thereto, but to the extent not so paid, such benefits shall remain the obligation of, and shall be paid by, the Company.

(c)Non-assignability.  Neither a Participant nor any other person shall have the right to commute, sell, assign, transfer, pledge, anticipate, mortgage or otherwise encumber, transfer, hypothecate or convey in advance of actual receipt the amounts, if any, payable hereunder, or any part thereof, which are, and all rights to which are, expressly declared to be non-assignable and nontransferable.  No part of the amounts payable shall, prior to actual payment, be subject to seizure or sequestration for the payment of any debts, judgments, alimony or separate maintenance owed by a Participant or any other person, nor be transferable by operation of law in the event of a Participant’s or any other person’s bankruptcy or insolvency.

(d)Not a Contract of Employment.  The terms and conditions of this Plan shall not be deemed to constitute a contract of employment between the Company and any Participant, and the Participants (and their beneficiaries) shall have no rights against the Company except as may otherwise be specifically provided herein.  Moreover, nothing in this Plan shall be deemed to give a Participant the right to be retained in the service of the Company or to interfere with the right of the Company to discipline or discharge the Participant at any time.

(e)Governing Law.  The provisions of this Plan shall be construed and interpreted according to the laws of the State of Oregon, except as preempted by federal law.

(f)Validity.  In case any provision of this Plan shall be held illegal or invalid for any reason, said illegality or invalidity shall not affect the remaining parts hereof, but this Plan shall be construed and enforced as if such illegal and invalid provisions had never been inserted herein.

(g)Notice.  Any notice or filing required or permitted to be given to the Company or the Committee under the Plan shall be sufficient if in writing and hand delivered, or sent by registered or certified mail, to the Secretary of the Company.  Such notice shall be deemed given as of the date of delivery or, if delivery is made by mail, as of the date shown on the postmark on the receipt for registration or certification.

(h)Successors.  The provisions of this Plan shall bind and inure to the benefit of the Company and its successors and assigns.  The term successors as used herein shall include any corporate or other business entity which shall, whether by merger, consolidation, purchase or otherwise acquire all or substantially all of the business and assets of the Company, and successors of any such corporation or other business entity.

The foregoing restatement of the Plan was approved by the Board of Directors of Northwest Natural Gas Company on and effective as of December 15, 2011.

NORTHWEST NATURAL GAS COMPANY

By:                                                                           

Attest:                                                      

EX-10.N

As amended

effective January 1, 2012

NORTHWEST NATURAL GAS COMPANY

EXECUTIVE ANNUAL INCENTIVE PLAN

This amended Executive Annual Incentive Plan (the “Plan”) is executed by Northwest Natural Gas Company, an Oregon corporation (the “Company”), effective January 1, 2012.

PURPOSE OF PLAN

The success of NNG is dependent upon its ability to attract and retain the services of key executives of the highest competence and to provide incentives for superior performance. The purpose of the plan is to advance the interests of the Company and its shareholders through an incentive compensation program that will attract and retain key executives and motivate them to achieve performance goals.

PROGRAM TERM

This Plan is an annual incentive plan and each new calendar year commences a new Program Term. Each Program Term will begin on January 1 and conclude on December 31.

PARTICIPATION

All executive officers of the company and any other highly compensated employees as designated by the Company’s Organization and Executive Compensation Committee (the “Committee”) are eligible to receive awards (“Awards”) under the Executive Annual Incentive Plan.

At the beginning of each Program Term, the Committee shall determine eligibility for Awards and establish for each participant, the target incentive level as a percentage of year-end annualized based salary (“Target Award”). This information will be set forth in Exhibit I of the Plan document for the Program Term. Each such participating employee shall be referred to as a “Participant.”

To be eligible for payout of an Award the Participant must have a minimum of three months of service during the Program Term. If the Participant is a new employee or is newly eligible to participate in the Plan, that Participant must be in an eligible position on or before September 30 of the Program Term. In addition, the Participant must be employed on December 31 of the Program Term to be eligible for payout of the Award for the Program Term unless the Participant is eligible for a prorated Award. Eligibility for a prorated Award occurs when a Participant has three or more months of participation in the Program Term but the Participant’s employment is terminated prior to December 31 of the Program Term due to one of the following: Retirement (unless such Retirement results from a termination of the Participant’s employment by the Company for Cause), disability and death. Prorated Awards will be determined by prorating the Participant’s final Award by the number of days employed during the Program Term.

“Retirement” shall mean termination of employment after Participant is (a) age 62 with at least five years of service as an employee of the Company, or (b) age 55 with age plus years of service (including fractions) as an employee of the Company totaling at least 70.

“Cause” shall mean (a) the willful and continued failure by a Participant to perform substantially the Participant’s assigned duties with the Company (other than any such failure resulting from incapacity due to physical or mental illness) after a demand for substantial performance is delivered to the Participant by the Company which specifically identifies the manner in which the Participant has not substantially performed such duties, (b) willful commission by a Participant of an act of fraud or dishonesty resulting in economic or financial injury to the Company, (c) willful misconduct by a Participant that substantially impairs the Company’s business or reputation, or (d) willful gross negligence by a Participant in the performance of his or her duties.

In the event of a change in job position during the Program Term, the Committee may, in its discretion, increase or decrease the amount of a Participant’s Award to reflect such change.

INCENTIVE FORMULA

The formula for calculating Awards for each Program Term is as follows:

Target Award  X                                                      ( Company      X                                           CPF      +                      Individual       XIPF)  =Participant

( Performance                           Factor                 Performance                           Factor              )         Award

( Factor (CPF)                           Weight                 Factor (IPF)                           Weight              )

COMPANY PERFORMANCE FACTOR

The Company performance goals in the Plan are intended to align the interest of Participants with those of the shareholders. The goals and the formula for determining the Company Performance Factor will be established by the Committee at the start of each Program Term and set forth as Exhibit II.  After the goals and formula are established for a Program Term, the Committee retains discretion to modify the goals and formula, including by adjusting the calculation of any financial or other goal to eliminate the effects of significant extraordinary, non-recurring or unplanned items such as changes in law or accounting principles.

There shall be no payout of Awards under the Plan for any Program Term in which net income is less than dividends payable on the preferred and common stock.

INDIVIDUAL PERFORMANCE FACTOR

The IPF weight used in calculating the Individual Performance Factor will be established for each Participant by the Committee at the beginning of the Program Term and set forth as part of Exhibit I. Also included in Exhibit I will be the CPF Factor Weight for the Company Performance Factor. Individual goals for each Participant will be established at the beginning of each Program Term and performance against these goals will be assessed by the Participant’s superior and approved by the C.E.O. at the end of the Program Term. This assessment will result in a rating on a scale of 0% to 150%. This rating is called the Individual Performance Factor. The Participant will not receive a payout under the Individual Performance component of an Award if the Individual Performance Factor is less than 50%.

ADMINISTRATION

Award payouts will be calculated and paid no later than the March 15 following the end of the Program Term. Award payouts are subject to tax withholding unless the Participant made a prior election to defer the Award payout under the terms of the Deferred Compensation Plan for Directors and Executives (“DCP”).

All Award payouts shall be audited by the Internal Audit department and approved by the Committee prior to payment.

The Plan shall be administered by the Committee. The Committee shall have the exclusive authority and responsibility for all matters in connection with the operation and administration of the Plan. Decisions by the Committee shall be final and binding upon all parties affected by the Plan, including the beneficiaries of Participants.

The Committee may rely on information and recommendations provided by management. The Committee may delegate to management the responsibility for decisions that it may make or actions that it may take under the terms of the Plan, subject to the Committee’s reserved right to review such decisions or actions and modify them when necessary or appropriate under the circumstances.  The Committee shall not allow any employee to obtain control over decisions or actions that affect that employee’s Plan benefits.

RECOUPMENT ON EARNINGS RESTATEMENT

If at any time before a Change in Control and within three years after the payout of Awards for a Program Term, the Company’s financial statements for that Program Term are the subject of a restatement due to the Misconduct of any person, each Participant who received an Award payout for that Program Term (whether or not such Participant was personally involved in such Misconduct) shall repay to the Company the Excess Bonus Compensation (as defined below).  For purposes of the Plan, “Excess Bonus Compensation” for any Participant means the positive difference, if any, between (i) the Participant’s Award payout as originally calculated, and (ii) the Participant’s Award payout as recalculated with the results for Company performance goals being based on the Company’s financial statements as restated.  Excess Bonus Compensation shall not include any amounts in respect of any individual performance goals or in respect of Company performance goals that are not measured in whole or in part on financial results reported in the Company’s financial statements.  The Committee may, in its sole discretion, reduce the amount of Excess Bonus Compensation to be repaid by any Participant to take into account the tax consequences of such repayment for the Participant.

If any portion of an Award payout was deferred under the DCP, any Excess Bonus Compensation to be repaid with respect to that Award shall first be recovered by canceling all or a portion of the amount so deferred under the DCP and any interest credited under the DCP with respect to such cancelled amount.  The Company may seek direct repayment from the Participant of any Excess Bonus Compensation not so recovered and may, to the extent permitted by applicable law, offset such Excess Bonus Compensation against any compensation or other amounts owed by the Company to the Participant.  In particular, Excess Bonus Compensation may be recovered by offset against the after-tax proceeds of deferred compensation payouts under the DCP, the Company’s Executive Supplemental Retirement Income Plan or the Company’s Supplemental Executive Retirement Plan at the times such deferred compensation payouts occur under the terms of those plans.  Excess Bonus Compensation that remains unpaid for more than 60 days after demand by the Company shall accrue interest at the rate used from time to time for crediting interest under the DCP.

“Misconduct” shall mean (a) willful commission by any person of an act of fraud or dishonesty or (b) willful gross negligence by any person in the performance of his or her duties.

“Change in Control” of the Company shall mean the occurrence of any of the following events:

(a)           The consummation of:

(i)           any consolidation, merger or plan of share exchange involving the Company (a “Merger”) as a result of which the holders of outstanding securities of the Company ordinarily having the right to vote for the election of directors (“Voting Securities”) immediately prior to the Merger do not continue to hold at least 50% of the combined voting power of the outstanding Voting Securities of the surviving corporation or a parent corporation of the surviving corporation immediately after the Merger, disregarding any Voting Securities issued to or retained by such holders in respect of securities of any other party to the Merger; or

(ii)           any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, the assets of the Company;

(b)           At any time during a period of two consecutive years, individuals who at the beginning of such period constituted the Company’s Board of Directors (“Incumbent Directors”) shall cease for any reason to constitute at least a majority thereof; provided, however, that the term “Incumbent Director” shall also include each new director elected during such two-year period whose nomination or election was approved by two-thirds of the Incumbent Directors then in office; or

(c)           Any person (as such term is used in Section 14(d) of the Securities Exchange Act of 1934, other than the Company or any employee benefit plan sponsored by the Company) shall, as a result of a tender or exchange offer, open market purchases or privately negotiated purchases from anyone other than the Company, have become the beneficial owner (within the meaning of Rule 13d-3 under the Securities Exchange Act of 1934), directly or indirectly, of Voting Securities representing twenty percent (20%) or more of the combined voting power of the then outstanding Voting Securities.

AMENDMENTS AND TERMINATION

The Board has the power to terminate this Plan at any time or to amend this Plan at any time and in any manner that it may deem advisable.

IN WITNESS WHEREOF this Plan was duly amended on the 15th day of December 2011, effective January 1, 2012.

NORTHWEST NATURAL GAS COMPANY

By:                                                                           

Gregg S. Kantor

President and Chief Executive Officer

EX-10.S

LONG TERM INCENTIVE AWARD AGREEMENT

This Agreement is entered into as of March __, 2009, between Northwest Natural Gas Company, an Oregon corporation (the “Company”), and ____________ (“Recipient”).

On February __, 2009, the Organization and Executive Compensation Committee (the “Committee”) of the Company’s Board of Directors (the “Board”) authorized an objectively-determinable performance-based award (the “TSR Award”) to Recipient pursuant to Section 8 of the Company’s Long Term Incentive Plan (the “Plan”) and a subjective performance-based award (the “Strategic Award”) to Recipient pursuant to Section 6 of the Plan.  Compensation paid pursuant to the TSR Award is intended to qualify as performance-based compensation under Section 162(m) of the Internal Revenue Code of 1986 (the “Code”), while compensation paid pursuant to the Strategic Award will not so qualify.  Recipient desires to accept the awards subject to the terms and conditions of this Agreement.

NOW, THEREFORE, the parties agree as follows:

1.Awards.  Recipient’s “Target Share Amount” for purposes of this Agreement is ________ shares.

1.1TSR Award.  Subject to the terms and conditions of this Agreement, the Company shall issue or otherwise deliver to the Recipient the number of shares of Common Stock of the Company (the “TSR Performance Shares”) determined under this Agreement based on (a) the performance of the Company’s Common Stock relative to a peer group of companies during the three-year period from January 1, 2009 to December 31, 2011 (the “Award Period”) as described in Section 2 and (b) Recipient’s continued employment during the Award Period as described in Section 4.  If the Company issues or otherwise delivers TSR Performance Shares to Recipient, the Company shall also pay to Recipient the amount of cash determined under Section 5 (the “TSR Dividend Equivalent Cash Award”).  Recipient’s “TSR Target Share Amount” for purposes of this Agreement is 75% of the Target Share Amount.

1.2Strategic Award.  Subject to the terms and conditions of this Agreement, the Company shall issue or otherwise deliver to the Recipient the number of shares of Common Stock of the Company (the “Strategic Performance Shares” and, together with the TSR Performance Shares, the “Performance Shares”) determined under this Agreement based on (a) the Company’s performance against milestones during the Award Period as determined by the Committee under Section 3 and (b) Recipient’s continued employment during the Award Period as described in Section 4.  If the Company issues or otherwise delivers Strategic Performance Shares to Recipient, the Company shall also pay to Recipient the amount of cash determined under Section 5 (the “Strategic Dividend Equivalent Cash Award” and, together with the TSR Dividend Equivalent Cash Award, the “Dividend Equivalent Cash Awards”).  Recipient’s “Strategic Target Share Amount” for purposes of this Agreement is 25% of the Target Share Amount.

2.TSR Performance Condition.

2.1Subject to possible reduction under Section 4, the number of TSR Performance Shares to be issued or otherwise delivered to Recipient shall be determined by multiplying the TSR Payout Factor (as defined below) by the TSR Target Share Amount; provided, however, that no TSR Performance Shares shall be issued or otherwise delivered unless the Company’s TSR (as defined below) for the Award Period is at least 19.1%.

2.2To determine the “TSR Payout Factor,” the ten Peer Group Companies (as defined below) shall be ranked based on their respective TSR’s from highest to lowest, with the Peer Group Company with the highest TSR having a TSR Ranking of “1” and the Peer Group Company with the lowest TSR having a TSR Ranking of “10.”  If the Company’s TSR is equal to the TSR of any other Peer Group Company, the TSR Payout Factor will be the percentage in the following table corresponding to the TSR Ranking of that Peer Group Company.

TSR Ranking	TSR Payout Factor
10	0%
9	0%
8	25%
7	25%
6	50%
5	75%
4	100%
3	125%
2	150%
1	200%

If the Company’s TSR is higher than the TSRs of all Peer Group Companies, the TSR Payout Factor will be 200%.  If the Company’s TSR is not at least as high as the TSR of the Peer Group Company with the TSR Ranking of “8,” the TSR Payout Factor will be 0%.  If the Company’s TSR is between the TSRs of any two Peer Group Companies with TSR Rankings between “1” and “8,” the TSR Payout Factor shall be interpolated as follows.  The excess of the Company’s TSR over the TSR of the lower Peer Group Company shall be divided by the excess of the TSR of the higher Peer Group Company over the TSR of the lower Peer Group Company.  The resulting fraction shall be multiplied by the difference between the percentages in the above table corresponding to the TSR Rankings of the two Peer Group Companies.  The product of that calculation shall be added to the percentage in the above table corresponding to the TSR Ranking of the lower Peer Group Company, and the resulting sum shall be the TSR Payout Factor.

2.3The “Peer Group Companies” are AGL Resources Inc., Atmos Energy Corporation, The Laclede Group, Inc., New Jersey Resources Corporation, NICOR Inc., Piedmont Natural Gas Company, Inc., South Jersey Industries, Inc., Southwest Gas Corporation, Vectren Corporation and W G L Holdings, Inc.  If prior to the end of the Award Period, the common stock of any Peer Group Company ceases to be publicly traded for any reason, then such company shall no longer be considered a Peer Group Company, and an alternate peer company shall become a Peer Group Company effective as of the start of the Award Period.  The alternate peer companies, and the order in which they will be added as Peer Group Companies, if necessary, are:  first, NiSource Inc.; second, National Fuel Gas Company; and third, Chesapeake Utilities Corporation.  If prior to the end of the Award Period, all of the above alternate peer companies have become Peer Group Companies and the common stock of yet another Peer Group Company ceases to be publicly traded for any reason so that there are only nine remaining Peer Group Companies, for purposes of Section 2.2 it shall be assumed that there is a hypothetical Peer Group Company with a TSR Ranking of “5”; provided, however, that if the Company’s TSR is between the TSRs of the Peer Group Companies with TSR Rankings of “4” and “6,” the TSR Payout Factor shall be interpolated between the payout percentages corresponding to the TSR Rankings of those two companies.  If yet another Peer Group Company ceases to be publicly traded for any reason so that there are only eight remaining Peer Group Companies, for purposes of Section 2.2 it shall be assumed that there are two hypothetical Peer Group Company with TSR Rankings of “5” and “6” and, if necessary, the TSR Payout Factor shall interpolated between the payout percentages corresponding to the Peer Group Companies with TSR Rankings of “4” and “7”.  Similarly, if additional Peer Group Companies cease to be publicly traded for any reason, additional hypothetical Peer Group Companies shall be assumed to exist with TSR Rankings of “4”, then “7”, then “3”, then “9”, and then “2”.

2.4The “TSR” for the Company and each Peer Group Company shall be calculated by (a) assuming that $100 is invested in the common stock of the company at a price equal to the average of the closing market prices of the stock for the period from October 1, 2008 to December 31, 2008, (b) assuming that for each dividend paid on the stock during the Award Period, the amount equal to the dividend paid on the assumed number of shares held is reinvested in additional shares at a price equal to the closing market price of the stock on the ex-dividend date for the dividend, and (c) determining the final dollar value of the total assumed number of shares based on the average of the closing market prices of the stock for the period from October 1, 2011 to December 31, 2011.  The “TSR” shall then equal the amount determined by subtracting $100 from the foregoing final dollar value, dividing the result by 100 and expressing the resulting fraction as a percentage.

2.5If during the Award Period any Peer Group Company enters into an agreement pursuant to which all or substantially all of the stock or assets of the Peer Group Company will be acquired by a third party (a “Signed Acquisition”), and if the Signed Acquisition is not completed so that such company remains a Peer Group Company at the end of the Award Period, then the calculation of the TSR for that Peer Group Company shall be modified as provided in this Section 2.5.  A “Partial Period TSR” for each Peer Group Company shall be calculated in the same manner as TSR is calculated under Section 2.4, except that for this purpose the Award Period shall be deemed to have ended on the day before the date of announcement of the Signed Acquisition and the final dollar value under clause (c) of Section 2.4 for each Peer Group Company shall be determined based on the average of the closing market prices of each stock for the three-month period ending on the day before such announcement date.  The TSR of the Peer Group Company subject to the Signed Acquisition shall then be equal to its Partial Period TSR multiplied by the Average Change Factor (as defined below).  The “Average Change Factor” shall be a fraction, the numerator of which is the average of the TSRs of all Peer Group Companies that are not subject to a Signed Acquisition, and the denominator of which is the average of the Partial Period TSRs of those Peer Group Companies.  If a Signed Acquisition of a Peer Group Company is terminated (other than in connection with the execution of another Signed Acquisition) before the end of the Award Period, then the above modification to the calculation of TSR for that Peer Group Company shall not apply, and the TSR for that Peer Group Company shall be calculated as provided in Section 2.4, except that if the announcement of the termination of the Signed Acquisition occurs during the last three months of the Award Period, for purposes of determining the final dollar value under clause (c) of Section 2.4, the three-month period for which closing market prices are averaged shall be shortened to exclude any trading days preceding the announcement of the termination of the Signed Acquisition.

3.Strategic Performance Condition.  Subject to possible reduction under Section 4, the number of Strategic Performance Shares to be issued or otherwise delivered to Recipient shall be determined by multiplying the Strategic Payout Factor by the Strategic Target Share Amount.  The “Strategic Payout Factor” shall be a percentage between 0% and 200% determined by the Committee after the Award Period based on the Committee’s assessment of the extent to which the Company has achieved the following goals during the Award Period:

[applicable goals]

The Strategic Payout Factor shall be the same percentage for Recipient and all other recipients of similar awards for the Award Period.  Although each goal category set forth above is shown as having a Goal Weight, such Goal Weights may be changed by the Committee at any time in its sole discretion.  In determining the Strategic Payout Factor, the Committee in its discretion generally will assign a percentage of 100% for satisfactory achievement of all goals, a higher percentage for exceeding expectations and a lower percentage if goals are not achieved.

4.Employment Condition.

4.1In order to receive the full number of Performance Shares determined under Section 2 or Section 3, Recipient must be employed by the Company on the last day of the Award Period.

4.2If Recipient’s employment by the Company is terminated at any time prior to the end of the Award Period because of death, physical disability (within the meaning of Section 22(e)(3) of the Code), or retirement (as defined in the Company’s Retirement Plan for Non-Bargaining Unit Employees) at or after reaching age 60, Recipient shall be entitled to receive pro-rated awards.  The number of each type of Performance Shares to be issued or otherwise delivered as a pro-rated award shall be determined by multiplying the number of Performance Shares determined under Section 2 or Section 3 by a fraction, the numerator of which is the number of days Recipient was employed by the Company during the Award Period and the denominator of which is the number of days in the Award Period.

4.3If Recipient’s employment by the Company is terminated at any time prior to the end of the Award Period and Section 4.2 does not apply to such termination, Recipient shall not be entitled to receive any Performance Shares.

5.Dividend Equivalent Cash Awards.  The amount of each type of Dividend Equivalent Cash Award shall be determined by multiplying the number of Performance Shares deliverable to Recipient as determined under Sections 2 and 4 or under Sections 3 and 4, as applicable, by the total amount of dividends paid per share of the Company’s Common Stock for which the dividend record date occurred after the beginning of the Award Period and before the date of delivery of the Performance Shares.

6.Certification and Payment.  At the regularly scheduled meeting of the Committee held in February of the year immediately following the final year of the Award Period (the “Certification Meeting”), the Committee shall determine the Strategic Payout Factor and certify in writing (which may consist of approved minutes of the Certification Meeting) the number of Strategic Performance Shares deliverable to Recipient and the amount of the Strategic Dividend Equivalent Cash Award payable to Recipient.  Prior to the Certification Meeting, the Company shall calculate the number of TSR Performance Shares deliverable and the amount of the TSR Dividend Equivalent Cash Award payable to Recipient, and shall submit these calculations to the Committee.  At or prior to the Certification Meeting, the Committee shall certify in writing (which may consist of approved minutes of the Certification Meeting) the levels of TSR attained by the Company and the Peer Group Companies, the number of TSR Performance Shares deliverable to Recipient and the amount of the TSR Dividend Equivalent Cash Award payable to Recipient.  Subject to applicable tax withholding, the amounts so certified shall be delivered or paid (as applicable) on a date (the “Payment Date”) that is the later of March 1, 2012 or five business days following the Certification Meeting, and no amounts shall be delivered or paid prior to certification.  No fractional shares shall be delivered and the number of Performance Shares deliverable shall be rounded to the nearest whole share.  Notwithstanding the foregoing, if Recipient shall have made a valid election to defer receipt of Performance Shares or Dividend Equivalent Cash Awards pursuant to the terms of the Company’s Deferred Compensation Plan for Directors and Executives, payment of the award shall be made in accordance with that election.

7.Tax Withholding.  Recipient acknowledges that, on the Payment Date when the Performance Shares are issued or otherwise delivered to Recipient, the Value (as defined below) on that date of the Performance Shares (as well as the amount of the Dividend Equivalent Cash Awards) will be treated as ordinary compensation income for federal and state income and FICA tax purposes, and that the Company will be required to withhold taxes on these income amounts.  To satisfy the required withholding amount, the Company shall first withhold all or part of the Dividend Equivalent Cash Awards, and if that is insufficient, the Company shall withhold the number of Performance Shares having a Value equal to the remaining withholding amount.  For purposes of this Section 7, the “Value” of a Performance Share shall be equal to the closing market price for Company Common Stock on the last trading day preceding the Payment Date.  Notwithstanding the foregoing, Recipient may elect not to have Performance Shares withheld to cover taxes by giving notice to the Company in writing prior to the Payment Date, in which case the Performance Shares shall be issued or acquired in the Recipient’s name on the Payment Date thereby triggering the tax consequences, but the Company shall retain the certificate for the Performance Shares as security until Recipient shall have paid to the Company in cash any required tax withholding not covered by withholding of the Dividend Equivalent Cash Awards.

8.Change in Control.

8.1If a Change in Control (as defined below) occurs before the end of the Award Period, the Company shall, within 5 business days thereafter and subject to applicable tax withholding as provided for in Section 7, issue or otherwise deliver to Recipient a number of Performance Shares determined by multiplying the CIC Share Amount (as defined below) by a fraction, the numerator of which is the number of days in the period starting on the first day of the Award Period and ending on the date of the Change of Control and the denominator of which is the number of days in the Award Period.  At the same time, the Company shall pay to Recipient a Dividend Equivalent Cash Award based on such number of Performance Shares.  The “CIC Share Amount” shall equal 100% of the Strategic Target Share Amount plus an amount equal to the CIC TSR Payout Factor (as defined below) multiplied by the TSR Target Share Amount.  The “CIC TSR Payout Factor” shall be determined in the same manner as the TSR Payout Factor is determined under Section 2 of this Agreement, except that the final dollar value under clause (c) of Section 2.4 for the Company and each Peer Group Company shall be determined based on the average of the closing market prices of each stock for the three-month period ending on the date of the Change of Control; provided, however, that the CIC TSR Payout Factor shall be zero percent if the Company’s TSR as computed for this purpose does not represent at least a 6% annual return (cumulated annually) for the period starting on the first day of the Award Period and ending on the date of the Change of Control.  Amounts delivered or paid under this Section 8 shall be in satisfaction of any and all obligations of the Company to issue or otherwise deliver Performance Shares or pay Dividend Equivalent Cash Awards under this Agreement.

8.2For purposes of this Agreement, a “Change in Control” of the Company shall mean the occurrence of any of the following events:

(a)The consummation of:

(1)any consolidation, merger or plan of share exchange involving the Company (a “Merger”) as a result of which the holders of outstanding securities of the Company ordinarily having the right to vote for the election of directors (“Voting Securities”) immediately prior to the Merger do not continue to hold at least 50% of the combined voting power of the outstanding Voting Securities of the surviving corporation or a parent corporation of the surviving corporation immediately after the Merger, disregarding any Voting Securities issued to or retained by such holders in respect of securities of any other party to the Merger; or

(2)any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, the assets of the Company;

(b)At any time during a period of two consecutive years, individuals who at the beginning of such period constituted the Board (“Incumbent Directors”) shall cease for any reason to constitute at least a majority thereof; provided, however, that the term “Incumbent Director” shall also include each new director elected during such two-year period whose nomination or election was approved by two-thirds of the Incumbent Directors then in office; or

(c)Any person (as such term is used in Section 14(d) of the Securities Exchange Act of 1934, other than the Company or any employee benefit plan sponsored by the Company) shall, as a result of a tender or exchange offer, open market purchases or privately negotiated purchases from anyone other than the Company, have become the beneficial owner (within the meaning of Rule 13d-3 under the Securities Exchange Act of 1934), directly or indirectly, of Voting Securities representing twenty percent (20%) or more of the combined voting power of the then outstanding Voting Securities.

9.Changes in Capital Structure.

9.1If the outstanding Common Stock of the Company is hereafter increased or decreased or changed into or exchanged for a different number or kind of shares or other securities of the Company by reason of any stock split, combination of shares or dividend payable in shares, recapitalization or reclassification, appropriate adjustment shall be made by the Committee in the number and kind of shares subject to this Agreement so that the Recipient’s proportionate interest before and after the occurrence of the event is maintained.

9.2If the outstanding Common Stock of the Company is hereafter converted into or exchanged for all of the outstanding Common Stock of a corporation (the “Parent Successor”) as part of a transaction (the “Transaction”) in which the Company becomes a wholly-owned subsidiary of Parent Successor, then (a) the obligations under this Agreement shall be assumed by Parent Successor and references in this Agreement to the Company shall thereafter generally be deemed to refer to Parent Successor, (b) Common Stock of Parent Successor shall be issued in lieu of Common Stock of the Company under this Agreement, (c) the performance measured pursuant to Sections 2 and 3 of this Agreement shall be the continuous performance of the Company prior to the Transaction and Parent Successor after the Transaction, (d) employment by the Company for purposes of Section 4 of this Agreement shall include employment by either the Company or Parent Successor, and (e) the Dividend Equivalent Cash Awards under Section 5 of this Agreement shall be based on dividends paid on the Common Stock of the Company prior to the Transaction and Parent Successor after the Transaction.

10.Approvals.  The issuance by the Company of authorized and unissued shares or reacquired shares under this Agreement is subject to the approval of the Oregon Public Utility Commission and the Washington Utilities and Transportation Commission, but no such approvals shall be required for the purchase of shares on the open market for delivery to Recipient in satisfaction of its obligations under this Agreement.  The obligations of the Company under this Agreement are otherwise subject to the approval of state and federal authorities or agencies with jurisdiction in the matter.  The Company will use its best efforts to take steps required by state or federal law or applicable regulations, including rules and regulations of the Securities and Exchange Commission and any stock exchange on which the Company’s shares may then be listed, in connection with the award under this Agreement.  The foregoing notwithstanding, the Company shall not be obligated to issue or deliver Common Stock under this Agreement if such issuance or delivery would violate applicable state or federal law.

11.No Right to Employment.  Nothing contained in this Agreement shall confer upon Recipient any right to be employed by the Company or to continue to provide services to the Company or to interfere in any way with the right of the Company to terminate Recipient’s services at any time for any reason, with or without cause.

12.Miscellaneous.

12.1Entire Agreement; Amendment.  This Agreement constitutes the entire agreement of the parties with regard to the subjects hereof and may be amended only by written agreement between the Company and Recipient.

12.2Notices.  Any notice required or permitted under this Agreement shall be in writing and shall be deemed sufficient when delivered personally to the party to whom it is addressed or when deposited into the United States Mail as registered or certified mail, return receipt requested, postage prepaid, addressed to the Company, Attention:  Corporate Secretary, at its principal executive offices or to Recipient at the address of Recipient in the Company’s records, or at such other address as such party may designate by ten (10) days’ advance written notice to the other party.

12.3Assignment; Rights and Benefits.  Recipient shall not assign this Agreement or any rights hereunder to any other party or parties without the prior written consent of the Company.  The rights and benefits of this Agreement shall inure to the benefit of and be enforceable by the Company’s successors and assigns and, subject to the foregoing restriction on assignment, be binding upon Recipient’s heirs, executors, administrators, successors and assigns.

12.4Further Action.  The parties agree to execute such further instruments and to take such further action as may reasonably be necessary to carry out the intent of this Agreement.

12.5Applicable Law; Attorneys’ Fees.  The terms and conditions of this Agreement shall be governed by the laws of the State of Oregon.  In the event either party institutes litigation hereunder, the prevailing party shall be entitled to reasonable attorneys’ fees to be set by the trial court and, upon any appeal, the appellate court.

12.6Counterparts.  This Agreement may be executed in two or more counterparts, each of which shall be deemed an original.

IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the day and year first above written.

NORTHWEST NATURAL GAS COMPANY

By           

Title           

RECIPIENT

EX-10.T

LONG TERM INCENTIVE AWARD AGREEMENT

This Agreement is entered into as of March 1, 2010, between Northwest Natural Gas Company, an Oregon corporation (the “Company”), and ____________ (“Recipient”).

On February 24, 2010, the Organization and Executive Compensation Committee (the “Committee”) of the Company’s Board of Directors (the “Board”) authorized an objectively-determinable performance-based award (the “TSR Award”) to Recipient pursuant to Section 8 of the Company’s Long Term Incentive Plan (the “Plan”) and a subjective performance-based award (the “Strategic Award”) to Recipient pursuant to Section 6 of the Plan.  Compensation paid pursuant to the TSR Award is intended to qualify as performance-based compensation under Section 162(m) of the Internal Revenue Code of 1986 (the “Code”), while compensation paid pursuant to the Strategic Award will not so qualify.  Recipient desires to accept the awards subject to the terms and conditions of this Agreement.

NOW, THEREFORE, the parties agree as follows:

1.Awards.  Recipient’s “Target Share Amount” for purposes of this Agreement is ________ shares.

1.1TSR Award.  Subject to the terms and conditions of this Agreement, the Company shall issue or otherwise deliver to the Recipient the number of shares of Common Stock of the Company (the “TSR Performance Shares”) determined under this Agreement based on (a) the performance of the Company’s Common Stock relative to a peer group of companies during the three-year period from January 1, 2010 to December 31, 2012 (the “Award Period”) as described in Section 2 and (b) Recipient’s continued employment during the Award Period as described in Section 4.  If the Company issues or otherwise delivers TSR Performance Shares to Recipient, the Company shall also pay to Recipient the amount of cash determined under Section 5 (the “TSR Dividend Equivalent Cash Award”).  Recipient’s “TSR Target Share Amount” for purposes of this Agreement is 75% of the Target Share Amount.

1.2Strategic Award.  Subject to the terms and conditions of this Agreement, the Company shall issue or otherwise deliver to the Recipient the number of shares of Common Stock of the Company (the “Strategic Performance Shares” and, together with the TSR Performance Shares, the “Performance Shares”) determined under this Agreement based on (a) the Company’s performance against milestones during the Award Period as determined by the Committee under Section 3 and (b) Recipient’s continued employment during the Award Period as described in Section 4.  If the Company issues or otherwise delivers Strategic Performance Shares to Recipient, the Company shall also pay to Recipient the amount of cash determined under Section 5 (the “Strategic Dividend Equivalent Cash Award” and, together with the TSR Dividend Equivalent Cash Award, the “Dividend Equivalent Cash Awards”).  Recipient’s “Strategic Target Share Amount” for purposes of this Agreement is 25% of the Target Share Amount.

2.TSR Performance Condition.

2.1Subject to possible reduction under Section 4, the number of TSR Performance Shares to be issued or otherwise delivered to Recipient shall be determined by multiplying the TSR Payout Factor (as defined below) by the TSR Target Share Amount; provided, however, that no TSR Performance Shares shall be issued or otherwise delivered if the Company’s TSR (as defined below) for the Award Period is less than 0%.

2.2To determine the “TSR Payout Factor,” the ten Peer Group Companies (as defined below) shall be ranked based on their respective TSR’s from highest to lowest, with the Peer Group Company with the highest TSR having a TSR Ranking of “1” and the Peer Group Company with the lowest TSR having a TSR Ranking of “10.”  If the Company’s TSR is equal to the TSR of any other Peer Group Company, the TSR Payout Factor will be the percentage in the following table corresponding to the TSR Ranking of that Peer Group Company.

TSR Ranking	TSR Payout Factor
10	0%
9	0%
8	25%
7	25%
6	50%
5	75%
4	100%
3	125%
2	150%
1	200%

If the Company’s TSR is higher than the TSRs of all Peer Group Companies, the TSR Payout Factor will be 200%.  If the Company’s TSR is not at least as high as the TSR of the Peer Group Company with the TSR Ranking of “8,” the TSR Payout Factor will be 0%.  If the Company’s TSR is between the TSRs of any two Peer Group Companies with TSR Rankings between “1” and “8,” the TSR Payout Factor shall be interpolated as follows.  The excess of the Company’s TSR over the TSR of the lower Peer Group Company shall be divided by the excess of the TSR of the higher Peer Group Company over the TSR of the lower Peer Group Company.  The resulting fraction shall be multiplied by the difference between the percentages in the above table corresponding to the TSR Rankings of the two Peer Group Companies.  The product of that calculation shall be added to the percentage in the above table corresponding to the TSR Ranking of the lower Peer Group Company, and the resulting sum shall be the TSR Payout Factor.

2.3The “Peer Group Companies” are AGL Resources Inc., Atmos Energy Corporation, The Laclede Group, Inc., New Jersey Resources Corporation, NICOR Inc., Piedmont Natural Gas Company, Inc., South Jersey Industries, Inc., Southwest Gas Corporation, Vectren Corporation and W G L Holdings, Inc.  If prior to the end of the Award Period, the common stock of any Peer Group Company ceases to be publicly traded for any reason, then such company shall no longer be considered a Peer Group Company, and an alternate peer company shall become a Peer Group Company effective as of the start of the Award Period.  The alternate peer companies, and the order in which they will be added as Peer Group Companies, if necessary, are:  first, NiSource Inc.; second, National Fuel Gas Company; and third, Chesapeake Utilities Corporation.  If prior to the end of the Award Period, all of the above alternate peer companies have become Peer Group Companies and the common stock of yet another Peer Group Company ceases to be publicly traded for any reason so that there are only nine remaining Peer Group Companies, for purposes of Section 2.2 it shall be assumed that there is a hypothetical Peer Group Company with a TSR Ranking of “5”; provided, however, that if the Company’s TSR is between the TSRs of the Peer Group Companies with TSR Rankings of “4” and “6,” the TSR Payout Factor shall be interpolated between the payout percentages corresponding to the TSR Rankings of those two companies.  If yet another Peer Group Company ceases to be publicly traded for any reason so that there are only eight remaining Peer Group Companies, for purposes of Section 2.2 it shall be assumed that there are two hypothetical Peer Group Company with TSR Rankings of “5” and “6” and, if necessary, the TSR Payout Factor shall interpolated between the payout percentages corresponding to the Peer Group Companies with TSR Rankings of “4” and “7”.  Similarly, if additional Peer Group Companies cease to be publicly traded for any reason, additional hypothetical Peer Group Companies shall be assumed to exist with TSR Rankings of “4”, then “7”, then “3”, then “9”, and then “2”.

2.4The “TSR” for the Company and each Peer Group Company shall be calculated by (a) assuming that $100 is invested in the common stock of the company at a price equal to the average of the closing market prices of the stock for the period from October 1, 2009 to December 31, 2009, (b) assuming that for each dividend paid on the stock during the Award Period, the amount equal to the dividend paid on the assumed number of shares held is reinvested in additional shares at a price equal to the closing market price of the stock on trade date immediately preceding the ex-dividend date for the dividend, and (c) determining the final dollar value of the total assumed number of shares based on the average of the closing market prices of the stock for the period from October 1, 2012 to December 31, 2012.  The “TSR” shall then equal the amount determined by subtracting $100 from the foregoing final dollar value, dividing the result by 100 and expressing the resulting fraction as a percentage.

2.5If during the Award Period any Peer Group Company enters into an agreement pursuant to which all or substantially all of the stock or assets of the Peer Group Company will be acquired by a third party (a “Signed Acquisition”), and if the Signed Acquisition is not completed so that such company remains a Peer Group Company at the end of the Award Period, then the calculation of the TSR for that Peer Group Company shall be modified as provided in this Section 2.5.  A “Partial Period TSR” for each Peer Group Company shall be calculated in the same manner as TSR is calculated under Section 2.4, except that for this purpose the Award Period shall be deemed to have ended on the day before the date of announcement of the Signed Acquisition and the final dollar value under clause (c) of Section 2.4 for each Peer Group Company shall be determined based on the average of the closing market prices of each stock for the three-month period ending on the day before such announcement date.  The TSR of the Peer Group Company subject to the Signed Acquisition shall then be equal to its Partial Period TSR multiplied by the Average Change Factor (as defined below).  The “Average Change Factor” shall be a fraction, the numerator of which is the average of the TSRs of all Peer Group Companies that are not subject to a Signed Acquisition, and the denominator of which is the average of the Partial Period TSRs of those Peer Group Companies.  If a Signed Acquisition of a Peer Group Company is terminated (other than in connection with the execution of another Signed Acquisition) before the end of the Award Period, then the above modification to the calculation of TSR for that Peer Group Company shall not apply, and the TSR for that Peer Group Company shall be calculated as provided in Section 2.4, except that if the announcement of the termination of the Signed Acquisition occurs during the last three months of the Award Period, for purposes of determining the final dollar value under clause (c) of Section 2.4, the three-month period for which closing market prices are averaged shall be shortened to exclude any trading days preceding the announcement of the termination of the Signed Acquisition.

3.Strategic Performance Condition.  Subject to possible reduction under Section 4, the number of Strategic Performance Shares to be issued or otherwise delivered to Recipient shall be determined by multiplying the Strategic Payout Factor by the Strategic Target Share Amount.  The “Strategic Payout Factor” shall be a percentage between 0% and 200% determined by the Committee after the Award Period based on the Committee’s assessment of the extent to which the Company has achieved the following goals during the Award Period:

[applicable goals]

The Strategic Payout Factor shall be the same percentage for Recipient and all other recipients of similar awards for the Award Period.  Although each goal category set forth above is shown as having a Goal Weight, such Goal Weights may be changed by the Committee at any time in its sole discretion.  In determining the Strategic Payout Factor, the Committee in its discretion generally will assign a percentage of 100% for satisfactory achievement of all goals, a higher percentage for exceeding expectations and a lower percentage if goals are not achieved.

4.Employment Condition.

4.1In order to receive the full number of Performance Shares determined under Section 2 or Section 3, Recipient must be employed by the Company on the last day of the Award Period.

4.2If Recipient’s employment by the Company is terminated at any time prior to the end of the Award Period because of death, physical disability (within the meaning of Section 22(e)(3) of the Code), or Retirement (unless such Retirement results from a termination of Recipient’s employment by the Company for Cause), Recipient shall be entitled to receive pro-rated awards.  The number of each type of Performance Shares to be issued or otherwise delivered as a pro-rated award shall be determined by multiplying the number of Performance Shares determined under Section 2 or Section 3 by a fraction, the numerator of which is the number of days Recipient was employed by the Company during the Award Period and the denominator of which is the number of days in the Award Period.

4.3If Recipient’s employment by the Company is terminated at any time prior to the end of the Award Period and Section 4.2 does not apply to such termination, Recipient shall not be entitled to receive any Performance Shares.

4.4“Retirement” shall mean termination of employment after Recipient is (a) age 62 with at least five years of service as an employee of the Company, or (b) age 60 with age plus years of service (including fractions) as an employee of the Company totaling at least 70.

4.5“Cause” shall mean (a) the willful and continued failure by Recipient to perform substantially Recipient’s assigned duties with the Company (other than any such failure resulting from incapacity due to physical or mental illness) after a demand for substantial performance is delivered to Recipient by the Company which specifically identifies the manner in which Recipient has not substantially performed such duties, (b) willful commission by Recipient of an act of fraud or dishonesty resulting in economic or financial injury to the Company, (c) willful misconduct by Recipient that substantially impairs the Company’s business or reputation, or (d) willful gross negligence by Recipient in the performance of his or her duties.

5.Dividend Equivalent Cash Awards.  The amount of each type of Dividend Equivalent Cash Award shall be determined by multiplying the number of Performance Shares deliverable to Recipient as determined under Sections 2 and 4 or under Sections 3 and 4, as applicable, by the total amount of dividends paid per share of the Company’s Common Stock for which the dividend record date occurred after the beginning of the Award Period and before the date of delivery of the Performance Shares.

6.Certification and Payment.  At the regularly scheduled meeting of the Committee held in February of the year immediately following the final year of the Award Period (the “Certification Meeting”), the Committee shall determine the Strategic Payout Factor and certify in writing (which may consist of approved minutes of the Certification Meeting) the number of Strategic Performance Shares deliverable to Recipient and the amount of the Strategic Dividend Equivalent Cash Award payable to Recipient.  Prior to the Certification Meeting, the Company shall calculate the number of TSR Performance Shares deliverable and the amount of the TSR Dividend Equivalent Cash Award payable to Recipient, and shall submit these calculations to the Committee.  At or prior to the Certification Meeting, the Committee shall certify in writing (which may consist of approved minutes of the Certification Meeting) the levels of TSR attained by the Company and the Peer Group Companies, the number of TSR Performance Shares deliverable to Recipient and the amount of the TSR Dividend Equivalent Cash Award payable to Recipient.  Subject to applicable tax withholding, the amounts so certified shall be delivered or paid (as applicable) on a date (the “Payment Date”) that is the later of March 1, 2013 or five business days following the Certification Meeting, and no amounts shall be delivered or paid prior to certification.  No fractional shares shall be delivered and the number of Performance Shares deliverable shall be rounded to the nearest whole share.  Notwithstanding the foregoing, if Recipient shall have made a valid election to defer receipt of Performance Shares or Dividend Equivalent Cash Awards pursuant to the terms of the Company’s Deferred Compensation Plan for Directors and Executives (the “DCP”), payment of the award shall be made in accordance with that election.

7.Tax Withholding.  Recipient acknowledges that, on the Payment Date when the Performance Shares are issued or otherwise delivered to Recipient, the Value (as defined below) on that date of the Performance Shares (as well as the amount of the Dividend Equivalent Cash Awards) will be treated as ordinary compensation income for federal and state income and FICA tax purposes, and that the Company will be required to withhold taxes on these income amounts.  To satisfy the required withholding amount, the Company shall first withhold all or part of the Dividend Equivalent Cash Awards, and if that is insufficient, the Company shall withhold the number of Performance Shares having a Value equal to the remaining withholding amount.  For purposes of this Section 7, the “Value” of a Performance Share shall be equal to the closing market price for Company Common Stock on the last trading day preceding the Payment Date.  Notwithstanding the foregoing, Recipient may elect not to have Performance Shares withheld to cover taxes by giving notice to the Company in writing prior to the Payment Date, in which case the Performance Shares shall be issued or acquired in the Recipient’s name on the Payment Date thereby triggering the tax consequences, but the Company shall retain the certificate for the Performance Shares as security until Recipient shall have paid to the Company in cash any required tax withholding not covered by withholding of the Dividend Equivalent Cash Awards.

8.Change in Control.

8.1If a Change in Control (as defined below) occurs before the end of the Award Period, the Company shall, within 5 business days thereafter and subject to applicable tax withholding as provided for in Section 7, issue or otherwise deliver to Recipient a number of Performance Shares determined by multiplying the CIC Share Amount (as defined below) by a fraction, the numerator of which is the number of days in the period starting on the first day of the Award Period and ending on the date of the Change of Control and the denominator of which is the number of days in the Award Period.  At the same time, the Company shall pay to Recipient a Dividend Equivalent Cash Award based on such number of Performance Shares.  The “CIC Share Amount” shall equal 100% of the Strategic Target Share Amount plus an amount equal to the CIC TSR Payout Factor (as defined below) multiplied by the TSR Target Share Amount.  The “CIC TSR Payout Factor” shall be determined in the same manner as the TSR Payout Factor is determined under Section 2 of this Agreement, except that the final dollar value under clause (c) of Section 2.4 for the Company and each Peer Group Company shall be determined based on the average of the closing market prices of each stock for the three-month period ending on the date of the Change of Control; provided, however, that the CIC TSR Payout Factor shall be 0% if the Company’s TSR as computed for this purpose is less than 0%.  Amounts delivered or paid under this Section 8 shall be in satisfaction of any and all obligations of the Company to issue or otherwise deliver Performance Shares or pay Dividend Equivalent Cash Awards under this Agreement.

8.2For purposes of this Agreement, a “Change in Control” of the Company shall mean the occurrence of any of the following events:

(a)The consummation of:

(1)any consolidation, merger or plan of share exchange involving the Company (a “Merger”) as a result of which the holders of outstanding securities of the Company ordinarily having the right to vote for the election of directors (“Voting Securities”) immediately prior to the Merger do not continue to hold at least 50% of the combined voting power of the outstanding Voting Securities of the surviving corporation or a parent corporation of the surviving corporation immediately after the Merger, disregarding any Voting Securities issued to or retained by such holders in respect of securities of any other party to the Merger; or

(2)any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, the assets of the Company;

(b)At any time during a period of two consecutive years, individuals who at the beginning of such period constituted the Board (“Incumbent Directors”) shall cease for any reason to constitute at least a majority thereof; provided, however, that the term “Incumbent Director” shall also include each new director elected during such two-year period whose nomination or election was approved by two-thirds of the Incumbent Directors then in office; or

(c)Any person (as such term is used in Section 14(d) of the Securities Exchange Act of 1934, other than the Company or any employee benefit plan sponsored by the Company) shall, as a result of a tender or exchange offer, open market purchases or privately negotiated purchases from anyone other than the Company, have become the beneficial owner (within the meaning of Rule 13d-3 under the Securities Exchange Act of 1934), directly or indirectly, of Voting Securities representing twenty percent (20%) or more of the combined voting power of the then outstanding Voting Securities.

9.Changes in Capital Structure.

9.1If the outstanding Common Stock of the Company is hereafter increased or decreased or changed into or exchanged for a different number or kind of shares or other securities of the Company by reason of any stock split, combination of shares or dividend payable in shares, recapitalization or reclassification, appropriate adjustment shall be made by the Committee in the number and kind of shares subject to this Agreement so that the Recipient’s proportionate interest before and after the occurrence of the event is maintained.

9.2If the outstanding Common Stock of the Company is hereafter converted into or exchanged for all of the outstanding Common Stock of a corporation (the “Parent Successor”) as part of a transaction (the “Transaction”) in which the Company becomes a wholly-owned subsidiary of Parent Successor, then (a) the obligations under this Agreement shall be assumed by Parent Successor and references in this Agreement to the Company shall thereafter generally be deemed to refer to Parent Successor, (b) Common Stock of Parent Successor shall be issued in lieu of Common Stock of the Company under this Agreement, (c) the performance measured pursuant to Sections 2 and 3 of this Agreement shall be the continuous performance of the Company prior to the Transaction and Parent Successor after the Transaction, (d) employment by the Company for purposes of Section 4 of this Agreement shall include employment by either the Company or Parent Successor, and (e) the Dividend Equivalent Cash Awards under Section 5 of this Agreement shall be based on dividends paid on the Common Stock of the Company prior to the Transaction and Parent Successor after the Transaction.

10.Recoupment On Misconduct Affecting TSR.

10.1If at any time before a Change in Control and within three years after the Payment Date, the Committee determines that Recipient engaged in any Misconduct (as defined below) during the Award Period that contributed to an obligation to restate the Company’s financial statements for any quarter or year in the Award Period or that otherwise has had (or will have when publicly disclosed) an adverse impact on the Company’s common stock price, Recipient shall repay to the Company the Excess LTIP Compensation (as defined below).  The term “Excess LTIP Compensation” means the excess of (a) the number of TSR Performance Shares and the amount of the TSR Dividend Equivalent Cash Award as originally calculated and certified under Section 6 of this Agreement, over (b) the number of TSR Performance Shares and the amount of the TSR Dividend Equivalent Cash Award as recalculated assuming that the average of the closing market prices of the Company’s common stock for the period from October 1, 2012 to December 31, 2012 was an amount determined appropriate by the Committee in its discretion to reflect what the Company’s common stock price would have been if the restatement had occurred or other Misconduct had been disclosed prior to October 1, 2012.  Excess LTIP Compensation shall not include any Strategic Performance Shares or any portion of the Strategic Dividend Equivalent Cash Award.  The Committee may, in its sole discretion, reduce the amount of Excess LTIP Compensation to be repaid by Recipient to take into account the tax consequences of such repayment or any other factors.  If any TSR Performance Shares included in the Excess LTIP Compensation are sold by Recipient prior to the Company’s demand for repayment (including any shares withheld for taxes under Section 7 of this Agreement), Recipient shall repay to the Company 100% of the proceeds of such sale or sales.  The return of Excess LTIP Compensation is in addition to and separate from any other relief available to the Company due to Recipient’s Misconduct.

10.2“Misconduct” shall mean (a) willful commission by Recipient of an act of fraud or dishonesty resulting in economic or financial injury to the Company, (b) willful misconduct by Recipient that substantially impairs the Company’s business or reputation, or (c) willful gross negligence by Recipient in the performance of his or her duties.

10.3If any portion of the TSR Performance Shares or the TSR Dividend Equivalent Cash Award was deferred under the DCP, the Excess LTIP Compensation shall first be recovered by canceling all or a portion of the amounts so deferred under the DCP and any dividends or other earnings credited under the DCP with respect to such cancelled amounts.  The Company may seek direct repayment from Recipient of any Excess LTIP Compensation not so recovered and may, to the extent permitted by applicable law, offset such Excess LTIP Compensation against any compensation or other amounts owed by the Company to Recipient.  In particular, Excess LTIP Compensation may be recovered by offset against the after-tax proceeds of deferred compensation payouts under the DCP, the Company’s Executive Supplemental Retirement Income Plan or the Company’s Supplemental Executive Retirement Plan at the times such deferred compensation payouts occur under the terms of those plans.  Excess LTIP Compensation that remains unpaid for more than 60 days after demand by the Company shall accrue interest at the rate used from time to time for crediting interest under the DCP.

11.Approvals.  The issuance by the Company of authorized and unissued shares or reacquired shares under this Agreement is subject to the approval of the Oregon Public Utility Commission and the Washington Utilities and Transportation Commission, but no such approvals shall be required for the purchase of shares on the open market for delivery to Recipient in satisfaction of its obligations under this Agreement.  The obligations of the Company under this Agreement are otherwise subject to the approval of state and federal authorities or agencies with jurisdiction in the matter.  The Company will use its best efforts to take steps required by state or federal law or applicable regulations, including rules and regulations of the Securities and Exchange Commission and any stock exchange on which the Company’s shares may then be listed, in connection with the award under this Agreement.  The foregoing notwithstanding, the Company shall not be obligated to issue or deliver Common Stock under this Agreement if such issuance or delivery would violate applicable state or federal law.

12.No Right to Employment.  Nothing contained in this Agreement shall confer upon Recipient any right to be employed by the Company or to continue to provide services to the Company or to interfere in any way with the right of the Company to terminate Recipient’s services at any time for any reason, with or without cause.

13.Miscellaneous.

13.1Entire Agreement; Amendment.  This Agreement constitutes the entire agreement of the parties with regard to the subjects hereof and may be amended only by written agreement between the Company and Recipient.

13.2Notices.  Any notice required or permitted under this Agreement shall be in writing and shall be deemed sufficient when delivered personally to the party to whom it is addressed or when deposited into the United States Mail as registered or certified mail, return receipt requested, postage prepaid, addressed to the Company, Attention:  Corporate Secretary, at its principal executive offices or to Recipient at the address of Recipient in the Company’s records, or at such other address as such party may designate by ten (10) days’ advance written notice to the other party.

13.3Assignment; Rights and Benefits.  Recipient shall not assign this Agreement or any rights hereunder to any other party or parties without the prior written consent of the Company.  The rights and benefits of this Agreement shall inure to the benefit of and be enforceable by the Company’s successors and assigns and, subject to the foregoing restriction on assignment, be binding upon Recipient’s heirs, executors, administrators, successors and assigns.

13.4Further Action.  The parties agree to execute such further instruments and to take such further action as may reasonably be necessary to carry out the intent of this Agreement.

13.5Applicable Law; Attorneys’ Fees.  The terms and conditions of this Agreement shall be governed by the laws of the State of Oregon.  In the event either party institutes litigation hereunder, the prevailing party shall be entitled to reasonable attorneys’ fees to be set by the trial court and, upon any appeal, the appellate court.

13.6Counterparts.  This Agreement may be executed in two or more counterparts, each of which shall be deemed an original.

IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the day and year first above written.

NORTHWEST NATURAL GAS COMPANY

By           

Title           

RECIPIENT

EX-10.U

LONG TERM INCENTIVE AWARD AGREEMENT

This Agreement is entered into as of  February 23, 2011, between Northwest Natural Gas Company, an Oregon corporation (the “Company”), and ____________ (“Recipient”).

On February 23, 2011, the Organization and Executive Compensation Committee (the “Committee”) of the Company’s Board of Directors (the “Board”) authorized an objectively-determinable performance-based award (the “TSR Award”) to Recipient pursuant to Section 8 of the Company’s Long Term Incentive Plan (the “Plan”) and a subjective performance-based award (the “Strategic Award”) to Recipient pursuant to Section 6 of the Plan.  Compensation paid pursuant to the TSR Award is intended to qualify as performance-based compensation under Section 162(m) of the Internal Revenue Code of 1986 (the “Code”), while compensation paid pursuant to the Strategic Award will not so qualify.  Recipient desires to accept the awards subject to the terms and conditions of this Agreement.

NOW, THEREFORE, the parties agree as follows:

1.Awards.  Recipient’s “Target Share Amount” for purposes of this Agreement is ________ shares.

1.1TSR Award.  Subject to the terms and conditions of this Agreement, the Company shall issue or otherwise deliver to the Recipient the number of shares of Common Stock of the Company (the “TSR Performance Shares”) determined under this Agreement based on (a) the performance of the Company’s Common Stock relative to a peer group of companies during the three-year period from January 1, 2011 to December 31, 2013 (the “Award Period”) as described in Section 2 and (b) Recipient’s continued employment during the Award Period as described in Section 4.  If the Company issues or otherwise delivers TSR Performance Shares to Recipient, the Company shall also pay to Recipient the amount of cash determined under Section 5 (the “TSR Dividend Equivalent Cash Award”).  Recipient’s “TSR Target Share Amount” for purposes of this Agreement is 75% of the Target Share Amount.

1.2Strategic Award.  Subject to the terms and conditions of this Agreement, the Company shall issue or otherwise deliver to the Recipient the number of shares of Common Stock of the Company (the “Strategic Performance Shares” and, together with the TSR Performance Shares, the “Performance Shares”) determined under this Agreement based on (a) the Company’s performance against milestones during the Award Period as determined by the Committee under Section 3 and (b) Recipient’s continued employment during the Award Period as described in Section 4.  If the Company issues or otherwise delivers Strategic Performance Shares to Recipient, the Company shall also pay to Recipient the amount of cash determined under Section 5 (the “Strategic Dividend Equivalent Cash Award” and, together with the TSR Dividend Equivalent Cash Award, the “Dividend Equivalent Cash Awards”).  Recipient’s “Strategic Target Share Amount” for purposes of this Agreement is 25% of the Target Share Amount.

2.TSR Performance Condition.

2.1Subject to possible reduction under Section 4, the number of TSR Performance Shares to be issued or otherwise delivered to Recipient shall be determined by multiplying the TSR Payout Factor (as defined below) by the TSR Target Share Amount;

2.2provided, however, that no TSR Performance Shares shall be issued or otherwise delivered if the Company’s TSR (as defined below) for the Award Period is less than 0%.

2.3To determine the “TSR Payout Factor,” the ten Peer Group Companies (as defined below) shall be ranked based on their respective TSR’s from highest to lowest, with the Peer Group Company with the highest TSR having a TSR Ranking of “1” and the Peer Group Company with the lowest TSR having a TSR Ranking of “10.”  If the Company’s TSR is equal to the TSR of any other Peer Group Company, the TSR Payout Factor will be the percentage in the following table corresponding to the TSR Ranking of that Peer Group Company.

TSR Ranking	TSR Payout Factor
10	0%
9	0%
8	25%
7	25%
6	50%
5	75%
4	100%
3	125%
2	150%
1	200%

If the Company’s TSR is higher than the TSRs of all Peer Group Companies, the TSR Payout Factor will be 200%.  If the Company’s TSR is not at least as high as the TSR of the Peer Group Company with the TSR Ranking of “8,” the TSR Payout Factor will be 0%.  If the Company’s TSR is between the TSRs of any two Peer Group Companies with TSR Rankings between “1” and “8,” the TSR Payout Factor shall be interpolated as follows.  The excess of the Company’s TSR over the TSR of the lower Peer Group Company shall be divided by the excess of the TSR of the higher Peer Group Company over the TSR of the lower Peer Group Company.  The resulting fraction shall be multiplied by the difference between the percentages in the above table corresponding to the TSR Rankings of the two Peer Group Companies.  The product of that calculation shall be added to the percentage in the above table corresponding to the TSR Ranking of the lower Peer Group Company, and the resulting sum shall be the TSR Payout Factor.

2.4The “Peer Group Companies” are AGL Resources Inc., Atmos Energy Corporation, The Laclede Group, Inc., New Jersey Resources Corporation, Piedmont Natural Gas Company, Inc., Questar Corporation, South Jersey Industries, Inc., Southwest Gas Corporation, Vectren Corporation and W G L Holdings, Inc.  If prior to the end of the Award Period, the common stock of any Peer Group Company ceases to be publicly traded for any reason, then such company shall no longer be considered a Peer Group Company, and an alternate peer company shall become a Peer Group Company effective as of the start of the Award Period.  The alternate peer companies, and the order in which they will be added as Peer Group Companies, if necessary, are:  first, NiSource Inc.; second, National Fuel Gas Company; and third, Chesapeake Utilities Corporation.  If prior to the end of the Award Period, all of the above alternate peer companies have become Peer Group Companies and the common stock of yet another Peer Group Company ceases to be publicly traded for any reason so that there are

2.5only nine remaining Peer Group Companies, for purposes of Section 2.2 it shall be assumed that there is a hypothetical Peer Group Company with a TSR Ranking of “5”; provided, however, that if the Company’s TSR is between the TSRs of the Peer Group Companies with TSR Rankings of “4” and “6,” the TSR Payout Factor shall be interpolated between the payout percentages corresponding to the TSR Rankings of those two companies.  If yet another Peer Group Company ceases to be publicly traded for any reason so that there are only eight remaining Peer Group Companies, for purposes of Section 2.2 it shall be assumed that there are two hypothetical Peer Group Company with TSR Rankings of “5” and “6” and, if necessary, the TSR Payout Factor shall interpolated between the payout percentages corresponding to the Peer Group Companies with TSR Rankings of “4” and “7”.  Similarly, if additional Peer Group Companies cease to be publicly traded for any reason, additional hypothetical Peer Group Companies shall be assumed to exist with TSR Rankings of “4”, then “7”, then “3”, then “9”, and then “2”.

2.6The “TSR” for the Company and each Peer Group Company shall be calculated by (a) assuming that $100 is invested in the common stock of the company at a price equal to the average of the closing market prices of the stock for the period from October 1, 2010 to December 31, 2010, (b) assuming that for each dividend paid on the stock during the Award Period, the amount equal to the dividend paid on the assumed number of shares held is reinvested in additional shares at a price equal to the closing market price of the stock on trade date immediately preceding the ex-dividend date for the dividend, and (c) determining the final dollar value of the total assumed number of shares based on the average of the closing market prices of the stock for the period from October 1, 2013 to December 31, 2013.  The “TSR” shall then equal the amount determined by subtracting $100 from the foregoing final dollar value, dividing the result by 100 and expressing the resulting fraction as a percentage.

2.7If during the Award Period any Peer Group Company enters into an agreement pursuant to which all or substantially all of the stock or assets of the Peer Group Company will be acquired by a third party (a “Signed Acquisition”), and if the Signed Acquisition is not completed so that such company remains a Peer Group Company at the end of the Award Period, then the calculation of the TSR for that Peer Group Company shall be modified as provided in this Section 2.5.  A “Partial Period TSR” for each Peer Group Company shall be calculated in the same manner as TSR is calculated under Section 2.4, except that for this purpose the Award Period shall be deemed to have ended on the day before the date of announcement of the Signed Acquisition and the final dollar value under clause (c) of Section 2.4 for each Peer Group Company shall be determined based on the average of the closing market prices of each stock for the three-month period ending on the day before such announcement date.  The TSR of the Peer Group Company subject to the Signed Acquisition shall then be equal to its Partial Period TSR multiplied by the Average Change Factor (as defined below).  The “Average Change Factor” shall be a fraction, the numerator of which is the average of the TSRs of all Peer Group Companies that are not subject to a Signed Acquisition, and the denominator of which is the average of the Partial Period TSRs of those Peer Group Companies.  If a Signed Acquisition of a Peer Group Company is terminated (other than in connection with the execution of another Signed Acquisition) before the end of the Award Period, then the above modification to the calculation of TSR for that Peer Group Company shall not apply, and the TSR for that Peer Group Company shall be calculated as provided in Section 2.4, except that if the announcement of the termination of the Signed Acquisition occurs during the last three months of the Award Period, for purposes of determining the final dollar value under clause (c)

2.8of Section 2.4, the three-month period for which closing market prices are averaged shall be shortened to exclude any trading days preceding the announcement of the termination of the Signed Acquisition.

3.Strategic Performance Condition.  Subject to possible reduction under Section 4, the number of Strategic Performance Shares to be issued or otherwise delivered to Recipient shall be determined by multiplying the Strategic Payout Factor by the Strategic Target Share Amount.  The “Strategic Payout Factor” shall be a percentage between 0% and 200% determined by the Committee after the Award Period based on the Committee’s assessment of the extent to which the Company has achieved the following goals during the Award Period:

[applicable goals]

The Strategic Payout Factor shall be the same percentage for Recipient and all other recipients of similar awards for the Award Period.  Although each goal category set forth above is shown as having a Goal Weight, such Goal Weights may be changed by the Committee at any time in its sole discretion.  In determining the Strategic Payout Factor, the Committee in its discretion generally will assign a percentage of 100% for satisfactory achievement of all goals, a higher percentage for exceeding expectations and a lower percentage if goals are not achieved.

4.Employment Condition.

4.1In order to receive the full number of Performance Shares determined under Section 2 or Section 3, Recipient must be employed by the Company on the last day of the Award Period.

4.2If Recipient’s employment by the Company is terminated at any time prior to the end of the Award Period because of death, physical disability (within the meaning of Section 22(e)(3) of the Code), or Retirement (unless such Retirement results from a termination of Recipient’s employment by the Company for Cause), Recipient shall be entitled to receive pro-rated awards.  The number of each type of Performance Shares to be issued or otherwise delivered as a pro-rated award shall be determined by multiplying the number of Performance Shares determined under Section 2 or Section 3 by a fraction, the numerator of which is the number of days Recipient was employed by the Company during the Award Period and the denominator of which is the number of days in the Award Period.

4.3If Recipient’s employment by the Company is terminated at any time prior to the end of the Award Period and Section 4.2 does not apply to such termination, Recipient shall not be entitled to receive any Performance Shares.

4.4“Retirement” shall mean termination of employment after Recipient is (a) age 62 with at least five years of service as an employee of the Company, or (b) age 60 with age plus years of service (including fractions) as an employee of the Company totaling at least 70.

4.5“Cause” shall mean (a) the willful and continued failure by Recipient to perform substantially Recipient’s assigned duties with the Company (other than any such failure resulting from incapacity due to physical or mental illness) after a demand for substantial performance is delivered to Recipient by the Company which specifically identifies the manner in which Recipient has not substantially performed such duties, (b) willful commission by Recipient of an act of fraud or dishonesty resulting in economic or financial injury to the Company, (c) willful misconduct by Recipient that substantially impairs the Company’s business or reputation, or (d) willful gross negligence by Recipient in the performance of his or her duties.

5.Dividend Equivalent Cash Awards.  The amount of each type of Dividend Equivalent Cash Award shall be determined by multiplying the number of Performance Shares deliverable to Recipient as determined under Sections 2 and 4 or under Sections 3 and 4, as applicable, by the total amount of dividends paid per share of the Company’s Common Stock for which the dividend record date occurred after the beginning of the Award Period and before the date of delivery of the Performance Shares.

6.Certification and Payment.  At the regularly scheduled meeting of the Committee held in February of the year immediately following the final year of the Award Period (the “Certification Meeting”), the Committee shall determine the Strategic Payout Factor and certify in writing (which may consist of approved minutes of the Certification Meeting) the number of Strategic Performance Shares deliverable to Recipient and the amount of the Strategic Dividend Equivalent Cash Award payable to Recipient.  Prior to the Certification Meeting, the Company shall calculate the number of TSR Performance Shares deliverable and the amount of the TSR Dividend Equivalent Cash Award payable to Recipient, and shall submit these calculations to the Committee.  At or prior to the Certification Meeting, the Committee shall certify in writing (which may consist of approved minutes of the Certification Meeting) the levels of TSR attained by the Company and the Peer Group Companies, the number of TSR Performance Shares deliverable to Recipient and the amount of the TSR Dividend Equivalent Cash Award payable to Recipient.  Subject to applicable tax withholding, the amounts so certified shall be delivered or paid (as applicable) on a date (the “Payment Date”) that is the later of March 1, 2014 or five business days following the Certification Meeting, and no amounts shall be delivered or paid prior to certification.  No fractional shares shall be delivered and the number of Performance Shares deliverable shall be rounded to the nearest whole share.  Notwithstanding the foregoing, if Recipient shall have made a valid election to defer receipt of Performance Shares or Dividend Equivalent Cash Awards pursuant to the terms of the Company’s Deferred Compensation Plan for Directors and Executives (the “DCP”), payment of the award shall be made in accordance with that election.

7.Tax Withholding.  Recipient acknowledges that, on the Payment Date when the Performance Shares are issued or otherwise delivered to Recipient, the Value (as defined below) on that date of the Performance Shares (as well as the amount of the Dividend Equivalent Cash Awards) will be treated as ordinary compensation income for federal and state income and FICA tax purposes, and that the Company will be required to withhold taxes on these income amounts.  To satisfy the required withholding amount, the Company shall first withhold all or part of the Dividend Equivalent Cash Awards, and if that is insufficient, the Company shall withhold the number of Performance Shares having a Value equal to the remaining withholding amount.  For purposes of this Section 7, the “Value” of a Performance Share shall be equal to the closing market price for Company Common Stock on the last trading day preceding the Payment Date.  Notwithstanding the foregoing, Recipient may elect not to have Performance Shares withheld to cover taxes by giving notice to the Company in writing prior to the Payment Date, in which case the Performance Shares shall be issued or acquired in the Recipient’s name on the Payment Date thereby triggering the tax consequences, but the Company shall retain the certificate for the Performance Shares as security until Recipient shall have paid to the Company in cash any required tax withholding not covered by withholding of the Dividend Equivalent Cash Awards.

8.Change in Control.

8.1If a Change in Control (as defined below) occurs before the end of the Award Period, the Company shall, within 5 business days thereafter and subject to applicable tax withholding as provided for in Section 7, issue or otherwise deliver to Recipient a number of Performance Shares determined by multiplying the CIC Share Amount (as defined below) by a fraction, the numerator of which is the number of days in the period starting on the first day of the Award Period and ending on the date of the Change of Control and the denominator of which is the number of days in the Award Period.  At the same time, the Company shall pay to Recipient a Dividend Equivalent Cash Award based on such number of Performance Shares.  The “CIC Share Amount” shall equal 100% of the Strategic Target Share Amount plus an amount equal to the CIC TSR Payout Factor (as defined below) multiplied by the TSR Target Share Amount.  The “CIC TSR Payout Factor” shall be determined in the same manner as the TSR Payout Factor is determined under Section 2 of this Agreement, except that the final dollar value under clause (c) of Section 2.4 for the Company and each Peer Group Company shall be determined based on the average of the closing market prices of each stock for the three-month period ending on the date of the Change of Control; provided, however, that the CIC TSR Payout Factor shall be 0% if the Company’s TSR as computed for this purpose is less than 0%.  Amounts delivered or paid under this Section 8 shall be in satisfaction of any and all obligations of the Company to issue or otherwise deliver Performance Shares or pay Dividend Equivalent Cash Awards under this Agreement.

8.2For purposes of this Agreement, a “Change in Control” of the Company shall mean the occurrence of any of the following events:

(a)The consummation of:

(1)any consolidation, merger or plan of share exchange involving the Company (a “Merger”) as a result of which the holders of outstanding securities of the Company ordinarily having the right to vote for the election of directors (“Voting Securities”) immediately prior to the Merger do not continue to hold at least 50% of the combined voting power of the outstanding Voting Securities of the surviving corporation or a parent corporation of the surviving corporation immediately after the Merger, disregarding any Voting Securities issued to or retained by such holders in respect of securities of any other party to the Merger; or

(2)any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, the assets of the Company;

(b)At any time during a period of two consecutive years, individuals who at the beginning of such period constituted the Board (“Incumbent Directors”) shall cease for any reason to constitute at least a majority thereof; provided, however, that the term “Incumbent Director” shall also include each new director elected during such two-year period whose nomination or election was approved by two-thirds of the Incumbent Directors then in office; or

(c)Any person (as such term is used in Section 14(d) of the Securities Exchange Act of 1934, other than the Company or any employee benefit plan sponsored by the Company) shall, as a result of a tender or exchange offer, open market purchases or privately negotiated purchases from anyone other than the Company, have become the beneficial owner (within the meaning of Rule 13d-3 under the Securities Exchange Act of 1934), directly or indirectly, of Voting Securities representing twenty percent (20%) or more of the combined voting power of the then outstanding Voting Securities.

9.Changes in Capital Structure.

9.1If the outstanding Common Stock of the Company is hereafter increased or decreased or changed into or exchanged for a different number or kind of shares or other securities of the Company by reason of any stock split, combination of shares or dividend payable in shares, recapitalization or reclassification, appropriate adjustment shall be made by the Committee in the number and kind of shares subject to this Agreement so that the Recipient’s proportionate interest before and after the occurrence of the event is maintained.

9.2If the outstanding Common Stock of the Company is hereafter converted into or exchanged for all of the outstanding Common Stock of a corporation (the “Parent Successor”) as part of a transaction (the “Transaction”) in which the Company becomes a wholly-owned subsidiary of Parent Successor, then (a) the obligations under this Agreement shall be assumed by Parent Successor and references in this Agreement to the Company shall thereafter generally be deemed to refer to Parent Successor, (b) Common Stock of Parent Successor shall be issued in lieu of Common Stock of the Company under this Agreement, (c) the performance measured pursuant to Sections 2 and 3 of this Agreement shall be the continuous performance of the Company prior to the Transaction and Parent Successor after the Transaction, (d) employment by the Company for purposes of Section 4 of this Agreement shall include employment by either the Company or Parent Successor, and (e) the Dividend Equivalent Cash Awards under Section 5 of this Agreement shall be based on dividends paid on the Common Stock of the Company prior to the Transaction and Parent Successor after the Transaction.

10.Recoupment On Misconduct Affecting TSR.

10.1If at any time before a Change in Control and within three years after the Payment Date, the Committee determines that Recipient engaged in any Misconduct (as defined below) during the Award Period that contributed to an obligation to restate the Company’s financial statements for any quarter or year in the Award Period or that otherwise has had (or will have when publicly disclosed) an adverse impact on the Company’s common stock price, Recipient shall repay to the Company the Excess LTIP Compensation (as defined below).  The term “Excess LTIP Compensation” means the excess of (a) the number of TSR Performance Shares and the amount of the TSR Dividend Equivalent Cash Award as originally calculated and certified under Section 6 of this Agreement, over (b) the number of TSR Performance Shares and the amount of the TSR Dividend Equivalent Cash Award as recalculated assuming that the average of the closing market prices of the Company’s common stock for the period from October 1, 2013 to December 31, 2013 was an amount determined appropriate by the Committee in its discretion to reflect what the Company’s common stock price would have been if the restatement had occurred or other Misconduct had been disclosed prior to October 1, 2013.  Excess LTIP Compensation shall not include any Strategic Performance Shares or any portion of the Strategic Dividend Equivalent Cash Award.  The Committee may, in its sole discretion, reduce the amount of Excess LTIP Compensation to be repaid by Recipient to take into account the tax consequences of such repayment or any other factors.  If any TSR Performance Shares included in the Excess LTIP Compensation are sold by Recipient prior to the Company’s demand for repayment (including any shares withheld for taxes under Section 7 of this Agreement), Recipient shall repay to the Company 100% of the proceeds of such sale or sales.  The return of Excess LTIP Compensation is in addition to and separate from any other relief available to the Company due to Recipient’s Misconduct.

10.2“Misconduct” shall mean (a) willful commission by Recipient of an act of fraud or dishonesty resulting in economic or financial injury to the Company, (b) willful misconduct by Recipient that substantially impairs the Company’s business or reputation, or (c) willful gross negligence by Recipient in the performance of his or her duties.

10.3If any portion of the TSR Performance Shares or the TSR Dividend Equivalent Cash Award was deferred under the DCP, the Excess LTIP Compensation shall first be recovered by canceling all or a portion of the amounts so deferred under the DCP and any dividends or other earnings credited under the DCP with respect to such cancelled amounts.  The Company may seek direct repayment from Recipient of any Excess LTIP Compensation not so recovered and may, to the extent permitted by applicable law, offset such Excess LTIP Compensation against any compensation or other amounts owed by the Company to Recipient.  In particular, Excess LTIP Compensation may be recovered by offset against the after-tax proceeds of deferred compensation payouts under the DCP, the Company’s Executive Supplemental Retirement Income Plan or the Company’s Supplemental Executive Retirement Plan at the times such deferred compensation payouts occur under the terms of those plans.  Excess LTIP Compensation that remains unpaid for more than 60 days after demand by the Company shall accrue interest at the rate used from time to time for crediting interest under the DCP.

11.Approvals.  The issuance by the Company of authorized and unissued shares or reacquired shares under this Agreement is subject to the approval of the Oregon Public Utility Commission and the Washington Utilities and Transportation Commission, but no such approvals shall be required for the purchase of shares on the open market for delivery to Recipient in satisfaction of its obligations under this Agreement.  The obligations of the Company under this Agreement are otherwise subject to the approval of state and federal authorities or agencies with jurisdiction in the matter.  The Company will use its best efforts to take steps required by state or federal law or applicable regulations, including rules and regulations of the Securities and Exchange Commission and any stock exchange on which the Company’s shares may then be listed, in connection with the award under this Agreement.  The foregoing notwithstanding, the Company shall not be obligated to issue or deliver Common Stock under this Agreement if such issuance or delivery would violate applicable state or federal law.

12.No Right to Employment.  Nothing contained in this Agreement shall confer upon Recipient any right to be employed by the Company or to continue to provide services to the Company or to interfere in any way with the right of the Company to terminate Recipient’s services at any time for any reason, with or without cause.

13.Miscellaneous.

13.1Entire Agreement; Amendment.  This Agreement constitutes the entire agreement of the parties with regard to the subjects hereof and may be amended only by written agreement between the Company and Recipient.

13.2Notices.  Any notice required or permitted under this Agreement shall be in writing and shall be deemed sufficient when delivered personally to the party to whom it is addressed or when deposited into the United States Mail as registered or certified mail, return receipt requested, postage prepaid, addressed to the Company, Attention:  Corporate Secretary, at its principal executive offices or to Recipient at the address of Recipient in the Company’s records, or at such other address as such party may designate by ten (10) days’ advance written notice to the other party.

13.3Assignment; Rights and Benefits.  Recipient shall not assign this Agreement or any rights hereunder to any other party or parties without the prior written consent of the Company.  The rights and benefits of this Agreement shall inure to the benefit of and be enforceable by the Company’s successors and assigns and, subject to the foregoing restriction on assignment, be binding upon Recipient’s heirs, executors, administrators, successors and assigns.

13.4Further Action.  The parties agree to execute such further instruments and to take such further action as may reasonably be necessary to carry out the intent of this Agreement.

13.5Applicable Law; Attorneys’ Fees.  The terms and conditions of this Agreement shall be governed by the laws of the State of Oregon.  In the event either party institutes litigation hereunder, the prevailing party shall be entitled to reasonable attorneys’ fees to be set by the trial court and, upon any appeal, the appellate court.

13.6Counterparts.  This Agreement may be executed in two or more counterparts, each of which shall be deemed an original.

IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the day and year first above written.

NORTHWEST NATURAL GAS COMPANY

By           

Title           

RECIPIENT

EX-10.V

LONG TERM INCENTIVE AWARD AGREEMENT

This Agreement is entered into as of February __, 2012, between Northwest Natural Gas Company, an Oregon corporation (the “Company”), and ____________ (“Recipient”).

On February __, 2012, the Organization and Executive Compensation Committee (the “Committee”) of the Company’s Board of Directors (the “Board”) authorized an objectively-determinable performance-based award (the “TSR Award”) to Recipient pursuant to Section 8 of the Company’s Long Term Incentive Plan (the “Plan”) and a subjective performance-based award (the “Strategic Award”) to Recipient pursuant to Section 6 of the Plan.  Compensation paid pursuant to the TSR Award is intended to qualify as performance-based compensation under Section 162(m) of the Internal Revenue Code of 1986 (the “Code”), while compensation paid pursuant to the Strategic Award will not so qualify.  Recipient desires to accept the awards subject to the terms and conditions of this Agreement.

NOW, THEREFORE, the parties agree as follows:

1.Awards.  Recipient’s “Target Share Amount” for purposes of this Agreement is ________ shares.

1.1TSR Award.  Subject to the terms and conditions of this Agreement, the Company shall issue or otherwise deliver to the Recipient the number of shares of Common Stock of the Company (the “TSR Performance Shares”) determined under this Agreement based on (a) the performance of the Company’s Common Stock relative to a peer group of companies during the three-year period from January 1, 2012 to December 31, 2014 (the “Award Period”) as described in Section 2 and (b) Recipient’s continued employment during the Award Period as described in Section 4.  If the Company issues or otherwise delivers TSR Performance Shares to Recipient, the Company shall also pay to Recipient the amount of cash determined under Section 5 (the “TSR Dividend Equivalent Cash Award”).  Recipient’s “TSR Target Share Amount” for purposes of this Agreement is 75% of the Target Share Amount.

1.2Strategic Award.  Subject to the terms and conditions of this Agreement, the Company shall issue or otherwise deliver to the Recipient the number of shares of Common Stock of the Company (the “Strategic Performance Shares” and, together with the TSR Performance Shares, the “Performance Shares”) determined under this Agreement based on (a) the Company’s performance against milestones during the Award Period as determined by the Committee under Section 3 and (b) Recipient’s continued employment during the Award Period as described in Section 4.  If the Company issues or otherwise delivers Strategic Performance Shares to Recipient, the Company shall also pay to Recipient the amount of cash determined under Section 5 (the “Strategic Dividend Equivalent Cash Award” and, together with the TSR Dividend Equivalent Cash Award, the “Dividend Equivalent Cash Awards”).  Recipient’s “Strategic Target Share Amount” for purposes of this Agreement is 25% of the Target Share Amount.

2.TSR Performance Condition.

2.1Subject to possible reduction under Section 4, the number of TSR Performance Shares to be issued or otherwise delivered to Recipient shall be determined by multiplying the TSR Payout Factor (as defined below) by the TSR Target Share Amount.

2.2The “TSR Payout Factor” shall be determined under the table below based on the TSR Percentile Rank (as defined below) of the Company; provided, however, that if the Company’s TSR (as defined below) is less than 0%, the actual TSR Payout Factor shall be equal to 75% of the TSR Payout Factor determined under the table below:

TSR Percentile Rank	TSR Payout Factor
less than 30%	0%
30%	25%
50%	100%
90% or more	200%

If the Company’s TSR Percentile Rank is between any two data points set forth in the first column of the above table, the TSR Payout Factor shall be interpolated as follows.  The excess of the Company’s TSR Percentile Rank over the TSR Percentile Rank of the lower data point shall be divided by the excess of the TSR Percentile Rank of the higher data point over the TSR Percentile Rank of the lower data point.  The resulting fraction shall be multiplied by the difference between the TSR Payout Factors in the above table corresponding to the two data points.  The product of that calculation shall be rounded to the nearest hundredth of a percentage point and then added to the TSR Payout Factor in the above table corresponding to the lower data point, and the resulting sum shall be the TSR Payout Factor.

2.3To determine the Company’s “TSR Percentile Rank,” the TSR of the Company and each of the Peer Group Companies (as defined below) shall be calculated, and the Peer Group Companies shall be ranked based on their respective TSR’s from lowest to highest.  If the Company’s TSR is equal to the TSR of any other Peer Group Company, the Company’s TSR Percentile Rank shall be equal to the number of Peer Group Companies with a lower TSR divided by the number that is one less than the total number of Peer Group Companies, with the resulting amount expressed as a percentage and rounded to the nearest tenth of a percentage point.  If the Company’s TSR is between the TSRs of any two Peer Group Companies, the TSR Percentile Ranks of those two Peer Group Companies shall be determined as set forth in the preceding sentence, and the Company’s TSR Percentile Rank shall be interpolated as follows.  The excess of the Company’s TSR over the TSR of the lower Peer Group Company shall be divided by the excess of the TSR of the higher Peer Group Company over the TSR of the lower Peer Group Company.  The resulting fraction shall be multiplied by the difference between the TSR Percentile Ranks of the two Peer Group Companies.  The product of that calculation shall be added to the TSR Percentile Rank of the lower Peer Group Company, and the resulting sum (rounded to the nearest tenth of a percentage point) shall be the Company’s TSR Percentile Rank.  The intent of this definition of TSR Percentile Rank is to produce the same result as calculated using the PERCENTRANK function in Microsoft Excel to determine the rank of the Company’s TSR within the array consisting of the TSRs of the Peer Group Companies.

2.4The “Peer Group Companies” consist of those companies that were components of the Dow Jones U.S. Gas Distribution Index on October 1, 2011 and that continue to be components of the Dow Jones U.S. Gas Distribution Index through December 31, 2014.  If the Dow Jones U.S. Gas Distribution Index ceases to be published prior to December 31, 2014, the Peer Group Companies shall consist of those companies that were components of the Dow Jones U.S. Gas Distribution Index on October 1, 2011 and that continued to have publicly-traded common stock through December 31, 2014.

2.5The “TSR” for the Company and each Peer Group Company shall be calculated by (a) assuming that $100 is invested in the common stock of the company at a price equal to the average of the closing market prices of the stock for the period from October 1, 2011 to December 31, 2011, (b) assuming that for each dividend paid on the stock during the Award Period, the amount equal to the dividend paid on the assumed number of shares held is reinvested in additional shares at a price equal to the closing market price of the stock on the ex-dividend date for the dividend, and (c) determining the final dollar value of the total assumed number of shares based on the average of the closing market prices of the stock for the period from October 1, 2014 to December 31, 2014.  The “TSR” shall then equal the amount determined by subtracting $100 from the foregoing final dollar value, dividing the result by 100 and expressing the resulting fraction as a percentage.

2.6If during the Award Period any Peer Group Company enters into an agreement pursuant to which all or substantially all of the stock or assets of the Peer Group Company will be acquired by a third party (a “Signed Acquisition”), and if the Signed Acquisition is not completed by the end of the Award Period, then that company shall not be a Peer Group Company.  If a Signed Acquisition of a Peer Group Company is terminated (other than in connection with the execution of another Signed Acquisition) before the end of the Award Period, then that company shall remain a Peer Group Company, and the TSR for that Peer Group Company shall be calculated as provided in Section 2.5, except that if the announcement of the termination of the Signed Acquisition occurs during the last three months of the Award Period, for purposes of determining the final dollar value under clause (c) of Section 2.5, the three-month period for which closing market prices are averaged shall be shortened to exclude any trading days preceding the announcement of the termination of the Signed Acquisition.

3.Strategic Performance Condition.  Subject to possible reduction under Section 4, the number of Strategic Performance Shares to be issued or otherwise delivered to Recipient shall be determined by multiplying the Strategic Payout Factor by the Strategic Target Share Amount.  The “Strategic Payout Factor” shall be a percentage between 0% and 200% determined by the Committee after the Award Period based on the Committee’s assessment of the extent to which the Company has achieved the following goals during the Award Period:

[applicable goals]

The Strategic Payout Factor shall be the same percentage for Recipient and all other recipients of similar awards for the Award Period.  Although each goal category set forth above is shown as having a Goal Weight, such Goal Weights may be changed by the Committee at any time in its sole discretion.  In determining the Strategic Payout Factor, the Committee in its discretion generally will assign a percentage of 100% for satisfactory achievement of all goals, a higher percentage for exceeding expectations and a lower percentage if goals are not achieved.

4.Employment Condition.

4.1In order to receive the full number of Performance Shares determined under Section 2 or Section 3, Recipient must be employed by the Company on the last day of the Award Period.

4.2If Recipient’s employment by the Company is terminated at any time prior to the end of the Award Period because of death, physical disability (within the meaning of Section 22(e)(3) of the Code), or Retirement (unless such Retirement results from a termination of Recipient’s employment by the Company for Cause), Recipient shall be entitled to receive pro-rated awards.  The number of each type of Performance Shares to be issued or otherwise delivered as a pro-rated award shall be determined by multiplying the number of Performance Shares determined under Section 2 or Section 3 by a fraction, the numerator of which is the number of days Recipient was employed by the Company during the Award Period and the denominator of which is the number of days in the Award Period.

4.3If Recipient’s employment by the Company is terminated at any time prior to the end of the Award Period and Section 4.2 does not apply to such termination, Recipient shall not be entitled to receive any Performance Shares.

4.4“Retirement” shall mean termination of employment after Recipient is (a) age 62 with at least five years of service as an employee of the Company, or (b) age 60 with age plus years of service (including fractions) as an employee of the Company totaling at least 70.

4.5“Cause” shall mean (a) the willful and continued failure by Recipient to perform substantially Recipient’s assigned duties with the Company (other than any such failure resulting from incapacity due to physical or mental illness) after a demand for substantial performance is delivered to Recipient by the Company which specifically identifies the manner in which Recipient has not substantially performed such duties, (b) willful commission by Recipient of an act of fraud or dishonesty resulting in economic or financial injury to the Company, (c) willful misconduct by Recipient that substantially impairs the Company’s business or reputation, or (d) willful gross negligence by Recipient in the performance of his or her duties.

5.Dividend Equivalent Cash Awards.  The amount of each type of Dividend Equivalent Cash Award shall be determined by multiplying the number of Performance Shares deliverable to Recipient as determined under Sections 2 and 4 or under Sections 3 and 4, as applicable, by the total amount of dividends paid per share of the Company’s Common Stock for which the dividend record date occurred after the beginning of the Award Period and before the date of delivery of the Performance Shares.

6.Certification and Payment.  At the regularly scheduled meeting of the Committee held in February of the year immediately following the final year of the Award Period (the “Certification Meeting”), the Committee shall determine the Strategic Payout Factor and certify in writing (which may consist of approved minutes of the Certification Meeting) the number of Strategic Performance Shares deliverable to Recipient and the amount of the Strategic Dividend Equivalent Cash Award payable to Recipient.  Prior to the Certification Meeting, the Company shall calculate the number of TSR Performance Shares deliverable and the amount of the TSR Dividend Equivalent Cash Award payable to Recipient, and shall submit these calculations to the Committee.  At or prior to the Certification Meeting, the Committee shall certify in writing (which may consist of approved minutes of the Certification Meeting) the levels of TSR attained by the Company and the Peer Group Companies, the number of TSR Performance Shares deliverable to Recipient and the amount of the TSR Dividend Equivalent Cash Award payable to Recipient.  Subject to applicable tax withholding, the amounts so certified shall be delivered or paid (as applicable) on a date (the “Payment Date”) that is the later of March 1, 2015 or five business days following the Certification Meeting, and no amounts shall be delivered or paid prior to certification.  No fractional shares shall be delivered and the number of Performance Shares deliverable shall be rounded to the nearest whole share.  Notwithstanding the foregoing, if Recipient shall have made a valid election to defer receipt of Performance Shares or Dividend Equivalent Cash Awards pursuant to the terms of the Company’s Deferred Compensation Plan for Directors and Executives (the “DCP”), payment of the award shall be made in accordance with that election.

7.Tax Withholding.  Recipient acknowledges that, on the Payment Date when the Performance Shares are issued or otherwise delivered to Recipient, the Value (as defined below) on that date of the Performance Shares (as well as the amount of the Dividend Equivalent Cash Awards) will be treated as ordinary compensation income for federal and state income and FICA tax purposes, and that the Company will be required to withhold taxes on these income amounts.  To satisfy the required withholding amount, the Company shall first withhold all or part of the Dividend Equivalent Cash Awards, and if that is insufficient, the Company shall withhold the number of Performance Shares having a Value equal to the remaining withholding amount.  For purposes of this Section 7, the “Value” of a Performance Share shall be equal to the closing market price for Company Common Stock on the last trading day preceding the Payment Date.  Notwithstanding the foregoing, Recipient may elect not to have Performance Shares withheld to cover taxes by giving notice to the Company in writing prior to the Payment Date, in which case the Performance Shares shall be issued or acquired in the Recipient’s name on the Payment Date thereby triggering the tax consequences, but the Company shall retain the certificate for the Performance Shares as security until Recipient shall have paid to the Company in cash any required tax withholding not covered by withholding of the Dividend Equivalent Cash Awards.

8.Change in Control.

8.1If a Change in Control (as defined below) occurs before the end of the Award Period, the Company shall, within 5 business days thereafter and subject to applicable tax withholding as provided for in Section 7, issue or otherwise deliver to Recipient a number of Performance Shares determined by multiplying the CIC Share Amount (as defined below) by a fraction, the numerator of which is the number of days in the period starting on the first day of the Award Period and ending on the date of the Change of Control and the denominator of which is the number of days in the Award Period.  At the same time, the Company shall pay to Recipient a Dividend Equivalent Cash Award based on such number of Performance Shares.  The “CIC Share Amount” shall equal 100% of the Strategic Target Share Amount plus an amount equal to the CIC TSR Payout Factor (as defined below) multiplied by the TSR Target Share Amount.  The “CIC TSR Payout Factor” shall be determined in the same manner as the TSR Payout Factor is determined under Section 2 of this Agreement, except that the final dollar value under clause (c) of Section 2.5 for the Company and each Peer Group Company shall be determined based on the average of the closing market prices of each stock for the three-month period ending on the date of the Change of Control.  Amounts delivered or paid under this Section 8 shall be in satisfaction of any and all obligations of the Company to issue or otherwise deliver Performance Shares or pay Dividend Equivalent Cash Awards under this Agreement.

8.2For purposes of this Agreement, a “Change in Control” of the Company shall mean the occurrence of any of the following events:

(a)The consummation of:

(1)any consolidation, merger or plan of share exchange involving the Company (a “Merger”) as a result of which the holders of outstanding securities of the Company ordinarily having the right to vote for the election of directors (“Voting Securities”) immediately prior to the Merger do not continue to hold at least 50% of the combined voting power of the outstanding Voting Securities of the surviving corporation or a parent corporation of the surviving corporation immediately after the Merger, disregarding any Voting Securities issued to or retained by such holders in respect of securities of any other party to the Merger; or

(2)any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, the assets of the Company;

(b)At any time during a period of two consecutive years, individuals who at the beginning of such period constituted the Board (“Incumbent Directors”) shall cease for any reason to constitute at least a majority thereof; provided, however, that the term “Incumbent Director” shall also include each new director elected during such two-year period whose nomination or election was approved by two-thirds of the Incumbent Directors then in office; or

(c)Any person (as such term is used in Section 14(d) of the Securities Exchange Act of 1934, other than the Company or any employee benefit plan sponsored by the Company) shall, as a result of a tender or exchange offer, open market purchases or privately negotiated purchases from anyone other than the Company, have become the beneficial owner (within the meaning of Rule 13d-3 under the Securities Exchange Act of 1934), directly or indirectly, of Voting Securities representing twenty percent (20%) or more of the combined voting power of the then outstanding Voting Securities.

9.Changes in Capital Structure.

9.1If the outstanding Common Stock of the Company is hereafter increased or decreased or changed into or exchanged for a different number or kind of shares or other securities of the Company by reason of any stock split, combination of shares or dividend payable in shares, recapitalization or reclassification, appropriate adjustment shall be made by the Committee in the number and kind of shares subject to this Agreement so that the Recipient’s proportionate interest before and after the occurrence of the event is maintained.

9.2If the outstanding Common Stock of the Company is hereafter converted into or exchanged for all of the outstanding Common Stock of a corporation (the “Parent Successor”) as part of a transaction (the “Transaction”) in which the Company becomes a wholly-owned subsidiary of Parent Successor, then (a) the obligations under this Agreement shall be assumed by Parent Successor and references in this Agreement to the Company shall thereafter generally be deemed to refer to Parent Successor, (b) Common Stock of Parent Successor shall be issued in lieu of Common Stock of the Company under this Agreement, (c) the performance measured pursuant to Sections 2 and 3 of this Agreement shall be the continuous performance of the Company prior to the Transaction and Parent Successor after the Transaction, (d) employment by the Company for purposes of Section 4 of this Agreement shall include employment by either the Company or Parent Successor, and (e) the Dividend Equivalent Cash Awards under Section 5 of this Agreement shall be based on dividends paid on the Common Stock of the Company prior to the Transaction and Parent Successor after the Transaction.

10.Recoupment On Misconduct Affecting TSR.

10.1If at any time before a Change in Control and within three years after the Payment Date, the Committee determines that Recipient engaged in any Misconduct (as defined below) during the Award Period that contributed to an obligation to restate the Company’s financial statements for any quarter or year in the Award Period or that otherwise has had (or will have when publicly disclosed) an adverse impact on the Company’s common stock price, Recipient shall repay to the Company the Excess LTIP Compensation (as defined below).  The term “Excess LTIP Compensation” means the excess of (a) the number of TSR Performance Shares and the amount of the TSR Dividend Equivalent Cash Award as originally calculated and certified under Section 6 of this Agreement, over (b) the number of TSR Performance Shares and the amount of the TSR Dividend Equivalent Cash Award as recalculated assuming that the average of the closing market prices of the Company’s common stock for the period from October 1, 2014 to December 31, 2014 was an amount determined appropriate by the Committee in its discretion to reflect what the Company’s common stock price would have been if the restatement had occurred or other Misconduct had been disclosed prior to October 1, 2014.  Excess LTIP Compensation shall not include any Strategic Performance Shares or any portion of the Strategic Dividend Equivalent Cash Award.  The Committee may, in its sole discretion, reduce the amount of Excess LTIP Compensation to be repaid by Recipient to take into account the tax consequences of such repayment or any other factors.  If any TSR Performance Shares included in the Excess LTIP Compensation are sold by Recipient prior to the Company’s demand for repayment (including any shares withheld for taxes under Section 7 of this Agreement), Recipient shall repay to the Company 100% of the proceeds of such sale or sales.  The return of Excess LTIP Compensation is in addition to and separate from any other relief available to the Company due to Recipient’s Misconduct.

10.2“Misconduct” shall mean (a) willful commission by Recipient of an act of fraud or dishonesty resulting in economic or financial injury to the Company, (b) willful misconduct by Recipient that substantially impairs the Company’s business or reputation, or (c) willful gross negligence by Recipient in the performance of his or her duties.

10.3If any portion of the TSR Performance Shares or the TSR Dividend Equivalent Cash Award was deferred under the DCP, the Excess LTIP Compensation shall first be recovered by canceling all or a portion of the amounts so deferred under the DCP and any dividends or other earnings credited under the DCP with respect to such cancelled amounts.  The Company may seek direct repayment from Recipient of any Excess LTIP Compensation not so recovered and may, to the extent permitted by applicable law, offset such Excess LTIP Compensation against any compensation or other amounts owed by the Company to Recipient.  In particular, Excess LTIP Compensation may be recovered by offset against the after-tax proceeds of deferred compensation payouts under the DCP, the Company’s Executive Supplemental Retirement Income Plan or the Company’s Supplemental Executive Retirement Plan at the times such deferred compensation payouts occur under the terms of those plans.  Excess LTIP Compensation that remains unpaid for more than 60 days after demand by the Company shall accrue interest at the rate used from time to time for crediting interest under the DCP.

11.Approvals.  The issuance by the Company of authorized and unissued shares or reacquired shares under this Agreement is subject to the approval of the Oregon Public Utility Commission and the Washington Utilities and Transportation Commission, but no such approvals shall be required for the purchase of shares on the open market for delivery to Recipient in satisfaction of its obligations under this Agreement.  The obligations of the Company under this Agreement are otherwise subject to the approval of state and federal authorities or agencies with jurisdiction in the matter.  The Company will use its best efforts to take steps required by state or federal law or applicable regulations, including rules and regulations of the Securities and Exchange Commission and any stock exchange on which the Company’s shares may then be listed, in connection with the award under this Agreement.  The foregoing notwithstanding, the Company shall not be obligated to issue or deliver Common Stock under this Agreement if such issuance or delivery would violate applicable state or federal law.

12.No Right to Employment.  Nothing contained in this Agreement shall confer upon Recipient any right to be employed by the Company or to continue to provide services to the Company or to interfere in any way with the right of the Company to terminate Recipient’s services at any time for any reason, with or without cause.

13.Miscellaneous.

13.1Entire Agreement; Amendment.  This Agreement constitutes the entire agreement of the parties with regard to the subjects hereof and may be amended only by written agreement between the Company and Recipient.

13.2Notices.  Any notice required or permitted under this Agreement shall be in writing and shall be deemed sufficient when delivered personally to the party to whom it is addressed or when deposited into the United States Mail as registered or certified mail, return receipt requested, postage prepaid, addressed to the Company, Attention:  Corporate Secretary, at its principal executive offices or to Recipient at the address of Recipient in the Company’s records, or at such other address as such party may designate by ten (10) days’ advance written notice to the other party.

13.3Assignment; Rights and Benefits.  Recipient shall not assign this Agreement or any rights hereunder to any other party or parties without the prior written consent of the Company.  The rights and benefits of this Agreement shall inure to the benefit of and be enforceable by the Company’s successors and assigns and, subject to the foregoing restriction on assignment, be binding upon Recipient’s heirs, executors, administrators, successors and assigns.

13.4Further Action.  The parties agree to execute such further instruments and to take such further action as may reasonably be necessary to carry out the intent of this Agreement.

13.5Applicable Law; Attorneys’ Fees.  The terms and conditions of this Agreement shall be governed by the laws of the State of Oregon.  In the event either party institutes litigation hereunder, the prevailing party shall be entitled to reasonable attorneys’ fees to be set by the trial court and, upon any appeal, the appellate court.

13.6Counterparts.  This Agreement may be executed in two or more counterparts, each of which shall be deemed an original.

IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the day and year first above written.

NORTHWEST NATURAL GAS COMPANY

By           

Title           

RECIPIENT

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Quarterly Financial Information (tables)

12 Months Ended

Dec. 31, 2011

Schedule Of Quarterly Financial Information [Abstract]

Schedule of Quarterly Financial Information [Table Text Block]

NORTHWEST NATURAL GAS COMPANY
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
			Quarter ended
Thousands, except per share amounts			March 31		June 30		Sept. 30		Dec. 31		Total
2011
Operating revenues		$	323,088	$	161,197	$	93,313	$	271,198	$	848,796
Net operating revenues			134,508		67,232		47,783		119,910		369,433
Net income (loss)			40,773		2,193		(8,312)		29,244		63,898
Basic earnings (loss) per share			1.53		0.08		(0.31)		1.09		2.39(1)
Diluted earnings (loss) per share			1.53		0.08		(0.31)		1.09		2.39(1)
2010
Operating revenues		$	286,529	$	162,365	$	95,067	$	268,145	$	812,106
Net operating revenues			130,926		72,193		46,211		118,251		367,581
Net income (loss)			43,608		6,888		(7,420)		29,591		72,667
Basic earnings (loss) per share			1.64		0.26		(0.28)		1.11		2.73(1)
Diluted earnings (loss) per share			1.64		0.26		(0.28)		1.11		2.73(1)
(1)	Quarterly earnings (loss) per share are based upon the average number of common shares outstanding during each quarter. Because the average number of shares outstanding has changed in each quarter shown, the sum of quarterly earnings (loss) per share may not equal earnings per share for the year. Variations in earnings between quarterly periods are due primarily to the seasonal nature of our business.

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Commitments and Contingencies (details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Commitments [Abstract]
Unrecorded Unconditional Purchase Obligation, Purchases	$ 94,200,000	$ 91,400,000	$ 84,600,000
Unrecorded Unconditional Purchase Obligation Offsetting Sales	3,100,000	4,200,000	4,200,000
Accrual For Environmental Loss Contingencies [Abstract]
Other current liabilities	41,597,000	35,457,000
Other non-current liabilities	76,265,000	70,942,000
Other Liabilities	72,700,000
Environmental Remediation Obligations Abstract
Loss Contingency Range Of Possible Loss	between $11 million and $30 million
Gasco Source Control Liability	12,000,000
Gasco Other Liabilities	49,200,000
Wutc Environmental Deferral Start Date	January 26, 2011
Cumulative Environmental Costs Recognized	124,800,000
Cumulative Environmental Costs Recognized Prior To Regulatory Order	4,900,000
Environmental Regulatory Assets Noncurrent	105,700,000
Damages Sought On Environmental Claims	50,000,000
Gas Purchase Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	98,534,000
Unrecorded Unconditional Purchase Obligation, Due within Two Years	18,331,000
Unrecorded Unconditional Purchase Obligation, Due within Three Years	15,290,000
Unrecorded Unconditional Purchase Obligation, Due within Four Years	5,651,000
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	137,806,000
Less: Amount representing interest	682,000
Total At Present Value	137,124,000
Pipeline Capacity Purchase Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	91,027,000
Unrecorded Unconditional Purchase Obligation, Due within Two Years	87,983,000
Unrecorded Unconditional Purchase Obligation, Due within Three Years	82,898,000
Unrecorded Unconditional Purchase Obligation, Due within Four Years	72,316,000
Unrecorded Unconditional Purchase Obligation, Due within Five Years	61,358,000
Unrecorded Unconditional Purchase Obligation, Due after Five Years	287,541,000
Unrecorded Unconditional Purchase Obligation	683,123,000
Less: Amount representing interest	99,252,000
Total At Present Value	583,871,000
Pipeline Capacity Release Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	3,464,000
Unrecorded Unconditional Purchase Obligation, Due within Two Years	0
Unrecorded Unconditional Purchase Obligation, Due within Three Years	0
Unrecorded Unconditional Purchase Obligation, Due within Four Years	0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	3,464,000
Less: Amount representing interest	2,000
Total At Present Value	3,462,000
Gasco [Member]
Accrual For Environmental Loss Contingencies [Abstract]
Other current liabilities	16,510,000	11,366,000
Other non-current liabilities	44,697,000	38,921,000
Other Liabilities	61,200,000
Siltronic [Member]
Accrual For Environmental Loss Contingencies [Abstract]
Other current liabilities	887,000	720,000
Other non-current liabilities	128,000	201,000
Other Liabilities	1,000,000
Portland Harbor [Member]
Accrual For Environmental Loss Contingencies [Abstract]
Other current liabilities	1,089,000	2,304,000
Other non-current liabilities	7,066,000	5,784,000
Other Liabilities	8,200,000
Central Service Center [Member]
Accrual For Environmental Loss Contingencies [Abstract]
Other current liabilities	0	5,000
Other non-current liabilities	495,000	510,000
Other Liabilities	500,000
Front Street [Member]
Accrual For Environmental Loss Contingencies [Abstract]
Other current liabilities	1,697,000	1,000
Other non-current liabilities	0	1,097,000
Other Liabilities	1,700,000
Other Environmental [Member]
Accrual For Environmental Loss Contingencies [Abstract]
Other current liabilities	0	0
Other non-current liabilities	$ 120,000	$ 108,000

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Pension and Other Postretirement Benefits (details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components	$ 67,000
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation	678,000
Defined Benefit Plan, Effect of One Percentage Point Decrease on Service and Interest Cost Components	(60,000)
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation	(613,000)
Defined Benefit Plan, Information about Plan Assets [Abstract]
Accrued Interest and Dividend Income	414,000	249,000
Due from broker for securities sold	321,000	448,000
Total Pension Plan Asset Receivables	735,000	697,000
Due to broker for securities purchased	839,000	42,000
Defined Benefit Plan, Fair Value of Plan Assets	215,970,000	219,014,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, Start	219,014,000
Defined Benefit Plan, Fair Value of Plan Assets, End	215,970,000	219,014,000
General Discussion Of Pension And Other Postretirement Benefits Abstract
Aggregate Projected Benefit Obligation Qualified Plans	362,900,000	314,500,000	285,200,000
Benefit Obligations Change in Discount Rate	40,300,000	17,900,000
Benefit Obligations Change in Other Assumptions	900,000	6,500,000
Next year Regulatory Asset Amortization	15,500,000
Next year Regulatory Asset Amortization, Actuarial Losses	14,700,000
Next year Regulatory Asset Amortization, Prior Service Costs	400,000
Next year Regulatory Asset Amortization, Transition Obligations	400,000
Next year AOCI Amortization, Actuarial Losses	1,000,000
Non-Qualified Obligations	28,200,000	24,900,000	22,800,000
Health Care Cost Trend Rate Assumed for Next Fiscal Year (medical)	8.00%
Health Care Cost Trend Rate Assumed for Next Fiscal Year (drugs)	10.00%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate	5.00%
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate	2021
Range Of Pension Costs Capitalized	30 to 40 percent
Underfunded Amount of Qualified Defined Benefit Plans	146,900,000
Qualified Contributions Expected During Next Fiscal Year	28,000,000
Defined Contribution Plan, Cost Recognized	2,400,000	2,100,000	2,100,000
Multiemployer Plan Contributions	400,000	400,000	400,000
Level 3 Change In Fair Value Of Plan Assets Roll Forward [Abstract]
Level 3, Actual Return on Plan Assets	596,000
Level 3, Purchases, Sales, and Settlements	0
Level 3 Plan Assets Balance	15,317,000	14,721,000
Plan Asset Target Allocation [Abstract]
US Large Cap Equity Pension Plan Asset Target Allocation	15.00%
US Small Mid Cap Equity Pension Plan Asset Target Allocation	10.00%
Non US Equity Pension Plan Asset Target Allocation	14.50%
Emerging Markets Equity Pension Plan Asset Target Allocation	3.50%
Long Government Credit Pension Plan Asset Target Allocation	24.00%
High Yield Pension Plan Asset Target Allocation	5.00%
Emerging Market Debt Pension Plan Asset Target Allocation	5.00%
Real Estate Funds Pension Plan Asset Target Allocation	5.80%
Absolute Return Strategy Pension Plan Asset Target Allocation	12.00%
Real Return Strategy Pension Plan Asset Target Allocation	5.20%
Defined Benefit Plan Fair Value Of Plan Assets By Measurement Table [Abstract]
US Large Cap Equity Pension Assets	36,236,000	37,231,000
US Small Mid Cap Equity Pension Assets	27,310,000	27,864,000
Non US Equity Pension Assets	33,745,000	39,179,000
Emerging Markets Equity Pension Assets	10,208,000	11,476,000
Fixed Income Pension Assets	19,121,000	36,429,000
Long Government Credit Pension Assets	18,897,000
Real Estate Funds Pension Assets	15,317,000	14,721,000
Absolute Return Strategy Pension Assets	30,475,000	32,378,000
Real Return Strategy Pension Assets	15,475,000	15,452,000
Cash And Cash Equivalents Pension Assets	9,290,000	3,629,000
Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Fair Value Of Plan Assets By Measurement Table [Abstract]
US Large Cap Equity Pension Assets	36,236,000	37,231,000
US Small Mid Cap Equity Pension Assets	0	0
Non US Equity Pension Assets	22,158,000	24,630,000
Emerging Markets Equity Pension Assets	10,208,000	11,476,000
Fixed Income Pension Assets	19,121,000	36,429,000
Long Government Credit Pension Assets	0
Real Estate Funds Pension Assets	0	0
Absolute Return Strategy Pension Assets	0	0
Real Return Strategy Pension Assets	15,475,000	15,452,000
Cash And Cash Equivalents Pension Assets	0	0
Total Pension Asset Investments Net Of Receivables And Payables	103,198,000	125,218,000
Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Fair Value Of Plan Assets By Measurement Table [Abstract]
US Large Cap Equity Pension Assets	0	0
US Small Mid Cap Equity Pension Assets	27,310,000	27,864,000
Non US Equity Pension Assets	11,587,000	14,549,000
Emerging Markets Equity Pension Assets	0	0
Fixed Income Pension Assets	0	0
Long Government Credit Pension Assets	18,897,000
Real Estate Funds Pension Assets	0	0
Absolute Return Strategy Pension Assets	30,475,000	32,378,000
Real Return Strategy Pension Assets	0	0
Cash And Cash Equivalents Pension Assets	9,290,000	3,629,000
Total Pension Asset Investments Net Of Receivables And Payables	97,559,000	78,420,000
Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Fair Value Of Plan Assets By Measurement Table [Abstract]
US Large Cap Equity Pension Assets	0	0
US Small Mid Cap Equity Pension Assets	0	0
Non US Equity Pension Assets	0	0
Emerging Markets Equity Pension Assets	0	0
Fixed Income Pension Assets	0	0
Long Government Credit Pension Assets	0
Real Estate Funds Pension Assets	15,317,000	14,721,000
Absolute Return Strategy Pension Assets	0	0
Real Return Strategy Pension Assets	0	0
Cash And Cash Equivalents Pension Assets	0	0
Total Pension Asset Investments Net Of Receivables And Payables	15,317,000	14,721,000
Pension Plans Defined Benefit [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	215,970,000	219,014,000	201,312,000
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, Start	339,338,000	307,991,000	281,127,000
Defined Benefit Plan Service Cost	7,122,000	6,688,000	6,402,000
Defined Benefit Plan Interest Cost	18,134,000	18,029,000	17,948,000
Defined Benefit Plan, Actuarial Net (Gains) Losses	44,802,000	25,275,000	23,584,000
Defined Benefit Plan, Benefits Paid	(18,269,000)	(18,645,000)	(17,149,000)
Defined Benefit Plan, Plan Amendments	0	0	(3,921,000)
Defined Benefit Plan, Benefit Obligation, End	391,127,000	339,338,000	307,991,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, Start	219,014,000	201,312,000	163,115,000
Defined Benefit Plan, Actual Return on Plan Assets	(6,684,000)	24,651,000	28,641,000
Defined Benefit Plan, Contributions by Employer	21,909,000	11,696,000	26,705,000
Defined Benefit Plan, Benefits Paid	(18,269,000)	(18,645,000)	(17,149,000)
Defined Benefit Plan, Fair Value of Plan Assets, End	215,970,000	219,014,000	201,312,000
Defined Benefit Plan, Funded Status of Plan	(175,157,000)	(120,324,000)	(106,679,000)
Defined Benefit Plan Amounts Recognized In Regulatory Amortization And Other Comprehensive Income Net Prior Service Cost Credit Before Tax [Abstract]
Actuarial Loss (Regulatory)	10,731,000	6,740,000	6,189,000
Prior Service Costs (Regulatory)	230,000	230,000	1,260,000
Transition Obligation (Regulatory)	0	0	0
Total Regulatory Amortization In Net Periodic Benefit Costs	10,961,000	6,970,000	7,449,000
Actuarial Loss (AOCI)	854,000	707,000	449,000
Prior Service Costs (AOCI)	122,000	(43,000)	(37,000)
Total AOCI Amortization In Net Periodic Benefit Costs	976,000	664,000	412,000
Defined Benefit Plans And Other Postretirement Benefit Plans Disclosures [Abstract]
Defined Benefit Plan Service Cost	7,122,000	6,688,000	6,402,000
Defined Benefit Plan Interest Cost	18,134,000	18,029,000	17,948,000
Defined Benefit Plan Expected Return On Plan Assets	(17,867,000)	(18,207,000)	(15,696,000)
Defined Benefit Plan Amortization Of Transition Obligations	0	0	0
Defined Benefit Plan Amortization Of Prior Service Costs	352,000	187,000	1,223,000
Defined Benefit Plan Amortization Of Net Actuarial Loss	(11,584,000)	(7,447,000)	(6,810,000)
Defined Benefit Plan Net Periodic Benefit Cost	19,325,000	14,144,000	16,687,000
Defined Benefit Plan Amount Allocated To Construction	(4,905,000)	(3,729,000)	(4,636,000)
Defined Benefit Plan Net Amount Deferred To Regulatory Balancing Account	(6,008,000)	0	0
Defined Benefit Plan Net Amount Charged To Expense	8,412,000	10,415,000	12,051,000
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Weighted Average Discount Rate (Cost)	5.49%	6.01%	6.60%
Rate of Increase in Compensation Low Range (Cost)	3.25%	3.25%	3.25%
Rate of Increase in Compensation High Range (Cost)	5.00%	5.00%	5.00%
Expected Long-Term Rate of Return (Cost)	8.25%	8.25%	8.25%
Weighted Average Discount Rate (Obligation)	4.51%	5.49%	6.01%
Rate of Increase in Compensation Low Range (Obligation)	3.25%	3.25%	3.25%
Rate of Increase in Compensation High Range (Obligation)	5.00%	5.00%	5.00%
Expected Long-Term Rate of Return (Obligation)	8.00%	8.25%	8.25%
Pension and Other Postretirement Benefit Contributions [Abstract]
Pension And Other Postretirement Benefit Contributions	22,325,000	12,088,000
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	30,109,000
Defined Benefit Plan, Benefits Paid	(18,269,000)	(18,645,000)	(17,149,000)
Defined Benefit Plan, Expected Future Benefit Payments in Year One	19,374,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	19,620,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	20,107,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	20,640,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	21,284,000
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	122,680,000
Other Postretirement Benefit Plans Defined Benefit [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0	0
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, Start	27,676,000	24,741,000	23,863,000
Defined Benefit Plan Service Cost	614,000	588,000	522,000
Defined Benefit Plan Interest Cost	1,404,000	1,436,000	1,568,000
Defined Benefit Plan, Actuarial Net (Gains) Losses	2,225,000	2,387,000	216,000
Defined Benefit Plan, Benefits Paid	(1,870,000)	(1,476,000)	(1,428,000)
Defined Benefit Plan, Plan Amendments	0	0	0
Defined Benefit Plan, Benefit Obligation, End	30,049,000	27,676,000	24,741,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, Start	0	0	0
Defined Benefit Plan, Actual Return on Plan Assets	0	0	0
Defined Benefit Plan, Contributions by Employer	1,870,000	1,476,000	1,428,000
Defined Benefit Plan, Benefits Paid	(1,870,000)	(1,476,000)	(1,428,000)
Defined Benefit Plan, Fair Value of Plan Assets, End	0	0	0
Defined Benefit Plan, Funded Status of Plan	(30,049,000)	(27,676,000)	(24,741,000)
Defined Benefit Plan Amounts Recognized In Regulatory Amortization And Other Comprehensive Income Net Prior Service Cost Credit Before Tax [Abstract]
Actuarial Loss (Regulatory)	289,000	131,000	17,000
Prior Service Costs (Regulatory)	197,000	197,000	197,000
Transition Obligation (Regulatory)	411,000	411,000	411,000
Total Regulatory Amortization In Net Periodic Benefit Costs	897,000	739,000	625,000
Defined Benefit Plans And Other Postretirement Benefit Plans Disclosures [Abstract]
Defined Benefit Plan Service Cost	614,000	588,000	522,000
Defined Benefit Plan Interest Cost	1,404,000	1,436,000	1,568,000
Defined Benefit Plan Expected Return On Plan Assets	0	0	0
Defined Benefit Plan Amortization Of Transition Obligations	411,000	411,000	411,000
Defined Benefit Plan Amortization Of Prior Service Costs	197,000	197,000	197,000
Defined Benefit Plan Amortization Of Net Actuarial Loss	(289,000)	(131,000)	0
Defined Benefit Plan Net Periodic Benefit Cost	2,915,000	2,763,000	2,698,000
Defined Benefit Plan Amount Allocated To Construction	(878,000)	(904,000)	(858,000)
Defined Benefit Plan Net Amount Deferred To Regulatory Balancing Account	0	0	0
Defined Benefit Plan Net Amount Charged To Expense	2,037,000	1,859,000	1,840,000
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Weighted Average Discount Rate (Cost)	5.16%	5.78%	7.12%
Weighted Average Discount Rate (Obligation)	4.33%	5.16%	5.78%
Pension and Other Postretirement Benefit Contributions [Abstract]
Pension And Other Postretirement Benefit Contributions	1,870,000	1,476,000
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	2,056,000
Defined Benefit Plan, Benefits Paid	(1,870,000)	(1,476,000)	(1,428,000)
Defined Benefit Plan, Expected Future Benefit Payments in Year One	2,056,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	2,083,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	2,138,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	2,149,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	2,198,000
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	$ 11,298,000

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Quarterly Financial Information (details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Quarterly Financial Information Disclosure [Abstract]
Gross operating revenues	$ 271,198	$ 93,313	$ 161,197	$ 323,088	$ 268,145	$ 95,067	$ 162,365	$ 286,529	$ 848,796	$ 812,106	$ 1,012,711
Net operating revenues	119,910	47,783	67,232	134,508	118,251	46,211	72,193	130,926	369,433	367,581	376,887
Net income	$ 29,244	$ (8,312)	$ 2,193	$ 40,773	$ 29,591	$ (7,420)	$ 6,888	$ 43,608	$ 63,898	$ 72,667	$ 75,122
Earnings Per Share, Basic	$ 1.09	$ (0.31)	$ 0.08	$ 1.53	$ 1.11	$ (0.28)	$ 0.26	$ 1.64	$ 2.39	$ 2.73	$ 2.83
Diluted eps	$ 1.09	$ (0.31)	$ 0.08	$ 1.53	$ 1.11	$ (0.28)	$ 0.26	$ 1.64	$ 2.39	$ 2.73	$ 2.83

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Cost and Fair Value Basis of Long-Term Debt (details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Liabilities, Fair Value Disclosure [Abstract]
Long-term Debt	$ 681,700,000	$ 601,700,000	$ 636,700,000
Debt Instrument Fair Value	808,724,000	690,126,000
Long-term Debt Current And Noncurrent Abstract
Long-term Debt, Description	In March 2009, the utility issued $75 million of 5.37 percent secured MTNs due February 1, 2020, and in July 2009 issued another $50 million of 3.95 percent secured MTNs due July 15, 2014.  The utility also issued $50 million of MTNs in September 2011 with an interest rate of 3.176 percent and a maturity date of September 15, 2021.
Subsidiary Debt Instrument, Description	In November 2011, Gill Ranch issued $40 million of subsidiary senior secured notes with an interest rate of 7.75 percent on the fixed portion and a 7.00 percent interest rate currently on the variable portion. The notes are secured by all of the membership interests in Gill Ranch Storage, LLC, and are nonrecourse notes to NW Natural. The maturity date of these notes is November 30, 2016.
Subsidiary Debt Instrument, Covenant Description	Under the note agreements, Gill Ranch is subject to certain covenants and restrictions, including but not limited to, a financial covenant that requires Gill Ranch to maintain minimum adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) at various levels over the term of the notes. The minimum adjusted EBITDA increases incrementally over the first few years, reaching its highest level in the 12-month period beginning April 1, 2015. Under the note agreements, Gill Ranch is also subject to a debt service reserve requirement of 10 percent of the outstanding principal amount, initially $4 million, certain prepayment penalties, restrictions on dividends out of Gill Ranch unless certain earnings ratios are met, and restrictions on incurrence of additional debt.
Maturities of Long-term Debt [Abstract]
Current maturities of long-term debt	40,000,000	10,000,000	35,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Two	0
Long-term Debt, Maturities, Repayments of Principal in Year Three	60,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Four	40,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Five	65,000,000
Debt Instrument [Line Items]
Long-term Debt	681,700,000	601,700,000	636,700,000
Current maturities of long-term debt	40,000,000	10,000,000	35,000,000
Long-term Debt, Noncurrent	641,700,000	591,700,000	601,700,000
Note 4110 Series Due 2010 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	0	0	10,000,000
Note 7450 Series Due 2010 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	0	0	25,000,000
Note 6665 Series Due 2011 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	0	10,000,000	10,000,000
Note 7130 Series Due 2012 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	40,000,000	40,000,000	40,000,000
Note 8260 Series Due 2014 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	10,000,000	10,000,000	10,000,000
Note 3950 Series Due 2014 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	50,000,000	50,000,000	50,000,000
Note 4700 Series Due 2015 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	40,000,000	40,000,000	40,000,000
Note 5150 Series Due 2016 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	25,000,000	25,000,000	25,000,000
Note 7000 Series Due 2017 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	40,000,000	40,000,000	40,000,000
Note 6600 Series Due 2018 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	22,000,000	22,000,000	22,000,000
Note 8310 Series Due 2019 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	10,000,000	10,000,000	10,000,000
Note 5370 Series Due 2020 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	75,000,000	75,000,000	75,000,000
Note 7630 Series Due 2019 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	20,000,000	20,000,000	20,000,000
Note 9050 Series Due 2021 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	10,000,000	10,000,000	10,000,000
Note 3176 Series Due 2021 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	50,000,000	0	0
Note 5620 Series Due 2023 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	40,000,000	40,000,000	40,000,000
Note 7720 Series Due 2025 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	20,000,000	20,000,000	20,000,000
Note 6520 Series Due 2025 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	10,000,000	10,000,000	10,000,000
Note 7050 Series Due 2026 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	20,000,000	20,000,000	20,000,000
Note 7000 Series Due 2027 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	20,000,000	20,000,000	20,000,000
Note 6650 Series Due 2027 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	19,700,000	19,700,000	19,700,000
Note 6650 Series Due 2028 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	10,000,000	10,000,000	10,000,000
Note 7740 Series Due 2030 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	20,000,000	20,000,000	20,000,000
Note 7850 Series Due 2030 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	10,000,000	10,000,000	10,000,000
Note 5820 Series Due 2032 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	30,000,000	30,000,000	30,000,000
Note 5660 Series Due 2032 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	40,000,000	40,000,000	40,000,000
Note 5250 Series Due 2035 [Member]
Debt Instrument [Line Items]
Total MTN Carrying Amount	10,000,000	10,000,000	10,000,000
Secured Notes Due 2016 [Member]
Debt Instrument [Line Items]
Subsidiary Senior Secured Notes	$ 40,000,000	$ 0	$ 0

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Income Tax (tables)

12 Months Ended

Dec. 31, 2011

Income Tax Expense Benefit Abstract

Effective Tax Rate Reconciliation

Thousands, except percentages			2011		2010		2009
Income taxes at federal statutory rate		$	37,550	$	42,745	$	42,627
Increase (decrease):
	Current state income tax, net of federal tax benefit		4,945		5,803		5,568
	Amortization of investment and energy tax credits		(442)		(525)		(593)
	Differences required to be flowed-through by
	regulatory commissions		1,647		1,647		(116)
	Gains on company and trust-owned life insurance		(786)		(715)		(1,195)
	Other - net		468		507		380
Total provision for income taxes		$	43,382	$	49,462	$	46,671
Effective tax rate			40.4%		40.5%		38.3%

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

Thousands			2011		2010		2009
Current
	Federal	$	130	$	(28,592)	$	6,221
	State		(929)		1,441		2,300
			(799)		(27,151)		8,521
Deferred
	Federal		35,481		69,159		31,937
	State		8,700		7,454		6,213
			44,181		76,613		38,150
	Total provision for income taxes	$	43,382	$	49,462	$	46,671
	Total income taxes paid	$	1,756	$	22,600	$	10,000

Schedule Of Regulated Utility And Non Utility Business Segments [Table Text Block]

Thousands			2011		2010		2009
Regulated utility:
	Current	$	(4,646)	$	(1,464)	$	871
	Deferred		50,152		47,741		40,829
	Deferred investment and energy tax credits		(422)		(525)		(593)
			45,084		45,752		41,107
Non-utility business segments:
	Current		3,846		(25,687)		7,650
	Deferred		(5,548)		29,397		(2,086)
			(1,702)		3,710		5,564
Total provision for income taxes		$	43,382	$	49,462	$	46,671

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

Thousands				2011		2010
Deferred tax liabilities:
	Plant and property		$	292,235	$	255,471
	Regulatory adjustment for income taxes paid			2,106		5,272
	Regulatory income tax assets			65,755		68,822
	Regulatory liabilities			35,638		23,159
	Non-regulated deferred tax liabilities			43,373		34,544
		Total	$	439,107	$	387,268
Deferred tax assets:
	Regulatory assets			(4,727)		(1,402)
	Unfunded pension and postretirement obligations			(5,119)		(4,342)
	Non-regulated deferred tax assets			(1,161)		(772)
	Alternative minimum tax credit carryforward			(1,626)		(1,702)
	Loss and credit carryforwards			(14,255)		(7,071)
		Total		(26,888)		(15,289)
Deferred income tax liabilities - net				412,219		371,979
Deferred investment tax credits				990		1,430
Deferred income taxes and investment tax credits			$	413,209	$	373,409

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Policy

12 Months Ended

Dec. 31, 2011

Accounting Policies Abstract

Consolidation, Policy [Policy Text Block]

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.

Certain prior year balances in our consolidated financial statements have been combined to conform with the current presentation. These changes had no impact on our prior year's consolidated results of operations, financial condition or cash flows.

Use of Estimates, Policy [Policy Text Block]

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America (U.S. GAAP) requires management to make estimates and assumptions that affect reported amounts in the consolidated financial statements and accompanying notes.  Actual amounts could differ from those estimates, and changes would most likely be reported in future periods.  Management believes that the estimates and assumptions used are reasonable.

Public Utilities, Policy [Policy Text Block]

Industry Regulation

Our principal businesses are the distribution of natural gas, which is regulated by the Public Utility Commission of Oregon (OPUC) and Washington Utilities and Transportation Commission (WUTC), and natural gas storage services, which are regulated by either the Federal Energy Regulatory Commission (FERC) or the California Public Utilities Commission (CPUC), and to a certain extent by the OPUC.  Accounting records and practices of our regulated businesses conform to the requirements and uniform system of accounts prescribed by these regulatory authorities in accordance with U.S. GAAP.  Our businesses regulated by the OPUC, WUTC and FERC earn a reasonable return on invested capital from approved cost-based rates, while our business regulated by the CPUC earns a return to the extent we are able to charge competitive prices above our costs (i.e. market-based rates).

In applying regulatory accounting principles, we capitalize or defer certain costs and revenues as regulatory assets and liabilities pursuant to orders of the OPUC or WUTC, which provides for the recovery of revenues or expenses from, or refunds to, utility customers in future periods, including a return or a carrying charge in most cases.

Property, Plant and Equipment, Policy [Policy Text Block]

Plant, Property and Accrued Asset Removal Costs

Plant and property are stated at cost, including capitalized labor, materials and overhead (see Note 11).  In accordance with regulatory accounting standards, the cost of acquiring and constructing long-lived plant and property generally includes an allowance for funds used during construction (AFUDC) or capitalized interest.  AFUDC represents the regulatory financing cost incurred when debt and equity funds are used for construction (see “Allowance for Funds Used During Construction,” below).  When constructed assets are subject to market-based rates rather than cost-based rates, then the financing cost incurred during construction are includedin capitalized interest inaccordance with U.S. GAAP, not regulatory financing cost under AFUDC.

Our provision for depreciation of utility plant and property is computed under the straight-line method in accordance with engineering studies approved by regulatory authorities. The weighted average depreciation rate for utility assets in service was approximately 2.8percentin2011 and 2010, and 2.9 percent in2009reflecting the approximate average economic life of the property.This includes 2011 weighted average depreciation rates for the following asset categories:2.7 percent for transmission and distribution plant, 2.2 percent for gas storage facilities, 4.6 percent for general plant, and 5.1 percent for intangible and other fixed assets.

Asset Retirement Obligations, Policy [Policy Text Block]

In accordance with long-standing regulatory treatment, our depreciation rates are comprised of three components: one based on the average service life of the asset, a second based on the estimated salvage value of the asset, and a third based on the asset's cost of removal. We collect, through rates, the estimated cost of removal on certain regulated properties through depreciation expense, with a corresponding offset to accumulated depreciation.  These removal costs are non-legal obligations as defined by regulatory accounting guidance. Therefore, we have included these costs in non-current regulatory liabilities on our consolidated balance sheets. In the rate setting process, the liability for the removal costs is treated as a reduction to the net rate base upon which the regulated utility has the opportunity to earn its allowed rate of return.

Allowance for Funds Used During Construction, Policy [Policy Text Block]

Allowance for Funds Used During Construction

Certain additions to utility plant include AFUDC, which represents the net cost of debtand equity funds used during construction. AFUDC is calculated using actual interest rates for debt and authorized rates for return on equity, if applicable. If short-term debt balances are less than the total balance of construction work in progress, then a composite AFUDC rate is used to represent interest on all debt funds, shown as a reduction to interest charges, and a return on equity funds, shown as other income. While cash is not immediately recognized from recording AFUDC, it is realized in future years through rate recovery resulting from the higher utility cost of service. Our composite AFUDC rates were 0.5percent in 2011, 0.6 percent in 2010 and 1.0 percent in 2009.

Cash and Cash Equivalents, Policy [Policy Text Block]

Cash and Cash Equivalents

For purposes of reporting cash flows, cash and cash equivalents include cash on hand plus highly liquid investment accounts with maturity dates of three months or less. At December 31, 2011, outstanding checks of approximately $3.9 million were included in accounts payable.

Revenue Recognition Policy Text Block

Revenue Recognition and Accrued Unbilled Revenues

Utility revenues, derived primarily from the sale and transportation of natural gas, are recognized upon delivery of gas commodity or service to customers.  Revenues include accruals for gas delivered but not yet billed to customers based on estimates of deliveries from meter reading dates to month end (accrued unbilled revenues). Accrued unbilled revenues are dependent upon a number of factors that require management's judgment, including total gas receipts and deliveries, customer use by billing cycle and weather factors.  Accrued unbilled revenues are reversed the following month when actual billings occur. Our accrued unbilled revenues at December 31, 2011 and 2010were $61.9 million and $64.8 million, respectively.

From 2007 through 2010, 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 based on estimates of the annual amount to be recognized. On May 24, 2011, SB 408 was repealed and replaced by Senate Bill 967. SB 967 required utilities to eliminate amounts accrued under SB 408 for the 2010 and 2011 tax years, thereby denying recovery by NW Natural of the surcharge accrued for 2010, which resulted in a one-time pre-tax charge of $7.4 million in the second quarter of 2011. Pursuant to SB 967, we changed our revenue recognition policy effective January 1, 2011 and no longer recognize a regulatory adjustment for income taxes for SB 408.

Non-utility revenues are derived primarily from the gas storage business segment. At Mist, revenues are recognized upon delivery of services to customers.  Revenues from our asset management partner are recognized over the life of the asset management contract for guaranteed amounts, if any, and are recognized as earned for amounts above the guaranteed amount. At Gill Ranch, firm storage services resulting from short-term and long-term contracts are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized.Asset management revenue is recognized using a straight-line, pro rata methodology over the term of each contract and provides us with 80 percent of the pre-tax income from our independent energy marketing company. See Note 4.

Receivables, Policy [Policy Text Block]

Accounts Receivable and Allowance for Uncollectible Accounts

Accounts receivable consist primarily of amounts due for natural gas sales and transportation services to core utility customers, plus amounts due for gas storage services.  With respect to these trade receivables, including accrued unbilled revenues, we establish an allowance for uncollectible accounts (allowance) based on the aging of receivables, collection experience of past due account balances including payment plans, and historical trends of write-offs as a percent of revenues.  With respect to large individual customer receivables, a specific allowance is established and added to the general allowance when amounts are identified as unlikely to be partially or fully recovered.  Inactive accounts are written-off against the allowance after they are 120 days past due or when deemed to be uncollectible.  Differences between our estimated allowance and actual write-offs will occur based on a number of factors, including changes in economic conditions, customer credit worthiness and the level of natural gas prices.  Each quarter the allowance for uncollectible accounts is adjusted, as necessary, based on information currently available.

Inventory, Policy [Policy Text Block]

Inventories

Utility gas inventories, which consist of natural gas in storage for the utility, are generally stated at the lower of average cost or net realizable value. The regulatory treatment of utility gas inventories provides for cost recovery in customer rates.  Utility gas inventories that are injected into storage are priced into inventory based on actual purchase costs. Utility gas inventories that are withdrawn from storage are charged to cost of gas during the current period at the weighted average inventory cost.

Gas Storageinventories, which primarily represent inventories at Gill Ranch, exclude cushion gas and consist of natural gas that we received as fuel-in-kind from storage customers. Gas Storage inventories are valued at the lower of average cost or net realizable value. Cushion gas is recorded at original cost and classified as long-term assets.

Material and supplies inventories, which consist of both utility and non-utility inventories, are stated at the lower of average cost or net realizable value.

Our utility and gas storage inventories totaled $65.6 million and $70.7 million at December 31, 2011 and 2010, respectively, and our materials and supplies inventories totaled $8.8 million and $9.7 million

Gas Reserves Policy [Text Block]

Our gas reserves are stated at cost, adjusted for regulatory amortization, with the associated deferred tax benefits recorded as liabilities on the balance sheet. Transactional costs to enter into the agreement (see Note 12) and payments by NW Natural to Encana Oil & Gas (USA) Inc. (Encana) are recognized as gas reserves on the balance sheet.  The current portion is calculated based on expected gas deliveries within the next fiscal year.  We recognize regulatory amortization of this asset on a volumetric basis and calculate using the proven reserves and the therms extracted and sold each month.  The amortization of gas reserves is recorded as an adjustment to the cost of gas.

Derivatives Policy Text Block

Derivatives

In accordance with accounting for derivatives and hedges, we measure derivatives at fair value and recognize them as either assets or liabilities on the balance sheet.  Accounting for derivatives requires that changes in the fair value be recognized currently in earnings unless specific hedge accounting criteria are met.  Accounting for derivatives and hedges provides an exception for contracts intended for normal purchases and normal sales for which physical delivery is probable.  In addition, certain derivative contracts are approved by regulatory authorities for recovery or refund through customer rates.  Accordingly, the changes in fair value of these approved contracts are deferred as regulatory assets or liabilities pursuant to regulatory accounting principles.  Derivative contracts entered into for core utility customer requirements after the annual purchased gas adjustment (PGA) rate has been set are subject to the PGA incentive sharing mechanism. Effective November 1, 2008, Oregon approved a PGA sharing mechanism under which we are required to select either an 80 percent deferral or 90 percent deferral of higher or lower gas costs such that the impact on current earnings from the gas cost sharing is either 20 percent or 10 percent of gas cost differences compared to PGA prices, respectively. For the PGA years in Oregon beginning November 1, 2011, 2010 and 2009, we selected a 90 percent deferral of gas cost differences.  In Washington, 100 percent of our gas cost differences are deferred.  See Note 13.

Our financial derivatives policy sets forth the guidelines for using selected derivative products to support prudent risk management strategies within designated parameters.  Our objective for using derivatives is to decrease the volatility of gas prices, earnings and cash flows and to prevent speculative risk. The use of derivatives is permitted only after the risk exposures have been identified, are determined to exceed acceptable tolerance levels and are necessary to support normal business activities.  We do not enter into derivative instruments for trading purposes and we believe that any increase in market risk created by holding derivatives should be offset by the exposures they modify.

Fair Value Of Financial Instruments Policy

Fair Value

In accordance with fair value accounting, we use the following fair value hierarchy for determining inputs for our debt, pension plan assets and 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 assumptions that 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. Fair values are primarily developed using 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; (g) credit spreads; (h) and other relevant economic measures.

Revenue Tax Policy [Text Block]

Revenue Taxes

We account for revenue-based taxes as a separate cost item collected from customers.  Therefore, revenue taxes are accounted for as a cost of sale and presented separately on the income statement.

Income Tax Policy [Text Block]

Income Tax Expense

NW Natural and its wholly-owned subsidiaries file consolidated federal and state income tax returns. Current income taxes are allocated based on each entity's respective taxable income or loss and tax credits as if each entity filed a separate return. We account for income taxes in accordance with accounting standards for income taxes. Accounting for income taxes requires recognition of deferred tax liabilities and assets for the future tax consequences of events that have been included in the consolidated financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse (see Note 10).

Accounting for income taxes also requires recognition of deferred income tax assets and liabilities for temporary differences where regulators prohibit deferred income tax treatment for ratemaking purposes.  We have recorded a deferred tax liability equivalent of $68.5million and $72.3 million at December 31, 2011 and 2010, respectively, to recognize future taxes payable resulting from transactions that have previously been reflected in the financial statements for these temporary differences.  Regulatory assets or liabilities corresponding to such additional deferred income tax assets or liabilities may be recorded to the extent we believe they will be recoverable from or payable to customers through the ratemaking process.  Pursuant to regulatory accounting principles, a corresponding regulatory asset has been recorded which represents the probable future revenue that will result from inclusion in rates charged to customers of taxes which will be paid in the future.  The probable future revenue to be recorded takes into consideration the additional future taxes which will be generated by that revenue.  Amounts applicable to income taxes due from customers primarily represent differences between the book and tax basis of net utility plant in service and actual removal costs incurred.

Deferred investment tax credits on utility plant additions, which reduce income taxes payable, are deferred for financial statement purposes and amortized over the life of the related plant or lease.

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Property, Plant and Equipment (details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Public Utilities Property Plant And Equipment Abstract
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	2.80%	2.80%	2.90%
Weighted Average Depreciation Rates Non Utility	2.20%	2.50%
Asset Removal Costs	$ 267,400,000	$ 252,900,000
Property Plant And Equipment Net By Type Abstract
Property, plant and equipment	2,661,102,000	2,576,402,000
Less: Accumulated depreciation	767,226,000	722,239,000
Total property, plant and equipment - net	1,893,876,000	1,854,163,000
Utility Plant [Member]
Property Plant And Equipment Net By Type Abstract
Property, plant and equipment	2,323,467,000	2,247,952,000
Public Utilities Property Plant And Equipment Construction Work In Progress	36,051,000	29,324,000
Less: Accumulated depreciation	749,603,000	710,214,000
Total property, plant and equipment - net	1,609,915,000	1,567,062,000
Non Utility Plant [Member]
Property Plant And Equipment Net By Type Abstract
Property, plant and equipment	293,205,000	290,038,000
Public Utilities Property Plant And Equipment Construction Work In Progress	8,379,000	9,088,000
Less: Accumulated depreciation	17,623,000	12,025,000
Total property, plant and equipment - net	$ 283,961,000	$ 287,101,000

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Earnings Per Share (details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Earnings per share of common stock [Abstract]
Net income	$ 29,244	$ (8,312)	$ 2,193	$ 40,773	$ 29,591	$ (7,420)	$ 6,888	$ 43,608	$ 63,898	$ 72,667	$ 75,122
Average common shares outstanding - basic									26,687	26,589	26,511
Additional shares for stock based compensation plans									57	68	65
Average common shares outstanding - diluted									26,744	26,657	26,576
Earnings per share of common stock - basic	$ 1.09	$ (0.31)	$ 0.08	$ 1.53	$ 1.11	$ (0.28)	$ 0.26	$ 1.64	$ 2.39	$ 2.73	$ 2.83
Earnings per share of common stock - diluted	$ 1.09	$ (0.31)	$ 0.08	$ 1.53	$ 1.11	$ (0.28)	$ 0.26	$ 1.64	$ 2.39	$ 2.73	$ 2.83
Antidilutive securities excluded from computation of earnings per share Amount									2,101	743	2,142

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Leases (tables)

Dec. 31, 2011

Leases [Abstract]

Schedule Of Future Minimum Lease Payments For Operating And Capital Leases [Table Text Block]

												Later
Thousands		2012		2013		2014		2015		2016		years		Total
Operating leases	$	4,929	$	4,841	$	5,078	$	5,042	$	5,018	$	24,659	$	49,567
Capital leases		443		313		118		23		-		-		897
Minimum lease payments	$	5,372	$	5,154	$	5,196	$	5,065	$	5,018	$	24,659	$	50,464

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Derivative Instruments (details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Summary Of Derivative Instruments Abstract
Cost of sales	$ (458,622,000)	$ (424,534,000)	$ (611,168,000)
General Discussion Of Derivative Instruments And Hedging Activities Abstract
Changes In Fair Value As Deferred Regulatory Assets Or Liabilities In Percentage	80 or a 90 percent
Changes In Fair Value Deferred As Income Statement For Contracts Not Qualifying For Hedge Accounting And To Other Comprehensive Income For Contracts Qualifying For Hedge Accounting	10 or 20 percent
Unrealized Loss on Foreign Currency Derivatives, before Tax	200,000
Unrealized Loss On Derivatives	63,500,000
Derivative Loss On Derivative	56,500,000	61,000,000
Maturity Of Credit Risk Derivatives 1	October 2013
Derivative Fair Value Of Derivative Net	(61,000,000)	(52,600,000)
Natural Gas Commodity [Member]
Summary Of Derivative Instruments Abstract
Cost of sales	60,799,000	52,677,000
Total Comprehensive Income	0	0
Less:Amounts deferred to regulatory accounts on balance sheet	60,799,000	52,677,000
Total Impact On Earnings	0	0
Foreign Currency [Member]
Summary Of Derivative Instruments Abstract
Cost of sales	0	0
Total Comprehensive Income	(201,000)	91,000
Less:Amounts deferred to regulatory accounts on balance sheet	201,000	(91,000)
Total Impact On Earnings	0	0
Moodys A3 Rating [Member]
Description Of Credit Risk Related Contingent Features Abstract
With Adequate Assurance Calls	0
Without Adequate Assurance Calls	0
Moodys Baa 1 Rating [Member]
Description Of Credit Risk Related Contingent Features Abstract
With Adequate Assurance Calls	0
Without Adequate Assurance Calls	0
Moodys Baa 2 Rating [Member]
Description Of Credit Risk Related Contingent Features Abstract
With Adequate Assurance Calls	2,013,000
Without Adequate Assurance Calls	851,000
Moodys Baa 3 Rating [Member]
Description Of Credit Risk Related Contingent Features Abstract
With Adequate Assurance Calls	9,585,000
Without Adequate Assurance Calls	5,923,000
Speculative [Member]
Description Of Credit Risk Related Contingent Features Abstract
With Adequate Assurance Calls	45,869,000
Without Adequate Assurance Calls	$ 37,206,000

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Short-Term Debt (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Short-term Debt [Abstract]
Commercial Paper	$ 141.60	$ 257.40
Short-term Debt, Weighted Average Interest Rate	0.30%	0.40%
Bank Loans	0	0
Line of Credit Facility, Current Borrowing Capacity	250.00
Line of Credit Facility, Expiration Date	May 31, 2013
Line of Credit Facility, Maximum Borrowing Capacity	400.00
Line of Credit Facility, Amount Outstanding	$ 0
Line of Credit Facility, Covenant Terms	The syndicated credit agreement requires that we maintain credit ratings with Standard & Poor’s (S&P) and Moody’s Investors Service, Inc. (Moody’s) and notify the lenders of any change in our senior unsecured debt ratings by such rating agencies. A change in our debt ratings is not an event of default, nor is the maintenance of a specific minimum level of debt rating a condition of drawing upon the credit facility. However, interest rates on any loans outstanding under the credit facility are tied to debt ratings, which would increase or decrease the cost of any loans under the credit facility when ratings are changed. There were no changes in our credit ratings during 2011. The syndicated credit agreement also requires us to maintain a consolidated indebtedness to total capitalization ratio of 70 percent or less. Failure to comply with this covenant would entitle the lenders to terminate their lending commitments and accelerate the maturity of all amounts outstanding. We were in compliance with this covenant at December 31, 2011 and 2010.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Disclosure Summary Of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies Text Block

2.Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America (U.S. GAAP) requires management to make estimates and assumptions that affect reported amounts in the consolidated financial statements and accompanying notes.  Actual amounts could differ from those estimates, and changes would most likely be reported in future periods.  Management believes that the estimates and assumptions used are reasonable.

Industry Regulation

Our principal businesses are the distribution of natural gas, which is regulated by the Public Utility Commission of Oregon (OPUC) and Washington Utilities and Transportation Commission (WUTC), and natural gas storage services, which are regulated by either the Federal Energy Regulatory Commission (FERC) or the California Public Utilities Commission (CPUC), and to a certain extent by the OPUC.  Accounting records and practices of our regulated businesses conform to the requirements and uniform system of accounts prescribed by these regulatory authorities in accordance with U.S. GAAP.  Our businesses regulated by the OPUC, WUTC and FERC earn a reasonable return on invested capital from approved cost-based rates, while our business regulated by the CPUC earns a return to the extent we are able to charge competitive prices above our costs (i.e. market-based rates).

In applying regulatory accounting principles, we capitalize or defer certain costs and revenues as regulatory assets and liabilities pursuant to orders of the OPUC or WUTC, which provides for the recovery of revenues or expenses from, or refunds to, utility customers in future periods, including a return or a carrying charge in most cases.

At December 31, 2011 and 2010, the amounts deferred as regulatory assets and liabilities were as follows:

			Regulatory Assets
Thousands			2011		2010
Current:
	Unrealized loss on derivatives(1)	$	57,317	$	38,437
	Pension and other postretirement benefit liabilities(2)		15,491		10,988
	Other(3)		21,865		3,289
Total current		$	94,673	$	52,714
Non-current:
	Unrealized loss on derivatives(1)	$	6,536	$	17,022
	Income tax asset		65,264		72,341
	Pension and other postretirement benefit liabilities(2)		170,512		118,248
	Environmental costs(4)		105,670		114,311
	Other(3)		23,410		26,975
Total non-current		$	371,392	$	348,897

			Regulatory Liabilities
Thousands			2011		2010
Current:
	Gas costs	$	17,994	$	15,583
	Unrealized gain on derivatives(1)		2,853		2,245
	Other(3)		10,199		-
Total current		$	31,046	$	17,828
Non-current:
	Gas costs	$	8,420	$	2,297
	Unrealized gain on derivatives(1)		-		628
	Accrued asset removal costs		267,355		252,941
	Other(3)		2,607		2,165
Total non-current		$	278,382	$	258,031

• An 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 annual Purchased Gas Adjustment mechanism when realized at settlement.
• 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 include an interest component when recognized in net periodic benefit costs or earn a rate of return or carrying charge (see Note 9).
• 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.
• Environmental costs are related to those sites that are approved for regulatory deferral.  In Oregon, we earn a rate of return on amounts paid, whereas amounts accrued but not yet paid do not earn a rate of return or a carrying charge until expended. Environmental costs related to Washington were deferred beginning in 2011, with cost recovery and carrying charge to be determined in a future proceeding.

The amortization period for our regulatory assets and liabilities ranges from less than one year to an undeterminable period.  Our regulatory deferrals for gas costs payable are generally amortized over 12 months beginning each

November 1 following the gas contract year during which the deferred gas costs are realized.  Similarly, most of our regulatory deferred accounts are amortized over 12 months.  However, certain regulatory account balances, such as income taxes, environmental costs, pension liabilities and accrued asset removal costs, are large and tend to be amortized over longer periods once we have agreed upon an amortization period with the respective regulatory agency.

We believe that continued application of regulatory accounting for these activities is appropriate and consistent with the current regulatory environment, and that all regulated assets and liabilities at December 31, 2011 and 2010 will be recoverable or refundable through future rate making decisions.  We annually review all regulatory assets and liabilities for recoverability and more often if circumstances warrant.  If we should determine that all or a portion of these regulatory assets or liabilities no longer meet the criteria for continued application of regulatory accounting, then we would be required to write off the net unrecoverable balances against earnings.

New Accounting Standards

Adopted Standards

Fair Value Disclosures.In January 2011, 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. The adoption of this standard did not have a material effect 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 have elected to early adopt this standard and present net income and other comprehensive income in one continuous statement.

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 has been adopted as shown in Note 9.

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.

Balance Sheet Offsetting.In December 2011, the FASB issued authoritative guidance regarding the offsetting of assets and liabilities on the balance sheet. The revised standard is intended to provide more comparable guidance between the U.S. GAAP and international accounting standards by requiring entities to disclose both gross and net amounts for assets and liabilities offset on the balance sheet as well as other disclosures concerning their enforceable master netting arrangements. This guidance is effective for annual reporting periods beginning after January 1, 2013 and we are currently assessing the impact on our financial statement disclosures.

Plant, Property and Accrued Asset Removal Costs

Plant and property are stated at cost, including capitalized labor, materials and overhead (see Note 11).  In accordance with regulatory accounting standards, the cost of acquiring and constructing long-lived plant and property generally includes an allowance for funds used during construction (AFUDC) or capitalized interest.  AFUDC represents the regulatory financing cost incurred when debt and equity funds are used for construction (see “Allowance for Funds Used During Construction,” below).  When constructed assets are subject to market-based rates rather than cost-based rates, then the financing cost incurred during construction are includedin capitalized interest inaccordance with U.S. GAAP, not regulatory financing cost under AFUDC.

In accordance with long-standing regulatory treatment, our depreciation rates are comprised of three components: one based on the average service life of the asset, a second based on the estimated salvage value of the asset, and a third based on the asset's cost of removal. We collect, through rates, the estimated cost of removal on certain regulated properties through depreciation expense, with a corresponding offset to accumulated depreciation.  These removal costs are non-legal obligations as defined by regulatory accounting guidance. Therefore, we have included these costs in non-current regulatory liabilities on our consolidated balance sheets. In the rate setting process, the liability for the removal costs is treated as a reduction to the net rate base upon which the regulated utility has the opportunity to earn its allowed rate of return.

Our provision for depreciation of utility plant and property is computed under the straight-line method in accordance with engineering studies approved by regulatory authorities. The weighted average depreciation rate for utility assets in service was approximately 2.8percentin2011 and 2010, and 2.9 percent in2009reflecting the approximate average economic life of the property.This includes 2011 weighted average depreciation rates for the following asset categories:2.7 percent for transmission and distribution plant, 2.2 percent for gas storage facilities, 4.6 percent for general plant, and 5.1 percent for intangible and other fixed assets.

Allowance for Funds Used During Construction

Certain additions to utility plant include AFUDC, which represents the net cost of debtand equity funds used during construction. AFUDC is calculated using actual interest rates for debt and authorized rates for return on equity, if applicable. If short-term debt balances are less than the total balance of construction work in progress, then a composite AFUDC rate is used to represent interest on all debt funds, shown as a reduction to interest charges, and a return on equity funds, shown as other income. While cash is not immediately recognized from recording AFUDC, it is realized in future years through rate recovery resulting from the higher utility cost of service. Our composite AFUDC rates were 0.5percent in 2011, 0.6 percent in 2010 and 1.0 percent in 2009.

Cash and Cash Equivalents

For purposes of reporting cash flows, cash and cash equivalents include cash on hand plus highly liquid investment accounts with maturity dates of three months or less. At December 31, 2011, outstanding checks of approximately $3.9 million were included in accounts payable.

Revenue Recognition and Accrued Unbilled Revenues

Utility revenues, derived primarily from the sale and transportation of natural gas, are recognized upon delivery of gas commodity or service to customers.  Revenues include accruals for gas delivered but not yet billed to customers based on estimates of deliveries from meter reading dates to month end (accrued unbilled revenues). Accrued unbilled revenues are dependent upon a number of factors that require management's judgment, including total gas receipts and deliveries, customer use by billing cycle and weather factors.  Accrued unbilled revenues are reversed the following month when actual billings occur. Our accrued unbilled revenues at December 31, 2011 and 2010were $61.9 million and $64.8 million, respectively.

From 2007 through 2010, 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 based on estimates of the annual amount to be recognized. On May 24, 2011, SB 408 was repealed and replaced by Senate Bill 967. SB 967 required utilities to eliminate amounts accrued under SB 408 for the 2010 and 2011 tax years, thereby denying recovery by NW Natural of the surcharge accrued for 2010, which resulted in a one-time pre-tax charge of $7.4 million in the second quarter of 2011. Pursuant to SB 967, we changed our revenue recognition policy effective January 1, 2011 and no longer recognize a regulatory adjustment for income taxes for SB 408.

Non-utility revenues are derived primarily from the gas storage business segment. At Mist, revenues are recognized upon delivery of services to customers.  Revenues from our asset management partner are recognized over the life of the asset management contract for guaranteed amounts, if any, and are recognized as earned for amounts above the guaranteed amount. At Gill Ranch, firm storage services resulting from short-term and long-term contracts are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized.Asset management revenue is recognized using a straight-line, pro rata methodology over the term of each contract and provides us with 80 percent of the pre-tax income from our independent energy marketing company. See Note 4.

Accounts Receivable and Allowance for Uncollectible Accounts

Accounts receivable consist primarily of amounts due for natural gas sales and transportation services to core utility customers, plus amounts due for gas storage services.  With respect to these trade receivables, including accrued unbilled revenues, we establish an allowance for uncollectible accounts (allowance) based on the aging of receivables, collection experience of past due account balances including payment plans, and historical trends of write-offs as a percent of revenues.  With respect to large individual customer receivables, a specific allowance is established and added to the general allowance when amounts are identified as unlikely to be partially or fully recovered.  Inactive accounts are written-off against the allowance after they are 120 days past due or when deemed to be uncollectible.  Differences between our estimated allowance and actual write-offs will occur based on a number of factors, including changes in economic conditions, customer credit worthiness and the level of natural gas prices.  Each quarter the allowance for uncollectible accounts is adjusted, as necessary, based on information currently available.

Inventories

Utility gas inventories, which consist of natural gas in storage for the utility, are generally stated at the lower of average cost or net realizable value. The regulatory treatment of utility gas inventories provides for cost recovery in customer rates.  Utility gas inventories that are injected into storage are priced into inventory based on actual purchase costs. Utility gas inventories that are withdrawn from storage are charged to cost of gas during the current period at the weighted average inventory cost.

Gas Storageinventories, which primarily represent inventories at Gill Ranch, exclude cushion gas and consist of natural gas that we received as fuel-in-kind from storage customers. Gas Storage inventories are valued at the lower of average cost or net realizable value. Cushion gas is recorded at original cost and classified as long-term assets.

Material and supplies inventories, which consist of both utility and non-utility inventories, are stated at the lower of average cost or net realizable value.

Our utility and gas storage inventories totaled $65.6 million and $70.7 million at December 31, 2011 and 2010, respectively, and our materials and supplies inventories totaled $8.8 million and $9.7 million at December 31, 2011 and 2010, respectively.

Gas Reserves

Our gas reserves are stated at cost, adjusted for regulatory amortization, with the associated deferred tax benefits recorded as liabilities on the balance sheet. Transactional costs to enter into the agreement (see Note 12) and payments by NW Natural to Encana Oil & Gas (USA) Inc. (Encana) are recognized as gas reserves on the balance sheet.  The current portion is calculated based on expected gas deliveries within the next fiscal year.  We recognize regulatory amortization of this asset on a volumetric basis and calculate using the proven reserves and the therms extracted and sold each month.  The amortization of gas reserves is recorded as an adjustment to the cost of gas.

Derivatives

In accordance with accounting for derivatives and hedges, we measure derivatives at fair value and recognize them as either assets or liabilities on the balance sheet.  Accounting for derivatives requires that changes in the fair value be recognized currently in earnings unless specific hedge accounting criteria are met.  Accounting for derivatives and hedges provides an exception for contracts intended for normal purchases and normal sales for which physical delivery is probable.  In addition, certain derivative contracts are approved by regulatory authorities for recovery or refund through customer rates.  Accordingly, the changes in fair value of these approved contracts are deferred as regulatory assets or liabilities pursuant to regulatory accounting principles.  Derivative contracts entered into for core utility customer requirements after the annual purchased gas adjustment (PGA) rate has been set are subject to the PGA incentive sharing mechanism. Effective November 1, 2008, Oregon approved a PGA sharing mechanism under which we are required to select either an 80 percent deferral or 90 percent deferral of higher or lower gas costs such that the impact on current earnings from the gas cost sharing is either 20 percent or 10 percent of gas cost differences compared to PGA prices, respectively. For the PGA years in Oregon beginning November 1, 2011, 2010 and 2009, we selected a 90 percent deferral of gas cost differences.  In Washington, 100 percent of our gas cost differences are deferred.  See Note 13.

Our financial derivatives policy sets forth the guidelines for using selected derivative products to support prudent risk management strategies within designated parameters.  Our objective for using derivatives is to decrease the volatility of gas prices, earnings and cash flows and to prevent speculative risk. The use of derivatives is permitted only after the risk exposures have been identified, are determined to exceed acceptable tolerance levels and are necessary to support normal business activities.  We do not enter into derivative instruments for trading purposes and we believe that any increase in market risk created by holding derivatives should be offset by the exposures they modify.

Fair Value

In accordance with fair value accounting, we use the following fair value hierarchy for determining inputs for our debt, pension plan assets and 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 assumptions that 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. Fair values are primarily developed using 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; (g) credit spreads; (h) and other relevant economic measures.

Revenue Taxes

We account for revenue-based taxes as a separate cost item collected from customers.  Therefore, revenue taxes are accounted for as a cost of sale and presented separately on the income statement.

Income Tax Expense

NW Natural and its wholly-owned subsidiaries file consolidated federal and state income tax returns. Current income taxes are allocated based on each entity's respective taxable income or loss and tax credits as if each entity filed a separate return. We account for income taxes in accordance with accounting standards for income taxes. Accounting for income taxes requires recognition of deferred tax liabilities and assets for the future tax consequences of events that have been included in the consolidated financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse (see Note 10).

Accounting for income taxes also requires recognition of deferred income tax assets and liabilities for temporary differences where regulators prohibit deferred income tax treatment for ratemaking purposes.  We have recorded a deferred tax liability equivalent of $68.5million and $72.3 million at December 31, 2011 and 2010, respectively, to recognize future taxes payable resulting from transactions that have previously been reflected in the financial statements for these temporary differences.  Regulatory assets or liabilities corresponding to such additional deferred income tax assets or liabilities may be recorded to the extent we believe they will be recoverable from or payable to customers through the ratemaking process.  Pursuant to regulatory accounting principles, a corresponding regulatory asset has been recorded which represents the probable future revenue that will result from inclusion in rates charged to customers of taxes which will be paid in the future.  The probable future revenue to be recorded takes into consideration the additional future taxes which will be generated by that revenue.  Amounts applicable to income taxes due from customers primarily represent differences between the book and tax basis of net utility plant in service and actual removal costs incurred.

Deferred investment tax credits on utility plant additions, which reduce income taxes payable, are deferred for financial statement purposes and amortized over the life of the related plant or lease.

Subsequent Events

We monitor significant events occurring after the balance sheet date and prior to theissuance of the financial statements to determine the impacts, if any, of events on the financialstatements to be issued. We do not have any subsequent events to report.

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Segment Information (details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Segment Reporting Abstract
Net operating revenues	$ 119,910,000	$ 47,783,000	$ 67,232,000	$ 134,508,000	$ 118,251,000	$ 46,211,000	$ 72,193,000	$ 130,926,000	$ 369,433,000	$ 367,581,000	$ 376,887,000
Depreciation and amortization									70,004,000	65,124,000	62,814,000
Income from operations									144,845,000	157,605,000	158,716,000
Net income	29,244,000	(8,312,000)	2,193,000	40,773,000	29,591,000	(7,420,000)	6,888,000	43,608,000	63,898,000	72,667,000	75,122,000
Total assets	2,746,574,000				2,616,616,000				2,746,574,000	2,616,616,000
Subsidiary Discussion [Abstract]
Percent Of Local Gas Distribution Customers In Oregon	90.00%								90.00%
Percent Of Local Gas Distribution Customers In Washington	10.00%								10.00%
Percent Of Total Local Gas Distribution Volume Attributed To Residential And Commercial Customers	50 to 60 percent								50 to 60 percent
Percent Of Total Local Gas Distribution Margin Attributed To Residential And Commercial Customers	80 to 90 percent								80 to 90 percent
Percent Of Total Local Gas Distribution Volume Attributed To Industrial Customers	40 to 50 percent								40 to 50 percent
Percent Of Total Local Gas Distribution Margin Attributed To Industrial Customers	5 to 15 percent								5 to 15 percent
Remaining Local Gas Margin Attributed To Misc	10.00%								10.00%
Percent Of Pre Tax Income From Gas Storage Retained When The Costs Of The Capacity Are Not In Utility Rates	80.00%								80.00%
Percent Of Pre Tax Income From Gas Storage Retained When The Costs Of The Capacity Are In Utility Rates	33.00%								33.00%
Percent Of Pre Tax Income From Gas Storage Credited To Deferred Regulatory Account	20.00%								20.00%
Percent Of Pre Tax Income From Gas Storage Credited To Deferred Regulatory Account When In Rates	67.00%								67.00%
Percent Ownership In Joint Project	75.00%								75.00%
Precent Interest In Subsidiary	10.00%								10.00%
Total Assets At NNG Financial	1,100,000				1,100,000				1,100,000	1,100,000
Utility Segment [Member]
Segment Reporting Abstract
Net operating revenues									342,970,000	346,148,000	357,005,000
Depreciation and amortization									63,843,000	62,661,000	61,472,000
Income from operations									135,722,000	145,688,000	142,228,000
Net income									60,527,000	66,262,000	65,960,000
Total assets	2,435,888,000				2,310,388,000				2,435,888,000	2,310,388,000
Gas Storage Segment [Member]
Segment Reporting Abstract
Net operating revenues									26,354,000	21,249,000	19,738,000
Depreciation and amortization									6,161,000	2,463,000	1,342,000
Income from operations									9,090,000	11,855,000	16,442,000
Net income									4,101,000	6,110,000	8,923,000
Total assets	294,637,000				282,945,000				294,637,000	282,945,000
Other Segment [Member]
Segment Reporting Abstract
Net operating revenues									109,000	184,000	144,000
Depreciation and amortization									0	0	0
Income from operations									33,000	62,000	46,000
Net income									(730,000)	295,000	239,000
Total assets	$ 16,049,000				$ 23,283,000				$ 16,049,000	$ 23,283,000

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Shares Outstanding (tables)

Dec. 31, 2011

Disclosure Common Stock [Abstract]

Summary Of Common Stock Shares Issued And Outstanding Table [Text Block]

Thousands		Shares
Balance, December 31, 2008		26,501
	Sales to employees under ESPP	9
	Exercise of stock options under Restated SOP - net	23
Balance, December 31, 2009		26,533
	Sales to employees under ESPP	24
	Exercise of stock options under Restated SOP - net	111
Balance, December 31, 2010		26,668
	Sales to employees under ESPP	15
	Exercise of stock options under Restated SOP - net	24
	Sales to shareholders under DRPP	49
Balance, December 31, 2011		26,756

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Segment Reporting (tables)

12 Months Ended

Dec. 31, 2011

Segment Reporting Abstract

Schedule of Segment Reporting Information, by Segment [Table Text Block]

Thousands		Utility		Gas Storage		Other		Total
2011
Net operating revenues	$	342,970	$	26,354	$	109	$	369,433
Depreciation and amortization		63,843		6,161		-		70,004
Income from operations		135,722		9,090		33		144,845
Net income		60,527		4,101		(730)		63,898
Total assets at December 31, 2011		2,435,888		294,637		16,049		2,746,574
2010
Net operating revenues	$	346,148	$	21,249	$	184	$	367,581
Depreciation and amortization		62,661		2,463		-		65,124
Income from operations		145,688		11,855		62		157,605
Net income		66,262		6,110		295		72,667
Total assets at December 31, 2010		2,310,388		282,945		23,283		2,616,616
2009
Net operating revenues	$	357,005	$	19,738	$	144	$	376,887
Depreciation and amortization		61,472		1,342		-		62,814
Income from operations		142,228		16,442		46		158,716
Net income		65,960		8,923		239		75,122

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Valuation Allowances and Reserves (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Valuation and Qualifying Accounts [Abstract]
Allowance For Doubtful Accounts Receivable Current	$ 2,895	$ 2,950	$ 3,125	$ 2,927
Valuation Allowances and Reserves, Charged to Cost and Expense	1,919	1,717	4,201
Valuation Allowances and Reserves, Deductions	1,974	1,892	4,003
Valuation Allowances and Reserves, Charged to Other Accounts	$ 0	$ 0	$ 0

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Common Stock (details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Common Stock Number Of Shares Par Value And Other Disclosures Abstract
Common Stock Shares Authorized	100,000,000	100,000,000
Reserved Shares Employee Stock Purchase Plan	155,955
Reserved Shares Dividend Reinvestment	293,246
Reserved Shares Stock Options	1,159,875
Date Through Which Entity May Repurchase Stock Under Board Authorization	May 2012
Aggregate Authorized Shares To Repurchase	2,800,000
Aggregate Authorized Value Of Shares To Repurchase	$ 100,000,000
Treasury Stock Shares	2,100,000
Treasury Stock Program	$ 83,300,000
Common Stock Shares Issued Table [Abstract]
Common Stock Shares Outstanding	26,756,000	26,668,000	26,533,000	26,501,000
Stock Issued During Period, Shares, Employee Stock Purchase Plans	15,000	24,000	9,000
Common Stock Issued During Period Shares Stock Options Exercised	24,000	111,000	23,000
Stock Issued During Period, Shares, Dividend Reinvestment Plan	49,000

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Stock-Based Compensation (tables)

12 Months Ended

Dec. 31, 2011

Share Based Compensation Abstract

Schedule Of Performance Based Award [Table Text Block]

Performance	Performance Share Awards Outstanding			2011		Cumulative Expense
Period	Threshold	Target	Maximum	Expense		At Dec. 31, 2011
2009-11	7,410	39,000	78,000	$	353	$	763
2010-12	n/a(1)	41,500	83,000		430		718
2011-13	n/a(1)	37,950	75,900		276	$	276
Total		118,450	236,900	$	1,059
(1)The threshold requirement was modified and is no longer applicable beginning in the 2010-12 performance period.

SOP Assumptions [Table Text Block]

		2011		2010		2009
Risk-free interest rate		2.0%		2.3%		2.0%
Expected life (in years)		4.5		4.7		4.7
Expected market price volatility factor		24.5%		23.2%		22.5%
Expected dividend yield		3.8%		3.8%		3.8%
Forfeiture rate		3.1%		3.2%		3.7%
Weighted average grant date fair value	$	6.73	$	6.36	$	5.46

Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]

			Weighted -		Intrinsic
	Option		Average		Value
	Shares		Price Per Share		(In millions)
Balance outstanding, Dec. 31, 2008	396,410	$	38.62	$	2.3
Granted	111,750		41.15		n/a
Exercised	(23,225)		30.92		0.3
Balance outstanding, Dec. 31, 2009	484,935		39.57		2.7
Granted	119,750		44.25		n/a
Exercised	(111,525)		39.01		0.9
Forfeited	(2,700)		43.00		n/a
Balance outstanding, Dec. 31, 2010	490,460		40.82		2.8
Granted	122,700		45.74		n/a
Exercised	(24,185)		33.88		0.3
Forfeited	(9,750)		44.38		n/a
Balance outstanding, Dec. 31, 2011	579,225	$	42.09	$	3.4
Exercisable, Dec. 31, 2011	311,951	$	40.20	$	2.4

Schedule Of Stock Based Compensation Capitalized Under LTIP SOP and ESPP [Table Text Block]

Thousands			2011		2010		2009
Operations and maintenance expense, for stock-based compensation		$	1,477	$	1,032	$	1,434
Income tax benefit			(597)		(418)		(559)
	Net stock-based compensation effect on net income	$	880	$	614	$	875
Amounts capitalized for stock-based compensation		$	261	$	182	$	229

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Cost and Fair Value Basis of Long-Term Debt (tables)

12 Months Ended

Dec. 31, 2011

Long-term Debt Current And Noncurrent Abstract

Schedule of Debt [Table Text Block]

Thousands			2011		2010		2009
Utility Medium-Term Notes:
First Mortgage Bonds:
	4.11 % Series B due 2010	$	-	$	-	$	10,000
	7.45 % Series B due 2010		-		-		25,000
	6.665% Series B due 2011		-		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
	3.95 % Series B due 2014		50,000		50,000		50,000
	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		75,000		75,000		75,000
	9.05 % Series A due 2021		10,000		10,000		10,000
	3.176 % Series A due 2021		50,000		-		-
	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		19,700		19,700		19,700
	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
			641,700		601,700		636,700
Subsidiary Senior Secured Notes:
	Gill Ranch Notes due 2016(1)		40,000		-		-
			681,700		601,700		636,700
	Less current maturities of long-term debt		40,000		10,000		35,000
Total long-term debt		$	641,700	$	591,700	$	601,700

Fair Value Of Long Term Debt Table [Text Block]

		December 31,
Thousands		2011		2010
Carrying amount	$	681,700	$	601,700
Estimated fair value	$	808,724	$	690,126

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Organization and Principles of Consolidation

12 Months Ended

Dec. 31, 2011

Organization And Principles Of Consolidation [Abstract]

Organization Consolidation And Presentation Of Financial Statements Disclosure Text Block

NORTHWEST NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Certain prior year balances in our consolidated financial statements have been combined to conform with the current presentation. These changes had no impact on our prior year's consolidated results of operations, financial condition or cash flows.

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Pension and Other Postretirement Benefits (tables)

12 Months Ended

Dec. 31, 2011

General Discussion Of Pension And Other Postretirement Benefits Abstract

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

			Postretirement Benefit Plans
			Pension Benefits						Other Benefits
Thousands			2011		2010		2009		2011		2010		2009
Reconciliation of change in benefit obligation:
	Obligation at January 1	$	339,338	$	307,991	$	281,127	$	27,676	$	24,741	$	23,863
	Service cost		7,122		6,688		6,402		614		588		522
	Interest cost		18,134		18,029		17,948		1,404		1,436		1,568
	Net actuarial (gain) or loss		44,802		25,275		23,584		2,225		2,387		216
	Benefits paid		(18,269)		(18,645)		(17,149)		(1,870)		(1,476)		(1,428)
	Plan amendments		-		-		(3,921)		-		-		-
	Obligation at December 31	$	391,127	$	339,338	$	307,991	$	30,049	$	27,676	$	24,741
Reconciliation of change in plan assets:
	Fair value of plan assets at January 1	$	219,014	$	201,312	$	163,115	$	-	$	-	$	-
	Actual return on plan assets		(6,684)		24,651		28,641		-		-		-
	Employer contributions		21,909		11,696		26,705		1,870		1,476		1,428
	Benefits paid		(18,269)		(18,645)		(17,149)		(1,870)		(1,476)		(1,428)
	Fair value of plan assets at December 31	$	215,970	$	219,014	$	201,312	$	-	$	-	$	-
Funded status at December 31		$	(175,157)	$	(120,324)	$	(106,679)	$	(30,049)	$	(27,676)	$	(24,741)

Schedule Of Amounts Recognized In Other Comprehensive Income Loss Table Text Block

			Regulatory Asset Amortization												AOCI Amortization
			Pension Benefits					Other Postretirement Benefits							Pension Benefits
Thousands			2011		2010		2009		2011		2010		2009		2011		2010		2009
Net periodic benefit costs:
	Actuarial loss	$	10,731	$	6,740	$	6,189	$	289	$	131	$	17	$	854	$	707	$	449
	Prior service cost		230		230		1,260		197		197		197		122		(43)		(37)
	Transition obligation		-		-		-		411		411		411		-		-		-
Total		$	10,961	$	6,970	$	7,449	$	897	$	739	$	625	$	976	$	664	$	412

Schedule of Allocation of Plan Assets [Table Text Block]

	Target
Asset Category	Allocation
U.S. large cap equity	15.0%
U.S. small/mid cap equity	10.0%
Non-U.S. equity	14.5%
Emerging markets equity	3.5%
Long government/credit	24.0%
High yield	5.0%
Emerging market debt	5.0%
Real estate funds	5.8%
Absolute return strategy	12.0%
Real return strategy	5.2%

Net Periodic Benefit Cost Components

				Pension Benefits						Other Postretirement Benefits
Thousands				2011		2010		2009		2011		2010		2009
	Service cost		$	7,122	$	6,688	$	6,402	$	614	$	588	$	522
	Interest cost			18,134		18,029		17,948		1,404		1,436		1,568
	Expected return on plan assets			(17,867)		(18,207)		(15,696)		-		-		-
	Amortization of transition
		obligations		-		-		-		411		411		411
	Amortization of prior service costs			352		187		1,223		197		197		197
	Amortization of net actuarial loss			11,584		7,447		6,810		289		131		-
		Net periodic benefit cost		19,325		14,144		16,687		2,915		2,763		2,698
	Amount allocated to construction			(4,905)		(3,729)		(4,636)		(878)		(904)		(858)
	Amount deferred to regulatory
		balancing account		(6,008)		-		-		-		-		-
		Net amount charged to expense	$	8,412	$	10,415	$	12,051	$	2,037	$	1,859	$	1,840

Sensitivity Analysis Of Retirement Benefit Costs and Benefit Obligations [Table Text Block]

			Impact on 2011	Impact on Retirement
		Change in	Retirement	Benefit Obligations
Thousands, except percent		Assumption	Benefit Costs	at Dec. 31, 2011
Discount rate:		(0.25%)
	Qualified defined benefit plans		$ 1,162	$ 11,796
	Non-qualified plans		8	53
	Other postretirement benefits		54	754
Expected long-term return on plan assets:		(0.25%)
	Qualified defined benefit plans		580	N/A

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]

Thousands		1% Increase		1% Decrease
Effect on net periodic postretirement health care benefit cost	$	67	$	(60)
Effect on the accumulated postretirement benefit obligation	$	678	$	(613)

Defined Benefit Plan Estimated Future Employer Contributions Benefit Payments and Estimated Future Payments [Table Text Block]

Thousands
	Employer Contributions			Pension Benefits		Other Benefits
		2010	$	12,088	$	1,476
		2011		22,325		1,870
		2012 (estimated)		30,109		2,056
	Benefit Payments
		2009		17,149		1,428
		2010		18,645		1,476
		2011		18,269		1,870
	Estimated Future Payments
		2012		19,374		2,056
		2013		19,620		2,083
		2014		20,107		2,138
		2015		20,640		2,149
		2016		21,284		2,198
		2017-2021		122,680		11,298

Schedule of Changes in Fair Value of Plan Assets [Table Text Block]

		December 31, 2011
Investments, in thousands				Level 1		Level 2		Level 3		Total
U.S. large cap equity			$	36,236	$	-	$	-	$	36,236
U.S. small/mid cap equity				-		27,310		-		27,310
Non-U.S. equity				22,158		11,587		-		33,745
Emerging markets equity				10,208		-		-		10,208
Fixed income				19,121		-		-		19,121
Long government/credit				-		18,897		-		18,897
Real estate funds				-		-		15,317		15,317
Absolute return strategy				-		30,475		-		30,475
Real return strategy				15,475		-		-		15,475
Cash and cash equivalents				-		9,290		-		9,290
	Total investments		$	103,198	$	97,559	$	15,317	$	216,074
		December 31, 2010
Investments, in thousands				Level 1		Level 2		Level 3		Total
U.S. large cap equity			$	37,231	$	-	$	-	$	37,231
U.S. small/mid cap equity				-		27,864		-		27,864
Non-U.S. equity				24,630		14,549		-		39,179
Emerging markets equity				11,476		-		-		11,476
Fixed income				36,429		-		-		36,429
Real estate funds				-		-		14,721		14,721
Absolute return strategy				-		32,378		-		32,378
Real return strategy				15,452		-		-		15,452
Cash and cash equivalents				-		3,629		-		3,629
	Total investments		$	125,218	$	78,420	$	14,721	$	218,359
							December 31,
Receivables								2011		2010
Accrued interest and dividend income							$	414	$	249
Due from broker for securities sold								321		448
	Total receivables						$	735	$	697
Liabilities
Due to broker for securities purchased							$	839	$	42
	Total investment in retirement trust						$	215,970	$	219,014

Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets [Table Text Block]

				Level 3 Assets
Thousands				Real estate Funds
January 1, 2011 balance			$	14,721
	Total gains or (losses):
		Included in earnings (or changes in net assets)		596
December 31, 2011 balance			$	15,317

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Valuation Allowances and Reserves (tables)

12 Months Ended

Dec. 31, 2011

Summary Of Valuation Allowance [Abstract]

Summary of Valuation Allowance [Table Text Block]

NORTHWEST NATURAL GAS COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
COLUMN A	COLUMN B		COLUMN C				COLUMN D		COLUMN E
			Additions				Deductions
	Balance at		Charged to		Charged to				Balance at
	beginning		costs and		other		Net		end of
Thousands (year ended Dec. 31)	of period		expenses		accounts		Write-offs		period
2011
Reserves deducted in balance sheet from assets to which they apply:
Allowance for uncollectible accounts	$	2,950	$	1,919	$	-	$	1,974	$	2,895
2010
Reserves deducted in balance sheet from assets to which they apply:
Allowance for uncollectible accounts	$	3,125	$	1,717	$	-	$	1,892	$	2,950
2009
Reserves deducted in balance sheet from assets to which they apply:
Allowance for uncollectible accounts	$	2,927	$	4,201	$	-	$	4,003	$	3,125

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Leases (details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Leases [Abstract]
Land Buildings And Equipment Expiration Date	various years through 2095
Operating Leases, Rent Expense, Minimum Rentals	$ 5,400,000	$ 5,100,000	$ 5,300,000
Operating And Capital Leases Table [Abstract]
Operating Leases, Future Minimum Payments Due, Current	4,929,000
Operating Leases, Future Minimum Payments, Due in Two Years	4,841,000
Operating Leases, Future Minimum Payments, Due in Three Years	5,078,000
Operating Leases, Future Minimum Payments, Due in Four Years	5,042,000
Operating Leases, Future Minimum Payments, Due in Five Years	5,018,000
Operating Leases, Future Minimum Payments, Due Thereafter	24,659,000
Operating Leases, Future Minimum Payments Due	49,567,000
Capital Leases, Future Minimum Payments Due, Current	443,000
Capital Leases, Future Minimum Payments Due in Two Years	313,000
Capital Leases, Future Minimum Payments Due in Three Years	118,000
Capital Leases, Future Minimum Payments Due in Four Years	23,000
Capital Leases, Future Minimum Payments Due in Five Years	0
Capital Leases, Future Minimum Payments Due Thereafter	0
Capital Leases, Future Minimum Payments Due	897,000
Future Minimum Payments Due Current	5,372,000
Future Minimum Payments Due In Two Years	5,154,000
Future Minimum Payments Due In Three Years	5,196,000
Future Minimum Payments Due In Four Years	5,065,000
Future Minimum Payments Due In Five Years	5,018,000
Future Minimum Payments Due Thereafter	24,659,000
Future Minimum Payments Due Total	$ 50,464,000

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Consolidated Statements of Income and Comprehensive Income (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating revenues:
Gross operating revenues	$ 848,796	$ 812,106	$ 1,012,711
Less: Cost of sales	458,622	424,534	611,168
Revenue taxes	20,741	19,991	24,656
Net operating revenues	369,433	367,581	376,887
Operating expenses:
Operations and maintenance	125,303	120,980	127,104
General taxes	29,281	23,872	28,253
Depreciation and amortization	70,004	65,124	62,814
Total operating expenses	224,588	209,976	218,171
Income from operations	144,845	157,605	158,716
Other income and expense - net	4,523	7,102	3,714
Interest expense - net	42,088	42,578	40,637
Income before income taxes	107,280	122,129	121,793
Income tax expense	43,382	49,462	46,671
Net income	63,898	72,667	75,122
Comprehensive Income [Abstract]
Change in non-qualified employee benefit plan liability, net of tax	(1,779)	(1,027)	(1,936)
Amortization of non-qualified employee benefit plan liabiliy, net of tax	583	391	354
Other Comprehensive Income (Loss), Net of Tax	$ 62,702	$ 72,031	$ 73,540
Average common shares outstanding:
Basic	26,687	26,589	26,511
Diluted	26,744	26,657	26,576
Earnings per share of common stock [Abstract]
Earnings per share of common stock - basic	$ 2.39	$ 2.73	$ 2.83
Earnings per share of common stock - diluted	$ 2.39	$ 2.73	$ 2.83
Dividends declared per share of common stock	$ 1.75	$ 1.68	$ 1.60

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Stock-Based Compensation (details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
ESPP Paragraph [Abstract]
Percent Of Offering Date Price Employees Are Allowed To Purchase Stock	85.00%
Maximum Value Of Stock Employees Are Allowed To Purchase	$ 21,210
LTIP Paragraph 2 [Abstract]
Weighted-average per share grant date fair value of unvested shares	$ 25.06	$ 23.1
Weighted-average per share grant date fair value of vested shares	$ 22.35
Weighted-average per share grant date fair value of granted shares	$ 19.38
LTIP Table 1 [Abstract]
Threshold For 2009 To 2011 LTIP Period	7,410
Target LTIP Award For Period Vesting In Current Year	39,000
Target LTIP Award For Period Vesting Next Year	41,500
Target LTIP Award For Period Vesting In Two Years	37,950
Target LTIP Award For All Periods	118,450
Maximum LTIP Award For Period Vesting In Current Year	78,000
Maximum LTIP Award For Period Vesting Next Year	83,000
Maximum LTIP Award For Period Vesting In Two Years	75,900
Maximum LTIP Award For All Periods	236,900
Current Year Expense LTIP Award For Period Vesting In Current Year	353,000
Current Year Expense LTIP Award For Period Vesting Next Year	430,000
Current Year Expense LTIP Award For Period Vesting In Two Years	276,000
Current Year Expense LTIP Award For All Periods	1,059,000
Cumulative Expense LTIP Award For Period Vesting In Current Year	763,000
Cumulative Expense LTIP Award For Period Vesting Next Year	718,000
Cumulative Expense LTIP Award For Period Vesting In Two Years	276,000
Share Based Compensation Arrangement By Share Based Payment Award Additional General Disclosures Abstract
LTIP Shares Authorized	600,000
LTIP Shares Available for Award	337,788
LTIP Vesting Period	three-year performance periods
Awarded LTIP shares (or estimated at yearend)	8,428	8,257	15,900
LTIP expense		200,000	500,000
Cumulative LTIP Expense Evaluation Period Vested In Prior Year	700,000
Cumulative LTIP Expense Evaluation Period Vested Two Years Ago	1,500,000
Share Based Compensation Arrangement By Share Based Payment Award Options Additional Disclosures Abstract
SOP shares authorized	2,400,000
SOP shares available for grant	580,650
SOP Vesting	up to 10 years and 7 days
Fair value pricing model SOP	Black-Scholes
SOP Paragraph 2 [Abstract]
Cash received for options exercised	800,000
Tax benefit for cash received for options exercised	26,000
Fair value of options vested	600,000	500,000	400,000
Weighted average remaining life of exercisable options	5.5
Outstanding average remaining life in years	6.8
Unrecognized compensation cost	1,000,000
Unrecognized compensation cost, period for recognition	2014
SOP Table 1 [Abstract]
Risk-free interest rate	2.00%	2.30%	2.00%
Expected life (in years)	4.5	4.7	4.7
Expected market price volatility factor	24.50%	23.20%	22.50%
Expected dividend yield	3.80%	3.80%	3.80%
Forfeiture rate	3.10%	3.20%	3.70%
Weighted-average grant date fair value of SOP shares granted	$ 6.73	$ 6.36	$ 5.46
SOP Table 2 [Abstract]
Number of Outstanding Options	579,225	490,460	484,935	396,410
Shares granted under SOP	122,700	119,750	111,750
Number of Options Exercised	(24,185)	(111,525)	(23,225)
Number of Options Forfeited	(9,750)	(2,700)	0
Weighted average option price at balance sheet date	$ 42.09	$ 40.82	$ 39.57	$ 38.62
Stock Price On Stock Option Plan Grant Date	$ 45.74	$ 44.25	$ 41.15
Weighted average price of options exercised	$ 33.88	$ 39.01	$ 30.92
Weighted average price of options forfeited	$ 44.38	$ 43.00
Intrinsic Value of options outstanding	3,400,000	2,800,000	2,700,000	2,300,000
Intrinsic Value of options exercised	300,000	900,000	300,000
Exercisable stock options	311,951
Weighted average exercise prices of exercisable options	$ 40.20
Aggregate intrinsic value of exercisable options	2,400,000
Stock Based Compensation FS Impact Summary Table [Abstract]
Stock Based Compensation Charged To Operations And Maintenance	1,477,000	1,032,000	1,434,000
Income Tax Benefit Of Stock Based Compensation	(597,000)	(418,000)	(559,000)
Net Income Impact Of Stock Based Compensation	880,000	614,000	875,000
Stock Based Compensation Capitalized	$ 261,000	$ 182,000	$ 229,000

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Consolidated Statement of Shareholders' Equity (USD $) In Thousands	Total	Common Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]
Beginning balance at Dec. 31, 2008	$ 628,373	$ 336,754	$ 296,005	$ (4,386)
Other Comprehensive Income (Loss), Net of Tax	73,540		75,122	(1,582)
Restricted stock amortizations	39	39
Dividends paid on common stock	(42,415)		(42,415)
Tax benefit from employee stock option plan	229	229
Stock-based compensation	(776)	(776)
Issuance of common stock	1,115	1,115
Ending balance at Dec. 31, 2009	660,105	337,361	328,712	(5,968)
Other Comprehensive Income (Loss), Net of Tax	72,031		72,667	(636)
Dividends paid on common stock	(44,652)		(44,652)
Tax benefit from employee stock option plan	(125)	(125)
Stock-based compensation	554	554
Issuance of common stock	5,188	5,188
Ending balance at Dec. 31, 2010	693,101	342,978	356,727	(6,604)
Other Comprehensive Income (Loss), Net of Tax	62,702		63,898	(1,196)
Dividends paid on common stock	(46,690)		(46,690)
Tax benefit from employee stock option plan	(26)	(26)
Stock-based compensation	1,769	1,769
Issuance of common stock	3,632	3,632
Common Stock Expense	0	30	(30)
Ending balance at Dec. 31, 2011	$ 714,488	$ 348,383	$ 373,905	$ (7,800)

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Investments

Dec. 31, 2011

Investments [Abstract]

Schedule Of Long Term Investments [Table Text Block]

Thousands			2011		2010
Investments in life insurance policies		$	51,911	$	51,090
Investments in gas pipeline joint ventures			14,340		15,742
Other			2,012		2,262
	Total other investments	$	68,263	$	69,094

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Commitments and Contigencies

12 Months Ended

Dec. 31, 2011

Disclosure Commitments And Contingencies [Abstract]

Commitments and Contingencies Text Block

15.Commitments and Contingencies

Gas Purchase and Pipeline Capacity Purchase and Release Commitments

We have signed agreements providing for the reservation of firm pipeline capacity under which we are required to make fixed monthly payments for contracted capacity.  The pricing component of the monthly payment is established, subject to change, by U.S. or Canadian regulatory bodies.  In addition, we have entered into long-term sale agreements to release firm pipeline capacity.  We also enter into short-term and long-term gas purchase agreements.  The aggregate amounts of these agreements were as follows at December 31, 2011:

					Pipeline		Pipeline
			Gas		Capacity		Capacity
			Purchase		Purchase		Release
Thousands			Agreements		Agreements		Agreements
2012		$	98,534	$	91,027	$	3,464
2013			18,331		87,983		-
2014			15,290		82,898		-
2015			5,651		72,316		-
2016			-		61,358		-
Thereafter			-		287,541		-
	Total		137,806		683,123		3,464
	Less: Amount representing interest		682		99,252		2
	Total at present value	$	137,124	$	583,871	$	3,462

Our total payments for fixed charges under capacity purchase agreements in 2011, 2010 and 2009 were $94.2million, $91.4 million and $84.6 million, respectively.  Included in the amounts were reductions for capacity release sales of $3.1 million for 2011and $4.2 million for 2010 and2009.  In addition, per-unit charges are required to be paid based on the actual quantities shipped under the agreements.  In certain take-or-pay purchase commitments, annual deficiencies may be offset by prepayments subject to recovery over a longer term if future purchases exceed the minimum annual requirements.

Environmental Matters

We own, or previously owned, properties that may require environmental remediation or action.  We recognize an environmental liability when it is probable the liability exists and the amount is reasonably estimable. We estimate the duration and extent of our remediation obligations based upon reports of outside consultants; internal analyses of clean-up costs and ongoing monitoring costs; communications with regulatory agencies; and changes in environmental law. If we were to determine that our estimates of the duration or extent of our environmental obligations were no longer accurate, we would adjust our environmental liabilities accordingly in the period that such determination is made. Estimated future expenditures for environmental remediation are not discounted to their present value. Accrued environmental liabilities are not reduced by potential insurance reimbursements. 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 which could be material. 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 estimate the range of loss for environmental liabilities using current technology, enacted laws and regulations, industry experience gained at similar sites and an assessment of the probable level of involvement and financial condition of other potentially responsible parties.  Unless there is an estimate within this range of possible losses that is more likely than other cost estimates, we record the liability at the lower end of this range.  It is likely that changes in these estimates and ranges will occur throughout the remediation process for each of these sites due to uncertainty concerning our responsibility, the complexity of environmental laws and regulations and the selection of potentially compliant remediation alternatives.  The status of each of the sites currently under investigation is provided below.

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.

Gasco site. We own property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 (Gasco site). The Gasco site has been under investigation by us for environmental contamination under the Oregon Department of Environmental Quality's (ODEQ) Voluntary Clean-Up Program. In June 2003, we filed a Feasibility Scoping Plan and an Ecological and Human Health Risk Assessment with the ODEQ, which outlined a range of compliant remedial alternatives for the most contaminated portion of the Gasco site. In May 2007, we completed a revised Remediation Investigation Report and submitted it to the ODEQ for review.  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 of 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 $12 million at December 31, 2011. The range of liability will be reassessed when ODEQ makes a final source control design decision, expected later this year.

In addition to groundwater source control, we signed a joint Order on Consent with the Environmental Protection Agency (EPA), which requires us to design remedial action for sediments from the Gasco site. This design project is underway. We also have other investigation and clean-up work, including potential work on the uplands portion of the Gasco site. For the sediments project and upland work, we have recorded an additional accrued liability of $49.2 million, which reflects the low end of the range of potential liability. We have accrued at the low end of the range of potential liability for the work at the Gasco site 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. However, during 2012, we expect EPA to complete a feasibility study that will provide additional cost information about the sediment cleanup work.

Siltronic site.We previously owned property adjacent to the Gasco site that now is the location of a manufacturing plant owned by Siltronic Corporation (Siltronic site). We are currently conducting an investigation of manufactured gas plant wastes on the uplands at this site for the ODEQ.  The liability accrued at December 31, 2011for the Siltronic site is $1.0 million, which is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another, and the high end of the range cannot reasonably be estimated.

Portland Harbor site.In 1998, the ODEQ and the EPA completed a study of sediments in a 5.5-mile segment of the WillametteRiver (PortlandHarbor) that includes an area adjacent to the Gasco and Siltronic sites. The PortlandHarbor 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 to allow the EPA to develop a feasibility study. Subsequently, the EPA approved a Programmatic Work Plan, Field Sampling Plan and Quality Assurance Project Plan for the Portland Harbor Remedial Investigation/Feasibility Study (RI/FS), completion of which is scheduled for 2012. The EPA and the Lower Willamette Group are conducting more focused studies on approximately nine miles of the lower Willamette River, including the 5.5-mile segment previously studied by the EPA. Further, in August 2008, we signed a cooperative agreement with the Portland Harbor Natural Resource Trustee Council to participate in a phased natural resource damage (NRD) assessment. The NRD assessment is intended to identify additional information necessary to estimate further liabilities to support an early restoration-based settlement of natural resource damage claims.  During 2012, the Lower Willamette Group will submit a draft feasibility study for this site to EPA, resulting in more information regarding the scope of potential costs. We expect that the feasibility study will allow us to estimate a range of potential liability and that the range may include significant estimates of potential liability. As of December 31, 2011, we have a liability accrued of $8.2 million for this site, which is at the low end of the range of the potential liability because no amount within the range is considered to be more likely than another, and the high end of the range cannot reasonably be estimated.

Central Service Center site. In 2006, we received notice from the ODEQ that our Central Service Center in southeast Portland (Central Service Center site) was assigned a high priority for further environmental investigation. Previously there were three manufactured gas storage tanks on the premises. The ODEQ believes there could be site contamination associated with releases of condensate from stored manufactured gas as a result of historic gas handling practices. In the early 1990s, we excavated waste piles and much of the contaminated surface soils and removed accessible waste from some of the abandoned piping. In early 2008, we received notice that this site was added to the ODEQ's list of sites where releases of hazardous substances have been confirmed and to its list where additional investigation or cleanup is necessary. We are currently performing an environmental investigation of the property with the ODEQ's Independent Cleanup Pathway.  As of December 31, 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 we could manage the site separately from the Portland Harbor site under ODEQ authority.  We submitted work plans for source control investigation and a historical report to ODEQ and completed initial studies.  In 2010, ODEQ required additional studies which are underway.  As of December 31, 2011, we have an estimated liability accrued of $1.7 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 “Other Legal Proceedings,” below.

Accrued Liabilities Relating to Environmental Sites. The following table summarizes the accrued liabilities relating to environmental sites at December 31, 2011 and 2010:

			Current Liabilities				Non-Current Liabilities
Thousands			2011		2010		2011		2010
Gasco site		$	16,510	$	11,366	$	44,697	$	38,921
Siltronic site			887		720		128		201
Portland Harbor site			1,089		2,304		7,066		5,784
Central Service Center site			-		5		495		510
Front Street site			1,697		1		-		1,097
Other sites			-		-		120		108
	Total	$	20,183	$	14,396	$	52,506	$	46,621

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 carrying costs 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 carrying cost accrual was extended through January 2012.  We have filed a request with the OPUC to reauthorize this deferral and expect reauthorization during the first half of 2012. In addition, we filed a request with the 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 20, 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 $124.8 million for environmental costs, including legal, investigation, monitoring and remediation costs, including $4.9 million accrued and paid prior to regulatory deferral order approval. At December 31, 2011, we had a regulatory asset of $105.7 million for deferred environmental costs.

In December 2010, NW Natural commenced litigation against certain of its historical liability insurers in Multnomah County Circuit Court, State of Oregon (see Item 3. Legal Proceedings). NW Natural seeks damages in excess of $50 million in losses it has incurred to date, as well as declaratory relief for additional losses it expects to incur in the future.  In December 2011, NW Natural reached a settlement with Associated Electric & Gas Insurance Services Limited and dismissed that insurer from the litigation.

Other Legal Proceedings

We are subject to claims and litigation arising in the ordinary course of business. We do not expect that the ultimate disposition of any of these matters, including the matter described below, will have a material effect on our financial condition, results of operations or cash flows.

Oregon Steel Mills site.In 2004, NW Natural was served with a third-party complaint by the Port of Portland (Port) in a Multnomah County Circuit Court case, Oregon Steel Mills, Inc. v. The Port of Portland. The Port alleges that in the 1940s and 1950s petroleum wastes generated by our predecessor, Portland Gas & Coke Company, and 10 other third-party defendants were disposed of in a waste oil disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by Oregon Steel Mills. The complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future remedial action costs. No date has been set for trial. 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.

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Derivative Instruments (tables)

12 Months Ended

Dec. 31, 2011

Summary Of Derivative Instruments Abstract

Income Statement Presentation of Derivative Instruments [Text Block]

		2011								2010
Thousands		Natural gas commodity		(1)	Foreign exchange		(2)	Natural gas commodity		(1)	Foreign exchange(2)
Cost of sales		$	(60,799)		$	-		$	(52,677)		$	-
Other comprehensive income (loss)			-			(201)			-			91
Less:
Amounts deferred to regulatory accounts on balance sheet			60,799			201			52,677			(91)
	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 exchange forward purchase contracts is recorded in other comprehensive income, and reclassified to regulatory deferral accounts on the balance sheet.

Credit Rating Downgrade Scenarios [Text Block]

				Credit Rating Downgrade Scenarios
Thousands		(Current Ratings) A+/A3		BBB+/Baa1		BBB/Baa2		BBB-/Baa3		Speculative
With Adequate Assurance Calls	$	-	$	-	$	2,013	$	9,585	$	45,869
Without Adequate Assurance Calls	$	-	$	-	$	851	$	5,923	$	37,206

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Valuation Allowances and Reserves

12 Months Ended

Dec. 31, 2011

Schedule Of Valuation And Qualifying Accounts Disclosure [Abstract]

Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]

NORTHWEST NATURAL GAS COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
COLUMN A	COLUMN B		COLUMN C				COLUMN D		COLUMN E
			Additions				Deductions
	Balance at		Charged to		Charged to				Balance at
	beginning		costs and		other		Net		end of
Thousands (year ended Dec. 31)	of period		expenses		accounts		Write-offs		period
2011
Reserves deducted in balance sheet from assets to which they apply:
Allowance for uncollectible accounts	$	2,950	$	1,919	$	-	$	1,974	$	2,895
2010
Reserves deducted in balance sheet from assets to which they apply:
Allowance for uncollectible accounts	$	3,125	$	1,717	$	-	$	1,892	$	2,950
2009
Reserves deducted in balance sheet from assets to which they apply:
Allowance for uncollectible accounts	$	2,927	$	4,201	$	-	$	4,003	$	3,125

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Consolidated Statement of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating activities:
Net income	$ 63,898	$ 72,667	$ 75,122
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization	70,004	65,124	62,814
Undistributed earnings from equity investments	1,329	(588)	(1,329)
Non-cash expenses related to qualified defined benefit pension plans	7,191	8,009	9,914
Contributions to qualified defined benefit pension plans	(22,045)	(10,000)	(25,000)
Deferred environmental expenditures	25,586	(7,826)	(10,069)
Settlement of interest rate hedge	0	0	(10,096)
Other	(1,049)	(2,265)	(3,461)
Changes in assets and liabilities:
Receivables	(6,246)	15,830	35,506
Inventories	6,022	572	15,110
Taxes accrued	34,189	(51,524)	23,461
Accounts payable	148	(11,846)	1,188
Interest accrued	675	(253)	8,582
Deferred gas costs	8,565	(26,090)	36,819
Deferred tax liabilities	46,877	76,410	36,775
Other - net	(1,682)	(1,751)	(15,001)
Cash provided by operating activities	233,462	126,469	240,335
Investing activities:
Capital expenditures	(100,534)	(248,505)	(135,124)
Utility gas reserves	(50,597)	0	0
Restricted cash	(3,076)	34,619	(30,524)
Other	1,142	1,015	3,507
Cash used in investing activities	(153,065)	(212,871)	(162,141)
Financing activities:
Common stock issued (purchased) - net	3,040	4,598	(375)
Long-term debt issued	90,000	0	125,000
Long-term debt retired	(10,000)	(35,000)	(300)
Change in short-term debt	(115,835)	155,435	(158,851)
Cash dividend payments on common stock	(46,690)	(44,652)	(42,415)
Other	1,464	1,046	263
Cash used in financing activities	(78,021)	81,427	(76,678)
Increase (decrease) in cash and cash equivalents	2,376	(4,975)	1,516
Cash and cash equivalents - beginning of period	3,457	8,432	6,916
Cash and cash equivalents - end of period	5,833	3,457	8,432
Supplemental disclosure of cash flow information:
Interest paid	41,413	41,037	36,762
Income taxes paid	$ 1,756	$ 22,600	$ 10,000

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Consolidated Statements of Income and Comprehensive Income (parentheticals) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Comprehensive Income Parentheticals [Abstract]
Change in non-qualified employee benefit plan liability, tax	$ 1,161	$ 674	$ 1,273
Other Comprehensive Income Amortization of Defined Benefit Plan Net Prior Service Cost Recognized in Net Periodic Pension Cost Tax Portion	$ (383)	$ (257)	$ (58)

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Income Tax

12 Months Ended

Dec. 31, 2011

Disclosure Income Tax [Abstract]

Income Tax Text Block

10.        Income Tax

A reconciliation between income taxes calculated at the statutory federal tax rate and the provision for income taxes reflected in the consolidated financial statements is as follows:

Thousands, except percentages			2011		2010		2009
Income taxes at federal statutory rate		$	37,550	$	42,745	$	42,627
Increase (decrease):
	Current state income tax, net of federal tax benefit		4,945		5,803		5,568
	Amortization of investment and energy tax credits		(442)		(525)		(593)
	Differences required to be flowed-through by
	regulatory commissions		1,647		1,647		(116)
	Gains on company and trust-owned life insurance		(786)		(715)		(1,195)
	Other - net		468		507		380
Total provision for income taxes		$	43,382	$	49,462	$	46,671
Effective tax rate			40.4%		40.5%		38.3%

The provision (benefit) for current and deferred income taxes consists of the following:

Thousands			2011		2010		2009
Current
	Federal	$	130	$	(28,592)	$	6,221
	State		(929)		1,441		2,300
			(799)		(27,151)		8,521
Deferred
	Federal		35,481		69,159		31,937
	State		8,700		7,454		6,213
			44,181		76,613		38,150
	Total provision for income taxes	$	43,382	$	49,462	$	46,671
	Total income taxes paid	$	1,756	$	22,600	$	10,000

The following table summarizes the total provision (benefit) for income taxes for the regulated utility and non-utility business segments for the three years ended December 31:

Thousands			2011		2010		2009
Regulated utility:
	Current	$	(4,646)	$	(1,464)	$	871
	Deferred		50,152		47,741		40,829
	Deferred investment and energy tax credits		(422)		(525)		(593)
			45,084		45,752		41,107
Non-utility business segments:
	Current		3,846		(25,687)		7,650
	Deferred		(5,548)		29,397		(2,086)
			(1,702)		3,710		5,564
Total provision for income taxes		$	43,382	$	49,462	$	46,671

The following table summarizes the tax effect of significant items comprising our deferred income tax accounts for the two years ended December 31:

Thousands				2011		2010
Deferred tax liabilities:
	Plant and property		$	292,235	$	255,471
	Regulatory adjustment for income taxes paid			2,106		5,272
	Regulatory income tax assets			65,755		68,822
	Regulatory liabilities			35,638		23,159
	Non-regulated deferred tax liabilities			43,373		34,544
		Total	$	439,107	$	387,268
Deferred tax assets:
	Regulatory assets			(4,727)		(1,402)
	Unfunded pension and postretirement obligations			(5,119)		(4,342)
	Non-regulated deferred tax assets			(1,161)		(772)
	Alternative minimum tax credit carryforward			(1,626)		(1,702)
	Loss and credit carryforwards			(14,255)		(7,071)
		Total		(26,888)		(15,289)
Deferred income tax liabilities - net				412,219		371,979
Deferred investment tax credits				990		1,430
Deferred income taxes and investment tax credits			$	413,209	$	373,409

We have determined that we are more likely than not to realize all recorded deferred tax assets as of December 31, 2011.

We calculate our deferred tax assets and liabilities according to accounting guidance on income taxes, whereby deferred income taxes are generally determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect in the years in which the differences are expected to reverse. Deferred tax provisions are not recorded in the income statement for certain temporary differences where regulators require that we flow through deferred income tax benefits or expenses in the utility ratemaking process.

In September 2010, Congress passed the Unemployment Insurance, Reauthorization and Job Creation Act of 2010 (the Act) and the legislation was signed into law by President Obama. The Act extended for one year the temporary bonus depreciation rules first enacted in the Economic Stimulus Act of 2008 and subsequently renewed in the American Recovery and Reinvestment Act of 2009. Under the bonus depreciation provision, an additional first-year tax deduction was allowed for depreciation equal to 50 percent of the adjusted basis of qualified property through September 8, 2010, in the year the property was placed in service, with the remaining percentage recovered under the normal depreciation rules. In addition, on December 17, 2010, President Barack Obama signed into law the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act), which allows 100 percent bonus depreciation for qualified property placed in service between September 9, 2010 through December 31, 2011. It also extended the 50% bonus depreciation deduction to qualifying property placed in service through 2012.

In 2011 the Company received a tax refund of $14.4 million for tax year2010. In addition, the companycarried back a portion of its 2010 net operating loss to tax year 2009 and received a refund of $22.3 million. In 2011 we filed an amended federal income tax return for 2009, primarily to report a deduction for repairs expense consistent with a change in accounting method approved by the IRS and in conformity with the deduction allowed by the IRS in its examination of years 2006-2008. The Company then amended its net operating loss carryback to tax year 2009. The result of the amended federal tax return for tax year 2009 and the amended net operating loss carryback is a federal income tax refund receivable of $3.5 million at December 31, 2011. The company estimates that it has a consolidatednet operating loss carryforward to 2012 of $33.7 million. The net operating loss carryforward will be carried forward to reduce our current tax liability in future years. We anticipate that we will be able to utilize the entire net operating loss carryforward before its expiration in twenty years.

For the year ended December 31, 2010, we reported taxable income for Oregon purposes due to lack of federal-state conformity with respect to the accelerated depreciation effects cited above. The Company recorded a current receivable of $3.5 million to reflect the excess of payments applied to year 2010 over the amount owed. The Company received this refund in the first quarter of 2012. As of January 1, 2011, Oregon conformed to federal rules including bonus depreciation. As a result, we anticipate generating an NOL for state purposes in 2011. Oregon does not allow NOL carrybacks, but allows NOLs to be carried forward for fifteen years. We expect to fully utilize the estimated NOL generated in 2011.

Uncertain tax positions are accounted for in accordance with accounting standards that require management's assessment of the expected treatment of a tax position taken in a filed tax return, or planned to be taken in a future tax return, that has not been reflected in measuring income tax expense for financial reporting purposes. Until such positions are sustained by the taxing authorities, we would not recognize the tax benefits resulting from such positions and would report the tax effect as a liability in the Company's consolidated balance sheet. As of December 31, 2011, we had no uncertain tax positions.

The IRS completed its examination of the 2006 through 2008 tax years in 2011. The examination resulted in payments of $1.5 million of tax and $0.2 million of interest. The Oregon Department of Revenue (ODOR) completed its field examination of our 2006 through 2009 consolidated Oregon income tax returns and issued preliminary assessments. If sustained by the ODOR, these assessments would result in an additional state tax liability of approximately $0.8 million, including interest and penalties. The Company is engaged in discussions with ODOR to resolve these issues; however, uncertainty exists with respect to the outcome of the audit as a result of information not yet fully considered by the ODOR. Resolution is expected to be reached within the next 12 months, and we have determined that it is more-likely-than-not that we will prevail on these issues. As such, no amounts have been recorded in our financial statements as of December 31, 2011 related to this matter.

Interest and penalties related to any future income tax deficiencies are recorded within income tax expense in the consolidated statements of income.

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2011	Feb. 24, 2012
Document and Entity Information [Abstract]
Document Type	10-K
Document period end date	Dec. 31, 2011
Amendment flag	false
Current fiscal year end date	--12-31
Entity central index key	0000073020
Entity current reporting status	Yes
Entity filer category	Large Accelerated Filer
Entity registrant name	Northwest Natural Gas Co.
Entity voluntary filers	No
Entity well known seasoned issuer	Yes
Entity common stock shares outstanding		26,668,712
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY
Entity public float	$ 1,282,419,920.93

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2011

Property Plant And Equipment [Abstract]

Property Plant And Equipment Disclosure Text Block

11.Property, Plant and Equipment

The following table sets forth the major classifications of our property, plant and equipment and accumulated depreciation at December 31:

Thousands		2011		2010
Utility plant in service		$	2,323,467	$	2,247,952
Utility construction work in progress			36,051		29,324
Less accumulated depreciation			749,603		710,214
	Utility plant-net		1,609,915		1,567,062
Non-utility plant in service			293,205		290,038
Non-utility construction work in progress			8,379		9,088
Less accumulated depreciation			17,623		12,025
	Non-utility plant-net		283,961		287,101
Total property plant and equipment		$	1,893,876	$	1,854,163

The weighted average depreciation rate for utility assets was 2.8 percent in 2011 and 2010. The weighted average depreciation rate for non-utility assets was2.2 percentin 2011 and 2.5 percent in 2010.

Accumulated depreciation does not include the accumulated provision for asset removal costs of $267.4 million and $252.9 million at December 31, 2011 and 2010, respectively.  These accrued asset removal costs are reflected on the balance sheets as regulatory liabilities (see Note 2, “Plant, Property and Accrued Asset Removal Costs”).

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 5,833	$ 3,457
Restricted cash	0	924
Accounts receivable	77,449	67,969
Unbilled Receivables, Current	61,925	64,803
Allowance for uncollectible accounts	(2,895)	(2,950)
Regulatory assets	94,673	52,714
Derivative instruments	2,853	2,245
Inventory	74,363	80,385
Gas Reserves	4,463	0
Income taxes receivable	7,045	41,066
Other current assets	22,980	19,652
Total current assets	348,689	330,265
Non-current assets:
Property, plant and equipment	2,661,102	2,576,402
Less: Accumulated depreciation	767,226	722,239
Total property, plant and equipment - net	1,893,876	1,854,163
Gas Reserves	47,451	0
Regulatory Assets	371,392	348,897
Derivative instruments	0	628
Other investments	68,263	69,094
Restricted cash	4,000	0
Other non-current assets	12,903	13,569
Total non-current assets	2,397,885	2,286,351
Total assets	2,746,574	2,616,616
Capitalization:
Common stock - no par value; authorized 100,000 shares; issued and outstanding 26,756 and 26,668 at December 31, 2011 and 2010, respectively	348,383	342,978
Retained earnings	373,905	356,727
Accumulated other comprehensive income (loss)	(7,800)	(6,604)
Total common stock equity	714,488	693,101
Long-term debt	641,700	591,700
Total capitalization	1,356,188	1,284,801
Current liabilities:
Short-term debt	141,600	257,435
Current maturities of long-term debt	40,000	10,000
Accounts payable	86,300	93,243
Taxes accrued	10,747	10,579
Interest accrued	5,857	5,182
Regulatory liabilities	31,046	17,828
Derivative instruments	57,317	38,437
Other current liabilities	41,597	35,457
Total current liabilities	414,464	468,161
Deferred credits and other non-current liabilities:
Deferred tax liabilities	413,209	373,409
Regulatory Liabilities	278,382	258,031
Pension and other postretirement benefit liabilities	201,530	144,250
Derivative instruments	6,536	17,022
Other non-current liabilities	76,265	70,942
Total deferred credits and other non-current liabilities	975,922	863,654
Commitments and contingencies (see Note 15)	0	0
Total capitalization and liabilities	$ 2,746,574	$ 2,616,616

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Common Stock

12 Months Ended

Dec. 31, 2011

Disclosure Common Stock [Abstract]

Common Stock Text Block

5.Common Stock

Common Stock

As of December 31, 2011 and 2010, our common shares authorized were 100,000,000.As of December 31, 2011, we had reserved for issuances 155,955 shares of common stock under the Employee Stock Purchase Plan (ESPP), 293,246 shares under our Dividend Reinvestment and Direct Stock Purchase Plan and 1,159,875 shares under our Restated Stock Option Plan (Restated SOP).

Stock Repurchase Program

We have a share repurchase program for our common stock under which we purchase shares on the open market or through privately negotiated transactions.  We currently have Board authorization through May 2012 to repurchase up to an aggregate of 2.8 million shares, or up to $100 million. No shares of common stock were repurchased pursuant to this program in 2011,2010or 2009. Since inception in 2000, a total of 2.1 million shares have been repurchased at a total cost of $83.3 million.

Summary of Changes in Common Stock

The following table shows the changes in the number of shares of our common stock issued and outstanding for the years 2011,2010 and 2009:

Thousands		Shares
Balance, December 31, 2008		26,501
	Sales to employees under ESPP	9
	Exercise of stock options under Restated SOP - net	23
Balance, December 31, 2009		26,533
	Sales to employees under ESPP	24
	Exercise of stock options under Restated SOP - net	111
Balance, December 31, 2010		26,668
	Sales to employees under ESPP	15
	Exercise of stock options under Restated SOP - net	24
	Sales to shareholders under DRPP	49
Balance, December 31, 2011		26,756

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Segment Information

12 Months Ended

Dec. 31, 2011

Disclosure Segment Information [Abstract]

Segment Information Text Block

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 asset management services. Our “other” segment includes NNG Financial and our equity investment in PGH, which is pursuing development ofthe Palomar pipeline project (see Other, below).

Local Gas Distribution

Our local gas distribution segment is a regulated utility principally engaged in the purchase, sale and delivery of natural gas and related services to customers in Oregon and southwest Washington. As a regulated utility, we are responsible for building and maintaining a safe and reliable pipeline distribution system, purchasing sufficient gas supplies from producers and marketers, contracting for firm and interruptible transportation of gas over interstate pipelines to bring gas from the supply basins into our service territory, and re-selling the gas to customers subject to rates, terms and conditions approved by the OPUC or WUTC.  Gas distribution also includes taking customer-owned gas and transporting it from interstate pipeline connections, or city gates, to the customers' end-use facilities for a fee, which is approved by the OPUC or WUTC.  Approximately 90 percent of our customers are located in Oregon and 10 percent in Washington. On an annual basis, residential and commercial customers typically account for 50 to 60 percent of our utility's total volumes delivered and 80 to 90 percent of our utility's margin.Industrial customers account for the remaining 40 to 50 percent of volumes and 5 to 15 percent of margin.  The remaining 10 percent or less of margin is derived from miscellaneous services, gains or lossesfrom an incentive gas cost sharing mechanism and other fees.

Industrial customers we serve include: pulp, paper and other forest products; the manufacture of electronic, electrochemical and electrometallurgical products; the processing of farm and food products; the production of various mineral products; metal fabrication and casting; the production of machine tools, machinery and textiles; the manufacture of asphalt, concrete and rubber; printing and publishing; nurseries; government and educational institutions; and electric generation.  No individual customer or industry group accounts for a significant portion of our utility revenues or margins.

Gas Storage

Our gas storage business segment includes natural gas storage services provided to customers primarily from two underground natural gas storage facilities, our Gill Ranch gas storage facility, which commenced commercial operations in October 2010, and the non-utility portion of our Mist gas storage facility. In addition to earning revenue from customer storage contracts, we also use an independent energy marketing company to provide asset management services for utility and non-utility capacity under contractual arrangement, the results of which are included in this business segment.   For the years ended December 31, 2011, 2010 and 2009, this business segment derived a majority of its revenues from asset management services and from firm and interruptible gas storage contracts.  

Mist Gas Storage Facility.Earnings from non-utility assets at the Mist facility are primarily related to firm storage capacity revenues. Earnings for the gas storage segmentinclude revenues, net of amounts shared with core utility customers, from management of utility assets at Mist and upstream capacity when not needed to serve core utility customers. In Oregon, the gas storage segment retains 80 percent of the pre-tax income from these services when the costs of the capacity have not been included in utility rates, or 33 percent of the pre-tax income when the costs have been included in utility rates. The remaining 20 percent and 67 percent, respectively, are credited to a deferred regulatory account for creditingback to core utility customers.  We have a similar sharing mechanism in Washington for revenue derived from storage and third party asset management services.

Gill Ranch Gas Storage Facility.Gill Ranch has a joint project agreement with Pacific Gas and Electric Company (PG&E) toown the Gill Ranch underground natural gas storage facility near Fresno, California. Gill Ranch has a 75 percent undivided ownership interest in the facility, which offers storage services to the California market at market-based rates, subject to CPUC regulation including, but not limited to, service terms and conditions and tariff regulations.

Other

We have non-utility investments and other business activities which are aggregated and reported as a business segment called “other.”  Although in the aggregate these investments and activities are currently not material to consolidated operations, we identify and report them as a stand-alone segment based on our organizational structure and decision-making process because these business investments and activities are not specifically related to our utility or gas storage segments.  This segment primarily consists of an equity method investment in a joint venture to build and operate an interstate gas transmission pipeline in Oregon (Palomar) and other pipeline assets in NNG Financial. For more on information on Palomar, see Note 12.  This segment also includes some operating and non-operating revenues and expenses of the parent company that cannot be allocated to utility operations.

NNG Financial holds certain non-utility financial investments, but its assets primarily consist of an active, wholly-owned subsidiary which owns a 10 percent interest in an 18-mile interstate natural gas pipeline. NNG Financial's total assets were $1.1 million at both December 31, 2011 and 2010.

Segment Information Summary

The following table presents summary financial information about the reportable segments for the years ended 2011, 2010 and 2009.  Inter-segment transactions are insignificant.

Thousands		Utility		Gas Storage		Other		Total
2011
Net operating revenues	$	342,970	$	26,354	$	109	$	369,433
Depreciation and amortization		63,843		6,161		-		70,004
Income from operations		135,722		9,090		33		144,845
Net income		60,527		4,101		(730)		63,898
Total assets at December 31, 2011		2,435,888		294,637		16,049		2,746,574
2010
Net operating revenues	$	346,148	$	21,249	$	184	$	367,581
Depreciation and amortization		62,661		2,463		-		65,124
Income from operations		145,688		11,855		62		157,605
Net income		66,262		6,110		295		72,667
Total assets at December 31, 2010		2,310,388		282,945		23,283		2,616,616
2009
Net operating revenues	$	357,005	$	19,738	$	144	$	376,887
Depreciation and amortization		61,472		1,342		-		62,814
Income from operations		142,228		16,442		46		158,716
Net income		65,960		8,923		239		75,122

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Quarterly Financial Information

12 Months Ended

Dec. 31, 2011

Selected Quarterly Financial Information [Abstract]

Quarterly Financial Information [Text Block]

NORTHWEST NATURAL GAS COMPANY
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
			Quarter ended
Thousands, except per share amounts			March 31		June 30		Sept. 30		Dec. 31		Total
2011
Operating revenues		$	323,088	$	161,197	$	93,313	$	271,198	$	848,796
Net operating revenues			134,508		67,232		47,783		119,910		369,433
Net income (loss)			40,773		2,193		(8,312)		29,244		63,898
Basic earnings (loss) per share			1.53		0.08		(0.31)		1.09		2.39(1)
Diluted earnings (loss) per share			1.53		0.08		(0.31)		1.09		2.39(1)
2010
Operating revenues		$	286,529	$	162,365	$	95,067	$	268,145	$	812,106
Net operating revenues			130,926		72,193		46,211		118,251		367,581
Net income (loss)			43,608		6,888		(7,420)		29,591		72,667
Basic earnings (loss) per share			1.64		0.26		(0.28)		1.11		2.73(1)
Diluted earnings (loss) per share			1.64		0.26		(0.28)		1.11		2.73(1)
(1)	Quarterly earnings (loss) per share are based upon the average number of common shares outstanding during each quarter. Because the average number of shares outstanding has changed in each quarter shown, the sum of quarterly earnings (loss) per share may not equal earnings per share for the year. Variations in earnings between quarterly periods are due primarily to the seasonal nature of our business.

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Gas Reserves and Other Investments

12 Months Ended

Dec. 31, 2011

Gas Reserves And Other Investments [Abstract]

Gas Reserves And Other Investments [Text Block]

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. The following table summarizes our other investments at December 31:

Thousands			2011		2010
Investments in life insurance policies		$	51,911	$	51,090
Investments in gas pipeline joint ventures			14,340		15,742
Other			2,012		2,262
	Total other investments	$	68,263	$	69,094

Gas Reserves

We entered into an agreement with Encana to develop physical gas reserves that are expected to supply a portion of our utility customers' requirements over the next 30 years. The volume of gas produced and allocated to us 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 approximately $250 million.

Upon reviewing the transaction, the OPUC determined that our costs under the agreement will be recovered on an ongoing basis through its annual 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 the agreements referred to above, and we are currently receiving gas from our interests in a section of the gas field. In 2011, volumes from gas reserves were less than one percent of our total gas purchases. Our net investment at December 31, 2011 is $36.3 million, including deferred tax liabilities totaling $15.6 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 due to the fact that our interest represents a minor portion of total extraction activities. We account for our investment in this VIE on the cost basis, and it is included under gas reserves on our balance sheet. Our maximum loss exposure related to this VIE is limited to our investment balance.

Palomar

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. PGH is a development stage variable interest entity.

Variable Interest Entity (VIE) Analysis.As of December 31,2011, we updated our VIE analysis and reconfirmed that we are not the primary beneficiary of PGH's activities as defined by the authoritative guidance related to consolidations due to the fact that we have a 50 percent share and there are no stipulations that allow disproportionate influence over the entity. 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 at each reporting period, and following updates to our corporate planning assumptions.  When it is determined that a loss in value is other than temporary, a 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 future cash flows. Differing assumptions could affect the timing and amount of a charge recorded in any period.

In 2011, our investment in PGH was reviewed for impairment when Palomar withdrew its original application with the FERC for a proposed natural gas pipeline in Oregon.  At the same time, Palomar informed FERC that it intended to re-file an application 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.

The evaluation of assets related to the west portion of the Palomar pipeline 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.  An evaluation of the assets related to the east portion was also performed in 2011, and a charge of $1.0 million was recorded. The east segmentcharge was related to costs that would potentially be outdatedand, if so, would need to be redone for the refiled application. Our remaining investment balance in Palomar was $13.5 million at December 31, 2011, which consists of costs related to the east segment. We also 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 charge of up to approximately $13.2 million based on the current amount of our equity investment net of cash and working capital at Palomar.  We will continue to monitor and update our impairment analysis as required.

Investment in Life Insurance Policies

We have invested in key person life insurance contracts to provide an indirect funding vehicle for certain long-term employee and director benefit plan liabilities.  The amount in the above table is reported as cash surrender value, net of policy loans.

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Short-term Debt and Credit Facilities

12 Months Ended

Dec. 31, 2011

Short Term Debt And Credit Facilities [Abstract]

Short-term Debt

8.       Short-term Debt and Credit Facilities

Our primary source of short-term funds is from the sale of commercial paper and bank loans.  In addition to issuing commercial paper or bank loans to meet seasonal working capital requirements, short-term debt is used temporarily to fund capital requirements.  Commercial paper and bank loans are periodically refinanced through the sale of long-term debt or equity securities.  Our commercial paper program is supported by one or more committed credit facilities.  At December 31, 2011 and 2010, the amounts and average interest rates of commercial paper debt outstanding were $141.6 million at 0.3 percent and $257.4 million at 0.4 percent, respectively. There were no bank loans outstanding at December 31, 2011 or 2010.

At NW Natural,we have a multi-year $250 million syndicated credit agreement, pursuant to which we may extend commitments for additional one-year periods subject to lender approval. We extended commitments under this syndicated agreement to May 31, 2013.  The syndicated agreement allows us to request increases in the total commitment amount from time to time, up to a maximum amount of $400 million, and to replace any lenders who decline to extend the terms of the agreement. The syndicated agreement also permits the issuance of letters of credit in an aggregate amount up to the applicable total borrowing commitment. Any principal and unpaid interest owed on borrowings under the syndicated agreement are due and payable on or before the expiration date.  There were no outstanding balances under the syndicated credit agreement and no letters of credit issued or outstanding at December 31, 2011 and 2010.

The syndicated credit agreement requires that we maintain credit ratings with Standard & Poor's (S&P) and Moody's Investors Service, Inc. (Moody's) and notify the lenders of any change in our senior unsecured debt ratings by such rating agencies. A change in our debt ratings is not an event of default, nor is the maintenance of a specific minimum level of debt rating a condition of drawing upon the credit facility. However, interest rates on any loans outstanding under the credit facility are tied to debt ratings, which would increase or decrease the cost of any loans under the credit facility when ratings are changed. There were no changes in our credit ratings during 2011.

The syndicated credit agreement also requires us to maintain a consolidated indebtedness to total capitalization ratio of 70 percent or less. Failure to comply with this covenant would entitle the lenders to terminate their lending commitments and accelerate the maturity of all amounts outstanding. We were in compliance with this covenant at December 31, 2011 and 2010.

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Stock-Based Compensation

12 Months Ended

Dec. 31, 2011

Disclosure Stock Based Compensation [Abstract]

Stock Based Compensation Text Block

6.       Stock-Based Compensation

We have several stock-based compensation plans, including the Long-Term Incentive Plan (LTIP), the Restated SOP and the ESPP. These plans are designed to promote stock ownership in NW Natural by employees and officers.

Long-Term Incentive Plan

The LTIP is intended to provide a flexible, competitive compensation program for eligible officers and key employees.  An aggregate of 600,000 shares of common stock was authorized for grants under the LTIP as stock bonus, restricted stock or performance-based stock awards.  Shares awarded under the LTIP may be purchased on the open market or issued as new shares.

At December 31, 2011, 337,788 shares of common stock were available for award under the LTIP, assuming that performance based grants currently outstanding are awarded at the target level.  The LTIP stock awards are compensatory awards for which compensation expense is based on the fair value of stock awards, with expense being recognized over the performance and vesting period for the outstanding awards.

Performance-based Stock Awards.Since the LTIP's inception in 2001, performance-based stock awards have been granted annually based on three-year performance periods.  At December 31, 2011, certain performance-based stock award measures had been achieved for the 2009-11 award period.  Accordingly, participants are estimated to receive 8,428 shares of common stock and a dividend equivalent cash payment equal to the number of shares of common stock received on the award payout multiplied by the aggregate cash dividends paid per share during the performance period. At December 31, 2010and 2009, we awarded8,007 and 15,900 shares of common stock, respectively, for the 2008-10 and 2007-09 award periods, plus a dividend equivalent cash payment equal to the number of shares of common stock received on the award payout multiplied by the aggregate cash dividends paid per share during the performance period. In 2010 and 2009, we expensed $0.2 million and $0.5 million respectively for both the 2008-10 and 2007-09 performance-based stock award periods, and on a cumulative basis we accrued a total of $0.7 million and $1.5 million, respectively, related to the 2008-10 and 2007-09 performance periods.

At December 31, 2011, the aggregate number of performance-based shares granted and outstanding at the threshold, target and maximum levels were as follows:

Performance	Performance Share Awards Outstanding			2011		Cumulative Expense
Period	Threshold	Target	Maximum	Expense		At Dec. 31, 2011
2009-11	7,410	39,000	78,000	$	353	$	763
2010-12	n/a(1)	41,500	83,000		430		718
2011-13	n/a(1)	37,950	75,900		276	$	276
Total		118,450	236,900	$	1,059
(1)The threshold requirement was modified and is no longer applicable beginning in the 2010-12 performance period.

The threshold level estimates future payout assuming the minimum award payable is achieved for each component of the formula in the LTIP.  For each of these performance periods, awards will be based on total shareholder return relative to a peer group of gas distribution companies over the three-year performance period and on performance results achieved relative to specific core and non-core strategies.  Compensation expense is recognized in accordance with the accounting standard for stock compensation based on performance levels achieved and an estimated fair value using a Black-Scholes or binomial model.  The weighted-average grant date fair value of unvested shares at December 31, 2011 and 2010was $25.06 and $23.10 per share, respectively.  The weighted-average grant date fair value of shares vested during the year was $22.35 per share and granted during the year was $19.38 per share.  

Restricted Stock Units.A new form of restricted stock awards was approved by the Board in 2011. Restricted Stock Units (RSUs) are expected to be used instead of the Restated SOP starting in February of 2012. The LTIP plan was amended to allow RSUs to be granted under the plan. RSUs are expected to include a performance based threshold and a vesting period of four years from the grant date. An RSU obligates the Company upon vesting to issue the RSU holder one share of common stock plus a cash payment equal to the total amount of dividends paid per share between the grant date and vesting date of the RSU.

Restated Stock Option Plan

A total of 2,400,000 shares of common stock were reserved for issuance under the Restated SOP with 580,650 available for grant as of December 31, 2011.  Options under the Restated SOP may be granted only to officers and key employees designated by a committee of our Board of Directors.  All options are granted at an option price equal to the closing market price on the date of grant and may be exercised for a period up to 10 years and 7 days from the date of grant.  Option holders may exchange shares they have owned for at least six months, at the current market price, to purchase shares at the option price.

The fair value of each stock option is estimated on the grant date using the Black-Scholes option pricing model with the following weighted average assumptions and outcomes:

		2011		2010		2009
Risk-free interest rate		2.0%		2.3%		2.0%
Expected life (in years)		4.5		4.7		4.7
Expected market price volatility factor		24.5%		23.2%		22.5%
Expected dividend yield		3.8%		3.8%		3.8%
Forfeiture rate		3.1%		3.2%		3.7%
Weighted average grant date fair value	$	6.73	$	6.36	$	5.46

The expected life of our grants was calculated based on our actual experience with previously exercised option grants.  The risk-free interest rate was based on the implied yield currently available on U.S. Treasury zero-coupon issues with a life equal to the expected life of the options.  Historical data was used to estimate the volatility factor, measured on a daily basis, for a period equal to the duration of the expected life of the option awards.  The dividend yield was based on management's current estimate for future dividend payouts at the time of grant.  We expense the total cost of stock option awards granted to retirement eligible employees at the date of grant in accordance with stock option accounting guidance and the retirement vesting provisions of our option agreements.

Information regarding the Restated SOP activity for the three years ended December 31, 2011 is summarized as follows:

			Weighted -		Intrinsic
	Option		Average		Value
	Shares		Price Per Share		(In millions)
Balance outstanding, Dec. 31, 2008	396,410	$	38.62	$	2.3
Granted	111,750		41.15		n/a
Exercised	(23,225)		30.92		0.3
Balance outstanding, Dec. 31, 2009	484,935		39.57		2.7
Granted	119,750		44.25		n/a
Exercised	(111,525)		39.01		0.9
Forfeited	(2,700)		43.00		n/a
Balance outstanding, Dec. 31, 2010	490,460		40.82		2.8
Granted	122,700		45.74		n/a
Exercised	(24,185)		33.88		0.3
Forfeited	(9,750)		44.38		n/a
Balance outstanding, Dec. 31, 2011	579,225	$	42.09	$	3.4
Exercisable, Dec. 31, 2011	311,951	$	40.20	$	2.4

In the year ended December 31, 2011, cash of $0.8 million was received for option shares exercised and a $26,000 thousand related tax benefit was realized.  For the 12 months ended December 31, 2011, 2010 and 2009, the total fair value of options that vested was $0.6 million, $0.5 million and $0.4 million, respectively. The weighted average remaining life of options exercisable and outstanding at December 31, 2011was 5.5 years and 6.8 years, respectively

Thousands			2011		2010		2009
Operations and maintenance expense, for stock-based compensation		$	1,477	$	1,032	$	1,434
Income tax benefit			(597)		(418)		(559)
	Net stock-based compensation effect on net income	$	880	$	614	$	875
Amounts capitalized for stock-based compensation		$	261	$	182	$	229

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Cost and Fair Value Basis of Long-Term Debt

12 Months Ended

Dec. 31, 2011

Disclosure Cost And Fair Value Basis Of Long Term Debt [Abstract]

Cost and Fair Value Basis of Long-Term Debt Text Block

7.       Cost and Fair Value Basis of Long-Term Debt

Cost of Long-Term Debt

The issuance of first mortgage debt, including secured medium-term notes (MTNs), under the Mortgage and Deed of Trust (Mortgage) is limited by eligible property, adjusted net earnings and other provisions of the Mortgage.  The Mortgage constitutes a first mortgage lien on substantially all of our utility property. In addition, our Gill Ranch subsidiary senior secured notes are secured by all of the membership interests in Gill Ranch Storage, LLC as well as Gill Ranch's debt service reserve account.

The maturities on the long-term debt outstanding for each of the 12-month periods through December 31, 2016 amount to: $40 million in 2012; none in 2013; $60 million in 2014; $40 million in 2015; and $65 million in 2016.

Thousands			2011		2010		2009
Utility Medium-Term Notes:
First Mortgage Bonds:
	4.11 % Series B due 2010	$	-	$	-	$	10,000
	7.45 % Series B due 2010		-		-		25,000
	6.665% Series B due 2011		-		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
	3.95 % Series B due 2014		50,000		50,000		50,000
	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		75,000		75,000		75,000
	9.05 % Series A due 2021		10,000		10,000		10,000
	3.176 % Series A due 2021		50,000		-		-
	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		19,700		19,700		19,700
	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
			641,700		601,700		636,700
Subsidiary Senior Secured Notes:
	Gill Ranch Notes due 2016(1)		40,000		-		-
			681,700		601,700		636,700
	Less current maturities of long-term debt		40,000		10,000		35,000
Total long-term debt		$	641,700	$	591,700	$	601,700

• In November 2011, Gill Ranch issued senior secured notes consisting of $20 million of fixed rate notes with an interest rate of 7.75 percent and $20 million of variable interest rate notes with an interest rate of LIBOR plus 5.50, or a minimum of 7.00 percent. Currently, the variable interest rate is 7.00 percent.

Utility Medium-Term Notes

In March 2009, the utility issued $75 million of 5.37 percent secured MTNs due February 1, 2020, and in July 2009 issued another $50 million of 3.95 percent secured MTNs due July 15, 2014.  The utility also issued $50 million of MTNs in September 2011 with an interest rate of 3.176 percent and a maturity date of September 15, 2021.

Subsidiary Senior Secured Notes

In November 2011, Gill Ranch issued $40 million of subsidiary senior secured notes with an interest rate of 7.75 percent on the fixed portion and a 7.00 percent interest rate currently on the variable portion. The notes are secured by all of the membership interests in Gill Ranch Storage, LLC, and are nonrecourse notes to NW Natural. The maturity date of these notes is November 30, 2016.

Under the note agreements, Gill Ranch is subject to certain covenants and restrictions, including but not limited to,a financial covenant that requires Gill Ranch to maintain minimum adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) at various levels over the term of the notes. The minimum adjusted EBITDA increases incrementally over the first few years, reaching its highest level in the 12-month period beginning April 1, 2015. Under the note agreements, Gill Ranch is also subject to a debt service reserve requirement of 10 percent of the outstanding principal amount, initially $4 million, certain prepayment penalties, restrictions on dividends out of Gill Ranch unless certain earnings ratios are met, and restrictions on incurrence of additional debt.

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 for outstanding debt issues that actively trade and have similar characteristics such as size, credit ratings, financial terms and remaining maturities to estimate fair value for our long-term debt issues.

		December 31,
Thousands		2011		2010
Carrying amount	$	681,700	$	601,700
Estimated fair value	$	808,724	$	690,126

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Pension and Other Postretirement Benefits

12 Months Ended

Dec. 31, 2011

Disclosure Pension And Other Postretirement Benefits [Abstract]

Pension and Other Postretirement Benefits Text Block

			Impact on 2011	Impact on Retirement
		Change in	Retirement	Benefit Obligations
Thousands, except percent		Assumption	Benefit Costs	at Dec. 31, 2011
Discount rate:		(0.25%)
	Qualified defined benefit plans		$ 1,162	$ 11,796
	Non-qualified plans		8	53
	Other postretirement benefits		54	754
Expected long-term return on plan assets:		(0.25%)
	Qualified defined benefit plans		580	N/A

9.       Pension and Other Postretirement Benefits

We maintain two qualified non-contributory defined benefit pension plans covering a majority of our regular NW Natural employees with more than one year of service, several non-qualified supplemental pension plans for eligible executive officers and certain key employees and other postretirement employee benefit plans.  We also have a qualified defined contribution plan (Retirement K Savings Plan) for all eligible employees. Only the two qualified defined benefit pension plans and Retirement K Savings Plan have plan assets, which are held in a qualified trust to fund retirement benefits.  Effective January 1, 2007 and 2010, the qualified defined benefit retirement plans and postretirement benefits for non-union employees and for union employees, respectively, were closed to new participants. These plans were not available to employees of our NW Natural subsidiaries.  Non-union and union employees hired or re-hired after December 31, 2006 and 2009, respectively, and employees of NW Natural subsidiariesare provided an enhanced Retirement K Savings Plan benefit. Also, effective January 1, 2007, the postretirement Welfare Benefit Plan for Non-Bargaining Unit Employees was closed to new participants after December 31, 2006.

The following table provides a reconciliation of the changes in benefit obligations and fair value of plan assets, as applicable, for the pension and other postretirement benefit plans, excluding the Retirement K Savings Plan,for the years ended December 31,2011,2010, and 2009, and a summary of the funded status and amounts recognized in the consolidated balance sheets using measurement dates as of December 31, 2011, 2010 and 2009:

			Postretirement Benefit Plans
			Pension Benefits						Other Benefits
Thousands			2011		2010		2009		2011		2010		2009
Reconciliation of change in benefit obligation:
	Obligation at January 1	$	339,338	$	307,991	$	281,127	$	27,676	$	24,741	$	23,863
	Service cost		7,122		6,688		6,402		614		588		522
	Interest cost		18,134		18,029		17,948		1,404		1,436		1,568
	Net actuarial (gain) or loss		44,802		25,275		23,584		2,225		2,387		216
	Benefits paid		(18,269)		(18,645)		(17,149)		(1,870)		(1,476)		(1,428)
	Plan amendments		-		-		(3,921)		-		-		-
	Obligation at December 31	$	391,127	$	339,338	$	307,991	$	30,049	$	27,676	$	24,741
Reconciliation of change in plan assets:
	Fair value of plan assets at January 1	$	219,014	$	201,312	$	163,115	$	-	$	-	$	-
	Actual return on plan assets		(6,684)		24,651		28,641		-		-		-
	Employer contributions		21,909		11,696		26,705		1,870		1,476		1,428
	Benefits paid		(18,269)		(18,645)		(17,149)		(1,870)		(1,476)		(1,428)
	Fair value of plan assets at December 31	$	215,970	$	219,014	$	201,312	$	-	$	-	$	-
Funded status at December 31		$	(175,157)	$	(120,324)	$	(106,679)	$	(30,049)	$	(27,676)	$	(24,741)

Our qualified defined benefit pension plans had an aggregate projected benefit obligation of $362.9 million, $314.5 million and $285.2 million at December 31, 2011, 2010, and 2009, respectively, and the fair value of plan assets was $216.0 million, $219.0 million and $201.3 million, respectively.  Changes in certain pension assumptions impact our projected benefit obligations.Benefit obligations at December 31, 2011 increased $40.3million due to decreases in our discount rate assumptions and increased by $0.9 million due to changes in other assumptions.The projected benefit obligations at December 31, 2010increased $17.9 million over the prior year due to decreases in our discount rate assumptions and increased by $6.5 million due to changes in other assumptions.

The following table provides amounts amortized from accumulated other comprehensive income (AOCI) or regulatory assets to net periodic benefit cost during 2011, 2010, and 2009:

			Regulatory Asset Amortization												AOCI Amortization
			Pension Benefits					Other Postretirement Benefits							Pension Benefits
Thousands			2011		2010		2009		2011		2010		2009		2011		2010		2009
Net periodic benefit costs:
	Actuarial loss	$	10,731	$	6,740	$	6,189	$	289	$	131	$	17	$	854	$	707	$	449
	Prior service cost		230		230		1,260		197		197		197		122		(43)		(37)
	Transition obligation		-		-		-		411		411		411		-		-		-
Total		$	10,961	$	6,970	$	7,449	$	897	$	739	$	625	$	976	$	664	$	412

In 2012, an estimated $15.5 million will be amortized from regulatory assets to net periodic benefit costs, consisting of $14.7 million of actuarial losses, $0.4 million of prior service costs and $0.4 million of transition obligations, and $1.0 million will be amortized from AOCIto earnings related to actuarial losses.

Our assumed discount rate was determined independently for each pension plan and other postretirement benefit plan based on the Citigroup Above Median Curve (discount rate curve) using high quality bonds (i.e. rated AA- or higher by S&P or Aa3 or higher by Moody's).  The discount rate curve was then applied to match the estimated cash flows in each plan to reflect the timing and amount of expected future benefit payments for these plans.

The assumption for expected long-term rate of return on plan assets was developed as a weighted average of the expected earnings for the target asset portfolio.  In developing the expected long-term rate of return assumption, consideration was given to the historical performance of each asset class in which the plans' assets are invested and the target asset allocation for plan assets.

Our investment strategy and policies for the qualified pension plan assets held in the Retirement Trust Fund were approved by our retirement committee, which is composed of senior management employees with the assistance of an investment consultant.  The policies set forth the guidelines and objectives governing the investment of plan assets.  Plan assets are invested for total return with appropriate consideration for liquidity and portfolio risk.  All investments are expected to satisfy the requirements of the rule of prudent investments as set forth under the Employee Retirement Income Security Act of 1974.  The approved asset classes include cash and short-term investments, fixed income, common stock and convertible securities, absolute and real return strategies, real estate and investments in our common stock.  Plan assets may be invested in separately managed accounts or in commingled or mutual funds.  Investment re-balancing takes place periodically as needed, or when significant cash flows occur, in order to maintain the allocation of assets within the stated target ranges.  Our expected long-term rate of return is based upon historical index returns by asset class, adjusted by a factor based on our historical return experience, diversified asset allocation and active portfolio management by professional investment managers.  The Retirement Trust Fund is not currently invested in any NW Natural securities.

The following is our pension planassettarget allocation at December 31, 2011:

	Target
Asset Category	Allocation
U.S. large cap equity	15.0%
U.S. small/mid cap equity	10.0%
Non-U.S. equity	14.5%
Emerging markets equity	3.5%
Long government/credit	24.0%
High yield	5.0%
Emerging market debt	5.0%
Real estate funds	5.8%
Absolute return strategy	12.0%
Real return strategy	5.2%

Our non-qualified supplemental defined benefit pension benefit obligations were $28.2 million, $24.9 million and $22.8 million at December 31, 2011, 2010 and 2009, respectively.  These plans are not subject to regulatory deferral and the changes in actuarial gains and losses, prior service costs and transition assets or obligations are recognized in AOCI under common stock equity, net of tax, until they are amortized as a component of net periodic benefit cost.  Although these are unfunded plans with no plan assets due to their nature as non-qualified plans, we indirectly fund a portion of our obligations with company- and trust-owned life insurance.

Our plans for providing postretirement benefits other than pensions also are unfunded plans, but are subject to regulatory deferral.  The gains and losses, prior service costs and transition assets or obligations for these plans were recognized as a regulatory asset. 

Net periodic benefit cost consists of service costs, interest costs, the amortization of actuarial gains and losses, the expected returns on plan assets and, in part, on a market-related valuation of assets.  The market-related valuation reflects differences between expected returns and actual investment returns, which are recognized over a three-year period or less from the year in which they occur, thereby reducing year-to-year net periodic benefit cost volatility.

The following tables provide the components of net periodic benefit cost for the qualified and non-qualified pension and other postretirement benefit plans for the years ended December 31, 2011, 2010 and 2009 and the assumptions used in measuring these costs and benefit obligations:

				Pension Benefits						Other Postretirement Benefits
Thousands				2011		2010		2009		2011		2010		2009
	Service cost		$	7,122	$	6,688	$	6,402	$	614	$	588	$	522
	Interest cost			18,134		18,029		17,948		1,404		1,436		1,568
	Expected return on plan assets			(17,867)		(18,207)		(15,696)		-		-		-
	Amortization of transition
		obligations		-		-		-		411		411		411
	Amortization of prior service costs			352		187		1,223		197		197		197
	Amortization of net actuarial loss			11,584		7,447		6,810		289		131		-
		Net periodic benefit cost		19,325		14,144		16,687		2,915		2,763		2,698
	Amount allocated to construction			(4,905)		(3,729)		(4,636)		(878)		(904)		(858)
	Amount deferred to regulatory
		balancing account		(6,008)		-		-		-		-		-
		Net amount charged to expense	$	8,412	$	10,415	$	12,051	$	2,037	$	1,859	$	1,840

The assumed annual increase in health care cost trend rates used in measuring other postretirement benefits as of December 31, 2011 were 8.0percent for medical and 10.0percent for prescription drugs.  Medical costs and prescription drugs are assumed to decrease gradually each year to a rate of 5.0 percent by 2021.

Assumed health care cost trend rates can have a significant effect on the amounts reported for the health care plans.  A one percentage point change in assumed health care cost trend rates would have the following effects:

Thousands		1% Increase		1% Decrease
Effect on net periodic postretirement health care benefit cost	$	67	$	(60)
Effect on the accumulated postretirement benefit obligation	$	678	$	(613)

The impact of a change in retirement benefit costs on operating results would be less than the amounts shown above because 30 to 40 percent of these amounts would be capitalized to construction accounts as payroll overhead and included in utility plant, and a certain amount of increases or decreases could be recorded to the regulatory balancing account for pensions, with the remaining amount recognized in current earnings.

The following table provides information regarding employer contributions and benefit payments for the two qualified pension plans, non-qualified pension plans and other postretirement benefit plans for the years ended December 31, 2011 and 2010, and estimated future contributions and payments:

Thousands
	Employer Contributions			Pension Benefits		Other Benefits
		2010	$	12,088	$	1,476
		2011		22,325		1,870
		2012 (estimated)		30,109		2,056
	Benefit Payments
		2009		17,149		1,428
		2010		18,645		1,476
		2011		18,269		1,870
	Estimated Future Payments
		2012		19,374		2,056
		2013		19,620		2,083
		2014		20,107		2,138
		2015		20,640		2,149
		2016		21,284		2,198
		2017-2021		122,680		11,298

We make contributions to our qualified defined benefit pension plans based on actuarial assumptions and estimates, tax regulations and funding requirements under federal law. The Pension Protection Act of 2006 (the Act) established new funding requirements for defined benefit plans.  The Act establishes a 100 percent funding target over seven years for plan years beginning after December 31, 2008.  Our qualified defined benefit pension plans are currently underfunded by $146.9 million at December 31, 2011, and we expect to make contributions during 2012 of approximately $28 million.

The Retirement KSavings Plan provided to our employees is a qualified defined contribution plan under Internal Revenue Code Section 401(k).  Our contributions to this plan totaled $2.4 million 2011and $2.1 million in 2010 and 2009.  The Retirement KSavings Plan includes an Employee Stock Ownership Plan. 

The supplemental deferred compensation plans for eligible officers and senior managers are non-qualified plans.  These plans are designed to enhance the retirement savings of employees and to assist them in strengthening their financial security by providing an incentive to save and invest regularly.  

In addition to the company-sponsored defined benefit plans referred to above, 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)in accordance with our collective bargaining agreement. The employer identification number of the plan is 94-6076144. 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 funded status of the plan.  Our contributions to the Western States Plan amounted to $0.4 million in 2011, 2010 and 2009which is greater than 5 percent of the total contributions to the plan by all participants.  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.

Fair Value

Following is a description of the valuation methodologies used for assets measured at fair value. In cases where the pension plan is invested through a collective trust fund or mutual fund, our custodian uses the fund's market value.  The custodianalso provides the market values for investments directly owned.

U.S. large cap equity:These are level 1 assets valued at the closing price reported on the active market on which the individual security is traded.  This asset class includes investments primarily in U.S. common stocks.

U.S. small/mid cap equity:  These are level 2 assets valued based on information provided by the plan's investment custodians. The financial statements of the commingled fund are audited annually by independent accountants. Values for such funds are stated at estimated fair values, which have been determined based on the unit values of the funds. Unit values are determined by the bank sponsoring such funds by dividing the fund's net assets at fair value by its units outstanding at the valuation date.  This asset class includes investments primarily in U.S. common stocks.

Non-U.S. equity:These are level 1 and 2 assets. Level 1 assets are valued at the closing price reported on the active market on which the individual security is traded.  Level 2 assets are valued based on information provided by the plan's investment custodians. The financial statements of the commingled fund are audited annually by independent accountants. Values for such funds are stated at estimated fair values, which have been determined based on the unit values of the funds. Unit values are determined by the bank sponsoring such funds by dividing the fund's net assets at fair value by its units outstanding at the valuation date.  This asset class includes investments primarily in foreign equity common stocks.

Emerging market equity:  These are level 1 assets valued at the net asset value of the shares held by the plan at the valuation date.  This asset class includes investments primarily in common stocks in emerging markets.

Fixed income:These are level 1 assets valued at the net asset value of the shares held by the plan at the valuation date.  This asset class includes investments primarily in investment grade debt and fixed income securities. 

Long Government/Credit:These are level 2 assets whose values are determined by closing values if available and by matrix pricing for illiquid securities. This asset class includes long duration fixed income investments primarily in U.S. treasuries, U.S. government agencies, municipal securities, mortgage-backed securities, asset-backed securities, as well as U.S. and international investment-grade corporate bonds.

Real estate funds: These are level 3 assets valued based on the interest held by the plan, for which fair values of the underlying investments are subject to appraisal as directed by the funds' management.  This asset class includes a real estate fund that invests directly in real estate.  The underlying properties held in the funds are appraised utilizing the following approaches: the cost approach (the current cost of replacing the real estate less deterioration and functional and economic obsolescence); the income approach (the ability of the underlying properties to generate net rental income); and the comparable sales approach (recent sales of comparable real estate in the same market). The plan's ability to redeem these investments is subject to certain restrictions and cash availability.

Absolute return strategy: These are level 2 assets valued based on information provided by the plan's investment custodians. The financial statements of the partnerships are audited annually by independent accountants, with the value of the underlying investments based on the estimated fair value of the various holdings in the portfolio as reported in the financial statements at net asset value.  This asset class includes a hedge fund.  Our investment normally provides for a quarterly distribution subject to 95 days advance notice of withdrawal.  Currently there are no restrictions on withdrawal requests, and as of December 31, 2011 we have not submitted a withdrawal request.

Real return strategy:These are level 1 assets valued at the net asset value of the shares held by the plan at the valuation date.  This asset class includes an investment in a broad range of assets and strategies primarily including fixed income and equity securities, along with commodities.

Cash and cash equivalents: These are level 2 assets valued at the net asset value of the shares held by the plan at the valuation date.  This asset class primarily includes a money market mutual fund.

The preceding valuation methods may produce a fair value calculation that is not indicative of net realizable value or reflective of future fair values. Although we believe these valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.

Investment securities are exposed to various financial risks including interest rate, market and credit risks.  Due to the level of risk associated with certain investment securities, it is reasonably possible that changes in the values of our investment securities will occur in the near term and that such changes could materially affect our investment account balances and the amounts reported as plan assets available for benefits payments.

The following table presents the fair value of plan assets, including outstanding receivables and liabilities, of the Retirement Trust Fund as of December 31, 2011and 2010:

		December 31, 2011
Investments, in thousands				Level 1		Level 2		Level 3		Total
U.S. large cap equity			$	36,236	$	-	$	-	$	36,236
U.S. small/mid cap equity				-		27,310		-		27,310
Non-U.S. equity				22,158		11,587		-		33,745
Emerging markets equity				10,208		-		-		10,208
Fixed income				19,121		-		-		19,121
Long government/credit				-		18,897		-		18,897
Real estate funds				-		-		15,317		15,317
Absolute return strategy				-		30,475		-		30,475
Real return strategy				15,475		-		-		15,475
Cash and cash equivalents				-		9,290		-		9,290
	Total investments		$	103,198	$	97,559	$	15,317	$	216,074
		December 31, 2010
Investments, in thousands				Level 1		Level 2		Level 3		Total
U.S. large cap equity			$	37,231	$	-	$	-	$	37,231
U.S. small/mid cap equity				-		27,864		-		27,864
Non-U.S. equity				24,630		14,549		-		39,179
Emerging markets equity				11,476		-		-		11,476
Fixed income				36,429		-		-		36,429
Real estate funds				-		-		14,721		14,721
Absolute return strategy				-		32,378		-		32,378
Real return strategy				15,452		-		-		15,452
Cash and cash equivalents				-		3,629		-		3,629
	Total investments		$	125,218	$	78,420	$	14,721	$	218,359
							December 31,
Receivables								2011		2010
Accrued interest and dividend income							$	414	$	249
Due from broker for securities sold								321		448
	Total receivables						$	735	$	697
Liabilities
Due to broker for securities purchased							$	839	$	42
	Total investment in retirement trust						$	215,970	$	219,014

Level 3 Investments

The following table presents the beginning balance, activity and ending balance of Level 3 investments that have their fair values established using significant unobservable inputs as of December 31, 2011: 

				Level 3 Assets
Thousands				Real estate Funds
January 1, 2011 balance			$	14,721
	Total gains or (losses):
		Included in earnings (or changes in net assets)		596
December 31, 2011 balance			$	15,317

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Property, Plant and Equipment (tables)

12 Months Ended

Dec. 31, 2011

Public Utilities Property Plant And Equipment Abstract

Major Classifications Of Property, Plant And Equipment And Accumulated Depreciation [Text Block]

Thousands		2011		2010
Utility plant in service		$	2,323,467	$	2,247,952
Utility construction work in progress			36,051		29,324
Less accumulated depreciation			749,603		710,214
	Utility plant-net		1,609,915		1,567,062
Non-utility plant in service			293,205		290,038
Non-utility construction work in progress			8,379		9,088
Less accumulated depreciation			17,623		12,025
	Non-utility plant-net		283,961		287,101
Total property plant and equipment		$	1,893,876	$	1,854,163

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Gas Reserves and Other Investments (details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Gas Reserves [Abstract]
Term Of Gas Reserves Contract In Years	30 years
Peak Volume Of Gas Reserves Contract	13.00%
Gas Reserves Average Volume Over First Ten Years	approximately 8 to 10 percent
Annual Gas Reserves Investment	approximately $45 million to $55 million per year for five years
Total Expected Gas Reserves Investment	$ 250,000,000
Maximum Regulatory Variance Exposure	10,000,000
Changes In Fair Value Deferred As Income Statement For Contracts Not Qualifying For Hedge Accounting And To Other Comprehensive Income For Contracts Qualifying For Hedge Accounting Percent	10.00%
Net Gas Reserves Investment	36,300,000
Deferred Taxes Related To Gas Reserves	15,600,000
Palomar [Abstract]
Equity Method Investment Ownership Percentage	50.00%
Palomar West Zone Impairment	300,000
Palomar East Zone Impairment	1,000,000
Equity Method Investment Underlying Equity In Net Assets	13,500,000
Equity Method Investment Exposure	13,200,000
Other Investments [Abstract]
Life Insurance, Corporate or Bank Owned, Amount	51,911,000	51,090,000
Equity Method Investments	14,340,000	15,742,000
Other Investments	2,012,000	2,262,000
Other investments	$ 68,263,000	$ 69,094,000

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Leases

12 Months Ended

Dec. 31, 2011

Capital Leases of Lessee [Abstract]

Leases of Lessee Disclosure [Text Block]

14.Leases

We lease land, buildings and equipment under agreements that expire in various years through 2095. Rental expense under operating leases was $5.4 million, $5.1 million and $5.3 million for the years ended December 31, 2011, 2010 and 2009, respectively.  The table below reflects the future minimum lease payments due under non-cancelable leases at December 31, 2011.  These commitments relate principally to the lease of our office headquarters, underground gas storage facilities, vehicles and computer equipment.

												Later
Thousands		2012		2013		2014		2015		2016		years		Total
Operating leases	$	4,929	$	4,841	$	5,078	$	5,042	$	5,018	$	24,659	$	49,567
Capital leases		443		313		118		23		-		-		897
Minimum lease payments	$	5,372	$	5,154	$	5,196	$	5,065	$	5,018	$	24,659	$	50,464

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Summary of Significant Accounting Policies (tables)

12 Months Ended

Dec. 31, 2011

Accounting Policies Abstract

Schedule Of Regulatory Assets Text Block

			Regulatory Assets
Thousands			2011		2010
Current:
	Unrealized loss on derivatives(1)	$	57,317	$	38,437
	Pension and other postretirement benefit liabilities(2)		15,491		10,988
	Other(3)		21,865		3,289
Total current		$	94,673	$	52,714
Non-current:
	Unrealized loss on derivatives(1)	$	6,536	$	17,022
	Income tax asset		65,264		72,341
	Pension and other postretirement benefit liabilities(2)		170,512		118,248
	Environmental costs(4)		105,670		114,311
	Other(3)		23,410		26,975
Total non-current		$	371,392	$	348,897

Schedule Of Regulatory Liabilities Text Block

			Regulatory Liabilities
Thousands			2011		2010
Current:
	Gas costs	$	17,994	$	15,583
	Unrealized gain on derivatives(1)		2,853		2,245
	Other(3)		10,199		-
Total current		$	31,046	$	17,828
Non-current:
	Gas costs	$	8,420	$	2,297
	Unrealized gain on derivatives(1)		-		628
	Accrued asset removal costs		267,355		252,941
	Other(3)		2,607		2,165
Total non-current		$	278,382	$	258,031

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Income Tax (details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Deferred Tax Assets And Liabilities [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment	$ 292,235,000	$ 255,471,000
Deferred Tax Liabilities Regulatory Taxes Paid	2,106,000	5,272,000
Deferred Tax Liabilities, Regulatory Assets	65,755,000	68,822,000
Deferred Tax Liabilities, Regulatory Assets and Liabilities	35,638,000	23,159,000
Deferred Tax Liabilities Non Regulated Liabilities	43,373,000	34,544,000
Deferred Tax Liabilities	439,107,000	387,268,000
Deferred Tax Assets, Regulatory Assets and Liabilities	4,727,000	1,402,000
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits	5,119,000	4,342,000
Deferred Tax Assets Non Regulated Assets	1,161,000	772,000
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	1,626,000	1,702,000
Deferred Tax Assets, Tax Credit Carryforwards, Other	14,255,000	7,071,000
Deferred Tax Assets, Net	26,888,000	15,289,000
Deferred Tax Assets (Liabilities), Net	412,219,000	371,979,000
Accumulated Deferred Investment Tax Credit	(990,000)	(1,430,000)
Deferred tax liabilities	413,209,000	373,409,000
Income Tax Disclosure [Abstract]
Federal Refund From Prior Year Tax Return	14,400,000
Federal Refund From Second Prior Year Tax Return	22,300,000
Federal Refund From Amending Second Prior Year Tax Return	3,500,000
Operating Loss Carryforwards	33,700,000
State Refund From Prior Year Tax Return	3,500,000
IRS Tax Payment Due To Examination	1,500,000
IRS Interest Payment Due To Examination	200,000
State Tax Assessment Under Review	800,000
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract]
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate	37,550,000	42,745,000	42,627,000
Income Tax Reconciliation, State and Local Income Taxes	4,945,000	5,803,000	5,568,000
Income Tax Reconciliation, Tax Credits, Investment	(442,000)	(525,000)	(593,000)
Differences Regulatory Commission	1,647,000	1,647,000	(116,000)
Income Tax Reconciliation, Tax Credits, Other	(786,000)	(715,000)	(1,195,000)
Income Tax Reconciliation, Other Adjustments	468,000	507,000	380,000
Income tax expense	43,382,000	49,462,000	46,671,000
Effective Income Tax Rate Continuing Operations	40.40%	40.50%	38.30%
Tax Provision Current And Deferred [Abstract]
Current Federal Tax Expense (Benefit)	130,000	(28,592,000)	6,221,000
Current State and Local Tax Expense (Benefit)	(929,000)	1,441,000	2,300,000
Current Income Tax Expense (Benefit)	(799,000)	(27,151,000)	8,521,000
Deferred Federal Income Tax Expense (Benefit)	35,481,000	69,159,000	31,937,000
Deferred State and Local Income Tax Expense (Benefit)	8,700,000	7,454,000	6,213,000
Deferred Income Tax Expense (Benefit)	44,181,000	76,613,000	38,150,000
Income tax expense	43,382,000	49,462,000	46,671,000
Income taxes paid	1,756,000	22,600,000	10,000,000
Tax Provision Regulated And Nonutility [Abstract]
Regulated Current Tax Expense Benefit	(4,646,000)	(1,464,000)	871,000
Regulated Deferred And Local Tax Expense Benefit	50,152,000	47,741,000	40,829,000
Regulated Investments And Credits Tax Expense Benefit	(422,000)	(525,000)	(593,000)
Total Tax Provision Related To Regulated Utility	45,084,000	45,752,000	41,107,000
Non Utility Current Tax Expense Benefit	3,846,000	(25,687,000)	7,650,000
Non Utility Deferred And Local Tax Expense Benefit	(5,548,000)	29,397,000	(2,086,000)
Total Tax Provision Related To Non Utility	(1,702,000)	3,710,000	5,564,000
Income tax expense	$ 43,382,000	$ 49,462,000	$ 46,671,000

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Summary of Significant Accounting Policies (details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Accounting Policies Abstract
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	2.80%	2.80%	2.90%
Weighted Average Depreciation Rates Transmission Distribution	2.70%
Weighted Average Depreciation Rates Utility Storage	2.20%
Weighted Average Depreciation Rates General Plant	4.60%
Weighted Average Depreciation Rates Intangible Other	5.10%
Public Utilities, Allowance for Funds Used During Construction, Additions	0.50%	0.60%	1.00%
Outstanding Checks In Accounts Payable	$ 3,900,000
Unbilled Receivables, Current	61,925,000	64,803,000
Senate Bill Four Zero Eight Charge	7,400,000
Inventory - Gas	65,600,000	70,700,000
Inventory - Materials and supplies	8,800,000	9,700,000
Deferred Tax Liabilities, Deferred Expense	68,500,000	72,300,000
Table Of Regulatory Assets [Abstract]
Current Regulatory Assets	94,673,000	52,714,000
Regulatory Assets	371,392,000	348,897,000
Table Of Regulatory Liabilities [Abstract]
Current Regulatory Liabilities	31,046,000	17,828,000
Regulatory Liabilities	278,382,000	258,031,000
Gas Costs Payable [Member]
Table Of Regulatory Liabilities [Abstract]
Current Regulatory Liabilities	17,994,000	15,583,000
Regulatory Liabilities	8,420,000	2,297,000
Unrealized Gain On Derivatives [Member]
Table Of Regulatory Liabilities [Abstract]
Current Regulatory Liabilities	2,853,000	2,245,000
Regulatory Liabilities	0	628,000
Other Regulatory [Member]
Table Of Regulatory Liabilities [Abstract]
Current Regulatory Liabilities	10,199,000	0
Regulatory Liabilities	2,607,000	2,165,000
Accrued Asset Removal Costs [Member]
Table Of Regulatory Liabilities [Abstract]
Regulatory Liabilities	267,355,000	252,941,000
Unrealized Loss On Derivatives [Member]
Table Of Regulatory Assets [Abstract]
Current Regulatory Assets	57,317,000	38,437,000
Regulatory Assets	6,536,000	17,022,000
Pension and Other Postretirement Benefit Liabilities [Member]
Table Of Regulatory Assets [Abstract]
Current Regulatory Assets	15,491,000	10,988,000
Regulatory Assets	170,512,000	118,248,000
Other Regulatory [Member]
Table Of Regulatory Assets [Abstract]
Current Regulatory Assets	21,865,000	3,289,000
Regulatory Assets	23,410,000	26,975,000
Income Tax Asset [Member]
Table Of Regulatory Assets [Abstract]
Regulatory Assets	65,264,000	72,341,000
Environmental Costs [Member]
Table Of Regulatory Assets [Abstract]
Regulatory Assets	$ 105,670,000	$ 114,311,000

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Consolidated Balance Sheets (Parentheticals) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Consolidated Balance Sheets Parentheticals [Abstract]
Common Stock Shares Outstanding	26,756	26,668	26,533	26,501
Common Stock Shares Authorized	100,000	100,000

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Earnings Per Share

12 Months Ended

Dec. 31, 2011

Earnings per share of common stock [Abstract]

Earnings Per Share Text Block

3.Earnings Per Share

Basic earnings per share are computed using net income and the weighted average number of common shares outstanding for each period presented.  Diluted earnings per share are computed in the same manner, except it uses the weighted average number of common shares outstanding plus the effects of the assumed exercise of stock options and the 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:

Thousands, except per share amounts			2011		2010		2009
Net income		$	63,898	$	72,667	$	75,122
Average common shares outstanding - basic			26,687		26,589		26,511
	Additional shares for stock-based compensation plans		57		68		65
Average common shares outstanding - diluted			26,744		26,657		26,576
Earnings per share of common stock - basic		$	2.39	$	2.73	$	2.83
Earnings per share of common stock - diluted		$	2.39	$	2.73	$	2.83
Additional information:
	Antidilutive shares not included in net income per diluted
	common share calculation		2,101		743		2,142

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Earnings Per Share (tables)

12 Months Ended

Dec. 31, 2011

Earnings per share of common stock [Abstract]

EPS Calculation Table Text Block

Thousands, except per share amounts			2011		2010		2009
Net income		$	63,898	$	72,667	$	75,122
Average common shares outstanding - basic			26,687		26,589		26,511
	Additional shares for stock-based compensation plans		57		68		65
Average common shares outstanding - diluted			26,744		26,657		26,576
Earnings per share of common stock - basic		$	2.39	$	2.73	$	2.83
Earnings per share of common stock - diluted		$	2.39	$	2.73	$	2.83
Additional information:
	Antidilutive shares not included in net income per diluted
	common share calculation		2,101		743		2,142

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Commitments and Contingencies (tables)

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies Disclosure Abstract

Long-term Purchase Commitment [Table Text Block]

					Pipeline		Pipeline
			Gas		Capacity		Capacity
			Purchase		Purchase		Release
Thousands			Agreements		Agreements		Agreements
2012		$	98,534	$	91,027	$	3,464
2013			18,331		87,983		-
2014			15,290		82,898		-
2015			5,651		72,316		-
2016			-		61,358		-
Thereafter			-		287,541		-
	Total		137,806		683,123		3,464
	Less: Amount representing interest		682		99,252		2
	Total at present value	$	137,124	$	583,871	$	3,462

Schedule Of Environmental Loss Contingencies By Site Text Block

			Current Liabilities				Non-Current Liabilities
Thousands			2011		2010		2011		2010
Gasco site		$	16,510	$	11,366	$	44,697	$	38,921
Siltronic site			887		720		128		201
Portland Harbor site			1,089		2,304		7,066		5,784
Central Service Center site			-		5		495		510
Front Street site			1,697		1		-		1,097
Other sites			-		-		120		108
	Total	$	20,183	$	14,396	$	52,506	$	46,621

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Derivaitve Instruments

12 Months Ended

Dec. 31, 2011

Disclosure Derivative Instruments [Abstract]

Derivative Instruments Text Block

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 of 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.  

Certain natural gas purchases from Canadian suppliers are payable in Canadian dollars, including both commodity and demand charges, which expose us to adverse changes in foreign currency rates.  Foreign currency forward contracts are used to hedge the fluctuation in foreign currency exchange rates for our commodity and commodity-related demand charges paid in Canadian dollars.  Foreign currency contracts for commodity costs are purchased on a month-to-month basis because the Canadian cost is priced at the average noon-day exchange rate for each month.  Foreign currency contracts for demand costs have terms ranging up to 12 months.  The gains and losses on the shorter-term currency contracts for commodity costs are recognized immediately in cost of gas.  The gains and losses on the currency contracts for demand charges are not recognized in current income because they are subject to a regulatory deferral tariff and, as such, are recorded as a regulatory asset or liability. The mark-to-market adjustment at December 31, 2011 was an unrealized loss of $0.2million.  This unrealized gain is subject to regulatory deferral and, as such, was recorded as a derivative instrument, which is offset by recording a corresponding amount to a regulatory liability account.

Derivative hedge contracts are subject to a hedge effectiveness test to determine the financial statement treatment of each specific derivative.  As of December 31, 2011, all of our derivatives were effective economic hedges and either qualified or were expected to qualify for regulatory deferral or hedge accounting treatment.  The effectiveness test applied to financial derivatives is dependent on the type of derivative and its use. We use the hypothetical derivative method under accounting standards for derivatives and hedging to determine the hedge effectiveness for our interest rate swaps and the dollar offset method for other derivative contracts under accounting standards for derivatives and hedging. All derivatives were effective as of December 31, 2011.

The following table reflects the income statement presentation for the unrealized gains and losses from our derivative instruments for the year ended December 31, 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.

		2011								2010
Thousands		Natural gas commodity		(1)	Foreign exchange		(2)	Natural gas commodity		(1)	Foreign exchange(2)
Cost of sales		$	(60,799)		$	-		$	(52,677)		$	-
Other comprehensive income (loss)			-			(201)			-			91
Less:
Amounts deferred to regulatory accounts on balance sheet			60,799			201			52,677			(91)
	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 exchange forward purchase contracts is recorded in other comprehensive income, and reclassified to regulatory deferral accounts on the balance sheet.

No collateral was posted with or by our counterparties as of December 31, 2011or 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 $63.5 million at December 31, 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	$	-	$	-	$	2,013	$	9,585	$	45,869
Without Adequate Assurance Calls	$	-	$	-	$	851	$	5,923	$	37,206

As of December 31, 2011 and 2010, we realized net losses of $56.5 million and $61.0 million, respectively, from the settlement of natural gas hedge contracts at maturity, which were recorded as increases 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 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 from counterparties in order for them to meet our minimum credit requirement standards.

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; instead 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 earnings-at-risk trading limits.  Our credit risk for all outstanding derivatives at December 31, 2011currently does not extend beyond October 2013.

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.

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 December 31, 2011. As of December 31, 2011 and 2010, the fair value was a liability of $61.0 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 years ended December 31, 2011 and 2010.