Edgar Filing: NORTHWEST NATURAL GAS CO

form10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2012

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

For the transition period from _______ to _______

Commission File No. 1-15973

NORTHWEST NATURAL GAS COMPANY

(Exact name of registrant as specified in its charter)

Oregon	93-0256722
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

220 N.W. Second Avenue, Portland, Oregon 97209

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: (503) 226-4211

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [ X ] No [ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [ X ] No [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer [ X ]	Accelerated filer [ ]
Non-accelerated filer [ ]	Smaller reporting company [ ]

(Do not check if a smaller reporting company)

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

Yes [ ] No [ X ]

At July 27, 2012, 26,831,575 shares of the registrant’s Common Stock (the only class of Common Stock) were outstanding.

NORTHWEST NATURAL GAS COMPANY

For the Quarterly Period Ended June 30, 2012


	PART I. FINANCIAL INFORMATION
		Page Number
	Forward-Looking Statements	1

Item 1.	Consolidated Financial Statements:

	Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2012 and 2011	2

	Consolidated Balance Sheets at June 30, 2012 and 2011 and December 31, 2011	3

	Consolidated Statements of Cash Flows for the six months ended June 30, 2012 and 2011	5

	Notes to Consolidated Financial Statements	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33

Item 4.	Controls and Procedures	33

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	34

Item 1A.	Risk Factors	34

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34

Item 6.	Exhibits	34

	Signature	35

Table of Contents

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;

·	operational performance and costs;

·	liquidity and financial positions;

·	project development and expansion;

·	competition;

·	storage levels and values;

·	procurement, development and production levels of gas supplies and reserves;

·	estimated expenditures and investments;

·	costs of compliance;

·	credit exposures;

·	potential efficiencies;

·	impacts of laws, rules and regulations;

·	tax liabilities or refunds;

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

·	projected status and obligations under retirement plans;

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

·	approval and adequacy of regulatory deferrals; and

·	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 in our 2011 Annual Report on Form 10-K, Part I, Item 1A. “Risk Factors” and Part II, Item 7. and Item 7A., “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures about Market Risk,” and in Part I, Items 2 and 3, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures About Market Risk,” and Part II, Item 1A, “Risk Factors,” herein.

Any forward-looking statement made by us in this report speaks only as of the date on which it is made. Factors or events that could cause our actual results to differ may emerge from time to time, and it is not possible for us to predict all of them. We undertake no obligation to publicly update any forward-looking statement, whether as a result of new information, future developments or otherwise, except as may be required by law.

Table of Contents

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Statements of Comprehensive Income
(Unaudited)


	Three Months Ended				Six Months Ended
	June 30,				June 30,
Thousands, except per share amounts	2012		2011		2012		2011
Operating revenues:
Gross operating revenues	$	106,569	$	161,197	$	424,063	$	484,285
Less: Cost of sales		34,512		90,122		204,283		270,747
Revenue taxes		2,578		3,843		10,433		11,798
Net operating revenues		69,479		67,232		209,347		201,740
Operating expenses:
Operations and maintenance		32,124		30,374		66,540		61,546
General taxes		7,417		6,659		16,253		14,824
Depreciation and amortization		18,099		17,546		36,049		34,855
Total operating expenses		57,640		54,579		118,842		111,225
Income from operations		11,839		12,653		90,505		90,515
Other income and expense - net		921		1,122		1,926		2,336
Interest expense - net		10,464		10,266		21,655		20,715
Income before income taxes		2,296		3,509		70,776		72,136
Income tax expense		887		1,316		28,760		29,170
Net income		1,409		2,193		42,016		42,966
Other comprehensive income:
Amortization of non-qualified employee benefit
plan liability, net of taxes of $109 and $96 for
the three months and $217 and $192 for the
six months ended June 30, 2012 and 2011,
respectively		166		146		332		292
Comprehensive income	$	1,575	$	2,339	$	42,348	$	43,258
Average common shares outstanding:
Basic		26,812		26,673		26,797		26,671
Diluted		26,896		26,727		26,879		26,725
Earnings per share of common stock:
Basic	$	0.05	$	0.08	$	1.57	$	1.61
Diluted	$	0.05	$	0.08	$	1.56	$	1.61
Dividends declared per share of common stock	$	0.445	$	0.435	$	0.890	$	0.870

See Notes to Consolidated Financial Statements.

Table of Contents

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Balance Sheets
(Unaudited)



	June 30,			June 30,			December 31,
Thousands	2012			2011			2011
Assets:
Current assets:
Cash and cash equivalents	$	4,002		$	3,700		$	5,833
Restricted cash		-			925			-
Accounts receivable		13,459			39,104			77,449
Accrued unbilled revenue		12,921			15,031			61,925
Allowance for uncollectible accounts		(2,653	)		(2,824	)		(2,895	)
Regulatory assets		65,297			59,766			94,673
Derivative instruments		2,142			4,433			2,853
Inventories		68,868			71,229			74,363
Gas reserves		11,021			749			4,463
Income taxes receivable		3,119			26,285			7,045
Other current assets		8,606			9,496			22,980
Total current assets		186,782			227,894			348,689
Non-current assets:
Property, plant and equipment		2,720,037			2,612,147			2,661,102
Less: Accumulated depreciation		791,021			744,929			767,226
Total property, plant and equipment - net		1,929,016			1,867,218			1,893,876
Gas reserves		65,026			15,403			47,451
Regulatory assets		366,981			326,081			371,392
Derivative instruments		1,170			1,042			-
Other investments		68,230			68,576			68,263
Restricted cash		4,000			-			4,000
Other non-current assets		13,936			15,780			12,903
Total non-current assets		2,448,359			2,294,100			2,397,885
Total assets	$	2,635,141		$	2,521,994		$	2,746,574

See Notes to Consolidated Financial Statements.

Table of Contents

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Balance Sheets
(Unaudited)



	June 30,			June 30,			December 31,
Thousands	2012			2011			2011
Capitalization and liabilities:
Capitalization:
Common stock - no par value; authorized 100,000 shares; issued and outstanding 26,827, 26,673, and 26,756 at June 30, 2012 and 2011 and December 31, 2011, respectively	$	352,955		$	344,451		$	348,383
Retained earnings		392,082			376,489			373,905
Accumulated other comprehensive income (loss)		(7,467	)		(6,312	)		(7,800	)
Total common stock equity		737,570			714,628			714,488
Long-term debt		641,700			551,700			641,700
Total capitalization		1,379,270			1,266,328			1,356,188

Current liabilities:
Short-term debt		113,200			185,400			141,600
Current maturities of long-term debt		-			40,000			40,000
Accounts payable		48,361			54,148			86,300
Taxes accrued		5,205			6,805			10,747
Interest accrued		5,607			5,127			5,857
Regulatory liabilities		20,748			25,784			31,046
Derivative instruments		29,407			25,986			57,317
Other current liabilities		42,336			37,574			41,597
Total current liabilities		264,864			380,824			414,464

Deferred credits and other non-current liabilities:
Deferred tax liabilities		440,073			398,825			413,209
Regulatory liabilities		280,295			265,703			278,382
Pension and other postretirement benefit liabilities		185,844			130,985			201,530
Derivative instruments		2,130			9,202			6,536
Other non-current liabilities		82,665			70,127			76,265
Total deferred credits and other non-current liabilities		991,007			874,842			975,922
Commitments and contingencies (see Note 13)
Total capitalization and liabilities	$	2,635,141		$	2,521,994		$	2,746,574

See Notes to Consolidated Financial Statements.

Table of Contents

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Statements of Cash Flows
(Unaudited)

	Six Months Ended
	June 30,
Thousands	2012			2011
Operating activities:
Net income	$	42,016		$	42,966
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization		36,049			34,855
Non-cash expenses related to qualified defined benefit pension plans		4,109			3,655
Contributions to qualified defined benefit pension plans		(18,400	)		(16,445	)
Deferred environmental expenditures, net of recoveries		(3,925	)		(1,770	)
Other		1,459			(819	)
Changes in assets and liabilities:
Receivables		114,117			79,711
Inventories		5,495			9,156
Taxes accrued		(1,616	)		11,007
Accounts payable		(37,854	)		(30,052	)
Interest accrued		(250	)		(55	)
Deferred gas costs		(11,830	)		2,682
Deferred tax liabilities		28,676			27,516
Other - net		17,336			6,328
Cash provided by operating activities		175,382			168,735
Investing activities:
Capital expenditures		(61,552	)		(47,815	)
Utility gas reserves		(27,060	)		(16,152	)
Other		61			67
Cash used in investing activities		(88,551	)		(63,900	)
Financing activities:
Common stock issued (purchased) - net, including common stock expense		2,910			(70	)
Long-term debt retired		(40,000	)		(10,000	)
Change in short-term debt		(28,400	)		(72,035	)
Cash dividend payments on common stock		(23,839	)		(23,204	)
Other		667			717
Cash used in financing activities		(88,662	)		(104,592	)
Increase (decrease) in cash and cash equivalents		(1,831	)		243
Cash and cash equivalents - beginning of period		5,833			3,457
Cash and cash equivalents - end of period	$	4,002		$	3,700

Supplemental disclosure of cash flow information:
Interest paid	$	21,652		$	20,770
Income taxes paid	$	2,648		$	1,522

See Notes to Consolidated Financial Statements.

Table of Contents

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Notes to Consolidated Financial Statements

(Unaudited)

1.	Organization and Principles of Consolidation

The accompanying consolidated financial statements represent the consolidation of Northwest Natural Gas Company (NW Natural, the Company or we) and all companies that we directly or indirectly control, either through majority ownership or otherwise. Our direct and indirect wholly-owned subsidiaries include NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), Gill Ranch Storage, LLC (Gill Ranch) 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 and notes have been reclassified 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.

Information presented in these interim consolidated financial statements is unaudited, but includes all material adjustments that management considers necessary for a fair statement of the results for each period reported including normal recurring accruals. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes included in our 2011 Annual Report on Form 10-K (2011 Form 10-K). A significant part of our business is of a seasonal nature; therefore, results of operations for interim periods are not necessarily indicative of the results for a full year.

2. Significant Accounting Policies Update

Our significant accounting policies are described in Note 2 of the 2011 Form 10-K. There were no material changes to those accounting policies during the six months ended June 30, 2012. The following are current updates to certain critical accounting policy estimates, subsequent events of the Company, and accounting standards in general.

Regulatory Accounting

In applying regulatory accounting principles in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP), we capitalize or defer certain costs and revenues as regulatory assets and liabilities. At June 30, 2012 and 2011 and at December 31, 2011, the amounts deferred as regulatory assets and liabilities were as follows:

Regulatory Assets
	June 30,		June 30,		December 31,
Thousands	2012		2011		2011
Current:
Unrealized loss on derivatives(1)	$	29,407	$	25,986	$	57,317
Pension and other postretirement benefit liabilities(2)		15,491		10,988		15,491
Other(3)		20,399		22,792		21,865
Total current	$	65,297	$	59,766	$	94,673
Non-current:
Unrealized loss on derivatives(1)	$	2,130	$	9,202	$	6,536
Pension balancing(2)		10,766		2,659		6,008
Income tax asset		63,452		70,241		65,264
Pension and other postretirement benefit liabilities(2)		162,767		112,743		170,512
Environmental costs(4)		117,905		120,285		105,670
Other(3)		9,961		10,951		17,402
Total non-current	$	366,981	$	326,081	$	371,392

Regulatory Liabilities
	June 30,		June 30,		December 31,
Thousands	2012		2011		2011
Current:
Gas costs	$	12,980	$	17,538	$	17,994
Unrealized gain on derivatives(1)		2,142		4,433		2,853
Other(3)		5,626		3,813		10,199
Total current	$	20,748	$	25,784	$	31,046
Non-current:
Gas costs	$	1,504	$	3,023	$	8,420
Unrealized gain on derivatives(1)		1,170		1,042		-
Accrued asset removal costs		274,756		259,593		267,355
Other(3)		2,865		2,045		2,607
Total non-current	$	280,295	$	265,703	$	278,382

(1)	Unrealized gains or losses on derivatives are non-cash items and therefore do 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 costs of the utility are approved for regulatory deferral, including amounts recorded to the pension balancing account, to mitigate the effects of higher and lower pension expenses. Pension costs that are deferred include an interest component when recognized in net periodic benefit costs or earn a rate of return or carrying charge (see Note 8).

(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 a carrying charge to be determined in a future proceeding.

Table of Contents

Subsequent Events

See Note 14 for information regarding the private placement bond purchase agreement entered into on July 12, 2012 and Note 7 for more detail on our debt.

New Accounting Standards

Recent Accounting Pronouncements

Balance Sheet Offsetting. In December 2011, the Financial Accounting Standards Board (FASB) issued authoritative guidance regarding the offsetting of assets and liabilities on the balance sheet. The 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.

3.	Earnings Per Share

Basic earnings per share are computed using the weighted-average number of common shares outstanding for each period presented. Diluted earnings per share are computed using the weighted-average number of common shares outstanding plus the potential effects of the assumed exercise of stock options, and payment of estimated stock awards from other stock-based compensation plans that are outstanding, at the end of each period presented. Diluted earnings per share are calculated as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Thousands, except per share amounts	2012		2011		2012		2011
Net income	$	1,409	$	2,193	$	42,016	$	42,966
Average common shares outstanding - basic		26,812		26,673		26,797		26,671
Additional shares for stock-based compensation
plans outstanding (See Note 6)		84		54		82		54
Average common shares outstanding - diluted		26,896		26,727		26,879		26,725
Earnings per share of common stock - basic	$	0.05	$	0.08	$	1.57	$	1.61
Earnings per share of common stock - diluted	$	0.05	$	0.08	$	1.56	$	1.61
Antidilutive shares		1,180		8,946		943		3,883

Table of Contents

4.	Segment Information

We operate in two primary reportable business segments, which we refer to as “utility” 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 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 underground storage facility in Oregon (Mist); and revenues from 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. For the periods presented, intersegment transactions were insignificant. For further discussion of our segments, see Note 4 in our 2011 Form 10-K.

The following table presents summary financial information about the reportable segments for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,
				Non-Utility
Thousands		Utility			Gas Storage		Other			Total
2012
Net operating revenues		$	61,440		$	7,996	$	43		$	69,479
Depreciation and amortization			16,478			1,621		-			18,099
Income from operations			8,547			3,264		28			11,839
Net income (loss)			312			1,124		(27	)		1,409
2011
Net operating revenues		$	60,048		$	7,197	$	(13	)	$	67,232
Depreciation and amortization			15,946			1,600		-			17,546
Income (loss) from operations			9,667			3,017		(31	)		12,653
Net income (loss)			1,090			1,315		(212	)		2,193

	Six Months Ended June 30,
				Non-Utility
Thousands		Utility			Gas Storage		Other			Total
2012
Net operating revenues		$	194,590		$	14,675	$	82		$	209,347
Depreciation and amortization			32,816			3,233		-			36,049
Income from operations			84,511			5,943		51			90,505
Net income (loss)			40,103			1,930		(17	)		42,016
Total assets at June 30, 2012			2,331,610			287,622		15,909			2,635,141
2011
Net operating revenues		$	189,210		$	12,501	$	29		$	201,740
Depreciation and amortization			31,860			2,995		-			34,855
Income (loss) from operations			85,791			4,733		(9	)		90,515
Net income (loss)			41,220			2,003		(257	)		42,966
Total assets at June 30, 2011			2,247,349			252,393		22,252			2,521,994

Total assets at December 31, 2011		$	2,435,888		$	294,637	$	16,049		$	2,746,574

5.	Common Stock

We have a share repurchase program for our common stock under which we may purchase shares on the open market or through privately negotiated transactions. We currently have Board authorization through May 2013 to repurchase up to an aggregate of 2.8 million shares, but not to exceed $100 million. No shares of common stock were repurchased pursuant to this program during the six months ended June 30, 2012. Since the plan’s inception in 2000 a total of 2.1 million shares have been repurchased at a total cost of $83.3 million.

Table of Contents

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

6.	Stock-Based Compensation

Our stock-based compensation plans include a Long-Term Incentive Plan (LTIP), an Employee Stock Purchase Plan, and a Restated Stock Option Plan (Restated SOP). The Restated SOP was terminated in the second quarter of 2012 as approved by shareholders. Shareholders also approved the amended LTIP and added 250,000 shares to the plan. These plans are designed to promote stock ownership in NW Natural by employees and officers. For additional information on our stock-based compensation plans, see Note 6, in the 2011 Form 10-K and current updates provided below.

Long-Term Incentive Plan

In the second quarter of 2012 shares available for issuance under the LTIP were increased from 600,000 shares to 850,000 shares. The additional 250,000 shares may only be used for option grants under the LTIP and not for full-value awards such as Restricted Stock Units (RSUs) or performance shares.

Performance-Based Stock Awards. On February 22, 2012, 35,340 performance-based shares were granted under the LTIP, which include a market condition, based on target-level awards and a weighted-average grant date fair value of $53.92 per share. Fair value was estimated as of the date of grant using a Monte-Carlo option pricing model based on the following assumptions:

Stock price on valuation date	$	48.00
Performance term (in years)		3.0
Quarterly dividends paid per share	$	0.445
Expected dividend yield		3.6	%
Dividend discount factor		0.9012

Restricted Stock Units. The current LTIP allows for a variety of awards including RSUs to be granted. The RSUs awarded include a performance based threshold and a vesting period of four years from the grant date. The Company is obligated upon vesting of an RSU 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. On February 22, 2012, RSUs totaling 21,720 were granted with a grant date fair value of $48.00 per share.

Restated Stock Option Plan

As of June 30, 2012, there was $0.7 million of unrecognized compensation cost from grants of stock options in prior years, which is expected to be recognized over a period extending through 2014. The Restated SOP was terminated in the second quarter of 2012; however, the outstanding options may still be exercised through their expiration dates. Any new grants of stock options would be made under the LTIP; however, no new stock options were granted in the six months ended June 30, 2012.

7.	Cost and Fair Value Basis of Debt

Cost and Fair Value of Short-Term Debt

Our short-term debt consists of commercial paper and notes payable with an average maturity date of September 17, 2012 and an outstanding balance of $113.2 million as of June 30, 2012. The fair value of our commercial paper approximates the amortized cost using Level 2 inputs. Level 2 in the fair value hierarchy are inputs that have significant other observable inputs.

Cost of Long-Term Debt

Our utility’s long-term debt consists of secured medium-term notes (MTNs) with maturity dates ranging from 2014 through 2035, interest rates ranging from 3.176 percent to 9.05 percent, and a weighted-average coupon rate of 5.85 percent. In March of 2012, we redeemed $40 million of MTNs. See Note 14 for more information regarding the bond purchase agreement for the sale and issuance of first mortgage bonds subsequent to June 30, 2012.

Our gas storage segment’s long-term debt consists of $40 million of fixed and variable senior secured notes with a maturity date of November 30, 2016. The $20 million fixed rate notes have an interest rate of 7.75 percent, and the $20 million variable rate notes currently have an interest rate of 7.00 percent. The notes are secured by all of the membership interests in Gill Ranch Storage, LLC and are nonrecourse to NW Natural. See Note 7 in our 2011 Form 10-K for more detail on our long-term debt.

Fair Value of Long-Term Debt

As our outstanding debt does not trade in active markets, we used interest rates of other companies’ outstanding debt issuances that actively trade in public markets and have similar credit ratings, terms and remaining maturities to estimate the fair value of our long-term debt issuances. These inputs are Level 2 inputs. 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:

	June 30,				December 31,
Thousands	2012		2011		2011
Carrying amount	$	641,700	$	591,700	$	681,700
Estimated fair value	$	768,429	$	678,281	$	808,724

Table of Contents

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

8.	Pension and Other Postretirement Benefit Costs

The following tables provide the components of net periodic benefit cost for our company-sponsored qualified and non-qualified defined benefit pension plans and other postretirement benefit plans:

	Three Months Ended June 30,
								Other Postretirement
		Pension Benefits						Benefits
Thousands		2012			2011			2012			2011
Service cost		$	2,130		$	1,900		$	177		$	168
Interest cost			4,304			4,526			315			343
Expected return on plan assets			(4,639	)		(4,456	)		-			-
Amortization of net actuarial loss			3,844			2,692			103			68
Amortization of prior service costs			49			88			49			49
Amortization of transition obligations			-			-			103			103
Net periodic benefit cost			5,688			4,750			747			731
Amount allocated to construction			(1,428	)		(1,251	)		(215	)		(229	)
Amount deferred to regulatory balancing account(1)			(2,094	)		(1,329	)		-			-
Net amount charged to expense		$	2,166		$	2,170		$	532		$	502

	Six Months Ended June 30,
								Other Postretirement
		Pension Benefits						Benefits
Thousands			2012			2011			2012			2011
Service cost		$	4,260		$	3,799		$	354		$	336
Interest cost			8,608			9,053			629			687
Expected return on plan assets			(9,277	)		(8,912	)		-			-
Amortization of net actuarial loss			7,687			5,384			206			136
Amortization of prior service costs			98			176			98			98
Amortization of transition obligations			-			-			206			206
Net periodic benefit cost			11,376			9,500			1,493			1,463
Amount allocated to construction			(2,846	)		(2,486	)		(429	)		(455	)
Amount deferred to regulatory balancing account(1)			(4,162	)		(2,659	)		-			-
Net amount charged to expense		$	4,368		$	4,355		$	1,064		$	1,008

(1) Effective January 1, 2011, the Oregon Public Utility Commission (OPUC) approved the deferral of certain pension expenses above or below the amount set in rates, with recovery of these deferred amounts through the implementation of a balancing account, which includes the expectation of lower pension expenses in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return. See "Regulatory Accounting" in Note 2.

Employer Contributions to Company-Sponsored Defined Benefit Pension Plans

In the six months ended June 30, 2012, we made cash contributions totaling $18.4 million to our qualified defined benefit pension plans. We also expect to make additional contributions up to $10 million to these qualified plans over the last six months of 2012, plus we expect to make ongoing benefit payments under our unfunded, non-qualified pension plans and other postretirement benefit plans.

Multiemployer Pension and Defined Contribution Plans

In addition to the company-sponsored defined benefit pension plans referred to above, we contribute to a multiemployer pension plan (EIN 94-6076144) for our utility’s bargaining unit employees, known as the Western States Office and Professional Employees Pension Fund (Western States Plan), and to defined contribution plans for utility and non-utility employees. The costs of these plans are in addition to pension expense in the table above. Our contributions to the Western States Plan amounted to $0.2 million, for the six months ended June 30, 2012 and 2011, respectively. Under the terms of our current collective bargaining agreement, 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. We do not recognize a liability currently for the Western States Plan because we have made no decision to withdraw from the plan.

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 $1.2 million and $1.3 million for the six months ended June 30, 2012 and 2011, respectively.

See Note 9, in the 2011 Form 10-K for more information about these plans.

9. Income Tax

The effective income tax rate for the six months ended June 30, 2012 and 2011 varied from the combined federal and state statutory tax rates principally due to the following:

	June 30,
	2012			2011
Federal statutory tax rate		35.0	%		35.0	%
Increase (decrease):
Current state income tax, net of federal tax benefit		4.5	%		4.5	%
Amortization of investment and energy tax credits		(0.3	) %		(0.4	) %
Differences required to be flowed-through by regulatory commissions		1.5	%		1.6	%
Gains on company and trust-owned life insurance		(0.7	) %		(0.6	) %
Other - net		0.6	%		0.3	%
Effective income tax rate		40.6	%		40.4	%

See Note 10 in our 2011 Form 10-K for more detail on income taxes and effective tax rates.

Table of Contents

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

10.	Property, Plant and Equipment

The following table sets forth the major classifications of our property, plant and equipment and accumulated depreciation as of June 30, 2012 and 2011 and December 31, 2011:

	June 30,				December 31,
Thousands	2012		2011		2011
Utility plant in service	$	2,363,061	$	2,281,407	$	2,323,467
Utility construction work in progress		54,039		32,814		36,051
Less: Accumulated depreciation		770,825		730,199		749,603
Utility plant-net		1,646,275		1,584,022		1,609,915
Non-utility plant in service		296,619		290,035		293,205
Non-utility construction work in progress		6,318		7,891		8,379
Less: Accumulated depreciation		20,196		14,730		17,623
Non-utility plant-net		282,741		283,196		283,961

Total property, plant and equipment	$	1,929,016	$	1,867,218	$	1,893,876

11. Gas Reserves and Other Investments

Our gas reserves are stated at cost, net of volumetric regulatory amortization, with the associated deferred tax benefits recorded as liabilities on the balance sheet. Other investments include financial investments in life insurance policies, which are accounted for at fair value, and equity investments in certain partnerships and limited liability companies, which are accounted for under the equity or cost methods. See Note 12 in the 2011 Form 10-K for more detail on our investments.

Gas Reserves

We entered into agreements with Encana Oil & Gas (USA) Inc. (Encana) to develop and produce physical gas reserves that are expected to supply a portion of NW Natural’s utility customers’ requirements over 30 years. Encana began drilling in 2011 under these agreements, and we are currently receiving gas from our interests in a section of the gas field. Our cost of gas and the carrying cost of the investment are included in our annual Oregon Purchased Gas Adjustment (PGA) filing and recovered through rates in a manner previously approved by the OPUC. This transaction accounted for approximately 3% of our gas supplies for the six months ended June 30, 2012. The following table outlines our net investment at June 30, 2012 and 2011 and December 31, 2011:

	June 30,				December 31,
Thousands	2012		2011		2011
Gas reserves, current	$	11,021	$	749	$	4,463
Gas reserves, non-current		69,097		15,403		48,597
Less: Accumulated amortization		4,071		-		1,146
Total gas reserves		76,047		16,152		51,914

Less: Deferred taxes on gas reserves		26,839		3,440		15,630

Net investment in gas reserves	$	49,208	$	12,712	$	36,284

Variable Interest Entity (VIE) Analysis. We concluded that the arrangements with Encana qualify as a VIE, but that we are not the primary beneficiary of these activities as defined by the authoritative guidance related to consolidations. We account for our investment in the VIE on the cost basis and it is included under gas reserves on our balance sheet. Our maximum loss exposure related to the VIE is limited to our investment balance.

Palomar

PGH is a development stage variable interest entity. Palomar, a wholly-owned subsidiary of PGH, is pursuing the development of a new gas transmission pipeline that would provide an interconnection with our utility distribution system. PGH is owned 50 percent by NWN Energy and 50 percent by TransCanada American Investments Ltd., an indirect wholly-owned subsidiary of TransCanada Corporation.

Variable Interest Entity (VIE) Analysis. As of June 30, 2012, there were no changes to our VIE analysis and we continue not to be 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, including Palomar, 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. There have been no significant changes in carrying value or estimated fair value since yearend.

Our investment balance in Palomar was $13.5 million at June 30, 2012, which consists of costs related to the east segment. We are continuing to work on development of commercial support and Palomar expects to file a new Federal Energy Regulatory Commission (FERC) certification application to reflect a revised scope based on regional needs for the eastern segment of the proposed Palomar pipeline project. However, if we learn later that the project is not viable or will not go forward, 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. See Note 12 in our 2011 Form 10-K for more detail on Palomar and our annual impairment analysis.

Table of Contents

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

12.	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.

The following table reflects the income statement presentation for the unrealized gains and losses from our derivative instruments for the three and six months ended June 30, 2012 and 2011. All of our currently outstanding derivative instruments are related to regulated utility operations as illustrated by the derivative gains and losses being deferred to balance sheet accounts in accordance with regulatory accounting standards.

	Three Months Ended
	June 30, 2012							June 30, 2011
Thousands		Natural gas commodity(1)			Foreign currency (2)				Natural gas commodity(1)			Foreign currency (2)
Cost of sales		$	27,780		$	-			$	3,631		$	-
Other comprehensive income (loss)			-			(237	)			-			(196	)
Less:
Amounts deferred to regulatory accounts on balance sheet			(27,780	)		237				(3,631	)		196
Total impact on earnings		$	-		$	-			$	-		$	-

	Six Months Ended
	June 30, 2012							June 30, 2011
Thousands		Natural gas commodity(1)			Foreign currency (2)				Natural gas commodity(1)			Foreign currency (2)
Cost of sales		$	(28,114	)	$	-			$	(30,119	)	$	-
Other comprehensive income (loss)			-			(111	)			-			406
Less:
Amounts deferred to regulatory accounts on balance sheet			28,114			111				30,119			(406	)
Total impact on earnings		$	-		$	-			$	-		$	-

(1)Unrealized gain (loss) from natural gas commodity hedge contracts is recorded in cost of sales and reclassified to regulatory deferral accounts on the balance sheet.
(2)Unrealized gain (loss) from foreign currency exchange contracts is recorded in other comprehensive income, and reclassified to regulatory deferral accounts on the balance sheet.

No collateral was posted with or by our counterparties as of June 30, 2012 or 2011. 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 2011 or 2012. 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 $28.2 at June 30, 2012, 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	$	-	$	-	$	-	$	-	$	15,342
Without Adequate Assurance Calls	$	-	$	-	$	-	$	-	$	19,222

In the three and six months ended June 30, 2012, we realized net losses of $21.3 million and $50.7 million, respectively, from the settlement of natural gas hedge contracts at maturity, which were recorded as increases to the cost of gas, compared to net losses of $8.7 million and $29.6 million, respectively, for the three and six months ended June 30, 2011. The exchange rate in all foreign currency forward purchase contracts is included in our purchased cost of gas at settlement; therefore, no gain or loss is recorded from the settlement of those contracts.

We are exposed to derivative credit and liquidity risk primarily through securing fixed price natural gas commodity swaps to hedge the risk of price increases for our natural gas purchases made on behalf of our customers. For more information on our derivative instruments, see Note 13 in our 2011 Form 10-K.

Fair Value

In accordance with fair value accounting, we include nonperformance risk in calculating fair value adjustments. This includes a credit risk adjustment based on the credit spreads of our counterparties when we are in an unrealized gain position, or on our own credit spread when we are in an unrealized loss position. The inputs in our valuation techniques include natural gas futures, volatility, credit default swap spreads and interest rates. Additionally, our assessment of non-performance risk is generally derived from the credit default swap market and from bond market credit spreads. The impact of the credit risk adjustments for all outstanding derivatives was immaterial to the fair value calculation at June 30, 2012. As of June 30, 2012 and 2011 and December 31, 2011, the fair value was $28.2 million, $29.7 million and $61.0 million, respectively, using significant other observable, or Level 2, inputs. We have used no Level 3 inputs in our derivative valuations. We did not have any transfers between Level 1 or Level 2 during the six months ended June 30, 2012 and 2011.

Table of Contents

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

13.	Commitments and Contingencies

Environmental Matters

We own, or previously owned, properties that may require environmental remediation or action. We accrue all material loss contingencies relating to these properties that we believe to be probable of assertion and reasonably estimable. We continue to study and evaluate the extent of our potential environmental liabilities, but due to the numerous uncertainties surrounding the course of environmental remediation and the preliminary nature of several site investigations, in some cases, we may not be able to reasonably estimate the high end of the range of possible loss. In those cases we have disclosed the nature of the possible loss and the fact that the high end of the range cannot be reasonably estimated.

We regularly review our environmental liability for each site where we may be exposed to remediation responsibilities, but the costs 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. Site investigations and remediation efforts often develop slowly over many years. 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 and ultimately also the cost. Many of these steps are dependent upon the approval and direction of federal and state environmental regulators whose policies, determinations and directions may change over time creating further uncertainty as to the timing and scope of remediation activities. In certain cases there are a number of other potentially responsible parties in addition to us, each of which may influence the course and scope of the remediation effort. The allocation of liability among the potentially responsible parties is subject to dispute and uncertainty at this time with respect to the sites noted below. These disputes could lead to adversarial administrative proceedings or litigation, with uncertain outcomes.

We estimate the range of loss for environmental liabilities using current remediation technology, enacted laws and regulations, industry experience gained at similar sites and an assessment of the probable level of involvement and financial condition of other potentially responsible parties. Unless there is an estimate within a range of possible losses that is more likely than other cost estimates within that range, we record the liability at the low 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 determination by regulators of remediation alternatives. The status of each of the sites currently under investigation is provided below.

Portland Harbor site. In 1998, the Oregon Department of Environmental Quality (ODEQ) and the Environmental Protection Agency (EPA) completed a study of sediments in a 5.5-mile segment of the Willamette River (Portland Harbor). Since then, EPA has extended the Portland Harbor site to approximately 11 miles of the Willamette River. The Portland Harbor site is adjacent to two upland sites owned by NW Natural that are discussed below as the Gasco upland and Siltronic upland 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 (the Lower Willamette Group or LWG) to fund the Portland Harbor Remedial Investigation/Feasibility Study (RI/FS), as discussed below. The LWG submitted the draft Final Portland Harbor Remedial Investigation to EPA in 2011. The LWG submitted the draft Feasibility Study (FS) to EPA in March 2012. The EPA will use the information in the RI/FS to select a cleanup plan for the Portland Harbor Superfund Site. The draft FS provides a range of remedial costs for the entire Portland Harbor Superfund Site, which includes the Gasco/Siltronic Sediment site, discussed below. The range of costs estimated for various remedial alternatives for the entire Portland Harbor, as provided in the draft FS, is $169 million to $1.8 billion. NW Natural's potential liability is a portion of the costs of the remedy EPA ultimately selects for the entire Portland Harbor Superfund site. The cost of that remedy is expected to be allocated among more than 100 potentially responsible parties. NW Natural is participating in a non-binding allocation process in an effort to settle this potential liability. On June 22, 2012, EPA delivered a notice of non-compliance to the LWG with respect to the Baseline Human Health Risk Assessment the LWG submitted to EPA in May 2011 (BHHRA), as a component of the RI. The LWG has disputed the EPA’s claims that the BHHRA is in any way deficient or noncompliant and has initiated formal dispute resolution under the 2001 Administrative Settlement Agreement and Order on Consent issued by EPA to LWG.

Gasco/Siltronic Sediments. In 2009, NW Natural and Siltronic Corporation entered into a separate Administrative Order on Consent with EPA to evaluate and design specific remedies for sediments adjacent to the Gasco upland and Siltronic upland sites. The Gasco/Siltronic Sediments is part of the Portland Harbor Superfund site. NW Natural submitted a draft Engineering Evaluation/Cost Analysis (EE/CA) to the EPA in May 2012 to provide the estimated cost of potential remedial alternatives for this site. The EE/CA will provide a variety of remedial alternatives for the sediments at this site. The alternatives provided in the EE/CA are based on EPA requirements to develop costs for the various remedies described therein. At this time, the estimated costs for the various sediment remedy alternatives in the draft EE/CA range from $34 million to $350 million. After the EPA determines an appropriate alternative from the EE/CA, a remedial design will be produced. We have recorded a liability of $34.0 million for the sediment clean-up, which reflects the low end of the EE/CA range. We have recorded an additional liability of $11.4 million for the additional studies and design work needed before the clean-up can occur, and for regulatory oversight throughout the clean-up. At this time, we believe the sediments at this site represent the largest portion of our liability related to the Portland Harbor site, discussed above. We accrued at the low end because no amount within the range is considered to be more likely than another.

Portland Harbor RI/FS and natural resource damage claims. NW Natural incurs costs related to its membership in the Lower Willamette Group which is performing the RI/FS for EPA. NW Natural also incurs costs related to natural resource damages. In 2008, the Portland Harbor Natural Resource Trustee Council advised a number of potentially responsible parties that it intended to pursue natural resource damage claims at the Portland Harbor Superfund site. The Company and other parties have signed a cooperative agreement with the Natural Resource Trustees to participate in a phased natural resource damage assessment to estimate liabilities to support an early restoration-based settlement of natural resource damage claims. As of June 30, 2012, we have an accrued liability of $4.7 million for these claims, 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 at this time. This liability is not included in the range of costs provided in the draft FS for the Portland Harbor.

Gasco upland 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 upland site is adjacent to the Portland Harbor site described above and has been under investigation by us for environmental contamination under the ODEQ Voluntary Clean-Up Program. It is not included in the range of remedial costs for the Portland Harbor site. In June 2003, we filed a Feasibility Scoping Plan which outlined a range of remedial alternatives for the most contaminated portion of the Gasco upland site. In December 2004, we submitted an Ecological and Human Health Risk Assessment to ODEQ, and in May 2007 we completed a revised Remedial Investigation Report and submitted it to ODEQ for review. The liability accrued at June 30, 2012 for the Gasco upland site is $8.6 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.

Table of Contents

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

In 2007, we also submitted a Focused Feasibility Study (FFS) for the groundwater source control portion of the Gasco site, which ODEQ conditionally approved in March 2008, subject to the submission of additional information. We provided that information to ODEQ and are now working with the agency on the final design for the source control system. Based on the information currently available for groundwater source control at the Gasco site and our current assumptions regarding remediation, we have estimated a range of liability between $14 million and $30 million, for which we have recorded an accrued liability of $14.8 million at June 30, 2012. The estimated range of liability will be reassessed when ODEQ makes a final source control design decision.

Siltronic upland site. We previously owned property adjacent to the Gasco site that now is the location of a manufacturing plant owned by Siltronic Corporation (the Siltronic upland site). The Siltronic upland site is also adjacent to the Portland Harbor site, but not included in the range of remedial costs for the Portland Harbor site. We are currently conducting an investigation of manufactured gas plant wastes on the uplands at this site for the ODEQ. The liability accrued at June 30, 2012 for the Siltronic site is $1.1 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.

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 in which releases of hazardous substances have been confirmed. ODEQ has also added this site to its list of sites where cleanup is necessary. We are currently performing an environmental investigation of the property under the ODEQ’s Independent Cleanup Pathway. As of June 30, 2012, we have a liability accrued of $0.5 million for investigation at this site. The estimate is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.

Front Street site. The Front Street site was the former location of a gas manufacturing plant we operated. It is near but outside the geographic scope of the current Portland Harbor site sediment studies. The EPA directed the Lower Willamette Group to collect a series of surface and subsurface sediment samples off the river bank adjacent to where that facility was located. Based on the results of that sampling, the EPA notified the Lower Willamette Group that additional sampling would be required. As the Front Street site is upstream from the Portland Harbor site, the EPA agreed that it could be managed separately from the Portland Harbor site under ODEQ authority. Work plans for source control investigation and a historical report were submitted to ODEQ and initial studies were completed. In 2010, ODEQ required additional studies which were completed in 2012. The results of those studies have been presented to ODEQ and a final sampling plan required by ODEQ is currently being developed. As of June 30, 2012, we have an estimated liability accrued of $1.5 million for the study of the sediments and riverbank groundwater and soils at the site. The estimate is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.

Oregon Steel Mills site. See “Legal Proceedings,” below.

Accrued Liabilities Relating to Environmental Sites. The following table summarizes the accrued liabilities relating to environmental sites at June 30, 2012 and 2011 and December 31 2011, which are recorded in other current liabilities and other noncurrent liabilities on the balance sheet:

	Current Liabilities						Non-Current Liabilities
	June 30,		June 30,		Dec. 31,		June 30,		June 30,		Dec. 31,
Thousands	2012		2011		2011		2012		2011		2011
Portland Harbor site:
Gasco/Siltronic Sediments	$	2,340	$	995	$	1,614	$	43,066	$	29,866	$	35,797
Other Portland Harbor		1,286		2,619		1,893		3,409		5,426		7,066
Gasco site		12,606		9,140		14,092		10,769		9,099		8,900
Siltronic upland site		467		836		887		620		71		128
Central Service Center site		100		5		-		436		543		495
Front Street site		866		-		1,697		646		823		-
Other sites		-		-		-		117		132		120
Total	$	17,665	$	13,595	$	20,183	$	59,063	$	45,960	$	52,506

Regulatory and Insurance Recovery for Environmental Costs. In May 2003, the OPUC approved our request to defer unreimbursed environmental costs associated with certain named sites, including those described above. Beginning in 2006, the OPUC granted us additional authorization to accrue interest on deferred environmental cost balances, subject to an annual demonstration that we have maximized our insurance recovery or made substantial progress in securing insurance recovery for unrecovered environmental expenses. Through a series of extensions, the authorized cost deferral and interest accrual has been extended through January 2013. In addition, beginning in 2011, the Washington Utilities and Transportation Commission (WUTC) authorized the deferral of certain environmental costs associated with services provided to Washington customers. Environmental costs related to Washington are being deferred as of January 26, 2011 with cost recovery and a carrying charge to be determined in a future proceeding.

On a cumulative basis, we have recognized a total of $133.4 million for environmental costs, including legal, investigation, monitoring and remediation costs, and $4.9 million paid and expensed prior to regulatory deferral order approval. At June 30, 2012, we had a regulatory asset of $117.9 million.

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 in the 2011 Form 10-K). 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 and Gas Insurance Services Limited and dismissed its claims against that insurer in the litigation.

Our regulatory recovery of environmental cost deferrals may be initiated when rates go into effect for the Oregon general rate case; however, because the rate case proceeding is ongoing, and because the ultimate amounts collected will depend upon future insurance recoveries and future expenditures, we are not currently able to estimate the amount of recovery expected through the implementation of new rates.

Legal Proceedings

We are subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings cannot be predicted with certainty, including the matter described below, we do not expect that the ultimate disposition of any of these matters will have a material effect on our financial condition, results of operations or cash flows as we would expect to receive insurance recovery or rate recovery. See also Part II, Item 1., “Legal Proceedings.”

Oregon Steel Mills site. In 2004, NW Natural was served with a third-party complaint by the Port of Portland (the Port) in a Multnomah County Circuit Court case, Oregon Steel Mills, Inc. v. The Port of Portland. The Port alleges that in the 1940s and 1950s petroleum wastes generated by our predecessor, Portland Gas & Coke Company, and 10 other third-party defendants were disposed of in a waste oil disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by Oregon Steel Mills. The complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future remedial action costs. No date has been set for trial. Although the final outcome of this proceeding cannot be predicted with certainty, we do not expect that the ultimate disposition of this matter will have a material effect on our financial condition, results of operations or cash flows.

14. Subsequent Event

On July 12, 2012, NW Natural entered into a bond purchase agreement under which a group of investors agreed to purchase $50 million of our first mortgage bonds with a coupon rate of 4.00 percent and a 30 year maturity. The bond issuance is subject to customary closing conditions and is expected to close on or before October 31, 2012. The proceeds of the issuance are to be used to reduce short-term debt and for other general corporate purposes.

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is management’s assessment of Northwest Natural Gas Company’s (NW Natural, the Company or we) financial condition, including the principal factors that affect results of operations. The disclosures contained in this report refer to our consolidated activities for the three and six months ended June 30, 2012 and 2011. Unless otherwise indicated, references below to “Notes” are to the Notes to Consolidated Financial Statements in this report. A significant portion of our business results are seasonal in nature, and as such the results of operations for these three and six month periods are not necessarily indicative of expected fiscal year results. Therefore, this discussion should be read in conjunction with our 2011 Annual Report on Form 10-K (2011 Form 10-K).

The consolidated financial statements include the accounts of NW Natural and its direct and indirect wholly-owned subsidiaries which include: NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), Gill Ranch Storage, LLC (Gill Ranch) and NNG Financial Corporation (NNG Financial). These statements also include accounts related to our equity investment in Palomar Gas Holdings, LLC (PGH), which is pursuing the development of a proposed natural gas pipeline through its wholly-owned subsidiary Palomar Gas Transmission LLC (Palomar). These accounts make up our regulated local gas distribution business, our regulated gas storage businesses, and other regulated and non-regulated investments primarily engaged in energy-related businesses. In this report, the term “utility” is used to describe our regulated gas distribution business (local distribution company), and the term “non-utility” is used to describe our regulated gas storage businesses (gas storage) and the term “other” is used to describe our other regulated and non-regulated investments and business activities (other). For further information on our business segments, see Note 4.

In addition to presenting results of operations and earnings amounts in total, certain financial measures are expressed in cents per share. These amounts reflect factors that directly impact earnings. We believe this per share information is useful because it enables readers to better understand the impact of these factors on consolidated earnings. All references in this section to earnings per share are on the basis of diluted shares (see Part II, Item 8., Note 3, “Earnings Per Share,” in our 2011 Form 10-K). We use such non-GAAP measures (i.e. measures not based on generally accepted accounting principles) in analyzing our financial performance and believe that they provide useful information to our investors and creditors in evaluating our financial condition and results of operations.

Executive Summary

Highlights of consolidated results for the second quarter of 2012 as compared to the same period in 2011 include:

·	Consolidated earnings of $1.4 million or 5 cents per share in 2012, compared to $2.2 million or 8 cents per share in 2011;

·	Net income from utility operations decreased $0.8 million, from $1.1 million in 2011 to $0.3 million in 2012;

·	Net income from gas storage operations decreased $0.2 million, from $1.3 million in 2011 to $1.1 million in 2012;

·	Net operating revenues (margins) increased $2.2 million or 3 percent over 2011, with utility margins up $1.4 million and gas storage margins up $0.8 million;

·	Operating expenses increased $3.0 million or 6 percent over 2011;

·	Cash flow from operating activities was $175.4 million for the six months ended June 30, 2012, an increase of $6.6 million or 4 percent over 2011;

·	Customer refunds totaling $39 million related to lower wholesale natural gas costs were credited to customer bills beginning in June 2012; and

·	Utility customer count increased by approximately 5,900 over the last 12 months, for an annual growth rate of 0.9 percent compared to 0.8 percent a year ago.

Table of Contents

Issues, Challenges and Performance Measures

Economic environment. Weakness in the local, national and global economies continued to impact utility customer growth, business demand for natural gas and market prices for gas storage. Our utility’s annual customer growth rate was 0.9 percent at June 30, 2012, as compared to 0.8 percent at both March 31, 2012 and June 30, 2011. The local economy is beginning to show signs of a slow recovery, with unemployment rates in Oregon and southwest Washington declining from 2011 to 2012. We believe our utility business is well positioned to continue adding customers and to serve increasing industrial demand as the economy recovers because of low, stable natural gas prices, our relatively low market penetration, our focus on converting homes and businesses to natural gas, and the potential for environmental initiatives favoring natural gas use in our region.

Managing gas prices and supplies. Our gas acquisition and management strategy is to secure sufficient supplies of natural gas to meet the needs of our utility customers and to hedge gas prices so we can effectively manage costs, reduce price volatility for customers and maintain a competitive advantage. With recent developments in drilling technologies and substantial access to gas supplies from shale formations around the U.S. and in Canada, the current outlook for North American natural gas supply is strong and is projected to remain this way well into the future. The abundance of gas suggests continued lower and relatively more stable gas prices, subject to a regulatory environment that continues to support hydraulic fracturing and other drilling technologies.

Our utility’s annual Purchased Gas Adjustment (PGA) mechanisms in Oregon and Washington, along with our own gas price hedging strategies, which include gas reserves and gas storage inventories, 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.

To manage gas prices we typically hedge approximately 75 percent of our utility’s annual sales requirement, based on normal weather, including both physical and financial hedges. For the current gas contract year (November 1, 2011 – October 31, 2012), we were roughly 51 percent hedged with financial swap and option contracts and 24 percent hedged with physical gas supplies. The physical supplies consisted of a combination of gas inventories in storage, gas production from the Mist area which we buy at pre-determined prices, and gas production from an investment we made in gas reserves with Encana Oil & Gas (USA) Inc. (Encana). The gas reserves with Encana relate to a new investment we made beginning in 2011, whereby we own working interests in certain leases in Encana’s Jonah gas field located in Rock Springs, Wyoming. For a further discussion of gas reserves, see “Investments in Gas Reserves” under “Strategic Opportunities” below and “Gas Reserves” under “Rate Mechanisms” below.

Besides the amount hedged for the current gas contract year, we are also hedged at approximately 59 percent for the 2012-13 gas year as of June 30, 2012. We have also entered into gas reserve purchases and financial hedge transactions that hedge gas prices beyond this upcoming gas contract year. Our hedge levels are subject to change based on actual load volumes, which depend to a certain extent on weather and economic conditions. In addition, our storage inventory levels may increase or decrease based on storage expansion or storage recall by the utility. The utility added 1 Bcf to its off-system storage capacity in October 2011 by entering into a three-year contract with a third-party for natural gas storage located in Canada, for which injections began in April 2012. We expect recovery of our off-system storage costs, including demand charges and other operating costs, through our normal PGA mechanism. As for gas reserve purchases and Mist area gas production, we include estimates in our hedge levels, which are subject to change based on possible unforeseen events including the impact from the pace of drilling activity and the volume of production from each well.

Although less expensive and more stable gas prices provide opportunities to manage costs for our utility customers, they also present challenges for our gas storage businesses by lowering the price of, and reducing the demand for, storage services. Consequently, our ability to sign longer-term storage contracts with customers at favorable prices affects our ability to improve financial results, but we remain committed to find opportunities for increasing revenues, lowering costs and developing enhanced services for storage customers.

Environmental clean-up costs. We continue to accrue all material loss contingencies related to environmental sites for which we are responsible. Due to numerous uncertainties surrounding the nature of environmental investigations and the development of or remediation solutions approved by regulatory agencies, actual costs could vary significantly from our loss estimates. As a regulated utility, we have been allowed to defer certain costs pursuant to regulatory decisions. We currently have regulatory authority to defer certain environmental costs and to seek recovery of those costs in future customer rates. However, we are expected to pursue recovery from insurance policies first and to seek recovery from customers only for amounts not recovered from insurance. Any amounts collected from insurance are expected to offset amounts that may otherwise be collected from customers. Ultimate recovery of environmental costs, either from regulated utility rates or from insurance, will depend on our ability to effectively manage these costs and demonstrate 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 Results of Operations—Regulatory Matters—Rate Mechanisms—Regulatory Recovery for Environmental Costs below, Note 13 in this report and Note 15 in our 2011 Form 10-K.

Performance measures. In order to deal with the issues and challenges affecting our businesses, we annually review and update our strategic plan to map a course over the next several years. Our plan includes: further improving our utility gas distribution system; enhancing utility and gas storage services and operations; optimizing and growing our utility and 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 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 (EBITDA).

Table of Contents

Strategic Opportunities

Increased investment in safety and service. To best respond to new federal pipeline safety legislation and system integrity management regulatory requirements, as well as increasing customer expectations for service responsiveness, the Company has increased staffing levels in the areas of pipeline safety, emergency response, regulatory compliance, field training, and customer service. We also continue to improve upon the quality and integrity of our pipeline infrastructure, and have initiated several facility upgrades to enhance business continuity, employee training and safety, productivity and energy efficiency. We remain committed to finding new ways to improve operational effectiveness and capitalize on our competitive position and service quality.

Gas storage developments. We currently own and operate two underground gas storage facilities—the Mist facility in Oregon and the Gill Ranch facility in Fresno, California. Our Mist facility currently consists of 16 Bcf of available storage capacity, with 10 Bcf allocated to the utility business and 6 Bcf allocated to the gas storage business. Our wholly-owned subsidiary, Gill Ranch holds a 75 percent undivided ownership interest in the Gill Ranch facility; Pacific Gas and Electric Company (PG&E) owns the other 25 percent interest. Our Gill Ranch facility currently consists of 15 Bcf of available storage capacity. Future expansion is possible at both the Mist and Gill Ranch storage facilities to serve increasing demand should the market for gas storage improve. For more information, see Note 4 in this report and Part II, Item 7., “2012 Outlook—Strategic Opportunities,” in our 2011 Form 10-K.

Due to an abundant supply of natural gas and lower, more stable prices in North America, storage values are expected to remain relatively low in the near term, which will likely affect the prices at which Gill Ranch is able to contract. Gas prices hit a 10-year low in early 2012, 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 national demand for natural gas as the lower pricing provides a competitive advantage over alternative energy sources including the potential for switching coal plants over to natural gas and increasing demand for exporting natural gas. Combined, these demand forces, and reduced drilling activity, may ultimately result in upward pressure on gas prices and return some price volatility to natural gas markets.

Our storage facilities position us well to capitalize on rising demand for natural gas, higher gas prices or increased market volatility because storage operations benefit from seasonal swings in commodity prices and market volatility. Additionally, if market demand increases and we are able to obtain regulatory permits and project financing, we have the ability to expand the Mist and Gill Ranch facilities beyond their current capacities. Gill Ranch for instance, can develop increased storage capacity without further expansion of our gas transmission pipeline. We estimate that the current Gill Ranch storage facility could support an additional 20 Bcf of storage capacity, bringing total capacity up to 40 Bcf with certain infrastructure modifications, of which we would have the rights to 50 percent of the total.

The Pacific Northwest storage markets are also 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. During the second quarter of 2012, a request for proposals (RFP) to provide additional energy generation was sent out by Portland General Electric (PGE). As part of the RFP process, PGE has submitted its own “benchmark” bids that other third party bids must compete with. The Company has an agreement to provide storage services to PGE should their bid be selected. Other third party bidders are free to make their own gas supply arrangements in support of their bids.

We are continuing to evaluate future expansion at Mist; however, we do not currently have a set timeline for development. 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 scope of the next expansion, which will likely include the development of storage wells, a second compression station and additional pipeline gathering facilities.

Pipeline diversification. Currently, our utility operations and gas storage operations at Mist depend on a single bi-directional interstate transmission pipeline to ship customer supplies. Palomar, a wholly-owned subsidiary of PGH, is pursuing the development of a new gas transmission pipeline that would provide an interconnection with our utility distribution system. PGH is owned 50 percent by NWN Energy and 50 percent by TransCanada American Investments Ltd., an indirect wholly-owned subsidiary of TransCanada Corporation. The Palomar pipeline was originally proposed with an east and a west segment, but currently Palomar’s plan is 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.

Palomar has negotiated a non-binding memorandum of understanding (joint agreement) 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 is the owner and operator of the single bi-directional interstate transmission pipeline that connects with NW Natural’s utility distribution system.

The proposed Palomar pipeline would be regulated by Federal Energy Regulatory Commission (FERC). In March 2011, Palomar withdrew its original application with FERC, but at the same time informed FERC that it intended to file a new application with a modified scope that excluded the western segment, after it has conducted a new open season to obtain commercial support for the eastern segment. The timing for construction of the Palomar pipeline depends on regulatory permits and commercial support from shippers.

In July of 2012, various federal agencies including the Bureau of Land Management, the U.S. Forest Service and the U.S. Department of Energy entered into a Settlement Agreement resolving litigation filed in 2009 by a number of environmental groups. The Agreement requires the agencies to periodically review the energy corridors on a regional basis to assess the need for potential revisions. We do not anticipate any material changes in our plans for Palomar due to this settlement.

Gas reserves. In addition to hedging gas prices with financial swap and option contracts, we signed an agreement with Encana in 2011 to acquire physical gas supplies to meet a portion of our utility customers’ requirements over 30 years. During the first 10 years, we forecast the volumes of gas received under the Encana agreements to provide approximately 8 to 10 percent of the average annual requirements of our utility customers. Under the agreement, we expect to invest approximately $45 million to $55 million per year for five years, subject to certain NW Natural rights to terminate the agreement, with our total investment expected to be about $250 million. We pay a fixed portion of drilling costs per well, and 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 interest entitles us to receive a portion of the gas produced in the assigned sections. Operation of the wells is governed by a joint operating agreement under which Encana is the operator, and we pay our proportionate share of the operating costs. We receive federal tax deductions associated with drilling costs. The timing of when the Company realizes federal tax benefits from these drilling costs may be affected by net operating losses for tax purposes, which will be carried forward to reduce our current tax liability in future years. See Note 10 and Results of Operations—Regulatory Matters—Rate Mechanisms—Gas Reserves below and Part II, Item 7., “2012 Outlook—Strategic Opportunities,” in our 2011 Form 10-K.

Table of Contents

Consolidated Earnings and Dividends

Three months ended June 30, 2012 compared to June 30, 2011:

For the three months ended June 30, 2012, we had net income of $1.4 million, or 5 cents per share, compared to net income of $2.2 million, or 8 cents per share, for the same period last year.

The primary factors contributing to decreased second quarter consolidated net income were:

·	a $1.8 million increase in operations and maintenance expense primarily due to increases in utility payroll and employee benefit costs;

·	a $0.8 million increase in general taxes primarily due to an increase in gas storage property taxes for Gill Ranch’s completed, in-service property assessed values; and

·	a $0.6 million increase in depreciation and amortization expenses primarily due to a higher level of investment in property, plant and equipment at the utility and gas storage operations.

Partially offsetting the above factors was:

a $1.4 million increase in utility net operating revenues (margins) primarily due to a one-time, pre-tax charge of $7.4 million recorded in the second quarter of 2011 related to Senate Bill 408, partially offset by a decrease in utility margin from the effects of warmer weather in the second quarter of 2012 compared to 2011.

Six months ended June 30, 2012 compared to June 30, 2011:

Net income was $42.0 million, or $1.56 per share, for the six months ended June 30, 2012, compared to $43.0 million, or $1.61 per share, for the same period last year.

The primary factors contributing to the $1.0 million decrease in net income were:

·	a $5.0 million increase in operations and maintenance expense due to increases in utility payroll and employee benefit costs, utility training costs, and expenses related to our Oregon general rate case;

·	a $1.4 million increase in general taxes primarily due to increased property taxes at Gill Ranch;

·	a $1.2 million increase in depreciation and amortization expenses primarily due to higher levels of investment in property, plant and equipment at the utility and gas storage operations; and

·	a $0.9 million increase in interest expense primarily due to the new debt issuance at Gill Ranch late in 2011.

Partially offsetting the above factors were:

a $5.4 million net increase in utility margin primarily due to a one-time, pre-tax charge of $7.4 million in 2011 related to Senate Bill 408, and an increase of $2.0 million for gains related to gas cost savings, partially offset by a decrease in utility margin from the effects of warmer weather in 2012 compared to 2011; and

·	a $2.2 million net increase in gas storage margin primarily attributable to revenue increases from Gill Ranch from additional contracted storage capacity, partially offset by margin decreases from Mist operations due to lower storage prices and lower optimization revenues.

Dividends paid on our common stock were 44.5 cents per share in the second quarter of 2012, compared to 43.5 cents per share in the second quarter of 2011. The Board of Directors declared a quarterly dividend on our common stock of 44.5 cents per share, payable on August 15, 2012, to shareholders of record on July 31, 2012. The current indicated annual dividend rate is $1.78 per share.

Table of Contents

Application of Critical Accounting Policies and Estimates

In preparing our financial statements using generally accepted accounting principles in the United States of America (GAAP), management exercises judgment in the selection and application of accounting principles, including making estimates and assumptions that affect reported amounts of assets, liabilities, revenues, expenses and related disclosures in the financial statements. Management considers our critical accounting policies to be those which are most important to the representation of our financial condition and results of operations and which require management’s most difficult and subjective or complex judgments, including accounting estimates that could result in materially different amounts if we reported under different conditions or used different assumptions. Our most critical estimates and judgments include accounting for:

·	regulatory cost recovery and amortizations;

·	revenue recognition;

·	derivative instruments and hedging activities;

·	pensions and postretirement benefits;

·	income taxes; and

·	environmental contingencies.

There have been no material changes to the information provided in the 2011 Form 10-K with respect to the application of critical accounting policies and estimates (see Part II, Item 7., “Application of Critical Accounting Policies and Estimates,” in the 2011 Form 10-K).

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.

Results of Operations

Regulatory Matters

Regulation and Rates

Utility. Our utility business is subject to regulation with respect to, among other matters, rates and systems of accounts set by the Oregon Public Utility Commission (OPUC), Washington Utilities and Transportation Commission (WUTC), and FERC. The OPUC and WUTC also regulate the issuance of securities by our utility. In 2011, approximately 90 percent of our utility gas volumes and revenues were derived from Oregon customers, with the remaining 10 percent from Washington customers. Future earnings and cash flows from utility operations will largely be determined by rate cases in Oregon and Washington, but will also be affected by the economies in Oregon and Washington, by the pace of customer growth in the residential and commercial markets, and by our ability to remain price competitive, control expenses, and obtain reasonable and timely regulatory recovery of our utility-related costs, including operating expenses and investment costs 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, California Public Utilities Commission (CPUC), and FERC. The OPUC and FERC regulate our Mist gas storage business under a maximum cost-based rate model, whereas the CPUC regulates Gill Ranch under a market-based rate model which allows for the price of storage services to be set by the marketplace. In 2011, approximately 65 percent of our storage revenues were derived from OPUC and FERC approved cost-based rates, and approximately 35 percent were from CPUC approved market-based rates.

See Part II, Item 7., “Results of Operations—Regulatory Matters,” in the 2011 Form 10-K.

Oregon General Rate Case

On December 30, 2011, we filed an application for a general rate increase with the OPUC. In the filing, we 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 the requested rate increase includes an estimated $15.1 million that represents the cumulative effect of declining use per customer. This amount is currently recovered in customers’ rates through the Company’s conservation tariff mechanism, which has been in place since 2003. Our requested 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 original filing also requested 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.

On May 3, 2012, the parties involved in NW Natural’s general rate case filed their testimony, which represents their first filing in the formal administrative proceeding through which the OPUC determines rate cases. These included the Staff of the OPUC, the Citizen’s Utility Board (CUB), and the Northwest Industrial Gas Users (NWIGU). In its testimony, the OPUC Staff recommended a revenue requirement reduction of $10.7 million, or a 1.5 percent decrease, compared to our requested $43.7 million or 6.2 percent increase. Staff’s testimony is based on a 7.56 percent overall cost of capital including a 9.2 percent return on common equity, and reductions to various operation and maintenance (O&M) expenses and capital additions requested. These parties also recommended certain modifications to our proposed environmental cost recovery mechanism, modifications to an existing allocation of revenues to customers from our interstate gas storage operations and denial of our request for recovery of certain costs related to our contributions covering employee pension benefits. The filings made by CUB and NWIGU overlap with Staff’s proposals in several areas while also recommending additional reductions to O&M and capital additions.

On June 15, 2012, we filed our rebuttal testimony reflecting the effects of a partial stipulation agreement and other revisions to our original filed case. Our revised case now requests a $35.9 million increase (5.1 percent) reflecting an overall rate of return of 8.14 percent based upon an ROE of 10.2 percent and a capital structure of 50 percent common equity.

On July 9, 2012, we filed along with several parties to the case, including Staff, CUB, and NWIGU, a partial stipulation resolving several issues in the case. The partial stipulation was the result of settlement conferences held May 22 and 23, 2012. While we were able to reach agreement on several issues, we were unable to resolve terms on capital structure, rate of return and other issues.

On July 20, 2012, the parties involved in the case filed their rebuttal testimony, responding to our June 15th testimony. In the filings, they made modifications to certain of the recommendations made in their May 3rd filing. These changes include a modification of OPUC Staff’s recommendation on NW Natural’s revenue requirement, which now proposes an increase to NW Natural’s revenue requirement of $8.4 million, compared to our revised request of a $35.9 million increase.

Throughout the formal administrative proceeding, NW Natural and the parties have the opportunity to engage in settlement discussions regarding any or all of the issues involved in the proceeding. We have engaged in such discussions during scheduled settlement conferences. We are unable at this time to predict the outcome of this rate proceeding, or to predict which, if any, issues will be presented to the OPUC as part of a contested proceeding or as part of a settlement proposal. The remaining schedule includes two days of hearings beginning on August 23, 2012 after which the final order is due on October 22, 2012. The effective date of the new rates will be November 1, 2012.

Table of Contents

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 gas prices under spot purchases as well as contract supplies, gas prices hedged with financial derivatives, gas prices from the withdrawal of storage inventories and gas reserves, interstate pipeline demand costs, the application of temporary rate adjustments, which amortize balances of deferred regulatory accounts, and the removal of temporary rate adjustments effective for the previous year.

Effective November 1, 2011, the OPUC and WUTC approved PGA rate changes to decrease the average monthly bills of Oregon and Washington residential customers by 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.

Under the current PGA mechanism in Oregon, there is an incentive sharing provision whereby we are required to select each year either an 80 percent deferral or a 90 percent deferral of higher or lower actual gas costs compared to estimated PGA prices, such that the impact on current earnings from the incentive sharing is either 20 percent or 10 percent of the difference between actual and estimated gas costs, respectively. Under the Washington PGA mechanism, we defer 100 percent of the higher or lower actual gas costs, and those gas cost differences are normally passed on to customers through the annual PGA rate adjustment. See “Customer Credits for Gas Cost Incentive Sharing” below for a discussion of our utility’s early refund to customers of deferred gas cost savings from November 1, 2011 through March 31, 2012.

In addition to the gas cost incentive sharing mechanism, we are subject to an annual earnings review to determine if the utility is earning above its authorized return on equity (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 both 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 2010 and 2011, the ROE threshold after adjustment for long-term interest rates was 11.02 percent and 10.92 percent, respectively. We refunded $0.2 million to customers based on the 2010 utility earnings test, and we expect to refund $0.7 million to customers in the upcoming PGA year based upon the 2011 utility earnings test. We do not expect to be subject to a refund for the 2012 earnings test year.

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 2013.

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. See Note 13 for further discussion of our regulatory and insurance recovery of environmental costs.

Pension Deferral. Effective January 1, 2011, the OPUC approved our request to defer annual pension expense above the amount set in rates in our last general rate case. The recovery of these deferred pension costs will be through the implementation of a balancing account, which includes the expectation of higher and lower pension expenses in future years. Our recovery of deferred balances includes accrued interest on the account balance at the utility’s authorized rate of return, which is currently 8.62 percent. The reduction to operations and maintenance expense in 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 being affected by pension contributions by the Company. We estimate pension expense deferrals totaling $8 million to $9 million in 2012, with $2.1 million and $4.2 million being deferred for the three and six months ended June 30, 2012, respectively.

Customer Credits for Gas Cost Incentive Sharing. For the period between November 1, 2011 and March 31, 2012, our actual gas costs were significantly lower than the gas costs currently embedded in customer rates. As a result, our PGA incentive sharing mechanism recorded 90 percent of gas cost savings during this period, attributed to Oregon customers, and 100 percent of the savings attributed to Washington customers, to a regulatory account for credit to customers (see “Purchased Gas Adjustment,” above). Ordinarily, these credits would be refunded in customer rates starting in November under the next year’s PGA filing, but in April 2012 the company requested regulatory approval to immediately refund $35.1 million and $4.2 million to our Oregon and Washington customers, respectively, through billing credits. These credits were approved, and we began crediting these amounts to customer bills in June of 2012.

Customer Credits for Gas Storage Sharing. In April 2012, the company requested regulatory approval to provide its Oregon utility customers with a $9.2 million interstate storage credit from our regulatory incentive sharing mechanism related to interstate gas storage and asset management services. The OPUC approved this credit and we began crediting this amount to customer bills in Oregon in June of 2012.

For a discussion of other rate mechanisms, see Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms” in our 2011 Form 10-K.

Table of Contents

Business Segments - Utility Operations

Our utility margin results are largely affected by customer growth and, to a certain extent, by changes in volume due to weather and customers’ gas usage patterns because a significant portion of our margin revenues are derived from natural gas sales to residential and commercial customers. In Oregon, we have a conservation tariff, which adjusts margin revenues up or down to offset changes resulting from increases or decreases in average use by residential and commercial customers. We also have a weather normalization tariff in Oregon, which adjusts customer bills up or down to offset changes in margin resulting from above- or below-average temperatures during the winter heating season. Both mechanisms are designed to reduce the volatility of our utility’s earnings and customer charges. For more information on our conservation and weather normalization tariffs, see discussion under “Results of Operations—Regulatory Matters—Rate Mechanisms” in our 2011 Form 10-K.

Three months ended June 30, 2012 compared to June 30, 2011:

Utility operations resulted in net income of $0.3 million, or 1 cent per share, in the second quarter of 2012 compared to net income of $1.1 million, or 4 cents per share, in the second quarter of 2011. The decrease in net income was primarily due to higher operating expenses and the effects of warmer weather on margin revenues. These decreases were partially offset by increases in margin revenues due to a non-recurring charge related to the repeal of Senate Bill 408 (SB 408) in 2011 and gains from gas cost savings and customer growth in 2012 compared to the same period in 2011.

Gas Utility Volumes, Revenues and Margin

Total utility volumes sold and delivered in the second quarter of this year decreased by 10 percent over last year primarily due to 25 percent warmer weather compared to the prior year, while total utility margin increased by $1.4 million, or 2 percent. The increase in margin was primarily due to a one-time, pre-tax charge in the second quarter of 2011 for $7.4 million related to the repeal of Senate Bill (SB) 408, which did not reoccur in 2012. Excluding the SB 408 charge, margin for the second quarter of 2012 decreased by $6.1 million primarily due to the earnings impact of colder weather in the second quarter of 2011.

Our weather normalization mechanism adjusted residential and commercial margins down by $19 thousand for the second quarter of 2012 based on temperatures that were 3 percent colder than average, compared to a margin decrease of $4.8 million for the second quarter of 2011 when temperatures were 38 percent colder than average. Our decoupling mechanism adjusted residential and commercial margins down by $214 thousand in the second quarter of 2012, compared to a margin increase of $2.2 million in 2011. The positive impact of colder weather in the second quarter of 2011 was disproportionately greater than the impact in the same period of 2012 because the colder weather in 2011 occurred mostly in the month of May when the weather normalization mechanism for customer usage ends on May 15th while the decoupling mechanism assumes weather adjusted volumes for the entire month.

Six months ended June 30, 2012 compared to June 30, 2011:

In the six months ended June 30, 2012, utility operations contributed net income of $40.1 million or $1.49 per share, compared to $41.2 million or $1.54 per share in 2011. The decrease in net income was primarily due to higher operating expenses and the effects of warmer weather on margin revenues, partially offset by increases in margin revenues due to a non-recurring charge related to the repeal of SB 408 in 2011 plus gains from gas cost savings and customer growth in the 2012 period compared to 2011.

Gas Utility Volumes, Revenues and Margin

Total utility volumes sold and delivered in the six months ended June 30, 2012 decreased by 3 percent over last year primarily due to 9 percent warmer weather, while total utility margin increased by $5.4 million, or 3 percent. The increase in margin was primarily due to a one-time, pre-tax charge of $7.4 million in the first six months of 2011 related to the repeal of Senate Bill 408, which did not reoccur in 2012, and a $3.1 million gain, up from $1.1 million last year, from gas cost savings due to lower prices, and a 0.9 percent increase in customer growth, which offset the decline in customer volumes and margins resulting from warmer weather. Excluding the SB 408 charge, margin decreased by $1.8 million primarily due to positive earnings impact of colder weather from the first six months of 2011 as discussed above.

During the six months ended June 30, 2012, our weather normalization mechanism adjusted residential and commercial margins down by $3.8 million based on temperatures that were 4 percent colder than average, compared to a margin decrease of $10.6 million last year when temperatures were 14 percent colder than average. Our decoupling mechanism adjusted residential and commercial margins up by $6.4 million for the six months ended June 30, 2012 and $10.9 million for the six months ended June 30, 2011, to largely offset the impact of lower average use per customer on a weather normalized basis.

Table of Contents

The following table summarizes the composition of gas utility volumes, revenues and margin. Certain amounts in prior year balances under the utility margin section of the table have been reclassified to conform with the current year’s presentation. These reclassifications reflect amounts moved from other margin adjustments into residential, commercial and industrial categories where amounts were assignable to a specific customer category. Utility margin in total was not affected by the reclassifications.

	Three Months Ended						Favorable/
	June 30,						(Unfavorable)
Thousands, except degree day and customer data	2012			2011			2012 vs. 2011
Utility volumes - therms:
Residential sales		64,097			78,349			(14,252	)
Commercial sales		43,674			51,232			(7,558	)
Industrial - firm sales		7,593			8,476			(883	)
Industrial - firm transportation		29,736			32,533			(2,797	)
Industrial - interruptible sales		14,190			14,295			(105	)
Industrial - interruptible transportation		59,727			57,867			1,860
Total utility volumes sold and delivered		219,017			242,752			(23,735	)
Utility operating revenues - dollars:
Residential sales	$	54,938		$	91,765		$	(36,827	)
Commercial sales		28,768			48,344			(19,576	)
Industrial - firm sales		4,477			6,880			(2,403	)
Industrial - firm transportation		1,779			1,628			151
Industrial - interruptible sales		4,955			8,407			(3,452	)
Industrial - interruptible transportation		2,021			2,284			(263	)
Regulatory adjustment for income taxes paid(1)		-			(7,451	)		7,451
Other revenues		1,578			2,088			(510	)
Total utility operating revenues		98,516			153,945			(55,429	)
Cost of gas sold		34,498			90,054			55,556
Revenue taxes		2,578			3,843			1,265
Utility margin	$	61,440		$	60,048		$	1,392
Utility margin:(2)
Residential sales	$	37,634		$	43,767		$	(6,133	)
Commercial sales		15,314			17,229			(1,915	)
Industrial - sales and transportation		6,751			6,840			(89	)
Miscellaneous revenues		1,371			1,526			(155	)
Gain from gas cost incentive sharing		452			87			365
Other margin adjustments		151			632			(481	)
Margin before regulatory adjustments		61,673			70,081			(8,408	)
Weather normalization adjustment		(19	)		(4,751	)		4,732
Decoupling adjustment		(214	)		2,169			(2,383	)
Regulatory adjustment for income taxes paid(1)		-			(7,451	)		7,451
Utility margin	$	61,440		$	60,048		$	1,392
Customers - end of period:
Residential customers		617,039			611,564			5,475
Commercial customers		62,975			62,532			443
Industrial customers		922			906			16
Total number of customers - end of period		680,936			675,002			5,934
Actual degree days		705			944
Percent colder than average weather(3)		3	%		38	%

Table of Contents

		Six Months Ended						Favorable/
		June 30,						(Unfavorable)
Thousands, except degree day and customer data		2012			2011			2012 vs. 2011
Utility volumes - therms:
Residential sales			240,134			253,053			(12,919	)
Commercial sales			143,796			150,409			(6,613	)
Industrial - firm sales			18,212			19,340			(1,128	)
Industrial - firm transportation			68,587			69,015			(428	)
Industrial - interruptible sales			31,920			31,532			388
Industrial - interruptible transportation			124,527			120,817			3,710
	Total utility volumes sold and delivered		627,176			644,166			(16,990	)
Utility operating revenues - dollars:
Residential sales		$	249,777		$	290,602		$	(40,825	)
Commercial sales			120,943			143,112			(22,169	)
Industrial - firm sales			12,786			15,725			(2,939	)
Industrial - firm transportation			3,687			3,374			313
Industrial - interruptible sales			15,003			18,734			(3,731	)
Industrial - interruptible transportation			4,067			4,600			(533	)
Regulatory adjustment for income taxes paid(1)			-			(7,165	)		7,165
Other revenues			3,013			2,690			323
	Total utility operating revenues		409,276			471,672			(62,396	)
Cost of gas sold			204,253			270,664			66,411
Revenue taxes			10,433			11,798			1,365
	Utility margin	$	194,590		$	189,210		$	5,380
Utility margin:(2)
Residential sales		$	123,242		$	128,019		$	(4,777	)
Commercial sales			48,279			49,787			(1,508	)
Industrial - sales and transportation			14,387			14,450			(63	)
Miscellaneous revenues			2,966			3,110			(144	)
Gain from gas cost incentive sharing			3,089			1,122			1,967
Other margin adjustments			18			(395	)		413
	Margin before regulatory adjustments		191,981			196,093			(4,112	)
Weather normalization adjustment			(3,834	)		(10,612	)		6,778
Decoupling adjustment			6,443			10,894			(4,451	)
Regulatory adjustment for income taxes paid(1)			-			(7,165	)		7,165
	Utility margin	$	194,590		$	189,210		$	5,380
Customers - end of period:
Residential customers			617,039			611,564			5,475
Commercial customers			62,975			62,532			443
Industrial customers			922			906			16
	Total number of customers - end of period		680,936			675,002			5,934
Actual degree days			2,659			2,918
Percent colder than average weather(3)			4	%		14	%

(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.

Table of Contents

Residential and Commercial Sales

Three months ended June 30, 2012 compared to June 30, 2011:

The primary factors contributing to changes in residential and commercial volumes and operating revenues in the second quarter of this year as compared to the same period last year were:

·	sales volumes decreased 17 percent due to weather that was 25 percent warmer than 2011;

·	utility operating revenues decreased $56.4 million or 40 percent, primarily due to $34.3 million of credits to customers’ bills in June related to the refund of gas cost savings, as well as the effects of warmer weather; and

utility margin decreased $5.7 million or 10 percent, including weather normalization, which stabilizes margins when weather is warmer or colder than normal and decoupling, which stabilizes margins when average use per customer increases or decreases. The net decrease in margin reflects last year’s positive margin contributions from colder weather when the full impact of the weather normalization mechanism was not in effect for the month of May.

Six months ended June 30, 2012 compared to June 30, 2011:

The primary changes that impacted margin from residential and commercial sales for the six months ended June 30, 2012 compared to June 30, 2011 were as follows:

·	utility sales volumes were 5 percent lower, primarily reflecting 9 percent warmer weather;

·	utility operating revenues decreased $63.0 million or 15 percent primarily due to $34.3 million of credits to customers’ bills in June related to the refund of gas cost savings, as well as the effects of warmer weather; and

utility margin decreased $4.0 million or 2 percent, including weather normalization, which stabilizes margins when weather is warmer or colder than normal and when average use per customer increases or decreases. The decrease in margin reflects the warmer weather compared to last year’s very cold weather when the full impact of the mechanisms were not in effect in May.

Industrial Sales and Transportation

Three months ended June 30, 2012 compared to June 30, 2011:

The primary factors that impacted second quarter results from industrial sales and transportation markets were as follows:

·	volumes delivered to industrial customers decreased by 1.9 million therms, or less than 2 percent primarily due to one large transportation customer closing their plant during June for maintenance. This closure did not have a significant impact on margin; and

·	margin remained flat with only a slight decrease of $0.1 million, or 1 percent.

Industrial customers also received credits totaling $2.6 million on their June bills related to the refund of gas cost savings.

Six months ended June 30, 2012 compared to June 30, 2011:

The primary factors that impacted year-to-date results from industrial sales and transportation markets were as follows:

volumes delivered to industrial customers increased 2.5 million therms, or 1.1 percent. The volume increase in the period reflects the addition of a few new customers in the forest products segment. In addition, due to the price advantage of natural gas over oil, we are beginning to see asphalt plants converting to natural gas and a trend in other businesses to also convert from legacy oil boilers to natural gas; and

·	margin from industrial customers remained relatively flat with only a slight decrease of $0.1 million.

Regulatory Adjustment for Income Taxes Paid

In prior years, Oregon law required the company to annually review the amount of income taxes collected in rates from utility operations and compare it to the amount of taxes the utility paid. In 2011, this law was repealed. We did not recognize any income or expense related to this regulatory adjustment for the three and six months ended June 30, 2012; however, in the second quarter of 2011, we recorded a one-time, pre-tax charge of $7.4 million, including accrued interest. For more information on regulatory income taxes paid, see Results of Operations – Business Segments – Utility Operations – Regulatory Adjustment for Income Taxes Paid in our 2011 Form 10-K.

Other Revenues

Other revenues include miscellaneous fee income and other regulatory adjustments. Other revenues were $1.6 million in the second quarter of 2012, a decrease of $0.5 million over the second quarter of 2011. Other revenues were $3.0 million in the six months ended June 30, 2012, an increase of $0.3 million over the same period of 2011.

Table of Contents

Cost of Gas Sold

Cost of gas sold as reported by the utility 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 WUTC generally require natural gas commodity costs to be billed to customers at the same cost incurred, or expected to be incurred, by the utility. Customer rates are set each year so that if cost estimates were met we would not earn a profit or incur a loss on gas commodity purchases; however, in Oregon we have an incentive sharing mechanism whereby we either increase or decrease margin results based on a percentage of actual gas costs as compared to embedded gas costs in the PGA. Under this provision, our net income can be affected by differences between actual and expected gas costs, which occur primarily because of market fluctuations and volatility affecting unhedged gas purchases in the PGA (see “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” above). 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., “Regulatory Matters-Rate Mechanisms-Purchased Gas Adjustment and Regulatory Matters-Rate Mechanisms-Gas Reserves in the 2011 Form 10-K).

We use natural gas commodity-based hedge contracts (derivative instruments), primarily fixed-price commodity swaps, consistent with our financial derivatives policies to help manage our exposure to rising gas prices. Gains and losses from these financial hedge contracts are generally included in our PGA prices and normally do not impact net income because the hedged prices are reflected in our annual rate changes, subject to a regulatory prudency review. However, 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 as compared to the corresponding commodity prices built into 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 Part II, Item 7., “Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities,” and “Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” in the 2011 Form 10-K, and Note 12 in this report).

Three months ended June 30, 2012 compared to June 30, 2011:

The following summarizes the major factors that contributed to changes in cost of gas sold for the three months ended June 30, 2012:

total cost of gas sold decreased $55.6 million, or 62 percent, including the $35.8 million of credits applied to customer billings in June 2012. Excluding the customer credits, total cost of gas decreased $19.8 million or 22 percent, primarily reflecting lower usage due to weather that was 25 percent warmer than the last year;

·	average gas cost collected through rates, excluding customer refunds for gas cost savings, decreased 10 percent from 59 cents per therm in 2011 to 53 cents per therm in 2012, primarily reflecting the lower prices that were passed on to customers through the PGA effective November 1, 2011; and

hedge losses totaling $21.3 million were realized and included in cost of gas sold this quarter, compared to $8.7 million of hedge losses in the same period of 2011. Since the underlying hedge prices were included in our PGA billing rates, these losses did not impact the company’s margin or net income.

The effect on operating results from our gas cost incentive sharing mechanism was a margin gain of $0.5 million in the second quarter of 2012, compared to a margin gain of $0.1 million for the second quarter of 2011.

Six months ended June 30, 2012 compared to June 30, 2011:

total cost of gas sold decreased $66.4 million, or 25 percent, including the $35.8 million of credits applied to customer billings in June 2012. Excluding the customer credits, total cost of gas decreased $30.7 million or 11 percent, primarily reflecting lower usage due to weather that was 9 percent warmer than the same period in 2011;

·	average gas cost collected through rates, excluding customer refunds for gas cost savings, decreased from 60 cents per therm in 2011 to 55 cents per therm in 2012, primarily reflecting lower gas prices that were passed on through PGA rate decreases effective November 1, 2011; and

hedge losses totaling $50.7 million were realized and included in cost of gas sold for the six months ended June 30, 2012, compared to $29.6 million of hedge losses in the same period of 2011. Since the underlying hedge prices were included in our PGA billing rates, these losses did not impact margin or net income.

The amount recorded to pre-tax income from the shareholders’ portion of our gas cost incentive sharing mechanism was a margin contribution of $3.1 million in the first half of 2012 compared to $1.1 million in 2011. For a discussion of our gas cost incentive sharing mechanism, see “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” above.

Table of Contents

Business Segments - Gas Storage

Our gas storage segment primarily consists of the non-utility portion of our Mist underground storage facility in Oregon and our 75% ownership interest in the Gill Ranch underground storage facility in California.

Three months ended June 30, 2012 compared to June 30, 2011:

For the three months ended June 30, 2012, we earned $1.1 million, or 4 cents per share, compared to $1.3 million, or 5 cents per share, for the same period in 2011. The $0.2 million decrease in net income over 2011 is primarily due to higher interest expense from Gill Ranch’s $40 million subsidiary senior secured debt, which was issued in the fourth quarter of 2011 and lower market prices for storage, partially offset by improved operating income at Gill Ranch for the second quarter of 2012 compared to 2011. These improved results primarily reflect higher revenues from an increase in contracted capacity and lower than expected power costs.

Six months ended June 30, 2012 compared to June 30, 2011:

For the six months ended June 30, 2012, our gas storage segment earned $1.9 million, or 7 cents per share, compared to $2.0 million, or 8 cents per share, for the same period in 2011. This decrease is primarily due to higher interest expense from Gill Ranch’s $40 million subsidiary senior secured debt, which was issued in the fourth quarter of 2011 and lower net operating income from our Mist facility, which was due to lower market prices for storage. In addition, we had lower revenues from third-party asset management services. Partially offsetting these decreases was improved operating income at Gill Ranch primarily reflecting higher revenues from an increase in contracted capacity and lower than expected power costs.

Gas storage margin increased $2.2 million to $14.7 million for the six months ended June 30, 2012. This increase in margin is primarily due to increased revenues from Gill Ranch from higher contracted capacity, partially offset by a decrease in Mist storage firm contract revenue, and third-party asset management revenues.

Business Segments - Other

Our other business segment consists primarily of NNG Financial’s investment in KB Pipeline, an equity investment in PGH, which in turn has invested in the Palomar pipeline project, and other miscellaneous non-utility investments and business activities. NNG Financial had total assets of $1.0 million as of both June 30, 2012 and 2011 primarily reflecting a non-controlling interest in the KB Pipeline, which is contracted to serve our utility. Our net equity investment in PGH as of June 30, 2012 and 2011 was $13.5 million and $14.4 million, respectively, with the year-over-year decrease reflecting a $1.3 million write-down taken in 2011. In aggregate, earnings from our other business segment for the six months ended June 30, 2012 and 2011 were net losses of $17 thousand and $0.3 million, respectively. See Note 4 in the 2011 Form 10-K, and Note 4 and Note 11 in this report, for further details on our other business segment and our investment in PGH.

Table of Contents

Consolidated Operations

Operations and Maintenance

Three months ended June 30, 2012 compared to June 30, 2011:

Operations and maintenance expense was $32.1 million in 2012 compared to $30.4 million in 2011 for an increase of $1.8 million or 6 percent. The primary factors contributing to the increase were:

·	a $1.2 million increase in utility payroll primarily related to an increase in field service employees; and

·	a $0.9 million increase in utility employee benefit expense, primarily related to health care and pension costs. See below for an additional discussion on pension costs.

Partially offsetting the above factors was:

·	a $0.2 million decrease in utility bad debt expense.

Six months ended June 30, 2012 compared to June 30, 2011:

Operations and maintenance expense was $66.5 million in 2012 compared to $61.5 million in 2011, for an increase of $5.0 million or 8 percent. The following summarizes the major factors that contributed to changes in operations and maintenance expense for the six months ended June 30, 2012 compared to June 30, 2011:

·	a $2.5 million increase in utility payroll primarily related to an increase in field service employees;

·	a $1.9 million increase in utility employee benefit expense, principally related to health care and pension costs (see below); and

·	a $1.8 million increase in utility non-payroll expense including higher costs for new employee training, expenses related to the Oregon general rate case, higher costs for information technology system maintenance and other customer service cost increases.

Partially offsetting the above factors were:

·	a $0.4 million reduction in operating expense in our gas storage segment primarily due to higher start-up costs for Gill Ranch in the first six months of 2011; and

·	a $0.2 million decrease in utility bad debt expense.

Our bad debt expense decreased in the second quarter of 2012 partly due to the positive impact of customer refunds on delinquent balances as of June 30, 2012. Our bad debt expense as a percent of revenues was 0.22 percent for the twelve months ended June 30, 2012, compared to 0.24 percent for the same period last year. Our bad debt expense results over the past few years have been favorable despite challenging economic conditions. We believe credit risks are still elevated due to the continuing weak economy and high unemployment rates, but we expect our bad debt expense ratio over the long term to remain below 0.5 percent of revenues.

Our accounting expense for pension costs increased fairly significantly in 2012 largely due to lower interest rates; however, the OPUC approved a deferral of NW Natural’s utility pension costs for amounts in excess of pension costs currently recovered in rates. The pension cost deferral is recorded to a regulatory balancing account, which reduces operations and maintenance expense. For the three and six months ended June 30, 2012, we deferred pension expenses totaling $2.1 million and $4.2 million, respectively, and $1.3 million and $2.7 million for the same periods last year (see Note 8). As a result, increased pension costs had a minimal effect on operations and maintenance expense in the current periods, with the increase principally related to the cost allocation to our Washington customers. For further explanation of the pension balancing account, see “Regulatory Matters—Rate Mechanisms—Pension Deferral,” above.

General Taxes

Three months ended June 30, 2012 compared to June 30, 2011:

General taxes increased $0.8 million, or 11 percent, in the three months ended June 30, 2012 over the same period in 2011, primarily due to a $0.5 increase in property taxes at Gill Ranch.

Six months ended June 30, 2012 compared to June 30, 2011:

General taxes increased $1.4 million in the first six months of 2012 compared to 2011. This increase was primarily due to a $1.0 increase in property taxes at Gill Ranch because of capital investments added to our assessed tax base for 2012.

Depreciation and Amortization

Depreciation and amortization expense increased by $0.6 million, or 3 percent for the three months ended June 30, 2012, compared to the same period in 2011. For the six months ended June 30, 2011, depreciation and amortization expense increased by $1.2 million, or 3 percent, as compared to the same period in 2011. The increased expense in 2012 was primarily related to higher depreciation at the utility and Gill Ranch because of plant asset additions.

Table of Contents

Other Income and Expense – Net

The following table provides details on other income and expense – net by primary components:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Thousands	2012			2011			2012			2011
Gains from company-owned life insurance	$	608		$	694		$	1,392		$	1,199
Interest income		89			23			105			30
Income from equity investments		2			(353	)		1			(353	)
Net interest on deferred regulatory accounts		835			1,501			1,840			3,015
Gain (loss) on sale of investments		-			-			-			(96	)
Other non-operating		(613	)		(743	)		(1,412	)		(1,459	)
Total other income and expense - net	$	921		$	1,122		$	1,926		$	2,336

Other income and expense – net for the six months ended June 30, 2012 decreased $0.4 million primarily due to $1.2 million of lower interest from net regulatory account balances. Net regulatory account balances in the first half of 2012 were lower due to environmental insurance recoveries received at the end of 2011 as well as accumulated gas cost savings from November 2011 through June 2012. The company’s refund of gas cost savings will increase the regulatory account balances which will result in higher interest in the second half of 2012. This decrease in other income and expense is partially offset by increases of $0.4 million and $0.2 million in income from equity investments and gains from life insurance policy proceeds, respectively.

Interest Expense – Net

Interest expense – net increased $0.2 million and $0.9 million for the three and six months ended June 30, 2012, respectively, compared to the same periods in 2011. The increase was primarily due to interest on our $40 million subsidiary senior secured debt, which was issued in the fourth quarter of 2011.

Income Tax Expense

The decrease in income tax expense of $0.4 million or 1 percent for the six months ended June 30, 2011, compared to the same period in 2011, was primarily due to lower pre-tax consolidated earnings of $1.4 million or 2 percent. See Note 9.

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 capital are also used to fund long-term debt redemptions and short-term commercial paper maturities (see “Liquidity and Capital Resources,” below, and Note 7). 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 at June 30, 2012 and 2011 and at December 31, 2011 was as follows:

	June 30,						December 31,
	2012			2011			2011
Common stock equity		49.4	%		47.9	%		46.5	%
Long-term debt		43.0	%		37.0	%		41.7	%
Short-term debt, including current maturities of long-term debt		7.6	%		15.1	%		11.8	%
Total		100	%		100	%		100	%

Table of Contents

Liquidity and Capital Resources

At June 30, 2012, we had $4.0 million of cash and cash equivalents compared to $3.7 million at June 30, 2011. We also had $4.0 million in restricted cash at Gill Ranch as of June 30, 2012 which is being held as collateral for the long-term debt outstanding. In order to maintain sufficient liquidity during periods when capital markets are volatile, we may elect to maintain higher cash balances, add short-term borrowing capacity, or 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 current market conditions are significantly better as reflected by tighter credit spreads and increased access to financing for investment grade issuers. Based on our current debt ratings (see “Credit Ratings,” below), we have been able to issue commercial paper and first mortgage bonds 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 certain regulatory approvals. As of June 30, 2012, we have OPUC approval to issue up to $125 million of additional debt for approved purposes, of which on July 12, 2012, NW Natural entered into an agreement with investors to sell $50 million of first mortgage bonds. The agreed upon bond issuance is subject to customary closing conditions and is expected to close on or before October 31, 2012.

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 June 30, 2012, we could have been required to post $19.2 million of collateral to our counterparties, but that assumes our long-term debt ratings were at non-investment grade levels, which would be a very significant change from current rating levels for NW Natural (see Note 12 and “Credit Ratings,” below).

In July 2010, the U.S. Congress passed and President Obama signed into law the “Dodd-Frank Wall Street Reform and Consumer Protection Act” (Dodd-Frank Act). The legislation established a new statutory framework for the comprehensive regulation of financial institutions that participate in the swaps market and, among other things, requires additional government regulation of derivative and over-the-counter transactions and expanded collateral requirements. In July 2012, pursuant to the Dodd-Frank Act, the Commodity Futures Trading Commission (CFTC) and SEC issued rules that further define the term “Swap,” and set forth requirements for the “End-User Exception.” At this time, we do not expect the rules to have a material impact on our financial statements and disclosures. We will continue to monitor interpretations and implementation requirements related to the Dodd-Frank Act to determine the impact, if any, on our hedging policies, procedures, results of operations, financial position and liquidity.

Other recent developments that may have a significant impact on our liquidity and capital resources include pension contribution requirements, tax benefits and liabilities, environmental expenditures and insurance recoveries, and customer refunds of gas cost savings. With respect to pension requirements, we expect to make significant contributions over the next several 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 allowed us to take 100 percent bonus depreciation on qualified expenditures during 2011, and allows 50 percent bonus depreciation on a majority of our capital expenditures in 2012, which significantly reduces our tax liability for those tax years and provides cash flow benefits in 2012 and 2013. 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, even though the amount and timing of these expenditures and recoveries is uncertain (see Note 13 and “Cash Flows—Operating Activities,” below).

With respect to customer refunds or credits, gas prices have been significantly lower in recent months than the gas prices embedded in customer rates. As a result, our PGA incentive sharing mechanism deferred 90 percent of these gas cost savings attributed to Oregon, and 100 percent of the savings attributed to Washington, into a regulatory account for refund back to customers (see “Purchased Gas Adjustment,” above). Ordinarily, these refunds would be credited to customer rates in the next year’s PGA filing, but in the second quarter of 2012 the company received regulatory approval to immediately credit $35 million to Oregon customers and $4 million to Washington customers through billing credits. In addition, the company also received approval to provide its Oregon utility customers with a $9 million interstate storage credit from our regulatory incentive sharing mechanism related to gas storage and asset management services. These credits were applied to customer bills beginning in June of 2012.

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 a fixed interest rate 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 through June 30, 2012. These notes are secured by all of the membership interests in Gill Ranch Storage, LLC, and are nonrecourse to NW Natural and other entities of the consolidated group. 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 the 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.

Table of Contents

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 June 30, 2012 and 2011, our utility had commercial paper outstanding of $113.2 million and $185.4 million, respectively. The effective interest rate on the utility’s commercial paper outstanding at June 30, 2012 and 2011 was 0.3 percent.

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 June 30, 2012 (see table below).

		Loan Commitment Amounts in Thousands
		Syndicated
Lender rating, by category		Facility
AA/Aa		$	125,000
A/A			125,000
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 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. This credit facility is scheduled to expire next year, but we intend to enter into a new agreement later this year to replace the existing facility.

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 June 30, 2012 and 2011. 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 June 30, 2012 and 2011, with consolidated indebtedness to total capitalization ratios of 51 percent and 52 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- or Baa3 by Moody’s would require additional approval from the OPUC prior to issuance of 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).

Table of Contents

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 current debt ratings from S&P and Moody’s:

	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.

Maturity and Redemption of Long-Term Debt

For the six months ended June 30, 2012, $40 million of secured Medium Term Notes (MTNs) with a coupon rate of 7.13% were redeemed at maturity. Over the next twelve months, there are no scheduled maturities or redemptions of long-term debt. For long-term debt maturing over the next five years, see “Contractual Obligations” in our 2011 Form 10-K.

Cash Flows

Operating Activities

Six months ended June 30, 2012 compared to June 30, 2011:

For the six months ended June 30, 2012, cash flow from operating activities totaled $175.4 million, compared to $168.7 million in 2011. Year-over-year changes in our operating cash flows are primarily affected by net income, changes in working capital requirements, and other cash and non-cash adjustments to operating results. The significant factors contributing to changes in operating cash flow in the first six months of 2012 compared to 2011 are as follows:

·	an increase of $34.4 million from reductions in receivable balances primarily due to customer credit refunds in June 2012 plus higher receivable balances from colder weather at the end of 2011, which were collected early in 2012;

·	an increase of $11.0 million from changes in regulatory and other long-term liability accounts offset by cash flow decreases related to derivatives;

·	a decrease of $14.5 million from changes in the deferred gas cost liability account balance, which resulted from credit refunds to customers in June 2012;

·	a decrease of $12.6 million from taxes accrued, primarily related to our federal tax refund of $14.4 million received in the first quarter of 2011; and

·	a decrease of $7.8 million from accounts payable, due to increased non-capital payables in 2012 compared to 2011.

Also affecting cash flow from operating activities is the amount of cash contributions being made to the utility’s qualified defined benefit pension plans. During the six months ended June 30, 2012, we contributed $18.4 million to these plans, which was significantly higher than the $4.1 million in non-cash expense recognized on the income statement, and for the six months ended 2011 we contributed $16.4 million while only $3.7 million in non-cash expense was recognized on the income statement. We expect contributions to these plans to exceed non-cash expense for the next few years, but amounts and timing of these expenses will depend on market interest rates and investment returns on the plans’ assets.

The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (the Tax Relief Act) allowed 100 percent bonus depreciation on 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 during 2012. These and other tax benefits resulted in a net operating tax loss for 2010, which was carried back to the tax year 2009 and resulted in a federal income tax refund of $22.3 million received in 2011. We also continue to generate net operating loss (NOL) carry-forwards. As of June 30, 2012, we had an estimated federal income tax receivable balance of $3.1 million and an estimated NOL carry-forward balance of $57.8 million to 2013. We anticipate being able to use the full amount of the current NOL carry-forward balance in future years. The federal NOL from 2010 would expire in 2031 if not used in earlier years.

Table of Contents

Investing Activities

Six months ended June 30, 2012 compared to June 30, 2011:

Cash used in investing activities for the six months ended June 30, 2012 totaled $88.6 million, up from $63.9 million for the same period in 2011. Capital expenditures were $61.6 million in the six months ended June 30, 2012, up from $47.8 million for the same period in 2011, which is being driven by facilities projects as noted below. We also invested $27.0 million into utility gas reserves in the first half of 2012 compared to $16.2 million in the second quarter of 2011 under our agreement with Encana.

In 2012, we purchased a property in Sherwood, Oregon which, along with anticipated sale of existing properties, will enable us to consolidate and streamline certain field operations and maintenance groups, and will provide us with expanded scenario-based pipeline training capabilities and a back-up business operations site.

We expect to spend up to $150 million in the utility and up to $5 million in the non-utility capital projects in 2012. Non-utility gas storage capital expenditures in 2012 are expected to be paid primarily from working capital, and potentially with additional funds from the NW Natural consolidated group. For more information on capital projects see “Cash Flows—Investing Activities” in the 2011 Form 10-K. For more information on non-utility investment opportunities, see Note 11 and “Strategic Opportunities—Gas Storage Operations” and “—Pipeline Diversification,” above.

Financing Activities

Six months ended June 30, 2012 compared to June 30, 2011:

Cash used in financing activities during the six months ended June 30, 2012 totaled $88.7 million, down from cash used of $104.6 million for the same period in 2011. The main driver of this decrease in financing activity is our short-term debt balances which decreased $28.4 million in the six months ended June 30, 2012, compared to a decrease of $72.0 million for the same period in 2011. This decrease was offset by a $30.0 million increase in long-term debt retirements in 2012. We continue to use long-term debt proceeds to finance capital expenditures, refinance maturing short-term or long-term debt maturities, and for general corporate purposes.

Pension Cost and Funding Status of Qualified Retirement Plans

We make pension contributions to company-sponsored qualified defined benefit plans based on actuarial assumptions and estimates, tax regulations and funding requirements under federal law. Our qualified defined benefit plans were underfunded by $146.9 million at December 31, 2011. For the six months ended June 30, 2012, we made cash contributions totaling $18.4 million into these qualified pension plans. We anticipate making additional contributions before yearend, bringing the total amount to around $28 million in 2012. In 2011 and 2010, we contributed $20 million and $10 million, respectively, into the qualified defined pension plans. For more information on the funded status of our qualified retirement plans and other postretirement benefits, see Note 8, and Part II, Item 7., “Financial Condition—Pension Cost and Funding Status of Qualified Retirement Plans,” and Part II, Item 8., Note 9, “Pension and Other Postretirement Benefits,” in the 2011 Form 10-K.

We also contribute to a multi-employer union pension plan (Western States Plan) pursuant to our collective bargaining agreement. We made contributions totaling $0.2 million to the Western States Plan in both the six months ended June 30, 2012 and 2011, and we expect to contribute a total of $0.4 million during 2012. See Note 8 for further discussion.

Ratios of Earnings to Fixed Charges

For the six and twelve months ended June 30, 2012 and the twelve months ended December 31, 2011, our ratios of earnings to fixed charges, were 4.15, 3.32 and 3.41 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 Part II, Item 7., “Application of Critical Accounting Policies and Estimates,” in our 2011 Form 10-K). At June 30, 2012, we had a regulatory asset of $117.9 million for deferred environmental costs, which includes $76.7 million for additional costs expected to be paid in the future and accrued interest of $21.2 million. 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 13.

Table of Contents

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various forms of market risk including commodity supply risk, commodity price and storage value risk, interest rate risk, foreign currency risk, credit risk and weather risk. We monitor and manage these financial exposures as an integral part of our overall risk management program. No material changes have occurred related to our disclosures about market risk for the six month period ending June 30, 2012. See Part I, Item 1A., “Risk Factors,” and Part II, Item 7A. “Quantitative and Qualitative Disclosures about Market Risk,” in the 2011 Form 10-K and Part II, Item 1A., “Risk Factors,” in this report for details regarding these risks.

ITEM 4. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

The Company's management, together with its consolidated subsidiaries, 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

The Company's management, together with its consolidated subsidiaries, 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 June 30, 2012 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 4(b).

Table of Contents

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Other than the proceedings disclosed in Note 13 and those proceedings disclosed and incorporated by reference in Part I, Item 3., “Legal Proceedings,” in our 2011 Form 10-K, we have only routine nonmaterial litigation in the ordinary course of business.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors discussed in Part I, “Item 1A. Risk Factors,” in our 2011 Form 10-K. In addition to the other information set forth in this report, you should carefully consider those risk factors, which could materially affect our business, financial condition or results of operations.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table provides information about purchases by us during the quarter ended June 30, 2012 of equity securities that are registered pursuant to Section 12 of the Exchange Act:

ISSUER PURCHASE 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
04/01/12 - 04/30/12		-	$	-		-		-
05/01/12 - 05/31/12		3,506		46.23		-		-
06/01/12 - 06/30/12		-		-		-		-
Total		3,506	$	46.23		2,124,528	$	16,732,648

(1)

During the quarter ended June 30, 2012, 3,506 shares of our common stock were purchased on the open market to meet the requirements of our share-based programs. During the quarter ended June 30, 2012, 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 common stock share repurchase program under which we purchase shares on the open market or through privately negotiated transactions. We currently have Board authorization through May 31, 2013 to repurchase up to an aggregate of 2.8 million shares or up to an aggregate of $100 million. During the quarter ended June 30, 2012, no shares of our common stock were purchased 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.

ITEM 6. EXHIBITS

See Exhibit Index attached hereto.

Table of Contents

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

NORTHWEST NATURAL GAS COMPANY

(Registrant)

Dated: August 3, 2012

/s/ Stephen P. Feltz

Stephen P. Feltz

Principal Accounting Officer

Treasurer and Controller

Table of Contents

NORTHWEST NATURAL GAS COMPANY

EXHIBIT INDEX

Quarterly Report on Form 10-Q

For the Quarter Ended

June 30, 2012

Exhibit Number Document


12	Statement re computation of ratios of earnings to fixed charges.

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.

101	The following materials from Northwest Natural Gas Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2012, 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.