Northwest Natural Gas Company (NWN)

Recent Accounting Pronouncements

Fair Value Measurement.> In May 2011, the FASB issued amendments to the authoritative guidance on fair value measurement.  The amendments are primarily related to disclosure requirements, which go into effect for periods beginning after December 15, 2011.  Early implementation is not allowed and we are currently assessing the impact on our financial statement disclosures.

Comprehensive Income.> In June 2011, the FASB issued authoritative guidance on the presentation of comprehensive income within the financial statements.  An entity can elect to present items of net income and other comprehensive income in one continuous statement — referred to as the statement of comprehensive income — or in two separate, but consecutive, statements. These changes are effective for periods beginning after December 15, 2011. We intend to present net income and other comprehensive income in one continuous statement starting January 1, 2012.

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

 

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PART I.  FINANCIAL INFORMATION

3.	Earnings Per Share

 

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

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

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

4.	Segment Information

We operate in two primary reportable business segments, local gas distribution and gas storage.  We also have other investments and business activities not specifically related to one of these two reporting segments, which we aggregate and report as “other.”  We refer to our local gas distribution business as the “utility,” and our “gas storage” and “other” business segments as “non-utility.” Our gas storage segment includes NWN Gas Storage, which is a wholly-owned subsidiary of NWN Energy, Gill Ranch, which is a wholly-owned subsidiary of NWN Gas Storage, the non-utility portion of our Mist underground storage facility in Oregon (Mist) and third-party optimization services. Our “other” segment includes NNG Financial and our equity investment in PGH, which is pursuing development of the Palomar pipeline project.  For further discussion of our segments, see Note 4 in our 2010 Form 10-K.

 

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

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

5.	Common Stock

 

We have a share repurchase program for our common stock under which we purchase shares on the open market or through privately negotiated transactions.  We currently have Board authorization through May 2012 to repurchase up to an aggregate of 2.8 million shares, but not to exceed $100 million. No shares of common stock were repurchased pursuant to this program during the nine months ended September 30, 2011.  Since inception in 2000, a total of 2.1 million shares have been repurchased at a total cost of $83.3 million.

 

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6.	Stock-Based Compensation

We have several stock-based compensation plans, including a Long-Term Incentive Plan (LTIP), a Restated Stock Option Plan (Restated SOP) and an Employee Stock Purchase Plan.  These plans are designed to promote stock ownership in NW Natural by employees and officers.  For additional information on our stock-based compensation plans, see Part II, Item 8., Note 6, in the 2010 Form 10-K and current updates provided below.

 

Long-Term Incentive Plan.>  On February 23, 2011, 37,950 performance-based shares were granted under the LTIP, which include a market condition, based on target-level awards and a weighted-average grant date fair value of $25.25 per share.  Fair value was estimated as of the date of grant using a Monte-Carlo option pricing model based on the following assumptions:

Stock price on valuation date		$	45.74
Performance term (in years)			3.0
Quarterly dividends paid per share		$	0.435
Expected dividend yield			3.7	%
Dividend discount factor			0.8930

Restated Stock Option Plan.>  On February 23, 2011, options to purchase 122,700 shares were granted under the Restated SOP, with an exercise price equal to the closing market price of $45.74 per share on the date of grant, vesting over a four-year period following the date of grant and a term of 10 years and 7 days. The weighted-average grant date fair value was $6.73 per share.  Fair value was estimated as of the date of grant using the Black-Scholes option pricing model based on the following assumptions:

Risk-free interest rate			2.0	%
Expected life (in years)			4.5
Expected market price volatility factor			24.5	%
Expected dividend yield			3.8	%
Forfeiture rate			3.1	%

As of September 30, 2011, there was $1.0 million of unrecognized compensation cost related to the unvested portion of outstanding Restated SOP awards expected to be recognized over a period extending through 2014.  

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

 

New Issuance of Long-Term Debt

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

Cost of Long-Term Debt

Our long-term debt consists of secured MTNs with maturity dates from 2012 through 2035, interest rates ranging from 3.176 percent to 9.05 percent, and a weighted-average coupon rate of 5.93 percent.  For the nine months ended September 30, 2011, we redeemed $10 million of MTNs.  For more detail on our outstanding long-term debt, see Note 7 in our 2010 Form 10-K and new issuance of long-term debt above.

 

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Fair Value of Long-Term Debt

 

The following table provides an estimate of the fair value of our long-term debt, including current maturities of long-term debt, using market prices in effect on the valuation date.  Because our debt outstanding does not trade in active markets, we used interest rates of other companies outstanding debt issues that actively trade and have similar credit ratings, terms and remaining maturities to estimate fair value of our long-term debt issues.  These are significant other observable inputs, or level 2 inputs, in the fair value hierarchy.

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

8.	Comprehensive Income

 

Items excluded from net income and charged directly to stockholders’ equity are included in accumulated other comprehensive income (loss), net of tax.  The amount of accumulated other comprehensive loss in stockholders’ equity is $6.2 million and $5.7 million as of September 30, 2011 and 2010, respectively, which is related to employee benefit plan liabilities.  The following table provides a reconciliation of net income to total comprehensive income for the nine months ended September 30, 2011 and 2010.

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

 

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9.	Pension and Other Postretirement Benefit Costs

 

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

	Three Months Ended September 30,
										Other Postretirement
		Pension Benefits								Benefits
Thousands		2011				2010				2011				2010
Service cost		$	1,839			$	1,435			$	168			$	156
Interest cost			4,503				4,517				344				343
Expected return on plan assets			(4,455	)			(4,528	)			-				-
Amortization of net actuarial loss			2,683				2,028				68				7
Amortization of prior service costs			88				(270	)			50				50
Amortization of transition obligations			-				-				103				103
Net periodic benefit cost			4,658				3,182				733				659
Amount allocated to construction			(1,279	)			(897	)			(234	)			(231	)
Amount deferred to regulatory balancing account(1)			(1,330	)			-				-				-
Net amount charged to expense		$	2,049			$	2,285			$	499			$	428
	Nine Months Ended September 30,
										Other Postretirement
		Pension Benefits								Benefits
Thousands			2011				2010				2011				2010
Service cost		$	5,638			$	4,981			$	504			$	468
Interest cost			13,556				13,500				1,031				1,028
Expected return on plan assets			(13,367	)			(13,655	)			-				-
Amortization of net actuarial loss			8,067				5,564				204				22
Amortization of prior service costs			264				140				148				148
Amortization of transition obligations			-				-				309				309
Net periodic benefit cost			14,158				10,530				2,196				1,975
Amount allocated to construction			(3,765	)			(2,797	)			(689	)			(646	)
Amount deferred to regulatory balancing account(1)			(3,989	)			-				-				-
Net amount charged to expense		$	6,404			$	7,733			$	1,507			$	1,329
(1) Effective January 1, 2011, the OPUC approved the deferral of certain pension expenses above or below the amount set in rates, with recovery of these deferred amounts through the implementation of a balancing account, which includes the expectation of lower pension expenses in future years. Our recovery of deferred pension expense balances includes accrued interest at the utility’s authorized rate of return.

See Part II, Item 8., Note 9, in the 2010 Form 10-K for more information about our pension and other postretirement benefit plans.

 

 

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In addition to the company-sponsored defined benefit plans referred to above, in accordance with our collective bargaining agreement, we contribute to a multiemployer pension plan for our bargaining unit employees known as the Western States Office and Professional Employees International Union Pension Fund (Western States Plan).  The cost of this plan is in addition to pension expense in the table above.  The Western States Plan is managed by a board of trustees that includes equal representation from participating employers and labor unions. Contribution rates are established by collective bargaining agreements, and benefit levels are set by the board of trustees based on the advice of an independent actuary regarding the level of benefits that agreed-upon contributions are expected to support.  The Western States Plan has reported an accumulated funding deficit for the current plan year and remains in critical status.  A plan is considered to be in critical status if its funded status is 65 percent or less. Federal law requires pension plans in critical status to adopt a rehabilitation plan designed to restore the financial health of the plan. Rehabilitation plans may specify benefit reductions, contribution surcharges, or a combination of the two.  The Western States Plan trustees adopted a rehabilitation plan that reduced benefit accrual rates and adjustable benefits for active employee participants and increased future employer contribution rates.  These changes are expected to improve the funding status of the plan.  We made contributions totaling $0.3 million to the Western States Plan for both the nine months ended September 30, 2011 and 2010.  This amount includes the 10 percent contribution surcharge.  Contribution surcharges above the current 10 percent rate will be assessed to employer participants, but these higher surcharges will not go into effect for NW Natural until its next collective bargaining agreement, which is expected to be no earlier than June 1, 2014. Under the terms of our current collective bargaining agreement, which became effective in July 2009, we can withdraw from the Western States Plan at any time. However, if we withdraw and the plan is underfunded, we could be assessed a withdrawal liability.  In accordance with accounting rules for multiemployer plans, we have not currently recognized these potential withdrawal liabilities on the balance sheet.  Currently, we have no intent to withdraw from the plan, so we have not recorded a withdrawal liability.

Employer Pension Contributions

 

In the nine months ended September 30, 2011, we made cash contributions totaling $19.2 million to our qualified defined benefit pension plans.  We also expect to make additional contributions of up to $4 million to these qualified plans over the last three months of 2011, plus we expect to make ongoing benefit payments under our unfunded, non-qualified pension plans and other postretirement benefit plans. For more information see Part II, Item 8., Note 9, in the 2010 Form 10-K.

 

10.           Income Tax

The effective income tax rate for the nine months ended September 30, 2011 and 2010 varied from the combined federal and state statutory tax rates principally due to the following:

		September 30,
		2011				2010
Federal statutory tax rate			35.0	%			35.0	%
Increase (decrease):
Current state income tax, net of federal tax benefit			4.5	%			4.8	%
Amortization of investment and energy tax credits			(0.4	) %			(0.4	) %
Differences required to be flowed-through by regulatory commissions			1.5	%			1.2	%
Gains on company and trust-owned life insurance			(0.9	) %			(0.8	) %
Other - net			0.7	%			0.5	%
Effective income tax rate			40.4	%			40.3	%

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

 

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11.	Property, Plant and Equipment

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

		September 30,								December 31,
Thousands		2011				2010				2010
Utility plant in service		$	2,296,788			$	2,222,222			$	2,247,952
Utility construction work in progress			36,459				33,359				29,324
Less: Accumulated depreciation			740,378				700,193				710,214
Utility plant-net			1,592,869				1,555,388				1,567,062
Non-utility plant in service			290,075				66,299				290,038
Non-utility construction work in progress			9,176				206,823				9,088
Less: Accumulated depreciation			16,214				10,853				12,025
Non-utility plant-net		$	283,037			$	262,269			$	287,101
Total property, plant and equipment		$	1,875,906			$	1,817,657			$	1,854,163

12.           Gas Reserves and Other Investments

Our gas reserves are stated at cost, net of regulatory amortization, with the associated deferred tax benefits recorded as liabilities on the balance sheet.  Other investments include financial investments in life insurance policies, which are accounted for at fair value, and equity investments in certain partnerships and limited liability companies, which are accounted for under the equity or cost methods.  See Part II, Item 8., Note 12, in the 2010 Form 10-K for more detail on our investments.

Gas Reserves

We entered into an agreement with Encana Oil & Gas (USA) Inc. (Encana) to develop physical gas reserves that are expected to supply a portion of NW Natural’s utility customers’ requirements over the next 30 years.  The volume of gas produced and allocated to NW Natural under the agreement will increase in the early years as we continue to invest in drilling, with volumes expected to peak at about 13 percent of our utility’s gas supply requirement in gas year 2015-2016.  Over the first 10 years of the agreement (2011-2020), volumes are expected to average approximately 8 to 10 percent of the annual gas purchase requirements of our utility customers.  Under the agreement, we expect to invest approximately $45 million to $55 million per year for five years, and our total investment is expected to be about $250 million.

Upon reviewing the transaction, the OPUC determined that our Company’s costs under the agreement will be recovered on an ongoing basis through its annual Purchased Gas Adjustment (PGA) mechanism, including the regulatory deferral and incentive sharing process for the commodity cost of gas.  Annually, a forecast will be established for the amounts related to costs and volumes expected, and any variances between forecasted and actual will be subject to the PGA incentive sharing in Oregon, up to a maximum variance of $10 million of which 10 percent (or $1 million maximum) would be recognized in current income. Variances in excess of $10 million, both negative and positive, will be deferred and passed through to customers in future rates at 100 percent.  As part of the decision by the OPUC, we agreed to file a general rate case in Oregon no later than December 31, 2011.

Encana began drilling in May 2011 under our agreements, and we are currently receiving gas from our interests in a section of the gas field.  Our net investment at September 30, 2011 is $20.4 million, with deferred taxes totaling $10.1 million.

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

 

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Palomar

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

Variable Interest Entity Analysis.> As of September 30, 2011, we updated our VIE analysis and determined that we are not the primary beneficiary of PGH’s activities as defined by the authoritative guidance related to consolidations.  Therefore, we account for our investment in PGH and the Palomar project under the equity method, which is included in other investments on our balance sheet.  Our maximum loss exposure related to PGH is limited to our equity investment balance, less our share of any cash or other assets available to us as a 50 percent owner.

Impairment Analysis.> Our investments in nonconsolidated entities accounted for under the equity method are reviewed for impairment when circumstances or events indicate a potential loss in value may have occurred, and on an annual basis following updates to our corporate planning assumptions.  When it is determined that a loss in value is other than temporary, an impairment charge is recognized for the difference between the investment’s carrying value and its estimated fair value.  Fair value is based on quoted market prices when available, or on the present value of expected discounted future cash flows. Differing assumptions could affect the timing and amount of an impairment recorded in any period.

Earlier in 2011, our investment in PGH was reviewed for impairment when Palomar withdrew its original application with the Federal Energy Regulatory Commission (FERC) for a proposed natural gas pipeline in Oregon.  At the same time, Palomar informed FERC that it intended to re-file an application later this year or in 2012 to reflect changes in the project scope, which was expected to eliminate the western portion of the proposed pipeline and align the revised project with the region’s current and future gas infrastructure needs. Palomar is working with customers in the Pacific Northwest to further understand their gas transportation needs and determine the commercial support for a revised pipeline proposal.  We expect to file a new FERC certificate application to reflect a revised scope based on regional needs.

During the second quarter of 2011, we re-evaluated our equity investment in Palomar assets related to the western portion of the pipeline and determined that these costs were impaired, and as a result we recorded a pre-tax charge of $0.3 million for our share of the project.  Our remaining investment balance in Palomar consists of costs related to the east zone, of which the investment balance at September 30, 2011 is $14.4 million.  We continue to review the east zone costs for impairment based on the current status of the project, including Palomar’s plans to conduct an open season and re-file a revised application with FERC thereafter.  Based on our current review, we determined that our remaining equity investment was not impaired because the fair value of expected cash flows from planned development of the eastern portion of the pipeline project exceeds our equity investment.  However, if we learn later that the project is not viable or will not go forward, then we could be required to recognize a maximum impairment charge of up to approximately $14.1 million based on the current amount of our equity investment net of cash and working capital at Palomar.  We will continue to monitor and update our impairment analysis as needed.

 

 

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13.	Derivative Instruments

 

We enter into swap, option and combinations of option contracts for the purpose of hedging natural gas.  We primarily use these derivative financial instruments to manage commodity prices related to our natural gas purchase requirements.  A small portion of our derivative hedging strategy involves foreign currency exchange transactions related to purchases on natural gas from Canadian suppliers.

 

In the normal course of business, we enter into indexed-price physical forward natural gas commodity purchase (gas supply) contracts to meet the requirements of core utility customers.  We also enter into financial derivatives, up to prescribed limits, to hedge price variability related to these physical gas supply contracts.  Derivatives entered into prudently for future gas years prior to our annual PGA filing receive regulatory deferred accounting treatment.  Derivative contracts entered into after the annual PGA rate is set for the current gas contract year are subject to our PGA incentive sharing mechanism, which, provides for either an 80 or a 90 percent deferral of any gains and losses as regulatory assets or liabilities, with the remaining 10 or 20 percent recognized in current  income.  All of our commodity hedging for the 2011-12 gas year was completed prior to the start of the gas year, and these hedge prices were included in our PGA filing.  

The following table reflects the income statement presentation for the unrealized gains and losses from our derivative instruments for the nine months ended September 30, 2011 and 2010.  All of our currently outstanding derivative instruments are related to regulated utility operations as illustrated by the derivative gains and losses being deferred to balance sheet accounts in accordance with regulatory accounting standards.

		Three Months Ended
		September 30, 2011						September 30, 2010
Thousands			Natural gas commodity(1)			Foreign currency (2)			Natural gas commodity(1)			Foreign currency (2)
Cost of sales		$	(18,987)		$	-		$	(35,744)		$	-
Other comprehensive income (loss)			-			(1,221)			-			449
Less:
Amounts deferred to regulatory accounts on balance sheet			18,987			1,221			35,744			(449)
	Total impact on earnings	$	-		$	-		$	-		$	-
		Nine Months Ended
		September 30, 2011						September 30, 2010
Thousands			Natural gas commodity(1)			Foreign currency (2)			Natural gas commodity(1)			Foreign currency (2)
Cost of sales		$	(49,106)		$	-		$	(84,837)		$	-
Other comprehensive income (loss)			-			(815)			-			110
Less:
Amounts deferred to regulatory accounts on balance sheet			49,106			815			84,837			(110)
	Total impact on earnings	$	-		$	-		$	-		$	-
(1)	Unrealized gain (loss) from natural gas commodity hedge contracts is recorded in cost of sales and reclassified to regulatory deferral accounts on the balance sheet.
(2)	Unrealized gain (loss) from foreign currency exchange contracts is recorded in other comprehensive income, and reclassified to regulatory deferral accounts on the balance sheet.

 

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No collateral was posted with or by our counterparties as of September 30, 2011 or 2010.  We attempt to minimize the potential exposure to collateral calls by counterparties to manage our liquidity risk.  Counterparties generally allow a certain credit limit threshold before requiring us to post collateral against loss positions. Given our counterparty credit limits and diversification, we have not been subject to collateral calls in 2010 or 2011.  Our collateral call exposure is set forth under credit support agreements, which generally contain credit limits. We could also be subject to collateral call exposure where we have agreed to provide adequate assurance, which is not specific as to the amount of credit limit allowed, but could potentially require additional collateral in the event of a material adverse change.  Based upon current contracts outstanding, which reflect unrealized losses of $49.9 million at September 30, 2011, we have estimated the level of collateral demands, with and without potential adequate assurance calls, using current gas prices and various downgrade credit rating scenarios for NW Natural as follows:

						Credit Rating Downgrade Scenarios
Thousands		(Current Ratings) A+/A3				BBB+/Baa1				BBB/Baa2				BBB-/Baa3				Speculative
With Adequate Assurance Calls		$	-			$	-			$	-			$	5,609			$	37,171
Without Adequate Assurance Calls		$	-			$	-			$	-			$	4,581			$	31,143

In the three and nine months ended September 30, 2011, we realized net losses of $6.6 million and $36.2 million, respectively, from the settlement of natural gas hedge contracts at maturity, which were recorded as increases to the cost of gas, compared to net losses of $12.6 million and $33.3 million, respectively, for the three and nine months ended September 30, 2010.  The exchange rate in all foreign currency forward purchase contracts is included in our purchased cost of gas at settlement; therefore, no gain or loss is recorded from the settlement of those contracts.

We are exposed to derivative credit and liquidity risk primarily through securing fixed price natural gas commodity swaps to hedge the risk of price increases for our natural gas purchases made on behalf of our customers.  For more information on our derivative instruments, see Note 13 in our 2010 Form 10-K.

 

Fair Value

 

In accordance with fair value accounting, we include nonperformance risk in calculating fair value adjustments.  This includes a credit risk adjustment based on the credit spreads of our counterparties when we are in an unrealized gain position, or on our own credit spread when we are in an unrealized loss position.  Our assessment of non-performance risk is generally derived from the credit default swap market and from bond market credit spreads. The impact of the credit risk adjustments for all outstanding derivatives was immaterial to the fair value calculation at September 30, 2011.  As of September 30, 2011 and 2010 and December 31, 2010, the fair value was $49.9 million, $84.7 million and $52.6 million, respectively, using significant other observable, or level 2, inputs.  We have used no level 3 inputs in our derivative valuations.  We also did not have any transfers between level 1 or level 2 during the nine months ended September 30, 2011 and 2010.

 

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14.	Commitments and Contingencies

Environmental Matters

 

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

We regularly review our environmental liability for each site where we may be exposed to remediation responsibilities.  The costs of environmental remediation are difficult to estimate.  A number of steps are involved in each environmental remediation effort, including site investigations, remediation, operations and maintenance, monitoring and site closure.  Each of these steps may, over time, involve a number of alternative actions, each of which can change the course and scope of the effort.  Many of these steps are dependent upon the approval and direction of federal and state environmental regulators.  The policies, determinations and directions of the regulators may develop and change over time and different regulators may take different positions on the various steps, creating further uncertainty as to the timing and scope of remediation activities.  In certain cases, in addition to us, there are a number of other potentially responsible parties, each of which, in proceedings and negotiations with other potentially responsible parties and regulators, may influence the course and scope of the remediation effort. The allocation of liabilities among the potentially responsible parties is often subject to dispute and can be highly uncertain.  The events giving rise to environmental liabilities often occurred many decades ago, which complicates the determination of allocating liabilities among potentially responsible parties.  Site investigations and remediation efforts often develop slowly over many years.  In addition, disputes may arise between potentially responsible parties and regulators as to the severity of particular environmental matters and what remediation efforts are appropriate.  These disputes could lead to adversarial administrative proceedings or litigation, with uncertain outcomes.

We estimate the range of loss for environmental liabilities using current technology, enacted laws and regulations, industry experience gained at similar sites and an assessment of the probable level of involvement and financial condition of other potentially responsible parties.  Unless there is an estimate within a range of possible losses that is more likely than other cost estimates within that range, we record the liability at the lower end of this range.  It is likely that changes in these estimates and ranges will occur throughout the remediation process for each of these sites due to uncertainty concerning our responsibility, the complexity of environmental laws and regulations and the selection of compliance alternatives.  The status of each of the sites currently under investigation is provided below.

 

Gasco site.> We own property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 (Gasco site). The Gasco site has been under investigation by us for environmental contamination under the Oregon Department of Environmental Quality’s (ODEQ) Voluntary Clean-Up Program. In June 2003, we filed a Feasibility Scoping Plan which outlined a range of remedial alternatives for the most contaminated portion of the Gasco site. In December 2004, we submitted an Ecological and Human Health Risk Assessment to ODEQ, and in May 2007 we completed a revised Remedial Investigation Report and submitted it to ODEQ for review. 

In 2007, we also submitted a Focused Feasibility Study (FFS) for the groundwater source control portion of the Gasco site, which ODEQ conditionally approved in March 2008, subject to the submission of additional information.  We provided that information to ODEQ and are now working with the agency on the final design for the source control system.  Based on the information currently available for groundwater source control at the Gasco site and our current assumptions regarding remediation, we have estimated a range of liability between $11 million and $30 million, for which we have recorded an accrued liability of $11.8 million at September 30, 2011.  The estimated range of liability will be reassessed when ODEQ makes a final source control design decision.

In addition to groundwater source control, we signed a joint Order on Consent with the Environmental Protection Agency (EPA), which requires the design of remedial action for sediments from the Gasco site. This design project is underway.  For the sediments project and the other investigation and clean-up work, we have recorded an additional accrued liability of $36.6 million, which reflects the low end of the range of potential liability.  We accrued at the low end because no amount within the range is considered to be more likely than another, and the high end of the range cannot reasonably be estimated.

 

Siltronic site.> We previously owned property adjacent to the Gasco site that now is the location of a manufacturing plant owned by Siltronic Corporation (the Siltronic site). We are currently conducting an investigation of manufactured gas plant wastes on the uplands at this site for the ODEQ.  The liability accrued at September 30, 2011 for the Siltronic site is $0.8 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.

 

 

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Portland Harbor site.> In 1998, the ODEQ and the EPA completed a study of sediments in a 5.5-mile segment of the Willamette River (Portland Harbor) that includes an area adjacent to the Gasco and Siltronic sites. The Portland Harbor was listed by the EPA as a Superfund site in 2000 and we were notified that we are a potentially responsible party. We then joined with other potentially responsible parties (Lower Willamette Group), to fund environmental studies in the Portland Harbor. Subsequently, the EPA approved a Programmatic Work Plan, Field Sampling Plan and Quality Assurance Project Plan for the Portland Harbor Remedial Investigation/Feasibility Study (RI/FS) under the plan. The draft FS is scheduled for submittal in 2012. In August 2008, we signed a cooperative agreement to participate in a phased natural resource damage assessment, with the intent to identify what, if any, other information is necessary to estimate additional liabilities to support an early restoration-based settlement of natural resource damage claims.  As of September 30, 2011, we have an accrued liability of $7.3 million for this site, which is at the low end of the range of the potential liability because no amount within the range is considered to be more likely than another, and the high end of the range cannot reasonably be estimated.

 

Central Service Center site.> In 2006, we received notice from the ODEQ that our Central Service Center in southeast Portland (Central Service Center site) was assigned a high priority for further environmental investigation. Previously there were three manufactured gas storage tanks on the premises. The ODEQ believes there could be site contamination associated with releases of condensate from stored manufactured gas as a result of historic gas handling practices. In the early 1990s, we excavated waste piles and much of the contaminated surface soils and removed accessible waste from some of the abandoned piping. In early 2008, we received notice that this site was added to the ODEQ’s list of sites where releases of hazardous substances have been confirmed and to its list where additional investigation or cleanup is necessary.  We are currently performing an environmental investigation of the property under the ODEQ’s Independent Cleanup Pathway.  As of September 30, 2011, we have a liability accrued of $0.5 million for investigation at this site. The estimate is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.

 

Front Street site.> The Front Street site was the former location of a gas manufacturing plant we operated. It is near but outside the geographic scope of the current Portland Harbor site sediment studies. The EPA directed the Lower Willamette Group to collect a series of surface and subsurface sediment samples off the river bank adjacent to where that facility was located. Based on the results of that sampling, the EPA notified the Lower Willamette Group that additional sampling would be required. As the Front Street site is upstream from the Portland Harbor site, the EPA agreed that it could be managed separately from the Portland Harbor site under ODEQ authority.  Work plans for source control investigation and a historical report were submitted to ODEQ and initial studies were completed.  In 2010, ODEQ required additional studies which are underway.  As of September 30, 2011, we have an estimated liability accrued of $0.8 million for the study of the sediments and riverbank groundwater and soils at the site.  The estimate is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.

 

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

 

Accrued Liabilities Relating to Environmental Sites.> The following table summarizes the accrued liabilities relating to environmental sites at September 30, 2011 and 2010 and December 31, 2010:

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

 

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Regulatory and Insurance Recovery for Environmental Costs.>  In May 2003, the OPUC approved our request to defer unreimbursed environmental costs associated with certain named sites, including those described above.  Beginning in 2006, the OPUC granted us additional authorization to accrue interest on deferred environmental cost balances, subject to an annual demonstration that we have maximized our insurance recovery or made substantial progress in securing insurance recovery for unrecovered environmental expenses. Through a series of extensions, the authorized cost deferral and interest accrual has been extended through January 2012.  In addition, we filed a request with the Washington Utilities and Transportation Commission (WUTC) in January 2011 to defer certain environmental costs associated with services provided to Washington customers.  We received an order from the WUTC on June 30, 2011 granting that request.  Environmental costs related to Washington are being deferred as of January 26, 2011 with cost recovery to be determined in a future proceeding.

On a cumulative basis, we have recognized a total of $107.7 million for environmental costs, including legal, investigation, monitoring and remediation costs, and $4.9 million paid and expensed prior to regulatory deferral order approval.  At September 30, 2011, we had a regulatory asset of $122.5 million, which includes $51.8 million of total paid expenditures to date, $58 million for additional environmental costs expected to be paid in the future and accrued interest of $18.1 million, partially offset by $5.4 million of environmental costs expensed in prior years.  See table below.

In December 2010, NW Natural commenced litigation against certain of its historical liability insurers in Multnomah County Circuit Court, State of Oregon, Case Number 1012-17532. The defendants include Associated Electric & Gas Insurance Services Limited, Allianz Global Risk US Insurance Company, Certain Underwriters at Lloyd's, London, certain London market insurance companies and other insurance companies.  In the suit, NW Natural alleges that the defendant insurance companies issued third party liability insurance policies to NW Natural and that the defendants have breached the terms of those policies by failing to indemnify NW Natural for liabilities arising from environmental contamination at certain sites caused or alleged to be caused by its historical operations.  NW Natural seeks damages for the losses it has incurred to date, as well as declaratory relief for additional losses it expects to incur in the future.  In addition to seeking recovery of our environmental costs from our insurers, we believe recovery of the remainder of our deferred charges, if any, is probable through the regulatory process. Our regulatory asset will be reduced by the amount of any corresponding insurance recoveries. We continue to anticipate that our overall insurance recovery effort could extend over several years, and may include settlements from time to time with one or more of the defendant insurance companies.

 

Our regulatory recovery of environmental cost deferrals may be initiated in the Oregon general rate case; however, we do not expect to have concluded our insurance recovery efforts by that point, so we are not currently able to estimate the amount of recovery expected through the implementation of new rates from the upcoming general rate proceeding.  The following table summarizes the non-current regulatory assets relating to environmental sites at September 30, 2011 and 2010 and December 31, 2010:

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

 

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Legal Proceedings

 

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

 

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

 

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

 
 

The following is management’s assessment of Northwest Natural Gas Company’s (NW Natural) financial condition, including the principal factors that affect results of operations. The disclosures contained in this report refer to our consolidated activities for the three and nine months ended September 30, 2011 and 2010. A significant portion of our business results are seasonal in nature, and as such the results of operations for the three and nine month periods are not necessarily indicative of expected fiscal year results. Therefore, this discussion should be read in conjunction with our 2010 Annual Report on Form 10-K (2010 Form 10-K) as well as our Quarterly Reports on Form 10-Q for the first and second quarters of 2011. Unless otherwise indicated, references below to “Notes” are to the Notes to Consolidated Financial Statements in this report.

 

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

 

In addition to presenting results of operations and earnings amounts in total, certain measures are expressed in cents per share. These amounts reflect factors that directly impact earnings. We believe this per share information is useful because it enables readers to better understand the impact of these factors on consolidated earnings. All references in this section to earnings per share are on the basis of diluted shares (see Part II, Item 8., Note 3, “Earnings Per Share,” in our 2010 Form 10-K).  We use such non-GAAP (i.e. non-generally accepted accounting principles) measures in analyzing our financial performance and believe that they provide useful information to our investors and creditors in evaluating our financial condition and results of operations.

 

Executive Summary

 

Highlights of consolidated results for the third quarter of 2011 as compared to the same period in 2010 include:

·	Consolidated earnings decreased $0.9 million, from a net loss of $7.4 million or 28 cents per share in the third quarter of 2010 to a net loss of $8.3 million or 31 cents per share in the third quarter of 2011;

·	Net loss from utility operations increased $0.4 million, from $9.1 million in 2010 to $9.5 million in 2011;

·	Net income from gas storage operations decreased $0.6 million, from $1.8 million in 2010 to $1.2 million in 2011, primarily reflecting current market values for contract storage and optimization services;

·	Net operating revenues (margin) increased $1.6 million or 3 percent over 2010, with utility margin down $0.2 million and gas storage margin up $1.8 million;

·	Operating expenses increased $3.8 million or 8 percent over 2010, primarily due to increases attributed to Gill Ranch’s first-year expenses for operations, maintenance, depreciation and amortization;

·	Income tax benefit increased $0.5 million in 2011 compared to 2010, primarily due to a higher pre-tax loss;

·	Cash flow from operating activities on a year-to-date basis was $191.3 million, for an increase of $76.8 million or 67 percent over the same year-to-date period in 2010;

·	Utility customers increased by approximately 5,400 over the last 12 months, for an annual growth rate of 0.8 percent compared to slightly above 1 percent a year ago.

 

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Issues, Challenges and Performance Measures

 

Economic Environment.>  Weakness in the local, national and global economies has continued to impact utility customer growth, the demand for natural gas, and the value of natural gas storage services.  Our utility’s annual customer growth rate was 0.8 percent at September 30, 2011, as compared to 0.8 percent at June 30, 2011 and 1.2 percent at September 30, 2010.  Total delivered volumes to utility customers in the third quarter of 2011 decreased 3 percent, with unemployment rates remaining around 10 percent throughout our service territories in Oregon and southwest Washington and business conditions remaining sluggish as well.  Despite these challenges, we believe our utility is well positioned to continue adding customers due to low natural gas prices, an ability to increase market share in residential and commercial sectors, ongoing programs to convert homes to natural gas, and the potential for environmental initiatives that could favor natural gas use in our region.

Managing Gas Prices and Supplies.>  Our gas acquisition strategy is regularly updated to secure sufficient supplies of natural gas to meet the needs of our utility customers and to hedge gas prices so that we can effectively manage costs, reduce price volatility and maintain a competitive advantage.  With recent developments in drilling technologies and substantial access to supplies from shale gas formations around the U.S. and in Canada, the supply outlook for North American natural gas has increased dramatically, which is contributing to lower and more stable gas prices.  

The Purchased Gas Adjustment (PGA) mechanisms in Oregon and Washington, along with our own gas price hedging strategies, gas reserves, and gas supplies in storage, enable us to reduce earnings risk exposure for the company and secure lower gas costs for our customers.  These lower gas prices, coupled with our focus on customer service and cost-effective energy efficiency programs, can help strengthen natural gas’ competitive advantage over other energy sources in key markets.  See discussion of Investments in Gas Reserves below under Strategic Opportunities.

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

Additionally, we are currently hedged at approximately 30 percent for the 2012-13 gas year and between 9 and 13 percent hedged for annual requirements over the following five gas years.  Our hedge levels are subject to change based on actual load volumes, which depend to a certain extent on weather and economic conditions.  Also, our storage levels may increase or decrease based on storage expansion or storage recall by the utility.  As for gas reserves, these levels are estimates of production, which are subject to change based on possible unforeseen events that include the impact from speed of drilling and the volume of production.

Although stable gas prices provide opportunities to manage costs for our utility customers, they also present challenges for our gas storage business by lowering the value of, and reducing the demand for, storage services, consequently affecting our ability to sign long-term customer contracts at favorable prices.

  

Environmental Costs.> We accrue material environmental loss contingencies related to our properties that require environmental investigation or remediation.  Due to numerous uncertainties surrounding the preliminary nature of investigations or the developing nature of remediation requirements, actual costs could vary significantly from our loss estimates.  As a regulated utility, we are allowed to defer certain costs pursuant to regulatory decisions.  We are authorized by the Public Utility Commission of Oregon (OPUC) and the Washington Utilities and Transportation Commission (WUTC) to defer certain environmental costs, and to seek recovery of those amounts in future rates to customers.  The Company is also seeking recovery of these costs under insurance policies.  Any amounts collected from insurance are expected to offset amounts that may otherwise be collected from customers.  Recovery of environmental costs from regulated utility rates will depend on our ability to effectively manage these costs and demonstrate that they were prudently incurred. Recovery may vary significantly from amounts currently recorded as regulatory assets, and amounts not recovered would be required to be charged to income in the period they were deemed to be unrecoverable.  See Results of Operations—Regulatory Matters—Rate Mechanisms—Regulatory Recovery for Environmental Costs below, Note 14 in this report and Note 15 in our 2010 Form 10-K.

 

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Climate Change. >See Part II, Item 7., “Executive Summary - Issues, Challenges and Performance Measures—Climate change,” in our 2010 Form 10-K for a discussion of the effect of climate change on our business.

Performance Measures.> In order to deal with the challenges affecting our businesses, we annually review and update our strategic plan to map our course over the next several years.  Our plan includes strategies for: further improving our utility gas distribution system, services and operations; growing our non-utility gas storage business; investing in natural gas infrastructure when necessary to support the needs of our region; and maintaining a leadership role within the gas utility industry by addressing long-term energy policies and pursuing business opportunities that support clean energy technologies.  We intend to measure our performance and monitor progress on relevant metrics such as: earnings per share growth; total shareholder return; return on invested capital; utility return on equity; utility customer satisfaction; utility margin; utility capital and operations and maintenance expense per customer; and non-utility earnings before interest, taxes, depreciation and amortization (non-utility EBITDA).

Strategic Opportunities

 

Business Process Improvements.> To address the current economic and competitive challenges, we continue to evaluate and implement business strategies to improve efficiencies. Our goal is to develop, integrate, consolidate and streamline operations and to support our employees and customers with new technology tools.

 

Gas Storage Operations.>  The Company has developed gas storage facilities in Oregon and California.  In California, Gill Ranch began operating during the fourth quarter of 2010 and offers storage services to the California market at market-based rates.  Gill Ranch is subject to California Public Utilities Commission (CPUC) regulation including, but not limited to, service terms and conditions, tariff regulations, and security issuances.  Gill Ranch currently is designed as a 20 Bcf facility, of which 75 percent is owned by NW Natural, but is expandable to a total estimated capacity of 40 Bcf of which NW Natural would own 50 percent.  Due to increasing supplies and price stability of natural gas in North America, and declining demand for natural gas due to current economic conditions, storage values are expected to remain low in the near term, which will likely affect the prices at which Gill Ranch is able to contract and the timing of future storage expansions. For more information, see Note 4 in this report and Part II, Item 7., “2011 Outlook—Strategic Opportunities,” in our 2010 Form 10-K.

In Oregon, we own storage facilities at Mist which serve the Pacific Northwest storage markets.  These markets also are negatively impacted by lower gas prices and lack of gas price volatility, but to a lesser extent than in California and other markets around the country because of limited availability of storage capacity in the Northwest.  In 2012, we expect to continue planning for possible expansion at our Mist gas storage facilities in anticipation of increased demand for electric generation in the Pacific Northwest.  We do not have an established timeline for the next expansion at Mist, but we believe expansion could be as early as 2014.  In the meantime, we will continue to monitor the market demand and work on preliminary design and project planning, which will ultimately require the development of storage wells, potentially a second compression station and additional pipeline gathering facilities that could enable future storage expansions.

Pipeline Diversification.> Currently, our utility and Mist gas storage operations depend on a single bi-directional interstate transmission pipeline to ship gas supplies.  Palomar, a wholly-owned subsidiary of PGH, is pursuing the development of a new gas transmission pipeline that would provide an interconnection with our utility distribution system.  PGH is owned 50 percent by NWN Energy and 50 percent by TransCanada American Investments Ltd., an indirect wholly-owned subsidiary of TransCanada Corporation.  The Palomar pipeline was originally proposed with an east and a west segment, but Palomar currently plans to design an east-only pipeline to serve our utility customers as well as the growing natural gas markets in Oregon and other parts of the Pacific Northwest. The proposed pipeline would be regulated by the Federal Energy Regulatory Commission (FERC).  

In March 2011, Palomar withdrew its original application with FERC for a natural gas pipeline in Oregon, but at the same time informed FERC that it intends to file a new application later this year or in 2012, after it has conducted an open season and obtained commercial support for the east segment pipeline, which is approximately 110 miles long.

 

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Investments in Gas Reserves. >In addition to hedging gas prices with financial derivative contracts over the next few years, we recently signed an agreement with Encana to develop physical gas supplies to supply a portion of our utility customers’ requirements over a period of about 30 years.  During the first 10 years of the agreement, we forecast the volumes of gas received under the Encana agreement to provide approximately 8 to 10 percent of the average annual requirements of our utility customers.  Under the agreement, we expect to invest approximately $45 million to $55 million per year for five years, with our total investment expected to be about $250 million.  Encana will assign to us a working interest in leases to certain sections of the Jonah gas field, located near Rock Springs, Wyoming.  These sections include both future and currently producing wells.  Operation of the wells will be governed by a joint operating agreement under which Encana will be the operator and we will pay our proportionate share of operating costs.

Upon reviewing the transaction, the OPUC determined that our Company’s costs under the agreement will be recovered on an ongoing basis through our annual PGA mechanism, including the regulatory deferral and incentive sharing process for the commodity cost of gas.  See Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment below.  Annually, a forecast will be established for the amounts related to costs and volumes expected, and any variances between forecasted and actual will be subject to our PGA incentive sharing in Oregon, up to a maximum variance of $10 million of which 10 percent (or $1 million maximum) would be recognized in current income. Variances in excess of $10 million, both negative and positive, will be deferred and passed through to customers in future rates at 100 percent.  As part of the decision by the OPUC, we agreed to file a general rate case in Oregon no later than December 31, 2011.

Consolidated Earnings and Dividends

Three months ended September 30, 2011 compared to September 30, 2010:

For the three months ended September 30, 2011, we reported a net loss of $8.3 million, or 31 cents per share, compared to a net loss of $7.4 million, or 28 cents per share, for the same period last year.

 

The primary factors contributing to the increased third quarter consolidated net loss were:

·	a $1.5 million increase in operations and maintenance expense primarily related to first-year expenses related to storage operations at Gill Ranch; and

·	a $1.4 million increase in depreciation and amortization also primarily related to first-year storage operations at Gill Ranch.

Partially offsetting the above factors were:

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

 

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Nine months ended September 30, 2011 compared to September 30, 2010:

 

Net income was $34.7 million, or $ 1.30 per share, for the nine months ended September 30, 2011, compared to $43.1 million, or $ 1.62 per share, for the same period last year.

 

The primary factors contributing to the $8.4 million decrease in net income were:

·

a $12.1 million reduction in utility net operating revenues (margin), representing a $7.4 million write-off taken in 2011 plus $5.0 million of revenues accrued in the first nine months of 2010, related to the repealed Oregon legislative rule on utility income taxes paid.  See “Results of Operations - Business Segments - Utility Operations - Regulatory Adjustment for Income Taxes Paid,” below for further explanation;

·	a $3.9 million increase in operations and maintenance expense, primarily due to a $4.4 million increase at Gill Ranch reflecting first-year operating expenses;

·	a $4.9 million increase in general taxes, primarily due to a $5.2 million refund of utility property taxes in 2010, partially offset by a $1.1 million decrease in other taxes, and a $0.8 million increase in property and other taxes at Gill Ranch, which reflect first-year operating expenses; and

·	a $4.4 million increase in depreciation and amortization expense, due to a $0.8 million increase at the utility and a $3.6 million increase at Gill Ranch.

Partially offsetting the above factors were:

·	an $8.1 million increase in utility margin attributable to an increase in residential and commercial customer use, reflecting gains from colder weather and customer growth; and

·	a $5.6 million decrease in income tax expense related to lower taxable income.

Dividends paid on our common stock were 43.5 cents per share in the third quarter of 2011, compared to 41.5 cents per share in the third quarter of 2010.  The Board of Directors declared a quarterly common stock dividend of 44.5 cents per share, payable on November 15, 2011, to shareholders of record on October 31, 2011, thereby increasing the indicated annual dividend rate by more than 2 percent from $1.74 to $1.78 per share.

Application of Critical Accounting Policies and Estimates

 

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

·	regulatory cost recovery and amortizations;

·	revenue recognition;

·	derivative instruments and hedging activities;

·	pensions and postretirement benefits;

·	income taxes; and

·	environmental contingencies.

There have been no material changes to the information provided in the 2010 Form 10-K with respect to the application of critical accounting policies and estimates (see Part II, Item 7., “Application of Critical Accounting Policies and Estimates,” in the 2010 Form 10-K), except as indicated below under Revenue Recognition and Pension Expense.  

 

 

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Revenue Recognition

Utility and non-utility revenues, which are derived primarily from the sale, transportation or storage of natural gas, are recognized upon the delivery of gas commodity or service to customers.  From 2007 through 2010, utility revenues included the recognition of a regulatory adjustment for income taxes paid pursuant to a legislative rule (commonly referred to as SB 408), which applied to certain gas and electric utilities in Oregon.  Under SB 408, we were required to automatically implement a rate refund, or a rate surcharge, to utility customers on an annual basis. The refund or surcharge amount was based on the difference between income taxes paid and income taxes authorized to be collected in customer rates. We recorded the refund, or surcharge, each quarter based on the annual amount to be recognized. On May 24, 2011 the Oregon Governor signed Senate Bill 967 (SB 967), which repealed SB 408. The new law requires utilities in Oregon, to reverse amounts accrued for the 2010 and 2011 tax years, which resulted in us recording a one-time pre-tax charge to earnings in the second quarter of 2011 in the amount of $7.4 million ($4.4 million after-tax or 17 cents per share).  See “Results of Operations—Business Segments - Utility Operations—Regulatory Adjustment for Income Taxes Paid,” below for a further discussion.

Pension Expense

Net periodic pension cost consists of service costs, interest costs, the expected returns on plan assets, and the amortization of actuarial gains and losses.  Effective January 1, 2011, we began deferring a portion of our net periodic pension cost to a regulatory account on the balance sheet pursuant to OPUC approval of pension expenses above or below the amount set in rates.  As of September 30, 2011, the cumulative amount deferred for future pension cost recovery was $4.0 million.

The funded status of our qualified pension plans is likely to be negatively affected by recent changes in market conditions, including a decline in corporate bond interest rates, which increases the value of pension liabilities, and a decline in equity market prices, which decreases the value of pension assets.  The combination of these recent market events is likely to result in higher net periodic pension costs and higher pension contributions.  For further discussion, see Note 9.

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

Results of Operations

 

Regulatory Matters

 

Regulation and Rates

 

We are subject to regulation with respect to, among other matters, rates and systems of accounts set by the OPUC, WUTC, FERC, and with respect to Gill Ranch, the CPUC.  The OPUC and WUTC also regulate our issuance of securities and the CPUC regulates the issuance of securities by Gill Ranch.  In 2011, approximately 90 percent of our utility gas volumes were delivered to, and utility operating revenues were derived from, Oregon customers, and the balance was derived from Washington customers. Future earnings and cash flows from utility operations will be determined largely by the Oregon and Washington economies in general, by the pace of growth in the residential and commercial markets in particular, and by our ability to remain price competitive, control expenses, and obtain reasonable and timely regulatory recovery for our utility gas costs, including operating and maintenance expenses and investment costs made in utility plant and other regulatory assets.  See Part II, Item 7., “Results of Operations—Regulatory Matters,” in the 2010 Form 10-K.

 
 

 

 

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Rate Mechanisms

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

 

    In October 2011, the OPUC and WUTC approved PGA rate changes effective on November 1, 2011.  The effect of these rate changes was to decrease the average monthly bills of Oregon and Washington residential customers by about 2 percent.  This was our third consecutive year of PGA rate decreases, and cumulatively our 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 or 90 percent deferral of higher or lower actual gas costs compared to estimated PGA prices, such that the impact on current earnings from the incentive sharing is either 20 percent or 10 percent of the difference between actual and estimated gas costs, respectively.  In addition to the gas cost incentive sharing mechanism, we are subject to an annual earnings test to determine if the