NOTE 9. FAIR VALUE

The carrying values of cash and cash equivalents, accounts and notes receivable, accounts payable and short-term borrowings are reasonable estimates of their fair values. Long-term debt (including current portion, but excluding capital leases), nonrecourse long-term debt and long-term debt to affiliated trusts are reported at carrying value on the Condensed Consolidated Balance Sheets.

The fair value hierarchy prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).

The three levels of the fair value hierarchy are defined as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values incorporates various factors that not only include the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit), but also the impact of Avista Corp.’s nonperformance risk on its liabilities.

The following table sets forth the carrying value and estimated fair value of the Company’s financial instruments not reported at estimated fair value on the Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011 (dollars in thousands):


	September 30, 2012				December 31, 2011
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	951,000	$	1,164,223	$	962,100	$	1,135,536
Long-term debt (Level 3)		222,000		245,995		222,000		234,226
Nonrecourse long-term debt (Level 3)		36,319		39,336		46,471		51,974
Long-term debt to affiliated trusts (Level 3)		51,547		43,686		51,547		43,810

These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market information. The Company’s publicly held long-term debt was classified as Level 2, as the fair value was determined utilizing observable inputs in non-active markets. The Company’s other long-term debt (including long-term debt to affiliated trusts and nonrecourse long-term debt) was classified as Level 3, as certain inputs used to determine the fair value are unobservable. In particular, due to the unique nature of the long-term fixed rate electric capacity contract securing the long-term debt of Spokane Energy (nonrecourse long-term debt), the estimated fair value of nonrecourse long-term debt was determined based on a discounted cash flow model using available market information.

The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011 at fair value on a recurring basis (dollars in thousands):


	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
September 30, 2012
Assets:
Energy commodity derivatives	$	—	$	76,695	$	—	$	(73,944	)	$	2,751
Level 3 energy commodity derivatives:
Power exchange agreements		—		—		366		(366	)		—
Interest rate swaps		—		5,069		—		—			5,069
Investments and funds held for clients:
Cash and cash equivalents		31,874		—		—		—			31,874
Securities available for sale:
U.S. government agency		—		63,458		—		—			63,458
Municipal		—		5,182		—		—			5,182
Corporate fixed income – financial		—		6,634		—		—			6,634
Corporate fixed income – industrial		—		4,999		—		—			4,999
Corporate fixed income – utility		—		1,068		—		—			1,068
Certificate of deposits		—		1,011		—		—			1,011
Funds held in trust account of Spokane Energy		1,600		—		—		—			1,600
Deferred compensation assets:
Fixed income securities (2)		2,148		—		—		—			2,148
Equity securities (2)		5,814		—		—		—			5,814

Total	$	41,436	$	164,116	$	366	$	(74,310	)	$	131,608

Liabilities:
Energy commodity derivatives	$	—	$	125,488	$	—	$	(83,418	)	$	42,070
Level 3 energy commodity derivatives:
Natural gas exchange agreements		—		—		3,105		—			3,105
Power exchange agreements		—		—		18,242		(366	)		17,876
Power option agreements		—		—		1,585		—			1,585
Interest rate swaps		—		3,827		—		—			3,827
Foreign currency derivatives		—		30		—		—			30

Total	$	—	$	129,345	$	22,932	$	(83,784	)	$	68,493


	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
December 31, 2011
Assets:
Energy commodity derivatives	$	—	$	80,571	$	—	$	(79,247	)	$	1,324
Level 3 energy commodity derivatives:
Natural gas exchange agreements		—		—		956		(956	)		—
Power exchange agreements		—		—		4,674		(4,674	)		—
Foreign currency derivatives		—		32		—		—			32
Investments and funds held for clients:
Cash and cash equivalents		21,957		—		—		—			21,957
Securities available for sale:
U.S. government agency		—		74,893		—		—			74,893
Municipal		—		425		—		—			425
Corporate fixed income – financial		—		11,154		—		—			11,154
Corporate fixed income – industrial		—		6,518		—		—			6,518
Corporate fixed income – utility		—		2,092		—		—			2,092
Certificate of deposits		—		1,497		—		—			1,497
Funds held in trust account of Spokane Energy		1,600		—		—		—			1,600
Deferred compensation assets:
Fixed income securities (2)		2,116		—		—		—			2,116
Equity securities (2)		5,252		—		—		—			5,252

Total	$	30,925	$	177,182	$	5,630	$	(84,877	)	$	128,860

Liabilities:
Energy commodity derivatives	$	—	$	177,743	$	—	$	(79,247	)	$	98,496
Level 3 energy commodity derivatives:
Natural gas exchange agreements		—		—		2,644		(956	)		1,688
Power exchange agreements		—		—		14,584		(4,674	)		9,910
Power option agreements		—		—		1,260		—			1,260
Interest rate swaps		—		18,895		—		—			18,895

Total	$	—	$	196,638	$	18,488	$	(84,877	)	$	130,249

(1)

The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and receivables for cash collateral held or placed with these same counterparties.

(2)	These assets are trading securities and are included in other intangibles, property and investments-net on the Condensed Consolidated Balance Sheets.

Avista Utilities enters into forward contracts to purchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. These contracts are entered into as part of Avista Utilities’ management of loads and resources and certain contracts are considered derivative instruments. The difference between the amount of derivative assets and liabilities disclosed in respective levels and the amount of derivative assets and liabilities disclosed on the Condensed Consolidated Balance Sheets is due to netting arrangements with certain counterparties. The Company uses quoted market prices and forward price curves to estimate the fair value of utility derivative commodity instruments included in Level 2. In particular, electric derivative valuations are performed using broker quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange (NYMEX) pricing for similar instruments, adjusted for basin differences, using broker quotes. Where observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2.

For securities available for sale (held at Ecova) the Company uses a nationally recognized third party to obtain fair value and reviews these prices for accuracy using a variety of market tools and analysis. The Company’s pricing vendor uses a generic model which uses standard inputs (listed in order of priority for use), including benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark securities, market bids/offers and other reference data. The pricing vendor also monitors market indicators, as well as industry and economic events. Further, the model uses Option Adjusted Spread and is a multidimensional relational model. All securities available for sale were deemed Level 2.

Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan. These funds consist of actively traded equity and bond funds with quoted prices in active markets. The balance disclosed in the table above excludes cash and cash equivalents of $0.9 million as of September 30, 2012 and $1.3 million as of December 31, 2011.

Level 3 Fair Value

For power exchange agreements, the Company compares the Level 2 brokered quotes and forward price curves described above to an internally developed forward price which is based on the average operating and maintenance (O&M) charges from four surrogate nuclear power plants around the country for the current year. Because the nuclear power plant O&M charges are only known for one year, all forward years are estimated assuming an annual escalation. In addition to the forward price being estimated using unobservable inputs, the Company also estimates the volumes of the transactions that will take place in the future based on historical average transaction volumes per delivery year (November to April). Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Generally, a change in the current year O&M charges for the surrogate plants is accompanied by a directionally similar change in O&M charges in future years. There is generally not a correlation between external market prices and the O&M charges used to develop the internal forward price.

For power commodity option agreements, the Company uses the Black-Scholes-Merton valuation model to estimate the fair value, and this model includes significant inputs not observable or corroborated in the market. These inputs include 1) the strike price (which is an internally derived price based on a combination of generation plant heat rate factors, natural gas market pricing, delivery and other O&M charges, 2) estimated delivery volumes for years beyond 2012, and 3) volatility rates for periods beyond October 2015. Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Generally, changes in overall commodity market prices and volatility rates are accompanied by directionally similar changes in the strike price and volatility assumptions used in the calculation.

For natural gas commodity exchange agreements, the Company uses the same Level 2 brokered quotes described above; however, the Company also estimates the purchase and sales volumes (within contractual limits) as well as the timing of those transactions. Changing the timing of volume estimates changes the timing of purchases and sales, impacting which brokered quote is used. Because the brokered quotes can vary significantly from period to period, the unobservable estimates of the timing and volume of transactions can have a significant impact on the calculated fair value. The Company currently estimates volumes and timing of transactions based on a most likely scenario using historical data. Historically, the timing and volume of transactions have not been highly correlated with market prices and market volatility.

The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of September 30, 2012 (dollars in thousands):


	Fair Value (Net) at September 30, 2012			Valuation Technique	Unobservable Input	Range
Power exchange agreements	$	(17,876	)	Surrogate facility pricing	O&M charges	$30.49 - $53.82/MWh (1)
Power exchange agreements				Surrogate facility pricing	Escalation factor	5% - 2012 to 2015
						3% - 2016 to 2019
					Transaction volumes	361,630 - 379,156 MWhs

Power option agreements		(1,585	)	Black-Scholes-Merton	Strike price	$41.84/MWh - 2012
				Black-Scholes-Merton		$78.21/MWh - 2019
					Delivery volumes	157,517 - 287,147 MWhs
					Volatility rates	0.20 (2)

Natural gas exchange agreements		(3,105	)	Internally derived weighted average cost of gas	Forward purchase prices	$3.53 - $3.69/mmBTU
Natural gas exchange agreements					Forward sales prices	$3.70 - $4.65/mmBTU
					Purchase volumes	135,000 - 465,000 mmBTUs
					Sales volumes	140,010 - 310,000 mmBTUs

(1)	The average O&M charges for 2012 were $40.87 per MWh.

(2)	The estimated volatility rate of 0.20 is compared to actual known volatility rates of 0.34 for 2012 to 0.24 in October 2015.

Avista Corp.’s risk management team and accounting team are responsible for developing the valuation methods described above and both groups report to the Chief Financial Officer. The valuation methods, the significant inputs, and the resulting fair values described above are reviewed on at least a quarterly basis by the risk management team and the accounting team to ensure they provide a reasonable estimate of fair value each reporting period.

The following table presents activity for net energy commodity derivative assets (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the three and nine months ended September 30, 2012 and 2011 (dollars in thousands):


	Natural Gas Exchange Agreements			Power Exchange Agreements			Power Option Agreements			Total


Three months ended September 30, 2012:
Balance as of July 1, 2012	$	(2,727	)	$	(10,438	)	$	(1,756	)	$	(14,921	)
Total gains or losses (realized/unrealized):
Included in net income		—			—			—			—
Included in other comprehensive income		—			—			—			—
Included in regulatory assets/liabilities (1)		(377	)		(7,438	)		171			(7,644	)
Purchases		—			—			—			—
Issuances		—			—			—			—
Settlements		(1	)		—			—			(1	)
Transfers to other categories		—			—			—			—

Ending balance as of September 30, 2012	$	(3,105	)	$	(17,876	)	$	(1,585	)	$	(22,566	)

Nine months ended September 30, 2012:
Balance as of January 1, 2012	$	(1,688	)	$	(9,910	)	$	(1,260	)	$	(12,858	)
Total gains or losses (realized/unrealized):
Included in net income		—			—			—			—
Included in other comprehensive income		—			—			—			—
Included in regulatory assets/liabilities (1)		(364	)		(12,216	)		(325	)		(12,905	)
Purchases		—			—			—			—
Issuances		—			—			—			—
Settlements		(1,053	)		4,250			—			3,197
Transfers to other categories		—			—			—			—

Ending balance as of September 30, 2012	$	(3,105	)	$	(17,876	)	$	(1,585	)	$	(22,566	)

Three months ended September 30, 2011:
Balance as of July 1, 2011	$	(4,404	)	$	13,058		$	(1,309	)	$	7,345
Total gains or losses (realized/unrealized):
Included in net income		—			—			—			—
Included in other comprehensive income		—			—			—			—
Included in regulatory assets/liabilities (1)		2,138			(8,962	)		(281	)		(7,105	)
Purchases		—			—			—			—
Issuances		—			—			—			—
Settlements		—			—			—			—
Transfers to other categories		—			—			—			—

Ending balance as of September 30, 2011	$	(2,266	)	$	4,096		$	(1,590	)	$	240

Nine months ended September 30, 2011:
Balance as of January 1, 2011	$	—		$	15,793		$	(2,334	)	$	13,459
Total gains or losses (realized/unrealized):
Included in net income		—			—			—			—
Included in other comprehensive income		—			—			—			—
Included in regulatory assets/liabilities (1)		2,138			(13,642	)		744			(10,760	)
Purchases		—			—			—			—
Issuances		—			—			—			—
Settlements		—			1,945			—			1,945
Transfers to other categories		(4,404	)		—			—			(4,404	)

Ending balance as of September 30, 2011	$	(2,266	)	$	4,096		$	(1,590	)	$	240

(1)

The WUTC and the IPUC issued accounting orders authorizing Avista Utilities to offset commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of settlement. The orders provide for Avista Utilities to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Condensed Consolidated Statements of Income. Realized gains or losses are recognized in the period of settlement, subject to approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in adjustments to retail rates through purchased gas cost adjustments, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rates cases.