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 and material 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, 2014 and December 31, 2013 (dollars in thousands):



	September 30, 2014				December 31, 2013
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	951,000	$	1,100,345	$	951,000	$	1,054,512
Long-term debt (Level 3)	417,000		431,758		342,000		329,581
Snettisham capital lease obligation (Level 3)	70,481		77,835		—		—
Nonrecourse long-term debt (Level 3)	5,666		5,756		17,838		18,636
Long-term debt to affiliated trusts (Level 3)	51,547		38,583		51,547		37,114

These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market information. 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) and the unique nature of the Snettisham capital lease obligation, the estimated fair value of these items 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, 2014 and December 31, 2013 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, 2014
Assets:
Energy commodity derivatives	$	—	$	52,691	$	—	$	(47,664	)	$	5,027
Level 3 energy commodity derivatives:
Natural gas exchange agreement	—		—		58		(58		)	—
Power exchange agreement	—		—		800		(800		)	—
Interest rate swaps	—		13,300		—		(5,047		)	8,253
Funds held in trust account of Spokane Energy	1,600		—		—		—			1,600
Deferred compensation assets:
Fixed income securities (2)	1,831		—		—		—			1,831
Equity securities (2)	6,096		—		—		—			6,096
Total	$	9,527	$	65,991	$	858	$	(53,569	)	$	22,807
Liabilities:
Energy commodity derivatives	$	—	$	52,881	$	—	$	(48,599	)	$	4,282
Level 3 energy commodity derivatives:
Natural gas exchange agreement	—		—		1,529		(58		)	1,471
Power exchange agreement	—		—		13,654		(800		)	12,854
Power option agreement	—		—		362		—			362
Foreign currency derivatives	—		280		—		—			280
Interest rate swaps	—		34,485		—		(17,777		)	16,708
Total	$	—	$	87,646	$	15,545	$	(67,234	)	$	35,957



	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
December 31, 2013
Assets:
Energy commodity derivatives	$	—	$	55,243	$	—	$	(51,367	)	$	3,876
Level 3 energy commodity derivatives:
Power exchange agreement	—		—		339		(339		)	—
Foreign currency derivatives	—		7		—		(6		)	1
Interest rate swaps	—		33,543		—		—			33,543
Investments and funds held for clients:
Money market funds	11,180		—		—		—			11,180
Securities available for sale:
U.S. government agency	—		61,078		—		—			61,078
Municipal	—		3,518		—		—			3,518
Corporate fixed income – financial	—		3,000		—		—			3,000
Corporate fixed income – industrial	—		765		—		—			765
Certificate of deposits	—		1,000		—		—			1,000
Funds held in trust account of Spokane Energy	1,600		—		—		—			1,600
Deferred compensation assets:
Fixed income securities (2)	1,960		—		—		—			1,960
Equity securities (2)	6,470		—		—		—			6,470
Total	$	21,210	$	158,154	$	339	$	(51,712	)	$	127,991
Liabilities:
Energy commodity derivatives	$	—	$	72,895	$	—	$	(60,099	)	$	12,796
Level 3 energy commodity derivatives:
Natural gas exchange agreement	—		—		1,219		—			1,219
Power exchange agreement	—		—		14,780		(339		)	14,441
Power option agreement	—		—		775		—			775
Foreign currency derivatives	—		6		—		(6		)	—
Total	$	—	$	72,901	$	16,774	$	(60,444	)	$	29,231


(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 property and investments-net on the Condensed Consolidated Balance Sheets.

Avista Corp. 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 Corp.’s 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.

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 $1.0 million as of September 30, 2014 and $0.7 million as of December 31, 2013.

Level 3 Fair Value

For the power exchange agreement, 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 the power commodity option agreement, 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, and 3) volatility rates for periods beyond October 2017. 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 the natural gas commodity exchange agreement, 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, 2014 (dollars in thousands):



	Fair Value (Net) at
	September 30, 2014			Valuation Technique	Unobservable Input	Range
Power exchange agreement	$	(12,854	)	Surrogate facility pricing	O&M charges	$30.66-$55.56/MWh (1)
					Escalation factor	3% - 2014 to 2019
					Transaction volumes	310,103 - 397,116 MWhs
Power option agreement	(362		)	Black-Scholes- Merton	Strike price	$56.20/MWh - 2015
					Strike price	$67.81/MWh - 2019
					Delivery volumes	32,472 - 287,147 MWhs
					Volatility rates	0.20 (2)
Natural gas exchange agreement	(1,471		)	Internally derived weighted average cost of gas	Forward purchase prices	$3.43 - $3.68/mmBTU
					Forward purchase prices	$3.43 - $3.68/mmBTU
					Forward sales prices	$4.19 - $4.72/mmBTU
					Purchase volumes	280,000 - 310,000 mmBTUs
					Sales volumes	279,990 - 310,000 mmBTUs

(1) The average O&M charges for the delivery year beginning in November 2014 were $42.90 per MWh. For ratemaking purposes the average O&M charges to be included for recovery in retail rates vary slightly between regulatory jurisdictions. The average O&M charges for the delivery year beginning in 2014 were $43.11 for Washington and $42.90 for Idaho.

(2) The estimated volatility rate of 0.20 is compared to actual quoted volatility rates of 0.30 for 2014 to 0.19 in October 2017.

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, significant inputs and 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 energy commodity derivative assets (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the three and nine months ended September 30 (dollars in thousands):



	Natural Gas Exchange Agreement			Power Exchange Agreement			Power Option Agreement			Total
Three months ended September 30, 2014:
Balance as of July 1, 2014	$	(2,183	)	$	(7,919	)	$	(605	)	$	(10,707	)
Total gains or losses (realized/unrealized):
Included in net income	—			—			—			—
Included in other comprehensive income	—			—			—			—
Included in regulatory assets/liabilities (1)	712			(4,935		)	243			(3,980		)
Purchases	—			—			—			—
Issuance	—			—			—			—
Settlements	—			—			—			—
Transfers to/from other categories	—			—			—			—
Ending balance as of September 30, 2014	$	(1,471	)	$	(12,854	)	$	(362	)	$	(14,687	)
Three months ended September 30, 2013:
Balance as of July 1, 2013	$	(1,022	)	$	(22,179	)	$	(596	)	$	(23,797	)
Total gains or losses (realized/unrealized):
Included in net income	—			—			—			—
Included in other comprehensive income	—			—			—			—
Included in regulatory assets/liabilities (1)	(170		)	6,135			(165		)	5,800
Purchases	—			—			—			—
Issuance	—			—			—			—
Settlements	(1		)	—			—			(1		)
Transfers to/from other categories	—			—			—			—
Ending balance as of September 30, 2013	$	(1,193	)	$	(16,044	)	$	(761	)	$	(17,998	)
Nine months ended September 30, 2014:
Balance as of January 1, 2014	$	(1,219	)	$	(14,441	)	$	(775	)	$	(16,435	)
Total gains or losses (realized/unrealized):
Included in net income	—			—			—			—
Included in other comprehensive income	—			—			—			—
Included in regulatory assets/liabilities (1)	2,796			2,120			413			5,329
Purchases	—			—			—			—
Issuance	—			—			—			—
Settlements	(3,048		)	(533		)	—			(3,581		)
Transfers to/from other categories	—			—			—			—
Ending balance as of September 30, 2014	$	(1,471	)	$	(12,854	)	$	(362	)	$	(14,687	)



	Natural Gas Exchange Agreement			Power Exchange Agreement			Power Option Agreement			Total
Nine months ended September 30, 2013:
Balance as of January 1, 2013	$	(2,379	)	$	(18,692	)	$	(1,480	)	$	(22,551	)
Total gains or losses (realized/unrealized):
Included in net income	—			—			—			—
Included in other comprehensive income	—			—			—			—
Included in regulatory assets/liabilities (1)	1,637			(113		)	719			2,243
Purchases	—			—			—			—
Issuance	—			—			—			—
Settlements	(451		)	2,761			—			2,310
Transfers from other categories	—			—			—			—
Ending balance as of September 30, 2013	$	(1,193	)	$	(16,044	)	$	(761	)	$	(17,998	)

(1)

The UTC and the IPUC issued accounting orders authorizing Avista Corp. to offset commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment defers the recognition of mark-to-market gains and losses on energy commodity transactions until the period of delivery. The orders provide for Avista Corp. 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 delivery, 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.