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•	financial performance;

•	cash flows;

•	capital expenditures;

•	dividends;

•	capital structure;

•	other financial items;

•	strategic goals and objectives;

•	business environment; and

•	plans for operations.

•	weather conditions, which affect both energy demand and electric generating capability, including the impact of precipitation and temperature on hydroelectric resources, the impact of wind patterns on wind-generated power, weather-sensitive customer demand, and similar impacts on supply and demand in the wholesale energy markets;

•	our ability to obtain financing through the issuance of debt and/or equity securities, which can be affected by various factors including our credit ratings, interest rates and other capital market conditions and the global economy;

•	changes in interest rates that affect borrowing costs, our ability to effectively hedge interest rates for anticipated debt issuances, variable interest rate borrowing and the extent to which we recover interest costs through retail rates collected from customers;

•	changes in actuarial assumptions, interest rates and the actual return on plan assets for our pension and other postretirement benefit plans, which can affect future funding obligations, pension and other postretirement benefit expense and the related liabilities;

•	deterioration in the creditworthiness of our customers;

•	the outcome of legal proceedings and other contingencies;

•	economic conditions in our service areas, including the economy's effects on customer demand for utility services;

•	declining energy demand related to customer energy efficiency, conservation measures and/or increased distributed generation;

•	changes in the long-term global climate and the long-term climate within our utilities' service areas, which can affect, among other things, customer demand patterns and the volume and timing of streamflows to our hydroelectric resources;

•	state and federal regulatory decisions or related judicial decisions that affect our ability to recover costs and earn a reasonable return including, but not limited to, disallowance or delay in the recovery of capital investments, operating costs, commodity costs, interest rate swap derivatives and discretion over allowed return on investment;

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volatility and illiquidity in wholesale energy markets, including exchanges, the availability of willing buyers and sellers, changes in wholesale energy prices that can affect operating income, cash requirements to purchase electricity and natural gas, value received for wholesale sales, collateral required of us by individual counterparties and/or exchanges in wholesale energy transactions and credit risk to us from such transactions, and the market value of derivative assets and liabilities;

•	default or nonperformance on the part of any parties from whom we purchase and/or sell capacity or energy;

•	potential environmental regulations or lawsuits affecting our ability to utilize or resulting in the obsolescence of our power supply resources;

•	explosions, fires, accidents, pipeline ruptures or other incidents that may limit energy supply to our facilities or our surrounding territory, which could result in a shortage of commodities in the market that could increase the cost of replacement commodities from other sources;

•	severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, earthquakes, snow and ice storms, that can disrupt energy generation, transmission and distribution, as well as the availability and costs of materials, equipment, supplies and support services;

•	explosions, fires, accidents, mechanical breakdowns or other incidents that may impair assets and may disrupt operations of any of our generation facilities, transmission, and electric and natural gas distribution systems or other operations and may require us to purchase replacement power;

•	explosions, fires, accidents or other incidents arising from or allegedly arising from our operations that may cause wildfires, injuries to the public or property damage;

•	blackouts or disruptions of interconnected transmission systems (the regional power grid);

•	terrorist attacks, cyber attacks or other malicious acts that may disrupt or cause damage to our utility assets or to the national or regional economy in general, including any effects of terrorism, cyber attacks or vandalism that damage or disrupt information technology systems;

•	work force issues, including changes in collective bargaining unit agreements, strikes, work stoppages, the loss of key executives, availability of workers in a variety of skill areas, and our ability to recruit and retain employees;

•	increasing costs of insurance, more restrictive coverage terms and our ability to obtain insurance;

•	delays or changes in construction costs, and/or our ability to obtain required permits and materials for present or prospective facilities;

•	increasing health care costs and cost of health insurance provided to our employees and retirees;

•	third party construction of buildings, billboard signs, towers or other structures within our rights of way, or placement of fuel containers within close proximity to our transformers or other equipment, including overbuild atop natural gas distribution lines;

•	the loss of key suppliers for materials or services or other disruptions to the supply chain;

•	adverse impacts to our Alaska operations that could result from an extended outage of its hydroelectric generating resources or their inability to deliver energy, due to their lack of interconnectivity to any other electrical grids and the cost of replacement power (diesel);

•	changing river regulation or operations at hydroelectric facilities not owned by us, which could impact our hydroelectric facilities downstream;

•	change in the use, availability or abundancy of water resources and/or rights needed for operation of our hydroelectric facilities;

•	compliance with extensive federal, state and local legislation and regulation, including numerous environmental, health, safety, infrastructure protection, reliability and other laws and regulations that affect our operations and costs;

•	the ability to comply with the terms of the licenses and permits for our hydroelectric or thermal generating facilities at cost-effective levels;

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•	cyber attacks on us or our vendors or other potential lapses that result in unauthorized disclosure of private information, which could result in liabilities against us, costs to investigate, remediate and defend, and damage to our reputation;

•	disruption to or breakdowns of information systems, automated controls and other technologies that we rely on for our operations, communications and customer service;

•	changes in costs that impede our ability to effectively implement new information technology systems or to operate and maintain current production technology;

•	changes in technologies, possibly making some of the current technology we utilize obsolete or introducing new cyber security risks;

•	insufficient technology skills, which could lead to the inability to develop, modify or maintain our information systems;

•	growth or decline of our customer base and the extent to which new uses for our services may materialize or existing uses may decline, including, but not limited to, the effect of the trend toward distributed generation at customer sites;

•	the potential effects of negative publicity regarding our business practices, whether true or not, which could hurt our reputation and result in litigation or a decline in our common stock price;

•	changes in our strategic business plans, which may be affected by any or all of the foregoing, including the entry into new businesses and/or the exit from existing businesses and the extent of our business development efforts where potential future business is uncertain;

•	entering into or growth of non-regulated activities may increase earnings volatility;

•	failure to complete the proposed acquisition of the Company by Hydro One, which would negatively impact the market price of Avista Corp.'s common stock and could result in termination fees that would have a material adverse effect on our results of operations, financial condition, and cash flows;

•	changes in environmental laws, regulations, decisions and policies, including present and potential environmental remediation costs and our compliance with these matters;

•	the potential effects of initiatives, legislation or administrative rulemaking at the federal, state or local levels, including possible effects on our generating resources or restrictions on greenhouse gas emissions to mitigate concerns over global climate changes;

•	political pressures or regulatory practices that could constrain or place additional cost burdens on our distribution systems through accelerated adoption of distributed generation or electric-powered transportation or on our energy supply sources, such as campaigns to halt coal-fired power generation and opposition to other thermal generation, wind turbines or hydroelectric facilities;

•	wholesale and retail competition including alternative energy sources, growth in customer-owned power resource technologies that displace utility-supplied energy or that may be sold back to the utility, and alternative energy suppliers and delivery arrangements;

•	failure to identify changes in legislation, taxation and regulatory issues which are detrimental or beneficial to our overall business;

•	the Tax Cuts and Jobs Act and its intended and unintended consequences on financial results and future cash flows, including the potential impact to credit ratings, which may affect our ability to borrow funds or increase the cost of borrowing in the future;

•	policy and/or legislative changes in various regulated areas, including, but not limited to, environmental regulation, healthcare regulations and import/export regulations; and

•	the risk of municipalization in any of our service territories.

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•	the number of customers,

•	current rates,

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•	meter reading dates,

•	actual native load for electricity,

•	actual throughput for natural gas, and

•	electric line losses and natural gas system losses.

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(1)	Physical transactions represent commodity transactions in which Avista Corp. will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of the benefit or cost but with no physical delivery of the commodity, such as futures, swap derivatives, options, or forward contracts.

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(a)	Total service costs in the table above are recorded to the same accounts as labor expense. Labor and benefits expense is recorded to various projects based on whether the work is a capital project or an operating expense. Approximately 40 percent of all labor and benefits is capitalized to utility property and 60 percent is expensed to utility other operating expenses.

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(1)	As of September 30, 2018 and December 31, 2017, the balance outstanding was classified as short-term borrowings on the Condensed Consolidated Balance Sheet.

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(1)

In December 2010, $66.7 million and $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) due in 2032 and 2034, respectively, which had been held by Avista Corp. since 2008 and 2009, respectively, were refunded by new variable rate bond issues (Series 2010A and Series 2010B). The new bonds were not offered to the public and were purchased by Avista Corp. due to market conditions. The Company expects that at a later date, subject to market conditions, these bonds may be remarketed to unaffiliated investors. So long as Avista Corp. is the holder of these bonds, the bonds will not be reflected as an asset or a liability on Avista Corp.'s Condensed Consolidated Balance Sheets.

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(2)

In May 2018, the Company issued and sold $375.0 million of 4.35 percent first mortgage bonds due in 2048 through a public offering. The total net proceeds from the sale of the bonds were used to repay maturing long-term debt of $276.8 million, repay the outstanding balance under Avista Corp.'s $400.0 million committed line of credit and for other general corporate purposes. In connection with the issuance and sale of the first mortgage bonds, the Company cash-settled fourteen interest rate swap derivatives (notional aggregate amount of $275.0 million) and paid a net amount of $26.6 million. See Note 5 for a discussion of interest rate swap derivatives.

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(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 included in other property and investments-net and other non-current assets on the Condensed Consolidated Balance Sheets.

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(1)	All gains and losses are included in other regulatory assets and liabilities. There were no gains and losses included in either net income or other comprehensive income during any of the periods presented in the table above.

(2)	There were no purchases, issuances or transfers from other categories of any derivatives instruments during the periods presented in the table above.

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(a)	Effective January 1, 2018, the Company adopted ASU No. 2018-02. As a result of the adoption of this new standard, $1.7 million in excess tax benefits was reclassified from accumulated other comprehensive loss to retained earnings. See Note 2 for additional discussion of the adoption of this standard.

(a)	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 6 for additional details).

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•	Jenβ v. Avista Corporation., et al., No. 2:17-cv-00333 (E.D. Wash.) (filed September 25, 2017);

•	Samuel v. Avista Corporation, et al., No. 2:17-cv-00334 (E.D. Wash.) (filed September 26, 2017); and

•	Sharpenter v. Avista Corporation., et al., No. 2:17-cv-00336 (E.D. Wash.) (filed September 26, 2017)

•	Fink v. Morris, et al., No. 17203616-6 (filed September 15, 2017, amended complaint filed October 25, 2017).

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(1)	Intersegment eliminations reported as interest expense represent intercompany interest.

(2)

Other operating expenses for Avista Utilities for the three and nine months ended September 30, 2018 include acquisition costs of $1.0 million and $2.6 million, respectively, which are separately disclosed on the Condensed Consolidated Statements of Income. The three and nine months ended September 30, 2017 include acquisition costs of $6.7 million and $8.0 million, respectively, which are also separately disclosed.

(3)	Including interest expense to affiliated trusts.

(4)	The capital expenditures for the other businesses are included in other investing activities on the Condensed Consolidated Statements of Cash Flows.

(5)

Effective January 1, 2018, the Company adopted ASU No. 2017-07, which resulted in a $1.9 million and $5.7 million reclassification of the non-service cost component of pension and other postretirement benefit costs for the three and nine months ended September 30, 2017, respectively. The costs were reclassified from utility other operating expenses to other expense (income) - net on the Condensed Consolidated Statements of Income.

•	Each of the directors of Hydro One in place at the time of the agreement resigned and were replaced by nominees identified as set out below.

•	The new board of directors initially consists of 10 members. The Province nominated four directors and the remaining six nominees were identified through an ad hoc nominating committee comprised of representatives from four of the

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•	The new board of directors is responsible for appointing a new chief executive officer who will also be appointed as the eleventh member of the board of directors.

•	Hydro One has agreed to consult with the Province in respect of future matters of executive compensation.

•	Hydro One's chief financial officer was appointed as acting chief executive officer until such time as the board of directors can appoint a new chief executive officer.

(a)	FCC - The transaction was approved by the FCC on May 4, 2018; however, this approval expired on November 5, 2018. Since the acquisition was not completed by the expiration date, the Company filed an extension request with the FCC. On October 3, 2018, the FCC granted the Company's extension request through April 13, 2019.

(b)	Washington - On March 27, 2018, Avista Corp. and Hydro One filed an all-parties, all-issues settlement agreement with the WUTC recommending approval of the acquisition of the Company by Hydro One. This represents a full settlement

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(c)

Idaho - On April 13, 2018, Avista Corp. and Hydro One filed an all-issues settlement agreement with the IPUC recommending approval of the acquisition of the Company by Hydro One. The settlement agreement is subject to IPUC approval. Subsequent to the filing of the settlement agreement with the IPUC, a new intervenor, the Avista Customer Group, was allowed into the case and it is not part of the original settlement agreement.

(d)

Oregon - On May 25, 2018, Avista Corp. and Hydro One filed an all-parties, all-issues settlement agreement with the OPUC related to the Oregon merger proceeding. The settlement agreement is subject to review and approval by the OPUC. Subsequent to the filing of the settlement agreement with the OPUC, the Citizens' Utility Board requested to be removed from the settlement agreement due to the Hydro One leadership changes described above.

(e)	Alaska - On June 4, 2018, Avista Corp. and Hydro One received approval from the RCA on the proposed merger with financial and non-financial commitments. The commitments included among other items, that AEL&P's capital structure

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(f)

Montana - On July 10, 2018, Avista Corp. and Hydro One received approval from the MPSC on the proposed merger, with conditions. The MPSC did not accept, for ratemaking purposes in Montana, an accelerated 2027 depreciation schedule for Colstrip, as otherwise agreed to by the parties in Washington. On May 10, 2018, Avista and Hydro One signed a Memorandum of Agreement with the City of Colstrip, whereby Avista and Hydro One agreed that upon the completion of the transaction, $4.5 million of funding would be made available to assist the community of Colstrip in meeting its immediate and future needs.

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•	seek recovery of operating costs and capital investments, and

•	seek the opportunity to earn reasonable returns as allowed by regulators.

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(1)	This balance includes public street and highway lighting, which is considered part of retail electric revenues, and deferrals/amortizations to customers related to federal income tax law changes.

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(a)	Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative numbers are decreases in decoupling revenue in the current year and will be rebated to customers in future years.

(b)

Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative numbers are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.

•	a $1.4 million decrease in retail electric revenue due to a decrease in total MWhs sold (decreased revenues $5.2 million), partially offset by an increase in revenue per MWh (increased revenues $3.8 million).

◦

The decrease in total retail MWhs sold was the result of weather that was cooler than the prior year (which decreased electric cooling loads), partially offset by customer growth. Compared to the third quarter of 2017, residential electric use per customer decreased 7 percent and commercial use per customer decreased 4 percent. Cooling degree days in Spokane were 4 percent below normal and 29 percent below the third quarter of 2017.

◦	The increase in revenue per MWh was primarily due to general rate increases in Idaho (effective January 1, 2018) and Washington (effective May 1, 2018), as well as an increase in decoupling surcharge rates. This was partially offset by rate decreases associated with the lower corporate tax rate.

•	a $2.4 million decrease in wholesale electric revenues due to a decrease in sales prices (decreased revenues $2.7 million), partially offset by an increase in sales volumes (increased revenues $0.3 million). The fluctuation in volumes and prices was primarily the result of our optimization activities.

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a $1.7 million decrease in sales of fuel due to a decrease in sales of natural gas fuel as part of thermal generation resource optimization activities. For the third quarter of 2018, $11.6 million of these sales were made to our natural gas operations and are included as intracompany revenues and resource costs. For the third quarter of 2017, $13.6 million of these sales were made to our natural gas operations.

•	a $5.0 million increase in electric revenue due to decoupling. Weather was cooler than normal in the third quarter of 2018, which resulted in decoupling deferral surcharges related to the current year.

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(1)	This balance includes interruptible and industrial revenues, which are considered part of retail natural gas revenues, and deferrals/amortizations to customers related to federal income tax law changes.

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(a)	Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative numbers are decreases in decoupling revenue in the current year and will be rebated to customers in future years.

(b)

Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative numbers are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.

•	a $1.6 million decrease in natural gas retail revenues due to lower retail rates (decreased revenues $2.1 million), partially offset by a slight increase in volumes (increased revenues $0.5 million).

◦	We sold slightly more retail natural gas in the third quarter of 2018 as compared to the third quarter of 2017. Retail natural gas loads and changes in customer usage during the third quarter are typically not significant to the full year.

◦	Lower retail rates were due to PGAs and rate decreases associated with the lower corporate tax rate, partially offset by general rate increases in Oregon (effective October 1 and November 1, 2017), Idaho (effective January 1, 2018) and Washington (effective May 1, 2018), as well as an increase in decoupling surcharge rates.

•

an $8.5 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $2.9 million) and a decrease in volumes (decreased revenues $5.6 million). In the third quarter of 2018, $12.4 million of these sales were made to our electric generation operations and are included as intracompany revenues and resource costs. In the third quarter of 2017, $17.0 million of these sales were made to our electric generation operations. Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.

•	a $0.4 million increase in natural gas revenue due to decoupling.

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•	a $7.6 million increase in purchased power due to an increase in the volume of power purchases (increased costs $1.8 million) and an increase in wholesale prices (increased costs $5.8 million). The fluctuation in volumes and prices was primarily the result of our optimization activities during the quarter.

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•	a $7.2 million decrease in fuel for generation primarily due to a decrease in thermal generation (due to an outage at Colstrip), as well as a decrease in natural gas fuel prices.

•	a $4.3 million decrease in other fuel costs. This represents fuel and the related derivative instruments that were purchased for generation but were later sold when conditions indicated that it was more economical to sell the fuel as part of the resource optimization process. When the fuel or related derivative instruments are sold, that revenue is included in sales of fuel.

•	a $0.4 million decrease from net amortizations and deferrals of power costs.

•	a $2.1 million net increase from other regulatory amortizations and other electric resource costs.

•	a $8.9 million decrease in natural gas purchased due to a decrease in the price of natural gas (decreased costs $3.9 million) and a decrease in total therms purchased (decreased costs $5.0 million).

•	a $1.5 million decrease from net amortizations and deferrals of natural gas costs.

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(1)	This balance includes public street and highway lighting, which is considered part of retail electric revenues, and deferrals/amortizations to customers related to federal income tax law changes.

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(a)	Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative numbers are decreases in decoupling revenue in the current year and will be rebated to customers in future years.

(b)

Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative numbers are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.

•	a $2.7 million decrease in retail electric revenue due to a decrease in total MWhs sold (decreased revenues $21.2 million), partially offset by an increase in revenue per MWh (increased revenues $18.5 million).

◦

The decrease in total retail MWhs sold was the result of weather that was warmer than the prior year during the heating season (which decreased electric heating loads) and cooler than the prior year during the cooling season (which decreased electric cooling loads), partially offset by customer growth. Compared to the nine months ended September 30, 2017, residential electric use per customer decreased 8 percent and commercial use per customer decreased 3 percent. Heating degree days in Spokane were 8 percent below normal and 12 percent below the first nine months of 2017. Year-to-date 2018 cooling degree days were 5 percent below normal and 30 percent below the prior year.

◦	The increase in revenue per MWh was primarily due to general rate increases in Idaho (effective January 1, 2018) and Washington (effective May 1, 2018), as well as an increase in decoupling surcharge rates. This was partially offset by rate decreases associated with the lower corporate tax rate.

•	a $16.4 million increase in wholesale electric revenues due to an increase in sales volumes (increased revenues $25.6 million), partially offset by a decrease in sales prices (decreased revenues $9.2 million). The fluctuation in volumes and prices was primarily the result of our optimization activities.

•

a $3.8 million decrease in sales of fuel due to a decrease in sales of natural gas fuel as part of thermal generation resource optimization activities. For the nine months ended September 30, 2018, $20.5 million of these sales were made to our natural gas operations and are included as intracompany revenues and resource costs. For the nine months ended September 30, 2017, $26.9 million of these sales were made to our natural gas operations.

•	a $9.6 million increase in electric revenue due to decoupling. Weather was warmer than normal during the heating season and cooler than normal during the cooling season in 2018, which resulted in decoupling surcharges for the first nine months of 2018.

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an $11.1 million decrease in electric revenue due to net deferrals for refunds to customers related to the federal income tax law changes that lowered the corporate tax rate from 35 percent to 21 percent. As our customers' rates had the 35 percent corporate tax rate built in from prior general rate cases through May 1, 2018 in Washington and June 1, 2018 in Idaho, we deferred the impact of the change beginning January 1, 2018. Effective May 1, 2018 in Washington and June 1, 2018 in Idaho, base rates reflect the lower 21 percent corporate tax.

•	a $3.1 million decrease in transmission revenue (included in other revenue in the graph above).

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(1)	This balance includes interruptible and industrial revenues, which are considered part of retail natural gas revenues, and deferrals/amortizations to customers related to federal income tax law changes.

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(a)	Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative numbers are decreases in decoupling revenue in the current year and will be rebated to customers in future years.

(b)

Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative numbers are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.

•	a $25.3 million decrease in natural gas retail revenues due to a decrease in volumes (decreased revenues $15.2 million) and lower retail rates (decreased revenues $10.1 million).

◦

We sold less retail natural gas in the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017 due to warmer weather during the heating season, partially offset by customer growth. Compared to the first nine months of 2017, residential natural gas use per customer decreased 9 percent and commercial use per customer decreased 8 percent. Heating degree days in Spokane were 8 percent below normal and 12 percent below the first nine months of 2017. Heating degree days in Medford were 5 percent below normal, and 4 percent below the first nine months of 2017.

◦	Lower retail rates were due to PGAs and rate decreases associated with the lower corporate tax rate, partially offset by general rate increases in Washington, Oregon and Idaho, as well as an increase in decoupling surcharge rates.

•

a $14.8 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $10.6 million) and a decrease in volumes (decreased revenues $4.2 million). In the nine months ended September 30, 2018, $30.0 million of these sales were made to our electric generation operations and are included as intracompany revenues and resource costs. In the nine months ended September 30, 2017, $36.5 million of these sales were made to our electric generation operations. Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.

•	a $4.2 million increase in natural gas revenue due to decoupling. Weather was warmer than normal in the first nine months of 2018, which resulted in decoupling surcharges.

•

a $4.9 million decrease in natural gas revenue due to net deferrals for refunds to customers related to the federal income tax law changes that lowered the corporate tax rate from 35 percent to 21 percent. As our customers' rates had the 35 percent corporate tax rate built in from prior general rate cases through May 1, 2018 in Washington and June 1, 2018 in Idaho, we deferred the impact of the change beginning January 1, 2018. Effective May 1, 2018 in Washington and June 1, 2018 in Idaho, base rates reflect the lower 21 percent corporate tax. Base rates in Oregon continue to have the 35 percent corporate tax rate built in and we are deferring the impact.

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•	a $12.5 million increase in purchased power due to an increase in the volume of power purchases (increased costs $13.8 million), partially offset by a decrease in wholesale prices (decreased costs $1.3 million). The fluctuation in volumes and prices was primarily the result of our optimization activities during the period.

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•	a $1.8 million decrease in fuel for generation primarily due to a decrease in natural gas fuel prices and an outage at Colstrip in the third quarter, partially offset by an overall increase in thermal generation.

•	a $9.5 million decrease in other fuel costs.

•	a $4.7 million increase from amortizations and deferrals of power costs. This change was primarily the result of lower net power supply costs.

•	a $6.4 million increase in other regulatory amortizations and other electric resource costs.

•	a $29.9 million decrease in natural gas purchased due to a decrease in the price of natural gas (decreased costs $21.4 million) and a decrease in total therms purchased (decreased costs $8.5 million). Total therms purchased decreased due to a decrease in retail sales, partially offset by an increase in wholesale sales.

•	a $5.8 million decrease from amortizations and deferrals of natural gas costs.

•	a $2.9 million decrease in other regulatory amortizations.

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•	net proceeds from the issuance of long-term debt of $374.6 million, which was used to repay maturing long-term debt of $276.8 million and repay the outstanding balance under our committed line of credit during 2018. This was compared to an increase in short-term borrowings of $75.0 million in 2017, and

•	cash dividends paid to Avista Corp. shareholders increased to $73.6 million (or $1.1175 per share) for the nine months ended September 30, 2018 from $69.2 million (or $1.0725 per share) for the nine months ended September 30, 2017.

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(1)	Physical transactions represent commodity transactions where we will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of the benefit or cost but with no physical delivery of the commodity, such as futures, swap derivatives, options, or forward contracts.

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•	We will need no additional natural gas transportation resources during the 20-year planning horizon in Washington, Idaho, or Oregon.

•	Due to expected carbon legislation at the state levels through a cap and trade mechanism (Oregon) or a fee mechanism (Washington), we expect natural gas prices to include a carbon price adder in Oregon and Washington, but not in Idaho.

•	North American supplies of natural gas will continue to be abundant led by shale gas development.

•	Customer growth in our service territory will increase slightly compared to the 2016 IRP. There will be increasing interest from customers to utilize natural gas for heating due to its abundant supply and consequent low cost.

•	We anticipate that any increased demand for natural gas regionally will primarily come from power generation as natural gas is increasingly being used to back up solar and wind technology, as well as replace retired coal plants. There is also potential for increased usage in other markets, such as LNG exports or exports to Mexico.

•	Slightly higher customer growth will continue to be offset by lower use per customer and an increased amount of demand side management (DSM). The combination of low priced natural gas in addition to carbon fees or other programs has led to a higher potential for DSM measures as compared to the previous three IRP’s.

•

The availability of natural gas in North America will continue to change global LNG dynamics. Existing and new LNG facilities will look to export low cost North American natural gas to the higher priced foreign markets. This could alter the price of natural gas and/or transportation in U.S. markets, constrain existing pipeline networks, stimulate development of new pipeline resources and change flows of natural gas across North America.

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(a)	Not applicable

(b)	Not applicable

(c)	Not applicable

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