SPOKANE, WA -- (Marketwired) -- 08/06/14 -- Avista Corp.(NYSE: AVA) today reported net income attributable to Avista Corp. shareholders of $100.9 million, or $1.67 per diluted share for the second quarter of 2014, compared to $25.7 million, or $0.43 per diluted share for the second quarter of 2013. For the six months ended June 30, 2014, net income attributable to Avista Corp. shareholders was $149.4 million, or $2.48 per diluted share, compared to $68.0 million, or $1.13 per diluted share for the six months ended June 30, 2013.

"We've had an eventful 2014 thus far, with the completion of our sale of Ecova on June 30 and the close of our acquisition of Alaska Energy and Resources Company (AERC) on July 1. Both of these transactions reflect our strategy to deliver long-term value to the customers, communities and investors we serve," said Avista Chairman, President and Chief Executive Officer Scott Morris.

"We are excited about AERC becoming a part of our company. This transaction allows us to immediately expand our energy customer base, as well as look at other market opportunities in Alaska.

"Utility earnings were higher than expected for the second quarter due to lower operating expenses, but this was partially offset by mild weather. Year-to-date utility earnings were above our expectations as a result of lower operating expenses throughout the year. We also had colder than normal weather in the first quarter, which was partially offset by milder weather in the second quarter. Our quarterly and year-to-date results also benefited from stronger hydroelectric generation. As compared to the prior year, our results improved as the result of general rate increases in each of our jurisdictions.

"On the sale of Ecova, we recognized a net gain of about $68 million during the second quarter, and we expect total net proceeds of approximately $133 million.

"At our other businesses, the settlement in the California power markets litigation was approved by the Federal Energy Regulatory Commission, and we received settlement proceeds that we recognized as earnings during the second quarter. We contributed a portion of these proceeds to the Avista Foundation to help sustain and support the communities we serve," Morris said.

Summary Results: Avista Corp.'s results for the second quarter of 2014 and the six months ended (YTD) June 30, 2014, as compared to the respective periods in 2013 are presented in the table below:

Earnings at Avista Utilities for the quarter and year-to-date increased primarily due to the implementation of general rate increases in all our jurisdictions. Our utility earnings also benefited from colder weather during the first quarter, which was partially offset in the second quarter by milder weather and expected increases in other operating expenses, depreciation and amortization and taxes other than income taxes. Results for 2013 also included the net benefit from the settlement with the Bonneville Power Administration (Bonneville).

Earnings at Ecova increased for the quarter and year-to-date due to our sale of Ecova. We included the net gain from the sale of $68.1 million in the results for Ecova. Exclusive of the net gain, net income from Ecova's regular operations was flat compared to 2013.

Earnings at our other businesses increased for the quarter and year-to-date as a result of the settlement of the California power markets litigation, partially offset by a contribution of a portion of the proceeds to the Avista Foundation, a charitable organization funded by Avista Corp. We also had positive earnings at METALfx, offset by increased costs associated with exploring strategic opportunities.

Avista Utilities

Utility Gross Margin -- 2014 compared to 2013

On a quarterly basis, operating revenues (exclusive of intra-company revenues between electric and natural gas of $28.4 million in the second quarter of 2014 and $31.9 million in the second quarter of 2013) increased $5.4 million, and resource costs increased $2.4 million, which resulted in an increase of $3.0 million in gross margin. The gross margin on electric sales increased $2.2 million, and the gross margin on natural gas sales increased $0.8 million. The increase in electric gross margin was primarily due to general rate increases in Washington and Idaho and lower power supply costs (due in part to increased hydroelectric generation), partially offset by the net benefit from the settlement with Bonneville in the prior year and weather that was milder than normal and milder than the prior year, which decreased heating and cooling loads. For the second quarter of 2014, we recognized a pre-tax benefit of $3.6 million under the ERM in Washington compared to a pre-tax benefit of $1.1 million for the second quarter of 2013. The increase in natural gas gross margin was due to general rate increases, partially offset by milder weather, which decreased heating loads.

On a year-to-date basis, operating revenues (exclusive of intra-company revenues between electric and natural gas of $63.3 million in the first half of 2014 and $73.3 million in the first half of 2013) increased $11.4 million and resource costs decreased $6.7 million, which resulted in an increase of $18.1 million in gross margin. The gross margin on electric sales increased $12.1 million and the gross margin on natural gas sales increased $6.0 million. The increase in electric gross margin was primarily due to general rate increases in Washington and Idaho, and lower power supply costs (due in part to increased hydroelectric generation), as well as colder weather in the first quarter. For the six months ended June 30, 2014, we recognized a pre-tax benefit of $4.9 million under the ERM in Washington compared to a pre-tax benefit of $4.1 million for the six months ended June 30, 2013. Electric gross margin for 2013 included the net benefit from the settlement with Bonneville. The increase in natural gas gross margin was due to general rate increases. A colder than average and colder than prior year first quarter was partially offset by milder weather in the second quarter as year-to-date use per customer did not change significantly.

Electric Revenues -- 2014 compared to 2013

Electric revenues decreased $25.8 million for the first half of 2014, as compared to the first half of 2013. Retail electric revenues increased by $11.0 million, wholesale electric revenues decreased by $4.1 million, sales of fuel decreased by $19.1 million and other electric revenues decreased by $10.5 million. We also recorded a provision for earnings sharing for our Idaho customers of $3.1 million for the six months ended June 30, 2014, with $1.2 million representing our estimate for the six months ended June 30, 2014, and $1.9 million representing an adjustment of our 2013 estimate.

Retail electric revenues increased $11.0 million due to an $18.6 million increase from higher retail rates. This was partially offset by a $7.6 million decrease resulting from lower industrial volumes, partially offset by higher residential volumes. The increase in revenue per MWh was due to general rate increases and a change in revenue mix, with a greater percentage of retail revenue from residential and commercial customers.

The increase in total MWhs sold to residential customers was primarily the result of colder weather in the first quarter of this year, mostly offset by milder weather in the second quarter. Compared to the six months ended June 30, 2013, residential electric use per customer increased 1 percent. Heating degree days at Spokane were 2 percent below historical average and were 0.4 percent above the six months ended June 30, 2013. Cooling degree days at Spokane (primarily for June) were 69 percent below average and 77 percent below the six months ended June 30, 2013. There has historically not been a significant amount of cooling degree days during the first six months of each year.

The decrease in total MWhs sold to industrial customers was primarily due to a contract renewal at a lower volume for one of our largest industrial customers which became effective July 1, 2013. This did not have an impact on our gross margin or net income.

Wholesale electric revenues decreased $4.1 million due to a $14.3 million decrease from lower sales volumes, partially offset by a $10.2 million increase from higher sales prices. The fluctuation in volumes and prices was primarily the result of our optimization activities during the quarter.

The revenues from sales of fuel decreased $19.1 million due to a decrease in sales of natural gas fuel as part of thermal generation resource optimization activities.

Other electric revenues decreased $10.5 million primarily due to the receipt of $11.7 million of revenue from the Bonneville Power Administration in the first quarter of 2013 for past use of our electric transmission system.

The 2013 Idaho general rate case settlement includes an after-the-fact earnings test for 2013 and 2014, such that if Avista Corp., on a consolidated basis for electric and natural gas operations in Idaho, earns more than a 9.8 percent return on equity, we will share with customers 50 percent of any earnings above the 9.8 percent. In the six months ended June 30, 2014, we estimated a provision for earnings sharing of $3.1 million for Idaho electric customers with $1.2 million representing our estimate for the six months ended June 30, 2014, and $1.9 million representing an adjustment of our 2013 estimate.

Natural Gas Revenues -- 2014 compared to 2013

Natural gas revenues increased $27.2 million for the first half of 2014, as compared to the first half of 2013, primarily due to an increase in retail natural gas revenues and wholesale natural gas revenues.

Retail natural gas revenues increased $13.1 million due to a $10.6 million increase from higher retail rates and a $2.5 million increase from higher volumes. Higher retail rates were due to purchased gas adjustments and general rate cases. We sold more retail natural gas in the first half of 2014 as compared to the first half of 2013 primarily due to customer growth and colder weather in the first quarter, partially offset by milder weather in the second quarter. Compared to the six months ended June 30, 2013, residential natural gas use per customer decreased 0.3 percent and commercial use per customer increased 2 percent. Heating degree days at Spokane for the first half of 2014 were 2 percent below historical average and 0.4 percent above the first half of 2013. Heating degree days at Medford were 22 percent below historical average for the six months ended June 30, 2014, and 16 percent below the six months ended June 30, 2013.

Wholesale natural gas revenues increased $14.3 million due to a $24.6 million increase related to higher prices, partially offset by a $10.3 million decrease from lower volumes. In addition, transportation revenues increased $0.2 million, other gas revenues decreased $0.3 million and we recorded a provision for Idaho earnings sharing of $0.1 million representing our estimate for the six months ended June 30, 2014.

Utility Operating Expenses -- 2014 compared to 2013

Utility resource costs decreased $6.7 million, after elimination of intracompany resource costs of $63.3 million for the first half of 2014 and $73.3 million for the first half of 2013. Including intracompany resource costs, electric resource costs decreased $37.9 million and natural gas resource costs increased $21.1 million. The decrease in electric resource costs was primarily due to a decrease in purchased power, fuel for generation and other fuel costs (representing fuel that was purchased for generation but was later sold when conditions indicated that it was not economical to use the fuel for generation as part of the resource optimization process). The decrease in electric resource costs was also partially due to increased hydroelectric generation in the current year. The increase in natural gas resource costs was primarily due to an increase in natural gas purchased, partially offset by a decrease in natural gas cost amortizations.

Utility other operating expenses increased $3.5 million as the result of increased generation, transmission and distribution operating and maintenance expenses and increased outside services, and dues and donations. There were also transaction fees associated with the AERC acquisition of $0.7 million in the first half of 2014. These were partially offset by a decrease in pension and other post-retirement benefits expense.

Utility depreciation and amortization increased $4.9 million driven by additions to utility plant. Utility taxes other than income taxes increased $2.1 million primarily due to increased state excise, municipal and property related taxes.

Ecova -- Discontinued Operations

Ecova's net income was $70.8 million for the first half of 2014 compared to $2.7 million for the first half of 2013. The increase was primarily attributable to the net gain recognized on the sale of Ecova of $68.1 million. Excluding the net gain, net income from Ecova's regular operations was flat compared to 2013.

Other Businesses

The net income from these operations was $3.9 million for the first half of 2014 compared to a net loss of $1.5 million for the first half of 2013. The net income for the first half of 2014 was primarily the result of the settlement of the California power markets litigation, where Avista Energy received settlement proceeds and recognized an increase in pre-tax earnings of $15 million. This was partially offset by a pre-tax contribution of $6.4 million of the proceeds to the Avista Foundation.

METALfx had net income of $0.3 million for the first half of 2014, compared to net income of $0.5 million for the first half of 2013.

Lastly, we incurred $1.1 million (net of tax) of corporate costs, including costs associated with exploring strategic opportunities.

Liquidity and Capital Resources

During the second quarter of 2014, we received cash proceeds of $205.4 million from the Ecova sale, and we expect to receive additional proceeds of $13.6 million from the escrow accounts related to the sale ($1.1 million in 2014 and $12.5 million in 2015). We also received $15 million from the California power markets litigation settlement. We used the above funds to pay off the outstanding balance owed on our committed line of credit on July 1, 2014, of $151.5 million, we contributed $6.4 million to the Avista Foundation, and we initiated a common stock share repurchase program for up to 4 million shares during the second half of 2014 (discussed below). We expect to borrow funds on our committed line of credit later during the third quarter of 2014, because we expect to make tax payments of $85.8 million associated with the sale of Ecova, and we will need additional funds to complete our stock repurchase program.

We have a $400 million committed line of credit with various financial institutions. In April 2014, we amended this committed line of credit agreement to extend the expiration date to April 2019. As of June 30, 2014, there were $151.5 million of cash borrowings and $21.9 million in letters of credit outstanding, leaving $226.6 million of available liquidity under this line of credit. However, as discussed above, on July 1, 2014, we paid off the outstanding cash borrowing balance of this committed line of credit agreement.

AEL&P has a committed line of credit in the amount of $14.5 million with an expiration date of June 2015. As of June 30, 2014, there were no borrowings outstanding under this committed line of credit.

We expect to issue approximately $165 million of long-term debt during 2014, including about $90 million of debt issuances combined between AERC and AEL&P associated with rebalancing the consolidated capital structure at AERC. In July 2014, AEL&P entered into a bond purchase agreement with two institutional investors in the private placement market for the purpose of issuing $75 million of 4.54 percent first mortgage bonds due in 2044. The bonds are expected to be issued in September 2014. In addition to the first mortgage bonds, we expect to issue about $15 million in term loans at AERC during the third quarter of 2014. We acquired AERC primarily by issuing Avista Corp. common stock; therefore the proceeds from the new AERC and AEL&P debt will be used to repay approximately $38 million of existing AEL&P debt and the remainder of the proceeds is expected to be paid as a cash dividend up to Avista Corp. We expect to also issue long-term debt of $75 million at Avista Corp. which will be used primarily to fund Avista Utilities' capital expenditures and other contractual commitments.

In the first half of 2014, we issued $2 million (net of issuance costs) of common stock under the dividend reinvestment and direct stock purchase plan, and employee plans. On July 1, 2014, we issued 4.5 million shares of common stock at a total fair value of approximately $150 million related to closing the AERC transaction. We do not expect to issue any additional shares for 2014, other than those under the dividend reinvestment and direct stock purchase plan, and employee plans.

On July 7, 2014, we commenced a stock repurchase program to repurchase up to 4 million shares of our outstanding common stock. The program will not continue past December 31, 2014, and we have the option to terminate the program before that date. Through July 31, 2014, we have repurchased 292,100 shares at a total cost of $9.4 million and an average cost of $32.28 per share.

Avista Utilities' capital expenditures were $136.5 million for the first half of 2014. We expect Avista Utilities' capital expenditures to be about $355 million for 2014, $355 million in 2015 and $350 million in 2016. The $20 million increase in estimated Avista Utilities' capital expenditures for 2014 relates to the replacement of our customer information system and work management systems. We expect to spend approximately $6 million for 2014 and $15 million for each of 2015 and 2016 related to capital expenditures at AEL&P.

2014 Earnings Guidance and Outlook

Based on the year-to-date results of Avista Utilities, increased expectations for Avista Utilities for the remainder of 2014 and the significant transactions that have occurred to date, we are raising our 2014 earnings guidance to include the impact of all these items. Our consolidated earnings guidance for 2014 is a range of $3.00 to $3.20 per diluted share. We expect to be near the upper end of this range, including the impacts of the ERM. The updated guidance includes the dilutive impact from issuing 4.5 million shares of common stock on July 1, 2014 for the AERC acquisition, as well as our current expectation to repurchase approximately 4 million shares of common stock through our repurchase program by Dec. 31, 2014. However, we can choose to terminate the repurchase program before Dec. 31, 2014, and there is no assurance that the goal of repurchasing 4 million shares will be achieved. Our consolidated and segment earnings guidance ranges encompass expected variability related to the timing of share repurchases through our stock repurchase program.

We expect Avista Utilities to contribute in the range of $1.79 to $1.94 per diluted share for 2014. This is an increase from our previous range of $1.68 to $1.82 per diluted share and is primarily due to lower than expected operating costs, higher loads and the delayed implementation of the replacement of our customer information system and work management systems. We expect to be near the upper end of this range, including the impacts of the ERM. In 2014, we expect to be in a benefit position under the ERM within the 90 percent customers/10 percent company sharing band. Our range for Avista Utilities encompasses expected variability in power supply costs and the application of the ERM to that power supply cost variability. Our outlook for Avista Utilities assumes, among other variables, normal precipitation, temperatures and hydroelectric generation for the remainder of the year.

We expect AERC to contribute in the range of $0.03 to $0.04 for the second half of 2014. Historically, AERC achieves approximately two-thirds of its earnings during the first half of the year and one-third during the second half.

We expect Ecova to contribute in the range of $1.13 and $1.15 per diluted share for their six months of earnings and the net gain on the sale.

We expect the other businesses to contribute between $0.05 and $0.07 per diluted share, which includes $0.09 of net earnings from the California power markets litigation settlement, net of the Avista Foundation contribution. It also includes the costs associated with exploring strategic opportunities.

Our guidance, including our 2014 guidance, generally includes only normal operating conditions and does not include unusual items such as settlement transactions, impairments or acquisitions/dispositions until the effects are known and certain.

NOTE: We will host a conference call with financial analysts and investors on August 6, 2014, at 10:30 a.m. ET to discuss this news release. The call will be available at (800) 708-4539, Confirmation number: 37666287. A simultaneous webcast of the call will be available on our website, www.avistacorp.com. A replay of the conference call will be available through August 14, 2014. Call (888) 843-7419, confirmation number 37666287#, to listen to the replay.

Avista Corp. is an energy company involved in the production, transmission and distribution of energy as well as other energy-related businesses. Avista Utilities is our operating division that provides electric service to 365,000 customers and natural gas to 325,000 customers. Our service territory covers 30,000 square miles in eastern Washington, northern Idaho and parts of southern and eastern Oregon, with a population of 1.6 million. Alaska Energy and Resources Company is an Avista subsidiary that, through its subsidiary Alaska Electric Light and Power Company, provides retail electric service to 16,000 customers in the city and borough of Juneau, Alaska. Our stock is traded under the ticker symbol "AVA". For more information about Avista, please visit www.avistacorp.com.

Avista Corp. and the Avista Corp. logo are trademarks of Avista Corporation.

This news release contains forward-looking statements, including statements regarding our current expectations for future financial performance and cash flows, capital expenditures, financing plans, our current plans or objectives for future operations and other factors, which may affect the company in the future. Such statements are subject to a variety of risks, uncertainties and other factors, most of which are beyond our control and many of which could have significant impact on our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements.

The following are among the important factors that could cause actual results to differ materially from the forward-looking statements: weather conditions (temperatures, precipitation levels and wind patterns) which affect both energy demand and electric generating capability, including the effect of precipitation and temperature on hydroelectric resources, the effect of wind patterns on wind-generated power, weather-sensitive customer demand, and similar effects on supply and demand in the wholesale energy markets; state and federal regulatory 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 and operating costs and discretion over allowed return on investment; 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 counterparties on wholesale energy transactions and credit risk to us from such transactions, and the market value of derivative assets and liabilities; 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 and/or conservation measures; 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; the potential effects of legislation or administrative rulemaking, including possible effects on our generating resources of 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 energy supply sources, such as campaigns to halt coal-fired power generation and opposition to other thermal generation, wind turbines or hydroelectric facilities; 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; volatility and illiquidity in wholesale energy markets, including the availability of willing buyers and sellers, and prices of purchased energy and demand for energy sales including related energy commodity derivative instruments that we rely upon to hedge our wholesale energy risks; the outcome of pending legal proceedings arising out of the "western energy crisis" of 2000 and 2001; the outcome of legal proceedings and other contingencies; changes in environmental and endangered species laws, regulations, decisions and policies, including present and potential environmental remediation costs and our compliance with these matters; 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; growth or decline of our customer base and the extent to which new uses for our services may materialize or existing uses may decline; the ability to comply with the terms of the licenses for our hydroelectric generating facilities at cost-effective levels; severe weather or natural disasters 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 distribution systems or other operations; public injuries or damage arising from or allegedly arising from our operations; blackouts or disruptions of interconnected transmission systems (the regional power grid); disruption to information systems, automated controls and other technologies that we rely on for our operations, communications and customer service; terrorist attacks, cyber attacks or other malicious acts that may disrupt or cause damage to our utility assets or to the national economy in general, including any effects of terrorism, cyber attacks or vandalism that damage or disrupt information technology systems; cyber attacks 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; delays or changes in construction costs, and/or our ability to obtain required permits and materials for present or prospective facilities; changes in the costs to implement new information technology systems and/or obstacles that impede our ability to complete such projects timely and effectively; changes in the long-term global and our utilities' service area climates, which can affect, among other things, customer demand patterns and the volume and timing of streamflows to our hydroelectric resources; changes in industrial, commercial and residential growth and demographic patterns in our service territory or changes in demand by significant customers; the loss of key suppliers for materials or services or disruptions to the supply chain; default or nonperformance on the part of any parties from which we purchase and/or sell capacity or energy; deterioration in the creditworthiness of our customers; potential decline in our credit ratings, with effects including impeded access to capital markets, higher interest costs, and restrictive covenants in our financing arrangements and wholesale energy contracts; increasing health care costs and the resulting effect on employee injury costs and health insurance provided to our employees and retirees; increasing costs of insurance, more restrictive coverage terms and our ability to obtain insurance; 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; the potential effects of negative publicity regarding business practices, whether true or not, which could result in litigation or a decline in our common stock price; changes in technologies, possibly making some of the current technology obsolete; changes in tax rates and/or policies; 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 that we recover interest costs through utility operations; potential difficulties in integrating acquired operations and in realizing expected opportunities, diversions of management resources and losses of key employees, challenges with respect to operating new businesses and other unanticipated risks and liabilities; 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; compliance with extensive federal, state and local legislation and regulation, including numerous environmental, health, safety and other laws and regulations that affect our operations and costs; information that was covered under management's representations and warranties related to the Ecova sale could be inaccurate or incomplete at the time of sale, or new information could be identified subsequent to the sale date, which could impact our ability to fully collect the indemnification escrow amounts; and the majority of hydroelectric power generation for our Alaska operations is provided by a single facility that is subject to a long-term power purchase agreement and any issues that negatively affect this facility's ability to generate or transmit power, any decrease in the demand for the power generated by this facility or any loss by our subsidiary of its contractual rights with respect thereto or other adverse effect thereon could negatively affect our Alaska operations' financial results.

For a further discussion of these factors and other important factors, please refer to our Annual Report on Form 10-K for the year ended Dec. 31, 2013 and Quarterly Report on Form 10-Q for the quarter ended Mar. 31, 2014. The forward-looking statements contained in this news release speak only as of the date hereof. We undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New risks, uncertainties and other factors emerge from time to time, and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on our business or the extent to which any such factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement.

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