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Share Name | Share Symbol | Market | Type |
---|---|---|---|
Avista Corp | NYSE:AVA | NYSE | Common Stock |
Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|
0.51 | 1.39% | 37.30 | 37.96 | 37.11 | 37.96 | 514,268 | 01:00:00 |
x
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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¨
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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AVISTA CORPORATION
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(Exact name of Registrant as specified in its charter)
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Washington
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91-0462470
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(State or other jurisdiction of
incorporation or organization)
|
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(I.R.S. Employer
Identification No.)
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1411 East Mission Avenue, Spokane, Washington
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99202-2600
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(Address of principal executive offices)
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(Zip Code)
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None
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(Former name, former address and former fiscal year, if changed since last report)
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Large accelerated filer
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x
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Accelerated filer
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¨
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Non-accelerated filer
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¨
(Do not check if a smaller reporting company)
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Smaller reporting company
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¨
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Item No.
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Item 3.
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Item 4.
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Item 1.
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Item 1A.
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Item 2.
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Item 4.
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Item 6.
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•
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financial performance;
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•
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cash flows;
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•
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capital expenditures;
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•
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dividends;
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•
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capital structure;
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•
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other financial items;
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•
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strategic goals and objectives;
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•
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business environment; and
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•
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plans for operations.
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•
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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;
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•
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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;
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•
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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;
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•
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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;
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•
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external pressure to meet financial goals that can lead to short-term or expedient decisions that reduce the likelihood of long-term objectives being met;
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•
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deterioration in the creditworthiness of our customers;
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•
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the outcome of legal proceedings and other contingencies;
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•
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economic conditions in our service areas, including the economy's effects on customer demand for utility services;
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•
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declining energy demand related to customer energy efficiency and/or conservation measures;
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•
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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;
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•
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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 and commodity costs and discretion over allowed return on investment;
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•
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possibility that our integrated resource plans for electric and natural gas will not be acknowledged by the state commissions;
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•
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volatility and illiquidity in wholesale energy markets, including 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 counterparties in wholesale energy transactions and credit risk to us from such transactions, and the market value of derivative assets and liabilities;
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•
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default or nonperformance on the part of any parties from whom we purchase and/or sell capacity or energy;
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•
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potential environmental requirements affecting our ability to utilize or resulting in the obsolescence of our power supply resources;
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•
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severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, 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;
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•
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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;
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•
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wildfires caused by our transmission or distribution system that may result in public injuries or property damages;
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•
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public injuries or damage arising from or allegedly arising from our operations;
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•
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blackouts or disruptions of interconnected transmission systems (the regional power grid);
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•
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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;
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•
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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;
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•
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increasing costs of insurance, more restrictive coverage terms and our ability to obtain insurance;
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•
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delays or changes in construction costs, and/or our ability to obtain required permits and materials for present or prospective facilities;
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•
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increasing health care costs and health insurance provided to our employees and retirees;
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•
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third party construction of buildings, billboard signs or towers within our rights of way, or placement of fuel receptacles within close proximity to our transformers or other equipment, including overbuild atop natural gas distribution lines;
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•
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the loss of key suppliers for materials or services or disruptions to the supply chain;
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•
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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 extensive cost of replacement power (diesel);
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•
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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;
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•
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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;
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•
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disruption to or breakdowns of information systems, automated controls and other technologies that we rely on for our operations, communications and customer service;
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•
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changes in the costs to operate and maintain current production technology or to implement new information technology systems that impede our ability to complete such projects timely and effectively;
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•
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changes in technologies, possibly making some of the current technology we utilize obsolete or the introduction of new technology that may create new cyber security related risk;
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insufficient technology skills, which could lead to the inability to develop, modify or maintain our information systems;
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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;
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•
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potential difficulties in integrating acquired operations and in realizing expected opportunities, diversions of management resources, loss of key employees, challenges with respect to operating new businesses and other unanticipated risks and liabilities;
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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;
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•
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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;
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non-regulated activities may increase earnings volatility;
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•
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changes in environmental laws, regulations, decisions and policies, including present and potential environmental remediation costs and our compliance with these matters;
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•
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the potential effects of legislation or administrative rulemaking at the federal, state or local levels, including possible effects on our generating resources of restrictions on greenhouse gas emissions to mitigate concerns over global climate changes;
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•
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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;
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•
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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;
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•
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failure to identify changes in legislation, taxation and regulatory issues which are detrimental or beneficial to our overall business; and
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•
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the risk of municipalization in any of our service territories.
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Avista Corporation
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Three months ended September 30,
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Nine months ended September 30,
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||||||||||||
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2016
|
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2015
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2016
|
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2015
|
||||||||
Operating Revenues:
|
|
|
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||||||||
Utility revenues
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$
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296,989
|
|
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$
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307,405
|
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$
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1,022,670
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$
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1,074,642
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Non-utility revenues
|
6,360
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|
|
6,244
|
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17,690
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22,829
|
|
||||
Total operating revenues
|
303,349
|
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313,649
|
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1,040,360
|
|
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1,097,471
|
|
||||
Operating Expenses:
|
|
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|
|
|
|
|
||||||||
Utility operating expenses:
|
|
|
|
|
|
|
|
||||||||
Resource costs
|
118,737
|
|
|
138,210
|
|
|
390,271
|
|
|
488,886
|
|
||||
Other operating expenses
|
75,160
|
|
|
74,315
|
|
|
229,605
|
|
|
220,599
|
|
||||
Depreciation and amortization
|
40,240
|
|
|
36,303
|
|
|
119,110
|
|
|
106,279
|
|
||||
Taxes other than income taxes
|
22,669
|
|
|
22,269
|
|
|
74,669
|
|
|
75,424
|
|
||||
Non-utility operating expenses:
|
|
|
|
|
|
|
|
||||||||
Other operating expenses
|
6,756
|
|
|
6,462
|
|
|
18,862
|
|
|
22,924
|
|
||||
Depreciation and amortization
|
193
|
|
|
178
|
|
|
573
|
|
|
512
|
|
||||
Total operating expenses
|
263,755
|
|
|
277,737
|
|
|
833,090
|
|
|
914,624
|
|
||||
Income from operations
|
39,594
|
|
|
35,912
|
|
|
207,270
|
|
|
182,847
|
|
||||
Interest expense
|
21,632
|
|
|
19,951
|
|
|
64,223
|
|
|
59,719
|
|
||||
Interest expense to affiliated trusts
|
164
|
|
|
120
|
|
|
456
|
|
|
347
|
|
||||
Capitalized interest
|
(507
|
)
|
|
(905
|
)
|
|
(2,258
|
)
|
|
(2,701
|
)
|
||||
Other income-net
|
(1,562
|
)
|
|
(2,123
|
)
|
|
(7,025
|
)
|
|
(6,190
|
)
|
||||
Income from continuing operations before income taxes
|
19,867
|
|
|
18,869
|
|
|
151,874
|
|
|
131,672
|
|
||||
Income tax expense
|
7,606
|
|
|
6,115
|
|
|
54,661
|
|
|
47,378
|
|
||||
Net income from continuing operations
|
12,261
|
|
|
12,754
|
|
|
97,213
|
|
|
84,294
|
|
||||
Net income from discontinued operations (Note 3)
|
—
|
|
|
289
|
|
|
—
|
|
|
485
|
|
||||
Net income
|
12,261
|
|
|
13,043
|
|
|
97,213
|
|
|
84,779
|
|
||||
Net income attributable to noncontrolling interests
|
(27
|
)
|
|
(32
|
)
|
|
(76
|
)
|
|
(73
|
)
|
||||
Net income attributable to Avista Corp. shareholders
|
$
|
12,234
|
|
|
$
|
13,011
|
|
|
$
|
97,137
|
|
|
$
|
84,706
|
|
|
|
|
|
|
|
|
|
Avista Corporation
|
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Amounts attributable to Avista Corp. shareholders:
|
|
|
|
|
|
|
|
||||||||
Net income from continuing operations attributable to Avista Corp. shareholders
|
$
|
12,234
|
|
|
$
|
12,722
|
|
|
$
|
97,137
|
|
|
$
|
84,221
|
|
Net income from discontinued operations attributable to Avista Corp. shareholders
|
—
|
|
|
289
|
|
|
—
|
|
|
485
|
|
||||
Net income attributable to Avista Corp. shareholders
|
$
|
12,234
|
|
|
$
|
13,011
|
|
|
$
|
97,137
|
|
|
$
|
84,706
|
|
|
|
|
|
|
|
|
|
||||||||
Weighted-average common shares outstanding (thousands), basic
|
63,857
|
|
|
62,299
|
|
|
63,282
|
|
|
62,299
|
|
||||
Weighted-average common shares outstanding (thousands), diluted
|
64,325
|
|
|
62,688
|
|
|
63,687
|
|
|
62,691
|
|
||||
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|
|
|
|
|
|
|
||||||||
Earnings per common share attributable to Avista Corp. shareholders, basic:
|
|
|
|
|
|
|
|
||||||||
Earnings per common share from continuing operations
|
$
|
0.19
|
|
|
$
|
0.21
|
|
|
$
|
1.53
|
|
|
$
|
1.35
|
|
Earnings per common share from discontinued operations
|
—
|
|
|
—
|
|
|
—
|
|
|
0.01
|
|
||||
Total earnings per common share attributable to Avista Corp. shareholders, basic
|
$
|
0.19
|
|
|
$
|
0.21
|
|
|
$
|
1.53
|
|
|
$
|
1.36
|
|
|
|
|
|
|
|
|
|
||||||||
Earnings per common share attributable to Avista Corp. shareholders, diluted:
|
|
|
|
|
|
|
|
||||||||
Earnings per common share from continuing operations
|
$
|
0.19
|
|
|
$
|
0.21
|
|
|
$
|
1.53
|
|
|
$
|
1.34
|
|
Earnings per common share from discontinued operations
|
—
|
|
|
—
|
|
|
—
|
|
|
0.01
|
|
||||
Total earnings per common share attributable to Avista Corp. shareholders, diluted
|
$
|
0.19
|
|
|
$
|
0.21
|
|
|
$
|
1.53
|
|
|
$
|
1.35
|
|
Dividends declared per common share
|
$
|
0.3425
|
|
|
$
|
0.3300
|
|
|
$
|
1.0275
|
|
|
$
|
0.9900
|
|
Avista Corporation
|
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Net income
|
$
|
12,261
|
|
|
$
|
13,043
|
|
|
$
|
97,213
|
|
|
$
|
84,779
|
|
Other Comprehensive Income (Loss):
|
|
|
|
|
|
|
|
||||||||
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $75, $132, $(512) and $396 respectively
|
140
|
|
|
246
|
|
|
(949
|
)
|
|
737
|
|
||||
Total other comprehensive income (loss)
|
140
|
|
|
246
|
|
|
(949
|
)
|
|
737
|
|
||||
Comprehensive income
|
12,401
|
|
|
13,289
|
|
|
96,264
|
|
|
85,516
|
|
||||
Comprehensive income attributable to noncontrolling interests
|
(27
|
)
|
|
(32
|
)
|
|
(76
|
)
|
|
(73
|
)
|
||||
Comprehensive income attributable to Avista Corporation shareholders
|
$
|
12,374
|
|
|
$
|
13,257
|
|
|
$
|
96,188
|
|
|
$
|
85,443
|
|
Avista Corporation
|
|
September 30,
|
|
December 31,
|
||||
|
2016
|
|
2015
|
||||
Assets:
|
|
|
|
||||
Current Assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
7,084
|
|
|
$
|
10,484
|
|
Accounts and notes receivable-less allowances of $4,266 and $4,530, respectively
|
116,054
|
|
|
169,413
|
|
||
Regulatory asset for utility derivatives
|
17,936
|
|
|
17,260
|
|
||
Materials and supplies, fuel stock and stored natural gas
|
58,080
|
|
|
54,148
|
|
||
Income taxes receivable
|
49,342
|
|
|
24,121
|
|
||
Other current assets
|
35,879
|
|
|
30,620
|
|
||
Total current assets
|
284,375
|
|
|
306,046
|
|
||
Net Utility Property:
|
|
|
|
||||
Utility plant in service
|
5,386,982
|
|
|
5,129,192
|
|
||
Construction work in progress
|
165,559
|
|
|
202,683
|
|
||
Total
|
5,552,541
|
|
|
5,331,875
|
|
||
Less: Accumulated depreciation and amortization
|
1,496,446
|
|
|
1,433,286
|
|
||
Total net utility property
|
4,056,095
|
|
|
3,898,589
|
|
||
Other Non-current Assets:
|
|
|
|
||||
Investment in exchange power-net
|
7,146
|
|
|
8,983
|
|
||
Investment in affiliated trusts
|
11,547
|
|
|
11,547
|
|
||
Goodwill
|
57,672
|
|
|
57,672
|
|
||
Long-term energy contract receivable
|
3,790
|
|
|
14,694
|
|
||
Other property and investments-net and other non-current assets
|
55,799
|
|
|
50,750
|
|
||
Total other non-current assets
|
135,954
|
|
|
143,646
|
|
||
Deferred Charges:
|
|
|
|
||||
Regulatory assets for deferred income tax
|
100,907
|
|
|
101,240
|
|
||
Regulatory assets for pensions and other postretirement benefits
|
223,596
|
|
|
235,009
|
|
||
Other regulatory assets
|
132,131
|
|
|
99,798
|
|
||
Regulatory asset for interest rate swaps
|
246,981
|
|
|
83,973
|
|
||
Non-current regulatory asset for utility commodity derivatives
|
27,336
|
|
|
32,420
|
|
||
Other deferred charges
|
7,731
|
|
|
5,928
|
|
||
Total deferred charges
|
738,682
|
|
|
558,368
|
|
||
Total assets
|
$
|
5,215,106
|
|
|
$
|
4,906,649
|
|
Avista Corporation
|
|
September 30,
|
|
December 31,
|
||||
|
2016
|
|
2015
|
||||
Liabilities and Equity:
|
|
|
|
||||
Current Liabilities:
|
|
|
|
||||
Accounts payable
|
$
|
81,898
|
|
|
$
|
114,349
|
|
Current portion of long-term debt and capital leases
|
3,257
|
|
|
93,167
|
|
||
Short-term borrowings
|
84,000
|
|
|
105,000
|
|
||
Utility energy commodity derivative liabilities
|
8,608
|
|
|
14,268
|
|
||
Other current liabilities
|
164,119
|
|
|
147,896
|
|
||
Total current liabilities
|
341,882
|
|
|
474,680
|
|
||
Long-term debt and capital leases
|
1,678,257
|
|
|
1,480,111
|
|
||
Long-term debt to affiliated trusts
|
51,547
|
|
|
51,547
|
|
||
Regulatory liability for utility plant retirement costs
|
270,972
|
|
|
261,594
|
|
||
Pensions and other postretirement benefits
|
202,329
|
|
|
201,453
|
|
||
Deferred income taxes
|
816,334
|
|
|
747,477
|
|
||
Non-current interest rate swap derivative liabilities
|
89,683
|
|
|
30,679
|
|
||
Other non-current liabilities, regulatory liabilities and deferred credits
|
135,578
|
|
|
130,821
|
|
||
Total liabilities
|
3,586,582
|
|
|
3,378,362
|
|
||
Commitments and Contingencies (See Notes to Condensed Consolidated Financial Statements)
|
|
|
|
||||
|
|
|
|
||||
Equity:
|
|
|
|
||||
Avista Corporation Shareholders’ Equity:
|
|
|
|
||||
Common stock, no par value; 200,000,000 shares authorized; 64,182,487 and 62,312,651 shares issued and outstanding as of September 30, 2016 and December 31, 2015, respectively
|
1,073,481
|
|
|
1,004,336
|
|
||
Accumulated other comprehensive loss
|
(7,599
|
)
|
|
(6,650
|
)
|
||
Retained earnings
|
562,905
|
|
|
530,940
|
|
||
Total Avista Corporation shareholders’ equity
|
1,628,787
|
|
|
1,528,626
|
|
||
Noncontrolling Interests
|
(263
|
)
|
|
(339
|
)
|
||
Total equity
|
1,628,524
|
|
|
1,528,287
|
|
||
Total liabilities and equity
|
$
|
5,215,106
|
|
|
$
|
4,906,649
|
|
Avista Corporation
|
|
2016
|
|
2015
|
||||
Operating Activities:
|
|
|
|
||||
Net income
|
$
|
97,213
|
|
|
$
|
84,779
|
|
Non-cash items included in net income:
|
|
|
|
||||
Depreciation and amortization
|
122,414
|
|
|
109,522
|
|
||
Deferred income tax provision and investment tax credits
|
87,246
|
|
|
12,381
|
|
||
Power and natural gas cost amortizations, net
|
11,422
|
|
|
10,004
|
|
||
Amortization of debt expense
|
2,595
|
|
|
2,651
|
|
||
Amortization of investment in exchange power
|
1,838
|
|
|
1,838
|
|
||
Stock-based compensation expense
|
6,261
|
|
|
5,263
|
|
||
Equity-related AFUDC
|
(6,306
|
)
|
|
(5,891
|
)
|
||
Pension and other postretirement benefit expense
|
29,076
|
|
|
28,179
|
|
||
Amortization of Spokane Energy contract
|
10,904
|
|
|
10,023
|
|
||
Gain on sale of Ecova
|
—
|
|
|
(710
|
)
|
||
Decoupling regulatory deferral
|
(24,693
|
)
|
|
(5,146
|
)
|
||
Other
|
(15,163
|
)
|
|
4,429
|
|
||
Contributions to defined benefit pension plan
|
(12,000
|
)
|
|
(12,000
|
)
|
||
Cash paid for settlement of interest rate swap agreements
|
(53,966
|
)
|
|
—
|
|
||
Changes in certain current assets and liabilities:
|
|
|
|
||||
Accounts and notes receivable
|
53,726
|
|
|
49,524
|
|
||
Materials and supplies, fuel stock and stored natural gas
|
(3,932
|
)
|
|
6,621
|
|
||
Increase in collateral posted for derivative instruments
|
(19,754
|
)
|
|
(9,917
|
)
|
||
Income taxes receivable
|
(25,222
|
)
|
|
43,266
|
|
||
Other current assets
|
(8,486
|
)
|
|
3,408
|
|
||
Accounts payable
|
(17,206
|
)
|
|
(32,378
|
)
|
||
Income taxes payable
|
713
|
|
|
158
|
|
||
Other current liabilities
|
17,438
|
|
|
5,240
|
|
||
Net cash provided by operating activities
|
254,118
|
|
|
311,244
|
|
||
|
|
|
|
||||
Investing Activities:
|
|
|
|
||||
Utility property capital expenditures (excluding equity-related AFUDC)
|
(288,072
|
)
|
|
(272,801
|
)
|
||
Other capital expenditures
|
(270
|
)
|
|
(852
|
)
|
||
Cash paid in acquisition, net
|
—
|
|
|
(95
|
)
|
||
Other
|
(26,611
|
)
|
|
2,646
|
|
||
Net cash used in investing activities
|
(314,953
|
)
|
|
(271,102
|
)
|
Avista Corporation
|
|
2016
|
|
2015
|
||||
Financing Activities:
|
|
|
|
||||
Net increase in borrowings from committed line of credit
|
$
|
82,000
|
|
|
$
|
25,000
|
|
Proceeds from issuance of long-term debt
|
70,000
|
|
|
—
|
|
||
Redemption and maturity of long-term debt
|
(92,375
|
)
|
|
(2,174
|
)
|
||
Maturity of nonrecourse long-term debt of Spokane Energy
|
—
|
|
|
(1,431
|
)
|
||
Issuance of common stock, net of issuance costs
|
66,756
|
|
|
1,397
|
|
||
Repurchase of common stock
|
—
|
|
|
(2,920
|
)
|
||
Cash dividends paid
|
(65,172
|
)
|
|
(61,828
|
)
|
||
Other
|
(3,774
|
)
|
|
(11,015
|
)
|
||
Net cash provided by (used in) financing activities
|
57,435
|
|
|
(52,971
|
)
|
||
|
|
|
|
||||
Net decrease in cash and cash equivalents
|
(3,400
|
)
|
|
(12,829
|
)
|
||
|
|
|
|
||||
Cash and cash equivalents at beginning of period
|
10,484
|
|
|
22,143
|
|
||
|
|
|
|
||||
Cash and cash equivalents at end of period
|
$
|
7,084
|
|
|
$
|
9,314
|
|
Avista Corporation
|
|
2016
|
|
2015
|
||||
Common Stock, Shares:
|
|
|
|
||||
Shares outstanding at beginning of period
|
62,312,651
|
|
|
62,243,374
|
|
||
Shares issued
|
1,869,836
|
|
|
149,883
|
|
||
Shares repurchased
|
—
|
|
|
(89,400
|
)
|
||
Shares outstanding at end of period
|
64,182,487
|
|
|
62,303,857
|
|
||
Common Stock, Amount:
|
|
|
|
||||
Balance at beginning of period
|
$
|
1,004,336
|
|
|
$
|
999,960
|
|
Equity compensation expense
|
5,462
|
|
|
4,579
|
|
||
Issuance of common stock, net of issuance costs
|
66,756
|
|
|
1,397
|
|
||
Payment of minimum tax withholdings for share-based payment awards
|
(3,073
|
)
|
|
(1,832
|
)
|
||
Repurchase of common stock
|
—
|
|
|
(1,431
|
)
|
||
Excess tax benefits
|
—
|
|
|
43
|
|
||
Balance at end of period
|
1,073,481
|
|
|
1,002,716
|
|
||
Accumulated Other Comprehensive Loss:
|
|
|
|
||||
Balance at beginning of period
|
(6,650
|
)
|
|
(7,888
|
)
|
||
Other comprehensive income (loss)
|
(949
|
)
|
|
737
|
|
||
Balance at end of period
|
(7,599
|
)
|
|
(7,151
|
)
|
||
Retained Earnings:
|
|
|
|
||||
Balance at beginning of period
|
530,940
|
|
|
491,599
|
|
||
Net income attributable to Avista Corporation shareholders
|
97,137
|
|
|
84,706
|
|
||
Cash dividends paid (common stock)
|
(65,172
|
)
|
|
(61,828
|
)
|
||
Repurchase of common stock
|
—
|
|
|
(1,489
|
)
|
||
Balance at end of period
|
562,905
|
|
|
512,988
|
|
||
Total Avista Corporation shareholders’ equity
|
1,628,787
|
|
|
1,508,553
|
|
||
Noncontrolling Interests:
|
|
|
|
||||
Balance at beginning of period
|
(339
|
)
|
|
(429
|
)
|
||
Net income attributable to noncontrolling interests
|
76
|
|
|
73
|
|
||
Balance at end of period
|
(263
|
)
|
|
(356
|
)
|
||
Total equity
|
$
|
1,628,524
|
|
|
$
|
1,508,197
|
|
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
|
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Utility related taxes
|
$
|
12,095
|
|
|
$
|
12,316
|
|
|
$
|
43,033
|
|
|
$
|
44,755
|
|
Property taxes
|
10,047
|
|
|
9,448
|
|
|
29,757
|
|
|
28,669
|
|
||||
Other taxes
|
527
|
|
|
505
|
|
|
1,879
|
|
|
2,000
|
|
||||
Total
|
$
|
22,669
|
|
|
$
|
22,269
|
|
|
$
|
74,669
|
|
|
$
|
75,424
|
|
|
September 30,
|
|
December 31,
|
||||
|
2016
|
|
2015
|
||||
Materials and supplies
|
$
|
39,487
|
|
|
$
|
37,101
|
|
Fuel stock
|
4,754
|
|
|
4,273
|
|
||
Stored natural gas
|
13,839
|
|
|
12,774
|
|
||
Total
|
$
|
58,080
|
|
|
$
|
54,148
|
|
|
September 30,
|
|
December 31,
|
||||
|
2016
|
|
2015
|
||||
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $4,092 and $3,580, respectively
|
$
|
7,599
|
|
|
$
|
6,650
|
|
|
|
Amounts Reclassified from Accumulated Other Comprehensive Loss
|
|
|
||||||||||||||
|
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
|
|
||||||||||||
Details about Accumulated Other Comprehensive Loss Components
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
Affected Line Item in Statement of Income
|
||||||||
Amortization of defined benefit pension items
|
|
|
|
|
|
|
|
|
||||||||||
Amortization of net prior service cost
|
|
$
|
(312
|
)
|
|
$
|
(273
|
)
|
|
$
|
(934
|
)
|
|
$
|
(819
|
)
|
|
(a)
|
Amortization of net loss
|
|
3,642
|
|
|
3,688
|
|
|
$
|
10,926
|
|
|
$
|
11,063
|
|
|
(a)
|
||
Adjustment due to effects of regulation
|
|
(3,115
|
)
|
|
(3,037
|
)
|
|
(11,453
|
)
|
|
(9,111
|
)
|
|
(a) (b)
|
||||
|
|
215
|
|
|
378
|
|
|
(1,461
|
)
|
|
1,133
|
|
|
Total before tax
|
||||
|
|
(75
|
)
|
|
(132
|
)
|
|
512
|
|
|
(396
|
)
|
|
Tax benefit (expense)
|
||||
|
|
$
|
140
|
|
|
$
|
246
|
|
|
$
|
(949
|
)
|
|
$
|
737
|
|
|
Net of tax
|
(a)
|
These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 5 for additional details).
|
(b)
|
The adjustment for the effects of regulation during the
nine months ended
September 30, 2016
includes approximately
$2.1 million
related to the reclassification of a pension regulatory asset associated with one of our jurisdictions into accumulated other comprehensive loss.
|
•
|
allowing excess tax benefits or tax deficiencies to be recognized as income tax benefits or expenses in the Statements of Income rather than in Additional Paid in Capital (APIC),
|
•
|
excess tax benefits no longer represent a financing cash inflow on the Statements of Cash Flows and instead will be included as an operating activity,
|
•
|
excess tax benefits and tax deficiencies will be excluded from the calculation of diluted earnings per share, whereas under current accounting guidance, these amounts must be estimated and included in the calculation,
|
•
|
allowing forfeitures to be accounted for as they occur, instead of estimating forfeitures, and
|
•
|
changing the statutory tax withholding requirements for share-based payments.
|
|
Three months ended September 30, 2015:
|
|
Nine months ended September 30, 2015:
|
||||
Gain on sale of Ecova (1)
|
$
|
547
|
|
|
$
|
710
|
|
Transaction expenses and accelerated employee benefits
|
24
|
|
|
24
|
|
||
Gain on sale of Ecova, net of transaction expenses
|
523
|
|
|
686
|
|
||
|
|
|
|
||||
Income before income taxes
|
523
|
|
|
686
|
|
||
Income tax benefit (2)
|
234
|
|
|
201
|
|
||
Net income from discontinued operations attributable to Avista Corp. shareholders
|
$
|
289
|
|
|
$
|
485
|
|
(1)
|
The gain recognized during 2015 relates to the resolution of the working capital adjustment, as well as a gain associated with the favorable settlement of outstanding litigation at Ecova that was shared between the Cofely USA, Inc. and the former shareholders and option holders of Ecova.
|
(2)
|
The tax expense during 2015 resulted from a state tax true-up, partially offset by tax expense associated with the gain on sale and the final true-up of 2014 federal tax payments.
|
|
Purchases
|
|
Sales
|
||||||||||||||||||||
|
Electric Derivatives
|
|
Gas Derivatives
|
|
Electric Derivatives
|
|
Gas Derivatives
|
||||||||||||||||
Year
|
Physical (1)
MWH
|
|
Financial (1)
MWH
|
|
Physical (1)
mmBTUs
|
|
Financial (1)
mmBTUs
|
|
Physical (1)
MWH |
|
Financial (1)
MWH |
|
Physical (1)
mmBTUs |
|
Financial (1)
mmBTUs |
||||||||
2016
|
170
|
|
|
701
|
|
|
9,094
|
|
|
46,475
|
|
|
95
|
|
|
1,009
|
|
|
2,058
|
|
|
35,170
|
|
2017
|
403
|
|
|
302
|
|
|
5,765
|
|
|
98,893
|
|
|
333
|
|
|
1,205
|
|
|
1,360
|
|
|
56,938
|
|
2018
|
397
|
|
|
—
|
|
|
—
|
|
|
35,628
|
|
|
286
|
|
|
438
|
|
|
1,360
|
|
|
11,978
|
|
2019
|
235
|
|
|
—
|
|
|
610
|
|
|
11,980
|
|
|
158
|
|
|
—
|
|
|
1,345
|
|
|
1,125
|
|
2020
|
—
|
|
|
—
|
|
|
910
|
|
|
2,725
|
|
|
—
|
|
|
—
|
|
|
1,430
|
|
|
—
|
|
Thereafter
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,060
|
|
|
—
|
|
|
Purchases
|
|
Sales
|
||||||||||||||||||||
|
Electric Derivatives
|
|
Gas Derivatives
|
|
Electric Derivatives
|
|
Gas Derivatives
|
||||||||||||||||
Year
|
Physical (1)
MWH
|
|
Financial (1)
MWH
|
|
Physical (1)
mmBTUs
|
|
Financial (1)
mmBTUs
|
|
Physical (1)
MWH |
|
Financial (1)
MWH |
|
Physical (1)
mmBTUs |
|
Financial (1)
mmBTUs |
||||||||
2016
|
407
|
|
|
1,954
|
|
|
17,252
|
|
|
142,693
|
|
|
280
|
|
|
2,656
|
|
|
3,182
|
|
|
112,233
|
|
2017
|
397
|
|
|
97
|
|
|
675
|
|
|
49,200
|
|
|
255
|
|
|
483
|
|
|
1,360
|
|
|
26,965
|
|
2018
|
397
|
|
|
—
|
|
|
—
|
|
|
15,118
|
|
|
286
|
|
|
—
|
|
|
1,360
|
|
|
2,738
|
|
2019
|
235
|
|
|
—
|
|
|
305
|
|
|
6,935
|
|
|
158
|
|
|
—
|
|
|
1,345
|
|
|
—
|
|
2020
|
—
|
|
|
—
|
|
|
455
|
|
|
905
|
|
|
—
|
|
|
—
|
|
|
1,430
|
|
|
—
|
|
Thereafter
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,060
|
|
|
—
|
|
(1)
|
Physical transactions represent commodity transactions in which Avista Utilities 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, swaps, options, or forward contracts.
|
|
September 30,
|
|
December 31,
|
||||
|
2016
|
|
2015
|
||||
Number of contracts
|
22
|
|
|
24
|
|
||
Notional amount (in United States currency)
|
$
|
8,572
|
|
|
$
|
1,463
|
|
Notional amount (in Canadian currency)
|
11,222
|
|
|
2,002
|
|
Balance Sheet Date
|
|
Number of Contracts
|
|
Notional Amount
|
|
Mandatory Cash Settlement Date
|
||
September 30, 2016
|
|
5
|
|
$
|
65,000
|
|
|
2017
|
|
|
14
|
|
275,000
|
|
|
2018
|
|
|
|
5
|
|
60,000
|
|
|
2019
|
|
|
|
1
|
|
10,000
|
|
|
2020
|
|
|
|
5
|
|
60,000
|
|
|
2022
|
|
December 31, 2015
|
|
6
|
|
$
|
115,000
|
|
|
2016
|
|
|
3
|
|
45,000
|
|
|
2017
|
|
|
|
11
|
|
245,000
|
|
|
2018
|
|
|
|
2
|
|
30,000
|
|
|
2019
|
|
|
|
1
|
|
20,000
|
|
|
2022
|
|
|
Fair Value as of September 30, 2016
|
||||||||||||||
Derivative and Balance Sheet Location
|
|
Gross
Asset
|
|
Gross
Liability
|
|
Collateral
Netted
|
|
Net Asset
(Liability)
on Balance
Sheet
|
||||||||
Foreign currency exchange derivatives
|
|
|
|
|
|
|
|
|
||||||||
Other current assets
|
|
$
|
27
|
|
|
$
|
(25
|
)
|
|
$
|
—
|
|
|
$
|
2
|
|
Interest rate swap derivatives
|
|
|
|
|
|
|
|
|
||||||||
Other current liabilities
|
|
—
|
|
|
(9,033
|
)
|
|
8,692
|
|
|
(341
|
)
|
||||
Non-current interest rate swap derivative liabilities
|
|
386
|
|
|
(145,737
|
)
|
|
55,668
|
|
|
(89,683
|
)
|
||||
Energy commodity derivatives
|
|
|
|
|
|
|
|
|
||||||||
Other current assets
|
|
823
|
|
|
(103
|
)
|
|
—
|
|
|
720
|
|
||||
Current utility energy commodity derivative liabilities
|
|
27,159
|
|
|
(45,815
|
)
|
|
10,048
|
|
|
(8,608
|
)
|
||||
Other non-current liabilities, regulatory liabilities and deferred credits
|
|
5,632
|
|
|
(32,968
|
)
|
|
7,914
|
|
|
(19,422
|
)
|
||||
Total derivative instruments recorded on the balance sheet
|
|
$
|
34,027
|
|
|
$
|
(233,681
|
)
|
|
$
|
82,322
|
|
|
$
|
(117,332
|
)
|
|
|
Fair Value as of December 31, 2015
|
||||||||||||||
Derivative and Balance Sheet Location
|
|
Gross
Asset
|
|
Gross
Liability
|
|
Collateral
Netted |
|
Net Asset
(Liability) on Balance Sheet |
||||||||
Foreign currency exchange derivatives
|
|
|
|
|
|
|
|
|
||||||||
Other current liabilities
|
|
$
|
2
|
|
|
$
|
(19
|
)
|
|
$
|
—
|
|
|
$
|
(17
|
)
|
Interest rate swap derivatives
|
|
|
|
|
|
|
|
|
||||||||
Other property and investments-net and other non-current assets
|
|
23
|
|
|
—
|
|
|
—
|
|
|
23
|
|
||||
Other current liabilities
|
|
118
|
|
|
(23,262
|
)
|
|
3,880
|
|
|
(19,264
|
)
|
||||
Non-current interest rate swap derivative liabilities
|
|
1,407
|
|
|
(62,236
|
)
|
|
30,150
|
|
|
(30,679
|
)
|
||||
Energy commodity derivatives
|
|
|
|
|
|
|
|
|
||||||||
Other current assets
|
|
1,236
|
|
|
(553
|
)
|
|
—
|
|
|
683
|
|
||||
Current utility energy commodity derivative liabilities
|
|
67,466
|
|
|
(85,409
|
)
|
|
3,675
|
|
|
(14,268
|
)
|
||||
Other non-current liabilities, regulatory liabilities and deferred credits
|
|
6,613
|
|
|
(39,033
|
)
|
|
10,851
|
|
|
(21,569
|
)
|
||||
Total derivative instruments recorded on the balance sheet
|
|
$
|
76,865
|
|
|
$
|
(210,512
|
)
|
|
$
|
48,556
|
|
|
$
|
(85,091
|
)
|
|
September 30,
|
|
December 31,
|
||||
|
2016
|
|
2015
|
||||
Energy commodity derivatives
|
|
|
|
||||
Cash collateral posted
|
$
|
18,140
|
|
|
$
|
28,716
|
|
Letters of credit outstanding
|
27,800
|
|
|
28,200
|
|
||
Balance sheet offsetting (cash collateral against net derivative positions)
|
17,962
|
|
|
14,526
|
|
||
|
|
|
|
||||
Interest rate swap derivatives
|
|
|
|
||||
Cash collateral posted
|
64,360
|
|
|
34,030
|
|
||
Letters of credit outstanding
|
39,100
|
|
|
9,600
|
|
||
Balance sheet offsetting (cash collateral against net derivative positions)
|
64,360
|
|
|
34,030
|
|
|
September 30,
|
|
December 31,
|
||||
|
2016
|
|
2015
|
||||
Energy commodity derivatives
|
|
|
|
||||
Liabilities with credit-risk-related contingent features
|
$
|
2,213
|
|
|
$
|
7,090
|
|
Additional collateral to post
|
1,966
|
|
|
6,980
|
|
||
|
|
|
|
||||
Interest rate swap derivatives
|
|
|
|
||||
Liabilities with credit-risk-related contingent features
|
154,770
|
|
|
85,498
|
|
||
Additional collateral to post
|
32,230
|
|
|
18,750
|
|
|
Pension Benefits
|
|
Other Post-retirement Benefits
|
||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Three months ended September 30:
|
|
|
|
|
|
|
|
||||||||
Service cost
|
$
|
4,567
|
|
|
$
|
4,984
|
|
|
$
|
806
|
|
|
$
|
721
|
|
Interest cost
|
6,895
|
|
|
6,531
|
|
|
1,530
|
|
|
1,292
|
|
||||
Expected return on plan assets
|
(6,887
|
)
|
|
(7,075
|
)
|
|
(465
|
)
|
|
(500
|
)
|
||||
Amortization of prior service cost
|
1
|
|
|
6
|
|
|
(300
|
)
|
|
(287
|
)
|
||||
Net loss recognition
|
2,161
|
|
|
2,397
|
|
|
1,453
|
|
|
1,324
|
|
||||
Net periodic benefit cost
|
$
|
6,737
|
|
|
$
|
6,843
|
|
|
$
|
3,024
|
|
|
$
|
2,550
|
|
Nine months ended September 30:
|
|
|
|
|
|
|
|
||||||||
Service cost
|
$
|
13,655
|
|
|
$
|
14,917
|
|
|
$
|
2,389
|
|
|
$
|
2,141
|
|
Interest cost
|
20,695
|
|
|
19,734
|
|
|
4,623
|
|
|
3,915
|
|
||||
Expected return on plan assets
|
(20,512
|
)
|
|
(21,566
|
)
|
|
(1,415
|
)
|
|
(1,431
|
)
|
||||
Amortization of prior service cost
|
1
|
|
|
18
|
|
|
(924
|
)
|
|
(853
|
)
|
||||
Net loss recognition
|
6,252
|
|
|
7,425
|
|
|
4,312
|
|
|
3,879
|
|
||||
Net periodic benefit cost
|
$
|
20,091
|
|
|
$
|
20,528
|
|
|
$
|
8,985
|
|
|
$
|
7,651
|
|
|
September 30,
|
|
December 31,
|
||||
|
2016
|
|
2015
|
||||
Borrowings outstanding at end of period (1)
|
$
|
187,000
|
|
|
$
|
105,000
|
|
Letters of credit outstanding at end of period
|
$
|
73,195
|
|
|
$
|
44,595
|
|
Average interest rate on borrowings at end of period
|
1.26
|
%
|
|
1.18
|
%
|
(1)
|
As of
September 30, 2016
, there was
$187.0 million
outstanding under the committed line of credit; however,
$84.0 million
was classified as short-term borrowings and the remaining
$103.0 million
was classified as long-term debt on the Condensed Consolidated Balance Sheet due to the Company's intention to refinance such amount on a long-term basis through the issuance and sale of first mortgage bonds pursuant to a bond purchase agreement entered into in August 2016. See Note 7 for further discussion of the bond purchase agreement and the refinancing of short-term debt on a long-term basis.
|
(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 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.
|
(2)
|
Prior to
September 30, 2016
, settled interest rate swaps were included as part of long-term debt on the Condensed Consolidated Balance Sheets because they were considered similar to a debt discount or premium. During the third quarter 2016, the Company reevaluated the presentation of settled interest rate swaps and determined that since they are regulatory assets and liabilities that are being recovered through the ratemaking process, the more appropriate classification is as regulatory assets and liabilities rather than as a component of long-term debt. As such, as of
September 30, 2016
, the Company has included unamortized settled interest rate swaps of
$92.8 million
in regulatory assets and
$12.8 million
in regulatory liabilities. The Company did not reclassify any amounts as of December 31, 2015 and prior because the amounts are not material to the financial statements. The increase in settled interest rate swaps during 2016 is due to the cash settlement of interest rate swaps during the third quarter of 2016 (discussed in detail below). There is no impact to the Condensed Consolidated Statements of Income and the Condensed Consolidated Statements of Cash Flows for any periods as a result of the balance sheet reclassification.
|
(3)
|
In August 2016, Avista Corp. entered into a term loan agreement with a commercial bank in the amount of
$70.0 million
with a maturity date of December 30, 2016. Loans under this agreement are unsecured and have a variable annual interest rate determined by either the Eurodollar rate or the Alternative Base Rate, depending on the type of loan selected by Avista Corp. The Company borrowed the entire
$70.0 million
available under this agreement, which was used to repay a portion of the
$90.0 million
in first mortgage bonds that matured in August 2016.
|
|
September 30,
|
|
December 31,
|
||
|
2016
|
|
2015
|
||
Low distribution rate
|
1.29
|
%
|
|
1.11
|
%
|
High distribution rate
|
1.72
|
%
|
|
1.29
|
%
|
Distribution rate at the end of the period
|
1.72
|
%
|
|
1.29
|
%
|
|
September 30, 2016
|
|
December 31, 2015
|
||||||||||||
|
Carrying
Value
|
|
Estimated
Fair Value
|
|
Carrying
Value
|
|
Estimated
Fair Value
|
||||||||
Long-term debt (Level 2)
|
$
|
951,000
|
|
|
$
|
1,100,059
|
|
|
$
|
951,000
|
|
|
$
|
1,055,797
|
|
Long-term debt (Level 3)
|
502,000
|
|
|
572,112
|
|
|
592,000
|
|
|
595,018
|
|
||||
Snettisham capital lease obligation (Level 3)
|
62,734
|
|
|
64,800
|
|
|
64,455
|
|
|
63,150
|
|
||||
Long-term debt to affiliated trusts (Level 3)
|
51,547
|
|
|
38,145
|
|
|
51,547
|
|
|
36,083
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Counterparty
and Cash Collateral Netting (1) |
|
Total
|
||||||||||
September 30, 2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Energy commodity derivatives
|
$
|
—
|
|
|
$
|
33,589
|
|
|
$
|
—
|
|
|
$
|
(32,869
|
)
|
|
$
|
720
|
|
Level 3 energy commodity derivatives:
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural gas exchange agreement
|
—
|
|
|
—
|
|
|
25
|
|
|
(25
|
)
|
|
—
|
|
|||||
Foreign currency derivatives
|
—
|
|
|
27
|
|
|
—
|
|
|
(25
|
)
|
|
2
|
|
|||||
Interest rate swaps
|
—
|
|
|
386
|
|
|
—
|
|
|
(386
|
)
|
|
—
|
|
|||||
Deferred compensation assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed income securities (2)
|
1,895
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,895
|
|
|||||
Equity securities (2)
|
5,627
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,627
|
|
|||||
Total
|
$
|
7,522
|
|
|
$
|
34,002
|
|
|
$
|
25
|
|
|
$
|
(33,305
|
)
|
|
$
|
8,244
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Energy commodity derivatives
|
$
|
—
|
|
|
$
|
55,233
|
|
|
$
|
—
|
|
|
$
|
(50,831
|
)
|
|
$
|
4,402
|
|
Level 3 energy commodity derivatives:
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural gas exchange agreement
|
—
|
|
|
—
|
|
|
6,546
|
|
|
(25
|
)
|
|
6,521
|
|
|||||
Power exchange agreement
|
—
|
|
|
—
|
|
|
16,310
|
|
|
—
|
|
|
16,310
|
|
|||||
Power option agreement
|
—
|
|
|
—
|
|
|
797
|
|
|
—
|
|
|
797
|
|
|||||
Foreign currency derivatives
|
—
|
|
|
25
|
|
|
—
|
|
|
(25
|
)
|
|
—
|
|
|||||
Interest rate swaps
|
—
|
|
|
154,770
|
|
|
—
|
|
|
(64,746
|
)
|
|
90,024
|
|
|||||
Total
|
$
|
—
|
|
|
$
|
210,028
|
|
|
$
|
23,653
|
|
|
$
|
(115,627
|
)
|
|
$
|
118,054
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Counterparty
and Cash Collateral Netting (1) |
|
Total
|
||||||||||
December 31, 2015
|
|
|
|
|
|
|
|
|
|
||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Energy commodity derivatives
|
$
|
—
|
|
|
$
|
74,637
|
|
|
$
|
—
|
|
|
$
|
(73,954
|
)
|
|
$
|
683
|
|
Level 3 energy commodity derivatives:
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural gas exchange agreement
|
—
|
|
|
—
|
|
|
678
|
|
|
(678
|
)
|
|
—
|
|
|||||
Foreign currency derivatives
|
—
|
|
|
2
|
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
|||||
Interest rate swaps
|
—
|
|
|
1,548
|
|
|
—
|
|
|
—
|
|
|
1,548
|
|
|||||
Deferred compensation assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed income securities (2)
|
1,727
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,727
|
|
|||||
Equity securities (2)
|
5,761
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,761
|
|
|||||
Total
|
$
|
7,488
|
|
|
$
|
76,187
|
|
|
$
|
678
|
|
|
$
|
(74,634
|
)
|
|
$
|
9,719
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Energy commodity derivatives
|
$
|
—
|
|
|
$
|
97,193
|
|
|
$
|
—
|
|
|
$
|
(88,480
|
)
|
|
$
|
8,713
|
|
Level 3 energy commodity derivatives:
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural gas exchange agreement
|
—
|
|
|
—
|
|
|
5,717
|
|
|
(678
|
)
|
|
5,039
|
|
|||||
Power exchange agreement
|
—
|
|
|
—
|
|
|
21,961
|
|
|
—
|
|
|
21,961
|
|
|||||
Power option agreement
|
—
|
|
|
—
|
|
|
124
|
|
|
—
|
|
|
124
|
|
|||||
Foreign currency derivatives
|
—
|
|
|
19
|
|
|
—
|
|
|
(2
|
)
|
|
17
|
|
|||||
Interest rate swaps
|
—
|
|
|
85,498
|
|
|
—
|
|
|
—
|
|
|
85,498
|
|
|||||
Total
|
$
|
—
|
|
|
$
|
182,710
|
|
|
$
|
27,802
|
|
|
$
|
(89,160
|
)
|
|
$
|
121,352
|
|
(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 and other non-current assets on the Condensed Consolidated Balance Sheets.
|
|
|
Fair Value (Net) at
|
|
|
|
|
|
|
||
|
|
September 30, 2016
|
|
Valuation Technique
|
|
Unobservable
Input
|
|
Range
|
||
Power exchange agreement
|
|
$
|
(16,310
|
)
|
|
Surrogate facility
pricing
|
|
O&M charges
|
|
$33.59-$49.15/MWh (1)
|
|
|
|
|
Escalation factor
|
|
3% - 2017 to 2019
|
||||
|
|
|
|
Transaction volumes
|
|
396,984 - 406,909 MWhs
|
||||
Power option agreement
|
|
$
|
(797
|
)
|
|
Black-Scholes-
Merton
|
|
Strike price
|
|
$37.46/MWh - 2019
|
|
|
|
|
|
$49.71/MWh - 2017
|
|||||
|
|
|
|
Delivery volumes
|
|
157,517 - 285,979 MWhs
|
||||
|
|
|
|
Volatility rates
|
|
0.21 (2)
|
||||
Natural gas exchange
agreement
|
|
$
|
(6,521
|
)
|
|
Internally derived
weighted average cost of gas |
|
Forward purchase
prices
|
|
$1.95 - $2.55/mmBTU
|
|
|
|
|
|
||||||
|
|
|
|
Forward sales prices
|
|
$2.03 - $3.37/mmBTU
|
||||
|
|
|
|
Purchase volumes
|
|
115,000 - 310,000 mmBTUs
|
||||
|
|
|
|
Sales volumes
|
|
60,000 - 310,000 mmBTUs
|
|
Natural Gas Exchange Agreement
|
|
Power Exchange Agreement
|
|
Power Option Agreement
|
|
Total
|
||||||||
Three months ended September 30, 2016:
|
|
|
|
|
|
|
|
||||||||
Balance as of July 1, 2016
|
$
|
(6,857
|
)
|
|
$
|
(14,614
|
)
|
|
$
|
(105
|
)
|
|
$
|
(21,576
|
)
|
Total gains or (losses) (realized/unrealized):
|
|
|
|
|
|
|
|
||||||||
Included in regulatory assets/liabilities (1)
|
336
|
|
|
(1,696
|
)
|
|
(692
|
)
|
|
(2,052
|
)
|
||||
Settlements
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Ending balance as of September 30, 2016 (2)
|
$
|
(6,521
|
)
|
|
$
|
(16,310
|
)
|
|
$
|
(797
|
)
|
|
$
|
(23,628
|
)
|
Three months ended September 30, 2015:
|
|
|
|
|
|
|
|
||||||||
Balance as of July 1, 2015
|
$
|
(6,825
|
)
|
|
$
|
(18,616
|
)
|
|
$
|
(145
|
)
|
|
$
|
(25,586
|
)
|
Total gains or (losses) (realized/unrealized):
|
|
|
|
|
|
|
|
||||||||
Included in regulatory assets/liabilities (1)
|
1,800
|
|
|
(4,563
|
)
|
|
28
|
|
|
(2,735
|
)
|
||||
Settlements
|
282
|
|
|
—
|
|
|
—
|
|
|
282
|
|
||||
Ending balance as of September 30, 2015 (2)
|
$
|
(4,743
|
)
|
|
$
|
(23,179
|
)
|
|
$
|
(117
|
)
|
|
$
|
(28,039
|
)
|
Nine months ended September 30, 2016:
|
|
|
|
|
|
|
|
||||||||
Balance as of January 1, 2016
|
$
|
(5,039
|
)
|
|
$
|
(21,961
|
)
|
|
$
|
(124
|
)
|
|
$
|
(27,124
|
)
|
Total gains or (losses) (realized/unrealized):
|
|
|
|
|
|
|
|
||||||||
Included in regulatory assets/liabilities (1)
|
(2,960
|
)
|
|
272
|
|
|
(673
|
)
|
|
(3,361
|
)
|
||||
Settlements
|
1,478
|
|
|
5,379
|
|
|
—
|
|
|
6,857
|
|
||||
Ending balance as of September 30, 2016 (2)
|
$
|
(6,521
|
)
|
|
$
|
(16,310
|
)
|
|
$
|
(797
|
)
|
|
$
|
(23,628
|
)
|
|
|
|
|
|
|
|
|
||||||||
Nine months ended September 30, 2015:
|
|
|
|
|
|
|
|
||||||||
Balance as of January 1, 2015
|
$
|
(35
|
)
|
|
$
|
(23,299
|
)
|
|
$
|
(424
|
)
|
|
$
|
(23,758
|
)
|
Total gains or (losses) (realized/unrealized):
|
|
|
|
|
|
|
|
||||||||
Included in regulatory assets/liabilities (1)
|
(5,586
|
)
|
|
(4,393
|
)
|
|
307
|
|
|
(9,672
|
)
|
||||
Settlements
|
878
|
|
|
4,513
|
|
|
—
|
|
|
5,391
|
|
||||
Ending balance as of September 30, 2015 (2)
|
$
|
(4,743
|
)
|
|
$
|
(23,179
|
)
|
|
$
|
(117
|
)
|
|
$
|
(28,039
|
)
|
|
|
|
|
|
|
|
|
(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.
|
|
Three months ended
|
|
Nine months ended
|
||||||||||||
|
September 30,
|
|
September 30,
|
||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Numerator:
|
|
|
|
|
|
|
|
||||||||
Net income from continuing operations attributable to Avista Corp. shareholders
|
$
|
12,234
|
|
|
$
|
12,722
|
|
|
$
|
97,137
|
|
|
$
|
84,221
|
|
Net income from discontinued operations attributable to Avista Corp. shareholders
|
—
|
|
|
289
|
|
|
—
|
|
|
485
|
|
||||
Denominator:
|
|
|
|
|
|
|
|
||||||||
Weighted-average number of common shares outstanding-basic
|
63,857
|
|
|
62,299
|
|
|
63,282
|
|
|
62,299
|
|
||||
Effect of dilutive securities:
|
|
|
|
|
|
|
|
||||||||
Performance and restricted stock awards
|
468
|
|
|
389
|
|
|
405
|
|
|
392
|
|
||||
Weighted-average number of common shares outstanding-diluted
|
64,325
|
|
|
62,688
|
|
|
63,687
|
|
|
62,691
|
|
||||
Earnings per common share attributable to Avista Corp. shareholders, basic:
|
|
|
|
|
|
|
|
||||||||
Earnings per common share from continuing operations
|
$
|
0.19
|
|
|
$
|
0.21
|
|
|
$
|
1.53
|
|
|
$
|
1.35
|
|
Earnings per common share from discontinued operations
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.01
|
|
Total earnings per common share attributable to Avista Corp. shareholders, basic
|
$
|
0.19
|
|
|
$
|
0.21
|
|
|
$
|
1.53
|
|
|
$
|
1.36
|
|
Earnings per common share attributable to Avista Corp. shareholders, diluted:
|
|
|
|
|
|
|
|
||||||||
Earnings per common share from continuing operations
|
$
|
0.19
|
|
|
$
|
0.21
|
|
|
$
|
1.53
|
|
|
$
|
1.34
|
|
Earnings per common share from discontinued operations
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.01
|
|
Total earnings per common share attributable to Avista Corp. shareholders, diluted
|
$
|
0.19
|
|
|
$
|
0.21
|
|
|
$
|
1.53
|
|
|
$
|
1.35
|
|
|
Avista
Utilities
|
|
Alaska Electric Light and Power Company
|
|
Total Utility
|
|
Other
|
|
Intersegment
Eliminations
(1)
|
|
Total
|
||||||||||||
For the three months ended September 30, 2016:
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Operating revenues
|
$
|
287,193
|
|
|
$
|
9,796
|
|
|
$
|
296,989
|
|
|
$
|
6,360
|
|
|
$
|
—
|
|
|
$
|
303,349
|
|
Resource costs
|
115,228
|
|
|
3,509
|
|
|
118,737
|
|
|
—
|
|
|
—
|
|
|
118,737
|
|
||||||
Other operating expenses
|
72,318
|
|
|
2,842
|
|
|
75,160
|
|
|
6,756
|
|
|
—
|
|
|
81,916
|
|
||||||
Depreciation and amortization
|
38,909
|
|
|
1,331
|
|
|
40,240
|
|
|
193
|
|
|
—
|
|
|
40,433
|
|
||||||
Income (loss) from operations
|
38,554
|
|
|
1,629
|
|
|
40,183
|
|
|
(589
|
)
|
|
—
|
|
|
39,594
|
|
||||||
Interest expense (2)
|
20,772
|
|
|
894
|
|
|
21,666
|
|
|
149
|
|
|
(19
|
)
|
|
21,796
|
|
||||||
Income taxes
|
7,983
|
|
|
339
|
|
|
8,322
|
|
|
(716
|
)
|
|
—
|
|
|
7,606
|
|
||||||
Net income (loss) from continuing operations attributable to Avista Corp. shareholders
|
12,673
|
|
|
866
|
|
|
13,539
|
|
|
(1,305
|
)
|
|
—
|
|
|
12,234
|
|
||||||
Capital expenditures (3)
|
101,558
|
|
|
3,699
|
|
|
105,257
|
|
|
105
|
|
|
—
|
|
|
105,362
|
|
||||||
For the three months ended September 30, 2015:
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Operating revenues
|
$
|
298,132
|
|
|
$
|
9,273
|
|
|
$
|
307,405
|
|
|
$
|
6,244
|
|
|
$
|
—
|
|
|
$
|
313,649
|
|
Resource costs
|
135,048
|
|
|
3,162
|
|
|
138,210
|
|
|
—
|
|
|
—
|
|
|
138,210
|
|
||||||
Other operating expenses
|
71,536
|
|
|
2,779
|
|
|
74,315
|
|
|
6,462
|
|
|
—
|
|
|
80,777
|
|
||||||
Depreciation and amortization
|
34,986
|
|
|
1,317
|
|
|
36,303
|
|
|
178
|
|
|
—
|
|
|
36,481
|
|
||||||
Income (loss) from operations
|
34,800
|
|
|
1,508
|
|
|
36,308
|
|
|
(396
|
)
|
|
—
|
|
|
35,912
|
|
||||||
Interest expense (2)
|
19,054
|
|
|
896
|
|
|
19,950
|
|
|
150
|
|
|
(29
|
)
|
|
20,071
|
|
||||||
Income taxes
|
5,980
|
|
|
229
|
|
|
6,209
|
|
|
(94
|
)
|
|
—
|
|
|
6,115
|
|
||||||
Net income (loss) from continuing operations attributable to Avista Corp. shareholders
|
12,525
|
|
|
394
|
|
|
12,919
|
|
|
(197
|
)
|
|
—
|
|
|
12,722
|
|
||||||
Capital expenditures (3)
|
92,271
|
|
|
2,778
|
|
|
95,049
|
|
|
348
|
|
|
—
|
|
|
95,397
|
|
|
Avista
Utilities
|
|
Alaska Electric Light and Power Company
|
|
Total Utility
|
|
Other
|
|
Intersegment
Eliminations
(1)
|
|
Total
|
||||||||||||
For the nine months ended September 30, 2016:
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Operating revenues
|
$
|
989,981
|
|
|
$
|
32,689
|
|
|
$
|
1,022,670
|
|
|
$
|
17,690
|
|
|
$
|
—
|
|
|
$
|
1,040,360
|
|
Resource costs
|
380,913
|
|
|
9,358
|
|
|
390,271
|
|
|
—
|
|
|
—
|
|
|
390,271
|
|
||||||
Other operating expenses
|
221,364
|
|
|
8,241
|
|
|
229,605
|
|
|
18,862
|
|
|
—
|
|
|
248,467
|
|
||||||
Depreciation and amortization
|
115,126
|
|
|
3,984
|
|
|
119,110
|
|
|
573
|
|
|
—
|
|
|
119,683
|
|
||||||
Income (loss) from operations
|
199,661
|
|
|
9,354
|
|
|
209,015
|
|
|
(1,745
|
)
|
|
—
|
|
|
207,270
|
|
||||||
Interest expense (2)
|
61,652
|
|
|
2,684
|
|
|
64,336
|
|
|
459
|
|
|
(116
|
)
|
|
64,679
|
|
||||||
Income taxes (4)
|
53,004
|
|
|
2,910
|
|
|
55,914
|
|
|
(1,253
|
)
|
|
—
|
|
|
54,661
|
|
||||||
Net income (loss) from continuing operations attributable to Avista Corp. shareholders
|
94,431
|
|
|
4,885
|
|
|
99,316
|
|
|
(2,179
|
)
|
|
—
|
|
|
97,137
|
|
||||||
Capital expenditures (3)
|
274,041
|
|
|
14,031
|
|
|
288,072
|
|
|
270
|
|
|
—
|
|
|
288,342
|
|
||||||
For the nine months ended September 30, 2015:
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Operating revenues
|
$
|
1,042,913
|
|
|
$
|
32,279
|
|
|
$
|
1,075,192
|
|
|
$
|
22,829
|
|
|
$
|
(550
|
)
|
|
$
|
1,097,471
|
|
Resource costs
|
479,604
|
|
|
9,282
|
|
|
488,886
|
|
|
—
|
|
|
—
|
|
|
488,886
|
|
||||||
Other operating expenses
|
212,293
|
|
|
8,306
|
|
|
220,599
|
|
|
23,474
|
|
|
(550
|
)
|
|
243,523
|
|
||||||
Depreciation and amortization
|
102,334
|
|
|
3,945
|
|
|
106,279
|
|
|
512
|
|
|
—
|
|
|
106,791
|
|
||||||
Income (loss) from operations
|
175,003
|
|
|
9,001
|
|
|
184,004
|
|
|
(1,157
|
)
|
|
—
|
|
|
182,847
|
|
||||||
Interest expense (2)
|
56,991
|
|
|
2,695
|
|
|
59,686
|
|
|
461
|
|
|
(81
|
)
|
|
60,066
|
|
||||||
Income taxes
|
45,500
|
|
|
2,504
|
|
|
48,004
|
|
|
(626
|
)
|
|
—
|
|
|
47,378
|
|
||||||
Net income (loss) from continuing operations attributable to Avista Corp. shareholders
|
81,387
|
|
|
3,953
|
|
|
85,340
|
|
|
(1,119
|
)
|
|
—
|
|
|
84,221
|
|
||||||
Capital expenditures (3)
|
264,283
|
|
|
8,518
|
|
|
272,801
|
|
|
852
|
|
|
—
|
|
|
273,653
|
|
||||||
Total Assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
As of September 30, 2016:
|
$
|
4,889,256
|
|
|
$
|
270,423
|
|
|
$
|
5,159,679
|
|
|
$
|
55,427
|
|
|
$
|
—
|
|
|
$
|
5,215,106
|
|
As of December 31, 2015:
|
$
|
4,601,708
|
|
|
$
|
265,735
|
|
|
$
|
4,867,443
|
|
|
$
|
39,206
|
|
|
$
|
—
|
|
|
$
|
4,906,649
|
|
(1)
|
Intersegment eliminations reported as operating revenues and resource costs represent intercompany purchases and sales of electric capacity and energy. Intersegment eliminations reported as interest expense and net income (loss) attributable to Avista Corp. shareholders represent intercompany interest.
|
(2)
|
Including interest expense to affiliated trusts.
|
(3)
|
The capital expenditures for the other businesses are included as other capital expenditures on the Condensed Consolidated Statements of Cash Flows.
|
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Avista Utilities
|
$
|
12,673
|
|
|
$
|
12,525
|
|
|
$
|
94,431
|
|
|
$
|
81,387
|
|
AEL&P
|
866
|
|
|
394
|
|
|
4,885
|
|
|
3,953
|
|
||||
Ecova - Discontinued operations
|
—
|
|
|
289
|
|
|
—
|
|
|
485
|
|
||||
Other
|
(1,305
|
)
|
|
(197
|
)
|
|
(2,179
|
)
|
|
(1,119
|
)
|
||||
Net income attributable to Avista Corporation shareholders
|
$
|
12,234
|
|
|
$
|
13,011
|
|
|
$
|
97,137
|
|
|
$
|
84,706
|
|
•
|
seek recovery of operating costs and capital investments, and
|
•
|
seek the opportunity to earn reasonable returns as allowed by regulators.
|
•
|
the discontinuation of the after-the-fact earnings test (provision for earnings sharing) that was originally agreed to as part of the settlement of our 2012 electric and natural gas general rate cases, and
|
•
|
the implementation of electric and natural gas Fixed Cost Adjustment mechanisms, as discussed below.
|
|
September 30,
|
|
December 31,
|
||||
|
2016
|
|
2015
|
||||
Washington
|
|
|
|
||||
Decoupling surcharge (1)
|
$
|
26,620
|
|
|
$
|
10,933
|
|
Provision for earnings sharing rebate (1)
|
(359
|
)
|
|
(3,422
|
)
|
||
Idaho
|
|
|
|
||||
Decoupling surcharge
|
$
|
6,598
|
|
|
n/a
|
|
|
Provision for earnings sharing rebate
|
(5,903
|
)
|
|
(8,814
|
)
|
||
Oregon
|
|
|
|
||||
Decoupling surcharge
|
$
|
2,407
|
|
|
n/a
|
|
|
Provision for earnings sharing rebate
|
—
|
|
|
—
|
|
(1)
|
As of September 30, 2016, the cumulative Washington electric provision for earnings sharing rebate for 2015 was $0.9 million and this amount was offset against the 2015 Washington electric decoupling surcharge to reduce the total decoupling surcharge balance.
|
|
Electric
|
|
Natural Gas
|
|
Intracompany
|
|
Total
|
||||||||||||||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||||||||||
Operating revenues
|
$
|
237,768
|
|
|
$
|
239,836
|
|
|
$
|
83,335
|
|
|
$
|
92,109
|
|
|
$
|
(33,910
|
)
|
|
$
|
(33,813
|
)
|
|
$
|
287,193
|
|
|
$
|
298,132
|
|
Resource costs
|
90,445
|
|
|
97,771
|
|
|
58,693
|
|
|
71,090
|
|
|
(33,910
|
)
|
|
(33,813
|
)
|
|
115,228
|
|
|
135,048
|
|
||||||||
Gross margin
|
$
|
147,323
|
|
|
$
|
142,065
|
|
|
$
|
24,642
|
|
|
$
|
21,019
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
171,965
|
|
|
$
|
163,084
|
|
|
Electric Operating
Revenues |
||||||
|
2016
|
|
2015
|
||||
Washington
|
|
|
|
||||
Decoupling surcharge (rebate)
|
$
|
266
|
|
|
$
|
(2,214
|
)
|
Provision for earnings sharing (1)
|
355
|
|
|
(940
|
)
|
||
Idaho
|
|
|
|
||||
Decoupling surcharge (rebate)
|
$
|
(515
|
)
|
|
n/a
|
|
|
Provision for earnings sharing (2)
|
n/a
|
|
|
(1,160
|
)
|
(1)
|
The provision for earnings sharing in Washington in the
third quarter
of 2016 resulted from a $0.4 million reduction in the 2016 estimated provision for earnings sharing (which increased third quarter 2016 revenues). We are estimating no provision for earnings sharing for the full year of 2016 for electric operations.
|
(2)
|
Beginning in 2016 there is no longer an earnings sharing mechanism in Idaho.
|
(n/a)
|
This mechanism did not exist during this time period.
|
•
|
a
$5.8 million
decrease in retail electric revenue due to a decrease in total MWhs sold (decreased revenues
$7.2 million
), partially offset by an increase in revenue per MWh (increased revenues
$1.4 million
).
|
◦
|
The increase in revenue per MWh was primarily due to a general rate increase in Idaho and the expiration of the ERM rebate to customers in Washington, partially offset by a general rate decrease in Washington.
|
◦
|
The decrease in total retail MWhs sold was the result of weather that was cooler than the prior year (which reduced electric cooling loads). Compared to the
third quarter
of
2015
, residential electric use per customer decreased
7 percent
and commercial use per customer decreased
4 percent
.
|
•
|
a
$0.3 million
decrease in wholesale electric revenues due to a decrease in sales prices (decreased revenues
$6.2 million
), partially offset by an increase in sales volumes (increased revenues
$5.9 million
). The fluctuation in volumes and prices was primarily the result of our optimization activities during the quarter.
|
•
|
a
$1.2 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
2016
,
$13.8 million
of these sales were made to our natural
|
•
|
a
$2.5 million
decrease in the electric provision for earnings sharing (which increases revenues) due to a $1.3 million reduction in the provision for earnings sharing in Washington and a $1.2 million reduction in the provision for earnings sharing in Idaho.
|
•
|
a
$2.0 million
increase in electric revenue due to decoupling, which reflected the implementation of a decoupling mechanism in Idaho effective January 1, 2016 and lower retail revenues as a result of cooler weather in the third quarter of 2016.
|
|
Natural Gas Operating
Revenues |
||||||
|
2016
|
|
2015
|
||||
Washington
|
|
|
|
||||
Decoupling surcharge
|
$
|
376
|
|
|
$
|
509
|
|
Provision for earnings sharing (1)
|
177
|
|
|
—
|
|
||
Idaho
|
|
|
|
||||
Decoupling surcharge (rebate)
|
$
|
(82
|
)
|
|
n/a
|
|
|
Provision for earnings sharing
|
n/a
|
|
|
—
|
|
||
Oregon
|
|
|
|
||||
Decoupling surcharge
|
$
|
486
|
|
|
n/a
|
|
|
Provision for earnings sharing
|
—
|
|
|
—
|
|
(1)
|
The provision for earnings sharing in Washington in the
third quarter
of 2016 resulted from a $0.2 million reduction in the 2016 estimated provision for earnings sharing (which increased 2016 revenues).
|
(n/a)
|
This mechanism did not exist during this time period.
|
•
|
a
$0.5 million
increase in natural gas retail revenues due an increase in volumes (increased revenues
$2.2 million
), partially offset by lower retail rates (decreased revenues
$1.7 million
).
|
◦
|
Lower retail rates were due to PGAs, partially offset by general rate increases.
|
◦
|
We sold more retail natural gas in the
third quarter
of
2016
as compared to the
third quarter
of
2015
due to weather that was cooler than the prior year. Compared to the
third quarter
of
2015
, residential natural gas use per customer increased
4 percent
and commercial use per customer increased
5 percent
. Retail natural gas loads and changes in customer usage during the third quarter are typically not significant to the full year.
|
•
|
a
$9.9 million
decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues
$5.7 million
) and a decrease in volumes (decreased revenues
$4.2 million
). In the
third quarter
of
2016
,
$20.1 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
2015
,
$19.0 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
$0.3 million
increase for natural gas decoupling revenues due primarily to the implementation of decoupling mechanisms in Idaho and Oregon.
|
|
Electric
Customers
|
|
Natural Gas
Customers
|
||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||
Residential
|
330,435
|
|
|
326,692
|
|
|
300,168
|
|
|
295,286
|
|
Commercial
|
41,830
|
|
|
41,176
|
|
|
34,792
|
|
|
34,110
|
|
Interruptible
|
—
|
|
|
—
|
|
|
35
|
|
|
36
|
|
Industrial
|
1,340
|
|
|
1,360
|
|
|
256
|
|
|
262
|
|
Public street and highway lighting
|
559
|
|
|
510
|
|
|
—
|
|
|
—
|
|
Total retail customers
|
374,164
|
|
|
369,738
|
|
|
335,251
|
|
|
329,694
|
|
•
|
an
$8.8 million
decrease in purchased power due to a decrease in the volume of power purchases (decreased costs
$2.6 million
) and a decrease in wholesale prices (decreased costs
$6.2 million
). The fluctuation in volumes and prices was primarily the result of our optimization activities during the quarter.
|
•
|
a
$2.1 million
increase from amortizations and deferrals of power costs.
|
•
|
a
$2.3 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
$2.0 million
increase in other regulatory amortizations.
|
•
|
a
$0.3 million
decrease in other electric resource costs.
|
•
|
a
$13.5 million
decrease in natural gas purchased due to a decrease in the price of natural gas (decreased costs
$9.6 million
) and a decrease in total therms purchased (decreased costs
$3.9 million
). Total therms purchased decreased due to a decrease in wholesale sales, partially offset by an increase in retail sales.
|
•
|
a
$0.5 million
increase from amortizations and deferrals of natural gas costs. This reflects lower natural gas prices and the deferral of lower costs which occurred in the current year for future rebate to customers.
|
•
|
a
$0.6 million
increase in other regulatory amortizations.
|
|
Electric
|
|
Natural Gas
|
|
Intracompany
|
|
Total
|
||||||||||||||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||||||||||
Operating revenues
|
$
|
735,361
|
|
|
$
|
742,984
|
|
|
$
|
319,700
|
|
|
$
|
378,094
|
|
|
$
|
(65,080
|
)
|
|
$
|
(78,165
|
)
|
|
$
|
989,981
|
|
|
$
|
1,042,913
|
|
Resource costs
|
258,147
|
|
|
292,942
|
|
|
187,846
|
|
|
264,827
|
|
|
(65,080
|
)
|
|
(78,165
|
)
|
|
380,913
|
|
|
479,604
|
|
||||||||
Gross margin
|
$
|
477,214
|
|
|
$
|
450,042
|
|
|
$
|
131,854
|
|
|
$
|
113,267
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
609,068
|
|
|
$
|
563,309
|
|
|
Electric Operating
Revenues |
||||||
|
2016
|
|
2015
|
||||
Washington
|
|
|
|
||||
Decoupling surcharge
|
$
|
8,900
|
|
|
$
|
(382
|
)
|
Provision for earnings sharing (1)
|
2,524
|
|
|
(1,500
|
)
|
||
Idaho
|
|
|
|
||||
Decoupling surcharge
|
$
|
4,516
|
|
|
n/a
|
|
|
Provision for earnings sharing (2)
|
711
|
|
|
(1,160
|
)
|
(1)
|
The provision for earnings sharing in Washington in the
nine months ended
September 30, 2016
resulted from a $2.5 million reduction in the 2015 provision for earnings sharing (which increased 2016 revenues). We are estimating no provision for earnings sharing for the full year of 2016 for electric operations.
|
(2)
|
The provision for earnings sharing in Idaho in the
nine months ended
September 30, 2016
resulted from a reduction in the 2015 provision for earnings sharing (which increased 2016 revenues). Beginning in 2016 there is no longer an earnings sharing mechanism in Idaho.
|
(n/a)
|
This mechanism did not exist during this time period.
|
•
|
a
$9.7 million
decrease in retail electric revenue due to a decrease in total MWhs sold (decreased revenues
$13.5 million
), partially offset by an increase in revenue per MWh (increased revenues
$3.8 million
).
|
◦
|
The increase in revenue per MWh was primarily due to a general rate increase in Idaho and the expiration of the ERM rebate to customers in Washington, partially offset by a general rate decrease in Washington.
|
◦
|
The decrease in total retail MWhs sold was the result of weather that was cooler in the first quarter (higher electric heating loads), warmer in April and May (lower electric heating loads) and cooler June through August (lower electric cooling loads) as compared to the prior year (which overall decreased electric loads), partially offset by customer growth. Compared to the
nine months ended
September 30, 2015
, residential electric use per customer decreased
2.6 percent
and commercial use per customer decreased
0.9 percent
. Heating degree days in Spokane were
15 percent
below normal and
1 percent
above the first
nine months
of
2015
. Year-to-date 2016 cooling degree days were
29 percent
above normal (mostly in June). However, cooling degree days were
41 percent
below the prior year.
|
•
|
an
$11.5 million
decrease in wholesale electric revenues due to a decrease in sales volumes (decreased revenues
$10.5 million
) and a decrease in sales prices (decreased revenues
$1.0 million
). The fluctuation in volumes and prices was primarily the result of our optimization activities.
|
•
|
a
$7.4 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, 2016
,
$30.1 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, 2015
,
$38.5 million
of these sales were made to our natural gas operations.
|
•
|
a
$5.9 million
decrease in the electric provision for earnings sharing (which increases revenues) due to a $2.5 million reduction in the 2015 provision for earnings sharing in Washington and a $0.7 million reduction in the 2015 provision for earnings sharing in Idaho recorded in 2016. This compares to provisions (which decreased revenues) of $1.5 million in Washington and $1.2 million in Idaho recorded for the nine months ended September 30, 2015.
|
•
|
a
$13.8 million
increase in electric revenue due to decoupling, which reflected the implementation of a decoupling (FCA) mechanism in Idaho effective January 1, 2016 and lower retail revenues in 2016 as compared to 2015.
|
|
Natural Gas Operating
Revenues |
||||||
|
2016
|
|
2015
|
||||
Washington
|
|
|
|
||||
Decoupling surcharge
|
$
|
7,142
|
|
|
$
|
5,413
|
|
Provision for earnings sharing
|
(359
|
)
|
|
—
|
|
||
Idaho
|
|
|
|
||||
Decoupling surcharge
|
$
|
2,044
|
|
|
n/a
|
|
|
Provision for earnings sharing
|
n/a
|
|
|
—
|
|
||
Oregon
|
|
|
|
||||
Decoupling surcharge
|
$
|
2,344
|
|
|
n/a
|
|
|
Provision for earnings sharing
|
—
|
|
|
—
|
|
(n/a)
|
This mechanism did not exist during this time period.
|
•
|
a
$10.1 million
decrease in natural gas retail revenues due to lower retail rates (decreased revenues
$16.5 million
), partially offset by an increase in volumes (increased revenues
$6.4 million
).
|
◦
|
Lower retail rates were due to PGAs, partially offset by general rate increases.
|
◦
|
We sold more retail natural gas in the
nine months ended
September 30, 2016
as compared to the
nine months ended
September 30, 2015
due to cooler weather in the first quarter and customer growth, partially offset by warmer weather in April and May. Compared to the first
nine months
of
2015
, residential natural gas use per customer increased
3 percent
and commercial use per customer increased
2 percent
. Heating degree days in Spokane were
15 percent
below normal and
1 percent
above the first
nine months
of
2015
. Heating degree days in Medford were
17 percent
below normal and
1 percent
below the first
nine months
of
2015
.
|
•
|
a
$54.4 million
decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues
$29.3 million
) and a decrease in volumes (decreased revenues
$25.1 million
). In the
nine months ended
September 30, 2016
,
$35.0 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, 2015
,
$39.6 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
$6.1 million
increase for natural gas decoupling revenues due primarily to the implementation of decoupling mechanisms in Idaho and Oregon, as well as an increase in the decoupling surcharge in Washington.
|
|
Electric
Customers
|
|
Natural Gas
Customers
|
||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||
Residential
|
330,018
|
|
|
326,318
|
|
|
300,033
|
|
|
295,275
|
|
Commercial
|
41,742
|
|
|
41,239
|
|
|
34,847
|
|
|
34,177
|
|
Interruptible
|
—
|
|
|
—
|
|
|
37
|
|
|
35
|
|
Industrial
|
1,345
|
|
|
1,356
|
|
|
256
|
|
|
262
|
|
Public street and highway lighting
|
556
|
|
|
527
|
|
|
—
|
|
|
—
|
|
Total retail customers
|
373,661
|
|
|
369,440
|
|
|
335,173
|
|
|
329,749
|
|
•
|
a
$23.0 million
decrease in purchased power due to a decrease in the volume of power purchases (decreased costs
$8.4 million
) and a decrease in wholesale prices (decreased costs
$14.6 million
). The fluctuation in volumes and prices was primarily the result of our optimization activities during the quarter.
|
•
|
a
$4.8 million
decrease from amortizations and deferrals of power costs.
|
•
|
an
$8.5 million
decrease in fuel for generation due to a decrease in thermal generation and a decrease in natural gas fuel prices.
|
•
|
an
$8.4 million
decrease in other fuel costs.
|
•
|
a
$5.4 million
increase in other electric resource costs primarily due to a benefit that was recorded during 2015 related to a capacity contract of Spokane Energy. This benefit was mostly deferred for probable future benefit to customers through the ERM and PCA.
|
•
|
a
$4.5 million
increase in other regulatory amortizations.
|
•
|
an
$85.2 million
decrease in natural gas purchased due to a decrease in the price of natural gas (decreased costs
$58.3 million
) and a decrease in total therms purchased (decreased costs
$26.9 million
). Total therms purchased decreased due to a decrease in wholesale sales, partially offset by an increase in retail sales.
|
•
|
a
$5.9 million
increase from amortizations and deferrals of natural gas costs. This reflects lower natural gas prices and the deferral of lower costs for future rebate to customers.
|
•
|
a
$2.3 million
increase in other regulatory amortizations.
|
|
September 30, 2016
|
|
December 31, 2015
|
||||||||||
|
Amount
|
|
Percent
of total
|
|
Amount
|
|
Percent
of total
|
||||||
Current portion of long-term debt and capital leases
|
$
|
3,257
|
|
|
0.1
|
%
|
|
$
|
93,167
|
|
|
2.9
|
%
|
Short-term borrowings
|
84,000
|
|
|
2.4
|
%
|
|
105,000
|
|
|
3.2
|
%
|
||
Long-term debt to affiliated trusts
|
51,547
|
|
|
1.5
|
%
|
|
51,547
|
|
|
1.6
|
%
|
||
Long-term debt and capital leases
|
1,678,257
|
|
|
48.7
|
%
|
|
1,480,111
|
|
|
45.4
|
%
|
||
Total debt
|
1,817,061
|
|
|
52.7
|
%
|
|
1,729,825
|
|
|
53.1
|
%
|
||
Total Avista Corporation shareholders’ equity
|
1,628,787
|
|
|
47.3
|
%
|
|
1,528,626
|
|
|
46.9
|
%
|
||
Total
|
$
|
3,445,848
|
|
|
100.0
|
%
|
|
$
|
3,258,451
|
|
|
100.0
|
%
|
|
2016
|
|
2015
|
||||
Borrowings outstanding at end of period
|
$
|
187,000
|
|
|
$
|
130,000
|
|
Letters of credit outstanding at end of period
|
$
|
73,195
|
|
|
$
|
43,812
|
|
Maximum borrowings outstanding during the period
|
$
|
205,000
|
|
|
$
|
137,500
|
|
Average borrowings outstanding during the period
|
$
|
138,296
|
|
|
$
|
84,013
|
|
Average interest rate on borrowings during the period
|
1.23
|
%
|
|
0.96
|
%
|
||
Average interest rate on borrowings at end of period
|
1.26
|
%
|
|
0.95
|
%
|
•
|
In April 2016, we entered into an agreement to invest in a company for a total of $10.0 million. The investment was $5.0 million for partial equity ownership in the company and $5.0 million in a short-term convertible loan. We issued the full $10.0 million to this company in April 2016.
|
•
|
In August 2016, we entered into a term loan agreement with a commercial bank in the amount of
$70.0 million
with a maturity date of December 30, 2016. We borrowed the entire
$70.0 million
available under this agreement, which was used to repay a portion of the
$90.0 million
of first mortgage bonds that matured in August 2016. See "Note 7 of the Notes to Condensed Consolidated Financial Statements" for further discussion of the term loan and its balance sheet classification.
|
•
|
In August 2016 we entered into a bond purchase agreement with five institutional investors in the private placement market for the issuance and sale of
$175.0 million
of Avista Corp. first mortgage bonds in December 2016. The first mortgage bonds will bear a coupon rate of
3.54 percent
and mature in
December 2051
. See "Note 7 of the Notes to Condensed Consolidated Financial Statements" for further discussion of the first mortgage bonds.
|
•
|
In September 2016, we entered into an agreement to invest up to $25.0 million in a private equity fund that invests in emerging technologies, products and services throughout the electricity supply chain from generation to consumption. The funding of this commitment will be required periodically over the next five years as capital calls are made by the fund manager. As of September 30, 2016, we have paid $2.1 million toward this commitment.
|
•
|
In September 2016, we entered into an agreement to replace all of our existing electric meters with new two-way digital meters and the related software and support services through our AMI project in Washington State. The total agreement provides for an estimated $49.3 million in equipment, software and professional services and $0.5 million in annual maintenance for a period of 15 years. The equipment will be installed over a four year period beginning in the second half of 2017. In addition to the meter agreement, we also have approximately $10.5 million in commitments to other vendors for meter data management software and associated integration services. See "Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations: Regulatory Matters: Washington General Rate Cases" for further discussion of the regulatory treatment of existing electric meters in Washington.
|
•
|
Ecology lacks statutory authority to regulate natural gas utilities, because the CAR holds them responsible for the indirect emissions of their customers;
|
•
|
Ecology does not have the authority to create an emission reduction trading program (ERUs); and
|
•
|
Ecology failed to comply with the requirements of the State Environmental Policy Act; and that the CAR is arbitrary and capricious.
|
|
Purchases
|
|
Sales
|
||||||||||||||||||||||||||||
|
Electric Derivatives
|
|
Gas Derivatives
|
|
Electric Derivatives
|
|
Gas Derivatives
|
||||||||||||||||||||||||
Year
|
Physical (1)
|
|
Financial (1)
|
|
Physical (1)
|
|
Financial (1)
|
|
Physical (1)
|
|
Financial (1)
|
|
Physical (1)
|
|
Financial (1)
|
||||||||||||||||
2016
|
$
|
(1,968
|
)
|
|
$
|
(1,918
|
)
|
|
$
|
(252
|
)
|
|
$
|
(9,555
|
)
|
|
$
|
24
|
|
|
$
|
3,755
|
|
|
$
|
(400
|
)
|
|
$
|
3,035
|
|
2017
|
(5,291
|
)
|
|
111
|
|
|
(801
|
)
|
|
(13,454
|
)
|
|
(636
|
)
|
|
3,542
|
|
|
(1,568
|
)
|
|
2,048
|
|
||||||||
2018
|
(5,591
|
)
|
|
—
|
|
|
—
|
|
|
(4,980
|
)
|
|
(45
|
)
|
|
(19
|
)
|
|
(1,115
|
)
|
|
644
|
|
||||||||
2019
|
(3,454
|
)
|
|
—
|
|
|
(228
|
)
|
|
(3,261
|
)
|
|
(17
|
)
|
|
—
|
|
|
(1,087
|
)
|
|
12
|
|
||||||||
2020
|
—
|
|
|
—
|
|
|
(259
|
)
|
|
(358
|
)
|
|
—
|
|
|
—
|
|
|
(1,290
|
)
|
|
—
|
|
||||||||
Thereafter
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(896
|
)
|
|
—
|
|
|
Purchases
|
|
Sales
|
||||||||||||||||||||||||||||
|
Electric Derivatives
|
|
Gas Derivatives
|
|
Electric Derivatives
|
|
Gas Derivatives
|
||||||||||||||||||||||||
Year
|
Physical (1)
|
|
Financial (1)
|
|
Physical (1)
|
|
Financial (1)
|
|
Physical (1)
|
|
Financial (1)
|
|
Physical (1)
|
|
Financial (1)
|
||||||||||||||||
2016
|
$
|
(6,928
|
)
|
|
$
|
(14,988
|
)
|
|
$
|
(5,895
|
)
|
|
$
|
(41,006
|
)
|
|
$
|
82
|
|
|
$
|
28,857
|
|
|
$
|
173
|
|
|
$
|
22,445
|
|
2017
|
(6,403
|
)
|
|
36
|
|
|
(1,050
|
)
|
|
(9,473
|
)
|
|
(23
|
)
|
|
3,971
|
|
|
(1,125
|
)
|
|
313
|
|
||||||||
2018
|
(5,614
|
)
|
|
—
|
|
|
—
|
|
|
(3,554
|
)
|
|
(50
|
)
|
|
—
|
|
|
(1,172
|
)
|
|
(162
|
)
|
||||||||
2019
|
(3,072
|
)
|
|
—
|
|
|
(22
|
)
|
|
(1,964
|
)
|
|
(44
|
)
|
|
—
|
|
|
(1,220
|
)
|
|
—
|
|
||||||||
2020
|
—
|
|
|
—
|
|
|
35
|
|
|
(18
|
)
|
|
—
|
|
|
—
|
|
|
(1,130
|
)
|
|
—
|
|
||||||||
Thereafter
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(679
|
)
|
|
—
|
|
(1)
|
Physical transactions represent commodity transactions in which 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, swaps, options, or forward contracts.
|
(a)
|
Not applicable
|
(b)
|
Not applicable
|
(c)
|
Not applicable
|
12
|
|
Computation of ratio of earnings to fixed charges*
|
15
|
|
Letter Re: Unaudited Interim Financial Information*
|
31.1
|
|
Certification of Chief Executive Officer (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002)*
|
31.2
|
|
Certification of Chief Financial Officer (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002)*
|
32
|
|
Certification of Corporate Officers (Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)**
|
101
|
|
The following financial information from the Quarterly Report on Form 10−Q for the period ended September 30, 2016, formatted in XBRL (Extensible Business Reporting Language) and filed electronically herewith: (i) the Condensed Consolidated Statements of Income; (ii) Condensed Consolidated Statements of Comprehensive Income; (iii) the Condensed Consolidated Balance Sheets; (iv) the Condensed Consolidated Statements of Cash Flows; (v) the Condensed Consolidated Statements of Equity; and (vi) the Notes to Condensed Consolidated Financial Statements.*
|
|
|
|
*
|
|
Filed herewith.
|
**
|
|
Furnished herewith.
|
|
|
|
AVISTA CORPORATION
|
|
|
|
(Registrant)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Date:
|
October 31, 2016
|
|
/s/ Mark T. Thies
|
|
|
|
Mark T. Thies
|
|
|
|
Senior Vice President,
Chief Financial Officer, and Treasurer
(Principal Financial Officer)
|
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