We could not find any results for:
Make sure your spelling is correct or try broadening your search.
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 | |
---|---|---|---|---|---|---|---|---|
0.00 | 0.00% | 36.64 | 0 | 09:00:01 |
x
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
¨
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
AVISTA CORPORATION
|
(Exact name of Registrant as specified in its charter)
|
Washington
|
|
91-0462470
|
(State or other jurisdiction of
incorporation or organization)
|
|
(I.R.S. Employer
Identification No.)
|
|
|
|
1411 East Mission Avenue, Spokane, Washington
|
|
99202-2600
|
(Address of principal executive offices)
|
|
(Zip Code)
|
None
|
(Former name, former address and former fiscal year, if changed since last report)
|
Large accelerated filer
|
x
|
Accelerated filer
|
¨
|
Non-accelerated filer
|
¨
(Do not check if a smaller reporting company)
|
Smaller reporting company
|
¨
|
Emerging growth company
|
¨
|
|
|
Item No.
|
|
|
Page
No.
|
|
|
|
|
|
|
||
|
|
||
|
|
||
Item 1.
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
|
|
Item 2.
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
|
|
||
|
|
||
|
|
|
|
Item 3.
|
|
||
|
|
|
|
Item 4.
|
|
||
|
|
|
|
|
|
||
Item 1.
|
|
||
|
|
|
|
Item 1A.
|
|
||
|
|
|
|
Item 2.
|
|
||
|
|
|
|
Item 4.
|
|
||
|
|
|
|
Item 6.
|
|
||
|
|
|
|
|
|
•
|
financial performance;
|
•
|
cash flows;
|
•
|
capital expenditures;
|
•
|
dividends;
|
•
|
capital structure;
|
•
|
other financial items;
|
•
|
strategic goals and objectives;
|
•
|
business environment; and
|
•
|
plans for operations.
|
•
|
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;
|
•
|
our ability to obtain financing through the issuance of debt and/or equity securities, which can be affected by various factors including our credit ratings, interest rates and other capital market conditions and the global economy;
|
•
|
changes in interest rates that affect borrowing costs, our ability to effectively hedge interest rates for anticipated debt issuances, variable interest rate borrowing and the extent to which we recover interest costs through retail rates collected from customers;
|
•
|
changes in actuarial assumptions, interest rates and the actual return on plan assets for our pension and other postretirement benefit plans, which can affect future funding obligations, pension and other postretirement benefit expense and the related liabilities;
|
•
|
deterioration in the creditworthiness of our customers;
|
•
|
the outcome of legal proceedings and other contingencies;
|
•
|
economic conditions in our service areas, including the economy's effects on customer demand for utility services;
|
•
|
declining energy demand related to customer energy efficiency and/or conservation measures;
|
•
|
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;
|
•
|
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;
|
•
|
possibility that our integrated resource plans for electric and natural gas will not be acknowledged by the state commissions;
|
•
|
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;
|
•
|
default or nonperformance on the part of any parties from whom we purchase and/or sell capacity or energy;
|
•
|
potential environmental regulations affecting our ability to utilize or resulting in the obsolescence of our power supply resources;
|
•
|
severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, earthquakes, snow and ice storms, that can disrupt energy generation, transmission and distribution, as well as the availability and costs of materials, equipment, supplies and support services;
|
•
|
explosions, fires, accidents, mechanical breakdowns or other incidents that may impair assets and may disrupt operations of any of our generation facilities, transmission, and electric and natural gas distribution systems or other operations and may require us to purchase replacement power;
|
•
|
wildfires caused by our electric transmission or distribution systems that may result in public injuries or property damage;
|
•
|
public injuries or damage arising from or allegedly arising from our operations;
|
•
|
blackouts or disruptions of interconnected transmission systems (the regional power grid);
|
•
|
terrorist attacks, cyber attacks or other malicious acts that may disrupt or cause damage to our utility assets or to the national or regional economy in general, including any effects of terrorism, cyber attacks or vandalism that damage or disrupt information technology systems;
|
•
|
work force issues, including changes in collective bargaining unit agreements, strikes, work stoppages, the loss of key executives, availability of workers in a variety of skill areas, and our ability to recruit and retain employees;
|
•
|
increasing costs of insurance, more restrictive coverage terms and our ability to obtain insurance;
|
•
|
delays or changes in construction costs, and/or our ability to obtain required permits and materials for present or prospective facilities;
|
•
|
increasing health care costs and cost of health insurance provided to our employees and retirees;
|
•
|
third party construction of buildings, billboard signs, towers or other structures within our rights of way, or placement of fuel receptacles within close proximity to our transformers or other equipment, including overbuild atop natural gas distribution lines;
|
•
|
the loss of key suppliers for materials or services or disruptions to the supply chain;
|
•
|
adverse impacts to our Alaska operations that could result from an extended outage of its hydroelectric generating resources or their inability to deliver energy, due to their lack of interconnectivity to any other electrical grids and the extensive cost of replacement power (diesel);
|
•
|
changing river regulation at hydroelectric facilities not owned by us, which could impact our hydroelectric facilities downstream;
|
•
|
compliance with extensive federal, state and local legislation and regulation, including numerous environmental, health, safety, infrastructure protection, reliability and other laws and regulations that affect our operations and costs;
|
•
|
the ability to comply with the terms of the licenses and permits for our hydroelectric or thermal generating facilities at cost-effective levels;
|
•
|
cyber attacks on us or our vendors or other potential lapses that result in unauthorized disclosure of private information, which could result in liabilities against us, costs to investigate, remediate and defend, and damage to our reputation;
|
•
|
disruption to or breakdowns of information systems, automated controls and other technologies that we rely on for our operations, communications and customer service;
|
•
|
changes in costs that impede our ability to effectively implement new information technology systems or to operate and maintain current production technology;
|
•
|
changes in technologies, possibly making some of the current technology we utilize obsolete or the introduction of new technology that may create new cyber security risk;
|
•
|
insufficient technology skills, which could lead to the inability to develop, modify or maintain our information systems;
|
•
|
growth or decline of our customer base and the extent to which new uses for our services may materialize or existing uses may decline, including, but not limited to, the effect of the trend toward distributed generation at customer sites;
|
•
|
the potential effects of negative publicity regarding business practices, whether true or not, which could result in litigation or a decline in our common stock price;
|
•
|
changes in our strategic business plans, which may be affected by any or all of the foregoing, including the entry into new businesses and/or the exit from existing businesses and the extent of our business development efforts where potential future business is uncertain;
|
•
|
non-regulated activities may increase earnings volatility;
|
•
|
failure to complete the proposed merger transaction could negatively impact the market price of Avista Corp.'s common stock or result in termination fees that could have a material adverse effect on our results of operations, financial condition, and cash flows;
|
•
|
the announced merger transaction could result in shareholder class action lawsuits against the Company, its management team and board of directors;
|
•
|
changes in environmental laws, regulations, decisions and policies, including present and potential environmental remediation costs and our compliance with these matters;
|
•
|
the potential effects of 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;
|
•
|
political pressures or regulatory practices that could constrain or place additional cost burdens on our distribution systems through accelerated adoption of distributed generation or electric-powered transportation or on our energy supply sources, such as campaigns to halt coal-fired power generation and opposition to other thermal generation, wind turbines or hydroelectric facilities;
|
•
|
wholesale and retail competition including alternative energy sources, growth in customer-owned power resource technologies that displace utility-supplied energy or that may be sold back to the utility, and alternative energy suppliers and delivery arrangements;
|
•
|
failure to identify changes in legislation, taxation and regulatory issues which are detrimental or beneficial to our overall business;
|
•
|
policy and/or legislative changes resulting from the new presidential administration in various regulated areas, including, but not limited to, potential tax reform, environmental regulation and healthcare regulations; and
|
•
|
the risk of municipalization in any of our service territories.
|
Avista Corporation
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
||||||||||||
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||||||
Operating Revenues:
|
|
|
|
|
|
|
|
||||||||
Utility revenues
|
$
|
308,729
|
|
|
$
|
312,888
|
|
|
$
|
739,266
|
|
|
$
|
725,681
|
|
Non-utility revenues
|
5,772
|
|
|
5,950
|
|
|
11,705
|
|
|
11,330
|
|
||||
Total operating revenues
|
314,501
|
|
|
318,838
|
|
|
750,971
|
|
|
737,011
|
|
||||
Operating Expenses:
|
|
|
|
|
|
|
|
||||||||
Utility operating expenses:
|
|
|
|
|
|
|
|
||||||||
Resource costs
|
102,751
|
|
|
109,815
|
|
|
268,337
|
|
|
271,534
|
|
||||
Other operating expenses
|
81,965
|
|
|
78,666
|
|
|
156,449
|
|
|
154,445
|
|
||||
Depreciation and amortization
|
42,643
|
|
|
39,678
|
|
|
84,628
|
|
|
78,870
|
|
||||
Taxes other than income taxes
|
23,802
|
|
|
22,615
|
|
|
56,464
|
|
|
52,000
|
|
||||
Non-utility operating expenses:
|
|
|
|
|
|
|
|
||||||||
Other operating expenses
|
7,086
|
|
|
6,281
|
|
|
13,265
|
|
|
12,106
|
|
||||
Depreciation and amortization
|
157
|
|
|
192
|
|
|
345
|
|
|
380
|
|
||||
Total operating expenses
|
258,404
|
|
|
257,247
|
|
|
579,488
|
|
|
569,335
|
|
||||
Income from operations
|
56,097
|
|
|
61,591
|
|
|
171,483
|
|
|
167,676
|
|
||||
Interest expense
|
23,670
|
|
|
21,318
|
|
|
47,215
|
|
|
42,591
|
|
||||
Interest expense to affiliated trusts
|
200
|
|
|
154
|
|
|
385
|
|
|
292
|
|
||||
Capitalized interest
|
(890
|
)
|
|
(837
|
)
|
|
(1,614
|
)
|
|
(1,751
|
)
|
||||
Other income-net
|
(1,656
|
)
|
|
(3,041
|
)
|
|
(4,757
|
)
|
|
(5,463
|
)
|
||||
Income before income taxes
|
34,773
|
|
|
43,997
|
|
|
130,254
|
|
|
132,007
|
|
||||
Income tax expense
|
13,051
|
|
|
16,710
|
|
|
46,395
|
|
|
47,055
|
|
||||
Net income
|
21,722
|
|
|
27,287
|
|
|
83,859
|
|
|
84,952
|
|
||||
Net loss (income) attributable to noncontrolling interests
|
49
|
|
|
(33
|
)
|
|
28
|
|
|
(49
|
)
|
||||
Net income attributable to Avista Corp. shareholders
|
$
|
21,771
|
|
|
$
|
27,254
|
|
|
$
|
83,887
|
|
|
$
|
84,903
|
|
Weighted-average common shares outstanding (thousands), basic
|
64,401
|
|
|
63,386
|
|
|
64,382
|
|
|
62,995
|
|
||||
Weighted-average common shares outstanding (thousands), diluted
|
64,553
|
|
|
63,783
|
|
|
64,511
|
|
|
63,368
|
|
||||
|
|
|
|
|
|
|
|
||||||||
Earnings per common share attributable to Avista Corp. shareholders:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
0.34
|
|
|
$
|
0.43
|
|
|
$
|
1.30
|
|
|
$
|
1.35
|
|
Diluted
|
$
|
0.34
|
|
|
$
|
0.43
|
|
|
$
|
1.30
|
|
|
$
|
1.34
|
|
Dividends declared per common share
|
$
|
0.3575
|
|
|
$
|
0.3425
|
|
|
$
|
0.7150
|
|
|
$
|
0.6850
|
|
Avista Corporation
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
||||||||||||
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||||||
Net income
|
$
|
21,722
|
|
|
$
|
27,287
|
|
|
$
|
83,859
|
|
|
$
|
84,952
|
|
Other Comprehensive Income (Loss):
|
|
|
|
|
|
|
|
||||||||
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $99, $76, $197 and $(587) respectively
|
183
|
|
|
140
|
|
|
366
|
|
|
(1,089
|
)
|
||||
Total other comprehensive income (loss)
|
183
|
|
|
140
|
|
|
366
|
|
|
(1,089
|
)
|
||||
Comprehensive income
|
21,905
|
|
|
27,427
|
|
|
84,225
|
|
|
83,863
|
|
||||
Comprehensive loss (income) attributable to noncontrolling interests
|
49
|
|
|
(33
|
)
|
|
28
|
|
|
(49
|
)
|
||||
Comprehensive income attributable to Avista Corporation shareholders
|
$
|
21,954
|
|
|
$
|
27,394
|
|
|
$
|
84,253
|
|
|
$
|
83,814
|
|
Avista Corporation
|
|
June 30,
|
|
December 31,
|
||||
|
2017
|
|
2016
|
||||
Assets:
|
|
|
|
||||
Current Assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
13,410
|
|
|
$
|
8,507
|
|
Accounts and notes receivable-less allowances of $5,607 and $5,026, respectively
|
133,946
|
|
|
180,265
|
|
||
Regulatory asset for energy commodity derivatives
|
13,982
|
|
|
11,365
|
|
||
Materials and supplies, fuel stock and stored natural gas
|
61,187
|
|
|
53,314
|
|
||
Income taxes receivable
|
35,808
|
|
|
48,265
|
|
||
Other current assets
|
62,403
|
|
|
49,625
|
|
||
Total current assets
|
320,736
|
|
|
351,341
|
|
||
Net Utility Property:
|
|
|
|
||||
Utility plant in service
|
5,617,233
|
|
|
5,506,499
|
|
||
Construction work in progress
|
169,000
|
|
|
150,474
|
|
||
Total
|
5,786,233
|
|
|
5,656,973
|
|
||
Less: Accumulated depreciation and amortization
|
1,558,773
|
|
|
1,509,473
|
|
||
Total net utility property
|
4,227,460
|
|
|
4,147,500
|
|
||
Other Non-current Assets:
|
|
|
|
||||
Investment in affiliated trusts
|
11,547
|
|
|
11,547
|
|
||
Goodwill
|
57,672
|
|
|
57,672
|
|
||
Other property and investments-net and other non-current assets
|
79,487
|
|
|
72,224
|
|
||
Total other non-current assets
|
148,706
|
|
|
141,443
|
|
||
Deferred Charges:
|
|
|
|
||||
Regulatory assets for deferred income tax
|
118,984
|
|
|
109,853
|
|
||
Regulatory assets for pensions and other postretirement benefits
|
234,046
|
|
|
240,114
|
|
||
Other regulatory assets
|
134,533
|
|
|
135,751
|
|
||
Regulatory asset for interest rate swaps
|
168,084
|
|
|
161,508
|
|
||
Non-current regulatory asset for energy commodity derivatives
|
15,023
|
|
|
16,919
|
|
||
Other deferred charges
|
5,432
|
|
|
5,326
|
|
||
Total deferred charges
|
676,102
|
|
|
669,471
|
|
||
Total assets
|
$
|
5,373,004
|
|
|
$
|
5,309,755
|
|
Avista Corporation
|
|
June 30,
|
|
December 31,
|
||||
|
2017
|
|
2016
|
||||
Liabilities and Equity:
|
|
|
|
||||
Current Liabilities:
|
|
|
|
||||
Accounts payable
|
$
|
69,165
|
|
|
$
|
115,545
|
|
Current portion of long-term debt and capital leases
|
277,814
|
|
|
3,287
|
|
||
Short-term borrowings
|
136,398
|
|
|
120,000
|
|
||
Energy commodity derivative liabilities
|
8,308
|
|
|
7,035
|
|
||
Accrued interest
|
16,128
|
|
|
15,869
|
|
||
Accrued taxes other than income taxes
|
33,169
|
|
|
33,374
|
|
||
Deferred natural gas costs
|
28,973
|
|
|
30,820
|
|
||
Current portion of pensions and other postretirement benefits
|
11,235
|
|
|
10,994
|
|
||
Current interest rate swap derivative liabilities
|
36,507
|
|
|
6,025
|
|
||
Other current liabilities
|
64,417
|
|
|
64,579
|
|
||
Total current liabilities
|
682,114
|
|
|
407,528
|
|
||
Long-term debt and capital leases
|
1,403,064
|
|
|
1,678,717
|
|
||
Long-term debt to affiliated trusts
|
51,547
|
|
|
51,547
|
|
||
Regulatory liability for utility plant retirement costs
|
280,580
|
|
|
273,983
|
|
||
Pensions and other postretirement benefits
|
219,584
|
|
|
226,552
|
|
||
Deferred income taxes
|
886,727
|
|
|
840,928
|
|
||
Non-current interest rate swap derivative liabilities
|
336
|
|
|
28,705
|
|
||
Other non-current liabilities, regulatory liabilities and deferred credits
|
162,158
|
|
|
153,319
|
|
||
Total liabilities
|
3,686,110
|
|
|
3,661,279
|
|
||
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; 64,408,983 and 64,187,934 shares issued and outstanding as of June 30, 2017 and December 31, 2016, respectively
|
1,075,667
|
|
|
1,075,281
|
|
||
Accumulated other comprehensive loss
|
(7,202
|
)
|
|
(7,568
|
)
|
||
Retained earnings
|
618,708
|
|
|
581,014
|
|
||
Total Avista Corporation shareholders’ equity
|
1,687,173
|
|
|
1,648,727
|
|
||
Noncontrolling Interests
|
(279
|
)
|
|
(251
|
)
|
||
Total equity
|
1,686,894
|
|
|
1,648,476
|
|
||
Total liabilities and equity
|
$
|
5,373,004
|
|
|
$
|
5,309,755
|
|
Avista Corporation
|
|
2017
|
|
2016
|
||||
Operating Activities:
|
|
|
|
||||
Net income
|
$
|
83,859
|
|
|
$
|
84,952
|
|
Non-cash items included in net income:
|
|
|
|
||||
Depreciation and amortization
|
86,790
|
|
|
81,071
|
|
||
Deferred income tax provision and investment tax credits
|
36,169
|
|
|
56,652
|
|
||
Power and natural gas cost amortizations, net
|
6,366
|
|
|
9,958
|
|
||
Amortization of debt expense
|
1,627
|
|
|
1,742
|
|
||
Amortization of investment in exchange power
|
1,225
|
|
|
1,225
|
|
||
Stock-based compensation expense
|
2,643
|
|
|
4,236
|
|
||
Equity-related Allowance for Funds Used During Construction (AFUDC)
|
(3,292
|
)
|
|
(4,368
|
)
|
||
Pension and other postretirement benefit expense
|
18,539
|
|
|
19,315
|
|
||
Amortization of Spokane Energy contract
|
—
|
|
|
7,192
|
|
||
Other regulatory assets and liabilities and deferred debits and credits
|
(8,831
|
)
|
|
(13,169
|
)
|
||
Change in decoupling regulatory deferral
|
10,365
|
|
|
(24,787
|
)
|
||
Other
|
420
|
|
|
5,032
|
|
||
Contributions to defined benefit pension plan
|
(14,800
|
)
|
|
(8,000
|
)
|
||
Changes in certain current assets and liabilities:
|
|
|
|
||||
Accounts and notes receivable
|
45,375
|
|
|
50,062
|
|
||
Materials and supplies, fuel stock and stored natural gas
|
(7,879
|
)
|
|
2,510
|
|
||
Collateral posted for derivative instruments
|
(5,460
|
)
|
|
(83,499
|
)
|
||
Income taxes receivable
|
12,457
|
|
|
(1,450
|
)
|
||
Other current assets
|
(3,825
|
)
|
|
(4,436
|
)
|
||
Accounts payable
|
(29,435
|
)
|
|
(31,484
|
)
|
||
Other current liabilities
|
(3,787
|
)
|
|
3,197
|
|
||
Net cash provided by operating activities
|
228,526
|
|
|
155,951
|
|
||
|
|
|
|
||||
Investing Activities:
|
|
|
|
||||
Utility property capital expenditures (excluding equity-related AFUDC)
|
(177,714
|
)
|
|
(182,815
|
)
|
||
Issuance of notes receivable at subsidiaries
|
(2,500
|
)
|
|
(9,668
|
)
|
||
Equity and property investments made by subsidiaries
|
(10,347
|
)
|
|
(6,988
|
)
|
||
Distributions received from investments
|
1,915
|
|
|
—
|
|
||
Other
|
(943
|
)
|
|
(7,153
|
)
|
||
Net cash used in investing activities
|
(189,589
|
)
|
|
(206,624
|
)
|
Avista Corporation
|
|
2017
|
|
2016
|
||||
Financing Activities:
|
|
|
|
||||
Net increase in short-term borrowings
|
$
|
16,000
|
|
|
$
|
55,000
|
|
Maturity of long-term debt and capital leases
|
(1,643
|
)
|
|
(1,583
|
)
|
||
Issuance of common stock, net of issuance costs
|
1,247
|
|
|
47,173
|
|
||
Cash dividends paid
|
(46,193
|
)
|
|
(43,267
|
)
|
||
Other
|
(3,445
|
)
|
|
(3,612
|
)
|
||
Net cash provided by (used in) financing activities
|
(34,034
|
)
|
|
53,711
|
|
||
|
|
|
|
||||
Net increase in cash and cash equivalents
|
4,903
|
|
|
3,038
|
|
||
|
|
|
|
||||
Cash and cash equivalents at beginning of period
|
8,507
|
|
|
10,484
|
|
||
|
|
|
|
||||
Cash and cash equivalents at end of period
|
$
|
13,410
|
|
|
$
|
13,522
|
|
Avista Corporation
|
|
2017
|
|
2016
|
||||
Common Stock, Shares:
|
|
|
|
||||
Shares outstanding at beginning of period
|
64,187,934
|
|
|
62,312,651
|
|
||
Shares issued
|
221,049
|
|
|
1,391,644
|
|
||
Shares outstanding at end of period
|
64,408,983
|
|
|
63,704,295
|
|
||
Common Stock, Amount:
|
|
|
|
||||
Balance at beginning of period
|
$
|
1,075,281
|
|
|
$
|
1,004,336
|
|
Equity compensation expense
|
2,559
|
|
|
3,708
|
|
||
Issuance of common stock, net of issuance costs
|
1,247
|
|
|
47,173
|
|
||
Payment of minimum tax withholdings for share-based payment awards
|
(3,420
|
)
|
|
(3,027
|
)
|
||
Balance at end of period
|
1,075,667
|
|
|
1,052,190
|
|
||
Accumulated Other Comprehensive Loss:
|
|
|
|
||||
Balance at beginning of period
|
(7,568
|
)
|
|
(6,650
|
)
|
||
Other comprehensive income (loss)
|
366
|
|
|
(1,089
|
)
|
||
Balance at end of period
|
(7,202
|
)
|
|
(7,739
|
)
|
||
Retained Earnings:
|
|
|
|
||||
Balance at beginning of period
|
581,014
|
|
|
530,940
|
|
||
Net income attributable to Avista Corporation shareholders
|
83,887
|
|
|
84,903
|
|
||
Cash dividends paid on common stock
|
(46,193
|
)
|
|
(43,267
|
)
|
||
Balance at end of period
|
618,708
|
|
|
572,576
|
|
||
Total Avista Corporation shareholders’ equity
|
1,687,173
|
|
|
1,617,027
|
|
||
Noncontrolling Interests:
|
|
|
|
||||
Balance at beginning of period
|
(251
|
)
|
|
(339
|
)
|
||
Net income (loss) attributable to noncontrolling interests
|
(28
|
)
|
|
49
|
|
||
Balance at end of period
|
(279
|
)
|
|
(290
|
)
|
||
Total equity
|
$
|
1,686,894
|
|
|
$
|
1,616,737
|
|
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
||||||||||||
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||||||
Utility related taxes
|
$
|
13,552
|
|
|
$
|
12,573
|
|
|
$
|
35,136
|
|
|
$
|
30,938
|
|
Property taxes
|
9,432
|
|
|
9,290
|
|
|
19,838
|
|
|
19,710
|
|
||||
Other taxes
|
818
|
|
|
752
|
|
|
1,490
|
|
|
1,352
|
|
||||
Total
|
$
|
23,802
|
|
|
$
|
22,615
|
|
|
$
|
56,464
|
|
|
$
|
52,000
|
|
|
June 30,
|
|
December 31,
|
||||
|
2017
|
|
2016
|
||||
Materials and supplies
|
$
|
41,492
|
|
|
$
|
40,700
|
|
Fuel stock
|
5,921
|
|
|
4,585
|
|
||
Stored natural gas
|
13,774
|
|
|
8,029
|
|
||
Total
|
$
|
61,187
|
|
|
$
|
53,314
|
|
|
June 30,
|
|
December 31,
|
||||
|
2017
|
|
2016
|
||||
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $3,878 and $4,075, respectively
|
$
|
7,202
|
|
|
$
|
7,568
|
|
|
|
Amounts Reclassified from Accumulated Other Comprehensive Loss
|
|
|
||||||||||||||
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
|
|
||||||||||||
Details about Accumulated Other Comprehensive Loss Components
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
Affected Line Item in Statement of Income
|
||||||||
Amortization of defined benefit pension items
|
|
|
|
|
|
|
|
|
||||||||||
Amortization of net prior service cost
|
|
$
|
(299
|
)
|
|
$
|
(311
|
)
|
|
$
|
(598
|
)
|
|
$
|
(622
|
)
|
|
(a)
|
Amortization of net loss
|
|
3,638
|
|
|
3,642
|
|
|
$
|
7,276
|
|
|
$
|
7,284
|
|
|
(a)
|
||
Adjustment due to effects of regulation
|
|
(3,057
|
)
|
|
(3,115
|
)
|
|
(6,115
|
)
|
|
(8,338
|
)
|
|
(a) (b)
|
||||
|
|
282
|
|
|
216
|
|
|
563
|
|
|
(1,676
|
)
|
|
Total before tax
|
||||
|
|
(99
|
)
|
|
(76
|
)
|
|
(197
|
)
|
|
587
|
|
|
Tax benefit (expense)
|
||||
|
|
$
|
183
|
|
|
$
|
140
|
|
|
$
|
366
|
|
|
$
|
(1,089
|
)
|
|
Net of tax
|
(a)
|
These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 4 for additional details).
|
(b)
|
The adjustment for the effects of regulation during the
six months ended
June 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 Condensed Consolidated Statements of Income rather than in Additional Paid in Capital (APIC),
|
•
|
excess tax benefits no longer represent a financing cash inflow on the Condensed Consolidated Statements of Cash Flows and instead will be included as an operating activity,
|
•
|
requiring excess tax benefits and tax deficiencies to be excluded from the calculation of diluted earnings per share, whereas under previous accounting guidance, these amounts had to 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.
|
|
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 |
||||||||
Remainder 2017
|
185
|
|
|
999
|
|
|
7,418
|
|
|
63,423
|
|
|
154
|
|
|
1,129
|
|
|
3,378
|
|
|
43,940
|
|
2018
|
397
|
|
|
307
|
|
|
—
|
|
|
78,488
|
|
|
254
|
|
|
1,244
|
|
|
1,360
|
|
|
46,805
|
|
2019
|
235
|
|
|
737
|
|
|
610
|
|
|
42,775
|
|
|
158
|
|
|
982
|
|
|
1,345
|
|
|
26,590
|
|
2020
|
—
|
|
|
—
|
|
|
910
|
|
|
3,635
|
|
|
—
|
|
|
—
|
|
|
1,430
|
|
|
—
|
|
2021
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,049
|
|
|
—
|
|
Thereafter
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
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 |
||||||||
2017
|
510
|
|
|
907
|
|
|
15,475
|
|
|
110,380
|
|
|
316
|
|
|
1,552
|
|
|
4,165
|
|
|
73,110
|
|
2018
|
397
|
|
|
—
|
|
|
—
|
|
|
52,755
|
|
|
286
|
|
|
1,244
|
|
|
1,360
|
|
|
15,113
|
|
2019
|
235
|
|
|
—
|
|
|
610
|
|
|
29,475
|
|
|
158
|
|
|
982
|
|
|
1,345
|
|
|
4,020
|
|
2020
|
—
|
|
|
—
|
|
|
910
|
|
|
2,725
|
|
|
—
|
|
|
—
|
|
|
1,430
|
|
|
—
|
|
2021
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,060
|
|
|
—
|
|
Thereafter
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
(1)
|
Physical transactions represent commodity transactions in which Avista Corp. will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of the benefit or cost but with no physical delivery of the commodity, such as futures, swap derivatives, options, or forward contracts.
|
|
June 30,
|
|
December 31,
|
||||
|
2017
|
|
2016
|
||||
Number of contracts
|
24
|
|
|
21
|
|
||
Notional amount (in United States dollars)
|
$
|
7,588
|
|
|
$
|
2,819
|
|
Notional amount (in Canadian dollars)
|
10,075
|
|
|
3,754
|
|
Balance Sheet Date
|
|
Number of Contracts
|
|
Notional Amount
|
|
Mandatory Cash Settlement Date
|
||
June 30, 2017
|
|
6
|
|
$
|
75,000
|
|
|
2017
|
|
|
14
|
|
275,000
|
|
|
2018
|
|
|
|
6
|
|
70,000
|
|
|
2019
|
|
|
|
3
|
|
30,000
|
|
|
2020
|
|
|
|
5
|
|
60,000
|
|
|
2022
|
|
December 31, 2016
|
|
6
|
|
$
|
75,000
|
|
|
2017
|
|
|
14
|
|
275,000
|
|
|
2018
|
|
|
|
6
|
|
70,000
|
|
|
2019
|
|
|
|
2
|
|
20,000
|
|
|
2020
|
|
|
|
5
|
|
60,000
|
|
|
2022
|
|
|
Fair Value as of June 30, 2017
|
||||||||||||||
Derivative and Balance Sheet Location
|
|
Gross
Asset
|
|
Gross
Liability
|
|
Collateral
Netted
|
|
Net Asset
(Liability)
on Balance
Sheet
|
||||||||
Foreign currency exchange derivatives
|
|
|
|
|
|
|
|
|
||||||||
Other current assets
|
|
$
|
187
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
187
|
|
Interest rate swap derivatives
|
|
|
|
|
|
|
|
|
||||||||
Other current assets
|
|
5,626
|
|
|
(208
|
)
|
|
—
|
|
|
5,418
|
|
||||
Other property and investments-net and other non-current assets
|
|
5,676
|
|
|
(1,645
|
)
|
|
—
|
|
|
4,031
|
|
||||
Current interest rate swap derivative liabilities
|
|
—
|
|
|
(78,077
|
)
|
|
41,570
|
|
|
(36,507
|
)
|
||||
Non-current interest rate swap derivative liabilities
|
|
—
|
|
|
(336
|
)
|
|
—
|
|
|
(336
|
)
|
||||
Energy commodity derivatives
|
|
|
|
|
|
|
|
|
||||||||
Other current assets
|
|
168
|
|
|
(11
|
)
|
|
—
|
|
|
157
|
|
||||
Current energy commodity derivative liabilities
|
|
22,577
|
|
|
(36,716
|
)
|
|
5,831
|
|
|
(8,308
|
)
|
||||
Other non-current liabilities, regulatory liabilities and deferred credits
|
|
12,532
|
|
|
(27,555
|
)
|
|
3,936
|
|
|
(11,087
|
)
|
||||
Total derivative instruments recorded on the balance sheet
|
|
$
|
46,766
|
|
|
$
|
(144,548
|
)
|
|
$
|
51,337
|
|
|
$
|
(46,445
|
)
|
|
|
Fair Value as of December 31, 2016
|
||||||||||||||
Derivative and Balance Sheet Location
|
|
Gross
Asset
|
|
Gross
Liability
|
|
Collateral
Netted |
|
Net Asset
(Liability) on Balance Sheet |
||||||||
Foreign currency exchange derivatives
|
|
|
|
|
|
|
|
|
||||||||
Other current liabilities
|
|
$
|
5
|
|
|
$
|
(28
|
)
|
|
$
|
—
|
|
|
$
|
(23
|
)
|
Interest rate swap derivatives
|
|
|
|
|
|
|
|
|
||||||||
Other current assets
|
|
3,393
|
|
|
—
|
|
|
—
|
|
|
3,393
|
|
||||
Other property and investments-net and other non-current assets
|
|
5,754
|
|
|
(397
|
)
|
|
—
|
|
|
5,357
|
|
||||
Current interest rate swap derivative liabilities
|
|
—
|
|
|
(15,756
|
)
|
|
9,731
|
|
|
(6,025
|
)
|
||||
Non-current interest rate swap derivative liabilities
|
|
3,951
|
|
|
(57,825
|
)
|
|
25,169
|
|
|
(28,705
|
)
|
||||
Energy commodity derivatives
|
|
|
|
|
|
|
|
|
||||||||
Other current assets
|
|
18,682
|
|
|
(16,787
|
)
|
|
—
|
|
|
1,895
|
|
||||
Current energy commodity derivative liabilities
|
|
16,335
|
|
|
(29,598
|
)
|
|
6,228
|
|
|
(7,035
|
)
|
||||
Other non-current liabilities, regulatory liabilities and deferred credits
|
|
13,071
|
|
|
(29,990
|
)
|
|
3,630
|
|
|
(13,289
|
)
|
||||
Total derivative instruments recorded on the balance sheet
|
|
$
|
61,191
|
|
|
$
|
(150,381
|
)
|
|
$
|
44,758
|
|
|
$
|
(44,432
|
)
|
|
June 30,
|
|
December 31,
|
||||
|
2017
|
|
2016
|
||||
Energy commodity derivatives
|
|
|
|
||||
Cash collateral posted
|
$
|
15,924
|
|
|
$
|
17,134
|
|
Letters of credit outstanding
|
37,250
|
|
|
24,400
|
|
||
Balance sheet offsetting (cash collateral against net derivative positions)
|
9,767
|
|
|
9,858
|
|
||
|
|
|
|
||||
Interest rate swap derivatives
|
|
|
|
||||
Cash collateral posted
|
41,570
|
|
|
34,900
|
|
||
Letters of credit outstanding
|
13,100
|
|
|
3,600
|
|
||
Balance sheet offsetting (cash collateral against net derivative positions)
|
41,570
|
|
|
34,900
|
|
|
June 30,
|
|
December 31,
|
||||
|
2017
|
|
2016
|
||||
Energy commodity derivatives
|
|
|
|
||||
Liabilities with credit-risk-related contingent features
|
$
|
648
|
|
|
$
|
1,124
|
|
Additional collateral to post
|
648
|
|
|
1,046
|
|
||
|
|
|
|
||||
Interest rate swap derivatives
|
|
|
|
||||
Liabilities with credit-risk-related contingent features
|
80,266
|
|
|
73,978
|
|
||
Additional collateral to post
|
11,210
|
|
|
21,100
|
|
|
Pension Benefits
|
|
Other Post-retirement Benefits
|
||||||||||||
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||||||
Three months ended June 30:
|
|
|
|
|
|
|
|
||||||||
Service cost
|
$
|
5,092
|
|
|
$
|
4,569
|
|
|
$
|
799
|
|
|
$
|
804
|
|
Interest cost
|
6,976
|
|
|
6,900
|
|
|
1,374
|
|
|
1,534
|
|
||||
Expected return on plan assets
|
(7,900
|
)
|
|
(6,875
|
)
|
|
(475
|
)
|
|
(475
|
)
|
||||
Amortization of prior service cost
|
—
|
|
|
—
|
|
|
(312
|
)
|
|
(312
|
)
|
||||
Net loss recognition
|
2,317
|
|
|
2,201
|
|
|
1,320
|
|
|
1,494
|
|
||||
Net periodic benefit cost
|
$
|
6,485
|
|
|
$
|
6,795
|
|
|
$
|
2,706
|
|
|
$
|
3,045
|
|
Six months ended June 30:
|
|
|
|
|
|
|
|
||||||||
Service cost
|
$
|
10,134
|
|
|
$
|
9,088
|
|
|
$
|
1,623
|
|
|
$
|
1,583
|
|
Interest cost
|
13,927
|
|
|
13,800
|
|
|
2,773
|
|
|
3,093
|
|
||||
Expected return on plan assets
|
(15,800
|
)
|
|
(13,625
|
)
|
|
(950
|
)
|
|
(950
|
)
|
||||
Amortization of prior service cost
|
—
|
|
|
—
|
|
|
(624
|
)
|
|
(624
|
)
|
||||
Net loss recognition
|
4,863
|
|
|
4,091
|
|
|
2,593
|
|
|
2,859
|
|
||||
Net periodic benefit cost
|
$
|
13,124
|
|
|
$
|
13,354
|
|
|
$
|
5,415
|
|
|
$
|
5,961
|
|
|
June 30,
|
|
December 31,
|
||||
|
2017
|
|
2016
|
||||
Borrowings outstanding at end of period
|
$
|
136,000
|
|
|
$
|
120,000
|
|
Letters of credit outstanding at end of period
|
$
|
56,703
|
|
|
$
|
34,353
|
|
Average interest rates at end of period
|
1.99
|
%
|
|
1.50
|
%
|
(1)
|
In December 2010,
$66.7 million
and
$17.0 million
of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) due in
2032
and
2034
, respectively, which had been held by Avista Corp. since 2008 and 2009, respectively, were refunded by new variable rate bond issues (Series 2010A and Series 2010B). The new bonds were not offered to the public and were purchased by Avista Corp. due to market conditions. The Company expects that at a later date, subject to market conditions, these bonds may be remarketed to unaffiliated investors. So long as Avista Corp. is the holder of these bonds, the bonds will not be reflected as an asset or a liability on Avista Corp.'s Consolidated Balance Sheets.
|
|
June 30,
|
|
December 31,
|
||
|
2017
|
|
2016
|
||
Low distribution rate
|
1.81
|
%
|
|
1.29
|
%
|
High distribution rate
|
2.08
|
%
|
|
1.81
|
%
|
Distribution rate at the end of the period
|
2.08
|
%
|
|
1.81
|
%
|
|
June 30, 2017
|
|
December 31, 2016
|
||||||||||||
|
Carrying
Value
|
|
Estimated
Fair Value
|
|
Carrying
Value
|
|
Estimated
Fair Value
|
||||||||
Long-term debt (Level 2)
|
$
|
951,000
|
|
|
$
|
1,076,925
|
|
|
$
|
951,000
|
|
|
$
|
1,048,661
|
|
Long-term debt (Level 3)
|
677,000
|
|
|
701,924
|
|
|
677,000
|
|
|
675,251
|
|
||||
Snettisham capital lease obligation (Level 3)
|
60,953
|
|
|
62,600
|
|
|
62,160
|
|
|
62,800
|
|
||||
Long-term debt to affiliated trusts (Level 3)
|
51,547
|
|
|
43,042
|
|
|
51,547
|
|
|
38,660
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Counterparty
and Cash Collateral Netting (1) |
|
Total
|
||||||||||
June 30, 2017
|
|
|
|
|
|
|
|
|
|
||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Energy commodity derivatives
|
$
|
—
|
|
|
$
|
35,198
|
|
|
$
|
—
|
|
|
$
|
(35,041
|
)
|
|
$
|
157
|
|
Level 3 energy commodity derivatives:
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural gas exchange agreement
|
—
|
|
|
—
|
|
|
79
|
|
|
(79
|
)
|
|
—
|
|
|||||
Foreign currency exchange derivatives
|
—
|
|
|
187
|
|
|
—
|
|
|
—
|
|
|
187
|
|
|||||
Interest rate swap derivatives
|
—
|
|
|
11,302
|
|
|
—
|
|
|
(1,853
|
)
|
|
9,449
|
|
|||||
Deferred compensation assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed income securities (2)
|
1,716
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,716
|
|
|||||
Equity securities (2)
|
6,067
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,067
|
|
|||||
Total
|
$
|
7,783
|
|
|
$
|
46,687
|
|
|
$
|
79
|
|
|
$
|
(36,973
|
)
|
|
$
|
17,576
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Energy commodity derivatives
|
$
|
—
|
|
|
$
|
46,203
|
|
|
$
|
—
|
|
|
$
|
(44,808
|
)
|
|
$
|
1,395
|
|
Level 3 energy commodity derivatives:
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural gas exchange agreement
|
—
|
|
|
—
|
|
|
4,252
|
|
|
(79
|
)
|
|
4,173
|
|
|||||
Power exchange agreement
|
—
|
|
|
—
|
|
|
13,784
|
|
|
—
|
|
|
13,784
|
|
|||||
Power option agreement
|
—
|
|
|
—
|
|
|
43
|
|
|
—
|
|
|
43
|
|
|||||
Interest rate swap derivatives
|
—
|
|
|
80,266
|
|
|
—
|
|
|
(43,423
|
)
|
|
36,843
|
|
|||||
Total
|
$
|
—
|
|
|
$
|
126,469
|
|
|
$
|
18,079
|
|
|
$
|
(88,310
|
)
|
|
$
|
56,238
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Counterparty
and Cash Collateral Netting (1) |
|
Total
|
||||||||||
December 31, 2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Energy commodity derivatives
|
$
|
—
|
|
|
$
|
47,994
|
|
|
$
|
—
|
|
|
$
|
(46,099
|
)
|
|
$
|
1,895
|
|
Level 3 energy commodity derivatives:
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural gas exchange agreement
|
—
|
|
|
—
|
|
|
69
|
|
|
(69
|
)
|
|
—
|
|
|||||
Power exchange agreement
|
—
|
|
|
—
|
|
|
25
|
|
|
(25
|
)
|
|
—
|
|
|||||
Foreign currency exchange derivatives
|
—
|
|
|
5
|
|
|
—
|
|
|
(5
|
)
|
|
—
|
|
|||||
Interest rate swap derivatives
|
—
|
|
|
13,098
|
|
|
—
|
|
|
(4,348
|
)
|
|
8,750
|
|
|||||
Deferred compensation assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed income securities (2)
|
1,789
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,789
|
|
|||||
Equity securities (2)
|
5,481
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,481
|
|
|||||
Total
|
$
|
7,270
|
|
|
$
|
61,097
|
|
|
$
|
94
|
|
|
$
|
(50,546
|
)
|
|
$
|
17,915
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Energy commodity derivatives
|
$
|
—
|
|
|
$
|
56,871
|
|
|
$
|
—
|
|
|
$
|
(55,957
|
)
|
|
$
|
914
|
|
Level 3 energy commodity derivatives:
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural gas exchange agreement
|
—
|
|
|
—
|
|
|
5,954
|
|
|
(69
|
)
|
|
5,885
|
|
|||||
Power exchange agreement
|
—
|
|
|
—
|
|
|
13,474
|
|
|
(25
|
)
|
|
13,449
|
|
|||||
Power option agreement
|
—
|
|
|
—
|
|
|
76
|
|
|
—
|
|
|
76
|
|
|||||
Foreign currency exchange derivatives
|
—
|
|
|
28
|
|
|
—
|
|
|
(5
|
)
|
|
23
|
|
|||||
Interest rate swap derivatives
|
—
|
|
|
73,978
|
|
|
—
|
|
|
(39,248
|
)
|
|
34,730
|
|
|||||
Total
|
$
|
—
|
|
|
$
|
130,877
|
|
|
$
|
19,504
|
|
|
$
|
(95,304
|
)
|
|
$
|
55,077
|
|
(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
|
|
|
|
|
|
|
||
|
|
June 30, 2017
|
|
Valuation Technique
|
|
Unobservable
Input
|
|
Range
|
||
Power exchange agreement
|
|
$
|
(13,784
|
)
|
|
Surrogate facility
pricing
|
|
O&M charges
|
|
$33.59-$49.15/MWh (1)
|
|
|
|
|
Escalation factor
|
|
3% - 2017 to 2019
|
||||
|
|
|
|
Transaction volumes
|
|
396,984 MWhs
|
||||
Power option agreement
|
|
$
|
(43
|
)
|
|
Black-Scholes-
Merton
|
|
Strike price
|
|
$35.92/MWh - 2019
|
|
|
|
|
|
$48.39/MWh - 2018
|
|||||
|
|
|
|
Delivery volumes
|
|
128,611 - 254,363 MWhs
|
||||
Natural gas exchange
agreement
|
|
$
|
(4,173
|
)
|
|
Internally derived
weighted average cost of gas |
|
Forward purchase
prices
|
|
$1.66 - $2.38/mmBTU
|
|
|
|
|
|
||||||
|
|
|
|
Forward sales prices
|
|
$1.67 - $3.29/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 June 30, 2017:
|
|
|
|
|
|
|
|
||||||||
Balance as of April 1, 2017
|
$
|
(4,278
|
)
|
|
$
|
(14,419
|
)
|
|
$
|
(266
|
)
|
|
$
|
(18,963
|
)
|
Total gains or (losses) (realized/unrealized):
|
|
|
|
|
|
|
|
||||||||
Included in regulatory assets/liabilities (1)
|
(195
|
)
|
|
(672
|
)
|
|
223
|
|
|
(644
|
)
|
||||
Settlements
|
300
|
|
|
1,307
|
|
|
—
|
|
|
1,607
|
|
||||
Ending balance as of June 30, 2017 (2)
|
$
|
(4,173
|
)
|
|
$
|
(13,784
|
)
|
|
$
|
(43
|
)
|
|
$
|
(18,000
|
)
|
Three months ended June 30, 2016:
|
|
|
|
|
|
|
|
||||||||
Balance as of April 1, 2016
|
$
|
(6,006
|
)
|
|
$
|
(20,193
|
)
|
|
$
|
(97
|
)
|
|
$
|
(26,296
|
)
|
Total gains or (losses) (realized/unrealized):
|
|
|
|
|
|
|
|
||||||||
Included in regulatory assets/liabilities (1)
|
(1,551
|
)
|
|
4,400
|
|
|
(8
|
)
|
|
2,841
|
|
||||
Settlements
|
700
|
|
|
1,179
|
|
|
—
|
|
|
1,879
|
|
||||
Ending balance as of June 30, 2016 (2)
|
$
|
(6,857
|
)
|
|
$
|
(14,614
|
)
|
|
$
|
(105
|
)
|
|
$
|
(21,576
|
)
|
Six months ended June 30, 2017:
|
|
|
|
|
|
|
|
||||||||
Balance as of January 1, 2017
|
$
|
(5,885
|
)
|
|
$
|
(13,449
|
)
|
|
$
|
(76
|
)
|
|
$
|
(19,410
|
)
|
Total gains or (losses) (realized/unrealized):
|
|
|
|
|
|
|
|
||||||||
Included in regulatory assets/liabilities (1)
|
1,817
|
|
|
(5,165
|
)
|
|
33
|
|
|
(3,315
|
)
|
||||
Settlements
|
(105
|
)
|
|
4,830
|
|
|
—
|
|
|
4,725
|
|
||||
Ending balance as of June 30, 2017 (2)
|
$
|
(4,173
|
)
|
|
$
|
(13,784
|
)
|
|
$
|
(43
|
)
|
|
$
|
(18,000
|
)
|
|
|
|
|
|
|
|
|
||||||||
Six months ended June 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)
|
(3,296
|
)
|
|
1,968
|
|
|
19
|
|
|
(1,309
|
)
|
||||
Settlements
|
1,478
|
|
|
5,379
|
|
|
—
|
|
|
6,857
|
|
||||
Ending balance as of June 30, 2016 (2)
|
$
|
(6,857
|
)
|
|
$
|
(14,614
|
)
|
|
$
|
(105
|
)
|
|
$
|
(21,576
|
)
|
|
|
|
|
|
|
|
|
(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 June 30,
|
|
Six months ended June 30,
|
||||||||||||
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||||||
Numerator:
|
|
|
|
|
|
|
|
||||||||
Net income attributable to Avista Corp. shareholders
|
$
|
21,771
|
|
|
$
|
27,254
|
|
|
$
|
83,887
|
|
|
$
|
84,903
|
|
Denominator:
|
|
|
|
|
|
|
|
||||||||
Weighted-average number of common shares outstanding-basic
|
64,401
|
|
|
63,386
|
|
|
64,382
|
|
|
62,995
|
|
||||
Effect of dilutive securities:
|
|
|
|
|
|
|
|
||||||||
Performance and restricted stock awards
|
152
|
|
|
397
|
|
|
129
|
|
|
373
|
|
||||
Weighted-average number of common shares outstanding-diluted
|
64,553
|
|
|
63,783
|
|
|
64,511
|
|
|
63,368
|
|
||||
Earnings per common share attributable to Avista Corp. shareholders:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
0.34
|
|
|
$
|
0.43
|
|
|
$
|
1.30
|
|
|
$
|
1.35
|
|
Diluted
|
$
|
0.34
|
|
|
$
|
0.43
|
|
|
$
|
1.30
|
|
|
$
|
1.34
|
|
|
Avista
Utilities
|
|
Alaska Electric Light and Power Company
|
|
Total Utility
|
|
Other
|
|
Intersegment
Eliminations
(1)
|
|
Total
|
||||||||||||
For the three months ended June 30, 2017:
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Operating revenues
|
$
|
296,747
|
|
|
$
|
11,982
|
|
|
$
|
308,729
|
|
|
$
|
5,772
|
|
|
$
|
—
|
|
|
$
|
314,501
|
|
Resource costs
|
99,461
|
|
|
3,290
|
|
|
102,751
|
|
|
—
|
|
|
—
|
|
|
102,751
|
|
||||||
Other operating expenses
|
78,970
|
|
|
2,995
|
|
|
81,965
|
|
|
7,086
|
|
|
—
|
|
|
89,051
|
|
||||||
Depreciation and amortization
|
41,195
|
|
|
1,448
|
|
|
42,643
|
|
|
157
|
|
|
—
|
|
|
42,800
|
|
||||||
Income (loss) from operations
|
53,971
|
|
|
3,597
|
|
|
57,568
|
|
|
(1,471
|
)
|
|
—
|
|
|
56,097
|
|
||||||
Interest expense (2)
|
22,826
|
|
|
895
|
|
|
23,721
|
|
|
176
|
|
|
(27
|
)
|
|
23,870
|
|
||||||
Income taxes
|
12,892
|
|
|
1,075
|
|
|
13,967
|
|
|
(916
|
)
|
|
—
|
|
|
13,051
|
|
||||||
Net income (loss) attributable to Avista Corp. shareholders
|
21,765
|
|
|
1,681
|
|
|
23,446
|
|
|
(1,675
|
)
|
|
—
|
|
|
21,771
|
|
||||||
Capital expenditures (3)
|
88,612
|
|
|
2,339
|
|
|
90,951
|
|
|
134
|
|
|
—
|
|
|
91,085
|
|
|
Avista
Utilities
|
|
Alaska Electric Light and Power Company
|
|
Total Utility
|
|
Other
|
|
Intersegment
Eliminations
(1)
|
|
Total
|
||||||||||||
For the three months ended June 30, 2016:
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Operating revenues
|
$
|
302,641
|
|
|
$
|
10,247
|
|
|
$
|
312,888
|
|
|
$
|
5,950
|
|
|
$
|
—
|
|
|
$
|
318,838
|
|
Resource costs
|
106,607
|
|
|
3,208
|
|
|
109,815
|
|
|
—
|
|
|
—
|
|
|
109,815
|
|
||||||
Other operating expenses
|
75,790
|
|
|
2,876
|
|
|
78,666
|
|
|
6,281
|
|
|
—
|
|
|
84,947
|
|
||||||
Depreciation and amortization
|
38,351
|
|
|
1,327
|
|
|
39,678
|
|
|
192
|
|
|
—
|
|
|
39,870
|
|
||||||
Income (loss) from operations
|
59,862
|
|
|
2,252
|
|
|
62,114
|
|
|
(523
|
)
|
|
—
|
|
|
61,591
|
|
||||||
Interest expense (2)
|
20,462
|
|
|
895
|
|
|
21,357
|
|
|
149
|
|
|
(34
|
)
|
|
21,472
|
|
||||||
Income taxes
|
16,349
|
|
|
676
|
|
|
17,025
|
|
|
(315
|
)
|
|
—
|
|
|
16,710
|
|
||||||
Net income (loss) attributable to Avista Corp. shareholders
|
26,771
|
|
|
1,058
|
|
|
27,829
|
|
|
(575
|
)
|
|
—
|
|
|
27,254
|
|
||||||
Capital expenditures (3)
|
88,048
|
|
|
5,889
|
|
|
93,937
|
|
|
46
|
|
|
—
|
|
|
93,983
|
|
||||||
For the six months ended June 30, 2017:
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Operating revenues
|
$
|
712,128
|
|
|
$
|
27,138
|
|
|
$
|
739,266
|
|
|
$
|
11,705
|
|
|
$
|
—
|
|
|
$
|
750,971
|
|
Resource costs
|
262,074
|
|
|
6,263
|
|
|
268,337
|
|
|
—
|
|
|
—
|
|
|
268,337
|
|
||||||
Other operating expenses
|
150,682
|
|
|
5,767
|
|
|
156,449
|
|
|
13,265
|
|
|
—
|
|
|
169,714
|
|
||||||
Depreciation and amortization
|
81,733
|
|
|
2,895
|
|
|
84,628
|
|
|
345
|
|
|
—
|
|
|
84,973
|
|
||||||
Income (loss) from operations
|
162,606
|
|
|
10,782
|
|
|
173,388
|
|
|
(1,905
|
)
|
|
—
|
|
|
171,483
|
|
||||||
Interest expense (2)
|
45,509
|
|
|
1,789
|
|
|
47,298
|
|
|
343
|
|
|
(41
|
)
|
|
47,600
|
|
||||||
Income taxes
|
43,909
|
|
|
3,538
|
|
|
47,447
|
|
|
(1,052
|
)
|
|
—
|
|
|
46,395
|
|
||||||
Net income (loss) attributable to Avista Corp. shareholders
|
80,204
|
|
|
5,534
|
|
|
85,738
|
|
|
(1,851
|
)
|
|
—
|
|
|
83,887
|
|
||||||
Capital expenditures (3)
|
174,015
|
|
|
3,699
|
|
|
177,714
|
|
|
169
|
|
|
—
|
|
|
177,883
|
|
||||||
For the six months ended June 30, 2016:
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Operating revenues
|
$
|
702,788
|
|
|
$
|
22,893
|
|
|
$
|
725,681
|
|
|
$
|
11,330
|
|
|
$
|
—
|
|
|
$
|
737,011
|
|
Resource costs
|
265,685
|
|
|
5,849
|
|
|
271,534
|
|
|
—
|
|
|
—
|
|
|
271,534
|
|
||||||
Other operating expenses
|
149,046
|
|
|
5,399
|
|
|
154,445
|
|
|
12,106
|
|
|
—
|
|
|
166,551
|
|
||||||
Depreciation and amortization
|
76,217
|
|
|
2,653
|
|
|
78,870
|
|
|
380
|
|
|
—
|
|
|
79,250
|
|
||||||
Income (loss) from operations
|
161,107
|
|
|
7,725
|
|
|
168,832
|
|
|
(1,156
|
)
|
|
—
|
|
|
167,676
|
|
||||||
Interest expense (2)
|
40,880
|
|
|
1,790
|
|
|
42,670
|
|
|
310
|
|
|
(97
|
)
|
|
42,883
|
|
||||||
Income taxes
|
45,021
|
|
|
2,571
|
|
|
47,592
|
|
|
(537
|
)
|
|
—
|
|
|
47,055
|
|
||||||
Net income (loss) attributable to Avista Corp. shareholders
|
81,758
|
|
|
4,019
|
|
|
85,777
|
|
|
(874
|
)
|
|
—
|
|
|
84,903
|
|
||||||
Capital expenditures (3)
|
172,483
|
|
|
10,332
|
|
|
182,815
|
|
|
165
|
|
|
—
|
|
|
182,980
|
|
||||||
Total Assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
As of June 30, 2017:
|
$
|
5,034,778
|
|
|
$
|
278,470
|
|
|
$
|
5,313,248
|
|
|
$
|
59,756
|
|
|
$
|
—
|
|
|
$
|
5,373,004
|
|
As of December 31, 2016:
|
$
|
4,975,555
|
|
|
$
|
273,770
|
|
|
$
|
5,249,325
|
|
|
$
|
60,430
|
|
|
$
|
—
|
|
|
$
|
5,309,755
|
|
(1)
|
Intersegment eliminations reported as interest expense represent intercompany interest.
|
(2)
|
Including interest expense to affiliated trusts.
|
(3)
|
The capital expenditures for the other businesses are included in other investing activities on the Condensed Consolidated Statements of Cash Flows.
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
||||||||||||
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||||||
Avista Utilities
|
$
|
21,765
|
|
|
$
|
26,771
|
|
|
$
|
80,204
|
|
|
$
|
81,758
|
|
AEL&P
|
1,681
|
|
|
1,058
|
|
|
5,534
|
|
|
4,019
|
|
||||
Other
|
(1,675
|
)
|
|
(575
|
)
|
|
(1,851
|
)
|
|
(874
|
)
|
||||
Net income attributable to Avista Corp. shareholders
|
$
|
21,771
|
|
|
$
|
27,254
|
|
|
$
|
83,887
|
|
|
$
|
84,903
|
|
•
|
seek recovery of operating costs and capital investments, and
|
•
|
seek the opportunity to earn reasonable returns as allowed by regulators.
|
|
|
Electric
|
|
Natural Gas
|
||||||||||
Effective Date
|
|
Proposed Revenue
Increase |
|
Proposed Base
Rate Increase |
|
Proposed Revenue
Increase
|
|
Proposed Base
Rate Increase
|
||||||
May 1, 2018 (1)
|
|
$
|
61.4
|
|
|
12.5
|
%
|
|
$
|
8.3
|
|
|
9.3
|
%
|
May 1, 2019 (2)
|
|
$
|
14.0
|
|
|
2.5
|
%
|
|
$
|
4.2
|
|
|
4.4
|
%
|
May 1, 2020 (2)
|
|
$
|
14.4
|
|
|
2.5
|
%
|
|
$
|
4.4
|
|
|
4.4
|
%
|
(1)
|
The $61.4 million electric revenue increase includes the $15.0 million power cost rate adjustment discussed above.
|
(2)
|
As a part of the electric rate plan, we have proposed to update power supply costs through a Power Supply Update, the effects of which would also go into effect on May 1, 2019 and May 1, 2020. The requested revenue increases for 2019 and 2020 do not include any power supply adjustments.
|
•
|
Major hydroelectric investments at the Little Falls and Nine Mile hydroelectric plants.
|
•
|
Generator maintenance at the Kettle Falls biomass plant that will ensure efficient generation and operations.
|
•
|
The ongoing project to systematically replace portions of natural gas distribution pipe in our service area that were installed prior to 1987, as well as replacement of other natural gas service equipment.
|
•
|
Transmission and distribution system and asset maintenance, such as wood pole replacements, feeder upgrades, and substation and transmission line rebuilds to maintain reliability for our customers.
|
•
|
Technology upgrades that support necessary business processes and operational efficiencies that allow us to effectively manage the utility and serve customers.
|
•
|
A refresh of the customer-facing website, providing relevant information, greater accessibility on mobile devices, easier navigation, and a streamlined payment experience.
|
|
|
Electric
|
|
Natural Gas
|
||||||||||
Effective Date
|
|
Proposed Revenue
Increase |
|
Proposed Base
Rate Increase |
|
Proposed Revenue
Increase
|
|
Proposed Base
Rate Increase
|
||||||
January 1, 2018
|
|
$
|
18.6
|
|
|
7.5
|
%
|
|
$
|
3.5
|
|
|
8.8
|
%
|
January 1, 2019 (1)
|
|
$
|
9.9
|
|
|
3.7
|
%
|
|
$
|
2.1
|
|
|
5.0
|
%
|
(1)
|
We are not proposing to update base power supply costs for year two of the rate plan, but rather have any differences flow through the PCA mechanism.
|
•
|
Generator maintenance at the Kettle Falls biomass plant that will ensure efficient generation and operations.
|
•
|
The ongoing project to systematically replace portions of natural gas distribution pipe in our service area that were installed prior to 1987, as well as replacement of other natural gas service equipment.
|
•
|
Transmission and distribution system and asset maintenance, such as wood pole replacements, feeder upgrades, and substation and transmission line rebuilds to maintain reliability for our customers.
|
•
|
Technology upgrades that support necessary business processes and operational efficiencies that allow us to effectively manage the utility and serve customers.
|
•
|
A refresh of the customer-facing website, providing relevant information, greater accessibility on mobile devices, easier navigation, and a streamlined payment experience.
|
|
June 30,
|
|
December 31,
|
||||
|
2017
|
|
2016
|
||||
Washington
|
|
|
|
||||
Decoupling surcharge
|
$
|
24,031
|
|
|
$
|
30,408
|
|
Provision for earnings sharing rebate
|
(5,860
|
)
|
|
(5,113
|
)
|
||
Idaho
|
|
|
|
||||
Decoupling surcharge
|
$
|
6,345
|
|
|
$
|
8,292
|
|
Provision for earnings sharing rebate
|
(3,731
|
)
|
|
(5,184
|
)
|
||
Oregon
|
|
|
|
||||
Decoupling surcharge (rebate)
|
$
|
(19
|
)
|
|
$
|
2,021
|
|
|
Electric
|
|
Natural Gas
|
|
Intracompany
|
|
Total
|
||||||||||||||||||||||||
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||||||||||||||
Operating revenues
|
$
|
230,558
|
|
|
$
|
234,791
|
|
|
$
|
80,430
|
|
|
$
|
80,955
|
|
|
$
|
(14,241
|
)
|
|
$
|
(13,105
|
)
|
|
$
|
296,747
|
|
|
$
|
302,641
|
|
Resource costs
|
69,427
|
|
|
73,350
|
|
|
44,275
|
|
|
46,362
|
|
|
(14,241
|
)
|
|
(13,105
|
)
|
|
99,461
|
|
|
106,607
|
|
||||||||
Gross margin
|
$
|
161,131
|
|
|
$
|
161,441
|
|
|
$
|
36,155
|
|
|
$
|
34,593
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
197,286
|
|
|
$
|
196,034
|
|
(1)
|
This balance includes public street and highway lighting, which is considered part of retail electric revenues and it also includes revenues and rebates from decoupling.
|
|
Electric Operating
Revenues |
||||||
|
2017
|
|
2016
|
||||
Washington
|
|
|
|
||||
Decoupling surcharge
|
$
|
3,661
|
|
|
$
|
4,553
|
|
Provision for earnings sharing (1)
|
(130
|
)
|
|
1,119
|
|
||
Idaho
|
|
|
|
||||
Decoupling surcharge
|
$
|
862
|
|
|
$
|
2,651
|
|
Provision for earnings sharing (2)
|
n/a
|
|
|
711
|
|
(1)
|
The provision for earnings sharing in Washington for the
second quarter
of 2017 represents an adjustment of the 2016 provision for earnings sharing. We are not expecting a provision for earnings sharing in Washington relating to 2017 earnings. The provision for earnings sharing in Washington in the
second quarter
of 2016 resulted from a $1.2 million reduction in the 2015 provision for earnings sharing (which increased 2016 revenues), partially offset by a $0.1 million provision for the second quarter of 2016.
|
(2)
|
The provision for earnings sharing in Idaho in the
second quarter
of 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.
|
•
|
a
$7.0 million
increase in retail electric revenue due to an increase in total MWhs sold (increased revenues
$3.8 million
) and an increase in revenue per MWh (increased revenues
$3.2 million
).
|
◦
|
The increase in total retail MWhs sold was the result of weather that was cooler than the prior year (which increased electric heating loads, partially offset by a decrease in cooling loads), as well as customer growth. Compared to the
second quarter
of
2016
, residential electric use per customer increased
6 percent
and commercial use per customer decreased
2 percent
. Heating degree days in Spokane were
12 percent
below normal, but
45 percent
above the
second quarter
of
2016
. Cooling degree days in Spokane were
54 percent
above normal, but
12 percent
below the
second quarter
of
2016
.
|
◦
|
The increase in revenue per MWh was primarily due to a general rate increase in Idaho and a greater portion of retail revenues from residential customers in the
second quarter
of 2017.
|
•
|
a
$10.1 million
decrease in wholesale electric revenues due to a decrease in sales prices (decreased revenues
$7.2 million
) and a decrease in sales volumes (decreased revenues
$2.9 million
). The fluctuation in volumes and prices was primarily the result of our optimization activities.
|
•
|
a
$1.1 million
increase in sales of fuel due to an increase in sales of natural gas fuel as part of thermal generation resource optimization activities. For the
second quarter
of
2017
,
$5.3 million
of these sales were made to our natural gas operations and are included as intracompany revenues and resource costs. For the
second quarter
of
2016
,
$8.0 million
of these sales were made to our natural gas operations.
|
•
|
a
$2.7 million
decrease in electric revenue due to decoupling. Weather was generally warmer than normal in both periods, which resulted in decoupling surcharges for both the second quarter of 2017 and 2016; however, the surcharges were larger during 2016 since the weather differed more from normal in 2016 than it did in 2017. Decoupling mechanisms are not impacted by fluctuations in weather compared to prior year, they are only impacted by weather fluctuations as compared to normal weather.
|
(1)
|
This balance includes interruptible and industrial revenues, which are considered part of retail natural gas revenues and it also includes revenues and rebates from decoupling.
|
|
Natural Gas Operating
Revenues |
||||||
|
2017
|
|
2016
|
||||
Washington
|
|
|
|
||||
Decoupling surcharge
|
$
|
30
|
|
|
$
|
3,595
|
|
Provision for earnings sharing
|
(617
|
)
|
|
(320
|
)
|
||
Idaho
|
|
|
|
||||
Decoupling surcharge (rebate)
|
$
|
(106
|
)
|
|
$
|
589
|
|
Oregon
|
|
|
|
||||
Decoupling surcharge (rebate)
|
$
|
(121
|
)
|
|
$
|
1,690
|
|
•
|
a
$10.3 million
increase in natural gas retail revenues due an increase in volumes (increased revenues
$14.4 million
), partially offset by lower retail rates (decreased revenues
$4.1 million
).
|
◦
|
We sold more retail natural gas in the
second quarter
of
2017
as compared to the
second quarter
of
2016
due to weather that was cooler than the prior year. Compared to the
second quarter
of
2016
, residential natural gas use per customer increased
39 percent
and commercial use per customer increased
33 percent
. Heating degree days in Spokane were
12 percent
below normal, but
45 percent
above the
second quarter
of 2016. Heating degree days in Medford were
11 percent
below normal, but
60 percent
above the
second quarter
of 2016.
|
◦
|
Lower retail rates were due to PGAs, partially offset by a general rate increase in Oregon.
|
•
|
a
$4.7 million
decrease in wholesale natural gas revenues due to a decrease in volumes (decreased revenues
$13.0 million
), partially offset by an increase in market prices (increased revenues
$8.3 million
). In the
second quarter
of
2017
,
$9.0 million
of these sales were made to our electric generation operations and are included as intracompany revenues and resource costs. In the
second quarter
of
2016
,
$5.1 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
decrease in natural gas revenue due to decoupling. Weather was generally warmer than normal during the second quarter 2017; however, due to the shape of the normal usage curve for natural gas in the decoupling mechanism, this resulted in a small rebate during the second quarter in Idaho and Oregon and a small net surcharge in Washington. This compares to significant decoupling surcharges in the
second quarter
of 2016. Decoupling mechanisms are not impacted by fluctuations in weather compared to prior year, they are only impacted by weather fluctuations as compared to normal weather.
|
|
Electric
Customers
|
|
Natural Gas
Customers
|
||||||||
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||
Residential
|
333,465
|
|
|
329,551
|
|
|
306,238
|
|
|
299,860
|
|
Commercial
|
42,074
|
|
|
41,732
|
|
|
35,197
|
|
|
34,867
|
|
Interruptible
|
—
|
|
|
—
|
|
|
38
|
|
|
37
|
|
Industrial (1)
|
1,328
|
|
|
1,346
|
|
|
250
|
|
|
255
|
|
Public street and highway lighting
|
558
|
|
|
559
|
|
|
—
|
|
|
—
|
|
Total retail customers
|
377,425
|
|
|
373,188
|
|
|
341,723
|
|
|
335,019
|
|
(1)
|
The decrease in electric industrial customers as compared to the
second quarter
of 2016 is primarily related to a decrease in Washington irrigation customers.
|
•
|
a
$7.3 million
decrease in purchased power due to a decrease in the volume of power purchases (decreased costs
$1.1 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
$5.5 million
decrease in fuel for generation primarily due to a decrease in thermal generation (due in part to increased hydroelectric generation).
|
•
|
a
$1.5 million
increase 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
|
•
|
a
$7.0 million
increase from amortizations and deferrals of power costs. This change was primarily to result of lower net power supply costs.
|
•
|
a
$0.2 million
net increase from other regulatory amortizations and other electric resource costs.
|
•
|
a
$5.4 million
increase in natural gas purchased due to an increase in the market price of natural gas (increased costs
$16.0 million
), partially offset by a decrease in total therms purchased (decreased costs
$10.6 million
). Total therms purchased decreased due to a decrease in wholesale sales, partially offset by an increase in retail sales.
|
•
|
a
$0.8 million
increase in other regulatory amortizations.
|
•
|
an
$8.3 million
decrease from amortizations and deferrals of natural gas costs. This reflects lower natural gas prices compared to our authorized PGA rates and the deferral of these lower costs, which occurred in the current quarter for future rebate to customers.
|
|
Electric
|
|
Natural Gas
|
|
Intracompany
|
|
Total
|
||||||||||||||||||||||||
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||||||||||||||
Operating revenues
|
$
|
494,276
|
|
|
$
|
497,593
|
|
|
$
|
250,642
|
|
|
$
|
236,365
|
|
|
$
|
(32,790
|
)
|
|
$
|
(31,170
|
)
|
|
$
|
712,128
|
|
|
$
|
702,788
|
|
Resource costs
|
160,302
|
|
|
167,702
|
|
|
134,562
|
|
|
129,153
|
|
|
(32,790
|
)
|
|
(31,170
|
)
|
|
262,074
|
|
|
265,685
|
|
||||||||
Gross margin
|
$
|
333,974
|
|
|
$
|
329,891
|
|
|
$
|
116,080
|
|
|
$
|
107,212
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
450,054
|
|
|
$
|
437,103
|
|
|
Electric Operating
Revenues |
||||||
|
2017
|
|
2016
|
||||
Washington
|
|
|
|
||||
Decoupling surcharge (rebate)
|
$
|
(1,461
|
)
|
|
$
|
8,634
|
|
Provision for earnings sharing (1)
|
(130
|
)
|
|
2,169
|
|
||
Idaho
|
|
|
|
||||
Decoupling surcharge (rebate)
|
$
|
(1,096
|
)
|
|
$
|
5,031
|
|
Provision for earnings sharing (2)
|
n/a
|
|
|
711
|
|
(1)
|
The provision for earnings sharing in Washington for the
six months ended
June 30, 2017
represents an adjustment of the 2016 provision for earnings sharing. We are not expecting a provision for earnings sharing in Washington relating to 2017 earnings. The provision for earnings sharing in Washington in the
six months ended
June 30, 2016
resulted from a $2.5 million reduction in the 2015 provision for earnings sharing (which increased 2016 revenues), partially offset by $0.3 million provision for the
six months ended
June 30, 2016
.
|
(2)
|
The provision for earnings sharing in Idaho in the
six months ended
June 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
$30.6 million
increase in retail electric revenue due to an increase in total MWhs sold (increased revenues
$22.2 million
) and an increase in revenue per MWh (increased revenues
$8.4 million
).
|
◦
|
The increase in total retail MWhs sold was the result of weather that was cooler than the prior year (which increased electric heating loads, partially offset by a decrease in cooling loads), as well as customer growth. Compared to the
six months ended
June 30, 2016
, residential electric use per customer increased
10.6 percent
and commercial use per customer increased
0.1 percent
. Heating degree days in Spokane were
6 percent
above normal and
29 percent
above the first
six months
of
2016
. Year-to-date 2016 cooling degree days were
54 percent
above normal (mostly in June). However, cooling degree days were
12 percent
below the prior year.
|
◦
|
The increase in revenue per MWh was primarily due to a general rate increase in Idaho and a greater portion of retail revenues from residential customers in 2017.
|
•
|
a
$19.4 million
decrease in wholesale electric revenues due to a decrease in sales volumes (decreased revenues
$6.8 million
) and a decrease in sales prices (decreased revenues
$12.6 million
). The fluctuation in volumes and prices was primarily the result of our optimization activities.
|
•
|
a
$0.8 million
increase in sales of fuel due to an increase in sales of natural gas fuel as part of thermal generation resource optimization activities. For the
six months ended
June 30, 2017
,
$13.3 million
of these sales were made to our natural gas operations and are included as intracompany revenues and resource costs. For the
six months ended
June 30, 2016
,
$16.3 million
of these sales were made to our natural gas operations.
|
•
|
a
$16.2 million
decrease in electric revenue due to decoupling. For the year-to-date, weather was overall cooler than normal in 2017, which resulted in decoupling rebates for the first half of 2017. Weather was warmer than normal in the first half of 2016, which resulted in significant decoupling surcharges. Decoupling mechanisms are not impacted by fluctuations in weather compared to prior year, they are only impacted by weather fluctuations as compared to normal weather.
|
|
Natural Gas Operating
Revenues |
||||||
|
2017
|
|
2016
|
||||
Washington
|
|
|
|
||||
Decoupling surcharge (rebate)
|
$
|
(5,221
|
)
|
|
$
|
6,766
|
|
Provision for earnings sharing
|
(617
|
)
|
|
(536
|
)
|
||
Idaho
|
|
|
|
||||
Decoupling surcharge (rebate)
|
$
|
(883
|
)
|
|
$
|
2,126
|
|
Oregon
|
|
|
|
||||
Decoupling surcharge (rebate)
|
$
|
(2,050
|
)
|
|
$
|
1,858
|
|
•
|
a
$33.5 million
increase in natural gas retail revenues due to an increase in volumes (increased revenues
$43.3 million
), partially offset by lower retail rates (decreased revenues
$9.8 million
).
|
◦
|
We sold more retail natural gas in the
six months ended
June 30, 2017
as compared to the
six months ended
June 30, 2016
due to cooler weather and customer growth. Compared to the first
six months
of
2016
, residential natural gas use per customer increased
28 percent
and commercial use per customer increased
29 percent
. Heating degree days in Spokane were
6 percent
above normal and
29 percent
above the first
six months
of
2016
. Heating degree days in Medford were
3 percent
below normal, but
24 percent
above the first
six months
of
2016
.
|
◦
|
Lower retail rates were due to PGAs, partially offset by a general rate increase in Oregon.
|
•
|
a
$1.0 million
decrease in wholesale natural gas revenues due to a decrease in volumes (decreased revenues
$22.6 million
), mostly offset by an increase in prices (increased revenues
$21.6 million
). In the
six months ended
June 30, 2017
,
$19.5 million
of these sales were made to our electric generation operations and are included as intracompany revenues and resource costs. In the
six months ended
June 30, 2016
,
$14.9 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.
|
•
|
an
$18.9 million
decrease in natural gas revenue due to decoupling. For the year-to-date, weather was overall cooler than normal in 2017, which resulted in decoupling rebates for the first half of 2017. Weather was warmer than normal in the first half of 2016, which resulted in significant decoupling surcharges. Decoupling mechanisms are not impacted by fluctuations in weather compared to prior year, they are only impacted by weather fluctuations as compared to normal weather.
|
|
Electric
Customers
|
|
Natural Gas
Customers
|
||||||||
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||
Residential
|
333,885
|
|
|
329,810
|
|
|
306,231
|
|
|
299,966
|
|
Commercial
|
42,070
|
|
|
41,698
|
|
|
35,217
|
|
|
34,874
|
|
Interruptible
|
—
|
|
|
—
|
|
|
37
|
|
|
38
|
|
Industrial (1)
|
1,327
|
|
|
1,347
|
|
|
251
|
|
|
256
|
|
Public street and highway lighting
|
562
|
|
|
555
|
|
|
—
|
|
|
—
|
|
Total retail customers
|
377,844
|
|
|
373,410
|
|
|
341,736
|
|
|
335,134
|
|
(1)
|
The decrease in electric industrial customers as compared to the first half of 2016 is primarily related to a decrease in Washington irrigation customers.
|
•
|
a
$7.0 million
decrease in purchased power due to a decrease in wholesale prices (decreased costs
$7.5 million
), partially offset by an increase in the volume of power purchases (increased costs
$0.5 million
). The fluctuation in volumes and prices was primarily the result of our optimization activities during the period.
|
•
|
an
$11.5 million
decrease in fuel for generation primarily due to a decrease in thermal generation (due in part to increased hydroelectric generation).
|
•
|
a
$2.3 million
increase in other fuel costs.
|
•
|
an
$8.2 million
increase from amortizations and deferrals of power costs. This change was primarily to result of lower
|
•
|
a
$0.6 million
increase in other regulatory amortizations and other electric resource costs.
|
•
|
a
$13.7 million
increase in natural gas purchased due to an increase in the price of natural gas (increased costs
$24.0 million
), partially offset by a decrease in total therms purchased (decreased costs
$10.3 million
). Total therms purchased decreased due to a decrease in wholesale sales, partially offset by an increase in retail sales.
|
•
|
an
$11.8 million
decrease from amortizations and deferrals of natural gas costs. This reflects lower natural gas prices compared to our authorized PGA rates and the deferral of these lower costs, which occurred in the current period for future rebate to customers.
|
•
|
a
$3.5 million
increase in other regulatory amortizations.
|
•
|
short-term borrowings increased by
$16.0 million
in the first half of 2017, compared to an increase of
$55.0 million
in 2016,
|
•
|
cash dividends paid to Avista Corp. shareholders increased to
$46.2 million
(or
$0.715
per share) for the first half of
2017
from
$43.3 million
(or
$0.685
per share) for the first half of
2016
, and
|
•
|
issuance of
$1.2 million
(net of issuance costs) under share-based compensation plans. In 2016, we issued
$47.2 million
of common stock under sales agency agreements.
|
|
June 30, 2017
|
|
December 31, 2016
|
||||||||||
|
Amount
|
|
Percent
of total
|
|
Amount
|
|
Percent
of total
|
||||||
Current portion of long-term debt and capital leases
|
$
|
277,814
|
|
|
7.8
|
%
|
|
$
|
3,287
|
|
|
0.1
|
%
|
Short-term borrowings
|
136,398
|
|
|
3.8
|
%
|
|
120,000
|
|
|
3.4
|
%
|
||
Long-term debt to affiliated trusts
|
51,547
|
|
|
1.5
|
%
|
|
51,547
|
|
|
1.5
|
%
|
||
Long-term debt and capital leases
|
1,403,064
|
|
|
39.5
|
%
|
|
1,678,717
|
|
|
47.9
|
%
|
||
Total debt
|
1,868,823
|
|
|
52.6
|
%
|
|
1,853,551
|
|
|
52.9
|
%
|
||
Total Avista Corporation shareholders’ equity
|
1,687,173
|
|
|
47.4
|
%
|
|
1,648,727
|
|
|
47.1
|
%
|
||
Total
|
$
|
3,555,996
|
|
|
100.0
|
%
|
|
$
|
3,502,278
|
|
|
100.0
|
%
|
|
2017
|
|
2016
|
||||
Borrowings outstanding at end of period
|
$
|
136,000
|
|
|
$
|
160,000
|
|
Letters of credit outstanding at end of period
|
$
|
56,703
|
|
|
$
|
45,795
|
|
Maximum borrowings outstanding during the period
|
$
|
136,000
|
|
|
$
|
160,000
|
|
Average borrowings outstanding during the period
|
$
|
105,157
|
|
|
$
|
118,832
|
|
Average interest rate on borrowings during the period
|
1.67
|
%
|
|
1.22
|
%
|
||
Average interest rate on borrowings at end of period
|
1.99
|
%
|
|
1.22
|
%
|
|
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)
|
||||||||||||||||
Remainder 2017
|
$
|
(2,485
|
)
|
|
$
|
456
|
|
|
$
|
(732
|
)
|
|
$
|
(14,207
|
)
|
|
$
|
(70
|
)
|
|
$
|
1,995
|
|
|
$
|
(213
|
)
|
|
$
|
5,808
|
|
2018
|
(6,880
|
)
|
|
(347
|
)
|
|
—
|
|
|
(9,416
|
)
|
|
(24
|
)
|
|
4,234
|
|
|
(870
|
)
|
|
3,402
|
|
||||||||
2019
|
(4,321
|
)
|
|
(1,168
|
)
|
|
(280
|
)
|
|
(6,160
|
)
|
|
(19
|
)
|
|
4,569
|
|
|
(891
|
)
|
|
1,557
|
|
||||||||
2020
|
—
|
|
|
—
|
|
|
(357
|
)
|
|
(489
|
)
|
|
—
|
|
|
—
|
|
|
(1,256
|
)
|
|
—
|
|
||||||||
2021
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(840
|
)
|
|
—
|
|
||||||||
Thereafter
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
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)
|
||||||||||||||||
2017
|
$
|
(4,274
|
)
|
|
$
|
1,939
|
|
|
$
|
97
|
|
|
$
|
(4,005
|
)
|
|
$
|
(225
|
)
|
|
$
|
576
|
|
|
$
|
(2,036
|
)
|
|
$
|
(3,440
|
)
|
2018
|
(5,598
|
)
|
|
—
|
|
|
—
|
|
|
(2,170
|
)
|
|
(33
|
)
|
|
854
|
|
|
(910
|
)
|
|
709
|
|
||||||||
2019
|
(3,123
|
)
|
|
—
|
|
|
(235
|
)
|
|
(3,732
|
)
|
|
(40
|
)
|
|
975
|
|
|
(927
|
)
|
|
103
|
|
||||||||
2020
|
—
|
|
|
—
|
|
|
(266
|
)
|
|
(370
|
)
|
|
—
|
|
|
—
|
|
|
(1,288
|
)
|
|
—
|
|
||||||||
2021
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(869
|
)
|
|
—
|
|
||||||||
Thereafter
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
(1)
|
Physical transactions represent commodity transactions where we will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of the benefit or cost but with no physical delivery of the commodity, such as futures, swap derivatives, options, or forward contracts.
|
(a)
|
Not applicable
|
(b)
|
Not applicable
|
(c)
|
Not applicable
|
2.1
|
|
Agreement and Plan of Merger, dated as of July 19, 2017, by and among Avista Corporation, Hydro One Limited, Olympus Holding Corp. and Olympus Corp. (1)
|
12
|
|
Computation of ratio of earnings to fixed charges (2)
|
15
|
|
Letter Re: Unaudited Interim Financial Information (2)
|
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) (2)
|
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) (2)
|
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) (3)
|
101
|
|
The following financial information from the Quarterly Report on Form 10−Q for the period ended June 30, 2017, 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. (2)
|
|
|
|
(1
|
)
|
Previously filed as exhibit 2.1 to the registrant's Current Report on Form 8-K, filed as of July 19, 2017 and incorporated herein by reference.
|
(2
|
)
|
Filed herewith.
|
(3
|
)
|
Furnished herewith.
|
|
|
|
AVISTA CORPORATION
|
|
|
|
(Registrant)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Date:
|
August 1, 2017
|
|
/s/ Mark T. Thies
|
|
|
|
Mark T. Thies
|
|
|
|
Senior Vice President,
Chief Financial Officer, and Treasurer
(Principal Financial Officer)
|
1 Year Avista Chart |
1 Month Avista Chart |
It looks like you are not logged in. Click the button below to log in and keep track of your recent history.
Support: +44 (0) 203 8794 460 | support@advfn.com
By accessing the services available at ADVFN you are agreeing to be bound by ADVFN's Terms & Conditions