UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
__________________________________________________________________________________________
Form 10-K
(Mark One)
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE FISCAL YEAR ENDED December 31, 2013 OR
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE TRANSITION PERIOD FROM TO
Commission file number 1-3701
__________________________________________________________________________________________
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) | |
Registrant’s telephone number, including area code: 509-489-0500
Web site: http://www.avistacorp.com
Securities registered pursuant to Section 12(b) of the Act:
| Title of Class | Name of Each Exchange on Which Registered | |
| Common Stock, no par value | New York Stock Exchange | |
Securities registered pursuant to Section 12(g) of the Act:
Title of Class
Preferred Stock, Cumulative, Without Par Value
__________________________________________________________________________________________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days: Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
| Large accelerated filer | x | Accelerated filer | ¨ |
| Non-accelerated filer | ¨ (Do not check if a smaller reporting company) | Smaller reporting company | ¨ |
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yes ¨ No x
The aggregate market value of the Registrant’s outstanding Common Stock, no par value (the only class of voting stock), held by non-affiliates is $1,620,660,221 based on the last reported sale price thereof on the consolidated tape on June 30, 2013.
As of January 31, 2014, 60,111,948 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.
__________________________________________________________________________________________
Documents Incorporated By Reference
| Document | Part of Form 10-K into Which Document is Incorporated | |
Proxy Statement to be filed in connection with the annual meeting of shareholders to be held on May 8, 2014. Prior to such filing, the Proxy Statement filed in connection with the annual meeting of shareholders held on May 9, 2013. | Part III, Items 10, 11, 12, 13 and 14 | |
INDEX
Item No. | Page No. | |||
| Part I | ||||
| 1 | ||||
| 1A. | ||||
| 1B. | ||||
| 2 | ||||
| 3 | ||||
| 4 | * | |||
| Part II | ||||
| 5 | ||||
| 6 | ||||
| 7 | ||||
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| 7A. | ||||
| 8. | ||||
| 9. | * | |||
| 9A. | ||||
| 9B. | ||||
| Part III | ||||
| 10. | ||||
| 11. | ||||
| 12. | ||||
| 13. | ||||
| 14. | ||||
| Part IV | ||||
| 15. | ||||
* = not an applicable item in the 2013 calendar year for Avista Corp.
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ACRONYMS AND TERMS
(The following acronyms and terms are found in multiple locations within the document)
| Acronym/Term | Meaning | |
| aMW | - | Average Megawatt - a measure of the average rate at which a particular generating source produces energy over a period of time |
| AEL&P | - | Alaska Electric Light & Power Company, the primary operating subsidiary of AERC |
| AERC | - | Alaska Energy and Resources Company, a privately-held company based in Juneau, Alaska. The Company entered into an agreement and plan of merger with AERC on November 4, 2013. |
| AFUDC | - | Allowance for Funds Used During Construction; represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period |
| AM&D | - | Advanced Manufacturing and Development, does business as METALfx |
| ASC | - | Accounting Standards Codification |
| Avista Capital | - | Parent company to the Company’s non-utility businesses |
| Avista Corp. | - | Avista Corporation, the Company |
| Avista Energy | - | Avista Energy, Inc., an electricity and natural gas marketing, trading and resource management business, subsidiary of Avista Capital. This entity is currently inactive; however, we still incur legal fees associated with this entity. |
| Avista Utilities | - | Operating division of Avista Corp. comprising the regulated utility operations |
| BPA | - | Bonneville Power Administration |
| Capacity | - | The rate at which a particular generating source is capable of producing energy, measured in KW or MW |
| Cabinet Gorge | - | The Cabinet Gorge Hydroelectric Generating Project, located on the Clark Fork River in Idaho |
| Colstrip | - | The coal-fired Colstrip Generating Plant in southeastern Montana |
| Coyote Springs 2 | - | The natural gas-fired Coyote Springs 2 Generating Plant located near Boardman, Oregon |
| CT | - | Combustion turbine |
| Deadband or ERM deadband | - | The first $4.0 million in annual power supply costs above or below the amount included in base retail rates in Washington under the Energy Recovery Mechanism in the state of Washington |
| Dekatherm | - | Unit of measurement for natural gas; a dekatherm is equal to approximately one thousand cubic feet (volume) or 1,000,000 BTUs (energy) |
| Ecology | - | The state of Washington’s Department of Ecology |
| Ecova | - | Ecova, Inc., a provider of facility information and cost management services for multi-site customers and energy efficiency program management for commercial enterprises and utilities throughout North America, subsidiary of Avista Capital. Formerly known as Advantage IQ, Inc. (Advantage IQ) |
| Energy | - | The amount of electricity produced or consumed over a period of time, measured in KWH or MWH. Also, refers to natural gas consumed and is measured in dekatherms. |
| EPA | - | Environmental Protection Agency |
| ERM | - | The Energy Recovery Mechanism, a mechanism for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Washington |
| FASB | - | Financial Accounting Standards Board |
| FERC | - | Federal Energy Regulatory Commission |
| GAAP | - | Generally Accepted Accounting Principles |
| GHG | - | Greenhouse gas |
| IPUC | - | Idaho Public Utilities Commission |
| IRP | - | Integrated Resource Plan |
| Jackson Prairie | - | Jackson Prairie Natural Gas Storage Project, an underground natural gas storage field located near Chehalis, Washington |
| kV | - | Kilovolt (1000 volts): a measure of capacity on transmission lines |
| KW, KWH | - | Kilowatt (1000 watts): a measure of generating output or capability. Kilowatt-hour (1000 watt hours): a measure of energy produced. |
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| Lancaster Plant | - | A natural gas-fired combined cycle combustion turbine plant located in Idaho |
| MPSC | - | Public Service Commission of the State of Montana |
| MW, MWH | - | Megawatt: 1000 KW. Megawatt-hour: 1000 KWH. |
| NERC | - | North American Electricity Reliability Corporation |
| Noxon Rapids | - | The Noxon Rapids Hydroelectric Generating Project, located on the Clark Fork River in Montana |
| OPUC | - | The Public Utility Commission of Oregon |
| PCA | - | The Power Cost Adjustment mechanism, a procedure for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Idaho |
| PGA | - | Purchased Gas Adjustment |
| PLP | - | Potentially liable party |
| PUD | - | Public Utility District |
| PURPA | - | The Public Utility Regulatory Policies Act of 1978, as amended |
| RCA | - | The Regulatory Commission of Alaska |
| RTO | - | Regional Transmission Organization |
| Spokane Energy | - | Spokane Energy, LLC, a special purpose limited liability company and all of its membership capital is owned by Avista Corp. |
| Spokane River Project | - | The five hydroelectric plants operating under one FERC license on the Spokane River (Long Lake, Nine Mile, Upper Falls, Monroe Street and Post Falls) |
| Therm | - | Unit of measurement for natural gas; a therm is equal to approximately one hundred cubic feet (volume) or 100,000 BTUs (energy) |
| UTC | - | Washington Utilities and Transportation Commission |
| Watt | - | Unit of measurement for electricity; a watt is equal to the rate of work represented by a current of one ampere under a pressure of one volt |
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Forward-Looking Statements
From time to time, we make forward-looking statements such as statements regarding projected or future:
| • | financial performance; |
| • | cash flows; |
| • | capital expenditures; |
| • | dividends; |
| • | capital structure; |
| • | other financial items; |
| • | strategic goals and objectives; |
| • | business environment; and |
| • | plans for operations. |
These statements have underlying assumptions (many of which are based, in turn, upon further assumptions). Such statements are made both in our reports filed under the Securities Exchange Act of 1934, as amended (including this Annual Report on Form 10-K), and elsewhere. Forward-looking statements are all statements except those of historical fact including, without limitation, those that are identified by the use of words that include “will,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “forecasts,” “projects,” “predicts,” and similar expressions.
Forward-looking statements (including those made in this Annual Report on Form 10-K) are subject to a variety of risks and uncertainties and other factors. Most of these factors are beyond our control and may have a significant effect on our operations, results of operations, financial condition or cash flows, which could cause actual results to differ materially from those anticipated in our statements. Such risks, uncertainties and other factors include, among others:
| • | weather conditions (temperatures, precipitation levels and wind patterns) which affect energy demand and electric generation, 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 impacts on supply and demand in the wholesale energy markets; |
| • | state and federal regulatory decisions that affect our ability to recover costs and earn a reasonable return including, but not limited to, disallowance or delay in the recovery of capital investments and operating costs and discretion over allowed return on investment; |
| • | changes in wholesale energy prices that can affect operating income, cash requirements to purchase electricity and natural gas, value received for wholesale sales, collateral required of us by counterparties on wholesale energy transactions and credit risk to us from such transactions, and the market value of derivative assets and liabilities; |
| • | economic conditions in our service areas, including the economy's effects on customer demand for utility services; |
| • | declining energy demand related to customer energy efficiency and/or conservation measures; |
| • | our ability to obtain financing through the issuance of debt and/or equity securities, which can be affected by various factors including our credit ratings, interest rates and other capital market conditions and the global economy; |
| • | the potential effects of legislation or administrative rulemaking, including possible effects on our generating resources of restrictions on greenhouse gas emissions to mitigate concerns over global climate changes; |
| • | political pressures or regulatory practices that could constrain or place additional cost burdens on our energy supply sources, such as campaigns to halt coal-fired power generation and opposition to other thermal generation, wind turbines or hydroelectric facilities; |
| • | changes in actuarial assumptions, interest rates and the actual return on plan assets for our pension and other postretirement benefit plans, which can affect future funding obligations, pension and other postretirement benefit expense and the related liabilities; |
| • | volatility and illiquidity in wholesale energy markets, including the availability of willing buyers and sellers, and prices of purchased energy and demand for energy sales including related energy commodity derivative instruments that we rely upon to hedge our wholesale energy risks; |
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| • | the outcome of pending regulatory and legal proceedings arising out of the “western energy crisis” of 2000 and 2001, including possible refunds; |
| • | the outcome of legal proceedings and other contingencies; |
| • | changes in environmental and endangered species laws, regulations, decisions and policies, including present and potential environmental remediation costs and our compliance with these matters; |
| • | wholesale and retail competition including alternative energy sources, growth in customer-owned power resource technologies that displace utility-supplied energy or that may be sold back to the utility, and alternative energy suppliers and delivery arrangements; |
| • | growth or decay of our customer base and the extent that new uses for our services may materialize or existing uses may decline; |
| • | the ability to comply with the terms of the licenses for our hydroelectric generating facilities at cost-effective levels; |
| • | severe weather or natural disasters that can disrupt energy generation, transmission and distribution, as well as the availability and costs of materials, equipment, supplies and support services; |
| • | explosions, fires, accidents, mechanical breakdowns, or other incidents that may impair assets and may disrupt operations of any of our generation facilities, transmission and distribution systems or other operations; |
| • | public injuries or damage arising from or allegedly arising from our operations; |
| • | blackouts or disruptions of interconnected transmission systems (the regional power grid); |
| • | disruption to information systems, automated controls and other technologies that we rely on for our operations, communications and customer service; |
| • | terrorist attacks, cyber attacks or other malicious acts that may disrupt or cause damage to our utility assets or to the national economy in general, including any effects of terrorism, cyber attacks or vandalism that damage or disrupt information technology systems; |
| • | cyber attacks or other potential lapses that result in unauthorized disclosure of private information, which could result in liabilities against us, costs to investigate, remediate and defend, and damage to our reputation; |
| • | delays or changes in construction costs, and/or our ability to obtain required permits and materials for present or prospective facilities; |
| • | changes in the costs to implement new information technology systems and/or obstacles that impede our ability to complete such projects timely and effectively; |
| • | changes in the long-term global and Pacific Northwest climates, which can affect, among other things, customer demand patterns and the volume and timing of streamflows to our hydroelectric resources; |
| • | changes in industrial, commercial and residential growth and demographic patterns in our service territory or changes in demand by significant customers; |
| • | the loss of key suppliers for materials or services or disruptions to the supply chain; |
| • | default or nonperformance on the part of any parties from which we purchase and/or sell capacity or energy; |
| • | deterioration in the creditworthiness of our customers; |
| • | potential decline in our credit ratings, with effects including impeded access to capital markets, higher interest costs, and restrictive covenants in our financing arrangements and wholesale energy contracts; |
| • | increasing health care costs and the resulting effect on employee injury costs and health insurance provided to our employees and retirees; |
| • | increasing costs of insurance, more restrictive coverage terms and our ability to obtain insurance; |
| • | work force issues, including changes in collective bargaining unit agreements, strikes, work stoppages, the loss of key executives, availability of workers in a variety of skill areas, and our ability to recruit and retain employees; |
| • | the potential effects of negative publicity regarding business practices, whether true or not, which could result in litigation or a decline in our common stock price; |
| • | changes in technologies, possibly making some of the current technology obsolete; |
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| • | changes in tax rates and/or policies; |
| • | changes in interest rates that affect borrowing costs, our ability to effectively hedge interest rates for anticipated debt issuances, variable interest rate borrowing and the extent that we recover interest costs through utility operations; |
| • | changes in the payment acceptance policies of Ecova’s client vendors that could reduce operating revenues; |
| • | potential difficulties in integrating acquired operations and in realizing expected opportunities, diversions of management resources and losses of key employees, challenges with respect to operating new businesses and other unanticipated risks and liabilities; and |
| • | 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. |
Our expectations, beliefs and projections are expressed in good faith. We believe they are reasonable based on, without limitation, an examination of historical operating trends, our records and other information available from third parties. However, there can be no assurance that our expectations, beliefs or projections will be achieved or accomplished. Furthermore, any forward-looking statement speaks only as of the date on which such statement is made. We undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New risks, uncertainties and other factors emerge from time to time, and it is not possible for us to predict all such factors, nor can we assess the effect of each such factor on our business or the extent that any such factor or combination of factors may cause actual results to differ materially from those contained in any forward-looking statement.
Available Information
Our Web site address is www.avistacorp.com. We make annual, quarterly and current reports available at our Web site as soon as practicable after electronically filing these reports with the Securities and Exchange Commission. Information contained on our Web site is not part of this report.
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PART I
Item 1. Business
Company Overview
Avista Corporation (Avista Corp. or the Company), incorporated in the territory of Washington in 1889, is an energy company engaged in the generation, transmission and distribution of electricity and the distribution of natural gas, as well as other energy-related businesses. As of December 31, 2013, we employed 1,643 people in our utility operations and 1,667 people in our subsidiary businesses. Our corporate headquarters are in Spokane, Washington, the second-largest city in Washington. Spokane serves as the business, transportation, medical, industrial and cultural hub of the Inland Northwest region (eastern Washington and northern Idaho). Regional services include government and higher education, medical services, retail trade and finance. The Inland Northwest also coincides closely with our utility service area in Washington and Idaho. Our gas utility operations also include separate service areas in parts of Oregon.
We have two reportable business segments as follows:
| • | Avista Utilities – an operating division of Avista Corp. that comprises our regulated utility operations. Avista Utilities generates, transmits and distributes electricity and distributes natural gas serving electric and gas customers in eastern Washington and northern Idaho and gas customers in parts of Oregon. The utility also engages in wholesale purchases and sales of electricity and natural gas. |
| • | Ecova – an indirect subsidiary of Avista Corp. (80.2 percent owned as of December 31, 2013) that provides energy efficiency and cost management programs and services for multi-site customers and utilities throughout North America. Ecova's service lines include expense management services for utility and telecom needs as well as strategic energy management and efficiency services that include procurement, conservation, performance reporting, financial planning, facility optimization and continuous monitoring, and energy efficiency program management for commercial enterprises and utilities. |
We have other businesses, including a sheet metal fabrication business, emerging technology venture fund investments and commercial real estate investments, as well as Spokane Energy, LLC (Spokane Energy). These activities do not represent a reportable business segment and are conducted by various indirect subsidiaries of Avista Corp.
Ecova and various other companies are subsidiaries of Avista Capital, Inc. (Avista Capital) which is a direct, wholly owned subsidiary of Avista Corp. Total Avista Corp. shareholders’ equity was $1,298.3 million as of December 31, 2013, of which $112.2 million represented our investment in Avista Capital. Additionally, Ecova represents $81.9 million of our investment in Avista Capital.
See “Item 6. Selected Financial Data” and “Note 23 of the Notes to Consolidated Financial Statements” for information with respect to the operating performance of each business segment (and other subsidiaries).
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Avista Utilities
General
Through our regulated utility operations, we generate, transmit and distribute electricity and distribute natural gas. Retail electric and natural gas customers include residential, commercial and industrial classifications. We also engage in wholesale purchases and sales of electricity and natural gas as an integral part of energy resource management and our load-serving obligation.
Our utility provides electric distribution and transmission, as well as natural gas distribution, services in parts of eastern Washington and northern Idaho. We also provide natural gas distribution service in parts of northeastern and southwestern Oregon. At the end of 2013, we supplied retail electric service to 366,000 customers and retail natural gas service to 326,000 customers across our entire service territory. Our service territory covers 30,000 square miles with a population of 1.6 million. Certain of our generating facilities are located in Montana, and we supply electricity to a small number of customers in Montana, most of whom are employees who operate one of such facilities. See “Item 2. Properties” for further information on our utility assets. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Economic Conditions and Utility Load Growth” for information on economic conditions in our service territory.
Electric Operations
In addition to providing electric distribution and transmission services, we generate electricity from facilities that we own and we purchase capacity, energy and fuel for generation under long-term and short-term contracts. We also sell electric capacity and energy, as well as surplus fuel in the wholesale market in connection with our resource optimization activities as described below.
As part of our resource procurement and management operations in the electric business, we engage in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve our load obligations and the use of these resources to capture available economic value. We transact business in the wholesale markets by selling and purchasing electric capacity and energy, fuel for electric generation, and derivative instruments related to capacity, energy, transport and fuel. Such transactions are part of the process of matching resources with our load obligations and hedging the related financial risks. These transactions range from terms of intra-hour up to multiple years. We make continuing projections of:
| • | electric loads at various points in time (ranging from intra-hour to multiple years) based on, among other things, estimates of customer usage and weather, historical data and contract terms, and |
| • | resource availability at these points in time based on, among other things, fuel choices and fuel markets, estimates of streamflows, availability of generating units, historic and forward market information, contract terms, and experience. |
On the basis of these projections, we make purchases and sales of electric capacity and energy, fuel for electric generation, and related derivative instruments to match expected resources to expected electric load requirements and reduce our exposure to electricity (or fuel) market price changes. Resource optimization involves generating plant dispatch and scheduling available resources and also includes transactions such as:
| • | purchasing fuel for generation, |
| • | when economical, selling fuel and substituting wholesale electric purchases, and |
| • | other wholesale transactions to capture the value of generation and transmission resources and fuel delivery (transport) capacity contracts. |
Our optimization process includes entering into hedging transactions to manage risks. Transactions include both physical energy contracts and related derivative instruments.
Our generation assets are interconnected through the regional transmission system and are operated on a coordinated basis to enhance load-serving capability and reliability. We provide transmission and ancillary services in eastern Washington, northern Idaho and western Montana. Transmission revenues were $26.5 million in 2013, $12.7 million in 2012 and $13.8 million in 2011. Transmission revenues for 2013 include $11.7 million from the BPA for past use of our electric transmission system.
Electric Requirements
Our peak electric native load requirement for 2013 occurred on December 8, 2013 at which time our total obligation was 2,223 MW consisting of:
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| • | native load of 1,669 MW, |
| • | long-term wholesale obligations of 223 MW, and |
| • | short-term wholesale obligations of 331 MW. |
At that time our maximum resource capacity available was 2,767 MW, which included:
| • | company-owned or controlled electric generation of 1,703 MW, |
| • | long-term hydroelectric contracts with certain Public Utility Districts (PUDs) of 156 MW, |
| • | long-term thermal generation contract with Lancaster Plant of 281 MW, |
| • | other long-term wholesale contracts of 151 MW, and |
| • | short-term wholesale purchases of 476 MW. |
Electric Resources
We have a diverse electric resource mix of Company-owned and contracted hydroelectric projects, thermal generating facilities, wind generation facilities, and power purchases and exchanges.
At the end of 2013, our Company-owned facilities had a total net capability of 1,844 MW, of which 55 percent was hydroelectric and 45 percent was thermal. See “Item 2. Properties” for detailed information on generating facilities.
Hydroelectric Resources We own and operate six hydroelectric projects on the Spokane River and two hydroelectric projects on the Clark Fork River. Hydroelectric generation is our lowest cost source per megawatt-hour (MWh) of electricity and the availability of hydroelectric generation has a significant effect on total power supply costs. Under normal streamflow and operating conditions, we estimate that we would be able to meet approximately one-half of our total average electric requirements (both retail and long-term wholesale) with the combination of our hydroelectric generation and long-term hydroelectric purchase contracts with certain PUDs in the state of Washington. Our estimate of normal annual hydroelectric generation for 2014 (including resources purchased under long-term hydroelectric contracts with certain PUDs) is 533 average megawatts (aMW) (or 4.7 million MWhs). Hydroelectric resources provided 527 aMW for 2013, 583 aMW for 2012 and 637 aMW for 2011.
The following table shows our hydroelectric generation (in thousands of MWhs) during the year ended December 31:
| 2013 | 2012 | 2011 | ||||||
| Noxon Rapids | 1,581 | 1,823 | 2,110 | |||||
| Cabinet Gorge | 1,042 | 1,199 | 1,292 | |||||
| Post Falls | 85 | 83 | 90 | |||||
| Upper Falls | 68 | 60 | 73 | |||||
| Monroe Street | 105 | 102 | 110 | |||||
| Nine Mile | 83 | 106 | 90 | |||||
| Long Lake | 505 | 513 | 556 | |||||
| Little Falls | 177 | 202 | 213 | |||||
| Total company-owned hydroelectric generation | 3,646 | 4,088 | 4,534 | |||||
| Long-term hydroelectric contracts with PUDs | 970 | 1,022 | 1,047 | |||||
| Total hydroelectric generation | 4,616 | 5,110 | 5,581 | |||||
| Normal hydroelectric generation (1) | 4,678 | 4,761 | 4,520 | |||||
| Percentage of normal | 99 | % | 107 | % | 123 | % | ||
| (1) | Normal hydroelectric generation is determined by applying an upstream regulation calculation to median natural water flow information. Natural water flow is the flow of the rivers without the influence of dams, whereas regulated water flow takes into account any water flows changes from upstream dams due to releasing or holding back water. The calculation of normal varies annually due to the timing of upstream dam regulation throughout the year. |
Thermal Resources We own:
| • | the combined cycle combustion turbine (CT) natural gas-fired Coyote Springs 2 Generation Project (Coyote Springs 2) located near Boardman, Oregon, |
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| • | a 15 percent interest in a twin-unit, coal-fired boiler generating facility, the Colstrip 3 & 4 Generating Project (Colstrip) in southeastern Montana, |
| • | a wood waste-fired boiler generating facility known as the Kettle Falls Generating Station (Kettle Falls GS) in northeastern Washington, |
| • | a two-unit natural gas-fired CT generating facility, located in northeastern Spokane (Northeast CT), |
| • | a two-unit natural gas-fired CT generating facility in northern Idaho (Rathdrum CT), and |
| • | two small natural gas-fired generating facilities (Boulder Park and Kettle Falls CT). |
Coyote Springs 2, which is operated by Portland General Electric Company, is supplied with natural gas under both term contracts and spot market purchases, including transportation agreements with bilateral renewal rights.
Colstrip, which is operated by PPL Montana, LLC, is supplied with fuel from adjacent coal reserves under coal supply and transportation agreements in effect through 2019.
The primary fuel for the Kettle Falls GS is wood waste generated as a by-product and delivered by trucks from forest industry operations within 100 miles of the plant. A combination of long-term contracts and spot purchases has provided, and is expected to meet, fuel requirements for the Kettle Falls GS.
The Northeast CT, Rathdrum CT, Boulder Park and Kettle Falls CT generating units are primarily used to meet peaking electric requirements. We also operate these facilities when marginal costs are below prevailing wholesale electric prices. These generating facilities have access to natural gas supplies that are adequate to meet their respective operating needs.
See "Item 2 Properties - Avista Utilities - Generation Properties" for the nameplate rating and present generating capabilities of the above thermal resources.
The following table shows our thermal generation (in thousands of MWhs) during the year ended December 31:
| 2013 | 2012 | 2011 | ||||||
| Coyote Springs 2 | 1,796 | 1,142 | 705 | |||||
| Colstrip | 1,227 | 1,499 | 1,433 | |||||
| Kettle Falls GS | 294 | 209 | 291 | |||||
| Northeast CT and Rathdrum CT | 34 | 7 | 8 | |||||
| Boulder Park and Kettle Falls CT | 32 | 7 | 10 | |||||
| Total company-owned thermal generation | 3,383 | 2,864 | 2,447 | |||||
| Long-term contract with Lancaster Plant | 1,656 | 1,208 | 835 | |||||
| Total thermal generation | 5,039 | 4,072 | 3,282 | |||||
Lancaster Plant Power Purchase Agreement The Lancaster Plant is a 270 MW natural gas-fired combined cycle combustion turbine plant located in Idaho, owned by an unrelated third-party. All of the output from the Lancaster Plant is contracted to us through 2026 under a power purchase agreement (PPA).
Palouse Wind PPA Palouse Wind is a wind generation project developed by Palouse Wind, LLC (Palouse Wind), an affiliate of First Wind Holdings, LLC, and located in Whitman County, Washington. In June 2011, we entered into a 30-year PPA with Palouse Wind to acquire all of the power and renewable attributes produced by the project at a fixed price per MWh with a fixed escalation of the price over the term of the agreement. The project has a nameplate capacity of approximately 105 MW and is expected to produce approximately 40 aMW. Deliveries from the project began during the fourth quarter of 2012. Generation from Palouse Wind was 297,027 MWhs in 2013 and 61,450 MWhs in 2012. We have an annual option to purchase the wind project following the 10th anniversary of its December 2012 commercial operation date. The purchase price per the PPA is a fixed price per KW of in-service capacity with a fixed decline in the price per KW over the remaining 20 year term of the agreement.
Other Purchases, Exchanges and Sales In addition to the resources described above, we purchase and sell power under various long-term contracts and we also enter into short-term purchases and sales. Further, pursuant to the Public Utility Regulatory Policies Act of 1978 (PURPA), as amended, we are required to purchase generation from qualifying facilities. This includes, among other resources, hydroelectric projects, cogeneration projects and wind generation projects at rates approved by the Washington Utilities and Transportation Commission (UTC) and the Idaho Public Utilities Commission (IPUC). Existing PURPA contracts expire at various times through 2022.
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See “Avista Utilities Operating Statistics – Electric Operations – Electric Energy Resources” for annual quantities of purchased power, wholesale power sales and power from exchanges in 2013, 2012 and 2011. See “Electric Operations” for additional information with respect to the use of wholesale purchases and sales as part of our resource optimization process and also see "Future Resource Needs" for the magnitude of these power purchase and sales contracts in future periods.
Hydroelectric Licensing
We are a licensee under the Federal Power Act as administered by the FERC, which includes regulation of hydroelectric generation resources. Excluding the Little Falls Hydroelectric Generating Project, our other seven hydroelectric plants are regulated by the FERC through two project licenses. The licensed projects are subject to the provisions of Part I of the Federal Power Act. These provisions include payment for headwater benefits, condemnation of licensed projects upon payment of just compensation, and take-over of such projects after the expiration of the license upon payment of the lesser of “net investment” or “fair value” of the project, in either case, plus severance damages.
The Cabinet Gorge Hydroelectric Generating Project (Cabinet Gorge) and the Noxon Rapids Hydroelectric Generating Project (Noxon Rapids) are under one 45-year FERC license issued in March 2001. See “Cabinet Gorge Total Dissolved Gas Abatement Plan” in “Note 20 of the Notes to Consolidated Financial Statements” for discussion of dissolved atmospheric gas levels that exceed state of Idaho and federal water quality standards downstream of Cabinet Gorge during periods when we must divert excess river flows over the spillway and our mitigation plans and efforts.
Five of our six hydroelectric projects on the Spokane River (Long Lake, Nine Mile, Upper Falls, Monroe Street, and Post Falls) are under one 50-year FERC license issued in June 2009 and are referred to collectively as the Spokane River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. For further information see “Spokane River Licensing” in “Note 20 of the Notes to Consolidated Financial Statements.”
Future Resource Needs
We have operational strategies to provide sufficient resources to meet our energy requirements under a range of operating conditions. These operational strategies consider the amount of energy needed, which varies widely because of the factors that influence demand over intra-hour, hourly, daily, monthly and annual durations. Our average hourly load was 1,086 aMW in 2013, 1,075 aMW in 2012 and 1,096 aMW in 2011. The following is a forecast of our average annual energy requirements and resources for 2014 through 2017:
Forecasted Electric Energy Requirements and Resources
(aMW)
| 2014 | 2015 | 2016 | 2017 | ||||||||
| Requirements: | |||||||||||
| System load (1) | 1,050 | 1,057 | 1,064 | 1,072 | |||||||
| Contracts for power sales (2) | 115 | 63 | 63 | 12 | |||||||
| Total requirements | 1,165 | 1,120 | 1,127 | 1,084 | |||||||
| Resources: | |||||||||||
| Company-owned and contract hydro generation (3) | 528 | 501 | 506 | 506 | |||||||
| Company-owned and contract thermal generation (4) | 723 | 725 | 718 | 715 | |||||||
| Other contracts for power purchases | 170 | 169 | 168 | 116 | |||||||
| Total resources | 1,421 | 1,395 | 1,392 | 1,337 | |||||||
| Surplus resources | 256 | 275 | 265 | 253 | |||||||
| Additional available energy (5) | 153 | 139 | 154 | 153 | |||||||
| Total surplus resources | 409 | 414 | 419 | 406 | |||||||
| (1) | Beginning on June 30, 2013 a large industrial customer began generating electricity to meet a portion of its own load rather than selling the generation to Avista. The full impact of this load change culminates in 2014 when load is reduced for 12 calendar months. See Item 7. Management's Discussion and Analysis - "Customer Contract Renewal" for further discussion of this industrial customer. |
| (2) | The contracts for power sales decrease in 2015 and again in 2017 due to certain contracts expiring at the beginning of each of these years. We are currently evaluating the future plan for the additional resources made available due to the expiration of these contracts. |
| (3) | The forecast assumes near normal hydroelectric generation (decline in 2015 is due to changes in contracts with PUDs). |
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| (4) | Includes our long-term contract with the owner of the Lancaster Plant. Excludes Northeast CT and Rathdrum CT as these are considered peaking facilities and are generally not used to meet our base load requirements. We generally dispatch thermal resources when operating costs are lower than short-term wholesale market prices. |
| (5) | Northeast CT and Rathdrum CT. The combined maximum capacity of the Northeast CT and Rathdrum CT is 242 MW, with estimated available energy production as indicated for each year. The available energy from these resources decreases during 2015 due to Rathdrum CT being down for scheduled maintenance. |
In August 2013, we filed our 2013 Electric Integrated Resource Plan (IRP) with the UTC and the IPUC. The IRP details projected growth in demand for energy and the new resources needed to serve customers over the next 20 years. We regard the IRP as a tool for resource evaluation, rather than an acquisition plan for a particular project.
Highlights of the 2013 IRP include:
| • | In our IRP in 2011, we had certain recommendations for new renewable resources. These have been met with a 30-year PPA with Palouse Wind and the Kettle Falls GS being qualified as a renewable energy resource under the Washington state Energy Independence Act. |
| • | Load growth is expected to be approximately 1 percent, a decline from the growth of 1.6 percent forecasted in 2011. This delays the need for a new natural gas-fired resource by one year. The decrease in expected load growth is primarily due to energy efficiency programs (using less energy to perform activities) over the next 20 years. See "Item 7. Management Discussion and Analysis – Forecasted Customer and Load Growth and Economic Conditions and Utility Load Growth" for further discussion regarding utility customer growth, load growth, and the general economic conditions in our service territory. |
| • | Demand response (temporarily reducing the demand for energy) is included in the Preferred Resource Strategy for the first time and could provide 19 MW of peak energy reduction in the 2022 to 2027 time frame. |
| • | 575 MW of additional natural gas-fired generation facilities are required between 2020 and 2033. |
| • | Transmission upgrades will be needed to deliver the energy from new generation resources to the distribution lines serving customers. We will continue to participate in regional efforts to expand the region’s transmission system. |
We are required to file an IRP every two years with the next IRP expected to be filed during the third quarter of 2015. Our resource strategy may change from the 2013 IRP based on market, legislative and regulatory developments.
We are subject to the Washington state Energy Independence Act, which requires us to obtain a portion of our electricity from qualifying renewable resources or through purchase of renewable energy credits and acquiring all cost effective conservation measures. Future generation resource decisions will be impacted by legislation for restrictions on greenhouse gas emissions and renewable energy requirements.
See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Issues and Other Contingencies” for information related to existing laws, as well as potential legislation that could influence our future electric resource mix.
Natural Gas Operations
General We provide natural gas distribution services to retail customers in parts of eastern Washington, northern Idaho, and northeastern and southwestern Oregon.
Market prices for natural gas, like other commodities, can be volatile. Our natural gas procurement strategy is to provide reliable supply to our customers with some level of price certainty. We procure natural gas from various supply basins and over varying time periods. The resulting portfolio is a diversified mix of spot market purchases and forward fixed price purchases, utilizing physical and financial derivative instruments. We also use natural gas storage to support high demand periods and to procure natural gas when prices may be lower. Securing prices throughout the year and even into subsequent years provides a level of price certainty and can mitigate price volatility to customers between years.
Weather is a key component of our natural gas customer load. This load is highly variable and daily natural gas loads can differ significantly from the monthly forecasted load projections. We make continuing projections of our natural gas loads and assess available natural gas resources. On the basis of these projections, we plan and execute a series of transactions to hedge a portion of our customer’s projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend for multiple years into the future with the highest volumes hedged for the current and most immediate
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upcoming natural gas operating year (November through October). We also leave a portion of our natural gas supply requirements unhedged for purchase in the short-term spot markets.
Our purchase of natural gas supply is governed by our procurement plan. This plan is reviewed and modified annually by an internal management group. The updated plan is presented and discussed with staff in all three state jurisdictions. Communication with staff does not constitute pre-approval; however, it provides transparency to our procurement practices and offers the staff and other stakeholders an opportunity to express concerns, ask questions and learn about the factors contributing to the plan’s development and subsequent execution. The plan is then presented to our Risk Management Committee (RMC) for approval. Once approval is received, the plan is implemented and monitored by our gas supply and risk management groups.
The plan’s ongoing progress is also presented to Washington and Idaho staff in semi-annual meetings, and in Oregon updates are given quarterly. Other stakeholders (Public Counsel, Citizen Utility Board) are also invited to participate. The RMC is provided with an update on plan results and changes in their monthly meetings. These activities provide transparency for the natural gas supply procurement plan. Any material changes to the plan are documented and communicated via email to RMC members.
As part of the process of balancing natural gas retail load requirements with resources, we engage in the wholesale purchase and sale of natural gas. We plan for sufficient natural gas delivery capacity to serve our retail customers for a theoretical peak day event. As such, we generally have more pipeline and storage capacity than what is needed during periods other than a peak day. We optimize our natural gas resources by using market opportunities to generate economic value that helps mitigate fixed costs. Wholesale sales are delivered through wholesale market facilities outside of our natural gas distribution system. Natural gas resource optimization activities include, but are not limited to:
| • | wholesale market sales of surplus natural gas supplies, |
| • | purchases and sales of natural gas to optimize use of pipeline and storage capacity, and |
| • | participation in the transportation capacity release market. |
We also provide distribution transportation service to qualified, large commercial and industrial natural gas customers who purchase natural gas through third-party marketers. For these customers, we receive their purchased natural gas from such third-party marketers into our distribution system and redeliver it to the customers’ premise.
Natural Gas Supply We purchase all of our natural gas in wholesale markets. We are connected to multiple supply basins in the western United States and Canada through firm capacity transportation rights on six different pipeline networks. Access to this diverse portfolio of natural gas resources allows us to make natural gas procurement decisions that benefit our natural gas customers. These interstate pipeline transportation rights provide the capacity to serve approximately 25 percent of peak natural gas customer demands from domestic sources, and 75 percent from Canadian sourced supply. Natural gas prices in the Pacific Northwest are affected by global energy markets, as well as supply and demand factors in other regions of the United States and Canada. Future prices and delivery constraints may cause our resource mix to vary.
Natural Gas Storage We own a one-third interest in the Jackson Prairie Natural Gas Storage Project (Jackson Prairie), an underground natural gas storage field located near Chehalis, Washington. Jackson Prairie has a total peak day deliverability of 11.5 million therms, with a total working natural gas capacity of 253 million therms. As an owner, our share is one-third of the peak day deliverability and total working capacity. We also contract for additional storage capacity and delivery at Jackson Prairie from Northwest Pipeline for a portion of their one-third share of the storage project.
Natural gas storage enables us to store gas in the summer when prices are traditionally lower and withdraw during higher priced winter months. It is also used as a variable peaking resource during cold weather events.
Natural Gas Pipeline Replacement In 2011 we began implementation of a plan to replace certain vintages of Aldyl A natural gas pipe within our distribution systems in Washington, Idaho, and Oregon. In early 2012, we released our protocol report to each state utility commission describing our Aldyl A natural gas pipe replacement plan across our natural gas system. Later in 2012, after technical workshops held by the UTC to gather perspectives on pipeline replacement programs, including the need for expedited cost recovery, the UTC required all natural gas utilities operating in Washington to file applicable replacement plans with the Commission. We subsequently filed our protocol report with the UTC proposing to replace our Aldyl A natural gas pipe across our three state jurisdictions over a 20-year period at a cost of approximately $10 million per year, indexed to inflation. Subsequent to this protocol report, during the third quarter of 2013, we revised our estimated replacement costs to approximately $16 million per year, indexed to inflation over a 20-year period. We expect to receive cost recovery for these capital expenditures from the three jurisdictions over the life of these assets.
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Regulatory Issues
General As a public utility, we are subject to regulation by state utility commissions for prices, accounting, the issuance of securities and other matters. The retail electric and natural gas operations are subject to the jurisdiction of the UTC, the IPUC, the Public Utility Commission of Oregon (OPUC), and the Public Service Commission of the State of Montana (MPSC). Approval of the issuance of securities is not required from the MPSC. We are also subject to the jurisdiction of the FERC for licensing of hydroelectric generation resources, and for electric transmission services and wholesale sales.
Our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are generally determined on a “cost of service” basis.
Rates are designed to provide an opportunity for us to recover allowable operating expenses and earn a reasonable return on “rate base.” Rate base is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation and retirement of utility plant and write-offs as authorized by the utility commissions. Our operating expenses and rate base are allocated or directly assigned among five regulatory jurisdictions: electric in Washington and Idaho, and natural gas in Washington, Idaho and Oregon. In general, a request for new retail rates in Washington and Idaho is made on the basis of net investment, operating expenses and revenues for a test year that ended prior to the date of the request, plus certain adjustments designed to reflect the expected revenues, expenses and net investment during the period new retail rates will be in effect. The retail rates approved by the state commissions in a rate proceeding may not provide sufficient revenues to provide recovery of costs and a reasonable return on investment for a number of reasons, including but not limited to, unexpected changes in revenues, expenses and investment following the time new retail rates are requested in the rate proceeding, and exclusion of certain costs and investment by the commission from the rate making process. Oregon currently allows the use of a forecasted test year to establish retail rates for the rate year.
Our rates for wholesale electric and natural gas transmission services are based on either “cost of service” principles or market-based rates as set forth by the FERC. See “Notes 1 and 22 of the Notes to Consolidated Financial Statements” for additional information about regulation, depreciation and deferred income taxes.
General Rate Cases We regularly review the need for electric and natural gas rate changes in each state in which we provide service. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Avista Utilities – Regulatory Matters – General Rate Cases” for information on general rate case activity.
Power Cost Deferrals We defer the recognition in the income statement of certain power supply costs that vary from the level currently recovered from our retail customers as authorized by the UTC and the IPUC. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Avista Utilities – Regulatory Matters – Power Cost Deferrals and Recovery Mechanisms” and “Note 22 of the Notes to Consolidated Financial Statements” for detailed information on power cost deferrals and recovery mechanisms in Washington and Idaho.
Purchased Gas Adjustment (PGA) Under established regulatory practices in each state, we are allowed to adjust natural gas rates periodically (with regulatory approval) to reflect increases or decreases in the cost of natural gas purchased. Differences between actual natural gas costs and the natural gas costs included in retail rates are deferred during the period the differences are incurred. During the subsequent period when regulators approve inclusion of the cost changes in rates, any amounts that were previously deferred are charged or credited to expense. We typically propose such PGAs at least once per year. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Avista Utilities – Regulatory Matters – Purchased Gas Adjustments” and “Note 22 of the Notes to Consolidated Financial Statements” for detailed information on natural gas cost deferrals and recovery mechanisms in Washington, Idaho and Oregon.
Federal Laws Related to Wholesale Competition
Federal law promotes practices that open the electric wholesale energy market to competition. The FERC requires electric utilities to transmit power and energy to or for wholesale purchasers and sellers, and requires electric utilities to enhance or construct transmission facilities to create additional transmission capacity for the purpose of providing these services. Public utilities (through subsidiaries or affiliates) and other entities may participate in the development of independent electric generating plants for sales to wholesale customers.
Public utilities operating under the Federal Power Act are required to provide open and non-discriminatory access to their transmission systems to third parties and establish an Open Access Same-Time Information System to provide an electronic means by which transmission customers can obtain information about available transmission capacity and purchase transmission access. The FERC also requires each public utility subject to the rules to operate its transmission and wholesale
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power merchant operating functions separately and to comply with standards of conduct designed to ensure that all wholesale users, including the public utility’s power merchant operations, have equal access to the public utility’s transmission system. Our compliance with these standards has not had any substantive impact on the operation, maintenance and marketing of our transmission system or our ability to provide service to customers.
See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Competition” for further information.
Regional Transmission Organizations
Beginning with FERC Order No. 888 and continuing with subsequent rulemakings and policies, the FERC has encouraged better coordination and operational consistency aimed to capture efficiencies that might otherwise be gained through the formation of a Regional Transmission Organization (RTO) or an independent system operator (ISO).
We meet our FERC requirements to coordinate transmission planning activities with other regional entities through ColumbiaGrid. ColumbiaGrid is a Washington nonprofit membership corporation with an independent board formed to improve the operational efficiency, reliability, and planned expansion of the transmission grid in the Pacific Northwest. We became a member of ColumbiaGrid in 2006 during its formation. ColumbiaGrid is not an ISO, but performs only those functions that its members request, as set forth in specific agreements. Currently, ColumbiaGrid fills the role of facilitating our regional transmission planning as required in Order No. 1000 and other clarifying Orders. ColumbiaGrid and its members also work with other western organizations to address transmission planning, including WestConnect and the Northern Tier Transmission Group (NTTG). In 2011, we became a registered Planning Participant of the NTTG. We will continue to assess the benefits of entering into other functional agreements with ColumbiaGrid and/or participating in other forums to attain operational efficiencies and to meet FERC policy objectives.
Reliability Standards
Among its other provisions, the U.S. Energy Policy Act provides for the implementation of mandatory reliability standards and authorizes the FERC to assess penalties for non-compliance with these standards and other FERC regulations.
The FERC certified the North American Electricity Reliability Corporation (NERC) as the single Electric Reliability Organization authorized to establish and enforce reliability standards and delegate authority to regional entities for the purpose of establishing and enforcing reliability standards. The FERC has approved the NERC Reliability Standards, including western region standards, making up the set of legally enforceable standards for the United States bulk electric system. The first of these reliability standards became effective in June 2007. We are required to self-certify our compliance with these standards on an annual basis and undergo regularly scheduled periodic reviews by the NERC and its regional entity, the Western Electricity Coordinating Council (WECC). Our failure to comply with these standards could result in financial penalties of up to $1 million per day per violation. Annual self-certification and audit processes to date have demonstrated our substantial compliance with these standards. Requirements relating to cyber security are continually evolving. Our compliance with the upcoming version 5 of the NERC's Critical Infrastructure Protection standard is driving several physical and electronic security initiatives in our control centers, generating stations and substations. We do not expect the costs of the physical and electronic securities initiatives to have a material impact to our financial results.
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AVISTA UTILITIES ELECTRIC OPERATING STATISTICS
| Years Ended December 31, | |||||||||||
| 2013 | 2012 | 2011 | |||||||||
| ELECTRIC OPERATIONS | |||||||||||
| OPERATING REVENUES (Dollars in Thousands): | |||||||||||
| Residential | $ | 331,867 | $ | 315,137 | $ | 324,835 | |||||
| Commercial | 289,604 | 286,568 | 280,139 | ||||||||
| Industrial | 113,632 | 119,589 | 122,560 | ||||||||
| Public street and highway lighting | 7,267 | 7,240 | 6,941 | ||||||||
| Total retail | 742,370 | 728,534 | 734,475 | ||||||||
| Wholesale | 127,556 | 102,736 | 78,305 | ||||||||
| Sales of fuel | 126,657 | 115,835 | 153,470 | ||||||||
| Other | 36,071 | 21,067 | 21,937 | ||||||||
| Provision for refunds (1) | (2,048 | ) | — | — | |||||||
| Total electric operating revenues | $ | 1,030,606 | $ | 968,172 | $ | 988,187 | |||||
| ENERGY SALES (Thousands of MWhs): | |||||||||||
| Residential | 3,745 | 3,608 | 3,728 | ||||||||
| Commercial | 3,147 | 3,127 | 3,122 | ||||||||
| Industrial | 1,979 | 2,100 | 2,147 | ||||||||
| Public street and highway lighting | 26 | 26 | 26 | ||||||||
| Total retail | 8,897 | 8,861 | 9,023 | ||||||||
| Wholesale | 3,874 | 3,733 | 2,796 | ||||||||
| Total electric energy sales | 12,771 | 12,594 | 11,819 | ||||||||
| ENERGY RESOURCES (Thousands of MWhs): | |||||||||||
| Hydro generation (from Company facilities) | 3,646 | 4,088 | 4,534 | ||||||||
| Thermal generation (from Company facilities) | 3,383 | 2,864 | 2,447 | ||||||||
| Purchased power - hydro generation from long-term contracts with PUDs | 970 | 1,022 | 1,047 | ||||||||
| Purchased power - thermal generation from long-term contracts with Lancaster plant | 1,656 | 1,208 | 835 | ||||||||
| Purchased power - wind generation from long-term contracts with Palouse Wind | 297 | 61 | — | ||||||||
| Purchased power - wholesale | 3,452 | 3,995 | 3,553 | ||||||||
| Power exchanges | (20 | ) | (10 | ) | (24 | ) | |||||
| Total power resources | 13,384 | 13,228 | 12,392 | ||||||||
| Energy losses and Company use | (613 | ) | (634 | ) | (573 | ) | |||||
| Total energy resources (net of losses) | 12,771 | 12,594 | 11,819 | ||||||||
| NUMBER OF RETAIL CUSTOMERS (Average for Period): | |||||||||||
| Residential | 321,098 | 318,692 | 316,762 | ||||||||
| Commercial | 40,202 | 39,869 | 39,618 | ||||||||
| Industrial | 1,386 | 1,395 | 1,380 | ||||||||
| Public street and highway lighting | 527 | 503 | 455 | ||||||||
| Total electric retail customers | 363,213 | 360,459 | 358,215 | ||||||||
| RESIDENTIAL SERVICE AVERAGES: | |||||||||||
| Annual use per customer (KWh) | 11,664 | 11,323 | 11,769 | ||||||||
| Revenue per KWh (in cents) | 8.86 | 8.73 | 8.71 | ||||||||
| Annual revenue per customer | $ | 1,033.54 | $ | 988.84 | $ | 1,025.48 | |||||
| AVERAGE HOURLY LOAD (aMW) | 1,086 | 1,075 | 1,096 | ||||||||
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AVISTA UTILITIES ELECTRIC OPERATING STATISTICS
| Years Ended December 31, | ||||||||
| 2013 | 2012 | 2011 | ||||||
| REQUIREMENTS AND RESOURCE AVAILABILITY at time of system peak (MW): | ||||||||
| Total requirements (winter): | ||||||||
| Retail native load | 1,669 | 1,554 | 1,669 | |||||
| Wholesale obligations | 554 | 637 | 712 | |||||
| Total requirements (winter) | 2,223 | 2,191 | 2,381 | |||||
| Total resource availability (winter) | 2,767 | 2,618 | 2,923 | |||||
| Total requirements (summer): | ||||||||
| Retail native load | 1,577 | 1,579 | 1,535 | |||||
| Wholesale obligations | 569 | 906 | 472 | |||||
| Total requirements (summer) | 2,146 | 2,485 | 2,007 | |||||
| Total resource availability (summer) | 2,813 | 3,060 | 2,370 | |||||
| COOLING DEGREE DAYS: (2) | ||||||||
| Spokane, WA | ||||||||
| Actual | 709 | 535 | 426 | |||||
| 30-year average (4) | 394 | 434 | 434 | |||||
| % of average | 180 | % | 123 | % | 98 | % | ||
| HEATING DEGREE DAYS: (3) | ||||||||
| Spokane, WA | ||||||||
| Actual | 6,683 | 6,256 | 6,861 | |||||
| 30-year average (4) | 6,780 | 6,676 | 6,647 | |||||
| % of average | 99 | % | 94 | % | 103 | % | ||
| (1) | This provision for refunds is specifically related to the Idaho general rate case which was settled in March 2013. See "Item 7. Management's Discussion and Analysis - Idaho General Rate Cases" for further discussion of this provision. |
| (2) | Cooling degree days are the measure of the warmness of weather experienced, based on the extent to which the average of high and low temperatures for a day exceeds 65 degrees Fahrenheit (annual degree days above historic indicate warmer than average temperatures). |
| (3) | Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures). |
| (4) | The 30-year average heating and cooling degree days fluctuated in 2013 due to a change in our methodology for calculating the amount. In 2013, we have switched to a rolling 30-year average whereas in prior years we only received updated 30-year average data on a periodic basis. |
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AVISTA UTILITIES NATURAL GAS OPERATING STATISTICS
| Years Ended December 31, | |||||||||||
| 2013 | 2012 | 2011 | |||||||||
| NATURAL GAS OPERATIONS | |||||||||||
| OPERATING REVENUES (Dollars in Thousands): | |||||||||||
| Residential | $ | 206,330 | $ | 196,719 | $ | 219,557 | |||||
| Commercial | 102,225 | 98,994 | 111,964 | ||||||||
| Interruptible | 2,681 | 2,232 | 2,519 | ||||||||
| Industrial | 3,599 | 3,635 | 4,180 | ||||||||
| Total retail | 314,835 | 301,580 | 338,220 | ||||||||
| Wholesale | 194,717 | 158,631 | 195,882 | ||||||||
| Transportation | 7,576 | 7,032 | 6,709 | ||||||||
| Other | 8,573 | 6,930 | 7,414 | ||||||||
| Provision for refunds (1) | (442 | ) | — | — | |||||||
| Total natural gas operating revenues | $ | 525,259 | $ | 474,173 | $ | 548,225 | |||||
| THERMS DELIVERED (Thousands of Therms): | |||||||||||
| Residential | 204,711 | 189,152 | 207,202 | ||||||||
| Commercial | 122,245 | 115,083 | 125,344 | ||||||||
| Interruptible | 5,694 | 4,363 | 4,503 | ||||||||
| Industrial | 5,181 | 5,073 | 5,654 | ||||||||
| Total retail | 337,831 | 313,671 | 342,703 | ||||||||
| Wholesale | 524,818 | 586,193 | 510,755 | ||||||||
| Transportation | 159,976 | 154,704 | 152,515 | ||||||||
| Interdepartmental and Company use | 418 | 381 | 440 | ||||||||
| Total therms delivered | 1,023,043 | 1,054,949 | 1,006,413 | ||||||||
| SOURCES OF NATURAL GAS DELIVERED (Thousands of Therms): | |||||||||||
| Purchases | 834,068 | 919,684 | 877,290 | ||||||||
| Storage - injections | (97,338 | ) | (105,904 | ) | (109,782 | ) | |||||
| Storage - withdrawals | 129,006 | 93,850 | 94,504 | ||||||||
| Natural gas for transportation | 159,976 | 154,704 | 152,515 | ||||||||
| Distribution system losses | (2,669 | ) | (7,385 | ) | (8,114 | ) | |||||
| Total natural gas delivered | 1,023,043 | 1,054,949 | 1,006,413 | ||||||||
| NUMBER OF RETAIL CUSTOMERS (Average for Period): | |||||||||||
| Residential | 288,708 | 286,522 | 284,504 | ||||||||
| Commercial | 33,932 | 33,763 | 33,540 | ||||||||
| Interruptible | 38 | 38 | 38 | ||||||||
| Industrial | 259 | 263 | 255 | ||||||||
| Total natural gas retail customers | 322,937 | 320,586 | 318,337 | ||||||||
| RESIDENTIAL SERVICE AVERAGES: | |||||||||||
| Annual use per customer (therms) | 709 | 660 | 728 | ||||||||
| Revenue per therm (in dollars) | $ | 1.01 | $ | 1.04 | $ | 1.06 | |||||
| Annual revenue per customer | $ | 714.67 | $ | 686.57 | $ | 771.72 | |||||
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AVISTA UTILITIES NATURAL GAS OPERATING STATISTICS
| Years Ended December 31, | ||||||||
| 2013 | 2012 | 2011 | ||||||
| HEATING DEGREE DAYS: (2) | ||||||||
| Spokane, WA | ||||||||
| Actual | 6,683 | 6,256 | 6,861 | |||||
| 30-year average (3) | 6,780 | 6,676 | 6,647 | |||||
| % of average | 99 | % | 94 | % | 103 | % | ||
| Medford, OR | ||||||||
| Actual | 4,576 | 4,182 | 4,634 | |||||
| 30-year average (3) | 4,539 | 4,422 | 4,402 | |||||
| % of average | 101 | % | 95 | % | 105 | % | ||
| (1) | This provision for rate refunds is specifically related to the Idaho general rate case which was settled in March 2013. See "Item 7. Management's Discussion and Analysis - Idaho General Rate Cases" for further discussion of this provision. |
| (2) | Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures). |
| (3) | The 30-year average heating degree days fluctuated in 2013 due to a change in our methodology for calculating the amount. In 2013, we have switched to a rolling 30-year average whereas in prior years we only received updated 30-year average data on a periodic basis. |
Ecova
Ecova provides sustainable utility expense management and energy management solutions to multi-site companies across North America. Ecova’s invoice processing, auditing and payment services, coupled with energy procurement, comprehensive reporting and advanced analysis, provide the critical data clients need to help balance the financial, social and environmental aspects of doing business.
As part of the expense management services, Ecova analyzes and audits invoices, then presents consolidated bills on-line, and processes payments. Information gathered from invoices, providers and other customer-specific data allows Ecova to provide its clients with in-depth analytical support, real-time reporting and consulting services.
Ecova also provides a wide array of energy efficiency program management services to utilities across North America. As part of these management services, Ecova helps utilities develop and execute energy efficiency programs and can provide utilities with a complete turn-key solution.
The following table presents key statistics for Ecova:
| 2013 | 2012 | 2011 | |||||||||
| Expense management and utility customers at year-end | 751 | 740 | 645 | ||||||||
| Billed sites at year-end | 722,123 | 697,076 | 496,842 | ||||||||
| Dollars of customer energy spend managed (in billions) | $ | 20.9 | $ | 19.4 | $ | 18.3 | |||||
Ecova's growth over the last several years in the key statistics listed above can be attributed to a combination of strategic acquisitions, new services and growth among existing customers, additional customers, and a high customer retention rate.
The noncontrolling interest of Ecova (which was 19.8 percent as of December 31, 2013) is primarily held by the previous owners of Cadence Network, a company acquired by Ecova in 2008.
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Other Businesses
The following table shows our assets related to our other businesses as of December 31 (dollars in thousands):
| 2013 | 2012 | |||||||
| Spokane Energy | $ | 42,829 | $ | 54,235 | ||||
| Avista Energy | 12,399 | 12,549 | ||||||
| METALfx | 11,105 | 11,273 | ||||||
| Steam Plant and Courtyard Office Center | 7,055 | 7,122 | ||||||
| Other | 7,894 | 10,459 | ||||||
| Total | $ | 81,282 | $ | 95,638 | ||||
Spokane Energy is a special purpose limited liability company and all of its membership capital is owned by Avista Corp. Spokane Energy was formed in December 1998, to assume ownership of a fixed rate electric capacity contract between Avista Corp. and Portland General Electric Company. Of the total assets for Spokane Energy, the fixed rate electricity capacity contract represents $40.6 million and $52.0 million for 2013 and 2012, respectively, and the likelihood of this asset being at risk of impairment is remote. In addition to the assets above, Spokane Energy also has nonrecourse long-term debt outstanding in the amount of $17.8 million and $32.8 million at December 31, 2013 and 2012, respectively, related to the acquisition of the fixed rate electric capacity contract. The final payment is due in January 2015 and Spokane Energy bears full recourse risk for the debt. See "Note 13 of the Notes to the Consolidated Financial Statements" for further information regarding this debt.
Avista Energy is a former electricity and natural gas marketing, trading and resource management business, which is a subsidiary of Avista Capital. This subsidiary has not been active since 2009; however, it continues to incur legal fees as it defends its actions related to several legal proceedings including the Federal Energy Regulatory Commission Inquiry, the
California Refund Proceeding, the Pacific Northwest Refund Proceeding, and the California Attorney General Complaint (the “Lockyer Complaint”). See "Note 20 of the Notes to the Consolidated Financial Statements" for further detail regarding these legal proceedings. The assets associated with Avista Energy are deferred tax assets related to its former operations.
Advanced Manufacturing and Development (AM&D) doing business as METALfx performs custom sheet metal fabrication of electronic enclosures, parts and systems for the computer, construction, telecom, renewable energy and medical industries.
Steam Plant and Courtyard Office Center consist of real estate investments (primarily commercial office buildings).
Our other investments and operations include emerging technology venture capital funds.
Over time as opportunities arise, we dispose of investments and phase out operations that do not fit with our overall corporate strategy. However, we may invest incremental funds to protect our existing investments and invest in new businesses that we believe fit with our overall corporate strategy.
We are focused on discovering new ways to accelerate growth for Avista Corp. within and adjacent to our core utility business and are planning to incur $2.0 million to $3.0 million of expense in 2014 exploring opportunities to develop new markets and ways for customers to improve the use of electricity and natural gas for commercial productivity and transportation. We may also make other targeted investments that will help us gain strategic insights to build new growth platforms.
Item 1A. Risk Factors
Risk Factors
The following factors could have a significant impact on our operations, results of operations, financial condition or cash flows. These factors could cause actual results or outcomes to differ materially from those discussed in our reports filed with the Securities and Exchange Commission (including this Annual Report on Form 10-K), and elsewhere. Please also see “Forward-Looking Statements” for additional factors which could have a significant impact on our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements.
Weather (temperatures, precipitation levels and storms) has a significant effect on our results of operations, financial condition and cash flows.
Weather impacts are described in the following subtopics:
| • | certain retail electricity and natural gas sales, |
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| • | the cost of natural gas supply, |
| • | the cost of power supply, and |
| • | damage to facilities. |
Certain retail electricity and natural gas sales volumes vary directly with changes in temperatures. We normally have our highest retail (electric and natural gas) energy sales during the winter heating season in the first and fourth quarters of the year. We also have high electricity demand for air conditioning during the summer (third quarter). In general, warmer weather in the heating season and cooler weather in the cooling season will reduce our customers’ energy demand and retail operating revenues.
The cost of natural gas supply tends to increase with higher demand during periods of cold weather. Increased costs adversely affect cash flows when we purchase natural gas for retail supply at prices above the amount then allowed for recovery in retail rates. We defer differences between actual natural gas supply costs and the amount currently recovered in retail rates and we have generally been allowed to recover substantially all of these differences after regulatory review. However, these deferred costs require cash outflows from the time of natural gas purchases until the costs are later recovered through retail sales. Inter-regional natural gas pipelines and competition for supply can allow demand-driven price volatility in other regions of North America to affect prices in our region, even though there may be less extreme weather conditions in our area.
The cost of power supply can be significantly affected by weather. Precipitation (consisting of snowpack, its water content and melting pattern plus rainfall) and other streamflow conditions (such as regional water storage operations) significantly affect hydroelectric generation capability. Variations in hydroelectric generation inversely affect our reliance on market purchases and thermal generation. To the extent that hydroelectric generation is less than normal, significantly more costly power supply resources must be acquired and the ability to realize net benefits from surplus hydroelectric wholesale sales is reduced. Wholesale prices also vary based on wind patterns as wind generation capacity is material in our region but its contribution to supply is inconsistent.
The price of power in the wholesale energy markets tends to be higher during periods of high regional demand, such as occurs with temperature extremes. We may need to purchase power in the wholesale market during peak price periods. The price of natural gas as fuel for natural gas-fired electric generation also tends to increase during periods of high demand which are often related to temperature extremes. We may need to purchase natural gas fuel in these periods of high prices to meet electric demands. The cost of power supply during peak usage periods may be higher than the retail sales price or the amount allowed in retail rates by our regulators. To the extent that power supply costs are above the amount allowed currently in retail rates, the difference is partially absorbed by the Company in current expense and it is partially deferred or shared with customers through regulatory mechanisms.
The price of power tends to be lower during periods with excess supply, such as the spring when hydroelectric conditions are usually at their maximum and various facilities are required to operate to meet environmental mandates. Oversupply can be exacerbated when intermittent resources such as wind generation are producing output that may be supported by price subsidies. In extreme situations, we may be required to sell excess energy at negative prices.
As a result of these combined factors, our net cost of power supply – the difference between our costs of generation and market purchases, reduced by our revenue from wholesale sales – varies significantly because of weather.
Damage to facilities may be caused by severe weather, such as snow, ice or wind storms. The cost to implement rapid repair to such facilities can be significant. Overhead electric lines are most susceptible to damage caused by severe weather.
Regulators may not grant rates that provide timely or sufficient recovery of our costs or allow a reasonable rate of return for our shareholders.
We have historically experienced higher costs for utility operations in each of the last several years with the exception of 2013 which saw a slight decrease from 2012 actual costs. We have also made significant capital investments into utility plant assets. Our ability to recover these costs depends on the amount and timeliness of retail rate changes allowed by regulatory agencies. We expect to periodically file for rate increases with regulatory agencies to recover our costs and provide an opportunity to earn a reasonable rate of return for shareholders. If regulators grant substantially lower rate increases than our requests in the future or if deferred costs are disallowed, it could have a negative effect on our operating revenues, net income and cash flows. In addition, provisions to our approved settlement in the Washington general rate cases in 2012 and our approved settlement to the Idaho general rate cases in 2013, do not prevent us from filing general rate cases in these two jurisdictions in 2014; however, new rates from these general rate case filings would not take effect prior to January 1, 2015.
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Energy commodity price changes affect our cash flows and results of operations.
Energy commodity prices can be volatile. A combination of factors exposes our operations to commodity price risks. We rely on energy markets and other counterparties for energy supply, surplus and optimization transactions and commodity price hedging. These factors include:
| • | Our obligation to serve our retail customers at rates set through the regulatory process. We cannot change retail rates to reflect current energy prices unless and until we receive regulatory approval. |
| • | Customer demand, which is beyond our control because of weather, customer choices, prevailing economic conditions and other factors. |
| • | Some of our energy supply cost is fixed by nature of the energy-producing assets or through contractual arrangements. However, a significant portion of our energy resource costs are not fixed. |
Because we must supply the amount of energy demanded by our customers and we must sell it at fixed rates and only a portion of our energy supply costs are fixed, we are subject to the risk of buying energy at higher prices in wholesale energy markets (and the risk of selling energy at lower prices if we are in a surplus position). Electricity and natural gas in wholesale markets are commodities with historically high price volatility. Changes in wholesale energy prices affect, among other things, the cash requirements to purchase electricity and natural gas for retail customers or wholesale obligations and the market value of derivative assets and liabilities.
When we enter into fixed price energy commodity transactions for future delivery, we are subject to credit terms that may require us to provide collateral to wholesale counterparties related to the difference between current prices and the agreed upon fixed prices. These collateral requirements can place significant demands on our cash flows or borrowing arrangements. Price volatility can cause collateral requirements to change quickly and significantly.
Cash flow deferrals related to energy commodities can be significant. We are permitted to collect from customers only amounts approved by regulatory commissions. However, our costs to provide energy service can be much higher or lower than the amounts currently billed to customers. We are permitted to defer most of this difference for review by the regulatory commissions who have discretion as to the extent and timing of future recovery or refund to customers.
Power and natural gas costs higher than those recovered in retail rates reduce cash flows. Amounts that are not allowed for deferral or which are not approved to become part of customer rates affect our results of operations.
We defer income statement recognition and recovery from customers of certain power and natural gas costs that are higher or lower than what are currently authorized in retail rates by regulators. These power and natural gas costs are recorded as deferred charges with the opportunity for future recovery through retail rates. These deferred costs are subject to review for prudence and potential disallowance by regulators.
Despite the opportunity to recover deferred power and natural gas costs, our operating cash flows can be negatively affected until these costs are recovered from customers.
Our energy resource risk management processes can cause volatility in our cash flows and results of operations. We engage in active hedging and resource optimization practices to reduce energy cost volatility and economic exposure related to commodity price fluctuations. We routinely enter into contracts to hedge a portion of our purchase and sale commitments for electricity and natural gas, as well as forecasted excess or deficit energy positions and inventories of natural gas. We use physical energy contracts and derivative instruments, such as forwards, futures, swaps and options traded in the over-the-counter markets or on exchanges. We cannot and do not attempt to fully hedge our energy resource assets or our forecasted net positions for various time horizons. To the extent we have positions that are not hedged, or if hedging positions do not fully match the corresponding purchase or sale, fluctuating commodity prices could have a material effect on our operating revenues, resource costs, derivative assets and liabilities, and operating cash flows. In addition, actual loads and resources typically vary from forecasts, sometimes to a significant degree, which require additional transactions or dispatch decisions that impact cash flows.
The hedges we enter into are reviewed for prudence by the various regulators and any deferred costs (including those as a result of our hedging transactions) are subject to review for prudence and potential disallowance by regulators.
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We rely on regular access to financial markets but we cannot assure favorable or reasonable financing terms will be available when we need them.
Access to capital markets is critical to our operations and our capital structure. We have significant capital requirements that we expect to fund, in part, by accessing capital markets. As such, the state of financial markets and credit availability in the global, United States and regional economies impacts our financial condition. We could experience increased borrowing costs or limited access to capital on reasonable terms.
We access long-term capital markets to finance capital expenditures, repay maturing long-term debt and obtain additional working capital from time to time. Our ability to access capital on reasonable terms is subject to numerous factors and market conditions, many of which are beyond our control. If we are unable to obtain capital on reasonable terms, it may limit or prohibit our ability to finance capital expenditures and repay maturing long-term debt. Our liquidity needs could exceed our short-term credit availability and lead to defaults on various financing arrangements. We would also likely be prohibited from paying dividends on our common stock.
Performance of the financial markets could also result in significant declines in the market values of assets held by our pension plan and/or a significant increase in the pension liability (which impacts the funded status of the plan) and could increase future funding obligations and pension expense.
We rely on credit from financial institutions for short-term borrowings. We need adequate levels of credit with financial institutions for short-term liquidity. We have a $400.0 million committed line of credit that is scheduled to expire in February 2017. There is no assurance that we will have access to credit beyond the expiration date. The committed line of credit agreement contains customary covenants and default provisions. In the event of default, it would be difficult for us to obtain financing on reasonable terms to pay creditors or fund operations. We would also likely be prohibited from paying dividends on our common stock.
Ecova has a $125.0 million committed line of credit agreement with various financial institutions that has an expiration date of July 2017. There is no assurance that Ecova will have access to credit beyond the expiration date, and if conditions in financial markets deteriorate, it may affect the access to and cost of reliable credit. The committed line of credit agreement contains customary covenants and default provisions, and based on certain covenant conditions contained in the credit agreement, at December 31, 2013, Ecova could borrow an additional $35.3 million and still be compliant with the covenants. The covenant restrictions are calculated on a rolling twelve month basis, so this additional borrowing capacity could increase or decrease or Ecova could be required to pay down the outstanding debt as future results change. See further discussion of the specific covenants in "Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations - Ecova Credit Agreement." In the event of default, it would be difficult for Ecova to obtain financing on reasonable terms to pay creditors or fund operations.
Downgrades in our credit ratings could impede our ability to obtain financing, adversely affect the terms of financing and impact our ability to transact for or hedge energy resources. If we do not maintain our investment grade credit rating with the major credit rating agencies, we could expect increased debt service costs, limitations on our ability to access capital markets or obtain other financing on reasonable terms, and requirements to provide collateral (in the form of cash or letters of credit) to lenders and counterparties. In addition, credit rating downgrades could reduce the number of counterparties willing to do business with us.
We are subject to various operational and event risks.
Our operations are subject to operational and event risks that include:
| • | blackouts or disruptions to distribution, transmission or transportation systems, |
| • | forced outages at generating plants, |
| • | fuel cost and availability, including delivery constraints, |
| • | explosions, fires, accidents, or mechanical breakdowns that may occur while operating and maintaining our generation, transmission and distribution systems, and |
| • | natural disasters that can disrupt energy generation, transmission and distribution and general business operations. |
Disasters may affect the general economy, financial and capital markets, specific industries, or the Company's ability to conduct business. As protection against operational and event risks, we maintain business continuity and disaster recovery plans, maintain insurance coverage against some, but not all, potential losses and we seek to negotiate indemnification arrangements
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with contractors for certain event risks. However, insurance or indemnification agreements may not be adequate to protect us against liability, extra expenses and operating disruptions from all of the operational and event risks described above. In addition, we are subject to the risk that insurers and/or other parties will dispute or be unable to perform on their obligations to us.
Ecova participates in a competitive environment and may be unable to attain the level or timeliness of growth we expect.
Ecova operates in a highly competitive market, with many competitors vying for the same clients and services. Some current and potential new entrants to the market could have greater access to capital than Ecova, more visible name recognition, or could develop products and services that directly compete with Ecova’s offerings and be more attractive to current or potential Ecova clients. While Ecova strives to maintain client satisfaction standards, competitive pressure could affect client retention and results of operations. If demand for Ecova’s energy efficiency and renewable energy solutions does not develop as we expect, or if certain federal, state, or local government support for energy efficiency programs declines, our revenue could decrease and our results of operations could decline. Ecova also encounters competition from energy efficiency technology advances and may or may not continue to maintain or grow its marketplace presence because of these and other factors.
Ecova's operations have been partially assembled through numerous acquisitions and may include other acquisitions in the future as opportunities warrant. There are various uncertainties involved with launching new products and services, expanding to new markets, assimilating acquired operations, achieving revenue growth and operating synergies from acquired operations. Past and future acquisitions, domestically or internationally, if any, could disrupt the business and may or may not be accretive to earnings or provide the expected client offerings, market position, key personnel, or technology, or could introduce an expanded risk profile to Ecova’s operations. Additionally, changes in investment returns or payment and processing activities could affect results of operations. Ecova's growth and its ability to manage costs within its competitive marketplace and emerging business processes could make it more difficult to accurately forecast cash flows and results of operations. As a result, earnings projections may not be achieved or may be more volatile and cash flows may be irregular in this business segment.
Cyber attacks, terrorism or other malicious acts could disrupt our businesses and have a negative impact on our results of operations and cash flows.
In the course of our operations, we rely on interconnected technology systems for operation of our generating plants, electric transmission and distribution systems, natural gas distribution systems, customer billing and customer service, accounting and other administrative processes and compliance with various regulations. Ecova also relies on remote access interconnected technology for the performance of services and client deliverables, and some of Ecova's clients rely upon Ecova for 24/7 energy monitoring services. For Ecova to deliver such services, Ecova relies upon technology from suppliers and third party service providers, which could be subject to interruption.
There are various risks associated with technology systems such as hardware or software failure, communications failure, data distortion or destruction, unauthorized access to data, misuse of proprietary or confidential data, unauthorized control through electronic means, programming mistakes and other deliberate or inadvertent human errors. In particular, cyber attacks, terrorism or other malicious acts could damage, destroy or disrupt these systems. Additionally, the facilities and systems of clients, suppliers and third party service providers could be vulnerable to these same risks and, to the extent of interconnection to our technology, may impact us. Any failure, unexpected, or unauthorized unavailability of technology systems could result in a loss of operating revenues, an increase in operating expenses and costs to repair or replace damaged assets. Any of the above could also result in the loss or release of confidential customer information or other proprietary data that could adversely affect our reputation, competitiveness, and result in costly litigation and impact on our results of operations. As these potential cyber attacks become more common and sophisticated, we could be required to incur costs to strengthen our systems and respond to emerging concerns.
We are currently the subject of several regulatory proceedings, and we are named in multiple lawsuits related to our participation in western energy markets.
Through our utility operations and the prior operations of Avista Energy, we are involved in a number of legal and regulatory proceedings and complaints related to energy markets in the western United States. Most of these proceedings and complaints relate to the significant increase in the spot market price of energy in 2000 and 2001. This allegedly contributed to or caused unjust and unreasonable prices. These proceedings and complaints include, but are not limited to:
| • | refund proceedings in California and the Pacific Northwest, |
| • | market conduct investigations by the FERC, and |
| • | complaints filed by various parties related to alleged misconduct by parties in western power markets. |
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As a result of these proceedings and complaints, certain parties have asserted claims for significant refunds and damages from us, which could result in a negative effect on our results of operations and cash flows. See “Note 20 of the Notes to Consolidated Financial Statements” for further information.
There have been numerous recent changes in legislation, related administrative rulemaking, and Executive Orders, including periodic audits of compliance with such rules, which may adversely affect our operational and financial performance.
We expect to continue to be affected by legislation at the national, state and local level, as well as by administrative rules and requirements published by government agencies, including but not limited to the FERC, the EPA and state regulators. We are also subject to NERC and WECC reliability standards. The FERC, the NERC and the WECC may perform periodic audits of the Company. Failure to comply with the FERC, the NERC, or the WECC requirements can result in financial penalties of up to $1 million per day per violation.
Future legislation or administrative rules could have a material adverse effect on our operations, results of operations, financial condition and cash flows.
Actions or limitations to address concerns over the long-term global and Pacific Northwest climate changes may affect our operations and financial performance.
Legislative developments and advocacy at the state, national and international levels concerning climate change and other environmental issues could have significant impacts on our operations. The electric utility industry is one of the largest and most immediate industries to be more heavily regulated in some proposals. For example, various legislative proposals have been made to limit or place further restrictions on byproducts of combustion, including sulfur dioxide, nitrogen oxide, carbon dioxide, and other greenhouse gases and mercury emissions. Such proposals, if adopted, could restrict the operation and raise the cost of our power generation resources.
We expect continuing activity in the future and we are evaluating the extent that potential changes to environmental laws and regulations may:
| • | increase the operating costs of generating plants, |
| • | increase the lead time and capital costs for the construction of new generating plants, |
| • | require modification of our existing generating plants, |
| • | require existing generating plant operations to be curtailed or shut down, |
| • | reduce the amount of energy available from our generating plants, |
| • | restrict the types of generating plants that can be built or contracted with, and |
| • | require construction of specific types of generation plants at higher cost. |
We have contingent liabilities, including certain matters related to potential environmental liabilities, and cannot predict the outcome of these matters.
In the normal course of our business, we have matters that are the subject of ongoing litigation, mediation, investigation and/or negotiation. We cannot predict the ultimate outcome or potential impact of any particular issue, including the extent, if any, of insurance coverage or that amounts payable by us may be recoverable through the ratemaking process. We are subject to environmental regulation by federal, state and local authorities related to our past, present and future operations. See “Note 20 of the Notes to Consolidated Financial Statements” for further details of these matters.
We may be adversely affected by our inability to successfully implement certain technology projects.
We are currently undertaking a multi-year technology project to replace our customer information and work management systems, which is expected to be completed by the end of 2014. Our customer information and work management systems are two of our most critical technology systems and are interconnected to many other systems in our company. Implementation of these information systems is complex, expensive and time consuming. If we do not successfully implement the new systems, or if the systems do not operate as intended, it could result in substantial disruptions to our business, which could have a material adverse effect on our results of operations and financial condition.
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Our planned transaction with AERC may not achieve its intended results.
On November 4, 2013, we entered into an agreement and plan of merger with AERC, a privately-held company based in Juneau, Alaska. If the transaction is completed, AERC will become a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is AEL&P, the sole provider of electric services to approximately 16,000 customers in the City and Borough of Juneau, Alaska. The transaction is expected to close by July 1, 2014, following the approval of the merger transaction by the requisite number of AERC shareholders, the receipt of necessary regulatory approvals and the satisfaction of other closing conditions. We expect that the addition of AERC will be slightly dilutive to earnings per share in 2014, and that it will be slightly accretive to earnings per share in 2015. The transaction is expected to result in the recording of a significant amount of goodwill (currently estimated at $48 million). Achieving the anticipated accretive earnings per share contribution from AERC is subject to numerous uncertainties, including market conditions and risks related to AERC's business. This transaction could result in increased costs (including integration costs), decreases in the expected revenues from AERC, the impairment of goodwill or other assets, and diversion of management time and resources, which could have a material adverse effect on our results of operations, financial condition and cash flows.
Item 1B. Unresolved Staff Comments
As of the filing date of this Annual Report on Form 10-K, we have no unresolved comments from the staff of the Securities and Exchange Commission.
Item 2. Properties
Avista Utilities
Substantially all of our utility properties are subject to the lien of our mortgage indenture.
Our utility electric properties, located in the states of Washington, Idaho, Montana and Oregon, include the following:
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Generation Properties
No. of Units | Nameplate Rating (MW) (1) | Present Capability (MW) (2) | |||||
| Hydroelectric Generating Stations (River) | |||||||
| Washington: | |||||||
| Long Lake (Spokane) | 4 | 70.0 | 88.0 | ||||
| Little Falls (Spokane) | 4 | 32.0 | 35.6 | ||||
| Nine Mile (Spokane) (3) | 4 | 26.4 | 22.4 | ||||
| Upper Falls (Spokane) | 1 | 10.0 | 10.2 | ||||
| Monroe Street (Spokane) | 1 | 14.8 | 15.0 | ||||
| Idaho: | |||||||
| Cabinet Gorge (Clark Fork) (4) | 4 | 265.0 | 273.0 | ||||
| Post Falls (Spokane) | 6 | 14.8 | 15.4 | ||||
| Montana: | |||||||
| Noxon Rapids (Clark Fork) | 5 | 487.8 | 562.4 | ||||
| Total Hydroelectric | 920.8 | 1,022.0 | |||||
| Thermal Generating Stations | |||||||
| Washington: | |||||||
| Kettle Falls GS | 1 | 50.7 | 53.5 | ||||
| Kettle Falls CT | 1 | 7.2 | 6.9 | ||||
| Northeast CT | 2 | 61.8 | 64.8 | ||||
| Boulder Park | 6 | 24.6 | 24.0 | ||||
| Idaho: | |||||||
| Rathdrum CT | 2 | 166.5 | 166.5 | ||||
| Montana: | |||||||
| Colstrip Units 3 and 4 (5) | 2 | 233.4 | 222.0 | ||||
| Oregon: | |||||||
| Coyote Springs 2 | 1 | 287.0 | 284.4 | ||||
| Total Thermal | 831.2 | 822.1 | |||||
| Total Generation Properties | 1,752.0 | 1,844.1 | |||||
| (1) | Nameplate Rating, also referred to as “installed capacity,” is the manufacturer’s assigned power capability under specified conditions. |
| (2) | Present capability is the maximum capacity of the plant under standard test conditions without exceeding specified limits of temperature, stress and environmental conditions. Information is provided as of December 31, 2013. |
| (3) | There are currently four units at the Nine Mile plant; however, Units 1 and 2 are currently not running due to a mechanical failure. A project is underway to replace these units and restore capability. The present capability disclosed above represents the capability of the two running units, which have a nameplate rating of 18 MW. |
| (4) | For Cabinet Gorge, we have water rights permitting generation up to 265 MW. However, if natural stream flows will allow for generation above our water rights we are able to generate above our water rights. If natural stream flows only allow for generation at or below 265 MW, we are limited to generation of 265 MW. The present capability disclosed above represents the capability based on maximum stream flow conditions when we are allowed to generate above our water rights. |
| (5) | Jointly owned; data refers to our 15 percent interest. |
Electric Distribution and Transmission Plant
We own and operate approximately 19,000 miles of primary and secondary electric distribution lines providing service to retail customers. We have an electric transmission system of 685 miles of 230 kV line and 1,534 miles of 115 kV line. We also own an 11 percent interest in approximately 500 miles of a 500 kV line between Colstrip, Montana and Townsend, Montana. Our transmission and distribution systems also include numerous substations with transformers, switches, monitoring and metering devices, and other equipment.
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The 230 kV lines are the backbone of our transmission grid and are used to transmit power from generation resources, including Noxon Rapids, Cabinet Gorge and the Mid-Columbia hydroelectric projects, to the major load centers in our service area, as well as to transfer power between points of interconnection with adjoining electric transmission systems. These lines interconnect at various locations with the Bonneville Power Administration (BPA), Grant County PUD, PacifiCorp, NorthWestern Energy and Idaho Power Company and serve as points of delivery for power from generating facilities outside of our service area, including Colstrip, Coyote Springs 2 and the Lancaster Plant.
These lines also provide a means for us to optimize resources by entering into short-term purchases and sales of power with entities within and outside of the Pacific Northwest.
The 115 kV lines provide for transmission of energy and the integration of smaller generation facilities with our service-area load centers, including the Spokane River hydroelectric projects, the Kettle Falls projects, Rathdrum CT, Boulder Park and the Northeast CT. These lines interconnect with the BPA, Chelan County PUD, the Grand Coulee Project Hydroelectric Authority, Grant County PUD, NorthWestern Energy, PacifiCorp and Pend Oreille County PUD. Both the 115 kV and 230 kV interconnections with the BPA are used to transfer energy to facilitate service to each other’s customers that are connected through the other’s transmission system. We hold a long-term transmission agreement with the BPA that allows us to serve our native load customers that are connected through the BPA’s transmission system. During 2013 we reached a settlement with BPA whereby they reimbursed us $11.7 million for past use of our transmission system. In addition, BPA agreed to pay an additional $0.3 million monthly ($3.2 million annually) for the use of our transmission system commencing on January 1, 2013. See "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Bonneville Power Administration Reimbursement and Reardan Wind Generation Project" for additional details surrounding this settlement agreement.
Natural Gas Plant
We have natural gas distribution mains of approximately 3,400 miles in Washington, 1,960 miles in Idaho and 2,300 miles in Oregon. We have natural gas transmission mains of approximately 75 miles in Washington and 50 miles in Oregon. Our natural gas system includes numerous regulator stations, service distribution lines, monitoring and metering devices, and other equipment.
We own a one-third interest in Jackson Prairie, an underground natural gas storage field located near Chehalis, Washington. Jackson Prairie has a total peak day deliverability of 11.5 million therms, with a total working natural gas capacity of 253 million therms. As an owner, our share is one-third of the peak day deliverability and total working capacity. Natural gas storage enables us to store gas in the summer when prices are traditionally lower and withdraw during higher priced winter months. Natural gas storage is also used as a variable peaking resource during cold weather events.
Item 3. Legal Proceedings
See “Note 20 of Notes to Consolidated Financial Statements” for information with respect to legal proceedings.
Item 4. Mine Safety Disclosures
Not applicable.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is currently listed on the New York Stock Exchange under the ticker symbol “AVA.” As of January 31, 2014, there were 9,637 registered shareholders of our common stock.
The Board of Directors considers the level of dividends on our common stock on a regular basis, taking into account numerous factors including, without limitation:
| • | our results of operations, cash flows and financial condition, |
| • | the success of our business strategies, and |
| • | general economic and competitive conditions. |
Our net income available for dividends is generally derived from our regulated utility operations.
The payment of dividends on common stock could be limited by:
| • | certain covenants applicable to preferred stock (when outstanding) contained in the Company’s Restated Articles of Incorporation, as amended (currently there are no preferred shares outstanding), |
| • | certain covenants applicable to the Company's outstanding long-term debt and committed line of credit agreements (see Item 7. Management's Discussion and Analysis - "Capital Resources" for compliance with these covenants), and |
| • | the hydroelectric licensing requirements of section 10(d) of the Federal Power Act, as amended (FPA) (see “Note 1 of Notes to Consolidated Financial Statements”). |
On February 7, 2014, Avista Corp.’s Board of Directors declared a quarterly dividend of $0.3175 per share on the Company’s common stock. This was an increase of $0.0125 per share, or 4 percent from the previous quarterly dividend of $0.305 per share.
For additional information, see “Notes 1, 17, 18 and 19 of Notes to Consolidated Financial Statements.”
The following table presents quarterly high and low stock prices as reported on the consolidated reporting system, as well as dividend information:
| Three Months Ended | |||||||||||||||
March 31 | June 30 | September 30 | December 31 | ||||||||||||
| 2013 | |||||||||||||||
| Dividends paid per common share | $ | 0.305 | $ | 0.305 | $ | 0.305 | $ | 0.305 | |||||||
| Trading price range per common share: | |||||||||||||||
| High | $ | 27.48 | $ | 29.26 | $ | 29.21 | $ | 28.45 | |||||||
| Low | $ | 24.10 | $ | 25.68 | $ | 25.55 | $ | 25.88 | |||||||
| 2012 | |||||||||||||||
| Dividends paid per common share | $ | 0.29 | $ | 0.29 | $ | 0.29 | $ | 0.29 | |||||||
| Trading price range per common share: | |||||||||||||||
| High | $ | 26.18 | $ | 27.07 | $ | 28.05 | $ | 26.77 | |||||||
| Low | $ | 24.48 | $ | 24.95 | $ | 25.07 | $ | 22.78 | |||||||
For information with respect to securities authorized for issuance under equity compensation plans, see “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”
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Item 6. Selected Financial Data
| (in thousands, except per share data and ratios) | Years Ended December 31, | ||||||||||||||||||
| 2013 | 2012 | 2011 | 2010 | 2009 | |||||||||||||||
| Operating Revenues: | |||||||||||||||||||
| Avista Utilities | $ | 1,403,995 | $ | 1,354,185 | $ | 1,443,322 | $ | 1,419,646 | $ | 1,395,201 | |||||||||
| Ecova | 176,761 | 155,664 | 137,848 | 102,035 | 77,275 | ||||||||||||||
| Other | 39,549 | 38,953 | 40,410 | 61,067 | 40,089 | ||||||||||||||
| Intersegment eliminations | (1,800 | ) | (1,800 | ) | (1,800 | ) | (24,008 | ) | — | ||||||||||
| Total | $ | 1,618,505 | $ | 1,547,002 | $ | 1,619,780 | $ | 1,558,740 | $ | 1,512,565 | |||||||||
| Income (Loss) from Operations (pre-tax): | |||||||||||||||||||
| Avista Utilities | $ | 232,572 | $ | 188,778 | $ | 202,373 | $ | 198,200 | $ | 188,511 | |||||||||
| Ecova | 13,304 | 2,972 | 20,917 | 15,865 | 11,603 | ||||||||||||||
| Other | (1,483 | ) | (1,680 | ) | 4,714 | 5,669 | (7,103 | ) | |||||||||||
| Total | $ | 244,393 | $ | 190,070 | $ | 228,004 | $ | 219,734 | $ | 193,011 | |||||||||
| Net income | $ | 112,294 | $ | 78,800 | $ | 103,539 | $ | 94,948 | $ | 88,648 | |||||||||
| Net income attributable to noncontrolling interests | $ | (1,217 | ) | $ | (590 | ) | $ | (3,315 | ) | $ | (2,523 | ) | $ | (1,577 | ) | ||||
| Net Income (Loss) attributable to Avista Corporation shareholders: | |||||||||||||||||||
| Avista Utilities | $ | 108,598 | $ | 81,704 | $ | 90,902 | $ | 86,681 | $ | 86,744 | |||||||||
| Ecova | 7,129 | 1,825 | 9,671 | 7,433 | 5,329 | ||||||||||||||
| Other | (4,650 | ) | (5,319 | ) | (349 | ) | (1,689 | ) | (5,002 | ) | |||||||||
| Total | $ | 111,077 | $ | 78,210 | $ | 100,224 | $ | 92,425 | $ | 87,071 | |||||||||
| Average common shares outstanding, basic | 59,960 | 59,028 | 57,872 | 55,595 | 54,694 | ||||||||||||||
| Average common shares outstanding, diluted | 59,997 | 59,201 | 58,092 | 55,824 | 54,942 | ||||||||||||||
| Common shares outstanding at year-end | 60,077 | 59,813 | 58,423 | 57,120 | 54,837 | ||||||||||||||
| Income from continuing operations per Avista Corporation common share: | |||||||||||||||||||
| Diluted | $ | 1.85 | $ | 1.32 | $ | 1.72 | $ | 1.65 | $ | 1.58 | |||||||||
| Basic | $ | 1.85 | $ | 1.32 | $ | 1.73 | $ | 1.66 | $ | 1.59 | |||||||||
| Dividends declared per common share | $ | 1.22 | $ | 1.16 | $ | 1.10 | $ | 1.00 | $ | 0.81 | |||||||||
| Book value per common share | $ | 21.61 | $ | 21.06 | $ | 20.30 | $ | 19.71 | $ | 19.17 | |||||||||
| Total Assets at Year-End: | |||||||||||||||||||
| Avista Utilities | $ | 3,940,998 | $ | 3,894,821 | $ | 3,809,446 | $ | 3,589,235 | $ | 3,400,384 | |||||||||
| Ecova | 339,643 | 322,720 | 292,940 | 221,086 | 143,060 | ||||||||||||||
| Other | 81,282 | 95,638 | 112,145 | 129,774 | 63,515 | ||||||||||||||
| Total | $ | 4,361,923 | $ | 4,313,179 | $ | 4,214,531 | $ | 3,940,095 | $ | 3,606,959 | |||||||||
| Long-Term Debt and Capital Leases (including current portion) | $ | 1,272,783 | $ | 1,228,739 | $ | 1,177,300 | $ | 1,101,857 | $ | 1,071,338 | |||||||||
| Nonrecourse Long-Term Debt of Spokane | |||||||||||||||||||
| Energy (including current portion) | $ | 17,838 | $ | 32,803 | $ | 46,471 | $ | 58,934 | $ | — | |||||||||
| Long-Term Debt to Affiliated Trusts | $ | 51,547 | $ | 51,547 | $ | 51,547 | $ | 51,547 | $ | 51,547 | |||||||||
| Total Avista Corporation Shareholders’ Equity | $ | 1,298,266 | $ | 1,259,477 | $ | 1,185,701 | $ | 1,125,784 | $ | 1,051,287 | |||||||||
| Ratio of Earnings to Fixed Charges (1) | 3.10 | 2.47 | 3.06 | 2.86 | 2.95 | ||||||||||||||
| (1) | See Exhibit 12 for computations. |
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Business Segments
We have two reportable business segments as follows:
| • | Avista Utilities – an operating division of Avista Corp. that comprises our regulated utility operations. Avista Utilities generates, transmits and distributes electricity and distributes natural gas serving electric and gas customers in eastern Washington and northern Idaho and gas customers in parts of Oregon. The utility also engages in wholesale purchases and sales of electricity and natural gas. |
| • | Ecova – an indirect subsidiary of Avista Corp. (80.2 percent owned as of December 31, 2013) that provides energy efficiency and cost management programs and services for multi-site customers and utilities throughout North America. Ecova's service lines include expense management services for utility and telecom needs as well as strategic energy management and efficiency services that include procurement, conservation, performance reporting, financial planning, facility optimization and continuous monitoring, and energy efficiency program management for commercial enterprises and utilities. |
We have other businesses, including sheet metal fabrication, venture fund investments and real estate investments, as well as certain other operations of Avista Capital. These activities do not represent a reportable business segment and are conducted by various direct and indirect subsidiaries of Avista Corp., including AM&D, doing business as METALfx.
The following table presents net income (loss) attributable to Avista Corp. shareholders for each of our business segments (and the other businesses) for the year ended December 31 (dollars in thousands):
| 2013 | 2012 | 2011 | |||||||||
| Avista Utilities | $ | 108,598 | $ | 81,704 | $ | 90,902 | |||||
| Ecova | 7,129 | 1,825 | 9,671 | ||||||||
| Other | (4,650 | ) | (5,319 | ) | (349 | ) | |||||
| Net income attributable to Avista Corporation shareholders | $ | 111,077 | $ | 78,210 | $ | 100,224 | |||||
Executive Level Summary
Overall Results
Net income attributable to Avista Corporation shareholders was $111.1 million for 2013, an increase from $78.2 million for 2012. This was due to an increase in earnings at Avista Utilities and Ecova and a decrease in losses at the other businesses. Earnings at Avista Utilities increased due to the implementation of general rate increases, weather that was warmer in the summer cooling season and colder in the fourth quarter heating season, the net benefit from the settlement with BPA, and a slight reduction in other operating expenses. These were partially offset by expected increases in depreciation and amortization and taxes other than income taxes. Net income at Ecova increased due to increased revenues associated with new services, expense and data management services, and energy management services. This was partially offset by higher other operating expenses and increased depreciation and amortization. These results, including a quantification of their respective impacts, are discussed in detail below.
Avista Utilities
Avista Utilities is our most significant business segment. Our utility financial performance is dependent upon, among other things:
| • | weather conditions (temperatures, precipitation levels and wind patterns) which affect energy demand and electric generation, 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 impacts on supply and demand in the wholesale energy markets, |
| • | regulatory decisions, allowing our utility to recover costs, including purchased power and fuel costs, on a timely basis, and to earn a reasonable return on investment, |
| • | the price of natural gas in the wholesale market, including the effect on the price of fuel for generation, and |
| • | the price of electricity in the wholesale market, including the effects of weather conditions, natural gas prices and other factors affecting supply and demand. |
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Forecasted Customer and Load Growth
Based on our forecasts for our utility operations for 2014 through 2017, we expect annual electric customer growth to average 0.7 percent to 1.4 percent per year and annual natural gas customer growth to average 0.7 percent to 1.5 percent within our service area. We anticipate retail electric load growth to average between 0.5 percent and 1.0 percent and natural gas load growth to average between 0.7 percent and 1.5 percent. We anticipate customer and load growth at the lower end of the range in 2014 and a modest recovery as the economy strengthens during the four-year period. While the number of electric and natural gas customers is growing, the average annual usage by each residential customer has not changed significantly.
For further discussion regarding utility customer growth, load growth, and the general economic conditions in our service territory, see "Economic Conditions and Utility Load Growth."
See also "Competition" for a discussion of competitive factors that could affect our results of operations in the future.
General Rate Cases
In our utility operations, we regularly review the need for rate changes in each jurisdiction to improve the recovery of costs and capital investments in our generation, transmission and distribution systems. The following are the recent general rate increases that have occurred or will go into effect in the near future.
| Jurisdiction | Service | Effective Date | ||
| Washington | Electric and Natural Gas | January 1, 2012 | ||
| Electric and Natural Gas | January 1, 2013 (1) (3) | |||
| Electric and Natural Gas | January 1, 2014 (1) (3) | |||
| Idaho | Electric and Natural Gas | October 1, 2011 | ||
| Natural Gas | April 1, 2013 (2) (3) | |||
| Electric and Natural Gas | October 1, 2013 (2) (3) | |||
| Oregon | Natural Gas | June 1, 2012 | ||
| Natural Gas | February 1, 2014 (4) | |||
| Natural Gas | November 1, 2014 (4) | |||
| (1) | Relates to a settlement agreement in our Washington general rate cases (originally filed on April 2, 2012), which was approved by the UTC in December 2012 (see further discussion below under "Washington General Rate Cases"). |
| (2) | Relates to a settlement agreement in our Idaho general rate cases (originally filed on October 11, 2012), which was approved by the IPUC in March 2013 (see further discussion below under "Idaho General Rate Cases"). |
| (3) | Included in the original settlement agreements is a provision that we will not file a general rate case in these jurisdictions seeking new rates to take effect before January 1, 2015. We filed general rate cases in Washington in February 2014 and we plan to file in Idaho in the second quarter of 2014 with proposed rates that would take effect on January 1, 2015. This provision does not preclude us from filing other rate adjustments such as PGAs. |
| (4) | Relates to a settlement agreement in our Oregon general rate case (originally filed in August 2013), which was approved by the OPUC in January 2014 (see further discussion below under "Oregon General Rate Case"). |
Capital Expenditures
We are making significant capital investments in generation, transmission and distribution systems to preserve and enhance service reliability for our customers and replace aging infrastructure. Utility capital expenditures were $294.4 million for 2013. We expect utility capital expenditures to be about $335 million for 2014 and $355 million in 2015. We increased our estimates for future capital expenditures from the previous estimates of $260 million annually in 2014 and 2015 due to the increased scope and costs of updating and maintaining our generation, transmission and energy distribution systems to ensure reliability. These estimates of capital expenditures are subject to continuing review and adjustment (see discussion under “Avista Utilities Capital Expenditures”).
Customer Contract Renewal
An agreement with one of our largest electric customers, which has consumed approximately 100 aMWs per year, expired on June 30, 2013. We negotiated a new agreement with this customer that became effective on July 1, 2013 which has a five-year term. A Joint Application requesting approval of the new agreement was approved by the IPUC on June 28, 2013. This
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customer intends to generate a significant portion of its electricity requirements. Accordingly, under the new agreement, we expect a decrease in annual power sales to this customer of approximately $21 million and a resulting decrease in resource costs of approximately $19 million. According to the approved Joint Application, any change in revenues and expenses associated with the new agreement, as compared with the revenues and expenses included in the last general rate case for this customer, will be tracked through the PCA in Idaho at 100 percent, until such time as the contract is included in our base rates. As such, we expect no impact on our earnings from the new agreement.
Colstrip Generating Facility Outage
We own a 15 percent interest in Units 3 and 4 of the Colstrip Generating Plant in southeastern Montana, a coal-fired facility which is operated by PPL Montana, LLC. On July 1, 2013, an unplanned outage occurred to Colstrip Unit 4, with identified damage to the stator and rotor assembly. On January 23, 2014, the required repairs were completed and Unit 4 was returned to service. The total repair costs through December 31, 2013 were $26.9 million with our 15 percent share being $4.0 million. It is expected that these costs will be fully reimbursed less our portion of the $2.5 million insurance deductible ($0.4 million). Through December 31, 2013 we have received $3.0 million in insurance proceeds and we expect all costs related to the repairs to be accumulated and the remaining reimbursement from the insurance company to occur by mid-year 2014. The insurance reimbursement will be offset against the costs incurred throughout the project and we expect the final out-of-pocket costs of $0.4 million to be allocated between capital and operating expenses at approximately 90 percent and 10 percent, respectively.
The lost generation of Colstrip Unit 4 resulted in a combination of lower surplus wholesale sales and increased thermal fuel costs and purchased power costs to replace the energy, which resulted in increased net power supply costs. Our estimates showed an increase in power supply costs of approximately $12 million system-wide for 2013 as a result of the outage. All of the additional costs were included in the ERM in Washington and the PCA in Idaho. After consideration of the impacts of the two recovery mechanisms and the sharing between us and our customers, the outage was estimated to have a negative impact on gross margin (operating revenues less resource costs) in the range of approximately $6 million to $7 million for 2013. In addition, based on our calculations, the Colstrip Generating Plant dropped below a 70 percent availability factor during 2013. As a result, a provision associated with the ERM was triggered and an automatic prudence review surrounding the cause of the outage and the costs to replace the lost power will be performed by the UTC. We do not expect this prudence review to have a material impact on our cost recovery. In addition to the availability factor calculations, actual fixed costs of the plant must be compared to authorized costs and if the fixed costs are below authorized costs, the difference is credited back to customers through the ERM. Based on our calculations, the difference between actual and authorized fixed costs for 2013 was not material.
Alaska Energy and Resources Company Planned Transaction
On November 4, 2013, we entered into an agreement and plan of merger (Merger Agreement) with AERC, a privately-held company based in Juneau, Alaska. When the transaction is complete, AERC will become a wholly-owned subsidiary of Avista Corp.
The primary subsidiary of AERC is AEL&P, the sole provider of electric services to approximately 16,000 customers in the City and Borough of Juneau, Alaska. In 2012, AEL&P had annual revenues of $42 million and a total rate base of $111 million. The utility has a firm retail peak load of approximately 80 MW. AEL&P owns four hydroelectric generating facilities, having a total present capacity of 24.7 MW, and has a power purchase commitment for the output of the Snettisham hydroelectric project, having a present capacity of 78 MW, for a total hydroelectric capacity of 102.7 MW. AEL&P is not interconnected to any other electric system; therefore, the utility has 93.9 MW of diesel generating present capacity to provide back-up service to firm customers when necessary.
In addition to the regulated utility, AERC owns 100 percent of AJT Mining, which is an inactive mining company holding certain mining properties.
The merger consideration at closing will be $170 million, less AERC's indebtedness and subject to other customary closing adjustments. The transaction will be funded primarily through the issuance of Avista Corp. common stock to the shareholders of AERC. The transaction is expected to close by July 1, 2014, following the approval of the merger transaction by the requisite number of AERC shareholders, the receipt of necessary regulatory approvals and the satisfaction of other closing conditions. Avista Corp. shareholder approval is not required. We expect that the addition of AERC will be slightly dilutive to earnings per share in 2014, and that it will be slightly accretive to earnings per share in 2015.
The transaction is expected to result in the recording of a significant amount of goodwill, currently estimated at $48 million.
AEL&P currently has an authorized utility capital structure of 53.8 percent equity and an authorized return on equity of 12.875 percent. We expect that AEL&P will maintain this capital structure following the merger. The consolidated capital structure of AERC is expected to be similar to the capital structure of Avista Corp.
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For additional information regarding the AERC transaction, including the valuation and number of shares of Avista Corp. common stock to be delivered to AERC shareholders, see “Note 4 of the Notes to Consolidated Financial Statements” and our Current Report on Form 8-K dated November 4, 2013.
Ecova
Ecova plans to continue to grow organically and possibly through strategic acquisitions. Ecova's acquisitions since 2008 have been funded through internally generated cash, borrowings under Ecova's credit facility and an equity infusion from existing shareholders. If Ecova's capital needs exceed its credit facility capacity or management determines a different capital structure is necessary, Ecova may require additional equity infusions from existing shareholders and/or new funding sources.
We may seek to monetize all or part of our investment in Ecova in the future. We regularly engage in discussions with potential investors and acquirors to explore opportunities for such a transaction. The value of a potential monetization would depend on future market conditions, growth of the business, transaction structure and other factors. A strategic change to Ecova's ownership structure could provide access to public market capital and provide potential liquidity to Avista Corp. and the other owners of Ecova. There can be no assurance that the terms for a proposed transaction, if any, would be acceptable to Avista Corp. or that any such transaction would be completed.
Liquidity and Capital Resources
We have a committed line of credit with various financial institutions in the total amount of $400.0 million with an expiration date of February 2017. As of December 31, 2013, there were $171.0 million of cash borrowings and $27.4 million in letters of credit outstanding leaving $201.6 million of available liquidity under this line of credit.
Ecova has a five-year $125.0 million committed line of credit agreement with various financial institutions that has an expiration date of July 2017. As of December 31, 2013, Ecova had $46.0 million of borrowings outstanding under its committed line of credit agreement. Based on certain covenant conditions contained in the credit agreement, at December 31, 2013, Ecova could borrow an additional $35.3 million and still be compliant with the covenants. The covenant restrictions are calculated on a rolling twelve month basis, so this additional borrowing capacity could increase or decrease or Ecova could be required to pay down the outstanding debt as future results change. See further discussion of the specific covenants below under "Ecova Credit Agreement."
In August 2013, we entered into a $90.0 million term loan agreement with an institutional investor bearing an annual interest rate of 0.84 percent and maturing in 2016. The net proceeds from the term loan agreement were used to repay a portion of corporate indebtedness in anticipation of the maturity of $50.0 million in First Mortgage Bonds which occurred in December 2013.
We expect to issue approximately $190.0 million of long-term debt during 2014, including about $90.0 million of debt issuances combined by AERC or AEL&P associated with rebalancing the consolidated capital structure at AERC. This amount assumes we are going to refinance the existing net debt, estimated to be about $25.0 million at closing. The net debt outstanding at AEL&P does not include the Snettisham obligation which had a balance of $74.0 million as of December 31, 2012, as this relates to a power purchase commitment for which AEL&P has recorded a long-term power purchase asset and corresponding liability. In addition to rebalancing the consolidated capital structure at AERC, the proceeds from the issuance of long-term debt will be used to repay a portion of short-term borrowings, fund utility capital expenditures and other contractual commitments.
In August 2012, we entered into two sales agency agreements under which we may sell up to 2.7 million shares of our common stock from time to time. We did not issue any shares under these agreements during 2013 and as of December 31, 2013, we had 1.8 million shares available to be issued under these agreements.
In 2013, we issued $4.6 million (net of issuance costs) of common stock under the dividend reinvestment and direct stock purchase plan, and employee plans.
We did not issue our previously estimated $50.0 million of common stock in 2013 due to our planned transaction with AERC (discussed above), which is expected to be funded primarily through the issuance of common stock during 2014.
For 2014, we expect to issue up to $145.0 million of common stock related to closing the planned transaction. Without the planned transaction, Avista Corp. would have issued common stock to maintain an appropriate capital structure. Assuming the transaction is completed, we will not need to issue any common stock under the sales agency agreements referred to above.
Included in our 2014 liquidity estimates is approximately $50.0 million of lower tax payments due to the planned adoption of federal tax tangible property regulations. This will be accomplished through an accounting method change filing with the Internal Revenue Service that will retroactively modify which tangible property transactions we expense versus capitalize and depreciate for federal tax purposes.
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After considering the expected issuances of long-term debt and common stock during 2014 and the lower tax payments from the adoption of the federal tax tangible property regulations, we expect net cash flows from operating activities, together with cash available under our $400.0 million committed line of credit agreement, to provide adequate resources to fund capital expenditures, dividends, and other contractual commitments.
Avista Utilities – Regulatory Matters
General Rate Cases
We regularly review the need for electric and natural gas rate changes in each state in which we provide service. We will continue to file for rate adjustments to:
| • | seek recovery of operating costs and capital investments, and |
| • | seek the opportunity to earn returns as allowed by regulators. |
With regards to the timing and plans for future filings, the assessment of our need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors that can affect the timing of rate filings. Such factors include, but are not limited to, in-service dates of major capital investments and the timing of changes in major revenue and expense items.
Washington General Rate Cases
In December 2011, the UTC approved a settlement agreement in our electric and natural gas general rate cases filed in May 2011. The settlement agreement provided that base electric rates for our Washington customers increase by an average of 4.6 percent, which was designed to increase annual revenues by $20.0 million. Base natural gas rates for our Washington customers increased by an average of 2.4 percent, which was designed to increase annual revenues by $3.8 million. The new electric and natural gas rates became effective on January 1, 2012.
The settlement agreement provided for the deferral of certain generation plant maintenance costs. For 2011 and 2012 the Company compared actual non-fuel maintenance expenses for the Coyote Springs 2 and Colstrip plants with the amount of baseline maintenance expenses used to establish base retail rates and deferred the difference. This deferral occurred each year, with no carrying charge, with deferred costs to be amortized over a four-year period, beginning in the year following the period costs are deferred. Total net deferred costs under this mechanism in Washington were a regulatory asset of $3.1 million as of December 31, 2013 compared to $4.0 million as of December��31, 2012. As part of the settlement agreement relating to our general rate case approved in December 2012, the parties agreed to terminate the maintenance cost deferral mechanism on December 31, 2012, with the four-year amortization of the 2011 and 2012 deferrals to conclude in 2015 and 2016, respectively.
In December 2012, the UTC approved a settlement agreement in our electric and natural gas general rate cases filed in April 2012. The settlement, effective January 1, 2013 provided that base rates for our Washington electric customers increase by an overall 3.0 percent (designed to increase annual revenues by $13.6 million), and base rates for our Washington natural gas customers increased by an overall 3.6 percent (designed to increase annual revenues by $5.3 million). Under the settlement, there was a one-year credit designed to return $4.4 million to electric customers from the existing ERM deferral balance so the net average electric rate increase to our customers in 2013 was 2.0 percent. The credit to customers from the ERM balance did not impact our earnings.
The approved settlement also provided that, effective January 1, 2014, base rates increased for our Washington electric customers by an overall 3.0 percent (designed to increase annual revenues by $14.0 million), and for our Washington natural gas customers by an overall 0.9 percent (designed to increase annual revenues by $1.4 million). The settlement provides for a one-year credit designed to return $9.0 million to electric customers from the then-existing ERM deferral balance, so the net average electric rate increase to our customers effective January 1, 2014 will be 2.0 percent. The credit to customers from the ERM balance will not impact our earnings. The ERM balance as of December 31, 2013 was a liability of $17.9 million.
The settlement agreement provides for an authorized return on equity of 9.8 percent, an equity ratio of 47 percent and an overall return on rate base of 7.64 percent.
The December 2012 UTC Order approving the settlement agreement included certain conditions.
| (1) | The new retail rates that became effective on January 1, 2014 are temporary rates, and on January 1, 2015 electric and natural gas base rates will revert back to 2013 levels absent any intervening action from the UTC. The original settlement agreement has a provision that we will not file a general rate case in Washington seeking new rates to take effect before January 1, 2015. |
| (2) | In its Order, the UTC found that much of the approved base rate increase is justified by the planned capital expenditures necessary to upgrade and maintain our utility facilities. If these capital projects are not completed to a level that was contemplated in the settlement agreement, this could result in base rates which are considered too high by the UTC. We |
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are required to file capital expenditure progress reports with the UTC on a periodic basis so that the UTC can monitor the capital expenditures and ensure they are in line with those contemplated in the settlement agreement. Total utility capital expenditures among all jurisdictions were $294.4 million for 2013. We expect utility capital expenditures to be about $335 million for 2014 and $355 million in 2015, which are above the capital expenditures contemplated in the settlement agreement.
On February 4, 2014 we filed electric and natural gas general rates cases with the UTC. We have requested an overall increase in base electric rates of 3.8 percent (designed to increase annual electric revenues by $18.2 million) and an overall increase in base natural gas rates of 8.1 percent (designed to increase annual natural gas revenues by $12.1 million). Our requests are based on a proposed overall rate of return of 7.71 percent, with a common equity ratio of 49.0 percent and a 10.1 percent return on equity.
We have also proposed a rebate beginning January 1, 2015, related to our sale of renewable energy credits (REC), that would reduce customers' monthly electric bills by 1.1 percent. The rebate associated with the sale of RECs is in response to the UTC Order approving our previous general rate case settlement in December 2012. This proposed REC rebate would commence simultaneously with the expiration of two rebates that, together, are currently reducing customers' monthly electric bills by 2.8 percent. The net effect, commencing January 1, 2015, of the proposed new 1.1 percent rebate and the expiration of the current 2.8 percent rebate would be an increase in monthly electric bills of approximately 1.7 percent from 2014 levels. These rebates do not increase or decrease our earnings.
The combination of the 3.8 percent requested increase in base electric rates and the effective 1.7 percent increase attributable to the rebates would be a 5.5 percent increase in electric billings.
As part of our electric and natural gas general rate case filings, we have requested the implementation of decoupling mechanisms, which sever the link between actual volumetric sales and the recovery of our fixed costs. Under the proposed decoupling mechanisms, we would compare actual non-power supply (electric) and non-PGA (natural gas) revenue to the allowed non-power supply and non-PGA revenue, as the case may be, and the difference would be deferred and either rebated or surcharged to customers, depending on the position of the deferral accounts, over a one-year period. The deferral balances would be reviewed annually by the UTC prior to the implementation of any annual rate adjustments under the mechanisms.
The proposed mechanisms would be subject to an annual earnings test which proposes that if our actual annual “Commission-basis” rate of return exceeds the most recently authorized Commission-basis rate of return for our Washington electric and natural gas operations, the amount of a proposed surcharge is reduced or eliminated to reduce the actual rate of return to the Commission-authorized level. In addition, the mechanisms would be subject to an annual rate increase limitation which would prevent the amount of the incremental proposed rate adjustments under the mechanisms from exceeding a 3 percent rate increase for each of electric and natural gas operations.
The UTC has up to 11 months to review the filings and issue a decision.
Idaho General Rate Cases
In September 2011, the IPUC approved a settlement agreement in our general rate case filed in July 2011. The new electric and natural gas rates became effective on October 1, 2011. The settlement agreement provided that base electric rates for our Idaho customers increase by an average of 1.1 percent, which was designed to increase annual revenues by $2.8 million. Base natural gas rates for our Idaho customers increased by an average of 1.6 percent, which was designed to increase annual revenues by $1.1 million.
The settlement agreement provided for the deferral of certain generation plant operation and maintenance costs. In order to address the variability in year-to-year operation and maintenance costs, beginning in 2011, we are deferring certain changes in operation and maintenance costs related to the Coyote Springs 2 natural gas-fired generation plant and our 15 percent ownership interest in Units 3&4 of the Colstrip generation plant. We compare actual, non-fuel, operation and maintenance expenses for the Coyote Springs 2 and Colstrip plants with the amount of expenses authorized for recovery in base rates in the applicable deferral year, and defer the difference from that currently authorized. The deferral occurs annually, with no carrying charge, with deferred costs being amortized over a three-year period, beginning in the year following the period costs are deferred. The amount of expense to be requested for recovery in future general rate cases will be the actual operation and maintenance expense recorded in the test period, less any amount deferred during the test period, plus the amortization of previously deferred costs. Total net deferred costs under this mechanism in Idaho were regulatory assets of $2.8 million as of December 31, 2013 and $2.3 million as of December 31, 2012.
In March 2013, the IPUC approved a settlement agreement in our electric and natural gas general rate cases filed in October 2012. As agreed to in the settlement, new rates were implemented in two phases: April 1, 2013 and October 1, 2013. Effective April 1, 2013, base rates increased for our Idaho natural gas customers by an overall 4.9 percent (designed to increase annual revenues by $3.1 million). There was no change in base electric rates on April 1, 2013. However, the settlement agreement
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provided for the recovery of the costs of the Palouse Wind Project through the PCA mechanism, subject to the 90 percent customers/10 percent Company sharing ratio, until these costs are reflected in base retail rates in our next general rate case.
The settlement also provided that, effective October 1, 2013, base rates increased for our Idaho natural gas customers by an overall 2.0 percent (designed to increase annual revenues by $1.3 million). A credit resulting from deferred natural gas costs of $1.6 million is being returned to our Idaho natural gas customers from October 1, 2013 through December 31, 2014, so the net annual average natural gas rate increase to natural gas customers effective October 1, 2013 was 0.3 percent.
Further, the settlement provided that, effective October 1, 2013, base rates increased for our Idaho electric customers by an overall 3.1 percent (designed to increase annual revenues by $7.8 million). A $3.9 million credit resulting from a payment made to us by the BPA relating to its prior use of our transmission system is being returned to Idaho electric customers from October 1, 2013 through December 31, 2014, so the net annual average electric rate increase to electric customers effective October 1, 2013 was 1.9 percent.
The $1.6 million credit to Idaho natural gas customers and the $3.9 million credit to Idaho electric customers do not impact our net income.
The settlement agreement allows us to file a general rate case in Idaho in 2014; however, new rates resulting from the filing would not take effect prior to January 1, 2015. We currently intend to file a general rate case in the second quarter of 2014 with proposed rates that would take effect on or after January 1, 2015. This provision does not preclude us from filing other rate adjustments such as the PGA.
The settlement agreement provides for an authorized return on equity of 9.8 percent and an equity ratio of 50.0 percent.
The settlement also includes an after-the-fact earnings test for 2013 and 2014, such that if Avista Corp., on a consolidated basis for electric and natural gas operations in Idaho, earns more than a 9.8 percent return on equity, we will refund to customers 50 percent of any earnings above the 9.8 percent. In 2013, our returns exceeded this level and we will refund $2.0 million to Idaho electric customers and $0.4 million to Idaho natural gas customers. The period over which these amounts will be returned to customers has not yet been determined by the IPUC.
Oregon General Rate Case
On January 21, 2014, the OPUC approved a settlement agreement to our natural gas general rate case (originally filed in August 2013). As agreed to in the settlement, new rates will be implemented in two phases: February 1, 2014 and November 1, 2014. Effective February 1, 2014, rates increased for Oregon natural gas customers on a billed basis by an overall 4.4 percent (designed to increase annual revenues by $4.3 million). Effective November 1, 2014, rates for Oregon natural gas customers will increase on a billed basis by an overall 1.6 percent (designed to increase annual revenues by $1.4 million).
The billed rate increase on November 1, 2014 could vary slightly from that noted above as it is dependent upon actual costs incurred through September 30, 2014 related to our customer information system upgrade and the actual costs incurred through June 30, 2014 related to our Aldyl A distribution pipeline replacement program. The estimated capital expenditures included in the general rate case settlement are $6.5 million and $2.0 million, respectively, for the two projects. If the actual costs incurred on the above projects are greater than the amounts contemplated in the general rate case settlement, the additional costs could be approved for recovery, subject to a prudence review.
The approved settlement agreement provides for an overall authorized rate of return of 7.47 percent, with a common equity ratio of 48 percent and a 9.65 percent return on equity.
Bonneville Power Administration Reimbursement and Reardan Wind Generation Project
In May 2013, the UTC approved our Petition for an order authorizing certain accounting and ratemaking treatment related to two issues. The first issue relates to transmission revenues associated with a settlement between Avista Corp. and the BPA, whereby the BPA reimbursed the Company $11.7 million for the BPA's past use of our transmission system. The second issue relates to $4.3 million of costs we incurred over the past several years for the development of a wind generation project site near Reardan, Washington, which was terminated. The UTC authorized us to retain $7.6 million of the BPA settlement payment, representing the entire portion of the settlement allocable to our Washington business. However, this amount was deemed to first reimburse the Company for the $2.5 million of Reardan project costs that are allocable to our Washington business, leaving $5.1 million to be retained for the benefit of shareholders.
The BPA agreed to pay $0.3 million monthly ($3.2 million annually) for the future use of our transmission system. We are separately tracking and deferring for the customers' benefit, the Washington portion of these revenue payments in 2013 and 2014 ($2.1 million annually). We implemented a one-year $4.2 million rate decrease for customers effective January 1, 2014 to partially offset our electric general rate increase effective January 1, 2014. To the extent actual revenues from the BPA in 2013 and 2014 differ from those refunded to customers in 2014, the difference will be added to or subtracted from the ERM balance.
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In Idaho, under the terms of the approved rate case settlement, 90 percent of the portion of the BPA settlement allocable to our Idaho business ($4.1 million) is being credited back to customers over 15 months, beginning October 2013, and we are amortizing the Idaho portion of Reardan costs ($1.7 million, including $1.3 million of incurred costs and $0.4 million of equity-related AFUDC) over a two-year period, beginning April 2013.
Purchased Gas Adjustments
PGAs are designed to pass through changes in natural gas costs to our customers with no change in gross margin (operating revenues less resource costs) or net income. In Oregon, we absorb (cost or benefit) 10 percent of the difference between actual and projected gas costs included in retail rates for supply that is not hedged. Total net deferred natural gas costs among all jurisdictions were a liability of $12.1 million as of December 31, 2013 and a liability of $6.9 million as of December 31, 2012.
The following PGAs went into effect in our various jurisdictions during 2012 and 2013:
| Jurisdiction | PGA Effective Date | Percentage Increase / (Decrease) in Billed Rates | ||
| Washington | March 1, 2012 | (6.4)% | ||
| November 1, 2012 | (4.4)% | |||
| November 1, 2013 | 9.2% | |||
| Idaho | March 1, 2012 | (6.0)% | ||
| October 1, 2012 | (3.1)% | |||
| October 1, 2013 | 7.5% | |||
| Oregon | November 1, 2012 (1) | (7.5)% | ||
January 1, 2013 (1) | (0.8)% | |||
| November 1, 2013 | (7.9)% | |||
| (1) | As it relates to the Oregon PGA, we requested that the PGA be implemented in two steps. The first step, implemented on November 1, 2012, was a decrease of 7.5 percent. The second step was an additional decrease of 0.8 percent, effective on January 1, 2013, to provide customers the net savings related to our purchase of the Klamath Falls Lateral transmission pipeline. |
Power Cost Deferrals and Recovery Mechanisms
The ERM is an accounting method used to track certain differences between actual power supply costs, net of the margin on wholesale sales and sales of fuel, and the amount included in base retail rates for our Washington customers. Total net deferred power costs under the ERM were a liability of $17.9 million as of December 31, 2013 compared to $22.2 million as of December 31, 2012, and these deferred power cost balances represent amounts due to customers. As part of the approved Washington general rate case settlement in December 2012, during 2013 there was a one-year credit designed to return $4.4 million to electric customers from the existing ERM deferral balance to reduce the net average electric rate increase impact to customers in 2013. Additionally, during 2014 there is a one-year credit designed to return $9.0 million to electric customers from the then-existing ERM deferral balance, so the net average electric rate increase impact to customers effective January 1, 2014 was also reduced. The credits to customers from the ERM balances do not impact our net income.
The difference in net power supply costs under the ERM primarily results from changes in:
| • | short-term wholesale market prices and sales and purchase volumes, |
| • | the level and availability of hydroelectric generation, |
| • | the level and availability of thermal generation (including changes in fuel prices), |
| • | the net value from optimization activities related to our generating resources, and |
| • | retail loads. |
Under the ERM, we absorb the cost or receive the benefit from the initial amount of power supply costs in excess of or below the level in retail rates, which is referred to as the deadband. The annual (calendar year) deadband amount is currently $4.0 million. We incur the cost of, or receive the benefit from, 100 percent of this initial power supply cost variance. We share annual power supply cost variances between $4.0 million and $10.0 million with customers. There is a 50 percent customers/50 percent Company sharing ratio when actual power supply expenses are higher (surcharge to customers) than the amount included in base retail rates within this band. There is a 75 percent customers/25 percent Company sharing ratio when actual
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power supply expenses are lower (rebate to customers) than the amount included in base retail rates within this band. To the extent that the annual power supply cost variance from the amount included in base rates exceeds $10.0 million, there is 90 percent customers/10 percent Company sharing ratio of the cost variance.
The following is a summary of the ERM:
| Annual Power Supply Cost Variability | Deferred for Future Surcharge or Rebate to Customers | Expense or Benefit to the Company | ||
| within +/- $0 to $4 million (deadband) | 0% | 100% | ||
| higher by $4 million to $10 million | 50% | 50% | ||
| lower by $4 million to $10 million | 75% | 25% | ||
| higher or lower by over $10 million | 90% | 10% | ||
Under the ERM, we make an annual filing on or before April 1 of each year to provide the opportunity for the UTC staff and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. We made our annual filing on March 28, 2013. The ERM provides for a 90-day review period for the filing; however, the period may be extended by agreement of the parties or by UTC order. The 2012 ERM deferred power cost transactions were approved by an order from the UTC on July 11, 2013.
As part of the April 2012 Washington general rate case filing, we proposed modifications to the ERM deadband and other sharing bands. The proposed modifications were not agreed to as part of the settlement agreement, and the ERM continued unchanged. However, the trigger point at which rates will change under the ERM was modified to be $30 million rather than the previous 10 percent of base revenues (approximately $45 million) under the mechanism.
We have a PCA mechanism in Idaho that allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power supply costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were an asset of $5.1 million as of December 31, 2013 compared to a liability of $5.1 million as of December 31, 2012.
Results of Operations
The following provides an overview of changes in our Consolidated Statements of Income. More detailed explanations are provided, particularly for operating revenues and operating expenses, in the business segment discussions (Avista Utilities, Ecova and the other businesses) that follow this section.
2013 compared to 2012
Utility revenues increased $49.8 million, after elimination of intracompany revenues of $151.9 million for 2013 and $88.2 million for 2012. Including intracompany revenues, electric revenues increased $62.4 million and natural gas revenues increased $51.1 million. Total retail electric revenues increased $13.8 million due to general rate increases and an increase in volumes sold, which was primarily the result of warmer than normal weather during the cooling season and colder than normal weather during the fourth quarter heating season. Wholesale electric revenues increased $24.8 million and sales of fuel increased $10.8 million. Other electric revenues increased $15.0 million primarily due to the receipt of revenue from the BPA for past use of our electric transmission system. Retail natural gas revenues increased $13.3 million due to an increase in volumes caused by colder than normal weather during the fourth quarter, partially offset by a decrease in retail rates. Wholesale natural gas revenues increased $36.1 million due to an increase in prices, partially offset by a decrease in volumes.
Ecova revenues increased $21.1 million to $176.8 million primarily as a result of an increase in revenues associated with new services, expense and data management services, and energy management services. In addition, results benefited from the recognition of a $2.3 million rebate during the third quarter associated with achieving certain milestones on a five-year contract related to expense and data management services.
Utility resource costs decreased $3.5 million, after elimination of intracompany resource costs of $151.9 million for 2013 and $88.2 million for 2012. Including intracompany resource costs, electric resource costs increased $24.8 million and natural gas resource costs increased $35.4 million. The increase in electric resource costs was primarily due to an increase in fuel costs (due to higher natural gas generation and higher natural gas fuel prices), other fuel costs (represents fuel that was purchased for generation but was later sold when conditions indicated that it was not economical to use the fuel for generation as part of the resource optimization process) and the write-off of $2.5 million of Reardan project costs that are allocable to our Washington business. The increase in natural gas resource costs was primarily due to an increase in natural gas prices, partially offset by a decrease in volumes (primarily attributable to wholesale sales).
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Utility other operating expenses decreased $0.6 million primarily as a result of a decrease in administrative and general labor expenses (which included $7.3 million of costs to implement the voluntary severance incentive plan in 2012 only) and a decrease in generation maintenance expenses. These decreases were partially offset by increases in pension and other postretirement benefit expenses and electric, production and gas distribution related operating and maintenance expenses.
Utility depreciation and amortization increased $5.1 million driven by additions to utility plant.
Taxes other than income taxes increased $5.0 million primarily due to increased franchise, municipal, and property related taxes.
Ecova other operating expenses increased $8.9 million primarily reflecting increased costs associated with new services and higher volumes in expense and data management services and energy management services. These were partially offset by a decrease in integration and acquisition costs of $2.6 million, which Ecova incurred during 2012 and did not reoccur during 2013.
Ecova depreciation and amortization increased $1.9 million primarily due to additions to software development costs, additional amortization of intangibles recorded in connection with Ecova's acquisitions and the impairment of $0.4 million of intangible assets during 2013.
Other non-utility operating expenses increased $0.6 million primarily due to increased costs associated with strategic investments, increased operating and maintenance and other expenses at METALfx, partially offset by decreased litigation costs associated with the previous operations of Avista Energy.
Interest expense increased $1.9 million primarily due to the issuance of long-term debt in November 2012 that increased the amount of long-term debt outstanding.
Capitalized interest increased $1.3 million primarily due to higher average construction work in progress balances.
Other income-net increased $1.7 million primarily due to an increase in equity-related AFUDC of $2.0 million. In addition, during 2013 we incurred impairment losses of $3.4 million ($2.2 million after-tax) associated with our investment in an energy storage company and our investment in a fuel cell business. During 2012, we incurred total losses on investments of $3.3 million, which included impairment losses of $2.4 million ($1.5 million after-tax) related to our investment in a fuel cell business and the write-off of our investment in a solar energy company.
Income taxes increased $22.0 million and our effective tax rate was 36.0 percent for 2013 compared to 34.4 percent for 2012. The increase in expense was primarily due to an increase in income before income taxes. The change in the effective tax rate is primarily related to a reduction in the amount of our pension contribution deduction.
2012 compared to 2011
Utility revenues decreased $89.1 million, after elimination of intracompany revenues of $88.2 million in 2012 and $93.1 million in 2011. Including intracompany revenues, electric revenues decreased $20.0 million and natural gas revenues decreased $74.1 million. Retail electric revenues decreased $5.9 million due to a decrease in volumes sold which was primarily the result of warmer weather during the heating season and lower usage at certain industrial customers, due to temporary operational challenges at these customers. This was mostly offset during the third quarter due to warmer weather (and increased cooling loads), which increased electric use per customer and also general rate increases. In addition, sales of fuel decreased $37.6 million due to a decrease in sales of natural gas fuel as part of thermal generation resource optimization activities and higher usage of our thermal generation plants. These decreases were partially offset by an increase in wholesale sales of $24.4 million due to an increase in sales volumes partially offset by a decrease in sales prices. Retail natural gas revenues decreased $36.6 million due to a decrease in volumes caused by warmer weather. Wholesale natural gas revenues decreased $37.3 million due to a decrease in prices, partially offset by an increase in volumes.
Ecova revenues increased $17.8 million to $155.7 million primarily as a result of Ecova's acquisitions of Prenova effective November 30, 2011 and LPB effective January 31, 2012.
Utility resource costs decreased $96.9 million, after elimination of intracompany resource costs of $88.2 million in 2012 and $93.1 million in 2011. Including intracompany resource costs, electric resource costs decreased $32.9 million and natural gas resource costs decreased $68.9 million. The decrease in electric resource costs was primarily due to a decrease in other fuel costs (represents fuel that was purchased for generation but was later sold when conditions indicated that it was not economical to use the fuel for generation as part of the resource optimization process) and the amortization of deferred power supply costs, partially offset by an increase in fuel costs (due to higher thermal generation) and power purchased. The decrease in natural gas resource costs was primarily due to a decrease in natural gas prices, partially offset by an increase in volumes.
Utility other operating expenses increased $14.9 million primarily due to labor (including $7.3 million of costs under the voluntary severance incentive plan), increased pensions and other postretirement benefits, and electric distribution costs,
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partially offset by decreased electric maintenance costs (which included the regulatory deferral of $6.7 million of maintenance costs) and outside service costs.
Utility depreciation and amortization increased $6.5 million driven by additions to utility plant.
Ecova other operating expenses increased $29.4 million primarily reflecting increased costs necessary for business growth and the acquisitions of Prenova and LPB, including transaction and integration costs of $2.6 million.
Ecova depreciation and amortization increased $6.3 million primarily due to the amortization of intangibles recorded in connection with Ecova's acquisitions of Prenova and LPB.
Other non-utility operating expenses increased $4.9 million primarily due to increased outside service expense of $1.2 million and increased consulting services and other corporate costs that could not be charged to utility customers of $2.5 million.
Interest expense increased $3.0 million primarily due to the issuance of long-term debt in December 2011 that increased the balance of long-term debt outstanding.
Other income-net increased $1.6 million primarily due to an increase in equity method earnings of $1.8 million from Ecova's investment in the SEEL variable interest entity. In prior years, this entity was consolidated and the operating revenues and expenses were included in the consolidated results of the Company. Additionally, equity-related AFUDC increased $1.8 million. These increases in other income were offset by an increase in losses on investments, including $2.4 million for the impairment of our investment in a fuel cell business and the write-off of our investment in a solar energy company.
Income taxes decreased $15.4 million and our effective tax rate was 34.4 percent for 2012 compared to 35.4 percent for 2011. The decrease in expense was primarily due to a decrease in income before income taxes.
Avista Utilities
Non-GAAP Financial Measures
The following discussion includes two financial measures that are considered “non-GAAP financial measures,” electric gross margin and natural gas gross margin. Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that excludes (or includes) amounts that are included (excluded) in the most directly comparable measure calculated and presented in accordance with GAAP. The presentation of electric gross margin and natural gas gross margin is intended to supplement an understanding of Avista Utilities' operating performance. We use these measures to determine whether the appropriate amount of energy costs are being collected from our customers to allow for recovery of operating costs, as well as to analyze how changes in loads (due to weather, economic or other conditions), rates, supply costs and other factors impact our results of operations. These measures are not intended to replace income from operations as determined in accordance with GAAP as an indicator of operating performance. The calculations of electric and natural gas gross margins are presented below.
2013 compared to 2012
Net income for Avista Utilities was $108.6 million for 2013, an increase from $81.7 million for 2012. Avista Utilities’ income from operations was $232.6 million for 2013 compared to $188.8 million for 2012. Earnings at Avista Utilities increased primarily due to the implementation of general rate increases, favorable weather, the net benefit from the settlement with the BPA and a slight reduction in other operating expenses. These were partially offset by expected increases in depreciation and amortization and taxes other than income taxes.
The following table presents our operating revenues, resource costs and resulting gross margin for the year ended December 31 (dollars in thousands):
| Electric | Natural Gas | Intracompany | Total | ||||||||||||||||||||||||||||
| 2013 | 2012 | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||||||||||
| Operating revenues | $ | 1,030,606 | $ | 968,172 | $ | 525,259 | $ | 474,173 | $ | (151,870 | ) | $ | (88,160 | ) | $ | 1,403,995 | $ | 1,354,185 | |||||||||||||
| Resource costs | 476,226 | 451,434 | 365,230 | 329,853 | (151,870 | ) | (88,160 | ) | 689,586 | 693,127 | |||||||||||||||||||||
| Gross margin | $ | 554,380 | $ | 516,738 | $ | 160,029 | $ | 144,320 | $ | — | $ | — | $ | 714,409 | $ | 661,058 | |||||||||||||||
Avista Utilities’ operating revenues increased $49.8 million and resource costs decreased $3.5 million, which resulted in an increase of $53.3 million in gross margin. The gross margin on electric sales increased $37.6 million and the gross margin on natural gas sales increased $15.7 million. The increase in both electric and natural gas gross margin was due in part to general rate increases. The increase in electric gross margin was also due to warmer than normal weather and increased cooling loads during the summer, as well as colder than normal weather and increased heating loads during the fourth quarter. This is
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compared to milder weather in the prior year, particularly warmer than normal weather during the fourth quarter, which reduced loads during that period. In addition, electric gross margin increased due to the net benefit from the settlement with the BPA of $5.1 million. For 2013, we recognized a pre-tax expense of $4.7 million under the ERM in Washington compared to a pre-tax benefit of $6.0 million for 2012. This change, which reduced electric gross margin, was primarily due to the Colstrip outage and partially due to lower hydroelectric generation and higher natural gas fuel prices as compared to 2012. The increase in natural gas gross margin was also due to colder than normal weather during the fourth quarter of 2013 as compared to the fourth quarter of 2012 and the increased heating loads. In addition to the above, our combined electric and natural gas earnings in Idaho for 2013 exceeded the 9.8 percent allowed return on equity as specified in the 2013 general rate case settlement, and, as a result, we will refund $2.0 million to Idaho electric customers and $0.4 million to Idaho natural gas customers. See further discussion of this refund provision above at "Idaho General Rate Cases."
Intracompany revenues and resource costs represent purchases and sales of natural gas between our natural gas distribution operations and our electric generation operations (as fuel for our generation plants). These transactions are eliminated in the presentation of total results for Avista Utilities and in the consolidated financial statements but are reflected in the presentation of the separate results for electric and natural gas below.
The following table presents our utility electric operating revenues and megawatt-hour (MWh) sales for the year ended December 31 (dollars and MWhs in thousands):
Electric Operating Revenues | Electric Energy MWh sales | ||||||||||||
| 2013 | 2012 | 2013 | 2012 | ||||||||||
| Residential | $ | 331,867 | $ | 315,137 | 3,745 | 3,608 | |||||||
| Commercial | 289,604 | 286,568 | 3,147 | 3,127 | |||||||||
| Industrial | 113,632 | 119,589 | 1,979 | 2,100 | |||||||||
| Public street and highway lighting | 7,267 | 7,240 | 26 | 26 | |||||||||
| Total retail | 742,370 | 728,534 | 8,897 | 8,861 | |||||||||
| Wholesale | 127,556 | 102,736 | 3,874 | 3,733 | |||||||||
| Sales of fuel | 126,657 | 115,835 | — | — | |||||||||
| Other | 36,071 | 21,067 | — | — | |||||||||
| Provision for refunds | (2,048 | ) | — | — | — | ||||||||
| Total | $ | 1,030,606 | $ | 968,172 | 12,771 | 12,594 | |||||||
Retail electric revenues increased $13.8 million due to an increase in revenue per MWh (increased revenues $10.8 million) and an increase in total MWhs sold (increased revenues $3.0 million).
The increase in total MWhs sold was primarily the result of warmer than normal weather during the cooling season, as well as colder than normal weather during the fourth quarter heating season. Compared to 2012, residential electric use per customer increased 3 percent. Cooling degree days at Spokane were 80 percent above historical average for 2013 and were 33 percent above 2012. Heating degree days at Spokane were 1 percent below historical average for 2013, and 7 percent above 2012.
The decrease in total MWhs sold to industrial customers was primarily due to a renewed contract which replaced an expired contract at one of our largest industrial customers which became effective July 1, 2013, partially offset by increased usage at certain industrial customers that had temporary operational challenges in 2012. Under the renewed contract, we expect a decrease in revenues from annual power sales to this customer of approximately $21 million and a resulting decrease in resource costs of approximately $19 million. Any change in revenues and expenses associated with the new agreement, as compared with the revenues and expenses included in the last general rate case for this customer, will be tracked through the PCA in Idaho at 100 percent, until such time as the contract is included in the Company’s base rates, so that we expect no impact on our gross margin or net income from the new agreement.
The increase in revenue per MWh was primarily due to a change in revenue mix, with a greater percentage of retail revenue from residential and commercial customers, and the Washington general rate increase, partially offset by other rate changes that do not impact gross margin (including the ERM rebate).
Wholesale electric revenues increased $24.8 million due to an increase in sales volumes (increased revenues $4.7 million) and an increase in sales prices (increased revenues $20.1 million), which were related to an increase in optimization activities.
When current and forward electric wholesale market prices are below the cost of operating our natural gas-fired thermal generating units, we sell the related natural gas purchased for generation in the wholesale market rather than operate the generating units. The revenues from sales of fuel increased $10.8 million due to an increase in sales of natural gas fuel as part of thermal generation resource optimization activities, as well as an increase in natural gas prices. These thermal optimization
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transactions also include forward hedges using derivative instruments for electricity and natural gas. As relative power and natural gas prices vary, our volume of thermal optimization also varies. For 2013, $102.4 million of these sales were made to our natural gas operations and are included as intracompany revenues and resource costs. For 2012, $45.3 million of these sales were made to our natural gas operations.
The net margin on wholesale sales and sales of fuel is applied to reduce or increase resource costs as accounted for under the ERM, the PCA mechanism, and in general rate cases as part of base power supply costs.
Other electric revenues increased $15.0 million primarily due to the receipt of $11.7 million of revenue from the BPA for past use of our electric transmission system. See further information above at "Bonneville Power Administration Reimbursement and Reardan Wind Generation Project."
The 2013 Idaho general rate case settlement includes an after-the-fact earnings test for 2013 and 2014, such that if Avista Corp., on a consolidated basis for electric and natural gas operations in Idaho, earns more than a 9.8 percent return on equity, we will refund to customers 50 percent of any earnings above the 9.8 percent. In 2013, our returns exceeded this level and we will refund $2.0 million to Idaho electric customers.
The following table presents our utility natural gas operating revenues and therms delivered for the year ended December 31 (dollars and therms in thousands):
Natural Gas Operating Revenues | Natural Gas Therms Delivered | ||||||||||||
| 2013 | 2012 | 2013 | 2012 | ||||||||||
| Residential | $ | 206,330 | $ | 196,719 | 204,711 | 189,152 | |||||||
| Commercial | 102,225 | 98,994 | 122,245 | 115,083 | |||||||||
| Interruptible | 2,681 | 2,232 | 5,694 | 4,363 | |||||||||
| Industrial | 3,599 | 3,635 | 5,181 | 5,073 | |||||||||
| Total retail | 314,835 | 301,580 | 337,831 | 313,671 | |||||||||
| Wholesale | 194,717 | 158,631 | 524,818 | 586,193 | |||||||||
| Transportation | 7,576 | 7,032 | 159,976 | 154,704 | |||||||||
| Other | 8,573 | 6,930 | 418 | 381 | |||||||||
| Provision for refunds | (442 | ) | — | — | — | ||||||||
| Total | $ | 525,259 | $ | 474,173 | 1,023,043 | 1,054,949 | |||||||
Retail natural gas revenues increased $13.3 million primarily due to an increase in volumes (increased revenues $22.5 million), partially offset by lower retail rates (decreased revenues $9.2 million). We sold more retail natural gas in 2013 as compared to 2012 primarily due to colder than normal weather during the fourth quarter. Compared to 2012, residential use per customer increased 7 percent and commercial use per customer increased 6 percent. Heating degree days at Spokane were 1 percent below historical average for 2013, and 7 percent above 2012. Heating degree days at Medford were 1 percent above historical average for 2013, and 9 percent above 2012. For the fourth quarter of 2013, heating degree days at Spokane were 3 percent above historical average and 16 percent above 2012. Heating degree days at Medford were 12 percent above historical average and 29 percent above 2012.
Wholesale natural gas revenues increased $36.1 million due to an increase in prices (increased revenues $58.9 million), partially offset by a decrease in volumes (decreased revenues $22.8 million). We plan for sufficient natural gas capacity to serve our retail customers on a theoretical peak day. As such, on nonpeak days we generally have more pipeline and storage capacity than what is needed for retail loads. We engage in optimization of available interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas to generate economic value that partially offsets net natural gas costs. In some situations, customer demand is below the amount hedged and we sell natural gas in excess of load requirements. In 2013, $49.5 million of these sales were made to our electric generation operations and are included as intracompany revenues and resource costs. In 2012, $42.9 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.
Based on the after-the-fact earnings test related to the 2013 Idaho general rate case settlement discussed above, our 2013 consolidated earnings exceeded the allowed return on equity for Idaho and we will refund $0.4 million to Idaho natural gas customers.
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The following table presents our average number of electric and natural gas retail customers for the year ended December 31:
Electric Customers | Natural Gas Customers | ||||||||||
| 2013 | 2012 | 2013 | 2012 | ||||||||
| Residential | 321,098 | 318,692 | 288,708 | 286,522 | |||||||
| Commercial | 40,202 | 39,869 | 33,932 | 33,763 | |||||||
| Interruptible | — | — | 38 | 38 | |||||||
| Industrial | 1,386 | 1,395 | 259 | 263 | |||||||
| Public street and highway lighting | 527 | 503 | — | — | |||||||
| Total retail customers | 363,213 | 360,459 | 322,937 | 320,586 | |||||||
The following table presents our utility resource costs for the year ended December 31 (dollars in thousands):
| 2013 | 2012 | ||||||
| Electric resource costs: | |||||||
| Power purchased | $ | 189,930 | $ | 194,088 | |||
| Power cost amortizations, net | (14,192 | ) | 12,784 | ||||
| Fuel for generation | 133,663 | 90,029 | |||||
| Other fuel costs | 121,987 | 120,074 | |||||
| Other regulatory amortizations, net | 22,734 | 15,665 | |||||
| Other electric resource costs | 22,104 | 18,794 | |||||
| Total electric resource costs | 476,226 | 451,434 | |||||
| Natural gas resource costs: | |||||||
| Natural gas purchased | 353,087 | 327,458 | |||||
| Natural gas cost amortizations, net | 4,784 | (5,804 | ) | ||||
| Other regulatory amortizations, net | 7,359 | 8,199 | |||||
| Total natural gas resource costs | 365,230 | 329,853 | |||||
| Intracompany resource costs | (151,870 | ) | (88,160 | ) | |||
| Total resource costs | $ | 689,586 | $ | 693,127 | |||
Power purchased decreased $4.2 million due to a decrease in wholesale prices (decreased costs $6.6 million), partially offset by an increase in the volume of power purchases (increased costs $2.4 million).
Amortizations and deferrals of power costs decreased electric resource costs by $14.2 million for 2013 compared to an increase of $12.8 million for 2012. During 2013, we refunded to customers $3.3 million of previously deferred power costs in Idaho through the PCA rebate. As part of the Washington general rate case settlement implemented on January 1, 2013, we refunded to customers $4.0 million through an ERM rebate. During 2013, actual power supply costs were above the amount included in base retail rates and we deferred $1.2 million in Washington and $6.9 million in Idaho for potential future surcharge to customers. In Washington, we also deferred $1.2 million of renewable energy related revenue for potential future rebate to customers.
Fuel for generation increased $43.6 million due to an increase in natural gas generation and an increase in natural gas fuel prices. Generation at Colstrip decreased due to an outage at Unit 4.
Other fuel costs increased $1.9 million. This represents fuel and the related derivative instruments that were purchased for generation but were later sold when conditions indicated that it was not economical to use the fuel for generation, as part of the resource optimization process. When the fuel or related derivative instruments are sold, that revenue is included in sales of fuel.
Electric other regulatory amortizations increased $7.1 million primarily due to the regulatory deferral of $3.9 million for the Idaho portion of the BPA revenue for future refund to our Idaho customers and $2.1 million of 2013 BPA revenue deferred for future rebate to our Washington customers.
Other electric resource costs increased $3.3 million primarily due to the write-off of $2.5 million of Reardan project costs that are allocable to our Washington business.
The expense for natural gas purchased increased $25.6 million due to an increase in the price of natural gas (increased costs $40.8 million), partially offset by a decrease in total therms purchased (decreased costs $15.2 million). Total therms purchased decreased due to a decrease in wholesale sales volumes which are used to balance loads and resources as part of the natural gas
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procurement and resource optimization process, partially offset by a slight increase in retail sales. We engage in optimization of available interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas to generate economic value that offsets net natural gas costs.
2012 compared to 2011
Net income for Avista Utilities was $81.7 million for 2012, a decrease from $90.9 million for 2011. Avista Utilities’ income from operations was $188.8 million for 2012 compared to $202.4 million for 2011. The decrease in net income and income from operations was primarily due to reduced retail loads during the first and fourth quarters of the year and an increase in other operating expenses (including costs for the voluntary severance incentive program), and depreciation and amortization, partially offset by the implementation of general rate increases. The decrease in net income from Avista Utilities was also due to an increase in interest expense.
The following table presents our operating revenues, resource costs and resulting gross margin for the year ended December 31 (dollars in thousands):
| Electric | Natural Gas | Intracompany | Total | ||||||||||||||||||||||||||||
| 2012 | 2011 | 2012 | 2011 | 2012 | 2011 | 2012 | 2011 | ||||||||||||||||||||||||
| Operating revenues | $ | 968,172 | $ | 988,187 | $ | 474,173 | $ | 548,225 | $ | (88,160 | ) | $ | (93,090 | ) | $ | 1,354,185 | $ | 1,443,322 | |||||||||||||
| Resource costs | 451,434 | 484,359 | 329,853 | 398,779 | (88,160 | ) | (93,090 | ) | 693,127 | 790,048 | |||||||||||||||||||||
| Gross margin | $ | 516,738 | $ | 503,828 | $ | 144,320 | $ | 149,446 | $ | — | $ | — | $ | 661,058 | $ | 653,274 | |||||||||||||||
Avista Utilities’ operating revenues decreased $89.1 million and resource costs decreased $96.9 million, which resulted in an increase of $7.8 million in gross margin. The gross margin on electric sales increased $12.9 million and the gross margin on natural gas sales decreased $5.1 million. The increase in electric gross margin was primarily due to general rate increases. This was partially offset by warmer weather during the heating season (primarily the first and fourth quarters) that reduced retail loads. In addition, electric gross margin growth was limited in part by lower usage at certain industrial customers due to temporary operational challenges. Natural gas gross margin decreased primarily due to warmer weather throughout the year that reduced retail heating loads, partially offset by general rate increases. For 2012, we recognized a pre-tax benefit of $6.0 million under the ERM in Washington compared to $6.4 million for 2011.
Intracompany revenues and resource costs represent purchases and sales of natural gas between our natural gas distribution operations and our electric generation operations (as fuel for our generation plants). These transactions are eliminated in the presentation of Avista Utilities' total results and in the consolidated financial statements.
The following table presents our utility electric operating revenues and megawatt-hour (MWh) sales for the year ended December 31 (dollars and MWhs in thousands):
Electric Operating Revenues | Electric Energy MWh sales | ||||||||||||
| 2012 | 2011 | 2012 | 2011 | ||||||||||
| Residential | $ | 315,137 | $ | 324,835 | 3,608 | 3,728 | |||||||
| Commercial | 286,568 | 280,139 | 3,127 | 3,122 | |||||||||
| Industrial | 119,589 | 122,560 | 2,100 | 2,147 | |||||||||
| Public street and highway lighting | 7,240 | 6,941 | 26 | 26 | |||||||||
| Total retail | 728,534 | 734,475 | 8,861 | 9,023 | |||||||||
| Wholesale | 102,736 | 78,305 | 3,733 | 2,796 | |||||||||
| Sales of fuel | 115,835 | 153,470 | — | — | |||||||||
| Other | 21,067 | 21,937 | — | — | |||||||||
| Total | $ | 968,172 | $ | 988,187 | 12,594 | 11,819 | |||||||
Retail electric revenues decreased $5.9 million due to a decrease in total MWhs sold (decreased revenues $13.3 million) offset by an increase in revenue per MWh (increased revenues $7.3 million). The decrease in MWhs sold was primarily the result of warmer weather during the heating season, and due in part to lower usage at certain industrial customers due to temporary operational challenges. This was partially offset during the cooling season due to warmer weather (and increased loads), which increased electric use per customer. Compared to 2011, residential electric use per customer decreased 4 percent. Cooling degree days at Spokane were 23 percent above historical average for 2012 and were 26 percent above 2011. Heating degree days at Spokane were 6 percent below historical average for 2012, and 9 percent below 2011. The increase in revenue per MWh was primarily due to the Washington and Idaho general rate increases.
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Wholesale electric revenues increased $24.4 million due to an increase in sales volumes (increased revenues $25.8 million), partially offset by a decrease in sales prices (decreased revenues $1.4 million). The increase in sales volumes was primarily due to the fact that our retail sales were lower than expected, as discussed above, and we sold the resulting excess capacity, energy and fuel on the wholesale market through our optimization procedures.
When current and forward electric wholesale market prices are below the cost of operating our natural gas-fired thermal generating units, we sell the natural gas purchased for generation in the wholesale market rather than operate the generating units. The revenues from sales of fuel decreased $37.6 million due to a decrease in sales of natural gas fuel as part of thermal generation resource optimization activities and higher usage of our thermal generation plants in 2012 as compared to 2011, as well as a decrease in natural gas prices. Higher usage of our thermal generation plants was due in part to decreased hydroelectric generation. The thermal optimization transactions also include forward hedges using derivative instruments for electricity and natural gas. As relative power and natural gas prices vary, our volume of thermal optimization also varies. For 2012, $45.3 million of these sales were made to our natural gas operations and are included as intracompany revenues and resource costs. For 2011, $38.6 million of these sales were made to our natural gas operations.
The net margin on wholesale sales and sales of fuel is applied to reduce or increase resource costs as accounted for under the ERM, the PCA mechanism, and in general rate cases as part of base power supply costs.
The following table presents our utility natural gas operating revenues and therms delivered for the year ended December 31 (dollars and therms in thousands):
Natural Gas Operating Revenues | Natural Gas Therms Delivered | ||||||||||||
| 2012 | 2011 | 2012 | 2011 | ||||||||||
| Residential | $ | 196,719 | $ | 219,557 | 189,152 | 207,202 | |||||||
| Commercial | 98,994 | 111,964 | 115,083 | 125,344 | |||||||||
| Interruptible | 2,232 | 2,519 | 4,363 | 4,503 | |||||||||
| Industrial | 3,635 | 4,180 | 5,073 | 5,654 | |||||||||
| Total retail | 301,580 | 338,220 | 313,671 | 342,703 | |||||||||
| Wholesale | 158,631 | 195,882 | 586,193 | 510,755 | |||||||||
| Transportation | 7,032 | 6,709 | 154,704 | 152,515 | |||||||||
| Other | 6,930 | 7,414 | 381 | 440 | |||||||||
| Total | $ | 474,173 | $ | 548,225 | 1,054,949 | 1,006,413 | |||||||
Retail natural gas revenues decreased $36.6 million primarily due to a decrease in volumes (decreased revenues $27.9 million) and lower retail rates (decreased revenues $8.7 million). We sold less retail natural gas in 2012 as compared to 2011 primarily due to warmer weather. Compared to 2011, residential and commercial natural gas use per customer decreased 9 percent. Heating degree days at Spokane were 6 percent below historical average for 2012, and 9 percent below 2011. Heating degree days at Medford were 5 percent below historical average for 2012, and 10 percent below 2011.
Wholesale natural gas revenues decreased $37.3 million due to a decrease in prices (decreased revenues $57.7 million), partially offset by an increase in volumes (increased revenues $20.4 million). We plan for sufficient natural gas capacity to serve our retail customers on a theoretical peak day. As such, on nonpeak days we generally have more pipeline and storage capacity than what is needed for retail loads. We engage in optimization of available interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas to generate economic value that partially offsets net natural gas costs. In some situations, customer demand is below the amount hedged and we sell natural gas in excess of load requirements. In 2012, $42.9 million of these sales were made to our electric generation operations and are included as intracompany revenues and resource costs. In 2011, $54.5 million of these sales were made to our electric generation operations. Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.
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The following table presents our average number of electric and natural gas retail customers for the year ended December 31:
Electric Customers | Natural Gas Customers | ||||||||||
| 2012 | 2011 | 2012 | 2011 | ||||||||
| Residential | 318,692 | 316,762 | 286,522 | 284,504 | |||||||
| Commercial | 39,869 | 39,618 | 33,763 | 33,540 | |||||||
| Interruptible | — | — | 38 | 38 | |||||||
| Industrial | 1,395 | 1,380 | 263 | 255 | |||||||
| Public street and highway lighting | 503 | 455 | — | — | |||||||
| Total retail customers | 360,459 | 358,215 | 320,586 | 318,337 | |||||||
The following table presents our utility resource costs for the year ended December 31 (dollars in thousands):
| 2012 | 2011 | ||||||
| Electric resource costs: | |||||||
| Power purchased | $ | 194,088 | $ | 169,845 | |||
| Power cost amortizations, net | 12,784 | 31,910 | |||||
| Fuel for generation | 90,029 | 84,367 | |||||
| Other fuel costs | 120,074 | 164,173 | |||||
| Other regulatory amortizations, net | 15,665 | 16,381 | |||||
| Other electric resource costs | 18,794 | 17,683 | |||||
| Total electric resource costs | 451,434 | 484,359 | |||||
| Natural gas resource costs: | |||||||
| Natural gas purchased | 327,458 | 396,497 | |||||
| Natural gas cost amortizations, net | (5,804 | ) | (10,041 | ) | |||
| Other regulatory amortizations, net | 8,199 | 12,323 | |||||
| Total natural gas resource costs | 329,853 | 398,779 | |||||
| Intracompany resource costs | (88,160 | ) | (93,090 | ) | |||
| Total resource costs | $ | 693,127 | $ | 790,048 | |||
Power purchased increased $24.2 million due to an increase in the volume of power purchases (increased costs $26.7 million), partially offset by a decrease in wholesale prices (decreased costs $2.4 million).
Net amortization of deferred power costs was $12.8 million for 2012 compared to $31.9 million for 2011. During 2012, we recovered (collected as revenue) $1.3 million of previously deferred power costs in Idaho through the PCA surcharge. During 2012, actual power supply costs were below the amount included in base retail rates and we deferred $8.9 million in Washington and $2.6 million in Idaho for potential future rebate to customers.
Fuel for generation increased $5.7 million primarily due to an increase in thermal generation. This was due in part to a decrease in hydroelectric generation. The increase in thermal generation usage was partially offset by a decrease in natural gas fuel prices.
Other fuel costs decreased $44.1 million. This represents fuel and the related derivative instruments that were purchased for generation but were later sold when conditions indicated that it was not economical to use the fuel for generation, as part of the resource optimization process. When the fuel or related derivative instruments are sold, that revenue is included in sales of fuel.
The expense for natural gas purchased decreased $69.0 million due to a decrease in the price of natural gas (decreased costs $85.9 million), partially offset by an increase in total therms purchased (increased costs $16.9 million). Total therms purchased increased due to an increase in wholesale sales which are used to balance loads and resources as part of the natural gas procurement and resource optimization process. We engage in optimization of available interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas to generate economic value that offsets net natural gas costs.
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Ecova
2013 compared to 2012
Ecova's net income attributable to Avista Corp. shareholders was $7.1 million for 2013 compared to net income of $1.8 million for 2012. Operating revenues increased $21.1 million and operating expenses increased $10.8 million. The increase in operating revenues was primarily the result of new services performed by Ecova, which added $9.9 million to revenue. In addition, growth in expense and data management services and energy management services (primarily an increase in volumes) added $6.4 million and $4.8 million to revenue, respectively. The increase in expense and data management services was partially the result of the recognition of a $2.3 million rebate in 2013 associated with achieving certain milestones on a five-year contract related to expense and data management services.
Ecova's other operating expenses associated with cost of services increased $10.3 million for 2013 and totaled $94.2 million. Expenses associated with new services added $7.5 million to cost of services and higher revenue volumes in expense and data management services and energy management services each added $1.4 million to cost of services.
Ecova's other operating expenses associated with selling, general and administrative expenses decreased by $1.5 million for 2013 and totaled $53.9 million. This decrease was the result of a decrease in acquisition and integration costs of $2.6 million, which were incurred during 2012 and did not reoccur during 2013 and a decrease in employee related costs. These were partially offset by a Business & Occupation tax refund that was received during 2012 and small increases in various other selling, general and administrative accounts.
Depreciation and amortization increased $1.9 million primarily due to additions to software development costs, additional amortization of intangibles recorded in connection with Ecova's acquisitions, and the impairment of $0.4 million of intangible assets during 2013.
As of December 31, 2013, Ecova had over 750 expense management and utility customers representing over 700,000 billed sites in North America. In 2013, Ecova managed customer energy spend totaling $20.9 billion, an increase of $1.5 billion as compared to 2012 primarily due to an increase in the number of billed sites.
2012 compared to 2011
Ecova's net income attributable to Avista Corp. shareholders was $1.8 million for 2012 compared to net income of $9.7 million for 2011. Operating revenues increased $17.8 million and total operating expenses increased $35.8 million. The increase in operating revenues was primarily the result of the acquisitions of Prenova effective November 30, 2011 and LPB effective January 31, 2012, which added $22.5 million to operating revenues for 2012 over 2011 revenues. In addition, there were delays associated with the process of onboarding new customers onto the monitoring system for energy management services due to more complex customers and systems, and there was a reduction in revenues related to the deconsolidation of a partnership. This, combined with the increased operating expenses, has contributed to a net decrease in net income attributable to Avista Corp. shareholders.
The increase in total operating expenses primarily reflects increased costs necessary to support ongoing and future business growth, as well as to support the increased revenue volume obtained through the acquisitions. There were increases in employee costs of $20.5 million, facilities costs of $1.7 million, and information technology costs and professional fees of $4.6 million. In addition, Ecova incurred $2.6 million in transaction and integration costs. Depreciation and amortization increased $6.3 million due to intangibles recorded in connection with the acquisitions. Included in the increased depreciation and amortization is an impairment loss of $0.7 million after-tax related to the write-off of internally developed software during the fourth quarter of 2012.
As of December 31, 2012, Ecova had 740 expense management customers representing 697,076 billed sites in North America. In 2012, Ecova managed bills totaling $19.4 billion, an increase of $1.1 billion as compared to 2011.
Other Businesses
2013 compared to 2012
The net loss from these operations was $4.7 million for 2013 compared to a net loss of $5.3 million for 2012. The net loss for 2013 was primarily the result of $2.1 million (net of tax) of corporate costs, including costs associated with exploring strategic opportunities and litigation costs incurred related to our previous operations at Avista Energy of $1.0 million (net of tax).
Additionally, during 2013 we incurred impairment losses of $2.2 million (net of tax) associated with our investment in an energy storage company and our investment in a fuel cell business. During 2012 we incurred impairment losses of $1.5 million (net of taxes) related to the impairment of our investment in a fuel cell business and the write-off of our investment in a solar energy company.
The losses above were partially offset by METALfx, which had net income of $1.2 million for 2013 and 2012.
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2012 compared to 2011
The net loss from these operations was $5.3 million for 2012 compared to a net loss of $0.3 million for 2011. The decline in results was due in part to losses on investments of $2.2 million (net of taxes) for 2012 compared to $0.3 million (net of taxes) for 2011. The losses for 2012 were primarily the result of an impairment loss of $1.5 million (net of taxes) recognized during the third quarter of 2012 related to the impairment of our investment in a fuel cell business and the write-off of our investment in a solar energy company. Additionally, there were increased costs associated with strategic consulting and other corporate costs of $2.3 million (net of taxes) and litigation costs related to the previous operations of Avista Energy of $1.5 million (net of taxes). These losses were partially offset by METALfx which had net income of $1.2 million for 2012 and $1.4 million for 2011.
Accounting Standards to be Adopted in 2014
At this time, we are not expecting the adoption of accounting standards to have a material impact on our financial condition, results of operations and cash flows in 2014. For information on accounting standards adopted in 2013 and earlier periods, see “Note 2 of the Notes to Consolidated Financial Statements.”
Critical Accounting Policies and Estimates
The preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect amounts reported in the consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on our consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein. The following accounting policies represent those that our management believes are particularly important to the consolidated financial statements and require the use of estimates and assumptions:
Avista Utilities Operating Revenues
Operating revenues for our utility business related to the sale of energy are generally recorded when service is rendered or energy is delivered to our customers. The determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, we estimate the amount of energy delivered to customers since the date of the last meter reading and the corresponding unbilled revenue is estimated and recorded. Our estimate of unbilled revenue is based on:
| • | the number of customers, |
| • | current rates, |
| • | meter reading dates, |
| • | actual native load for electricity, and |
| • | actual throughput for natural gas. |
Any difference between actual and estimated revenue is automatically corrected in the following month when the actual meter reading and customer billing occurs.
Regulatory Accounting
We prepare our consolidated financial statements in accordance with regulatory accounting practices. This requires that certain costs and/or obligations (such as incurred power and natural gas costs not currently recovered through rates, but expected to be recovered in the future) be reflected as deferred charges on our Consolidated Balance Sheets and are not reflected in our Consolidated Statements of Income until the period during which matching revenues are recognized. We expect to recover our regulatory assets through future rates. Our regulatory assets are subject to review for prudence and recoverability. As such, certain deferred costs may be disallowed by our regulators. If at some point in the future we determine that we no longer meet the criteria for continued application of regulatory accounting for all or a portion of our regulated operations, we could be:
| • | required to write off regulatory assets, and |
| • | precluded from the future deferral of costs not recovered through rates when such costs are incurred, even if we expect to recover such costs in the future. |
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Utility Energy Commodity Derivative Assets and Liabilities
Our utility enters into forward contracts to purchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. These contracts are entered into as part of our management of loads and resources and certain contracts are considered derivative instruments. The UTC and the IPUC issued accounting orders authorizing us to offset commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of delivery. The orders provide for us to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Consolidated Statements of Income. Realized gains or losses are recognized in the period of delivery, subject to approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in adjustments to retail rates through purchased gas cost adjustments, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rates cases. We use quoted market prices and forward price curves to estimate the fair value of our utility derivative commodity instruments. As such, the fair value of utility derivative commodity instruments recorded on our Consolidated Balance Sheets is sensitive to market price fluctuations that can occur on a daily basis.
Pension Plans and Other Postretirement Benefit Plans
We have a defined benefit pension plan covering substantially all regular full-time employees at Avista Utilities that were hired prior to January 1, 2014. For substantially all regular non-union full-time employees at Avista Utilities that were hired on or after January 1, 2014, a defined contribution 401(k) plan replaced the defined benefit pension plan.
The Finance Committee of the Board of Directors approves investment policies, objectives and strategies that seek an appropriate return for the pension plan and it reviews and approves changes to the investment and funding policies.
We have contracted with an independent investment consultant who is responsible for managing/monitoring the individual investment managers. The investment managers’ performance and related individual fund performance is reviewed at least quarterly by an internal benefits committee and by the Finance Committee to monitor compliance with our established investment policy objectives and strategies.
Our pension plan assets are invested in mutual funds, trusts and partnerships that hold marketable debt and equity securities, real estate, absolute return and commodity funds. In seeking to obtain the desired return to fund the pension plan, the investment consultant recommends allocation percentages by asset classes. These recommendations are reviewed by the internal benefits committee, which then recommends their adoption by the Finance Committee. The Finance Committee has established target investment allocation percentages by asset classes and also investment ranges for each asset class. The target investment allocation percentages are typically the midpoint of the established range and are disclosed in “Note 9 of the Notes to Consolidated Financial Statements.”
We also have a Supplemental Executive Retirement Plan (SERP) that provides additional pension benefits to our executive officers whose benefits under the pension plan are reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred compensation plans.
Pension costs (including the SERP) were $28.8 million for 2013, $28.1 million for 2012 and $23.9 million for 2011. Of our pension costs, approximately 65 percent are expensed and 35 percent are capitalized consistent with labor charges. The costs related to the SERP are expensed. Our costs for the pension plan are determined in part by actuarial formulas that are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.
Pension costs are affected by:
| • | employee demographics (including age, compensation and length of service by employees), |
| • | the amount of cash contributions we make to the pension plan, and |
| • | the return on pension plan assets. |
Changes made to the provisions of our pension plan may also affect current and future pension costs. Pension plan costs may also be significantly affected by changes in key actuarial assumptions, including the:
| • | expected return on pension plan assets, |
| • | discount rate used in determining the projected benefit obligation and pension costs, and |
| • | assumed rate of increase in employee compensation. |
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The change in pension plan obligations associated with these factors may not be immediately recognized as pension costs in our Consolidated Statement of Income, but we generally recognize the change in future years over the remaining average service period of pension plan participants. As such, our costs recorded in any period may not reflect the actual level of cash benefits provided to pension plan participants.
In October 2013, we revised our defined benefit pension plan including closing the plan to all non-union employees hired or rehired by us on or after January 1, 2014. A defined contribution 401(k) plan replaced the defined benefit pension plan for non-union employees hired or rehired on or after January 1, 2014. In addition, we revised our lump sum calculation for non-union retirees under the defined benefit pension plan to provide a lump sum amount equivalent to the present value of the annuity based upon applicable discount rates. The financial statement amounts disclosed as of December 31, 2013 reflect the benefit changes described above.
In addition to the revisions described above, we have revised the key assumption of the discount rate in 2013, 2012 and 2011. Such changes had an effect on our pension costs and projected benefit obligation in 2013, 2012 and 2011 and may affect future years, given the cost recognition approach described above. However, in determining pension obligation and cost amounts, our assumptions can change from period to period, and such changes could result in material changes to our future pension costs and funding requirements.
In selecting a discount rate, we consider yield rates for highly rated corporate bond portfolios with maturities similar to that of the expected payout of pension benefits. In 2013, we increased the pension plan discount rate (exclusive of the SERP) to 5.1 percent from 4.15 percent in 2012. We used a discount rate of 5.05 percent in 2011. These changes in the discount rate decreased the projected benefit obligation (exclusive of the SERP) by approximately $68.2 million in 2013 and increased the obligation by $66.5 million in 2012.
The expected long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments held by our plan. We used an expected long-term rate of return of 6.60 percent in 2013, 6.95 percent in 2012 and 7.40 percent in 2011. This increased pension costs by approximately $1.5 million in 2013 and by approximately $1.5 million in 2012. The actual return on plan assets, net of fees, was a gain of $52.5 million (or 12.5 percent) for 2013, a gain of $54.3 million (or 15.9 percent) for 2012 and a gain of $14.7 million (or 4.8 percent) for 2011. We periodically analyze the estimated long-term rate of return on assets based upon updated economic forecasts and revisions to the investment portfolio.
The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage (dollars in thousands):
| Actuarial Assumption | Change in Assumption | Effect on Projected Benefit Obligation | Effect on Pension Cost | |||||||
| Expected long-term return on plan assets | (0.5 | )% | $ | — | * | $ | 2,096 | |||
| Expected long-term return on plan assets | 0.5 | % | — | * | (2,096 | ) | ||||
| Discount rate | (0.5 | )% | 34,657 | 4,134 | ||||||
| Discount rate | 0.5 | % | (31,081 | ) | (3,692 | ) | ||||
| * | Changes in the expected return on plan assets would not have an effect on our total pension liability. |
We provide certain health care and life insurance benefits for substantially all of our retired employees. We accrue the estimated cost of postretirement benefit obligations during the years that employees provide service. Assumed health care cost trend rates have a significant effect on the amounts reported for our postretirement plans. A one-percentage-point increase in the assumed health care cost trend rate for each year would increase our accumulated postretirement benefit obligation as of December 31, 2013 by $3.8 million and the service and interest cost by $0.8 million. A one-percentage-point decrease in the assumed health care cost trend rate for each year would decrease our accumulated postretirement benefit obligation as of December 31, 2013 by $3.1 million and the service and interest cost by $0.6 million.
In October 2013, we revised the health care benefit plan including the method for calculating health insurance premiums for non-union retirees under age 65 and non-union active Company employees. We also eliminated our contribution towards the retiree medical plan for non-union employees hired or rehired on or after January 1, 2014. See "Note 9 of the Notes to Consolidated Financial Statements" and the "Pension Plan" section below for additional information regarding the changes to the defined benefit pension plan and health care benefit plan and the related financial statement impact. The financial statement amounts disclosed as of December 31, 2013 reflect the benefit changes described above.
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Goodwill
We evaluate goodwill for impairment using a combination of a discounted cash flow model and a market approach on at least an annual basis or more frequently if impairment indicators arise. Examples of impairment indicators include: a deterioration in general economic conditions, market considerations such as a deterioration in the environment in which the entity operates, a decline in market-dependent multiples or metrics, increases in costs, overall financial performance such as a decline in earnings or cash flows, or a loss of key customers.
The annual evaluation of goodwill for potential impairment is completed as of December 31 for Ecova and as of November 30 for our other businesses. As of December 31, 2013, we had goodwill of $71.0 million related to Ecova and $5.2 million related to our other businesses.
Application of the goodwill impairment test requires judgment and the use of significant estimates, including the identification of reporting units, assignment of assets and liabilities to reporting units, and the estimation of the fair value of reporting units. The goodwill impairment test is a two-step process performed at the reporting unit level. The first step involves comparing the carrying amount of the reporting unit to its estimated fair value. If the estimated fair value of the reporting unit is greater than its carrying value, the goodwill impairment test is complete and no impairment is recorded. If the estimated fair value of the reporting unit is less than its carrying value, the second step of the test is performed to determine the amount of impairment loss, if any. This would result in a full valuation of the reporting unit's assets and liabilities and comparing the valuation to its carrying amounts, with the aggregate difference indicating the amount of impairment. In 2013, 2012 and 2011, each reporting unit that has been evaluated for impairment has a fair value that substantially exceeds its book value, and no impairment losses have been recorded.
Contingencies
We have unresolved regulatory, legal and tax issues for which there is inherent uncertainty for the ultimate outcome of the respective matter. We accrue a loss contingency if it is probable that an asset is impaired or a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. We also disclose losses that do not meet these conditions for accrual, if there is a reasonable possibility that a loss may be incurred.
For all material contingencies, we have made a judgment as to the probability of a loss occurring and as to whether or not the amount of the loss can be reasonably estimated. If the loss recognition criteria are met, liabilities are accrued or assets are reduced. However, no assurance can be given to the ultimate outcome of any particular contingency.
Liquidity and Capital Resources
Overall Liquidity
Our consolidated operating cash flows are primarily derived from the operations of Avista Utilities. The primary source of operating cash flows for our utility operations is revenues from sales of electricity and natural gas. Significant uses of cash flows from our utility operations include the purchase of power, fuel and natural gas, and payment of other operating expenses, taxes and interest, with any excess being available for other corporate uses such as capital expenditures and dividends.
We design operating and capital budgets to control operating costs and to direct capital expenditures to choices that support immediate and long-term strategies, particularly for our regulated utility operations. In addition to operating expenses, we have continuing commitments for capital expenditures for construction, improvement and maintenance of utility facilities.
Our annual net cash flows from operating activities usually do not fully support the amount required for annual utility capital expenditures. As such, from time to time, we need to access long-term capital markets in order to fund these needs as well as fund maturing debt. See further discussion at “Capital Resources.”
We periodically file for rate adjustments for recovery of operating costs and capital investments to seek the opportunity to earn returns as allowed by regulators. See further details in the section “Avista Utilities - Regulatory Matters.”
For our utility operations, when power and natural gas costs exceed the levels currently recovered from retail customers, net cash flows are negatively affected. Factors that could cause purchased power and natural gas costs to exceed the levels currently recovered from our customers include, but are not limited to, higher prices in wholesale markets when we buy energy or an increased need to purchase power in the wholesale markets. Factors beyond our control that could result in an increased need to purchase power in the wholesale markets include, but are not limited to:
| • | increases in demand (due to either weather or customer growth), |
| • | low availability of streamflows for hydroelectric generation, |
| • | unplanned outages at generating facilities, and |
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| • | failure of third parties to deliver on energy or capacity contracts. |
We monitor the potential liquidity impacts of changes to energy commodity prices and other increased operating costs for our utility operations. We believe that we have adequate liquidity to meet such potential needs through our $400.0 million committed line of credit.
As of December 31, 2013, we had $201.6 million of available liquidity under our committed line of credit. With our $400.0 million credit facility that expires in February 2017, we believe that we have adequate liquidity to meet our needs for the next 12 months.
Our utility has regulatory mechanisms in place that provide for the deferral and recovery of the majority of power and natural gas supply costs. However, if prices rise above the level currently allowed in retail rates in periods when we are buying energy, deferral balances would increase, negatively affecting our cash flow and liquidity until such time as these costs, with interest, are recovered from customers.
Review of Cash Flow Statement
Overall During 2013, positive cash flows from operating activities of $242.6 million, proceeds from the issuance of long-term debt of $90.0 million and $119.0 million of short-term borrowings under Avista Corp.'s committed line of credit were used to fund the majority of our cash requirements. These cash requirements included utility capital expenditures of $294.4 million, the redemption and maturity of long-term debt of $50.5 million, defined benefit pension plan contributions of $44.3 million and dividends of $73.3 million.
2013 compared to 2012
Operating Activities Net cash provided by operating activities was $242.6 million for 2013 compared to $316.6 million for 2012. Net cash used by certain current assets and liabilities components was $48.2 million for 2013, compared to net cash provided of $63.6 million for 2012. The net cash used during 2013 primarily reflects cash outflows from accounts receivable, accounts payable and other current assets (primarily related to miscellaneous current assets and income taxes receivable). These were partially offset by cash inflows from other current liabilities (primarily related to accrued taxes and interest).
The net cash provided during 2012 primarily reflects positive cash flows from other current assets (primarily related to a decrease in deposits with counterparties and income taxes receivable) and net cash inflows related to accounts payable.
Net deferrals of power and natural gas costs were $9.4 million for 2013 compared to net amortizations of $6.7 million for 2012. The provision for deferred income taxes was $23.5 million for 2013 compared to $21.4 million for 2012. Contributions to our defined benefit pension plan were $44.3 million for 2013 compared to $44.0 million in 2012. Cash paid for interest was $75.4 million for 2013, compared to $74.9 million for 2012.
Investing Activities Net cash used in investing activities was $312.2 million for 2013, an increase compared to $294.7 million for 2012. Utility property capital expenditures increased by $23.2 million for 2013 compared to 2012. A significant portion of Ecova's funds held for clients are held as securities available for sale with purchases of $35.9 million and sales and maturities of $23.0 million in 2013. For 2012, Ecova had purchases of $100.4 million and sales and maturities of $138.0 million. In 2012, Ecova paid $50.3 million for the acquisition of LPB.
Financing Activities Net cash provided by financing activities was $76.8 million for 2013 compared to net cash used of $21.1 million for 2012. Cash inflows during 2013 were from a $119.0 million increase in short-term borrowings on Avista Corp.’s committed line of credit, the issuance of $90.0 million of long-term debt and the issuance of $4.6 million of common stock. We also cash settled interest rate swap agreements for $2.9 million related to the pricing of the $90.0 million of long-term debt. Cash outflows during 2013 were from the maturity of long-term debt of $50.5 million and a net decrease in borrowings on Ecova's committed line of credit of $8.0 million (borrowings of $3.0 million and repayments of $11.0 million). Cash dividends paid increased to $73.3 million (or $1.22 per share) for 2013 from $68.6 million (or $1.16 per share) for 2012.
During 2012, short-term borrowings on Avista Corp.'s committed line of credit decreased $9.0 million. Borrowings on Ecova's committed line of credit increased $33.0 million and these proceeds were used to fund the acquisition of LPB. We issued $29.1 million of common stock during 2012. We cash settled interest rate swap agreements for $18.5 million related to the pricing of $80.0 million of long-term debt issued in November 2012. Customer fund obligations at Ecova decreased $31.0 million.
2012 compared to 2011
Operating Activities Net cash provided by operating activities was $316.6 million for 2012 compared to $269.5 million for 2011. Net cash provided by certain current assets and liabilities components was $63.6 million for 2012, compared to net cash used of $14.9 million for 2011. The net cash provided during 2012 primarily reflects positive cash flows from other current
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assets (primarily related to a decrease in deposits with counterparties and income taxes receivable) and net cash inflows related to accounts payable.
The net cash used during 2011 primarily reflects negative cash flows from other current assets (primarily related to an increase in deposits with counterparties), net cash outflows related to accounts payable and an increase in natural gas stored. These negative cash flows were partially offset by net cash inflows related to accounts receivable.
Net amortization of deferred power and natural gas costs was $6.7 million for 2012 compared to $21.9 million for 2011. The provision for deferred income taxes was $21.4 million for 2012 compared to $24.0 million for 2011. Contributions to our defined benefit pension plan were $44.0 million for 2012 compared to $26.0 million for 2011. Cash paid for interest was $74.9 million for 2012, compared to $69.1 million for 2011.
Investing Activities Net cash used in investing activities was $294.7 million for 2012, an increase compared to $282.3 million for 2011. Utility property capital expenditures increased by $31.4 million for 2012 as compared to 2011. In 2012, a significant portion of Ecova's funds held for clients were held as securities available for sale (purchases of $100.4 million and sales and maturities of $138.0 million). At the end of 2011, the majority of Ecova's funds held for clients were held as securities available for sale (purchases of $96.6 million). The net cash paid by subsidiaries for acquisitions in 2012 of $50.3 million represents Ecova's acquisition of LPB. The net cash paid by subsidiaries for acquisitions in 2011 of $31.4 million primarily represents Ecova’s acquisition of Prenova.
Financing Activities Net cash used in financing activities was $21.1 million for 2012 compared to net cash provided of $18.1 million for 2011. During 2012, short-term borrowings on Avista Corp.’s committed line of credit decreased $9.0 million. Borrowings on Ecova's committed line of credit increased $19.0 million (net of borrowings of $33.0 million and repayments of $14.0 million) and these proceeds were used to fund a portion of the acquisition of LPB. Cash dividends paid increased to $68.6 million (or $1.16 per share) for 2012 from $63.7 million (or $1.10 per share) for 2011. We issued $29.1 million of common stock during 2012. We cash settled interest rate swap agreements for $18.5 million related to the pricing of $80.0 million of long-term debt issued in November 2012. Customer fund obligations at Ecova decreased $18.5 million.
During 2011, short-term borrowings on Avista Corp.'s committed line of credit decreased $49.0 million. Borrowings on Ecova's committed line of credit increased $35.0 million and these proceeds were used to fund the acquisition of Prenova. We issued $26.5 million of common stock during 2011. We cash settled interest rate swap agreements for $10.6 million related to the pricing of $85.0 million of long-term debt issued in December 2011. Customer fund obligations at Ecova increased $17.8 million.
Collateral Requirements
Our contracts for the purchase and sale of energy commodities can require collateral in the form of cash or letters of credit. As of December 31, 2013, we had cash deposited as collateral of $26.1 million and letters of credit of $20.3 million outstanding related to our energy derivative contracts. Price movements and/or a downgrade in our credit ratings could impact further the amount of collateral required. See “Credit Ratings” for further information. For example, in addition to limiting our ability to conduct transactions, if our credit ratings were lowered to below “investment grade” based on our positions outstanding at December 31, 2013, we would potentially be required to post additional collateral of up to $10.3 million. This amount is different from the amount disclosed in “Note 5 of the Notes to Consolidated Financial Statements” because, while this analysis includes contracts that are not considered derivatives in addition to the contracts considered in Note 5, this analysis takes into account contractual threshold limits that are not considered in Note 5. Without contractual threshold limits, we would potentially be required to post additional collateral of $26.1 million.
Under the terms of interest rate swap agreements that we enter into periodically, we may be required to post cash or letters of credit as collateral depending on fluctuations in the fair value of the instrument. This has not historically been significant to our liquidity position. As of December 31, 2013, we had interest rate swap agreements outstanding with a notional amount totaling $245 million and we did not have any collateral posted. If our credit ratings were lowered to below “investment grade” based on our interest rate swap agreements outstanding at December 31, 2013, we would not be required to post additional collateral.
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Capital Resources
Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings, and excluding noncontrolling interests, consisted of the following as of December 31, 2013 and 2012 (dollars in thousands):
| December 31, 2013 | December 31, 2012 | ||||||||||||
| Amount | Percent of total | Amount | Percent of total | ||||||||||
| Current portion of long-term debt | $ | 358 | — | % | $ | 50,372 | 1.9 | % | |||||
| Current portion of nonrecourse long-term debt (Spokane Energy) | 16,407 | 0.6 | % | 14,965 | 0.6 | % | |||||||
| Short-term borrowings | 171,000 | 6.0 | % | 52,000 | 1.9 | % | |||||||
| Long-term borrowings under committed line of credit | 46,000 | 1.6 | % | 54,000 | 2.0 | % | |||||||
| Long-term debt to affiliated trusts | 51,547 | 1.8 | % | 51,547 | 1.9 | % | |||||||
| Nonrecourse long-term debt (Spokane Energy) | 1,431 | 0.1 | % | 17,838 | 0.7 | % | |||||||
| Long-term debt | 1,272,425 | 44.5 | % | 1,178,367 | 44.0 | % | |||||||
| Total debt | 1,559,168 | 54.6 | % | 1,419,089 | 53.0 | % | |||||||
| Total Avista Corporation shareholders’ equity | 1,298,266 | 45.4 | % | 1,259,477 | 47.0 | % | |||||||
| Total | $ | 2,857,434 | 100.0 | % | $ | 2,678,566 | 100.0 | % | |||||
We need to finance capital expenditures and acquire additional funds for operations from time to time. The cash requirements needed to service our indebtedness, both short-term and long-term, reduce the amount of cash flow available to fund capital expenditures, purchased power, fuel and natural gas costs, dividends and other requirements. Our shareholders’ equity increased $38.8 million during 2013 primarily due to net income partially offset by dividends.
We generally fund capital expenditures with a combination of internally generated cash and external financing. The level of cash generated internally and the amount that is available for capital expenditures fluctuates depending on a variety of factors. Cash provided by our utility operating activities, as well as issuances of long-term debt and common stock, are expected to be the primary source of funds for operating needs, dividends and capital expenditures for 2014. Borrowings under our $400.0 million committed line of credit will supplement these funds to the extent necessary.
In August 2012, we entered into two sales agency agreements under which we may sell up to 2.7 million shares of our common stock from time to time. We did not issue any shares under these plans in 2013 and as of December 31, 2013, we had 1.8 million shares available to be issued under these agreements.
In 2013, we issued $4.6 million (net of issuance costs) of common stock. The additional shares were issued under the dividend reinvestment and direct stock purchase plan and employee plans.
We are planning to issue up to $145.0 million of common stock in 2014 related to closing the planned acquisition of AERC. Without the planned transaction, Avista Corp. would have issued common stock to maintain an appropriate capital structure. Assuming the transaction is completed, we will not need to issue any common stock under the sales agency agreements referred to above.
In August 2013, we entered into a $90.0 million term loan agreement with an institutional investor bearing an annual interest rate of 0.84 percent and maturing in 2016. The net proceeds from the term loan agreement were used to repay a portion of corporate indebtedness in anticipation of the maturation of $50.0 million in First Mortgage Bonds which occurred in December 2013. In connection with the pricing of the First Mortgage Bonds, we cash settled interest rate swap contracts and received a total of $2.9 million, which will be amortized as a component of interest expense over the life of the debt.
We expect to issue approximately $190.0 million of long-term debt during 2014, including about $90.0 million of debt issuances combined by AERC or AEL&P associated with rebalancing the consolidated capital structure at AERC. This amount assumes we are going to refinance the existing net debt, estimated to be about $25.0 million at closing. The net debt outstanding at AEL&P does not include the Snettisham obligation which had a balance of $74.0 million as of December 31, 2012, as this related to a power purchase commitment for which AEL&P has recorded a long-term power purchase asset and corresponding liability. In addition to rebalancing the consolidated capital structure at AERC, the proceeds from the issuance of long-term debt will be used to repay a portion of short-term borrowings, fund utility capital expenditures and other contractual commitments.
Included in our 2014 liquidity estimates is approximately $50.0 million in lower tax payments due to the planned adoption of federal tax tangible property regulations. This will be accomplished through an accounting method change filing with the Internal Revenue Service that will retroactively modify which tangible property transactions we expense versus capitalize and depreciate for federal tax purposes.
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We have a committed line of credit with various financial institutions in the total amount of $400.0 million with an expiration date of February 2017. Borrowings under this line of credit agreement are classified as short-term on the Consolidated Balance Sheets.
This facility contains customary covenants and default provisions, including a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at any time. As of December 31, 2013, we were in compliance with this covenant with a ratio of 54.6 percent.
Balances outstanding and interest rates of borrowings (excluding letters of credit) under our committed line of credit were as follows as of and for the year ended December 31 (dollars in thousands):
| 2013 | 2012 | 2011 | |||||||||
| Balance outstanding at end of year | $ | 171,000 | $ | 52,000 | $ | 61,000 | |||||
| Letters of credit outstanding at end of year | $ | 27,434 | $ | 35,885 | $ | 29,030 | |||||
| Maximum balance outstanding during the year | $ | 171,000 | $ | 92,500 | $ | 130,000 | |||||
| Average balance outstanding during the year | $ | 27,580 | $ | 23,921 | $ | 74,947 | |||||
| Average interest rate during the year | 1.14 | % | 1.18 | % | 1.43 | % | |||||
| Average interest rate at end of year | 1.02 | % | 1.12 | % | 1.12 | % | |||||
As part of our cash management practices and operations, Ecova and Avista Corp. entered into an arrangement in January 2012 under which (1) Avista Corp. issued to Ecova a master unsecured promissory note and (2) Ecova will from time to time make short-term loans to Avista Corp. as a temporary investment of its funds received from its clients. The master promissory note limits the total outstanding indebtedness to no more than $50.0 million in principal. Additionally, such loans are required to be repaid on the last business day of each quarter (March, June, September and December) and sooner upon demand by Ecova. Amounts are loaned at a rate consistent with Avista Corp.'s credit facility. The average balance outstanding was $34.0 million and the maximum balance was $50.0 million during 2013. The average balance outstanding was $31.6 million and the maximum balance was $50.0 million during 2012.
Any default on the line of credit or other financing arrangements of Avista Corp. or any of our “significant subsidiaries,” if any, could result in cross-defaults to other agreements of such entity, and/or to the line of credit or other financing arrangements of any other of such entities. Any defaults could also induce vendors and other counterparties to demand collateral. In the event of any such default, it would be difficult for us to obtain financing on reasonable terms to pay creditors or fund operations. We would also likely be prohibited from paying dividends on our common stock. Avista Corp. does not guarantee the indebtedness of any of its subsidiaries. As of December 31, 2013, Avista Corp. and its subsidiaries were in compliance with all of the covenants of their financing agreements, and none of Avista Corp.'s subsidiaries constituted a “significant subsidiary” as defined in Avista Corp.'s committed line of credit.
Ecova also has a committed line of credit agreement with various financial institutions for $125.0 million with an expiration date of July 2017. This credit agreement is used primarily to fund acquisitions at Ecova and supplement cash flow for Ecova's operations when necessary and is generally not available for capital acquisitions. There were $46.0 million of borrowings outstanding under Ecova’s credit agreement as of December 31, 2013 classified as long-term. See the "Ecova Credit Agreement" section below for further discussion regarding this agreement.
We are restricted under our Restated Articles of Incorporation, as amended, as to the additional preferred stock we can issue. As of December 31, 2013, we could issue $1.2 billion of additional preferred stock at an assumed dividend rate of 6.5 percent. We are not planning to issue preferred stock.
Under the Mortgage and Deed of Trust securing our First Mortgage Bonds (including Secured Medium-Term Notes), we may issue additional First Mortgage Bonds in an aggregate principal amount equal to the sum of:
| • | 66-2/3 percent of the cost or fair value (whichever is lower) of property additions which have not previously been made the basis of any application under the Mortgage, or |
| • | an equal principal amount of retired First Mortgage Bonds which have not previously been made the basis of any application under the Mortgage, or |
| • | deposit of cash. |
However, we may not issue any additional First Mortgage Bonds (with certain exceptions in the case of bonds issued on the basis of retired bonds) unless our “net earnings” (as defined in the Mortgage) for any period of 12 consecutive calendar months out of the preceding 18 calendar months were at least twice the annual interest requirements on all mortgage securities at the
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time outstanding, including the First Mortgage Bonds to be issued, and on all indebtedness of prior rank. As of December 31, 2013, our property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $916.3 million in aggregate principal amount of additional First Mortgage Bonds. We believe that we have adequate capacity to issue First Mortgage Bonds to meet our financing needs over the next several years.
Avista Utilities Capital Expenditures
Capital expenditures for our utility were $805.3 million for the years 2011 through 2013. We expect utility capital expenditures to be about $335 million for 2014, $355 million for 2015 and $350 million for 2016. Our capital budget for 2014 includes the following (dollars in millions):
| Transmission and distribution (upgrade current facilities) | $ | 98 | |
| Information technology | 58 | ||
| Customer growth (incremental transmission and distribution) | 33 | ||
| Generation | 65 | ||
| Natural gas | 40 | ||
| Facilities | 12 | ||
| Environmental | 16 | ||
| Other | 13 | ||
| Total | $ | 335 | |
Most of the capital expenditures above are for upgrading and maintenance of our existing facilities, and not for construction of new facilities and we expect all of these capital expenditures to be included in rate base in future years. These estimates of capital expenditures are subject to continuing review and adjustment. Actual capital expenditures may vary from our estimates due to factors such as changes in business conditions, construction schedules and environmental requirements.
Future generation resource decisions may be further impacted by legislation for restrictions on greenhouse gas (GHG) emissions and renewable energy requirements as discussed at “Environmental Issues and Other Contingencies.”
Included in our estimates of capital expenditures is the replacement of our customer information and work management systems, which is expected to be completed by the end of 2014. Our customer information and work management systems are two of our most critical technology systems and are interconnected to many other systems in our company. We expect to spend a total of approximately $80 million (including internal labor) over the term of the project. As of December 31, 2013 we have spent approximately $48.6 million on the project (including internal labor).
Ecova Credit Agreement
Ecova has a $125.0 million committed line of credit agreement with various financial institutions that has an expiration date of July 2017. The credit agreement is secured by all of Ecova's assets excluding investments and funds held for clients. There were $46.0 million of long-term borrowings outstanding under Ecova’s credit agreement as of December 31, 2013. The proceeds from these borrowings were used to fund the acquisitions in 2011 and 2012.
The committed line of credit agreement contains customary covenants and default provisions, including a covenant which requires that Ecova's “Consolidated Total Funded Debt to EBITDA Ratio” (as defined in the credit agreement) must be 2.50 to 1.00 or less, with provisions in the credit agreement allowing for a temporary increase of this ratio if a qualified acquisition is consummated by Ecova. In addition, Ecova's “Consolidated Fixed Charge Coverage Ratio” (as defined in the credit agreement) must be greater than 1.50 to 1.00 as of the last day of any fiscal quarter. As of December 31, 2013, Ecova was in compliance with these covenants and based on the Consolidated Total Funded Debt to EBITDA Ratio, Ecova could borrow an additional $35.3 million and still be compliant with the covenants. The covenant restrictions are calculated on a rolling twelve month basis, so this additional borrowing capacity could increase or decrease or Ecova could be required to pay down the outstanding debt as future results change.
Ecova Redeemable Stock
Ecova's amended employee stock incentive plan provides an annual window at which time certain holders of common stock can put their shares back to Ecova, providing the shares are held for a minimum of six months and a day. Stock is reacquired at fair market value at the date of reacquisition. The value of the redeemable noncontrolling interests in Ecova associated with redeemable stock options and other outstanding redeemable stock was $15.9 million at December 31, 2013, an increase from $4.9 million at December 31, 2012. Options are valued at their maximum redemption amount which is equal to their intrinsic value (fair value less exercise price). During 2013, the estimated fair value of Ecova common stock increased such that it is higher compared to the exercise price of the options which increased the overall value of the redeemable noncontrolling
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interests to their current value. In 2009, the Ecova employee stock incentive plan was amended such that, on a prospective basis, not all options granted under the plan have the put right.
Off-Balance Sheet Arrangements
As of December 31, 2013, we had $27.4 million in letters of credit outstanding under our $400.0 million committed line of credit, compared to $35.9 million as of December 31, 2012.
Pension Plan
We contributed $44.3 million to the pension plan in 2013. We expect to contribute a total of $80.0 million to the pension plan in the period 2014 through 2018, with the following contributions.
| 2014 | 2015 | 2016 | 2017 | 2018 | Total | ||||||||||||||||||
| Pension Plan Funding | $ | 32,000 | $ | 20,000 | $ | 10,000 | $ | 9,000 | $ | 9,000 | $ | 80,000 | |||||||||||
We had previously estimated our contributions for the period 2014 to 2016 to be $104.5 million. Our contributions are expected to decrease to $62.0 million during this same period due to an increase in the discount rate and greater than expected returns on fund assets which has caused us to become closer to fully funded status. The final determination of pension plan contributions for future periods is subject to multiple variables, most of which are beyond our control, including changes to the fair value of pension plan assets, changes in actuarial assumptions (in particular the discount rate used in determining the benefit obligation), or changes in federal legislation. We may change our pension plan contributions in the future depending on changes to any of the above variables.
In October 2013, we revised our defined benefit pension plan such that as of January 1, 2014 the plan is closed to all non-union employees hired or rehired by us on or after January 1, 2014. All actively employed non-union employees that were hired prior to January 1, 2014 and are currently covered under the defined benefit pension plan will continue accruing benefits as originally specified in the plan. A defined contribution 401(k) plan will replace the defined benefit pension plan for all non-union employees hired or rehired on or after January 1, 2014. Under the defined contribution plan we will provide a non-elective contribution as a percentage of each employee's pay based on his or her age. This defined contribution is in addition to the existing 401(k) contribution in which we match a portion of the pay deferred by each participant. In addition to the above changes, we also revised our lump sum calculation for non-union retirees under the defined benefit pension plan to provide non-union participants who retire on or after January 1, 2014 with a lump sum amount equivalent to the present value of the annuity based upon applicable discount rates.
Also in October 2013, we revised the health care benefit plan such that beginning on January 1, 2020, the method for calculating health insurance premiums for non-union retirees under age 65 and active Company employees will be revised. The revisions will result in separate health insurance premium calculations for each group. In addition, for non-union employees hired or rehired on or after January 1, 2014, upon retirement we will no longer provide a contribution towards his or her medical premiums. We will provide access to our retiree medical plan, but the non-union employees hired or rehired on or after January 1, 2014 will pay the full cost of premiums upon retirement.
The above revisions resulted in a $10.5 million overall reduction to the pension and other postretirement benefits obligations as of December 31, 2013.
Credit Ratings
Our access to capital markets and our cost of capital are directly affected by our credit ratings. In addition, many of our contracts for the purchase and sale of energy commodities contain terms dependent upon our credit ratings. See “Collateral Requirements” and “Note 5 of the Notes to Consolidated Financial Statements.” The following table summarizes our credit ratings as of February 26, 2014:
| Standard & Poor’s (1) | Moody’s (2) | ||
| Corporate/Issuer rating | BBB | Baa1 | |
| Senior secured debt | A- | A2 | |
| Senior unsecured debt | BBB | Baa1 | |
| (1) | Standard & Poor’s lowest “investment grade” credit rating is BBB-. |
| (2) | Moody’s lowest “investment grade” credit rating is Baa3. |
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A security rating is not a recommendation to buy, sell or hold securities. Each security rating is subject to revision or withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be considered in the context of the applicable methodology, independent of all other ratings. The rating agencies provide ratings at the request of Avista Corp. and charge fees for their services.
Dividends
The Board of Directors considers the level of dividends on our common stock on a regular basis, taking into account numerous factors including, without limitation:
| • | our results of operations, cash flows and financial condition, |
| • | the success of our business strategies, and |
| • | general economic and competitive conditions. |
Our net income available for dividends is primarily derived from our regulated utility operations.
The payment of dividends on common stock could be limited by:
| • | certain covenants applicable to preferred stock (when outstanding) contained in the Company’s Restated Articles of Incorporation, as amended (currently there are no preferred shares outstanding), |
| • | certain covenants applicable to the Company's outstanding long-term debt and committed line of credit agreements (see Item 7. Management's Discussion and Analysis - "Capital Resources" for compliance with these covenants), and |
| • | the hydroelectric licensing requirements of section 10(d) of the FPA (see “Note 1 of Notes to Consolidated Financial Statements”). |
On February 7, 2014, Avista Corp.’s Board of Directors declared a quarterly dividend of $0.3175 per share on the Company’s common stock. This was an increase of $0.0125 per share, or 4 percent from the previous quarterly dividend of $0.305 per share.
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Contractual Obligations
The following table provides a summary of our future contractual obligations as of December 31, 2013 (dollars in millions):
| 2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | ||||||||||||||||||
| Avista Utilities: | |||||||||||||||||||||||
| Long-term debt maturities | $ | — | $ | — | $ | 90 | $ | — | $ | 273 | $ | 931 | |||||||||||
| Long-term debt to affiliated trusts | — | — | — | — | — | 52 | |||||||||||||||||
| Interest payments on long-term debt (1) | 67 | 67 | 67 | 66 | 57 | 622 | |||||||||||||||||
| Short-term borrowings | 171 | — | — | — | — | — | |||||||||||||||||
| Energy purchase contracts (2) | 304 | 190 | 159 | 153 | 144 | 1,358 | |||||||||||||||||
| Operating lease obligations (3) | 2 | 1 | — | — | — | 3 | |||||||||||||||||
| Other obligations (4) | 30 | 27 | 31 | 29 | 24 | 211 | |||||||||||||||||
| Information technology contracts (5) | 18 | 7 | 7 | 8 | — | — | |||||||||||||||||
| Pension plan funding (6) | 32 | 20 | 10 | 9 | 9 | — | |||||||||||||||||
| Spokane Energy: | |||||||||||||||||||||||
| Nonrecourse long-term debt maturities | 16 | 1 | — | — | — | — | |||||||||||||||||
| Interest payments on nonrecourse long-term debt | 1 | — | — | — | — | — | |||||||||||||||||
| Avista Capital (consolidated): | |||||||||||||||||||||||
| Redeemable noncontrolling interests (7) | 16 | — | — | — | — | — | |||||||||||||||||
| Long-term borrowings under committed line of credit | — | — | — | 46 | — | — | |||||||||||||||||
| Interest payments on long-term borrowings under committed line of credit (1) | 1 | 1 | 1 | 1 | — | — | |||||||||||||||||
| Operating lease obligations (3) | 5 | 5 | 3 | 3 | 3 | 5 | |||||||||||||||||
| Client fund obligations | 99 | — | — | — | — | — | |||||||||||||||||
| Total contractual obligations | $ | 762 | $ | 319 | $ | 368 | $ | 315 | $ | 510 | $ | 3,182 | |||||||||||
| (1) | Represents our estimate of interest payments on long-term debt, which is calculated based on the assumption that all debt is outstanding until maturity. Interest on variable rate debt is calculated using the rate in effect at December 31, 2013. |
| (2) | Energy purchase contracts were entered into as part of the obligation to serve our retail electric and natural gas customers’ energy requirements. As a result, costs are generally recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost adjustment mechanisms. |
| (3) | Includes the interest component of the lease obligation. Future capital lease obligations are not material. |
| (4) | Represents operational agreements, settlements and other contractual obligations for our generation, transmission and distribution facilities. These costs are generally recovered through base retail rates. |
| (5) | Includes information service contracts which are recorded to other operating expenses in the Consolidated Statements of Income as well as information technology contracts associated with the replacement of our customer information and work management systems, which are capital expenditures and expected to be completed in 2014. |
| (6) | Represents our estimated cash contributions to the pension plan through 2018. We cannot reasonably estimate pension plan contributions beyond 2018 at this time and have excluded them from the table above. |
| (7) | Certain shares acquired under Ecova’s employee stock incentive plan are redeemable at the option of the shareholder. |
The above contractual obligations do not include income tax payments. Also, asset retirement obligations are not included above and payments associated with these have historically been less than $1 million per year. There are approximately $2.9 million remaining asset retirement obligations as of December 31, 2013.
In addition to the contractual obligations disclosed above, we will incur additional operating costs and capital expenditures in future periods for which we are not contractually obligated as part of our normal business operations.
Competition
Our utility electric and natural gas distribution business has historically been recognized as a natural monopoly. In each regulatory jurisdiction, our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are generally determined on a
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“cost of service” basis. Rates are designed to provide, after recovery of allowable operating expenses and capital investments, an opportunity for us to earn a reasonable return on investment as allowed by our regulators.
In retail markets, we compete with various rural electric cooperatives and public utility districts in and adjacent to our service territories in the provision of service to new electric customers. Alternative energy technologies, including solar, wind or geothermal generation, may also compete with us for sales to existing customers. While the risk is currently small in our service territory given the small numbers of customers utilizing these technologies, advances in power generation, energy efficiency and other alternative energy technologies could lead to more wide-spread usage of these technologies, thereby reducing customer demand for the energy supplied by us. This reduction in usage and demand would reduce our revenue and negatively impact our financial condition including possibly leading to our inability to fully recover our investments in generation, transmission and distribution assets. Similarly, our natural gas distribution operations compete with other energy sources including heating oil, propane and other fuels.
Certain natural gas customers could bypass our natural gas system, reducing both revenues and recovery of fixed costs. To reduce the potential for such bypass, we price natural gas services, including transportation contracts, competitively and have varying degrees of flexibility to price transportation and delivery rates by means of individual contracts. These individual contracts are subject to state regulatory review and approval. We have long-term transportation contracts with several of our largest industrial customers under which the customer acquires its own commodity while using our infrastructure for delivery. Such contracts reduce the risk of these customers bypassing our system in the foreseeable future and minimizes the impact on our earnings.
Also, non-utility businesses are developing new technologies and services to help energy consumers manage energy in new ways that may improve productivity and could alter demand for the energy we sell.
In wholesale markets, competition for available electric supply is influenced by the:
| • | localized and system-wide demand for energy, |
| • | type, capacity, location and availability of generation resources, and |
| • | variety and circumstances of market participants. |
These wholesale markets are regulated by the FERC, which requires electric utilities to:
| • | transmit power and energy to or for wholesale purchasers and sellers, |
| • | enlarge or construct additional transmission capacity for the purpose of providing these services, and |
| • | transparently price and offer transmission services without favor to any party, including the merchant functions of the utility. |
Participants in the wholesale energy markets include:
| • | other utilities, |
| • | federal power marketing agencies, |
| • | energy marketing and trading companies, |
| • | independent power producers, |
| • | financial institutions, and |
| • | commodity brokers. |
Ecova is subject to competition for service to existing customers and as they develop products and services and enter new markets. Competition from other companies may mean challenges for Ecova to be the first to market a new product or service to gain an advantage in market share. In addition, Ecova's services utilize rapidly advancing technologies which require continual product enhancement to avoid obsolescence.
Economic Conditions and Utility Load Growth
The general economic data, on both national and local levels, contained in this section is based, in part, on independent government and industry publications, reports by market research firms or other independent sources. While we believe that these publications and other sources are reliable, we have not independently verified such data and can make no representation as to its accuracy.
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We track multiple economic indicators affecting three distinct metropolitan areas in our service area: Spokane, Washington, Coeur d'Alene, Idaho, and Medford, Oregon. Several key indicators are employment change, unemployment rates and foreclosure rates. On a year-over-year basis, December 2013 showed positive job growth, and lower unemployment rates in all three metropolitan areas. Foreclosure rates are in line with or below the U.S rate in all three areas. However, the unemployment rates are still above the national average and two key leading indicators, initial unemployment claims and residential building permits, continue to signal modest growth over the next 12 months. Therefore, in 2014, we continue to expect economic growth in our service area to be somewhat slower than the U.S. as a whole.
Seasonally adjusted nonfarm employment in our eastern Washington, northern Idaho, and southwestern Oregon metropolitan service areas exhibited moderate growth between December 2012 and December 2013. In Spokane, Washington employment growth was 1.1 percent with gains in mining, logging, and construction; trade, transportation, and utilities; leisure and hospitality; and other services. Employment increased by 2.1 percent in Coeur d'Alene, Idaho, reflecting gains in construction; trade, transport, and utilities; leisure and hospitality; and government. In Medford, Oregon, employment growth was 0 percent, with gains in manufacturing; leisure and hospitality; and government offset by declines in construction; professional and business services; and financial activities. U.S. nonfarm sector jobs grew by 1.6 percent in the same twelve-month period.
Seasonally adjusted unemployment rates went down in December 2013 from the year earlier in Spokane, Coeur d'Alene, and Medford. In Spokane the rate was 8.3 percent in December 2012 and declined to 7.4 percent in December 2013; in Coeur d'Alene the rate went from 7.6 percent to 6.9 percent; and in Medford the rate declined from 10.4 percent to 9.1 percent. The U.S. rate declined from 7.9 percent to 6.7 percent in the same period.
The housing market in our service area continues to experience foreclosure rates in line with or lower than the national average. The December 2013 national rate was 0.09 percent, compared to 0.07 percent in Spokane County, Washington; 0.02 percent in Kootenai County (Coeur d'Alene), Idaho; and 0.01 percent in Jackson County (Medford), Oregon.
Based on our forecast for 2014 through 2017, we expect annual electric customer growth to average 0.7 percent to 1.4 percent per year and annual natural gas customer growth to average 0.7 percent to 1.5 percent within our service area. We anticipate retail electric load growth to average between 0.5 percent and 1.0 percent and natural gas load growth to average between 0.7 percent and 1.5 percent. We anticipate customer and load growth at the lower end of the range in 2014 and a modest recovery as the economy strengthens during the four-year period. While the number of electric and natural gas customers is growing, the average annual usage by each residential customer has not changed significantly. Growth in electric and natural gas sales has slowed as retail prices have increased and Company sponsored conservation programs have intensified. With a weaker than normal post-recession recovery in Avista's service area, population and business growth in our three-state service territory remains at or below the national average. In addition to the foregoing, electric and natural gas sales vary significantly with annual fluctuations in weather within our service territories.
The forward-looking statements set forth above regarding retail load growth are based, in part, upon purchased economic forecasts and publicly available population and demographic studies. The expectations regarding retail load growth are also based upon various assumptions, including:
| • | assumptions relating to weather and economic and competitive conditions, |
| • | internal analysis of company-specific data, such as energy consumption patterns, |
| • | internal business plans, |
| • | an assumption that we will incur no material loss of retail customers due to self-generation or retail wheeling, and |
| • | an assumption that demand for electricity and natural gas as a fuel for mobility will for now be immaterial. |
Changes in actual experience can vary significantly from our projections.
Environmental Issues and Contingencies
We are subject to environmental regulation by federal, state and local authorities. The generation, transmission, distribution, service and storage facilities in which we have ownership interests are designed and operated in compliance with applicable environmental laws. Furthermore, we conduct periodic reviews and audits of pertinent facilities and operations to ensure compliance and to respond to or anticipate emerging environmental issues. The Company's Board of Directors has established a committee to oversee environmental issues.
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We monitor legislative and regulatory developments at all levels of government for environmental issues, particularly those with the potential to impact the operation and productivity of our generating plants and other assets.
Environmental laws and regulations may:
| • | increase the operating costs of generating plants; |
| • | increase the lead time and capital costs for the construction of new generating plants; |
| • | require modification of our existing generating plants; |
| • | require existing generating plant operations to be curtailed or shut down; |
| • | reduce the amount of energy available from our generating plants; |
| • | restrict the types of generating plants that can be built or contracted with; and |
| • | require construction of specific types of generation plants at higher cost. |
Compliance with environmental laws and regulations could result in increases to capital expenditures and operating expenses. We intend to seek recovery of any such costs through the ratemaking process.
Clean Air Act
We must comply with the requirements under the Clean Air Act (CAA) in operating our thermal generating plants. The CAA currently requires a Title V operating permit for Colstrip (expires in 2017), Coyote Springs 2 (expires in 2018), the Kettle Falls GS (renewal expected in 2014), and the Rathdrum CT (expires in 2016). Boulder Park GS, Northeast CT, and other activities only require minor source operating or registration permits based on their limited operation and emissions. The Title V operating permits are renewed every five years and updated to include all newly applicable CAA requirements. We actively monitor legislative, regulatory and program developments within the CAA that may impact our facilities.
On March 6, 2013, the Sierra Club and Montana Environmental Information Center, filed a Complaint (Complaint) in the United States District Court for the District of Montana, Billings Division, against the owners of the Colstrip. The Complaint alleges certain violations of the CAA. We are evaluating the allegations set forth in the Complaint and cannot at this time predict the outcome of the matter. See “Sierra Club and Montana Environmental Information Center Litigation” in “Note 20 of the Notes to Consolidated Financial Statements” for further information on this matter.
Hazardous Air Pollutants (HAPs)
The EPA regulates hazardous air pollutants from a published list of industrial sources referred to as "source categories" which must meet control technology requirements if they emit one or more of the pollutants in significant quantities. In 2012, the EPA finalized the Mercury Air Toxic Standards (MATS) for the coal and oil-fired source category. For Colstrip Units 3 & 4, the only units in which we are a minority owner, the existing emission control systems should be sufficient to meet mercury limits. For the remaining portion of the rule that utilizes Particulate Matter as a surrogate for air toxics (including metals and acid gases), the Colstrip owners have reviewed recent stack testing data and expect that no additional emission control systems will be needed for Units 3 & 4 MATS compliance at this time. We will continue to monitor future testing results but currently we do not believe there will be any material effect on Colstrip Units 3 & 4.
Regional Haze Program
The EPA set a national goal of eliminating man-made visibility degradation in Class I areas by the year 2064. States are expected to take actions to make “reasonable progress” through 10-year plans, including application of Best Available Retrofit Technology (BART) requirements. BART is a retrofit program applied to large emission sources, including electric generating units built between 1962 and 1977. In the case where a State opts out of implementing the Regional Haze program, the EPA may act directly. On September 18, 2012, the EPA finalized the Regional Haze federal implementation plan (FIP) for Montana. The FIP includes both emission limitations and pollution controls for Colstrip Units 1 & 2. Colstrip Units 3 & 4, the only units of which we are a minority owner, are not currently affected, but will be evaluated for Reasonable Progress at the next review period in September 2017. We do not anticipate any material impacts on Units 3 & 4 at this time. In November 2012, the National Parks Conservation Association, MEIC and Sierra Club filed a petition for review of the EPA's Montana FIP in the U.S. Court of Appeals for the Ninth Circuit. We continue to monitor, but are unable to predict the outcome of this matter.
Climate Change
Concerns about long-term global climate changes could have a significant effect on our business. Our operations could also be affected by changes in laws and regulations intended to mitigate the risk of or alter global climate changes, including restrictions on the operation of our power generation resources and obligations imposed on the sale of natural gas. Changing temperatures and precipitation, including snowpack conditions, affect the availability and timing of streamflows, which impact
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hydroelectric generation. Extreme weather events could increase service interruptions, outages and maintenance costs. Changing temperatures could also increase or decrease customer demand.
Our Climate Policy Council (an interdisciplinary team of management and other employees):
| • | facilitates internal and external communications regarding climate change issues, |
| • | analyzes policy effects, anticipates opportunities and evaluates strategies for Avista Corp., and |
| • | develops recommendations on climate related policy positions and action plans. |
Federal Legislation
The U.S. Congress has considered many proposals to reduce greenhouse gas emissions and mandate renewable or clean energy. The financial and operational impacts of climate or energy legislation, if enacted, would depend on a variety of factors, including the specific provisions and timing of any legislation that might ultimately be adopted. Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable or clean energy standards, and/or energy efficiency standards are expected to continue to be considered by the U.S. Congress.
Federal Regulatory Actions
The U.S. Supreme Court ruled in 2007 that the EPA had authority under the CAA to regulate greenhouse gas emissions from new motor vehicles; subsequently, the EPA issued regulations on tailpipe emissions of greenhouse gases (GHG). When these regulations became effective, GHG became regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants and other commercial and industrial facilities. In 2010, the EPA issued a final rule, known as the Tailoring Rule, governing how these programs would be applied to stationary sources, including power plants. The EPA proposed a rule in early 2012 setting performance standards for GHG emissions from new and modified fossil fuel-fired electric generating units and announced plans to issue GHG emissions guidelines for existing sources. The rule for new sources has not been finalized, and no rule for existing sources has yet been proposed.
GHG emission standards could result in significant compliance costs. Such standards could also preclude us from developing, operating or contracting with certain types of generating plants. Our thermal generation facilities may be impacted by the promulgated PSD permitting rules in the future. These rules can impact the time to obtain permits for new generation and major modifications to existing generating units and the final permit limitations. The promulgated and proposed GHG rulemakings mentioned above also have been legally challenged in multiple venues, so we cannot fully anticipate the outcome or extent our facilities may be impacted by these regulations at this time.
In June 2013, President Obama released his Climate Action Plan which reiterates the goal of reducing greenhouse gas emissions in the U.S. "in the range of" 17 percent below 2005 levels by 2020 through such actions as regulating power plant emissions, promoting increased use of renewables and clean energy technology, and establishing tighter energy efficiency standards. In keeping with a Presidential Memorandum also issued June 25, 2013 the EPA issued a new proposal to limit carbon dioxide emissions from new coal-fired and natural gas-fueled electrical generating units on September 20, 2013. The Presidential Memorandum also directs the EPA to issue a final rule in a timely fashion thereafter, and to issue proposed standards for existing plants by June 1, 2014 with a final rule by June 1, 2015. The EPA was further directed to require that states develop implementation plans for existing plants by June 2016. Regulation of existing plants could have a significant impact depending on the structure and stringency of the final rule and the state implementation plans. Additionally, the Climate Action Plan requirements related to preparing the U.S. for the impacts of climate change could affect the Company and others in the industry as transmission system modifications to improve resiliency may be needed in order to meet those requirements.
EPA Mandatory Reporting Rule (MRR)
Any facility emitting over 25,000 metric tons of GHGs per year must report its emissions. We currently report under this requirement for Colstrip, Coyote Springs 2, and Rathdrum CT. MRR also requires GHG reporting for natural gas distribution system throughput, fugitive emissions from electric power transmission and distribution systems, fugitive emissions from natural gas distribution systems, and from natural gas storage facilities.
State Legislation and State Regulatory Activities
The states of Washington and Oregon have adopted non-binding targets to reduce GHG emissions. Both states enacted their targets with an expectation of reaching the targets through a combination of renewable energy standards, and assorted “complementary policies,” but no specific reductions are mandated.
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Washington State's Department of Ecology has adopted regulations to update its State Implementation Plan relative to the EPA's regulation of GHG emissions. We will continue to monitor actions by the Department as it may proceed to adopt additional regulations under its CAA authorities, and cannot predict any material impact at this time.
Washington and Oregon apply a GHG emissions performance standard (EPS) to electric generation facilities used to serve retail loads in their jurisdictions. The EPS prevents utilities from constructing or purchasing generation facilities, or entering into power purchase agreements of five years or longer duration, to purchase energy produced by plants that have emission levels higher than 1,100 pounds of GHG per MWh. The Washington State Department of Commerce (Commerce) initiated a process to adopt a lower emissions performance standard in 2012, any new standard will be applicable until at least 2017. Commerce published a supplemental notice of proposed rulemaking on January 16, 2013 with a new EPS of 970 pounds of GHG per MWh. We will continue to monitor this rulemaking and cannot predict any material impact at this time.
Initiative Measure 937 (I-937), the Energy Independence Act, became law in Washington's 2006 General Election. I-937 requires electric utilities with over 25,000 customers to acquire qualified renewable energy resources and/or renewable energy credits equal to 15 percent of the utility's total retail load in 2020. I-937 also requires these utilities to meet biennial energy conservation targets beginning in 2012. Furthermore, by January 1, 2012, electric utilities subject to I-937's mandates must acquire enough qualified renewable energy and/or renewable energy credits to meet three percent of their retail load. This renewable energy standard increases to nine percent in 2016. Failure to comply with renewable energy and efficiency standards could result in penalties of $50 per MWh or greater assessed against a utility for each MWh it is deficient in meeting a standard. We have met, and will continue to meet, the requirements of I-937 through a variety of renewable energy generating means, including, but not limited to, some combination of hydro upgrades, wind and biomass. In 2012, I-937 was amended in such a way that our Kettle Falls GS and certain other biomass energy facilities which commenced operation before March 31, 1999, are considered resources that may be used to meet the renewable energy standards beginning in 2016.
During its 2013 Regular Session, the Washington State Legislature, under Engrossed Second Substitute Senate Bill 5802, created the Climate Legislative and Executive Workgroup (Workgroup). The Workgroup is charged with recommending a state program of actions and policies to reduce GHG emissions, that if implemented would ensure achievement of Washington State’s emissions reductions goals set in Chapter 70.235 by the 2008 legislature. Washington Governor Jay Inslee, who chaired the Workgroup, has mentioned in recent statements his objective of eliminating “coal by wire” into Washington State. He has also endorsed other GHG emission reductions policies that could impact us, including an economy-wide cap and trade regulatory regime. While no specific legislative proposal or executive action has been proposed that would affect coal-fired generation serving retail loads in Washington, such actions could affect us and our operations. While we cannot predict the outcome of any such actions, we will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to the continued operation of cost-effective generation assets.
On February 6, 2014, the UTC issued a letter finding that Puget Sound Energy’s (PSE’s) 2013 Electric Integrated Resource Plan meets the requirements of the Revised Code of Washington and the Washington Administrative Code. In its letter, however, the UTC expressed concern regarding the continued operation of the Colstrip plant as a resource to serve retail customers. Although the UTC recognized that the results of the analyses presented by PSE “differed significantly between [Colstrip] Units 1 and 2 and Units 3 and 4,” the UTC did not limit its concerns solely to Colstrip Units 1 and 2. The UTC recommended that PSE “consult with UTC staff to consider a Colstrip Proceeding to determine the prudency of any new investment in Colstrip before it is made or, in the alternative, a closure or partial-closure plan.” As a 15 percent owner of Colstrip Units 3 and 4, we cannot predict the effect of such proceeding, should it occur, on the future ownership and operation of our share of Colstrip Units 3 and 4.
Coal Ash Management/Disposal
Currently, coal combustion byproducts (CCBs) are not regulated by the EPA as a hazardous waste. Under a proposed rule issued in 2010, the EPA is reconsidering the classification of CCBs under the Resource Conservation and Recovery Act (RCRA). The draft rules included two options: to require management of CCBs as a hazardous waste under Subtitle C of the RCRA; or to regulate coal ash under Subtitle D of the RCRA, for non-hazardous solid wastes, with possible special waste requirements. Under a January 2014 consent decree, the EPA has committed to issuing final rules regarding CCBs under Subtitle D, but this does not necessarily mean that the EPA will regulate CCB under Subtitle D. Should the EPA determine to regulate CCBs as a hazardous waste under RCRA, such action could have a significant effect on future operations of Colstrip. Congress has also considered proposed legislation regarding CCB management. We cannot predict the impact of future CCB regulation. If we were to incur incremental costs as a result of new CCB regulations, we would seek recovery in customer rates. On April 19, 2013, the EPA signed proposed revisions to the Steam Electric Guidelines (40 CFR Part 423), which, once
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developed and if adopted, could impact wastewater management at Colstrip. We are reviewing the proposed revisions and cannot at this time predict whether they will have any material impact.
Threatened and Endangered Species and Wildlife
A number of species of fish in the Northwest are listed as threatened or endangered under the Federal Endangered Species Act. Efforts to protect these and other species have not directly impacted generation levels at any of our hydroelectric facilities. We are implementing fish protection measures at our hydroelectric project on the Clark Fork River under a 45-year FERC operating license for Cabinet Gorge and Noxon Rapids (issued March 2001) that incorporates a comprehensive settlement agreement. The restoration of native salmonid fish, including bull trout, is a key part of the agreement. The result is a collaborative native salmonid restoration program with the U.S. Fish and Wildlife Service, Native American tribes and the states of Idaho and Montana on the lower Clark Fork River, consistent with requirements of the FERC license. The U.S. Fish & Wildlife Service issued an updated Critical Habitat Designation for bull trout in 2010 that includes the lower Clark Fork River, as well as portions of the Coeur d'Alene basin within our Spokane River Project area, and is currently developing a final Bull Trout Recovery Plan under the ESA. Issues related to these activities are expected to be resolved through the ongoing collaborative effort of our Clark Fork and Spokane River FERC licenses. See “Spokane River Licensing” and “Fish Passage at Cabinet Gorge and Noxon Rapids” in “Note 20 of the Notes to Consolidated Financial Statements” for further information.
Various statutory authorities, including the Migratory Bird Treaty Act, have established penalties for the unauthorized take of migratory birds. Because we operate facilities that can pose risks to a variety of such birds, we have developed and follow an avian protection plan.
Other
For other environmental issues and other contingencies see “Note 20 of the Notes to Consolidated Financial Statements.”
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Our primary market risk exposures are:
| • | Commodity prices for electric power and natural gas |
| • | Credit related to the wholesale energy market |
| • | Interest rates on long-term and short-term debt |
| • | Foreign exchange rates between the U.S. dollar and the Canadian dollar |
Commodity Price Risk
Electric Power Commodities
We are exposed to market risks for electric power because of:
| • | imbalances between available power supply resources and our load obligations, |
| • | substitution of resources to achieve economic dispatch from available power supply choices, and |
| • | our objective to optimize the value of specific power resource facilities. |
Imbalances between available power supply resources and our electric load obligations arise because of seasonal factors, operating parameters of our facilities, contract rights and contract obligations, and variations in customer demand. We forecast both obligations and resources to estimate our future surplus or deficit positions. We hedge a portion of the open position with forward transactions that establish physical supply (or disposition) and/or financially-equivalent derivatives that mitigate economic uncertainty. Seasonal factors and prevailing weather affect power supplies. Supply is affected by both temperature and the timing and amount of precipitation, particularly with respect to our hydroelectric generation facilities that rely on river flows from immediate precipitation and from melting snow. Wind conditions affect the amount and timing of supply from wind generation facilities. Operational parameters affecting power resources include natural river flow, water storage and regulation-driven constraints for hydroelectric generation. Operational parameters also include maintenance requirements and forced outages at electric generating plants, fuel availability for thermal plants, environmental and other regulatory constraints and other factors.
Electric power obligations include retail customer demand and other commitments between Avista Corp. and other parties in the wholesale power market. Retail customer demand is sensitive to temperature and to normal seasonal temperature variation that impacts customers’ heating and cooling-related demand for energy. Obligations are also affected by customer growth, economic conditions, technology that adds to or reduces electric demand, and choices that customers make about energy usage. Our
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forecasts of obligations consider contract terms, past energy demand patterns and indicators of potential changes in energy consumption.
Economic dispatch involves the decisions that we make in the mix of power resources to meet our retail customer requirements and other obligations. We make dispatch decisions to operate or not operate our resources and to dispose of energy or to obtain resources from others in the wholesale power market (including natural gas fuel markets). Hydroelectric generation is typically the lowest cost source of supply. Thermal generation resource costs vary with fuel costs and other factors. Power purchase agreements may provide us with variable power supply quantities and contract terms can include both fixed and variable costs.
To balance electric power resources and electric demand obligations, we enter into transactions in the wholesale power and fuel markets. These transactions include physical power and natural gas and derivative instruments based on wholesale prices of power and natural gas. Wholesale market prices tend to vary with natural gas fuel costs to the extent that natural gas-fired resources are the least cost alternative in the region (which is often the case in recent years). Wholesale prices also tend to vary with the extent of hydroelectric surplus or shortages, particularly during the highest hydroelectric generation periods of spring rains and snow melt. Wholesale prices also vary based on wind patterns that affect output from wind generation facilities in the region. Requirements for renewable energy resources and tax credit incentives for such resources can impact wholesale prices, including sometimes pushing prices to negative values. Generating resource availability and regional demand tend to impact energy prices. Wholesale prices are quoted for energy to be delivered in time frames ranging from intra-hour, hourly, daily, multi-day, monthly, quarterly and annually. Future market prices extend several years into the future, though market liquidity tends to become limited beyond a few years into the future.
Natural Gas Commodities
We purchase natural gas for delivery to retail natural gas customers. Some natural gas is purchased for injection into storage, which can later be withdrawn from storage. We also sell natural gas originally purchased for retail natural gas supply or inventory back into the wholesale market. Some of the wholesale natural gas transactions are executed at fixed prices for future delivery, while some are executed based on market index prices or spot prices. We transact for physical delivery of natural gas and we enter into swaps that create a financial hedge for future natural gas prices.
Natural gas is a significant source of fuel for electric generation. We buy natural gas as fuel for electric generating facilities that we own and for the Lancaster Plant where we have contractual rights to dispatch its operation. We also sell natural gas when we have an opportunity to displace thermal generation with other power supply resources or when expected thermal generation does not actually occur for any reason.
We hedge a portion of these natural gas purchases and sales, including the use of physical delivery contracts and derivative instruments based on wholesale prices of natural gas. We also transact based on index pricing in the wholesale natural gas market and at spot market prices that can vary significantly.
Some, but not all, natural gas transactions related to thermal generation are executed concurrently with similar quantities of electric energy (based on physical fuel-to-power conversion parameters of generation facilities that we own or control). In such cases, the net economic cost or benefit between natural gas purchases and power sales (or gas sales offset by power purchases) will vary as each commodity price moves independently of the other.
We enter into natural gas transactions intended to extract value from our assets and contract rights. These asset optimization transactions include purchases and offsetting sales at two delivery locations when we have excess capacity available in natural gas pipelines (such pipelines are usually owned by other parties where we have contract rights for that capacity). Asset optimization strategies also include time difference purchases and sales of natural gas that use excess storage capacity available in our underground natural gas storage facilities. These transactions include commitments for future physical delivery and/or financial swaps tied to the price of natural gas.
Matters Affecting Both Electric and Natural Gas Commodities
Variation in electric and natural gas commodity prices affects our cash flow, customer retail rates and the amount of net income we recognize. Regulatory cost recovery mechanisms address these power supply and natural gas cost variations, such that a portion of the cost variation is passed on to customers and a portion is recognized by the Company. The timing of incurring costs can be significantly different than the timing for recovering costs, resulting in the need for a significant liquidity cushion. Historically, we have carried significant balances of deferred power supply and natural gas supply costs, which represent costs we expect to recover from customers in future retail rates, subject to approval by regulators.
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When we have surplus electric generation, its value varies with market prices and economics of other resources in the region. When we have a shortage of electric generation from our own resources and other resources that we have long-term rights to control, the cost to obtain electric power or fuel varies. We make forecasts to estimate surplus and deficit conditions and we may enter into forward hedging arrangements to reduce the expected net surplus or deficit. Our forecasts cannot avoid uncertainty about loads or obligations and we do not attempt to fully hedge all forecast net open positions. Our hedges include forward transactions ranging from intra-hour to multiple years in the future, with transaction blocks of intra-hour, hourly, daily, monthly, quarterly, annually, and multiple years. See further information at “Avista Utilities - Regulatory Matters.”
See “Risk Management for Energy Resources” for additional information on our activities to hedge our exposure to price risk by making forward commitments for energy purchases and sales.
Wholesale electricity prices are affected by a number of factors, including:
| • | demand for electricity, |
| • | adequacy of generating reserve margins, |
| • | scheduled and unscheduled outages of generating facilities, |
| • | availability of streamflows for hydroelectric generation, |
| • | price and availability of fuel for thermal generating plants, |
| • | disruptions to or constraints on transmission facilities, |
| • | the number of market participants and the willingness of market participants to trade, and |
| • | weather (including temperature fluctuations and generation resulting from wind). |
Wholesale natural gas prices are affected by a number of factors, including:
| • | demand for natural gas, including natural gas as fuel for electric generation, |
| • | actual and expected changes in the North American natural gas supply volume or source mix including the growth in new supplies such as natural gas from shale, |
| • | natural gas production that can be delivered to our service areas, |
| • | level of imports and exports, particularly from Canada by pipeline, and any taxes or restrictions that apply, |
| • | potential development of liquefied natural gas export facilities that compete for supplies, |
| • | level of storage inventories and regional accessibility, |
| • | global energy markets, including oil or other natural gas substitutes, such as coal, |
| • | availability of pipeline capacity to transport natural gas from region to region, |
| • | the number of market participants and the willingness of market participants to trade, and |
| • | weather conditions (temperatures, precipitation levels and wind patterns) which affect energy demand, including weather-sensitive customer demand, and electric generation. |
Any combination of these factors that reduce the supply of or increases demand for energy generally causes the market price to move upward. Conversely, factors that reduce demand or increase production will generally reduce market prices for energy. In addition to these factors, wholesale power markets are subject to regulatory constraints including price controls.
Price risk relates to physical energy products and to fluctuation in market prices of associated derivative commodity instruments (such as swaps, options and forward contracts). Price risk may be influenced to the extent that the performance or non-performance by market participants of their contractual obligations and commitments affect the supply of, or demand for, the commodity.
Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are generally accounted for on the accrual basis until they are settled or realized, unless there is a decline in the fair value of the contract that is determined to be other than temporary.
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The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2013 that are expected to settle in each respective year (dollars in thousands):
| 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) | |||||||||||||||||||||||
| 2014 | $ | (215 | ) | $ | 7,243 | $ | (6,131 | ) | $ | (2,663 | ) | $ | (221 | ) | $ | (6,226 | ) | $ | (1,214 | ) | $ | (1,404 | ) | ||||||||
| 2015 | (2,818 | ) | (1,798 | ) | (2,450 | ) | (9,586 | ) | (34 | ) | 3,121 | — | 4,298 | ||||||||||||||||||
| 2016 | (3,289 | ) | — | (1,171 | ) | (7,400 | ) | (83 | ) | 3,529 | — | 2,230 | |||||||||||||||||||
| 2017 | (2,955 | ) | — | (86 | ) | — | (187 | ) | — | — | — | ||||||||||||||||||||
| 2018 | (2,661 | ) | — | — | — | (313 | ) | — | — | — | |||||||||||||||||||||
| Thereafter | (1,456 | ) | — | — | — | (148 | ) | — | — | — | |||||||||||||||||||||
The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2012 that are expected to settle in each respective year (dollars in thousands):
| 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) | |||||||||||||||||||||||
| 2013 | $ | (5,165 | ) | $ | (26,360 | ) | $ | (20,085 | ) | $ | (17,560 | ) | $ | 154 | $ | 21,423 | $ | (709 | ) | $ | 13,218 | ||||||||||
| 2014 | (3,745 | ) | (1,664 | ) | (6,384 | ) | (5,390 | ) | 310 | 6,721 | (1,125 | ) | (434 | ) | |||||||||||||||||
| 2015 | (2,890 | ) | (273 | ) | (1,684 | ) | 389 | (136 | ) | 116 | — | (227 | ) | ||||||||||||||||||
| 2016 | (2,644 | ) | — | (270 | ) | 72 | (194 | ) | — | — | — | ||||||||||||||||||||
| 2017 | (2,293 | ) | — | — | — | (323 | ) | — | — | — | |||||||||||||||||||||
| Thereafter | (2,396 | ) | — | — | — | (753 | ) | — | — | — | |||||||||||||||||||||
| (1) | Physical transactions represent commodity transactions where we will take delivery of either electricity or natural gas and financial transactions represent derivative instruments with no physical delivery, such as futures, swaps, options, or forward contracts. |
The above electric and natural gas derivative contracts will be included in either power supply costs or natural gas supply costs during the period they are delivered and will be included in the various recovery mechanisms (ERM, PCA, and PGAs), or in the general rate case process, and are expected to eventually be collected through retail rates from customers.
Credit Risk
Counterparty Non-Performance Risk
Credit risk relates to potential losses that we would incur as a result of non-performance of contractual obligations by counterparties to deliver energy or make financial settlements. We often extend credit to counterparties and customers, and we are exposed to the risk of not being able to collect amounts owed to us. Credit risk includes potential counterparty default due to circumstances:
| • | relating directly to the counterparty, |
| • | caused by market price changes, and |
| • | relating to other market participants that have a direct or indirect relationship with such counterparty. |
Changes in market prices may dramatically alter the size of credit risk with counterparties, even when we establish conservative credit limits. Should a counterparty fail to perform, we may be required to honor the underlying commitment or to replace existing contracts with contracts at then-current market prices.
We enter into bilateral transactions with various counterparties. We also trade energy and related derivative instruments through clearinghouse exchanges.
We seek to mitigate bilateral credit risk by:
| • | entering into bilateral contracts that specify credit terms and protections against default, |
| • | applying credit limits and duration criteria to existing and prospective counterparties, |
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| • | actively monitoring current credit exposures, |
| • | asserting our collateral rights with counterparties, and |
| • | carrying out transaction settlements timely and effectively. |
We also mitigate credit risk by transacting through exchanges that use fully collateralized clearing arrangements to significantly reduce counterparty default risk. The extent of transactions conducted through exchanges has increased as many market participants have shown a preference toward exchange trading and have reduced bilateral transactions. We actively monitor the collateral required by such exchanges to effectively manage our capital requirements.
Our credit policy and processes include an evaluation of the financial condition and credit ratings of counterparties, collateral requirements or other credit enhancements, such as letters of credit or parent company guarantees. We use both tailored and standardized agreements as we negotiate contract terms with counterparties. Such contract terms often allow for the netting or offsetting of positive and negative exposures associated with a single counterparty or affiliated group. Despite mitigation efforts, the risk of counterparty default or excessive collateral demands on us cannot be entirely eliminated.
Credit risk may be affected by industry concentration and geographic concentration. We have concentrations of suppliers and customers in the electric and natural gas industries including:
| • | electric and natural gas utilities, |
| • | electric generators and transmission providers, |
| • | natural gas producers and pipelines, |
| • | financial institutions including commodity clearing exchanges and related parties, and |
| • | energy marketing and trading companies. |
We have concentrations of credit risk related to our geographic location in the western United States and western Canada energy markets. These concentrations of counterparties and concentrations of geographic location may affect our overall exposure to credit risk because the counterparties may be similarly affected by changes in conditions.
Demands for Collateral
Credit risk affects demands on our capital. We are subject to limits and credit terms that counterparties may assert to allow us to enter into transactions with them and maintain acceptable credit exposures. Many of our counterparties allow unsecured credit at limits prescribed by agreements or their discretion. Capital requirements for certain transaction types involve a combination of initial margin and market value margins without any unsecured credit threshold. Counterparties may seek assurances of performance from us in the form of letters of credit, prepayment or cash deposits.
Credit exposure can change significantly in periods of price volatility. As a result, sudden and significant demands may be made against our credit facilities and cash. We actively monitor the exposure to possible collateral calls and take steps to minimize capital requirements.
Counterparties’ credit exposure to us is dynamic in normal markets and may change significantly in more volatile markets. The amount of potential default risk to us from each counterparty depends on the extent of forward contracts, unsettled transactions and market prices. There is a risk that we may seek additional collateral from counterparties that are unable or unwilling to provide it.
Risk Management for Energy Resources
We have an energy resources risk policy, which includes our wholesale energy markets credit policy and control procedures to manage energy commodity price and credit risks. Our Risk Management Committee established our risk management policy for energy resources. The Risk Management Committee is comprised of certain officers and other management. Our Risk Management Committee also established our wholesale energy markets credit policy. The credit policy is designed to reduce the risk of financial loss in case counterparties default on delivery or settlement obligations and to conserve our liquidity as other parties may place credit limits or require cash collateral.
The Audit Committee of the Company’s Board of Directors periodically reviews and discusses enterprise risk management processes, and it focuses on the Company’s material financial and accounting risk exposures and the steps management has undertaken to control them. In addition, the Environmental and Operations Committee of the Company's Board of Directors has the role of overseeing risks associated with the Company’s legal and regulatory compliance in its operations including environmental compliance, energy resources, transmission and distribution operations, employee safety performance, and
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corporate security, including technology risks. Our Risk Management and Environmental and Operations Committees review the status of risk exposures through regular reports and meetings. Nonetheless, adverse changes in commodity prices, generating capacity, customer loads, regulation and other factors may result in losses of earnings, cash flows and/or fair values.
In implementing our risk management policy for energy resources, we measure the volume of monthly, quarterly and annual energy imbalances between projected power loads and resources. The measurement process is based on expected loads at fixed prices (including those subject to retail rates) and expected resources to the extent that costs are essentially fixed by virtue of known fuel supply costs or projected hydroelectric conditions. To the extent that expected costs are not fixed, either because of volume mismatches between loads and resources or because fuel cost is not locked in through fixed price contracts or derivative instruments, our risk policy guides the process to manage this open forward position over a period of time. Normal operations result in seasonal mismatches between power loads and available resources. We are able to vary the operation of generating resources to match parts of intra-hour, hourly, daily and weekly load fluctuations. We use the wholesale power markets, including the natural gas market as it relates to power generation fuel, to sell projected resource surpluses and obtain resources when deficits are projected. We buy and sell fuel for thermal generation facilities based on comparative power market prices and marginal costs of fueling and operating available generating facilities and the relative economics of substitute market purchases for generating plant operation.
To address the impact on our operations of energy market price volatility, our hedging practices for electricity (including fuel for generation) and natural gas extend beyond the current operating year. Executing this extended hedging program may increase our credit risks. Our credit risk management process is designed to mitigate such credit risks through limit setting, contract protections and counterparty diversification, among other practices.
Our projected retail natural gas loads and resources are regularly reviewed by operating management and the Risk Management Committee. To manage the impacts of volatile natural gas prices, we seek to procure natural gas through a diversified mix of spot market purchases and forward fixed price purchases from various supply basins and time periods. We have an active hedging program that extends four years into the future with the goal of reducing price volatility in our natural gas supply costs. We use natural gas storage capacity to support high demand periods and to procure natural gas when prices are likely to be seasonally lower. Securing prices throughout the year and even into subsequent years mitigates potential adverse impacts of significant purchase requirements in a volatile price environment.
Interest Rate Risk
We are affected by fluctuating interest rates related to a portion of our existing debt, our future borrowing requirements, and our pension and other post-retirement benefit obligations. The Finance Committee of our Board of Directors periodically reviews and discusses interest rate risk management processes, and it focuses on the steps management has undertaken to control it. Our Risk Management Committee also reviews our interest risk management plan. We manage interest rate exposure by limiting our variable rate exposures to a percentage of total capitalization. Additionally, interest rate risk is managed by monitoring market conditions when timing the issuance of long-term debt and optional debt redemptions and through the use of fixed rate long-term debt with varying maturities. We also hedge a portion of our interest rate risk with financial derivative instruments, which may include interest rate swaps and U.S. Treasury lock agreements.
These interest rate swap agreements are considered economic hedges against fluctuations in future cash flows associated with anticipated debt issuances.
As of December 31, 2013, we had interest rate swap agreements with a total notional amount of $245.0 million with mandatory cash settlement dates in 2014 through 2018. In anticipation of issuing long-term debt in future years, we entered into four interest rate swap agreements in January 2014, with a total notional amount of $70.0 million and mandatory cash settlement dates ranging from 2015 to 2018.
As of December 31, 2013, we had a current derivative asset of $14.0 million and a long-term derivative asset of $19.6 million, with an offsetting regulatory liability on the Consolidated Balance Sheets in accordance with regulatory accounting practices. We estimate that a 10-basis-point increase in forward LIBOR interest rates as of December 31, 2013 would increase the interest rate swap derivative net asset by $3.3 million, while a 10-basis-point decrease would decrease the interest rate swap net asset by $3.4 million.
As of December 31, 2012, we had interest rate swap agreements with a total notional amount of $160.0 million and a current derivative liability of $1.4 million and a long-term derivative asset of $7.3 million. We estimated that a 10-basis-point increase in forward LIBOR interest rates as of December 31, 2012 would have increased the interest rate swap derivative net asset by $3.3 million, while a 10-basis-point decrease would decrease the interest rate swap net asset by $3.3 million.
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In June 2013, the Company cash settled two interest rate swap contracts (notional amount of $85.0 million) and received a total of $2.9 million. The interest rate swap contracts were settled in connection with the pricing of $90.0 million of First Mortgage Bonds that were issued in August 2013. Upon settlement of interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a component of interest expense over the term of the associated debt.
The interest rate on $51.5 million of long-term debt to affiliated trusts is adjusted quarterly, reflecting current market rates. Amounts borrowed under our committed line of credit agreements have variable interest rates.
The following table shows our long-term debt (including current portion) and related weighted average interest rates, by expected maturity dates as of December 31, 2013 (dollars in thousands):
| 2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | Total | Fair Value | |||||||||||||||||||||||
| Fixed rate long-term debt | $ | — | — | $ | 90,000 | — | $ | 272,500 | $ | 930,500 | $ | 1,293,000 | $ | 1,384,093 | ||||||||||||||||
| Weighted average interest rate | — | — | 0.84 | % | — | 6.07 | % | 5.30 | % | 5.16 | % | |||||||||||||||||||
| Fixed rate nonrecourse long-term debt of Spokane Energy | $ | 16,407 | $ | 1,431 | $ | — | — | — | — | $ | 17,838 | $ | 18,636 | |||||||||||||||||
| Weighted average interest rate | 8.45 | % | 8.45 | % | — | — | — | — | 8.45 | % | ||||||||||||||||||||
| Variable rate long-term debt to affiliated trusts | — | — | — | — | — | $ | 51,547 | $ | 51,547 | $ | 37,114 | |||||||||||||||||||
| Weighted average interest rate | — | — | — | — | — | 1.11 | % | 1.11 | % | |||||||||||||||||||||
Foreign Currency Risk
A significant portion of our utility natural gas supply (including fuel for electric generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of our short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices. The short-term natural gas transactions are typically settled within sixty days with U.S. dollars. We economically hedge a portion of the foreign currency risk by purchasing Canadian currency when such commodity transactions are initiated. This risk has not had a material effect on our financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations are included with natural gas supply costs for ratemaking. As of December 31, 2013, we had a net current derivative asset for foreign currency hedges of less than $0.1 million included in other current assets on the Consolidated Balance Sheet. As of December 31, 2013, we had entered into 23 Canadian currency forward contracts with a notional amount of $8.6 million ($9.2 million Canadian). As of December 31, 2012, we had entered into 20 Canadian currency forward contracts with a notional amount of $12.6 million ($12.5 million Canadian) with a net current derivative liability of less than $0.1 million.
Further information for derivatives and fair values is disclosed at “Note 5 of the Notes to Consolidated Financial Statements” and “Note 16 of the Notes to Consolidated Financial Statements.”
Item 8. Financial Statements and Supplementary Data
The Report of Independent Registered Public Accounting Firm and Financial Statements begin on the next page.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Avista Corporation
Spokane, Washington
We have audited the accompanying consolidated balance sheets of Avista Corporation and subsidiaries (the “Company”) as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, equity and redeemable noncontrolling interests, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Avista Corporation and subsidiaries at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report, dated February 26, 2014 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Seattle, Washington
February 26, 2014
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CONSOLIDATED STATEMENTS OF INCOME
| Avista Corporation |
For the Years Ended December 31
Dollars in thousands, except per share amounts
| 2013 | 2012 | 2011 | |||||||||
| Operating Revenues: | |||||||||||
| Utility revenues | $ | 1,402,195 | $ | 1,352,385 | $ | 1,441,522 | |||||
| Ecova revenues | 176,761 | 155,664 | 137,848 | ||||||||
| Other non-utility revenues | 39,549 | 38,953 | 40,410 | ||||||||
| Total operating revenues | 1,618,505 | 1,547,002 | 1,619,780 | ||||||||
| Operating Expenses: | |||||||||||
| Utility operating expenses: | |||||||||||
| Resource costs | 689,586 | 693,127 | 790,048 | ||||||||
| Other operating expenses | 276,228 | 276,780 | 261,926 | ||||||||
| Depreciation and amortization | 117,174 | 112,091 | 105,629 | ||||||||
| Taxes other than income taxes | 88,435 | 83,409 | 83,347 | ||||||||
| Ecova operating expenses: | |||||||||||
| Other operating expenses | 148,023 | 139,173 | 109,738 | ||||||||
| Depreciation and amortization | 15,434 | 13,519 | 7,193 | ||||||||
| Other non-utility operating expenses: | |||||||||||
| Other operating expenses | 38,651 | 38,041 | 33,117 | ||||||||
| Depreciation and amortization | 581 | 792 | 778 | ||||||||
| Total operating expenses | 1,374,112 | 1,356,932 | 1,391,776 | ||||||||
| Income from operations | 244,393 | 190,070 | 228,004 | ||||||||
| Interest expense | 78,755 | 76,894 | 73,876 | ||||||||
| Interest expense to affiliated trusts | 467 | 541 | 332 | ||||||||
| Capitalized interest | (3,676 | ) | (2,401 | ) | (2,942 | ) | |||||
| Other income-net | (6,677 | ) | (5,025 | ) | (3,433 | ) | |||||
| Income before income taxes | 175,524 | 120,061 | 160,171 | ||||||||
| Income tax expense | 63,230 | 41,261 | 56,632 | ||||||||
| Net income | 112,294 | 78,800 | 103,539 | ||||||||
| Less: Net income attributable to noncontrolling interests | (1,217 | ) | (590 | ) | (3,315 | ) | |||||
| Net income attributable to Avista Corporation shareholders | $ | 111,077 | $ | 78,210 | $ | 100,224 | |||||
| Weighted-average common shares outstanding (thousands), basic | 59,960 | 59,028 | 57,872 | ||||||||
| Weighted-average common shares outstanding (thousands), diluted | 59,997 | 59,201 | 58,092 | ||||||||
| Earnings per common share attributable to Avista Corporation shareholders: | |||||||||||
| Basic | $ | 1.85 | $ | 1.32 | $ | 1.73 | |||||
| Diluted | $ | 1.85 | $ | 1.32 | $ | 1.72 | |||||
The Accompanying Notes are an Integral Part of These Statements.
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
| Avista Corporation |
For the Years Ended December 31
Dollars in thousands
| 2013 | 2012 | 2011 | |||||||||
| Net income | $ | 112,294 | $ | 78,800 | $ | 103,539 | |||||
| Other Comprehensive Income (Loss): | |||||||||||
| Unrealized investment gains/(losses) - net of taxes of $(1,026), $191 and $77, respectively | (1,741 | ) | 323 | 134 | |||||||
| Reclassification adjustment for realized gains on investment securities included in net income - net of taxes of $(7) and $(171), respectively | (12 | ) | (290 | ) | — | ||||||
| Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $1,418, $(590) and $(778), respectively | 2,634 | (1,096 | ) | (1,445 | ) | ||||||
| Total other comprehensive income (loss) | 881 | (1,063 | ) | (1,311 | ) | ||||||
| Comprehensive income | 113,175 | 77,737 | 102,228 | ||||||||
| Comprehensive income attributable to noncontrolling interests | (1,217 | ) | (590 | ) | (3,315 | ) | |||||
| Comprehensive income attributable to Avista Corporation shareholders | $ | 111,958 | $ | 77,147 | $ | 98,913 | |||||
The Accompanying Notes are an Integral Part of These Statements.
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CONSOLIDATED BALANCE SHEETS
| Avista Corporation |
As of December 31
Dollars in thousands
| 2013 | 2012 | ||||||
| Assets: | |||||||
| Current Assets: | |||||||
| Cash and cash equivalents | $ | 82,574 | $ | 75,464 | |||
| Accounts and notes receivable-less allowances of $44,309 and $44,155, respectively | 221,343 | 193,683 | |||||
| Utility energy commodity derivative assets | 3,022 | 4,139 | |||||
| Regulatory asset for utility derivatives | 10,829 | 35,082 | |||||
| Investments and funds held for clients | 96,688 | 88,272 | |||||
| Materials and supplies, fuel stock and natural gas stored | 44,946 | 47,455 | |||||
| Deferred income taxes | 24,788 | 34,281 | |||||
| Income taxes receivable | 7,783 | 2,777 | |||||
| Other current assets | 57,706 | 24,641 | |||||
| Total current assets | 549,679 | 505,794 | |||||
| Net Utility Property: | |||||||
| Utility plant in service | 4,290,464 | 4,054,644 | |||||
| Construction work in progress | 160,323 | 143,098 | |||||
| Total | 4,450,787 | 4,197,742 | |||||
| Less: Accumulated depreciation and amortization | 1,248,362 | 1,174,026 | |||||
| Total net utility property | 3,202,425 | 3,023,716 | |||||
| Other Non-current Assets: | |||||||
| Investment in exchange power-net | 13,883 | 16,333 | |||||
| Investment in affiliated trusts | 11,547 | 11,547 | |||||
| Goodwill | 76,257 | 75,959 | |||||
| Intangible assets-net of accumulated amortization of $36,634 and $26,030, respectively | 39,576 | 46,256 | |||||
| Long-term energy contract receivable of Spokane Energy | 40,619 | 52,033 | |||||
| Other property and investments-net | 58,555 | 46,542 | |||||
| Total other non-current assets | 240,437 | 248,670 | |||||
| Deferred Charges: | |||||||
| Regulatory assets for deferred income tax | 71,421 | 79,406 | |||||
| Regulatory assets for pensions and other postretirement benefits | 156,984 | 306,408 | |||||
| Other regulatory assets | 102,915 | 103,946 | |||||
| Non-current utility energy commodity derivative assets | 854 | 1,093 | |||||
| Non-current regulatory asset for utility derivatives | 23,258 | 25,218 | |||||
| Other deferred charges | 13,950 | 18,928 | |||||
| Total deferred charges | 369,382 | 534,999 | |||||
| Total assets | $ | 4,361,923 | $ | 4,313,179 | |||
The Accompanying Notes are an Integral Part of These Statements.
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CONSOLIDATED BALANCE SHEETS (continued)
| Avista Corporation |
As of December 31
Dollars in thousands
| 2013 | 2012 | ||||||
| Liabilities and Equity: | |||||||
| Current Liabilities: | |||||||
| Accounts payable | $ | 182,088 | $ | 198,914 | |||
| Client fund obligations | 99,117 | 87,839 | |||||
| Current portion of long-term debt | 358 | 50,372 | |||||
| Current portion of nonrecourse long-term debt of Spokane Energy | 16,407 | 14,965 | |||||
| Short-term borrowings | 171,000 | 52,000 | |||||
| Utility energy commodity derivative liabilities | 10,875 | 29,515 | |||||
| Other current liabilities | 145,495 | 142,544 | |||||
| Total current liabilities | 625,340 | 576,149 | |||||
| Long-term debt | 1,272,425 | 1,178,367 | |||||
| Nonrecourse long-term debt of Spokane Energy | 1,431 | 17,838 | |||||
| Long-term debt to affiliated trusts | 51,547 | 51,547 | |||||
| Long-term borrowings under committed line of credit | 46,000 | 54,000 | |||||
| Regulatory liability for utility plant retirement costs | 242,850 | 234,128 | |||||
| Pensions and other postretirement benefits | 122,513 | 283,985 | |||||
| Deferred income taxes | 535,343 | 524,877 | |||||
| Other non-current liabilities and deferred credits | 130,318 | 110,215 | |||||
| Total liabilities | 3,027,767 | 3,031,106 | |||||
| Commitments and Contingencies (See Notes to Consolidated Financial Statements) | |||||||
| Redeemable Noncontrolling Interests | 15,889 | 4,938 | |||||
| Equity: | |||||||
| Avista Corporation Shareholders’ Equity: | |||||||
| Common stock, no par value; 200,000,000 shares authorized; 60,076,752 and 59,812,796 shares outstanding | 896,993 | 889,237 | |||||
| Accumulated other comprehensive loss | (5,819 | ) | (6,700 | ) | |||
| Retained earnings | 407,092 | 376,940 | |||||
| Total Avista Corporation shareholders’ equity | 1,298,266 | 1,259,477 | |||||
| Noncontrolling Interests | 20,001 | 17,658 | |||||
| Total equity | 1,318,267 | 1,277,135 | |||||
| Total liabilities and equity | $ | 4,361,923 | $ | 4,313,179 | |||
The Accompanying Notes are an Integral Part of These Statements.
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CONSOLIDATED STATEMENTS OF CASH FLOWS
| Avista Corporation |
For the Years Ended December 31
Dollars in thousands
| 2013 | 2012 | 2011 | |||||||||
| Operating Activities: | |||||||||||
| Net income | $ | 112,294 | $ | 78,800 | $ | 103,539 | |||||
| Non-cash items included in net income: | |||||||||||
| Depreciation and amortization | 133,189 | 126,402 | 113,600 | ||||||||
| Provision for deferred income taxes | 23,532 | 21,449 | 24,007 | ||||||||
| Power and natural gas cost amortizations (deferrals), net | (9,408 | ) | 6,702 | 21,870 | |||||||
| Amortization of debt expense | 3,813 | 3,803 | 4,617 | ||||||||
| Amortization of investment in exchange power | 2,450 | 2,450 | 2,450 | ||||||||
| Stock-based compensation expense | 6,218 | 5,792 | 5,756 | ||||||||
| Equity-related AFUDC | (6,066 | ) | (4,055 | ) | (2,225 | ) | |||||
| Pension and other postretirement benefit expense | 42,067 | 39,838 | 32,067 | ||||||||
| Amortization of Spokane Energy contract | 11,414 | 10,492 | 9,645 | ||||||||
| Write-off of Reardan wind generation capitalized costs | 2,534 | — | — | ||||||||
| Other | 12,982 | 5,256 | (4,988 | ) | |||||||
| Contributions to defined benefit pension plan | (44,263 | ) | (44,000 | ) | (26,000 | ) | |||||
Changes in certain current assets and liabilities: | |||||||||||
| Accounts and notes receivable | (32,675 | ) | 8,100 | 30,616 | |||||||
| Materials and supplies, fuel stock and natural gas stored | 2,509 | 4,551 | (3,388 | ) | |||||||
| Other current assets | (18,471 | ) | 27,258 | (23,881 | ) | ||||||
| Accounts payable | (8,389 | ) | 30,189 | (18,032 | ) | ||||||
| Other current liabilities | 8,827 | (6,474 | ) | (188 | ) | ||||||
| Net cash provided by operating activities | 242,557 | 316,553 | 269,465 | ||||||||
| Investing Activities: | |||||||||||
| Utility property capital expenditures (excluding equity-related AFUDC) | (294,363 | ) | (271,187 | ) | (239,782 | ) | |||||
| Other capital expenditures | (8,750 | ) | (4,787 | ) | (3,590 | ) | |||||
| Federal grant payments received | 3,409 | 8,277 | 16,928 | ||||||||
| Cash paid by subsidiaries for acquisitions, net of cash received | — | (50,310 | ) | (31,409 | ) | ||||||
| Decrease (increase) in funds held for clients | 1,815 | (6,811 | ) | 78,561 | |||||||
| Purchase of securities available for sale | (35,949 | ) | (100,374 | ) | (96,634 | ) | |||||
| Sale and maturity of securities available for sale | 22,960 | 137,999 | 80 | ||||||||
| Other | (1,339 | ) | (7,475 | ) | (6,435 | ) | |||||
| Net cash used in investing activities | (312,217 | ) | (294,668 | ) | (282,281 | ) | |||||
The Accompanying Notes are an Integral Part of These Statements.
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CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
| Avista Corporation |
For the Years Ended December 31
Dollars in thousands
| 2013 | 2012 | 2011 | |||||||||
| Financing Activities: | |||||||||||
| Net increase (decrease) in short-term borrowings | $ | 119,000 | $ | (9,000 | ) | $ | (49,000 | ) | |||
| Borrowings from Ecova line of credit | 3,000 | 33,000 | 35,000 | ||||||||
| Repayment of borrowings from Ecova line of credit | (11,000 | ) | (14,000 | ) | — | ||||||
| Proceeds from issuance of long-term debt | 90,000 | 80,000 | 85,000 | ||||||||
| Redemption and maturity of long-term debt | (50,462 | ) | (11,492 | ) | (297 | ) | |||||
| Maturity of nonrecourse long-term debt of Spokane Energy | (14,965 | ) | (13,669 | ) | (12,463 | ) | |||||
| Long-term debt and short-term borrowing issuance costs | (531 | ) | (764 | ) | (4,477 | ) | |||||
| Cash received (paid) for settlement of interest rate swap agreements | 2,901 | (18,547 | ) | (10,557 | ) | ||||||
| Issuance of common stock | 4,609 | 29,079 | 26,463 | ||||||||
| Cash dividends paid | (73,276 | ) | (68,552 | ) | (63,737 | ) | |||||
| Purchase of subsidiary noncontrolling interest | (4,587 | ) | (917 | ) | (6,179 | ) | |||||
| Increase (decrease) in client fund obligations | 11,278 | (30,996 | ) | 17,782 | |||||||
| Issuance of subsidiary noncontrolling interest | 480 | 3,714 | — | ||||||||
| Other | 323 | 1,061 | 530 | ||||||||
| Net cash provided by (used in) financing activities | 76,770 | (21,083 | ) | 18,065 | |||||||
| Net increase in cash and cash equivalents | 7,110 | 802 | 5,249 | ||||||||
| Cash and cash equivalents at beginning of year | 75,464 | 74,662 | 69,413 | ||||||||
| Cash and cash equivalents at end of year | $ | 82,574 | $ | 75,464 | $ | 74,662 | |||||
| Supplemental Cash Flow Information: | |||||||||||
| Cash paid during the year: | |||||||||||
| Interest | $ | 75,411 | $ | 74,900 | $ | 69,083 | |||||
| Income taxes | 44,772 | 8,069 | 26,451 | ||||||||
| Non-cash financing and investing activities: | |||||||||||
| Accounts payable for capital expenditures | 12,723 | 21,331 | 20,629 | ||||||||
| Valuation adjustment for redeemable noncontrolling interests | 10,704 | (10,104 | ) | 4,059 | |||||||
| Contingent consideration by subsidiary for acquisition | — | 375 | — | ||||||||
The Accompanying Notes are an Integral Part of These Statements.
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CONSOLIDATED STATEMENTS OF EQUITY AND REDEEMABLE NONCONTROLLING INTERESTS
| Avista Corporation |
For the Years Ended December 31
Dollars in thousands
| 2013 | 2012 | 2011 | |||||||||
| Common Stock, Shares: | |||||||||||
| Shares outstanding at beginning of year | 59,812,796 | 58,422,781 | 57,119,723 | ||||||||
| Issuance of common stock through equity compensation plans | 58,002 | 245,661 | 275,057 | ||||||||
| Issuance of common stock through Employee Investment Plan (401-K) | 42,073 | 45,715 | 43,179 | ||||||||
| Issuance of common stock through Dividend Reinvestment Plan | 163,881 | 167,448 | 177,822 | ||||||||
| Issuance of common stock | — | 931,191 | 807,000 | ||||||||
| Shares outstanding at end of year | 60,076,752 | 59,812,796 | 58,422,781 | ||||||||
| Common Stock, Amount: | |||||||||||
| Balance at beginning of year | $ | 889,237 | $ | 855,188 | $ | 827,592 | |||||
| Equity compensation expense | 6,002 | 5,716 | 3,635 | ||||||||
| Issuance of common stock through equity compensation plans | (878 | ) | 305 | 1,879 | |||||||
| Issuance of common stock through Employee Investment Plan (401-K) | 1,127 | 1,165 | 1,073 | ||||||||
| Issuance of common stock through Dividend Reinvestment Plan | 4,360 | 4,226 | 4,299 | ||||||||
| Issuance of common stock, net of issuance costs | — | 23,383 | 19,213 | ||||||||
| Equity transactions of consolidated subsidiaries | (2,855 | ) | (746 | ) | (2,503 | ) | |||||
| Balance at end of year | 896,993 | 889,237 | 855,188 | ||||||||
| Accumulated Other Comprehensive Loss: | |||||||||||
| Balance at beginning of year | (6,700 | ) | (5,637 | ) | (4,326 | ) | |||||
| Other comprehensive income (loss) | 881 | (1,063 | ) | (1,311 | ) | ||||||
| Balance at end of year | (5,819 | ) | (6,700 | ) | (5,637 | ) | |||||
| Retained Earnings: | |||||||||||
| Balance at beginning of year | 376,940 | 336,150 | 302,518 | ||||||||
| Net income attributable to Avista Corporation shareholders | 111,077 | 78,210 | 100,224 | ||||||||
| Cash dividends paid (common stock) | (73,276 | ) | (68,552 | ) | (63,737 | ) | |||||
| Expiration of subsidiary noncontrolling interests redemption rights | — | 23,805 | — | ||||||||
| Valuation adjustments and other noncontrolling interests activity | (7,649 | ) | 7,327 | (2,855 | ) | ||||||
| Balance at end of year | 407,092 | 376,940 | 336,150 | ||||||||
| Total Avista Corporation shareholders’ equity | 1,298,266 | 1,259,477 | 1,185,701 | ||||||||
| Noncontrolling Interests: | |||||||||||
| Balance at beginning of year | 17,658 | 174 | (600 | ) | |||||||
| Net income attributable to noncontrolling interests | 1,066 | 451 | 756 | ||||||||
| Deconsolidation of variable interest entity | — | (673 | ) | — | |||||||
| Issuance of subsidiary noncontrolling interests | 480 | — | — | ||||||||
| Purchase of subsidiary noncontrolling interests | (4,182 | ) | (117 | ) | — | ||||||
| Expiration of subsidiary noncontrolling interests redemption rights | — | 17,790 | — | ||||||||
| Other | 4,979 | 33 | 18 | ||||||||
| Balance at end of year | 20,001 | 17,658 | 174 | ||||||||
| Total equity | $ | 1,318,267 | $ | 1,277,135 | $ | 1,185,875 | |||||
| Redeemable Noncontrolling Interests: | |||||||||||
| Balance at beginning of year | $ | 4,938 | $ | 51,809 | $ | 46,722 | |||||
| Net income attributable to noncontrolling interests | 151 | 139 | 2,559 | ||||||||
| Issuance of subsidiary noncontrolling interests | — | 3,714 | — | ||||||||
| Purchase of subsidiary noncontrolling interests | (405 | ) | (784 | ) | (6,179 | ) | |||||
| Expiration of subsidiary noncontrolling interests redemption rights | — | (41,595 | ) | — | |||||||
| Valuation adjustments and other noncontrolling interests activity | 11,205 | (8,345 | ) | 8,707 | |||||||
| Balance at end of year | $ | 15,889 | $ | 4,938 | $ | 51,809 | |||||
The Accompanying Notes are an Integral Part of These Statements.
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| NOTES TO CONSOLIDATED FINANCIAL STATEMENTS |
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Business
Avista Corporation (Avista Corp. or the Company) is an energy company engaged in the generation, transmission and distribution of electricity and the distribution of natural gas, as well as other energy-related businesses. Avista Utilities is an operating division of Avista Corp., comprising the regulated utility operations. Avista Utilities provides electric distribution and transmission, as well as natural gas distribution, services in parts of eastern Washington and northern Idaho. Avista Utilities also provides natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Utilities has generating facilities in Washington, Idaho, Oregon and Montana. The Company also supplies electricity to a small number of customers in Montana, most of whom are employees who operate one of the Montana generating facilities. Avista Capital, Inc. (Avista Capital), a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility businesses, except Spokane Energy, LLC (Spokane Energy). Avista Capital’s subsidiaries include Ecova, Inc. (Ecova), a 80.2 percent owned subsidiary as of December 31, 2013. Ecova is a provider of energy efficiency and other facility information and cost management programs and services for multi-site customers and utilities throughout North America. See Note 23 for business segment information.
Basis of Reporting
The consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries, including Ecova and other majority owned subsidiaries and variable interest entities for which the Company or its subsidiaries are the primary beneficiaries. Intercompany balances were eliminated in consolidation. The accompanying consolidated financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants (see Note 6).
Use of Estimates
The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) requires management to make estimates and assumptions that affect amounts reported in the consolidated financial statements. Significant estimates include:
| • | determining the market value of energy commodity derivative assets and liabilities, |
| • | pension and other postretirement benefit plan obligations, |
| • | contingent liabilities, |
| • | goodwill impairment testing, |
| • | recoverability of regulatory assets, and |
| • | unbilled revenues. |
Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on the consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein.
System of Accounts
The accounting records of the Company’s utility operations are maintained in accordance with the uniform system of accounts prescribed by the Federal Energy Regulatory Commission (FERC) and adopted by the state regulatory commissions in Washington, Idaho, Montana and Oregon.
Regulation
The Company is subject to state regulation in Washington, Idaho, Montana and Oregon. The Company is also subject to federal regulation primarily by the FERC, as well as various other federal agencies with regulatory oversight of particular aspects of its operations.
Utility Revenues
Utility revenues related to the sale of energy are recorded when service is rendered or energy is delivered to customers. Revenues and resource costs from Avista Utilities’ settled energy contracts that are “booked out” (not physically delivered) are reported on a net basis as part of utility revenues. The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, the
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amount of energy delivered to customers since the date of the last meter reading is estimated and the corresponding unbilled revenue is estimated and recorded.
Accounts receivable includes unbilled energy revenues of the following amounts as of December 31 (dollars in thousands):
| 2013 | 2012 | ||||||
| Unbilled accounts receivable | $ | 81,059 | $ | 77,298 | |||
Ecova Revenues
Service revenues from Ecova are recognized over the period services are rendered, which is typically on a straight-line basis for fixed-fee or project-fee engagements or ratably for other types of services. New client account setup fees and implementation (onboarding) fees are deferred and recognized over the contractual life that approximates the expected customer relationship, which is typically the contract period. Investment earnings on funds held for clients and fees earned from third parties on payment processing are an integral part of Ecova’s product offerings and are recognized in revenues as earned. Revenue arrangements with multiple elements occur infrequently and generally represent a very small percentage of total Ecova revenues. When they occur, the separate deliverables are divided into separate units of accounting if certain criteria are met, and the total consideration received is allocated among the different deliverables using the relative selling price method. In most cases, management uses its best estimate of the selling price for each deliverable to determine the amount of consideration to allocate and revenue is recognized for each deliverable once all the applicable revenue recognition criteria are met.
Other Non-Utility Revenues
Revenues from the other businesses are primarily derived from the operations of Advanced Manufacturing and Development (doing business as METALfx) and are recognized when the risk of loss transfers to the customer, which occurs when products are shipped.
Advertising Expenses
The Company expenses advertising costs as incurred. Advertising expenses were not a material portion of the Company’s operating expenses in 2013, 2012 and 2011.
Depreciation
For utility operations, depreciation expense is estimated by a method of depreciation accounting utilizing composite rates for utility plant. Such rates are designed to provide for retirements of properties at the expiration of their service lives. For utility operations, the ratio of depreciation provisions to average depreciable property was as follows for the years ended December 31:
| 2013 | 2012 | 2011 | ||||||
| Ratio of depreciation to average depreciable property | 2.90 | % | 2.92 | % | 2.92 | % | ||
The average service lives for the following broad categories of utility plant in service are:
| • | electric thermal production - 41 years, |
| • | hydroelectric production - 79 years, |
| • | electric transmission - 56 years, |
| • | electric distribution - 36 years, and |
| • | natural gas distribution property - 48 years. |
Taxes Other Than Income Taxes
Taxes other than income taxes include state excise taxes, city occupational and franchise taxes, real and personal property taxes and certain other taxes not based on net income. These taxes are generally based on revenues or the value of property. Utility related taxes collected from customers (primarily state excise taxes and city utility taxes) are recorded as operating revenue and expense and totaled the following amounts for the years ended December 31 (dollars in thousands):
| 2013 | 2012 | 2011 | |||||||||
| Utility taxes | $ | 55,565 | $ | 53,716 | $ | 55,739 | |||||
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Allowance for Funds Used During Construction
The Allowance for Funds Used During Construction (AFUDC) represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. As prescribed by regulatory authorities, AFUDC is capitalized as a part of the cost of utility plant and the debt related portion is credited against total interest expense in the Consolidated Statements of Income in the line item “capitalized interest.” The equity related portion of AFUDC is included in the Consolidated Statement of Income in the line item “other income-net.” The Company is permitted, under established regulatory rate practices, to recover the capitalized AFUDC, and a reasonable return thereon, through its inclusion in rate base and the provision for depreciation after the related utility plant is placed in service. Cash inflow related to AFUDC does not occur until the related utility plant is placed in service and included in rate base. The effective AFUDC rate was the following for the years ended December 31:
| 2013 | 2012 | 2011 | ||||||
| Effective AFUDC rate | 7.64 | % | 7.62 | % | 7.91 | % | ||
Income Taxes
A deferred income tax asset or liability is determined based on the enacted tax rates that will be in effect when the differences between the financial statement carrying amounts and tax basis of existing assets and liabilities are expected to be reported in the Company’s consolidated income tax returns. The deferred income tax expense for the period is equal to the net change in the deferred income tax asset and liability accounts from the beginning to the end of the period. The effect on deferred income taxes from a change in tax rates is recognized in income in the period that includes the enactment date. Deferred income tax liabilities and regulatory assets are established for income tax benefits flowed through to customers as prescribed by the respective regulatory commissions.
Stock-Based Compensation
Compensation cost relating to share-based payment transactions is recognized in the Company’s financial statements based on the fair value of the equity or liability instruments issued and recorded over the requisite service period. See Note 19 for further information.
Other Income - Net
Other Income - net consisted of the following items for the years ended December 31 (dollars in thousands):
| 2013 | 2012 | 2011 | |||||||||
| Interest income | $ | (754 | ) | $ | (944 | ) | $ | (1,327 | ) | ||
| Interest on regulatory deferrals | (126 | ) | (68 | ) | (89 | ) | |||||
| Equity-related AFUDC | (6,066 | ) | (4,055 | ) | (2,225 | ) | |||||
| Net loss on investments | 3,378 | 3,343 | 488 | ||||||||
| Other income | (3,109 | ) | (3,301 | ) | (280 | ) | |||||
| Total | $ | (6,677 | ) | $ | (5,025 | ) | $ | (3,433 | ) | ||
Earnings per Common Share Attributable to Avista Corporation Shareholders
Basic earnings per common share attributable to Avista Corporation shareholders is computed by dividing net income attributable to Avista Corporation shareholders by the weighted average number of common shares outstanding for the period. Diluted earnings per common share attributable to Avista Corporation shareholders is calculated by dividing net income attributable to Avista Corporation shareholders (adjusted for the effect of potentially dilutive securities issued by subsidiaries) by diluted weighted average common shares outstanding during the period, including common stock equivalent shares outstanding using the treasury stock method, unless such shares are anti-dilutive. Common stock equivalent shares include shares issuable upon exercise of stock options and contingent stock awards. See Note 18 for earnings per common share calculations.
Cash and Cash Equivalents
For the purposes of the Consolidated Statements of Cash Flows, the Company considers all temporary investments with a maturity of three months or less when purchased to be cash equivalents.
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Allowance for Doubtful Accounts
The Company maintains an allowance for doubtful accounts to provide for estimated and potential losses on accounts receivable. The Company determines the allowance for utility and other customer accounts receivable based on historical write-offs as compared to accounts receivable and operating revenues. Additionally, the Company establishes specific allowances for certain individual accounts. The following table presents the activity in the allowance for doubtful accounts during the years ended December 31 (dollars in thousands):
| 2013 | 2012 | 2011 | |||||||||
| Allowance as of the beginning of the year | $ | 44,155 | $ | 43,958 | $ | 44,883 | |||||
| Additions expensed during the year | 5,099 | 4,213 | 5,232 | ||||||||
| Net deductions | (4,945 | ) | (4,016 | ) | (6,157 | ) | |||||
| Allowance as of the end of the year | $ | 44,309 | $ | 44,155 | $ | 43,958 | |||||
Materials and Supplies, Fuel Stock and Natural Gas Stored
Inventories of materials and supplies, fuel stock and natural gas stored are recorded at average cost for our regulated operations and the lower of cost or market for our non-regulated operations and consisted of the following as of December 31 (dollars in thousands):
| 2013 | 2012 | ||||||
| Materials and supplies | $ | 28,747 | $ | 26,058 | |||
| Fuel stock | 3,170 | 4,121 | |||||
| Natural gas stored | 13,029 | 17,276 | |||||
| Total | $ | 44,946 | $ | 47,455 | |||
Investments and Funds Held for Clients and Client Fund Obligations
In connection with the bill paying services, Ecova collects funds from its clients and remits the funds to the appropriate utility or other service provider. Some of the funds collected are invested by Ecova and classified as investments and funds held for clients, and a related liability for client fund obligations is recorded. Investments and funds held for clients include cash and cash equivalent investments, money market funds and investment securities classified as available for sale. Ecova does not invest the funds directly for the clients' benefit; therefore, Ecova bears the risk of loss associated with the investments. Investments and funds held for clients as of December 31, 2013 are as follows (dollars in thousands):
Amortized Cost (1) | Unrealized Gain (Loss) | Fair Value | |||||||||
| Cash and cash equivalents | $ | 16,147 | $ | — | $ | 16,147 | |||||
| Money market funds | 11,180 | — | 11,180 | ||||||||
| Securities available for sale: | |||||||||||
| U.S. government agency | 63,633 | (2,555 | ) | 61,078 | |||||||
| Municipal | 3,497 | 21 | 3,518 | ||||||||
| Corporate fixed income – financial | 3,000 | — | 3,000 | ||||||||
| Corporate fixed income – industrial | 753 | 12 | 765 | ||||||||
| Certificates of deposit | 1,000 | — | 1,000 | ||||||||
| Total securities available for sale | 71,883 | (2,522 | ) | 69,361 | |||||||
| Total investments and funds held for clients | $ | 99,210 | $ | (2,522 | ) | $ | 96,688 | ||||
(1) Amortized cost represents the original purchase price of the investments, plus or minus any amortized purchase premiums or accreted purchase discounts.
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Investments and funds held for clients as of December 31, 2012 are as follows (dollars in thousands):
Amortized Cost | Unrealized Gain (Loss) | Fair Value | |||||||||
| Cash and cash equivalents | $ | 13,867 | $ | — | $ | 13,867 | |||||
| Money market funds | 15,084 | — | 15,084 | ||||||||
| Securities available for sale: | |||||||||||
| U.S. government agency | 48,340 | 156 | 48,496 | ||||||||
| Municipal | 820 | 28 | 848 | ||||||||
| Corporate fixed income – financial | 5,010 | 16 | 5,026 | ||||||||
| Corporate fixed income – industrial | 3,887 | 49 | 3,936 | ||||||||
| Certificates of deposit | 1,000 | 15 | 1,015 | ||||||||
| Total securities available for sale | 59,057 | 264 | 59,321 | ||||||||
| Total investments and funds held for clients | $ | 88,008 | $ | 264 | $ | 88,272 | |||||
Investments and funds held for clients are classified as a current asset since these funds are held for the purpose of satisfying the client fund obligations. As of December 31, 2013 and 2012 approximately 95 percent and 97 percent of the investment portfolio, respectively, was rated AA-, Aa3 and higher by nationally recognized statistical rating organizations. All fixed income securities were rated as investment grade as of December 31, 2013 and 2012.
Ecova management reviews its investments continuously for indicators of other-than-temporary impairment. To make this determination, management employs a methodology that considers available quantitative and qualitative evidence in evaluating potential impairment of its investments. If the cost of an investment exceeds its fair value, management evaluates, among other factors, general market conditions, credit quality of instrument issuers, the length of time and extent to which the fair value is less than cost, and whether it has plans to sell the security or it is more-likely-than not that the Company will be required to sell the security before recovery. Management also considers specific adverse conditions related to the financial health of and specific prospects for the issuer as well as other cash flow factors. Once a decline in fair value is determined to be other-than-temporary, an impairment charge is recorded in earnings and a new cost basis in the investment is established. Based on management’s analysis, securities available for sale do not meet the criteria for other-than-temporary impairment as of December 31, 2013.
The following is a summary of the disposition of available-for-sale securities during the years ended December 31 (dollars in thousands):
| 2013 | 2012 | ||||||
| Proceeds from sales, maturities and calls | $ | 22,960 | $ | 137,999 | |||
| Gross realized gains | 19 | 461 | |||||
| Gross realized losses | — | — | |||||
Contractual maturities of securities available for sale as of December 31, 2013 and 2012 are as follows (dollars in thousands):
| Due within 1 year | After 1 but within 5 years | After 5 but within 10 years | After 10 years | Total | |||||||||||||||
| December 31, 2013 | $ | 5,382 | $ | 12,745 | $ | 48,310 | $ | 2,924 | $ | 69,361 | |||||||||
| December 31, 2012 | 3,047 | 11,786 | 41,485 | 3,003 | 59,321 | ||||||||||||||
Actual maturities may differ due to call or prepayment rights and the effective maturity was 3.0 years as of December 31, 2013 and 1.9 years as of December 31, 2012.
Utility Plant in Service
The cost of additions to utility plant in service, including an allowance for funds used during construction and replacements of units of property and improvements, is capitalized. The cost of depreciable units of property retired plus the cost of removal less salvage is charged to accumulated depreciation.
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Asset Retirement Obligations
The Company recovers certain asset retirement costs through rates charged to customers as a portion of its depreciation expense for which the Company has not recorded asset retirement obligations (see Note 8). The Company has estimated retirement costs (that do not represent legal or contractual obligations) included as a regulatory liability on the Consolidated Balance Sheets of the following amounts as of December 31 (dollars in thousands):
| 2013 | 2012 | ||||||
| Regulatory liability for utility plant retirement costs | $ | 242,850 | $ | 234,128 | |||
Goodwill
Goodwill arising from acquisitions represents the excess of the purchase price over the estimated fair value of net assets acquired. The Company evaluates goodwill for impairment using a combination of discounted cash flow models and a market approach on at least an annual basis or more frequently if impairment indicators arise. The Company completed its annual evaluation of goodwill for potential impairment as of December 31, 2013 for Ecova and as of November 30, 2013 for the other businesses and determined that goodwill was not impaired at that time.
The changes in the carrying amount of goodwill are as follows (dollars in thousands):
| Ecova | Other | Accumulated Impairment Losses | Total | ||||||||||||
| Balance as of January 1, 2012 | $ | 33,799 | $ | 12,979 | $ | (7,733 | ) | $ | 39,045 | ||||||
| Goodwill acquired during the year | 33,484 | — | — | 33,484 | |||||||||||
| Adjustments | 3,430 | — | — | 3,430 | |||||||||||
| Balance as of the December 31, 2012 | 70,713 | 12,979 | (7,733 | ) | 75,959 | ||||||||||
| Adjustments | 298 | — | — | 298 | |||||||||||
| Balance as of the December 31, 2013 | $ | 71,011 | $ | 12,979 | $ | (7,733 | ) | $ | 76,257 | ||||||
The goodwill acquired in 2012 was related to Ecova's acquisition of LPB Energy Management (LPB) effective January 31, 2012. The adjustment to goodwill in 2012 represents purchase accounting adjustments for Ecova's acquisition of Prenova, Inc. in 2011 based upon final review of the fair market values of relevant assets and liabilities identified as of the acquisition date. The primary cause of the revisions was due to a net operating loss study and a change in the value of customer relationships. The adjustment to goodwill in 2013 represents a purchase accounting adjustment for Ecova's acquisition of LPB based upon final review of the fair market value of the noncontrolling interests associated with a portion of the LPB business and based on review of the fair market value of the client relationship intangible asset. The 2013 adjustment also includes a purchase accounting adjustment for Prenova, Inc. associated with the calculation of deferred tax assets.
Intangible Assets
Amortization expense related to Intangible Assets was as follows for the years ended December 31 (dollars in thousands):
| 2013 | 2012 | 2011 | |||||||||
| Intangible asset amortization | $ | 11,828 | $ | 10,435 | $ | 4,682 | |||||
The following table details the estimated amortization expense for the next five years related to Intangible Assets (dollars in thousands):
| 2014 | 2015 | 2016 | 2017 | 2018 | |||||||||||||||
| Estimated amortization expense | $ | 10,677 | $ | 8,720 | $ | 7,599 | $ | 6,795 | $ | 2,758 | |||||||||
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The gross carrying amount and accumulated amortization of Intangible Assets as of December 31, 2013 and 2012 are as follows (dollars in thousands):
Estimated Useful Lives | 2013 | 2012 | |||||||
| Client relationships | 2 - 12 years | $ | 33,562 | $ | 32,059 | ||||
| Software development costs | 3 - 7 years | 39,327 | 33,990 | ||||||
| Other | 1 - 10 years | 3,321 | 6,237 | ||||||
| Total intangible assets | 76,210 | 72,286 | |||||||
| Client relationships accumulated amortization | (12,336 | ) | (7,793 | ) | |||||
| Software development costs accumulated amortization | (21,861 | ) | (16,557 | ) | |||||
| Other accumulated amortization | (2,437 | ) | (1,680 | ) | |||||
| Total accumulated amortization | (36,634 | ) | (26,030 | ) | |||||
| Total intangible assets - net | $ | 39,576 | $ | 46,256 | |||||
As of December 31, 2013 and December 31, 2012, all of the intangible assets reported above are associated with Ecova.
Derivative Assets and Liabilities
Derivatives are recorded as either assets or liabilities on the Consolidated Balance Sheets measured at estimated fair value. In certain defined conditions, a derivative may be specifically designated as a hedge for a particular exposure. The accounting for derivatives depends on the intended use of the derivatives and the resulting designation.
The Washington Utilities and Transportation Commission (UTC) and the Idaho Public Utilities Commission (IPUC) issued accounting orders authorizing Avista Utilities to offset commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of delivery. The orders provide for Avista Utilities to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Consolidated Statements of Income. Realized gains or losses are recognized in the period of delivery, subject to approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in adjustments to retail rates through purchased gas cost adjustments, the Energy Recovery Mechanism (ERM) in Washington, the Power Cost Adjustment (PCA) mechanism in Idaho, and periodic general rates cases. Regulatory assets are assessed regularly and are probable for recovery through future rates.
Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are accounted for on the accrual basis until they are settled or realized, unless there is a decline in the fair value of the contract that is determined to be other than temporary.
Fair Value Measurements
Fair value represents the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, investments and funds held for clients, deferred compensation assets, as well as derivatives related to interest rate swap agreements and foreign currency exchange contracts, are reported at estimated fair value on the Consolidated Balance Sheets. See Note 16 for the Company’s fair value disclosures.
Regulatory Deferred Charges and Credits
The Company prepares its consolidated financial statements in accordance with regulatory accounting practices because:
| • | rates for regulated services are established by or subject to approval by independent third-party regulators, |
| • | the regulated rates are designed to recover the cost of providing the regulated services, and |
| • | in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates can be charged to and collected from customers at levels that will recover costs. |
Regulatory accounting practices require that certain costs and/or obligations (such as incurred power and natural gas costs not currently included in rates, but expected to be recovered or refunded in the future) are reflected as deferred charges or credits on the Consolidated Balance Sheets. These costs and/or obligations are not reflected in the Consolidated Statements of Income until the period during which matching revenues are recognized. If at some point in the future the Company determines that it
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no longer meets the criteria for continued application of regulatory accounting practices for all or a portion of its regulated operations, the Company could be:
| • | required to write off its regulatory assets, and |
| • | precluded from the future deferral of costs not recovered through rates at the time such costs are incurred, even if the Company expected to recover such costs in the future. |
See Note 22 for further details of regulatory assets and liabilities.
Investment in Exchange Power-Net
The investment in exchange power represents the Company’s previous investment in Washington Public Power Supply System Project 3 (WNP-3), a nuclear project that was terminated prior to completion. Under a settlement agreement with the Bonneville Power Administration in 1985, Avista Utilities began receiving power in 1987, for a 32.5-year period, related to its investment in WNP-3. Through a settlement agreement with the UTC in the Washington jurisdiction, Avista Utilities is amortizing the recoverable portion of its investment in WNP-3 (recorded as investment in exchange power) over a 32.5-year period that began in 1987. For the Idaho jurisdiction, Avista Utilities fully amortized the recoverable portion of its investment in exchange power.
Unamortized Debt Expense
Unamortized debt expense includes debt issuance costs that are amortized over the life of the related debt.
Unamortized Debt Repurchase Costs
For the Company’s Washington regulatory jurisdiction and for any debt repurchases beginning in 2007 in all jurisdictions, premiums paid to repurchase debt are amortized over the remaining life of the original debt that was repurchased or, if new debt is issued in connection with the repurchase, these costs are amortized over the life of the new debt. In the Company’s other regulatory jurisdictions, premiums paid to repurchase debt prior to 2007 are being amortized over the average remaining maturity of outstanding debt when no new debt was issued in connection with the debt repurchase. These costs are recovered through retail rates as a component of interest expense.
Redeemable Noncontrolling Interests
Certain option holders of Ecova have the right to put their shares back to Ecova at their discretion during an annual put window. Stock options and other outstanding redeemable stock are valued at their maximum redemption amount which is equal to their intrinsic value (fair value less exercise price) (see Note 19 for further information).
Accumulated Other Comprehensive Loss
Accumulated other comprehensive loss, net of tax, consisted of the following as of December 31 (dollars in thousands):
| 2013 | 2012 | ||||||
| Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $(2,280) and $(3,698), respectively | $ | (4,233 | ) | $ | (6,867 | ) | |
| Unrealized gain (loss) on securities available for sale - net of taxes of $(936) and $97, respectively | (1,586 | ) | 167 | ||||
| Total accumulated other comprehensive loss | $ | (5,819 | ) | $ | (6,700 | ) | |
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The following table details the reclassifications out of accumulated other comprehensive loss by component for the year ended December 31, 2013 (dollars in thousands):
| Details about Accumulated Other Comprehensive Loss Components | Amounts Reclassified from Accumulated Other Comprehensive Loss | Affected Line Item in Statement of Income | ||||
| Realized gains on investment securities | $ | 19 | Other income-net | |||
| 19 | Total before tax | |||||
| (7 | ) | Tax expense | ||||
| $ | 12 | Net of tax | ||||
| Amortization of defined benefit pension items | ||||||
| Amortization of net prior service cost | $ | (10,681 | ) | (a) | ||
| Amortization of net loss | (142,794 | ) | (a) | |||
| Adjustment due to effects of regulation | 149,423 | (a) | ||||
| (4,052 | ) | Total before tax | ||||
| 1,418 | Tax benefit | |||||
| $ | (2,634 | ) | Net of tax | |||
| (a) | These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 9 for additional details). |
Appropriated Retained Earnings
In accordance with the hydroelectric licensing requirements of section 10(d) of the Federal Power Act (FPA), the Company maintains an appropriated retained earnings account for any earnings in excess of the specified rate of return on the Company's investment in the licenses for its various hydro projects. The rate of return on investment is specified in the various hydroelectric licensing agreements for the Clark Fork River and Spokane River. Per section 10(d) of the FPA, the Company must maintain these excess earnings in an appropriated retained earnings account until the termination of the licensing agreements or apply them to reduce the net investment in the licenses of the hydroelectric projects at the discretion of the FERC. The appropriated retained earnings amounts included in retained earnings were as follows as of December 31 (dollars in thousands):
| 2013 | 2012 | ||||||
| Appropriated retained earnings | $ | 9,714 | $ | 1,548 | |||
Contingencies
The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss contingency if it is probable that a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. The Company also discloses losses that do not meet these conditions for accrual, if there is a reasonable possibility that a loss may be incurred.
Voluntary Severance Incentive Program
At December 31, 2012, the Company accrued total severance costs of $7.3 million (pre-tax) related to the voluntary termination of 55 employees. The total severance costs were made up of the severance payments and the related payroll taxes and employee benefit costs. All terminations under the voluntary severance incentive program were completed by December 31, 2012. The cost of the program was recognized as expense during the fourth quarter of 2012 and severance pay was distributed in a single lump sum cash payment to each participant during January 2013. As of December 31, 2013, there was no remaining liability accrued.
NOTE 2. NEW ACCOUNTING STANDARDS
In February 2013, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2013-02, “Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.” This ASU does not change current requirements for reporting net income or other comprehensive income in financial statements; however, it requires entities to disclose the effect on the line items of net income for reclassifications out of
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accumulated other comprehensive income if the item being reclassified is required to be reclassified in its entirety to net income under U.S. GAAP. For other items that are not required to be reclassified in their entirety to net income under U.S. GAAP, an entity is required to cross-reference other disclosures required under U.S. GAAP to provide additional detail about those items. The Company adopted this ASU effective January 1, 2013. The adoption of this ASU required additional disclosures in the Company's financial statements; however, it did not have any impact on the Company's financial condition, results of operations and cash flows.
In December 2011, the FASB issued ASU No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.” This ASU enhances disclosure requirements about the nature of an entity's right to offset and related arrangements associated with its financial instruments and derivative instruments. ASU No. 2011-11 requires the disclosure of the gross amounts subject to rights of set off, amounts offset in accordance with the accounting standards followed, and the related net exposure. The Company adopted this ASU effective January 1, 2013. The adoption of this ASU required additional disclosures in the Company's financial statements; however, it did not have any impact on the Company's financial condition, results of operations and cash flows.
In January 2013, the FASB issued ASU No. 2013-01, “Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” This ASU clarifies which instruments and transactions are subject to the enhanced disclosure requirements of ASU 2011-11 regarding the offsetting of financial assets and liabilities. ASU No. 2013-01 limits the scope of ASU No. 2011-11 to only recognized derivative instruments, repurchase agreements and reverse repurchase agreements, and borrowing and lending securities transactions that are offset in accordance with either Accounting Standards Codification (ASC) 210-20-45 or ASC 815-10-45. The Company adopted this ASU effective January 1, 2013. The adoption of this ASU did not have any impact on the Company's financial condition, results of operations and cash flows.
NOTE 3. VARIABLE INTEREST ENTITIES
Lancaster Power Purchase Agreement
The Company has a power purchase agreement (PPA) for the purchase of all the output of the Lancaster Plant, a 270 MW natural gas-fired combined cycle combustion turbine plant located in Idaho, owned by an unrelated third-party (Rathdrum Power LLC), through 2026.
Avista Corp. has a variable interest in the PPA. Accordingly, Avista Corp. made an evaluation of which interest holders have the power to direct the activities that most significantly impact the economic performance of the entity and which interest holders have the obligation to absorb losses or receive benefits that could be significant to the entity. Avista Corp. pays a fixed capacity and operations and maintenance payment and certain monthly variable costs under the PPA. Under the terms of the PPA, Avista Corp. makes the dispatch decisions, provides all natural gas fuel and receives all of the electric energy output from the Lancaster Plant. However, Rathdrum Power LLC (the owner) controls the daily operation of the Lancaster Plant and makes operating and maintenance decisions. Rathdrum Power LLC controls all of the rights and obligations of the Lancaster Plant after the expiration of the PPA in 2026. It is estimated that the plant will have 15 to 25 years of useful life after that time. Rathdrum Power LLC bears the maintenance risk of the plant and will receive the residual value of the Lancaster Plant. Avista Corp. has no debt or equity investments in the Lancaster Plant and does not provide financial support through liquidity arrangements or other commitments (other than the PPA). Based on its analysis, Avista Corp. does not consider itself to be the primary beneficiary of the Lancaster Plant. Accordingly, neither the Lancaster Plant nor Rathdrum Power LLC is included in Avista Corp.’s consolidated financial statements. The Company has a future contractual obligation of approximately $298 million under the PPA (representing the fixed capacity and operations and maintenance payments through 2026) and believes this would be its maximum exposure to loss. However, the Company believes that such costs will be recovered through retail rates.
Palouse Wind Power Purchase Agreement
In June 2011, the Company entered into a 30-year PPA with Palouse Wind, LLC (Palouse Wind), an affiliate of First Wind Holdings, LLC. The PPA relates to a wind project that was developed by Palouse Wind in Whitman County, Washington and under the terms of PPA, the Company acquires all of the power and renewable attributes produced by the wind project for a fixed price per MWh, which escalates annually, without consideration for market fluctuations. The wind project has a nameplate capacity of approximately 105 MW and is expected to produce approximately 40 MW annually. The project was completed and energy deliveries began during the fourth quarter of 2012. Under the PPA, the Company has an annual option to purchase the wind project following the 10th anniversary of the commercial operation date at a fixed price determined under the contract.
The Company evaluated this agreement to determine if it has a variable interest which must be consolidated. Based on its analysis, Avista Corp. does not consider itself to be the primary beneficiary of the Palouse Wind facility due to the fact that it
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pays a fixed price per MWh, which represents the only financial obligation, and does not have any input into the management of the day-to-day operations of the facility. Accordingly, Palouse Wind is not included in Avista Corp.’s consolidated financial statements. The Company has a future contractual obligation of approximately $604 million under the PPA (representing the charges associated with purchasing the energy and renewable attributes through 2042) and believes this would be its maximum exposure to loss. However, the Company believes that such costs will be recovered through retail rates.
NOTE 4. BUSINESS ACQUISITIONS
Alaska Energy and Resources Company - Avista Corporation
On November 4, 2013, the Company entered into an agreement and plan of merger (Merger Agreement) with AERC, a privately-held company based in Juneau, Alaska. When the transaction is completed, AERC will become a wholly-owned subsidiary of Avista Corp.
The primary subsidiary of AERC is AEL&P, the sole provider of electric services to approximately 16,000 customers in the City and Borough of Juneau, Alaska. In 2012, AEL&P had annual revenues of $42 million, a total rate base of $111 million and had 60 full-time employees. The utility has a firm retail peak load of approximately 80 MW. AEL&P owns four hydroelectric generating facilities, having a total present capacity of 24.7 MW, and has a power purchase commitment for the output of the Snettisham hydroelectric project, having a present capacity of 78 MW, for a total hydroelectric capacity of 102.7 MW. AEL&P is not interconnected to any other electric system; therefore, the utility has 93.9 MW of diesel generating present capacity to provide back-up service to firm customers when necessary.
In addition to the regulated utility, AERC owns the AJT Mining subsidiary, which is an inactive mining company holding certain mining properties.
The merger consideration at closing will be $170 million, less AERC's indebtedness and is subject to other customary closing adjustments (Merger Consideration). The transaction will be funded primarily through the issuance of Avista Corp. common stock to the shareholders of AERC. The transaction is expected to close by July 1, 2014, following the receipt of necessary regulatory approvals, the approval of the merger transaction by the requisite number of AERC shareholders and the satisfaction of other closing conditions. Avista Corp. shareholder approval is not required.
Pursuant to the Merger Agreement, among other things, each of the issued and outstanding shares of AERC common stock (other than Dissenting Shares) will be converted into the right to receive consideration as follows:
| i. | the number of shares of Avista Corp. common stock equal to one share of AERC common stock multiplied by the Exchange Ratio; and |
| ii. | a portion of the Representative Reimbursement Amount. |
For purposes of the foregoing:
The Exchange Ratio is the ratio obtained by dividing the Per Share Amount by (i) $21.48 if the Avista Corp. Closing Price is less than or equal to $21.48, (ii) the Avista Corp. Closing Price, if the Avista Corp. Closing Price is greater than $21.48 and less than $34.30 or (iii) $34.30 if the Avista Corp. Closing Price is greater than or equal to $34.30.
The Per Share Amount is the amount determined by dividing (a) the Merger Consideration (as adjusted) by (b) the aggregate number of shares of AERC common stock outstanding immediately prior to the closing of the transaction.
The Representative Reimbursement Amount is a $500,000 cash payment to be made by Avista Corp. at the Closing to the Shareholders’ Representative account. The purpose of the Representative Reimbursement Amount is to reimburse the Shareholders’ Representative for expenses incurred by the Shareholders’ Representative in acting for the current shareholders of AERC in connection with the Merger. The total Merger Consideration will be reduced by the Representative Reimbursement Amount.
Dissenting Shares will not be converted into, or represent the right to receive, the Merger Consideration or any portion of the Representative Reimbursement Amount. Such shareholders will be entitled to receive payment of the fair value of Dissenting Shares held by them in accordance with the provisions of AS 10.06.580 of the Alaska Corporations Code. Any amounts paid to Dissenting Shares over the amounts otherwise payable in the form of Merger Consideration are indemnified expenses owed by AERC to Avista Corp.
The Merger Agreement has been approved by Avista Corp.'s and AERC's Boards of Directors, the UTC, the U.S. Federal Trade Commission and the Antitrust Division of the U.S. Department of Justice, but the consummation of the transaction is subject to the satisfaction or waiver of specified closing conditions, including:
| • | the registration under the Securities Act of 1933 of the shares of common stock that will be issued to AERC shareholders; |
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| • | the approval of such shares for listing on the New York Stock Exchange; |
| • | the approval of the merger transaction by the requisite number of AERC shareholders; |
| • | the receipt of regulatory approvals and other consents required to consummate the merger transaction, including, among others, approvals from the RCA, the IPUC, the OPUC and any other applicable regulatory bodies on the terms and conditions specified in the definitive purchase agreement; |
| • | the absence of the occurrence of a material adverse effect (as defined in the Merger Agreement) relating to either AERC or Avista Corp. after the date of the signed agreement; and |
| • | other customary closing conditions. |
The Merger Agreement also provides for customary termination rights for each of the Company and AERC, including the right for either party to terminate if the Merger has not been consummated by December 31, 2014 provided, however, that the failure of the Merger to have been consummated on or before December 31, 2014 was not caused by the failure of such party or any affiliate of such party to perform any of its obligations under the Merger Agreement. Upon termination of the Merger Agreement in accordance with its terms, there will be no further liability under the agreement except that nothing shall relieve any party thereto from liability for any breach of the agreement.
There may be certain commitments and contingencies that will be assumed when the merger transaction is consummated; however, Avista Corp. has not fully completed its evaluation of all the potential commitments and contingencies as of the date of this filing.
For the year ended December 31, 2013, Avista Corp. incurred $1.6 million (pre-tax) of transaction related fees which have been expensed and presented in the Consolidated Statements of Income in other operating expenses within utility operating expenses. Avista Corp. expects to incur additional transaction related fees upon consummation of the transaction.
Prenova and LPB Energy Management (LPB) - Subsidiary Acquisitions
On November 30, 2011, Ecova acquired all of the capital stock of Prenova, Inc. (Prenova), an Atlanta-based energy management company. The cash paid for the acquisition of Prenova of $35.7 million was funded primarily through borrowings under Ecova’s committed credit agreement. The acquired assets and assumed liabilities of Prenova were recorded at their respective estimated fair values as of the date of acquisition. These intangible assets are included in intangible assets on the Consolidated Balance Sheets. The results of operations of Prenova are included in the consolidated financial statements beginning December 1, 2011.
On January 31, 2012, Ecova acquired all of the capital stock of LPB Energy Management (LPB), a Dallas, Texas-based energy management company. The cash paid for the acquisition of LPB of $50.6 million was funded by Ecova through $25.0 million of borrowings under its committed credit agreement, a $20.0 million equity infusion from existing shareholders (including Avista Capital and the other owners of Ecova), and available cash. The acquired assets and assumed liabilities of LPB were recorded at their respective estimated fair values as of the date of acquisition. The results of operations of LPB are included in the consolidated financial statements beginning February 1, 2012.
At the time of the LPB acquisition, the Company recorded a contingent liability of $0.4 million related to additional purchase price payments the sellers had the potential to receive of $0.5 million in 2012, $1.0 million in 2013 and $1.5 million in 2014. The sellers of LPB did not receive the additional purchase price payments in 2012 and 2013. The sellers still have the potential to receive additional purchase price payments in the amount of $1.5 million in 2014; however, based on management's assessment of the probability that the revenue thresholds will be achieved, there is no contingent liability recorded as of December 31, 2013. There was an estimated contingent liability of $0.3 million recorded as of December 31, 2012 associated with these additional purchase price payments.
Pro forma disclosures reflecting the effects of Ecova’s acquisitions are not presented, as the acquisitions are not material to Avista Corp.’s consolidated financial condition or results of operations.
NOTE 5. DERIVATIVES AND RISK MANAGEMENT
Energy Commodity Derivatives
Avista Utilities is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices. Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Avista Utilities utilizes derivative instruments, such as forwards, futures, swaps and options in order to manage the various risks relating to these commodity price exposures. The Company has an energy resources risk policy and control procedures to manage these risks. The Company’s Risk Management Committee establishes the Company’s energy resources
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risk policy and monitors compliance. The Risk Management Committee is comprised of certain Company officers and other members of management. The Audit Committee of the Company’s Board of Directors periodically reviews and discusses enterprise risk management processes, and it focuses on the Company’s material financial and accounting risk exposures and the steps management has undertaken to control them.
As part of our resource procurement and management operations in the electric business, the Company engages in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve the Company's load obligations and the use of these resources to capture available economic value. The Company transacts in wholesale markets by selling and purchasing electric capacity and energy, fuel for electric generation, and contracts related to capacity, energy and fuel. Such transactions are part of the process of matching resources with load obligations and hedging the related financial risks. These transactions range from terms of intra-hour up to multiple years.
Avista Utilities makes continuing projections of:
| • | electric loads at various points in time (ranging from intra-hour to multiple years) based on, among other things, estimates of customer usage and weather, historical data and contract terms, and |
| • | resource availability at these points in time based on, among other things, fuel choices and fuel markets, estimates of streamflows, availability of generating units, historic and forward market information, contract terms, and experience. |
On the basis of these projections, we make purchases and sales of electric capacity and energy, fuel for electric generation, and related derivative instruments to match expected resources to expected electric load requirements and reduce our exposure to electricity (or fuel) market price changes. Resource optimization involves generating plant dispatch and scheduling available resources and also includes transactions such as:
| • | purchasing fuel for generation, |
| • | when economical, selling fuel and substituting wholesale electric purchases, and |
| • | other wholesale transactions to capture the value of generation and transmission resources and fuel delivery capacity contracts. |
Avista Utilities’ optimization process includes entering into hedging transactions to manage risks. Transactions include both physical energy contracts and related derivative financial instruments.
As part of its resource procurement and management of its natural gas business, Avista Utilities makes continuing projections of its natural gas loads and assesses available natural gas resources including natural gas storage availability. Natural gas resource planning typically includes peak requirements, low and average monthly requirements and delivery constraints from natural gas supply locations to Avista Utilities’ distribution system. However, daily variations in natural gas demand can be significantly different than monthly demand projections. On the basis of these projections, Avista Utilities plans and executes a series of transactions to hedge a significant portion of its projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend as much as four natural gas operating years (November through October) into the future. Avista Utilities also leaves a significant portion of its natural gas supply requirements unhedged for purchase in short-term and spot markets.
Natural gas resource optimization activities include:
| • | wholesale market sales of surplus natural gas supplies, |
| • | optimization of interstate pipeline transportation capacity not needed to serve daily load, and |
| • | purchases and sales of natural gas to optimize use of storage capacity. |
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The following table presents the underlying energy commodity derivative volumes as of December 31, 2013 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):
| 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 | |||||||||||||||
| 2014 | 769 | 2,156 | 29,642 | 145,719 | 509 | 3,116 | 3,504 | 105,433 | |||||||||||||||
| 2015 | 397 | 1,043 | 4,973 | 73,580 | 222 | 2,542 | — | 46,840 | |||||||||||||||
| 2016 | 397 | — | 2,505 | 46,150 | 287 | 1,634 | — | 21,320 | |||||||||||||||
| 2017 | 397 | — | 675 | — | 286 | — | — | — | |||||||||||||||
| 2018 | 397 | — | — | — | 286 | — | — | — | |||||||||||||||
| Thereafter | 235 | — | — | — | 158 | — | — | — | |||||||||||||||
| (1) | Physical transactions represent commodity transactions where Avista Utilities will take delivery of either electricity or natural gas and financial transactions represent derivative instruments with no physical delivery, such as futures, swaps or options. |
The above electric and natural gas derivative contracts will be included in either power supply costs or natural gas supply costs during the period they are delivered and will be included in the various recovery mechanisms (ERM, PCA, and PGAs), or in the general rate case process, and are expected to be collected through retail rates from customers.
Foreign Currency Exchange Contracts
A significant portion of Avista Utilities’ natural gas supply (including fuel for power generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of Avista Utilities’ short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices and settled within 60 days with U.S. dollars. Avista Utilities hedges a portion of the foreign currency risk by purchasing Canadian currency contracts when such commodity transactions are initiated. This risk has not had a material effect on the Company’s financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations were included with natural gas supply costs for ratemaking. The following table summarizes the foreign currency hedges that the Company has entered into as of December 31 (dollars in thousands):
| 2013 | 2012 | ||||||
| Number of contracts | 23 | 20 | |||||
| Notional amount (in United States dollars) | $ | 8,631 | $ | 12,621 | |||
| Notional amount (in Canadian dollars) | 9,191 | 12,502 | |||||
Interest Rate Swap Agreements
Avista Corp. is affected by fluctuating interest rates related to a portion of its existing debt, and future borrowing requirements. The Finance Committee of the Board of Directors periodically reviews and discusses interest rate risk management processes, and it focuses on the steps management has undertaken to control it. The Risk Management Committee also reviews the interest risk management plan. Avista Corp. manages interest rate exposure by limiting the variable rate exposures to a percentage of total capitalization. Additionally, interest rate risk is managed by monitoring market conditions when timing the issuance of long-term debt and optional debt redemptions and through the use of fixed rate long-term debt with varying maturities. The Company also hedges a portion of its interest rate risk with financial derivative instruments, which may include interest rate swaps and U.S. Treasury lock agreements. These interest rate swaps and U.S. Treasury lock agreements are considered economic hedges against fluctuations in future cash flows associated with anticipated debt issuances.
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The following table summarizes the interest rate swaps that the Company has entered into as of December 31 (dollars in thousands):
| Balance Sheet Date | Number of Contracts | Notional Amount | Mandatory Cash Settlement Date | |||||
| December 31, 2013 | 2 | $ | 50,000 | 2014 | ||||
| 2 | 45,000 | 2015 | ||||||
| 2 | 40,000 | 2016 | ||||||
| 1 | 15,000 | 2017 | ||||||
| 4 | 95,000 | 2018 | ||||||
| December 31, 2012 | 2 | 85,000 | 2013 | |||||
| 2 | 50,000 | 2014 | ||||||
| 1 | 25,000 | 2015 | ||||||
In June 2013, the Company cash settled two interest rate swap contracts (notional amount of $85.0 million) and received a total of $2.9 million. The interest rate swap contracts were settled in connection with the pricing of $90.0 million of First Mortgage Bonds that were issued in August 2013 (see Note 13). Upon settlement of interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a component of interest expense over the term of the associated debt.
The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheet as of December 31, 2013 (in thousands):
| Fair Value | ||||||||||||||||||||||||||||||
| Derivative | Balance Sheet Location | Gross Asset | Gross Liability | Collateral Netting | Net Asset (Liability) in Balance Sheet | Gross Assets Not Offset | Gross Liabilities Not Offset | Net Asset (Liability) | ||||||||||||||||||||||
| Foreign currency contracts | Other current assets | $ | 7 | $ | (6 | ) | $ | — | $ | 1 | $ | — | $ | — | $ | 1 | ||||||||||||||
| Interest rate contracts | Other current assets | 13,968 | — | — | 13,968 | — | — | 13,968 | ||||||||||||||||||||||
| Interest rate contracts | Other property and investments - net | 19,575 | — | — | 19,575 | — | — | 19,575 | ||||||||||||||||||||||
| Commodity contracts (1) | Current utility energy commodity derivative assets | 7,416 | (4,394 | ) | — | 3,022 | — | — | 3,022 | |||||||||||||||||||||
| Commodity contracts (1) | Non-current utility energy commodity derivative assets | 7,610 | (6,756 | ) | — | 854 | — | — | 854 | |||||||||||||||||||||
| Commodity contracts (1) | Current utility energy commodity derivative liabilities | 23,455 | (37,306 | ) | 2,976 | (10,875 | ) | — | — | (10,875 | ) | |||||||||||||||||||
| Commodity contracts (1) | Other non-current liabilities and deferred credits | 17,101 | (41,213 | ) | 5,756 | (18,356 | ) | — | — | (18,356 | ) | |||||||||||||||||||
| Total derivative instruments recorded on the balance sheet | $ | 89,132 | $ | (89,675 | ) | $ | 8,732 | $ | 8,189 | $ | — | $ | — | $ | 8,189 | |||||||||||||||
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The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheet as of December 31, 2012 (in thousands):
| Fair Value | ||||||||||||||||||||||||||||||
| Derivative | Balance Sheet Location | Gross Asset | Gross Liability | Collateral Netting | Net Asset (Liability) in Balance Sheet | Gross Assets Not Offset | Gross Liabilities Not Offset | Net Asset (Liability) | ||||||||||||||||||||||
| Foreign currency contracts | Other current liabilities | $ | 7 | $ | (34 | ) | $ | — | $ | (27 | ) | $ | — | $ | — | $ | (27 | ) | ||||||||||||
| Interest rate contracts | Other current liabilities | — | (1,406 | ) | — | (1,406 | ) | — | — | (1,406 | ) | |||||||||||||||||||
| Interest rate contracts | Other property and investments - net | 7,265 | — | — | 7,265 | — | — | 7,265 | ||||||||||||||||||||||
| Commodity contracts (1) | Current utility energy commodity derivative assets | 10,772 | (6,633 | ) | — | 4,139 | (9,678 | ) | 6,572 | 1,033 | ||||||||||||||||||||
| Commodity contracts (1) | Non-current utility energy commodity derivative assets | 18,779 | (17,686 | ) | — | 1,093 | — | — | 1,093 | |||||||||||||||||||||
| Commodity contracts (1) | Current utility energy commodity derivative liabilities | 50,227 | (89,449 | ) | 9,707 | (29,515 | ) | 9,678 | (6,572 | ) | (26,409 | ) | ||||||||||||||||||
| Commodity contracts (1) | Other non-current liabilities and deferred credits | 2,247 | (28,558 | ) | — | (26,311 | ) | — | — | (26,311 | ) | |||||||||||||||||||
| Total derivative instruments recorded on the balance sheet | $ | 89,297 | $ | (143,766 | ) | $ | 9,707 | $ | (44,762 | ) | $ | — | $ | — | $ | (44,762 | ) | |||||||||||||
| (1) | Avista Corp. has a master netting agreement that governs the transactions of multiple affiliated legal entities under this single master netting agreement. This master netting agreement allows for cross-commodity netting (i.e. netting physical power, physical natural gas, and financial transactions) and cross-affiliate netting for the parties to the agreement. Avista Corp. performs cross-commodity netting for each legal entity that is a party to the master netting agreement for presentation in the Consolidated Balance Sheets; however, Avista Corp. does not perform cross-affiliate netting because the Company believes that cross-affiliate netting may not be enforceable. Therefore, the requirements for cross-affiliate netting under ASC 210-20-45 are not applicable for Avista Corp. As of December 31, 2013, all derivatives for each affiliated entity under this master netting agreement were in a net liability position. As such, there is no additional netting which requires disclosure. |
Exposure to Demands for Collateral
The Company's derivative contracts often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement, in the event of a downgrade in the Company's credit ratings or changes in market prices. In periods of price volatility, the level of exposure can change significantly. As a result, sudden and significant demands may be made against the Company's credit facilities and cash. The Company actively monitors the exposure to possible collateral calls and takes steps to mitigate capital requirements. As of December 31, 2013, the Company had cash deposited as collateral of $26.1 million and letters of credit of $20.3 million outstanding related to its energy derivative contracts. The Consolidated Balance Sheet at December 31, 2013 reflects the offsetting of $8.7 million of cash collateral against net derivative positions where a legal right of offset exists. As of December 31, 2012, the Company had cash deposited as collateral of $10.1 million and letters of credit of $28.1 million outstanding related to its energy derivative contracts. The Consolidated Balance Sheet at December 31, 2012 reflects the offsetting of $9.7 million of cash collateral against net derivative positions where a legal right of offset exists.
Certain of the Company’s derivative instruments contain provisions that require the Company to maintain an investment grade credit rating from the major credit rating agencies. If the Company’s credit ratings were to fall below “investment grade,” it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position as of December 31,
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2013 was $13.3 million. If the credit-risk-related contingent features underlying these agreements had been triggered on December 31, 2013, the Company could have been required to post $12.6 million of additional collateral to its counterparties. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position as of December 31, 2012 was $35.9 million. If the credit-risk-related contingent features underlying these agreements had been triggered on December 31, 2012, the Company could have been required to post $25.8 million of additional collateral to its counterparties.
Credit Risk
Credit risk relates to the potential losses that the Company would incur as a result of non-performance by counterparties of their contractual obligations to deliver energy or make financial settlements. The Company often extends credit to counterparties and customers and is exposed to the risk that it may not be able to collect amounts owed to the Company. Credit risk includes potential counterparty default due to circumstances:
| • | relating directly to it, |
| • | caused by market price changes, and |
| • | relating to other market participants that have a direct or indirect relationship with such counterparty. |
Changes in market prices may dramatically alter the size of credit risk with counterparties, even when conservative credit limits are established. Should a counterparty fail to perform, the Company may be required to honor the underlying commitment or to replace existing contracts with contracts at then-current market prices.
We enter into bilateral transactions between Avista Corp. and various counterparties. We also trade energy and related derivative instruments through clearinghouse exchanges.
The Company seeks to mitigate bilateral credit risk by:
| • | entering into bilateral contracts that specify credit terms and protections against default, |
| • | applying credit limits and duration criteria to existing and prospective counterparties, |
| • | actively monitoring current credit exposures, |
| • | asserting our collateral rights with counterparties, |
| • | carrying out transaction settlements timely and effectively, and |
| • | conducting transactions on exchanges with fully collateralized clearing arrangements that significantly reduce counterparty default risk. |
The Company's credit policy includes an evaluation of the financial condition of counterparties. Credit risk management includes collateral requirements or other credit enhancements, such as letters of credit or parent company guarantees. The Company enters into various agreements that address credit risks including standardized agreements that allow for the netting or offsetting of positive and negative exposures.
The Company has concentrations of suppliers and customers in the electric and natural gas industries including:
| • | electric and natural gas utilities, |
| • | electric generators and transmission providers, |
| • | natural gas producers and pipelines, |
| • | financial institutions including commodity clearing exchanges and related parties, and |
| • | energy marketing and trading companies. |
In addition, the Company has concentrations of credit risk related to geographic location as it operates in the western United States and western Canada. These concentrations of counterparties and concentrations of geographic location may impact the Company’s overall exposure to credit risk because the counterparties may be similarly affected by changes in conditions.
The Company maintains credit support agreements with certain counterparties and margin calls are periodically made and/or received. Margin calls are triggered when exposures exceed contractual limits or when there are changes in a counterparty’s creditworthiness. Price movements in electricity and natural gas can generate exposure levels in excess of these contractual limits. Negotiating for collateral in the form of cash, letters of credit, or performance guarantees is common industry practice.
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NOTE 6. JOINTLY OWNED ELECTRIC FACILITIES
The Company has a 15 percent ownership interest in a twin-unit coal-fired generating facility, the Colstrip Generating Project (Colstrip) located in southeastern Montana, and provides financing for its ownership interest in the project. The Company’s share of related fuel costs as well as operating expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income. The Company’s share of utility plant in service for Colstrip and accumulated depreciation were as follows as of December 31 (dollars in thousands):
| 2013 | 2012 | ||||||
| Utility plant in service | $ | 349,781 | $ | 344,958 | |||
| Accumulated depreciation | (239,538 | ) | (234,126 | ) | |||
NOTE 7. PROPERTY, PLANT AND EQUIPMENT
The balances of the major classifications of property, plant and equipment are detailed in the following table as of December 31 (dollars in thousands):
| 2013 | 2012 | ||||||
| Avista Utilities: | |||||||
| Electric production | $ | 1,141,790 | $ | 1,112,670 | |||
| Electric transmission | 569,056 | 546,019 | |||||
| Electric distribution | 1,284,428 | 1,217,827 | |||||
| Electric construction work-in-progress (CWIP) and other | 276,582 | 244,761 | |||||
| Electric total | 3,271,856 | 3,121,277 | |||||
| Natural gas underground storage | 41,248 | 40,890 | |||||
| Natural gas distribution | 762,044 | 704,839 | |||||
| Natural gas CWIP and other | 47,751 | 57,745 | |||||
| Natural gas total | 851,043 | 803,474 | |||||
| Common plant (including CWIP) | 327,888 | 272,991 | |||||
| Total Avista Utilities | 4,450,787 | 4,197,742 | |||||
| Ecova (1) | 31,865 | 30,138 | |||||
| Other (1) | 20,132 | 22,690 | |||||
| Total | $ | 4,502,784 | $ | 4,250,570 | |||
| (1) | Included in other property and investments-net on the Consolidated Balance Sheets. Accumulated depreciation was $26.4 million as of December 31, 2013 and $23.4 million as of December 31, 2012 for Ecova and $11.4 million as of December 31, 2013 and $13.7 million as of December 31, 2012 for the other businesses. The decrease in accumulated depreciation for the other businesses was due to the retirement of a fully depreciated asset during 2013. |
NOTE 8. ASSET RETIREMENT OBLIGATIONS
The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the associated costs of the asset retirement obligation are capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the related capitalized costs are depreciated over the useful life of the related asset. Upon retirement of the asset, the Company either settles the retirement obligation for its recorded amount or incurs a gain or loss. The Company records regulatory assets and liabilities for the difference between asset retirement costs currently recovered in rates and asset retirement obligations recorded since asset retirement costs are recovered through rates charged to customers. The regulatory assets do not earn a return.
Specifically, the Company has recorded liabilities for future asset retirement obligations to:
| • | restore ponds at Colstrip, |
| • | cap a landfill at the Kettle Falls Plant, |
| • | remove plant and restore the land at the Coyote Springs 2 site at the termination of the land lease, |
| • | remove asbestos at the corporate office building, and |
| • | dispose of PCBs in certain transformers. |
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Due to an inability to estimate a range of settlement dates, the Company cannot estimate a liability for the:
| • | removal and disposal of certain transmission and distribution assets, and |
| • | abandonment and decommissioning of certain hydroelectric generation and natural gas storage facilities. |
The following table documents the changes in the Company’s asset retirement obligation during the years ended December 31 (dollars in thousands):
| 2013 | 2012 | 2011 | |||||||||
| Asset retirement obligation at beginning of year | $ | 3,168 | $ | 3,513 | $ | 3,887 | |||||
| Liability settled | (263 | ) | (559 | ) | (612 | ) | |||||
| Accretion expense (income) | (46 | ) | 214 | 238 | |||||||
| Asset retirement obligation at end of year | $ | 2,859 | $ | 3,168 | $ | 3,513 | |||||
NOTE 9. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS
The Company has a defined benefit pension plan covering substantially all regular full-time employees at Avista Utilities. Individual benefits under this plan are based upon the employee’s years of service, date of hire and average compensation as specified in the plan. The Company’s funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes. The Company contributed $44.3 million in cash to the pension plan in 2013, $44.0 million in 2012 and $26.0 million in 2011. The Company expects to contribute $32.0 million in cash to the pension plan in 2014.
In October 2013, the Company revised its defined benefit pension plan such that as of January 1, 2014 the plan is closed to all non-union employees hired or rehired by the Company on or after January 1, 2014. All actively employed non-union employees that were hired prior to January 1, 2014 and are currently covered under the defined benefit pension plan will continue accruing benefits as originally specified in the plan. A new and separate defined contribution 401(k) plan replaced the defined benefit pension plan for all non-union employees hired or rehired on or after January 1, 2014. Under the new defined contribution plan, the Company provides a non-elective contribution as a percentage of each employee's pay based on his or her age. This new defined contribution plan is in addition to the existing 401(k) plan in which the Company matches a portion of the pay deferred by each participant. In addition to the above changes, the Company has also revised its lump sum calculation from its previous lump sum calculation for non-union participants who retire under the defined benefit pension plan to provide non-union retirees on or after January 1, 2014 with a lump sum amount equivalent to the present value of the annuity based upon applicable discount rates.
The Company also has a Supplemental Executive Retirement Plan (SERP) that provides additional pension benefits to executive officers of the Company. The SERP is intended to provide benefits to executive officers whose benefits under the pension plan are reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred compensation plans. The liability and expense for this plan are included as pension benefits in the tables included in this Note.
The Company expects that benefit payments under the pension plan and the SERP will total (dollars in thousands):
| 2014 | 2015 | 2016 | 2017 | 2018 | Total 2019-2023 | ||||||||||||||||||
| Expected benefit payments | $ | 25,176 | $ | 26,735 | $ | 27,731 | $ | 28,880 | $ | 30,379 | $ | 172,887 | |||||||||||
The expected long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments held by the plan. In selecting a discount rate, the Company considers yield rates for highly rated corporate bond portfolios with maturities similar to that of the expected term of pension benefits.
The Company provides certain health care and life insurance benefits for substantially all of its retired employees. The Company accrues the estimated cost of postretirement benefit obligations during the years that employees provide services. The Company elected to amortize the transition obligation of $34.5 million over a period of 20 years, beginning in 1993. In October 2013, the Company revised the health care benefit plan such that beginning on January 1, 2020, the method for calculating health insurance premiums for non-union retirees under age 65 and active Company employees was revised. The revisions resulted in separate health insurance premium calculations for each group. In addition, for non-union employees hired or rehired on or after January 1, 2014, upon retirement the Company no longer provides a contribution towards his or her medical premiums. The Company will provide access to its retiree medical plan, but the non-union employees hired or rehired on or after January 1, 2014 will pay the full cost of premiums upon retirement.
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The Company has a Health Reimbursement Arrangement to provide employees with tax-advantaged funds to pay for allowable medical expenses upon retirement. The amount earned by the employee is fixed on the retirement date based on the employee’s years of service and the ending salary. The liability and expense of this plan are included as other postretirement benefits.
The Company provides death benefits to beneficiaries of executive officers who die during their term of office or after retirement. Under the plan, an executive officer’s designated beneficiary will receive a payment equal to twice the executive officer’s annual base salary at the time of death (or if death occurs after retirement, a payment equal to twice the executive officer’s total annual pension benefit). The liability and expense for this plan are included as other postretirement benefits.
The Company expects that benefit payments under other postretirement benefit plans will total (dollars in thousands):
| 2014 | 2015 | 2016 | 2017 | 2018 | Total 2019-2023 | ||||||||||||||||||
| Expected benefit payments | $ | 6,969 | $ | 6,707 | $ | 7,056 | $ | 7,120 | $ | 7,247 | $ | 35,121 | |||||||||||
The Company expects to contribute $7.0 million to other postretirement benefit plans in 2014, representing expected benefit payments to be paid during the year. The Company uses a December 31 measurement date for its pension and other postretirement benefit plans.
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The following table sets forth the pension and other postretirement benefit plan disclosures as of December 31, 2013 and 2012 and the components of net periodic benefit costs for the years ended December 31, 2013, 2012 and 2011 (dollars in thousands):
| Pension Benefits | Other Post- retirement Benefits | ||||||||||||||
| 2013 | 2012 | 2013 | 2012 | ||||||||||||
| Change in benefit obligation: | |||||||||||||||
| Benefit obligation as of beginning of year | $ | 584,619 | $ | 494,192 | $ | 132,541 | $ | 104,730 | |||||||
| Service cost | 19,045 | 15,551 | 4,144 | 2,804 | |||||||||||
| Interest cost | 23,896 | 24,349 | 5,216 | 5,056 | |||||||||||
| Actuarial (gain)/loss | (78,234 | ) | 72,170 | (18,017 | ) | 24,543 | |||||||||
| Plan change | 277 | — | (10,788 | ) | — | ||||||||||
| Transfer of accrued vacation | — | — | 1,189 | 336 | |||||||||||
| Benefits paid | (22,599 | ) | (21,643 | ) | (6,036 | ) | (4,928 | ) | |||||||
| Benefit obligation as of end of year | $ | 527,004 | $ | 584,619 | $ | 108,249 | $ | 132,541 | |||||||
| Change in plan assets: | |||||||||||||||
| Fair value of plan assets as of beginning of year | $ | 406,061 | $ | 328,150 | $ | 25,288 | $ | 22,455 | |||||||
| Actual return on plan assets | 52,502 | 54,318 | 4,444 | 2,833 | |||||||||||
| Employer contributions | 44,263 | 44,000 | — | — | |||||||||||
| Benefits paid | (21,324 | ) | (20,407 | ) | — | — | |||||||||
| Fair value of plan assets as of end of year | $ | 481,502 | $ | 406,061 | $ | 29,732 | $ | 25,288 | |||||||
| Funded status | $ | (45,502 | ) | $ | (178,558 | ) | $ | (78,517 | ) | $ | (107,253 | ) | |||
| Unrecognized net actuarial loss | 107,043 | 223,308 | 56,885 | 94,202 | |||||||||||
| Unrecognized prior service cost | 278 | 319 | (707 | ) | (856 | ) | |||||||||
| Prepaid (accrued) benefit cost | 61,819 | 45,069 | (22,339 | ) | (13,907 | ) | |||||||||
| Additional liability | (107,321 | ) | (223,627 | ) | (56,178 | ) | (93,346 | ) | |||||||
| Accrued benefit liability | $ | (45,502 | ) | $ | (178,558 | ) | $ | (78,517 | ) | $ | (107,253 | ) | |||
| Accumulated pension benefit obligation | $ | 464,432 | $ | 505,695 | — | — | |||||||||
| Accumulated postretirement benefit obligation: | |||||||||||||||
| For retirees | $ | 52,384 | $ | 49,232 | |||||||||||
| For fully eligible employees | $ | 24,320 | $ | 35,570 | |||||||||||
| For other participants | $ | 31,545 | $ | 47,739 | |||||||||||
| Included in accumulated other comprehensive loss (income) (net of tax): | |||||||||||||||
| Unrecognized prior service cost | $ | 180 | $ | 207 | $ | (7,472 | ) | $ | (556 | ) | |||||
| Unrecognized net actuarial loss | 69,578 | 145,150 | 43,988 | 61,231 | |||||||||||
| Total | 69,758 | 145,357 | 36,516 | 60,675 | |||||||||||
| Less regulatory asset | (64,925 | ) | (138,184 | ) | (37,116 | ) | (60,981 | ) | |||||||
| Accumulated other comprehensive loss (income) | $ | 4,833 | $ | 7,173 | $ | (600 | ) | $ | (306 | ) | |||||
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| Pension Benefits | Other Post- retirement Benefits | ||||||||||
| 2013 | 2012 | 2013 | 2012 | ||||||||
| Weighted average assumptions as of December 31: | |||||||||||
| Discount rate for benefit obligation | 5.10 | % | 4.15 | % | 5.02 | % | 4.15 | % | |||
| Discount rate for annual expense | 4.15 | % | 5.04 | % | 4.15 | % | 4.98 | % | |||
| Expected long-term return on plan assets | 6.60 | % | 6.95 | % | 6.35 | % | 6.55 | % | |||
| Rate of compensation increase | 4.96 | % | 4.89 | % | |||||||
| Medical cost trend pre-age 65 – initial | 7.00 | % | 7.00 | % | |||||||
| Medical cost trend pre-age 65 – ultimate | 5.00 | % | 5.00 | % | |||||||
| Ultimate medical cost trend year pre-age 65 | 2020 | 2019 | |||||||||
| Medical cost trend post-age 65 – initial | 7.50 | % | 7.50 | % | |||||||
| Medical cost trend post-age 65 – ultimate | 5.00 | % | 5.00 | % | |||||||
| Ultimate medical cost trend year post-age 65 | 2021 | 2021 | |||||||||
| Pension Benefits | Other Post-retirement Benefits | ||||||||||||||||||||||
| 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | ||||||||||||||||||
| Components of net periodic benefit cost: | |||||||||||||||||||||||
| Service cost | $ | 19,045 | $ | 15,551 | $ | 12,936 | $ | 4,144 | $ | 2,804 | $ | 1,805 | |||||||||||
| Interest cost | 23,896 | 24,349 | 24,134 | 5,216 | 5,056 | 4,126 | |||||||||||||||||
| Expected return on plan assets | (27,671 | ) | (23,810 | ) | (23,115 | ) | (1,606 | ) | (1,471 | ) | (1,601 | ) | |||||||||||
| Transition obligation recognition | — | — | — | — | 505 | 505 | |||||||||||||||||
| Amortization of prior service cost | 319 | 346 | 475 | (149 | ) | (149 | ) | (149 | ) | ||||||||||||||
| Net loss recognition | 13,199 | 11,637 | 9,493 | 5,674 | 5,020 | 3,458 | |||||||||||||||||
| Net periodic benefit cost | $ | 28,788 | $ | 28,073 | $ | 23,923 | $ | 13,279 | $ | 11,765 | $ | 8,144 | |||||||||||
Plan Assets
The Finance Committee of the Company’s Board of Directors approves investment policies, objectives and strategies that seek an appropriate return for the pension plan and other postretirement benefit plans and reviews and approves changes to the investment and funding policies.
The Company has contracted with investment consultants who are responsible for managing/monitoring the individual investment managers. The investment managers’ performance and related individual fund performance is periodically reviewed by an internal benefits committee and by the Finance Committee to monitor compliance with investment policy objectives and strategies.
Pension plan assets are invested in mutual funds, trusts and partnerships that hold marketable debt and equity securities, real estate, absolute return and commodity funds. In seeking to obtain the desired return to fund the pension plan, the investment consultant recommends allocation percentages by asset classes. These recommendations are reviewed by the internal benefits committee, which then recommends their adoption by the Finance Committee. The Finance Committee has established target investment allocation percentages by asset classes and also investment ranges for each asset class. The target investment allocation percentages are typically the midpoint of the established range. The target investment allocation percentages by asset classes are indicated in the table below:
| 2013 | 2012 | ||||
| Equity securities | 47 | % | 51 | % | |
| Debt securities | 31 | % | 31 | % | |
| Real estate | 6 | % | 5 | % | |
| Absolute return | 12 | % | 10 | % | |
| Other | 4 | % | 3 | % | |
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The market-related value of pension plan assets invested in debt and equity securities was based primarily on fair value (market prices). The fair value of investment securities traded on a national securities exchange is determined based on the reported last sales price; securities traded in the over-the-counter market are valued at the last reported bid price. Investment securities for which market prices are not readily available or for which market prices do not represent the value at the time of pricing, are fair-valued by the investment manager based upon other inputs (including valuations of securities that are comparable in coupon, rating, maturity and industry). Investments in common/collective trust funds are presented at estimated fair value, which is determined based on the unit value of the fund. Unit value is determined by an independent trustee, which sponsors the fund, by dividing the fund’s net assets by its units outstanding at the valuation date. The fair value of the closely held investments and partnership interests is based upon the allocated share of the fair value of the underlying assets as well as the allocated share of the undistributed profits and losses, including realized and unrealized gains and losses.
The market-related value of pension plan assets invested in real estate was determined by the investment manager based on three basic approaches:
| • | properties are externally appraised on an annual basis by independent appraisers, additional appraisals may be performed as warranted by specific asset or market conditions, |
| • | property valuations are reviewed quarterly and adjusted as necessary, and |
| • | loans are reflected at fair value. |
The market-related value of pension plan assets was determined as of December 31, 2013 and 2012.
The following table discloses by level within the fair value hierarchy (see Note 16 for a description of the fair value hierarchy) of the pension plan’s assets measured and reported as of December 31, 2013 at fair value (dollars in thousands):
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Mutual funds: | |||||||||||||||
| Fixed income securities | $ | 86,481 | $ | 310 | $ | — | $ | 86,791 | |||||||
| U.S. equity securities | 152,831 | — | — | 152,831 | |||||||||||
| International equity securities | 85,942 | — | — | 85,942 | |||||||||||
| Absolute return (1) | 23,599 | — | — | 23,599 | |||||||||||
| Common/collective trusts: | |||||||||||||||
| Fixed income securities | — | 55,872 | — | 55,872 | |||||||||||
| Real estate | — | — | 19,735 | 19,735 | |||||||||||
| Partnership/closely held investments: | |||||||||||||||
| Absolute return (1) | — | — | 34,151 | 34,151 | |||||||||||
| Private equity funds (3) | — | — | 377 | 377 | |||||||||||
| Commodities (2) | — | 18,331 | — | 18,331 | |||||||||||
| Real estate | — | — | 3,873 | 3,873 | |||||||||||
| Total | $ | 348,853 | $ | 74,513 | $ | 58,136 | $ | 481,502 | |||||||
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The following table discloses by level within the fair value hierarchy (see Note 16 for a description of the fair value hierarchy) of the pension plan’s assets measured and reported as of December 31, 2012 at fair value (dollars in thousands):
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Mutual funds: | |||||||||||||||
| Fixed income securities | $ | 83,037 | $ | — | $ | — | $ | 83,037 | |||||||
| U.S. equity securities | 135,436 | — | — | 135,436 | |||||||||||
| International equity securities | 79,448 | — | — | 79,448 | |||||||||||
| Absolute return (1) | 20,764 | — | — | 20,764 | |||||||||||
| Commodities (2) | 8,258 | — | — | 8,258 | |||||||||||
| Common/collective trusts: | |||||||||||||||
| Fixed income securities | — | 43,107 | — | 43,107 | |||||||||||
| Real estate | — | — | 17,596 | 17,596 | |||||||||||
| Partnership/closely held investments: | |||||||||||||||
| Absolute return (1) | — | — | 17,755 | 17,755 | |||||||||||
| Private equity funds (3) | — | — | 660 | 660 | |||||||||||
| Total | $ | 326,943 | $ | 43,107 | $ | 36,011 | $ | 406,061 | |||||||
| (1) | This category invests in multiple strategies to diversify risk and reduce volatility. The strategies include: (a) event driven, relative value, convertible, and fixed income arbitrage, (b) distressed investments, (c) long/short equity and fixed income, and (d) market neutral strategies. |
| (2) | This investment is in derivatives linked to commodity indices to gain exposure to the commodity markets. These positions are fully collateralized with debt securities. |
| (3) | This category includes private equity funds that invest primarily in U.S. companies. |
The table below discloses the summary of changes in the fair value of the pension plan’s Level 3 assets for the year ended December 31, 2013 (dollars in thousands):
| Common/collective trusts | Partnership/closely held investments | ||||||||||||||
Real estate | Absolute return | Private equity funds | Real estate | ||||||||||||
| Balance, as of January 1, 2013 | $ | 17,596 | $ | 17,755 | $ | 660 | $ | — | |||||||
| Realized gains | — | — | (323 | ) | — | ||||||||||
| Unrealized gains (losses) | 2,139 | 2,396 | 345 | 113 | |||||||||||
| Purchases (sales), net | — | 14,000 | (305 | ) | 3,760 | ||||||||||
| Balance, as of December 31, 2013 | $ | 19,735 | $ | 34,151 | $ | 377 | $ | 3,873 | |||||||
The table below discloses the summary of changes in the fair value of the pension plan’s Level 3 assets for the year ended December 31, 2012 (dollars in thousands):
| Common/collective trusts | Partnership/closely held investments | ||||||||||
Real estate | Absolute return | Private equity funds | |||||||||
| Balance, as of January 1, 2012 | $ | 8,598 | $ | 16,587 | $ | 808 | |||||
| Realized gains (losses) | 411 | — | 108 | ||||||||
| Unrealized gains (losses) | 1,087 | 1,168 | 80 | ||||||||
| Purchases (sales), net | 7,500 | — | (336 | ) | |||||||
| Balance, as of December 31, 2012 | $ | 17,596 | $ | 17,755 | $ | 660 | |||||
The market-related value of other postretirement plan assets invested in debt and equity securities was based primarily on fair value (market prices). The fair value of investment securities traded on a national securities exchange is determined based on the last reported sales price; securities traded in the over-the-counter market are valued at the last reported bid price. Investment securities for which market prices are not readily available or for which market prices do not represent the value at the time of pricing, are fair-valued by the investment manager based upon other inputs (including valuations of securities that are comparable in coupon, rating, maturity and industry). The target asset allocation was 60 percent equity securities and 40 percent debt securities in 2013 and 62 percent equity securities and 38 percent debt securities in 2012.
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The market-related value of other postretirement plan assets was determined as of December 31, 2013 and 2012.
The following table discloses by level within the fair value hierarchy (see Note 16 for a description of the fair value hierarchy) of other postretirement plan assets measured and reported as of December 31, 2013 at fair value (dollars in thousands):
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Cash equivalents | $ | — | $ | 4 | $ | — | $ | 4 | |||||||
| Mutual funds: | |||||||||||||||
| Fixed income securities | 11,645 | — | — | 11,645 | |||||||||||
| U.S. equity securities | 11,831 | — | — | 11,831 | |||||||||||
| International equity securities | 6,252 | — | — | 6,252 | |||||||||||
| Total | $ | 29,728 | $ | 4 | $ | — | $ | 29,732 | |||||||
The following table discloses by level within the fair value hierarchy (see Note 16 for a description of the fair value hierarchy) of other postretirement plan assets measured and reported as of December 31, 2012 at fair value (dollars in thousands):
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Cash equivalents | $ | — | $ | 6 | $ | — | $ | 6 | |||||||
| Mutual funds: | |||||||||||||||
| Fixed income securities | 9,314 | — | — | 9,314 | |||||||||||
| U.S. equity securities | 10,266 | — | — | 10,266 | |||||||||||
| International equity securities | 5,702 | — | — | 5,702 | |||||||||||
| Total | $ | 25,282 | $ | 6 | $ | — | $ | 25,288 | |||||||
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement benefit obligation as of December 31, 2013 by $3.8 million and the service and interest cost by $0.8 million. A one-percentage-point decrease in the assumed health care cost trend rate for each year would decrease the accumulated postretirement benefit obligation as of December 31, 2013 by $3.1 million and the service and interest cost by $0.6 million.
The Company and its most significant subsidiaries have salary deferral 401(k) plans that are defined contribution plans and cover substantially all employees. Employees can make contributions to their respective accounts in the plans on a pre-tax basis up to the maximum amount permitted by law. The respective company matches a portion of the salary deferred by each participant according to the schedule in the respective plan.
Employer matching contributions were as follows for the years ended December 31 (dollars in thousands):
| 2013 | 2012 | 2011 | |||||||||
| Employer 401(k) matching contributions | $ | 8,579 | $ | 8,168 | $ | 7,027 | |||||
The Company has an Executive Deferral Plan. This plan allows executive officers and other key employees the opportunity to defer until the earlier of their retirement, termination, disability or death, up to 75 percent of their base salary and/or up to 100 percent of their incentive payments. Deferred compensation funds are held by the Company in a Rabbi Trust. There were deferred compensation assets included in other property and investments-net and corresponding deferred compensation liabilities included in other non-current liabilities and deferred credits on the Consolidated Balance Sheets of the following amounts as of December 31 (dollars in thousands):
| 2013 | 2012 | ||||||
| Deferred compensation assets and liabilities | $ | 9,170 | $ | 8,806 | |||
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NOTE 10. ACCOUNTING FOR INCOME TAXES
Income tax expense consisted of the following for the years ended December 31 (dollars in thousands):
| 2013 | 2012 | 2011 | |||||||||
| Taxes currently provided | $ | 39,698 | $ | 19,812 | $ | 32,625 | |||||
| Deferred income tax expense | 23,532 | 21,449 | 24,007 | ||||||||
| Total income tax expense | $ | 63,230 | $ | 41,261 | $ | 56,632 | |||||
A reconciliation of federal income taxes derived from statutory federal tax rates (35 percent in 2013, 2012 and 2011) applied to income before income taxes as set forth in the accompanying Consolidated Statements of Income is as follows for the years ended December 31 (dollars in thousands):
| 2013 | 2012 | 2011 | |||||||||
| Federal income taxes at statutory rates | $ | 61,433 | $ | 42,021 | $ | 56,060 | |||||
| Increase (decrease) in tax resulting from: | |||||||||||
| Tax effect of regulatory treatment of utility plant differences | 3,532 | 2,432 | 1,798 | ||||||||
| State income tax expense | 1,967 | 985 | 687 | ||||||||
| Settlement of prior year tax returns and adjustment of tax reserves | (1,104 | ) | (2,198 | ) | 163 | ||||||
| Manufacturing deduction | (2,033 | ) | (1,100 | ) | (1,099 | ) | |||||
| Other | (565 | ) | (879 | ) | (977 | ) | |||||
| Total income tax expense | $ | 63,230 | $ | 41,261 | $ | 56,632 | |||||
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and tax credit carryforwards. The total net deferred income tax liability consisted of the following as of December 31 (dollars in thousands):
| 2013 | 2012 | ||||||
| Deferred income tax assets: | |||||||
| Allowance for doubtful accounts | $ | 12,202 | $ | 12,140 | |||
| Reserves not currently deductible | 6,322 | 5,923 | |||||
| Net operating loss from subsidiary acquisition | 9,258 | 11,136 | |||||
| Deferred compensation | 3,676 | 3,631 | |||||
| Unfunded benefit obligation | 42,230 | 94,891 | |||||
| Utility energy commodity derivatives | 13,303 | 22,953 | |||||
| Power and natural gas deferrals | 9,226 | 12,490 | |||||
| Tax credits | 11,365 | 19,401 | |||||
| Other | 29,133 | 19,291 | |||||
| Total deferred income tax assets | 136,715 | 201,856 | |||||
| Deferred income tax liabilities: | |||||||
| Intangible assets from subsidiary acquisition | 4,271 | 5,582 | |||||
| Differences between book and tax basis of utility plant | 521,238 | 494,579 | |||||
| Regulatory asset for pensions and other postretirement benefits | 54,945 | 107,243 | |||||
| Power exchange contract | 5,484 | 10,753 | |||||
| Utility energy commodity derivatives | 13,305 | 22,954 | |||||
| Loss on reacquired debt | 5,732 | 6,751 | |||||
| Interest rate swaps | 15,097 | 12,308 | |||||
| Settlement with Coeur d’Alene Tribe | 13,190 | 13,448 | |||||
| Other | 14,008 | 18,227 | |||||
| Total deferred income tax liabilities | 647,270 | 691,845 | |||||
| Net deferred income tax liability | $ | 510,555 | $ | 489,989 | |||
| Consolidated balance sheet classification of net deferred income taxes: | |||||||
| Current deferred income tax asset | $ | 24,788 | $ | 34,281 | |||
| Ecova long-term deferred income tax asset (1) | — | 607 | |||||
| Long-term deferred income tax liability | 535,343 | 524,877 | |||||
| Net deferred income tax liability | $ | 510,555 | $ | 489,989 | |||
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| (1) | Ecova files its own tax return and its deferred tax assets and liabilities cannot be netted with Avista Corp.'s deferred income tax assets and liabilities. As of December 31, 2012, Ecova had a long-term deferred income tax asset that was included in other deferred charges on the Consolidated Balance Sheet. As of December 31, 2013, Ecova no longer has any long-term deferred tax assets, they are now in a liability position and are included in long-term deferred income tax liabilities on the Consolidated Balance Sheet. |
As of December 31, 2013, the Company had $5.9 million of state tax credit carryforwards. State tax credits expire from 2016 to 2027. The Company recognizes the effect of state tax credits generated from utility plant as they are utilized.
The realization of deferred income tax assets is dependent upon the ability to generate taxable income in future periods. The Company evaluated available evidence supporting the realization of its deferred income tax assets and determined it is more likely than not that deferred income tax assets will be realized.
The Company and its eligible subsidiaries file consolidated federal income tax returns. The Company also files state income tax returns in certain jurisdictions, including Idaho, Oregon and Montana. Subsidiaries are charged or credited with the tax effects of their operations on a stand-alone basis. The Internal Revenue Service (IRS) has completed its examination of all tax years through 2009 and all issues were resolved related to these years. The IRS has not completed an examination of the Company’s 2010 through 2012 federal income tax returns. The Company does not believe that any open tax years for federal or state income taxes could result in any adjustments that would be significant to the consolidated financial statements.
The Company did not incur any penalties on income tax positions in 2013, 2012 or 2011. The Company would recognize interest accrued related to income tax positions as interest expense and any penalties incurred as other operating expense.
The Company had net regulatory assets related to the probable recovery of certain deferred income tax liabilities from customers through future rates as of December 31 (dollars in thousands):
| 2013 | 2012 | ||||||
| Regulatory assets for deferred income taxes | $ | 71,421 | $ | 79,406 | |||
NOTE 11. ENERGY PURCHASE CONTRACTS
Avista Utilities has contracts for the purchase of fuel for thermal generation, natural gas for resale and various agreements for the purchase or exchange of electric energy with other entities. The termination dates of the contracts range from one month to the year 2042. Total expenses for power purchased, natural gas purchased, fuel for generation and other fuel costs, which are included in utility resource costs in the Consolidated Statements of Income, were as follows for the years ended December 31 (dollars in thousands):
| 2013 | 2012 | 2011 | |||||||||
| Utility power resources | $ | 524,810 | $ | 523,416 | $ | 557,619 | |||||
The following table details Avista Utilities’ future contractual commitments for power resources (including transmission contracts) and natural gas resources (including transportation contracts) (dollars in thousands):
| 2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | Total | |||||||||||||||||||||
| Power resources | $ | 201,693 | $ | 125,072 | $ | 112,570 | $ | 110,405 | $ | 106,200 | $ | 874,990 | $ | 1,530,930 | |||||||||||||
| Natural gas resources | 102,651 | 64,860 | 46,665 | 43,011 | 37,570 | 482,986 | 777,743 | ||||||||||||||||||||
| Total | $ | 304,344 | $ | 189,932 | $ | 159,235 | $ | 153,416 | $ | 143,770 | $ | 1,357,976 | $ | 2,308,673 | |||||||||||||
These energy purchase contracts were entered into as part of Avista Utilities’ obligation to serve its retail electric and natural gas customers’ energy requirements, including contracts entered into for resource optimization. As a result, these costs are recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost deferral and recovery mechanisms.
The above future contractual commitments for power resources include fixed contractual amounts related to the Company's contracts with certain Public Utility Districts (PUD) to purchase portions of the output of certain generating facilities. Although Avista Utilities has no investment in the PUD generating facilities, the fixed contracts obligate Avista Utilities to pay certain minimum amounts (based in part on the debt service requirements of the PUD) whether or not the facilities are operating. The cost of power obtained under the contracts, including payments made when a facility is not operating, is included in utility
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resource costs in the Consolidated Statements of Income. The contractual amounts included above consist of Avista Utilities’ share of existing debt service cost and its proportionate share of the variable operating expenses of these projects.
In addition, Avista Utilities has operating agreements, settlements and other contractual obligations to see the output of its generating facilities and transmission and distribution services. The expenses associated with these agreements are reflected as other operating expenses in the Consolidated Statements of Income. The following table details future contractual commitments under these agreements (dollars in thousands):
| 2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | Total | |||||||||||||||||||||
| Contractual obligations | $ | 30,197 | $ | 27,236 | $ | 30,543 | $ | 29,199 | $ | 23,534 | $ | 211,392 | $ | 352,101 | |||||||||||||
NOTE 12. COMMITTED LINES OF CREDIT
Avista Corp.
Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million with an expiration date of February 2017.
The committed line of credit is secured by non-transferable First Mortgage Bonds of the Company issued to the agent bank that would only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of credit.
The committed line of credit agreement contains customary covenants and default provisions. The credit agreement has a covenant which does not permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 65 percent at any time. As of December 31, 2013, the Company was in compliance with this covenant.
Balances outstanding and interest rates of borrowings (excluding letters of credit) under the Company’s revolving committed lines of credit were as follows as of December 31 (dollars in thousands):
| 2013 | 2012 | 2011 | |||||||||
| Balance outstanding at end of period | $ | 171,000 | $ | 52,000 | $ | 61,000 | |||||
| Letters of credit outstanding at end of period | $ | 27,434 | $ | 35,885 | $ | 29,030 | |||||
| Average interest rate at end of period | 1.02 | % | 1.12 | % | 1.12 | % | |||||
As of December 31, 2013 the borrowings outstanding under Avista Corp.'s committed line of credit were classified as short-term borrowings on the Consolidated Balance Sheet.
Ecova
Ecova has a $125.0 million committed line of credit agreement with various financial institutions that has an expiration date of July 2017. The credit agreement is secured by all of Ecova's assets excluding investments and funds held for clients.
The committed line of credit agreement contains customary covenants and default provisions, including a covenant which requires that Ecova's “Consolidated Total Funded Debt to EBITDA Ratio” (as defined in the credit agreement) must be 2.50 to 1.00 or less, with provisions in the credit agreement allowing for a temporary increase of this ratio if a qualified acquisition is consummated by Ecova. In addition, Ecova's “Consolidated Fixed Charge Coverage Ratio” (as defined in the credit agreement) must be greater than 1.50 to 1.00 as of the last day of any fiscal quarter. As of December 31, 2013, Ecova was in compliance with these covenants.
Balances outstanding and interest rates of borrowings under Ecova’s credit agreements were as follows as of December 31 (dollars in thousands):
| 2013 | 2012 | 2011 | |||||||||
| Balance outstanding at end of period | $ | 46,000 | $ | 54,000 | $ | 35,000 | |||||
| Average interest rate at end of period | 2.17 | % | 2.21 | % | 2.38 | % | |||||
As of December 31, 2013 the borrowings outstanding under Ecova's committed line of credit were classified as long-term borrowings under committed line of credit on the Consolidated Balance Sheet.
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NOTE 13. LONG-TERM DEBT
The following details long-term debt outstanding as of December 31 (dollars in thousands):
Maturity Year | Description | Interest Rate | 2013 | 2012 | ||||||||
| 2013 | First Mortgage Bonds | 1.68% | $ | — | $ | 50,000 | ||||||
| 2016 | First Mortgage Bonds | 0.84% | 90,000 | — | ||||||||
| 2018 | First Mortgage Bonds | 5.95% | 250,000 | 250,000 | ||||||||
| 2018 | Secured Medium-Term Notes | 7.39%-7.45% | 22,500 | 22,500 | ||||||||
| 2019 | First Mortgage Bonds | 5.45% | 90,000 | 90,000 | ||||||||
| 2020 | First Mortgage Bonds | 3.89% | 52,000 | 52,000 | ||||||||
| 2022 | First Mortgage Bonds | 5.13% | 250,000 | 250,000 | ||||||||
| 2023 | Secured Medium-Term Notes | 7.18%-7.54% | 13,500 | 13,500 | ||||||||
| 2028 | Secured Medium-Term Notes | 6.37% | 25,000 | 25,000 | ||||||||
| 2032 | Secured Pollution Control Bonds (1) | (1) | 66,700 | 66,700 | ||||||||
| 2034 | Secured Pollution Control Bonds (2) | (2) | 17,000 | 17,000 | ||||||||
| 2035 | First Mortgage Bonds | 6.25% | 150,000 | 150,000 | ||||||||
| 2037 | First Mortgage Bonds | 5.70% | 150,000 | 150,000 | ||||||||
| 2040 | First Mortgage Bonds | 5.55% | 35,000 | 35,000 | ||||||||
| 2041 | First Mortgage Bonds | 4.45% | 85,000 | 85,000 | ||||||||
| 2047 | First Mortgage Bonds | 4.23% | 80,000 | 80,000 | ||||||||
| Total secured long-term debt | 1,376,700 | 1,336,700 | ||||||||||
| Other long-term debt and capital leases | 4,630 | 5,092 | ||||||||||
| Settled interest rate swaps (3) | (23,560 | ) | (27,900 | ) | ||||||||
| Unamortized debt discount | (1,287 | ) | (1,453 | ) | ||||||||
| Total | 1,356,483 | 1,312,439 | ||||||||||
| Secured Pollution Control Bonds held by Avista Corporation (1) (2) | (83,700 | ) | (83,700 | ) | ||||||||
| Current portion of long-term debt | (358 | ) | (50,372 | ) | ||||||||
| Total long-term debt | $ | 1,272,425 | $ | 1,178,367 | ||||||||
| (1) | In December 2010, $66.7 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) due 2032, which had been held by Avista Corp. since 2008, were refunded by a new bond issue (Series 2010A). 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. |
| (2) | In December 2010, $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds, (Avista Corporation Colstrip Project) due 2034, which had been held by Avista Corp. since 2009, were refunded by a new bond issue (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, the 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 Sheet. |
| (3) | Upon settlement of interest rate swaps, these are recorded as a regulatory asset or liability and included as part of long-term debt above. They are amortized as a component of interest expense over the life of the associated debt and included as a part of the Company's cost of debt calculation for ratemaking purposes. |
In August 2013, Avista Corp. entered into a $90.0 million term loan agreement with an institutional investor that bears an annual interest rate of 0.84 percent and matures in 2016. The term loan agreement is secured by non-transferable First Mortgage Bonds of the Company issued to the agent bank that will only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the term loan agreement. The net proceeds from the $90.0 million term loan
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agreement were used to repay a portion of corporate indebtedness in anticipation of $50.0 million in First Mortgage Bonds that matured in December 2013.
The following table details future long-term debt maturities including long-term debt to affiliated trusts (see Note 14) (dollars in thousands):
| 2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | Total | |||||||||||||||||||||
| Debt maturities | $ | — | $ | — | $ | 90,000 | $ | — | $ | 272,500 | $ | 982,047 | $ | 1,344,547 | |||||||||||||
Substantially all utility properties owned by the Company are subject to the lien of the Company’s mortgage indenture. Under the Mortgage and Deed of Trust securing the Company’s First Mortgage Bonds (including Secured Medium-Term Notes), the Company may issue additional First Mortgage Bonds in an aggregate principal amount equal to the sum of: 1) 66-2/3 percent of the cost or fair value (whichever is lower) of property additions which have not previously been made the basis of any application under the Mortgage, or 2) an equal principal amount of retired First Mortgage Bonds which have not previously been made the basis of any application under the Mortgage, or 3) deposit of cash. However, the Company may not issue any additional First Mortgage Bonds (with certain exceptions in the case of bonds issued on the basis of retired bonds) unless the Company’s “net earnings” (as defined in the Mortgage) for any period of 12 consecutive calendar months out of the preceding 18 calendar months were at least twice the annual interest requirements on all mortgage securities at the time outstanding, including the First Mortgage Bonds to be issued, and on all indebtedness of prior rank. As of December 31, 2013, property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $916.3 million in aggregate principal amount of additional First Mortgage Bonds.
See Note 12 for information regarding First Mortgage Bonds issued to secure the Company’s obligations under its committed line of credit agreement.
Nonrecourse Long-Term Debt
Nonrecourse long-term debt (including current portion) represents the long-term debt of Spokane Energy. To provide funding to acquire a long-term fixed rate electric capacity contract from Avista Corp., Spokane Energy borrowed $145.0 million from a funding trust in December 1998. The long-term debt has scheduled monthly installments and interest at a fixed rate of 8.45 percent with the final payment due in January 2015. Spokane Energy bears full recourse risk for the debt, which is secured by the fixed rate electric capacity contract and $1.6 million of funds held in a trust account. The following table details future nonrecourse long-term debt maturities (dollars in thousands):
| 2014 | 2015 | 2016 | 2017 | Total | |||||||||||||||
| Debt maturities | $ | 16,407 | $ | 1,431 | $ | — | $ | — | $ | 17,838 | |||||||||
NOTE 14. LONG-TERM DEBT TO AFFILIATED TRUSTS
In 1997, the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of $51.5 million to Avista Capital II, an affiliated business trust formed by the Company. Avista Capital II issued $50.0 million of Preferred Trust Securities with a floating distribution rate of LIBOR plus 0.875 percent, calculated and reset quarterly. The distribution rates paid were as follows during the years ended December 31:
| 2013 | 2012 | 2011 | ||||||
| Low distribution rate | 1.11 | % | 1.19 | % | 1.13 | % | ||
| High distribution rate | 1.19 | % | 1.40 | % | 1.40 | % | ||
| Distribution rate at the end of the year | 1.11 | % | 1.19 | % | 1.40 | % | ||
Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $1.5 million of Common Trust Securities to the Company. These debt securities may be redeemed at the option of Avista Capital II on or after June 1, 2007 and mature on June 1, 2037. In December 2000, the Company purchased $10.0 million of these Preferred Trust Securities.
The Company owns 100 percent of Avista Capital II and has solely and unconditionally guaranteed the payment of distributions on, and redemption price and liquidation amount for, the Preferred Trust Securities to the extent that Avista Capital II has funds available for such payments from the respective debt securities. Upon maturity or prior redemption of such debt securities, the Preferred Trust Securities will be mandatorily redeemed. The Company does not include these capital trusts in its consolidated financial statements as Avista Corp. is not the primary beneficiary. As such, the sole assets of the capital trusts are $51.5 million
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of junior subordinated deferrable interest debentures of Avista Corp., which are reflected on the Consolidated Balance Sheets. Interest expense to affiliated trusts in the Consolidated Statements of Income represents interest expense on these debentures.
NOTE 15. LEASES
The Company has multiple lease arrangements involving various assets, with minimum terms ranging from 1 to forty-five years. Rental expense under operating leases was as follows for the years ended December 31 (dollars in thousands):
| 2013 | 2012 | 2011 | |||||||||
| Rental expense | $ | 8,288 | $ | 8,152 | $ | 6,463 | |||||
Future minimum lease payments required under operating leases having initial or remaining noncancelable lease terms in excess of one year as of December 31 were as follows (dollars in thousands):
| 2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | Total | |||||||||||||||||||||
| Minimum payments required | $ | 6,668 | $ | 5,293 | $ | 3,639 | $ | 3,189 | $ | 2,849 | $ | 7,998 | $ | 29,636 | |||||||||||||
NOTE 16. FAIR VALUE
The carrying values of cash and cash equivalents, accounts and notes receivable, accounts payable and short-term borrowings are reasonable estimates of their fair values. Long-term debt (including current portion, but excluding capital leases), nonrecourse long-term debt and long-term debt to affiliated trusts are reported at carrying value on the Consolidated Balance Sheets.
The fair value hierarchy prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).
The three levels of the fair value hierarchy are defined as follows:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Level 3 – Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values incorporates various factors that not only include the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit), but also the impact of Avista Corp.’s nonperformance risk on its liabilities.
The following table sets forth the carrying value and estimated fair value of the Company’s financial instruments not reported at estimated fair value on the Consolidated Balance Sheets as of December 31 (dollars in thousands):
| 2013 | 2012 | ||||||||||||||
Carrying Value | Estimated Fair Value | Carrying Value | Estimated Fair Value | ||||||||||||
| Long-term debt (Level 2) | $ | 951,000 | $ | 1,054,512 | $ | 951,000 | $ | 1,164,639 | |||||||
| Long-term debt (Level 3) | 342,000 | 329,581 | 302,000 | 320,892 | |||||||||||
| Nonrecourse long-term debt (Level 3) | 17,838 | 18,636 | 32,803 | 35,297 | |||||||||||
| Long-term debt to affiliated trusts (Level 3) | 51,547 | 37,114 | 51,547 | 43,686 | |||||||||||
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These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market information. Due to the unique nature of the long-term fixed rate electric capacity contract securing the long-term debt of Spokane Energy (nonrecourse long-term debt), the estimated fair value of nonrecourse long-term debt was determined based on a discounted cash flow model using available market information.
The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Consolidated Balance Sheets as of December 31, 2013 and 2012 at fair value on a recurring basis (dollars in thousands):
| Level 1 | Level 2 | Level 3 | Counterparty and Cash Collateral Netting (1) | Total | |||||||||||||||
| December 31, 2013 | |||||||||||||||||||
| Assets: | |||||||||||||||||||
| Energy commodity derivatives | $ | — | $ | 55,243 | $ | — | $ | (51,367 | ) | $ | 3,876 | ||||||||
| Level 3 energy commodity derivatives: | |||||||||||||||||||
| Power exchange agreement | — | — | 339 | (339 | ) | — | |||||||||||||
| Foreign currency derivatives | — | 7 | — | (6 | ) | 1 | |||||||||||||
| Interest rate swaps | — | 33,543 | — | — | 33,543 | ||||||||||||||
| Investments and funds held for clients: | |||||||||||||||||||
| Money market funds | 11,180 | — | — | — | 11,180 | ||||||||||||||
| Securities available for sale: | |||||||||||||||||||
| U.S. government agency | — | 61,078 | — | — | 61,078 | ||||||||||||||
| Municipal | — | 3,518 | — | — | 3,518 | ||||||||||||||
| Corporate fixed income – financial | — | 3,000 | — | — | 3,000 | ||||||||||||||
| Corporate fixed income – industrial | — | 765 | — | — | 765 | ||||||||||||||
| Certificate of deposits | — | 1,000 | — | — | 1,000 | ||||||||||||||
| Funds held in trust account of Spokane Energy | 1,600 | — | — | — | 1,600 | ||||||||||||||
| Deferred compensation assets: | |||||||||||||||||||
| Fixed income securities (2) | 1,960 | — | — | — | 1,960 | ||||||||||||||
| Equity securities (2) | 6,470 | — | — | — | 6,470 | ||||||||||||||
| Total | $ | 21,210 | $ | 158,154 | $ | 339 | $ | (51,712 | ) | $ | 127,991 | ||||||||
| Liabilities: | |||||||||||||||||||
| Energy commodity derivatives | $ | — | $ | 72,895 | $ | — | $ | (60,099 | ) | $ | 12,796 | ||||||||
| Level 3 energy commodity derivatives: | |||||||||||||||||||
| Natural gas exchange agreement | — | — | 1,219 | — | 1,219 | ||||||||||||||
| Power exchange agreement | — | — | 14,780 | (339 | ) | 14,441 | |||||||||||||
| Power option agreement | — | — | 775 | — | 775 | ||||||||||||||
| Foreign currency derivatives | — | 6 | — | (6 | ) | — | |||||||||||||
| Total | $ | — | $ | 72,901 | $ | 16,774 | $ | (60,444 | ) | $ | 29,231 | ||||||||
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| Level 1 | Level 2 | Level 3 | Counterparty and Cash Collateral Netting (1) | Total | |||||||||||||||
| December 31, 2012 | |||||||||||||||||||
| Assets: | |||||||||||||||||||
| Energy commodity derivatives | $ | — | $ | 81,640 | $ | — | $ | (76,408 | ) | $ | 5,232 | ||||||||
| Level 3 energy commodity derivatives: | |||||||||||||||||||
| Power exchange agreement | — | — | 385 | (385 | ) | — | |||||||||||||
| Foreign currency derivatives | — | 7 | — | (7 | ) | — | |||||||||||||
| Interest rate swaps | — | 7,265 | — | — | 7,265 | ||||||||||||||
| Investments and funds held for clients: | |||||||||||||||||||
| Money market funds | 15,084 | — | — | — | 15,084 | ||||||||||||||
| Securities available for sale: | |||||||||||||||||||
| U.S. government agency | — | 48,496 | — | — | 48,496 | ||||||||||||||
| Municipal | — | 848 | — | — | 848 | ||||||||||||||
| Corporate fixed income – financial | — | 5,026 | — | — | 5,026 | ||||||||||||||
| Corporate fixed income – industrial | — | 3,936 | — | — | 3,936 | ||||||||||||||
| Certificate of deposits | — | 1,015 | — | — | 1,015 | ||||||||||||||
| Funds held in trust account of Spokane Energy | 1,600 | — | — | — | 1,600 | ||||||||||||||
| Deferred compensation assets: | |||||||||||||||||||
| Fixed income securities (2) | 2,010 | — | — | — | 2,010 | ||||||||||||||
| Equity securities (2) | 5,955 | — | — | — | 5,955 | ||||||||||||||
| Total | $ | 24,649 | $ | 148,233 | $ | 385 | $ | (76,800 | ) | $ | 96,467 | ||||||||
| Liabilities: | |||||||||||||||||||
| Energy commodity derivatives | $ | — | $ | 119,390 | $ | — | $ | (86,115 | ) | $ | 33,275 | ||||||||
| Level 3 energy commodity derivatives: | |||||||||||||||||||
| Natural gas exchange agreement | — | — | 2,379 | — | 2,379 | ||||||||||||||
| Power exchange agreement | — | — | 19,077 | (385 | ) | 18,692 | |||||||||||||
| Power option agreement | — | — | 1,480 | — | 1,480 | ||||||||||||||
| Foreign currency derivatives | — | 34 | — | (7 | ) | 27 | |||||||||||||
| Interest rate swaps | — | 1,406 | — | — | 1,406 | ||||||||||||||
| Total | $ | — | $ | 120,830 | $ | 22,936 | $ | (86,507 | ) | $ | 57,259 | ||||||||
| (1) | The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and receivables for cash collateral held or placed with these same counterparties. |
| (2) | These assets are trading securities and are included in other property and investments-net on the Consolidated Balance Sheets. |
Avista Corp. enters into forward contracts to purchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. These contracts are entered into as part of Avista Corp.’s management of loads and resources and certain contracts are considered derivative instruments. The difference between the amount of derivative assets and liabilities disclosed in respective levels and the amount of derivative assets and liabilities disclosed on the Consolidated Balance Sheets is due to netting arrangements with certain counterparties. The Company uses quoted market prices and forward price curves to estimate the fair value of utility derivative commodity instruments included in Level 2. In particular, electric derivative valuations are performed using broker quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange (NYMEX) pricing for similar instruments, adjusted for basin differences, using broker quotes. Where observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2.
For securities available for sale (held at Ecova) Ecova uses a nationally recognized third party to obtain fair value and reviews these prices for accuracy using a variety of market tools and analysis. Ecova’s pricing vendor uses a generic model which uses standard inputs, including (listed in order of priority for use) benchmark yields, reported trades, broker/dealer quotes, issuer
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spreads, two-sided markets, benchmark securities, market bids/offers and other reference data. The pricing vendor also monitors market indicators, as well as industry and economic events. All securities available for sale were deemed Level 2.
Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan. These funds consist of actively traded equity and bond funds with quoted prices in active markets. The balance disclosed in the table above excludes cash and cash equivalents of $0.7 million as of December 31, 2013 and $0.8 million as of December 31, 2012.
Level 3 Fair Value
For the power exchange agreement, the Company compares the Level 2 brokered quotes and forward price curves described above to an internally developed forward price which is based on the average operating and maintenance (O&M) charges from four surrogate nuclear power plants around the country for the current year. Because the nuclear power plant O&M charges are only known for one year, all forward years are estimated assuming an annual escalation. In addition to the forward price being estimated using unobservable inputs, the Company also estimates the volumes of the transactions that will take place in the future based on historical average transaction volumes per delivery year (November to April). Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Generally, a change in the current year O&M charges for the surrogate plants is accompanied by a directionally similar change in O&M charges in future years. There is generally not a correlation between external market prices and the O&M charges used to develop the internal forward price.
For the power commodity option agreement, the Company uses the Black-Scholes-Merton valuation model to estimate the fair value, and this model includes significant inputs not observable or corroborated in the market. These inputs include 1) the strike price (which is an internally derived price based on a combination of generation plant heat rate factors, natural gas market pricing, delivery and other O&M charges, 2) estimated delivery volumes for years beyond 2014, and 3) volatility rates for periods beyond October 2016. Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Generally, changes in overall commodity market prices and volatility rates are accompanied by directionally similar changes in the strike price and volatility assumptions used in the calculation.
For the natural gas commodity exchange agreement, the Company uses the same Level 2 brokered quotes described above; however, the Company also estimates the purchase and sales volumes (within contractual limits) as well as the timing of those transactions. Changing the timing of volume estimates changes the timing of purchases and sales, impacting which brokered quote is used. Because the brokered quotes can vary significantly from period to period, the unobservable estimates of the timing and volume of transactions can have a significant impact on the calculated fair value. The Company currently estimates volumes and timing of transactions based on a most likely scenario using historical data. Historically, the timing and volume of transactions have not been highly correlated with market prices and market volatility. As of December 31, 2013, all contractual purchases have been made by Avista Corp. under the natural gas commodity exchange agreement; therefore, the Company no longer estimates forward purchase volumes and forward purchase prices as these are not significant inputs to the calculation.
The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of December 31, 2013 (dollars in thousands):
| Fair Value (Net) at | ||||||||||
| December 31, 2013 | Valuation Technique | Unobservable Input | Range | |||||||
| Power exchange agreement | $ | (14,441 | ) | Surrogate facility pricing | O&M charges | $30.18-$53.90/MWh (1) | ||||
Escalation factor | 3% - 2014 to 2019 | |||||||||
| Transaction volumes | 234,064 - 397,116 MWhs | |||||||||
Power option agreement | (775 | ) | Black-Scholes- Merton | Strike price | $55.62/MWh - 2016 | |||||
| $65.31/MWh - 2019 | ||||||||||
| Delivery volumes | 157,517 - 287,147 MWhs | |||||||||
| Volatility rates | 0.20 (2) | |||||||||
Natural gas exchange agreement | (1,219 | ) | Internally derived weighted average cost of gas | Forward purchase prices | (3) | |||||
| Forward sales prices | $3.98 - $4.57/mmBTU | |||||||||
| Purchase volumes | (3) | |||||||||
| Sales volumes | 150,000 - 310,000 mmBTUs | |||||||||
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(1) The average O&M charges for the delivery year beginning in November 2013 were $40.93 per MWh. For rate-making purposes the average O&M calculations vary slightly between regulatory jurisdictions. For Washington, the average O&M charges were $42.44 and the average O&M charges for Idaho were $40.93 for the delivery year beginning in 2013.
(2) The estimated volatility rate of 0.20 is compared to actual quoted volatility rates of 0.31 for 2014 to 0.20 in October 2016.
(3) As of December 31, 2013, all contractual purchases have been made by Avista Corp. under the original natural gas exchange agreement; therefore, the Company did not estimate forward purchase volumes and forward purchase prices as these are not significant inputs to the calculation at December 31, 2013. On January 31, 2014, the Company executed an extension to this agreement; therefore, during the first quarter of 2014, forward purchase volumes and forward purchase prices will again be a significant input to the calculation and the Company will resume estimating these amounts.
Avista Corp.'s risk management team and accounting team are responsible for developing the valuation methods described above and both groups report to the Chief Financial Officer. The valuation methods, the significant inputs, and the resulting fair values described above are reviewed on at least a quarterly basis by the risk management team and the accounting team to ensure they provide a reasonable estimate of fair value each reporting period.
The following table presents activity for energy commodity derivative assets (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the years ended December 31 (dollars in thousands):
| Natural Gas Exchange Agreement | Power Exchange Agreement | Power Option Agreement | Total | ||||||||||||
| Year ended December 31, 2013: | |||||||||||||||
| Balance as of January 1, 2013 | $ | (2,379 | ) | $ | (18,692 | ) | $ | (1,480 | ) | $ | (22,551 | ) | |||
| Total gains or losses (realized/unrealized): | |||||||||||||||
| Included in net income | — | — | — | — | |||||||||||
| Included in other comprehensive income | — | — | — | — | |||||||||||
| Included in regulatory assets/liabilities (1) | 2,298 | 1,017 | 705 | 4,020 | |||||||||||
| Purchases | — | — | — | — | |||||||||||
| Issuance | — | — | — | — | |||||||||||
| Settlements | (1,138 | ) | 3,234 | — | 2,096 | ||||||||||
| Transfers to/from other categories | — | — | — | — | |||||||||||
| Ending balance as of December 31, 2013 | $ | (1,219 | ) | $ | (14,441 | ) | $ | (775 | ) | $ | (16,435 | ) | |||
| Year ended December 31, 2012: | |||||||||||||||
| Balance as of January 1, 2012 | $ | (1,688 | ) | $ | (9,910 | ) | $ | (1,260 | ) | $ | (12,858 | ) | |||
| Total gains or losses (realized/unrealized): | |||||||||||||||
| Included in net income | — | — | — | — | |||||||||||
| Included in other comprehensive income | — | — | — | — | |||||||||||
| Included in regulatory assets/liabilities (1) | 343 | (15,236 | ) | (220 | ) | (15,113 | ) | ||||||||
| Purchases | — | — | — | — | |||||||||||
| Issuance | — | — | — | — | |||||||||||
| Settlements | (1,034 | ) | 6,454 | — | 5,420 | ||||||||||
| Transfers from other categories | — | — | — | — | |||||||||||
| Ending balance as of December 31, 2012 | $ | (2,379 | ) | $ | (18,692 | ) | $ | (1,480 | ) | $ | (22,551 | ) | |||
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| Natural Gas Exchange Agreement | Power Exchange Agreement | Power Option Agreement | Total | ||||||||||||
| Year ended December 31, 2011: | |||||||||||||||
| Balance as of January 1, 2011 | $ | — | $ | 15,793 | $ | (2,334 | ) | $ | 13,459 | ||||||
| Total gains or losses (realized/unrealized): | |||||||||||||||
| Included in net income | — | — | — | — | |||||||||||
| Included in other comprehensive income | — | — | — | — | |||||||||||
| Included in regulatory assets/liabilities (1) | 2,621 | (28,571 | ) | 1,074 | (24,876 | ) | |||||||||
| Purchases | — | — | — | — | |||||||||||
| Issuance | — | — | — | — | |||||||||||
| Settlements | 95 | 2,868 | — | 2,963 | |||||||||||
| Transfers from other categories (2) | (4,404 | ) | — | — | (4,404 | ) | |||||||||
| Ending balance as of December 31, 2011 | $ | (1,688 | ) | $ | (9,910 | ) | $ | (1,260 | ) | $ | (12,858 | ) | |||
| (1) | The UTC and the IPUC issued accounting orders authorizing Avista Corp. to offset commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of delivery. The orders provide for Avista Corp. to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Consolidated Statements of Income. Realized gains or losses are recognized in the period of delivery, subject to approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in adjustments to retail rates through purchased gas cost adjustments, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rates cases. |
| (2) | A derivative contract was reclassified from Level 2 to Level 3 during 2011 due to a particular unobservable input becoming more significant to the fair value measurement. There were not any reclassifications between Level 1 and Level 2. The Company's policy is to reclassify identified items as of the end of the reporting period. |
NOTE 17. COMMON STOCK
The Company has a Direct Stock Purchase and Dividend Reinvestment Plan under which the Company’s shareholders may automatically reinvest their dividends and make optional cash payments for the purchase of the Company’s common stock at current market value. Shares issued under this plan in 2013, 2012 and 2011 are disclosed in the Consolidated Statements of Equity and Redeemable Noncontrolling Interests.
The payment of dividends on common stock could be limited by:
| • | certain covenants applicable to preferred stock (when outstanding) contained in the Company’s Restated Articles of Incorporation, as amended (currently there are no preferred shares outstanding), |
| • | certain covenants applicable to the Company's outstanding long-term debt and committed line of credit agreements (see Item 7. Management's Discussion and Analysis - "Capital Resources" for compliance with these covenants), and |
| • | the hydroelectric licensing requirements of section 10(d) of the FPA (see Note 1). |
The Company declared the following dividends for the year ended December 31:
| 2013 | 2012 | 2011 | |||||||||
| Dividends paid per common share | $ | 1.22 | $ | 1.16 | $ | 1.10 | |||||
In August 2012, the Company entered into two sales agency agreements under which the Company may sell up to 2,726,390 shares of its common stock from time to time. There were no shares issued under these agreements during 2013 and as of December 31, 2013, the Company had 1,795,199 shares available to be issued under these agreements.
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Shares issued under sales agency agreements were as follows in the year ended December 31:
| 2013 | 2012 | 2011 | ||||||
| Shares issued under sales agency agreement | — | 931,191 | 807,000 | |||||
The Company has 10 million authorized shares of preferred stock. The Company did not have any preferred stock outstanding as of December 31, 2013 and 2012.
NOTE 18. EARNINGS PER COMMON SHARE ATTRIBUTABLE TO AVISTA CORPORATION SHAREHOLDERS
The following table presents the computation of basic and diluted earnings per common share attributable to Avista Corporation shareholders for the years ended December 31 (in thousands, except per share amounts):
| 2013 | 2012 | 2011 | |||||||||
| Numerator: | |||||||||||
| Net income attributable to Avista Corporation shareholders | $ | 111,077 | $ | 78,210 | $ | 100,224 | |||||
| Subsidiary earnings adjustment for dilutive securities | (229 | ) | (38 | ) | (473 | ) | |||||
| Adjusted net income attributable to Avista Corporation shareholders for computation of diluted earnings per common share | $ | 110,848 | $ | 78,172 | $ | 99,751 | |||||
| Denominator: | |||||||||||
| Weighted-average number of common shares outstanding-basic | 59,960 | 59,028 | 57,872 | ||||||||
| Effect of dilutive securities: | |||||||||||
| Performance and restricted stock awards | 37 | 162 | 172 | ||||||||
| Stock options | — | 11 | 48 | ||||||||
| Weighted-average number of common shares outstanding-diluted | 59,997 | 59,201 | 58,092 | ||||||||
| Earnings per common share attributable to Avista Corporation shareholders: | |||||||||||
| Basic | $ | 1.85 | $ | 1.32 | $ | 1.73 | |||||
| Diluted | $ | 1.85 | $ | 1.32 | $ | 1.72 | |||||
There were no shares excluded from the calculation because they were antidilutive. All stock options had exercise prices which were less than the average market price of Avista Corp. common stock during the respective period.
NOTE 19. STOCK COMPENSATION PLANS
Avista Corp. (Excluding Ecova)
1998 Plan
In 1998, the Company adopted, and shareholders approved, the Long-Term Incentive Plan (1998 Plan). Under the 1998 Plan, certain key employees, officers and non-employee directors of the Company and its subsidiaries may be granted stock options, stock appreciation rights, stock awards (including restricted stock) and other stock-based awards and dividend equivalent rights. The Company has available a maximum of 4.5 million shares of its common stock for grant under the 1998 Plan. As of December 31, 2013, 0.9 million shares were remaining for grant under this plan.
2000 Plan
In 2000, the Company adopted a Non-Officer Employee Long-Term Incentive Plan (2000 Plan), which was not required to be approved by shareholders. The provisions of the 2000 Plan are essentially the same as those under the 1998 Plan, except for the exclusion of non-employee directors and executive officers of the Company. The Company has available a maximum of 2.5 million shares of its common stock for grant under the 2000 Plan. However, the Company currently does not plan to issue any further options or securities under the 2000 Plan. As of December 31, 2013, 1.9 million shares were remaining for grant under this plan.
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Stock Compensation
The Company records compensation cost relating to share-based payment transactions in the financial statements based on the fair value of the equity or liability instruments issued. The Company recorded stock-based compensation expense (included in other operating expenses) and income tax benefits in the Consolidated Statements of Income of the following amounts for the years ended December 31 (dollars in thousands):
| 2013 | 2012 | 2011 | |||||||||
| Stock-based compensation expense | $ | 6,218 | $ | 5,792 | $ | 5,756 | |||||
| Income tax benefits | 2,176 | 2,027 | 2,014 | ||||||||
Stock Options
The following summarizes stock options activity under the 1998 Plan and the 2000 Plan for the years ended December 31:
| 2013 | 2012 | 2011 | |||||||||
| Number of shares under stock options: | |||||||||||
| Options outstanding at beginning of year | 3,000 | 92,499 | 201,674 | ||||||||
| Options granted | — | — | — | ||||||||
| Options exercised | (3,000 | ) | (89,499 | ) | (107,575 | ) | |||||
| Options canceled | — | — | (1,600 | ) | |||||||
| Options outstanding and exercisable at end of year | — | 3,000 | 92,499 | ||||||||
| Weighted average exercise price: | |||||||||||
| Options exercised | $ | 12.41 | $ | 10.63 | $ | 12.25 | |||||
| Options canceled | $ | — | $ | — | $ | 11.80 | |||||
| Options outstanding and exercisable at end of year | $ | — | $ | 12.41 | $ | 10.69 | |||||
| Cash received from options exercised (in thousands) | $ | 37 | $ | 951 | $ | 1,318 | |||||
| Intrinsic value of options exercised (in thousands) | $ | 40 | $ | 1,349 | $ | 1,279 | |||||
| Intrinsic value of options outstanding (in thousands) | $ | — | $ | 35 | $ | 1,393 | |||||
There are no longer any stock options outstanding as of December 31, 2013 and the Company does not have any plans to issue additional stock options in the near future.
Restricted Shares
Restricted share awards vest in equal thirds each year over a three-year period and are payable in Avista Corp. common stock at the end of each year if the service condition is met. In addition to the service condition, the Company must meet a return on equity target in order for the CEO’s restricted shares to vest. During the vesting period, employees are entitled to dividend equivalents which are paid when dividends on the Company’s common stock are declared. Restricted stock is valued at the close of market of the Company’s common stock on the grant date. The weighted average remaining vesting period for the Company’s restricted shares outstanding as of December 31, 2013 was 0.7 years. The following table summarizes restricted stock activity for the years ended December 31:
| 2013 | 2012 | 2011 | |||||||||
| Unvested shares at beginning of year | 117,118 | 93,482 | 84,134 | ||||||||
| Shares granted | 44,556 | 70,281 | 50,618 | ||||||||
| Shares canceled | (1,802 | ) | (790 | ) | (431 | ) | |||||
| Shares vested | (55,456 | ) | (45,855 | ) | (40,839 | ) | |||||
| Unvested shares at end of year | 104,416 | 117,118 | 93,482 | ||||||||
| Weighted average fair value at grant date | $ | 26.04 | $ | 25.83 | $ | 23.06 | |||||
| Unrecognized compensation expense at end of year (in thousands) | $ | 1,199 | $ | 1,428 | $ | 932 | |||||
| Intrinsic value, unvested shares at end of year (in thousands) | $ | 2,943 | $ | 2,824 | $ | 2,407 | |||||
| Intrinsic value, shares vested during the year (in thousands) | $ | 1,363 | $ | 1,173 | $ | 934 | |||||
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Performance Shares
Performance share awards vest after a period of three years and are payable in cash or Avista Corp. common stock at the end of the three-year period. Performance share awards entitle the recipients to dividend equivalent rights, are subject to forfeiture under certain circumstances, and are subject to meeting a specific performance criterion. Based on the attainment of the performance criterion, the amount of cash paid or common stock issued will range from 0 to 200 percent of the performance shares granted depending on the change in the value of the Company’s common stock relative to an external benchmark. Dividend equivalent rights are accumulated and paid out only on shares that eventually vest.
Performance share awards entitle the grantee to shares of common stock or cash payable once the service condition is satisfied. Based on attainment of the performance criteria, grantees may receive 0 to 200 percent of the original shares granted. The performance criterion used is the Company’s Total Shareholder Return performance over a three-year period as compared against other utilities; this is considered a market-based condition. Performance shares may be settled in common stock or cash at the discretion of the Company. Historically, the Company has settled these awards through issuance of stock and intends to continue this practice. These awards vest at the end of the three-year period. Performance shares are equity awards with a market-based condition, which results in the compensation cost for these awards being recognized over the requisite service period, provided that the requisite service period is rendered, regardless of when, if ever, the market condition is satisfied.
The Company measures (at the grant date) the estimated fair value of performance shares awarded. The fair value of each performance share award was estimated on the date of grant using a statistical model that incorporates the probability of meeting performance targets based on historical returns relative to a peer group. Expected volatility was based on the historical volatility of Avista Corp. common stock over a three-year period. The expected term of the performance shares is three years based on the performance cycle. The risk-free interest rate was based on the U.S. Treasury yield at the time of grant. The compensation expense on these awards will only be adjusted for changes in forfeitures.
The following summarizes the weighted average assumptions used to determine the fair value of performance shares and related compensation expense as well as the resulting estimated fair value of performance shares granted:
| 2013 | 2012 | 2011 | |||||||||
| Risk-free interest rate | 0.4 | % | 0.3 | % | 1.2 | % | |||||
| Expected life, in years | 3 | 3 | 3 | ||||||||
| Expected volatility | 19.1 | % | 22.7 | % | 26.9 | % | |||||
| Dividend yield | 4.6 | % | 4.5 | % | 4.7 | % | |||||
| Weighted average grant date fair value (per share) | $ | 23.30 | $ | 26.06 | $ | 20.79 | |||||
The fair value includes both performance shares and dividend equivalent rights.
The following summarizes performance share activity:
| 2013 | 2012 | 2011 | |||||||||
| Opening balance of unvested performance shares | 359,700 | 351,345 | 325,700 | ||||||||
| Performance shares granted | 175,000 | 181,000 | 184,600 | ||||||||
| Performance shares canceled | (13,298 | ) | (4,544 | ) | (2,177 | ) | |||||
| Performance shares vested | (176,718 | ) | (168,101 | ) | (156,778 | ) | |||||
| Ending balance of unvested performance shares | 344,684 | 359,700 | 351,345 | ||||||||
| Intrinsic value of unvested performance shares (in thousands) | $ | 9,717 | $ | 8,672 | $ | 9,047 | |||||
| Unrecognized compensation expense (in thousands) | $ | 3,651 | $ | 3,800 | $ | 2,991 | |||||
The weighted average remaining vesting period for the Company’s performance shares outstanding as of December 31, 2013 was 1.5 years. Unrecognized compensation expense as of December 31, 2013 includes only the amount attributable to the equity portion of the performance share awards and will be recognized during 2014 and 2015.
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The following summarizes the impact of the market condition on the vested performance shares:
| 2013 | 2012 | 2011 | |||||||||
| Performance shares vested | 176,718 | 168,101 | 156,778 | ||||||||
| Impact of market condition on shares vested | (176,718 | ) | (168,101 | ) | (15,678 | ) | |||||
| Shares of common stock earned | — | — | 141,100 | ||||||||
| Intrinsic value of common stock earned (in thousands) | $ | — | $ | — | $ | 3,633 | |||||
Shares earned under this plan are distributed to participants in the quarter following vesting.
Outstanding performance share awards include a dividend component that is paid in cash. This component of the performance share grants is accounted for as a liability award. These liability awards are revalued on a quarterly basis taking into account the number of awards outstanding, historical dividend rate, and the change in the value of the Company’s common stock relative to an external benchmark. Over the life of these awards, the cumulative amount of compensation expense recognized will match the actual cash paid. As of December 31, 2013 and 2012, the Company had recognized cumulative compensation expense and a liability of $0.9 million and $0.7 million related to the dividend component on the outstanding and unvested performance share grants.
Ecova
Ecova has an employee stock incentive plan under which certain employees of Ecova may be granted options to purchase shares of Ecova at prices no less than the estimated fair value on the date of grant. The fair value of each employee option grant is estimated on the date of grant using the Black-Scholes option-pricing model and certain assumptions deemed reasonable by management. Options outstanding under this plan generally vest over periods of four years from the date granted and terminate ten years from the date granted. The employee stock incentive plan was amended in 2013 to clarify certain language in the document; however, there were no material changes to the overall terms of the plan. Unrecognized compensation expense for stock based awards at Ecova was $2.1 million as of December 31, 2013, which will be expensed over a weighted average period of two years.
In 2007, Ecova amended its employee stock incentive plan to provide an annual window at which time holders of common stock can put their shares back to Ecova providing the shares are held for a minimum of six months. In 2009, Ecova amended its employee stock incentive plan to make this put feature optional at the Board's discretion for future stock option grants. Stock is reacquired at fair market value less exercise price at the date of reacquisition. The following amounts of common stock were repurchased from Ecova employees during the years ended December 31 (dollars in thousands):
| 2013 | 2012 | 2011 | |||||||||
| Stock repurchased from Ecova employees | $ | 405 | $ | 599 | $ | 464 | |||||
NOTE 20. COMMITMENTS AND CONTINGENCIES
In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters, including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve litigation or other contested proceedings. For all such matters, the Company intends to vigorously protect and defend its interests and pursue its rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other contested proceedings are inherently subject to numerous uncertainties. For matters that affect Avista Utilities’ operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process.
Federal Energy Regulatory Commission Inquiry
In April 2004, the Federal Energy Regulatory Commission (FERC) approved the contested Agreement in Resolution of Section 206 Proceeding (Agreement in Resolution) between Avista Corp. doing business as Avista Utilities, Avista Energy and the FERC's Trial Staff which stated that there was: (1) no evidence that any executives or employees of Avista Utilities or Avista Energy knowingly engaged in or facilitated any improper trading strategy during 2000 and 2001; (2) no evidence that Avista Utilities or Avista Energy engaged in any efforts to manipulate the western energy markets during 2000 and 2001; and (3) no finding that Avista Utilities or Avista Energy withheld relevant information from the FERC's inquiry into the western energy markets for 2000 and 2001 (Trading Investigation). The FERC’s decisions approving the Agreement in Resolution are pending before the United States Court of Appeals for the Ninth Circuit (Ninth Circuit). In May 2004, the FERC provided notice that Avista Energy was no longer subject to an investigation reviewing certain bids above $250 per MW in the short-term energy
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markets operated by the California Independent System Operator (CalISO) and the California Power Exchange (CalPX) from May 1, 2000 to October 2, 2000 (Bidding Investigation). That matter is also pending before the Ninth Circuit.
As discussed in "California Refund Proceeding" below, in November 2013, Avista Utilities and Avista Energy arrived at a settlement in principle with Pacific Gas & Electric (PG&E), Southern California Edison, San Diego Gas & Electric, the California Attorney General (AG), the California Department of Water Resources (CERS), and the California Public Utilities Commission that would resolve these matters and obviate the need for further litigation. The Company expects to file the settlement at the FERC for its approval no later than March of 2014. The Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or cash flows.
California Refund Proceeding
In July 2001, the FERC ordered an evidentiary hearing to determine the amount of refunds due to California energy buyers for purchases made in the spot markets operated by the CalISO and the CalPX during the period from October 2, 2000 to June 20, 2001 (Refund Period). Proposed refunds are based on the calculation of mitigated market clearing prices for each hour. The FERC ruled that if the refunds required by the formula would cause a seller to recover less than its actual costs for the Refund Period, sellers may document these costs and limit their refund liability commensurately. In 2011, the FERC approved Avista Energy’s cost filing, a decision that is now before the Ninth Circuit.
In August 2006, the Ninth Circuit remanded to the FERC its decision not to consider an FPA section 309 remedy for tariff violations prior to October 2, 2000. In May 2011, the FERC clarified the issues set for hearing for the period May 1, 2000 - October 1, 2000 (Summer Period): (1) which market practices and behaviors constitute a violation of the then-current CalISO, CalPX, and individual seller's tariffs and FERC orders; (2) whether any of the sellers named as respondents in this proceeding engaged in those tariff violations; and (3) whether any such tariff violations affected the market clearing price. The FERC also gave the California parties an opportunity to show that exchange transactions with the CalISO during the Refund Period were not just and reasonable. During a FERC hearing in 2012, the Presiding Administrative Law Judge (ALJ) issued a partial initial decision granting Avista Utilities' motion for summary disposition, based on the stipulation by the California Parties that there are no allegations of tariff violations made against Avista Utilities in this proceeding and therefore no tariff violations by Avista Utilities that affected the market clearing price in any hour during the Summer Period. On November 2, 2012, the FERC issued an order affirming the partial initial decision and dismissing Avista Utilities from the proceeding, thereby terminating all claims against Avista Utilities for the Summer Period. In the same order, the FERC also held that a market-wide remedy would not be appropriate with regard to any respondent during the Summer Period. The FERC stated that it is clear that the Ninth Circuit did not mandate a specific remedy on remand and, instead, left it to the FERC's discretion to determine which remedy would be appropriate. On February 15, 2013, the ALJ issued an initial decision ruling that the California Parties met their burden in the case against Avista Energy by relying on “screens” that identified transactions that potentially could have signified tariff violations. The initial decision did not discuss evidence offered by Avista Energy, on an hour-by-hour basis, rebutting the alleged violations. With respect to Avista Energy's one exchange transaction with the CalISO during the Refund Period, the judge made no findings with respect to the justness and reasonableness of that transaction, but nonetheless determined that Avista Energy owed approximately $0.2 million in refunds with regard to the transaction.
In November of 2013, Avista Utilities and Avista Energy arrived at a settlement in principle that would resolve this matter which obviates the need for further litigation. The 2001 bankruptcy of PG&E resulted in a default on its payment obligations to the CalPX, and as a result, Avista Energy has not been paid for all of its sales during the Refund Period. Those funds have been held in escrow accounts pending resolution of this proceeding. The settlement would return $15 million of Avista Energy’s receivable to Avista Energy, with the balance of the Avista Energy receivable flowing to the purchasers associated with the hourly transactions at issue. There is no admission of wrongdoing on the part of the settling parties, and thus it is further agreed that no part of the refund payment by Avista Energy constitutes a fine or a penalty. The settlement resolves all claims for alleged overcharges during the Summer and Refund Periods in the California Refund Proceeding, and in the Pacific Northwest Refund Proceeding, for sales made to CERS, as discussed below. The settlement also includes settlement of the Federal Energy Regulatory Commission Inquiry, the Pacific Northwest Refund Proceeding, and the California Attorney General Complaint (the "Lockyer Complaint").
The settlement is subject to approval by the FERC. The Company expects to file the settlement at the FERC for its approval no later than March of 2014. The Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or cash flows.
Pacific Northwest Refund Proceeding
In July 2001, the FERC initiated a preliminary evidentiary hearing to develop a factual record as to whether prices for spot market sales of wholesale energy in the Pacific Northwest between December 25, 2000 and June 20, 2001 were just and reasonable. In June 2003, the FERC terminated the Pacific Northwest refund proceedings, after finding that the equities do not justify the imposition of refunds. In August 2007, the Ninth Circuit found that the FERC, in denying the request for refunds,
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had failed to take into account new evidence of market manipulation in the California energy market and its potential ties to the Pacific Northwest energy market and that such failure was arbitrary and capricious and, accordingly, remanded the case to the FERC, stating that the FERC's findings must be reevaluated in light of the evidence. The Ninth Circuit expressly declined to direct the FERC to grant refunds. On October 3, 2011, the FERC issued an Order on Remand, finding that, in light of the Ninth Circuit's remand order, additional procedures are needed to address possible unlawful activity that may have influenced prices in the Pacific Northwest spot market during the period from December 25, 2000 through June 20, 2001. The Order on Remand established an evidentiary, trial-type hearing before an ALJ, and reopened the record to permit parties to present evidence of unlawful market activity. The Order on Remand stated that parties seeking refunds must submit evidence demonstrating that specific unlawful market activity occurred, and must demonstrate that such activity directly affected negotiations with respect to the specific contract rate about which they complain. Simply alleging a general link between the dysfunctional spot market in California and the Pacific Northwest spot market will not be sufficient to establish a causal connection between a particular seller's alleged unlawful activities and the specific contract negotiations at issue.
On July 11, 2012, Avista Energy and Avista Utilities filed settlements of all issues in this docket with regard to the claims made by the City of Tacoma, which the FERC approved. The two remaining direct claimants against Avista Utilities and Avista Energy in this proceeding are the City of Seattle, Washington (Seattle), and the California AG (on behalf of CERS).
On April 5, 2013, the FERC issued an Order on Rehearing expanding the temporal scope of the proceeding to permit parties to submit evidence on transactions during the period from January 1, 2000 through and including June 20, 2001.
On April 11, 2013, the California Parties filed a petition for review of the October 3, 2011 Order on Remand, and the April 5, 2013 Order on Rehearing, in the Ninth Circuit. Seattle filed a petition for review of the same orders on April 26, 2013. On May 22, 2013, the Ninth Circuit issued an order consolidating the California Parties' and Seattle's petitions for review with respect to the Order on Remand and the Order on Rehearing.
The hearing before an ALJ began on August 27, 2013, and briefing is now concluded. The ALJ’s initial decision is anticipated on or before March 18, 2014.
As discussed in "California Refund Proceeding" above, in November 2013, Avista Utilities and Avista Energy arrived at a settlement in principle that would resolve these matters with regard to the CERS claims. Seattle continues to pursue claims against both Avista Utilities and Avista Energy, and if, refunds are ordered by the FERC with regard to any particular contract with Seattle, Avista Utilities and Avista Energy could be liable to make payments. The Company cannot predict the outcome of this proceeding or the amount of any refunds that Avista Utilities or Avista Energy could be ordered to make. Therefore, the Company cannot predict the potential impact the outcome of this matter could ultimately have on the Company's results of operations, financial condition or cash flows.
California Attorney General Complaint (the “Lockyer Complaint”)
In May 2002, the FERC conditionally dismissed a complaint filed in March 2002 by the California AG that alleged violations of the FPA by the FERC and all sellers (including Avista Corp. and its subsidiaries) of electric power and energy into California. The complaint alleged that the FERC's adoption and implementation of market-based rate authority was flawed and, as a result, individual sellers should refund the difference between the rate charged and a just and reasonable rate. In May 2002, the FERC issued an order dismissing the complaint. In September 2004, the Ninth Circuit upheld the FERC's market-based rate authority, but held that the FERC erred in ruling that it lacked authority to order refunds for violations of its reporting requirement. The Court remanded the case for further proceedings, which ultimately resulted in summary disposition at the FERC in favor of Avista Utilities and Avista Energy. The proceeding is now before the Ninth Circuit.
As discussed in "California Refund Proceeding" above, in November 2013, Avista Utilities and Avista Energy arrived at a settlement in principle that would resolve these matters and obviate the need for further litigation. The settlement is subject to approval by the FERC. The Company expects to file the settlement at the FERC for its approval no later than March of 2014. The Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or cash flows.
Colstrip Generating Project - Complaint Alleging Water Pollution
In March 2007, two families that own property near the holding ponds from Units 3 & 4 of the Colstrip Generating Project (Colstrip) filed a complaint against the owners of Colstrip and Hydrometrics, Inc. in Montana District Court. Avista Corp. owns a 15 percent interest in Units 3 & 4 of Colstrip. The plaintiffs alleged that the holding ponds and remediation activities adversely impacted their property. They alleged contamination, decrease in water tables, reduced flow of streams on their property and other similar impacts to their property. They also sought punitive damages, attorneys' fees, an order by the court to remove certain ponds, and the forfeiture of profits earned from the generation of Colstrip. In September 2010, the owners of Colstrip filed a motion with the court to enforce a settlement agreement that would resolve all issues between the parties. In October 2011 the court issued an order which enforced the settlement agreement. All subsequent appeals by the plaintiffs of the
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court’s decision were denied and in 2013 a motion to dismiss the case was approved by the court. Under the settlement, Avista Corp.'s portion of payment (which was accrued in 2010) to the plaintiffs was not material to its financial condition, results of operations or cash flows.
Sierra Club and Montana Environmental Information Center Complaint Against the Owners of Colstrip
On March 6, 2013, the Sierra Club and Montana Environmental Information Center (MEIC) (collectively "Plaintiffs"), filed a Complaint (Complaint) in the United States District Court for the District of Montana, Billings Division, against the owners of the Colstrip Generating Project (Colstrip). Avista Corp. owns a 15 percent interest in Units 3 & 4 of Colstrip. The other Colstrip co-owners are PPL Montana, Puget Sound Energy, Portland General Electric Company, NorthWestern Energy and PacifiCorp. The Complaint alleges certain violations of the Clean Air Act, including the New Source Review, Title V and opacity requirements. The Plaintiffs request that the Court grant injunctive and declaratory relief, impose civil penalties, require a beneficial environmental project in the areas affected by the alleged air pollution and require payment of Plaintiffs' costs of litigation and attorney fees.
On May 3, 2013, the Colstrip owners and operator filed a partial motion to dismiss, seeking dismissal of 36 of the 39 claims. The Plaintiffs filed their opposition on May 31, 2013, and the owners and operator filed their reply on June 21, 2013. On July 17, 2013, the Court held a preliminary pretrial conference, and on July 18, 2013, the Court issued an Order establishing a procedural schedule and deadlines.
On September 12, 2013, the Plaintiffs filed Plaintiffs’ First Motion for Partial Summary Judgment on the Applicable Method for Calculating Emission Increases from Modifications Made to the Colstrip Power Plant. The Colstrip Owners and Operator Response filed their reply on November 15, 2013.
On September 27, 2013, the Plaintiffs filed an Amended Complaint. The Amended Complaint withdrew from the original Complaint fifteen claims related to seven pre-January 1, 2001 Colstrip maintenance projects, upgrade projects and work projects and claims alleging violations of Title V and opacity requirements. The Amended Complaint alleges certain violations of the Clean Air Act and the New Source Review and adds claims with respect to post-January 1, 2001 Colstrip projects. The Plaintiffs request that the Court grant injunctive and declaratory relief, order remediation of alleged environmental damage, impose civil penalties, require a beneficial environmental project in the areas affected by the alleged air pollution and require payment of Plaintiffs’ costs of litigation and attorney fees.
On October 11, 2013, the Colstrip owners and operator filed a motion to dismiss, seeking dismissal of all of Plaintiffs' claims contained in the Amended Complaint. Due to the preliminary nature of the lawsuit, Avista Corporation cannot, at this time, predict the outcome of the matter.
Harbor Oil Inc. Site
Avista Corp. used Harbor Oil Inc. (Harbor Oil) for the recycling of waste oil and non-PCB transformer oil in the late 1980s and early 1990s. In June 2005, the Environmental Protection Agency (EPA) Region 10 provided notification to Avista Corp. and several other parties, as customers of Harbor Oil, that the EPA had determined that hazardous substances were released at the Harbor Oil site in Portland, Oregon and that Avista Corp. and several other parties may be liable for investigation and cleanup of the site under the Comprehensive Environmental Response, Compensation, and Liability Act, commonly referred to as the federal “Superfund” law, which provides for joint and several liability. Six potentially responsible parties, including Avista Corp., signed an Administrative Order on Consent with the EPA on May 31, 2007 to conduct a remedial investigation and feasibility study (RI/FS). Based on the RI/FS submitted to the EPA, the EPA issued a Record of Decision (ROD) which proposes the “No Action Alternative” for the site. Based on the review of its records related to Harbor Oil, the Company does not believe it is a significant contributor to this potential environmental contamination based on the small volume of waste oil it delivered to the Harbor Oil site. As such, and in light of the EPA's ROD, the Company does not expect that this matter will have a material effect on its financial condition, results of operations or cash flows. The Company has expensed its share of the RI/FS ($0.5 million) for this matter.
Spokane River Licensing
The Company owns and operates six hydroelectric plants on the Spokane River. Five of these (Long Lake, Nine Mile, Upper Falls, Monroe Street, and Post Falls) are regulated under one 50-year FERC license issued in June 2009 and are referred to as the Spokane River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. The license incorporated the 4(e) conditions that were included in the December 2008 Settlement Agreement with the United States Department of Interior and the Coeur d’Alene Tribe, as well as the mandatory conditions that were agreed to in the Idaho 401 Water Quality Certifications and in the amended Washington 401 Water Quality Certification.
As part of the Settlement Agreement with the Washington Department of Ecology (Ecology), the Company has participated in the Total Maximum Daily Load (TMDL) process for the Spokane River and Lake Spokane, the reservoir created by Long Lake
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Dam. On May 20, 2010, the EPA approved the TMDL and on May 27, 2010, Ecology filed an amended 401 Water Quality Certification with the FERC for inclusion into the license. The amended 401 Water Quality Certification includes the Company's level of responsibility, as defined in the TMDL, for low dissolved oxygen levels in Lake Spokane. The Company submitted a draft Water Quality Attainment Plan for Dissolved Oxygen to Ecology in May 2012 and this was approved by Ecology in September 2012. This plan was subsequently approved by the FERC. The Company began implementing this plan in 2013, and management believes costs will not be material. On July 16, 2010, the City of Post Falls and the Hayden Area Regional Sewer Board filed an appeal with the United States District Court for the District of Idaho with respect to the EPA's approval of the TMDL. The Company, the City of Coeur d'Alene, Kaiser Aluminum and the Spokane River Keeper subsequently moved to intervene in the appeal. In September 2011, the EPA issued a stay to the litigation that will be in effect until either the permits are issued and all appeals and challenges are complete or the court lifts the stay. The stay is still in effect.
During 2013, through a collaborative process with key stakeholders, a decision was reached to not move forward with a specific capital project to add oxygen to Lake Spokane. At the time of such decision, the Company had expended $1.3 million on the discontinued project. On September 26, 2013 and October 23, 2013, the UTC and IPUC, respectively, issued Orders approving the Company's petition for an accounting order authorizing deferral of costs related to the discontinued project. The Washington portion of the project costs were $0.9 million and this amount has been recorded as a regulatory asset until the next general rate case. The Idaho portion of the costs of $0.5 million was recorded as a regulatory asset during the fourth quarter of 2013 and will be included in the next general rate case. The Company will address the prudence and recovery of these costs in the next Washington and Idaho general rate cases, expected to be filed in 2014.
The UTC and IPUC approved the recovery of licensing costs through the general rate case settlements in 2009. The Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to implementing the license for the Spokane River Project.
Cabinet Gorge Total Dissolved Gas Abatement Plan
Dissolved atmospheric gas levels in the Clark Fork River exceed state of Idaho and federal water quality standards downstream of the Cabinet Gorge Hydroelectric Generating Project (Cabinet Gorge) during periods when excess river flows must be diverted over the spillway. Under the terms of the Clark Fork Settlement Agreement as incorporated in Avista Corp.'s FERC license for the Clark Fork Project, Avista Corp. has worked in consultation with agencies, tribes and other stakeholders to address this issue. In the second quarter of 2011, the Company completed preliminary feasibility assessments for several alternative abatement measures. In 2012, Avista Corp., with the approval of the Clark Fork Management Committee (created under the Clark Fork Settlement Agreement), moved forward to test one of the alternatives by constructing a spill crest modification on a single spill gate. Based on testing in 2013, the modification appears to provide significant Total Dissolved Gas reduction. Further evaluation and design improvements are underway prior to applying this approach to other spill gates. The Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue.
Fish Passage at Cabinet Gorge and Noxon Rapids
In 1999, the USFWS listed bull trout as threatened under the Endangered Species Act. The Clark Fork Settlement Agreement describes programs intended to help restore bull trout populations in the project area. Using the concept of adaptive management and working closely with the USFWS, the Company evaluated the feasibility of fish passage at Cabinet Gorge and Noxon Rapids. The results of these studies led, in part, to the decision to move forward with development of permanent facilities, among other bull trout enhancement efforts. Fishway designs for Cabinet Gorge are still being finalized. Construction cost estimates and schedules will be developed after several remaining issues are resolved, related to Montana's approval of fish transport from Idaho and expected minimum discharge requirements. Fishway design for Noxon Rapids has also been initiated, and is still in early stages.
In January 2010, the USFWS revised its 2005 designation of critical habitat for the bull trout to include the lower Clark Fork River as critical habitat. The Company believes its ongoing efforts through the Clark Fork Settlement Agreement continue to effectively address issues related to bull trout. The Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to fish passage at Cabinet Gorge and Noxon Rapids.
Aluminum Recycling Site
In October 2009, the Company (through its subsidiary Pentzer Venture Holdings II, Inc. (Pentzer)) received notice from Ecology proposing to find Pentzer liable for a release of hazardous substances under the Model Toxics Control Act (MTCA), under Washington state law. Pentzer owns property that adjoins land owned by the Union Pacific Railroad (UPR). UPR leased their property to operators of a facility designated by Ecology as “Aluminum Recycling - Trentwood.” Operators of the UPR property maintained piles of aluminum dross, which designate as a state-only dangerous waste in Washington State. In the
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course of its business, the operators placed a portion of the aluminum dross pile on the property owned by Pentzer. During the second quarter of 2013, the Company completed an agreement with UPR which resolves all liability related to the MTCA action. Through Pentzer Corporation, a wholly-owned subsidiary of the Company, the Company made a one-time payment of $0.1 million and UPR has taken full responsibility for the cleanup activities at the site. Based on information currently known to the Company's management, the Company believes any potential liability related to the site has been resolved, and does not expect this issue will have a material effect on its financial condition, results of operations or cash flows.
Collective Bargaining Agreements
The Company's collective bargaining agreement with the International Brotherhood of Electrical Workers represents approximately 45 percent of all of Avista Utilities' employees. The agreement with the local union in Washington and Idaho representing the majority (approximately 90 percent) of the bargaining unit employees expires in March 2014. Two local agreements in Oregon, which cover approximately 50 employees, expire in March 2014. Negotiations are currently ongoing for these labor agreements.
Other Contingencies
In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company believes that any ultimate liability arising from these actions will not have a material impact on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.
The Company routinely assesses, based on studies, expert analyses and legal reviews, its contingencies, obligations and commitments for remediation of contaminated sites, including assessments of ranges and probabilities of recoveries from other responsible parties who either have or have not agreed to a settlement as well as recoveries from insurance carriers. The Company’s policy is to accrue and charge to current expense identified exposures related to environmental remediation sites based on estimates of investigation, cleanup and monitoring costs to be incurred. For matters that affect Avista Utilities’ operations, the Company seeks, to the extent appropriate, recovery of incurred costs through the ratemaking process.
The Company has potential liabilities under the Endangered Species Act for species of fish that have either already been added to the endangered species list, listed as “threatened” or petitioned for listing. Thus far, measures adopted and implemented have had minimal impact on the Company. However, the Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue.
Under the federal licenses for its hydroelectric projects, the Company is obligated to protect its property rights, including water rights. The state of Montana is examining the status of all water right claims within state boundaries. Claims within the Clark Fork River basin could adversely affect the energy production of the Company’s Cabinet Gorge and Noxon Rapids hydroelectric facilities. The state of Idaho has initiated adjudication in northern Idaho, which will ultimately include the lower Clark Fork River, the Spokane River and the Coeur d’Alene basin. In addition, the state of Washington has indicated an interest in initiating adjudication for the Spokane River basin in the next several years. The Company is and will continue to be a participant in these adjudication processes. The complexity of such adjudications makes each unlikely to be concluded in the foreseeable future. As such, it is not possible for the Company to estimate the impact of any outcome at this time.
NOTE 21. INFORMATION SERVICES CONTRACTS
The Company has information services contracts that expire at various times through 2017. The largest of these contracts provides for increases due to changes in the cost of living index and further provides flexibility in the annual obligation from year-to-year. Total payments under these contracts were as follows for the years ended December 31 (dollars in thousands):
| 2013 | 2012 | 2011 | |||||||||
| Information service contract payments | $ | 12,647 | $ | 13,221 | $ | 13,038 | |||||
The majority of the costs are included in other operating expenses in the Consolidated Statements of Income. The following table details minimum future contractual commitments for these agreements (dollars in thousands):
| 2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | Total | |||||||||||||||||||||
| Contractual obligations | $ | 8,350 | $ | 7,384 | $ | 7,446 | $ | 7,508 | $ | — | $ | — | $ | 30,688 | |||||||||||||
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NOTE 22. AVISTA UTILITIES REGULATORY MATTERS
Regulatory Assets and Liabilities
The following table presents the Company’s regulatory assets and liabilities as of December 31, 2013 (dollars in thousands):
Receiving Regulatory Treatment | ||||||||||||||||||||||
Remaining Amortization Period | (1) Earning A Return | Not Earning A Return | (2) Expected Recovery | Total 2013 | Total 2012 | |||||||||||||||||
| Regulatory Assets: | ||||||||||||||||||||||
| Investment in exchange power-net | 2019 | $ | 13,883 | $ | — | $ | — | $ | 13,883 | $ | 16,333 | |||||||||||
| Regulatory assets for deferred income tax | (3 | ) | 71,421 | — | — | 71,421 | 79,406 | |||||||||||||||
| Regulatory assets for pensions and other postretirement benefit plans | (4 | ) | — | 156,984 | — | 156,984 | 306,408 | |||||||||||||||
| Current regulatory asset for utility derivatives | (5 | ) | — | 10,829 | — | 10,829 | 35,082 | |||||||||||||||
| Unamortized debt repurchase costs | (6 | ) | 19,417 | — | — | 19,417 | 21,635 | |||||||||||||||
| Regulatory asset for settlement with Coeur d’Alene Tribe | 2059 | 49,198 | — | — | 49,198 | 50,509 | ||||||||||||||||
| Demand side management programs | (3 | ) | — | 9,576 | — | 9,576 | 2,579 | |||||||||||||||
| Montana lease payments | (3 | ) | 3,022 | — | — | 3,022 | 4,059 | |||||||||||||||
| Lancaster Plant 2010 net costs | 2015 | 2,607 | — | — | 2,607 | 3,967 | ||||||||||||||||
| Deferred maintenance costs | 2016 | — | 5,813 | — | 5,813 | 6,312 | ||||||||||||||||
| Power deferrals | (3 | ) | 5,065 | — | — | 5,065 | — | |||||||||||||||
| Regulatory asset for interest rate swaps | 2013 | — | — | — | — | 1,406 | ||||||||||||||||
| Non-current regulatory asset for utility derivatives | (5 | ) | — | 23,258 | — | 23,258 | 25,218 | |||||||||||||||
| Other regulatory assets | (3 | ) | 4,002 | 4,683 | 4,597 | 13,282 | 13,717 | |||||||||||||||
| Total regulatory assets | $ | 168,615 | $ | 211,143 | $ | 4,597 | $ | 384,355 | $ | 566,631 | ||||||||||||
| Regulatory Liabilities: | ||||||||||||||||||||||
| Natural gas deferrals | (3 | ) | $ | 12,075 | $ | — | $ | — | $ | 12,075 | $ | 6,917 | ||||||||||
| Power deferrals | (3 | ) | 17,904 | — | — | 17,904 | 27,323 | |||||||||||||||
| Regulatory liability for utility plant retirement costs | (7 | ) | 242,850 | — | — | 242,850 | 234,128 | |||||||||||||||
| Income tax related liabilities | (3 | ) | — | 9,203 | — | 9,203 | 17,206 | |||||||||||||||
| Regulatory liability for interest rate swaps | 2014-2015 | — | 33,543 | — | 33,543 | 7,265 | ||||||||||||||||
| Regulatory liability for Spokane Energy | (8 | ) | — | — | 25,046 | 25,046 | 21,488 | |||||||||||||||
| Other regulatory liabilities | (3 | ) | 7,249 | 6,411 | — | 13,660 | 4,316 | |||||||||||||||
| Total regulatory liabilities | $ | 280,078 | $ | 49,157 | $ | 25,046 | $ | 354,281 | $ | 318,643 | ||||||||||||
| (1) | Earning a return includes either interest on the regulatory asset/liability or a return on the investment as a component of rate base at the allowed rate of return. |
| (2) | Expected recovery is pending regulatory treatment including regulatory assets and liabilities that have prior regulatory precedence. |
| (3) | Remaining amortization period varies depending on timing of underlying transactions. |
| (4) | As the Company has historically recovered and currently recovers its pension and other postretirement benefit costs related to its regulated operations in retail rates, the Company records a regulatory asset for that portion of its pension and other postretirement benefit funding deficiency. |
| (5) | The UTC and the IPUC issued accounting orders authorizing Avista Corp. to offset commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to- |
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market gains and losses on energy commodity transactions until the period of settlement. The orders provide for Avista Corp. to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Consolidated Statements of Income. Realized gains or losses are recognized in the period of settlement, subject to approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in adjustments to retail rates through purchased gas cost adjustments, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rates cases.
| (6) | For the Company’s Washington jurisdiction and for any debt repurchases beginning in 2007 in all jurisdictions, premiums paid to repurchase debt are amortized over the remaining life of the original debt that was repurchased or, if new debt is issued in connection with the repurchase, these costs are amortized over the life of the new debt. In the Company’s other regulatory jurisdictions, premiums paid to repurchase debt prior to 2007 are being amortized over the average remaining maturity of outstanding debt when no new debt was issued in connection with the debt repurchase. These costs are recovered through retail rates as a component of interest expense. |
| (7) | This amount is dependent upon the cost of removal of underlying utility plant assets and the life of utility plant. |
| (8) | Consists of a regulatory liability recorded for the cumulative retained earnings of Spokane Energy that the Company will flow through regulatory accounting mechanisms in future periods. |
Power Cost Deferrals and Recovery Mechanisms
Deferred power supply costs are recorded as a deferred charge on the Consolidated Balance Sheets for future prudence review and recovery through retail rates. The power supply costs deferred include certain differences between actual net power supply costs incurred by Avista Utilities and the costs included in base retail rates. This difference in net power supply costs primarily results from changes in:
| • | short-term wholesale market prices and sales and purchase volumes, |
| • | the level and availability of hydroelectric generation, |
| • | the level and availability of thermal generation (including changes in fuel prices), |
| • | the net value from optimization activities related to the Company's generating resources, and |
| • | retail loads. |
In Washington, the Energy Recovery Mechanism (ERM) allows Avista Utilities to periodically increase or decrease electric rates with UTC approval to reflect changes in power supply costs. The ERM is an accounting method used to track certain differences between actual power supply costs, net of the margin on wholesale sales and sales of fuel, and the amount included in base retail rates for Washington customers. Total net deferred power costs under the ERM were a liability of $17.9 million as of December 31, 2013, and these deferred power cost balances represent amounts due to customers. As part of the approved Washington general rate case settlement in December 2012, during 2013 a one-year credit designed to return to customers $4.4 million from the existing ERM deferral balance reduced the net average electric rate increase impact to customers in 2013. Additionally, during 2014 a one-year credit up to $9.0 million will be returned to electric customers from the ERM deferral balance, so the net average electric rate increase impact to customers effective January 1, 2014 was also be reduced. The credits to customers from the ERM balances do not impact the Company's net income.
Under the ERM, the Company absorbs the cost or receives the benefit from the initial amount of power supply costs in excess of or below the level in retail rates, which is referred to as the deadband. The annual (calendar year) deadband amount is currently $4.0 million. The Company will incur the cost of, or receive the benefit from, 100 percent of this initial power supply cost variance. The Company shares annual power supply cost variances between $4.0 million and $10.0 million with customers. There is a 50 percent customers/50 percent Company sharing ratio when actual power supply expenses are higher (surcharge to customers) than the amount included in base retail rates within this band. There is a 75 percent customers/25 percent Company sharing ratio when actual power supply expenses are lower (rebate to customers) than the amount included in base retail rates within this band. To the extent that the annual power supply cost variance from the amount included in base rates exceeds $10.0 million, there is a 90 percent customers/10 percent Company share ratio of the cost variance.
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The following is a summary of the ERM:
| Annual Power Supply Cost Variability | Deferred for Future Surcharge or Rebate to Customers | Expense or Benefit to the Company | ||
| within +/- $0 to $4 million (deadband) | 0% | 100% | ||
| higher by $4 million to $10 million | 50% | 50% | ||
| lower by $4 million to $10 million | 75% | 25% | ||
| higher or lower by over $10 million | 90% | 10% | ||
As part of the April 2012 Washington general rate case filing, the Company proposed modifications to the ERM deadband and other sharing bands. The proposed modifications were not agreed to as part of the settlement agreement, and the ERM continued unchanged. However, the trigger point at which rates will change under the ERM was modified to be $30 million rather than the previous 10 percent of base revenues (approximately $45 million) under the mechanism.
Avista Utilities has a Power Cost Adjustment (PCA) mechanism in Idaho that allows it to modify electric rates on October 1 of each year with Idaho Public Utilities Commission (IPUC) approval. Under the PCA mechanism, Avista Utilities defers 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for its Idaho customers. These annual October 1 rate adjustments recover or rebate power costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were a regulatory asset of $5.1 million as of December 31, 2013 compared to a regulatory liability of $5.1 million as of December 31, 2012.
Natural Gas Cost Deferrals and Recovery Mechanisms
Avista Utilities files a purchased gas cost adjustment (PGA) in all three states it serves to adjust natural gas rates for: 1) estimated commodity and pipeline transportation costs to serve natural gas customers for the coming year, and 2) the difference between actual and estimated commodity and transportation costs for the prior year. These annual PGA filings in Washington and Idaho provide for the deferral, and recovery or refund, of 100 percent of the difference between actual and estimated commodity and pipeline transportation costs, subject to applicable regulatory review. The annual PGA filing in Oregon provides for deferral, and recovery or refund, of 100 percent of the difference between actual and estimated pipeline transportation costs and commodity costs that are fixed through hedge transactions. Commodity costs that are not hedged for Oregon customers are subject to a sharing mechanism whereby Avista Utilities defers, and recovers or refunds, 90 percent of the difference between these actual and estimated costs. Total net deferred natural gas costs to be refunded to customers were a liability of $12.1 million as of December 31, 2013 compared to a liability of $6.9 million as of December 31, 2012.
Washington General Rate Cases
In December 2011, the UTC approved a settlement agreement in the Company's electric and natural gas general rate cases filed in May 2011. The settlement agreement provided that base electric rates for Washington customers increase by an average of 4.6 percent, which was designed to increase annual revenues by $20.0 million. Base natural gas rates for Washington customers increased by an average of 2.4 percent, which was designed to increase annual revenues by $3.8 million. The new electric and natural gas rates became effective on January 1, 2012.
In addition, the settlement agreement provided for the deferral of certain generation plant maintenance costs. For 2011 and 2012 the Company compared actual non-fuel maintenance expenses for the Coyote Springs 2 and Colstrip plants with the amount of baseline maintenance expenses used to establish base retail rates, and deferred the difference. This deferral occurred each year, with no carrying charge, with deferred costs to be amortized over a four-year period, beginning the year following the period costs are deferred. Total net deferred costs under this mechanism in Washington were a regulatory asset of $3.1 million as of December 31, 2013 compared to a regulatory asset of $4.0 million as of December 31, 2012. As part of the settlement agreement relating to the Company's latest general rate case approved in December 2012, the parties agreed to terminate the maintenance cost deferral mechanism on December 31, 2012, with the four-year amortization of the 2011 and 2012 deferrals to conclude in 2015 and 2016, respectively.
In December 2012, the UTC approved a settlement agreement in the Company's electric and natural gas general rate cases filed in April 2012. The settlement, effective January 1, 2013, provided that base rates for Washington electric customers increase by an overall 3.0 percent (designed to increase annual revenues by $13.6 million), and base rates for Washington natural gas customers increased by an overall 3.6 percent (designed to increase annual revenues by $5.3 million). Under the settlement, there was a one-year credit designed to return $4.4 million to electric customers from the existing ERM deferral balance so the net average electric rate increase impact to the Company's customers in 2013 was 2.0 percent. The credit to customers from the ERM balance did not impact the Company's earnings.
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The approved settlement also provided that, effective January 1, 2014, the Company increased base rates for Washington electric customers by an overall 3.0 percent (designed to increase annual revenues by $14.0 million), and for Washington natural gas customers by an overall 0.9 percent (designed to increase annual revenues by $1.4 million). The settlement provides for a one-year credit up to $9.0 million to electric customers from the ERM deferral balance, so the net average electric rate increase to customers effective January 1, 2014 was 2.0 percent. The credit to customers from the ERM balance will not impact the Company's earnings. The ERM balance as of December 31, 2013 was a liability of $17.9 million.
The settlement agreement provides for an authorized return on equity of 9.8 percent and an equity ratio of 47.0 percent, resulting in an overall rate of return on rate base of 7.64 percent.
The December 2012 UTC Order approving the settlement agreement included certain conditions.
| (1) | The new retail rates to become effective January 1, 2014 will be temporary rates, and on January 1, 2015 electric and natural gas base rates will revert back to 2013 levels absent any intervening action from the UTC. The original settlement agreement has a provision that the Company will not file a general rate case in Washington seeking new rates to take effect before January 1, 2015. |
| (2) | In its Order, the UTC found that much of the approved base rate increases are justified by the planned capital expenditures necessary to upgrade and maintain the Company's utility facilities. If these capital projects are not completed to a level that was contemplated in the settlement agreement, this could result in base rates which are considered too high by the UTC. Avista Corp. is required to file capital expenditure progress reports with the UTC on a periodic basis so that the UTC can monitor the capital expenditures and ensure they are in line with those contemplated in the settlement agreement. The Company expects total utility capital expenditures to be above the level contemplated in the settlement agreement. |
On February 4, 2014 the Company filed electric and natural gas general rates cases with the UTC. The Company has requested an overall increase in base electric rates of 3.8 percent (designed to increase annual electric revenues by $18.2 million) and an overall increase in base natural gas rates of 8.1 percent (designed to increase annual natural gas revenues by $12.1 million). The requests are based on a proposed overall rate of return of 7.71 percent, with a common equity ratio of 49.0 percent and a 10.1 percent return on equity.
Avista Corp. has also proposed a rebate beginning January 1, 2015, related to its sale of renewable energy credits (REC), that would reduce customers' monthly electric bills by 1.1 percent. The rebate associated with the sale of RECs is in response to the UTC Order approving the Company's previous general rate case settlement in December 2012. This proposed REC rebate would commence simultaneously with the expiration of two rebates that, together, are currently reducing customers' monthly electric bills by 2.8 percent. The net effect, commencing January 1, 2015, of the proposed new 1.1 percent rebate and the expiration of the current 2.8 percent rebate would be an increase in monthly electric bills of approximately 1.7 percent from 2014 levels. These rebates do not increase or decrease Avista Corp.'s earnings.
The combination of the 3.8 percent requested increase in base electric rates and the effective 1.7 percent increase attributable to the rebates would be a 5.5 percent increase electric billings.
As part of the Company's electric and natural gas general rate case filings, it has requested the implementation of decoupling mechanisms which sever the link between actual volumetric sales and the recovery of the Company's fixed costs. Under the proposed decoupling mechanisms, the Company would compare actual non-power supply (electric) and non-PGA (natural gas) revenue to the allowed non-power supply and non-PGA revenue, as the case may be, and the difference would be deferred and either rebated or surcharged to customers, depending on the position of the deferral accounts, over a one-year period. The deferral balances would be reviewed annually by the UTC prior to the implementation of any annual rate adjustments under the mechanisms.
The proposed mechanisms would be subject to an annual earnings test which proposes that if the Company's actual annual “Commission-basis” rate of return exceeds the most recently authorized Commission-basis rate of return for the Company's Washington electric and natural gas operations, the amount of a proposed surcharge is reduced or eliminated to reduce the rate of return to the Commission-authorized level. In addition, the mechanisms would be subject to an annual rate increase limitation which would prevent the amount of the incremental proposed rate adjustments under the mechanisms from exceeding a 3 percent rate increase for each of electric and natural gas operations.
The UTC has up to 11 months to review the filings and issue a decision.
Idaho General Rate Cases
In September 2011, the IPUC approved a settlement agreement in the Company’s general rate case filed in July 2011. The new electric and natural gas rates became effective on October 1, 2011. The settlement agreement provided that base electric rates for the Company’s Idaho customers increase by an average of 1.1 percent, which was designed to increase annual revenues by
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$2.8 million. Base natural gas rates for the Company’s Idaho customers increased by an average of 1.6 percent, which was designed to increase annual revenues by $1.1 million.
The September 2011 settlement agreement provides for the deferral of certain generation plant operation and maintenance costs. In order to address the variability in year-to-year operation and maintenance costs, beginning in 2011, the Company is deferring certain changes in operation and maintenance costs related to the Coyote Spring 2 natural gas-fired generation plant and its 15 percent ownership interest in Units 3 & 4 of the Colstrip generation plant. The Company compares actual, non-fuel, operation and maintenance expenses for the Coyote Springs 2 and Colstrip plants with the amount of expenses authorized for recovery in base rates in the applicable deferral year, and defers the difference from that currently authorized. The deferral occurs annually, with no carrying charge, with deferred costs being amortized over a three-year period, beginning in the year following the period costs are deferred. The amount of expense to be requested for recovery in future general rate cases will be the actual operation and maintenance expense recorded in the test period, less any amount deferred during the test period, plus the amortization of previously deferred costs. Total net deferred costs under this mechanism in Idaho were regulatory assets of $2.8 million as of December 31, 2013 and $2.3 million as of December 31, 2012.
In March 2013, the IPUC approved a settlement agreement in the Company's electric and natural gas general rate cases filed in October 2012. As agreed to in the settlement, new rates were implemented in two phases: April 1, 2013 and October 1, 2013. Effective April 1, 2013, base rates increased for the Company's Idaho natural gas customers by an overall 4.9 percent (designed to increase annual revenues by $3.1 million). There was no change in base electric rates on April 1, 2013. However, the settlement agreement provided for the recovery of the costs of the Palouse Wind Project, subject to the 90 percent customers/10 percent Company sharing ratio, through the PCA mechanism until these costs are reflected in base retail rates in the next general rate case.
The settlement also provided that, effective October 1, 2013, base rates increased for Idaho natural gas customers by an overall 2.0 percent (designed to increase annual revenues by $1.3 million). A credit resulting from deferred natural gas costs of $1.6 million is being returned to the Company's Idaho natural gas customers from October 1, 2013 through December 31, 2014, so the net annual average natural gas rate increase to natural gas customers effective October 1, 2013 was 0.3 percent.
Further, the settlement provided that, effective October 1, 2013, base rates increased for Idaho electric customers by an overall 3.1 percent (designed to increase annual revenues by $7.8 million). A $3.9 million credit resulting from a payment to be made to Avista Corp. by the Bonneville Power Administration relating to its prior use of Avista Corp.'s transmission system is being returned to Idaho electric customers from October 1, 2013 through December 31, 2014, so the net annual average electric rate increase to electric customers effective October 1, 2013 was 1.9 percent.
The $1.6 million credit to Idaho natural gas customers and the $3.9 million credit to Idaho electric customers do not impact the Company's net income.
The settlement agreement allows the Company to file a general rate case in Idaho in 2014; however, new rates resulting from the filing would not take effect prior to January 1, 2015.
The settlement agreement provides for an authorized return on equity of 9.8 percent and an equity ratio of 50.0 percent.
The settlement also includes an after-the-fact earnings test for 2013 and 2014, such that if Avista Corp., on a consolidated basis for electric and natural gas operations in Idaho, earns more than a 9.8 percent return on equity, Avista Corp. will refund to customers 50 percent of any earnings above the 9.8 percent. In 2013, the Company's returns exceeded this level and the Company will refund $2.0 million to Idaho electric customers and $0.4 million to Idaho natural gas customers. The period over which these amounts will be returned to customers has not yet been determined by the IPUC.
Oregon General Rate Case
On January 21, 2014, the Public Utility Commission of Oregon (OPUC) approved a settlement agreement to the Company's natural gas general rate case (originally filed in August 2013). As agreed to in the settlement, new rates will be implemented in two phases: February 1, 2014 and November 1, 2014. Effective February 1, 2014, rates increased for Oregon natural gas customers on a billed basis by an overall 4.4 percent (designed to increase annual revenues by $4.3 million). Effective November 1, 2014, rates for Oregon natural gas customers will increase on a billed basis by an overall 1.55 percent (designed to increase annual revenues by $1.4 million).
The billed rate increase on November 1, 2014 could vary slightly from that noted above as it is dependent upon actual costs incurred through September 30, 2014 related to the Company's customer information system upgrade and the actual costs incurred through June 30, 2014 related to the Company's Aldyl A distribution pipeline replacement program. The estimated capital expenditures included in the general rate case settlement are $6.5 million and $2.0 million, respectively, for the two projects. If the actual costs incurred on the above projects are greater than the amounts contemplated in the general rate case settlement, the additional costs could be approved for recovery, subject to a prudence review.
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The approved settlement agreement provides for an overall authorized rate of return of 7.47 percent, with a common equity ratio of 48 percent and a 9.65 percent return on equity.
Bonneville Power Administration Reimbursement and Reardan Wind Generation Project
On May 9, 2013, the UTC approved the Company's Petition for an order authorizing certain accounting and ratemaking treatment related to two issues. The first issue relates to transmission revenues associated with a settlement between Avista Corp. and the Bonneville Power Administration (BPA), whereby the BPA reimbursed the Company $11.7 million for Bonneville's past use of Avista Corp.'s transmission system. The second issue relates to $4.3 million of costs the Company incurred over the past several years for the development of a wind generation project site near Reardan, Washington, which has been terminated. The UTC authorized the Company to retain $7.6 million of the BPA settlement payment, representing the entire portion of the settlement allocable to the Washington business. However, this amount was deemed to first reimburse the Company for the $2.5 million of Reardan project costs that are allocable to the Washington business, leaving $5.1 million to be retained for the benefit of shareholders.
The BPA agreed to pay $0.3 million monthly ($3.2 million annually) for the future use of Avista Corp.'s transmission system. The Company is separately tracking and deferring for the customers' benefit, the Washington portion of these revenue payments in 2013 and 2014 ($2.1 million annually). The Company implemented a one-year $4.2 million rate decrease for customers effective January 1, 2014 to partially offset the electric general rate increase effective January 1, 2014. To the extent actual revenues from the BPA in 2013 and 2014 differ from those refunded to customers in 2014, the difference will be added to or subtracted from the ERM balance. In Idaho, under the terms of the approved rate case settlement, 90 percent of the portion of the BPA settlement allocable to the Idaho business ($4.1 million) is being credited back to customers over 15 months, beginning October 2013, and the Company is amortizing the Idaho portion of Reardan costs ($1.7 million) over a two-year period, beginning April 2013.
NOTE 23. INFORMATION BY BUSINESS SEGMENTS
The business segment presentation reflects the basis used by the Company's management to analyze performance and determine the allocation of resources. The Company's management evaluates performance based on income (loss) from operations before income taxes as well as net income (loss) attributable to Avista Corp. shareholders. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. Avista Utilities' business is managed based on the total regulated utility operation. Ecova is a provider of facility information and cost management services for multi-site customers throughout North America. The Other category, which is not a reportable segment, includes Spokane Energy, other investments and operations of various subsidiaries, as well as certain other operations of Avista Capital.
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The following table presents information for each of the Company’s business segments (dollars in thousands):
Avista Utilities | Ecova | Other | Total Non-Utility | Intersegment Eliminations (1) | Total | ||||||||||||||||||
| For the year ended December 31, 2013: | |||||||||||||||||||||||
| Operating revenues | $ | 1,403,995 | $ | 176,761 | $ | 39,549 | $ | 216,310 | $ | (1,800 | ) | $ | 1,618,505 | ||||||||||
| Resource costs | 689,586 | — | — | — | — | 689,586 | |||||||||||||||||
| Other operating expenses | 276,228 | 148,023 | 40,451 | 188,474 | (1,800 | ) | 462,902 | ||||||||||||||||
| Depreciation and amortization | 117,174 | 15,434 | 581 | 16,015 | — | 133,189 | |||||||||||||||||
| Income from operations | 232,572 | 13,304 | (1,483 | ) | 11,821 | — | 244,393 | ||||||||||||||||
| Interest expense (2) | 75,663 | 1,637 | 2,247 | 3,884 | (325 | ) | 79,222 | ||||||||||||||||
| Income taxes | 60,472 | 5,216 | (2,458 | ) | 2,758 | — | 63,230 | ||||||||||||||||
| Net income (loss) attributable to Avista Corporation shareholders | 108,598 | 7,129 | (4,650 | ) | 2,479 | — | 111,077 | ||||||||||||||||
| Capital expenditures | 294,363 | 8,379 | 371 | 8,750 | — | 303,113 | |||||||||||||||||
| For the year ended December 31, 2012: | |||||||||||||||||||||||
| Operating revenues | $ | 1,354,185 | $ | 155,664 | $ | 38,953 | $ | 194,617 | $ | (1,800 | ) | $ | 1,547,002 | ||||||||||
| Resource costs | 693,127 | — | — | — | — | 693,127 | |||||||||||||||||
| Other operating expenses | 276,780 | 139,173 | 39,841 | 179,014 | (1,800 | ) | 453,994 | ||||||||||||||||
| Depreciation and amortization | 112,091 | 13,519 | 792 | 14,311 | — | 126,402 | |||||||||||||||||
| Income from operations | 188,778 | 2,972 | (1,680 | ) | 1,292 | — | 190,070 | ||||||||||||||||
| Interest expense (2) | 72,552 | 1,790 | 3,437 | 5,227 | (344 | ) | 77,435 | ||||||||||||||||
| Income taxes | 42,842 | 1,497 | (3,078 | ) | (1,581 | ) | — | 41,261 | |||||||||||||||
| Net income (loss) attributable to Avista Corporation shareholders | 81,704 | 1,825 | (5,319 | ) | (3,494 | ) | — | 78,210 | |||||||||||||||
| Capital expenditures | 271,187 | 4,121 | 666 | 4,787 | — | 275,974 | |||||||||||||||||
| For the year ended December 31, 2011: | |||||||||||||||||||||||
| Operating revenues | $ | 1,443,322 | $ | 137,848 | $ | 40,410 | $ | 178,258 | $ | (1,800 | ) | $ | 1,619,780 | ||||||||||
| Resource costs | 790,048 | — | — | — | — | 790,048 | |||||||||||||||||
| Other operating expenses | 261,926 | 109,738 | 34,917 | 144,655 | (1,800 | ) | 404,781 | ||||||||||||||||
| Depreciation and amortization | 105,629 | 7,193 | 778 | 7,971 | — | 113,600 | |||||||||||||||||
| Income from operations | 202,373 | 20,917 | 4,714 | 25,631 | — | 228,004 | |||||||||||||||||
| Interest expense (2) | 69,347 | 305 | 4,943 | 5,248 | (387 | ) | 74,208 | ||||||||||||||||
| Income taxes | 48,964 | 7,852 | (184 | ) | 7,668 | — | 56,632 | ||||||||||||||||
| Net income (loss) attributable to Avista Corporation shareholders | 90,902 | 9,671 | (349 | ) | 9,322 | — | 100,224 | ||||||||||||||||
| Capital expenditures | 239,782 | 2,998 | 592 | 3,590 | — | 243,372 | |||||||||||||||||
| Total Assets: | |||||||||||||||||||||||
| As of December 31, 2013 | $ | 3,940,998 | $ | 339,643 | $ | 81,282 | $ | 420,925 | $ | — | $ | 4,361,923 | |||||||||||
| As of December 31, 2012 | $ | 3,894,821 | $ | 322,720 | $ | 95,638 | $ | 418,358 | $ | — | $ | 4,313,179 | |||||||||||
| (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 represent intercompany interest. |
| (2) | Including interest expense to affiliated trusts. |
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NOTE 24. SELECTED QUARTERLY FINANCIAL DATA (Unaudited)
The Company’s energy operations are significantly affected by weather conditions. Consequently, there can be large variances in revenues, expenses and net income between quarters based on seasonal factors such as, but not limited to, temperatures and streamflow conditions. A summary of quarterly operations (in thousands, except per share amounts) for 2013 and 2012 follows:
| Three Months Ended | |||||||||||||||
| March 31 | June 30 | September 30 | December 31 | ||||||||||||
| 2013 | |||||||||||||||
| Operating revenues | $ | 482,906 | $ | 352,048 | $ | 335,875 | $ | 447,676 | |||||||
| Operating expenses | 397,844 | 294,306 | 300,606 | 381,356 | |||||||||||
| Income from operations | $ | 85,062 | $ | 57,742 | $ | 35,269 | $ | 66,320 | |||||||
| Net income | $ | 43,101 | $ | 25,730 | $ | 11,931 | $ | 31,532 | |||||||
| Net loss (income) attributable to noncontrolling interests | (760 | ) | (73 | ) | (518 | ) | 134 | ||||||||
| Net income attributable to Avista Corporation shareholders | $ | 42,341 | $ | 25,657 | $ | 11,413 | $ | 31,666 | |||||||
| Outstanding common stock: | |||||||||||||||
| Weighted average, basic | 59,866 | 59,937 | 59,994 | 60,037 | |||||||||||
| Weighted average, diluted | 59,898 | 59,962 | 60,032 | 60,087 | |||||||||||
| Earnings per common share attributable to Avista Corporation shareholders, diluted | $ | 0.71 | $ | 0.43 | $ | 0.19 | $ | 0.53 | |||||||
| 2012 | |||||||||||||||
| Operating revenues | $ | 452,257 | $ | 343,585 | $ | 340,632 | $ | 410,528 | |||||||
| Operating expenses | 375,863 | 297,565 | 314,023 | 369,481 | |||||||||||
| Income from operations | $ | 76,394 | $ | 46,020 | $ | 26,609 | $ | 41,047 | |||||||
| Net income | $ | 38,213 | $ | 18,532 | $ | 5,962 | $ | 16,093 | |||||||
| Net loss (income) attributable to noncontrolling interests | 175 | (354 | ) | (176 | ) | (235 | ) | ||||||||
| Net income attributable to Avista Corporation shareholders | $ | 38,388 | $ | 18,178 | $ | 5,786 | $ | 15,858 | |||||||
| Outstanding common stock: | |||||||||||||||
| Weighted average, basic | 58,581 | 58,702 | 59,047 | 59,774 | |||||||||||
| Weighted average, diluted | 58,950 | 58,924 | 59,123 | 59,826 | |||||||||||
| Earnings per common share attributable to Avista Corporation shareholders, diluted | $ | 0.65 | $ | 0.31 | $ | 0.10 | $ | 0.26 | |||||||
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A. Controls and Procedures
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
The Company has disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) to ensure that information required to be disclosed in the reports it files or submits under the Act is recorded, processed, summarized and reported on a timely basis. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Act is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers as appropriate to allow timely decisions regarding required disclosure. Under the supervision and with the participation of the Company’s management, including the Company’s principal executive officer and principal financial officer, the Company evaluated its disclosure controls and procedures as of the end of the period covered by this report. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives. Based upon the Company’s evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective at a reasonable assurance level as of December 31, 2013.
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Management’s Report on Internal Control Over Financial Reporting
The Company’s management, together with its consolidated subsidiaries, is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s principal executive officer and principal financial officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external reporting purposes in accordance with accounting principles generally accepted in the United States of America.
The Company’s internal control over financial reporting includes policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of the Company; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the Company’s financial statements.
Under the supervision and with the participation of the Company’s management, including the Company’s principal executive officer and principal financial officer, the Company conducted an assessment of the effectiveness of the Company’s internal control over financial reporting based on the framework established in Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management determined that the Company’s internal control over financial reporting as of December 31, 2013 is effective at a reasonable assurance level.
The Company’s independent registered public accounting firm, Deloitte & Touche LLP, has issued an attest report on the Company’s internal control over financial reporting as of December 31, 2013.
Changes in Internal Control Over Financial Reporting
There have been no changes in the Company’s internal control over financial reporting that occurred during the Company’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Avista Corporation
Spokane, Washington
We have audited the internal control over financial reporting of Avista Corporation and subsidiaries (the “Company”) as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.
Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2013 of the Company and our report dated February 26, 2014 expressed an unqualified opinion on those financial statements.
/s/ Deloitte & Touche LLP
Seattle, Washington
February 26, 2014
132
Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this Item (other than the information regarding executive officers and the Company's Code of Business Conduct and Ethics set forth below) is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows:
| • | on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 8, 2014, from such Proxy Statement; and |
| • | prior to such date, from the Registrant's definitive Proxy Statement, dated March 29, 2013, relating to its Annual Meeting of Shareholders held on May 9, 2013. |
133
| Executive Officers of the Registrant | |||||
| Name | Age | Business Experience | |||
| Scott L. Morris | 56 | Chairman, President and Chief Executive Officer effective January 1, 2008. Director since February 9, 2007; President and Chief Operating Officer May 2006 – December 2007; Senior Vice President February 2002 – May 2006; Vice President November 2000 – February 2002; President – Avista Utilities August 2000 – December 2008; General Manager – Avista Utilities for the Oregon and California operations October 1991 – August 2000; various other management and staff positions with the Company since 1981. | |||
| Mark T. Thies | 50 | Treasurer since January 2013; Senior Vice President and Chief Financial Officer (Principal Financial Officer) since September 2008; prior to employment with the Company held the following positions with Black Hills Corporation: Executive Vice President and Chief Financial Officer March 2003 to January 2008; Senior Vice President and Chief Financial Officer March 2000 to March 2003; Controller May 1997 to March 2000. | |||
| Marian M. Durkin | 60 | Senior Vice President, General Counsel and Chief Compliance Officer since November 2005; Senior Vice President and General Counsel August 2005 – November 2005; prior to employment with the Company: held several legal positions with United Air Lines, Inc. from 1995 to August 2005, most recently served as Vice President Deputy General Counsel and Assistant Secretary. | |||
| Karen S. Feltes | 58 | Senior Vice President of Human Resources and Corporate Secretary since November 2005; Vice President of Human Resources and Corporate Secretary March 2003 – November 2005; Vice President of Human Resources and Corporate Services February 2002 – March 2003; various human resources positions with the Company April 1998 – February 2002. | |||
| Dennis P. Vermillion | 52 | Senior Vice President since January 2010; Vice President July 2007- December 2009; President – Avista Utilities since January 2009; Vice President of Energy Resources and Optimization – Avista Utilities July 2007 – December 2008; President and Chief Operating Officer of Avista Energy February 2001 – July 2007; various other management and staff positions with the Company since 1985. | |||
| Christy M. Burmeister-Smith | 57 | Vice President, Controller and Principal Accounting Officer since May 2007. Vice President and Treasurer January 2006 – May 2007; Vice President and Controller June 1999 – January 2006; various other management and staff positions with the Company since 1980. | |||
| James M. Kensok | 55 | Vice President and Chief Information Officer since January 2007; Chief Information Officer February 2001 – December 2006; various other management and staff positions with the Company since 1996. | |||
| Don F. Kopczynski | 58 | Vice President since May 2004; Vice President of Operations - Avista Utilities since June 2012; Vice President of Customer Solutions – Avista Utilities April 2011 - December 2012; Vice President of Transmission and Distribution Operations – Avista Utilities May 2004 – April 2011; various other management and staff positions with the Company and its subsidiaries since 1979. | |||
| David J. Meyer | 60 | Vice President and Chief Counsel for Regulatory and Governmental Affairs since February 2004; Senior Vice President and General Counsel September 1998 – February 2004. | |||
| Kelly O. Norwood | 55 | Vice President since November 2000; Vice President of State and Federal Regulation – Avista Utilities since March 2002; Vice President and General Manager of Energy Resources - Avista Utilities August 2000 – March 2002; various other management and staff positions with the Company since 1981. | |||
| Jason R. Thackston | 43 | Senior Vice President since January 2014; Vice President of Energy Resources since December 2012; Vice President of Customer Solutions – Avista Utilities June 2012 - December 2012; Vice President of Energy Delivery April 2011 – December 2012; Vice President of Finance June 2009 – April 2011; various other management and staff positions with the Company since 1996. | |||
| Roger D. Woodworth | 57 | Vice President since November 1998; Vice President and Chief Strategy Officer since April 2011; Vice President, Sustainable Energy Solutions Avista Utilities February 2007 – April 2011; Vice President, Customer Solutions for Avista Utilities March 2003 – February 2007; Vice President of Utility Operations of Avista Utilities September 2001 – March 2003; Vice President – Corporate Development November 1998 – September 2001; various other management and staff positions with the Company since 1979. | |||
134
All of the Company’s executive officers, with the exception of James M. Kensok, Don F. Kopczynski, David J. Meyer, and Kelly O. Norwood, were officers or directors of one or more of the Company’s subsidiaries in 2013. The Company’s executive officers are elected annually by the Board of Directors.
The Company has adopted a Code of Business Conduct and Ethics (Code of Conduct) for directors, officers (including the principal executive officer, principal financial officer and principal accounting officer), and employees. The Code of Conduct is available on the Company’s Web site at www.avistacorp.com and will also be provided to any shareholder without charge upon written request to:
Avista Corp.
General Counsel
P.O. Box 3727 MSC-12
Spokane, Washington 99220-3727
Any changes to or waivers for executive officers and directors of the Company’s Code of Conduct will be posted on the Company’s Web site.
Item 11. Executive Compensation
The information required by this Item is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows:
| • | on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 8, 2014, from such Proxy Statement; and |
| • | prior to such date, from the Registrant's definitive Proxy Statement, dated March 29, 2013, relating to its Annual Meeting of Shareholders held on May 9, 2013. |
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
| (a) | Security ownership of certain beneficial owners (owning 5 percent or more of Registrant’s voting securities): |
Information regarding security ownership of certain beneficial owners (owning 5 percent or more of Registrant’s voting securities) has been omitted pursuant to General Instruction G to Form 10-K. Reference is made to the Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Registrant’s annual meeting of shareholders to be held on May 8, 2014.
| (b) | Security ownership of management: |
The information required by this Item regarding the security ownership of management is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows:
| • | on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 8, 2014, from such Proxy Statement; and |
| • | prior to such date, from the Registrant's definitive Proxy Statement, dated March 29, 2013, relating to its Annual Meeting of Shareholders held on May 9, 2013. |
| (c) | Changes in control: |
None.
| (d) | Securities authorized for issuance under equity compensation plans as of December 31, 2013: |
| Plan category | (a) Number of securities to be issued upon exercise of outstanding options, warrants and rights | (b) Weighted average exercise price of outstanding options, warrants and rights | (c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | ||||||
| (1) | |||||||||
| Equity compensation plans approved by security holders (2) | — | $ | — | 936,071 | |||||
| (1) | Excludes unvested restricted shares and performance share awards granted under Avista Corp.’s Long Term Incentive Plan. At December 31, 2013, 104,416 Restricted Share awards were outstanding. Performance share awards may be paid out at zero shares at a minimum achievement level; 344,684 shares at target level; or 689,368 shares at a maximum level. Because there is no exercise price associated with restricted shares or performance share awards, such shares are not included in the weighted-average price calculation. |
135
| (2) | Includes the Long-Term Incentive Plan approved by shareholders in 1998 and the Non-Employee Director Stock Plan approved by shareholders in 1996. In February 2005, the Board of Directors elected to terminate the Non-Employee Director Stock Plan. |
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this Item is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows:
| • | on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 8, 2014, from such Proxy Statement; and |
| • | prior to such date, from the Registrant's definitive Proxy Statement, dated March 29, 2013, relating to its Annual Meeting of Shareholders held on May 9, 2013. |
Item 14. Principal Accounting Fees and Services
The information required by this Item is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows:
| • | on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 8, 2014, from such Proxy Statement; and |
| • | prior to such date, from the Registrant's definitive Proxy Statement, dated March 29, 2013, relating to its Annual Meeting of Shareholders held on May 9, 2013. |
136
PART IV
Item 15. Exhibits, Financial Statement Schedules
| (a) | 1. Financial Statements (Included in Part II of this report): |
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Income for the Years Ended December 31, 2013, 2012 and 2011
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2013, 2012 and 2011
Consolidated Balance Sheets as of December 31, 2013 and 2012
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011
Consolidated Statements of Equity and Redeemable Noncontrolling Interests for the Years Ended December 31, 2013, 2012 and 2011
Notes to Consolidated Financial Statements
| (a) | 2. Financial Statement Schedules: |
None
| (a) | 3. Exhibits: |
Reference is made to the Exhibit Index commencing on page 140. The Exhibits include the management contracts and compensatory plans or arrangements required to be filed as exhibits to this Form 10-K pursuant to Item 15(b).
137
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| AVISTA CORPORATION | |||||
| February 26, 2014 | By | /s/ Scott L. Morris | |||
| Date | Scott L. Morris | ||||
| Chairman of the Board, President and Chief Executive Officer | |||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
| Signature | Title | Date |
| /s/ Scott L. Morris | Principal Executive Officer | February 26, 2014 |
| Scott L. Morris | ||
Chairman of the Board, President and Chief Executive Officer | ||
| /s/ Mark T. Thies | Principal Financial Officer | February 26, 2014 |
Mark T. Thies (Senior Vice President, Chief Financial Officer, and Treasurer) | ||
| /s/ Christy M. Burmeister-Smith | Principal Accounting Officer | February 26, 2014 |
Christy M. Burmeister-Smith (Vice President, Controller and Principal Accounting Officer) | ||
| /s/ Erik J. Anderson | Director | February 26, 2014 |
| Erik J. Anderson | ||
| /s/ Kristianne Blake | Director | February 26, 2014 |
| Kristianne Blake | ||
| /s/ Donald C. Burke | Director | February 26, 2014 |
| Donald C. Burke | ||
| /s/ John F. Kelly | Director | February 26, 2014 |
| John F. Kelly | ||
| /s/ Rebecca A. Klein | Director | February 26, 2014 |
| Rebecca A. Klein | ||
| /s/ Marc F. Racicot | Director | February 26, 2014 |
| Marc F. Racicot | ||
138
| /s/ Heidi B. Stanley | Director | February 26, 2014 |
| Heidi B. Stanley | ||
| /s/ R. John Taylor | Director | February 26, 2014 |
| R. John Taylor | ||
139
EXHIBIT INDEX
| Previously Filed (1) | ||||||
| Exhibit | With Registration Number | As Exhibit | ||||
| 2.1 | 1-3701 (with Form 8-K filed as of November 4, 2013) | 2.1 | Agreement and Plan of Merger, among Avista Corporation, Alaska Merger Sub, Inc., Alaska Energy and Resources Company and William A. Corbus, dated as of November 4, 2013. | |||
| 3.1 | 1-3701 (with June 30, 2012 Form 10-Q) | 3.1 | Restated Articles of Incorporation of Avista Corporation, as amended and restated June 6, 2012. | |||
| 3.2 | 1-3701 (with Form 8-K filed as of February 12, 2014) | 3.2 | Bylaws of Avista Corporation, as amended February 7, 2014. | |||
| 4.1 | 2-4077 | B-3 | Mortgage and Deed of Trust, dated as of June 1, 1939. | |||
| 4.2 | 2-9812 | 4(c) | First Supplemental Indenture, dated as of October 1, 1952. | |||
| 4.3 | 2-60728 | 2(b)-2 | Second Supplemental Indenture, dated as of May 1, 1953. | |||
| 4.4 | 2-13421 | 4(b)-3 | Third Supplemental Indenture, dated as of December 1, 1955. | |||
| 4.5 | 2-13421 | 4(b)-4 | Fourth Supplemental Indenture, dated as of March 15, 1967. | |||
| 4.6 | 2-60728 | 2(b)-5 | Fifth Supplemental Indenture, dated as of July 1, 1957. | |||
| 4.7 | 2-60728 | 2(b)-6 | Sixth Supplemental Indenture, dated as of January 1, 1958. | |||
| 4.8 | 2-60728 | 2(b)-7 | Seventh Supplemental Indenture, dated as of August 1, 1958. | |||
| 4.9 | 2-60728 | 2(b)-8 | Eighth Supplemental Indenture, dated as of January 1, 1959. | |||
| 4.10 | 2-60728 | 2(b)-9 | Ninth Supplemental Indenture, dated as of January 1, 1960. | |||
| 4.11 | 2-60728 | 2(b)-10 | Tenth Supplemental Indenture, dated as of April 1, 1964. | |||
| 4.12 | 2-60728 | 2(b)-11 | Eleventh Supplemental Indenture, dated as of March 1, 1965. | |||
| 4.13 | 2-60728 | 2(b)-12 | Twelfth Supplemental Indenture, dated as of May 1, 1966. | |||
| 4.14 | 2-60728 | 2(b)-13 | Thirteenth Supplemental Indenture, dated as of August 1, 1966. | |||
| 4.15 | 2-60728 | 2(b)-14 | Fourteenth Supplemental Indenture, dated as of April 1, 1970. | |||
| 4.16 | 2-60728 | 2(b)-15 | Fifteenth Supplemental Indenture, dated as of May 1, 1973. | |||
| 4.17 | 2-60728 | 2(b)-16 | Sixteenth Supplemental Indenture, dated as of February 1, 1975. | |||
| 4.18 | 2-60728 | 2(b)-17 | Seventeenth Supplemental Indenture, dated as of November 1, 1976. | |||
| 4.19 | 2-69080 | 2(b)-18 | Eighteenth Supplemental Indenture, dated as of June 1, 1980. | |||
| 4.20 | 1-3701 (with 1980 Form 10-K) | 4(a)-20 | Nineteenth Supplemental Indenture, dated as of January 1, 1981. | |||
| 4.21 | 2-79571 | 4(a)-21 | Twentieth Supplemental Indenture, dated as of August 1, 1982. | |||
| 4.22 | 1-3701 (with Form 8-K dated September 20, 1983) | 4(a)-22 | Twenty-First Supplemental Indenture, dated as of September 1, 1983. | |||
| 4.23 | 2-94816 | 4(a)-23 | Twenty-Second Supplemental Indenture, dated as of March 1, 1984. | |||
| 4.24 | 1-3701 (with 1986 Form 10-K) | 4(a)-24 | Twenty-Third Supplemental Indenture, dated as of December 1, 1986. | |||
| 4.25 | 1-3701 (with 1987 Form 10-K) | 4(a)-25 | Twenty-Fourth Supplemental Indenture, dated as of January 1, 1988. | |||
| 4.26 | 1-3701 (with 1989 Form 10-K) | 4(a)-26 | Twenty-Fifth Supplemental Indenture, dated as of October 1, 1989. | |||
| 4.27 | 33-51669 | 4(a)-27 | Twenty-Sixth Supplemental Indenture, dated as of April 1, 1993. | |||
| 4.28 | 1-3701 (with 1993 Form 10-K) | 4(a)-28 | Twenty-Seventh Supplemental Indenture, dated as of January 1, 1994. | |||
| 4.29 | 1-3701 (with 2001 Form 10-K) | 4(a)-29 | Twenty-Eighth Supplemental Indenture, dated as of September 1, 2001. | |||
| 4.30 | 333-82502 | 4(b) | Twenty-Ninth Supplemental Indenture, dated as of December 1, 2001. | |||
140
| Previously Filed (1) | ||||||
| Exhibit | With Registration Number | As Exhibit | ||||
| 4.31 | 1-3701 (with June 30, 2002 Form 10-Q) | 4(f) | Thirtieth Supplemental Indenture, dated as of May 1, 2002. | |||
| 4.32 | 333-39551 | 4(b) | Thirty-First Supplemental Indenture, dated as of May 1, 2003. | |||
| 4.33 | 1-3701 (with September 30, 2003 Form 10-Q) | 4(f) | Thirty-Second Supplemental Indenture, dated as of September 1, 2003. | |||
| 4.34 | 333-64652 | 4(a)33 | Thirty-Third Supplemental Indenture, dated as of May 1, 2004. | |||
| 4.35 | 1-3701 (with Form 8-K dated as of December 15, 2004) | 4.1 | Thirty-Fourth Supplemental Indenture, dated as of November 1, 2004. | |||
| 4.36 | 1-3701 (with Form 8-K dated as of December 15, 2004) | 4.2 | Thirty-Fifth Supplemental Indenture, dated as of December 1, 2004. | |||
| 4.37 | 1-3701 (with Form 8-K dated as of December 15, 2004) | 4.3 | Thirty-Sixth Supplemental Indenture, dated as of December 1, 2004. | |||
| 4.38 | 1-3701 (with Form 8-K dated as of December 15, 2004) | 4.4 | Thirty-Seventh Supplemental Indenture, dated as of December 1, 2004. | |||
| 4.39 | 1-3701 (with Form 8-K dated as of May 12, 2005) | 4.1 | Thirty-Eighth Supplemental Indenture, dated as of May 1, 2005. | |||
| 4.40 | 1-3701 (with Form 8-K dated as of November 17, 2005) | 4.1 | Thirty-Ninth Supplemental Indenture, dated as of November 1, 2005. | |||
| 4.41 | 1-3701 (with Form 8-K dated as of April 6, 2006) | 4.1 | Fortieth Supplemental Indenture, dated as of April 1, 2006. | |||
| 4.42 | 1-3701 (with Form 8-K dated as of December 15, 2006) | 4.1 | Forty-First Supplemental Indenture, dated as of December 1, 2006. | |||
| 4.43 | 1-3701 (with Form 8-K dated as of April 3, 2008) | 4.1 | Forty-Second Supplemental Indenture, dated as of April 1, 2008. | |||
| 4.44 | 1-3701 (with Form 8-K dated as of November 26, 2008) | 4.1 | Forty-Third Supplemental Indenture, dated as of November 1, 2008. | |||
| 4.45 | 1-3701 (with Form 8-K dated as of December 16, 2008) | 4.1 | Forty-Fourth Supplemental Indenture, dated as of December 1, 2008. | |||
| 4.46 | 1-3701 (with Form 8-K dated as of December 30, 2008) | 4.3 | Forty-Fifth Supplemental Indenture, dated as of December 1, 2008. | |||
| 4.47 | 1-3701 (with Form 8-K dated as of September 15, 2009) | 4.1 | Forty-Sixth Supplemental Indenture, dated as of September 1, 2009. | |||
| 4.48 | 1-3701 (with Form 8-K dated as of November 25, 2009) | 4.1 | Forty-Seventh Supplemental Indenture, dated as of November 1, 2009. | |||
| 4.49 | 1-3701 (with Form 8-K dated as of December 15, 2010) | 4.5 | Forty-Eighth Supplemental Indenture, dated as of December 1, 2010. | |||
| 4.50 | 1-3701 (with Form 8-K dated as of December 20, 2010) | 4.1 | Forty-Ninth Supplemental Indenture, dated as of December 1, 2010. | |||
141
| Previously Filed (1) | ||||||
| Exhibit | With Registration Number | As Exhibit | ||||
| 4.51 | 1-3701 (with Form 8-K dated as of December 30, 2010) | 4.1 | Fiftieth Supplemental Indenture, dated as of December 1, 2010. | |||
| 4.52 | 1-3701 (with Form 8-K dated as of February 11, 2011) | 4.1 | Fifty-First Supplemental Indenture, dated as of February 1, 2011. | |||
| 4.53 | 1-3701 (with Form 8-K dated as of August 16, 2011) | 4.1 | Fifty-Second Supplemental Indenture, dated as of August 1, 2011. | |||
| 4.54 | 1-3701 (with Form 8-K dated as of December 14, 2011) | 4.1 | Fifty-Third Supplemental Indenture, dated as of December 1, 2011. | |||
| 4.55 | 1-3701 (with Form 8-K dated as of November 30, 2012) | 4.1 | Fifty-Fourth Supplemental Indenture, dated as of November 1, 2012. | |||
| 4.56 | 1-3701 (with Form 8-K dated as of August 14, 2013) | 4.1 | Fifty-Fifth Supplemental Indenture, dated as of August 1, 2013. | |||
| 4.57 | 1-3701 (with Form 8-K dated as of December 15, 2004) | 4.5 | Supplemental Indenture No. 1, dated as of December 1, 2004 to the Indenture dated as of April 1, 1998 between Avista Corporation and JPMorgan Chase Bank, N.A. | |||
| 4.58 | 333-82165 | 4(a) | Indenture dated as of April 1, 1998 between Avista Corporation and The Bank of New York, as Successor Trustee. | |||
| 4.59 | 1-3701 (with Form 8-K dated as of December 15, 2010) | 4.1 | Loan Agreement between City of Forsyth, Montana and Avista Corporation $66,700,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010A dated as of December 1, 2010. | |||
| 4.60 | 1-3701 (with Form 8-K dated as of December 15, 2010) | 4.3 | Trust Indenture between City of Forsyth, and the Bank of New York Mellon Trust Company, N.A., as Trustee, $66,700,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010A, dated as of December 1, 2010. | |||
| 4.61 | 1-3701 (with Form 8-K dated as of December 15, 2010) | 4.2 | Loan Agreement between City of Forsyth, Montana and Avista Corporation $17,000,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010B dated as of December 1, 2010. | |||
| 4.62 | 1-3701 (with Form 8-K dated as of December 15, 2010) | 4.4 | Trust Indenture between City of Forsyth, and the Bank of New York Mellon Trust Company, N.A., as Trustee, $17,000,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010B, dated as of December 1, 2010. | |||
| 10.1 | 1-3701 (with Form 8-K dated as of February 11, 2011) | 10.1 | Credit Agreement, dated as of February 11, 2011, among Avista Corporation, the Banks Party hereto, The Bank of New York Mellon, Keybank National Association, and U.S. Bank National Association, as Co-Documentation Agents, Wells Fargo Bank National Association as Syndication Agent and an Issuing Bank, and Union Bank N.A. as Administrative Agent and an Issuing Bank. | |||
| 10.2 | 1-3701 (with Form 8-K dated as of February 11, 2011) | 10.2 | Bond Delivery Agreement, dated as of February 11, 2011, between Avista Corporation and Union Bank, N.A. | |||
| 10.3 | 1-3701 (with Form 8-K dated as of August 14, 2013) | 10.1 | Term Loan Agreement, dated as of August 14, 2013, among Avista Corporation, the Lenders Party hereto and Union Bank N.A. as Administrative Agent. | |||
| 10.4 | 1-3701 (with Form 8-K dated as of August 14, 2013) | 10.2 | Bond Delivery Agreement, dated as of August 14, 2013, between Avista Corporation and Union Bank, N.A. | |||
142
| Previously Filed (1) | ||||||
| Exhibit | With Registration Number | As Exhibit | ||||
| 10.5 | 1-3701 (with Form 8-K dated as of December 14, 2011) | 10.1 | First Amendment and Waiver Thereunder, dated as of December 14, 2011, to the Credit Agreement dated as of February 11, 2011, among Avista Corporation, the Banks Party hereto, Wells Fargo Bank National Association as an Issuing Bank, and Union Bank N.A. as Administrative Agent and an Issuing Bank. | |||
| 10.6 | 1-3701 (with 2002 Form 10-K) | 10(b)-3 | Priest Rapids Project Product Sales Contract executed by Public Utility District No. 2 of Grant County, Washington and Avista Corporation dated December 12, 2001 (effective November 1, 2005 for the Priest Rapids Development and November 1, 2009 for the Wanapum Development). | |||
| 10.7 | 1-3701 (with 2002 Form 10-K) | 10(b)-4 | Priest Rapids Project Reasonable Portion Power Sales Contract executed by Public Utility District No. 2 of Grant County, Washington and Avista Corporation dated December 12, 2001 (effective November 1, 2005 for the Priest Rapids Development and November 1, 2009 for the Wanapum Development). | |||
| 10.8 | 1-3701 (with 2002 Form 10-K) | 10(b)-5 | Additional Product Sales Agreement (Priest Rapids Project) executed by Public Utility District No. 2 of Grant County, Washington and Avista Corporation dated December 12, 2001 (effective November 1, 2005 for the Priest Rapids Development and November 1, 2009 for the Wanapum Development). | |||
| 10.9 | 2-60728 | 5(g) | Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of September 18, 1963. | |||
| 10.10 | 2-60728 | 5(g)-1 | Amendment to Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of February 9, 1965. | |||
| 10.11 | 2-60728 | 5(h) | Reserved Share Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of September 18, 1963. | |||
| 10.12 | 2-60728 | 5(h)-1 | Amendment to Reserved Share Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of February 9, 1965. | |||
| 10.13 | 1-3701 (with September 30, 1985 Form 10-Q) | 1 | Settlement Agreement and Covenant Not to Sue executed by the United States Department of Energy acting by and through the Bonneville Power Administration and the Company, dated as of September 17, 1985, describing the settlement of Project 3 litigation. | |||
| 10.14 | 1-3701 (with 1981 Form 10-K) | 10(s)-7 | Ownership and Operation Agreement for Colstrip Units No. 3 and 4, dated as of May 6, 1981. | |||
| 10.15 | 1-3701 (with 1992 Form 10-K) | 10(s)-1 | Agreements for Purchase and Sale of Firm Capacity between the Company and Portland General Electric Company dated March and June 1992. | |||
| 10.16 | 1-3701 (with 2011 Form 10-K) | 10.15 | Avista Corporation Executive Deferral Plan. (3) | |||
| 10.17 | 1-3701 (with 2011 Form 10-K) | 10.16 | Avista Corporation Executive Deferral Plan. (3)(8) | |||
| 10.18 | 1-3701 (with 2011 Form 10-K) | 10.17 | Avista Corporation Supplemental Executive Retirement Plan. (3)(8) | |||
| 10.19 | 1-3701 (with 2011 Form 10-K) | 10.18 | Avista Corporation Supplemental Executive Retirement Plan. (3)(8) | |||
| 10.20 | 1-3701 (with 1992 Form 10-K) | 10(t)-11 | The Company’s Unfunded Supplemental Executive Disability Plan. (3) | |||
| 10.21 | 1-3701 (with 2007 Form 10-K) | 10.34 | Income Continuation Plan of the Company. (3) | |||
| 10.22 | 1-3701 (with 2010 Definitive Proxy Statement filed March 31, 2010) | Appendix A | Avista Corporation Long-Term Incentive Plan. (3) | |||
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| Previously Filed (1) | ||||||
| Exhibit | With Registration Number | As Exhibit | ||||
| 10.23 | 1-3701 (with 2010 Form 10-K) | 10.23 | Avista Corporation Performance Award Plan Summary. (3)(9) | |||
| 10.24 | 1-3701 (with 2010 Form 10-K) | 10.24 | Avista Corporation Performance Award Agreement. (3)(9) | |||
| 10.25 | 1-3701 (with 2011 Form 10-K) | 10.24 | Avista Corporation Performance Award Agreement. (3)(10) | |||
| 10.26 | 1-3701 (with 2012 Form 10-K) | 10.25 | Avista Corporation Performance Award Agreement. (3)(11) | |||
| 10.27 | (2) | Avista Corporation Performance Award Agreement. (3)(12) | ||||
| 10.28 | 1-3701 (with Form 8-K dated June 21, 2005) | 10.1 | Employment Agreement between the Company and Marian Durkin in the form of a Letter of Employment. (3) | |||
| 10.29 | 1-3701 (with Form 8-K dated August 13, 2008) | 10.1 | Employment Agreement between the Company and Mark T. Thies in the form of a Letter of Employment. (3) | |||
| 10.30 | 333-47290 | 99.1 | Non-Officer Employee Long-Term Incentive Plan. | |||
| 10.31 | 1-3701 (with 2010 Form 10-K) | Form of Change of Control Agreement between the Company and its Executive Officers. (3)(5) | ||||
| 10.32 | 1-3701 (with 2010 Form 10-K) | Form of Change of Control Agreement between the Company and its Executive Officers. (3)(6) | ||||
| 10.33 | 1-3701 (with 2010 Form 10-K) | Form of Change of Control Agreement between the Company and its Executive Officers. (3)(7) | ||||
| 10.34 | 1-3701 (with 2010 Form 10-K) | Form of Change of Control Agreement between the Company and its Executive Officers. (3)(7) | ||||
| 10.35 | (2) | Avista Corporation Non-Employee Director Compensation. | ||||
| 10.36 | 1-03701 (with May 4, 2012 Form 10-Q) | 10.1 | Ecova, Inc. (formerly known as Advantage IQ, Inc.) Second Amended and Restated 1997 Stock Plan | |||
| 12 | (2) | Statement Re: computation of ratio of earnings to fixed charges. | ||||
| 21 | (2) | Subsidiaries of Registrant. | ||||
| 23 | (2) | Consent of Independent Registered Public Accounting Firm. | ||||
| 31.1 | (2) | 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 | (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 | (4) | Certification of Corporate Officers (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002). | ||||
| 101 | (2) | The following financial information from the Annual Report on Form 10 K for the period ended December 31, 2013, formatted in XBRL (Extensible Business Reporting Language) and filed electronically herewith: (i) the Consolidated Statements of Income; (ii) Consolidated Statements of Comprehensive Income; (iii) the Consolidated Balance Sheets; (iv) the Consolidated Statements of Cash Flows; (v) the Consolidated Statements of Equity and Redeemable Noncontrolling Interests; and (vi) the Notes to Consolidated Financial Statements. | ||||
| (1) | Incorporated herein by reference. |
| (2) | Filed herewith. |
| (3) | Management contracts or compensatory plans filed as exhibits to this Form 10-K pursuant to Item 15(b). |
| (4) | Furnished herewith. |
| (5) | Applies to Christy M. Burmeister-Smith, Don F. Kopczynski, James M. Kensok, David J. Meyer, Kelly O. Norwood, Jason R. Thackston, Dennis P. Vermillion, and Roger D. Woodworth. |
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| (6) | Applies to Marian M. Durkin, Karen S. Feltes, Scott L. Morris, and Mark T. Thies. |
| (7) | Applies to executive officers appointed after October 1, 2010. The Company does not currently have any officers that these agreements apply to. |
| (8) | Applies to executive officers appointed after February 4, 2011. The Company does not currently have any officers that these plans apply to. |
| (9) | Applies to awards in 2010. |
| (10) | Applies to awards in 2011. |
| (11) | Applies to awards in 2012. |
| (12) | Applies to awards in 2013. |
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