ITEM 1. BUSINESS
NV Energy, Inc. is an investor-owned holding company that was incorporated under Nevada law on December 12, 1983. The company’s stock is traded on the New York Stock Exchange under the symbol “NVE”. NVE’s mailing address is P.O. Box 98910 (6226 West Sahara Avenue), Las Vegas, Nevada 89151.
NVE has four primary, wholly-owned subsidiaries: Nevada Power Company d/b/a NV Energy, Sierra Pacific Power Company d/b/a NV Energy, NVE Insurance Company, Inc. and Lands of Sierra. References to NVE refer to the consolidated entity, except where the context provides otherwise. NPC and SPPC are referred to collectively in this report as the “Utilities”.
The Utilities operate three business segments, as defined by the Segment Reporting Topic of the FASC: NPC electric; SPPC electric; and SPPC natural gas. Electric service is provided by NPC to Las Vegas and surrounding Clark County, and by SPPC to northern Nevada. Natural gas service is provided by SPPC in the Reno-Sparks area of Nevada. The Utilities are the major contributors to NVE’s financial position and results of operations. Other subsidiaries either do not meet the definition of a segment or are below the quantitative threshold for separate segment disclosure and are combined under “all other” in the following pages. Parenthetical references are included after each major section title to identify the specific entity or entities addressed in the section. See Note 2, Segment Information, of the Notes to Financial Statements, for further discussion.
NPC is a Nevada corporation organized in 1929 and, by itself and through a predecessor corporation, has been providing electric services to southern Nevada since 1906. NPC became a subsidiary of NVE in July 1999. Its mailing address is P.O. Box 98910 (6226 West Sahara Avenue), Las Vegas, Nevada 89151.
NEICO is a wholly-owned subsidiary of NPC. NEICO is a 25% member of Northwind Aladdin, LLC, the other 75% of Northwind Aladdin, LLC is owned by Macquarie Infrastructure Company Trust.
A Nevada corporation since 1965, SPPC was originally incorporated in Maine in 1912. SPPC became a subsidiary of NVE in 1984. Its mailing address is P.O. Box 10100 (6100 Neil Road), Reno, Nevada 89520-0024.
SPPC has three primary, wholly-owned subsidiaries: GPSF-B, PPC and PPIC. GPSF-B, PPC and PPIC, collectively, own Piñon Pine Company, LLC, which was formed to utilize federal income tax credits available under Section 20 of the Internal Revenue Code associated with the alternative fuel (syngas) produced by the coal gasifier located at the Piñon Pine facility.
Periodic reports for NVE, NPC and SPPC on Form 10-K and Form 10-Q and current reports on Form 8-K are made available to the public, free of charge, on NVE’s website (www.nvenergy.com) through links on this website to the SEC’s website at www.sec.gov, as soon as reasonably practicable after they have been filed with the SEC. The contents of the above referenced website address are not part of this Form 10-K. The public may also read any copy of materials filed with the SEC by NVE, NPC or SPPC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-(800) SEC-0030. Reports, proxy and information statements, and other information regarding NVE, NPC and SPPC may also be obtained directly from the SEC’s website, www.sec.gov. Available on the nvenergy.com website are the code of ethics for the chief executive officer, chief financial officer and controller, charters for the Audit, Compensation, Finance, and Nominating and Governance Committees of NVE’s BOD and our corporate governance and standards of conduct guidelines. Printed copies of these documents may be obtained free of charge by writing to NVE’s Corporate Secretary at NV Energy, Inc., 6226 West Sahara Avenue, Las Vegas, Nevada 89146.
The statistical data used throughout this 2012 Form 10-K, other than data relating specifically solely to NVE and its subsidiaries, are based upon independent industry publications, government publications, reports by market research firms or other published independent sources. We did not commission any of these publications or reports. These publications generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy or completeness of such information. While we believe that each of these studies and publications is reliable, we have not independently verified such data and make no representation as to the accuracy of such information.
Overview
NPC and SPPC are public utilities that generate, transmit and distribute electric energy in Nevada and, in the case of SPPC, also deliver natural gas service. At year-end 2012, NVE served approximately 1.2 million electric customers, of which approximately 850,000 electric customers primarily in Las Vegas, North Las Vegas, Henderson and adjoining areas were served by NPC, and approximately 324,000 electric customers in an approximate 42,000 square mile area of western, central and northeastern Nevada, including the cities of Reno, Sparks, Carson City, and Elko were served by SPPC. Additionally, SPPC provided natural gas service to approximately 153,000 customers in an area of about 800 square miles in Nevada’s Reno/Sparks area.
Major industries served by the Utilities include gaming/recreation, mining, warehousing/manufacturing and governmental entities. The Utilities’ revenues and operating income are subject to fluctuations during the year due to the impacts that seasonal weather, rate changes and customer usage patterns have on demand for electric energy and services. NPC is a summer peaking utility, experiencing its highest retail energy sales in response to the demand for air conditioning. SPPC’s electric system peak also occurs in the summer, with a slightly lower peak demand in the winter. SPPC’s gas business typically peaks in the winter months due to heating demands.
NPC and SPPC service territories are as follows:
NVE Transformation
Beginning in 2006, NVE committed to an energy strategy to manage resources in relation to our load by constructing/purchasing generating facilities, purchasing and developing renewable energy, encouraging energy efficiency and conservation programs, as well as expanding our transmission capability in an effort to reduce our reliance on purchased power. The implementation of this strategy required significant amounts of liquidity and capital. To meet these capital requirements during the transformation, NVE and the Utilities issued, refinanced and reduced debt which improved credit ratings and decreased interest costs. At the same time, management worked with the PUCN to communicate the necessity of investments to better serve our customers, the prudency of costs incurred and the importance of a reasonable and timely return on investment for our shareholders.
As discussed above, in 2006, the Utilities embarked on their energy strategy to manage resources in relation to their load. Since then the energy strategy has transformed to include: empowering customers through focused service and efficiency programs,
pursuing cost-effective renewable energy initiatives, optimizing generating facilities and enhancing transmission capabilities, and engaging employees to improve processes, reduce costs and enhance performance. The details of this energy strategy are discussed below:
Energy Strategy
Empower customers through focused service and efficiency programs
NV Energize
NV Energize is a NVE project which includes Advanced Meter Infrastructure, Smart Grid Technology and Meter Data Management. The NV Energize capabilities will allow NVE to help customers better manage their usage with the most cost-effective mix of pricing, service, efficiency and conservation options. As of December 31, 2012, NVE has installed approximately 1.3 million Smart Meters in Nevada, and the implementation of the NV Energize project is nearing completion. NVE expects to substantially complete the installation process of the final 80,000 meters before the end of the second quarter of 2013.
The NV Energize system provides more convenience for customers and is achieving operating savings through both automated meter reading and the elimination to date of approximately one million trips to customers’ premises to process service requests. The system also enables NVE to launch new customer programs. Recruitment of participants for a trial of a combination of time based rates, supporting technology and education options is now underway. New detailed customer usage reports have been integrated into our web self-service capability, and customers can also request alerts on their billing information. An enhanced air conditioning demand response program was launched in the fourth quarter. It is designed to provide energy market based rebates for specific event participation and also includes an energy efficiency management capability. Similar programs for commercial customers are under development.
Pursue cost-effective renewable energy initiatives
Even before Nevada first adopted the Portfolio Standard in 1997, NVE has been committed to renewable energy. As part of our continued commitment, NVE will seek the most competitive opportunities that will benefit our customers, our companies, our state, and our environment. NVE has a number of tools available to undertake renewable energy initiatives, including construction of new renewable energy facilities, entering into new renewable energy contracts, exploring opportunities to either jointly construct or develop renewable energy projects, investment in renewable energy projects, undertaking short-term purchases from existing renewable facilities and restructuring existing renewable relationships for the benefit of our customers.
NVE has been required by statute to comply with the Portfolio Standard since 1997, when Nevada first mandated that a certain percentage of the energy that the Utilities deliver come from renewable energy resources (including solar energy) and efficiency measures. In 2013, the Utilities are required to obtain an amount of PECs equivalent to 18% of their total retail energy from renewable energy resources, with up to 25% of this amount eligible to be met with energy efficiency measures and at least 5% required to be met with solar energy resources. The Portfolio Standard increases every two to five years until it reaches 25% in 2025. NVE is committed to meeting the Portfolio Standard using the most cost-effective means for our customers and undertaking those renewable energy opportunities that present the greatest value for our companies and our customers.
Optimizing generating facilities and enhancing transmission capabilities
Since 2006, when NVE began its energy independence initiative, we have added over 3,800 MWs (nominally rated) of internal generation. As a result, NVE may obtain approximately 80% of its energy from internal generation. In 2013, NVE’s management continues to strive to optimize the Utilities’ energy portfolio in order to meet load obligations in a cost effective and reliable manner. In addition, to the extent the Utilities have the economic opportunity to sell excess capacity or energy, they may enter into such transactions to reduce overall energy costs. NVE anticipates it will have sufficient resources to meet its forecasted load requirements for 2013. However, resource adequacy could be affected by a number of factors, including the unplanned retirement of generating stations, plant outages, the timing of commercial operation of renewable energy projects and associated purchase power agreements, customer behavior with respect to energy efficiency and conservation programs, and environmental regulations which may limit our ability to operate certain generating units.
Construction of ON Line
NVE will continue with the construction of ON Line which will enable us to optimize our generation assets by enhancing our transmission capabilities. Upon completion (expected in late 2013), ON Line will connect NVE’s southern and northern service territories and, pending certain state and federal regulatory approvals, will provide the ability to jointly dispatch energy throughout the
state and provide access to renewable energy resources in parts of northern and eastern Nevada, which will enhance NVE’s ability to manage its Portfolio Standard, discussed above, and optimize its generating facilities. ON Line will also provide the opportunity for NVE to merge NPC and SPPC (the “One Company” merger). A merger application is expected to be filed with the PUCN and FERC by mid-2013.
ON Line is Phase 1 of a Joint Project between the Utilities and GBT-South. The Joint Project consists of two phases. In Phase 1 of the Joint Project, the parties would complete construction of a 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen substation on the NPC system. The Utilities own a 25% interest in ON Line and have entered into a TUA with GBT-South for its 75% interest in ON Line. The Utilities’ 25% interest in ON Line, which approximates $138 million (excluding AFUDC), will be allocated 95% and 5% to NPC and SPPC, respectively. See the Transmission section, later, for further details of ON Line. Also, see the Integrated Resource Plan section, later, for further discussion of certain regulatory matters concerning ON Line.
Engage employees to improve processes, reduce costs, and enhance performance
The Utilities will continue to control operating and maintenance and capital costs through diligent review and process improvement initiatives by providing appropriate tools to our employees to find ways to reduce costs, improve processes, and enhance performance. This is particularly important at a time when customer growth is low. Going forward this will continue to be an over-arching theme of our energy strategy. Our goal is to reduce or eliminate upward pressure on our customers’ prices while always delivering safe and reliable energy and assure compliance with all laws and regulations.
Business and Competitive Environment
Operations
NPC and SPPC Electric
The Utilities are charged with meeting the energy needs for most of Nevada. Revenues are impacted by rate changes, cost of fuel and purchased power, seasonal or atypical weather and customer use. The Utilities’ electric peak demand occurs in the summer. Therefore, the Utilities’ revenues and associated expenses are not incurred or generated evenly throughout the year.
To serve their customer base, the Utilities generate electricity and purchase power in accordance with an ESP, as discussed in more detail later in this section, under Energy Supply.
SPPC Gas
The Gas LDC is responsible for providing natural gas to residential, commercial and industrial customers. SPPC is well connected with several major gas producing regions and gas transportation systems into northern Nevada. SPPC’s gas distribution system receives gas supplies from two interstate natural gas pipelines, the Paiute Pipeline Company and the Tuscarora Gas Transmission Company. In addition, SPPC has contracted for natural gas storage services to supplement firm and spot market purchases.
Regulatory Environment
The FERC and PUCN regulate portions of the Utilities’ accounting practices and electricity and natural gas rates. The FERC has jurisdiction under the Federal Power Act with respect to wholesale rates, service, interconnection, accounting, and other matters in connection with the Utilities sale of electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which the Utilities buy transportation for natural gas. The PUCN has authority over rates charged to retail customers, the issuance of securities by the Utilities and transactions with affiliated parties.
Nevada state regulations require the Utilities to file electric GRCs every three years with the PUCN to adjust rates, based primarily on cost of service and return on investment. Nevada state regulations also require the Utilities to file annual DEAA applications to review costs for prudency and reasonableness, and if any costs are disallowed on such grounds, the disallowance will be incorporated into the next subsequent rate change. The Utilities may also file to reset BTERs quarterly, based on the last 12 months fuel and purchased power costs. Additionally, Nevada regulations allow an electric or gas utility that adjusts its BTER on a quarterly basis to request PUCN approval to make quarterly changes to its DEAA rate if the request is in the public interest. Moreover, in 2010, the PUCN adopted regulations authorizing an electric utility to recover an amount from its customers that is attributable to the measurable and verifiable effects associated with the Utilities’ implementation of energy efficiency and
conservation programs approved by the PUCN. In addition, the regulation approved the transition of the recovery of energy efficiency program costs from general rates (filed every three years) to recover through independent annual rate filings. The Utilities also file an triennial IRP, as discussed later. See Note 3, Regulatory Actions, of the Notes to Financial Statements, for further discussion on the various rate cases.
The PUCN regulations also require a Gas Supply Report as well as a Gas Informational Report to be filed annually. SPPC may also file gas GRCs to adjust gas division rates including cost of service and return on investment. Rate cases are discussed in more detail in Note 3, Regulatory Actions, of the Notes to Financial Statements.
Competition
NPC and SPPC Electric
The Utilities operate under certificates of public convenience and necessity as regulated by the PUCN, as well as, franchise agreements with local governments in their respective operating areas. Under Nevada state law, commercial customers with an average annual load of one MW or more may file a letter of intent and application with the PUCN to acquire electric energy, capacity, and ancillary services from another provider. The law requires customers wishing to choose a new supplier to receive the approval of the PUCN and meet public interest standards. In particular, departing customers must secure new energy resources that are not under contract to NPC or SPPC, the departure must not burden the Utilities with increased costs or cause any remaining customers to pay increased costs, and the departing customers must pay their portion of any deferred energy balances. The PUCN adopted regulations prescribing the criteria that will be used to determine if there will be negative impacts to remaining customers or to the Utilities. Customers wishing to choose a new supplier must provide 180-day notice to NPC or SPPC. The Utilities would continue to provide transmission, distribution, metering, and billing services to such customers.
Currently, there are no material applications pending with the PUCN to exit the system in NPC’s or SPPC’s service territory.
Commercial customers who receive approval from the PUCN to acquire electric energy, capacity, and ancillary services from another provider, and who may have previously received service from the Utilities, may migrate to being served under the provisions of a DOS agreement. Under a DOS agreement, customer-specific facilities charges will continue to be collected along with a flat distribution charge per meter. Currently, NPC and SPPC have 50 and three premises served, respectively, under the DOS tariff.
Distributed generation remains a relatively limited source of competition for the Utilities. However, changes in law, technological improvements and differences in regulatory oversight for distributed generation providers may result in increased competition for the Utilities in the future.
SPPC Gas
SPPC’s natural gas LDC business is subject to competition from other suppliers and other forms of energy available to its customers. Large gas customers using 12,000 therms per month with fuel switching capability are allowed to participate in the Incentive Natural Gas Rate tariff. Once a service agreement has been executed, a customer can compare natural gas prices under this tariff to alternative energy sources and choose their source of fuel. Additionally, customers using greater than 1,000 therms per day have the ability to secure their own gas supplies under the Transportation Tariff. As of January 1, 2013, there were 17 large customers securing their own supplies. These customers have a combined firm distribution load of approximately 5,739 Dth per day. Transportation customers continue to pay firm and interruptible distribution charges. These customers are responsible for procuring and paying for their own gas supply, which reduces SPPC’s purchases, but does not have an impact on net income.
Sales
In 2012, NVE’s revenues, NPC’s revenues and SPPC’s electric revenues were approximately $3.0 billion, $2.1 billion and $725.9 million, respectively. SPPC’s natural gas business revenues were approximately $108 million in 2012 or 13% of SPPC’s total revenues. In 2012, NVE’s, NPC’s and SPPC’s electric system peaks were 7,437 MW, 5,761 MW and 1,676 MW, respectively, compared to 7,052 MW, 5,539 MW and 1,513 MW, respectively, in 2011.
NVE’s electric customers by class contributed the following MWh sales:
NPC’s electric customers by class contributed the following MWh sales:
Total retail MWh sales increased approximately 3.6% in 2012 from 2011, primarily due to an increase in customer usage as a result of an increase in CDDs, as outlined in the tables below, particularly during the second quarter of 2012, as well as increased usage by certain industrial customers and slight growth in the number of customers. NPC’s average residential and commercial customers increased by 1.4% and 0.7%, respectively, while average industrial customers decreased by 1.5%.
SPPC’s electric customers by class contributed the following MWh sales:
Total retail MWh sales increased approximately 3.6% in 2012 from 2011, due to increased customer usage primarily due to an increase in CDDs as outlined in the table below and increased usage by mining customers. SPPC’s average number of residential and industrial customers increased by 0.7% and 4.7%, respectively, and commercial customers remained flat. SPPC’s total retail electric MWh sales decreased in 2011, as compared to 2010, primarily due to the sale of the California Assets to CalPeco in January 2011 and the sale of energy to CalPeco accounted for as a wholesale customer beginning in 2011.
HDDs and CDDs
MWh usage may be affected by the change in HDDs or CDDs in a given period. A degree day indicates how far that day's average temperature departed from 65 degrees Fahrenheit. HDDs measure heating energy demand and indicate how far the average temperature fell below 65 degrees Fahrenheit. CDDs measure cooling energy demand and indicate how far the temperature averaged above 65 degrees Fahrenheit. For example, if a location had a mean temperature of 60 degrees Fahrenheit on day 1 and 80 degrees Fahrenheit on day 2, there would be 5 HDDs (65 minus 60) and 0 CDDs for day 1. In contrast, there would be 0 HDDs and 15 CDDs (80 minus 65) for day 2.
The following table shows the heating degree days and cooling degree days within NPC’s and SPPC’s service territories for each of the last three years:
Demand
Load and Resources Forecast
NPC’s peak electric demand increased in 2012 to 5,761 MWs from 5,539 MWs in 2011. SPPC’s peak electric demand increased in 2012 to 1,676 MWs from 1,513 MWs in 2011. Variations in energy usage occur as a result of varying weather conditions, economic conditions, and other energy usage behaviors, such as conservation efforts by our customers. These variations necessitate a continual balancing of loads and resources and requires both purchases and sales of energy under short and long-term contracts as well as the prudent management and optimization of available resources.
The Utilities plan to meet their customers’ needs through a combination of company-owned-generation and purchased power. See the Generation section and Purchased Power section below for details of the Utilities’ generation assets and contracts for purchased power. Remaining needs will be met through power purchases through term RFPs or short-term purchases. As shown in the tables below, the Utilities have sufficient resources to meet anticipated customer requirements. However, resource adequacy may be affected by a variety of factors including, but not limited to, the unplanned retirement of generating stations, the timing or achievement of commercial operation with respect to renewable energy power projects not yet commercially operable, the intermittent generation of renewable energy resources, customer behavior with respect to energy efficiency, and conservation programs and environmental regulations which may limit our ability to operate certain generating units. Resource adequacy provides the Utilities the ability to maintain a reliable supply of energy; however as discussed under the Resource Optimization section, to the extent the resources are not needed, the Utilities will attempt to sell their additional availability in an effort to reduce costs.
Below are tables as of December 31, 2012 summarizing the forecasted summer electric capacity requirement and resource needs of NVE and the Utilities after consideration of energy conservation programs and the completion of ON Line (as discussed in the Transmission section later):
(1)
Includes projected system peak load plus 12% planning reserves.
(2)
Includes 232 MWs of peaking capacity at Reid Gardner Generating Station Unit No. 4, which is co-owned with CDWR, see Item 2, Properties. The increase in 2016 company-owned generation is based on the assumption that the purchase option with respect to the Sunpeak units will be exercised. Currently MWs associated with the Sun Peak units are included in power purchases. The decrease in company-owned generation is due to the retirement of Tracy Units 1 and 2, expected as of January 1, 2015.
(3)
Includes long term purchase power agreements for renewable energy that are not yet commercially operable and/or may not materialize due to project delays, under performance, or cancelations.
(4)
Total additional required is the difference between the total requirements and total resources. Total additional required represents the amount needed to achieve the total requirement; conversely, additional resources represents resources in excess of the total requirement.
(1)
Includes projected system peak load plus 12% planning reserves.
(2)
Includes 232 MWs of peaking capacity at Reid Gardner Generating Station Unit No. 4, which is co-owned with CDWR, see Item 2, Properties. The increase in 2016 company-owned generation is based on the assumption that the purchase option with respect to the Sunpeak units will be exercised. Currently MWs associated with the Sun Peak units are included in power purchases.
(3)
Includes long term purchase power agreements for renewable energy that are not yet commercially operable and/or may not materialize due to project delays, under performance, or cancelations.
(4)
Total additional required is the difference between the total requirements and total resources. Total additional required represents the amount needed to achieve the total requirement; conversely, additional resources represents resources in excess of the total requirement..
(1)
Includes projected system peak load plus 15% planning reserves.
(2)
The decrease in company-owned generation is due to the retirement of Tracy Units 1 and 2, expected as of January 1, 2015.
(3)
Total additional required represents the difference between the total requirements and total resources. Total additional required represents the amount needed to achieve the total requirement; conversely, additional resources represents resources in excess of the total requirement.
Resource Optimization
Resource optimization entails the prudent dispatch of company generation, as well as the purchase and sale of electric power, fuel and financial energy products by the Utilities. The Utilities optimize their portfolios continuously in order to meet load obligations in a cost effective and reliable manner within transmission constraints. The Utilities continuously monitor the resources available to meet load obligations, recognizing the uncertainty not only in system conditions, such as planned and unplanned outages of generating or transmission facilities, but also in regional energy markets organized across different commodities, locations, demand and trading timeframes. As conditions change and new information becomes available, the Utilities optimize their portfolios as appropriate to account for changes in load, cost, volatility, reliability and other commercial or technical factors.
Energy Supply
Total System
The Utilities manage a portfolio of energy supply options. The availability of alternate resources allows the Utilities to dispatch its electric generation system in a more cost-effective manner under varying operating and fuel market conditions while maintaining system integrity. During 2012, NVE generated 68.6% of its total system requirements, purchasing the remaining 31.4%, NPC generated approximately 74.0% of its total system requirements, purchasing the remaining 26.0%, and SPPC generated 55.3% of its total electric energy requirements, purchasing the remaining 44.7% as shown below.
As a supplement to their own generation, the Utilities purchase spot, short-term firm, intermediate-term firm, long-term firm, and non-firm energy to meet its customer demand requirements. Total energy supply includes purchases from outside the electric system due to limited control area generation and also the need to access market energy supplies. The Utilities decision to purchase this energy is based on economics, mitigation of availability risk, and system import limits. Firm block purchases are transacted as both a price hedging strategy and to ensure that needed firm capacity is available over peak load periods. Spot market energy is purchased based on the economics of purchasing “as-available” energy when it is less expensive than the Utilities own generation, again, subject to net system import limits.
NPC’s 2012 company generated MWhs increased 9.7% from 2011 resulting in a corresponding decrease in purchase power. SPPC’s 2012 company generated MWhs also increased 12.8% resulting in a decrease in purchase power compared to 2011. See Energy Supply, above, for additional information regarding the Utilities’ purchasing strategies.
Generation
NPC’s generation capacity consists of a combination of 44 gas, oil and coal generating units with a combined summer capacity of 4,570 MWs as described in Item 2, Properties. In 2012, NPC generated approximately 74.0% of its total system requirements.
SPPC’s generation capacity consists of a combination of 17 gas, oil and coal generating units with a combined summer capacity of 1,508 MWs as described in Item 2, Properties. In 2012, SPPC generated approximately 55.3% of its total system requirements.
Fuel Sources
The Utilities’ 2012 fuel sources for electric generation were primarily provided by natural gas and coal. The average costs of gas and coal, including hedging costs, for energy generation per MMBtu for the years 2008 through 2012, along with the percentage contribution to the Utilities’ total fuel sources were as follows:
For a discussion of the change in fuel costs, see Results of Operations in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.
NPC has two long term coal supply contracts for the Reid Gardner Generating Station with Arch Coal Sales Company, a subsidiary of Arch Coal, Inc. (“Arch”) that extend through December 31, 2013. Coal shipped under these contracts is supplied from Arch’s mine in Central Utah. These contracts represent 73% of the current forecasted coal requirements of Reid Gardner Generating Station for 2013. However, as of December 31, 2012, NPC’s Reid Gardner Generating Station coal inventory level was 357,915 tons, or approximately 97 days of consumption at full capacity.
A take or pay transportation services contract with the Union Pacific Railroad Company that extends through 2014 provides for unit train coal deliveries from various mines in Utah, Colorado and Wyoming as well as from the Provo, Utah interchange to the Reid Gardner Generating Station in Moapa, Nevada.
The Navajo Generating Station is jointly owned by NPC along with five other entities and is operated by Salt River Project. Coal is obtained under a Coal Sales Agreement with Peabody Western Coal Company that extends through 2019. Coal is supplied from the Kayenta Mine’s surface mining operations conducted on Navajo Nation and Hopi Tribe reservation lands on the Black Mesa in Arizona.
In 2012, NPC used a four season ahead physical gas laddering strategy to cover the time period beginning with summer season 2012. NPC employs two seasonal competitive bidding processes each year. Therefore, the physical gas prices are set at an appropriate industry index during the month of current delivery. Natural gas is delivered to NPC through the use of firm gas transport contracts. Monthly and daily gas supply adjustments are made based on the current energy marketplace and operational considerations.
The laddering strategy entails the purchase of one quarter of NPC’s gas supply approximately two years before delivery, another quarter about 18 months before delivery, another quarter about 12 months before delivery and the last quarter procured about 6 months before delivery, or one season ahead. NPC utilizes this strategy in an attempt to ensure that all required gas supply for a season is not procured at one point in time, a point in time that may be subject to supply constraints and/or high premiums.
To secure gas supplies for the generating stations that NPC either owns or has under long-term contract (tolling arrangements), NPC contracted for firm winter, summer, and annual gas supplies with numerous domestic suppliers. In 2012, for generating stations located in NPC’s control area, gas supply net purchases averaged approximately 317,645 Dth per day, with the winter period contracts averaging approximately 256,704 Dth per day, and the summer period contracts averaging approximately 360,645 Dth per day.
Listed below is NPC’s transportation portfolio as of December 31, 2012:
Domestic gas supplies are accessed utilizing gas transport service from Kern River directly to Lenzie, Silverhawk, Higgins, Harry Allen, and Reid Gardner (for start-up only) Generating Stations or from Kern River to SWG and then to LV Cogen 1, LV Cogen 2, Clark, and Sunpeak Generating Stations.
For a discussion of the change in fuel costs, see Results of Operations in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.
SPPC has a long-term coal supply contract with Black Butte Coal Company for the Valmy Generating Station that extends through December 31, 2015. Coal shipped under this contract is supplied from Black Butte’s surface mine in Southern Wyoming. This contract represents 98% of the current forecasted coal requirements of Valmy Generating Station for 2013, 132% for 2014, and 64% for 2015. However, as of December 31, 2012, SPPC’s coal inventory level at Valmy Generating Station was 395,061 tons or approximately 131 days of consumption at full capacity.
A take or pay transportation services contract with Union Pacific Railroad Company that extends through 2014 provides for unit train coal deliveries from various mines in Utah, Colorado and Wyoming as well as from the Provo, Utah interchange to the Valmy Generating Station near Battle Mountain, Nevada.
In 2012, SPPC used a four season ahead physical gas laddering strategy, similar to NPC. SPPC employs two seasonal competitive bidding processes each year. Therefore, the physical gas prices are set at an appropriate industry index during the month of current delivery. Natural gas is delivered to SPPC through the use of firm gas transport contracts. Monthly and daily gas supply adjustments are made based on the current energy marketplace and operational considerations.
SPPC Gas
SPPC plans its gas transportation and supply to serve a demand that would occur if the average of the high and low temperatures for a given day drops to negative five degrees Fahrenheit, which is estimated to be 192,840 Dth per day for the winter of 2012/2013.
To secure gas supplies for SPPC’s generating stations and the LDC, SPPC contracted for firm winter, summer, and annual gas supplies with numerous Canadian and domestic suppliers using a four season ahead physical gas laddering strategy discussed above. In 2012, seasonal and monthly gas supply net purchases averaged approximately 125,134 Dth per day with the winter period contracts averaging approximately 144,986 Dth per day (November 2011- March 2012), and the summer period contracts averaging approximately 110,191 Dth per day (April - October 2012).
SPPC’s firm natural gas supply is supplemented with natural gas storage services and supplies from Northwest’s facility located at Jackson Prairie in southern Washington. The Jackson Prairie facility can contribute up to a total of 12,687 Dth per day of peaking supplies. In an effort to optimize the value of SPPC’s assets, from November 2011 through October 2012 and November 2012 through October 2013, SPPC entered into one year agreements whereby the respective counterparty acquired the rights to the Jackson Prairie storage facility and some of SPPC’s gas transport assets during the term of the agreement with SPPC retaining the ability to call on the resources, subject to limitations.
SPPC also has storage on the Paiute Pipeline system. This liquefied gas storage facility provides for an incremental supply of 23,000 Dth per day and is available at any time during the winter with two hours notice. Therefore, this storage project supports increases in short term gas supply needs due to unforeseen events such as extreme weather patterns and pipeline interruptions.
Listed below is SPPC’s transportation and storage portfolio as of December 31, 2012:
Firm Transportation Capacity
Dth per day firm
Term
Northwest
68,696
Annual
Paiute
68,696
Winter
Paiute
61,044
Summer
Paiute
23,000
Winter (Storage related)
AB Nova (Canadian Pipeline)
130,319
Annual
BC System (Canadian Pipeline)
128,932
Annual
GTN
140,169
Winter
GTN
79,899
Summer
Tuscarora
172,823
Annual
Storage Capacity
Northwest
281,242
Storage Capacity (Jackson Prairie)
12,687
Daily Withdrawal Capacity
Paiute
303,604
Storage Capacity
23,000
Daily Withdrawal Capacity
Canadian gas supplies are accessed utilizing gas transport service on AB Nova to BC System to GTN to Tuscarora and then directly to Tracy Generating Station. Domestic gas supplies are also accessed utilizing gas transport on Northwest to Paiute and then directly to Ft. Churchill and Tracy Generating Stations. The LDC is dual sourced from the pipelines listed above.
Total LDC supply requirements in 2012 and 2011 were 14.6 million Dth and 16.7 million Dth, respectively. SPPC’s electric generating fuel requirements for 2012 and 2011 were 31.2 million Dth and 25.9 million Dth, respectively.
Water Supply
NPC and SPPC
Assured supplies of water are important for the Utilities’ generating plants, and at the present time, the Utilities have adequate water to meet their generation needs. Reliable water supply is critical to the entire desert southwest region, including the State of Nevada. The newer generation facilities in the Utilities’ fleet have been designed to minimize water usage and employ innovative conservation based technologies such as dry cooling and recycled water. Although there are current drought conditions in the Las Vegas area, water resources for most of these facilities rely on regional aquifers and recycled water that are not closely connected to transient drought conditions.
Purchased Power
Under the guidelines set forth in the respective ESPs, NPC and SPPC continue to manage a diverse portfolio of contracted and spot market supplies, as well as its own generation resources, with the objective of minimizing its net average system operating costs. During 2012, NPC and SPPC purchased approximately 26.0% and 44.7%, respectively, of their total electric energy requirements.
NPC Electric
NPC purchases both forward firm energy and spot market energy based on economics, regulatory requirements, operating reserve margins, and unit availability. NPC seeks to manage its loads efficiently by utilizing its generation resources and long-term purchase power contracts in conjunction with buying and selling opportunities in the market.
NPC has entered into long-term purchase power contracts (3 or more years) with suppliers that generate electricity utilizing gas and renewable resource facilities with a total nameplate capacity of approximately 2,401 MW and contract termination dates ranging from 2013 to 2038. Included in these contracts are approximately 797 MW of nameplate capacity of renewable energy of which approximately 229 MW of nameplate capacity are under development or construction and not currently available. The PECs from renewable resource facilities are used towards compliance with the Portfolio Standard. Energy from some of these contracts is delivered and sold to SPPC through intercompany related purchase power contracts due to the resource location and transmission constraints; however, NPC retains the PECs associated with such contracts. The completion of ON Line will give NPC the ability to take delivery of the energy from these contracts.
NPC is a member of the SRSG and the WSPP. NPC’s membership in the SRSG has allowed it to network with other utilities in an effort to use its resources more efficiently in the sharing of responsibilities for reserves.
NPC’s credit standing may affect the terms under which NPC is able to purchase fuel and electricity in the western energy markets; however, as a result of NPC’s investment grade credit rating over the last several years, this was not a significant factor in 2012.
SPPC Electric
SPPC purchases both forward firm energy and spot market energy based on economics, regulatory requirements, operating reserve margins, and unit availability. SPPC seeks to manage its loads efficiently by utilizing its generation resources and long-term purchase power contracts in conjunction with buying and selling opportunities in the market.
SPPC has entered into long-term purchase power contracts (3 or more years) with suppliers that generate electricity utilizing coal and renewable resource facilities, with a total nameplate capacity of approximately 415 MW and contract termination dates ranging from 2016 to 2039. Included in these contracts are approximately 212 MW of nameplate capacity of renewable energy. The PECs from renewable resource facilities are used towards compliance with the Portfolio Standard. Energy from one of these contracts is delivered and sold to NPC through an intercompany related purchase power contract due to the resource location and transmission constraints; however, SPPC retains the PECs associated with this contract. The completion of ON Line will give SPPC the ability to take delivery of the energy from these contracts.
SPPC is a member of the NWPP and WSPP. These pools have provided SPPC further access to reserves and spot market power, respectively, in the Pacific Northwest and Southwest. In turn, SPPC’s generation resources provide a backup source for other pool members who rely heavily on hydroelectric systems.
SPPC’s credit standing may affect the terms under which SPPC is able to purchase fuel and electricity in the western energy markets; however, as a result of SPPC’s investment grade credit rating over the last several years, this was not a significant factor in 2012.
Transmission
General
Electric transmission systems deliver energy from electric generators to distribution systems for final delivery to customers. Transmission systems are designed to move electricity over long distances because generators can be located anywhere from a few miles to hundreds of miles from customers.
The Utilities’ electric transmission systems are part of the Western Interconnection, the regional grid in the western United States. The Western Interconnection includes the interconnected transmission systems of fourteen western states, two Canadian provinces and the parts of Mexico that make up the Western Electricity Coordinating Council (WECC). WECC is one of eight regional councils of the NERC, the entity responsible for the reliability, adequacy and security of North America’s bulk electric system.
NPC’s transmission system links generating units within and outside of the NPC Balancing Authority Area for delivery to the NPC distribution system and provides interconnections with the balancing authority areas of Western Area Power Administration, Los Angeles Department of Water and Power, California Independent System Operator (“CAISO”), and PacifiCorp.
SPPC’s transmission system links generating units within the SPPC balancing authority area for delivery to the SPPC distribution system and provides interconnections with the balancing authority areas of Idaho Power, Los Angeles Department of Water and Power, CAISO, PacifiCorp, and Bonneville Power Administration.
The service territories of NPC and SPPC are not directly interconnected at present; however, the construction of ON Line, discussed below, is expected to be completed in late 2013 and will interconnect the systems for the first time.
Under the NERC Standards, the Utilities are Balancing Authorities, Transmission Operators, and Transmission Owners among other roles. As defined by NERC, the Balancing Authority integrates resource plans ahead of time, maintains load-interchange-generation balance within the Balancing Authority Area, and supports Interconnection frequency in real time (i.e., the Balancing Authority is responsible for assuring that the demands on the system are matched by an equivalent amount of resources, whether from generators within its area or from energy imports). The Transmission Operator is responsible for the reliability of its local transmission system, and operates or directs the operations of the transmission facilities. The Transmission Owner owns and maintains transmission facilities. The Utilities also schedule power deliveries over their transmission systems and maintain reliability through their operations and maintenance practices and by verifying that customers are matching loads with resources.
The Utilities plan, build, and operate transmission systems that delivered approximately 21,481,000 MWh and 8,558,000 MWh of electricity to NPC’s and SPPC’s retail customers, respectively, in their Balancing Authority Areas in 2012. The NPC system handled a system peak load of 5,761 MW in 2012 through approximately 1,725 miles of transmission lines and other transmission facilities ranging from 60 kV to 500 kV. The SPPC system handled a system peak load of 1,676 MW in 2012 through 2,050 miles of transmission lines and other facilities ranging from 55 kV to 345 kV. The Utilities process generation and transmission interconnection requests and requests for transmission service from a variety of customers. These requests usually involve new planning studies and the negotiation of contracts with new and existing customers.
Transmission Regulatory Environment
Transmission for the Utilities’ bundled retail customers is subject to the jurisdiction of the PUCN for rate making purposes. The Utilities provide cost based wholesale and retail access transmission services under the terms of a FERC approved Open Access Transmission Tariff (“OATT”). In accordance with the OATT, the Utilities offer several services to eligible customers:
• Network transmission service (equivalent to the service NVE provides for NVE’s bundled retail customers)
• Long-term and short-term firm point-to-point transmission service (“highest quality” service with fixed delivery and receipt points)
• Non-firm point-to-point service (“as available” service with fixed delivery and receipt points)
• Generation interconnection
• Retail open access
These services are all offered on a nondiscriminatory basis in that all potential customers, including the Utilities, have an equal opportunity to access the transmission system. The Utilities’ transmission business is managed and operated independently from the energy marketing business in accordance with FERC’s Standards of Conduct.
On October 31, 2012, NVE filed separate Notices of Transmission Rate Changes with FERC for NPC and SPPC. The filings requested incremental rate relief of approximately $14.5 million annually effective January 1, 2013. On December 31, 2012, FERC suspended the effective date of the rates until June 1, 2013 (except for two rates that were reductions from the existing rate which were effective January 1, 2013) and set the cases for hearing or settlement proceedings. See Note 3, Regulatory Actions, FERC Matters, of the Notes to Financial Statements for further discussion of these rate cases.
The One Nevada Transmission Line (“ON Line”)
As discussed earlier, the Utilities are currently constructing ON Line. ON Line is Phase 1 of a Joint Project between the Utilities and GBT-South. The Joint Project consists of two phases. In Phase 1 of the Joint Project, the parties will complete construction of a 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen substation on the NPC system. The Utilities own a 25% undivided ownership interest in ON Line under the terms of the Transmission Use and Capacity Exchange Agreement (TUA) with GBT-South, which owns the remaining 75% undivided ownership interest in ON Line. The Utilities’ 25% interest in ON Line, which approximates $138 million (based on the revised costs, discussed below) will be allocated 95% and 5% to NPC and SPPC, respectively. The Utilities will have rights to 100% of the capacity of ON Line during Phase 1 (estimated to be approximately 600-800 MW). If GBT elects to construct Phase 2, it would construct two additional transmission segments at either end of ON Line: one would extend from the Robinson Summit substation north to Midpoint, Idaho, and the other would commence at the Harry Allen substation and interconnect south at the Eldorado substation. GBT would pay for and own 100% of Phase 2 facilities. However, NPC and SPPC would have rights to transmission capacity from Midpoint to Eldorado (for a total of approximately 760 MW based on a rating of 2,000 MW for the completed Phase 1 and Phase 2 project).
In March 2012, NVE announced that the in-service date for ON Line would be delayed due to efforts to address wind-related damage sustained by some of the tower structures erected for the project. On June 29, 2012, NPC filed its triennial 2013 - 2032 IRP with the PUCN. The 2012 IRP included revised cost estimates for the ON Line project and provided an expected in-service date of no later than December 31, 2013. The overall ON Line construction budget was revised from approximately $510 million to approximately $552 million before AFUDC. The revised construction budget is based on the estimated cost of completing the project, including the costs for installation of mitigation measures identified to address the wind-induced vibration issues that delayed the project. The Utilities requested PUCN approval of the decision to continue with construction of ON Line with the revised in-service date and revised budget.
On December 24, 2012, the PUCN issued an order on NPC and SPPC’s IRP’s approving the Utilities’ request and finding that it was reasonable to continue with the construction of the ON Line project with the revised budget and according to the revised schedule, subject to certain conditions described below under Integrated Resource Plan.
Regional Planning
The Utilities are members of the WestConnect Subregional Transmission Planning Committee. This planning committee was established to provide coordinated transmission planning across the WestConnect footprint, including the Southwest Area Transmission Group, in which NPC participates, and the Sierra Subregional Planning Group, in which SPPC participates.
In October 2012, NPC and SPPC submitted a compliance filing to the FERC reflecting their participation with other jurisdictional utilities in the WestConnect Planning Management Committee relating to certain FERC Order 1000 requirements. FERC Order 1000, issued in July 2011, establishes certain procedural and substantive requirements relating to participation, cost allocation and non-incumbent developer aspects of regional and inter-regional electric transmission planning activities.
Integrated Resource Plan
The Utilities are required to file IRPs every three years, and as necessary, may file amendments to their IRPs. The IRPs are prepared in compliance with Nevada laws and regulations and cover a 20-year period. The IRPs develop a comprehensive, integrated plan that considers customer energy requirements and propose the resources to meet those requirements in a manner that is consistent with prevailing market fundamentals. The ultimate goal of the IRPs is to balance the objectives of minimizing costs and reducing volatility while reliably meeting the electric needs of NPC’s and SPPC’s customers. Projects approved through the IRP process still remain subject to prudency review by the PUCN. The ESP, discussed in detail later, operates in conjunction with the IRP. It serves as a guide for near-term execution and fulfillment of energy needs.
NPC Electric
In December 2012, the PUCN issued its order on NPC’s 2012 IRP, which included the following significant items:
•
Approval to proceed with the construction of ON Line with the revised budget ($552 million, excluding AFUDC) and according to the revised schedule (expected in service date of no later than December 31, 2013), assuming a satisfactory resolution of the wind-induced vibration issues.
•
Approval to defer the difference between the actual monthly payment to GBT and the monthly payment amount excluding all costs arising from the wind-induced vibration into a deferred regulatory asset for later investigation and disposition. The Utilities are authorized to accrue carrying charges on the portion of the deferred balance that is ultimately found by the PUCN to be prudently incurred.
•
Approval of various DSM programs to increase energy efficiency and conservation programs totaling approximately $6.0 million over the remaining one year action plan.
•
Deferred approval of NPC’s proposal to issue an RFP for additional renewable energy contracts for no more than 100 MW, subject to a PUCN rulemaking docket associated with the portfolio standard and resource planning process.
•
Approval of the long-term load forecast and the three-year forecast.
SPPC Electric
SPPC’s 2010 triennial IRP as amended includes the following significant items:
•
Approval of the long-term load forecast and the three-year forecast.
•
A finding that the sale of the California Assets to CalPeco is in the public interest of Nevada, authorizing and accepting the accounting adjustments and ratemaking treatment proposed by SPPC and authorizing entry into and performing transactions necessary to accomplish the sale of the California Assets to CalPeco. The sale of the California Assets was completed in January 2011. See Note 15, Assets Held for Sale, of the Notes to Financial Statements.
•
Authority to modify retirement dates for eleven remote generation facilities and retire and decommission ten remote generation facilities and to accumulate the costs of decommissioning and remediating the remote generation sites in separate regulatory assets subaccounts for recovery in a future GRC proceeding.
•
Affirmed the funding level for a transmission project approved in SPPC’s 2007 IRP filing of approximately $30 million.
•
Approval of DSM programs scopes, budgets, timetables and measures and the Demand Side Plan.
•
Similar approvals for ON Line, as discussed above under NPC.
Energy Supply Planning
General
The energy supply function at the Utilities encompasses the reliable and efficient operation of the Utilities’ owned generation, the procurement of all fuels and purchased power and resource optimization (e.g., physical and economic dispatch).
There is the potential for continued price volatility in each Utility’s service territory, particularly during peak periods. Too great a dependence on generation from the wholesale market can lead to power price volatilities depending on available power supply and prevailing gas prices. Both Utilities face load obligation uncertainty due to the potential for customer switching. Some counterparties in these areas have significant credit difficulties, representing credit risk to the Utilities. Finally, each Utility’s own credit situation can have an impact on its ability to enter into transactions.
In response to these energy supply challenges, the Utilities have adopted an approach to managing the energy supply function that has three primary elements. The first element is a set of management guidelines to procuring and optimizing the supply portfolio that is consistent with the requirements of a load serving entity with a full requirements obligation. The second element is an energy risk management and risk control approach that ensures clear separation of roles between the day-to-day management of risks and compliance monitoring and control; and ensures clear distinction between policy setting (or planning) and execution. Lastly, the Utilities will pursue a process of ongoing regulatory involvement and acknowledgement of the resource portfolio management plans.
Within the energy supply planning process, there are three key components covering different time frames:
1.
The PUCN-approved long-term IRP, which is filed every three years, has a twenty-year planning horizon;
2.
The PUCN-approved ESP which is an intermediate term resource procurement and risk management plan that establishes the supply portfolio strategies within which intermediate term resource requirements will be met, has a one to three year planning horizon; and
3.
Tactical execution activities with a one-month to twelve-month focus.
The ESP operates in conjunction with the PUCN-approved twenty-year IRP. It serves as a guide for near-term execution and fulfillment of energy needs. When the ESP calls for executing contracts of longer than three years, PUCN approval is required.
In developing and executing ESPs, management guidelines followed by the Utilities include:
•
Maintaining an ESP that minimizes supply costs and retail price volatility and maximizes reliability of supply over the term of the ESP;
•
Investigating feasible commercial options to execute the ESP;
•
Applying quantitative techniques and diligence commensurate with risk to evaluate and execute each transaction;
•
Monitoring the portfolio against evolving market conditions and managing the resource optimization options; and
•
Ensuring transparent and well-documented decisions and execution processes.
Energy Risk Management and Control
The Utilities’ efforts to manage energy commodity (electricity, natural gas, coal and oil) price risk are governed by the BOD's revised and approved Enterprise Risk Management and Control Policy. That policy created the EROC and made that committee responsible for the overall policy direction of the Utilities’ risk management and control efforts. That policy further instructed the EROC to oversee the development of appropriate risk management and control policies, including the Energy Risk Management and Control Policy.
The Utilities’ commodity risk management program establishes a control framework based on existing commercial practices. The program creates predefined risk thresholds and delineates management responsibilities and organizational relationships. The program requires that transaction accounting systems and procedures be maintained for systematically identifying, measuring, evaluating and responding to the variety of risks inherent in the Utilities’ commercial activities. The program’s control framework consists of a disclosure and reporting mechanism designed to keep management fully informed of the operation’s compliance with portfolio and credit limits.
Currently, the Utilities are not operating under a PUCN-approved hedging plan, nor are they hedged against commodities. However, the Utilities may purchase and sell financial instruments and physical products to maintain an energy risk management program that limits energy risk to levels consistent with ESPs approved by the CEO and the EROC.
Intermediate Term ESPs
The Utilities update their intermediate term ESPs annually. In June 2012, NPC filed its 2013-2015 ESP, and in August 2012, SPPC filed its ESP update for 2013. Both plans were approved by the EROC and the CEO prior to submission to the PUCN.
The summer needs of 2013 for both Utilities will be met through a portfolio consisting of self-generation, forward contracts for power and peaking and seasonal capacity, or synthetic tolling based contracts (e.g., power prices indexed to gas prices) while striving to provide the lowest cost energy within reliability and transmission constraints.
Long-Term Purchased Power Activities
The Utilities update their respective planning documents (IRPs, ESPs, and the Portfolio Standard Annual Report) on a regular and as needed basis to determine their energy and PEC needs. When the planning documents call for long term purchased power and/or PEC agreements, RFPs are issued, bids are evaluated, and contracts are executed with the successful bidders. Contracts requiring PUCN approval are submitted to the PUCN as part of the IRP or an amendment to an IRP. Long-term purchased power contracts are discussed in more detail earlier, under Purchased Power.
Short-Term Resource Optimization Strategy
The Utilities’ short-term resource optimization strategy involves both day-ahead (next day through the end of the current month) and real-time (next hour through the end of the current day) activities that require buying, selling and scheduling power resources to determine the most economical way to produce or procure the power resources needed to meet the retail customer load and operating reserve requirement. The Utilities commit and dispatch generating units based on the comparative economics of generation versus spot-market purchase opportunities. Any amount of excess capacity or energy is sold on the wholesale market, while any deficient capacity or energy position is filled by either buying on the spot market or utilizing available generating capacity.
The day-ahead resource optimization begins with an analysis of projected hourly loads, existing resources and operating reserve requirements. Firm forward take-or-pay contracts are scheduled and counted towards meeting the capacity needs of the day being pre-scheduled. The day-of resource optimization involves minimizing system production costs each hour by lowering or raising generating unit output or buying power and/or selling excess power in the wholesale market all in order to meet the system load requirement and operating reserve requirement. Any sale of excess power priced above the incremental cost of producing such power
reduces the net production cost of operating the electrical system and thereby benefits the end use customer. The Utilities endeavor to reduce the electrical systems’ net production cost by selling available excess energy when it exists.
Real-time resource optimization requires an hourly determination of whether to increase or decrease the loading of on-line generating units, commit previously off-line generating units, un-commit on-line generating units, sell excess power, or purchase power in the real-time market to meet the companies’ resource needs. In order to achieve the lowest production cost, the projected incremental or decremental cost of the next available generation resource options are compared to determine the lowest cost option.
Construction Program
NVE’s and the Utilities construction programs and estimated expenditures are subject to continuing review, and are periodically revised to include the rate of load growth, construction costs, availability of fuel types, the number and status of proposed independent generation projects, the need for additional transmission capacity in Nevada, regulatory considerations and impact to customers, NVE’s and the Utilities’ ability to raise necessary capital, and changes in environmental regulations. Under the Utilities’ franchise agreements, they are obligated to provide a safe and reliable source of energy to their customers. Capital construction expenditures and estimates are reflective of the Utilities’ obligation to serve their customer base. Estimated construction expenditures may change depending on additional resources needed by the Utilities as disclosed in the Load and Resources table, earlier.
Gross construction expenditures for 2012, including AFUDC-debt, net salvage and CIAC, were $498.9 million, $287.6 million and $211.3 million for NVE, NPC and SPPC, respectively, and for the period 2008 through 2012, were $4.1 billion, $3.2 billion and $907.8 million, respectively. Cash requirements related to construction projects in 2012 for NVE, NPC and SPPC were $414.3 million, $245.2 million and $169.1 million, respectively. Estimated construction expenditures for PUCN approved projects, projects under contract, environmental compliance projects and other base capital requirements are as follows (dollars in thousands):
Total estimated cash requirements related to NVE construction projects consist of the following (dollars in thousands):
Total estimated cash requirements related to NPC construction projects consist of the following (dollars in thousands):
Total estimated cash requirements related to SPPC construction projects consist of the following (dollars in thousands):
ENVIRONMENTAL (NVE, NPC AND SPPC)
As with other utilities, NPC and SPPC are subject to various environmental laws and regulations enforced by federal, state and local authorities. The EPA, NDEP, the Southern Nevada Health District, and the Clark County Department of Air Quality and Environmental Management administer regulations involving air quality, water pollution, solid, and hazardous and toxic waste. Nevada’s Utility Environmental Protection Act also requires the Utilities to obtain approval of the PUCN prior to construction of major utility, generation or transmission facilities.
From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities, our activities involve compliance with diverse laws and regulations which address noise, emissions, impacts to air and water, protected and cultural resources, and solid, hazardous, and toxic waste. Our activities often require complex and lengthy processes as we obtain approvals, permits or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including waste) requires release prevention plans and emergency response procedures. As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or our operations to ensure complete compliance. The most significant environmental laws and regulations, both in effect and proposed, that could impact NPC and SPPC are discussed below:
Federal Environmental Laws, Regulations and Regulatory Initiatives
Clean Air Standards
The Clean Air Act (CAA) provides a framework for protecting and improving the nation’s air quality and controlling mobile and stationary sources of air emissions. The 1990 amendments to the CAA impose limitations on the emissions of sulfur dioxide (SO2), nitrogen oxide (NOX) as well as other pollutants. All of the Utilities' fossil fuel generating stations are subject to these limitations and are in compliance with current standards. Congress has from time to time considered legislation that would amend the CAA to target specific emissions from electric utility generating plants. The EPA has also proposed potential regulations associated
with these types of emissions. If enacted, this legislation and/or regulations could require reductions in emissions of NOX, SO2, mercury and/or other pollutants. The CAA programs which most directly affect the State of Nevada and NVE’s electric generating facilities are described below:
Mercury and Air Toxics Standards (MATS)
In December 2011, the EPA signed for publication in the Federal Register a final rule regulating hazardous air pollutant (HAP) emissions from coal- and oil-fired electric utility steam generating units. The rule, referred to as the MATS rule requires coal- and oil-fired electric utility steam generating units to meet HAP emission standards reflecting the application of the maximum achievable control technology (MACT). The final MATS rule (previously referred to as the Utility MACT Rule) was published in the Federal Register on February 16, 2012. The final rule establishes emission limits for hazardous air pollutants from new and existing coal-fired and oil-fired steam electric generating units. The rule requires sources to comply with the emission limits by April 16, 2015, with a potential one year compliance extension available for sources that are unable to complete the installation of emission controls before the compliance deadline. Numerous petitions for review of the final MATS rule have been filed with the United States Court of Appeals for the District of Columbia. The court has established a schedule for the litigation that has final briefs being filed as soon as in April, 2013.
The final rule does not specifically list control technologies that are required to achieve the MATS emission standards. Coal- and oil-fired electric generating units are required to meet the applicable HAP emission limits using whatever control technology, or combination of technologies, they deem appropriate for their specific situation. In general, control technology requirements will be a function of the fuel being fired and the performance of existing air pollution control systems. Based on a review of emissions data available from NVE’s generating units, as well as emissions data available from EPA for similar sources, the Utilities anticipate that SO2 and/or acid gas reduction will be required at SPPC’s Valmy Generating Station, Unit 1 to achieve compliance with the MATS standards. At the present time, SPPC believes a dry sorbent injection system will be selected as the final control option for Unit 1, at an estimated capital cost for SPPC’s 50% ownership interest of approximately $6.4 million, excluding AFUDC. The actual cost will be dependent upon final engineering design.
Currently, all four of the units at the Reid Gardner Generating Station, as well as Unit 2 at the Valmy Generating Station are compliant with the MATS emission standards, based on the current fuel blend. However, NVE and the Utilities will continue to monitor the chemical coal composition utilized in these units to ensure continued compliance.
NAAQS
The CAA requires the EPA to set minimum NAAQS for certain air emissions including ozone, particulate matter, SO2 and nitrogen dioxide (NO2). The CAA established two types of NAAQS: (1) primary standards, which set limits to protect public health, and (2) secondary standards, which set limits to protect public welfare. Most NAAQS require measurement over a defined period of time (typically one hour, eight hours, twenty-four hours, or one year) to determine the average concentration of the pollutant present in a defined geographic area.
When a NAAQS has been established, each state must recommend, and the EPA must designate, the areas within its boundaries that meet NAAQS (“attainment areas”) and those that do not (“non-attainment areas”). Each state must develop a state implementation plan (“SIP”) to bring non-attainment areas into compliance with NAAQS and maintain good air quality in attainment areas. The NAAQS that affect or potentially affect our Utility operations are summarized below.
Ozone NAAQS
In March 2008, the EPA issued final rules adopting new, more stringent eight-hour NAAQS for ozone. The EPA lowered the primary and secondary standards from 84 parts per billion to 75 parts per billion. States were to submit plans to the EPA, no later than 2014, demonstrating attainment with the standard. In early 2010, the EPA proposed reducing the NAAQS for ozone from 75 parts per billion to a lower value, between 60 to 70 parts per billion; however this change was not finalized. The next scheduled reconsideration of the ozone standard will likely occur in 2013. It is believed that an ozone NAAQS in the range of 60 to 70 parts per billion would potentially redesignate new and largely rural areas of Nevada as nonattainment and require the development of plans to manage these airsheds back into an attainment status. In addition, the CAA requires states to make determinations about interstate transport of ozone and its impact on other states when the NAAQS is revised.
On December 20, 2012, the EPA approved Nevada's request to redesignate Clark County to attainment for the earlier 1997 eight-hour ozone standard while also approving Clark County's plan to maintain compliance with the standard through 2022. However, Clark County remains unclassifiable for the 2008 ozone standard. Assuming the EPA revises the ozone standard in 2013,
which is expected to go beyond the 2008 limit of 75 parts per billion; it is possible that Clark County will once again be designated as non-attainment for ozone.
Particulate Matter NAAQS
The EPA has developed annual NAAQS for coarse particulate matter (defined as particles of 10 micrometers or larger) and both annual and 24-hour NAAQS for fine particulate matter (particles with a size of up to 2.5 micrometers). Nevada counties have historically been meeting the existing particulate matter 2.5 standards. However, the Las Vegas/Clark County and Washoe County regions are in non-attainment for particulate matter 10 standards. In January 2013, the EPA published a new proposal for fine particles lowering the limit to 12.0 micrograms per cubic meter. In that notice, the EPA also retained the existing standards for coarse particle pollution.
Based on evidence obtained from monitoring, the State of Nevada believes the majority of fine particulates in the various regional airsheds do not originate from stationary sources but instead are attributable to forest and range fires as well as wood burning (stoves and fireplaces) during winter inversion events. At this time, it appears that the lowered fine particulate standard will not result in any new non-attainment designations in our service territory.
SO2 NAAQS
On June 22, 2010, the EPA established a new one-hour primary SO2 NAAQS at 75 parts per billion and revoked the 24 hour and annual SO2 NAAQS. The 3-hour secondary NAAQS was established at 0.5 parts per million.
Under the CAA, the EPA is legally required by June 3, 2013 to issue the final 1-hour SO2 NAAQS designations of attainment, non-attainment or unclassifiable for each county and portion of county within each state. The CAA also requires that states submit their state implementation plans (SIPs) demonstrating how they will attain and maintain the 1-hour SO2 NAAQS. For electric power plants with significant SO2 emissions, this means revisions to Title V Permits to establish or lower allowable SO2 emission rates among other measures.
Based on the State of Nevada’s evaluation, it appears that the newest SO2 standards will not result in any new non-attainment designations in our service territory
NO2 NAAQS
On February 9, 2010, the EPA established a new one-hour NAAQS for NO2 at the level of 100 parts per billion. To determine compliance with the new standard, the EPA is establishing new ambient air monitoring requirements near major roads as well as in other locations where maximum concentrations are expected. Although existing air quality monitors do not currently show exceedances of this new standard in the Utilities’ service areas, additional community and roadside monitoring could result in the designation of new non-attainment areas. The EPA intends to re-designate areas as soon as 2016, based on the air quality data from the new monitoring network. In the February rulemaking, the annual primary and secondary annual NO2 NAAQS was maintained at 53 parts per billion. Currently, the various state and county air districts in Nevada have submitted their implementation plans for managing the new NO2 standard to the EPA.
The recent changes to the NAAQS have not had a material impact to the Utilities’ operations. However, due to uncertainty regarding the potential stringency of any new NAAQS related proposals coming in the future, the Utilities will continue to monitor the development of these standards and assess their potential impact on our generation fleet as new information becomes available.
Regional Haze Rules
In 2005, the EPA finalized amendments to its Regional Haze Rules that require the installation and operation of emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the U.S. Certain NVE generating facilities are subject to BART requirements. Pursuant to the EPA’s Regional Haze Rules, individual states were required to identify the facilities located in their states that will have to reduce sulfur dioxide (SO2), nitrogen oxide (NOx) and particulate matter emissions under BART and then set emissions limits for those facilities.
In June 2011, the EPA published in the Federal Register its proposal to approve Nevada's State Implementation Plan (SIP) implementing the Regional Haze Rules for affected units in the State of Nevada, which includes units at our Reid Gardner, Tracy and Ft. Churchill Generating Stations. However, in March 2012, the EPA approved Nevada’s SIP as it pertains to all affected units and
emissions, except for NOx controls at Units 1-3 at the Reid Gardner Generating Station. The specified compliance date for this action, which includes the affected Tracy and Ft. Churchill Generating Station units, is January 1, 2015. In that same March 2012 Federal Register notice, the EPA stated that it intended to make a BART determination on those Reid Gardner Generating Station Units at a later date. In August 2012, the EPA published its final determination for NOx BART controls for the Reid Gardner Generating Station Units 1-3, approving and rejecting certain components of Nevada’s SIP. For the limited portions of Nevada’s SIP that EPA rejected, it put in place a Federal Implementation Plan (FIP) that will remain enforceable until such time as Nevada submits a revised SIP to address the concerns the EPA noted in its August 2012 Federal Register notice. Within the August 2012 notice, the EPA approved Nevada’s determination in its SIP that the installation of selective non-catalytic reduction technology (SNCR) represented BART for purposes of compliance with the Regional Haze Rule, with a specified compliance date of January 1, 2015. On October 19, 2012, NPC submitted to EPA a Petition for Reconsideration of the August 2012 final rule requesting EPA to reconsider the compliance deadline so that it be set no earlier than June 30, 2016, which would match the modified compliance data put forward by the State of Nevada. The modified State’s compliance date of 2016 also applies to SPPC. Since filing of the Petition for Reconsideration, NPC has participated in various discussions with EPA regarding the compliance date. A final decision from EPA on the Petition for Reconsideration remains pending.
NVE continues to work toward finalizing the retrofit designs for the affected BART units. NVE filed and has already received approval from the PUCN to retire Tracy Generating Station Units 1 and 2, and install retrofit controls on Tracy Generating Station Unit 3 and Ft. Churchill Generating Station Units 1 and 2. NVE intends to also file with the PUCN the request to install SNCRs on Reid Gardner Generating Station Units 1, 2 & 3. Compliance with the Regional Haze Rules are estimated to cost approximately $77.1 million, excluding AFUDC, over the next several years; however, these costs are preliminary and subject to change based on final engineering analysis and retirement of generating station units. NVE expects that costs incurred to comply with the Regional Haze Rules would be capitalized and recovered through the Utilities’ regulatory proceedings similar to other environmental compliance requirements.
Environmental groups have challenged both of the EPA’s final determinations with respect to Nevada’s regional haze SIP submittal. In May 2012, WildEarth Guardians petitioned the Ninth Circuit to review the EPA’s March 2012 approval of Nevada’s SIP for all affected units and emissions except NOx controls at the Reid Gardner Generating Station, alleging that the EPA’s approval did not conform to the requirements set forth in the Regional Haze Rule. NVE has intervened in that lawsuit. In October 2012, Earthjustice, on behalf of the Moapa Band of Paiute Indians, Sierra Club, and the National Parks Conservation Association, petitioned the Ninth Circuit to review the EPA’s August 2012 final determinations pertaining to NOx controls at the Reid Gardner Generating Station. NVE has intervened in this lawsuit. At this time management is unable to determine the likelihood of success by petitioners in these litigation matters. An adverse decision in either lawsuit could impact our compliance strategy for the Tracy, Ft. Churchill and Reid Gardner Generating Stations, and could result in the requirement to install more stringent emissions controls, or the retirement of certain units earlier than currently planned.
The Navajo Generating Station is also an affected unit under EPA’s Regional Haze Rules. On January 17, 2013, the EPA announced a proposed FIP addressing BART and an “Alternative to BART” for the Navajo Generating Station that includes a flexible timeline for reducing NOx emissions. NVE, along with the other owners of the facility, are reviewing the EPA proposal to determine its impact on the viability of the plant’s future operations. The land lease for the Navajo Generating Station is up for renewal in 2019. Renewal of this lease will require completion of an Environmental Impact Statement as well as a renewal of the fuels supply agreement, among other considerations. It is believed that the EPA BART proposal will require an investment of up to $1.1 billion in additional emission controls at the plant of which NPC’s ownership share is 11.3%. Given that the lease must be renegotiated by 2019, the timeline for BART installation is unclear, and EPA’s overall proposal will be subject to significant input from a variety of affected parties before it is finalized, NVE cannot predict at this time the ultimate financial impact to the Navajo Generating Station operations or what other alternative actions the ownership may decide to take.
Climate Change
The topic of climate change continues to evolve, and response to this issue brings with it significant environmental, economic and social implications for NVE and other electric utilities. Potential impacts from proposed legislation could vary, depending upon proposed carbon dioxide (CO2) emission limits, the timing of implementation of those limits, the program design, the degree to which offsets are allowed and available, and provisions for cost containment measures, such as a safety valve that provides a ceiling price for emission allowance purchases. However, the Utilities’ contribution of greenhouse gases (GHG) from its current generation fleet is partly mitigated due to our fuel portfolio being predominately natural gas which emits approximately 50% less CO2 than coal.
The impact on NVE and the Utilities of future initiatives related to GHG emissions and global climate change remains unknown. Although compliance costs are unlikely to be realized in the near future, federal legislative, federal regulatory, and state and regional-sponsored initiatives to control GHG emissions continue to progress, making it more likely that some form of control will
eventually be required. For example, California is moving forward with the adoption of a proposed state cap on GHG emissions and developing market-based compliance mechanisms, including compliance offset protocols.
Since these initiatives continue to evolve, NVE has and will continue to identify projects that minimize or offset GHG emissions and believes that precautionary actions to limit GHG emissions are appropriate.
The EPA finalized regulations in September 2009 that require certain categories of businesses, including fossil fuel-fired power plants, to monitor and report their emissions beginning in 2011. NVE has been reporting its annual GHG emissions since it joined the California Climate Action Registry in 2006 and has continued timely reporting into the national Climate Registry. As required by the EPA, NVE will continue to report annual GHG emissions to comply with the federal mandatory GHG reporting program.
After a series of developments and rule proposals, in March of 2010, the EPA affirmed its position that the CAA permitting requirements under the Prevention of Significant Deterioration (PSD) and Title V permit programs are not triggered for a pollutant until a regulatory requirement to control emissions of that pollutant becomes effective. As a result of this EPA determination, new or modified plants that were subject to PSD or Title V programs had to address GHG emissions in new permit applications as of January 2011. Similarly, GHG emitted above certain thresholds from existing plants were also covered under the Title V program beginning in January 2011. Currently, all NVE generation facilities have operating permits that could require modification to comply with the rule if modifications are undertaken. The extent to which this rule could have a material impact on our generating facilities depends upon whether physical changes or change in operations subject to the rule would occur at our generating facilities; future EPA determinations on what constitutes best available control technology for GHG emissions from power plants; and whether federal legislation is passed which overrides the rule. During 2012, none of NVE’s generation facilities triggered the criteria specified in this rule.
GHG - New Source Performance Standards (NSPS)
As an outcome from a 2010 settlement agreement with states and environmental groups, in April 2012, the EPA proposed the initial GHG NSPS for new electric generating units under the CAA. The proposed rule establishes carbon dioxide (CO2) emissions standards for pulverized coal, coal gasification and natural gas combined cycle electric generating units that are permitted and constructed in the future.
The settlement agreement also required the EPA to establish an NSPS program for existing sources on the same timeline as for new sources, both of which remain under review by the EPA. The EPA will eventually be compelled to produce GHG standards for existing sources which is anticipated for introduction sometime in 2013. Compliance could be expected as quickly as three to four years following the initial final proposal.
While the final outcome and timing for the EPA's actions cannot be estimated, the Utilities continue to monitor the development of these proposals and will assess their potential impact on their generation fleet as new information becomes available.
Clean Water Act Standards
The EPA administers rules establishing aquatic protection requirements for power generation facilities that withdraw and discharge large quantities of water from and into rivers, streams, lakes, reservoirs, estuaries, oceans, or other U.S. waters for cooling purposes, known as 316(b). In consideration of the desert environment in which the Utilities operate, none of the Utilities’ generation plants employ “once through” cooling water intake/discharge structures into public water bodies. Further, all of the Utilities’ generation stations are designed to have either minimal or zero water discharge into the surrounding environment. Therefore, the current laws regulating “once through” cooling water intake structures and thermal discharges of wastewater from power generation facilities do not adversely impact the NPC and SPPC generation sites.
Under the terms of a settlement agreement, the EPA agreed to finalize a new 316(b) rule by June 2013. Assuming that date is met, compliance with portions of the rule could begin as early as 2016. Due to uncertainties associated with any modified rule requirements, NVE is unable to estimate the impacts of this rulemaking on its Utilities. However, based on the water usage profile discussed previously, the impact appears minimal at this time.
The EPA is currently developing revised effluent limitation guidelines and standards for the steam electric power generating industry which are now expected to be introduced by April 2013. The EPA's revision of these guidelines is driven primarily by concern over wastewater discharges from coal-fired power plants, but will also address discharges from ash ponds and flue gas desulfurization air pollution controls. Under the terms of a related court-approved consent decree, the final rules must be published by January 31, 2014, unless an extension is granted. It is reasonable to expect that the new guidelines will impose more stringent limits
on wastewater discharges from coal-fired power plants and ash ponds. However, until the revised guidelines are proposed, it is impossible to predict the effect the revised guidelines may have on generating facility operations.
Coal Combustion Product (CCP) Management
In 2010, the EPA released the text of a proposed rule describing two possible regulatory options it is considering under the Resource Conservation and Recovery Act (RCRA) for the disposal of coal ash generated from the combustion of coal by electric utilities and independent power producers. Under either option, the EPA would regulate the construction of impoundments and landfills, and seek to ensure both the physical and environmental integrity of disposal facilities; however, none of the Utilities’ coal facilities currently manage ash in surface water impoundments; rather, these ash products are handled and processed in a dry form at both the Reid Gardner and Valmy Generating Stations. The Utilities believe it is possible that the EPA will continue to allow some beneficial use, such as recycling of ash, without classifying it as hazardous waste. However, any additional regulations which more stringently regulate the management disposal or reuse of coal ash will likely increase costs for NVE’s coal generation facilities if the ability to recycle this material is impaired or current landfill disposal requirements are modified. A final decision by the EPA is still pending; however, in response to a motion filed in federal court by environmental groups asking the court to compel the EPA to issue a final rule, the EPA filed a declaration in October 2012, suggesting that it may take more than one year to complete the regulation. Due to the uncertainties of how this material may ultimately be regulated in the future, the Utilities are unable to predict the outcome any such regulations might have on their systems at this time.
Remediation Activities
Due to the age and/or historical usage of past and present operating properties, the Utilities may be responsible for various levels of environmental remediation at contaminated sites. This can include properties that are part of ongoing Utility operations, sites formerly owned or used by NVE or the Utilities, and/or sites owned by third parties. The responsibility to remediate typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, NVE, the Utilities or their respective affiliates could potentially be held responsible for contamination caused by other parties. In some instances, NVE or the Utilities may share liability associated with contamination with other potentially responsible parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. These types of sites/situations are generally managed in the normal course of business operations.
GENERAL - EMPLOYEES (ALL)
NVE and its subsidiaries had 2,699 employees as of January 22, 2013, of which 1,524 were employed by NPC, and 1,075 were employed by SPPC.
NPC and IBEW 396, which covers approximately 54% of NPC’s workforce, have signed an agreement to extend the current collective bargaining agreement (CBA) from an original expiration of January 31, 2013 to June 15, 2013. All terms of the current CBA will remain in effect until June 15, 2013.
On August 12, 2010, SPPC and IBEW Local 1245, which covers approximately 56% of SPPC’s workforce, entered into a new CBA. The CBA is effective August 16, 2010 for a three-year period ending August 15, 2013.
GENERAL - FRANCHISES (NPC AND SPPC)
The Utilities have nonexclusive local franchises or revocable permits to carry on their business in the localities in which their respective operations are conducted in Nevada. The franchise and other governmental requirements of some of the cities and counties in which the Utilities operate provide for payments based on gross revenues. Public utilities are required by law to collect from their customers a universal energy charge (UEC) based on consumption. The UEC is designed to help those customers who need assistance in paying their utility bills or need help in paying for ways to reduce energy consumption. During 2012, the Utilities collected $132.9 million in franchise or other fees based on gross revenues. They collected $10.0 million in UEC based on consumption. They also paid and recorded as expense $1.6 million of fees based on net profits.
The Utilities will apply for renewal of franchises in a timely manner prior to their respective expiration dates.
ITEM 1A.
ITEM 1A. RISK FACTORS
Risks related to NVE and the Utilities’ Results of Operations
Economic conditions both nationally and globally could negatively impact our business.
Our operations are affected by local, national and global economic conditions. Over the last several years, adverse economic conditions have created uncertainty within the capital and commodity markets, including availability and cost of credit, inflation rates, monetary policy, unemployment rates and legislative and regulatory uncertainty. A continued high rate of unemployment in Nevada may impact customers’ ability to pay their utility bills on a timely basis, increase customer bankruptcies, and lead to increased bad debt.
Our operating results will likely fluctuate on a seasonal and quarterly basis due to changes in weather conditions.
Electric power generation is generally a seasonal business. In many parts of the country, including our service areas, demand for power peaks during the hot summer months, with market prices also peaking at that time. As a result, our operating results in the future will likely fluctuate substantially on a seasonal basis. In addition, we have historically sold less power, and consequently earned less income, when weather conditions in our service areas are milder. Unusually mild weather in the future could diminish our results of operations and harm our financial condition.
Changes in customer demand for electricity and natural gas resulting from the continuation of current economic conditions both nationally and globally, conservation efforts by our customers, and the development and integration of alternative technologies including distributive generation may harm our future growth and operating results.
Changes in customer demand for electricity and natural gas are affected by a number of factors outside the control of NVE and the Utilities, current economic conditions both nationally and globally, employment levels, housing activities, conservation and energy efficiency measures, demand side management goals, and technological improvements and differences in regulatory oversight for distributed generation providers, have resulted in a decline in energy consumption, which has and may continue to affect our future growth and results of operations.
Our business operations could be adversely affected by cyber-attacks or security breaches.
The Utilities are subject to cyber-security risks primarily related to breaches of security, of their supervisory control and data acquisition systems and other computer-based systems upon which the Utilities rely, networks used in the operation of their businesses, as well as breaches of security pertaining to sensitive customer, employee and vendor information maintained by the Utilities in the normal course of business. Security breaches of other computer systems or networks, or a loss of confidential or proprietary data could adversely affect the Utilities’ reputation, diminish customer confidence, adversely affect the Utilities’ ability to manage facilities, networks, systems, programs and data efficiently or effectively, disrupt operations, and subject the Utilities to possible financial liability, any of which could have a material adverse effect on our financial condition and results of operations. While the Utilities have procured insurance and have implemented protective measures designed to deter cyber-attacks and security breaches and to mitigate their effects, there can be no assurance that such protective measures will be completely effective in protecting the Utilities from a cyber-attack or security breach or the effects thereof or that insurance will be sufficient to compensate third parties from damages that result from cyber-attacks or security breaches.
If the Utilities’ advanced metering systems fail to operate as intended, or if the Utilities’ are unable to continue relying on the third-party contractors and vendors that support and maintain certain proprietary components of the system, the Utilities’ financial condition, results of operations and cash flows could be materially affected.
The Utilities’ operating revenues depend on accurate and timely measurement of customer energy usage and the generation of accurate billing information. If the Utilities’ advanced metering system failed to accurately and timely measure customer energy usage and generate billing information, if there were a disruption of the required support and maintenance due to a vendor or contractor cessation of services or a contractual dispute or impasse, or mechanical or system failure, or otherwise not operate as intended then the Utilities could incur unanticipated costs for the disruption of measurement and billing operations and to develop and maintain alternative operating arrangements.
The Utilities could be subject to penalties if they violate mandatory NERC reliability standards.
The Energy Policy Act of 2005 amended the Federal Power Act to, among other matters, provide for mandatory reliability standards designed to assure the reliable operation of the bulk power system. NERC established, and FERC approved, reliability
standards that impose certain operating, planning and cyber-security requirements applicable to the Utilities. The Utilities have been, and will continue to be, subject to routine audits and monitoring with respect to compliance with applicable NERC reliability standards, including standards requested by FERC to increase the number of assets (including cyber-security assets) subject to NERC cyber-security standards that are designated as “critical assets.” If the Utilities are found to be in violation of NERC’s mandatory reliability standards, the Utilities could be subject to civil fines imposed by the enforcement entities, which could have a material adverse effect on our results of operations, cash flows and financial condition.
Construction projects that we engage in are subject to a number of risks inherent in such projects, which could have adverse effects on our results of operations.
The nature of our business requires us to engage in significant construction projects from time to time, and each such construction project is subject to usual construction risks which could adversely affect project costs and completion time. These risks include, but are not limited to, shortages of, the ability to obtain or the cost of labor or materials; the ability of the contractors to perform under their contracts; equipment, engineering and design failure; strikes; adverse weather conditions; the ability to obtain necessary operating permits in a timely manner; legal challenges; disputes with third parties; delays due to funding which is yet to be secured by third parties; changes in applicable law or regulations; adverse interpretation or enforcement of permit conditions, laws and regulations by courts or the permitting agencies; other governmental actions; and events in the global economy. If we are unable to complete the development or construction of any construction project or decide to delay or cancel construction, we may not be able to recover our investment in the project and may incur substantial cancellation payments under equipment and construction contracts. Even if a construction project is completed, the total costs may be higher than estimated and/or higher than amounts approved by our regulators, and there is no guarantee that we will be allowed to recover these costs in rates. In addition, construction delays can result in the delay of revenues and, therefore, could affect our results of operations.
The ownership and operation of certain power generation and transmission lines on Indian lands could result in uncertainty related to continued leases, easements and rights-of-way, which could have a significant impact on our business.
Certain portions of the Utilities’ generating facilities and transmission lines that carry power from these facilities are located on Indian lands pursuant to leases, easements or other rights-of-way that are effective for specified periods. The Utilities are currently unable to predict the final outcome of discussions with the appropriate Indian tribes and approval by their respective governing bodies with respect to renewals of these leases, easements and rights-of-way.
Risks related to NVE and the Utilities’ Regulatory Proceedings
If the Utilities do not receive favorable rulings in their future regulatory proceedings with the PUCN and the FERC, such events may have a significant adverse effect on our financial condition, cash flows and future results of operations.
The Utilities are subject to comprehensive regulation by federal and state regulatory agencies that significantly influence its business, liquidity, results of operations and its ability to fully recover costs from its customers in a timely manner. The PUCN regulates the Utilities’ retail electric, and in the case of SPPC natural gas rates and the FERC regulates rates and compliance for wholesale power sales and transmission services. In the Utilities’ GRCs, the PUCN establishes, among other things, their recoverable rate base, their ROE, overall ROR, depreciation rates and their cost of capital. Inadequate rates may have a significant adverse effect on the Utilities’ financial condition and future results of operations and may cause downgrades of their securities by the rating agencies and make it significantly more difficult or expensive to finance operations and construction projects and to buy fuel, natural gas and purchased power from third parties.
For a discussion of NPC’s and SPPC’s recent rate filings, see Note 3, Regulatory Actions, of the Notes to Financial Statements.
If the Utilities do not receive favorable rulings in the deferred energy applications that they file with the PUCN and they are unable to recover their deferred purchased power, natural gas and fuel costs, they will experience an adverse impact on cash flow and earnings. Any significant disallowance of deferred energy charges in the future could materially adversely affect their cash flow, financial condition and liquidity.
Under Nevada law, purchased power, natural gas and fuel costs in excess of those included within BTER are deferred as an asset on the Utilities’ balance sheets and are not shown as an expense until recovered from their retail customers. The Utilities may also file to reset BTERs quarterly, based on the last twelve months fuel and purchased power costs. Additionally, Nevada regulations allow an electric or gas utility that adjusts its BTER on a quarterly basis to request PUCN approval to make quarterly changes to its DEAA rate if the request is in the public interest. The Utilities are also required to file DEAA applications with the PUCN at least
once every twelve months so that the PUCN may verify the prudence of the energy costs. Nevada law also requires the PUCN to act on these cases within a specified time period. Any of these costs determined by the PUCN to have been imprudently incurred cannot be recovered from the Utilities’ customers.
For a discussion of NPC’s and SPPC’s recent and pending deferred energy rate cases, see Note 3, Regulatory Actions, of the Notes to Financial Statements.
Material disallowances of deferred energy costs or inadequate BTERs would have a significant adverse effect on the Utilities’ financial condition and future results of operations, could cause downgrades of NVE’s and the Utilities’ securities by the rating agencies and could make it more difficult or expensive to finance operations and construction projects and buy fuel, natural gas and purchased power from third parties.
The Utilities purchase a portion of the power that they sell to their customers from power suppliers. If the Utilities’ and/or their power suppliers’ credit ratings are downgraded, the Utilities may experience difficulty entering into new power supply contracts, and to the extent that they must rely on the spot market, they may experience difficulty obtaining such power from suppliers in the spot market in light of their financial condition, or the financial condition of their power suppliers. In addition, if the Utilities experience unexpected failures or outages in their generation facilities, they may need to purchase a greater portion of the power they provide to their customers. If access to liquidity is limited to obtain their power requirements, particularly for NPC at the onset of the summer months, and the Utilities are unable to obtain power through other means, their business, operations and financial condition will be materially adversely affected.
If the Utilities cannot maintain the required level of renewable energy or procure sufficient solar energy to meet Nevada’s Portfolio Standard, the PUCN may, among other things, impose an administrative fine for noncompliance.
Nevada law sets forth the Portfolio Standard requiring providers of electric service to acquire, generate or save from renewable energy systems or energy efficiency measures a specific percentage of its total retail sales from renewable energy sources or efficiency measures, which increases over time. The standard also includes a specific requirement for solar energy that must be met on an annual basis by both Utilities. The required amount of renewable energy and available supply can fluctuate widely based on multiple factors, including customer energy use, changes in law or regulation, renewable resource availability, and the contractual performance of renewable counterparties. These fluctuations make the ability to anticipate future renewable energy needs and supplies difficult. Renewable energy and qualified contributions from conservation and energy efficiency measures must also be certified by the PUCN as forecasted each year in order to be used by the Utilities for compliance with the Portfolio Standard. In the event the Utilities do not fully meet the standard in a given year, if the PUCN does not exempt them, they will be required to make up the PEC deficiency in subsequent years and may be subject to a financial penalty. While both Utilities are expected to be successful in 2012 with respect to the Portfolio Standard, the intermittent nature of renewable energy, variations in customer load and any legislative changes in the Portfolio Standard, mean that future years may still be subject to uncertainty around the Utilities’ ability to comply with the Portfolio Standard.
The Utilities’ ability to access the capital markets is dependent on their ability to obtain regulatory approval to do so.
The Utilities will need to continue to support capital expenditures and to refinance maturing debt through external financing. The Utilities must obtain regulatory approval in Nevada in order to borrow money or to issue securities and are therefore dependent on the PUCN to issue favorable orders in a timely manner to permit them to finance their operations, construction and acquisition costs and to purchase power and fuel necessary to serve their customers. As of December 31, 2012, NPC has financing authority from the PUCN for the period ending December 31, 2013, consisting of authority (1) to issue additional long-term debt securities of up to $725 million; (2) to refinance up to approximately $322.5 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $1.3 billion. As of December 31, 2012, SPPC has financing authority from the PUCN for the period ending December 31, 2015, consisting of authority to (1) issue additional long-term debt securities of up to $350 million; (2) to refinance approximately $348 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $600 million. However, we cannot assure you that in the future the PUCN will issue such favorable orders or that such favorable orders will be issued on a timely basis.
Risks related to NVE and the Utilities’ Environmental Matters
The Utilities are subject to numerous environmental laws and regulations that may increase our cost of operations, impact or limit our business plans, expose us to environmental liabilities, or make some electric generating units uneconomical to maintain or operate.
The Utilities are subject to extensive federal, state and local laws and regulations relating to environmental protection. These laws and regulations can result in increased capital, construction, operating, and other costs. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals, and may be enforced by both public officials and private individuals. We cannot predict the outcome or effect of any action or litigation that may arise from applicable environmental regulations.
In addition, either of the Utilities may be identified as a responsible party for environmental cleanup by environmental agencies or regulatory bodies. We cannot predict with certainty the amount or timing of future expenditures related to environmental matters because of the difficulty of estimating clean-up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liabilities on all potentially responsible parties. Environmental regulations may also require us to install pollution control equipment at, or perform environmental remediation on, our facilities.
Existing environmental regulations regarding air emissions (such as NOX, SO2 or mercury emissions), water quality, coal combustion by products and other pollutants may be revised or new climate change laws or regulations may be adopted or become applicable to us. Revised or additional laws or regulations, which may result in increased compliance costs, including the adoption of new technologies or additional operating restrictions, could have a material adverse effect on our financial condition and results of operations particularly if those costs are not fully recoverable from our customers.
Emissions of nitrogen and sulfur oxides, mercury and particulates from fossil fueled generating plants are potentially subject to increased regulations, controls and mitigation expenses. Certain congressional leaders, environmental advocacy groups and regulatory agencies in the U.S. have also been focusing considerable attention on emissions from power generation facilities and their potential role in climate change and/or regional air quality. Moreover, there are many legislative and rulemaking initiatives pending at the federal and state level that are aimed at the reduction of fossil plant emissions, as well as modification of the NAAQS for ozone and other pollutants. We cannot predict the outcome of pending or future legislative and rulemaking proposals. Future changes in environmental laws or regulations governing emissions reductions could make certain electric generating units, especially those utilizing coal for fuel, uneconomical to construct, maintain or operate or could require design changes or the adoption of new technologies that could significantly increase costs or delay in-service dates. In addition, any legal obligation that would require the Utilities to substantially reduce their emissions beyond present levels could require extensive mitigation efforts and, in the case of CO2 legislation or regulation, would raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities.
Furthermore, we may not be able to obtain or maintain all environmental regulatory approvals necessary to our business. If there is a delay in obtaining any required environmental regulatory approval or if we fail to obtain, maintain or comply with any such approval, operations at our affected facilities could be delayed, halted or subjected to additional costs.
Risks related to NVE and the Utilities’ Liquidity and Capital Resources
Changes in actuarial pension and other postretirement assumptions and other factors may increase NVE’s pension and other postretirement plan liability and funding requirements.
Substantially all of NVE employees are covered by a single employer defined benefit pension and other postretirement plan. At present, the pension and other postretirement plan is underfunded in that the projected benefit obligations exceed the aggregate fair value of plan assets. The funded status of the plan can be affected by contributions to plan assets, plan design, investment returns on plan assets, discount rates, mortality rates of plan participants, pension reform legislation and a number of other factors. There can be no assurance that the value of NVE’s pension and other postretirement plan assets will be sufficient to cover future liabilities. Although NVE has made significant contributions to its pension and other postretirement plan in recent years, it is possible that NVE could incur a significant pension and other postretirement liability adjustment, or could be required to make significant additional cash contributions to its plan, which would reduce the cash available for operating activities, and have a material impact on earnings. Refer to Note 10, Retirement Plan and Postretirement Benefits, of the Notes to Financial Statements.
The Utilities are subject to fuel and wholesale electricity pricing risks, which could result in unanticipated liabilities and cash flow requirements or increased volatility in our earnings, and to related credit and liquidity risks.
The Utilities’ business and operations are subject to changes in purchased power prices and fuel costs that may cause increases in the amounts they must pay for power supplies on the wholesale market and the cost of producing power in their generation plants. Prices for electricity, fuel and natural gas may fluctuate substantially over relatively short periods of time and expose the Utilities to significant commodity price risks.
Increasing energy commodity prices, particularly with respect to natural gas, have a significant effect on our short-term liquidity. Although the Utilities are entitled to recover their prudently incurred power, natural gas and fuel costs through deferred energy rate case filings with the PUCN, if current commodity prices increase, the Utilities’ deferred energy balances will increase, which will negatively affect our cash flow and liquidity until such costs are recovered from customers.
If deemed prudent, the Utilities may still purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power. As such, fluctuating commodity prices could have a material adverse effect on their cash flows and their ability to operate and, consequently, on our financial condition.
The Utilities are also subject to credit risk for losses that they incur as a result of non-performance by counterparties of their contractual obligations to deliver fuel, purchased power, natural gas (for resale) or settlement payments. The Utilities often extend credit to counterparties and customers and they are exposed to the risk that they may not be able to collect amounts owed to them. Credit risk includes the risk that a counterparty may default due to circumstances relating directly to it, and also the risk that a counterparty may default due to circumstances that relate to other market participants that have a direct or indirect relationship with such counterparty. Should a counterparty, customer or supplier fail to perform, the Utilities may be required to replace existing contracts with contracts at then-current market prices or to honor the underlying commitment.
The Utilities are also subject to liquidity risk resulting from the exposure that their counterparties perceive with respect to the possible non-performance by the Utilities of their physical and financial obligations under their energy, fuel and natural gas contracts. These counterparties may under certain circumstances, pursuant to the Utilities’ agreements with them, seek assurances of performance from the Utilities in the form of letters of credit, prepayment or cash deposits, or reduce availability under the Utilities’ revolving credit facilities for negative mark-to-market positions. In periods of price volatility, the Utilities’ exposure levels can change significantly, which could have a significant negative impact on our liquidity and earnings. In the event the Utilities’ credit ratings are downgraded below investment grade, the maximum amount of collateral the Utilities would currently be required to post is approximately $86.7 million. Additionally, the Utilities must reduce their availability under their revolving credit facilities for negative mark-to-market positions on hedging contracts with counterparties who are lenders under the revolving credit facilities provided that the reduction of availability under the revolving credit facilities shall at no time exceed 50% of the total commitments then in effect under the credit facilities. As of December 31, 2012, the Utilities were not parties to any hedging contracts.
If NVE is precluded from receiving dividends from the Utilities, its financial condition, and its ability to meet its debt service obligations, pay dividends and make capital contributions to its subsidiaries, will be materially adversely affected.
Since NVE is a holding company, substantially all of its cash flow is provided by dividends paid to NVE by NPC and SPPC on their common stock, all of which is owned by NVE. Since NPC and SPPC are public utilities, they are subject to regulation by the PUCN, which may impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay. While the PUCN has in the past imposed a dividend restriction with respect to NPC and SPPC, as of December 31, 2012, there were no dividend restrictions imposed on the Utilities by the PUCN.
In addition, certain agreements entered into by the Utilities set restrictions on the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid. As a result of the Utilities’ credit rating on their senior secured debt at investment grade by S&P and Moody’s, these restrictions are suspended and no longer in effect so long as the debt remains investment grade by both rating agencies. In addition to the restrictions imposed by specific agreements, the Federal Power Act prohibits the payment of dividends from “capital accounts.” Although the meaning of this provision is unclear, the Utilities believe that the Federal Power Act restriction, as applied to their particular circumstances, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts. If, however, the FERC were to interpret this provision differently, the ability of the Utilities to pay dividends to NVE could be jeopardized.
We cannot assure investors that future dividend payments on NVE’s Common Stock will be made or, if made, in what amounts they may be paid.
Dividends are considered periodically by NVE’s BOD and are subject to factors that ordinarily affect dividend policy, such as current and prospective financial condition, earnings and liquidity, prospective business conditions, regulatory factors, and dividend restrictions in NVE’s and the Utilities’ financing agreements. The BOD will continue to review these factors on a periodic basis to determine if and when it would be prudent to declare a dividend on NVE’s Common Stock; however, there is no guarantee that dividends will be paid in the future, or that, if paid, the dividends will be paid in the same amount or with the same frequency as in the past.
NVE’s indebtedness is effectively subordinated to the liabilities of its subsidiaries, particularly NPC and SPPC. NVE and the Utilities have the ability to issue a significant amount of additional indebtedness under the terms of their various financing agreements.
Because NVE is a holding company, its indebtedness is effectively subordinated to the Utilities’ existing indebtedness and other future liabilities, including claims by the Utilities’ trade creditors, debt holders, secured creditors, taxing authorities, and guarantee holders. NVE conducts substantially all of its operations through its subsidiaries, and thus NVE’s ability to meet its obligations under its indebtedness and to pay any dividends on its common stock will be dependent on the earnings and cash flows of those subsidiaries and the ability of those subsidiaries to pay dividends or to advance or repay funds to NVE. As of December 31, 2012, the Utilities had approximately $4.5 billion of debt outstanding. The terms of NVE’s indebtedness restrict the amount of additional indebtedness that NVE and the Utilities may issue. Based on NVE’s December 31, 2012 financial statements, NVE’s indebtedness restrictions would allow NVE and the Utilities to issue up to approximately $3.3 billion of additional indebtedness in the aggregate, plus indebtedness that is specifically permitted under the terms of NVE’s indebtedness. However, NPC and SPPC are subject to restrictions under the terms of their various financing agreements and PUCN restrictions on their ability to issue additional indebtedness. See Note 8, Debt Covenant and Other Restrictions, of the Notes to Financial Statements.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
Substantially all of NPC’s and SPPC’s property in Nevada is subject to the lien of the General and Refunding Mortgage Indentures dated as of May 1, 2001, between NPC and SPPC, respectively, and The Bank of New York Mellon Trust Company, N.A., as trustee, as amended and supplemented.
NVE’s total summer MW capacity and units were 6,078 and 61 units, respectively. The following is a list of the Utilities’ share of electric generation plants including the type and fuel used, the anticipated 2013 net capacity (MW), and the years that the units were installed.
(1)
Silverhawk Generating Station is jointly owned by NPC and SNWA, 75% and 25%, respectively. The acquisition of a 75% ownership interest in the Silverhawk Generating Station from Pinnacle West was consummated in 2006. SNWA continues to hold a 25% ownership interest in the plant. The combined cycle plant consists of two gas turbines, two HRSGs and one steam turbine.
(2)
As of December 31, 2012, Reid Gardner Generating Station Unit No. 4 is co-owned by the CDWR (67.8%) and NPC (32.2%); NPC is the operating agent. NPC is entitled to 24 MW of base load capacity and 233 MW of peaking capacity from that Unit, subject to the following limitations: 1,500 hours/year, 300 hours/month, and 8 hours/day. The total summer net capacity of the Unit, subject to heat input limitation, is 257 MW. Reid Gardner Generating Station Units 1, 2, and 3, subject to heat input limitations, have a combined net capacity of 300 MW. The Reid Gardner Generating Station summer capacity is 557 MW. The agreement with CDWR terminates in June 2013. See Note 5, Jointly Owned Facilities, of the Notes to Financial Statements for further discussion on the termination.
(3)
Valmy Generating Station is co-owned by Idaho Power Company (50%) and SPPC (50%); SPPC is the operator. Valmy Generating Station has a total net capacity of 522 MW.
(4)
NPC has an 11.3% interest in the Navajo Generating Station. The total capacity of the Navajo Generating Station is 2,250 MW. Salt River is the operator (21.7% interest). There are four other partners: U.S. Bureau of Reclamation (24.3% interest), Los Angeles Dept. of Water & Power (21.2% interest), Arizona Public Service Co. (14% interest), and Tucson Electric Power (7.5% interest).
(5)
The total capacity from diesel generators has been reduced by 11 MW. The reduction reflects retirement of the Gabbs diesel (5 MWs) in the second amendment to SPPC’s 2011-2030 IRP and the change in the status of the Brunswick diesels (6 MW) to an ‘emergency resource’.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
NVE and its subsidiaries, through the course of their normal business operations, are currently involved in a number of legal actions, none of which have had or, in the opinion of management, is expected to have a significant impact on their financial positions or results of operations. See Note 12, Commitments and Contingencies, of the Notes to Financial Statements for further discussion of other legal matters.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES (NVE)
NVE’s Common Stock is traded on the New York Stock Exchange (symbol NVE). Dividends declared per share and high and low sale prices of the Common Stock as reported for 2012 and 2011 are as follows:
Dividends are considered periodically by the BOD and are subject to factors that ordinarily affect dividend policy, such as current and prospective earnings, current and prospective business conditions, regulatory factors, NVE’s financial condition and other matters within the discretion of the BOD.
On February 7, 2013, NVE’s BOD declared a quarterly cash dividend of $0.19 per share payable on March 20, 2013 to common shareholders of record on March 5, 2013.
There is no guarantee that NVE will continue to pay dividends in the future, or that the dividends will be paid at the same amount or with the same frequency. See Note 8, Debt Covenant and Other Restrictions, of the Notes to Financial Statements, for a description of the restrictions on NPC’s and SPPC’s ability to pay dividends to NVE and on NVE’s ability to pay dividends on its common stock.
For information on the equity compensation plans, see Item 12.
The information in Item 5 of this Annual Report on Form 10-K is not deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934 or to the liabilities of Section 18 of the Securities Exchange Act of 1934, and will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent we specifically incorporate it by reference into such a filing.
Issuer Purchase of Equity Securities
The following table contains information about NVE’s purchases of common stock for the quarter ended December 31, 2012:
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, for a discussion of factors that may affect the future financial condition and results of operations of NVE, NPC and SPPC (dollars in thousands, except per share amounts):
(1) During the fourth quarter of 2012, SPPC discovered an error in its calculation of accumulated deferred income taxes and the related income tax regulatory asset specific to amounts associated with AFUDC-equity resulting in an understatement of both regulatory assets and deferred tax liabilities of the same amount. Total Assets for NVE has been corrected in the table above as of December 31, 2011, 2010, 2009, and 2008, by $32.0 million, $30.6 million, $28.9 million, and $27.3 million, respectively. Refer to Note 1, Summary of Significant Accounting Policies, NVE and SPPC Balance Sheet Corrections, of the Notes to Financial Statements for further information.
(1) During the fourth quarter of 2012, SPPC discovered an error in its calculation of accumulated deferred income taxes and the related income tax regulatory asset specific to amounts associated with AFUDC-equity resulting in an understatement of both regulatory assets and deferred tax liabilities of the same amount. Total Assets for SPPC has been corrected in the table above as of December 31, 2011, 2010, 2009, and 2008, by $32.0 million, $30.6 million, $28.9 million, and $27.3 million, respectively. Refer to Note 1, Summary of Significant Accounting Policies, NVE and SPPC Balance Sheet Corrections, of the Notes to Financial Statements for further information.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements and Risk Factors
The information in this Form 10-K includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters.
Words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan” and “objective” and other similar expressions identify those statements that are forward-looking. These statements are based on management’s beliefs and assumptions and on information currently available to management. Actual results could differ materially from those contemplated by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such statements, factors that could cause the actual results of NVE, NPC or SPPC (NPC and SPPC are collectively referred to as the “Utilities”) to differ materially from those contemplated in any forward-looking statement include, among others, the following:
Operational Risks
·
economic conditions, inflation rates, monetary policy, unemployment rates, customer bankruptcies, including major gaming customers with significant debt maturities, weaker housing markets, each of which affect customer growth, customer collections, customer demand and usage patterns;
·
changes in the rate of industrial, commercial and residential growth in the service territories of the Utilities, and the impact of energy conservation programs, which could affect the Utilities’ ability to accurately forecast electric and gas demand;
·
construction risks, including but not limited to those associated with ON Line, such as difficulty in securing adequate skilled labor, cost and availability of materials and equipment, third-party disputes, equipment failure, engineering and design failure, work accidents, fire or explosions, business interruptions, recovery of possible cost overruns, delay of in-service dates, and pollution and environmental damage;
·
security breaches of our information technology or supervising control and data systems, or the systems of others upon which the Utilities rely, whether through cyber-attack, cyber-crime, sabotage, accident or other means, which may affect our ability to prevent system or service disruptions, generating facility shutdowns or disclosure of confidential corporate or customer information;
·
unseasonable or severe weather, drought, wildfire and other natural phenomena, which could affect the Utilities’ customers’ demand for power, seriously impact the Utilities’ ability and/or cost to procure adequate supplies of fuel or purchased power, affect the amount of water available for electric generating plants in the southwestern U.S., and have other adverse effects on our business;
·
employee workforce factors, changes in and renewals of collective bargaining unit agreements, strikes or work stoppages, an aging workforce, the ability to adjust the labor cost structure to changes in growth within our service territories;
·
whether the Utilities’ newly installed advanced metering systems continue to operate as intended, accurately and timely measure customer energy usage and generate billing information, and whether the Utilities can continue to rely on third-party vendors or contractors to support certain proprietary components of the advanced metering systems;
·
changes in and/or implementation of FERC and NERC mandatory reliability, security, and other requirements for system infrastructure, which could significantly affect existing and future operations;
·
explosions, fires, accidents and mechanical breakdowns that may occur while operating and maintaining an electric and natural gas system in the Utilities’ service territory, including gas distribution services that the Utilities may rely upon, that can cause unplanned outages, reduce generating output, damage the Utilities’ assets or operations, subject the Utilities to third-party claims for property damage, personal injury or loss of life, or result in the imposition of civil, criminal, or regulatory fines or penalties on the Utilities;
·
the extent to which NVE or the Utilities incur costs in connection with third-party claims or litigation that are not recoverable through insurance, rates, or from other third parties;
·
changes in the business of the Utilities’ major customers engaged in mining or gaming, including availability and cost of capital or power demands, which may result in changes in the demand for the Utilities’ services, including the effect on the Nevada gaming industry from the opening of additional gaming establishments in other states and internationally;
·
the effect that any future terrorist attacks, wars, threats of war or pandemics may have on the tourism and gaming industries in Nevada, particularly in Las Vegas, as well as on the national economy in general;
·
whether, following the Great Basin Water Network, et al. v. Nevada State Engineer litigation, certain permitted water rights of the SNWA that are used to supply water to the Utilities’ power production plants and service territories could be re-opened, which could adversely impact the operations of those plants and future growth and customer usage patterns; and
·
unusual or unanticipated changes in normal business operations of the Utilities, including unusual maintenance or repairs.
Regulatory/Legislative Risks
·
unfavorable rulings, penalties and findings by the PUCN in rate or other cases, investigations or proceedings, including GRCs, the periodic applications to recover costs for fuel and purchased power that have been recorded by the Utilities in their deferred energy accounts, deferred natural gas costs recorded by SPPC for its gas distribution business, renewable energy and energy efficiency recovery programs, and unfavorable rulings, penalties or findings by the FERC in rate or other cases, investigations and proceedings with regard to wholesale power sales and transmission services;
·
the effect of existing or future Nevada, or federal laws or regulations affecting the electric industry, including those which could allow additional customers to choose new electricity suppliers, or use alternative sources of energy, or change the conditions under which they may do so;
·
whether the Utilities can procure, obtain, and/or maintain sufficient renewable energy sources in each compliance year to satisfy the Portfolio Standard in the State of Nevada; and
·
changes in tax or accounting matters or other laws and regulations to which NVE or the Utilities are subject or which change the rate of federal or state taxes payable by our shareholders or common stock dividends.
Environmental Risks
·
changes in and/or implementation of environmental laws or regulations, including the imposition of limits on emissions of carbon or other pollutants from electric generating facilities, which could significantly affect the Utilities existing operations as well as our construction program.
Liquidity and Capital Resources Risks
·
whether the Utilities will be able to continue to obtain fuel and power from their suppliers on favorable payment terms and favorable prices, particularly in the event of unanticipated power demands, physical availability, sharp increases in the prices for fuel (including increases in long-term transportation costs) and/or power, or a ratings downgrade;
·
wholesale market conditions, including availability of power on the spot market and the availability to enter into commodity financial hedges with creditworthy counterparties, including the impact as a result of the Dodd-Frank Act on counterparties who are lenders under our revolving credit facilities, which may affect the prices the Utilities have to pay for power as well as the prices at which the Utilities can sell any excess power;
·
whether provisions of the Dodd-Frank Act or rules made under the act governing derivative transaction reporting, trading, and clearing or imposing margin or collateral requirements will materially increase the cost, or limit the availability or usefulness, to the Utilities of financial transactions and techniques important in managing risks the Utilities face in the commodity, power and financial markets;
·
the ability and terms upon which NVE, NPC and SPPC will be able to access the capital markets to support their capital needs, particularly in the event of: volatility in the global credit markets or other problems, changes in availability and cost of capital either due to market conditions or as a result of unfavorable rulings by the PUCN, a downgrade of the current debt ratings of NVE, NPC or SPPC, and/or interest rate fluctuations;
·
whether NVE's BOD will declare NVE's common stock dividends based on the BOD’s periodic consideration of factors ordinarily affecting dividend policy, such as current and prospective financial condition, earnings and liquidity, prospective business conditions, regulatory factors, and restrictions contained in NVE's and the Utilities' agreements;
·
whether the Utilities will be able to continue to pay NVE dividends under the terms of their respective financing and credit agreements and limitations imposed by the Federal Power Act; and
·
further increases in the unfunded liability or changes in actuarial assumptions, the interest rate environment and the actual return on plan assets for our pension and other postretirement plans, which can affect future funding obligations, costs and pension and other postretirement plan liabilities.
Other factors and assumptions not identified above may also have been involved in deriving forward-looking statements, and the failure of those other assumptions to be realized, as well as other factors, may also cause actual results to differ materially from those projected. NVE, NPC and SPPC assume no obligation to update forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting forward-looking statements.
NOTE REGARDING RELIANCE ON STATEMENTS IN OUR CONTRACTS
In reviewing the agreements filed as exhibits to this Annual Report on Form 10-K, please remember that they are filed to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about NVE, the Utilities or the other parties to the agreements. The agreements contain representations and warranties by each of the parties that are specific to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and:
•
should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to the agreement if those statements prove to be inaccurate;
•
have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;
•
may apply standards of materiality in a way that is different from what may be viewed as material to investors; and
•
were made only as of the date of the applicable agreement or such other date or dates as may be specified in such agreements and are subject to more recent developments.
Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.
EXECUTIVE OVERVIEW
Management’s Discussion and Analysis of Financial Condition and Results of Operations explains the general financial condition and the results of operations of NVE and its two primary subsidiaries, NPC and SPPC, collectively referred to as the “Utilities” (references to “we,” “us” and “our” refer to NVE and the Utilities collectively), and includes discussion of the following:
NVE’s Utilities operate three regulated business segments which are NPC electric, SPPC electric and SPPC natural gas. The Utilities are public utilities engaged in the generation, transmission, distribution and sale of electricity and, in the case of SPPC, sale of natural gas. Other operations consist mainly of unregulated operations and the holding company operations. The Utilities are the principal operating subsidiaries of NVE and account for substantially all of NVE’s assets and revenues. NVE, NPC and SPPC are separate filers for SEC reporting purposes and as such this discussion has been divided to reflect the individual filers (NVE, NPC and SPPC), except for discussions that relate to all three entities or the Utilities.
The Utilities are regulated by the PUCN with respect to rates, standards of service, siting of and necessity for generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to generation, distribution and transmission operations. The FERC has jurisdiction under the Federal Power Act with respect to wholesale rates, service, interconnection, accounting, and other matters in connection with the Utilities’ sale of electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which the Utilities take service. As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the ROR they are permitted to earn on their utility assets, are subject to the approval of governmental agencies.
The Utilities’ revenues and operating income are subject to fluctuations during the year due to impacts that seasonal weather, rate changes, and customer usage patterns have on demand for electric energy and resources. NPC is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning. SPPC’s electric system peak typically occurs in the summer, while its gas business typically peaks in the winter. The variations in energy usage due to varying weather, customer growth and other energy usage patterns, including energy efficiency and conservation measures, necessitates a continual balancing of loads and resources and purchases and sales of energy under short and long term energy supply contracts. As a result, the prudent management and optimization of available resources has a direct effect on the operating and financial performance of the Utilities. Additionally, the timely recovery of purchased power and fuel costs, and other costs, and the ability to earn a fair return on investments through rates are essential to the operating and financial performance of the Utilities.
Overview of Major Factors Affecting Results of Operations
NVE recognized net income of $321.9 million for the year ended December 31, 2012, compared to $163.4 million for the same period in 2011. The increase in net income is primarily due to the following pre-tax items:
•
An increase in gross margin of $202.0 million, primarily due to an increase in BTGR revenues of $153.2 million, as a result of NPC’s 2011 GRC which increased BTGR rates and increased customer usage of $ 46.9 million partially due to an increase in CDDs as a result of hotter weather during 2012 and increased usage by certain industrial customers. See the Utilities’ respective Results of Operations, for further discussion of gross margin;
•
A decrease in interest expense of $29.2 million primarily due to the redemption of NVE’s 6.75% Senior Notes in November 2011, various debt redemptions and re-financings at NPC and lower borrowings on the Utilities revolving credit facilities. See Note 6, Long Term Debt, of the Notes to Financial Statements for further discussion of debt;
•
An increase in other income of $13.7 million due to a $5.5 million gain on the sale of telecommunications towers and reversal of accrued carrying charges previously recorded, and a $4.9 million settlement for the Harry Allen Generating Station construction project; and
•
A decrease in other expense of $26.2 million primarily due to the following adjustments made in 2011 which increased 2011 other expense: $12.2 million disallowance resulting from NPC’s 2011 GRC and $5.8 million resulting from an order by the PUCN to adjust EEIR revenues. See Note 3, Regulatory Actions, of the Notes to Financial Statements for further discussion of the Utilities’ regulatory decisions. Also contributing to the decrease was a decrease in donations of approximately $3.0 million and a decrease in the loss on investments.
Reducing the increase in net income was an increase in depreciation expense of $19.7 million (pre-tax) primarily due to the completion of Harry Allen Generating Station in May 2011. Further reducing the increase in net income was the absence, in 2012, of an $8.0 million (pre-tax) reduction in maintenance expense recorded in 2011 as a result of the final calculation of a termination amount for a long term service agreement for the Higgins Generating Station which was previously expensed in 2010.
NVE recognized net income of $163.4 million in for the year ended December 31, 2011 compared to $227.0 million for the same period in 2010. The decrease in net income was primarily due to the following pre-tax items:
•
An increase in depreciation expense of $24.9 million and a decrease in AFUDC-debt and equity of $31.9 million, primarily due to the completion of the expansion at the Harry Allen Generating Station in May 2011;
•
A decrease in gross margin of $15.6 million primarily due to the reduction in California revenues as a result of the sale of the California Assets and a decrease in usage primarily due to milder weather in 2011, partially offset by an increase in BTGR revenues as a result of SPPC’s GRC effective January 1, 2011. See Note 3, Regulatory Actions, of the Notes to Financial Statements for further discussion of the Utilities’ regulatory decisions;
•
$15.9 million in adjustments as a result of the PUCN final order on NPC’s 2011 GRC, of which approximately $12.2 million was recorded to Other Expense. See Note 3, Regulatory Actions, of the Notes to Financial Statements for further discussion of the Utilities’ regulatory decisions;
•
Performance pay adjustments, maintenance at Reid Gardner Generating Station, $5.8 million adjustment for revenue recorded in 2010 as a result of the PUCN’s final decision on the EEIR rate; and
•
The recognition of income in 2010 for the sale of Independence Lake of approximately $7.6 million and legal settlements.
Offsetting these decreases in net income was an $8.0 million (pre-tax) favorable settlement in 2011 with a vendor on a long term service agreement for the Higgins Generating Station, which was accrued for in the third quarter 2010. Further offsetting the decrease in net income was a decrease in interest expense and reduced operating expenses.
NVE Transformation
Beginning in 2006, NVE committed to an energy strategy to manage resources against our load by constructing/purchasing generating facilities, purchasing and developing renewable energy, encouraging energy efficiency and conservation programs, as well as, expanding our transmission capability in an effort to reduce our reliance on purchased power. The implementation of this strategy required significant amounts of liquidity and capital. To meet these capital requirements during the transformation, NVE and the Utilities issued, refinanced and reduced debt which improved credit ratings and decreased interest costs. At the same time, management worked with the PUCN to communicate the necessity of investments to better serve our customers, the prudency of costs incurred and the importance of a reasonable and timely return on such investments for our shareholders.
The energy strategy and regulatory diligence discussed above created a strong foundation for NVE and the Utilities to earn our allowable return on their investments during 2012, while meeting a higher percentage of its load through owned generation. Additionally, as a result of our financial policies, which focused on lowering interest rates and reducing debt, interest costs decreased and our capital structure improved during 2012. Furthermore, through employee dedication and increased use of technology we continued to improve processes to enhance performance while keeping operating and maintenance costs relatively stable. As a result, NVE was able to generate free cash flow in 2012, which has provided it the ability to increase its dividend while preserving its ability to invest in new opportunities.
Key Initiatives
The economy in Nevada continues to recover slowly. While a low growth environment can be challenging, the foundation established in prior years, including establishing energy independence, improving capital structure and liquidity and managing our regulatory environment, has positioned the Utilities to operate in this environment. However, NVE and the Utilities continue to implement and develop key initiatives that collectively may further our ability to increase our common stock dividend, strengthen our capital structure and consider new investment opportunities. These initiatives should enable us to contain operating and maintenance costs while effectively managing our regulatory environment and continuing to promote and improve a safe and reliable work environment. These key initiatives are discussed below.
Continuous Improvement of Safety
The safety of NVE’s employees and the public is a core value of NVE and the Utilities. Accordingly, NVE has worked to integrate a set of safety principles into their business operations and culture. These principles include complying with applicable safety, health, and security regulations and implementing programs and processes aimed at continually improving safety and security conditions. Our initiatives in 2013 and beyond will include modeling a safety culture in all areas of the company similar to the achievements recognized at SPPC’s Fort Churchill Generating Station. In January 2013, the Fort Churchill Generating Station reached a safety milestone of operating 25 years without a lost-time accident. According to the Edison Electric Institute, the 226-MW natural gas-fueled plant has the longest safety record for any fossil-fueled generating station in the nation.
Construction of ON Line and One Company Merger
ON Line is Phase 1 of a joint project between the Utilities and GBT-South. Completion of the ON Line, expected in late 2013, will connect NVE’s southern and northern service territories. Pending certain state and federal regulatory approvals, ON Line will provide:
•
Ability to jointly dispatch energy throughout the state;
•
Access to renewable energy resources in parts of northern and eastern Nevada which will enhance NVE’s ability to meet its Portfolio Standard;
•
Ability to optimize its generating and transmission facilities to benefit its customers; and
•
The opportunity for NVE to merge NPC and SPPC (the “One Company” merger). A merger application is expected to be filed with the PUCN and FERC in June 2013.
Empower Customers through Focused Service and Efficiency Programs
NV Energize is a NVE project that includes Advanced Meter Infrastructure, Smart Grid Technology and Meter Data Management. The NV Energize capabilities will allow NVE to help customers better manage their usage with the most cost-effective mix of pricing, service, efficiency and conservation options. As of December 31, 2012, NVE had installed approximately 1.3 million Smart Meters in Nevada, and the implementation of the NV Energize project is nearing completion. NVE expects to substantially complete the installation process of the final 80,000 Smart Meters before the end of the second quarter of 2013.
The NV Energize system provides more convenience for customers and is achieving operating savings through both automated meter reading and the elimination to date of approximately 1 million trips to customers’ premises to process service requests. The system also enables NVE to launch new customer programs. Recruitment of participants for a trial of a combination of time based rates, supporting technology and education options is now underway. New detailed customer usage reports have been integrated into our web self-service capability, and customers can also request alerts on their billing information. An enhanced air conditioning demand response program was launched in the fourth quarter. It is designed to provide energy market based rebates for specific event participation and also includes an energy efficiency management capability. Similar programs for commercial customers are under development.
Managing Generation Portfolio Within Environmental Compliance
As discussed in more detail in Note 12, Commitments and Contingencies, of the Notes to Financial Statements, certain generating stations of NVE are affected under EPA’s Regional Haze Rules. The implementation costs of the Regional Haze Rules are significant. Therefore, NVE must balance the cost of implementing the retrofits associated with the Regional Haze Rule with the effect current and future load requirements, retirements of generating stations and plant outages will have on its ability to serve its customers reliably.
Investment opportunities
NVE continues to explore investment opportunities that may benefit our customers and that will add to our core business of generation, transmission and distribution of energy. In addition, NVE’s geographical location affords it access to various renewable resources for potential investment opportunities.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
NVE prepared its consolidated financial statements in accordance with GAAP. In doing so, certain estimates were made that were critical in nature to the results of operations. The following discusses those significant estimates that may have a material impact on the financial results of NVE and the Utilities and are subject to the greatest amount of subjectivity. Senior management has discussed the development and selection of these critical accounting policies with the Audit Committee of NVE's BOD. The items discussed below represent critical accounting estimates that under different conditions or using different assumptions could have a material effect on the financial condition, results of operation, cash flows, liquidity and capital resources of NVE and the Utilities.
Regulatory Accounting
The Utilities’ retail rates are currently subject to the approval of the PUCN and are designed to recover the cost of providing generation, transmission and distribution services. NVE is a “holding company” under the Public Utility Holding Company Act of 2005 (PUHCA 2005). As a result, NVE and all of its subsidiaries (whether or not engaged in any energy related business) are required to maintain books, accounts and other records in accordance with FERC regulations and to make them available to the FERC and the PUCN. In addition, the PUCN or the FERC have the authority to review allocations of costs of non-power goods and administrative services among NVE and its subsidiaries. The FERC has the authority generally to require that rates subject to its jurisdiction be just and reasonable and in this context would continue to be able to, among other things, review transactions between NVE, NPC and/or SPPC and/or any other affiliated company.
As a result, the Utilities qualify for the application of regulatory accounting treatment as allowed by the Regulated Operations Topic of the FASC. The accounting guidance for regulated operations recognizes that the rate actions of a regulator can provide reasonable assurance of the existence of an asset and requires the capitalization of incurred costs that would otherwise be charged to expense where it is probable that future revenue will be provided to recover these costs. The accounting guidance prescribes the method to be used to record the financial transactions of a regulated entity. The criteria for applying the accounting guidance for regulated operations include the following: (i) rates are set by an independent third party regulator, (ii) approved rates are intended to recover the specific costs of the regulated products or services, and (iii) rates that are set at levels that will recover costs can be charged to and collected from customers. Under federal law, wholesale rates charged by the Utilities are subject to certain jurisdictional regulation, primarily by the FERC. The FERC has jurisdiction under the Federal Power Act with respect to rates, service, interconnection, accounting, and other matters in connection with the Utilities’ sale of electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which the Utilities take service.
Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates collected from customers. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred. Although current rates do not include the recovery of all existing regulatory assets as discussed further below and in Note 1, Summary of Significant Accounting Policies, of the Notes to Financial Statements, management believes the existing regulatory assets are probable of recovery either because we have received prior PUCN approval or due to regulatory precedent set for similar circumstances. Management’s judgment reflects the current political and regulatory climate in the state, and is subject to change in the future. If future recovery of costs ceases to be probable, the write-off of regulatory assets would be required to be recognized as a charge and expensed in current period earnings.
Regulatory Accounting affects other Critical Accounting Policies, including Deferred Energy Accounting, Accounting for Pensions, and Accounting for Derivatives and Hedging Activities, all of which are discussed immediately below.
Deferred Energy Accounting
Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates, the excess is not recorded as a current expense on the statement of operations but rather is deferred and recorded as an asset on the balance sheet. Conversely, a liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs. These excess amounts are reflected in adjustments to rates and recorded as revenue or expense in future time periods, subject to PUCN approval. Nevada law provides that the PUCN may
not allow the recovery of any costs for purchased fuel or purchased power “that were the result of any practice or transaction that was undertaken, managed or performed imprudently by the electric utility.” Nevada law specifies that fuel and purchased power costs include all costs incurred to purchase fuel, to purchase capacity, and to purchase energy. Both Utilities are entitled under statute to utilize deferred energy accounting for their electric operations and both Utilities accumulate amounts in their deferral of energy costs accounts. The Utilities also record a carrying charge, equal to the weighted cost of capital, on such deferred balances, recognized as interest income/expense on regulatory items in the current period.
The Utilities are exposed to commodity price risk primarily related to changes in the market price of electricity, and the suspension of our hedging program, as well as changes in fuel costs incurred to generate electricity. See Item 7A, Quantitative and Qualitative Disclosures about Market Risk, for a discussion of the Utilities’ purchased power procurement strategies, and commodity price risk and commodity risk management program. Currently, commodity price increases and decreases are recoverable through the deferred energy accounting mechanism, with no anticipated effect on earnings. However, the Utilities are subject to regulatory risk related to commodity price changes due to the fact that the PUCN may disallow recovery for any of these costs that it considers imprudently incurred.
See Note 3, Regulatory Actions, of the Notes to Financial Statements, for additional discussion of the regulatory process to recover these deferred costs.
Energy Efficiency Implementation Rate (EEIR) and Energy Efficiency Program Rate (EEPR)
In July 2010, regulations were adopted by the Nevada Legislature that authorizes an electric utility to recover lost revenue that is attributable to the measurable and verifiable effects associated with the implementation of efficiency and conservation programs approved by the PUCN. As a result, the Utilities file annually in March, to adjust rates and set a clearing rate or EEIR effective in October of the same year for over or under collected balance, similar to the deferred energy mechanism discussed above. In addition, the regulation approved the transition of the recovery for the implementation costs of energy efficiency programs from general rates (filed every 3 years) to recovery through annual rate filings annually in March, to adjust rates and set a clearing rate or EEPR effective in October of the same year for over or under collected balance, similar to the deferred energy mechanism discussed above. See Note 3, Regulatory Actions, of the Notes to Financial Statements for details regarding EEIR and EEPR balances. Although a rate is established for EEIR, the actual effects associated with the implementation of energy efficiency and conservation programs is still subject to a measurement and verification process by the PUCN. To the extent the PUCN does not approve the measurement and verification amounts, the Utilities may not be allowed recovery of such amounts.
Fair Value Measurements and Disclosures
NVE and the Utilities’ follow the Fair Value Measurements and Disclosure Topic of the FASC, which defines fair value, establishes a framework for measuring fair value and enhances disclosures about assets and liabilities recorded at fair value.
Fair Value Measurements and Disclosure Topic of the FASC establishes a three-level hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The three levels are defined as follows:
Level 1 - Quoted prices in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities.
Level 2 - Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant.
As required by the Fair Value Measurements and Disclosure Topic of the FASC, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. NVE and the Utilities’ assessment of the significance of a particular input to fair value measurements requires judgment. The fair value of the Utilities’ assets and liabilities are sensitive to market price fluctuations that can occur on a daily basis. The use of different assumptions and variables in determining fair value could significantly impact the valuation and classification within the fair value hierarchy of assets and liabilities. See Note 1, Summary of Significant Accounting Policies, Note 4, Investments and Other Property and Note 10, Retirement
Plan and Postretirement Benefits of the Notes to Financial Statements for more detailed disclosure of NVE’s, NPC’s and SPPC’s fair value measurements.
Accounting for Income Taxes
Current and deferred income tax provisions and benefits as well as deferred income tax assets and liabilities involve significant management estimates and judgments. NVE and the Utilities file a consolidated federal income tax return. Current income taxes are allocated based on NVE and the Utilities’ respective taxable income or loss and tax credits as if each utility filed a separate return.
NVE and the Utilities recognize deferred tax liabilities and assets for the future tax consequences of events that have been included in the financial statements or tax returns. Deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using tax rates in effect for the year in which the differences are expected to reverse. Deferred tax assets are also recorded for deductions incurred and credits earned that have not been utilized in tax returns filed or to be filed for tax years through the date of the financial statements. Management considers estimates of the amount and character of future taxable income by tax jurisdiction in assessing the likelihood of realization of deferred tax assets. If it is not more likely than not that a deferred tax asset will be realized in its entirety, a valuation allowance is recorded with respect to the portion estimated not likely to be realized. Management has determined that the Federal NOL does not require a valuation allowance based on projections of future taxable income and the reversal of deferred tax liabilities.
At December 31, 2012, NVE had a gross Federal NOL carryover of approximately $1.1 billion. The following table summarizes the NOL and tax credit carryovers and associated carryover periods, and valuation allowance for amounts which NVE has determined that realization is unlikely as of December 31, 2012 (dollars in millions):
Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, our financial condition and results of operations in future periods, and the review of filed tax returns by taxing authorities. NVE and the Utilities’ income tax returns are regularly audited by applicable tax authorities. Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the more-likely-than-not recognition threshold is satisfied and measured at the largest amount of benefit that is greater than 50% likely of being realized upon settlement. NVE and the Utilities classify interest and penalties associated with unrecognized tax benefits as interest and other expense, respectively, within the income statement. No interest expense or penalties associated with unrecognized tax benefits have been recorded. As of December 31, 2012, NVE and the Utilities recorded a liability for uncertain tax positions of approximately $6.6 million.
The Utilities reduce rates to reflect the current tax benefits associated with recognizing certain tax deductions sooner than when the expenses are recognized for financial reporting purposes. A regulatory asset is recorded for these amounts to reflect the future increases in income taxes payable that will be recovered from customers when these temporary differences reverse. The Utilities have been fully normalized since 1987. AFUDC-equity is recorded on an after-tax basis. Accordingly, a regulatory asset is recorded when AFUDC-equity is recognized. This regulatory asset reverses as the related plant is depreciated, resulting in an increase to the tax provision. The Utilities also record regulatory liabilities for obligations to reduce rates charged customers for deferred taxes recovered from customers in prior years at corporate tax rates higher than the current tax rates. The reduction in rates charged customers will occur as the temporary differences resulting in the excess deferred tax liabilities reverse. NVE and subsidiaries had a net regulatory tax liability of $254.6 million at December 31, 2012.
Environmental Contingencies
NVE and its subsidiaries are subject to federal, state and local regulations governing air and water quality, hazardous and solid waste, land use and other environmental considerations. Nevada’s Utility Environmental Protection Act requires approval of the
PUCN prior to construction of major utility, generation or transmission facilities. The EPA, NDEP and Clark County Department of Air Quality and Environmental Management administer regulations involving air and water quality, solid, and hazardous and toxic waste.
NVE and its subsidiaries are subject to rising costs that result from a steady increase in the number of federal, state and local laws and regulations designed to protect the environment. These laws and regulations can result in increased capital, operating, and other costs as a result of compliance, remediation, containment and monitoring obligations, particularly with laws relating to power plant emissions. In addition, NVE or its subsidiaries may be a responsible party for environmental cleanup at any site identified by a regulatory body. The management of NVE and its subsidiaries cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating cleanup costs and compliance and the possibility that changes will be made to current environmental laws and regulations. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liabilities on all potentially responsible parties.
Depending on whether environmental liabilities occurred from normal operations or as part of new environmental laws, the Utilities accrue for environmental remediation liabilities in accordance with the accounting guidance required by the Asset Retirement and Environmental Obligations Topic of the FASC. Estimated costs from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study or when the accounting requirements for environmental obligations have been met. Such costs are adjusted as additional information develops or circumstances change. Certain environmental costs receive regulatory accounting treatment, under which the costs are recorded as regulatory assets. Recoveries of environmental remediation costs from other parties are recognized when their receipt is deemed probable. Environmental expenditures that have future economic benefits are capitalized in accordance with our asset capitalization policy.
Note 1, Summary of Significant Accounting Policies, Asset Retirement Obligations, of the Notes to Financial Statements and Note 12, Commitments and Contingencies, of the Notes to Financial Statements, discusses the environmental matters of NVE and its subsidiaries that have been identified, and the estimated financial effect of those matters. To the extent that (1) actual results differ from the estimated financial effects, (2) there are environmental matters not yet identified for which NVE or its subsidiaries are determined to be responsible, or (3) the Utilities are unable to recover through future rates the costs to remediate such environmental matters, there could be a material adverse effect on the financial condition and future liquidity and results of operations of NVE and its subsidiaries.
Defined Benefit Plans and Other Postretirement Plans
As further explained in Note 10, Retirement Plan and Postretirement Benefits, of the Notes to Financial Statements, NVE maintains a qualified pension plan, a non-qualified supplemental executive retirement plan (SERP) and restoration plan, as well as a postretirement benefit (OPEB) plan which provides health and life insurance for retired employees.
Pension Plans
NVE’s reported costs of providing non-contributory defined pension benefits (described in Note 10, Retirement Plan and Postretirement Benefits, of the Notes to Financial Statements) are dependent upon numerous factors resulting from actual plan experience and assumptions for future experience.
In accordance with the Compensation Retirement Benefits Topic of the FASC, changes in pension obligations associated with these factors may not be immediately recognized as pension costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants. Furthermore, the Compensation Retirement Benefits Topic of the FASC requires the immediate recognition of changes in benefit obligations due to differences between actuarial assumptions and actual experience in Accumulated Other Comprehensive Income, net of taxes. However, since NVE recovers costs through rates, amounts to be recovered in rates will be recorded as Other Regulatory Assets under the provisions of the Regulated Operations Topic of the FASC, and will be recognized as expense over a period of time.
For the years ended December 31, 2012, 2011, and 2010, NVE recorded pension expense for all pension plans of approximately $19.7 million, $24.0 million, and $30.8 million, respectively, in accordance with the accounting guidance as defined by the Compensation Retirement Benefits Topic of the FASC. Actual payments of benefits made to retirees and terminated vested employees for the years ended December 31, 2012, 2011 and 2010 were $73.0 million, $42.5 million, and $58.0 million, respectively. Pension costs are impacted by actual employee demographics (including age and employment periods), the level of contributions NVE makes to the plan, and earnings on plan assets. Changes made to the provisions of the plan may also impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return
on plan assets, the discount rates and demographic (mortality, retirement, termination) assumptions used in determining the projected benefit obligation and pension costs.
In 2012, NVE offered a voluntary lump sum pension payout to former employees not currently of retirement age but eligible for future benefits and certain retiree participants already receiving benefits under NVE’s pension plan in an effort to reduce NVE’s future pension obligation. The 2012 payouts increased the benefits paid by approximately $28.9 million. NVE expects to payout an additional lump sum of approximately $15.6 million from the pension assets during 2013 based on outstanding offers at December 31, 2012.
Plan Assets
NVE’s pension plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased pension costs in future periods. See Note 10, Retirement and Postretirement Benefits, of the Notes to Financial Statements, for further discussion on NVE’s investment strategy and asset allocation.
Plan Assumptions and Sensitivities Analysis
As further described in Note 10, Retirement Plan and Postretirement Benefits, of the Notes to Financial Statements, NVE has revised the pension plan discount rate for its 2012 benefit obligations to 4.01%, as compared to the 2011 benefit obligations rate of 4.91%. In determining the pension benefit obligation and related costs, these assumptions can change with each measurement date, and such changes could result in material changes to such amounts.
As disclosed in Note 10, Retirement and Postretirement Benefits, of the Notes to Financial Statements, the funded status of the plan has decreased compared to the prior year due primarily to the change in the discount rate.
The pension plan discount rates for 2012 and 2011 related to the benefit obligations were determined by identifying a theoretical settlement portfolio of high quality corporate bonds sufficient to provide for the plans projected benefit payments.
The pension plan discount rates for 2012 related to the net periodic benefit costs were determined by identifying a theoretical settlement portfolio of high quality corporate bonds sufficient to provide for the plans projected benefit payments. However, to determine the pension plan discount rates for 2011 and 2010 related to the net periodic benefit costs, NVE’s projected benefit payments were matched to the yield curve derived from a portfolio of over 300 high quality Aa bonds with yields within the 10th to 90th percentiles of these bond yields.
In selecting an assumed rate of return on plan assets, NVE considers past performance and economic forecasts for the types of investments held by the plan. NVE used an assumed rate of return on plan assets of 6.15% for 2012 and 6.75% for 2011, as disclosed in Note 10, Retirement and Postretirement Benefits, of the Notes to Financial Statements. Actual return on pension plan assets increased by approximately $8.0 million in 2012 and $7.3 million in 2011.
The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage for all pension plans (dollars in thousands):
Other Postretirement Benefits
NVE’s reported costs of providing other postretirement benefits (described in Note 10, Retirement Plan and Postretirement Benefits of the Notes to Financial Statements) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.
For the year ended December 31, 2012, 2011, and 2010, NVE recorded other postretirement benefit expense of $2.7 million, $5.0 million, and $5.4 million, respectively, in accordance with the provisions of the Compensation Retirement Benefits Topic of the FASC. Actual payments of benefits made to retirees for the year ended December 31, 2012, 2011 and 2010 were $11.2 million, $12.3 million, and $12.5 million, respectively. Other postretirement benefit costs are impacted by actual employee demographics (including age and employment periods), the level of contributions made to the plan, earnings on plan assets, and health care cost trends. Changes made to the provisions of the plan may also impact current and future other postretirement benefit costs. Other postretirement benefit costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, discount rates and demographic (mortality, retirement, termination) assumptions used in determining the postretirement benefit obligation and postretirement costs.
Plan Assets
NVE’s other postretirement benefit plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns, as well as, changes in general interest rates may result in increased or decreased other postretirement benefit costs in future periods. See Note 10, Retirement and Postretirement Benefits of the Notes to Financial Statements, for further discussion on NVE’s investment strategy and asset allocation.
Plan Assumptions and Sensitivities Analysis
As further described in Note 10, Retirement Plan and Postretirement Benefits of the Notes to Financial Statements, NVE has revised the other postretirement benefits discount rate for its 2012 benefit obligations to 4.09%, as compared to the 2011 benefit obligations rate of 5.09%. In determining the other postretirement benefit obligation and related cost, these assumptions can change with each measurement date, and such changes could result in material changes to such amounts.
The other postretirement benefits discount rates for 2012 and 2011 related to the benefit obligations were determined by identifying a theoretical settlement portfolio of high quality corporate bonds sufficient to provide for the plans projected benefit payments.
The other postretirement benefits discount rates for 2012 related to the net periodic benefit costs were determined by identifying a theoretical settlement portfolio of high quality corporate bonds sufficient to provide for the plans projected benefit payments. However, to determine the other postretirement benefits discount rates for 2011 and 2010 related to the net periodic benefit costs, NVE’s projected benefit payments were matched to the yield curve derived from a portfolio of over 300 high quality Aa bonds with yields within the 10th to 90th percentiles of these bond yields.
In selecting an assumed rate of return on plan assets, NVE considers past performance and economic forecasts for the types of investments held by the plan. NVE used an assumed rate of return on plan assets of 7.10% for some plans and 6.15% for others in 2012, and 7.10% and 6.75% in 2011, as disclosed in Note 10, Retirement and Postretirement Benefits of the Notes to Financial Statements. Actual return on other postretirement benefit plan assets increased $2.5 million in 2012 and decreased $2.0 million in 2011.
The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage (dollars in thousands):
Revenues
Unbilled Receivables
Revenues related to the sale of energy are recorded based on meter reads, which occur on a systematic basis throughout a month, rather than when the service is rendered or energy is delivered. At the end of each month, the energy delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenues are calculated. These estimates of unbilled sales and revenues are based on the ratio of billable days versus unbilled days, amount of energy procured and generated during that month, historical customer class usage patterns, line loss and the Utilities’ current tariffs. Accounts receivable as of December 31, 2012, include unbilled receivables of $86 million and $50 million for NPC and SPPC, respectively. Accounts receivable as of December 31, 2011, include unbilled receivables of $93 million and $51 million for NPC and SPPC, respectively.
RECENT PRONOUNCEMENTS
As of December 31, 2012, there were no recent accounting pronouncements which would have a significant impact on NVE and the Utilities financial statements or financial statement disclosure requirements.
NV ENERGY, INC.
RESULTS OF OPERATIONS
NV Energy, Inc. (Holding Company) and Other Subsidiaries
NVE (Holding Company)
The Holding Company’s (stand alone) operating results included approximately $26.3 million $39.3 million and $50.1 million of interest costs for the years ended December 31, 2012, 2011 and 2010, respectively. The decrease in interest costs for the year ended December 31, 2012 as compared to the same period in 2011 is primarily due to the redemption of NVE’s 6.75% Senior Notes in November 2011. The decrease in interest costs for the year ended December 31, 2011 as compared to the same period in 2010 is primarily due to early redemption costs incurred in 2010 as discussed below and the redemption of NVE’s 6.75% Senior Notes in November 2011. See Note 6, Long-Term Debt, of the Notes to Financial Statements, for further discussion of debt transactions.
Other Subsidiaries
Other Subsidiaries of NVE, except for NPC and SPPC, did not contribute materially to the consolidated results of operations of NVE.
NV Energy, Inc. (Consolidated)
See Executive Overview, Overview of Major Factors Affecting Results of Operations for NVE Consolidated.
ANALYSIS OF CASH FLOWS
NVE’s cash flows increased during the year ended December 31, 2012, compared to the same period in 2011, due to increased cash from operating activities, partially offset by an increase in cash used by investing and financing activities.
Cash from Operating Activities - The increase in cash from operating activities was primarily due to increased revenues resulting primarily due to increase BTGR rates as a result of NPC’s 2011 GRC and increased customer usage. Also contributing to the increase were over collections of EEPR, reduction in spend for conservation programs, reduced funding for retirement plans, and increased customer deposits. These increases were partially offset by a change in payment terms with energy counterparties from
weekly to monthly settlements in mid-2011, expiration of rates to collect the deferred rate increase from NPC’s 2008 GRC, and timing of property tax payments.
Cash used by Investing Activities - The increase in cash used by investing activities was primarily due to the receipt of proceeds from the sale of California Assets in 2011 and a decrease in the use of cash as a result of a decrease in construction activity primarily for the Harry Allen Generating Station expansion.
Cash used by Financing Activities - Cash used by financing activities increased due to the reduction in cash from issuance of debt, the repurchase of common stock which may be reissued to satisfy future equity compensation costs, and higher dividend payments partially offset by a 2011 settlement payment for the interest rate swap agreement as discussed in Note 6, Long Term Debt, of the Notes to Financial Statements.
NVE’s cash flows increased in 2011 compared to 2010 due to a decrease in cash used by investing and financing, offset partially by a reduction in cash from operating activities.
Cash from Operating Activities - The decrease in cash from operating activities was primarily due to a decrease in net income, overall decrease in rates resulting from quarterly BTER adjustments and negative DEAA rates implemented in October 2010 to refund prior period over collected balances to customers, as well as a reduction in revenues from California customers due to the sale of the California Assets, as discussed in Note 15, Assets Held for Sale, of the Notes to Financial Statements. Also contributing to this decrease was an increase in coal and other inventory, increased incentive compensation payments for 2010 operating results, refund of customer deposits and an increase in conservation programs and solar rebates. These decreases were partially offset by an increase in cash resulting from NPC’s deferred rate increase beginning in October 2010 and recovery of deferred conservation program costs.
Cash used by Investing Activities - The decrease in cash used by investing activities was primarily due to the receipt of proceeds from the sale of California Assets by SPPC and telecommunication towers by NPC, as discussed in Note 15, Assets Held for Sale, of the Notes to Financial Statements. Further contributing to the decrease in cash used by investing activities CIAC received under the American Recovery and Reinvestment Act of 2009, as part of the NV Energize project.
Cash used by Financing Activities - Cash used by financing activities decreased due to a reductions in draws on the Utilities’ revolving credit facilities, the redemption of NPC’s $350 million aggregate principal amount of 8.25%, Series A, General and Refunding Mortgage Notes, which were partially paid by proceeds from the issuance of NPC’s $250 million 5.45%, Series Y, General and Refunding Mortgage Notes and a draw on the NPC Credit Agreement.
LIQUIDITY AND CAPITAL RESOURCES (NVE CONSOLIDATED)
Overall Liquidity
NVE’s consolidated operating cash flows are primarily derived from the operations of NPC and SPPC. The primary source of operating cash flows for the Utilities is revenues (including the recovery of previously deferred energy costs and natural gas costs) from sales of electricity and, in the case of SPPC, natural gas. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and interest. Another significant use of cash is the refunding of previously over-collected amounts from customers. See Note 3, Regulatory Actions, of the Notes to Financial Statements for more details of over-collected balances. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcomes, and economic conditions. Available liquidity as of December 31, 2012 was as follows (in millions):
NVE and the Utilities attempt to maintain their cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills and bank deposits. In addition to cash on hand, the Utilities’ may use their revolving credit facilities in order to meet their liquidity needs. Alternatively, depending on the usage of their revolving credit facilities, the Utilities may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below.
NVE has no debt maturities in 2013. However, NPC is required to redeem approximately $98.1 million of its variable rate debt, due 2020, prior to ON Line’s commercial operation date expected by December 31, 2013, and SPPC’s $250 million 5.45% General and Refunding Notes, Series Q, will mature on September 1, 2013. To meet these long term maturing debt obligations, the Utilities intend to use a combination of internally generated funds, the Utilities’ revolving credit facilities, and/or the issuance of long-term debt. In 2012, NVE and the Utilities’ credit ratings on their senior secured debt remained at investment grade (see Credit Ratings below). In 2012, NVE and the Utilities did not experience any limitations in the credit markets nor do we expect any in 2013. However, disruptions in the banking and capital markets not specifically related to NVE or the Utilities may affect their ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.
In prior years, NVE and the Utilities required significant amounts of liquidity due to the magnitude of capital expenditures needed to support a growing customer base and to support unstable energy markets. As NVE and the Utilities have transitioned to slower growth, the amount of capital expenditures has declined. NVE and the Utilities’ investment in generating stations in the past several years and more stable energy markets have positioned the Utilities to better manage and optimize their resources. As a result, NVE and the Utilities anticipate that they will be able to meet short term operating costs and capital expenditures with internally generated funds and the use of the Utilities revolving credit facilities. Furthermore, with new investments now in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, federal tax NOL and a decrease in capital expenditures, NVE and the Utilities expect to generate free cash flow. The free cash flow may be used to reduce debt, to increase the dividend payout and for potential investment opportunities.
However, if energy costs rise at a rapid rate and the Utilities do not recover the cost of fuel, purchased power and operating costs in a timely manner or the Utilities were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to the Utilities could be significantly less. In order to maintain sufficient liquidity, NVE and the Utilities may be required to delay capital expenditures, re-finance debt or issue equity at NVE. Additionally, if deemed prudent, the Utilities may enter into hedging transactions in an attempt to mitigate projected or actual rising energy costs. Currently, the Utilities are not operating under a PUCN approved hedging plan. Hedging transactions may have a material impact on the Utilities’ cash flows, unless recovered in rates in a timely manner.
As of February 21, 2013, NVE has approximately $24.3 million payable of debt service obligations remaining for 2013, which it intends to pay through dividends from subsidiaries. (See Factors Affecting Liquidity-Dividends from Subsidiaries below). On February 7, 2013, NPC declared a dividend payable to NVE of $50 million.
NVE designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, NVE has continuing commitments for capital expenditures for construction, improvement and maintenance of facilities.
Detailed below are NVE’s Capital Structure, Capital Requirements, recently completed financing transactions and factors affecting our ability to obtain debt on favorable terms, including the effect of our holding company structure and limitation on dividends from the Utilities.
Capital Structure
NVE’s actual capital structure on a consolidated basis was as follows at December 31 (dollars in thousands):
Capital Requirements
Construction Expenditures
NVE’s consolidated cash requirements for construction expenditures for 2013 are projected to be $450.5 million. NVE’s consolidated cash requirements for construction expenditures for 2013-2017 are projected to be $2.1 billion. Gross construction expenditures, including AFUDC-debt, net salvage and CIAC for the years ended 2012, 2011 and 2010 were $498.9 million, $620.5
million, and $629.5 million, respectively. Net cash requirements to fund construction for the years ended 2012, 2011 and 2010 were $414.3 million, $522.2 million, and $577.3 million, respectively. To fund future capital projects, NVE and the Utilities may meet such financial obligations with a combination of internally generated funds, the use of the Utilities’ revolving credit facilities, the issuance of long-term debt, and if necessary, the issuance of equity by NVE.
Estimated construction expenditures for PUCN approved projects, projects under contract, environmental compliance projects and other base capital requirements are as follows (dollars in thousands):
(1)
Generation for 2013 includes the termination payment for Reid Gardner Generating Station Unit No. 4, which is co-owned with CDWR at December 31, 2012. See Note 5, Jointly Owned Facilities, of the Notes to Financial Statements.
(2)
Environmental capital forecasts are in accordance with NDEP approved timelines which are pending federal approval.
Total estimated cash requirements related to construction projects consist of the following (dollars in thousands):
Contractual Obligations (NVE Consolidated)
The table below provides NVE’s contractual obligations on a consolidated basis, as of December 31, 2012, (except as otherwise indicated) that NVE expects to satisfy through a combination of internally generated cash and, as necessary, through the issuance of short-term and long-term debt. Certain contracts contain variable factors which required NVE to estimate the obligation depending on the final variable amount. Actual amounts could differ. The table does not include estimated construction expenditures described above, except for major capital projects for which the Utilities have executed contracts by December 31, 2012, or funding requirements under pension and other postretirement benefit plans, as discussed in Note 10, Retirement Plan and Postretirement Benefits, of the Notes to Financial Statements, as of December 31, 2012. Additionally, at December 31, 2012, NVE has recorded an uncertain tax liability of $6.6 million in accordance with the accounting guidance for Uncertainty in Income Taxes Topic of the FASC all of which is classified as non-current. NVE is unable to make a reasonably reliable estimate of the period of cash payments to relevant tax authorities; consequently, none of the uncertain tax liability is included in the contractual obligations table below (dollars in millions):
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Related party purchase power agreements have been eliminated for 2013. Upon completion of ON Line, the related party purchase power agreements will no longer be required.
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Represents estimated payments under renewable energy power purchase contracts, which have been approved by the PUCN and are contingent upon the developers obtaining commercial operation and their ability to deliver energy.
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Included is the TUA with GBT of which NPC is responsible for 95% and SPPC 5% and is contingent upon final construction costs and reaching commercial operation.
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Amounts based on estimated usage.
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Capital projects include NPC’s termination payment for the undepreciated cost of capital of Reid Gardner Generating Station Unit No. 4 from CDWR. See Note 5, Jointly Owned Facilities, of the Notes to Financial Statements. Additionally, included in capital projects are obligations regarding the construction of ON Line, of which NPC will be responsible for 95% and SPPC 5%. See Note 12, Commitment and Contingencies, of the Notes to Financial Statements.
Pension and Other Postretirement Benefit Plan Matters
NVE has a qualified pension plan and other postretirement benefits plan which cover substantially all employees of NVE, NPC and SPPC. The annual net benefit cost for the plans is expected to increase in 2013 by approximately $3.1 million compared to the 2012 cost of $22.5 million. As of December 31, 2012, the measurement date, the plan was under funded under the provisions of the Compensation Retirement Benefits Topic of the FASC. Refer to Note 10, Retirement Plan and Postretirement Benefits, of the Notes to the Consolidated Financial Statements. During 2012, NVE funded a total of $22.1 million to the trusts established for the qualified pension and postretirement benefit plans. At the present time it is not anticipated that additional funding will be required in 2013 to meet the minimum funding level requirements defined by the Pension Protection Act of 2006. However, NVE and the Utilities have included in their 2013 assumptions funding levels similar to the 2012 funding. The amounts to be contributed in 2013 may change subject to market conditions.
Factors Affecting Liquidity
Ability to Issue Debt
NVE’s Term Loan contains conditions of borrowing, events of default, and affirmative and negative covenants. The Term Loan includes (i) a financial covenant to maintain a ratio of total consolidated indebtedness to total consolidated capitalization, determined on the last day of each fiscal quarter, not to exceed 0.70 to 1.00 and (ii) a fixed charge covenant that requires NVE not to permit the fixed charge coverage ratio, determined on the last day of each fiscal quarter, to be less than 1.50 to 1.00.
Under these covenant restrictions, as of December 31, 2012, NVE (consolidated) would be allowed to incur up to $3.3 billion of additional indebtedness, which includes the use of the Utilities revolving credit facilities. The amount of additional indebtedness allowed would likely be impacted if there is a change in current market conditions or material change in our financial condition. NPC’s and SPPC’s Ability to Issue Debt sections further discuss the limitations on their ability to issue debt.
Effect of Holding Company Structure
As of December 31, 2012, NVE (on a stand-alone basis) has outstanding debt and other obligations including, but not limited to: $195 million Term Loan due 2014; and $315 million of its unsecured 6.25% Senior Notes due 2020.
Due to the holding company structure, NVE’s right as a common shareholder to receive assets of any of its direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiary by its creditors. Therefore, NVE’s debt obligations are effectively subordinated to all existing and future claims of the creditors of NPC and SPPC and its other subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders.
As of December 31, 2012, NVE, NPC, SPPC and their subsidiaries had approximately $5.0 billion of debt and other obligations outstanding, consisting of approximately $3.3 billion of debt at NPC, approximately $1.2 billion of debt at SPPC and approximately $510 million of debt at the holding company and other subsidiaries. Although NVE and the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, NVE and the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.
Dividends from Subsidiaries
Since NVE is a holding company, substantially all of its cash flow is provided by dividends paid to NVE by NPC and SPPC on their common stock, all of which is owned by NVE. Since NPC and SPPC are public utilities, they are subject to regulation by the PUCN, which may impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay. While the PUCN has in the past imposed a dividend restriction with respect to NPC and SPPC, as of December 31, 2012, there were no dividend restrictions imposed on the Utilities by the PUCN.
In addition, certain financing agreements entered into by the Utilities set restrictions on the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid. As a result of the Utilities’ credit rating on their senior secured debt being rated investment grade by S&P and Moody’s, these restrictions are suspended and no longer in effect so long as such debt remains investment grade by both rating agencies. In addition to the restrictions imposed by specific agreements, the Federal Power Act prohibits the payment of dividends from “capital accounts.” Although the meaning of this provision is unclear, the Utilities believe that the Federal Power Act restriction, as applied to their particular circumstances, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts. If, however, the FERC were to interpret this provision differently, the ability of the Utilities to pay dividends to NVE could be jeopardized.
Credit Ratings
The liquidity of NVE and the Utilities, the cost and availability of borrowing by the Utilities under their respective credit facilities, the potential exposure of the Utilities to collateral calls under various contracts and the ability of the Utilities to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for the companies’ debt. On February 20, 2013, S&P upgraded NVE’s corporate credit ratings for NVE, NPC and SPPC from BB+ to investment grade BBB-. NPC’s and SPPC’s senior secured debt is rated investment grade by three NRSROs: Fitch, Moody’s and S&P. The senior debt credit ratings are as follows:
Fitch’s rating outlook is Positive, while Moody’s and S&P’s rating outlook is Stable for NVE, NPC and SPPC.
A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and 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 evaluated in the context of the applicable methodology, independently of all other ratings. The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.
Energy Supplier Matters
With respect to NPC’s and SPPC’s contracts for purchased power, NPC and SPPC purchase and sell electricity with counterparties under the WSPP agreement, an industry standard contract that NPC and SPPC use as members of the WSPP. The WSPP contract is posted on the WSPP website.
Under these contracts, a material adverse change, which includes a credit rating downgrade of NPC and SPPC, may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. A default must be declared within 30 days of the event giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market value as of December 31, 2012 for all suppliers continuing to provide power under a WSPP agreement would approximate a $72 million payment or obligation to NPC. No amounts would be due to or from SPPC. These contracts qualify for the normal purchases scope exception under the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet.
Gas Supplier Matters
With respect to the purchase and sale of natural gas, NPC and SPPC use several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily means a credit rating downgrade below investment grade. Most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurances. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure.
Gas transmission service is secured under FERC Tariffs or custom agreements. These service contracts and Tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service. NPC has a transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades. As of December 31, 2012, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $86.7 million. Of this amount, approximately $26 million would be required if NPC’s Senior Unsecured ratings (and/or equivalent) are rated below BB (S&P) or Ba3 (Moody’s) and an additional amount of approximately $60.7 million would be required if NPC’s Senior Secured ratings and Senior Unsecured ratings (or equivalent), both are downgraded to below investment grade. During the second quarter of 2012, $17.9 million of letters of credit posted as collateral were returned from the counterparty to NPC during the period due to NPC’s unsecured credit rating equivalent becoming investment grade. In exchange, the amount of additional cash collateral that would be required in the event of a credit rating downgrade increased.
Financial Gas Hedges
The Utilities may enter into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed under NPC’s and SPPC’s Financing Transactions, the availability under the Utilities’ revolving credit facilities is reduced for net negative mark-to-market positions on hedging contracts with counterparties who are lenders under the revolving credit facilities provided that the reduction of availability under the revolving credit facilities shall at no time exceed 50% of the total commitments then in effect under the credit facilities. Currently, there are no negative mark-to-market exposures that would impact borrowings of the Utilities. If deemed prudent, the Utilities may still purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.
Cross Default Provisions
None of the Utilities’ financing agreements contains a cross-default provision that would result in an event of default by that Utility upon an event of default by NVE or the other Utility under any of their respective financing agreements. Certain of NVE’s financing agreements, however, do contain cross-default provisions that would result in an event of default by NVE upon an event of default by the Utilities under their respective financing agreements. In addition, certain financing agreements of each of NVE and the Utilities provide for an event of default if there is a failure under other financing agreements of that entity to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay other indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event, during which time NVE or the Utilities may rectify or correct the situation before it becomes an event of default.
NEVADA POWER COMPANY
RESULTS OF OPERATIONS
NPC recognized net income of $257.7 million in 2012 compared to net income of $132.6 million in 2011 and $185.9 million in 2010. In 2012, NPC paid dividends to NVE of approximately $184.0 million. On February 7, 2013, NPC declared a dividend of approximately $50 million to NVE. Details of NPC’s operating results are further discussed below.
Gross margin is presented by NPC in order to provide information that management believes aids the reader in determining how profitable the electric business is at the most fundamental level. Gross margin, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, provides a measure of income available to support the other operating expenses of the business and is a key factor utilized by management in its analysis of its business.
NPC believes presenting gross margin allows the reader to assess the impact of NPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which NPC calculates as operating revenues less energy costs and EEPR costs provides a measure of income available to support the other operating expenses of NPC.
EEPR costs are conservation costs being recovered from ratepayers through EEPR revenues which were implemented in July 2011 (See Note 3, Regulatory Actions, of the Notes to Financial Statements). Costs incurred prior to the implementation of the EEPR are recovered through general rates and amortized to other operating expense. See Note 3, Regulatory Actions, of the Notes to Financial Statements for conservation program amount details. The EEPR mechanism is designed such that conservation costs are equal to revenues collected and any over/under collection is deferred as a regulatory asset/liability until rates are reset. As a result, amounts related to EEPR do not have an effect on gross margin, operating income or net income.
For reconciliation to operating income, see Note 2, Segment Information, of the Notes to Financial Statements. Gross margin changes are based primarily on general base rate adjustments (which are required by statute to be filed every three years).
The components of gross margin for the years ended December 31 were as follows (dollars in thousands):
Gross margin increased for the year ended December 31, 2012, compared to the same period in 2011, primarily due to the following:
• $157.6 million increase primarily due to BTGR revenues as a result of NPC’s 2011 GRC effective January 1, 2012;
• $39.1 million as a result of increased customer usage, primarily due to an increase in CDDs, particularly during the second quarter of 2012, as well as increased usage by certain industrial customers; and
• $5.8 million primarily due to growth.
Gross margin decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to decreased customer usage as a result of milder weather and conservation programs. Partially offsetting this decrease was the implementation of the EEIR rates, which became effective August 1, 2010 as well as a slight increase in customer growth.
The causes for significant changes in specific lines comprising the results of operations for the years ended are provided below (dollars in thousands except for amounts per unit):
HDDs and CDDs
MWh usage may be affected by the change in HDDs or CDDs in a given period. A degree day indicates how far that day's average temperature departed from 65 degrees Fahrenheit. HDDs measure heating energy demand and indicate how far the average temperature fell below 65 degrees Fahrenheit. CDDs measure cooling energy demand and indicate how far the temperature averaged above 65 degrees Fahrenheit. For example, if a location had a mean temperature of 60 degrees Fahrenheit on day 1 and 80 degrees Fahrenheit on day 2, there would be 5 HDDs (65 minus 60) and 0 CDDs for day 1. In contrast, there would be 0 HDDs and 15 CDDs (80 minus 65) for day 2.
The following table shows the HDDs and CDDs within NPC’s service territory:
The causes for significant changes in specific lines comprising the results of operations for the years ended are provided below (dollars in thousands except for amounts per unit):
NPC’s retail revenues increased for the year ended December 31, 2012 compared to the same period in 2011 primarily due to the following:
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$157.6 million primarily due to BTGR retail revenues as a result of NPC’s GRC (see Note 3, Regulatory Actions, of the Notes to Financial Statements);
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$87.9 million due to an increase in usage, primarily due to an increase in CDDs, particularly during the second quarter of 2012, as well as increased usage by certain industrial customers and slight growth in the number of customers; and
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$44.2 million due to the implementation of EEPR rates effective July 1, 2011 and EEPR amortization rates effective October 1, 2011.
These revenue increases were offset by approximately $173.0 million of rate decreases as a result of NPC’s various BTER and DEAA quarterly updates (see Note 3, Regulatory Actions, of the Notes to Financial Statements). Further offsetting the increase in retail revenues was decrease in industrial customers primarily due to their switch to DOS service.
For the year ended December 31, 2012, the average number of retail customers increased by 1.3%, consisting of an increase in residential and commercial customers of 1.4% and 0.7%, respectively, and a decrease in industrial customers of 1.5%, compared to 2011.
NPC’s retail revenues decreased for the year ended December 31, 2011, compared to the same period in 2010 primarily due to the following:
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$220.6 million as a result of decreased energy rates from NPC’s various BTER quarterly updates, the annual Deferred Energy cases effective October 1, 2010 and October 1, 2011 and the expiration of the Western Energy Crisis Amortization rate on May 1, 2010 (See Note 3, Regulatory Actions, of the Notes to Financial Statements); and
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$25.8 million due to decrease usage by residential customers due to milder temperatures during the summer months of 2011 and conservation programs.
These decreases were partially offset by an increase of approximately $37.0 million due to the implementation of EEPR rates effective July 1, 2011 and EEPR amortization rates effective October 1, 2011. (See Note 3, Regulatory Actions, of the Notes to Financial Statements).
For the year ended December 31, 2011, the average number of retail customers increased by 1.0%, consisting of an increase in residential and commercial customers of 1.1% and 0.4%, respectively, and a decrease in industrial customers of 1.9%, compared to 2010.
Electric Operating Revenues - Other decreased for the year ended December 31, 2012 compared to the same period in 2011 primarily due to a decrease in connection fees of approximately $3.1 million as a result of Smart Meter utilization. Also contributing
to the decrease was a decrease in rental income of approximately $1.8 million, as a result of the sale of the wireless communications towers by NPC in 2011.
Electric Operating Revenues - Other decreased for the year ended December 31, 2011 compared to the same period in 2010 primarily due to a $1.9 million decrease in revenue from Public Street and Highway Lighting, resulting from lower energy rates. The remaining decrease was the result of revenue decreases from various miscellaneous sources.
Energy Costs
Energy Costs include Fuel for Generation and Purchased Power. Energy costs are dependent upon several factors which may vary by season or period. As a result, NPC’s usage and average cost per MWh of Fuel for Generation versus Purchased Power to meet demand can vary significantly. Factors that may affect Energy Costs include, but are not limited to:
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Weather;
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Generation efficiency;
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Plant outages;
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Total system demand;
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Resource constraints;
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Transmission constraints;
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Natural gas constraints;
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Long term contracts; and
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Mandated power purchases.
Energy Costs decreased for the year ended December 31, 2012, compared to the same period in 2011, primarily due to a decrease in natural gas prices. Volume increased primarily due to an increase in CDDs, as discussed previously, as well as, an increase in demand by certain industrial customers partially offset by an increase in heat rate option sales. The average cost per MWh decreased primarily due to lower natural gas prices. In 2012, self-generation, which is primarily gas fired generating units, satisfied 74% of NPC’s system load.
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Fuel for power generation costs decreased for the year ended December 31, 2012, compared to the same period in 2011 primarily due to a $102.7 million decrease in the cost of natural gas and a $20.9 million decrease in hedging costs, both offset by a $32.8 million increase in volume due to increased reliance on internal generation. The average cost per MWh of generated power decreased primarily due to a decrease in the cost of natural gas and hedging costs.
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Purchased power costs decreased for the year ended December 31, 2012 compared to the same period in 2011 primarily due to an $81.6 million decrease in volume offset by a $77.1 million increase in the price of purchased power primarily due to an increase in the cost of renewable energy. The decrease in volume was primarily due to an increase in the sale of heat rate options which are netted in purchased power and the increased reliance on internal generation. The average cost per MWh of purchased power increased primarily due to an increase in the price and volume of renewable energy and the decrease in non-renewable energy coupled with an increase in the volume of heat rate option sales.
Energy Costs decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to a decrease in costs associated with hedging activities and a slight decrease in natural gas prices. In 2011, self-generation, which is primarily gas fired generating units, satisfied 70% of NPC’s system load.
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Fuel for generation costs decreased for the year ended December 31, 2011, compared to the same period in 2010 primarily due to a $73.1 million decrease in hedging costs as well as $7.6 million lower natural gas prices and a $9.2 million decrease in volume. The decrease in volume was primarily due to planned outages with the generation fleet, discussed below.
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Purchased power costs decreased for the year ended December 31, 2011, compared to the same period in 2010 primarily due to a $22.7 million decrease in market prices of as well as an $18.0 million decrease in hedging costs related to tolling, both offset by a $12.7 million increase in volume. Volume for the year ended December 31, 2011 increased primarily due to planned outages within the generation fleet early in the year.
Amounts for 2012, 2011 and 2010 include amortization of deferred energy of $(170.0) million, $(105.6) million and $1.2 million, respectively; which represent cash refunds to our customers for previous over-collections, offset by an over-collection of amounts recoverable in rates of $102.0 million, $89.3 million and $93.6 million, respectively.
Deferred energy represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through current rates, the excess is recognized as a reduction in costs. Conversely, to the extent actual costs are less than amounts recoverable through current rates, the difference is recognized as an increase in costs. Deferred energy also includes the current amortization of fuel and purchased power costs previously deferred. Reference Note 3, Regulatory Actions, of the Notes to Financial Statements for further detail of deferred energy balances.
Energy efficiency program costs increased for the year ended December 31, 2012 compared to the same period in 2011 due to the implementation of EEPR base rates in July 2011 and amortization rates effective October 2011.
Energy efficiency program costs are conservation costs being recovered from ratepayers through EEPR revenues which were implemented in July 2011 for base rates and in October 2011 for amortization rates (See Note 3, Regulatory Actions, of the Notes to Financial Statements). Costs incurred prior to the implementation of the EEPR rates are recovered through the general rates and amortized to other operating expense discussed below. The EEPR mechanism is designed such that conservation costs are equal to revenues collected and any over/under collection is deferred as a regulatory asset/liability until rates are reset. As a result, amounts related to EEPR do not have an effect on gross margin, operating income or net income.
Other operating expense increased for the year ended December 31, 2012, compared to the same period in 2011, primarily due to the following:
• $12.5 million increase in amortization of energy efficiency and conservation costs; and
• $5.2 million increase in stock compensation costs.
The increase was partially offset by the following:
• $4.2 million decrease in regulatory amortization costs;
• $2.3 million decrease in lease expense;
• $1.5 million decrease in telecommunications expenses;
• $1.1 million decrease in transmission and distribution costs; and
• $1.0 million decrease in pension and benefit costs.
Other operating expense decreased slightly for the year ended December 31, 2011, compared to the same period in 2010, primarily due to the following:
• $3.4 million decrease in overall generating expenses;
• $2.5 million decrease in employee pension and benefit cost;
• $2.2 million decrease in consulting fees; and
• $2.2 million in higher capitalization of administrative and general costs for the Harry Allen Generating Station.
The decrease in other operating expense was partially offset by a $9.5 million increase in stock compensation costs.
Maintenance expense increased for the year ended December 31, 2012, compared to the same period in 2011, primarily due to the following:
• the absence of an $8 million reduction in maintenance expense recorded in 2011 as a result of the final calculation of a terminated amount for a long-term service agreement for the Higgins Generating Station which was previously expensed in 2010;
• $11.8 million increase primarily due to planned maintenance and outages at the Lenzie, Silverhawk, Harry Allen and Higgins Generating Stations; and
• $2.8 million cancellation fee for the Silverhawk Generating Station long-term service agreement.
The increase was partially offset by a $12.9 million decrease in planned maintenance and outages at the Reid Gardner, Navajo and Clark Generating Stations.
Maintenance expense decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to the following:
• $16 million impact of an accrual in 2010 for estimated payments for the termination of the long-term service agreement for the Higgins Generating Station, which was reversed in the third quarter of 2011 upon final calculation of the termination amount; and
• $8.3 million decrease in planned maintenance and outages at the Higgins, Lenzie and Silverhawk Generating Stations.
This decrease was partially offset by a $15.6 million increase in planned maintenance and outages at the Reid Gardner, Navajo, Clark and Harry Allen Generating Stations.
Depreciation and amortization increased for the year ended December 31, 2012, compared to 2011, primarily due to increased depreciation of $7.8 million resulting from the expansion at Harry Allen Generating Station placed in service in May 2011. Also contributing to the increase was a change in depreciation rates, as of January 1, 2012, resulting from a recent depreciation study, additional regulatory assets amortizations, and other general increases in plant-in-service.
Depreciation and amortization increased for the year ended December 31, 2011, compared to 2010, primarily due to increased depreciation of $14.9 million resulting from the expansion at Harry Allen Generating Station placed in service in May 2011. Also contributing to the increase were other general increases in plant-in-service.
Interest expense decreased for the year ended December 31, 2012, compared to the same period in 2011 primarily due to approximately $10.8 million in decreased net interest costs from various re-financings and redemptions, partially offset by variable rate debt fluctuations and a $1.6 million decrease in AFUDC-debt. See Note 6, Long-Term Debt, of the Notes to Financial Statements for additional information regarding long-term debt.
Interest expense increased for the year ended December 31, 2011, compared to the same period in 2010 primarily due to a $13.0 million decrease in AFUDC primarily due to the completion of the Harry Allen Generating Station in May 2011. The increase was partially offset by an $8.6 million decrease in net interest costs as a result of various re-financings, redemptions and a lower revolving credit facility balance. See Note 6, Long-Term Debt, of the Notes to Financial Statements for additional information regarding long-term debt.
Interest income (expense) on regulatory items changed for the year ended December 31, 2012, compared to the same period in 2011 due to a $3.1 million decrease in interest income related to the deferred BTGR balance. Also contributing to the change was a $6.3 million decrease of interest income due to lower regulatory asset balances partially offset by a decrease in interest expense of $2.3 million due to lower over-collected deferred energy balances in 2012. See Note 3, Regulatory Actions, of the Notes to Financial Statements for further details of deferred energy balances.
Interest income (expense) on regulatory items changed for the year ended December 31, 2011, compared to the same period in 2010 due to a $3.1 million decrease in interest income related to the deferred BTGR balance. Also contributing to the change was $3.3 million decrease of interest income due to lower over-collected deferred energy balances in 2011, offset by an increase of interest income of $3.9 million due to lower regulatory asset balances. See Note 3, Regulatory Actions, of the Notes to Financial Statements for further details of deferred energy balances.
AFUDC-equity decreased for the year ended December 31, 2012, compared to 2011, primarily due to the completion of various construction projects. Approximately $3.7 million of the decrease was due to the completion of the Harry Allen Generating Station in May 2011, partially offset by an increase of $1.9 million related to construction of ON-Line.
AFUDC-equity decreased for the year ended December 31, 2011, compared to 2010, primarily due to the completion of various construction projects. Approximately $15.5 million of the decrease was due to the completion of Harry Allen Generating Station in May 2011.
Other income increased for the year ended December 31, 2012, compared to the same period in 2011, primarily due to the $5.5 million gain on the sale of telecommunication towers and the reversal of carrying charges previously recorded (see Note 15, Assets Held for Sale, of the Notes to Financial Statements), which was recognized in 2012, and a $4.9 million settlement for the Harry Allen construction project.
Other income decreased for the year ended December 31, 2011, compared to the same period in 2010 primarily due to interest income of $2.7 million recorded in 2010 related to an income tax refund, and a decrease of $1.0 million related to lower gains on investments.
Other expense decreased for the year ended December 31, 2012, compared to the same period in 2011 primarily due to the following:
• $10.8 million adjustment in 2011 resulting from NPC’s GRC in 2011;
• $3.0 million adjustment, recorded in 2011, as a result on an order from the PUCN adjusting EEIR revenue recorded in 2010;
• $2.8 million adjustments for the settlement of the deferred energy rate case in 2011
• $2.3 million decrease in loss on investments in 2011; and
• $2.0 million decrease in donations in 2012.
The decrease was offset slightly by a $1.1 million adjustment for the settlement of the deferred energy rate case in 2012. For further discussion of regulatory adjustments see Note 3, Regulatory Actions, of the Notes to Financial Statements.
Other expense increased for the year ended December 31, 2011, compared to the same period in 2010 primarily due to the following:
• $10.8 million adjustment in 2011 resulting from NPC’s GRC in 2011;
• $3.0 million adjustment, recorded in 2011, as a result on an order from the PUCN adjusting EEIR revenue recorded in 2010;
• $2.8 million adjustments for the settlement of the deferred energy rate case in 2011;
• $2.0 million increase in donations in 2011; and
• $1.5 million increase in loss on investments in 2011.
The increase was offset slightly by $3.5 million adjustment for the settlement of the deferred energy rate case in 2010. For further discussion of regulatory adjustments see Note 3, Regulatory Actions, of the Notes to Financial Statements.
Analysis of Cash Flows
NPC’s cash flows increased during the year ended December 31, 2012, compared to the same period in 2011, due to an increase in cash from operating and a reduction in cash used by investing activities, offset partially by an increase in cash used by financing activities.
Cash from Operating Activities - The increase in cash from operating activities was primarily due to increased revenues resulting primarily due to increase BTGR rates as a result of NPC’s 2011 GRC and increased customer usage. Also contributing to the increase were over collections of EEPR, reduced funding of the retirement plan, a reduction in spend for conservation programs and refunds of customer deposits in 2011. These increases were partially offset by quarterly BTER adjustments and negative DEAA rates to refund prior period over collected balances and expiration of rates to collect the deferred rate increase from NPC’s 2008 GRC.
Cash used by Investing Activities - The decrease in cash used by investing activities was primarily due to the completion of construction at the Harry Allen Generating Station in May 2011 partially offset by proceeds from the sale of certain telecommunication towers in 2011 and CIAC received under the American Recovery and Reinvestment Act of 2009, related to the NV Energize project.
Cash used by Financing Activities - Cash used by financing activities increased primarily due to a reduction in capital contribution from NVE, an increase in dividends paid to NVE and a reduction in cash from the issuance of debt, partially offset by a 2011 settlement payment for the interest rate swap agreement as discussed in Note 6, Long Term Debt, of the Notes to Financial Statements.
NPC’s cash flows decreased during in 2011 compared to 2010 due to a decrease in cash from operating and financing activities, offset partially by a reduction in cash used by investing activities.
Cash from Operating Activities - The decrease in cash from operating activities was primarily due to a decrease in net income, an overall decrease in rates resulting from quarterly BTER adjustments and negative DEAA rates implemented in October 2010 to refund prior period over collected balances to customers, increased incentive compensation payments for the 2010 operating results, an increase in coal and other inventory, refunds of customer deposits and an increase in conservation programs and solar rebates. These decreases were partially offset by an increase in cash resulting from NPC’s deferred rate increase beginning in October 2010, the recovery of deferred conservation program costs and lower funding for pension plans.
Cash used by Investing Activities - The decrease in cash used by investing activities was primarily due to proceeds from the sale of certain telecommunication towers as discussed in Note 15, Assets Held for Sale, of the Notes to Financial Statements and CIAC received under the American Recovery and Reinvestment Act of 2009, as a part of the NV Energize project.
Cash used by Financing Activities - Cash used by financing activities decreased primarily due to a reduction in draws on NPC’s revolving credit facility, the redemption of NPC’s $350 million aggregate principal amount of 8.25%, Series A, General and
Refunding Mortgage Notes, which were partially paid by proceeds from the issuance of NPC’s $250 million 5.45%, Series Y, General and Refunding Mortgage Notes. Also contributing to the decrease was the payment of dividends to NVE and a settlement payment for the interest rate swap agreement as discussed in Note 6, Long Term Debt, of the Notes to Financial Statements. The decrease was partially offset by a capital contribution from NVE.
LIQUIDITY AND CAPITAL RESOURCES
Overall Liquidity
NPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on NPC’s outstanding indebtedness. Another significant use of cash is the refunding of previously over-collected amounts from customers. See Note 3, Regulatory Actions, of the Notes to Financial Statements for more details of over-collected balances. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome, and economic conditions. Available liquidity as of December 31, 2012 was as follows (in millions):
NPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills and bank deposits. In addition to cash on hand, NPC may use its revolving credit facility in order to meet its liquidity needs. Alternatively, depending on the usage of the revolving credit facility, NPC may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below.
NPC is required to redeem approximately $98.1 million of its variable rate debt, due 2020, prior to ON Line’s commercial operation date, expected no later than December 31, 2013. To meet this maturing debt obligation, NPC intends to use a combination of internally generated funds, its revolving credit facility, and/or the issuance of long-term debt. As of February 21, 2013, NPC has no borrowings on its revolving credit facility, not including letters of credit. In 2012, NPC’s credit ratings on its senior secured debt remained at investment grade (see Credit Ratings below). In 2012, NPC did not experience any limitations in the credit markets, nor does NPC expect any significant limitations in 2013. However, disruptions in the banking and capital markets not specifically related to NPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.
In prior years, NPC required significant amounts of liquidity due to the magnitude of capital expenditures needed to support a growing customer base and to support unstable energy markets. As NPC transitioned to slower growth, the amount of capital expenditures has declined. NPC’s investment in generating stations in the past several years and more stable energy markets have positioned NPC to better manage and optimize its resources. As a result, NPC anticipates that it will be able to meet short term operating costs and capital expenditures with internally generated funds and the use of its revolving credit facilities. Furthermore, with new investments now in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, federal tax NOL and a decrease in capital expenditures, NPC expects to generate free cash flow. The free cash flow may be used to reduce debt, to increase dividend payout and for potential investment opportunities.
However, if energy costs rise at a rapid rate and NPC does not recover the cost of fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner or NPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to NPC could be significantly less. In order to maintain sufficient liquidity, NPC may be required to further delay capital expenditures, refinance debt or obtain funding through an equity issuance by NVE. Additionally, if deemed prudent, NPC may enter into hedging transactions in an attempt to mitigate projected or actual rising energy costs. Currently, NPC is not operating under a PUCN approved hedging plan. Hedging transactions may have a material impact on NPC’s cash flows, unless recovered in rates in a timely manner.
In 2012, NPC paid dividends to NVE of $184.0 million. On February 7, 2013, NPC declared a dividend payable to NVE of $50 million.
NPC designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, NPC has continuing commitments for capital expenditures for construction, improvement and maintenance of facilities.
Detailed below are NPC’s Capital Structure, Capital Requirements, recently completed Financing Transactions and Factors Affecting Liquidity, including our ability to obtain debt on favorable terms.
Capital Structure
NPC’s actual consolidated capital structure was as follows at December 31 (dollars in thousands):
Capital Requirements
Construction Expenditures
NPC’s cash requirement for construction expenditures for 2013 is projected to be $283.1 million. NPC’s cash requirements for construction expenditures for 2013 through 2017 are projected to be $1.2 billion. Gross construction expenditures, including AFUDC-debt, net salvage and CIAC for the years ended 2012, 2011, and 2010 were $287.6 million, $475.1 million, and $499.4 million, respectively. Net cash requirements to fund construction for the years ended 2012, 2011 and 2010 were $245.2 million, $387.5 million, and $452.9 million, respectively. To fund future capital projects NPC may meet such financial obligations with a combination of internally generated funds, the use of its revolving credit facilities, the issuance of long-term debt, and if necessary, capital contributions from NVE.
Contractual Obligations
The table below provides NPC’s consolidated contractual obligations, as of December 31, 2012, that NPC expects to satisfy through a combination of internally generated cash and, as necessary, through the issuance of short-term and long-term debt. Certain contracts contain variable factors which required NPC to estimate the obligation depending on the final variable amount. Actual amounts could differ. The table does not include estimated construction expenditures described above, except for major capital projects for which NPC has executed contracts by December 31, 2012. Additionally, at December 31, 2012, NPC has recorded an uncertain tax liability of $3.8 million required by the accounting guidance for Uncertainty in Income Taxes Topic of the FASC, all of which is classified as non-current. NPC is unable to make a reasonably reliable estimate of the period of cash payments to relevant tax authorities; consequently, none of the uncertain tax liability is included in the contractual obligations table below (dollars in millions):
(1) Represents estimated payments under renewable energy power purchase contracts, which have been approved by the PUCN and are contingent upon the developers obtaining commercial operation and their ability to deliver energy.
(2) Includes the TUA with GBT which is contingent upon final construction costs and reaching commercial operation.
(3) Amounts based on estimated usage.
(4) Capital projects include NPC’s termination payment for the undepreciated cost of capital of Reid Gardner Generating Station Unit No. 4 from CDWR. See Note 5, Jointly Owned Facilities, of the Notes to Financial Statements. Additionally, included in capital projects are obligations regarding the construction of ON Line, of which NPC will be responsible for 95% and SPPC 5%. See Note 12, Commitment and Contingencies, of the Notes to Financial Statements.
Pension and Other Postretirement Benefit Plan Matters
NVE has a qualified pension plan and other postretirement benefits plan which cover substantially all employees of NVE, NPC and SPPC. The annual net benefit cost for the plans is expected to increase in 2013 by approximately $3.1 million compared to the 2012 cost of $22.5 million. As of December 31, 2012, the measurement date, the plan was under funded under the provisions of the Compensation Retirement Benefits Topic of the FASC. Refer to Note 10, Retirement Plan and Postretirement Benefits, of the Notes to Financial Statements. During 2012, NVE funded a total of $22.1 million to the trusts established for the qualified pension and postretirement benefit plans. At the present time it is not anticipated that additional funding will be required in 2013 to meet the minimum funding level requirements defined by the Pension Protection Act of 2006. However, NVE and the Utilities have included in their 2013 assumptions funding levels similar to the 2012 funding. The amounts to be contributed in 2013 may change subject to market conditions.
Financing Transactions
General and Refunding Mortgage Notes, Series I
In April 2012, NPC used $120 million from its revolving credit facility along with $10 million cash on hand to pay for the maturity of its 6.5% General and Refunding Mortgage Notes, Series I, in an aggregate principal amount of $130 million. NPC did not have any other debt maturities in 2012; however, NPC is required to redeem approximately $98.1 million of its variable rate debt, due 2020, prior to ON Line’s commercial operation date, expected no later than December 31, 2013.
$500 Million Revolving Credit Facility
In March 2012, NPC terminated its $600 million secured revolving credit facility which would have expired in April 2013 and replaced it with a $500 million secured revolving credit facility, for which borrowings mature in 2017. The fees on the $500 million revolving credit facility for the unused portion and on the amounts borrowed have decreased from the prior facility reflecting current market conditions. The Administrative Agent for the facility remains Wells Fargo Bank, N.A., and amounts due under the NPC Credit Agreement are collateralized by NPC’s general and refunding mortgage bonds.
The rate for outstanding loans under the revolving credit facility will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus 0.5% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin. The margin varies based upon NPC’s credit rating by S&P and Moody’s. Currently, NPC’s applicable base rate margin is 0.25% and the LIBOR rate margin is 1.25 %. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.
The $500 million revolving credit facility contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates. The reduction in availability limits the amount that NPC can borrow or use for letters of credit and would require that NPC prepay any amount in excess of that limitation. The amount of the reduction is calculated by NPC on a monthly basis, and after calculating such reduction, the NPC Credit Agreement provides that the reduction in availability under the revolving credit facility to NPC shall in no event exceed 50% of the total commitments then in effect under the revolving credit facility. Currently, there are no negative mark-to-market exposures that would impact borrowings.
The NPC Credit Agreement contains one financial maintenance covenant that requires NPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. In the event that NPC did not meet the financial maintenance covenant or there is a different event of default, the NPC Credit Agreement would restrict dividends to NVE. Moreover, so long as NPC’s senior secured debt remains rated investment grade by S&P and Moody’s (in each case, with a stable or better outlook), a representation concerning no material adverse change in NPC’s business, assets, property or financial condition would not be a condition to the availability of credit under the facility. In the event that NPC’s senior secured debt rating were rated below investment grade by either S&P or Moody’s, or investment grade by either S&P or
Moody’s but with a negative outlook, a representation concerning no material adverse change in NPC’s business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility.
The NPC Credit Agreement provides for an event of default if there is a failure under NPC’s other financing agreements to meet certain payment terms or to observe other covenants that would result in an acceleration of payments due.
The NPC Credit Agreement places certain restrictions on debt incurrence, liens and dividends. These restrictions are discussed in Note 8, Debt Covenant and Other Restrictions, of the Notes to Financial Statements.
Factors Affecting Liquidity
Ability to Issue Debt
NPC
NPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and revolving credit facility agreements, and the terms of NVE’s Term Loan. As of December 31, 2012, the most restrictive of the factors below is the PUCN authority. As such, NPC may issue up to $725 million in long-term debt, in addition to the use of its existing credit facilities. However, depending on NVE’s or SPPC’s issuance of long-term debt or the use of the Utilities’ revolving credit facilities, the PUCN authority may not remain the most restrictive factor. The factors affecting NPC’s ability to issue debt are further detailed below:
a. Financing authority from the PUCN - As of December 31, 2012, NPC has financing authority from the PUCN for the period ending December 31, 2013, consisting of authority: (1) to issue additional long-term debt securities of up to $725 million; (2) to refinance up to approximately $322.5 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $1.3 billion.
b. Financial covenants within NPC’s financing agreements - Under its $500 million revolving credit facility, NPC must maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. Based on December 31, 2012 financial statements, NPC was in compliance with this covenant and could incur up to $2.8 billion of additional indebtedness.
All other financial covenants contained in NPC’s financing agreements are currently suspended; as NPC’s senior secured debt is rated investment grade. However, if NPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, NPC would again be subject to the limitations under these additional covenants; and
c. Financial covenants within NVE’s Term Loan - As discussed in NVE’s Ability to Issue Debt, NPC is also subject to NVE’s cap on additional consolidated indebtedness of $3.3 billion.
Ability to Issue General and Refunding Mortgage Securities
To the extent that NPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, NPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under NPC’s Indenture.
NPC’s Indenture creates a lien on substantially all of NPC’s properties in Nevada. As of December 31, 2012, $3.8 billion of NPC’s General and Refunding Mortgage Securities were outstanding. NPC had the capacity to issue $1.6 billion of additional General and Refunding Mortgage Securities as of December 31, 2012. That amount is determined on the basis of:
1. 70% of net utility property additions; and/or
2. The principal amount of retired General and Refunding Mortgage Securities.
Property additions include plant-in-service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.
NPC also has the ability to release property from the lien of NPC’s Indenture on the basis of net property additions, cash and/or retired bonds. To the extent NPC releases property from the lien of NPC’s Indenture, it will reduce the amount of securities issuable under the Indenture.
Credit Ratings
The liquidity of NPC, the cost and availability of borrowing by NPC under its credit facility, the potential exposure of NPC to collateral calls under various contracts and the ability of NPC to acquire fuel and purchased power on favorable terms are all directly affected by the credit rating for NPC’s debt. On February 20, 2013, S&P upgraded NPC’s corporate credit rating from BB+ to investment grade BBB-. NPC’s senior secured debt is rated investment grade by three NRSROs: Fitch, Moody’s and S&P. The senior secured debt credit ratings are as follows:
Fitch’s rating outlook is Positive, while Moody’s and S&P’s rating outlook for NPC is Stable.
A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and 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 evaluated in the context of the applicable methodology, independently of all other ratings. The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.
Energy Supplier Matters
With respect to NPC’s contracts for purchased power, NPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that NPC uses as a member of the WSPP. The WSPP contract is posted on the WSPP website.
Under these contracts, a material adverse change, which includes a credit rating downgrade, in NPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. A default must be declared within 30 days of the event giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market value as of December 31, 2012 for all suppliers continuing to provide power under a WSPP agreement would approximate a $72 million payment or obligation to NPC. These contracts qualify for the normal purchases scope exception under the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet.
Gas Supplier Matters
With respect to the purchase and sale of natural gas, NPC uses several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily means a credit rating downgrade below investment grade. Most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurances. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure.
Gas transmission service is secured under FERC Tariffs or custom agreements. These service contracts and Tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive
service. Service contracts are subject to FERC approved Tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service. NPC has a transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades. As of December 31, 2012, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $86.7 million. Of this amount, approximately $26 million would be required if NPC’s Senior Unsecured ratings (and/or equivalent) are rated below BB (S&P) or Ba3 (Moody’s) and an additional amount of approximately $60.7 million would be required if NPC’s Senior Unsecured ratings and Senior Secured ratings (or equivalent), both are downgraded to below investment grade. During the second quarter of 2012, $17.9 million of letters of credit posted as collateral were returned from the counterparty to NPC during the period due to NPC’s unsecured credit rating equivalent becoming investment grade. In exchange, the amount of additional cash collateral that would be required in the event of a credit rating downgrade increased.
Financial Gas Hedges
NPC may enter into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed under NPC’s Financing Transactions, the availability under NPC’s revolving credit facility is reduced by the amount of net negative mark-to-market positions on hedging contracts with counterparties who are lenders to the revolving credit facility, provided that the reduction in availability under the revolving credit facility shall at no time exceed 50% of the total commitments then in effect under the revolving credit facility. Currently, there are no negative mark-to-market exposures that would impact borrowings of NPC. If deemed prudent, NPC may still purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.
Cross Default Provisions
None of the financing agreements of NPC contains a cross-default provision that would result in an event of default by NPC upon an event of default by NVE or SPPC under any of its financing agreements. In addition, certain financing agreements of NPC provide for an event of default if there is a failure under other financing agreements of NPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time NPC may rectify or correct the situation before it becomes an event of default.
Sierra Pacific Power Company
RESULTS OF OPERATIONS
SPPC recognized net income of $84.4 million for the year ended December 31, 2012, compared to net income of $59.9 million in 2011 and a net income of $72.4 million in 2010. In 2012, SPPC paid dividends to NVE of approximately $20 million. Details of SPPC’s operating results are further discussed below.
Gross margin is presented by SPPC in order to provide information that management believes aids the reader in determining how profitable the electric business is at the most fundamental level. Gross margin, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, provides a measure of income available to support the other operating expenses of the business and is a key factor utilized by management in its analysis of its business.
SPPC believes presenting gross margin allows the reader to assess the impact of SPPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in regulated electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which SPPC calculates as operating revenues less energy costs and EEPR costs, provides a measure of income available to support the other operating expenses of SPPC.
EEPR costs are conservation costs being recovered from ratepayers through EEPR revenues which were implemented in July 2011 (See Note 3, Regulatory Actions, of the Notes to Financial Statements). Costs incurred prior to the implementation of the EEPR are recovered through general rates and amortized to other operating expense. See Note 3, Regulatory Actions, of the Notes to Financial Statements for conservation program amount details. The EEPR mechanism is designed such that conservation costs are equal to revenues collected and any over/under collection is deferred as a regulatory asset/liability until rates are reset. As a result, amounts related to EEPR do not have an effect on gross margin, operating income or net income.
For reconciliation to operating income, see Note 2, Segment Information, of the Notes to Financial Statements. Gross margin changes are based primarily on general base rate adjustments (which are required to be filed by statute every three years).
The components of gross margin for the years ended December 31 were as follows (dollars in thousands):
Electric gross margin increased for the year ended December 31, 2012, compared to the same period in 2011, primarily due to a $7.8 increase in customer usage and a $4.4 million increase as a result of customer growth.
Electric gross margin decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to the sale of the California Assets, as discussed in Note 15, Assets Held for Sale, of the Notes to Financial Statements, partially offset by a related five year power sale agreement entered into as a condition to the sale of the assets. Further contributing to the decrease was increased margin in 2010 as a result of an adjustment for California revenues upon a final filing in 2010 with the CPUC in regards to the Rate Reduction Certificates Series 1991-1. In addition, reduced DOS impact fees in 2011 contributed to the decrease in margin. Partially offsetting this decrease were increased rates, particularly among commercial and industrial customer classes, as a result of SPPC’s GRC effective January 1, 2011, as well as increased customer usage among residential and industrial classes primarily as a result of weather.
Gas gross margin decreased for the year ended December 31, 2012, compared to the same period in 2011, primarily due to decreased customer usage as a result of warmer weather.
Gas gross margin increased for the year ended December 31, 2011, as compared to the same period in 2010, primarily due to increased customer usage.
The causes for significant changes in specific lines comprising the results of operations for the years ended are provided below (dollars in thousands except for amounts per unit):
HDDs and CDDs
MWh usage may be affected by the change in HDDs or CDDs in a given period. A degree day indicates how far that day's average temperature departed from 65 degrees Fahrenheit. HDDs measure heating energy demand and indicate how far the average temperature fell below 65 degrees Fahrenheit. CDDs measure cooling energy demand and indicate how far the temperature averaged above 65 degrees Fahrenheit. For example, if a location had a mean temperature of 60 degrees Fahrenheit on day 1 and 80 degrees Fahrenheit on day 2, there would be 5 HDDs (65 minus 60) and 0 CDDs for day 1. In contrast, there would be 0 HDDs and 15 CDDs (80 minus 65) for day 2.
The following table shows the HDDs and CDDs within SPPC’s service territory:
Retail revenue increased for the year ended December 31, 2012, as compared to the same period in 2011 primarily due to the following:
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$12.9 million increase in customer usage primarily due to an increase in CDDs as outlined in the table above, and increased usage by mining customers;
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$8.6 million attributable to the implementation of EEPR base rates effective July 1, 2011, and EEPR amortization rates effective October 1, 2011;
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$2.0 million increase in EEIR revenue (see Note 3, Regulatory Actions, of the Notes to Financial Statements);and
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$2.9 million attributable to customer growth.
These increases were partially offset by approximately $16.5 million of rate decreases due to SPPC’s annual Deferred Energy cases effective October 1, 2012 and 2011, and various BTER and DEAA quarterly updates (see Note 3, Regulatory Actions, of the Notes to Financial Statements).
For the year ended December 31, 2012, the average number of residential and industrial customers increased 0.7% and 4.7%, respectively, while commercial customers remained the same compared to the same period in 2011.
Retail revenue decreased for the year ended December 31, 2011, as compared to the same period in 2010 primarily due to the following:
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$114.2 million due to decreases in retail rates as a result of SPPC’s annual Deferred Energy cases effective October 1, 2011 and 2010 and various BTER quarterly updates (see Note 3, Regulatory Actions, of the Notes to Financial Statements).
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$69.5 million attributable to a reduction in California revenues due to the sale of the California Assets on January 1, 2011 (see Note 15, Assets Held for Sale, of the Notes to Financial Statements).
These decreases were partially offset by:
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$11.6 million of rate increases due to SPPC’s 2010 GRC effective January 1, 2011;
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$6.2 million due to the implementation of EEPR rates effective July 1, 2011 (see Note 3, Regulatory Actions, of the Notes to Financial Statements); and
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$3.5 million due to customer growth.
Excluding California customers, the average number of residential and commercial customers increased by 0.4% and 0.9%, respectively, while industrial customers decreased by 1.8% compared to the same period in 2010.
Electric Operating Revenues - Other decreased for the year ended December 31, 2012, compared to the same period in 2011 primarily due to a decrease of $5.0 million in energy sales to CalPeco. This decrease was partially offset by an increase of approximately $1.7 million in transmission service revenues.
Electric Operating Revenues - Other increased for the year ended December 31, 2011, compared to the same period in 2010 primarily due to a $43.2 million increase in revenues from energy sales to CalPeco, under a five year agreement as a condition to the sale of SPPC’s California Assets which occurred on January 1, 2011 (see Note 15, Assets Held for Sale, of the Notes to Financial Statements). This increase was partially offset by an $8.4 million decrease in the amortization of DOS impact fees.
SPPC’s retail gas revenues decreased for the year ended December 31, 2012, compared to the same period in 2011, primarily due to a $36.5 million decrease in retail rates as a result of SPPC’s annual Deferred Energy cases, effective October 1, 2012 and 2011, and various BTER and DEAA quarterly updates (see Note 3, Regulatory Actions, of the Notes to Financial Statements). Retail revenues further decreased due $9.4 million related to a decrease in usage primarily due to a decrease in HDDs, as shown in the table above.
SPPC’s retail gas revenues decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to a $34.3 million decrease in retail rates as a result of SPPC’s various BTER quarterly updates and the annual Natural Gas and Propane Deferred Rate Cases effective October 1, 2011 and 2010 (see Note 3, Regulatory Actions, of the Notes to Financial Statements). The decrease was partially offset by an $8.1 million increase in customer usage primarily due to an increase in HDDs, and $2.6 million of rate increases due to SPPC’s 2010 GRC effective January 1, 2011 (see Note 3, Regulatory Actions, of the Notes to Financial Statements).
Wholesale revenues decreased for year ended December 31, 2012, compared to the same period in 2011, primarily due to a decrease in pipeline optimization sales, an increase in the utilization of capacity releases and a general decrease in natural gas costs.
Wholesale revenues increased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to an increase in pipeline optimization sales and seasonal availability of unused capacity.
Energy Costs
Energy Costs include Fuel for Generation and Purchased Power. These costs are dependent upon many factors which may vary by season or period. As a result, SPPC’s usage and average cost per MWh of Fuel for Generation versus Purchased Power can vary significantly as the company meets the demands of the season. These factors include, but are not limited to:
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Weather;
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Plant outages;
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Total system demand;
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Resource constraints;
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Transmission constraints;
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Gas transportation constraints;
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Natural gas constraints;
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Mandated power purchases; and
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Generation efficiency.
Energy costs and average cost per MWh decreased for the year ended December 31, 2012, compared to the same period in 2011 primarily due to lower natural gas prices and a decrease in costs associated with hedging activities.
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Fuel for generation costs decreased for the year ended December 31, 2012 compared to the same period in 2011. Approximately $35.4 million of the change is due to lower natural gas prices partially offset by an increase in volume of approximately $16.8 million. Fuel for generation costs were further decreased by $5.8 million due to a decrease in hedging activities.
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Purchased power costs decreased for the year ended December 31, 2012 compared to the same period in 2011. Approximately $15.8 million of the decrease is due to lower natural gas prices and $9.6 million is due to decreased volume. Volume decreased due to increased reliance on internal generation.
Energy costs and the average cost per MWh decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to decreased hedging costs along with lower natural gas costs. Total system demand for the year ended December 31, 2011 increased for the same period due to colder winter temperatures.
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Fuel for generation costs decreased for the year ended December 31, 2011 as compared to the same period in 2010. Approximately $25.6 million of the change was due to a decrease in volume primarily due to outages at the Tracy and Valmy Generating Stations. Fuel for generation costs were further decreased by $26.3 million due to a decrease in hedging activities. These decreases were offset by a $1.0 million increase in coal prices.
•
Purchased power costs increased for the year ended December 31, 2011 as compared to the same period in 2010. Approximately $18.0 million of the change was due to an increase in volume, primarily due to outages discussed above and the availability of hydro power purchases early in the year which were more economical. The increase was partially offset by a decrease in natural gas prices of $5.0 million.
Gas purchased for resale decreased for the year ended December 31, 2012, compared to the same period in 2011. Approximately $24.3 million of the decrease is due to lower natural gas prices and approximately $21.0 million is due to a decrease in volume. Volume decreased primarily due to a decrease in pipeline optimization sales and an increase in the utilization of capacity releases.
Gas purchased for resale decreased for the year ended December 31, 2011, compared to the same period in 2010. Approximately $13.1 million of the decrease is due to a decrease in option expense and approximately $12.7 million is due to lower natural gas prices, both offset by an increase in volume of $13.2 million. The volume of gas purchased for resale increased in 2011 compared to 2010 primarily due to pipeline optimization sales.
Deferred energy - electric for 2012, 2011 and 2010 reflect amortization of deferred energy costs of $(78.6), $(104.9) and $(42.5) million, respectively; which represent cash refunds to our customers for previous over-collections partially offset by an over-collection of amounts recoverable in rates of $52.2, $39.5 and $51.0 million in 2012, 2011 and 2010 respectively. Refer to Note 3, Regulatory Actions, of the Notes to Financial Statements for further detail of deferred energy balances.
Deferred energy - gas for 2012, 2011 and 2010 reflect amortization of deferred energy of $(29.2), $(22.2) and $(11.1) million, respectively; which represent cash refunds to our customers for previous over-collections partially offset by an over-collection of amounts recoverable in rates of $16.9, $20.7 and $20.9 million in 2012, 2011 and 2010 respectively.
Deferred energy represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through current rates, the excess is recognized as a reduction in costs. Conversely to the extent actual costs are less than amounts recoverable through current rates, the difference is recognized as an increase in costs. Deferred energy also includes the current amortization of fuel and purchased power costs previously deferred.
Energy efficiency program costs increased for the year ended December 31, 2012 compared to the same period in 2011 due to the implementation of EEPR base rates in July 2011 and amortization rates effective October 2011.
Energy efficiency program costs are conservation costs being recovered from ratepayers through EEPR revenues which were implemented in July 2011 for base rates and in October 2011 for amortization rates (See Note 3, Regulatory Actions, of the Notes to Financial Statements). Costs incurred prior to the implementation of the EEPR rates are recovered through the general rates and amortized to other operating expense discussed below. The EEPR mechanism is designed such that conservation costs are equal to revenues collected and any over/under collection is deferred as a regulatory asset/liability until rates are reset. As a result, amounts related to EEPR do not have an effect on gross margin, operating income or net income.
Other operating expense decreased for the year ended December 31, 2012, compared to the same period in 2011, primarily due to the following:
• $4.4 million decrease in pension and benefit costs;
• $3.3 million increase in capitalized costs due to an increase in construction activity;
• $1.8 million decrease in rate cases expenses; and
• $1.3 million decrease in telecommunications and information technology expenses.
The decrease was partially offset by a $2.1 million increase in outside legal consulting fees, and a $1.4 million increase in stock compensation costs.
Other operating expense decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to the following:
• $5.1 million in reduced customer expenses;
• $4.0 million decrease in outside consulting fees;
• $2.1 million decrease in rate case expenses;
• $2.0 million decrease in lease expenses; and
• $1.2 million decrease in employee pension and benefit costs.
These decreases were partially offset by $9.6 million of regulatory amortizations primarily for conservation programs and a $3.7 million increase in stock compensation costs.
Maintenance expense decreased for the year ended December 31, 2012, compared to the same period in 2011, primarily due to a $5.9 million decrease in planned maintenance and outages at the Valmy Generating Station, offset by a $1.5 million increase in planned maintenance and outages at the Tracy Generating Station.
Maintenance expense increased for the year ended December 31, 2011, compared to the same period in 2010, mainly due to a $2.1 million increase for planned maintenance outages at the Valmy Generating Station and a $2.9 million increase for planned maintenance and outages at the Tracy and Ft. Churchill Generating Stations.
Depreciation and amortization increased for the year ended December 31, 2012, compared to 2011, primarily due to growth in plant.
Depreciation and amortization decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to change in depreciation rates effective January 1, 2011.
Interest expense decreased for the year ended December 31, 2012, compared to the same period in 2011, primarily due to decreased debt amortization expense of $4.2 million.
Interest expense decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to the decrease of interest expense of $6.1 million related to the redemption of $100 million Series H General and Refunding Mortgage Bonds in December 2010, offset by an increase of $5.3 million in debt redemption amortization expenses. See Note 6, Long-Term Debt, of the Notes to Financial Statements for additional information regarding long-term debt.
Interest expense on regulatory items decreased for the year ended December 31, 2012, compared to the same period in 2011, primarily due to $3.2 million in decreased interest expense related to lower over-collected deferred energy balances in 2012. See Note 3, Regulatory Actions, of the Notes to Financial Statements for further details of deferred energy balances.
Interest expense on regulatory items decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to $1.8 million in decreased interest expense related to lower over-collected deferred energy balances in 2011 of $1.8 million, offset by a $1.0 million decrease in carrying charges on solar conservation programs. See Note 3, Regulatory Actions, of the Notes to Financial Statements for further details of deferred energy balances.
AFUDC-equity increased slightly for the year ended December 31, 2012, compared to 2011, primarily due to an increase in base construction projects.
AFUDC-equity decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to completion of various construction projects.
Other income increased for the year ended December 31, 2012, compared to the same period in 2011, primarily due to a $1.1 million settlement with CAISO in 2011 recognized in 2012. For further discussion, see Note 3, Regulatory Actions, FERC Matters, of the Notes to Financial Statements.
Other income decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to the recognition of the gain on sale of Independence Lake in 2010 of $4.9 million, as further discussed in Note 15, Assets Held for Sale, of the Notes to Financial Statements, a decrease in income from subleases in 2011 of $2.1 million, and a reduction in other miscellaneous gains of $1.1 million.
Other expense decreased for the year ended December 31, 2012, as compared to the same period in 2011 primarily due to the following:
• $2.8 million adjustment, recorded in 2011, as a result of an order from the PUCN adjusting EEIR revenue recorded in 2010 see Note 3, Regulatory Actions, EEIR, of the Notes to Financial Statements;
• $1.4 million adjustment in 2011 for the EEC as a result of NPC’s 2011 GRC;
• $1.0 million in decreased charitable donations;
• a net adjustment to legal reserves of $0.7 million;
• lower losses on investments of $0.5 million in 2012; and
• $0.5 million adjustment for the settlement of the deferred energy rate case in 2011.
These decreases were offset slightly by $0.2 million adjustment for the settlement of the deferred energy rate case in 2012. For further discussion of the DEAA adjustment see Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2011 Form 10-K and Note 3, Regulatory Actions, of the Notes to Financial Statements.
Other expense increased for the year ended December 31, 2011 compared to the same period in 2010 primarily due to the following:
• $2.8 million adjustment in the second quarter of 2011, upon final order from the PUCN, for EEIR revenue recorded in 2010;
• increased legal reserves of $2.7 million in 2011; and
• an adjustment of $1.4 million for the EEC as a result of NPC’s 2011 GRC.
Partially offsetting these increases was a decrease in lease expense of $2.6 million in 2011.
Analysis of Cash Flows
SPPC’s cash flows decreased during the year ended December 31, 2012, compared to the same period in 2011, due to an increase in cash used by investing activities, offset partially by an increase in cash from operating activities and a reduction in cash used by financing activities.
Cash from Operating Activities - The increase in cash from operating activities was primarily due to a reduction in refunds of over collected balances for energy, reduced coal purchases, increased customer deposits and over collections of EEPR. These increases were partially offset by increased energy payments due to a change in terms with energy counterparties from weekly to monthly settlements in mid-2011, higher rebates for wind energy in 2012, the receipt of cash in 2011 under the affiliate tax sharing agreement and the timing of property tax payments.
Cash used by Investing Activities - The increase in cash used by investing activities was primarily due to increased capital expenditure for the NV Energize project in 2012 partially offset by CIAC received under the American Recovery and Reinvestment Act of 2009 for the NV Energize project. The increase in cash used by investing activities further increased due to the receipt of proceeds in 2011 from the sale of the California Assets.
Cash used by Financing Activities - The decrease in cash used by financing activities is primarily due to a reduction in dividends to NVE and the repayment of draws under SPPC’s revolving credit facility in 2011.
SPPC’s cash flows increased in 2011 compared to 2010 due to a decrease in cash used by investing and financing activities, offset partially by a decrease in cash from operating activities.
Cash from Operating Activities - The decrease in cash from operating activities was primarily due to a decrease in net income, an overall decrease in rates resulting from quarterly BTER adjustments and negative DEAA rates implemented in October 2010 to refund prior period over collected balances to customers. Also contributing to the decrease is the reduction in revenues from California customers due to the sale of the California Assets, as discussed in Note 15, Assets Held for Sale, of the Notes to Financial Statements, an increase in coal inventory for the Valmy Generating Station, an increase in conservation and renewable energy program costs, increased funding of pension plans and increased incentive compensation payments for the 2010 operating results. These decreases were partially offset by the recovery of deferred conservation program costs as a result of SPPC’s 2010 GRC.
Cash used by Investing Activities - Cash used by investing activities decreased due to the receipt of proceeds from the sale of California Assets, as discussed in Note 15, Assets Held for Sale, of the Notes to Financial Statements and CIAC received under the American Recovery and Reinvestment Act of 2009, as part of NV Energize.
Cash used by Financing Activities - The decrease in cash used by financing activities is primarily due to a reduction in retirement of long-term debt, offset partially by higher dividends to NVE.
LIQUIDITY AND CAPITAL RESOURCES
Overall Liquidity
SPPC’s primary source of operating cash flows is electric and natural gas revenues, including the recovery of previously deferred energy costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on SPPC’s outstanding indebtedness. Another significant use of cash is the refunding of previously over-collected amounts from customers. See Note 3, Regulatory Actions, of the Notes to Financial Statements for more details of over-collected balances. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions. Available liquidity as of December 31, 2012 was as follows (in millions):
SPPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills and bank deposits. In addition to cash on hand, SPPC may use its revolving credit facility in order to meet its liquidity needs. Alternatively, depending on the usage of the revolving credit facility, SPPC may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below.
SPPC’s $250 million 5.45% General and Refunding Notes, Series Q, will mature on September 1, 2013. To meet this maturing debt obligation, SPPC intends to use a combination of internally generated funds, its revolving credit facility, and/or the issuance of long-term debt. As of February 21, 2013, SPPC has no borrowings on its revolving credit facility, not including letters of credit. In 2012, SPPC’s credit ratings on its senior secured debt remained at investment grade (see Credit Ratings below). In 2012, SPPC did not experience any limitations in the credit markets, nor do we expect any significant limitations in 2013. However, disruptions in the banking and capital markets not specifically related to SPPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.
In prior years, SPPC required significant amounts of liquidity due to the magnitude of capital expenditures needed to support a growing customer base and to support unstable energy markets. As SPPC transitioned to slower growth, the amount of capital expenditures has declined. SPPC’s investment in generating stations in the past several years and more stable energy markets have positioned SPPC to better manage and optimize its resources. As a result, SPPC anticipates that it will be able to meet short term operating costs and capital expenditures with internally generated funds and the use of its revolving credit facilities. Furthermore, with new investments now in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, federal tax NOL and a decrease in capital expenditures, SPPC expects to generate free cash flow. The free cash flow may be used to reduce debt, to increase dividend payout and for potential investment opportunities.
However, if energy costs rise at a rapid rate and SPPC does not recover the cost of fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner or SPPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to SPPC could be significantly less. In order to maintain sufficient liquidity, SPPC may be required to further delay capital expenditures, refinance debt or obtain funding through an equity issuance by NVE. Additionally, if deemed prudent, SPPC may enter into hedging transactions in an attempt to mitigate projected or actual rising energy costs. Currently, SPPC is not operating under a PUCN approved hedging plan. Hedging transactions may have a material impact on SPPC’s cash flows, unless recovered in rates in a timely manner.
In 2012, SPPC paid dividends to NVE of $20 million.
SPPC designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, SPPC has continuing commitments for capital expenditures for construction, improvement and maintenance of facilities.
Detailed below are SPPC’s Capital Structure, Capital Requirements, recently completed Financing Transactions and Factors Affecting Liquidity, including its ability to obtain debt on favorable terms.
Capital Structure
SPPC’s actual consolidated capital structure was as follows at December 31 (dollars in thousands):
Capital Requirements
Construction Expenditures
SPPC’s cash requirement for construction expenditures for 2013 is projected to be $167.5 million. SPPC’s cash requirement for construction expenditures for 2013 through 2017 is projected to be $847.5 million. Gross construction expenditures, including AFUDC-debt, net salvage and CIAC for the years ended 2012, 2011 and 2010 were $211.3 million, $145.4 million and $143.2
million, respectively. Net cash requirements to fund construction for the years ended 2012, 2011 and 2010 were $169.1 million, $134.7 million and $137.5 million, respectively. To fund future capital projects SPPC may meet such financial obligations with a combination of internally generated funds, the use of its revolving credit facility and if necessary, the issuance of long-term debt and/or capital contributions from NVE.
Contractual Obligations
The table below provides SPPC’s consolidated contractual obligations, as of December 31, 2012, that SPPC expects to satisfy through a combination of internally generated cash and, as necessary, through the issuance of short-term and long-term debt. Certain contracts contain variable factors which required SPPC to estimate the obligation depending on the final variable amount. Actual amounts could differ. The table does not include estimated construction expenditures described above, except for major capital projects for which SPPC has executed contracts by December 31, 2012. Additionally, at December 31, 2012, SPPC recorded an uncertain tax liability of $2.8 million as required by the accounting guidance for Uncertainty in Income Taxes Topic of the FASC, all of which is classified as non-current. SPPC is unable to make a reasonably reliable estimate of the period of cash payments to relevant tax authorities; consequently, none of the uncertain tax liability is included in the contractual obligations table below (dollars in millions):
(1) Includes the TUA with GBT which is contingent upon final construction costs and reaching commercial operation.
(2) Amounts based on estimated usage.
(3) SPPC, as a joint owner, has obligations regarding the construction of ON Line.
Pension and Other Postretirement Benefit Plan Matters
NVE has a qualified pension plan and other postretirement benefits plan which cover substantially all employees of NVE, NPC and SPPC. The annual net benefit cost for the plans is expected to increase in 2013 by approximately $3.1 million compared to the 2012 cost of $22.5 million. As of December 31, 2012, the measurement date, the plan was under funded under the provisions of the Compensation Retirement Benefits Topic of the FASC. Refer to Note 10, Retirement Plan and Postretirement Benefits, of the Notes to Financial Statements. During 2012, NVE funded a total of $22.1 million to the trusts established for the qualified pension and postretirement benefit plans. At the present time it is not anticipated that additional funding will be required in 2013 to meet the minimum funding level requirements defined by the Pension Protection Act of 2006. However, NVE and the Utilities have included in their 2013 assumptions funding levels similar to the 2012 funding. The amounts to be contributed in 2013 may change subject to market conditions.
Financing Transactions
$250 Million Revolving Credit Facility
In March 2012, SPPC terminated its $250 million secured revolving credit facility which would have expired in April 2013 and replaced it with a $250 million secured revolving credit facility, for which borrowings mature in 2017. The fees on the $250 million revolving credit facility for the unused portion and on the amounts borrowed have decreased from the prior facility reflecting current market conditions. The Administrative Agent for the facility is Wells Fargo, N.A., and amounts due under the SPPC Credit Agreement are collateralized by SPPC’s general and refunding mortgage bonds.
The rate for outstanding loans under the revolving credit facility will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus 0.5% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin. The margin varies based upon SPPC’s credit rating by S&P and Moody’s. Currently, SPPC’s applicable base rate margin is 0.25% and the LIBOR rate margin is 1.25%. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.
The $250 million revolving credit facility contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates. The reduction in availability limits the amount that SPPC can borrow or use for letters of credit and would require that SPPC prepay any amount in excess of that limitation. The amount of the reduction is calculated by SPPC on a monthly basis, and after calculating such reduction, the SPPC Credit Agreement provides that the reduction in availability under the revolving credit facility to SPPC shall in no event exceed 50% of the total commitments then in effect under the revolving credit facility. Currently, there are no negative mark-to-market exposures that would impact borrowings.
The SPPC Credit Agreement contains one financial maintenance covenant that requires SPPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. In the event that SPPC did not meet the financial maintenance covenant or there is a different event of default, the SPPC Credit Agreement would restrict dividends to NVE. Moreover, so long as SPPC’s senior secured debt remains rated investment grade by S&P and Moody’s (in each case, with a stable or better outlook), a representation concerning no material adverse change in SPPC’s business, assets, property or financial condition would not be a condition to the availability of credit under the facility. In the event that SPPC’s senior secured debt rating were rated below investment grade by either S&P or Moody’s, or investment grade by either S&P or Moody’s but with a negative outlook, a representation concerning no material adverse change in SPPC’s business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility.
The SPPC Credit Agreement provides for an event of default if there is a failure under SPPC’s other financing agreements to meet certain payment terms or to observe other covenants that would result in an acceleration of payments due.
The SPPC Credit Agreement places certain restrictions on debt incurrence, liens and dividends. These limitations are discussed in Note 8, Debt Covenant and Other Restrictions, of the Notes to Financial Statements.
Factors Affecting Liquidity
Ability to Issue Debt
SPPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and its revolving credit facility agreement, and the terms of NVE’s Term Loan. As of December 31, 2012, the most restrictive of the factors below is the PUCN authority. Based on this restriction, SPPC may issue up to $350 million of long-term debt securities, and maintain a credit facility of up to $600 million. However, depending on NVE’s or NPC’s issuance of long-term debt or the use of the Utilities’ revolving credit facilities, the PUCN authority may not remain the most restrictive factor. The factors affecting SPPC’s ability to issue debt are further detailed below:
a. Financing authority from the PUCN - As of December 31, 2012, SPPC has financing authority from the PUCN for the period ending December 31, 2015, consisting of authority (1) to issue additional long-term debt securities of up to $350 million; (2) to refinance approximately $348 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $600 million.
b. Financial covenants within SPPC’s financing agreements - Under SPPC’s $250 million revolving credit facility, SPPC must maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. Based on December 31, 2012 financial statements, SPPC was in compliance with this covenant and could incur up to $1.0 billion of additional indebtedness.
All other financial covenants contained in SPPC’s financing agreements are currently suspended; as SPPC’s senior secured debt is rated investment grade. However, if SPPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, SPPC would again be subject to the limitations under these additional covenants.
c. Financial covenants within NVE’s Term Loan - As discussed in NVE’s Ability to Issue Debt, SPPC is also subject to NVE’s cap on additional consolidated indebtedness of $3.3 billion.
Ability to Issue General and Refunding Mortgage Securities
To the extent that SPPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, SPPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under SPPC’s Indenture.
SPPC’s Indenture creates a lien on substantially all of SPPC’s properties in Nevada. As of December 31, 2012, $1.5 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. SPPC had the capacity to issue $824 million of additional General and Refunding Mortgage Securities as of December 31, 2012. That amount is determined on the basis of:
1. 70% of net utility property additions; and/or
2. The principal amount of retired General and Refunding Mortgage Securities.
Property additions include plant in service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.
SPPC also has the ability to release property from the lien of SPPC’s Indenture on the basis of net property additions, cash and/or retired bonds. To the extent SPPC releases property from the lien of SPPC’s Indenture, it will reduce the amount of securities issuable under the Indenture.
Credit Ratings
The liquidity of SPPC, the cost and availability of borrowing by SPPC under its credit facility, the potential exposure of SPPC to collateral calls under various contracts and the ability of SPPC to acquire fuel and purchased power on favorable terms are all directly affected by the credit rating for SPPC’s debt. On February 20, 2013, S&P upgraded SPPC’s corporate credit rating from BB+ to investment grade BBB-. SPPC’s senior secured debt is rated investment grade by three NRSROs: Fitch, Moody’s and S&P. The senior secured debt credit ratings are as follows:
Fitch’s rating outlook is Positive, while Moody’s and S&P’s rating outlook for SPPC is Stable.
A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and 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 evaluated in the context of the applicable methodology, independently of all other ratings. The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.
Energy Supplier Matters
With respect to SPPC’s contracts for purchased power, SPPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that SPPC uses as a member of the WSPP. The WSPP contract is posted on the WSPP website.
Under these contracts, a material adverse change, which includes a credit rating downgrade, in SPPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. A default must be declared within 30 days of the event, giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single
liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. According to the net mark-to-market value as of December 31, 2012, no amounts would be due to or from SPPC for all suppliers continuing to provide power under a WSPP agreement. These contracts qualify for the normal purchases scope exception as defined by the Derivatives and Hedging Topic of the FASC, and as such, are not required to be mark-to-market on the balance sheet.
Gas Supplier Matters
With respect to the purchase and sale of natural gas, SPPC uses several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse change, which primarily means a credit rating downgrade below investment grade. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure. Most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, no counterparties require payment in advance of delivery.
Gas transmission service is secured under FERC Tariffs or custom agreements. These service contracts and Tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved Tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service.
Financial Gas Hedges
SPPC may enter into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed under SPPC’s Financing Transactions, the availability under SPPC’s revolving credit facility is reduced by the amount of net negative mark-to-market positions on hedging contracts with counterparties who are lenders to the revolving credit facility, provided that the reduction in availability under the revolving credit facility shall at no time exceed 50% of the total commitments then in effect under the revolving credit facility. Currently, there are no negative mark-to-market exposures that would impact borrowings of SPPC. If deemed prudent, SPPC may still purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.
Cross Default Provisions
None of the financing agreements of SPPC contains a cross default provision that would result in an event of default by SPPC upon an event of default by NVE or NPC under any of its financing agreements. In addition, certain financing agreements of SPPC provide for an event of default if there is a failure under other financing agreements of SPPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time SPPC may rectify or correct the situation before it becomes an event of default.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk
As of December 31, 2012, NVE, NPC and SPPC have evaluated their risk related to financial instruments whose values are subject to market sensitivity. Such instruments are fixed and variable rate debt. Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities (dollars in thousands):
Commodity Price Risk
Commodity price increases due to changes in market conditions are recovered through the deferred energy mechanism. Although the Utilities actively manage energy commodity (electric, natural gas, coal and oil) price risk through their procurement strategies, the ability to recover commodity price changes through future rates substantially mitigates commodity price risk. However, the Utilities are subject to cash flow risk due to changes in the value of their open positions and are subject to regulatory risk because the PUCN may disallow recovery for any costs that it considers imprudently incurred. The Utilities mitigate both risk associated with its open positions and regulatory risk through prudent energy supply practices which include the use of long-term fuel supply agreements, long-term purchase power agreements and derivative instruments such as forwards, options and swaps to meet the anticipated fuel and power requirements. See Energy Supply in Item 1, Business, for a discussion of the Utilities’ purchased power procurement strategies.
Credit Risk
The Utilities monitor and manage credit risk with their trading counterparties. Credit risk is defined as the possibility that a counterparty to one or more contracts will be unable or unwilling to fulfill its financial or physical obligations to the Utilities because of the counterparty’s financial condition. The Utilities’ credit risk associated with trading counterparties was approximately $77.5 million as of December 31, 2012, compared to a balance of $40.7 million at December 31, 2011. The increase from December 31, 2011 is primarily due to the increase in forward prices of natural gas and power during 2012.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
NV Energy, Inc.
Las Vegas, Nevada
We have audited the accompanying consolidated balance sheets of NV Energy, Inc. and subsidiaries (the "Company") as of December 31, 2012 and 2011, and the related consolidated statements of comprehensive income, shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule 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 NV Energy, Inc. and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
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, 2012, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2013 expressed an unqualified opinion on the Company's internal control over financial reporting.
/s/ Deloitte & Touche LLP
Las Vegas, Nevada
February 26, 2013
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Nevada Power Company
Las Vegas, Nevada
We have audited the accompanying consolidated balance sheets of Nevada Power Company and subsidiaries (the "Company") as of December 31, 2012 and 2011, and the related consolidated statements of comprehensive income, shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 Nevada Power Company and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects the information set forth therein.
/s/ Deloitte & Touche LLP
Las Vegas, Nevada
February 26, 2013
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Sierra Pacific Power Company
Las Vegas, Nevada
We have audited the accompanying consolidated balance sheets of Sierra Pacific Power Company and subsidiaries (the "Company") as of December 31, 2012 and 2011, and the related consolidated statements of comprehensive income, shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 Sierra Pacific Power Company and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects the information set forth therein.
/s/ Deloitte & Touche LLP
Las Vegas, Nevada
February 26, 2013
NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Thousands, Except Share Amounts)
NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(Dollars in Thousands, Except Share Amounts)
NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Thousands)
NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDER’S EQUITY
(Dollars in Thousands, Except Share Amounts)
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Thousands)
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDER’S EQUITY
(Dollars in Thousands, Except Share Amounts)
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The significant accounting policies for both utility and non-utility operations are as follows:
Basis of Presentation
The consolidated financial statements include the accounts of NV Energy, Inc. and its wholly-owned subsidiaries, NPC, SPPC, Sierra Pacific Communications, Lands of Sierra, Inc., NVE Insurance and Sierra Gas Holding Company. All intercompany balances and intercompany transactions have been eliminated in consolidation.
The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities. These estimates and assumptions also affect the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of certain revenues and expenses during the reporting period. Actual results could differ from these estimates.
NPC is an operating public utility that provides electric service in Clark County in southern Nevada. The assets of NPC represent approximately 72% of the consolidated assets of NVE at December 31, 2012. NPC provides electricity to approximately 850,000 customers in the communities of Las Vegas, North Las Vegas, Henderson, Searchlight, Laughlin and adjoining areas, including Nellis Air Force Base. The consolidated financial statements of NPC include its wholly-owned subsidiary, NEICO.
SPPC is an operating public utility that provides electric service in northern Nevada and previously provided service to northeastern California. SPPC also provides natural gas service in the Reno/Sparks area of Nevada. The assets of SPPC represent approximately 28% of the consolidated assets of NVE at December 31, 2012. SPPC provides electricity to approximately 324,000 customers in an approximate 42,000 square mile service area including western, central and northeastern Nevada, including the cities of Reno, Sparks, Carson City and Elko. On January 1, 2011, SPPC sold its California Assets, as discussed in Note 15, Assets Held for Sale. SPPC also provides natural gas service in Nevada to approximately 153,000 customers in an area of about 800 square miles in the Reno and Sparks areas. The consolidated financial statements of SPPC include the accounts of SPPC’s wholly-owned subsidiaries, PPC, PPIC and GPSF-B.
The Utilities’ accounts are maintained in accordance with the Uniform System of Accounts prescribed by the FERC.
Reclassifications
Financial statement line items for current and long-term risk management liabilities from prior periods have been combined with Other current liabilities and Other deferred credits and liabilities lines to conform with current year presentation. In addition, interest on regulatory items other than deferred charges has been classified from Other income, Other expense to Interest income (expense) on regulatory items. The reclassifications have not affected previously reported reports of operations, statements of financial position or shareholders’ equity.
NVE and SPPC Balance Sheet Corrections
During the fourth quarter of 2012, SPPC discovered an error in its calculation of deferred income taxes and the related income tax regulatory asset specific to amounts associated with AFUDC-equity resulting in an understatement of both regulatory assets and deferred tax liabilities of the same amount. NVE and SPPC have corrected the December 31, 2011 consolidated balance sheets to increase the regulatory assets and deferred income tax liabilities by $32.0 million, which did not result in a change to net assets. NVE and SPPC’s Statements of Comprehensive Income, Equity and Cash Flow were not impacted. December 31, 2011 and 2010 amounts for Assets, in Note 2, Segment Information, for both NVE and SPPC were also adjusted by $32.0 million and $30.6 million, respectively. Additionally, December 31, 2011 amounts for Regulatory assets, Income taxes, in the Other Regulatory Assets tables for both NVE and SPPC in Note 3, Regulatory Actions, and related deferred tax amounts in Note 9, Income Taxes (Benefits), have been adjusted. Management has concluded that this correction is immaterial.
Regulatory Accounting and Other Regulatory Assets
The Utilities’ rates are subject to the approval of the PUCN and are designed to recover the cost of providing generation, transmission and distribution services. As a result, the Utilities qualify for the application of regulatory accounting treatment as allowed by the Regulated Operations Topic of the FASC. This statement recognizes that the rate actions of a regulator can provide reasonable assurance of the existence of an asset and requires the deferral of incurred costs that would otherwise be charged to
expense where it is probable that future revenue will be provided to recover these costs. The accounting guidance prescribes the method to be used to record the financial transactions of a regulated entity. The criteria for applying the accounting for regulated operations include the following: (i) rates are set by an independent third party regulator; (ii) regulated rates are designed to recover the specific costs of the regulated products or services; and (iii) it is reasonable to assume that rates are set at levels that recovered costs can be charged to and collected from customers. Management periodically assesses whether the requirements for application of regulatory accounting treatment as allowed by the Regulated Operations Topic of the FASC are satisfied.
Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates collected from customers. If at any time the incurred costs no longer meet these criteria, these costs are charged to earnings. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections, except for cost of removal which represents the cost of removing future electric and gas assets. Management believes the existing regulatory assets are probable of recovery either because the Utilities received prior PUCN approval or due to regulatory precedent set for similar circumstances. Included in Note 3, Regulatory Actions, are details of other regulatory assets and liabilities, and their current regulatory treatment.
Equity Carrying Charges
In accordance with various regulatory orders, the Utilities record carrying charges as allowed by the Regulated Operations Topic of the FASC. However, for financial reporting purposes the amounts representing equity carrying charges are not recognized until collected through regulated rates. As of December 31, 2012 and 2011, NPC and SPPC have accumulated approximately $11.1 million and $0.6 million, and $12.7 million and $0.9 million, respectively, of equity related carrying charges that will be recognized into income when the corresponding regulatory assets primarily related to NPC’s deferred rate increase, the Lenzie Generating Station and the Utilities’ conservation programs are collected through rates. For further information, see Note 3, Regulatory Actions, Other Regulatory Assets table.
Deferred Energy Accounting
Nevada and California statutes permit regulated utilities to adopt deferred energy accounting procedures. However, on January 1, 2011, SPPC sold its California Assets, as disclosed in Note 15, Assets Held for Sale. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased gas, fuel and purchased power.
Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the statement of operations but rather is deferred and recorded as an asset on the balance sheet in accordance with the provisions of the Regulated Operations Topic of the FASC. Conversely, a liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs. These excess amounts are reflected in adjustments to rates and recorded as revenue or expense in future time periods, subject to PUCN review.
Nevada law requires the Utilities file annual DEAA applications and provides that the PUCN may not allow the recovery of any costs for purchased fuel or purchased power “that were the result of any practice or transaction that was undertaken, managed or performed imprudently by the electric utility.” Nevada law also specifies that fuel and purchased power costs include all costs incurred to purchase fuel, to purchase capacity and to purchase energy. The Utilities also record and are eligible under the statute to recover a carrying charge on such deferred balances. The Utilities may also file to reset BTERs quarterly, based on the last 12 months fuel and purchased power costs. Additionally, Nevada regulations allow an electric or gas utility that adjusts its BTER on a quarterly basis to request PUCN approval to make quarterly changes to its DEAA rate if the request is in the public interest. The Utilities are still required to file an annual DEAA case to review costs for prudency and reasonableness, and if any costs are disallowed on such grounds, the disallowance will be incorporated into the next subsequent quarterly rate change. See Note 3, Regulatory Actions for details regarding deferred energy balances.
Energy Efficiency Implementation Rate (EEIR) and Energy Efficiency Program Rate (EEPR)
In July 2010, regulations were adopted by the Legislature that authorizes an electric utility to recover lost revenue that is attributable to the measurable and verifiable effects associated with the implementation of efficiency and conservation programs approved by the PUCN. As a result, the Utilities file annually in March, to adjust rates and set a clearing rate or EEIR effective in October of the same year for over or under collected balance, similar to the deferred energy mechanism discussed above. In addition, the regulation approved the transition of the recovery for the implementation costs of energy efficiency programs from general rates (filed every 3 years) to recovery through annual rate filings annually in March, to adjust rates and set a clearing rate or EEPR effective
in October of the same year for over or under collected balance, similar to the deferred energy mechanism discussed above. See Note 3, Regulatory Actions for details regarding EEIR and EEPR balances.
Materials, Supplies and Fuel
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. Fuel inventory includes the average cost of coal, natural gas and oil. Fuel is charged to inventory when purchased and then expensed as used in energy costs and recovered by the Utilities through BTER rates approved by the PUCN.
Utility Plant
The cost of additions, including betterments and replacements of units of property, are charged to utility plant. When units of property are replaced, renewed or retired, their cost plus removal or disposal costs, less salvage proceeds, are charged to accumulated depreciation. The cost of current repairs and minor replacements are charged to maintenance expense when incurred, with the exception of long term service agreements. These agreements may have annual payment amounts for repairs which could vary over the life of the agreement between maintenance expense and amounts to be capitalized. To ensure consistency in annual expense for rate making purposes, the amounts to be charged to maintenance expense are smoothed over the life of the contract, with an offset to a regulatory asset or liability account. Amounts prepaid for capital expenditure are recorded in a prepaid asset account.
In addition to direct labor and material costs, certain other direct and indirect costs are capitalized. The indirect construction overhead costs capitalized are based upon the following cost components: the cost of time spent by administrative and supervision employees in planning and directing construction; property taxes; employee benefits including such costs as pensions, postretirement and post-employment benefits, vacations and payroll taxes; and an AFUDC which includes the cost of debt and equity capital associated with construction activity.
Included in Total Utility Property, net, as Electric and Natural Gas Distribution assets are the net carrying values of the remaining meters subject to early retirement under the NV Energize program for NPC and SPPC. In accordance with a PUCN order, the net carrying values are reclassified to a regulatory asset at the time of retirement. NPC and SPPC expect full recovery of the regulatory assets through the Utilities’ regulatory proceedings.
Utility Property
NVE, NPC and SPPC’s gross utility property and CWIP are divided into the following major classes at December 31 (dollars in millions):
AFUDC
AFUDC represents the cost of borrowed funds and, where appropriate, the cost of equity funds used for construction purposes in accordance with rules prescribed by the FERC and the PUCN. AFUDC is capitalized in the same manner as construction labor and material costs, however, with an offsetting credit to “other income” for the portion representing the cost of equity funds; and as a reduction of interest charges for the portion representing borrowed funds. Recognition of this item as a cost of utility plant is in accordance with established regulatory ratemaking practices. Such practices are intended to permit the Utility to earn a fair return on, and recover in rates charged for utility services, all capital costs. This is accomplished by including such costs in the rate base and in the provision for depreciation. NPC’s AFUDC rate used during 2012, 2011 and 2010 were 8.09%, 8.47% and 8.32% respectively.
SPPC’s AFUDC rates used during 2012, 2011 and 2010 were 7.86% (Electric), 5.15% (Gas) and 7.59% (Common), 7.86% (Electric) and 5.15% (Gas), and 7.85%, respectively. (In 2012 and 2011, separate rates were calculated for common due to different rates of return allowed by PUCN Docket 10-06002 for electric and gas). As specified by the PUCN, certain projects may be assigned a lower or higher AFUDC rate due to specific interest-rate financings directly associated with those projects.
Depreciation
Substantially all of the Utilities’ plant is subject to the ratemaking jurisdiction of the PUCN or the FERC. Depreciation expense is calculated using the straight-line composite method over the estimated remaining service lives of the related properties, which approximates the anticipated physical lives of these assets in most cases. NPC’s depreciation provision, as authorized by the PUCN and stated as a percentage of the average depreciable property balances for those years, was approximately 3.22%, 3.04% and 2.99% during 2012, 2011 and 2010, respectively. SPPC’s depreciation provision for 2012, 2011 and 2010, as authorized by the PUCN and stated as a percentage of the average cost of depreciable property, was approximately 2.94%, 2.89% and 3.02%, respectively.
The average estimated useful life for each major class of utility property, plant and equipment are as follows:
Impairment of Long-Lived Assets
NVE, NPC and SPPC evaluate on an ongoing basis the recoverability of its assets for impairments whenever events or changes in circumstance indicate that the carrying amount may not be recoverable as described in the Property, Plant and Equipment Topic of the FASC.
Cash and Cash Equivalents
Cash is comprised of cash on hand and working funds. Cash equivalents consist of high quality investments in money market funds with maturities of 90 days or less and do not have any withdrawal restrictions.
Allowance for Uncollectible Accounts
The allowance for uncollectible accounts is based on the Utilities' estimate of the collectability of amounts owed by customers. This estimate is primarily derived from historical write-off trends applied to the previous five months of revenue and accounts receivable balances. The Utilities' also have the ability to assess deposits on customers who have delayed payments or who are deemed to be a credit risk. Accounts receivable are shown on the balance sheet net of the allowance for uncollectible accounts.
Federal Income Taxes
NVE and the Utilities file a consolidated federal income tax return. Current income taxes are allocated based on NVE’s and each Utility’s respective taxable income or loss and tax credits as if each Utility filed a separate return.
NVE and the Utilities recognize deferred tax liabilities and assets for the future tax consequences of events that have been included in the financial statements or tax returns. Deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Deferred tax assets are also recorded for deductions incurred and credits earned that have not been utilized in tax returns filed or to be filed for tax years through the date of the financial statements. Management considers estimates of the amount and character of future taxable income by tax jurisdiction in assessing the likelihood of realization of deferred tax assets. If it is not more likely than not that a deferred tax asset will be realized in its entirety, a valuation allowance is recorded with respect to the portion estimated not likely to be realized.
Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the more-likely-than-not recognition threshold is satisfied and measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. NVE and the Utilities classify interest and penalties associated with unrecognized tax benefits as interest and other expense, respectively, within the income statement. No interest expense or penalties associated with unrecognized tax benefits have been recorded.
The Utilities reduce rates to reflect the current tax benefits associated with recognizing certain tax deductions sooner than when the expenses are recognized for financial reporting purposes. A regulatory asset is recorded for these amounts to reflect the future increases in income taxes payable that will be recovered from customers when these temporary differences reverse. The Utilities have been fully normalized since 1987. AFUDC-equity is recorded on an after-tax basis. Accordingly, a regulatory asset is recorded when AFUDC-equity is recognized. This regulatory asset reverses as the related plant is depreciated, resulting in an increase to the tax provision.
The Utilities also record regulatory liabilities for obligations to reduce rates charged customers for deferred taxes recovered from customers in prior years at corporate tax rates higher than the current tax rates. The reduction in rates charged customers will occur as the temporary differences resulting in the excess deferred tax liabilities reverse.
Investment tax credits are deferred and amortized over the estimated service lives of the related properties.
Revenues
Unbilled
Revenues related to the sale of energy are recorded based on meter reads, which occur on a systematic basis throughout a month, rather than when the service is rendered or energy is delivered. At the end of each month, the energy delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenues are calculated. These estimates of unbilled sales and revenues are based on the ratio of billable days versus unbilled days, amount of energy procured and generated during that month, historical customer class usage patterns, line loss and the Utilities’ current tariffs. Accounts receivable as of December 31, 2012, included unbilled receivables of $86 million and $50 million for NPC and SPPC, respectively. Accounts receivable as of December 31, 2011, included unbilled receivables of $93 million and $51 million for NPC and SPPC, respectively.
Asset Retirement Obligations
The Asset Retirement and Environmental Liabilities Topic of the FASC provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the accounting guidance, these liabilities are recognized in other deferred credits and liabilities at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. Accretion of the liabilities due to the passage of time is classified as an operating expense. Retirement obligations associated with long-lived assets included within the scope of the accounting guidance are those for which a legal obligation exists under enacted laws, statutes written or oral contracts, including obligations arising under the doctrine of promissory estoppel.
Management’s methodology to assess its legal obligation included an inventory of assets by company, system and components and a review of rights of way and easements, regulatory orders, leases and federal, state and local environmental laws. Management identified a legal obligation to retire generation plant assets specified in land leases for NPC’s jointly-owned Navajo Generating Station and the Higgins Generating Station. Provisions of the lease require the lessees to remove the facilities upon request of the lessors at the expiration of the leases. Additionally, management has determined evaporative ponds, dry ash landfills, fuel storage tanks, asbestos and oils treated with Poly Chlorinated Biphenyl to have met the conditional asset retirement obligations as defined in the Asset Retirement and Environmental Liabilities Topic of the FASC.
The following table presents a reconciliation of the beginning and ending aggregate carrying amounts of asset retirement obligation for the years presented below (dollars in thousands):
Cost of Removal
In addition to the legal asset retirement obligations booked under the accounting guidance for asset retirement obligations, the Utilities have accrued for the cost of removing non-legal retirement obligations of other electric and gas assets. The amounts of such accruals included in regulatory liabilities in 2012 are approximately $252.6 million and $204.4 million for NPC and SPPC, respectively. In 2011, the amounts were approximately $232.0 million and $189.9 million for NPC and SPPC, respectively.
Derivatives and Hedging Activities
NVE and the Utilities apply the accounting guidance as required by the Derivatives and Hedging Topic of the FASC. The accounting guidance for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities, requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those instruments at fair value, and recognize changes in the fair value of the derivative instruments in earnings in the period of change, unless the derivative meets certain defined conditions and qualifies as an effective hedge. The accounting guidance for derivative instruments also provides a scope exception for commodity contracts that meet the normal purchase and sales criteria specified in the standard. The normal purchases and normal sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchases and normal sales are accounted for under deferred energy accounting and not recorded on the consolidated balance sheets of NVE and the Utilities at fair value.
Commodity Risk
The energy supply function encompasses the reliable and efficient operation of the Utilities' generation, the procurement of all fuels and power and resource optimization (i.e., physical and economic dispatch) and is exposed to risks relating to, but not limited to, changes in commodity prices. NVE and the Utilities' objective in using derivative instruments is to reduce exposure to energy price risk. Energy price risks result from activities that include the generation, procurement and sale of power and the procurement and sale of natural gas. Derivative instruments used to manage energy price risk from time to time may include: forward contracts, which involve physical delivery of an energy commodity; over-the-counter options with financial institutions and other energy companies, which mitigate price risk by providing the right, but not the requirement, to buy or sell energy related commodities at a fixed price; and swaps, which require the Utilities to receive or make payments based on the difference between a specified price and the actual price of the underlying commodity. These contracts may assist the Utilities reduce the risks associated in volatile electricity and natural gas markets. As of December 31, 2012, the Utilities were not parties to such derivative transactions.
Interest Rate Risk
NVE and the Utilities may enter into interest rate swap agreements to manage existing and future fixed rate interest rate exposure in an effort to lower overall borrowing costs. These transactions are discussed further in Note 6, Long Term Debt, under the respective financing agreements as applicable.
Variable Interest Entities
NVE and the Utilities continually perform an analysis to determine whether their variable interests give them controlling financial interest in a VIE which would require consolidation. This analysis identifies the primary beneficiary of a VIE as the enterprise that has both the following characteristics: a) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, and b) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. To identify potential variable interests, management reviews contracts under leases, long term purchase power contracts, tolling contracts and jointly owned facilities. The Utilities identified certain long-term purchase power contracts that could be defined as variable interests. However, the Utilities are not the primary beneficiary as defined above, as they primarily lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions. The Utilities' maximum exposure to loss is limited to the cost of replacing these purchase power contracts if the providers are unable to deliver power. However, the Utilities believe their exposure is mitigated as they would likely recover these costs through their deferred energy accounting mechanism. As of December 31, 2012, the carrying amount of assets and liabilities in the Utilities’ balance sheets that relate to their involvement with VIEs are
predominately related to working capital accounts and generally represent the amounts owed by the Utilities for the deliveries associated with the current billing cycle under the contracts.
Franchise Fees and Universal Energy Charges
NPC and SPPC, as agents for some state and local governments collect from customers franchise fees and universal energy charges levied by the state or local governments on our customers. NPC and SPPC present such fees on a net basis, as such, fees are excluded from revenue and expense.
NOTE 2. SEGMENT INFORMATION
The Utilities operate three regulated business segments, NPC electric, SPPC electric and SPPC natural gas service, which are reported in accordance with Segment Reporting of the FASC. Electric service is provided to Las Vegas and surrounding Clark County by NPC, and to northern Nevada by SPPC. Natural gas services are provided by SPPC in the Reno-Sparks area of Nevada. Other information includes amounts below the quantitative thresholds for separate disclosure.
Operational information of the different business segments is set forth below based on the nature of products and services offered. NVE evaluates performance based on several factors, of which the primary financial measure is business segment gross margin. Gross margin, which the Utilities calculate as operating revenues less energy and energy efficiency program costs, provides a measure of income available to support the other operating expenses of the Utilities. Energy efficiency program costs are conservation costs being recovered from ratepayers through EEPR revenues which were implemented in July 2011. Costs incurred prior to the implementation of the EEPR are recovered through general rates and amortized to other operating expense. The EEPR mechanism is designed such that conservation costs are equal to revenues collected and any under/over collection is deferred as a regulatory asset/liability until rates are reset. As a result, amounts related to EEPR do not have an effect on gross margin, operating income or net income.
Operating expenses are provided by segment in order to reconcile to operating income as reported in the consolidated financial statements for the years ended December 31 (dollars in thousands):
NOTE 3. REGULATORY ACTIONS
The Utilities are subject to the jurisdiction of the PUCN and in the case of SPPC in prior years, the CPUC with respect to rates, standards of service, siting of and necessity for generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to electric distribution and transmission operations. However, on January 1, 2011, SPPC sold its California Assets, as discussed further in Note 15, Assets Held for Sale, and therefore is no longer subject to the jurisdiction of the CPUC. Under federal law, the Utilities are subject to certain jurisdictional regulation, primarily by the FERC. The FERC has jurisdiction under the Federal Power Act with respect to rates, service, interconnection, accounting and other matters in connection with the Utilities’ sale of electricity for resale and interstate transmission.
As a result of regulation, the Utilities are required to file annual electric and gas DEAA, EEIR and EEPR cases by March 1, and triennial GRCs. In addition, the Utilities may also file quarterly DEAA and BTER updates for the Utilities’ electric and gas departments. Reference Note 1, Summary of Significant Accounting Policies for further discussion of the various rate components. Detailed below are Deferred Energy Costs which relate to the DEAA and BTER filings and further below are other regulatory assets and liabilities which primarily relate to the GRCs. Additionally, significant pending or settled rate cases are discussed below.
The following deferred energy amounts were included in the consolidated balance sheets as of December 31 for the years shown below (dollars in thousands):
As discussed in Note 1, Summary of Significant Accounting Policies, regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates collected from customers. If at any time the incurred costs no longer meet these criteria, these costs are charged to earnings. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections, except for cost of removal which represents the cost of removing future electric and gas assets. Management regularly assesses whether the regulatory assets are probable of future recovery by considering actions of regulators, current laws related to regulation, applicable regulatory environment changes and the status of any current, pending or potential legislation. Detailed below are Other Regulatory Assets and Liabilities included in the balance sheet of NVE, NPC and SPPC and their current regulatory treatment as of December 31 (dollars in thousands):
(1) Earning a return includes either a carrying charge on the asset/liability balance, or a return as a component of rate base.
(2) Pending regulatory treatment includes either amounts which have prior regulatory precedent or have been approved and are subject to prudency review.
(3) Assets which are allowed to earn a carrying charge until included in rates. Reference Note 1, Summary of Significant Accounting Policies, Equity Carrying Charges.
(4) Liability balance represents amounts that have been overcollected.
Regulatory Actions
NPC
NPC 2012 DEAA, TRED and REPR, Rate Filings
In March 2012, NPC filed an application for the PUCN to review fuel and purchased power transactions for the 12-month period ending December 31, 2011, to reset the TRED and REPR rate elements and to retire the unamortized balance of NPC’s 2008 GRC deferred rate increase, as discussed below in NPC’s 2010 DEAA. In September 2012, the PUCN issued its final order which resulted in an increase in revenue requirement, as disclosed in the table below, for the 2008 GRC deferred rate increase, REPR and TRED effective October 2012. Included in its September order are immaterial adjustments to deferred fuel and purchase power balances and a requirement to increase the REPR rate to include prospective customer incentives associated primarily with its solar rebate programs.
NPC 2012 EEIR, EEPR Rate Filings
Subsequent to filing NPC’s DEAA, TRED, and REPR rate filings in March 2012, the PUCN issued a final order in NPC’s Annual Demand Side Management Update Report, requiring NPC to revise all lighting-specific calculations used in the EEIR and EEPR rate applications. As a result, the parties agreed to bifurcate the EEIR and EEPR portions of the March filing to allow NPC to amend the EEIR and EEPR rate requests using revised lighting-specific calculations and to hold a separate hearing on these components. In July 2012, NPC filed an amended EEIR and EEPR rate request. In December 2012, the PUCN issued its final order which resulted in an overall decrease in revenue requirement in EEIR and EEPR, as disclosed in the table below.
The PUCN approvals of the 2012 DEAA, TRED, REPR, EEIR and EEPR filings include the following (dollars in millions):
NPC 2011 GRC
In June 2011, NPC filed its statutorily required triennial GRC and updated the filing in August 2011. The filing, as updated requested an ROE of 11.25% and ROR of 8.64% and an increase to general revenues of $249.9 million. The PUCN issued its order in December 2011, which resulted in the following significant items:
• Increase in general rates of $158.6 million, approximately an 8.3% overall increase effective January 1, 2012;
• ROE and ROR of 10.0% and 8.09%, respectively;
• Recovery of approximately $635.9 million, excluding AFUDC, for the 500 MW (nominally rated) expansion at the Harry Allen Generating Station;
• Recovery of approximately $23.2 million for EEC project development costs;
• Recovery of approximately $17.7 million for demand side management costs;
• Recovery of approximately $12.7 million for Mohave Generating Station closure costs;
• Postpone final regulatory treatment of EWAM Phase 1 of approximately $46.9 million pending project completion and prudency review of NPC’s subsequent GRC filing; and
• Various other rate case adjustments for the Harry Allen Generating Station, Clark Peaking Units, and the EEC, offset by regulatory asset treatment for operating expenses for a net decrease to NVE’s fourth quarter 2011 consolidated net income of approximately $15.9 million before tax.
NPC 2011 DEAA, TRED, REPR, EEIR, EEPR Rate Filings
In March 2011, NPC filed an application to establish a new DEAA to refund over-collected purchased power and fuel costs and reset or establish several other rate elements (TRED, REPR, EEIR and EEPR). In September 2011, the PUCN accepted stipulations which resulted in an overall decrease in revenue requirement of approximately $78.6 million. The PUCN authorized the refund and recovery of the following amounts (dollars in millions):
NPC 2010 DEAA
In March 2010, NPC filed an application to create a new DEAA rate. In its application, NPC requested to refund $102 million of deferred fuel and purchased power costs. Separately, NPC filed a petition to offset the NPC DEAA over collection (credit balance) of $102 million against the deferred BTGR debit balance of $95.8 million. The BTGR debit balance of $95.8 million was a result of NPC’s 2008 GRC, which granted NPC approval to defer billings of its rate increase from July 1, 2009 to December 31, 2009 in a regulatory asset for which NPC recognized revenues in 2009. The PUCN consolidated both dockets for hearing purposes.
In September 2010, the PUCN accepted a stipulation for the DEAA and BTGR offset applications, which resulted in an overall revenue decrease of $9.2 million or 0.41% for the period October 1, 2010 through December 31, 2011.
Mohave Generating Station
NPC owns approximately 14% of the Mohave Generating Station. Southern California Edison is the operating partner of the Mohave Generating Station.
When operating, the Mohave Generating Station obtained all of its coal supply from a mine in northeast Arizona on lands of the Navajo Nation and the Hopi Tribe (the Tribes). This coal was delivered from the mine to the Mohave Generating Station by means of a coal slurry pipeline, which requires water that is obtained from groundwater wells located on lands of the Tribes in the mine vicinity.
The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S. District Court, District of Nevada in February 1998 against the owners (including NPC) of the Mohave Generating Station, alleging violations of the Clean Air Act regarding emissions of sulfur dioxide and particulates. An additional plaintiff, National Parks and Conservation Association, later joined the suit. In 1999, the plant owners and plaintiffs filed a settlement with the court, which resulted in a consent decree, approved by the court in November 1999. The consent decree established emission limits for sulfur dioxide and opacity and required installation of air pollution controls for sulfur dioxide, nitrogen oxides, and particulate matter. Pursuant to the decree, the Mohave Generating Station Units 1 and 2 ceased operations as of January 2006 as the new emission limits were not met. Due to the lack of resolutions regarding continual availability of the coal and water supply with the Tribes, the Owners did not proceed with the consent decree.
In December 2005, the Owners of the Mohave Generating Station suspended operation, pending resolution of these issues. However, in June 2006, majority stake holder Southern California Edison announced it would no longer participate in the efforts to return the plant to service. As a result, NPC decided it is not economically feasible to continue its participation in the project. In September 2006, Salt River’s co-tenancy agreement expired and the operating agreement between the Owners expired in July 2006. The Owners are discussing the negotiation of new agreements that would address the potential disposition of the assets and rights, title, interest and obligations in the Mohave Generating Station.
Included in other regulatory assets is approximately $6.9 million, which has been approved by the PUCN and included in rates. All other costs for Mohave Generating Station, including approximately $14.8 million of decommissioning costs were accumulated in other regulatory assets as incurred of which $10.5 million were approved by the PUCN, see the Other Regulatory Assets/Liabilities table above.
In June 2009, Southern California Edison announced that the Mohave Generating Station will be dismantled and its operating permits terminated following a December 2005 suspension of operations due to pending environmental matters. NPC believes it will continue to recover the costs for the Mohave Generating Station through the regulatory process and does not expect the dismantling of the plant to have a material impact on its financial condition.
SPPC
SPPC 2012 Electric DEAA, TRED and REPR Rate Filings
In March 2012, SPPC filed an application for the PUCN to review fuel and purchased power transactions for the 12-month period ending December 31, 2011 and to reset the TRED and REPR rate elements. In September 2012, the PUCN issued its final order which resulted in an increase in revenue requirement, as outlined in the table below, for the REPR and TRED effective October 2012. Included in its September order are immaterial adjustments to deferred fuel and purchase power balances and a requirement to increase the REPR rate to include prospective customer incentives associated primarily with its solar rebate programs.
SPPC 2012 EEIR, EEPR Rate Filings
Subsequent to filing SPPC’s DEAA, TRED, and REPR rate filings in March 2012, the PUCN issued a final order in SPPC’s Annual Demand Side Management Update Report, requiring SPPC to revise all lighting-specific calculations used in the EEIR and EEPR rate applications. As a result, the parties agreed to bifurcate the EEIR and EEPR portions of the March filing to allow SPPC to amend the EEIR and EEPR rate requests using revised lighting-specific calculations and to hold a separate hearing on these components. In July 2012, SPPC filed an amended EEIR and EEPR rate request. In December 2012, the PUCN issued its final order which resulted in a decrease in revenue requirement for EEIR and EEPR, as outlined in the table below.
The PUCN approvals of the 2012 DEAA, TRED, REPR, EEIR and EEPR filings include the following (dollars in millions):
SPPC 2012 Nevada Gas DEAA
In March 2012, SPPC filed an application for the PUCN to review the physical gas, transportation and financial gas transactions that were recorded during the 12-month period ending December 31, 2011 and to reset the REPR. In September 2012, the PUCN issued its final order which resulted in an overall increase of $0.2 million that was effective October 1, 2012.
SPPC 2011 Electric DEAA, TRED, REPR, EEIR, EEPR Rate Filings
In March 2011, SPPC filed an application to establish a new DEAA to refund over-collected purchased power and fuel costs and reset or establish several other rate elements (TRED, REPR, EEIR and EEPR). In September 2011, the PUCN accepted stipulations which resulted in an overall decrease in revenue requirement of approximately $8.2 million. The PUCN authorized refund and recovery of the following amounts (dollars in millions):
SPPC 2011 Nevada Gas DEAA
In March 2011, SPPC filed an application to create a new DEAA rate to refund over-collected gas costs and to establish a new STPR (Solar Thermal Prospective Rate) to recover a legislatively mandated solar thermal program. In September 2011, the PUCN accepted stipulations which resulted in an overall decrease in revenue requirement of $12.1 million that was effective October 1, 2011.
SPPC 2010 Nevada Gas DEAA
In March 2010, SPPC filed an application to create a new DEAA rate. In September, the PUCN accepted a stipulation to decrease rates by $8.3 million, a decrease of 4.69%, while refunding approximately $17 million of deferred gas costs. The new DEAA rate became effective October 1, 2010.
SPPC 2010 Nevada Electric DEAA
In March 2010, SPPC filed an application to create a new DEAA rate. In September, the PUCN accepted a stipulation to decrease rates by $47.0 million, a decrease of 6.31%, while refunding $101 million of deferred fuel and purchased power costs. The new DEAA rate became effective October 1, 2010.
SPPC 2010 Electric GRC
In June 2010, SPPC filed its statutorily required GRC for its Nevada electric operations and further updated the filing in July and August 2010. The filing, as updated, requested an ROE of 10.75% and ROR of 8.14% and an increase to general revenues of $29.3 million.
The PUCN issued its order in December 2010, which resulted in the following significant items:
• Increase in general rates by $13.1 million, approximately a 1.90% increase effective January 1, 2011;
• ROE and ROR of 10.10% and 7.86%, respectively;
• Authorized to recover new electric and common plant additions along with ordinary changes in operating expense, maintenance expense and administrative and general costs; and
• Ordered to file a separate application concurrent with the filing of NPC’s GRC to determine the reasonableness of the EEC project development costs and propose reclassification of these costs from a deferred debit to a regulatory asset. Reference NPC’s 2011 GRC above for further discussion.
SPPC 2010 Gas GRC
In June 2010, SPPC filed a GRC for its gas operations and further updated the filing in July and August 2010. The filing, as updated, requested an ROE of 10.75% and ROR of 5.48% and an increase to general revenues of $4.3 million.
The PUCN issued its order in December 2010, which resulted in the following significant items:
• Increase in general rates by $2.7 million, approximately a 1.93% increase effective January 1, 2011;
• ROE and ROR of 10.00% and 5.15%, respectively; and
• Authorized to recover new gas and common plant additions along with ordinary changes in operating expense, maintenance expense and administrative and general costs.
NPC and SPPC
Energy Efficiency Implementation Rate (EEIR) and Energy Efficiency Program Rate (EEPR)
EEIR
In 2009, the Legislature passed Senate Bill 358, which required the PUCN to adopt regulations authorizing an electric utility to recover lost revenue that is attributable to the measurable and verifiable effects associated with the implementation of efficiency and conservation programs approved by the PUCN. As a result, the PUCN opened Docket No. 09-07016 to amend and adopt the regulation. The regulation was adopted by the Legislature on July 22, 2010. Accordingly, as of August 1, 2010, the Utilities began recording the amount of additional revenues which are objectively determinable and probable of recovery and are attributable to reduced kWh sales related to energy efficiency programs, prior to their inclusion in rates in accordance with FASC 980-605-25, Alternative Revenue Programs.
In October 2010, the Utilities filed to set 2011 base rates effective mid-2011 to recover approximately $35.1 million and $7.6 million for NPC and SPPC, respectively, for estimated reduced kWh sales related to the Utilities’ energy efficiency programs. Annually, thereafter, the Utilities file in March, to adjust rates and set a clearing rate or EEIR for over or under collected balances, effective in October of the same year. In May 2011, the PUCN issued a final order on the October 2010 filing authorizing increases to the base rates of $14.5 million and $2.6 million for NPC and SPPC, respectively, effective July 1, 2011. As a result of the May order, in June 2011, NPC and SPPC recorded a pre-tax adjustment to earnings for revenue previously recorded of approximately $4.5 million and $4.1 million, respectively. As of December 31, 2011, NPC and SPPC recognized 2011 revenues of approximately $15.5 million and $2.5 million, respectively, of the authorized EEIR base amounts.
In March 2011 and 2012, the Utilities filed applications with their annual DEAA filings to reset the base rates and clear the accumulated regulatory asset accounts between January 1 and December 31, 2010 and 2011, respectively, with rates effective October 2011 and January 2013, respectively. Reference further discussion above at NPC and SPPC DEAA, TRED, REPR, EEIR, EEPR Rate Filings.
EEPR
In addition, the regulation approved the transition of the recovery of energy efficiency program costs from general rates (filed every 3 years) to recovery through independent annual rate filings. Accordingly, in their filing made in October 2010, the Utilities requested to set base rates beginning mid-2011 to recover the 2011 costs of implementing energy efficiency program costs of approximately $71.0 million and $12.1 million for NPC and SPPC, respectively. In May 2011, the PUCN issued a final order authorizing increases to the base rates of $58.4 million and $9.7 million for NPC and SPPC, respectively, effective July 1, 2011. As of December 31, 2011, NPC and SPPC recorded $37.3 million and $6.2 million respectively, of EEPR revenues. Costs accumulated between January 1 and December 31, 2010 and 2011, respectively, were requested for recovery in the March 2011 and 2012 filings with rates effective October 2011 and January 2013, respectively. Reference further discussion above at NPC and SPPC DEAA, TRED, REPR, EEIR, EEPR Rate Filings.
Ely Energy Center
In February 2011, NVE and the Utilities cancelled plans to construct the EEC due to increasing environmental and economic uncertainties. In June 2009, the Utilities filed to withdraw the initial construction application under the Utility Environmental Protection Act (UEPA) filed in 2006 due to postponing the construction of the EEC. The PUCN had previously approved the Utilities spending on development costs and farming assets for the EEC up to $130 million, of which the Utilities had spent and recorded as an other deferred asset approximately $58.0 million as of December 31, 2011. In compliance with the SPPC 2010 Electric GRC, SPPC
filed a separate application concurrent with the filing of NPC’s GRC filed in June 2011, to determine the reasonableness of the EEC project development costs and farming assets and proposed reclassification of these costs from a deferred debit to a regulatory asset. In December 2011, the PUCN authorized recovery of approximately $23.2 million of the development costs for NPC and reclassification of $23.1 million of farming assets to a regulatory asset for NPC. The PUCN also authorized SPPC to reclassify approximately $11.6 million of development costs and farming assets to regulatory asset accounts. In accordance with NPC’s December 2011 GRC order, farming assets on NPC and SPPC are subject to prudence review in a subsequent filing to the PUCN.
FERC Matters
California Wholesale Spot Market Refunds
NPC and SPPC were participants in a FERC proceeding wherein California parties have been authorized to recalculate, or mitigate, the prices they paid for wholesale spot market power between October 2, 2000 and June 20, 2001. Both of the Utilities made spot market sales that were eligible for mitigation. NPC and SPPC have negotiated a comprehensive settlement with the California parties and a FERC order on the joint offer of settlement was approved in February 2012.
NPC
At the time of the settlement the CAISO and CALPX owed NPC approximately $19 million (plus interest) for power delivered during the same timeframe, but which was being held pending resolution of the FERC proceedings, and for which NPC had fully reserved in 2001. As a part of the settlement, NPC released these receivables to the California parties which resulted in reversal of the accounts receivable reserve as of December 31, 2011.
SPPC
At the time of the settlement the CAISO and CALPX owed SPPC approximately $1 million (plus interest) for power delivered during the same timeframe, but which was being held pending resolution of the FERC proceedings, and SPPC had recorded a reserve against the receivable in 2001. As a part of the settlement, SPPC released these receivables to the California parties which resulted in reversal of the accounts receivable reserve as of December 31, 2011.
In 2009, SPPC recorded an additional $3 million liability for this item.
Settlement
As a result of the February 2012 FERC order, NPC and SPPC released to the California parties, NPC and SPPC’s claims to the receivables held by the CALPX and CAISO, plus interest therein, and, paid an immaterial cash amount.
NPC
NPC 2012 FERC Transmission Rate Case
In October 2012, NPC filed an application with the FERC to reset transmission and ancillary service rates that were last set in 2003. The rate changes requested in this filing would result in an overall annual revenue increase of $11.3 million. In December 2012, FERC issued an order which suspended certain rate increases until June 1, 2013 and accepted two proposed rate decreases effective January 1, 2013. All rates are subject to final approval by FERC in 2013.
SPPC
SPPC 2012 FERC Transmission Rate Case
In October 2012, SPPC filed an application with the FERC to reset transmission and ancillary service rates that were last set in 2007 and 2003, respectively. The rate changes requested in this filing would result in an overall annual revenue increase of $3.2 million. In December 2012, FERC issued an order which suspended certain rate increases until June 1, 2013 and accepted two proposed rate decreases effective January 1, 2013. All rates are subject to final approval by FERC in 2013.
NOTE 4. INVESTMENTS IN SUBSIDIARIES AND OTHER PROPERTY
Investments in subsidiaries and other property consisted of the following as of December 31 (dollars in thousands):
(1) Rabbi Trust assets represent non-qualified deferred compensation and certain defined benefit plans, which consist of actively traded money market and equity funds with quoted prices in active markets which are considered level 1 in the fair value hierarchy. The balance also includes life insurance policies, which are recorded at the cash surrender value of $19.9 million and $13.5 million at December 31, 2012 and 2011, respectively.
NOTE 5. JOINTLY OWNED FACILITIES
At December 31, 2012 and 2011, NPC and SPPC owned the following undivided interests in jointly owned electric utility facilities (dollars in thousands):
The amounts for Navajo Generating Station include NPC’s share of transmission systems, general plant equipment and NPC’s share of the jointly owned railroad which delivers coal to the plant. Each participant provides its own financing for all these jointly owned facilities. NPC’s share of the operating expenses for these facilities is included in the corresponding operating expenses in its consolidated income statements.
Reid Gardner Generating Station Unit No. 4 is owned by the CDWR (67.8%) and Nevada Power Company (32.2%). Nevada power is operating agent. Contractually, NPC is entitled to receive 25 MW of base load capacity and 232 MW of peaking capacity, subject to certain operating limitations. NPC's share of the operating expenses for this facility is included in the corresponding operating expenses in its consolidated income statements. In June 2013, NPC will be required to pay CDWR a termination payment. After such payment is made, NPC will be 100% owner of Unit No. 4 and assume 100% of all operating and maintenance costs of the Unit.
NPC is the operator of the Silverhawk Generating Station, which is jointly owned with SNWA. NPC’s owns 75% and its share of direct operation and maintenance expenses is included in its accompanying consolidated income statements.
SPPC and Idaho Power Company each own an undivided 50% interest in the Valmy Generating Station, with each company being responsible for financing its share of capital and operating costs. SPPC is the operating agent of the plant for both parties. SPPC’s share of direct operation and maintenance expenses for the Valmy Generating Station are in included in its accompanying consolidated income statements.
NOTE 6. LONG-TERM DEBT
NVE’s, NPC’s and SPPC’s long-term debt consists of the following as of December 31 (dollars in thousands):
Maturities of Long-Term Debt
As of December 31, 2012, NPC’s, SPPC’s and NVE’s aggregate annual amount of maturities for long-term debt (including obligations related to capital leases) for the next five years and thereafter are shown below (dollars in thousands):
(1) Amounts may differ from current portion of long-term debt as reported on the consolidated balance sheet due to the timing difference of payments and the change in obligation.
Substantially all utility plant is subject to the liens of NPC’s and SPPC’s indentures under which their respective General and Refunding Mortgage bonds are issued.
Lease Commitments
•
In 1984, NPC entered into a 30-year capital lease for its Pearson Building with (5) five-year renewal options beginning in year 2015. In February 2010, NPC amended this capital lease agreement to include the lease of the adjoining parking lot and to exercise, three of the five-year renewal options beginning in year 2015. There remain two additional renewal options which could extend the lease an additional ten years.
•
In 2007, NPC entered into a 20-year lease, with three 10-year renewal options, to occupy land and building for its Beltway Complex, and operations center in southern Nevada. As required by the Lease Topic of the FASC, NPC accounts for the building portion of the lease as a capital lease and the land portion of the lease as an operating lease. NPC transferred operations to the facilities in June 2009.
•
The Utilities have Master leasing agreements of which various pieces of equipment qualify as capital leases. The remaining equipment is treated as operating leases. Lease terms average seven years under the master lease agreement.
Future cash payments for these capital leases, combined, as of December 31, 2012, were as follows (dollars in thousands):
Financing Transactions
NVE
$195 Million Term Loan Agreement
In October 2011, NVE entered into a $195 million 3-year term loan agreement (Term Loan). The Term Loan is an unsecured, single-draw loan that is due on October 7, 2014. The borrowing under the Term Loan bears interest at the LIBOR rate plus a margin. The current LIBOR margin rate is 2.00%. The margin varies based upon NVE’s long-term unsecured debt credit rating by S&P and Moody’s. However, NVE entered into a floating- for- fixed interest rate swap agreement to lock in an effective interest rate of 2.81% for the length of the Term Loan.
The Term Loan contains conditions of borrowing, events of default, and affirmative and negative covenants. The Term Loan includes (i) a financial covenant to maintain a ratio of total consolidated indebtedness to total consolidated capitalization, determined on the last day of each fiscal quarter, not to exceed 0.70 to 1.00 and (ii) a fixed charge covenant that requires NVE not to permit the fixed charge coverage ratio, determined on the last day of each fiscal quarter, to be less than 1.50 to 1.00.
Redemption of 6.75% Senior Notes
In November 2011, NVE used the proceeds of the Term Loan, plus cash on hand, to redeem its unsecured $191.5 million 6.75% Senior Notes (“Senior Notes”). The notes were redeemed at 102.25% of the stated principal amount plus accrued interest to the date of redemption. With this redemption, NVE and the Utilities are no longer subject to the restrictive covenants contained in the Senior Notes, which were more restrictive then the covenants described above for the Term Loan.
NPC
5.45% General and Refunding Mortgage Notes, Series Y
In May 2011, NPC issued and sold $250 million of its 5.45% General and Refunding Mortgage Notes, Series Y, due May 15, 2041. The approximately $248 million in net proceeds, plus a portion of the proceeds from a draw on NPC’s revolving credit facility, were utilized to pay at maturity NPC’s $350 million aggregate principal amount of 8.25% General and Refunding Mortgage Notes, Series A, which matured on June 1, 2011. In conjunction with this debt issuance, NPC entered into an interest rate swap hedging agreement with a notional principal amount of $250 million and a mandatory termination date of June 1, 2011. The interest rate swap agreement was entered into to effectively lock the interest rate of the U.S. Treasury component of the prospective General and Refunding Note issuance. The swap transaction was settled on May 9, 2011, when NPC launched and priced the Series Y Notes, resulting in a settlement payment amount of $14.9 million, which was recorded as a cost to issue in a deferred debit and will be amortized over the 30 year life of the Series Y Notes in accordance with past accounting precedent for our regulated Utilities.
General and Refunding Mortgage Notes, Series I
In April 2012, NPC used $120 million from its revolving credit facility along with $10 million cash on hand to pay for the maturity of its 6.5% General and Refunding Mortgage Notes, Series I, in an aggregate principal amount of $130 million.
$500 Million Revolving Credit Facility
In March 2012, NPC terminated its $600 million secured revolving credit facility which would have expired in April 2013 and replaced it with a $500 million secured revolving credit facility, for which borrowings mature in 2017. The fees on the $500 million revolving credit facility for the unused portion and on the amounts borrowed have decreased from the prior facility reflecting current market conditions. The Administrative Agent for the facility remains Wells Fargo Bank, N.A., and amounts due under the NPC Credit Agreement are collateralized by NPC’s general and refunding mortgage bonds.
The rate for outstanding loans under the revolving credit facility will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus 0.5% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin. The margin varies based upon NPC’s credit rating by S&P and Moody’s. Currently, NPC’s applicable base rate margin is 0.25% and the LIBOR rate margin is 1.25 %. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.
The $500 million revolving credit facility contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates. The reduction
in availability limits the amount that NPC can borrow or use for letters of credit and would require that NPC prepay any amount in excess of that limitation. The amount of the reduction is calculated by NPC on a monthly basis, and after calculating such reduction, the NPC Credit Agreement provides that the reduction in availability under the revolving credit facility to NPC shall in no event exceed 50% of the total commitments then in effect under the revolving credit facility. Currently, there are no negative mark-to-market exposures that would impact borrowings.
The NPC Credit Agreement contains one financial maintenance covenant that requires NPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. In the event that NPC did not meet the financial maintenance covenant or there is a different event of default, the NPC Credit Agreement would restrict dividends to NVE. Moreover, so long as NPC’s senior secured debt remains rated investment grade by S&P and Moody’s (in each case, with a stable or better outlook), a representation concerning no material adverse change in NPC’s business, assets, property or financial condition would not be a condition to the availability of credit under the facility. In the event that NPC’s senior secured debt rating were rated below investment grade by either S&P or Moody’s, or investment grade by either S&P or Moody’s but with a negative outlook, a representation concerning no material adverse change in NPC’s business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility.
The NPC Credit Agreement provides for an event of default if there is a failure under NPC’s other financing agreements to meet certain payment terms or to observe other covenants that would result in an acceleration of payments due.
The NPC Credit Agreement places certain restrictions on debt incurrence, liens and dividends. These restrictions are discussed in Note 8, Debt Covenant and Other Restrictions.
SPPC
$250 Million Revolving Credit Facility
In March 2012, SPPC terminated its $250 million secured revolving credit facility which would have expired in April 2013 and replaced it with a $250 million secured revolving credit facility, for which borrowings mature in 2017. The fees on the $250 million revolving credit facility for the unused portion and on the amounts borrowed have decreased from the prior facility reflecting current market conditions. The Administrative Agent for the facility is Wells Fargo, N.A., and amounts due under the SPPC Credit Agreement are collateralized by SPPC’s general and refunding mortgage bonds.
The rate for outstanding loans under the revolving credit facility will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus 0.5% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin. The margin varies based upon SPPC’s credit rating by S&P and Moody’s. Currently, SPPC’s applicable base rate margin is 0.25%% and the LIBOR rate margin is 1.25%. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.
The $250 million revolving credit facility contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates. The reduction in availability limits the amount that SPPC can borrow or use for letters of credit and would require that SPPC prepay any amount in excess of that limitation. The amount of the reduction is calculated by SPPC on a monthly basis, and after calculating such reduction, the SPPC Credit Agreement provides that the reduction in availability under the revolving credit facility to SPPC shall in no event exceed 50% of the total commitments then in effect under the revolving credit facility. Currently, there are no negative mark-to-market exposures that would impact borrowings.
The SPPC Credit Agreement contains one financial maintenance covenant that requires SPPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. In the event that SPPC did not meet the financial maintenance covenant or there is a different event of default, the SPPC Credit Agreement would restrict dividends to NVE. Moreover, so long as SPPC’s senior secured debt remains rated investment grade by S&P and Moody’s (in each case, with a stable or better outlook), a representation concerning no material adverse change in SPPC’s business, assets, property or financial condition would not be a condition to the availability of credit under the facility. In the event that SPPC’s senior secured debt rating were rated below investment grade by either S&P or Moody’s, or investment grade by either S&P or Moody’s but with a negative outlook, a representation concerning no material adverse change in SPPC’s business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility.
The SPPC Credit Agreement provides for an event of default if there is a failure under SPPC’s other financing agreements to meet certain payment terms or to observe other covenants that would result in an acceleration of payments due.
The SPPC Credit Agreement places certain restrictions on debt incurrence, liens and dividends. These limitations are discussed in Note 8, Debt Covenant and Other Restrictions.
NOTE 7. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amount of cash and cash equivalents, current assets, accounts receivable, accounts payable and current liabilities approximate fair value due to the short-term nature of these instruments. As reported in Note 4, Investments in Subsidiaries & Other Property, investments held in Rabbi Trust and cash surrender value of life insurance policies continue to be considered Level 1 and Level 2, respectively, in the fair value hierarchy.
The total fair value of NVE’s consolidated long-term debt at December 31, 2012, is estimated to be $5.9 billion based on quoted market prices for the same or similar issues or on the current rates offered to NVE for debt of the same remaining maturities. The total fair value was estimated to be $6.0 billion as of December 31, 2011.
The total fair value of NPC’s consolidated long-term debt at December 31, 2012, is estimated to be $4.1 billion based on quoted market prices for the same or similar issues or on the current rates offered to NPC for debt of the same remaining maturities. The total fair value was estimated to be $4.1 billion at December 31, 2011.
The total fair value of SPPC’s consolidated long-term debt at December 31, 2012, is estimated to be $1.3 billion based on quoted market prices for the same or similar issues or on the current rates offered to SPPC for debt of the same remaining maturities. The total fair value was estimated to be $1.3 billion as of December 31, 2011.
NOTE 8. DEBT COVENANT AND OTHER RESTRICTIONS
Dividends from Subsidiaries
Since NVE is a holding company, substantially all of its cash flow is provided by dividends paid to NVE by NPC and SPPC on their common stock, all of which is owned by NVE. In 2012, NPC and SPPC paid $184.0 million and $20.0 million in dividends, respectively, to NVE.
On February 7, 2013, NPC declared dividends to NVE of $50 million to NVE.
Limits on Restricted Payments
NVE
Dividends are considered periodically by NVE’s BOD and are subject to factors that ordinarily affect dividend policy, such as current and prospective earnings, current and prospective business conditions, regulatory factors, NVE’s financial conditions and other matters within the discretion of the BOD, as well as dividend restrictions set forth in NVE’s debt. The BOD will continue to review the factors described above on a periodic basis to determine if and when it is prudent to declare a dividend on NVE’s Common Stock. There is no guarantee that dividends will be paid in the future, or that, if paid; the dividends will be paid at the same amount or with the same frequency as in the past. In February 2012, NVE declared a cash dividend of $0.13 per share and for each of May, August and November of 2012, NVE declared a cash dividend of $0.17 per share. In February, 2013, NVE declared a cash dividend of $0.19 per share for common stock holders of record as of March 2013.
Dividend Restrictions Applicable to the Utilities
Since NVE is a holding company, substantially all of its cash flow is provided by dividends paid to NVE by NPC and SPPC on their common stock, all of which is owned by NVE. Since NPC and SPPC are public utilities, they are subject to regulation by the PUCN, which may impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay. While the PUCN has in the past imposed a dividend restriction with respect to NPC and SPPC, as of December 31, 2012, there were no dividend restrictions imposed on the Utilities by the PUCN.
In addition, certain agreements entered into by the Utilities set restrictions on the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid. As a result of the Utilities’ credit rating on their senior secured debt being rated investment grade by S&P and Moody’s, these restrictions are suspended and no longer in effect so long as such debt remains investment grade by both rating agencies. In addition to the restrictions imposed by specific agreements, the Federal Power Act prohibits the payment of dividends from “capital accounts.” Although the meaning of this provision is unclear,
the Utilities believe that the Federal Power Act restriction, as applied to their particular circumstances, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts. If, however, the FERC were to interpret this provision differently, the ability of the Utilities to pay dividends to NVE could be jeopardized.
Ability to Issue Debt
NVE
Certain debt of NVE contain conditions of borrowing, events of default, and affirmative and negative covenants. The most restrictive of which is the Term Loan, which includes (i) a financial covenant to maintain a ratio of total consolidated indebtedness to total consolidated capitalization, determined on the last day of each fiscal quarter, not to exceed 0.70 to 1.00 and (ii) a fixed charge covenant that requires NVE not to permit the fixed charge coverage ratio, determined on the last day of each fiscal quarter, to be less than 1.50 to 1.00.
Under these covenant restrictions, as of December 31, 2012, NVE (consolidated) would be allowed to incur up to $3.3 billion of additional indebtedness, which includes the use of the Utilities revolving credit facilities. The amount of additional indebtedness allowed would likely be impacted if there is a change in current market conditions or material change in our financial condition.
NPC
NPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and revolving credit facility agreements, and the terms of NVE’s Term Loan. As of December 31, 2012, the most restrictive of the factors below is the PUCN authority. As such, NPC may issue up to $725 million in long-term debt, in addition to the use of its existing credit facilities. However, depending on NVE’s or SPPC’s issuance of long-term debt or the use of the Utilities’ revolving credit facilities, the PUCN authority may not remain the most restrictive factor. The factors affecting NPC’s ability to issue debt are further detailed below:
a. Financing authority from the PUCN - As of December 31, 2012, NPC has financing authority from the PUCN for the period ending December 31, 2013, consisting of authority: (1) to issue additional long-term debt securities of up to $725 million; (2) to refinance up to approximately $322.5 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $1.3 billion.
b. Financial covenants within NPC’s financing agreements - Under its $500 million revolving credit facility, NPC must maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. Based on December 31, 2012 financial statements, NPC was in compliance with this covenant and could incur up to $2.9 billion of additional indebtedness.
All other financial covenants contained in NPC’s financing agreements are currently suspended; as NPC’s senior secured debt is rated investment grade. However, if NPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, NPC would again be subject to the limitations under these additional covenants; and
c. Financial covenants within NVE’s Term Loan - As discussed in NVE’s Ability to Issue Debt, NPC is also subject to NVE’s cap on additional consolidated indebtedness of $3.3 billion.
Ability to Issue General and Refunding Mortgage Securities
To the extent that NPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, NPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under NPC’s Indenture.
NPC’s Indenture creates a lien on substantially all of NPC’s properties in Nevada. As of December 31, 2012, $3.8 billion of NPC’s General and Refunding Mortgage Securities were outstanding. NPC had the capacity to issue $1.6 billion of additional General and Refunding Mortgage Securities as of December 31, 2012. That amount is determined on the basis of:
1. 70% of net utility property additions; and/or
2. The principal amount of retired General and Refunding Mortgage Securities.
Property additions include plant-in-service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.
NPC also has the ability to release property from the lien of NPC’s Indenture on the basis of net property additions, cash and/or retired bonds. To the extent NPC releases property from the lien of NPC’s Indenture, it will reduce the amount of securities issuable under the Indenture.
SPPC
SPPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and its revolving credit facility agreement, and the terms of NVE’s Term Loan. As of December 31, 2012, the most restrictive of the factors below is the PUCN authority. Based on this restriction, SPPC may issue up to $350 million of long-term debt securities, and maintain a credit facility of up to $600 million. However, depending on NVE’s or NPC’s issuance of long-term debt or the use of the Utilities’ revolving credit facilities, the PUCN authority may not remain the most restrictive factor. The factors affecting SPPC’s ability to issue debt are further detailed below:
a. Financing authority from the PUCN - As of December 31, 2012, SPPC has financing authority from the PUCN for the period ending December 31, 2015, consisting of authority (1) to issue additional long-term debt securities of up to $350 million; (2) to refinance approximately $348 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $600 million.
b. Financial covenants within SPPC’s financing agreements - Under SPPC’s $250 million revolving credit facility, the Utility must maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. Based on December 31, 2012 financial statements, SPPC was in compliance with this covenant and could incur up to $1.0 billion of additional indebtedness.
All other financial covenants contained in SPPC’s financing agreements are currently suspended; as SPPC’s senior secured debt is rated investment grade. However, if SPPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, SPPC would again be subject to the limitations under these additional covenants.
c. Financial covenants within NVE’s Term Loan - As discussed in NVE’s Ability to Issue Debt, SPPC is also subject to NVE’s cap on additional consolidated indebtedness of $3.3 billion.
Ability to Issue General and Refunding Mortgage Securities
To the extent that SPPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, SPPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under SPPC’s Indenture.
SPPC’s Indenture creates a lien on substantially all of SPPC’s properties in Nevada. As of December 31, 2012, $1.5 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. SPPC had the capacity to issue $824 million of additional General and Refunding Mortgage Securities as of December 31, 2012. That amount is determined on the basis of:
1. 70% of net utility property additions; and/or
2. The principal amount of retired General and Refunding Mortgage Securities.
Property additions include plant in service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.
SPPC also has the ability to release property from the lien of SPPC’s Indenture on the basis of net property additions, cash and/or retired bonds. To the extent SPPC releases property from the lien of SPPC’s Indenture, it will reduce the amount of securities issuable under the Indenture.
NOTE 9. INCOME TAXES (BENEFITS)
The following reflects the composition of taxes on income from continuing operations for the years ended December 31 (dollars in millions):
A reconciliation between income tax expense and the expected tax expense at the federal statutory rate for the years ended December 31 are as follows (dollars in millions):
The net deferred income tax liability consists of deferred income tax liabilities less related deferred income tax assets as of December 31 (dollars in millions):
For balance sheet presentation, the regulatory tax asset is included in regulatory assets and the regulatory tax liability is included in regulatory liabilities. The regulatory tax asset balance consists of future revenue to be received from customers due to flow-through of the tax benefits of temporary differences and goodwill recognized from the merger of NPC and NVE. Offset against these amounts are future revenues to be refunded to customers (regulatory tax liabilities). The regulatory tax liability balance consists of temporary differences for liberalized depreciation at rates in excess of current rates and unamortized investment tax credits. The regulatory liability for temporary differences related to liberalized depreciation will continue to be amortized using the average rate assumption method required by the Tax Reform Act of 1986. The regulatory liability for temporary differences caused by the investment tax credit will be amortized ratably similar to the accumulated deferred investment tax credit.
The following tables summarize as of December 31, 2012, the net operating loss and tax credit carryovers and associated carryover periods, and valuation allowance for amounts which NVE and the Utilities have determined that realization is uncertain (dollars in millions):
At December 31, 2012, NVE has a gross Federal NOL carryover of $1.1 billion, NPC of $723.7 million and SPPC of $161.1 million.
Considering all positive and negative evidence regarding the utilization of NVE’s and the Utilities’ deferred tax assets, it has been determined that NVE, NPC and SPPC are more-likely-than-not to realize all recorded deferred tax assets, except the Arizona coal credits on NVE and NPC. As such, these Arizona coal credits represent the only valuation allowance that has been recorded as of December 31, 2012 on NVE and NPC.
Accounting for Uncertainty in Income Taxes
Under Accounting for Uncertainty in Income Taxes, as reflected in the FASC, uncertain tax liabilities are all long-term and are included in the “other deferred credits and liabilities” line item on the balance sheet.
A summary of unrecognized tax benefits as of December 31 are as follows (dollars in millions):
A reconciliation of the beginning and ending amount of unrecognized tax benefits as of December 31 are as follows (dollars in millions):
On September 15, 2012, NVE and the Utilities filed a Form 3115, Application for Change in Accounting Method, with the IRS requesting a change in method of accounting for routine repair and maintenance costs deductible under §162 to use the Transmission and Distribution Property Safe Harbor Method of Accounting as required by Rev. Proc. 2011-43.
NVE and the Utilities classify interest and penalties related to income taxes as interest and other expense, respectively. NVE and the Utilities have not accrued interest or penalties as of December 31, 2012, December 31, 2011 and December 31, 2010. NVE and the Utilities do not expect unrecognized tax benefits to change within the next twelve months.
NVE and its subsidiaries file a consolidated federal income tax return. Current income taxes are allocated based on NVE’s and each subsidiaries’ respective taxable income or loss and tax credits as if each subsidiary filed a separate return. The U.S. federal jurisdiction is the only “significant” tax jurisdiction for NVE. In July 2012, the IRS concluded their examination of NVE with respect to its Federal income tax returns for December 31, 2005 through December 31, 2008. The audit is currently under review by the Joint Committee on Taxation. As of December 31, 2012, NVE is no longer subject to examinations by U.S. federal, state, or local tax authorities for years before 2008, with a few exceptions.
NOTE 10. RETIREMENT PLAN AND POSTRETIREMENT BENEFITS
NVE has a single employer defined benefit pension plan covering substantially all employees of NVE and the Utilities. NVE allocates the unfunded liability and the net periodic benefit costs for its pension benefit and other postretirement benefit plans to NPC and SPPC based upon the current, or in the case of the retirees, previous, employment location. Certain grandfathered and union employees are covered under a benefit formula based on years of service and the employee's highest compensation for a period prior to retirement, while most employees are covered under a cash balance formula with vesting after three years of service. NVE also has other postretirement plans, including a defined contribution plan which provides medical and life insurance benefits for certain retired employees.
Plan Changes
In 2012, NVE offered a voluntary lump sum pension payout to former employees not currently of retirement age but eligible for future benefits and certain retiree participants already receiving benefits under NVE’s pension plan in an effort to reduce NVE’s future pension obligation. The 2012 payouts, as indicated in the benefits obligations table below, increased benefits paid by approximately $28.9 million. Of the offers still outstanding at December 31, 2012, NVE expects to payout an additional lump sum of approximately $15.6 million from the pension assets during 2013.
During 2011, the sale of California Assets, as discussed in detail in Note 15, Assets Held for Sale, resulted in employees being transferred to CalPeco. Certain employees who did not want to transfer, and who could not obtain comparable positions with NVE, had their service periods bridged to retirement age under the terms of the collective bargaining agreement with IBEW 1245. Amounts recorded for this event were not material.
NVE also has a non-qualified Supplemental Executive Retirement Plan and a Restoration Plan for executives. NVE contributed $26.5 million to establish a rabbi trust for these plans in 2009. See Note 4, Investments in Subsidiaries and Other Property, for details regarding the trust assets. NVE’s obligation under these supplemental and restoration plans is included in “Accrued retirement benefits” in NVE’s consolidated balance sheet, and amounted to $36.1 million at December 31, 2012. NVE is not required to make contributions to the plans.
Plan Obligations, Plan Assets and Funded Status
The following tables provide a reconciliation of benefit obligations, plan assets and the funded status of the plans. These reconciliations are based on a December 31 measurement date (dollars in thousands):
(1) The 2011 difference between benefits paid in the table of changes in pension obligations and the table of changes in plan assets, is due to a difference in benefit payments recognized by the pension actuary from the actual benefit payments made by the trustee bank in order to facilitate timely benefit payments to participants.
(2) Amounts recognized as non-current liabilities (accrued retirement benefits) in the consolidated balance sheets as of December 31, 2012 and 2011.
The expected long-term rate of return for both the pension and other postretirement benefit plan assets is 6.15% and 6.75%, and 6.15-7.10% and 6.75-7.10%, respectively, in 2012 and 2011, respectively.
The following amounts would have been recognized in Accumulated Other Comprehensive Income, net of taxes, according to the provisions of the Compensation Retirement Benefits Topic of the FASC. Since NVE is able to recover expenses through rates, the amounts noted below will be recorded as Regulatory Assets for pension plans under the provisions of the Regulated Operations Topic of the FASC. Amounts recognized as of December 31, consist of (dollars in thousands):
The estimated amounts that will be amortized from the regulatory assets for pension plans and accumulated other comprehensive income into net periodic cost in 2013 are as follows (dollars in thousands):
As of December 31, 2012 and 2011, the projected benefit obligation, accumulated benefit obligation, and fair value of plan net assets for pension plans with a projected benefit obligation in excess of plan net assets, and pension plans with an accumulated benefit obligation in excess of plan assets, were as follows (dollars in thousands):
Plan Assets
NVE’s investment strategy is to ensure the safety of the principal of the assets and obtain asset performance to meet the continuing obligations of the plan. NVE contributed a total of $22.1 million and $40.6 million in 2012 and 2011, respectively, towards the qualified pension and other postretirement benefit plans.
NVE strives to maintain a reasonable and prudent amount of risk, and seeks to limit risk through diversification of assets. Also, NVE considers the ability of the plan to pay all benefit and expense obligations when due, and to control the costs of administering and managing the plan.
NVE’s long term strategy for the pension plan assets is to maximize risk adjusted returns while maintaining adequate liquidity to pay plan benefits. NVE is committed to prudent investments with ample diversification in terms of asset types, fund strategies, and investment managers. As such, NVE has elected to include an appropriate mix of indexed and actively managed investments to accomplish its strategy. The allocation for pension plan net assets at December 31, 2012 is 61% fixed income, 26% U.S. equity, 7% international equity and 6% cash. The allocation for pension plan net assets at December 31, 2011 is 61% fixed income, 19% U.S. equity, 14% international equity, 5% cash and 1% other. The long-term target allocation for pension plan net assets is 65% fixed income, 20% U.S. equity, and 15% international equity. The fixed income investments are benchmarked against government and corporate credit bond indices. U.S. equity investments include large cap, mid-cap, and small-cap companies with an emphasis towards small and mid-cap investments relative to the Russell 3000 Index. International equity is currently actively managed and includes investments in both established and emerging markets.
The allocation for the other postretirement benefit plan net assets at December 31, 2012 is 49% equity securities, 48% fixed income and 3% cash. The allocation for other postretirement benefit plan net assets at December 31, 2011 is 51% equity securities, 46% fixed income and 3% cash. The long-term strategy for the other postretirement benefit plan net assets is similar to the pension plan net assets strategy as described above. The target allocation for other postretirement benefit assets is 60% equity and 40% fixed income. The equity is invested in indexed securities that track the S&P 500 Index. The fixed income is indexed and benchmarked against government and corporate credit bond indices.
The fair values of NVE’s pension plan and other postretirement benefits assets at December 31, 2012 and 2011, within the fair value hierarchy as required by the Fair Value Measurements and Disclosures Topic of the FASC, by asset category are as follows (dollars in thousands):
(1) Cash and cash equivalents consist of investment in commingled funds that are primarily comprised of money market holdings and marketable securities, U.S. Treasury bills and commercial paper valued and redeemable at cost.
(2) This category includes approximately 27% small and mid-cap and 73% broad market domestic equity investments.
(3) This category includes approximately 26% small and mid-cap and 74% broad market domestic equity investments.
(4) Level 1 investments are comprised of fixed income securities that primarily invest in U.S. Treasury bonds. Level 2 investments consist of commingled funds that track the Barclays Capital Long Government and Corporate Credit Index and the Barclays Capital Aggregate US Fixed Income Index.
(5) The administrative trust net assets/liabilities are primarily comprised of amounts payable to and from brokers for sold and purchased securities.
The actuarial assumptions used to determine December 31 benefit obligations and net periodic benefit costs were as follows:
The discount rates for 2012 and 2011 related to the benefit obligations were determined by identifying a theoretical settlement portfolio of high quality corporate bonds sufficient to provide for the plans projected benefit payments.
The discount rates for 2012 related to the net periodic benefit costs were determined by identifying a theoretical settlement portfolio of high quality corporate bonds sufficient to provide for the plans projected benefit payments. However, to determine the discount rates for 2011 and 2010 related to the net periodic benefit costs, NVE’s projected benefit payments were matched to the yield curve derived from a portfolio of over 300 high quality Aa bonds with yields within the 10th to 90th percentiles of these bond yields.
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effect:
The expected ROR on plan assets was determined by considering a realistic projection of what assets can earn, given existing capital market conditions, historical equity and bond premiums over inflation, the effect of “normative” economic conditions that may differ from existing conditions, and projected ROR on reinvested assets.
There were no significant transactions between the plan and the employer or related parties during 2012, 2011, or 2010.
Net Periodic Cost
The components of net periodic pension and other postretirement benefit costs for NVE, NPC and SPPC for the years ended December 31, are presented below (dollars in thousands):
The average percentage of NVE net periodic costs capitalized during 2012, 2011 and 2010 was 34.6%, 33.4% and 34.0%, respectively.
The average percentage of NPC net periodic costs capitalized during 2012, 2011 and 2010 was 37.0%, 36.9% and 37.0%, respectively.
The average percentage of SPPC net periodic costs capitalized during 2012, 2011 and 2010 was 35.3%, 31.7% and 34.2%, respectively.
The expected cash flows for the plans, including trust accounts, are as follows (dollars in thousands):
The above benefit payments are obligations of the indicated plan, and reflect payments which do not include employee contributions. The expected benefit payment information that reflects the employee obligation is almost exclusively paid from plan assets. A small portion of the pension benefit obligation is paid from the plan sponsor’s assets.
NOTE 11. STOCK COMPENSATION PLANS
NVE’s executive long-term incentive plan for key management employees, which was approved by shareholders in May 2004 and amended and restated in 2011, provides for the issuance of up to 7,750,000 of NVE’s shares to key employees through December 31, 2013. The plan permits the following types of grants, separately or in combination: nonqualified and qualified stock options, stock appreciation rights, restricted stock units, performance units, performance shares, and bonus stock. During 2012, NVE granted restricted stock units, performance units and performance shares under the long-term incentive plan. The Company also has an employee stock purchase plan which is available to all employees who meet minimum service requirements. The employees can choose to have amounts deducted from their paychecks which will be used to buy NVE’s common stock at a discount. The plans are discussed in more detail below.
Under the long-term incentive plan and employee stock purchase plan, NVE may settle awards by either new issuances of shares, open market purchases, or issuance of treasury shares. See Note 13, Common Stock and Other Paid-In Capital, for further discussion on treasury stock.
Total stock-based compensation expense for the following years was as follows (dollars in thousands):
Non-Qualified Stock Options
Elected officers and key employees specifically designated by a committee of the BOD are eligible to be awarded non-qualified stock options (NQSO’s) based on the guidelines in the plan. These grants are at 100% of the then current fair market value, and vest over different periods as stated in the grant. These options have to be exercised within ten years of award, and no earlier than one year from the date of grant. At the time of grant, rights to dividend equivalents may be awarded; however, historically, dividend equivalents have not been granted. The options may be exercised using either cash or previously acquired shares valued at the current market price, or a combination of both. The Committee also allows cashless exercises, subject to applicable securities law restrictions or other means consistent with the purpose of the plan and the applicable law.
There have been no grants of non-qualified stock options made to employees since 2007.
A summary of the status of NVE’s nonqualified stock option plan as of December 31, 2012, 2011, and 2010, and changes during the year is presented below:
Cash received from options exercised was $1.7 million, $0.8 million and $0.5 million in 2012, 2011 and 2010, respectively. The tax benefit realized for the tax deductions from option exercises was immaterial for all years. The fair value of options vested was zero for all years presented.
The fair value of each nonqualified option has been estimated on the date of grant using the Black-Scholes option pricing model using the following assumptions: Average Dividend Yield, Average Expected Volatility, Average Risk-Free Rate of Return, and Average Expected Life. As of January 1, 2011 all of the nonqualified stock options have been fully vested and expensed.
The following table summarizes information about nonqualified stock options outstanding at December 31, 2012:
Performance Awards
Performance Units
Performance Units vest at the end of a three-year period to the extent that specific stock price related performance targets are met, as determined by the Compensation Committee. If the established objectives are not met, the Performance Units are forfeited. Performance Units are typically paid in shares after vesting. At the time of grant, rights to dividend equivalents may be awarded; however, historically, dividend equivalents have not been granted. These awards do not have any voting rights associated with them. Performance Units granted are measured based on NVE’s TSR relative to the average TSR of companies listed in the S&P Super Composite Electric Utility Index throughout the three-year performance period. The Committee determined that the awards will vest according to the table shown below (a proportionate amount of shares will vest in the case of performance between the percentiles listed below):
Performance
Shares Vested
Below 35th Percentile
0% of grant
35th Percentile
50% of grant
50th Percentile
100% of grant
75th Percentile
150% of grant
Performance Shares
Performance Shares vest at the end of a three-year period, based on average aggregate Corporate Goal performance under the Short Term Incentive Plan (STIP) and the average STIP payout over those three years. If the established objectives are not met, the Performance Shares are forfeited. Performance Shares are paid in shares, minus applicable taxes, based on the then fair market value of the shares. At the time of grant, rights to dividend equivalents may be awarded; however, historically, dividend equivalents have not been granted. Performance shares do not have any voting rights associated with them.
The following table summarizes Performance Units and Performance Shares activity for the following years:
There were no performance units or performance shares issued in 2010.
Compensation expense for performance units and performance shares is recognized ratably over the three year vesting period. In the event the conditional criteria are not met, the awards are forfeited and the expense is reversed. Performance units and performance shares are accounted for as liability awards and compensation costs are measured at each balance sheet date using the Company’s closing stock price for that date. The closing trading price of NVE stock on December 31, 2012 was $18.14.
Restricted Stock Units
Elected officers and key employees specifically designated by a committee of the BOD are eligible to be awarded restricted stock units based on the guidelines in the plan. These grants vest over different periods as stated within the terms of each grant. The issuance of these shares is conditional upon the employee retaining employment with NVE throughout the entire vesting period. Of the 169,000 units granted in 2012, 125,000 are eligible for dividend equivalents over the vesting period.
The following table summarizes Restricted Stock Units activity for the following years:
There were no restricted stock units issued in 2010.
Compensation expense for restricted stock units is recognized ratably over the vesting period of each grant. If employment is terminated prior to the end of the vesting period, the award is forfeited and the expense is reversed. Restricted stock units are accounted for as liability awards and compensation costs are measured at each balance sheet date using the Company’s closing stock price for that date. The closing trading price of NVE stock on December 31, 2012 was $18.14.
Employee Stock Purchase Plan
The employee stock purchase plan is available to all employees who meet minimum service requirements. In 2010, shareholders approved an additional 1,000,000 shares for distribution under the plan, bringing the total authorized up to an aggregate of 1,900,162 shares of common stock. According to the terms of the plan, employees can choose twice each year to have up to 15% of their base earnings withheld to purchase NVE’s common stock. The option price discount is 15%, and the purchase price is the lesser of 85% of the market value on the offering commencement date, or 85% of the market value on the offering exercise date. Employees can withdraw from the plan at any time prior to the exercise date. Under the plan NVE sold 134,069, 134,266 and 147,457 shares to employees in 2012, 2011 and 2010, respectively.
In accordance with the Stock Compensation Topic of the FASC, NVE recognized compensation expense in 2012, 2011 and 2010 related to the employee stock purchase plan. The expense for 2012 was calculated for the employees’ purchase rights based on the stock price at the exercise date. The expense for 2011 and 2010 was estimated for the employees’ purchase rights on the date of grant, using the Black-Scholes option-pricing model. The following assumptions were used for those years, with an option life of six months:
NOTE 12. COMMITMENTS AND CONTINGENCIES
The Utilities enter into several purchase commitments for electric power, coal, natural gas and transportation, as well as, long-term service agreements, capital project commitments and operating leases. Detailed below are estimates of future commitments under these arrangements (dollars in millions):
Purchased Power
The Utilities have several contracts for long-term purchase of electric energy; the expiration of these contracts range from 2013 to 2039. While the Utilities are not required to make payment if power is not delivered under these contracts, estimated future payments are included in the tables above. Related party purchase power agreements have been eliminated from the NVE totals for the year 2013.
Purchased Power - Not Commercially Operable
The Utilities entered into several contracts for long-term purchase of electric energy in which the facility remains under development. This represents the estimated payments under renewable energy power purchase contracts, which have been approved by the PUCN and are contingent upon the developers obtaining commercial operation and their ability to deliver power.
Coal & Natural Gas
The Utilities have several long-term contracts for the purchase of coal and natural gas; the expiration of these contracts range from 2013 to 2019.
Transportation
The Utilities have several long-term contracts for the transport of coal and natural gas. Also included in the transportation obligations is the TUA with GBT, of which NPC will be responsible for 95% and SPPC 5%. The TUA remains contingent upon final construction costs, and reaching commercial operation. The expiration of these transportation contracts range from 2013 to 2054.
Long-Term Service Agreements
The Utilities have long term service agreements for the performance of maintenance on generation units. Obligation amounts are based on estimated usage.
Capital Projects
Capital projects at NPC includes NPC’s requirement to purchase the CDWR’s share of the undepreciated cost of capital of Reid Gardner Generating Station Unit No. 4 in 2013 (see Note 5, Jointly Owned Properties), at which time NPC will be required to assume all associated operating and maintenance costs for the Unit. Additionally, the Utilities have obligations regarding the construction of ON Line, of which NPC will be responsible for 95% and SPPC 5%.
Operating Leases
The Utilities have entered into various non-cancelable operating leases primarily for building, land and equipment. Contract expiration dates range from 2013 to 2103. NVE’s rent payments meeting the above described criteria for 2012 and 2011 were $2.4 million and $2.4 million respectively. Prior to 2011, NVE did not have non-cancelable operating leases that were material. NPC’s rent payments meeting the above described criteria for 2012, 2011 and 2010 were $9.6 million, $11.5 million and $13.6 million respectively. SPPC’s rent payments meeting the above described criteria for 2012, 2011 and 2010 were $5.8 million, $7.4 million and $14.0 million respectively.
Environmental
NPC
NEICO
NEICO, a wholly-owned subsidiary of NPC, owns property in Wellington, Utah, which was the site of a coal washing and load-out facility. The site has a reclamation estimate supported by a bond of approximately $5 million with the Utah Division of Oil and Gas Mining, which management believes is sufficient to cover reclamation costs. Management is continuing to evaluate various options for this property going forward, including reclamation or sale to a third party.
Reid Gardner Generating Station
On October 4, 2011, NPC received a request for information from the EPA-Region 9 under Section 114 of the Federal Clean Air Act requesting current and historical operations and capital project information for NPC’s Reid Gardner Generating Station located near Moapa, Nevada. NPC operates the facility and owns Units 1-3. Unit 4 of the facility is co-owned with the California Department of Water Resources. The EPA’s Section 114 information request does not allege any incidents of non-compliance at the plant. NPC completed its responses to EPA during the first quarter of 2012 and will continue to monitor developments relating to this Section 114 request. At this time, NPC cannot predict the impact, if any, associated with this information request.
SPPC
Valmy Generating Station
On June 22, 2009, SPPC received a request for information from the EPA-Region 9 under Section 114 of the federal Clean Air Act requesting current and historical operations and capital project information for SPPC’s Valmy Generating Station located in Valmy, Nevada. SPPC co-owns and operates this coal-fired plant. Idaho Power Company owns the remaining 50%. The EPA’s Section 114 information request does not allege any incidents of non-compliance at the plant, and there have been no other new enforcement-related proceedings that have been initiated by the EPA relating to the plant. SPPC completed its response to the EPA in December 2009 and will continue to monitor developments relating to this Section 114 request. At this time, SPPC cannot predict the impact, if any, associated with this information request.
NPC and SPPC
Regional Haze Rules
In 2005, the EPA finalized amendments to its Regional Haze Rules that require the installation and operation of emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the U.S. Certain NVE generating facilities are subject to BART requirements. Pursuant to the EPA’s Regional Haze Rules, individual states were required to identify the facilities located in their states that will have to reduce sulfur dioxide (SO2), nitrogen oxide (NOx) and particulate matter emissions under BART and then set emissions limits for those facilities.
In June 2011, the EPA published in the Federal Register its proposal to approve Nevada's State Implementation Plan (SIP) implementing the Regional Haze Rules for affected units in the State of Nevada, which includes units at our Reid Gardner, Tracy and Ft. Churchill Generating Stations. However, in March 2012, the EPA approved Nevada’s SIP as it pertains to all affected units and emissions, except for NOx controls at Units 1-3 at the Reid Gardner Generating Station. The specified compliance date for this action, which includes the affected Tracy and Ft. Churchill Generating Station units, is January 1, 2015. In that same March 2012 Federal Register notice, the EPA stated that it intended to make a BART determination on those Reid Gardner Generating Station Units at a later date. In August 2012, the EPA published its final determination for NOx BART controls for the Reid Gardner Generating Station Units 1-3, approving and rejecting certain components of Nevada’s SIP. For the limited portions of Nevada’s SIP that EPA rejected, it put in place a Federal Implementation Plan (FIP) that will remain enforceable until such time as Nevada submits a revised SIP to address the concerns the EPA noted in its August 2012 Federal Register notice. Within the August 2012 notice, the EPA approved Nevada’s determination in its SIP that the installation of selective non-catalytic reduction technology (SNCR) represented BART for purposes of compliance with the Regional Haze Rule, with a specified compliance date of January 1, 2015. On October 19, 2012, NPC submitted to EPA a Petition for Reconsideration of the August 2012 final rule requesting EPA to reconsider the compliance deadline so that it be set no earlier than June 30, 2016, which would match the modified compliance data put forward by the State of Nevada. The modified State’s compliance date of 2016 also applies to SPPC. Since filing of the Petition for
Reconsideration, NPC has participated in various discussions with EPA regarding the compliance date. A final decision from EPA on the Petition for Reconsideration remains pending.
NVE continues to work toward finalizing the retrofit designs for the affected BART units. NVE filed and has already received approval from the PUCN to retire Tracy Generating Station Units 1 and 2, and install retrofit controls on Tracy Generating Station Unit 3 and Ft. Churchill Generating Station Units 1 and 2. NVE intends to also file with the PUCN the request to install SNCRs on Reid Gardner Generating Station Units 1, 2 & 3. Compliance with the Regional Haze Rules are estimated to cost approximately $77.1 million, excluding AFUDC, over the next several years; however, these costs are preliminary and subject to change based on final engineering analysis and retirement of generating station units. NVE expects that costs incurred to comply with the Regional Haze Rules would be capitalized and recovered through the Utilities’ regulatory proceedings similar to other environmental compliance requirements.
Environmental groups have challenged both of the EPA’s final determinations with respect to Nevada’s regional haze SIP submittal. In May 2012, WildEarth Guardians petitioned the Ninth Circuit to review the EPA’s March 2012 approval of Nevada’s SIP for all affected units and emissions except NOx controls at the Reid Gardner Generating Station, alleging that the EPA’s approval did not conform to the requirements set forth in the Regional Haze Rule. NVE has intervened in that lawsuit. In October 2012, Earthjustice, on behalf of the Moapa Band of Paiute Indians, Sierra Club, and the National Parks Conservation Association, petitioned the Ninth Circuit to review the EPA’s August 2012 final determinations pertaining to NOx controls at the Reid Gardner Generating Station. NVE has intervened in this lawsuit. At this time management is unable to determine the likelihood of success by petitioners in these litigation matters. An adverse decision in either lawsuit could impact our compliance strategy for the Tracy, Ft. Churchill and Reid Gardner Generating Stations, and could result in the requirement to install more stringent emissions controls, or the retirement of certain units earlier than currently planned.
The Navajo Generating Station is also an affected unit under EPA’s Regional Haze Rules. On January 17, 2013, the EPA announced a proposed FIP addressing BART and an “Alternative to BART” for the Navajo Generating Station that includes a flexible timeline for reducing NOx emissions. NVE, along with the other owners of the facility, are reviewing the EPA proposal to determine its impact on the viability of the plant’s future operations. The land lease for the Navajo Generating Station is up for renewal in 2019. Renewal of this lease will require completion of an Environmental Impact Statement as well as a renewal of the fuels supply agreement, among other considerations. It is believed that the EPA BART proposal will require an investment of up to $1.1 billion in additional emission controls at the plant of which NPC’s ownership share is 11.3%. Given that the lease must be renegotiated by 2019, the timeline for BART installation is unclear, and EPA’s overall proposal will be subject to significant input from a variety of affected parties before it is finalized, NVE cannot predict at this time the ultimate financial impact to the Navajo Generating Station operations or what other alternative actions the ownership may decide to take at this time.
Mercury and Air Toxics Standards (MATS)
In December 2011, the EPA signed for publication in the Federal Register a final rule regulating hazardous air pollutant (HAP) emissions from coal- and oil-fired electric utility steam generating units. The rule, referred to as the MATS rule requires coal- and oil-fired electric utility steam generating units to meet HAP emission standards reflecting the application of the maximum achievable control technology (MACT). The final MATS rule (previously referred to as the Utility MACT Rule) was published in the Federal Register on February 16, 2012. The final rule establishes emission limits for hazardous air pollutants from new and existing coal-fired and oil-fired steam electric generating units. The rule requires sources to comply with the emission limits by April 16, 2015, with a potential one year compliance extension available for sources that are unable to complete the installation of emission controls before the compliance deadline. Numerous petitions for review of the final MATS rule have been filed with the United States Court of Appeals for the District of Columbia. The court has established a schedule for the litigation that has final briefs being filed as soon as in April, 2013.
The final rule does not specifically list control technologies that are required to achieve the MATS emission standards. Coal- and oil-fired electric generating units are required to meet the applicable HAP emission limits using whatever control technology, or combination of technologies, they deem appropriate for their specific situation. In general, control technology requirements will be a function of the fuel being fired and the performance of existing air pollution control systems. Based on a review of emissions data available from NVE’s generating units, as well as emissions data available from EPA for similar sources, the Utilities anticipate that SO2 and/or acid gas reduction will be required at SPPC’s Valmy Generating Station, Unit 1 to achieve compliance with the MATS standards. At the present time, SPPC believes a dry sorbent injection system will be selected as the final control option for Unit 1, at an estimated capital cost for SPPC’s 50% ownership interest of approximately $6.4 million, excluding AFUDC. Note that the actual cost will be dependent upon final engineering design.
Currently, all four of the units at the Reid Gardner Generating Station, as well as Unit 2 at the Valmy Generating Station are compliant with the MATS emission standards, based on the current fuel blend. However, NVE and the Utilities will continue to monitor the chemical coal composition utilized in these units to ensure continued compliance.
Other Environmental Matters
NVE and the Utilities are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. Due to the age and/or historical usage of past and present operating properties, the Utilities may be responsible for various levels of environmental remediation at contaminated sites. This can include properties that are part of ongoing Utility operations, sites formerly owned or used by NVE or the Utilities, and/or sites owned by third parties. The responsibility to remediate typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, NVE, the Utilities or their respective affiliates could potentially be held responsible for contamination caused by other parties. In some instances, NVE or the Utilities may share liability associated with contamination with other parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. These types of sites/situations are generally managed in the normal course of business operations.
In 2008, NPC signed an Administrative Order of Consent (AOC) as owner and operator of Reid Gardner Generating Station Unit Nos. 1, 2 and 3 and as co-owner and operating agent of Unit No. 4. Based on the AOC, in 2008, NPC recorded estimated ARO and capital remediation costs. However, actual costs of work under the AOC may vary significantly once the scope of work is defined and additional site characterization has been completed.
NVE and the Utilities seek to continually comply with environmental regulations; however, given the uncertainties involved in the federal, state and local regulatory environment, future costs to comply may be material.
Litigation Contingencies
NPC
Peabody Western Coal Company - Royalty Claim
NPC owns an 11% interest in the Navajo Generating Station, which is located in northern Arizona and operated by Salt River Project (SRP). Other participants in the Navajo Generating Station are Arizona Public Service Company, Los Angeles Department of Water and Power and Tucson Electric Power Company (together with SRP and NPC, the “Navajo Joint Owners”). NPC also owns a 14% interest in the Mohave Generating Station which is located in Laughlin, Nevada and was operated by Southern California Edison (SCE) prior to the time it became non-operational on December 31, 2005.
In June 1999, the Navajo Nation filed suit against SRP, several Peabody Coal Company entities (collectively referred to as “Peabody”) and SCE in the U.S. District Court for the District of Columbia (the “DC Lawsuit”). NPC was not a party to the DC Lawsuit although, as noted above, it is a participant in both the Navajo Generating Station and the Mohave Generating Station. The DC Lawsuit asserted claims relating to the renegotiation of coal royalty and lease agreements and alleged, among other things, that the defendants obtained a favorable coal royalty rate for leases under which Peabody mined coal for both the Navajo Generating Station and Mohave Generating Station by improperly influencing the outcome of a federal administrative process. The DC Lawsuit sought $600 million in damages and punitive damages of not less than $1.0 billion.
In 2004, Peabody brought suit against the Navajo Joint Owners in state court in St. Louis, Missouri, seeking a declaration that the Navajo Joint Owners are obligated to reimburse Peabody for any royalty, tax or other obligations arising out of the DC Lawsuit. In July 2008, the court dismissed all counts against NPC, two without prejudice to their possible re-filing.
In August 2011, all claims in the DC Lawsuit were dismissed pursuant to a settlement agreement among the Navajo Nation, Peabody, SRP and SCE. At the request of SRP, NPC contributed an immaterial amount toward the settlement of the DC Lawsuit based on its 11% ownership stake in the Navajo Generating Station.
SCE also has asked that the Mohave Joint Owners, including NPC, contribute toward the settlement based upon their ownership stakes in the Mohave Generating Station. NPC has not agreed to contribute to SCE’s portion of the DC Lawsuit settlement. Management has discussed the matters with SCE, but does not believe the impact of any claim by, or settlement with, SCE will be material to NPC.
SPPC
Farad Dam
In June 2001, SPPC sold four hydro generating units (10.3 MW total capacity) located in Nevada and California to TMWA for $8.0 million. One of the units, the Farad Hydro (2.8 MW), has been out of service since the summer of 1996 due to a collapsed flume. Under the terms of the contract with TMWA, SPPC is not entitled to receive the proceeds of sale relating to Farad unless and until it has reconstructed the Farad facility in a manner reasonably acceptable to TMWA or, alternatively, SPPC assigns its casualty loss claim to TMWA and TMWA is reasonably satisfied regarding its rights with respect to such claim. The current estimate to rebuild the diversion dam, if management decides to rebuild, is approximately $20 million.
SPPC filed a claim with the Farad Dam’s insurers, Hartford Steam Boiler Inspection and Insurance Company and Zurich-American Insurance Company, and in 2003 initiated federal court litigation against the insurers. The insurers contested the extent and amount of insurance coverage. Coverage was established through this litigation, but until July 2012 the matter remained in litigation to determine the amount of coverage.
In July 2012, the U.S. Court of Appeals for the Ninth Circuit entered its order reversing the valuation holding of the U.S. District Court and setting the value of Farad Dam at $19.8 million dollars (as was argued by SPPC), with some deduction for depreciation to be determined on remand. The court also affirmed SPPC’s right to recover $4.0 million dollars in permitting and design costs, but held that if SPPC accepts the money, rather than rebuild, the $4.0 million is part of the $19.8 million replacement cost. In addition, the court held that SPPC is entitled to recover full replacement cost in the event of a rebuild, and that the District Court is free, on remand, to extend the three year time to rebuild to start at the conclusion of all litigation.
It is not known at this time when the District Court will set hearings for the issues remanded by the Ninth Circuit. Management cannot assess or predict the outcome or the impact of the District Court decisions at this time, but they are not expected to be material to SPPC.
Other Legal Matters
NVE and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal actions, none of which, in the opinion of management, is expected to have a significant impact on their financial positions, results of operations or cash flows.
Other Commitments
NPC and SPPC
ON Line TUA
During the second quarter of 2011, NVE began to construct Phase 1 of ON Line, which is a joint project between the Utilities and GBT-South. Construction of Phase 1 consists of the initial 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen substation on the NPC system. ON Line has an expected in-service date of no later than December 31, 2013. The Utilities will own a 25% interest in Phase 1 and have entered into a TUA with GBT-South for its 75% interest in Phase 1. Under the terms of the TUA, NVE’s future lease payments are adjusted for construction costs, including cost overruns; for which the Utilities expect to get regulatory recovery of. For accounting purposes NVE is treated as the owner of the construction project in accordance with Lease Accounting, The Effect of Lessee Involvement in Asset Construction of the FASC. As a result, as of December 31, 2012, capitalized construction costs associated with GBT’s 75% interest were $264.9 and $14.2 million at NPC and SPPC, respectively, in CWIP with a corresponding credit to other deferred liabilities. NVE expects to recover future lease payments including cost overruns through the Utilities’ regulatory proceedings.
NOTE 13. COMMON STOCK AND OTHER PAID-IN CAPITAL
Policy on Shareholder Rights Plans
NVE’s policy is to seek shareholder approval prior to the adoption of a shareholder rights plan, unless the BOD, in the exercise of its fiduciary duties and with the concurrence of a majority of its independent members, determines that, under the circumstances existing at the time, it is in the best interest of NVE’s shareholders to adopt a shareholder rights plan without first
obtaining shareholder approval. If a shareholder rights plan is adopted without prior shareholder approval, the plan must provide that it shall expire, unless ratified by shareholders, within one year of adoption.
Stock Ownership Plans
As of December 31, 2012, 14,050,162 shares of common stock have been made available for the CSIP, ESPP, LTIP and NEDSP.
The LTIP allows awards to be granted to officers and key employees through December 2013. The LTIP permits the following types of grants, separately or in combination: nonqualified and qualified stock options; incentive stock options; stock appreciation rights; dividend equivalent rights; restricted stock; restricted stock units; performance units; performance shares; and other equity based awards in cash. Awards may be paid out in shares of common stock.
The ESPP is available to all employees meeting minimum service requirements. Employees can choose twice each year to have up to 15% of their base earnings withheld to purchase NVE common stock. The purchase price of the stock is 85% of the market value on the offering date or the exercise date, whichever is less.
NEDSP
The annual retainer for non-employee directors is $135,000, and the minimum amount to be paid in NVE stock is $75,000 per director. The director may elect to take the remainder in cash or in stock, and a stock award may be deferred until such time as the director is no longer a director of NVE, provided such elections are made sufficiently in advance pursuant to applicable plan provisions. Stock to fulfill the common stock portions of the annual BOD and BOD chair retainers is issued under the NEDSP. Under the NEDSP, the number of shares awarded in compensation is based on the closing price of the common stock listed on The New York Stock Exchange (“NYSE”) on the date of the annual meeting of stockholders (or on the preceding trading day if the meeting is held on a date when the NYSE is closed). Under the NEDSP, NVE granted the following total shares and related compensation to directors during 2012, 2011 and 2010, respectively: 43,808, 49,002, and 65,933 shares, and $748,248, $745,879, $829,074.
CSIP
NVE offers the CSIP for the purpose of promoting long-term ownership by providing a convenient method to purchase shares of our common stock. New investors can purchase common stock directly from the company for as little as $250 for the first purchase. Existing shareholders can purchase additional shares up to once per month for as little as $50. Shareholders can also choose to reinvest all or a portion (specified in increments of 10%) of cash dividends to purchase additional shares of common stock. Shares are purchased on the first business day of each month with the exception of months in which a dividend is paid in which case purchases are scheduled to be made on the date of the dividend payment.
Dividends
On February 7, 2013, NVE’s BOD declared a quarterly cash dividend of $0.19 per share payable on March 20, 2013, to common shareholders of record on March 5, 2013.
During 2012 and 2011, NPC paid dividends to NVE of $184.0 million and $99.0 million, respectively. During 2012 and 2011, SPPC paid dividends to NVE of $20.0 million and $114.0 million, respectively. On February 7, 2013, NPC declared a $50 million dividend payable to NVE.
Treasury Stock
NVE periodically repurchases common stock on the open market for the purpose of meeting the requirements of its stock compensation plans; such purchases were not made pursuant to a publicly announced stock repurchase plan or program. All shares repurchased are held as treasury stock and may be reissued upon exercise or settlement of the stock compensation award. Treasury
stock is accounted for using the cost method. For the year ended December 31, 2012, NVE repurchased approximately 1.1 million shares of common stock for approximately $19.9 million.
NOTE 14. EARNINGS PER SHARE (NVE)
The difference between basic EPS and diluted EPS is due to potentially dilutive common shares resulting from NEDSP, the ESPP and the LTIP.
The following table outlines the calculation for earnings per share (EPS):
NOTE 15. ASSETS HELD FOR SALE
NPC
Sale of NPC’s Telecommunication Towers
In August 2011, NPC completed the sale of 37 telecommunication towers to Global Tower Partners, LLC. Cash proceeds from the sale were approximately $32 million with the gain on sale deferred subject to the final accounting approval by the PUCN.
In March 2012, NPC filed a petition with the PUCN to obtain a declaratory order and the accounting guidance necessary to establish a regulatory account for the gain on sale of NPC’s telecommunication towers to Global Tower Partners, LLC. In July 2012, the PUCN approved a stipulation between NPC, the Bureau of Consumer Protection, and PUCN staff that provides for an allocation of $27.3 million of the approximate $32.0 million gain on sale to the ratepayers. The amortization of the gain will coincide with the rate effective date of NPC’s next GRC, which is mandated in 2015. NPC recorded approximately $5.5 million, including an adjustment to
previously recorded carrying charges to other income for the remaining balance of the gain on sale for the year ended December 31, 2012.
SPPC
Sale of California Electric Distribution and Generation Assets
On January 1, 2011, SPPC sold its California electric distribution and generation assets to CalPeco, d/b/a Liberty Energy-CalPeco. Cash proceeds from the sale were approximately $132 million, plus additional closing adjustments resulting in an immaterial after tax gain, for which the final accounting was approved by the FERC in September 2011. In connection with the sale of the assets, SPPC entered into a separate five year purchase power agreement to sell energy to CalPeco.
In accordance with FASB presentation accounting guidance for discontinued operations, ASC 205-10-20, the California asset sale met the “assets held for sale” criteria, but, did not meet the “component-of-an-entity” criteria. The California electric distribution and generation assets held for sale did not have cash flows that could be clearly distinguished operationally from the rest of the entity because they did not operate individually, but rather as a part of SPPC’s whole operating system, which included all of the electric distribution and generation assets owned by SPPC.
Sale of Independence Lake
In May 2010, SPPC sold a lake and surrounding property located in the State of California, known as Independence Lake, for approximately $15 million. The gain on sale was approximately $14.7 million before taxes; however, approximately $7.1 million of the gain has been deferred as a regulatory liability and will be paid to SPPC’s ratepayers over approximately three years.
NOTE 16. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following figures are unaudited and include all adjustments necessary in the opinion of management for a fair presentation of the results of interim periods. Dollars are presented in thousands except per share amounts.
NVE
(1)
Total Net Income per Share per the Consolidated Statement of Comprehensive Income may differ slightly due to rounding.
(1)
Total Net Income per Share per the Consolidated Statement of Comprehensive Income may differ slightly due to rounding.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
(a) Evaluation of disclosure controls and procedures.
NVE, NPC and SPPC management, under the supervision and with the participation of the company’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of NVE, NPC and SPPC disclosure controls and procedures (as that term is defined in Rules 13a-15(e) or 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period, NVE, NPC and SPPC disclosure controls and procedures are effective.
(b) Reports on Internal Control Over Financial Reporting.
Management’s Annual Report on Internal Control Over Financial Reporting
NVE
The management of NVE is responsible for establishing and maintaining adequate internal control over financial reporting. NVE’s internal control system was designed to provide reasonable assurance to NVE’s management and BOD regarding the preparation and fair presentation of published financial statements.
Although NVE is firmly committed to effective internal controls over financial reporting, internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
NVE’s management assessed the effectiveness of NVE’s internal control over financial reporting as of December 31, 2012. In making this assessment, NVE used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment we believe that, as of December 31, 2012, NVE’s internal control over financial reporting is effective based on those criteria.
NVE’s independent registered public accountants have issued an attestation report on NVE’s internal control over financial reporting.
NPC
The management of NPC is responsible for establishing and maintaining adequate internal control over financial reporting. NPC’s internal control system was designed to provide reasonable assurance to the Company’s management and BOD regarding the preparation and fair presentation of published financial statements.
Although NPC is firmly committed to effective internal controls over financial reporting, internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
NPC’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2012. In making this assessment, NPC used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment we believe that, as of December 31, 2012, NPC’s internal control over financial reporting is effective based on those criteria.
SPPC
The management of SPPC is responsible for establishing and maintaining adequate internal control over financial reporting. SPPC’s internal control system was designed to provide reasonable assurance to the Company’s management and BOD regarding the preparation and fair presentation of published financial statements.
Although SPPC is firmly committed to effective internal controls over financial reporting, internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
SPPC’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2012. In making this assessment, SPPC used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment we believe that, as of December 31, 2012, SPPC’s internal control over financial reporting is effective based on those criteria.
Attestation Report
This annual report does not include an attestation report of the independent registered public accountants regarding internal control over financial reporting of NPC and SPPC. The management reports of NPC and SPPC were not subject to attestation by the independent registered public accountants pursuant to the rules of the SEC that permit NPC and SPPC to provide only management’s reports in their annual report.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
NV Energy, Inc.
Las Vegas, Nevada
We have audited the internal control over financial reporting of NV Energy, Inc. and subsidiaries (the "Company") as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework 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 Annual 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 and correction 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, 2012, based on the criteria established in Internal Control - Integrated Framework 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 and financial statement schedule as of and for the year ended December 31, 2012 of the Company and our report dated February 26, 2013 expressed an unqualified opinion on those financial statements and financial statement schedule.
/s/ Deloitte & Touche LLP
Las Vegas, Nevada
February 26, 2013
(c) Changes in Internal Controls
None for the quarter and year ended December 31, 2012.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
DIRECTORS
The information required by this Item is incorporated by reference to the definitive proxy statement for our 2013 Annual Meeting of Stockholders to be filed with the SEC, other than the information regarding executive officers shown below, within 120 days after the end of our 2012 fiscal year (the “2013 Proxy Statement”).
EXECUTIVE OFFICERS
The following are the current executive officers of NVE, NPC and SPPC and their ages as of December 31, 2012. There are no family relationships among them. Officers serve a term which extends to and expires at the annual meeting of the BOD or until a successor has been elected and qualified:
Michael W. Yackira, 61, is chief executive officer of NVE, NPC and SPPC, and president of NPC and SPPC. He joined in 2003 and served as chief financial officer, chief operating officer and president before being named chief executive officer in 2007. He formerly served as chief financial officer of FPL Group, Inc. (now known as NextEra) from 1995 to 1998, and as president of FPL Energy, LLC from 1998 to 2000. Mr. Yackira is a CPA. He has been a director of NVE, NPC and SPPC since 2007.
E. Kevin Bethel, 49, has served as vice president, chief accounting officer, and controller of NVE since 2007 and was elected to the same positions at NPC and SPPC in February 2008. Mr. Bethel served as interim chief financial officer and treasurer from February 2010 through May 2010. Prior to joining NVE, Mr. Bethel served as Assistant Controller for American Electric Power, Inc. where he held several management positions in accounting from 2001 to 2007. Mr. Bethel is a CPA.
Alice A. Cobb, 64, has been the senior vice president, human resources and information technology & telecom of NVE, NPC and SPPC since January 2012. Prior to that, she served as senior vice president and chief administrative officer of PNM Resources, Inc. from 2005 to 2011, and as senior vice president, people services and development for both Public Service Company of New Mexico and PNM Resources, Inc. from 2001 to 2005. Ms. Cobb further served as a director of Texas-New Mexico Power Company from 2005 to January 2012, and as a director of Public Service Company of New Mexico from 2007 until January 2012.
Roberto R. Denis, 63, has served as senior vice president, energy delivery of NVE, NPC and SPPC since 2009. He joined in 2003 and served as senior vice president, energy supply for five years and vice president, energy supply of NPC and SPPC for one year. Prior to that, he served as vice president, market & regulatory affairs from 2001 to 2003 and as vice president of market services from 1999 to 2001 at FPL Energy LLC, a subsidiary of FPL Group, Inc. (now known as NextEra).
Kevin C. Geraghty, 47, has been the vice president, energy supply of NVE, NPC, and SPPC since July 2012. Prior to that, he served as vice president, power generation since 2009 and executive, generation, from 2008 to 2009. Before joining in 2008, Mr. Geraghty had served in various management positions with Allegheny Energy since 1987.
Jonathan S. Halkyard, 48, has served as executive vice president and chief financial officer of NVE, NPC and SPPC since July 2012. He joined from Caesars Entertainment, where he was chief financial officer from 2006 to 2012, and executive vice president from 2011 to 2012. Prior to that, he was senior vice president from 2005 to 2011 and treasurer from 2003 to 2010, after having served Caesars in other management positions since 1999.
Paul J. Kaleta, 57, has served as executive vice president, shared services, general counsel and corporate secretary of NVE, NPC and SPPC since July 2012. Mr. Kaleta joined in 2006 as senior vice president, general counsel and corporate secretary, and gained responsibility for shared services in 2009. Previously, he was general counsel for Koch Industries, Inc. and various Koch subsidiaries from 1998 to 2005. Prior to joining Koch, he was vice president and general counsel of Niagara Mohawk Power Company for eight years.
Dilek L. Samil, 57, has been the executive vice president and chief operating officer of NVE, NPC and SPPC since July 2012. She joined in 2010 as senior vice president, finance, chief financial officer and treasurer. Prior to joining, she was president and chief operating officer of CLECO Power LLC, after serving as its chief financial officer since 2001. Prior to 2001, she held positions as vice president, finance of FPL Energy LLC and treasurer of FPL Group, Inc. (now known as NextEra).
Anthony F. Sanchez, III, 46, has served as senior vice president, government and community strategy of NVE, NPC and SPPC since August 2007. Prior to that, Mr. Sanchez was a partner in the Nevada-based law firm of Jones Vargas since 1999. He served as assistant general counsel for the PUCN from 1995 to 1998.
Robert E. Stewart, 64, has been the senior vice president, customer relationship of NVE, NPC and SPPC since 2009 after serving as vice president, marketing since 2008. From 1997 to 2008, he worked as an independent consultant in several industries, including energy services and telecommunications. Prior to that, Mr. Stewart served as vice president, marketing of FPL Group, Inc. (now known as NextEra) for five years and as vice president, product management of GTE Telephone Operations for two years.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference to the 2013 Proxy Statement.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this Item is incorporated by reference to the 2013 Proxy Statement.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this Item is incorporated by reference to the 2013 Proxy Statement.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this Item is incorporated by reference to the 2013 Proxy Statement.
SIGNATURES
Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company (both d/b/a NV Energy) have each duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized. The signatures for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
2012 FORM 10-K EXHIBIT INDEX
(a) Exhibits Index
Certain of the following exhibits with respect to NV Energy, Inc. and its subsidiaries, Nevada Power Company d/b/a NV Energy and Sierra Pacific Power Company d/b/a NV Energy, are filed herewith. Certain other of such exhibits have heretofore been filed with the SEC and are incorporated herein by reference.
(* filed herewith)
·
Officer’s Certificate establishing the terms of Nevada Power Company’s 5 7/8% General and Refunding Mortgage Notes, Series L, due 2015 (filed as Exhibit 4(A) to Form 10-K filed for year ended December 31, 2005).
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Form of Nevada Power Company’s 5 7/8% General and Refunding Mortgage Notes, Series L, due 2015 (filed as Exhibit 4(B) to Form 10-K filed for year ended December 31, 2005).
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Officer’s Certificate establishing the terms of Nevada Power Company’s 5.95% General and Refunding Mortgage Notes, Series M, due 2016 (filed as Exhibit 4(A) to Form 10-K for the year ended December 31, 2005).
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Form of Nevada Power Company’s 5.95% General and Refunding Mortgage Notes, Series M, due 2016 (filed as Exhibit 4(B) to Form 10-K for the year ended December 31, 2005).
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Officer’s Certificate establishing the terms of Nevada Power Company’s 6.650% General and Refunding Mortgage Notes, Series N, due 2036 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended March 31, 2006).
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Form of Nevada Power Company’s 6.650% General and Refunding Mortgage Notes, Series N, due 2036 (filed as Appendix A to Exhibit 4.1 to Form 10-Q for the quarter ended March 31, 2006).
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Officer’s Certificate establishing the terms of Nevada Power Company’s 6.50% General and Refunding Mortgage Notes, Series O, due 2018 (filed as Exhibit 4.7 to Form S-4 filed June 7, 2006).
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Form of Nevada Power Company’s 6.50% General and Refunding Mortgage Notes, Series O, due 2018 (filed as Appendix A to Exhibit 4.7 to Form S-4 filed June 7, 2006).
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Officer’s Certificate establishing the terms of Nevada Power Company’s 6.750% General and Refunding Mortgage Notes, Series R, due 2037 (filed as Exhibit 4.1 to Form 8-K dated June 27, 2007).
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Form of Nevada Power Company’s 6.750% General and Refunding Mortgage Notes, Series R, due 2037 (filed as Appendix A to Exhibit 4.1 to Form 8-K dated June 27, 2007).
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Officer’s Certificate establishing the terms of Nevada Power Company’s 6.50% General and Refunding Mortgage Notes, Series S, due 2018 (filed as Exhibit 4.1 to Form 8-K dated July 28, 2008).
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Form of Nevada Power Company’s 6.50% General and Refunding Mortgage Notes, Series S, due 2018 (filed as Appendix A to Exhibit 4.1 to Form 8-K dated July 28, 2008).
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Officer’s Certificate establishing the terms of Nevada Power Company d/b/a NV Energy’s 7.375% General and Refunding Mortgage Notes, Series U, due 2014 (filed as Exhibit 4.1 to Form 8-K dated January 8, 2009).
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Form of Nevada Power Company d/b/a NV Energy’s 7.375% General and Refunding Mortgage Notes, Series U, due 2014 (filed as Appendix A to Exhibit 4.1 to Form 8-K dated January 8, 2009).
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Officer’s Certificate establishing the terms of Nevada Power Company d/b/a NV Energy’s 7.125% General and Refunding Mortgage Notes, Series V, due 2019 (filed as Exhibit 4.1 to Form 8-K dated February 25, 2009).
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Form of Nevada Power Company d/b/a NV Energy’s 7.125% General and Refunding Mortgage Notes, Series V, due 2019 (filed as Appendix A to Exhibit 4.1 to Form 8-K dated February 25, 2009).
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Officers’ Certificate establishing the terms of Nevada Power Company d/b/a NV Energy’s 5.375% General and Refunding Mortgage Notes, Series X, due 2040 (filed as Exhibit 4.1 to Form 8-K dated September 10, 2010).
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Form of Nevada Power Company d/b/a NV Energy’s 5.375% General and Refunding Mortgage Notes, Series X, due 2040 (filed as Appendix A to Exhibit 4.1 to Form 8-K dated September 10, 2010).
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Officer's Certificate establishing the terms of Nevada Power Company d/b/a NV Energy's 5.45% General and Refunding Mortgage Notes, Series Y, due 2041 (filed as Exhibit 4.1 to Form 8-K dated May 9, 2011).
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Form of Nevada Power Company d/b/a NV Energy's General and Refunding Mortgage Notes, Series Y, due 2041 (filed as Appendix A to Exhibit 4.1 to Form 8-K dated May 9, 2011).