ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Forward-Looking Statements and Risk Factors
The information in this Form 10-Q 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:
Risks Related to the Pending MidAmerican Merger
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whether NVE or MEHC will be able to satisfy the remaining closing conditions of the MidAmerican Merger Agreement, including the receipt of regulatory approvals from the PUCN and the FERC on the terms and schedules contemplated by the parties;
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whether an event, effect or change will occur that gives rise to a termination of the MidAmerican Merger;
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whether NVE will experience unanticipated difficulties and/or incur unanticipated expenditures relating to the MidAmerican Merger, and whether the MidAmerican Merger will disrupt current plans and operations and create difficulties in employee retention;
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whether legal proceedings against NVE and others related to the MidAmerican Merger will be successful; and
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the impact of delay or failure to complete the MidAmerican Merger on NVE’s common stock price.
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Operational Risks
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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;
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changes in customer demand for electricity and gas resulting from variations in the rate of industrial, commercial and residential growth in the Utilities’ service territories, from energy conservation programs, and from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies;
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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;
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security breaches of our information technology or supervisory 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;
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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;
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employee workforce factors, changes in and renewals of collective bargaining unit agreements, strikes or work stoppages, an aging workforce, and the ability to adjust the labor cost structure to changes in growth within our service territories;
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whether the Utilities’ NV Energize 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;
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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;
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explosions, fires, accidents, mechanical breakdowns or vandalism 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;
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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;
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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;
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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; and
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unusual or unanticipated changes in normal business operations of the Utilities, including unusual maintenance or repairs.
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Regulatory/Legislative Risks
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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;
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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, use alternative sources of energy, generate their own electricity, or change the conditions under which they may do so;
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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
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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.
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Environmental Risks
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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.
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Liquidity and Capital Resources Risks
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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;
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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;
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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;
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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;
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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;
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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
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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.
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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 Quarterly Report on Form 10-Q, 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:
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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;
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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;
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may apply standards of materiality in a way that is different from what may be viewed as material to investors; and
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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.
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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:
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Critical Accounting Policies and Estimates:
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For each of NVE, NPC and SPPC:
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Liquidity and Capital Resources
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Regulatory Proceedings (Utilities)
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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.
MidAmerican Merger
In May 2013, NVE entered into the MidAmerican Merger Agreement, which provides for the merger of Silver Merger Sub, Inc. with and into NVE, with NVE continuing as the surviving corporation. Once merged, NVE will become an indirect wholly-owned subsidiary of MEHC, which in turn is a wholly-owned subsidiary of Berkshire Hathaway, Inc. Pursuant to the MidAmerican Merger Agreement, at the effective time of the MidAmerican Merger, each share of common stock of NVE issued and outstanding immediately prior to the closing will be converted into the right to receive cash in the amount of $23.75 per share, without interest. The MidAmerican Merger Agreement is subject to various conditions and is discussed in more detail in Note 2,
Merger-Related Activities,
of the Condensed Notes to Financial Statements. In order to close in late 2013 or the first quarter of 2014, management intends to work diligently to satisfy the conditions as outlined in Note 2,
Merger-Related Activities,
of the Condensed Notes to Financial Statements, as well as transitional requirements.
Overview of Major Factors Affecting Results of Operations
NVE recognized net income of $187.2 million for the three months ended September 30, 2013, compared to $223.2 million for the same period in 2012. The decrease in net income is primarily due to the following pre-tax items:
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The PUCN disallowance of EEIR revenue and carrying charges of $16.2 million and the additional provision recorded against 2013 EEIR revenue of $15.1 million and other regulatory disallowances of $1.1 million. See Note 4,
Regulatory Actions
, of the Condensed Notes to Financial Statements;
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MidAmerican merger-related costs of $7.9 million as discussed in Note 2,
Merger-Related Activities,
of the Condensed Notes to Financial Statements;
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An increase in other operating expense primarily due to an increase in meter software maintenance, and right of way leases, overall generation expenses and wage increases for the IBEW 396 collective bargaining agreement. See the Utilities’ respective
Results of Operations
for further discussion;
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A decrease in other income primarily due to the gain on sale of telecommunications towers recorded in 2012; and
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A decrease in gross margin of $4.3 million not including the disallowance and provision discussed above. See the Utilities’ respective
Results of Operations
for further discussion of gross margin.
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These decreases were partially offset by the following pre-tax items:
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A decrease in interest expense on regulatory items primarily due to lower over collected deferred energy and regulatory balances.
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NVE recognized net income of $271.9 million for the nine months ended September 30, 2013, compared to $304.8 million for the same period in 2012. The decrease in net income is primarily due to the following pre-tax items:
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The PUCN disallowance of EEIR revenue and carrying charges of $16.2 million and the additional provision recorded against 2013 EEIR revenue of $15.1 million and other regulatory disallowances of $1.1 million. See Note 4,
Regulatory Actions
, of the Condensed Notes to Financial Statements;
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MidAmerican merger-related costs of $21.4 million as discussed in Note 2,
Merger-Related Activities
, of the Condensed Notes to Financial Statements;
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An increase in other operating expense primarily due to an increase in regulatory expenses, a $3.4 million reduction in capitalized costs as a result of a decrease in construction activity, an increase in chemical and operating expenses at the Reid Gardner and Clark Generating Stations, an increase in outside consulting fees, and increased meter software maintenance and right of way. See the Utilities’ respective
Results of Operations
for further discussion;
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An increase in depreciation expense primarily due to the completion of various projects; and
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A decrease in other income primarily due to income recognized in 2012 for a construction contract settlement for the Harry Allen Generating Station and the gain on sale of telecommunications towers recorded in 2012.
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These increases were partially offset by the following pre-tax items:
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An increase in gross margin of $14.1 million not including the disallowance and provision discussed above. See the Utilities’ respective
Results of Operations
for further discussion of gross margin;
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A decrease in maintenance expense primarily due to a decrease in outages;
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A decrease in interest expense primarily due to the redemption of NPC’s 6.5% General and Refunding Mortgage Notes, Series I in April 2012; and
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A decrease in interest expense on regulatory items primarily due to lower over collected deferred energy and regulatory balances.
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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 their allowable return on their investments while meeting a higher percentage of their load through owned generation. Additionally, as a result of their financial policies, which focused on lowering interest rates and reducing debt, interest costs and their capital structure continue to improve. Furthermore, through employee dedication and increased use of technology we continue to improve processes to enhance performance while keeping operating and maintenance costs relatively stable. As a result, NVE expects to generate free cash flow in 2013, which will continue to provide NVE the ability to maintain its dividend.
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 strengthen our capital structure and to consider new investment opportunities. In addition, NVE management remains focused on the execution of the MidAmerican Merger. 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 its business operations and culture. These principles include not only complying with applicable safety, health and security regulations, but also implementing programs and processes aimed at continually improving safety and security conditions. Our initiatives in 2013 and beyond will continue modeling a safety culture in all areas of the company.
Construction of ON Line
ON Line is Phase 1 of a joint project between the Utilities and GBT-South. Completion of ON Line, expected in December 2013, will connect NVE’s southern and northern service territories. ON Line will provide:
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Ability to dispatch energy jointly throughout the state;
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Access for southern Nevada to renewable energy resources in parts of northern and eastern Nevada, which will enhance NVE’s ability to meet its Portfolio Standard; and
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Ability to optimize its generating and transmission facilities to benefit its customers.
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One Company Merger
In May 2013, NPC and SPPC filed a joint application with the PUCN to consolidate the Utilities into a single jurisdictional utility. The joint application with the PUCN requested the following:
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Authority to modify the legal and regulatory structures of NPC and SPPC by merging SPPC into NPC, effectively transferring all of SPPC’s assets and obligations to NPC, and renaming the surviving utility "NV Energy Operating Company" (NVEOC);
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Authority to transfer SPPC’s certificates of public convenience and necessity (CPCN) to NPC, and to modify the transferred CPCNs and NPC’s CPCN to reflect the name of the surviving utility, NVEOC; and
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Authority to transfer all SPPC’s electric and gas utility assets, including electric generation assets, to NPC.
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The PUCN may not authorize the One Company Merger unless it finds, among other things, that the proposed transaction is “in the public interest.” The PUCN is not bound by any statutory deadlines with respect to this application. Hearings were expected to begin in February 2014, but the Utilities are seeking to delay the proceedings to the second half of 2014.
In May 2013, NVE, NPC and SPPC filed an application with the FERC under Section 203 of the Federal Power Act for Approval of Internal Reorganization. In their request, NPC and SPPC requested FERC authorization for an internal corporate reorganization under which SPPC will merge into NPC and be renamed NVEOC. On October 21, 2013, NVE, NPC and SPPC submitted an informational filing with FERC indicating that given the status of an application pending before the PUCN, the applicants did not object to FERC deferring its consideration of the application. The application remains pending before FERC for consideration.
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. Since April 30, 2013, the project was deemed to be substantially complete. SPPC has included its proportionate share of costs, in its 2013 GRC, and NPC’s proportionate share of costs will be included in a future rate case.
The NV Energize system provides more convenience for customers and is achieving operating savings through both automated meter reading and the elimination annually 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 and NVision
As discussed further in Note 8,
Commitments and Contingencies,
of the Condensed Notes to Financial Statements, NVision is NVE’s comprehensive plan for the reduction of emissions from coal-fired generation plants through the accelerated retirement of certain coal-fired plants, the replacement of the generation capacity of such plants with increased capacity from renewable energy facilities and other electric generating plants. In June 2013, the Nevada State Legislature passed SB 123, which was supported by NVE as part of its NVision initiative. The Utilities expect to file an emissions reduction plan in 2014 to specifically address the plan details.
Also discussed in more detail in Note 8,
Commitments and Contingencies,
of the Condensed Notes to Financial Statements, certain generating stations of NVE are affected under EPA’s Regional Haze Rules and Mercury and Air Toxics Standards (MATS). The implementation costs of these rules are significant. Therefore, NVE must balance the costs of implementing the retrofit and control technology associated with the Regional Haze Rule and MATS standards with the effects of NVision, current and future load requirements, retirements of generating stations, plant outages and the ability to serve customers reliably. To that end, the PUCN has accepted the Utilities’ resource plan to install necessary controls on the Tracy Generating Station Unit 3 and Fort Churchill Generating Station Units 1 and 2 to comply with Regional Haze. Tracy Generating Station Units 1 and 2 will be retired on or before the regional haze compliance date. Reid Gardner Generating Station Units 1, 2 and 3 are also affected by the regional haze compliance date, but no decision has been made for these units at this time as NVE considers the impacts of NVision on these units. In addition, the Utilities anticipate that sulfur dioxide (SO2) and/or acid gas reduction will be required at SPPC’s Valmy Generating Station Unit 1 to achieve compliance with the MATS standards. Furthermore, NPC expects to file an emissions reduction plan in 2014 to specifically address its 11.3% ownership participation in the Navajo Generating Station, as a result of a number of uncertainties, as well as environmental compliance and the passage of NVision.
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.
NV ENERGY, INC.
RESULTS OF OPERATIONS
NV Energy, Inc. and Other Subsidiaries
NVE (Holding Company)
The operating results of NVE primarily reflect those of NPC and SPPC, discussed later. The holding company’s (stand alone) operating results included approximately $18.7 million and $18.9 million of long-term debt interest costs for the nine months ended September 30, 2013 and 2012, respectively.
For the nine month period ended September 30, 2013, NPC and SPPC paid $105.0 million and $40.0 million, respectively, in dividends to NVE. On November 6, 2013, NPC and SPPC declared dividends payable to NVE of $73.0 million and $37.0 million, respectively.
Other Subsidiaries
Subsidiaries of NVE, other than NPC and SPPC, did not contribute materially to the consolidated results of operations of NVE.
ANALYSIS OF CASH FLOWS
Cash From Operating Activities
NVE’s net cash flows from operating activities were $553.7 million and $644.2 million for the nine months ended September 30, 2013 and 2012, respectively.
The decrease in cash from operating activities was primarily due to:
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Under-collection of energy costs due to higher energy costs of $306.4 million, offset by reduced refunds to customers of $121.7 million;
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Reduced EEPR collections of $50.1 million;
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Payments in 2013 for outages that occurred in 2012 at the Reid Gardner and Lenzie Generating Stations of $22.7 million; and
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Reduced revenues due to decreased BTER and EEPR rates combined with reduced customer energy usage due to cooler summer weather in 2013 compared to the same period in 2012.
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The decrease in cash from operating activities was partially offset by:
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Reduced coal purchases of $34.5 million;
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Reduced spending on renewable programs of $27.8 million; and
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Receipt of approximately $9.0 million in insurance proceeds related to a previous claim.
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Cash Used By Investing Activities
NVE’s net cash used by investing activities were $(233.3) million and $(325.2) million for the nine months ended September 30, 2013 and 2012, respectively.
The decrease in cash used by investing activities was primarily due to:
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Reduced capital expenditure for the NV Energize project of $95.5 million, partially offset by reduced CIAC received under the American Recovery and Reinvestment Act of 2009 of $28.0 million; and
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Reduced capital maintenance at Reid Gardner, Lenzie and Silverhawk Generating Stations of $54.2 million.
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Cash Used By Financing Activities
NVE’s net cash flows used by financing activities were $(245.6) million and $(257.0) million for the nine months ended September 30, 2013 and 2012, respectively.
The decrease in cash used by financing activities was primarily due to:
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Issuance of SPPC’s $250 million, 3.375% General and Refunding Mortgage Notes, Series T debt; and
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Reduction in cash used by NPC to retire debt of $166.9 million.
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The decrease in cash used by financing activities was partially offset by:
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Redemption of SPPC’s $250 million, 5.45% General and Refunding Mortgage Notes, Series Q debt;
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Reduction of draws from the NPC revolving credit facility of $135.0 million; and
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|
•
|
Increased dividends to shareholders of $23.3 million.
|
NVE paid common stock dividends of $134.3 million and $110.9 million during the nine months ended September 30, 2013 and 2012, respectively.
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 BTER amounts from customers. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcomes and economic conditions.
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|
|
Available Liquidity as of September 30, 2013 (in millions)
|
|
|
NVE
|
|
NPC
|
|
SPPC
|
|
Cash and Cash Equivalents
|
$
|
33.1
|
|
|
$
|
255.2
|
|
|
$
|
84.1
|
|
|
Balance available on Revolving Credit Facilities
(1)
|
N/A
|
|
|
500.0
|
|
|
243.7
|
|
|
|
$
|
33.1
|
|
|
$
|
755.2
|
|
|
$
|
327.8
|
|
|
|
|
|
(1)
|
As of November 6, 2013, NPC and SPPC had approximately $500.0 million and $244.0 million available under their revolving credit facilities, which includes reductions in availability for letters of credit.
|
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.
For the remainder of 2013, NVE and the Utilities have no other debt maturities. NPC’s $125 million 7.375% General and Refunding Notes, Series U, will mature in January 2014. Additionally, in October of 2014, NVE's $195.0 million Term Loan will mature. 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. The Utilities’ credit ratings on their senior secured debt remains at investment grade (see
Credit Ratings
below). NVE and the Utilities have not recently experienced any limitations in the credit markets, nor do we expect any for the remainder of 2013. However, disruption in the banking and capital markets not specifically related to NVE and 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’s 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 in 2013; however, NVE’s and the Utilities’ cash flow may vary from quarter to quarter due to the seasonality of our business. Free cash flow may be used to reduce debt, to maintain our dividend payout and for potential investment opportunities.
However, if energy costs rise at a rapid rate, 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 under such circumstances, NVE and the Utilities may be required to delay capital expenditures or refinance debt. 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 November 6, 2013, NVE has approximately $10.8 million payable of debt service obligations remaining for 2013, which it intends to fund through dividends from subsidiaries. See
Factors Affecting Liquidity-Dividends from Subsidiaries,
below. For the nine months ended September 30, 2013, NPC and SPPC paid dividends to NVE of approximately $105.0 million and $40.0 million, respectively. On November 6, 2013, NPC and SPPC declared dividends payable to NVE of $73.0 million and $37.0 million, respectively.
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, environmental compliance, improvement and maintenance of facilities. As discussed in Note 12,
Commitments and Contingencies,
of the 2012 Form 10-K, capital projects include NPC’s payment of Reid Gardner Generating Station Unit 4 from CDWR, which was completed in October 2013 for approximately $47.6 million.
During the nine months ended September 30, 2013, there were no material changes to contractual obligations as set forth in NVE’s 2012 Form 10-K except that in June 2013, SPPC entered into a long-term capital lease for a solar array facility, still subject to commercial operation and approval by the PUCN. The contract requires SPPC to make annual payments of approximately $3.0 million per year for a twenty year period. However, SPPC has the option to terminate the lease and purchase the facility on or after the sixth anniversary of the commercial operation date of the facility for approximately $20.0 million.
Financing Transactions
Nevada Power Company
In July 2013, NPC issued a notice of redemption to the bondholders for its $100 million Clark County Industrial Development Refunding Revenue Bonds, Series 2000A. In August 2013, NPC redeemed the aggregate principal amount outstanding of $98.1 million at 100% of the principal amount plus accrued interest with the use of cash on hand.
Sierra Pacific Power Company
In August 2013, SPPC issued and sold $250 million of its 3.375% General and Refunding Notes, Series T due 2023. The approximately $247.9 million in net proceeds was used, together with cash on hand, to pay at maturity the $250 million principal amount of its 5.45% General and Refunding Notes, Series Q, which matured in September 2013.
Factors Affecting Liquidity
Ability to Issue Debt
Certain debt of NVE (holding company) places restrictions on debt incurrence and liens, unless, at the time the debt is incurred, the ratio of cash flow to fixed charges for NVE’s (consolidated) most recently ended four-quarter period on a pro forma basis is at least 1.50 to 1.00 and the ratio of consolidated total indebtedness to consolidated capitalization does not exceed 0.70 to 1.00. Under these covenant restrictions, as of September 30, 2013, NVE (consolidated) would be allowed to incur up to $3.7
billion of additional indebtedness. 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 their limitations on their ability to issue debt.
Effect of Holding Company Structure
As of September 30, 2013, NVE (on a stand-alone basis) had outstanding debt and other obligations including, but not limited to: a $195 million Term Loan due October 2014; and $315 million of 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 September 30, 2013, NVE, NPC, SPPC and their subsidiaries had approximately $4.9 billion of debt and other obligations outstanding, consisting of approximately $3.2 billion of debt at NPC, approximately $1.2 billion of debt at SPPC and approximately $510.0 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 September 30, 2013, 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.
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 May 22, 2013, Moody’s upgraded NVE’s, NPC’s and SPPC’s ratings. On May 30, 2013, Fitch and Standard & Poor’s upgraded NPC’s and SPPC’s rating outlook from Stable to Positive. NPC’s and SPPC’s senior secured debt is rated investment grade by three NRSRO’s: Fitch, Moody’s and S&P. As of September 30, 2013, the ratings are as follows:
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Rating Agency
|
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|
Fitch
(1)
|
|
Moody’s
(2)
|
|
S&P
(3)
|
|
NVE
|
Sr. Unsecured Debt
|
|
BB+
|
|
Baa3*
|
|
BB+
|
|
NPC
|
Sr. Secured Debt
|
|
BBB+*
|
|
A3*
|
|
BBB+*
|
|
SPPC
|
Sr. Secured Debt
|
|
BBB+*
|
|
A3*
|
|
BBB+*
|
|
|
|
|
(1)
|
Fitch's lowest level of "investment grade" credit rating is BBB-.
|
|
|
|
|
(2)
|
Moody's lowest level of "investment grade" credit rating is Baa3.
|
|
|
|
|
(3)
|
S&P's lowest level of "investment grade" credit rating is BBB-.
|
Fitch’s and S&P’s rating outlooks are Positive, while Moody’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 September 30, 2013 for all suppliers continuing to provide power under a WSPP agreement would approximate a $49.7 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 mean 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 September 30, 2013, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $87.2 million. Of this amount, approximately $26.0 million would be required if NPC’s Senior Unsecured ratings are rated below BB (S&P) or Ba3 (Moody’s) and an additional amount of approximately $61.2 million would be required if NPC’s Senior Unsecured and Senior Secured ratings both are downgraded to below investment grade.
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 in Note 6,
Long-Term Debt,
of the Notes to Financial Statements in the 2012 Form 10-K, 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 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.
Change of Control Provisions; Consent of Lenders
The MidAmerican Merger will accelerate the vesting and settlement of equity compensation awards to executives and employees which will be cashed out upon consummation of the MidAmerican Merger. Certain executives are also entitled to additional change of control payments in the event of an occurrence of a qualified termination. The consummation of the MidAmerican Merger will also trigger mandatory redemption requirements under financing agreements of NVE and the Utilities. As a result, NVE, NPC and SPPC will be required to offer to purchase approximately $315.0 million, $3.1 billion, and $951.7 million, respectively, of debt at 101% of par within 10 days after the MidAmerican Merger closing. At this time, NVE and the Utilities are unable to determine the extent to which holders of these debt securities will accept such tender offers. The average interest rate under these financing agreements is approximately 6.25%, 6.42% and 5.51% for NVE, NPC and SPPC, respectively. To the extent that debt securities are tendered pursuant to the required tender offers, NVE and the Utilities intend to fund the purchases using a combination of internal funds, the Utilities’ revolving credit facilities or the issuance of long-term debt. Furthermore, NVE and the Utilities were required to obtain consents from lenders under the terms of Utilities’ revolving credit facilities and NVE’s Term Loan before consummating the MidAmerican Merger. In November 2013, NVE amended its Term Loan and NPC and SPPC amended their revolving credit facilities, in each case to permit the MidAmerican Merger.
NEVADA POWER COMPANY
RESULTS OF OPERATIONS
NPC recognized net income of approximately $164.4 million during the three months ended September 30, 2013, compared to $195.2 million for the same period in 2012. During the nine months ended September 30, 2013, NPC recognized net income of approximately $228.6 million, compared to $256.2 million for the same period in 2012.
For the nine month period ended September 30, 2013, NPC paid $105.0 million in dividends to NVE. On November 6, 2013, NPC declared a dividend of $73.0 million to NVE.
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, energy efficiency program costs and regulatory disallowances, provides a measure of income available to support the other operating expenses of NPC. For reconciliation to operating income, see Note 3,
Segment Information,
of the Condensed Notes to Financial Statements. Gross margin changes are primarily due to general base rate adjustments and regulatory disallowances (which are required by statute to be filed every three years).
The components of gross margin were (dollars in thousands):
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|
Three Months Ended September 30,
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|
Nine Months Ended September 30,
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|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
Operating Revenues:
|
$
|
786,142
|
|
|
$
|
802,334
|
|
|
$
|
(16,192
|
)
|
|
(2.0)%
|
|
$
|
1,695,129
|
|
|
$
|
1,751,165
|
|
|
$
|
(56,036
|
)
|
|
(3.2)%
|
|
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|
Energy Costs:
|
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|
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|
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|
|
|
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|
Fuel for power generation
|
163,127
|
|
|
123,992
|
|
|
39,135
|
|
|
31.6%
|
|
412,904
|
|
|
285,799
|
|
|
127,105
|
|
|
44.5%
|
|
|
Purchased power
|
172,582
|
|
|
171,687
|
|
|
895
|
|
|
0.5%
|
|
383,386
|
|
|
388,494
|
|
|
(5,108
|
)
|
|
(1.3)%
|
|
|
Deferred energy
|
(45,381
|
)
|
|
(22,685
|
)
|
|
(22,696
|
)
|
|
100.0%
|
|
(154,484
|
)
|
|
(15,461
|
)
|
|
(139,023
|
)
|
|
899.2%
|
|
Energy efficiency program costs
|
13,998
|
|
|
28,492
|
|
|
(14,494
|
)
|
|
(50.9)%
|
|
32,807
|
|
|
65,466
|
|
|
(32,659
|
)
|
|
(49.9)%
|
|
Regulatory disallowance
|
11,866
|
|
|
—
|
|
|
11,866
|
|
|
N/A
|
|
11,866
|
|
|
—
|
|
|
11,866
|
|
|
N/A
|
|
|
Total Costs
|
$
|
316,192
|
|
|
$
|
301,486
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|
|
$
|
14,706
|
|
|
4.9%
|
|
$
|
686,479
|
|
|
$
|
724,298
|
|
|
$
|
(37,819
|
)
|
|
(5.2)%
|
|
|
|
|
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|
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|
|
|
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|
|
|
|
|
|
Gross Margin
|
$
|
469,950
|
|
|
$
|
500,848
|
|
|
$
|
(30,898
|
)
|
|
(6.2)%
|
|
$
|
1,008,650
|
|
|
$
|
1,026,867
|
|
|
$
|
(18,217
|
)
|
|
(1.8)%
|
Gross margin decreased for the three and nine months ended September 30, 2013, compared to the same period in 2012. The decrease is primarily due to the disallowance of EEIR revenue and carrying charge and other deferred energy disallowances of $11.9 million (pre-tax) and a provision of $11.1 million (pre-tax) recorded against 2013 EEIR revenues, as a result of the precedent set by the PUCN’s ruling in NPC’s EEIR filing, as well as, NPC’s estimated rate of return in excess of its allowed rate of return as of September 30, 2013. See Note 4,
Regulatory Actions
, of the Condensed Notes to Financial Statements for further discussion of the EEIR disallowance. Also contributing to the decrease in margin was a decrease in usage primarily due to a decrease in CDDs, as shown in the table below. The decrease was partially offset by customer growth and an increase in BTGR revenue.
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° F. HDDs measure heating energy demand and indicate how far the average temperature fell below 65° F. CDDs measure cooling energy demand and indicate how far the temperature averaged above 65° F. For example, if a location had a mean temperature of 60° F on day 1 and 80° F 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:
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|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
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|
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
NPC
|
|
|
|
|
|
|
|
|
|
|
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|
|
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|
|
|
Heating
|
—
|
|
|
—
|
|
|
—
|
|
|
N/A
|
|
1,084
|
|
|
986
|
|
|
98
|
|
|
9.9
|
%
|
|
|
Cooling
|
2,164
|
|
|
2,313
|
|
|
(149
|
)
|
|
(6.4
|
)%
|
|
3,658
|
|
|
3,771
|
|
|
(113
|
)
|
|
(3.0
|
)%
|
The causes for significant changes in specific lines comprising the results of operations for NPC for the respective periods are provided below (dollars in thousands except for amounts per unit):
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Operating Revenue
|
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|
|
|
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|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
Operating Revenues:
|
|
|
|
|
|
|
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|
|
|
|
|
Residential
|
$
|
420,072
|
|
|
$
|
436,534
|
|
|
$
|
(16,462
|
)
|
|
(3.8
|
)%
|
|
$
|
891,024
|
|
|
$
|
915,953
|
|
|
$
|
(24,929
|
)
|
|
(2.7
|
)%
|
|
|
Commercial
|
120,407
|
|
|
121,334
|
|
|
(927
|
)
|
|
(0.8
|
)%
|
|
305,876
|
|
|
318,126
|
|
|
(12,250
|
)
|
|
(3.9
|
)%
|
|
|
Industrial
|
226,739
|
|
|
227,824
|
|
|
(1,085
|
)
|
|
(0.5
|
)%
|
|
452,825
|
|
|
473,548
|
|
|
(20,723
|
)
|
|
(4.4
|
)%
|
|
|
|
Retail revenues
|
767,218
|
|
|
785,692
|
|
|
(18,474
|
)
|
|
(2.4
|
)%
|
|
1,649,725
|
|
|
1,707,627
|
|
|
(57,902
|
)
|
|
(3.4
|
)%
|
|
|
Other
|
18,924
|
|
|
16,642
|
|
|
2,282
|
|
|
13.7
|
%
|
|
45,404
|
|
|
43,538
|
|
|
1,866
|
|
|
4.3
|
%
|
|
|
|
Total Operating Revenues
|
$
|
786,142
|
|
|
$
|
802,334
|
|
|
$
|
(16,192
|
)
|
|
(2.0
|
)%
|
|
$
|
1,695,129
|
|
|
$
|
1,751,165
|
|
|
$
|
(56,036
|
)
|
|
(3.2
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail sales in thousands of MWhs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
3,627
|
|
|
3,752
|
|
|
(125
|
)
|
|
(3.3
|
)%
|
|
7,592
|
|
|
7,619
|
|
|
(27
|
)
|
|
(0.4
|
)%
|
|
|
Commercial
|
1,329
|
|
|
1,374
|
|
|
(45
|
)
|
|
(3.3
|
)%
|
|
3,423
|
|
|
3,480
|
|
|
(57
|
)
|
|
(1.6
|
)%
|
|
|
Industrial
|
2,078
|
|
|
2,145
|
|
|
(67
|
)
|
|
(3.1
|
)%
|
|
5,756
|
|
|
5,836
|
|
|
(80
|
)
|
|
(1.4
|
)%
|
|
Retail sales in thousands of MWhs
|
7,034
|
|
|
7,271
|
|
|
(237
|
)
|
|
(3.3
|
)%
|
|
16,771
|
|
|
16,935
|
|
|
(164
|
)
|
|
(1.0
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average retail revenue per MWh
|
$
|
109.07
|
|
|
$
|
108.06
|
|
|
$
|
1.01
|
|
|
0.9
|
%
|
|
$
|
98.37
|
|
|
$
|
100.83
|
|
|
$
|
(2.46
|
)
|
|
(2.4
|
)%
|
NPC’s retail revenues decreased for the three months ended September 30, 2013, as compared to the same period in 2012 due to $25.8 million in decreased usage primarily resulting from a decrease in CDDs, as shown in the table above, and an additional $14.4 million due to decreased EEPR rates, effective January 1, 2013. Also contributing to the decrease was a provision of $11.1 million recorded against 2013 EEIR revenues as a result of the precedent set by the PUCN’s ruling in NPC’s EEIR filing and NPC’s estimated rate of return in excess of its allowed rate of return as of September 30, 2013. See Note 4,
Regulatory Actions
, of the Condensed Notes to Financial Statements for further discussion of the EEIR disallowance. These decreases were offset by an increase of $26.3 million as a result of NPC’s various BTER and DEAA quarterly updates (see Note 3,
Regulatory Actions
, of the Notes to the Financial Statements in the 2012 Form 10-K) and $6.0 million due to retail customer growth.
For the three months ended September 30, 2013, the average number of retail customers increased by 1.3%, consisting of an increase in residential and commercial customers of 1.3% and 1.7%, respectively, and a decrease in industrial customers of 0.6%, compared to the same period in the prior year.
Electric Operating Revenues - Other increased for the three months ended September 30, 2013, compared to the same period in 2012, due to an increase in transmission rates of $2.4 million as a result of the FERC rate case effective June 1, 2013. See Note 4,
Regulatory Actions
, of the Condensed Notes to Financial Statements for further discussion.
NPC’s retail revenues decreased for the nine months ended September 30, 2013, as compared to the same period in 2012 due to $32.4 million from decreased EEPR rates effective January 1, 2013, $19.4 million due to a decrease in CDDs, as shown in the table above, $11.1 million provision for EEIR revenue recorded in 2013, as discussed above, and $8.6 million as a result of NPC’s various BTER and DEAA quarterly updates (see Note 3,
Regulatory Actions
, of the Notes to the Financial Statements in the 2012 Form 10-K). These decreases were offset by an increase of $9.2 million from residential customer growth.
For the nine months ended September 30, 2013, the average number of retail customers increased by 1.0%, consisting of an increase in residential and commercial customers of 1.0% and 1.6%, respectively, and a decrease in industrial customers of 0.1%, compared to the same period in the prior year.
Electric Operating Revenues - Other increased for the nine months ended September 30, 2013, compared to the same period in 2012, primarily due to an increase in transmission rates of $2.1 million as a result of the FERC rate case effective June 1, 2013. See Note 4,
Regulatory Actions
, of the Condensed Notes to Financial Statements for further discussion.
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:
|
|
|
|
•
|
transmission constraints
|
|
|
|
|
•
|
natural gas constraints
|
|
|
|
|
•
|
mandated power purchases; and
|
|
|
|
|
•
|
volatility of commodity prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
Energy Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel for power generation
|
$
|
163,127
|
|
|
$
|
123,992
|
|
|
$
|
39,135
|
|
|
31.6
|
%
|
|
$
|
412,904
|
|
|
$
|
285,799
|
|
|
$
|
127,105
|
|
|
44.5
|
%
|
|
|
Purchased power
|
172,582
|
|
|
171,687
|
|
|
895
|
|
|
0.5
|
%
|
|
383,386
|
|
|
388,494
|
|
|
(5,108
|
)
|
|
(1.3
|
)%
|
|
Energy Costs
|
$
|
335,709
|
|
|
$
|
295,679
|
|
|
$
|
40,030
|
|
|
13.5
|
%
|
|
$
|
796,290
|
|
|
$
|
674,293
|
|
|
$
|
121,997
|
|
|
18.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWhs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWhs Generated (in thousands)
|
5,242
|
|
|
5,105
|
|
|
137
|
|
|
2.7
|
%
|
|
13,310
|
|
|
12,264
|
|
|
1,046
|
|
|
8.5
|
%
|
|
|
Purchased Power (in thousands)
|
2,077
|
|
|
2,392
|
|
|
(315
|
)
|
|
(13.2
|
)%
|
|
4,225
|
|
|
5,415
|
|
|
(1,190
|
)
|
|
(22.0
|
)%
|
|
Total MWhs
|
7,319
|
|
|
7,497
|
|
|
(178
|
)
|
|
(2.4
|
)%
|
|
17,535
|
|
|
17,679
|
|
|
(144
|
)
|
|
(0.8
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average cost per MWh
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average fuel cost per MWh of Generated Power
|
$
|
31.12
|
|
|
$
|
24.29
|
|
|
$
|
6.83
|
|
|
28.1
|
%
|
|
$
|
31.02
|
|
|
$
|
23.30
|
|
|
$
|
7.72
|
|
|
33.1
|
%
|
|
|
Average cost per MWh of Purchased Power
|
$
|
83.09
|
|
|
$
|
71.78
|
|
|
$
|
11.32
|
|
|
15.8
|
%
|
|
$
|
90.74
|
|
|
$
|
71.74
|
|
|
$
|
19.00
|
|
|
26.5
|
%
|
|
|
Average total cost per MWh
|
$
|
45.87
|
|
|
$
|
39.44
|
|
|
$
|
6.43
|
|
|
16.3
|
%
|
|
$
|
45.41
|
|
|
$
|
38.14
|
|
|
$
|
7.27
|
|
|
19.1
|
%
|
Energy Costs and the average total cost per MWh increased for the three and nine months ended September 30, 2013, compared to the same period in 2012, primarily due to an increase in costs associated with higher natural gas prices partially offset by a decrease in the volume of purchased power which is typically more expensive than generated power. Overall volume decreased slightly primarily due to a decrease in CDDs, as shown in the table above.
|
|
|
|
•
|
Fuel for generation costs increased for the three months ended September 30, 2013, compared to the same period in 2012. Contributing to the increase was approximately $34.1 million due to higher natural gas prices, partially offset by a decrease in the volume of natural gas of $8.4 million. The increase in the volume of coal and the price of coal prices also contributed approximately $12.2 million and $1.2 million, respectively, to the increase in fuel for generation costs.
|
Fuel for generation costs increased for the nine months ended September 30, 2013, compared to the same periods in 2012. Contributing to the increase was approximately $96.4 million and $8.2 million due to higher natural gas prices and the volume of natural gas used, respectively. The increase in the volume of coal used and a slight increase in coal prices also contributed approximately $21.6 million and $0.9 million, to the increase in fuel for generation costs.
|
|
|
|
•
|
Purchased power costs increased for the three months ended September 30, 2013, compared to the same period in 2012. The increase in purchased power costs for the three month period was primarily due to a $23.6 million and a $3.7 million increase in the price of non-renewable purchases and renewable purchases, respectively. The increase in cost was largely offset by a decrease in the volume of non-renewable power purchases and renewable power purchases of approximately $16.4 million and $10.0 million, respectively.
|
Purchased power costs decreased for the nine months ended September 30, 2013, compared to the same period in 2012. The decrease is primarily due to $72.2 million and $35.6 million attributable to decreased volume of non-renewable power purchases and renewable purchases, respectively. The decrease was largely offset by an increase in the price of non-renewable purchases of approximately $70.8 million, primarily due to higher natural gas prices, and an increase in the price of renewable purchases of $31.9 million.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Energy
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
Deferred energy
|
$
|
(45,381
|
)
|
|
$
|
(22,685
|
)
|
|
$
|
(22,696
|
)
|
|
100.0%
|
|
$
|
(154,484
|
)
|
|
$
|
(15,461
|
)
|
|
$
|
(139,023
|
)
|
|
899.2%
|
Deferred Energy for the three months ended September 30, 2013 and 2012 include amortization of deferred energy of $(6.2) million and $(58.3) million, respectively, which primarily represents cash refunds to our customers for previous over-collections. Further
contributing to the deferred energy balance are under-collections of amounts recoverable in rates of $(39.2) million in 2013 and over-collections of $35.6 million in 2012.
Amounts for the nine months ended September 30, 2013 and 2012 include amortization of deferred energy of $(57.1) million and $(136.5) million, respectively which primarily represents cash refunds to our customers for previous over-collections. Further contributing to the deferred energy balance are under-collections of amounts recoverable in rates of $(97.4) million in 2013, and over-collections of $121.0 million in 2012.
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 4,
Regulatory Actions
, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
Energy efficiency program costs
|
$
|
13,998
|
|
|
$
|
28,492
|
|
|
$
|
(14,494
|
)
|
|
(50.9)%
|
|
$
|
32,807
|
|
|
$
|
65,466
|
|
|
$
|
(32,659
|
)
|
|
(49.9)%
|
|
Regulatory disallowance
|
$
|
11,866
|
|
|
$
|
—
|
|
|
$
|
11,866
|
|
|
N/A
|
|
$
|
11,866
|
|
|
$
|
—
|
|
|
$
|
11,866
|
|
|
N/A
|
|
Merger-related costs
|
$
|
5,620
|
|
|
$
|
—
|
|
|
$
|
5,620
|
|
|
N/A
|
|
$
|
14,487
|
|
|
$
|
—
|
|
|
$
|
14,487
|
|
|
N/A
|
|
Other operating expenses
|
$
|
70,844
|
|
|
$
|
65,372
|
|
|
$
|
5,472
|
|
|
8.4%
|
|
$
|
208,336
|
|
|
$
|
200,484
|
|
|
$
|
7,852
|
|
|
3.9%
|
|
Maintenance
|
$
|
11,208
|
|
|
$
|
12,533
|
|
|
$
|
(1,325
|
)
|
|
(10.6)%
|
|
$
|
45,172
|
|
|
$
|
52,594
|
|
|
$
|
(7,422
|
)
|
|
(14.1)%
|
|
Depreciation and amortization
|
$
|
68,849
|
|
|
$
|
66,975
|
|
|
$
|
1,874
|
|
|
2.8%
|
|
$
|
207,915
|
|
|
$
|
201,096
|
|
|
$
|
6,819
|
|
|
3.4%
|
For the three and nine months ended September 30, 2013 energy efficiency program costs decreased compared to the same periods in 2012, primarily due to lower EEPR base and amortization rates effective January 1, 2013. Reference Note 3,
Regulatory Actions
, of the Notes to the Financial Statements in the 2012 Form 10-K for more information on EEPR base and amortizations rate filings. See Note 4,
Regulatory Actions
of the Condensed Notes to Financial Statements for further information on EEPR rates effective October 2013.
The regulatory disallowance consists of $10.8 million related to EEIR revenues earned in 2012 (including carrying charges) in excess of NPC’s authorized ROR. The amount also includes a disallowance of approximately $1.1 million in deferred energy. See Note 4,
Regulatory Actions
, of the Condensed Notes to Financial Statements.
As discussed further in Note 2,
Merger-Related Activities,
of the Condensed Notes to Financial Statements, in May 2013, NVE and the Utilities entered into the MidAmerican Merger Agreement. As a result of the MidAmerican Merger, NPC incurred $5.6 million and $14.5 million in merger-related fees and stock compensation costs for the three and nine months ended September 30, 2013, respectively. Stock compensation costs increased primarily due to the increase in the average price per share of NVE common stock used to value the liability for stock compensation upon announcement of the MidAmerican Merger. NPC expects to incur additional merger-related fees upon consummation of the MidAmerican Merger.
Other operating expense increased for the three months ended September 30, 2013, compared to the same period in 2012, primarily due to $2.2 million in increased meter software maintenance and right of way leases, $1.2 million increase in overall generation operating expenses, $1.0 million increase due to IBEW 396 collective bargaining agreement ratification bonus and wage increase, and $0.4 million increase in regulatory expenses.
Other operating expense increased for the nine months ended September 30, 2013, compared to the same period in 2012, primarily due to a $2.5 million reduction in capitalized costs as a result of a decrease in construction activity, a $2.5 million increase in chemical and operating expenses at the Reid Gardner and Clark Generating Stations, a $2.3 million increase in outside consulting fees, $1.7 million increase in regulatory expenses and $1.6 million in increased meter software maintenance and right of way leases.
Maintenance expense decreased for the three months ended September 30, 2013, compared to the same period in 2012, primarily due to $1.2 million of major planned maintenance outages in 2012 at the Silverhawk and Harry Allen Generating Stations and lower expenses at Higgins Generating Station.
Maintenance expense decreased for the nine months ended September 30, 2013, compared to the same period in 2012, primarily due to $10.0 million of major maintenance outages in 2012 at the Silverhawk, Lenzie, Harry Allen and Reid Gardner Generating Stations, offset by $2.8 million of planned maintenance outages in 2013 at the Higgins and Clark Generating Stations.
Depreciation and amortization increased for the three and nine months ended September 30, 2013 compared to the same period in 2012, primarily due to general increases in plant-in-service.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(net of AFUDC-debt: $1,520, $1,528, $4,763 and $4,021)
|
$
|
52,856
|
|
|
$
|
51,784
|
|
|
$
|
1,072
|
|
|
2.1%
|
|
$
|
155,758
|
|
|
$
|
158,791
|
|
|
(3,033
|
)
|
|
(1.9)%
|
Interest expense increased for the three months ended September 30, 2013, compared to the same period in 2012 due to interest charges of $1.7 million for an assessment on a right of way lease, offset by a $0.3 million decrease in debt amortization expense and a $0.3 million decrease in interest for debt. See Note 6,
Long-Term Debt
, of the Notes to Financial Statements in the 2012 Form 10-K and Note 5,
Long-Term Debt
, in the Condensed Notes to Financial Statements, for additional information regarding long-term debt.
Interest expense decreased for the nine months ended September 30, 2013, compared to the same period in 2012 due to a $2.5 million decrease in interest costs primarily due to the redemption of the 6.5% General and Refunding Mortgage Notes, Series I in April 2012, an increase in AFUDC-debt of $0.7 million,
a $0.7 million decrease in interest for debt, and a $0.6 million decrease in debt amortization expense. Offsetting these decreases was interest charges of $1.7 million for an assessment on a right of way lease. See Note 6,
Long-Term Debt
, of the Notes to Financial Statements in the 2012 Form 10-K and Note 5,
Long-Term Debt
, in the Condensed Notes to Financial Statements, for additional information regarding long-term debt.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense)
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income (expense) on regulatory items
|
$
|
(194
|
)
|
|
$
|
(1,623
|
)
|
|
$
|
1,429
|
|
|
(88.0
|
)%
|
|
$
|
(1,177
|
)
|
|
$
|
(5,488
|
)
|
|
$
|
4,311
|
|
|
(78.6
|
)%
|
|
AFUDC-equity
|
$
|
1,959
|
|
|
$
|
1,833
|
|
|
$
|
126
|
|
|
6.9
|
%
|
|
$
|
6,151
|
|
|
$
|
4,823
|
|
|
$
|
1,328
|
|
|
27.5
|
%
|
|
Other income
|
$
|
1,948
|
|
|
$
|
7,096
|
|
|
$
|
(5,148
|
)
|
|
(72.5
|
)%
|
|
$
|
5,330
|
|
|
$
|
14,197
|
|
|
$
|
(8,867
|
)
|
|
(62.5
|
)%
|
|
Other expense
|
$
|
(1,966
|
)
|
|
$
|
(2,823
|
)
|
|
$
|
857
|
|
|
(30.4
|
)%
|
|
$
|
(6,200
|
)
|
|
$
|
(7,162
|
)
|
|
$
|
962
|
|
|
(13.4
|
)%
|
Interest income (expense) on regulatory items decreased for the three and nine months ended September 30, 2013, compared to the same periods in 2012. The decrease was primarily due to a decrease in interest on deferred energy of $2.9 million and $7.1 million for the three and nine month periods, respectively, as a result of lower over-collected balances in 2013. The decrease in interest income (expense) on regulatory items was partially offset by $1.0 million and $3.6 million for the three and nine month periods, respectively, as a result of decreased interest income due to lower regulatory asset balances. See Note 3,
Regulatory Actions
, of the Notes to Financial Statements in the 2012 Form 10-K.
AFUDC-equity increased for the three and nine months ended September 30, 2013, compared to the same periods in 2012, primarily due to various construction projects.
Other income decreased for the three months ended September 30, 2013, compared to the same periods in 2012, due to a $5.5 million gain on the sale of telecommunication towers in 2012, offset slightly by higher gains on investments in 2013.
Other income decreased for the nine months ended September 30, 2013, compared to the same periods in 2012, due to a $5.5 million gain on the sale of telecommunication towers in 2012, a $4.9 million Harry Allen Generating Station construction project settlement recorded in 2012, offset slightly by several items, none of which were individually material.
Other expense decreased for the three and nine months ended September 30, 2013 compared to the same period in 2012, by several items, none of which were individually material.
ANALYSIS OF CASH FLOWS
Cash From Operating Activities
NPC’s net cash flows from operating activities were $399.2 million and $514 million for the nine months ended September 30, 2013 and 2012, respectively.
The decrease in cash from operating activities was primarily due to:
|
|
|
|
•
|
Under-collection of energy costs due to higher energy costs of $214 million, offset by reduced refunds to customers of $79.7 million;
|
|
|
|
|
•
|
Reduced EEPR collections of $44.3 million;
|
|
|
|
|
•
|
Payments in 2013 for outages that occurred in 2012 at Reid Gardner and Lenzie Generating Stations of $22.7 million;
|
|
|
|
|
•
|
Timing of payments for energy costs of $4.9 million; and
|
|
|
|
|
•
|
Reduced revenues due to decreased BTER and EEPR rates combined with reduced customer energy usage due to cooler summer weather in 2013 compared to the same period in 2012.
|
The decrease in cash from operating activities was partially offset by:
|
|
|
|
•
|
Reduced coal purchases of $11.1 million; and
|
|
|
|
|
•
|
Reduced spend on renewable programs of $7.4 million.
|
Cash Used By Investing Activities
NPC’s net cash used by investing activities were $(136.2) million and $(197.4) million for the nine months ended September 30, 2013 and 2012, respectively.
The decrease in cash used by investing activities was primarily due to:
|
|
|
|
•
|
Reduced capital maintenance at Reid Gardner, Lenzie and Silverhawk Generating Stations of $54.2 million.
|
The decrease in cash used by investing activities was partially offset by:
|
|
|
|
•
|
Reduced CIAC received under the American Recovery and Reinvestment Act of 2009 of $10.6 million.
|
Cash Used By Financing Activities
NPC’s net cash flows used by financing activities were $(209) million and $(258) million for the nine months ended September 30, 2013 and 2012, respectively.
The decrease in cash used by financing activities was primarily due to:
|
|
|
|
•
|
A reduction in cash used to retire debt of $166.9 million; and
|
|
|
|
|
•
|
Decreased dividends to NVE of $14 million.
|
The decrease in cash used by financing activities was partially offset by:
|
|
|
|
•
|
Reduced draws from the NPC revolving credit facility of $135 million.
|
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. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions.
|
|
|
|
|
|
|
|
Available Liquidity as of September 30, 2013 (in millions)
|
|
|
NPC
|
|
Cash and Cash Equivalents
|
$
|
255.2
|
|
|
Balance available on Revolving Credit Facility
(1)
|
500.0
|
|
|
|
$
|
755.2
|
|
|
|
|
|
(1)
|
As of November 6, 2013, NPC had approximately $500 million available under its revolving credit facility.
|
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 has no further debt maturities for the remainder of 2013; however, NPC’s $125 million 7.375% General and Refunding Notes, Series U, will mature in January 2014. To meet these maturing debt obligations, NPC intends to use a combination of internally generated funds, its revolving credit facility, and/or the issuance of long-term debt. As of November 6, 2013, NPC has no borrowings on its revolving credit facility. NPC’s credit ratings on its senior secured debt remains at investment grade (see
Credit Ratings
below). NPC has not recently experienced any limitations in the credit markets, nor does NPC expect any significant limitations for the remainder of 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 has transitioned to slower growth, the amount of capital expenditures required 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 facility. Furthermore, with new investments now in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, current federal tax NOL and a decrease in capital expenditures, NPC expects to generate free cash flow in 2013; however, NPC’s cash flow may vary significantly from quarter to quarter due to the seasonality of our business. 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 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 under such circumstances, NPC may be required to delay capital expenditures, re-finance debt or receive capital contributions from NVE.
During the nine months ended September 30, 2013, NPC paid dividends to NVE of $105.0 million. On November 6, 2013, NPC declared a dividend to NVE of $73 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, environmental compliance, improvement and maintenance of facilities. As discussed, in Note 12,
Commitments and Contingencies,
of the 2012 Form 10-K, capital projects include NPC’s payment of Reid Gardner Generating Station Unit 4 from CDWR, which was completed in October 2013 for approximately $47.6 million.
During the nine months ended September 30, 2013, there were no material changes to contractual obligations as set forth in NPC’s 2012 Form 10-K.
Financing Transactions
In July 2013, NPC issued a notice of redemption to the bondholders for its $100 million Clark County Industrial Development Refunding Revenue Bonds, Series 2000A. In August 2013, NPC redeemed the aggregate principal amount outstanding of $98.1 million at 100% of the principal amount plus accrued interest with the use of cash on hand.
Ability to Issue Debt
NPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements, its revolving credit facility agreement, and the terms of certain NVE debt. As of September 30, 2013, the most restrictive of the factors below is the PUCN authority. As such, NPC may issue up to $725.0 million in long-term debt, in addition to the use of its existing credit facility. 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 September 30, 2013, 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 $725.0 million; (2) to refinance up to approximately $422.5 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $1.3 billion. In May 2013, NPC and SPPC filed a joint financing application with the PUCN, see Note 4,
Regulatory Actions
of the Condensed Notes to Financial Statements for further details;
|
|
|
|
|
b.
|
Financial covenants within NPC’s financing agreements - Under the NPC Credit Agreement, 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 1.00. Based on financial statements for the period ended September 30, 2013, NPC was in compliance with this covenant and could incur up to $3.2
billion of additional indebtedness
|
All other financial covenants contained in NPC’s financing agreements are suspended as NPC’s senior secured debt is currently 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 $3.7
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 and NVE’s 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 the NPC Indenture.
The NPC Indenture creates a lien on substantially all of NPC’s properties in Nevada. As of September 30, 2013, $3.7 billion of NPC’s General and Refunding Mortgage Securities were outstanding. NPC had the capacity to issue $1.8 billion
of General and Refunding Mortgage Securities as of September 30, 2013. 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. Although specific assets in CWIP can also qualify as property additions, the amount of bond capacity listed above does not reflect eligible property in CWIP.
NPC also has the ability to release property from the lien of the NPC Indenture on the basis of net property additions, cash and/or retired bonds. To the extent NPC releases property from the lien of the NPC Indenture, it will reduce the amount of securities issuable under the NPC Indenture.
Credit Ratings
The liquidity of NPC, the cost and availability of borrowing by NPC under the NPC Credit Agreement, 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 ratings for NPC’s debt. On May 22, 2013, Moody’s upgraded NPC’s ratings. On May 30, 2013, Fitch and S&P upgraded NPC’s rating outlook from Stable to Positive. NPC’s senior secured debt is rated investment grade by three NRSRO’s: Fitch, Moody’s and S&P. The senior secured debt credit ratings are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rating Agency
|
|
|
|
|
Fitch
(1)
|
|
Moody’s
(2)
|
|
S&P
(3)
|
|
NPC
|
Sr. Secured Debt
|
|
BBB+*
|
|
A3*
|
|
BBB+*
|
|
|
|
|
(1)
|
Fitch’s lowest level of “investment grade” credit rating is BBB-.
|
|
|
|
|
(2)
|
Moody’s lowest level of “investment grade” credit rating is Baa3.
|
|
|
|
|
(3)
|
S&P’s lowest level of “investment grade” credit rating is BBB-.
|
Fitch’s and S&P’s rating outlooks are Positive, while Moody’s rating outlook is Stable for NPC.
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 agreement 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 September 30, 2013 for all suppliers continuing to provide power under a WSPP agreement would approximate a $49.7 million payment or obligation to NPC. These contracts qualify for the normal purchases and normal sales 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 September 30, 2013, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $87.2 million. Of this amount, approximately $26 million would be required if NPC’s Senior Unsecured ratings are rated below BB (S&P) or Ba3 (Moody’s) and an additional amount of approximately $61.2 million would be required if NPC’s Senior Unsecured and Senior Secured ratings, both are downgraded to below investment grade.
Financial Gas Hedges
NPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed in Note 6,
Long Term Debt,
of the Notes to Financial Statements in the 2012 Form 10-K, NPC’s
Financing Transactions
, the availability under the NPC’s revolving credit facility 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 facility shall at no time exceed 50% of the total commitments then in effect under the credit facility. Currently, there are no negative mark-to-market exposures that would impact borrowings of NPC. If deemed prudent, NPC may 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 their respective 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.
Change of Control Provisions; Consent of Lenders
The MidAmerican Merger will accelerate the vesting and settlement of equity compensation awards to executives and employees which will be cashed out upon consummation of the MidAmerican Merger. Certain executives are also entitled to additional change of
control payments in the event of an occurrence of a qualified termination. The consummation of the MidAmerican Merger will also trigger mandatory redemption requirements under financing agreements of NPC. As a result, NPC will be required to offer to purchase approximately $3.1 billion of debt at 101% of par within 10 days after the MidAmerican Merger closing. At this time, NPC is unable to determine the extent to which holders of these debt securities will accept such tender offers. The average interest rate under NPC’s debt securities is approximately 6.42%. To the extent that debt securities are tendered pursuant to the required tender offers, NPC intends to fund the purchases using a combination of internal funds, its revolving credit facility or the issuance of long-term debt. Furthermore, NPC was required to obtain consents from lenders under the terms of its revolving credit facility before consummating the MidAmerican Merger. In November 2013, NPC amended its revolving credit facility to permit the MidAmerican Merger.
SIERRA PACIFIC POWER COMPANY
RESULTS OF OPERATIONS
SPPC recognized net income of $29.3 million for the three months ended September 30, 2013, compared to net income of $34.4 million for the same period in 2012. During the nine months ended September 30, 2013, SPPC recognized net income of approximately $61.9 million compared to $65.8 million for the same period in 2012.
During the nine months ended September 30, 2013, SPPC paid dividends to NVE of $40.0 million. On November 6, 2013, SPPC declared a dividend of $37.0 million to NVE.
Gross margin is presented by SPPC in order to provide information by segment that management believes aids the reader in determining how profitable the electric and gas businesses are 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 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, energy efficiency program costs and regulatory disallowances, provides a measure of income available to support the other operating expenses of SPPC. For reconciliation to operating income, see Note 3,
Segment Information
, of the Condensed Notes to Financial Statements. Gross margin changes are primarily due to general base rate adjustments (which are required by statute to be filed every three years).
The components of gross margin were (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
$
|
213,463
|
|
|
$
|
212,073
|
|
|
$
|
1,390
|
|
|
0.7
|
%
|
|
$
|
560,392
|
|
|
$
|
549,886
|
|
|
$
|
10,506
|
|
|
1.9
|
%
|
|
|
Gas
|
13,543
|
|
|
12,077
|
|
|
1,466
|
|
|
12.1
|
%
|
|
73,480
|
|
|
77,543
|
|
|
(4,063
|
)
|
|
(5.2
|
)%
|
|
|
|
$
|
227,006
|
|
|
$
|
224,150
|
|
|
$
|
2,856
|
|
|
1.3
|
%
|
|
$
|
633,872
|
|
|
$
|
627,429
|
|
|
$
|
6,443
|
|
|
1.0
|
%
|
|
Energy Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel for power generation
|
54,827
|
|
|
47,324
|
|
|
7,503
|
|
|
15.9
|
%
|
|
141,277
|
|
|
115,137
|
|
|
26,140
|
|
|
22.7
|
%
|
|
|
Purchased power
|
33,388
|
|
|
33,999
|
|
|
(611
|
)
|
|
(1.8
|
)%
|
|
114,755
|
|
|
98,400
|
|
|
16,355
|
|
|
16.6
|
%
|
|
|
Gas purchased for resale
|
7,383
|
|
|
5,382
|
|
|
2,001
|
|
|
37.2
|
%
|
|
62,277
|
|
|
46,491
|
|
|
15,786
|
|
|
34.0
|
%
|
|
|
Deferred energy - electric - net
|
(7,925
|
)
|
|
(5,498
|
)
|
|
(2,427
|
)
|
|
44.1
|
%
|
|
(44,223
|
)
|
|
(13,854
|
)
|
|
(30,369
|
)
|
|
219.2
|
%
|
|
|
Deferred energy - gas - net
|
(1,964
|
)
|
|
(853
|
)
|
|
(1,111
|
)
|
|
130.2
|
%
|
|
(22,315
|
)
|
|
(970
|
)
|
|
(21,345
|
)
|
|
2,201
|
%
|
|
Energy efficiency program costs
|
2,044
|
|
|
4,092
|
|
|
(2,048
|
)
|
|
(50.0
|
)%
|
|
5,679
|
|
|
11,143
|
|
|
(5,464
|
)
|
|
(49.0
|
)%
|
|
Regulatory disallowance
|
5,469
|
|
|
—
|
|
|
5,469
|
|
|
N/A
|
|
|
5,469
|
|
|
—
|
|
|
5,469
|
|
|
N/A
|
|
|
|
Total Costs
|
$
|
93,222
|
|
|
$
|
84,446
|
|
|
$
|
8,776
|
|
|
10.4
|
%
|
|
$
|
262,919
|
|
|
$
|
256,347
|
|
|
$
|
6,572
|
|
|
2.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost by Segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
$
|
87,803
|
|
|
$
|
79,917
|
|
|
$
|
7,886
|
|
|
9.9
|
%
|
|
$
|
222,957
|
|
|
$
|
210,826
|
|
|
$
|
12,131
|
|
|
5.8
|
%
|
|
|
Gas
|
5,419
|
|
|
4,529
|
|
|
890
|
|
|
19.7
|
%
|
|
39,962
|
|
|
45,521
|
|
|
(5,559
|
)
|
|
(12.2
|
)%
|
|
|
|
$
|
93,222
|
|
|
$
|
84,446
|
|
|
$
|
8,776
|
|
|
10.4
|
%
|
|
$
|
262,919
|
|
|
$
|
256,347
|
|
|
$
|
6,572
|
|
|
2.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Margin by Segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
$
|
125,660
|
|
|
$
|
132,156
|
|
|
$
|
(6,496
|
)
|
|
(4.9
|
)%
|
|
$
|
337,435
|
|
|
$
|
339,060
|
|
|
$
|
(1,625
|
)
|
|
(0.5
|
)%
|
|
|
Gas
|
8,124
|
|
|
7,548
|
|
|
576
|
|
|
7.6
|
%
|
|
33,518
|
|
|
32,022
|
|
|
1,496
|
|
|
4.7
|
%
|
|
|
Gross Margin
|
$
|
133,784
|
|
|
$
|
139,704
|
|
|
$
|
(5,920
|
)
|
|
(4.2
|
)%
|
|
$
|
370,953
|
|
|
$
|
371,082
|
|
|
$
|
(129
|
)
|
|
—
|
%
|
Electric gross margin decreased for the nine months ended September 30, 2013 compared to the same period in 2012. The decrease is primarily due to the disallowance of EEIR revenue and carrying charge of $5.5 million (pre-tax) and a provision of $4.0 million (pre-tax) recorded against 2013 EEIR revenues as a result of the precedent set by the PUCN’s ruling in NPC’s EEIR filing, as well as, SPPC’s estimated rate of return in excess of its allowed rate of return as of September 30, 2013. See Note 4,
Regulatory Actions
, of the Condensed Notes to Financial Statements for further discussion of the EEIR disallowance. Also contributing to the increase was customer growth and usage. The decrease was largely offset by an increase in customer usage, customer growth and an increase in sales of $3.8 million to Cal Peco 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 in the 2012 Form 10-K).
Gas gross margin for the three and nine months ended September 30, 2013, compared to the same periods in 2012 increased slightly primarily due to weather.
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° F. HDDs measure heating energy demand and indicate how far the average temperature fell below 65° F. CDDs measure cooling energy demand and indicate how far the temperature averaged above 65° F. For example, if a location had a mean temperature of 60° F on day 1 and 80° F 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
SPPC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heating
|
85
|
|
|
1
|
|
|
84
|
|
|
N/A
|
|
2,859
|
|
|
2,677
|
|
|
182
|
|
|
6.8
|
%
|
|
Cooling
|
914
|
|
|
1,020
|
|
|
(106
|
)
|
|
(10.4
|
)%
|
|
1,177
|
|
|
1,255
|
|
|
(78
|
)
|
|
(6.2
|
)%
|
The causes for significant changes in specific lines comprising the results of operations for SPPC for the respective periods are provided below (dollars in thousands except for amounts per unit):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric Operating Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
Operating Revenues:
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
|
Residential
|
$
|
68,808
|
|
|
$
|
68,677
|
|
|
$
|
131
|
|
|
0.2
|
%
|
|
$
|
184,309
|
|
|
$
|
180,953
|
|
|
$
|
3,356
|
|
|
1.9
|
%
|
|
|
Commercial
|
78,080
|
|
|
78,409
|
|
|
(329
|
)
|
|
(0.4
|
)%
|
|
201,761
|
|
|
200,912
|
|
|
849
|
|
|
0.4
|
%
|
|
|
Industrial
|
48,722
|
|
|
48,541
|
|
|
181
|
|
|
0.4
|
%
|
|
122,082
|
|
|
120,234
|
|
|
1,848
|
|
|
1.5
|
%
|
|
|
|
Retail Revenues
|
195,610
|
|
|
195,627
|
|
|
(17
|
)
|
|
—
|
%
|
|
508,152
|
|
|
502,099
|
|
|
6,053
|
|
|
1.2
|
%
|
|
|
Other
|
17,853
|
|
|
16,446
|
|
|
1,407
|
|
|
8.6
|
%
|
|
52,240
|
|
|
47,787
|
|
|
4,453
|
|
|
9.3
|
%
|
|
|
|
Total Operating Revenues
|
$
|
213,463
|
|
|
$
|
212,073
|
|
|
$
|
1,390
|
|
|
0.7
|
%
|
|
$
|
560,392
|
|
|
$
|
549,886
|
|
|
$
|
10,506
|
|
|
1.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail sales in thousands of MWhs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
671
|
|
|
667
|
|
|
4
|
|
|
0.6
|
%
|
|
1,794
|
|
|
1,737
|
|
|
57
|
|
|
3.3
|
%
|
|
|
Commercial
|
851
|
|
|
849
|
|
|
2
|
|
|
0.2
|
%
|
|
2,268
|
|
|
2,233
|
|
|
35
|
|
|
1.6
|
%
|
|
|
Industrial
|
701
|
|
|
686
|
|
|
15
|
|
|
2.2
|
%
|
|
2,092
|
|
|
2,005
|
|
|
87
|
|
|
4.3
|
%
|
|
Retail sales in thousands of MWhs
|
2,223
|
|
|
2,202
|
|
|
21
|
|
|
1.0
|
%
|
|
6,154
|
|
|
5,975
|
|
|
179
|
|
|
3.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average retail revenue per MWh
|
$
|
87.99
|
|
|
$
|
88.84
|
|
|
$
|
(0.85
|
)
|
|
(1.0
|
)%
|
|
$
|
82.57
|
|
|
$
|
84.03
|
|
|
$
|
(1.46
|
)
|
|
(1.7
|
)%
|
Retail revenue decreased for the three months ended September 30, 2013, as compared to the same period in 2012, primarily due to a provision of $4.0 million recorded against 2013 EEIR revenues as a result of the precedent set by the PUCN’s ruling in SPPC’s EEIR filing and SPPC’s estimated rate of return in excess of its allowed rate of return as of September 30, 2013. See Note 4,
Regulatory Actions
, of the Condensed Notes to Financial Statements for further discussion of the EEIR disallowance. Also contributing to the decrease was $2.0 million of rate decreases in EEPR due to SPPC’s annual Deferred Energy cases effective January 1, 2013. These decreases were largely offset by $5.2 million of rate increases as a result of various BTER and DEAA quarterly and a $1.1 million increase from customer growth. See Note 3,
Regulatory Actions
of the Notes to Financial Statements in the 2012 Form 10-K.
For the three months ended September 30, 2013, the average number of residential and commercial customers increased 0.7% and 2.5%, respectively, while industrial customers remained the same compared to the same period in 2012.
Electric operating revenues - Other increased for the three months ended September 30, 2013, compared to the same periods in 2012, primarily due to an increase in energy sales of $1.5 million 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 in the 2012 Form 10-K).
Retail revenue increased for the nine months ended September 30, 2013, as compared to the same period in 2012, due to a $7.6 million increase in customer usage primarily due to an unusually cold January and unusually hot June and July, $4.8 million in rate increases due to various BTER and DEAA quarterly updates (see Note 4,
Regulatory Actions
of the Notes to Financial Statements) and a $1.8 million increase from customer growth. These increases were partially offset by $5.4 million of rate decreases in EEPR due to SPPC’s annual Deferred Energy cases effective January 1, 2013 and a provision of $4.0 million for 2013 EEIR revenues as a result of the precedent set by the PUCN’s ruling in SPPC’s EEIR filing and SPPC’s estimated rate of return in excess of its allowed rate of return as of September 30, 2013. See Note 4,
Regulatory Actions
of the Condensed Notes to Financial Statements).
For the nine months ended September 30, 2013, the average number of residential, commercial, and industrial customers increased 0.7%, 2.1%, and 1.8%, respectively, compared to the same period in 2012.
Electric operating revenues - Other increased for the nine months ended September 30, 2013, compared to the same periods in 2012, primarily due to a $3.8 million increase in 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 in the 2012 Form 10-K) and $0.7 million increase in miscellaneous revenues.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Operating Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
Gas Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
$
|
7,750
|
|
|
$
|
7,306
|
|
|
$
|
444
|
|
|
6.1
|
%
|
|
$
|
39,781
|
|
|
$
|
45,104
|
|
|
$
|
(5,323
|
)
|
|
(11.8
|
)%
|
|
|
Commercial
|
2,680
|
|
|
2,583
|
|
|
97
|
|
|
3.8
|
%
|
|
14,657
|
|
|
17,961
|
|
|
(3,304
|
)
|
|
(18.4
|
)%
|
|
|
Industrial
|
1,041
|
|
|
906
|
|
|
135
|
|
|
14.9
|
%
|
|
4,591
|
|
|
5,115
|
|
|
(524
|
)
|
|
(10.2
|
)%
|
|
|
Retail Revenues
|
11,471
|
|
|
10,795
|
|
|
676
|
|
|
6.3
|
%
|
|
59,029
|
|
|
68,180
|
|
|
(9,151
|
)
|
|
(13.4
|
)%
|
|
|
Wholesale Revenues
|
1,359
|
|
|
563
|
|
|
796
|
|
|
141.4
|
%
|
|
12,149
|
|
|
7,033
|
|
|
5,116
|
|
|
72.7
|
%
|
|
|
Miscellaneous
|
713
|
|
|
719
|
|
|
(6
|
)
|
|
(0.8
|
)%
|
|
2,302
|
|
|
2,330
|
|
|
(28
|
)
|
|
(1.2
|
)%
|
|
|
Total Gas Revenues
|
$
|
13,543
|
|
|
$
|
12,077
|
|
|
$
|
1,466
|
|
|
12.1
|
%
|
|
$
|
73,480
|
|
|
$
|
77,543
|
|
|
$
|
(4,063
|
)
|
|
(5.2
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail sales in thousands of Dths
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
698
|
|
|
642
|
|
|
56
|
|
|
8.7
|
%
|
|
6,039
|
|
|
5,613
|
|
|
426
|
|
|
7.6
|
%
|
|
|
Commercial
|
400
|
|
|
374
|
|
|
26
|
|
|
7.0
|
%
|
|
3,086
|
|
|
2,939
|
|
|
147
|
|
|
5.0
|
%
|
|
|
Industrial
|
190
|
|
|
153
|
|
|
37
|
|
|
24.2
|
%
|
|
986
|
|
|
876
|
|
|
110
|
|
|
12.6
|
%
|
|
Retail sales in thousands of Dths
|
1,288
|
|
|
1,169
|
|
|
119
|
|
|
10.2
|
%
|
|
10,111
|
|
|
9,428
|
|
|
683
|
|
|
7.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average retail revenue per Dth
|
$
|
8.91
|
|
|
$
|
9.23
|
|
|
$
|
(0.32
|
)
|
|
(3.5
|
)%
|
|
$
|
5.84
|
|
|
$
|
7.23
|
|
|
$
|
(1.39
|
)
|
|
(19.2
|
)%
|
SPPC’s retail gas revenues increased for the three months ended September 30, 2013, compared to the same period in 2012, primarily due to a $565 thousand increase in usage, due to an increase in HDDs as shown in the table above.
SPPC’s retail gas revenues decreased for the nine months ended September 30, 2013, compared to the same period in 2012, primarily due to a $12.4 million decrease in retail rates as a result of SPPC’s annual Deferred Energy cases, effective October 1, 2012, and various BTER and DEAA quarterly updates (see Note 4,
Regulatory Actions
of the Notes to Financial Statements in the 2012 Form 10-K). The decrease was partially offset by a $2.8 million increase in customer usage, due to an increase in HDDs as shown in the table above.
Wholesale revenues increased for the three and nine months ended September 30, 2013, compared to the same periods in 2012, primarily due to an increase in natural gas prices.
Energy Costs
Energy Costs include purchased power and fuel for generation. 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 purchased power versus fuel for generation can vary significantly as the company meets the demands of the season. These factors include, but are not limited to:
|
|
|
|
•
|
transmission constraints
|
|
|
|
|
•
|
gas transportation constraints
|
|
|
|
|
•
|
natural gas constraints
|
|
|
|
|
•
|
mandated power purchases
|
|
|
|
|
•
|
generation efficiency; and
|
|
|
|
|
•
|
volatility of commodity prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
Energy Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel for power generation
|
$
|
54,828
|
|
|
$
|
47,324
|
|
|
$
|
7,504
|
|
|
15.9
|
%
|
|
$
|
141,277
|
|
|
$
|
115,137
|
|
|
$
|
26,140
|
|
|
22.7
|
%
|
|
|
Purchased power
|
33,388
|
|
|
33,999
|
|
|
(611
|
)
|
|
(1.8
|
)%
|
|
114,755
|
|
|
98,400
|
|
|
16,355
|
|
|
16.6
|
%
|
|
Total Energy Costs
|
$
|
88,216
|
|
|
$
|
81,323
|
|
|
$
|
6,893
|
|
|
8.5
|
%
|
|
$
|
256,032
|
|
|
$
|
213,537
|
|
|
$
|
42,495
|
|
|
19.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWhs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWhs Generated (in thousands)
|
1,580
|
|
|
1,512
|
|
|
68
|
|
|
4.5
|
%
|
|
3,829
|
|
|
3,829
|
|
|
—
|
|
|
—
|
%
|
|
|
Purchased Power (in thousands)
|
916
|
|
|
971
|
|
|
(55
|
)
|
|
(5.7
|
)%
|
|
3,169
|
|
|
3,031
|
|
|
138
|
|
|
4.6
|
%
|
|
Total MWhs
|
2,496
|
|
|
2,483
|
|
|
13
|
|
|
0.5
|
%
|
|
6,998
|
|
|
6,860
|
|
|
138
|
|
|
2.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average cost per MWh
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average fuel cost per MWh of Generated Power
|
$
|
34.70
|
|
|
$
|
31.30
|
|
|
$
|
3.40
|
|
|
10.9
|
%
|
|
$
|
36.90
|
|
|
$
|
30.07
|
|
|
$
|
6.83
|
|
|
22.7
|
%
|
|
|
Average cost per MWh of Purchased Power
|
$
|
36.45
|
|
|
$
|
35.01
|
|
|
$
|
1.44
|
|
|
4.1
|
%
|
|
$
|
36.21
|
|
|
$
|
32.46
|
|
|
$
|
3.75
|
|
|
11.5
|
%
|
|
|
Average total cost per MWh
|
$
|
35.34
|
|
|
$
|
32.75
|
|
|
$
|
2.59
|
|
|
7.9
|
%
|
|
$
|
36.59
|
|
|
$
|
31.13
|
|
|
$
|
5.46
|
|
|
17.5
|
%
|
Energy costs and average cost per MWh increased for the three and nine months ended September 30, 2013, compared to the same period in 2012 primarily due to higher natural gas prices.
|
|
|
|
•
|
Fuel for generation costs increased for the three months ended September 30, 2013, compared to the same period in 2012. Contributing to the increase was $5.2 million due to higher natural gas and coal prices. Also contributing to the increase was $1.2 million and $1.1 million in volume increases of coal and natural gas used for generation, respectively.
|
Fuel for generation costs increased for the nine months ended September 30, 2013 compared to the same period in 2012. Contributing to the increase was $26.8 million in higher natural gas prices. Higher costs were partially offset by a decrease in natural gas volume of approximately $13.0 million and an increase of $12.0 million in coal volume, respectively.
|
|
|
|
•
|
Purchased power costs decreased for the three months ended September 30, 2013 compared to the same period in 2012. Approximately $1.8 million of the decrease is primarily due to decreased volume. The decrease was partially offset by an increase in the price of purchased power of $1.2 million.
|
Purchased power costs increased for the nine months ended September 30, 2013 compared to the same period in 2012. Contributing to the increase was an increase in price of $10.9 million and $1.5 million for non-renewable and renewable energy, respectively. Approximately $4.0 million of the increase was due to an increase in volume of power purchased.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Purchased for Resale
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
Gas purchased for resale
|
$
|
7,383
|
|
|
$
|
5,382
|
|
|
$
|
2,001
|
|
|
37.2
|
%
|
|
$
|
62,277
|
|
|
$
|
46,491
|
|
|
$
|
15,786
|
|
|
34.0
|
%
|
|
Gas purchased for resale (in thousands of Dths)
|
1,688
|
|
|
1,349
|
|
|
339
|
|
|
25.1
|
%
|
|
13,614
|
|
|
12,636
|
|
|
978
|
|
|
7.7
|
%
|
|
Average cost per Dth
|
$
|
4.37
|
|
|
$
|
3.99
|
|
|
$
|
0.38
|
|
|
9.5
|
%
|
|
$
|
4.57
|
|
|
$
|
3.68
|
|
|
$
|
0.89
|
|
|
24.2
|
%
|
Gas purchased for resale increased for the three months ended September 30, 2013, compared to the same period in 2012. Approximately $1.5 million of the increase is due to an increase in volume and approximately $0.5 million is due to higher natural gas prices. Volume increased primarily due to an increase in HDDs as shown in the table above.
Gas purchased for resale increased for the nine months ended September 30, 2013, compared to the same period in 2012. Approximately $11.3 million of the increase is due higher natural gas prices and approximately $4.5 million is due to an increase in volume. Volume increased primarily due to an increase in HDDs as shown in the table above.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Energy
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
Deferred energy - electric - net
|
$
|
(7,925
|
)
|
|
$
|
(5,498
|
)
|
|
$
|
(2,427
|
)
|
|
44.1%
|
|
$
|
(44,223
|
)
|
|
$
|
(13,854
|
)
|
|
$
|
(30,369
|
)
|
|
219.2%
|
|
Deferred energy - gas - net
|
$
|
(1,964
|
)
|
|
$
|
(853
|
)
|
|
$
|
(1,111
|
)
|
|
130.2%
|
|
$
|
(22,315
|
)
|
|
$
|
(970
|
)
|
|
$
|
(21,345
|
)
|
|
2,200.5%
|
|
|
$
|
(9,889
|
)
|
|
$
|
(6,351
|
)
|
|
$
|
(3,538
|
)
|
|
55.7%
|
|
$
|
(66,538
|
)
|
|
$
|
(14,824
|
)
|
|
$
|
(51,714
|
)
|
|
348.9%
|
Deferred energy - electric for the three months ended September 30, 2013 and 2012 include amortization of deferred energy of $(4.5) million and $(19.3) million, respectively, which primarily represents cash refunds to our customers for previous over-collections. Further contributing to the deferred energy - electric balance are under-collections of amounts recoverable in rates of $(3.4) million in 2013 and over-collections of $13.8 million in 2012.
Deferred energy - electric for the nine months ended September 30, 2013 and 2012 include amortization of deferred energy of $(23.7) million and $(65.0) million, respectively, which primarily represents cash refunds to our customers for previous over-collections. Further contributing to the deferred energy - electric balance are under-collections of amounts recoverable in rates of $(20.5) million in 2013 and over-collections of $51.2 million in 2012.
Deferred energy - gas for the three months ended September 30, 2013 and 2012 include amortization of deferred energy of $(1.9) million and $(2.2) million, respectively, which primarily represents cash refunds to our customers for previous over-collections. Further contributing to the deferred energy - gas balance for 2012 were over-collections recoverable in rates of $1.3 million. Under collections for the three months ended September 30, 2013 are immaterial.
Deferred energy - gas for the nine months ended September 30, 2013 and 2012 include amortization of deferred energy of $(19.0) million and $(19.9) million, respectively, which primarily represents cash refunds to our customers for previous over-collections. Further contributing to the deferred energy - gas balance are under-collections of amounts recoverable in rates of $(3.3) million in 2013 and over-collections of $18.9 million in 2012.
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 4,
Regulatory Actions
of the Condensed Notes to Financial Statements for further detail of deferred energy balances.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
Energy efficiency program costs
|
$
|
2,044
|
|
|
$
|
4,092
|
|
|
$
|
(2,048
|
)
|
|
(50.0)%
|
|
$
|
5,679
|
|
|
$
|
11,143
|
|
|
$
|
(5,464
|
)
|
|
(49.0)%
|
|
Regulatory disallowance
|
$
|
5,469
|
|
|
$
|
—
|
|
|
$
|
5,469
|
|
|
N/A
|
|
$
|
5,469
|
|
|
$
|
—
|
|
|
$
|
5,469
|
|
|
N/A
|
|
Merger-related costs
|
$
|
2,008
|
|
|
$
|
—
|
|
|
$
|
2,008
|
|
|
N/A
|
|
$
|
5,528
|
|
|
$
|
—
|
|
|
$
|
5,528
|
|
|
N/A
|
|
Other operating expenses
|
$
|
34,394
|
|
|
$
|
34,128
|
|
|
$
|
266
|
|
|
0.8%
|
|
$
|
106,455
|
|
|
$
|
104,214
|
|
|
$
|
2,241
|
|
|
2.2%
|
|
Maintenance
|
$
|
5,968
|
|
|
$
|
6,481
|
|
|
$
|
(513
|
)
|
|
(7.9)%
|
|
$
|
20,956
|
|
|
$
|
23,596
|
|
|
$
|
(2,640
|
)
|
|
(11.2)%
|
|
Depreciation and amortization
|
$
|
27,952
|
|
|
$
|
27,537
|
|
|
$
|
415
|
|
|
1.5%
|
|
$
|
83,772
|
|
|
$
|
80,594
|
|
|
$
|
3,178
|
|
|
3.9%
|
For the three and nine months ended September 30, 2013, energy efficiency program costs decreased compared to the same periods in 2012, primarily due to lower EEPR base and amortization rates effective January 1, 2013. Reference Note 3,
Regulatory Actions
, of the Notes to the Financial Statements in the 2012 Form 10-K for more information on EEPR base and amortizations rate filings. See Note 4,
Regulatory Actions
of the Condensed Notes to Financial Statements for further information on EEPR rates effective October 2013.
The regulatory disallowance consists of $5.5 million related to EEIR revenues earned in 2012 (including carrying charges) in excess of SPPC’s authorized ROR. See Note 4,
Regulatory Actions
, of the Condensed Notes to Financial Statements.
As discussed further in Note 2,
Merger-Related Activities,
of the Condensed Notes to Financial Statements, in May 2013, NVE and the Utilities entered into the MidAmerican Merger Agreement. As a result of the MidAmerican Merger, SPPC incurred $2.0 million and $5.5 million in merger-related fees and stock compensation costs for the three and nine months ended September 30, 2013, respectively. Stock compensation costs increased primarily due to the increase in the average price per share of NVE common stock used to value the liability for stock compensation upon announcement of the MidAmerican Merger. SPPC expects to incur additional merger-related fees upon consummation of the MidAmerican Merger.
Other operating expense increased for the three months ended September 30, 2013, compared to the same period in 2012, primarily due to $0.7 million increase in regulatory expenses. The increase was offset by a $0.7 million decrease due to a 2012 claim settlement.
Other operating expense increased for the nine months ended September 30, 2013, compared to the same period in 2012, primarily due to $2.6 million increase in regulatory expenses, $0.9 million reduction in capitalized costs as a result of a decrease in construction activity. The increase was partially offset by a $0.9 million decrease in pension and benefit costs.
Maintenance expense decreased for the three months ended September 30, 2013, compared to the same period in 2012, primarily due to $0.2 million of 2012 major outage at the Tracy Generating Station and $0.2 million in 2012 maintenance at the Ft. Churchill Generating Station.
Maintenance expense decreased for the nine months ended September 30, 2013, compared to the same period in 2012, primarily due to $3.7 million of planned major outages in 2012 at the Tracy, Valmy and Ft. Churchill Generating Stations, and $0.3 million of 2012 transmission poles maintenance expenses, offset by $1.5 million of 2013 turbine maintenance at the Tracy Generating Station.
Depreciation and amortization increased for the three and nine months ended September 30, 2013, compared to the same period in 2012, primarily due to general increases in plant-in-service.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(net of AFUDC-debt: $437, $448, $1,007 and $1,458)
|
(15,122
|
)
|
|
(15,298
|
)
|
|
176
|
|
|
(1.2)%
|
|
(46,020
|
)
|
|
(47,650
|
)
|
|
1,630
|
|
|
(3.4)%
|
Interest expense is comparable to prior period for the three months ended September 30, 2013.
Interest expense decreased $1.6 million for the nine months ended September 30, 2013, as compared to the same period in 2012, primarily due to decreased debt amortization expense of $1.6 million. See Note 6,
Long-Term Debt
of the Notes to Financial Statements in the 2012 Form 10-K for additional information regarding long-term debt.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense)
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
2013
|
|
2012
|
|
Variance
|
|
% Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income (expense) on regulatory items
|
$
|
(87
|
)
|
|
$
|
(401
|
)
|
|
$
|
314
|
|
|
(78.3
|
)%
|
|
$
|
53
|
|
|
$
|
(715
|
)
|
|
$
|
768
|
|
|
(107.4
|
)%
|
|
AFUDC-equity
|
$
|
632
|
|
|
$
|
582
|
|
|
$
|
50
|
|
|
8.6
|
%
|
|
$
|
1,579
|
|
|
$
|
1,843
|
|
|
$
|
(264
|
)
|
|
(14.3
|
)%
|
|
Other income
|
$
|
983
|
|
|
$
|
1,399
|
|
|
$
|
(416
|
)
|
|
(29.7
|
)%
|
|
$
|
4,641
|
|
|
$
|
4,181
|
|
|
$
|
460
|
|
|
11.0
|
%
|
|
Other expense
|
$
|
(982
|
)
|
|
$
|
(998
|
)
|
|
$
|
16
|
|
|
(1.6
|
)%
|
|
$
|
(3,803
|
)
|
|
$
|
(3,609
|
)
|
|
$
|
(194
|
)
|
|
5.4
|
%
|
Interest income (expense) on regulatory items decreased for the three and nine months ended September 30, 2013, compared to the same periods in 2012, primarily due to $1.2 million and $2.9 million, respectively, of decreases in interest on deferred energy as a result of lower over-collected balances in 2013, offset by $0.7 million and $1.7 million, respectively, of decreases in carrying charges on solar conservation programs and by $0.2 million and $0.4 million, respectively, of decreases in interest income due to lower regulatory asset balances. See Note 4,
Regulatory Actions
of the Condensed Notes to Financial Statements for further details of deferred energy balances.
AFUDC-equity increased slightly for the three months ended September 30, 2013 compared to the same period in 2012, primarily due to an increase in base construction projects. AFUDC-equity decreased slightly for the nine months ended September 30, 2013 compared to the same period in 2012, primarily due to the completion of the NV Energize.
Other income decreased for the three months ended September 30, 2013, compared to the same period in 2012, primarily due to higher refunds in 2012, offset by several items, none of which were individually material.
Other income increased for the nine months ended September 30, 2013, compared to the same period in 2012, primarily due to a $1.9 million insurance settlement in 2013, offset by $1.1 million settlement with CA ISO in 2011 recognized in 2012, and higher refunds in 2012. See Note 3,
Regulatory Actions, FERC Matters
, in the Notes to Financial Statements in the 2012 Form 10-K.
Other expense decreased for the three months ended and increased for the nine months ended September 30, 2013, compared to the same period in 2012, by several items, none of which are individually material.
ANALYSIS OF CASH FLOWS
Cash From Operating Activities
SPPC’s net cash flows from operating activities were $156.9 million and $146.9 million for the nine months ended September 30, 2013 and 2012, respectively.
The increase in cash from operating activities was primarily due to:
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Reduced coal purchases of $23.4 million;
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Reduced spend on renewable programs of $19.6 million;
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Receipt of approximately $9.0 million in insurance proceeds related to a previous claim;
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Timing of payments for property taxes of $4.6 million; and
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Timing of payments for energy costs of $4.5 million.
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The increase in cash from operating activities was partially offset by:
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Under-collection of energy costs resulting from adjustments to BTER rates and higher energy costs of $92.4 million, offset by reduced refunds to customers of $42 million;
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Reduced EEPR collections of $5.8 million; and
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Increased funding of the retirement plan in 2013 of $2.9 million.
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Cash Used By Investing Activities
SPPC’s net cash used by investing activities were $(90.4) million and $(127.8) million for the nine months ended September 30, 2013 and 2012, respectively.
The decrease in cash used by investing activities was primarily due to:
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Reduced capital expenditure for the NV Energize project of $91.0 million, partially offset by reduced CIAC received under the American Recovery and Reinvestment Act of 2009 of $17.4 million.
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Cash Used By Financing Activities
SPPC’s net cash flows used by financing activities were $(43.2) million and $(22.6) million for the nine months ended September 30, 2013 and 2012, respectively.
The increase in cash used by financing was primarily due to:
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Maturity of $250 million of 5.45% General and Refunding Mortgage Notes, Series Q debt ; and
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Increased dividends to NVE of $20 million.
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The increase in cash used by financing was partially offset by:
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The issuance of $250 million of 3.375% General and Refunding Mortgage Notes, Series T debt.
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SPPC paid dividends of $40 million and $20 million to NVE during the nine months ended September 30, 2013 and 2012, respectively.
LIQUIDITY AND CAPITAL RESOURCES
Overall Liquidity
SPPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on SPPC’s outstanding indebtedness. Another significant use of cash is the refunding of previously over-collected amounts from customers. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions.
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Available Liquidity as of September 30, 2013 (in millions)
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SPPC
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Cash and Cash Equivalents
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$
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84.1
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Balance available on Revolving Credit Facility(1)
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243.7
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$
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327.8
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(1)
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As of November 6, 2013, SPPC had approximately $244.0 million available under its revolving credit facility which includes reductions for letters of credits.
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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 has no further debt maturities for the remainder of 2013. As of November 6, 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 for the remainder of 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 has transitioned to slower growth, the amount of capital expenditures required 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 facility. Furthermore, with significant investments in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, current federal tax NOL, and a decrease in capital expenditures, SPPC expects to generate free cash flow in 2013; however, SPPC’s cash flow may vary from quarter to quarter due to the seasonality of our business. Free cash flow may be used to reduce debt, to increase dividend payout and for potential investment opportunities. To meet long term maturing debt obligations, SPPC may use a combination of internally generated funds, its revolving credit facility, the issuance of long-term debt, or capital contributions from NVE.
However, if energy costs rise at a rapid rate, 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 under such circumstances, SPPC may be required to delay capital expenditures, refinance debt, or receive capital contributions from NVE.
The ability to issue debt, as discussed later, is subject to certain covenant calculations which include consolidated net income of NVE and the Utilities. As a result of these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from quarter to quarter, and the Utilities may not be able to fully utilize the availability on their revolving credit facilities. Additionally, 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.
During the nine months ended September 30, 2013, SPPC paid dividends to NVE of approximately $40.0 million. On November 6, 2013, SPPC declared a dividend to NVE of $37.0 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, environmental compliance, improvement, and maintenance of facilities.
During the nine months ended September 30, 2013, there were no material changes to contractual obligations as set forth in SPPC’s 2012 Form 10-K, except that in June 2013, SPPC entered into a long-term capital lease for a solar array facility, still subject to commercial operation and approval by the PUCN. The contract requires SPPC to make annual payments of approximately $3.0 million per year for a twenty year period. However, SPPC has the option to terminate the lease and purchase the facility on or after the sixth anniversary of the commercial operation date of the facility for approximately $20.0 million.
Financing Transactions
In August 2013, SPPC issued and sold $250 million of its 3.375% General and Refunding Notes, Series T due 2023. The approximately $247.9 million in net proceeds was used, together with cash on hand to pay at maturity the $250 million principal amount of its 5.45% General and Refunding Notes, Series Q, which matured in September 2013.
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 certain NVE debt. As of September 30, 2013, 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:
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a.
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Financing authority from the PUCN - As of September 30, 2013, 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 up to approximately $348.3 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $600 million. In May 2013, NPC and SPPC filed a joint financing application with the PUCN, see Note 4,
Regulatory Actions
of the Condensed Notes to Financial Statements for further details.
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b.
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Financial covenants within SPPC’s financing agreements - Under the SPPC Credit Agreement, 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 1.00. Based on financial statements for the period ended September 30, 2013, SPPC was in compliance with this covenant and could incur up to $1.1
billion of additional indebtedness.
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All other financial covenants contained in SPPC’s financing agreements are suspended as SPPC’s senior secured debt is currently 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.
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c.
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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 $3.7 billion.
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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 and NVE’s 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 the SPPC Indenture.
The SPPC Indenture creates a lien on substantially all of SPPC’s properties in Nevada. As of September 30, 2013, $1.5 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. SPPC had the capacity to issue $860 million of additional General and Refunding Mortgage Securities as of September 30, 2013. That amount is determined on the basis of:
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1.
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70% of net utility property additions; and/or
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2.
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the principal amount of retired General and Refunding Mortgage Securities.
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Property additions include plant in service. Although specific assets in CWIP can also qualify as property additions, the amount of bond capacity listed above does not reflect eligible property in CWIP.
SPPC also has the ability to release property from the lien of the SPPC Indenture on the basis of net property additions, cash, and/or retired bonds. To the extent SPPC releases property from the lien of the SPPC Indenture, it will reduce the amount of securities issuable under the SPPC Indenture.
Credit Ratings
The liquidity of SPPC, the cost and availability of borrowing by SPPC under the SPPC Credit Agreement, 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 ratings for SPPC’s debt. On May 22, 2013, Moody’s upgraded SPPC’s ratings. On May 30, 2013, Fitch and S&P upgraded SPPC’s rating outlook from Stable to Positive. 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:
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Rating Agency
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Fitch
(1)
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Moody’s
(2)
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S&P
(3)
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SPPC
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Sr. Secured Debt
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BBB+*
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A3*
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BBB+*
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(1)
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Fitch’s lowest level of “investment grade” credit rating is BBB-.
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(2)
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Moody’s lowest level of “investment grade” credit rating is Baa3.
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(3)
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S&P’s lowest level of “investment grade” credit rating is BBB-.
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Fitch’s and S&P’s rating outlooks are Positive, while Moody’s rating outlook is Stable for 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 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 September 30, 2013, 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 and normal sales 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 enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed in Note 6,
Long Term Debt
of the Notes to Financial Statements in the 2012 Form 10-K, SPPC’s
Financing Transactions
, the availability under the SPPC’s revolving credit facility 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 facility shall at no time exceed 50% of the total commitments then in effect under the credit facility. Currently, there are no negative mark-to-market exposures that would impact borrowings of SPPC. If deemed prudent, SPPC may 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 their respective 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.
Change of Control Provisions; Consent of Lenders
The MidAmerican Merger will accelerate the vesting and settlement of equity compensation awards to executives and employees which will be cashed out upon consummation of the MidAmerican Merger. Certain executives are also entitled to additional change of control payments in the event of an occurrence of a qualified termination. The consummation of the MidAmerican Merger will also trigger mandatory redemption requirements under financing agreements of SPPC. As a result, SPPC will be required to offer to purchase approximately $951.7 million of debt at 101% of par within 10 days after the MidAmerican Merger closing. At this time, SPPC is unable to determine the extent to which holders of these debt securities will accept such tender offers. The average interest rate under these debt securities is approximately 5.51% for SPPC. To the extent that debt securities are tendered pursuant to the required tender offers, SPPC intends to fund the purchases using a combination of internal funds, SPPC’s revolving credit facility or the issuance of long-term debt. Furthermore, SPPC was required to obtain consents from lenders under the terms of its revolving credit facility before consummating the MidAmerican Merger. In November 2013, SPPC amended its revolving credit facility to permit the MidAmerican Merger.
RECENT PRONOUNCEMENTS
See Note 1,
Summary of Significant Accounting Policies
of the Condensed Notes to Financial Statements, and Note 1,
Summary of Significant Accounting Policies
of the Notes to Financial Statements in the 2012 Form 10-K for discussion of accounting policies and recent pronouncements.