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NEVADA POWER CO - 10-Q - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(Edgar Glimpses Via Acquire Media NewsEdge) 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:
Operational Risks
† economic conditions, inflation rates, monetary policy, unemployment
rates, customer bankruptcies, including major gaming customers with
significant debt maturities, weaker housing markets, each of which
affect customer growth, customer collections, customer demand and usage
patterns;
† changes in the rate of industrial, commercial and residential growth in
the service territories of the Utilities, and the impact of energy
conservation programs, which could affect the Utilities' ability to
accurately forecast electric and gas demand;
† construction risks, including but not limited to those associated with
ON Line, such as difficulty in securing adequate skilled labor, cost and
availability of materials and equipment, third-party disputes, equipment
failure, engineering and design failure, work accidents, fire or
explosions, business interruptions, recovery of possible cost overruns,
delay of in-service dates, and pollution and environmental damage;
† security breaches of our information technology or 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;
† unseasonable or severe weather, drought, wildfire and other natural
phenomena, which could affect the Utilities' customers' demand for
power, seriously impact the Utilities' ability and/or cost to procure
adequate supplies of fuel or purchased power, affect the amount of water
available for electric generating plants in the southwestern U.S., and
have other adverse effects on our business;
† employee workforce factors, changes in and renewals of collective
bargaining unit agreements, strikes or work stoppages, an aging
workforce, and the ability to adjust the labor cost structure to changes
in growth within our service territories;
† whether the Utilities' newly installed advanced metering systems continue to operate as intended, accurately and timely measure customer
energy usage and generate billing information, and whether the Utilities
can continue to rely on third-party vendors or contractors to support
certain proprietary components of the advanced metering systems;
† changes in and/or implementation of FERC and NERC mandatory reliability,
security, and other requirements for system infrastructure, which could
significantly affect existing and future operations;
† explosions, fires, accidents, 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;
† the extent to which NVE or the Utilities incur costs in connection with
third-party claims or litigation that are not recoverable through
insurance, rates, or from other third parties;
† changes in the business of the Utilities' major customers engaged in
mining or gaming, including availability and cost of capital or power
demands, which may result in changes in the demand for the Utilities'
services, including the effect on the Nevada gaming industry from the
opening of additional gaming establishments in other states and
internationally;
† the effect that any future terrorist attacks, wars, threats of war or
pandemics may have on the tourism and gaming industries in Nevada,
particularly in Las Vegas, as well as on the national economy in
general;
† unusual or unanticipated changes in normal business operations of the
Utilities, including unusual maintenance or repairs.
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Regulatory/Legislative Risks
† unfavorable rulings, penalties and findings by the PUCN in rate or other
cases, investigations or proceedings, including GRCs, the periodic
applications to recover costs for fuel and purchased power that have
been recorded by the Utilities in their deferred energy accounts, deferred natural gas costs recorded by SPPC for its gas distribution
business, renewable energy and energy efficiency recovery programs, and
unfavorable rulings, penalties or findings by the FERC in rate or other
cases, investigations and proceedings with regard to wholesale power
sales and transmission services;
† the effect of existing or future Nevada or federal laws or regulations
affecting the electric industry, including those which could allow
additional customers to choose new electricity suppliers, use
alternative sources of energy, generate their own electricity, or change
the conditions under which they may do so;
† whether the Utilities can procure, obtain, and/or maintain sufficient
renewable energy sources in each compliance year to satisfy the
Portfolio Standard in the State of Nevada; and
† changes in tax or accounting matters or other laws and regulations to
which NVE or the Utilities are subject or which change the rate of
federal or state taxes payable by our shareholders or common stock
dividends.
Environmental Risks
† changes in and/or implementation of environmental laws or regulations,
including the imposition of limits on emissions of carbon or other
pollutants from electric generating facilities, which could
significantly affect the Utilities existing operations as well as our
construction program.
Liquidity and Capital Resources Risks
† whether the Utilities will be able to continue to obtain fuel and power
from their suppliers on favorable payment terms and favorable prices,
particularly in the event of unanticipated power demands, physical
availability, sharp increases in the prices for fuel (including
increases in long-term transportation costs) and/or power, or a ratings
downgrade;
† wholesale market conditions, including availability of power on the spot market and the availability to enter into commodity financial hedges
with creditworthy counterparties, including the impact as a result of the Dodd-Frank Act on counterparties who are lenders under our revolving
credit facilities, which may affect the prices the Utilities have to pay
for power as well as the prices at which the Utilities can sell any
excess power;
† whether provisions of the Dodd-Frank Act or rules made under the act
governing derivative transaction reporting, trading, and clearing or imposing margin or collateral requirements will materially increase the
cost, or limit the availability or usefulness, to the Utilities of
financial transactions and techniques important in managing risks the
Utilities face in the commodity, power and financial markets;
† the ability and terms upon which NVE, NPC and SPPC will be able to access the capital markets to support their capital needs, particularly
in the event of: volatility in the global credit markets or other
problems, changes in availability and cost of capital either due to
market conditions or as a result of unfavorable rulings by the PUCN, a
downgrade of the current debt ratings of NVE, NPC or SPPC, and/or
interest rate fluctuations;
† whether NVE's BOD will declare NVE's common stock dividends based on the
BOD's periodic consideration of factors ordinarily affecting dividend
policy, such as current and prospective financial condition, earnings
and liquidity, prospective business conditions, regulatory factors, and
restrictions contained in NVE's and the Utilities' agreements;
† whether the Utilities will be able to continue to pay NVE dividends
under the terms of their respective financing and credit agreements and
limitations imposed by the Federal Power Act; and
† further increases in the unfunded liability or changes in actuarial assumptions, the interest rate environment and the actual return on plan
assets for our pension and other postretirement plans, which can affect future funding obligations, costs and pension and other postretirement
plan liabilities.
Other factors and assumptions not identified above may also have been involved
in deriving forward-looking statements, and the failure of those other
assumptions to be realized, as well as other factors, may also cause actual
results to differ materially from those projected. NVE, NPC and SPPC assume no
obligation to update forward-looking statements to reflect actual results,
changes in assumptions or changes in other factors affecting forward-looking
statements.
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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:
• should not in all instances be treated as categorical statements of fact,
but rather as a way of allocating the risk to one of the parties to the
agreement if those statements prove to be inaccurate;
• have been qualified by disclosures that were made to the other party in
connection with the negotiation of the applicable agreement, which
disclosures are not necessarily reflected in the agreement;
• may apply standards of materiality in a way that is different from what may
be viewed as material to investors; and
• were made only as of the date of the applicable agreement or such other
date or dates as may be specified in such agreements and are subject to
more recent developments.
Accordingly, these representations and warranties may not describe the actual
state of affairs as of the date they were made or at any other time.
NOTE REGARDING STATISTICAL DATA
The statistical data used throughout this 10-Q, other than data relating
specifically to NVE and its subsidiaries, are based upon independent industry
publications, government publications, reports by market research firms or other
published independent sources. NVE and the Utilities did not commission any of
these publications or reports. These publications generally state that they
have obtained information from sources believed to be reliable, but do not
guarantee the accuracy or completeness of such information. While NVE and the
Utilities believe that each of these studies and publications is reliable, NVE
and the Utilities have not independently verified such data and make no
representation as to the accuracy of such information.
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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:
• Critical Accounting Policies and Estimates:
• Recent Pronouncements
• For each of NVE, NPC and SPPC:
• Results of Operations
• Analysis of Cash Flows
• Liquidity and Capital Resources
• Regulatory Proceedings (Utilities)
NVE's Utilities operate three regulated business segments which are NPC
electric, SPPC electric and SPPC natural gas. The Utilities are public utilities
engaged in the generation, transmission, distribution and sale of electricity
and, in the case of SPPC, sale of natural gas. Other operations consist mainly
of unregulated operations and the holding company operations. The Utilities are
the principal operating subsidiaries of NVE and account for substantially all of
NVE's assets and revenues. NVE, NPC and SPPC are separate filers for SEC
reporting purposes and as such this discussion has been divided to reflect the
individual filers (NVE, NPC and SPPC), except for discussions that relate to all
three entities or the Utilities.
The Utilities are regulated by the PUCN with respect to rates, standards of
service, siting of and necessity for generation and certain transmission
facilities, accounting, issuance of securities and other matters with respect to
generation, distribution and transmission operations. The FERC has jurisdiction
under the Federal Power Act with respect to wholesale rates, service,
interconnection, accounting and other matters in connection with the Utilities'
sale of electricity for resale and interstate transmission. The FERC also has
jurisdiction over the natural gas pipeline companies from which the Utilities
take service. As a result of regulation, many of the fundamental business
decisions of the Utilities, as well as the ROR they are permitted to earn on
their utility assets, are subject to the approval of governmental agencies.
The Utilities' revenues and operating income are subject to fluctuations during
the year due to impacts that seasonal weather, rate changes and customer usage
patterns have on demand for electric energy and resources. NPC is a summer
peaking utility experiencing its highest retail energy sales in response to the
demand for air conditioning. SPPC's electric system peak typically occurs in the
summer, while its gas business typically peaks in the winter. The variations in
energy usage due to varying weather, customer growth and other energy usage
patterns, including energy efficiency and conservation measures, necessitates a
continual balancing of loads and resources and purchases and sales of energy
under short and long term energy supply contracts. As a result, the prudent
management and optimization of available resources has a direct effect on the
operating and financial performance of the Utilities. Additionally, the timely
recovery of purchased power and fuel costs, and other costs, and the ability to
earn a fair return on investments through rates are essential to the operating
and financial performance of the Utilities.
Overview of Major Factors Affecting Results of Operations
NVE recognized net income of $21.5 million for the three months ended March 31,
2013, compared to $12.2 million for the same period in 2012. The increase in
net income is primarily due to the following pre-tax items:
• An increase in gross margin of $9.3 million; see the Utilities' respective
Results of Operations for further discussion of gross margin;
• A decrease in maintenance expense of $7.6 million due to the timing of
outages; see the Utilities' respective Results of Operations for further
discussion; and
• A decrease in interest expense of $4.6 million primarily due to the
redemption of NPC's 6.5% General and Refunding Mortgage Notes, Series I in
April 2012 and an increase in AFUDC-debt.
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 continues 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 may
provide NVE the ability to increase its dividend while preserving its ability to
invest in new opportunities.
Key Initiatives
The economy in Nevada continues to recover slowly. While a low growth
environment can be challenging, the foundation established in prior years,
including establishing energy independence, improving capital structure and
liquidity and managing our regulatory environment, has positioned the Utilities
to operate in this environment. However, NVE and the Utilities continue to
implement and develop key initiatives that collectively may further our ability
to increase our common stock dividend, strengthen our capital structure and
consider new investment opportunities. These initiatives should enable us to
contain operating and
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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 and One Company Merger
ON Line is Phase 1 of a joint project between the Utilities and GBT-South.
Completion of ON Line, expected in late 2013, will connect NVE's southern and
northern service territories. Pending certain state and federal regulatory
approvals, ON Line will provide:
• Ability to dispatch energy jointly throughout the state;
• 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;
• Ability to optimize its generating and transmission facilities to
benefit its customers; and
• The opportunity for NVE to merge NPC and SPPC (the "One Company" merger). A merger application is expected to be filed with the PUCN and
FERC in June 2013.
Empower Customers through Focused Service and Efficiency Programs
NV Energize is a NVE project that includes Advanced Meter Infrastructure, Smart
Grid Technology and Meter Data Management. The NV Energize capabilities will
allow NVE to help customers better manage their usage with the most
cost-effective mix of pricing, service, efficiency and conservation options. As
of March 31, 2013, the installation of the Smart Meters is nearly complete.
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
As discussed in more detail in Note 7, Commitments and Contingencies, of the
Notes to Financial Statements, certain generating stations of NVE are affected
under EPA's Regional Haze Rules. The implementation costs of the Regional Haze
Rules are significant. Therefore, NVE must balance the cost of implementing the
retrofits associated with the Regional Haze Rule with the effect current and
future load requirements, retirements of generating stations, including the
effects of NVision discussed below, and plant outages will have on its ability
to serve its customers reliably.
Investment opportunities
NVE continues to explore investment opportunities that may benefit our customers
and that will add to our core business of generation, transmission and
distribution of energy. In addition, NVE's geographical location affords it
access to various renewable resources for potential investment opportunities.
Proposed Legislation in Nevada
The Nevada Legislature is currently in session and is expected to
complete its session in the second quarter of 2013. The most significant
legislation under consideration that would directly impact NVE is Senate Bill
123 (SB 123), which is a bill supported by NVE as part of its NVision
initiative. NVision is a 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 natural gas-fired
plants and the implementation of further demand response programs. At the time
of this filing, management cannot predict whether SB 123 will be adopted in its
present or an amended form, or its ultimate impact on NVE and the Utilities.
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 $6.3 million and $6.3 million of long term debt interest costs for
the three months ended March 31, 2013 and 2012, respectively.
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--------------------------------------------------------------------------------For the period ended March 31, 2013, NPC paid $50.0 million in dividends to NVE.
On May 8, 2013, NPC and SPPC declared dividends payable to NVE of $30.0 million
and $20.0 million, respectively.
Other Subsidiaries
Other subsidiaries of NVE, except for NPC and SPPC, did not contribute
materially to the consolidated results of operations of NVE.
ANALYSIS OF CASH FLOWS
NVE's cash flows decreased during the three months ended March 31, 2013,
compared to the same period in 2012, due to an increase in cash used by
financing activities, offset partially by an increase in cash from operating
activities and a decrease in cash used by investing activities.
Cash from Operating Activities - The increase in cash from operating activities
was primarily due to increased cash flows from accounts receivable as a result
of higher balances at December 31, 2012, compared to balances at December 31,
2011, due to higher BTGR rates resulting from NPC's 2011 GRC which were
effective January 1, 2012. Also contributing to the increase was a reduction in
refunds to customers for previously over collected BTER balances, a reduction in
coal and gas purchases, and the receipt of approximately $9.0 million in
insurance proceeds related to a previous claim. These increases were offset by
an under collection of energy costs in 2013 as opposed to an over collection of
energy costs in 2012, resulting from adjustments to BTER rates.
Cash used by Investing Activities - The decrease in cash used by investing
activities was primarily due to the decrease in construction activity related to
the NV Energize project, partially offset by the reduction of CIAC received
under the American Recovery and Reinvestment Act of 2009, also related to the NV
Energize project.
Cash used by Financing Activities - Cash used by financing activities increased
primarily due to an increase in dividends to shareholders, a reduction in draws
from the NPC's revolving credit facility, and the repurchase of common stock,
which may be reissued to satisfy future equity compensation costs.
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. Available liquidity as of March 31, 2013 was as follows
(in millions):
Available Liquidity as of March 31, 2013 (in millions)
NVE NPC SPPC
Cash and Cash Equivalents $ 27.4 $ 132.2 $ 85.3
Balance available on Revolving Credit
Facilities(1) N/A 497.3 243.7
27.4 629.5 329.0
(1) As of May 7, 2013, NPC and SPPC had approximately $497.3 million and $243.7 million available under their revolving
credit facilities, which includes reductions inavailability 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.
NVE has no debt maturities in 2013. However, NPC is required to redeem
approximately $98.1 million of its variable rate debt, due 2020 prior to ON
Line's commercial operation date expected by December 31, 2013 and its $125
million 7.375% General and Refunding Notes, Series U, will mature in January
2014. SPPC's $250 million 5.45% General and Refunding Notes, Series Q, will
mature in September 2013. To meet these long term maturing debt obligations,
the Utilities intend to use a combination of internally generated funds, the
Utilities' revolving credit facilities, and/or the issuance of long term debt.
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 increase dividend payout and for potential investment
opportunities.
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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, re-finance debt or issue equity
at NVE. Additionally, if deemed prudent, the Utilities may enter into hedging
transactions in an attempt to mitigate projected or actual rising energy costs.
Currently, the Utilities are not operating under a PUCN approved hedging plan.
Hedging transactions may have a material impact on the Utilities' cash flows,
unless recovered in rates in a timely manner.
As of May 8, 2013, NVE has approximately $22.9 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 three months ended March 31, 2013, NPC paid dividends to NVE of
approximately $50.0 million. On May 8, 2013, NPC and SPPC declared dividends
payable to NVE of $30.0 million and $20.0 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 purchase of
Reid Gardner Generating Station Unit No. 4 from CDWR. The purchase is expected
to be completed mid 2013 for approximately $47.1 million, subject to final
approval by the FERC.
During the three months ended March 31, 2013, there were no material changes to
contractual obligations as set forth in NVE's 2012 Form 10-K.
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 .70 to 1.00. Under
these covenant restrictions, as of March 31, 2013, NVE (consolidated) would be
allowed to incur up to $3.2 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 March 31, 2013, NVE (on a stand-alone basis) had outstanding debt and
other obligations including, but not limited to: a $195 million Term Loan due
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 March 31, 2013, NVE, NPC, SPPC and their subsidiaries had approximately
$5.0 billion of debt and other obligations outstanding, consisting of
approximately $3.3 billion of debt at NPC, approximately $1.2 billion of debt at
SPPC and approximately $510.0 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 state utility commissions, 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 March 31, 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
April 30, 2013, Fitch upgraded NVE's corporate credit ratings from BB to BB+,
and for NPC and SPPC, from BB+ to investment grade BBB-. NPC's and SPPC's
senior secured debt is rated investment grade by three NRSRO's: Fitch, Moody's
and S&P. The senior debt credit ratings are as follows:
Rating Agency
Fitch(1) Moody's(2) S&P(3)
NVE Sr. Unsecured Debt BB+ Ba1 BB+
NPC Sr. Secured Debt BBB+* Baa1* BBB+*
SPPC Sr. Secured Debt BBB+* Baa1* BBB+*
* Investment grade
(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-.
37
--------------------------------------------------------------------------------Fitch's, Moody's and S&P's rating outlooks are 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 March 31, 2013 for all suppliers continuing to
provide power under a WSPP agreement would approximate a $94.6 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 March 31, 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
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
38
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indebtedness) provide for a cure period of 30-60 days from the occurrence of a
specified event, during which time NVE or the Utilities may rectify or correct
the situation before it becomes an event of default.
NEVADA POWER COMPANY
RESULTS OF OPERATIONS
NPC recognized net income of approximately $5.4 million during the three months
ended March 31, 2013, compared to a net loss of approximately $1.3 million for
the same period in 2012.
For the period ended March 31, 2013, NPC paid $50.0 million in dividends to
NVE. On May 8, 2013, NPC declared a dividend of $30.0 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 and energy efficiency program
costs, provides a measure of income available to support the other operating
expenses of NPC. For reconciliation to operating income, see Note 2, 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):
39
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Three Months Ended March 31,
2013 2012 Variance % Change
Operating Revenues: $ 371,863 $ 395,688 $ (23,825) (6.0) %
Energy Costs: Fuel for power generation 105,531 80,549 24,982 31.0 %
Purchased power 81,408 81,531 (123) (0.2) %
Deferred energy (45,355) 2,171 (47,526) (2,189.1) %
Energy efficiency program costs 7,967 15,774 (7,807)
(49.5) %
Total Costs $ 149,551 $ 180,025 $ (30,474) (16.9) %
Gross Margin $ 222,312 $ 215,663 $ 6,649 3.1 %
Gross margin increased for the three months ended March 31, 2013, compared to
the same period in 2012. The increase is primarily due to $2.6 million related
to a slight increase in the BTGR effective rate, a $2.3 million net increase in
usage primarily due to milder weather in 2012 as indicated in the table below,
and approximately $1.4 million due to customer growth.
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:
Three Months Ended March 31,
2013 2012 Variance % Change
NPC
Heating 1,050 924 126 13.6 %
Cooling 86 41 45 109.8 %
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):
Operating Revenue
Three Months Ended March 31,
Operating Revenues: 2013 2012 Variance % Change
Residential $ 191,894 $ 194,489 $ (2,595) (1.3) %
Commercial 79,561 87,735 (8,174) (9.3) %
Industrial 88,477 99,914 (11,437) (11.4) %
Retail revenues 359,932 382,138 (22,206) (5.8) %
Other 11,931 13,550 (1,619) (11.9) % Total Operating Revenues $ 371,863 $ 395,688 $ (23,825) (6.0) %
Retail sales in thousands of MWhs
Residential 1,611 1,536 75 4.9 %
Commercial 916 957 (41) (4.3) %
Industrial 1,635 1,652 (17) (1.0) %
Retail sales in thousands of MWhs 4,162 4,145 17 0.4 %
Average retail revenue per MWh $ 86.48 $ 92.19 (5.71) (6.2) %
NPC's retail revenues decreased for the three months ended March 31, 2013, as
compared to the same period in 2012 primarily due to $22.1 million in rate
decreases largely due to 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 $7.7 million from decreases in EEPR rates effective January 1, 2013.
These decreases were offset by an increase of $6.5 million resulting from
increased residential usage, primarily due to an increase in HDDs.
40
--------------------------------------------------------------------------------For the three months ended March 31, 2013, the average number of retail
customers increased slightly by 0.6%, consisting of an increase in residential,
commercial and industrial customers of 0.6%, 1.1% and 0.7%, respectively,
compared to the same period in the prior year.
Electric operating revenue - other for the three months ended March 31, 2013,
compared to the same period in 2012, did not change materially.
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:
• weather
• generation efficiency
• plant outages
• total system demand
• resource constraints
• transmission constraints
• natural gas constraints
• long-term contracts
• mandated power purchases; and
• volatility of commodity prices
Three Months Ended March 31,
2013 2012 Variance % Change
Energy Costs
Fuel for power generation $ 105,531 $ 80,549 $ 24,982 31.0 %
Purchased power 81,408 81,531 (123) (0.2) %
Total Energy Costs $ 186,939 $ 162,080 $ 24,859 15.3 %
MWhs
MWhs Generated (in
thousands) 3,675 3,287 388 11.8 %
Purchased Power (in
thousands) 643 1,026 (383) (37.3) %
Total MWhs 4,318 4,313 5 0.1 %
Average cost per MWh
Average fuel cost per MWh
of Generated Power $ 28.72 $ 24.51 $ 4.21 17.2 %
Average cost per MWh of
Purchased Power $ 126.61 $ 79.46 $ 47.14 59.3 %
Average total cost per MWh $ 43.29 $ 37.58 $ 5.71 15.2 %
Energy Costs and the average total cost per MWh increased for the three months
ended March 31, 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.
• Fuel for generation costs increased for the three months ended March 31,
2013, compared to the same period in 2012. Approximately $13.5 million
of the increase is due to an increase in natural gas prices and
approximately $11.5 million of the increase is due to an increase in
volume. Volume increased due to continued reliance on internal generation
to satisfy load requirements.
• Purchased power costs decreased slightly for the three months ended March
31, 2013, compared to the same period in 2012. Approximately $65.5
million of the decrease was due to a decrease in volume. The decrease
was largely offset by an increase of approximately $65.4 million in the
cost of purchased power. As the volume of purchased power decreases, the
remaining contracts consist primarily of higher cost renewable energy
contracts and other long term fixed capacity contracts which are
increasing the average cost per unit. Also contributing to the increase
in the average cost per unit is the increase in the volume of power sales
which are offset in purchased power.
Deferred Energy
Three Months Ended March 31,
2013 2012 Variance % Change
Deferred energy $ (45,355) $ 2,171 $ (47,526) (2,189.1) %
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Deferred Energy for the three months ended March 31, 2013 include amortizations
of $(27.3) million, which primarily represents cash refunds to our customers for
previous over-collections. Further contributing to the 2013 deferred energy
balance are under-collections of amounts recoverable in rates of $(18.0)
million.
Deferred Energy for the three months ended March 2012 include amortizations of
previous over-collections of $(35.2) million, partially offset by
over-collections of amounts recoverable in rates of $37.3 million.
Deferred energy represents the difference between actual fuel and purchased
power costs incurred during the period and amounts recoverable through current
rates. To the extent actual costs exceed amounts recoverable through current
rates, the excess is recognized as a reduction in costs. Conversely, to the
extent actual costs are less than amounts recoverable through current rates, the
difference is recognized as an increase in costs. Deferred energy also includes
the current amortization of fuel and purchased power costs previously deferred.
Reference Note 3, Regulatory Actions, of the Condensed Notes to Financial
Statements for further detail of deferred energy balances.
Other Operating Expenses
Three Months Ended March 31,
2013 2012 Variance % Change
Energy efficiency program costs $ 7,967 $ 15,774 $ (7,807) (49.5) %
Other operating expenses $ 67,392 $ 66,462 $ 930 1.4 %
Maintenance $ 18,075 $ 23,073 $ (4,998) (21.7) % Depreciation and amortization $ 68,661 $ 64,990 $ 3,671 5.6 %
For the three months ended March 31, 2013 energy efficiency program costs
decreased compared to the same period 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 amortization rate filings.
Other operating expense increased for the three months ended March 31, 2013,
compared to the same period in 2012, primarily due to a $2.7 million increase in
stock compensation costs, offset by a $1.3 million decrease in
telecommunications, meter reading and meter replacement software costs, and $0.7
million in lower pension and benefit costs.
Maintenance expense decreased for the three months ended March 31, 2013,
compared to the same period in 2012, primarily due to $5.3 million in planned
maintenance and outages at the Silverhawk, Higgins, Reid Gardner and Lenzie
Generating Stations in 2012.
Depreciation and amortization increased slightly for the three months ended
March 31, 2013, compared to the same period in 2012, primarily due to general
increases in plant-in-service.
Interest Expense
Three Months Ended March 31,
2013 2012 Variance % Change
Interest expense
(net of AFUDC-debt: $1,837 and $1,179) $ 51,259 $ 54,405 $ (3,146) (5.8) %
Interest expense decreased for the three months ended March 31, 2013, compared
to the same period in 2012 due to a $2.2 million decrease in interest cost
primarily due to the redemption of the 6.5% General and Refunding Mortgage
Notes, Series I in April 2012 and an increase in AFUDC-debt of $0.7 million. See
Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2012 Form
10-K and Note 4, Long-Term Debt, in the Condensed Notes to Financial Statements,
for additional information regarding long-term debt.
Other Income (Expense)
Three Months Ended March 31,
2013 2012 Variance % Change
Interest income (expense) on
regulatory items $ (802) $ (2,016) $ 1,214 (60.2) %
AFUDC-equity $ 2,366 $ 1,413 $ 953 67.4 %
Other income $ 2,404 $ 1,709 $ 695 40.7 %
Other expense $ (2,401) $ (1,346) $ (1,055) 78.4 %
Interest expense on regulatory items decreased for the three months ended March
31, 2013, compared to the same period in 2012, due to a $1.6 million decrease in
interest on deferred energy as a result of lower over-collected balances in
2013, and a decrease of $0.7 million in estimated interest expense accrued on
the deferred gain on NPC's wireless towers sold in 2011 pending final accounting
approval by the PUCN in 2012, offset by $1.3 million net decrease of 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.
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--------------------------------------------------------------------------------AFUDC-equity increased for the three months ended March 31, 2013, compared to
the same period in 2012, primarily due to various construction projects.
Other income increased for the three months ended March 31, 2013, compared to
the same period in 2012, by several items, all of which were immaterial.
Other expense increased for the three months ended March 31, 2013, compared to
the same period in 2012, by several items, all of which were immaterial.
Analysis of Cash Flows
NPC's cash flows decreased during the three months ended March 31, 2013,
compared to the same period in 2012, due to a decrease in cash from operating
activities and an increase in cash used by investing and financing activities.
Cash from Operating Activities -The decrease in cash from operating activities
was primarily due to an under collection of energy costs in 2013 as opposed to
an over collection of energy costs in 2012, resulting from adjustments to BTER
rates, and reduced energy efficiency rates. These decreases were partially
offset by increased cash flows from accounts receivable as a result of higher
balances at December 31, 2012, compared to balances at December 31, 2011, due to
higher BTGR rates resulting from NPC's 2011 GRC which were effective January 1,
2012. Further offsetting the decrease in cash from operating activities was the
reduction in refunds to customers for previously over collected BTER balances.
Cash used by Investing Activities - The increase in cash used by investing
activities was primarily due to the reduction of CIAC received under the
American Recovery and Reinvestment Act of 2009, related to the NV Energize
project, partially offset by decreased construction activity related to the NV
Energize project.
Cash used by Financing Activities -Cash used by financing activities increased
primarily due to an increase in dividends paid to NVE and a reduction in draws
from the NPC revolving credit facility.
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 March 31, 2013 was as follows
(in millions):
Available Liquidity as of March 31, 2013 (in millions)
NPC
Cash and Cash Equivalents $ 132.2
Balance available on Revolving Credit Facility(1) 497.3
$ 629.5
(1) As of May 7, 2013, NPC had approximately $497.3 million available under its
revolving credit facility which includes reductions for letters of credits.
NPC attempts to maintain its cash and cash equivalents in highly liquid
investments, such as U.S. Treasury Bills and bank deposits. In addition to cash
on hand, NPC may use its revolving credit facility in order to meet its
liquidity needs. Alternatively, depending on the usage of the revolving credit
facility, NPC may issue debt, subject to certain restrictions as discussed in
Factors Affecting Liquidity, Ability to Issue Debt, below.
NPC is required to redeem approximately $98.1 million of its variable rate debt,
due 2020, prior to ON Line's commercial operation date, expected no later than
December 31, 2013 and its $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 May 8, 2013, NPC
has no borrowings on its revolving credit facility, not including letters of
credit. NPC's credit ratings on its senior secured debt remains at investment
grade (see Credit Ratingsbelow). 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 bettermanage and optimize its resources. As a result,
NPC anticipates that they 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.
43
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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 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 three months ended March 31, 2013, NPC paid dividends to NVE
of $50.0 million. On May 8, 2013, NPC declared a dividend to NVE of $30.0
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 purchase of
Reid Gardner Generating Station Unit No. 4 from CDWR. The purchase is expected
to be completed mid 2013 for approximately $47.1 million, subject to final
approval by the FERC.
During the three months ended March 31, 2013, there were no material changes to
contractual obligations as set forth in NPC's 2012 Form 10-K.
Factors Affecting Liquidity
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
March 31, 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 March 31, 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.
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 March 31, 2013 financial
statements, NPC was in compliance with this covenant and could incur up to
$2.8 billion of additional indebtedness.
All other financial covenants contained in NPC's financing agreements are
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 $3.2 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 March 31, 2013, $3.8 billion of NPC's General and Refunding
Mortgage Securities were outstanding. NPC had the capacity to issue $1.6 billion
of General and Refunding Mortgage Securities as of March 31, 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 April 30, 2013, Fitch upgraded NPC's corporate credit rating from BB+ to
investment grade BBB-. 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+* Baa1* BBB+*
* Investment grade
(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-.
44
--------------------------------------------------------------------------------Fitch's, Moody's and S&P's rating outlooks are 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 March 31, 2013 for all suppliers continuing to
provide power under a WSPP agreement would approximate a $94.6 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 March 31, 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 its financing agreements. In addition, certain financing
agreements of NPC provide for an event of default if there is a failure under
other financing agreements of NPC to meet payment terms or to observe other
covenants that would result in an acceleration of payments due. Most of these
default provisions (other than ones relating to a failure to pay such other
indebtedness when due) provide for a cure period of 30-60 days from the
occurrence of a specified event during which time NPC may rectify or correct the
situation before it becomes an event of default.
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Sierra Pacific Power Company
RESULTS OF OPERATIONS
SPPC recognized net income of $21.9 million for the three months ended March 31,
2013, compared to net income of $18.6 million for the same period in 2012.
During the three months ended March 31, 2012, SPPC did not pay dividends to NVE.
On May 8, 2013, SPPC declared a dividend of $20.0 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 and energy efficiency program
costs, provides a measure of income available to support the other operating
expenses of SPPC. For reconciliation to operating income, see Note 2, 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 March 31,
2013 2012 Variance % Change
Operating Revenues:
Electric $ 172,627 $ 169,806 $ 2,821 1.7 %
Gas 39,729 45,922 (6,193) (13.5) %
$ 212,356 $ 215,728 $ (3,372) (1.6) %
Energy Costs: Fuel for power generation 41,717 36,486 5,231 14.3 %
Purchased power 39,902 35,585 4,317 12.1 %
Gas purchased for resale 37,620 31,617 6,003 19.0 % Deferral of energy - electric - net (19,335) (12,670) (6,665) 52.6 %
Deferral of energy - gas - net (14,375) (1,240) (13,135) 1,059.3 %
Energy efficiency program costs 1,878 3,651 (1,773) (48.6) %
Total Costs $ 87,407 $ 93,429 $ (6,022) (6.4) %
Cost by Segment:
Electric $ 64,162 $ 63,052 1,110 1.8 %
Gas 23,245 30,377 (7,132) (23.5) %
$ 87,407 $ 93,429 $ (6,022) (6.4) %
Gross Margin by Segment:
Electric $ 108,465 $ 106,754 $ 1,711 1.6 %
Gas 16,484 15,545 939 6.0 %
$ 124,949 $ 122,299 $ 2,650 2.2 %
Electric gross margin increased for the three months ended March 31, 2013,
compared to the same period in 2012. Approximately $1.2 million of the increase
is due to customer growth and approximately $1.1 million of the increase is due
to an increase in customer usage primarily due to an increase in HDDs as shown
in the tables below.
Gas gross margin increased for the three months ended March 31, 2013, compared
to the same period in 2012. The increase is primarily due to the increase in
HDDs as shown in the tables below.
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:
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Three Months Ended March 31,
2013 2012 Variance % Change
SPPC
Heating 2,285 2,128 157 7.4 %
Cooling - - N/A N/A
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 March 31,
Operating Revenues: 2013 2012 Variance % Change
Residential $ 62,978 $ 61,360 $ 1,618 2.6 %
Commercial 56,886 58,712 (1,826) (3.1) %
Industrial 34,640 33,070 1,570 4.7 %
Retail revenues 154,504 153,142 1,362 0.9 %
Other 18,123 16,664 1,459 8.8 %
Total Operating Revenues $ 172,627 $ 169,806 $ 2,821 1.7 %
Retail sales in thousands of MWhs
Residential 629 600 29 4.8 %
Commercial 650 659 (9) (1.4) %
Industrial 668 633 35 5.5 %
Retail sales in thousands of MWhs 1,947 1,892 55 2.9 %
Average retail revenue per MWh $ 79.35 $ 80.94 $ (1.59) (2.0) %
Retail revenue increased for the three months ended March 31, 2013, as compared
to the same period in 2012, primarily due to a $2.2 million increase in
residential customer usage primarily due to an increase in HDDs as outlined in
the table above, a $1.2 million increase in usage by mining customers and $0.7
million attributable to customer growth. These increases were partially offset
by $1.8 million of rate decreases in EEPR due to SPPC's annual Deferred Energy
cases effective January 1, 2013 (see Note 3, Regulatory Actions of the Notes to
Financial Statements) and $1.6 million of rate decreases due to various BTER and
DEAA quarterly updates (see Note 3, Regulatory Actions of the Notes to Financial
Statements).
For the three months ended March 31, 2013, the average number of residential,
commercial and industrial customers increased 0.6%, 0.7% and 4.8%, respectively,
compared to the same period in 2012.
Electric operating revenues - Other increased by $1.5 million for the three
months ended March 31, 2013, compared to the same period in 2012, primarily due
to an 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).
Gas Operating Revenue
Three Months Ended March 31,
2013 2012 Variance % Change
Gas Operating Revenues:
Residential $ 22,545 $ 26,557 $ (4,012) (15.1) %
Commercial 8,719 10,966 (2,247) (20.5) %
Industrial 2,278 2,715 (437) (16.1) %
Retail Revenues 33,542 40,238 (6,696) (16.6) %
Wholesale Revenues 5,325 4,830 495 10.2 %
Miscellaneous 862 854 8 0.9 %
Total Gas Revenues $ 39,729 $ 45,922 $ (6,193) (13.5) %
Retail sales in thousands of Dths
Residential 4,136 3,708 428 11.5 %
Commercial 2,076 1,879 197 10.5 %
Industrial 533 476 57 12.0 % Retail sales in thousands of Dths 6,745 6,063 682
11.2 %
Average retail revenue per Dth $ 4.97 $ 6.64 $ (1.67)
(25.1) %
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SPPC's retail gas revenues decreased for the three months ended March 31, 2013,
compared to the same period in 2012, primarily due to a $9.7 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 3,
Regulatory Actions, of the Notes to Financial Statements in the 2012 Form 10-K).
The decrease was partially offset by a $2.7 million increase in customer usage
primarily due to an increase in HDDs, as shown in the table above.
Wholesale revenues increased for the three months ended March 31, 2013,
compared to the same period 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:
• weather
• plant outages
• total system demand
• resource constraints
• transmission constraints
• gas transportation constraints
• natural gas constraints
• long-term contracts
• mandated power purchases
• generation efficiency; and
• volatility of commodity prices
Three Months Ended March 31,
2013 2012 Variance % Change
Energy Costs
Fuel for power generation $ 41,717 $ 36,486 $ 5,231 14.3 %
Purchased power 39,902 35,585 4,317 12.1 %
Total Energy Costs $ 81,619 $ 72,071 $ 9,548 13.2 %
MWhs
MWhs Generated (in
thousands) 1,147 1,178 (31) (2.6) %
Purchased Power (in
thousands) 1,105 1,011 94 9.3 %
Total MWhs 2,252 2,189 63 2.9 %
Average cost per MWh
Average fuel cost per MWh
of Generated Power $ 36.37 $ 30.97 $ 5.40 17.4 %
Average cost per MWh of
Purchased Power $ 36.11 $ 35.20 $ 0.91 2.6 %
Average total cost per MWh $ 36.24 $ 32.92 $ 3.32 10.1 %
Energy Costs and the average total cost per MWh increased for the three months
ended March 31, 2013, compared to the same period in 2012, primarily due to
higher natural gas prices. Total MWhs increased for the three month period
primarily due to an increase in HDDs.
• Fuel for generation costs increased for the three months ended March 31,
2013, compared to the same period in 2012. Approximately $6.4 million of
the change is due to higher natural gas prices partially offset by a
decrease in volume of approximately $1.2 million.
• Purchased power costs for the three months ended March 31, 2013, compared
to the same period in 2012. Approximately $3.1 million of the increase is
due to increased reliance on purchased power along with a $1.2 million
increase due to higher natural gas prices. Volume increased due to less
reliance on internal generation.
Gas Purchased for Resale
Three Months Ended March 31,
2013 2012 Variance % Change
Gas purchased for resale $ 37,620 $ 31,617 $ 6,003 19.0 %
Gas purchased for resale (in
thousands of Dths) 8,427 8,274 153 1.8 %
Average cost per Dth $ 4.46 $ 3.82 $ 0.64 16.8 %
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Gas purchased for resale increased for the three months ended March 31, 2013,
compared to the same period in 2012. Approximately $5.3 million of the increase
is due to higher natural gas prices and approximately $0.7 million is due to an
increase in volume.
Deferred Energy
Three Months Ended March 31,
2013 2012 Variance % Change
Deferral of energy - electric - net $ (19,335) $ (12,670) $ (6,665) 52.6 %
Deferral of energy - gas - net (14,375) (1,240) (13,135) 1,059.3 %
$ (33,710) $ (13,910) $ (19,800) 142.3 %
Deferred energy-electric for the three months ended March 31, 2013 include
amortization of $(11.3) million which represent cash refunds to our customers
for previous over-collections. Further contributing to the 2013 deferred energy
balance are under-collections of amounts recoverable in rates of $(8.0)
million.
Deferred energy-electric for the three months ended March 31, 2012 include
amortization of previous over-collections of $(25.5) million, partially offset
by over-collections of amounts recoverable in rates of $12.8 million.
Deferred energy-gas for the three months ended March 31, 2013 include
amortizations of previous over-collections of ($13.4) million and
under-collections of amounts recoverable in rates of $(0.9) million.
Deferred energy-gas for the three months ended March 31, 2012 include
amortization of previous over-collections of ($13.4) million, partially offset
by over-collections of amounts recoverable in rates of $12.2 million.
Deferred energy represents the difference between actual fuel and purchased
power costs incurred during the period and amounts recoverable through current
rates. To the extent actual costs exceed amounts recoverable through current
rates, the excess is recognized as a reduction in costs. Conversely, to the
extent actual costs are less than amounts recoverable through current rates, the
difference is recognized as an increase in costs. Deferred energy also includes
the current amortization of fuel and purchased power costs previously deferred.
Reference Note 3, Regulatory Actions, of the Condensed Notes to Financial
Statements for further detail of deferred energy balances.
Other Operating Expenses
Three Months Ended March 31,
2013 2012 Variance % Change
Energy efficiency program costs $ 1,878 $ 3,651 (1,773) (48.6) %
Other operating expenses $ 35,805 $ 36,432 (627) (1.7) %
Maintenance $ 6,831 $ 9,453 (2,622) (27.7) %
Depreciation and amortization $ 27,341 $ 25,872 1,469 5.7 %
For the three months ended March 31, 2013, energy efficiency program costs
decreased compared to the same period 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 amortization rate filings.
Other operating expenses decreased for the three months ended March 31, 2013,
compared to the same period in 2012, primarily due to $1.0 million in lower
telecommunications and software costs, and $0.6 million in lower pension and
benefit costs. The decrease was partially offset by a $1.2 million increase in
stock compensation costs.
Maintenance expense decreased for the three months ended March 31, 2013,
compared to the same period in 2012, primarily due to a $1.4 million planned
major outage at the Tracy Generating Station in 2012 and maintenance at the
Valmy Generating Station in 2012 for $0.7 million.
Depreciation and amortization increased slightlyfor the three months ended March
31, 2013, compared to the same period in 2012, primarily due to general
increases in plant-in-service.
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Interest Expense
Three Months Ended March 31,
2013 2012 Variance % Change
Interest expense (net of AFUDC-debt: $294 and $416) $ 15,525 $ 16,973 (1,448)
(8.5) %
Interest expense decreased for the three months ended March 31, 2013, compared
to the same period in 2012, primarily due to decreased debt amortization expense
of $1.5 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 March 31,
2013 2012 Variance % Change
Interest expense on regulatory items $ (25) $ (186) 161 (86.6) %
AFUDC-equity $ 523 $ 519 4 0.8 %
Other income $ 1,140 $ 2,183 (1,043) (47.8) %
Other expense $ (1,248) $ (1,335) 87 (6.5) %
Interest expense on regulatory items decreased for the three months ended March
31, 2013, compared to the same period in 2012, primarily due to a $0.6 million
decrease in interest on deferred energy as a result of lower over-collected
balances in 2013, offset by a $0.4 million decrease in carrying charges on solar
conservation programs. See Note 3, Regulatory Actions, of the Condensed Notes to
Financial Statements for further details of deferred energy balances.
AFUDC-equity did not change materially for the three months ended March 31,
2013, compared to the same period in 2012.
Other income decreased for the three months ended March 31, 2013, compared to
same period in 2012, primarily due to the $1.1 million settlement with CA ISO in
2011, recognized in 2012. See Note 3, Regulatory Actions, FERC Matters, in the
Notes to Financial Statements in the 2012 Form 10-K.
Other expense is comparable for the three months ended March 31, 2013, as
compared to the same period in 2012.
Analysis of Cash Flows
SPPC's cash flows increased during the three months ended March 31, 2013,
compared to the same period in 2012, due to an increase in cash from operating
activities and a decrease in cash used by investing and financing activities.
Cash from Operating Activities - The increase in cash from operating activities
was primarily due to reduced coal and gas purchases, over collections of EEPR
and reduction in refunds to customers for previously over collected BTER
balances. Also contributing to the increase was the receipt of approximately
$9.0 million in insurance proceeds related to a previous claim. These increases
were partially offset by an under collection of energy costs in 2013, as opposed
to an over collection of energy costs in 2012, resulting from adjustments to
BTER rates.
Cash used by Investing Activities - The decrease in cash used by investing
activities was primarily due to decreased capital expenditure for the NV
Energize project, partially offset by the reduction of CIAC received under the
American Recovery and Reinvestment Act of 2009, also related to the NV Energize
project.
Cash used by Financing Activities - The decrease in cash used by financing
activities is primarily due to a reduction in dividends to NVE.
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. Available liquidity as of March 31, 2013 was as follows
(in millions):
Available Liquidity as of March 31, 2013 (in millions)
SPPC
Cash and Cash Equivalents $ 85.3
Balance available on Revolving Credit Facility(1) 243.7
$ 329.0
(1) As of May 7, 2013, SPPC had approximately $243.7 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's $250 million 5.45% General and Refunding Notes, Series Q, will mature on
September 1, 2013. To meet this maturing debt obligation, SPPC intends to use a
combination of internally generated funds, its revolving credit facility, and/or
the issuance of long-term debt. As of May 8, 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 Ratingsbelow). In 2012, SPPC did not experience any limitations in the
credit markets, nor do we expect any significant limitations in 2013. However,
disruptions in the banking and capital markets not specifically related to SPPC
may affect its ability to access funding sources or cause an increase in the
interest rates paid on newly issued debt.
In prior years, SPPC required significant amounts of liquidity due to the
magnitude of capital expenditures needed to support a growing customer base and
to support unstable energy markets. As SPPC 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 they 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 three months ended March 31, 2013, SPPC did not pay dividends to
NVE. On May 8, 2013 SPPC declared a dividend to NVE of $20.0 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 three months ended March 31, 2013, there were no material changes to
contractual obligations as set forth in SPPC's 2012 Form 10-K.
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
March 31, 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:
a. Financing authority from the PUCN - As of March 31, 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 $598.3 million
of long-term debt securities; and (3) ongoing authority to maintain a
revolving credit facility of up to $600 million;
b. Financial covenants within SPPC's financing agreements - Under 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 March 31, 2013
financial statements, SPPC was in compliance with this covenant and could
incur up to $1.1 billion of additional indebtedness;
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; and
c. Financial covenants within NVE's Term Loan - As discussed in NVE's Ability
to Issue Debt, SPPC is also subject to NVE's cap on additional
consolidated indebtedness of $3.2 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 March 31, 2013, $1.5 billion of SPPC's General and Refunding
Mortgage Securities were outstanding. SPPC had the capacity to issue $824
million of additional General and Refunding Mortgage Securities as of March 31,
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.
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 April 30, 2013, Fitch upgraded SPPC's corporate credit rating from BB+
to investment grade BBB-. SPPC's senior secured debt is rated investment grade
by three NRSROs: Fitch, Moody's and S&P. The senior secured debt credit ratings
are as follows:
Rating Agency
Fitch(1) Moody's(2) S&P(3)
SPPC Sr. Secured Debt BBB+* Baa1* BBB+*
*Investment grade
(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, Moody's and S&P's rating outlooks are 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 March 31, 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.
52
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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 its financing agreements. In addition, certain financing
agreements of SPPC provide for an event of default if there is a failure under
other financing agreements of SPPC to meet payment terms or to observe other
covenants that would result in an acceleration of payments due. Most of these
default provisions (other than ones relating to a failure to pay such other
indebtedness when due) provide for a cure period of 30-60 days from the
occurrence of a specified event during which time SPPC may rectify or correct
the situation before it becomes an event of default.
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.
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