Exhibit 99.2
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Sierra Pacific Power Company and Nevada )
Power Company's Application to Adopt a ) Docket No. 01-_________
Market Stabilization Plan and to Establish )
an Equitable Obligation to Ensure Sufficient )
Capacity is Available )
APPLICATION FOR ORDER AUTHORIZING
IMMEDIATE IMPLEMENTATION OF
COMPREHENSIVE ENERGY PLAN ("CEP")
---------------------------------
COMES NOW Sierra Pacific Power Company ("SPPC") and Nevada Power Company
("NPC") (hereinafter "Applicants") and apply to the Public Utilities Commission
of Nevada ("PUCN") for an order accepting and adopting the Comprehensive Energy
Plan ("CEP") attached hereto as Exhibit A, and to thereby establish an equitable
obligation on the part of customers of SPPC and NPC to fund the plan and an
obligation on the part of SPPC and NPC to ensure sufficient short- and long-term
electrical energy and capacity is available to customers at reasonable prices.
This Application is authorized by NRS (S) 704.988, 704.110(6), and 704.320, and
is supported by this Application and exhibits, all supporting documentation, and
any and all oral and/or written testimony and other evidence that may be
presented at any hearing on this matter.
I.
APPLICATION
Applicants are Sierra Pacific Power Company and Nevada Power Company, both
regulated public utilities subject to the authority and jurisdiction of the
PUCN, are located at:
William Peterson, General Counsel
Sierra Pacific Power Company
6100 Neil Road
Reno, Nevada 89511
775/834-5900
William Peterson, General Counsel
Nevada Power Company
6226 W. Sahara Avenue
Las Vegas, Nevada 89146
775/834-5900
1. The material facts that Applicants are presenting to the PUCN are set
forth immediately below, and in all attached exhibits.
2. Exhibits supporting this Application are attached.
3. Applicants request an order from the PUCN directing them to implement
the Comprehensive Energy Protection Plan, which elements include:
. Long-term fuel and purchased power supply portfolios including a
strategy for reforming NPC's current short-term portfolio ("2001
Contract Reformation").
. A cost recovery mechanism that includes the implementation, effective
March 1, 2001, of tariffs establishing an average CEP Rider of
$ 0.01250 per kWh.
. Conservation and Low-Income Protections including tiered rate
structures for residential and small commercial customers, a $5
million protection fund, and voluntary curtailment program for large
customers.
4. This Application and the relief requested authorized by NRS
(S)(S)704.988, 704.110 and 704.320.
II.
OVERVIEW OF APPLICATION
This Application is brought on by an extraordinary and unforeseen crisis in
wholesale and retail power markets in the western United States, including
Nevada. That crisis has resulted in the imminent bankruptcy of the two largest
utilities in the western United States, severe and dire financial distress to
SPPC, NPC and many other western utilities, indefinite delay in opening the
retail markets to competition, establishment of an executive bipartisan Energy
Policy Committee ("Committee") to advise the Governor on the current crisis, and
to recommend a course of action insuring a safe and reliable supply of
electricity for Nevada's present and future needs at reasonable cost. Among the
recommendations proposed and adopted by the Committee is that SPPC and NPC:
. Continue in their current role as the designated provider of energy
and capacity; and
. Remain responsible for obtaining a portfolio of short- and long-term
energy contracts; and
. Secure capacity to ensure an adequate supply of electricity for Nevada
customers at reasonable rates.
The Committee's report recommends that the PUCN order the utilities to
submit a plan to procure such a portfolio of energy to include short-,
intermediate-, and long-term contracts for electricity, to provide a mechanism
for the full and timely recovery of costs of such obligations, and that the PUCN
should expedite the process for approving the portfolio.
Concurring reports issued by the Southern Nevada Water Authority ("SNWA")
and the Bureau of Consumer Protection ("BCP") likewise recommend that the
utilities reaffirm their commitment to be the "Designated Provider" and obtain a
diversified resource portfolio to meet
Nevada's needs. The SNWA recommends that the utilities secure longer-term
commitments of sale at cost-based rates, including a reasonable return for the
utilities' investors and that such contracts extend beyond the presently
negotiated transitional supply contracts entered into with the purchasers of the
utilities' power plants.
The PUCN is charged with the responsibility to (1) maximize the benefits
of a competitive market place for the provision of electric service ((S)
704.151(1)), (2) ensure and enhance reliability of service ((S) 704.151(5)), (3)
provide a flexible mechanism for regulating electric services ((S) 704.151(6)),
(4) provide for fair and impartial regulation ((S) 704.151(2)), (5) provide for
economic and reliable service ((S) 704.001(3)), and (6) balance the interests of
customers and investors by providing investors with an opportunity to earn a
fair return and provide customers with just and reasonable rates. The PUCN also
has the power and the duty to substitute fair and reasonable rates and charges
for any rates or charges that are not fair and reasonable ((S) 704.120).
NRS (S) 704.988 provides that if the PUCN determines that sufficient
capacity will not be available to customers at a reasonable price, that the PUCN
should establish "equitable obligations" for customers and electric utilities to
ensure that sufficient capacity will be made available ((S) 704.988). The
Energy Policy Committee and the Governor have recommended that the PUCN exercise
its authority under NRS (S) 704.988 to determine and establish equitable
obligations to insure sufficient capacity and energy will be made available at
reasonable prices.
There is virtually overwhelming consensus among all constituents that the
PUCN exercise its statutory authority to direct the utilities to procure long-
term supplies for Nevada customers and that the PUCN should create a mechanism,
as authorized by statute, to enable the utilities to recover the costs
associated with that effort through the imposition of equitable obligations on
customers. This Application sets forth a proposal and a Plan implementing
recommendations of the Energy Policy Committee and the Governor, and fulfills
the PUCN's
obligations under NRS (S) 704.988 and other statutes to ensure the availability
of capacity and energy at fair and reasonable prices.
As recognized by the Committee and confirmed by the extraordinary and
cataclysmic events taking place in California, reliability of supply is
absolutely dependent on the ability of the utilities to finance their supply
portfolio. The key to financability (and thus reliability) is legal assurance
of timely and fair recovery of the costs of the supply portfolio. Without such
assurance, the utilities cannot pay their fuel and energy bills and suppliers
will not undertake the risk of non-payment. This Application and Plan are aimed
at securing the reliability of supply demanded of SPPC and NPC. The rudiments
of the Plan are as follows:
. Quick and unequivocal resolution of the fate of generation
divestiture.
. Acceptance of the Utilities' long-term fuel and purchased power supply
approval, pursuant to NRS (S)704.320, of the 2001 Contract Reformation
strategy for NPC.
. Approval of the cost recovery mechanism described in Plan Section
5(b), including the implementation, effective March 1, 2001, of
tariffs establishing an average CEP Rider of $ 0.01250 per kWh.
. Approval of the Conservation and Low-Income Protections described in
Plan Section 7, including tiered rate structures for residential and
small commercial customers, a $5 million protection fund, and
voluntary curtailment program for large customers.
The Plan attached hereto and incorporated by reference sets forth the
details of each element of the Applicants' proposal. The Applicants make this
filing pursuant to and consistent with the direction provided by the Governor
and the Governor's Committee, with the sincere conviction that its adoption: 1)
is consistent with current law and regulation; 2) it is easily implemented and
practical; and 3) offers consumers of all classes maximum mitigation of current
wholesale energy prices and thus is the least burdensome means of avoiding the
extreme and irreversible impacts of the current energy crisis.
WHEREFORE, the Applicants request that the PUCN issue an Order
1. Accepting and authorizing the implementation of each element of the
Comprehensive Energy Protection Plan as described above and attached hereto,
which Plan is incorporated by reference; and
2. Grant such deviations from regulations and prior Commission Orders as
may be necessary and appropriate to implement the relief requested here; and
3. Issue such other and further relief as the PUCN deems necessary and
appropriate.
Dated this 29th day of January, 2001.
Respectfully submitted,
SIERRA PACIFIC POWER COMPANY
and NEVADA POWER COMPANY
William E. Peterson
Sierra Pacific Power Company
6100 Neil Road
Reno, Nevada 89511
775/834-5900
William E. Peterson
Nevada Power Company
6226 W. Sahara Avenue
Las Vegas, Nevada 89146
775/834-5900
By________________________________
William E. Peterson
Attorney for Applicants Sierra Pacific
Power Company and Nevada Power
Company
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Comprehensive Energy Plan
Proposal to Assure A Reliable Energy Supply
at a Reasonable Cost
for the
Citizens of the State of Nevada
January 29, 2001
Contents
Purpose............................................................ 1
Executive Summary.................................................. 2
I. Background.................................................. 6
A. Current Energy Markets Described............... 6
B. California and Nevada Compared...................... 8
C. How This All Came About............................. 11
D. Impact of Industry Restructuring.................... 12
E. Generation Divestiture & TPPAs...................... 14
F. Elements of a Solution.............................. 16
II. Load Forecast and Existing Power Portfolio.................. 18
A. Existing NPC Load Forecast and Supply............... 18
Figure 1............................................ 20
Figure 2............................................ 21
Figure 2A........................................... 22
Figure 3............................................ 23
B. Existing NPC Fuel and Purchased Power Portfolio..... 24
Figure 4............................................ 25
Figure 5............................................ 26
C. Value of NPC's TPPAs................................ 27
Contents
(continued)
D. Existing SPPC Load Forecast and Supply................ 28
Figure 6.............................................. 29
Figure 7.............................................. 30
Figure 7A............................................. 31
Figure 8.............................................. 32
E. Existing SPPC Fuel and Purchased Power Portfolio...... 33
Figure 9.............................................. 34
Figure 10............................................. 35
F. Value of SPPC's TPPAs................................. 36
III. Proposed Long-Term Portfolio.................................. 37
A. Criteria for a Long-Term Supply Portfolio............. 37
B. Proposed Portfolio.................................... 38
IV. Financial Implications........................................ 42
A. Fuel & Purchased Power Cost Trends.................... 42
B. F&PP Adjustments Under the Global Settlement.......... 43
C. Severe Financial Impact of Higher Costs............... 45
Contents
(continued)
V. Cost Recovery................................................... 48
A. Requirement for Rate Relief........................... 48
B. Mechanism Described................................... 49
VI. Conservation & Low-Income Customer Protection................... 52
A. Conservation and Low-Income Rate Design............... 52
B. Conservation and Low Income Protection Fund........... 53
C. Large Commercial Curtailment Program.................. 53
VII. Authority Requested in this Application......................... 55
A. Long-Term Supply Portfolio............................ 55
B. Cost Recovery and Rate Mitigation..................... 55
Conclusion........................................................... 57
PURPOSE
-------
In accordance with PUCN regulations and Nevada Revised Statutes, Nevada Power
Company ("NPC") and Sierra Pacific Power Company ("SPPC"), together "the
Utilities," respectively submit this comprehensive energy protection plan
("Plan"). The Plan includes proposals that:
. Protect the long-term reliability of electricity supply
. Provide some certainty in retail rates in this volatile wholesale
market
. Provide a pricing plan that assures that the Utilities will have the
financial ability to secure this supply
. Protect low-income customers from many of the impacts of upheavals in
the market
. Put in place pricing initiatives that promote the efficient allocation
of energy resources
EXECUTIVE SUMMARY
-----------------
Current Situation:
- ------------------
The collapse of the energy markets in California is terrifying and
unprecedented. Skyrocketing wholesale prices for electricity and natural gas,
aggravated by severe shortages of power have created an emergency that is now
threatening the reliability of energy services throughout the Western U.S. and
even the national economy. While the causes for the California crisis are being
debated, the effect is rippling through neighboring states and now threatens the
ability of other utilities to secure their own supplies and maintain reliable
service. This condition is not self-correcting. Consumers, utilities and
governments that hope to avoid seeing the disaster spill over their borders must
be prepared for painful, bold and thoughtful action.
Many factors have contributed to the California debacle including an increasing
mismatch between growing demand and consumer opposition to new power plants. One
of the most critical factors, however, has been the inability of either Southern
California Edison ("Edison") or Pacific Gas and Electric ("PG&E") to adjust
retail prices as wholesale prices climbed. Retail consumers have been insulated
from the effects of the wholesale market and have had no incentive to conserve
or reduce demand. Edison and PG&E have been unable to recover wholesale costs
and have exhausted their financial resources in order to purchase power and
fuel. As a result, their credit ratings have been driven to low "junk bond"
status, they have slipped into default on credit agreements, and they are now
essentially insolvent.
As a result, these California companies can no longer finance the power needed
to meet their obligations to serve customers. Both Edison and PG&E have
defaulted on payments to the California Power Exchange ("CalPX"), which has in
turn failed to settle its accounts with suppliers. These defaults have caused
the CalPX to lose liquidity and close its doors March 31st, and have put other
utilities, banks, fuel suppliers, and wholesale power providers at risk.
Essential utility service is now in jeopardy as evidenced by widespread rolling
blackouts.
Consumers and their elected officials are outraged by service interruptions and
the prospect of uncontrolled increases in utility rates. Many did not believe
that the supply crisis was real until the lights went out, and many still doubt
or are confused about the magnitude of the ensuing financial crisis. The urgency
of the crisis has created a climate for easy culprits and easy solutions, but
lasting
resolution requires a balance of interests and a shared understanding of the
real market forces that will remain in play.
It is important to understand that the California crisis is both a good and bad
example of what solutions or approaches can best prevent a spread of this
problem to other states. Most notably, the imposition of artificial rate caps
on retail prices, the shortage of wholesale power, and the bottleneck effect of
a single wholesale power gatekeeper through the CalPX were the most aggravating
factors in the power system's collapse.
Exacerbating market chaos, one proposal already rushed through the California
legislature would block the sale of utility power plants to independent
generation companies, reflecting an impression that native load plants can
somehow operate less expensively under different control (or in isolation from
the rest of the wholesale market).
Risk to Nevada:
- ---------------
Nevada policy makers have already demonstrated tremendous foresight in looking
ahead when the first hint of a pricing/supply pinch appeared unexpectedly last
Spring. Shortly thereafter, the PUCN and its staff, the BCP and its staff, a
coalition of large customers and the Utilities began crafting a solution. As a
result, Nevadans have so far been spared the immediate impacts of the supply
crisis being suffered in California. However, wholesale markets have
deteriorated even further since that effort last summer, and the situation now
requires fresh and forceful measures to survive what is expected to be a
lingering or even catastrophic spread of the California crisis heading into the
summer months.
Market conditions have had a severe impact on the financial condition of the
Nevada Utilities. Compounding these conditions, delay in Nevada's generation
divestiture program will have important and potentially devastating short-term
implications for both Utilities' fuel and purchased power costs:
1) Every month that divestiture is delayed, the Utilities and its customers
loose price protections that were built into those sale agreements;
provisions that ensure that through February 2003, the Utilities can
purchase power from those plants at 1998 fuel costs.
2) The Utilities, which anticipated closing on most sales contracts by mid-
year, must now go out into today's punishing wholesale markets to purchase
the fuel supplies needed to continue to operate these plants on their own.
Acknowledging the Problem:
- --------------------------
Fortunately, many of this State's policy leaders are acknowledging the problem,
as is evidenced by the negotiations last summer around the Global Settlement,
the PUCN's resource planning order directing NPC to find longer-term solutions
to its energy supply, and the Governor's decision to delay retail open access
and appoint a panel of State and business leaders (the Nevada Electric Energy
Policy Committee) to consider these complex issues.
With this filing, the Utilities set forth concrete and lasting solutions.
Action is required, with or without generation divestiture. However, the Plan
is specifically aimed at surviving the delay of divestiture while averting a
supply and financial crisis of the magnitude being experienced by our neighbor
to the West. This Comprehensive Energy Plan ("Plan" or "CEP") incorporates
important recommendations from the Nevada Electric Energy Policy Committee
report, as well as recommendations of other key participants including the
Consumer Advocate and the Southern Nevada Water Authority ("SNWA"). The Plan
also responds to the PUCN's mandate that NPC revise its resource plan to
emphasize a long-term energy portfolio.
Plan Summary:
- -------------
Under the Plan the Utilities can fulfill their most fundamental obligations to,
and the expectations of, the customers they are pledged to serve:
. Protect access to a longer-term, balanced and reliable energy portfolio
amid the growing crisis in the Western U.S.
. Provide reasonableness in pricing to consumers to protect them from
uncontrolled price volatility and assure that retail prices will decline
when wholesale prices subside.
. Protect the financial viability of the Utilities so that they can
maintain supply agreements and creditworthiness to endure the pending
crisis and ensure adequate supply.
. Provide protections for low-income customers hit hardest by price
increases.
. Encourage conservation and stimulate responsible development of energy
supplies that ensure the long-term viability of the State's energy
market.
Requested Action:
- -----------------
NPC and SPPC jointly request immediate PUCN action on the following initiatives:
. Quick and unequivocal resolution of the fate of generation divestiture.
. Acceptance of the Utilities' long-term fuel and purchased power supply
portfolios as described in Section 3(a), including specific approval,
pursuant to NRS (S)704.320, of the 2001 Contract Reformation strategy
for NPC.
. Approval of the cost recovery mechanism described in Section 5(b),
including the implementation, effective March 1, 2001, of tariffs
establishing an average CEP Rider of $ 0.01250 per kWh.
. Approval of the Conservation and Low-Income Protections described in
Section 7, including tiered rate structures for residential and small
commercial customers, a $5 million protection fund, and a voluntary
curtailment program for large customers.
I. BACKGROUND
--------------
A. Current Energy Markets Described
--------------------------------------
After years of abundant, cheap energy supplies, global energy markets are
tightening, with demand exceeding supply. The natural result is higher global
energy prices.
i. Current State of US Electricity Markets
-------------------------------------------
In the US, the long period of energy price stability has ended. Rapid
escalations in US electrical energy markets have been caused by several
converging factors and events: a sustained and booming economy, an aging supply
of generation, insufficient new generation, laxness in conservation efforts, and
drastic and sudden changes in how electrical utilities are structured and
regulated. Because of retail rate freezes imposed as part of restructuring
efforts, the impact of these changed conditions has been largely apparent only
in the wholesale markets for electricity and natural gas. The consequent impact
of wholesale price escalations on the financial stability of utilities has
pushed the issue into the fore, however, as many utilities across the West seek
emergency rate relief to remain solvent.
ii. Current State of Western US Energy Markets
-----------------------------------------------
Western markets, and California in particular, are in full-blown crisis. Poor
market institutions, acute supply shortages, high natural gas prices, and
environmental emission constraints have driven wholesale prices to extraordinary
levels. A useful comparison of the magnitude of current wholesale prices might
be to a gallon of gasoline priced at $40.00.
Because many Western utilities have not been able to adjust their retail rates
to reflect these higher costs, they are compelled to buy wholesale energy at
prices vastly above what they can collect in their capped or frozen retail
rates. With billions of dollars of losses the two largest utilities in
California are now on the brink of bankruptcy and others in the region are fast-
approaching that condition. Accordingly, they cannot secure supplies and
customers have lost or are threatened with the loss of reliable utility service.
Even bankruptcy does not afford a solution because the bankruptcy court can
neither raise retail rates nor compel wholesale generators to sell energy to
bankrupt utilities who cannot recover revenues sufficient to pay the costs of
procurement. Creditors can only operate a utility in the context of a
bankruptcy if its ongoing revenues cover its ongoing costs. Furthermore,
bankruptcy divests state regulators of all jurisdiction and control over the
utilities and transfers that authority to the bankruptcy court.
This is no short-term problem. New supply cannot be brought on line quickly
enough to solve today's problems, as new power plants can take years to site and
construct. Pipelines are also costly and difficult to expand. As the Nevada
Consumer Advocate has pointed out, the cheapest and most abundant generating
fuel in the US is coal. Yet it's been seven years since the last new coal plant
was permitted. Moreover, as evidenced by the City of San Jose's refusal to
issue siting authority to a new generator even while its high-tech Silicon
Valley industries were suffering through 90 minute rolling blackouts, community
resistance to any new power plant development remains strong-- NIMBY ("not in my
back yard") has given way to BANANA ("build absolutely nothing, anywhere, near
anybody").
In the face of shortages and utility obligations to buy high and sell low, large
unregulated generation owners find they have a great market advantage. Even
without illegal or collusive pricing, generators are operating in a very
attractive "sellers' market," selling their ever-more-dear wholesale supplies at
whatever prices the market will bear, and withholding generation where payment
default is likely.
If end-use consumers actually had to pay these prices, basic economic theory
tells us that demand would fall and price decreases would soon follow. But any
retail energy rate increases haven't come close to increased fuel and purchased
power costs. In fact, retail energy customers continue to pay rates established
when (and consume energy as if), supplies were abundant and cheap. Moreover,
after years of abundant supply and stable (or even declining) prices, customers
do not trust in or believe the underlying economics of the current crisis, and
are protesting even the notion of higher rates.
The answer to this dysfunctional market is not as simple as confiscating the
excess profits of wholesale generators. Those excess profits, as painful as
they are to bear, would eventually spur generation to: (1) stay on line, (2)
become more efficient, and (3) be newly constructed. If California becomes less
profitable than other markets by way of windfall profits tax or punitive re-
regulation, these same
generators will move to another market, or part of another market, thereby
exacerbating the problem. As an illustration, when price caps were placed on the
high "peak hour" prices last fall, the peak prices came down to the cap, but the
off-peak prices rose and the "average price" actually ended up higher.
Ultimately the market finds the path of least resistance.
B. California and Nevada Compared
- ------------------------------------
Fortunately Nevada differs in many respects from California. However, the
States share enough similarities that Nevada will find itself in precisely the
same crisis in absence of responsible leadership and prompt action.
i. Differences Between California and Nevada
---------------------------------------------
1. Nevada Utilities continue to own and operate generation plants that
produce nearly half of their energy requirements. Even after divestiture,
Nevada Utilities will have access to the entire regional wholesale market
to meet their Provider of Last Resort obligations. This differs
substantially from the California model, which required certain generation
divestiture and then mandated that California utilities sell any output
from retained generation exclusively into and buy exclusively out of the
artificial and highly constrained CalPX.
2. If the Nevada Utilities are allowed to complete the sale of their
generators (in accordance with FERC and PUCN orders and as encouraged by
others), the Utilities have negotiated "call" rights on the output of
their plants through at least February, 2003. The prices for these
protective buy-back purchases are based on historical (1998) fuel and
operating costs-- significantly below recent wholesale prices. These
transitional purchased power agreements ("TPPAs") have a value of hundreds
of millions of dollars because the purchase price of energy under the
contracts is hundreds of million of dollars below what it would cost the
Utilities to: 1) purchase replacement power in the wholesale market, or 2)
generate power using current fuel prices. However, delay in the sale of
these plants delays the implementation of the TPPAs. The California
utilities were prohibited from making such buy-back arrangements, but
rather were required to purchase exclusively from the CalPX.
3. The California utilities were effectively prohibited from executing forward
contracts, but instead were required to purchase almost exclusively from
the CalPX, a highly constrained and volatile wholesale spot market. Within
the limits of Nevada's restructuring statutes, the Nevada Utilities have
been able to purchase much of their requirements for wholesale power in the
forward markets and lock in the price of future purchases. For example,
assuming that divestiture proceeds on schedule and that the TPPAs are in
place, the Nevada Utilities have already contracted for virtually all of
their normalized expected loads for 2001 and significant amounts for 2002.
Because the prices negotiated are significantly below current and projected
market prices, these forward purchase contracts (like the TPPAs) are now
worth hundreds of millions of dollars more than current wholesale market
purchases.
While this buying strategy has worked to hold costs down, it could be far
more effective if the uncertainty around date(s) for retail open access
were lifted. Because of the loss of load necessitated by customer choice,
the Utilities have been unable to secure supplies much beyond 2001 as they
may be without customers to use that supply.
4. California Utilities PG&E and Edison have been under an absolute rate
freeze since the opening of the retail energy market. In fact, they only
recently received emergency authority to implement insufficient interim
increases-- under great protest and subject to refund. Through the
foresight of the PUCN and its staff, the BCP, a coalition of large
customers and the Utilities, Nevada has already begun to slowly increase
retail prices. As painful as these staged increases are, they have begun to
address the financial implications of these markets and communicate the
correct price signals to customers, although as outlined below, these
actions have also proven to be inadequate and insufficient to protect
consumers.
5. The Nevada Utilities have not been deferring the high cost of purchases on
their balance sheets. Instead, they have been reflecting these losses in
current period income statements as red ink. As a result, Nevada Utilities
are not seeking recovery of historical energy costs. In contrast, the
California companies are facing much higher prices for future costs and the
collection of billions of dollars of past costs deferred onto their balance
sheets.
ii. Similarities Between California and Nevada
-----------------------------------------------
Unfortunately, there are also significant similarities between Nevada and
California. While the Nevada Utilities have been able to moderate and forestall
devastating customer impacts being experienced in California, they cannot avoid
them altogether or forever. Following are some important similarities:
1. Nevada Utilities operate in regional wholesale markets suffering severe
shortages and rapidly escalating prices.
2. New generation supply will take time to come on line.
3. Because of rate caps, customers are not exposed to and therefore have little
appreciation for the actual cost of their energy usage and thus consume it
inefficiently.
4. The Utilities are losing hundreds of millions of dollars as they buy in the
wholesale market at multiples of their retail price recovery.
5. Without prompt and adequate rate relief, the Nevada Utilities will be unable
to pay for wholesale power, and the "California crisis" will be upon Nevada.
6. Restructuring and the schedule for customer choice have inserted
uncertainties that prevent cogent, long-term energy planning.
C. How This All Came About
- --------------------------------
Economic growth is the principal driver of long-term utility demand. In the
short term, utility demand is closely correlated with weather. The supply of
generation is principally influenced by four major factors:
1. Technology
2. Environmental pressures
3. Regulation
4. Pricing
Improvements in generation plant efficiency associated with economies of scale
ended in the early 1970s. After building very large (and expensive) nuclear and
pulverized coal generating stations, utilities found themselves with an over
abundance of supply in a sluggish economy. The largest plant was no longer the
most efficient to run. Many utilities and their customers suffered the impact of
paying for plants that were not fully utilized. Customer rates went up.
Shareholder value fell as utilities had to write-off assets, the costs of which
regulators would not allow to be passed on to consumers.
In order to meet future customer demand, and with pressure from regulators,
utilities exercised a bias for purchasing power in the supply-rich wholesale
market (at prices below long-run marginal cost) rather than building additional
generation. Utility customers enjoyed stable and declining rates.
Even as excess wholesale supply began to be used up, the bias for purchased
power continued. Environmental opposition mounted to large central station coal
plants-- the most familiar to utilities and the most economical to operate. In
addition, marketers employing new generation technology now had access to the
wholesale electricity markets. Independent Power Producers ("IPPs") using
smaller scale, highly efficient, clean burning natural gas turbine technologies
were ready to meet demand. Fortunately, natural gas was both abundant and cheap.
The bias for purchased power was strengthened by the National Energy Policy Act
of 1992. Wholesale competition for electricity was mandated and if utilities
built expensive generation plants, they might not have the customers to pay for
them. Utilities with growth (e.g., NPC and SPPC) therefore used capital to build
wires. Utilities without customer growth invested outside of the industry--
sometimes with disastrous financial results.
Encouraged by price signals that electricity was cheap customer demand began to
outstrip supply. Opposition to new large central station generating supply
continued, and the IPPs, who focused on smaller, natural gas fired generating
supply, were unable to keep up with demand. Natural gas supplies also began to
diminish.
D. Impact of Industry Restructuring
- --------------------------------------
Competitive restructuring initiatives were introduced in the midst of these
market dynamics. Restructuring the electric utility market was intended to
duplicate the successful introduction of competition in other industries such as
long-distance telecommunications and natural gas pipelines. Proponents argued
that competition would drive out inefficiencies and result in lower prices. But
just in case retail competition didn't result in lower prices, policy makers
adopted a "have your cake and eat it too" strategy that ostensibly protected
customers from the potential negative impacts of the open market with retail
price caps.
While in the long run it may be true that competition reduces prices, markets
always reflect the balance (or imbalance) of supply and demand. Given that
competition was introduced during supply shortages, prices skyrocketed. The
magnitude of the impact made the policy of rate freezes financially disastrous
for utilities in Nevada and elsewhere.
When prices rise to the point that suppliers earn excess profits, economic
theory tells us that two events are triggered. First, it causes new entrants to
enter the market. Second, it causes consumers to reduce the quantities they are
buying.
These effects haven't been experienced, however. First, the relative supply
imbalance was miscalculated. While prices rose, no one expected them to become
so extreme. Second, because of existing retail rate caps, customers have
exercised inaccurate or inappropriate demand responses. Third, while new
supplies always take time to bring to market, the extant uncertainties in the
regulatory and political environment actually discourage the development of some
new generation supplies.
i. Nevada's Restructuring Plan
------------------------------
Each State has taken its own unique approach to utility restructuring. Some have
adopted sweeping changes on an accelerated pace (e.g., California) while others
have moved little or not at all (e.g., Kansas and Missouri). Some states'
restructuring plans leave utilities with a large role in supplying energy.
Others leave the utility with the exclusive job of delivering electricity
provided by others.
Under Nevada's approach customers have the option-- but are not required-- to
find competitive energy supplies through February 2003, with such third-party
supplies delivered across the Utilities' wires. Beginning March 1, 2003, the law
states that Utilities must be structured so that the distribution utility
provides only wire service. At that time, all customers must then take energy
service from some third party-- a Provider of Last Resort or an Alternative
Seller.
ii. Changing Customer Choice Dates & Portfolio Planning
-------------------------------------------------------
One serious deficiency in Nevada's restructuring plan is the uncertainty in
knowing (and therefore the impossibility of planning for), who will have the
responsibility for supplying energy to retail customers and for how long. AB
366, the restructuring law passed in 1997, called for customer choice to begin
on 12/31/99, and completely excluded the Utilities from the energy supply
business. SB 438 changed that date to 3/1/00 or such other date as the Governor
declares. Under SB 438, the Utilities would have limited supply obligations as
early as July 2001, and would be entirely out of the supply business on March 1,
2003, to be replaced by a third party (perhaps a utility affiliate) designated
by the PUCN as a "provider of last resort." In February 2000, the Governor
delayed open access indefinitely. The Global Settlement called for phased-in
customer choice, beginning November 1, 2000 and continuing through December 31,
2001. In October the Governor acknowledged the weaknesses in the market and
delayed phased-in open access until September 2001, or such sooner date, as he
deems appropriate. In his State of the State address the Governor further
indicated that he would not support deregulation without assurances that power
supplies are secure.
These delays have been prudent given market conditions. Nevertheless, it is
impossible to execute a long-term portfolio plan in such an environment. Neither
the Utilities nor potential competitive suppliers have any way of knowing who
will serve a given customer when or for how long. Because of the huge credit
risk and expense of long-term contracts or obligations, the length of time it
takes to build generation, and the large capital investment generation requires,
neither the Utilities nor the competitive suppliers can effectively prepare to
meet future
customer demand unless they know with some assurance what the demands on them
might be.
Puts and calls (option tools), which are normally available to hedge such risk,
are not cost effective. Unfortunately, the extreme volatility in both natural
gas and electricity markets makes these tools highly ineffective for such
planning. Indeed, in this market just the right to buy power at specified prices
costs more than the actual power did just a few months ago.
E. Generation Divestiture & TPPAs
- ---------------------------------
Under Nevada's restructuring laws and regulations, the Utilities were not
required to divest their generation resources. However, absent divestiture they
were required to functionally separate generation from the regulated wires
business.
For many reasons, the Utilities opted for divestiture. First, the Utilities
believed the required functional separation would be an inefficient, burdensome
and uneconomical way to operate their businesses. Second, in the face of large,
regional competitive energy markets populated by generation owners many times
their size, the Utilities believed they would have been disadvantaged by owning
a relatively small, thermally inefficient fleet of plants in a large and
intensely competitive market. Given the alternatives, the Utilities offered to
divest. Not only was the offer accepted, but both federal and State regulators
demanded divestiture as a condition to their merger approvals. The merger of NPC
and SPPC, and the obligation to divest generation, became a cornerstone of 1999
restructuring legislation (SB 438) and the Global Settlement. Two iterations of
a formal divestiture plan were filed with and ultimately approved by the PUCN.
The Utilities have since completed competitive auctions of their generating
units, which to date have resulted in seven purchase and sale contracts.
To bridge the supply gap between the period during which the Utilities would
continue to serve customers and the date on which customers would be served by
competitive third-party providers (March 1, 2003), the Utilities also entered
into favorable supply contracts with the buyers of the power plants. Under these
TPPAs, the Utilities have the right to call on the output from their divested
plants at very favorable (1998) wholesale prices. Because of the extreme fuel
costs experienced since the TPPAs were executed, the prices negotiated in the
TPPAs last fall are far below the price the Utilities would be able to achieve
were they to
retain ownership of the units. Thus the value of these contracts to the
Utilities and their customers today is far greater than it was when they were
negotiated.
The Asset Sales Agreements listed below are each subject to approval by the
PUCN, the FERC, and in some instances the CPUC. The Utilities have been working
with the PUCN Staff and the Consumer Advocate to prepare a series of filings
with the PUCN, the first of which is to be made within days of this writing, to
obtain approval of these pending sales. The review process for each filing is 60
days:
. Harry Allen (NPC): Pinnacle West Energy Corporation
. Sunrise/Sunpeak (NPC): Reliant Energy
. Reid Gardner (NPC): NRG Energy/Dynegy
. Clark (NPC): NRG Energy/Dynegy
. Tracy/Pinon (SPPC): WPS (Wisconsin Power)
. Valmy (SPPC): NRG Energy
With the auctions completed and the sales contracts and TPPAs negotiated and
signed, the only remaining obstacle to closing these transactions on time (July
1, 2001) is final regulatory approval. Despite the progress made to date, recent
events in both California and Nevada have put generation divestiture and thus
the value of the TPPAs in jeopardy.
. On January 12/th/ the general manager of the SNWA publicly challenged
the wisdom of NPC's pending divestiture of its generation units and
suggested that SNWA or some other public authority assume the role of
energy purveyor for the Las Vegas metropolitan area. If acted upon by
the Legislature or the PUCN, SNWA's proposal would halt the pending
sales and destroy the value of the TPPAs negotiated as a part of the
sale of the Mohave, Reid Gardner, Clark, Sunrise and Sunpeak plants.
. On January 18/th/ California enacted a law prohibiting any further
divestiture of generation properties by California utilities--
including Sierra Pacific Power Company-- until 2006. Unless modified by
future legislative action or by a court, divestiture of SPPC's Valmy,
Tracy and Ft. Churchill plants is halted. As Edison is the operating
partner in the Mohave Station, the pending sale of that unit is also
implicated. Without divestiture, the TPPAs negotiated with the buyers
of these units as part of the sale agreements are
terminated. If, as a result of California's actions, the buyers of
NPC's other units are unable to qualify as exempt wholesale generators,
Nevada consumers will lose the value of the TPPAs for Reid Gardner,
Clark, and Sunrise/Sunpeak as well.
. On January 24/th/ the Consumer Advocate filed a Petition with the PUCN
seeking to halt regulatory review of all pending sales agreements for
all Nevada generation until the PUCN can make a determination that
generation divestiture is still in the public interest. If adopted by
the PUCN, the Consumer Advocate's proposal would at minimum delay the
effective date for TPPAs for all SPPC and NPC units, and require that
the Utilities immediately secure a fuel supply to run these generators
through the Summer peak and perhaps beyond.
F. Elements of a Solution
- -------------------------------
Nevada can avoid the energy crisis presently afflicting California, but to do
so, the State must exercise bold leadership and act immediately. Virtually every
person and every business in Nevada will benefit from the implementation of a
cogent, comprehensive energy plan. These issues cannot be effectively addressed
without difficult compromises, however. Existing institutions, understandings
and relationships must demonstrate flexibility and willingness to change and
adapt to these unprecedented conditions.
In order to assure a long-term, fairly priced, reliable energy supply in Nevada,
the comprehensive energy plan must have the following components:
1. To avoid the debacle in California, Nevada must implement a
well-planned and measured approach to customer choice and retail
competition. At a minimum, the Utilities, wholesale generators, energy
marketers and customers require from policy-makers:
a. Quick and unequivocal resolution of the fate of Nevada's
divestiture process, as lingering uncertainty will only increase
risk and thus costs.
b. Approval of longer-term contracting for wholesale fuel and
purchased power in a balanced and, where possible, an assignable
portfolio with the following elements:
i. Mixture of short, intermediate and long-term resources
ii. Blend of spot, indexed and fixed prices
iii. Flexibility to accommodate future changes with the
potential to benefit from future lower prices.
c. Renewed focus on planning and development of new generation
supplies and other infrastructure featuring:
i. Greater fuel diversity
ii. More electric and gas transmission infrastructure
iii. Expedited environmental and siting review
2. As events in California have proven, reliability of supply is
absolutely dependent on the ability of the Utilities to finance their
supply portfolio. The key to financability (and thus reliability) is
legal assurance of timely and fair recovery of the costs of the supply
portfolio. Without such assurance, Utilities cannot pay their fuel and
energy bills and suppliers will not undertake the risk of non-payment.
In addition, timely recovery of supply costs:
a. Is the best means for triggering accurate, timely and meaningful
demand and conservation responses
b. Is necessary to achieve an efficient allocation of scarce energy
resources
c. Can be combined with rate design innovations to provide
protections for low-income customers
II. LOAD FORECAST AND EXISTING SUPPLY PORTFOLIO
-----------------------------------------------
As a matter of course the Utilities forecast expected loads many years into the
future. Regardless of whether that energy is supplied by the Utilities, or by
third-party competitive suppliers, a discussion of forecasted demands and
available resource options is helpful to understanding Nevada's electrical
requirements.
A. Existing NPC Load Forecast and Supply Requirements
- -------------------------------------------------------
Due to the tremendous population growth in Las Vegas, NPC has one of the more
rapidly growing resource requirements in the nation. Figure 1 (page 20)
illustrates historical and projected peak (summer) demand in MW (left scale) and
MWh energy use (right scale).
Southern Nevada has a poor seasonal load factor (based on uniform consumption
over time) due to hot summer temperatures. As a result, the supply portfolio
must accommodate huge swings in load, not only within a day but across seasons.
This is illustrated in Figure 2 (page 21), which depicts total estimated typical
daily requirements, by semi-month period, for summer 2001.
Given uncertainty as to when customers may have choice, a long-term portfolio
matched to load has been impossible. Nevertheless, NPC has secured essentially
all of its normalized projected needs for 2001, albeit at considerable cost and
at great economic risk. See Figure 2A (page 22). If prices fall and the market
opened to retail competition, NPC could be left with a high-priced, "out of
market" white elephant portfolio, which it would have to unload at a loss.
NPC has also secured significant supplies for 2002. For the reasons articulated
above, however, the Company has not contracted for new long-term resources.
Figure 3 (page 23) shows the relative amount of supply secured to date through
2002 (excluding existing long-term contracts and generating capability).
If NPC is required to continue integrated utility service (i.e., energy supply
and distribution/transmission) beyond February 28, 2003, its current portfolio
is vastly short. However, without any certainty that it will have this
obligation, and without any legal assurance of recovering the future costs of
these obligations, NPC does not have the financial ability to secure this
supply. Given current market
conditions, regulatory assurance of revenues sufficient to recover these
expenditures is absolutely necessary to satisfy the credit worthiness
requirements of wholesale suppliers.
B. Existing NPC Fuel and Purchased Power Portfolio
- --------------------------------------------------
As indicated above, provided divestiture proceeds on schedule, NPC has secured
virtually all of its normalized requirements for 2001, and a share of its
requirements through 2002. NPC has expedited these purchases on a far more
aggressive schedule than in any previous year. To date, this strategy has paid
off. The existing portfolio was secured at prices vastly below what it would
cost to acquire that same portfolio today. However and very significantly, NPC's
existing portfolio was acquired at prices far above what is presently being
recovered in current retail rates, including the projected monthly adjustments
for the F&PP Rider.
As an illustration, Figure 4 (page 25) shows the increase in price of the Palo
Verde forward contract for on-peak Q3 2001, along with the price of getting it
to NPC's service territory (i.e., the "basis"). The price for this power has
more than doubled since the Global Settlement was negotiated last summer. NPC's
customers have benefited by purchasing much its 2001 supply prior to this latest
price movement.
Natural gas prices have also risen precipitously. The April-October 2001 NYMEX
contract for natural gas at the Henry Hub shows a significant run-up in price.
More telling still is the expansion of the basis into southern California, a
proxy for getting natural gas into Las Vegas. See Figure 5 (page 26). NPC has
not locked in fuel prices beyond June 2001, the expected date of the plant
sales. However, NPC has acquired fuel and locked in prices through the
anticipated closing date of the pending plant sales. These fuel contracts were
also acquired at prices favorable to the current market. Were NPC required to
acquire further fuel supplies should the plant sales be delayed, the price for
this fuel would be considerably higher given current market prices. Current fuel
contracts are summarized in Table 1.
Table 1
Nevada Power Plant Gas
----------------------------------------------------------------
Jan thru June 2001
----------------------------------------------------------------
Volume Dth Cost/Dth Total Value
------------------------------------------
Contracted 26,570,000 $ 7.04 $ 187,052,800
Current Market $ 10.09 $ 268,091,300
=========================
Value "in the money" $ 3.05 $ 81,038,500
C. Value of NPC's Transitional Purchase Power Agreements
- ----------------------------------------------------------
As contemplated by SB 438 and the Global Settlement, NPC negotiated buy-back
contracts (dubbed TPPAs) with the buyers of its power plants. These agreements
provide NPC with the rights to call on 100% of the output from the divested
power plants through February 2003 at historical (1998) prices. Because of
higher current fuel costs, NPC can purchase the energy output from these plants
through February 2003 at prices well below the costs NPC would incur as its
"all-in costs" were it to retain the plants and buy its own fuel in the current
market.
Because of this favorable pricing, the buyers have appropriately discounted the
purchase price of the plants to account for their uneconomic obligations. As an
additional benefit, these contracts offer protection from the further run-up in
prices experienced since the contracts were negotiated. Indeed, if the contracts
were to be negotiated today, the discounts would be much higher than those
agreed to in the pending TPPAs.
Table 2 below summarizes the quantity of capacity under contract, the negotiated
discounts, estimated current value of the contracts, and their net in-the-money
value. Two comparisons are offered. The first is the excess value compared to
purchasing that same power in the current wholesale markets. The second is the
estimated excess value compared to retaining ownership of the plants and running
them with fuel purchased at current market prices. Were divestiture halted, this
very significant value would be lost. However, if divestiture remains on course,
the contracts will provide tremendous value that can be either transferred or
restructured into other contractual portfolio arrangements for the benefit of
Nevada's economy.
Table 2
----------------------------------------------------------------------------------------------
Nevada Power - Market Value of TPPAs *
----------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------
Mark-to-Market as of Jan 10, 2001
TPPA Cost
TPPA Total* Assume 6/30/01 Net in the Money
(1) Divestiture "Replacement Cost in the Market"
----------------------------------------------------------------------------------------------
1910MW $ 348M $ 1550M $ 1202M
----------------------------------------------------------------------------------------------
*Excludes: Navajo
------------------------------------------------------------------------------
No Plant Additional Cost of Fuel Average Monthly
(2) Sales July 1, 2001 to February 28, 2003 Fuel cost of delay
------------------------------------------------------------------------------
2165MW $ 557M $ 28M
------------------------------------------------------------------------------
D. Existing SPPC Load Forecast and Supply Requirements
- --------------------------------------------------------
SPPCO also has one of the more rapidly growing resource requirements in the
nation. Figure 6 (page 29) illustrates historical and projected peak (summer)
demand in MW (left scale) and MWh energy use (right scale).
However unlike NPC, SPPC benefits from a high seasonal load factor due to its
less varied climate and a substantial portion of load consumed by mining and
manufacturing sectors. Customers within these segments typically consume power
on a more uniform basis throughout the season and during the day. In addition,
residential and small commercial customers' load is more evenly balanced between
the heating and cooling seasons. As a result, the supply portfolio does not need
to accommodate huge swings in load across seasons. This aspect is illustrated in
Figure 7 (page 30), which shows the total estimated typical daily requirements,
by semi-month period, for summer 2001.
Given the uncertainty as to when customers may have choice, SPPC has also not
been able to acquire a matched long-term portfolio. Nevertheless, like NPC, SPPC
has secured virtually all of its normalized projected needs for 2001, again at
considerable cost and at great economic risk. See Figure 7A (page 31). SPPC has
also secured some supplies for 2002. For the reasons articulated above, however,
the Company has not contracted for new long-term resources. Figure 8 (page 32)
shows the relative amount of supplies secured to date, through 2002.
If SPPC is required to continue integrated utility service (i.e., energy supply
and distribution/transmission) beyond February 28, 2003, this portfolio is
vastly short. However, without any certainty that it will have this obligation,
and without any assurance of recovering future costs of these obligations, SPPC
also does not have the financial ability to satisfy wholesale energy providers.
Given current market conditions, regulatory assurance of revenues sufficient to
recover these expenditures is necessary and required to satisfy the credit
worthiness requirements of wholesale suppliers.
E. Existing SPPC Portfolio
- ----------------------------
As illustrated above, SPPC has secured virtually all of its normalized
requirements for 2001, as well as a share of its requirements through 2002. Like
NPC, SPPC has expedited these purchases on a schedule that is more aggressive
than in any previous year. Again, this strategy has paid off. This portfolio was
secured at prices vastly below what it would cost to acquire that same portfolio
today, but again at costs well above those covered in current rates (including
the projected monthly increases provided by the F&PP Rider).
As an illustration, Figure 9 (page 34) shows the increase in price of the
California-Oregon Border (COB) forward contract for on peak Q3 2001, along with
the price of getting energy to SPPC's service territory (i.e., the "basis"). The
price of this power has almost tripled since the Global Settlement was
negotiated last summer. SPPC's customers have benefited by purchasing much its
2001 supply prior to the latest price movement.
Again, natural gas prices also demonstrate significant price escalations. See
Figure 10 (page 35). The April-October 2001 NYMEX contract for natural gas at
the Henry Hub shows a similar run-up. More telling still is the expansion of the
basis into northern Nevada. Just a few months ago, natural gas in this region
could be purchased at a discount to the price at the hub. Now it trades at a
premium. Like NPC, SPPC has acquired fuel through the approximate expected
closing date of the pending plant sales. These fuel contracts were also acquired
at prices very favorable to the current market. Were SPPC required to acquire
further fuel supplies should the plant sales be delayed, the price for this fuel
would be considerably higher given current market prices. See Table 3.
Table 3
Sierra Fuel Prices
-------------------------------------------------------------------------
Sierra Pacific Plant Gas Jan thru June 2001
-------------------------------------------------------------------------
Volume Dth Cost/Dth Total Value
------------------------------------------------
Contracted 26,120,000 $6.33 $165,339,600
Current Market $8.81 $230,117,200
============================
Value "in the money" $2.48 $ 64,777,600
F. Value of SPPC's Transitional Purchase Power Agreements
- -----------------------------------------------------------
SPPC has also negotiated TPPAs with the buyers of its power plants. Like the NPC
TPPAs, these agreements provide SPPC with the rights to call on 100% of the
output from the divested power plants through February 2003 at historical (1998)
prices. Because of escalating fuel costs, SPPC can purchase energy from these
plants through February 2003 at prices below what it would cost SPPC to retain
and run the plants, buying its own fuel.
Because of this favorable pricing, the SPPC plant buyers have also significantly
discounted the purchase price of the plants to reflect their uneconomic
obligation to sell at below cost. As an additional benefit, these contracts
offer further protection from run-ups in prices experienced after the contracts
were negotiated. Indeed, if the contracts were negotiated today, the discounts
would be far greater than those agreed to in the pending TPPAs.
Table 4 below summarizes the TPPA contracts, the negotiated discounts, the
estimated current value of the contracts, and their net in-the-money value. Two
comparisons are offered. The first is the excess value compared to purchasing
that same power in the current wholesale markets. The second is the estimated
excess value compared to retaining ownership of the plants, and having to
purchase fuel at current costs. Were divestiture halted and these contracts lost
or delayed, this very significant value would be lost. However, if divestiture
remains on course, the contracts provide tremendous value that may be
transferred or restructured into other contractual portfolio arrangements for
the benefit of SPPC customers.
Table 4
--------------------------------------------------------------------------------------------------
Sierra Pacific - Market Value of TPPAs *
--------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------
Mark-to-Market as of Jan 10, 2001
TPPA Cost
TPPA Total* Assume 6/30/01 Net in the Money
(1) Divestiture "Replacement Cost in the Market"
--------------------------------------------------------------------------------------------------
789MW $ 130M $ 236M $ 106M
--------------------------------------------------------------------------------------------------
* Excludes: Fort Churchill
--------------------------------------------------------------------------------
No Plant Additional Cost of Fuel Average Monthly
(2) Sales July 1, 2001 to February 28, 2003 Fuel cost of delay
--------------------------------------------------------------------------------
1015MW $ 315M $ 16M
--------------------------------------------------------------------------------
III. PROPOSED LONG-TERM PORTFOLIO
---------------------------------
The drastic changes in the energy markets over the last year are now painfully
obvious. Management of these market conditions is much more difficult with
delays in generation divestiture. Not only are the customer protections of the
TPPAs delayed, but the Utilities are suddenly back in the generation business--
at least for the short term-- and need to find and secure fuel supplies for
units that were to have been sold prior to the summer peak. In addition,
leadership from many constituencies is calling for serious redirection of
Nevada's energy policy with an emphasis on securing a reasonably priced
long-term supply portfolio.
With sufficient time and study others could perhaps formulate and execute such a
plan. In making the proposals set forth herein the Utilities do not intend to
preclude other entities from eventually assuming the role of retail energy
provider. Notwithstanding the Utilities' stated desire to eventually exit the
supply business to focus on pipes and wires, no one can reasonably dispute that
given current market conditions and the need to immediately respond
operationally to meet summer peak, the Utilities are in the best position to
undertake this responsibility. The Utilities will, however, take reasonable
steps to ensure the assignability of their long-term portfolios to any other
entity willing and able to assume that responsibility in the future.
Accordingly, NPC and SPPC propose the following portfolio plan.
A. Criteria for a Long-Term Supply Portfolio
- ----------------------------------------------
In creating a long-term supply portfolio, there are important trade-offs that
must be carefully balanced and accommodated in order to arrive at the optimum
overall solution.
Price certainty: Fixed prices remove the risk of price increases, but they
---------------
also preclude taking advantage of falling prices. Furthermore, fixed prices
can create price shocks when favorable contracts expire, and may send poor
price signals to customers with regard to demand and conservation. If the
contracted-for fixed prices turn out to be a poor financial decision for
suppliers, counter-party risk, and risk of failure to deliver also exists.
Term: Long-term contracts reduce supply risk, but they also require a high
----
level of Utility financial strength and creditworthiness, as the seller
wants
security that future payments will be made. Long-term contracts also mean
long-term obligations, and therefore less flexibility, should loads decline
(e.g. as economies slow or with retail open access). Flexibility shifts
risks and suppliers charge more for assuming more risk. Thus flexibility in
pricing long-term contracts can only be obtained at additional cost.
Facilities: Purchases from existing facilities carries little development
----------
risk. A contract with a new plant developer includes some risk. If the
project is delayed or fails, the power may not be available when needed. On
the other hand, purchases from new facilities may reflect lower prices, as
new generators are capable of producing energy more efficiently.
Technology: Renewable energy resources are more environmentally friendly.
----------
However, they are usually smaller, less reliable, and more expensive than
conventional technology.
B. Proposed Portfolio
- -----------------------
The Utilities propose purchased power and fuel portfolios that balance risks,
mitigate rate impacts, encourage the construction of new generation, and provide
the Utilities with the necessary financial strength to enter into contracts.
After suffering the drastic run-up in prices of the past few months, wholesale
prices in the near term are the highest they have ever been. Therefore the
Utilities have proposed a portfolio that includes longer time horizons during
which contract pricing can be smoothed out over the duration of the contract.
The State of California has recently attempted to implement a similar strategy
to alleviate its current crisis. As proven by events there, their efforts were
too little and too late. It is very difficult to negotiate when you are already
in crisis.
The Utilities' strategy reduces (but does not eliminate) the need for further
immediate rate increases and helps to preserve the overall limitations of the
F&PP rider maximums. This strategy can be used for both new contracts and for
restructuring existing portfolio resources.
The Utilities' proposed portfolios are designed to meet the following
objectives:
1. Secure physically firm resources for NPC/Sierra customers.
2. Secure reasonable prices without undue volatility.
3. Encourage the development of new generating resources with diverse
fuel supplies both regionally and within the State.
4. Balance short, intermediate and long-term contracts covering both
fixed and indexed pricing.
. The final target value for hedged resources, shall be 107% of the
monthly average of the daily peak loads.
. Once the portfolio is filled, optimize that portfolio to ensure
any unused energy is sold into the marketplace to reduce the
overall cost of the portfolio.
5. Reduce the Utilities' risk to weather.
6. Send accurate price signals to consumers.
Based on these objectives, the Utilities propose to immediately implement fuel
and purchased power portfolios with the following features and attributes:
i. Long-Term Resources
(over three but less than ten years)
. In the event divestiture of generation is completed, the Utilities will
supplement quantities of physically and financially firm energy and
capacity delivered under existing TPPAs, which end February 28th 2003, with
longer-term contracts either from (1) divested resources, or (2) from other
resources. The Utilities will look to institute two-part pricing with the
first component fixed to represent capacity-related costs and the second
indexed to represent variable costs associated with energy production.
Requests for proposals should attempt to consider/replicate fuel diversity
inherent with historical ownership. The Utilities have also indicated to
developers interested in constructing new generation in the region their
willingness to partner in such projects (as allowed by law and regulators)
and/or to execute long-term purchase agreements for power when output
becomes available.
. The Utilities will mitigate high short- and intermediate-term market prices
and reduce price volatility over time by securing approximately 1000 MW of
physically firm energy for NPC under a combination of fixed pricing/indexed
price contracts with terms no greater than ten years. A request for
proposals describing this transaction ("2001 Contract Reformation") is set
forth in Appendix A. It seeks a ten-year commitment for Firm Energy, with
deliveries to begin April 1, 2001 and continuing through December 31, 2010.
Contract quantities vary by quarter and year, increasing from 275 MW in Q4
of 2001 to 1,000 MW in Q2 of 2002. Products requested include baseload (7 x
24) and peak (6 x 16). Pricing is to be fixed for the first four and three-
quarter years and indexed for the remaining five years based upon natural
gas prices. Because of the urgency of this contract opportunity, NPC
requests the PUCN's immediate approval of this strategy.
. Retain existing QF and other (PAC II) long-term contracts and NPC's
allocated share of Hoover.
ii. Short-Term and Intermediate-Term Resources
(less than three years)
. Purchase products to fill the remaining open position for Q1-Q4 of each
year, with annual, quarterly, monthly, daily and hourly spot market
purchases.
. Meet target ranges for short-term and intermediate-term purchases:
. 95%-100% physically and financially firm by beginning of period (time
t=0)
. 35%-70% physically and financially firm six months prior to start of
period
. 10%-40% physically and financially firm twelve months prior to start
of period
. 0-20% physically and financially firm up to thirty-six months prior to
start of period
iii. Daily/Hourly Spot Market Purchases/Sales
. Purchase/sell difference between firm resources secured above and
forecasted resource requirement in day-ahead/hour-ahead/real-time markets.
These differences are typically due the following factors: forecast error
in load, weather abnormalities, to forced outage of a plant or forced
outages of customers' loads.
IV. FINANCIAL IMPLICATIONS
--------------------------
The drastic increase in wholesale prices has taken a huge financial toll on the
Utilities. The Utilities continue to pay unprecedented high prices for fuel and
wholesale power. These prices would be even higher if they were not offset
somewhat by profitable wholesale trades. As verified by their respective income
statements, however, rather than reflecting the cost of capital (i.e., a fair
return on capital investment), the Utilities are hemorrhaging red ink.
Loads vary from forecast for many reasons. NPC and SPPC regularly seek to
optimize their daily and hourly portfolio by buying and selling short or excess
power in the wholesale markets. During 2000, the Utilities produced a margin on
these wholesale sales of approximately $100 million. In other words, the net
cost of purchased power would have been about $100 million higher had the
Utilities not been successful in the wholesale markets.
A. Fuel & Purchased Power Cost Trends
- -------------------------------------------
Table 5 below shows the trend for both Utilities through 2000, and projects fuel
and purchased power costs five years forward. These projections assume that
generation plant sales close June 30, 2001 and that the TPPAs are in effect
through February 2003. This table does not reflect the 2001 Contract Reformation
described above.
Table 5
Fuel and Purchase Power Cost Trends
Nevada Power Company
Historical Forecast - 7/01 Divestiture
-------------------------- ----------------------------------
1997 1998 1999 2000 2001 2002 2003 2004 2005
Nevada Jurisdiction
Net Fuel & Purchased Power Costs 395 430 466 730 1,368 1,162 1,406 1,492 1,536
(Million $)
Cost per MWh sales 28.75 30.17 30.36 43.54 79.83 65.07 75.63 77.33 76.93
% change in Cost per MWh 4.9% 0.6% 43.4% 83.4% -18.5% 16.2% 2.2% -0.5%
Sierra Pacific Power Company
Historical Forecast - 7/01 Divestiture
-------------------------- -----------------------------------
1997 1998 1999 2000 2001 2002 2003 2004 2005
Nevada Jurisdiction
Net Fuel & Purchased Power Costs 207 223 230 347 495 491 524 614 625
(Million $)
Cost per MWh sales 28.64 28.87 29.01 41.75 59.93 56.77 58.28 64.86 65.18
% change in Cost per MWh 0.8% 0.5% 43.9% 43.6% -5.3% 2.7% 11.3% 0.5%
The cost per MWh is a revealing measure. Notwithstanding the MWh cost increases
in 2000 and 2001, had NPC not purchased forward and had access to its plants to
offset those costs with wholesale sales, the costs would have been much higher.
B. F&PP Adjustments Permitted Under the Global Settlement
- ---------------------------------------------------------
General rates (non-fuel and purchased power rates) of both Utilities were frozen
pursuant to the Global Settlement until March 1, 2003. Under the Global
Settlement, fuel and purchased power ("F&PP") rates are adjusted monthly in
order reflect historical changes in fuel and purchased power costs. Monthly
adjustments are capped at levels that reflected the parties' then-best (July
2000) projections of forward price curves. Unfortunately, the caps under the
current mechanism are far lower than current prices and the F&PP rate
adjustments are no where near enough to support current fuel and purchased power
costs. See Figures 4, 5, 9 and 10. Since its implementation in August through
December 2000, the current F&PP Rider mechanism has resulted in under-recovery
of fuel and purchased power costs of $77 million at NPC and $53 million at SPPC.
Projected future under-recovery is in the hundreds of millions of dollars, which
without additional revenues will be fatal to both utilities.
A number of factors have limited the effectiveness and adequacy of the current
cost recovery mechanism. First, the F&PP Rider is calculated using a 12-month
historical average of fuel and purchased power costs. Given the rapid escalation
in prices, the 12-month average vastly understates current or even recent costs.
In other words, the Utilities pay the current MWh price for energy but recover
the much lower historical average price. This is illustrated in Table 6. This
table shows the 12-month average fuel and purchased power cost per kWh and the
monthly fuel and purchased power cost per kWh for the period September 2000
through August 2001,with actual numbers through November 2000. This result is
even starker under the case where divestiture-- and the benefits of the TPPAs--
is halted or delayed.
Table 6
Twelve Month Average vs. Current Month Cost per MWh
Nevada Power Company Sierra Pacific Power Company
12 Month 12 Month
Average Used Current Average Used Current
Month for Rates/1/ Month Difference for Rates/1/ Month Difference
Sep-00 31.62 51.00 (19.38)
Oct-00 34.23 37.20 (2.97)
Nov-00 37.37 33.58 3.79 33.46 45.13 (11.67)
Dec-00 40.50 38.16 2.34 34.95 52.61 (17.66)
Jan-00 42.01 51.59 (9.58) 36.57 62.21 (25.64)
Feb-00 42.50 53.50 (11.00) 37.39 57.59 (20.20)
Mar-00 42.72 63.41 (20.69) 38.68 75.43 (36.75)
Apr-00 43.52 66.20 (22.68) 40.25 55.55 (15.30)
May-00 45.32 88.71 (43.39) 42.57 60.49 (17.92)
Jun-00 46.94 131.85 (84.91) 44.72 61.13 (16.41)
Jul-00 49.25 96.32 (47.07) 48.29 65.00 (16.71)
Aug-00 51.74 94.69 (42.95) 49.85 63.41 (13.56)
/1/"12 Month Average Used for Rates" is the 12 months ending 3 months prior
to effective date of rate (e .g. 12 months ending June is used for rates
effective September)
Second, the F&PP Rider is effective three months following the twelve-month
historical period. As a result, cost recovery is between three and fifteen
months late. Under stable market conditions this wouldn't be a problem, but
under the current market conditions the lag results in very serious cash flow
deficiencies and huge losses in income. The mismatch between expenditures and
revenues must be funded with additional working capital that must be borrowed
(because with revenues capped there is no other source). The Utilities must also
obtain authority from the PUCN for such borrowings. Delays in the processing of
financing requests adds to the financial strain.
Third, the adjustment mechanism is capped. While these caps increase after each
six-month period, during the early period of its operation, the Utilities' costs
far exceed the permitted adjustment.
Finally, adjustments are only permitted if the 12-month average cost-per-unit
increases from one month to the next. As a result, the mechanism doesn't permit
an increase if the average doesn't increase, even if actual level of costs far
exceeds revenues. In fact, the mechanism can actually reduce revenues, even when
the average level of cost recovery is below the actual incurred costs.
Partially offsetting these limitations is the 50% carry-over mechanism.
Beginning six months into the F&PP process, if head room is available under the
caps, the ongoing F&PP Rider rate can be adjusted up to the cap to recapture
under-recovery in earlier periods. However, even with this provision, the
under-recovery is severe. The Utilities have no way of recovering costs even up
to the permissible limits contemplated in the Global Settlement. As indicated
above, the combined under-recovery for the Utilities for the period since the
Global Settlement has been in place (August through December 2000) was $130
million. For 2001, the under-recovery is even more severe-- an additional $600
million-- under the base case scenario (i.e. with divestiture and TPPAs
effective July 2001). Without divestiture and the TPPAs, the under recovery is
forecasted to be $800 million. As a comparison, the highest combined level of
net income the Utilities' have ever earned is only $160 million. Without relief
the end result is swift and certain.
C. Severe Financial Impact of Higher Costs
- ------------------------------------------------
NPC and SPPC cannot sustain these high wholesale costs without appropriate rate
recovery. While the monthly increases provided by the Global Settlement mitigate
these sharply rising costs, they do not come close to fully compensatory rates
with or without divestiture. With delays in divestiture and postponement of the
effective date of the TPPAs, the impacts are even greater.
Table 7 shows a comparison of fuel and purchased power revenues to fuel and
purchased power costs for both Utilities for the historic period 1997-2000 and
forecasted for 2001-2002 for the scenario with divestiture occurring on July 1,
2001.
Table 7
Fuel and Purchase Power Revenues vs. Cost 1997-2002
Nevada Power Company
Nevada Jurisdiction
(Million $) Historical Forecast
---------------------------- -------------------
1997 1998 1999 2000 2001 2002
Base Fuel & Purchase Power Revenues/3/ 377 390 434 480 605 724
Additional Revenue under Global Settlement 0 0 0 42 260 510
Net Fuel & Purchase Power Costs 395 430 466 730 1,368 1,162
---------------------------- -------------------
Fuel & Purchase Power Margin/2/ * * * (207) (503) 72
Fuel & Purchase Power Margin (2001-2002) (431)
/1/Includes BTER revenue (without Global Settlement), estimated F&PP related
revenue in BTGR (8.8 mills) and generation related revenue in BTGR for post-
divestiture period.
/2/Deferred energy in effect for NPC during 1997-1999; deferred energy write-off
in 1999 is not included in these numbers.
Sierra Pacific Power Company
Nevada Jurisdiction
(Million $) Historical Forecast
------------------------------------ -------------------
1997 1998 1999 2000 2001 2002
Base Fuel & Purchase Power Revenues/3/ 222 234 240 252 300 365
Additional Revenue under Global Settlement 0 0 0 5 88 145
Net Fuel & Purchase Power Costs 207 223 230 347 495 491
----------------------------------- -------------------
Fuel & Purchase Power Margin 15 11 10 (90) (107) 18
Fuel & Purchase Power Margin (2001-2002) (88)
/3/Includes BTER revenue and estimated generation related revenue in BTGR for
post-divestiture period.
The above scenario, which assumes the very low costs of the TPPA contracts
beginning July 1, 2001, shows substantial losses due to unrecovered fuel,
exceeding $600 million for 2001.
With the passage of AB 6 in California (barring further divestiture by
California utilities to 2006) and the petition by the Consumer Advocate seeking
to halt the sale of all Nevada generation (pending re-review of the
appropriateness of
divestiture), divestiture is at best delayed. Given these developments, the
Utilities have developed a "no divestiture" scenario to be used as the base case
for short-term financial analysis. Table 8 shows the impact of not divesting
generation. Fuel & purchase power losses increase to $818 million in 2001.
Table 8
Impact of No Divestiture 2001-2002
Nevada Jurisdiction
(Million $) Nevada Power Sierra Pacific Power
Forecast Forecast
-------------------------- --------------------
2001 2002 2001 2002
Base Fuel & Purchase Power Revenues 493 513 250 262
Additional Revenue under Global Settlement 260 552 88 205
Net Fuel & Purchase Power Costs 1,384 1,103 526 532
-------------------------- --------------------
Fuel & Purchase Power Margin (631) (38) (187) (65)
Fuel & Purchase Power Margin (2001-2002) (669) (253)
With or without divestiture, the losses reflected in the above scenarios will
not support operating & maintenance expenses, capital recovery, or interest
expense. Insolvency is virtually guaranteed. Significant new revenue is needed
to meet these minimum requirements and avoid problems similar to those being
experienced in California. As important, additional revenues or the assurance of
additional revenues, is required under either scenario before the Utilities (or
anyone else) can plan for and secure a longer-term, reliable energy supply for
Nevada.
Either of the above scenarios can be improved upon by restructuring existing
contracts (see, for example, the 2001 Contract Reformation). Restructuring can
reduce costs in the short-term and provide for a portion of long-term supply
requirements. This will reduce but by no means eliminate the need for immediate
rate relief. The Utilities cannot enter into such long-term contracts without
PUCN authority and the assurance of cost recovery.
V. COST RECOVERY
----------------
The ability of the Utilities to adjust prices was limited by the Global
Settlement until March 1, 2003. However, without recovery of the current costs
of providing service, the Utilities will not be able to secure a longer-term,
reliable supply of energy for Nevada. The Utilities have crafted a cost recovery
mechanism, set forth below, that accommodates both of these seemingly
requirements-- in both the scenario where plants are divested as planned, and in
the developing alternative scenario of no divestiture/no TPPAs.
A. Requirement for Rate Relief
- ------------------------------
As discussed above, the use of a twelve-month average for setting fuel and
purchase power rates is punitive and inadequate. In order solve this current
crisis, the Commission will need to look at shorter historic period and consider
known future costs and forward curves. Table 9 shows known and measurable costs
incurred for the period August 2000 through November 2000. As indicated, NPC's
fuel and purchased power rates were inadequate by nearly 13 mills per kWh, and
SPPC's fuel and purchase power rates by 14 mills per kWh.
Table 9
Under-Recovery Since F&PP Rider
Nevada Power Company
Nevada Jurisdiction
(Million $)
Aug Sep Oct Nov Total
Fuel & Purchase Power Revenues 66 50 45 41 202
Net Fuel & Purchase PowerCosts 117 75 48 38 278
-----------------------------------------------------
Fuel & Purchase Power Margin (50) (25) (3) 3 (76)
Margin per kWh (0.01283)
Sierra Pacific Power Company
Nevada Jurisdiction
(Million $)
Aug Sep Oct Nov Total
Fuel & Purchase Power Revenues 24 19 21 24 89
Net Fuel & Purchase Power Costs 37 33 26 33 129
-----------------------------------------------------
Fuel & Purchase Power Margin (13) (13) (5) (9) (40)
Margin per kWh (0.01408)
B. Mechanism Described
- ----------------------
The Utilities are committed to honoring to the greatest extent possible both the
F&PP rate-making mechanism and rate caps established in the Global Settlement.
Thus recovery of the ongoing costs of the portfolio described above must be
accomplished through a separate charge. The Utilities therefore propose to
institute a new charge, a Comprehensive Energy Plan ("CEP") Rider, that is to
mitigate the impact of current market prices and the delay or loss of the
benefits of divestiture, including the value of the TPPAs. The CEP Rider would
be adjusted when and if plants are sold and the TPPAs take effect to assure that
the Utilities do not over-recover their fuel and purchased power expenses. The
CEP Rider mechanism would operate as follows:
1. For both SPPC and NPC, an average CEP Rider of $ 0.01250 per kWh
(subject to the conservation and low-income protection rate design
described below) will become effective on March 1, 2001 and remain in
effect until adjusted as set forth below.
2. The CEP Rider will be adjusted on March 1, 2002, or sooner, if
divestiture of all units is completed and the TPPAs are in effect, and
again on September 1, 2002. The adjustment will be based on historical
experienced costs, known future costs of the fuel and purchase power
supply portfolio, and forward curves at the time of the revision.
3. In order to ensure that the CEP Rider does not cause the Utilities to
either over- or under-collect on their actual fuel and purchase power
costs, the Utilities will track and accumulate (with a carrying
charge), the difference between Nevada fuel and purchased power
revenues and costs during period January 1, 2001 through February 28,
2003.
4. Any adjustment to the CEP Rider will take into account the accumulation
of the difference between Nevada fuel and purchased power revenues and
Nevada fuel and purchased power costs, with the goal of minimizing the
accumulation through February 28, 2003.
5. Any accumulation of the difference between Nevada fuel and purchase
power revenues and Nevada fuel and purchased power costs at February
28, 2003, will either be collected from or refunded to customers over a
three year period beginning March 1, 2003, using the CEP Rider.
Thereafter, the
CEP Rider may be revised from time to time to provide full recovery of
the March 1, 2003, balance by February 28, 2006.
6. The CEP Rider is a non-bypassable charge. Thus, in the event that
retail open access is implemented prior to February 28, 2006, customers
that opt for retail open access shall be assessed the CEP Rider.
Table 10 shows the impact on the forecasted fuel margin with the implementation
of the proposed 2001 Contract Reformation solution for NPC and the proposed CEP
rider for both NPC and SPPC. Both the divestiture and no divestiture scenarios
are depicted. Note that in no case does the CEP Rider compensate the Utilities
for the under-recovery experienced to date under the F&PP Rider mechanism ($130
million).
Table 10
Impact of Proposed CEP Rider
Nevada Jurisdiction
(Million ) $
Nevada Power Divestiture No Divestiture
Forecast Forecast
------------------------ ---------------------------
2001 2002 2003* 2001 2002 2003*
Base Fuel & Purchase Power Revenues 605 724 110 493 513 78
Additional Revenue under Global Settlement 260 320 41 260 431 58
Additional Revenue From CEP Rider 63 (58) (9) 183 (9) (7)
Net Fuel & Purchase Power Costs 962 984 114 977 925 100
------------------------ ---------------------------
Fuel & Purchase Power Margin (33) 2 29 (42) 10 29
Fuel & Purchase Power Margin (2001 - Feb 2003) (3) (2)
Sierra Pacific Power Divestiture No Divestiture
Forecast Forecast
------------------------ ---------------------------
2001 2002 2003* 2001 2002 2003*
Base Fuel & Purchase Power Revenues 300 365 63 250 262 45
Additional Revenue under Global Settlement 88 145 22 88 205 41
Additional Revenue From CEP Rider 52 24 4 86 139 25
Net Fuel & Purchase Power Costs 495 491 76 526 532 88
------------------------ ---------------------------
Fuel & Purchase Power Margin (55) 42 13 (102) 73 24
Fuel & Purchase Power Margin (2001- Feb 2003) 0 (4)
*2003 includes only January and February 2003
VI. CONSERVATION AND LOW-INCOME PROTECTION
------------------------------------------
A. Conservation and Low-Income Rate Design
------------------------------------------
The Utilities also propose to mitigate the impact of rate increases on its
low-income residential and small commercial customers and to encourage energy
conservation through an intraclass, revenue-neutral, rate design adjustment.
This rate design will allow low income and low usage customers to avoid the CEP
Rider altogether while encouraging high usage customers to conserve. The
residential and small commercial CEP Rider is structured as a tiered rate with
the per kWh charge increasing with consumption.
Table 11
Residential and Small Commercial Rate Design for CEP Rider
Nevada Power
Residential Small Commercial (GS)
CEP Rider CEP Rider
First 400 kWh per month $ 0.00000 per kWh First 400 kWh per month $ 0.00000 per kWh
Next 275 kWh per month $ 0.01500 per kWh Next 275 kWh per month $ 0.01500 per kWh
Above 675 kWh per month $ 0.02000 per kWh Above 675 kWh per month $ 0.02065 per kWh
Sierra Pacific Power
Residential Small Commercial (GS-1)
CEP Rider CEP Rider
First 300 kWh per month $ 0.00000 per kWh First 550 kWh per month $ 0.00000 per kWh
Next 250 kWh per month $ 0.01500 per kWh Next 750 kWh per month $ 0.01500 per kWh
Above 550 kWh per month $ 0.02617 per kWh Above 1,300 kWh per month $ 0.01760 per kWh
This type of rate structure will require modifications to the Utilities' billing
system. Once approved by the Commission these modifications will take
approximately 60 days to complete. The Utilities' are proposing that until such
modifications can be completed, the residential and small commercial CEP Rider
rate be set at $ 0.01250 per kWh. The Utilities will implement the tiered
structure as soon as the billing system modifications can be implemented.
Assuming timely regulatory authorization of the Plan, this rate structure will
be implemented prior to the beginning of the Summer peak.
B. Conservation and Low Income Protection Fund
- ----------------------------------------------
In addition, the Utilities propose to use the CEP Rider to fund conservation and
low-income protection programs. The Utilities propose that up to $5 million in
revenue generated by the CEP Rider be provided to the State of Nevada to be used
at the State's discretion to fund conservation and low-income protection
programs.
C. Voluntary Curtailment and Conservation Program
-------------------------------------------------
Both Utilities have established a target date of February 9th for filing new
tariffs that will allow large customers to voluntarily curtail blocks of load at
the Utilities' request and receive payment at a percentage of market prices. The
Utilities have been working with the PUCN Staff and customers for several months
in a workshop forum to develop the details of this program, which are summarized
below.
The tariffs will be offered on an experimental basis for a period of one year at
which time the effectiveness of the program will be evaluated. The program is
unique in that it will compensate customers who elect to curtail their load to
share in market prices for power that would have otherwise been purchased by the
Utilities (at even greater cost) to serve expected load. The goal of the program
is to reduce purchase power costs and assist in meeting increasing load
requirements.
The optional curtailment program will be offered to customers with a minimum
load of 1 MW and the ability to curtail a minimum of 500 kW. By concentrating on
larger loads, the savings and benefits are expected to far outweigh any
additional costs of administering the program. Customers will have the option to
voluntarily curtail their load when the day-ahead market price of power reaches
or exceeds $250/MWh and the Utilities need the capacity and energy. Upon receipt
of notice, eligible customers will have the option to confirm their commitment
to curtail load for the next day. The Utilities will then schedule or rely on
the curtailment in meeting the next day's load requirement. Curtailment credits
will be calculated monthly and applied to the customer's bill.
Customers can meet their curtailment obligations by shedding load, starting
standby or backup generation, and running their standby generation in parallel
with the utility grid. Ideally customers will use generation to offset the
curtailed load to minimize the impact to their operations, which has the dual
effect of efficiently allocating resources and attracting new resources to the
system.
The Utilities have been working with the PUCN Staff and customers through a
workshop forum to develop this program. Initial discussions with customers
participating in the workshops indicate a high level of willingness to
participate. The Utilities hope to attract 100 MW of curtailable load in SPPC's
service territory and 200 MW in NPC's service territory to the new tariff.
VII. AUTHORITY REQUESTED
------------------------
A. Long-Term Supply Portfolio
- -----------------------------
The Utilities are requesting authority to pursue the above-described Plan either
as amendments to their respective resource plans and/or as separate authority
granted by the PUCN under NRS (S)704.320 and (S)704.988.
With respect to the Utilities' plan to repackage NPC's short-term portfolios
pursuant to the RFP set forth in Appendix A (the 2001 Contract Reformation), NPC
and is requesting pre-approval of the contract terms described there. So that
the PUCN may verify that the material terms and conditions of the pre-approved
contract terms have been satisfied, NPC will file the final contract(s) within
15 days of execution.
With respect to remaining contracts that will be necessary to implement the
proposed Plan, the Utilities are requesting a commitment to expedited contract
review. Effective March 1, 2001 and ending February 28, 2003, the Utilities will
file proposed contracts, within specified terms and ranges, for pre-approval by
the PUCN. The Utilities request that such contracts be either rejected within 30
days or deemed approved.
B. Cost Recovery and Rate Mitigation
- ------------------------------------
In order to enable SPPC and NPC to enter into such contracts and to provide
security to the sellers of fuel and purchased power that the Utilities will have
the financial wherewithal to honor their payment obligations, the PUCN will
allow the Utilities to implement the rate recovery mechanism described above.
Appendices B and C set forth the tariffs for NPC and SPPC respectively that
implement the CEP Rider, including the tiered mitigation rate design for
residential and small commercial customers. The Utilities ask that these tariffs
be made effective without suspension, but subject to refund, on March 1, 2001.
Table 1 of Appendices D and E show the impact by class of the CEP Rider for NPC
and SPPC, respectively. Table 2 of these appendices provides the rate design
calculation for the residential and small commercial CEP Rider. Table 3 of these
appendices provides illustrative sample bill calculations showing various
customer usage for the residential and small commercial classes.
CONCLUSION
----------
To avoid the debacle in California, Nevada must implement a well-planned and
measured approach to customer choice and retail competition. As events in
California have conclusively proven, reliability of supply is absolutely
dependent on the ability of the Utilities to finance their supply portfolio. The
key to financability (and thus reliability) is legal assurance of timely and
fair recovery of the costs of the supply portfolio. Without such assurance,
Utilities cannot pay their fuel and energy bills and suppliers will not
undertake the risk of non-payment. An effective and comprehensive response to
the current energy crisis must therefore include:
. Quick and unequivocal resolution of the fate of Nevada's
divestiture process.
. Approval of longer-term contracting for wholesale fuel and
purchased power in a balanced and, where possible, an
assignable portfolio, including specific approval of the 2001
Contract Reformation.
. Implementation of a cost recovery mechanism sufficient to
finance the Utilities' long-term portfolios.
. Approval of the conservation programs for all classes of
customers.
. Protections for those customers least able to weather the
effects of current energy market conditions.
. Renewed focus on planning and development of new generation
supplies and other infrastructure.
This Plan addresses each of these elements in turn. The Utilities
respectfully submit this Comprehensive Energy Plan in order to insure that
Nevadans weather the current crisis, and are better positioned to face the
future, whatever it may hold.
PURPOSE & SCOPE
Nevada Power Company (NPC) issues this Request for Proposals (RFP) to solicit
competitive proposals for power to support its growing electrical service
territory demand. NPC is an operating subsidiary of Sierra Pacific Resources.
General information related to Sierra Pacific Resources and NPC can be obtained
at http://www.sierrapacificresources.com.
-------------------------------------
NPC invites proposals that will offer exceptional value to NPC and its
customers. Respondents are required to provide Firm Energy in the amounts, and
during the term, specified in Attachment 1. This RFP also requires the sale of
Energy to Respondent by NPC during 2001 in the amounts and at prices specified
in Attachment 1. For purposes of this solicitation, NPC is encouraging
Respondents to provide a proposal that conforms to the specifications contained
in Attachment 1. Proposals for different contract terms and contract options may
be considered only to the extent that year 2001 pricing and quantities conform
to the requirements contained in Attachment 1.
SCHEDULE
NPC reserves the right to revise, suspend, or terminate this schedule at its
sole discretion. Any changes to the schedule will be provided, as appropriate,
to entities which have been provided a copy of this RFP by NPC.
Summary of Key Dates
- --------------------
. January 31, 2001 - RFP issued.
. January 31 - February 19, 2001 - NPC will respond to questions regarding
RFP. All questions must be submitted in writing.
. February 23, 200 - Proposals must be received by NPC by 5:00P.M. PST.
. March 23, 2001 - Negotiations completed and Agreements signed.
. April 1, 2001 - Delivery of power to NPC begins.
PROPOSAL INSTRUCTIONS
1. All inquiries and other communications relating in any manner to this RFP
must be directed in writing or by facsimile or e-mail to NPC's RFP Contact.
Meetings via conference calls or in-person will be arranged by NPC if
required to clarify any outstanding issues or questions the Respondents may
have.
2. All Respondents must submit with their proposal a Proposal Summary Form
using the form provided as Attachment 1.
3. All proposals submitted must conform to the information contained in
Attachment 1 and include all applicable information for NPC to properly
evaluate Respondent's proposal.
Respondent should, at the time of submittal, supply any additional
information not included in the forms if such information may be needed for
a thorough understanding or evaluation of the proposal. All responses will
be considered commitments to be used in developing the agreement between
NPC and the Respondent that may arise from this RFP. A signed written
original, and an electronic copy including all attachments, must be
submitted. In the event of a discrepancy between the electronic forms and
the printed copy, the printed and signed copy will be considered to be
correct.
4. Respondent shall state in its proposal acceptance to using WSPP contract
terms as modified by the contract terms contained in the RFP. If
applicable, Respondent shall identify its changes to the contract terms
herein in its proposal.
5. A duly authorized officer of the Respondent must sign the proposal.
6. All proposals, including all attachments, must be properly completed and
submitted by overnight courier or Registered or Certified Mail, Return
Receipt Requested, in both hard copy and electronic versions, to NPC' s RFP
Contact:
Mr. Craig Berg
Director Risk Management Sierra Pacific
Resources
6100 Neil Road, Mail Station S3B40
Reno, Nevada 89520-3150
ATTENTION: REQUEST FOR PROPOSAL
Phone: (775) 834-4531
Fascsimile: (775)834-3841
E-mail: Cberg@sppc.com
--------------
7. All proposals must be received by NPC's RFP Contact by no later than 5:00
PM (PST) on Friday, February 23, 2001. Late and/or incomplete proposals
may not be considered. Proposals will remain binding on Respondent through
the date for completion of negotiations.
8. Complete information is needed to facilitate a timely evaluation. NPC may
request clarifying or additional information at any time during the
evaluation process, and Respondent will be expected to provide timely
responses to facilitate the evaluation and decision making process within
the time constraints. Respondent must provide all data requested in the RFP
and the applicable attachments. NPC may eliminate non-specific proposals
from further consideration.
9. Proposals must reflect any and all of the costs that NPC would be expected to
pay for power delivered to NPC. If any portion of the total delivered cost
of power is not intended to be clearly defined in the pricing outlined in
the proposal, then a detailed description of the proposed approach
regarding that portion of cost must be clearly delineated in the proposal.
Prices and dollar figures quoted must be clearly stated in $US as nominal
for the year in
which they occur. For non-nominal prices, the appropriate year for the
stated dollars must be identified along with applicable escalation rates to
be used for subsequent years.
10. None of the material received by NPC from Respondent in response to this
RFP will be returned to Respondent. All materials and proposals submitted
by Respondent will become the property of NPC and may be used by NPC for
any purpose.
CONFIDENTIALITY
NPC will take reasonable precautions and use reasonable efforts to protect any
proprietary and confidential information contained in a proposal provided that
such information is clearly identified by Respondent as "Proprietary and
Confidential" on the page on which proprietary and confidential information
appears. Such information may, however, be made available under applicable state
or federal law to regulatory commission(s), their staff(s), or other
governmental agencies having an interest in these matters. NPC also reserves the
right to release such information to its agents, or contractors for the purpose
of evaluating Respondent's proposal but such agents, or contractors will be
required to observe the same care with respect to disclosure as NPC. Under no
circumstances will NPC, Sierra Pacific Resources or their agents, or
contractors, be liable for any damages resulting from any disclosure during or
after the solicitation process.
FIRM ENERGY REQUIREMENTS
NPC's Firm Energy requirements, for the purpose of this RFP, are defined as the
quantities identified in Attachment 1. NPC will consider proposals of less than
the required quantities identified in Attachment 1, provided that such proposals
can be grouped with other proposals to make up the necessary quantities. In such
an event, Respondents will be allocated and awarded a pro-rata portion of the
amounts shown in Attachment 1 during the term of the agreement.
PROPOSAL EVALUATION
1. NPC will evaluate proposals and select proposals, if any, which provide the
most value to NPC and its customers. NPC reserves the right to evaluate the
proposals in a manner that ultimately produces the most competitive
responses from which to begin negotiations.
2. Proposals may be combined with other proposals.
3. NPC will determine at its sole discretion the value of any and/or all
proposals.
4. Information provided from each Respondent by the proposal due date will be
used to begin negotiations.
5. NPC will evaluate the proposals in terms of price and non-price attributes.
6. NPC will perform an initial screening evaluation to identify and eliminate
any proposals that are not responsive to the RFP, do not meet the minimum
requirements set forth in the RFP, are clearly not economically competitive
with other proposals, or are submitted by Respondents that lack appropriate
creditworthiness or sufficient financial resources or qualifications to
provide dependable and reliable service.
7. NPC reserves the right, without qualification and in its sole discretion, to
accept or reject any or all proposals for any reason without explanation to
the Respondent, or to make the award to that Respondent, who, in the opinion
of NPC, will provide the most value to NPC and its customers. NPC also
reserves the right to make an award to other than the lowest price offer or
to the proposal evidencing the greatest technical ability if NPC determines
that to do so would result in the greatest value to NPC and its customers.
8. NPC reserves the right to reject any, all, or portions of the proposals
received for failure to meet any criteria set forth in this RFP. NPC also
may decline to enter into a power purchase arrangement with any Respondent,
terminate negotiations with any Respondent, or to abandon the RFP process in
its entirety. NPC reserves the right to revise the Firm Energy needs
forecast at any point during the RFP process or during negotiations and any
such change may reduce, eliminate, or increase the amount of power sought.
9. Those who submit proposals agree to do so without legal recourse against
NPC, Sierra Pacific Resources, its affiliates or subsidiaries, and their
directors, officers, employees and agents for rejection of their proposal(s)
or for failure to execute a power purchase agreement for any reason. NPC and
Sierra Pacific Resources shall not be liable to any Respondent or party in
law or equity for any reason whatsoever for any acts or omissions arising
out of or in connection with this RFP.
10. Respondent shall be liable for all its costs and NPC shall not be
responsible for any of Respondent's costs, incurred by Respondent to
prepare, submit, or negotiate its proposal.
DELIVERY POINT(S)
NPC may accept some or all of Respondent's Firm Energy at Mead, McCullough,
Eldorado, Crystal, Harry Allen, Navajo, El Dorado Merchant Substation or at
another mutually acceptable delivery point within the Nevada Power Company
transmission system. (Respondent shall select a delivery point(s) in its
proposal.)
TRANSMISSION CONSTRAINTS
The NPC transmission system has several constraints, which may limit the amount
of energy that could be transferred from points "upstream" of the constraints
and delivered into the NPC load pocket. Respondent is advised that proposals
that split up delivery points or provide delivery out of existing units or
planned construction of new units within the NPC load pocket will be given
preference. A transmission diagram identifying NPC's transmission rights and
transmission constraints can be reviewed at www.swoasis.com (click on
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"Documents", go to "Intertie and Netloading" and then to "Nevada Power
Transmission Rights Diagram").
REGULATORY APPROVALS
Any contract for the purchase of power between NPC and the Respondent will be
filed with the applicable regulatory authorities that have jurisdiction over any
or all of the subject matter.
GENERAL CONTRACT TERMS
MINIMUM CREDIT REQUIREMENTS
Respondent must possess at time the Agreement is executed and during the period
of performance of the Agreement either a senior unsecured debt rating of no less
than BBB- from Standard & Poor's or Baa3 from Moody's, possess a minimum
tangible net worth (MTNW) of one billion dollars, or be able to provide a
guarantee in form and substance equivalent to the above. If at any time during
the term of the Agreement, Respondent's debt rating or MTNW, as applicable,
falls below these levels, Respondent must notify NPC and as a condition of
further contract performance NPC may require Respondent to provide whatever
other form of credit assurance NPC deems necessary.
FORM OF CONTRACT AND FAILURE TO PERFORM
1. NPC anticipates negotiating a power purchase agreement based upon WSPP
contract terms as may be modified by the terms in this RFP. Respondent shall
include a statement in its proposal that it will accept WSPP contract terms
and the contract terms included in this RFP or, if applicable, will identify
changes to the terms herein in its proposal.
2. NPC will rely on power purchased under this RFP to meet the electric needs
of its customers. Should Respondent fail to deliver power to NPC, Respondent
shall be liable to NPC for Replacement Costs in an amount equal to 110% of
total costs actually incurred by NPC to replace the power.
GAS INDEX
"Natural Gas Intelligence Weekly Gas Price Index" under the heading "Spot Gas
Prices" in the section "California: Southern Cal. Border Avg. Bidweek: Avg."
SCHEDULING
NPC will perform the schedule coordinator functions. By no later than 6:00 a.m.
(P.P.T.) on the business day prior to each delivery day or days, NPC will
provide the ISO, RTO, or local control area operator with a balanced schedule.
FAILURE TO DELIVER PAYMENT - REPLACEMENT COSTS
Respondent will pay to NPC 110% of total costs incurred by NPC to replace the
energy not delivered by Respondent, subject to causes of Force Majeure.
FAILURE TO TAKE PAYMENT
NPC shall pay Respondent for energy NPC failed to take, subject to causes of
Force Majeure.
TRANSMISSION
NPC will be responsible for any transmission fees and losses, if any, after
receipt by NPC at the Delivery Point(s).
LIMITATION OF LIABILITY
1. Responsibility for Damages: Except as otherwise provided herein or to the
--------------------------
extent of the other Party's negligence or willful misconduct, each Party
shall be responsible for all physical damage to or destruction of the
property, equipment and/or facilities owned by it and its affiliates and
any physical injury or death to natural Persons resulting therefrom,
regardless of who brings the claim and regardless of who caused the
damage, and shall not seek recovery or reimbursement from the other Party
for such damage; provided, that in any such case the Parties will exercise
due diligence to remove the cause of any disability at the earliest
practicable time.
2. No Consequential Damages: To the fullest extent permitted by law and
------------------------
notwithstanding other provisions of the Agreement, in no event shall a
Party, or any of its agents, be liable to the other Party, whether in
contract, warranty, tort, negligence, strict liability, or otherwise, for
special, indirect, incidental, multiple, consequential (including but not
limited to lost profits or revenues and lost business opportunities), or
punitive damages related to or resulting from performance or
nonperformance of the Agreement or any activity associated with or arising
out of the Agreement. For purposes of clarification, Replacement Costs
shall not be considered consequential or incidental damages. In addition,
this limitation on liability shall not apply with respect to claims of
indemnification by third parties.
3. Survival: The provisions of this clause shall survive any termination,
--------
cancellation, or suspension of the Agreement.
FORCE MAJEURE
1. An event of "Force Majeure" shall be defined as any interruption or
failure of service or deficiency in the quality or quantity of service or
any other failure to perform any of its obligations hereunder to the
extent such failure occurs without fault or negligence on the part of that
Party and is caused by factors beyond that Party's reasonable control,
which by the exercise of reasonable diligence that Party is unable to
prevent, avoid, mitigate or overcome, including:
a. acts of God or the public enemy, such as storms, flood, lightning, and
earthquakes,
b. failure, threat of failure, or unscheduled withdrawal of facilities
from operation for maintenance or repair, and including unscheduled
transmission and distribution outages,
c. sabotage of facilities and equipment,
d. civil disturbance,
e. strike or labor dispute,
f. action or inaction of a court or public authority, or
g. any other cause of similar nature beyond the reasonable control of that
Party.
2. Economic hardship of either Party shall not constitute Force Majeure under
the Agreement. Notwithstanding this, if NPC suffers an event of Force
Majeure it shall be relieved of its obligation to take delivery of, or
otherwise pay for the Energy under the Agreement for the duration of the
event of Force Majeure. In addition, if NPC is unable to have Energy
delivered from the Point(s) of Delivery to its service territory due to an
outage on the Transmission System, that shall be considered a Force
Majeure event and shall relieve NPC of performance for the extent of the
event.
3. In the event of a Force Majeure, neither Party shall be considered in
default under the Agreement or responsible to the other Party in tort,
strict liability, contract or other legal theory for damages of any
description, and affected performance obligations shall be extended by a
period equal to the term of the resultant delay, but in no event shall
exceed the term of the Agreement, provided that the Party relying on a
claim of Force Majeure:
a. provides prompt written notice of such Force Majeure event to the other
Party, giving an estimate of its expected duration and the probable
impact on the performance of its obligations hereunder;
b. exercises all reasonable efforts to continue to perform its obligations
under the Agreement;
c. expeditiously takes action to correct or cure the event or condition
excusing performance so that the suspension of performance is no
greater in scope and no longer in duration than is dictated by the
problem; provided, however, that settlement of strikes or other labor
disputes will be completely within the sole discretion of the Party
affected by such strike or labor dispute;
d. exercises all reasonable efforts to mitigate or limit damages to the
other Party; and
e. provides prompt notice to the other Party of the cessation of the event
or condition giving rise to its excuse from performance.
DISPUTES
1. Any action, claim or dispute which either Party may have against the other
arising out of or relating to the Agreement or the transactions contemplated
hereunder, or the breach, termination or validity thereof (any such claim or
dispute, a "Dispute") shall be submitted in writing to the other Party. The
written submission of any Dispute shall include a concise statement of the
question or issue in dispute together with a statement listing the relevant
facts and documentation that support the claim.
2. The Parties agree to cooperate in good faith to expedite the resolution of
any Dispute. Pending resolution of a Dispute, the Parties shall proceed
diligently with the performance of their obligations under the Agreement.
3. The Parties shall first attempt in good faith to resolve any Dispute through
informal negotiations. In the event that the Parties are unable to
satisfactorily resolve the Dispute within thirty (30) days from the receipt
of notice of the Dispute, either Party may by written notice to the other
Party refer the Dispute to its respective senior management for resolution as
promptly as practicable. If the Parties' senior management are unable to
resolve the Dispute within thirty (30) days from the date of such referral,
either Party may initiate arbitration through the serving and filing of a
demand for arbitration and the Parties expressly agree that arbitration in
accordance with the Agreement shall be the exclusive means to further resolve
any Dispute and hereby irrevocably waive their right to any trial with
respect to any Dispute, provided that at any time:
a. A request made by a Party for provisional remedies requesting preservation
of the Parties' respective rights and obligations under the Agreement may
be resolved by a court of law located in Clark County, Nevada.
b. Nothing in the Agreement shall preclude, or be construed to preclude, any
Party from filing a petition or complaint with the FERC or PUCN with
respect to any arbitrable Dispute over which said agency has jurisdiction.
In such case, the other Party may request the FERC or PUCN, as applicable,
to reject or to waive jurisdiction. If jurisdiction is rejected or waived
with respect to all or a portion of the Dispute, the portion of the
Dispute not so accepted by the FERC or PUCN, as applicable, shall be
resolved through arbitration in accordance with the Agreement. To the
extent that the FERC or PUCN, as applicable, asserts or accepts
jurisdiction over the Dispute, the decision, finding of fact or order of
FERC or PUCN shall be final and binding, subject to judicial review under
the Federal Power Act or Nevada Revised Statutes. Any arbitration
proceedings that may have commenced with respect to the Dispute prior to
the assertion or acceptance of jurisdiction by the FERC or PUCN, as
applicable, shall be terminated to the extent the FERC or PUCN accepts or
asserts jurisdiction over such Dispute.
4. Unless otherwise agreed by the Parties, any arbitration initiated under the
Agreement shall be conducted in accordance with the following:
a. Arbitrations shall be held within Clark County, Nevada.
b. Except as otherwise modified herein, the arbitration shall be conducted
in accordance with the "Commercial Arbitration Rules" of the American
Arbitration Association ("AAA") then in effect.
c. Arbitration shall be conducted by one neutral arbitrator who shall be
selected pursuant to the AAA rules and the following:
i. The Parties agree that the list of potential arbitrators provided
by the AAA shall, if available, contain twenty (20) candidates, and
at least fifty percent (50%) of the candidates shall be members of
the AAA National Energy Panel.
ii. The Parties also agree that each shall be allowed to strike the
names of five candidates before ranking the remaining candidates
and returning the list to the AAA in accordance with the Commercial
Arbitration Rules. If the Parties are unable to agree on an
arbitrator, such arbitrator shall be appointed by the AAA.
iii. The arbitrator shall not have any current or past substantial
business, financial, or personal relationships with either Party
(or their Affiliates) and shall not be a past or present vendor,
supplier, customer, employee, consultant, or competitor to either
of the Parties or their Affiliates.
iv. The arbitrator shall be authorized only to interpret and apply the
provisions of the Agreement and shall have no power to modify or
change any provision of the Agreement. The arbitrator shall have no
authority to award punitive or multiple damages or any damages
inconsistent with the Agreement. The arbitrator shall within thirty
(30) days of the conclusion of the hearing, unless such time is
extended by agreement of the Parties, notify the Parties in writing
of his or her decision, stating his or her reasons for such
decision and separately listing his or her findings of fact and
conclusions of law. Judgment on the award may be entered in any
court having jurisdiction.
5. The Parties shall proceed with the arbitration expeditiously, and the
arbitration shall be concluded within five (5) months of the filing of the
demand for arbitration in order that the decision may be rendered within six
(6) months of such filing, unless the arbitrator extends such time at the
request of a Party upon a showing of good cause or upon agreement of the
Parties.
6. Any arbitration proceedings, decision or award rendered hereunder and the
validity, effect and interpretation of any arbitration agreement shall be
governed by the Federal Arbitration Act of the United States, 9 U.S.C.
(S)(S) 1 et seq.
7. The decision of the arbitrator shall be final and binding on both Parties
and may be enforced in any court having jurisdiction over the Party against
which enforcement is sought.
8. The fees and expenses of the arbitrator shall be shared by the Parties
equally, unless the decision of the arbitrator shall specify some other
apportionment of such fees and expenses. All other expenses and costs of the
arbitration shall be borne by the Party incurring the same.
CHOICE OF LAW
The Agreement and the rights and obligations of the Parties shall be construed
and governed by the Laws of: (i) the State of Nevada as if executed and
performed wholly within that state; and (ii) the Federal Power Act, to the
extent the rights and obligations of the Parties are covered by such act.
ATTACHMENT 1
PROPOSAL SUMMARY FORM
BUYER: Nevada Power Company
RESPONDENT:
CONTRACT
- --------
TERM: April 1, 2001 - December 31, 2010
PRODUCT: Respondent will deliver Firm Energy to NPC and NPC will take
Firm Energy from Respondent during the hours defined below.
CONTRACT
QUANTITY: Respondent will deliver the following contract quantities to
the delivery point during the term of the Agreement:
--------------------------------------------------
Volume (MW)
--------------------------------------------------
2001 2002 2003 2004-
2010
--------------------------------------------------
Quarter 1 0 500 500 500
--------------------------------------------------
Quarter 2 450 750 750 750
--------------------------------------------------
Quarter 3 775 1000 1000 1000
--------------------------------------------------
Quarter 4 275 500 500 500
--------------------------------------------------
DELIVERY
PROFILE: The following delivery profiles will be applicable during the
term of the Agreement:
-----------------------------------------------------
Delivery Profile
-----------------------------------------------------
2001 2002 2003 2004 - 2010
-----------------------------------------------------
Quarter 1 n/a HLH HLH AH
-----------------------------------------------------
Quarter 2 HLH HLH AH AH
-----------------------------------------------------
Quarter 3 HLH HLH AH AH
-----------------------------------------------------
Quarter 4 HLH HLH AH AH
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HLH - Monday through Saturday, hours ending 7 through 22 inclusive,
excluding NERC holidays.
AH - Monday through Sunday, hours ending 1 through 24 inclusive, including
NERC holidays.
RESPONDENT'S
CHOICE OF
DELIVERY
POINT(S) ________________________________________
NPC SALE
TO SELLER: NPC will sell to Respondent the following quantities in the
year 2001 delivered at Mead; Monday through Saturday, hours 7-
22 inclusive, excluding NERC holidays, at the prices specified
below:
---------------------------------
Volume Price
(MW)
---------------------------------
Quarter 2 450 $350.00
---------------------------------
Quarter 3 775 $350.00
---------------------------------
Quarter 4 275 $350.00
---------------------------------
CONTRACT
PRICE 2001: The Contract Price for deliveries made by Respondent to NPC
during the period April 1, 2001- December 31, 2001 will be
$0.00/MWh.
CONTRACT
PRICE 2002-2005: The Contract Price for deliveries by Respondent to NPC during
the period January 1, 2002-December 31, 2005 will be
$______/MWh.
CONTRACT
PRICE 2006-2010: The Contract Price for deliveries by Respondent to NPC during
the period 2006-2010 is defined as the sum of the Base Charge
and the Fuel Charge.
BASE
CHARGE: NPC shall pay to Respondent for service provided during a month
a Base Charge equal to the product of (a) the Base Rate and (b)
the energy (in MWh) delivered during the month.
BASE
RATE: The Base Rate shall be $______/MWh
ENERGY
- ------
CHARGE: NPC shall pay Respondent for service provided during a month an
Energy Charge equal to the product of (a) the Fuel Rate and (b)
the energy (in MWh) delivered during such month.
FUEL RATE: The Fuel Rate equals the Contract Heat Rate multiplied by the
Gas Index.
CONTRACT
HEAT RATE: 8,000 MMBtu per MWh.
Appendix B
Proposed Tarriff Sheets
Nevada Power Company
Appendix B has been omitted from this filing. This information has been filed
with the Public Utilities Commission of Nevada and is available through their
offices.
Appendix C
Proposed Tarriff Sheets
Sierra Pacific Power Company
Appendix C has been omitted from this filing. This information has been filed
with the Public Utilities Commission of Nevada and is available through their
offices.
Appendix D
Proposed Rate Design and Impact
Nevada Power Company
Appendix D has been omitted from this filing. This information has been filed
with the Public Utilities Commission of Nevada and is available through their
offices.
Appendix E
Proposed Rate Design and Impact
Sierra Pacific Power Company
Appendix E has been omitted from this filing. This information has been filed
with the Public Utilities Commission of Nevada and is available through their
offices.